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 .
Response to Arguments
112 Rejections
Based on applicant’s filed amendments, the previous 112(b) rejections have been overcome.
101 Rejections
Based on applicant’s filed amendments, the previous 101 rejections have been overcome.
103 Rejections
Applicant argues Jandhyala fails to teach or suggest data related to a formation surrounding the wellbore, however the examiner respectfully disagrees.
To assert applicant’s position, paragraph [0017] was cited. However, para. [0017] not only is interested in applicant’s asserted cement barrier but also the formation surrounding the wellbore, including rock properties, mechanics and mineral changes. Therefore, the examiner’s interpretation includes Jandhyala teaching data related to a formation surrounding the wellbore.
The examiner is not persuaded.
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, 3-7, 11, 13-16, 19 and 20 is/are rejected under 35 U.S.C. 103 as being unpatentable over Jandhyala et al. (2023/0112008) in view of Ma et al. (2017/0045636).
With respect to claim 1, Jandhyala et al. teaches a method comprising: injecting (via pump 26; Fig. 1) the first mass of the CO2 into the wellbore (as Jandhyala et al. teaches in [0032] structure for injecting a first mass of CO2 into a wellbore 6 at a predetermined flowrate, i.e. a first mass; [0036]); collecting a second set of wellbore data (using the various sensors disclosed in [0033]) associated with the formation (16) surrounding the wellbore (6) associated with the formation (16) surrounding the wellbore (6); identifying a change (as Jandhyala teaches in [0006] identifying a change) associated with the formation (16) surrounding the wellbore (as Jandhyala teaches the injection of CO2 react with minerals found in the wellbore; [0036]) based on the second set of wellbore data (via the sensors collecting data); estimating a quantity of the first mass of the CO2 that has been transformed into a mineral compound by a chemical reaction based on the identified change associated with the formation (as Jandhyala teaches in [0017]; “[t]he well barrier modeling applications can utilize computational fluid dynamics (CFD) modeling, geochemical modeling, rock mechanical model, and cement mechanical model to model a future state based on the injection rate of CO.sub.2 and the downhole environment changes from the dissolution of minerals within the formation and reaction of CO.sub.2 with set cement; hence Jandhyala teaches estimating a mass of CO2 that gets transferred in the surrounding minerals of the wellbore using computational fluid dynamics) and controlling further injection of CO2 into the wellbore (6) based on the estimated quantity of the first mass of the CO2 that has been transformed into the mineral (as Jandhyala et al. teaches changing the injection rate into a zone based on a change in the wellbore environment, i.e. the estimated quantity of CO2; [0006]).
Jandhyala et al. remains silent regarding collecting a first set of wellbore data before a first mass of carbon dioxide (CO2) is injected into a wellbore, wherein the first set of wellbore data is associated with a formation surrounding the wellbore.
Ma et al. teaches a similar method that includes collecting a first set of wellbore data before a first mass of carbon dioxide (CO2) is injected into a wellbore (see para. [0062]” [t]he microseismic data 151 can include information collected by sensors 136. The microseismic event data can include data collected from one or more stimulation treatments, which may include data collected before, during, or after a fluid injection), wherein the first set of wellbore data (i.e. the data collected before fluid injection; [0062]) is associated with a formation (defined by bubble 134 encircling the formation having microseismic events) surrounding a wellbore (102).
It would have been obvious to one of ordinary skill in the art before the effective filing of the instant invention to modify the method of Jandhyala et al. to include the data collection step before to CO2 injection into the identification step, as taught by Ma et al., because such a modification improves the accuracy of modeling by providing detailed data on the geologic formation prior to any chemical reactions due to injected fluids.
With respect to claim 11, Jandhyala et al. as modified teaches a non-transitory computer-readable storage media [0039] having embodied thereon instructions executable by one or more processors (considered to be a part of 112) to implement the rejection method of claim 1.
With respect to claim 3, Jandhyala et al. as modified teaches further comprising: transmitting a first acoustic signal into the materials of the formation while the first set of wellbore data is collected (as the combination, a whole teaches transmitting acoustic data [0034] of Jandhyala et al. before CO2 is injected into the formation, as taught by Ma et al.); and transmitting a second acoustic signal (via the sensors taught in Jandhyala et al.) into the materials of the formation while the second set of wellbore data is collected (i.e. during CO2 injection).
Note: claim 13 is rejected similar to claim 3.
With respect to claim 4, Jandhyala et al. as modified teaches further comprising: deploying one or more sensors along an inside surface of a casing of the wellbore (as Jandhyala et al. sensors being deployed to the surface of the casing of the wellbore; [0034]), wherein the one or more sensors [0033] sense the first and the second set of wellbore data based on being deployed on the inside surface of the casing [0033].
Note: claim 14 is rejected similar to claim 4.
With respect to claim 5, Jandhyala et al. as modified teaches wherein the casing includes an electrical insulating material (Jandhyala teaches the casing being made of cement 12, which is considered to be highly insulating).
Note: claim 15 is rejected similar to claim 5.
With respect to claim 6, Jandhyala et al. as modified teaches wherein the electrical insulating material of the casing (i.e. cement) resists corrosion (as cement is known to be corrosion resistant, insofar as to what level of resistance is structurally defined) and allows electromagnetic fields to propagate through the casing (as cement will allow EM fields to propagate through it, especially at lower frequencies).
With respect to claim 7, Jandhyala et al. as modified teaches wherein the change associated with the materials of the Earth (i.e. minerals found within the wellbore formed into the Earth) corresponds to a temperature difference associated with the injection of the first mass of the CO2 into the wellbore (as the modeling taught in Janhyala et al. used to identify change includes temperature data associated with wellbore during injection of CO2; [0017] [0019]).
Note: claim 16 is rejected similar to claim 7.
With respect to claim 19, Jandhyala et al. teaches an apparatus comprising: one or more sensors [0032-0033]; a CO2 source (36) that provides the first mass of the CO2 into the wellbore (6, as Jandhyala et al. teaches in [0032] structure for injecting a first mass of CO2 into a wellbore 6 at a predetermined flowrate, i.e. a first mass; [0036]), wherein the one or more sensors collects a second set of wellbore data (using the various sensors disclosed in [0033], data is collected after CO2 has been injected into the wellbore) associated with the formation (16) surrounding the wellbore (6) associated with the formation (16) surrounding the wellbore (6); a memory [0032]; and a processor [0032] that executes instructions out of the memory [0032] to; identify a change associated with a formation surrounding the wellbore (as Jandhyala teaches the injection of CO2 react with minerals found in the wellbore; [0036]) based on the second set of wellbore data (via the sensors collecting data); estimate a quantity of the first mass of the CO2 that has been transformed into a mineral compound by a chemical reaction based on the identified change associated with the formation (as Jandhyala teaches in [0017]; “[t]he well barrier modeling applications can utilize computational fluid dynamics (CFD) modeling, geochemical modeling, rock mechanical model, and cement mechanical model to model a future state based on the injection rate of CO.sub.2 and the downhole environment changes from the dissolution of minerals within the formation and reaction of CO.sub.2 with set cement; hence Jandhyala teaches estimating a mass of CO2 that gets transferred in the surrounding minerals of the wellbore using computational fluid dynamics) and controlling further injection of CO2 into the wellbore (6) based on the estimated quantity of the first mass of the CO2 that has been transformed into the mineral (as Jandhyala et al. teaches changing the injection rate into a zone based on a change in the wellbore environment, i.e. the estimated quantity of CO2; [0006]).
Jandhyala et al. remains silent regarding that collect a first set of wellbore data before a first mass of carbon dioxide (CO2) is injected into a wellbore, wherein the first set of wellbore data is associated with a formation surrounding the wellbore.
Ma et al. teaches a similar apparatus that includes collecting a first set of wellbore data before a first mass of carbon dioxide (CO2) is injected into a wellbore (see para. [0062]” [t]he microseismic data 151 can include information collected by sensors 136. The microseismic event data can include data collected from one or more stimulation treatments, which may include data collected before, during, or after a fluid injection), wherein the first set of wellbore data (i.e. the data collected before fluid injection; [0062]) is associated with a formation (defined by bubble 134 encircling the formation having microseismic events) surrounding a wellbore (102).
It would have been obvious to one of ordinary skill in the art before the effective filing of the instant invention to modify the method of Jandhyala et al. to include the data collection step prior to CO2 injection into the identification step, as taught by Ma et al., because such a modification improves the accuracy of modeling by providing detailed data on the geologic formation prior to any chemical reactions due to injected fluids.
Claim(s) 2, 12 and 20 is/are rejected under 35 U.S.C. 103 as being unpatentable over Jandhyala et al. (2023/0112008) in view of Ma et al. (2017/0045636), as applied to claim 1, further in view of Haghshenas et al. (2020/0011169).
With respect to claims 2, 12 and 20, Jandhyala et al. as modified teaches all that is claimed in the above rejection of claims 1, 11 and 19, but remains silent regarding the method further comprising: transmitting a first electromagnetic field into the formation while the first set of wellbore data is collected; and transmitting a second electromagnetic field into the formation while the second set of wellbore data is collected.
Haghshenas et al. teaches a similar method that includes electromagnetic field sensors [0018-0019] to sense data from a wellbore.
It would have been obvious to one of ordinary skill in the art before the effective filing of the instant invention to modify the method of Jandhyala et al. to include the sensors taught in Haghshenas et al. because such a modification increases the precision of data collection while providing non-contact.
Allowable Subject Matter
Claims 17-18 are objected to as being dependent upon a rejected base claim, but would be allowable if rewritten in independent form including all of the limitations of the base claim and any intervening claims.
Conclusion
The prior art made of record and not relied upon is considered pertinent to applicant's disclosure.
Tsuji et al. (2024/0060397) teaches injecting CO2 into a wellbore for the purpose of evaluating the wellbore.
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 MATTHEW G MARINI whose telephone number is (571)272-2676. The examiner can normally be reached Monday-Friday 8am-5pm.
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If attempts to reach the examiner by telephone are unsuccessful, the examiner’s supervisor, Stephen Meier can be reached at 571-272-2149. The fax phone number for the organization where this application or proceeding is assigned is 571-273-8300.
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/MATTHEW G MARINI/ Primary Examiner, Art Unit 2853
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