WO2018169857A1 - Procédés et compositions incorporant un tensioactif alkyl polyglycoside destinés à être utilisés dans des puits de pétrole et/ou de gaz - Google Patents

Procédés et compositions incorporant un tensioactif alkyl polyglycoside destinés à être utilisés dans des puits de pétrole et/ou de gaz Download PDF

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Publication number
WO2018169857A1
WO2018169857A1 PCT/US2018/021983 US2018021983W WO2018169857A1 WO 2018169857 A1 WO2018169857 A1 WO 2018169857A1 US 2018021983 W US2018021983 W US 2018021983W WO 2018169857 A1 WO2018169857 A1 WO 2018169857A1
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Prior art keywords
microemulsion
composition
fluids
ppm
fluid
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PCT/US2018/021983
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English (en)
Inventor
Siwar Trabelsi
Randal M. Hill
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Flotek Chemistry, Llc
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Priority claimed from US15/457,792 external-priority patent/US10421707B2/en
Application filed by Flotek Chemistry, Llc filed Critical Flotek Chemistry, Llc
Priority to CA3056225A priority Critical patent/CA3056225C/fr
Publication of WO2018169857A1 publication Critical patent/WO2018169857A1/fr

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Classifications

    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/25—Methods for stimulating production
    • E21B43/26—Methods for stimulating production by forming crevices or fractures
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/25—Methods for stimulating production
    • E21B43/26—Methods for stimulating production by forming crevices or fractures
    • E21B43/27—Methods for stimulating production by forming crevices or fractures by use of eroding chemicals, e.g. acids

Definitions

  • compositions for Stimulating the Production of Hydrocarbons from Subterranean Compositions for Stimulating the Production of Hydrocarbons from Subterranean
  • compositions comprising an emulsion or a microemulsion for treating an oil and/or gas well are provided.
  • Emulsions and/or microemulsions are commonly employed in a variety of operations related to the extraction of hydrocarbons, such as well stimulation.
  • Subterranean formations are often stimulated to improve recovery of hydrocarbons.
  • Common stimulation techniques include hydraulic fracturing.
  • Hydraulic fracturing consists of the high pressure injection of a fluid containing suspended proppant into the wellbore in order to create fractures in the rock formation and facilitate production from low permeability zones. All chemicals pumped downhole in an oil and/or gas well can filter through the reservoir rock and block pore throats with the possibility of creating formation damage. It is well known that fluid invasion can significantly reduce hydrocarbon production from a well. In order to reduce fluid invasion, emulsions or microemulsions are generally added to the well-treatment fluids to help unload the residual aqueous treatment from the formation.
  • compositions comprising an emulsion or a microemulsion for use in treating an oil and/or gas well having a wellbore are provided.
  • a method of treating an oil and/or gas well having a wellbore comprising: injecting a fluid comprising an emulsion or a microemulsion into the wellbore, wherein the emulsion or the microemulsion comprises an aqueous phase; a surfactant comprising alkyl polyglycoside; a solvent selected from the group consisting of terpene, alkyl aliphatic carboxylic acid ester, and combinations thereof; and an alcohol selected from the group consisting of butanol, amyl alcohol, and combinations thereof.
  • a composition for use in an oil and/or gas well having a wellbore comprising a fluid and an emulsion or a microemulsion, wherein the emulsion or the microemulsion comprises an aqueous phase; a surfactant comprising alkyl polyglycoside; a solvent selected from the group consisting of terpene, alkyl aliphatic carboxylic acid ester, and combinations thereof; and an alcohol selected from the group consisting of butanol, amyl alcohol, and combinations thereof.
  • a microemulsion may comprise an aqueous phase, a solvent (e.g., terpene and/or methyl aliphatic carboxylic acid ester), a surfactant comprising alkyl polyglycoside ("APG"), an alcohol (e.g., an alcohol functioning as a co- solvent, such as butanol or amyl alcohol), and optionally other additives (e.g., a freezing point depression agent, a demulsifier, etc.).
  • a solvent e.g., terpene and/or methyl aliphatic carboxylic acid ester
  • APG alkyl polyglycoside
  • an alcohol e.g., an alcohol functioning as a co- solvent, such as butanol or amyl alcohol
  • additives e.g., a freezing point depression agent, a demulsifier, etc.
  • the methods and compositions relate to various aspects of the life cycle of an oil and/or gas well (e.g., fracturing fluids, drilling, mud displacement, casing, cementing, perforating, stimulation, remediation, kill fluids, enhanced oil recovery/improved oil recovery, etc.).
  • an emulsion or a microemulsion is added to a fluid utilized in the life cycle of a well thereby increasing hydrocarbon (e.g., liquid or gaseous) production of the well, improving recovery of the fluid and/or other fluids, and/or preventing or minimizing damage to the well caused by exposure to the fluid (e.g., from imbibition).
  • a method of treating an oil and/or gas well having a wellbore comprises injecting a fluid comprising an emulsion or a microemulsion into the wellbore.
  • Embodiments of the disclosed microemulsions overcome shortcomings of generally known microemulsions, which have been shown to be generally incompatible with a wide range of conditions. For example, many commonly used surfactants for microemulsions are useful only within a certain temperature range even though, in reality, oil field reservoirs vary widely in actual bottom hole or formation temperatures. Likewise, known compositions that form transparent microemulsions at surface temperatures may be well above their cloud point at bottom hole temperatures. Previous combinations of surfactants have been found to broaden the temperature range, but at the cost of compatibility with other components in the fluid system. Some common surfactants become insoluble in the high salinity brines often found in oil-bearing and gas-bearing formations.
  • Embodiments of the presently disclosed microemulsions may provide several advantages over previous microemulsions.
  • embodiments of the disclosed microemulsions are compatible with a wide range of water salinities (e.g., fresh, flowback and produced waters or mixtures thereof) and temperatures. This range of compatibility may prevent the microemulsion from undergoing phase separation during use which, in some circumstances, could decrease the microemulsion' s efficacy.
  • the disclosed emulsions or microemulsions are able to lower capillary pressure and promote unloading at higher temperatures when used in applications where a wide range of temperatures and/or salinities may be encountered, such as multi-stage hydraulic fracturing in horizontal, lateral, or deviated wells, which may require millions of gallons of water per well.
  • the disclosed emulsions and microemulsions facilitate unloading of the aqueous treatment fluid from deep in the formation.
  • emulsions and microemulsions disclosed herein provide for high performance in these and other difficult conditions, using renewable plant-based materials in a simple composition with a minimum number of components.
  • an emulsion or a microemulsion comprises an aqueous phase, a solvent, a surfactant, and an alcohol (which may function as a co-solvent).
  • the emulsion or the microemulsion further comprises additional additives. Details of each of the components of the emulsions or the microemulsions are described in detail herein. In disclosed embodiments, the components of the emulsions or the
  • microemulsions are selected so as to provide a desired performance over a wide range of temperatures and salinities.
  • the emulsion or the microemulsion comprises an aqueous phase; a solvent comprising terpene (e.g., d-limonene) and/or alkyl aliphatic carboxylic acid ester (e.g., methyl aliphatic carboxylic acid ester, also referred to as methyl ester); a surfactant comprising alkyl polyglycoside; and an alcohol (e.g., butanol and/or amyl alcohol).
  • the alcohol may function as a co-solvent.
  • the terpene comprises d-limonene.
  • the alkyl aliphatic carboxylic acid ester comprises methyl ester.
  • the alcohol comprises butanol and/or amyl alcohol.
  • the emulsion or the microemulsion comprises an aqueous phase; a solvent comprising d-limonene and/or methyl ester; a surfactant comprising alkyl polyglycoside; and an alcohol comprising butanol and/or amyl alcohol.
  • additives may be added to the emulsion or microemulsion.
  • the emulsion or the microemulsion may comprise a freezing point depression agent (e.g., propylene glycol) and/or a demulsifier, without disturbing the stability of the emulsion or the microemulsion over a range of salinities or temperatures.
  • a freezing point depression agent e.g., propylene glycol
  • demulsifier e.g., a demulsifier
  • the emulsion or the microemulsion consists essentially of an aqueous phase; a solvent comprising d-limonene and/or methyl ester; a surfactant comprising alkyl polyglycoside; an alcohol comprising butanol and/or amyl alcohol; and, optionally, one or more additives.
  • the aqueous phase is present in the emulsion or the microemulsion in an amount of between about 10 wt% and about 70 wt%, or between about 35 wt% and about 60 wt%.
  • the alkyl polyglycoside surfactant is present in the emulsion or the microemulsion in an amount of between about 10 wt% and about 25 wt% or between about 16 wt% and about 24 wt%.
  • the solvent is present in the emulsion or the microemulsion in an amount between about 1 wt% and about 20 wt% or between about 9 wt% and about 17 wt%.
  • the alcohol e.g., alcohol co-solvent
  • the alcohol is present in the emulsion or the microemulsion in an amount between about 2 wt% and about 15 wt% or between about 4 wt% and about 9 wt%.
  • the emulsion or the microemulsion comprises an aqueous phase; a solvent comprising an oleaginous hydrocarbon solvent; a surfactant comprising an alkyl polyglycoside; and a co-surfactant comprising an oxygenated co-surfactant.
  • the emulsion or the microemulsion comprises between about 10 wt% and about 60 wt% aqueous phase (e.g., water).
  • the emulsion or the microemulsion consists essentially of an aqueous phase; a solvent comprising an oleaginous hydrocarbon solvent; a surfactant comprising an alkyl polyglycoside; a co-surfactant comprising an oxygenated co-surfactant; and, optionally, one or more additives.
  • the emulsion or the microemulsion comprises between about 10 wt% and about 60 wt% aqueous phase (e.g., water). In some embodiments, the emulsion or the microemulsion comprises between about 1 wt% and about 17 wt% solvent.
  • the emulsion or the microemulsion comprises between about 10 wt% and about 25 wt% surfactant. In some embodiments, the emulsion or the microemulsion comprises between about 2 wt% and about 15 wt% oxygenated co- surfactant. In some embodiments, the emulsion or microemulsion comprises between about 10 wt% and about 60 wt% aqueous phase (e.g., water), between about 1 wt% and about 17 wt% solvent, between about 10 wt% and about 25 wt% surfactant, and between about 2 wt% and about 15 wt% oxygenated co-surfactant.
  • aqueous phase e.g., water
  • other additives are present in an amount between about 1 wt% and about 30 wt%, between about 1 wt% and about 25 wt%, or between about 1 wt% and about 20 wt%.
  • the other additives comprise one or more salts and/or one or more acids.
  • fluids comprising the disclosed microemulsions remain stable and exhibit low turbidity over a wide range of salinities and/or temperatures.
  • turbidity refers to the measure of cloudiness or haziness of a fluid caused by the presence of suspended particles in the fluid.
  • turbidity serves as an indication of the stability of the microemulsion. A higher turbidity may be caused by phase separation of a less stable microemulsion upon dilution into high salinity and/or high temperature well conditions. Conversely, a low turbidity may be an indication that the microemulsion is more stable.
  • Phase separation may decrease the efficacy of the microemulsion.
  • Commonly-used units for measuring turbidity are Nephelometric Turbidity Units (NTU).
  • NTU Nephelometric Turbidity Units
  • a clear fluid corresponds to the fluid having a turbidity from 0 NTU to 15 NTU.
  • a slightly hazy fluid corresponds to the fluid having a turbidity from 15 NTU to 100 NTU.
  • a hazy fluid corresponds to the fluid having a turbidity from 100 NTU to 200 NTU.
  • An opaque fluid corresponds to the fluid having a turbidity of 200 NTU or greater.
  • Fluids comprising a microemulsion should have a turbidity in the range of slightly hazy or preferably clear to maximize the efficacy of the microemulsion.
  • Microemulsions disclosed herein demonstrate unexpectedly low turbidities even over a wide range of salinities.
  • the microemulsions disclosed herein upon dilution, have a turbidity of less than 100 NTU, of less than 50 NTU, or of less than 15 NTU, upon dilution at 2 gallons per thousand (gpt) in a brine having a TDS (total dissolved solids) value of from about 20,000 ppm up to about 310,000 ppm, when measured at room temperature one minute after dilution.
  • the microemulsions disclosed herein may demonstrate unexpectedly low turbidities over a wide range of temperatures.
  • the microemulsions upon dilution at 2 gallons per thousand with a brine having a TDS value of about 240,000 ppm, have a turbidity value of less than 15 NTU, when measured at 75 °F using a turbidimeter, and a turbidity value of less than 15 NTU, when measured at 200 °F using a turbidimeter.
  • the emulsion or the microemulsion comprises an aqueous phase.
  • the aqueous phase comprises water.
  • the water may be provided from any suitable source (e.g., sea water, fresh water, deionized water, reverse osmosis water, water from field production).
  • the water may be present in any suitable amount.
  • the total amount of water present in the emulsion or the microemulsion is between about 10 wt% and about 70 wt%, between about 35 wt% and about 60 wt%, between about 10 wt% about 60 wt%, between about 35 wt% and about 55 wt%, between about 5 wt% and about 60 wt%, between about 10 wt% and about 55 wt%, or between about 15 wt% and about 45 wt%, versus the total emulsion or microemulsion composition.
  • the emulsion or the microemulsion comprises a solvent.
  • the solvent may be a single type of solvent or a combination of two or more types of solvent.
  • the solvent may comprise an oleaginous hydrocarbon solvent; for example, the solvent may be a substance with a significant hydrophobic character with linear, branched, cyclic, bicyclic, saturated, or unsaturated structure, including terpenes and/or alkyl aliphatic carboxylic acid esters.
  • the term "oleaginous” denotes an oily, non-polar liquid phase.
  • the solvent comprises terpene and/or methyl aliphatic carboxylic acid ester.
  • the terpene is a non-oxygenated terpene.
  • the terpene is d-limonene. In some embodiments, the terpene is dipentene. In some embodiments, the terpene is selected from the group consisting of d-limonene, nopol, alpha terpineol, eucalyptol, dipentene, linalool, alpha-pinene, beta-pinene, and combinations thereof. As used herein, " terpene” refers to a single terpene compound or a blend of terpene compounds.
  • the solvent is present in the emulsion or the microemulsion in an amount between about 1 wt% and about 25 wt%, between about 1 wt% and about 20 wt% or between about 9 wt% and about 17 wt%.
  • d-limonene is present in the emulsion or the microemulsion in an amount between about 1 wt% and about 25 wt%, between about 1 wt% and about 20 wt% or between about 9 wt% and about 17 wt%.
  • methyl aliphatic carboxylic acid ester is present in the emulsion or the microemulsion in an amount between about 1 wt% and about 25 wt%, between about 1 wt% and about 20 wt% or between about 9 wt% and about 17 wt%.
  • a combination of d-limonene and methyl aliphatic carboxylic acid ester is present in the emulsion or the microemulsion in an amount between about 1 wt% and about 25 wt%, between about 1 wt% and about 20 wt% or between about 9 wt% and about 17 wt%.
  • the ratio of the d-limonene to the methyl aliphatic carboxylic acid ester is from about 1:0.01 to about 0.5: 1 by weight, or from about 0.8: 1 to about 1:0.8 by weight.
  • the terpene is an oxygenated terpene, for example, a terpene comprising an alcohol, an aldehyde, an ether, and/or a ketone group.
  • the terpene comprises an alcohol group, otherwise referred to as a terpene alcohol.
  • Non- limiting examples of terpene alcohols are linalool, geraniol, nopol, a-terpineol, and menthol.
  • the terpene comprises an ether-oxygen, for example, eucalyptol.
  • the terpene is a non-oxygenated terpene, for example, d-limonene or dipentene.
  • Terpenes are derived biosynthetically from units of isoprene. Terpenes may be generally classified as monoterpenes (e.g., having two isoprene units), sesquiterpenes (e.g., having 3 isoprene units), diterpenes, or the like.
  • the term "terpenoid” also includes natural degradation products, such as ionones, and natural and synthetic derivatives, e.g., terpene alcohols, ethers, aldehydes, ketones, acids, esters, epoxides, and hydrogenation products (e.g., see Ullmann's Encyclopedia of Industrial Chemistry, 2012, pages 29-45, herein incorporated by reference).
  • the terpene is a naturally occurring terpene. In some cases, the terpene is a non-naturally occurring terpene and/or a chemically modified terpene (e.g., saturated terpene, terpene amine, fluorinated terpene, or silylated terpene).
  • a chemically modified terpene e.g., saturated terpene, terpene amine, fluorinated terpene, or silylated terpene.
  • terpenoids When terpenes are modified chemically, such as by oxidation or rearrangement of the carbon skeleton, the resulting compounds are generally referred to as terpenoids.
  • alkyl aliphatic carboxylic acid ester refers to a compound or a blend of compounds having the general formula: o
  • R 1 — C— OR 2 wherein R 1 is a C 4 to C 22 aliphatic group, including those bearing heteroatom-containing substituent groups, and R 2 is a Ci to C 6 alkyl group.
  • R 2 is -CH 3
  • the compound or blend of compounds is referred to as methyl aliphatic carboxylic acid ester, or methyl ester.
  • alkyl aliphatic carboxylic acid esters may be derived from a fully synthetic process or from natural products, and thus comprise a blend of more than one ester.
  • the emulsion or microemulsion comprises a surfactant.
  • the emulsion or the microemulsion comprises a first surfactant and a second surfactant or co- surfactant.
  • surfactant as used herein, is given its ordinary meaning in the art and refers to compounds having an amphiphilic structure which gives them a specific affinity for oil/water-type and water/oil-type interfaces which helps the compounds to reduce the free energy of these interfaces and to stabilize the dispersed phase of an emulsion or a microemulsion.
  • the surfactant comprises alkyl polyglycoside (APG).
  • APG alkyl polyglycoside
  • the surfactant may comprise one APG surfactant or a mixture of APG surfactants with different alkyl chains and/or degrees of polymerization (DP).
  • APGs are non-ionic surfactants having the following formula:
  • R is an aliphatic hydrocarbon group which can be straight chained or branched, saturated or unsaturated, and having from 6 to 16 carbon atoms;
  • R 4 is H, -C3 ⁇ 4, or -CH 2 CH 3 ;
  • G is the residue of a reducing saccharide, for example, a glucose residue;
  • Y is an average number of from about 0 to about 5;
  • X is an average degree of polymerization (DP) of from about 1 to about 4.
  • the DP is an average of the number of glycose groups attached to the molecule.
  • the surfactant comprising APG refers both to where a single APG species is present and to where a mixture of APG species with different alkyl chains and/or degrees of polymerization (DP) are present.
  • the number of carbon atoms in the aliphatic hydrocarbon group R is referred to as the carbon chain length of the APG surfactant.
  • the APG surfactant comprises one or more species having a carbon chain length between 6 and 16 carbon atoms. In some embodiments, the number average carbon chain length of the APG surfactant is between 6 and 16 carbon atoms.
  • alkyl polyglycoside surfactant is present in the emulsion or the microemulsion in an amount between about 10 wt% and about 25 wt% or between about 16 wt% and about 24 wt%. Other values are also possible.
  • specific surfactant components are excluded from the emulsion or the microemulsion.
  • the surfactant of the emulsion or the microemulsion may exclude an ethoxylated castor oil.
  • the surfactant component of the emulsion or the microemulsion consists of or consists essentially of APG surfactant. That is, no other surfactants are present in the emulsion or the microemulsion, or they are present in only a negligible amount.
  • APG surfactant in some embodiments, increased the stability of the emulsion or the microemulsion over a wide range of
  • Such emulsions or microemulsions may maintain stability even when subjected to a wide range of temperatures due to the environmental conditions present at the subterranean formation and/or reservoir.
  • the emulsion or microemulsion comprises an alcohol.
  • the alcohol may function as a co-solvent.
  • the alcohol may be selected from alcohols having from 1 to 8 carbon atoms, and combinations thereof.
  • the alcohol may be selected from the group consisting of butanol, pentanol, amyl alcohol, and combinations thereof.
  • the alcohol is selected from the group consisting of butanol, amyl alcohol, and combinations thereof.
  • the alcohol comprises butanol.
  • the alcohol comprises amyl alcohol.
  • the alcohol comprises a combination of butanol and amyl alcohol.
  • the alcohol is present in the emulsion or the microemulsion in an amount between about 2 wt% and about 15 wt% or between about 4 wt% and about 9 wt%.
  • butanol is present in the emulsion or the microemulsion in an amount between about 2 wt% and about 15 wt% or between about 4 wt% and about 9 wt%.
  • amyl alcohol is present in the emulsion or the microemulsion in an amount between about 2 wt% and about 15 wt% or between about 4 wt% and about 9 wt%.
  • a combination of butanol and amyl alcohol is present in the emulsion or the microemulsion in an amount between about 2 wt% and about 15 wt% or between about 4 wt% and about 9 wt%.
  • the emulsion or microemulsion may comprise one or more additives in addition to the components discussed above.
  • the additive is a freezing point depression agent (e.g., propylene glycol).
  • the additive is a demulsifier.
  • the demulsifier aids in preventing the formulation of an emulsion between a treatment fluid and crude oil.
  • demulsifiers include polyoxyethylene (50) sorbitol hexaoleate.
  • Other potential additives include a proppant, a scale inhibitor, a friction reducer, a biocide, a corrosion inhibitor, a buffer, a viscosifier, an oxygen scavenger, a clay control additive, a paraffin control additive, an asphaltene control additive, an acid, an acid precursor, or a salt.
  • Additional additive may be present in the emulsion or the microemulsion in any suitable amount.
  • the one or more additional additives are present in an amount between about 0.5 wt% and about 30 wt%, between about 1 wt% and about 40 wt%, between about 0 wt% and about 25 wt%, between about 1 wt% and about 25 wt%, between about 1 wt% and about 20 wt%, between about 3 wt% and about 20 wt%, or between about 8 wt% and about 16 wt%, versus the total emulsion or microemulsion composition.
  • a freezing point depression agent is present in the emulsion or microemulsion in an amount between about 10 wt% and about 15 wt%.
  • a demulsifier is present in the emulsion or microemulsion in an amount between about 4 wt% and about 8 wt%.
  • the emulsion or the microemulsion comprises a freezing point depression agent.
  • the emulsion or the microemulsion may comprise a single freezing point depression agent or a combination of two or more freezing point depression agents.
  • the term "freezing point depression agent” is given its ordinary meaning in the art and refers to a compound which is added to a solution to reduce the freezing point of the solution. That is, a solution comprising the freezing point depression agent has a lower freezing point as compared to an essentially identical solution not comprising the freezing point depression agent.
  • suitable freezing point depression agents for use in the emulsions or the microemulsions described herein.
  • Non-limiting examples of freezing point depression agents include primary, secondary, and tertiary alcohols with between 1 and 20 carbon atoms.
  • the emulsion or the microemulsion may comprise other additives.
  • Further non-limiting examples of other additives include proppants, scale inhibitors, friction reducers, biocides, corrosion inhibitors, buffers, viscosifiers, oxygen scavengers, clay control additives, paraffin control additives, asphaltene control additives acids, acid precursors, and salts.
  • proppants include grains of sand, glass beads, crystalline silica (e.g., quartz), hexamethylenetetramine, ceramic proppants (e.g., calcined clays), resin coated sands, and resin coated ceramic proppants.
  • crystalline silica e.g., quartz
  • ceramic proppants e.g., calcined clays
  • resin coated sands e.g., calcined clays
  • resin coated ceramic proppants e.g., resin coated ceramic proppants.
  • Other proppants are also possible and will be known to those skilled in the art.
  • Non-limiting examples of scale inhibitors include one or more of methyl alcohol, organic phosphonic acid salts (e.g., phosphonate salt, aminopolycarboxlic acid salts), polyacrylate, ethane- 1,2-diol, calcium chloride, and sodium hydroxide.
  • organic phosphonic acid salts e.g., phosphonate salt, aminopolycarboxlic acid salts
  • polyacrylate ethane- 1,2-diol
  • calcium chloride ethane- 1,2-diol
  • Non-limiting examples of friction reducers include oil-external emulsions of polymers with oil-based solvents and an emulsion- stabilizing surfactant.
  • the emulsions may include Natural-based polymers like guar, cellulose, xanthan, proteins, polypeptides or derivatives of same or synthetic polymers like polyacrylamide-co-acrylic acid (PAM-AA), polyethylene oxide, polyacrylic acid, and other copolymers of acrylamide and other vinyl monomers.
  • Drag-reducing additives include dispersions of natural- or synthetic polymers and copolymers in saline solution and dry natural- or synthetic polymers and copolymers. These polymers or copolymers may be nonionic, zwitterionic, anionic, or cationic depending on the composition of polymer and pH of solution. Other friction reducers are also possible and will be known to those skilled in the art.
  • biocides include didecyl dimethyl ammonium chloride, gluteral, Dazomet, bronopol, tributyl tetradecyl phosphonium chloride, tetrakis
  • (hydroxymethyl) phosphonium sulfate AQUCAR®, UCARCIDE®, glutaraldehyde, sodium hypochlorite, and sodium hydroxide.
  • Other biocides are also possible and will be known to those skilled in the art.
  • Non-limiting examples of corrosion inhibitors include quaternary ammonium compounds, thiourea/formaldehyde copolymers, and propargyl alcohol.
  • Other corrosion inhibitors are also possible and will be known to those skilled in the art.
  • Non-limiting examples of buffers include acetic acid, acetic anhydride, potassium hydroxide, sodium hydroxide, and sodium acetate.
  • Other buffers are also possible and will be known to those skilled in the art.
  • Non-limiting examples of viscosifiers include polymers like guar, cellulose, xanthan, proteins, polypeptides or derivatives of same or synthetic polymers like polyacrylamide-co- acrylic acid (PAM-AA), polyethylene oxide, polyacrylic acid, and other copolymers of acrylamide and other vinyl monomers.
  • PAM-AA polyacrylamide-co- acrylic acid
  • Other viscosifiers are also possible and will be known to those skilled in the art.
  • oxygen scavengers include sulfites and bisulfites. Other oxygen scavengers are also possible and will be known to those skilled in the art.
  • Non-limiting examples of clay control additives include quaternary ammonium chloride and tetramethylammonium chloride. Other clay control additives are also possible and will be known to those skilled in the art.
  • paraffin control additives and asphaltene control additives include active acidic copolymers, active alkylated polyester, active alkylated polyester amides, active alkylated polyester imides, aromatic naphthas, and active amine sulfonates.
  • Other paraffin control additives and asphaltene control additives are also possible and will be known to those skilled in the art.
  • the emulsion or the microemulsion comprises an acid or an acid precursor.
  • the emulsion or the microemulsion may comprise an acid when used during acidizing operations.
  • the APG surfactant used is alkaline and an acid (e.g., HC1) used to adjust the pH of the emulsion or the microemulsion to neutral.
  • the emulsion or the microemulsion may comprise a single acid or a combination of two or more acids.
  • the acid comprises a first type of acid and a second type of acid.
  • Non-limiting examples of acids or di-acids include hydrochloric acid, acetic acid, formic acid, succinic acid, maleic acid, malic acid, lactic acid, and hydrochloric - hydrofluoric acids.
  • the emulsion or the microemulsion comprises an organic acid or organic di-acid in the ester (or di-ester) form, whereby the ester (or diester) is hydrolyzed in the wellbore and/or reservoir to form the parent organic acid and an alcohol in the wellbore and/or reservoir.
  • esters or di-esters include isomers of methyl formate, ethyl formate, ethylene glycol diformate, a,a-4-trimethyl-3-cyclohexene-l- methylformate, methyl lactate, ethyl lactate, ⁇ , ⁇ -4-trimethyl 3-cyclohexene-l-methyllactate, ethylene glycol dilactate, ethylene glycol diacetate, methyl acetate, ethyl acetate, ⁇ , ⁇ ,-4- trimethyl-3-cyclohexene-l-methylacetate, dimethyl succinate, dimethyl maleate, di(a,a-4- trimethyl-3-cyclohexene-l-methyl)succinate, l-methyl-4-(l-methylethenyl)- cyclohexylformate, 1 -methyl-4-( 1 -ethylethenyl)-cyclohexylactate, 1 -methyl-4-( 1 -methyle
  • the emulsion or the microemulsion comprises a salt.
  • the presence of the salt may reduce the amount of water needed as a carrier fluid, and in addition, may lower the freezing point of the emulsion or the microemulsion,
  • the emulsion or the microemulsion may comprise a single salt or a combination of two or more salts.
  • the salt comprises a first type of salt and a second type of salt.
  • Non-limiting examples of salts include salts comprising K, Na, Br, Cr, Cs, or Li, for example, halides of these metals, including NaCl, KC1, CaCl 2 , and MgCl 2 .
  • the emulsion or the microemulsion comprises a clay control additive.
  • the emulsion or the microemulsion may comprise a single clay stabilizer or a combination of two or more clay stabilizers.
  • the clay control additive comprises a first type of clay control additive and a second type of clay control additive.
  • Non-limiting examples of clay control additives include the salts above, polymers (PAC, PHPA, etc), glycols, sulfonated asphalt, lignite, sodium silicate, and choline chloride.
  • the components of the microemulsion and/or the amounts of the components are selected such that the microemulsion is stable over a wide-range of temperatures, as demonstrated, for example, by a turbidity below a certain threshold (e.g., 100 NTU, 50 NTU, or 15 NTU).
  • a certain threshold e.g. 100 NTU, 50 NTU, or 15 NTU.
  • the components of the microemulsion and/or the amounts of the components are selected such that the microemulsion is stable over a wide-range of salinities.
  • the microemulsion may exhibit stability between about 20,000 ppm TDS and about 310,000 ppm TDS.
  • the emulsions and the microemulsions described herein may be formed using methods known to those of ordinary skill in the art.
  • the aqueous and non-aqueous phases may be combined (e.g., the water and the solvent(s)), followed by addition of a surfactant and co-surfactant and optional additives (e.g., a freezing point depression agent or a demulsifier) and agitation.
  • a surfactant and co-surfactant and optional additives e.g., a freezing point depression agent or a demulsifier
  • the strength, type, and length of the agitation may be varied as known in the art depending on various factors including the components of the emulsions or the microemulsion, the quantity of the emulsions or the microemulsion, and the resulting type of emulsion or microemulsion formed. For example, for small samples, a few seconds of gentle mixing can yield an emulsion or a microemulsion, whereas for larger samples, longer agitation times and/or stronger agitation may be required.
  • Agitation may be provided by any suitable source, for example, a vortex mixer, a stirrer (e.g., magnetic stirrer), etc.
  • any suitable method for injecting the emulsion or the microemulsion e.g., a diluted microemulsion
  • the emulsion or the microemulsion, optionally diluted may be injected into a subterranean formation by injecting it into a well or wellbore in the zone of interest of the formation and thereafter pressurizing it into the formation for the selected distance.
  • Methods for achieving the placement of a selected quantity of a mixture in a subterranean formation are known in the art.
  • the well may be treated with the emulsion or the microemulsion for a suitable period of time.
  • the emulsion or the microemulsion and/or other fluids may be removed from the well using known techniques, including producing the well.
  • an emulsion or a microemulsion may be diluted and/or combined with other liquid component(s) prior to and/or during injection (e.g., via straight tubing, via coiled tubing, etc.).
  • the emulsion or the microemulsion is diluted with an aqueous carrier fluid (e.g., water, brine, sea water, fresh water, or a well-treatment fluid (e.g., an acid, a fracturing fluid comprising polymers, produced water, sand, slickwater, etc.,)) prior to and/or during injection into the wellbore.
  • a composition for injecting into a wellbore comprising an emulsion or a microemulsion as described herein and an aqueous carrier fluid, wherein the emulsion or the microemulsion is present in an amount between about 0.1 and about
  • gpt 50 gallons per thousand gallons (gpt) per dilution fluid, between about 0.1 and about 100 gpt, between about 0.5 and about 10 gpt, between about 0.5 and about 2 gpt, or between about 1 gpt and about 4 gpt.
  • emulsions and microemulsions described herein may be used in various aspects of the life cycle of an oil and/or gas well, including, but not limited to, drilling, mud displacement, casing, cementing, perforating, stimulation, remediation, and enhanced oil recovery/ improved oil recovery, etc.
  • Inclusion of an emulsion or a microemulsion into the fluids typically employed in these processes, for example, fracturing fluids, drilling fluids, mud displacement fluids, casing fluids, cementing fluids, perforating fluid, stimulation fluids, kill fluids, etc. results in many advantages as compared to use of the fluid alone.
  • stimulation generally refers to the treatment of geological formations to improve the recovery of liquid hydrocarbons (e.g., formation crude oil and/or formation gas).
  • liquid hydrocarbons e.g., formation crude oil and/or formation gas.
  • the porosity and permeability of the formation determine its ability to store hydrocarbons, and the facility with which the hydrocarbons can be extracted from the formation.
  • Common stimulation techniques include well fracturing (e.g., fracturing, hydraulic fracturing), high rate water pack, and acidizing (e.g., fracture acidizing, matrix acidizing) operations.
  • Non-limiting examples of fracturing operations include hydraulic fracturing, which is commonly used to stimulate low permeability geological formations to improve the recovery of hydrocarbons.
  • the process can involve suspending chemical agents in a stimulation fluid (e.g., fracturing fluid) and injecting the fluid down a wellbore.
  • the fracturing fluid may be injected at high pressures and/or at high rates into a wellbore.
  • the assortment of chemicals pumped down the well can cause damage to the surrounding formation by entering the reservoir material and blocking pores. For example, one or more of the following may occur: wettability reversal, emulsion blockage, aqueous -filtrate blockage, mutual
  • microemulsion in the fracturing fluid may have many advantages as compared to the use of a fracturing fluid alone, including, for example, maximizing the transfer and/or recovery of injected fluids, increasing oil and/or gas recovery, and/or other benefits described herein.
  • Non-limiting examples of acidizing operations include the use of water-based fluids to remove drilling fluids and particles remaining in the wellbore to permit optimal flow feeding into the wellbore (e.g., matrix acidizing).
  • Matrix acidizing generally refers to the formation of wormholes (e.g., pores or channels through which oil, gas, and/or other fluids can flow) through the use of a fluid (e.g., acidic stimulation fluid) comprising, for example, an acid, wherein the wormholes are continuous channels and holes formed in the reservoir of a controlled size and depth.
  • a fluid e.g., acidic stimulation fluid
  • the addition of an emulsion or a microemulsion to the stimulation fluid may have many advantages as compared to the use of a stimulation fluid alone.
  • Fracture acidizing generally refers to the use of an acid to extend fractures formed by the injection of treatment fluid at high-pressure (e.g., fracturing).
  • the addition of an emulsion or a microemulsion to the stimulation fluid may have advantages as compared to the use of a stimulation fluid alone, including, for example, increasing the removal of fracturing fluid skin (e.g., fluid and solids from the reservoir which may block optimal flow of the wellbore) from the fractures allowing for more effective acid treatment.
  • stimulation fluids e.g., acidizing fluids, fracturing fluids, etc.
  • stimulation fluids include water and hydrochloric acid (e.g., 15% HC1 in water).
  • the acid is partially or completely consumed after reacting with carbonates in the reservoir.
  • stimulation fluids include conventional fluids (e.g., gelling agents, gelling agents comprising crosslinking agents such as borate, zirconate, and/or titanate), water fracture fluids (e.g., friction reducers, gelling agents, viscoelastic surfactants), hybrid fluids (e.g., friction reducers, gelling agents, viscoelastic surfactants, and combinations thereof), energized fluids (e.g., foam generating energizers comprising nitrogen or carbon dioxide), acid fracture fluids (e.g., gelled acid base fluids), gas fracture fluids (e.g., propane), and matrix acidizing fluids (e.g., an acid).
  • conventional fluids e.g., gelling agents, gelling agents comprising crosslinking agents such as borate, zirconate, and/or titanate
  • water fracture fluids e.g., friction reducers, gelling agents, viscoelastic surfactants
  • hybrid fluids e.g., friction reducers,
  • the stimulation fluid comprises a viscosifier (e.g., guar gum) and/or a bridging agent (e.g., calcium carbonate, size salt, oil-soluble resins, mica, ground cellulose, nutshells, and other fibers).
  • a viscosifier e.g., guar gum
  • a bridging agent e.g., calcium carbonate, size salt, oil-soluble resins, mica, ground cellulose, nutshells, and other fibers.
  • removal of leftover drilling fluids or reservoir fluids refers to the breakdown and removal of a near- wellbore skin (e.g., fluid and solids from the reservoir which may block optimal flow into the wellbore).
  • skin materials include paraffin, asphaltene, drilling mud components (e.g., barite, clays), non-mobile oil in place, and fines (e.g., which may block pores in the reservoir material).
  • an emulsion or a microemulsion to the acidizing fluid may have many advantages as compared to the use of an acidizing fluid alone, including, for example, increasing the breakdown of the skin into smaller components to be more easily removed by flow from the wellbore, increasing oil and/or gas recovery, and/or other benefits described herein.
  • incorporation of an emulsion or a microemulsion into a stimulation fluid can aid in reducing fluid trapping, for example, by reducing capillary pressure and/or minimizing capillary end effects, as compared to the use of a stimulation fluid alone.
  • Capillary pressure is defined by
  • Reducing capillary pressure and/or minimizing capillary end effects is beneficial, because it decreases resistance to flow of oil (sometimes called water blocks) and increases production of hydrocarbon.
  • incorporation of an emulsion or a microemulsion into stimulation fluids can promote increased flow back of aqueous phases following well treatment, increasing production of liquid and/or gaseous hydrocarbons, and/or increasing the displacement of residual fluids (e.g., drilling fluids, etc.) by formation crude oil and/or formation gas.
  • non-limiting advantages as compared to the use of a stimulation fluid alone include increasing the amount of water extracted from the reservoir, increasing the amount or oil and/or gas extracted from the reservoir, more uniformly distributing the acid along the surface of the wellbore and/or reservoir, improving the formation of wormholes (e.g., by slowing down the reaction rate to create deeper and more extensive wormholes during fracture acidizing).
  • the addition of an emulsion or a microemulsion increases the amount of hydrocarbons transferred from the reservoir to fluids injected into the reservoir during hydraulic fracturing.
  • the stimulation fluid comprises an emulsion or a
  • microemulsion as described herein wherein the emulsion or the microemulsion is present in an amount between about 0.5 gpt and about 200 gpt of stimulation fluid, or between about 0.5 gpt and about 100 gpt, between about 0.5 gpt and about 50 gpt, between about 1 gpt and about 50 gpt, between about 1 gpt and about 20 gpt, between about 2 gpt and about 20 gpt, between about 2 gpt and about 10 gpt, between about 2 gpt and about 5 gpt, or between about 5 gpt and about 10 gpt.
  • the emulsion or the microemulsion is present in an amount between about 2 gpt and about 5 gpt of stimulation fluid.
  • the stimulation fluid contains at least about 0.5 gpt, at least about 1 gpt, at least about 2 gpt, at least about 4 gpt, at least about 10 gpt, at least about 20 gpt, at least about 50 gpt, at least about 100 gpt, or at least about 200 gpt of an emulsion or a microemulsion.
  • the stimulation fluid contains less than or equal to about 200 gpt, less than or equal to about 100 gpt, less than or equal to about 50 gpt, less than or equal to about 20 gpt, less than or equal to about 10 gpt, less than or equal to about 4 gpt, less than or equal to about 2 gpt, less than or equal to about 1 gpt, or less than or equal to about 0.5 gpt of an emulsion or a microemulsion.
  • refracturing or the process of repeating the above stimulation processes, is further improved by the addition of an emulsion or a microemulsion to the stimulation fluid.
  • emulsion and "microemulsion” should be understood to include emulsions or microemulsions that have a water continuous phase, or that have an oil continuous phase, or microemulsions that are bicontinuous or multiple continuous phases of water and oil.
  • Emulsion is given its ordinary meaning in the art and refers to dispersions of one immiscible liquid in another, in the form of droplets, with diameters approximately in the range of about 100 to about 10,000 nanometers (nm). Emulsions may be thermodynamically unstable and/or require high shear forces to induce their formation.
  • microemulsion is given its ordinary meaning in the art and refers to dispersions of one immiscible liquid in another, in the form of droplets, with diameters approximately in the range of about between about 10 to about 300 nanometers. Microemulsions are clear or transparent because they contain domains smaller than the wavelength of visible light. In addition, microemulsions are homogeneous,
  • Microemulsions may be characterized by a variety of
  • advantageous properties including, by not limited to, (i) clarity, (ii) very small particle size, (iii) ultra-low interfacial tensions, (iv) the ability to combine properties of water and oil in a single homogeneous fluid, (v) shelf life stability, (vi) ease of preparation; (vii) compatibility; and (viii) solvency.
  • microemulsions described herein are stabilized
  • microemulsions that are formed by the combination of a solvent- surfactant blend with an appropriate oil-based or water-based carrier fluid.
  • the microemulsion forms upon simple mixing of the components without the need for high shearing generally required in the formation of emulsions.
  • the microemulsion is a thermodynamically stable system, and the droplets remain finely dispersed over time. In some cases, the average droplet size ranges from about 10 nm to about 300 nm.
  • co-solvent refers to a glycol or an alcohol having 1 to 8 carbon atoms, that when incorporated in an emulsion or microemulsion composition, increases the temperature, salinity, and composition stability of the microemulsion to form the microemulsion.
  • co-surfactant refers to a low-molecular-weight surfactant, e.g., a lower fatty alcohol, which acts in conjunction with a surfactant to form an emulsion or microemulsion.
  • Certain compounds of the present invention may exist in particular geometric or stereoisomeric forms.
  • the present invention contemplates all such compounds, including cis- and irans-isomers, R- and S-enantiomers, diastereomers, (D)-isomers, (L)-isomers, the racemic mixtures thereof, and other mixtures thereof, as falling within the scope of the invention.
  • Additional asymmetric carbon atoms may be present in a substituent such as an alkyl group. All such isomers, as well as mixtures thereof, are intended to be included in this invention.
  • Isomeric mixtures containing any of a variety of isomer ratios may be utilized in accordance with the present invention. For example, where only two isomers are combined, mixtures containing 50:50, 60:40, 70:30, 80:20, 90: 10, 95:5, 96:4, 97:3, 98:2, 99: 1, or 100:0 isomer ratios are all contemplated by the present invention. Those of ordinary skill in the art will readily appreciate that analogous ratios are contemplated for more complex isomer mixtures.
  • aliphatic includes both saturated and unsaturated, nonaromatic, straight chain (i.e. unbranched), branched, acyclic, and cyclic (i.e. carbocyclic) hydrocarbons, which are optionally substituted with one or more functional groups.
  • aliphatic is intended herein to include, but is not limited to, alkyl, alkenyl, alkynyl, cycloalkyl, cycloalkenyl, and cycloalkynyl moieties.
  • alkyl includes straight, branched and cyclic alkyl groups.
  • alkyl alkenyl
  • alkynyl alkynyl
  • aliphatic is used to indicate those aliphatic groups (cyclic, acyclic, substituted
  • Aliphatic group substituents include, but are not limited to, any of the substituents described herein, that result in the formation of a stable moiety (e.g., aliphatic, alkyl, alkenyl, alkynyl, heteroaliphatic, heterocyclic, aryl, heteroaryl, acyl, oxo, imino, thiooxo, cyano, isocyano, amino, azido, nitro, hydroxyl, thiol, halo, aliphaticamino, heteroaliphaticamino, alkylamino, heteroalkylamino, arylamino, heteroarylamino, alkylaryl, arylalkyl, aliphaticoxy, heteroaliphaticoxy, alkyloxy, heteroalkyloxy, aryloxy, heteroaryloxy, aliphaticthioxy, heteroaliphaticthioxy, alkylthi
  • alkane is given its ordinary meaning in the art and refers to a saturated hydrocarbon molecule.
  • branched alkane refers to an alkane that includes one or more branches, while the term “unbranched alkane” refers to an alkane that is straight- chained.
  • cyclic alkane refers to an alkane that includes one or more ring structures, and may be optionally branched.
  • acyclic alkane refers to an alkane that does not include any ring structures, and may be optionally branched.
  • the sand was added to the columns in a stepwise fashion with the brine to be studied.
  • the sand was packed using a hand-held vibrating column packer in between each stepwise addition until all of the material (40-45 grams) had been added.
  • the amount of fluid used in the process was tracked and the pore volume of the sand pack was calculated for both columns. Five pore volumes of the treatment were passed through the first column, collected from the first column, then passed through the second column. After the last pore volume was passed through the first and second columns, the level of the aqueous phase was adjusted exactly to the top of sand bed and crude oil was added on top of the sand bed to a height of 5 cm oil column above the bed.
  • This example describes an experiment for determining the displacement of residual aqueous treatment fluid by crude oil to test the performance of a microemulsion comprising APG surfactant [Microemulsion A], in which the microemulsion is diluted in different brines (2% KCl, 12% API brine, and 24% API brine and produced water from the Bakken formation (310,000 ppm TDS)).
  • Microemulsion A used in this example was prepared using 51.4 wt% water; 16.8 wt% d-limonene as a solvent; 23.4 wt% APG surfactant; and 8.4 wt% butanol as an alcohol functioning as a co-solvent.
  • the APG surfactant used in this example had a C 8-16 alkyl chain and a degree of polymerization (DP) equal to 1.5.
  • Table 1 shows the results of displacement of residual aqueous treatment fluid by crude oil using the experimental procedure outlined in Example 1. Microemulsion A performs very well at all salinities for both columns. Table 1 presents the percentages of residual aqueous fluid displaced from the column as measured after 120 minutes. The residual aqueous fluid was displaced by crude oil (30.9° API gravity; 3.2% asphaltenes; 4.32% paraffin) for Microemulsion A diluted at 2 gpt in 2% KCl (20,000 ppm TDS), 12% API brine (120,000 ppm TDS) and 24% API brine (240,000 ppm TDS).
  • Microemulsion B used in this example was prepared using 36.0 wt% water; 8.16 wt% d-limonene and 8.16 wt% methyl ester as a solvent; 22.7 wt% APG surfactant; 6.7 wt% amyl alcohol functioning as a co- solvent; 13 wt% propylene glycol as a freezing point depression agent, and 5.25 wt% demulsifier.
  • Microemulsion C was prepared using 36.0 wt% water; 8.16 wt% d-limonene, and 8.16 wt% methyl ester as a solvent; 22.7 wt% non-ionic surfactant (C12-15 E7) as a surfactant; 6.7 wt% amyl alcohol functioning as a co- solvent; and 13 wt% propylene glycol as a freezing point depression agent, and 5.25 wt% demulsifier. Two gpt dilutions of
  • Microemulsions B and C were prepared in the Bakken C water (310,000 ppm TDS) and tested.
  • the methyl ester used in this example was a Qo to a C 16 aliphatic carboxylic acid ester with one degree of unsaturation in the aliphatic group.
  • the demulsifier was polyoxyethylene (50) sorbitol hexaoleate.
  • Table 2 shows the results of displacement of residual aqueous treatment fluid by crude oil (32.4° API gravity; 3.4% asphaltenes; 4.63% paraffin) for Microemulsions B and C diluted at 2 gpt in Bakken C water.
  • Microemulsion C shows a much lower performance in the second column compared to Microemulsion B, possibly due to the salting out of the C12 15 E 7 surfactant, demonstrating the superiority of Microemulsion B comprising APG surfactant.
  • Table 3 shows the results of displacement of residual aqueous treatment fluid by crude oil. As shown in Table 3, Microemulsion D loses all performance in the second column, demonstrating the unexpected benefit of using a microemulsion comprising an APG surfactant [Microemulsion A] for enhanced displacement of residual aqueous treatment fluid. Table 3 shows the results of displacement of residual aqueous treatment fluid by a crude oil (30.9° API gravity; 3.2% asphaltenes; 4.32% paraffin) for Microemulsion A and
  • Microemulsion D diluted at 2 gpt in Bakken C water.
  • Microemulsion F used in this example was prepared using 62.6 wt% water; 17.33 wt% d-limonene as a first solvent; 16.24 wt% APG surfactant; and 3.47 wt% isopropyl alcohol and 0.36 wt% octanol as a co-solvent.
  • Microemulsion G used in this example was prepared using 69.3 wt% water; 9.23 wt% d-limonene as a first solvent; 16.2 wt% APG surfactant; and 5.27 wt% isopropyl alcohol as a co-solvent.
  • Microemulsions F and G gave a displacement of residual aqueous treatment fluid of 90% using a medium crude oil (30.9° API gravity; 3.2% asphaltenes; 4.32% paraffin) and 15% API brine in the first column.
  • the APG surfactant used in Microemulsions F and and G had a C 10 -16 alkyl chain and a DP equal to 1.4. This example shows that
  • microemulsions comprising a different APG surfactant and amounts of terpene solvent from 9.23 wt% to 17.33 wt% surprisingly provide superior displacement of residual aqueous treatment fluid in 15% API brine compared with Microemulsions C and D, which do not contain APG surfactant.
  • Example 6
  • NTUs Nephelometric Turbidity Units
  • Microemulsion B was made with amyl alcohol and Microemulsion H was made with alpha-terpineol.
  • the choice of the co-solvent is very important to obtain a water clear dilution.
  • Microemulsion H used in this example was prepared using 36.0 wt% water; 8.16 wt% d-limonene and 8.16 wt% methyl ester as a solvent; 22.7 wt% APG surfactant; 6.7 wt % alpha-terpineol as an alcohol functioning as a co-solvent; 13.05 wt% propylene glycol as a freezing point depression agent; and 5.25 wt% demulsifier.
  • the APG surfactant used in Microemulsion H had a C 8-16 alkyl chain and a DP equal to 1.5.
  • Table 4 shows the turbidity measurements of 2 gpt dilutions of Microemulsions B, C, and H in different brines (2% KC1, 12% API brine, 24% API brine and Bakken C water).
  • Microemulsion B which incorporates APG surfactant and amyl alcohol demonstrated robust performance throughout salinities ranging from about 20,000 ppm TDS to about 310,000 ppm TDS, maintaining a turbidity of less than 15 NTU for all salinities in this range.
  • Microemulsion H which incorporated alpha-terpinol rather than amyl alcohol as the co-solvent, had a turbidity in the slightly hazy range demonstrating instability of the microemulsion at different salinities, and showing a less robust performance than
  • Microemulsion B The difference in performance between Microemulsion B and
  • Microemulsion H demonstrates the criticality of using certain alcohols as co-solvents as compared to other alcohols. Butanol also shows strong performance as a co-solvent as demonstrated through Microemulsion A referenced in Examples 2 and 4. Microemulsion C which did not include APG surfactant, also showed poor dilution in brines compared to Microemulsion B, demonstrating the criticality of using APG surfactant. TABLE 4:
  • Microemulsions I and Microemulsion J were measured through a procedure like that described in Example 6. Microemulsion I and Microemulsion J differed only in the alcohol used. Amyl alcohol was used for Microemulsion I and octanol was used for Microemulsion J.
  • Microemulsion I used in this example was prepared using 35.35 wt% water; 8.085 wt% d-limonene and 8.085 wt% methyl ester as a solvent; 22.26 wt% APG surfactant (C 8-16 alkyl chain and DP equal to 1.5); 8.18 wt% amyl alcohol as an alcohol functioning as a co- solvent; 12.86 wt% propylene glycol as a freezing point depression agent; and 5.18 wt% demulsifier.
  • the demulsifier was polyoxyethylene (50) sorbitol hexaoleate.
  • Microemulsion J used in this example was prepared using 35.35 wt% water; 8.085 wt% d-limonene and 8.085 wt% methyl ester as solvent; 22.26 wt% APG surfactant (C 8-16 alkyl chain and DP equal to 1.5); 8.18 wt % octanol as an alcohol functioning as a co-solvent; 12.86 wt% propylene glycol as a freezing point depression agent; and 5.18 wt% demulsifier.
  • the demulsifier was polyoxyethylene (50) sorbitol hexaoleate.
  • Table 5 shows the turbidity measurements of 2 gpt dilutions of Microemulsions I and J in different brines (2% KC1, 12% API brine, 24% API brine and Bakken C water).
  • Microemulsion I which incorporates APG surfactant and amyl alcohol, demonstrated robust dilution throughout salinities ranging from about 20,000 ppm TDS to about 310,000 ppm TDS, maintaining a turbidity of less than 15 NTU at all salinities in this range.
  • Microemulsion J which incorporated octanol rather than amyl alcohol as the co-solvent, exhibited turbidity in the opaque range demonstrating the instability of Microemulsion J at different salinities, and showing a less robust dilution than Microemulsion I.
  • the difference in dilution between Microemulsion I and Microemulsion J demonstrates the criticality of using certain alcohols as co-solvents as compared to other alcohols.
  • Microemulsions using butanol also show desirable dilution as a co- solvent as demonstrated by Microemulsion A, referenced in Examples 2 and 4. TABLE 5:
  • Microemulsion K used in this example was prepared using 36.0 wt% water; 16.32 wt% methyl ester as solvent; 22.7 wt% APG surfactant (C 8-16 alkyl chain and DP equal to 1.5); 6.7 wt% amyl alcohol functioning as a co-solvent; 13 wt.% propylene glycol as a freezing point depression agent and 5.25 wt% demulsifier.
  • the demulsifier was prepared using 36.0 wt% water; 16.32 wt% methyl ester as solvent; 22.7 wt% APG surfactant (C 8-16 alkyl chain and DP equal to 1.5); 6.7 wt% amyl alcohol functioning as a co-solvent; 13 wt.% propylene glycol as a freezing point depression agent and 5.25 wt% demulsifier.
  • the demulsifier was
  • polyoxyethylene (50) sorbitol hexaoleate polyoxyethylene (50) sorbitol hexaoleate.
  • Microemulsion L used in this example was prepared using 36.0 wt% water; 16.32 wt% butyl 3-hydroxybutanoate as solvent; 22.7 wt% APG surfactant (C 8-16 alkyl chain and DP equal to 1.5); 6.7 wt% amyl alcohol functioning as a co-solvent; 13 wt.% propylene glycol as a freezing point depression agent and 5.25 wt% demulsifier.
  • the demulsifier was polyoxyethylene (50) sorbitol hexaoleate.
  • Table 6 shows the turbidity measurements of 2 gpt dilutions of Microemulsions K and L in different brines (2% KC1, 12% API brine, 24% API brine and Bakken C water).
  • Microemulsion A Two samples of Microemulsion A, (Microemulsion A formulation is described in Example 2 above, and incorporated herein by reference) were prepared at 2 gpt in 24% API brine. One sample was kept at 75 °F and the other one was placed for few hours in an oven at 200 °F. Each of the samples remained clear (had a turbidity of 15 NTU or less) and did not exhibit phase separation showing the higher tolerance of Microemulsion A comprising APG surfactant within this range of temperatures.
  • the critical point the maximum amount of solvent that can be included in the microemulsion while maintaining a clear dilution in brine. Where solvent is present in an amount greater than the critical point, dilution into aqueous brine ceases to be clear.
  • the examples were conducted using 2% KC1 as the aqueous brine.
  • microemulsion M was prepared using 11.605 wt% APG surfactant (C 8-16 alkyl chain and DP equal to 1.5), 3.94 wt% amyl alcohol, 5.5 wt% demulsifier, 14.10 wt% propylene glycol, the balance being aqueous phase and solvent.
  • the critical point for a 50:50 blend of d-limonene : methyl ester solvent was determined to be
  • the critical point was determined for a microemulsion formulation in which higher amounts of APG surfactant and amyl alcohol were present.
  • Microemulsion N was prepared using 22.27 wt% APG surfactant, 8.2 wt% amyl alcohol, 5.37 wt% demulsifier, 12.78 wt% propylene glycol, the balance being aqueous phase and solvent.
  • the critical point for a 50:50 blend of d-limonene : methyl ester solvent was determined to be 20.34 wt%. Greater amounts of the solvent blend gave dilutions in 2% KC1 that were slightly hazy or worse.
  • the methyl ester used in Example 10 was a Cio to a Ci 6 aliphatic carboxylic acid ester with one degree of unsaturation in the aliphatic group and the demulsifier was
  • polyoxyethylene (50) sorbitol hexaoleate polyoxyethylene (50) sorbitol hexaoleate.
  • a reference to "A and/or B,” when used in conjunction with open-ended language such as “comprising” can refer, in one embodiment, to A without B (optionally including elements other than B); in another embodiment, to B without A (optionally including elements other than A); in yet another embodiment, to both A and B (optionally including other elements); etc.
  • the phrase "at least one,” in reference to a list of one or more elements, should be understood to mean at least one element selected from any one or more of the elements in the list of elements, but not necessarily including at least one of each and every element specifically listed within the list of elements and not excluding any combinations of elements in the list of elements.
  • This definition also allows that elements may optionally be present other than the elements specifically identified within the list of elements to which the phrase "at least one" refers, whether related or unrelated to those elements specifically identified.
  • At least one of A and B can refer, in one embodiment, to at least one, optionally including more than one, A, with no B present (and optionally including elements other than B); in another

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Abstract

L'invention concerne des procédés et des compositions comprenant une émulsion ou une microémulsion destinés à être utilisés en traitement d'un puits de pétrole et/ou de gaz. Dans certains modes de réalisation, l'émulsion ou la microémulsion comprend une phase aqueuse, un solvant, un tensioactif comprenant un alkyl polyglycoside, un alcool et, de manière facultative, un ou plusieurs additifs.
PCT/US2018/021983 2017-03-13 2018-03-12 Procédés et compositions incorporant un tensioactif alkyl polyglycoside destinés à être utilisés dans des puits de pétrole et/ou de gaz WO2018169857A1 (fr)

Priority Applications (1)

Application Number Priority Date Filing Date Title
CA3056225A CA3056225C (fr) 2017-03-13 2018-03-12 Procedes et compositions incorporant un tensioactif alkyl polyglycoside destines a etre utilises dans des puits de petrole et/ou de gaz

Applications Claiming Priority (2)

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US15/457,792 US10421707B2 (en) 2013-03-14 2017-03-13 Methods and compositions incorporating alkyl polyglycoside surfactant for use in oil and/or gas wells
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