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 .
Status of Claims
Claims 1, 3-10, 12-16, 18-20 are Rejected under 35 USC §101 Rejection.
Claims 2, 11 and 17 are Canceled Claims.
Remarks
Applicant’s arguments, filed (01/07/2026), with respect to pending claims 1, 3-10, 12-16, and 18-20 have been fully considered and are directed to claims as amended. The arguments addressed to the 101 rejection is not persuasive.
Arguments
The Applicant argues (Page 12, lines 17-25):
“The Applicants respectfully submit that the Examiner's analysis of Step 2A,
Prong 1 of the Alice framework is incorrect with respect to amended claims 1, 10, and
16. This is because the analysis does not take into consideration that the Applicants'
claims are specifically directed to a physical process - namely the process of fluid
injection. Claim 1 recites a method directed to performing a fluid injection. The fact that
the claim also includes steps directed to the manipulation of data to produce an estimated maximum reservoir pressure does not change the recitation that the claim is directed to a physical process - fluid injection. Thus, the Applicants' claims as amended are not directed to an abstract idea at all”.
and further the Applicant argues (page 14, lines 3-7):
“Examiner appears to merely reject claim 3 based on the fact that claim 3 is "merely an
additional abstract limitation" and appears to loosely group claim 2 and 3 together in the
rejection merely based on the reasoning that they both "recite performing an injection
operation based on computed reservoir pressure." Id. However, this was not the basis of the rejection of claim 3.”
The Examiner respectfully disagree and points, that new steps of “control performing the fluid injection operation…”, just controlling steps performed by the any computer/software and is merely insignificant extra solution activity.
Claims 1 and 3 do not directed to any physical activity/process is performed, e.g., actually perform the physical act/process of injection or controlling steps and claim do not describes how to perform the injection operation.
Similarly, with respect to Claim 3: the steps of “performing the fluid injection operation” correspond to the program steps, which could be performed by the program instruction running on the computer, which is insignificant additional steps.
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, 3-10, 12-16, and 18-20 are rejected under 35 U.S.C. 101 because the claimed invention is directed to an abstract idea without significantly more as addressed below.
The new 2019 Revised Patent Subject Matter Eligibility Guidance published in the Federal Register (Vol. 84 No. 4, Jan 7, 2019 pp 50-57) has been applied and the claims are deemed as being patent ineligible.
The current 35 USC 101 analysis is based on the current guidance (Federal Register vol. 79, No. 241. pp. 74618-74633). The analysis follows several steps. Step 1 determines whether the claim belongs to a valid statutory class. Step 2A prong 1 identifies whether an abstract idea is claimed. Step 2A prong 2 determines whether an abstract idea is integrated into a practical application. If the abstract idea is integrated into a practical application the claim is patent eligible under 35 USC 101. Last, step 2B determines whether the claims contain something significantly more than the abstract idea. In most cases the existence of a practical application predicates the existence of an additional element that is significantly more.
Under the Step 1 of the eligibility analysis, we determine whether the claims are to a
statutory category by considering whether the claimed subject matter falls within the four statutory categories of patentable subject matter identified by 35 U.S.C.
101: Process, machine, manufacture, or composition of matter. The below claim is considered to be in a statutory category (process).
Under Step 2A Prong 1, the independent claim 1 includes abstract ideas as highlighted (using a bold font) below.
“1. A method performing a fluid injection, comprising:
accessing first input data comprising sonic, density, and
mineralogy logs for a location of interest;
computing average formation static anisotropic elastic properties for the location of interest based on the first input data; computing a Biot’s coefficient and a stress path parameter based on the average formation static anisotropic elastic properties; computing a static anisotropic elastic distribution corresponding to the average formation static anisotropic elastic properties; computing a Biot’s coefficient distribution and a stress path distribution based on the static anisotropic elastic distribution; enforcing hysteresis on the stress path distribution; accessing second input data comprising an overburden stress, a minimum horizontal stress, an initial reservoir pressure, estimated fault/fracture Mohr-Coulomb frictional strength parameters, and a depleted pressure for the location of interest; computing a stress change due to depletion at the location of interest based on the second input data, the computed Biot’s coefficient, and the computed stress path parameter;
computing a first pressure distribution comprising a first range of potential maximum reservoir pressures for the location of interest prior to fracture/fault reactivation at the given depleted pressure, wherein the pressure distribution is computed based on the computed stress change due to depletion, the estimated fault/fracture Mohr- Coulomb frictional strength parameters, the computed Biot’s coefficient distribution, and the computed stress path distribution with hysteresis enforced; accessing third input data comprising properties corresponding to a second location for which a field estimate or a laboratory estimate of a maximum reservoir pressure prior to fracture/fault reactivation is available;
repeating the computation of the average formation static anisotropic elastic properties, the computation of the Biot’s coefficient and the stress path parameter, the computation of the static anisotropic elastic distribution, the computation of the Biot’s coefficient distribution and the stress path distribution, the enforcement of the hysteresis on the stress path distribution, and the computation of the stress change due to depletion for the second location; computing a second pressure distribution comprising a second range of potential maximum reservoir pressures for the second location prior to fracture/fault reactivation at the given depleted pressure;
computing a probability of non-exceedance for the field estimate or the laboratory estimate of the first maximum reservoir pressure prior to fracture/fault reactivation for the second location; computing a second maximum reservoir pressure for the location of interest prior to fracture/fault reactivation at the given depleted pressure based on the computed probability of non-exceedance and the computed first pressure distribution; and outputting the computed second maximum reservoir pressure as an estimated maximum reservoir pressure for performing a fluid injection operation for the location of interest; and
performing the fluid injection operation for the location of interest based on the estimated maximum reservoir pressure.”
“10. A computing system, comprising: a processor; and a non-transitory, computer-readable storage medium, comprising code configured to direct
the processor to:
access first input data comprising sonic, density, and mineralogy logs for a location of interest;
compute average formation static anisotropic elastic properties for the location of interest based on the first input data;
compute a Biot’s coefficient and a stress path parameter based on the average formation static anisotropic elastic properties;
compute a static anisotropic elastic distribution corresponding to the average formation static anisotropic elastic properties;
compute a Biot’s coefficient distribution and a stress path distribution based on the static anisotropic elastic distribution;
enforce hysteresis on the stress path distribution;
access second input data comprising an overburden stress, a minimum horizontal stress, an initial reservoir pressure, estimated fault/fracture Mohr-Coulomb frictional strength parameters, estimated fault/fracture Mohr-Coulomb frictional strength parameters, and a depleted pressure for the location of interest;
compute a stress change due to depletion at the location of interest based on the second input data, the computed Biot’s coefficient, and the computed stress path parameter;
compute a first pressure distribution comprising a first range of potential maximum reservoir pressures for the location of interest prior to fracture/fault reactivation at the given depleted pressure, wherein the pressure distribution is computed based on the computed stress change due to depletion, the estimated fault/fracture Mohr-Coulomb frictional strength parameters, the computed Biot’s coefficient distribution, and the computed stress path distribution with hysteresis enforced;
access third input data comprising properties corresponding to a second location for which a field estimate or a laboratory estimate of a maximum reservoir pressure prior to fracture/fault reactivation is available;
repeat the computation of the average formation static anisotropic elastic properties, the computation of the Biot’s coefficient and the stress path parameter, the computation of the static anisotropic elastic distribution, the computation of the Biot’s coefficient distribution and the stress path distribution, the enforcement of the hysteresis on the stress path distribution, and the computation of the stress change due to depletion for the second location; compute a second pressure distribution comprising a second range of potential maximum reservoir pressures for the second location prior to fracture/fault reactivation at the given depleted pressure; compute a probability of non-exceedance for the field estimate or the laboratory estimate of the first maximum reservoir prior to fracture/fault reactivation pressure for the second location; compute a second maximum reservoir pressure for the location of interest prior to fracture/fault reactivation at the given depleted pressure based on the computed probability of non-exceedance and the computed first pressure distribution; and output the computed second maximum reservoir pressure as an estimated maximum reservoir pressure for performing a fluid injection operation for the location of interest; and
control performing the fluid injection operation for the location of interest based on the estimated maximum reservoir pressure.”
“16. A non-transitory, computer-readable storage medium, comprising program instructions that are executable by a processor to cause the processor to:
access first input data comprising sonic, density, and mineralogy logs for a location of interest;
compute average formation static anisotropic elastic properties for the location of interest based on the first input data; compute a Biot’s coefficient and a stress path parameter based on the average formation static anisotropic elastic properties;
compute a static anisotropic elastic distribution corresponding to the average formation static anisotropic elastic properties;
compute a Biot’s coefficient distribution and a stress path distribution based on the static anisotropic elastic distribution;
enforce hysteresis on the stress path distribution;
access second input data comprising an overburden stress, a minimum horizontal stress, an initial reservoir pressure, estimated fault/fracture Mohr-Coulomb frictional strength parameters, and a depleted pressure for the location of interest;
compute a stress change due to depletion at the location of interest based on the second input data, the computed Biot’s coefficient, and the computed stress path parameter;
compute a first pressure distribution comprising a first range of potential maximum reservoir pressures for the location of interest prior to fracture/fault reactivation at the given depleted pressure, wherein the pressure distribution is computed based on the computed stress change due to depletion, the estimated fault/fracture Mohr- Coulomb frictional strength parameters, the computed Biot’s coefficient distribution, and the computed stress path distribution with hysteresis enforced;
access third input data comprising properties corresponding to a second location for which a field estimate or a laboratory estimate of a maximum reservoir pressure prior to fracture/fault reactivation is available;
repeat the computation of the average formation static anisotropic elastic properties, the computation of the Biot’s coefficient and the stress path parameter, the computation of the static anisotropic elastic distribution, the computation of the Biot’s coefficient distribution and the stress path distribution, the enforcement of the hysteresis on the stress path distribution, and the computation of the stress change due to depletion for the second location;
compute a second pressure distribution comprising a second range of potential maximum reservoir pressures for the second location prior to fracture/fault reactivation at the given depleted pressure;
compute a probability of non-exceedance for the field estimate or the laboratory estimate of the first maximum reservoir pressure prior to fracture/fault reactivation for the second location;
compute a second maximum reservoir pressure for the location of interest prior to fracture/fault reactivation at the given depleted pressure based on the computed probability of non-exceedance and the computed first pressure distribution; and
output the computed second maximum reservoir pressure as an estimated maximum reservoir pressure for performing a fluid injection operation for the location of interest; and
control performing the fluid injection operation for the location of interest based on the estimated maximum reservoir pressure.”
The highlighted steps is considered to be equivalent of a mathematical concepts and mathematical steps.
Under step 2A prong 2,
The Claim 1 does not comprise any additional elements into which the Abstract idea can be integrated to create a practical application.
The new limitations of “control performing the fluid injection operation for the location of interest based on the estimated maximum reservoir pressure” just insignificant extra solution activity, because controlling steps are perform by computer/software.
In consideration of step 2B, the claim does not include additional elements that are sufficient to amount to significantly more than the judicial exception because the new steps of “control performing the fluid injection operation…”, just controlling steps performed by the any computer/software and is merely insignificant extra solution activity.
There are not details of any physical activity perform, e.g., actually perform the physical act of injection and how to perform the injection operation.
Under step 2B
The claim 1 comprises an abstract idea, except the step of “accessing first input data comprising sonic, density, and mineralogy logs for a location of interest” and “access first input data comprising sonic, density, and mineralogy logs for a location of interest” of claims 10 and 16. That step is just obtaining the data, which is just insignificant extra solution activity.
In claims 1, 10 and 16:
The steps of “accessing second input data comprising an overburden stress, a minimum horizontal stress, an initial reservoir pressure, estimated fault/fracture Mohr-Coulomb frictional strength parameters,” and “accessing third input data comprising properties corresponding to a second location for which a field estimate or a laboratory estimate of a maximum reservoir pressure prior to fracture/fault reactivation is available”, in claim 1.
The steps of claim 10: “access second input data comprising an overburden stress, a minimum horizontal stress, an initial reservoir pressure, estimated fault/fracture Mohr-Coulomb frictional strength parameters, estimated fault/fracture Mohr-Coulomb frictional strength parameters, and a depleted pressure for the location of interest” and “access third input data comprising properties corresponding to a second location for which a field estimate or a laboratory estimate of a maximum reservoir pressure prior to fracture/fault reactivation is available’.
The steps of claim 16: “access second input data comprising an overburden stress, a minimum horizontal stress, an initial reservoir pressure, estimated fault/fracture Mohr-Coulomb frictional strength parameters, and a depleted pressure for the location of interest” and “access third input data comprising properties corresponding to a second location for which a field estimate or a laboratory estimate of a maximum reservoir pressure prior to fracture/fault reactivation is available”.
The accessing steps of claims 1, 10 and 16 just obtaining the data, and further describing the obtaining the type of data, which is just insignificant extra solution activity.
The claims do not recites real measurements steps.
The highlighted step above: “compute…”, “computed...” is considered to be equivalent of a mathematical concept and mental steps performed in the human mind (including observation and evaluation) including using a processor.
In claims 1, 10 and 16: the steps of “output the computed second maximum reservoir pressure as an estimated maximum reservoir pressure for performing a fluid injection operation for the location of interest” just outputting data, which is insignificant extra solution activity.
The depended claims 4-9, 12-15, and 18-20 are merely extend the details of the abstract idea of mathematical concepts.
Claim 3 recite the steps of “performing the fluid injection operation” based on computed reservoir pressure correspond to the steps in program , which could be performed by the computer, which is insignificant additional steps.
However the injection operation, according to claim 3 further comprises designing a compression/pumping capacity for the fluid injection operation based on the computed second maximum reservoir pressure, which is merely an additional abstract limitation.
Therefore claims 3-9, 12-15 and 18-20 are similarly rejected under 35 U.S.C. 101.
Examiner note regarding the prior art of the record:
Regarding Claims 1, 10 and 16:
Khan et al., (US Pub.20200284945A1) discloses para [0201], where reservoir stability analysis using Mohr-Coulomb criterion is presented below. The flow and transport of carbon dioxide along the reservoir is strongly dependent on the injection pressure. The more the injection pressure increases, the more the flow of carbon dioxide increases into the reservoir. For maximum storage capacity of carbon dioxide, it is desirable to increase the injection pressure;
(para [0111], where Mohr-Coulomb failure criterion is a mathematical model describing the failure of materials such as rocks due to shear stresses as well as normal stresses. The Mohr-Coulomb failure criterion represents the linear envelope that is obtained from a plot of the shear strength of a material versus the applied normal stress);
Also Khan discloses the excessive pressure buildup may cause horizontal stresses to decrease and can cause failure of the reservoir structure, including the caprock.
Both ground uplift during carbon dioxide injection and ground subsidence during the oil and gas productions may affect the infrastructure in the vicinity of the injection reservoir (para [0028]);
(para [0111], where Mohr-Coulomb criterion for shear failure is incorporated in the model in order to predict the stability of the reservoir. The Mohr-Coulomb failure criterion is a mathematical model describing the failure of materials such as rocks due to shear stresses as well as normal stresses. The Mohr-Coulomb failure criterion represents the linear envelope that is obtained from a plot of the shear strength of a material versus the applied normal stress);
[00199], TABLE-US-00003 TABLE 3 Formation properties for the simulation of CO2 injection into a carbonate reservoir. For under Model parameter reservoir caprock burden layer Rock density, 2400 1870 2550 ρ (Kg/m.sup.3) Young's modulus, 48.5 37.05 53.5 E (GPa) Bulk modulus, 39.24 23.75 34.5 K (GPa) Shear modulus, 18.1 13.8 19 9 G (GPa) Initial porosity, ∅m 0.13 0.01 0.10 Initial permeability, 0.6 0.00001 0.2 km (10.sup.−15 m.sup.2) Biot coefficient, α 0.8 0.2 0.4.
Liu et al (US Pub.20190369282A1) discloses new criterion takes into account the effects of natural fractures on rock strength degradation and also the intermediate principal stress on rock strength enhancement. Modified Hoek-Brown failure criterion reduces to the original Hoek-Brown failure criterion when the intermediate principal stress is equal to the minimal principal stress(para [005]); Para [0048] FIG. 3 shows an example of a tectonic regime 300 and examples of normal faulting 310, strike slip faulting 320 and thrust or reverse faulting 330. Stress may be defined, for example, as force per unit area acting on a plane. In a solid body, for example, a stress state at a point in the solid body may be described by orientations and magnitudes of three stresses called principal stresses, which are oriented perpendicular to each other (for example, orthogonal to each other);
(para [0003], where [0003] Understanding rock failure is essential in almost all projects related to subsurface rock formations. For example, such projects include design of tunnels, underground excavations in mining, and drilling in the oil and gas business. Many different criteria have been proposed to predict shear failure in rock formations, including Mohr-Coulomb criterion, Drucker-Prager criterion, Modified Lade criterion, and Hoek-Brown criterion).
Mohammadkazem Amiri “ Mechanical earth modeling and fault reactivation analysis for CO2- enhanced oil recovery in Gachsaran oil field, south-west of Iran” , Environmental Earth Sciences (2019) 78:112 https://doi.org/10.1007/s12665-019-8062-; 5 February , 2019 Pages 1-18; discloses (Abstract, where , mechanical and
strength properties of formation rocks (e.g., reservoir rock and caprock), in situ stress magnitudes and orientation and in situ pore pressure profile… Empirical correlations are obtained to convert dynamic rock properties and well-log data to static elastic properties and strength parameters. The initial in situ pore pressure is calculated using modified Eaton method. In situ stresses state is evaluated based on the poroelastic method and calibrated using LOT and XLOT tests. The orientation of in situ stresses is obtained based on image logs. Fractures and faults analysis is performed to determine their orientations. An analytical analysis is performed to estimate the maximum sustainable CO2 injection pressure to prevent fault reactivation. This study presents
a comprehensive method to reservoir and caprock characterization using laboratory and well-log data and 1D mechanical earth model. It helps the analysis of the geomechanical problems during CO2-EOR and provides the necessary information
to build 3D geomechanical model for numerical simulations); (Page 9, right col, para 2, where Biot’s effective stress coefficient can be calculated using Eq. 13
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Tare (US Pat.6609067B2) discloses (Col. 12, lines 32-42, where e) Rock Strength--Rock strength can be differentiated between two types--the compressive strength and the tensile strength. Rock strength is a critical input parameter along with the stresses and can be defined by various failure models. The existing real-time wellbore stability process includes but is not be limited to failure models such as the Mohr-Coulomb Failure Criterion, Drucker-Prager model, Modified Lade Criterion, Hoek and Brown Expression, Johnston and Chiu Model, Peak Strength Criterion, Uniaxial Compressive Strength limitation, etc.).
None of the above references fully disclose all the teachings of the following
Computing steps in the sequence in claims 1, 10 and 16:
Claims 3-9, 12-15 and 18-20 are not rejected as being dependent from an base claims 1, 10 and 16 respectfully.
NOTE: Currently there are no outstanding prior art rejection under 35 USC §102 or §103.
Conclusion
Applicant's amendment necessitated the new ground(s) of rejection presented in this Office action. Accordingly, THIS ACTION IS MADE FINAL. See MPEP § 706.07(a). Applicant is reminded of the extension of time policy as set forth in 37 CFR 1.136(a).
A shortened statutory period for reply to this final action is set to expire THREE MONTHS from the mailing date of this action. In the event a first reply is filed within TWO MONTHS of the mailing date of this final action and the advisory action is not mailed until after the end of the THREE-MONTH shortened statutory period, then the shortened statutory period will expire on the date the advisory action is mailed, and any nonprovisional extension fee (37 CFR 1.17(a)) pursuant to 37 CFR 1.136(a) will be calculated from the mailing date of the advisory action. In no event, however, will the statutory period for reply expire later than SIX MONTHS from the mailing date of this final action.
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/KALERIA KNOX/
Examiner, Art Unit 2857
/MICHAEL J DALBO/Primary Examiner, Art Unit 2857