In Situ Fluid Formation for Cleaning Oil

8/3/2019 In Situ Fluid Formation for Cleaning Oil

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In Situ Fluid Formation for Cleaning Oil- or Synthetic-Oil-Based MudUnited States Patent Application 20080110618What is claimed is:

1. A method of cleaning oil-based mud (OBM) filter cake particles from a hydrocarbon reservoir wellbore

comprising: drilling a wellbore in a hydrocarbon reservoir with an OBM; forming a filter cake of OBMparticles over at least part of the wellbore; contacting the OBM and filter cake with at least one surfactant

and a polar liquid to form in situ an in-situ fluid selected from the group consisting of a miniemulsion, a

nanoemulsion, a microemulsion in equilibrium with excess oil or water or both (Winsor III) and a single

phase microemulsion (Winsor IV), and thereby incorporating at least a portion of the oil in the filter cake

particles into the in-situ fluid.

2. The method of claim 1 where the at least one surfactant is selected from the group consisting of non-

ionic surfactants, anionic surfactants, cationic surfactants and amphoteric surfactants, surfactants

containing a non-ionic spacer-arm central extension and an ionic or nonionic polar group, and mixtures

thereof.

3. The method of claim 2 where in the surfactants, the nonionic surfactants are selected from the group

consisting of alkyl polyglycosides, sorbitan esters, amine ethoxylates, diamine ethoxylates, methyl

glucoside esters, polyglycerol esters, alkyl ethoxylates, alcohol that have been polypropoxylated

and/or ethoxylated; the anionic surfactants are selected from the group consisting of alkali metal alkyl

sulfates, alkyl or alkylaryl sulfonates, linear or branched alkyl ether sulfates and sulfonates, alcohol

polypropoxylated and/or polyethoxylated sulfates, alkyl or alkylaryl disulfonates, alkyl disulfates, alkyl

sulphosuccinates, alkyl ether sulfates, linear and branched ether sulfates; the cationic surfactants are

selected from the group consisting of arginine methyl esters, alkanolamines, and alkylenediamides, and

mixtures thereof, and surfactants containing a non-ionic spacer-arm central extension and an ionic or

nonionic polar group.

4. The method of claim 1 where the in-situ fluid further comprises brine containing salts selected from the

group consisting of inorganic salts, organic salts and combinations thereof.

5. The method of claim 1 where the in-situ fluid is a thermodynamically stable, macroscopically

homogeneous mixture of at least three components, where the three components comprise: a polar phase

from the polar liquid, a nonpolar phase from the OBM or filter cake and the at least one surfactant.

6. The method of claim 1 where the filter cake particles are selected from the group consisting of calcium

carbonate, hematite, ilmenite, magnesium tetroxide, manganous oxide, iron carbonate, magnesium oxide,

barium sulfate, and mixtures thereof.

7. The method of claim 1 where the in-situ fluid further comprises an acid selected from the group

consisting of mineral acids and organic acids.

8. The method of claim 7 further comprising generating the acid in situ.


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9. A method of cleaning oil-based mud (OBM) filter cake particles from a hydrocarbon reservoir wellbore

comprising: drilling a wellbore in a hydrocarbon reservoir with an OBM; forming a filter cake of OBM

particles over at least part of the wellbore; pumping into the wellbore a gravel pack carrier brine

comprising: sized gravel, at least one surfactant, and a polar liquid; placing a gravel pack into the

wellbore; contacting the OBM and filter cake with the gravel pack carrier brine to form in situ an in-situ

fluid selected from the group consisting of a miniemulsion, a nanoemulsion, a microemulsion, and asingle phase microemulsion, and thereby incorporating at least a portion of the oil from the OBM into the

in-situ fluid by solubilization without circulating the well; changing the wettability of the filter cake

particles from oil-wet to water-wet allowing the in-situ fluid to contact the filter cake for a period of time

as a soak solution; and removing a majority of the filter cake particles.




thereof.



glucoside esters, polyglycerol esters, alkyl ethoxylates, alcohol that have been polypropoxylated and/or

ethoxylated; the anionic surfactants are selected from the group consisting of alkali metal alkyl sulfates,

alkyl or alkylaryl sulfonates, linear or branched alkyl ether sulfates and sulfonates, alcohol






12. The method of claim 9 where the in-situ fluid further comprises brine containing salts selected from

the group consisting of inorganic salts, organic salts and combinations thereof.

13. The method of claim 9 where the in-situ fluid is a thermodynamically stable, macroscopically

homogeneous mixture.

14. The method claim 9 where the filter cake particles are selected from the group consisting of calcium

carbonate, hematite, ilmenite, magnesium tetroxide, manganous oxide, iron carbonate, magnesium oxide,

barium sulfate, and mixtures thereof.

15. The method of claim 9 where the in-situ fluid further comprises an acid selected from the group

consisting of mineral acids and organic acids.

16. The method of claim 15 further comprising generating the acid in situ.

17. A method of cleaning oil-based mud (OBM) filter cake particles from a hydrocarbon reservoir

wellbore comprising: drilling a wellbore in a hydrocarbon reservoir with an OBM; forming a filter cake of


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OBM particles over at least part of the wellbore; contacting the OBM and filter cake with at least one

surfactant and a brine to form in situ an in-situ fluid selected from the group consisting of a miniemulsion,

a nanoemulsion, a microemulsion in equilibrium with excess oil or water or both (Winsor III) and a single

phase microemulsion (Winsor IV), and thereby incorporating at least a portion of the oil in the filter cake

particles into the in-situ fluid, where the in-situ fluid is a thermodynamically stable, macroscopically

homogeneous mixture of at least three components, where the three components comprise: brine, anonpolar phase from the OBM or filter cake and the at least one surfactant, and where the filter cake

particles are selected from the group consisting of calcium carbonate, hematite, ilmenite, magnesium

tetroxide, manganous oxide, iron carbonate, magnesium oxide, barium sulfate, and mixtures thereof.




thereof.



glucoside esters, polyglycerol esters, alkyl ethoxylates, alcohol that have been polypropoxylated and/or

ethoxylated; the anionic surfactants are selected from the group consisting of alkali metal alkyl sulfates,







20. The method of claim 17 where the in-situ fluid further comprises an acid selected from the groupconsisting of mineral acids and organic acids.


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IN SITU MICROEMULSIONS USED AS SPACER FLUIDSUnited States Patent Application 20080274918

What is claimed is:

1. A method of removing at least a portion of oil-based mud or synthetic-based mud (O/SBM) from a

wellbore comprising: drilling a wellbore in a hydrocarbon reservoir with an O/SBM; pumping a fluid pill

into the wellbore, where the fluid pill comprises: at least one surfactant; at least one viscosifier; and water

or brine; forming an emulsion in situ in the wellbore; and contacting the O/SBM and removing at least a

portion of the O/SBM from the wellbore.




thereof.

3. The method of claim 2 where: the nonionic surfactants are selected from the group consisting of alkyl

polyglycosides, sorbitan esters, methyl glucoside esters, alcohol ethoxylates, and polyglycol esters; the

anionic surfactants are selected from the group consisting of alkali metal alkyl sulfates, alkyl or alkylaryl

sulfonates, linear or branched alkyl ether sulfates and sulfonates, alcohol polypropoxylated and/or

polyethoxylated sulfates, alkyl or alkylaryl disulfonates, alkyl disulfates, alkyl sulphosuccinates, alkyl

ether sulfates, linear and branched ether sulfates; and the cationic surfactants are selected from the group

consisting of arginine methyl esters, alkanolamines, and alkylenediamides, and mixtures thereof.

4. The method of claim 1 where the water in the fluid pill comprises brine selected from the group

consisting of halide brines, formate brines and mixtures thereof.

5. The method of claim 1 where the in situ emulsion is a macroscopically homogeneous mixture of at

least four components, where the four components comprise a polar phase from the water or brine, a

nonpolar phase from the O/SBM, the at least one viscosifier and the at least one surfactant.

6. The method of claim 1 further comprising pumping a cement slurry into the wellbore subsequent to

forming the emulsion in situ.

7. The method claim 1 where the emulsion is selected from the group consisting of miniemulsions,

microemulsions, nanoemulsions, and single phase emulsions.

8. The method of claim 1 where the fluid pill is a first fluid pill that is a drive weighted spacer

comprising: at least one weighting agent; the at least one surfactant; the at least one viscosifer; and the

water or brine; and the method further comprises pumping a second fluid pill into the wellbore subsequent

to the first fluid pill, where the second fluid pill comprises: at least one surfactant; and water or brine.

9. A method of removing at least a portion of oil-based mud or synthetic-based mud (O/SBM) from a


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wellbore comprising: drilling a wellbore in a hydrocarbon reservoir with an O/SBM; pumping a first fluid

pill into the wellbore, where the first fluid pill is a drive weighted spacer comprising: at least one

weighting agent; at least one surfactant; at least one viscosifer; and water or brine; pumping a second

fluid pill into the wellbore subsequent to the first fluid pill, where the second fluid pill comprises: at least

one surfactant; and water or brine; forming a single phase microemulsion (SPME) in situ in the wellbore;

and contacting the O/SBM and substantially removing at least a portion of the O/SBM from the wellbore.




thereof.

11. The method of claim 10 where: the nonionic surfactants are selected from the group consisting of

alkyl polyglycosides, sorbitan esters, methyl glucoside esters, alcohol ethoxylates, and polyglycol esters;

the anionic surfactants are selected from the group consisting of alkali metal alkyl sulfates, alkyl or

alkylaryl sulfonates, linear or branched alkyl ether sulfates and sulfonates, alcohol polypropoxylated

and/or polyethoxylated sulfates, alkyl or alkylaryl disulfonates, alkyl disulfates, alkyl sulphosuccinates,

alkyl ether sulfates, linear and branched ether sulfates; and the cationic surfactants are selected from the

group consisting of arginine methyl esters, alkanolamines, and alkylenediamides, and mixtures thereof.

12. The method of claim 9 where the water in the first and/or second fluid pill comprises brine.

13. The method of claim 9 where the in situ SPME is a macroscopically homogeneous mixture of at least

four components, where the four components comprise a polar phase from the water or brine, a nonpolar

phase from the O/SBM, the at least one viscosifier and the at least one surfactant.

14. The method claim 9 where the first fluid pill and/or second fluid pill further comprises an alkoxylatedalcohol co-surfactant.

15. The method of claim 9 further comprising pumping a cement slurry into the wellbore subsequent to

forming the emulsion in situ.

16. A thermodynamically stable, single phase microemulsion (SPME) comprising a polar phase, a

nonpolar phase, a polyglycerol ester surfactant and at least one viscosifier.

17. The SPME of claim 16 where the polar phase is water or brine.

18. The SPME of claim 16 where the polar phase is brine selected from the group consisting of halide

brines and formate brines.

19. The SPME of claim 16 where the nonpolar phase is selected from the group consisting of oil-based

mud, synthetic-based mud, residual oily debris, and combinations thereof.

20. The SPME of claim 16 further comprising a second surfactant selected from the group consisting of:


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nonionic surfactants selected from the group consisting of alkyl polyglycosides, sorbitan esters, methyl

glucoside esters, alcohol ethoxylates, and mixtures thereof; anionic surfactants selected from the group

consisting of alkali metal alkyl sulfates, alkyl or alkylaryl sulfonates, linear or branched alkyl ether

sulfates and sulfonates, alcohol polypropoxylated and/or polyethoxylated sulfates, alkyl or alkylaryl

disulfonates, alkyl disulfates, alkyl sulphosuccinates, alkyl ether sulfates, linear and branched ether

sulfates and mixtures thereof; and cationic surfactants selected from the group consisting of argininemethyl esters, alkanolamines, and alkylenediamides, and mixtures thereof.

21. The SPME of claim 20 where the second surfactant is an alkoxylated alcohol.

Single Phase Microemulsions and In Situ Microemulsions for Cleaning

Formation Damage

Abstract:


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Single phase microemulsions (SPMEs) and in situ-formed microemulsions may be used to clean

up and remove non-polar materials from reservoir production zones of oil and gas wells. Thisclean up occurs by solubilization of the non-polar material into the microemulsion when the

treatment fluid contacts the non-polar material. An in situ microemulsion may be formed when

one or more surfactant and a polar phase (e.g. water or brine), and eventually some small amount

of organic phase, contacts the reservoir formation and solubilizes the non-polar materialencountered in the porous media. The microemulsions are effective for removing the formation

damage caused by non-polar materials which include, but are not necessarily limited to oil-based

mud, synthetic-based mud, paraffins, asphaltenes, emulsions, slugs, and combinations thereof.

Claims:

1. A method of removing at least a portion of non-polar material from a subterranean reservoir

containing non-polar material, the method comprising:pumping a cleaning fluid into the

subterranean reservoir to contact the cleaning fluid with the non-polar material, where the

cleaning fluid comprises components selected from the group consisting of:a single-phase

microemulsion (SPME), which comprises:at least one surfactant;at least one non-polar fluid;andat least one polar fluid; andin situ emulsion-forming components comprising:at least one

surfactant; andat least one polar fluid;incorporating at least part of the non-polar material into anemulsion selected from the group consisting of the SPME and an emulsion formed in situ in the

subterranean reservoir; andremoving the emulsion incorporating the non-polar material from the

subterranean reservoir.

2. The method of claim 1 where the at least one surfactant is selected from the group consisting

of non-ionic surfactants, anionic surfactants, cationic surfactants and amphoteric surfactants,

extended surfactants containing a non-ionic spacer-arm central extension and an ionic ornonionic polar group, and mixtures thereof.

3. The method of claim 2 where in the surfactants:the nonionic surfactants are selected from thegroup consisting of alkyl polyglycosides, sorbitan esters, methyl glucoside esters, polyglycol

esters, and alcohol ethoxylates;the anionic surfactants are selected from the group consisting of

alkali metal alkyl sulfates, alkyl or alkylaryl sulfonates, linear or branched alkyl ether sulfates

and sulfonates, alcohol polypropoxylated and/or polyethoxylated sulfates, alkyl or alkylaryldisulfonates, alkyl disulfates, alkyl sulphosuccinates, alkyl ether sulfates, linear and branched

ether sulfates; andthe cationic surfactants are selected from the group consisting of arginine

methyl esters, alkanolamines, and alkylenediamines, extended surfactants with propoxylated orethoxylated spacer arms, and mixtures thereof.

4. The method of claim 1 where the at least one polar fluid further comprises brine.

5. The method of claim 1 where the in situ emulsion-forming components further comprise a

non-polar fluid and/or a fluid of intermediate polarity.

6. The method of claim 1 where the SPME or the in situ-formed emulsion is athermodynamically stable, macroscopically homogeneous mixture of at least three components,

where the three components are: a polar phase from the polar fluid, a non-polar phase from the


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non-polar fluid and/or the non-polar material, and the at least one surfactant.

7. The method of claim 1 where the cleaning fluid further comprises a component selected from

the group consisting of acids, oxidizing agents, water-soluble enzymes, barite dissolvers,

precursors to these components, and combinations thereof.

8. The method of claim 1 where the surfactant in the cleaning fluid is an ionic surfactant and the

cleaning fluid further comprises a co-surfactant.

9. The method of claim 8 where the co-surfactant is a surface active substance selected from the

group consisting of mono or poly-alcohols, low molecular weight organic acids or amines,

polyethylene glycol, low ethoxylation solvents and mixtures thereof.


containing non-polar material, the method comprising:pumping a cleaning fluid into the

subterranean reservoir to contact the cleaning fluid with the non-polar material, where the

cleaning fluid comprises components selected from the group consisting of:a single-phasemicroemulsion (SPME), which comprises:at least one surfactant;at least one non-polar fluid;

andat least one polar brine; andin situ emulsion-forming components comprising:at least onesurfactant; andat least one polar brine;incorporating at least part of the non-polar material into an

emulsion selected from the group consisting of the SPME and an emulsion formed in situ in the

subterranean reservoir; andremoving the emulsion incorporating the non-polar material from thesubterranean reservoir,where the SPME or the in situ-formed emulsion is a thermodynamically

stable, macroscopically homogeneous mixture of at least three components; and where the three

components are: a polar phase from the polar fluid, a non-polar phase from the non-polar fluid

and/or the non-polar material, and the at least one surfactant.

11. The method of claim 10 where the at least one surfactant is selected from the group

consisting of non-ionic surfactants, anionic surfactants, cationic surfactants and amphoteric

surfactants, extended surfactants containing a non-ionic spacer-arm central extension and anionic or nonionic polar group, and mixtures thereof.

12. The method of claim 11 where in the surfactants:the nonionic surfactants are selected fromthe group consisting of alkyl polyglycosides, sorbitan esters, methyl glucoside esters, polyglycol

esters, and alcohol ethoxylates;the anionic surfactants are selected from the group consisting of

alkali metal alkyl sulfates, alkyl or alkylaryl sulfonates, linear or branched alkyl ether sulfatesand sulfonates, alcohol polypropoxylated and/or polyethoxylated sulfates, alkyl or alkylaryl

disulfonates, alkyl disulfates, alkyl sulphosuccinates, alkyl ether sulfates, linear and branched

ether sulfates; andthe cationic surfactants are selected from the group consisting of arginine

methyl esters, alkanolamines, and alkylenediamines, extended surfactants with propoxylated orethoxylated spacer arms, and mixtures thereof.

13. The method of claim 10 where the cleaning fluid further comprises a component selectedfrom the group consisting of acids, oxidizing agents, water-soluble enzymes, barite dissolvers,

precursors to these components, and combinations thereof.


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15. The method of claim 10 where the surfactant in the cleaning fluid is an ionic surfactant and

the cleaning fluid further comprises a co-surfactant.

16. The method of claim 15 where the co-surfactant is a surface active substance selected from

the group consisting of mono or poly-alcohols, low molecular weight organic acids or amines,

polyethylene glycol, low ethoxylation solvents and mixtures thereof.

17. The method of claim 10 where the non-polar material is selected from the group consisting of

oil-based mud, synthetic-based mud, paraffins, aromatic hydrocarbons, asphaltenes, emulsions,slugs, and combinations thereof.


that contains non-polar material, the method comprising:pumping a cleaning fluid into the

subterranean reservoir to contact the cleaning fluid with the non-polar material, where thecleaning fluid comprises components selected from the group consisting of:a single-phase

microemulsion (SPME), which comprises:at least one surfactant;at least one non-polar fluid;andat least one polar brine; andin situ emulsion-forming components comprising:at least one

surfactant; andat least one polar brine;where the at least one surfactant is selected from the group

consisting of non-ionic surfactants, anionic surfactants, cationic surfactants and amphotericsurfactants, extended surfactants containing a non-ionic spacer-arm central extension and an

ionic or nonionic polar group, and mixtures thereof; andwhere the non-polar material is selected

from the group consisting of oil-based mud, synthetic-based mud, paraffins, aromatic

hydrocarbons, asphaltenes, emulsions, slugs, and combinations thereof;incorporating at least partof the non-polar material into an emulsion selected from the group consisting of the SPME and

an emulsion formed in situ in the subterranean reservoir; andremoving the emulsion

incorporating the non-polar material from the subterranean reservoir.



20. The method of claim 18 where the surfactant in the cleaning fluid is an ionic surfactant and

the cleaning fluid further comprises a co-surfactant.

Mesophase Fluids with Extended Chain Surfactants for Downhole TreatmentsUnited States Patent Application 20090183877What is claimed is:

1. A method of treating non-polar material in a wellbore and/or subterranean reservoir containing non-

polar material, the method comprising: introducing a mesophase fluid into the wellbore and/or

subterranean reservoir to contact the mesophase fluid with the non-polar material, where the mesophase


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fluid comprises components selected from the group consisting of: a pre-formed mesophase fluid which

comprises: at least one extended chain surfactant; at least one non-polar fluid; and at least one polar fluid;

and in situ mesophase fluid-forming components comprising: at least one extended chain surfactant; and

at least one polar fluid.

2. The method of claim 1 where the extended chain surfactant is selected from the group consistingof extended surfactants with a propoxylated spacer arm having from 2 to 20 propoxy moieties and

an ethoxylated spacer arm having from 0 to 20 ethoxy moieties.

3. The method of claim 2 where the extended chain surfactant has a lipophilic moiety selected from the

group consisting of linear or branched, saturated or unsaturated hydrocarbon chains having from 8 to 50

carbon atoms.

4. The method of claim 2 where the extended chain surfactant has a hydrophilic polar head selected from

the group consisting of polyoxyethylene, sulfate, ethoxysulfate, carboxylate, ethoxy-carboxylate, C6

sugar, xylitol, di-xylitol, ethoxy-xylitol, carboxylate and xytol, carboxylate and glucose.

5. The method of claim 2 where the extended chain surfactant has a lipophilic spacer arm and a

hydrophilic polar head, where the extended chain surfactant does not precipitate in the mesophase fluid.

6. The method of claim 1 where the extended chain surfactant is present in a concentration from

about 0.1% w/w to about 20% w/w.

7. The method of claim 1 where the in situ mesophase fluid-forming components further comprise a non-

polar fluid and/or a fluid of intermediate polarity.

8. The method of claim 1 where the mesophase fluid further comprises at least one additional surfactantselected from the group consisting of a non-extended chain surfactant, a co-surfactant, and combinations

thereof.

9. The method of claim 8 where the co-surfactant is a surface active substance selected from the group

consisting of mono or poly-alcohols, low molecular weight organic acids or amines, polyethylene glycol,

low ethoxylation solvents and mixtures thereof.

10. The method of claim 1 further comprising a procedure selected from the group consisting of:

removing at least a portion of non-polar material from a subterranean reservoir containing the non-polar

material by incorporating at least part of the non-polar material into a mesophase fluid selected from the

group consisting of the pre-formed mesophase fluid and the mesophase fluid formed in situ in the

subterranean reservoir, and removing the mesophase fluid incorporating the non-polar material from the

subterranean reservoir; introducing the mesophase fluid into the subterranean reservoir as a fluid pill,

where the fluid pill is selected from the group consisting of a water-wetting pill, a drive-weighted spacer,

and combinations thereof; releasing a stuck drill string; and combinations thereof.



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fluid comprises components selected from the group consisting of: a pre-formed mesophase fluid which

comprises: at least one extended chain surfactant; at least one non-polar fluid; and at least one polar fluid;

and in situ mesophase fluid-forming components comprising: at least one extended chain surfactant; and

at least one polar fluid. where the extended chain surfactant is present in a concentration from about 0.1%w/w to about 20% w/w, and where the extended chain surfactant is selected from the group consisting of

extended surfactants with spacer arms having from 2 to 20 propoxy moieties, from 0 to 20 ethoxy

moieties, and combinations thereof.



carbon atoms.

13. The method of claim 11 where the extended chain surfactant has a hydrophilic polar head selected

from the group consisting of polyoxyethylene, sulfate, ethoxysulfate, carboxylate, ethoxy-carboxylate, C6

sugar, xylitol, di-xylitol, ethoxy-xylitol, carboxylate and xytol, carboxylate, and glucose.

14. The method of claim 11 where the extended chain surfactant has a lipophilic spacer arm and a

hydrophilic polar head, where the extended chain surfactant does not precipitate in the mesophase fluid.

15. The method of claim 11 where the in situ mesophase fluid-forming components further comprise a


16. The method of claim 11 where the mesophase fluid further comprises at least one additional surfactant

selected from the group consisting of a non-extended chain surfactant, a co-surfactant, and combinations

thereof.







fluid comprises components selected from the group consisting of: a pre-formed mesophase fluid, which

comprises: at least one extended chain surfactant; at least one non-polar fluid; and brine; and in situ

mesophase fluid-forming components comprising: at least one extended chain surfactant; and brine;

where the extended chain surfactant has a lipophilic spacer arm and a hydrophilic polar head, where the

extended chain surfactant does not precipitate in the mesophase cleaning fluid.

19. The method of claim 18 where the extended chain surfactant is selected from the group

consisting of extended surfactants with propoxylated and/or ethoxylated spacer arms.


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20. The method of claim 18 where the spacer arms contain alkoxy moieties selected from the group

consisting of from 2 to 20 propoxy moieties, from 0 to 20 ethoxy moieties, and combinations thereof.

21. The method of claim 18 where the extended chain surfactant is present in a concentration from about

0.1% w/w to about 20% w/w.



carbon atoms.

23. The method of claim 18 where the extended chain surfactant has a hydrophilic polar head selected

from the group consisting of polyoxyethylene, sulfate, ethoxysulfate, carboxylate, ethoxy-carboxylate, C6

sugar, xylitol, di-xylitol, ethoxy-xylitol, carboxylate and xytol, carboxylate, and glucose.

24. The method of claim 18 where the in situ mesophase fluid-forming components further comprise a


25. The method of claim 18 where the mesophase fluid further comprises at least one additional surfactant

selected from the group consisting of a non-extended chain surfactant, a co-surfactant, and combinations

thereof.




METHOD FOR CHANGING THE WETTABILITY OF ROCK FORMATIONSUnited States Patent Application 20090325826

What is claimed is:

1. A method of changing the wettability of a rock formation previously contacted with an oil-based mud

(OBM), the method comprising: pumping a water-wetting pill into the rock formation, where the water-

wetting pill is selected from the group consisting of: a composition selected from the group consisting of

a miniemulsion, a nanoemulsion, an emulsion, and a microemulsion, which composition comprises: at

least one surfactant; at least one non-polar fluid; and at least one polar fluid; and in situ emulsion-forming

components comprising: at least one surfactant; and at least one polar fluid; thereby contacting the rock

formation with the composition and or the in situ-formed emulsion, where in at least the case of the in situ

emulsion-forming components, at least some of the first non-polar fluid is incorporated into the in situ-

formed emulsion; changing the wettability of at least part of the rock formation to water-wet; and

subsequently pumping a second pill into the rock formation where the subsequent pill comprises water.

2. The method of claim 1 where the second pill is selected from the group consisting of fluid loss pills,


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crosslink pills, reservoir rock cleaning pills, horizontal healing pills and combinations thereof.


ionic surfactants, anionic surfactants, cationic surfactants, amphoteric surfactants, fluorocarbon

surfactants, silicon surfactants, cleavable, gemini surfactants, and extended surfactants containing a non-

ionic spacer-arm central extension and an ionic or nonionic polar group, and mixtures thereof.

4. The method of claim 3 where in the surfactants: the nonionic surfactants are selected from the

group consisting of alkyl polyglycosides, sorbitan esters, methyl glucoside esters, polyglycol esters,

and alcohol ethoxylates; the anionic surfactants are selected from the group consisting of alkali metal

alkyl sulfates, alkyl or alkylaryl sulfonates, linear or branched alkyl ether sulfates and sulfonates, alcohol



selected from the group consisting of arginine methyl esters, alkanolamines, and alkylenediamides; and

the extended chain surfactants comprise propoxylated and/or ethoxylated spacer arms, and mixtures

thereof.

5. The method of claim 1 where at least one polar fluid further comprises brine.

6. The method of claim 1 where the in situ emulsion-forming components further comprise a fluid

selected from the group consisting of a non-polar fluid, a fluid of intermediate polarity and mixtures

thereof.

7. The method of claim 1 where the compositions and/or the in situ-formed emulsion is a

thermodynamically stable, macroscopically homogeneous mixture of at least three components, where the

three components comprise a polar phase from the polar fluid, a non-polar phase at least partially from the

first non-polar fluid of the OBM, and the at least one surfactant.

8. The method of claim 1 where the surfactant in the water-wetting pill is an ionic surfactant and the

water-wetting pill further comprises a co-surfactant.




10. The method of claim 1 where the water wetting pill further comprises an acid.



wetting pill is selected from the group consisting of: a single-phase microemulsion (SPME), which

comprises: at least one surfactant; at least one non-polar fluid; and at least one polar brine fluid; and in

situ emulsion-forming components comprising: at least one surfactant; and at least one polar brine fluid;

thereby contacting the rock formation with the SPME and/or the in situ-formed emulsion, where the

SPME and/or the in situ-formed emulsion is a thermodynamically stable, macroscopically homogeneous


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mixture of at least three components, where the three components comprise a polar phase from the polar

fluid, a non-polar phase at least partially from the first non-polar fluid of the OBM, and the at least one

surfactant; changing the wettability of at least part of the rock formation to water-wet; and subsequently

pumping a second pill into the rock formation where the subsequent pill comprises water.

12. The method of claim 11 where the second pill is selected from the group consisting of fluid losspills, crosslink pills, horizontal healer pills, reservoir rock cleaning pills and combinations thereof.

13. The method of claim 11 where the at least one surfactant is selected from the group consisting of

non-ionic surfactants, anionic surfactants, cationic surfactants, amphoteric surfactants,

fluorocarbon surfactants, silicon surfactants, cleavable, gemini surfactants, and extended

surfactants containing a non-ionic spacer-arm central extension and an ionic or nonionic polar

group, and mixtures thereof.

14. The method of claim 13 where in the surfactants: the nonionic surfactants are selected from the group

consisting of alkyl polyglycosides, sorbitan esters, methyl glucoside esters, polyglycol esters, and alcohol

ethoxylates; the anionic surfactants are selected from the group consisting of alkali metal alkyl sulfates,






thereof.



thereof.








wetting pill is selected from the group consisting of: a composition selected from the group consisting of

a miniemulsion, a nanoemulsion, an emulsion, and a microemulsion, which composition comprises: at

least one surfactant; at least one non-polar fluid; and at least one polar fluid; and in situ emulsion-forming

components comprising: at least one surfactant; and at least one polar fluid; thereby contacting the rock

formation with the composition and or the in situ-formed emulsion, where in at least the case of the in situ

emulsion-forming components, at least some of the first non-polar fluid is incorporated into the in situ-

formed emulsion; changing the wettability of at least part of the rock formation to water-wet; and


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subsequently pumping a second pill into the rock formation where the subsequent pill comprises water,

the second pill being selected from the group consisting of fluid loss pills, crosslink pills, reservoir rock

cleaning pills, horizontal healing pills and combinations thereof; where the at least one surfactant is

selected from the group consisting of non-ionic surfactants, anionic surfactants, cationic surfactants,

amphoteric surfactants, fluorocarbon surfactants, silicon surfactants, cleavable, gemini surfactants, and

extended surfactants containing a non-ionic spacer-arm central extension and an ionic or nonionic polargroup, and mixtures thereof.

19. The method of claim 18 where in the surfactants: the nonionic surfactants are selected from the group

consisting of alkyl polyglycosides, sorbitan esters, methyl glucoside esters, polyglycol esters, and alcohol

ethoxylates; the anionic surfactants are selected from the group consisting of alkali metal alkyl sulfates,






thereof.



thereof.




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NANOEMULSIONSUnited States Patent Application 20100137168

What is claimed is:

1. A nanoemulsion composition comprising: (1) a continuous phase, (2) a discontinuous phase with a

mean droplet size of less than 1000 nm, (3) a surfactant, and (4) a solid weighting agent; wherein, one of

the phases (1) and (2) is a non-polar based phase and the other of these is a polar based phase.

2. The nanoemulsion composition of claim 1, wherein the mean droplet size of the discontinuous phase is

less than 400 nm, the non-polar based phase is an oil phase and the polar based phase is an aqueous phase.

3. The nanoemulsion composition of claim 2, wherein the solid weighting agent is selected from the

group consisting of barium sulfate, calcium carbonate, hematite, ilmenite, siderite, manganese tetraoxide

and combinations thereof.

4. The nanoemulsion composition of claim 2, wherein the aqueous phase comprises water and a dissolved

salt, the dissolved salt being different from the material chosen for the surfactant (3) and for the solid

weighting agent (4).

5. The nanoemulsion composition of claim 4, wherein the dissolved salt in the aqueous phase is selected

from the group consisting of: a chloride of sodium, potassium, calcium, silver, cobalt, nickel, copper, zinc

or iron; a bromide of sodium, potassium, calcium, silver, cobalt, nickel, copper, zinc or iron; a sulfate of

sodium, potassium, calcium, silver, cobalt, nickel, copper, zinc or iron; a phosphate of sodium, potassium,

calcium, silver, cobalt, nickel, copper, zinc or iron; a formate of sodium, potassium, cesium or other

cation; an ammonium salt; and combinations thereof.

6. The nanoemulsion composition of claim 2, further comprising a cosurfactant, where the co-surfactant is

different from the material chosen for the surfactant (3) and for the solid weighting agent (4) and is

selected from the group consisting of a mono-alcohol, a poly-alcohol, an organic acid, a salt of an organic

acid, an amine, a polyethylene glycol, an ethoxylated solvent and combinations thereof.

7. The nanoemulsion composition of claim 1, wherein the surfactant (3) is selected from the group

consisting of an anionic surfactant selected from the group consisting of alkali metal alkyl sulfates, alkyl

ether sulfonates, alkyl sulfonates, alkylaryl sulfonates, linear and branched alkyl ether sulfates and

sulfonates, alcohol polypropoxylated sulfates, alcohol polyethoxylated sulfates, alcohol polypropoxylated

polyethoxylated sulfates, alkyl disulfonates, alkylaryl disulfonates, alkyl disulfates, alkyl sulfosuccinates,alkyl ether sulfates, linear and branched ether sulfates, alkali metal carboxylates, fatty acid carboxylates,

and phosphate esters; a nonionic surfactant selected from the group consisting of amides, diamides,

polyglycol esters, alkyl polyglycosides, sorbitan esters, methyl glucoside esters and alcohol ethoxylates; a

cationic surfactant selected from the group consisting of arginine methyl esters, alkanolamines and

alkylenediamines; a surfactant containing a non-ionic spacer-arm central extension and an ionic or

nonionic polar group, wherein the non-ionic spacer-arm central extension results from a process selected


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from the group consisting of polypropoxylation, polyethoxylation and both; and dimeric surfactants,

gemini surfactants, cleavable surfactants and fluorinated surfactants; and combinations thereof.

8. A method comprising: introducing a nanoemulsion into a wellbore where the nanoemulsion comprises:

(1) a continuous phase, (2) a discontinuous phase with a mean droplet size of less than 1000 nm, and (3) a

surfactant, wherein, one of the phases (1) and (2) is a non-polar based phase and the other of these is apolar based phase; and a further procedure selected from the group consisting of: drilling a wellbore using

a fluid comprising the nanoemulsion; completing a well using a fluid comprising the nanoemulsion;

remediating a subterranean formation, other than by acidizing, using a fluid comprising the

nanoemulsion; stimulating a subterranean formation using a fluid comprising the nanoemulsion;

fracturing a subterranean formation using a fluid comprising the nanoemulsion; and combinations thereof.

9. The method of claim 8 where the nanoemulsion further comprises (4) a solid weighting agent.

10. The method of claim 9, where in the nanoemulsion, the solid weighting agent is selected from the



11. The method of claim 8, where in the nanoemulsion, the mean droplet size of the discontinuous phase

is less than 400 nm, the non-polar based phase is an oil phase and the polar based phase is an aqueous

phase.

12. The method of claim 11, where in the nanoemulsion, the aqueous phase comprises water and a

dissolved salt, the dissolved salt being different from the material chosen for the surfactant (3) and for the

solid weighting agent (4).

13. The method of claim 12, wherein the dissolved salt in the aqueous phase is selected from the groupconsisting of: a chloride of sodium, potassium, calcium, silver, cobalt, nickel, copper, zinc or iron; a

bromide of sodium, potassium, calcium, silver, cobalt, nickel, copper, zinc or iron; a sulfate of sodium,

potassium, calcium, silver, cobalt, nickel, copper, zinc or iron; a phosphate of sodium, potassium,


cation; an ammonium salt; and combinations thereof.

14. The method of claim 8, where the nanoemulsion further comprises a cosurfactant, where the co-

surfactant is different from the material chosen for the surfactant (3) and for the solid weighting agent (4)

and is selected from the group consisting of a mono-alcohol, a poly-alcohol, an organic acid, a salt of an

organic acid, an amine, a polyethylene glycol, an ethoxylated solvent and combinations thereof.

15. The method of claim 8, where in the nanoemulsion the surfactant (3) is selected from the group

consisting of an anionic surfactant selected from the group consisting of alkali metal alkyl sulfates, alkyl

ether sulfonates, alkyl sulfonates, alkylaryl sulfonates, linear and branched alkyl ether sulfates and

sulfonates, alcohol polypropoxylated sulfates, alcohol polyethoxylated sulfates, alcohol polypropoxylated

polyethoxylated sulfates, alkyl disulfonates, alkylaryl disulfonates, alkyl disulfates, alkyl sulfosuccinates,

alkyl ether sulfates, linear and branched ether sulfates, alkali metal carboxylates, fatty acid carboxylates


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and phosphate esters; a nonionic surfactant selected from the group consisting of amides, diamides,

polyglycol esters, alkyl polyglycosides, sorbitan esters, methyl glucoside esters and alcohol ethoxylates; a

cationic surfactant selected from the group consisting of arginine methyl esters, alkanolamines and

alkylenediamines; a surfactant containing a non-ionic spacer-arm central extension and an ionic or

nonionic polar group, wherein the non-ionic spacer-arm central extension results from a process selected

from the group consisting of polypropoxylation, polyethoxylation and both; dimeric surfactants, geminisurfactants, cleavable surfactants, fluorinated surfactants; and combinations thereof.

16. The method of claim 9 where the fluid has an improved property selected from the group consisting of

reduced friction pressure loss, reduced weighting agent subsidence and both, as compared with an

otherwise identical fluid absent the nanoemulsion.

17. A method comprising drilling a wellbore using a drilling fluid comprising a nanoemulsion where the

nanoemulsion comprises: (1) a continuous phase, (2) a discontinuous phase with a mean droplet size of

less than 400 nm, and (3) a surfactant, (4) a solid weighting agent; wherein, one of the phases (1) and (2)

is a non-polar based phase and the other of these is a polar based phase.

18. The method of claim 17, where in the nanoemulsion, the solid weighting agent is selected from the



19. The method of claim 17, where in the nanoemulsion, the polar based phase comprises water and a

dissolved salt, the dissolved salt being different from the material chosen for the surfactant (3) and for the

solid weighting agent (4).

20. The method of claim 17, where the nanoemulsion further comprises a cosurfactant, where the co-

surfactant is different from the material chosen for the surfactant (3) and for the solid weighting agent (4)and is selected from the group consisting of a mono-alcohol, a poly-alcohol, an organic acid, a salt of an

organic acid, an amine, a polyethylene glycol, an ethoxylated solvent and combinations thereof.

21. A method of making a nanoemulsion composition comprising: (1) mixing a group of components

comprising an oil and a surfactant, (2) adding an aqueous salt solution to the result of (1) with mixing, (3)

mixing the result of (2), (4) adding more of the aqueous salt solution to the result of (3) while mixing, and

(5) mixing the result of (4).

22. The method of claim 21, wherein the group of components of (1) further comprises a co-surfactant.

23. The method of claim 22, wherein the aqueous salt solution comprises a salt that is selected from the

group consisting of: a chloride of sodium, potassium, calcium, silver, cobalt, nickel, copper, zinc or iron;

a bromide of sodium, potassium, calcium, silver, cobalt, nickel, copper, zinc or iron; a sulfate of sodium,

potassium, calcium, silver, cobalt, nickel, copper, zinc or iron; a phosphate of sodium, potassium,


cation; ammonium chloride, bromide, sulfate, phosphate, formate; an ammonium salt; and combinations

thereof; with the proviso that the average weight percentage of the salt in the aqueous salt solution is at


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least one-tenth of the weight percentage of this salt in water at 25 C. at maximum solubility.

24. The method of claim 21, further comprising adding a solid weighting agent to the result of (5).

25. The method of claim 21, wherein the adding with mixing of (2) occurs until the viscosity of the

composition of (2) reaches a viscosity of at least about 275 cP when measured at a shear rate of 500/s at25 C.; and the mixing of (3) occurs until the viscosity of the composition of (3) drops below about 20 cP

when measured at a shear rate of 500/s at 25 C.

26. The nanoemulsion composition produced by the method of claim 21.

MICROEMULSIONS TO CONVERT OBM FILTER CAKES TO WBM

FILTER CAKES HAVING FILTRATION CONTROLUnited States Patent Application 20100216671What is claimed is:

1. A thermodynamically stable, macroscopically homogeneous, single phase microemulsion (SPME)

comprising: a polar phase; a nonpolar phase; a surfactant; and a water-soluble filtration control additive

selected from the group consisting of solid particulates, polymers and mixtures thereof.

2. The SPME of claim 1 where the surfactant is selected from the group consisting of non-ionic

surfactants, anionic surfactant, cationic surfactants and amphoteric surfactants.

3. The SPME of claim 1 further comprising an acid selected from the group of inorganic acids consisting

of hydrochloric acid, sulfuric acid, and mixtures thereof, and organic acids consisting of acetic acid,

formic acid and salts of these organic acids, and mixtures of one or more of these acids.


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4. The SPME of claim 1 further comprising at least one polyamino carboxylic acid or salt thereof, where

the concentration of polyamino carboxylic acid or a salt thereof in the microemulsion ranges from 1 to 30

volume %.

5. The SPME of claim 1 where in the filtration control additive, the solid particulates are selected fromthe group consisting of sized salts, hematite, ilmenite, manganese tetroxide, and mixtures thereof, and

where the water-soluble polymers are selected from the group consisting of natural and synthetic

polymers and copolymers and mixtures thereof.

6. The SPME of claim 1 where the proportion of filtration control additive in the SPME ranges from

about 0.1 to about 10 lb/bbl.

7. The SPME of claim 1 where the nonpolar phase is selected from the group consisting of synthetic base

and mineral oils, ester fluids, paraffins, and isomerized olefins.


comprising: a polar phase; a nonpolar phase; a surfactant selected from the group consisting of non-ionic

surfactants, anionic surfactant, cationic surfactants and amphoteric surfactants; and from about 0.1 to

about 10 lb/bbl, based on the SPME, of a water-soluble filtration control additive selected from the group

consisting of solid particulates, polymers and mixtures thereof.

9. The SPME of claim 8 further comprising an acid selected from the group of inorganic acids consisting

of hydrochloric acid, sulfuric acid, and mixtures thereof, and organic acids consisting of acetic acid,

formic acid and salts of these organic acids, and mixtures of one or more of these acids.

10. The SPME of claim 8 further comprising at least one polyamino carboxylic acid or salt thereof, wherethe concentration of polyamino carboxylic acid or a salt thereof in the microemulsion ranges from 1 to 30

volume %.

11. The SPME of claim 8 where in the filtration control additive, the solid particulates are selected from

the group consisting of sized salts, hematite, ilmenite, manganese tetroxide, and mixtures thereof, and

where the water-soluble polymers are selected from the group consisting of natural and synthetic

polymers and copolymers and mixtures thereof.

12. The SPME of claim 8 where the nonpolar phase is selected from the group consisting of synthetic

base and mineral oils, ester fluids, paraffins, and isomerized olefins.


comprising: a polar phase; a nonpolar phase; a surfactant; and from about 0.1 to about 10 lb/bbl, based on

the SPME, of a water-soluble filtration control additive selected from the group consisting of sized salts,

hematite, ilmenite, manganese tetroxide, and mixtures thereof, and where the water-soluble polymers are

selected from the group consisting of natural and synthetic polymers and copolymers and mixtures

thereof.


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14. The SPME of claim 13 where the surfactant is selected from the group consisting of non-ionic

surfactants, anionic surfactant, cationic surfactants and amphoteric surfactants.

15. The SPME of claim 13 further comprising an acid selected from the group of inorganic acids

consisting of hydrochloric acid, sulfuric acid, and mixtures thereof, and organic acids consisting of aceticacid, formic acid and salts of these organic acids, and mixtures of one or more of these acids.

16. The SPME of claim 13 further comprising at least one polyamino carboxylic acid or salt thereof,

where the concentration of polyamino carboxylic acid or a salt thereof in the microemulsion ranges from

1 to 30 volume %.

17. The SPME of claim 13 where the nonpolar phase is selected from the group consisting of synthetic

base and mineral oils, ester fluids, paraffins, and isomerized olefins.

Documents

In Situ Fluid Formation for Cleaning Oil