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 Amendment
The amendments filed 11/11/2025 have been entered. Claims 1-2, 4-5, 7, 9-16, & 18-20 remain pending. Claims 1-2, 4, 7, 9, 12-14, & 18 have been amended. Claims 3, 6, 8, & 17 have been cancelled.
The Applicant’s amendments and arguments regarding the ‘Objection to the Drawings’, ‘Objection to the Specification’, ‘Rejection Under 35 U.S.C. §112(b)’, & “Claim Rejections – 35 USC §101” overcome the objections and rejections in the office action filed 08/21/2025.
Response to Arguments
Applicant’s arguments, see "Applicant Argument/Remarks Made in an Amendment" page 14 line 15 to page 15 line 2, filed 11/11/2025, with respect to ‘Objection to the Claims’ have been fully considered but they are not persuasive.
The Applicant argues that (page 15 line 1):
“Claims 1, 2, 4, 9, 12-14, and 18 are amended to correct antecedent basis.”
The Examiner respectfully responds:
Rule:
See MPEP 2173.05(a)(I): “The meaning of every term used in a claim should be apparent from the prior art or from the specification and drawings at the time the application is filed. Claim language may not be "ambiguous, vague, incoherent, opaque, or otherwise unclear in describing and defining the claimed invention."
Analysis:
At least under the broadest reasonable interpretation, the dependent claims of the form “the method of claim 1” (or similar) could refer to any method within claim 1 (or respective parent claim) and are therefore ambiguous as to which method is being modified in the dependent claim(s). Methods within claim 1 include “obtaining, using a logging system”, “determining a regional stratigraphic column”, etc..
Conclusion:
Although amendments overcome issue regarding using “the [distinctive claim terminology] prior to a first use of “a [distinctive claim terminology]”, the amended claims do not use sufficiently distinctive claim terminology. There are multiple elements within the parent claims which could (at least under the broadest reasonable interpretation) be referred to as “the method of claim parent 1”. The Examiner recommends amending the parent claim 1 with “A method for Exploration Dynamic Data Analysis” and the claims dependent on claim 1 with “The method for Exploration Dynamic Data Analysis”. The other claims should be amended similarly so as to avoid ambiguous or vague elements.
Applicant’s arguments with respect to claim(s) claims 1-2, 4-5, 7, 9-16, & 18-20 rejected under U.S.C. §103 (US 20210149069 A1 (Lin) in view of US 11585955 B2 (Stewart)) have been considered but are moot because the new ground of rejection does not rely on any reference applied in the prior rejection of record for any teaching or matter specifically challenged in the argument.
Claim Objections
Claims 2, 4-5, 7, 9-16, & 18-20 objected to because of the following informalities:
Claims 2, 4-5, 7, & 9-11 in line 1 (each claim) recites the limitation "the method of claim 1[9]" in the preamble. There are multiple limitations within the base claim 1 which could be referred to by “the method of claim 1”. This lack of particularity when referring to an element or limitation in a claim could lead to 35 U.S.C. §112(b) antecedent basis issues. The Examiner recommends amending the parent claim 1 with “A method for Exploration Dynamic Data Analysis” and the claims dependent on claim 1 with “The method for Exploration Dynamic Data Analysis”.
Claims 13-16, & 18-20 in line 1 (each claim) recites the limitation "the system of claim 12[14[18]" in the preamble. There are multiple limitations within the base claim 12 which could be referred to by “the system of claim 12”. This lack of particularity when referring to an element or limitation in a claim could lead to 35 U.S.C. §112(b) antecedent basis issues. The Examiner recommends amending the independent claim 12 in the preamble with “A system for Exploration Dynamic Data Analysis” and the dependent claims in their preambles with “The system for Exploration Dynamic Data Analysis”.
Note: the first instance of an element should be in the form “a [unique descriptive terminology]” and successive references to that element should be in the form “the [unique descriptive terminology]” where [unique descriptive terminology] is the same throughout the claims. This is necessary because similarly phrased elements can be patentably distinct. Otherwise, the claim would likely raise 35 U.S.C § 112(b) antecedent basis issues.
Appropriate correction is required.
Claim Rejections - 35 USC § 103
In the event the determination of the status of the application as subject to AIA 35 U.S.C. 102 and 103 (or as subject to pre-AIA 35 U.S.C. 102 and 103) is incorrect, any correction of the statutory basis (i.e., changing from AIA to pre-AIA ) for the rejection will not be considered a new ground of rejection if the prior art relied upon, and the rationale supporting the rejection, would be the same under either status.
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) 1-2, 4-5, 7, 9-16, & 18-20 is/are rejected under 35 U.S.C. 103 as being unpatentable over US 10428642 B2 (newly cited, henceforth Carpenter) in view of US 11162356 B2 (newly cited, henceforth Fitzgerald).
Regarding claim 1, Carpenter teaches a method comprising: iteratively: drilling, using a drilling system comprising a drill bit (drilling of the substantially horizontal well 105 as seen in Fig. 1 necessarily requires the use of a drill bit), a portion of a wellbore among a plurality of wellbores (Fig. 1-120 through 125, column 3 lines 21-23: “FIG. 1 illustrates six locations 110-115 along the horizontal well that are represented by both horizontal situational data 120-125 and vertical situational data 130-135”, plurality of wellbores/(“vertical situational data 130-135”)) through a subsurface region of interest guided by a wellbore path (Fig. 1-105: “horizontal well”, column 2 lines 24-25: “A substantially horizontal well 105 is drilled through the geological formation 100.”); obtaining, using a logging system (the pseudo-logs necessarily require that there was a logging system involved) while drilling, a well log and a well test result for the portion of the wellbore (Fig. 2-209: “pseudo-logs of horizontal well path”, column 1 lines 45-47: “FIG. 2 is a flowchart showing an embodiment of a method for transposition of logs onto horizontal wells in accordance with the embodiment of FIG. 1”); projecting the plurality of wellbores onto a line of section (Fig. 1-105: “”, column 2 lines 1-4: “A pseudo log may be defined as a geometric projection of an offset well log along a well path through a geological model. If the offset well data are projected along the planned well path parallel to the geology, a predicted or pseudo log may be created.”, projecting onto line of section/(“ geometric projection … along a well path”)); for each of the plurality of wellbores, determining a stratigraphic column (column 2 lines 60-62: “Referring to FIG. 1, the geological model may be represented by the different illustrated layers of the formation 100.”, stratigraphic column/(“layers of the formation”)) and a petroleum system description using the well log and the well test result (Fig. 2-209: “pseudo-logs of horizontal well path”); determining a regional stratigraphic column based on the stratigraphic column for the plurality of wellbores and a depth interval (Fig. 3-314: “subsurface geological formations”, column 6 lines 9-13: “During the upward trip, at a series of depths, the instruments (e.g., transducers and receivers) included in the tool body 320 may be used to perform measurements on the subsurface geological formations 314 adjacent the borehole 312 (and the tool body 320)”); generating a visual representation comprising aligning the regional stratigraphic column with the petroleum system description for the plurality of wellbores by determining a geologic time (column 2 lines 55-62: “Referring to the flowchart of FIG. 2, in block 201, a geological model is generated for the geological formation through which the horizontal well path is drilled. As described previously, this model describes the geophysical and geological attributes of the portion of the Earth's crust that the horizontal well is drilled or will be drilled. Referring to FIG. 1, the geological model may be represented by the different illustrated layers of the formation 100.”, aligning is done by matching layers from each well to their corresponding location in the other wells as in Fig. 1, POSITA knows the layers represent different geologic time periods) within the regional stratigraphic column that the petroleum system description is true for; displaying the visual representation on a display device (column 7 lines 21-23: “In some embodiments, a system 364, 464 may include a display 496 to present geological data as discussed previously.”);
Carpenter does not as explicitly teach identifying, using an interpretation workstation, a drilling target within the subsurface region of interest based, on the visual representation; updating the wellbore path to intersect the drilling target; and updating an orientation of the drill bit based on the updated wellbore path.
Fitzgerald teaches identifying, using an interpretation workstation (Fig. 8 is a display and necessarily requires a workstation), a drilling target within the subsurface region of interest based, on the visual representation; updating the wellbore path to intersect the drilling target (Fig. 2-280: “target area”, column 7 lines 26-29: “A target area 280 specified in the drill plan may be located in strata layer 272-1 as shown in FIG. 2. Target area 280 may represent a desired endpoint of borehole 106, such as a hydrocarbon producing area indicated by strata layer 272-1”); and updating an orientation of the drill bit based on the updated wellbore path (Fig. 7-732: “Calculate Trajectory Misfit” & Fig. 7-736: “corrective action” , column 1 lines 60-61: “FIG. 7 is a depiction of a steering control process used by the rig control systems”, Fig. 10-1014: “Geosteering Control”,).
It would have been obvious to one of ordinary skill in the relevant art before the effective filing date of the claimed invention to have modified the method taught by Carpenter with the teachings of Fitzgerald. One would add to the “Transposition Of Logs Onto Horizontal Wells” of Carpenter the “Downhole Display” of Fitzgerald. The motivation would have been that the inventive concept of Carpenter would enable a user to accurately find target areas and the inventive concept of Fitzgerald would then allow one to quickly reach the target areas (see Fitzgerald column 25 lines 15-21: “allowing a user to easily and quickly manipulate the data via the downhole display provided by the downhole display system is advantageous because it minimizes the time required and increases the likelihood of a correct correlation of downhole data, thus allowing for faster and better decisions and adjustments in essentially real time during drilling.”)
Regarding claim 2, Carpenter in view of Fitzgerald teaches the method of claim 1,
Fitzgerald further teaches further comprising planning the wellbore path, using a wellbore path planning system(Fig. 7-732: “calculate trajectory misfit”, Fig. 7-734: “corrective action to minimize misfit”), to intersect the drilling target (Fig. 2-106, Fig. 2-280, column 7 lines 26-29: “A target area 280 specified in the drill plan may be located in strata layer 272-1 as shown in FIG. 2. Target area 280 may represent a desired endpoint of borehole 106, such as a hydrocarbon producing area indicated by strata layer 272-1”).
Regarding claim 4, Carpenter in view of Fitzgerald teaches the method of claim 1,
Carpenter further teaches wherein projecting the plurality of wellbores comprises: interrogating a spatial map of the plurality of wellbores penetrating the subsurface region of interest (column 3 lines 36-41: “This may be accomplished by mapping the collected geological data to each particular location of a plurality of locations 110-115 along the horizontal well path 105 using the horizontal situational data 120-125 that is associated with the vertical situational data 130-135”); forming the line of section on the spatial map (Fig. 1-105, In Fig. 1 the line 105 is equivalent to the “line of section” but seen from a side view); and projecting spatial coordinates of a wellhead from at least one of the plurality of wellbores onto the line of section (column 2 line 67-colunmn 3 line 5: “The situational data may be defined as some type of indication representative of a particular location in the well. For the vertical well, the situational data may be representative of a particular depth. For the horizontal well, the situational data may be representative of a particular horizontal location.”, system determines locations of the plurality of wellbores).
Regarding claim 5, Carpenter in view of Fitzgerald teaches the method of claim 4,
Fitzgerald further teaches wherein the spatial map further comprises a reservoir indicating attribute overlaid on the spatial map (column 7 lines 26-29: “A target area 280 specified in the drill plan may be located in strata layer 272-1 as shown in FIG. 2. Target area 280 may represent a desired endpoint of borehole 106, such as a hydrocarbon producing area indicated by strata layer 272-1”).
Regarding claim 7, Carpenter in view of Fitzgerald teaches the method of claim 1,
Carpenter further teaches wherein the well test result comprises a hydrocarbon flow rate (column 4 lines 33-35: “One or more Production Indices may also be computed from pseudo logs, log predictions obtained from a neural network, logs obtained in the horizontal well and facies.”, production indices would include hydrocarbon flow rate).
Regarding claim 9, Carpenter in view of Fitzgerald teaches the method of claim 1,
Carpenter further teaches wherein generating the visual representation comprises: partitioning the regional stratigraphic column aligned with the petroleum system description into a series of rows that categorizes a petroleum system formation (Fig. 1-103: “gamma ray plot”, gamma ray plot characterizes rows in the graph where rows correspond to geographic layers ); and for each of the plurality of wellbores: labeling [[each]] the petroleum system description using a plurality of differentiators(Fig. 1-120 through 125, these labels differentiate the plurality of vertical wellbores).
Regarding claim 10, Carpenter in view of Fitzgerald teaches the method of claim 9,
Carpenter further teaches wherein the series of rows that categorizes the petroleum system formation are positioned in order from a starting wellhead location on the line of section to an ending wellhead location on the line of section (Fig. 1-120 to Fig. 1-125: “”, column 3 lines 21-23: “six locations 110-115 along the horizontal well that are represented by both horizontal situational data 120-125 and vertical situational data 130-135”, system has a series of rows representing locations from a starting location to ending location).
Regarding claim 11, Carpenter in view of Fitzgerald teaches the method of claim 1,
Carpenter further teaches wherein identifying the drilling target further comprises interrogating the visual representation to identify a drilling target pattern based on a plurality of differentiators (column 4 lines 3-8: “The following methodology may be used to engineer a completion process. In a completion process, stages are defined and, within each stage, locations to perforate are selected. Stages need not be contiguous (e.g., gaps may exist between stages). After the perforations are shot for a stage, the well may be fractured.”, system determines A drilling target pattern/(“locations to perforate”) to find oil or gas).
Regarding claim 12, Carpenter teaches system comprising: iteratively: a drilling system comprising a drill bit (drilling of the substantially horizontal well 105 as seen in Fig. 1 necessarily requires the use of a drill bit) and configured to drill a portion of a wellbore among a plurality of wellbores (Fig. 1-120 through 125, column 3 lines 21-23: “FIG. 1 illustrates six locations 110-115 along the horizontal well that are represented by both horizontal situational data 120-125 and vertical situational data 130-135”, plurality of wellbores/(“vertical situational data 130-135”)) through a subsurface region of interest guided by a wellbore path (Fig. 1-105: “horizontal well”, column 2 lines 24-25: “A substantially horizontal well 105 is drilled through the geological formation 100.”); a logging system (the pseudo-logs necessarily require that there was a logging system involved) configured to obtain, while drilling, a well log and a well test result for the portion of the wellbore (Fig. 2-209: “pseudo-logs of horizontal well path”, column 1 lines 45-47: “FIG. 2 is a flowchart showing an embodiment of a method for transposition of logs onto horizontal wells in accordance with the embodiment of FIG. 1”); a computer processor (Fig. 4-354: workstation, a workstation necessarily has a processor) configured to: project the plurality of wellbores onto a line of section (Fig. 1-105: “”, column 2 lines 1-4: “A pseudo log may be defined as a geometric projection of an offset well log along a well path through a geological model. If the offset well data are projected along the planned well path parallel to the geology, a predicted or pseudo log may be created.”, projecting onto line of section/(“ geometric projection … along a well path”)), , determine a stratigraphic column (column 2 lines 60-62: “Referring to FIG. 1, the geological model may be represented by the different illustrated layers of the formation 100.”, stratigraphic column/(“layers of the formation”)) and a petroleum system description for each of the plurality of wellbores using the well log and the well test result (Fig. 2-209: “pseudo-logs of horizontal well path”), determine a regional stratigraphic column based on the stratigraphic column for the plurality of wellbores and a depth interval (Fig. 3-314: “subsurface geological formations”, column 6 lines 9-13: “During the upward trip, at a series of depths, the instruments (e.g., transducers and receivers) included in the tool body 320 may be used to perform measurements on the subsurface geological formations 314 adjacent the borehole 312 (and the tool body 320)”), generate a visual representation comprising aligning the regional stratigraphic column with the petroleum system description for the plurality of wellbores by determining a geologic time (column 2 lines 55-62: “Referring to the flowchart of FIG. 2, in block 201, a geological model is generated for the geological formation through which the horizontal well path is drilled. As described previously, this model describes the geophysical and geological attributes of the portion of the Earth's crust that the horizontal well is drilled or will be drilled. Referring to FIG. 1, the geological model may be represented by the different illustrated layers of the formation 100.”, aligning is done by matching layers from each well to their corresponding location in the other wells as in Fig. 1, POSITA knows the layers represent different geologic time periods) within the regional stratigraphic column that the petroleum system description is true for, and display the visual representation on a display device (column 7 lines 21-23: “In some embodiments, a system 364, 464 may include a display 496 to present geological data as discussed previously.”);
Carpenter does not as explicitly teach and an interpretation workstation configured to identify a drilling target within the subsurface region of interest based, on the visual representation, wherein the drilling system is further configured to: update the wellbore path to intersect the drilling target, and update an orientation of the drill bit based on the updated wellbore path.
Fitzgerald teaches and an interpretation workstation (Fig. 8 is a display and necessarily requires a workstation) configured to identify a drilling target within the subsurface region of interest based, on the visual representation, wherein the drilling system is further configured to: update the wellbore path to intersect the drilling target (Fig. 2-280: “target area”, column 7 lines 26-29: “A target area 280 specified in the drill plan may be located in strata layer 272-1 as shown in FIG. 2. Target area 280 may represent a desired endpoint of borehole 106, such as a hydrocarbon producing area indicated by strata layer 272-1”), and update an orientation of the drill bit based on the updated wellbore path (Fig. 7-732: “Calculate Trajectory Misfit” & Fig. 7-736: “corrective action” , column 1 lines 60-61: “FIG. 7 is a depiction of a steering control process used by the rig control systems”, Fig. 10-1014: “Geosteering Control”,).
It would have been obvious to one of ordinary skill in the relevant art before the effective filing date of the claimed invention to have modified the system taught by Carpenter with the teachings of Fitzgerald. One would add to the “Transposition Of Logs Onto Horizontal Wells” of Carpenter the “Downhole Display” of Fitzgerald. The motivation would have been that the inventive concept of Carpenter would enable a user to accurately find target areas and the inventive concept of Fitzgerald would then allow one to quickly reach the target areas (see Fitzgerald column 25 lines 15-21: “allowing a user to easily and quickly manipulate the data via the downhole display provided by the downhole display system is advantageous because it minimizes the time required and increases the likelihood of a correct correlation of downhole data, thus allowing for faster and better decisions and adjustments in essentially real time during drilling.”).
Regarding claim 13, Carpenter in view of Fitzgerald teaches the system of claim 12,
Fitzgerald further teaches further comprising: a wellbore path planning system (Fig. 7-732: “calculate trajectory misfit”, Fig. 7-734: “corrective action to minimize misfit”) configured to plan the wellbore path to intersect the drilling target (Fig. 2-106, Fig. 2-280, column 7 lines 26-29: “A target area 280 specified in the drill plan may be located in strata layer 272-1 as shown in FIG. 2. Target area 280 may represent a desired endpoint of borehole 106, such as a hydrocarbon producing area indicated by strata layer 272-1”).
Regarding claim 14, Carpenter in view of Fitzgerald teaches the system of claim 12,
Carpenter further teaches wherein projecting the plurality of wellbores comprises: interrogating a spatial map of the plurality of wellbores penetrating the subsurface region of interest (column 3 lines 36-41: “This may be accomplished by mapping the collected geological data to each particular location of a plurality of locations 110-115 along the horizontal well path 105 using the horizontal situational data 120-125 that is associated with the vertical situational data 130-135”); forming the line of section on the spatial map (Fig. 1-105, In Fig. 1 the line 105 is equivalent to the “line of section” but seen from a side view); and projecting spatial coordinates of a wellhead from at least one of the plurality of wellbores onto the line of section (column 2 line 67-colunmn 3 line 5: “The situational data may be defined as some type of indication representative of a particular location in the well. For the vertical well, the situational data may be representative of a particular depth. For the horizontal well, the situational data may be representative of a particular horizontal location.”, system determines locations of the plurality of wellbores).
Regarding claim 15, Carpenter in view of Fitzgerald teaches the system of claim 14,
Fitzgerald further teaches wherein the spatial map further comprises a reservoir indicating attribute overlaid on the spatial map (column 7 lines 26-29: “A target area 280 specified in the drill plan may be located in strata layer 272-1 as shown in FIG. 2. Target area 280 may represent a desired endpoint of borehole 106, such as a hydrocarbon producing area indicated by strata layer 272-1”).
Regarding claim 16, Carpenter in view of Fitzgerald teaches the system of claim 12,
Carpenter further teaches wherein the well test result comprises a hydrocarbon flow rate (column 4 lines 33-35: “One or more Production Indices may also be computed from pseudo logs, log predictions obtained from a neural network, logs obtained in the horizontal well and facies.”, production indices would include hydrocarbon flow rate).
Regarding claim 18, Carpenter in view of Fitzgerald teaches the system of claim 12,
Carpenter further teaches wherein generating the visual representation comprises: partitioning the regional stratigraphic column aligned with the petroleum system description into a series of rows that categorizes a petroleum system formation (Fig. 1-103: “gamma ray plot”, gamma ray plot characterizes rows in the graph where rows correspond to geographic layers ); and for each of the plurality of wellbores: labeling the petroleum system description using a plurality of differentiators (Fig. 1-120 through 125, these labels differentiate the plurality of vertical wellbores).
Regarding claim 19, Carpenter in view of Fitzgerald teaches the system of claim 18,
Carpenter further teaches wherein the series of rows that categorizes the petroleum system formation are positioned in order from a starting wellhead location on the line of section to an ending wellhead location on the line of section (Fig. 1-120 to Fig. 1-125: “”, column 3 lines 21-23: “six locations 110-115 along the horizontal well that are represented by both horizontal situational data 120-125 and vertical situational data 130-135”, system has a series of rows representing locations from a starting location to ending location).
Regarding claim 20, Carpenter in view of Fitzgerald teaches the system of claim 12,
Carpenter further teaches wherein identifying the drilling target further comprises interrogating the visual representation to identify a drilling target pattern based on a plurality of differentiators (column 4 lines 3-8: “The following methodology may be used to engineer a completion process. In a completion process, stages are defined and, within each stage, locations to perforate are selected. Stages need not be contiguous (e.g., gaps may exist between stages). After the perforations are shot for a stage, the well may be fractured.”, system determines A drilling target pattern/(“locations to perforate”) to find oil or gas).
Conclusion
The prior art made of record and not relied upon is considered pertinent to applicant's disclosure.
US 12248111 B2 "Well Log Correlation System" (Kulkarni) is relevant to the Applicant's disclosure, see Fig. 2 & Fig. 5.
US 10083258 B2 "Combining Downhole Fluid Analysis And Petroleum Systems Modeling" (Kauerauf) is relevant to the Applicant's disclosure, see Fig. 2 & Fig. 3.4.
US 20230041525 A1 "Automatic Model Selection Through Machine Learning" (Hong) is relevant to the Applicant's disclosure, see Fig. 3.
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.
Any inquiry concerning this communication or earlier communications from the examiner should be directed to MARTIN WALTER BRAUNLICH whose telephone number is (571)272-3178. The examiner can normally be reached Monday-Friday 7:30 am-5:00 pm.
Examiner interviews are available via telephone, in-person, and video conferencing using a USPTO supplied web-based collaboration tool. To schedule an interview, applicant is encouraged to use the USPTO Automated Interview Request (AIR) at http://www.uspto.gov/interviewpractice.
If attempts to reach the examiner by telephone are unsuccessful, the examiner’s supervisor, Huy Phan can be reached at (571) 272-7924. The fax phone number for the organization where this application or proceeding is assigned is 571-273-8300.
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/MARTIN WALTER BRAUNLICH/Examiner, Art Unit 2858
/RAUL J RIOS RUSSO/Examiner, Art Unit 2858