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 .
DETAILED ACTION
Election/Restrictions
Applicant’s election without traverse of Group I, claims 1-7, 10, 11, 19, 20, 27, 56, 57, and 66-69 in the reply filed on 13 February 2026 is acknowledged.
Claims 70 and 71 are withdrawn from further consideration pursuant to 37 CFR 1.142(b) as being drawn to a nonelected Invention, there being no allowable generic or linking claim.
Specification
The lengthy specification has not been checked to the extent necessary to determine the presence of all possible minor errors. Applicant’s cooperation is requested in correcting any errors of which applicant may become aware in the specification.
Claim Rejections - 35 USC § 112
The following is a quotation of the first paragraph of 35 U.S.C. 112(a):
(a) IN GENERAL.—The specification shall contain a written description of the invention, and of the manner and process of making and using it, in such full, clear, concise, and exact terms as to enable any person skilled in the art to which it pertains, or with which it is most nearly connected, to make and use the same, and shall set forth the best mode contemplated by the inventor or joint inventor of carrying out the invention.
The following is a quotation of the first paragraph of pre-AIA 35 U.S.C. 112:
The specification shall contain a written description of the invention, and of the manner and process of making and using it, in such full, clear, concise, and exact terms as to enable any person skilled in the art to which it pertains, or with which it is most nearly connected, to make and use the same, and shall set forth the best mode contemplated by the inventor of carrying out his invention.
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.
Claims 1-7, 10, 11, 19, 20, 27, 56, 57, and 66-69 are rejected under 35 U.S.C. 112(a) or 35 U.S.C. 112 (pre-AIA ), first paragraph, as failing to comply with the written description requirement. The claim(s) contains subject matter which was not described in the specification in such a way as to reasonably convey to one skilled in the relevant art that the inventor or a joint inventor, or for applications subject to pre-AIA 35 U.S.C. 112, the inventor(s), at the time the application was filed, had possession of the claimed invention.
Claims 1-7, 10, 11, 19, 20, 27, 56, 57, and 66-69 are rejected under 35 U.S.C. 112(a) or 35 U.S.C. 112 (pre-AIA ), first paragraph, because the specification, while being enabling for:
“a monitoring subsystem configured to monitor carbon mineralization in the active storage zone within the subterranean rock formation” wherein the monitoring subsystem is so configured using measuring equipment for “electromagnetic monitoring, magnetic monitoring, gravity monitoring, interferometric synthetic aperture radar monitoring, seismic monitoring, or fluid chemistry monitoring”, and “wherein the fluid injection well subsystem and the fluid production well subsystem operate based on measurements made by the monitoring subsystem to control the injection rate of the pressurized fluid and the inflow rate of the production fluid so as to maximize carbon storage potential of the subterranean rock formation via the carbon mineralization” wherein the carbon storage potential is maximized by following recommendations developed by an analysis module based on how much and where carbonate is being deposited throughout a process life cycle,
does not reasonably provide enablement for:
“a monitoring subsystem configured to monitor carbon mineralization in the active storage zone within the subterranean rock formation” wherein the monitoring subsystem is so configured using any/every possible equipment for monitoring carbon mineralization, and “wherein the fluid injection well subsystem and the fluid production well subsystem operate based on measurements made by the monitoring subsystem to control the injection rate of the pressurized fluid and the inflow rate of the production fluid so as to maximize carbon storage potential of the subterranean rock formation via the carbon mineralization” wherein the carbon storage potential is maximized using any/every possible algorithm for maximizing the carbon storage potential.
The specification does not enable any person skilled in the art to which it pertains, or with which it is most nearly connected, to make and/or use the invention commensurate in scope with these claims.
Claims 1-7, 10, 11, 19, 20, 27, 56, 57, and 66-69 are 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.
Independent claim 1 recites:
“a monitoring subsystem configured to monitor carbon mineralization in the active storage zone within the subterranean rock formation, wherein the fluid injection well subsystem and the fluid production well subsystem operate based on measurements made by the monitoring subsystem to control the injection rate of the pressurized fluid and the inflow rate of the production fluid so as to maximize carbon storage potential of the subterranean rock formation via the carbon mineralization.”
Regarding “a monitoring subsystem configured to monitor carbon mineralization in the active storage zone within the subterranean rock formation,” upon consultation with the Specification, the Office observes that Applicant discloses “The monitoring functions of the monitoring subsystem 190 may be performed by the measuring equipment 160. In such cases, one or more of the controllers 104 of the monitoring subsystem 190 may be used to control operation of the measuring equipment 160 and/or processing of the measurements made by the measuring equipment 160. The measuring equipment 160 may be any devices, components, apparatuses, and/or systems that are configured to assess or contribute to assessing one or more of the active storage zones 111 within the subterranean rock formation 110. For example, the measuring equipment 160 of the monitoring subsystem 190 may be configured to detect mineralized carbon in solid form that forms on the exposed rock surfaces of one or more of the active storage zones 111 within the subterranean rock formation. Examples of the measuring equipment 160 may be or include electromagnetic monitoring, magnetic monitoring, gravity monitoring, interferometric synthetic aperture radar monitoring, seismic monitoring, fluid chemistry monitoring (e.g., water chemistry monitoring), and CO2 content monitoring” ([0081]-[0082]) and details how this may be done for electromagnetic monitoring ([0083]-[0084]), magnetic monitoring ([0085]), gravity monitoring ([0086]-[0087]), interferometric synthetic aperture radar (InSAR) monitoring ([0088]), seismic monitoring ([0089]), and fluid chemistry monitoring ([0090]-[0091]). However, Applicant does not actually describe how the monitoring system may be configured to monitor carbon mineralization using CO2 content monitoring, nor does Applicant provide guidance on how to use other types of monitoring equipment to monitor carbon mineralization.
First, while there is a presumption that an adequate Written Description of the claimed invention is present in the Specification as filed, a question as to whether a Specification provides an adequate Written Description may arise in the context of an original claim. An original claim may lack Written Description support when (1) the claim defines the invention in functional language specifying a desired result but the disclosure fails to sufficiently identify how the function is performed or the result is achieved or (2) a broad Genus claim is presented but the disclosure only describes a narrow Species with no evidence that the Genus is contemplated. See MPEP 2163.03 Typical Circumstances Where Adequate Written Description Issue Arises.
In this case, (2) a broad Genus claim is presented (broadly encompassing “a monitoring subsystem configured to monitor carbon mineralization in the active storage zone within the subterranean rock formation” wherein the monitoring subsystem is so configured using any/every possible equipment for monitoring carbon mineralization) but the disclosure only describes a narrow Species (specifically, “a monitoring subsystem configured to monitor carbon mineralization in the active storage zone within the subterranean rock formation” wherein the monitoring subsystem is so configured using measuring equipment for “electromagnetic monitoring, magnetic monitoring, gravity monitoring, interferometric synthetic aperture radar monitoring, seismic monitoring, or fluid chemistry monitoring”) with no evidence that the Genus is contemplated. For example, Applicant has provided no direction or guidance on whether an operator could use other forms of monitoring equipment to monitor carbon mineralization, such as using pressure monitoring, temperature monitoring, spectroscopic monitoring, permeability monitoring, etc., nor how such other forms of monitoring equipment would be operated to monitor carbon mineralization. Similarly, although Applicant generically states that “CO2 content monitoring” ([0082]) may be used to monitor carbon mineralization, Applicant has not actually described how such CO2 content monitoring would be operated to monitor carbon mineralization, unlike the descriptions provided for electromagnetic monitoring, magnetic monitoring, gravity monitoring, interferometric synthetic aperture radar monitoring, seismic monitoring, and fluid chemistry monitoring ([0083]-[0091]).
Accordingly, one of ordinary skill would not reasonably believe Applicant possessed these other configurations to monitor carbon mineralization, and the claim lacks an adequate Written Description for its full scope.
Second, based on the foregoing, per In re Wands, 858 F.2d 731, 737, 8 USPQ2d 1400, 1404 (Fed. Cir. 1988), the following Undue Experimentation factors do not support a determination that the disclosure satisfies the Enablement requirement for the Full claim Scope: (A) breadth of claims; (D) level of ordinary skill; (F) direction provided; (G) working examples; and (H) quantity of experimentation needed. That is, five of the Wands factors do not support Enablement, four of which relates directly to the current claim scope (A/F/G/H).
Therefore, there exists a Scope of Enablement deficiency for the current claim.
Third, based on the foregoing, it is unclear which other forms of monitoring equipment may be used to monitor carbon mineralization or not, because Applicant has not disclosed how such other forms of monitoring equipment would be operated to monitor carbon mineralization. For example, it is unclear if using pressure monitoring equipment would provide “a monitoring subsystem configured to monitor carbon mineralization in the active storage zone within the subterranean rock formation” or not. Similarly, it is unclear if using temperature monitoring equipment would provide “a monitoring subsystem configured to monitor carbon mineralization in the active storage zone within the subterranean rock formation” or not. Also, it is unclear if using spectroscopic monitoring equipment would provide “a monitoring subsystem configured to monitor carbon mineralization in the active storage zone within the subterranean rock formation” or not. As well, it is unclear if using permeability monitoring equipment would provide “a monitoring subsystem configured to monitor carbon mineralization in the active storage zone within the subterranean rock formation” or not.
Accordingly, the claim scope is also rendered Indefinite.
Regarding “wherein the fluid injection well subsystem and the fluid production well subsystem operate based on measurements made by the monitoring subsystem to control the injection rate of the pressurized fluid and the inflow rate of the production fluid so as to maximize carbon storage potential of the subterranean rock formation via the carbon mineralization,” upon consultation with the Specification, the Office observes that Applicant discloses “In addition to developing construction plans and developing, initiating, monitoring, and adjusting fluid flow plans for well bores (e.g., production well bores 182, injection well bores 142) with respect to ech250 of the controller 104 may be configured to maximize the carbon storage potential of a rock formation within an active storage zone 111 by, for example, monitoring the carbonate deposition process throughout the process life cycle. To fully understand how the mineralization process is progressing within the rock within an active storage zone 111, the analysis module 250 may utilize information provided by the monitoring equipment 160 using one or multiple monitoring techniques that the monitoring equipment 160 is capable of achieving” ([0121]) and “In certain example embodiments, the analysis module 250 may use such information yielded from such techniques used by the monitoring equipment 160 to understanding how much and where carbonate is being deposited within an active storage zone 111. With such information, analysis module 250 may develop and provide specific steps that may be taken to control the overall mineralization process in such a way as to maximize the amount of permanently stored carbon in an active storage zone 111. Recommendations made by the analysis module 250 may include, but are not limited to, injection rates for pressurized fluid 143, chemical composition and form of the pressurized fluid 143, inflow rates of production fluid 183, settings and/or design of a FICS 148, settings and/or design of a FPCS 188, and future well placements (e.g., number of wellbores, types of wellbores, orientation (e.g., horizontal, vertical, non-vertical) of each wellbore, entry point of each wellbore) in the subterranean rock formation 11” ([0122]). However, Applicant does not actually describe how the fluid injection well subsystem and the fluid production well subsystem operate “based on” measurements… to control the injection rate of the pressurized fluid and the inflow rate of the production fluid “so as maximize the carbon storage potential of the subterranean rock formation via the carbon mineralization” other than by following recommendations developed by an analysis module based on how much and where carbonate is being deposited throughout a process life cycle.
First, regarding Written Description, in this case, (2) a broad Genus claim is presented (broadly encompassing “wherein the fluid injection well subsystem and the fluid production well subsystem operate based on measurements made by the monitoring subsystem to control the injection rate of the pressurized fluid and the inflow rate of the production fluid so as to maximize carbon storage potential of the subterranean rock formation via the carbon mineralization” wherein the carbon storage potential is maximized using any/every possible algorithm for maximizing the carbon storage potential) but the disclosure only describes a narrow Species (specifically, “wherein the fluid injection well subsystem and the fluid production well subsystem operate based on measurements made by the monitoring subsystem to control the injection rate of the pressurized fluid and the inflow rate of the production fluid so as to maximize carbon storage potential of the subterranean rock formation via the carbon mineralization” wherein the carbon storage potential is maximized by following recommendations developed by an analysis module based on how much and where carbonate is being deposited throughout a process life cycle) with no evidence that the Genus is contemplated. For example, Applicant has provided no direction or guidance on what other algorithms or methodologies may be used to control the pressurized fluid injection rate and production fluid inflow rate so as to maximize the carbon storage potential, such as if this may include, e.g., instantaneous responses to a specific measurement at a specific time, a pre-programmed array of decisions following data collected from prior treatments in other well systems, spur-of-the-moment decision-making by an on-site operator viewing the incoming measurements, etc.
Accordingly, one of ordinary skill would not reasonably believe Applicant possessed these other algorithms or methodologies to control the pressurized fluid injection rate and production fluid inflow rate so as to maximize the carbon storage potential, and the claim lacks an adequate Written Description for its full scope.
Second, based on the foregoing, per In re Wands, 858 F.2d 731, 737, 8 USPQ2d 1400, 1404 (Fed. Cir. 1988), the following Undue Experimentation factors do not support a determination that the disclosure satisfies the Enablement requirement for the Full claim Scope: (A) breadth of claims; (B) nature of invention; (D) level of ordinary skill; (F) direction provided; (G) working examples; and (H) quantity of experimentation needed. That is, six of the Wands factors do not support Enablement, four of which relates directly to the current claim scope (A/F/G/H).
Therefore, there exists a Scope of Enablement deficiency for the current claim.
Third, based on the foregoing, it is unclear which other algorithms or methodologies may be used to control the pressurized fluid injection rate and production fluid inflow rate so as to maximize the carbon storage potential or not, because Applicant has not disclosed what other ways it may be done other than by following recommendations developed by an analysis module based on how much and where carbonate is being deposited throughout a process life cycle. For example, it is unclear if using instantaneous responses to a specific measurement at a specific time would provide “wherein the fluid injection well subsystem and the fluid production well subsystem operate based on measurements made by the monitoring subsystem to control the injection rate of the pressurized fluid and the inflow rate of the production fluid so as to maximize carbon storage potential of the subterranean rock formation via the carbon mineralization” or not. Similarly, it is unclear if using a pre-programmed array of decisions following data collected from prior treatments in other well systems would provide “wherein the fluid injection well subsystem and the fluid production well subsystem operate based on measurements made by the monitoring subsystem to control the injection rate of the pressurized fluid and the inflow rate of the production fluid so as to maximize carbon storage potential of the subterranean rock formation via the carbon mineralization” or not. Also, it is unclear if using spur-of-the-moment decision-making by an on-site operator viewing the incoming measurements would provide “wherein the fluid injection well subsystem and the fluid production well subsystem operate based on measurements made by the monitoring subsystem to control the injection rate of the pressurized fluid and the inflow rate of the production fluid so as to maximize carbon storage potential of the subterranean rock formation via the carbon mineralization” or not.
Accordingly, the claim scope is also rendered Indefinite.
Claims 2-7, 10, 11, 19, 20, 27, 56, 57, and 66-69 are rejected by dependency, also failing to limit the claims to the Described and Enabled scope in a Definite manner. Claim 19 further repeats “wherein the fluid injection well subsystem and the fluid production well subsystem operate based on measurements made by the monitoring subsystem to control the injection rate of the pressurized fluid and the inflow rate of the production fluid so as to maximize carbon storage potential of the subterranean rock formation via the carbon mineralization” but extends it to each of the plurality of fluid production well systems, which retains the same deficiencies. Although claim 57 requires certain specific monitoring measurement types, claim 57 is still deficient based on the “control… so as to maximize carbon storage potential” in independent claim 1.
For examination purposes, claims will be read as though including the Described and Enabled scope:
“1. (Currently Amended) A system for implementing subterranean carbon mineralization, the system comprising:
a fluid injection well subsystem comprising:
an injection wellbore that traverses and is in fluid communication with a subterranean rock formation comprising a group consisting of a mafic rock formation, an ultramafic rock formation, and a combination thereof;
a pumping system configured to pump a pressurized fluid into the injection wellbore, wherein the pressurized fluid comprises carbon dioxide; and
a fluid injection completion system disposed at an injection range along the injection wellbore, wherein the fluid injection completion system is configured to control an injection rate of the pressurized fluid from the injection range of the injection wellbore into an active storage zone within the subterranean rock formation;
a fluid production well subsystem comprising:
a production wellbore that traverses and is in fluid communication with the subterranean rock formation; and
a fluid production completion system disposed at a production range along the production wellbore, wherein the fluid production completion system is configured to control an inflow rate of production fluid from the active storage zone within the subterranean rock formation into the production range of the production wellbore; and
a monitoring subsystem configured to monitor carbon mineralization in the active storage zone within the subterranean rock formation using measuring equipment for measurements selected from the group consisting of electromagnetic monitoring, magnetic monitoring, gravity monitoring, interferometric synthetic aperture radar monitoring, seismic monitoring, and fluid chemistry monitoring, wherein the fluid injection well subsystem and the fluid production well subsystem operate based on measurements made by the monitoring subsystem to control the injection rate of the pressurized fluid and the inflow rate of the production fluid so as to maximize carbon storage potential of the subterranean rock formation via the carbon mineralization by following recommendations developed by an analysis module based on how much and where carbonate is being deposited throughout a process life cycle.”
Allowable Subject Matter
Claims 1-7, 10, 11, 19, 20, 27, 56, 57, and 66-69 would be allowable if rewritten or amended to overcome the rejection(s) under 35 U.S.C. 112 set forth in this Office action.
Conclusion
The prior art made of record and not relied upon is considered pertinent to applicant's disclosure:
The reference to Hasan (12,553,315) (PCT filed Oct. 31, 2022) is the closest Prior Art of record and discloses and claims “A method of measuring a rate of mineralization, including: positioning a seismic sensor and/or a harmonic sensor in acoustic communication with a rock formation; injecting carbon dioxide into a borehole in the rock formation; reacting the carbon dioxide with the rock formation to form mineralized carbon dioxide; measuring an acoustic activity generated in the rock formation with the seismic sensor and/or harmonic sensor during the reacting; calculating the rate of mineralization based on the acoustic activity; and adjusting a rate of carbon dioxide injection into the rock formation based on the calculated rate of mineralization” (abstract and claims; also Figs. 1 and 2). This reference thus discloses A system for implementing subterranean carbon mineralization (abstract), the system comprising:
a fluid injection well subsystem comprising:
an injection wellbore that traverses and is in fluid communication with a subterranean rock formation (“injecting carbon dioxide into a borehole in the rock formation”) comprising a group consisting of a mafic rock formation, an ultramafic rock formation, and a combination thereof (“The rock formation of the present disclosure may be any suitable rock formation for CO2 sequestration, including but not limited to rock formations made of mafic and ultramafic rocks”);
a pumping system configured to pump a pressurized fluid into the injection wellbore (“Preferably the CO2 rich fluid-mixture is injected into the geologic formation at pressures substantially less than those necessary in order to mechanically fracture the formation, e.g., pressures in the range of ambient borehole or downhole pressure to generally less than 1 MPa and preferably in the range of from 100-1,000 psi”), wherein the pressurized fluid comprises carbon dioxide (“In an embodiment, the carbon dioxide to be injected, is dissolved in an aqueous solution or a CO2 rich aqueous-mixture. … In some embodiments, the injected carbon dioxide is in gaseous form”); and
a fluid injection completion system disposed at an injection range along the injection wellbore, wherein the fluid injection completion system is configured to control an injection rate of the pressurized fluid from the injection range of the injection wellbore into an active storage zone within the subterranean rock formation (“The CO2 rich fluid-mixture is then injected through a well head including an injection well at the entrance of the borehole. The injection well head is preferably connected through a non-corrosive pipe (e.g., tubing) to a packer system that is installed just above the target injection zone. The packer system hydraulically isolates the column for injection of CO2 rich fluid-mixture into the peridotite rock formation. The injected CO2 rich fluid-mixture is dispersed through the annulus in the borehole within the peridotite formation where the dissolved CO2 reacts in-situ with the peridotite rocks”);
…; and
a monitoring subsystem configured to monitor carbon mineralization in the active storage zone within the subterranean rock formation using measuring equipment for measurements selected from the group consisting of electromagnetic monitoring, magnetic monitoring, gravity monitoring, interferometric synthetic aperture radar monitoring, seismic monitoring, and fluid chemistry monitoring (“At step 108 of the method 100, the method includes measuring an acoustic activity with the seismic sensor and/or harmonic sensor during the reacting” and “the method 100 at step 110 includes calculating the rate of mineralization based on the acoustic activity”; also “At step 114 the method 100 further optionally includes measuring a pH, an alkalinity and/or dissolved inorganic carbon content of a fluid composition exiting the rock formation following the reacting” and “At step 116 the method 100 further includes measuring a time-lapse surface gravity to monitor changes in a density of the rock formation during and/or following the reacting with a fixed gravity observation pad. … Changes in the gravity indicate that CO2 has been reacted to form mineralized carbon dioxide in the rock formation. An algorithm can then convert the change in gravity to mass of carbonate precipitated in the subsurface pore space. This along with the pH data and the acoustic activity data can provide information about the amount of CO2 that has been mineralized/sequestered in the rock formation”), wherein the fluid injection well subsystem … operate based on measurements made by the monitoring subsystem to control the injection rate of the pressurized fluid … so as to maximize carbon storage potential of the subterranean rock formation via the carbon mineralization by following recommendations developed by an analysis module based on how much and where carbonate is being deposited throughout a process life cycle (“the method 100 at step 112 includes adjusting a rate of carbon dioxide injection into the rock formation based on the calculated rate of mineralization. For example, if the rate of mineralization is high, more CO2 can be sequestered into the rock formation and if the rate is low or no mineralization is taking place, then injection of CO2 may need to be moved to another location” and “At step 122 the method further includes locating an area portion of the rock formation where the reacting takes place based on the acoustic activity. The location of the origin of the acoustic signal in the rock formation may be determined by detecting the acoustic signal with a plurality of sensors or a seismic array which data in turn permit calculation of the location of origin and other information such as direction and length of fracture etc. Based on the location of the signals produced, it is possible to locate where in the rock the reactions are taking place. This information can give insight into areas of the rock that are more reactive than others and/or that have the capacity to store more CO2. In an embodiment, injection of the CO2 may be shifted towards areas with higher reactivity. This information can also provide insight as to when a location can no longer react with the CO2 and thereby CO2 should no longer be injected in that area”).
This reference refers to “At step 114 the method 100 further optionally includes measuring a pH, an alkalinity and/or dissolved inorganic carbon content of a fluid composition exiting the rock formation following the reacting” (10:48-51). However, this reference fails to disclose a fluid production wellbore capable of controlling an inflow rate of production fluid, and thus further “wherein the fluid injection well subsystem and the fluid production well subsystem operate based on measurements made by the monitoring subsystem to control the injection rate of the pressurized fluid and the inflow rate of the production fluid so as to maximize carbon storage potential of the subterranean rock formation via the carbon mineralization by following recommendations developed by an analysis module based on how much and where carbonate is being deposited throughout a process life cycle,” and it would not be obvious to modify this reference to include the production considerations absent some teaching suggesting that controlling the production fluid inflow rate would be a relevant consideration for this sort of carbon mineralization process and/or for maximizing carbon storage potential.
Other relevant references include:
The reference to Berge (2008/0319726) discloses performing an oilfield operation including modeling/simulating the operation (abstract) using a controller for actuating mechanisms at the oilfield which may be selectively adjusted based on the data collected to optimize fluid recovery rates, or to maximize the longevity of the reservoir ([0047]), for sites for storage of carbon dioxide ([0085]), wherein the storage capacity and trapping mechanisms such as mineralization/absorption can be modeled ([0108]). However, this reference fails to disclose or teach equipment for monitoring carbon mineralization; and nor controlling pressurized fluid injection rate and production fluid inflow rate so as to maximize carbon storage potential, especially not by following recommendations from an analysis module based on how much and where carbonate is being deposited throughout a process life cycle.
The reference to Hasan ‘447 (2023/0038447) (cited by Applicant) discloses mineralizing CO2 by injecting CO2 into peridotite (abstract) wherein the well system includes a monitoring system for monitoring physical properties such as injected tracers to “monitor the change of the molar ratio of CO2 to tracers, which is kept constant in the injection well. Changes in this ratio will indicate CO2-water-rock reactions and thus CO2 abatement. In addition, utilizing natural tracers such as stable carbon, strontium, magnesium and calcium isotopes, it is possible to determine the reactivity of the peridotite system to mineralize the injected CO2” ([0056]). However, this reference discloses “Submersible pump (SP2) is installed in the observation borehole at depth and is used to pump ground water into an on-surface storage tank. SP2 flow rates and pressures preferably match the permeability of the subsurface formation. The on-surface storage tank is equipped with sensors that automate the operation of the SP2 and acts as a buffer between the observation and injection boreholes. … A set of Booster pumps (BP) are used in parallel to inject water from the on-surface storage tank at pressure to the injection well. The flow rates of the fluid-mixture are adapted to the permeability of the target injection zone at the injection borehole. A permeability test is carried out to determine these rates at the injection borehole prior to injecting CO2 rich fluid-mixture” ([0048]), and thus this reference fails to disclose or teach controlling pressurized fluid injection rate and production fluid inflow rate so as to maximize carbon storage potential, especially not by following recommendations from an analysis module based on how much and where carbonate is being deposited throughout a process life cycle.
The reference to Al-Qasim (2023/0313645) (cited by Applicant) discloses a well system for introducing a CO2 fluid and monitoring the injection formation (abstract) for carbon dioxide capture ([0017]) which includes controllers for control inflow control devices (ICDs) ([0090]) and sensors for detecting treatment zone conditions ([0091]). However, this reference fails to disclose or teach equipment for monitoring carbon mineralization; and nor controlling pressurized fluid injection rate and production fluid inflow rate so as to maximize carbon storage potential, especially not by following recommendations from an analysis module based on how much and where carbonate is being deposited throughout a process life cycle.
The reference to Tsuji (2024/0060397) (PCT version filed Dec. 27, 2021) discloses “an apparatus for injecting carbon dioxide into underground capable of capturing carbon dioxide from the atmosphere and injecting it into underground” (abstract) wherein “The stored mixture fluid may be mineralized. … In some cases, over 95% of carbon dioxide injected into basalt can be converted to stable carbonate minerals within two years. Carbon dioxide can be stored efficiently and safely by investigating the rate of CO mineralization in the reservoir and controlling CO2 storage and the injection rate” ([0125]) and “The control unit may further control the injection well as well as the capturing unit. For example, the monitoring unit monitors the mineralization rate of carbon dioxide (or mixture fluid) in the reservoir with a sensor or the like, thereby making it possible to control the injection well concerning the amount of carbon dioxide stored and the injection rate” ([0157]). However, this reference fails to specify how, exactly the mineralization rate is monitored or under what basis, exactly, the injection rate is controlled, and it would not be obvious to modify this reference to include controlling pressurized fluid injection rate and production fluid inflow rate so as to maximize carbon storage potential by following recommendations from an analysis module based on how much and where carbonate is being deposited throughout a process life cycle.
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/ANDREW SUE-AKO/Primary Examiner, Art Unit 3674