DETAILED ACTION
In response to remarks filed on 5 March 2025
Status of Claims
Claims 1-17 and 21-23 are pending;
Claims 1, 3, 5-12, 15 and 16 are currently amended;
Claims 2, 4, 13, 14 and 17 were previously presented;
Claims 18-20 are cancelled;
Claims 21-23 are new;
Claims 1-17 and 21-23 are rejected herein.
Response to Arguments
Applicant’s arguments filed on 5 March 2025 have been fully considered and they are moot since a new reference is being incorporated to reject the claims in view of the new limitations.
Claim Rejections - 35 USC § 103
The following is a quotation of 35 U.S.C. 103 which forms the basis for all obviousness rejections set forth in this Office action:
A patent for a claimed invention may not be obtained, notwithstanding that the claimed invention is not identically disclosed as set forth in section 102, if the differences between the claimed invention and the prior art are such that the claimed invention as a whole would have been obvious before the effective filing date of the claimed invention to a person having ordinary skill in the art to which the claimed invention pertains. Patentability shall not be negated by the manner in which the invention was made.
Claims 1, 13-17 and 21-23 is/are rejected under 35 U.S.C. 103 as being unpatentable over Vinegar et al (U.S. Patent Application Publication No. 2022/0251935) in view of Zupanick (U.S. Patent No. 6,708,764).
As to Claim 1, Vinegar discloses a system for storing gas within a subterranean formation (30), comprising:
A first wellbore (Figure 2A,112) comprising a curved wellbore path (The wellbore bend from vertical to horizontal is curved) extending into the subterranean formation from a first wellhead (80) at a surface location;
A fractured volume (35) of the subterranean formation (30) comprising a volume of proppant within a fracture network (32), wherein the fracture network is in response to a fracturing operation (Paragraph 0155: “In a second stage, between Time=T.sub.0 and Time=T.sub.1, the reservoir is hydraulically fractured. The deep horizontal wellbore is perforated for hydraulic fracturing, e.g., by a perforating gun. A fracturing fluid is injected under pressure through a horizontal wellbore into the geological formation to effect the fracturing by propagation and expansion of cracks in the rock structure. The hydraulic fracturing process is used to facilitate and/or accelerate the recovery of gas from the reservoir by opening up cracks in the deep shale formations. As is known in the art, successive sections of the reservoir along the wellbore are fractured sequentially and not simultaneously. An example of a suitable fracturing fluid is a mixture of water, a proppant such as sand or a ceramic, and/or a chemical or polymer to improve a flow characteristic such as the water's surface friction and/or to act as a lubricant”), wherein a volume of proppant is enhanced by the curved wellbore path (The curved wellbore enhances the volume of proppant by allowing the introduction of proppant to a larger area parallel to the ground surface), and wherein the subterranean formation (30) is a non-permeable formation (Deep shale formations are impermeable. See https://glossary.slb.com/terms/i/impermeable);
A gas source (80; Paragraph 0243: “The pumping arrangements 80 are in fluid communication with the wellbore 10 and are configured to inject hydrogen gas 8 therethrough into the hydraulically-fractured reservoir 35. In some embodiments, kerogen concentration in the reservoir is at least 1% by volume, or at least 2%, or at least 3%. The pumping arrangements 80 include pumps and compressors, piping (e.g., piping 12), power equipment, and other equipment as necessary for injecting the hydrogen gas 8. The pumping arrangements 80 are configured to inject the hydrogen 8 at a pressure higher than a current shut-in gas pressure at the wellbore”) fluidically coupled to the first wellhead (Figure 2A,112) and configured to pump a compressed gas into the fractured volume via the first wellbore (Paragraph 0200: “In a fourth stage, between Time=T2 and Time=T3, hydrogen gas is injected into the reservoir. In embodiments, the transition from the third stage to the fourth stage, at Time=T2, is based on a trigger criterion. The trigger criterion can include a trigger criterion that corresponds to a change in an isotope ratio matching an isotope-signature trigger criterion. An example of an isotopic-signature trigger criterion suitable for triggering a transition of operation of an unconventional gas reservoir to injecting compressed hydrogen for long- and/or short-term storage is a 6(13C) isotopic signature based on a ratio of 13C to 12C”); and
Wherein the fractured volume (35) within the non-permeable formation is configured to store the compressed gas (Paragraph 0243: “The pumping arrangements 80 are in fluid communication with the wellbore 10 and are configured to inject hydrogen gas 8 therethrough into the hydraulically-fractured reservoir 35).
However, Vinegar as modified is silent about the first wellbore comprising a curved single wellbore path comprising a curved wellbore path, wherein the curved wellbore path has a repetitive function with an amplitude and a period of repetition between transition sections. Zupanick discloses a first wellbore (200) comprising a curved single wellbore path (208, 210, 212) comprising a curved wellbore path (213), wherein the curved wellbore path has a repetitive function with an amplitude (215) and a period (214) of repetition between transition sections (Figures 6 and 7). Before the effective filing date of the invention, it would have been obvious to a person of ordinary skill in the art to have the first wellbore comprise a curved single wellbore path comprising a curved wellbore path, wherein the curved wellbore path has a repetitive function with an amplitude and a period of repetition between transition sections. The motivation would have been to distribute the material in a larger area.
As to Claim 13, Vinegar as modified teaches the invention of Claim 1 (Refer to Claim 1 discussion). Vinegar as modified also teaches wherein the proppant comprises a material that is i) porous (Paragraph 0155: “In a second stage, between Time=T.sub.0 and Time=T.sub.1, the reservoir is hydraulically fractured. The deep horizontal wellbore is perforated for hydraulic fracturing, e.g., by a perforating gun. A fracturing fluid is injected under pressure through a horizontal wellbore into the geological formation to effect the fracturing by propagation and expansion of cracks in the rock structure. The hydraulic fracturing process is used to facilitate and/or accelerate the recovery of gas from the reservoir by opening up cracks in the deep shale formations. As is known in the art, successive sections of the reservoir along the wellbore are fractured sequentially and not simultaneously. An example of a suitable fracturing fluid is a mixture of water, a proppant such as sand or a ceramic, and/or a chemical or polymer to improve a flow characteristic such as the water's surface friction and/or to act as a lubricant”) or ii) coated with a second material; wherein the second material comprises i) metal hydride or ii) metal-organic frameworks (MOF); wherein the metal hydrides comprise an alloy of palladium, magnesium, aluminum, or combinations thereof; and wherein the MOFs comprise microporous organometallic framework compounds, microporous crystalline aluminosilicates, microscopically small carbon nanotubes, copper, zinc, chromium, or combinations thereof.
As to Claim 14, Vinegar as modified teaches the invention of Claim 1 (Refer to Claim 1 discussion). Vinegar as modified also teaches wherein the non-permeable formation comprises a permeability value of less than 3 microdarcy (Paragraph 0154: “Non-limiting examples of technical selection criteria include, and not exhaustively: low permeability, e.g., permeability lower than 10−1 millidarcy (mD), lower than 10−2 mD, lower than 10−3 mD, or lower than 10−4 mD”).
As to Claim 15, Vinegar as modified teaches the invention of Claim 1 (Refer to Claim 1 discussion). Vinegar as modified also teaches wherein the gas source is further configured to: (i) generate a volume of hydrogen gas; (ii) compress the volume of hydrogen gas to provide a compressed hydrogen gas; and deliver the compressed hydrogen gas to the first wellhead (Paragraph 0243: “The pumping arrangements 80 are in fluid communication with the wellbore 10 and are configured to inject hydrogen gas 8 therethrough into the hydraulically-fractured reservoir 35. In some embodiments, kerogen concentration in the reservoir is at least 1% by volume, or at least 2%, or at least 3%. The pumping arrangements 80 include pumps and compressors, piping (e.g., piping 12), power equipment, and other equipment as necessary for injecting the hydrogen gas 8. The pumping arrangements 80 are configured to inject the hydrogen 8 at a pressure higher than a current shut-in gas pressure at the wellbore”).
As to Claim 16, Vinegar as modified teaches the invention of Claim 1 (Refer to Claim 1 discussion). Vinegar as modified also teaches wherein the system further comprises a gas retrieval system configured to: (i) retrieve a volume of hydrogen gas from the compressed gas in the fractured volume of the subterranean formation (Paragraph 0158: “In a fifth stage, between Time=T3 and Time=T4, stored hydrogen gas is recovered from the reservoir. The recovered hydrogen gas is mostly pure hydrogen”); and (ii) generate electrical power from the retrieved hydrogen gas (Paragraph 0151: “generating electricity from at least a portion of the recovered hydrogen-containing gas”).
As to Claim 17, Vinegar as modified teaches the invention of Claim 16 (Refer to Claim 16 discussion). Vinegar as modified also teaches wherein the volume of hydrogen gas is retrieved via the first wellbore (Paragraph 0158: “In a fifth stage, between Time=T3 and Time=T4, stored hydrogen gas is recovered from the reservoir. The recovered hydrogen gas is mostly pure hydrogen”), via a second wellbore, via a third wellbore, or any combination thereof.
As to Claim 21, Vinegar as modified teaches the invention of Claim 1 (Refer to Claim 1 discussion). Vinegar as modified also teaches wherein the period varies along a length of the curved wellbore path (Zupanick: Column 9, Line 66 to Column 10, Line 19: “In an alternative embodiment, undulating well bore 200 need not have periodic characteristics. The displacement of undulating well bore 200 may vary over space in a non-uniform manner. The wavelength 214 of each waveform 213 may vary throughout the length of undulating well bore 200. For example, the wave length 214 of the first wave cycle may be six hundred feet, while the wave length 214 of the second waveform 213 may be seven hundred feet. Thus, the wave length 214 of each waveform 213 may vary throughout undulating well bore 200 and may be of any number of lengths for effectively accessing layer 202. Additionally or alternatively, the wave height 214 of each waveform 213 may vary such that the wave height 215 of a specific waveform 213 is different from the wave height 215 of the preceding waveform 213. For example, the wave height 215 of the first waveform 213 may be ten feet, while the wave height 215 of the second waveform 213 may be fifteen feet. One of ordinary skill in the art may recognize, however, that the above described wave heights 215 are merely exemplary. The wave height 215 of each waveform 213 may vary and be of any height for effectively accessing layer 202”).
As to Claim 22, Vinegar as modified teaches the invention of Claim 1 (Refer to Claim 1 discussion). Vinegar as modified also teaches wherein the amplitude varies along a length of the curved wellbore path (Zupanick: Column 9, Line 66 to Column 10, Line 19: “In an alternative embodiment, undulating well bore 200 need not have periodic characteristics. The displacement of undulating well bore 200 may vary over space in a non-uniform manner. The wavelength 214 of each waveform 213 may vary throughout the length of undulating well bore 200. For example, the wave length 214 of the first wave cycle may be six hundred feet, while the wave length 214 of the second waveform 213 may be seven hundred feet. Thus, the wave length 214 of each waveform 213 may vary throughout undulating well bore 200 and may be of any number of lengths for effectively accessing layer 202. Additionally or alternatively, the wave height 214 of each waveform 213 may vary such that the wave height 215 of a specific waveform 213 is different from the wave height 215 of the preceding waveform 213. For example, the wave height 215 of the first waveform 213 may be ten feet, while the wave height 215 of the second waveform 213 may be fifteen feet. One of ordinary skill in the art may recognize, however, that the above described wave heights 215 are merely exemplary. The wave height 215 of each waveform 213 may vary and be of any height for effectively accessing layer 202”).
As to Claim 23, Vinegar as modified teaches the invention of Claim 1 (Refer to Claim 1 discussion). Vinegar as modified also teaches wherein the curved wellbore path (Zupanick: 208, 210, 212) promotes fracture interference between fracture stresses extending from initiation points produced during the fracturing operation.
Claim 1 is/are rejected under 35 U.S.C. 103 as being unpatentable over Dykstra et al (U.S. Patent Application Publication No. 2017/0335663) in view of Zupanick (U.S. Patent No. 6,708,764).
As to Claim 1, Dykstra discloses a system for storing gas within a subterranean formation (104), comprising:
A first wellbore (102) comprising a curved wellbore path (The wellbore bend from vertical to horizontal is curved. Additionally, Paragraph 0011 states: “Wellbore 102, as shown in FIG. 1, may include a horizontal wellbore. However, a well system may include any combination of horizontal, vertical, slant, curved, or other wellbore orientations”) extending into the subterranean formation from a first wellhead (105) at a surface location;
A fractured volume (130) of the subterranean formation comprising a volume of proppant within a fracture network (Paragraph 0025: “When the proppant enters fracture 130, the proppant may form a packed mass in fracture 130”), wherein the fracture network (Elements 130 grouped together) is in response to a fracturing operation, wherein a volume of proppant is enhanced by the curved wellbore path (The curved wellbore enhances the volume of proppant by allowing the introduction of proppant to a larger area parallel to the ground surface), and wherein the subterranean formation (104) is a non-permeable formation (Paragraph 0014: “For example, subterranean region 104 may include all or part of a rock formation (e.g., shale, coal, sandstone, granite, or others) that contains natural gas”. Paragraph 0034 of applicant’s own specification states that granite formations are non-permeable);
A gas source (108) fluidically coupled to the first wellhead (105) and configured to pump a compressed gas into the fractured volume via the first wellbore (Paragraph 0017: “Injection system 108 may include instrument truck 114, pump truck 116, and injection treatment control subsystem 111”; Paragraph 0018: “Pump trucks 116 may include mobile vehicles, immobile installations, skids, hoses, tubes, fluid tanks, fluid reservoirs, pumps, valves, mixers, or other types of structures and equipment. Pump trucks 116 may supply treatment fluid or other materials for a treatment. Pump trucks 116 may contain multiple different treatment fluids, proppant materials, or other materials for different stages of a treatment”. The pump is capable of pumping a compressed gas downhole. The limitation “configured to” only requires capability); and
Wherein the fractured volume (130) within the non-permeable formation is configured to store the compressed gas (The fracture volume are openings in the formation accessible via the wellbore. Therefore, this volume is capable of storing compressed gas. The limitation “configured to” only requires capability).
However, Dykstra is silent about the first wellbore comprising a curved single wellbore path comprising a curved wellbore path, wherein the curved wellbore path has a repetitive function with an amplitude and a period of repetition between transition sections. Zupanick discloses a first wellbore (200) comprising a curved single wellbore path (208, 210, 212) comprising a curved wellbore path (213), wherein the curved wellbore path has a repetitive function with an amplitude (215) and a period (214) of repetition between transition sections (Figures 6 and 7). Before the effective filing date of the invention, it would have been obvious to a person of ordinary skill in the art to have the first wellbore comprise a curved single wellbore path comprising a curved wellbore path, wherein the curved wellbore path has a repetitive function with an amplitude and a period of repetition between transition sections. The motivation would have been to distribute the material in a larger area.
Claims 2-12 is/are rejected under 35 U.S.C. 103 as being unpatentable over Vinegar et al (U.S. Patent Application Publication No. 2022/0251935) in view of Zupanick (U.S. Patent No. 6,708,764); and further in view of Boone et al (U.S. Patent Application Publication No. 2011/0272153).
As to Claim 2, Vinegar as modified teaches the invention of Claim 1 (Refer to Claim 1 discussion). However, Vinegar as modified is silent about wherein the curved wellbore path of the first wellbore comprises a sinusoidal wellbore path with a vertical portion coupled to the first wellhead. Boone discloses a curved wellbore path of a first wellbore comprising a sinusoidal wellbore path (50) with a vertical portion coupled to the first wellhead (Figure 5). Before the effective filing date of the invention, it would have been obvious to a person of ordinary skill in the art to make the curved wellbore path of the first wellbore comprise a sinusoidal wellbore path with a vertical portion coupled to the first wellhead. The motivation would have been to distribute the material in a larger area.
As to Claim 3, Vinegar as modified teaches the invention of Claim 1 (Refer to Claim 1 discussion). However, Vinegar as modified is silent about wherein the curved wellbore path of the first wellbore comprises a helical wellbore path with a vertical portion coupled to the first wellhead. Boone discloses a curved wellbore path of a first wellbore comprising a helical wellbore path (60, 61) with a vertical portion coupled to the first wellhead (Figure 6). Before the effective filing date of the invention, it would have been obvious to a person of ordinary skill in the art to make the curved wellbore path of the first wellbore comprise a helical wellbore path with a vertical portion coupled to the first wellhead. The motivation would have been to distribute the material in a larger area.
As to Claim 4, Vinegar as modified teaches the invention of Claim 3 (Refer to Claim 3 discussion). Vinegar as modified also teaches wherein the curved wellbore path with the helical wellbore path (Boone: 60, 61) is drilled along or substantially coincident to a fracture plane (Boone: 65, 66) of the subterranean formation.
As to Claim 5, Vinegar as modified teaches the invention of Claim 1 (Refer to Claim 1 discussion). However, Vinegar as modified is silent about further comprising a second wellbore comprising a substantially horizontal wellbore penetrating the subterranean formation from a second wellhead at the surface location, and wherein the second wellbore is fluidically coupled to the first wellbore via the fractured volume. Boone discloses a second wellbore (52 or 64) comprising a substantially horizontal wellbore penetrating the subterranean formation from a second wellhead at the surface location, and wherein the second wellbore is fluidically coupled to a first wellbore (51 or 62) via a fractured volume (55 or 63). Before the effective filing date of the invention, it would have been obvious to a person of ordinary skill in the art to provide a second wellbore comprising a substantially horizontal wellbore penetrating the subterranean formation from a second wellhead at the surface location, and wherein the second wellbore is fluidically coupled to the first wellbore via the fractured volume. The motivation would have been to distribute the material in a larger area.
As to Claim 6, Vinegar as modified teaches the invention of Claim 5 (Refer to Claim 5 discussion). Vinegar as modified also teaches wherein the substantially horizontal wellbore (Boone: 52) of the second wellbore is located i) above or ii) below the curved wellbore with a sinusoidal wellbore path (Boone: 50) in a horizontal plane.
As to Claim 7, Vinegar as modified teaches the invention of Claim 5 (Refer to Claim 5 discussion). Vinegar as modified also teaches wherein the curved wellbore path comprises a sinusoidal wellbore path (Boone: 50) in a horizontal plane drilled perpendicular to a fracture plane (Boone: 53 or 54) of the subterranean formation.
As to Claim 8, Vinegar as modified teaches the invention of Claim 5 (Refer to Claim 5 discussion). Vinegar as modified also teaches wherein the substantially horizontal second wellbore (Boone: 52) is located substantially parallel to a wellbore axis of the curved wellbore path with a sinusoidal wellbore path (Boone: 50) in a vertical plane.
As to Claim 9, Vinegar as modified teaches the invention of Claim 8 (Refer to Claim 8 discussion). Vinegar as modified also teaches wherein the curved wellbore path with the sinusoidal wellbore path (Boone: 50) in a vertical plane is drilled along or substantially coincident to a fracture plane (Boone: 53 or 54) of the subterranean formation.
As to Claim 10, Vinegar as modified teaches the invention of Claim 5 (Refer to Claim 5 discussion). Vinegar as modified also teaches wherein the substantially horizontal second wellbore (Boone: 64) is located substantially coincident to a wellbore axis of the curved wellbore path, and wherein the curved wellbore path comprises a helical wellbore path (Boone: 52).
As to Claim 11, Vinegar as modified teaches the invention of Claim 5 (Refer to Claim 5 discussion). However, Vinegar as modified is silent about a third wellbore comprising a substantially horizontal wellbore penetrating the subterranean formation from a third wellhead at the surface location, and wherein the third wellbore is fluidically coupled to the first wellbore via the fractured volume. Boone discloses a third wellbore (75) comprising a substantially horizontal wellbore penetrating the subterranean formation from a third wellhead at the surface location, and wherein the third wellbore (75) is fluidically coupled to a first wellbore (70) via a fractured volume (74). Before the effective filing date of the invention, it would have been obvious to a person of ordinary skill in the art to provide a third wellbore comprising a substantially horizontal wellbore penetrating the subterranean formation from a third wellhead at the surface location, and wherein the third wellbore is fluidically coupled to the first wellbore via the fractured volume. The motivation would have been to distribute the material in a larger area.
As to Claim 12, Vinegar as modified teaches the invention of Claim 11 (Refer to Claim 11 discussion). Vinegar as modified also teaches wherein the substantially horizontal third wellbore (Boone: 75) is located below the curved wellbore path of the first wellbore (Boone: 70).
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.
Any inquiry concerning this communication or earlier communications from the examiner should be directed to EDWIN J TOLEDO-DURAN whose telephone number is (571)270-7501. The examiner can normally be reached Monday through Friday: 10:00AM to 6:00PM EST.
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/EDWIN J TOLEDO-DURAN/ Primary Examiner, Art Unit 3678
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