Patent Publication Number: US-2023151715-A1

Title: Well Sealing Tool with Isolatable Setting Chamber

Description:
BACKGROUND 
     Wells are drilled to recover valuable hydrocarbons such as oil and gas deep within the earth. The construction and servicing of a well typically involves long strings of tubular equipment. For example, a wellbore may be drilled with a drill string progressively assembled from segments of drill pipe to reach the desired well depth. A wellbore is often lined with a tubular casing string, which may be perforated for extracting hydrocarbon fluids from a production zone. Alternatively, a tubular work string may be lowered into an encased (“open hole”) portion of a well to seal off and deliver a stimulation treatment to selected production zones. In the process of completing the well, a production tubing string may be run into the well, providing a flow path from the production zone to a wellhead through which the oil and gas can be produced. 
     It is often necessary to seal an annulus between tubular members downhole. For example, one or more production zones may be isolated by setting packers at different intervals of the wellbore to seal an annulus between a tubular work string and the formation. Sealing devices are also sometimes deployed to seal between tubular members such as a work string and casing. Such sealing devices are often required to seal at very high pressure. For example, hydraulic fracturing (tracking) involves the delivery of a proppant-laden fluid at sufficiently high pressure to fracture the formation. A challenge in downhole sealing systems is to design robust mechanisms that withstand these high pressures, yet fit within the tight downhole confines. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       These drawings illustrate certain aspects of some of the embodiments of the present disclosure and should not be used to limit or define the method. 
         FIG.  1    is an elevation view of a well system in which one or more wellbore sealing tools may be deployed downhole. 
         FIG.  2    is a sectional view of the packer disposed in the wellbore in a run-in condition according to one example configuration. 
         FIG.  3    is a sectional view of the setting mechanism in the run-in condition according to the example configuration of  FIG.  2   . 
         FIG.  4    is an enlarged view of the portion around the setting port of  FIG.  3   . 
         FIG.  5    is a sectional view of the packer after setting against the wellbore and pressure-isolating the setting chamber. 
         FIG.  6    is an enlarged view of the portion around the setting port after the valve element has been released to the closed position. 
         FIG.  7    is a sectional view of the packer as used in a method of servicing the wellbore according to an example method. 
     
    
    
     DETAILED DESCRIPTION 
     The disclosure has identified that high pressure differentials can be problematic, especially with packers designed to be set with low setting forces. Large pressure differentials between a setting pressure and a well servicing fluid pressure require stricter material and geometry limitations, which increases costs. In particular, if the setting chamber of a packer is going to see higher differentials after packer set, it must be designed to withstand this differential. The disclosure is directed in part to a setting mechanism wherein the setting chamber is subsequently isolated from tubing pressure after setting. This allows the setting mechanism to be designed according to a lower pressure rating, which is more cost efficient. 
     In examples, a well sealing tool includes a hydraulic setting mechanism that may be pressure-isolated after setting the well sealing tool downhole. In examples discussed below the well sealing tool is embodied as a packer that includes a sealing element for sealing an annulus between a tool string and the wellbore. The setting mechanism includes a setting chamber that uses fluid pressure to both deploy the sealing element and to then close the setting chamber. By pressure-isolating the setting chamber, a service fluid may then be delivered along the through bore of the well sealing tool at a fluid pressure greater than the fluid pressure used to set the sealing element. 
       FIG.  1    is an elevation view of a well system  100  in which one or more wellbore sealing tools (e.g., a packer  120 ) may be deployed downhole. The well system  100  may include an oil and gas rig  102  arranged at the earth&#39;s surface  104 . The rig  102  may include a large support structure, such as a derrick  110 , erected over the wellbore  106  on a support foundation or platform, such as a rig floor  112 . Even though certain drawing features of  FIG.  1    depict a land-based oil and gas rig  102 , it will be appreciated that the embodiments of the present disclosure are useful with other types of rigs, such as offshore platforms or floating rigs used for subsea wells, and in any other geographical location. For example, in a subsea context, the earth&#39;s surface  104  may be the floor of a seabed, and the rig floor  112  may be on the offshore platform or floating rig over the water above the seabed. A subsea wellhead may be installed on the seabed and accessed via a riser from the platform or vessel. 
     A wellbore  106  may be drilled through the various strata of an earthen formation  108  according to a wellbore plan. The wellbore  106  may be drilled along a desired wellbore path from where the wellbore  106  is initiated at the surface  104  (i.e., the “heel”) to the end of the well (i.e., the “toe”). The initial portion of the wellbore  106  is typically vertically downward as the drill string would generally be suspended vertically from the rig  102 . Thereafter the wellbore  106  may deviate in any direction as measured by azimuth or inclination, which may result in sections that are vertical, horizontal, angled up or down, and/or curved. The term uphole generally refers to a direction along the wellbore path toward the surface  104  and the term downhole generally refers to a direction toward the toe at the end of the well, without regard to whether a feature is vertically upward or vertically downward with respect to a reference point. The wellbore path in  FIG.  1    is simplified for ease of illustration, and is not to scale. In this example, the wellbore path includes an initial, vertical section  105 , followed by at least one deviated section  115  downhole of the vertical section  105 , which transitions from the vertical section  105  to a horizontal or lateral section  107  downhole of the curved section  115 . Thus, the vertical section  105  is uphole of the curved section  115  and lateral section  107 . 
     The wellbore  106  may be at least partially cased with a string of casing  116  at selected locations within the wellbore  106 , while other portions of the wellbore  106  may remain uncased. In  FIG.  1   , by way of example, the casing  116  is shown along just a portion of the vertical section  105  and the remainder of the wellbore  106  is shown as open hole. The casing  116  may be secured within the wellbore  106  using cement. In other embodiments, the casing  116  may be omitted entirely. 
     A hoisting apparatus (not shown) may be suspended from the rig  102  for raising and lowering equipment in the wellbore  106  on a tubular conveyance  114 . The conveyance  114  may also be used to convey fluids, and to support electrical communication, power, and fluid transmission during wellbore operations. The conveyance  114  may include any suitable equipment for mechanically conveying tools. Such conveyance may include, for example, a tubular string made up of interconnected tubing segments, coiled tubing, or any combination of the foregoing. In some examples, conveyance  114  may provide mechanical suspension, as well as electrical and fluidic connectivity, for downhole tools. The conveyance  114  may be used to lower one or more tools into the wellbore  106 , i.e. run/tripped into the hole. When a wellbore operation is complete, or when it becomes necessary to exchange or replace tools or components of the conveyance  114 , the conveyance  114  may be raised or fully removed from the wellbore  106 , i.e., tripped out of the hole. 
     A variety of wellbore sealing tools may be configured according to this disclosure. A packer  120  is one example of a wellbore sealing tool for discussion purposes. The packer includes a sealing element  130  and a hydraulic setting mechanism  140  for deploying the sealing element  130  into engagement with the wellbore  106  or other sealing surface. The sealing element  130  is alternately referred to in the art as the “element” of a packer, and the process of deploying the element into engagement with the sealing surface may be referred to as “setting” the packer  120 . The packer  120  is shown in a first example location  120   a  in a run-in condition as it is being lowered into a wellbore  106 , i.e., run in hole (RIH), and a second location  120   b  where the packer  120  has been set. One packer  120  is shown for ease of discussion, but it is understood that any number of packers may be run in hole on a work string to be deployed to different locations along the wellbore  106 . 
     Various types of packers exist. Examples of packers include production packers that may be permanently set and service packers that may be retrievable. As just one example, the packer  120  in  FIG.  1    may be a production packer that will remain in the well during well production. Another example is a service packer used temporarily during well servicing, such as for cementing, acidizing, or fracturing. When set, multiple packers  120  may be used to isolate zones of the annulus between wellbore  106  and a tubing string by providing a seal between production tubing and casing  116  or between production tubing and open hole. In examples, a packer may be disposed on production tubing. 
       FIG.  2    is a sectional view of the packer  120  disposed in the wellbore  106  in a run-in condition according to one example configuration. A mandrel  122  is a centrally disposed, elongate, tubular, structural member at which the packer  120  may be connected within a tool string. The mandrel  122  in this example includes an uphole end  124  for directly or indirectly coupling to a conveyance or a tool string supported on the conveyance, and a downhole end  126 . Other tool string components (not shown) may be coupled to the downhole end  126 , such as other packers. The mandrel  122  extends through the packer  120  and supports various packer component thereon. The mandrel  122  may include a circular cross section with an outer diameter (OD)  121  and an inner diameter (ID)  123 . The ID  123  may be defined by a mandrel through bore  125 . The mandrel OD  121  is useful for externally supporting the various packer components in an annulus between the mandrel  122  and the wellbore  106  in which the packer  120  is disposed. The mandrel OD  121  may also provide a generally straight, cylindrical surface allowing for relative axial movement between certain packer components and the mandrel  122 . The through bore  125  is useful for conveying fluids through the packer  120  within ID  123 , such as production fluids flowing up from the downhole end  126  and well servicing fluids flowed downhole from surface via the tubular conveyance. 
     The packer  120  includes a sealing element (“element”)  130  and a setting mechanism  140  for setting the element  130 . The element  130  comprises a compliant, elastically-deformable material, such as a rubber or elastomer. The element  130  is supported on the mandrel OD  121  and is axially restrained at a first end  134 , such as with a shroud  132 . An opposing second end  136  of the element  130  may be slidable along the mandrel OD  121  toward the first end  134 . When it is desired to set the element  130 , the setting mechanism  140  may be used to urge the second end  136  of the element  130  toward the axially-constrained first end  134 . The resulting axial compression of the element  130  will correspondingly squeeze the element  130  to deploy the element  130  outwardly into engagement with the wellbore  106 . The setting mechanism  40  is hydraulically actuated by supplying a pressurized fluid downhole through the mandrel ID  123 , as further discussed below. 
       FIG.  3    is a sectional view of the setting mechanism  140  in the run-in condition according to the example configuration of  FIG.  2   . A setting chamber housing  142  disposed about the mandrel  122  defines at least a portion of an annular setting chamber  144  between the mandrel OD  121  and the setting chamber housing  142 . A setting port  128  along the mandrel  122  fluidically couples the mandrel through bore  125  with the setting chamber  144 , so that fluid pressure may be supplied to the setting chamber  144  via the setting port  128 . The fluid pressure may be supplied downhole from the surface of the well site through a tubular conveyance in fluid communication with the mandrel  122 . A valve element  160  in the setting port  128  is moveable between open and closed positions to open and close the setting port  128 . A moveable guide sleeve  148  initially props a valve element  160  to the open position, but may be moved to release the valve element  160  to the closed position to isolate the setting chamber after setting the packer  120 , as further described below. 
     An element-setting piston  146  is slidably disposed on the mandrel OD  121 . The element-setting piston  146  may be sealed between the mandrel OD  121  and a surface of the setting chamber housing  144  with corresponding seals (e.g., O-rings)  145 ,  147 . A guide sleeve piston  150  is also slidably disposed on the mandrel OD  121 , sealed between the mandrel OD  121  and setting chamber housing  142  with corresponding seals (e.g., O-rings)  149 ,  151 . The seals  149 ,  151  may also help avoid any communication from annulus and tubing after the setting port  128  is closed. The element-setting piston  146  and guide sleeve piston  150  are each exposed to (and may define respective portions of) the setting chamber  144 . The element-setting piston  146  and guide sleeve piston  150  are axially opposite one another with respect to the setting port  128  in this configuration. The guide sleeve  148  is coupled to the guide sleeve piston  150  and may be unitarily formed therewith. 
     The element-setting piston  146  and the guide sleeve piston  150  are each moveable in response to pressure supplied to the setting chamber  144 . A setting pressure may be supplied to the setting chamber  144  to urge the element-setting piston  146  into engagement with the sealing element  130  to deploy the sealing element  130  into engagement with the wellbore  106 . The packer  120  may be configured to require a certain threshold pressure to move the guide sleeve piston  150 . In the present example, this is accomplished with a shear member  154  to initially retain the guide sleeve  148  in a first position. The shear rating of the shear member  154  may be selected to control the amount of pressure required to initially move the guide sleeve piston  150  relative to the amount of pressure required to move the element-setting piston  160 . For example, the shear member  154  may be configured to fail at a threshold pressure in excess of the setting pressure. This allows the packer to be set prior to shifting the guide sleeve  148  to release the valve element  160  and isolate the setting chamber  144 . The use of a shear member to releasably secure the guide sleeve  148  is economical and reliable. However, any other suitable mechanism for securing the guide sleeve  148  (e.g., collets, dogs, etc.) and subsequently releasing by application a threshold pressure is also considered within the scope of the disclosure. 
     The setting mechanism  140  may also work even if configured so the threshold pressure required to move the guide sleeve piston  150  is less than the setting pressure used to set the sealing element  130 . For example, in the illustrated configuration, a pressure may be supplied to both set the packer and fail the shear member  154  concurrently. That pressure may be maintained to avoid shifting the guide sleeve  148  and closing the setting port  128  until after the packer  120  is fully set. After the packer  120  is set, the pressure in the setting chamber  144  may be bled down to allow the guide sleeve  148  to gradually release the valve element  160  to the closed position. 
     A biasing member, such as a spring  147 , may be provided to bias the guide sleeve  148  from the first position of  FIG.  3    to a second position (e.g.,  FIG.  6   , discussed below). The spring  147  is currently compressed in  FIG.  3    while the shear member  154  remains intact. The compression of the spring  147  is what provides the biasing action in this example toward the second position, although any other biasing member and biasing configuration may be considered within the scope of this disclosure. The shear member  154  may resist movement of the guide sleeve piston in either axial direction. Thus, the shear member  154  may prevent the spring  147  from urging the guide sleeve  148  to the closed position (to the left in  FIG.  3   ) until the shear member  154  is first failed by supplying the threshold pressure to the setting chamber  144  (to the right in  FIG.  3   ). Then, once the shear member  154  is failed and the pressure bled off, the guide sleeve  148  may then be free to move to the second position under the biasing action of the spring  147  to release the valve element  160 . Thus, in the process of isolating the setting chamber  144 , the guide sleeve  148  first moves axially away from the setting port  128  in response to the threshold pressure, and the spring  147  then biases the guide sleeve  148  back toward the setting port  128  in response to bleeding off the threshold pressure. 
       FIG.  4    is an enlarged view of the portion around the setting port  128  enclosed by window  4  of  FIG.  3   . The guide sleeve  148  is in the first position, propping the valve element  160  open. The setting port  128  extends through a wall of the mandrel  122 , from the mandrel ID  123  to the mandrel OD  121 . The valve element  160  comprises a ball in this example, for sealing with a setting port  128  having a generally circular cross-section. However, any suitable valve element and complementary setting port of any shape may be used for selectively closing a setting port. The guide sleeve  148  includes a ball-engagement portion  162  aligned with the valve element  160  when the guide sleeve  148  is in the first position. The ball-engagement portion  162  engages the valve element  160  to prop it to the open position against the biasing action of a valve spring  166 . In the open position, a gap is present between the valve element  160  and a valve seat  168 , allowing fluid pressure flow through the setting port  128  and into the annular setting chamber  144  along a flow path generally indicated by arrows  145 . A relief  164  in the guide sleeve  148  is axially spaced from the ball-engagement portion  162 . To release the valve element  160  to the closed position requires shifting the sleeve  148  to the left to align the relief  164  with the valve element  160 , as further discussed below. One or more seals (e.g., one or more O-rings)  169  may also be provided to avoid an unintended fluid communication path other than the space between the valve seat  168  and the valve element  160  as explained above. 
       FIG.  5    is a sectional view of the packer  120  after setting against the wellbore  106  and pressure-isolating the setting chamber  144 . The element  160  may have been set by supplying the setting pressure downhole to the mandrel through bore  125  to the setting port  128 . After setting the element  160 , pressure may have been bled off to release the valve element  160  to the closed position. The setting chamber is now closed, pressure-isolating the setting chamber  144 . By pressure-isolating the setting chamber  144 , pressure now be supplied downhole to the mandrel through bore  125  without the pressure entering the setting chamber  144 . The setting chamber  144  is now isolated from pressure in the mandrel greater than was applied to the setting chamber to set the packer and release the guide sleeve  148 . 
       FIG.  6    is an enlarged view of the portion around the setting port  128  after the valve element  160  has been released to the closed position. To release the valve element  160  to the closed position, the threshold pressure may be supplied as described above to release the guide sleeve  148  (e.g., shearing a shear member) and shifting the guide sleeve  148  to the second position of  FIG.  6   . In the second position, the ball-engagement portion  162  has been axially shifted away from the valve element  160  and align the relief  164  in the guide sleeve  148  with the valve element  160 . The valve element  160 , having previously been retained in the open position by the ball-engagement portion  162  as shown in  FIG.  4   , has been released by alignment with the relief  164 . The valve spring  166  now urges the valve element  160  into sealing engagement with the corresponding valve seat  168 . The closing force provided by the valve spring  166  is sufficient to pressure-isolate the setting chamber  144 . This closing force may be assisted or reinforced by any pressure subsequently supplied to the mandrel, by helping to urge the valve element  160  against the valve seat  168 . Seal  169  helps avoid an unintended fluid communication path (i.e., a leak) when the valve element  160  is in the closed position. 
       FIG.  7    is a sectional view of the packer  120  as used in a method of servicing the wellbore  106  according to an example method. The packer  120 , which includes the annular sealing element  130  and setting mechanism  140 , has been lowered into the wellbore on the tubular conveyance  114 . The tubular conveyance  114  is coupled to the packer  120  with the tubular conveyance  114  in fluid communication with the mandrel through bore  125 . The packer  120  was run into the wellbore  106  in a run-in condition (e.g.,  120   a  of  FIG.  1   ), and subsequently set in the current position by supplying a setting pressure downhole via the tubular conveyance  114 . The element  130  has been outwardly deployed into engagement with the wellbore  106 , thereby sealing an annulus  170  between the packer  120  and the wellbore  106 . The setting chamber is then isolated as described above, after which pressures may supplied to the mandrel through bore  125  in excess of the pressures used to set the packer. This pressure isolation allows higher pressures to now be delivered downhole, without damaging components of the setting chamber that may be rated for lower pressures required to set the packer. 
     A wellbore service may now be performed comprising delivering a service fluid down through the mandrel  122  and into the annulus  170  sealed by the annular sealing element  130 . By having isolated the setting chamber, fluid pressure may now be supplied to the mandrel in excess of the setting pressure and threshold pressure For example, the service fluid may be pressurized to at least 50% greater than the setting pressure. In one example, the packer may be set with a setting pressure of 5,000 psi (34 MPa) or less, and the service fluid may be pressurized up to two or three times that pressure. The wellbore is shown as being closed downhole of the packer  120 , such as with a plug  180  or any other device, so that the service fluid is constrained to flow out of the mandrel  122  and out into the annulus  170 . In one example, the service fluid may be a proppant-laden hydraulic fracturing fluid used to form fractures  182  in the formation  108 . However, any wellbore servicing operation may be employed, with fluid pressures that may exceed the pressures supplied to set the packer and subsequently isolate the setting mechanism. 
     Accordingly, the present disclosure may provide a well sealing tool and related devices and methods for sealing a wellbore, wherein the setting mechanism used to set the well sealing tool is subsequently pressure isolated. Although the disclosed example tools use an element-setting piston that is hydraulically driven by the setting pressure, other embodiments may be devised. For example, an inflatable packer according to this disclosure may use a setting pressure to inflate a packer rather than to drive an element-setting piston into engagement with the element. In that case, pressures may still be used to release a valve element as described to subsequently pressure isolate the setting chamber after setting the packer. 
     It should also be recognized that the principles of this disclosure to set and then pressure isolate a well sealing device are not limited to packers. These principles may be applied to other well sealing tools used to seal against any downhole surface, such as with a casing or between two tubular members downhole. 
     The disclosed methods/systems/tools may include any of the various features disclosed herein, including one or more of the following statements. 
     Statement 1. A packer setting mechanism, comprising: a setting chamber housing positionable about a mandrel to define at least a portion of a setting chamber between the mandrel and the setting chamber housing; a setting port fluidically coupling a through bore of the mandrel with the setting chamber; a valve element biased toward a closed position within the setting port; and a guide sleeve disposed about the mandrel in a first position that props the valve element to an open position, the guide sleeve moveable to a second position in response to a threshold pressure applied to the setting chamber that releases the valve element to the closed position. 
     Statement 2. The packer setting mechanism of Statement 1, further comprising: an element-setting piston exposed to the setting chamber, the element-setting piston moveable into engagement with an annular sealing element in response to a setting pressure applied to the setting chamber. 
     Statement 3. The packer setting mechanism of Statement 1 or 2, further comprising: a guide sleeve piston exposed to the setting chamber and coupled to the guide sleeve, the guide sleeve piston moveable in response to the threshold pressure applied to the setting chamber. 
     Statement 4. The packer setting mechanism of Statement 3, further comprising a shear member initially securing the guide sleeve in the first position, the shear member configured to shear in response to the threshold pressure applied to the guide sleeve piston. 
     Statement 5. The packer setting mechanism of Statement 3, further comprising a spring biasing the guide sleeve to the second position. 
     Statement 6. The packer setting mechanism of any of Statements 1-3, further comprising an element-setting piston and a guide sleeve piston axially opposite one another with respect to the setting port. 
     Statement 7. The packer setting mechanism of Statement 6, wherein the guide sleeve moves axially away from the setting port in response to the threshold pressure, and the spring biases the guide sleeve back toward the setting port in response to bleeding off the threshold pressure. 
     Statement 8. The packer setting mechanism of any of Statements 1-7, wherein the threshold pressure is greater than the setting pressure. 
     Statement 9. The packer setting mechanism of any of Statements 1-8, wherein releasing the valve element to the closed position isolates the setting chamber to pressure in the mandrel of at least 50% higher than the setting pressure. 
     Statement 10. A wellbore sealing tool, comprising: a mandrel positionable in a wellbore and defining a mandrel through bore for fluid communication with a tubular conveyance; an annular sealing element disposed about the mandrel; a setting mechanism including a setting chamber and a setting port along the mandrel fluidically coupling the mandrel through bore to the setting chamber, the setting mechanism configured for deploying the sealing element outwardly in response to a setting pressure applied to the setting chamber through the setting port; a valve element moveable between an open position and a closed position with respect to the setting port; and a guide member initially propping the valve element to the open position and then releasing the valve element to the closed position in response to a threshold pressure applied to the setting chamber through the setting port. 
     Statement 11. The wellbore sealing tool of Statement 10, wherein the setting mechanism further comprises an element-setting piston disposed on the mandrel exposed to the setting chamber, wherein the setting pressure applied to the element-setting piston deploys the sealing element outwardly into engagement with the wellbore. 
     Statement 12. The wellbore sealing tool of Statement 11 or 12, wherein the setting mechanism further comprises: a shear member initially securing the guide member in a first position initially propping the valve element to the open position; and a guide member piston coupled to the guide member for shearing the shear member in response to the threshold pressure applied to the guide member piston. 
     Statement 13. The wellbore sealing tool of Statement 12, wherein the threshold pressure at which the shear member is configured to shear is greater than or equal to the setting pressure applied to the element-setting piston to deploy the sealing element outwardly into engagement with the wellbore. 
     Statement 14. The wellbore sealing tool of Statement 12 or 13, wherein the element-setting piston and the guide member piston are on opposite sides of the setting port to be urged axially away from one another in response to pressure supplied to the setting chamber. 
     Statement 15. The wellbore sealing tool of any of Statements 12-14, further comprising a biasing member for biasing the guide member toward a second position, wherein the guide member is initially moved away from the second position in response to the threshold pressure before the biasing member urges the guide sleeve to a second position releasing the valve element to the closed position. 
     Statement 16. A method of sealing a wellbore, comprising: lowering an annular sealing element on a mandrel into a wellbore; initially propping a valve element in an open position with a guide sleeve to hold open a setting port along the mandrel; supplying a setting pressure through the setting port into a setting chamber defined about the mandrel to deploy the annular sealing element into engagement with the wellbore; and moving the guide sleeve to release the valve element to a closed position closing the setting port, thereby isolating the setting chamber to pressures greater than the setting pressure. 
     Statement 17. The method of Statement 16, further comprising: performing a wellbore service comprising delivering a service fluid down through the mandrel and into an annulus sealed by the annular sealing element, wherein the service fluid is pressurized to greater than the setting pressure. 
     Statement 18. The method of Statement 16 or 17, wherein moving the guide sleeve to release the valve element comprises applying a threshold pressure through the setting port into the setting chamber to shear a shear member initially preventing movement of the guide sleeve to release the valve element. 
     Statement 19. The method of any of Statements 16-19, further comprising: biasing the valve element toward a closed position using a first biasing member, to urge the valve element to the closed position when released by the guide sleeve; and biasing the guide sleeve from a first position propping the valve element in the open position to a second position at which the guide sleeve releases the valve element. 
     Statement 20. The method of any of Statements 17-19, wherein the setting chamber is isolated to pressures in excess of a maximum pressure rating of the setting chamber. 
     For the sake of brevity, only certain ranges are explicitly disclosed herein. However, ranges from any lower limit may be combined with any upper limit to recite a range not explicitly recited, as well as, ranges from any lower limit may be combined with any other lower limit to recite a range not explicitly recited, in the same way, ranges from any upper limit may be combined with any other upper limit to recite a range not explicitly recited. Additionally, whenever a numerical range with a lower limit and an upper limit is disclosed, any number and any included range falling within the range are specifically disclosed. In particular, every range of values (of the form, “from about a to about b,” or, equivalently, “from approximately a to b,” or, equivalently, “from approximately a-b”) disclosed herein is to be understood to set forth every number and range encompassed within the broader range of values even if not explicitly recited. Thus, every point or individual value may serve as its own lower or upper limit combined with any other point or individual value or any other lower or upper limit, to recite a range not explicitly recited. 
     Therefore, the present embodiments are well adapted to attain the ends and advantages mentioned as well as those that are inherent therein. The particular embodiments disclosed above are illustrative only, as the present embodiments may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Although individual embodiments are discussed, all combinations of each embodiment are contemplated and covered by the disclosure. Furthermore, no limitations are intended to the details of construction or design herein shown, other than as described in the claims below. Also, the terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee. It is therefore evident that the particular illustrative embodiments disclosed above may be altered or modified and all such variations are considered within the scope and spirit of the present disclosure.