Notice of Pre-AIA or AIA Status
The present application, filed on or after March 16, 2013, is being examined under the first inventor to file provisions of the AIA .
Response to Amendment
The Amendment filed 12/17/25 has been entered. Claims 1-14 are pending in the application, of which claims 13 and 14 are new. Applicant’s amendments to the claims have overcome each and every objection and 112(b) rejection previously set forth in the Non-Final Office Action mailed 9/18/25.
Claim Rejections - 35 USC § 103
In the event the determination of the status of the application as subject to AIA 35 U.S.C. 102 and 103 (or as subject to pre-AIA 35 U.S.C. 102 and 103) is incorrect, any correction of the statutory basis (i.e., changing from AIA to pre-AIA ) for the rejection will not be considered a new ground of rejection if the prior art relied upon, and the rationale supporting the rejection, would be the same under either status.
The text of those sections of Title 35, U.S. Code not included in this action can be found in a prior Office action.
Claims 1-13 are rejected under 35 U.S.C. 103 as being unpatentable over Oghena et al. (US 2017/0058186- cited previously).
With respect to independent claim 1, Oghena discloses a method for recovering crude oil (Abstract and [0016]), the method comprising:
a reservoir modification fluid injection step of injecting, through an injection well into a crude oil-containing reservoir between the injection well and the production well, a reservoir modification fluid that reforms the wettability of the reservoir (Abstract, [0006], [0024]-[0026], [0040]-[0042], [0047], [0056], claims 23 and 24, and Fig. 1; the first of a sequence of injected slugs as part of a method which comprises injecting cycles of water and gas, the first slug comprising water and/or a gas, nanoparticles, and surfactant),
a primary crude oil recovery step of injecting an overflush fluid through the injection well into the reservoir, thereby moving the crude oil contained in the reservoir from a side of the injection well toward a side of the production well, and enabling recovery of the crude oil from the reservoir via the production well (Abstract, [0006], [0024]-[0026], [0040]-[0042], [0056], claims 23 and 24, and Fig. 1; the second of a sequence of injected slugs as part of a method which comprises injecting cycles of water and gas, the second slug comprising a gas),
a secondary crude oil recovery step of injecting a foam-stabilizing fluid and a foam-forming fluid through the injection well into the reservoir, thereby moving the crude oil contained in the reservoir from the side of the injection well toward the side of the production well, and enabling recovery of the crude oil from the reservoir via the production well (Abstract, [0006], [0024]-[0026], [0040]-[0042], [0056], claims 23 and 24, and Fig. 1; the third of a sequence of injected slugs as part of a method which comprises injecting cycles of water and gas, the third slug comprising water and/or a gas, foam, nanoparticles, and surfactant),
wherein the foam-stabilizing fluid is a surfactant-containing fluid, wherein the surfactant is an amphoteric surfactant ([0032]).
Regarding claim 1, Oghena discloses injecting a reservoir modification fluid into a crude-oil containing reservoir, wherein the fluid comprises water and/or a gas, nanoparticles, and surfactant (Abstract, [0006], [0024]-[0026], [0040]-[0042], [0047], [0056], claims 23 and 24, and Fig. 1). Since Oghena discloses the same composition as claimed, the material, if injected into a crude-oil containing reservoir would naturally act in the same manner as claimed, i.e., it would reform the wettability of the reservoir from oil-wetting to water-wetting. If there is any difference between the composition of Oghena and that of the instant claims, the difference would have been minor and obvious insofar as because it has been held "Products of identical chemical composition cannot have mutually exclusive properties." A chemical composition and its properties are inseparable. Therefore, if the prior art teaches the identical chemical structure, the properties Applicant discloses and/or claims are necessarily present. See MPEP 2112.01(I), In re Best, 562 F2d at 1255, 195 USPQ at 433, Titanium Metals Corp v Banner, 778 F2d 775,227 USPQ 773 (Fed Cir 1985), In re Ludtke, 441 F2d 660, 169 USPQ 563 (CCPA 1971) and Northam Warren Corp v D F Newfield Co, 7 F Supp 773, 22 USPQ 313 (EDNY 1934). Furthermore, inasmuch as Oghena discloses wherein the reservoir modification fluid changes rock wettability of an oil-wet reservoir ([0047]), the act of reforming the wettability “from oil-wetting to water-wetting” amounts to nothing more than choosing from a finite number of possible and predictable solutions (oil-wet to water-wet, oil-wet maintained, oil-wet to more oil-wet), as it has been taught "When there is a design need or market pressure to solve a problem and there are a finite number of identified, predictable solutions, a person having ordinary skill has good reason to pursue the known options within his or her technical grasp. If this leads to the anticipated success, it is likely the product not of innovation but of ordinary skill and common sense." KSR at 1397
With respect to depending claims 2 and 3, Oghena discloses wherein the secondary crude oil recovery step is started either during execution of the primary crude oil recovery step or following execution of the primary oil recovery step ([0042], [0056], and claims 23 and 24). Furthermore, the act of performing the secondary crude oil recovery step either during execution of the primary crude oil recovery step or following it amounts to nothing more than choosing from a finite number of possible and predictable solutions, as it has been taught "When there is a design need or market pressure to solve a problem and there are a finite number of identified, predictable solutions, a person having ordinary skill has good reason to pursue the known options within his or her technical grasp. If this leads to the anticipated success, it is likely the product not of innovation but of ordinary skill and common sense." KSR at 1397 With respect to depending claim 4, Oghena discloses wherein the reservoir modification fluid is at least one type of fluid selected from a group consisting of first nanoparticle-containing fluids, water vapor, surfactant-containing fluids, polymer compound-containing fluids, and saline water (Abstract, [0006], [0024]-[0026], [0040]-[0042], [0047], [0056], claims 23 and 24, and Fig. 1).
Regarding claim 4, Oghena discloses wherein the reservoir modification fluid is a saline water, wherein the water ranges in salinity, including alternatives such as freshwater, groundwater, or seawater ([0023]-[0026]). Although silent to wherein the water has “a lower salinity concentration than groundwater that exists naturally inside an oil field,” as instantly claimed, it would have been obvious for a person having ordinary skill in the art before the effective filing date of the claimed invention to provide for a water salinity as claimed insofar as because it has been held "[W]here the general conditions of a claim are disclosed in the prior art, it is not inventive to discover the optimum or workable ranges by routine experimentation." In re Aller, 220 F. 2d 454, 456, 105 USPQ 233, 235 (CCPA 1955) With respect to depending claim 5, which is dependent upon claim 4, Oghena discloses wherein the first nanoparticle-containing fluid comprises nanoparticles and a dispersion medium, and the nanoparticles have hydrophilicity (Abstract, [0006], [0024]-[0026], [0031], [0040]-[0042], [0047], [0056], claims 23 and 24, and Fig. 1).
With respect to depending claim 6, which is dependent upon claim 5, Oghena discloses wherein the nanoparticles may be formed from one component, or two or more components, selected from the group consisting of aluminum, iron, zinc, copper, nickel, or tin (Abstract, [0006], and [0031]-[0034]). With regard to the remaining materials of the Markush group, the Office considers these as obvious variants to those disclosed by the reference, and, therefore, it would have been obvious for a person having ordinary skill in the art before the effective filing date of the claimed invention to alternatively include such materials in the formation of the nanoparticles.
With respect to depending claim 7, which is dependent upon claim 5, Oghena discloses wherein a maximum particle size of the nanoparticles is at least 1 nm but not more than 100 nm ([0027] and [0030]).
With respect to depending claim 8, which is dependent upon claim 5, Oghena discloses wherein the dispersion medium may be water, natural gas, carbon dioxide, nitrogen, or methane (Abstract, [0006], and [0024]). With regard to the remaining materials of the Markush group, the Office considers these as obvious variants to those disclosed by the reference, and, therefore, it would have been obvious for a person having ordinary skill in the art before the effective filing date of the claimed invention to alternatively include such materials as the dispersion medium.
With respect to depending claim 9, which is dependent upon claim 4, Oghena discloses wherein the surfactant may be amphoteric (Abstract, [0006], [0024], and [0032]). With regard to the remaining materials of the Markush group, the Office considers these as obvious variants to those disclosed by the reference, and, therefore, it would have been obvious for a person having ordinary skill in the art before the effective filing date of the claimed invention to alternatively include such materials as the surfactant. With respect to depending claim 10, Oghena discloses wherein the overflush fluid comprises water, natural gas, carbon dioxide, nitrogen, or methane (Abstract, [0006], and [0024]). With regard to the remaining materials of the Markush group, the Office considers these as obvious variants to those disclosed by the reference, and, therefore, it would have been obvious for a person having ordinary skill in the art before the effective filing date of the claimed invention to alternatively include such materials in the overflush fluid. With respect to depending claim 11, Oghena discloses wherein the foam-stabilizing fluid is at least one fluid selected from the group consisting of surfactant-containing fluids and second nanoparticles-containing fluids (Abstract, [0006], and [0024]).
With respect to depending claim 12, Oghena discloses wherein the foam-forming fluid may be natural gas, carbon dioxide, nitrogen, or methane (Abstract, [0006], and [0024]). With regard to the remaining materials of the Markush group, the Office considers these as obvious variants to those disclosed by the reference, and, therefore, it would have been obvious for a person having ordinary skill in the art before the effective filing date of the claimed invention to alternatively include such materials as the foam-forming fluid.
With respect to depending claim 13, which is dependent upon claim 4, Oghena discloses wherein the reservoir modification fluid is at least one type of fluid selected from a group consisting of first nanoparticle-containing fluids, water vapor, surfactant-containing fluids, polymer compound-containing fluids, and saline water (Abstract, [0006], [0024]-[0026], [0040]-[0042], [0047], [0056], claims 23 and 24, and Fig. 1).
Claim 14 is rejected under 35 U.S.C. 103 as being unpatentable over Oghena et al. (US 2017/0058186- cited above) in view of Nguyen et al. (US 2019/0345375).
With respect to depending claim 14, which is dependent upon claim 4, Oghena discloses wherein the reservoir modification fluid may be a polymer compound-containing fluid (Abstract, [0006], [0024]-[0026], [0040]-[0042], [0047], [0056], claims 23 and 24, and Fig. 1). However, Oghen fails to expressly disclose the specific polymer, as instantly claimed. Nguyen teaches a polymer compound-containing reservoir modification fluid, wherein the polymer may be a polysaccharide and/or a polyacrylamide (Abstract and [0104]). Replacing the polymer disclosed by Oghena with the polymer taught by Nguyen is but a simple substitution of one known equivalent polymer in a reservoir modification fluid for another, performing the same function for the same purpose. It would have been obvious for a person having ordinary skill in the art before the effective filing date of the claimed invention to make this simple substitution as it has been held “[W]hen a patent claims a structure already known in the prior art that is altered by the mere substitution of one element for another known in the field, the combination must do more than yield a predictable result.” KSR at 1395 (citing United States v. Adams, 383 US 39, 50-51 (1966)).
Response to Arguments
Applicant's arguments filed 12/17/25 have been fully considered but they are not persuasive.
Applicant argues, based on the amendments, that Oghena fails to disclose reforming the wettability of the reservoir “from oil-wetting to water-wetting.” The Examiner finds this argument unpersuasive. As noted above, inasmuch as Oghena discloses the same composition, it too would provide the same result. Furthermore, reforming from oil-wetting to water-wetting amounts to nothing more than selecting from finite possible solutions. Applicant argues that Oghena’s disclosure of restoring the oil relative permeability and mitigating asphaltene formation results in a maintained state of oil-wetting. The Examiner finds this argument unpersuasive. Oil relative permeability is the flow conductivity of oil in the reservoir whereas oil-wet is the preference of rock surfaces in the reservoir to be coated by oil; while these variables might be related, it is unpersuasive to state that a restored oil relative permeability necessarily makes reservoir rocks more oil-wet. Additionally, less asphaltenes translates to less oil-wet surfaces.
Applicant argues that while Oghena discloses the use of anionic surfactants such as sodium dodecyl sulfate, Oghena fails to disclose wherein the foam-stabilizing fluid contains an amphoteric surfactant. The Examiner finds this argument unpersuasive. Oghena discloses a foam-stabilizing fluid comprising nanoparticles, wherein the nanoparticles may be coated with an amphoteric surfactant ([0032]).
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 AVI T. SKAIST whose telephone number is (571)272-9348. The examiner can normally be reached M-F 9:30-6.
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/AVI T SKAIST/Examiner, Art Unit 3674
/WILLIAM D HUTTON JR/Supervisory Patent Examiner, Art Unit 3674