WO2010132362A2

WO2010132362A2 - Method for treating hydrocarbon-bearing formations with fluorinated polyurethanes

Info

Publication number: WO2010132362A2
Application number: PCT/US2010/034246
Authority: WO
Inventors: Mukul M. Sharma; Rudolf J. Dams; Yong K. Wu; Wayne W. Fan; Steve J. Martin
Original assignee: Board Of Regents, The University Of Texas System; 3M Innovative Properties Company
Priority date: 2009-05-11
Filing date: 2010-05-10
Publication date: 2010-11-18
Also published as: WO2010132362A3

Abstract

A method of treating a hydrocarbon-bearing formation including receiving data comprising a temperature and a brine composition of the hydrocarbon-bearing formation; selecting a treatment composition for the hydrocarbon-bearing formation comprising a fluorinated polyurethane and solvent, wherein, at the temperature, a mixture of an amount of the brine composition and the treatment composition is transparent and free of precipitated solid, and wherein the mixture does not separate into layers; and contacting the hydrocarbon-bearing formation with the treatment composition. Another method of treating a hydrocarbon-bearing formation includes contacting a limestone formation with a treatment composition comprising a fluorinated polyurethane and solvent. Hydrocarbon-bearing formations treated according to the method are also disclosed. A composition comprising a fluorinated polyurethane and a combination of solvents is also disclosed.

Description

METHOD FOR TREATING HYDROCARBON-BEARING FORMATIONS WITH

FLUORINATED POLYURETHANES

BACKGROUND

In the oil and gas industry, certain surfactants (including certain fluorinated surfactants) are known as fluid additives for various downhole operations (e.g., fracturing, waterflooding, and drilling). Often, these surfactants function to decrease the surface tension of the fluid or to stabilize foamed fluids.

Some hydrocarbon and fluorochemical compounds have been used to modify the wettability of reservoir rock, which may be useful, for example, to prevent or remedy water blocking (e.g., in oil or gas wells) or liquid hydrocarbon accumulation (e.g., in gas wells) in the vicinity of the well bore (i.e., the near well bore region). Water blocking and liquid hydrocarbon accumulation may result from natural phenomena (e.g., water-bearing geological zones or condensate banking) and/or operations conducted on the well (e.g., using aqueous or hydrocarbon fluids). Water blocking and condensate banking in the near well bore region of a hydrocarbon-bearing geological formation can inhibit or stop production of hydrocarbons from the well and hence are typically not desirable. Not all hydrocarbon and fluorochemical compounds, however, provide the desired wettability modification. And some of these compounds modify the wettability of siliciclastic hydrocarbon-bearing formations but not carbonate formations, or vice versa. Hence, there is a continuing need for alternative and/or improved techniques for increasing the productivity of oil and/or gas wells that have brine and/or two phases of hydrocarbons in a near wellbore region of a hydrocarbon-bearing geological formation.

Summary

The methods of treating a hydrocarbon-bearing formation disclosed herein are typically useful for increasing the permeability in hydrocarbon-bearing formations having brine and/or two phases of liquid hydrocarbons (e.g., connate brine and/or water blocking). Treatment of an oil and/or gas well that has brine in the near wellbore region using the methods disclosed herein may increase the productivity of the well. Although not wishing to be bound by theory, it is believed that the fluorinated polyurethanes disclosed herein generally adsorb to or react with at least one of hydrocarbon-bearing formations or proppants under downhole conditions and modify the wetting properties of the rock in the formation to facilitate the removal of hydrocarbons and/or brine. The fluorinated polyurethanes are generally delivered to hydrocarbon-bearing formations in treatment compositions comprising solvent, which treatment compositions may encounter brine in the hydrocarbon-bearing formation. It is believed that useful solvents will prevent the precipitation of the fluorinated polyurethanes, dissolved salts, or other solids when the treatment compositions encounter the brine. Such precipitation may inhibit the adsorption or reaction of the fluorinated polyurethane on the formation, may clog the pores in the hydrocarbon-bearing formation thereby decreasing the permeability and the hydrocarbon and/or brine production, or a combination thereof.

In one aspect, the present disclosure provides a method of treating a hydrocarbon-bearing formation, the method comprising: receiving data comprising a temperature and a brine composition of the hydrocarbon- bearing formation; selecting a treatment composition for the hydrocarbon-bearing formation comprising a fluorinated polyurethane and solvent, wherein, at the temperature, a mixture of an amount of the brine composition and the treatment composition is transparent and free of precipitated solid, and wherein the mixture does not separate into layers; and contacting the hydrocarbon-bearing formation with the treatment composition, wherein the fluorinated polyurethane has at least two repeat units and comprises: at least one end group represented by the formula -A '-Z-RF, and at least one end group represented by the formula -A^l-W-SiG₃; wherein each RF independently represents a fluoroalkyl group optionally containing at least one -O- or a polyfluoropolyether having at least 10 carbon atoms and at least three -O- groups; each Z is independently selected from the group consisting of alkylene, alkylarylene, and arylalkylene, each of which is optionally interrupted or terminated with at least one of -0-, -C(O)-, -S(O)_0-2-, -N(R)-, -SO₂N(R)-, -C(O)N(R)-, -C(O)-O-, -O-C(O)-, -OC(O)-N(R)-, -N(R)-C(O)-O-, or -N(R)-C(O)-N(R)-, wherein each R is independently hydrogen or alkyl having up to four carbon atoms; each A¹ is independently selected from the group consisting of -NH-C(O)-N(R¹¹)-, -NH-C(O)-S-, -NH-C(O)-O-, -N(R^π)-C(O)-NH-_; and -0-C(O)-NH-, wherein R¹¹ is hydrogen or alkyl having up to four carbon atoms; each W is independently selected from the group consisting of alkylene, arylalkylene, and arylene, wherein alkylene is optionally interrupted with at least one -O-; and each G is independently hydroxyl, alkoxy, acyloxy, aryloxy, halogen, alkyl, or phenyl, with the proviso that at least one G is hydroxyl, alkoxy, acyloxy, aryloxy, or halogen.

In another aspect, the present disclosure provides a method of treating a hydrocarbon-bearing formation, the method comprising: contacting the hydrocarbon-bearing formation with a treatment composition comprising solvent and a fluorinated polyurethane, wherein the fluorinated polyurethane has at least two repeat units and comprises: at least one end group represented by the formula -A¹ -Z-RF, and at least one end group represented by the formula -A'-W-SiG₃; wherein each RF independently represents a fluoroalkyl group optionally containing at least one -O- or a polyfluoropolyether having at least 10 carbon atoms and at least three -O- groups; each Z is independently selected from the group consisting of alkylene, alkylarylene, and arylalkylene, each of which is optionally interrupted or terminated with at least one of -0-, -C(O)-, -S(O)_0-2-, -N(R)-, -SO₂N(R)-, -C(O)N(R)-, -C(O)-O-, -O-C(O)-, -OC(O)-N(R)-, -N(R)-C(O)-O-, or -N(R)-C(O)-N(R)- , wherein each R is independently hydrogen or alkyl having up to four carbon atoms; each A¹ is independently selected from the group consisting of -NH-C(O)-N(R¹¹)-, -NH-C(O)-S-, -NH-C(O)-O-, -N(R¹¹J-C(O)-NH-, and -0-C(O)-NH-, wherein R¹ ' is hydrogen or alkyl having up to four carbon atoms; each W is independently selected from the group consisting of alkylene, arylalkylene, and arylene, wherein alkylene is optionally interrupted with at least one -0-; and each G is independently hydroxyl, alkoxy, acyloxy, aryloxy, halogen, alkyl, or phenyl, with the proviso that at least one G is hydroxyl, alkoxy, acyloxy, aryloxy, or halogen; and wherein the hydrocarbon-bearing formation comprises limestone.

In some embodiments of the foregoing aspects, the fluorinated polyurethane is represented by formula:

wherein

R¹ is alkylene, arylene, or arylalkylene, each of which is optionally interrupted by at least one biruet, allophanate, uretdione, or isocyanurate linkage;

X¹ is alkylene, polyalkyleneoxy, fluoroalkylene, or polyfluoroalkyleneoxy, wherein alkylene is optionally interrupted by -O- and is optionally substituted with -Si(G)₃, or -M; each a' is 0, 1, or 2; e is a value in a range from 1 to 20; each E is independently an end group represented by formula RF-Z-A-C(O)-N(H)-; (G)₃Si-W-A-C(O)-N(H)-, or (M) ,_₂- W- A-C(O)-N(H)-; each A is independently -0-, -N(R¹¹)-, -S-, or -C(O)O-, wherein R¹¹ is hydrogen or alkyl having up to four carbon atoms; each M is independently selected from the group consisting of an ammonium group, a carboxylate, a sulfonate, a sulfate, a phosphate, or a phosphonate; and RF, Z, W, and G are as defined above, In some of these embodiments, at least one E group is represented by formula (M)_I-2-W-A-C(O)-N(H)-, or X¹ is substituted with at least one M.

In another aspect, the present disclosure provides a hydrocarbon-bearing formation treated according to the methods disclosed herein.

In some embodiments of foregoing aspects, the end group represented by formula -A¹ -Z-RF is - NH-C(O)-O-(C_jH_2j)N(R")S(O)₂-Rf², and wherein the end group represented by formula -A¹ -W- SiG₃ is -NH-(C_kH_2k)-SiG'₃, wherein Rf² is perfluoroalkyl having from 2 to 6 carbon atoms, R" is hydrogen or alkyl having up to four carbon atoms; each G¹ is independently alkyoxy or hydroxyl, and j and k are each independently 1 to 6. In some of these embodiments, the perfluoroalkyl is perfluorobutyl. In some embodiments, the fluorinated polyurethane is free of ester groups. In some embodiments, the solvent comprises at least one of water, a monohydroxy alcohol having up to 4 carbon atoms, ethylene glycol, propylene glycol, acetone, a glycol ether, supercritical carbon dioxide or liquid carbon dioxide.

In some embodiments of any of the methods disclosed herein, the method further comprising providing an increase in gas permeability of the hydrocarbon-bearing formation after contacting the hydrocarbon-bearing formation with the treatment composition. In some of these embodiments, the increase in gas permeability is an increase in gas relative permeability. In some embodiments, the increase in gas permeability degrades at a slower rate than a comparative increase in gas permeability obtained when an equivalent hydrocarbon-bearing formation is treated with a nonϊonic fluorinated polymeric surfactant free of stlane groups. In some embodiments, the hydrocarbon-bearing formation is a retrograde condensate gas well, hi some embodiments, the hydrocarbon-bearing formation is a volatile oil well or a black oil well.

In some embodiments of any of the methods disclosed herein, the hydrocarbon-bearing formation has at least one fracture, and wherein the fracture has a plurality of proppants therein. In some embodiments, the plurality of proppants comprises bauxite. In other embodments, the hydrocarbon-bearing formation is free of manmade fractures having proppants therein.

In another aspect, the present disclosure provides a composition comprising: a fluorinated polyurethane having at least two repeat units, the fluorinated polyurethane comprising: at least one end group represented by the formula -NH-C(O)-O-(C_jH_2j)N(R")S(O)₂-Rf² _J and at least one end group represented by the formula -NH-(CkHJk)-SiG¹ _J, wherein

Rf² is perfluoroalkyl having from 2 to 6 carbon atoms;

R" is hydrogen or alkyl having up to four carbon atoms; each G' is independently alkoxy or hydroxyl; and j and k are each independently 1 to 6; and solvent comprising: water; a monohydroxy alcohol having up to 4 carbon atoms; and a polyol or polyol ether, each having from 2 to 25 carbon atoms.

Methods according to the present disclosure are useful for changing the wettability of a variety of materials found in hydrocarbon-bearing formations, including sandstone, limestone, and bauxite proppants. Thus, the treatment methods are more versatile than other treatment methods which are effective with only certain substrates (e.g., sandstone). Methods disclosed herein can be carried out with one treatment step (i.e., application of one treatment composition). The fluorinated polyurethanes useful for practicing the present disclosure are also stable in the solvents disclosed herein and can be delivered to hydrocarbon-bearing formations having brine at a variety of temperatures.

Brief Description of the Drawings

For a more complete understanding of the features and advantages of the present disclosure, reference is now made to the detailed description along with the accompanying figures and in which:

Fig. 1 is a schematic illustration of an exemplary embodiment of an offshore oil platform operating an apparatus for progressively treating a near wellbore region according to some embodiments of the present disclosure;

Fig. 2 is a schematic illustration of the core flood set-up used for Examples 6 to 8;

Fig. 3 is a schematic illustration of the core flood set-up used for Comparative Example

B;

Fig. 4 is a schematic illustration of the core flood set-up used for Examples 1 to 5;

Fig. 5 is a schematic illustration of the core flood set-up used for Example 9.

Detailed Description

To facilitate the understanding of this disclosure, a number of terms are defined below. Terms defined herein have meanings as commonly understood by a person of ordinary skill in the areas relevant to the present disclosure. Terms such as "a", "an", "at least one", and "the" are not intended to refer to only a singular entity, but include the general class of which a specific example may be used for illustration. The terms "a", "an", and "the" are used interchangeably with the term "at least one". The terminology herein is used to describe specific embodiments of the disclosure, but their usage does not delimit the invention, except as outlined in the claims. The term "brine" refers to water having at least one dissolved electrolyte salt therein (e.g., having any nonzero concentration, and which may be less than 1000 parts per million by weight (ppm), or greater than 1000 ppm, greater than 10,000 ppm, greater than 20,000 ppm, 30,000 ppm, 40,000 ppm, 50,000 ppm, 100,000 ppm, 150,000 ppm, or greater than 200,000 ppm). The term "hydrocarbon-bearing formation" includes both hydrocarbon-bearing formations in the field (i.e., subterranean hydrocarbon-bearing formations) and portions of such hydrocarbon- bearing formations (e.g., core samples).

The term "treating" includes placing a composition within a hydrocarbon-bearing formation using any suitable manner known in the art (e.g., pumping, injecting, pouring, releasing, displacing, spotting, or circulating the fluorinated polymer into a well, well bore, or hydrocarbon-bearing formation.

The term "solvent" refers to a homogeneous liquid material {inclusive of any water with which it may be combined) that is capable of at least partially dissolving the fluorinated polyurethane at 25 ⁰C.

"Alkyl group" and the prefix "alk-" are inclusive of both straight chain and branched chain groups and of cyclic groups. Unless otherwise specified, alkyl groups herein have up to 20 carbon atoms. Cyclic groups can be monocyclic or polycyclic and, in some embodiments, have from 3 to 10 ring carbon atoms.

The term "polymer" refers to a molecule having a structure which essentially includes the multiple repetition of units derived, actually or conceptually, from molecules of low relative molecular mass. The term "polymer" encompasses oligomers.

The term "polyurethane" refers to polymers containing at least one of urethane or urea functional groups.

The term "fluoroalkyl group" includes linear, branched, and/or cyclic alkyl groups in which all C-H bonds are replaced by C-F bonds as well as groups in which hydrogen or chlorine atoms are present instead of fluorine atoms provided that up to one atom of either hydrogen or chlorine is present for every two carbon atoms. In some embodiments of fluoroalkyl groups, when at least one hydrogen or chlorine is present, the fluoroalkyl group includes at least one trifluoromethyl group. Unless otherwise specified, fluoroalkyl groups herein have up to 30 (e.g., up to 25, 20, 15, 12, 10, 8, or 6) fluorinated carbon atoms.

The term "productivity" as applied to a well refers to the capacity of a well to produce hydrocarbons (i.e., the ratio of the hydrocarbon flow rate to the pressure drop, where the pressure drop is the difference between the average reservoir pressure and the flowing bottom hole well pressure (i.e., flow per unit of driving force)). The phrase "comprises at least one of followed by a list refers to comprising any one of the items in the list and any combination of two or more items in the list. Similarly, the phrase "at least one of followed by a list refers to any one of the items in the list and any combination of two or more items in the list.

The term "transparent" refers to allowing clear view of objects beyond. In some embodiments, transparent refers to liquids that are not hazy or cloudy.

All numerical ranges are inclusive of their endpoints and non-integral values between the endpoints unless otherwise stated.

In some embodiments, the fluorinated polyurethane has at least two repeat units and comprises the reaction product of (a) at least one multifunctional isocyanate compound; (b) at least one polyol; (c) at least one fluorochemical monoalcohol or monoamine; (d) at least one isocyanate- reactive silane; and optionally (e) at least one water-solubilizing compound comprising at least one water-solubilizing group and at least one isocyanate-reactive hydrogen containing group. In some embodiments, at least one polyamine may also be used.

In some embodiments, the fluorinated polyurethane comprises a multivalent unit comprising a segment represented by formula:

, wherein b is 1 to 5 (e.g., 1 to 4, 1 to 3, or 1 to 2), and R is alkylene, arylene, or arylalkylene, each of which is optionally interrupted by at least one biruet, allophanate, uretdione, or isocyanurate linkage. Typically, such multivalent units arise from a condensation reaction of a multifunctional isocyanate compound comprising at least two (e.g., 2, 3, 4, or more) isocyanate groups (i.e., -NCO) linked together by alkylene, arylene, or arylalkylene, each of which is optionally attached to at least one of a biuret, an allophanate, an isocyanurate, or a uretdione. The multivalent unit is typically incorporated into the polyurethane through carbamate, urea, biuret, or allophanate linkages. In some embodiments, b is 1, and R¹⁰ is divalent alkylene, arylene, or arylalkylene (i.e., the multivalent unit is derived from a diisocyanate). In some embodiments, b is 2, and R¹⁰ is alkylene, arylene, or arylalkylene groups, which are attached to a biuret or an isocyanurate (i.e., the multivalent unit is derived from a triisocyanate). Mixtures of multivalent units may be present in the polyurethane.

In some embodiments, useful fluorinated polyurethanes are represented by formula:

wherein R¹⁰ is as defined above.

For fluorinated polyurethanes disclosed herein, RF represents a fluoroalkyl group optionally containing at least one -O- or a polyfluoropolyether group having at least 10 fluorinated carbon atoms and at least three -O- groups. In some embodiments, RF represents a fluoroalkyl group having up to 12, 10, 8, or 6 fluorinated carbon atoms. In some embodiments each RF independently represents a fluoroalkyl group having from 1 to 10 (in some embodiments, 1 to 8, 1 to 6, 2 to 6, or 2 to 4) carbon atoms (e.g., trifluoromethyl, perfluoroethyl, 1,1,2,2- tetrafluoroethyl, 2-chlorotetrafluoroethyl, perfluoro-n-propyl, perfluoroisopropyl, perfluoro-n- butyl, 1,1,2,3,3,3-hexafluoropropyl, perfluoroisobutyl, perfluoro-.sec-butyl, or perfluoro-terf- butyl, perfluoro-n-pentyl, pefluoroisopentyl, perfluorohexyl, perfluoroheptyl, perfluorooctyl, perfluorononyl, or perfluorodecyl). hi some embodiments, RF is perfluorobutyl (e.g., perfluoro- n-butyl, perfluoroisobutyl, or perfluoro-sec-butyl). hi some embodiments, RF is perfluoropropyl (e.g., perfluoro-n-propyl or perfluoroisopropyl). RF may contain a mixture of fluoroalkyl groups (e.g., with an average of up to 8, 6, or 4 carbon atoms). In some embodiments, RF is represented by formula R_f ^a-O-(R_f ^b-O-)k<Rf^C)-, wherein Rf^a is a perfluoroalkyl having 1 to 10 (in some embodiments, 1 to 6, 1 to 4, 2 to 4, or 3) carbon atoms; each R_f ^b is independently a perfluoroalkylene having 1 to 4 (i.e., 1, 2, 3, or 4) carbon atoms; R/ is a perfluoroalkylene having 1 to 6 (in some embodiments, 1 to 4 or 2 to 4) carbon atoms; and k' is a number from 2 to 50 (in some embodiments, 2 to 25, 2 to 20, 3 to 20, 3 to 15, 5 to 15, 6 to 10, or 6 to 8). Representative R_f ^a groups include CF₃-, CF₃CF₂-, CF₃CF₂CF₂-, CF₃CF(CF₃)-, CF₃CF(CF₃)CF₂-, CF₃CF₂CF₂CF₂-, CF₃CF₂CF(CF₃)-, CF₃CF₂CF(CF₃)CF₂-, and CF₃CF(CF₃)CF₂CF₂-. In some embodiments, R_f ^a is CF₃CF₂CF₂-. Representative R_f ^b groups include -CF₂-, -CF(CF₃)-, - CF₂CF₂-, -CF(CF₃)CF₂-, -CF₂CF₂CF₂-, -CF(CF₃)CF₂CF₂-, -CF₂CF₂CF₂CF₂-, and -CF₂C(CF₃)₂-. Representative R_f ^c groups include -CF₂-, -CF(CF₃)-, -CF₂CF₂-, -CF₂CF₂CF₂-, and CF(CF₃)CF₂-. In some embodiments, R_f ^c is -CF(CF₃)-. hi some embodiments, Rf is selected from the group consisting of C₃F₇O(CF(CF₃)CF₂O)_nCF(CF₃)-, C₃F₇O(CF₂CF₂CF₂O)_nCF₂CF₂-, and CF₃O^F₄O)_nCF₂-, and wherein n has an average value in a range from 3 to 50 (in some embodiments, 3 to 25, 3 to 15, 3 to 10, 4 to 10, or even 4 to 7).

For fluorinated polyurethanes disclosed herein, including any of the above embodiments, Z is selected from the group consisting of alkylene, alkylarylene, and arylalkylene, each of which is optionally interrupted or terminated with at least one of -O-, -C(O)-, -S(0)o_-2-, -N(R)-, - SO₂N(R)-, -C(O)N(R)-, -C(O)-O-, -O-C(O)-, -OC(O)-N(R)-, -N(R)-C(O)-O-, or -N(R)-C(O)- N(R)-, and wherein R is selected from the group consisting of hydrogen and alkyl having up to 4 carbon atoms (e.g., methyl, ethyl, n-propyl, isopropyl, n-butyl, or isobutyl). In some embodiments, R is methyl or ethyl. The phrase "interrupted by at least one functional group" refers to having alkylene or arylalkylene on either side of the functional group. The term "terminated by a functional group" refers to the functional group being connected to the RF. In some embodiments Z is alkylene. In some embodiments, Z is -S(0)2-N(R)-alkylene. X¹ is alkylene, polyalkyleneoxy, fiuoroalkylene, or polyfluoroalkyleneoxy, wherein alkylene is optionally interrupted by -O- and is optionally substituted with -Si(G)₃, an ammonium group, a carboxylate, a sulfonate, a sulfate, a phosphate, or a phosphonate. In some embodiments, X¹ is alkylene or polyalkyleneoxy. In some embodiments, X¹ is alkylene that is substituted with a carboxylate group. Each a' is O, 1, or 2 (e.g., O or 1). In some embodiments, e is an integer from 1 to 20 (e.g., 2 to 15 or 3 to 10). Each E is independently an end group represented by formula RF-Z-A-C(O)-N(H)-;

(G)₃Si-W-A-C(O)-N(H)-, and (M) _I-2-W-A-C(O)-N(H)- (i.e., W may be substituted with one or two M groups); wherein A is -0-, -N(R¹¹)-, -S-, or -C(O)O-; G is as defined above; M is selected from the group consisting of an ammonium group, a carboxylate, a sulfonate, a sulfate, a phosphate, or a phosphonate; and each W is independently selected from the group consisting of alkylene, arylalkylene, and arylene, wherein alkylene is optionally interrupted with at least one - O-. In some embodiments, W is alkylene (e.g., having up to 6, 4, or 3 carbon atoms). In some embodiments, Z is -C_jH₂J-, -CON(R")C_jH_2j-,

-SO₂N(R")C_jH_2j-, or -C_jH_2jSO₂N(R")C_jH_2j-, wherein R" is hydrogen or alkyl having up to four carbon atoms, and j is independently an integer from 1 to 6 (in some embodiments from 2 to 4). In some embodiments, useful fluorinated polyurethanes are represented by formula

Ri?-S(0).-N(R")-C_jH_Ij-

wherein each a¹ is about 1 ; each E is as defined above with the proviso that at least one E is Rf²- S(O)₂N(R")-CjH_2j-O-C(O)-N(H)-; X¹ is alkylene that is substituted with a carboxylate group; each G' is independently alkoxy (e.g., having up to four carbon atoms) or hydroxyl; j and k are each values from 1 to 6; R¹⁰ is as defined above; each R" is independently hydrogen or alkyl having up to four carbon atoms; and each Rf² independently represents perfluoroalkyl having from 2 to 6 (in some embodiments, 3 to 4 or 4) carbon atoms. Such fluorinated polyurethanes may be prepared, for example, by a condensation reaction of at least one multifunctional isocyanate with at least one polyol and reaction of the resulting oligomer with at least one fluorinated monoalcohol and at least one isocyanate-reactive silane.

Aromatic multifunctional isocyanate compounds useful for the preparation of fluorinated polyurethanes according to any of the above embodiments include 2,4-toluene diisocyanate (TDI), 2,6-toluene diisocyanate, an adduct of TDI with trimethylolpropane (available, for example, from Bayer Corporation, Pittsburgh, Pa. under the trade designation "DESMODUR CB"), the isocyanurate trimer of TDI (available, for example, from Bayer Corporation under the trade designation "DESMODUR IL"), diphenylmethane 4,4'-diisocyanate (MDI), diphenylmethane 2,4'-diisocyanate, 1,5-diisocyanatonaphthalene, 1,4-phenylene diisocyanate, 1,3-ρhenylene diisocyanate, 1 -methyoxy-2,4-phenylene diisocyanate, 1 -chloroρhenyl-2,4- diisocyanate, and mixtures thereof.

Multifunctional alkylene isocyanate compounds useful for the preparation of fluorinated polyurethanes according to any of the above embodiments include 1,4-tetramethylene diisocyanate, hexamethylene 1,4-diisocyanate, hexamethylene 1,6-diisocyanate (HDI), 1,12- dodecane diisocyanate, 2,2,4-trimethyl-hexamethylene diisocyanate (TMDI), 2,4,4-trimethyl- hexamethylene diisocyanate, 2-methyl-l,5-pentamethylene diisocyanate, dimer diisocyanate, the urea of hexamethylene diisocyanate, the biuret of hexamethylene 1,6-diisocyanate (HDI) (available, for example, from Bayer Corporation under the trade designations "DESMODUR N- 100" and "DESMODUR N-3200"), the isocyanurate of HDI (available, for example, from Bayer Corporation under the trade designations "DESMODUR N-33OO" and "DESMODUR N-3600"), a blend of the isocyanurate of HDI and the uretdione of HDI (available, for example, from Bayer Corporation under the trade designation "DESMODUR N-3400"), dicyclohexylmethane diisocyanate (H|₂ MDI, available, for example, from Bayer Corporation under the trade designation "DESMODUR W"), 4,4'-isoρropyl-bis(cyclohexylisocyanate), isophorone diisocyanate (IPDI), cyclobutane- 1,3 -diisocyanate, cyclohexane 1,3 -diisocyanate, cyclohexane 1,4-diisocyanate (CHDI), 1 ,4-cyclohexanebis(methylene isocyanate) (BDI), 1,3- bis(isocyanatomethyl)cyclohexane (H₆ XDI), 3-isocyanatomethyl-3,5,5-trimethylcyclohexyl isocyanate, and mixtures thereof.

Multifunctional arylalkylene isocyanates useful for the preparation of fiuorinated polyurethanes according to any of the above embodiments include m-tetramethyl xylylene diisocyanate (m- TMXDI), p-tetramethyl xylylene diisocyanate (p-TMXDI), 1,4-xylylene diisocyanate (XDI), 1,3- xylylene diisocyanate, p-(l-isocyanatoethyl)-phenyl isocyanate, m-(3-isocyanatobutyl)-phenyl isocyanate, 4-(2-isocyanatocyclohexyl-methyl)-phenyl isocyanate, and mixtures thereof. The product from the reaction of m-tetramethylxylene diisocyanate with 1,1,1- tris(hydroxymethyl)propane, available, for example, from American Cyanamid, Stamford, Conn, under the trade designation "CYTHANE 3160" can also be used.

In some embodiments, fiuorinated polyurethanes useful for practicing the present disclosure are prepared from a multifunctional isocyanate selected from the group consisting of HDI, 1,12- dodecane diisocyanate, isophorone diisocyanate, toluene diisocyanate, dicyclohexylmethane 4,4'diisocyanate, MDI, a biuret, uretdione, or isocyanurate thereof, and mixtures thereof. In some embodiments, fiuorinated polyurethanes useful for practicing the present disclosure are prepared from the reaction of a multifuncitional isocyanate and a polyol. Useful polyols include alkylene, arylene, arylalkylene, or polymeric groups, which are optionally interrupted with at least one ether linkage (e.g., polyalkyleneoxy compounds) or amine linkage, which have an average hydroxyl functionality of at least about 2 (e.g., up to 5, 4, or 3), and which are optionally substituted with -Si(G)₃, an ammonium group, a carboxylate, a sulfonate, a sulfate, a phosphate, or a phosphonate, wherein each G is independently as defined above. The hydroxyl groups can be primary or secondary. Mixtures of diols with polyols that have a higher average hydroxyl functionality (e.g., 2.5 to 5, 3 to 4, or 3) can also be used. Exemplary useful polyols include mono fatty acid esters of polyols (e.g., glycerol monooleate, glycerol monostearate, glycerol monoricinoleate, or C₅ to C₂o alkyl di-esters of pentaerythritol); castor oil; polyester diols or polyols (e.g., those available from Union Camp under the trade designation "UNIFLEX", from Rohm and Haas Co., Philadelphia, PA under the trade designation "PARAPLEX U-148", from Mobay Chemical Corp., Irvine, CA, under the trade designation "MULTRON", or those derived from dimer acids or dimer diols and available, for example, from Uniqema, Gouda, Netherlands, under the trade designations "PRIPLAST" or "PRIPOL"; hydroxy-terminated polylactones (e.g., polycaprolactone polyols, for example, with number average molecular weights in the range of about 200 to about 2000 available, for example, from Union Carbide Corp., Danbury, CT, under the trade designation "TONE", for example, grades 0201, 0210, 0301, and 0310); hydroxy- terminated polyalkadienes (e.g., hydroxyl-terminated polybutadienes, for example, those available from Elf Atochem, Philadelphia, PA, under the trade designation "POLY BD"); alkylene diols (e.g., 1 ,2-ethanediol, 1,2-propanediol, 3-chloro-l,2-propanediol, 1,3-propanediol, 1,3-butanediol, 1,4-butanediol, 2-methyl-l,3-propanediol, 2,2-dimethyl- 1,3 -propanediol (neopentyl glycol), 2-ethyl- 1,3 -propanediol, 2,2-diethyl- 1,3-propanediol, 1 ,5-pentanediol, 2- ethyl-l,3-pentanediol, 2,2,4-trimethyl-l,3-pentanediol, 3-methyl-l,5-ρentanediol, 1,2-, 1,5-, and 1,6-hexanediol, 2-ethyl-l,6-hexanediol, bis(hydroxymethyl)cyclohexane, 1,8-octanediol, bicyclo- octanediol, 1,10-decanediol, tricyclo-decanediol, norbornanediol, and 1,18- dihydroxyoctadecane); polyhydroxyalkanes (e.g., glycerol, trimethylolethane, trimethylolpropane, 2-ethyl-2-(hydroxymethyl)- 1 ,3-propanediol, 1 ,2,6-hexanetriol, pentaerythritol, quinitol, mannitol, and sorbitol); Bisphenol A ethoxylate, Bisphenol A propyloxylate, and Bisphenol A propoxylate/ethoxylate (available from Sigma-Aldrich, Milwaukee, WI); polytetramethylene ether glycols available, for example, from Quaker Oats Company, Chicago, IL, under the trade designation "POLYMEG", for example, grades 650 and 1000) and polyether polyols available, for example, from E.I. duPont de Nemours, Wilmington, DE, under the trade designation "TERATHANE"); polyoxyalkylene tetrols having secondary hydroxyl groups available, for example, from Wyandotte Chemicals Corporation, Wyandotte, MI, under the trade designation "PeP", for example grades 450, 550, and 650; polycarbonate diols (e.g., a hexanediol carbonate with M_n = 900 available, for example, from PPG Industries, Inc., Pittsburgh, PA, under the trade designation "DURACARB 120", aromatic diols (e.g., N,N- bis(hydroxyethyl)benzamide, 4,4'-bis(hydroxymethyl)diphenylsulfone, 1 ,4-benzenedimethanol, l,3-bis(2-hydroxyethyoxy)benzene, 1 ,2-dihydroxybenzene, resorcinol, 1 ,4-dihydroxybenzene, 3,5-, 2,6-, 2,5-, and 1,6-, 2,6-, 2,5-, and 2,7-dihydroxynaphthalene, 2,2'- and 4,4'-biρhenol, 1,8- dihydroxybiphenyl, 2,4-dihydroxy-6-methyl-pyrimidine, 4,6-dihydroxypyrimidine, 3,6- dihydroxypyridazine, bisphenol A, 4,4'-ethylidenebisphenol, 4,4'-isopropylidenebis(2,6- dimethylphenol), bis(4-hydroxyphenyl)methane, 1 , 1 -bis(4-hydroxyphenyl)- 1 -phenylethane (bisphenol C), l,4-bis(2-hydroxyethyl)piperazine, bis(4-hydroxyphenyl) ether; and diols and polyols containing another functional group (e.g., bis(hydroxymethyl)propionic acid, 2,4- dihydroxybenzoic acid, N,N-bis(2-hydroxyethyl)-3-aminopropyltriethoxysilane, and bicine). In some embodiments, useful polyols comprise alkyleneoxy groups, which may be useful, for example, for increasing the water-solubility of the compounds disclosed herein. Useful alkyleneoxy-containing polyols include di and polyalkylene glycols (e.g., di(ethylene glycol), tri(ethylene glycol), tetra(ethylene glycol), dipropylene glycol, diisopropylene glycol, tripropylene glycol, l,l l-(3,6-dioxaundecane)diol, l,14-(3,6,9,12-tetraoxatetradecane)diol, 1,8- (3,6-dioxa-2,5,8-trimethyloctane)diol, or l,14-(5,10-dioxatetradecane)diol); polyoxyethylene, polyoxypropylene, and ethylene oxide-terminated polypropylene glycols and triols of molecular weights from about 200 to about 2000 (e.g., available from Union Carbide Corp. under the trade designation "CARBOWAX", poly(propylene glycol) available, for example, from Lyondell Chemical Company, Houston, TX, under the trade designation "PPG-425"); block copolymers of poly(ethylene glycol) and poly(propylene glycol) available from BASF Corporation, Mount Olive, NJ, under the trade designation "PLURONIC".

Other alkyleneoxy-containing compounds may be useful co-reactants with multifunctional isocyanates to prepare fluorinated polyurethanes useful for practicing the present disclosure. For example, diamino terminated poly(alkylene oxide) compounds (e.g., those available from Huntsman Corp., The Woodlands, Texas under the trade designations "JEFFAMINE ED" or "JEFFAMINE EDR- 148") and poly(oxyalkylene) thiols may be used.

Useful fluorinated monoalcohols include, for example, 2-(N- methylperfluorobutanesulfonamido)ethanol; 2-(N-ethylperfluorobutanesulfonamido)ethanol; 2- (N-methylperfluorobutanesulfonarnido)propanol; N-methyl-N-(4- hydroxybutyl)perfluorohexanesulfonamide; 1,1,2,2- tetrahydroperfluorooctanol ; 1,1- dihydroperfluorooctanol; C₆F_I3CF(CF₃)CO₂C₂H₄CH(CH₃)OH; n-

C₆F₁₃CF(CF₃)CON(H)CH₂CH₂OH; C₄F₉OC₂F₄OCF₂CH₂OCH₂CH₂OH;

C₃F₇CON(H)CH₂CH₂OH; 1,1,2,2,3,3-hexahydroperfluorodecanol; C₃F₇O(CF(CF₃)CF₂O)_{1 -} ₃₆CF(CF₃)CH₂OH; CF₃O(CF₂CF₂O)_1-36CF₂CH₂OH; and mixtures thereof. In some embodiments, the fluorinated mono alcohol is represented by the formula HO- (CjH_2j)N(R")S(O)₂-Rf², wherein j, R", and Rf² are as defined above.

An end-group of the formula -A '-W- SiG₃ can be incorporated into a fluorinated urethane oligomer by carrying out the polymerization reaction (e.g., as described above) in the presence of a silane of formula HA-W-SiG₃ (in some embodiments, H₂N-(CH₂)_n-SiG₃). Useful silanes of formula HA-W-SiG₃ include H₂NCH₂CH₂CH₂Si(OC₂Hs)₃; H₂NCH₂CH₂CH₂Si(OCH₃)₃; H₂NCH₂CH₂CH₂Si(O-N=C(CH₃)(C₂H₅))₃; HSCH₂CH₂CH₂Si(OCH₃)₃; HO(C₂H₄O)₃C₂H₄N(CH₃)(CH₂)₃Si(OC₄H₉)₃; H₂NCH₂C₆H₄CH₂CH₂Si(OCH₃)₃; HSCH₂CH₂CH₂Si(OCOCH₃)₃; HN(CH₃)CH₂CH₂Si(OCH₃)₃; HSCH₂CH₂CH₂SiCH₃(OCH₃)₂; (H₃CO)₃SiCH₂CH₂CH₂NHCH₂CH₂CH₂Si(OCH₃);_!; HN(CH₃)C₃H₆Si(OCH₃)₃; CH₃CH₂OOCCH₂CH(COOCH₂CH₃)HNC₃H₆Si(OCH₂CH₃)₃; C₆H₅NHC₃H₆Si(OCH₃)J; H₂NC3H₆SiCH₃(OCH₂CH₃)₂;

HOCH(CH₃)CH₂OCONHC₃H₆Si(OCH₂CHj)₃; (HOCH₂CH₂)₂NCH₂CH₂CH₂Si(OCH₂CH₃)₃; and mixtures thereof.

Typically, condensation reactions useful for preparing fluorinated polyurethanes are run in the presence of a catalyst, for example, a tin II or tin IV salt (e.g., dibutyltin dilaurate, stannous octanoate, stannous oleate, tin dibutyldi-(2-ethyl hexanoate), tin (II) 2-ethyl hexanoate, and stannous chloride) or a tertiary amine (e.g., triethylamine, tributylamine, triethylenediamine, tripropylamine, bis(dimethylaminoethyl) ether, ethyl morpholine, 2,2 '-dimorpholinodi ethyl ether, l,4-diazabicyclo[2.2.2]octane (DABCO), and l,8-diazabicyclo[5.4.0.]undec-7-ene (DBU). In some embodiments, a tin salt is used. The amount of catalyst present will depend on the particular reaction. Generally, however, suitable catalyst concentrations are from about 0.001 percent to about 10 percent (in some embodiments, about 0.1 percent to about 5 percent or about 0.1 to about 1 percent) by weight based on the total weight of the reactants. Typically, the reaction will be carried out such that all or almost all (e.g., greater than 90, 95, 98, 99, or 99.5 percent) isocyanate groups have been reacted, resulting in a product that is essentially free of isocyanate groups.

The condensation reaction useful for the preparation of fluorinated polyurethanes is typically carried out under dry conditions in common, non-protic organic solvents (e.g., ethyl acetate, acetone, methyl isobutyl ketone, methyl ethyl ketone, and toluene) and fluorinated solvents (e.g., hydrofluoroethers and trifluorotoluene). Suitable reaction temperatures can be determined by those skilled in the art based on the particular reagents, solvents, and catalysts being used. Generally suitable reaction temperatures are between about room temperature and about 120 ⁰C (e.g., 30 ⁰C to 100 ⁰C, 40 ⁰C to 90 ⁰C, or 60 ⁰C to 80 ⁰C). Generally the reaction is carried out such that between 1 and 100 percent (e.g., from 5 to 60, 10 to 50, or 10 to 40 percent) of the isocyanate groups of the multifunctional isocyanate compound or mixture of multifunctional isocyanate compounds is reacted with the fluorinated alcohol or amine. The remainder of the isocyanate groups is reacted with one or more of the components described above. For example, an oligomeric compound may be obtained by reacting 10 to 30 percent of the isocyanate groups with a fluorinated alcohol, reacting 10 to 30 percent of the isocyanate groups with a silane compound represented by formula (G)₃Si-W-AH, and reacting 0 to 40 percent of the isocyanate groups with water or a fluorinated alcohol or amine, an aliphatic alcohol, or a compound represented by formula (M) _I-2-W-AH. When a compound represented by formula (M)_1-2-W-AH is used, typically the ratio of the multifunctional isocyanate compound to the compound represented by formula (M)i_-2-W-AH is from about 3:1 to about 16:1 (e.g., 5:1 to about 11 :1). The order of the addition of components can be changed as would be understood by a person of skill in the art.

In some embodiments, the multifunctional isocyanate compound is combined with a fluorinated or non-fluorinated polyol in addition to the fluorinated compound represented by formula RF-Z- AH. A mixture of polyols can be used instead of a single polyol. When the multifunctional isocyanate compound is a triisocyanate, the polyol is typically a diol to prevent undesired gelation. The resulting isocyanate functional oligomers are then further reacted with a fluorinated compound represented by formula RF-Z-AH and at least one of a fluorinated alcohol, an aliphatic alcohol, a silane compound represented by formula (G)₃Si-W-AH, or a compound represented by formula (M)I_-2-W-AH. End groups represented by formula RF-Z-A¹- are thereby bonded to the isocyanate functional oligomers. In some embodiments, a compound represented by formula G)₃Si-W-AH (e.g., an aminosilane) is used in the reaction mixture. Exemplary reaction conditions and other components useful for preparing useful fluorinated polyurethanes are described in U.S. Pat. No. 6,646,088 (Fan et al.), the disclosure of which is incorporated herein by reference in its entirety.

Typically, in treatment compositions according to the present disclosure and/or useful for practicing any of the methods described herein, the fluorinated polyurethane is present in the treatment composition at at least 0.01, 0.015, 0.02, 0.025, 0.03, 0.035, 0.04, 0.045, 0.05, 0.055, 0.06, 0.065, 0.07, 0.075, 0.08, 0.085, 0.09, 0.095, 0.1, 0.15, 0.2, 0.25, 0.5, 1, 1.5, 2, 3, 4, or 5 percent by weight, up to 5, 6, 7, 8, 9, or 10 percent by weight, based on the total weight of the composition. For example, the amount of the fluorinated polyurethane in the treatment composition may be in a range of from 0.01 to 10, 0.1 to 10, 0.1 to 5, 1 to 10, or even in a range from 1 to 5 percent by weight, based on the total weight of the composition. Lower and higher amounts of the fluorinated polyurethane in the treatment composition may also be used, and may be desirable for some applications. The treatment composition is typically homogeneous. Treatment compositions according to and/or useful in practicing the present disclosure comprise solvent. Examples of useful solvents for any of these methods include organic solvents, water, easily gasified fluids (e.g., ammonia, low molecular weight hydrocarbons, and supercritical or liquid carbon dioxide), and combinations thereof. In some embodiments, the solvent is water- mi scible. Examples of organic solvents useful for practicing the methods disclosed herein include polar solvents such as alcohols (e.g., methanol, ethanol, isopropanol, propanol, or butanol), glycols (e.g., ethylene glycol or propylene glycol), glycol ethers (e.g., ethylene glycol monobutyl ether or those glycol ethers available under the trade designation "DOWANOL" from Dow Chemical Co., Midland, MI), or acetone.

In some embodiments, treatment compositions useful in practicing the present disclosure contain two or more different solvents. In some embodiments, the compositions comprise at least one of a polyol or polyol ether independently having from 2 to 25 (in some embodiments, 2 to 15, 2 to 10, 2 to 9, or even 2 to 8) carbon atoms and at least one of water, a monohydroxy alcohol, an ether, or a ketone, wherein the monohydroxy alcohol, the ether, and the ketone each independently have up to 4 carbon atoms. In some of these embodiments, the polyol or polyol ether is present in the composition at at least 50, 55, 60, or 65 percent by weight and up to 75, 80, 85, or 90 percent by weight, based on the total weight of the composition. The term "polyol" refers to an organic molecule consisting of C, H, and O atoms connected one to another by C-H, C-C, C-O, O-H single bonds, and having at least two C-O-H groups. In some embodiments, useful polyols (e.g., diols or glycols) have 2 to 25, 2 to 20, 2 to 15, 2 to 10, 2 to 8, or even 2 to 6 carbon atoms. In some embodiments, the solvent comprises a polyol ether. The term "polyol ether" refers to an organic molecule consisting of C, H, and O atoms connected one to another by C-H, C-C, C-O, O-H single bonds, and which is at least theoretically derivable by at least partial etherification of a polyol. In some embodiments, the polyol ether has at least one C-O-H group and at least one C-O-C linkage. Useful polyol ethers (e.g., glycol ethers) may have from 3 to 25 carbon atoms, 3 to 20, 3 to 15, 3 to 10, 3 to 9, 3 to 8, or even from 5 to 8 carbon atoms. In some embodiments, the polyol is at least one of ethylene glycol, propylene glycol, ρoly(propylene glycol), 1,3 -propanediol, or 1 ,8-octanediol, and the polyol ether is at least one of 2-butoxyethanol, diethyl ene glycol monomethyl ether, ethylene glycol monobutyl ether, dipropylene glycol monomethyl ether, or l-methoxy-2-propanol. In some embodiments, the polyol and/or polyol ether has a normal boiling point of less than 450 ⁰F (232 ⁰C), which may be useful, for example, to facilitate removal of the polyol and/or polyol ether from a well after treatment. In these embodiments, in the event that a component of the solvent is a member of two functional classes, it may be used as either class but not both. For example, ethylene glycol methyl ether may be a polyol ether or a monohydroxy alcohol, but not as both simultaneously. In these embodiments, each solvent component may be present as a single component or a mixture of components. In some embodiments, for example, useful solvents for the methods and compositions disclosed herein comprise two different monohydroxy alcohol having up to 4 carbon atoms. Useful combinations of two solvents include 1,3 -propanediol (80%)/isopropanol (IPA) (20%), propylene glycol (70%)/IPA (30%), propylene glycol (90%)/IPA (10%), propylene glycol (80%)/IPA (20%), ethylene glycol (50%)/ethanol (50%), ethylene glycol (70%)/ethanol (30%), propylene glycol monobutyl ether (PGBE) (50%)/ethanol (50%), PGBE (70%)/ethanol (30%), dipropylene glycol monomethyl ether (DPGME) (50%)/ethanol (50%), DPGME (70%)/ethanol (30%), diethylene glycol monomethyl ether (DEGME) (70%)/ethanol (30%), triethylene glycol monomethyl ether (TEGME) (50%)/ethanol (50%), TEGME (70%)/ethanol (30%), 1,8-octanediol (50%)/ethanol (50%), propylene glycol (70%)/tetrahydrofuran (THF) (30%), propylene glycol (70%)/acetone (30%), propylene glycol (70%), methanol (30%), propylene glycol (60%)/IPA (40%), 2-bυtoxyethanol (80%)/ethanol (20%), 2-butoxyethanol (70%)/ethanol (30%), 2-butoxyethanol (60%)/ethanol (40%), propylene glycol (70%)/ethanol (30%), ethylene glycol (70%)/IPA (30%), and glycerol (70%)/IPA (30%), wherein the exemplary percentages are by weight are based on the total weight of solvent.

Typically, the solvents disclosed herein are capable of solubilizing more brine (i.e., no salt precipitation occurs) in the presence of a fluorinated polyurethane than methanol, ethanol, propanol, butanol, or acetone alone. In some embodiments of the methods disclosed herein, the solvent comprises up to 50, 40, 30, 20, or 10 percent by weight of a monohydroxy alcohol having up to 4 carbon atoms, based on the total weight of the treatment composition. In some embodiments, the solvent comprises water in a range from 5 to 40 percent by weight, based on the total weight of the treatment composition.

The amount of solvent typically varies inversely with the amount of other components in compositions according to and/or useful in practicing the present disclosure. For example, based on the total weight of the composition the solvent may be present in the composition in an amount of from at least 50, 60, or 75 percent by weight or more up to 60, 70, 80, 90, 95, 98, or 99 percent by weight, or more.

The ingredients for treatment compositions described herein including fluorinated polyurethanes, solvents, and optionally water can be combined using techniques known in the art for combining these types of materials, including using conventional magnetic stir bars or mechanical mixer (e.g., in-line static mixer and recirculating pump).

In some embodiments, the methods disclosed herein are useful for hydrocarbon-bearing formations having brine. The brine present in the hydrocarbon-bearing formation may be from a variety of sources including at least one of connate water, flowing water, mobile water, immobile water, residual water from a fracturing operation or from other downhole fluids, or crossflow water (e.g., water from adjacent perforated formations or adjacent layers in the formations). The brine may cause water blocking in the hydrocarbon-bearing formation. Salts that may be present in the brine include sodium chloride, calcium chloride, strontium chloride, magnesium chloride, potassium chloride, ferric chloride, ferrous chloride, and hydrates thereof. In some embodiments of the methods disclosed herein, the amount of the brine composition in the mixture is in a range from 5 to 95 percent by weight (e.g., at least 10, 20, 30, percent by weight and up to 35, 40, 45, 50, 55, 60, or 70 percent by weight) based on the total weight of the mixture. Methods disclosed herein may also be advantageous because at a given temperature lower amounts of treatment compositions disclosed herein will typically be required to treat a hydrocarbon-bearing formation than compositions having lower brine solubility (i.e., compositions that can dissolve a relatively lower amount of brine) but containing the same fluorinated polyurethane at the same concentration.

For the methods disclosed herein, a mixture of an amount of brine and the treatment composition is substantially free of precipitated solid (e.g., salts, asphaltenes, or fluorinated polyurethanes). As used herein, the term "substantially free of precipitated solid" refers to an amount of precipitated solid that does not interfere with the ability of the fluorinated polymer to increase the gas permeability of the hydrocarbon-bearing formation. In some embodiments, "substantially free of precipitated solid" means that no precipitated solid is visually observed. In some embodiments, "substantially free of precipitated solid" is an amount of solid that is less than 5% by weight higher than the solubility product of the solid at a given temperature and pressure. Methods according to the present disclosure include receiving (e.g., obtaining or measuring) data comprising the temperature and the brine composition (including the brine saturation level and components of the brine) of a selected hydrocarbon-bearing formation. These data can be obtained or measured using techniques well known to one of skill in the art. Phase behavior of a mixture of the brine composition and the treatment composition can be evaluated prior to treating the hydrocarbon-bearing formation by obtaining a sample of the brine from the hydrocarbon-bearing formation and/or analyzing the composition of the brine from the hydrocarbon-bearing formation and preparing an equivalent brine having the same or similar composition to the composition of the brine in the formation. The brine composition and the treatment composition can be combined (e.g., in a container) at the temperature and then mixed together (e.g., by shaking or stirring). The mixture is then maintained at the temperature for a certain time period (e.g., 15 minutes), removed from the heat, and immediately visually evaluated to see if phase separation or if cloudiness or precipitation occurs. The phase behavior of the composition and the brine can be evaluated over an extended period of time (e.g., 1 hour, 12 hours, 24 hours, or longer) to determine if any phase separation, precipitation, or cloudiness is observed. By adjusting the relative amounts of brine (e.g., equivalent brine) and the treatment composition, it is possible to determine the maximum brine uptake capacity (above which precipitation occurs) of the treatment composition at a given temperature. Varying the temperature at which the above procedure is carried out typically results in a more complete understanding of the suitability of treatment compositions for a given well.

In addition to using a phase behavior evaluation, it is also contemplated that one may be able to obtain the compatibility information, in whole or in part, by computer simulation or by referring to previously determined, collected, and/or tabulated information (e.g., in a handbook, table, or a computer database). In some embodiments, the selecting a treatment composition comprises consulting a table of compatibility data between brines and treatment compositions at different temperatures.

Whether the mixture of the brine composition and the treatment composition is transparent, substantially free of precipitated solid, and does not separate into layers at the temperature of the hydrocarbon-bearing formation can depend on many variables (e.g., concentration of the fiuorinated polyurethane, solvent composition, brine concentration and composition, hydrocarbon concentration and composition, and the presence of other components (e.g., surfactants or scale inhibitors)). In some embodiments, the treatment composition further comprises a scale inhibitor. Useful scale inhibitors include polyacrylic acid, ethylenediaminetetraacetic acid, hydrochloric acid, formic acid, citric acid, acetic acid, phosphonates, phosphonic acids (e.g., 2-phosphono-l,2,4-butanetricaboxylic acid, amino(trimethylene) phosphonic acid), diphosphonic acid, and phosphate esters. In some embodiments, the scale inhibitor is polyacrylic acid.

In some embodiments of the treatment methods disclosed herein, the hydrocarbon-bearing formation has both liquid hydrocarbons and gas, and the hydrocarbon-bearing formation has at least a gas permeability that is increased after the hydrocarbon-bearing formation is treated with the treatment composition. In some embodiments, the gas permeability after treating the hydrocarbon-bearing formation with the composition is increased by at least 5 percent (in some embodiments, by at least 10, 15, 20, 30, 40, 50, 60, 70, 80, 90, or 100 percent or more) relative to the gas permeability of the formation before treating the formation with the composition. In some embodiments, the gas permeability is a gas relative permeability. In some embodiments, the liquid (e.g., oil or condensate) permeability m the hydrocarbon-bearing formation is also increased (in some embodiments, by at least 5, 10, 15, 20, 30, 40, 50, 60, 70, 80, 90, or 100 percent or more) after treating the formation with the treatment composition. In some embodiments, the increase in gas permeability degrades at a slower rate than a comparative increase in gas permeability obtained when an equivalent hydrocarbon-bearing formation is treated with a nonionic fluorinated polymeric surfactant free of silane groups. The term "equivalent hydrocarbon-bearing formation" refers to a hydrocarbon-bearing formation that is similar to or the same (e.g., in chemical make-up, surface chemistry, brine composition, and hydrocarbon composition) as a hydrocarbon-bearing formation disclosed herein before it is treated with a method according to the present disclosure. In some embodiments, both the hydrocarbon-bearing formation and the equivalent hydrocarbon-bearing formation are siliciclastic formations, in some embodiments, greater than 50 percent sandstone. In some embodiments, the hydrocarbon-bearing formation and the equivalent hydrocarbon-bearing formation may have the same or similar pore volume and porosity (e.g., within 15 percent, 10 percent, 8 percent, 6 percent, or even within 5 percent). An increase in gas permeability (e.g., gas relative permeability) can be measured in a laboratory environment using the techniques shown in the Examples, below. For example, in a core flood an initial increase in gas permeability (e.g., gas relative permeability) after a treatment composition is applied can be measured after a steady state is reached following the injection of a gas/liquid hydrocarbon blend. The flow can be stopped, and the hydrocarbon blend can be re-injected to determine if there is any degradation of the initial increase. In some embodiments, the degradation is up to 1, 2, 3, 4, or 5 percent. For the equivalent hydrocarbon-bearing formation treated with a nonionic fluorinated polymeric surfactant free of silane groups, the degradation may be greater than 5 or at least 5, 6, 7, 8, 9, or 10 percent when a second injection of the hydrocarbon blend is made. See, e.g., Example 1 of PCT Pat. App. Pub. No. WO 2009/137285 (Baran et al.), the disclosure of which Example is incorporated herein by reference.

The hydrocarbon-bearing formation may have both gas and liquid hydrocarbons and may have gas condensate, black oil, or volatile oil. The hydrocarbons may comprise, for example, at least one of methane, ethane, propane, butane, pentane, hexane, heptane, octane, nonane, decane, or higher hydrocarbons. The term "black oil" refers to the class of crude oil typically having gas-oil ratios (GOR) less than about 2000 scf/stb (356 m³/m³). For example, a black oil may have a GOR in a range from about 100 (18), 200 (36), 300 (53), 400 (71), or even 500 scf/stb (89 nvVm³) up to about 1800 (320), 1900 (338), or 2000 scf/stb (356 m³/m³). The term "volatile oil" refers to the class of crude oil typically having a GOR in a range between about 2000 and 3300 scf/stb (356 and 588 m³/m³). For example, a volatile oil may have a GOR in a range from about 2000 (356), 2100 (374), or 2200 scf/stb (392 m³/m³) up to about 3100 (552), 3200 (570), or 3300 scf/stb (588 m³/m³). In some embodiments, the at least one of solvent or water (in the composition) at least partially solubttizes or at least partially displaces the liquid hydrocarbons in the hydrocarbon-bearing formation.

Generally, for the treatment methods disclosed herein, the amounts of the fluorinated polyurethane and solvent (and type of solvent) is dependent on the particular application since conditions typically vary between wells, at different depths of individual wells, and even over time at a given location in an individual well. Advantageously, treatment methods according to the present disclosure can be customized for individual wells and conditions. The hydrocarbon-bearing formations that may be treated according to the present disclosure may be siliciclastic (e.g., shale, conglomerate, diatomite, sand, and sandstone) or carbonate (e.g., limestone or dolomite) formations. In some embodiments, the hydrocarbon-bearing formation is predominantly sandstone (i.e., at least 50 percent by weight sandstone). In some embodiments, the hydrocarbon-bearing formation is predominantly limestone (i.e., at least 50 percent by weight limestone). The methods disclosed herein are unexpectedly effective at treating both sandstone and limestone hydrocarbon-bearing formations. In previous work, nonionic polymeric fluorinated surfactants have been shown to have limited effectiveness on limestone; (see, e.g., Comparative Example A in U. S. Pat. App. Pub. No. WO 2009/148831 (Sharma et al.), the disclosure of which example is incorporated herein by reference).

Methods according to the present disclosure may be practiced, for example, in a laboratory environment (e.g., on a core sample (i.e., a portion) of a hydrocarbon-bearing formation or in the field (e.g., on a subterranean hydrocarbon-bearing formation situated downhole). Typically, the methods disclosed herein are applicable to downhole conditions having a pressure in a range from about 1 bar (100 kPa) to about 1000 bars (100 MPa) and have a temperature in a range from about 100 ⁰F (37.8 ⁰C) to 400 ⁰F (204 ⁰C) although the methods are not limited to hydrocarbon-bearing formations having these conditions. In some embodiments, the hydrocarbon-bearing formation that is treated has a temperature of at least 175 ⁰F (79 ⁰C), 200 ⁰F (93 ⁰C), 225 ⁰F (107 ⁰C), 250 ⁰F (121 ⁰C) or 275 ⁰F (135 ⁰C). In some embodiments, the hydrocarbon-bearing formation that is treated has a temperature of up to 175 ⁰F (79 ⁰C) or 200 ⁰F (93 ⁰C). Those skilled in the art, after reviewing the instant disclosure, will recognize that various factors may be taken into account in practice of the any of the disclosed methods including the ionic strength of the brine, pH (e.g., a range from a pH of about 4 to about 10), and the radial stress at the wellbore (e.g., about 1 bar (100 kPa) to about 1000 bars (100 MPa)). In the field, treating a hydrocarbon-bearing formation with a composition described herein can be carried out using methods (e.g., by pumping under pressure) well known to those skilled in the oil and gas art. Coil tubing, for example, may be used to deliver the treatment composition to a particular geological zone of a hydrocarbon-bearing formation. In some embodiments of practicing the methods described herein it may be desirable to isolate a geological zone (e.g., with conventional packers) to be treated with the composition.

Methods described herein are useful, for example on both existing and new wells. In some embodiments, it may be desirable to allow for a shut-in time after treatment compositions described herein contact hydrocarbon-bearing formations. Exemplary shut-in times include a few hours (e.g., 1 to 12 hours), about 24 hours, or even a few (e.g., 2 to 10) days. After the treatment composition has been allowed to remain in place for a selected time, the solvents present in the composition may be recovered from the formation by simply pumping fluids up tubing in a well as is commonly done to produce fluids from a formation. In some embodiments of treatment methods according to the present disclosure, the method comprises treating the hydrocarbon-bearing formation with a fluid prior to treating the hydrocarbon-bearing formation with the composition. In some embodiments, the fluid at least one of at least partially solubilizes or at least partially displaces the brine in the hydrocarbon- bearing formation, hi some embodiments, the fluid at least partially solubilizes the brine. In some embodiments, the fluid at least partially displaces the brine. In some embodiments, the fluid at least one of at least partially solubilizes or displaces liquid hydrocarbons in the hydrocarbon-bearing formation. In some embodiments, the fluid is substantially free of fluorinated polymers. The term "substantially free of fluorinated polymers" refers to fluid that may have a fluorinated polymer in an amount insufficient for the fluid to have a cloud point (e.g., when it is below its critical micelle concentration). A fluid that is substantially free of fluorinated polymers may be a fluid that has a fluorinated polymer but in an amount insufficient to alter the wettability of, for example, a hydrocarbon-bearing formation under downhole conditions. A fluid that is substantially free of fluorinated polymers includes those that have a weight percent of such polymers as low as 0 weight percent. The fluid may be useful for decreasing the concentration of at least one of the salts present in the brine prior to introducing the composition to the hydrocarbon-bearing formation. The change in brine composition may change the results of a phase behavior evaluation (e.g., the combination of a composition with a first brine prior to the fluid preflush may result in salt precipitation while the combination of the treatment composition with the brine after the fluid preflush may result in no salt precipitation and the formation of a transparent mixture that does not separate into layers.) In some embodiments of treatment methods disclosed herein, the fluid comprises at least one of toluene, diesel, heptane, octane, or condensate. In some embodiments, the fluid comprises at least one of water, methanol, ethanol, or isopropanol. In some embodiments, the fluid comprises any of the solvents or solvent combinations mentioned above. In some embodiments, the fluid comprises at least one of nitrogen, carbon dioxide, or methane. In some embodiments, the fluid comprises a scale inhibitor (e.g., any of the scale inhibitors described above). In some embodiments of the methods disclosed herein, the hydrocarbon-bearing formation has at least one fracture. In some embodiments, fractured formations have at least 2, 3, 4, 5, 6, 7, 8, 9, or 10 or more fractures, to the field, for example, manmade fractures are typically made by injecting a fracturing fluid into a subterranean geological formation at a rate and pressure sufficient to open a fracture therein (i.e., exceeding the rock strength), to some embodiments, the fracture is a natural fracture (e.g., in a limestone or carbonate formation). Natural fractures may be formed, for example, as part of a network of fractures.

In some embodiments of the methods disclosed herein, wherein treating the formation with the treatment composition provides an increase in at least one of the gas permeability or the liquid permeability of the formation, the formation is free of man-made fractures having proppants therein. That is, in some embodiments, the method does not include intentionally fracturing the hydrocarbon-bearing formation. Advantageously, treatment methods disclosed herein typically provide an increase in at least one of the gas permeability or the hydrocarbon liquid permeability of the formation without fracturing the formation.

In some embodiments of the treatment methods and articles disclosed herein, wherein the hydrocarbon-bearing formation has at least one fracture, the fracture has a plurality of proppants therein. Prior to delivering the proppants into a fracture, the proppants may be treated with a fluorinated polyurethane or may be untreated (e.g., may comprise less than 0.1% by weight fluorinated polyurethane, based on the total weight of the plurality of proppants). In some embodiments, the fluorinated polyurethane in the treatment composition is adsorbed on at least a portion of the plurality of proppants.

Exemplary proppants known in the art include those made of sand (e.g., Ottawa, Brady or Colorado Sands, often referred to as white and brown sands having various ratios), resin-coated sand, sintered bauxite, ceramics (i.e., glasses, crystalline ceramics, glass-ceramics, and combinations thereof), thermoplastics, organic materials (e.g., ground or crushed nut shells, seed shells, fruit pits, and processed wood), and clay. Sand proppants are available, for example, from Badger Mining Corp., Berlin, WI; Borden Chemical, Columbus, OH; and Fairmont Minerals, Chardon, OH. Thermoplastic proppants are available, for example, from the Dow Chemical Company, Midland, MI; and BJ Services, Houston, TX. Clay-based proppants are available, for example, from CarboCeramics, Irving, TX; and Saint-Gobain, Courbevoie, France. Sintered bauxite ceramic proppants are available, for example, from Borovichi Refractories, Borovichi, Russia; 3M Company, St. Paul, MN; CarboCeramics; and Saint Gobain. Glass bubble and bead proppants are available, for example, from Diversified Industries, Sidney, British Columbia, Canada; and 3M Company.

Bauxite proppants have been reported in the art to be difficult to treat (e.g., in a hydrocarbon- bearing formation) with chemical treatments in order to improve the conductivity of a fracture; (see, e.g., Bang, V., "Development of a Successful Chemical Treatment for Gas Wells with Condensate or Water Blocking Damage" (Thesis), December 2007, pp. 267-268). The data in the examples, below, show that the methods disclosed herein are useful for treating bauxite proppants and for improving the conductivity of fractures containing bauxite proppants. In some embodiments of methods of treating fractured formations, the proppants form packs within a formation and/or wellbore. Proppants may be selected to be chemically compatible with the solvents and compositions described herein. The term "proppant" as used herein includes fracture proppant materials introducible into the formation as part of a hydraulic fracture treatment and sand control particulate introducible into the wellbore/formation as part of a sand control treatment such as a gravel pack or frac pack.

In some embodiments, methods according to the present disclosure include treating the hydrocarbon-bearing formation with the treatment composition at least one of during fracturing or after fracturing the hydrocarbon-bearing formation.

In some embodiments of methods of treating fractured formations, the amount of the treatment composition introduced into the fractured formation is based at least partially on the volume of the fracture(s). The volume of a fracture can be measured using methods that are known in the art (e.g., by pressure transient testing of a fractured well). Typically, when a fracture is created in a hydrocarbon-bearing subterranean formation, the volume of the fracture can be estimated using at least one of the known volume of fracturing fluid or the known amount of proppant used during the fracturing operation. Coil tubing, for example, may be used to deliver the treatment composition to a particular fracture. In some embodiments, in practicing the methods disclosed herein it may be desirable to isolate the fracture (e.g., with conventional packers) to be treated with the treatment composition.

In some embodiments, wherein the formation treated according to the methods described herein has at least one fracture, the fracture has a conductivity, and after the composition treats at least one of the fracture or at least a portion of the plurality of proppants, the conductivity of the fracture is increased (e.g., by 25, 50, 75, 100, 125, 150, 175, 200, 225, 250, 275, or by 300 percent).

Referring to Fig. 1 , an exemplary offshore oil platform is schematically illustrated and generally designated 10. Semi-submersible platform 12 is centered over submerged hydrocarbon-bearing formation 14 located below sea floor 16. Subsea conduit 18 extends from deck 20 of platform 12 to wellhead installation 22 including blowout preventers 24. Platform 12 is shown with hoisting apparatus 26 and derrick 28 for raising and lowering pipe strings such as work string 30. Wellbore 32 extends through the various earth strata including hydrocarbon-bearing formation 14. Casing 34 is cemented within wellbore 32 by cement 36. Work string 30 may include various tools including, for example, sand control screen assembly 38 which is positioned within wellbore 32 adjacent to hydrocarbon-bearing formation 14. Also extending from platform 12 through wellbore 32 is fluid delivery tube 40 having fluid or gas discharge section 42 positioned adjacent to hydrocarbon-bearing formation 14, shown with production zone 48 between packers 44, 46. When it is desired to treat the near-wellbore region (a region within about 25 (in some embodiments, 20, 15, or 10) feet of the wellbore) of hydrocarbon-bearing formation 14 adjacent to production zone 48, work string 30 and fluid delivery tube 40 are lowered through casing 34 until sand control screen assembly 38 and fluid discharge section 42 are positioned adjacent to the near-wellbore region of hydrocarbon-bearing formation 14 including perforations 50. Thereafter, a composition described herein is pumped down delivery tube 40 to progressively treat the near-wellbore region of hydrocarbon-bearing formation 14.

While the drawing depicts an offshore operation, the skilled artisan will recognize that the methods for treating a production zone of a wellbore are equally well-suited for use in onshore operations. Also, while the drawing depicts a vertical well, the skilled artisan will also recognize that methods according to the present disclosure are equally well-suited for use in deviated wells, inclined wells or horizontal wells.

Advantages and embodiments of this disclosure are further illustrated by the following examples, but the particular materials and amounts thereof recited in these examples, as well as other conditions and details, should not be construed to unduly limit this disclosure. Unless otherwise noted, all parts, percentages, ratios, etc. in the examples and the rest of the specification are by weight. In the Tables, "nd" means not determined.

EXAMPLES

Preparation of Fluorinated Polyurethane A

To a 250 mL dry flask was added 102 g (mw 585, 0.0697 equiv. -NCO) of the isocyanurate of HDI (obtained from Bayer Corporation as DESMODUR N-3300); 12.2 g (mw 135, 0.020 equiv. -OH) dimethanolpropionic acid; 95 g (mw 357, 0.041mole)N- methylperfiuorobutanesulfonamidoethanol (prepared as described in Example 2A of U. S. Pat. No. 6,664,354 (Savu et al.)); and 260 g ethyl acetate. Dibutyltin dilaurate catalyst (0.5 g) was added. The reaction was carried out under agitation at 60 ⁰C for three hours. Aminopropyltriethoxysilane (8.5 g, 22\A, 0.0033 mole) was then added and the reaction was maintained at 60oC for one hour. DPM (68 g) was added and mixed for 30 minutes. A pre-mix of methyldiethanolamine in 990 g DI Water was charged at 60 ⁰C. The ethyl acetate was then stripped off under reduced pressure to give the final product, in which the % solid of fluorinated polyurethane was 15%.

Examples 1 to 2

Treatment Solution Preparation:

For Examples 1 and 2, each of Fluorinated Polyurethane 1 was diluted with a mixture of 90% by weight ethanol and 10% by weight water to make about 200 grams of treatment solution. The components were mixed together using a magnetic stirrer and a magnetic stir bar. For Example

1 the amount of Fluorinated Polyurethane 1 in the treatment solution was 2% by weight, and for

Example 2, the amount of Fluorinated Polyurethane in the treatment solution was 1% by weight.

Flow Setup and Procedure:

A schematic diagram of a flow apparatus 300 used to determine relative permeability of sea sand or particulate calcium carbonate is shown in Fig. 4. Flow apparatus 300 included positive displacement pump 302 (Model GammaM-W 2001 PP, obtained from Prolingent AG, Regensdorf, Germany) to inject n-heptane at constant rate. Nitrogen gas was injected at constant rate through a gas flow controller 320 (Model DK37/MSE, Krohne, Duisburg, Germany). Pressure indicators 313, obtained from Siemens under the trade designation "SITRANS P" 0-16 bar, were used to measure the pressure drop across a sea sand pack in vertical core holder 309 (20 cm by 12.5 cm²) (obtained from 3M Company, Antwerp, Belgium). A back-pressure regulator (Model No. BS(H)2; obtained from RHPS, The Netherlands) 304 was used to control the flowing pressure upstream and downstream of core holder 309. Core holder 309 was heated by circulating silicone oil, heated by a heating bath obtained from Lauda, Switzerland, Model

R22.

The core holder was filled with sea sand (obtained from from Aldrich, Bornem, Belgium, grade

60-70 mesh) and then heated to 75 ⁰C. The temperature of 75 ⁰C was maintained for each of the flows described below. A pressure of about 5 bar (5 x 10⁵ Pa) was applied, and the back pressure was regulated in such a way that the flow of nitrogen gas through the sea sand was about 500 to 1000 mL/minute. The initial gas permeability was calculated using Darcy's law.

Synthetic brine according to the natural composition of North Sea brine, was prepared by mixing

5.9% sodium chloride, 1.6% calcium chloride, 0.23% magnesium chloride, and 0.05% potassium chloride and distilled water up to 100% by weight. The brine was then introduced into the core holder at about 1 mL/minute using displacement pump 302.

Heptane was then introduced into the core holder at about 0.5 mL/minute using displacement pump 302. Nitrogen and n-heptane were co-injected into the core holder until steady state was reached.

The treatment solution was then injected into the core at a flow rate of 1 mL/minute for about one pore volume. The gas permeability after treatment was calculated from the steady state pressure drop, and improvement factor was calculated as the permeability after treatment/permeability before treatment.

Heptane was then injected for about four to six pore volumes. The gas permeability and improvement factor were again calculated.

For Examples 1 to 2, the liquid used for each injection, the initial pressure, the pressure change

(ΔP), the flow rate for each injection, the amount of liquid used for each injection, the flow rate of gas through the core (Q), the gas permeability (K), and the improvement factor (PI) are shown in Table I, below. The improvement factor is the ratio of the gas permeability after treatment to the gas permeability before treatment. Table 1

Example 3

Example 3 was carried out according to the method of Examples 2, with a 1% by weight solution of Fluorinated Polyurethane A, except that particulate calcium carbonate (obtained from Merck,

Darmstadt , Germany as granular marble, particle size in a range from 0.5 mm to 2 mm) was used instead of sea sand.

The liquid used for each injection, the initial pressure, the pressure change (ΔP), the flow rate for each injection, the amount of liquid used for each injection, the flow rate of gas through the core

(Q), the gas permeability (K), and the improvement factor (PI) are shown in Table 1, above.

Example 4

Example 4 was carried out according to the method of Examples 2, with a 1% by weight solution of Fluorinated Polyurethane A, except that a bauxite proppant obtained from CarboCeramics, Aberdeen, UK, under the trade designation "CARBO PROP 16/30" was used instead of sea sand. The liquid used for each injection, the initial pressure, the pressure change (ΔP), the flow rate for each injection, the amount of liquid used for each injection, the flow rate of gas through the core (Q), the gas permeability (K), and the improvement factor (PI) are shown in Table 1, above.

Example 5

Example 5 was carried out according to the method of Examples 2, with a 1% by weight solution of Fluorinated Polyurethane 1, except that a bauxite proppant obtained from CarboCeramics, Aberdeen, UK, under the trade designation "CARBO PROP 16/30" was used instead of sea sand. Also, no heptane flows were used. The liquid used for each injection, the initial pressure, the pressure change (ΔP), the flow rate for each injection, the amount of liquid used for each injection, the flow rate of gas through the core (Q), the gas permeability (K), and the improvement factor (PI) are shown in Table 1, above.

Comparative Example A

Comparative Example A was carried out using the method of Example 3 (i.e., using calcium carbonate) except with the treatment composition was 2% by weight of a Nonionic Fluorinated Polymer A (NFP-A) prepared as described below, 69% by weight 2-butoxyethanol, and 29% by weight ethanol. The results shown in Table 1, above, were obtained.

The Nonionic Fluorinated Polymer A was prepared essentially as in Examples 2A, 2B, and 4 of U. S. Pat. No. 6,664,354 (Savu et al.), incorporated herein by reference, except using 4270 kilograms (kg) of N-methylperfluorobutanesulfonamidoethanol, 1.6 kg of phenothiazine, 2.7 kg of methoxyhydroquinone, 1590 kg of heptane, 1030 kg of acrylic acid, 89 kg of methanesulfonic acid (instead of triflic acid), and 7590 kg of water in the procedure of Example 2B and using 15.6 grams of 50/50 mineral spirits/TRIGONOX-21-C50 organic peroxide initiator (tert-butyl peroxy-2-ethylhexanoate obtained from Akzo Nobel, Arnhem, The Netherlands) in place of 2,2'- azobisisobutyronitrile, and with 9.9 grams of l-methyl-2-pyrrolidinone added to the charges in the procedure of Example 4.

Core Flood Setup for Examples 6-8:

A schematic diagram of a core flood apparatus 100 used to determine relative permeability of a substrate sample (i.e., core) is shown in Figure 2. Core flood apparatus 100 included positive displacement pumps (Quizix Model 6000 QX; obtained from Chandler Engineering) 102 to inject fluid 103 at constant rate into fluid accumulators 116. Multiple pressure ports 112 on high-pressure core holder 108 (Hassler-type Model UTPT- Ix8-3K- 13 obtained from Phoenix, Houston TX) were used to measure pressure drop across four sections (2 inches (5.1 cm) in length each) of core 109. An additional pressure port 111 on core holder 108 was used to measure pressure drop across the entire length (8 inches (20.3 cm)) of core 109. Two backpressure regulators (Model No. BPR-50; obtained from Temco, Tulsa, OK) 104, 106 were used to control the flowing pressure upstream 106 and downstream 104 of core 109. The flow of fluid was through a vertical core to avoid gravity segregation of the gas. High- pressure core holder 108, back pressure regulators 104 and 106, fluid accumulators 116, and tubing were placed inside a pressure- and temperature-controlled oven 110 (Model DC 1406F; maximum temperature rating of 650 ⁰F (343 ⁰C) obtained from SPX Corporation, Williamsport, PA). The maximum flow rate of fluid was 7,000 mL/hr. An overburden pressure of 3400 psig

(2.3 x 10⁷ Pa) was applied.

Cores:

Core samples used for each Example were cut from a sandstone block obtained from Cleveland

Quarries, Vermillion, OH, under the trade designation "BEREA SANDSTONE". The porosity was determined from the measured mass of the dry core, the bulk volume of the core, and the grain density of quartz. The pore volume is the product of the bulk volume and the porosity.

The cores had 1-inch diameters (2.54 cm) and were 8 inches (20.3 cm) long.

Synthetic Fluids:

One synthetic gas-condensate fluid and one volatile oil fluid were prepared for the core flood evaluations. The components and their amounts in each of the synthetic fluids are shown in

Table 2, below.

Table 2

Example 6

A sandstone core was dried for 24 hours in a standard laboratory oven at 180 ⁰C and then wrapped in aluminum foil and heat shrink tubing (obtained under the trade designation 'TEFLON HEAT SHRINK TUBING" from Zeus, Inc., Orangeburg, SC). Referring again to Fig. 2, the wrapped core 109 was placed in core holder 108 inside oven 110 at 75 ⁰F (24 ⁰C). Initial permeability of the core was measured at flow rates of 1500 to 6000 cc/hr using nitrogen at 75 ⁰F (24 ⁰C) and was determined to be 129 md. The temperature of the oven was then raised to 175 ⁰F (79 ⁰C).

Brine (30,000 ppm sodium chloride) was introduced into the core 109 by the following procedure. The outlet end of the core holder was connected to a vacuum pump and a full vacuum was applied for 30 minutes with the inlet closed. The inlet was connected to a burette with the brine in it. The outlet was closed and the inlet was opened to allow 4.3 mL of brine to flow into the core, and the inlet value was closed to establish a brine saturation of 25%. The permeability was measured at the brine saturation of 25% by flowing nitrogen gas at 1000 psig (6.8 x 10⁶ Pa) and 75 ⁰F (20⁰C). The results are shown in Table 3, below. Following the measurement of the nitrogen gas permeability at the brine saturation of 25%, the pressure of the core was dropped to 500 psig (3.4 x 10⁶ Pa), and the temperature of the oven 110 was raised to 175 ⁰F (79 ⁰C). The wrapped core 109 in the oven 110 was maintained at 175 ⁰F (79 ⁰C) for 12 hours.

An initial two-phase flood was conducted using Synthetic Fluid 1, shown in Table 2 (above), with the upstream back-pressure regulator 106 set at 5100 psig (3.5 x 10⁷ Pa), above the dew point pressure of the fluid, and downstream back-pressure regulator 104 was set at about 500 psig (3.4 x 10⁶ Pa). Flow rates of 125 mL/hour and 250 mL/hour were used at a core pressure of 1200 psi (8.3 x 10⁶ Pa). After a steady state was established, the gas relative permeability before treatment was then calculated from the steady state pressure drop. The gas relative permeability (krg) calculated from the initial two-phase flood is shown in Table 3, below. A treatment composition was prepared by combining Fluorinated Polyurethane A and a mixture of 2-butoxyethanol (60%), ethanol (30%), and isopropanol (10%) to make 400 grams of a 2% by weight solution of the fluorinated polyurethane. The components were mixed together using a magnetic stirrer and magnetic stir bar. When the treatment composition was evaluated before injection by combining it with 25% by weight of the brine, the mixture was transparent and free of precipitate. No phase separation was observed.

The treatment composition was then injected into the core for 20 pore volumes at a rate of 100 mL/hour. The composition was then held in the core at 175 ⁰F (79 ⁰C) for about 15 hours. A post-treatment two-phase flood was then conducted using the same conditions as the initial two- phase flood. After a steady state was established (220 pore volumes), the gas relative permeability after treatment was then calculated from the steady state pressure drop. The improvement factor is the krg after treatment divided by the krg before treatment. The ratio of the gas relative permeability over the oil relative permeability was also determined (krg/kro). The results are shown in Table 3, below. Additional post-treatment two-phase floods were carried out, and an improvement factor of 1.93 was measured after 480 pore volumes. An improvement factor of 1.86 was measured after 690 pore volumes. The improvement factors were slightly lower at the higher flow rate of 250 mL/hour. Following the relative permeability measurements, methane gas was injected, using positive displacement pump 102, to displace Synthetic Fluid 1 and measure the final single-phase gas permeability.

Table 3

Example 7

Example 7 was carried out using the methods of Example 6 but with the following modifications. The treatment composition was made in the same way except a 1% by weight solution of the fluorinated polyurethane was prepared. An oven temperature of 155 ⁰F (68 ⁰C) was used, and Synthetic Fluid 2 was used. A brine saturation of 20% was used with 25000 ppm sodium chloride. The core pressure was adjusted to 800 psi (6.2 x 10⁶ Pa), 1500 psi (1.1 x 10⁷ Pa), 2200 psi (1.7 x 10⁷ Pa), 2900 psi (2.1 x 10⁷ Pa), under which conditions Synthetic Fluid 2 exhibited volatile oil behavior with varying liquid dropouts. A flow rate of 150 mL/hour was used. The krg value and initial improvement factor obtained after about 80 pore volumes at 800 psi (6.2 x 10⁶ Pa) are shown in Table 3, above. The improvement factor decreased with increasing number of pore volumes injected at a given pressure and with increasing liquid dropouts. After about 200 pore volumes at 1500 psi (6.2 x 10⁶ Pa), the measured krg and improvement factor were 0.076 and 1.32, respectively. No improvement was observed at krg/kro of less than about 0.5.

Example 8

Fractured Core Preparation. A 1 inch (2.5 cm) diameter Berea core plug was sawed in half longitudinally and then put in a standard laboratory oven to dry overnight at 150⁰C. One half of the rock was rested on the lab bench and two long spacers were laid on top of it with the ends protruding beyond one end of the core and flush with the other. The other half was placed on top. The core was then wrapped with polytetrafluoroethylene (PTFE) tape. The resulting fracture space was the width of the spacers (0.22 cm). The void was then filled with bauxite proppant (obtained from Sintex Minerals and Services, Inc., Houston, TX, under the trade designation "SINTEX 30/50") having an average mesh size of about 35 corresponding to an average grain diameter of on the order of 0.04 cm. The core was lightly tapped to distribute the proppant throughout the fracture space and then the spacers were slowly pulled out as the sand filled the void. The fractured rock was wrapped with aluminum foil and shrink wrapped with heat shrink tubing (obtained under the trade designation "TEFLON HEAT SHRINK TUBING" from Zeus, Inc.) and then loaded into core holder 108 with a 1 inch (2.5 cm) sleeve. Core Flooding Procedure. The core flooding procedure was carried out using the method of Example 6. High flow rates ranging from 1580 to 5150 mL/hour were used. In general, the krg decreased with increasing gas velocity. Therefore a plot of the pressure drop/velocity vs. velocity was made, and the krg was calculated from the intercept to correct for non-Darcy flow effects using the Forscheimer equation. The results are shown in Table 4, below.

Table 4

Example 9

A core sample was cut from a Texas Cream limestone block obtained from Texas Quarries, Round Rock, TX having approximately a 7 millidarcy (mD) dry permeability. A treatment composition was prepared by diluting Fluorinated Polyurethane A to provide a solution containing 0.5% Fluorinated Polyurethane 1, 29% isopropanol, 53% methyl ethyl ketone, 14.5% methyl isobutyl ketone, and 3% deionized water. A brine of 30,000 ppm potassium chloride was used. When the treatment composition was combined with the brine to evaluate compatibility before the core flood, two transparent layers free of precipitate were formed.

A schematic diagram of a core flood apparatus 400 used to determine relative permeability of the limestone core is shown in Fig. 5. Core flood apparatus 400 included positive displacement pump 402 (Model D-100; obtained from ISCO, Lincoln, NE) to inject fluid at constant flow rates into fluid accumulator 416 (CFR series, obtained from Temco, Inc., Tulsa, OK). The pressure in the accumulator 416 was controlled and maintained by upstream back-pressure regulator 406 (Model No. BPR-100 obtained from Temco, Inc.). Pressure ports 412 on high-pressure core holder 408 (Hassler-type Model RCHR- 1.0 obtained from Tempo, Inc.) was used to measure pressure drop across the vertical core 109 by a differential pressure regulator 411 (Model 305 IS obtained from Rosemount, Chanhassen, MN). The core pressure was regulated by a downstream back pressure regulator 404 (Model BPR-100 obtained from Tempo, Inc.). The pressures of back pressure regulators 404, 406 were measured at pressure ports P404, P406. The accumulator 416, the backpressure regulators 406, 404, and the core holder 408 were all installed in an oven 410 (Model RFD2-19-2E obtained from Despatch, Lakeville, MN).

The core was dried for 72 hours in a standard laboratory oven at 95 oC and then wrapped in aluminum foil and heat shrink tubing. The wrapped core was then inserted into a fluorinated elastomer core sleeve and mounted onto the core holder. An overburden pressure of 1000 psi (6.8 x 10⁶ Pa) over the core pressure was applied in the core holder 408.

Fluid (e.g., nitrogen, gas condensate, or treatment solution) was delivered from accumulator 416 into the core 409. The absolute permeability of the core was measured with nitrogen at room temperature using at least four different flow rates to take the average. The result is shown in Table 5, below. After the absolute permeability measurement, the brine (30,000 ppm KCl) was introduced to the core by the following procedure to establish a saturation of 50% (i.e., 50% of the pore volume of the core was saturated with the brine). The outlet end of the core holder 408 was connected to a vacuum pump and a full vacuum was applied for 30 minutes with the inlet closed. The inlet was connected to a burette with the brine in it. The outlet was closed and the inlet was opened to allow the appropriate volume of brine to flow into the core. The inlet and outlet valves were then closed, and the brine was allowed to distribute in the core overnight. A synthetic gas condensate made from 89 mole% methane, 5 mole% butane, 2.5 mole% n- heptane, 2.5 mole% n-decane, and 1% pentadecane was prepared by weighing each component into accumulator 116. The gas condensate was then placed into the oven 110 on a pneumatically controlled rocker allowing it to reach equilibrium overnight at 150 ⁰F (65.5 ⁰C). The synthetic gas condensate was then injected into the core at a constant pump rate of 3.0 mL/minute. Upstream back-pressure regulator 406 was set at about 500 psi (3.4 x 10⁶ Pa) above the dew point pressure of the fluid, and downstream back-pressure regulator 404 was set at about 1500 psi (3.38 x 10⁷ Pa). The injection was continued until a steady state was reached. The gas relative permeability before treatment was then calculated from the steady state pressure drop. The treatment composition was then injected into the core. After about 6 pore volumes were injected, the treatment composition was held in the core at 150 ⁰F (65.5 ⁰C) for about 30 minutes. The synthetic gas condensate fluid described above was then introduced again at the same rate using positive displacement pump 402 until a steady state was reached. The gas relative permeability after treatment was then calculated from the steady state pressure drop. The the inital permeability of the core (Kabs), the pressure change pre and post-treatment (Δp), the gas relative permeability pre and post-treatment (Krg), the oil relative permeability pre and post-treatment (Kro), the capillary number pre and post-treatment (Nc) and the improvement factor (PI), are shown in Table 5, below.

Comparative Example B

A treatment composition was prepared by diluting the Fluorinated Polyurethane A to 2% by weight with a 50/50 mixture of isopropanol/water. 2% by weight of KCl was added to the composition and stirred. There was much precipitation upon mixing. The liquid had a turbid to hazy appearance. The supernatant was used as the treatment composition. Characteristics of the sandstone core (obtained from Cleveland Quarries under the trade designation "BEREA SANDSTONE") are shown in Table 6, below.

Table 6

A schematic diagram of a core flood apparatus 200 used to determine relative permeability of the substrate sample (i.e., core) is shown in Fig. 3. Core flood apparatus 200 included positive displacement pump 202 (Model QX6000SS, obtained from Chandler Engineering, Tulsa, OK) to inject n-heptane at constant rate into fluid accumulators 216. Nitrogen gas was injected at constant rate through a gas flow controller 220 (Model 5850 Mass Flow Controller, Brokks Instrument, Hatfield, PA). A pressure port 211 on high-pressure core holder 208 (Hassler-type Model RCHR-1.0 obtained from Temco, Inc., Tulsa, OK) were used to measure pressure drop across the vertical core 209. A back-pressure regulator (Model No. BP-50; obtained from Temco, Tulsa, OK) 204 was used to control the flowing pressure downstream of core 209. High- pressure core holder 208 was heated with 3 heating bands 222 (Watlow Thinband Model STB4A2AFR-2, St. Louis, MO).

The core was dried for 72 hours in a standard laboratory oven at 95 ⁰C and then wrapped in aluminum foil and heat shrink tubing (obtained under the trade designation "TEFLON HEAT SHRINK TUBING" from Zeus, Inc., Orangeburg, SC). Referring again to Fig. 3, the wrapped core 209 was placed in core holder 208 at 75 ⁰F (24 ⁰C), An overburden pressure of 2300 psig (1.6 x 10⁷ Pa) was applied. The initial single-phase gas permeability was measured using nitrogen at low system pressures between 5 to 10 psig (3.4 x 10⁴ to 6.9 x 10⁴ Pa). Brine (30,000 ppm potassium chloride) was introduced into the core 209 to establish a brine saturation of 50% using the procedure described in Example 6. The gas permeability was measured at the brine saturation by flowing nitrogen at 500 psig (3.4 x 10⁶ Pa) and 75 ⁰F (24⁰C). The core holder 208 was then heated to 250 ⁰F (121 ⁰C) for several hours. Nitrogen and n- heptane were co-injected into the core at an average total flow rate in the core of 450 mL/hour at a system pressure of 900 psig (6.2 x 10⁶ Pa) until steady state was reached. The flow rate of nitrogen was controlled by gas flow controller 220, and the rate for n-heptane was controlled by positive displacement pump 202. The flow rates of nitrogen and n-heptane were set such that the fractional flow of gas in the core was 0.75. The gas relative permeability before treatment was then calculated from the steady state pressure drop. The treatment composition was then injected into the core at a flow rate of 2 mL/min for 50 pore volumes and held in the core for 15 hours. Nitrogen and n-heptane co-injection was resumed at an average total flow rate in the core of 450 mL/hour at a system pressure of 900 psig (6.2 x 10⁶ Pa) until steady state was reached. The gas relative permeability after treatment was then calculated from the steady state pressure drop. No improvement was observed. The improvement factor (PI) was 0.58. The core was partially blocked by the treatment solution.

Various modifications and alterations of this disclosure may be made by those skilled the art without departing from the scope and spirit of the disclosure, and it should be understood that this disclosure is not to be unduly limited to the illustrative embodiments set forth herein.

Claims

What is claimed is:

1. A method of treating a hydrocarbon-bearing formation, the method comprising: receiving data comprising a temperature and a brine composition of the hydrocarbon- bearing formation; selecting a treatment composition for the hydrocarbon-bearing formation comprising a fiuorinated polyurethane and solvent, wherein, at the temperature, a mixture of an amount of the brine composition and the treatment composition is transparent and free of precipitated solid, and wherein the mixture does not separate into layers; and contacting the hydrocarbon-bearing formation with the treatment composition, wherein the fiuorinated polyurethane has at least two repeat units and comprises: at least one end group represented by the formula -A¹ -Z-RF, and at least one end group represented by the formula -A'-W-SiG₃; wherein each RF independently represents a fluoroalkyl group optionally containing at least one -O- or a polyfluoropolyether having at least 10 carbon atoms and at least three - O- groups; each Z is independently selected from the group consisting of alkylene, alkylarylene, and arylalkylene, each of which is optionally interrupted or terminated with at least one of -0-, -C(O)-, -S(O)_0-2-, -N(R)-, -SO₂N(R)-, -C(O)N(R)-, -C(O)-O-, -O-C(O)-, -OC(O)-N(R)-, -N(R)-C(O)-O-, or -N(R)-C(O)-N(R)-, wherein each R is independently hydrogen or alkyl having up to four carbon atoms; each A¹ is independently selected from the group consisting of -NH-C(O)-N(R¹¹)-, -NH-C(O)-S-, -NH-C(O)-O-, -N(R^π)-C(O)-NH-, and -0-C(O)-NH-, wherein R¹¹ is hydrogen or alkyl having up to four carbon atoms; each W is independently selected from the group consisting of alkylene, arylalkylene, and arylene, wherein alkylene is optionally interrupted with at least one -O-; and each G is independently hydroxyl, alkoxy, acyloxy, aryloxy, halogen, alkyl, or phenyl, with the proviso that at least one G is hydroxyl, alkoxy, acyloxy, aryloxy, or halogen.

2. A method of treating a hydrocarbon-bearing formation, the method comprising: contacting the hydrocarbon-bearing formation with a treatment composition comprising solvent and a fluorinated polyurethane, wherein the fluorinated polyurethane has at least two repeat units and comprises: at least one end group represented by the formula -A '-Z-RF, and at least one end group represented by the formula -A¹ -W-SiG₃; wherein each RF independently represents a fluoroalkyl group optionally containing at least one -O- or a polyfluoropolyether having at least 10 carbon atoms and at least three - O- groups; each Z is independently selected from the group consisting of alkylene, alkylarylene, and arylalkylene, each of which is optionally interrupted or terminated with at least one of -0-, -C(O)-, -S(O)_0-2-, -N(R)-, -SO₂N(R)-, -C(O)N(R)-, -C(O)-O-, -O-C(O)-, -OC(O)-N(R)-, -N(R)-C(O)-O-, or -N(R)-C(O)-N(R)- , wherein each R is independently hydrogen or alkyl having up to four carbon atoms; each A¹ is independently selected from the group consisting of -NH-C(O)-N(R¹¹)-, -NH-C(O)-S-, -NH-C(O)-O-, -N(Rⁿ)-C(0)-NH-, and -0-C(O)-NH-, wherein R¹¹ is hydrogen or alkyl having up to four carbon atoms; each W is independently selected from the group consisting of alkylene, arylalkylene, and arylene, wherein alkylene is optionally interrupted with at least one -O- ; and each G is independently hydroxyl, alkoxy, acyloxy, aryloxy, halogen, alkyl, or phenyl, with the proviso that at least one G is hydroxyl, alkoxy, acyloxy, aryloxy, or halogen; and wherein the hydrocarbon-bearing formation comprises limestone.

3. The method according to claim 1 or 2, wherein the fluorinated polyurethane is represented by formula:

or

wherein

R¹⁰ is alkylene, arylene, or arylalkylene, each of which is optionally interrupted by at least one biruet, allophanate, uretdione, or isocyanurate linkage;

X¹ is alkylene, polyalkyleneoxy, fluoroalkylene, or polyfluoroalkyleneoxy, wherein alkylene is optionally interrupted by -O- and is optionally substituted with -Si(G)₃, or -M; each a¹ is 0, 1, or 2; e is a value in a range from 1 to 20; each E is independently an end group represented by formula RF-Z-A-C(O)-N(H)-; (G)₃Si-W-A-C(O)-N(H)-, or (M)_1-2-W-A-C(O)-N(H)-; each A is independently -O-, -N(R¹¹)-, -S-, or -C(O)O-, wherein R¹¹ is hydrogen or alkyl having up to four carbon atoms; each M is independently selected from the group consisting of an ammonium group, a carboxylate, a sulfonate, a sulfate, a phosphate, or a phosphonate; each RF independently represents a fluoroalkyl group optionally containing at least one - O-; each Z is independently selected from the group consisting of alkylene, alkylarylene, and arylalkylene, each of which is optionally interrupted or terminated with at least one of -O-, - C(O)-, -S(O)_0-2-, -N(R)-, -SO₂N(R)-, -C(O)N(R)-, -C(O)-O-,

-O-C(O)-, -OC(O)-N(R)-, -N(R)-C(O)-O-, or -N(R)-C(O)-N(R)-, wherein each R is independently hydrogen or alkyl having up to four carbon atoms; each W is independently selected from the group consisting of alkylene, arylalkylene, and arylene, wherein alkylene is optionally interrupted with at least one -0-; and each G is independently hydroxyl, alkoxy, acyloxy, aryloxy, halogen, alkyl, or phenyl, with the proviso that at least one G is hydroxyl, alkoxy, acyloxy, aryloxy, or halogen.

4. The method according to any claim 3, wherein at least one E group is represented by formula (M) _I-2-W-A-C(O)-N(H)- or wherein X' is substituted with at least one M.

5. The method according to any preceding claim, wherein the end group represented by formula -A'-Z-RF is -NH-C(O)-O-(CjH₂J)N(IT)S(O)₂-Rf², and wherein the end group represented by formula -A^]-W-SiG₃ is -NH-(C_kH_2k)-SiG'₃, wherein Rf² is perfluoroalkyl having from 2 to 6 carbon atoms, R" is hydrogen or alkyl having up to 4 carbon atoms, each G¹ is independently alkoxy or hydroxyl, and j and k are each independently 1 to 6.

6. The method according to any preceding claim, wherein the solvent comprises at least one of water, a monohydroxy alcohol having up to 4 carbon atoms, ethylene glycol, propylene glycol, acetone, a glycol ether, supercritical carbon dioxide or liquid carbon dioxide.

7. The method according to any preceding claim, further comprising providing an increase in gas permeability of the hydrocarbon-bearing formation after contacting the hydrocarbon- bearing formation with the treatment composition.

8. The method according to claim 7, wherein the increase in gas permeability degrades at a slower rate than a comparative increase in gas permeability obtained when an equivalent hydrocarbon-bearing formation is treated with a nonionic fluorinated polymeric surfactant free of silane groups.

9. The method according to claim 7 or 8, wherein the increase in gas permeability comprises an increase in gas relative permeability.

10. The method according to any preceding claim, wherein the hydrocarbon-bearing formation is a retrograde condensate gas well, a volatile oil well, or a black oil well.

11. The method according to claim 1 or any one of claims 3 to 10 as dependent on claim 1, wherein the brine composition comprises at least 150,000 milligrams per liter of total dissolved salts.

12. The method according to any preceding claim, wherein the hydrocarbon-bearing formation has at least one fracture, and wherein the fracture has a plurality of proppants therein.

13. The method according to any one of claims 1 to 11, wherein the hydrocarbon-bearing formation is free of manmade fractures having proppants therein.

14. A hydrocarbon-bearing formation treated according to the method of any preceding claim.

15. A composition comprising : a fmorinated polyurethane having at least two repeat units, the fluorinated polyurethane comprising: at least one end group represented by the formula -NH-C(O)-O-(C_jH₂J)N(R¹OS(O)₂-Rf², and at least one end group represented by the formula -NH-(CkH₂k)-SiG'3, wherein

Rf² is perfluoroalkyl having from 2 to 6 carbon atoms;

R" is hydrogen or alkyl having up to four carbon atoms; each G¹ is independently alkoxy or hydroxyl; and j and k are each independently 1 to 6; and solvent comprising: water; a monohydroxy alcohol having up to 4 carbon atoms; and a polyol or polyol ether, each having from 2 to 25 carbon atoms.

16. The composition according to claim 15, wherein solvent further comprises a second, different monohydroxy alcohol having up to 4 carbon atoms.