WO2014093069A1 - Packer material with cut fiber reinforcing agent - Google Patents

Abstract

A seal element for a packer having cut fiber reinforcing agent incorporated thereinto. The element may be for swell or mechanically compressible packers. Regardless, an enhanced degree of strength and sealability are simultaneously provided to the element and packer. That is, unique bonding characteristics of the cut fiber relative the underlying base polymer resin allow for an improvement in tensile strength without substantial compromise to swell or other type of expansive characteristics of the element. By way of contrast, the cut fiber additive may bond with the base polymer resin to a degree that is less than another incorporated cross-linking co-agent that may also be provided for purposes of enhancing tensile strength.

Description

PACKER MATERIAL WITH CUT FIBER REINFORCING AGENT

BACKGROUND

[0001] Exploring, drilling and completing hydrocarbon and other wells are generally complicated, time consuming, and ultimately very expensive endeavors. As a result, over the years, a significant amount of added emphasis has been placed on well monitoring and maintenance. By the same token, perhaps even more emphasis has been directed at initial well architecture and design. All in all, careful attention to design, monitoring and maintenance may help maximize production and extend well life. Thus, a substantial return on the investment in the completed well may be better ensured.

[0002] In the case of well monitoring and logging, mostly minimally-invasive applications may be utilized which provide temperature, pressure and other production related information. By contrast, well design, completion and subsequent maintenance, may involve a host of more direct interventional applications. For example, perforations may be induced in the wall of the well, debris or tools and equipment removed, etc. In some cases, the well may even be designed or modified such that entire downhole regions are isolated or closed off from production. Such is often the case where an otherwise productive well region is prone to produce water or other undesirable fluid that tends to hamper hydrocarbon recovery.

[0003] Regardless of the purpose, closing off well regions as noted above is generally achieved by way of setting one or more packers. Such packers may be set at downhole locations and serve to seal off certain downhole regions from others. Sealing in this manner is achieved by way of an elastomeric element of the packer which interfaces with a casing or formation defining the well wall. For example, in the case of a mechanical packer, the element may be compressibly expanded into interface with the wall whereas in the case of swell packers, a given period of exposure to well fluids may result in element expansion into such a sealable interfacing.

[0004] Whether of a mechanical or swellable variety, the packer generally achieves a seal sufficient for isolating the well as indicated, at least at the outset. For example, once set, an application that introduces high differential pressures may be performed in the isolated region. By way of a specific example, stimulation applications that present differentials far in excess of 10,000 PSI in the isolated region are often performed therein, immediately above the seal. However, due to the set seal, such an application may be run without undue concern over fluid migration out of the isolated region.

[0005] Unfortunately, while the packer may provide a sufficient seal at the outset, the material of the element will often begin to degrade and compromise seal performance over time. For example, in a matter of hours, the polymeric element material may begin to soften and decrease in tensile strength. Micro-cracks may begin to emerge and the seal is no longer maintained in the face of high pressure differentials. With continued reference to the example stimulation application, the introduction of high pressure into the isolated region may lead to extrusion and ultimate failure of the seal. This in turn may result in the operator having to remove and replace the packer and re-run the entire stimulation application. Ultimately this may translate into hundreds of thousands of dollars in lost time and equipment expenses.

[0006] Given the potential costs incurred due to packer failure, measures are generally undertaken to help extend the life of its polymeric seal element in the face of exposure to the downhole environment. Specifically, a host of different reinforcing agents are generally added to the polymer material during manufacture of the seal element. That is, while some ingredients may be added to protect the base polymer from breakdown during manufacture, others are added which are specifically introduced to subsequently prolong the life of the seal element in the face of the downhole environment. For example, cross-linking agents and initiators may be added to increase the robustness of the seal element, providing an anti-extrusion character to the seal element.

[0007] Unfortunately, adding anti-extrusion character to the seal element by way of cross-linking agents also affects the mechanical properties of the element in terms of providing an effective seal. That is, to the extent that such additives increase robustness or reduce element softness over time, they also tend to restrict swell and/or compressibility. Specifically, in the case of a compressibly expansive seal element for a mechanical packer, the added cross-linking may reduce the overall compressibility of the element and adversely affect the seal that is attained once the packer is set.

[0008] Even more notably, a swellable element of a swell packer may be dramatically affected by the introduction of cross-linking additive. This is due to the fact that a swell packer does not rely on mechanical compressibility. Rather, it is generally configured with an element capable of swelling to several times its originally manufactured size in order to seal off and isolate a well region. Thus, depending on the amount of cross-linking additive, the seal may be ineffective due to the lack of any underlying mechanical actuation for expanding the seal into interface with a well wall.

[0009] The sealing element of a packer is prone to failure over time in a well environment. Yet, the possibility of enhancing the robustness of the seal element is available through use of cross-linking additives. Ultimately, however, given that such agents tend to affect seal performance, the operator is left compromising between this performance and potential failure of the packer at some point in the future.

SUMMARY

[0010] A seal element is provided for use with a packer. The element includes a base resin material and a cut fiber additive to bond with the base resin. The additive and bonding thereof is configured to enhance the strength of the element as well as its sealing character. By way of contrast, cross-linking agent may also be provided that bonds to the base resin to a degree greater than the bond between the resin material and the additive. Additionally, the additive itself may be of a length to diameter ratio that is between about 10 and about 1,000.

[0011] The present disclosure is directed to an elastomeric material for a seal element. The material includes a base polymer resin and a cut fiber reinforcing additive to bond with the polymer resin for enhancing element strength and sealability.

[0012] In further embodiments, the present disclosure is directed to a packer isolation system for disposal in a well including a packer with a seal element having a base polymer resin with cut fiber additive for bonding with the polymer resin to enhance element modulus. The system also includes a treatment device adjacent the packer for delivery of a fluid to an isolated region of the well. A pressure rating of the packer for the isolating of the region is enhanced by the incorporation of the cut fiber additive.

[0013] In yet further embodiments, the present disclosure is directed to a method including incorporating a cut fiber reinforcing agent into a base polymer resin to form an elastomeric seal element, and assembling a packer of enhanced tensile strength and seal character with the seal element. The method also includes deploying the packer into a well, and expanding the packer into sealing engagement with a wall of the well to form an isolated region of the well thereat. The method also includes expanding one of a mechanically compressible expanding of the seal element and a swelling of the seal element. BRIEF DESCRIPTION OF THE DRAWINGS

[0014] Fig. 1A is an enlarged view of packer seal element material of the assembly taken from 1-1 of Fig. 2.

[0015] Fig. IB is a schematic view of the seal element material of Fig. 1A representing the interaction of cut fiber reinforcing agent with a base polymer.

[0016] Fig. 2 is an overview depiction of an oilfield with a well accommodating the assembly of Fig. 1 therein.

[0017] Fig. 3 is a side view of a swell packer assembly utilizing embodiments of seal elements with cut fiber reinforcing agent.

[0018] Fig. 4A is an enlarged view of another packer of the assembly of Fig. 2 deployed in the well and in an un-swollen state.

[0019] Fig. 4B is a depiction of the packer material of Fig. 4A shown in a swollen state to help isolate a region of the well.

[0020] Fig. 4C is a schematic depiction of the packer material of Fig. 4B during introduction of high differential pressure into the isolated region.

[0021] Fig. 5 is a flow-chart summarizing an embodiment of manufacturing and utilizing a packer having a seal element with cut fiber reinforcing agent therein.

DETAILED DESCRIPTION

[0022] Embodiments herein are described with reference to certain types of downhole operations. For example, these embodiments focus on the use of swell packers to support multi-zonal stimulation operations. However, a variety of alternative applications may employ seal element material types as detailed herein. For example, mechanically set packers may also make use of such seal element materials. Additionally, such packers may be utilized in operations other than stimulation operations. Regardless, embodiments of a packer seal element are provided that include a base resin material with cut fiber additives to enhance the strength thereof as well as its sealing character.

[0023] Referring now to Figs. 1A and IB, a detailed look at an embodiment of seal element material and behavior is described. More specifically, these figures are enlarged or 'close-up' views of seal element materials that are utilized in a downhole environment. For example, a seal element 155 of such materials which is part of a larger overall downhole assembly may be positioned adjacent a formation 197 for sake of well isolation. Indeed, the particular depictions of Figs. 1A and IB are enlargements taken from 1-1 of Fig. 2 which depicts such a larger overall assembly disposed in a well. As to the present depictions, Fig. 1A is an enlarged view of packer seal element material whereas, Fig. IB is a schematic view of this same seal element material that represents the interaction of cut fiber reinforcing agent 100 with a base polymer 150.

[0024] With specific reference to Fig. 1A, a seal element 155 of an enlarged packer is shown enlarged as indicated. Further, an adjacent well wall 187 which defines the formation may be a bit irregular. Nevertheless, the seal element 155 and underlying material are of a swellable design. Thus, the seal element 155 may readily be sealably swollen into tight interface with the well wall 187 in spite of the irregular morphology.

[0025] In Fig. 1A, the material of the packer seal element is shown in cross-section with an apparent fibrous texture. However, with reference to the more schematic representation of Fig. IB, the fibrous appearance of Fig. 1A is now replaced with representative cut fiber 100 dispersed throughout. While the addition of the cut fiber 100 does increase tensile strength of the material, it also bonds with the base polymer 150 in a comparatively weaker fashion. For example, in the embodiment shown, cross- linking agents 175 are also provided which further add to material tensile strength. These agents 175 may include six member oxygen or nitrogen rings and form a generally stronger bond and tighter knit with the base polymer 150. Thus, to the extent that cut fiber 100 is utilized in place of, or as a supplement to cross-linking agents 175, an intentionally weaker bond and looser matrix material may be attained. As a result, strength may be enhanced without substantial compromise to swellability.

[0026] Closer examination of the matrix-like schematic of Fig. IB, reveals cut fibers 100 that bond with base polymer chains 150 at certain locations 125. The cut fibers 100 may even intersect and bond with one another (120). Additionally, as with more traditional seal element materials, the base polymer 150 may be bonded to cross linking agents 175. These may in turn bond with other base polymers 150 and agents 175 forming a sophisticated interwoven polymer matrix which makes up a seal element 155 of the packer. However, the introduction of the cut fibers 100 allows for the matrix to display the character of enhanced strength and sealability at the well wall 187 simultaneously.

[0027] The cut fibers 100 may be considered "short" with a length (L) of under 100mm. In one embodiment, the length (L) is between about 0.1 micrometer and 6 mm. The diameter (D) of the fibers may be between about 1 nm and 500 micrometers (e.g. between 100 nm and 100 micrometers or from 0.5 to 50 micrometers). However, the diameter (D) is generally relational. That is, in terms of aspect ratio or length (L) to diameter (D), the ratio may be larger than 10. In one embodiment, the ratio is between 10 andlOOO.

[0028] As a matter of processing, the fibers 100 are cut or "chopped" before combining with the base polymer resin 150. They may be chopped from a variety of available fiber types. These may include aramid fiber, carbon fiber, polyethylene, polyethylene terephthalate, an aliphatic polyamide (i.e. Nylon), polyacryalonitrile, fiber glass, metal fibers and natural fibers (e.g. cotton, linen, wool).

[0029] Before use, however, the fibers 100 may be provided with a surface finish or treatment to enhance interaction with the base polymer 150. For example, a covering or coupling agent may be provided in the form of a silane with an alkyl, acryloxy, methacryloxy, epoxy or mercapto group. The silane may be γ- methacryloxypropyltrimethoxysilane, γ-acryloxypropyltrimethoxysilane, hexadecyl- trimethoxysilane, mercaptoproyltrimethoxysilane, 3 -glycidoxypropyltrimethoxysilane, bis(triethoxysilylpropyl)tetrasufide, 3 -thiocyanatopropyl-triethoxy silane, and/or bis- (dimethylethoxysilylpropyl)tetrasulfide.

[0030] In one embodiment, the fibers 100 are loaded to between about 0.1 phr (parts per hundred rubber) and about 50 phr with reference to the base polymer 150. For example, the fibers 100 may be between 1 and 20 phr. Additionally, as to fiber orientation, a random orientation may be utilized for swellable packer embodiments. However, axial or transverse orientation may also be specifically used as directed by certain extrusion dies during manufacture.

[0031] As to the base polymer 150, materials may be selected or tailored to swell upon exposure to downhole well fluids such as hydrocarbons and/or brine. Alternatively, the base polymer 150 may be configured to swell upon exposure to a fluid introduced from surface. Further, the polymer 150 may display rubber characteristics without swell, such as for use in mechanical packers. Regardless, such materials may include ethylene propylene diene monomer, ethylene propylene rubber, a nitrile rubber, natural rubber, polychloroprene, epichlorohydrin, polyacrylate rubber, ethylene-acrylate rubber, vinyl methyl silicone, fluoronated hydrocarbon, perfluorocarbon rubber, ethylene vinyl acetate, alkylated chlorosulfonated polyethylene, fluorosilicone rubber, and a tetrafluoroethylene propylene copolymer.

[0032] Continuing with reference to Figs. 1A and IB, the material of the seal element 155 may be formed in a variety of ways. In one embodiment, the cut fiber 100 and any cross-linking agents may be combined with initiators or other fillers and/or additives and then transfer molded with the base polymer 150 to form a seal element. Alternatively, conventional compression molding or mandrel wrapping techniques may be utilized. It is of note that to the extent that cut fiber 100 is utilized in place of continuous fiber or cross-linking agents, costs may be saved due to the greater degree of workability afforded by such fibers 100.

[0033] In one embodiment, the material mixture may be cured during transfer molding or compression molding or in an autoclave after mandrel wrapping. For example, a peroxide curative may be utilized in the form of 2,4-dichlorobenzoyl peroxide (DCBP), dibenzoyl peroxide(BP-50), dicumyl peroxide (DCP), 2,5-bis(tert- butylperoxy) 2,5-dimethyl-hexane (DBPH), di(4-methylbenzoyl) peroxide, Tert-butyl peroxybenzoate, di(tertbutylperoxyisopropyl) benzene, or di-tert-butyl peroxide. Alternatively, a sulfur curative may be used in the form of element sulfur and sulfur donor cure systems with accelerators. Common accelerators may include N- Oxydienthylene-2-benzothiazole sulfenamide, mercaptobenzothiazole, mercaptobenzthiazole disulfide, tetramethylthiuram disulfide, tetramethylthiuram disulfide, tetramethyl thiuram monosulphide, zinc-dibutyldithiocarbamate, zinc o,o- dibutyl Dithiophosphate.

[0034] Once formed, the material of the seal element will be enhanced in terms of tensile strength and modulus as noted above. In one embodiment, where the element is swellable, a swell of between about 50% and 125% may take place with no more than a 1/3 reduction in durometer (shore A) as compared to the virgin material. Quantifiably, this may likely translate to over 100% in elongation capacity to of the seal material (measured at break).

[0035] Referring now to Figs. 2 and 3, depictions are shown of larger overall environments in which such seal element materials may be utilized. Specifically, Fig. 2 is an overview depiction of an oilfield 200 and Fig. 3 is a side view of an isolation assembly 300 that includes the seal element 155 detailed hereinabove. That is, the oilfield 200 includes a well 280 which accommodates the assembly 300. Further, the assembly 300 is made up of packers 201, 205 that include seal elements 155, 375 for isolation of the well 280 as alluded to hereinabove.

[0036] With specific reference to the overview depiction of Fig. 2, the packers 201, 205 are of a swellable configuration and of simultaneously enhanced strength and sealability due to the unique use of cut fiber reinforcing agent 100 in the material of the elements 155, 375 (see also Fig. 3). Thus, these packers 201, 205 may be well suited for use in multi-zonal stimulation operations as depicted.

[0037] In the embodiment of Fig. 2, the packers 201, 205 are shown in a fully swelled or swollen state. In one embodiment, the packers 201, 205 include a built in swelling delay that retards swelling for a predetermined period of time. Thus, proper delivery and positioning may be achieved before substantial swelling. For example, in one embodiment, the well diameter may be between about 7 and 10 inches with the packers 201, 205 outfitted on 5-6 inch support tube mandrels 255, 279. In such an embodiment, the packers 201, 205 may be configured to achieve sealing in a matter of a few days, with a maximum swell completed at between one and two weeks.

[0038] The well 280 may be uncased or "open-hole" in the area accommodating the packers 201, 205. Thus, the well diameter may be a bit inconsistent or irregular. Nevertheless, attaining a complete seal is assured in spite of the use of reinforcing agent in packer element material. That is, the packers 201, 205 may be of enhanced strength while also swelling to a diameter (d) that fully reaches the well wall 187 and provides a reliably isolated region 281. This character of simultaneously enhanced strength and sealibility is a result of the cut fiber reinforcing agent 100 as noted above.

[0039] The well 280 of Fig. 2 traverses multiple formation layers 295, 197 and may include casing 285 in certain locations while remaining uncased in others as indicated above. In the embodiment shown, the well 280 extends into a horizontal terminal portion that is uncased and includes a production region 270 with perforations 275 extending into the surrounding formation 197. As indicated, the hardware installed in the well 280 is part of a multistage system for well stimulation. This may include use of the noted packers 201, 205 for defining the isolated region 281. Thus, a treatment device 225 may be used to deliver a stimulation fluid so as to enhance subsequent uptake of hydrocarbons and other production from the production region 270. For example, in one embodiment, a ball-drop technique may be used where a ball is dropped from the surface and through tubing 210 in order to open a valve in the device 225 and allow stimulation to proceed.

[0040] In the embodiment of Fig. 2, the packers 201, 205 are positioned as indicated and the system further includes the indicated tubing 210 running to the oilfield surface. Specifically, at the surface, equipment 240 is present, including a well head 230 for receiving the tubing 210. A fluid injection line 260 may run to the well head 230 for sake of delivering stimulation, acidizing or other fluids to the isolated region 281 downhole. Additionally, a production line 250 may emerge from the well head 250 for managing produced fluids from the region 281. Further, a rig 220 is shown to help support system installation and/or subsequent interventions.

[0041] Of course, the overview of equipment 240 and well architecture shown in Fig. 2 is for exemplary purposes. That is, a host of additional and/or different surface equipment may be provided to help in management of a wide variety of different types of wells that are able to take advantage of the depicted packer embodiments 101, 105.

[0042] With brief specific reference to Fig. 3, the isolation or "swell packer" assembly 300 alone is discussed. Namely, as indicated, the assembly 300 serves as part of a multistage system for well stimulation as described above. Thus, multiple packers 201, 205 are provided with swellable seal elements 155, 375, each supported about a central mandrel 255, 279. In addition to providing seal support, a mandrel 255, 279 may connect a packer 201 to well tubing 210 and/or a zonal treatment device 225. The mandrel 255, 279 may also include gauge rings for retaining each end of each seal element 155, 375. As noted, the system is directed at multistage stimulation. Thus, the treatment device 225 may include a section 330 with orifices 335 allowing the delivery of stimulation fluids into an isolated region 281 of a well 280 as shown in Fig. 2.

[0043] Again, the seal elements 155, 375 of the packers 201, 205 include cut fiber reinforcing agent 100 incorporated therein (see Fig. IB). As with other types of reinforcing agents, this will improve the modulus and tensile strength of the seal elements 155, 375. These elements 155, 375 may be rubber based or of a complex polymer base with properties similar to that of conventional rubber. Regardless, due to the use of reinforcing agents in the swell packers 201, 205, a higher pressure differential rating may be achieved. Additionally, the cut fiber reinforcing agent 100 also tends to enhance sealability of the packer elements 155, 375. Specifically, the noted improvement in strength is attained in a manner that does not substantially compromise swellability. As a result, the elements 155, 375 may have both a longer effective life in the well 280 with assured swell and sealing performance (see Fig. 2).

[0044] With such seal element material available for use in an isolation assembly 300 at an oilfield 200 as described hereinabove, the installation and use of a multi-zonal packer system is revisited. That is, Figs. 4A-4C show enlarged views of another packer seal element 375 of the system from the time of deployment into the well 280, to swelling and use during high pressure stimulation. Specifically, Fig. 4A, shows the element 375 in an un-swollen state as it is delivered to the production region 270 of Fig. 2. Fig. 4B shown the complete swelling of the element 375 and its sealing off of an isolated region 281 of the well 280. Specifically, as noted above, improved strength and sealability is available to the packer material due to the use cut fibers 100. Thus, with the packer element 375 fully swollen, the interface 400 between the well wall 187 and the packer element 375 may be reliably sealed. That is, both the integrity of the element 375 and the completed seal may be further assured.

[0045] In fact, with added reference to Fig. 4C, the element 375 and outer surface 475 thereof, may reliably withstand the introduction of high pressure fluid 450 into the isolated region 281. For example, as described hereinabove stimulation fluids 450 may introduce several thousand PSI of differential pressure into the region 281 for sake of stimulation. Yet, the performance of the short fiber 100, base polymer 150, cross-link agent 175 and overall packer material, is sufficient to keep the element 375 from extruding while maintaining sealability.

[0046] Referring now to Fig. 5, a flow-chart is shown that summarizes an embodiment of manufacturing and utilizing a packer having a seal element with cut fiber reinforcing agent therein. Primarily, as detailed hereinabove, a cut fiber reinforcing agent is incorporated into a base polymer matrix as indicated at 505. Thus, the strength of the material may be enhanced while also allowing enhancing salability and/or swellability of a seal element that is formed from the material. Similarly, cross- linking co-agent may be added as another measure of reinforcing agent (see 520).

[0047] As noted at 535 and 550, with the seal element formed, a packer may be assembled that utilizes the element and is available for deployment into a well. Thus, whether the seal element is swollen 565 or mechanically expanded 580, a region of the well may be isolated with the packer. Further, due to the short cut fiber reinforcing agent in the element, even high differential pressure applications may be performed in the isolated region without undue concern over packer or seal failure.

[0048] Embodiments described hereinabove provide packers with seal elements that include anti-extrusion characteristics. This may include traditional cross-linking and other additives but also includes cut fibers having unique bonding properties with base polymers of the seal element material. Namely, with such cut fibers incorporated, the strength of the element may be enhanced in terms of anti-extrusion character as noted and without any substantial compromise to swelling performance of the element. Thus, strength is enhanced along with the sealing character of the element. Enhancing of the sealing character occurs in the respect that the cut fiber additive is able to increase robustness and/or reduce softness of the element over time, thereby extending life and effective swellability. As a result, sealing performance of the element is ultimately enhanced and the life of the element extended. Stated another way, an operator may no longer be required to dramatically compromise seal performance in order to eliminate risk of mechanical failure of the packer.

[0049] The preceding description has been presented with reference to presently preferred embodiments. Persons skilled in the art and technology to which these embodiments pertain will appreciate that alterations and changes in the described structures and methods of operation may be practiced without meaningfully departing from the principle, and scope of these embodiments. Furthermore, the foregoing description should not be read as pertaining only to the precise structures described and shown in the accompanying drawings, but rather should be read as consistent with and as support for the following claims, which are to have their fullest and fairest scope.

Claims

CLAIMS We Claim:

1. An elastomeric material for a seal element, the material comprising:

a base polymer resin; and

a cut fiber reinforcing additive to bond with the polymer resin for enhancing element strength and sealability.

2. The material of claim 1 further comprising a cross-link agent to bond with the polymer resin to a degree greater than the bond between the polymer resin and the cut fiber additive.

3. The material of claim 1 wherein an orientation of the cut fiber additive is one of axial, transverse and random.

4. The material of claim 1 wherein fiber loading of the cut fiber additive relative the polymer resin is between about 1 and about 20 phr.

5. The material of claim 1 wherein the polymer resin is selected from a group consisting of ethylene propylene diene monomer rubber, ethylene propylene rubber, nitrile rubber, nitrile butadiene rubber, hydrogenated nitrile butadiene rubber, natural rubber, polychloroprene, epichlorohydrin, polyacrylate rubber, ethylene-acrylate rubber, vinyl methyl silicone, fluoronated hydrocarbon, perfluorocarbon rubber, ethylene vinyl acetate, alkylated chlorosulfonated polyethylene, fluorosilicone rubber, and a tetrafluoroethylene propylene copolymer.

6. The material of claim 1 wherein the cut fiber additive is selected from a group consisting of aramid fiber, carbon fiber, polyethylene, polyethylene terephthalate, an aliphatic polyamide, polyacryalonitrile, fiber glass, metal and natural fibers.

7. The material of claim 6 wherein the cut fiber additive is treated with a silane surface finishing agent.

8. The material of claim 1 wherein the cut fiber additive is of an aspect ratio that is between about 10 and aboutlOOO.

9. The material of claim 8 wherein individual fibers of the cut fiber additive are between about 0.1 micrometer and about 6 mm in length and about 0.5 micrometers and about 50 micrometers in diameter.

10. A packer isolation system for disposal in a well, the system comprising:

a packer with a seal element having a base polymer resin with cut fiber additive incorporated thereinto for bonding with the polymer resin to enhance element modulus; and

a treatment device adjacent the packer for delivery of a fluid to an isolated region of the well, a pressure rating of the packer for the isolating of the region enhanced by the incorporation of the cut fiber additive.

1 1. The system of claim 10 wherein the fluid delivered by the treatment device is one of a stimulation fluid and an acidizing agent.

12. The system of claim 10 wherein the packer is one of a swell packer and a mechanical packer.

13. The system of claim 12 wherein the packer is the swell packer and the isolated region of the well is uncased.

14. The system of claim 10 further comprising:

a mandrel to accommodate the packer thereabout; and

tubing coupled to one of the mandrel and the treatment device.

15. The system of claim 14 wherein the packer is a first packer, the system further comprising a second packer coupled to the tubing to define the isolated region between the first and second packers during the delivery of the fluid thereto.

16. A method comprising:

incorporating a cut fiber reinforcing agent into a base polymer resin to form an elastomeric seal element; and

assembling a packer of enhanced tensile strength and seal character with the seal element.

17. The method of claim 16 further comprising adding a cross-linking co-agent to the base polymer resin prior to the assembling of the packer, the co-agent to bond with the polymer resin to a greater degree than bonding of the polymer resin with the cut fiber.

18. The method of claim 16 wherein the assembling of the packer comprises forming of the seal element by one of transfer molding, compression molding and mandrel wrapping.

19. The method of claim 16 further comprising:

deploying the packer into a well; and

expanding the packer into sealing engagement with a wall of the well to form an isolated region of the well thereat, the expanding one of a mechanically compressible expanding of the seal element and a swelling of the seal element.

20. The method of claim 19 further comprising;

opening a valve in a treatment device adjacent the packer at the isolated region; and

performing a fluid pressurized application through the valve.