DETAILED ACTION
Continued Examination Under 37 CFR 1.114
A request for continued examination under 37 CFR 1.114, including the fee set forth in 37 CFR 1.17(e), was filed in this application after final rejection. Since this application is eligible for continued examination under 37 CFR 1.114, and the fee set forth in 37 CFR 1.17(e) has been timely paid, the finality of the previous Office action has been withdrawn pursuant to 37 CFR 1.114. Applicant's submission filed on 3 June 2026 has been entered.
Response to Amendment
The Amendment filed 3 June 2026 has been entered. Claims 1, 2, 9-12, 14, and 21 remain pending in the application. Claims 3-5, 8, 13, and 15-18 are canceled. Claims 6, 7, 19, and 20 were previously withdrawn as being drawn to non-elected Species. The previous Office Action was mailed 26 March 2026.
Specification
The disclosure is objected to because of the following informalities:
It appears that every occurrence of “polyethylenoxy” should recite “polyethyleneoxy” (correcting the typos).
Appropriate correction is required.
Claim Objections
Claims 1, 2, 9-12, 14, and 21 are objected to because of the following informalities:
It appears that independent claim 1 should recite “nonylphenoxy polyethyleneoxy alcohol” (correcting the typo). The dependent claims are objected to by dependency.
Claim 10 still refers to the 60-99.9 wt% carrier solvent, which is the same element as the 80-95 wt% water now in independent claim 1. Accordingly, it appears claim 10 should be canceled or adapted for further comprising diesel. For example, claim 1 might recite “from about 80 wt.% to about 95 wt.% carrier solvent, based on the total weight of the overflush fluid, wherein the carrier solvent comprises water” and claim 10 might recite “wherein the carrier solvent further comprises diesel” etc. Claim 11 is objected to by dependency.
It appears that independent claim 14 should recite “nonylphenoxy polyethyleneoxy alcohol” (correcting the typo). The dependent claims are objected to by dependency.
Appropriate correction is required.
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 1-5 and 9-12 are rejected under 35 U.S.C. 103 as obvious over Blumer (2017/0260441) in view of Nasr-El-Din (2013/0274154) (both cited previously).
Regarding independent claim 1, Blumer discloses A method (abstract “scale inhibitor squeeze treatment”) comprising:
providing a pre-flush fluid to a portion of a subterranean formation via a wellbore (e.g., [0050] “As with other commercial preflush chemicals, this preflush composition needs to be pumped before the aqueous main pill of the squeeze treatment. The proper sequence of a scale inhibitor squeeze treatment using these preflush chemicals is: 1. pump preflush composition”);
after providing the pre-flush fluid, providing an inhibitor main pill fluid to the portion of the subterranean formation via the wellbore (e.g., [0050] “2. pump main scale inhibitor solution”), wherein the inhibitor main pill fluid comprises a scale inhibitor (e.g., [0109] “The “scale inhibitor fluid” can be any known in the art, and typically includes four classes of compounds that have been widely applied in the oilfield: polyphosphates, phosphonates, phosphate esters, and polyacrylates/polyacrylamides”); and
after providing the inhibitor main pill fluid, providing an overflush fluid to the portion of the subterranean formation via the wellbore after the inhibitor main pill fluid (e.g., [0050] “3. pump overflush; 4. shut-in for certain period of time; 5. open the well for backflow and start the well in production mode” and [0064] “As used herein “push” fluid and “overflush” are used interchangeably intended to refer to any fluid used to force the scale inhibitor into the formation”),
wherein the overflush fluid comprises:
… one or more nonionic surfactant ([0061] “wherein said push fluid comprises brine or preflush solution”; note that the “preflush solution” in Blumer is [0049] “The preflush chemicals are mixtures, with various formulations, of nonionic surfactants (alkylpolyglycoside, APG)” e.g. [0054] “A preflush solution for injection into a wellbore before a scale inhibitor squeeze treatment, said preflush solution comprising at least 90% diesel, at least 1% alkyl polyglycoside, at least 0.5% ethoxylated alcohol, and at least 1% alcohol”)…
shutting in the pre-flush fluid, the inhibitor main pill fluid, and the overflush fluid within the portion of the subterranean formation … ([0050] “As with other commercial preflush chemicals, this preflush composition needs to be pumped before the aqueous main pill of the squeeze treatment. The proper sequence of a scale inhibitor squeeze treatment using these preflush chemicals is: 1. pump preflush composition; 2. pump main scale inhibitor solution; 3. pump overflush; 4. shut-in for certain period of time”); and
… allow[ing] produced fluid in the subterranean formation to flow out of the wellbore ([0050] “5. open the well for backflow and start the well in production mode”)…
Regarding the overflush fluid comprising 0.01-5 wt% surfactant, 5-10 wt% electrolyte, and 80-95 wt% water, Blumer discloses “As used herein “push” fluid and “overflush” are used interchangeably intended to refer to any fluid used to force the scale inhibitor into the formation, and is typically, (but not necessarily) brine. Diesel has also been used for overflush” ([0064]) and “wherein said push fluid comprises brine or preflush solution” ([0061]). That is, Blumer teaches an overflush that is brine and, separately, an overflush that is preflush solution i.e. of diesel, APG, ethoxylated alcohol, and linear alcohol.
However, Blumer fails to specify the specific combination wherein the overflush comprises 0.01-5 wt% surfactant, 5-10 wt% electrolyte, and 80-95 wt% water.
Nevertheless, this appears to be a common type of overflush fluid for scale inhibitor treatments. For example, Nasr-El-Din teaches “treating a sandstone formation” (abstract) using “a treatment process consisting of several stages, such as the pre-flush, main treatment and postflush stage” ([0013]) wherein “Scale inhibitors may be added to the fluids of the present invention, for example, when such fluids are not particularly compatible with the formation waters in the formation in which they are used” ([0122]) and “in one embodiment, a surfactant is used as a preflush and/or postflush fluid” ([0013]) wherein “Where used, the surfactants may be present in the fluid in an amount sufficient to prevent incompatibility with formation fluids, other treatment fluids, or wellbore fluids at reservoir temperature” ([0044]) such as “the surfactants are generally present in an amount in the range of from about 0.01% to about 5.0% by volume of the fluid” ([0045]) and “Alkoxylated alcohols, preferably ethoxylated alcohols, optionally in combination with (alkyl) polyglycosides, are the most preferred nonionic surfactants” ([0025]). Nasr-El-Din further teaches “The carrier fluids are aqueous solutions which … contain an inorganic salt, preferably NaCl or KCl” ([0052]) such as “brines” ([0032]) wherein “The amount of salt to be added should be the amount necessary for formation compatibility, such as the amount necessary for the stability of clay minerals, taking into consideration the crystallization temperature of the brine, e.g., the temperature at which the salt precipitates from the brine as the temperature drops. Preferred suitable brines may include seawater” ([0068]-[0069]). Seawater is well-known to have a mixture of ~3.5 wt% salts. Nasr-El-Din further teaches an Example wherein “the core was saturated with 5 wt % NaCl brine” ([0141]), and thus “brine” in Nasr-El-Din presumably at least includes 5 wt% brines. Also, preventing incompatibility by use of the surfactant would be expected to increase the recovery rate of fluid compared to without the surfactant because of reduced clay instability and fines migration that would decrease permeability.
Although Nasr-El-Din does not specify that the KCl carrier fluid embodiment for the postflush would also be ~85 wt% water and ~5 wt% KCl with ~0.01-5 wt% APG surfactant, this is presumably within the general conditions taught by Nasr-El-Din. Accordingly, 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 Blumer’s overflush to be e.g. ~85 wt% water and ~5 wt% KCl with ~0.01-5 wt% APG surfactant, with a reasonable expectation of success, in order to provide a suitable type of “brine” overflush fluid known in the art for flushing after a treatment fluid comprising scale inhibitors “to prevent incompatibility with formation fluids, other treatment fluids, or wellbore fluids at reservoir temperature” (thereby including:
“from about 0.01 wt.% to about 5 wt.% of one or more nonionic surfactant, based on a total weight of the overflush fluid, wherein the nonionic surfactant comprises at least one member selected from the group consisting of alkyl polyglycoside, alcohol ethoxylate, nonylphenoxy polyethylenoxy alcohol, and poly(ethylene oxide)-poly(propylene oxide) block copolymer; and
from about 5 wt.% to about 10 wt.% of an electrolyte, based on the total weight of the overflush fluid; and
from about 80 wt.% to about 95 wt.% water, based on the total weight of the overflush fluid;
…
wherein a recovery rate of the overflush fluid after opening the wellbore valve is higher relative to the same method performed using a control overflush fluid not having the one or more nonionic surfactant”). 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 may note that Blumer does not appear to teach away from such an overflush fluid, because Blumer plainly discloses that brine may be a suitable overflush as an alternative to Blumer’s overflush that is the same as Blumer’s preflush solution.
Furthermore, the Office observes that Applicant does not appear to point to any criticality to using these particular amounts in the overflush fluid.
Finally, Applicant may note that “brine” in general is well-understood to refer to high-concentration salt solutions ranging up to e.g. ~26 wt%, the salt saturation limit, and neither Blumer nor Nasr-El-Din appear to indicate a particularly-lower upper limit on the salt concentration in the brines.
Regarding the shutting in by closing a wellbore valve and opening the wellbore valve to allow produced fluid, Blumer does not specify opening a wellbore valve for the backflow and starting the well in production mode.
Nevertheless, presumably, Blumer is using a valve for shutting in and reopening the well, insofar as valves are the standard equipment (in the art and in general) for doing so. Accordingly, even if it were found that Blumer fails to disclose a valve per se, 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 Blumer to include opening a wellbore valve for backflow and starting the well in production mode, with a reasonable expectation of success, in order to shut in then backflow and start the well in production mode using the standard equipment in the art for doing so (thereby including:
“shutting in the pre-flush fluid, the inhibitor main pill fluid, and the overflush fluid within the portion of the subterranean formation by closing a wellbore valve; and
opening the wellbore valve to allow produced fluid in the subterranean formation to flow out of the wellbore;).
Regarding claim 2, as in claim 1, Blumer discloses “As with other commercial preflush chemicals, this preflush composition needs to be pumped before the aqueous main pill of the squeeze treatment. The proper sequence of a scale inhibitor squeeze treatment using these preflush chemicals is: 1. pump preflush composition; 2. pump main scale inhibitor solution; 3. pump overflush; 4. shut-in for certain period of time; 5. open the well for backflow and start the well in production mode” ([0050]). Accordingly, 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 Blumer to include opening a wellbore valve for backflow and starting the well in production mode, with a reasonable expectation of success, in order to shut in then backflow and start the well in production mode using the standard equipment in the art for doing so (thereby including:
“shutting in the pre-flush fluid, the inhibitor main pill fluid, and the overflush fluid within the portion of the subterranean formation for a pre-determined period of time; and
wherein after the pre-determined period of time has elapsed, opening a wellbore valve to allow produced fluid in the subterranean formation to flow out of the wellbore”).
Regarding claim 9, as in claim 1, 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 Blumer’s overflush to be e.g. 5 wt% KCl with APG surfactant, with a reasonable expectation of success, in order to provide a suitable type of “brine” overflush fluid known in the art for flushing after a treatment fluid comprising scale inhibitors (thereby including “wherein the electrolyte comprises potassium chloride”).
Regarding claims 10 and 11, as in claim 1, 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 Blumer’s overflush to be e.g. ~85 wt% water and ~5 wt% KCl with ~0.01-5 wt% APG surfactant, with a reasonable expectation of success, in order to provide a suitable type of “brine” overflush fluid known in the art for flushing after a treatment fluid comprising scale inhibitors (thereby including:
(claim 10) wherein the overflush fluid further comprises a carrier solvent, wherein the carrier solvent is present in an amount from about 60 wt.% to about 99.9 wt.%, based on a total weight of the overflush fluid; and further
(claim 11) wherein the carrier solvent is selected from the group consisting of water, diesel, or combinations thereof.
Nevertheless, Applicant may note that claims 10 and 11 appear to erroneously still refer to the water which was moved into independent claim 1.
Regarding claim 12, as in claim 1, Nasr-El-Din teaches “Where used, the surfactants may be present in the fluid in an amount sufficient to prevent incompatibility with formation fluids, other treatment fluids, or wellbore fluids at reservoir temperature” ([0044]) such as “the surfactants are generally present in an amount in the range of from about 0.01% to about 5.0% by volume of the fluid” ([0045]) and “Alkoxylated alcohols, preferably ethoxylated alcohols, optionally in combination with (alkyl) polyglycosides, are the most preferred nonionic surfactants” ([0025]).
Accordingly, 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 Blumer’s overflush to be e.g. ~85 wt% water and ~5 wt% KCl with ~0.1-0.75 wt% APG surfactant, with a reasonable expectation of success, in order to provide a suitable type of “brine” overflush fluid known in the art for flushing after a treatment fluid comprising scale inhibitors (thereby including:
“wherein the nonionic surfactant is present in the overflush fluid in an amount from about 0.01 wt.% to about 0.75 wt.%, based on the total weight of the overflush fluid”).
For example, the Office observes that Applicant does not appear to point to any criticality to using these particular amounts in the overflush fluid.
Claim 14 is rejected under 35 U.S.C. 103 as obvious over Blumer in view of Nasr-El-Din as in claim 1, and further as evidenced by Hernandez de la Bastida (2023/0399938) (cited previously).
Regarding independent claim 14, Blumer discloses A system (abstract “scale inhibitor squeeze treatment” and Figs. 7 & 8) comprising:
a first vessel comprising a pre-flush fluid (e.g., Fig. 7 “Stage 1” “PREFLUSH”);
a second vessel comprising an inhibitor main pill fluid (e.g., Fig. 7 “Stage 2” “MAIN INJECTION”);
a third vessel comprising an overflush fluid (e.g., Fig. 7 “Stage 3” “OVERFLUSH”), wherein the overflush fluid comprises one or more surfactant;
a wellbore formed in a subterranean formation, wherein the wellbore comprises one or more perforations that place crude oil positioned in a portion of the subterranean formation in fluid communication with the wellbore (e.g., Fig. 8 and [0113] “A well casing 30 is positioned in wellbore 28 and cemented in place with cement 32. A tubing 34 extends downwardly through casing 30 to near the bottom of well 20. Perforations 36 are positioned through casing 30, cement 32 and into subterranean 26”);
at least one pump configured to transport the pre-flush fluid from the first vessel to the wellbore, the inhibitor main pill fluid from the second vessel to the wellbore, and the overflush fluid from the third vessel to the wellbore (e.g., [0050] “As with other commercial preflush chemicals, this preflush composition needs to be pumped before the aqueous main pill of the squeeze treatment. The proper sequence of a scale inhibitor squeeze treatment using these preflush chemicals is: 1. pump preflush composition; 2. pump main scale inhibitor solution; 3. pump overflush”);
… and
…
provide, using the at least one pump, the pre-flush fluid through the wellbore and to the subterranean formation (e.g., [0050] “The proper sequence of a scale inhibitor squeeze treatment using these preflush chemicals is: 1. pump preflush composition”);
after providing the pre-flush fluid, provide the inhibitor main pill fluid through the wellbore and to the subterranean formation using the at least one pump (e.g., [0050] “2. pump main scale inhibitor solution”); and
after providing the inhibitor main pill fluid, provide the overflush fluid through the wellbore and to the subterranean formation using the at least one pump (e.g., [0050] “3. pump overflush”); and
… shut in the pre-flush fluid, the inhibitor main pill fluid, and the overflush fluid within the subterranean formation for a pre-determined period of time (e.g., [0050] “4. shut-in for certain period of time”); and
after the pre-determined period of time has elapsed, … allow[ing] produced fluid in the subterranean formation to flow out of the wellbore ([0050] “5. open the well for backflow and start the well in production mode”)…
However, Blumer fails to specify 0.01-5 wt% of the claimed nonionic surfactants; 5-10 wt% electrolyte; 80-95 wt% water; using a wellbore valve to shut in; and a controller to control the operation.
Regarding the overflush fluid comprising 0.01-5 wt% surfactant, 5-10 wt% electrolyte, and 80-95 wt% water, Blumer discloses “As used herein “push” fluid and “overflush” are used interchangeably intended to refer to any fluid used to force the scale inhibitor into the formation, and is typically, (but not necessarily) brine. Diesel has also been used for overflush” ([0064]) and “wherein said push fluid comprises brine or preflush solution” ([0061]). That is, Blumer teaches an overflush that is brine and, separately, an overflush that is preflush solution i.e. of diesel, APG, ethoxylated alcohol, and linear alcohol.
However, Blumer fails to specify the specific combination wherein the overflush comprises 0.01-5 wt% surfactant, 5-10 wt% electrolyte, and 80-95 wt% water.
Nevertheless, this appears to be a common type of overflush fluid for scale inhibitor treatments. For example, Nasr-El-Din teaches “treating a sandstone formation” (abstract) using “a treatment process consisting of several stages, such as the pre-flush, main treatment and postflush stage” ([0013]) wherein “Scale inhibitors may be added to the fluids of the present invention, for example, when such fluids are not particularly compatible with the formation waters in the formation in which they are used” ([0122]) and “in one embodiment, a surfactant is used as a preflush and/or postflush fluid” ([0013]) wherein “Where used, the surfactants may be present in the fluid in an amount sufficient to prevent incompatibility with formation fluids, other treatment fluids, or wellbore fluids at reservoir temperature” ([0044]) such as “the surfactants are generally present in an amount in the range of from about 0.01% to about 5.0% by volume of the fluid” ([0045]) and “Alkoxylated alcohols, preferably ethoxylated alcohols, optionally in combination with (alkyl) polyglycosides, are the most preferred nonionic surfactants” ([0025]). Nasr-El-Din further teaches “The carrier fluids are aqueous solutions which … contain an inorganic salt, preferably NaCl or KCl” ([0052]) such as “brines” ([0032]) wherein “The amount of salt to be added should be the amount necessary for formation compatibility, such as the amount necessary for the stability of clay minerals, taking into consideration the crystallization temperature of the brine, e.g., the temperature at which the salt precipitates from the brine as the temperature drops. Preferred suitable brines may include seawater” ([0068]-[0069]). Seawater is well-known to have a mixture of ~3.5 wt% salts. Nasr-El-Din further teaches an Example wherein “the core was saturated with 5 wt % NaCl brine” ([0141]), and thus “brine” in Nasr-El-Din presumably at least includes 5 wt% brines. Also, preventing incompatibility by use of the surfactant would be expected to increase the recovery rate of fluid compared to without the surfactant because of reduced clay instability and fines migration that would decrease permeability.
Although Nasr-El-Din does not specify that the KCl carrier fluid embodiment for the postflush would also be ~85 wt% water and ~5 wt% KCl with ~0.01-5 wt% APG surfactant, this is presumably within the general conditions taught by Nasr-El-Din. Accordingly, 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 Blumer’s overflush to be e.g. ~85 wt% water and ~5 wt% KCl with ~0.01-5 wt% APG surfactant, with a reasonable expectation of success, in order to provide a suitable type of “brine” overflush fluid known in the art for flushing after a treatment fluid comprising scale inhibitors “to prevent incompatibility with formation fluids, other treatment fluids, or wellbore fluids at reservoir temperature” (thereby including:
“a third vessel comprising an overflush fluid, wherein the overflush fluid comprises:
from about 0.01 wt.% to about 5 wt.% of one or more nonionic surfactant, based on a total weight of the overflush fluid, wherein the nonionic surfactant comprises at least one member selected from the group consisting of alkyl polyglycoside, alcohol ethoxylate, nonylphenoxy polyethyleneoxy alcohol, and poly(ethylene oxide)-poly(propylene oxide) block copolymer; and
from about 5 wt.% to about 10 wt.% of an electrolyte, based on a total weight of the overflush fluid; and
from about 80 wt.% to about 95 wt.% water, based on the total weight of the overflush fluid;
…
wherein a recovery rate of the overflush fluid after opening the wellbore valve is higher relative to the same method performed using a control overflush fluid not having the one or more nonionic surfactant”). See also MPEP 2144.05 Obviousness of Similar and Overlapping Ranges, Amounts, and Proportions.
Regarding the wellbore valve, nevertheless, presumably, Blumer is using a valve for shutting in and reopening the well, insofar as valves are the standard equipment (in the art and in general) for doing so. Accordingly, even if it were found that Blumer fails to disclose a valve per se, 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 Blumer to include opening a wellbore valve for backflow and starting the well in production mode, with a reasonable expectation of success, in order to shut in then backflow and start the well in production mode using the standard equipment in the art for doing so (thereby including:
“a wellbore valve moveable between an open position that is configured to allow fluid to flow through the wellbore valve and a closed position that is configured to mitigate the flow of the fluid through the wellbore valve; and …
close the wellbore valve to shut in the pre-flush fluid, the inhibitor main pill fluid, and the overflush fluid within the subterranean formation for a pre-determined period of time; and
after the pre-determined period of time has elapsed, open the wellbore valve to allow produced fluid in the subterranean formation to flow out of the wellbore”).
Regarding the controller, nevertheless, controllers to control various wellbore equipment is rather well-known in the art. For example, Hernandez de la Bastida provides evidence of this, stating “automatically adjusting the one or more operating parameters of the equipment may include determining a scale inhibitor injection rate setpoint based at least in part on the predicted scale precipitation, and automatically adjusting a speed of one or more chemical injection pumps of a chemical injection system in accordance with the scale inhibitor injection rate setpoint” (abstract) e.g. for use in a “scale squeeze” ([0027]) wherein “For example, an operator may directly provide instructions to the chemical injection system 12 via the user interface, and the instructions may be output to a chemical injection pump of the chemical injection system 12 via a controller and a communication system of the equipment” ([0065]) and “the control logic synchronizes the operation of the chemical injection equipment with a corresponding submersible pump status” ([0026]).
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 Blumer to include a controller, with a reasonable expectation of success, in order to control the wellbore equipment to perform the operation (thereby including:
“a controller communicatively coupled to the at least one pump, the controller including a memory configured to store instructions that when executed by a processor cause the controller to:
provide, using the at least one pump, the pre-flush fluid through the wellbore and to the subterranean formation;
after providing the pre-flush fluid, provide the inhibitor main pill fluid through the wellbore and to the subterranean formation using the at least one pump; and
after providing the inhibitor main pill fluid, provide the overflush fluid through the wellbore and to the subterranean formation using the at least one pump; and
close the wellbore valve to shut in the pre-flush fluid, the inhibitor main pill fluid, and the overflush fluid within the subterranean formation for a pre-determined period of time; and
after the pre-determined period of time has elapsed, open the wellbore valve to allow produced fluid in the subterranean formation to flow out of the wellbore”).
Second, the modification is obvious as no more than the use of familiar elements (known preflush, scale inhibitor, and overflush fluids; valves; pumps; controllers) according to known techniques (controlling a scale squeeze operation) in a manner that achieves predictable results (inhibiting scale in a wellbore and preventing incompatibility). 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.
Claim 21 is rejected under 35 U.S.C. 103 as obvious over Blumer in view of Nasr-El-Din as in claim 1, and further as evidenced by Harrison (2002/0119902) (cited previously).
Regarding claim 21, Blumer discloses “wherein said push fluid comprises brine or preflush solution” ([0061]) wherein “The preflush chemicals are mixtures, with various formulations, of nonionic surfactants (alkylpolyglycoside, APG)” ([0049]) such as wherein “A preflush solution for injection into a wellbore before a scale inhibitor squeeze treatment, said preflush solution comprising at least 90% diesel, at least 1% alkyl polyglycoside, at least 0.5% ethoxylated alcohol, and at least 1% alcohol” ([0054]) and “Preferred APG are C8-C16 or C10-C14” ([0104]), such as “GLUCOPON® 600 UP” which is a “C10-C16 preservative free. 50-53% active. Lauryl/myristyl glucoside” ([0094]-[0100]).
APGs such as GLUCOPON® 600 UP have the claimed structure. For example, Harrison provides evidence of this, stating “an alkylpolyglycoside compound according to the structure:
PNG
media_image1.png
218
275
media_image1.png
Greyscale
wherein:
R is an alkyl group, preferably a linear alkyl chain, which comprises C8 to C16 alkyl groups; and
x is an integer value of from 0-3, inclusive.
Examples of such alkylpolyglycoside compounds according to this structure include: where R is comprised substantially of C8 and C10 alkyl chains yielding an average value of about 9.1 alkyl carbons per molecule (GLUCOPON 220 UP, GLUCOPON 225 DK); where R is comprised of C8, C10, C12, C14 and C16 alkyl carbons yielding an average value of about 10.3 alkyl carbons per molecule (GLUCOPON 425); where R is comprised substantially of C12, C14 and C16 alkyl carbons yielding an average value of about 12.8 alkyl carbons per molecule (GLUCOPON 600 UP, GLUCOPON 625 CSUP, and GLUCOPON 625 FE), all of which are available from Henkel Corp., Ambler, Pa.)” ([0028]-[0032]).
Thus, the APGs such as GLUOCOPON® 600 UP used in Blumer disclose the claimed structure with m = 2-4 and n = 9-15, providing “wherein the one or more surfactant comprises alkyl polyglycoside, wherein the alkyl polyglycoside has a structure according to formula (I):
PNG
media_image2.png
147
308
media_image2.png
Greyscale
(I);
wherein m is an integer from 2 to 10 and n is an integer from 4 to 30.”
Alternatively, 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 Blumer to include using APGs with the claimed structure (such as GLUCOPON® 600 UP), with a reasonable expectation of success, in order to provide suitable alkyl polyglycosides within the general conditions disclosed by Blumer. See also MPEP 2144.05 Obviousness of Similar and Overlapping Ranges, Amounts, and Proportions.
Response to Arguments
Applicant's arguments filed 3 June 2026 have been fully considered but they are not entirely persuasive based on the current claim language.
In Applicant’s arguments, Applicant points to the “claimed surprising and unexpected result” (p.7), detailing a comparison between the Prior Art and the disclosure from the instant application (p.7-9, esp. p.9).
The Office appreciates the citation to the data from the Specification demonstrating an improvement of the overflush recovery rate from about 8% for a control squeeze overflush of 8% KCl to 85% and 80% for two exemplary APG-containing overflushes, which is indeed a surprising and unexpected result in the degree of difference in overflush recovery rate.
However, Applicant should note that the current claim language is not commensurate in scope with this disclosed result. For example, the claims broadly recite “wherein a recovery rate of the overflush fluid after opening the wellbore valve is higher relative to the same method performed using a control overflush fluid not having the one or more nonionic surfactant,” which broadly encompasses any amount of improvement in the recovery rate.
Notably, Nasr-El-Din as cited teaches “Where used, the surfactants may be present in the fluid in an amount sufficient to prevent incompatibility with formation fluids, other treatment fluids, or wellbore fluids at reservoir temperature” ([0044]). “Incompatibility” as taught by Nasr-El-Din refers to ensuring the injected fluids do not negatively interact with any other components downhole. For example, with reference to the salt, Nasr-El-Din states “The amount of salt to be added should be the amount necessary for formation compatibility, such as the amount necessary for the stability of clay minerals, taking into consideration the crystallization temperature of the brine, e.g., the temperature at which the salt precipitates from the brine as the temperature drops” ([0068]) and, with reference to the chelating agents, “After injecting 2 PV (pore volumes), GLDA was more compatible than HEDTA (it is suspected that there was some fines migration in this phase using HEDTA), and after injecting 5 PV, the normalized pressure drop was the same for the two chelating agents. On the basis of these results it can be concluded that both HEDTA and GLDA at pH 4 are compatible with the Berea sandstone core” ([0146]). Accordingly, Nasr-El-Din teaches that the surfactants are provided to prevent negative effects from incompatibility, such as instability of clay minerals and fines migration in the formation, which would reduce the permeability of the formation.
Reducing the permeability of the formation due to a negative interaction would also be expected to reduce the recovery rate of any fluid, and thus including surfactant as in Nasr-El-Din would be expected to prevent incompatibility, which would be expected to avoid a reduction in permeability and thus also would be expected to allow a higher recovery rate of a given injected fluid having surfactant, compared to the same method performed using a control overflush fluid not having the surfactant.
Accordingly, the claim language as written merely describes an expected effect of including surfactant in view of Nasr-El-Din, not the “surprising and unexpected effect” described in Applicant’s Specification.
Accordingly, this argument is not entirely persuasive based on the current claim language, and the rejections are maintained insofar as Blumer in view of Nasr-El-Din would lead one of ordinary skill to expect, broadly, “wherein a recovery rate of the overflush fluid after opening the wellbore valve is higher relative to the same method performed using a control overflush fluid not having the one or more nonionic surfactant” as a consequence of following the teachings of Nasr-El-Din.
Nevertheless, Applicant may incorporate into the claims a more-specific description of the surprising and unexpected effect, which would overcome these rejections. For example, Applicant might incorporate language such as “wherein the overflush fluid is capable of providing a recovery rate of the overflush fluid after opening the wellbore valve of at least 80%” or the like.
As always, Applicant may consider contacting the Examiner for an Interview or the like, in the case further explanation or guidance is desired.
Conclusion
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/ANDREW SUE-AKO/Primary Examiner, Art Unit 3674
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