Methods and apparatus for fiber-based diversion

Abstract

Methods and apparatus are described for fiber-based fluid diversion in hydrocarbon-containing wells. One method embodiment of the invention comprises treating a first zone in a well; conveying a tool into the well, the tool carrying a composition comprising fibers; and activating the tool to deploy enough of the composition to form a fibrous plug and at least partially plug the first zone. The tool may be a positive displacement bailer, and an apparatus of the invention comprises a positive displacement bailer; the bailer comprising a compartment for holding a composition comprising fibers for forming fiber-based plugs in a well; the compartment partially defined by and cooperating with a positive displacement portion to expel and selectively deploy the composition in the well to form one or more fiber-based plugs in the well.

Description

CROSS-REFERENCE TO RELATED APPLICATIONS

The present application claims priority under 35 U.S.C. § 119(e) to U.S. Provisional Application Ser. No. 60/890,085, filed Feb. 15, 2007, incorporated by reference herein in its entirety.

BACKGROUND OF THE INVENTION

1. Field of Invention

The present invention provides efficient methods and apparatus of fiber-based fluid diversion in hydrocarbon-containing wells. More specifically, the present invention provides efficient methods and apparatus to treat multiple zones in hydrocarbon-containing wells by use of fiber-based diversion.

2. Related Art

A common technique for achieving zonal isolation useful for treating and/or completing wells having multiple pay zones is through use of a wireline deployable bridge plug such as is described in U.S. Pat. No. 6,708,768. The inherent disadvantage of bridge plugs is that they require setting and drill-out when used for more than one zone; hence increasing both time and cost of the operation.

An example operation is described in the below sequence that details the steps performed to treat and complete a multi-zone well using bridge plugs. In the below example, the bridge plug is of the “flow-thru” type that acts like a check valve providing positive hydraulic isolation when fluids are injected in a downward direction, but allows fluid passage therethrough in an upwards direction when fluids are produced from the formation. The example operational sequence is as follows:

• • 1. Run in hole with wireline guns and perforate the desired intervals;
  • 2. Run out of the hole with wire line and spent perforating guns;
  • 3. Fracture stimulate the perforated intervals;
  • 4. Flowback for about 1 hr to ensure minimum amount of proppant is left in the wellbore;
  • 5. Run in hole with bridge plug and guns for the second interval;
  • 6. Set the bridge plug above the zones fractured on step 3;
  • 7. Perforate the layers for the second fracture stage;
  • 8. Run out of the hole with spent perforating guns and wireline;
  • 9. Fracture stimulate the perforated intervals;
  • 10. Repeat 4-9 steps as many times as necessary.

Once the last fracture stage is pumped, operations cease for a few days or even weeks to flowback as much fracturing fluid injected as possible. After the flowback period, the next step is to mill out the bridge plugs by using a workover rig or coiled tubing. Finally production tubing is run in the wellbore and the well is connected to the flow line to start producing oil and/or gas.

There is thus a long-felt but as yet unmet need in the hydrocarbon production industry for improved methods and apparatus for treating and/or completing a well having multiple pay zones.

SUMMARY OF THE INVENTION

In accordance with the present invention, methods and apparatus for performing multi-zone well treatment operations are presented.

One aspect of the invention are methods for carrying and selectively deploying fiber-based plugs in wells, one embodiment comprising:

• • (a) treating a first zone in a well;
  • (b) conveying a tool into the well, the tool carrying a composition comprising fibers; and
  • (c) activating the tool to deploy enough of the composition to form a fibrous plug and at least partially plug the first zone.

Methods within the invention comprise (d) repeating steps (a) through (c) for at least one more zone, and methods wherein the treating comprises flowing a stimulation fluid through one or more previously formed perforations into channels. Other methods within the invention include those comprising injecting the stimulation fluid under pressure sufficient to fracture a formation which the well intersects, methods wherein the conveying a tool into the well comprises conveying a bailer, and methods wherein the bailer is a positive displacement bailer. In certain embodiments the bailer may be connected to and deployed on the distal end of a perforating gun.

Methods within the invention are particularly adept in delivery of fiber-based plugs, wherein the fibers of the composition are selected from degradable fibers, non-degradable fibers, fibers comprising a degradable portion and a non-degradable portion, and mixtures and combinations thereof. The fibers may be organic, inorganic, or combination thereof. The cross-sectional shape of the fibers may be any cross-section known or conceived. The fibers may be core-sheath, side-by-side, crimped, uncrimped, and the like. The fiber length may be staple fibers, longer than staple fibers, or mixture thereof.

In certain methods the composition may comprise non-fiber particulates. Suitable non-fiber particulates may be selected from organic materials, organometallic materials, inorganic materials, and combinations and mixtures thereof. Suitable inorganic materials may be selected from sand, ceramics, salts, and combinations and mixtures thereof. Suitable organic particulates include polymeric particulates, such as thermoplastics, thermosets, thermoplastic elastomers, adhesive particles, and the like. In certain embodiments the composition may comprise two or more particulates having different average particle sizes, or simply different sizes, which tends to increase the bridging characteristic of the compositions. In certain embodiments, a retainer/basket arrangement may be used to deposit the fiber-based composition in the well. The retainer/basket may be comprised of degradable materials as well. As used herein the term “degradable” means that the material referred to in the particular case may be dissolved, melted, or otherwise rendered incapable of supporting pressure or holding vacuum. “Dissolved” and “dissolvable” mean acid-, base-, and/or water-soluble. Non-limiting examples of compositions that may be dissolved by acid include materials selected from magnesium, aluminum, and the like.

Other methods of the invention include those wherein the conveying comprises stopping the tool adjacent the first zone, and the method comprises forming a fiber-based plug in the well adjacent the perforations using the composition, the comprising fibers having bridging characteristics.

Another aspect of the invention are apparatus useful for performing multi-zone well treatment operations, one apparatus comprising:

• • a positive displacement bailer;
  • the bailer comprising a compartment for holding a composition comprising fibers for forming fiber-based plugs in a well;
  • the compartment partially defined by and cooperating with a positive displacement portion to expel and selectively deploy the composition in the well to form one or more fiber-based plugs in the well.

Apparatus within the invention include those wherein the positive displacement bailer is connected to an end of a perforating gun. In other apparatus within the invention the positive displacement bailer may be connected to a wireline, coiled tubing, or a jetting device.

As used in herein, the phrase “composition comprising fibers” means a Newtonian or non-Newtonian fluid that is able to flow or be expelled from a compartment of a positive displacement bailer. A non-limiting list of suitable compositions for use in the invention may include slurries, gels, liquids, foams, and the like. An acceptable composition may differ from well to well, depending on such parameters as the time of the year; geographic location of the well; depth, pressure, and/or temperature of the zone or zones to be treated; compositions of the well fluids; customer requirements; laws and regulations, and the like. In certain embodiments the fibers are dispersible by water-based completion fluids and water-based well-stimulation fluids. Additionally, it should be understood that the term “fiber-based plug” encompasses all fiber-based plugs and compositions comprising fibers having bridging characteristics. As will be discussed below, the fiber-based compositions may additionally comprise materials that enhance the bridging such as different particle sizes of organic and/or inorganic materials, for example calcium carbonate, benzoic acid flakes, sand and ceramic proppants.

As used herein the terms “treat” and “treating” should be understood to encompass all known fracture or stimulation techniques and fluids. “Treating” may include exposing the formation to organic or inorganic compositions, chemical, physical, mechanical, and other conditions, or combination thereof, and either simultaneously or sequentially.

As used herein the phrase “activating the tool” includes, but is not limited to activation or actuation using hard-wired connections, wireless telemetry, fiber-optic cables, explosive shock, and the like.

Apparatus and methods of the invention allow the bailer to be run in hole along with the perforation guns, the ability to store enough fiber-based diverter composition for plugging multiple zones, the ability to place multiple fiber-based slugs to cover previously fracture stimulated layers, and the ability to be recharged with the fiber-based diverter on location.

Apparatus and methods of the invention will become more apparent upon review of the detailed description of the invention and the claims that follow.

BRIEF DESCRIPTION OF THE DRAWINGS

The manner in which the objectives of the invention and other desirable characteristics may be obtained is explained in the following description and attached drawing in which:

FIG. 1A is a schematic side elevation view, with parts broken away, illustrating an embodiment of the positive displacement bailer of the present invention, which may deliver a fiber-based plug on top of a retaining basket as illustrated in FIG. 1B;

FIGS. 2 through 6 illustrate an example operational sequence in accordance with methods of the present invention; and

FIG. 7 is a schematic logic diagram illustrating a method of the invention.

It is to be noted, however, that the appended drawings are not to scale and illustrate only typical embodiments of this invention, and are therefore not to be considered limiting of its scope, for the invention may admit to other equally effective embodiments.

DETAILED DESCRIPTION

In the following description, numerous details are set forth to provide an understanding of the present invention. However, it will be understood by those skilled in the art that the present invention may be practiced without these details and that numerous variations or modifications from the described embodiments may be possible.

In the specification and appended claims, the terms “connect”, “connection”, “connected”, “in connection with”, and “connecting” are used to mean “in direct connection with” or “in connection with via another element”; and the term “set” is used to mean “one element” or “more than one element”. As used herein, the terms “up” and “down”, “upper” and “lower”, “upwardly” and downwardly”, “upstream” and “downstream”; “above” and “below”; and other like terms indicating relative positions above or below a given point or element are used in this description to more clearly describe some embodiments of the invention. However, when applied to equipment and methods for use in wells that are deviated or horizontal, such terms may refer to a left to right, right to left, or other relationship as appropriate.

There are many applications in well drilling, servicing, and completion in which it becomes necessary to isolate particular zones within the well. In some applications, such as cased-hole situations, conventional bridge plugs such as the Baker Hughes model T, N1, NC1, P1, or S wireline-set bridge plugs are inserted into the well to isolate zones. The bridge plugs may be temporary or permanent; the purpose of the plugs is simply to isolate some portion of the well from another portion of the well. In some instances perforations in the well in one portion need to be isolated from perforations in another portion of the well. In other situations there may be a need to use a bridge plug to isolate the bottom of the well from the wellhead. There are also situations where these plugs are not used necessarily for isolation but instead are used to create a cement plug in the wellbore which may be used for permanent abandonment. In other applications a bridge plug with cement on top of it may be used as a kickoff plug for side-tracking the well. Bridge plugs may be drillable or retrievable. Brillable bridge plugs must be drilled out, and therefore are constructed of a brittle metal such as cast iron that can be drilled out. However, as rig time is typically charged for by the hour, it would be highly advantageous to avoid any drilling of bridge plugs.

The methods and apparatus of the invention are useful to efficiently treat multiple zones in oil or gas wells by using a fiber-based plug that is precisely positioned using a positive displacement bailer. In one embodiment, the positive displacement bailer is attached to the end of a perforating gun. An advantage of the inventive apparatus is the elimination of the need for hardware plugs, such as bridge plugs, to achieve zonal isolation for effective treatment. Removing the necessity of the hardware plugs reduces both time and cost of completion by eliminating the setting and drill out of bridge plugs.

The fiber-based plugs of the present invention comprise one or more fiber-based materials that may be used by themselves or in combination with particulates; in certain embodiments the particulates may comprise two or more particulates having different average particle sizes, or simply of different sizes. The particulates need not be any particular shape, and may be random or non-randomly shaped. The particulates may be round, ovoid, cubed, pellet-shaped, coated, non-coated, porous, non-porous, and the like. The plugs may be designed with one or more particulates and the composition of those particulates may be selected from inorganic materials, such as sand, ceramics, and salts, and organic materials such as benzoic acid flakes, thermoplastic polymers, thermoset polymers, elastomeric polymers, and the like, and polymers having a combination of these properties, such as thermoplastic elastomers. In certain embodiments, degradable materials may be used to minimize formation damage. Degradable materials include degradable fibers, thermoplastics and solid acids. As used herein the terms “polymer” and “polymeric” include thermoplastic, elastomeric, and, under certain conditions, thermosetting resins. The term includes polymers, oligomers, co-polymers, and the like, which may or may not be cross-linked. Polymers may be carbon chain polymers, heterochain polymers, combinations (co-polymers) thereof, and physical mixtures thereof. If two or more polymers are present, they may be physically mixed, and may be cross-linked via covalent bonds, ionic bonds, or both covalent and ionic bonds. The polymers may exist as a matrix for a curing agent or other active chemical specie, as a matrix for relatively inert ingredients, such as fillers, or both.

Referring now to the figures, where the same numerals are used throughout to indicate like components unless otherwise indicated, FIG. 1A illustrates one embodiment of a positive displacement bailer of the present invention, indicated generally by numeral 10. Bailer 10 in this embodiment is a positive displacement bailer, and has as its main components a bailer body 12 and a piston 14. Bailer body 12 defines two internal compartments 16 and 18 in this embodiment. Compartment 16 may hold a hydraulic fluid or some other working fluid, while compartment 18 is designed to hold composition which is deposited through one or more ports 20, 22, to form a fiber-based plug in accordance with the invention. Fiber-based plugs of the invention may be precisely positioned near perforations in casing 8 (as illustrated in FIGS. 2-6). Bailer 10 may also include threaded connection 24 for attaching a perforating tool (not illustrated in FIG. 1A), and a wire-line 26. In certain embodiments it may be useful to employ a retainer and basket arrangement as illustrated in FIG. 1B for supporting the deployed fiber-based plug. Basket 6 may be run in hole using the wireline 26. As illustrated, basket 6 seals against the inside of casing 8 at points 7 and 9 (multiple seal points may be present). Composition from bailer ports 20, 22 may be delivered into the basket and allowed to build up to a height determined by the particular situation. The use of a basket is optional and depends on the setting ability of the composition used to form the fiber-based plugs. If, for example, the composition is formulated to have a specific gravity close to or slight less than fluid in the well, it may be possible to “float” the composition in the well fluid and build up a mass of fibers, optionally with particulates, that bridges the well bore. Further discussion of this point may be seen herein below.

The positive displacement bailer 10 may be run along with the perforation guns, and chamber 18 may be sized so that it can store enough of the fiber-based material to place multiple fiber-based slugs to plug previously fractured zones. Piston 14 of positive displacement bailer 10 can be displaced multiple times to accommodate the multiple zone placement of the slugs. In addition, the positive displacement bailer 10 may be pre-loaded with the fiber-based material on location.

FIGS. 2 through 6 illustrate an example operational sequence in accordance with methods of the present invention. As illustrated in FIG. 2, during a first stage, multiple zones are perforated and treated, with perforations illustrated at 32 previously having been formed by a perforating gun 28 having a plurality of perforating charges 29, which may be selectively fired by an operator. The extent of the treatment fluid entry into the reservoir is illustrated schematically as plumes 30a, 30b, 30c, and so on. Fiber-based material plugs 31, 31a, 31b, 31c, 31d, and so on are spotted using the positive displacement bailer 10 to temporarily plug the treated zones. The length L of a first stage may range from about 50 to 200 ft, or from 100 to 200 ft, or from 125 ft to 175 ft, or in some embodiments may range from 140 ft to 160 ft, or from 148 ft to 152 ft. FIGS. 2, 3, 4, and 5 illustrate one, two, three, and four fiber-based plugs, respectively, spotted in casing 28 adjacent perforations 32. Once all of the zones of the first stage L have been plugged, the process is repeated for a second treating stage. The perforating gun 28 may then be removed, as illustrated in FIG. 6. It should be noted that in the embodiment illustrated in FIGS. 2 through 6 it may not always be necessary for the perforating gun string to be removed from the hole unless it is necessary for the positive displacement bailer to be recharged with more fiber-based material. For example, the perforating gun string may comprise multiple guns adapted to selectively fire when located in specific zones; thus removing the necessity to pull out of hole between each zone or stage.

An operational sequence of one method of the present invention is illustrated schematically as a logic diagram in FIG. 7. A first step is to run in hole with wireline the perforating guns and perforate the desired intervals; then run out of the hole with wireline; fracture stimulate the perforated intervals; flowback for about 1 hr to ensure minimum amount of proppant is left in the well bore; run in hole with the wire line deployable, positive displacement bailer and guns for the second interval; place a fiber-based plug in front of or above each previously fracture stimulated interval; perforate the layers for the second fracture stage; run out of the hole with wireline; and fracture stimulate the perforated intervals. The fiber-based plug will bridge in front of the perforations, preventing any re-fracture. The steps may be repeated as many times as necessary, or until there is no more composition in the bailer. Once last fracture stage is pumped, the well may be connected for clean up for few days or even weeks to flowback as much fracturing fluid injected as possible. A wellbore cleanout may then be conducted by either workover rig or coiled tubing using a jetting device. Finally production tubing is run in the wellbore.

Regarding the perforation operation, shaped charge perforating is commonly used, in which shaped charges are mounted in perforating guns that are conveyed into the well on a slickline, wireline, tubing, or another type of carrier. The perforating guns are then fired to create openings in the casing and to extend perforations as penetrations into the formation. In some cases wells may include a pre-pack comprising an oxidizer composition, and perforation may proceed through the pre-pack. These techniques may be used separately or in conjunction with shaped charges that include an oxidizer in the charge itself. Any type of perforating gun may be used. A first type, as an example, is a strip gun that includes a strip carrier on which capsule shaped charges may be mounted. The capsule shaped charges are contained in sealed capsules to protect the shaped charges from the well environment. Another type of gun is a sealed hollow carrier gun, which includes a hollow carrier in which non-capsule shaped charges may be mounted. The shaped charges may be mounted on a loading tube or a strip inside the hollow carrier. Thinned areas (referred to as recesses) may be formed in the wall of the hollow carrier housing to allow easier penetration by perforating jets from fired shaped charges. Another type of gun is a sealed hollow carrier shot-by-shot gun, which includes a plurality of hollow carrier gun segments in each of which one non-capsule shaped charge may be mounted.

Other downhole perforating mechanisms are described generally in U.S. Pat. No. 6,543,538. Alternative perforating devices include water and/or abrasive jet perforating, chemical dissolution, and laser perforating for the purpose of creating a flow path between the wellbore and the surrounding formation. Each individual gun may be on the order of 2 to 8 feet in length, and contain on the order of 8 to 20 perforating charges placed along the gun tube; as many as 15 to 20 individual guns could be stacked one on top of another such that the assembled gun system total length may be approximately 80 to 100 feet. This total gun length may be deployed in the wellbore using a surface crane and lubricator systems. Longer gun lengths could also be used, but would generally require additional or special equipment. The perforating device may be conveyed downhole by various means, such as electric line, wireline, slickline, conventional tubing, coiled tubing, and casing conveyed systems. The perforating device can remain in the hole after perforating the first zone and then be positioned to the next zone before, during, or after treatment of the first zone. There are numerous other patents describing perforating requiring either a mechanical device (such as a sliding sleeve), pumping fluid though a jetting device, perforating guns, or other downhole devices.

Alternatively, the well or portions thereof may be cased using pre-perforated casing and casing sections as described in assignee's co-pending U.S. patent application Ser. No. 11/769,284, filed Jun. 27, 2007, incorporated herein by reference, which describes providing a plurality of casing sections and a plurality of casing joints for joining the casing sections, the casing joints having a plurality of flow-through passages therethrough temporarily plugged with a composition, the composition independently selected for each casing joint; (b) forming a casing string comprising the casing sections and casing joints and running the casing string in hole; (c) exposing a first casing joint of the casing string to conditions sufficient to displace the composition from the flow-through passages in the first casing joint; (d) pumping a stimulation treatment fluid into a formation through the flow-through passages in the first casing joint; (e) plugging the flow-through passages in the first casing section; and (f) exposing a second casing joint of the casing string to conditions sufficient to displace the composition from the flow-through passages in the second casing joint. The flow-through passages may be formed by any known techniques, such as cutting, sawing, drilling, filing, and the like. The process of forming the flow-through passages may be manual, automated, or combination thereof. The dimensions and shapes of the flow-through passages may be any number of sizes and shapes, such as circular, oval, rectangular, rectangular with half circles on each end, slots, including slots angled to the longitudinal axis of the casing, and the like. The flow-through passages may surround the casing or casing joint in 60 degree (or other angle) phasing. The phasing may be 5, 10, 20, 30, 60, 75, 90, 120 degree phasing. In certain embodiments it may be desired to maximize the Area Open to Flow (AOF), in which case rectangular flow-through passages may be the best choice; however, these shapes may be more difficult to manufacture, and may present problems with mechanical strength of the pup joint. Circular flow-through passages would be easiest to make, but these sacrifice AOF due to the casing curvature. Slots and notches may be used in certain embodiments and allow covering the “weep hole” formed by pulsation of tubing while sand jetting. The slots in the casing, if used, could also be at an angle to the casing (not longitudinal with it). In certain embodiments, from 4 to 6 angled slots at the same depth around the casing may be used. In this way we would be more likely to get an opening in the casing that would align with the frac plane. Regarding the composition to temporarily fill the flow-through passages prior to treatment of the well, these may be inorganic materials, organic materials, mixtures of organic and inorganic, and the like. As used herein the term “filling” the flow-through passages may include a soluble “patch” over the flow-through passages (on inside or outside surface of the pipe). Non-limiting examples of compositions that may be dissolved by acid include materials selected from magnesium, aluminum, and the like. Reactive metals, earth metals, composites, ceramics, and the like may also be used. The composition should be able to hold pressure up to an absolute pressure of about 6,000 psi [41 megapascals], in certain embodiments up to about 7,000 psi [48 megapascals], in other embodiments up to about 8,000 psi [55 megapascals], in certain embodiments up to about 9,000 psi [62 megapascals], and in certain embodiments up to about 10,000 psi [68 megapascals].

Suitable degradable materials may be organic, inorganic, or combinations (mixtures) thereof. Examples of usable degradable organic materials are those that comprise aqueous phase-soluble polymers, for example polylactic acid, polyglycolic acid or copolymers thereof that are soluble in the aqueous phases in the subterranean environment. Other suitable degradable organic materials are oil-phase soluble materials, such as polystyrene and homologs thereof, derivatives of polystyrene and homologs thereof, and some low molecular weight polyolefin fibers and co-polymers thereof. Degradable organic materials useful in the invention may comprise physical mixtures of two or more aqueous-phase soluble polymers, two or more oil-phase soluble polymers, and mixtures of one or more aqueous-phase soluble polymers and one or more oil-phase soluble polymers.

Other suitable degradable organic materials include materials such as degradable simple carbohydrates such as sugars, also called saccharides, such as mono-, di-, and trisaccharides. Oligosaccharides are saccharides comprising up to eight units. Polysaccharides are polymeric saccharides having greater than eight subunits; natural polysaccharides generally comprise 10-3000 subunits. Examples of suitable monosaccharides include sucrose, fructose, ribulose, mannose, galactose, and glucose. Suitable disaccharides include those wherein the saccharide units are the same or different. An example of a disaccharide in which the subunits are the same is maltose, while lactose is an example of a disaccharide in which the two monosaccharide units are different. The saccharides may be in the pyranose form, the furanose form, or both.

If the additive comprises a saccharide, there are many options for first and second states; indeed, there may be many intermediate states. The easiest transition from a first state to a second state to visualize is the transition from a solid to a liquid. For example, the first state of the saccharide additive may be a solid, and the second state of the additive may be a dissolved version of the saccharide in water, as saccharides are extremely water-soluble due to their polyhydroxy nature. They tend to form viscous syrups that crystallize poorly. If the saccharide is a polysaccharide, it may be possible to controllably, gradually hydrolyze the molecules to oligo- and/or monosaccharides; for example the first state may be a polysaccharide having 20 subunits, and the second state may be an oligosaccharide having 8 or less subunits. Another second state may be one of the many chemical derivatives of saccharides, such as ethers, cyclic acetals, ketals, esters, alditols, aldonic acids, saccharic acids, dialdehydes, phyneylhydrazones, osazones, and the like, all of which may be formed from saccharides using well-known published techniques. For example, ethers may be formed from saccharides under mildly acidic conditions. In these reactions the OH group at the anomeric carbon is replaced by an alkoxy group. Cyclic acetals and ketals may be formed by reacting the saccharide 1,2-diols with an aldehyde or ketone under mildly acidic conditions. Esters (acetates) may be formed by reacting one or more of the saccharide OH groups with acetic anhydride and a mild basic catalyst such as sodium acetate or pyridine. Alditols such as D-mannitol may be produced by the sodium borohydride reduction of D-mannose. Aldonic and saccharic acids may be produced by oxidizing the saccharide employing bromine in a buffered solution at pH ranging from 5-6. Aqueous nitric acid may be used as a more vigorous oxidizing agent to form polyhydroxy dicarboxylic acids (called saccharic acids). Periodic acid (HIO₄) may be used to cleave saccharides to dialdehydes. These and other reactions of saccharides are discussed in standard textbooks, such as Streitwieser, Jr., et al., “Introduction to Organic Chemistry”, pp. 704-718 (1976), incorporated herein by reference.

Yet other suitable organic degradable additive embodiments are organic compounds, or mixtures thereof, that sublime at temperatures ranging from about 0° C. and higher in the presence of hydrocarbon gas streams. Example of these include camphor, naphthalene, benzaldehyde, mixtures thereof, and the like.

Salts of any of the above organic degradable additives may also be used.

Suitable inorganic degradable materials for use as additives in the invention are inorganic salts, for example sodium chloride, potassium chloride, ammonium carbonate, ammonium perchlorate, mixtures thereof, and the like.

Suitable degradable materials (fibers, particulates, casing flow-through passage filling, or any of these) include acid-, basic-, and/or water-soluble polymers, with or without inclusion of relatively insoluble materials, such as water-insoluble polymers, ceramics, fillers, and combinations thereof. Aluminum and magnesium bolts or plugs are one example of acid-soluble inorganic materials that may be used for casing flow-though passage filler. Compositions useful in the invention may comprise a water-soluble inorganic material, a water-soluble organic material, and combinations thereof. The water-soluble organic material may comprise a water-soluble polymeric material, for example, but not limited to poly(vinyl alcohol), poly(lactic acid), and the like. The water-soluble polymeric material may either be a normally water-insoluble polymer that is made soluble by hydrolysis of side chains, or the main polymeric chain may be hydrolysable.

The fiber-based plugs and casing flow-through passage fillers function to dissolve when exposed in a user controlled fashion to one or more activators. In this way, zones in a wellbore, or the wellbore itself or branches of the wellbore, may be treated for periods of time uniquely defined by the user. Suitable activators include chemicals, heat, light, pressure or some other activator or combination of activators useful in a variety of well treatment operations.

If the activator is a fluid composition, suitable fibers, particulates, and casing fillers useful in the invention include water-soluble materials selected from water-soluble inorganic materials, water-soluble organic materials, and combinations thereof. Suitable water-soluble organic materials may be water-soluble natural or synthetic polymers or gels. The water-soluble polymer may be derived from a water-insoluble polymer made soluble by main chain hydrolysis, side chain hydrolysis, or combination thereof, when exposed to a weakly acidic environment. Furthermore, the term “water-soluble” may have a pH characteristic, depending upon the particular polymer used.

Suitable water-insoluble polymers which may be made water-soluble by acid hydrolysis of side chains include those selected from polyacrylates, polyacetates, and the like and combinations thereof.

Suitable water-soluble polymers or gels include those selected from polyvinyls, polyacrylics, polyhydroxyacids, and the like, and combinations thereof.

Suitable polyvinyls include polyvinyl alcohol, polyvinyl butyral, polyvinyl formal, and the like, and combinations thereof. Polyvinyl alcohol is available from Celanese Chemicals, Dallas, Tex., under the trade designation Celvol. Individual Celvol polyvinyl alcohol grades vary in molecular weight and degree of hydrolysis. Molecular weight is generally expressed in terms of solution viscosity. The viscosities are classified as ultra low, low, medium and high, while degree of hydrolysis is commonly denoted as super, fully, intermediate and partially hydrolyzed. A wide range of standard grades is available, as well as several specialty grades, including polyvinyl alcohol for emulsion polymerization, fine particle size and tackified grades. Celvol 805, 823 and 840 polyvinyl alcohols are improved versions of standard polymerization grades—Celvol 205, 523 and 540 polyvinyl alcohols, respectively. These products offer a number of advantages in emulsion polymerization applications including improved water solubility and lower foaming. Polyvinyl butyral is available from Solutia Inc., St. Louis, Mo., under the trade designation BUTVAR. One form is Butvar Dispersion BR resin, which is a stable dispersion of plasticized polyvinyl butyral in water. The plasticizer level is at 40 parts per 100 parts of resin. The dispersion is maintained by keeping pH above 8.0, and may be coagulated by dropping the pH below this value. Exposing the coagulated version to pH above 8.0 would allow the composition to disperse, thus affording a control mechanism.

Suitable polyacrylics include polyacrylamides and the like and combinations thereof, such as N,N-disubstituted polyacrylamides, and N,N-disubstituted polymethacrylamides. A detailed description of physico-chemical properties of some of these polymers are given in, “Water-Soluble Synthetic Polymers: Properties and Behavior”, Philip Molyneux, Vol. I, CRC Press, (1983) incorporated herein by reference.

Suitable polyhydroxyacids may be selected from polyacrylic acid, polyalkylacrylic acids, interpolymers of acrylamide/acrylic acid/methacrylic acid, combinations thereof, and the like.

So-called “multicomponent” fibers may also be used in forming fiber-based plugs. By “multicomponent” fibers we mean fibers that have two or more distinct phases, regions, or chemical compositions; in other words, two or more regions that are distinct either physically, chemically, or both physically and chemically. Because multicomponent fibers have at least two distinct regions they may be engineered to have multiple beneficial properties, and these properties can be tuned to a greater extent than that of a single component material fiber. As one of many examples, the material in the inner core of a core-sheath fiber can be selected for strength, flexibility and robustness, while the outer layer can be selected for its adhesive qualities. As one of many examples, in the case of multicomponent fibers, the material in the inner core of a core-sheath fiber may be selected for strength, flexibility and robustness, while the outer layer may be selected for its adhesive qualities. As another example, a side-by-side bicomponent fiber may have one component selected for strength, flexibility and robustness, while the other component may be selected for its adhesive qualities. Other suitable multicomponent articles include those wherein the least robust material is enclosed in a more robust sheath; those wherein polymers such as PLA and polyglycolic acid is enclosed in a sheath comprised of polyester, polyamide, and/or polyolefin thermoplastic; those wherein a sensitive adhesive, for example a pressure-sensitive adhesive, temperature-sensitive adhesive, or moisture-sensitive adhesive, or curable adhesive is enclosed in a degradable sheath, such as a polymer sheath; and those wherein one of the components is selected to be tacky at a specific downhole temperature, such as the bottomhole static temperature (BHST), and have a modulus of less than 3×10⁶ dynes/cm² at a frequency of about 1 Hz, the tacky component and is embedded in a degradable polymer sheath.

Certain fluid compositions useful in forming fiber-based plugs of the invention may comprise proppant. Methods within this aspect of the invention include those wherein proppant is combined with the fluid composition prior to and/or during injecting the fluid composition into the wellbore. Other methods within the invention include those wherein the injecting comprises pumping the fluid composition into the wellbore under pressure, either with or without a proppant in the fluid composition.

When desired, proppant may be pumped into the formation, either combined with the compositions of the invention, or combined in situ. As has been indicated above, the function of a proppant is to “prop” the walls adjacent a fracture in a subterranean formation apart so that the fracture is not closed by the forces which are extent in the formation. It is advantageous for the walls adjacent the fracture to be “propped” apart so that the formation can be worked, usually to remove oil or natural gas. In general the fluid compositions, multicomponent articles therein, methods, and networks of the invention perform well with any known proppant, but may be particularly effective when using the least expensive proppant, siliceous sand. At greater stresses, it is believed, the sand particles are disintegrated, forming fines which then may plug the formation, reducing its permeability and resulting in costly well cleanouts, or even abandoning the well. This is discussed in U.S. Pat. No. 3,929,191, the disclosure of which is incorporated herein by reference. Sintered bauxite has also been used as a proppant, and may be preferable to siliceous sand because of its ability to withstand higher stresses without disintegration. However, sintered bauxite can be less desirable than siliceous sand as a proppant because it is substantially more expensive and is less generally available. The use of sintered bauxite as a proppant is disclosed in U.S. Pat. No. 4,068,718, the disclosure of which is incorporated herein by reference.

Other suitable proppants are described in U.S. Pat. Nos. 6,406,789; 6,582,819; and 6,632,527, the disclosures of which are incorporated herein by reference. As the '789 patent explains, three different types of propping materials, i.e., proppants, are currently employed. The first type of proppant is a sintered ceramic granulation/particle, usually aluminum oxide, silica, or bauxite, often with clay-like binders or with incorporated hard substances such as silicon carbide (e.g., U.S. Pat. No. 4,977,116 to Rumpf et al, incorporated herein by reference, EP Patents 0 087 852, 0 102 761, or 0 207 668). The ceramic particles have the disadvantage that the sintering must be done at high temperatures, resulting in high energy costs. The second type of proppant is made up of a large group of known propping materials from natural, relatively coarse, sands, the particles of which are roughly spherical, such that they can allow significant flow (English “frac sand”) (see U.S. Pat. No. 5,188,175 for the state of the technology). The third type of proppant includes samples of type one and two that may be coated with a layer of synthetic resin (U.S. Pat. No. 5,420,174 to Deprawshad et al; U.S. Pat. No. 5,218,038 to Johnson et al and U.S. Pat. No. 5,639,806 to Johnson et al (the disclosures of U.S. Pat. Nos. 5,420,174, 5,218,038 and 5,639,806, incorporated herein by reference); EP Patent No. 0 542 397). As discussed herein, in some hydraulic fracturing circumstances, the precured proppants in the well would flow back from the fracture, especially during clean up or production in oil and gas wells. Some of the proppant can be transported out of the fractured zones and into the well bore by fluids produced from the well. This transportation is known as flow back. Flowing back of proppant from the fracture is undesirable and has been controlled to an extent in some instances by the use of a proppant coated with a curable resin which will consolidate and cure underground. Phenolic resin coated proppants have been commercially available for some time and used for this purpose. Thus, resin-coated curable proppants may be employed to “cap” the fractures to prevent such flow back. The resin coating of the curable proppants is not significantly crosslinked or cured before injection into the oil or gas well. Rather, the coating is designed to crosslink under the stress and temperature conditions existing in the well formation. This causes the proppant particles to bond together forming a 3-dimensional matrix and preventing proppant flow back. These curable phenolic resin coated proppants work best in environments where temperatures are sufficiently high to consolidate and cure the phenolic resins. However, conditions of geological formations vary greatly. In some gas/oil wells, high temperature (>180° F. (82° C.) and high pressure (>6,000 psi (41 MPa)) are present downhole. Under these conditions, most curable proppants can be effectively cured. Moreover, proppants used in these wells need to be thermally and physically stable, i.e., do not crush appreciably at these temperatures and pressures. Curable resins include (i) resins which are cured entirely in the subterranean formation and (ii) resins which are partially cured prior to injection into the subterranean formation with the remainder of curing occurring in the subterranean formation. Many shallow wells often have downhole temperatures less than 130° F. (54° C.), or even less than 100° F. (38° C.).

Due to the diverse variations in geological characteristics of different oil and gas wells, no single proppant possesses all properties which can satisfy all operating requirements under various conditions. The choice of whether to use a precured or curable proppant or both is a matter of experience and knowledge as would be known to one skilled in the art. In use, the proppant is suspended in the fracturing fluid. Thus, interactions of the proppant and the fluid will greatly affect the stability of the fluid in which the proppant is suspended. The fluid needs to remain viscous and capable of carrying the proppant to the fracture and depositing the proppant at the proper locations for use. However, if the fluid prematurely loses its capacity to carry, the proppant may be deposited at inappropriate locations in the fracture or the well bore. This may require extensive well bore cleanup and removal of the mispositioned proppant. It is also important that the fluid breaks (undergoes a reduction in viscosity) at the appropriate time after the proper placement of the proppant. After the proppant is placed in the fracture, the fluid shall become less viscous due to the action of breakers (viscosity reducing agents) present in the fluid. This permits the loose and curable proppant particles to come together, allowing intimate contact of the particles to result in a solid proppant pack after curing. Failure to have such contact will give a much weaker proppant pack. Foam, rather than viscous fluid, may be employed to carry the proppant to the fracture and deposit the proppant at the proper locations for use. The foam is a stable foam that can suspend the proppant until it is placed into the fracture, at which time the foam breaks. Agents other than foam or viscous fluid may be employed to carry proppant into a fracture where appropriate. Also, resin coated particulate material, e.g., sands, may be used in a wellbore for “sand control.” In this use, a cylindrical structure is filled with the proppants, e.g., resin coated particulate material, and inserted into the wellbore to act as a filter or screen to control or eliminate backwards flow of sand, other proppants, or subterranean formation particles. Typically, the cylindrical structure is an annular structure having inner and outer walls made of mesh. The screen opening size of the mesh being sufficient to contain the resin coated particulate material within the cylindrical structure and let fluids in the formation pass therethrough.

In certain embodiments, the particulates employed may have a unimodal size distribution; in other embodiments a multimodal size distribution, such as bimodal, trimodal, and higher modalities. In other embodiments, the particulates may be polymeric, and may be designed to hold their shape up to a desired temperature, above which the particles deform. For example, a plurality of microspheres may deform to form a substantially continuous coating over fibers. Other polymeric microspheres may comprise one or more hydrocarbons, such as a relatively low molecular weight normal, branched, or cyclic alkanes, alkenes, alkynes, and the like, as well as aromatic compounds such as toluene, xylene, styrene, divinylbenzene, and the like. Some of these, such as styrene and divinylbenzene, may react to form an oligomer within the polymeric microsphere. Microspheres may have more than one of these features in a single microsphere; for example, a single microsphere may be both acid functionalized, have a degree of elasticity, and be bimodal in size distribution. Furthermore, in any single proppant particle, the microspheres may be substantially identical, or they vary widely in composition and properties.

Fluid compositions useful in methods of the invention may be used with and/or employ any of a number of well treatments or well completions. As used herein the terms “well completion” and “completion” are used as nouns except when referring to a completion operation. Well completions within the invention include, but are nor limited to, casing completions, commingled completions, hydraulic fracturing, coiled tubing completions, dual completions, high temperature completions, high pressure completions, high temperature/high pressure completions, multiple completions, natural completions, artificial lift completions, partial completions, primary completions, tubingless completions, and the like.

When a fluid having, a specific, controlled pH and temperature is pumped into the well, the fiber-based plugs will be exposed to the fluid and begin to degrade, depending on the composition and the fluid chosen. The degradation may be controlled in time to degrade quickly, for example over a few seconds or minutes, or over longer periods of time, such as hours or days. For example, a composition useful in the invention comprising fibers that dissolve at a temperature above reservoir temperature may be used to form a fiber-based plug, and subsequently exposed to a fluid pumped from the surface having a temperature above the reservoir temperature. The reverse may be desirable in other well treatment operations. The fiber-based plug may then be allowed to warm up to the pumped fluid temperature at the layer where treatment is taking place, allowing degradation of the fiber-based plug.

As noted previously, ingredients may be added to the composition dispensed from the positive displacement baler to facilitate the fiber-based plugs in bridging, such as expandable inorganic or organic materials. Examples of expandable materials are intumescent materials, where “intumescent” refers to a material which expands upon heating above about 100° C., although the temperature at which a particular intumescent material intumesces is dependent on the composition of that material. One useful intumescent material comprises a non-aqueous, indefinitely conformable, halogen-free, intumescent putty comprising a blend of intumescent material, rubber, and unvulcanized rubber, the rubber and unvulcanized rubber together provide the putty with a softness value of at least 4 mm (preferably, at least 4.5 mm; more preferably at least 5 mm; and even more preferably, at least 6 mm). Further, the putty is essentially free (i.e., contains less than 0.25 percent by weight) of a rubber curing agent. These putties are described in U.S. Pat. No. 5,578,671, assigned to Minnesota Mining and Manufacturing Company, St. Paul, Minn., incorporated herein by reference. In these intumescent compositions the rubber may be selected from natural rubber, butyl rubbers, polybutadiene rubbers, synthetic isoprene rubbers, styrene butadiene rubbers, ethylene acrylic rubbers, nitrile rubbers, urethane rubbers, ethylene vinyl acetate rubbers, and combinations thereof, and the unvulcanized rubber may be selected from unvulcanized natural rubber, unvulcanized butyl rubbers, unvulcanized polybutadiene rubbers, unvulcanized synthetic isoprene rubbers, unvulcanized styrene butadiene rubbers, unvulcanized ethylene acrylic rubbers, unvulcanized nitrile rubbers, unvulcanized urethane rubbers, unvulcanized ethylene vinyl acetate rubbers, and combinations thereof. Other intumescent compositions are described in U.S. Pat. Nos. 4,273,879; 4,952,615; and 5,175,197.

The term “reservoir” may include hydrocarbon deposits accessible by one or more wellbores. A “well” or “wellbore” includes cased, cased and cemented, or open-hole wellbores, and may be any type of well, including, but not limited to, a producing well, an experimental well, an exploratory well, and the like. Wellbores may be vertical, horizontal, any angle between vertical and horizontal, diverted or non-diverted, and combinations thereof, for example a vertical well with a non-vertical component.

As will be readily apparent to those skilled in the art, the present invention may easily be produced in other specific forms without departing from its spirit or essential characteristics. The present embodiments are, therefore, to be considered as merely illustrative and not restrictive, the scope of the invention being indicated by the claims rather than the foregoing description, and all changes which come within the meaning and range of equivalence of the claims are therefore intended to be embraced therein. Although only a few exemplary embodiments of this invention have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible in the exemplary embodiments without materially departing from the novel teachings and advantages of this invention. Accordingly, all such modifications are intended to be included within the scope of this invention as defined in the following claims. Although the above described examples of the present invention are directed toward wire line methods and apparatus, one skilled in the art will recognize that the present invention has equal applicability to coiled tubing or slickline operations. For example, the positive displacement bailer of the present invention could be attached to a jetting head deployed on coiled tubing and used in a multi-zone stimulation operation where either the zones have already been perforated or the jetting head is used to perform jet perforating operations.

Claims

1. A method of fluid diversion in a well, comprising:

(a) treating a first zone in a well;

(b) conveying a tool into the well, the tool carrying a composition comprising fibers; and

(c) activating the tool to deploy enough of the composition to form a fibrous plug and at least partially plug the first zone.

2. The method of claim 1, comprising (d) repeating steps (a) through (c) for at least one more zone.

3. The method of claim 1, wherein the treating comprises flowing a stimulation fluid through one or more previously formed perforations into channels.

4. The method of claim 3 comprising injecting the stimulation fluid under pressure sufficient to fracture a formation which the well intersects.

5. The method of claim 1 wherein the conveying a tool into the well comprises conveying a bailer.

6. The method of claim 5 wherein the bailer is a positive displacement bailer.

7. The method of claim 5 comprising conveying the bailer on the distal end of a perforating gun.

8. The method of claim 1 wherein the fibers of the composition are selected from degradable fibers, non-degradable fibers, fibers comprising a degradable portion and a non-degradable portion, and mixtures and combinations thereof.

9. The method of claim 1 wherein the composition comprises non-fiber particulates.

10. The method of claim 9 wherein the non-fiber particulates are selected from organic materials, organometallic materials, inorganic materials, and combinations and mixtures thereof.

11. The method of claim 10 wherein the inorganic materials are selected from sand, ceramics, salts, and combinations and mixtures thereof.

12. The method of claim 3 wherein the conveying comprises stopping the tool adjacent the first zone, the composition comprises fibers having bridging characteristics, and the method comprises forming a fiber-based plug in the well adjacent the perforations.

13. A method for performing multi-zone well treatment operations, comprising:

(a) treating a first zone in a well by flowing a completion or stimulation fluid through one or more previously formed perforations into channels;

(b) conveying a bailer on the distal end of a perforating gun into the well using a conveying device selected from slickline, wireline, coiled tubing, and jointed tubing, the bailer carrying a composition comprising water-dispersible fibers;

(c) stopping the bailer adjacent the first zone;

(d) activating the bailer to deploy enough of the composition to form a fiber-based plug and at least partially plug the first zone; and

(e) repeating steps (a) through (d) for at least one more zone.

14. The method of claim 13 wherein the bailer is a positive displacement bailer.

15. The method of claim 13 wherein the composition comprises fibers having bridging characteristics and at least two particulates having different particle sizes, and the method comprises forming a fiber-based plug in the well adjacent the perforations of the first zone and said at least one other zone.

16. An apparatus useful for performing multi-zone well treatment operations, the apparatus comprising:

a positive displacement bailer;

the bailer comprising a compartment for holding a composition comprising fibers for forming fiber-based plugs in a well;

the compartment partially defined by and cooperating with a positive displacement portion to expel and selectively deploy the composition in the well to form one or more fiber-based plugs in the well.

17. The apparatus of claim 16 wherein the positive displacement bailer is connected to an end of a perforating gun.

18. The apparatus of claim 16 wherein the positive displacement bailer is attached to and deployable by a wireline.

19. The apparatus of claim 16 wherein the positive displacement bailer is attached to and deployable by coiled tubing.

20. The apparatus of claim 16 wherein the positive displacement bailer is attached to a jetting device.