DETAILED ACTION
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 .
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.
Claims 10, 11 and 13-20 are rejected under 35 U.S.C. 103 as being unpatentable over Dobson, JR. et al. (US 2013/0213657 – cited previously) in view of Walters et al. (US 2009/0281006 – cited previously) and Stahl et al. (US 5,186,257).
With respect to independent claim 10, Dobson, JR. et al. discloses a method for treating a subterranean formation using a fracturing fluid, the method comprising:
preparing a fracturing fluid ([0057], wherein the fluid is disclosed as used for hydraulic fracturing) by combining an organic acid ester ([0092], wherein poly(lactides) are disclosed; [0108], wherein various esters corresponding to those instantly claimed and disclosed by Applicant are disclosed), a water-soluble terpolymer ([0068]), a terpolymer hydration aid ([0133] and claim 8 wherein at least ethoxylated alcohols are disclosed, thereby providing for a terpolymer that is an alkoxylated alcohol as is disclosed by Applicant as an example thereof), an antioxidizing agent ([0119]-[0124]), a metal crosslinking agent ([0074]-[0076]), a breaker ([0137]-[0138]), and an aqueous base fluid comprising a total dissolved solids concentration ([0059]-[0061]),
introducing the fracturing fluid into a wellbore penetrating the subterranean formation at a pressure sufficient to fracture the subterranean formation ([0080]; [0092]), wherein the wellbore comprises a high temperature ([0083]), and
fracturing the subterranean formation with the fracturing fluid ([0057]; [0080]; [0090]).
With regard to the combination of specifically choosing each of the above elements in the fracturing fluid used by the method of Dobson, JR. et al., Dobson, JR. et al. discloses wherein the well treatment fluid compositions comprise water/an aqueous fluid, a hydratable polymer, a crosslinking agent, and one or more of the suggested formation damage control agents of a scale inhibitor, i.e., Applicant’s instantly claimed organic acid ester, iron control agents, i.e., Applicant’s instantly claimed antioxidizing agent, non-emulsifiers, i.e., Applicant’s instantly claimed terpolymer hydration aid and polymer breakers, i.e., Applicant’s instantly claimed breaker ([0058]). Thus, the Dobson, JR. et al. suggests a fracturing fluid comprising each component as claimed. Since Dobson, JR. et al. discloses the inclusion of each of the noted components, a prima facie case of obviousness exists over the claimed combination. See Merck v Biocraft, 10 USPQ2d 1843 (Fed Cir 1985) where it has been held that though a specific embodiment is not taught as preferred makes it no less obvious, also that the mere fact that a reference suggests a multitude of possible combinations does not in and of itself make any one of those combinations less obvious. One skilled in the art would be motivated to select Applicant’s claimed combination of fracturing fluid components from the suggested components of Dobson JR. et al. as set forth above as such are disclosed as useful for forming a well fracturing fluid suitable for use in fracturing a formation while also controlling formation damage therewith.
With further regard to the total dissolved solids concentration of the aqueous base fluid, Dobson, JR. et al. discloses wherein the aqueous base fluid can include fresh water, salt water, sea water, a brine such as a saturated salt water or formation brine, or a combination thereof ([0059]); the aqueous based fluid may comprise fresh water or salt water depending upon the particular density of the composition required ([0060]) and suitable brine systems are suggested as comprising from about 1-75% by weight of one or more appropriate salts ([0061]).
The reference, however, fails to disclose the total dissolved solids concentration thereof. Walters et al. teaches TDS concentration ranges for various salt containing waters used in wellbore treatment fluids, wherein saline water is defined to have a TDS of 15,000-30,000 ppm, seawater is defined to have a TDS of 30,000-40,000 ppm and brine is defined to have a TDS of greater than 40,000 ppm ([0076]-[0078]). Given Dobson, JR. et al.’s disclosure and suggestion of using waters such as salt water, sea water or brine, it would have been obvious to one having ordinary skill in the art to try an aqueous base fluid having a TDS within the range as claimed as such TDS values are known to be associated with the aqueous base fluids suggested by Dobson, JR. et al. and thus one of ordinary skill would recognize aqueous base fluids having such TDS values as chosen from a finite number of water sources disclosed as suitable for use as the aqueous base fluid in order to yield the predictable result of providing a base fluid capable of delivering the treatment components to the formation. Furthermore, given the percent by weight of one or more salts suggested by Dobson, JR. et al., one having ordinary skill in the art would recognize an appropriate salt weight percent and thus total dissolved solids concentration within the aqueous base fluid to include in order to achieve the desired density therewith since it has been held generally, differences in concentration or temperature will not support the patentability of subject matter encompassed by the prior art unless there is evidence indicating such concentration or temperature is critical. "[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) (Claimed process which was performed at a temperature between 40°C and 80°C and an acid concentration between 25% and 70% was held to be prima facie obvious over a reference process which differed from the claims only in that the reference process was performed at a temperature of 100°C and an acid concentration of 10%.).
With further regard to the wellbore temperature, Dobson, JR. et al. discloses wherein in the case of high bottom hole static temperature situations, one or more temperature stabilizers may be added to the composition and suggests wherein such temperatures are those greater than 95oC ([0082]-[0083]). Although silent to the wellbore as comprising a temperature within the range instantly claimed, since Dobson, JR. et al. clearly suggests the ability to use the treatment fluid under temperature conditions greater than 95oC [203oF], i.e., a temperature range that is suggestive of temperatures that may overlap those instantly claimed, it would have been obvious to one having ordinary skill in the art to try the method of Dobson, JR. in a wellbore having a temperature of 300oF to 450oF in order to generate a fracture therein while controlling formation damage since it has been held wherein generally, differences in concentration or temperature will not support the patentability of subject matter encompassed by the prior art unless there is evidence indicating such concentration or temperature is critical. "[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) (Claimed process which was performed at a temperature between 40°C and 80°C and an acid concentration between 25% and 70% was held to be prima facie obvious over a reference process which differed from the claims only in that the reference process was performed at a temperature of 100°C and an acid concentration of 10%.). Additionally, the Examiner notes, obviousness can be shown in a predictable art when a difference between the claimed ranges is virtually negligible absent any showing of unexpected results or criticality. In re Brandt, 886 F. 3d 1171, 1177, 126 USPQ2d 1079, 1082 (Fed. Cir. 2018). The instant specification fails to explicitly establish the instantly claimed temperature as critical and it is unclear if any unexpected results are achieved by using the method at such temperatures. Since the fracturing fluid of Dobson, JR. et al. is suggested as used at temperatures above 95oC, as well as wherein the method is applicable to high temperature formations, the determination of optimal temperature there above for conducting the method as claimed would be achievable through routine experimentation in the art.
Dobson, JR. et al. discloses wherein the fracturing fluid includes a water-soluble terpolymer of an ethylenically unsaturated polar monomer, an ethylenically unsaturated ester and a monomer selected from AMPS and/or N-vinylpyrrolidone ([0068]). The reference, however, fails to disclose wherein the water-soluble terpolymer comprises structural units derived from ethylene unsaturated phosphonic acid or salts thereof as instantly claimed. Stahl et al. teaches water soluble polymers (abstract) for use in reservoirs with higher temperatures and appreciable hardness levels, wherein it is suggested 2-acrylamido-2-methyl-propanephosponate (AMPP) terpolymers with 2-vinylpyrrolidone (VP) are preferred because of their improved retention of viscosity; reservoirs with temperatures of 230oF or higher are suggested to require terpolymers of AMPP, AMPS and VP (col. 23, l. 27-51). Since Dobson, JR. et al. discloses the use of a water soluble terpolymer comprising AMPS and/or VP, wherein such further includes an ethylenically unsaturated polar monomer and an ethylenically unsaturated ester, wherein such is used in reservoirs having a higher temperature and in a fluid having a hardness level and Stahl et al. teaches water soluble terpolymers for use in a reservoir having high temperatures and appreciable hardness levels that include AMPS, VP and AMPP, i.e., structural units derived from ethylene unsaturated phosphonic acid or salts thereof, it would have been obvious to one having ordinary skill in the art to try such a water soluble terpolymer as taught by Stahl et al. as the water soluble terpolymer in the fracturing fluid of Dobson, JR. et al. in order to yield the predictable result of retaining fluid viscosity therewith, particularly at higher temperatures and in conditions of appreciable hardness.
With respect to dependent claim 11, Dobson, JR. discloses the same chemicals instantly disclosed and claimed by Applicant to undergo hydrolysis after contact with water present in the subterranean formation (see rejections of dependent claims 15 and 16, below). Although silent to such organic acid esters as undergoing hydrolysis as instantly claimed, since Dobson, JR. et al. discloses the same chemicals as indicated by Applicant as having such a property, the organic acid esters of Dobson, JR. et al. would be expected to act in the same manner as claimed, i.e., undergo hydrolysis after contact with water present in the subterranean formation. If there is any difference between the hydrolysis of the organic acid ester of Dobson, JR. et al. and that of the instant claims, the difference would have been minor and obvious insofar as because “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(1), 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, 1 F Supp 773, 22 USPQ 313 (EDNY 1934).
With respect to dependent claim 13, Dobson, JR. et al. discloses wherein the fluid is pumped into the formation at a high rate so as to stimulate the formation ([0080]). Although silent to the specific pumping rate thereof, given the extensiveness of the range instantly claimed, as well as Dobson, JR et al.’s disclosure of introducing the fluid into the formation so as to generate a fracture therein, it is the position of the Office that one having ordinary skill in the art would recognize the optimal pump rate for the fracturing fluid in order to generate a fracture in the subterranean formation therewith since 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). For more recent cases applying this principle, see Merck & Co. Inc. v. Biocraft Lab. Inc., 874 F.2d 804, 10 USPQ2d 1843 (Fed. Cir.), cert. denied, 493 U.S. 975 (1989); In re Kulling, 897 F.2d 1147, 14 USPQ2d 1056 (Fed. Cir. 1990); and In re Geisler, 116 F.3d 1465, 43 USPQ2d 1362 (Fed. Cir. 1997); Smith v. Nichols, 88 U.S. 112, 118-19 (1874) (a change in form, proportions, or degree "will not sustain a patent"); In re Williams, 36 F.2d 436, 438 (CCPA 1929) ("It is a settled principle of law that a mere carrying forward of an original patented conception involving only change of form, proportions, or degree, or the substitution of equivalents doing the same thing as the original invention, by substantially the same means, is not such an invention as will sustain a patent, even though the changes of the kind may produce better results than prior inventions."). See also KSR Int’l Co. v. Teleflex Inc., 550 U.S. 398, 416 (2007) (identifying "the need for caution in granting a patent based on the combination of elements found in the prior art."). Additionally, the Examiner notes, obviousness can be shown in a predictable art when a difference between the claimed ranges is virtually negligible absent any showing of unexpected results or criticality. In re Brandt, 886 F. 3d 1171, 1177, 126 USPQ2d 1079, 1082 (Fed. Cir. 2018). The instant specification fails to explicitly establish the instantly claimed pump rate as critical and it is unclear if any unexpected results are achieved by using such during the introduction of the fracturing fluid into the wellbore. Since the fracturing fluid of Dobson, JR. et al. is suggested as provided at a pump rate to achieve a desired fracture within a particular formation, it does not appear that such would be considered an unexpected result of using the presently claimed pump rate, and, as such, the determination of optimal pump rate for the fracturing fluid would be achievable through routine experimentation in the art.
With respect to dependent claim 14, Dobson, JR. et al. discloses wherein the fracturing fluid further comprises a proppant and the method further comprises depositing the proppant in the fracture ([0077]-[0078]).
With respect to dependent claim 15, Dobson, JR. et al. discloses wherein the organic acid ester is selected from the group as claimed ([0092], wherein poly(lactides) are disclosed).
With respect to dependent claim 16, Dobson, JR. et al. discloses wherein the organic acid ester is selected from the group as claimed ([0108], wherein various esters corresponding to those instantly claimed and disclosed by Applicant are disclosed).
With respect to independent claim 17, Dobson, JR. et al. discloses a system for treating a subterranean formation using a fracturing fluid ([0057]), the system comprising:
a fracturing fluid ([0057], wherein the fluid is disclosed as used for hydraulic fracturing) comprising:
an organic acid ester ([0092], wherein poly(lactides) are disclosed; [0108], wherein various esters corresponding to those instantly claimed and disclosed by Applicant are disclosed),
a water-soluble terpolymer ([0068]),
a terpolymer hydration aid ([0133] and claim 8 wherein at least ethoxylated alcohols are disclosed, thereby providing for a terpolymer that is an alkoxylated alcohol as is disclosed by Applicant as an example thereof) ,
an antioxidizing agent ([0119]-[0124]),
a metal crosslinking agent ([0074]-[0076]),
a breaker ([0137]-[0138]), and
an aqueous base fluid comprising a total dissolved solids concentration ([0059]-[0061])
mixing equipment configured to mix ([0063]) the organic acid ester, the water-soluble terpolymer, the terpolymer hydration aid, the antioxidizing agent, the metal crosslinking agent, the breaker, and the aqueous base fluid; and
pumping equipment configured to pump ([0080]; [0119]) the fracturing fluid in a wellbore comprising a high temperature ([0083]).
With regard to the combination of specifically choosing each of the above elements in the fracturing fluid used by the system of Dobson, JR. et al., Dobson, JR. et al. discloses wherein the well treatment fluid compositions comprise water/an aqueous fluid, a hydratable polymer, a crosslinking agent, and one or more of the suggested formation damage control agents of a scale inhibitor, i.e., Applicant’s instantly claimed organic acid ester, iron control agents, i.e., Applicant’s instantly claimed antioxidizing agent, non-emulsifiers, i.e., Applicant’s instantly claimed terpolymer hydration aid and polymer breakers, i.e., Applicant’s instantly claimed breaker ([0058]). Thus, the Dobson, JR. et al. suggests a fracturing fluid comprising each component as claimed. Since Dobson, JR. et al. discloses the inclusion of each of the noted components, a prima facie case of obviousness exists over the claimed combination. See Merck v Biocraft, 10 USPQ2d 1843 (Fed Cir 1985) where it has been held that though a specific embodiment is not taught as preferred makes it no less obvious, also that the mere fact that a reference suggests a multitude of possible combinations does not in and of itself make any one of those combinations less obvious. One skilled in the art would be motivated to select Applicant’s claimed combination of fracturing fluid components from the suggested components of Dobson JR. et al. as set forth above as such are disclosed as useful for forming a well fracturing fluid suitable for use in fracturing a formation while also controlling formation damage therewith.
With further regard to the total dissolved solids concentration of the aqueous base fluid, Dobson, JR. et al. discloses wherein the aqueous base fluid can include fresh water, salt water, sea water, a brine such as a saturated salt water or formation brine, or a combination thereof ([0059]); the aqueous based fluid may comprise fresh water or salt water depending upon the particular density of the composition required ([0060]) and suitable brine systems are suggested as comprising from about 1-75% by weight of one or more appropriate salts ([0061]).
The reference, however, fails to disclose the total dissolved solids concentration thereof. Walters et al. teaches TDS concentration ranges for various salt containing waters used in wellbore treatment fluids, wherein saline water is defined to have a TDS of 15,000-30,000 ppm, seawater is defined to have a TDS of 30,000-40,000 ppm and brine is defined to have a TDS of greater than 40,000 ppm ([0076]-[0078]). Given Dobson, JR. et al.’s disclosure and suggestion of using waters such as salt water, sea water or brine, it would have been obvious to one having ordinary skill in the art to try an aqueous base fluid having a TDS within the range as claimed as such TDS values are known to be associated with the aqueous base fluids suggested by Dobson, JR. et al. and thus one of ordinary skill would recognize aqueous base fluids having such TDS values as chosen from a finite number of water sources disclosed as suitable for use as the aqueous base fluid in order to yield the predictable result of providing a base fluid capable of delivering the treatment components to the formation. Furthermore, given the percent by weight of one or more salts suggested by Dobson, JR. et al., one having ordinary skill in the art would recognize an appropriate salt weight percent and thus total dissolved solids concentration within the aqueous base fluid to include in order to achieve the desired density therewith since it has been held generally, differences in concentration or temperature will not support the patentability of subject matter encompassed by the prior art unless there is evidence indicating such concentration or temperature is critical. "[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) (Claimed process which was performed at a temperature between 40°C and 80°C and an acid concentration between 25% and 70% was held to be prima facie obvious over a reference process which differed from the claims only in that the reference process was performed at a temperature of 100°C and an acid concentration of 10%.).
With further regard to the wellbore temperature, Dobson, JR. et al. discloses wherein in the case of high bottom hole static temperature situations, one or more temperature stabilizers may be added to the composition and suggests wherein such temperatures are those greater than 95oC ([0082]-[0083]). Although silent to the wellbore as comprising a temperature within the range instantly claimed, since Dobson, JR. et al. clearly suggests the ability to use the treatment fluid under temperature conditions greater than 95oC [203oF], i.e., a temperature range that is suggestive of temperatures that may overlap those instantly claimed, it would have been obvious to one having ordinary skill in the art to try the method of Dobson, JR. in a wellbore having a temperature of 300oF to 450oF in order to generate a fracture therein while controlling formation damage since it has been held wherein generally, differences in concentration or temperature will not support the patentability of subject matter encompassed by the prior art unless there is evidence indicating such concentration or temperature is critical. "[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) (Claimed process which was performed at a temperature between 40°C and 80°C and an acid concentration between 25% and 70% was held to be prima facie obvious over a reference process which differed from the claims only in that the reference process was performed at a temperature of 100°C and an acid concentration of 10%.). Additionally, the Examiner notes, obviousness can be shown in a predictable art when a difference between the claimed ranges is virtually negligible absent any showing of unexpected results or criticality. In re Brandt, 886 F. 3d 1171, 1177, 126 USPQ2d 1079, 1082 (Fed. Cir. 2018). The instant specification fails to explicitly establish the instantly claimed temperature as critical and it is unclear if any unexpected results are achieved by using the method at such temperatures. Since the fracturing fluid of Dobson, JR. et al. is suggested as used at temperatures above 95oC, as well as wherein the method is applicable to high temperature formations, the determination of optimal temperature there above for conducting the method as claimed would be achievable through routine experimentation in the art.
Dobson, JR. et al. discloses wherein the fracturing fluid includes a water-soluble terpolymer of an ethylenically unsaturated polar monomer, an ethylenically unsaturated ester and a monomer selected from AMPS and/or N-vinylpyrrolidone ([0068]). The reference, however, fails to disclose wherein the water-soluble terpolymer comprises structural units derived from ethylene unsaturated phosphonic acid or salts thereof as instantly claimed. Stahl et al. teaches water soluble polymers (abstract) for use in reservoirs with higher temperatures and appreciable hardness levels, wherein it is suggested 2-acrylamido-2-methyl-propanephosponate (AMPP) terpolymers with 2-vinylpyrrolidone (VP) are preferred because of their improved retention of viscosity; reservoirs with temperatures of 230oF or higher are suggested to require terpolymers of AMPP, AMPS and VP (col. 23, l. 27-51). Since Dobson, JR. et al. discloses the use of a water soluble terpolymer comprising AMPS and/or VP, wherein such further includes an ethylenically unsaturated polar monomer and an ethylenically unsaturated ester, wherein such is used in reservoirs having a higher temperature and in a fluid having a hardness level and Stahl et al. teaches water soluble terpolymers for use in a reservoir having high temperatures and appreciable hardness levels that include AMPS, VP and AMPP, i.e., structural units derived from ethylene unsaturated phosphonic acid or salts thereof, it would have been obvious to one having ordinary skill in the art to try such a water soluble terpolymer as taught by Stahl et al. as the water soluble terpolymer in the fracturing fluid of Dobson, JR. et al. in order to yield the predictable result of retaining fluid viscosity therewith, particularly at higher temperatures and in conditions of appreciable hardness.
With respect to dependent claim 18, Dobson, JR. et al. discloses wherein the organic acid ester is selected from the group as claimed ([0092], wherein poly(lactides) are disclosed).
With respect to dependent claim 19, Dobson, JR. et al. discloses wherein the organic acid ester is selected from the group as claimed ([0108], wherein various esters corresponding to those instantly claimed and disclosed by Applicant are disclosed).
With respect to dependent claim 20, Dobson, JR. et al. discloses wherein the fracturing fluid further comprises a proppant ([0077]-[0078]).
Response to Arguments
Applicant’s comments pertaining to claims 19-20 have been fully considered. It is noted, claims 19-20 were inadvertently not previously listed as pending. As the limitations thereof correspond to previously rejected claims 14 and 16, the grounds of rejection made with respect thereto have been included in the listing of claims 19-20 herein.
Applicant’s arguments with respect to the rejection(s) of claim(s) as unpatentable over Dobson, JR. et al. in view of Walters et al. have been fully considered; upon consideration of Applicant’s amendments to each of independent claims 10 and 17, a modified grounds of rejection has been presented above with respect thereto in further view of the teachings of Stahl et al. to provide for structural units derived from ethylene unsaturated phosphonic acid for at least the reasons set forth above.
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 Angela M DiTrani Leff whose telephone number is (571)272-2182. The examiner can normally be reached Monday-Friday, 9AM-5PM.
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/Angela M DiTrani Leff/Primary Examiner, Art Unit 3674
ADL
07/30/25