DETAILED ACTION
Response to Amendment
The Amendment filed 20 January 2026 has been entered. Claims 1-26 remain pending in the application. The Non-Final Office Action was mailed 17 July 2025.
Claim Objections
Claims 1-26 are objected to because of the following informalities:
Independent claim 1 should recite “rubber tire crumb, class H cement, buffered metal ion cross-linked partially hydrolyzed polyacrylamide (PHPA), or any combination thereof” (correcting the typo as in [0008]/[0016]; and because “buffered metal ion cross-linked” is nonsensical without the thing that is cross-linked i.e. the polyacrylamide). The dependent claims are objected to by dependency.
As in claim 1, independent claim 12 should recite “rubber tire crumb, class H cement, buffered metal ion cross-linked partially hydrolyzed polyacrylamide (PHPA), or any combination thereof” (correcting the typo). The dependent claims are objected to by dependency.
As in claim 1, independent claim 21 should recite “rubber tire crumb, class H cement, buffered metal ion cross-linked partially hydrolyzed polyacrylamide (PHPA), or any combination thereof” (correcting the typo). The dependent claims are objected to by dependency.
Appropriate correction is required.
Priority
As previously, the disclosure of the prior-filed application, Application No. 18/128,004 (and 63/325,066), fails to provide adequate support or enablement in the manner provided by 35 U.S.C. 112(a) or pre-AIA 35 U.S.C. 112, first paragraph for one or more claims of this application. Specifically, 18/128,004 (and 63/325,066) fails to provide adequate support or enablement for:
(independent claims 1 and 14) “A method of storing fluid in rock of a subterranean zone for energy storage purposes”; and
(independent claim 21) “wherein the first fluid and the second fluid are stored under pressure in the rock formation after injecting, and wherein stored fluids comprise the first fluid and the second fluid stored under pressure in the rock formation; and wherein thermal features of the rock formation provide heat to the stored fluids to provide heated stored fluids, and further wherein the heated stored fluids retain heat from the rock formation when flowing out of the rock formation.”
Accordingly, as previously, 18/128,004 fails to provide adequate support or enablement for all claims, and these are being treated under the current filing date of 22 October 2024.
If Applicant wishes to take advantage of the effective filing date of parent 18/128,004 and 63/325,066 (effectively filed 29 March 2022), then Applicant should remove the new features from the claims (e.g., merely stating “A method ”) and add different features to distinguish from the Prior Art. This would also overcome the rejections over Schmidt (2023/0313657) (also parent Application 18/128,004) below.
Claim Rejections - 35 USC § 103
The text of those sections of Title 35, U.S. Code not included in this action can be found in a prior Office action.
FIRST GROUP:
Claims 1-26 are rejected under 35 U.S.C. 103 as obvious over Schmidt (2023/0313657) (also parent Application 18/128,004) (published 5 October 2023) (cited previously).
As above, to overcome Schmidt, then Applicant should remove the new features from the claims (e.g., merely stating “A method ”) and add different features to distinguish from Lord, Nguyen, etc. below.
Regarding independent claim 14 (and independent claim 1, Schmidt discloses A method of “generating a self-propped hydraulic fracture” (claims 1/9/16), comprising:
injecting a first fluid into a wellbore, wherein the first fluid has a viscosity from one to one thousand centipoise (e.g. claims 1/9/16 “injecting a first fluid into a wellbore, wherein the first fluid has a viscosity from one to one thousand centipoise”);
injecting a second fluid into the wellbore, wherein the second fluid begins as a fluid with viscosity from ten to five thousand centipoise but becomes more viscous, or even solid, over time (e.g., claim 16 “injecting a second fluid into the wellbore, wherein the second fluid begins as a fluid with viscosity from ten to five thousand centipoise but becomes more viscous, or even solid, over time”), and wherein the second fluid comprises rubber tire crumb, class H cement, buffered metal ion cross-linked partially hydrolyzed polyacrylamide (PHPA), or any combination thereof ([0012] “the second stage sealing slurry may contain material for forming an impermeable barrier near the tip of the fracture. … Embodiments may include fiber, clay, asphalt emulsion, water-born epoxy resins plus hardeners, particle slurries such as crushed rock, walnut shells, rubber tire crumb, pre-formed particle gels, metal cation crosslinkers for hydrolyzed polyacrylamide, Portland cement, or combinations thereof” and [0016] “For example, in a first embodiment, the injection fluids may include a 15% (of total volume) pad comprised of 27 pounds-per-barrel (ppb) bentonite mud; a 30% (of total volume) slurry comprised of up to 2 mm rubber tire crumb (RTC) in 25 pounds-per-thousand (ppt) cross-linked guar with 4 ppb mineral fiber; a 4% (of total volume) spacer fluid comprised of 2% PHPA, and a 51% (of total volume) sweep comprised of 35 ppt cross-linked guar with enzymatic breaker. In a second embodiment, the modified fluids and particle assemblies may include a 20% (of total volume) pad comprised of water; a 40% (of total volume) slurry comprised of class H cement; and a 40% (of total volume) sweep comprised of 35 ppt cross-linked guar with enzymatic breaker. In a third embodiment, the modified fluids and particle assemblies may include a 2% (of total volume) pad comprised of 1% partially hydrolyzed poly acrylamide (PHPA) gel; a 16% slurry comprised of buffered metal ion cross-linked 1% PHPA loaded with RTC mixture up to 2 mm; and a 82% sweep comprised of 35 ppt cross-linked guar with enzymatic breaker”);
wherein the first fluid and the second fluid are injected such that the second fluid has a viscosity equal to or greater than the viscosity of the first fluid, and may also exhibit greater shear thickening behavior (e.g., claims 1/9/16 “wherein the three fluids are injected such that each successive injection fluid has a viscosity equal to or greater than the viscosity of the preceding fluid, and may also sequentially exhibit greater shear thickening behavior”).
However, Schmidt fails to disclose wherein the method is used for storing fluid in rock of a subterranean zone for energy storage purposes.
Nevertheless, Schmidt teaches in the Background of the Invention that “Hydraulic fracture technology may be employed in conjunction with a wellbore to access geological materials and subterranean locations of interest for a variety of purposes. Often the geological material of interest may be one or more fluids located or trapped in pore spaces of the rock matrix, for example hydrocarbon fluids such as oil or gas. Hydraulic fractures may also be utilized to access geopressured fluids, geothermal brines, or other minerals of interest. In other applications, a fracture may be utilized as a heat exchanger to exploit thermal features of the rock matrix. Alternatively, hydraulic fractures may be utilized to store pressurized fluids for energy storage purposes” ([0004]).
It would have been obvious to one of ordinary skill in the art before the effective filing date of the claimed invention to have modified Schmidt to include wherein the self-propped hydraulic fracture is “utilized to store pressurized fluids for energy storage purposes,” with a reasonable expectation of success, in order to employ the self-propped hydraulic fracture for a suggested application of hydraulic fractures generally (thereby including “A method of storing fluid in rock of a subterranean zone for energy storage purposes”).
Regarding claims 2-13 and 15-20, these correspond with Schmidt claims 16, 16, 16, 16, 16, 11, 17, 18, 19, 2, 3, 4, 16, 16, 16, 17, 18, and 19, respectively.
Regarding independent claim 21, Schmidt discloses A method of generating a self-propped hydraulic fracture in a rock formation (claims 1/9/16), comprising:
injecting a first fluid into a wellbore, wherein the first fluid has a viscosity from one to one thousand centipoise (e.g. claims 1/9/16 “injecting a first fluid into a wellbore, wherein the first fluid has a viscosity from one to one thousand centipoise”);
injecting a second fluid into the wellbore, wherein the second fluid has a viscosity from ten to five thousand centipoise and is loaded between 5% and 30% by weight with particles of varying composition (e.g., claims 1/9/16 “injecting a second fluid into the wellbore, wherein the second fluid has a viscosity from ten to five thousand centipoise and is loaded between 5% and 30% by weight with particles of varying composition”), and wherein the second fluid comprises rubber tire crumb, class H cement, buffered metal ion cross-linked partially hydrolyzed polyacrylamide (PHPA), or any combination thereof ([0012] “the second stage sealing slurry may contain material for forming an impermeable barrier near the tip of the fracture. … Embodiments may include fiber, clay, asphalt emulsion, water-born epoxy resins plus hardeners, particle slurries such as crushed rock, walnut shells, rubber tire crumb, pre-formed particle gels, metal cation crosslinkers for hydrolyzed polyacrylamide, Portland cement, or combinations thereof” and [0016] “For example, in a first embodiment, the injection fluids may include a 15% (of total volume) pad comprised of 27 pounds-per-barrel (ppb) bentonite mud; a 30% (of total volume) slurry comprised of up to 2 mm rubber tire crumb (RTC) in 25 pounds-per-thousand (ppt) cross-linked guar with 4 ppb mineral fiber; a 4% (of total volume) spacer fluid comprised of 2% PHPA, and a 51% (of total volume) sweep comprised of 35 ppt cross-linked guar with enzymatic breaker. In a second embodiment, the modified fluids and particle assemblies may include a 20% (of total volume) pad comprised of water; a 40% (of total volume) slurry comprised of class H cement; and a 40% (of total volume) sweep comprised of 35 ppt cross-linked guar with enzymatic breaker. In a third embodiment, the modified fluids and particle assemblies may include a 2% (of total volume) pad comprised of 1% partially hydrolyzed poly acrylamide (PHPA) gel; a 16% slurry comprised of buffered metal ion cross-linked 1% PHPA loaded with RTC mixture up to 2 mm; and a 82% sweep comprised of 35 ppt cross-linked guar with enzymatic breaker”)…
However, Schmidt fails to disclose wherein the first and second fluids are stored under pressure after injecting; wherein thermal features provide heat to the stored fluids; and wherein the heated stored fluids retain heat when flowing out.
Nevertheless, Schmidt teaches in the Background of the Invention that “Hydraulic fracture technology may be employed in conjunction with a wellbore to access geological materials and subterranean locations of interest for a variety of purposes. Often the geological material of interest may be one or more fluids located or trapped in pore spaces of the rock matrix, for example hydrocarbon fluids such as oil or gas. Hydraulic fractures may also be utilized to access geopressured fluids, geothermal brines, or other minerals of interest. In other applications, a fracture may be utilized as a heat exchanger to exploit thermal features of the rock matrix. Alternatively, hydraulic fractures may be utilized to store pressurized fluids for energy storage purposes” ([0004]).
It would have been obvious to one of ordinary skill in the art before the effective filing date of the claimed invention to have modified Schmidt to include wherein the self-propped hydraulic fracture is both “utilized to store pressurized fluids for energy storage purposes” and “utilized as a heat exchanger to exploit thermal features of the rock matrix” for the “one or more fluids located or trapped in pore spaces of the rock matrix, for example hydrocarbon fluids such as oil or gas” which are geological materials of interest that are accessed by the wellbore i.e. flowed out of the rock formation, with a reasonable expectation of success, in order to employ the self-propped hydraulic fracture simultaneously for several known applications of hydraulic fractures generally (thereby including “A method of storing fluid in rock of a subterranean zone for energy storage purposes…
wherein the first fluid and the second fluid are stored under pressure in the rock formation after injecting, and wherein stored fluids comprise the first fluid and the second fluid stored under pressure in the rock formation; and
wherein thermal features of the rock formation provide heat to the stored fluids to provide heated stored fluids, and further wherein the heated stored fluids retain heat from the rock formation when flowing out of the rock formation”).
Regarding claims 22-26, these correspond with Schmidt claims 16, 16, 16, 16, and 2, respectively.
SECOND GROUP:
Claims 1-5, 8-11, 13-23, 25, and 26 are also rejected under 35 U.S.C. 103 as obvious over Lord (4,887,670) (cited previously)in view of Nguyen ’160 (2018/0238160) (cited previously), Schmidt ‘362 (2011/0030362) (cited previously), and Nguyen ‘273 (2016/0153273).
Regarding independent claim 1, Lord discloses A method … (abstract “methods of controlling the growth of one or more vertically oriented fractures in a subterranean formation during a fracturing treatment” and Col. 2, lines 18-66 and Figs. 1-16), comprising:
injecting a first fluid into a wellbore (Col. 5, lines 10-14 “The formation 11 is broken down and the fracture 10 is initially hydraulically induced by the injection of a high density, usually low viscosity preflush fluid (often referred to as a prepad)”), wherein the first fluid has “low viscosity” (Col. 5, line 13);
injecting a second fluid into the wellbore (Col. 5, lines 20-23 “after injection of the preflush fluid, a first fracturing fluid (often referred to as a pad) having a high density, a moderate to high viscosity and having diverting agent suspended therein is injected”), wherein the second fluid has “a moderate to high viscosity” (Col. 5, line 22)…;
wherein the first fluid and the second fluid are injected such that the second fluid has a viscosity equal to or greater than the viscosity of the first fluid (i.e., by virtue of the prepad having a “low” viscosity, the first fracturing fluid having a “moderate” viscosity, and the second fracturing fluid having a “high” viscosity).
Regarding the 1-1000 cP and 10-5000 cP, Lord does not actually specify the viscosity values of the “low” viscosity, “moderate” viscosity, and “high” viscosity fluids, only giving an example of fluids viscosified with 20 lb/1000 gal of hydroxypropyl guar gelling agent (Col. 8, Example).
Nevertheless, low viscosities of 1-1000 cP and high viscosities of 100-1,000,000 cP are ordinary and typical in the art. For example, Nguyen ‘160 teaches fracturing with “low-viscosity” fluids and “high-viscosity” fluids (abstract) wherein “The low-viscosity … may have a viscosity in the range of from about 1 cP to about 200 cP at a shear rate of 40 sec−1 at room temperature, encompassing any value and subset therebetween. For example, the low-viscosity of the micro-proppant fluid may be in the range of about 1 cP to about 40 cP, or about 40 cP to about 80 cP, or about 80 cP to about 120 cP, or about 120 cP to about 160 cP, or about 160 cP to about 200 cP” ([0036]) and “The viscosity of the high-viscosity pad fluids described herein may be in the range of from about 100 centipoise (cP) to about 20000 cP at a shear rate of 40 sec−1 at room temperature, encompassing any value and subset therebetween. For example, the viscosity of the high-viscosity pad fluids may be in the range of about 100 cP to about 1000 cP, or about 1000 cP to about 4000 cP, or about 4000 cP to about 8000 cP, or about 8000 cP to about 12000 cP, or about 12000 cP to about 16000 cP, or about 16000 cP to about 20000 cP” ([0035]).
Similarly, a “moderate” viscosity is presumably somewhere between 1-200 cP low viscosity and 100-20,000 cP high viscosity, e.g., 10-2,000 cP moderate viscosity. Accordingly, although silent to the exact values as instantly claimed, it would have been obvious to one having ordinary skill in the art before the effective filing date of the claimed invention to have modified Lord to include 1-200 cP low viscosity, 10-2,000 cP moderate viscosity, and 100-20,000 cP high viscosity, with a reasonable expectation of success, in order to provide typical and ordinary viscosities for the “low” viscosity, “moderate” viscosity, and “high” viscosity fluids (thereby providing:
“injecting a first fluid into a wellbore, wherein the first fluid has a viscosity from one to one thousand centipoise;
injecting a second fluid into the wellbore, wherein the second fluid has a viscosity from ten to five thousand centipoise”). Applicant may note that, after KSR, the presence of a known result-effective variable would be one, but not the only, motivation for a person of ordinary skill in the art to experiment to reach another workable product or process. See also MPEP 2144.05 Obviousness of Similar and Overlapping Ranges, Amounts, and Proportions. For example, Applicant has not disclosed any particular criticality to these claimed ranges.
Regarding the “storing fluid in rock of a subterranean zone for energy storage purposes,” Lord as above discloses injecting etc.
However, Lord fails to disclose storing fluid in rock of a subterranean zone for energy storage purposes.
Schmidt ‘362 teaches “Energy is stored by injecting fluid into a hydraulic fracture in the earth and producing the fluid hack while recovering power” (abstract) wherein “the energy used to deform the rock elastically is actually stored as potential energy. This energy can be recovered from the fluid stream ejected from the fracture and borehole as the rock relaxes to its original position. Thus, after a large fracture is formed, the fluid filled space can be used to hydraulically lift (and flex) overburden and store mechanical energy. That energy can be efficiently recovered by allowing the pressurized fluid to escape through a turbine. The process of injecting fluids at a pressure above the fracture gradient may be repeated a selected number of times, alternately with the process of producing fluid back to generate power. Thus the fracture functions as an elastic storage vessel” ([0023]).
It would have been obvious to one of ordinary skill in the art before the effective filing date of the claimed invention to have modified Lord to include using the energy obtained from an outside source to pump a fluid down Lord’s well comprising hydraulic fractures, with a reasonable expectation of success, in order to “deform the rock elastically” then “This energy can be recovered from the fluid stream ejected from the fracture and borehole as the rock relaxes to its original position” (thereby providing “A method of storing fluid in rock of a subterranean zone for energy storage purposes, comprising” etc.).
Regarding the second fluid comprising rubber tire crumb, class H cement, and/or buffered metal ion cross-linked PHPA, Lord discloses “Moderate to high viscosity can be imparted to the first fracturing fluid by viscosity increasing agents, e.g., guar and guar derivatives such as hydroxypropylguar, cellulose derivatives such as hydroxyethylcellulose, synthetic polymers such as polyacrylamide, and other polymers, all of which may or may not be crosslinked” (Col. 5, lines 30-35).
However, Lord fails to specify including buffered metal ion cross-linked PHPA.
Nguyen ‘273 teaches “forming a fracture” with “a pad fluid,” “a first slurry fluid,” and “a second slurry fluid” (abstract), these being wellbore servicing fluids (WSFs) ([0030]), wherein “the WSF comprises a viscosifying agent or a viscosifier” ([0039]) such as “polyacrylamide (PAM), partially hydrolyzed polyacrylamide (PHPA)” ([0043]) and “the WSF further comprises a crosslinker” ([0049]) such as “polyvalent metal ions” ([0050]) which may be “commercially available” as a “crosslinker/buffer system” or the like ([0051]).
It would have been obvious to one of ordinary skill in the art before the effective filing date of the claimed invention to have modified Lord to include imparting viscosity to Lord’s first fracturing fluid with viscosifying agents such as the “polyvalent metal ions” in a “crosslinker/buffer system” for “partially hydrolyzed polyacrylamide (PHPA)” as taught in Nguyen ‘273, with a reasonable expectation of success, in order to provide a specific type of “crosslinked” “synthetic polymers” which are “commercially available” as in Nguyen ‘273 (thereby including:
“injecting a second fluid into the wellbore, wherein the second fluid has a viscosity from ten to five thousand centipoise, and wherein the second fluid comprises rubber tire crumb, class H cement, buffered metal ion cross-linked partially hydrolyzed polyacrylamide (PHPA), or any combination thereof;”).
Second, the modification is obvious as no more than the use of familiar elements (known injection fluids, pumps, fractures, buffered crosslinkers, viscosifying polymers) according to known techniques (injecting viscosified fluids to fracture; pumping fluids into fractures) in a manner that achieves predictable results (fracturing and deforming the rock matrix to store energy). KSR Int'l Co. v. Teleflex Inc., 550 U.S. 398, 415-421, 82 USPQ2d 1385, 1395-97 (2007). See MPEP 2143 Examples of Basic Requirements of a Prima Facie Case of Obviousness.
Regarding independent claim 14, Lord discloses A method … (abstract “methods of controlling the growth of one or more vertically oriented fractures in a subterranean formation during a fracturing treatment” and Col. 2, lines 18-66 and Figs. 1-16), comprising:
injecting a first fluid into a wellbore (Col. 5, lines 10-14 “The formation 11 is broken down and the fracture 10 is initially hydraulically induced by the injection of a high density, usually low viscosity preflush fluid (often referred to as a prepad)”), wherein the first fluid has “low viscosity” (Col. 5, line 13);
injecting a second fluid into the wellbore (Col. 5, lines 20-23 “after injection of the preflush fluid, a first fracturing fluid (often referred to as a pad) having a high density, a moderate to high viscosity and having diverting agent suspended therein is injected”), wherein the second fluid begins as a fluid with “a moderate to high viscosity” (Col. 5, line 22);
wherein the first fluid and the second fluid are injected such that the second fluid has a viscosity equal to or greater than the viscosity of the first fluid (i.e., by virtue of the prepad having a “low” viscosity, the first fracturing fluid having a “moderate” viscosity, and the second fracturing fluid having a “high” viscosity), and may also exhibit greater shear thickening behavior (note “may”; also see Semenov below).
Regarding the 1-1000 cP and 10-5000 cP, Lord does not actually specify the viscosity values of the “low” viscosity, “moderate” viscosity, and “high” viscosity fluids, only giving an example of fluids viscosified with 20 lb/1000 gal of hydroxypropyl guar gelling agent (Col. 8, Example).
Nevertheless, low viscosities of 1-1000 cP and high viscosities of 100-1,000,000 cP are ordinary and typical in the art. For example, Nguyen teaches fracturing with “low-viscosity” fluids and “high-viscosity” fluids (abstract) wherein “The low-viscosity … may have a viscosity in the range of from about 1 cP to about 200 cP at a shear rate of 40 sec−1 at room temperature, encompassing any value and subset therebetween. For example, the low-viscosity of the micro-proppant fluid may be in the range of about 1 cP to about 40 cP, or about 40 cP to about 80 cP, or about 80 cP to about 120 cP, or about 120 cP to about 160 cP, or about 160 cP to about 200 cP” ([0036]) and “The viscosity of the high-viscosity pad fluids described herein may be in the range of from about 100 centipoise (cP) to about 20000 cP at a shear rate of 40 sec−1 at room temperature, encompassing any value and subset therebetween. For example, the viscosity of the high-viscosity pad fluids may be in the range of about 100 cP to about 1000 cP, or about 1000 cP to about 4000 cP, or about 4000 cP to about 8000 cP, or about 8000 cP to about 12000 cP, or about 12000 cP to about 16000 cP, or about 16000 cP to about 20000 cP” ([0035]).
Similarly, a “moderate” viscosity is presumably somewhere between 1-200 cP low viscosity and 100-20,000 cP high viscosity, e.g., 10-2,000 cP moderate viscosity. Accordingly, although silent to the exact values as instantly claimed, it would have been obvious to one having ordinary skill in the art before the effective filing date of the claimed invention to have modified Lord to include 1-200 cP low viscosity, 10-2,000 cP moderate viscosity, and 100-20,000 cP high viscosity, with a reasonable expectation of success, in order to provide typical and ordinary viscosities for the “low” viscosity, “moderate” viscosity, and “high” viscosity fluids (thereby providing:
“injecting a first fluid into a wellbore, wherein the first fluid has a viscosity from one to one thousand centipoise;
injecting a second fluid into the wellbore, wherein the second fluid has a viscosity from ten to five thousand centipoise”). See also MPEP 2144.05 Obviousness of Similar and Overlapping Ranges, Amounts, and Proportions. For example, Applicant has not disclosed any particular criticality to these claimed ranges.
Regarding the “becomes more viscous, or even solid, over time,” Nguyen further teaches “it may be desirable to crosslink the gelling agent(s) in the treatment fluids to further increase the viscosity thereof” ([0073]) and “the crosslinking agent may be formulated to remain inactive until it is “activated” by, among other things, certain conditions in the treatment fluid (e.g., pH, temperature, etc.) and/or interaction with some other substance. This may allow ease of pumping into the formation and, once therein, the treatment fluid may achieve its desired viscosity before being used to create or enhance a fracture (e.g., main fracture or branch fracture)” ([0075]).
It would have been obvious to one of ordinary skill in the art before the effective filing date of the claimed invention to have modified Lord to include an inactive crosslinking agent that become activated in the formation where it further increases the viscosity, with a reasonable expectation of success, in order to “allow ease of pumping into the formation and, once therein, the treatment fluid may achieve its desired viscosity before being used to create or enhance a fracture” (thereby including:
“injecting a second fluid into the wellbore, wherein the second fluid begins as a fluid with viscosity from ten to five thousand centipoise but becomes more viscous, or even solid, over time;”).
Regarding the “storing fluid in rock of a subterranean zone for energy storage purposes,” Lord as above discloses injecting etc.
However, Lord fails to disclose storing fluid in rock of a subterranean zone for energy storage purposes.
Schmidt ‘362 teaches “Energy is stored by injecting fluid into a hydraulic fracture in the earth and producing the fluid hack while recovering power” (abstract) wherein “the energy used to deform the rock elastically is actually stored as potential energy. This energy can be recovered from the fluid stream ejected from the fracture and borehole as the rock relaxes to its original position. Thus, after a large fracture is formed, the fluid filled space can be used to hydraulically lift (and flex) overburden and store mechanical energy. That energy can be efficiently recovered by allowing the pressurized fluid to escape through a turbine. The process of injecting fluids at a pressure above the fracture gradient may be repeated a selected number of times, alternately with the process of producing fluid back to generate power. Thus the fracture functions as an elastic storage vessel” ([0023]).
It would have been obvious to one of ordinary skill in the art before the effective filing date of the claimed invention to have modified Lord to include using the energy obtained from an outside source to pump a fluid down Lord’s well comprising hydraulic fractures, with a reasonable expectation of success, in order to “deform the rock elastically” then “This energy can be recovered from the fluid stream ejected from the fracture and borehole as the rock relaxes to its original position” (thereby providing “A method of storing fluid in rock of a subterranean zone for energy storage purposes, comprising” etc.).
Regarding the second fluid comprising rubber tire crumb, class H cement, and/or buffered metal ion cross-linked PHPA, Lord discloses “Moderate to high viscosity can be imparted to the first fracturing fluid by viscosity increasing agents, e.g., guar and guar derivatives such as hydroxypropylguar, cellulose derivatives such as hydroxyethylcellulose, synthetic polymers such as polyacrylamide, and other polymers, all of which may or may not be crosslinked” (Col. 5, lines 30-35).
However, Lord fails to specify including buffered metal ion cross-linked PHPA.
Nguyen ‘273 teaches “forming a fracture” with “a pad fluid,” “a first slurry fluid,” and “a second slurry fluid” (abstract), these being wellbore servicing fluids (WSFs) ([0030]), wherein “the WSF comprises a viscosifying agent or a viscosifier” ([0039]) such as “polyacrylamide (PAM), partially hydrolyzed polyacrylamide (PHPA)” ([0043]) and “the WSF further comprises a crosslinker” ([0049]) such as “polyvalent metal ions” ([0050]) which may be “commercially available” as a “crosslinker/buffer system” or the like ([0051]).
It would have been obvious to one of ordinary skill in the art before the effective filing date of the claimed invention to have modified Lord to include imparting viscosity to Lord’s first fracturing fluid with viscosifying agents such as the “polyvalent metal ions” in a “crosslinker/buffer system” for “partially hydrolyzed polyacrylamide (PHPA)” as taught in Nguyen ‘273, with a reasonable expectation of success, in order to provide a specific type of “crosslinked” “synthetic polymers” which are “commercially available” as in Nguyen ‘273 (thereby including:
“injecting a second fluid into the wellbore, wherein the second fluid begins as a fluid with viscosity from ten to five thousand centipoise but becomes more viscous, or even solid, over time, and wherein the second fluid comprises rubber tire crumb, class H cement, buffered metal ion cross-linked partially hydrolyzed polyacrylamide (PHPA), or any combination thereof;”).
Second, the modification is obvious as no more than the use of familiar elements (known injection fluids, pumps, fractures, buffered crosslinkers, viscosifying polymers) according to known techniques (injecting viscosified fluids to fracture; pumping fluids into fractures) in a manner that achieves predictable results (fracturing and deforming the rock matrix to store energy). KSR Int'l Co. v. Teleflex Inc., 550 U.S. 398, 415-421, 82 USPQ2d 1385, 1395-97 (2007). See MPEP 2143 Examples of Basic Requirements of a Prima Facie Case of Obviousness.
Regarding claims 2 and 15, Lord discloses an Example with “1.5 lb./gal. of a 50:50 mixture of 70-170 mesh sand and silica flour suspended in the first fracturing fluid” (Col. 8, lines 41-43). However, Lord discloses this Example for a first fracturing fluid being a “75% quality foam having a density of 4.13 lb./gal.” (Col. 8, lines 38-39), which is directed to a different embodiment using a “low density” first fracturing fluid (Col. 6, lines 44-52). Lord does not provide particle loading values for the embodiment using “a high density, a moderate to high viscosity” first fracturing fluid (Col. 5, lines 20-46).
Nevertheless, presumably the “high density” and “moderate” viscosity first fracturing fluid uses a similar particle loading, and an exemplary “high density” fluid has a density of “7.53 to 8.44 lb./gal.” (Col. 8, line 58), which is
1.5
l
b
/
g
a
l
7.53
t
o
8.44
l
b
/
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a
l
=
17.8
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19.9
w
t
%
.
Accordingly, even if it were found that Lord fails to disclose this per se, it would have been obvious to one having ordinary skill in the art before the effective filing date of the claimed invention to have modified Lord to include:
(claims 2 and 15) wherein the second fluid is loaded between 5% and 30% by weight with particles of varying composition;
such as 18-20 wt%, with a reasonable expectation of success, in order to provide a similar amount of particle loaded in the first fracturing fluid as in the general conditions described by Lord. See also MPEP 2144.05 Obviousness of Similar and Overlapping Ranges, Amounts, and Proportions.
For example, although not required to render this limitation obvious, Nguyen similarly teaches “the micro-proppant particulates may be present in the treatment fluids of the present disclosure in an amount in the range of from about 0.01 lbm/gal to about 1 lbm/gal, encompassing any value and subset therebetween” such as “from about 0.01 lbm/gal to about 0.2 lbm/gal, or about 0.2 lbm/gal to about 0.4 lbm/gal, or about 0.4 lbm/gal to about 0.6 lbm/gal, or about 0.6 lbm/gal to about 0.8 lbm/gal, or about 0.8 lbm/gal to about 1 lbm/gal” ([0082]). 0.6-1 lb/gal in water (~8.345 lb/gal density) is 7.2-12 wt%.
Regarding independent claim 21, Lord discloses A method of generating a self-propped hydraulic fracture in a rock formation (abstract “methods of controlling the growth of one or more vertically oriented fractures in a subterranean formation during a fracturing treatment” and Col. 2, lines 18-66 and Figs. 1-16), comprising:
injecting a first fluid into a wellbore (Col. 5, lines 10-14 “The formation 11 is broken down and the fracture 10 is initially hydraulically induced by the injection of a high density, usually low viscosity preflush fluid (often referred to as a prepad)”), wherein the first fluid has “low viscosity” (Col. 5, line 13);
injecting a second fluid into the wellbore (Col. 5, lines 20-23 “after injection of the preflush fluid, a first fracturing fluid (often referred to as a pad) having a high density, a moderate to high viscosity and having diverting agent suspended therein is injected”), wherein the second fluid has “a moderate to high viscosity” (Col. 5, line 22)…
Regarding the 1-1000 cP and 10-5000 cP, Lord does not actually specify the viscosity values of the “low” viscosity, “moderate” viscosity, and “high” viscosity fluids, only giving an example of fluids viscosified with 20 lb/1000 gal of hydroxypropyl guar gelling agent (Col. 8, Example).
Nevertheless, low viscosities of 1-1000 cP and high viscosities of 100-1,000,000 cP are ordinary and typical in the art. For example, Nguyen teaches fracturing with “low-viscosity” fluids and “high-viscosity” fluids (abstract) wherein “The low-viscosity … may have a viscosity in the range of from about 1 cP to about 200 cP at a shear rate of 40 sec−1 at room temperature, encompassing any value and subset therebetween. For example, the low-viscosity of the micro-proppant fluid may be in the range of about 1 cP to about 40 cP, or about 40 cP to about 80 cP, or about 80 cP to about 120 cP, or about 120 cP to about 160 cP, or about 160 cP to about 200 cP” ([0036]) and “The viscosity of the high-viscosity pad fluids described herein may be in the range of from about 100 centipoise (cP) to about 20000 cP at a shear rate of 40 sec−1 at room temperature, encompassing any value and subset therebetween. For example, the viscosity of the high-viscosity pad fluids may be in the range of about 100 cP to about 1000 cP, or about 1000 cP to about 4000 cP, or about 4000 cP to about 8000 cP, or about 8000 cP to about 12000 cP, or about 12000 cP to about 16000 cP, or about 16000 cP to about 20000 cP” ([0035]).
Similarly, a “moderate” viscosity is presumably somewhere between 1-200 cP low viscosity and 100-20,000 cP high viscosity, e.g., 10-2,000 cP moderate viscosity. Accordingly, although silent to the exact values as instantly claimed, it would have been obvious to one having ordinary skill in the art before the effective filing date of the claimed invention to have modified Lord to include 1-200 cP low viscosity, 10-2,000 cP moderate viscosity, and 100-20,000 cP high viscosity, with a reasonable expectation of success, in order to provide typical and ordinary viscosities for the “low” viscosity, “moderate” viscosity, and “high” viscosity fluids (thereby providing:
“injecting a first fluid into a wellbore, wherein the first fluid has a viscosity from one to one thousand centipoise;
injecting a second fluid into the wellbore, wherein the second fluid has a viscosity from ten to five thousand centipoise”). See also MPEP 2144.05 Obviousness of Similar and Overlapping Ranges, Amounts, and Proportions. For example, Applicant has not disclosed any particular criticality to these claimed ranges.
Regarding the 5-30 wt% particle loading in the second fluid, Lord discloses an Example with “1.5 lb./gal. of a 50:50 mixture of 70-170 mesh sand and silica flour suspended in the first fracturing fluid” (Col. 8, lines 41-43). However, Lord discloses this Example for a first fracturing fluid being a “75% quality foam having a density of 4.13 lb./gal.” (Col. 8, lines 38-39), which is directed to a different embodiment using a “low density” first fracturing fluid (Col. 6, lines 44-52). Lord does not provide particle loading values for the embodiment using “a high density, a moderate to high viscosity” first fracturing fluid (Col. 5, lines 20-46).
Nevertheless, presumably the “high density” and “moderate” viscosity first fracturing fluid uses a similar particle loading, and an exemplary “high density” fluid has a density of “7.53 to 8.44 lb./gal.” (Col. 8, line 58), which is
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.
Accordingly, even if it were found that Lord fails to disclose this per se, it would have been obvious to one having ordinary skill in the art before the effective filing date of the claimed invention to have modified Lord to include:
“injecting a second fluid into the wellbore, wherein the second fluid has a viscosity from ten to five thousand centipoise and is loaded between 5% and 30% by weight with particles of varying composition” such as 18-20 wt%,
with a reasonable expectation of success, in order to provide a similar amount of particle loaded in the first fracturing fluid as in the general conditions described by Lord. See also MPEP 2144.05 Obviousness of Similar and Overlapping Ranges, Amounts, and Proportions.
For example, although not required to render this limitation obvious, Nguyen similarly teaches “the micro-proppant particulates may be present in the treatment fluids of the present disclosure in an amount in the range of from about 0.01 lbm/gal to about 1 lbm/gal, encompassing any value and subset therebetween” such as “from about 0.01 lbm/gal to about 0.2 lbm/gal, or about 0.2 lbm/gal to about 0.4 lbm/gal, or about 0.4 lbm/gal to about 0.6 lbm/gal, or about 0.6 lbm/gal to about 0.8 lbm/gal, or about 0.8 lbm/gal to about 1 lbm/gal” ([0082]). 0.6-1 lb/gal in water (~8.345 lb/gal density) is 7.2-12 wt%.
Regarding the second fluid comprising rubber tire crumb, class H cement, and/or buffered metal ion cross-linked PHPA, Lord discloses “Moderate to high viscosity can be imparted to the first fracturing fluid by viscosity increasing agents, e.g., guar and guar derivatives such as hydroxypropylguar, cellulose derivatives such as hydroxyethylcellulose, synthetic polymers such as polyacrylamide, and other polymers, all of which may or may not be crosslinked” (Col. 5, lines 30-35).
However, Lord fails to specify including buffered metal ion cross-linked PHPA.
Nguyen ‘273 teaches “forming a fracture” with “a pad fluid,” “a first slurry fluid,” and “a second slurry fluid” (abstract), these being wellbore servicing fluids (WSFs) ([0030]), wherein “the WSF comprises a viscosifying agent or a viscosifier” ([0039]) such as “polyacrylamide (PAM), partially hydrolyzed polyacrylamide (PHPA)” ([0043]) and “the WSF further comprises a crosslinker” ([0049]) such as “polyvalent metal ions” ([0050]) which may be “commercially available” as a “crosslinker/buffer system” or the like ([0051]).
It would have been obvious to one of ordinary skill in the art before the effective filing date of the claimed invention to have modified Lord to include imparting viscosity to Lord’s first fracturing fluid with viscosifying agents such as the “polyvalent metal ions” in a “crosslinker/buffer system” for “partially hydrolyzed polyacrylamide (PHPA)” as taught in Nguyen ‘273, with a reasonable expectation of success, in order to provide a specific type of “crosslinked” “synthetic polymers” which are “commercially available” as in Nguyen ‘273 (thereby including:
“injecting a second fluid into the wellbore, wherein the second fluid has a viscosity from ten to five thousand centipoise and is loaded between 5% and 30% by weight with particles of varying composition, and wherein the second fluid comprises rubber tire crumb, class H cement, buffered metal ion cross-linked partially hydrolyzed polyacrylamide (PHPA), or any combination thereof;”).
Regarding the stored fluids, as above, Lord fractures the formation, but Lord fails to disclose storing the fluids under pressure in the rock formation.
Schmidt ‘362 teaches “Energy is stored by injecting fluid into a hydraulic fracture in the earth and producing the fluid hack while recovering power” (abstract) wherein “the energy used to deform the rock elastically is actually stored as potential energy. This energy can be recovered from the fluid stream ejected from the fracture and borehole as the rock relaxes to its original position. Thus, after a large fracture is formed, the fluid filled space can be used to hydraulically lift (and flex) overburden and store mechanical energy. That energy can be efficiently recovered by allowing the pressurized fluid to escape through a turbine. The process of injecting fluids at a pressure above the fracture gradient may be repeated a selected number of times, alternately with the process of producing fluid back to generate power. Thus the fracture functions as an elastic storage vessel” ([0023]).
It would have been obvious to one of ordinary skill in the art before the effective filing date of the claimed invention to have modified Lord to include using the energy obtained from an outside source to pump a fluid down Lord’s well comprising hydraulic fractures, with a reasonable expectation of success, in order to “deform the rock elastically” then “This energy can be recovered from the fluid stream ejected from the fracture and borehole as the rock relaxes to its original position” (thereby providing:
“wherein the first fluid and the second fluid are stored under pressure in the rock formation after injecting, and wherein stored fluids comprise the first fluid and the second fluid stored under pressure in the rock formation;”).
Regarding the thermal features providing heat and the heated fluids retaining heat, Applicant should note that mere recognition of latent properties in the prior art does not render nonobvious an otherwise known invention, and "[t]he fact that appellant has recognized another advantage which would flow naturally from following the suggestion of the prior art cannot be the basis for patentability when the differences would otherwise be obvious." See MPEP 2145.
In this case, fluids placed downhole are well-known to acquire and retain heat, as is well-known to be utilized in geothermal applications, heat pumps, and the like. For example, Nguyen states “with time and heat in a subterranean environment, the anhydrous borate materials react with surrounding aqueous fluid and are hydrated” ([0090]); “Temperature activated breakers may activate by being heated by a subterranean formation in which they are placed” ([0103]); and “Some suitable resins, such as epoxy resins, may be cured with an internal catalyst or activator so that when pumped downhole, they may be cured using time and temperature. Other suitable resins, such as furan resins generally require a time-delayed catalyst or an external catalyst to help activate the polymerization of the resins if the cure temperature is low (i.e., less than about 121°C (about 250°F), but will cure under the effect of time and temperature, as well as a subterranean formation having a formation temperature above about 121°C (about 250°F), preferably above about 149°C (about 300°F)” ([0115]). Accordingly, Lord in view of Schmidt ‘142 as above must further provide:
“wherein thermal features of the rock formation provide heat to the stored fluids to provide heated stored fluids, and further wherein the heated stored fluids retain heat from the rock formation when flowing out of the rock formation,” by virtue of the natural processes that always occur, and this would be merely an advantage that flows naturally from following the suggestion of the prior art.
Second, the modifications are obvious as no more than the use of familiar elements (known injection fluids, pumps, fractures, buffered crosslinkers, viscosifying polymers, downhole heat) according to known techniques (injecting viscosified fluids to fracture; pumping fluids into fractures; heating fluids downhole) in a manner that achieves predictable results (fracturing and deforming the rock matrix to store energy; producing heated fluids). KSR Int'l Co. v. Teleflex Inc., 550 U.S. 398, 415-421, 82 USPQ2d 1385, 1395-97 (2007). See MPEP 2143 Examples of Basic Requirements of a Prima Facie Case of Obviousness.
Regarding claims 3-5, 16, 17, 22, 23, and 25, Lord discloses “a second fracturing fluid having a low density, a high viscosity and containing propping agent suspended therein is injected” (Col. 5, lines 60-62), injected after a “low” viscosity prepad and a “moderate” viscosity 1st fracturing fluid.
However, Lord fails to disclose the 100-1,000,000 cP; a breaker; or 0.01-5 wt% particles in the third fluid.
Nevertheless, these are all well-known and ordinary in the art. For example, Nguyen teaches fracturing with “low-viscosity” fluids and “high-viscosity” fluids (abstract) wherein “The viscosity of the high-viscosity pad fluids described herein may be in the range of from about 100 centipoise (cP) to about 20000 cP at a shear rate of 40 sec−1 at room temperature, encompassing any value and subset therebetween. For example, the viscosity of the high-viscosity pad fluids may be in the range of about 100 cP to about 1000 cP, or about 1000 cP to about 4000 cP, or about 4000 cP to about 8000 cP, or about 8000 cP to about 12000 cP, or about 12000 cP to about 16000 cP, or about 16000 cP to about 20000 cP” ([0035]). Nguyen further teaches “any of the treatment fluids (i.e., the high-viscosity pad fluid, the low-viscosity micro-proppant fluid, the low-viscosity macro-proppant fluid, and the low-viscosity diversion fluid) of the present disclosure may further comprise a breaker. As used herein, the term “breaker” refers to any substance that is capable of decreasing the viscosity of a fluid. The breaker may be activated to reduce the viscosity of a treatment to facilitate removal of at least a portion of the broken treatment fluid from the wellbore and to the surface” ([0100]). Nguyen also teaches “the macro-proppant particulates may be present in the treatment fluids of the present disclosure in an amount in the range of from about 0.25 pounds per gallon (lbm/gal) to about 10 lbm/gal” such as “about 0.25 lbm/gal to about 2 lbm/gal, or about 2 lbm/gal to about 4 lbm/gal, or about 4 lbm/gal to about 6 lbm/gal, or about 6 lbm/gal to about 8 lbm/gal, or about 8 lbm/gal to about 10 lbm/gal, encompassing any value and subset therebetween” ([0082]). 0.25 lb/gal in water (~8.345 lb/gal density) is 3.0 wt%.
Accordingly, it would have been obvious to one having ordinary skill in the art before the effective filing date of the claimed invention to have modified Lord to include the 2nd fracturing fluid being 100-20,000 cP high viscosity; with a breaker; and about 3.0 wt% proppant loading, with a reasonable expectation of success, in order to provide a typical and ordinary viscosity of a “high viscosity” fluid; to reduce the viscosity of a treatment to facilitate removal; and to provide a typical and ordinary amount of proppant (thereby providing:
(claim 3) injecting a third fluid into the wellbore, wherein the third fluid has a viscosity of one hundred to one million centipoise; and further
(claim 4) wherein the second fluid and the third fluid are injected such that the third fluid has a viscosity equal to or greater than the viscosity of the second fluid; and/or
(claim 5) wherein the third fluid comprises a chemical component which causes the third fluid’s viscosity to reduce, or break, over a predetermined period of time; and/or
(claim 16) injecting a third fluid into the wellbore, wherein the third fluid has a viscosity of one hundred to one million centipoise, has a chemical breaker which reduces its viscosity over time, and contains particles between 0.01% and 5% by weight; and further
(claim 17) wherein the second fluid and the third fluid are injected such that the third fluid has a viscosity equal to or greater than the viscosity of the second fluid, and may also exhibit greater shear thickening behavior; and/or
(claim 22) injecting a third fluid into the wellbore, wherein the third fluid has a viscosity of one hundred to one million centipoise; and further
(claim 23) wherein the first fluid, the second fluid and the third fluid are injected such that each successive injection fluid has a viscosity equal to or greater than the viscosity of the preceding injection fluid; and/or
(claim 25) wherein the stored fluids comprise the third fluid).
See also MPEP 2144.05 Obviousness of Similar and Overlapping Ranges, Amounts, and Proportions. For example, Applicant has not disclosed any particular criticality to these claimed ranges.
Regarding claims 8, 9, 18, and 19, Lord discloses “In preferred embodiments of the methods described, spacer fluids containing additives for providing fracturing fluid compatibility with the formation being fractured and for establishing flow patterns over or under the fracturing fluids involved are also introduced into the fractures” (Col. 2, line 67-Col. 3, line 4) such as where “a low viscosity spacer fluid having a density lower than the density of the first fracturing fluid and preflush fluid is next injected into the fracture 10” i.e. between the second and third fluids (Col. 5, lines 47-50; see also Figs. 1-16). Lord does not mention interaction between the fluids and the spacer. Accordingly, Lord discloses:
(claims 8 and 18) injecting a spacer fluid between any of the first, second, or third fluids, wherein the spacer fluid prevents or retards interaction of any of the first, second, or third fluids between which the spacer is injected; and further
(claims 9 and 19) wherein the spacer retains nominal composition or is acted upon by one or more downhole or injected chemicals causing the properties of the spacer to change over time.
Regarding claims 10 and 20, Lord discloses using spacer fluids (Col. 2, line 67-Col. 3, line 4).
However, Lord does not specify that the spacer fluids are cycled out of the fracture.
Nevertheless, such fluids are typically produced back and thus cycled out of the fracture. For example, Nguyen teaches fracturing with “low-viscosity” fluids and “high-viscosity” fluids (abstract) wherein “the breaker may be included in a spacer fluid” and “The breaker may be activated to reduce the viscosity of a treatment to facilitate removal of at least a portion of the broken treatment fluid from the wellbore and to the surface” i.e. cycling out of the fracture ([0100]).
It would have been obvious to one of ordinary skill in the art before the effective filing date of the claimed invention to have modified Lord to include “wherein the spacer fluid is cycled out of the fracture,” with a reasonable expectation of success, in order to remove at least a portion of the broken spacer fluid from the wellbore and to the surface, thereby enhancing production from the fracture.
Regarding claims 11, 13, and 26, Lord discloses all elements, except for including a breaker.
Nevertheless, breakers are rather well-known in the art. For example, Nguyen teaches fracturing with “low-viscosity” fluids and “high-viscosity” fluids (abstract) wherein “any of the treatment fluids (i.e., the high-viscosity pad fluid, the low-viscosity micro-proppant fluid, the low-viscosity macro-proppant fluid, and the low-viscosity diversion fluid) of the present disclosure may further comprise a breaker. As used herein, the term “breaker” refers to any substance that is capable of decreasing the viscosity of a fluid. The breaker may be activated to reduce the viscosity of a treatment to facilitate removal of at least a portion of the broken treatment fluid from the wellbore and to the surface. In some embodiments, the breaker may be included in a spacer fluid included prior to the introduction of the low-viscosity macro-proppant fluid and/or the low-viscosity diversion fluid” ([0100]).
It would have been obvious to one of ordinary skill in the art before the effective filing date of the claimed invention to have modified Lord to include a breaker in any of the fluids, such as the prepad, 1st fracturing, 2nd fracturing, or spacer fluids, with a reasonable expectation of success, in order to “reduce the viscosity of a treatment to facilitate removal of at least a portion of the broken treatment fluid from the wellbore and to the surface” either directly or with the adjacent fluid (thereby including:
(claim 11) injecting a fluid with a breaker that substantially lowers the viscosity of the previously injected fluid; and/or
(claim 13) in which a further injection is of a fluid that has a chemical component which causes the fluid to reduce, or break, its viscosity over a predetermined range of times; and/or
(claim 26) injecting a fluid with a breaker that substantially lowers the viscosity of the previously injected fluid).
Second, the modification is obvious as no more than the use of familiar elements (known low viscosity, moderate viscosity, and high viscosity fluids and breakers) according to known techniques (fracturing with spacer fluids) in a manner that achieves predictable results (propping a fracture and then removing viscosified fluids). KSR Int'l Co. v. Teleflex Inc., 550 U.S. 398, 415-421, 82 USPQ2d 1385, 1395-97 (2007). See MPEP 2143 Examples of Basic Requirements of a Prima Facie Case of Obviousness.
Claims 6, 7, 12, and 24 are also rejected under 35 U.S.C. 103 as obvious over Lord in view of Nguyen and Schmidt ‘362 as in claims 1 and 21, and further in view of Semenov (2016/0319185) (cited by Applicant and in parent).
Regarding claims 6, 12, and 24, Lord discloses “The propping agent is maintained in suspension in the second fracturing fluid as a result of high viscosity imparted to it by viscosity increasing agents” (Col. 5, line 68-Col. 6, line 3).
However, Lord fails to specify using shear thickening fluids.
Semenov teaches “delivering materials downhole employing a shear thickening treatment fluid” wherein “The shear thickening fluid may inhibit particulate dispersion, settling or a combination thereof at high shear rates and facilitate dispersion and/or settling of the particulates and/or formation of pillars or clusters in the fracture at low shear rates” (abstract) and more specifically, “following the injection into the wellbore, transitioning the shear thickening treatment fluid, from a first flow regime with a relatively moderate shear rate from 10 up to 100 s−1, to a second flow regime with a higher shear rate relative to the moderate shear rate of the first flow regime, wherein the viscosity of the shear thickening treatment fluid increases with increasing shear rate in the second flow regime to inhibit dispersion and/or settling of the particulates; and transitioning the shear thickening treatment fluid from the second flow regime to a third flow regime with a lower shear rate relative to the moderate shear rate of the first flow regime, to promote dispersion and/or settling of at least some of the particulates” ([0017]).
It would have been obvious to one of ordinary skill in the art before the effective filing date of the claimed invention to have modified Lord to include shear thickening fluids, which have increasing shear thickening properties, with a reasonable expectation of success, in order to first “inhibit dispersion and/or settling of the particulates” then “promote dispersion and/or settling” increasingly for each fluid (thereby including:
(claim 6) wherein each successive fluid has successively increasing shear thickening properties; and/or
(claim 12) in which a further injection is of a fluid that is shear thickening; and/or
(claim 24) wherein each successive fluid has successively increasing shear thickening properties).
Regarding claim 7, Lord discloses “a second fracturing fluid having a low density, a high viscosity and containing propping agent suspended therein is injected” (Col. 5, lines 60-62).
However, Lord fails to disclose 0.01-5 wt% particles in the third fluid.
Nguyen teaches “the macro-proppant particulates may be present in the treatment fluids of the present disclosure in an amount in the range of from about 0.25 pounds per gallon (lbm/gal) to about 10 lbm/gal” such as “about 0.25 lbm/gal to about 2 lbm/gal, or about 2 lbm/gal to about 4 lbm/gal, or about 4 lbm/gal to about 6 lbm/gal, or about 6 lbm/gal to about 8 lbm/gal, or about 8 lbm/gal to about 10 lbm/gal, encompassing any value and subset therebetween” ([0082]). 0.25 lb/gal in water (~8.345 lb/gal density) is 3.0 wt%.
Although silent to the exact concentration of proppant as instantly claimed, it would have been obvious to one having ordinary skill in the art before the effective filing date of the claimed invention to have modified Lord to include, e.g, about 0.25 lb/gal or 3 wt%, with a reasonable expectation of success, in order to provide a typical and ordinary amount of proppant (thereby including “in which the third fluid contains particles between 0.01% and 5% by weight that serve as healing materials for previous treatments”). See also MPEP 2144.05 Obviousness of Similar and Overlapping Ranges, Amounts, and Proportions. For example, Applicant has not disclosed any particular criticality to this claimed range.
Double Patenting
Claims 1-26 are rejected on the ground of nonstatutory double patenting as being unpatentable over claims 1-15 of U.S. Patent No. 12,123,293 in view of Schmidt ‘362.
Regarding independent claims 1, 14, and 21, these correspond with 12,123,293 claims 1, 7, and 12, except for storing fluids for energy storage and thermal features providing heat. Nevertheless, these aspects are obvious over Schmidt ‘362 as above.
Regarding claims 2-13, 15-20, and 22-26, these correspond with 12,123,293 claims 1-15.
Response to Arguments
Applicant's arguments filed 20 January 2026 with respect to claims rejected under 35 USC § 103 over Schmidt have been fully considered but they are not persuasive.
First, regarding Priority, Applicant has only pointed to the Background of the Specification as providing support for “A method of storing fluid in rock of a subterranean zone for energy storage purposes” (independent claims 1/14/21) and further “wherein the first fluid and the second fluid are stored under pressure in the rock formation after injecting, and wherein stored fluids comprise the first fluid and the second fluid stored under pressure in the rock formation; and wherein thermal features of the rock formation provide heat to the stored fluids to provide heated stored fluids, and further wherein the heated stored fluids retain heat from the rock formation when flowing out of the rock formation” (claim 21) (Applicant Remarks, p.6-7).
However, at no point do any statements in the Background indicate or suggest that Applicant reasonably demonstrated possession of the particular combination as claimed in claims 1, 12, and 21. The Background section is typically understood to not refer to the disclosed Invention itself, but rather background information.
Notably, Applicant states “It is inherent and also specifically taught in the Specification that injecting a first fluid into a wellbore and injecting a second fluid into a wellbore are for storing fluid in rock of a subterranean zone for energy storage purposes, as required by independent claims l and 14, as the Specification in paragraph [0004] teaches using hydraulic fractures to store pressurized fluids for energy storage purposes and that transport of the fluid through the fracture is important to such energy storage purposes as well as using a fracture for heat exchanger purposes” (p.7) (underlining added).
To satisfy the written description requirement, a patent specification must describe the claimed invention in sufficient detail that one skilled in the art can reasonably conclude that the inventor had possession of the claimed invention. While there is no in haec verba requirement, newly added claims or claim limitations must be supported in the specification through express, implicit, or inherent disclosure. The fundamental factual inquiry is whether the specification conveys with reasonable clarity to those skilled in the art that, as of the filing date sought, the inventor was in possession of the invention as now claimed. See MPEP 2163.
Any statements that the Specification “teaches” or has “taught” a limitation is insufficient for Written Description support because a teaching is not “express, implicit, or inherent disclosure.” Accordingly, Applicant’s statements about “teaches” or has “taught” cannot be persuasive to demonstrate Written Description support.
As for Applicant’s statement that there is “inherent” disclosure of the energy storage embodiment, Applicant should note that the fact that a certain result or characteristic may occur or be present in the prior art is not sufficient to establish the inherency of that result or characteristic. See MPEP 2112. Also, "[a]n invitation to investigate is not an inherent disclosure" where a prior art reference "discloses no more than a broad genus of potential applications of its discoveries." Metabolite Labs., Inc. v. Lab. Corp. of Am. Holdings, 370 F.3d 1354, 1367, 71 USPQ2d 1081, 1091 (Fed. Cir. 2004).
In this case, it appears that the disclosure at best provides an “invitation to investigate” if the “self-propped hydraulic fractures” formed by the Invention (Specification Brief Summary and Detailed Description, [0007]-[0017]) may be used for “a broad genus of potential applications of its discoveries” such as “to access geopressured fluids, geothermal brines, or other minerals of interest,” “as a heat exchanger to exploit thermal features of the rock matrix,” or “to store pressurized fluids for energy storage purposes” (Specification Background [0004]). However, at no point does the disclosure actually describe using the self-propped hydraulic fractures for these purposes, and especially does not describe the steps that would be taken in using the sealed fractures for these purposes e.g. as in claim 21.
The same applies to Applicant’s further statements about claim 21 (p.7)
Accordingly, these arguments are not persuasive, and the current claims are being treated under the current filing date of 22 October 2024. Similarly, the rejections over Schmidt are maintained.
Applicant’s arguments with respect to claims rejected under 35 USC § 103 over Lord in view of Nguyen and Schmidt ‘362 have been fully considered and are persuasive. Therefore, the rejection has been withdrawn. However, based on Applicant’s Amendment to the claims, a new ground(s) of rejection is made under 35 USC § 103 over Lord in view of Nguyen ‘160, Schmidt ‘362, and the new reference to Nguyen ‘273, and the arguments do not apply to the combination being used in the current rejection.
In the case of further Amendments, Applicant is advised to consider what are the critical features of the current Invention, and how do these critical features interact in the Invention in order to produce the unique phenomena of the Invention.
Nevertheless, Applicant is advised to beware the inclusion of New Matter.
As always, Applicant may consider contacting the Examiner for an Interview or the like, in the case further explanation or guidance is desired.
Conclusion
Applicant's amendment necessitated the new ground(s) of rejection presented in this Office action. Accordingly, THIS ACTION IS MADE FINAL. See MPEP § 706.07(a). Applicant is reminded of the extension of time policy as set forth in 37 CFR 1.136(a).
A shortened statutory period for reply to this final action is set to expire THREE MONTHS from the mailing date of this action. In the event a first reply is filed within TWO MONTHS of the mailing date of this final action and the advisory action is not mailed until after the end of the THREE-MONTH shortened statutory period, then the shortened statutory period will expire on the date the advisory action is mailed, and any nonprovisional extension fee (37 CFR 1.17(a)) pursuant to 37 CFR 1.136(a) will be calculated from the mailing date of the advisory action. In no event, however, will the statutory period for reply expire later than SIX MONTHS from the mailing date of this final action.
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/ANDREW SUE-AKO/Primary Examiner, Art Unit 3674