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 . The rejections from the Office Action of 3/11/2026 are hereby withdrawn. New grounds for rejection are presented below.
Claim Rejections - 35 USC § 112
The following is a quotation of 35 U.S.C. 112(b):
(b) CONCLUSION.—The specification shall conclude with one or more claims particularly pointing out and distinctly claiming the subject matter which the inventor or a joint inventor regards as the invention.
The following is a quotation of 35 U.S.C. 112 (pre-AIA ), second paragraph:
The specification shall conclude with one or more claims particularly pointing out and distinctly claiming the subject matter which the applicant regards as his invention.
Claim 3 is rejected under 35 U.S.C. 112(b) or 35 U.S.C. 112 (pre-AIA ), second paragraph, as being indefinite for failing to particularly point out and distinctly claim the subject matter which the inventor or a joint inventor (or for applications subject to pre-AIA 35 U.S.C. 112, the applicant), regards as the invention.
Claim 3 changes the scope of the first element of Claim 1 by changing the NMR log from being present to being optional. This leaves the scope of Claim 3 unclear.
The following is a quotation of 35 U.S.C. 112(d):
(d) REFERENCE IN DEPENDENT FORMS.—Subject to subsection (e), a claim in dependent form shall contain a reference to a claim previously set forth and then specify a further limitation of the subject matter claimed. A claim in dependent form shall be construed to incorporate by reference all the limitations of the claim to which it refers.
The following is a quotation of pre-AIA 35 U.S.C. 112, fourth paragraph:
Subject to the following paragraph [i.e., the fifth paragraph of pre-AIA 35 U.S.C. 112], a claim in dependent form shall contain a reference to a claim previously set forth and then specify a further limitation of the subject matter claimed. A claim in dependent form shall be construed to incorporate by reference all the limitations of the claim to which it refers.
Claim 9 is rejected under 35 U.S.C. 112(d) or pre-AIA 35 U.S.C. 112, 4th paragraph, as being of improper dependent form for failing to further limit the subject matter of the claim upon which it depends, or for failing to include all the limitations of the claim upon which it depends. Claim 9 depends from Claim 1 and recites an identical limitation to that already recited in Claim 1; Claim 9 fails to further limit the scope of Claim 1. Applicant may cancel the claim(s), amend the claim(s) to place the claim(s) in proper dependent form, rewrite the claim(s) in independent form, or present a sufficient showing that the dependent claim(s) complies with the statutory requirements.
Claim Rejections - 35 USC § 103
In the event the determination of the status of the application as subject to AIA 35 U.S.C. 102 and 103 (or as subject to pre-AIA 35 U.S.C. 102 and 103) is incorrect, any correction of the statutory basis (i.e., changing from AIA to pre-AIA ) for the rejection will not be considered a new ground of rejection if the prior art relied upon, and the rationale supporting the rejection, would be the same under either status.
The following is a quotation of 35 U.S.C. 103 which forms the basis for all obviousness rejections set forth in this Office action:
A patent for a claimed invention may not be obtained, notwithstanding that the claimed invention is not identically disclosed as set forth in section 102, if the differences between the claimed invention and the prior art are such that the claimed invention as a whole would have been obvious before the effective filing date of the claimed invention to a person having ordinary skill in the art to which the claimed invention pertains. Patentability shall not be negated by the manner in which the invention was made.
Claim(s) 1-5 and 8-20 is/are rejected under 35 U.S.C. 103 as being unpatentable over Aldred (US 10400590 B1), Galford et al. (US 20160274266 A1)[hereinafter “Galford”], and Lafitte et al. (US 20170145285 A1)[hereinafter “Lafitte”].
Regarding Claim 1, Aldred discloses a process, comprising:
combining at least two downhole logs including a nuclear magnetic resonance (NMR) log and at least one of an induction resistivity log, a bulk density log, or an epithermal neutron porosity log into input data [Column 3 line 53 to Column 5 line 33 discloses “tri-axial induction measurements which have been modelled into vertical and horizontal resistivities,” “bulk density,” “Epithermal Neutron porosity,” “Elemental Capture Spectroscopy,” and “Nuclear Magnetic Resonance logs” as log measurement data for use as input data.];
using an interpretation method, including exploratory factor analysis of the NMR log, to convert the input data into interpretative data including geological facies information and poro-fluid distributions [Column 4 lines 64-67 – “Log measurement data may include some or all of the following:… Permeability logs generated from processing of data such as NMR, Stoneley Wave, from rock typing including porosity/permeability transforms for different electrofacies, or from probe permeameter on core slabs”Column 5 lines 41-42 – “interpretation techniques are used to infer the properties of the reservoir.”Column 5 lines 43-51 – “The interpretation techniques have many different forms depending on the data available and the formation type being assessed. The two principal modes of interpretation techniques that have dominated petrophysics include deterministic workflows, where individual petrophysical properties are determined in a step-by-step process, and optimizing systems, where log measurements are simultaneously modeled in order to evaluate the composition of the rock in terms of volumes of minerals and fluids.”]; and
using elemental analysis to convert the interpretative data into at least one formation model [Column 6 lines 45-56 – “In embodiments of the present invention described herein, 3D Formation Evaluation (3DFE) may be used to model a rock formation more accurately, taking into account not only the minerals and fluids present, but also the structure of the rock, formation properties, or rock types, by using directional measurements. 3DFE modeling of geological cells is a “low resolution technique”, so the individual beds are not defined. Furthermore, rather than defining the individual minerals and fluids present in the formation, this technique defines the content in terms of rock types, or rock components, with a measure of the degree of mixing of components in each direction fundamental to the model.”].
Aldred fails to disclose using elemental analysis, including NMR factor analysis and porosity partitioning based on established T² cutoffs, to convert the interpretative data into at least one formation model that includes micro-pore, meso-pore, and macro-pore classifications.
However, Galford discloses using elemental analysis, including NMR factor analysis and porosity partitioning based on established T² cutoffs [See Fig. 5 and Paragraph [0046] – “For example, and with reference to FIG. 5, micro/meso and meso/macro porosity break-over points corresponding to 0.5 and 5 micron pore radii in a limestone formation are represented by line 510 and line 520.”], to convert data into at least one formation model that includes micro-pore, meso-pore, and macro-pore classifications [See Paragraph [0016]]. It would have been obvious to use such an approach to better assess the subsurface.
Aldred, as modified, would disclose acquiring formation properties, including porosity and permeability derived from the porosity partitioning [per Galford], from the at least one formation model [Column 6 lines 56-59 – “From these rock components, the porosity, permeability and fluid content can be determined with greater accuracy than with conventional models.”].
Aldred discloses validating formation properties using capillary pressure measurements of a core sample [Column 9 lines 30-34 – “If no usable conductivity measurements are available then fluid saturations based on capillary pressure data from core samples, along with permeability interpretation from the model may be used.”], but fails to disclose that the process further comprises validating the formation properties using mercury injection capillary pressure measurements of a core sample.
However, Lafitte discloses using mercury injection capillary pressure measurements of a core sample to evaluate pore sizes [See Paragraph [0154] and the corresponding Table – “The sandstone cores were analyzed by mercury injection capillary pressure tests. Results of the pores size distribution of the different samples are highlighted in the table below.”]. It would have been obvious to perform such a technique to better characterize the subsurface.
Aldred, as modified, would disclose creating a reservoir quality classification, associated with formation depth and geological facies, from the formation properties [Column 6 lines 59-61 – “Petrophysicists may upscale the 3DFE models of the geological cells and incorporate them into a larger scale reservoir model as will be described later.”Column 10 lines 29-33 – “Rock layers with rock types of high porosity and high permeability are typically indicative of a layer in which hydrocarbons are trapped (e.g., reservoir quality rock). Similarly, rock layers with low porosity and low permeability are not indicative of layers with trapped hydrocarbon.”Column 15 lines 50-62 – “A ‘reservoir summary’ is a listing of the individual reservoir units, layers, intervals or formations, and is common to all forms of petrophysical interpretation. Essentially, a reservoir summary of an oil reservoir is made using the reservoir model with the upscaled distribution of rock types. There are some variations in the detail of summaries, but in general, the listing typically gives the following information for each unit: Top Depth, Bottom Depth, Gross thickness Definition of ‘net reservoir’ and ‘net pay’ which are the parts of the interval that are considered reservoir quality rock and reservoir quality rock including quantities of hydrocarbon, respectively.”]; and
performing one or more physical downhole operations, including at least one of drilling, perforating, or hydrocarbon production, using the reservoir quality classification to select a preferred downhole operation location [Column 17 lines 20-34 – “The resulting reservoir model can then be used as a starting point for building a new 3DFE model along the planned trajectory of a new high angle well. As the well is drilled, the existing model is compared to the data recorded from the new well, thereby allowing the drillers to be able to steer the new well with greatly increased confidence than previously available. This is a process known as ‘geosteering’.If horizontal well 12 is about to be drilled through a reservoir, the drillers may need to know whether or not wellbore 14 is being drilled through oil bearing layer 15 and, if not, whether to change direction of the well up or down. Essentially, the reservoir model with the upscaled distribution of rock types may be used to compute an angle or trajectory for drilling the well.”].
Regarding Claim 2, Aldred discloses that the at least two downhole logs include one or more open-hole logs [Column 7 lines 1-8 – “A measurement sensor 32 which measures the different measurements data that are used to characterize and evaluate the rock formation communicates with processor 34 via a sensor interface 33. Sensor 32 may not only include log measurement sensors and logging tools, but also sensor and devices for analyzing rock and fluid samples taken at different depths from the wellbore during drilling.”Column 17 lines 20-27 – “The resulting reservoir model can then be used as a starting point for building a new 3DFE model along the planned trajectory of a new high angle well. As the well is drilled, the existing model is compared to the data recorded from the new well, thereby allowing the drillers to be able to steer the new well with greatly increased confidence than previously available. This is a process known as ‘geosteering’.”The log data being of an “open-hole log” type as measurements are taken during drilling, which would be prior to borehole completion.], one or more cased-hole logs, or a combination of one or more open-hole logs and one or more cased-hole logs.
Regarding Claim 3, Aldred discloses that the at least two downhole logs comprise at least two of: an induction resistivity log, a bulk density log, an epithermal neutron porosity log, a spectroscopy log, or a nuclear magnetic resonance log [Column 3 line 53 to Column 5 line 33 discloses “tri-axial induction measurements which have been modelled into vertical and horizontal resistivities,” “bulk density,” “Epithermal Neutron porosity,” “Elemental Capture Spectroscopy,” and “Nuclear Magnetic Resonance logs” as log measurement data for use as input data.].
Regarding Claim 4, Aldred discloses that the interpretation method includes exploratory factor analysis [Column 5 lines 43-51 – “The interpretation techniques have many different forms depending on the data available and the formation type being assessed. The two principal modes of interpretation techniques that have dominated petrophysics include deterministic workflows, where individual petrophysical properties are determined in a step-by-step process, and optimizing systems, where log measurements are simultaneously modeled in order to evaluate the composition of the rock in terms of volumes of minerals and fluids.”This being an “exploratory factor” analysis because it is used for hydrocarbon exploration purposes (Column 17 lines 28-34 – “If horizontal well 12 is about to be drilled through a reservoir, the drillers may need to know whether or not wellbore 14 is being drilled through oil bearing layer 15 and, if not, whether to change direction of the well up or down. Essentially, the reservoir model with the upscaled distribution of rock types may be used to compute an angle or trajectory for drilling the well.”).].
Regarding Claim 5, Aldred discloses that the interpretative data includes geological facies information [Column 5 lines 43-51 – “The interpretation techniques have many different forms depending on the data available and the formation type being assessed. The two principal modes of interpretation techniques that have dominated petrophysics include deterministic workflows, where individual petrophysical properties are determined in a step-by-step process, and optimizing systems, where log measurements are simultaneously modeled in order to evaluate the composition of the rock in terms of volumes of minerals and fluids.”].
Regarding Claim 8, although Aldred discloses the use of NMR logs as log data [Column 3 line 53 to Column 5 line 33 discloses “tri-axial induction measurements which have been modelled into vertical and horizontal resistivities,” “bulk density,” “Epithermal Neutron porosity,” “Elemental Capture Spectroscopy,” and “Nuclear Magnetic Resonance logs” as log measurement data for use as input data.], Aldred fails to disclose that the elemental analysis includes establishing T2 cutoffs.
However, Galford discloses establishing T2 cutoffs as part sorting interpretative data according to geological facies information [See Fig. 5 and Paragraph [0046] – “For example, and with reference to FIG. 5, micro/meso and meso/macro porosity break-over points corresponding to 0.5 and 5 micron pore radii in a limestone formation are represented by line 510 and line 520.”]. It would have been obvious to perform such a sorting step in order to better characterize rock types.
Regarding Claim 9, Aldred discloses validating formation properties using capillary pressure measurements of a core sample [Column 9 lines 30-34 – “If no usable conductivity measurements are available then fluid saturations based on capillary pressure data from core samples, along with permeability interpretation from the model may be used.”], but fails to disclose that the process further comprises validating the formation properties using mercury injection capillary pressure measurements of a core sample.
However, Lafitte discloses using mercury injection capillary pressure measurements of a core sample to evaluate pore sizes [See Paragraph [0154] and the corresponding Table – “The sandstone cores were analyzed by mercury injection capillary pressure tests. Results of the pores size distribution of the different samples are highlighted in the table below.”]. It would have been obvious to perform such a technique to better characterize the wellbore.
Regarding Claim 10, Aldred discloses that the reservoir quality classification includes a quality rating system [Column 6 lines 59-61 – “Petrophysicists may upscale the 3DFE models of the geological cells and incorporate them into a larger scale reservoir model as will be described later.”Column 10 lines 29-33 – “Rock layers with rock types of high porosity and high permeability are typically indicative of a layer in which hydrocarbons are trapped (e.g., reservoir quality rock). Similarly, rock layers with low porosity and low permeability are not indicative of layers with trapped hydrocarbon.”Column 15 lines 50-62 – “A ‘reservoir summary’ is a listing of the individual reservoir units, layers, intervals or formations, and is common to all forms of petrophysical interpretation. Essentially, a reservoir summary of an oil reservoir is made using the reservoir model with the upscaled distribution of rock types. There are some variations in the detail of summaries, but in general, the listing typically gives the following information for each unit: Top Depth, Bottom Depth, Gross thickness Definition of ‘net reservoir’ and ‘net pay’ which are the parts of the interval that are considered reservoir quality rock and reservoir quality rock including quantities of hydrocarbon, respectively.”] associated with formation depth [Column 8 lines 8-10 – “Geological cells 75 are defined along the depth of wellbore 70 as shown in FIG. 3.”].
Regarding Claim 11, Aldred discloses that the quality rating system includes a carbonate reservoir porosity partitioning [Column 13 lines 54-61 – “In some embodiments of the present invention, the petrophysicist assesses which method is going to be used to define fluid content, based on measurements available and the formation type. If resistivity data is to be used, then there are three possible model types: Model A: Rock components are quantified using hydrocarbon corrected log data and conventional saturation equations are used for fluid saturations.”Column 14 lines 15-23 – “In this technique, a range is defined as being made up of different types of rock, such as thin beds of multiple types or a gradual change from one extreme of a rock type to another or even, for some complex carbonates, the rock could be made up of separate porous matrix, vugs and fractures. These are termed ‘rock components’ and they are quantified in each cell. The properties for the complete rock are then derived using any conventional petrophysical technique.”].
Regarding Claim 12, Aldred discloses that the quality rating system includes a distribution of porosity and associated permeability of a carbonate reservoir [Column 13 lines 54-61 – “In some embodiments of the present invention, the petrophysicist assesses which method is going to be used to define fluid content, based on measurements available and the formation type. If resistivity data is to be used, then there are three possible model types: Model A: Rock components are quantified using hydrocarbon corrected log data and conventional saturation equations are used for fluid saturations.”Column 14 lines 15-23 – “In this technique, a range is defined as being made up of different types of rock, such as thin beds of multiple types or a gradual change from one extreme of a rock type to another or even, for some complex carbonates, the rock could be made up of separate porous matrix, vugs and fractures. These are termed ‘rock components’ and they are quantified in each cell. The properties for the complete rock are then derived using any conventional petrophysical technique.”].
Regarding Claim 13, Aldred discloses that the preferred downhole operation location is based on the quality rating system [Column 17 lines 28-34 – “If horizontal well 12 is about to be drilled through a reservoir, the drillers may need to know whether or not wellbore 14 is being drilled through oil bearing layer 15 and, if not, whether to change direction of the well up or down. Essentially, the reservoir model with the upscaled distribution of rock types may be used to compute an angle or trajectory for drilling the well.”].
Regarding Claim 14, Aldred discloses that the elemental analysis includes a producible hydrocarbon porosity prediction [Column 6 lines 45-56 – “In embodiments of the present invention described herein, 3D Formation Evaluation (3DFE) may be used to model a rock formation more accurately, taking into account not only the minerals and fluids present, but also the structure of the rock, formation properties, or rock types, by using directional measurements. 3DFE modeling of geological cells is a “low resolution technique”, so the individual beds are not defined. Furthermore, rather than defining the individual minerals and fluids present in the formation, this technique defines the content in terms of rock types, or rock components, with a measure of the degree of mixing of components in each direction fundamental to the model.”Column 10 lines 29-33 – “Rock layers with rock types of high porosity and high permeability are typically indicative of a layer in which hydrocarbons are trapped (e.g., reservoir quality rock). Similarly, rock layers with low porosity and low permeability are not indicative of layers with trapped hydrocarbon.”Column 15 lines 50-62 – “A ‘reservoir summary’ is a listing of the individual reservoir units, layers, intervals or formations, and is common to all forms of petrophysical interpretation. Essentially, a reservoir summary of an oil reservoir is made using the reservoir model with the upscaled distribution of rock types. There are some variations in the detail of summaries, but in general, the listing typically gives the following information for each unit: Top Depth, Bottom Depth, Gross thickness Definition of ‘net reservoir’ and ‘net pay’ which are the parts of the interval that are considered reservoir quality rock and reservoir quality rock including quantities of hydrocarbon, respectively.”].
Regarding Claim 15, Aldred discloses that the elemental analysis includes a carbonate formation permeability prediction [Column 6 lines 45-56 – “In embodiments of the present invention described herein, 3D Formation Evaluation (3DFE) may be used to model a rock formation more accurately, taking into account not only the minerals and fluids present, but also the structure of the rock, formation properties, or rock types, by using directional measurements. 3DFE modeling of geological cells is a “low resolution technique”, so the individual beds are not defined. Furthermore, rather than defining the individual minerals and fluids present in the formation, this technique defines the content in terms of rock types, or rock components, with a measure of the degree of mixing of components in each direction fundamental to the model.”Column 10 lines 29-33 – “Rock layers with rock types of high porosity and high permeability are typically indicative of a layer in which hydrocarbons are trapped (e.g., reservoir quality rock). Similarly, rock layers with low porosity and low permeability are not indicative of layers with trapped hydrocarbon.”Column 15 lines 50-62 – “A ‘reservoir summary’ is a listing of the individual reservoir units, layers, intervals or formations, and is common to all forms of petrophysical interpretation. Essentially, a reservoir summary of an oil reservoir is made using the reservoir model with the upscaled distribution of rock types. There are some variations in the detail of summaries, but in general, the listing typically gives the following information for each unit: Top Depth, Bottom Depth, Gross thickness Definition of ‘net reservoir’ and ‘net pay’ which are the parts of the interval that are considered reservoir quality rock and reservoir quality rock including quantities of hydrocarbon, respectively.”].
Regarding Claim 16, the combination would disclose generating a plurality of graphical outputs including:
an NMR-T² distribution and T² cutoffs chart [See Fig. 5 of Galford];
an NMR cumulative pore volumes and porosity chart [See Fig. 9B and Paragraph [0058] of Galford – “Track 4 (940) displays the volumes of the three primary porosity groups obtained from fitting five Gaussian functions to the measured T.sub.2 relaxation distribution which is shown in Track 5 (950).”];
a micro-pore, meso-pore, and macro-pore volume chart [See Fig. 7 of Galford]; and
a permeability chart [Column 4 lines 64-67 of Aldred – “Log measurement data may include some or all of the following:… Permeability logs generated from processing of data such as NMR, Stoneley Wave, from rock typing including porosity/permeability transforms for different electrofacies, or from probe permeameter on core slabs”]; and
analyzing data shown in the plurality of graphical outputs to generate an NMR poro-fluid facies chart [Column 4 lines 64-67 of Aldred – “Log measurement data may include some or all of the following:… Permeability logs generated from processing of data such as NMR, Stoneley Wave, from rock typing including porosity/permeability transforms for different electrofacies, or from probe permeameter on core slabs”Column 5 lines 41-42 of Aldred – “interpretation techniques are used to infer the properties of the reservoir.”Column 5 lines 43-51 of Aldred – “The interpretation techniques have many different forms depending on the data available and the formation type being assessed. The two principal modes of interpretation techniques that have dominated petrophysics include deterministic workflows, where individual petrophysical properties are determined in a step-by-step process, and optimizing systems, where log measurements are simultaneously modeled in order to evaluate the composition of the rock in terms of volumes of minerals and fluids.”].
Regarding Claim 17, Aldred discloses that the NMR poro-fluid facies chart combines acquired and analyzed data to determine fluid and pore characteristics at a plurality of geological facies within the formation or reservoir [Column 4 lines 64-67 of Aldred – “Log measurement data may include some or all of the following:… Permeability logs generated from processing of data such as NMR, Stoneley Wave, from rock typing including porosity/permeability transforms for different electrofacies, or from probe permeameter on core slabs”Column 5 lines 41-42 of Aldred – “interpretation techniques are used to infer the properties of the reservoir.”Column 5 lines 43-51 of Aldred – “The interpretation techniques have many different forms depending on the data available and the formation type being assessed. The two principal modes of interpretation techniques that have dominated petrophysics include deterministic workflows, where individual petrophysical properties are determined in a step-by-step process, and optimizing systems, where log measurements are simultaneously modeled in order to evaluate the composition of the rock in terms of volumes of minerals and fluids.”].
Regarding Claim 18, Aldred discloses generating a reservoir quality classification chart that uses an NMR poro-fluid facies chart to qualify each geological facies as having at least one of favorable, unfavorable, or another qualified condition for the one or more physical downhole operations [Column 15 line 50 to Column 16 line 9 – “A ‘reservoir summary’ is a listing of the individual reservoir units, layers, intervals or formations, and is common to all forms of petrophysical interpretation. Essentially, a reservoir summary of an oil reservoir is made using the reservoir model with the upscaled distribution of rock types. … For the net reservoir and net pay in each unit the average property values are usually noted, including average shale volume, average porosity (total and effective), average and geometric mean permeability and, for net pay, the average water saturation The amount of hydrocarbon in place in one dimensional sense, expressed as hydrocarbon pore fraction or equivalent hydrocarbon column”].
Regarding Claim 19, Aldred discloses that favorable conditions in the reservoir quality classification chart show the preferred downhole operation location based upon the formation depth and/or geological facies [Column 17 lines 20-34 – “The resulting reservoir model can then be used as a starting point for building a new 3DFE model along the planned trajectory of a new high angle well. As the well is drilled, the existing model is compared to the data recorded from the new well, thereby allowing the drillers to be able to steer the new well with greatly increased confidence than previously available. This is a process known as ‘geosteering’.If horizontal well 12 is about to be drilled through a reservoir, the drillers may need to know whether or not wellbore 14 is being drilled through oil bearing layer 15 and, if not, whether to change direction of the well up or down. Essentially, the reservoir model with the upscaled distribution of rock types may be used to compute an angle or trajectory for drilling the well.”].
Regarding Claim 20, Aldred discloses the recited one or more processors and memory [See Fig. 2] and the remaining subject matter would have been obvious (see the rejection of Claims 1 and 16, above).
Claim(s) 6 is/are rejected under 35 U.S.C. 103 as being unpatentable over Aldred (US 10400590 B1); Galford et al. (US 20160274266 A1)[hereinafter “Galford”]; Lafitte et al. (US 20170145285 A1)[hereinafter “Lafitte”]; Ramamoorthy et al., A New Workflow For Petrophysical and Textural Evaluation of Carbonate Reservoirs, SPWLA, 2008 (disclosed by the Applicant in the IDS of 9/22/2023); and Donaldson et al. (US 20160178545 A1)[hereinafter “Donaldson”].
Regarding Claim 6, although Aldred discloses the use of NMR logs as log data [Column 3 line 53 to Column 5 line 33 discloses “tri-axial induction measurements which have been modelled into vertical and horizontal resistivities,” “bulk density,” “Epithermal Neutron porosity,” “Elemental Capture Spectroscopy,” and “Nuclear Magnetic Resonance logs” as log measurement data for use as input data.], Aldred fails to disclose that the elemental analysis includes sorting interpretative data according to geological facies information to provide sorted interpretative data and applying a logarithmic transformation and square function to the sorted interpretative data.
However, Ramamoorthy discloses sorting interpretative data according to geological facies information to provide sorted interpretative data [See the sorting of NMR data based on porosity type in Fig. 6 and related text as a form of “porosity partitioning.”]. It would have been obvious to perform such a sorting step in order to better characterize rock types.
Donaldson discloses applying a logarithmic transformation and square function to NMR data [Paragraph [0008] – “In some examples, the function of an NMR parameter that is analyzed is a function of the T.sub.2 of the sample. In some examples, the T.sub.2 function is a linear mean (first moment) of T.sub.2, <T.sub.2>, as a function of pressure or temperature. In some examples, the T.sub.2 function is a logarithmic mean of T.sub.2, T.sub.2LM, as a function of pressure or temperature. In some examples, the T.sub.2 function is linear mean of the square of T.sub.2 divided by the linear mean of T.sub.2, <T.sub.2.sup.2>/<T.sub.2>, as a function of pressure or temperature.”]. It would have been obvious to use such transformations in order to better characterize hydrocarbon fluids present in the wellbore.
Claim(s) 7 is/are rejected under 35 U.S.C. 103 as being unpatentable over Aldred (US 10400590 B1), Galford et al. (US 20160274266 A1)[hereinafter “Galford”], Lafitte et al. (US 20170145285 A1)[hereinafter “Lafitte”], and Lucas-Oliveira et al., Sandstone surface relaxivity determined by NMR T2 distribution and digital rock simulation for permeability evaluation, Elsevier, 2020 [hereinafter “Lucas-Oliveira”].
However, the first recited equation amounts to merely an application of an equation disclosed by Oliveira [See Equation 7].
The second recited equation amounts to merely an application of an equation disclosed by Oliveira [See Equation 11] using a known manner of representing pore size [See the equations in Paragraph [0053] of Galford]. The recited equations would have been considered obvious because they are known to be effective in making the recited calculations.
Response to Arguments
Applicant argues:
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Examiner’s Response:
The instant claims have been amended to recite “performing” the recited operations, not “directing” or “guiding” them and the rejections under 35 USC 101 are hereby withdrawn for that reason.
Applicant argues:
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Examiner’s Response:
The corresponding rejection is hereby withdrawn.
Applicant argues:
The amended claims overcome the prior art rejections from the Office Action of 3/11/2026.
Examiner’s Response:
The Examiner agrees. New grounds for rejection are presented above.
Conclusion
The prior art made of record and not relied upon is considered pertinent to applicant's disclosure:
Ramamoorthy et al., A New Workflow for Petrophysical and Textural Evaluation of Carbonate Reservoirs, PETROPHYSICS, 2010
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Applicant's amendment necessitated the new ground(s) of rejection presented in this Office action. Accordingly, THIS ACTION IS MADE FINAL. See MPEP § 706.07(a). Applicant is reminded of the extension of time policy as set forth in 37 CFR 1.136(a).
A shortened statutory period for reply to this final action is set to expire THREE MONTHS from the mailing date of this action. In the event a first reply is filed within TWO MONTHS of the mailing date of this final action and the advisory action is not mailed until after the end of the THREE-MONTH shortened statutory period, then the shortened statutory period will expire on the date the advisory action is mailed, and any nonprovisional extension fee (37 CFR 1.17(a)) pursuant to 37 CFR 1.136(a) will be calculated from the mailing date of the advisory action. In no event, however, will the statutory period for reply expire later than SIX MONTHS from the mailing date of this final action.
Any inquiry concerning this communication or earlier communications from the examiner should be directed to KYLE ROBERT QUIGLEY whose telephone number is (313)446-4879. The examiner can normally be reached 9AM-5PM EST.
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If attempts to reach the examiner by telephone are unsuccessful, the examiner’s supervisor, Arleen Vazquez can be reached at (571) 272-2619. The fax phone number for the organization where this application or proceeding is assigned is 571-273-8300.
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/KYLE R QUIGLEY/Primary Examiner, Art Unit 2857
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