Patent Publication Number: US-2016237775-A1

Title: Setting assembly and method thereof

Description:
CROSS REFERENCE TO RELATED APPLICATIONS 
     This application is a divisional of U.S. application Ser. No. 13/945,092 filed Jul. 18, 2013, the disclosure of which is incorporated by reference herein in its entirety. 
    
    
     BACKGROUND 
     In the drilling and completion industry, the formation of boreholes for the purpose of production or injection of fluid is common. The boreholes are used for exploration or extraction of natural resources such as hydrocarbons, oil, gas, water, and alternatively for CO2 sequestration. It is often necessary to isolate a zone within the borehole or within a tubular structure within the borehole, such as a casing or tubing string. Zone isolation is typically performed using packers which perform well for such a purpose. The packer is typically a flexible, elastomeric device that has a smaller initial outside diameter that then expands externally to seal to the borehole or outer tubing, thus separating the annulus between a tubular that supports the packer and the borehole or outer tubing into separate zones. Packers may be set through inflation or compression and are useful in both production and injection operations where zone isolation is useful. Some packers are also re-settable allowing for multiple uses and trips within the borehole. 
     One situation in which zonal isolation is useful is steam assisted gravity drainage (“SAGD”). SAGD is a process for the recovery of heavy oil in which two parallel adjacent horizontal boreholes are drilled in a formation. The upper borehole (an injection well) injects steam to the formation and reduces the viscosity of the heavy crude oil or bitumen, allowing it to flow down to the lower borehole (a production well) that collects the heated crude oil or bitumen. 
     The art would be receptive to alternative devices and methods for isolation within a borehole, as well as alternative devices and methods useful in SAGD. 
     BRIEF SUMMARY 
     A setting assembly includes an inflatable packer, a housing including a chamber, a setting material disposed in the chamber and having a first phase of matter and a second phase of matter, the setting material occupying a greater volume in the second phase than in the first phase, the setting material arranged to exert a setting force on the inflatable packer during transition of the setting material from the first phase to the second phase, and at least one pressure relief member within the chamber, the pressure relief member configured to protect the inflatable packer from rupturing. 
     A downhole system includes a tubular structure having a longitudinal axis, and a setting assembly. The setting assembly includes an inflatable packer, a housing including a chamber, the housing connected to the tubular structure and sharing an interior flowpath with the tubular structure, the chamber disposed exteriorly of the interior flowpath, a setting material disposed in the chamber and having a first phase of matter and a second phase of matter, the setting material occupying a greater volume in the second phase than in the first phase, the setting material arranged to exert a setting force on the inflatable packer during transition of the setting material from the first phase to the second phase, and at least one pressure relief member within the chamber, the pressure relief member configured to protect the inflatable packer from rupturing. 
     A method of setting an inflatable packer, the method including enclosing a phase changeable setting material within a chamber of a housing in a solid state, heating the setting material to melt the setting material to a liquid state to expand a volume of the setting material, harnessing the expansion of the setting material as a setting force to set the inflatable packer, and protecting the inflatable packer from rupture. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       Referring now to the drawings wherein like elements are numbered alike in the several Figures: 
         FIG. 1  shows a cross-sectional view of an exemplary embodiment of a downhole tool having a setting assembly using packers; 
         FIG. 2  shows a partial cross-sectional view of an exemplary embodiment of the setting assembly of  FIG. 1  with the packer in an unset condition; 
         FIG. 3  shows a partial cross-sectional view of an exemplary embodiment of the setting assembly of  FIG. 1  with the packer in a set condition; 
         FIG. 4  shows a partial cross-sectional view of another exemplary embodiment of the setting assembly of  FIG. 1  with the packer in a set condition; 
         FIG. 5  shows a partial cross-sectional view of another exemplary embodiment of the setting assembly of  FIG. 1  with the packer in a set condition; 
         FIG. 6  shows a cross-sectional view of another exemplary embodiment of a setting assembly; and, 
         FIG. 7  shows a cross-sectional view of another exemplary embodiment of a downhole tool having a setting assembly using packers. 
     
    
    
     DETAILED DESCRIPTION 
       FIG. 1  shows an exemplary embodiment of a downhole tool  8  including a setting assembly  10 . The setting assembly  10  is thermally energized due to the inclusion of a settable member  12  being settable and unsettable in response to thermal conditions. The setting assembly  10  includes at least one settable member  12  which has a set condition which is distinct from the initial condition. In the illustrated embodiment of  FIG. 1 , the settable member includes first and second packers  14 . The set condition of the packers  14  is the expanded condition shown in  FIG. 1 . The packers  14  in the expanded condition divide an annulus  16  between the formation wall  18  of a borehole  20  and a tubular structure  22  of the downhole tool  8  into three exemplary zones A, B, and C. The downhole tool  8  may be provided within an open borehole  20  for a SAGD process, however the downhole tool  8  may alternatively be provided within a cased borehole or other tubular. Also, while two packers  14  are shown, it should be understood that any number of packers  14  may be employed with the downhole tool  8 . The downhole tool  8  includes a longitudinally extending flowpath  24  useful for the injection of steam  26 , as indicated by the arrows. The tubular structure  22  includes apertures  28  that allow the injected steam  26  to escape the tool  8  in a radial direction and into the annulus  16 , as indicated by arrows  30 . Because the packers  14  are in their expanded condition, the steam injected in Zone A is at least substantially separated from steam injected in Zone B, which is at least substantially separated from steam injected in Zone C. 
     Turning to  FIG. 2 , the setting assembly  10  is shown in an initial or un-set condition with the packer  14  in the non-expanded state. The longitudinal axis  32  of the downhole tool  8  is depicted, and therefore it should be understood that only one half of the cross-section of the downhole tool  8  is illustrated in  FIG. 2 . The tubular structure  22  extends to, is continuous with, or otherwise includes a tubular shaped mandrel  34 . While the mandrel  34  itself is shown as a one-piece unit such as a solid pipe, alternate embodiments of the setting assembly  10  may include two or more sections of tubulars, such as threaded pipes, screwed or otherwise secured together to serve as the mandrel  34 . The mandrel  34  has an exterior surface  36  defining an outer diameter of the mandrel  34 . Exterior to the mandrel  34  is an outer section  38  that at least substantially radially surrounds the mandrel  34 . The outer section  38  is affixed to the mandrel  34  at first and second ends  40 ,  42  thereof either directly or via first and second connecting members  44 ,  46 . The remainder of the outer section  38  includes an interior surface  52  that is positioned in a spaced relation with respect to the mandrel  34 . The outer section  38  includes a rigid portion  48  and a flexible portion  50 . In the exemplary embodiment shown, the rigid portion  48  includes an aperture  54 , such as a cylindrically shaped aperture, and the flexible portion  50  spans the aperture  54  from a first section  56  of the rigid portion  48  to a second section  58  of the rigid portion  48 . The flexible portion  50 , which is also tubular, may include first and second ends  60 ,  62  that are overlapped by the first and second sections  56 ,  58  of the rigid portion  48  and may be elastomeric to have a stretched and unstretched condition. The interior surface  52  of the outer section  38 , at least along the rigid portion  48 , defines an interior diameter that is greater than the outer diameter of the mandrel  34  and the area between the mandrel  34  and the outer section  38  encloses a chamber  64  to secure a variable volume, phase changeable material  66  therein which is changeable between different states of matter. The mandrel  34 , outer section  38 , and connecting portions  44 ,  46  if used, together form a housing  68  that defines the chamber  64 . 
     The material  66  is changeable between different states of matter. Each distinct form is called a phase. A solid has a definite shape and volume, while a liquid has a definite volume but takes the shape of a container. In an exemplary embodiment of the setting assembly  10 , the variable volume, phase changeable material  66  is or at least includes paraffin. Paraffin expands up to 20% by volume when changing (melting) from a solid state phase to a liquid state phase. While paraffin alone is usable as the paraffin material  66 , the paraffin material  66  can alternatively include other components in addition to paraffin to vary the melting point of the paraffin material  66 . Alternatively, the paraffin itself can be selected to have the melting point qualities suitable for a particular operation. The paraffin may be selected to remain solid at ambient downhole conditions, but to melt at temperatures expected during thermal injection operations. 
     In use, the downhole tool  8  having the setting assembly  10  is run downhole to a selected position within borehole  20 . During this process, the packer  14  is in a non-expanded condition shown in  FIG. 2 . The paraffin material  66  is in a solid state due to the ambient temperature near the surface and of the downhole environment being such that the paraffin material  66  remains in a solid state, or at least substantially in a solid state, such that the flexible portion  50  remains non-expanded. With reference to  FIG. 3 , when the downhole tool  8  reaches a selected location within the borehole  20 , and when the environment of the downhole tool  8  experiences an increase in temperature, such as via the injection of steam  26  through the flowpath  24  of the downhole tool  8  in a SAGD operation, the paraffin material  66  melts and increases in volume. Because the mandrel  34  and the rigid portion  48  are not expandable, the flexible portion  50  is forced to expand radially outwardly to accommodate the increased volume of the paraffin material  66  within the chamber  64 . The flexible portion  50  expands to fill the width of the annulus  16  from the outer section  38  to the formation wall  18  in the expanded condition shown in  FIG. 3 . The chamber  64  is sized such that the flexible portion  50  of outer section  38  will be “inflated” due to the thermal expansion of the paraffin material  66  upon melting. The inflation will be to an extent that the formation wall  18  will be contacted with some pressure and a seal effected. In the inflated state, the tool  8  acts to compartmentalize a section of the well during thermal injection, such as in SAGD wells. When thermal injection ceases, the borehole  20  will cool and the paraffin will contract and solidify. That is, when the heat is removed, such as by the cessation of steam injection, the paraffin material  66  will begin to solidify and reduce in volume allowing the flexible portion  50  to retract from the formation wall  18  in order to either allow zones A, B, and C to have fluidic communication, remove the downhole tool  8  from the borehole  20 , or reposition the downhole tool  8  as desired. By utilizing the heat from injected steam  26  to set the packers  14 , no additional equipment is required to set or unset the packers  14 , and thus there is no risk of such equipment becoming damaged in the SAGD operation. 
     While the above described embodiment advantageously utilizes the heat from injected steam  26  to set the packers  14 , in an alternative exemplary embodiment illustrated in  FIG. 4 , a heating member  70  is incorporated in the downhole tool  8  to selectively heat the paraffin material  66  when desired. The heating member  70  may take the form of a tubular member, coiled member, or any other shape capable of conducting heat to the chamber  64  and paraffin material  66 . While the heating member is illustrated as positioned adjacent the setting assembly  10  and along the mandrel  34 , it could alternatively be positioned anywhere within or along the downhole tool  8  in a location that conducts heat towards the material  66 . The heating of the heating member  70  may be operated from the surface via a control line  72 . 
       FIG. 5  shows another alternate embodiment of a setting assembly  110 . The setting assembly  110  is substantially the same as the setting assembly  10  of  FIGS. 2-4  except for the inclusion of pressure relief members  112  provided within the chamber  64  to protect the flexible portion  50  from rupturing due to excess heat or a smaller than expected diameter of the borehole  20  or width of the annulus  16 . An exemplary embodiment of the pressure relief member  112  includes a movable block  114  and spring  116 . The movable block  114  may be substantially ring-shaped to fill a cross-section of the chamber  64 , and to separate an area of the chamber  64  filled with the material  66  from an area  120  of the chamber  64  not filled with the material  66 . The movable block  114  is sealed to the interior of the chamber  64 , such as via O-ring  118  to prevent the material  66  from entering area  120 . While first and second pressure relief members  112  are provided at the first and second ends  40 ,  42  of the setting assembly  110 , respectively, it would also be within the scope of these embodiments to provide a single pressure relief member  112 . The pressure relief members  112  are biased away from the first and second ends  40 ,  42  of the setting assembly  112 , respectively. The spring force of the spring  116  and the flexibility of the flexible portion  50  are such that the bias of the spring  116  cannot be overcome by the volume expansion of the material  66  until after the flexible portion  50  has been expanded. In other words, it requires less force to expand the flexible portion  50  to the formation wall  18  than it does to compress the spring  116 . After the temperature rises and the flexible portion  50  expands, the flexible portion  50  protected from rupturing due to overheating or overexpansion because the increasing volume (beyond what is required by the expansion of the flexible portion  50 ) is absorbed by the pressure relief member(s)  112 . That is, when the flexible portion  50  can no longer expand, the increasing volume presses the block  114  towards the respective first or second end  40 ,  42  by compressing the spring  116  in the directions  122 ,  124 , respectively, as indicated by the arrows to accommodate the increased volume and thus prevent the rupturing of the flexible portion  50 . 
     While  FIGS. 2-5  illustrate a setting assembly  10  in which the settable members  12  are packers  14  which are set through inflation, the setting assembly  10  may alternatively include compression set packers as the settable member  12 . A compression set packer expands in response to compression of an elastomeric material of the packer, forcing the sides of the packer to bulge radially outwardly.  FIG. 6  shows one exemplary embodiment of a setting assembly  210  usable in conjunction with a compression set packer  212 , shown in  FIG. 7 . In an exemplary embodiment, the setting assembly  210  includes a wireline pressure setting assembly (“WLPSA”)  214  that may be employed to ensure the successful setting of one or more settable members such as, but not limited to, bridge plugs, retainer production packers, and cement retainers. While a prior WLPSA builds up pressure through the products of combustion, the setting assembly  210  uses the variable volume, phase changeable material  66 , such as paraffin material, sealed therein to build up the pressure necessary to set the settable member. The setting assembly  210  includes an enclosed tubular housing  216  containing a piston head  218  of a piston  220  therein. A piston rod  222  of the piston  220  extends from the piston head  218  and then exteriorly of the enclosed housing  216 . The piston rod  222  includes an engagement feature  224  that engages with either the settable member, a cooperating feature that engages with the engagement feature to set the settable member, or another engagement feature that engages with the settable member or cooperating feature. In an exemplary embodiment, the piston rod  222  includes a threaded end  226  and may connect with a variety of potential engagement features thereon. In an exemplary embodiment of a setting assembly  210  for a compression packer  212 , the cooperating feature is a compressing member  228  such that movement of the piston  220  translates to movement of the compressing member  228 . The compressing member  228  is configured to be capable of compressing the compression packer  212 , and therefore may be substantially ring shaped, however it may include apertures, petals, or be foldable as necessary. The piston  220  is longitudinally moveable between a first end  230  of an interior of the housing  216  and a second end  232  of the interior of the housing  216 . The piston head  218  is disposed between the first and second ends  230 ,  232  and a seal, such as O-ring  234  may be secured around the piston head  218  to separate a first area  236  between the piston head  218  and the first end  230  from a second area  238  between the piston head  218  and the second end  232 . The second area  238  is filled with the material  66 . The first area  236  may include a spring (not shown) or other biasing member that biases the piston head  218  towards the second end  232  to return to its initial position after removal of heat. In normal surface or ambient temperatures, the piston rod  222  will be in a position such that the compressing member  228 , or other cooperating feature, does not compress the compression packer  212 , or otherwise set the settable member. However, upon application of heat, such as injection of steam  26  shown in  FIG. 7  or via a control line  72  and heatable member  70  shown in  FIG. 6 , the material  66  will begin to melt and expand in volume as previously described. Volume expansion of the paraffin material  66  pushes the piston head  218  towards the first end  230 , which in turn pulls the piston rod in direction  240 , as well as the compressing member  228  in direction  240 . Movement of the compressing member  228  in direction  240  compresses the packer  212  between the compressing member  228  and another plate or compressing member  242 . 
     While  FIG. 6  demonstrates a wireline operation of the setting assembly  210 , an alternate exemplary embodiment incorporating the material  66  to move a piston could also be configured to encircle the downhole tool  208 , such as shown in  FIG. 7 . In such an embodiment, the piston head  244  would be substantially ring shaped, as would the surrounding housing  246 . The piston rod  248  need not be ring shaped, so long as the connection to compressing member  228  is sufficient to pull the compressing member  228  in direction  240  without damage. Also, while  FIG. 7  illustrates a SAGD operation, application of heat may alternatively be accomplished via control line  72  and heating member  70 . The compressing member  228  is positioned at one side of the compression packer  212  and a remainder of the setting assembly  310  is provided on an opposite side of the compression packer  212  in  FIG. 7 , however the setting assembly  310  could be alternatively arranged to accommodate varying settable members. 
     Thus, an isolation tool for wells using thermal injection (such as SAGD completions) has been described that uses a thermally energizable, phase and volume changeable material to deploy and energize a settable member, such as a packer, seal, or other settable member. A method of setting the settable member includes enclosing the phase changeable setting material within a chamber of a housing in a solid state, heating the setting material to melt the setting material to a liquid state to expand a volume of the setting material, and harnessing the expansion of the setting material as a setting force to set the settable member. 
     Set forth below are some embodiments of the foregoing disclosure: 
     Embodiment 1: A setting assembly comprising: an inflatable packer; a housing including a chamber; a setting material disposed in the chamber and having a first phase of matter and a second phase of matter, the setting material occupying a greater volume in the second phase than in the first phase, the setting material arranged to exert a setting force on the inflatable packer during transition of the setting material from the first phase to the second phase; and, at least one pressure relief member within the chamber, the pressure relief member configured to protect the inflatable packer from rupturing. 
     Embodiment 2: The setting assembly of any of the preceding embodiments, wherein the first phase of the setting material is solid and the second phase is liquid. 
     Embodiment 3: The setting assembly of any of the preceding embodiments, wherein the housing includes a mandrel and an outer section, the outer section including a rigid portion and a flexible portion, the flexible portion forming the packer. 
     Embodiment 4: The setting assembly of any of the preceding embodiments wherein the at least one pressure relief member includes a spring biased movable device longitudinally movable between the mandrel and the rigid portion of the outer section. 
     Embodiment 5: The setting assembly of any of the preceding embodiments, wherein the rigid portion includes a gap, the flexible portion spanning the gap in the rigid portion. 
     Embodiment 6: The setting assembly of any of the preceding embodiments, wherein the flexible portion is elastomeric. 
     Embodiment 7: The setting assembly of any of the preceding embodiments, wherein the housing further includes first and second connecting members at uphole and downhole ends of the setting assembly, the first and second connecting member connecting the rigid portion of the outer section to the mandrel. 
     Embodiment 8: The setting assembly of any of the preceding embodiments, wherein the at least one pressure relief member is configured to enlarge an available volume of the chamber after the inflatable packer has expanded. 
     Embodiment 9: The setting assembly of any of the preceding embodiments, wherein the at least one pressure relief member includes a spring biased movable device, the device biased within the chamber to permit the material to occupy a first volume within the chamber, and the device movable within the chamber to allow the material to occupy a second volume within the chamber greater than the first volume. 
     Embodiment 10: The setting assembly of any of the preceding embodiments, wherein a force to expand a flexible portion of the inflatable packer is less than a force to move the movable device against its spring bias. 
     Embodiment 11: The setting assembly of any of the preceding embodiments, wherein the inflatable packer is a first inflatable packer, and further comprising a second inflatable packer, a tubular structure extending between the first and second inflatable packers having a radial aperture, wherein steam injected through the tubular structure and out the radial aperture transitions the setting material from the first phase to the second phase to set the first and second inflatable packers and isolate a zone between the first and second inflatable packers. 
     Embodiment 12: The setting assembly of any of the preceding embodiments, further comprising a heat source to transition the setting material from the first phase to the second phase. 
     Embodiment 13: The setting assembly of any of the preceding embodiments, wherein the heat source is heated fluid pumped into a borehole. 
     Embodiment 14. The setting assembly of any of the preceding embodiments, wherein the heat source is a heating element adjacent the housing, the heating element selectively controlled by a control line. 
     Embodiment 15: A downhole system comprising a tubular structure having a longitudinal axis, and a setting assembly, the setting assembly including: an inflatable packer; a housing including a chamber, the housing connected to the tubular structure and sharing an interior flowpath with the tubular structure, the chamber disposed exteriorly of the interior flowpath; a setting material disposed in the chamber and having a first phase of matter and a second phase of matter, the setting material occupying a greater volume in the second phase than in the first phase, the setting material arranged to exert a setting force on the inflatable packer during transition of the setting material from the first phase to the second phase; and, at least one pressure relief member within the chamber, the pressure relief member configured to protect the inflatable packer from rupturing. 
     Embodiment 16: A method of setting an inflatable packer, the method comprising: enclosing a phase changeable setting material within a chamber of a housing in a solid state; heating the setting material to melt the setting material to a liquid state to expand a volume of the setting material; harnessing the expansion of the setting material as a setting force to set the inflatable packer; and, protecting the inflatable packer from rupture. 
     Embodiment 17: The method of any of the preceding embodiments, wherein harnessing the expansion of the setting material includes inflating a flexible member of the inflatable packer with expanding setting material. 
     Embodiment 18: The method of any of the preceding embodiments, wherein protecting the inflatable packer from rupture includes enlarging an available volume of the chamber after the inflatable packer inflates. 
     Embodiment 19: The method of any of the preceding embodiments, wherein protecting the inflatable packer from rupture includes relieving pressure within the chamber during expansion of the setting material by moving a spring biased device with expanding setting material to increase a volume of the chamber, wherein the inflatable packer expands prior to moving the spring biased device. 
     Embodiment 20: The method of any of the preceding embodiments, wherein heating the setting material includes injecting heated fluid into a borehole. 
     The use of the terms “a” and “an” and “the” and similar referents in the context of describing the invention (especially in the context of the following claims) are to be construed to cover both the singular and the plural, unless otherwise indicated herein or clearly contradicted by context. Further, it should further be noted that the terms “first,” “second,” and the like herein do not denote any order, quantity, or importance, but rather are used to distinguish one element from another. The modifier “about” used in connection with a quantity is inclusive of the stated value and has the meaning dictated by the context (e.g., it includes the degree of error associated with measurement of the particular quantity). 
     The teachings of the present disclosure may be used in a variety of well operations. These operations may involve using one or more treatment agents to treat a formation, the fluids resident in a formation, a wellbore, and/or equipment in the wellbore, such as production tubing. The treatment agents may be in the form of liquids, gases, solids, semi-solids, and mixtures thereof. Illustrative treatment agents include, but are not limited to, fracturing fluids, acids, steam, water, brine, anti-corrosion agents, cement, permeability modifiers, drilling muds, emulsifiers, demulsifiers, tracers, flow improvers etc. Illustrative well operations include, but are not limited to, hydraulic fracturing, stimulation, tracer injection, cleaning, acidizing, steam injection, water flooding, cementing, etc. 
     While the invention has been described with reference to an exemplary embodiment or embodiments, it will be understood by those skilled in the art that various changes may be made and equivalents may be substituted for elements thereof without departing from the scope of the invention. In addition, many modifications may be made to adapt a particular situation or material to the teachings of the invention without departing from the essential scope thereof. Therefore, it is intended that the invention not be limited to the particular embodiment disclosed as the best mode contemplated for carrying out this invention, but that the invention will include all embodiments falling within the scope of the claims. Also, in the drawings and the description, there have been disclosed exemplary embodiments of the invention and, although specific terms may have been employed, they are unless otherwise stated used in a generic and descriptive sense only and not for purposes of limitation, the scope of the invention therefore not being so limited.