DETAILED ACTION
Claims 1-6, 9-15, and 17-20 are presented for examination.
Claims 7-8 and 16 have been cancelled by Applicant.
This office action is in response to submission of Applicant’s Amendment and Response to Office Action, filed April 7, 2025.
Rejection of claims 1-9,11, 16, and 18 under 35 U.S.C. 112(b) as being indefinite are withdrawn.
Claims 1-20 remain rejected under 35 U.S.C. 101 because the claimed invention is directed to an abstract idea without significantly more.
Rejection of claims 1, 3-7, 9-10, 12-17, and 19-20 are rejected under 35 U.S.C. 103 as being unpatentable over Quintero in view of Aslanyan and Chace are withdrawn.
Rejection of claims 2, 11, and 18 are rejected under 35 U.S.C. 103 as being unpatentable over Quintero in view of Aslanyan, Chace, and Davydov are withdrawn.
Rejection of claim 8 is rejected under 35 U.S.C. 103 as being unpatentable over Quintero in view of Aslanyan, Chace, and Friehauf are withdrawn.
Rejection of claims 1-6, 9-15, and 17-20 under 35 U.S.C. 103 as being obvious over Kremenetsky in view of Aslanyan and Benlakhdar.
Notice of Pre-AIA or AIA Status
The present application, filed on or after March 16, 2013, is being examined under the first inventor to file provisions of the AIA .
Response to Arguments
With respect to Applicant’s amendments to the claims addressing the rejections of claims 1-9, 11, 16, and 18 under 35 U.S.C. 112(b), Examiner is persuaded. The amendments remedy the deficiencies of the claims and/or cancel rejected claims. Accordingly, rejection of claims 1-9, 11, 16, and 18 are withdrawn.
With respect to Applicant’s arguments regarding rejection of claims 1, 10, and 17 under 35 U.S.C. 101:
Applicant asserts that the inclusion of “simulating temperature gradients of reservoir fluids at different well conditions corresponding to inflow zones of a harsh wellbore environment resulting from sticky materials and high water cut" and "generating a multiphase oil and water flow profile using the total flow rate, the oil flow rate, and the water flow rate that models flow behavior in the presence of sticky material and high water cut that prevents an accurate determination of wellbore characteristics using mechanical downhole tools in the harsh wellbore environment to identify active formation fractures of inflow zones that produce or take fluid” are “technical improvements over the prior art” because the limitations are directed to “identifying active formation fractures of inflow zones that produce or take fluid. The specification describes that noise logging and numerical temperature simulation is combined with a pulsed neutron log to provide an accurate oil/water production profile and identify formation fractures.” Response at pg. 10. Further, Applicant asserts that “[t]he independent claims realize technical improvements over the prior art by identifying active formation fractures of inflow zones that produce or take fluid. The specification describes that noise logging and numerical temperature simulation is combined with a pulsed neutron log to provide an accurate oil/water production profile and identify formation fractures.” Id.
However, regarding improvements to existing technology, the MPEP states: “An indication that the claimed invention provides an improvement can include a discussion in the specification that identifies a technical problem and explains the details of an unconventional technical solution expressed in the claim, or identifies technical improvements realized by the claim over the prior art.” MPEP 2106.05(a). Further, “ if the specification explicitly sets forth an improvement but in a conclusory manner (i.e., a bare assertion of an improvement without the detail necessary to be apparent to a person of ordinary skill in the art), the examiner should not determine the claim improves technology.” Id.
Examiner is not persuaded by the arguments that the amended claims are directed to an improvement in technology nor that the asserted improvement is “non-conventional.”
First, the claim is directed to a method of “flow profiling,” not a method for using non-conventional techniques to identify inflow zones in a well. The method results in a “multiphase oil and water flow profile” that uses one or more models to simulate temperature gradients in the well. The claim does not recite how the inflow zones are identified in the noise log, so the limitation that the inflow zones are identified for a “harsh wellbore environment resulting from sticky materials and high water cut” is extra-solution activity. The claim, as amended, merely limits the usage to a particular field or technological environment. See, e.g., Intellectual Ventures I LLC v. Capital One Bank (USA), N.A., 792 F.3d 1363, 1366, 115 USPQ2d 1636, 1639 (Fed. Cir. 2015) (“An abstract idea does not become nonabstract by limiting the invention to a particular field of use or technological environment…).
Next, the asserted improvement is recited and disclosed in a conclusory manner that does not provide details that would make the improvement apparent to a person of ordinary skill in the art. The claim does not, for example, detail what constitutes a “harsh wellbore environment,” a limitation that, to some extent, is characteristic of all typical oil wells. Further, “sticky materials and high water cut” can be interpreted to apply to all oil wells because oil is a “sticky material” and, at least to some extent, water is present in well fluids (i.e., there is no explicit limitation to “high”).
Finally, the specification asserts that “[c]onventional techniques are limited to the use of an array spinner and holdup measurements to represent the phase velocity and fluid fractions which have limitations in harsh downhole conditions.” Spec. at [0010]. However, as of at least the effective filing date of the present application, using noise logs, temperature logs, and pulsed neutron logs to identify phase velocities and fluid fractions was well understood, routine, and conventional. See, e.g., Benlakhdar, et al., “Integrating Pulse Neutron Measurements with Array Production Logging for Enhanced Production Characterization in Horizontal Wells,” (“Horizontal wells with barefoot completion are common. Since presence of debris is more likely in these completions, there are always chances of spinners to be damaged or become stuck, thus rendering them useless for velocity measurements,” describing uses for pulsed neutron measurements when determining flow characteristics); Aslanyan, et al., “Numerical Temperature Modelling for Quantitative Analysis of Low-Compressible Fluid Production,” (“Temperature logging can detect wellbore flows with rates way below the mechanical spinner’s threshold.”); Roscoe, et al., “Measurement of Oil and Water Flow Rates in a Horizontal Well With Chemical Markers and a Pulsed-Neutron Tool,” (“Existing production-logging techniques, such as spinners, that have been successfully used in vertical wells cannot always be applied to horizontal wells with full confidence owing to the segregated flow in the borehole. For this reason, new techniques must be developed to evaluate oil and water flow rates in horizontal wells.”); Aslanyan, et al., “Identification of Inflow Zones in Low-Rate Horizontal Wells by Spectral Noise Logging,” (“To solve these complex downhole logging problems, the hardware and software system of High-Definition Spectral Noise Logging has been developed. It can handle various tasks arising during downhole logging, including identification of flow zones in low-rate horizontal wells where conventional logging techniques (temperature, pressure, spinner, multiphase sensors) do not always provide decisive answers.”).
Accordingly, rejection of the pending claims under 35 U.S.C. 101 is maintained.
With respect to Applicant’s amendments and arguments directed to the rejection of the claims under 35 U.S.C. 103:
Applicant asserts that “the Examiner fails to show that Quintero teaches or suggests ‘inputting the inflow zones identified in a noise log of a well and corresponding thermal properties from a temperature log into a temperature mixture model.’” Response at pg. 11.
Examiner disagrees. As cited in the Office Action at pp. 14-15, Quintero discloses “Based on the NL data, the noise log borehole model determines a second radial distance of the one or more flow paths from center of the wellbore 102.” The “radial distance” (i.e., distance between the sensor and the flow path) is analogous to “inflow path” and identifies an “active zone” where fluid is flowing within the wellbore environment. See Spec. at [0014].
However, Quintero does not appear to disclose inputting, to a temperature mixture model, “inflow zones of a harsh wellbore environment resulting from sticky materials and high water cut,” as recited by the amended claim. Further, Quintero does not appear to teach or disclose modeling “flow behavior in the presence of sticky material and high water cut that prevents an accurate determination of wellbore characteristics using mechanical downhole tools in the harsh wellbore environment to identify active formation fractures of inflow zones that produce or take fluid.” Accordingly, previous rejection of the claims under 35 U.S.C. 103 are withdrawn.
Applicant further asserts that “the Examiner fails to identify any ‘inflow zone identified by a noise log of a well’ in Davydov. Davydov simply describes spectral noise logging that allows for the detection of fluid flow” and “the Examiner has not shown that Davydov teaches or suggests inputting inflow zones identified in a noise log of a well into a temperature mixture model.” Response at pp. 11-12.
In light of the withdrawal of the rejections for failing to teach or disclose “inflow zones of a harsh wellbore environment resulting from sticky materials and high water cut” and “flow behavior in the presence of sticky material and high water cut that prevents an accurate determination of wellbore characteristics using mechanical downhole tools in the harsh wellbore environment to identify active formation fractures of inflow zones that produce or take fluid,” Applicant’s argument regarding claims 2, 11, and 18 are moot.
Amendments to the claims to include “inflow zones of a harsh wellbore environment resulting from sticky materials and high water cut” and “flow behavior in the presence of sticky material and high water cut that prevents an accurate determination of wellbore characteristics using mechanical downhole tools in the harsh wellbore environment to identify active formation fractures of inflow zones that produce or take fluid” necessitate new rejections under 35 U.S.C. 103 in view of additional and/or alternative prior art.
Claim Rejections - 35 USC § 101
35 U.S.C. 101 reads as follows:
Whoever invents or discovers any new and useful process, machine, manufacture, or composition of matter, or any new and useful improvement thereof, may obtain a patent therefor, subject to the conditions and requirements of this title.
Claims 1-20 are rejected under 35 U.S.C. 101 because the claimed invention is directed to an abstract idea without significantly more.
In view of Step 1 of the analysis, claims 1-9 are directed to the statutory category of a process. Claims 10-16 are directed to the statutory category of a machine. Claims 17-20 are directed to a statutory category of manufacture.
Claim 1
Step 2A, Prong 1: The claim 1 limitations include (bolded for abstract idea identification):
Claim 1
Mapping Under Step 2A Prong 1
A computer-implemented method for flow profiling, the method comprising:
simulating temperature gradients of reservoir fluids at different well conditions corresponding to inflow zones of a harsh wellbore environment resulting from sticky materials and high water cut by
inputting the inflow zones identified in a noise log of a well and corresponding thermal properties from a temperature log into a
temperature mixture model that characterizes mixture temperatures, inflow temperatures, upward flow temperatures, static temperatures, flowing temperatures, and geothermal temperatures for the identified inflow zones;
quantifying a total flow rate of the reservoir fluids based on the simulated temperature gradients;
calculating a water flow rate of water in the reservoir fluids based on, at least in part, a pulsed neutron log;
calculating an oil flow rate from the total flow rate of the reservoir fluids and the water flow rate; and
generating a multiphase oil and water flow profile using the total flow rate, the oil flow rate, and the water flow rate that models flow behavior in the presence of sticky material and high water cut that prevents an accurate determination of wellbore characteristics using mechanical downhole tools in the harsh wellbore environment to identify active formation fractures of inflow zones that produce or take fluid.
Abstract Idea: Mathematical Calculations
A simulation includes one or more mathematical functions that are utilized to perform calculations based on provided parameters. Thus, “simulating…well conditions” is a mathematical concept. See MPEP § 2106.04(a)(2), Subsection I.
Abstract Idea: Mathematical Calculations
A “model” is a mathematical construct that provides behavior of a system by using mathematical functions that are characteristic of the system. Thus, a “model” is a mathematical concept. See MPEP § 2106.04(a)(2), Subsection I.
Abstract Idea: Mathematical Calculations
“Quantifying” includes performing mathematical calculations to generate a numerical value that is characteristic of a property, thus a mathematical concept. See MPEP § 2106.04(a)(2), Subsection I.
Abstract Idea: Mathematical Calculations
“Calculating” rates includes performing mathematical calculations. See MPEP § 2106.04(a)(2), Subsection I.
Abstract Idea: Mathematical Calculations
“Calculating” rates includes performing mathematical calculations. See MPEP § 2106.04(a)(2), Subsection I.
Abstract Idea: Mental Process
Giving “profile” its broadest reasonable interpretation, “a multiphase oil and water flow profile” can include steps of observation, evaluation, opinion, and judgment that can be done in the human mind and/or with the aid of a pencil and paper. See e.g., MPEP 2106.04(a)(2), Subsection III. Alternatively, even if “generating a…profile” is not an abstract idea (either a mental process or a mathematical calculation), the limitation is an idea of a solution (See below),
Step 2A, Prong 2: The claim 1 limitations recite (bolded for additional element identification):
Claim 1
Mapping Under Step 2A Prong 2
A computer-implemented method for flow profiling, the method comprising:
simulating temperature gradients of reservoir fluids at different well conditions corresponding to inflow zones of a harsh wellbore environment resulting from sticky materials and high water cut by
inputting the inflow zones identified in a noise log of a well and corresponding thermal properties from a temperature log
into a temperature mixture model that characterizes mixture temperatures, inflow temperatures, upward flow temperatures, static temperatures, flowing temperatures, and geothermal temperatures for the identified inflow zones;
quantifying a total flow rate of the reservoir fluids based on the simulated temperature gradients;
calculating a water flow rate of water in the reservoir fluids based on, at least in part, a pulsed neutron log;
calculating an oil flow rate from the total flow rate of the reservoir fluids and the water flow rate; and
generating a multiphase oil and water flow profile using the total flow rate, the oil flow rate, and the water flow rate that models flow behavior in the presence of sticky material and high water cut that prevents an accurate determination of wellbore characteristics using mechanical downhole tools in the harsh wellbore environment to identify active formation fractures of inflow zones that produce or take fluid.
Recitation of generic computer components is an additional element that amounts to reciting a judicial exception and then reciting “apply it.” See MPEP 2106.05(f).
Inputting data that is collected from a logging device is the extra-solution activities of data gathering and transmission. See MPEP 2106.05(g)(3).
Even if “generating a…profile” is not an abstract idea (see above), the limitation is an idea of a solution and does not recite details that point out a solution to a particular problem and/or how the solution is accomplished. See MPEP 2106.05(f).
In view of Step 2B, the claim does not include additional elements that are sufficient to amount to significantly more than the judicial exception because the additional elements are viewed as insignificant extra-solution activity as described in Step 2A prong two. For example, gathering data from logs to utilize in determining fluid flow in a well is well-understood, routine, and conventional, which courts have found to be insignificantly more than the recited judicial exception. See, e.g., Davydov (U.S. Patent Publication No. 2015/0204184) at [0001], “…the present invention concerns well logging and in particular relates to apparatus and methods for spectral noise logging that allow for the detection of fluid flow through, or behind a casing of a well penetrating subsurface formation, including noise generated by fluid filtration within a reservoir.”
Further, the limitations directed to the “harsh wellbore environment” and instances wherein “the presence of sticky material and high water cut that prevents an accurate determination of wellbore characteristics using mechanical downhole tools” are not significantly more than the recited judicial exceptions. Instead, as previously indicated, using combinations of pulsed neutron logs and/or spectral noise logging in wellbore environments that inconducive to using spinners and/or other mechanical logging tools to determine flow rates is well-understood, routine, and conventional. See, e.g., Benlakhdar, et al., “Integrating Pulse Neutron Measurements with Array Production Logging for Enhanced Production Characterization in Horizontal Wells,” (“Horizontal wells with barefoot completion are common. Since presence of debris is more likely in these completions, there are always chances of spinners to be damaged or become stuck, thus rendering them useless for velocity measurements,” describing uses for pulsed neutron measurements when determining flow characteristics); Aslanyan, et al., “Numerical Temperature Modelling for Quantitative Analysis of Low-Compressible Fluid Production,” (“Temperature logging can detect wellbore flows with rates way below the mechanical spinner’s threshold.”); Roscoe, et al., “Measurement of Oil and Water Flow Rates in a Horizontal Well With Chemical Markers and a Pulsed-Neutron Tool,” (“Existing production-logging techniques, such as spinners, that have been successfully used in vertical wells cannot always be applied to horizontal wells with full confidence owing to the segregated flow in the borehole. For this reason, new techniques must be developed to evaluate oil and water flow rates in horizontal wells.”); Aslanyan, et al., “Identification of Inflow Zones in Low-Rate Horizontal Wells by Spectral Noise Logging,” (“To solve these complex downhole logging problems, the hardware and software system of High-Definition Spectral Noise Logging has been developed. It can handle various tasks arising during downhole logging, including identification of flow zones in low-rate horizontal wells where conventional logging techniques (temperature, pressure, spinner, multiphase sensors) do not always provide decisive answers.”).
Claim 2
The claim recites “identifying the inflow zones across a horizontal section of the well” and “extracting the thermal properties from the temperature log of the well corresponding to inflow zones identified by the noise log of the well,” which are both directed to the extra-solution activity of mere data gathering and do not amount to significantly more than the claimed judicial exceptions enumerated above regarding claim 1. See, e.g., Mayo, 566 U.S. at 79, 101 USPQ2d at 1968; OIP Techs., Inc. v. Amazon.com, Inc., 788 F.3d 1359, 1363, 115 USPQ2d 1090, 1092-93 (Fed. Cir. 2015). Accordingly, the claim as a whole does not amount to significantly more than the abstract idea and is therefore not patent eligible.
Claim 3
The claim recites “different well conditions include static, transient, and flowing,” which are mere observations that can be performed by a human, which is a mental process. See MPEP 2106.04(a)(2), Subsection III. Accordingly, the claim is therefore not patent eligible.
Claim 4
The claim recites “executing an oxygen activation technique to determine a water velocity of the reservoir fluids, wherein data is extracted from the pulsed neutron log and used to calculate the water flow rate,” which is directed to mathematical concepts in the form of performing mathematical calculations and relations using “extracted” data, which is an extra-solution activity of data gathering. Accordingly, the claim is directed to an abstract idea without significantly more and is therefore not patent eligible.
Claim 5
The claim recites “determining a water faction of the reservoir fluids,” which is directed to the abstract idea of “mathematical calculations” without additional elements that amount to significantly more. Further, claim 5 recites “wherein the water faction is calculated from C/O ratios extracted from the pulsed neutron log and used to calculate the water flow rate,” which is directed to the extra-solution activities of data gathering and observation, both of which can be performed by a human. Accordingly, claim 5 does not include additional limitations that amount to significantly more than the judicial exception and is not patent eligible.
Claim 6
The claim recites “wherein the water flow rate is based on, at least in part, a water velocity, a water faction, and a bore hole section area of the well,” which are directed to mathematical calculations performed using gathered data. The gathering of data is an extra-solution activity that does not amount to significantly more than the recited abstract idea of performing mathematical calculations. See, e.g., Mayo, 566 U.S. at 79, 101 USPQ2d at 1968; OIP Techs., Inc. v. Amazon.com, Inc., 788 F.3d 1359, 1363, 115 USPQ2d 1090, 1092-93 (Fed. Cir. 2015). Accordingly, the claim is therefore not patent eligible.
Claim 9
The claim recites “wherein the oil flow rate and water flow rate are used to determine cross flows of reservoir fluids in the well,” which is an additional element that merely links the calculation of oil and water flow rates to a field of use. Courts have found such additional elements to be insignificantly more than the recited judicial exception. See MPEP 2106.05(h). Further, the additional elements are mere instructions to apply the judicial exception, thus reciting an idea of a solution. See MPEP 2016.05(f)(1). Accordingly, claim 9 is rejected for being directed to unpatentable subject matter.
Claims 10-15
Claims 10-16 recite a machine that performs the process that is recited in claims 1-9. As previously indicated with regards to those claims, the claimed invention is directed to the abstract ideas of mental processes and mathematical calculations. Claims 10 further recites “a system, comprising: one or more memory modules; one or more hardware processors communicably coupled to the one or more memory modules, the one or more hardware processors configured to execute instructions stored on the one or more memory models to perform operations.” The additional system recited in claims 10-16 are nothing more than a recitation of generic computer components and amount to no more than an application of an abstract idea. Accordingly, for at least the same reasons as claims 1-9, claims 10-16 are not patent eligible.
Claims 17-20
Claims 17-20 recite a manufacture that includes instructions to perform the processes previously recited in claims 1-4. As previously indicated with regards to those claims, the claimed invention is directed to the abstract ideas of mental processes and mathematical calculations. Claims 17-20 further recite “An apparatus comprising a non-transitory, computer readable, storage medium that stores instructions that, when executed by at least one processor, cause the at least one processor to perform operations” that were previously recited in claim 1. The additional limitations are nothing more than a recitation of generic computer components and amount to no more than an application of an abstract idea. Accordingly, for at least the same reasons as claims 1-4, claims 17-20 are not patent eligible.
Claim Rejections - 35 USC § 103
In the event the determination of the status of the application as subject to AIA 35 U.S.C. 102 and 103 (or as subject to pre-AIA 35 U.S.C. 102 and 103) is incorrect, any correction of the statutory basis (i.e., changing from AIA to pre-AIA ) for the rejection will not be considered a new ground of rejection if the prior art relied upon, and the rationale supporting the rejection, would be the same under either status.
The following is a quotation of 35 U.S.C. 103 which forms the basis for all obviousness rejections set forth in this Office action:
A patent for a claimed invention may not be obtained, notwithstanding that the claimed invention is not identically disclosed as set forth in section 102, if the differences between the claimed invention and the prior art are such that the claimed invention as a whole would have been obvious before the effective filing date of the claimed invention to a person having ordinary skill in the art to which the claimed invention pertains. Patentability shall not be negated by the manner in which the invention was made.
The factual inquiries 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 1-6, 9-15, and 17-20 are rejected under 35 U.S.C. 103 as being unpatentable over Kremenetsky , et al., (“New Way of Individual Evaluation of Tight Comingled Reservoirs,” hereinafter “Kremenetsky”) in view of Aslanyan, et al., (“Identification of Inflow Zones in Low-Rate Horizontal Wells by Spectral Noise Logging,” hereinafter “Aslanyan”), and Benlakhdar, et al., (“Integrating Pulse Neutron Measurements with Array Production Logging for Enhanced Production Characterization in Horizontal Wells,” hereinafter “Benlakhdar”).
Claim 1
Kremenetsky discloses:
A
With due regard to possible errors in estimating the thermal properties, a reliable estimation of the inflow profile is possible for comingled formations with 2 or 3 times flow rates difference. Relative estimates among separate intervals or over time allow the error to be decreased to 20-30%. Kremenetsky at pg. 7-8.
simulating temperature gradients of reservoir fluids
As part of framing the solution, the authors examine the efficiency of conventional temperature log interpretation methods in the first part. Then, by simulating well heat and mass transfer, the informational capabilities of temperature survey are analyzed and the applicability limits of the standard approach are determined. Kremenetsky at pg. 2.
at different well conditions
Two approaches can be applied to estimate relative flow rates based on the temperature survey results. The first is related to analyzing the downhole temperature distribution in case of long-term production. To successfully implement this, the logging shall be preceded during production without shutting the well. Production period duration must exceed the duration of the previous possible shut-in periods. The second is related to analyzing the temperature fluctuation rate immediately after a well drawdown is dramatically changed, or well is shutted. Its apparent advantage is that data on geothermal temperature distribution are not used. Kremenetsky at pg. 15.
Logging when the well is “shutted” and “after a well drawdown is dramatically changed” are “different well conditions.”
corresponding to inflow zones of a harsh wellbore environment resulting from sticky materials and high water cut by
Simulation illustrates traditional temperature interpretation technique with comparing well temperature logging curve with geothermal gradient is useless in case of tight reservoirs due to high influence of previous production and unstable flow. New way can handle that problem. Kremenetsky at Abstract.
The comparison results show that, in the absence of reliable data about the thermal properties, the quantitative interpretation can be only estimated. With due regard to possible errors in estimating the thermal properties, a reliable estimation of the inflow profile is possible for comingled formations with 2 or 3 times flow rates difference. Relative estimates among separate intervals or over time allow the error to be decreased to 20-30%. Kremenetsky at pg. 7-8.
“Sticky materials” can include any oil product and “high water cut” is not limited to a particular percentage of water content. Thus, given its broadest reasonable interpretation, any presence of water may be considered “high.”
“Unstable flow” is analogous to “a harsh wellbore environment.”
inputting the inflow zones
The first method allows for an analysis of temperature abnormalities in the inflow intervals. Such anomalies are caused by the thermodynamic effects that accompany filtration within the active formation strata and calorimetric mixing in the borehole. Kremenetsky at pg. 2.
The second method provides for temperature change along the borehole outside the inflow intervals. It is caused by heat exchange between the fluid moving along the borehole and the environment. This study will make use of this approach. Kremenetsky at pg. 2.
The “inflow intervals” and immediately surrounding area are analogous to “inflow zones.” Thus, an “inflow zone” includes both “inflow intervals” and “the borehole outside the inflow intervals” that is affected by the flow from the “inflow interval.”
corresponding thermal properties from a temperature log
To prepare the downhole facilities for logging the well was shut down. At the end of the shut down cycle, baseline temperature logging (TF) was performed. Kremenetsky at pg. 8.
into a temperature mixture model that characterizes mixture temperatures, inflow temperatures, upward flow temperatures, static temperatures, flowing temperatures, and geothermal temperatures for the identified inflow zones;
See Figure A-2, illustrating the temperature mixture model:
PNG
media_image1.png
556
565
media_image1.png
Greyscale
Downhole temperature distribution outside the active formations a, b) Impact of the difference between the formation fluid temperature and geothermal temperature at the upward (a) an downward (b) fluid motion. c) Impact of the flow rate on the upward motion, the temperature of the fluid entering the well is higher than the geothermal temperature. d) Flow rate estimation per the temperature log outside the inflow interval using the area method. Tg - baseline (geothermal) depth-dependent temperature distribution, ΔTo<0,=0,>0 temperature logs in a production well with the temperature of incoming fluid being lower, equal to or higher than the geothermal temperature, Tw1, Tw2, Tw3 - temperature logs in a production well with the temperature of the incoming fluid being higher than the geothermal temperature at various flow rates (Q1<Q2<Q3), S - the area between the temperature log and geothermal log in the log interval, AT - the difference between the top and bottom temperatures in the log interval. Kremenetsky at pg. 18.
The temperature model includes the “inflow interval” and immediately surrounding area. Combined, the “inflow interval” and the area “outside the active formation” are analogous to the “inflow zone.”
quantifying a total flow rate of the reservoir fluids based on the simulated temperature gradients;
To estimate the well formation flow rate, temperature logs (TESP-24) were used during prolonged period of production. The conditions in this mode were favorable. Against the background of the natural thermal field, the typical depth temperature distribution was observed. It represents the aggregate volumetric flow rate of the phases moving inside the borehole. Kremenetsky at pg. 10.
The “aggregate volumetric flow rate” is analogous to “a total flow rate.”
generating a multiphase oil and water flow profile
With due regard to possible errors in estimating the thermal properties, a reliable estimation of the inflow profile is possible for comingled formations with 2 or 3 times flow rates difference. Relative estimates among separate intervals or over time allow the error to be decreased to 20-30%. Kremenetsky at pp. 7-8.
Simulation illustrates traditional temperature interpretation technique with comparing well temperature logging curve with geothermal gradient is useless in case of tight reservoirs due to high influence of previous production and unstable flow. New way can handle that problem. Kremenetsky at Abstract.
The comparison results show that, in the absence of reliable data about the thermal properties, the quantitative interpretation can be only estimated. With due regard to possible errors in estimating the thermal properties, a reliable estimation of the inflow profile is possible for comingled formations with 2 or 3 times flow rates difference. Relative estimates among separate intervals or over time allow the error to be decreased to 20-30%. Kremenetsky at pp. 7-8.
prevents an accurate determination of wellbore characteristics using mechanical downhole tools in the harsh wellbore environment to identify active formation fractures of inflow zones that produce or take fluid.
Due to the low rate and complex composition of the flow in the borehole, a spinner flow survey does not convey enough information to estimate interval production. Kremenetsky at pg. 8.
Aslanyan discloses:
inflow zones identified in a noise log of a well
To solve these complex downhole logging problems, the hardware and software system of High-Definition Spectral Noise Logging has been developed. It can handle various tasks arising during downhole logging, including identification of flow zones in low-rate horizontal wells where conventional logging techniques (temperature, pressure, spinner, multiphase sensors) do not always provide decisive answers. Aslanyan at pg. 2.
Aslanyan is analogous art to the claimed invention because both are related to determining inflow zones in wellbore environments using noise logging to identify the inflow zones. It would have been obvious to a person having ordinary skill in the art, before the effective filing date of the claimed invention, to combine the temperature mixture model disclosed in Kremenetsky with the inflow identification of Aslanyan to result in a system that identifies inflow zones without requiring the use of array spinners to detect fluid flows. Motivation to combine includes utilizing non-mechanical equipment to determine multi-phase flow profiles, thus allowing for better accuracy and utility in environments that are not conducive to mechanical measurement tools, such as harsh environments, low flow wells, and/or wells that contain debris.
Benlakhdar discloses:
A computer-implemented method for flow profiling
The calculated PN holdups are imported into the production logging interpretation software and based on the fluid phase combinations, a selection is made between one of the three utilities. This utility allows calculations of a single phase holdup for each of the 48 probes in a customized capacitance tool defined specifically for this interpretation. Data from this tool can then be combined with other APL tools, such as Spinner Array, for further processing using the layered profile approach described earlier. Benlakhdar at pg. 5.
calculating a water flow rate of water in the reservoir fluids based on, at least in part, a pulsed neutron log;
PN technology can be used for independent PN phase holdup and water velocity measurements in near horizontal wellbores with stratified multiphase flows. Comparison between phase holdups and velocities calculated from Array Production Logging (APL) and PN devices are presented with field examples. Benlakhdar at Abstract.
PN water rates using oxygen activation principle of measurement showed water velocity having good match with APL water velocity, Fig. 7. Benlakhdar at pg. 5.
calculating an oil flow rate from the total flow rate of the reservoir fluids and the water flow rate; and
In the log analysis, measured and calibrated values of N/F and C/O are used in equations 1 and 2. Equations 1-3 are then solved for the oil, water, and gas holdups. Benlakhdar at pg. 3.
generating a multiphase oil and water flow profile using the total flow rate, the oil flow rate, and the water flow rate that models flow behavior
To implement the calculation of pseudo-APL holdups from PN holdups, a workflow was developed as shown in Fig. 5. The calculated PN holdups are imported into the production logging interpretation software and based on the fluid phase combinations, a selection is made between one of the three utilities. This utility allows calculations of a single phase holdup for each of the 48 probes in a customized capacitance tool defined specifically for this interpretation. Data from this tool can then be combined with other APL tools, such as Spinner Array, for further processing using the layered profile approach described earlier. Benlakhdar at pg. 5.
Benlakhdar is analogous art to the claimed invention because both are directed to utilizing pulsed neutron logs to determine oil/water faction flow velocities in a multi-phase well. It would have been obvious to a person having ordinary skill in the art, before the effective filing date of the claimed invention, to combine Benlakhdar with Kremenetsky and Aslanyan to result in a system that generates a profile of fluid flows of individual phases of fluid (i.e., oil and water). Motivation to combine includes improved fluid flow analysis because pulsed neutron logs can be utilized to determine fluid factions in instances where other methods are deficient. For example, “Sometimes array sensors are not enough to meet the objective comprehensively and require Pulsed Neutron Logging: limitations in array sensors could be one or more as listed below… Low flow rates in horizontal wells means that fluid holdups in the stratified flow are very sensitive to the wellbore inclintation, and the higher water cut means a small portion of the flowing liquid will be oil. This holdup could be missed depends on sensors position.” Benlakhdar at pg. 2.
Claim 2
Aslanyan discloses:
identifying the inflow zones across a horizontal section of the well;
To solve these complex downhole logging problems, the hardware and software system of High-Definition Spectral Noise Logging has been developed. It can handle various tasks arising during downhole logging, including identification of flow zones in low-rate horizontal wells where conventional logging techniques (temperature, pressure, spinner, multiphase sensors) do not always provide decisive answers. Aslanyan at pg. 2.
extracting the thermal properties from the temperature log of the well corresponding to inflow zones identified by the noise log of the well.
Fig. 2 shows the integrated survey results. As a consequence of low flow rate observed in the well after stimulation, no decisive conclusion on the flow zones could be drawn from the conventional spinner data (See Fig. 2, SPINNER column). The HEX data indicate a minor flow from Zone 2. Aslanyan at pg. 4.
Fig. 2 illustrates the identified inflow intervals and the corresponding temperature logs at the “inflow zones.”
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Claim 3
Kremenetsky discloses:
wherein the different well conditions include static, transient, and flowing.
Two approaches can be applied to estimate relative flow rates based on the temperature survey results. The first is related to analyzing the downhole temperature distribution in case of long-term production. To successfully implement this, the logging shall be preceded during production without shutting the well. Production period duration must exceed the duration of the previous possible shut-in periods. The second is related to analyzing the temperature fluctuation rate immediately after a well drawdown is dramatically changed, or well is shutted. Its apparent advantage is that data on geothermal temperature distribution are not used. Kremenetsky at pg. 15.
Claim 4
Benlakhdar discloses:
executing an oxygen activation technique to determine a water velocity of the reservoir fluids, wherein data is extracted from the pulsed neutron log and used to calculate the water flow rate.
Pulsed neutron measurements utilizing oxygen activation techniques can provide a quantitative measurement of water velocity in either upward or downward direction (depending on configuration) in horizontal wells where spinners got damage or become sticky. Benlakhdar at pg. 6.
Claim 5
Benlakhdar discloses:
determining a water faction of the reservoir fluids, wherein the water faction is calculated from C/O ratios extracted from the pulsed neutron log and used to calculate the water flow rate.
The Pulsed Neutron Holdup Imager (PNHI) measurement described here employs a through tubing pulsed neutron logging instrument designed to measure inelastic carbon-to-oxygen (C/O) and inelastic near-to-far (N/F) gamma ray ratios. The instrument also measures the formation macroscopic capture cross section, sigma (∑), and additional thermal neutron capture data. While the capture information is not used in the holdup algorithm, it is acquired simultaneously while logging. The measured inelastic C/O and N/F ratios are used in a linear algorithm in combination with Monte Carlo (MCNP) modeling to determine three phase holdups. Benlakhdar at pp. 2-3.
Claim 6
Benlakhdar discloses:
wherein the water flow rate is based on, at least in part, a water velocity, a water faction, and a bore hole section area of the well.
When dealing with APL data, the hope is that the discrete values of holdups and velocity can be combined to define local flow. By integrating this information over the cross-section at every depth, we can produce phase rates, hence waving the need for slippage models. Benlakhdar at pg. 4.
The “cross-section” is analogous to “a borehole section.”
Claim 9
Kremenetsky discloses:
wherein the oil flow rate and water flow rate are used to determine cross flows of reservoir fluids in the well
After shutting a well down, cross-flowing begins within the commingled formations. Kremenetsky at pg. 4.
See also Figure 3 and Figure 4, illustrating the determined cross-flows based on a flow rate Q.
Claim 10
Aslanyan discloses:
A system, comprising: one or more memory modules; one or more hardware processors communicably coupled to the one or more memory modules, the one or more hardware processors configured to execute instructions stored on the one or more memory models to perform operations comprising:
To solve these complex downhole logging problems, the hardware and software system of High-Definition Spectral Noise Logging has been developed. It can handle various tasks arising during downhole logging, including identification of flow zones in low-rate horizontal wells where conventional logging techniques (temperature, pressure, spinner, multiphase sensors) do not always provide decisive answers. Aslanyan at pg. 2.
The remainder of the claim includes limitations that are substantially the same as claim 1. For at least the same reasons, and based on the same references as claim 1, claim 10 is rejected under 35 U.S.C. 103 as being obvious over Kremenetsky in view of Aslanyan and Benlakhdar.
Claims 11-15
Claims 11-15 recite substantially the same limitations as recited in claims 2-6. For at least the same reasons and based on the same references as the rejection of claims 2-6, claims 11-15 are rejected under 35 U.S.C. 103 as being obvious over Kremenetsky in view of Aslanyan and Benlakhdar.
Claim 17
Benlakhdar discloses:
An apparatus comprising a non-transitory, computer readable, storage medium that stores instructions that, when executed by at least one processor, cause the at least one processor to perform operations comprising:
The calculated PN holdups are imported into the production logging interpretation software and based on the fluid phase combinations, a selection is made between one of the three utilities. This utility allows calculations of a single phase holdup for each of the 48 probes in a customized capacitance tool defined specifically for this interpretation. Data from this tool can then be combined with other APL tools, such as Spinner Array, for further processing using the layered profile approach described earlier. Benlakhdar at pg. 5.
The remainer of claim 17 recites substantially the same limitations as claim 1. Accordingly, for at least the same reasons, and based on the same references as claim 1, claim 17 is rejected under 35 U.S.C. 103 as being obvious over Kremenetsky in view of Aslanyan and Benlakhdar.
Claims 18-20
Claims 18-20 recite substantially the same limitations as claims 2-4. Accordingly, and for at least the same reasons and based on the same references, claims 18-20 are rejected under 35 U.S.C. 103.
Conclusion
The prior art made of record and not relied upon is considered pertinent to applicant’s disclosure. Applicant is strongly encouraged to review the cited pertinent prior art as it includes disclosure directly related to both currently claimed subject matter as well as additional subject matter disclosed in the present Specification and not currently claimed:
Zhang, Shuang et al., “Efficient Flow Rate Profiling for Multiphase Flow in Horizontal Wells Using Downhole Temperature Measurement,” International Petroleum Technology Conference, (March 2019).
Poe et al., U.S. Patent Publication No. 2007/0108380: Previously cited reference, includes pertinent disclosure related to pulsed neutron logs and identifying faction percentages in a fluid.
Elather et al., U.S. Patent Publication No. 2021/0072422: Previously cited reference, includes pertinent disclosure related to identifying fracture formations in multiphase wells using sensor data.
Al-Enzini, et al., “Enhanced Flow Profile Evaluation by Combining Acoustic Noise Log and Thermal Modeling in Complex Design Wells,” Abu Dhabi International Petroleum Exhibition & Conference, 2020.
Aibazarov, et al., “The Application of Multi-Sensor Production Logging and Spectral Noise Logging Tools in Optimising Water Shut-off in a Carbonate Environment,” SPE Annual Caspian Technical Conference & Exhibition, Astana, Kazakhstan, November 2016.
Vlasov, et al., “Experience of Thermo-Hydrodynamic Studies of Wells in Combination with Noise Logging and Quantitative Interpretation of Data Based on the Simulator,” SPE Russian Petroleum Technology Conference, Moscow, Russia, October 2019.
Roscoe, et al., “Measurement of Oil and Water Flow Rates in a Horizontal Well With Chemical Markers and a Pulsed-Neutron Tool,” SPE Res Eng 12 (02): 94–103.
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.
Communication
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