Alkaline persulfate for low-temperature breaking of polymer viscosified fluid

Abstract

A persulfate compound activated by a strong base is used for low-temperature breaking of fluids viscosified with one or more water-soluble synthetic polymers, wherein the water-soluble synthetic polymers are selected from the group consisting of polyacrylamides, copolymers of polyacrylamide, derivatives of polyacrylamide or of copolymers of polyacrylamide, and any combination thereof. The breaker system can be used in an oilfield or pipeline application where such a synthetic polymer, a multi-chain polysaccharide, or combination thereof may be present in a fluid. It is particularly useful at low temperatures of less than 100° F.

Claims

1. A method for breaking a fluid having an apparent viscosity greater than 5 cP, wherein the fluid comprises one or more water-soluble synthetic polymers, wherein the water-soluble synthetic polymers are selected from the group consisting of: a polyacrylamide, a copolymer of polyacrylamide, a derivative of polyacrylamide, a derivative of polyacrylamide copolymer, and any combination thereof, the method comprising the steps of: contacting the fluid with: (i) one or more water-soluble persulfates; and (ii) one or more strong bases, wherein the fluid is contacted with the one or more strong bases in an amount sufficient to adjust the fluid to a pH of at least 10.5; and allowing the fluid to break to an apparent viscosity of 3 cP or less at a surface of a well site at a temperature less than 100° F.

2. The method according to claim 1, wherein the fluid comprises a brine.

3. The method according to claim 1, wherein the step of contacting does not dilute the fluid more than 10 percent by volume.

4. The method according to claim 1, wherein the fluid having an apparent viscosity greater than 5 cP is selected from the group consisting of: a flow-back fluid, an unused well fluid, a push pill, a pipeline cleaning fluid, and any combination thereof.

5. The method according to claim 1, wherein the water-soluble synthetic polymers are in at least a sufficient concentration in the water such that the fluid has a viscosity greater than 5 cP.

6. The method according to claim 1, wherein the one or more water-soluble synthetic polymer are anionic or cationic.

7. The method according to claim 1, wherein the one or more persulfates are in a weight ratio of at least 0.5 to 1 of the one or more synthetic polymers in the water of the fluid.

8. The method according to claim 1, wherein the one or more strong bases are in a mole ratio based on hydroxide of at least 0.5 to 1 of the one or more persulfates.

9. A method for breaking a fluid having an apparent viscosity greater than 5 cP, wherein the fluid comprises one or more water-soluble synthetic polymers, wherein the water-soluble synthetic polymers are selected from the group consisting of: a polyacrylamide, a copolymer of polyacrylamide, a derivative of polyacrylamide, a derivative of polyacrylamide copolymer, and any combination thereof, the method comprising the steps of: contacting the fluid with: (i) one or more water-soluble persulfates; and (ii) one or more strong bases, wherein the fluid is contacted with the one or more strong bases in an amount sufficient to adjust the fluid to a pH of at least 10.5, wherein the step of contacting is at one or more temperatures less than 100° F.; and allowing the fluid to break to an apparent viscosity of 3 cP or less at a surface of a well site at a temperature less than 100° F.

10. The method according to claim 9, wherein the fluid comprises a brine.

11. The method according to claim 9, wherein the step of contacting does not dilute the fluid more than 10 percent by volume.

12. The method according to claim 9, wherein the fluid having an apparent viscosity greater than 5 cP is selected from the group consisting of: a flow-back fluid, an unused well fluid, a push pill, a pipeline cleaning fluid, and any combination thereof.

13. The method according to claim 9, wherein the water-soluble synthetic polymers are in at least a sufficient concentration in the water such that the fluid has a viscosity greater than 5 cP.

14. The method according to claim 9, wherein the one or more water-soluble synthetic polymer are anionic or cationic.

15. The method according to claim 9, wherein the one or more persulfates are in a weight ratio of at least 0.5 to 1 of the one or more synthetic polymers in the water of the fluid.

16. The method according to claim 9, wherein the one or more strong bases are in a mole ratio based on hydroxide of at least 0.5 to 1 of the one or more persulfates.

Description

DETAILED DESCRIPTION OF PRESENTLY PREFERRED EMBODIMENTS AND BEST MODE

(1) General Definitions and Usages

(2) Interpretation

(3) The words or terms used herein have their plain, ordinary meaning in the field of this disclosure, except to the extent explicitly and clearly defined in this disclosure or unless the specific context otherwise requires a different meaning.

(4) If there is any conflict in the usages of a word or term in this disclosure and one or more patent(s) or other documents that may be incorporated by reference, the definitions that are consistent with this specification should be adopted.

(5) The words “comprising,” “containing,” “including,” “having,” and all grammatical variations thereof are intended to have an open, non-limiting meaning. For example, a composition comprising a component does not exclude it from having additional components, an apparatus comprising a part does not exclude it from having additional parts, and a method having a step does not exclude it having additional steps. When such terms are used, the compositions, apparatuses, and methods that “consist essentially of” or “consist of” the specified components, parts, and steps are specifically included and disclosed.

(6) The indefinite articles “a” or “an” mean one or more than one of the component, part, or step that the article introduces.

(7) Whenever a numerical range of degree or measurement with a lower limit and an upper limit is disclosed, any number and any range falling within the range is also intended to be specifically disclosed. For example, every range of values (in the form “from a to b,” or “from about a to about b,” or “from about a to b,” “from approximately a to b,” and any similar expressions, where “a” and “b” represent numerical values of degree or measurement) is to be understood to set forth every number and range encompassed within the broader range of values.

(8) Terms such as “first,” “second,” “third,” etc. are assigned arbitrarily and are merely intended to differentiate between two or more components, parts, or steps that are otherwise similar or corresponding in nature, structure, function, or action. For example, the words “first” and “second” serve no other purpose and are not part of the name or description of the following name or descriptive terms. The mere use of the term “first” does not require that there be any “second” similar or corresponding component, part, or step. Similarly, the mere use of the word “second” does not require that there by any “first” or “third” similar or corresponding component, part, or step. Further, it is to be understood that the mere use of the term “first” does not require that the element or step be the very first in any sequence, but merely that it is at least one of the elements or steps. Similarly, the mere use of the terms “first” and “second” does not necessarily require any sequence. Accordingly, the mere use of such terms does not exclude intervening elements or steps between the “first” and “second” elements or steps, etc.

(9) The control or controlling of a condition includes any one or more of maintaining, applying, or varying of the condition. For example, controlling the temperature of a substance can include maintaining an initial temperature, heating, or cooling.

(10) Oil and Gas Reservoirs

(11) In the context of production from a well, however, oil and “gas” are understood to refer to crude oil and natural gas, respectively. Oil and gas are naturally occurring hydrocarbons in certain subterranean formations.

(12) A “subterranean formation” is a body of rock that has sufficiently distinctive characteristics and is sufficiently continuous for geologists to describe, map, and name it.

(13) A subterranean formation having a sufficient porosity and permeability to store and transmit fluids is sometimes referred to as a “reservoir.”

(14) A subterranean formation containing oil or gas may be located under land or under the seabed off shore. Oil and gas reservoirs are typically located in the range of a few hundred feet (shallow reservoirs) to a few tens of thousands of feet (ultra-deep reservoirs) below the surface of the land or seabed.

(15) Well Servicing and Well Fluids

(16) To produce oil or gas from a reservoir, a wellbore is drilled into a subterranean formation, which may be the reservoir or adjacent to the reservoir.

(17) Generally, well services include a wide variety of operations that may be performed in oil, gas, geothermal, or water wells, such as drilling, cementing, completion, and intervention. Well services are designed to facilitate or enhance the production of desirable fluids such as oil or gas from or through a subterranean formation. A well service usually involves introducing a well fluid into a well.

(18) Wells

(19) A “well” includes a wellhead and at least one wellbore from the wellhead penetrating the earth. The “wellhead” is the surface termination of a wellbore, which surface may be on land or on a seabed. A “well site” is the geographical location of a wellhead of a well. It may include related facilities, such as a tank battery, separators, compressor stations, heating or other equipment, and fluid pits. If offshore, a well site can include a platform.

(20) The “wellbore” refers to the drilled hole, including any cased or uncased portions of the well or any other tubulars in the well. The “borehole” usually refers to the inside wellbore wall, that is, the rock surface or wall that bounds the drilled hole. A wellbore can have portions that are vertical, horizontal, or anything in between, and it can have portions that are straight, curved, or branched. As used herein, “uphole,” “downhole,” and similar terms are relative to the direction of the wellhead, regardless of whether a wellbore portion is vertical or horizontal.

(21) A wellbore can be used as a production or injection wellbore. A production wellbore is used to produce hydrocarbons from the reservoir. An injection wellbore is used to inject a fluid, e.g., liquid water or steam, to drive oil or gas to a production wellbore.

(22) As used herein, introducing “into a well” means introducing at least into and through the wellhead. According to various techniques known in the art, tubulars, equipment, tools, or well fluids can be directed from the wellhead into any desired portion of the wellbore.

(23) As used herein, the word “tubular” means any kind of body in the general form of a tube. Examples of tubulars include, but are not limited to, a drill pipe, a casing, a tubing string, a line pipe, and a transportation pipe. Tubulars can also be used to transport fluids such as oil, gas, water, liquefied methane, coolants, and heated fluids into or out of a subterranean formation. For example, a tubular can be placed underground to transport produced hydrocarbons or water from a subterranean formation to another location.

(24) As used herein, a “well fluid” broadly refers to any fluid adapted to be introduced into a well for any purpose. A well fluid can be, for example, a drilling fluid, a setting composition, a treatment fluid, or a spacer fluid. If a well fluid is to be used in a relatively small volume, for example less than about 200 barrels (about 8,400 US gallons or about 32 m.sup.3), it is sometimes referred to as a wash, dump, slug, or pill.

(25) As used herein, the word “treatment” refers to any treatment for changing a condition of a portion of a pipeline, a wellbore, or a subterranean formation adjacent a wellbore; however, the word “treatment” does not necessarily imply any particular treatment purpose. A treatment usually involves introducing a well fluid for the treatment, in which case it may be referred to as a treatment fluid, into a well. As used herein, a “treatment fluid” is a fluid used in a treatment. The word “treatment” in the term “treatment fluid” does not necessarily imply any particular treatment or action by the fluid.

(26) A zone refers to an interval of rock along a wellbore that is differentiated from uphole and downhole zones based on hydrocarbon content or other features, such as permeability, composition, perforations or other fluid communication with the wellbore, faults, or fractures. A zone of a wellbore that penetrates a hydrocarbon-bearing zone that is capable of producing hydrocarbon is referred to as a “production zone.” A “treatment zone” refers to an interval of rock along a wellbore into which a well fluid is directed to flow from the wellbore. As used herein, “into a treatment zone” means into and through the wellhead and, additionally, through the wellbore and into the treatment zone.

(27) Generally, the greater the depth of the formation, the higher the static temperature and pressure of the formation. Initially, the static pressure equals the initial pressure in the formation before production. After production begins, the static pressure approaches the average reservoir pressure.

(28) A “design” refers to the estimate or measure of one or more parameters planned or expected for a particular fluid or stage of a well service or treatment. For example, a fluid can be designed to have components that provide a minimum viscosity for at least a specified time under expected downhole conditions. A well service may include design parameters such as fluid volume to be pumped, required pumping time for a treatment, or the shear conditions of the pumping.

(29) The term “design temperature” refers to an estimate or measurement of the actual temperature at the downhole environment at the time of a treatment. For example, the design temperature for a well treatment takes into account not only the bottom hole static temperature (“BHST”), but also the effect of the temperature of the well fluid on the BHST during treatment. The design temperature for a well fluid is sometimes referred to as the bottom hole circulation temperature (“BHCT”). Because well treatment fluids may be considerably cooler than BHST, the difference between the two temperatures can be quite large. Ultimately, if left undisturbed, a subterranean formation will return to the BHST.

(30) Pipelines

(31) “Pipeline transport” refers to a conduit made from pipes connected end-to-end for long-distance fluid transport. Oil pipelines are made from steel or plastic tubulars with inner diameter typically from 4 to 48 inches (100 to 1,200 mm). Most pipelines are typically buried at a depth of about 3 to 6 feet (0.91 to 1.8 m). To protect pipes from impact, abrasion, and corrosion, a variety of methods are used. These can include wood lagging (wood slats), concrete coating, rockshield, high-density polyethylene, imported sand padding, and padding machines. The oil is kept in motion by pump stations along the pipeline, and usually flows at speed of about 3.3 to 20 ft/s (1 to 6 meters per second).

(32) Gathering pipelines are a group of smaller interconnected pipelines forming complex networks with the purpose of bringing crude oil or natural gas from several nearby wells to a treatment plant or processing facility. In this group, pipelines are usually relatively short (usually about 100 to 1000 yards or meters) and with small diameters (usually about 4 to about 12 inches). Also sub-sea pipelines for collecting product from deep water production platforms are considered gathering systems.

(33) Transportation pipelines are mainly long pipes (many miles or kilometers) with large diameters (larger than 12 inches or 30 cm), moving products (oil, gas, refined products) between cities, countries, and even continents. These transportation networks include several compressor stations in gas lines or pump stations for crude oil or multi-product pipelines.

(34) Distribution pipelines are composed of several interconnected pipelines with small diameters (usually about 1 to about 4 inches), used to take the products to the final consumer. An example of distribution pipelines is feeder lines to distribute natural gas to homes and businesses downstream. Pipelines at terminals for distributing products to tanks and storage facilities are included in this group.

(35) Physical States, Phases, and Materials

(36) The common physical states of matter include solid, liquid, and gas.

(37) As used herein, “phase” is used to refer to a substance having a chemical composition and physical state that is distinguishable from an adjacent phase of a substance having a different chemical composition or a different physical state.

(38) The word “material” is anything made of matter, constituted of one or more phases. Rock, water, air, metal, cement slurry, sand, and wood are all examples of materials.

(39) As used herein, if not otherwise specifically stated, the physical state (e.g., solid or fluid) of a substance (or mixture of substances) and other physical properties are determined at a temperature of 77° F. (25° C.) and a pressure of 1 atmosphere (Standard Laboratory Conditions) without applied shear.

(40) Hydratability or Solubility

(41) As referred to herein, “hydratable” means capable of being hydrated by contacting the hydratable agent with water. Regarding a hydratable agent that includes a polymer, this means, among other things, to associate sites on the polymer with water molecules and to unravel and extend the polymer chain in the water.

(42) A substance is considered to be “soluble” in a liquid if at least 1.0 gram of the substance can be dissolved in one liter of the liquid when tested at 77° F. and 1 atmosphere pressure for 2 hours, considered to be “insoluble” if less than 1.0 gram per liter.

(43) As will be appreciated by a person of skill in the art, the hydratability, dispersibility, or solubility of a substance in water can be dependent on the salinity, pH, or other substances in the water. Accordingly, the salinity, pH, and additive selection of the water can be modified to facilitate the hydratability, dispersibility, or solubility of a substance in aqueous solution. To the extent not specified, the hydratability, dispersibility, or solubility of a substance in water is determined in deionized water, at neutral pH, and without any other additives.

(44) As used herein, the term “polar” means having a dielectric constant greater than 30. The term “relatively polar” means having a dielectric constant greater than about 2 and less than about 30. “Non-polar” means having a dielectric constant less than 2.

(45) Fluids

(46) A fluid can be a single phase or a dispersion. In general, a fluid is an amorphous substance that is or has a continuous phase of particles that are smaller than about 1 micrometer that tends to flow and to conform to the outline of its container.

(47) Examples of fluids are gases and liquids. A gas (in the sense of a physical state) refers to an amorphous substance that has a high tendency to disperse (at the molecular level) and a relatively high compressibility. A liquid refers to an amorphous substance that has little tendency to disperse (at the molecular level) and relatively high incompressibility. The tendency to disperse is related to Intermolecular Forces (also known as van der Waal's Forces). (A continuous mass of a particulate, e.g., a powder or sand, can tend to flow as a fluid depending on many factors such as particle size distribution, particle shape distribution, the proportion and nature of any wetting liquid or other surface coating on the particles, and many other variables. Nevertheless, as used herein, a fluid does not refer to a continuous mass of particulate as the sizes of the solid particles of a mass of a particulate are too large to be appreciably affected by the range of Intermolecular Forces.)

(48) As used herein, a fluid is a substance that behaves as a fluid under Standard Laboratory Conditions, that is, at 77° F. (25° C.) temperature and 1 atmosphere pressure, and at the higher temperatures and pressures usually occurring in subterranean formations without applied shear.

(49) Every fluid inherently has at least a continuous phase. A fluid can have more than one phase. The continuous phase of a well fluid is a liquid under Standard Laboratory Conditions. For example, a well fluid can be in the form of a suspension (larger solid particles dispersed in a liquid phase), a sol (smaller solid particles dispersed in a liquid phase), an emulsion (liquid particles dispersed in another liquid phase), or a foam (a gas phase dispersed in a liquid phase).

(50) As used herein, a water-based fluid means that water or an aqueous solution is the dominant material of the continuous phase, that is, greater than 50% by weight, of the continuous phase of the fluid based on the combined weight of water and any other solvents in the phase (that is, excluding the weight of any dissolved solids).

(51) In contrast, “oil-based” means that oil is the dominant material by weight of the continuous phase of the fluid. In this context, the oil of an oil-based fluid can be any oil, based on the combined weight of oil and any other solvents in the phase (that is, excluding the weight of any dissolved solids).

(52) In the context of a well fluid, oil is understood to refer to an oil liquid, whereas gas is understood to refer to a physical state of a substance, in contrast to a liquid. In general, an oil is any substance that is liquid under Standard Laboratory Conditions, is hydrophobic, and soluble in organic solvents. Oils have a high carbon and hydrogen content and are non-polar substances. This general definition includes classes such as petrochemical oils, vegetable oils, and many organic solvents. All oils can be traced back to organic sources.

(53) Apparent Viscosity of a Fluid

(54) Viscosity is a measure of the resistance of a fluid to flow. In everyday terms, viscosity is “thickness” or “internal friction.” Thus, pure water is “thin,” having a relatively low viscosity whereas honey is “thick,” having a relatively higher viscosity. Put simply, the less viscous the fluid is, the greater its ease of movement (fluidity). More precisely, viscosity is defined as the ratio of shear stress to shear strain.

(55) A fluid moving along solid boundary will incur a shear stress on that boundary. The no-slip condition dictates that the speed of the fluid at the boundary (relative to the boundary) is zero, but at some distance from the boundary the flow speed must equal that of the fluid. The region between these two points is aptly named the boundary layer. For all Newtonian fluids in laminar flow, the shear stress is proportional to the rate of shear strain in the fluid where the viscosity is the constant of proportionality. However for non-Newtonian fluids, this is no longer the case as for these fluids the viscosity is not constant. The shear stress is imparted onto the boundary as a result of this loss of velocity.

(56) A Newtonian fluid (named after Isaac Newton) is a fluid for which stress versus strain rate curve is linear and passes through the origin. The constant of proportionality is known as the viscosity. Examples of Newtonian fluids include water and most gases. Newton's law of viscosity is an approximation that holds for some substances but not others.

(57) Non-Newtonian fluids exhibit a more complicated relationship between shear stress and velocity gradient (i.e., shear rate) than simple linearity. Thus, there exist a number of forms of non-Newtonian fluids. Shear thickening fluids have an apparent viscosity that increases with increasing the rate of shear. Shear thinning fluids have a viscosity that decreases with increasing rate of shear. Thixotropic fluids become less viscous over time at a constant shear rate. Rheopectic fluids become more viscous over time at a constant shear rate. A Bingham plastic is a material that behaves as a solid at low stresses but flows as a viscous fluid at high yield stresses.

(58) Most well fluids are non-Newtonian fluids. Accordingly, the apparent viscosity of a fluid applies only under a particular set of conditions including shear stress versus shear rate, which must be specified or understood from the context. As used herein, a reference to viscosity is actually a reference to an apparent viscosity. Apparent viscosity is commonly expressed in units of centipoise (“cP”).

(59) Like other physical properties, the viscosity of a Newtonian fluid or the apparent viscosity of a non-Newtonian fluid may be highly dependent on the physical conditions, primarily temperature and pressure.

(60) Gels and Deformation

(61) The physical state of a gel is formed by a network of interconnected molecules, such as a crosslinked polymer or a network of micelles. The network gives a gel phase its structure and an apparent yield point. At the molecular level, a gel is a dispersion in which both the network of molecules is continuous and the liquid is continuous. A gel is sometimes considered as a single phase.

(62) Technically, a “gel” is a semi-solid, jelly-like physical state or phase that can have properties ranging from soft and weak to hard and tough. Shearing stresses below a certain finite value fail to produce permanent deformation. The minimum shear stress which will produce permanent deformation is referred to as the shear strength or gel strength of the gel.

(63) Historically, to be considered to be suitable for use as a carrier fluid for a proppant for conventional reservoirs or applications such as gravel packing, it has been believed that a crosslinked gel needs to exhibit sufficient viscoelastic properties, in particular relatively high viscosities (e.g., at least about 300 to 500 cP at a shear rate of 100 sec-1). One aspect of such gel behavior may be described in the art as “lipping,” which may be distinguishable from freely pouring when poured out of a container. “Lipping” as used herein refers to a gel being deformable but retaining a coherent structure that has a lower tendency to disperse than a liquid such as water. Lipping depends on the lifetime of the crosslinking. Fluids are considered lipping if they form a lip when tilted, and that lip will not tear.

(64) In the oil and gas industry, however, the term “gel” may be used to refer to any fluid having a viscosity-increasing agent, regardless of whether it is a viscous fluid or meets the technical definition for the physical state of a gel. A “base gel” is a term used in the field for a fluid that includes a viscosity-increasing agent, such as guar, but that excludes crosslinking agents. Typically, a base gel is mixed with another fluid containing a crosslinker, wherein the mixture is adapted to form a crosslinked gel. Similarly, a “crosslinked gel” may refer to a substance having a viscosity-increasing agent that is crosslinked, regardless of whether it is a viscous fluid or meets the technical definition for the physical state of a gel.

(65) As used herein, a substance referred to as a “gel” is subsumed by the concept of “fluid” if it is a pumpable fluid.

(66) Viscosity and Gel Measurements

(67) There are numerous ways of measuring and modeling viscous properties, and new developments continue to be made. The methods depend on the type of fluid for which viscosity is being measured. A typical method for quality assurance or quality control (QA/QC) purposes uses a couette device, such as a FANN™ Model 35 or 50 viscometer or a CHANDLER™ 5550 HPHT viscometer, that measures viscosity as a function of time, temperature, and shear rate. The viscosity-measuring instrument can be calibrated using standard viscosity silicone oils or other standard viscosity fluids.

(68) Due to the geometry of most common viscosity-measuring devices, however, solid particulate, especially if larger than silt (larger than 74 micron), would interfere with the measurement on some types of measuring devices. Therefore, the viscosity of a fluid containing such solid particulate is usually inferred and estimated by measuring the viscosity of a test fluid that is similar to the fracturing fluid without any proppant or gravel that would otherwise be included. However, as suspended particles (which can be solid, gel, liquid, or gaseous bubbles) usually affect the viscosity of a fluid, the actual viscosity of a suspension is usually somewhat different from that of the continuous phase.

(69) Most well fluids are non-Newtonian fluids. Accordingly, the apparent viscosity of a fluid applies only under a particular set of conditions including shear stress versus shear rate, which must be specified or understood from the context. Unless otherwise specified, as used herein the apparent viscosity of a fluid (excluding any suspended solid particulate larger than silt) is measured with a Fann Model 35 type viscometer at a shear rate of 511 l/s and at 77° F. (25° C.) and a pressure of 1 atmosphere. Apparent viscosity is reported in units of centipoise (cP). For reference, the viscosity of pure water is 1 cP. In the oilfield and as used herein, unless the context otherwise requires it is understood that “viscosity” is actually a reference to apparent viscosity.

(70) A substance is considered to be a fluid if it has an apparent viscosity less than 5,000 cP (independent of any gel characteristic).

(71) As used herein, a fluid is considered to be “viscous” if it has an apparent viscosity of 10 cP or higher. The viscosity of a viscous fluid is considered to break or be broken if the viscosity is greatly reduced. Preferably, although not necessarily for all applications depending on how high the initial viscosity of the fluid, the viscous fluid breaks to a viscosity of 5 cP or lower.

(72) General Measurement Terms

(73) Unless otherwise specified or unless the context otherwise clearly requires, any ratio or percentage means by weight.

(74) Unless otherwise specified or unless the context otherwise clearly requires, the phrase “by weight of the water” means the weight of the water of an aqueous phase of the fluid without the weight of any viscosity-increasing agent, dissolved salt, suspended particulate, or other materials or additives that may be present in the water.

(75) As used herein, “% wt/vol” means the mass-volume percentage, sometimes referred to as weight-volume percentage or percent weight per volume and often abbreviated as % m/v or % w/v, which describes the mass of the solute in g per 100 mL of the liquid. Mass-volume percentage is often used for solutions made from a solid solute dissolved in a liquid. For example, a 40% w/v sugar solution contains 40 g of sugar per 100 mL of liquid.

(76) Unless otherwise specified, any doubt regarding whether units are in U.S. or Imperial units, where there is any difference U.S. units are intended herein. For example, “gal/Mgal” means U.S. gallons per thousand U.S. gallons.

(77) General Purposes and Applications of the Invention

(78) Fluids viscosified with a synthetic polymer or a multi-chain polysaccharide are very commonly used in gravel packing operations, sometimes in fracturing operations, and occasionally in other well treatments. An example of a synthetic polymer is a polyacrylamide. Examples of a multi-chain polysaccharide include diutan, scleroglucan, and xanthan.

(79) There are some situations where it would be valuable to be able to break a fluid viscosified with a synthetic polymer or a multi-chain polysaccharide at low temperatures. Surface or near surface applications at temperatures typically below 100° F., include, for example:

(80) (a) breaking a flow-back fluid from a well, in which a synthetic polymer or a multi-chain polysaccharide was used to increase viscosity of a well fluid used in the well.

(81) (b) breaking unused well fluids that were viscosified with a synthetic polymer or a multi-chain polysaccharide but not actually introduced into the well. This occurs, for example, when all the made-up fluid was not actually needed, leaving an excess of the unused well fluid.

(82) (c) breaking of push pills, that is, where a slug viscosified with a synthetic polymer or a multi-chain polysaccharide is used to push fluids to clean out an oil or gas transmission pipeline located at or near the surface of the ground or seafloor.

(83) Surface applications would be conveniently performed on or near the well site. Such applications would be more economical if it were not necessary to heat the fluid to achieve the break of undesired viscosity.

(84) Downhole well applications at temperatures that can be below 100° F., include, for example: (a) gravel pack fluids used in shallow wells; and (b) push pills, for example as a slug, to push other fluids in a well or subterranean formation.

(85) Such downhole applications would be more economical if it were not necessary to heat the well fluid to effect the break of undesired viscosity.

(86) For example, in some well applications, it is desirable to have a delayed break of the fluid viscosified with a synthetic polymer or a multi-chain polysaccharide in the well at less than 100° F.

(87) Synthetic polymers and multi-chain polysaccharides are typically more difficult to break than single-chain polysaccharides. This is especially a problem at low temperatures. Generally, to break fluid viscosified with a polyacrylamide or polysaccharide requires the generation of a certain number of cleavages in the polymer backbone so as to break the polymer and cause the desired reduction in viscosity of the fluid. The polyacrylamides or multi-chain polysaccharides require more cleavages of the polymer backbone than for a single-chain polysaccharide to break the viscosity.

(88) It is known in the art, however, that the effectiveness of an oxidizer for breaking a polyacrylamide or polysaccharide decreases with decreasing temperature. Various oxidizer systems are available to break a fluid viscosified with xanthan at high and even moderate temperatures; however, most of them cannot achieve similar breaking results at low temperatures, which in this context means less than 100° F. Known oxidizers are essentially ineffective for this purpose at low temperatures of less than 100° F.

(89) For example, oxidizers such as hypochlorites are commonly used to break viscosified fluids at moderate or higher temperatures, in this context meaning greater than 100° F. However, at low temperatures below 100° F., their activity is low. Hence, high concentrations and excessive volumes of hypochlorites are required for initiating the breaking action. Even in these situations, it is difficult to achieve viscosities comparable to those of water (1.0 cP), which is the ideal objective. In field applications where large quantities of fluid viscosified with xanthan are required to be broken, using enormous quantities of hypochlorite breakers becomes highly impractical and expensive.

(90) In cases where a delayed break is desired, such as a downhole well application, at moderate temperatures above 100° F. (38° C.) and higher, this can be achieved by a reduction of the concentration of the oxidizer. However, there is a limit to the degree to which the concentration of the oxidizer can be reduced because, as noted above, there are a certain number of cleavages in the polymer backbone that are necessary to achieve the desired reduction in viscosity.

(91) Therefore, especially at low or very low temperatures, to achieve a delayed break, a control mechanism other than the concentration of strong oxidizer alone is necessary.

(92) A prior invention for Halliburton discloses the method of using a composition comprising of water, a source of hydrogen peroxide (e.g., sodium perborate), and an activator for the source of hydrogen peroxide to break viscosified fluids used for treating portions of wellbore or formation at temperatures below 100° F. US patent Publication No. US 2008/0176770 A1, published Jul. 24, 2008, having for named inventors Michael W. Sanders, Jeffrey L. Mundy, Fong Fong Foo, and Rajesh K. Saini, entitled “Compositions & Methods for breaking a viscosity increasing polymer at very low temperature used in downhole well applications,” is incorporated by reference in its entirety.

(93) The purpose of this invention is to provide a breaker system that can effectively break a fluid viscosified with a synthetic polymer or a multi-chain polysaccharide. The method is especially useful at low temperatures, which in this context means at less than 100° F. Preferably, a breaker system should be able to effectively break such polyacrylamides or multi-chain polysaccharides at very low temperatures, which in this context means at less than 90° F. Other oxidizing systems such as peroxides with catalysts have been used though with little success for multi-chain polysaccharides at low temperatures, and especially at very low temperatures. Another purpose is to provide a breaker system that is simple to use and inexpensive.

(94) It has been discovered that a persulfate compound activated by a strong base can break a fluid viscosified with a synthetic polymer or a multi-chain polysaccharide at low and very low temperatures.

(95) A breaker system according to the invention can be used in an oilfield or pipeline application where a synthetic polymer or a multi-chain polysaccharide may be used in a fluid. It is particularly useful at low and very low temperatures.

(96) A commonly used synthetic polymer is a polyacrylamide.

(97) A commonly used multi-chain viscosity-increasing polysaccharide is xanthan. For example, xanthan is typically used in the range of from about 0.25% to about 1.5% by weight of the water in well fluids. Xanthan is being used, for example, in low-temperature gravel pack and frac-pack applications. For example, 0.2% xanthan exhibits some elasticity, and elasticity is expected to be observable down to about 0.1% by weight xanthan in water. Any returned fluid from a well or any unused well fluid exhibiting viscosity greater than 5 cP would be a candidate for low-temperature breaking of the fluid before other use, particularly for other use in a well or disposal.

(98) An added advantage of this breaker system is the use of small relative volumes, which makes this system attractive and practical for field conditions. The breaker system can be a simple and inexpensive two-component system.

(99) Another advantage of the compositions and methods according to the invention is the ability to break a fluid viscosified with a synthetic polymer or a multi-chain polysaccharide in a controlled manner at low temperature or very low temperature, that is, the rate of degradation of the polymer is not immediate and can be relatively slow. The rate of degradation of the fluid can be controlled, including by varying the concentration of persulfate or the mole ratio of persulfate to alkali.

(100) Presently, the most preferred embodiment uses a simple two-component breaker system comprising sodium persulfate and sodium hydroxide. This breaker system can break a fluid of 60 lb/Mgal xanthan to a very low viscosity of 3 cP or less at 85° F. within a very short time of 24 hrs.

(101) The persulfate anion is a very strong oxidant species. Without being limited by any theory, it is believed that the persulfate anion can be induced to form a sulfate free radical, which has an estimated redox potential of 2.6 V. These species can then initiate a free radical reaction to affect the breaking of viscosified fluids. According to the breaker system of the present invention, combination of the persulfate and the alkali generates free radicals that can break synthetic polymers such as polyacrylamides or break multi-chain polysaccharides such as xanthan. Persulfate radicals are generated at temperatures above about 140° F. At temperatures below 140° F., however, persulfate needs to be activated so that persulfate radicals can be produced at lower temperatures.

(102) The apparent viscosity of the fluid to be broken is greater than 5 cP. Preferably, the apparent viscosity of the fluid to be broken is greater than 10 cP. More preferably, the apparent viscosity of the fluid to be broken is in the range of 10 cP to 50 cP.

(103) Preferably the synthetic polymer, multi-chain polysaccharide, or combination thereof is present in at least 0.24% by weight of the water (20 lb/Mgal) in the fluid, and more preferably in the range of 0.24% by weight of the water (20 lb/Mgal) to about 1% by weight of the water (about 80 lb/Mgal).

(104) The persulfate is present in a sufficient concentration to break the viscosity of a fluid comprising water and the synthetic polymer or the multi-chain polysaccharide, or any combination thereof. The concentration of the persulfate and the strong base can be adjusted to help control the break times. For example, the persulfate is preferably present in at least about 0.4% by weight (about 30 lb/Mgal) of the water, and more preferably in the range of about 0.5% by weight (about 40 lb/Mgal) to about 3% by weight (about 250 lb/Mgal) of the water of the fluid to be broken.

(105) A well fluid according to the invention is preferably injected at a temperature of less than 150° F. (65° C.). This temperature range is within the normal ambient temperature range at the wellhead and avoids any need for heating the treatment fluid. The treatment fluid has particular application when injected at a temperature below 100° F. (38° C.). The treatment fluids and methods according to the invention are especially useful at low temperatures, at which fluids viscosified with xanthan are more difficult to break, such as where the design temperature of the subterranean formation is less than 100° F. (38° C.).

(106) In addition, it is presently believed that this breaker system of persulfate and strong base would work on other water-soluble polymers. More particularly, it is presently expected that this breaker system would be effective to break water-soluble synthetic polymers, such as those used as friction reducers in well fluids. Still more particularly, it is presently expected that this breaker system would be effective to break a fluid of a water-soluble polyacrylamide.

(107) In comparison to certain other oxidizing systems, the components of the alkaline persulfate according to this invention can be provided in aqueous solutions that can be metered as liquid additives. This can offer handling advantages over solid additives such as certain peroxides. In addition, the alkaline persulfate can break in much shorter times at low temperatures.

(108) Another advantage of the alkaline persulfate breaker system is that it is an environmental friendly system.

(109) Surface or Subsurface Applications

(110) According to an embodiment, methods are provided for breaking the viscosity of a fluid having an apparent viscosity greater than 5 cP, wherein the viscous fluid comprises a synthetic polymer or a multi-chain polysaccharide or a combination thereof in water. The method includes the step of contacting the viscous fluid with: (i) one or more water-soluble persulfates; and (ii) one or more strong bases. Preferably, the step of contacting is at one or more temperatures less than 150° F. More preferably, the step of contacting is at one or more temperatures less than 100° F.

(111) The methods are useful at very low temperatures, wherein the step of contacting is at one or more temperatures less than 90° F. Most preferably, the step of contacting is at one or more temperatures less than 80° F. Most preferably, the portion of the well has a design temperature greater than 70° F.

(112) As discussed in more detail, the methods are useful in several applications, including, for example, treating of flow-back water, unused treatment fluid, pipeline cleaning, etc.

(113) Preferably, the step of contacting further involves mixing. The mixing can be by any convenient technique.

(114) The one or more water-soluble persulfates can be used in any convenient form, such as solid particulate or pre-dissolved in an aqueous solution. Similarly, the one or more strong bases can be used in any convenient form, such as solid particulate or pre-dissolved in an aqueous solution.

(115) Preferably, the step of contacting does not dilute the fluid more than 10 percent by volume. More preferably, the step of contacting does not dilute the fluid more than 5 percent by volume.

(116) The fluid to be broken can be of various sources or types. Most commonly, it is expected that the fluid to be broken will be one in which the continuous phase of the fluid comprises the synthetic polymer or multi-chain polysaccharide in water. Advantageously, the water can be a brine.

(117) In an embodiment, the synthetic polymer or the multi-chain polysaccharide or the combination thereof is in at least a sufficient concentration in the water such that the fluid to be broken has a viscosity greater than 5 cP. Preferably, the apparent viscosity of the fluid to be broken is greater than about 10 cP. More preferably, the apparent viscosity of the fluid to be broken is in the range of about 10 cP to about 50 cP. For example, a fluid of 20 lb/Mgal xanthan in tap water shows 10 cP apparent viscosity as measured with a Fann 35 viscometer at 300 rpm (511 sec-1 shear rate).

(118) In an embodiment, the multi-chain polysaccharide is xanthan.

(119) Preferably, the one or more persulfates are in a weight ratio of at least 0.5 to 1 of a synthetic polymer or the multi-chain polysaccharide or combination thereof in the fluid. In another embodiment, the one or more persulfates are in a concentration of at least 30 lb/Mgal of the viscous fluid.

(120) Preferably, the one or more persulfates are selected from the group consisting of sodium persulfate, potassium persulfate, ammonium persulfate, and any combination thereof. More preferably, the one or more persulfates are selected from the group consisting of sodium, potassium persulfate, and any combination thereof.

(121) In an embodiment, the one or more strong bases are in a mole ratio based on hydroxide of at least 0.5 to 1 of the one or more persulfates.

(122) Preferably, the one or more strong bases are selected from the group consisting of sodium hydroxide, potassium hydroxide, sodium carbonate, potassium carbonate and any combination thereof. Most preferably, the one or more strong bases are selected from the group consisting of sodium hydroxide, potassium hydroxide, and any combination thereof.

(123) Delayed Break in Well Fluid Application

(124) According to another embodiment, methods are provided of treating a well, wherein the methods include the steps of: (a) forming a treatment fluid comprising: (i) water; and (ii) one or more synthetic polymers, multi-chain polysaccharides, or combination thereof wherein the synthetic polymers, multi-chain polysaccharides, or combination thereof are in at least a sufficient concentration in the water such that the first treatment fluid has a viscosity of at least 5 cP; (iii) one or more persulfates; and (iv) one or more strong bases; and (b) introducing the treatment fluid into the well and directing the treatment fluid to a portion of the well. Preferably, the portion of the well has a design temperature less than 150° F. More preferably, the portion of the well has a design temperature less than 100° F.

(125) The methods are useful at very low temperatures, wherein the portion of the well has a design temperature less than 90° F. Most preferably, the portion of the well has a design temperature greater than 70° F.

(126) Preferably, the water is of any convenient source that does not have any component that would interfere with the chemistry of hydrating the polysaccharide, the chemistry of the breaking, the intended use of the viscosified treatment fluid, or the use of the fluid after breaking.

(127) Preferably, the methods further include the steps of: (a) after the step of introducing, allowing the treatment fluid to break in the portion of the well; and then (b) flowing back from the well.

(128) The treatment fluid can further include proppant or gravel.

(129) The step of introducing the treatment fluid can further include introducing above the fracture pressure of the subterranean formation.

(130) The step of introducing the treatment fluid can further include: gravel packing, which is below the fracture pressure of the subterranean formation.

(131) Stepwise Well Fluid Application

(132) According to yet another embodiment, methods are provided of treating a well, wherein the method include the steps of: (a) forming a first treatment fluid comprising: (i) water; and (ii) one or more synthetic polymers, multi-chain polysaccharides, or a combination thereof, wherein the synthetic polymers, multi-chain polysaccharides, or the combination thereof are in at least a sufficient concentration in the water such that the first treatment fluid has a viscosity of at least 5 cP; (b) forming a second treatment fluid comprising: (i) one or more persulfates; and (ii) one or more strong bases; (c) introducing the first treatment fluid into the well; (d) introducing the second treatment fluid into the well; and (e) directing the first treatment fluid and the second treatment fluid to contact each other in a portion of the well. Preferably, the portion of the well has a design temperature less than 150° F. More preferably, the portion of the well has a design temperature less than 100° F.

(133) The methods are useful at very low temperatures, wherein the portion of the well has a design temperature less than 90° F. Most preferably, the portion of the well has a design temperature greater than 70° F.

(134) Preferably, the water is of any convenient source that does not have any component that would interfere with the chemistry of hydrating the polysaccharide, the chemistry of the breaking, the intended use of the viscosified treatment fluid, or the use of the fluid after breaking.

(135) Preferably, the method further includes the steps of: (a) after the step of directing the first treatment fluid and the second treatment fluid to contact each other in a portion of the well, allowing the second fluid to break the viscosity of the first fluid in the portion of the well; and then (b) flowing back from the well.

(136) The step of introducing the first treatment fluid into the well can be before the step of introducing the second treatment fluid into the well. In a different embodiment, the step of introducing the first treatment fluid into the well is after the step of introducing the second treatment fluid into the well. Thus, the second treatment fluid comprising the one or more persulfates can be introduced according to an overflush technique or according to a “poison pill” technique.

(137) In an embodiment, the first treatment fluid further comprises proppant or gravel.

(138) In an embodiment, the step of introducing the first treatment fluid further comprises introducing above the fracture pressure of the subterranean formation.

(139) In another embodiment, the step of introducing the first treatment further comprises: gravel packing, which is below the fracture pressure of the formation.

EXAMPLES

(140) General procedure: to a blender jar, add the water and xanthan and allow the xanthan to fully hydrate. Measure the viscosity of the fluid at the start (that is, upon hydration of the xanthan); add the sodium persulfate and the sodium hydroxide; place the test sample in a temperature bath; measure the viscosity over time.

(141) Unless otherwise specified, the water used in these examples is fresh tap water. Sodium persulfate is sometimes reported as simply “persulfate.” Sodium hydroxide is sometimes reported as simply “hydroxide.”

(142) All temperatures are reported in degrees Fahrenheit (° F.).

(143) In all the experiments, apparent viscosity in centiPoise (cP) was measured on a Fann Model 35 viscometer using R1 rotor, B1 bob, and F1 spring at 300 rpm, equivalent to 511 sec.sup.−1 shear. Viscosity readings were taken on a F1 spring Fann 35 Viscometer. The initial viscosity readings were taken with the viscosified fluid at room temperature (about 77° F.). All other readings were taken with the test sample placed in a temperature bath of the stated temperature. The samples were placed in the temperature bath of the stated temperature. Each day, the bottles were removed from the temperature bath and immediately readings were taken on the Fann 35 viscometer.

(144) Xanthan loading used was a 60 lb/Mgal in fresh tap water or a 9.1 ppg NaCl brine. The initial viscosity of the fluid was 39.0 cP. The persulfate used was sodium persulfate. The hydroxide used was sodium hydroxide. Concentrations of the persulfate are reported in pounds per 1000 gallons (lb/Mgal). Concentrations of the hydroxide concentrations are reported in mole ratio to the persulfate concentration. The fluid was considered to be broken when viscosity of 3.0 cP or less was measured.

(145) For a fluid of 60 lb/Mgal xanthan in tap water at 85° F., Table 1 shows the effect on the break time of varying the mole ratio of hydroxide to persulfate, using a persulfate concentration of 50 lb/Mgal persulfate.

(146) TABLE-US-00001 TABLE 1 Conc. of Mole Ratio Xanthan Test Sodium Hy- Broken Break Loading Temp.. Persulfate Persulfate droxide Viscosity Time 60 85° F. 50 1.0 0.5 3.0 cP Day 10 lb/Mgal lb/Mgal (240 hrs) in (0.60% 1.0 0.6 3.0 cP Day 8 tap w/v) (192 hrs) water 1.0 0.7 3.0 cP Day 6 (144 hrs) 1.0 0.8 3.0 cP Day 5 (120 hrs) 1.0 0.9 3.0 cP Day 4 (96 hrs) 1.0 1.0 3.0 cP Day 3 (72 hrs) 1.0 1.1 2.5 cP Day 3 (72 hrs) 1.0 1.2 2.5 cP Day 3 (72 hrs) 1.0 1.3 3.0 cP Day 2 (48 hrs) 1.0 1.4 2.5 cP Day 2 (48 hrs) 1.0 1.5 3.0 cP Day 1 (24 hrs) 1.0 3.0 1.5 cP Day 1 (24 hrs) 1.0 4.5 1.5 cP Day 1 (24 hrs) 1.0 6.0 1.0 cP Day 1 (24 hrs)

(147) For a fluid of 60 lb/Mgal xanthan in tap water at 85° F., Table 2 shows the effect on break time of varying the mole ratio of hydroxide to persulfate, using a persulfate concentration of 40 lb/Mgal.

(148) TABLE-US-00002 TABLE 2 Conc. of Mole Ratio Xanthan Test Sodium Hy- Broken Break Loading Temp. Persulfate Persulfate droxide Viscosity Time 60 85° F. 40 1.0 0.5 Unbroken (5.0 cP) lb/Mgal lb/Mgal after 12 days in (0.48% 1.0 0.6 3.0 cP Day 10 tap w/v) (240 hrs) water 1.0 0.7 3.0 cP Day 7 (168 hrs) 1.0 0.8 3.0 cP Day 5 (120 hrs) 1.0 0.9 3.0 cP Day 5 (120 hrs) 1.0 1.0 3.0 cP Day 5 (120 hrs) 1.0 1.1 3.0 cP Day 4 (96 hrs) 1.0 1.2 3.0 cP Day 3 (72 hrs) 1.0 1.3 2.5 cP Day 3 (72 hrs) 1.0 1.4 2.5 cP Day 3 (72 hrs) 1.0 1.5 2.5 cP Day 3 (72 hrs)

(149) The data in the Tables 1 and 2 show that at a particular temperature and at a particular persulfate concentration, the break times can be controlled by adjusting the concentration of the persulfate and the mole ratio of the hydroxide to the persulfate.

(150) For a fluid of 60 lb/Mgal xanthan in tap water at 85° F., Table 3 shows the effect on break time of varying the concentration of persulfate, keeping a constant mole ratio of hydroxide to persulfate.

(151) TABLE-US-00003 TABLE 3 Conc. of Mole Ratio Xanthan Test Sodium Hy- Broken Break Loading Temp. Persulfate Persulfate droxide Viscosity Time 60 85° F. 30 1.0 1.0 3.0 cP Day 8 lb/Mgal lb/Mgal (192 hrs) in (0.36% tap w/v) water 40 1.0 1.0 3.0 cP Day 5 lb/Mgal (120 hrs) (0.48% w/v) 50 1.0 1.0 3.0 cP Day 3 lb/Mgal (72 hrs) (0.60% w/v)

(152) Data in Table 3 shows that at a particular temperature, break times can be controlled by adjusting the concentration of the persulfate.

(153) For a fluid of 60 lb/Mgal xanthan in tap water, Table 4 shows the effect of varying the temperature on the break time.

(154) TABLE-US-00004 TABLE 4 Conc. of Mole Ratio Xanthan Test Sodium Hy- Broken Break Loading Temp. Persulfate Persulfate droxide Viscosity Time 60 90° F. 50 1.0 1.0 3.0 cP Day 1 lb/Mgal lb/Mgal (24 hrs) in 85° F. (0.60% 1.0 1.0 3.0 cP Day 3 tap w/v) (72 hrs) water 80° F. 1.0 1.0 3.0 cP Day 6 (144 hrs)

(155) Data in Table 4 shows that the activated breaker composition can be used to effectively break fluids viscosified with xanthan at very low temperatures, in this context meaning down to 80° F.

(156) For a fluid of 60 lb/Mgal xanthan in 9.1 ppg NaCl brine at 90° F., Table 5 shows the effect on break time of varying the mole ratio of hydroxide to persulfate, using a persulfate concentration of 50 lb/Mgal.

(157) TABLE-US-00005 TABLE 5 Conc. of Mole Ratio Xanthan Test Sodium Hy- Broken Break Loading Temp. Persulfate Persulfate droxide Viscosity Time 60 90° F. 50 1.0 0.8 3.0 cP Day 4 lb/Mgal lb/Mgal (96 hrs) in (0.60% 1.0 0.9 3.0 cP Day 3 9.1 ppg w/v) (72 hrs) NaCl 1.0 1.0 3.0 cP Day 1 brine (24 hrs)

(158) Data in Table 5 shows that at a particular temperature and at a particular persulfate concentration in a brine, the break times can be controlled by adjusting the ratio of persulfate:hydroxide. It also shows that the alkaline activated persulfate mechanism can work to break fluids of xanthan in brines.

(159) In addition, the experimental data described below highlights the utility of this breaker recipe towards breaking of fluid containing a polyacrylamide friction reducer to essentially water-like viscosities of about 1.0 cP (measured at a shear rate of 511 sec.sup.−1 on a Fann 35 viscometer).

(160) A solution of “FR-56”™, which is a polyacrylamide friction reducer commercially available from Halliburton Energy Services, Inc., was prepared in fresh water at a concentration of 1.0 gal/Mgal. 200 ml of this solution was taken in different bottles to which a sufficient amount of a 25% w/v solution of sodium persulfate was added to provide the required amount of sodium persulfate in each of the test bottle. For alkaline activation of the persulfate, the pH of each of these bottles was adjusted to the desired value with the help of a 25% w/v aqueous solution of NaOH.

(161) The preliminary test results are shown in Tables 6 and 7, below.

(162) TABLE-US-00006 TABLE 6 pH Break adjusted Time with 25% (when w/v viscosity Test Sodium solution Initial drops to Broken FR-56 ™ Temp. Persulfate of NaOH viscosity 1.0 cP) viscosity 1.0 85° F. 1.0 10.5 9.0 cP 12 hrs 1.0 cP gal/Mgal lb/Mgal 1.0 85° F. 1.0 11.0 9.0 cP  7 hrs 1.0 cP gal/Mgal lb/Mgal 1.0 85° F. 1.0 11.5 9.0 cP  4 hrs 1.0 cP gal/Mgal lb/Mgal

(163) TABLE-US-00007 TABLE 7 pH Break adjusted Time with 25% (when w/v viscosity Test Sodium solution Initial drops to Broken FR-56 ™ Temp. Persulfate of NaOH viscosity 1.0 cP) viscosity 1.0 85° F. 1.0 11.0 9.0 cP 7 hrs 1.0 cP gal/Mgal lb/Mgal 1.0 90° F. 1.0 11.0 9.0 cP 3 hrs 1.0 cP gal/Mgal lb/Mgal

(164) Tables 6 and 7 show that persulfate can be sufficiently activated to effectively break a polyacrylamide friction reducer that is typically used in slick water fracturing and HRWP gravel packing operation to water-like viscosity at such a low temperature of 85° F.

(165) This data also indicates that the break time can be optimized depending upon the requirements by changing the amount of the alkaline activator. The tables above also show that the disclosed breaker system can help break a polyacrylamide friction reducer in as short a time as 3 hours.

(166) Water shut-off applications often use copolymers of polyacrylamide and t-butyl acrylate. This copolymer is further crosslinked using organic crosslinkers of the type similar to polyethyleneimine. The breaker described in this particular invention are expected to work in breaking down the copolymers of polyacrylamide and t-butyl acrylate as well as the crosslinked polymer formed using polyethyleneimine

(167) The breaker is also expected to work on water-soluble polyacrylamide derivatives like poly(N,N-dimethyl acrylamide) and its water soluble copolymer with acrylamide formed by incorporating varying percentages of N,N-dimethyl acrylamide.

CONCLUSIONS

(168) Therefore, the present invention is well adapted to attain the ends and advantages mentioned as well as those that are inherent therein.

(169) The exemplary fluids disclosed herein may directly or indirectly affect one or more components or pieces of equipment associated with the preparation, delivery, recapture, recycling, reuse, or disposal of the disclosed fluids. For example, the disclosed fluids may directly or indirectly affect one or more mixers, related mixing equipment, mud pits, storage facilities or units, fluid separators, heat exchangers, sensors, gauges, pumps, compressors, and the like used generate, store, monitor, regulate, or recondition the exemplary fluids. The disclosed fluids may also directly or indirectly affect any transport or delivery equipment used to convey the fluids to a well site or downhole such as, for example, any transport vessels, conduits, pipelines, trucks, tubulars, or pipes used to move the fluids from one location to another, any pumps, compressors, or motors (e.g., topside or downhole) used to drive the fluids into motion, any valves or related joints used to regulate the pressure or flow rate of the fluids, and any sensors (i.e., pressure and temperature), gauges, or combinations thereof, and the like. The disclosed fluids may also directly or indirectly affect the various downhole equipment and tools that may come into contact with the chemicals/fluids such as, but not limited to, drill string, coiled tubing, drill pipe, drill collars, mud motors, downhole motors or pumps, floats, MWD/LWD tools and related telemetry equipment, drill bits (including roller cone, PDC, natural diamond, hole openers, reamers, and coring bits), sensors or distributed sensors, downhole heat exchangers, valves and corresponding actuation devices, tool seals, packers and other wellbore isolation devices or components, and the like.

(170) The particular embodiments disclosed above are illustrative only, as the present invention may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. It is, therefore, evident that the particular illustrative embodiments disclosed above may be altered or modified and all such variations are considered within the scope and spirit of the present invention.

(171) The various elements or steps according to the disclosed elements or steps can be combined advantageously or practiced together in various combinations or sub-combinations of elements or sequences of steps to increase the efficiency and benefits that can be obtained from the invention.

(172) The invention illustratively disclosed herein suitably may be practiced in the absence of any element or step that is not specifically disclosed or claimed.

(173) Furthermore, no limitations are intended to the details of construction, composition, design, or steps herein shown, other than as described in the claims.