DETAILED ACTION
The present application, filed on or after March 16, 2013, is being examined under the first inventor to file provisions of the AIA .
Responsive to the communication dated 06/22/2026
Claims 1 and 10 are amended.
Claims 1 – 18 are presented for examination.
Continued Examination
A request for continued examination under 37 CFR 1.114, including the fee set forth in 37 CFR 1.17(e), was filed in this application after final rejection. Since this application is eligible for continued examination under 37 CFR 1.114, and the fee set forth in 37 CFR 1.17(e) has been timely paid, the finality of the previous Office action has been withdrawn pursuant to 37 CFR 1.114. Applicant's submission filed on 6/22/2026 has been entered.
Response to Arguments
Page 9. The Applicant has amended claims 1 and 10 to recite, in pertinent part: “… sequentially stimulating the subterranean geologic formation… (i) in a first step, modeling pumping a first volume of one or more fluide… (ii) after completion of the first step, in a second step modeling pumping a second volume of the one or more fluids during an injection…. (iii) after completion of the second step, in a third step modeling pumping a second volume of the one or more fluids during an injection period…”. The Applicant asserts that the combination of prior art does not make obvious sequential operatons.
In response the arguments are not persuasive. Fig. 3, Fig. 5, Fig. 7, Fig. 8 and Fig. 9 each clearly illustrates sequentially stimulating a subterranean geologic formation over time. The events occur sequentially over time. The sequence first injects a fluid and second pulses the fluid. There is also additional pumping sequences that occur after the second pulsed sequence. See the figures shown below.
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Page 10. The Applicant argues that Stolyarov does not mention the word “geothermal at all” and accordingly combining this reference with those that use the word “geothermal” would go against the indication that Stolyarov teaches that hydro-shearing is not required in shale.
The Applicant appears to be asserting that the references are not from the same field of endeavor or that Stolarov teaches away from using hydro-shearing in shale.
In response the argument is not persuasive. Stolyarov is clearly directed towards hydrocarbon exploration/recovery. COL 1 lines 6 – 20 recite: “… in fracture operations on a formation or reservoir, a frac fluid is introduced into a wellbore penetrating the formation in order to break or fracture the formation, allowing an increased production of formation fluid from the formation. The hydrocarbons output from the wellbore… the frac schedule parameter can include… a propant type, proppant mass, proppant concentration, etc.. The hydrocarbon output from the formation can be maximimzed or increase by knowing how to set the parameters…”.
Hoffman_2018 is also directed towards hydraulic stimulation treatments including fracture operation for hydrocarbon production/exploration. Abstract: “hydraulic stimulation treatments are standard techniques to access geologic resources… fluid injection into unproductive formations may increase their permeability by forming new fractures…”
Therefore, Stolyarov_2020 and Hoffman_2018 are clearly from the same field of endeavor.
Further, The omission of the word “geothermal” is not a teaching away as merely not using a word does not criticize, discredit, or otherwise discourage the use of fracture operations in shale as asserted by the applicant. Stolyarov_2020 uses the general term of “formation.” Accordingly, Stolyarov_2020 teaches to use fracture operations in subsurface formations. This include shale formations because shale formations are subsurface formations.
Page 11. The Applicant asserts that the combination of references would teach to avoid creating tensile stressing in formations because Hofmann and KC primary research interest was to avoid seismic events while fracturing geologic formations.
In response the argument is not persuasive. Hofman_2018 does not teach to avoid creating tensile stress but rather to control the amount of tensile stress to avoid seismic events. The Applicant is simply mischaracterizing the reference.
Page 12 the Applicant argues that the Office action does not explain how a reference that teaches stimulating a reservoir makes obvious to modeling the stimulation of a reservoir.
The argument is not persuasive. Hoffman_2018 explicitly states: “… the proposed stimulation concept is based on past experiences from cyclic mechanical loading experiments and cyclic injection experiments on different scales and numerical simulation…”
Page 13 the Applicant asserts, with regard to dependent claims claims 2 and 11 that the art of record does not teach all the independent claims and therefore these claims are allowable. In response the argument is not persuasive due to the reasons outlined above.
Page 14 with regard to claims 4 and 13 the Applicant asserts that the art of record does not teach all the independent claims and therefore these claims are allowable. In response the argument is not persuasive due to the reasons outlined above.
Page 15 with regard to claims 5 and 14 the Applicant asserts that the art of record does not teach all the independent claims and therefore these claims are allowable. In response the argument is not persuasive due to the reasons outlined above.
Page 16 with regard to claims 6 and 15 the Applicant asserts that the art of record does not teach all the independent claims and therefore these claims are allowable. In response the argument is not persuasive due to the reasons outlined above.
Page 17 with regard to claims 7 and 16 the Applicant asserts that the art of record does not teach all the independent claims and therefore these claims are allowable. In response the argument is not persuasive due to the reasons outlined above.
Page 19 with regard to claims 9 and 18 the Applicant asserts that the art of record does not teach all the independent claims and therefore these claims are allowable. In response the argument is not persuasive due to the reasons outlined above.
End Response to Arguments
Claim Rejections - 35 USC § 103
Claim Rejections - 35 USC § 103The 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.
Claims 1, 10, 8, 17 are rejected under 35 U.S.C. 103 as being unpatentable over Stolyarov_2020 (US 10,677,036 B2) in view of Hoffman_2018 (Cyclic Soft Stimulation (CSS): a new fluid injection protocol and traffic light system to mitigate seismic risks of hydraulic stimulation treatments, Geothermal Energy 2018) in view of KC_2021 (Geothermal Reservoir Stimulation Through Hydro-Shearing: An experimental study under conditions close to enhanced geothermal systems, Geothermics 96 2021) in view of Balushi_2023 (Thermally conductive Proppants to Improve Heat Extraction in Geothermal Systems October 9 2023).
Claim 1. Stolyarov_2020 makes obvious “A method of modeling enhancing connectivity in a subterranean geologic formation between an injector well and a producer well, comprising: (COL 1 lines 25 – 40: “a method for performing a fracture operation… for a formation surrounding a wellbore… determining a relation between the formation parameter and a parameter of the fracture operation… a relation between a fracture treatment parameter of the fracture operation and a formation parameter; determining, from the relation and a first value of the fracture treatment parameter, a value of the formation parameter; determining from the formation parameter a second value of the fracture treatment parameter; and altering the fracture treatment parameter from the first value to the second value…” COL 3 lines 15 – 20: “… the proppant holds open the fractures… thereby allowing a channel through which formation fluid can flow into the tubular 202 and uphole to the surface 105 for processing…” COL 4 lines 30 – 35: “… the model 302 recommends or implements an action, such as changing the fracture treatment parameters in real-time, in order to optimize or maximize an amount of hydrocarbon production by the fracture operation…” EXAMINER NOTE: the above citation teaches a method of modeling the relationship between input parameters and output parameters of a geological fracturing operation. A geological fracturing operation opens up the connectivity in the subterranean formation between injector wells and producer wells.)
Inputting properties of one or more stimulation fluids (COL 1 lines 15 – 21: “… the frac schedule parameters can include… a proppant type, proppant mass, proppant concentration, etc…”; COL 3 lines 10 – 20: “… the frac fluid 205 exits the tubular 202 into the formation 108 in order to form fissures or fractures 210 in the formation 108. The frac fluid 205 contains a proppant that is injected into the formation… thereby allowing open channels through which formation fluid can flow… the design of the geometry of the fracture system and frac stages 204, and the frac treatment parameters of the well injection system 206 such as pump rate, injection pressure, proppant type, proppant density or concentration, etc…”);
inputting estimated total porosity of natural fractures encountered in the subterranean geologic formation estimated from a borehole logging tool (abstract: “a method for performing a fracture operation. A log of a formation parameter is obtained for a formation surrounding a wellbore in which the fracture operation is to be implemented. A relation is determined between the formation parameter and a parameter of the fracture operation. A value of the parameter of the fracture operation is selected based on the relation and a value of the formation parameter.” FIG. 3 block 304: “subsurface Info: Mudlog, Drilling Data, Wireline Data Completion Data” FIG. 4 block 410: “Permeability/Porosity” is input into FracFit Advisor that is used for the Stage-Tailored Treatment Schedule. COL 2 lines 40 – 55: “… mud logging can be used to determine parameters of the formation… sensors 132 obtain log measurement of various parameters of the formation 108 in a process known as logging-while-drilling (LWD) or measurement-while-drilling (MWD)… exemplary formation parameters can include, but are not limited to, horizontal stress, formation brittleness, natural fracture intensity of naturally-occurring fractures, etc…”; COL 3 lines 35 – 40: “… mud logging or measurements from the formation evaluation sensors…”; COL 4 lines 10 – 16: “… employs the results of mud logging and from the logging of formation parameters using the formation evaluation sensors of either the drill string or the wireline devices, as discussed with respect to FIG. 6…”; COL 9 lines 65 – COL 9 lines 5: “… formation parameters comprises at least one of… a natural fracture intensity of the formation…” EXAMINER NOTE: the natural fracture intensity (i.e., density) of a formation is related to the porosity of the natural fractures in that higher fracture intensity (i.e., more fractures per unit volume) generally increases fracture porosity. Accordingly, the above citations teach to obtain estimates of subterranean formation geologic inputs that include a natural fracture intensity of the formation which is indicative of the total porosity of the fractures.); and
Estimating enhancement of connectivity in the subterranean geologic formation after artificially stimulating the subterranean geologic formation with stimulation fluid from a lattice therein by sequentially (COL 3 lines 50 - 65: “… the model 302 provides a method of designing a fracture operation or completion operation in a wellbore using logging data… the model 302 further determines a correlation or relation between the fracture treatment parameters and parameters of a fracture operation… in order to increase or maximize an amount of hydrocarbons that are recovered…”; COL 4 lines 30 – 45: “… the model 302 recommends or implements an action, such as changing the fracture treatment parameters… parameters that can be used in order to design a fracture operation… parameters include brittleness… stress… fracture intensity… formation permeability/porosity… fault locations… the model 302 determine geometrical parameters 432 of the fracture system…”; EXAMINER NOTE: the above citation teaches that the model correlates inputs and expected outputs of a treatment plan in order to optimize/maximize the hydrocarbon production by increasing permeability/connectivity of the formation. The correlation of the output to the inputs is an estimating of enhanced connectivity because the treatment plan is based upon achieving a desired/expected amount of permeability that maximizes oil production.)
Pumping a first volume of one or more fluids to tensile fracture the subterranean geologic formation, generating a downhole pressure that produces a stress of the subterranean geologic formation exceeding a minimum horizontal stress of the subterranean geologic formation, from the injector well to a producer well, the producer well extending form the surface to the subterranean geologic formation (COL 3 lines 5 – 20: “FIG. 2 shows a fracture operation 200 being performed in the wellbore 102 of FIG. 1… a tubular 202 including one or more frac stages 204 is lowered through the wellbore 102 in order to place the frac stages 204 at selected locations within the wellbore 102. One a frac stage 204 is set in place in the wellbore, a well injection system 206 at the surface 105 injects a frac fluid 205 downhole at high pressure. At the frac stage 204 the frac fluid 205 exits the tubular 202 into the formation 108 in order to form fissures or fracture 210 in the formation 108…” COL 6 lines 60 – 67: “… breakdown pressure and fracture intensity… a correlation between breakdown pressure and minimum horizontal stress…” EXAMINER NOTE: breakdown pressure is the maximum wellbore fluid pressure required to initiate and propagate a new or pre-existing fracture within a rock formation. COL 10 lines 25 – 40: “… the teachings of the present disclosure may be used in a variety of well operations… hydraulic fracturing, stimulation, tracer injection, cleaning, acidizing, steam injection, water flooding…” EXAMINER NOTE: waterflooding is a process where a fluid is injected into an oil reservoir to push oil towards a production well.)
While Stolyarov_2020 teaches to input properties of stimulant fluids into the model,
(e.g., COL 3 lines 10 – 20: “… frac treatment parameters of the well injection system 206 such as pump rate, injection pressure, proppant type, proppant density or concentration, etc…”), Stolyarov_2020 does not explicitly teach “thermodynamic” properties of the fluid nor “thermal” lattice.
Stalyarov_2020 doesn’t explicitly recite:
“… sequentially….
After completion of the first step, in a second step modeling Pumping the one or more fluids in a pulsing mode to cause fatigue to any existing natural fractures intersecting fractures caused by the tensile fracture, or to natural non-fractured rock, the pulsing mode having a pulse amplitude below the minimum horizontal stress of the subterranean geologic formation with frequency controlled by rock fabric of the subterranean geologic formation and bottom hole static temperature;
After completion of the second step, in a third step, modeling Pumping a second volume of the one or more fluids during an injection period as a hydro-shearing stage, the second pump volume based on an estimated total porosity of natural features encountered in the subterranean geologic formation estimated from the borehole logging tool
Hoffman_2018 makes obvious:
“… sequentially (Fig. 3, Fig. 5, Fig. 7, Fig. 8 and Fig. 9 each clearly illustrates sequentially stimulating a subterranean geologic formation over time. The events occur sequentially over time. The sequence first injects a fluid and second pulses the fluid. There is also additional pumping sequences that occur after the second pulsed sequence)
In a first step, modeling (Fig. 3, Fig. 5, Fig. 7, Fig. 8 and Fig. 9 each clearly illustrates sequentially stimulating a subterranean geologic formation over time. The events occur sequentially over time. The sequence first injects a fluid and second pulses the fluid. There is also additional pumping sequences that occur after the second pulsed sequence. See the figures shown below.)
After completion of the first step, in a second step (Fig. 3, Fig. 5, Fig. 7, Fig. 8 and Fig. 9 each clearly illustrates sequentially stimulating a subterranean geologic formation over time. The events occur sequentially over time. The sequence first injects a fluid and second pulses the fluid. There is also additional pumping sequences that occur after the second pulsed sequence. See the figures shown below.) modeling (page 27: “… the proposed stimulation concept is based on past experiences from cyclic mechanical loading experiments and cyclic injection experiments on different scales and numerical simulation…”) Pumping the one or more fluids in a pulsing mode to cause fatigue to any existing natural fractures intersecting fractures caused by the tensile fracture, or to natural non-fractured rock, the pulsing mode having a pulse amplitude below the minimum horizontal stress of the subterranean geologic formation with frequency controlled by rock fabric of the subterranean geologic formation and bottom hole static temperature (FIG. 3, FIG. 8, Fig. 9 each illustrate a pumping fluids in a pulsing model to cause fatigue. FIG. 8 also clearly illustrates pumping a first volume prior to pumping fluids in a pulsing mode. Page 2: “… factors include operational parameters such as… in situ stress… depth and temperature of the formation… permeability, which defines if a system is ‘closed’ or ‘open’…”; page 3: “… hydraulic stimulation design… injection scheme… with the aim of effectively reduce the risk of inducing seismic events above a given threshold, called cycle soft stimulation… with a tailor-made seismic traffic light system…”; page 9: “… long-term cycles describe the long-term (> hours) alternation between HIR and BIR in the CSS concept. The HIR phase is equivalent to the stimulation phase with fracture network opening and extension, while the BIR phase leads to pressure reduction and fracture closure. LTCs are repeated until the stimulation target is achieved or the traffic light system forces a change in injection schedule…”; page 13: “… uniform cycle injection intends to reduce the maximum magnitude of induced seismic events, to reduce the fracture breakdown pressure, and to increase fracture network complexity. The shorter pressure pulses are intended to amplify the fatigue and weakening of the rock by inducing additional small fissures before and beside macroscopic fracture development… tensile cracks (compared to shear cracks)…” EXAMINER NOTE: the above teaches to control pressure cycles on the formation below breakdown pressure (i.e., minimum horizontal stress of the subterranean geologic formation) with a variable length (i.e., frequency) controlled by the response of the geologic formation/fracture network (i.e., rock fabric).
After completion of the second step, in a third step (Fig. 3, Fig. 5, Fig. 7, Fig. 8 and Fig. 9 each clearly illustrates sequentially stimulating a subterranean geologic formation over time. The events occur sequentially over time. The sequence first injects a fluid and second pulses the fluid. There is also additional pumping sequences that occur after the second pulsed sequence. See the figures shown below.) modeling (page 27: “… the proposed stimulation concept is based on past experiences from cyclic mechanical loading experiments and cyclic injection experiments on different scales and numerical simulation…”) Pumping a second volume of the one or more fluids during an injection period as a “… subcritical shear stresses, induced earthquake ruptures are able to propagate only over a sufficiently pressurized portion of the fault. In that case, the maximum magnitude is likely limited by extent of the pressurized zone… which depend on the injection parameters and can hence better be controlled…” page 28: “… it is recommended to perform cycle soft stimulation treatment in conjunction with a multi-stage injection concept…”; FIG. 9 illustrates limited seismic events which indicates hydro shearing.).
Stalyarov_2020 and Hoffman_2018 are analogous art because they are from the same field of endeavor called modeling reservoirs/geologic fracturing. Before the effective filing date, it would have been obvious to a person of ordinary skill in the art to combine Stalyarov_2020 and Hoffman_2018.
The rationale for doing so would have been Stalyarov_2020 teaches to perform modeling to design/control staged treatment schedules/plans based on relevant input parameters and Hoffman_2018 teaches that during hydraulic fracturing activities, “a major risk of this process is a possible occurrence of seismic events that can potentially be felt on the surface or even cause minor damage” and then teaches to use relevant input parameters to control the hydraulic fracturing process “to mitigate these unwanted events and to improve the permeability enhancement process” (see abstract) by designing a hydraulic fracturing schedule that involves cyclic injections where the pore pressure disturbance propagates in relation to the permeability of the formation. Therefore, it would have been obvious to combine the modeling of Stalyarov_2020 that designs treatment schedules using, for example, permeability with a cyclic treatment schedule of Hoffman_2018 for the benefit of minimizing seismic events that cause damage and to improve permeability/connectivity of the reservoir to obtain the invention as specified in the claims.
Stalyarov_2020 and Hoffman_2018 does not explicitly teach “thermodynamic” properties of the fluid nor “thermal” lattice nor “hydro-shearing.”
Balushi_2023 makes obvious “thermodynamic” properties of the fluid and “thermal” lattice (abstract teaches that during hydraulic fracturing geothermal system not only provide channels for fluid flow, but also provide a larger contact area for heat transfer to achieve an efficient economic heat extraction and to use numerical modeling of proppants in the reservoir and to use the model to simulate efficient thermal conductivity of the proppant and determine the improved heat exchange).
Stalyarov_2020 and Hoffman_2018 and Balushi_2023 are analogous art because they are from the same field of endeavor called hydrocarbon exploration/recovery/modeling. Before the effective filing date, it would have been obvious to a person of ordinary skill in the art to combine Stalyarov_2020 and Balushi_2023. The rationale for doing so would have been Stalyarov_2020 teaches to have a model to create a hydraulic fracturing plan that uses proppants. Balushi_2023 teaches to have a model to calculate proppant use for creating an economic and efficient method of heat extraction. Therefore, it would have been obvious to combine Stalyarov_2020 and Balushi_2023 for the benefit of having a model that can both determine hydraulic fracturing schedule but also efficiently and economically perform heat extraction to obtain the invention as specified in the claims.
Stalyarov_2020 and Hoffman_2018 and Balushi_2023 does not explicitly teach “hydro-shearing.”
KC_2021 however, makes obvious “hydro-shearing” (title: “geothermal reservoir stimulation through hydro-shearing…”; abstract: “injection-induced shear stimulation (commonly known as ‘hydro-shearing’) is often implemented in Enhanced Geothermal Systems (EGS) to enhance the reservoir permeability. Hydro-shearing occurs when a critically stressed pre-existing fracture (or fault) slips at an injection pressure below the minimum principal stress in the reservoir, which opens the fracture due to self-propping of asperities on the fracture surface…”).
Stalyarov_2020 and Hoffman_2018 and Balushi_2023 and KC_2021 are analogous art because they are from the same field of endeavor called hydrocarbon exploration/recovery/modeling. Before the effective filing date, it would have been obvious to a person of ordinary skill in the art to combine Hoffman_2018 and KC_2021. The rationale for doing so would have been that Hoffman_2018 teaches to perform Enhanced Geothermal Systems (EGS) to stimulate a reservoir by cyclically stressing a formation to lower the fracture breakdown pressure for the purpose of being able to create reservoir ‘openness”/permeability without causing significant seismic events. KC_2021 teaches that hydro-shearing is “often implemented in Enhanced Geothermal Systems (EGS) to enhance the reservoir permeability.” Therefore, it would have been obvious to combine the cyclic schedules of Hoffman_2018 with the hydro-shearing of KC_2021 for the benefit of opening fractures to increase permeability without causing significant seismic events to obtain the invention as specified in the claims.
Claim 10. The limitations of claim 10 are substantially the same as those of claim 1 and are rejected due to the same reasons as outlined above for claim 1. Additionally, Stolyarov_2020 makes obvious the further limitations of “… inputting estimated total porosity of natural fractures encountered in the subterranean geologic formation estimated from the geologic settings of the subterranean geologic formation…” and “… from geologic settings of the subterranean geologic formation” (COL 4 lines 39 – 65: “… parameters that can be used in order to design a fracture operation… includes brittleness 404, stress 406, natural fracture intensity 408, formation permeability/porosity 410… fault locations 418. These parameters are provided to the model 302 which designs the fracture operation… parameters such as brittleness 404, stress 406 and natural fracture intensity 408 are fracability parameters 420 of a formation. The parameters of natural fracture intensity 408, permeability/porosity 410 and TOC 412 are productivity parameters 420 of the formation… during early-occurring aspects of the fracture operation, the model 302 may rely mostly on the fracability parameters 420 in order to determine fracture operation parameters such as geometrical parameters 432. As the other parameters become available to the model 302, the model 320 can incorporate these parameters in its calculations…”);
Claim 8, 17. Stolyarow_2020 teaches (COL 3 lines 21 – 30) “… controls various aspects of the fracture operation including, for example, the design of the geometry of the fracture system and frac stages 204, and the frac treatment parameters of the well injection system 206 such as pump rate, injection pressure, proppant type, proppant density or concentration, etc…”. Therefore, the model of Stolyarow_2020 that is used to design the treatment plan (i.e., proppant density) comprising modeling a density of the stimulation fluid. Further, Hoffman_2018 teaches (page 6 of 33) “… When fluid is injected during a stimulation treatment in a saturated porous rock, the speed of the resulting pore pressure disturbance is proportional to the diffusivity… that means the higher the permeability and the lower the compressibility, the faster the pore pressure disturbance propagates…”. Therefore, Hoffman_2018 makes obvious to control the surface density of a stimulation fluid for the purpose of controlling, for example, the propagation velocity/speed of pore disturbances to control/prevent seismic events by controlling the compressibility which is a function of proppant concentration in volume of fluid (i.e., density). The surface density is the obvious control point to those of ordinary skill in the art because it is at the surface at the injection point where the slurry is mixed.
Accordingly, Stolyarov_2020 in view of Hoffman_2018 in view of KC_2021 in view of Balushi_2023 makes obvious “comprising modeling a density of the one or more stimulation fluids at surface, at injection point.”
Claims 2, 11 are rejected under 35 U.S.C. 103 as being unpatentable over Stolyarov_2020 in view of Hoffman_2018 in view of KC_2021 in view of Balushi_2023 in view of Alves_1992 (A Unified Model for Predicting Flowing Temperature Distribution in Wellbores and Pipelines, 1992).
Claim 2, 11. Alves_1992 makes obvious “comprising modeling a return fluid annulus surface temperature” (This model develops the comprehensive heat transfer coefficients (U) required to calculate the temperature drop across the various radial resistances (fluid film, pipe wall conduction, annulus fluid, casing wall, cement, formation). By applying these comprehensive heat transfer equations from the flowing fluid inside the tubing all the way to the external surface of the outermost casing/annulus at the wellhead, you can derive the specific external surface temperature as claimed.).
Stolyarov_2020 and Alves_1992 are analogous art because they are from the same field of endeavor called modeling wells/drilling operations. Before the effective filing date, it would have been obvious to a person of ordinary skill in the art to combine Stolyarov_2020 and Alves_1992. The rationale for doing so would have been that Stolyarov_2020 teaches to have a model and use the model to design/control injection operation and Alves_1992 teaches “a general an unified equation for flowing temperature prediction. It can be applied to pipelines and production and injection well.” Therefore, it would have been obvious to combine Stolyarov_2020 and Alves_1992 because Alves_1992 teaches to use the model with production and injection wells and Stolyarov_2020 has production and injection wells and also teaches to use models with them to obtain the invention as specified in the claims.
Claims 3, 12 are rejected under 35 U.S.C. 103 as being unpatentable over Stolyarov_2020 in view of Hoffman_2018 in view of KC_2021 in view of Balushi_2023 in view of Martins_2022 (Predicting the annular pressure behavior during water injection in offshore wells with a transient, multiphysics model, Journal of Petroleum Science and Engineering 218 2022)
Claim 3, 12. Martins_2022 makes obvious “comprising modeling the fluid temperature of the one or more stimulation fluids at a stimulation fluid injection location” (abstract: “… thermos-structural model that calculates temperature and pressure profiles during a recycled saltwater injection operation… deviation between the numerical results and the field down-hole pressure was lower than 4%. Absolute down-hole temperature deviations were smaller than 5’C…”; page 5: “… the temperature at the interface between the wellbore and the rock formation… wellbore/formation interface temperature… for the energy balances, the initial condition is thermal equilibrium with the formation. The injection fluid temperature is known at the top of the well… the entire wellbore temperature distribution; page 6: “… a commercial PVT and physical properties package (multiflash, 2014) was coupled to the main program to calculate the change in local properties of all fluids as a function of temperature and pressure. In particular… with respect to temperature, pressure and annual volume… calculate pressure change as a function of temperature and volume changes…” Fig. 3 “interface with formation”). Fig. 4).
Stolyarov_2020 and Martins_2022 are analogous art because they are from the same field of endeavor called modeling and simulation of wells. Before the effective filing date, it would have been obvious to a person of ordinary skill in the art to combine Stolyarov_2020 and Martins_2022.
The rationale for doing so would have been that Stolyarov_2020 teaches to use a model to design/control stimulation injections and Martins_2022 teaches a model with “allowed a compete evaluation of pressure and temperature distributions for short and long injection times’ and allow “a detailed assessment of thermally-induced annular pressure changes” and further teaches that use of such models allow modeled “hypothetical scenarios involving the installation of rupture disks in the casing between adjacent annuli were simulated to quantify the effectiveness of mitigation techniques in preventing casing collapse” (conclusion). Therefore, it would have been obvious to combine Stolyarov_2020 and Martins_2022 for the benefit of having a complete evaluation of pressure and temperature distributions during stimulation injections that allow a detailed assessment of thermally-induced pressure changes to control for/prevent/mitigate casing failures to obtain the invention as specified in the claims.
Claims 4, 13 are rejected under 35 U.S.C. 103 as being unpatentable over Stolyarov_2020 in view of Hoffman_2018 in view of KC_2021 in view of Balushi_2023 in view of Martins_2022.
Claim 4, 13. Martins_2022 makes obvious “comprising modeling a fluid temperature at surface, at or near a fluid injection position” (abstract: “… thermos-structural model that calculates temperature and pressure profiles during a recycled saltwater injection operation… deviation between the numerical results and the field down-hole pressure was lower than 4%. Absolute down-hole temperature deviations were smaller than 5’C…”; page 5: “… the temperature at the interface between the wellbore and the rock formation… wellbore/formation interface temperature… for the energy balances, the initial condition is thermal equilibrium with the formation. The injection fluid temperature is known at the top of the well… the entire wellbore temperature distribution; page 6: “… a commercial PVT and physical properties package (multiflash, 2014) was coupled to the main program to calculate the change in local properties of all fluids as a function of temperature and pressure. In particular… with respect to temperature, pressure and annual volume… calculate pressure change as a function of temperature and volume changes…” Fig. 3 “interface with formation”). Fig. 4).
Stolyarov_2020 and Martins_2022 are analogous art because they are from the same field of endeavor called modeling and simulation of wells. Before the effective filing date, it would have been obvious to a person of ordinary skill in the art to combine Stolyarov_2020 and Martins_2022.
The rationale for doing so would have been that Stolyarov_2020 teaches to use a model to design/control stimulation injections and Martins_2022 teaches a model with “allowed a compete evaluation of pressure and temperature distributions for short and long injection times’ and allow “a detailed assessment of thermally-induced annular pressure changes” and further teaches that use of such models allow modeled “hypothetical scenarios involving the installation of rupture disks in the casing between adjacent annuli were simulated to quantify the effectiveness of mitigation techniques in preventing casing collapse” (conclusion). Therefore, it would have been obvious to combine Stolyarov_2020 and Martins_2022 for the benefit of having a complete evaluation of pressure and temperature distributions during stimulation injections that allow a detailed assessment of thermally-induced pressure changes to control for/prevent/mitigate casing failures to obtain the invention as specified in the claims.
Claims 5, 14 are rejected under 35 U.S.C. 103 as being unpatentable over Stolyarov_2020 in view of Hoffman_2018 in view of KC_2021 in view of Balushi_2023 in view of Youcefi_2022 (New model for standpipe pressure prediction while drilling using group method of data handling, Petroleum 8 (2022) 210- 218).
Claim 5, 14. Youcefi_2022 makes obvious “comprising modeling a standpipe pressure” (page 212: “… predict the SSP… predict the SPP in real-time…”; page 213: “… develop a polynomial correlation for predicting SPP based on input parameters…” EXAMINER NOTE: a polynomial correlation that predicts is a model.).
Stolyarov_2020 and Youcefi_2022 are analogous art because they are from the same field of endeavor called modeling oil wells. Before the effective filing date, it would have been obvious to a person of ordinary skill in the art to combine Stolyarov_2020 and Youcefi_2022. The rationale for doing so would have been that Stolyarov_2020 teaches to model drilling operations and to use the model to design and control the drilling operations. Youcefi_2022 teaches “the total amount of these pressure losses is termed as the stand pipe pressure (SPP) and its accurate calculation is a key parameter for successful drilling operations”. Therefore, it would have been obvious to combine Stolyarov_2020 and Youcefi_2022 for the benefit of having a model that include accurate calculation of SSP which is a key parameters for successful drilling operation to obtain the invention as specified in the claims.
Claims 6, 15 are rejected under 35 U.S.C. 103 as being unpatentable over Stolyarov_2020 in view of Hoffman_2018 in view of KC_2021 in view of Balushi_2023 in view of Martins_2022.
Claim 6, 15. Martins_2022 makes obvious “comprising modeling a fluid pressure at surface, at or near fluid injection position” (abstract: “… thermos-structural model that calculates temperature and pressure profiles during a recycled saltwater injection operation… deviation between the numerical results and the field down-hole pressure was lower than 4%. Absolute down-hole temperature deviations were smaller than 5’C…”; page 5: “… the temperature at the interface between the wellbore and the rock formation… wellbore/formation interface temperature… for the energy balances, the initial condition is thermal equilibrium with the formation. The injection fluid temperature is known at the top of the well… the entire wellbore temperature distribution; page 6: “… a commercial PVT and physical properties package (multiflash, 2014) was coupled to the main program to calculate the change in local properties of all fluids as a function of temperature and pressure. In particular… with respect to temperature, pressure and annual volume… calculate pressure change as a function of temperature and volume changes…” Fig. 3 “interface with formation”). Fig. 4).
Stolyarov_2020 and Martins_2022 are analogous art because they are from the same field of endeavor called modeling and simulation of wells. Before the effective filing date, it would have been obvious to a person of ordinary skill in the art to combine Stolyarov_2020 and Martins_2022.
The rationale for doing so would have been that Stolyarov_2020 teaches to use a model to design/control stimulation injections and Martins_2022 teaches a model with “allowed a compete evaluation of pressure and temperature distributions for short and long injection times’ and allow “a detailed assessment of thermally-induced annular pressure changes” and further teaches that use of such models allow modeled “hypothetical scenarios involving the installation of rupture disks in the casing between adjacent annuli were simulated to quantify the effectiveness of mitigation techniques in preventing casing collapse” (conclusion). Therefore, it would have been obvious to combine Stolyarov_2020 and Martins_2022 for the benefit of having a complete evaluation of pressure and temperature distributions during stimulation injections that allow a detailed assessment of thermally-induced pressure changes to control for/prevent/mitigate casing failures to obtain the invention as specified in the claims.
Claims 7, 16 are rejected under 35 U.S.C. 103 as being unpatentable over Stolyarov_2020 in view of Hoffman_2018 in view of KC_2021 in view of Balushi_2023 in view of Al-Rubaii_2023 (US 2023/0235657 A1)
Claim 7, 16. Al-Rubaii_2023 makes obvious “comprising modeling an annular velocity of the one or more stimulation fluids” (par 27: “… the system 100 generates the model 104 based on a plurality of predetermined mathematical equations that define parameters… the model 104 is configured to use the drilling data 102 to calculate one or more of… annular velocity (Ve)… annular mud velocity…”).
Stolyarov_2020 and Al-Rubaii_2023 are analogous art because they are from the same field of endeavor called drilling operations. Before the effective filing date, it would have been obvious to a person of ordinary skill in the art to combine Stolyarov_2020and Al-Rubaii_2023. The rationale for doing so would have been that Stolyarov_2020 teaches to use a model and Al-Rabaii_2023 teaches to include in the model annular velocity. Therefore, it would have been obvious to combine Stolyarov_2020 and Al-Rubaii_2023 for the benefit of having a model that include a more complete set of parameters and therefore capable of more accurately modeling the drilling operation to obtain the invention as specified in the claims.
Claims 9, 18 are rejected under 35 U.S.C. 103 as being unpatentable over Stolyarov_2020 in view of Hoffman_2018 in view of KC_2021 in view of Balushi_2023 in view of Fagnou_2012 (US 2012/0274664 A1).
Claim 9, 18. Stolyarov_2020 illustrates a graphical display in, for example, FIG. 6 and further teaches that the parameters used include “… injection pressures, proppant type, proppant density or concentration…” (COL 3) and while this properly makes obvious to those of ordinary still in the art “one or more of stimulation fluid pressure and stimulation fluid density, Stalyarov_2020 does not explicitly recite the words “graphical display”.
Fagnou_2012, however, makes obvious “comprising producing graphical display (abstract: “… display a user interface on the tough screen display that graphically displays elements of the well data…”; page 4: “… display that graphically displays elements of the well data…”) “of one or more of stimulation fluid pressure , stimulation fluid temperature, stimulation fluid state curve in p-H diagram, stimulation fluid density, and stimulation fluid specific heat” (Par 50: “… data relating to various oilfield operations… for example… fluid composition/and other parameters of the oilfield operation…”; Par 52: “… fluid parameters, such as fluid composition, flow rates, pressures, temperatures, and/or other parameters…”; Par 56: “… tests for density and viscosity may be performed on the fluids…”; Par 53: “… may also include injection wells…”)
Stolyarov_2020 and Fagnou_2012 are analogous art because they are from the same field of endeavor called oil well operations. Before the effective filing date, it would have been obvious to a person of ordinary skill in the art to combine Stolyarov_2020 and Fagnou_2012. The rationale for doing so would have been that Stolyarov_2020 teaches to model/control oil well operations and teaches to use parameters such as injection pressure, proppant type and density. Fagnou_2012 teaches to have a graphical user interface that graphically displays elements of the well operation data for the purpose of visualization and manipulation of the well data. Therefore, it would have been obvious to combine Stolyarov_2020 and Fagnou_2012 for the benefit of visualizing and manipulating the data to control the well operations to obtain the invention as specified in the claims.
Conclusion
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/BRIAN S COOK/Primary Examiner, Art Unit 2187
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