An embodiment of a well bore servicing apparatus includes a housing having a through bore and at least one high pressure fluid aperture in the housing, the fluid aperture being in fluid communication with the through bore to provide a high pressure fluid stream to the well bore, and a removable member coupled to the housing and disposed adjacent the fluid jet forming aperture and isolating the fluid jet forming aperture from an exterior of the housing. An embodiment of a method of servicing a well bore includes applying a removable member to an exterior of a well bore servicing tool, wherein the removable member covers at least one high pressure fluid aperture disposed in the tool, lowering the tool into a well bore, exposing the tool to a well bore material, wherein the removable cover prevents the well bore material from entering the fluid aperture, removing the removable member to expose a fluid flow path adjacent an outlet of the high pressure fluid aperture, and flowing a well bore servicing fluid through the fluid aperture outlet and flow path.

CROSS-REFERENCE TO RELATED APPLICATIONS 
     This is a Divisional Application of U.S. patent application Ser. No. 11/833,802, filed Aug. 3, 2007 and published as US 2009/032255 A1, and entitled “Method and Apparatus for Isolating a Jet Forming Aperture in a Well Bore Servicing Tool,” which is hereby incorporated by reference herein in its entirety. 
    
    
     BACKGROUND 
     Hydrocarbon-producing wells often are stimulated by hydraulic fracturing operations, wherein a fracturing fluid may be introduced into a portion of a subterranean formation penetrated by a well bore at a hydraulic pressure sufficient to create or enhance at least one fracture therein. Stimulating or treating the well in such ways increases hydrocarbon production from the well. 
     In some wells, it may be desirable to individually and selectively create multiple fractures along a well bore at a distance apart from each other. The multiple fractures should have adequate conductivity, so that the greatest possible quantity of hydrocarbons in an oil and gas reservoir can be drained/produced into the well bore. When stimulating a reservoir from a well bore, especially those well bores that are highly deviated or horizontal, it may be difficult to control the creation of multi-zone fractures along the well bore without cementing a casing or liner to the well bore and mechanically isolating the subterranean formation being fractured from previously-fractured formations, or formations that have not yet been fractured. 
     To avoid explosive perforating steps and other undesirable actions associated with fracturing, certain tools may be placed in the well bore to place fracturing fluids under high pressure and direct the fluids into the formation. In some tools, high pressure fluids may be “jetted” into the formation. For example, a tool having jet forming nozzles, also called a “hydrojetting” or “hydrajetting” tool, may be placed in the well bore near the formation. Hydrojetting may also be referred to as a process of controlling high pressure fluid jets with surgical accuracy. The jet forming nozzles create a high pressure fluid flow path directed at the formation of interest. In another tool, which may be called a casing window, a stimulation sleeve, or a stimulation valve, a section of casing includes holes or apertures pre-formed in the casing. The casing window may also include an actuatable window assembly for selectively exposing the casing holes to a high pressure fluid inside the casing. The casing holes may include jet forming nozzles to provide a fluid jet into the formation, causing tunnels and fractures therein. 
     SUMMARY OF THE INVENTION 
     An embodiment of a well bore servicing apparatus includes a housing having a through bore and at least one high pressure fluid aperture in the housing, the fluid aperture being in fluid communication with the through bore to provide a high pressure fluid stream to the well bore, and a removable member coupled to the housing and disposed adjacent the fluid jet forming aperture and isolating the fluid jet forming aperture from an exterior of the housing. In other embodiments, the removable member is a degradable sleeve removed by degradation. Still other embodiments include a jet forming nozzle in the high pressure fluid aperture. 
     An embodiment of a method of servicing a well bore includes applying a removable member to an exterior of a well bore servicing tool, wherein the removable member covers at least one high pressure fluid aperture disposed in the tool, lowering the tool into a well bore, exposing the tool to a well bore material, wherein the removable cover prevents the well bore material from entering the fluid aperture, removing the removable member to expose a fluid flow path adjacent an outlet of the high pressure fluid aperture, and flowing a well bore servicing fluid through the fluid aperture outlet and flow path. In other embodiments, removing the removable member includes degrading a protective sleeve. In yet other embodiments, flowing the well bore servicing fluid further expands the fluid flow path adjacent the tool, into the surrounding formation, or both. 
     Another embodiment of a method of servicing a well bore includes disposing a fluid jetting tool in the well bore, the fluid jetting tool having a fluid jetting aperture and a removable member adjacent the fluid jetting aperture, cementing the fluid jetting tool into the well bore, wherein the removable member prevents cement from entering the fluid jetting aperture, and removing the removable member to expose a fluid flow path adjacent an outlet of the fluid jetting aperture. Other embodiments include pumping a well bore servicing fluid into the fluid jetting tool and through the fluid jetting aperture, and perforating the cement to further expand the fluid flow path. Still other embodiments include continuing to pump the servicing fluid into a formation adjacent the perforated cement to fracture the formation. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       For a more detailed description of the embodiments, reference will now be made to the following accompanying drawings: 
         FIG. 1  is a schematic, partial cross-section view of a fluid stimulation tool in an operating environment; 
         FIG. 2  is a cross-section view of a hydrojetting tool assembly; 
         FIG. 3  is a cross-section view of a fluid pressurizing well completion assembly; 
         FIG. 4A  is a partial cross-section view of a hydrojetting casing window assembly; 
         FIG. 4B  is a partial cross-section view of the casing window assembly of  FIG. 4A  in a shifted position; 
         FIG. 5  is a partial cross-section view of a well completing assembly including embodiments of  FIGS. 4A and 4B ; 
         FIG. 6A  is a partial cross-section view of an exemplary fluid jetting window assembly in an open position; 
         FIG. 6B  is a partial cross-section view of an embodiment of the assembly of  FIG. 6A  in a closed position; 
         FIG. 6C  is a partial cross-section view of an embodiment of the assembly of  FIG. 6B  showing removal of a removable member; 
         FIG. 6D  is a partial cross-section view of an embodiment of the assembly of  FIG. 6C  showing fracturing; 
         FIG. 6E  is a partial cross-section view of an embodiment of the assembly of  FIG. 6D  moved to a closed position; and 
         FIG. 7  is a partial cross-section view of an alternative embodiment of the fluid jetting window assembly of  FIG. 6A . 
     
    
    
     DETAILED DESCRIPTION 
     In the drawings and description that follows, like parts are marked throughout the specification and drawings with the same reference numerals, respectively. The drawing figures are not necessarily to scale. Certain features of the invention may be shown exaggerated in scale or in somewhat schematic form and some details of conventional elements may not be shown in the interest of clarity and conciseness. The present invention is susceptible to embodiments of different forms. Specific embodiments are described in detail and are shown in the drawings, with the understanding that the present disclosure is to be considered an exemplification of the principles of the invention, and is not intended to limit the invention to that illustrated and described herein. It is to be fully recognized that the different teachings of the embodiments discussed below may be employed separately or in any suitable combination to produce desired results. Unless otherwise specified, any use of any form of the terms “connect”, “engage”, “couple”, “attach”, or any other term describing an interaction between elements is not meant to limit the interaction to direct interaction between the elements and may also include indirect interaction between the elements described. In the following discussion and in the claims, the terms “including” and “comprising” are used in an open-ended fashion, and thus should be interpreted to mean “including, but not limited to . . . ”. Reference to up or down will be made for purposes of description with “up”, “upper”, “upwardly” or “upstream” meaning toward the surface of the well and with “down”, “lower”, “downwardly” or “downstream” meaning toward the terminal end of the well, regardless of the well bore orientation. The various characteristics mentioned above, as well as other features and characteristics described in more detail below, will be readily apparent to those skilled in the art upon reading the following detailed description of the embodiments, and by referring to the accompanying drawings. 
     Disclosed herein are several embodiments of fracturing or stimulation tools wherein pressurized fluid is directed or jetted through fluid apertures into an earth formation to create and extend fractures in the earth formation, or otherwise extend a flow path from the tool to the formation. Also disclosed are several embodiments of a removable member disposed over the fluid apertures, particularly jet forming nozzles, for example, to isolate the fluid apertures from an exterior environment of the tool. The exterior environment of the tool may include cement or other viscous, aperture-plugging materials that negatively effect the pressurizing or jetting nature of the apertures. As disclosed herein, exemplary embodiments of the removable member include a degradable sleeve wrapped around a portion of the tool housing having the fluid apertures. A degradable sleeve can comprise a variety of materials, as disclosed below. Also disclosed herein are operations of a fluid pressurizing or jetting tool including the removable member disposed over the fluid apertures to isolate such apertures from materials that may encumber or obstruct the fluid apertures. As disclosed, the operations of the fluid pressurizing or jetting tools may include a complete well servicing or treatment process to adequately fracture the earth formation. 
       FIG. 1  schematically depicts an exemplary operating environment for a fluid pressurizing or hydrojetting tool  100  for fracturing an earth formation F. As disclosed below, there are many embodiments of the fluid pressurizing or hydrojetting tool  100 , but for reference purposes, the schematic tool  100  will be called the “fluid stimulation tool  100 .” As depicted, a drilling rig  110  is positioned on the earth's surface  105  and extends over and around a well bore  120  that penetrates a subterranean formation F for the purpose of recovering hydrocarbons. The well bore  120  may drilled into the subterranean formation F using conventional (or future) drilling techniques and may extend substantially vertically away from the surface  105  or may deviate at any angle from the surface  105 . In some instances, all or portions of the well bore  120  may be vertical, deviated, horizontal, and/or curved. 
     At least the upper portion of the well bore  120  may be lined with casing  125  that is cemented  127  into position against the formation F in a conventional manner. Alternatively, the operating environment for the fluid stimulation tool  100  includes an uncased well bore  120 . The drilling rig  110  includes a derrick  112  with a rig floor  114  through which a work string  118 , such as a cable, wireline, E-line, Z-line, jointed pipe, coiled tubing, or casing or liner string (should the well bore  120  be uncased), for example, extends downwardly from the drilling rig  110  into the well bore  120 . The work string  118  suspends a representative downhole fluid stimulation tool  100  to a predetermined depth within the well bore  120  to perform a specific operation, such as perforating the casing  125 , expanding a fluid path therethrough, or fracturing the formation F. The drilling rig  110  is conventional and therefore includes a motor driven winch and other associated equipment for extending the work string  118  into the well bore  120  to position the fluid stimulation tool  100  at the desired depth. 
     While the exemplary operating environment depicted in  FIG. 1  refers to a stationary drilling rig  110  for lowering and setting the fluid stimulation tool  100  within a land-based well bore  120 , one of ordinary skill in the art will readily appreciate that mobile workover rigs, well servicing units, such as slick lines and e-lines, and the like, could also be used to lower the tool  100  into the well bore  120 . It should be understood that the fluid stimulation tool  100  may also be used in other operational environments, such as within an offshore well bore or a deviated or horizontal well bore. 
     The fluid stimulation tool  100  may take a variety of different forms. In an embodiment, the tool  100  comprises a hydrojetting tool assembly  150 , which in certain embodiments may comprise a tubular hydrojetting tool  140  and a tubular, ball-activated, flow control device  160 , as shown in  FIG. 2 . The tubular hydrojetting tool  140  generally includes an axial fluid flow passageway  180  extending therethrough and communicating with at least one angularly spaced lateral port  142  disposed through the sides of the tubular hydrojetting tubular hydrojetting tool  140 . In certain embodiments, the axial fluid flow passageway  180  communicates with as many angularly spaced lateral ports  142  as may be feasible, (e.g., a plurality of ports). A fluid jet forming nozzle  170  generally is connected within each of the lateral ports  142 . As used herein, the term “fluid jet forming nozzle” refers to any fixture that may be coupled to an aperture so as to allow the communication of a fluid therethrough such that the fluid velocity exiting the jet is higher than the fluid velocity at the entrance of the jet. In certain embodiments, the fluid jet forming nozzles  170  may be disposed in a single plane that may be positioned at a predetermined orientation with respect to the longitudinal axis of the tubular hydrojetting tool  140 . Such orientation of the plane of the fluid jet forming nozzles  170  may coincide with the orientation of the plane of maximum principal stress in the formation to be fractured relative to the longitudinal axis of the well bore penetrating the formation. 
     The tubular, ball-activated, flow control device  160  generally includes a longitudinal flow passageway  162  extending therethrough, and may be threadedly connected to the end of the tubular hydrojetting tool  140  opposite from the work string  118 . The longitudinal flow passageway  162  may comprise a relatively small diameter longitudinal bore  164  through an exterior end portion of the tubular, ball-activated, flow control device  160  and a larger diameter counter bore  166  through the forward portion of the tubular, ball-activated, flow control device  160 , which may form an annular seating surface  168  in the tubular, ball-activated, flow control device  160  for receiving a ball  172 . Before ball  172  is seated on the annular seating surface  168  in the tubular, ball-activated, flow control device  160 , fluid may freely flow through the tubular hydrojetting tool  140  and the tubular, ball-activated, flow control device  160 . After ball  172  is seated on the annular seating surface  168  in the tubular, ball-activated, flow control device  160  as illustrated in  FIG. 2 , flow through the tubular, ball-activated, flow control device  160  may be terminated, which may cause fluid pumped into the work string  118  and into the tubular hydrojetting tool  140  to exit the tubular hydrojetting tool  140  by way of the fluid jet forming nozzles  170  thereof. When an operator desires to reverse-circulate fluids through the tubular, ball-activated, flow control device  160 , the tubular hydrojetting tool  140  and the work string  118 , the fluid pressure exerted within the work string  118  may be reduced, whereby higher pressure fluid surrounding the tubular hydrojetting tool  140  and tubular, ball-activated, flow control device  160  may flow freely through the tubular, ball-activated, flow control device  160 , causing the ball  172  to disengage from annular seating surface  168 , and through the fluid jet forming nozzles  170  into and through the work string  118 . 
     The hydrojetting tool assembly  150 , schematically represented at  100  in  FIG. 1 , may be moved to different locations in the well bore  120  by using work string  118 . Work string  118  also carries the fluid to be jetted through jet forming nozzles  170 . During use, the hydrojetting tool assembly  150  may be exposed to a variety of hindrances or nozzle plugging materials. Therefore, it is desirable to maintain unhindered jet forming nozzles  170  such that successful fluid jets are created each time the tool assembly  150  is used. 
     Referring now to  FIG. 3 , in another embodiment, the schematic fluid jetting tool  100  comprises an exemplary well completion assembly  200 . The well completion assembly  200  is disposed in the well bore  120  coupled to the surface  105  and extending down through the subterranean formation F. The completion assembly  200  includes a conduit  208  extending through at least a portion of the well bore  120 . The conduit  208  may or may not be cemented to the subterranean formation F. In some embodiments, the conduit  208  is a portion of a casing string coupled to the surface  105  by an upper casing string, represented schematically by work string  118  in  FIG. 1 . Cement is flowed through an annulus  222  to attach the casing string to the well bore  120 . In some embodiments, the conduit  208  may be a liner that is coupled to a previous casing string. When uncemented, the conduit  208  may contain one or more permeable liners, or it may be a solid liner. As used herein, the term “permeable liner” includes, but is not limited to, screens, slots and preperforations. Those of ordinary skill in the art, with the benefit of this disclosure, will recognize whether the conduit  208  should be cemented or uncemented and whether conduit  208  should contain one or more permeable liners. 
     The conduit  208  includes one or more pressurized fluid apertures  210 . Fluid apertures  210  may be any size, for example, 0.75 inches in diameter. In some embodiments, the fluid apertures  210  are jet forming nozzles, wherein the diameter of the jet forming nozzles are reduced, for example, to 0.25 inches. The inclusion of jet forming nozzles  210  in the well completion assembly  200  adapts the assembly  200  for use in hydrojetting. In some embodiments, the fluid jet forming nozzles  210  may be longitudinally spaced along the conduit  208  such that when the conduit  208  is inserted into the well bore  120 , the fluid jet forming nozzles  210  will be adjacent to a local area of interest, e.g., zones  212  in the subterranean formation F. As used herein, the term “zone” simply refers to a portion of the formation and does not imply a particular geological strata or composition. Conduit  208  may have any number of fluid jet forming nozzles, configured in a variety of combinations along and around the conduit  208 . 
     Once the well bore  120  has been drilled and, if deemed necessary, cased, a fluid  214  may be pumped into the conduit  208  and through the fluid jet forming nozzles  210  to form fluid jets  216 . In one embodiment, the fluid  214  is pumped through the fluid jet forming nozzles  210  at a velocity sufficient for the fluid jets  216  to form perforation tunnels  218 . In one embodiment, after the perforation tunnels  218  are formed, the fluid  214  is pumped into the conduit  208  and through the fluid jet forming nozzles  210  at a pressure sufficient to form cracks or fractures  220  along the perforation tunnels  218 . 
     The composition of fluid  214  may be changed to enhance properties desirous for a given function, i.e., the composition of fluid  214  used during fracturing may be different than that used during perforating. In certain embodiments, an acidizing fluid may be injected into the formation F through the conduit  208  after the perforation tunnels  218  have been created, and shortly before (or during) the initiation of the cracks or fractures  220 . The acidizing fluid may etch the formation F along the cracks or fractures  220 , thereby widening them. In certain embodiments, the acidizing fluid may dissolve fines, which further may facilitate flow into the cracks or fractures  220 . In another embodiment, a proppant may be included in the fluid  214  being flowed into the cracks or fractures  220 , which proppant may prevent subsequent closure of the cracks or fractures  220 . The proppant may be fine or coarse. In yet another embodiment, the fluid  214  includes other erosive substances, such as sand, to form a slurry. Complete well treatment processes including a variety of fluids and fluid particulates may be understood with reference to Halliburton Energy Service's SURGIFRAC® and COBRAMAX®. The fluid component embodiments described above may be used in various combinations with each other and with the other embodiments disclosed herein. 
     Referring now to  FIGS. 4A and 4B , an exemplary casing window assembly  300  is shown as adapted for use in the well completion assembly  200 . As used herein, the term “casing window” refers to a section of casing configured to enable selective access to one or more specified zones of an adjacent subterranean formation. A casing window has a window that may be selectively opened and closed by an operator, for example, movable sleeve member  304 . The casing window assembly  300  can have numerous configurations and can employ a variety of mechanisms to selectively access one or more specified zones of an adjacent subterranean formation. 
     The casing window  300  includes a substantially cylindrical outer casing  302  that receives a movable sleeve member  304 . The outer casing  302  includes one or more apertures  306  to allow the communication of a fluid from the interior of the outer casing  302  into an adjacent subterranean formation. The apertures  306  are configured such that fluid jet forming nozzles  308  may be coupled thereto. In some embodiments, the fluid jet forming nozzles  308  may be threadably inserted into the apertures  306 . The fluid jet forming nozzles  308  may be isolated from the annulus  310  (formed between the outer casing  302  and the movable sleeve member  304 ) by coupling seals or pressure barriers  312  to the outer casing  302 . 
     The movable sleeve member  304  includes one or more apertures  314  configured such that, as shown in  FIG. 4A , the apertures  314  may be selectively misaligned with the apertures  306  so as to prevent the communication of a fluid from the interior of the movable sleeve member  304  into an adjacent subterranean formation. The movable sleeve member  304  may be shifted axially, rotatably, or by a combination thereof such that, as shown in  FIG. 4B , the apertures  314  selectively align with the apertures  306  so as to allow the communication of a fluid from the interior of the movable sleeve member  304  into an adjacent subterranean formation. The movable sleeve member  304  may be shifted via the use of a shifting tool, a hydraulic activated mechanism, or a ball drop mechanism. 
     Referring now to  FIG. 5 , an exemplary well completion assembly  400  includes open casing window  402  and closed casing window  404  formed in a conduit  406 . Alternatively, the well completion assembly  400  may be selectively configured such that the casing window  404  is open and the casing window  402  is closed, such that the casing windows  402  and  404  are both open, or such the that casing windows  402  and  404  are both closed. 
     A fluid  408  may be pumped down the conduit  406  and communicated through the fluid jet forming nozzles  410  of the open casing window  402  against the surface of the well bore  120  in the zone  414  of the subterranean formation F. The fluid  408  would not be communicated through the fluid jet forming nozzles  418  of the closed casing window  404 , thereby isolating the zone  420  of the subterranean formation F from any well completion operations being conducted through the open casing window  402  involving the zone  414 . The fluid  408  may include any of the embodiments disclosed elsewhere herein. 
     In one embodiment, the fluid  408  is pumped through the fluid jet forming nozzles  410  at a velocity sufficient for fluid jets  422  to form perforation tunnels  424 . In one embodiment, after the perforation tunnels  424  are formed, the fluid  408  is pumped into the conduit  406  and through the fluid jet forming nozzles  410  at a pressure sufficient to form cracks or fractures  426  along the perforation tunnels  424 . 
     The embodiments disclosed above including hydrojetting are especially useful in deviated or horizontal well bores. In deviated or horizontal well bores, fractures induced in the formation tend to extend longitudinally, or parallel, relative to the well bore. Such fractures limit production. Hydrojetting causes fractures to extend radially outward, transverse, or perpendicular relative to the well bore. Such transverse fractures increase the area of the fractured zone, thereby increasing production of hydrocarbons from the formation. Including more hydrojetting apertures along the tool also increases the length of the fractured zone. 
     The embodiments described above are illustrative of various fluid jetting tools and conveyances to which embodiments described below may be applied. Other conveyances for fluid jetting apertures or nozzles are contemplated by the present disclosure as indicated below and elsewhere herein. 
     Referring now to  FIG. 6A , a partial cross-section view of a fluid jetting window assembly  500  is shown, wherein the lower half of the assembly  500  is shown in cross-section for viewing certain internal components of the assembly  500 . The fluid jetting window assembly  500  includes an outer housing  502  having a flow bore  512  and apertures  504 , which will be described as jet forming apertures  504  but may also be pressurizing apertures or ports for directing fracturing fluids from the tool into the formation. The outer housing  502  may be coupled to casing string portions  506 ,  508  to form a casing string cementable within a well bore as previously shown and described herein. As noted previously, the well bore may be vertical, horizontal, or various angles in between, and thus it is to be understood that the horizontal depiction of assembly  500  in  FIGS. 6A-E  and  7  may apply to any such well bore orientation. The outer housing  502  retains a movable window sleeve  510 , the window sleeve  510  being reciprocally disposed within the flowbore  512  of the outer housing  502 . The window sleeve  510  includes apertures  514  for communicating with a fluid flowing through the flow bore  512 . A removable member  516  is disposed over a portion of the outer surface of the outer housing  502  having the jet forming apertures  504 . 
     In the embodiment shown in  FIG. 6A , the removable member  516  is a sleeve disposed around the outer housing  502  and over the jet forming apertures  504 . Retaining rings  518  are positioned above and below the removable sleeve  516  to couple the sleeve  516  to the outer housing  502  and retain the sleeve  516  in place over the jet forming apertures  504  (sleeve  516  and rings  518  being shown in cross-section). In some embodiments, the retaining rings  518  protect the removable sleeve  516  as the assembly  500  moves through the well bore  120 . The removable sleeve  516  is configured to cover the jet forming apertures  504  and isolate them from materials, fluid, and other obstructions that may be applied to the exterior of the outer housing  502  in the well bore environment. For the sake of clarity, the embodiments of  FIGS. 6A through 7  are described with the removable member  516  being a sleeve, and the jetting tool assembly  500  being a jetting window conveyed as part of a casing string. Further, the casing string and assembly  500  are cemented in the well bore with cement  520  as one example of a plugging material that may obstruct the fluid jet forming apertures. However, as is recognized throughout the present disclosure, other combinations of fluid pressurizing or jetting tools (e.g., tools such as those shown in  FIGS. 1 to 5 ), removable members, and obstructions are contemplated as part of the present disclosure. 
     In some embodiments, the sleeve  516  is removable by degradation. The degradable sleeve  516  may comprise a variety of materials. For example, the degradable sleeve may comprise water-soluble materials such that the sleeve degrades as it absorbs water. In an embodiment, the degradable sleeve  516  comprises a biodegradable material such as polylactic acid (PLA). In some embodiments, the degradable sleeve  516  comprises metals that degrade when exposed to an acid, also known as “acidizing.” Other embodiments for degradable sleeve  516  are also disclosed herein. 
     For example, the sleeve  516  comprises consumable materials that burn away and/or lose structural integrity when exposed to heat. Such consumable components may be formed of any consumable material that is suitable for service in a downhole environment and that provides adequate strength to enable proper operation of the degradable sleeve  516 . In embodiments, the consumable materials comprise thermally degradable materials such as magnesium metal, a thermoplastic material, composite material, a phenolic material or combinations thereof. 
     In an embodiment, the degradable materials comprise a thermoplastic material. Herein a thermoplastic material is a material that is plastic or deformable, melts to a liquid when heated and freezes to a brittle, glassy state when cooled sufficiently. Thermoplastic materials are known to one of ordinary skill in the art and include for example and without limitation polyalphaolefins, polyaryletherketones, polybutenes, nylons or polyamides, polycarbonates, thermoplastic polyesters such as those comprising polybutylene terephthalate and polyethylene terephthalate; polyphenylene sulphide; polyvinyl chloride; styrenic copolymers such as acrylonitrile butadiene styrene, styrene acrylonitrile and acrylonitrile styrene acrylate; polypropylene; thermoplastic elastomers; aromatic polyamides; cellulosics; ethylene vinyl acetate; fluoroplastics; polyacetals; polyethylenes such as high-density polyethylene, low-density polyethylene and linear low-density polyethylene; polymethylpentene; polyphenylene oxide, polystyrene such as general purpose polystyrene and high impact polystyrene; or combinations thereof. 
     In an embodiment, the degradable materials comprise a phenolic resin. Herein a phenolic resin refers to a category of thermosetting resins obtained by the reaction of phenols with simple aldehydes such as for example formaldehyde. The component comprising a phenolic resin may have the ability to withstand high temperature, along with mechanical load with minimal deformation or creep thus provides the rigidity necessary to maintain structural integrity and dimensional stability even under downhole conditions. In some embodiments, the phenolic resin is a single stage resin. Such phenolic resins are produced using an alkaline catalyst under reaction conditions having an excess of aldehyde to phenol and are commonly referred to as resoles. In some embodiments, the phenolic resin is a two stage resin. Such phenolic resins are produced using an acid catalyst under reaction conditions having a substochiometric amount of aldehyde to phenol and are commonly referred to as novalacs. Examples of phenolic resins suitable for use in this disclosure include without limitation MILEX and DUREZ 23570 black phenolic which are phenolic resins commercially available from Mitsui Company and Durez Corporation respectively. 
     In an embodiment, the degradable material comprises a composite material. Herein a composite material refers to engineered materials made from two or more constituent materials with significantly different physical or chemical properties and which remain separate and distinct within the finished structure. Composite materials are well known to one of ordinary skill in the art and may include for example and without limitation a reinforcement material such as fiberglass, quartz, kevlar, Dyneema or carbon fiber combined with a matrix resin such as polyester, vinyl ester, epoxy, polyimides, polyamides, thermoplastics, phenolics, or combinations thereof. In an embodiment, the composite is a fiber reinforced polymer. 
     The degradable sleeve  516  is used for description purposes herein, but the removable member is not to be limited by same. In some embodiments, the removable member is removable by other means. For example, in some embodiments, the removable member is a sleeve movable by actuation or shifting, as with the movable sleeve member  304 . In other embodiments, the removable member may be removed by breakage. 
     Referring now to  FIGS. 6A through 6E , the fluid jetting window assembly  500  is illustrated in operation, wherein the embodiment shown includes a degradable sleeve  516 . Referring first to  FIG. 6A , a closed position of the fluid jetting window assembly  500  is shown, wherein the window sleeve  510  is positioned such that the apertures  514  communicating with the fluid in the flowbore  512  are misaligned with the jet forming apertures  504 . The degradable sleeve  516  is disposed about the outer housing  502  adjacent the jet forming apertures  504 , and retained by retaining rings  518 . The window assembly  500 , in this “run-in” position, may be coupled to casing string portions  506 ,  508  and conveyed together into a well bore, such as well bore  120 . Cement  520  may then be applied to the outer portions of the window assembly  500  and casing string portions  506 ,  508  to attach them to the well bore (not shown). The sleeve  516  prevents cement from entering the jet forming apertures  504  and plugging them or otherwise obstructing the apertures. 
     In some embodiments of the cemented, closed position shown in  FIG. 6A , the degradable sleeve  516  begins to degrade immediately or soon after the assembly  500  is cemented into position. For example, if the degradable sleeve  516  is a PLA sleeve, water from the environment exterior of the housing  502  will contact the PLA sleeve and begin to degrade it. Water may come from screens in the back side of the casing, for example, or from the cement slurry. The degradable sleeve  516  may experience varying degrees of degradation, from little to entire sleeve consumption, for example, while the assembly  500  is closed. Alternatively, the sleeve  516  may have begun to degrade from exposure to other fluids or materials present in the well bore during other operations involving the jetting window assembly  500 . 
     Referring now to  FIG. 6B , fluid jetting window assembly  500  is shown in the open position. The window sleeve  510  has been selectively actuated, mechanically, hydraulically, or by other means for actuating movable sleeves, to a position where the window apertures  514  are aligned with the jet forming apertures  504 . The alignment of the window apertures  514  and the jet forming apertures  504  provides a fluid jet flow path  530  between the interior flow bore  512  and the exterior of the outer housing  502 . At this time, in embodiments including a biodegradable sleeve  516 , the sleeve  516  is in varying stages of degradation. In alternative embodiments, the sleeve  516  is moved, broken, or otherwise removed from covering the jet forming apertures  504  just before or after the assembly is opened as just described. It may be desirable to degrade or remove the sleeve  516  before the assembly  500  is opened such that the apertures  504  are uncovered, or partially uncovered, while pressure integrity is maintained within the assembly  500 . 
     In some embodiments wherein a degradable sleeve is present, while the assembly  500  is in the open position, a fluid is communicated from the flow bore  512 , through the jet flow path  530 , and to the degradable sleeve  516  to begin or assist in the degradation process. In embodiments where the sleeve is made of PLA or other biodegradable materials, it may take, for example, a day to several days for substantial degradation of the sleeve to occur while only exposed to the well bore environment. In one embodiment, an acid may be “spotted” through the jet flow path  530  to assist with degradation of the sleeve  516 . This provides a more selective degradation of the degradable sleeve  516 . Spotting acid at this point and location may also focus the process of extending the jet flow path from the jet forming apertures  504  radially outward from the housing  502  at least to a distance equal to the width W of the sleeve  516 . In a further embodiment wherein the sleeve  516  is made of metal, such as aluminum, or another more robust material, an acid may be flowed into the jet flow path  530  to melt or otherwise degrade the sleeve while the assembly  500  is in the open position. 
     In additional embodiments wherein the sleeve  516  is degradable, the degradation of the sleeve  516  may create an acid, such as lactic acid, or other erosive material which then begins to degrade the cement. Degradation of the cement beyond the sleeve  516  assists in further extending the jet flow path generally in the area  522  of the cement formation  520  (which is created from a cement slurry applied in the usual manner). 
     In still further embodiments, the jet forming apertures  504  may be filled with a degradable substance or removable member. In one embodiment, the apertures  504  are filled with a plug made of the same material as the degradable sleeve  516 , such as PLA. A PLA plug may simply be a portion of PLA in the shape of a plug that is adapted to be inserted into an aperture  504 . In another embodiment, the apertures  504  are filled with a gel that can be degraded as disclosed herein, or may be pushed out of the apertures  504  with fluid pressure. It yet another embodiment, the apertures  504  can be filled with removable members, for example, rupture disks that are selectively ruptured for removal. In the embodiments just described, the aperture-fillers may be used in conjunction with the sleeve  516 , or, alternatively, in place of the sleeve. If the sleeve  516  is not present, the aperture-fillers just described may be removed consistent with those embodiments disclosed herein. In such an embodiment, certain benefits may be achieved, such as the presence of less PLA material; however, certain features are compromised, such as the cavity created by a sleeve beyond the outer tool surface to increase jetting, and the increased acidization provided by a sleeve. 
     Referring now to  FIG. 6C , degradation of the sleeve  516  has weakened the sleeve  516  and, in some embodiments, the adjacent cement or other surrounding degradable materials. A fluid, such as a perforating or fracturing fluid, is pumped through the flow bore  512  and into the first jet flow path  530  formed by the aligned window apertures  504  and jet forming apertures  504 . The fluid jet from the jet forming apertures  504  creates a perforation  524 , or second jet flow path, extending from the jet forming apertures  504 , through the degraded sleeve  516  (or possibly a completely eliminated sleeve depending on the degree of degradation), and into the cement formation  520 . 
     Despite the high pressure in flow bore  512 , the perforation  524  or other extension of the jet fluid flow path beyond the jet forming apertures  504  is significantly hindered without the sleeve  516 . As used herein, high pressure, for example, is generally greater than about 3,500 p.s.i., alternatively greater than about 10,000 p.s.i., and alternatively greater than about 15,000 p.s.i. If sleeve  516  is not present, the cement  520  abuts the outer housing  502  and is flush with the jet forming apertures  504 , thereby obstructing them and resisting fluid flow. Cement may also enter the jet forming apertures  504  and plug them, thereby further increasing resistance to fluid flow therethrough. Under these circumstances, the area of the cement, or other viscous material applied to the outer housing  502 , to which the high pressure fluid in the flow bore  512  is applied is very small, i.e., the size of the jet forming aperture, which is intended to be small to provide the fluid jetting function. If, for example, the jet forming aperture has a diameter of 0.25 inches, the area of the aperture is 0.049 inches squared. Even at 5,000 p.s.i. in flow bore  512 , the force applied to the cement  520  is approximately 250 pounds. A force of this size is typically not efficient to crack or perforate the cement  520 . 
     Removal of the sleeve  516 , however, increases the force applied to the cement  520  by creating distance between the jet forming apertures  504  and the cement  520  and widening the area upon which the high pressure jet is applied. For example, as shown in  FIGS. 6A and 6B , the area of applied pressure may be increased, in one dimension, from the diameter of the aperture  504  to the length L of the sleeve  516 . Furthermore, the distance between the apertures  504  and the cement  520  also allows the high pressure fluid to flow along an extended fluid jet flow path. For example, as also shown in  FIGS. 6A and 6B , the distance W may be used to extend the high pressure fluid jet flow path. 
     Referring next to  FIG. 6D , the fluid in flow bore  512  continues to be pumped at a high pressure such that the fluid continues to flow along the first jet fluid flow path  530  at apertures  514 ,  504 , along the second jet fluid flow path extending from the jet forming apertures  504  and along the perforations  524 , and further extends the jet fluid flow path at the fractures  526 . The fractures  526  increase production of hydrocarbons from the formation F. In one embodiment, hydrocarbons may be produced through the assembly  500  by pumping fluids in the flow bore  512  in the opposite direction, thereby drawing hydrocarbons from the formation F along the jet fluid flow path at the fracture  526 , the perforations  524 , and finally in through the aligned apertures  514 ,  504 . In another embodiment, as shown in  FIG. 6E , the jetting window assembly  500  may be closed. The window sleeve  510  is moved or actuated back to its original closed position, thereby misaligning the apertures  514  and the jet forming apertures  504  and preventing fluid flow therebetween. 
     Referring to  FIG. 7 , an alternative embodiment of the jetting window assembly is shown. Jetting window assembly  600  includes a larger degradable sleeve  616  (which may also be any of the various sleeves or removable members disclosed herein) bounded by larger retaining and protection rings  618 . In this embodiment, the area of isolation about the jet forming apertures  604  is increased, as partially shown by the dimensional length L 2 . As previously disclosed, increasing the length to L 2  increases the available area for fluid jetting onto the cement formation (not shown), and thereby increasing the perforating and fracturing forces on the cement. Furthermore, the length L 2 , as opposed to the length L of  FIGS. 6A and 6B , for example, provides more flow space for creating longitudinal fractures. A sleeve with length L may be used for creating transverse fractures. 
     The various embodiment described herein provide a system for isolating apertures in a high pressure fluid stimulation tool from the exterior of the tool and preventing the apertures from becoming plugged or otherwise obstructed. In some embodiments, the apertures include jet forming nozzles that are susceptible to plugging when the tool in which the jet forming nozzles are placed is cemented onto a well bore. In addition to cementing, other downhole operations or conditions may also introduce plugging materials or hindrances at the nozzles in a jetting tool. A plugged or hindered jetting nozzle then cannot perform its fluid jetting function properly. Thus, maintaining unplugged and unobstructed high pressure fluid apertures and/or jet forming nozzles in high precision fluid stimulation tools is very beneficial. In addition, while some embodiments disclosed herein include acidizing a degradable sleeve, the embodiments of the system disclosed herein avoid the difficult and expensive step of attempting to acidize cement or other obstruction present inside the relatively small fluid apertures and/or jet forming nozzles. 
     While specific embodiments have been shown and described, modifications can be made by one skilled in the art without departing from the spirit or teaching of this invention. The embodiments as described are exemplary only and are not limiting. Many variations and modifications are possible and are within the scope of the invention. Accordingly, the scope of protection is not limited to the embodiments described, but is only limited by the claims that follow, the scope of which shall include all equivalents of the subject matter of the claims.