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 .
This is a response to Applicant's amendment filed on June 30, 2026.
Status of Claims
Claims 1 has been amended. No new claim has been added. Claims 1-20 are pending. Claims 1-20 are examined herein.
Response to Amendments
The Amendments to the Claims filed 04/20/2026 have been entered. The previous 35 U.S.C. 112(b) or 35 U.S.C. 112 (pre-AIA ), second paragraph rejections of claims 1-20 are withdrawn in view of the Applicant's amendments and arguments.
Response to Arguments
Applicant's Remarks/Arguments and Amendments to the Claims both filed 06/30/2026 have been fully considered. It is noted that claim 1, an independent claim from which all dependent claims depend, has been amended to recite “for measuring a volume of fluid and a basic sediment and water content” in the context of a method of measuring a fluid flow rate from a well as claimed.
Applicant argues that the claim 1 as amended and its dependent claims are not anticipated nor prima facie obvious over cited prior art(s), Hogue (US 4,720,998), Marshall (US 9,334,728 B2), and Thomas (DE 10,2018,218,890 A1) since the cited references do not teach the sight glass integrally formed in the sample-vessel body, the amended calibrated volumetric BS&W measurement feature, that Thomas concerns continuously flowing lubricating oil, that the proposed combination is based on hindsight and non-analogous teachings, and that Marshall does not disclose the claimed pressure gauge, in the context of a method of measuring a fluid flow rate from a well, “for measuring a volume of fluid and a basic sediment and water content”. See Remarks, pages 9-13.
Applicants argues that the Thomas does not teach sight glass integrally formed in the sample-vessel body and therefore does not cure the deficiency of Hogue. See Remarks, page 8 paragraph 3 thru p. 9, paragraph 2.
In response, the examiner respectfully disagrees. The rejection does not rely on Thomas alone. Hogue teaches sample vessel 18 and sight glass 21 for observing the retained petroleum sample, while Thomas teaches a transparent sight-glass section incorporated into a fluid-containing housing. It would have been obvious to incorporate Thomas’s sight-glass construction into Hogue’s sample-vessel body because doing so predictably provides direct observation through the vessel body while reducing external fluid connections and potential leakage paths. The references must be considered for their combined teachings, and bodily incorporation of Thomas’s entire apparatus is not required. See MPEP 2143 and 2145.
Applicants argues that the cited references do not teach “a sight glass comprising a calibrated volumetric scale for measuring a volume of fluid and a basic sediment and water content.” See Remarks, pp. 10-11, paragraph 1.
In response, the argument has been considered. The limitation was newly added by amendment. Gillingham is therefore additionally applied and teaches a transparent crude-oil sample-measurement container having volumetric indicia for quantitatively determining sample volume and separated basic sediment and water (BS&W) volume. It would have been obvious to provide the Hogue-Thomas sight glass with Gillingham’s volumetric indicia because doing so predictably permits quantitative visual measurement of fluid volume and BS&W content using known measurement features according to their established function. See MPEP 2141 and 2143.
Regarding the newly amended limitation, the applicants’ arguments direct a newly amended claim limitation which is a new issue. Therefore, the arguments are considered moot. Applicant's amendment necessitated a modified/new ground(s) of rejection presented in this Office action.
Applicants argues that Thomas concerns continuously flowing lubricating oil rather than a retained well-fluid sample and therefore is inapplicable to the claimed system. See Remarks, p. 11, paragraph 1.
In response, the examiner respectfully disagrees. Thomas is relied upon for its relevant sight-glass construction, not for bodily incorporation of its complete continuous-flow system into Hogue. Hogue remains the base petroleum-sampling system. The fact that Thomas employs the relevant structure in a different embodiment does not negate what that structure would have taught one of ordinary skill in the art. See MPEP 2145.
Applicants argues that there is no motivation to combine Hogue, Marshall, and Thomas and that the rejection is based on hindsight. See Remarks, p. 11, paragraph 2.
In response, the examiner respectfully disagrees. The rejection provides an articulated technical reason for each modification: Marshall’s instrumentation improves characterization of sampled fluid, and Thomas’s integrated viewing structure permits direct vessel observation while reducing external connections. Gillingham (US 2020/0048564 A1) is additionally applied in response to the amendment because its volumetric indicia provide quantitative fluid-volume and BS&W measurement. Each modification uses known components for its established functions and yield predictable results; therefore, the rationale is derived from the prior art and technical problem rather than Applicant’s disclosure. See MPEP 2141, 2143; KSR Int’l Co.v. Teleflex Inc., 550 U.S. 398, 417-18(2007).
Applicants argues that Thomas is non-analogous art because it concerns lubricant monitoring rather than well-fluid sampling. See Remarks, p. 12, paragraph 1.
In response, the examiner respectfully disagrees. Thomas is at least reasonably pertinent to the particular problem for which it is relied upon-providing a transparent viewing structure in a fluid-containing body for observation of contained fluid. Hogue, Marshall, Thomas and Gillingham concern fluid-containing systems and structure for sampling, observing, or measuring fluid characteristics. Thus, their teachings would reasonably have commended themselves to one of ordinary skill in the art addressing vessel-based fluid observation and measurement. See MPEP 2141.01(a).
Applicants argues that Marshall does not teach the claimed first pressure gauge configured to measure pressure of fluid received from the sample-point port. See Remarks, pp. 12-13, paragraph 2.
In response, the examiner respectfully disagrees. Marshall teaches pressure measurement of fluid received by its sampling arrangement, and the claim does not require the first pressure gauge to be positioned at the sample-point port or upstream of the sample vessel. When considered with Hogue’s sample-point and vessel arrangement, Marshall teaches the claimed measurement of pressure of fluid received from the sample point. Applicant’s argument therefore relies on a narrower construction not required by the claim language. See MPEP 2111 and 2145.
Upon further consideration and search, a modified/new ground of rejections to claims 1- 20 are presented, in view of the previously presented prior art(s), Hogue (US 4,720,998), Marshall (US 9,334,728 B2), and Thomas (DE 10,2018,218,890 A1), together with newly applied reference, Gillingham (US 2020/0048564 A1), as presented in the instant Office action.
MODIFIED REJECTIONS
Claim Rejections - 35 USC § 103
The following is a quotation of 35 U.S.C. 103 which forms the basis for all obviousness rejections set forth in this Office action:
A patent for a claimed invention may not be obtained, notwithstanding that the claimed invention is not identically disclosed as set forth in section 102, if the differences between the claimed invention and the prior art are such that the claimed invention as a whole would have been obvious before the effective filing date of the claimed invention to a person having ordinary skill in the art to which the claimed invention pertains. Patentability shall not be negated by the manner in which the invention was made.
The factual inquiries 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”), and further in view of Gillingham (US 2020/0048564 A1, hereinafter as “Gillingham’).
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.
However, Gillingham teaches a method for separating basic-sediment and water (BS & W) from oil in an oil field crude oil sample using a halogen lighting unit and a sample measurement container (Abstract). Gillingham discloses a transparent material (i.e., glass) having calibrated volumetric indicia for quantitatively determining total sample volume and separated basic sediment and water (BS&W) volume (¶¶ [0015, 0021]).
Hogue, Marshall, Thomas and Gillingham are analogous arts because each is reasonably pertinent to the problem of sampling, observing, and quantitatively measuring fluids within a vessel-based system using know-fluid containment.
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 incorporate Thomas’s integrated sight glass construction into Hogue’s sample-vessel body w because doing so would permit direct observation of the retained sample vessel through the vessel wall (Thomas: ¶ ([0008, 0013]); it would have been further obvious to provide the integrated sight glass of the Hogue-Marshall- Thomas combined system with Gillingham’s volumetric indicia because a transparent graduated crude oil sample container permits quantitative measurement of total sample volume and separated BS&W volume (Gillingham: ¶¶ [0005-0006] ). See MPEP 2141 and 2143.
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. See 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. See 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
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 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
Prosecution Insights