WO2011005666A2

WO2011005666A2 - Methods for treating hydrocarbon-bearing formations with fluorinated acid compositions

Info

Publication number: WO2011005666A2
Application number: PCT/US2010/040861
Authority: WO
Inventors: Rudolf J. Dams; Steven J. Martin; Yong K. Wu
Original assignee: 3M Innovative Properties Company
Priority date: 2009-07-09
Filing date: 2010-07-02
Publication date: 2011-01-13
Also published as: WO2011005666A3

Abstract

Method of treating a carbonate hydrocarbon-bearing formation. The method includes contacting the hydrocarbon-bearing formation with a composition comprising solvent and a fluorinated acid. The fluorinated acid is present in the treatment composition at less than 1 weight percent, based on the total weight of the treatment composition.

Description

METHODS FOR TREATING HYDROCARBON-BEARING FORMATIONS WITH

FLUORINATED ACID COMPOSITIONS

CROSS-REFERENCE TO RELATED APPLICATION

This application claims the benefit of U. S. Provisional Application No.

61/224,218, filed July 9, 2009, the disclosure of which is incorporated by reference herein in its entirety.

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 wellbore (i.e., the near wellbore 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 wellbore 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 described herein may be useful in hydrocarbon-bearing formations having at least one of brine (e.g., connate brine and/or water blocking) or two phases of hydrocarbons present in the near wellbore region, (e.g., in gas wells having retrograde condensate and oil wells having black oil or volatile oil), resulting in an increase in permeability of at least one of gas, oil, or condensate. Treatment of an oil and/or gas well that has brine and/or two phases of hydrocarbons 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 acids disclosed herein generally at least one of adsorb to, chemisorb onto, or react with carbonate hydrocarbon-bearing formations under downhole conditions and modify the wetting properties of the rock in the formation to facilitate the removal of hydrocarbons and/or brine.

To optimize efficiency and minimize cost, it is typically desirable to use the lowest effective concentration of a fluorochemical for modifying the wetting properties of the rock in a hydrocarbon-bearing formation. The methods described herein, which use treatment compositions having up to 1 percent by weight of a fluorinated acid, have been found to be surprisingly effective.

In one 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 acid, wherein the fluorinated acid is present in the treatment composition at less than 1 weight percent, based on the total weight of the treatment composition, wherein the hydrocarbon-bearing formation comprises carbonate, and wherein the fluorinated acid is selected from the group consisting of:

(Rf-X-O)_x-P(O)-(OH)₃._x;

(Rf-X-O)-P(O)-(OH)(O-X"-OH);

Rf-X-SO₃H;

Rf-X-CO₂H;

Rf-X-P(O)(OH)₂;

R

[Rf-SO₂-N-CH₂J₂Q-Z; and

combinations thereof;

wherein

Rf is independently fluoroalkyl having up to 8 carbon atoms and optionally interrupted by up to 5 ether groups; X is independently:

a bond;

-SO₂-N(R)(C_yH_2y)-;

-C(O)-N(R)(C_yH_2y)-; or

alkylene that is optionally interrupted by -O- or -S-;

X" is alkylene that is optionally interrupted by -O- or -S- and optionally substituted by hydroxyl;

x is a value from 1 to 2;

R is an alkyl group having up to 4 carbon atoms;

y is a value from 1 to 11;

R is alkyl having up to 4 carbon atoms or aryl;

Q is -CHO-, -CHO(C₂H₂₂)-, -CHO(C₂H_2zO)_q(C₂H_2z)-, -CHS-, -CHS(C_zH_2z)-, -CHS(C_zH_2zO)_q(C_zH_2z)- or -CHOC(O)(C_zH_2z)-, wherein q is a value from 1 to 50, and each z is independently a value from 1 to 5; and

Z is -COOH, -SO₃H, -OSO₃H, or -P(O)(OH)₂.

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

Hydrocarbon-bearing formations that comprise carbonate include limestone or dolomite formations, wherein limestone and dolomite forms at least a portion (e.g., at least 50, 60, 75, or 90 percent by weight) of the formation. In some embodiments of the foregoing aspects, the hydrocarbon-bearing formation comprises limestone (e.g., at least 50, 60, 75, or 90 percent by weight limestone).

In some embodiments of the foregoing aspects, the fluorinated acid is represented by formula Rf-X-SO₃H or Rf-X-CO₂H, and wherein Rf is perfluoroalkyl having up to 6 (e.g., up to 5, 4, or 3) carbon atoms and optionally interrupted by up to 5 ether groups (i.e.,

1, 2, 3, 4, or 5). In some of these embodiments, the fluorinated acid is represented by formula Rf^SO₃H, wherein Rf¹ is perfluoroalkyl having up to 6 (e.g., up to 5, 4, or 3) carbon atoms. In other of these embodiments, the fluorinated acid is represented by formula Rf²-CO₂H, wherein Rf² is perfluoroalkyl having up to 8 (e.g., up to 6, 5, 4, or 3) perfluorinated carbon atoms and optionally interrupted by up to 5 ether groups. In some embodiments, Rf² is CF₃CF₂CF₂-O-[CF(CF₃)CF₂O]_k-CF(CF₃)-, wherein k is 1, 2, 3, or 4. In some embodiments, the fluorinated acid is represented by formula [Rf¹SO₂N(R^>)CH₂]₂CHO(C_zH_2z)COOH, wherein Rf¹ is perfluoroalkyl having up to 6 carbon atoms, R is alkyl having up to 4 carbon atoms; and z is from 1 to 3.

In some embodiments of the foregoing aspects, the solvent comprises at least one of water, a monohydroxy alcohol, an ether, a ketone, a glycol, a glycol ether, or supercritical carbon dioxide.

In some embodiments of the foregoing aspects, the fluorinated acid 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, 0.3, 0.4, or 0.5 percent by weight, up to 0.6, 0.7, 0.8, 0.9, or 0.95 percent by weight, based on the total weight of the treatment composition. For example, the amount of the fluorinated acid in the treatment composition may be in a range of from 0.01 to 0.95, 0.1 to 0.95, 0.3 to 0.9, 0.3 to 0.85, or even in a range from 0.4 to 0.8 percent by weight, based on the total weight of the treatment composition.

In some embodiments of the foregoing methods, the hydrocarbon-bearing formation is penetrated by a wellbore, wherein a region near the wellbore is contacted with the composition. The region near the wellbore (i.e., near wellbore region) includes a region within about 25 feet (in some embodiments, 20, 15, or 10 feet) of the wellbore. In some of these embodiments, the method further comprises obtaining hydrocarbons from the wellbore after contacting the hydrocarbon-bearing formation with the composition.

The fluorinated acids useful for practicing the methods disclosed herein have been found to be surprisingly effective at very low concentrations, for example, up to 1 percent by weight, based on the total weight of the treatment composition. Also, typically, and unexpectedly, the fluorinated acids provide, for example, a gas permeability that is higher than any increase in gas permeability obtained when an equivalent hydrocarbon-bearing formation is treated with a comparative composition, wherein the comparative

composition is the same as the treatment composition except that the fluorinated acid is replaced with a salt of the fluorinated acid. This increase also typically degrades at a slower rate than any increase provided by the comparative composition.

In this application:

Terms such as "a", "an" 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 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 "brine" refers to water having at least one dissolved electrolyte salt therein (e.g., sodium chloride, calcium chloride, strontium chloride, magnesium chloride, potassium chloride, ferric chloride, ferrous chloride, and hydrates thereof) at any nonzero concentration (in some embodiments, 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 even 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 "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 term "contacting" includes placing a treatment 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 treatment composition into a well, wellbore, or hydrocarbon-bearing formation).

"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 poly cyclic and, in some embodiments, have from 3 to 10 ring carbon atoms. "Alkylene" is the divalent form of "alkyl".

The term "fluoroalkyl" 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. The term "perfluoroalkyl group" includes linear, branched, and/or cyclic alkyl groups in which all C-H bonds are replaced by C-F bonds. The term "interrupted by up to 5 ether groups" refers to having fluoroalkyl on both sides of the ether group.

The term "aryl" as used herein includes carbocyclic aromatic rings or ring systems, for example, having 1, 2, or 3 rings, optionally containing at least one heteroatom (e.g., O, S, or N) in the ring, and optionally substituted by up to five substituents including one or more alkyl groups having up to 4 carbon atoms(e.g., methyl or ethyl), alkoxy having up to 4 carbon atoms, halo (i.e., fluoro, chloro, bromo or iodo), hydroxy, or nitro groups.

Examples of aryl groups include phenyl, naphthyl, biphenyl, fluorenyl as well as furyl, thienyl, oxazolyl, and thiazolyl.

The term "solvent" refers to a homogeneous liquid material, which may be a single compound or a combination of compounds and which may or may not include water, that is capable of at least partially dissolving a fluorinated acid disclosed herein at 25 ⁰C.

The term "precipitate" means to separate from solution and remain separated under the conditions of the treatment method (e.g., in the presence of the brine and at the temperature of the hydrocarbon-bearing formation).

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

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 the present disclosure;

Fig. 2 is a schematic illustration of the flow apparatus used for Examples 1 to 10 and Comparative Examples 1 to 6; and

Fig. 3 is a schematic illustration of a core flood set-up that can be used to evaluate the method disclosed herein in a laboratory. DETAILED DESCRIPTION

Methods according to the present disclosure include contacting a hydrocarbon- bearing formation with a composition comprising solvent and a fluorinated acid. In some embodiments, the fluorinated acid is represented by formula:

(Rf-X-O)_x-P(O)-(OH)₃-X,

(Rf-X-O)-P(O)-(OH)(O-X"-OH),

Rf-X-SO₃H,

Rf-X-CO₂H, or

Rf-X-P(O)(OH)₂.

In some embodiments, the fluorinated acid is represented by formula:

Rf-X-SO₃H; or

Rf-X-CO₂H.

In some embodiments of the treated hydrocarbon-bearing formations according to the present disclosure, the formation is treated with at least one of:

(Rf-X-O)_x-P(O)-(OY)₃._x,

(Rf-X-0)-P(0)-(0Y)(0-X"-0H),

Rf-X-SO₃Y,

Rf-X-CO₂Y, or

Rf-X-P(O)(OY)₂.

wherein Y is hydrogen or a bond (e.g., an ionic bond, hydrogen bond, or covalent bond) to the hydrocarbon-bearing formation. In some embodiments of these embodiments, the formation is treated with at least one of:

Rf-X-SO₃Y; or

Rf-X-CO₂Y.

In any of the above embodiments having an Rf group, Rf is independently fluoroalkyl group having up to 8 carbon atoms (e.g., up to 6 or 4 carbon atoms, for example, in a range from 2 to 8, 4 to 8, or 2 to 6 carbon atoms) and optionally up to 5 ether groups (e.g., 1, 2, 3, 4, or 5). Rf may be fluoroalkyl having no ether groups. Rf may be a fluoropolyether group, for example, having up to 8 carbon atoms and at least 2 ether linkages (e.g., 2 to 5, 2 to 4, or 2 to 3). Rf may be a mixture of fluoroalkyl groups.

In any of the aforementioned embodiments containing an X group, X is

independently a bond,-SO₂-N(R)(C_yH_2y)-, -C(0)-N(R)(C_yH_2y)-, or alkylene that is optionally interrupted by -O- or -S-, wherein R is an alkyl group having up to 4 carbon atoms; and y is an integer having a value from 1 to 11. In some embodiments, X is independently -SO2-N(R)(C_yH2_y)- or alkylene that is optionally interrupted by -O- or -S-. The term "interrupted by -O- or -S-" refers to having a portion of the alkylene group on either side of the -O- or -S-. In some embodiments, R is methyl or ethyl. In some embodiments, y is 1 or 2. In some embodiments, X is -CH₂-CH₂-. In some embodiments, X is a bond. When X is a bond, the fluorinated acids may also be represented by the following formulas:

(Rf-O)_x-P(O)-(OH)₃._x;

(Rf-O)-P(O)-(OH)(O-X"-OH);

Rf-SO₃H;

Rf-CO₂H; and

Rf-P(O)(OH)₂.

In any of the aforementioned embodiments containing an X" group, X" is alkylene that is optionally interrupted by -O- or -S- or substituted by hydroxyl. In some of these embodiments, X" is alkylene.

In embodiments wherein the fluorinated acid is (Rf-X-O)_x-P(O)-(OH)₃__x, x is a value from 1 to 2. In some embodiments, x is about 1. In some embodiments, x is about 2. Typically, a compound represented by formula (Rf-X-O)_x-P(O)-(OH)₃__x is a mixture wherein x can be 1 or 2.

In some embodiments, the fluorinated acid is represented by formula

R

[Rf-SO₂-N-CH₂]₂Q-Z,

wherein Rf is as defined in any of the aforementioned embodiments of Rf.

In some of these embodiments, Rf is C4F9-. In some embodiments, R is -CH₃ or

-CH₂CH₃. R' may also be an aryl group (e.g., phenyl). In some embodiments, Q is -CHO- or -CHOCH₂-. In some embodiments, Z is -COOH.

In some embodiments of treated hydrocarbon-bearing formations according to the present disclosure, the hydrocarbon-bearing formation is treated with:

R

[Rf-SO₂-N-CH₂]₂Q-Z', wherein Rf, R', and Q are as defined in any of the above embodiments, and Z' is -COOY, -SO₃Y, -OSO₃Y, or -P(O)(OY)₂, wherein Y is as defined above.

The salts of many fluorinated acids (e.g., fluorinated phosphates, fluorinated sulfonates, and fluorinated carboxylates) are commercially available. Fluorinated phosphates are available, for example, from E. I. du Pont de Nemours and Co.,

Wilmington, DE, under the trade designation "ZONYL FSP", "ZONYL 9361", "ZONYL FSE", "ZONYL UR", and "ZONYL 9027". Fluorinated sulfonates are available, for example, from E. I. du Pont de Nemours and Co. under the trade designation "ZONYL FS-62". Fluorinated carboxylates are available, for example, from E. I. du Pont de Nemours and Co. under the trade designation "ZONYL FSA". Other salts of the fluorinated acids can be prepared, for example, by known methods. For example, potassium perfluorobutanesulfonate, potassium N-(perfluorobutylsulfonyl)-N- methylglycinate (i.e., C₄F₉SO₂N(CH₃)CH₂CO₂K), and N-(perfiuorohexylsulfonyl)-N- methylglycinate (i.e., CeFi₃SO₂N(CH₃)CH₂CO₂K) can be prepared from perfluoro-1- butanesulfonyl fluoride, which is available from Sigma-Aldrich, St. Louis, MO, and perfluoro-1-hexanesulfonyl fluoride, respectively, using the methods described in U. S. Pat. No. 6,664,354 (Savu et al), the disclosure of which methods are incorporated herein by reference. Acids can be obtained from these salts using conventional techniques (e.g., treating with sulfuric acid and extracting). Other fluorinated acids and fluorinated acid fluorides that are commercially available include carboxylic acids of formula

CF₃-[O-CF₂]i_₃C(O)OH, which are available, for example, from Anles Ltd., St. Petersburg, Russia, and acid fluorides of formulas C₂F₅-O-(CF₂)₂-C(O)F, C₃F₇-O-(CF₂)₂-C(O)F and CF₃CF₂-O-CF₂CF₂-O-CF₂C(O)F, which are available, for example, from Exfluor, Round Rock, TX. Acid fluorides may be converted to fluorinated acids using known techniques (e.g., hydrolysis).

In some embodiments of the methods and the hydrocarbon-bearing formations disclosed herein, Rf is a perfluorinated polyether group of formula:

CF₃CF₂CF₂-O-[CF(CF₃)CF₂O]_k-CF(CF₃)-, wherein k is 1, 2, 3, or 4. Fluorinated acids of this type can be prepared by oligomerization of hexafluoroproyplene oxide to provide a perfluoropolyether carbonyl fluoride. Carbonyl fluorides may be converted to an acid or ester using reaction conditions well known to those skilled in the art. Fluorinated acids can also be prepared, for example, starting from fluorinated ether olefins represented by formula

wherein Rf represents a partially or fully fluorinated alkyl group having from 1 to 10 carbon atoms and optionally interrupted with at least one oxygen atom, and t is 0 or 1, with the proviso that when t is 0, then Rf is interrupted with at least one oxygen atom. Numerous fluorinated ether olefins are known

(e.g., perfluorinated vinyl ethers and perfluorinated allyl ethers), and many can be obtained from commercial sources (e.g., 3M Company, St. Paul, MN, and E.I. du Pont de Nemours and Company, Wilmington, DE). Others can be prepared by known methods; (see, e.g., U. S. Pat. Nos. 5,350,497 (Hung et al.) and 6,255,536 (Worm et al.)).

Fluorinated ether olefins represented by formula

can be treated, for example, with a base (e.g., ammonia, alkali metal hydroxides, and alkaline earth metal hydroxides) to provide a fluorinated acid represented by formula Rf-(O)₁-CHF-C(O)OH. When the reaction is carried out in an aliphatic alcohol (e.g., methanol, ethanol, n-butanol, and t-butanol) in an alkaline medium, the resulting ether can be decomposed under acidic conditions to provide a fluorinated carboxylic acid of formula Rf-(O)₁-CHF-C(O)OH.

Fluorinated acids represented by formula Rf-(O)₁-CHF-CF₂-C(O)OH can be prepared, for example, by a free radical reaction of the fluorinated ether olefin represented by formula Rf -(O)_t-CF=CF₂ with methanol followed by an oxidation of the resulting reaction product using conventional methods. Conditions for these reactions are described, for example, in U. S. Pat. App. No. 2007/0015864 (Hintzer et al.), the disclosure of which, relating to the preparation of compounds of formula Rf-(O)_t-CHF-CF₂-C(O)OH, is incorporated herein by reference.

Fluorinated vinyl ethers represented by formula Rf-O-CF=CF₂ can be oxidized (e.g., with oxygen) in the presence of a fluoride source (e.g., antimony pentafluoride) to carboxylic acid fluorides of formula Rf-O-CF₂C(O)F according to the methods described in U. S. Pat. No. 4,987,254 (Schwertfeger et al.), in column 1, line 45 to column 2, line 42, the disclosure of which is incorporated herein by reference. Examples of compounds that can be prepared according to this method include CF₃-(CF₂)₂-O-CF₂-C(O)-CH₃ and CF₃-O-(CF₂)_S-O-CF₂-C(O)-CH₃, which are described in U. S. Pat. No. 2007/0015864 (Hintzer et al.), the disclosure of which, relating to the preparation of these compounds, is incorporated herein by reference. These esters can be converted to the corresponding carboxylic acids using, for example, conventional techniques. Fluorinated carboxylic acids represented by formula CF₃CFH-O-(CF₂)p-C(O)OH, wherein p is 1 to 6, and their derivatives can be prepared, for example, by decarbonylation of difunctional perfluorinated acid fluoride according to the reaction:

FCOCF(CF₃)-O-(CF₂)_PC(O)F→ CF₃-CHF-O-(CF₂)_PC(O)OH. The reaction is typically carried out at an elevated temperature in the presence of water and base (e.g., a metal hydroxide or metal carbonate) according to known methods; see, e.g., U. S. Pat. No. 3,555,100 (Garth et al), the disclosure of which, relating to the decarbonylation of difunctional acid fluorides, is incorporated herein by reference.

A fluorinated methyl ester, prepared according to any of the techniques described above, can be also be treated with an amine having formula NH₂-(C_yH_2y)-COOH according to the following reaction scheme.

Rf-C(O)-OCH₃ + NH₂-C_yH_2y-COOH→ Rf-C(O)-NH-C_yH_2y-COOH

The reaction may be carried out, for example, at an elevated temperature (e.g., up to 80 ⁰C, 70 ⁰C, 60 ⁰C, or 50 ⁰C), and may be carried out neat or in a suitable solvent. In this sequence, Rf and y are as defined in any of the above embodiments. Some amines having formula NH₂-C_yH_2y-COOH are commercially available, such as sarcosine, 7- aminoheptanoic acid, and 12-aminododecanoic acid. 3-Aminopropylphosphonic acid is also commercially available and can be used in the above reaction scheme to provide fluorinated phosphonic acids.

Other useful Rf structures for fluoriated acids include partially fluorinated Rf groups disclosed, for example, in PCT International Pub. No. WO 2008/154345 Al, pages 8 to 10, the disclosure of which is incorporated herein by reference.

Fluorinated acids represented by formula

R

[Rf-SO₂-N-CH₂J₂Q-Z

can be prepared, for example, by reacting two moles Of C₄F₉SO₂NH(CH)₃ with either 1,3- dichloro-2-propanol or epichlorohydrin in the presence of base to provide a hydroxyl- substituted compound represented by formula [C₄F₉SO₂N(CH)₃CH₂J₂CHOH. The hydroxyl-substituted compound can then be treated with, for example, phosphonoacetic acid, phosphonopropionic acid, phosphorous (V) oxychloride, 1,3-propanesultone, or ethyl bromoacetate followed by hydroylsis to provide a fluorinated acid. The reaction with phosphonoacetic acid or phosphonopropionic acid can be carried out, for example, in a suitable solvent (e.g., methyl isobutyl ketone or methyl ethyl ketone), optionally in the presence of a catalyst (e.g., methanesulfonic acid or sodium tert-butoxide) and optionally at an elevated temperature (e.g., up to the reflux temperature of the solvent). The reaction of the hydroxyl-substituted compound with phosphorous (V) oxychloride or 1,3- propanesultone can be carried out, for example, in a suitable solvent (e.g., toluene), optionally at an elevated temperature (e.g., the reflux temperature of the solvent). If one equivalent of the hydroxyl-substituted compound is used to prepare a compound wherein Z is a phosphate, an equivalent of water or alcohol may be added. Further methods for preparing these compounds may be found in the Examples of U. S. Pat. No. 7,160,850 (Dams et al.), the disclosure of which examples are incorporated herein by reference.

Treatment compositions useful in practicing the methods disclosed herein comprise solvent. Examples of useful solvents include organic solvents, water, easily gasified fluids (e.g., supercritical or liquid carbon dioxide, ammonia, or low-molecular- weight hydrocarbons), and combinations thereof. In some embodiments, the compositions comprise water and at least one organic solvent. In some embodiments, the compositions are essentially free of water (i.e., contains less than 0.1 percent by weight of water, based on the total weight of the composition). In some embodiments, the solvent is a water- miscible solvent (i.e., the solvent is soluble in water in all proportions). Examples of organic solvents include polar and/or water-miscible solvents, for example, monohydroxy alcohols having from 1 to 4 or more carbon atoms (e.g., methanol, ethanol, isopropanol, propanol, or butanol); polyols such as glycols (e.g., ethylene glycol or propylene glycol), terminal alkanediols (e.g., 1,3- propanediol, 1 ,4-butanediol, 1,6-hexanediol, or 1,8- octanediol), polyglycols (e.g., diethylene glycol, triethylene glycol, dipropylene glycol, or poly(propylene glycol)), triols (e.g., glycerol, trimethylolpropane), or pentaerythritol; ethers such as diethyl ether, methyl t-butyl ether, tetrahydrofuran, p-dioxane, or polyol ethers (e.g., glycol ethers (e.g., ethylene glycol monobutyl ether, diethylene glycol monomethyl ether, dipropylene glycol monomethyl ether, propylene glycol monomethyl ether, 2-butoxyethanol, or those glycol ethers available under the trade designation "DOWANOL" from Dow Chemical Co., Midland, MI)); ketones (e.g., acetone, methyl ethyl ketone, 4-methyl-2-pentanone, 3-methyl-2-pentanone, 2-methyl-3-pentanone, and 3,3-dimethyl-2-butanone), esters (e.g., ethyl acetate, methyl formate, propyl acetate, and butyl acetate); and combinations thereof. In some embodiments, the solvent comprises 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. In some embodiments, the solvent comprises a polyol. 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 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 etherifϊcation 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 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, poly(propylene glycol), 1,3 -propanediol, or 1,8-octanediol, and the polyol ether is at least one of 2-butoxyethanol, diethylene 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 some embodiments, useful solvents for practicing the methods disclosed herein comprise 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. Exemplary monohydroxy alcohols having from 1 to 4 carbon atoms include methanol, ethanol, n-propanol, isopropanol, 1-butanol, 2-butanol, isobutanol, and t- butanol. Exemplary ethers having from 2 to 4 carbon atoms include diethyl ether, ethylene glycol methyl ether, tetrahydrofuran, p-dioxane, and ethylene glycol dimethyl ether. Exemplary ketones having from 3 to 4 carbon atoms include acetone, l-methoxy-2- propanone, and 2-butanone. In some embodiments, useful solvents for practicing the methods disclosed herein comprise at least one of methanol, ethanol, isopropanol, tetrahydrofuran, or acetone.

In some embodiments of the methods disclosed herein, the treatment compositions comprise at least two organic 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 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 both simultaneously. In these embodiments, each solvent component may be present as a single component or a mixture of components. In some embodiments, compositions useful for practicing the methods disclosed herein 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 monohydroxy alcohol having up to 4 carbon atoms. In some embodiments, the solvent consists essentially of (i.e., does not contain any components that materially affect water solubilizing or displacement properties of the composition under downhole conditions) at least one of a polyol having from 2 to 25 (in some embodiments, 2 to 20, 2 to 15, 2 to 10, 2 to 9, 2 to 8, or even 2 to 6) carbon atoms or polyol ether having from 3 to 25 (in some embodiments, 3 to 20, 3 to 15, 3 to 10, 3 to 9, 3 to 8, or even from 5 to 8) carbon atoms, and at least one monohydroxy alcohol having from 1 to 4 carbon atoms, ether having from 2 to 4 carbon atoms, or ketone having from 3 to 4 carbon atoms. Typically, the solvents described herein are capable of solubilizing more brine in the presence of fluorinated acid than methanol alone.

In some embodiments of methods according to the present disclosure, useful solvents at least one of at least partially solubilize or at least partially displace brine in the hydrocarbon-bearing formation. By the term "solubilizes", it is meant that the solvent dissolves the water and the salts in the brine. "At least partially solubilize" includes dissolving all or nearly all (e.g., at least 95% including up to 100%) of the water and the salts in the brine. In some embodiments, useful solvents at least partially solubilize or at least partially displace liquid hydrocarbons in the hydrocarbon-bearing formation.

For any of the embodiments wherein the treatment compositions useful for practicing the methods disclosed herein 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, the polyol or polyol ether is present in the treatment 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. In some embodiments, the treatment composition comprises up to 50, 40, 30, 20, or even 10 percent by weight of a

monohydroxy alcohol having up to 4 carbon atoms, based on the total weight of the treatment composition.

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%), Methylene 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- butoxyethanol (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.

In some embodiments of treatment compositions disclosed herein, the solvent comprises a ketone, ether, or ester having from 4 to 10 (e.g., 5 to 10, 6 to 10, 6 to 8, or 6) carbon atoms or a hydro fluoroether or hydro fluorocarbon. In some of these embodiments, the solvent comprises two different ketones, each having 4 to 10 carbon atoms (e.g., any combination of 2-butanone, 4-methyl-2-pentanone, 3-methyl-2-pentanone, 2-methyl-3- pentanone, and 3,3-dimethyl-2-butanone). In some embodiments, the solvent further comprises at least one of water or a monohydroxy alcohol having up to 4 carbon atoms (e.g., methanol, ethanol, n-propanol, isopropanol, 1-butanol, 2-butanol, isobutanol, and t- butanol). Useful ethers having 4 to 10 carbon atoms include diethyl ether, diisopropyl ether, tetrahydrofuran, p-dioxane, and tert-butyl methyl ether. Useful esters having 4 to 10 carbon atoms include ethyl acetate, propyl acetate, and butyl acetate. Useful

hydrofluoroethers may be represented by the general formula Rf³-[O-Rh]_a, wherein a is an integer from 1 to 3; Rf³ is a perfluoroalkyl or di- or trivalent perfluoroalkylene, each of which may be interrupted with at least one -O-; and Rh is an alkyl group optionally interrupted with at least one -O- . Numerous hydro fluoroethers of this type are disclosed in U. S. Pat. No. 6,380,149 (Flynn et al.), the disclosure of which is incorporated herein by reference. In some embodiments, the hydrofluoroether is methyl perfluorobutyl ether or ethyl perfluorobutyl ether. Useful hydrofluoroethers also include hydrofluoroethers available, for example, from 3M Company, St. Paul, MN, under the trade designations "HFE-7100" and "HFE-7200".

The ingredients for treatment compositions described herein including fluorinated acids and solvents 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).

The amount of solvent typically varies inversely with the amount of other components in treatment compositions useful in practicing any of the methods disclosed herein. For example, based on the total weight of the treatment composition the solvent may be present in the treatment composition in an amount of from at least 10, 20, 30, 40, or 50 percent by weight or more up to 60, 70, 80, 90, 95, 98, or even 99 percent by weight, or more.

Generally, the amounts of the fluorinated acid 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.

In some embodiments of the methods disclosed herein, the hydrocarbon-bearing formation includes brine. The brine present in the 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 formation). In some embodiments, the brine is connate water. In some embodiments, the brine causes water blocking (i.e., declining productivity resulting from increasing water saturation in a well). It is believed that useful treatment compositions will not undergo precipitation of the fluorinated acids, dissolved salts, or other solids when the treatment compositions encounter the brine. Such precipitation may inhibit the adsorption or reaction of the fluorinated acid 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 some embodiments, 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 skilled in the art. In some embodiments, the methods comprise selecting a treatment composition for the hydrocarbon-bearing formation comprising the fluorinated acid and solvent, based on the behavior of a mixture of the brine composition and the treatment composition. Typically, for the methods disclosed herein, a mixture of an amount of brine and the treatment composition is transparent and substantially free of precipitated solid (e.g., salts, asphaltenes, or fluorinated acids).

Although not wanting to be bound by theory, it is believed that the effectiveness of the methods disclosed herein for improving hydrocarbon productivity of a particular oil and/or gas well having brine accumulated in the near wellbore region will typically be determined by the ability of the treatment composition to dissolve the quantity of brine present in the near wellbore region of the well. Hence, at a given temperature greater amounts of treatment compositions having lower brine solubility (i.e., treatment compositions that can dissolve a relatively lower amount of brine) will typically be needed than in the case of treatment compositions having higher brine solubility and containing the same fluorinated acid at the same concentration.

In some embodiments, a mixture of an amount of the brine composition and the treatment composition, at the temperature of the hydrocarbon-bearing formation, is transparent and free of precipitated solids. As used herein, the term transparent refers to allowing clear view of objects beyond. In some embodiments, transparent refers to liquids that are not hazy or cloudy. The term "substantially free of precipitated solid" refers to an amount of precipitated solid that does not interfere with the ability of the fluorinated acid to increase the gas or liquid 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 at a given temperature and pressure.

In some embodiments, the transparent mixture of the brine composition and the treatment composition does not separate into layers, and in other embodiments, the transparent mixture of the brine composition and the treatment composition separates into at least two separate transparent liquid layers. 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, cloudiness, or precipitation occurs. The amount of the brine composition in the mixture may be 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.

Whether the mixture of the brine composition and the treatment composition is transparent, substantially free of precipitated solid, and separates into layers at the temperature of the hydrocarbon-bearing formation can depend on many variables (e.g., concentration of the fluorinated acid, solvent composition, brine concentration and composition, hydrocarbon concentration and composition, and the presence of other components (e.g., surfactants or scale inhibitors)). Typically, for treatment compositions comprising at least one of a polyol or polyol ether described above and a monohydroxy alcohol having up to 4 carbon atoms, mixtures of the brine composition and the treatment composition do not separate into two or more layers. In some of these embodiments, the salinity of the brine is less than 150,000 ppm (e.g., less than 140,000, 130,000, 120,000, or 110,000 ppm) total dissolved salts. Typically, for treatment compositions described above comprising at least one (e.g., one or two) ketone having from 4 to 10 carbon atoms or a hydro fluoroether, mixtures of the brine composition and the treatment composition separate into two or more layers. In some of these embodiments, the salinity of the brine is greater than 100,000 ppm (e.g., greater than 110,000, 125,000, 130,000, or 150,000 ppm) total dissolved salt. Although not wishing to be bound by theory, it is believed that when two or more layers form in such mixtures, the fluorinated acid preferentially partitions into a layer rich in organic solvent that has a lower concentration of dissolved salts. Typically, treatment compositions comprising at least one of a polyol or polyol ether described above and treatment compositions comprising at least one ketone having from 4 to 10 carbon atoms or a hydro fluoroether are capable of solubilizing more brine (i.e., no salt precipitation occurs) in the presence of a fluorinated acid than methanol, ethanol, propanol, butanol, or acetone alone.

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.

In some embodiments of the methods disclosed herein, the fluorinated acid is present in an amount sufficient to increase at least the gas permeability of the

hydrocarbon-bearing formation. Before contacting the hydrocarbon-bearing formation with the treatment composition, the hydrocarbon-bearing formation typically has at least one of brine or liquid hydrocarbons. In some embodiments, the gas permeability after contacting the hydrocarbon-bearing formation with the treatment 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 even 100 percent or more) relative to the gas permeability of the formation before contacting the formation with the treatment composition. In some embodiments, the gas permeability is a gas relative permeability. In some embodiments, the liquid (e.g., oil or condensate) permeability in 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 even 100 percent or more) after contacting the formation with the treatment composition.

In some embodiments wherein the methods disclosed herein provide an increase in gas permeability, at least one of (a) the increase is higher than any increase in gas permeability obtained when an equivalent hydrocarbon-bearing formation is treated with a comparative composition; or (b) the increase degrades at a slower rate than any increase in gas permeability obtained when an equivalent hydrocarbon-bearing formation is treated with the comparative composition, wherein the comparative composition is the same as the treatment composition except that the fluorinated acid is replaced with a salt of the fluorinated acid. 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 comprise greater than 50 percent limestone. 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). The fluorinated acids useful for practicing the present disclosure are typically more effective at lower concentrations (i.e., less than 1 percent by weight) than certain of their

corresponding salts even though certain of their corresponding salts have been

demonstrated to be effective at higher concentration (see, e.g., Int. Appl. Pub. No. WO 2009/085899 (Baran et al.)).

In some embodiments of the methods disclosed herein, hydrocarbon-bearing formations have both gas and liquid hydrocarbons. The liquid hydrocarbons in the hydrocarbon-bearing formation may be, for example, at least one of retrograde gas condensate or oil and may comprise, for example, at least one of methane, ethane, propane, butane, pentane, hexane, heptane, octane, nonane, decane, or higher

hydrocarbons. In some of these embodiments, the liquid hydrocarbons may be

condensate, black oil, or volatile oil. 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 m³/m³) up to about 1800 (320), 1900 (338), or even 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 even 2200 scf/stb (392 m³/m³) up to about 3100 (552), 3200 (570), or even 3300 scf/stb (588 m³/m³).

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. The skilled artisan, 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, for example, 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, contacting a hydrocarbon-bearing formation with a treatment 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 contacted with the treatment composition.

Methods of using treatment compositions described herein are useful, for example, on both existing and new wells. Typically, it is believed to be desirable to allow for a shut-in time after compositions described herein are contacted with the 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 composition has been allowed to remain in place for a selected time, the solvents present in the treatment 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 methods according to the present disclosure, the method comprises contacting the hydrocarbon-bearing formation with a fluid prior to contacting the hydrocarbon-bearing formation with the treatment composition, wherein the fluid at least one of partially solubilizes or partially displaces the brine in the hydrocarbon-bearing formation. In some embodiments, the fluid partially solubilizes the brine. In some embodiments, the fluid partially displaces the brine. In some embodiments, the fluid is substantially free of fluorinated surfactants. The term "substantially free of fluorinated surfactants" refers to fluid that may have a fluorinated surfactant 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 surfactants may be a fluid that has a fluorinated surfactant 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 surfactants includes those that have a weight percent of such surfactants as low as 0 weight percent. The fluid may be useful for decreasing the concentration of at least one of the salts present in a brine before introducing the treatment 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 treatment composition with a first brine before 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 a transparent mixture with no salt precipitation.) In some embodiments, 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 at least one of a polyol or polyol ether independently having from 2 to 25 carbon atoms. In some embodiments, useful polyols have 2 to 20, 2 to 15, 2 to 10, 2 to 8, or even 2 to 6 carbon atoms. Exemplary useful polyols include ethylene glycol, propylene glycol, poly(propylene glycol), 1,3 -propanediol,

trimethylolpropane, glycerol, pentaerythritol, and 1,8-octanediol. In some embodiments, useful polyol ethers may have from 3 to 25 carbon atoms, 3 to 20, 3 to 15, 3 to 10, 3 to 8, or even from 5 to 8 carbon atoms. Exemplary useful polyol ethers include diethylene glycol monomethyl ether, ethylene glycol monobutyl ether, dipropylene glycol monomethyl ether, 2-butoxyethanol, and l-methoxy-2-propanol. In some embodiments, the fluid comprises at least one monohydroxy alcohol, ether, or ketone independently having up to four carbon atoms. In some embodiments, the fluid comprises at least one of nitrogen, carbon dioxide, or methane.

In some embodiments, the fluid at least one of partially solubilizes or displaces the liquid hydrocarbons in the hydrocarbon-bearing formation.

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 even 10 or more fractures. As used herein, the term "fracture" refers to a fracture that is manmade. In the field, for example, 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). Typically, fracturing refers to hydraulic fracturing, and the fracturing fluid is a hydraulic fluid.

Fracturing fluids may or may not contain proppants. Unintentional fracturing can sometimes occur, for example, during drilling of a wellbore. Unintentional fractures can be detected (e.g., by fluid loss from the wellbore) and repaired. Typically, fracturing a hydrocarbon-bearing formation refers to intentionally fracturing the formation after the wellbore is drilled. In some embodiments, hydrocarbon-bearing formations that may be treated according to the methods disclosed herein (e.g., limestone or carbonate formations) have natural fractures. Natural fractures may be formed, for example, as part of a network of fractures.

Fracturing of carbonate formations can also be carried out in the presence of acids (e.g., hydrochloric acid, acetic acid, formic acid or combinations thereof) to etch the open faces of induced fractures. When the treatment is complete and the fracture closes, the etched surface provides a high-conductivity path from the hydrocarbon-bearing formation or reservoir to the wellbore. Treatments are most commonly conducted with 15% to 30% solutions of hydrochloric acid. Applications for various acid types or blends are typically based on the reaction characteristics of the prepared treatment fluid. Fluorinated acids described herein may be useful in conjunction with acid treatments (e.g., before, during, or after the acid treatment) to modify the wettability of the fractured formation. In some embodiments of the treatment methods disclosed herein, wherein contacting the formation with the composition provides an increase in at least one of the gas permeability or the liquid permeability of the formation, the formation is a non- fractured formation (e.g., free of manmade fractures made by the hydraulic fracturing processes described herein). Advantageously, treatment methods disclosed herein typically provide an increase in at least one of the gas permeability or the liquid permeability of the formation without fracturing the formation.

In some of embodiments of the treatment methods disclosed herein, wherein the hydrocarbon-bearing formation has at least one fracture, the fracture has a plurality of proppants therein. 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.

In some embodiments, the proppants form packs within a formation and/or wellbore. Proppants may be selected to be chemically compatible with the solvents and fluorinated acids 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 contacting the hydrocarbon-bearing formation with the treatment composition during fracturing, after fracturing, or during and after fracturing the hydrocarbon-bearing formation. In some of these embodiments, the fracturing fluid, which may contain proppants, may be aqueous (e.g., a brine) or may contain predominantly organic solvent (e.g., an alcohol or a hydrocarbon). In some embodiments, it may be desirable for the fracturing fluid to include viscosity enhancing agents (e.g., polymeric viscosifϊers), electrolytes, corrosion inhibitors, scale inhibitors, and other such additives that are common to a fracturing fluid.

In some embodiments of methods of treated 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 contacted 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 contacts 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 even 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 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.

Selected Embodiments of the Disclosure

In a first embodiment, the present disclosure provides method of treating a hydrocarbon-bearing formation, the method comprising:

(Rf-X-O)_x-P(O)-(OH)₃._x;

(Rf-X-O)-P(O)-(OH)(O-X"-OH);

Rf-X-SO₃H;

Rf-X-CO₂H;

Rf-X-P(O)(OH)₂;

R

I

[Rf-SO₂-N-CH₂]₂Q-Z; and

combinations thereof;

wherein Rf is independently fluoroalkyl having up to 8 carbon atoms and optionally interrupted by up to 5 ether groups;

X is independently:

a bond;

-SO₂-N(R)(C_yH_2y)-;

-C(O)-N(R)(C_yH_2y)-; or

alkylene that is optionally interrupted by -O- or -S-;

x is a value from 1 to 2;

R is an alkyl group having up to 4 carbon atoms;

y is a value from 1 to 11 ;

R is alkyl having up to 4 carbon atoms or aryl;

Q is -CHO-, -CHO(C₂H₂₂)-, -CH0(C₂H_2z0)_q(C₂H₂₂)-, -CHS-, -CHS(C₂H₂₂)-, -CHS(C₂H_2zO)_q(C₂H_2z)- or -CHOC(O)(C₂H₂₂)-, wherein q is a value from 1 to 50, and each z is independently a value from 1 to 5; and

Z is -COOH, -SO₃H, -OSO₃H, or -P(O)(OH)₂.

In a second embodiment, the present disclosure provides the method of the first embodiment, wherein the solvent comprises at least one of water, a monohydroxy alcohol, an ether, a ketone, a glycol, a glycol ether, or supercritical carbon dioxide.

In a third embodiment, the present disclosure provides the method of the first or second embodiment, wherein the fluorinated acid is adsorbed on the hydrocarbon-bearing formation.

In a fourth embodiment, the present disclosure provides the method of any one of the first to third embodiments, wherein the hydrocarbon-bearing formation comprises limestone.

In a fifth embodiment, the present disclosure provides the method of any one of the first to fourth embodiments, wherein the fluorinated acid is represented by formula Rf-X-SO₃H or Rf-X-CO₂H, and wherein Rf is perfluoroalkyl having up to 6 carbon atoms and optionally interrupted by up to 5 ether groups.

In a sixth embodiment, the present disclosure provides the method of any one of the first to fifth embodiments, wherein the fluorinated acid is represented by formula Rf^SChH, wherein Rf¹ is perfluoroalkyl having up to 6 carbon atoms.

In a seventh embodiment, the present disclosure provides the method of any one of the first to fifth embodiments, wherein the fluorinated acid is represented by formula R^-CO₂H, wherein Rf² is perfluoroalkyl having up to 8 perfluorinated carbon atoms and optionally interrupted by up to 5 ether groups.

In an eighth embodiment, the present disclosure provides the method of any one of the first to fourth embodiments, wherein the fluorinated acid is represented by formula [Rf¹SO₂N(R^>)CH₂]₂CHO(C_zH_2Z)COOH, wherein Rf¹ is perfluoroalkyl having up to 6 carbon atoms, R is alkyl having up to 4 carbon atoms; and z is from 1 to 3.

In a ninth embodiment, the present disclosure provides the method of any one of the first to eighth embodiments, wherein the fluorinated acid is present in the treatment composition in a range from 0.4 to 0.8 weight percent, based on the total weight of the treatment composition.

In a tenth embodiment, the present disclosure provides the method of any one of the first to ninth embodiments, further comprising:

receiving data comprising a temperature and a brine composition of the

hydrocarbon-bearing formation; and

selecting the treatment composition for treating the hydrocarbon-bearing formation, 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.

In an eleventh embodiment, the present disclosure provides the method of any one of the first to ninth embodiments, further comprising:

receiving data comprising a temperature and a brine composition of the

hydrocarbon-bearing formation; and

selecting the treatment composition for treating the hydrocarbon-bearing formation, wherein, at the temperature, a mixture of the brine composition and the treatment composition separates into at least two separate transparent liquid layers, and wherein the mixture is free of precipitated solid.

In a twelfth embodiment, the present disclosure provides the method of any one of the first to ninth embodiments, further comprising: receiving data comprising a temperature and a first brine composition of the hydrocarbon-bearing formation;

contacting the hydrocarbon-bearing formation with a fluid, wherein after the fluid contacts the hydrocarbon-bearing formation, the hydrocarbon-bearing formation has a second brine composition that is different from the first brine composition; and

selecting the treatment composition for treating the hydrocarbon-bearing formation, wherein, at the temperature, a mixture of an amount of the second brine composition and the treatment composition is transparent and free of precipitated solid, and wherein the mixture does not separate into layers.

In a thirteenth embodiment, the present disclosure provides the method of the twelfth embodiment, wherein the fluid comprises at least one of toluene, diesel, heptane, octane, condensate, water, methanol, ethanol, or isopropanol.

In a fourteenth embodiment, the present disclosure provides the method of any one of the first to thirteenth embodiments, wherein the hydrocarbon-bearing formation is penetrated by a wellbore, and wherein a region near the wellbore is contacted with the treatment composition.

In a fifteenth embodiment, the present disclosure provides the method of the fourteenth embodiment, further comprising obtaining hydrocarbons from the wellbore after contacting the hydrocarbon-bearing formation with the treatment composition.

In a sixteenth embodiment, the present disclosure provides the method of any one of the first to fifteenth embodiments, further comprising fracturing the hydrocarbon- bearing formation, wherein contacting the hydrocarbon-bearing formation with the treatment composition is carried out during the fracturing, after the fracturing, or during and after the fracturing.

In a seventeenth embodiment, the present disclosure provides the method of the sixteenth embodiment, wherein the fracturing comprises acid fracturing.

In an eighteenth embodiment, the present disclosure provides the method of any one of the first to seventeenth embodiments, wherein the hydrocarbon-bearing formation has at least one fracture, and wherein the fracture has a plurality of proppants therein.

In a nineteenth embodiment, the present disclosure provides the method of any one of the first to eighteenth embodiments, wherein before contacting the hydrocarbon-bearing formation with the treatment composition, the hydrocarbon-bearing formation has at least one of brine or liquid hydrocarbons, and wherein the hydrocarbon-bearing formation has an increase in at least gas permeability after it is contacted with the treatment composition.

In a twentieth embodiment, the present disclosure provides the method of the nineteenth embodiment, wherein at least one of (a) the increase is higher than any increase in gas permeability obtained when an equivalent hydrocarbon-bearing formation is treated with a comparative composition; or (b) the increase degrades at a slower rate than any increase in gas permeability obtained when an equivalent hydrocarbon-bearing formation is treated with the comparative composition, wherein the comparative composition is the same as the treatment composition except that the fluorinated acid is replaced with a salt of the fluorinated acid.

In a twenty-first embodiment, the present disclosure provides a hydrocarbon- bearing formation treated according to the method of any one of the first to twentieth embodiments. Advantages and embodiments of the methods disclosed herein 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.

EXAMPLES

Preparation 1

To 50 grams (0.15 mol) of potassium nonafluorobutanesulfonate (C4F9SO3K) (available from 3M Company, Minnesota, USA, under the trade designation "FR-2025 3M

FLAME RETARDANT ADDITIVE") placed in a three-necked flask of 1000 mL fitted with a stirrer, thermometer, cooler and heating mantle, were added 200 grams (2.04 mol) of sulfuric acid (available from Aldrich, Bornem, Belgium). The reaction was carried out at room temperature for 2 hours.

After the reaction, 400 grams of diisopropylether (available from Aldrich) were added to the reaction mixture, stirred and the ether phase was separated off. The diisopropylether was subsequently distilled off at atmospheric pressure. The resulting nonafluorobutanesulfonic acid was diluted with ethanol to make a 0.75% by weight solution.

Preparation 2

Tridecafluorohexanesulfonic acid was prepared according to the method of US

2,732,398, Example 4, incorporated herein by reference. The resulting

tridecafluorohexanesulfonic acid was diluted with ethanol to make a 0.75% by weight solution. Preparations 3 - 6

Preparations 3 to 6 were prepared using 0.75% by weight of a fluorinated acid in ethanol. For Preparation 3, the fluorinated acid was CeFi₃COOH, obtained from ABCR, Kalsruhe, Germany. For Preparation 4, the fluorinated acid was C3F7COOH, obtained from ABCR.

In Preparations 5 and 6, nonafluoro-3,5,7-trioxaoctanoic acid

(CF₃O(CF₂O)₂CF₂COOH) (obtained from Anles Ltd., St. Petersburg, Russia), and undecafluoro-3,5,7,9-tetraoxadecanoic acid (CF₃O(CF₂O)₃CF₂COOH) (obtained from Anles Ltd. ), respectively, were used. Preparation 7

HFPO-trimer acid (obtained from ABCR as perfluoro-2,5-dimethyl-3,6- dioxanonanoic acid) was diluted with ethanol to make a 0.75% by weight solution.

Preparation 8

In Preparation 8, a fluorinated acid was prepared essentially according to the method of U.S. Pat. Application No. 2006/0148671 (Dams), Example 4, incorporated herein by reference. No further purification was carried out once the acid was recovered.

The fluorinated acid was diluted with a solvent mixture of 2-butoxyethanol and ethanol at a 70:30 weight ratio to prepare a 0.75% by weight solution, based upon the total weight of the composition. Comparative Preparations A - D

In Comparative Preparation A, the fluorinated surfactant was C₄F₉SO₃NH₄ which was prepared by neutralizing perfluorobutanesulfonic acid (C4F9SO3H,) as described in Preparation 1, with ammonium hydroxide (available from Aldrich, Bornem,Belgium ), at room temperature. The ammonium salt was diluted with ethanol to make a 0.75% by weight solution.

In Comparative Preparation B, the fluorinated surfactant was

CF3OCF2OCF2OCF2OCF2C(O)O-l/2Ca²⁺, which was prepared by treating

undecafluoro-3,5,7,9-tetraoxadecanoic acid, obtained from Anles Ltd., St Petersburg, Russia with Ca(OH)₂, obtained from Aldrich, Bornem, Belgium. The calcium salt was diluted with ethanol to make a 0.75% by weight solution.

In Comparative Preparation C, the fluorinated surfactant was

([C₄F₉Sθ₂N(CH₃)CH₂]₂CHOCH₂COOK) prepared essentially according to the method of U.S. Pat. Application No. 2006/0148671 (Dams), Example 4, incorporated herein by reference. The salt was diluted with ethanol to make a 0.75% by weight solution.

In the following Comparative Preparation D, lauric acid (obtained from Aldrich) was used.

Flow set up and procedure for Examples 1-2 and Comparative Example 1.

A schematic diagram of a flow apparatus 100 used to determine relative permeability of sea sand or particulate calcium carbonate is shown in Fig. 2. Flow apparatus 100 included positive displacement pump 102 (Model Gamma/4-W 2001 PP, obtained from Prolingent AG, Regensdorf, Germany). Nitrogen gas was injected at constant rate through a gas flow controller 120 (Model DK37/MSE, Krohne, Duisburg, Germany). Pressure indicators 113, obtained from Siemens under the trade designation

"SITRANS P" 0-16 bar, were used to measure the pressure drop across a particulate pack in vertical core holder 109 (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) 104 was used to control the flowing pressure upstream and downstream of core holder 109. Core holder 109 was heated by circulating silicone oil, heated by a heating bath obtained from Lauda, Switzerland, Model R22. The core holder was filled with particulate calcium carbonate (obtained Merck, Darmstadt, Germany as granular marble - 0.5 to 2 mm size) and then heated to 75 ⁰C. 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 particulate calcium carbonate was about 500 to 1000 niL/minute. The initial gas permeability was calculated using Darcy's law.

Synthetic brine, prepared 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 introduced into the core holder at about 1 niL/minute using displacement pump 102.

The treatment composition (Preparation 1 or 3 or Comparative Preparation A) was then injected into the core at a flow rate of 1 niL/minute. 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.

After the treatment, brine was injected into the core at about 1 niL/minute using displacement pump 102.

For treatment with the compositions of Preparations 1 and 3, and Comparative

Preparation A, the liquid injected, initial pressure (bar), 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, below. In the table, a "-" means not measured or not applicable.

Table 1

Flow set up and procedure for Examples 3-10 and Comparative Examples 2-6.

The flow setup and procedure described for Examples 1-2 were used, except that the core was subjected to introducing heptane at about 0.5 mL/minute before and after the injection of the treatment composition.

The compositions of Preparations 1-8 and Comparative Preparations A-D were used. In Comparative Example F, ethanol was used as treatment composition. For all the examples, the liquid injected, initial pressure (bar), 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 2, below. In the table, a "-" means not measured or not applicable. Table 2

The results of the evaluations using particulate calcium carbonate can be verified using core flood evaluations on limestone core samples. A schematic diagram of a core flood apparatus 200 that can be used is shown in Fig. 3. Core flood apparatus 200 includes 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 can be 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) can be used to measure pressure drop across the vertical core 209. A backpressure regulator (Model No. BP-50; obtained from Temco, Tulsa, OK) 204 can be used to control the flowing pressure downstream of core 209. High-pressure core holder 208 can be heated with 3 heating bands 222 (Watlow Thinband Model STB4A2AFR-2, St. Louis, MO).

In a typical procedure, a core can be dried for 72 hours in a standard laboratory oven at 95 ⁰C and then wrapped in aluminum foil and heat shrink tubing. Referring again to Fig. 3, the wrapped core 209 can placed in core holder 208 at the desired temperature. An overburden pressure of, for example, 2300 psig (1.6 x 10⁷ Pa) can be applied. The initial single-phase gas permeability can be measured using nitrogen at low system pressures between 5 to 10 psig (3.4 x 10⁴ to 6.9 x 10⁴ Pa).

Deionized water or brine can be introduced into the core 209 by the following procedure to establish the desired water saturation. The outlet end of the core holder is connected to a vacuum pump and a full vacuum can be applied for 30 minutes with the inlet closed. The inlet can be connected to a burette with the water in it. The outlet is closed and the inlet is opened to allow 2.1 mL of water to flow into the core. The inlet and the outlet valves can then be closed for the desired time. The gas permeability can be measured at the water saturation by flowing nitrogen at 500 psig (3.4 x 10⁶ Pa).

The core holder 208 can then be heated to a higher temperature, if desired, for several hours. Nitrogen and n-heptane can be co-injected into the core at an average total flow rate in the core of, for example, 450 mL/hour at a system pressure of, for example, 900 psig (6.2 x 10⁶ Pa) until steady state is reached. The flow rate of nitrogen is controlled by gas flow controller 220, and the rate for n-heptane is controlled by positive displacement pump 202. The flow rates of nitrogen and n-heptane can be set such that the fractional flow of gas in the core was 0.66. The gas relative permeability before treatment can then be calculated from the steady state pressure drop. The treatment composition can then be injected into the core at a flow rate of, for example, 120 mL/hour for about 20 pore volumes. Nitrogen and n-heptane co-injection can be resumed at an average total flow rate in the core of, for example, 450 mL/hour at a system pressure of, for example, 900 psig (6.2 x 10⁶ Pa) until steady state is reached. The gas relative permeability after treatment can then be calculated from the steady state pressure drop. 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: contacting the hydrocarbon-bearing formation with a treatment composition comprising solvent and a fluorinated acid, wherein the fluorinated acid is present in the treatment composition at less than 1 weight percent, based on the total weight of the treatment composition, wherein the hydrocarbon-bearing formation comprises carbonate, and wherein the fluorinated acid is selected from the group consisting of:

(Rf-X-O)_x-P(O)-(OH)₃-X;

(Rf-X-O)-P(O)-(OH)(O-X"-OH);

Rf-X-SO₃H;

Rf-X-CO₂H;

Rf-X-P(O)(OH)₂;

R'

[Rf-SO₂-N-CH₂J₂Q-Z; and

combinations thereof;

wherein

Rf is independently fluoroalkyl having up to 8 carbon atoms and optionally interrupted by up to 5 ether groups;

X is independently:

a bond;

-SO₂-N(R)(C_yH_2y)-;

-C(0)-N(R)(C_yH_2y)-; or

alkylene that is optionally interrupted by -O- or -S-;

x is a value from 1 to 2;

R is an alkyl group having up to 4 carbon atoms;

y is a value from 1 to 11 ;

R' is alkyl having up to 4 carbon atoms or aryl;

Q is -CHO-, -CH0(C_zH_2z)-, -CHO(C_zH_2zO)_q(C_zH_2z)-, -CHS-, -CHS(C_zH_2z)-, -CHS(C_zH_2zO)_q(C_zH_2z)- or -CHOC(O)(C_zH_2z)-, wherein q is a value from 1 to 50, and each z is independently a value from 1 to 5; and

Z is -COOH, -SO₃H, -OSO₃H, or -P(O)(OH)₂.

2. The method of claim 1, wherein the solvent comprises at least one of water, a monohydroxy alcohol, an ether, a ketone, a glycol, a glycol ether, or supercritical carbon dioxide.

3. The method according to claim 1 or 2, wherein the fluorinated acid is represented by formula Rf-X-SO₃H or Rf-X-CO₂H, and wherein Rf is perfluoroalkyl having up to 6 carbon atoms and optionally interrupted by up to 5 ether groups.

4. The method according to claim 1 or 2, wherein the fluorinated acid is represented by formula R^-SO₃H, wherein Rf¹ is perfluoroalkyl having up to 6 carbon atoms.

5. The method according to claim 1 or 2, wherein the fluorinated acid is represented by formula Rf²-CO₂H, wherein Rf² is perfluoroalkyl having up to 8 perfluorinated carbon atoms and optionally interrupted by up to 5 ether groups.

6. The method according to claim 1 or 2, wherein the fluorinated acid is represented by formula [Rf¹SO₂N(R)CH₂]₂CHO(C_zH_2Z)COOH, wherein Rf¹ is perfluoroalkyl having up to 6 carbon atoms, R is alkyl having up to 4 carbon atoms; and z is from 1 to 3.

7. The method according to any preceding claim, wherein the fluorinated acid is present in the treatment composition in a range from 0.4 to 0.8 weight percent, based on the total weight of the treatment composition.

8. The method according to claim 1 or 2, further comprising:

receiving data comprising a temperature and a brine composition of the hydrocarbon-bearing formation; and

9. The method according to claim 1 or 2, further comprising:

receiving data comprising a temperature and a brine composition of the

hydrocarbon-bearing formation; and

10. The method according to claim 1 or 2, further comprising:

receiving data comprising a temperature and a first brine composition of the hydrocarbon-bearing formation;

11. The method according to claim 1 or 2, further comprising fracturing the hydrocarbon-bearing formation, wherein contacting the hydrocarbon-bearing formation with the treatment composition is carried out during the fracturing, after the fracturing, or during and after the fracturing.

12. The method according to claim 11, wherein the fracturing comprises acid fracturing.

13. The method according to claim 1 or 2, wherein the hydrocarbon-bearing formation has at least one fracture, and wherein the fracture has a plurality of proppants therein.

14. The method according to claim 1 or 2, wherein before contacting the hydrocarbon- bearing formation with the treatment composition, the hydrocarbon-bearing formation has at least one of brine or liquid hydrocarbons, wherein the hydrocarbon-bearing formation has an increase in at least gas permeability after it is contacted with the treatment composition, wherein at least one of (a) the increase is higher than any increase in gas permeability obtained when an equivalent hydrocarbon-bearing formation is treated with a comparative composition; or (b) the increase degrades at a slower rate than any increase in gas permeability obtained when an equivalent hydrocarbon-bearing formation is treated with the comparative composition, and wherein the comparative composition is the same as the treatment composition except that the fluorinated acid is replaced with a salt of the fluorinated acid.

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