Abstract:
An improved inflatable packer is provided. In one embodiment, the improved packer has a tubular mandrel with an outer diameter essentially equal to the deflated inner diameter of an inflatable element surrounding the mandrel and has fluid flow passages that are adapted to cause at least a portion of pressurized fluid for inflating the element to be introduced into the annular space between the packer and the mandrel in a direction substantially parallel to the longitudinal axis of the tubular mandrel.

Description:
FIELD OF THE INVENTION  
       [0001]     This invention relates generally to an improved inflatable packer useful for restricting flow of fluids in a wellbore during the perforating and treating of a subterranean formation to increase the production of oil and gas therefrom. More particularly, this invention relates to an inflatable packer having a tubular mandrel with an outer diameter essentially equal to the deflated inner diameter of an inflatable element surrounding the mandrel and further having fluid flow passages that direct the flow of fluid for inflating the element into and through the annular space between the mandrel and the element. Preferably, the fluid flow passages direct the flow of fluid for inflating the element in a direction substantially parallel to the longitudinal axis of the mandrel.  
       BACKGROUND OF THE INVENTION  
       [0002]     When a hydrocarbon-bearing, subterranean reservoir formation does not have enough permeability or flow capacity for the hydrocarbons to flow to the surface in economic quantities or at optimum rates, hydraulic fracturing or chemical stimulation is often used to increase the flow capacity. A wellbore penetrating a subterranean formation typically includes a metal casing cemented into the original drill hole. Perforations are made to penetrate through the casing and the cement sheath surrounding the casing to allow hydrocarbon flow into the wellbore and, if necessary, to allow treatment fluids to flow from the wellbore into the formation.  
         [0003]     Hydraulic fracturing comprises injecting fluids (usually viscous shear thinning, non-Newtonian gels or emulsions) into a formation at pressures and rates high enough to cause the reservoir rock to fail and to form a planar, typically vertical, fracture (or fracture network) much like the fracture that extends through a wooden log as a wedge is driven into it. Granular proppant materials, such as sand, ceramic beads, or other materials, are generally injected with the later portion of the fracturing fluid to hold the fracture(s) open after the fluid pressure is released. Increased flow capacity from the reservoir results from the flow path left between grains of the proppant material within the fracture(s). In chemical stimulation treatments, flow capacity is improved by dissolving materials in the formation or otherwise changing formation properties.  
         [0004]     Application of hydraulic fracturing as described above is a routine part of petroleum industry operations as applied to individual target zones of up to about 60 meters (200 feet) of gross, vertical thickness of subterranean formation. When there are multiple or layered reservoirs to be hydraulically fractured, or a very thick hydrocarbon-bearing formation (over about 60 meters), then alternate treatment techniques are required to obtain treatment of the entire target zone.  
         [0005]     When multiple hydrocarbon-bearing zones are stimulated by hydraulic fracturing or chemical stimulation treatments, economic and technical gains are realized by injecting multiple treatment stages that can be diverted (or separated) by various means, including mechanical devices such as bridge plugs, packers, downhole valves, sliding sleeves, and baffle/plug combinations; ball sealers; particulates such as sand, ceramic material, proppant, salt, waxes, resins, or other compounds; or by alternative fluid systems such as viscosified fluids, gelled fluids, foams, or other chemically formulated fluids; or using limited entry methods.  
         [0006]     In mechanical bridge plug diversion, for example, the deepest interval is first perforated and fracture stimulated, then the interval is typically isolated by a wireline-set bridge plug, and the process is repeated in the next interval up. Assuming ten target perforation intervals, treating 300 meters (1,000 feet) of formation in this manner would typically require ten jobs over a time interval of ten days to two weeks with not only multiple fracture treatments, but also multiple perforating and bridge plug running operations. At the end of the treatment process, a wellbore clean-out operation would be required to remove the bridge plugs and put the well on production. The major advantage of using bridge plugs or other mechanical diversion agents is high confidence that only the target zone is treated, and the stimulation is diverted from previously treated zones. The major disadvantages are the high cost of treatment resulting from multiple trips into and out of the wellbore and the risk of complications resulting from so many operations in the well. For example, a bridge plug can become stuck in the casing and need to be drilled out at great expense. A further disadvantage is that the required wellbore clean-out operation may damage some of the successfully fractured intervals.  
         [0007]     To overcome some of the limitations associated with completion operations that require multiple trips of hardware into and out of the wellbore to perforate and stimulate subterranean formations, methods and apparatus have been proposed for “single-trip” deployment of a downhole tool string to allow for fracture and chemical stimulation of zones in conjunction with perforating. Specifically, these methods and apparatus allow operations that minimize the number of required wellbore operations and time required to complete these operations, thereby reducing the stimulation treatment cost. Frequently, an inflatable packer assembly is included in a tool string used for these types of applications.  
         [0008]     Referring now to  FIG. 1  (PRIOR ART), a standard inflatable packer assembly  10  comprises several separate parts, including an inflatable element  14 , a tubular mandrel  12 , two end-caps  13 , and two ends  16  and  18 . Often, end  16  is fixed and end  18  is sliding, i.e., adapted to slide along mandrel  12  as element  14  is inflated and/or deflated, as will be familiar to those skilled in the art. The packer assembly is typically attached to tubing  17 . There are three categories of commercially-available, inflatable elements: metal-slat reinforced, metal-cable reinforced, and polymer composite reinforced. An inflatable packer can be assembled using any type of inflatable element, including the three described above, by inserting a mandrel through the center of the element and using two end-caps to attach the element to the mandrel.  
         [0009]     Currently, the elements that have the most desirable properties in terms of absolute pressure resistance and internal differential-pressure resistance, comprise an outer elastomeric cover (which, when inflated and sealingly engaged with the wall or casing of the wellbore, provides pressure seals above and below the packer), a reinforcement structure (which provides adequate mechanical strength to withstand stresses induced by inflation), and an internal elastomeric bladder (which provides a pressure seal between the fluids inside and outside the element). The combination of high pressure resistance, sufficient thermal stability, and thin cross-section has allowed these cover-reinforcement-bladder composite elements to essentially dominate the oil-field market.  
         [0010]     As each type of reinforced element has different strengths and weaknesses, each type is generally best suited for particular types of applications. Commercially available polymer-reinforced packers are most often used in low temperature and/or low pressure water well applications and can typically survive many inflation/deflation cycles under lower pressure conditions. Metal-cable reinforced packers have also been optimized to maximize fatigue life (and hence the number of inflation/deflation cycles), and while testing has shown that currently available varieties may not handle as many cycles as the polymer-reinforced variety, they are currently able to handle relatively high temperatures. Lastly, metal-slat reinforced elements have been optimized for high-pressure, high-temperature service at the cost of shorter fatigue life.  
         [0011]     All three varieties of packers are typically exposed to service conditions that place the mandrel of the packer in tension. Recent extension of these packers to newly developed completion techniques, for example, as described in U.S. Pat. Nos. 6,394,184 and 6,520,255, and in U.S. Publication No. 2003/0051876, which deal with a technology known as “Annular Coiled Tubing Fracturing” or “ACT-Frac”, require that the packers withstand much higher compressive loads than currently available packers can withstand without buckling the mandrel. Existing partial solutions to large compressive loads include the use of a larger diameter inflatable element with a correspondingly larger mandrel, the use of cement as an inflation fluid, and alternate designs to the tool-string to reduce the effective compressive loads, such as by adjusting the position of the element within the tool-string. Each of these partial solutions introduces additional drawbacks. The use of a larger diameter element reduces the clearance between the outer diameter of the element and the inner diameter of the casing, which decreases the cross-sectional area between the element and the casing. This reduces the maximum running speeds and increases the chance for damaging the element or sticking the tool downhole. Inflating the element with cement or other hardening material supports compressive loads extremely well but does not allow for the multiple inflation/deflation cycles required by some applications. Lastly, placing the element in a different position within a string of tools to reduce compressive loading may be detrimental in several ways, including shifting the higher compressive loads to other tools, exposing other downhole tools to flows/environments otherwise protected by the packer, making the tool-string more complex, or changing the functionality of the tool-string itself.  
         [0012]     Using a larger mandrel without increasing the diameter of the inflatable element is also an option, but raises other concerns. In packer designs that use the gap between the mandrel and the element to inflate or deflate the element, increasing the diameter of the mandrel results in a smaller inflation/deflation pathway and increases the likelihood that the rubber interior of the element will pinch off flow to the inflation chamber. Operational problems will arise if the flow blockage results in either a partial inflation (e.g., lack of pressure isolation in the wellbore) or partial deflation (e.g., the packer is more likely to become stuck in the wellbore, the outer cover is more likely to experience additional wear, and the element is more likely to experience pinching failures). Despite these problems, however, larger mandrels are occasionally used for either their mechanical strength/buckling resistance, or to allow for a larger passageway through the interior of the mandrel. Towards this end, two techniques have arisen to alleviate flow restrictions through the mandrel-element gap.  
         [0013]     One technique utilizes a plurality of holes drilled through the entire covered length of the mandrel thereby affording multiple fluid pathways between an energized fluid source within the mandrel and the inflation chamber. Unfortunately, for several tool designs and completion procedures, it is undesirable to have the inflation fluid pathway include the interior of the mandrel (which may be required to contain electric lines or serve as a passageway for a separate fluid system). In addition, the holes can result in internal-bladder failure initiation sites due to either external pressure extrusion through the holes or jet-impingement onto the bladder during inflation. A second technique, which does not use the interior of the mandrel in the inflation fluid pathway, requires a second, concentric, perforated tube between the element and a solid mandrel (see U.S. Pat. No. 5,495,892). The inflation pathway is then shifted to between the mandrel and the concentric tube, effectively preventing the element from pinching off the inflation/deflation fluid pathway. However, this design is not applicable in situations where the mandrel is placed under larger compressive stresses, as the additional tube can not be load bearing when used in floating head packers (i.e., inflatable packers that use one fixed end and one floating end, i.e., an end that is allowed to travel during inflation (the predominant packer design in the oil-field)). Moreover, the perforated concentric tube requires additional space which must translate into either a larger element diameter (less wellbore-element clearance), a smaller mandrel diameter (less buckling resistance), or a thinner element design (lower pressure resistance).  
         [0014]     Inner-bladder failures are the most common failure mechanism in composite packers. This is not surprising as these bladders tend to be constructed of thin elastomeric tubes (necessary to allow expansion during inflation) and they are typically the only pressure seal around the inflatable chamber. Two of the most common inner-bladder failure mechanisms are pinching failures and extrusion failures. Pinching failures initiate during deflation when the thin elastomeric bladder, having just been stretched during the inflation stage, is now quickly forced into its initial deflated dimensions without giving the elastomer enough time to relax. To accommodate a smaller diameter in less time than the elastomer requires to relax, the still distended bladder can fold over itself given enough radial clearance. If a large external or internal pressure is applied to the packer element while a fold is present, the pressure can act to squeeze the fold together and split the bladder along the fold line. Once the bladder splits, the element no longer possesses pressure integrity and the packer has failed. A smaller clearance between the mandrel and the element would alleviate this problem, but can result in other problems as stated above.  
         [0015]     Extrusion failures occur when applied pressure forces the thin elastomeric bladder through a gap or hole in either the surrounding reinforcement structure or the mandrel/mandrel-end-cap junction. To help prevent internal-pressure related extrusion failures, element design has focused on minimizing the gap-sizes in the element reinforcing structures wrapped around the inner bladder. How effective the design is in minimizing the reinforcement gap size, coupled with the strength of the reinforcement, generally determines the maximum internal pressure differential that the element will be able to resist without failure. However, the same degree of care has not been extended to preventing extrusion failures caused by large applied external pressures. This is in part due to the relatively low frequency of events with large applied external pressures. Large external pressures can arise inadvertently (e.g., well control events, greater than anticipated reservoir pressures, human or mechanical error, etc.) or be applied on purpose (e.g., standard wellbore or lubricator pressure tests, stimulation procedures, production, well tests, etc.). With the extension of inflatable packers to high pressure stimulation operations, the likelihood that packers will experience higher external pressures is increased; thereby requiring packers with improved external pressure resistance. Improved external pressure resistance will permit application of inflatable packers to a wider range of newly developed completion operations, allow the packers to be present in the wellbore or lubricator during pressure testing, and allow the packer to remain in service after an unexpected external pressure event. The inner-bladders are especially susceptible to external pressure extrusion failures when the element is in a deflated, non-sealing state because the inner-bladder is in direct contact with any holes or gaps in the mandrel assembly.  
         [0016]     Inflatable packers are rarely used in conjunction with proppant fracturing operations due to their propensity to become damaged or stuck downhole when exposed to particulate-laden environments. Current designs generally rely on single o-ring seals to provide both static and dynamic pressure seals at the mandrel/end-cap junction to isolate the pressurized, inflatable chamber from the wellbore. Through testing, we have found that, under both particulate-free and particulate-laden environments, more robust pressure seals would be advantageous. In addition to seal design, the design of the outer elastomeric cover used in currently available packers also can led to poor performance in particulate-laden environments. The ability of the packer to return to its original outer diameter after each inflation maximizes the cross-sectional area in the annulus between the packer and the wellbore. This large annular area increases the ability of particulate-laden fluid to flow past the packer after each set, consequently reducing the likelihood of not being able to move the packer in the wellbore.  
         [0017]     Extensive testing of commercially available, inflatable packers revealed several limitations in existing packer designs, including the inability of these packers to resist bending and buckling under applied compressive loads, to resist extrusion and pinching failures of the element bladders, to perform in particulate-laden environments, and to have large annular clearance when deflated. With the development of the above-referenced completion technologies, there is now a need for an improved inflatable packer that possesses high buckling resistance, improved inner-bladder failure resistance, improved inflation-cycle repeatability, better resistance to particulate damage, a large tubular mandrel inner diameter through which fluids and electrical conduits can be passed, and a minimal deflated outer diameter to minimize the restriction to annular flow.  
         [0018]     Therefore, an object of this invention is to provide such improved inflatable packers. Other objects of this invention will be made apparent by the following description of the invention.  
       SUMMARY OF THE INVENTION  
       [0019]     An inflatable packer is provided that comprises: (a) a tubular mandrel having a longitudinal axis; (b) an inflatable element substantially concentrically disposed around said mandrel, said element having a first end and a second end with each said end being sealingly attached to the mandrel, and said element being adapted (i) to be inflated by introduction of pressurized fluid into an annular space between said element and the mandrel and (ii) to be deflated by removal of said pressurized fluid from said annular space; and (c) one or more fluid flow passages extending through the annular space between the element and the mandrel, which fluid flow passages are adapted to cause at least a portion of said pressurized fluid to be introduced into said annular space in a direction substantially parallel to said longitudinal axis of said tubular mandrel. In one embodiment, each of said fluid flow passages is in fluid communication with each of the other said fluid flow passages. In one embodiment, the mandrel has an outer diameter that is substantially equal to the inner diameter of the element prior to inflation. In one embodiment, at least one of the fluid flow passages is formed by two or more grooves in the mandrel. In another embodiment, the element comprises an outer elastomeric cover and a plurality of interconnected inner slats and, further, at least a portion of said elastomeric cover has been removed such that at least a portion of the interconnected inner slats are exposed.  
         [0020]     In another embodiment, an inflatable packer suitable for use under a pre-selected compressive load is provided, wherein the inflatable packer comprises: (a) a tubular mandrel having a longitudinal axis, and (b) an inflatable element substantially concentrically disposed around said mandrel and adapted to provide pressure seals above and below said inflatable packer when inflated, and further said mandrel has an outer diameter suitably large to prevent bending and buckling of the mandrel under said pre-selected compressive load that results in failure of either of said pressure seals or of said inflatable packer.  
         [0021]     In another embodiment, an inflatable packer suitable for use under a pre-selected external pressure is provided, wherein said inflatable packer comprises: (a) a tubular mandrel having a longitudinal axis; (b) an inflatable element comprising an inner bladder and an outer elastomeric cover and being substantially concentrically disposed around said mandrel, said element having a first end and a second end with each said end being sealingly attached to the mandrel, and said element being adapted (i) to be inflated by introduction of pressurized fluid into an annular space between said element and the mandrel and (ii) to be deflated by removal of said pressurized fluid from said annular space; (c) one or more fluid flow passages extending through the annular space between the element and the mandrel, which fluid flow passages are adapted to cause at least a portion of said pressurized fluid to be introduced into said annular space in a direction substantially parallel to said longitudinal axis of said tubular mandrel, and further wherein said mandrel has an outer diameter suitably large to prevent extrusion of said inner bladder into one or more of said fluid flow passages in a direction substantially parallel to said longitudinal axis of said tubular mandrel when said packer is subjected to said pre-selected external pressure. In one embodiment, each of said fluid flow passages is in fluid communication with each of the other said fluid flow passages.  
         [0022]     In another embodiment, an inflatable packer is provided that comprises: (a) a tubular mandrel having a longitudinal axis, and (b) an inflatable element comprising an inner bladder and an outer elastomeric cover and being substantially concentrically disposed around said mandrel, said element having a first end and a second end with each said end being sealingly attached to the mandrel, and said element being adapted (i) to be inflated by introduction of pressurized fluid into an annular space between said element and the mandrel and (ii) to be deflated by removal of said pressurized fluid from said annular space, and further wherein said mandrel has an outer diameter suitably large to prevent folding of said inner bladder within said annular space between said element and said mandrel.  
         [0023]     In another embodiment, an inflatable packer is provided that comprises: (a) a tubular mandrel having a longitudinal axis, and (b) an inflatable element comprising an outer elastomeric cover and a plurality of interconnected inner slats and being substantially concentrically disposed around said mandrel, said element having a first end and a second end with each said end being sealingly attached to the mandrel, and said element being adapted (i) to be inflated by introduction of pressurized fluid into an annular space between said element and the mandrel and (ii) to be deflated by removal of said pressurized fluid from said annular space, and further wherein at least a portion of said elastomeric cover has been removed such that an appropriate length of said interconnected inner slats are exposed to minimize the deflated diameter of said element and to prevent loss of said outer elastomeric cover when said packer undergoes a plurality of inflation/deflation cycles. In one embodiment, a plurality is meant to include two or more inflation/deflation cycles. In another embodiment, a plurality is meant to include three or more inflation/deflation cycles. In yet another embodiment, a plurality is meant to include five or more inflation/deflation cycles.  
         [0024]     In another embodiment, an inflatable packer suitable for use under a pre-selected internal pressure is provided, wherein said inflatable packer comprises: (a) a tubular mandrel having a longitudinal axis, and (b) an inflatable element comprising an outer elastomeric cover, an inner bladder, and a plurality of interconnected inner slats and being substantially concentrically disposed around said mandrel, said element having a first end and a second end with each said end being sealingly attached to the mandrel, and said element being adapted (i) to be inflated by introduction of pressurized fluid into an annular space between said element and the mandrel and (ii) to be deflated by removal of said pressurized fluid from said annular space, and further, wherein a portion of said elastomeric cover has been removed such that an appropriate length of said interconnected inner slats are exposed to prevent said exposed slats from damaging said inner bladder when said packer is subjected to said pre-selected internal pressure.  
         [0025]     In another embodiment, an inflatable packer suitable for use under a pre-selected external pressure is provided, wherein said packer comprises: (a) a tubular mandrel having a longitudinal axis; (b) an inflatable element comprising an inner bladder and an outer elastomeric cover and being substantially concentrically disposed around said mandrel, said element having a first end and a second end with each said end being sealingly attached to the mandrel, and said element being adapted (i) to be inflated by introduction of pressurized fluid into an annular space between said element and the mandrel and (ii) to be deflated by removal of said pressurized fluid from said annular space; and (c) one or more fluid flow passages extending through the annular space between the element and the mandrel, which fluid flow passages are adapted to cause at least a portion of said pressurized fluid to be introduced into said annular space in a direction substantially parallel to said longitudinal axis of said tubular mandrel, and wherein at least one of said fluid flow passages has at least one edge that is chamfered at an angle of about 40 degrees to about 50 degrees. In one embodiment, said at least one edge is chamfered at an angle of about 45 degrees.  
         [0026]     In another embodiment, an inflatable packer suitable for use under a pre-selected external pressure is provided, wherein said inflatable packer has a fixed end and a floating end and comprises: (a) a tubular mandrel having a longitudinal axis; (b) an inflatable element comprising an inner bladder and an outer elastomeric cover and being substantially concentrically disposed around said mandrel, said element having a first end and a second end with each said end being sealingly attached to the mandrel, and said element being adapted (i) to be inflated by introduction of pressurized fluid into an annular space between said element and the mandrel and (ii) to be deflated by removal of said pressurized fluid from said annular space; (c) one or more fluid flow passages extending through the annular space between the element and the mandrel, which fluid flow passages are adapted to cause at least a portion of said pressurized fluid to be introduced into said annular space in a direction substantially parallel to said longitudinal axis of said tubular mandrel; and (d) at least one device adjacent said fixed end, said device being adapted to prevent extrusion of said inner bladder into one or more of said fluid flow passages in a direction substantially parallel to said longitudinal axis of said tubular mandrel when said packer is subjected to said pre-selected external pressure. Said device that is adapted to prevent extrusion of said inner bladder when said packer is subjected to said pre-selected external pressure may comprise a filter, a screen, or any other device capable of preventing such extrusion, as will be familiar to those skilled in the art.  
     
    
     DESCRIPTION OF THE DRAWINGS  
       [0027]     The advantages of the present invention will be better understood by referring to the following detailed description and the attached drawings in which:  
         [0028]      FIG. 1  (PRIOR ART) is a sketch of a standard inflatable packer assembly;  
         [0029]      FIG. 2A  is a cut-away view of an inflatable packer according to this invention;  
         [0030]      FIG. 2B  is a plan view at section  24  of the inflatable packer illustrated in  FIG. 2A  (looking down at the top);  
         [0031]      FIG. 2C  is a plan view at section  34  of the inflatable packer illustrated in  FIG. 2A  (looking down at the top);  
         [0032]      FIG. 2D  is a detailed sketch of groove  33  shown in  FIG. 2C ;  
         [0033]      FIG. 3  is a sketch of an element useful in the present invention; and  
         [0034]      FIG. 4  is a graphical representation of data showing the benefits of use in the present invention of the element illustrated in  FIG. 3 ; 
     
    
       [0035]     While the invention will be described in connection with its preferred embodiments, it will be understood that the invention is not limited thereto. On the contrary, the invention is intended to cover all alternatives, modifications, and equivalents which may be included within the spirit and scope of the present disclosure, as defined by the appended claims.  
       DETAILED DESCRIPTION OF THE INVENTION  
       [0036]     This invention comprises several improvements to an inflatable packer assembly to address performance limitations in existing packer designs. These improvements allow the assembly to operate more reliably when (1) large compressive loads are applied to the packer, (2) large external pressures are applied to the packer, and/or (3) the packer is placed in a particulate-laden environment.  
         [0037]     In the current invention, the compressive load capability is optimized by maximizing the outer tubular diameter of the mandrel with respect to the inner diameter of the element. To facilitate load transfer through the large-diameter tubular mandrel, the threads at both ends are oriented so as to compress at one quarter of the buckling load thereby allowing the shoulders above and below the threads to shoulder with the adjacent female sub. This feature substantially ensures that the entire load-bearing cross-sectional area is in contact when the tool is subjected to large compressive load.  
         [0038]     The tubular mandrel is constructed to be effectively flush with the inner diameter of the element, i.e., the outer diameter of the mandrel is substantially equal to the inner diameter of the element. In one embodiment, the tubular mandrel has one or more passages therethrough for the passage of fluid, electrical wires, or other devices though the interior thereof. Fluid flow passages, e.g., comprising a plurality of metal runners to form slots or “flutes”, are provided down the sides of the mandrel and/or on the inner-bladder of the element to allow fluid flow along the length of the element while retaining the large outer diameter required for high resistance to buckling and bending loads. As used herein, the term “fluid flow passages” includes any passage formed in any way in the annulus between the mandrel and the inner-bladder, such as flutes in the mandrel or inserted tubes, but is not intended to refer to an annular region between the mandrel and the inner bladder. Passages may comprise holes, perforations, grooves, slots, or other continuous openings. To reduce the likelihood of damage to the inner-bladder, the fluid entrance to the flutes are preferably oriented parallel to the longitudinal axis of the mandrel to avoid any fluid-jet impingement on the inner-bladder. Fluid flow through the flutes and annulus is preferably substantially parallel to the longitudinal axis of the mandrel; however, some or all of the fluid flow may be oriented to flow in a helical path around the outer surface of the mandrel, or in some other path.  
         [0039]     When flutes are used to provide the fluid flow passages, the flutes are designed to accommodate external pressure loading without damaging the thin inner-bladder. This is accomplished, for example without limiting this invention, through the use of chamfered and beveled edges, a slow run-out at the end of the flutes, and/or the installation of a suitable filter or screen at the entrance to, throughout and/or covering the flutes. A suitable filter or screen may comprise, for example, a shaped load-bearing, porous material, sintered metal filters, machined screens, and other suitable filters or screens as will be familiar to those skilled in the art. The combination of these features minimizes the chance to cut the inner-bladder in the event external pressure forces the bladder into the mandrel and mandrel/end-cap junctions.  
         [0040]     In addition to resisting higher compressive loads without buckling, the new, larger mandrel design improves packer performance in other ways; 1) the smaller resultant clearance between the mandrel and the element minimizes the opportunity for occurrence of inner-bladder pinching failures, 2) the design of the mandrel&#39;s outer diameter profile mitigates element inner-bladder extrusion failures caused by the application of external-pressure, and 3) the proportionately larger inner diameter allows for both significant fluid flow for rapid pressure equalization across the packer and the passage of secondary conduits for additional communication (pressure, flow, electrical) with the wellbore and remaining bottomhole assembly below the packer.  
         [0041]     In one embodiment of the present invention, numerous fine holes are drilled (via mechanical means, by laser, etc) through the tubular mandrel, each hole preferably having no greater than a 0.8 mm ( 1/32 inch) diameter. The hole diameter is then small enough to prevent extrusion failures. In this embodiment, enough holes are drilled to allow for adequate inflation and deflation times, as will be familiar to those skilled in the art.  
         [0042]     Referring now to  FIG. 2A , in one embodiment of this invention a mandrel  20  has an upper end  25  having threads  26 , for connection to tubing or an end-cap, and sealant ring glands  42  and  44  to assist in sealing. Neither tubing or an end-cap is shown in any of  FIG. 2A - FIG. 2D ; any tubing or end-cap that is suitable for the application at hand may be used, although same may require modification to fit mandrel upper end  25 , all as will be familiar to those skilled in the art. Further, in this embodiment mandrel  20  in section  24  has an outer edge  20   c  and an outer diameter  22  of about 5.05 cm. (1.99 inches). Referring to  FIG. 2B , mandrel  20  at section  24  has outer edge  20   c  and a plurality of flutes or grooves  23  having outer edge  20   a , each having a width  21  of about 0.64 cm. (0.25 inches) and a depth  27  of about 0.25 cm. (0.1 inch) and being substantially evenly spaced at an angle  29  of about 45 degrees along the circumference of mandrel  20 . Referring again to  FIG. 2A , mandrel  20  has a lower end  35  having threads  36 , for connection to an end-cap, and sealant ring glands  52  and  54  to assist in sealing, as will be familiar to those skilled in the art. The end-cap is not shown in any of  FIG. 2A-2D  and may be any end-cap that is suitable for the application at hand, although same may require modification to fit mandrel lower end  35 , as will be familiar to those skilled in the art. Further, mandrel  20  in section  34  has outer edge  20   b  and an outer diameter  32  of about 4.92 cm. (1.937 inches). Referring to  FIG. 2C , mandrel  20  at section  34  has outer edge  20   b  and a plurality of flutes or grooves  33  having outer edge  20   a , each having a width  31  of about 0.64 cm. (0.25 inches) and a depth  37  of about 0.188 cm. (0.074 inch) and being substantially evenly spaced at an angle  39  of about 45 degrees along the circumference of mandrel  20 . Referring now to  FIG. 2D , grooves  33  in section  34  are manufactured with chamfers  40  at an angle of about 45 degrees and are beveled to minimize damage to the inner bladder of the inflatable element circumferentially disposed over mandrel  20  when exposed to external pressure. Preferably, grooves  23  in section  24  (see  FIG. 2B ) are similarly chamfered and beveled. This embodiment may include screen sleeves that are disposed axially over the length of the fluted region and are supported against radial external loading by the non-fluted portion  20   b  of mandrel  20  outside diameter. The screen sleeves could be confined axially through a diameter upset on the mandrel at one end and a removable securing device on the other end, for example, a threaded sleeve that screws onto mandrel  20  and axially presses the screen sleeves against the mandrel diameter upset. The screen sleeves would contain numerous radial holes sized to prevent extrusion of the inner bladder when external pressure is applied, the numerous radial holes having diameters of about 0.2 mm (0.008″) and numbering in the thousands. It may be preferable to make the screen sleeve in two or more sections in order to reduce the longitudinal dimension over which tight radial tolerances must be maintained and to facilitate cleaning and inspection. Reference to a screen herein will be understood to include embodiments having such multiple sections. The inflatable element is not shown in any of  FIG. 2A - FIG. 2D  and may be any inflatable element that is suitable for the application at hand, as will be familiar to those skilled in the art. The specific description of this embodiment of the invention in no way limits this invention. As is familiar to those skilled in the art, dimensions of parts are adjusted as needed for the application at hand.  
         [0043]     In order to accommodate operation of the inflatable packer assembly according to this invention in a particulate-laden fluid, wipers are preferably added to the floating end to remove particulates as the packer is inflated and deflated. In addition to the wipers, redundant o-rings seals with back-up rings to prevent extrusion preferably replace the single o-ring seals commonly used in existing designs. A POLY-PAK, pressure-energized seal is preferably used in the floating end for improved sealing and a more robust seal for use in particulate-laden environments.  
         [0044]     Referring again to  FIG. 2A , upper end  25  of tubular mandrel  20  comprises a blunt nose  43  and threads  26 , which threads  26  are oriented so as to compress at one quarter of the buckling load thereby allowing the shoulders above and below the threads to shoulder with the female sub above, as will be familiar to those skilled in the art. In this embodiment, threads  26  are oriented at an angle  41  of about 30 degrees. Also, the seal system comprises VITON o-rings (not shown in the FIG.) in ring glands  44  with PARBAK backup rings (not shown in the FIG.) in ring glands  42 . The tubular or end-cap to which upper end  25  is connected may require modification to ensure a tight fit, as will be familiar to those skilled in the art.  
         [0045]     Lower end  35  of tubular mandrel  20  comprises a blunt nose  53  and threads  36 , which threads  36  are oriented so as to compress at one quarter of the buckling load thereby allowing the shoulders above and below the threads to shoulder with the female sub below, as will be familiar to those skilled in the art. In this embodiment, threads  36  are oriented at an angle  51  of about 30 degrees. Also, the seal system comprises VITON o-rings (not shown in the FIG.) in ring glands  54  with PARBAK backup rings (not shown in the FIG.) in ring glands  52 . The end-cap to which lower end  35  is connected may require modification to ensure a tight fit, as will be familiar to those skilled in the art. When mandrel lower end  35  is attached to a floating end (end not shown in the FIG.) the floating end preferably comprises a TEFLON wiper ring and a poly-pack pressure energized seal, both as will be familiar to those skilled in the art.  
         [0046]     Additionally, when a packer assembly according to this invention is used in a particulate-laden fluid, a metal-slat reinforced element is preferred. Referring now to  FIG. 3 , one end of a preferred element  60  for use in a packer assembly according to this invention is illustrated as attached to an end-cap  66 . Prior to inflation, the outer elastomer cover  64  has a length  62  of exposed slats  63  of about 7.62 cm. (3.0 inches) with a taper  65  of about 15 degrees. Preferably element  60  has such exposed slats at both ends.  
         [0047]     In an experimental testing program conducted to evaluate the performance of existing packer/mandrel assemblies and assemblies according to this invention, conventional packer/mandrel assemblies buckled and failed under a compressive load of 378.1 kN (85,000 lbs.) or 34,474 kPa (5000 psi) differential. The modified, larger diameter mandrel according to this invention withstood 458.2 kN (103,000 lbs.) or 41,369 kPa (6000 psi) differential with no buckling, and up to 685 kN (154,000 lbs.) or 62,053 kPa (9000 psi) differential with slightly bending but no pressure containment failure of the packer element.  
         [0048]      FIG. 4  compares the deflated outer diameter of a packer according to this invention without exposure of 3 inches of the slats at each end to the deflated outer diameter of a packer according to this invention with exposure of 3 inches of slats (as illustrated in  FIG. 3 ) at each end. Each packer was tested within casing having an inner diameter of about 11.86 cm (4.67 inches). The element on each packer had an outer diameter of about 9.53 cm (3.75 inches) and a rubber outer cover with a thickness of about 0.95 cm (⅜ inch). Referring again to  FIG. 4 , abscissa  70  indicates axial position of the packers during testing, with the numerals 2, 4, 6, . . . 32 indicating inches from the rubber edge nearest the top end. Ordinate  71  indicates the measured outer diameter of the element in inches, area  72  shows measurement data from the original element before the first inflation, area  73  shows measurement data about the element as modified with the exposed slats after 30 inflation/deflation cycles, and area  74  shows measurement data about the original element (unmodified) after 20 inflation/deflation cycles. The maximum final outer diameter of the packer with the exposed slats was about 10.62 cm. (4.182 inches) after 30 cycles compared to a maximum final outer diameter of about 11.30 cm. (4.45 inches) after 20 cycles for the packer without exposed slats. This reduction in outer diameter increased the annular flow area by 115% from about 10.2 cm 2  (1.58 inches 2 ) for the original outer cover to about 21.9 cm 2  (3.39 inches 2 ) for the modified outer cover. The modified packer/mandrel assembly was tested successfully in 20/40 proppant, as will be familiar to those skilled in the art, at pressures up to about 55,159 kPa (8,000 psi) without failing. During this experiment, the wiper and improved seal designs discussed herein were found to operate successfully in particulate-laden fluid.  
         [0049]     While the present invention has been described in terms of one or more preferred embodiments, it is to be understood that other modifications may be made without departing from the scope of the invention, which is set forth in the claims below.