WO2016076747A1

WO2016076747A1 - Chemical assisted selective diversion during multistage well treatments

Info

Publication number: WO2016076747A1
Application number: PCT/RU2014/000867
Authority: WO
Inventors: Dmitry Ivanovich Potapenko; Bruno Lecerf; Olga Petrovna Alekseenko; Matthew Robert GILLARD; Svetlana Viktorovna Nesterova; Christopher Fredd
Original assignee: Schlumberger Canada Ltd; Services Petroliers Schlumberger SA; Schlumberger Technology BV; Schlumberger Technology Corp; Schlumberger Holdings Ltd; Prad Research and Development Ltd
Current assignee: Schlumberger Canada Ltd; Services Petroliers Schlumberger SA; Schlumberger Technology BV; Schlumberger Technology Corp; Schlumberger Holdings Ltd; Prad Research and Development Ltd
Priority date: 2014-11-14
Filing date: 2014-11-14
Publication date: 2016-05-19
Anticipated expiration: 2017-05-14

Abstract

A method of treating a subterranean formation which includes: sealing at least one zone of a wellbore with at least one removable sealing agent; selectively removing the removable sealing agent from at least one target zone; and treating the at least one target zone is disclosed.

Description

CHEMICAL ASSISTED SELECTIVE DIVERSION DURING MULTISTAGE WELL TREATMENTS

BACKGROUND

The recovery of hydrocarbons from subterranean formations often entails performing multistage stimulation treatments. Types of such treatments include fracturing operations, high-rate matrix treatments and acid fracturing, matrix acidizing, and injection of chelating agents. Completing wells with multiple stages is performed in order to increase the stimulation efficiency by maximizing injection energy per unit of wellbore length. Such methods enable deeper penetration of the stimulation fluids, increases their contact with the reservoir, and in the end provide improved well production performance.

The staging of a treatment involves effective separation between individual stages, which is generally achieved by applying various diversion techniques, such as the use of various mechanical tools, ball sealers, diversion with particulates, viscous fluids and foams, limited entry methods, etc.

SUMMARY OF DISCLOSURE

In one aspect, embodiments disclosed herein relate to a method of treating a subterranean formation which includes: sealing at least one zone of a wellbore with at least one removable sealing agent; selectively removing the removable sealing agent from at least one target zone; and treating the at least one target zone.

In another aspect, embodiments disclosed herein relate to a method for selective diversion during a multi-stage well treatment, which includes: sealing all but one of a plurality of open zones of a wellbore with a removable sealing agent; performing a treatment of the open zone while the other zones are sealed; sealing the treated zone or isolating the section of the wellbore comprising the treated zone; selectively removing the removable sealing agent from an untreated sealed zone; and repeating the sequence of treating the unsealed zone while the other zones are sealed, sealing or isolating the treated zone, and selectively removing the removable sealing agent from an untreated sealed zone until the desired number of zones are treated.

In another aspect, embodiments disclosed herein relate to a method of treating a subterranean formation, which include: sealing at least one previously treated zone, of a wellbore with at least one removable sealing agent; enabling access to at least one untreated zone within the wellbore; and treating the accessed untreated zone.

In yet another aspect, embodiments disclosed herein relate to a method of treating a subterranean formation, which include: sealing at least one open zone of a wellbore with at least one removable sealing agent while leaving at least one open zone unsealed; treating at least one unsealed open zone while at least one other zone is sealed; and enabling access to at least one zone.

Other aspects and advantages of the disclosure will be apparent from the following description and the appended claims. BRIEF DESCRIPTION OF DRAWINGS

FIG. 1 shows a flowchart of an embodiment of the present disclosure.

FIG. 2 shows selective dissolution of various components that may be used to seal one of more zones of a wellbore in accordance with embodiments of the present disclosure. FIG. 3 shows a schematic of a wellbore undergoing a multi-stage treatment process of the present disclosure.

FIG. 4 shows a schematic of a wellbore undergoing a multi-stage treatment process of the present disclosure.

FIG. 5 shows a schematic of a wellbore undergoing a multi-stage treatment process of the present disclosure.

FIG. 6 shows a schematic of a wellbore undergoing a multi-stage treatment process of the present disclosure. FIG. 7 shows a schematic of a wellbore undergoing a multi-stage treatment process of the present disclosure.

FIG. 8 shows a flowchart of an embodiment of the present disclosure.

DETAILED DESCRIPTION In one aspect, embodiments disclosed herein relate to methods of using controllable and selective chemical induced zonal sealing/unsealing for treatment diversion during multistage well stimulation operations. More particularly, embodiments disclosed herein are based on dividing the wellbore into multiple zones, sealing at least one zone with various removable sealing agents, then selectively removing the sealing agents and unsealing one or more previously sealed zones so that the unsealed zone(s) may be treated. The embodiments of the diverting methods disclosed herein may combine the effectiveness of mechanical isolation with the efficiency of tool-free diverting techniques.

The embodiments of methods for selective zonal sealing/unsealing for treatment diversion between the stages of a multi-stage well presented herein are applicable for stimulating wells regardless of their completion type. The selectivity of the zonal sealing/unsealing as used herein may be conferred by either selective placement or selective reaction. Selective placement may involve selecting the location at which the sealing agent is applied or removed, which may be^' enabled by placing a tool at the depth where the sealing or removing takes place. For example, a coiled tubing line spotted at the depth where the sealing agent is to be removed may then use abrasive jet perforating to perforate through the seal or to spot a chemical capable of removing the seal. Selective reaction may involve a selective degradation time for the sealing agent or a selective chemical agent for removing selected sealing agents. In some embodiments, selective degradation may occur via a sealing agent degrading at a faster rate in the presence of a certain wellbore fluid or chemical than another sealing agent used to seal the wellbore. Selective reaction and removal of a sealing agent may occur when a chemical removing agent reacts or interacts with certain sealing agents while being substantially inert towards other sealing agents. For example, the chemical removing agent may react or interact to induce hydrolysis, oxidation, dissolution, and/or degradation of the sealing agent.

A flowchart for one of the presently described embodiments is shown in FIG. 1. As illustrated, one or more embodiments may involve having a well with at least one open zone at 102. Subsequently, at least one open zone of the wellbore may be sealed with one or more removable sealing agents at 104. One of the removable sealing agents may then be removed from at least one target zone at 106. Treating the target zone may then be performed at 108.

If further treatments of different zones of the wellbore are warranted or desired, the treated target zone of the wellbore may optionally be sealed with at least one or more removable sealing agents. It is another possibility to leave the treated target zone unsealed. The removable sealing agents sealing the next target zone(s) may be selectively removed to enable treatment of the next target zone(s). In this way, the treatment of the desired wellbore zone may be completed by repeating the process as many times as desired. Eventually, if no further treatments are warranted or desired, a final selective removal of at least one of the removable sealing agents in the sealed zones may be performed to reach the end of the job and allow for production through the wellbore.

During execution of the workflow exemplified in FIG. 1, decisions about the next stage to undergo treatment and about the end of the multi-stage treatment process may be made during the job based upon any collected information, the initial treatment design, and/or the formation response during any one of the stages of the workflow. In one or more embodiments, examples of sources of the information used for making such decisions may comprise magnitude of the treating pressure, temperature log data, microseismic including real-time microseismic data, or any other known sources of information that may be beneficial to the decision making process.

As mentioned, the method may begin with a well having at least one zone open at 102. As used herein, an open zone refers to a zone in which there may be fluid communication between the formation and the wellbore extending through the formation. That is, such open zone may refer to an open hole or a section of an open hole (where no casing or liner is cemented in place, serving as a barrier between the formation and the wellbore), or to a cased well which has been modified to allow for such access to the formation. In one or more embodiments, such well may be a cased well with at least one perforation, perforation cluster, a jetted hole in the casing, a slot, at least one sliding sleeve or wellbore casing valve, or any other opening in the casing that provides communication between the formation and the wellbore. In one or more embodiments, the well may not initially contain an open zone or may not contain an open zone in a desired portion of the well, and the open zone may be created by perforating the casing with perforating charges, jetting with a coiled tubing (CT) line or slick-line conveyed tools, cutting the casing, or any other known methods for creating an open zone in a well. In some embodiments, manipulating at least one sliding sleeve or wellbore casing valve within the wellbore or the creation of an open zone within a wellbore may enable access to an untreated zone of the formation. At 104, at least one open zone may be sealed (temporarily) with a removable sealing agent that may be a dissolvable or otherwise removable composition. As used herein, sealing of an open zone (or zones) may involve reduction of a fluid's ability to flow from the wellbore into the open zone, which may include reduction in the permeability of the zone. As used herein, sealing an open zone refers to sealing the^" open zone at the sandface and does not involve plugging the wellbore itself, which is referred to instead as isolation of the wellbore. In particular, isolation may be used to isolate an entire section of the wellbore from any treatment or operations occurring in more upstream sections of the wellbore, whereas sealing, as used herein, leaves the wellbore open and instead seals the sandface.

As used herein, the term "sealing agent" or "removable sealing agent" may refer to a solid or fluid that may plug or fill, either partially or fully, a portion of a subterranean formation. The portion to be filled may be a fracture that is opened, for example, by a hydraulic or acid fracturing treatment. The removable sealing agents may be any materials, such as solid materials (including, for example, degradable solids and/or dissolvable solids), that may be removed within a desired period of time. In some embodiments, the removal may be assisted or accelerated by a wash containing an appropriate reactant (for example, capable of reacting with one or more molecules of the sealing agent to cleave a bond in one or more molecules in the sealing agent), and/or solvent (for example, capable of causing a sealing agent molecule to transition from the solid phase to being dispersed and/or dissolved in a liquid phase), such as a component that changes the pH and/or salinity within the wellbore. In some embodiments, the removal may be assisted or accelerated by a wash containing an appropriate component that changes the pH and/or salinity. The removal may also be assisted by an increase in temperature, for example, when the treatment is performed before steam flooding, and/or a change in pressure.

In some embodiments, the removable sealing agents may be a degradable material and/or a dissolvable material. A degradable material refers to a material that will at least partially degrade (for example, by cleavage of a chemical bond) within a desired period of time such that no additional intervention is used to remove the seal. For example, at least 30% of the removable sealing agent may degrade, such as at least 50%, or at least 75%. In some embodiments, 100% of the removable sealing agent may degrade. The degradation of the removable sealing agent may be triggered by a temperature change, and/or by chemical reaction between the removable sealing agent and another reactant. Degradation may include dissolution of the removable sealing agent.

For the purposes of the disclosure, the removable sealing agents may have a homogeneous structure or may also be non-homogeneous including porous materials or composite materials. A removable sealing agent that is a degradable composite composition may comprise a degradable polymer mixed with particles of a filler material that may act to modify the degradation rate of the degradable polymer. In some embodiments, the particles of a filler material may be discrete particles. The particles of the filler material may be added to accelerate degradation and the filler particles may be from 10 nm to 5 microns in mean average size. In some embodiments, smaller filler particles may further accelerate degradation in comparison to larger filler particles. The filler particles may be water soluble materials, include hygroscopic or hydrophilic materials, a meltable material, such as wax, or be a reactive filler material that can catalyze degradation, such as a filler material that provides an acid, base or metal ion. In some embodiments, the filler particles may have a protective coating, thus allowing them to be mixed with a degradable polymer and/or heated during manufacturing processes, such as extrusion, whilst retaining their structural and compositional characteristics, the structural and compositional characteristics of the degradable polymer, and their capability for degradation. The coatings can also be chosen to delay degradation or fine tune the rate of degradation for particular conditions.

Examples of water soluble filler materials comprise NaCl, ZnC12, CaC12, MgC12, NaC03, KC03, KH2P04, K2HP04, K3P04, sulfonate salts, such as sodium benzenesulfonate (NaBS), sodium dodecylbenzenesulfonate (NaDBS), water soluble hydrophilic polymers, such as poly(ethylene-co-vinyl alcohol) (EVOH), modified EVOH, SAP (super absorbent polymer), polyacrylamide or polyacrylic acid and polyvinyl alcohols) (PVOH), and the mixture of these fillers. Examples of filler materials that may melt under certain conditions of use include waxes, such as candelilla wax, carnauba wax, ceresin wax, Japan wax, macrocrystalline wax, montan wax, ouricury wax, ozocerite^ paraffin wax, rice bran wax, sugarcane wax, Paricin 220, Petrac wax 165, Petrac 215, Petrac GMS Glycerol Monostearate, Silicon wax, Fischer-Tropsch wax, Ross wax 140 or Ross wax 160. Examples of reactive filler materials that may accelerate degradation include metal oxides, metal hydroxides, and metal carbonates, such as Ca(OH)2, Mg(OH)2, CaC03, Borax, MgO,CaO, ZnO, NiO, CuO, A1203, a base or a base precursor. The degradable composites may also include a metal salt of a long chain (defined herein as > C8) fatty acids, such as Zn, Sn, Ca, Li, Sr, Co, Ni, K octoate, stearate, palmate, myrisate, and the like. In some embodiments, the degradable composite composition comprises a degradable PLA mixed with filler particles of either i) a water soluble material, ii) a wax filler, iii) a reactive filler, or iv) combinations thereof, said degradable composite may degrade in 60°C water in less than 30, 14 or 7 days. Solid removable sealing agents for use as the sealing agent may be in any suitable shape: for example, powder, particulates, beads, chips, or fibers, and may be a combination of shapes. When the removable sealing agent is in the shape of fibers, the fibers may have a length of from about 2 to about 25 mm, such as from about 3mm to about 20mm. In some embodiments, the fibers may have a linear mass density of about 0.1 1 1 dtex to about 22.2 dtex (about 0.1 to about 20 denier), such as about 0.167 to about 6.67 dtex (about 0.15 to about 6 denier). Suitable fibers may degrade under downhole conditions, which may include temperatures as high as about 180°C (about 350°F) or more and pressures as high as about 137.9 MPa (about 20,000 psi) or more, in a duration that is suitable for the selected operation, from a minimum duration of about 0.5, about 1 , about 2 or about 3 hours up to a maximum of about 24, about 12, about 10, about 8 or about 6 hours, or a range from any minimum duration to any maximum duration.

The removable sealing agents may be sensitive to the environment, so dilution and precipitation properties may be taken into account when selecting the appropriate removable sealing agents. The removable sealing agent used as a sealer may survive in the formation or wellbore for a sufficiently long duration (for example, about 3 hours to about 6 hours). The duration may be long enough for wireline services to perforate the next pay sand, subsequent fracturing treatment(s) to be completed, and the fracture to close on the proppant before it completely settles, providing an improved fracture conductivity.

Further suitable removable sealing agents and methods of use thereof include those described in U.S. Patent Application Publication Nos. 2006/0113077, 2008/0093073, and 2012/0181034, the disclosures of which are incorporated by reference herein in their entireties. Such removable sealing agents include inorganic fibers, for example of limestone or glass, but are more commonly polymers or co-polymers of esters, amides, or other similar materials. They may be partially hydrolyzed at non-backbone locations. Any such materials that are removable (due in-part because the materials may, for example, degrade and/or dissolve) at the appropriate time under the encountered conditions may also be employed as removable sealing agents in the methods of the present disclosure. For example, polyols containing three or more hydroxyl groups may be used. Suitable polyols include polymeric polyols that solubilizable upon heating, desalination or a combination thereof, and contain hydroxyl-substituted carbon atoms in a polymer chain spaced from adjacent hydroxyl-substituted carbon atoms by at least one carbon atom in the polymer chain. The polyols may be free of adjacent hydroxyl substituents. In some embodiments, the polyols have a weight average molecular weight from about 5000 to about 500,000 Daltons or more, such as from about 10,000 to about 200,000 Daltons. Further examples of removable sealing agents include polyhdroxyalkanoates, polyamides, polycaprolactones, polyhydroxybutyrates, polyethyleneterephthalates, polyvinyl alcohols, polyethylene oxide (polyethylene glycol), polyvinyl acetate, partially hydrolyzed polyvinyl acetate, and copolymers of these materials. Polymers or. co-polymers of esters, for example, include substituted and unsubstituted lactide, glycolide, polylactic acid, and polyglycolic acid. For example, suitable removable materials for use as plugging agents include polylactide acid; polycaprolactone; polyhydroxybutyrate; polyhydroxyvalerate; polyethylene; polyhydroxyalkanoates, such as poly[R-3-hydroxybutyrate], poly[R- 3-hydroxybutyrate-co-3 -hydroxyvalerate] , poly [R-3 -hydroxybutyrate-co-4- hydroxyvalerate], and the like; starch-based polymers; polylactic acid and copolyesters; polyglycolic acid and copolymers; aliphatic-aromatic polyesters, such as poly(s-caprolactone), polyethylene terephthalate, polybutylene terephthalate, and the like; polyvinylpyrrolidone; polysaccharides; polyvinylimidazole; polymethacrylic acid; polyvinylamine; polyvinylpyridine; and proteins, such as gelatin, wheat and maize gluten, cottonseed flour, whey proteins, myofibrillar proteins, casins, and the like. Polymers or co-polymers of amides, for example, may include polyacrylamides.

Removable sealing agents, such as, for example, degradable and/or dissolvable materials, may be used in the sealing agent at high concentrations (such as from about 201bs/1000gal to about lOOOlbs/lOOOgal, or from about 401bs/1000gal to about 7501bs/1000gal) in order to form temporary plugs or bridges. The removable material may also be used at concentrations at least 4.8 g/L (40 lbs/1,000 gal), at least 6 g/L (50 lbs/1,000 gal), or at least 7.2 g/L (60 lbs/ 1,000 gal). The maximum concentrations of these materials that can be used may depend on the surface addition and blending equipment available.

Suitable removable sealing agents also include dissolvable materials and meltable materials (both of which may also be capable of degradation). A meltable material is a material that will transition from a solid phase to a liquid phase upon exposure to an adequate stimulus, which is generally temperature. A dissolvable material (as opposed to a degradable material, which, for example, may be a material that can (under some conditions) be broken in smaller parts by a chemical process that results in the cleavage of chemical bonds, such as hydrolysis) is a material that will transition from a solid phase to a liquid phase upon exposure to an appropriate solvent or solvent system (that is, it is soluble in one or more solvents). The solvent may be the carrier fluid used for fracturing the well, or the produced fluid (hydrocarbons) or another fluid used during the treatment of the well. In some embodiments, dissolution and degradation processes may both be involved in the removal of the sealing agent.

Such removable sealing agents, for example dissolvable, meltable and/or degradable materials, may be in any shape: for example, powder, particulates, beads, chips, fibers, or a combination of shapes. When such material is in the shape of fibers, the fibers may have a length of about 2 to about 25 mm, such as from about 3mm to about 20mm. The fibers may have any suitable denier value, such as a denier of about 0.1 to about 20, or about 0.15 to about 6.

Examples of suitable removable fiber materials include polylactic acid (PLA) and polyglycolide (PGA) fibers, glass fibers, polyethylene terephthalate (PET) fibers, and the like.

In uncased wells, the zonal sealing of a specified open zone may generally be achieved by reducing the permeability of the formation rock by injecting viscous fluids into the specified zones. In one or more embodiments, the viscous fluids injected may comprise at least one of viscoelastic surfactant fluids, cross-linked polymer solutions, slick-water, foams, emulsions, dispersions of acid soluble particulate carbonates, dispersions of oil soluble resins, or any other viscosified fluid that may be subsequently dissolved or otherwise removed (such as by breaking of the viscosification).

For cased wells, zonal sealing of open zone(s) may be achieved by placing a solid removable sealing agent in the perforations or in the space between the formation rock and the casing. In one or more embodiments, the solid removable sealing agent may be a dissolvable material for zonal sealing, which may comprise acid soluble cement, calcium and/or magnesium carbonate, polyesters including esters of lactic hydroxycarbonic acids and copolymers thereof, active metals such as magnesium, aluminum, zinc, and their alloys, hydrocarbons with greater than 30 carbon atoms including, for example, paraffins and waxes, and carboxylic acids such as benzoic acid and its derivatives. Further, in one or more embodiments, the dissolvable solid removable sealing agent may be slightly soluble in a wellbore fluid at certain conditions and would have a long dissolution time in said fluid. Examples of combinations of removable sealing agents and wellbore fluids that result in slightly soluble dissolvable removable sealing agents are benzoic acid with a water-based wellbore fluid and rock salt with a brine in the wellbore fluid.

The solid removable sealing agent used for zonal sealing may be in any size and form: grains, powder, spheres, balls, beads, fibers, or other forms known in the art. In order to facilitate the delivery of the solid composition to the desired zone for sealing, the solid composition may be suspended in liquids such as gelled water, viscoelastic surfactant fluids, cross-linked fluids, slick-water, foams, emulsions, brines, water, and sea-water.

In one or more embodiments, the removable sealing agent may be a manufactured shape, at a loading sufficiently high to be intercepted in the proximity of the wellbore. The loading may be more than about 50 lb/1000 gal. The manufactured shape of the removable sealing agent may be round particles having dimensions that are optimized for sealing. Also, the particles may be of different shapes, such as cubes, tetrahedrons, octahedrons, plate-like shapes (flakes), oval, and the like. The removable sealing agent may be of any dimension that is suitable for sealing. For example, as described in U.S. Patent Application Publication No. 2012/0285692, the disclosure of which is incorporated by reference herein in its entirety, the removable sealing agent may including particles having an average particle size of from about 3 mm to about 2 cm. Additionally, the removable sealing agent may additionally include a second amount of particles having an average particle size from about 1.6 to about 20 times smaller than the first average particle size. Also, the removable sealing agent may include flakes having an average particle size up to 10 times smaller than the first average particle size.

In some embodiments, the removable sealing agent is a diverter pill. The diverter pill may be a diversion blend with fibers and degradable particles with a particular particle size distribution. The diverter pill may include about 2 to 50bbl of a carrier fluid. The diverter pill may include a diversion blend that is used as a plug and may have a mass of 10 to 4001bs. The diversion blend may include about 50 pounds to 200 lbs of fiber per 1000 gallons of blend. It may include about 20 to about 200 pounds of particles per 1000 gallons of blend. The diverter may include beads with an average size such as described in TABLE 1 of U.S. Patent Application Publication No. 2012/0285692 Al , which is hereby incorporated by reference in its entirety. Additionally, any other diverters that are used in the industry may qualify as removable sealing agents.

The delivery and placement of the removable sealing agent (including viscous fluids and solid compositions) for zonal sealing may be performed by bullheading the material downhole, spotting the material at the wellbore with a CT-line or slick-line, or by using downhole containers capable of releasing the material at a desired zone. In one or more embodiments, after spotting the removable sealing agent composition in the wellbore the removable sealing agent is injected into the zone to be sealed by increasing the pressure in the wellbore. Any excess of the removable sealing agent applied downhole may be removed from the wellbore by cleaning it out using a coiled tubing or washing line and an appropriate cleaner for the sealing material.

The mechanical strength of the removable seals created during the zonal sealing may be increased by compacting the removable seals with gluing systems such as epoxy resins or emulsion systems such as wax and paraffin emulsions. In one or more embodiments, the gluing systems for increasing the mechanical strength of the removable seals may be compounded with the solid removable sealing agent before placement in the wellbore or may be injected separately into the wellbore after sealing the zone with the removable sealing agent. An increase in the mechanical strength of the removable seals may also be achieved by compounding the solid removable sealing agents with at least one reinforcement agent chosen from the group including fibers, deformable particulates, and particles coated with temperature and/or chemically activated formaldehyde resins.

Further, as mentioned above, for cased holes, the workflow of the present disclosure may also include creating openings in the casing to create the one or more open zones and enable access to the formation. It is also within the scope of the present disclosure that zonal sealing may be combined with the creation of the open zone(s). For example, a sequence may include creation of open zone 1 , sealing of open zone 1, creation of open zone 2, sealing of open zone 2, etc., which may be performed as many times as desired, and in combination with wellbore clean out if desired. Thus, referring back to FIG. 1, the workflow may involve repetition of elements 102 and 104 multiple times before proceeding to elements 106 and 108. This procedure may allow for the selective sealing of various wellbore zones with various removable sealing agents.

At 108, once a target zone or zones has had its removable sealing agent selectively removed, treatment of the target zone may be performed. Further, as one or more other zones may still be sealed with removable sealing agents, such sealed zones may not be subjected to the treatment at the given stage, and in fact, may be inaccessible to such treatments given the removable sealing agent in place. In one or more embodiments, the at least one treatment may be a propped fracturing treatment, a non-propped fracturing treatment, a slick-water treatment, an acidizing acid fracturing, and/or an injection of chelating agents. The injecting fluid may be selected from one of water, slick-water, gelled water, brines, viscoelastic surfactants, cross-linked fluids, acids, emulsions, energized fluids, foams, and mixtures thereof. Assuming one or more zones remain sealed (and such zones warrant treatment), after performing the at least one treatment stage at 106, the treated zone may optionally be isolated or sealed in order to temporarily decrease or stop fluid penetration therein. This isolation or sealing may be achieved by several methods including plugging the perforations, the wellbore, or the annulus space between the casing and the borehole in the treated zone, including use of the various removable sealing agents described in reference to stage 104 above. However, it is also within the scope of the present disclosure that conventional zonal isolation and diversion techniques may be used to isolate the treated zone such as pumping degradable and/or soluble ball sealers, setting sand or proppant plugs, setting packers, and bridge plugs including flow-through bridge plugs, and using completion conveyed tools such as sliding sleeves and wellbore valves. While sealing has been used to describe the sealing of the sandface, leaving the wellbore open, isolation is used to describe the complete closing off of a section or zone of the wellbore. When conventional zonal isolation and diversion techniques are utilized to effectively isolate a treated zone, the de-isolation of the treated zone may be performed by conventional techniques known in the art such as creating pressure draw across the casing to remove ball sealers from the perforation tunnels, wellbore clean out with a coiled tubing line, unsetting bridge plugs or milling them out, etc.

As mentioned above, the treated target zone may be sealed through the use of various removable sealing agents described in reference to stage 104 above. For example, sealing of the treated zone may also be achieved using various particulate materials such as rock salt, oil-soluble resins, waxes, carboxylic acids, cements including acid soluble cements, ceramic beads, glass beads, and cellophane flakes. Additionally, permeability reduction in the treated target zone may be achieved by injecting viscous fluids, foams, emulsions, cross-linked fluids, viscoelastic surfactant fluids, brines, and mixtures thereof into the treated formation zone. Permeability reduction in the treated formation zone may also be achieved by injecting suspensions of solids such as carbonates, polyesters, rock salt, oil-soluble resins, waxes, carboxylic acids, and mixtures thereof.

In one or more embodiments, modification of the stress field in the treated zone may also be a way of sealing the target zone after treatment. Modifying the stress field in a treated target zone of the formation may be achieved by increasing the pore pressure in the treated target zone by injecting fluids including water, oil, foams, emulsions, cross-linked fluids, viscoelastic solid fluids, brines, and mixtures thereof. Alternatively, or in addition, the stress field may be modified by cooling or heating the formation rock in the treated target zone by using downhole heaters or coolers, or injecting heated or cooled fluids including energized fluids and gases in the treated zone of the formation. As the operation progresses beyond the initially treated target zone(s), at least one of the open zones sealed at stage 104 may be selectively unsealed. That is, one or more wellbore zones sealed may be selectively unsealed to facilitate their treatment during the multi-stage treatment process. For embodiments using a solid, dissolvable component as the removable sealing agent, the selective unsealing of at least one sealed wellbore zone may be accomplished by contacting the removable sealing agent comprising the solid, dissolvable component with a suitable dissolving agent to dissolve the dissolvable component. In one or more embodiments, suitable dissolving agents may comprise at least one of inorganic acids (such as hydrochloric acid), organic acids (such as formic acid, acetic acid), hydroxides, ammonia, organic solvents, diesel, oil, water, brines, solutions of organic and/or non-organic salts, and mixtures thereof. For example, FIG. 2 shows the selectivity of particular solid dissolvable components for dissolving agents. Specifically, the dissolvable components calcium carbonate, boric acid, and paraffin are shown to be selectively dissolvable by 10% HC1, 10% NaOH, and hexane, respectively, while remaining substantially insoluble when contacted by the other dissolving agents. In one or more other embodiments in which viscous fluids are used as the sealing material, the viscous fluids may be broken by breaker fluids known to reduce the viscosity thereof. For example, viscoelastic surfactants containing a quaternary amine group may possess a pH-dependent viscosity profile such that the fluid viscosifies at certain pH values, and may have a reduced viscosity at a lower pH value.

The delivery and placement of the dissolving agent or breaker for the selective removal of the removable sealing agent may be performed by bullheading the dissolving agent or breaker downhole, spotting the dissolving agent or breaker at the wellbore with tubing or a coiled tubing string (including any tubing with an inner diameter less than 1 inch), or by using downhole containers capable of releasing the dissolving agent or breaker at the sealed zone to dissolve or otherwise break the removable sealing agent. When using a fluid flush to deliver the dissolving agent or breaker to a sealed zone, it may be desirable to minimize contact of the fluid including the dissolving agent or breaker with sealed zones that are not intended to have the removable sealing agent removed and be unsealed, while maximizing the contact of the fluid including the dissolving agent or breaker with the sealed target zone or zones that are intended to have the removable sealing agent removed and be unsealed.

As mentioned above, in one or more embodiments, the aforementioned stages of treating the target zone at stage 108, optional isolation or re-sealing of the treated target zone at stage, and/or selectively removing the removable sealing agent from a different untreated target zone may be repeated as many times as desired for the multi-stage treating of the specified wellbore interval. The decision about each stage and treatment continuation may be made on the multi-stage treatment job design and/or on data obtained during the multi-stage treatment process.

Specifically, in one or more embodiments, a cased wellbore open zone sealing may utilize a sequence, performed at least one time, comprising creating an open zone in the casing and sealing the created open zone with a removable sealing agent. Utilizing this sequence may allow for the sealing of the created wellbore zones with solid removable sealing agents comprising different dissolvable components. For example, referring back to FIG. 2, the three solid dissolvable components may be used in a system for sealing at least three different zones, each with a different solid removable sealing agent. Thus, in one or more embodiments, a zonal sealing method may utilize a sequence of creating and/or sealing a first open zone with a solid removable sealing agent comprising a first dissolvable component, creating and/or sealing a second open zone with a solid removable sealing agent comprising a second dissolvable component, and repeating the sealing process with different dissolvable components as many times as desired for the chosen treatment process. In particular embodiments, the steps of using a dissolving agent to selectively unseal a previously sealed zone to create an opened target zone and performing a treatment on the created open target zone may be substituted anywhere in the sequence recited above.

Eventually, after the desired zones have been treated, communication between sealed or isolated zones and the wellbore may be reestablished so that the job can be completed and the wellbore can be put into production. The sealed and isolated zones of the wellbore may be unsealed and de-isolated using the techniques described above. Specifically, de-isolation techniques may include, for example, creation of pressure draw across a casing to remove ball sealers from perforation tunnels, wellbore clean-out with coiled tubing, unsetting bridge plugs and milling them out, etc.

In some embodiments, the multi-stage treatment method outlined above may be applied to wellbores that have zones that have previously undergone stimulation treatments. In this way, the wellbore may undergo re-stimulation treatments of the previously treated zones or the removable sealing agents may serve to seal the previously treated zones while untreated zones undergo stimulation treatments via a multi-stage treatment method. Types of treatments that zones of a wellbore may have undergone or that may be repeated (re- stimulation) during embodiments of a multi-stage treatment method described herein generally include fracturing operations, high-rate matrix treatments and acid fracturing, matrix acidizing, and injection of chelating agents.

A flowchart for an example embodiment is illustrated in FIG. 8. In one or more embodiments, in a wellbore that has at least one zone that has previously undergone stimulation treatments there may exist at least one open zone at 802. The at least one open zone may be one of the zones of the wellbore that has previously undergone stimulation treatments or the open zone may not have previously undergone stimulation treatments. Additionally, there may be a combination of open zones that have been treated along with zones that have not previously undergone stimulation treatments. Subsequently, at least one open zone of the wellbore may be sealed with one or more removable sealing agents, while leaving at least one open zone unsealed at 804. The at least one open zone may then be treated while the at least on other zone is sealed at 806. Following the treatment, access may be enabled to at least one zone at 808. In some embodiments, enabling access to at least one zone may include selectively removing at least one removable sealing agent from a zone that was previously sealed. In some embodiments, enabling access may include creating an open zone by perforating the wellbore casing with perforating charges, jetting with a coiled tubing (CT) line or slick-line conveyed tools, cutting the casing, manipulating at least one sliding sleeve or wellbore casing valve within the wellbore or any other known methods for creating an open zone in a well. In some embodiments, manipulating at least one sliding sleeve or wellbore casing valve within the wellbore or the creation of an open zone within a wellbore may enable access to an untreated zone of the formation.

Referring now to FIG. 3, a schematic of a wellbore subjected to a multi- stage treatment of the present disclosure is shown. The wellbore 300 illustrated in FIG. 3 has a series of perforated zones 301-306 created in a separate step prior to, or that existed before, the beginning of the multi-stage treatment. Different stages of the treatment are illustrated in 3.1-3.4. As can be seen in stage 3.1, all of the perforated zones 302-306 but the one 301 located at the farthest end of the toe section of the wellbore 300 are sealed by a solid removable sealing agent comprising a dissolvable component. In one embodiment, this configuration of sealed and open zones may be achieved by sealing perforated zones 302-306, cleaning out the wellbore, and then creating a new set of unsealed perforations 301. In another embodiment, the configuration of sealed and open zones may be achieved by sealing the perforated zones 301-306 followed by deploying a coiled tubing line for selective spotting of a dissolving agent in the wellbore zones which are to be selectively unsealed via the removal of the removable sealing agent. In stage 3.2, treatment of open zone 301 is performed. The treatment may comprise fracturing, matrix acidizing, slick-water treatment, or any other type of treatment as described above. Stage 3.3 depicts the isolation of the area of the wellbore comprising treated zone 301. The isolation of the area of the wellbore comprising treated zone 301 can be performed by setting wellbore plugs 310 as shown in the figure, pumping ball sealers, plugging of the treated zone with fiber materials and/or solid particulates, as well as applying any other zonal isolation technique described above. Stage 3.3 also depicts the placement of a dissolving agent 320 at sealed zone 302 to selectively remove the removable sealing agent from and unseal zone 302. The placement of the dissolving agent may be done simultaneous with the plugging of the wellbore to isolate the area of the wellbore comprising zone 301 by including the dissolving agent 320 in the flush fluid. Control over what specific sealed zone has the removable sealing agent removed may be achieved by varying the time of contact of the flush fluid including the dissolving agent to the sealed zones. For example, as depicted in stage 3.3 to unseal sealed zone 302, one may minimize the contact of the dissolving agent with sealed zones 303-306 and maximize contact time with sealed zone 302. The placement of the dissolving agent 320 in a specific zone may also be accomplished by spotting the dissolving agent 320 with a coiled tubing line.

The well configuration after selectively removing the removable sealing agent and opening zone 302 is shown in stage 3.4, and it is similar to the configuration at the beginning (stage 3.1) of the multi-stage treatment in that all zones are sealed/isolated except for one. This configuration may allow for the staged treatment of the well zones by repeating the same procedures as already stated in this example. For example, and as shown in stage 3.5 selectively unsealed zone 302 may now be treated as desired. Further repetition of the previously described procedure allows for the treatment of the other wellbore zones in the direction from the toe of the well to heel. Upon completion of the multi-stage treatment, the isolating materials and/or tools used for isolation of the wellbore zones comprising the treated zones are removed by an appropriate technique to re-establish connectivity between the treated zones of the wellbore. For example, if sand plugs were used, then a wellbore clean-out operation can be performed.

While the given example provides a description of a situation where a well is treated in a zonal direction from toe to heel, the same procedure is applicable for treating various wellbore zones regardless of their position and order. In the case where the zone to be treated next is located further down the wellbore than the currently treated zone, isolation of the treated zone may not be performed, but sealing the sandface by plugging the perforations, formation, or space between the formation and the casing using any method previously mentioned may be performed. In this case, the delivery of the dissolving agent to unseal the next zone to be treated may be achieved by spotting with a coiled tubing line.

Referring to FIG. 4, an embodiment illustrating a multistage treatment of a well completed with an open hole section is shown, although the same procedure used in this example may be used with a well with a cased completion type. Prior to the treatment the wellbore interval to be treated is broken into several zones 401, 402, 403, 404 and the permeability of all of the zones 402, 403, 404 but one 401 is reduced by injecting a removable sealing agent into the formation, as shown in stage 4.1. The situation shown in stage 4.1 may be achieved by initially reducing the permeability of all of the zones 401 - 404 followed by wellbore clean-out and then spotting, via coiled tubing or slick-line, of a dissolving agent to dissolve the removable sealing agent in solely the zone planned to be open 401. In this case, the removable sealing agent is selected to be stable in the treating fluid but substantially dissolvable in some other dissolving agent. For example, when performing an acid treatment process, wax beads soluble in organic solvents may be used as the removable sealing agent to prevent their dissolution during treatment.

As shown in stage 4.2, the open zone 401 is then treated by any of the aforementioned treatment processes involving the injection of a fluid into the wellbore (e.g. matrix acidizing). In stage 4.3, the treated zone 401 is then sealed by injecting a diverting material 410. The diverting material may comprise benzoic acid flakes, wax beads, poly lactic acid (PLA) fibers, a viscous fluid including self-diverting fluids, or any type of removable sealing agent previously described.

Stage 4.3 also depicts the placement of a dissolving agent 420 at sealed zone 402 in order to remove the removable sealing agent from and selectively unseal zone 402. The placement of the dissolving agent may be done simultaneous with the placement of the diverting material into the treated zone 401 to seal zone 401 by including the dissolving agent in the flush fluid. The diverting material 410 and the dissolving agent 420 may be selected from groups of chemicals which do not react with and are substantially insoluble within each other. For example, if benzoic acid flakes are used as the diverting material 410 for sealing treated target zone 401 then an organic solvent or diesel oil may be used as the dissolving agent 420 for the selective removal of the removable sealing agent from zone 402. Control over what specific sealed zone has the removable sealing agent removed may be achieved by varying the time of contact of the flush fluid including the dissolving agent to the sealed zones. For example, as depicted in stage 4.3 to selectively remove the removable sealing agent from sealed zone 402, one may minimize the contact of the dissolving agent 420 with sealed zones 403, 404 and maximize contact time with sealed zone 402. The placement of the dissolving agent 420 in a specific zone may also be accomplished by spotting the dissolving agent with a coiled tubing line.

The well configuration after selectively unsealing and opening zone 402 is shown in stage 4.4 and it is similar to the configuration at the beginning (stage 4.1) of the multi-stage treatment in that all zones are sealed except for one. This configuration allows for the staged treatment of the well zones by repeating the same procedures as already stated in this example. For example, and as shown in stage 4.5, selectively unsealed target zone 402 may now be treated as desired. Further repetition of the previously described procedure allows for the treatment of the other wellbore zones in the direction from the toe of the well to heel. Upon completion of the multi-stage treatment any removable sealing agent and diverting material used for the sealing of the treated zones are removed by an appropriate technique to re-establish connectivity between the treated zones of the wellbore. For example, if benzoic acid were used then flow-back fluid that has a temperature higher than the temperature of the treating fluid may be used to dissolve the benzoic acid flake. In the case where wax beads are used as the sealing/diverting material, they may be dissolved later on by the hydrocarbons produced from the formation. While the given example provides a description of a situation where a well is treated in a zonal direction from toe to heel, the same procedure is applicable for treating various wellbore zones regardless of their position and order. In this case, the delivery of the dissolving agent to selectively remove the removable sealing agent and unseal the next target zone to be treated may be achieved by selectively spotting the dissolving agent with a coiled tubing line.

Referring to FIG. 5, an embodiment of a multi-stage treatment process with use of various removable sealing agents and dissolving agents is shown. Specifically, this embodiment describes the use of a series of removable sealing agents 50, 52, 54, 56, 58 specifically dissolvable in dissolving agents 60, 62, 64, 66, 68 for multi-stage well treatments. One of the possible examples of such a system of removable sealing agents and dissolving agents is shown in FIG. 2. Further, the removable sealing agents must also be selected so that they do not interact and dissolve in the fluid that will be used during the well treatment.

As shown in FIG. 5, the well to be treated has a series of perforated regions 501, 502, 503, 504, 505, 506 which are created in a separate step prior to, or existed before, the beginning of the multi-stage treatment. As shown in stage 5.1, all zones 502, 503, 504, 505, 506 except for the one 501 located at the toe are sealed, and each is sealed with a removable sealing agent 50, 52, 54, 56, 58 having different dissolvability. Thus, methods of sealing specific wellbore zones with different materials will be specifically described with reference to FIG. 5. Treatment of the open zone 501 is performed, as shown in stage 5.2. The treatment performed may be fracturing, matrix acidizing, slick water treatment, or any other type of treatment previously mentioned. In the next stage, shown in stage 5.3, isolation of the wellbore zone comprising the treated zone is performed. Such isolation can be performed by setting wellbore plugs 510 as shown in the figure, pumping ball sealers, plugging of the wellbore zone with fibrous materials and/or solid particulates, as well as applying any other isolation technique previously described. Also, the treated zone may be sealed with a removable sealing agent, as previously described.

Additionally, in stage 5.3, simultaneous with the isolation of the wellbore zone comprising the treated zone 501 , the selective removal of the removable sealing agent and unsealing of sealed zone 502 by a flush fluid containing a suitable dissolving agent 60 is shown. The dissolving agent containing flush fluid is displaced to the zone 502 that is planned to be unsealed. A selective reaction or simple dissolution related to dissolving agent 60 and sealing material 50 may result in the selective dissolution of the removable sealing agent 50 to create an open zone as shown in stage 5.4. The selective removal of the removable sealing agent 50 from sealed zone 502 over the other sealed zones 503-506 may also be a function of the amount of contact time that the dissolving agent 60 is in contact with sealed zone 502. For example, dissolving agent 60 may controllably be in contact for a longer period of time with the removable sealing agent 50 in zone 502 than those removable sealing agents in zones 503-506. The placement of the dissolving agent in the desired zone may also be performed by using a coiled tubing line.

The well configuration after the selective removal of removable sealing agent 50 from zone 502 is shown in stage 5.4, and it is similar to the configuration at the beginning (stage 5.1) of the multi-stage treatment in that all zones are sealed/isolated except for one. This configuration allows for the staged treatment of the wellbore zones by repeating the same procedures as already stated in this example. For example, and as shown in stage 5.5, unsealed zone 502 may now be treated as desired. Following the treatment, treated zone 502 may then be sealed with a removable sealing agent or the wellbore zone comprising treated zone 502 may be isolated, as was previously done for zone 501. Stage 5.6 shows that simultaneous with or after the isolation of the wellbore zone comprising treated zone 502, a suitable dissolving agent 62 may be spotted at zone 503 in order to selectively dissolve removable sealing agent 52. Once removable sealing agent 52 is dissolved, as shown in stage 5.7, repetition of the previously recited sequence for the multi-stage treatment may be performed to allow for the treatment of the other wellbore zones up to 506 if it is so desired. Upon completion of the multistage treatment, the isolating materials and/or tools used for isolation of the wellbore zones comprising the treated zones are removed by an appropriate technique to re-establish connectivity between the treated zones of the wellbore. For example, if sand plugs were used for isolation of wellbore zones, then a wellbore clean-out operation can be performed.

While the given example provides a description of a situation where a well is treated in a zonal direction from toe to heel, the same procedure is applicable for treating various wellbore zones regardless of their position and order. In the case where the targeted zone to be treated in the next stage is located further down the wellbore than the currently treated zone, sealing of the currently treated zone is performed not by wellbore isolation via plugging, but by plugging the perforations, formation, or space between the formation and the casing. In this case, the delivery of the dissolving agent to the next zone to be treated for removal of the removable sealing agent may be achieved by spotting with a coiled tubing line. Referring now to FIG. 6, an embodiment of a wellbore having long intervals is shown. Specifically, this embodiment is directed towards applying the procedure described with respect to FIGS. 3-5 for treating long wellbore intervals in multiple stages. As shown in FIG. 6, the well to be treated has a series of perforated regions 601-606, which are created in a separate step prior to, or existed before, the beginning of the multi-stage treatment. As shown in stage 6.1, all zones except for the one 601 located at the toe are sealed, and each is sealed with a removable sealing agent having a different dissolvability 50, 52, 5.4, 56, 58. In other embodiments, the same sealing materials may be used. As shown in stage 6.2, by applying the repeatable sequence of steps including zonal treatment of the open target zone, target zone sealing or wellbore isolation after treatment, and selective removal of the removable sealing agent as described above with respect to FIGS. 3-5 allows for the complete treatment of the considered wellbore interval in multiple stages. As discussed, the sealing of the treated zones or isolation of the wellbore comprising the treated zones between the stages can be performed by using ball sealers, setting wellbore plugs, sand plugs, plugging of the treated zone with fibrous materials and/or solid particulates, or by applying any previously discussed sealing and isolation technique.

Upon the completion of treatment for zone 606, the whole treated wellbore interval 610 (including zones 601-606) is isolated as shown in stage 6.2. The isolation of the treated wellbore interval 610 may be performed by setting various wellbore plugs, such as bridge plugs, packers, sand plugs, using ball sealers, solid particulates, or any other previously discussed sealing and isolation technique. After isolation of the treated wellbore interval 610, the next wellbore interval 620 is perforated and the perforations are sealed with a removable sealing agent to provide the same wellbore configuration as the beginning of the treatment sequence (i.e. all zones sealed except for one). The multi-stage treatment sequence including zonal treatment of the open target zone, target zone sealing or wellbore isolation after treatment, and selective removal of the removable sealing agent as described with respect to FIGS. 3-5 can then commence to fully treat the new wellbore interval. The procedure described above may be repeated as many times as desired to enable the selective treatment and stimulation of individual wellbore zones in long wellbore sections and thereby allows for a minimization in the usage of mechanical tools and operation time during the multi-stage treatment operation. Referring now to FIG. 7, another embodiment is illustrated. This embodiment describes a procedure for sealing cased wellbore zones with removable sealing agents having different dissolvable components 50, 52, 54, 56, 58. Said dissolvable components may have substantially different or similar dissolution properties and thus dissolving agents capable of their dissolution. The selected cased wellbore interval initially has no openings in the casing or the existing openings may be sealed prior to the procedure to substantially limit communication between the wellbore and the reservoir.

During the first stage, a perforating tool 730 is spotted in the wellbore at the position selected for the first zone 701 and a first opening in the casing is created, as shown in stage 7.1. Perforating tool 730 can be any tool that conveys explosive charges, tubing or coiled tubing line conveyed jetting tools, or casing cutting tools, etc. After the creation of the first zone 701, the perforating tool 730 is shifted away from the first zone 701 and the first zone 701 is sealed with a removable sealing agent 50 by injecting a fluid comprising said removable sealing agent into the first zone 701. The delivery of such fluid downhole can be performed by bullheading, injecting through a coiled tubing line or tubing string, or by using downhole containers.

After sealing the first zone 701, the perforating tool 730 is then positioned at the location selected for the second zone 702 and the perforation/sealing procedure is repeated, as illustrated by stages 7.3-7.4. Thus, repeating the described procedure creates openings and zones, and their respective sealing with sealing materials 50, 52, 54, 56, 58 in the whole specified wellbore interval, as shown in stage 7.5. Upon completion of the described procedure one or several zones in the wellbore region may be opened. Opening of zones may be performed by spotting a dissolving agent in one of the zones to dissolve the sealing material, as is pictured in stage 7.6. In stage 7.7, a way of providing a window in the casing of the wellbore is by creating a new opening 706, which can be done using the same tool as already described above.

Upon completion of the described procedure, one or several zones in the wellbore region may be opened through the selective removal of the removable sealing agent. This removal may be performed by spotting a suitable dissolving agent in one of the zones that has a corresponding dissolvable component. Such spotting may be performed by using coiled tubing or tubing-lines which can be combined with possible wellbore clean-out from any excess removable sealing agent. Another way to "unseal" specific zones would be to use the perforation tool 730 already described in this example.

Further, it is also within the scope of the present disclosure that creation of openings in a casing may involve controlled dissolution of a sealing material that is in a plugged or sealed zone. In such a case, the removable sealing agent may be slightly soluble in a wellbore fluid at certain conditions and would have a long dissolution time in said fluid. Upon extended exposure to such wellbore fluid, the removable sealing agent may dissolve and reveal openings. Examples of combinations of removable sealing agents providing slightly soluble dissolvable components are benzoic acid with a water-based wellbore fluid as the dissolving agent and rock salt with brine in the wellbore fluid as the dissolving agent. Although only a few 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. In the claims, means-plus-function clauses are intended to cover the structures described herein as performing the recited function and not only structural equivalents, but also equivalent structures. Thus, although a nail and a screw may not be structural equivalents in that a nail employs a cylindrical surface to secure wooden parts together, whereas a screw employs a helical surface, in the environment of fastening wooden parts, a nail and a screw may be equivalent structures. It is the express intention of the applicant not to invoke 35 U.S.C. § 112, paragraph 6 for any limitations of any of the claims herein, except for those in which the claim expressly uses the words 'means for' together with an associated function.

Claims

CLAIMS What is claimed:

1. A method of treating a subterranean formation, comprising:

sealing at least one zone of a wellbore with at least one removable sealing agent; selectively removing the removable sealing agent from at least one target zone; and

treating the at least one target zone.

2. The method of claim 1, wherein the treating occurs while at least one zone of the wellbore is sealed with at least one removable sealing agent.

3. The method of claim 1 , wherein at least one of the: sealing at least one zone of a wellbore with at least one removable sealing agent, selectively removing the at least one removable sealing agent at a target zone, or treating the target zone is repeated at least one time.

4. The method of claim 3, further comprising isolating at least one section of the wellbore.

5. The method of claim 4, further comprising unisolating the isolated section of the wellbore.

6. The method of claim 3, wherein during the repeating multiple zones are treated and form a first interval of a wellbore, which upon completion of their treatment the first interval is isolated and at least one more interval comprising a plurality of wellbore zones is treated in a substantially similar manner.

7. The method of claim 3, further comprising enabling access to at least one previously untreated zone within the wellbore, wherein the enabling access comprises perforating or jet perforating the wellbore at least one time or manipulating at least one sliding sleeve or wellbore casing valve within the wellbore.

8. The method of claim 1, further comprising sealing the treated target zone with at least one removable sealing agent.

9. The method of claim 1, wherein the selective removing comprises at least one of perforating, abrading, dissolving, hydrolyzing, oxidizing, degrading, or melting the removable sealing agent from at least one sealed target zone.

10. The method of claim 1 , wherein the selective removal of the removable sealing agent comprises contacting the at least one target zone with a removal agent by bullheading the removal agent downhole, spotting the removal agent downhole, and/or the use of downhole containers to deliver the removal agent. 5

1 1. The method of claim 10, wherein the removal agent dissolves the removable sealing agent; and wherein the removal agent is at least one of hydrochloric acid, formic acid, acetic acid, hydroxides, ammonia, organic solvents, diesel, oil, water, brines, solutions of organic and/or non-organic salts, and mixtures thereof.

10 12. The method of claim 1 , wherein the treating comprises at least one of a propped fracturing, a non-propped fracturing, a slick-water, acidizing, acid fracturing, injection of chelating agents, stimulating, or squeezing a chemical.

13. The method of claim 1, wherein the removable sealing agent comprises a viscous fluid from at least one of gelled water, viscoelastic surfactant fluids,

15 crosslinked polymer solutions, slick- water, foams, emulsions, dispersions of acid soluble solid particulates, dispersions of oil-soluble resins, and mixtures thereof.

14. The method of claim 1, wherein the removable sealing agent comprises a solid material comprising at least one of acid soluble cement, calcium carbonate, magnesium carbonate, polyesters, magnesium, aluminum, zinc, and their alloys,

20 hydrocarbons with greater than 30 carbon atoms, and carboxylic acids and derivatives thereof.

15. The method of claim 1 , wherein the removable sealing agent comprises manufactured shapes selected from at least one of particulates, sized particulates, fibers, flakes, rods, pellets and combinations thereof.

25 16. The method of claim 1 , wherein the removable sealing agent comprises a degradable composite material comprising a degradable polymer mixed with particles of a filler material.

17. The method of claim 1, wherein the sealing comprises placing the removable sealing agent in a desired zone in the .wellbore by at least one of

-30 bullheading the removable sealing agent downhole, spotting the removable sealing agent downhole, or using downhole containers to deliver the removable sealing agent.

18. The method of claim 17, wherein the sealing further comprises: injecting the sealing material into the selected zone by increasing pressure in the wellbore.

19. The method of claim 1, wherein at least one seal of the sealed zones are mechanically strengthened by compacting the seal with an epoxy resin gluing system or an emulsion comprising wax or paraffin.

20. The method of claim 1, wherein at least two zones are sealed with two distinct removable sealing agents which possess the capability of being removed by dissimilar removal processes.

21. The method of claim 1, further comprising sealing the treated zone(s) by at least one of plugging of the perforations and/or wellbore or annulus space between the casing and the borehole, reducing permeability of the formation rock, modifying the stress field, or changing formation fluid pressure.

22. A method for selective diversion during a multi-stage well treatment, comprising:

sealing all but one of a plurality of open zones of a wellbore with a removable sealing agent;

performing a treatment of the open zone while the other zones are sealed;

sealing the treated zone or isolating the section of the wellbore comprising the treated zone;

selectively removing the removable sealing agent from an untreated sealed zone; and

repeating the sequence of treating the unsealed zone while the other zones are sealed, sealing or isolating the treated zone, and selectively removing the removable sealing agent from an untreated sealed zone until the desired number of zones are treated.

23. A method of treating a subterranean formation, comprising:

sealing at least one previously treated zone of a wellbore with at least one removable sealing agent;

enabling access to at least one untreated zone within the wellbore; and

treating the accessed untreated zone.

24. The method of claim 23, further comprising sealing the treated accessed zone or isolating the portion of the wellbore comprising the treated accessed zone and then enabling access to and treating at least one other untreated zone within the wellbore.

25. The method of claim 23, further comprising selectively removing the removable sealing agent from at least one previously treated zone of the wellbore.

26. A method of treating a subterranean formation, comprising:

sealing at least one open zone of a . wellbore with at least one removable sealing agent while leaving at least one open zone unsealed;

treating at least one unsealed open zone while at least one other zone is sealed; and enabling access to at least one zone.

27. The method of treating a subterranean formation of claim 26, wherein enabling access comprises selectively removing the removable sealing agent from at least one zone.

28. The method of treating a subterranean formation of claim 26, wherein enabling access comprises perforating or jet perforating the wellbore at least one time or manipulating at least one sliding sleeve or wellbore casing valve within the wellbore.

29. The method of treating a subterranean formation of claim 26, wherein at least one of the open zones sealed with at least one removable sealing agent was treated prior to the sealing.