DETAILED ACTION
1. Claims 1-20 of application 18/759,151, filed on 28-June-2024, are presented for examination. The IDSs received on 28-June-2024 and 24-March-2025 have been considered.
The present application, filed on or after 16-March-2013, is being examined under the first inventor to file provisions of the AIA .
Claim Rejections under 35 U.S.C. § 102(a)(1)
2.1 The following is a quotation of the appropriate paragraphs of 35 U.S.C. § 102 that form the basis for the rejections under this section made in this Office action:
(a)(1) the claimed invention was patented, described in a printed publication, or in public use, on sale or otherwise available to the public before the effective filing date of the claimed invention.
2.2 Claims 1-3, 6, 8-10, 13, 15-17 and 20 are rejected under 35 U.S.C. § 102(a)(1) as being anticipated by Lockherd, SR. et al, INV, USP Publication 2005/0161258.
2.3 Lockherd discloses:
Claims 1, 8 and 15: A system comprising:
one or more acoustic elements of an acoustic device [¶0022 (acoustic transmitters)] that:
transmit acoustic waves as the acoustic device is deployed in a wellbore [0022 (Transmitters 34 are operable to transmit a sound wave into the wall of the well bore surrounding sensor section 22); 0041], and sense reflections of the transmitted acoustic waves [0023 (Receivers 32 may be aligned in a row as discussed earlier with regard to transmitters 34 so as to receive the reflected sound wave from all directions around acoustic position measurement system 23 during rotation of drill string U.); 0041];
a memory [0024; 0025 (electronics package)]; and
one or more processors that execute instructions out of the memory [0024; 0025 (electronics package)] to:
identify that the acoustic device is at a target location of the wellbore based on one or more evaluations of data associated with the acoustic wave reflections [0024 (Electronics
package 36 controls transmitters 34 to transmit acoustic signals in well bore 18 and processes reflected or return signals to provide positional information of the system in the well bore…the
positional information may be the distance between the acoustic position measurement
system 23 and a boundary.); 0038],
initiate one or more control functions [0021; 0037] that result in:
the deployment of the acoustic device being paused based on the identification that the acoustic device is at the target location of the wellbore [0021 (acoustic position measurement
system 23 provides positional feedback so that an operator or an automated drill guidance system may maintain drill string 12 in a desired position within coal seam 26 and/or to prevent drill string 12 from leaving coal seam 26.); 0037 (The information may enable an operator or an automated drill guidance system to keep the drill string at a desired relative position within the target formation. For example, if the operator or automated drill guidance system receives distance
and directional information indicating that the drill string is getting closer than desired to a boundary of the target formation, the operator or automated drill guidance system may guide the drill string in another direction to keep it centralized within the target formation.); 0038], and
a control setting of wellbore equipment being updated when the acoustic device is at the target location [0021 (acoustic position measurement system 23 provides positional feedback so that an operator or an automated drill guidance system may maintain drill string 12 in a desired position within coal seam 26 and/or to prevent drill string 12 from leaving coal seam 26.); 0037 (The information may enable an operator or an automated drill guidance system to keep the drill string at a desired relative position within the target formation. For example, if the operator or automated drill guidance system receives distance and directional information indicating that the drill string is getting closer than desired to a boundary of the target formation, the operator or automated drill guidance system may guide the drill string in another direction to keep it centralized within the target formation.); 0038].
Claims 2, 9 and 16: wherein the one or more processors execute the instructions out of the memory to:
identify that the acoustic device has reached a first feature of the wellbore based on an analysis of a first portion of the data associated with the acoustic wave reflections [0024 (the positional information may be the distance between the acoustic position measurement system 23 and a boundary, such as upper boundary 28 or lower boundary 29 of coal seam 26 of FIG. 1 as discussed in further detail below. In another embodiment, the positional information may be whether the system is within a specified range of a boundary, such as one or two feet.)], and
identify that the acoustic device has reached a second feature of the wellbore based on an analysis of a second portion of the data associated with the acoustic wave reflections [0024 (the positional information may be the distance between the acoustic position measurement system 23 and a boundary, such as upper boundary 28 or lower boundary 29 of coal seam 26 of FIG. 1 as discussed in further detail below. In another embodiment, the positional information may be whether the system is within a specified range of a boundary, such as one or two feet.)].
Claims 3, 10 and 17: wherein the first and the second feature of the wellbore correspond to different locations of a wellbore map [0039 (Electronics package 36 or another device may also be able to chart such a map based on the distance information provided by electronics package 36 and the directional information provided by directional sensor 38. The polar distance map may be continuously updated in real-time and may be charted below the surface.); 0040 (polar distance map 70 shows the distance from the acoustic position measurement system of the drill string to a point of closest approach (PCA) 72 of the target formation boundary in one direction and to a PCA
74 of the target formation boundary in an opposite direction.)].
Claims 6, 13 and 20: wherein the one or more processors execute the instructions out of the memory to:
identify that a portion of the data associated with the acoustic wave reflections matches a pattern indicative of a wellbore feature located at the target location [0040 (If it is desired to maintain a centralized position within the target formation with respect to the directions upon which polar distance map 70 is based, an operator or automated drill guidance system would want polar distance map 70 to appear symmetrical (e.g., approximately equal distance to PCA 72 and to PCA 74), as illustrated.)].
Claim Rejections under 35 U.S.C. § 103
3.1 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 of this title, 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 set forth in Graham v. John Deere Co., 383 U.S. 1, 148 USPQ 459 (1966), that are applied for establishing a background for determining obviousness under 35 U.S.C. § 103 are summarized as follows:
1. Determining the scope and contents of the prior art.
2. Ascertaining the differences between the prior art and the claims at issue.
3. Resolving the level of ordinary skill in the pertinent art.
4. Considering the objective evidence present in the application indicating
obviousness or nonobviousness.
3.2 Claims 7 and 14 are rejected under 35 U.S.C. § 103 as being unpatentable over Lockherd, SR. et al, INV, USP Publication 2005/0161258, in view of Romer et al, USP Publication 2020/0158903.
3.3 Lockherd discloses the invention substantially as claimed, but does not specifically disclose all of the features of claims 7 and 14. However, in an analogous prior art reference in the same field of endeavor and/or reasonably pertinent to the problem being solved, Romer describes these features, including:
Claims 7 and 14: wherein the one or more processors execute the instructions out of the memory to:
identify a first arrival time indicative of a first separation distance [0022 (An example of such a reflected acoustic pulse 124, as sensed by sensor assembly 140, is illustrated in FIG. 2.
FIG. 2 plots an intensity of sound detected by sensor assembly 40 as a function of time. However, as discussed, acoustic pulse 122 reflects from obstructions 90 and returns to sensor assembly 140 as reflected acoustic pulse 124. As such, and after a period of time that is sufficient for the acoustic pulse to travel to the obstruction and for the reflected acoustic pulse to return to the sensor assembly, a change and/or an increase in the acoustic intensity is detected by the sensor
assembly, as indicated at 125. As discussed in more detail herein, the elapsed time between initiation of acoustic pulse 122 and receipt of reflected acoustic pulse 124 by sensor assembly 140 may be utilized to calculate and/or to quantify the location of obstruction 90 and/or a distance between downhole tool 100 and the obstruction.)];
identify a second arrival time indicative of a second separation distance [0022; 0023 (However, it is within the scope of the present disclosure that the hydrocarbon well may include a plurality of downhole obstructions, as illustrated schematically in FIG. 1 and indicated at 90. When present, the plurality of downhole obstructions may generate a plurality of distinct reflected acoustic pulses 124, each of which may be received and/or detected by sensor assembly 140.)];
identify that the acoustic device has reached the target location based on the first arrival
time indicative of the first separation distance and the second arrival time indicative of the second separation distance corresponding to a wellbore feature located at the target location [0008 (The methods include positioning a downhole tool within a target region of a wellbore. The methods also include generating an acoustic pulse with an acoustic pulse generator of the downhole tool and propagating the acoustic pulse within the wellbore liquid and in a downhole direction. The methods further include reflecting the acoustic pulse from a downhole obstruction to generate a reflected acoustic pulse and propagating the reflected acoustic pulse within the wellbore liquid and in an uphole direction. The methods also include receiving the reflected acoustic pulse with an acoustic detector of a sensor assembly of the downhole tools and characterizing the downhole obstruction based, at least in part, on the reflected acoustic pulse.); 0046 (Under these conditions, controller 170 may be programmed to initiate acoustic pulse 122 with acoustic pulse generator 120 based, at least in part, on the position signal. More
specifically, the position signal may indicate if and/or when tool 100 is within target region 54. Controller 170 may initiate the acoustic pulse when the position signal indicates that the downhole tool is within the target region of the wellbore.)].
3.4 Therefore, it would have been obvious for a person of ordinary skill in the art, as of the effective filing date of the claimed invention, to modify the acoustic position measurement system as described by Lockherd, with the downhole tools for detecting a downhole obstruction within a wellbore as disclosed by Romer, because doing so would provide an improved technique to obtain knowledge of the presence, location, extent, and/or chemical composition
of an obstruction that would permit more targeted and/or effective removal techniques to be selected and/or performed, with a reasonably predictable expectation of success.
Claim Objections
4. In regard to the 35 U.S.C. § 102 or 103 rejections noted above, claims 4, 5, 11, 12, 18 and 19 are objected to as being dependent upon a rejected base claim.
Prior Art
5. The following prior art, discovered in an updated search and herein made of record but not relied upon, is considered pertinent to Applicant’s disclosure, and consists of documents A and B on the attached PTO-892 Notice of References Cited, such documents defining the general state of the art which is not considered to be of particular relevance.
Prior Art of Record
6. The Examiner has cited particular paragraphs or columns and line numbers in the references applied to the claims above for the convenience of the applicant. Although the specified citations are representative of the teachings of the art and are applied to specific limitations within the individual claim, other passages and figures may apply as well. It is respectfully requested of the applicant in preparing responses, to fully consider the references in their entirety as potentially teaching all or part of the claimed invention, as well as the context of the passage as taught by the prior art or disclosed by the Examiner. The prompt development of a clear issue requires that the replies of the Applicant meet the objections to and rejections of the claims. Applicant should also specifically point out the support for any amendments made to the disclosure (see MPEP §2163.06). Applicant is reminded that the Examiner is entitled to give the Broadest Reasonable Interpretation (BRI) of the language of the claims. Furthermore, the Examiner is not limited to Applicant’s definition which is not specifically set forth in the claims. [SEE MPEP 2141.02 [R-07.2015] VI. PRIOR ART MUST BE CONSIDERED IN ITS ENTIRETY, INCLUDING DISCLOSURES THAT TEACH AWAY FROM THE CLAIMS: A prior art reference must be considered in its entirety, i.e., as a whole, including portions that would lead away from the claimed invention. W.L. Gore & Associates, Inc. v. Garlock, Inc., 721 F.2d 1540, 220 USPQ 303 (Fed. Cir. 1983), cert, denied, 469 U.S. 851 (1984). See also MPEP §2123].
In addition, disclosures in a reference must be evaluated for what they would fairly teach one of ordinary skill in the art [See In re Snow, 471 F.2d 1400, 176 USPQ 328 (CCPA 1973) and In re Boe, 355 F.2d 961, 148 USPQ 507 (CCPA 1966)]. Specifically, in considering the teachings of a reference, it is proper to take into account not only the specific teachings of the reference, but also the inferences that one skilled in the art would reasonably have been expected to draw from the reference [See In re Freda, 401 F.2d 825, 159 USPQ 342 (CCPA 1968) and In re Shepard, 319 F.2d 194, 138 USPQ 148 (CCPA 1963)]. Likewise, it is proper to take into consideration not only the teachings of the prior art, but also the level of ordinary skill in the art [See In re Luck, 476 F.2d 650, 177 USPQ 523 (CCPA 1973)]. Specifically, those of ordinary skill in the art are presumed to have some knowledge of the art apart from what is expressly disclosed in the references [See In re Jacoby, 309 F.2d 513, 135 USPQ 317 (CCPA 1962)].
Response Guidelines
7.1 A shortened statutory period for response to this non-final action is set to expire 3 (three) months and 0 (zero) days from the date of this letter. Unless the applicant is notified in writing that a reply is required in less than six months (see the shortened response period previously noted), a maximum period of six months is allowed, if a petition for an extension of time and the fee set in § 1.17(a) are filed [see MPEP 710 and 35 U.S.C. 133]. Failure to respond within the required period for response will cause the application to become abandoned [see MPEP 710.02, 710.02(b)].
7.2 Any response to the Examiner in regard to this non-final action should be
directed to: Russell Frejd, telephone number (571) 272-3779, Monday-Friday from 0730 to
1600 ET. If attempts to reach the examiner by telephone are unsuccessful,
please contact the examiner’s supervisor, Peter Nolan, who can be reached at
(571) 270-7016.
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/RUSSELL FREJD/
Primary Examiner AU 3661
Prosecution Insights