WO2013085410A1

WO2013085410A1 - Well treatment

Info

Publication number: WO2013085410A1
Application number: PCT/RU2011/000969
Authority: WO
Inventors: Bruno Lecerf; Anna Petrovna DUNAEVA; Alexey Alexandrovich Sova; Dmitry Ivanovich Potapenko
Original assignee: Schlumberger Canada Limited; Services Petroliers Schlumberger; Schlumberger Holdings Limited; Schlumberger Technology B.V.; Prad Research And Development Limited
Priority date: 2011-12-09
Filing date: 2011-12-09
Publication date: 2013-06-13

Abstract

A method is given for temporarily isolating a chemical or chemicals and/or one or more physical components from a trigger or trigger mechanism, that causes or allows them to function, by preventing direct contact and therefore interaction between the chemical or physical materials and, for example, the main treatment fluid or other chemicals or the formation. The method involves immersing the reagent(s) and/or physical components in a trigger-preventing fluid, for example a phase immiscible with the phase containing the trigger, in a fit-for-purpose injector on the surface and then injecting the injection fluid into the main fluid on the surface. Optionally the chemical or physical material(s) are in a container that is insoluble in the injection fluid and soluble in the main fluid. The triggering event, for example mixing of miscible and immiscible fluids, or a change in the pH or salinity of the main fluid, or dissolution of the container, occurs in the wellbore and allows direct contact of the one or more chemical or physical materials with the main fluid and thus interaction and carrying out of the function of the one or more chemicals or physical materials.

Description

WELL TREATMENT Background

The statements in this section merely provide background information related to the present disclosure and may not constitute prior art.

This disclosure relates to drilling, completion, stimulation and workover of wells. Such operations frequently require using various chemical and physical additives. In some situations it is necessary to control, for example to delay, a triggering process or contact with a triggering chemical that allows direct contact and therefore interaction between the chemical or physical materials and, for example, the main treatment fluid or other chemicals or the formation. Various approaches are .commonly used to delay triggering processes. As examples, in various methods, delaying agents are used in fracturing applications to delay polymer crosslinking; separate conveying methods, for example bailers and microcoils, are used to separate reactive reagents physically until they reach a desired downhole location; water proofing agents are used to delay reaction with water; and encapsulation in a material insoluble in the main fluid is used to delay contact of a polymer with an encapsulated breaker.

Some methods are engineered to inhibit the downhole trigger for a specified significant amount of time, and/or until the chemicals and triggers have reached, for example, a selected pressure, depth, location, temperature or travel time. In other methods, preventing the triggering event from happening in surface equipment is needed, so that the triggered chemical or physical process is started only after the chemical or physical components and triggers are in the wellbore. Often, only a short inhibition time after all the chemicals and/or physical materials have been combined and are injected is required to prevent a triggering process from occurring while the fluid is in the surface equipment. For example, this may be necessary to avoid damage to the equipment, or damage to the chemicals and/or physical materials that subsequently affect their performance downhole.

Summary

This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter. One embodiment disclosed is a method of adding, on the surface, one or _^more chemical or physical materials to a main treatment fluid being pumped into a well while preventing direct contact of the one or more chemical or physical materials with the main treatment fluid before they enter the wellbore. Direct contact on the surface must be prevented because the one or more chemical or physical materials would interact with the main treatment fluid when they directly contact the main treatment fluid. The method involves a) providing an injector on the surface that contains a trigger- preventing injection fluid that contains the one or more chemical or physical materials, b) injecting the injection fluid into the main fluid on the surface, c) and allowing the injection fluid and the main fluid to mix in the wellbore, thus allowing a triggering event that provides direct contact and interaction of the one or more chemical or physical materials with the main treatment fluid. Brief Description of the Drawings

Embodiments of the well treatment are described with reference to the following figures. The same numbers are used throughout the figures to reference like features and components.

Figure 1 is a schematic of one device by which embodiments can be implemented by introducing injection fluids into main fluids in a high pressure flow line.

Figure 2 is a schematic of another device by which embodiments can be implemented by introducing injection fluids into main fluids in a high pressure flow line.

Figures 3A and 3B illustrate examples of a ball injector, placed on a wellhead, by which embodiments can be implemented to inject containers.

Figure 4 shows swelling of alginate/calcium complexes vs. time in water in the presence of various ions in one embodiment.

Figure 5 shows swelling of alginate/calcium complexes in solutions of potassium and calcium chloride in one embodiment.

Detailed Description

It should be noted that in the development of any actual embodiments, numerous implementation-specific decisions may be made to achieve the developer's specific goals, for example compliance with system- and

business-related constraints, which can vary from one implementation to another. Moreover, it will be appreciated that such a development effort might be complex and time consuming but would nevertheless be a routine undertaking for those of ordinary skill in the art having the benefit of this disclosure.

The description and examples are presented solely for the purpose of illustrating embodiments and should not be construed as a limitation to the scope and applicability. Although some of the following discussion emphasizes fracturing and gravel packing, the temporary chemical isolation devices and methods of the embodiments may be used in many other operations. The embodiments may be described in terms of treatment of vertical wells, but is equally applicable to wells of any orientation. The embodiments may be described for hydrocarbon production wells, but it is to be understood that the concepts may be used for wells for production of other fluids, for example water or carbon dioxide, or, for example, for injection or storage wells. It should also be understood that throughout this specification, when a concentration or amount range is described as being useful, or suitable, or the like, it is intended that any and every concentration or amount within the range, including the end points, is to be considered as having been stated. Furthermore, each numerical value should be read once as modified by the term "about" (unless already expressly so modified) and then read again as not to be so modified unless otherwise stated in context. For example, "a range of from 1 to 10" is to be read as indicating each and every possible number along the continuum between about 1 and about 10. In other words, when a certain range is expressed, even if only a few specific data points are explicitly identified or referred to within the range, or even when no data points are referred to within the range, it is to be understood that the inventors appreciate and understand that any and all data points within the range are to be considered to have been specified, and that the inventors have possession of the entire range and all points within the range.

The discussion in this paragraph of possible alternatives to the presently disclosed embodiments merely provides context information related to the present disclosure and may not constitute prior art. U. S. Patent Application No. 13/105,588, filed May 11, 201 1, entitled "Destructible Containers for Downhole Material and Chemical Delivery" and assigned to the same assignee as the present application, and having inventors in common, discloses a method of wellsite delivery of solid materials useful for fluid flow diversion that utilizes mechanically destructible containers which are bullheaded downhole and destroyed in the wellbore before entering a formation. U. S. Patent Application No. 13/105,588 also discloses a method of downhole delivery of chemical agents or solid materials that are placed in destructible containers that are pre-formed empty and then filled, or are placed around the agents or materials, and then broken in surface equipment or in the wellbore by special apparatus previously placed in the wellbore or by perforations to release the contents into a formation or fracture; the containers include, but are not limited to, bags or hollow balls (that may optionally be rigid and may optionally dissolve, degrade, etc. after release of the contents). However, U. S. Patent Application No. 13/105,588 does not disclose a method of preventing chemical dissolution from initiating or occurring on the surface when the container is in contact with the liquid present in the surface equipment, including liquid left over from pumping the previous stage, prior to or during pumping. U.S. Pat. No. 7,049,272 discloses a method of treating a well with solids, liquids or apparatuses by 1 ) encasing said solids, liquids or apparatuses in a pre-formed water soluble shell, for example a polyvinyl alcohol (PVA) cylinder, 2) conveying said encased solids, liquids or apparatuses to a predetermined location in the well, and 3) allowing the water-soluble shell to dissolve in the aqueous phase in the wellbore. The shell is "resistant to diffusion in either direction" and "able to resist substantial physical and mechanical forces without breaking"; illustrative examples include placing encased soap at the bottom of the well for assisting in gas-lift, and placing corrosion inhibitors. No action is taken to destroy the shell, the shell is not injected in a fluid other than the main well fluid, and the shell does not release any material before it reaches the treatment location. In order to prevent early dissolution of the shell, the inventors proposed inclusion of a layer, or partial layer, of a waterproofing agent to prevent premature dissolution on contact with water. The water proofing agent comprises, for example, a phenoxy resin, or wax, or mixtures thereof. There are several applications in the oil-field industry which are based on using encapsulated chemicals for delayed triggering of chemical reactions downhole. U. S. Pat. No. 6,794,340 discloses a method of removing drill cuttings from wellbores and drilling fluids by crosslinking drilling fluid with a crosslinker and a crosslinker activator that is encapsulated and released by destruction of the capsule as it passes through the drill bit or that is released by dissolution or melting of the encapsulation material at bottomhole temperature. All encapsulated material and any remaining encapsulation material are returned to the surface. U. S. Pat. No. 4,614,599 discloses a lost circulation treatment comprising encapsulating lime in a reaction-preventive protective casing (for example a film of wax) in a circulating drilling fluid to prevent the lime from reacting with clays in the borehole until it is desired to breach the casing; if lost circulation occurs, circulation is slowed or stopped so that the temperature rises and the time of the fluid in the lost circulation pathway lengthens and the coating dissolves or melts and the lime reacts with clays in the drilling fluid and/or the formation to plug the lost circulation pathway. Using encapsulated liquids for formation treatments is disclosed in U.S. Pat. No. 6,761 ,220 in which contents of capsules "within the downhole region of a well" may be released by crushing, rupturing, dissolving, diffusion of fluid through, or melting of, the capsule. U. S. Pat. No. 6,924,253 discloses release of encapsulated ionic liquids for scale removal in the wellbore or near wellbore region. Encapsulated chemicals for downhole or in-formation release for various treatments, for example gel breakers for hydraulic fracturing, are known; breaker release in the fracture after leaving the wellbore is activated by temperature or by crushing capsules during fracture closure. Capsules may also degrade in the wellbore or formation, or dissolve, or melt, or be ruptured by entrance of a fluid by osmosis. The methods of some of the presently disclosed examples may be used in conjunction with some of these methods. There are also downhole tools that can be controlled to release active chemicals. Some are integrated into the casing where transferring the internal fluid from the reservoir relies on the Venturi effect. Others are wireline or string conveyed apparatuses; release of chemicals is activated from the surface after positioning the apparatuses at the desired location.

It would be very useful to have a method of separating chemicals and/or physical materials from one another or from a main treatment fluid prior to a triggering event; it would be particularly useful if the method was simple, inexpensive, and easy to use and was not sensitive to the nature of the chemicals and/or physical materials. The present disclosure teaches a method of temporarily isolating a chemical (sometimes called a reagent) or chemicals (for example a breaker, a crosslinker, or a diversion agent that acts entirely or primarily by a chemical reaction) and/or one or more physical component(s) (for example fluid loss agents or proppants or diversion materials that act entirely or primarily physically) from a trigger or trigger mechanism (for example another chemical or a carrier fluid, for example an aqueous fluid) that causes or allows them to function by allowing direct contact and therefore interaction between the chemical or physical materials and, for example, the main treatment fluid or other chemicals or the formation, by immersing the reagent(s) and/or physical components directly in a "trigger-preventing fluid" (for example a phase immiscible with the phase containing the trigger) in fit- for-purpose surface equipment. In this description, the principal fluid being pumped into the well (for example a pad, a carrier fluid or slickwater fluid with proppant or gravel, in hydraulic fracturing or gravel packing, acid-based fluids, and chelating-agent-based fluids) is referred to as the "main" fluid; the small amount of fluid in which the chemicals(s) or physical material(s) are temporarily isolated is referred to as the "injection fluid"; the surface equipment in which the injection fluid is temporarily held is referred to as the "fit-for-purpose surface equipment" or the "injector"; and the main fluid either contains the trigger or is the trigger. The triggering event, for example, but not limited to mixing of miscible and immiscible fluids, dissolution of a container, a change in salinity, or a change in pH, causes reaction and/or allows direct contact of the one or more chemical or physical materials and thus interaction. Mixing of miscible and immiscible liquids refers to, for example (i) a process by which the main fluid displaces the injection fluid away from the reagent, and (ii) a process by which the interfaces between the immiscible phases are broken by mixing energy, resulting in emulsion and/or dispersion of the two phases, or (iii) any other process of physical or chemical interaction between miscible and immiscible fluids which results in substantial exposure of agents contained in one fluid to those contained in another fluid. Such processes result in at least partial contact between the reagent and the trigger. Direct contact is the contact required for the reagent and the trigger to interact chemically. Immersion of the reagent in the main fluid is an example of direct contact. One embodiment is the temporary isolation of the chemical or chemicals and/or one or more physical component(s), by placing them in a water-soluble container in a fit-for- purpose injector filled with a water-immiscible injection fluid (by non- limiting examples, mineral or vegetable oils, diesel or other hydrocarbons). After injection, the bullheaded injection fluid mixes with the main fluid, the container dissolves, and the contents come into direct contact with the main fluid and triggering occurs. In another embodiment, rather than using a container, the chemical or physical component(s) are dissolved or slurried directly in a fluid in the injector that is immiscible with the main fluid, or has a different salinity or pH from the main fluid, or contains a material that interacts with the main fluid to change a property of the main fluid, for example the pH or salinity. In either case, the trigger is water or is in water or is water-wet. It should be noted that in all cases where an embodiment is described for aqueous main fluids (with the chemical(s) or physical materials(s) (optionally in a container) in a non-aqueous immiscible injection fluid, the reverse may be used. That is, an embodiment may comprise the temporary isolation of an oil-soluble chemical or chemicals and/or one or more physical component(s) (optionally in a container), by placing the materials in a fit-for-purpose injector filled with an aqueous fluid (by non- limiting examples, fresh water or brine), wherein the trigger in the main oil fluid is the oil, or is in the oil or is oil-wet. Overall, the apparatus and method can be used in all well treatments relying on or benefitting from chemical downhole trigger(s) that allows direct contact and therefore interaction between the chemical or physical materials and, for example, the main treatment fluid or other chemicals or the formation. It should also be noted that in the above embodiments, the chemical or material considered the trigger may be in the injection fluid (or in a container in the fluid) and the reagent or physical component may be in the main fluid or in the wellbore or formation. Furthermore, the injection fluid, whether nor not containers are used, may contain fibers (for example PGA and/or PLA), flakes (for example benzoic acid), platelets (for example mica), that may or may not be the chemical or physical components. It should also be noted that the embodiments may be used more than once in a well treatment operation. For example, a first (main) fluid may be pumped into a well. Then a second (injection) fluid containing the physical and/or chemical component(s) to be added through the fit-for-purpose equipment may be injected, optionally in a container or containers, and then pumping of the first fluid may be resumed; optionally a third fluid may be substituted for the first fluid in the third step. This sequence may be repeated; the first fluid, the second fluid and its contents, and the optional third fluid need not be the same as in the first cycle. When a second fluid contains more than one physical or chemical component, they may have different triggers; if in another cycle, the "second" fluid differs from the previous "second" fluid it may respond to one or more additional triggers. Furthermore, when containers are used, a mixture of different containers may be used for selective delivery (for example of selected amounts) at specific locations (for example by different-solubility containers) and/or for selective delivery of different materials (for example in different- solubility containers) at different locations. In all embodiments using containers, the containers may vary in one or more of size, composition, or contents. Note that when a container is used the contents of the container may or may not undergo a triggered event in the wellbore or formation. When a container is used, a first triggering event is direct contact of the container shell with a substance that destroys the container sufficiently to release the contents and allows direct contact and therefore interaction between the chemical or physical materials and, for example, the main treatment fluid or other chemicals or the formation; an optional subsequent triggering event may or may not occur when the contents contact the main fluid, reservoir fluid, or the reservoir rock. That is, when a container is used, the container contents may optionally perform their function without a triggering event (other than the dissolution, destruction, or disintegration of the container). Containers may be designed to release their contents immediately upon contact of the injection fluid and the main fluid, of they may be designed to release their contents at a specified time later (for example 10 minutes or 20 minutes) or at a specified downhole temperature, or at some other delayed point.

When a container is used to separate the chemical or physical material(s) from the trigger(s), the container is partially or completely degradable, soluble, reactable, meltable or otherwise destroyable other than mechanically after it contacts the main fluid being pumped. Containers may be made of more than one component, at least one of which is destroyable other than mechanically, so that after destruction at least part of the container will be gone. In describing a container as at least partially destroyable or degradable we mean that at least 5 %, preferably at least 50 %, of the container is destroyable or degradable. Container (shell) destruction optionally may be initiated by penetration of the wellbore fluid into the container (as examples, a water-soluble enzyme breaker placed inside a container having a gelatin shell; citric acid placed inside a container having an acid-soluble or acid-destructible shell, for example one made of borate cross- linked guar or cellulose; or solids, for example NaOH, Ca(OH)₂, CaC0₃ or Mg(OH)₂ included in the contents of a polylactic acid shell). Optionally, the container may be destroyed sufficiently by at least partial dissolution (for example more than 5% of the shell being dissolved) in the surrounding fluid (for example a polyvinyl alcohol shell), or by weakening of the shell by partial dissolution in the surrounding fluid followed by or accompanied by mechanical destruction (for example a gelatin shell). Optionally, the "container" or shell may be a coating of another material that is put on by spray coating or polymerization and the like as is often meant in the literature when a material is described as "encapsulated". In the present examples, this coating is insoluble in the injection fluid but soluble in the main fluid. Dissolvable or reactable containers may be tested by measuring the time required for sufficient destruction of the shell by dissolution or reaction at conditions emulating the conditions during pumping (shear rate, temperature, pressure, etc.). The shell is considered to have been destroyed at the point at which, although the shell may not have been completely dissolved, degraded or destroyed, the mechanical integrity has been reduced significantly enough that the contents can be released. When a container is used to separate the chemical or physical material(s) from the trigger(s), if the chemical or physical material(s) are solids, they may be dried or slurried. The liquid in which the solids are slurried may be, for example, an aqueous liquid or a linear or crosslinked aqueous polymer solution. In one specific embodiment the solids may be slurried in situ in a wellbore fluid which reacts with or dissolves the container dowrihole but not in the injector in the time before injection. The liquid phase of the slurry may also be non-aqueous, for example an alcohol (as examples glycerol, ethanol, methanol, and isopropanol, ethylene glycol); and/or liquid hydrocarbons, for example diesel, hexane, or aromatic hydrocarbons, for example benzene, toluene etc. Delivery of acid or acid sources in such containers with subsequent acid release downhole provides surface equipment and some casing or wellbore wall protection during acid treatments. Other treatment agents may be delivered advantageously, for example bases such as sodium hydroxide.

Furthermore, using containers and fit-for-purpose injectors significantly simplifies wellsite delivery of container contents. Problems with existing methods of delivery based on using screw feeders or pumps include, but are not limited to, metering difficulties and plugging of equipment. Wellsite delivery of materials in injectable containers solves these problems, because such containers may be introduced into the main fluid with fit-for-purpose injectors or with the same techniques as commonly used for ball sealers. In many embodiments, chemical or physical material(s) are optionally vacuum packed into small volumes (to maximize the concentration) and surrounded by coatings or put into enclosures, for example shrink-wrapped or vacuum packed, that are optionally engineered to have various trigger times. Alternatively, an additive is used at various concentrations to interact with the coating or container at varying rates. In one specific example, where the container's principal purposes are wellsite delivery and metering, and it is not necessary to minimize dilution or separation of the contents as they travel downhole, such a shell or coating may optionally quickly be degraded or destroyed after introduction into the main fluid. Note that if a container is made of multiple layers, it is not considered destroyed until all of the layers have been destroyed to the point that the contents can be released.

The thickness of the container shell may range from about 0.01 mm to about 5 mm, preferably from about 0.05 mm to about 2 mm, and most preferably from about 0.1 mm to about 1 mm. Optionally, the container may be made with several layers, for example up to about 10 layers, that may be the same or different. Multiple layers increases the mechanical stability of the container and/or allows control of the dissolution time of the shell. In one embodiment, the physical material(s) or chemical(s) are placed into heat shrinkable plastic film (for example a polyvinyl alcohol film or fabric, embossed polyvinyl alcohol film, polyethylene film, other polyolefin films, PVC film, oriented films having at least one or two oriented layers, multilayer oriented films, shrinkable polyester films, for example those made of polylactic acid, polyglycolic acids or other polyesters or copolymers thereof, polysaccharide films, for example starch films or cellulose films, etc.), sealed in, heated to cause shrinkage to form a container, and if desired for greater strength the first container is placed into a second heat shrinkable film, sealed in, and heated to cause shrinkage to form a stronger container. Subsequent additional films may also be used, for example to enclose the first container formed. The films may be the same or different. Such film or films may optionally be selected to degrade at a desired rate. In another embodiment the material(s) or chemical(s) are placed into a hollow plastic ball that is initially in at least two components that are then sealed together. In one specific example these components are two half spheres. Optionally, the components may be made of a gelatin, for example from a mixture including water, a water-soluble polymer gelatin material that may include, for example, agar or processed seaweed, non toxic white glue, and the like, plasticizers, and a preserving additive, for example benzoic acid, that is formed and dried.

The container may be of any shape, but is preferably spherical or has an aspect ratio of less than about 3. An approximately spherical shape is advantageous because: (1) if the container is not approximately spherical and one dimension is significantly longer than the others, then the container may become trapped in surface lines or connections if it is not correctly oriented when it enters a connection or pipe; (2) surface handling of spheres is easier than surface handling of non-spherical shapes and the orientation when feeding the container into the well is not an issue; and (3) for spheres, the same equipment, calculations, and considerations established for ball sealers may be used. Those correlations do not apply if containers are not spherical. The exact dimensions depend upon the nature of the wellbore, surface equipment, and downhole equipment, but typically, the volume of the containers varies from about 0.5 cm (which corresponds to a sphere having a diameter of about 1 cm), to about 24 L (which corresponds to a cylinder having a diameter of about 17.5 cm and a length of about 100 cm). The preferred volume of the containers ranges from about 8 cm to about 2.8 L (which corresponds to spheres having diameters from about 2.5 cm to about 17.5 cm). The most preferred volume of the containers is in the range of from about 20 cm to about 1 L (which corresponds to spheres having diameters from about 5 cm to about 12.5 cm).

For containers that dissolve, melt, react, disintegrate, etc., the preferred time for this to occur is from about 1 second to about 1 hour, more preferably from about 10 seconds to about 30 minutes, and most preferably from about 1 minute to about 15 minutes, at a preferred temperature range of from about 1 °C to about 100 °C, more preferably from about 10 °C to about 50 °C, and most preferably from about 10 °C to about 30 °C.

The outer enclosure or shell (or bag or envelope, etc.) of the container, which may be rigid or flexible, is made of a material which may be chemically degradable, dissolvable or meltable. In one embodiment, the shell is degradable in, or soluble in, the wellbore or formation fluids. Examples of degradable materials which may be used for making the shell of the container are polyesters (including polylactic acid (PLA), polyglycolic acid (PGA), esters of lactic acid, glycolic acid, other hydroxyl acids, and copolymers thereof; polyamides and copolymers thereof; polyethers and copolymers thereof); polyurethanes, etc. Nonlimiting examples of degradable materials that may be used include certain polymer materials that are capable of generating acids upon degradation. These polymer materials may herein be referred to as "polymeric acid precursors," for example PLA and PGA. These materials are typically solids at room temperature. The polymeric acid precursor materials include the polymers and oligomers that hydrolyze or degrade in certain chemical environments under known and controllable conditions of temperature, time and pH to release organic acid molecules that may be referred to as "monomeric organic acids." As used herein, the expression "monomeric organic acid" or "monomeric acid" may also include dimeric acid or acid with a small number of linked monomer units that function similarly to monomer acids composed of only one monomer unit, in that they are fully in solution at room temperature. Polymer materials for making containers may include those polyesters obtained by polymerization of hydroxycarboxylic acids, for example the aliphatic or aromatic polyesters of lactic acid, referred to as polylactic acid; of glycolic acid, referred to as polyglycolic acid; of 3-hydroxbutyric acid, referred to as polyhydroxybutyrate; of 2-hydroxyvaleric acid, referred to as polyhydroxyvalerate; of epsilon caprolactone, referred to as polyepsilon caprolactone or polycaprolactone; the polyesters obtained by esterification of hydroxyl aminoacids, for example serine, threonine and tyrosine; and the copolymers obtained by mixtures of the monomers listed above. Additional examples of suitable degradable polymers include polyethylenes; polyhydroxyalkanoates, for example poly[R-3-hydroxybutyrate], poly[R-3- hydroxybutyrate-co-3 -hydroxy valerate], poly[R-3-hydroxybutyrate-co-4- hydroxyvalerate] and others; starch-based polymers; polyethylene terephthalate, polybutylene terephthalate, and other aliphatic-aromatic polyesters; and proteins, for example gelatins, wheat and maize glutens, cottonseed flours, whey proteins, myofibrillar proteins, caseins and others. Additional examples of suitable water-soluble polymers include polyvinyl alcohols; polyethylene oxides (polyethylene glycols); polyvinylpyrrolidones; polysaccharides, for example, starches, chitosans, guar gums, (for example hydroxyethyl guars, hydroxypropyl guars, and hydroxybutyl guars), celluloses (for example hydroxyethyl celluloses, carboxymethyl celluloses, and carboxymethyl hydroxyethyl celluloses), xanthan gums, carrageenans, popcorn polymers; polyacrylamides; polyvinylimidazoles; polymethacrylic acids; polyvinylpyridines; polyvinylamines; and others.

One method, that may be used for many embodiments, of manufacturing a water soluble skin containing another material is described in WO 1992/022355 which discloses making a water-soluble golf ball "comprising a core, said core, formed of a first water soluble material, and an external skin formed from two skin halves or semi-spheres, said skin formed of a second water soluble material, when the two skin halves or semi-spheres and core are adhered together with a water soluble non toxic adhesive..." The skin is made, for example, from paper pulp or from material selected from gelatin, agar, processed seaweed, and non toxic glue. Containers comprising various filling materials can be made by placing such materials into hollow objects or chambers, preferably of spherical shape. Methods of making hollow plastic spheres are disclosed in Japanese Patents 56021836, 57066920, and 61239936; and Japanese Patent Application 2005349678 also discloses a plastic ball containing a closed cell foam. U. S. Patent No. 7,395,646 discloses an article packaging device and a method for packing individual articles in a tubular thermoplastic sheet. U. S. Patent No. 7,306,093 describes a method and apparatus of packing materials, into a sealed package shaped like a bale. U. S. Patent No. 7,739,857 also discloses a method and apparatus for vacuum packing of materials into one or more bales and packages. Containers with various fillers can also be prepared for use in embodiments by surrounding portions of the fillers with a polymer or thermoplastic material. In some specific examples, shrinkable films or stretch films can be used. Shrinkable films and methods of making such films are disclosed in U. S. Patent Nos. 7,846,517 (polylactic acids), 6,340,532 (polyesters), 7,638,203 (polyesters), 7,744,806 (polyamides), and 6,340,532 (poly ethylenes). A method of shrink-wrapping a material into a shrinkable plastic film with sample holes is disclosed in U. S. Patent No. 7, 172,065. A process of preparing water-soluble containers is disclosed in U. S. Patent No. 6,898,921. The process comprises a) thermoforming a first poly(vinyl alcohol) film having a water content of less than 5% to produce a pocket; b) filling the pocket with a composition; c) placing a second film on the top of the pocket; and d) sealing the first film and the second film together. All these methods and devices may be adapted for use in many embodiments.

The chemical or physical materials injected into a well with the apparatus and method disclosed herein may be, but are not limited to: a proppant, for example sand, ceramic, or other particles understood in the art to at least partially hold open a fracture after a fracturing job is completed; a fluid loss agent, for example calcium carbonate particles or other fluid loss agents known in the art; a lost circulation control agent; breakers (for example polymer- or viscoelastic-surfactant system (VES) breakers), diverting agents, anti-oxidants, crosslinkers, corrosion inhibitors, delay agents, biocides, buffers, pH control agents, solid acids, solid acid precursors, organic scale inhibitors, inorganic scale inhibitors, demulsifying agents, paraffin inhibitors, corrosion inhibitors, gas hydrate inhibitors, asphaltene treating chemicals, foaming agents, surfactants, enzymes, water blocking agents, EOR enhancing agents, or the like. If the chemical component is in liquid form, it may be encapsulated or adsorbed of absorbed on or in porous media.

The wellbores treated can be completed with casing and perforations or open hole. Many embodiments further may provide for controlled or sustained release of chemicals in adequate abundance during well treatments (e.g., fracturing, matrix acidizing, and acid fracturing), gravel packs, tubular, and hydraulic fracturing services to ensure more uniform, continuous longer- term delivery of chemicals to inhibit materials impacting performance in formations, well-bores, and piping. Typical materials that impact performance are water, brine, completion fluids, organic scales (e.g., asphaltenes, waxes, paraffin, and gas hydrates) and inorganic scales (e.g., sulfates and/or carbonates of calcium, barium, strontium, and radium).

One objective of many embodiments is to delay direct contact of the chemical(s) or physical component(s) with the trigger or triggers until all chemicals and the trigger are in the wellbore so that the triggering event occurs in the wellbore. A secondary objective may optionally be to delay direct contact of the chemical or physical material(s) with surface equipment that could be affected or damaged by the chemical or material. A non-limiting example is to prevent early triggering of a reaction on the surface, before the chemicals are injected into a wellbore.

Examples of triggered reactions include but are not limited to:

• crosslinking a polymer or promoting formation of viscoelastic surfactant system (VES) micelles in fracturing treatments,

• delivery of a mixture of different sized solids to a downhole location (for example for diversion, in which case it may be desirable that the diverting material be partially or completely degradable, soluble, reactible, meltable or otherwise destroyable other than mechanically) while minimizing reaction of any of the solids with the carrier fluid or separation of the different sizes, • radically changing a property of the main fluid, for example by gelling or breaking or other reactions of components in the solid or in the liquid phase,

• radically changing the mobility of a high solids content fluid (HSCF) by precipitation, gelling or other reactions of components in the solid or in the continuous phase "second additional embodiment: below, and

• dissolving a water soluble chemical by direct contact with the aqueous phase used in a fracturing treatment, or conversely dissolving an oil soluble component by direct contact with the oil-based phase used in a treatment.

. In these examples, it is desirable to prevent the triggered reaction from occurring in the equipment on the surface. Examples of triggers include oil, water, hydrate, hydrogen sulfide, carbon dioxide, acid, base, and changes in concentration gradient, for example changes in salinity.

Many embodiments are particularly well suited to the addition of high solids contents fluids to fluids being injected into a well, as described in U. S. Patent No. 7,833,947, hereby incorporated in its entirety. A non-limiting example of the teachings of that patent is a method of delivering a first chemical component to a subterranean formation in a wellbore comprising: providing a fluid comprising a carrier fluid and at least two different sizes of solid particulate materials selected from a group consisting of: very large particles, large particles, medium particles, fine particles, very fine particles and ultrafme particles; wherein the packed volume fraction of the two sizes of solid particulate materials exceeds 0.80, and wherein a first type of solid particulate materials contains the first chemical component able to be released by a first downhole trigger and a second type of solid particulate materials contains the first chemical component or a second chemical component able to be released by a second downhole trigger; pumping the fluid into the wellbore; and allowing the first chemical component to be released by the first downhole trigger. Embodiments may be used with all the combinations and permutations of the above example disclosed in U. S. Patent No. 7,833,947, as well as with any of the mixtures of particle sizes disclosed for various downhole uses in the literature, for example those described in U. S. Patent Application Publication No. 2009/0025934, and U. S. Patent Nos. 7,784,541, and 7,004,255. Many embodiments described herein take advantage of the interaction of high solids content fluids with the main fluid or with a trigger in the wellbore during pumping rather than after the high solids content fluid has been delivered and placed, for example at bottomhole or in the formation.

Examples involving loading the injector with a high solids content fluid in a trigger-preventing fluid include, but are not limited to, the following:

• The first chemical component is a granulated crosslinker (for example a borate-based crosslinker), to be released by contact with water at the proper pH. The second chemical component is a crosslinkable polymer. The crosslinkable polymer is in solid granulated form and must be hydrated at the proper pH before crosslinking. If the injection fluid is aqueous, it is at a pH at which the crosslinker is not soluble and/or the polymer is not hydratable. Optionally, either the crosslinker may already be dissolved in the main fluid or the polymer may already be a solvated linear polymer in the main fluid, but not both. In this embodiment, the water in the main fluid having the proper pH for forming a crosslinked hydrated polymer is the chemical trigger. A high solids content fluid (HSCF) containing the solid crosslinker and/or the solid polymer in a liquid phase immiscible with water or at a pH at which the solid crosslinker is insoluble and/or the solid polymer is not hydratable is loaded into a fit-for-purpose injector and injected as desired. The triggered formation of a hydrated crosslinked polymer greatly increases the viscosity of the fluid containing the high solids content and the desired result is that the mobility of the fluid is greatly reduced.

The HSCF is a multimodal mixture, in which the particle size distribution has been optimized to minimize the void between particles. Many particle size selections may be made, as discussed above, but a typical particle size distribution, that can be used in any of the examples here, is the following:

For each lOOg of solid phase:

• Large particles: (mean diameter 616 microns), 61g.

• Medium particles: 100 mesh (mean diameter 101 microns), 19g.

• Small particles: (mean diameter 8.0 microns, 20g.

The same material may be used for all sizes in the mixture, for example sand or ceramic beads as proppants, plugs, or diverting agents, or two or three different materials may be used for the three sizes. The reagent (the first and/or se cond chemical component above), which upon triggering will cause the loss of mobility may replace or be a portion of one of the solid particles above, or may be another solid. If it is another solid, the size of the reagent does not have to be optimized if the reagent is at a concentration low enough that it does not affect the packed volume fraction and solid volume fraction significantly. If the loss of mobility is triggered by hydration of the polymer gel, the solid mixture may occupy up to 80% of the injector by volume. The liquid therefore occupies 20% of the volume. To generate the required viscosity increase of the carrier fluid after triggering, for example to above about 150 cP at 511 sec^"1, only 1.25% by weight of carboxymethyl hydroxypropyl guar (CMHPG) in the water is required. Even in the extreme case where the particles and the water are of the same density, the CMHPG is only about 0.2% by weight of the whole HSCF. This does not affect the HSCF packed and solid volume fractions, and so does not affect the mobility, even if the polymer particles do not match the large, medium, or small particle sizes exactly. When the loss of mobility of the HSCF slurry is triggered by crosslinking of the gel, only lg of solid crosslinker per liter of liquid phase is required. In practice, the addition of lg/L to the blend described above does not affect the mobility, the particle volume fraction, or the solid volume fraction before crosslinking, so the blend is still an HSCF fluid, even if some crosslinker grains do not have the exact size of the large, medium or fine particles.

• The first chemical component is an acid soluble particulate (for example CaC0₃). In this embodiment, an acid, for example HC1, is the chemical trigger. A high solids content fluid containing the CaC0₃ in a liquid phase immiscible with diluted HC1 (the main treatment fluid) is. loaded into a fit-for-purpose injector and injected as desired.

• The first chemical component is an acid-soluble particulate (for example CaC0₃). In this embodiment, a viscoelastic acid (which increases in viscosity when the pH is increased), for example a viscoelastic diverting acid (VDA) is the chemical trigger. (The VDA is, for example, a blend of a suitable viscoelastic surfactant (VES) and a suitable concentration of HCl). A high solids content fluid containing the CaC0₃ is loaded into a fit-for-purpose injector in a liquid phase immiscible with diluted HCl. Once the trigger (VDA) and the chemical component (CaC03) are in contact in the wellbore, the reaction increases the pH and as a result, the mobility of the high solids content fluid is radically decreased.

Experiments have shown that the bulk mobility may be decreased by a factor 10 or more (as characterized by the differential pressure required to move a slurry along a rough 1.27 cm (0.5 inch) pipe). The exact factor depends upon the composition of the carrier fluid, including the surfactant concentration and the initial acid concentration. A VDA- triggered immobilization of an HSCF may be used for diversion in carbonates. As an example, a low-viscosity HSCF is normally squeezed into wormholes and/or natural fractures, and upon reaction with carbonates loses mobility rapidly. However, when CaC0₃ is incorporated in the HSCF, the mobility of the mixture is reduced before it contacts the formation, or without contacting the formation. Thus an injector that can provide a pill of VDA-triggered immobilized HSCF may be used for contingency planning (as examples a) when a bridge plug is leaking and requires a cement plug or b) when a reinforced sand plug is needed for zonal isolation. The delay in the loss of mobility may not need to be long; the reaction may occur as soon as the whole mixture is in the wellbore, and the reagents and trigger are in contact. For cases where the trigger must occur at a significant depth, mixing of the injector and main fluids may not provide enough delay, even if they are immiscible. Examples of treatments that may require a long delay include (i) squeezing the slurry into a fracture prior to immobilization, or (ii) using the blend as a 'VDA' for sandstone. Some additional delay may be provided, for example, by increasing the viscosity of the fluid, by increasing the particle size of the CaC0₃ or by using CaMg(C0₃)₂ instead of CaC0₃, (because CaMg(C0₃)2 reacts more slowly than CaC0₃ at temperatures below about 200 °F (93 °C)). Laminar flow may help delay the mixing, but it is difficult to control the exact location of the onset of reaction. A more robust solution is to prevent interface mixing between the main fluid and the injection fluid during the transport downhole. This can be done using a mechanical displacer, for example a wiper ball, which keeps the two fluids isolated until after the injection fluid has been squeezed into the formation.

The injection fluid containing one or more chemical reagents or physical materials, optionally in containers, may be introduced into a wellbore and pumped down to a target zone in a variety of ways. For introducing containers into the fluid for dissolution, destruction or disintegration in the wellbore, a standard or modified flow injector, for example those used for ball sealers, may be placed in the high pressure line. Such devices are typically used for injection of large containers (greater than about 10 mm in diameter) and the injector is commonly installed after the pumping units so the containers are not subjected to forces that would break them in the surface equipment. A representative schematic is shown in Figure 1. Injection fluid containing the chemical and/or physical component(s) that will later be triggered, optionally with the component(s) in containers, is loaded through a plug valve [1] into the accumulator [2], which is isolated from the main pumping (treating) line [3] by two closed remotely operated valves [4]. The broad arrow shows the direction of the main fluid flow. The accumulator is filled during the loading with a trigger-preventing injection fluid, for example an injection fluid which is immiscible with the liquid phase of the main fluid that contains or is the chemical trigger. In the most common case, in which the chemical trigger is or is carried in an aqueous liquid, the immiscible fluid can be (but is not limited to) ethylene glycol, glycerin, kerosene, diesel, mineral oil or vegetable oil. Vegetable oil includes but is not limited to canola oil, palm oil, peanut oil, sunflower oil, walnut oil. (Note that the same technique can be used to increase the concentration of containers, if present, in the accumulator as is used to increase the concentration of particles in a fluid: for example, use a mixture of a first size of destructible containers, and a second size of from about 7 to about 10 times smaller than the first, optionally a third size of from about 7 to about 10 times smaller than the second, and optionally additional sizes.) Then the accumulator loader is closed until the well treatment requires injection of the chemical and/or physical component(s) into the wellbore, the valves are then opened, and the injection fluid and optional containers are flushed from the accumulator into the high pressure line by the main fluid which contains the chemical trigger and the mixture is transported past the wellhead and into the wellbore before the onset of triggering caused by the mixing of the main fluid and the injection fluid, for example miscible and immiscible liquids, and thus direct contact and therefore interaction between the chemical or physical materials and, for example, the main treatment fluid or other chemicals or the formation.

An alternative design is shown schematically in Figure 2, which shows a different arrangement of the plug valve [1], accumulator [2], main pumping (treating) line [3] and two closed remotely operated valves [4]. The broad arrows show the direction of the main fluid flow. Figure 2 shows that there may be a section or sections of the apparatus having several changes in direction, possibly, although not likely, including some sharp angles (Figure 1 was more simplistic). Such angles are designed to make the parts of the injector more flexible in order to provide higher stability to vibration. Typically it is advantageous to avoid rigidity in high pressure lines because vibration of massive rigid pieces may be a cause of failure. If injectors are built on site with existing iron, then containers, if used, must be designed and manufactured to resist impacts at the angles. The volume of the injector may be in the range of about 1 to 1000 L; preferably between about 1 and 100 L; and most preferably between about 1 and 50 L. The number of containers loaded into one injector depends upon the size of the containers used. The number of containers may be from 1 to about 10,000; preferably from 1 to about 1 ,000 and most preferably from about 10 to about 250. The total amount of material in the immiscible phase is defined by the total volume of the containers and may vary in the range of from about 1 to 1000 L, preferably between about 1 and 100 L; and most preferably between about 1 and about 50 L.

In all embodiments not using containers, the injector may optionally be loaded manually, by pouring the injection fluid into the injector and then placing the reagent in the injector. In some embodiments, the reagent and trigger-preventing fluid may be premixed in a batch tank and then pumped to the injector. This requires disconnecting the injector from the treating line and connecting it to the outlet of a batch mixer, or to the outlet of pump which displaces the content of the batch mixer into the injector. Once the slurry is in the injector, then the valves are closed. The injector is then similar to a closed container that is then connected to the treatment lines. In practice, it is generally preferable to load the injector at the wellsite, but the injector may be loaded prior to moving to the wellsite. The injector can then serve as a storage container that is subsequently connected to the treatment lines.

Whether or not containers are used, several injectors may be connected in parallel. In some situations, each injector may contain the same slurry or containers. This setup may be useful in multistage treatments, where the well is divided into sections that are treated individually (for example in multistage fracturing). Then, one injector can be used in each stage. In other situations, the injectors can vary in volume (for example from smaller to larger injectors) or in the number of containers (for example from fewer to more). This is useful when the formation properties are unknown and the injection of the active component may have to be done with a trial and error approach. An example is when the fracture size from which diversion is needed is unknown, and a design can consist of pumping pills that are of larger and larger volumes until the fracture is plugged. Finally, another embodiment is to connect injectors with different contents for treatments where several actions may be needed. One example is a fracturing treatment in which a fiber-based diversion is needed at one time, and then a consolidated sand plug is needed at another time. In general, there may be situations in which an operator may set up a system of multiple injectors and then might or might not use it. For example the injectors might contain a fluid loss agent, or a lost circulation agent, or a diverting agent, etc., that might or might not be used in a job. Or, there might be several different sets of containers on site that contain different materials (for example different sizes of particles or different strengths of chemicals, or different melting points of materials, etc.) and several different trigger-preventing fluids (for example of differing pH or salinity) and the operator may decide during the job which materials to use and load them into one or more injectors.

One advantage in all embodiments is that there is no contact between reagents, and therefore no triggering, until it is needed. This may be particularly useful when unplanned events occur at the wellsite, which can slow or temporarily halt operations and may lead to unwanted reactions at the surface when other methods, for example batch mixing of all chemicals, including delaying agents, are used.

For practical purposes, an injector about 5-10 m (about 15-30 ft) long and about 7.5-10 cm (about 3-4 in) inside diameter is preferred, although the sizes are solely a function of the space and tubing available. In a multistage diversion treatment, each injector should contain the amount of material (optionally in containers) needed per stage. As an example, about 100-200 containers per stage might be used, in which case each injector should contain about 100-200 containers.

Normally, there is little or no risk in overestimating the amount of reagent to be used. It is much more important to ensure that the threshold amount required to trigger a downhole reaction is at least employed, and preferably is exceeded. Yet another method available for injection of fluid, especially when the chemical or physical component(s) are in containers, for example balls, is a ball-injector, as shown schematically in Figures 3 A and 3B. In these embodiments, the balls [6] are injected into the main fracturing line [8] above the wellhead [10]. Not shown is a pump attached to a pressure line [12] for positive displacement of the containers. A valve [14] may be used to keep the balls in place until injection. The main difference is that Figures 1 and 2 depict an injector installed on a frac line (the line going from the missile to the wellhead), while Figures 3A and 3B depict equipment that is fitted onto the wellhead. With an injector on the frac line, the advantage is that the operator never has to attach equipment to the wellhead or approach the wellhead for reloading, which is potentially dangerous and difficult and may require a lift. However, if the injector is in the frac line (as in Figures 1 and 2), there may be increased contact between the chemical or physical component(s) and the main fluid that occurs while the injector fluid and its contents are travelling from the injector to the wellhead. In the case of a dissolvable container, one obvious risk is that the container may break in a chiksan (swivel joint or flexible coupling) or sharp angle, and then contact between the container contents and the trigger could occur before the container is effectively in the wellbore. Proper selection or assembly of the injector depends upon the situation at each job.

Note that it is possible to use an injector, for example those of Figures 1 or 2 (with or without containers), or a ball injector without containers, fitted directly onto the wellhead. In that case, the injector has an accumulator that is loaded with the chemical or chemicals and/or one or more physical components and the trigger-preventing injection fluid. On one side, the accumulator has a valve that connects to but can isolate the injector from the wellbore. On the other side, the accumulator is connected to a line that goes to a separate pressure pump that can positively displace the chemical or chemicals and/or one or more physical components and the trigger-preventing injection fluid into the wellbore. In the normal course of the treatment, the accumulator is bypassed. At the time when the reagent must be injected, the appropriate valve is opened, and the contents are displaced into the wellbore.

Additional embodiments follow:

A first additional embodiment is based on the observation that during the development of fiber-based diversion, for example the StimMORE™ service available from Schlumberger, it was found that the viscosity and the type of fluid system played a critical role in the efficiency of fiber bridging in a hydraulic fracture. In the case of a mixture of a quaternary ammonium compound and an alkylaryl sulfonate (such a mixture is a VES (viscoelastic surfactant) based fluid system), a decrease of viscosity by 10 cP (0.01 Pa^'s) results in 50% less of the fiber being required for effective bridging of a 2 mm wide fracture. For a borate-crosslinked guar fluid, a viscosity reduction from 100 cP (0.1 Pa s) to 20 cP (0.02 Pa^'s) resulted in the fiber loading required decreasing from 9 g/L (75 ppt) to 3 g/L (25 ppt) (ppt is "pounds per thousand" gallons).

Patent Application PCT/RU2010/000667 by Fu et al entitled "METHOD TO ENHANCE FIBER BRIDGING," filed on Nov. 12, 2010, described the use of this effect to promote fiber bridging in a variety of treatments, with a variety of systems. Examples were provided in that patent -application, where a) a main fluid (for example a VES, or crosslinked polysaccharide) containing fibers b) a reagent (for example acids, bases, salts, surfactants, enzymes, oxidizing agents, polyelectrolyte polymers, organic solvents, mutual solvents, surfactants, alcohols, precursors thereof, and mixtures thereof), and c) triggering mechanisms (reactions causing viscosity reduction, depending upon choices of a) and b)) were described. Ranges of fiber compositions and dimensions were also given (for example PLA fibers, basalt fibers, soy bean fibers, PGA fibers, PET fibers, PVA fibers, glass fibers, polyester fibers, and combinations thereof, having a diameter of between 1 and 1000 microns and a length between 2 and 25 mm.) There was no mention of a surface injector containing some components and a trigger- preventing fluid.

The apparatus and method of the present application may be used by isolating the reagent in an immiscible phase (for example oil, diesel oil or ethylene glycol) in the injector. The merit of using such a system is that the fiber slurry is well dispersed and non-bridging on the surface until contact with the reagent is made after injection. Consequently, there will not be unwanted bridging in surface lines. As a more specific example, such a system may be used for zonal isolation or diversion for well treatments with fibers bridging and stopping fluid loss during workover operations, and for diversion with fiber bridges in fractures in fracturing treatments. An example of a fiber based main fluid slurry may have 7.2 g/L (60 lbm/1000 US gal (ppt)) of PLA fibers having dimensions of 6 mm by 12 μπι dispersed in an aqueous fluid containing 2.4 g/L (20 ppt) uncrosslinked guar. The reagent may be ammonium persulfate, (NH₄)₂S₂0_8, in an amount such that the final pill contains at least 0.18 g/L. The trigger-preventing injection fluid may be canola oil. The triggering mechanism is fiber flocculation caused by the decrease of viscosity resulting from the reaction between the guar and the breaker.

A second additional embodiment is described in more detail in a Patent Application entitled "WELL TREATMENT WITH HIGH SOLIDS CONTENT FLUIDS" by Potapenko, Nesterova, Lecerf, Ivanov, Fu, Bulova. filed on the same day as, and assigned to the same assignee as, this application. It is another example of zonal isolation, using a High Solid Content Fluid (HSCF) as a plugging agent. The triggering mechanism is an increase of viscosity of the carrier fluid, which results in a drastic increase of the bulk mobility of the HSCF. Several systems can be used to increase the viscosity of the carrier fluid. For example, one can rely on the hydration properties of certain biopolymers (for example guar derivatives). These biopolymers each require a specific pH range to hydrate. Outside of that pH range, hydration is either very slow or does not proceed at all. In the case of guar gum derivatives, the pH dependence of the hydration rate can be attributed to the specific manufacturing process. One of the stages of the manufacturing process includes mild crosslinking of guar splits with borates. The crosslinking reaction occurs at a basic pH (usually higher than 9) and the resulting polymer has basic properties. Borate crosslinks that remain stable at a pH above 9 hold the guar molecules together, preventing water molecules from penetrating inside the polymer grains and thus slowing down the hydration. Once the crosslinks have been chemically removed by decreasing the pH, the polymer molecules unwrap and hydration occurs instantaneously, resulting in swelling of the polymer grains and a dramatic viscosity increase. A more specific example of the pH dependence of hydration is one in which experiments have shown that a suspension of 1.25 % (by weight) CMHPG in water does not hydrate and therefore develop any viscosity at pH's of 10.5, 1 1.0, and 1 1.6. However, once the pH is reduced to 7.7 with a few drops of HC1, the hydration occurs instantaneously, resulting in a sharp viscosity increase of the gel. Other processes to increase the viscosity can be used (for example crosslinking a polymer gel, or changing the pH of a .VES system).

Drastically changing the mobility of an HSCF can be used for zonal isolation. Such a process requires the change in viscosity to occur when the HSCF is in the formation. The methods described above for retarding and controlling a delay may be used for the HSCF drop in mobility. If they are inadequate, other delaying agents may also be used so that the reaction leading to a change in viscosity is further delayed after contact between the chemicals occurs. Examples of delaying agents are well known to those skilled in the art and include saccharides, polysaccharides, and polyols for delaying crosslinking with borate; pH adjusters for delaying crosslinking with zirconium, and others. Forming slowly reacting complexes to control the crosslinking rate is commonly used with borate ions to minimize friction pressure. Slowly dissolving crosslinkers and activators can also be used to delay crosslinking. Some borate compounds, such as colemanite and ulexite, dissolve slowly in water, producing a controllable crosslinking rate and delaying viscosity development. In addition, slowly dissolving acids or bases can be used to delay the crosslinking rate of pH dependent crosslinkers. The pH of the fluid containing the desired concentration of crosslinker is initially at a value that does not initiate significant crosslinking. The pH adjuster (base or acid or source of base or acid) dissolves at a controlled rate, producing the desired pH change and initating crosslinking. In one embodiment, this method can be used to control the crosslinking rate of borate ions by using a rapidly-dissolving borate compound such as boric acid and a slowly- dissolving base, such as CaO or MgO. In one particular embodiment, pH buffers maybe used as delaying agents for the systems for which activation is determined by pH level. Examples of such systems include a caroboxypolymer solution such as alginate mixed with a slowly hydrolyzing lactone and CaC0₃. Here, crosslinking of alginate by Ca can be delayed by sodium carbonate which, until neutralization, will keep the pH at a level insufficient for generating Ca ions. Without the use of additional delaying agents, many of the present embodiments may be used to generate cementlike plugs in the wellbore; this is useful for consolidated sand plugs, which should perform better than conventional sand plugs in horizontal wells. It may also allow building a plug without having it form on the bottom of the well. Finally, the availability of such a solidified HSCF mixture can also be used as a contingency remediation plan for leaking in-wellbore isolation situations (for example building an HSCF plug on a leaking bridge plug). An experiment was run in which crosslinker was added to the carrier fluid of an HSCF (see Table 1 below). As the table shows, a change in viscosity of the carrier fluid radically reduces the mobility of the entire mixture. Results are not reported in viscosity units, but reported as the differential pressure required to move the mixture at a rate of 10 ml/min in a pipe having an ID of 10 mm. The delayed crosslinker system was a borate solution prepared by dissolving 6 g of H₃BO₃, 10 g of NaOH and 18 g of sodium gluconate in 70 ml of water; 1 ml of this crosslinker was added per 20 ml of carrier fluid in the HSCF (High Solids Content Fluid). N High solid content fluid Plug

stability limit

Solid phase Carrier fluid

(low viscosity)

1 100% by ~55kPa

volume: (8psi)

1.8% guar

solution in DI

water

2 15% by volume 85% by -76 kPa (l l

For each 100 g of solid phase: volume psi)

20/40 sand (mean diameter 616 1.6% guar

microns, SG 2.65) 93.7g solution in DI

PLA fibers (SG 1.25, length 6 mm, water

diameter 14 microns) 6.3g

3 60% by volume 40% by >1034kPa

For each 100 g of solid phase: volume: (150 psi)

20/40 sand (mean diameter 616 microns, 1.2% guar

SG 2.65) 61g solution in DI

100 mesh sand (mean diameter 101 water

microns, SG 2.65) 19g

CaC0₃ (mean diameter 8.0 microns, SG

2.7) 20g

Table 1

As two more specific examples of how this may be used for zonal isolation by immobilization of an HSCF: In one embodiment, the main fluid is water (that may contain other components including a viscosifier) at an acidic pH or the HSCF containing the solids distribution of the last row of Table 1 (except that all three sizes are sand) at an acidic pH, and an injector at the surface is loaded with a slurry made with an HSCF made with the solids of the last row of Table 1 and 1.25 wt % of a suspension of CMHPG in water having a pH of about 12 (in which the CMHPG is not hydrated). Optionally, an HSCF in the injector may also be all sand, or, if the main fluid is an HSCF, the injector need not contain an HSCF fluid, but rather another fluid containing CMHPG in water having a pH of about 12. When zonal isolation is required, mixing of the injector contents and the main fluid results in a pH decrease that causes fast hydration of the gel and a quick loss of mobility. In another embodiment, the main fluid is water or an HSCF, in which all three sizes of the solid are sand, that may contain other components including a viscosifier, at an acidic pH, and the injector at the surface is loaded with a slurry made with an HSCF made with the solids of the last row of Table 1 in water having a pH of about 12. When the two fluids mix, there is a drop in pH that causes a loss in mobility of the HSCF in the injector, that results from dissolution of the fine component (CaC0₃) of the HSCF fluid.

In a third additional embodiment, the well treatment is fracture cleanup. The triggering event is exposure of PLA or a lactic acid copolymer to a high pH fluid (for example at a pH greater than about 8), which causes hydrolysis to be drastically accelerated. In this embodiment, the main fluid is a fracturing fluid at a high pH. The reagent (lactic acid) is stored in a polymerized form in the injection fluid at a pH, for example, of 1.5. At that pH, the hydrolysis of PLA is "frozen", or significantly reduced by at least a factor of 6. When the injection fluid and the main fluid mix, the pH is drastically increased and the hydrolysis is accelerated. The hydrolysis of the PLA releases lactic acid which helps clean out the fracture. Under these conditions, triggering will be fast after the mixing. A delay may be introduced by increasing the viscosity of the injection fluid, by using a less soluble lactic acid or lactic acid copolymer (or one with less surface area/unit volume), or by pumping a spacer between the fluids. Laboratory experiments have shown that at 79 °C a 4.8 g/L (40 ppt) suspension of PLA fiber SG 1.25, length 6 mm, diameter 12 microns in water is less than about 25% degraded in water at a pH of about 1.5 after a week but is completely degraded in about 3 days in water at a pH of about 9.3.

A fourth additional embodiment is an example of temporary zonal isolation or fluid diversion with fibers that bridge, followed by removal of the fiber bridge by injection of a reagent. The main fluid is a fiber-based slurry, for example a 7.2 kg/m³ (60 lbm/1000 US gal) slurry of PLA fibers having dimensions of 6 mm by 12 μηι dispersed in an aqueous fluid containing 0.6 g/L (40 ppt) guar. The reagent is a strong base, for example sodium hydroxide, which significantly accelerates the dissolution of polyesters, for example polylactic acid. The trigger-preventing (in this case immiscible) fluid is a viscous paraffin (preferably very viscous, like wax) that coats the NaOH, which is present in the injection fluid as solid grains. The triggering mechanism for the removal of the temporary bridge is the drastic acceleration of PLA hydrolysis by a pH increase caused by the dissolution of the NaOH. The quantity of NaOH is adjusted such that the pH of the final fluid exceeds 9. Laboratory experiments like those of the third additional embodiment above have shown that fibers at 79 °C dissolve about 6 times faster at a pH of about 9 than at a pH of about 7. Another application of this embodiment is the use of NaOH particles in a viscous paraffin, in balls that are larger than the perforations in a well. The balls can be pumped at the tail of a fiber plug during a fracturing treatment. The paraffin-coated NaOH particles being in balls larger than the perforations, they are not transported into the fracture but are screened out in the wellbore, where they can accelerate the degradation of fibers that may accidentally be left behind after a fiber-assisted treatment.

A fifth additional embodiment is zonal isolation or diversion using swellable particles as the plugging agent. In one example, swellable particles are the reagent placed in the injector. The immiscible fluid is selected to prevent the particles from swelling prematurely; it may be an organic fluid (for example, oil), but in practice it will be easier to use water with a fine- tuned salinity (for example, 1% KC1 + 2% CaCl₂). The main fluid is a treatment fluid having a salinity such that the particles will swell when immersed in it (for example 3% KC1). The triggering mechanism is the initiation of swelling of the particles. Ideally, particles should swell only after being squeezed into the fracture (in practice, onset of swelling can start before the particles are in the formation, but the residual swelling in the wellbore should be minimized).

Alginate/calcium beads were made in the laboratory by adding drops of sodium alginate solution to a solution of calcium chloride (for example a 2% solution of sodium alginate added to 1 L of a 1% CaCl₂ solution). Drying of the beads formed (that had diameters of about 3 to 5 mm) overnight gave solid particles with a significantly smaller size (about ½ to 2 mm). Those particles were swellable, as demonstrated by adding the particles to deionized water, which yielded beads of about 3 to 7 mm diameter.

The swelled complexes of alginate with calcium obtained had significant rigidity, so such complexes could be used for fracture sealing. However, the rigidity of alginate/calcium complexes may be negatively impacted by agents which are able to displace calcium ions from the carboxylic groups of the alginate, for example monovalent ions, chelating agents, boric acid, dicarboxylic acids, and others. Figure 4 shows the swelling dependencies of alginate/calcium particles in water in the presence of sodium, potassium and calcium ions. Alginate/calcium particles were prepared by mixing 1 L of a 2% solution of sodium alginate with 1 L of 1% CaCl₂ solution. Then the mixture was left for 24 hours at room temperature and the solid precipitate obtained was washed with deionized water and dried at 50 °C for another 24 hours. The solid mass obtained was then ground and the 20/40 fraction was isolated. Potassium and sodium ions significantly enhanced the swelling of alginate/calcium particles. Not meaning to be bound by theory, but it is believed that the replacement of Ca ions with monovalent ions in alginate networks decreases the effective calcium content in the complexes and therefore increases their ability to swell. Note that increasing the concentration of potassium and sodium chlorides above 1% in the experiments performed did not result in dramatically additional swelling of the alginate/calcium particles.

Adding calcium chloride to solutions of salts of monovalent ions allows reduction of the impact of such salts on the swelling, as shown in Figure 5. Note that alginate/calcium complexes in this situation did not lose rigidity, in contrast to the experiments performed using solutions of salts of monovalent ions without calcium. These two observations allow control of the swelling properties of alginate/calcium particles in fluids with wide ranges of compositions. For example, adding a mixture of calcium and potassium chlorides, in significant concentration, to a solution of potassium chloride made swelling of alginate/calcium complexes insensitive to the initial concentration of KC1 in the solution; 1% CaCl₂ prevented swelling in a 3% KC1 solution, while in 3% KC1 alone, calcium/alginate particles swelled dramatically. Increasing the concentration of potassium chloride from 1 % to 3% in a mixture of KCl having from 0.1 to 1% of CaCl₂ makes swelling of alginate/calcium complexes less sensitive to the initial concentration of KCl in the solution (as shown in Figure 5).

An example of the use of this fifth additional embodiment is in zonal isolation or in diversion. The main fluid is a 3% KCl brine; the reagent is dried alginate beads crosslinked with CaCl_2, or a dried crosslinked polysaccharide (for example guar, hydroxypropyl guar (HPG), or scleroglucan) and is added at a concentration of 480 g to 1 L of fluid (4 ppa) (ppa is "pounds proppant added" or pounds of proppant per gallon of slurry). The trigger-preventing fluid is a brine comprising 1% KCl with 1% CaCl₂ to avoid swelling. Triggering causes absorption of water to swell the beads once they are exposed to the 3% KCl brine, providing zonal isolation or diversion.

A sixth additional embodiment is a sandstone acidizing treatment in which the main fluid is 9% HC1 and the reagent is NH₄HF₂. The solid reagent salt is initially suspended in water in the injector, but isolated from the water by a container, for example by being agglomerated inside a PVOH or biostarch solid matrix, or held inside a container made from a PVOH film or a biostarch film. The triggering mechanism is the dissociation of the NH₄HF₂ into NH₄OH and HF once the reagent is freed from the container, after injection, and allowed to dissolve in the main fluid. The amount of reagent is calculated so that the final fluid downhole is, for example, a 9/1 mud acid (which is 9 wt% HC1 and 1 wt% F£F) which can dissolve aluminosilicates in the sandstone.

A seventh additional embodiment is triggering by dilution of the trigger-preventing fluid by the main fluid. For example, the trigger- preventing fluid can be a viscoelastic diverting acid system (VDA) formulated with 15% by weight of HCl and 7.5% by weight of a viscoelastic agent (containing a betaine surfactant having an erucic acid amide group (including a C2₁H₄] alkene tail group) at a concentration of approximately 40% active ingredient, with the remainder being substantially water, sodium chloride, and isopropanol). The main fluid is the same concentration of the VDA system, but in 7.5 weight % HCL. In 15% HCl, the surfactant molecules are arranged in irregularly shaped micelles, in which the heads of the surfactant molecule are oriented towards the surface of the micelle, and the tails point towards the center. These micelles do not have "structure" to build viscosity. When the two fluid streams mix, the HCl is effectively diluted, but the VDA system is not. This decrease in acid concentration is responsible for the viscosity buildup, because it causes the irregularly-shaped micelles to grow by adding other surfactant molecules to form rod- or worm-like micelles. These rod- or worm-like micelles then tangle up to form a "spaghetti-like" mass that is responsible for the viscosity increase. For example, the viscosity measured at 10^sec"' increases from 500 cP to 2000 cP when the HCl concentration drops from 15% to 7.5% in a 7.5% solution of the VDA system. The viscosity build-up can be more dramatic at other mixing ratios.

When the trigger-preventing fluid is corrosive, such as the 15% HCl in the seventh additional embodiment above, protection of the injector from corrosion is recommended. This can be done by using a metal which is resistant to corrosion (for example, a chromium-rich steel alloy), by using a layer of protective film (for example TEFLON™ film), or by using a corrosion inhibitor in the small volume of the injector. If the cost of the use and reuse of a corrosion-resistant material is prohibitive, the injector can be made of unprotected steel and can be disposed of after the treatment.

In the seventh additional embodiment above, the dilution is selective to one component (HC1) while leaving the concentration of another component (the VDA system) unchanged. Other embodiments include non selective dilution. Dilution in water of systems such as surfactants and water-oil- water emulsions causes viscosity increases, which can be used for immobilization of HSCF's as described earlier. Some surfactants, for example sodium laureth sulphate (SLES) show a drastic viscosity increase when diluted from a 70% solution by weight to a 45% solution by weight.

In an eighth additional embodiment, an enzyme may be maintained in an inactive form on the surface, by immersing it in a suitable trigger- preventing fluid (in this case a fluid having a pH of 10 or above) in an injector. The enzyme can then be rendered active by mixing the injection fluid with a main treatment fluid having a pH of 5 or below. US6818594B1 discloses enzymes which are encapsulated in pH responsive materials. Example 1 of US6818594B1 describes an encapsulated starch-degrading enzyme (amylase A) that is inactive at pH 10 and higher but releases active enzyme at pH 8 and lower. The pH-responsive enzyme can be used to break fracturing fluid viscosified with starch at a low-pH (the main fluid) and decrease the viscosity. Decreasing the viscosity with a pH-responsive enzyme can be used to enhance fiber bridging for applications such as fiber diversion or fluid loss control.

Any elements of the disclosed embodiments may be replaced by any one of numerous equivalent alternatives, only some of which are disclosed in the specification. Embodiments may be used in, by non-limiting examples, hydraulic fracturing (with linear fluids, slick-water, cross-linked fluids, emulsion fluids, and VES fluids); acid treatments and acid fracturing; scale prevention treatments; and treatments with chelating agents.

Embodiments can be further understood from the following examples.

Example 1: Isolating a water-soluble chemical from an aqueous chemical triggering event.

The trigger may be the aqueous phase itself. Laboratory experiments were performed as follows: A container was made by shrink-wrapping PL A particles in 2 layers of polyvinyl alcohol film using the steps listed below. The film used in the experiments was obtained from Gunold + Stickma, GmbH, Stockstadt, Germany (80 micron thickness):

1. Cut a 10 18 cm (3.9x7.0 inch) piece of film

2. Folded the film in two to get a square

3. Sealed two sides of this square with an impulse sealer to form a bag

4. Measured 60 mL of a PLA particles as shown in Table 2

N Particle size Volume Optimal particle Optimal particle size ratio

(68.8% size for (16 mm slot)

total) enabling low

plug

permeability

(16 mm slot)

1 6.5 mm 25.0 6.5 4.2

2 0.64-4.5 mm 12.5 1.55 1 2.4

3 0.25-1.3 mm 6.3 0.66 1 2.7 4 0.45-0.042

mm 6.3 0.2475 1 5.9

5 0.01-0.115

mm 12.5 0.042 1

6 6-14 microns 6.3 ~10 microns*

* The size was not optimized

Table 2

5. Put the blend into the bag

6. Sealed the open sides of the bag to close it

7. Cut off the corners of the bag by applying the impulse sealer

8. Pierced the bag several times with a needle to let the air out

9. Tightly wrapped the bag in aluminum foil and put the ball into an oven preheated to 150 °C (302 °F))

10. Took out the aluminum ball and unwrapped it after 10 min.

The container was then immersed in sunflower oil for 20 minutes at room temperature. After the immersion, the container showed no visible damage, and the envelope was intact. The container, still wet with oil, was then immersed in tap water at room temperature. Agitation was provided, with care taken to ensure that the agitation did not destroy the container mechanically by direct contact with the stirrer. The dissolution, determined by the time of first particle release, occurred at 4 minutes; 8 minutes was necessary for total dissolution. First and total dissolution took 2 and 4 minutes respectively under similar conditions for a container that had not previously been immersed in the plant oil. Example 2: Isolating a water-soluble chemical from an aqueous chemical triggering event.

This example describes how a fracturing treatment of one stage of a horizontal well would be performed; the trigger is the aqueous phase itself. A widespread technique for fracturing long horizontal wells consists of dividing the wellbore into sections, each for example about 30.5 m (about 100 feet) long, and performing a hydraulic fracturing treatment on each of these sections individually. Each section has perforations going though the casing which connect the wellbore to the formation. A typical well in the Fayetteville shale, for example, has 5 clusters of perforations, with each cluster being an approximately 30 cm (1-ft) section perforated with 6 to 10 holes. A typical fracturing treatment of one such stage is done by pumping 1750 m³ (11,000 bbls) of water and a total of 72,550 kg (160,000 lbm) of sand. Typically, during a fracturing treatment, not all perforations take fluids simultaneously and only a fraction of the perforations is "fractured". Estimates are that only 1/3 of the clusters are effectively fractured during such treatment. Therefore a diverter is used to divert fracturing slurry from fractured clusters to non fractured clusters. The diverter used for the treatment is a blend of particles, designed according to the recommendations for designing high solids content fluids given in U. S. Patent Application Publication No. 2009/0025934:

• 700 μπι PL A particles (36% by volume)

• 100 μιη PLA particles (15% by volume)

• 10 μπι PLA particles (9% by volume) This blend is packed into individual containers, each holding 65 ml, made with a water soluble shell, for example the polyvinyl alcohol film whose properties and use to make a container were described in Example 1. (Other methods of fabrication are described in US Patent Application No. 13/105586 entitled "DESTRUCTIBLE CONTAINERS FOR DOWNHOLE MATERIAL AND CHEMICAL DELIVERY" by Lafferty et al, filed on 1 1 May, 201 1 and assigned to the same assignee as the present application. For one stage that has about 40 perforations, about 100 such containers are used (in theory, 40 such containers should be sufficient, but practice with diverters tends to show that effective diversion requires pumping larger quantities than designed based on the size and number of perforations).

The dissolvable containers are injected into the main fluid flow stream using the system shown in 2. The injector is connected downstream of the fracturing pumps (the side referred to as the high pressure side). The injector is about 5 m (16 ft) long (and has an inside diameter of about 7.5 cm (about 3 in)). The water soluble shell is the reagent for the triggering event, the release of the PLA, which is the reagent for the well treatment. Two layers of film are used for each container. The loading of the containers is done as follows:

a. Place 1 L of immiscible fluid, for example ethylene glycol, into the injector via the valve 1, for example a ball valve b. Place containers into the injector via valve 1

c. Fill the rest of the injector with ethylene glycol via the ball valve and then close valve 1

As the fracturing treatment is being performed, and real time monitoring via microseismics reveals where the fracture is growing. During the fracturing treatment, microseismic activity reveals that near-wellbore regions of the formation see no activity, implying that no fluid is injected into some perforations clusters. Therefore, a diversion stage is to be pumped. To do so, valves 4 on the injector are opened to displace the containers into the surface lines and then into the wellbore. During the displacement, the ethylene glycol (the immiscible phase) and the fracturing slurry (the main fluid) mix. The triggering mechanism (dissolution of the reagent water soluble film) occurs while the containers travel from the surface downhole. A successful diversion is then observed by a pressure spike on the treating pressure, and by microseismic activity in near wellbore areas near the perforations clusters that were previously unfractured.

Example 3; Temporary isolation of a chemical component of a High Solids Content Fluid for zonal isolation

This is an example of an intervention in a well; the objective of the intervention is to plug a zone that is experiencing extreme fluid loss, for example a situation in which a natural fracture connected to the wellbore has opened under treatment pressure. Such an event can also occur when a vertical well has two perforated zones, with one zone already stimulated in a previous treatment. The objective of the treatment is then to stimulate (fracture) zone number two without losing fracturing slurry into zone number one. Such events are difficult to predict, and preventive measures to avoid these types of situations are not always practical. However, an HSCF may be kept ready in a surface injector, and, if the need arises, the pill is injected and converted downhole into a low mobility plug.

In such a situation, this apparatus and method is practical, because it allows keeping an HSCF pill untriggered during the normal course of the treatment. Only if and when the need has developed (as shown by loss of fluid) is the pumping of the HSCF pill and its triggering initiated. In this example, the HSCF is prepared and kept untriggered by being kept on the surface at a high pH. Once the HSCF is injected into the well, the high pH injection fluid mixes with the low pH main fluid. The trigger is a drop in the pH, resulting in hydration of gel in the HSCF and a subsequent drastic loss of mobility of the HSCF.

In this example, it is assumed that the channel causing the fluid loss has an aperture that can be plugged by the HSCF immobilized in the wellbore (prior to entering the formation). It is believed that a more robust method would be to trigger the loss of mobility once the HSCF had been squeezed into the fracture. However, to do so, would require keeping the reagent and the HSCF separated until they reach the perforation (for example by using a foam wiper, or by incorporating a delay mechanism to the trigger mechanism (for example, by including an additive in the HSCF pill that consumes HC1 and keeps the pH high for a time greater than the time it takes to displace the HSCF pill downhole)). The present example shows the easiest and least expensive method.

Before the treatment starts, 189.3 L (189.3 L = 50 gallons) (HSCF) are prepared by mixing particles of three different mesh sizes and liquid in a batch reactor. To determine the required amount of each type of particles, the same approach was used as for preparing high solids content high-mobility cements. For determining the size distribution of each particle type, we used a Mastersizer 2000 Particle Analyzer obtained from Malvern Instruments. A typical HSCF slurry for use in this intervention is shown in Table 3. 60% by volume 40% by

For each lOOg of solid phase: volume:

20/40 mesh (mean diameter 616 microns) sand 1.25% weight

(SG=2.65) 61g of CMHPG in

100 mesh (mean diameter 101 microns) PLA particles pH 12 water

(SG=2.65) 19g

PLA particles (mean diameter 8.0 microns, SG=2.7)

20g

Table 3

The liquid phase contains 1.25% by weight CMHPG. About 75.7 liter (20 gal) of this fluid is necessary to produce 189.3 liters (50 gal) of HSCF. Small variations in the required volume can be tuned on site in order to make mixing practical. Once the HSCF is mixed, it is displaced into the 189.3 liters (50 gal) injector (several injectors may be used simultaneously to achieve the desired volume). The injector is then hooked up in parallel with the treatment line. Two closed, remotely operated, valves keep the HSCF isolated from the treatment fluid. Once all the connections are made and pressure-tested the treatment can be started. Fracturing treatments are typically done with viscous fluids. Some of these fluids have a high pH (for example, it is common for borate-crosslinked fluids to have a pH of 10). Other fluids, such as slickwater, can have their pH adjusted to 5 with HC1. During the treatment, variables such as treating pressure, bottom hole pressure, and microseismic activity may be monitored to ensure that the treatment results in a fracture as per design. If variables indicate that an undesirable amount of fracturing fluid is being lost, then the fracturing fluid is switched, if necessary, to a proppant free pad of low pH (for example a pH of 5.0). .During the injection of the low pH pad, the remotely operated valves of the injector are opened and the high pH HSCF is injected. In the wellbore, the pH of the carrier fluid is lowered by mixing with the main fluid, which leads to the hydration of the CMHPG guar and a drastic loss of mobility of the HSCF, making it a very effective plug. The HSCF is pumped and plugs the route of the undesired fluid loss. Once the monitored variables confirm that the fluid loss has been stopped, then the fracturing treatment can restart. The PL A particles in the HSCF will degrade with time and the zone that was temporarily plugged will be reopened for production.

A variation on example 3 is a method of treating a well having multiple perforations clusters using slick-water fluid. The treatment is performed at a pumping rate of 15.9 mVmin, or 265 L/second (100 barrels per minute (bpm)) and comprises a pad stage, proppant stages and a flush stage. Microseismics is used for estimating treatment effectiveness by defining how many of the perforation clusters are treated. After treating the open clusters, a decision about treatment diversion to the non-treated wellbore interval is made. Treatment diversion is accomplished by using dissolvable containers containing blends of particles, for example as described above in this example. Prior to the treatment, such containers are placed in the injector shown in Figure 1 using valve 1 and then the injector is filled with diesel. After making the decision about treatment diversion, proppant delivery into the treating fluid is stopped (without dropping the pumping rate) and upstream valve 4 on the injector is opened to equalize the pressure inside the injector. Then downstream valve 4 is opened and the dissolvable containers are flushed into the treating line. Then the containers are pumped downhole without decreasing the pumping rate, releasing diverting material into the treating zones. The effectiveness of the treatment diversion is estimated from microseismic data and pressure responses.

Although some example embodiments have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible in the example embodiments without materially departing from this invention. Accordingly, all such modifications are intended to be included within the scope of this disclosure as defined in the following claims.

Claims

We claim:

1. A method of adding one or more chemical or physical materials to a main treatment fluid being pumped into a well while preventing direct contact of the one or more chemical or physical materials with the main treatment fluid before they enter the wellbore, wherein the one or more chemical or physical materials would interact with the main treatment fluid when they directly contact the main treatment fluid, and wherein the one or more chemical or physical materials are added to the main treatment fluid on the surface, the method comprising a) providing an injector on the surface that contains a trigger-preventing injection fluid, said injection fluid comprising the one or more chemical or physical materials, b) injecting the injection fluid into the main fluid on the surface, c) and allowing the injection fluid and the main fluid to mix in the wellbore, thus allowing a triggering event that provides direct contact and interaction of the one or more chemical or physical materials with the main treatment fluid.

2. The method of claim 1 wherein the triggering event is dilution of the injection fluid by the main fluid.

3. The method of claim 1 wherein the main fluid is an aqueous fluid and the injection fluid is immiscible with an aqueous fluid.

4. The method of claim 3 wherein the injection fluid comprises an oil selected from the group consisting of diesel oil and vegetable oil.

5. The method of claim 1 wherein the main fluid is immiscible with an aqueous fluid and the injection fluid is an aqueous fluid.

6. The method of claim 1 wherein the main treatment fluid is a fracturing fluid.

7. The method of claim 1 wherein the physical material is selected from the group consisting of fluid loss agent, lost circulation agent, treatment diverting agent, proppant, and gravel.

8. The method of claim 1 wherein the chemical material is selected from the group consisting of one or more of breakers, anti-oxidants, crosslinkers, corrosion inhibitors, delay agents, biocides, buffers, pH control agents, solid acids, solid acid precursors, organic scale inhibitors, inorganic scale inhibitors, demulsifying agents, paraffin inhibitors, corrosion inhibitors, gas hydrate inhibitors, asphaltene treating chemicals, foaming agents, surfactants, enzymes, water blocking agents, and enhanced oil recovery agents.

9. The method of claim 1 wherein the chemical component comprises one or more water soluble compounds.

10. The method of claim 1 wherein the chemical component comprises one or more pH responsive compounds.

1 1. The method of claim 1 wherein the injection fluid comprises a high solids content fluid.

12. The method of claim 10 wherein the high solids content fluid comprises at least two different sizes of particles.

13. The method of claim 1 wherein the injection fluid comprises both a chemical component and a physical component.

14. The method of claim 1 wherein the injector comprises more than one remotely operated valve.

15. The method of claim 1 wherein there is more than one injection.

16. The method of claim 1 wherein the one or more chemical or physical materials in the injection fluid is inside one or more containers insoluble in the injection fluid and soluble in the main fluid.

17. The method of claim 16 wherein the triggering event comprises at least partial dissolution of the one or more containers.

18. The method of claim 16 wherein the contents are released from the one or more containers in the wellbore.

19. The method of claim 16 wherein the injector comprises a ball dropper.

20. The method of claim 16 wherein the one or more containers do not release their contents before reaching the wellbore.

21. The method of claim 16 wherein the one or more chemical or physical materials inside the one or more containers comprises a high solids content fluid.