Abstract:
A temperature actuated element includes a mandrel, a housing coupled to the mandrel, the housing defining a fluid expansion chamber. A piston is positioned within the fluid expansion chamber. A thermally expanding fluid is positioned within the fluid expansion chamber. An end ring coupled to the piston slides along the mandrel in response to a sliding of the piston. A degradable ring is coupled to the mandrel to prevent movement of the end ring before the degradable ring is dissolved. A packer having a first end and a second end, the first end adapted to slide along the mandrel in response to a sliding of the end ring, and the second end fixedly coupled to the mandrel, so that a sliding of the first end of the packer toward the second end causes the packer element to decrease in length and increase in radius.

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
       [0001]    This application is a continuation in part of U.S. application Ser. No. 14/337,892, a non-provisional application which claims priority from U.S. provisional application No. 61/857,092, filed Jul. 22, 2013. The entirety of U.S. application Ser. No. 14/337,892 is hereby incorporated by reference in its entirety. 
     
    
     TECHNICAL FIELD/FIELD OF THE DISCLOSURE 
       [0002]    The present disclosure relates to downhole tools for forming a well seal in an annulus between an inner tubular and either an outer tubular or a borehole wall, or forming a plug with the outer tubular or borehole wall. 
       BACKGROUND OF THE DISCLOSURE 
       [0003]    Swellable packers are isolation devices used in a downhole wellbore to seal the inside of the wellbore or a downhole tubular that rely on elastomers to expand and form an annular seal when immersed in certain wellbore fluids. Typically, elastomers used in swellable packers are either oil- or water-sensitive. Various types of swellable packers have been devised, including packers that are fixed to the OD of a tubular and the elastomer formed by wrapped layers, and designs wherein the swellable packer is slipped over the tubular and locked in place. 
       SUMMARY 
       [0004]    The present disclosure provides for a temperature compensated element. The temperature compensated element may include a mandrel. The mandrel may be generally tubular and may have a central axis and an exterior cylindrical surface. The temperature compensated element may further include a housing coupled to the mandrel. The housing may define a fluid expansion chamber between an inner wall of the housing and the exterior cylindrical surface of the mandrel. The temperature compensated element may further include a piston positioned about the mandrel. The piston may have a piston head positioned within the fluid expansion chamber and adapted to slide along the mandrel. The piston head may form a seal against the housing and the mandrel to enclose the fluid expansion chamber. The temperature compensated element may further include a thermally expanding fluid positioned within the fluid expansion chamber. The temperature compensated element may further include an end ring positioned about the mandrel. The end ring may be coupled to the piston. The end ring may be adapted to slide along the mandrel in response to a sliding of the piston. The temperature compensated element may further include a degradable ring coupled to the mandrel. The degradable ring may be positioned adjacent to the end ring and adapted to prevent sliding of the end ring before the degradable ring has at least partially dissolved. The temperature compensated element may further include a packer including a packer element coupled to the exterior cylindrical surface of the mandrel. The packer may have a first end and a second end. The first end may be adapted to slide along the mandrel in response to a sliding of the end ring. The second end may be fixedly coupled to the mandrel, so that a sliding of the first end of the packer toward the second end causes the packer element to decrease in length and increase in radius. 
         [0005]    The present disclosure also provides for a method of isolating a section of wellbore. The method may include providing a temperature compensated element. The temperature compensated element may include a mandrel. The mandrel may be generally tubular and may have a central axis and an exterior cylindrical surface. The temperature compensated element may further include a housing coupled to the mandrel. The housing may define a fluid expansion chamber between an inner wall of the housing and the exterior cylindrical surface of the mandrel. The temperature compensated element may further include a piston positioned about the mandrel. The piston may have a piston head positioned within the fluid expansion chamber and adapted to slide along the mandrel. The piston head may form a seal against the housing and the mandrel to enclose the fluid expansion chamber. The temperature compensated element may further include a thermally expanding fluid positioned within the fluid expansion chamber. The temperature compensated element may further include an end ring positioned about the mandrel. The end ring may be coupled to the piston. The end ring may be adapted to slide along the mandrel in response to a sliding of the piston. The temperature compensated element may further include a degradable ring coupled to the mandrel. The degradable ring may be positioned adjacent to the end ring and adapted to prevent sliding of the end ring before the degradable ring has at least partially dissolved. The temperature compensated element may further include a packer including a packer element coupled to the exterior cylindrical surface of the mandrel. The packer may have a first end and a second end. The first end may be adapted to slide along the mandrel in response to a sliding of the end ring. The second end may be fixedly coupled to the mandrel. The method may further include coupling the temperature compensated element to a downhole tubular assembly, running the downhole tubular assembly into a wellbore, and heating the downhole tubular assembly. The method may also include dissolving the degradable ring. The method may further include expanding the thermally expanding fluid, causing the piston, end ring, and first end of the packer to move along mandrel so that the packer element decreases in length and increases in radius, defining an actuated position. The method may further include contacting the wellbore with the outer surface of the packer. 
         [0006]    The present disclosure also provides for a delayed compensation element. The delayed compensation element may include a mandrel. The mandrel may be generally tubular and may have a central axis and an exterior cylindrical surface. The delayed compensation element may further include a housing coupled to the mandrel. The delayed compensation element may further include an end ring positioned about the mandrel. The end ring may be adapted to slide along the mandrel. The delayed compensation element may further include a spring positioned between the housing and the end ring. The spring may be adapted to force the end ring away from the housing. The delayed compensation element may further include a degradable ring coupled to the mandrel. The degradable ring may be positioned adjacent to the end ring and adapted to prevent sliding of the end ring before the degradable ring has at least partially dissolved. The delayed compensation element may further include a packer including a packer element coupled to the exterior cylindrical surface of the mandrel. The packer may have a first end and a second end. The first end may be adapted to slide along the mandrel in response to a sliding of the end ring. The second end may be fixedly coupled to the mandrel, so that a sliding of the first end of the packer toward the second end causes the packer element to decrease in length and increase in radius. 
     
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         [0007]    The present disclosure is best understood from the following detailed description when read with the accompanying figures. It is emphasized that, in accordance with the standard practice in the industry, various features are not drawn to scale. In fact, the dimensions of the various features may be arbitrarily increased or reduced for clarity of discussion. 
           [0008]      FIG. 1  is an elevation view of a temperature compensated element in a run in configuration consistent with at least one embodiment of the present disclosure. 
           [0009]      FIG. 2  is an elevation view of the temperature compensated element of  FIG. 1  in an actuated configuration. 
           [0010]      FIG. 3  is a partial quarter-section view of a piston of a temperature compensated element consistent with at least one embodiment of the present disclosure. 
           [0011]      FIG. 4  is a partial cutaway view of a temperature compensated element consistent with at least one embodiment of the present disclosure. 
           [0012]      FIG. 5  is a cross section of a temperature compensated element consistent with at least one embodiment of the present disclosure. 
           [0013]      FIG. 6  is a cross section of the temperature compensated element of  FIG. 5 . 
       
    
    
     DETAILED DESCRIPTION 
       [0014]    It is to be understood that the following disclosure provides many different embodiments, or examples, for implementing different features of various embodiments. Specific examples of components and arrangements are described below to simplify the present disclosure. These are, of course, merely examples and are not intended to be limiting. In addition, the present disclosure may repeat reference numerals and/or letters in the various examples. This repetition is for the purpose of simplicity and clarity and does not in itself dictate a relationship between the various embodiments and/or configurations discussed. 
         [0015]      FIGS. 1 and 2  illustrate one embodiment of a temperature compensated element  20  for positioning downhole in a well to seal with either the interior surface of a borehole or an interior surface of a downhole tubular. Temperature compensated element  20  is coupled to mandrel  5 . Mandrel  5  may be included as part of a well tubular string (not shown). One having ordinary skill in the art with the benefit of this disclosure will understand that the well tubular string may be a drill string, casing string, tubing string, or any other suitable tubular member for use in a wellbore, and may have multiple components including, without limitation, tubulars, valves, or packers without deviating from the scope of this disclosure. 
         [0016]    In at least one embodiment, temperature compensated element  20  may include housing  22 , end ring  24 , and swellable packer  26 . Swellable packer  26  may include packer element  29 . Swellable packer  26  may include a plurality of slats  28  at either end to, for example, form an extrusion barrier for packer element  29 , couple swellable packer  26  to mandrel  5  and help prevent flow of the swellable packer material when in a swelled state. Swellable packer  26  may also include retainer ring  27  positioned to, for example, couple swellable packer  26  to mandrel  5  and to prevent any movement of swellable packer  26  along mandrel  5 . One having ordinary skill in the art with benefit of this disclosure will understand that although the packer is described as a swellable packer throughout this disclosure, a non-swellable elastomeric packer element may be substituted without deviating from the scope of this disclosure. 
         [0017]    Housing  22 , end ring  24 , and swellable packer  26  may be positioned about mandrel  5  and may be coupled thereto. As depicted in  FIG. 4 , housing  22  of temperature compensated element  20  may be coupled to mandrel  5  by set screw  21 . One having ordinary skill in the art with the benefit of this disclosure will understand that housing  22  may be coupled to mandrel  5  by any suitable mechanism without deviating from the scope of this invention, including without limitation a set screw, shear wire, adhesive, etc. 
         [0018]    Housing  22  may include a fluid expansion chamber  30 . Fluid expansion chamber  30  may be filled with a thermally expanding fluid which may volumetrically expand in response to an increase in temperature caused by, for example, steam being passed through the interior of mandrel  5  or higher temperature hydrocarbons produced within the well. In some embodiments, the thermally expanding fluid may be selected to remain in a liquid phase throughout the temperatures and pressures to which it may be exposed during operation of temperature compensated element  20 . 
         [0019]    As depicted in  FIGS. 3 ,  4 , fluid expansion chamber  30  may be an annular space defined by the outer surface of mandrel  5 , the inner surface of housing  22 , and piston  32 . Housing  22  may include at least one seal  23  to fluidly seal fluid expansion chamber  30  against mandrel  5 . Piston  32  may include a piston head  34 , a piston extension  36 , and a piston operating body  38 . Piston  32  may be positioned to slide within fluid expansion chamber  30  along the outer surface of mandrel  5  in response to a volumetric expansion of the fluid within fluid expansion chamber  30  as the fluid is heated. The fluid presses on piston head  34 , causing a sliding displacement of piston  32  along mandrel  5 . Piston head  34  may include one or more seals  40  positioned to prevent the fluid from escaping expansion chamber  30 . As piston  32  moves, piston operating body  38  contacts end ring  24  and causes it to likewise slide along mandrel  5 . The movement of end ring  24  towards swellable packer  26  causes a compression of swellable packer  26  along mandrel  5 , which causes swellable packer  26  to mechanically expand in the wellbore. 
         [0020]    As depicted in  FIG. 4 , end ring  24  may, in some embodiments, include a body lock ring  42  positioned within a recess in the interior surface of end ring  24 . Body lock ring  42  may include teeth  44  on its interior positioned to interlock with wickers  46 , here depicted as formed on the outer surface of mandrel. Body lock ring  42  may be positioned so that once piston  32  has moved in response to the thermal expansion of the fluid in the fluid expansion chamber  30 , teeth  44  mesh with wickers  46  and prevent end ring  24  and piston  32  from returning to the run-in position from, for example, elastic reaction forces of swellable packer  26 . One having ordinary skill in the art with the benefit of this disclosure will understand that body lock ring  42  may be positioned in other locations, such as piston extension  32 , slats  28 , etc. without deviating from the scope of this disclosure. Furthermore, one having ordinary skill in the art with the benefit of this disclosure will understand that wickers  46  may be formed in a separate member and not directly in the surface of mandrel  5 . One having ordinary skill in the art with the benefit of this disclosure will understand that body lock ring  42  may be positioned along mandrel  5  with wickers positioned on end ring  24 , piston extension  32 , or slats  28 . 
         [0021]    Swellable packer  26  may be formed from a material which swells in response to the absorption of a swelling fluid, generally an oil or water-based fluid. The composition of the swelling fluid needed to activate swellable packer  26  may be selected with consideration of the intended use of the packer. For example, a packer designed to pack off an area of a well at once may be either oil or water-based and activated by a fluid pumped downhole. Alternatively, a delayed-use packer may be positioned in a well for long periods of time during, for example, hydrocarbon production. A swellable packer  26  which swells in response to an oil-based fluid would prematurely pack off the annulus. A swellable packer  26  which swells in response to water would therefore be used. 
         [0022]    When swellable packer  26  is activated, the selected swelling fluid comes into contact with swellable packer  26  and may be absorbed by the material. In response to the absorption of swelling fluid, swellable packer  26  increases in volume and eventually contacts the wellbore, or the inner bore of the surrounding tubular. Continued swelling of swellable packer  26  forms a fluid seal between mandrel  5  and the wellbore or surrounding tubular. Pressure may then be applied from one or more ends of swellable packer  26 . 
         [0023]    Swellable packer  26  may likewise expand or contract in response to variations in temperature. For example, during a cycling steam stimulation (CSS) operation or steam-assisted gravity drainage (SAG-D) operation, high-pressure steam may be forced through a tool string. This steam will heat swellable packer  26  and may cause a thermal expansion in addition to any swelling expansion. When steam injection is halted, a conventional swellable packer may thermally contract, thereby potentially compromising the seal created by the swelling expansion of the swellable packer. As illustrated in  FIG. 2  and previously described, swellable packer  26  may be mechanically expanded by the movement of end ring  24  as the thermally expanding fluid in fluid expansion chamber  22  is heated. This mechanical expansion may, for example, compensate for any thermal contraction as swellable packer  26  cools. 
         [0024]    In some embodiments, housing  22  may include a pressure relief apparatus to prevent damage to temperature compensated element  20  caused by too much pressure within fluid expansion chamber  22 . The pressure relief apparatus may be positioned to, at a selected threshold pressure, release at least some thermally expanding fluid from fluid expansion chamber  22  into, for example, the surrounding wellbore. In some embodiments, the pressure relief apparatus may include, for example and without limitation, a relief or safety valve, blowoff valve, or a rupture disc such as rupture disc  48  as depicted in  FIG. 4 . Rupture disc  48  may be positioned in the wall of fluid expansion chamber  22 . Rupture disc  48  may be calibrated to mechanically fail once the fluid in fluid expansion chamber  22  reaches a selected threshold pressure to, for example, prevent damage to temperature compensated element  20  or swellable packer  26 . When rupture disc  48  fails, fluid from fluid expansion chamber  22  may flow into the surrounding wellbore. Rupture disc  48  may be calibrated by varying, for example, its diameter, thickness, and by placing weakening grooves in its structure. 
         [0025]    In some embodiments, temperature compensated element  20  may include a backup system to, for example and without limitation, prevent or delay the extension of piston  32  while in the wellbore. In some embodiments, as depicted in  FIGS. 5 ,  6 , temperature compensated element  20  may include at least one backup ring  50 . Backup ring  50  may, in some embodiments, be coupled between end ring  24  and swellable packer  26 . In some embodiments, at least a part of backup ring  50  may include degradable ring  52 . Degradable ring  52  may be formed from a material selected to be initially solid and to degrade when exposed to one or more selected conditions. For example and without limitation, degradable ring  52  may be adapted to dissolve when exposed to, for example and without limitation, high temperature, oil or water based fluids, acidic or basic fluids, or by chemical reaction with a dissolving agent introduced into the wellbore. In some embodiments, degradable ring  52  may be formed from a material which requires a selected amount of time to dissolve when exposed to the selected conditions. For example and without limitation, in some embodiments, degradable ring  52  may be formed from PLA. 
         [0026]    In some embodiments, as depicted in  FIG. 5 , degradable ring  52  may be coupled to mandrel  5 . Degradable ring  52  may be positioned to prevent the extension of end ring  24  before degradable ring  52  at least partially dissolves. Once degradable ring  52  sufficiently dissolves, end ring  24  may be extended as discussed herein as depicted in  FIG. 6 . 
         [0027]    In some embodiments, as depicted in  FIG. 5 , degradable ring  52  may be contained within encapsulation  54 . In some embodiments, encapsulation  54  may surround degradable ring  52  to, for example and without limitation, prevent damage to degradable ring  52  while allowing fluid contact between degradable ring  52  and the wellbore. In some embodiments, encapsulation  54  may be, for example and without limitation, formed as a metal mesh. In some embodiments, encapsulation  54  may be formed from a material selected such that encapsulation  54  does not interfere with the extension of end ring  24 . In some embodiments, encapsulation  54  may be adapted to be crushed between end ring  24  and swellable packer  26  as depicted in  FIG. 6 . 
         [0028]    One having ordinary skill in the art with the benefit of this disclosure will understand that backup ring  50  may be used in conjunction with any mechanism configured to compress a swellable packer  26  including, for example and without limitation, a spring positioned to extend end ring  32 . In such an embodiment, an end ring is biased to compress a swellable packer as discussed hereinabove, but is prevented from moving by backup ring  50  until degradable ring  52  has sufficiently dissolved. 
         [0029]    In order to understand the operation of a temperature compensated element as described herein, an exemplary operation thereof will now be described. Although this example describes only a cycling steam stimulation operation, one having ordinary skill in the art with the benefit of this disclosure will understand that the example is not intended to limit use of the temperature compensated element in any way to one particular operation, and the temperature compensated element described may be used in other operations without deviating from the scope of this disclosure. 
         [0030]    In a CSS operation, as understood in the art, high-pressure steam may be injected into a formation through a downhole tubular. The steam heats the formation and any hydrocarbons contained therein to, for example, reduce viscosity thereof and thereby allow a higher flow rate. Once the desired heating has been effected, the steam injection is halted, and hydrocarbons may flow through the tubular more rapidly than before the CSS operation. Cycles of heating and production may be repeated multiple times. 
         [0031]    Temperature compensated element  20  as depicted in  FIG. 1  may be included as a part of the downhole tubular assembly (not shown). In one embodiment, the downhole tubular assembly may be a string of production casing. Temperature compensated element  20  may be run-into the wellbore (not shown) in the run-in position depicted in  FIG. 1 . Once in position in the wellbore, fluids in the wellbore may be absorbed by swellable packer  26 . Swellable packer  26  volumetrically expands as swelling fluids are absorbed, causing swellable packer  26  to form a seal against the surrounding wellbore. Temperature compensated element  20  may be left to expand for a period of time before enhanced recovery operations commence, i.e. during primary and/or secondary recovery operations. During this time, swellable packer  26  may operate as a normal swellable packer in the wellbore to isolate the formation on one side of temperature compensated element  20  from the wellbore on the other side of temperature compensated element  20 . 
         [0032]    At some point it may be decided to run a CSS operation. At this time, steam may be injected through the downhole tubular assembly including through mandrel  5  of temperature compensated element  20 . The hot steam causes the thermally expanding fluid in fluid expansion chamber  30  to expand, forcing piston  32  and end ring  24  along mandrel  5  as previously discussed. Swellable packer  26  may be compressed along mandrel  5 . This deformation causes swellable packer  26  to increase in radius and/or press more firmly against the surrounding wellbore. Once the desired expansion has been achieved, body lock ring  42  engages wickers  46 , thereby locking swellable packer  26  in the actuated position depicted in  FIG. 2 . When steam injection is halted, body lock ring  42  maintains the actuated position even as fluid in the fluid expansion chamber cools. 
         [0033]    In some embodiments, temperature compensated element  20  may be heated by fluids within the formation naturally or artificially heated in the formation. For example, in a SAG-D operation as understood in the art, a temperature compensated element  20  located within the production well may be heated by the hydrocarbons heated by the steam injection well. In other embodiments, produced hydrocarbons may naturally exist at a higher temperature than the wellbore when drilled. Therefore, the production of the hydrocarbons themselves may serve to heat the fluid within temperature compensated element  20 . 
         [0034]    In embodiments utilizing a backup ring  50  as depicted in  FIG. 5 , although the pressure in fluid expansion chamber  30  has risen, backup ring  50  may prevent unwanted or premature extension of end ring  24 . Only once degradable ring  52  has sufficiently dissolved, by the application of a dissolving agent, fluid, or heat as determined by the composition of degradable ring  52 , may end ring  24  extend. 
         [0035]    In some embodiments, rupture disc  48  may be included in the wall of housing  22 , and may be calibrated such that the pressure necessary to achieve full actuation will cause rupture disc  48  to fail, allowing the pressurized fluid within fluid expansion chamber  30  to flow into the surrounding wellbore, relieving pressure on piston  32 . 
         [0036]    In some embodiments of the invention, the fluid in fluid expansion chamber  30  may be heated to between 200° F. and 900° F. In other embodiments, the fluid in fluid expansion chamber  30  may be heated to between 200° F. and 650° F. In some embodiments, the pressure of fluid in fluid expansion chamber  30  may be increased to between 500 and 4000 psi. In other embodiments, the pressure of fluid in fluid expansion chamber  30  may be increased to between 500 and 2200 psi. 
         [0037]    The foregoing outlines features of several embodiments so that a person of ordinary skill in the art may better understand the aspects of the present disclosure. Such features may be replaced by any one of numerous equivalent alternatives, only some of which are disclosed herein. One of ordinary skill in the art should appreciate that they may readily use the present disclosure as a basis for designing or modifying other processes and structures for carrying out the same purposes and/or achieving the same advantages of the embodiments introduced herein. One of ordinary skill in the art should also realize that such equivalent constructions do not depart from the spirit and scope of the present disclosure and that they may make various changes, substitutions, and alterations herein without departing from the spirit and scope of the present disclosure.