Abstract:
A device and method to control the rate of radial expansion of a compressible sealing element on a packer over the longitudinal length of the sealing element. By varying the rate of compression of the element, the rate of radial expansion of the corresponding portions of the element may also be controlled. Additionally, the rate of radial expansion may also be controlled by controlling the direction and amount of radial expansion along the length of the sealing by reinforcing certain portions of the sealing element while decreasing the rigidity of the reinforcement for other portions.

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
       [0001]    This application claims the benefit of U.S. Provisional Appl. Nos. 61/774,727, filed 8 Mar. 2013, and 61/776,561, filed 11 Mar. 2013, which are incorporated herein by reference. 
     
    
     BACKGROUND 
       [0002]    In connection with the completion of oil and gas wells, it is frequently necessary to utilize packers in both open and cased boreholes. The walls of the well or casing are plugged or packed from time to time for a number of reasons. As shown in  FIG. 1 , for example, sections of a well  10  may be packed off with packers  16  on a tubing string  12  in the well. The packers  16  isolate sections of the well  10  so pressure can be applied to a particular section of the well  10 , such as when fracturing a hydrocarbon bearing formation, through a sliding sleeve  14  while protecting the remainder of the well  10  from the applied pressure. 
         [0003]    In some situations, operators may prefer to utilize a comparatively long sealing element on the packer&#39;s  16 . In these instances, as the sealing element is compressed longitudinally by a piston, friction and other forces combine to cause the sealing element to bunch up or otherwise bind near the piston. As a result, the longer sealing element does not uniformly compress in the longitudinal direction and by extension does not expand uniformly in the radial direction. The lack of uniform expansion tends to prevent the packer  16  from forming a seal that meets the operator&#39;s expectations, thereby defeating the purpose of utilizing a longer sealing element 
         [0004]    Therefore, a significant need exists for a packer that is able to utilize an extended length sealing element. 
       SUMMARY 
       [0005]    A packer, plug, or other downhole tool has an extended-length, compressible sealing element. The sealing element is reinforced with a rigid member that causes the sealing element to deform in a controlled manner when the sealing element is longitudinally compressed. The rigid member reinforces certain portions of the sealing element. Yet, the rigid member has one or more areas of decreased rigidity that decreases the reinforcement for certain portions of the sealing element. 
         [0006]    By controlling the deformation of the sealing element with the rigid member, unwanted deformation is prevented. Such unwanted deformation is usually caused by friction between the sealing element, the tool&#39;s mandrel, and the casing or wellbore. In the past, the unwanted deformation has typically caused longer sealing elements to bunch up on the end of the element closest to the mechanism causing the sealing element to be longitudinally compressed. Additionally, such unwanted deformation has also tended to limit the effectiveness of the seal created between the tool&#39;s mandrel and the casing or wellbore by the sealing element. Thus, previous sealing elements on tools, such as packers, have been limited in length in order to retain an effective seal. 
         [0007]    In an embodiment of the present disclosure, a rigid member is bonded to the elastomeric sealing element. The rigid member can be a cylinder or can be a plurality of slats. The rigid sealing member has thinner and thicker portions that control the deformation of both the rigid member and the adjacent sealing element with respect to the rest of the sealing element during longitudinal compression of the sealing element. As the rigid member and the elastomer deform, the longitudinal compression causes a first portion of the sealing element to bend outward while the adjacent portion may bend inwards. The first portion bending outwards may tend to seal more against the wellbore wall or the casing while the adjacent portion may tend to seal more against the mandrel. The reverse may also be true depending on the circumstances. 
         [0008]    The rigid member can be metallic, non-metallic, or a combination of metallic and non-metallic. In some embodiments, the rigid member can be configured to bend at certain locations, or if desired the rigid member can be configured to break at certain points. In other embodiments, the rigid member can have an accordion-like, corrugated, or spring structure. In this case, this type of rigid member can bend over its length in a single direction, such as longitudinally, while resisting radial deformation. 
         [0009]    In another embodiment, an accordion-like, corrugated, or spring-like rigid member may be used to control the expansion of the elastomeric sealing element. By utilizing a structure, such as a spring, the deformation of the sealing element may be locally limited until the entire sealing element has at least partially deformed. The circumferential hoops in the structure, such as a spring, would tend to limit the initial radial expansion of the bonded elastomeric sealing element while allowing the sealing element to be longitudinally compressed. 
         [0010]    In another embodiment, a sealing element for use in a wellbore may have an inner elastomeric element, an outer elastomeric element, and a rigid member disposed between them. The rigid member has at least one area of decreased rigidity, such as from a notch of reduced thickness, from a difference in corrugated structure, from a difference in spring strength, and from other differences of the rigid member as disclosed herein. 
         [0011]    Although the rigid member may be located between the inner elastomeric element and the outer elastomeric element, the inner elastomeric element and the outer elastomeric element may actually be attached, bonded, molded, or formed to one another. The rigid member may be affixed to the inner elastomeric element and the outer elastomeric element by an adhesive or by bonding, such as during an extrusion process. In some instances, the rigid member may be at least two rigid members, and typically the two rigid members may run parallel to one another along the longitudinal length of the sealing element. 
         [0012]    In another embodiment, a sealing element for use in a wellbore may have an elastomeric element and a rigid member having at least one area of decreased rigidity. The rigid member may be attached to the elastomeric element by an adhesive or by bonding such as during an extrusion or molding process. Typically, the rigid member is embedded in the elastomeric element. In some instances, the rigid member may have at least two rigid members, and the rigid members may be linked by a band, such as a circumferential band. 
         [0013]    In another embodiment, a sealing element for use in a wellbore may have an elastomeric element and at least one spring. The spring may be embedded in the element or may be attached to the elastomeric element by an adhesive or by bonding, such as during an extrusion or molding process. Typically, the spring limits the initial radial expansion of the elastomeric element when the spring and the elastomeric element are longitudinally compressed. The spring can vary in strength or rigidity along its length. In some instances, more than one spring, such as a first spring and a second spring, may be used end-to-end in a single sealing element. In some instances, the first spring has a first spring strength and the second spring has a second spring strength. 
         [0014]    In another embodiment, an apparatus, such as a plug or a packer for use in a wellbore, may have a sealing element having a first elastomeric portion and a second elastomeric portion. The first portion has a first compressive strength and the second portion has a second compressive strength. In some instances the first elastomeric portion and the second elastomeric portions may be connected. In other instances the first elastomeric portion and the second elastomeric portions may be separate. 
         [0015]    To seal a downhole tool in a wellbore, the downhole tool is deployed in the wellbore. The compressible element is then sealed in the wellbore by radially expanding the compressible element in response longitudinal compression of the compressible element. This deforms the rigid member. Ultimately, sealing of at least a portion of the compressible element is controlled with the rigid member by deforming at least one area of reduced rigidity on the rigid member adjacent the portion the compressible element different from other portions of the compressible element. 
         [0016]    As used herein, the terms such as lower, downhole, downward, upper, uphole, and upward are merely provided for understanding. Additionally, the terms packer and plug may be used interchangeably. 
     
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         [0017]      FIG. 1  depicts a wellbore having a tubular with a plurality of sealing element tools disposed thereon. 
           [0018]      FIG. 2  depicts a downhole tool in partial cross-section having an extended-length sealing element according to the present disclosure. 
           [0019]      FIG. 3A  depicts a side view of the disclosed sealing element in an uncased wellbore with an embedded rigid member. 
           [0020]      FIG. 3B  depicts a detailed cutaway of the disclosed sealing element in  FIG. 3A . 
           [0021]      FIG. 4  depicts a perspective view of a sealing element with an embedded rigid member. 
           [0022]      FIG. 5  depicts a side view of a sealing element with an embedded rigid member having circumferential bands. 
           [0023]      FIG. 6  depicts a side view of a sealing element with an embedded spring. 
           [0024]      FIG. 7  depicts a side view of a sealing element with multiple embedded springs. 
           [0025]      FIG. 8  depicts a side view of another sealing element having a corrugated rigid member. 
           [0026]      FIG. 9  depicts a side view of a sealing element having portions of varying compressive strength along its longitudinal length. 
       
    
    
     DETAILED DESCRIPTION 
       [0027]    The description that follows includes exemplary apparatus, methods, techniques, and instruction sequences that embody techniques of the inventive subject matter. However, it is understood that the described embodiments may be practiced without these specific details. 
         [0028]      FIG. 2  depicts a downhole tool  50  having a compressible sealing element  100  according to the present disclosure. As depicted herein, the tool  50  can be a packer having a mandrel  60  with a through-bore  62 . A fixed end ring  66  is disposed on the mandrel  60  at one end of the sealing element  100 . On the opposite end of the sealing element  100 , the packer  50  has a setting mechanism  68 . Although not shown, the packer  50  can include a slip assembly to lock the packer longitudinally in place in the well and can include other common features. Although shown used on the packer  50 , the disclosed sealing element  100  can be used on any type of downhole tool used for sealing in a borehole, including, but not limited to, a packer, a liner hanger, a bridge plug, a fracture plug, and the like. 
         [0029]    The sealing element  100  has an initial diameter to allow the packer  50  to be run into a well and has a second, radially-larger size when compressed to seal against the wellbore. When the packer  50  is set downhole, the mandrel  60  is held in place and force is applied longitudinally to the sealing element  100  by the setting mechanism  68 , which in this example is a hydraulic piston mechanism. 
         [0030]    For example, the mechanism  68  is activated by a build-up of hydraulic pressure in a chamber of the mechanism  68  through a port  64  in the mandrel  60 . In turn, the piston mechanism  68  pushes against the end of the sealing element  100  to compress the sealing element  100  longitudinally. As it is compressed, the sealing element  100  expands radially outward to engage the surrounding surface, which can be an open or cased hole. Although the tool  50  is shown as being hydraulically actuated, other types of mechanisms  68  known in the art can be used on the tool  50  including, mechanical, hydro-mechanical, and electrical mechanisms for compressing the sealing element  100 . 
         [0031]    As briefly depicted in  FIG. 2 , the sealing element  100  has an elastomeric member  110  disposed adjacent the mandrel  60  of the tool  50 . The sealing element  100  also has a rigid member  150  disposed in or associated with the elastomeric member  110 . The rigid member  150  has at least one area of decreased rigidity or reduced thickness. The rigid member  150  can be metallic, non-metallic, or a combination of metallic and non-metallic. For example, the rigid member  150  can be composed of metal, plastic, elastomer, or the like. In some embodiments, the rigid member  150  can be configured to bend at certain locations, or if desired the rigid member  150  can be configured to break at certain points. 
         [0032]    The element&#39;s elastomeric member  110  can be attached, bonded, molded, or formed on the mandrel  60  and the rigid member  150  in any suitable fashion. For instance, the element&#39;s elastomeric member  110  can be comprised of separate layers  120  and  122  of the same or different elastomeric material. The rigid member  150  may be affixed between the inner elastomeric layer  120  and the outer elastomeric layer  122  by an adhesive or by bonding, such as during an extrusion or molding process. Alternatively, the rigid member  150  may be molded or embedded directly into the elastomeric material of the member  110 . 
         [0033]    In any event, the member  110  has an outer elastomeric portion or layer  120  disposed external to an inner elastomeric layer  122 . Each of the layers  120  and  122  may be separate elements or sleeves disposed, molded, or formed on the rigid member  150 . Alternatively, the inner and outer elastomeric layers  120  and  122  may be integrally molded or formed portions of the same underlying element on the rigid member  150 . 
         [0034]    In one embodiment, the rigid member  150  is a cylindrical sleeve disposed about the mandrel  60 . In another embodiment, the rigid member  150  is comprised of several longitudinal strips disposed parallel to one another along the axis of the sealing element  100  and the mandrel  60 . In yet another embodiment, the rigid member  150  is a cage structure having a combination of cylindrical bands disposed around the mandrel  60  and having a number of longitudinal members spaced around the mandrel  60 . 
         [0035]      FIG. 3A  depicts an embodiment of a compressible sealing element  100  in more detail relative to an uncased wellbore  10  and a mandrel  60 . While the uncased wellbore  10  is depicted, any of the embodiments can be used in open holes or in casing. Again, as noted above, the sealing element  100  circumferentially surrounds the mandrel  60  and includes the elastomeric member  110  and the rigid member  150 . The elastomeric member  110  has its radially inward layer  120 , which can be of a first elastomer, and has its radially outward layer  122 , which can be of a second elastomer. The first and second elastomers may be of the same elastomer, or they may be different elastomers depending upon the sealing characteristics desired. 
         [0036]    The rigid member  150  is disposed as an intermediate layer in the elastomeric member  110 . The rigid member  150  may be affixed to one or both of the push rings (not shown), or the ends of the members  150  may simply abut adjacent the rings. As shown, the rigid member  150  has areas of different rigidity or thicknesses along its length. In the embodiment depicted, thinned regions or notches  160   a - c  are alternatingly facing opposing sides of the rigid member  150 . For instance, first notches  160   a,    106   c  face inward toward the mandrel  60 , while second notches  160   b  face outward towards the wellbore  10 . The layers  120  and  122  can fill in the various notches  160   a - c  with material, depending on how the layers  120  and  122  are formed on the rigid member  150  and mandrel  60 . 
         [0037]    As shown in the detail of  FIG. 3B , each notch  160  may have a bottom wall  162  and angled sidewalls  164   a - b , although curved or other rectilinear profiles can be used. In any event, each notch  160  defines a particular depth (d) and width (w) in the rigid member  150 . Additionally, the various notches  160   a - c  are defined at various spacings (s) from one another along the length of the rigid member  150 . 
         [0038]    In general, the depths (d), widths (w), and spacings (s) of the notches  160   a - c  can be the same or different, but the characteristics of the notches  160   a - c  can be configured to govern how the rigid member  150  will bend and the sealing element  100  will deform when compressed. In particular, the depths (d), widths (w), and spacings (s) of the notches  160   a - c  determine what direction and when the rigid member  150  will deform at particular locations. 
         [0039]    Moving the notch sidewalls  164   a - b  in towards one another as well as increasing the angle of the notch sidewalls  164   a - b  can determine how far the rigid member  150  will initially deform. The depth (d) of each notch  160   a - b  can determine the order in which the various notches  160   a - c  will deflect. For instance, shallower notches  160   a  leave a thicker bridge of material on the rigid member  150 . Such a thicker bridge will allow this portion of the rigid member  150  around the shallower notch  160   a  to deform later than a deeper notch  160   c  having a thinner bridge of material. Additionally, the location of a given notch  160   a - c  in either side of the rigid member  150  determines in which direction the rigid member  150  will deform. A notch  160   b  that faces the wellbore  10  tends to cause the rigid member  150  to deform away from the wellbore  10 , while a notch  160   a,    160   c  facing the mandrel  60  tends to cause the rigid member  150  to deform away from the mandrel  60 . 
         [0040]    The notches  160  may be reversed. Furthermore, thinner notches  160  can be positioned in the middle, on the outer portion, or to one side of the rigid member  150  depending of the desired outcome of the element&#39;s compression. Additionally, deeper notches  160  can be positioned on the top end of the rigid member  150  and shallower on the bottom end, or vice versa. 
         [0041]    Because the sealing element  100  has an extended length, the timing of how it deforms as it is longitudinally compressed on the mandrel  60  can be controlled by the rigid member  150  so the element  100  does not prematurely buckle, crease, fold, or otherwise expand improperly against the surrounding wall. In this particular example having five notches  160   a - c  along the length of the element  100 , the notches  160   a - c  are symmetrically arranged with a center notch  160   c,  two intermediate notches  160   b,  and two end notches  160   a.  The depth (d), width (w), angles, etc. of the center notch  160   c  are configured to force the center portion of the element  100  to deform and set first. This is not strictly necessary because there may be implementations in which the center portion sets after one or both of the ends. 
         [0042]    In this implementation, however, the intermediate notches  160   b  spaced outside of the center notch  160   c  are configured with widths (w) and depths (d) to set later at a delayed timing from the center notch  160   c.  By first setting the center of the element  100  followed and then setting outward along the length of the element  100 , fluid can escape from the annulus between the element  100  and the wellbore  10  during setting procedures. Finally, the end notches  160   a  spaced toward the ends of the element  100  are configured to set even later during the overall setting process. 
         [0043]    The arrangement here is symmetrical and includes five notches  160   a - c . Other configurations can be used with more or less notches  160 , and such an alternating arrangement can be repeated along the length of the sealing element  100 . Accordingly, the number of notches  160  may vary depending on the length of the element  100  and the desired number of timed seal points. 
         [0044]      FIG. 4  depicts a side view of a sealing element  200  mounted on a mandrel  202  with a first push ring  204  and a second push ring  206 . As will be appreciated, the mandrel  202  and push rings  204  and  206  can be components of a downhole tool, such as a packer or a plug. The sealing element  200  has an elastomeric member  210  with a plurality of spaced apart rigid members  250  embedded therein. The rigid members  250  run parallel to one another along the length of the elastomeric member  210 . As noted above, the elastomeric member  210  has a radially inward elastomeric layer  220  and a radially outward elastomeric layer  222 , which is shown in dashed line to reveal details of the rigid members  250 . 
         [0045]    Each rigid member  250  has notches  260 . As noted previously, each notch  260  may have a width, depth, notch bridge thickness, distance between the notch sidewalls, and notch sidewall angles that are configured different or similar to one another depending upon the desired deformation characteristics. Additionally, the notches  260  can be arranged to face inward and/or outward as desired. Each notch  260  tends to cause the rigid members  250  to deflect radially inward or outward in an organized way configured for a particular implementation, as disclosed herein. 
         [0046]    Here, the rigid members  250  are a plurality of longitudinal strips or slats disposed parallel to one another along the longitudinal axis and around the circumference of the elastomeric element  210 . The members  250  may be affixed to one or both of the push rings  204  and  206 , or the ends of the members  250  may simply abut adjacent the rings  204  and  206 . Again, the rigid members  250  can be composed of any suitable material, including metal, plastic, or an elastomer more rigid than the overall sealing element  200 . 
         [0047]      FIG. 5  depicts a side view of a compressible sealing element  300  mounted on a mandrel  302  with a first push ring  304  and a second push ring  306 . As will be appreciated, the mandrel  302  and push rings  304  and  306  can be components of a downhole tool, such as a packer or a plug. The sealing element  300  has an elastomeric member  310  with a rigid member in the form of a cage  330  embedded therein. As noted above, the elastomeric member  310  has a radially inward elastomeric layer  320  and a radially outward elastomeric layer  322 , which is shown in dashed line to reveal details of the rigid cage  330 . 
         [0048]    For its part, the rigid cage  330  has rings or bands  332  with a plurality of rigid strips or slats  350  running parallel to one another along the length of the cage  330 . The rings  332  and the rigid slats  350  are attached to one another and are embedded in the radially inward and outward elastomeric layers  320  and  322  (depicted in dashed lines). The bands  332  can be affixed to or abut against the push rings  304  and  306 . Although the bands  332  are shown at the ends of the cage  330  one or more bands can also be used at intermediate locations of the cage  330  between the ends. 
         [0049]    Each rigid slat  350  has notches  360 . As before, each notch  360  may have a different notch bridge thickness, a different distance between the notch sidewalls, different notch sidewall angles, face inward or outward, and other features depending upon the desired deformation characteristics. 
         [0050]      FIG. 6  depicts a side view of a compressible sealing element  400  mounted on a mandrel  402  with a first push ring  404  and a second push ring  406 . As will be appreciated, the mandrel  402  and push rings  404  and  406  can be components of a downhole tool, such as a packer or a plug. The sealing element  400  has an accordion-like structure, which in this case is a spring  450 . The spring  450  is embedded in the elastomeric member  410 . For example, the spring  450  can be attached to a radially inward elastomeric layer  420  and to a radially outward elastomeric layer  422 . 
         [0051]    The spring  450  varies in rigidity by varying in pitch from the push rings  404  and  406  as it progresses longitudinally along the elastomeric sealing element  410 . In some instances, the spring  450  can vary in pitch from the first push ring  404  towards the second push ring  406  in any combination that meets the operator&#39;s requirements. The spring&#39;s  450  variation in pitch can be seen as a different in the distance between the spring&#39;s hoops, such as the different distances (w 1 ) and (w 2 ) depicted in  FIG. 6 . 
         [0052]    The circumferential hoops formed by the spring  450  as it circumferentially surrounds the mandrel  402  can tend to limit the initial radial expansion of the sealing element  400  while allowing the sealing element  400  to be longitudinally compressed. The differences in distances between the hoops tend to allow the sealing element  400  to radially expand at certain location to an extent greater than where the spring&#39;s  450  hoops are closer together. In certain instances, it may be desirable to utilize an accordion-like structure that does not vary in pitch but tends to limit the initial radial expansion of the elastomeric sealing element  400  to a uniform amount. 
         [0053]      FIG. 7  depicts a side view of a compressible sealing element  500  mounted on a mandrel  502  with a first push ring  504  and a second push ring  506 , which can be components of a downhole tool, such as a packer or a plug. The sealing element  510  has at least two accordion-like structures  550   a - c , in this case a first spring  550   a,  a second spring  550   b,  and a third spring  550   c.    
         [0054]    The springs  550   a - c  are embedded in the elastomeric member  510 . For example, the springs  550   a - c  can be attached to a radially inward elastomeric layer  520  and to a radially outward elastomeric layer  522 . In  FIG. 7 , the radially outward elastomeric layer  522  is shown in dashed line overlaying the springs  550   a - c  and attached to the inward elastomeric layer  520 . 
         [0055]    Each spring  550   a - c  varies in strength or the force exerted as the spring  550   a - c  compresses. In  FIG. 7 , the strength of each spring  550   a - c  decreases as the springs  550   a - c  are longitudinally positioned along the mandrel  502  from one push ring  504  to the other. Other configurations could be used. For example, opposing sets of springs could decrease in strength from the two push rings  504  and  506  towards the center of the element  500 . In fact, any combination of varying strength of each spring  550  could be used to meet the operator&#39;s requirements. 
         [0056]    When the sealing element  500  is set, the weakest spring (e.g.,  550   c ) will tend to longitudinally compress first, thereby causing the sealing element  510  adjacent to the spring  550   c  to longitudinally compress and thereby radially expand. By varying the strength of each spring  550   a - c , the timing of the radial expansion of each portion of the sealing element  500  may be controlled by the operator. 
         [0057]      FIG. 8  depicts a side view of a compressible sealing element  600  having a corrugated rigid member  650 . The sealing element  600  is mounted on a mandrel  602  between first and second push rings  604  and  606 , which can be components of a downhole tool, such as a packer or a plug. The sealing element  600  consists of inward and outward elastomeric sealing elements  610  and  620  with the corrugated or crumpled rigid member  650  disposed therebetween. Spacing between corrugations can vary along the length of the mandrel  602 , thereby altering the flexibility and stiffness of the various sections of the member  650 . In  FIG. 8 , for example, the corrugations near the push rings  604  and  606  have widths (e.g., c 1 ) that is greater than the widths (e.g., c 2 ) of the corrugations near the center of the element  600 . Thus, the flexibility of the rigid member  650  increases longitudinally from the push rings  604  and  606  toward the center of the element  600 . Other configurations could be used. For example, the flexibility can increase along the length of the element  600  from one push ring  604  to the other  606 . In fact, any combination of flexibility could be used to meet the operator&#39;s requirements. 
         [0058]    When the packer and thus the sealing element  600  is set, the more flexible sections of the rigid member  650  tend to longitudinally compress first, thereby causing the elastomeric sealing element  600  to radially expand. By varying the flexibility, the timing of the radial expansion of the sealing element  600  may be controlled by the operator. 
         [0059]    Finally,  FIG. 9  depicts a side view of a compressible sealing element  700  mounted on a mandrel  702  with a first push ring  704  and a second push ring  706 , which can be components of a downhole tool, such as a packer or a plug. The sealing element  700  consists of longitudinally separate elastomeric sealing members or sections  750   a - n  disposed along the mandrel  702  between the push rings  704  and  706 . As shown here, each of the sections  750   a - n  can be a separate washer, ring, wrapping, or sleeve portion disposed on the mandrel  702 . 
         [0060]    Each section  750   a - n  of the sealing element  700  varies in compressive strength or the force required to compress each section  750   a - n . In a variation of this embodiment, the longitudinally separate sections  750   a - n  of elastomer could be a single elastomeric member, in which the elastomeric compounds differ over the element&#39;s length, thereby providing variations in the compressive strength of the sealing element  700  over its length. 
         [0061]    In  FIG. 9 , the strength of each elastomeric sealing sections  750   a - n  increases as the section  750   a - n  are longitudinally positioned along the mandrel  702  from one of the push ring  704 . Other configurations could be used. For example, opposing sets of sections  750  could decrease in strength from the two push rings  704  and  706  towards the center of the element  700 . In fact, any combination of varying strength of each section  750  could be used to meet the operator&#39;s requirements. 
         [0062]    When the packer and thus the sealing element  700  is set, the weakest elastomeric sealing section (e.g.,  750   n ) tends to longitudinally compress first, thereby causing the elastomeric sealing element  700  to radially expand. By varying the compressive strength of each elastomeric sealing section  750   a - n , the timing of the radial expansion of each portion of the sealing element  700  may be controlled by the operator. 
         [0063]    The foregoing description of preferred and other embodiments is not intended to limit or restrict the scope or applicability of the inventive concepts conceived of by the Applicants. It will be appreciated with the benefit of the present disclosure that features described above in accordance with any embodiment or aspect of the disclosed subject matter can be utilized, either alone or in combination, with any other described feature, in any other embodiment or aspect of the disclosed subject matter. 
         [0064]    In exchange for disclosing the inventive concepts contained herein, the Applicants desire all patent rights afforded by the appended claims. Therefore, it is intended that the appended claims include all modifications and alterations to the full extent that they come within the scope of the following claims or the equivalents thereof.