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BACKGROUND 
     In connection with the completion of oil and gas wells, it is frequently necessary to utilize packers in both open and cased bore holes. The walls of the well or casing are plugged or packed from time to time for a number of reasons. For example, a section of the well may be packed off to permit applying pressure to a particular section of the well, such as when fracturing a hydrocarbon bearing formation, while protecting the remainder of the well from the applied pressure. 
     In a staged frac operation, for example, multiple zones of a formation need to be isolated sequentially for treatment. To achieve this, operators install a fracture assembly  10  as shown in  FIG. 1  in a wellbore  12 . Typically, the assembly  10  has a top liner packer (not shown) supporting a tubing string  14  in the wellbore  12 . Open hole packers  50  on the tubing string  14  isolate the wellbore  12  into zones  16 A-C, and various sliding sleeves  20  on the tubing string  14  can selectively communicate the tubing string  14  with the various zones  16 A-C. When the zones  16 A-C do not need to be closed after opening, operators may use single shot sliding sleeves  20  for the frac treatment. These types of sleeves  20  are usually ball-actuated and lock open once actuated. Another type of sleeve  20  is also ball-actuated, but can be shifted closed after opening. 
     Initially, all of the sliding sleeves  20  are closed. Operators then deploy a setting ball to close a wellbore isolation valve (not shown), which seals off the downhole end of the tubing string  14 . At this point, the packers  50  are hydraulically set by pumping fluid with a pump system  35  connected to the wellbore&#39;s rig  30 . The build-up of tubing pressure in the tubing string  14  actuates the packers  50  to isolate the annulus  18  into the multiple zones  16 A-C. With the packers  50  set, operators rig up fracturing surface equipment and pump fluid down the tubing string  14  to open a pressure actuated sleeve (not shown) so a first downhole zone (not shown) can be treated. 
     As the operation continues, operators drop successively larger balls down the tubing string  14  to open successive sleeves  20  and pump fluid to treat the separate zones  16 A-C in stages. When a dropped ball meets its matching seat in a sliding sleeve  20 , fluid is pumped by the pump system  35  down the tubing string  14  and forced against the seated ball. The pumped fluid forced against the seated ball shifts the sleeve  20  open. In turn, the seated ball diverts the pumped fluid out ports in the sleeve  20  to the surrounding annulus  18  between packers  50  and into the adjacent zone  16 A-C and prevents the fluid from passing to lower zones  16 A-C. By dropping successively increasing sized balls to actuate corresponding sleeves  20 , operators can accurately treat each zone  16 A-C up the wellbore  12 . 
     The packers  50  typically have a first diameter to allow the packer  50  to be run into the wellbore  12  and have a second radially larger size to seal in the wellbore  12 . The packer  50  typically consists of a mandrel about which the other portions of the packer  50  are assembled. A setting apparatus includes a port from the inner throughbore of the packer  50  to an interior cavity. The interior cavity may have a piston that is arranged to apply force either directly to a sealing element or to a rod or other force transmitter that will apply the force to the sealing element. 
     Typically, when the packer  50  is set, fluid pressure is applied from the surface via the tubular string  14  and typically through the bore of the tubular string  14 . The fluid pressure is in turn applied through a port on the packer  50  to the packer&#39;s piston. The fluid pressure applied over the surface of the piston is then transmitted to the packer&#39;s sealing element to compress the sealing element longitudinally. 
     Most sealing elements are an elastomeric material, such as rubber. When the sealing element is compressed in one direction it expands in another. Therefore, as the sealing element is compressed longitudinally, it expands radially to form a seal with the well or casing wall. 
     In some situations, operators may want to utilize comparatively long sealing elements in their packers  50 . In these instances, however, as the packer&#39;s piston pushes the sealing element to compress the sealing element longitudinally, friction and other forces combine to cause the sealing element to bunch up or otherwise bind near the packer&#39;s piston, preventing the sealing element from uniformly compressing longitudinally and thereby preventing the uniform radial expansion of the sealing element. The lack of uniform expansion tends to prevent the packer  50  from forming a seal that meets the operator&#39;s expectations, thereby defeating the purpose of utilizing a longer sealing element. For this reason, operators may not use an unset sealing element on a packer  50  that is more than about 24-inches long. Instead, a typical length of an unset seal element is only about 10-inches. 
     Therefore, a need exists for a packer that is able to utilize an extended length sealing element. The present invention fulfills these needs and provides further related advantages. 
     SUMMARY 
     A dual-set hydraulic packer disclosed herein allows a sealing element to be set from both ends so that more setting force and more uniform or balance setting can be applied to the sealing element. The sealing element can be relatively longer than conventionally used. Firstly, the packer is set by applying fluid pressure through the interior throughbore of the packer&#39;s mandrel to a first piston on an end of the sealing element. Then secondly, the packer is set by using pressure in the annulus to set a second piston on the other end of the sealing element. The setting order depends upon the desire of the operator because the packer can be installed either with the annular set piston on top and the tubular set piston on the bottom or vice versa. 
     Accordingly, the disclosed packer has an upper hydraulic setting mechanism, a lower hydraulic setting mechanism, and a sealing element disposed therebetween. The sealing element is sequentially longitudinally compressed separately by the upper hydraulic setting mechanism and the lower hydraulic setting mechanism so that the sealing element experiences compression from both ends during a fracture treatment, acid stimulation, or other operation or treatment where the pressure in a zone is increased. 
     The packer may have a mandrel with an interior and an exterior. The upper hydraulic setting mechanism, the lower hydraulic setting mechanism, and the sealing element are attached to the exterior of the mandrel. Fluid pressure in the mandrel interior typically actuates one or the other of the upper hydraulic setting mechanism or the lower hydraulic setting mechanism, but not both. Also, fluid pressure on the mandrel exterior typically actuates one or the other of the upper hydraulic setting mechanism or the lower hydraulic setting mechanism but not both. 
     The packer may have one or more sealing elements. In one embodiment, the packer may have at least two sealing elements separated by a barrier. The upper hydraulic setting mechanism may have a first piston adjacent to a first of the sealing elements, and the lower hydraulic setting mechanism may have a second piston adjacent to a second of the sealing elements. During operation, internal fluid pressure in the packer may act upon the first piston to radially expand a portion of (or the entire extent of) the sealing element(s). Additionally, external fluid pressure in the surrounding annulus may act upon the second piston to radially expand a portion of (or the entire extent of) the sealing element(s). 
     The packer may have a mandrel with an interior throughbore and an exterior. A first housing may be attached to a first end of the mandrel exterior and a second housing may be attached to a second end of the mandrel exterior. A first cylinder may be located within the first housing and a second cylinder may be located within the second housing. A first piston may be located within the first cylinder and the first piston is in fluid communication with the mandrel interior. A second piston may be located within the second cylinder and the second piston is in fluid communication with the mandrel exterior. 
     The first piston is disposed adjacent to the sealing element and the second piston is also disposed adjacent to the sealing element. Fluid pressure acts upon the first piston or the second piston to radially expand a portion of the sealing element. The first cylinder may be located between the first housing and the mandrel. The second cylinder may be located between the second housing and the mandrel. 
     In use, a packer having an interior, an exterior, a first hydraulic actuating mechanism, and a second hydraulic actuating mechanism may be run into a well. The interior of the packer is pressurized to actuate the first hydraulic actuating mechanism causing the sealing element to radially expand. The exterior of the packer is then pressurized to actuate the second hydraulic actuating mechanism causing the sealing element to radially expand. 
     As used herein, the terms such as lower, downward, downhole, and the like refer to a direction towards the bottom of the well, while the terms such as upper, upwards, uphole, and the like refer to a direction towards the surface. The uphole end is referred to and is depicted in the figures at the top of each page, while the downhole end is referred to and is depicted in the figures at the bottom of each page. This is done for illustrative purposes in the following figures. The tool may be run in a reverse orientation. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         FIG. 1  diagrammatically illustrates a tubing string having multiple sleeves and openhole packers of a fracture system. 
         FIG. 2  depicts a double-set hydraulic packer according to the present disclosure in a run-in condition. 
         FIG. 3  depicts the double-set hydraulic packer with a first (downhole) hydraulic setting mechanism in an actuated condition. 
         FIG. 4  depicts the double-set hydraulic packer with the downhole hydraulic setting mechanism and a second (uphole) hydraulic setting mechanism in actuated conditions. 
         FIG. 5  depicts a double-set hydraulic packer having first and second hydraulic setting mechanisms in actuated conditions and having a barrier disposed between first and second members of a sealing element. 
     
    
    
     DETAILED DESCRIPTION 
     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. 
       FIG. 2  depicts a double-set hydraulic packer  100  according to the present disclosure in an unset or run-in condition in a wellbore  12 , which may be a cased or open hole. The packer  100  includes a mandrel  110  with an internal bore  112  passing therethrough that connects on a tubing string ( 14 :  FIG. 1 ) using known techniques. The packer  100  has first and second hydraulic setting mechanisms  150  and  160  disposed adjacent to ends of a sealing element  140 . As will be appreciated, the sealing element  140  may be longer or shorter than depicted and may comprise several pieces. In fact, the sealing element  140  for the disclosed packer  100  may be considerably longer than conventional elements used on packers and can be greater than 10-in. in length depending on the implementation. 
     In general and as shown in  FIG. 2 , the first hydraulic setting mechanism  150  can be disposed on a downhole end of the packer  100 , while the second hydraulic setting mechanism  160  can be disposed on an uphole end. As will be appreciated with the benefit of the present disclosure, however, a reverse arrangement can be used, depending on the implementation, orientation, and access to tubing and annulus pressures in the wellbore  12 . 
     A first (downhole) end of the packer  100  has a first end ring  120  fixed to the mandrel  110  by lock wire  118 , pins, or the like. Part of this first end ring  120  forms a first housing  124  having an inner surface, which forms a first internal cylinder chamber  122  in conjunction with the external surface of the mandrel  110 . A first push rod or piston  152  resides in the first cylinder chamber  122  and has its end surface exposed to the chamber  122 . Accordingly, the first push rod  152  acts as a first piston in the presence of pressurized fluid F ( FIG. 3 ) communicated from the internal bore  112  of the mandrel  110  into the chamber  122  through one or more ports  115 . 
     During a setting operation, for example, fluid pressure is communicated downhole through the tubing string ( 14 :  FIG. 1 ) and eventually enters the internal bore  112  of the packer&#39;s mandrel  110 . This setting operation can be performed after run-in of the packer  100  in the wellbore  12  so that the packer  100  can be set and zones of the wellbore&#39;s annulus  18  can be isolated from one another. While the tubing pressure inside the packer  100  is increased, external fluid pressure in the annulus  18  surrounding the packer  100  remains below the tubing pressure. During this setting operation, the packer  100  begins a first setting procedure in which the first setting mechanism  150  is activated to compress the sealing element  140 . 
       FIG. 3  depicts the packer  100  during this first setting procedure where only the first hydraulic setting mechanism  150  is being utilized. Pressurized fluid F in the mandrel&#39;s bore  112  accesses the first piston  152  in the first cylinder chamber  122  through the one or more first ports  115  in the mandrel  110 . Building in the chamber  122 , the pressurized fluid F acts on the first piston  152  and forces the piston&#39;s end  154  against one end  144  of the sealing element  140  disposed on the mandrel  110 . As the piston  152  moves along the mandrel  110 , it longitudinally compresses the sealing element  140 . In turn, as the sealing element  140  is longitudinally compressed, the element  140  radially expands from a first diameter D 1  to a second diameter D 2  toward the surrounding borehole  12 . 
     As depicted in  FIG. 3 , the radial expansion is shown as occurring partially along the length of the sealing element  140 . This may or may not be the case depending on the length of the sealing element  140  and the friction and other forces encountered. In any event, the radial expansion of the sealing element  140  against the wellbore  12  separates the annulus  18  into an uphole annular region  18 U and a downhole annular region  18 D. 
     As will be appreciated, fluid pressure in the mandrel  110  entering second ports  116  for the second mechanism  160  does not activate this mechanism  160 , for reasons that will be apparent below. Instead, fluid pressure entering a chamber  170  of the second mechanism  160  during the first setting procedure actually tends to keep the second mechanism  160  in its original position so that the mechanism  160  acts as a fixed stop for the compression of the sealing element  140 . 
     During setting, the increased second diameter D 2  tends to cause the sealing element  140  to experience an increase in friction that can eventually limit the radial expansion of the sealing element  140 . In general, all or only a portion of the sealing element  140  may longitudinally compress and radially expand to a full or nearly full extent against the surrounding wellbore  12 .  FIG. 3  only shows partial activation for the purposes of illustration. The compression and expansion can proceed at least until the friction and any other external forces equal the force used to compress the element  140 . 
       FIG. 3  also depicts further details of the second hydraulic setting mechanism  160  at the second end of the packer  100 . A second end ring  130  is fixed to the mandrel  110  by lock wires  118  or the like is disposed adjacent to a second piston  162  of the mechanism  160 . As shown, the piston  162  can be composed of several components, including a push rod end  164  connected by an intermediate sleeve  165  to a piston end  166 . Use of these multiple components  164 ,  165 , and  166  can facilitate assembly of the mechanism  160 , but other configurations can be used. 
     The push rod end  164  of the second piston  162  is disposed against a second end  146  of the sealing element  140 . On the other end, the piston end  166  is disposed adjacent to the second end ring  130 , but the piston end  166  is subject to effects of fluid pressure in the uphole annular region  18 U, as will be discussed further below. A fixed piston  168  is attached to the mandrel  110  by lock wire  118  to enclose the second piston chamber  170  of the second piston  162 . The chamber  170  is isolated by various seals (not shown) from fluid pressure in the uphole annular region  18 U formed by the packer  100  and the wellbore  12 . As long as the second hydraulic setting mechanism  160  remains in an unactuated state as in  FIG. 3 , the chamber  170  does not decrease or increase in volume. 
     During operations after the first mechanism  150  is actuated and the sealing element  140  set, fluid pressure in the uphole annular region  18 U may be increased, which will then actuate the second mechanism  160 . For example, during a fracture treatment, operators fracture zones downhole from the disclosed packer  100  by pumping fluid pressure downhole, which merely communicates through the mandrel&#39;s bore  112  to further downhole components. The buildup of tubing pressure may tend to further set the first hydraulic setting mechanism  150 , but may tend to keep the second hydraulic setting mechanism  160  unactuated, as noted above. 
     Then, operators isolate the packer&#39;s internal bore  112  uphole of the packer  100 . For example, operators may drop a ball down the tubing string ( 14 :  FIG. 1 ) to land in a seat of a sliding sleeve ( 20 :  FIG. 1 ) uphole of this packer  100 . When the sliding sleeve ( 20 ) is opened and fracture pressure is applied to the formation through the open sleeve ( 20 ), the borehole pressure in the uphole annular region  18 U increases above the isolated tubing pressure in the mandrel&#39;s bore  112 . However, the internal pressure in the mandrel&#39;s bore  112  does not increase due to the plugging by the set ball on the seat in the uphole sliding sleeve ( 20 ). It is this buildup of borehole pressure in the uphole annular region  18 U outside the packer  100  compared to the tubing pressure inside the packer  100  that activates the second mechanism  160 . 
     In particular,  FIG. 4  depicts the packer  100  with both the first and second hydraulic setting mechanisms  150  and  160  having been actuated. For the second hydraulic setting mechanism  160  to actuate, the tubing pressure in the inner bore  112  of the mandrel  110  is relieved, reduced, or isolated as noted above, while the borehole pressure in the uphole annular region  18 U around the packer  100  is increased. In certain instances, it may not be necessary to relieve the fluid pressure in the inner bore  112  as long as the pressure in the uphole annular region  18 U may be increased to overcome any pressure in the inner bore  112  to a sufficient level to actuate the second hydraulic setting mechanism  160 . 
     With a sufficient buildup of pressure in the uphole annular region  18 U, the external pressurized fluid in the region  18 U acts upon the external face of the piston end  166 . Chamber  170 , which is at the lower tubing pressure, is sealed from the external pressure from the annular region  18 U. Thus, an internal face of the piston end  166  is exposed to the lower tubing pressure in the chamber  170 . Consequently, the pressure differential causes the second piston  162  to move along the mandrel  110  and exert a force against the sealing element  140 . 
     As the second piston  162  moves, it further compresses the sealing element  140 . The lower tubing pressure in the chamber  170  can escape into the mandrel&#39;s bore  112  through ports  116  while the chamber  170  decreases in volume with any movement of the second piston  162 . As the piston  162  moves, it longitudinally compresses against the sealing element  140 , which can radially expand further or more fully against the wellbore  12 , thereby completing the radial expansion of the sealing element  140  against the surrounding wellbore  12 . As noted above, the first mechanism  150  may compress the sealing element  140  practically to its full extent at least until a level of friction and other force is met. The second mechanism  160  can overcome the built-up friction to even further compress the sealing element  140 , which can further radially expand the element  140 . 
     As can be seen in the above embodiment, the packer  100  has a first hydraulic setting mechanism  150  for the sealing element  140  that uses an internal piston and cylinder arrangement moved with fluid pressure F from the interior bore  112  of the packer&#39;s mandrel  110  to at least partially set the sealing element  140 . In this first setting procedure, the interior bore  112  has a high pressure, while the annulus  18  has a lower pressure. The second setting mechanism  160  remains unactivated and acts as a stop against the other end of the sealing element  140 . This can be useful when fracturing a formation downhole of the packer  100 , for example. 
     As also seen above, the packer  100  has the second hydraulic setting mechanism  160  for the sealing element  140 . This second mechanism  160  has an annulus piston and cylinder arrangement moved by fluid pressure in the uphole annular region  18 U surrounding the packer  100 . In the second setting procedure, the second mechanism  160  is actuated when there is a higher pressure in the annular region  18 U and a lower pressure in the mandrel&#39;s interior bore  112 . This procedure can be useful when fracturing the formation uphole of the packer  100 , for example. The two setting mechanisms  150  and  160  may have the same or different setting pressures depending on the implementation. 
     Having the second setting mechanism  160  allows the sealing element  140  to be set additionally, and more uniformly with more force from the opposite side, after the packer  100  has already completed a first setting procedure and engagement with the wellbore  12 . Accordingly, the length of the sealing element  140  can be longer than conventionally used to seal over longer cracks in a formation. In other words, the sealing element  140  can be greater than the conventional 10-in. length usually used, and the mechanisms  150  and  160  may overcome the issues typically experienced with longer sealing elements. 
     The second setting procedure of the sealing element  140  can be performed when the element  140  has been allowed to cool and contract due to cold fluid flowing through the packer&#39;s mandrel  110 . The second setting procedure also overcomes the friction issue encountered with longer sealing elements used on the packer  100 . The second setting procedure of the sealing element  140  after it has contracted can also give the packer  100  a much better long term sealing capability. Finally, the annular pressure applied in the second setting procedure can act against a larger annular area to set the packer  100  and can provide a much higher total setting force. 
     In certain instances, it may be desirable to isolate one end of the sealing element  140  from the other end, thereby allowing separate sealing actions to work together while each end is actuated independently.  FIG. 5  depicts an embodiment of a packer  100  having a central sealing element  140  with at least two members  142   a - b  between the mechanisms  150  and  160 . The first hydraulic setting mechanism  150  sets a first sealing member  142   a  of the packer&#39;s central sealing element  140 , and the second hydraulic setting mechanism  160  sets a second sealing member  142   b  of the packer&#39;s element  140 . 
     A barrier  148  isolates the first sealing member  142   a  from the second sealing member  142   b . The barrier  148  may or may not be anchored to the mandrel  110  and can be composed of any suitable material (e.g., metal, plastic, elastomer, etc.). If the barrier  148  is anchored to the mandrel  110 , the barrier  148  allows either sealing member  142   a - b  to be set without regard to the other sealing element. If the barrier  148  is not anchored to the mandrel  110 , it will move with the elastomer if either mechanism  150  or  160  sets. In other words, the sealing members  142   a - b  will behave like a single element  140 . 
     While the embodiments are described with reference to various implementations and exploitations, it will be understood that these embodiments are illustrative and that the scope of the inventive subject matter is not limited to them. Many variations, modifications, additions and improvements are possible. 
     For example, although not shown in the figures, the packer  100  may use any of the conventional mechanisms for locking the push rods or pistons  152  and  162  in place on the mandrel  110  once set against the sealing element  140 . Accordingly, ratchet mechanisms, lock rings, or the like (not shown) can be used to prevent the rods or pistons  152  and  162  from moving back away from the sealing element  140  once set. Additionally, various internal seals, threads, and other conventional features for components of the packer  110  are not shown in the figures for simplicity, but would be evident to one skilled in the art. 
     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. 
     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.

Summary:
A device and method allow a longer sealing element to be used on a packer or other downhole tool while providing an increase in the total amount of setting force that can be used and providing for more uniform or balanced setting of the sealing element. The packer may be first set using internal bore pressure to radially expand one end of the sealing element with a first hydraulic setting mechanism. The packer may then be set a second time using annulus pressure to continue the radial expansion of the sealing element with a second hydraulic setting mechanism.