WO2017161157A1

WO2017161157A1 - Energizing fluids for shale formations

Info

Publication number: WO2017161157A1
Application number: PCT/US2017/022771
Authority: WO
Inventors: Chammi MILLER; Kishore K. Mohanty; Mehdi Matt Honarpour; Edward A. Turek; Douglas G. PECK
Original assignee: Bhp Billiton Innovation Pty Ltd.; Board Of Regents, The University Of Texas System
Priority date: 2016-03-18
Filing date: 2017-03-16
Publication date: 2017-09-21

Abstract

Chemical compositions or "cocktails" for injecting into shale oil formations to stimulate oil, condensate and/or gas recovery are disclosed, along with the corresponding processes for stimulating oil, condensate and/or gas recovery. These chemical cocktails or are referred to as energizing fluids, and they deliver improved performance for stimulating recovery and provide a combined or synergistic effect when prepared and used as disclosed.

Description

ENERGIZING FLUIDS FOR SHALE FORMATIONS

CROSS REFERENCE TO RELATED APPLICATIONS

This application claims priority benefit of U.S. Provisional Application No. 62/310,064, filed March 18, 2016, and U.S. Provisional Application No. 62/470,602, filed March 13, 2017, each of which is incorporated by reference herein in its entirety.

TECHNICAL FIELD OF THE INVENTION

This disclosure relates to the recovery of oil from shale oil formations and chemical compositions used in stimulating shale oil formations.

BACKGROUND OF THE INVENTION

The development of alternative energy sources has become increasingly attractive, not only because energy consumption is increasing faster than new sources are discovered, but also for regulatory, economic, environmental and geopolitical reasons. One appealing alternative energy source is shale oil from which oil, gas and condensates can be extracted and subsequently refined and used. A fundamental economic factor that dictates the viability of extracting energy from shale oil is the extent to which the shale oil formation can be stimulated to achieve commercially-viable levels of production.

Shale oil formations or reservoirs contain crude oil and also contain varying amounts of kerogen and bitumen, which are essentially precursors to the crude oil and gas. Kerogen is a complex mixture of organic compounds that are generally insoluble in common organic solvents largely due to their high molecular weights. Bitumen is also a complex mixture of organic compounds, but bitumen is more soluble in common organic solvents as its constituents are generally lower molecular weight than kerogen components. During the oil generation process or primary production, some of the higher molecular weight organic compounds from kerogen and bitumen may be non-movable or may be deposited in the shale pore spaces, reduce porosity, and complicate the recovery of hydrocarbons from the shale oil formation.

Therefore, the technical challenges associated with extracting hydrocarbons from shale oil formations are substantial, and improvements in existing technologies are needed. There is a particular need for new technologies for extracting oil, gas and condensates from a shale formations that will improve the commercial viability of this process. Improvements in such technologies should also moderate the price of oil and generally reduce U.S. dependence on foreign oil.

SUMMARY OF THE INVENTION

This disclosure provides for new chemical compositions and processes for injecting the new chemical compositions into shale oil reservoirs or formations to stimulate oil, condensate and/or gas recovery. The specific compositions are centered around chemical "cocktails" or combinations of chemical components, referred to as energizing fluids, that deliver improved performance for stimulating recovery and provide a combined or synergistic effect as compared to the results when using any single or individual component in the same manner. Moreover, the energizing fluids can be injected into shale oil reservoirs or formations prior to, simultaneously with, or after injecting a fracturing fluid, including during fracturing, refracturing or defracturing. The disclosed energizing fluids may also be injected in any sequence in a chemical alternating gas (CAG) injection process, with gases such as a hydrocarbon gas and carbon dioxide.

In an aspect, there is provided a process for stimulating oil, condensate and/or gas recovery from a hydrocarbon-bearing shale formation, the process comprising:

a) injecting an energizing fluid into a hydrocarbon-bearing shale formation comprising oil, condensate and/or gas, the energizing fluid comprising, consisting essentially of, or being selected from any combination of at least two of:

i) an oxidizing agent comprising a peroxymonosulfate ([O₃SOOH]^") compound; ii) a surfactant; and

iii) an acid;

b) contacting the hydrocarbon-bearing shale formation having a pre-contact permeability with the energizing fluid, under conditions sufficient to increase the pre-contact permeability; and

c) recovering one or more of the oil, condensate and/or gas.

Another aspect of the disclosure provides for the chemical cocktails or "energizing fluids" for stimulating oil, condensate and/or gas recovery from a hydrocarbon-bearing shale formation, the energizing fluid comprising, consisting essentially of, or being selected from any combination of at least two of: a) an oxidizing agent comprising a peroxymonosulfate ([O₃SOOH]^") compound;

b) a surfactant; and

c) an acid.

If desired, the energizing fluids according to the preceding composition or process that uses the composition, can further comprise one, or any combination of more than one, of:

d) an organic solvent;

e) a hydrocarbon gas;

f) a synthetic brine; and/or

g) carbon dioxide.

Accordingly, the process for stimulating oil, condensate and/or gas recovery from a

hydrocarbon-bearing shale formation can use an energizing fluid that includes, if desired, any one, or any combination of more than one, of these components d) through g) recited above. That is, the energizing fluid can also consist essentially of or be selected from any combination of at least two of components a), b) and c) listed above and one or any combination of more than one of components d), e), f) and g).

The oxidizing agent component was used in the present compositions and methods for oxidizing non-movable or low-mobility organic materials. It was discovered that an oxidizing agent comprising a peroxymonosulfate ([O₃SOOH]^") compound, such as potassium

peroxymonosulfate (OXONE®) not only increased permeability substantially and provided economic efficiency, it also exhibited a synergistic effect with other cocktail components.

Therefore, in an aspect, there is provided

In an aspect, there is provided a process for stimulating oil, condensate and/or gas recovery from a hydrocarbon-bearing shale formation in which peroxymonosulfate ([O₃SOOH]^") is used along with other cocktail components, the process comprising:

a) injecting an energizing fluid into a hydrocarbon-bearing shale formation comprising oil, condensate and/or gas, the energizing fluid comprising: i) an oxidizing agent comprising, consisting of, or selected from a peroxymonosulfate ([O₃SOOH]^") compound; and one or both of ii) a surfactant; and iii) an acid;

b) contacting the hydrocarbon-bearing shale formation having a pre-contact permeability with the energizing fluid, under conditions sufficient to increase the pre-contact permeability; and c) recovering one or more of the oil, condensate and/or gas.

Therefore, there is also provided an energizing fluid comprising: i) an oxidizing agent comprising a peroxymonosulfate ([O3SOOH]^") compound; and one or both of ii) a surfactant; and iii) an acid.

A surfactant component can be used in the compositions and methods to reduce low interfacial tension, which in turn reduced water holdup and enhances recovery. Examples of suitable surfactants include AOS C14-C16 which is stable at relatively high temperatures and high salinity, and carboxylate + IOS 1518 mixtures which works well for low salinity conditions. Most of the surfactants described herein are generally stable from about 50,000 ppm salinity or lower for relatively short term (ca. 1 day) applications. Other examples of suitable surfactants include carboxylate surfactants, which show ultralow tension microemulsions (type III regions) with oil.

An acid component can also be used in the present energizing fluid compositions and methods for enhancing recovery. Mineral dissolution by an acid can increase the permeability and porosity of shale matrix. In some aspects, strong acids such as hydrochloric acid can be used. In other aspects, weak acids such as phosphoric acid and acetic acid can be used, which not only improve permeability but maintain surface strength very well.

Kerogen thermal maturation can leave low mobility remnants of the original kerogen, and the present energizing fluid compositions can use an organic solvent if desired. Compositions including organic solvents can help solubilize the hydrocarbons as well as these kerogen remnants and improve oil flow. A wide range of aliphatic and aromatic solvents can be used in this aspect, and examples of suitable organic solvents include cyclohexane, naphtha, and limonene. It was unexpectedly discovered that energizing fluids that include limonene work particularly well, as do energizing fluids that include naphtha.

Hydrocarbon ("HC") gases can be used as a component of the disclosed energizing fluids and associated methods. Examples of HC gases that can be used in the disclosed energizing fluids include, but are not limited to, natural gas, methane, ethane, propane and butane, and any combinations thereof. This disclosure provides for the use of HC gases as a component of the energizing fluid itself and also for the use of HC gases in any sequence in a chemical alternating gas (C AG) injection process. Relative permeability of oil is higher in water-wet rocks than in oil-wet rocks, yet shale samples are oil-wet in formation brine. Using conventional KCl solutions, wettability remained oil-wet as concentration changed from high to low salinity. However, using synthetic brine as a component of the energizing fluid, wettability was changed preferentially from oil-wet to water- wet, including at a very low salinity (for example, about 0.1 wt% NaCl). AMPHOAM®, CALF AX®, and Lauryl Betaine are examples of surfactants that work well for wettability alteration, particularly when using high salinity brines.

Carbon dioxide (C0₂) is also a useful component of the disclosed energizing fluids. This disclosure provides for the use of HC gases as a component of the energizing fluid itself and also for the use of HC gases in any sequence in a chemical alternating gas (CAG) injection process.

These and other aspects and embodiments of the new chemical compositions and processes for injecting the new compositions into shale oil reservoirs or formations to stimulate oil, condensate and/or gas recovery are disclosed in the Detailed Description. Examples of specific chemical cocktails that have unexpectedly delivered improved performance for stimulating recovery and provided a combined or synergistic effect include, but are not limited to: surfactant + acid; oxidizing agent (peroxymonosulfate) + acid; surfactant + acid + organic solvents; and surfactant + acid + HC gases. Test results are set out that demonstrate the efficacy of these chemical cocktails, including their stability.

BRIEF DESCRIPTION OF THE DRAWINGS

Figure 1 plots the X-ray Fluorescence (XRF) composition Eagle Ford shale samples (6 samples).

Figure 2 presents a schematic diagram for the low pressure crushed shale extraction test procedure.

Figure 3 presents a schematic diagram for the high pressure crushed shale extraction test procedure.

Figure 4 illustrates a schematic diagram for the crushed shale reaction experiments procedure for the brine, acid, and oxidizing agent tests.

Figure 5 provides a schematic diagram of flow cell experiments and shows photographs and diagrams of the flow cell, an internal view of the flow cell system, and an epoxy- immobilized shale slice. Figure 6 provides a schematic diagram of contact angle experiments.

Figure 7 plots the XRF analysis of Eagle Ford shale samples acid treated with phosphoric acid or HC1 at various concentrations.

Figure 8 provides an XRF graph of elemental compositions of OXONE® treated Eagle Ford shale at different pH values.

Figure 9 illustrates the mass change trends and pH change trend with changes in

OXONE® concentration, and it is seen that mass change is relatively small. Each test was carried out at 125 °C for 7 days.

Figure 10 shows the temperature change during heating, and reveals that there are no temperature spikes.

Figure 11 illustrates the mass and pH change as a function of increasing HC1

concentration.

Figure 12 presents an XRF analysis for Permian Basin shale samples.

Figure 13 shows the XRF composition of Mika A shale samples and Eagle Ford bulk samples (STS).

Figure 14 provides a schematic diagram of a conductivity experiment.

Figure 15 shows fluid analysis of calcium and potassium ions while Mika A was subjected to a fracture conductivity experiment.

Figure 16 shows fluid analysis of sulfate and sodium ions while Mika A was subjected to a fracture conductivity experiment.

Figure 17 provides a schematic diagram of flow cell experiments and shows photographs and diagrams of the flow cell and an internal view of the flow cell system.

Figure 18 shows the effects of sulfate ions on acid-calcite reaction rate in static experiments at 125 °C.

Figure 19 shows concentration dependent reactions for weak acid -CH₃COOH.

Figure 20 shows pH change in an acetic acid-calcite time dependent experiment.

Figure 21 shows the change in Ca²⁺ concentration in acetic acid-calcite time dependent experiments.

Figure 22 shows the change in S0₄ ^2" concentration in acetic acid-calcite time dependent experiments. Figure 23 shows results from a volumetric study of the oxone reactivity in a cocktail mixture (0.5% Oxone, 0.5% Calfax, 2% limonene, and 0.2% NaCl) and in a 0.2% NaCl solution (0.5% Oxone, 0.2% NaCl).

Figure 24 shows results from a volumetric study of the oil recovery from a cocktail mixture with limonene (0.5% Oxone, 0.5% Calfax, 2% limonene, and 0.2% NaCl) and a cocktail mixture without limonene (0.5% Oxone, 0.5% Calfax, and 0.2% NaCl) at variable shale to cocktail volume ratios.

DETAILED DESCRIPTION OF THE INVENTION

General Description

In the development of chemicals and/or chemical cocktails that can be injected into shale oil reservoirs to stimulate oil recovery, it was desirable that these energizing fluids would be suitable for injection prior to or simultaneously with a fracturing fluid, regardless of whether fracturing occurred. It was also desirable that injecting the energizing fluid could be effected prior to or simultaneously with a fracturing fluid during fracturing, refracturing or defracturing. Moreover, the energizing fluids that have been developed also can be injected in any sequence in a chemical alternating gas (CAG) injection process, with gases such as a hydrocarbon gas, carbon dioxide, and the like.

Tests were initially carried out on Eagle Ford shale, which is predominantly calcite (calcium carbonate, about 55%) and has a total organic content (TOC) varying from about 5-6 wt%. The Eagle Ford shale has a surface that appears very homogeneous, having no apparent natural fractures at the micrometer resolution. Tests were also carried out on a Permian Basin core, which is predominantly quartz and has less than about 8 wt% calcite. Development work was also carried out on Mika A shale, which is rich in calcium.

In an aspect, this disclosure provides a process for stimulating oil, condensate and/or gas recovery from a hydrocarbon-bearing shale formation, the process comprising:

a) injecting an energizing fluid into a hydrocarbon-bearing shale formation comprising oil, condensate and/or gas, the energizing fluid comprising any combination of at least two of:

iii) an acid; b) contacting the hydrocarbon-bearing shale formation having a pre-contact permeability with the energizing fluid, under conditions sufficient to increase the pre-contact permeability; and

c) recovering one or more of the oil, condensate and/or gas.

According to another aspect, there is provided an energizing fluid for stimulating oil, condensate and/or gas recovery from a hydrocarbon-bearing shale formation, the energizing fluid comprising any combination of at least two of:

a) an oxidizing agent comprising a peroxymonosulfate ([O₃SOOH]^") compound;

b) a surfactant; and

c) an acid.

In another aspect, this disclosure provides a process or an energizing fluid as set out above, in which the energizing fluid further comprises one, or any combination of more than one, of the following additional components:

d) an organic solvent;

e) a hydrocarbon gas;

f) a synthetic brine; and/or

g) carbon dioxide.

Each of the combinations of chemical components that are encompassed by this disclosure is described as follows, and the particulars of each individual component that can be used in these combinations are further described.

In these aforementioned aspects or embodiments, an aspect, peroxymonosulfate is selected as a component of the energizing fluid, therefore, the energizing fluid comprises: i) an oxidizing agent selected from, consisting of or comprising a peroxymonosulfate ([O₃SOOH]^") compound; and one or both of ii) a surfactant; and iii) an acid.

Energizing Fluid Components

The energizing fluid disclosed herein includes combinations of selected components, specifically, the energizing fluid comprising any combination of at least two of: i) an oxidizing agent comprising a peroxymonosulfate ([O3SOOH]^") compound; ii) a surfactant; and iii) an acid. In addition to any combination of at least two of these components recited immediately above, the energizing fluid can further comprise one, or any combination of more than one, of: iv) an organic solvent; v) a hydrocarbon gas; vi) a synthetic brine; and/or vii) carbon dioxide.

Accordingly, the energizing fluid disclosed herein can comprise, consist essentially of, or can be selected from:

an oxidizing agent and a surfactant;

an oxidizing agent and an acid;

a surfactant and an acid; or

an oxidizing agent, a surfactant, and an acid.

If desired, each of these four combinations of oxidizing agent, surfactant, and acid components can further include (comprise, consist essentially of, or can be selected from):

an organic solvent;

a hydrocarbon gas;

a synthetic brine;

carbon dioxide;

an organic solvent and a hydrocarbon gas;

an organic solvent and a synthetic brine;

an organic solvent and carbon dioxide;

a hydrocarbon gas and a synthetic brine;

a hydrocarbon gas and carbon dioxide;

an organic solvent, a hydrocarbon gas, and a synthetic brine;

an organic solvent, a hydrocarbon gas, and carbon dioxide;

an organic solvent, a synthetic brine and, carbon dioxide;

a hydrocarbon gas, a synthetic brine and, carbon dioxide; or

an organic solvent, a hydrocarbon gas, a synthetic brine, and carbon dioxide.

In any of the aforementioned embodiments or aspects, the oxidizing agent can comprising, consist essentially of, consist of, or be selected from a peroxymonosulfate ([O3SOOH]^") compound.

The following sections set out the particulars of each of these energizing fluid components. Unless otherwise indicated or the context does not allow, the wt % compositions disclosed below are the weight percentages in the final aqueous energizing fluid composition. Oxidizing agent

The disclosed energizing fluid includes an oxidizing agent component, used in any combination with any one or both of a surfactant and an acid. That is, combinations with an oxidizing agent include: an oxidizing agent and a surfactant; an oxidizing agent and an acid; and an oxidizing agent, a surfactant, and an acid. The oxidizing agent component can be used with the other energizing fluid components of this disclosure in any combination or subcombination.

The oxidizing agent used in the energizing fluids of this disclosure comprises a peroxymonosulfate ([O3SOOH]^") compound. Use of the term "compound" includes any compound containing the peroxymonosulfate moiety, including salts thereof. The oxidizing agent can also include further oxidants, if desired, with the peroxymonosulfate compound. In an aspect, the oxidizing agent can comprise, can consist essentially or, or can be selected from a peroxymonosulfate compound. According to a further aspect, the oxidizing agent can be absent any other oxidant except for a peroxymonosulfate compound. That is, if desired, the oxidizing agent can consist essentially of or can be selected from a peroxymonosulfate compound. The peroxymonosulfate ([O3SOOH]^") compound can be used with the other energizing fluid components in any combination or subcombination. In an aspect, compounds containing the peroxomonosulfate ([SO₅]^2") ion, the peroxydi sulfate ([S₂O₈]^2") ion, or their acids, can be used in energizing fluids of this disclosure, either alone or in combination with each other, with peroxymonosulfate ([O₃SOOH]^") compounds, or other oxidants.

A common a peroxymonosulfate compound that is useful in the compositions and processes of the disclosure is potassium peroxymonosulfate, which is available under the trade names OXO E® and CAROAT®. Also, peroxymonosulfate compounds are also referred to as monopersulfate compounds. Therefore, the chemical names potassium peroxymonosulfate, potassium monopersulfate (abbreviated KMPS), and these trade names are used interchangeably in this disclosure. Potassium peroxymonosulfate occurs in the form of the triple salt, represented by the formula 2KHS05*KHS0₄*K₂S0₄, which may also be used interchangeably with the names above. Any other peroxymonosulfate salt or compound may also be used.

Because the oxidizing agent used in the energizing fluids of this disclosure can comprise a peroxymonosulfate compound such as potassium peroxymonosulfate, additional oxidants can be included in the oxidizing agent component. Examples of additional oxidants that can be used as a component of the oxidizing agent component include but are not limited to, hydrogen peroxide, air, oxygen-enriched air, oxygen, oxygen plus carbon dioxide, and oxygen plus other inert diluents. Further examples of additional oxidants that can be used as a component of the oxidizing agent component include a permanganate compound, examples of which include potassium permanganate, sodium permanganate, calcium permanganate, and ammonium permanganate.

Generally, the oxidizing agent can be present in the energizing fluid from about 0.1 wt% to about 5 wt%. That is, the oxidizing agent can be present in about 0.1, about 0.2, about 0.3, about 0.4, about 0.5, about 0.6, about 0.7, about 0.8, about 0.9, about 1, about 1.1, about 1.2, about 1.3, about 1.4, about 1.5, about 1.6, about 1.7, about 1.8, about 1.9, about 2, about 2.1, about 2.2, about 2.3, about 2.4, about 2.5, about 2.6, about 2.7, about 2.8, about 2.9, about 3, about 3.1, about 3.2, about 3.3, about 3.4, about 3.5, about 3.6, about 3.7, about 3.8, about 3.9, about 4, about 4.1, about 4.2, about 4.3, about 4.4, about 4.5, about 4.6, about 4.7, about 4.8, about 4.9, or about 5 wt%. Concentrations greater than 5 wt% are also useful. In some embodiments, it is preferable to have sulfate based oxidizing agents present in the energizing fluids from about 0.1 wt% to about 1 wt%. That is, in some embodiments, a sulfate based oxidizing agent is preferably present in about 0.1, about 0.2, about 0.3, about 0.4, about 0.5, about 0.6, about 0.7, about 0.8, about 0.9, or about 1 wt%. Applicants intend that any ranges or combinations of subranges between any of these concentrations are encompassed by this disclosure.

Surfactant

The disclosed energizing fluid also includes a surfactant, which can be used in any combination with any one or both of an oxidizing agent and an acid. That is, combinations with a surfactant include: a surfactant and an oxidizing agent; a surfactant and an acid; and a surfactant, an oxidizing agent, and an acid. The surfactant can be used with the other energizing fluid components of this disclosure in any combination or subcombination.

Generally, suitable surfactants can comprise, consist essentially of, or be selected from a non-ionic surfactant, an anionic surfactant, a cationic surfactant, an amphoteric surfactant, or a silane. Examples of useful surfactants include, but are not limited to, an internal olefin sulfonate (IOS), an alpha-olefin sulfonate (AOS), an alkyl aryl sulfonate (ARS), an alkane sulfonate, a petroleum sulfonate, an alkyl diphenyl oxide (di)sulfonate, an alcohol sulfate, an alkoxy sulfate, an alkoxy sulfonate, an alcohol phosphate, an alkoxy phosphate, a sulfosuccinate ester, an alcohol ethoxylate, an alkyl phenol ethoxylate, a quaternary ammonium salt, a betaine or a sultaine.

Within each of the surfactant types described above, a variety of specific or subgenus of surfactance can be selected. For example, useful surfactants in the energizing fluids can comprise, consist essentially of, or be selected from a carboxylate, the carboxylate comprising a C28-25PO-45EO-carboxylate, a C12-322-50PO 2-100EO carboxylate, a C12-322-50PO carboxylates, C12-322-100EO carboxylates, Tristyrylphenol (TSP) 2-50PO 2-100EO

carboxylate, Tristyrylphenol (TSP) 15PO 22EO carboxylate, a monoalkylphenolalkoxy carboxylate, a dialkylphenolalkoxy carboxylate, Coco amidopropylbetaine, CI 2-20 betaines or sultaines.

Suitable surfactants in the energizing fluids also can comprise, consist essentially of, or be selected from a sulfate, the sulfate comprising a TSP-35PO-20EO sulfate, a TSP 2-50PO 2- 100EO sulfate, a monoalkylphenolalkoxy sulfate, a dialkylphenolalkoxy sulfate, a

trialkylphenolalkoxysulfate, a C13-13PO-sulfate, a C10-12-2.5EO-sulfate, a C12-322-50PO 2- 100EO sulfate, a C12-322-50PO sulfate, or a C12-322-100EO sulfate.

Useful surfactants in the energizing fluids also may comprise, consist essentially of, or be selected from a sulfonic acid or sulfonate, the sulfonic acid or sulfonate comprising

dodecylbenzenesulfonic acid or sulfonate, a CI 0-20 alkylbenzenesulfonic acid or sulfonate (ABS), a C12-30 internal olefin sulfonate (IOS), a C12-20 alpha-olefin sulfonate (AOS), a C12- 28 glycerol sulfonate, a C12-28 diphenyloxidedisulfonate, a C15-17 alkylbenzenesulfonic acid, a CI 5- 18 internal olefin sulfonate, a CI 9-28 internal olefin sulfonate, a CI 9-23 internal olefin sulfonate, or a CI 2-20 alpha-olefin sulfonate.

Particularly useful surfactants include, but are not limited to, AOS C14-C16, C28 25PO 45EO carboxylate, TSP 15PO 22EO carboxylate + IOS 1518, C28 25PO 45EO carboxylate + IOS 1518, TDA-35PO-20EO, and TDA-35PO-45EO. Other useful surfactants include, but are not limited to, AMPHOAM®, CALF AX®, Lauryl Betaine, AOS C14-C16, and a combination of IOS 1518 + a carboxylate surfactant.

As disclosed herein certain surfactants may be selected as a function of salinity, and some surfactants work better in high salinity while others work better in low salinity. For example, when the energizing fluid is characterized by a high salinity (>40,000 ppm), the surfactant can comprise or can be selected from AMPHOAM®, CALFAX®, Lauryl Betaine, AOS C14-C16, and/or combinations thereof. Similarly, when the energizing fluid is characterized by a low salinity (<40,000 ppm), the surfactant can comprise or can be selected from AOS C14-C16, IOS 1518 + a carboxylate surfactant, and/or combinations thereof.

Generally, the surfactant can be present in the energizing fluid from about 0.1 wt% to about 5 wt%. That is, the surfactant can be present in about 0.1, about 0.2, about 0.3, about 0.4, about 0.5, about 0.6, about 0.7, about 0.8, about 0.9, about 1, about 1.1, about 1.2, about 1.3, about 1.4, about 1.5, about 1.6, about 1.7, about 1.8, about 1.9, about 2, about 2.1, about 2.2, about 2.3, about 2.4, about 2.5, about 2.6, about 2.7, about 2.8, about 2.9, about 3, about 3.1, about 3.2, about 3.3, about 3.4, about 3.5, about 3.6, about 3.7, about 3.8, about 3.9, about 4, about 4.1, about 4.2, about 4.3, about 4.4, about 4.5, about 4.6, about 4.7, about 4.8, about 4.9, or about 5 wt%. Concentrations greater than 5 wt% are also useful. Moreover, applicants intend that any ranges or combinations of subranges between any of these concentrations are

encompassed by this disclosure.

Another aspect of the surfactant provides for component combinations of the energizing fluid to form an emulsion. Stable emulsions have been developed for the components that, for example, are thermally stable for at least 2 days at the formation temperature. Stable emulsions can be thermally stable for at least over one month at the formation temperature. Calfax is one example of a surfactant that results in a stable cocktail mixture emulsion for over a month (e.g. 0.5% oxone, 0.5%> calfax, 2.0%> limonene, and brine is stable for over a month). In some aspects, brine salinity can vary from about 0.2 wt%> to about 5 wt%> and produce a stable cocktail emulsion. While there is no specific requirement for the volume ratio of organic phase to aqueous phase in the stable emulsions, the energizing fluid can form an emulsion comprising an organic phase and an aqueous phase in a volume ratio from about 40:60 to about 60:40, and a surfactant. The energizing fluid also can form an emulsion comprising an organic phase and an aqueous phase in a volume ratio from about 30:70 to about 70:30, and a suitable surfactant. The energizing fluid also may form an emulsion comprising an organic phase and an aqueous phase in a volume ratio from about 20:80 to about 80:20, and a surfactant. Acids

The disclosed energizing fluid also includes an acid, which can be used in any

combination with any one or both of an oxidizing agent and a surfactant. That is, combinations with an acid include: an acid and an oxidizing agent; an acid and a surfactant; and an acid, an oxidizing agent, and a surfactant. The acid(s) can be used with the other energizing fluid components of this disclosure in any combination or subcombination.

Generally, suitable acids can comprise, can consist essentially of, or can be selected from a mineral (inorganic) acid or an organic acid. Suitable examples of acids include, but are not limited to, hydrochloric acid, phosphoric acid, acetic acid, propionic acid, butyric acid, valeric acid, caproic acid, oxalic acid, lactic acid, malic acid, citric acid or benzoic acid. Various organic acids were particularly useful, for example, citric acid worked well in the disclosed combinations of components in the energizing fluid.

Generally, an acid can be present in the energizing fluid from about 0.1 wt% to about 5 wt%, where concentrations over about 2 wt% are useful particularly for organic acids That is, the acid can be present in about 0.1, about 0.2, about 0.3, about 0.4, about 0.5, about 0.6, about 0.7, about 0.8, about 0.9, about 1, about 1.1, about 1.2, about 1.3, about 1.4, about 1.5, about 1.6, about 1.7, about 1.8, about 1.9, about 2, about 2.1, about 2.2, about 2.3, about 2.4, about 2.5, about 2.6, about 2.7, about 2.8, about 2.9, about 3, about 3.1, about 3.2, about 3.3, about 3.4, about 3.5, about 3.6, about 3.7, about 3.8, about 3.9, about 4, about 4.1, about 4.2, about 4.3, about 4.4, about 4.5, about 4.6, about 4.7, about 4.8, about 4.9, or about 5 wt%. Concentrations greater than 5 wt% are also useful for some organic acids. In some embodiments, it is preferable to have strong acids such as HCl present in the energizing fluids from about 0.1 wt% to about 1.5 wt%. That is, in some embodiments, a strong acid is preferably present in about 0.1, about 0.2, about 0.3, about 0.4, about 0.5, about 0.6, about 0.7, about 0.8, about 0.9, about 1, about 1.1, about 1.2, about 1.3, about 1.4, or about 1.5 wt%. In some embodiments, it is preferable to have organic acids present in the energizing fluids from about 0.1 wt% to about 5 wt%. That is, in some embodiments, an organic acid is preferably present in about 0.1, about 0.2, about 0.3, about 0.4, about 0.5, about 0.6, about 0.7, about 0.8, about 0.9, about 1, about 1.1, about 1.2, about 1.3, about 1.4, about 1.5, about 1.6, about 1.7, about 1.8, about 1.9, about 2, about 2.1, about 2.2, about 2.3, about 2.4, about 2.5, about 2.6, about 2.7, about 2.8, about 2.9, about 3, about 3.1, about 3.2, about 3.3, about 3.4, about 3.5, about 3.6, about 3.7, about 3.8, about 3.9, about 4, about 4.1, about 4.2, about 4.3, about 4.4, about 4.5, about 4.6, about 4.7, about 4.8, about 4.9, or about 5 wt%. Applicants intend that any ranges or combinations of subranges between any of these concentrations are encompassed by this disclosure. Additional or Optional Components

In an aspect, this disclosure provides for the chemical cocktails or "energizing fluids" for stimulating oil, condensate and/or gas recovery from a hydrocarbon-bearing shale formation, in which the energizing fluid comprising, consisting essentially of, or being selected from any combination of at least two of: a) an oxidizing agent comprising a peroxymonosulfate

([O₃SOOH]^") compound; b) a surfactant; and c) an acid. If desired, the energizing fluids according to the preceding composition or process that uses the composition, can further comprise one, or any combination of more than one, of: d) an organic solvent; e) a hydrocarbon gas; f) a synthetic brine; and/or g) carbon dioxide. That is, the process for stimulating oil, condensate and/or gas recovery from a hydrocarbon-bearing shale formation can use an energizing fluid that includes, if desired, any one, or any combination of more than one, of these components d) through g) recited above. That is, the energizing fluid can also consist essentially of or be selected from any combination of at least two of components a), b) and c) listed above and one or any combination of more than one of components d), e), f) and g). each of these additional or optional components is described as follows.

Organic Solvent

In addition to the oxidizing agent, surfactant, and/or acid components described herein, the chemical cocktails (energizing fluids) of this disclosure can also comprise, if desired, an organic solvent for stimulating oil, condensate and/or gas recovery from a hydrocarbon-bearing shale formation. The organic solvent can be used with the other energizing fluid components of this disclosure in any combination or subcombination.

Suitable organic solvents include but are not limited to at least one aliphatic hydrocarbon solvent, at least one aromatic hydrocarbon solvent, or any combination thereof. For example, the organic solvent can comprise, consist essentially of, or be selected from naphtha, limonene, cyclohexane, methyl cyclohexane, pentane, hexane, heptane, octane, and any combination thereof. The solvent limonene is particularly useful in energizing fluids of this disclosure.

Limonene (IUPAC name, l-methyl-4-(l-methylethenyl)-cyclohexene) is a terpene found in citrus fruits, particularly the rinds. The more common <i-isomer (<i-limonene, which is the R-(+)- enantiomer) is produced in nature and therefore is the common industrial form of limonene. However, either enantiomer of limonene as well as racemic limonene (termed dipentene) can be used according to this disclosure. Therefore, the use of the term limonene is intended to encompasses <i-limonene, /-limonene, and i/J-limonene, and any one or any combination of these forms can be used. Advantages of using limonene include that it is sourced from renewable resources and is a product of nature, and its economic viability. The structure of limonene is illustrated here, without designating st

Terpenes other than limonene can also be used in accordance with this disclosure, in place of limonene or other suitable organic solvents, or in addition to limonene or other suitable organic solvents. Examples of other terpenes that can be used include, but are not limited to, pinene and/or terpinene.

For limonene, other terpenes, any other organic solvent, and any particular compound disclosed herein, the general structure presented is also intended to encompasses all

conformational isomers and stereoisomers that can arise from a particular set of substituents, unless indicated otherwise. Thus, the general structure encompasses all enantiomers, diastereomers, epimers, and other optical isomers whether in enantiomeric or racemic forms, as well as mixtures of stereoisomers, as the context permits or requires. For any particular formula that is presented, any general formula presented also encompasses all conformational isomers, regioisomers, and stereoisomers that can arise from a particular set of substituents.

Another useful solvent is naphtha, which includes any boiling range of naphtha. For example, lower-boiling light naphtha (boiling point (b.p.) ca. 30°C-90°C), higher-boiling heavy naphtha (b.p. ca. 90°C-200°C), or combinations thereof can be utilized. Further, naphtha can be used in combinations with other organic solvents in constituting the energizing fluids of this disclosure. Generally, the organic solvent can constitute all of a portion of an organic phase that is used in combination with the water soluble portion of aqueous phase, that together constitute the energizing fluid. Without limitation, generally, the organic phase can be, in volume percent relative to the aqueous phase (i.e. 100 vol% is a 50:50 vol:vol combination), about 10%, about 20%, about 30%, about 40%, about 50%, about 60%, about 70%, about 80%, about 90%, about 100%, about 110%, about 120%, about 130%, about 140%, about 150%, about 160%, about 170%, about 180%, about 190%, about 200%, about 210%, about 220%, about 230%, about 240%, about 250%, about 260%, about 270%, about 280%, about 290%, or about 300% of the aqueous phase. Further, applicants intend that any ranges or combinations of subranges between any of these concentrations are encompassed by this disclosure.

Hydrocarbon Gas

In addition to the oxidizing agent, surfactant, and/or acid components described herein, the chemical cocktails (energizing fluids) of this disclosure can also comprise, if desired, a hydrocarbon (HC) gas for stimulating oil, condensate and/or gas recovery from a hydrocarbon- bearing shale formation. The HC gas can be used with the other energizing fluid components of this disclosure in any combination or subcombination. Generally, suitable hydrocarbon gases can comprise, consist essentially of, or be selected from natural gas, methane, ethane, propane and butane, and any combination thereof.

In another aspect, the energizing fluid can be injected in any sequence in a chemical alternating gas (CAG) injection process that involves a hydrocarbon (HC) gas. For example, the energizing fluid can be injected in a chemical alternating gas (CAG) process that alternates injection of the energizing fluid with injection of a gaseous component selected from the hydrocarbon gas, the organic solvent (which will have a vapor pressure at the injection conditions or be entirely gaseous), carbon dioxide, and any combination thereof.

Synthetic Brine

In addition to the oxidizing agent, surfactant, and/or acid components described herein, the chemical cocktails (energizing fluids) of this disclosure can also comprise, if desired, a synthetic brine for stimulating oil, condensate and/or gas recovery from a hydrocarbon-bearing shale formation. The synthetic brine can be used with the other energizing fluid components of this disclosure in any combination or subcombination. Synthetic brines generally comprise a combination of brine salts, for example, the energizing fluid can include a synthetic brine that comprising any one of, or any combination of, NaCl, KC1, and CaCl₂.

Without limitation, examples of suitable synthetic brines include, but are not limited to, a synthetic brine comprising or consisting essentially of 3-4 wt% NaCl, 0.1-1 wt% KC1, and 0.01-1 wt% CaCl₂ in aqueous solution. Examples of suitable synthetic brines also include, but are not limited to, a synthetic brine comprising or consisting essentially of 6-8 wt% NaCl and 0.5-1.5 wt% CaCl₂ in aqueous solution. While various KC1 concentrations and various synthetic brine concentrations were used for brine dependent wettability studies, a number of Examples of this disclosure employ the following brine composition: 3.4 wt% NaCl, 0.5 wt% KC1, and 0.1 wt% CaCl₂ in aqueous solution. The measured pH of this synthetic was about pH 6.89.

Generally, any individual component of the synthetic brines can be present in the energizing fluid from about 0.1 wt% to about 5 wt%. That is, any individual component of the synthetic brines can be present in about 0.1, about 0.2, about 0.3, about 0.4, about 0.5, about 0.6, about 0.7, about 0.8, about 0.9, about 1, about 1.1, about 1.2, about 1.3, about 1.4, about 1.5, about 1.6, about 1.7, about 1.8, about 1.9, about 2, about 2.1, about 2.2, about 2.3, about 2.4, about 2.5, about 2.6, about 2.7, about 2.8, about 2.9, about 3, about 3.1, about 3.2, about 3.3, about 3.4, about 3.5, about 3.6, about 3.7, about 3.8, about 3.9, about 4, about 4.1, about 4.2, about 4.3, about 4.4, about 4.5, about 4.6, about 4.7, about 4.8, about 4.9, or about 5 wt%.

Concentrations greater than 5 wt% are also useful. Moreover, applicants intend that any ranges or combinations of subranges between any of these concentrations are encompassed by this disclosure.

Carbon Dioxide

In addition to the oxidizing agent, surfactant, and/or acid components described herein, the chemical cocktails (energizing fluids) of this disclosure can also comprise, if desired, carbon dioxide for stimulating oil, condensate and/or gas recovery from a hydrocarbon-bearing shale formation. The carbon dioxide can be used with the other energizing fluid components of this disclosure in any combination or subcombination. For example, the carbon dioxide can be used along with the hydrocarbon gases if desired. In another aspect, the energizing fluid can be injected in any sequence in a chemical alternating gas (CAG) injection process that involves carbon dioxide gas. For example, the energizing fluid can be injected in a chemical alternating gas (CAG) process that alternates injection of the energizing fluid with injection of a gaseous component selected from carbon dioxide, the hydrocarbon gas, the organic solvent (which will have a vapor pressure at the injection conditions or be entirely gaseous), and any combination thereof.

Specific Chemical Cocktail Compositions

The individual components of the energizing fluids (chemical cocktails) have been described, and this section sets out some useful aspects, embodiments, and combinations of selected components that have been found to be useful. These specific chemical cocktails deliver improved performance for stimulating recovery and provide a combined or synergistic effect as compared to the results when using any single or individual component in the same manner. These embodiments and examples are exemplary and are not intended to be limiting, but rather illustrative of how selections of the possible chemical cocktail components can be carried out. Further, unless otherwise indicated or the context does not allow, each of these embodiments and examples can be used in combinations with other components disclosed herein. Also unless otherwise indicated or the context does not allow, the wt % compositions disclosed are the weight percentages in the final aqueous energizing fluid composition.

Aspects, embodiments, and combinations of selected components that are useful in the chemical cocktails and the processes disclosed herein include these combinations, in which the energizing fluid or chemical cocktail can comprise, consist essentially of, or be selected from the following.

1. 0.1-1.0 wt % CALF AX® or a carboxylate surfactant and 0.1-0.5 wt% acetic acid;

2. 0.5 wt % CALF AX® or a carboxylate surfactant and 0.2 wt% acetic acid;

3. 0.1-1.5 wt % OXO E® and 0.5-1.5 wt% HC1 or acetic acid;

4. 0.5-1.0 wt % OXONE® and 1 wt% HC1 or acetic acid;

5. a 40:60 (vokvol) to a 60:40 (vokvol) mixture of:

a) a combination of 0.1-1.0 wt % surfactant and 0.1-0.5 wt% acid; and b) naphtha;

6. a 50:50 (vokvol) mixture of: a) a combination of 0.5 wt % surfactant and 0.2 wt% HC1; and

b) naphtha;

7. a 40:60 (vol: vol) to a 60:40 (vol: vol) mixture of:

a) a combination of 0.1-1.0 wt % surfactant and 0.1-0.5 wt% acid; and b) a hydrocarbon gas;

8. a 40:60 (vol: vol) to a 60:40 (vol: vol) mixture of:

a) a combination of 0.1-1.0 wt % surfactant and 0.1-0.5 wt% acid; and b) carbon dioxide;

9. a 50:50 (vol: vol) mixture of:

a) a combination of 0.5 wt % surfactant and 0.2 wt% HC1; and

b) hydrocarbon gas selected from natural gas, methane, ethane, propane and butane, and any combination thereof;

10. a combination of C28-25PO-45EO-carboxylate, IOS 1518, acetic acid, and limonene;

11. a combination of TDA-35PO-20EO, acetic acid, and limonene;

12. a combination of components that form an emulsion, the emulsion comprising:

a) an organic phase comprising 55-85 wt% limonene;

b) an aqueous phase comprising 1-5 wt% acetic acid and a synthetic brine comprising 3-4 wt% NaCl, 0.1-1 wt% KC1, and 0.01-1 wt% CaCl₂; and

c) a surfactant comprising:

i) 0.1-1 wt% tristyrylphenol (TSP) 15PO 22EO carboxylate and 0.1-1 wt% IOS 1518;

ii) TDA-35PO-20EO; or

iii) TDA-35PO-45EO;

13. a combination of components that form an emulsion, the emulsion comprising:

a) an organic phase comprising 40-60 wt% limonene;

b) an aqueous phase comprising sufficient HC1 to achieve pH of 2 and a synthetic brine comprising 3-4 wt% NaCl, 0.1-1 wt% KC1, and 0.01-1 wt% CaCl₂; and

c) a surfactant comprising 0.3-1.5 wt% CALF AX®.

Again, these aspects, embodiments and examples are merely exemplary and are not intended to be limiting, but simply illustrative of possible chemical cocktails according to the disclosure. Process Parameters for Stimulating Oil, Condensate and/or Gas Recovery

The chemical cocktails or energizing fluids of this disclosure have been found to deliver improved performance for stimulating recovery, and they provide a combined or synergistic effect as compared to the results when using any single or individual component in the same manner. The general process parameters have been set out as follows: there is provided a process for stimulating oil, condensate and/or gas recovery from a hydrocarbon-bearing shale formation, the process comprising:

iii) an acid;

c) recovering one or more of the oil, condensate and/or gas.

The energizing fluid described above can further comprising, consisting essentially of, or be selected from any one, or any combination of more than one, of:

d) an organic solvent;

e) a hydrocarbon gas;

f) a synthetic brine; and/or

g) carbon dioxide.

The energizing fluids can be injected into shale oil reservoirs or formations prior to, simultaneously with, or after injecting a fracturing fluid, including during fracturing, refracturing or defracturing. The disclosed energizing fluids may also be injected in any sequence in a chemical alternating gas (CAG) injection process, with gases such as an organic solvent, a hydrocarbon gas, and carbon dioxide.

Specific process parameters will be appreciated and understood by one of ordinary skill in the art, and in addition, the following process parameters can be specified. The injecting step as set out generally above can be carried out by injecting the energizing fluid prior to or simultaneously with a fracturing fluid, regardless of whether fracturing occurs. Thus, the injecting step can be carried out by injecting the energizing fluid prior to or simultaneously with a fracturing fluid during fracturing, refracturing or defracturing. The injecting step also may be carried out by injecting the energizing fluid after injecting a fracturing fluid.

By way of example, the injecting step and/or the step of contacting the hydrocarbon- bearing shale formation with the energizing fluid generally take place at formation temperature, or alternatively, at a temperature from about 25°C to about 200°C. The energizing fluid can be injected in any sequence in a chemical alternating gas (CAG) injection process, for example, the energizing fluid is injected in a chemical alternating gas (CAG) process that alternates injection of the energizing fluid with injection of a gaseous component selected from the organic solvent, the hydrocarbon gas, and carbon dioxide.

The present disclosure is further illustrated by the following examples, which are not to be construed in any way as imposing limitations upon the scope thereof. On the contrary, it is to be clearly understood that resort can be had to various other aspects, embodiments,

modifications, and equivalents thereof which, after reading the description herein, may suggest themselves to one of ordinary skill in the art without departing from the spirit of the present invention or the scope of the appended claims. EXAMPLES

In the following examples, unless otherwise specified, solvents and reagents were purchased from commercial sources and typically were used as received. Core samples from Eagle Ford shale, Permian Basin shale, and Mika A shale were obtained and tested according to the principles of this disclosure. Unless specified otherwise, a percentage is a weight percentage.

Eagle Ford (EF) Shale

Mineralogy, Elemental Compositions, and Organic Matter

Eagle Ford (EF) shale samples at depths of 11143' and 11227' were evaluated for their composition. Comparative analysis included mineralogy, elemental composition, total organic content (TOC), and thermal degradation. The mineralogy was determined using X-ray diffraction (XRD), the results are presented in Table 1. EF shale is comparatively rich in calcite, which is present in about 55 wt%, quartz is present in about 17 wt%-19 wt%, and clay content is about 15 wt%.

Table 1. XRD analysis for Eagle Ford shale sample at depths 11143' (ft) and 11227' (ft).

The elemental composition of the samples were determined by X-ray florescence analysis. As shown in Figure 1, the EF shale matrix is rich in calcium and silicon, with a Ca/Si ratio of about 1.71 illustrated in the Figure 1 data and a Calcite/(quartz + clay) ratio of about 1.66 provided in the Table 1 data.

The organic content was measured using three different methods: total organic content

(TOC), combustion and thermal gravimetric analysis (TGA). TOC, which represents all organic forms of carbon in the sample, was measured at 1100 °C in the presence of oxygen. All samples were treated with HC1 to remove carbonates (inorganic carbon) before the TOC measurements. The average TOC values of the shale at depth 11143' and depth 11227' were 5.48 wt% and 5.98 wt%, respectively. Combustion was conducted at 350 °C for 7 days, using a sample size of about 30 g. The percent mass loss of the shale at depths 11143' and 11227' were 2.07 wt% and 1.94 wt%, respectively. Both TOC and combustible carbon were comparable for these two different depth samples. Thermal gravimetric analysis (TGA) was performed to understand the bitumen and kerogen content. The samples were heated under nitrogen up to 350 °C at a temperature ramp rate of 5°C/min (minute), followed by maintaining the sample at 350 °C for 30 minutes. The percent mass loss at depth 11143' and depth 11227' samples was 1.07 wt% and 1.16 wt%, respectively. Samples were then heated up to 600 °C at a rate of 5 °C/min, followed by constant heating at 600 °C for 30 minutes. The total mass loss at depth 11143' and depth 11227' samples was determined to be 4.28 wt% and 4.97 wt%, respectively.

The porosity distribution of the samples in the scale of microns was studied by a micro- CT method, also known as high-resolution x-ray tomography or micro-computed tomography (micro-CT or μCT). According to micro-CT images, EF shale matrix is very homogeneous at this scale, and exhibited no apparent fractures. There were some occasional high absorption pixels, which may be due to the presence of pyrite.

Environmental scanning electron microscopy (ESEM) images of an Eagle Ford shale sample were taken to examine grain-scale shale surface morphology. The grains are from about 0.1-3 μιη (micron) in size. There were no apparent fractures at the 1-5 μιη scale. Energy- dispersive X-ray spectroscopy (EDX, also termed energy dispersive X-ray analysis) was carried out in the ESEM testing and shows that the shale surface is rich in calcium.

In summary, mineralogy, elemental composition, and organic content at both depths 11143' and depth 11227' are very similar.

Porosity and Permeability

Eagle Ford (EF) shale samples were examined for permeability using the methods set out below. Generally, data suggests that the porosity of lower layer shale is generally from about 3% to about 6%. Vertical permeability varies in the range from about 0.044 μd to about 0.233 μd, and horizontal permeability varies in the range from about 0.125 μd to about 58 μd.

Permeability for upper and lower level shale samples were measured using a flow cell apparatus described below {see Figure 5). The measured values were found to be 0 μd for 3 samples, 5 μd for one sample and 8 μd for one sample. General Experimental Procedures and Reagents

Crushed shale experimental procedure for solvent extraction

Each experiment to test an organic solvent consisted of three trials. Shale samples were crushed into chips from about 0.5 cm to about 1.0 cm in size (e.g. the size of shale chips was about 0.5 cm x 0.5 cm x 0.5 cm to about 1.0 cm x 1.0 cm x 1.0 cm.). A 5-10 g sample of shale chips were utilized in each test. All solid samples were placed under vacuum for 30 min (minutes) prior to each experiment. All solutions were made according to wt%. From that, (x) mL of liquid was used to keep a consistent shale-to-test reagent volume. The average shale/test reagent ratio is about 1 :5 (v/v ratio) unless otherwise stated. It is assumed this ratio comprises average contacted surface area of the shale with the contacted liquid volume.

In each low pressure test (for example, about 30 psi), shale chips and 10 mL of the corresponding reagents were placed in a custom made reaction vessel, as shown in Figure 2. High pressure experiments (for example, about 500 psi) were performed in a custom made reaction cell shown in Figure 3. All reaction mixtures were placed at 125 °C for 7 days in an explosion proof oven throughout the test.

After the extraction, solid and liquid portions of the test mixture were separated using gravity filtration. The solid samples were dried at 60 °C for 24 hours, and then vacuum dried for an additional 2 hours. The final mass of each shale sample following extraction and proper drying was measured.

After the solvent extraction experiments, a 3 g (gram)-sample of the resulting shale was pulverized for TOC and TGA measurements. The resulting liquid was analyzed by gas chromatography (GC) using a DB-HT Sim Dis column (5 m x 0.53 mm i.d., 0.15 μπι GC column). The chromatograph column oven was heated from 50 °C to 375 °C at 10°/min, using helium carrier gas at 18 mL/min and an FID (flame ionization detector) detector at 425 °C.

Crushed shale experimental procedure for brine, acid and oxidizing agents

Each experiment to test various brine solutions, acids, and oxidizing agents consisted of three trials. Shale samples were again crushed into chips from about 0.5 cm to about 1.0 cm in size, and about 10 g of crushed shale chips were utilized for each experiment. The shale chips were soaked in 100 g of the selected test solution for 7 days at 125 °C, as illustrated in Figure 4. In these tests, the shale chips were soaked in excess test solution (no v/v ratio was controlled) to understand the maximum reactivity.

After soaking the samples under these conditions, the solid and liquid portions of the test sample were separated using gravity filtration. The final mass of the solid was measured after drying the samples for 48 hours at 60 °C. The solid samples were subsequently analyzed for elemental composition changes using X-ray Fluorescence (XRF) and ESEM.

The initial pH of each reaction solution was measured prior to heating, and the final pH of the filtrate from each filtered solution was measured at room temperature. Ion dissolution was measured from emissions in an inductively-coupled plasma (ICP) for Ca²⁺ and Mg²⁺ ion content.

Flow Cell Experiments for Shale Cores

Shale cores were prepared and tested for permeability before and after treatment with the selected chemical cocktails, as follows. A shale core of dimensions 4 in. x 1.5 in. x 1.5 in. was placed inside a 1.75 in. diameter plastic tube, and the space in between core and tube was filled with epoxy. After the epoxy was fully cured, the tube was cut into 0.25 in. -thick slices, and each epoxy-immobilized slice was placed inside the cell. The cell was then sealed with Teflon® O- rings as illustrate in Figure 5. Once sealed, the cell was pre-flushed with a 3% KCl(aq) solution.

As shown in Figure 5, two Back Pressure Regulators (BPR) were used to regulate the flow along the shale surface and the flow perpendicular to the shale surface. The inlet pressure was slightly above 120 psi, surface outlet flow pressure was 120 psi, and penetration outlet flow was 90 psi. After the system reached the required pressure gradients, the flow was switched to the test solution. The initial flow rate was 0.1 mL/min. After 48 hours the flow was stopped and the system was allowed to rest or soak for 24 hours. After this rest period, the flow was switched back to pre-flush fluid for 24 hours at 0.5 mL/min. The surface flow effluents and the penetration effluents as illustrated in Figure 5 were collected every 2 hours. The final pre-flush fluids were collected every 2 hours up to 6 hours.

The effluents were tested for pH and Ca²⁺ ion concentration. Following the tests, the core was removed from the flow cell and washed with 3% KCl(aq). The resulting core was vacuum dried for 24 hours and the final weight of the core was measured after drying.

Following treatment with the selected chemical cocktails as described, the core was then placed back into the flow cell in order to measure post-reaction {i.e. post-treatment) permeability using this method. The core was also evaluated for new fractures using micro-CT, and the surface morphology and elemental distribution were analyzed using an ESEM.

Reagents and Chemicals

All salts used for preparing brines were purchased from Fisher Scientific (ACS grade). Various KCl concentrations and various synthetic brine concentrations were prepared and used for brine-dependent wettability studies. For all other experiments, the brine composition used was 3.4 wt% NaCl, 0.5 wt% KCl, and 0.1 wt% CaCl₂. The pH of this synthetic brine solution was about pH 6.89.

Hydrochloric acid, phosphoric acid, acetic acid and other acids were purchased from Fisher Scientific (ACS grade). Various acid concentrations were used in a 40,000 ppm synthetic brine. The pH and densities of each acid solution were measured.

The following oxidizing agents were tested: potassium permanganate in HCl, potassium permanganate in NaOH, potassium dichromate in HCl, and OXONE®. These oxidizing agents used for testing were all purchased from Fisher Scientific (ACS grade).

The following organic solvents tested were also purchased from Fisher Scientific (ACS grade): naphtha boiling range 35-60°C, <i-limonene, and cyclohexane. All the gases were purchased from Praxair.

Contact Angle Measurements in Brine

Before contact angle measurements, shale samples were aged in crude oil at 80 °C for a month. The oil aged shale samples were then each placed in a quartz cell and covered with a lid. Samples were heated up to 80 °C before the measurements. An oil droplet was introduced carefully onto the bottom of the shale surface using a needle, and the image of the oil droplet was recorded. A Rame-hart Model 500 Advanced Goniometer with DROPimage Advanced v2.4 was used for all the measurements.

Contact Angle Measurements in Surfactant Solutions

As illustrated in the schematic diagram of Figure 6, all shale samples were aged in crude oil at 80 °C for a month prior to contact angle testing. Samples were placed in synthetic brine for 1 hour to confirm that they were oil wet. Each shale sample was then equilibrated by heating at 80 °C for one hour prior to measurements. An external crude oil droplet was then introduced and the contact angle was measured in brine. The plate was then transferred into a surfactant solution and equilibrated at 80 °C for 10-15 minutes. Then an external oil droplet was introduce every 30 minutes up to 2 hours and the contact angles were measured. Contact angles were measured in this manner for up to 48 hours. A Rame-hart Model 500 Advanced Goniometer with DROPimage Advanced v2.4 was used for all the measurements.

Results of Treatment with Individual Fluid Components and Chemical Cocktails

Solvent Extraction

The solvent extraction tests utilized three different solvents, specifically, cyclohexane, naphtha, and limonene, as well as mixtures thereof. All the experiments were conducted at 125 °C and above the critical vapor pressure of the solvents.

As explained below, the percentage mass difference (ΔΜ %) is not a direct measure of the extent of organic dissolution, but provides a proxy measurement that is related to the extent of dissolution. In order to understand the organic matter dissolution process, the extract was analyzed using gas chromatography (GC). The extracted organic compounds were quantified as the percent of dissolved material (solute) in each solvent. The base solvent peak was used in calculation to quantify the solute. As seen in the data of Table 2, cyclohexane extraction under the stated conditions resulted in a mass change of 1.3 wt% in the matrix.

Table 2. Solvent extraction data for solid matrix

The data obtained from the GC analysis of the extract is presented in Table 3 and provides an explanation for this process. The percentage mass change in shale matrix (Table 2) is thought to reflect the removed organics plus water removed during the extraction process. The GC data show the percent solute in the dissolved organic content. Limonene extraction is seen to provide about 1.36 wt% dissolved solute under low pressure conditions, whereas cyclohexane has only about 0.13 wt% dissolved solute under high pressure conditions. Further, the GC data reveal that limonene has extracted 204 different compound in its extract, as compared to 29 compounds for the cyclohexane extract. Naptha extraction provided 0.74 wt% solute and 24 compounds. The cyclohexane-limonene mixture also worked well in the extraction process.

Table 3. GC data for extracted solvents

In the solvent testing process in this disclosure, and while not intending to be bound by theory, solvent molecules diffuse into the matrix and dissolve some of the organic molecules. A portion of the organic molecules diffuse out of the matrix, which some of the solvent molecules stay in the matrix. As a result, the measured mass difference is not a direct measure of the extent of organic dissolution, but provides a proxy measurement that is related to the extent of dissolution. While not intending to be bound by theory, it is thought that during the oil generation process or primary production, some asphaltene type of organic material could be deposited in the pore space of shales. It is possible this non-movable bitumen might be dissolved in organic solvents, which could perhaps clear the flow path resulting in improved recovery and enhanced permeability.

Acid Tests— Mineral Dissolution in Crushed Shale

Eagle Ford shale is rich in calcite, therefore it was thought that the injection of acid into fractures might result in dissolution of some of the calcite, thereby increasing the permeability of the matrix. It was further believed that a combined or synergistic effect may be possible with combining acids with the other energizing fluid components described herein. Without being bound by theory, while the reaction of the shale with acid might increase the surface roughness, which would positively affect fracture conductivity, an incorrectly selected acid, improper acid strength, or excessive concentrations of the acid might result in excessive dissolution on a rock face, possibly decreasing its strength and lowering the fracture conductivity.

The following acids were selected for their properties and tested in this Example:

hydrochloric acid (HC1), phosphoric (H3PO₄) and acetic acid (HO₂CCH3, also abbreviated HO Ac or MeC0₂H). Calcite consists of calcium carbonate and alkaline earth metal carbonates such as calcium carbonate generally react with acids according to the following equation.

2HA (aq) + MC0₃ (s)→ M²⁺(aq) + 2A^" (aq) + C0₂ (g) + H₂0 (1); M = Ca, Mg

If the acid reacts completely (100%) with the calcite it contacts, the fracture surface may become weaker. Therefore, in order to obtain surface roughness and permeability enhancement without adversely affecting fracture conductivity, the specific selected acid, acid strength, and concentrations were carefully controlled. Generally, it was found that the controlled reactivity of an acid could be achieved by using sufficiently low concentrations. Alternatively, the selection of the acid according to strength (acid dissociation constants), particularly using acids over a range of relatively weak acid strengths such as found in organic acids, provided good control over the acid reaction. That is, certain weak having measureable and relatively low acid dissociation constants was found to provide control over the acid reaction so that surface roughness and permeability enhancement (without adversely affecting fracture conductivity) could be achieved.

Table 4 summarizes the mineral dissolution with different acids at variable

concentrations. The volume ratio of shale to acid solution was -1 :5 (v/v). All of these examples were conducted at 125 °C for 7 days, and the percentage mass change was measured, along with the initial and final pH of the mixture of acid and shale. The extent of the acid reaction with calcite was measured by determining the calcium (Ca²⁺) concentration in the final mixture. Table 4. Mineral dissolution data in different aqueous acids

As Table 4 illustrates, based on the final basic pH of the hydrochloric acid examples, the HCl was completely consumed during the reaction with calcite. The mass change of 27.6% with 2% HCl(aq) reveals that a significant amount of matrix surface was eroded during the process. Based on a scratch test, the surface had become much softer after the HCl treatment.

Phosphoric and acetic acid reacted much differently from treatment with HCl. These acids were not consumed 100% after 7 days according to the final pH of the solutions, which remained acidic. The 5% acetic acid (CH₃C0₂H) dissolved 21.66% of shale matrix. However this surface was much harder as compared to the HCl-treated shale surface.

In the phosphoric acid-treated samples, the shale mass actually increased after the reaction due to calcium phosphate deposition. This deposition was demonstrated using ESEM analysis. ESEM images of 2% phosphoric acid treated Eagle Ford shale samples showed that calcium phosphate was crystallized on the surface of the shale sample. Therefore, phosphoric acid is a good candidate for generating in situ proppant on the facture surfaces.

A comparative analysis of elemental compositions of the phosphoric acid and hydrochloric acid treated samples versus untreated samples was undertaken, and the results are illustrated in the XRE analysis chart of Figure 7. These elemental analysis results revealed that 2% phosphoric acid yield significantly phosphate deposition (Figure 7). Furthermore, calcium dissolution was lower for the shale in phosphoric acid.

Acid Tests— Flow Cell Experiments for Shale Cores with Acids

Flow cell experiments were conducted using flow cell apparatus illustrated in Figure 5, using 1%) hydrochloric acid and 2% phosphoric acid. Shale cores were prepared and the experimental procedure for these tests were carried out as presented above in the procedure for Flow Cell Experiments for Shale Cores.

For the HC1 flow cell experiment, the initial pH of the solution was pH 0.96 and the pH of the fluid that flowed through the shale was pH 7.02. The pH of the fluid that flowed past the top shale surface was pH 6.57. These pH measurements of the effluents confirmed the substantially total consumption of the acid. The results of the permeability measurements in the flow cell are shown in Table 5. Permeability of the core was measured to increase from 8 μd to 100 μd in this HCl(aq) experiment. Table 5. Permeability data for acid flow cell experiments

Environmental scanning electron microscopy (ESEM) images of the shale surface before and after acid treatment were taken, and showed that the roughness of the surface increased significantly with acid treatment. For example, ESEM images of two Eagle Ford shale surfaces, one treated with 1% HC1 and the other untreated, showed that surface roughness increased significantly with acid treatment. However, the surface hardness decreased from 117 to 70 MPa, as suggested previously in with the scratch test. For reference, the surface hardness of the pure Eagle Ford shale generally varies from 95-117 MPa.

Energy-dispersive X-ray spectroscopy (EDX) analysis of pure Eagle Ford shale and HQ- treated Eagle Ford shale for a 2 μπι x 2 μπι area was performed. This analysis showed a significant decrease of calcium from the surface of the shale with HC1 treatment. It is thought that acid had reacted with calcite on the surface to remove solid calcium(2+) from the surface, thus the clay content on the surface is more dominant after the acid treatment than before acid treatment. EDX mapping diagrams of pure Eagle Ford shale and HC1 treated Eagle Ford shale showed the elemental distribution in a 2 μπι x 2 μπι area of the shale surface, and further highlighted the loss of calcium relative to aluminum and silicon following treatment. Micro-CT (micro-computed tomography or μCT) images showed that the apparent micro fractures created after HC1 acid treatment were about 40-80 μπι. The phosphoric acid treatment provided different results as follows. The initial pH of the phosphoric acid was pH 1.10 and the pH of the fluid that flowed through the shale was pH 4.35, demonstrating some reaction but maintenance of the acidic solution. The surface effluent fluid pH was about pH 2.35. These results reveal that acid did not react completely with shale matrix. The top shale surface was observed to have many artifacts after the experiments. Phosphoric acid treated shale has apparent micro factures present according to micro-CT images.

ESEM images were taken from the bottom of the phosphoric acid-treated shale sample. As seen in ESEM images of the phosphoric acid treated core, there are apparent calcium phosphate crystals situated on the bottom surface of the core. It is evident that in-situ crystal formation required some soaking time to initiate the process. EDX analysis of pure Eagle Ford shale core and a phosphoric acid treated eagle Ford shale core was performed and the phosphoric acid-treated shale showed a high phosphorous signal compared to the pure shale. The permeability of this sample increased dramatically from negligible to 500 μd following phosphoric acid treatment.

Oxidizing agents Tests and Enhancement of Porosity and Permeability

The oxidizing agent component used in the present compositions and methods was also tested. It was believed that oxidizing agents might be included in the chemical cocktails of this disclosure, with the thought that oxidants might lead to partial fragmentation of the non-movable organic compounds found in kerogen and bitumen, which could in turn lead to improved fluid flow in the matrix. Some of the oxidants screened for testing included potassium permanganate, potassium dichromate, and potassium peroxymonosulfate (OXO E®). The testing focused on using peroxymonosulfate compounds such as OXONE®, based on potassium permanganate showed some instability at high temperature and potassium dichromate having a level of environmental toxicity.

It was discovered that an oxidizing agent comprising a peroxymonosulfate ([O3SOOH]^") compound, such as potassium peroxymonosulfate (OXONE®) could increase permeability substantially and also provide economic efficiency.

OXONE® is a cleaning agent used in certain household products, but it has substantially different properties than hypochlorite compounds such as bleach. The reduction potential of the peroxymonosulfate ion is much higher that of hypochlorite, as shown here. Hypochlorite:

CIO^" + H₂0 + 2e^"→ CI^" + 20H^"; Reduction Potential: + 0.81 V

Peroxymonosulfate :

HSO₅ ^" + 2 H⁺ + 2 e^"→ HSO₄ ^" + H₂0; Reduction Potential: + 1.44 V

The byproducts of the oxidation using peroxymonosulfate ion are bisulfate and water. Because the acid dissociation constant of HSO₄ ^" is 1.2 x 10^"2, in the presence of carbonate, the bisulfate ion will react to form sulfate ions. It was thought that the sulfate ions may coordinate with clay or calcium in the matrix.

Crushed shale reactions with OXONE®

Crushed shale reactions with oxidants, particularly OXONE®, were performed to understand the basic chemical effects of interactions of oxidants with the Eagle Ford shale. The tradename OXONE® is used in this disclosure to refer to potassium peroxymonosulfate, which occurs as the triple salt 2KHS0₅*KHS0₄*K₂S0₄. All reactions were conducted at 125 °C for 7 days. The first series of experiments were conducted at variable salinities with 1% OXONE®. At higher salinities, more sulfate ion tended to form deposits on the matrix, a hypothesis that was quantified with 2% OXONE® as shown in Table 6.

Table 6. OXONE® reaction at variable salinities

Table 7. OXONE® reaction at variable pH

The OXONE® reaction was repeated under different pH conditions to understand the pH effect on sulfate deposition. For all reactions, synthetic brine of 40,000 ppm was utilized. As shown in Table 7, at lower pH values, the mass change was substantially greater as compared to the same experiment under higher pH values. This observation indicates that at relatively low pH conditions, sulfate deposition occurs less than under higher pH conditions. The XRF graph in Figure 8 shows the increase in sulfur content at the higher pH, consistent with this finding.

Flow Cell Tests with OXONE®

Flow cell experiments were conducted to evaluate permeability enhancement with

OXONE® treatment, using the flow cell apparatus illustrated in Figure 5. As shown in Table 8, the post permeability increased for all reaction conditions. However, the permeability enhancements derived from the OXONE®-treated samples were smaller as compared to the permeability enhancements derived from the acid treatments. Micro-CT images of 1%

OXONE® treated Eagle Ford shale showed apparent micro factures created after the OXONE® treatments. ESEM images of OXONE® treated Eagle Ford shale, OXONE® + acid treated Eagle Ford shale, and pure Eagle Ford shale showed that OXONE®-treated samples had enhanced porosity. EDX analysis also showed significant sulfate deposition on the OXONE®- treated samples, and showed that sulfur occurrence in OXONE®-treated samples were much higher than that of pure shale.

Table 8. Permeability data for OXONE® reactions

OXONE® treatment did not change the hardness of the samples. The hardness of pure shale is generally in the range of 95-117 MPa, whereas the hardness of 1% OXONE® treated sample was found to be 128 MPa. The hardness of 1% OXONE® + 1% HC1 treated sample was 57 MPa, significantly lower than the hardness of the pure OXONE® treated sample. The ESEM image of the 1% OXONE® treated shale showed the enhancement of pores structures compared to the pure untreated shale.

Wettability Alterations using Low Salinity Brine

Relative permeability of oil is higher in water-wet rocks than in oil-wet rocks, yet shale samples are oil-wet in formation brine. It was thought that synthetic brines, even at low salinity, might change the surface charges due to ion exchange process, which in turn could lead to the wettability alterations in a shale matrix.

Low salinity brine tests were conducted using brines with different KC1 concentrations and different synthetic brine concentrations. Table 9 lists the brine compositions tested and the salinity.

Table 9. Brine compositions for wettability testing

All the tested samples were prepared according to the procedure discussed in the

Examples section above. The contact angles were measured for different salinities, the results of which are included in Table 10 below. In KC1 solutions, the contact angles remain very similar in both 0.1%) and 4% salinities, and wettability remained preferential oil-wet at low salinities. However, in the synthetic brines, the contact angles changed significantly, and wettability changed to preferential water-wet in the lowest salinity brine. Table 10. Measured contact angles of Eagle Ford shale in different salinities in KC1 and synthetic brine

Wettability Alterations using Surfactants

A number of surfactants were tested, and it was discovered that AMPHOAM® and

CALF AX® were stable under high salinity and high temperature conditions. The synthetic brine used in these experiments was 6.9 wt% NaCl and 1.1 wt% CaCl₂. The contact angles measured for CALF AX® or AMPHOAM® in the synthetic brine are included in Table 11 below. In both cases, the wettability altered preferentially to water wet. Therefore, this combination of

AMPHOAM® and CALF AX® with high salinity was particularly useful, including at high temperatures.

Table 11. Measured contact angles of Eagle Ford shale in AMPHOAM® or CALF AX® with synthetic brine

Identification of ultra-low Interfacial Tension (IFT) surfactant formulations

It was thought that certain specialized surfactants, particularly nano-emulsion surfactants, might be an appropriate candidate for lowering the interfacial tension between oil and water under the relevant conditions. The surfactant formulations listed in Table 13 are examples of the surfactants and surfactant combinations that were tested for aqueous stability at 125 °C, in 80,000 ppm synthetic brine (6.9% CaCl₂ and 1.1% CaCl₂), 50,000 NaCl, and 10,000 NaCl compositions. Depending upon the aqueous stability, the following six surfactant formulations were selected for phase behavior studies:

AOS C14-C16;

C28 25PO 45 EO COO-;

TSP 15PO 22EO COO- + IOS 1518;

C28 25PO 45 EO COO- + IOS1518;

TDA-35-PO-20EO; and

TDA-35-PO-45EO.

AOS C14-C16 was thought to be a good surfactant for high temperature and high salinity conditions, while carboxylate + IOS 1518 was thought to be good for low salinity conditions. Most of these selected surfactants are stable at 50000 ppm salinity for short term applications. It has been found that carboxylates show potential type III regions in phase behavior studies, and TSP 15PO 22EO COO- + IOS 1518 formulation gave three phases in 8% and 5% salinities after 5 days.

Table 13. Tested surfactant formulations for ultra-low IFT

Cocktail mixtures

As a result of these studies, the following combinations of components for the chemical cocktails or energizing fluids for stimulating oil, condensate and/or gas recovery from a hydrocarbon-bearing shale formation have been identified. The energizing fluid can comprise any combination of at least two of:

a) an oxidizing agent comprising a peroxymonosulfate ([O₃SOOH]^") compound;

b) a surfactant; and

c) an acid.

These energizing fluids according to the preceding composition can also further comprise one, or any combination of more than one, of:

d) an organic solvent;

e) a hydrocarbon gas;

f) a synthetic brine; and/or

g) carbon dioxide.

Our studies have also pointed to the following specific cocktail mixtures that work well in stimulating a hydrocarbon-bearing shale formation, which can also increase in situ

effectiveness of fracture fluids:

Acid + a peroxymonosulfate compound, such as OXONE®;

surfactants + acid;

surfactants + acid + solvents;

a peroxymonosulfate compound, such as OXONE® + surfactants + HC gases.

The acid + OXONE® combination tests identified this combination as surprisingly effective. For example, 1% OXONE® was stable in 1% HCl solution at 125 °C, and the initial pH of this solution was about pH 1.2. In the flow cell experiments, the fluid that penetrated the core had a pH of about pH 6.9, indicating that all the acid was consumed during penetration. The flow cell experiments also showed increased permeability of shale.

Regarding particularly useful surfactants, CALF AX® (0.5 wt%) was tested for stability at pH 2, and this mixture was found to be stable at 125 °C in a synthetic brine of 40,000 salinity. Wettability alterations were tested using contact angle measurements as a function of time, and 0.5% CALF AX® alone changed the wettability preferentially to water wet. At the start of the CALF AX® testing, for example using 0.5 wt % CALF AX® and 0.2 wt% acid such as acetic acid, the solution started began to react with the shale, as evidenced by the continuous bubbling indicating the acid reaction with carbonates. After about 30 minutes, the system had reached an equilibrium and an oil droplet was introduced onto the shale surface. Acidified CALF AX® changed the wettability to water-wet. Various combinations of CALF AX® or a carboxylate surfactant and acids work well. For example, a composition of 0.1-1.0 wt % CALF AX® or a carboxylate surfactant and 0.1-0.5 wt% acetic acid works well. The contact angles measured for CALF AX® in the synthetic brine at pH 2 are included in Table 12 below.

Table 12. Measured contact angles of Eagle Ford shale in CALF AX® with synthetic brine at pH 2.

So-called encapsulated acids were generated by combining acid, surfactant, and limonene. The stabilities of the cocktail mixtures using exemplary surfactants listed in Table 14 were tested at 125 °C. The cocktail mixture was always prepared according to wt% for all the components including water. The surfactant-to-limonene ratio was 1 :4 (wt%) in the cocktail mixture. The total volume of the cocktail mixture was 10 mL (components + water). A clear colorless organic layer turned milky or cloudy after about 48 hours. After 7 days the organic phase turned transparent and yellow in color.

Table 14. Initial stability tests for encapsulated acid-surfactant mixtures. The percentagi weight percentages in the initial cocktail mixture to be used in the tests.

Cocktail Mixture Tests

Based on tests, the following chemical cocktail was developed for injecting into shale oil reservoirs to stimulate oil recovery, including for injecting with the fracturing fluids or later during the production. The cocktail mixture includes (in weight percentages) 4% salinity brine (3.4% NaCl, 0.5% KC1, 0.1% CaCl₂), 0.5% OXONE®, 0.5% CALF AX®, and 2.0% limonene. Using the low pressure testing protocol of Figure 2, four trials of bottle tests were conducted. In each test, conducted at about 30 psi, shale chips and 10 mL of the cocktail mixture (energizing fluid) noted above were placed in a custom made reaction vessel, as shown in Figure 2. All reaction mixtures were placed at 125 °C for 7 days in an explosion proof oven throughout the test. After this time, the solid and liquid portions of the test mixture were separated using gravity filtration. The solid samples were dried at about 60 °C for 24 hours, and then vacuum dried for an additional 2 hours. The final mass of each shale sample following extraction and proper drying was measured.

An initial cocktail mixture (including in weight percentages 4% salinity brine (3.4% NaCl, 0.5% KC1, 0.1% CaCl₂), 0.5% OXONE®, 0.5% CALF AX®, and 2% limonene) was compared against the state of the chemical cocktail in contact with the shale at 125 °C for 7 days. The comparisons showed extracted oil on top of the water, after 7 days of aging at 125 °C. Very producible results were obtained on scale-up, which recovered more oil.

An extraction test was also done to compare a control sample solution having a cocktail mixture (4% salinity brine 0.5% OXONE®, 0.5% CALF AX®, and 2.0% Limonene) without shale with a test sample solution having a cocktail mixture (4% salinity brine 0.5% OXONE®, 0.5% CALF AX®, and 2.0% Limonene) with shale. The test and control sample solutions were aged at 125 °C for 7 days. The resulting oil layer was extracted into cyclohexane and analyzed by gas chromatography (GC). The cyclohexane extract had an intense yellow color compared to the control test extract. In more detail, there was significant color contrast as the chemical cocktail extract had a much deeper yellowish-brown color than the control sample solution which had a light yellow color. The oil, limonene and the extract were analyzed by gas chromatography (GC) which simulated distillation in the GC. The oil has mostly light components, while the extract also showed many light components.

Comparable results are obtained in extraction tests using CALF AX® + OXONE®,

CALF AX® + limonene, and slick water + the specified cocktail mixture.

Flow of OXONE® into core material

Flow cell experiments were conducted using the Figure 5 flow cell setup and the general procedure set out above, at different OXONE® concentrations. In these experiments the

OXONE® solution was flowed past the face of a shale core while a pressure drop was applied across its thickness. The shale permeabilities before (Ki) and after (Kf) treatment with the solutions shown in Table 15 were measured for each experiment. The hardness of the

OXONE®-exposed shale surface was measured after OXONE® treatment.

Table 15. Permeability and hardness for flow cell experiment

As these data demonstrate, permeability increased after each OXONE® treatment. Hardness of the shale matrix did not change significantly. Effect of OXONE® Concentration on Shale Surface

Low pressure tests using the protocol of Figure 2 were conducted at a shale:test solution ratio of 1 :5 (v/v), using six different OXONE® concentrations ranging from 0.1 wt% to 2.0 wt%. The brine composition was 3.4% NaCl, 0.5% KC1, 0.1% CaCl₂ for the test solutions. Figure 9 illustrates the mass change trends and pH change trend with changes in OXONE® concentration, and it is seen that mass change is relatively small. Each test was carried out at 125 °C for 7 days. The pH change was about 3 pH units for the 0.1% OXONE® solution, and increased with the OXONE® concentration. For example, at OXONE® concertations greater than 1.0%, the pH change was about 5 pH units, with the pH changed from acidic (pH about 3) to basic range (pH about 8).

Reaction of OXONE® with Hydrocarbons (HQ

To identify any combustion point of OXONE® and the oil, a BHP oil and 1% OXONE® were mixed in a calorimeter and heated the mixture up to 90 °C using constant current. The temperature increments were measured at each minute. Figure 10 shows the temperature change during heating, and reveals that there are no temperature spikes. During the heating process the rate of heat generation did not change dramatically, indicating that there was no exothermic heat generation during this process resulting from an exothermic oxidation reaction. Similar tests were conducted with OXONE® and slick water fracturing (frac) fluid, which were also found to be compatible.

Effect of Different HCl Concentrations

Shale dissolution in dilute HCl was examined and the mass change, pH change, surface morphology, and elemental compositions were analyzed as a function of these variable acid concentrations. The experiments were conducted at a shale:test solution ratio of 1 :5 (v/v). As shown in Table 16, increasing acid concentration resulted in a greater mass change in matrix. In all cases, the pH changed from initially highly acidic to almost neutral, demonstrating essentially complete consumption of the acid. Calcium ion concentrations in the effluent also increased as acid concentration increased. Figure 11 illustrates the mass and pH change as a function of increasing HCl concentration. The hardness for the 2% acid treated sample was 70 MPa, whereas the 0.1% HCl treated sample has a hardness of 207 MPa.

Table 16. Changes in pH, Ca²⁺, and mass using different HCl concentrations

Exemplary Chemical Cocktails

Based on these examples and studies for both each individual component of the energizing fluid and their combinations in a chemical cocktail, the following chemical cocktails are presented in Table 17. These particular embodiments are exemplary, and the skilled person will appreciate that modifications are possible in these embodiments without materially departing from the novel teachings and advantages set out in this disclosure.

32001-0015

Table 17. Exemplary Chemical Cocktails (in values of "about x wt%", in the combined aqueous cocktail mixture)

Permian Basin characterization

Permian Basin (PB) shale was also evaluated for mineralogy and elemental distribution and used for testing the compositions and methods of this disclosure. A core sample from a depth of 10029' (feet) showed visible fractures alone the bedding plane of the PB shale, and distinct visible bedding layers were observed in the length scales of mm to cm.

The mineralogy was determined using X-ray diffraction, Table 18. Each of the sections labeled a, b, c and d in Table 18 corresponds to a section of Permian Basin shale. The mineralogy of each section was analyzed, and about 55% of matrix was found to be quartz. The total clay content was 17-26%. Calcite content was from 0 to 7.5%, with the highest for region d. Sample from the "a" region and the "c" region have 0.1-0.3%) calcite content. According to XRF as shown in Figure 12, the silicon content is significantly higher compared to other elements. Table 18. XRD analysis for Permian Basin

A Micro-CT scan was taken to map the fracture patterns. The micro-CT images of Permian Basin shale showed apparent fractures in the matrix. ESEM images of Permian Basin shale were also captured.

The TOC content of the Permian Basin shale was 4.94 wt%, which is slightly less than that of the Eagle Ford shale, which was between about 5.5 wt% and about 6 wt%. The combustible carbon content was found to be 1.62 % which also is less than in the Eagle Ford shale. A thermal gravimetric analysis (TGA) was performed to examine the bitumen and kerogen content. The percent mass loss at 350 °C was 2.06 wt% and the percent mass lost at 600 °C was 5.05 wt%.

Mika A Shale

Mika A, mineralogy

Mika A shale was evaluated for mineralogy and elemental distribution and used for testing the compositions and methods of this disclosure. The mineralogy was determined using X-ray diffraction (XRD), the results are presented in Table 19. Mika A cores showed higher amounts of calcite relative to STS pad cores.

Table 19. XRD analysis for Mika A shale samples (% mass).

The elemental composition of the Mika A and STS samples was determined by X-ray florescence analysis. As shown in Figure 13, the Mika A shale matrix is rich in calcium and silicon.

Mika A, total organic content (TOC) and thermal degradation

The organic content of Mika A and STS samples was measured using two different methods: total organic content (TOC) and thermal gravimetric analysis (TGA). TOC

measurements were taken by heating samples in the presence of oxygen. The TOC content of Mika A shale was 4.41 wt%, which was slightly less than that of STS core samples taken at a depth of 11143', which has a TOC content of 4.75 wt%.

A thermal gravimetric analysis (TGA) was performed under nitrogen atmosphere to examine the bitumen and kerogen content, the results of which are presented in Table 20. The change in total mass at 100 °C was attributable to water and the change in total mass at 300 °C was attributable to water and organic matter. The oil content in Mika A cores is relatively lower than the oil content in STS cores as shown by the change in organic mass of an STS core (1.04%) relative to the change in organic mass of a Mika A sample (0.72%).

Table 20. TGA analysis for Mika A and STS core shale samples.

Oil extraction from Mika A - static experiments

A chemical cocktail was developed for injecting into shale oil reservoirs to stimulate oil recovery, including for injecting with the fracturing fluids or later during the production. The chemical cocktail includes (in weight percentages) 0.2% salt (water source BHP brine), 0.5% OXONE, 0.5% CALF AX, and 2.0% limonene. The BHP brine (slick water) had a dissolved ion concentration, as measured by ion chromatography, as follows: 844 ppm Na⁺, 4 ppm K⁺, 0 ppm Mg²⁺, 0 ppm Ca²⁺, 300 ppm S0₄ ^2", 500 ppm CI^", total ion concentration 1648 ppm. The chemical cocktail was tested for its ability to extract oil using the low pressure testing protocol of Figure 2. In each test, conducted at about 30 psi, shale chips and 10 mL of the chemical cocktail noted above were placed in a custom made reaction vessel, as shown in Figure 2. All reaction mixtures were placed at 125 °C for 7 days in an explosion proof oven throughout the test. After this time, the solid and liquid portions of the test mixture were separated using gravity filtration. The solid samples were dried at about 60 °C for 24 hours, and then vacuum dried for an additional 2 hours. The final mass of each solid shale sample following extraction and proper drying was measured by thermal gravimetric analysis under nitrogen atmosphere, the results of which are presented in Table 21. The change in total mass at 100 °C was attributable to water and the change in total mass at 300 °C was attributable to water and organic matter. The shale samples treated with the chemical cocktail had a reduced oil content of about 25% relative to shale samples not treated with the chemical cocktail.

Table 21. TGA analysis for Mika A samples subjected to the low pressure testing protocol in the presence of chemical cocktail.

A low pressure crushed shale extraction test procedure was performed on a control sample (a chemical cocktail of this disclosure with no shale chips) and two test group samples having Mika A shale chips mixed with the chemical cocktail. The control sample and two test samples were heated at 125 °C for 7 days. Several observations were made regarding the test group samples having Mika A shale chips mixed with the chemical cocktail. First, surfactant disappeared as a result of adsorption on the shale. Second, oil had been released. Third, limonene was separated from oil, with the oil staying on top. Fractured core experiment—fracture conductivity

Fracture conductivity experiments were conducted on Mika A shale according to the schematic illustrated in Figure 14 to test the impact of chemical cocktail on shale conductivity and hardness. A Mika A shale core of dimensions 4"-6" (4-6 inches) long and 1.0" (1 inch) diameter was constructed with a propped fracture in between. The core was placed in heat shrink and then placed in a Hassler Coreholder. Two short shale cores were aligned in one experiment as a result of batch core sample limitations.

The experiment consisted of three steps. Step 1 consisted of a brine flush to measure conductivity. Step 2 consisted of a cocktail flush for 48 hours followed by a cocktail soak for 24 hours. The cocktail flush had a flow rate of 0.02 cc/min. Step 3 consisted of injecting water and measuring conductivity. The overburden pressure was 1000 psi, and the downstream back pressure regulator (BPR) was 100 psi.

The conductivity experiment results are shown in Table 22. The chemical cocktail in Sample ID 3 includes 0.2% salt (water source BHP brine) (the 1648 ppm brine described above) and 0.5% OXONE. The chemical cocktail in Sample IDs 1 and 2 includes a modified BHP brine that had 2% more calcium ion and either 0.5% OXONE (Sample ID 1) or 1.0% OXONE

(Sample ID 2). The 1% OXONE concentration resulted in lower hardness relative to the 0.5% OXONE concentration. Not many fines (e.g. sulphates) were mobilized at the core outlet during flow. For reference, the hardness of untreated shale measured at two different sample points in the shale was 341 Mpa and 358 Mpa respectively. No significant oil was produced during the experiment; some oil was trapped in tubing and in between sand.

Table 22. Conductivity experiment results. Hardness was measured at two different sample points in the shale for each Sample ID (#, #), and each individual value is in Mpa.

Fluid analysis was performed on the Mika A shale cores as they were subjected to the fracture conductivity experiment described above. Figure 15 shows fluid analysis of calcium and potassium ions for Sample ID 3. Figure 16 shows fluid analysis of sulfate and sodium ions for Sample ID 3.

In Figure 15, the original Ca²⁺ concentration was approximately 0 ppm, and the average dissolved Ca²⁺ was approximately 275 ppm. The chemical cocktail did not have any calcium but some calcium from core material was dissolved. The K⁺ came from the OXO E in the cocktail solution. The brine injection following the cocktail solution injection did not show any calcium or potassium.

In Figure 16, the original S0₄ ^2" concentration was approximately 3130 ppm and the original Na⁺ concentration was approximately 705 ppm. The effluent analysis showed that no significant sulfate ions came out and, therefore, no scale was developed. Sodium from the surfactant was at the original concentration.

SEM images were captured of Mika A shale samples after they were subjected to the fracture conductivity experiment described above. The treated shale had fractures not present in the untreated shale. Some fractures were created in the cocktail treated samples as a result of stress and temperature changes. Localized crystallization was observed in the SEM images.

Table 23 shows the chemical composition by an EDX analysis of both cocktail treated Mika A shale and pure Mika A shale (i.e. not treated with cocktail, identified as "untreated" in Table 23) after being subjected to the fracture conductivity experiment described above. EDX analysis revealed that cocktail treatment resulted in more calcium dissolution and more exposed silica.

Table 23. EDX analysis.

Flow cell experiment—pre/post permeability

Flow cell experiments were conducted using the flow cell setup shown in Figure 5 and Figure 17, and the general procedure set out above, using OXONE in combination with different brine formulations. In these experiments, a cocktail solution comprising 0.5% OXONE and a select brine formulation was flown past the face of a Mika A shale core while a pressure drop was applied across its thickness. The flow tests were conducted on a 2.0" long slab that is 0.25" thick with 100-150 psi back pressure. The shale hardness, and permeability before and after treatment with the cocktail solutions, were measured and are shown in Table 24. As these data demonstrate, there was a 4-8 fold increase in permeability of cocktail treated shale without compromising shale hardness. For reference, raw shale had a hardness of 186 -341 Mpa. As another reference point, shale treated with 2% HC1 had a hardness of 70 Mpa. Thus, shale treated with 2% HC1 had significantly reduced hardness but shale treated with cocktail did not.

Table 24. Permeability and hardness for Mika A shale in a flow cell experiment

Micro-CT images of midsections from Mika A samples treated with a cocktail mixture comprising 0.5% Oxone in BFIP brine were taken. The micro-CT images show dissolution and microchanneling development.

Delayed acid reactions with divalent anions

Mika A has about 10% more calcite in the matrix than STS shale, and the effect of acetic acid on Mika A shale treated with cocktail was tested. The results shown in Figures 18-22 are from cocktails comprising: BHP brine; various concentrations of Oxone (either 0 wt% or 0.5 wt%, referred to as "sul" "sulf ' and "sulfate" in the figures); and various concentrations of acetic acid (0 wt%, 3 wt%, or 6 wt%, referred to as HA in the figures). Control refers to BHP brine alone.

Figure 18 shows the effects of sulfate ions on acid-calcite reaction rate in static experiments at 125 °C. There was a delayed reaction of acid in the static experiments at 125 °C. The sulfate from Oxone protected surfaces against reaction with acid for a period of time. Figure 19 shows concentration dependent reactions for weak acid CH₃COOH. The experiments were 7 day static experiments at 125 °C. Figure 20 shows pH change in an acetic acid-calcite time dependent experiment. Figure 21 shows the change in Ca²⁺ concentration in acetic acid-calcite time dependent experiments. Figure 22 shows the change in SO₄ ^2" concentration in acetic acid- calcite time dependent experiments.

Second fracture conductivity experiment

A second fracture conductivity experiment was conducted on Mika A shale according to the same methodology described above in the fractured core experiment -fracture conductivity section. The conductivity experiment results are shown in Table 25. The chemical cocktail in Sample IDs 4, 5, and 6 included 0.2% BHP brine and 0.5%, 0.75%, or 1.0% OXONE. For reference, the hardness of untreated shale measured at two different sample points in the shale was 341 Mpa and 358 Mpa respectively. Treatment with the various chemical cocktails did not change hardness by much, but conductivity changed by 30-60%>. it appeared that the 0.75%> Oxone had a problem with the proppant pack. The core was cut into half with a thick blade, and after the experiment some sand migrated out of the fracture.

Table 25. Conductivity experiment results. Hardness was measured at two different sample points in the shale for each Sample ID (#, #), and each individual value is in Mpa.

Images were captured of Mika A shale samples after they were subjected to the fracture conductivity experiment described above. No mineral deposits were observed for 0.5% and 0.75%) OXONE concentrations (e.g. no mineral deposits occurred at an OXONE concentration below 0.75%). Mineral deposits were observed for 1.0% OXONE. SEM images of 0.5% OXONE cocktail treated Mika A shale and 1.0% OXONE cocktail treated Mika A shale confirmed the absence of or presence of mineral deposits respectively.

Volumetric Studies

The reactivity of cocktail mixture with Mika A shale and the reactivity of pure oxone with Mika A shale were tested. Different volumes of cocktail mixture (0.5%> Oxone, 0.5%

Calfax, 2% limonene, and 0.2% NaCl) and pure Oxone (0.5% Oxone, 0.2% NaCl) were reacted with shale to measure calcite dissolution, the results of which are shown in Figure 23. Oxone dissolves calcite. Calcite dissolution was less dominant in the cocktail mixture. Calcite dissolution is increased by increasing [cocktail: shale] ratio.

Oil recovery from two different cocktail mixtures was measured by thermal gravimetric analysis. Different volumes of cocktail mixture with limonene (0.5%> Oxone, 0.5% Calfax, 2% limonene, and 0.2% NaCl) and cocktail mixture without limonene (0.5% Oxone, 0.5% Calfax, and 0.2%) NaCl) were reacted with shale and %> oil recovery was measured. The results of the study are shown in Figure 24 and Table 26. Limonene was not responsible for oil

mobilization/recovery.

Table 26. Volumetric study showing impact of limonene on oil recovery.

Emulsion Studies The emulsion of cocktail in oil and produced water was studied to understand, for example, how long a cocktail injection should reside in a well before an emulsion would break. Cocktail (0.5% Oxone, 0.5% Calfax, 2% limonene, and 0.2% NaCl) was aged with or without shale at 125° C for three days. After 3 days at 125 °C, it was confirmed that 99% (v/v) of the mixture was in a stable emulsion and about -1% (v/v) was free limonene. Afterwards, various cocktail dilutions with oil and various cocktail dilutions with produced water, as shown in Table 27, were aged at 75° C for 1 day. The emulsion of cocktail with shale in oil dilution (cocktail + oil) and the emulsion of cocktail in produced water dilution (cocktail + produced water) both broke after 6 hours at 75° C for all ratios tested (e.g. all ratios in Table 27).

Table 27. Cocktail dilutions for emulsion studies, showing the volume ratio (x:y) of cocktail to oil, where the "x z" number is the inverse of the volume percentage of the cocktail. The "x z" number indicates the dilution factor for the emulsion in the relevant fluid (oil or produced water). Cocktail :test fluid ratio is m:n. Therefore, m:n→ x z means, fluid ratio→ dilution factor.

Osmosis and Diffusion Studies

Osmosis and diffusion studies were carried out to examine the ability of cocktail and/or cocktail components to enter shale matrix, which has an abundance of salt. Experiments were conducted by separating high salinity water (6 wt% NaCl) from low salinity water (0.2 wt% NaCl, which simulates cocktail) by a thin piece of shale. Changes in total dissolved solids in the low salinity compartment were measured and the results are presented in Table 28. Table 28. Results of diffusion and osmosis studies for shale samples of varying depths, reported as a percentage of total dissolved solid change in the low salinity compartment

Cocktail— Compositional Component and their Actions in Combination

Based on the examples set out herein, and while not intending to be bound by theory, it is believed that the various cocktail components set out below initially operate in the following manner, although a synergistic effect is observed when the individual components are combined into a cocktail.

• 0.5% Oxone

o Active component: Peroxymonosulfate [HS0₅]^" (having the structure

([O₃SOOH]^"). Action: Oxidation of organic matter,

o Active component: Hydrogen sulfate [HSO₄]^" (also termed bisulfate). Action:

Weak acid - Calcium dissolution,

o Active component: Sulfate SO₄ ^2" Counter anion. Action: Delay the acid reactivity with the shale matrix, facilitate cocktail propagation into fractures, keep the matrix hardness.

o Active component: K⁺ Counter cation. Action: Can be used to monitor cocktail flow.

• 0.5% Calfax

o Active component: anionic surfactant. Action: Wettability alteration to water- wet, lower the capillary end effects, increase limonene-water miscibility.

• 2% Limonene

o Active component: organic solvent. Action: Enhance the organic extraction into cocktail and removes asphaltene from pores. • Based on these examples set out above for Mike A, the following observations regarding Mika A were made. Again, while not intending to be theory bound it was observed that:

o Mika A has about 10% more calcite in the matrix than STS shale

o The cocktail static experiments are reproducible

o Oil extraction from static experiments was about 25%

o Higher Oxone concentration decreases fracture conductivity due to fines formation

o EDX shows surface calcium dissolution

o After cocktail treatment surface hardness increase slightly

o The permeability increased by about 8 times in the flow cell experiment o There is no significant deposition of CaS0₄

o Sulfate ions delayed the reactivity of acid with shale.

Various aspects, features and embodiments of this disclosure can be summarized as follows.

• Chemical cocktail mixtures comprising OXONE®, CALF AX® surfactant, Limonene work unexpectedly well to extract oil from shale, an example of which is , for example, 0.5% OXONE®, 0.5% CALF AX® surfactant and 2% Limonene combination provides unexpectedly good results.

• OXONE® treatment increases the shale permeability and does not weaken the shale surface, surprisingly even at high concentrations. Moreover, OXONE® does not produce heat during the interaction between OXONE® and oil, and OXONE®' s utility is further demonstrated by its broad compatibility with fracturing fluid.

• OXONE® also increases the permeability of the shale, even with concentrations as low as 0.5 wt%. Concurrently, the OXONE® treated samples exhibited a greater hardness as compared to the HCl-treated shale.

• Solvent extraction processes were developed with cyclohexane, naphtha, and limonene.

Based on the mass change in the solid shale matrix and solute dissolved in the extract, limonene worked unexpectedly well in the chemical cocktails. Other solvents such as naptha worked well. • Mineral dissolution by an acid can increase the permeability and porosity of shale matrix, and acid treatment tends to increase the surface roughness. Due to strong acids tending to (e.g. hydrochloric acid) tending to weaken the surface, more versatile acids include the weak acids such as phosphoric acid and acetic acid which sustained the strength of the surfaces.

• Synthetic brines such as those disclosed herein were helpful to change the wettability of the shale surface from preferentially oil-wet to water-wet thereby enhancing recovery, even at a very low salinities such as 0.1 wt%.

• AMPHOAM®, CALF AX®, and Lauryl Betaine were found to be very useful materials for wettability alteration at high salinities. The surfactant AOS C14-C16 had good stability for high temperature and high salinity conditions, whereas carboxylate + IOS 1518 combination was stable under lower salinity conditions. Most of the surfactants selected were stable at about 50,000 ppm salinity or lower for short term applications.

These aspects, embodiments and examples are merely exemplary and are not intended to be limiting, but simply illustrative of possible chemical cocktails according to the disclosure. In an aspect, the following table shows some of the specific embodiments of the chemical cocktails according to this disclosure, where the check mark indicates the presence of the listed component in the chemical cocktail.

Chemical Cocktail Embodiments

Definitions

To define more clearly the terms used herein, the following definitions are provided, and unless otherwise indicated or the context requires otherwise, these definitions are applicable throughout the disclosure. If a term is used in this disclosure but is not specifically defined, the definition from the IUPAC Compendium of Chemical Terminology, 2^nd Ed (1997) can be applied, as long as that definition does not conflict with any other disclosure or definition applied herein, or render indefinite or non-enabled any claim to which that definition is applied. To the extent that any definition or usage provided by any document incorporated herein by reference conflicts with the definition or usage provided herein, the definition or usage provided herein controls.

Regarding claim transitional terms or phrases, the transitional term "comprising", which is synonymous with "including," "containing," or "characterized by," is inclusive or open-ended and does not exclude additional, unrecited elements or method steps. The transitional phrase "consisting of excludes any element, step, or ingredient not specified in the claim. The transitional phrase "consisting essentially of limits the scope of a claim to the specified materials or steps and those that do not materially affect the basic and novel characteristic(s) of the claimed invention. Absent an indication to the contrary, when describing a compound or composition "consisting essentially of is not to be construed as "comprising," but is intended to describe the recited component that includes materials which do not significantly alter composition or method to which the term is applied. When a claim includes different features and/or feature classes (for example, a method step or a composition feature, among other possibilities), the transitional terms comprising, consisting essentially of, and consisting of, apply only to feature class to which is utilized and it is possible to have different transitional terms or phrases utilized with different features within a claim. While compositions and methods are described in terms of "comprising" various components or steps, the compositions and methods can also "consist essentially of or "consist of the various components or steps.

As used in the specification and the appended claims, the singular forms "a," "an," and "the" include plural referents, unless the context clearly dictates otherwise. Thus, for example, reference to "a light" includes a single light as well as any combination of more than one light if the contact indicates or allows, such as multiple UV lights that are used in combination. Reference throughout this specification to "one embodiment," "an embodiment," or "embodiments" means that a particular feature, structure, or characteristic described in connection with the embodiment is included in at least one embodiment. Thus, the appearances of the phrases "in one embodiment" or "in an embodiment" in various places in the specification are not necessarily all referring to the same embodiment. Furthermore, the particular features, aspects, structures, or characteristics may be combined in any suitable manner in one or more embodiments.

"Optional" or "optionally" means that the subsequently described element, component, step, or circumstance can or cannot occur, and that the description includes instances where the element, component, step, or circumstance occurs and instances where it does not.

Throughout this specification, various publications may be referenced. The disclosures of these publications are hereby incorporated by reference in pertinent part, in order to more fully describe the state of the art to which the disclosed subject matter pertains. The references disclosed are also individually and specifically incorporated by reference herein for the material contained in them that is discussed in the sentence in which the reference is relied upon. Again, to the extent that any definition or usage provided by any document incorporated herein by reference conflicts with the definition or usage applied herein, the definition or usage applied herein controls.

Unless indicated otherwise, when a range of any type is disclosed or claimed, for example a range of the sizes, number, percentages, and the like, it is intended to disclose or claim individually each possible number that such a range could reasonably encompass, including any sub-ranges or combinations of sub-ranges encompassed therein. When describing a range of measurements such as sizes or percentages, every possible number that such a range could reasonably encompass can, for example, refer to values within the range with one significant figure more than is present in the end points of a range, or refer to values within the range with the same number of significant figures as the end point with the most significant figures, as the context indicates or permits. For example, when describing a range of percentages such as from 5% to 15%, it is understood that this disclosure is intended to encompass each of 5%, 6%, 7%, 8%, 9%, 10%, 11%, 12%, 13%, 14%, and 15%, as well as any ranges, sub-ranges, and combinations of sub-ranges encompassed therein. Applicants' intent is that these two methods of describing the range are interchangeable. Accordingly, Applicants reserve the right to proviso out or exclude any individual members of any such group, including any sub-ranges or combinations of sub-ranges within the group, if for any reason Applicants choose to claim less than the full measure of the disclosure, for example, to account for a reference that Applicants are unaware of at the time of the filing of the application.

Values or ranges may be expressed herein as "about", from "about" one particular value, and/or to "about" another particular value. When such values or ranges are expressed, other embodiments disclosed include the specific value recited, from the one particular value, and/or to the other particular value. Similarly, when values are expressed as approximations, by use of the antecedent "about," it will be understood that the particular value forms another embodiment. It will be further understood that there are a number of values disclosed therein, and that each value is also herein disclosed as "about" that particular value in addition to the value itself. In another aspect, use of the term "about" means ±20% of the stated value, ±15% of the stated value, ±10% of the stated value, ±5% of the stated value, or ±3% of the stated value.

In any application before the United States Patent and Trademark Office, the Abstract of this application is provided for the purpose of satisfying the requirements of 37 C.F.R. § 1.72 and the purpose stated in 37 C.F.R. § 1.72(b) "to enable the United States Patent and Trademark Office and the public generally to determine quickly from a cursory inspection the nature and gist of the technical disclosure." Therefore, the Abstract of this application is not intended to be used to construe the scope of the claims or to limit the scope of the subject matter that is disclosed herein. Moreover, any headings that are employed herein are also not intended to be used to construe the scope of the claims or to limit the scope of the subject matter that is disclosed herein. Any use of the past tense to describe an example otherwise indicated as constructive or prophetic is not intended to reflect that the constructive or prophetic example has actually been carried out.

Those skilled in the art will readily appreciate that many modifications are possible in the exemplary embodiments disclosed herein without materially departing from the novel teachings and advantages according to this disclosure. Accordingly, all such modifications and equivalents are intended to be included within the scope of this disclosure as defined in the following claims. Therefore, it is to be understood that resort can be had to various other aspects, embodiments, modifications, and equivalents thereof which, after reading the description herein, may suggest themselves to one of ordinary skill in the art without departing from the spirit of the present disclosure or the scope of the appended claims.

Applicants reserve the right to proviso out any selection, feature, range, element, or aspect, for example, to limit the scope of any claim to account for a prior disclosure of which Applicants may be unaware.

SELECTED EMBODIMENTS

This disclosure has been made with reference to numerous aspects and embodiments, and specific examples. Other embodiments of the invention can include, but are not limited to, the following. These embodiments typically are described as "comprising" but, alternatively, can "consist essentially of or "consist of unless specifically stated otherwise.

1. A process for stimulating oil, condensate and/or gas recovery from a hydrocarbon- bearing shale formation, the process comprising:

i) an oxidizing agent comprising a peroxymonosulfate ([0₃SOOH]^") compound; ii) a surfactant; and

iii) an acid;

c) recovering one or more of the oil, condensate and/or gas.

2. An energizing fluid for stimulating oil, condensate and/or gas recovery from a hydrocarbon-bearing shale formation, the energizing fluid comprising any combination of at least two of:

a) an oxidizing agent comprising a peroxymonosulfate ([O₃SOOH]^") compound;

b) a surfactant; and

c) an acid. 3. A process or an energizing fluid according to any of the preceding embodiments, wherein the energizing fluid further comprises one, or any combination of more than one, of: iv) or d) an organic solvent;

v) or e) a hydrocarbon gas;

vi) or f) a synthetic brine; and/or

vii) or g) carbon dioxide. 4. A process or an energizing fluid according to embodiments 1-2, wherein the energizing fluid comprises a surfactant and an acid.

5. A process or an energizing fluid according to embodiments 1-2, wherein the energizing fluid comprises an oxidizing agent and an acid.

6. A process or an energizing fluid according to embodiments 1-2, wherein the energizing fluid comprises an oxidizing agent and a surfactant. 7. A process or an energizing fluid according to embodiments 1-2, wherein the energizing fluid comprises an oxidizing agent, a surfactant, and an acid.

8. A process or an energizing fluid according to embodiment 3, wherein the energizing fluid further comprises an organic solvent.

9. A process or an energizing fluid according to embodiment 3, wherein the energizing fluid further comprises a hydrocarbon gas.

10. A process or an energizing fluid according to embodiment 3, wherein the energizing fluid further comprises a synthetic brine.

11. A process or an energizing fluid according to embodiment 3, wherein the energizing fluid further comprises carbon dioxide. 12. A process or an energizing fluid according to embodiment 3, wherein the energizing fluid comprises a surfactant, an acid, and an organic solvent.

13. A process or an energizing fluid according to embodiment 3, wherein the energizing fluid comprises a surfactant, an acid, and a hydrocarbon gas. 14. A process or an energizing fluid according to embodiment 3, wherein the energizing fluid comprises an oxidizing agent, a surfactant, and a hydrocarbon gas.

15. A process or an energizing fluid according to embodiment 3, wherein the energizing fluid comprises a surfactant, an acid, and carbon dioxide.

16. A process or an energizing fluid according to embodiment 3, wherein the energizing fluid comprises an oxidizing agent, a surfactant, and carbon dioxide. 17. A process or an energizing fluid according to any of embodiments 1-16, wherein the peroxymonosulfate compound is potassium peroxymonosulfate (OXO E®).

18. A process or an energizing fluid according to any of embodiments 1-16, wherein the oxidizing agent further comprises a permanganate compound.

19. A process or an energizing fluid according to any of embodiments 1-16, wherein the oxidizing agent further comprises potassium permanganate, sodium permanganate, calcium permanganate, and ammonium permanganate. 20. A process or an energizing fluid according to any of embodiments 1-16, wherein the oxidizing agent further comprises hydrogen peroxide, air, oxygen-enriched air, oxygen, oxygen and carbon dioxide, or oxygen and an inert diluent.

21. A process or an energizing fluid according to any of embodiments 1-16, wherein the surfactant comprises a non-ionic surfactant, an anionic surfactant, a cationic surfactant, an amphoteric surfactant, or a silane.

22. A process or an energizing fluid according to any of embodiments 1-16, wherein the surfactant comprises an internal olefin sulfonate (IOS), an alpha-olefin sulfonate (AOS), an alkyl aryl sulfonate (ARS), an alkane sulfonate, a petroleum sulfonate, an alkyl diphenyl oxide

(di)sulfonate, an alcohol sulfate, an alkoxy sulfate, an alkoxy sulfonate, an alcohol phosphate, an alkoxy phosphate, a sulfosuccinate ester, an alcohol ethoxylate, an alkyl phenol ethoxylate, a quaternary ammonium salt, a betaine or a sultaine.

23. A process or an energizing fluid according to any of embodiments 1-16, wherein the surfactant comprises a carboxylate, the carboxylate comprising a C28-25PO-45EO-carboxylate, a C12-322-50PO 2-100EO carboxylate, a C12-322-50PO carboxylates, C12-32 2-lOOEO carboxylates, Tristyrylphenol (TSP) 2-50PO 2-lOOEO carboxylate, Tristyrylphenol (TSP) 15PO 22EO carboxylate, a monoalkylphenolalkoxy carboxylate, a dialkylphenolalkoxy carboxylate, Coco amidopropylbetaine, CI 2-20 betaines or sultaines.

24. A process or an energizing fluid according to any of embodiments 1-16, wherein the surfactant comprises a sulfate, the sulfate comprising a TSP-35PO-20EO sulfate, a TSP 2-50PO 2-lOOEO sulfate, a monoalkylphenolalkoxy sulfate, a dialkylphenolalkoxy sulfate, a

25. A process or an energizing fluid according to any of embodiments 1-16, wherein the surfactant comprises a sulfonic acid or sulfonate, the sulfonic acid or sulfonate comprising dodecylbenzenesulfonic acid or sulfonate, a CI 0-20 alkylbenzenesulfonic acid or sulfonate (ABS), a C12-30 internal olefin sulfonate (IOS), a C12-20 alpha-olefin sulfonate (AOS), a C12- 28 glycerol sulfonate, a C12-28 diphenyloxidedisulfonate, a C15-17 alkylbenzenesulfonic acid, a CI 5- 18 internal olefin sulfonate, a CI 9-28 internal olefin sulfonate, a CI 9-23 internal olefin sulfonate, or a CI 2-20 alpha-olefin sulfonate. 26. A process or an energizing fluid according to any of embodiments 1-16, wherein the surfactant is selected from AOS C14-C16, C28 25PO 45EO carboxylate, TSP 15PO 22EO carboxylate + IOS 1518, C28 25PO 45EO carboxylate + IOS 1518, TDA-35PO-20EO, and TDA-35PO-45EO. 27. A process or an energizing fluid according to any of embodiments 1-16, wherein the surfactant is selected from AMPHOAM®, CALF AX®, Lauryl Betaine, AOS C14-C16, and a combination of IOS 1518 + a carboxylate surfactant. 28. A process or an energizing fluid according to any of embodiments 1-16, wherein the acid comprises a mineral acid or an organic acid.

29. A process or an energizing fluid according to any of embodiments 1-16, wherein the acid is selected from hydrochloric acid, phosphoric acid, acetic acid, propionic acid, butyric acid, valeric acid, caproic acid, oxalic acid, lactic acid, malic acid, citric acid or benzoic acid.

30. A process or an energizing fluid according to any of the preceding embodiments, wherein the energizing fluid further comprises an organic solvent. 31. A process or an energizing fluid according to any of the preceding embodiments, wherein the energizing fluid further comprises an organic solvent, the organic solvent comprising at least one aliphatic hydrocarbon solvent, at least one aromatic hydrocarbon solvent, or any combination thereof. 32. A process or an energizing fluid according to any of the preceding embodiments, wherein the energizing fluid further comprises an organic solvent selected from naphtha, limonene, cyclohexane, methyl cyclohexane, pentane, hexane, heptane, octane, and any combination thereof. 33. A process or an energizing fluid according to any of the preceding embodiments, wherein the energizing fluid further comprises limonene.

34. A process or an energizing fluid according to any of the preceding embodiments, wherein the energizing fluid further comprises a hydrocarbon gas. 35. A process or an energizing fluid according to any of the preceding embodiments, wherein the energizing fluid further comprises carbon dioxide.

36. A process or an energizing fluid according to any of the preceding embodiments, wherein the energizing fluid further comprises a hydrocarbon gas selected from natural gas, methane, ethane, propane and butane, and any combination thereof.

37. A process or an energizing fluid according to any of the preceding embodiments, wherein the energizing fluid further comprises a synthetic brine.

38. A process or an energizing fluid according to any of the preceding embodiments, wherein the energizing fluid further comprises a synthetic brine, the synthetic brine comprising any one of, or any combination of, NaCl, KC1, and CaCl₂.

39. A process or an energizing fluid according to any of the preceding embodiments, wherein the energizing fluid further comprises a synthetic brine comprising 3-4 wt% NaCl, 0.1-1 wt% KC1, and 0.01-1 wt% CaCl₂ in aqueous solution.

40. A process or an energizing fluid according to any of the preceding embodiments, wherein the energizing fluid further comprises a synthetic brine comprising 6-8 wt% NaCl and 0.5-1.5 wt% CaCl₂ in aqueous solution.

41. A process or an energizing fluid according to any of the preceding embodiments, wherein the energizing fluid is characterized by a high salinity (>40,000 ppm) and the surfactant is selected from AMPHOAM®, CALF AX®, Lauryl Betaine, and AOS C14-C16.

42. A process or an energizing fluid according to any of the preceding embodiments, wherein the energizing fluid is characterized by a low salinity (<40,000 ppm) and the surfactant is selected from AOS C14-C16 and a combination of IOS 1518 + a carboxylate surfactant. 43. A process or an energizing fluid according to any of embodiments 1-3, wherein the energizing fluid comprises 0.1-1.0 wt % CALF AX® or a carboxylate surfactant and 0.1-0.5 wt% acetic acid

44. A process or an energizing fluid according to any of embodiments 1-3, wherein the energizing fluid comprises 0.5 wt % CALF AX® or a carboxylate surfactant and 0.2 wt% acetic acid.

45. A process or an energizing fluid according to any of embodiments 1-3, wherein the energizing fluid comprises 0.1-1.5 wt % OXONE® and 0.5-1.5 wt% HCl or acetic acid.

46. A process or an energizing fluid according to any of embodiments 1-3, wherein the energizing fluid comprises 0.5-1.0 wt % OXONE® and 1 wt% HCl or acetic acid. 47. A process or an energizing fluid according to any of embodiments 1-3, wherein the energizing fluid comprises from a 40:60 (vol:vol) to a 60:40 (vol:vol) mixture of:

a) a combination of 0.1-1.0 wt % surfactant and 0.1-0.5 wt% acid; and

b) naphtha.

48. A process or an energizing fluid according to any of embodiments 1-3, wherein the energizing fluid comprises a 50:50 (vol:vol) mixture of:

a) a combination of 0.5 wt % surfactant and 0.2 wt% HCl; and

b) naphtha.

49. A process or an energizing fluid according to any of embodiments 1-3, wherein the energizing fluid comprises from a 40:60 (vol:vol) to a 60:40 (vol:vol) mixture of:

a) a combination of 0.1-1.0 wt % surfactant and 0.1-0.5 wt% acid; and

b) a hydrocarbon gas.

50. A process or an energizing fluid according to any of embodiments 1-3, wherein the energizing fluid comprises from a 40:60 (vol:vol) to a 60:40 (vol:vol) mixture of: a) a combination of 0.1-1.0 wt % surfactant and 0.1-0.5 wt% acid; and

b) carbon dioxide.

51. A process or an energizing fluid according to any of embodiments 1-3, wherein the energizing fluid comprises a 50:50 (vol:vol) mixture of:

a) a combination of 0.5 wt % surfactant and 0.2 wt% HC1; and

b) hydrocarbon gas selected from natural gas, methane, ethane, propane and butane, and any combination thereof.

52. A process or an energizing fluid according to any of embodiments 1-3, wherein the energizing fluid comprises C28-25PO-45EO-carboxylate, IOS 1518, acetic acid, and limonene.

53. A process or an energizing fluid according to any of embodiments 1-3, wherein the energizing fluid comprises TDA-35PO-20EO, acetic acid, and limonene.

54. A process or an energizing fluid according to any of the preceding embodiments, wherein the energizing fluid forms an emulsion.

55. A process or an energizing fluid according to any of the preceding embodiments, wherein the energizing fluid forms an emulsion and wherein the emulsion is thermally stable for about 2 days at the formation temperature.

56. A process or an energizing fluid according to embodiment 3, wherein the energizing fluid forms an emulsion comprising an organic phase and an aqueous phase in a volume ratio from about 40:60 to about 60:40, and a surfactant.

57. A process or an energizing fluid according to embodiment 3, wherein the energizing fluid forms an emulsion comprising:

a) an organic phase comprising 55-85 wt% limonene;

b) an aqueous phase comprising 1-5 wt% acetic acid and a synthetic brine comprising 3-4 wt% NaCl, 0.1-1 wt% KC1, and 0.01-1 wt% CaCl₂; and c) a surfactant comprising:

i) 0.1-1 wt% tristyrylphenol (TSP) 15PO 22EO carboxylate and 0.1-1 wt% IOS

1518;

ii) TDA-35PO-20EO; or

iii) TDA-35PO-45EO.

58. A process or an energizing fluid according to embodiment 3, wherein the energizing fluid forms an emulsion comprising:

a) an organic phase comprising 40-60 wt% limonene;

c) a surfactant comprising 0.3-1.5 wt% CALF AX®.

59. A process according to any of the above embodiments, wherein the injecting step is carried out by injecting the energizing fluid prior to or simultaneously with a fracturing fluid.

60. A process according to any of the above embodiments, wherein the injecting step is carried out by injecting the energizing fluid prior to or simultaneously with a fracturing fluid during fracturing, refracturing or defracturing.

61. A process according to any of the above embodiments, wherein the injecting step is carried out by injecting the energizing fluid after injecting a fracturing fluid.

62. A process according to any of the above embodiments, wherein the contacting step occurs at a temperature from about 25°C to about 200°C.

63. A process according to any of the above embodiments, wherein the energizing fluid is injected in any sequence in a chemical alternating gas (CAG) injection process. 64. A process according to any of the above embodiments, wherein the energizing fluid is injected in a chemical alternating gas (CAG) process that alternates injection of the energizing fluid with injection of a gaseous component selected from the organic solvent, the hydrocarbon gas, and carbon dioxide.

Claims

iii) an acid;

c) recovering one or more of the oil, condensate and/or gas.

2. The process according to claim 1, wherein the oxidizing agent further comprises hydrogen peroxide, air, oxygen-enriched air, oxygen, oxygen and carbon dioxide, oxygen and an inert diluent, or any combination thereof.

3. The process according to claim 1 or claim 2, wherein the surfactant comprises

AMPHOAM®, CALF AX®, Lauryl Betaine, AOS C14-C16, a combination of IOS 1518 + a carboxylate surfactant, or any combination thereof.

4. The process according to any of claims 1-3, wherein the acid comprises hydrochloric acid, phosphoric acid, acetic acid, propionic acid, butyric acid, valeric acid, caproic acid, oxalic acid, lactic acid, malic acid, citric acid, benzoic acid, or any combination thereof.

5. The process according to any of claims 1-4, wherein the energizing fluid further comprises an organic solvent.

6. The process according to claim 5, wherein the organic solvent is selected from naphtha, limonene, cyclohexane, methyl cyclohexane, pentane, hexane, heptane, octane, and any combination thereof.

7. The process according to any of claims 1-6, further comprising a synthetic brine.

8. The process according to claim 7, wherein the synthetic brine comprises brine salts selected from NaCl, KC1, and CaCl₂, and any combination thereof.

9. The process according to any of claims 1-8, further comprising a hydrocarbon gas.

10. The process according to claim 9, where the hydrocarbon gas is selected from natural gas, methane, ethane, propane, butane, and any combination thereof.

11. The process according to any of claims 1-10, further comprising carbon dioxide.

12. The process according to claim 1, wherein the energizing fluid comprises 0.1-0.75 wt % OXONE®, 0.1-1.0 wt % CALF AX® or a carboxylate surfactant, 0.1-4 wt % limonene, and a synthetic brine comprising 0.1-4 wt% NaCl.

13. The process according to claim 12, wherein the energizing fluid is 0.5 wt % OXONE®, 0.5 wt % CALF AX®, 2 wt % limonene, and a synthetic brine consisting of 0.2 wt% NaCl

14. An energizing fluid for stimulating oil, condensate and/or gas recovery from a

hydrocarbon-bearing shale formation according to any of claims 1-13.

15. An energizing fluid for stimulating oil, condensate and/or gas recovery from a

hydrocarbon-bearing shale formation, the energizing fluid forming an emulsion comprising: a) an organic phase comprising 55-85 wt% limonene;

i) 0.1-1 wt% tnstyrylphenol (TSP) 15PO 22EO carboxylate and 0.1-1 wt% IOS

1518;

ii) TDA-35PO-20EO; or

iii) TDA-35PO-45EO.