DETAILED ACTIONS
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 .
Information Disclosure Statement
The information disclosure statements (IDS) submitted on 08/15/2023. The submission is in compliance with the provisions of 37 CFR 1.97. Accordingly, the information disclosure statements are being considered by the examiner.
Claim Rejections - 35 USC § 102
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 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 the appropriate paragraphs of 35 U.S.C. 102 that form the basis for the rejections under this section made in this Office action:
A person shall be entitled to a patent unless –
(a)(1) the claimed invention was patented, described in a printed publication, or in public use, on sale, or otherwise available to the public before the effective filing date of the claimed invention.
Claims 1-2,7-16, and 20 are rejected under 35 U.S.C. 102(a)(1) as being anticipated by Manzar et al. (US 2016/0130935 A1, hereinafter Manzar, IDS ref).
Regarding Claim 1, Manzar teaches,
A system for measuring mass flow rate in a downhole pipe of a lateral section of a well, the system (Manzar, Figure 2, Logging tool 10, wellbore 12, subterranean formation 14, [0008] “disclosed herein is an example method of estimating a flow of fluid within a wellbore”) comprising:
a mobile vessel configured (Manzar, Figure 2, upper portion 22) for submersion (Manzar, Figure 1, [0022], ‘disposed in a well bore 12”) into a fluid mixture of (Manzar, Figure 1, [0022], “wellbore 12 intersects a subterranean formation 14”) the downhole pipe (Manzar, Figure 1, [0022] “wellbore 12. Body 20 is bisected into an upper portion 22 and lower portion 24 that are coupled together via an elongated and axial connector rod 26”);
attached to the mobile vessel the flow velocity sensor (Manzar, Figure 3, Flow meter 36 [0024]) configured to rotate about a longitudinal center axis of the mobile vessel for placement according to a plurality of discrete angular positions of a velocity sensing region of the flow velocity sensor (Manzar, Figure1-3, [0024] FIG. 3; A rotational meter 44 is shown in dashed outline embedded in a body 45 of the flow meter 36, and which may detect the rotational speed or frequency of spinner member 38.”)
a composition sensor (Manzar, Figure 3-4, 52,53,54) attached to the mobile vessel (Figure 2, 22),
the composition sensor configured to rotate about the longitudinal center axis of the mobile vessel for placement according to a plurality of discrete angular positions of a composition sensing region of the composition sensor (Manzar, Figure 3-4, [0025], additional sensors that are included with the sensor module 32. More specifically, further included in in module 32 are an optical sensor 52 (FIG. 3), with attached optical sensor line 53, and conductivity sensor 54” NOTE: 52,53,54 sensors are used to identify types of hydrocarbons/ compositions of hydrocarbon are attached with sensor module of flow meter 36 with a spinner 38. A hall sensor 50 and magnet 49 is attached with the spinner 38 for detecting position. See [0024]); and
processing means (Manzar, Figure 1, [0022], Communication from the sensor module 32 may be provided through line 46 to a controller 47 (FIG.1)) configured to use a plurality of time-series measurements of velocity and composition of the fluid mixture sensed at the plurality of discrete angular positions of the velocity and composition sensing regions to determine a total cross-sectional area and flow velocity of each of a plurality of fluid components of the fluid mixture. (Manzar, Figures 1-2, [0026], “Signals which may be transmitted to controller 47 (FIG. 1) can be analyzed to estimate axial location of the end of arm 30 and further thereby estimating location of the mid-portion M of arm 30, to thereby provide an estimate of the location of sensor modules 321, 322 (FIG. 2) and their relative distances
from axis Ax. Thus, sensing the flow rate of any fluid flowing past tool 10 as well as the different phases of fluid at the differential spatial locations of sensor modules 321, 322 may provide full information about the cross-section of the entire amount of fluid flowing through wellbore 12”).
Regarding Claim 2, Manzar teaches the system according to claim 1,
Manzar further teaches wherein: the plurality of time-series measurements of the velocity are time-correlated with the plurality of time-series measurements of the composition (Manzar, Figures 1-2, [0026], “Signals which may be transmitted to controller 47 (FIG. 1) can be analyzed to estimate axial location of the end of arm 30 and further thereby estimating location of the mid-portion M of arm 30, to thereby provide an estimate of the location of sensor modules 321, 322 (FIG. 2) and their relative distances from axis Ax. Thus, sensing the flow rate of any fluid flowing past tool 10 as well as the different phases of fluid at the differential spatial locations of sensor modules 321, 322 may provide full information about the cross-section of the entire amount of fluid flowing through wellbore 12” NOTE: Manzar teaches the measurement of composition at different levels and as well as measuring the flow rate at the respective levels, therefore there is a correlations of measurement signals between the composition and flow rate. See [0025], Knowing the sections of the cross-sectional stream of fluid that are made up of the different phases necessarily results in a more accurate estimate of the rate of fluid flowing through well bore 12. Further shown in FIG. 4,). It is also known in the art that sensor signals are measured over a time interval. Signals were collected during lowering or raising of the tool see [0032], “sensing can occur when raising or lowering the tool 10 in the wellbore 12”).
Regarding Claim 7, Manzar teaches the system according to claim 1,
Manzar further teaches wherein: the processing means is further configured to use geometry parameters that define portions of the composition and flow velocity sensors that interact with the fluid mixture to determine the flow velocity of each of the plurality of fluid components of the fluid mixture. (Manzar, [0023] FIG. 2 shows in a side view a detailed example of a sensor assembly 28 of FIG. 1. In this embodiment, sensor
assembly 28 includes a pair of sensor modules 32 1, 322, each mounted on an elongate and flexible sensor arm 30. In this example, one end of sensor arm 30 pivotingly couples to an upper portion 22 of body 20. Thus, when tool 10 is disposed in a wellbore having diameters that vary in size, the arm 30
may flex radially inward or outwardly depending on the specific dimensions of the well bore, and outer diameter of the mid-section M of the sensor arms 30”).
Regarding Claim 8, Manzar teaches the system according to claim 7,
Manzar further teaches wherein: the geometry parameters include geometries of respective protrusions of the flow velocity and sensors into the flow, including height and/or diameter of the respective protrusions, and/or relative distance between the respective protrusions. (Manzar, Figure 2, 4, [0023], when tool 10 is disposed in a wellbore having diameters that vary in size, the arm 30 may flex radially inward or outwardly depending on the specific dimensions of the well bore, and outer diameter of the mid-section M of the sensor arms 30.Anoptional linkage arm 34 is shown having one end pivotingly connected to a portion of upper portion 22, and an opposite end pivotingly connected to a body portion of sensor module 321 . Strategically positioning the elongate linkage arm 34, in combination with its pivoting com1ection to the upper portion 22 and sensor module 321, provides a support for sensor module 321 “).
Regarding Claim 9, Manzar teaches the system according to claim 1,
Manzar further teaches wherein: the plurality of discrete angular positions of the velocity sensing region are offset from the plurality of discrete angular positions of the composition sensing region. (Manzar, Figure 3, [0024], In an example, magnets 49 are provided at the same axial in the spinner member 38, but on opposite lateral edges. By alternating the polarity of the magnets 49 at the opposite lateral
edges, each rotation of the spinner member 38 can be detected by the Hall effect sensors 50. In an alternate example, the magnets 49 are spaced axially along the curved lateral edges at distances so that when viewed axially, adjacent magnets 49 are disposed 60° from one another”).
Regarding Claim 10, Manzar teaches the system according to claim 1,
Manzar further teaches wherein: the mobile vessel (Manzar, Figure 1, 2, upper portion 22) comprises a first element having a substantially tubular shape about the longitudinal center axis (Manzar, [0022], illustrated example, lower portions 22, 24 are generally cylindrical elongate members and each have an outer diameter that
is greater than an outer diameter of connector rod 26), the first element configured to rotate about the longitudinal center axis, and each sensor of the flow velocity and composition sensors include an enclosure or a mast that protrude from the first element. Manzar, Figure 1, [0022] “wellbore 12. Body 20 is bisected into an upper portion 22 and lower portion 24 that are coupled together via an elongated and axial connector rod 26”);
Regarding Claim 11, Manzar teaches the system according to claim 10,
Manzar further teaches wherein: the enclosure or mast include a cylindrical shape that is radially attached to the first element (Manzar, Figure 2, elongated shape upper portion 22.[0023], one end of sensor arm 30 pivotingly couples to an upper portion 22 of body 20. Thus, when tool 10 is disposed in a wellbore having diameters that vary in size, the arm 30 may flex radially inward or outwardly depending on the specific dimensions of the well bore, and outer diameter of the mid-section M of the sensor arms 30”).
Regarding Claim 12, Manzar teaches the system according to claim 1, Manzar further teaches wherein: the fluid mixture comprises gas, oil and water (Manzar, [0025], “identifying the phase (i.e. gas, vapor, liquid, or combinations thereof) and/or type of fluid flowing through wellbore 12”).
Regarding Claim 13, Manzar teaches the system according to claim 1, Manzar further teaches wherein: the processing means includes a first processing means internal to the mobile vessel, and a second processing means external to the mobile vessel. (Manzar, Figure 1, [0022], Communication from the sensor module 32 may be provided through line 46 to a controller 47 (FIG.1))
Regarding Claim 14, Manzar teaches the system according to claim 13, Manzar further teaches wherein: wherein: the first processing means(Manzar, Figure 1, [0022], Communication from the sensor module 32 may be provided through line 46 to a controller 47 (FIG.1))includes storage means to store data corresponding to the plurality of time-series measurements, and the second processing means includes means to determine the total cross-sectional area and flow velocity of each of a plurality of fluid components of the fluid mixture based on the stored data. (Manzar, Figures 1-2, [0026], “Signals which may be transmitted to controller 47 (FIG. 1) can be analyzed to estimate axial location of the end of arm 30 and further thereby estimating location of the mid-portion M of arm 30, to thereby provide an estimate of the location of sensor modules 321, 322 (FIG. 2) and their relative distances
from axis Ax. Thus, sensing the flow rate of any fluid flowing past tool 10 as well as the different phases of fluid at the differential spatial locations of sensor modules 321, 322 may provide full information about the cross-section of the entire amount of fluid flowing through wellbore 12”).
Regarding Claim 15, Manzar teaches,
A system for measuring mass flow rate of a fluid mixture (Manzar, [0002] “The present disclosure relates in general to monitoring flow in a well bore, and more specifically to sensing fluid flow at discrete and known locations in the wellbore” NOTE: this system can be modified and apply in other fluid flow measurement system)., the system comprising: a submersion vessel configured for submersion into the fluid mixture;
a flow velocity sensor (Manzar, Figure 3, Flow meter 36 [0024]) attached to the submersion vessel (Manzar, Figure 2, upper portion 22),
the flow velocity sensor configured to rotate about a longitudinal center axis of the submersion vessel according to a plurality of discrete angular positions (Manzar, Figure1-3, [0024] FIG. 3; A rotational meter 44 is shown in dashed outline embedded in a body 45 of the flow meter 36, and which may detect the rotational speed or frequency of spinner member 38.”);
a composition sensor (Manzar, Figure 3-4, 52,53,54) attached to the mobile vessel (Figure 2, 22),
the composition sensor configured to rotate about the longitudinal center axis of the mobile vessel for placement according to a plurality of discrete angular positions of a composition sensing region of the composition sensor (Manzar, Figure 3-4, [0025], additional sensors that are included with the sensor module 32. More specifically, further included in in module 32 are an optical sensor 52 (FIG. 3), with attached optical sensor line 53, and conductivity sensor 54” NOTE: 52,53,54 sensors are used to identify types of hydrocarbons/ compositions of hydrocarbon are attached with sensor module of flow meter 36 with a spinner 38. A hall sensor 50 and magnet 49 is attached with the spinner 38 for detecting position. See [0024]); and
processing means (Manzar, Figure 1, [0022], Communication from the sensor module 32 may be provided through line 46 to a controller 47 (FIG.1)) configured to use a plurality of time-series measurements of velocity and composition of the fluid mixture sensed at the plurality of discrete angular positions of the velocity and composition sensing regions to determine a total cross-sectional area and flow velocity of each of a plurality of fluid components of the fluid mixture. (Manzar, Figures 1-2, [0026], “Signals which may be transmitted to controller 47 (FIG. 1) can be analyzed to estimate axial location of the end of arm 30 and further thereby estimating location of the mid-portion M of arm 30, to thereby provide an estimate of the location of sensor modules 321, 322 (FIG. 2) and their relative distances
from axis Ax. Thus, sensing the flow rate of any fluid flowing past tool 10 as well as the different phases of fluid at the differential spatial locations of sensor modules 321, 322 may provide full information about the cross-section of the entire amount of fluid flowing through wellbore 12”).
Regarding Claim 16, Manzar teaches the system according to claim 15,
Manzar further teaches wherein: the plurality of time-series measurements of the velocity are time-correlated with the plurality of time-series measurements of the composition (Manzar, Figures 1-2, [0026], “Signals which may be transmitted to controller 47 (FIG. 1) can be analyzed to estimate axial location of the end of arm 30 and further thereby estimating location of the mid-portion M of arm 30, to thereby provide an estimate of the location of sensor modules 321, 322 (FIG. 2) and their relative distances from axis Ax. Thus, sensing the flow rate of any fluid flowing past tool 10 as well as the different phases of fluid at the differential spatial locations of sensor modules 321, 322 may provide full information about the cross-section of the entire amount of fluid flowing through wellbore 12” NOTE: Manzar teaches the measurement of composition at different levels and as well as measuring the flow rate at the respective levels, therefore there is a correlations of measurement signals between the composition and flow rate. See [0025], Knowing the sections of the cross-sectional stream of fluid that are made up of the different phases necessarily results in a more accurate estimate of the rate of fluid flowing through well bore 12. Further shown in FIG. 4,). It is also known in the art that sensor signals are measured over a time interval. Signals were collected during lowering or raising of the tool see [0032], “sensing can occur when raising or lowering the tool 10 in the wellbore 12”).
Regarding Claim 20, Manzar teaches,
A method for measuring mass flow rate velocity of a fluid mixture, the method (Manzar, Figure 2, Logging tool 10, wellbore 12, subterranean formation 14, [0008] “disclosed herein is an example method of estimating a flow of fluid within a wellbore”) comprising:
performing a plurality of time-series measurements of velocity and composition of the fluid mixture at a plurality of discrete angular positions relative to a center axis (Manzar, Figure1-3, [0024] FIG. 3; A rotational meter 44 is shown in dashed outline embedded in a body 45 of the flow meter 36, and which may detect the rotational speed or frequency of spinner member 38.”); based on the performing,
obtaining time-correlated measurements of the velocity and composition at each of the discrete angular positions; based on the obtaining, identifying a plurality of fluid components of the fluid mixture; and based on the obtaining and the identifying, determining a total cross-sectional area and flow velocity of each of the plurality of fluid components. (Manzar, Figures 1-2, [0026], “Signals which may be transmitted to controller 47 (FIG. 1) can be analyzed to estimate axial location of the end of arm 30 and further thereby estimating location of the mid-portion M of arm 30, to thereby provide an estimate of the location of sensor modules 321, 322 (FIG. 2) and their relative distances from axis Ax. Thus, sensing the flow rate of any fluid flowing past tool 10 as well as the different phases of fluid at the differential spatial locations of sensor modules 321, 322 may provide full information about the cross-section of the entire amount of fluid flowing through wellbore 12” NOTE: Manzar teaches the measurement of composition at different levels and as well as measuring the flow rate at the respective levels, therefore there is a correlations of measurement signals between the composition and flow rate. See [0025], Knowing the sections of the cross-sectional stream of fluid that are made up of the different phases necessarily results in a more accurate estimate of the rate of fluid flowing through well bore 12. Further shown in FIG. 4,). It is also known in the art that sensor signals are measured over a time interval. Signals were collected during lowering or raising of the tool see [0032], “sensing can occur when raising or lowering the tool 10 in the wellbore 12”).
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.
Claims 3-4, 17-18, and 21, are rejected under 35 U.S.C. 103 as being unpatentable over Manzar and in view of Gary Lucas. (US 4,975,645, hereinafter Lucas, IDS ref.).
Regarding Claim 3, Manzar teaches the system according to claim 1,
Manzar is silent on wherein: the system further comprises a pressure sensor and a temperature sensor, and the processing means is further configured to use pressure and temperature measurements sensed by the pressure and temperature sensors as thermodynamic state variables to determine a mass density of each of the plurality of fluid components of the fluid mixture.
However, Lucas teaches wherein: the system further comprises a pressure sensor (Lucas, Figure2, Col. 4, line 34, Pressure Transducer 60) and a temperature sensor (Lucas, Figure 2, Col. 4, line 35, Temperature Transducer 68), and the processing means is further configured to use pressure and temperature measurements sensed by the pressure and temperature sensors as thermodynamic state variables (Lucas, Figure2, Col. 4, lines 34-37, The logging tool also comprises a pressure transducer 60 and a temperature transducer 68 which are connected
to the electronic section 24 by electrical wires passing through the ducts 36.) to determine a mass density of each of the plurality of fluid components of the fluid mixture. (Lucas, Figures1-2, Col. 8, lines 14-27, By combining the measured values of gas velocity and gas void fraction in each flow sector with a measurement of the pressure and temperature of the fluid at the location of the tool, it is possible to calculate the volume flow rate and mass flow rate of gas in each sector, the mass flow rate being obtained by multiplying the volume flow rate by the density of the gas (as a consequence, in the following description equations related to mass flow rate only are given). As a fact, the density d of the gas at the location of the logging tool is a function of the downhole temperature T and the downhole pressure p, both of which are measured with transducers 60 and 62”).
It would have been obvious to a person of ordinary skill before the effective filing date to modify Manzar system in view of Lucas to include a pressure and temperature sensors attached with the tool as taught by Lucas in order to measure the temperature and pressure of the flow fluid and measure density of flow fluid. (Lucas, Col 8, lines 14-30). It would have been obvious to a person of ordinary skill to include the well-known pressure and temperature sensor values with the other fluid parameters, in order to yield the predicted results of density value measurement data, yet with higher accuracy (KSR).
Regarding Claim 4, combination of Manzar and Lucas teaches the system according to claim 1,
Manzar further teaches wherein: the processing means is further configured to combine the total cross-sectional area, the flow velocity, (Manzar, Figures 1-2, [0026], “Signals which may be transmitted to controller 47 (FIG. 1) can be analyzed to estimate axial location of the end of arm 30 and further thereby estimating location of the mid-portion M of arm 30, to thereby provide an estimate of the location of sensor modules 321, 322 (FIG. 2) and their relative distances from axis Ax. Thus, sensing the flow rate of any fluid flowing past tool 10 as well as the different phases of fluid at the differential spatial locations of sensor modules 321, 322 may provide full information about the cross-section of the entire amount of fluid flowing through wellbore 12”).
Manzar is silent on the mass density of each of the plurality of fluid components of the fluid mixture to determine a corresponding mass flow rate.
However, Lucas teaches and the mass density of each of the plurality of fluid components of the fluid mixture to determine a corresponding mass flow rate(Lucas, Figures1-2, Col. 8, lines 14-27, By combining the measured values of gas velocity and gas void fraction in each flow sector with a measurement of the pressure and temperature of the fluid at the location of the tool, it is possible to calculate the volume flow rate and mass flow rate of gas in each sector, the mass flow rate being obtained by multiplying the volume flow rate by the density of the gas (as a consequence, in the following description equations related to mass flow rate only are given). As a fact, the density d of the gas at the location of the logging tool is a function of the downhole temperature T and the downhole pressure p, both of which are measured with transducers 60 and 62”).
It would have been obvious to a person of ordinary skill before the effective filing date to modify Manzar system in view of Lucas to include a pressure and temperature sensors attached with the tool as taught by Lucas in order to measure the temperature and pressure of the flow fluid and measure density of flow fluid. (Lucas, Col 8, lines 14-30). It would have been obvious to a person of ordinary skill to include the well-known pressure and temperature sensor values with the other fluid parameters, in order to yield the predicted results of density value measurement data, yet with higher accuracy (KSR).
Regarding Claim 17, Manzar teaches the system according to claim 15,
Manzar is silent on wherein: the system further comprises a pressure sensor and a temperature sensor, and the processing means is further configured to use pressure and temperature measurements sensed by the pressure and temperature sensors as thermodynamic state variables to determine a mass density of each of the plurality of fluid components of the fluid mixture
However, Lucas teaches wherein: the system further comprises a pressure sensor (Lucas, Figure2, Col. 4, line 34, Pressure Transducer 60) and a temperature sensor (Lucas, Figure 2, Col. 4, line 35, Temperature Transducer 68) , and the processing means is further configured to use pressure and temperature measurements sensed by the pressure and temperature sensors as thermodynamic state variables (Lucas, Figure2, Col. 4, lines 34-37, The logging tool also comprises a pressure transducer 60 and a temperature transducer 68 which are connected
to the electronic section 24 by electrical wires passing through the ducts 36.) to determine a mass density of each of the plurality of fluid components of the fluid mixture. (Lucas, Figures1-2, Col. 8, lines 14-27, By combining the measured values of gas velocity and gas void fraction in each flow sector with a measurement of the pressure and temperature of the fluid at the location of the tool, it is possible to calculate the volume flow rate and mass flow rate of gas in each sector, the mass flow rate being obtained by multiplying the volume flow rate by the density of the gas (as a consequence, in the following description equations related to mass flow rate only are given). As a fact, the density d of the gas at the location of the logging tool is a function of the downhole temperature T and the downhole pressure p, both of which are measured with transducers 60 and 62”).
It would have been obvious to a person of ordinary skill before the effective filing date to modify Manzar system in view of Lucas to include a pressure and temperature sensors attached with the tool as taught by Lucas in order to measure the temperature and pressure of the flow fluid and measure density of flow fluid. (Lucas, Col 8, lines 14-30). It would have been obvious to a person of ordinary skill to include the well-known pressure and temperature sensor values with the other fluid parameters, in order to yield the predicted results of density value measurement data, yet with higher accuracy (KSR).
Regarding Claim 18, Manzar teaches the system according to claim 15,
Manzar further teaches wherein: the processing means is further configured to combine the total cross-sectional area, the flow velocity, (Manzar, Figures 1-2, [0026], “Signals which may be transmitted to controller 47 (FIG. 1) can be analyzed to estimate axial location of the end of arm 30 and further thereby estimating location of the mid-portion M of arm 30, to thereby provide an estimate of the location of sensor modules 321, 322 (FIG. 2) and their relative distances from axis Ax. Thus, sensing the flow rate of any fluid flowing past tool 10 as well as the different phases of fluid at the differential spatial locations of sensor modules 321, 322 may provide full information about the cross-section of the entire amount of fluid flowing through wellbore 12”).
Manzar is silent on the mass density of each of the plurality of fluid components of the fluid mixture to determine a corresponding mass flow rate.
However, Lucas teaches and the mass density of each of the plurality of fluid components of the fluid mixture to determine a corresponding mass flow rate(Lucas, Figures1-2, Col. 8, lines 14-27, By combining the measured values of gas velocity and gas void fraction in each flow sector with a measurement of the pressure and temperature of the fluid at the location of the tool, it is possible to calculate the volume flow rate and mass flow rate of gas in each sector, the mass flow rate being obtained by multiplying the volume flow rate by the density of the gas (as a consequence, in the following description equations related to mass flow rate only are given). As a fact, the density d of the gas at the location of the logging tool is a function of the downhole temperature T and the downhole pressure p, both of which are measured with transducers 60 and 62”).
It would have been obvious to a person of ordinary skill before the effective filing date to modify Manzar system in view of Lucas to include a pressure and temperature sensors attached with the tool as taught by Lucas in order to measure the temperature and pressure of the flow fluid and measure density of flow fluid. (Lucas, Col 8, lines 14-30). It would have been obvious to a person of ordinary skill to include the well-known pressure and temperature sensor values with the other fluid parameters, in order to yield the predicted results of density value measurement data, yet with higher accuracy (KSR).
Regarding Claim 21, Manzar teaches the system according to claim 1,
Manzar is silent on wherein: the system further comprises a pressure sensor and a temperature sensor, and the processing means is further configured to use pressure and temperature measurements sensed by the pressure and temperature sensors as thermodynamic state variables to determine a mass density of each of the plurality of fluid components of the fluid mixture.
However, Lucas teaches wherein: the system further comprises a pressure sensor (Lucas, Figure2, Col. 4, line 34, Pressure Transducer 60) and a temperature sensor (Lucas, Figure 2, Col. 4, line 35, Temperature Transducer 68) , and the processing means is further configured to use pressure and temperature measurements sensed by the pressure and temperature sensors as thermodynamic state variables (Lucas, Figure2, Col. 4, lines 34-37, The logging tool also comprises a pressure transducer 60 and a temperature transducer 68 which are connected
to the electronic section 24 by electrical wires passing through the ducts 36.) to determine a mass density of each of the plurality of fluid components of the fluid mixture. and combining the total cross-sectional area, the flow velocity, and the mass density of each of the plurality of fluid components to determine a corresponding mass flow rate. (Lucas, Figures1-2, Col. 8, lines 14-27, By combining the measured values of gas velocity and gas void fraction in each flow sector with a measurement of the pressure and temperature of the fluid at the location of the tool, it is possible to calculate the volume flow rate and mass flow rate of gas in each sector, the mass flow rate being obtained by multiplying the volume flow rate by the density of the gas (as a consequence, in the following description equations related to mass flow rate only are given). As a fact, the density d of the gas at the location of the logging tool is a function of the downhole temperature T and the downhole pressure p, both of which are measured with transducers 60 and 62”).
It would have been obvious to a person of ordinary skill before the effective filing date to modify Manzar system in view of Lucas to include a pressure and temperature sensors attached with the tool as taught by Lucas in order to measure the temperature and pressure of the flow fluid and measure density of flow fluid. (Lucas, Col 8, lines 14-30). It would have been obvious to a person of ordinary skill to include the well-known pressure and temperature sensor values with the other fluid parameters, in order to yield the predicted results of density value measurement data, yet with higher accuracy (KSR).
Claims 5-6, and 19 are rejected under 35 U.S.C. 103 as being unpatentable over Manzar and in view of Frey et al. (US 2012/0111561 A1, hereinafter Frey, IDS ref.).
Regarding Claim 5, Manzar teaches the system according to claim 1,
Manzar is silent on further teaches determine the total cross-sectional area and the flow velocity of each of the plurality of fluid components of the fluid mixture (Manzar, Figures 1-2, [0026], “Signals which may be transmitted to controller 47 (FIG. 1) can be analyzed to estimate axial location of the end of arm 30 and further thereby estimating location of the mid-portion M of arm 30, to thereby provide an estimate of the location of sensor modules 321, 322 (FIG. 2) and their relative distances from axis Ax. Thus, sensing the flow rate of any fluid flowing past tool 10 as well as the different phases of fluid at the differential spatial locations of sensor modules 321, 322 may provide full information about the cross-section of the entire amount of fluid flowing through wellbore 12”).
Manzar is silent on wherein: the processing means is further configured to use a measurement time length of each of the plurality of time-series
However, Frey teaches wherein: the processing means is further configured to use a measurement time length of each of the plurality of time-series (Frey, Figure 3, [0034], For example, the temperature sensor 37 may be positioned adjacent to and/or within the first phase 2 for a first duration of time based on the rotational
speed of the BHA 24. As a result, the temperature sensor 37 may detect, acquire and/or obtain first temperature measurements associated with the first phase 2 during the first duration of time. Moreover, the temperature sensor 37 may be
rotated and may be positioned adjacent to and/or within the second phase 4 for a second duration of time based on the BHA rotational speed. The temperature sensor may detect, acquire and/or obtain second temperature measurements
associated with the second phase 4 during the second duration of time” NOTE: the measurement time durations are based on rotational speed and each set of measurement has a specific time length)
It would have been obvious to a person of ordinary skill before the effective filing date to modify Manzar system in view of Frey to include a time measurement duration for each set of measurement as taught by Frey in order to measure the flow rate and other characteristic parameters. (Frey, [0034]). It would have been obvious to a person of ordinary skill to include the well-known timed measurement of well bore sensor values with the other fluid parameters, in order to yield the predicted results of correct time interval flow rate and density value for different composition, yet with higher accuracy (KSR).
Regarding Claim 6, combination of Manzar and Frey teaches the system according to claim 5,
Manzar is silent on wherein: the measurement time length is based on an observed flow velocity of the fluid mixture.
However, Frey teaches wherein: the measurement time length is based on an observed flow velocity of the fluid mixture (Frey, [0039], “the resistivity sensor 39 may be positioned adjacent to and/ or within the first phase 2 for a first duration of time based on the BHA rotational speed. As a result, the resistivity sensor 37 may detect, acquire and/or obtain first resistivity measurements based on an amount of current flowing between the electrode 202 and the collar 206 through the first phase 2”.)
It would have been obvious to a person of ordinary skill before the effective filing date to modify Manzar system in view of Frey to include a time measurement duration for each set of measurement as taught by Frey in order to measure the flow rate and other characteristic parameters. (Frey, [0034]). It would have been obvious to a person of ordinary skill to include the well-known timed measurement of well bore sensor values with the other fluid parameters, in order to yield the predicted results of correct time interval flow rate and density value for different composition, yet with higher accuracy (KSR).
Regarding Claim 19, Manzar teaches the system according to claim 15,
Manzar is silent on further teaches determine the total cross-sectional area and the flow velocity of each of the plurality of fluid components of the fluid mixture (Manzar, Figures 1-2, [0026], “Signals which may be transmitted to controller 47 (FIG. 1) can be analyzed to estimate axial location of the end of arm 30 and further thereby estimating location of the mid-portion M of arm 30, to thereby provide an estimate of the location of sensor modules 321, 322 (FIG. 2) and their relative distances from axis Ax. Thus, sensing the flow rate of any fluid flowing past tool 10 as well as the different phases of fluid at the differential spatial locations of sensor modules 321, 322 may provide full information about the cross-section of the entire amount of fluid flowing through wellbore 12”).
Manzar is silent on wherein: the processing means is further configured to use a measurement time length of each of the plurality of time-series
However, Frey teaches wherein: the processing means is further configured to use a measurement time length of each of the plurality of time-series (Frey, Figure 3, [0034], For example, the temperature sensor 37 may be positioned adjacent to and/or within the first phase 2 for a first duration of time based on the rotational
speed of the BHA 24. As a result, the temperature sensor 37 may detect, acquire and/or obtain first temperature measurements associated with the first phase 2 during the first duration of time. Moreover, the temperature sensor 37 may be
rotated and may be positioned adjacent to and/or within the second phase 4 for a second duration of time based on the BHA rotational speed. The temperature sensor may detect, acquire and/or obtain second temperature measurements
associated with the second phase 4 during the second duration of time” NOTE: the measurement time durations are based on rotational speed and each set of measurement has a specific time length)
It would have been obvious to a person of ordinary skill before the effective filing date to modify Manzar system in view of Frey to include a time measurement duration for each set of measurement as taught by Frey in order to measure the flow rate and other characteristic parameters. (Frey, [0034]). It would have been obvious to a person of ordinary skill to include the well-known timed measurement of well bore sensor values with the other fluid parameters, in order to yield the predicted results of correct time interval flow rate and density value for different composition, yet with higher accuracy (KSR).
Conclusion
Citation of Pertinent Prior Art
The prior art made of record and not relied upon is considered pertinent to applicant's disclosure.
Livescu et al. (US 2020/0301393 A1) recites “A system for tool monitoring includes one or more tools of an energy industry system, the one or more tools configured to be disposed in one or more boreholes in one or more
resource bearing formations, and one or more sensors connected to each tool of the one or more tools, each sensor of the one or more sensors configured to measure at least one parameter related to performance of each tool of the one or
more tools. The system also includes a processing device configured to collect measurements of the at least one parameter from each sensor, generate an individual performance history record for each tool, and store the individual
performance history record for each tool in a database configured to store individual performance history records for a plurality of tools in one or more energy industry systems” (abstract)
Moscato et al. (US 2015/0135817 A1) recites “Example methods and apparatus to determine downhole fluid parameters are disclosed herein. An example method includes determining a velocity of a portion of a downhole tool moving in a well and determining a response of a fluid sensor disposed on the portion of the downhole tool. The fluid sensor includes a resistance temperature detector at least partially immersed in a fluid in the well. The example method further includes determining a velocity of the fluid based the velocity of the
portion of the downhole tool and the response of the fluid sensor” (abstract)
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/DILARA SULTANA/Examiner, Art Unit 2858
/PARESH PATEL/Primary Examiner, Art Unit 2858 December 17, 2025