CTNF 18/424,475 CTNF 101394 DETAILED ACTION Notice of Pre-AIA or AIA Status 07-03-aia AIA 15-10-aia The present application, filed on or after March 16, 2013, is being examined under the first inventor to file provisions of the AIA. Information Disclosure Statement The information disclosure statement (IDS) submitted on 01/26/2024 has been considered by the examiner. Claim Rejections - 35 USC § 103 07-20-aia AIA 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. 07-23-aia AIA 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 objective evidence present in the application indicating obviousness or nonobviousness. Claims 1-7 are rejected under 35 U.S.C. 103 as being unpatented over Hogue ( US 4,720,998 , hereinafter as “ Hogue ” ) in view of Marshall ( US 9,334,728 B2 , hereinafter as “ Marshall ”) and Thomas ( DE 10,2018,218,890 A1 , hereinafter as “ Thomas ”). In regard to claim 1, Hogue teaches a sampling system that obtains and stores a representative sample of crude oil as the oil flows from a stock tank into a sales line (Abstract). Hogue discloses a system measuring a fluid flow rate from a well (Fig. 1-6, col. 4, line 22 thru col. 6, line 47), including a water flow rate, the system comprising: (i) a production well (as oil well 14, Fig. 1); (ii) a flow line (the flow line before the storage tank and flow line (16, Fig. 1) for transporting produced fluids from the production well (14, Fig. 1) towards an oil meter (17, Fig. 1) then to the sales line (17’. Fig. 1), which implies fluid went through an oil separation process through a gas-oil separation process in a plant, as evidenced by Soliman et al., (US US10023811B2; see Fig. 2, col. 10, lines 41-54); (iii) a sample system (10, Fig. 1) comprising a sample vessel (18, Fig. 2) fluidly connected to a sample point port (12, Fig. 1) disposed on the flow line (16, Fig. 1); (iv) wherein the sample vessel (18, Fig. 1) comprises, an inlet port (90, Fig. 2; col. 6 line 8) fluidly connected to the sample point port (12, Fig. 1) via an inlet valve (26, Fig. 2), disposed on an inlet flow line (the flow line between the inlet valve 26 and inlet port 90, Fig. 2); (v) a pressure gauge (58, Fig. 2) configured to measure a total vessel pressure (col. 5, line 38), fluidly connected to a pressure release line (a pressure line connected to the popoff valve 56, Fig. 2, col. 5, lines 33-37), wherein the pressure release line is configured to vent a gas from the sample vessel (18, Fig. 2). This pressure gauge (58, Fig. 2) is referred here as “a second pressure gauge” since it measures the pressure of the sample vessel; (vi) an outlet port (outlet tee 20, Fig. 2) fluidly connected to a fluid discharge line (the line between outlet port 20 and outlet valve 66; Fig. 6) via outlet valves (65 and 66, Fig. 6); (vii) a sight glass (21, Fig, 2) configured to permit observation of fluid level outside the vessel that is not integrally formed in a vessel body; and (viii) a valve system comprising a sample flow line (16 through tee connection 12, Fig. 1) and a sample regulator (11. Fig. 1), conduits including tee connection (20, Fig. 6), and associated valves (65, 66 and 68, Fig. 6) that control diversion of fluid from production flow, and subsequently discharge collected fluid (col. 5, lines 39-48). The tee connection (20, Fig. 6) provides a fluid communication point on the flow line corresponding to a sample point port (12, Fig. 1) and the valve arrangement (26, 27, Fig. 2) controls fluid diversion into the sampling vessel (18, Fig. 2), corresponding to the limitation “a valve system for redirecting fluid flow from the flow line to the sample vessel via the sample point port”. But Hogue does not explicitly disclose a temperature gauge configured to measure a temperature of fluid received from the sample point port and a first pressure gauge configured to measure a pressure of fluid received from the sample point port. However, Marshall teaches an oil well production analyzing system including a sampling vessel/cylinder with instrumentation for measuring fluid properties (Abstract). Marshall discloses: (i) a production well where fluid produced from an oil well and delivered to a sampling system (i.e., flow-line) within a production environment (col. 4, lines 44-49); (ii) a temperature gauge configured to measure a temperature of fluid received from the sample point port, referred as sample inlet (Fig. 4, col. 7, line 61 thru col. 7, line 4); (iii) pressure sensors associated with sampling cylinder (300, Fig. 1) measuring pressure of produced fluid entering the sampling system (Fig. 4; col. 7, lines 4-6), corresponding to the recited claim, “a first pressure gauge…from the sample point port”. Marshall is an analogous art to Hogue because it is directed to the same field of endeavor, namely sampling and analysis of produced fluids from wells, and addresses the same problem of measuring fluid properties including pressure, temperature and water content. Therefore, before the effective filing date of the claimed invention, it would have been prima facie obvious to one ordinary skill in the art to incorporate a temperature gauge configured to measure a temperature of fluid received from the sample point port and an additional pressure gauge configured to measure a pressure of fluid received from the sample point port as taught by Marshall in the Hogue system to improve monitoring of fluid conditions during sampling, since providing temperature and multiple pressure measurements at different locations in a fluid sampling system are useful for improving accuracy of fluid characterization within the sample vessel, and that pressure, temperature and fluid composition measurements are useful for determining production parameters including oil rate and water rate (Marshall; Fig. 1 and Fig.4; col. 6, line 59 thru col. 7 line 13). But, Hogue, in view of Marshall, does not explicitly disclose a sight glass comprising a calibrated volume scale and that is integrally formed in a vessel body. However, Thomas teaches a device for detecting water in oil, in particular lubricating oil, comprising an optical indicator element (Abstract). Thomas discloses a sight glass (3, Fig. 1) configured for determining water content in lubricating oil using a refractometer ([¶ 0010]) integrally configured in a vessel or housing section (2, Fig. 1; ¶ [0025]). However, Thomas did not explicitly disclose a sight glass that comprises a calibrated volumetric scale in a vessel body. Thomas is an analogous art to Hogue and Marshall because it relates to measurement of liquid content in fluid-containing vessels, which is directly relevant to determining fluid measurement in a sampling vessel used to evaluate fluid flow characteristics. Therefore, before the effective filing date of the claimed invention, it would have been prima facie obvious to one of ordinary skill in the art to configure the sight glass (21, Fig. 2) of Hogue as integrated with the vessel body (3, Fig. 1) as taught by Thomas and include volumetric calibration markings to enable quantitative determination of collected fluid volume, since sight glasses are commonly used to visually determine liquid level in vessels, and providing calibration indicia represents a predictable modification yielding improved measurement accuracy of fluid volumetric measurements. See MPEP 2144.04(IV). In regard to claims 2, 3, and 4, Hogue teaches a sampling system connected to a production flow line including diversion of fluid flow line (12, Fig. 1) via sample regulator (11, Fig. 1) into sample vessel (18, Fig. 1). The reference further teaches use of valves (27, 47 and 65, Fig 2 and Fig. 6) and inlet conduit (90, Fig. 2) for directing fluid flow within the sampling system. Marshall discloses sampling systems implemented within production flow environments, including sampling cylinder (300, Fig. 1) receiving fluid from a production stream (Fig. 3, col. 6, lines 12-23) and measurement of fluid characteristics such as pressure, temperature and water content (Fig. 4; col. 6, line 64 thru col. 7, line 13), demonstrating that sampling may be performed at different locations or under different flow conditions within the production system. In light of teachings from Hogue, in view of Marshall, it would have been obvious to one of ordinary skill in the art to provide multiple sample vessels and corresponding sample point ports along the flow line (claim 2) and to position such sample points upstream and downstream of a choke valve (claim 3) or upstream thereof (claim 4) in order to monitor changes in fluid properties across flow restrictions such as a choke, since pressure drop and phase behavior across restrictions are known to affect fluid characteristics in oilfield production systems as taught by Marshall (col. 2, lines 21-25; col. 4, lines 2-20). In regard to claims 5 and 6, Hogue discloses a pressure-containing sample vessel (18, Fig. 2) used in oil production environment., including pressure gauge (58, Fig. 2) configured to measure pressure and popoff valve (56, Fig. 2), configured to relieve pressure (Fig. 2, col. 5, lines 33-37), thereby demonstrating that the vessel is configured to operate under pressurized conditions typical of production systems. Marshall further discloses a pressurized sampling vessel (300, Fig. 1) operating under production conditions with pressure monitoring (Fig. 4, col. 6, line 61 thru col. 7, line 13), confirming that sampling vessels in production environments are designed to withstand pressures associated with production fluids. But the references do not explicitly disclose maximum pressure rating of 1660 psi (claim 5), a vessel volume in the range of 3-7 gallons (claim 6). However, selection pressure rating and vessel size constitutes routine engineering design consideration based on expected operating pressures, required sample capacity, and compatibility with hydrocarbons and corrosive environments. Such parameters represent result-effective variables that would have been optimized by one of ordinary skill in the art to achieve suitable performance in a sampling vessel used in oilfield production systems. See MPEP 2144.05; MPEP 2144.07 . In regard to claim 7, Marshall discloses that the sampling cylinder may be fabricated from stainless steel (col. 6, 14-16), satisfying the claimed limitation. Claims 8-20 are rejected under 35 USC 103 as being unpatented over Hogue in view of Marshall, and Thomas. In regard to claim 8, Hogue teaches a method oil sampling that obtains and stores a representative sample of crude oil as the oil flows from a stock tank into a sales line (Abstract). Hogue discloses a method comprising: (i) producing fluid from a production well and transporting produced fluid through a petroleum production flow line (16, Fig. 1) and diverting produced fluid towards an oil meter (17, Fig. 1) then to the sales line (17’. Fig. 1), which implies fluid went through an oil separation process through a gas-oil separation process in a plant, as evidenced by Soliman et al., (US 10,023,811 B2; see Fig. 2, col. 10, lines 41-54), corresponding to “producing fluid from the production well and transporting produced fluid to a processing system”. (ii) measuring a flow rate of produced fluid within the sample vessel (18, Fig. 2) evaluating characteristics of the produced fluid including sediment and water content (col. 3, lines 35-37), corresponding to “quantifying water content of produced fluid”. But, Hogue does not explicitly disclose adjusting an operating condition of the gas-oil separation plant based upon the measured flow rate and water content. However, Marshall teaches systems and methods for analyzing produced fluids from oil and gas wells using sampling vessels and instrumentation to determine production characteristics (Abstract). Marshall discloses determining production parameters including daily oil rate and water rate from produced fluid samples using sampling cylinder (300, Fig. 1), temperature probe (332, Fig. 3), and associated pressure instrumentation (col. 7, lines 4-6), corresponding to measuring flow rate of produced fluid and quantifying water content of produced fluid. Marshall is analogous to Hogue because both references relate to sampling produced fluids in petroleum production systems to determine fluid characteristics including oil rate and water rate content. Therefore, before the effective filing date of the claimed invention, it would have been prima facie obvious to one of ordinary skill in the art to adjust the operating condition such as the sampling and volume of fluid tested (Marshall: col. 7, lines 22-25) based upon the measured flow rate and water content in the Hogue system using the analytical techniques (Fig. 1, col. 4 lines 37-62) by Marshall through a processor receiving data from gas meter, water cut, or gas analyzer via data received from a gas analyzer (Marshall: col. 7, lines 25-26), to adjust sampling frequency to ascertain flow rates and downhole flowing pressure (Marshall: col. 4, lines 10-20) In regard to claim 9, Hogue discloses collecting produced fluid samples from a flow line (16, Fig. 1) using sample regulator 11, via sample flow line (12, Fig. 1) directing fluid into sample vessel 18 (through tee 12, Fig. 1-3; col. 3-4) and performing analysis of collected fluid (from sample spout 70 for obtaining a sample, Fig. 6) including determination of fluid parameters such as sediment and water content (col. 6, line 43-45), wherein produced fluid comprises a mixture of oil and water, thereby making claim 9 obvious. See MPEP 2112 . In regard to claim 10, Hogue discloses method of claim 8 comprising: (i) operating valves of a sampling system to direct fluid from flow line (16 through 12, Fig. 1) into sample vessel (18, Fig. 2) via a regulator (11, Fig. 1) and associated valve arrangements including inlet valves (27, 26, Fig. 2) and inlet port (90, Fig. 2), corresponding to the claimed limitation “operating valves of the valve system to direct total fluid flow from the flow line into the sample vessel”. (ii) collecting produced fluid characteristics including sediment and water content (col. 6, lines 43-45), corresponding to the claimed limitation “collecting a volume of produced fluid within the sample vessel”. (iii) a finite sampling interval (col. 4, lines 22-28) in which fluid is diverted into the vessel and subsequently isolated by operation of valves (26, 27, Fig. 2) corresponding to the limitation “operating valves of the valve system, to stop fluid flow into the sample vessel”. But Hogue does not explicitly disclose “recording at start time” and “recording an end time” for the sampling interval. Marshall teaches determining production parameters including oil rate and water rate from produced fluid samples obtained from a production of flow stream (col. 4 lines 37-50), which requires measurement of sampling duration and collected fluid quantity in order to determine flow characteristics. It would have been obvious to record a start time and end time corresponding to the sampling interval of Hogue system in order to determine volumetric flow characteristics of produced fluid as taught by Marshall, since determining flow rate from measured volume and elapsed time allows real-time determination of density of produced fluid and in determining production of rate of such fluids (Marshall, col.1, lines 20-24). (iv) measuring volume of produced fluid level using sight glass (Hogue; 21, Fig. 2) associated with sample vessel (18, Fig. 2), corresponding to visual determination of collected fluid level. But, Hogue does not explicitly disclose that the sight glass comprises a “calibrated volumetric scale” enabling quantitative determination of collected fluid volume. Thomas discloses a viewing window integrated into a fluid-containing vessel wall enabling observation of fluid condition inside the container (sight glass, 3, Fig. 1). Because observable fluid level within a vessel corresponds to contained fluid volume, it would have been obvious to provide volumetric calibration indicia associated with the sight glass (21, Fig. 2) of Hogue in order to enable quantitative determination of collected fluid volume for calculating production flow characteristics, representing routine adaptation of visual level indicators yielding predictable results. (v) emptying the volume of collected fluid from the sample vessel through outlet valves including valves (66 and 68, Fig. 6) connected to outlet conduits (outlet tee, 20, Fig. 2), corresponding to the limitation, “emptying the volume…of the sample vessel”. In regards to claim 11, Hogue discloses produced fluid in sample vessel (18, Fig. 2) and observing phase separation of sediment and water within the collected fluid sample (col. 3, lines 26-38), corresponding to determining phase of produced fluid including water content. Hogue further discloses: (i) determining fluid level via sight glass (Hogue, 21, Fig. 2), corresponding to determining relative quantities of separated fluid phases within the collected sample. Hogue disclose calculating volume percent of basic sediment and water (BS&W) (col. 1, lines 49-53) but not using a calibrated volumetric scale on the sight glass. It would have been prima facie obvious to one of ordinary skill in the art to configure the sight glass (21, Fig. 2) of Hogue as integrated with the vessel body (3, Fig. 1) as taught by Thomas and include volumetric calibration markings to enable quantitative determination of calculating volume percent of basic sediment and water (BS&W), in order to insure that the true representative samples of the total months production is analyzed (Hogue, col. 1, lines 62-67). In regard to claim 12, 13 and 14, although the prior art references (i.e., Hogue in view of Marshall, and in further view of Thomas) do not explicitly disclose applying conversion factors to determine volumetric flow rate at as-produced conditions (claim 12), calculating temperature-corrected volume of produced fluid at standard temperature (claim 13), or calculating pressure- and temperature-corrected volume at standard pressure (claim 14), applying conversion factors and thermodynamics relationships to normalize measured fluid volume based on pressure and temperature represents routine mathematical manipulation of measured variables used in petroleum production analysis, yielding predictable results, thereby render claims 12, 13, and 14 obvious. S ee MPEP 2144.03; MPEP 2144.05. In regard to claim 15, Hogue discloses collecting produced fluid within sample vessel (18, Fig. 2) from production flow line (16, Fig. 1) and observing separation sediment and water within the collected fluid sample (Abstract), corresponding to determining phase distribution of produce fluid. Marshall discloses oil rate and water rate fluid samples using properties including pressure and temperature (Fig. 4, col. 6, line 59 thru col. 7, line 6), corresponding to calculating flow rates of oil and water from sampled produced fluid. Although the references do not explicitly disclose calculating flow rates at standard conditions, calculating flow rates of produced fluid phases based on normalized volume at standard pressure and temperature represents routine mathematical manipulation of measured fluid properties yielding predictable results, thereby render claim 15 obvious. S ee MPEP 2144.04 In regard to claim 16, Hogue discloses transporting produced fluid through flow line (16 Fig. 1) within a petroleum production system and directing produced fluid from the production well (14, Fig. 1) towards an oil meter (17, Fig. 1) then to the sales line (17’. Fig. 1), which implies fluid went through an oil separation process through a gas-oil separation process in a plant, as evidenced by Soliman et al., (US US10023811B2; see Fig. 2, col. 10, lines 41-54). In regard to 17, Hogue discloses redirecting produced fluid using a flow line (16, Fig. 1) via a sample point port (12, Fig. 1) and a sample regulator (11, Fig. 1) and associated valves (26 and 27, Fig 2), corresponding to redirecting fluid flow to sample system using a valve system and collecting a sample of produced fluid using a sample vessel. Hogue further discloses: (i) an inlet port (90, Fig. 2) fluidly connected to the fluid flow line (16, Fig. 1) via regulator (11, Fig. 1) and associated conduits (26 and 27, Fig. 2); (ii) a pressure measurement device including pressure gauge (58, Fig. 2) configured to measure a total vessel pressure (col. 5, line 38), fluidly connected to a pressure release line (a pressure line connected to the popoff valve 56, Fig. 2, col. 5, lines 33-37), wherein the pressure release line is configured to vent a gas from the sample vessel (18, Fig. 2). This pressure gauge is referred here as “a second pressure gauge” (58, Fig. 2), since it measures the pressure of the sample vessel. (iii) an outlet port (outlet tee 20, Fig. 2) fluidly connected to a fluid discharge line (the line between outlet port 20 and outlet valve 66; Fig. 6) via outlet valves (65 and 66, Fig. 6); (iv) a sight glass (21, Fig, 2) configured to permit observation of fluid level outside the vessel but is not integrally formed in a vessel body. With respect to the recited limitation, “a first pressure gauge configured to measure a pressure of fluid received from the sample point port”, Marshall discloses measuring temperature and pressure of produced fluid using temperature probe (332, Fig. 3) and associated pressure sensors (Fig. 4; col. 7, lines 4-6) within the sampling cylinder (300, Fig. 1) receiving produced fluid from a production flow stream (Fig.1, col. 4, lines 37-50), corresponding to measuring temperature and pressure of fluid received from the flow line. It would have been obvious to include temperature measurement and additional pressure measurement instrumentation in the Hogue sampling system (Fig. 2) in order to improve characterization of produced fluid properties, since providing multiple measurement devices in fluid sampling system represents routine instrumentation practice yielding predictable results. See MPEP 2143(I)(B); MPEP 2144.04(IV) . With respect to the recited limitation, “a sight glass comprising a calibrated volumetric scale, wherein the sight glass is integrally formed in a vessel body”, Thomas discloses a sight glass (3, Fig. 1) configured for determining water content in lubricating oil using a refractometer ([¶ 0010]) integrally configured in a vessel or housing section (2, Fig. 1; ¶ [0025]). However, Thomas did not explicitly disclose a sight glass that comprises a calibrated volumetric scale in a vessel body. It would have been obvious to one of ordinary skill in the art to configure the sight glass (21, Fig. 2) of Hogue as integrated with the vessel body (3, Fig. 1) as taught by Thomas and include volumetric calibration markings to enable quantitative determination of collected fluid volume, since sight glasses are commonly used to visually determine liquid level in vessels, and providing calibration indicia represents a predictable modification yielding improved measurement accuracy of fluid volumetric measurements. See MPEP 2144.04(IV). In regard to claim 18, Hogue discloses redirecting produced fluid to second sample system through a sample flow line (16 through tee connection 12, Fig. 1) via sample point port and a sample regulator (11. Fig. 1), conduits including an outlet tee connection (20, Fig. 6), and associated valves (65, 66 and 68, Fig. 6), corresponding to redirecting fluid flow to a sample system using a valve system. But Hogue does not explicitly disclose a “second sample system” disposed at a second sample point port along the flow line. Marshall discloses obtaining produced fluid samples and determining production parameters including oil rate and water rate (Fig. 4, col. 6 lines 65-67), corresponding to “evaluating fluid characteristics from sample produced fluid”. It would have been obvious to provide a second sample vessel at a second sample point port along the flow line in the Hogue sample system (Fig. 1) in order to obtain additional fluid samples at different points within the production flow system to improve characterization of produced fluid properties, since collecting samples at multiple locations along a process stream represents a known technique improving accuracy and reliability of process measurements yielding predictable results, thereby render claim 18 obvious. See MPEP 2144.04(VI); MPEP 2143(I)(C). In regard to claim 19, although the prior art references (Hogue in view of Marshall and in further view of Thomas) do not explicitly disclose calculating an average volumetric flow rate between two sampling locations, calculating an average value based on multiple measured flow values obtained from different sample locations represents routine mathematical analysis used to improve accuracy and reliability of production measurements. Averaging measured flow values from multiple sampling points along a flow line yield predictable results, thereby render claim 19 obvious. See MPEP 2144.03. In regard to claim 20, in light of the teachings of Hogue and Marshall and as previously discussed with respect to 8, it would have been obvious to adjust operating conditions of downstream gas-oil separation equipment including flow rates, a chemical injection rate, a separator vessel pressure level, a gas compression ratio, a settling time, a pH level, a concentration of emulsion breaker, a heat exchanger temperature, a level control, a flow path routing, a sampling frequency, an equipment maintenance schedule, a gas composition, a water disposal plan, and a water treatment plan, based on measured flow rate and water content in order to improve separation efficiency and production performance because measured production parameters such as oil rate, water rate, pressure and temperature are commonly used to evaluate and optimize performance of petroleum production and gas-oil separation systems. Furthermore, Marshall disclosed that through a processor receiving data from gas meter, water cut, or gas analyzer, sampling frequency can be adjusted to ascertain flow rates and downhole flowing pressure (Marshall: col. 7, lines 20-25). So, adjusting process parameters in gas-oil separation plant based on measured fluid characteristics represents routine process optimization yielding predictable results. See MPEP 2143(I)(B); MPEP 2144 . Conclusion Any inquiry concerning this communication or earlier communication from the examiner Any inquiry concerning this communication or earlier communication from the examiner should be directed to Wilson Mendoza whose telephone number is (571) 272-8443. The examiner can normally be reached on Monday – Friday from 9:00 AM until 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, an applicant is encouraged to use the USPTO Automated Interview request at http://www.uspto.gov.intwerviewpractice . If attempts to reach the examiner by telephone are unsuccessful, the examiner’s supervisor, In Suk Bullock can be reached on 571-272-5954. The fax phone number for the organization where this application or processing is assigned is 571-273-8300. If attempts to reach the examiner by telephone are unsuccessful, the examiner’s supervisor, In Suk Bullock can be reached on 571-272-5954. The fax phone number for the organization where this application or processing is assigned is 571-273-8300. Information regarding the status of an application may be obtained from the Patent Application Information Retrieval (PAIR) system. Status information for published applications may be obtained from either Private PAIR or Public PAIR. Status information for unpublished applications is available through private PAIR only. For more information about PAIR system, see http://pair-direct.uspto.gov. Should you have any questions on access to the private PAIR system, contact the Electronic Business Center (EBC) at 866-217-9197 (toll-free). If you would like assistance from a USPTO Customer Serv ice Representative or access to the automated information system, call 800-786-9199 (IN USA OR CANADA) or 571-272-1000. /WILSON GALLARDO MENDOZA/Examiner, Art Unit 1772 /YOUNGSUL JEONG/Primary Examiner, Art Unit 1772 Application/Control Number: 18/424,475 Page 2 Art Unit: 1772 Application/Control Number: 18/424,475 Page 3 Art Unit: 1772 Application/Control Number: 18/424,475 Page 4 Art Unit: 1772 Application/Control Number: 18/424,475 Page 5 Art Unit: 1772 Application/Control Number: 18/424,475 Page 6 Art Unit: 1772 Application/Control Number: 18/424,475 Page 7 Art Unit: 1772 Application/Control Number: 18/424,475 Page 8 Art Unit: 1772 Application/Control Number: 18/424,475 Page 9 Art Unit: 1772 Application/Control Number: 18/424,475 Page 10 Art Unit: 1772 Application/Control Number: 18/424,475 Page 11 Art Unit: 1772 Application/Control Number: 18/424,475 Page 12 Art Unit: 1772 Application/Control Number: 18/424,475 Page 13 Art Unit: 1772 Application/Control Number: 18/424,475 Page 14 Art Unit: 1772 Application/Control Number: 18/424,475 Page 15 Art Unit: 1772 Application/Control Number: 18/424,475 Page 16 Art Unit: 1772 Application/Control Number: 18/424,475 Page 17 Art Unit: 1772 Application/Control Number: 18/424,475 Page 18 Art Unit: 1772
Prosecution Insights