Patent Publication Number: US-11377923-B2

Title: Isolation device with inner mandrel removed after setting

Description:
TECHNICAL FIELD 
     An isolation device and methods of using the isolation device are provided. The isolation device includes an inner mandrel that is removed from the isolation device after setting. The isolation device does not require a spacer ring to aid in the setting process as a setting sleeve has direct contact with the top slips. 
    
    
     
       BRIEF DESCRIPTION OF THE FIGURES 
       The features and advantages of certain embodiments will be more readily appreciated when considered in conjunction with the accompanying figures. The figures are not to be construed as limiting any of the preferred embodiments. 
         FIG. 1  is a perspective view of an isolation device in a run-in state. 
         FIG. 2  is a cross-sectional view of the isolation device of  FIG. 1 . 
         FIG. 3  is a cross-sectional view of the isolation device of  FIG. 1  after being set. 
         FIG. 4  is a cross-sectional view of the isolation device showing a mule shoe being sheared from the device after setting. 
         FIG. 5  is a cross-sectional view of the isolation device showing a frac ball seated at the top of the isolation device. 
     
    
    
     DETAILED DESCRIPTION OF THE INVENTION 
     Oil and gas hydrocarbons are naturally occurring in some subterranean formations. In the oil and gas industry, a subterranean formation containing oil and/or gas is referred to as a reservoir. A reservoir can be located under land or offshore. Reservoirs are typically located in the range of a few hundred feet (shallow reservoirs) to a few tens of thousands of feet (ultra-deep reservoirs). In order to produce oil or gas, a wellbore is drilled into a reservoir or adjacent to a reservoir. The oil, gas, or water produced from a reservoir is called a reservoir fluid. 
     As used herein, a “fluid” is a substance having a continuous phase that can flow and conform to the outline of its container when the substance is tested at a temperature of 71° F. (22° C.) and a pressure of one atmosphere “atm” (0.1 megapascals “MPa”). A fluid can be a liquid or gas. A homogenous fluid has only one phase, whereas a heterogeneous fluid has more than one distinct phase. 
     A well can include, without limitation, an oil, gas, or water production well, an injection well, or a geothermal well. As used herein, a “well” includes at least one wellbore. A wellbore can include vertical, inclined, and horizontal portions, and it can be straight, curved, or branched. As used herein, the term “wellbore” includes any cased, and any uncased, open-hole portion of the wellbore. A near-wellbore region is the subterranean material and rock of the subterranean formation surrounding the wellbore. As used herein, a “well” also includes the near-wellbore region. The near-wellbore region is generally considered to be the region within approximately 100 feet radially of the wellbore. As used herein, “into a subterranean formation” means and includes into any portion of the well, including into the wellbore, into the near-wellbore region via the wellbore, or into the subterranean formation via the wellbore. 
     A portion of a wellbore can be an open hole or a cased hole. In an open-hole wellbore portion, a tubing string can be placed into the wellbore. The tubing string allows fluids to be introduced into or flowed from a remote portion of the wellbore. In a cased-hole wellbore portion, a casing is placed into the wellbore that can also contain a tubing string. A wellbore can contain an annulus. Examples of an annulus include, but are not limited to: the space between the wellbore and the outside of a tubing string in an open-hole wellbore; the space between the wellbore and the outside of a casing in a cased-hole wellbore; and the space between the inside of a casing and the outside of a tubing string in a cased-hole wellbore. 
     It is not uncommon for a wellbore to extend several hundreds of feet or several thousands of feet into a subterranean formation. The subterranean formation can have different zones. A zone is an interval of rock differentiated from surrounding rocks on the basis of its fossil content or other features, such as faults or fractures. For example, one zone can have a higher permeability compared to another zone. It is often desirable to treat one or more locations within multiples zones of a formation. One or more zones of the formation can be isolated within the wellbore via the use of an isolation device to create multiple wellbore intervals. At least one wellbore interval corresponds to a formation zone. The isolation device can be used for zonal isolation and functions to block fluid flow within a tubular section, such as a tubing string, or within an annulus. The blockage of fluid flow prevents the fluid from flowing across the isolation device in any direction and isolates the zone of interest. In this manner, treatment techniques, such as fracturing operations, can be performed within the zone of interest. 
     Common isolation devices include, but are not limited to, a ball and a seat, a bridge plug, a packer, a plug, a frac plug, and a wiper plug. It is to be understood that reference to a “ball” is not meant to limit the geometric shape of the ball to spherical, but rather is meant to include any device that is capable of engaging with a seat. A “ball” can be spherical in shape, but can also be a dart, a bar, or any other shape. Zonal isolation can be accomplished by dropping or flowing a ball from the wellhead onto a seat that is located within the wellbore. The ball engages with the seat, and the seal created by this engagement prevents fluid communication into other wellbore intervals downstream of the ball and seat. As used herein, the relative term “downstream” means at a location further away from a wellhead. 
     Plugs, for example, frac plugs, are generally composed primarily of slips, wedges, an inner plug mandrel, a spacer ring, a mule shoe, and a rubber sealing element. The plug can also include a setting device and an additional mandrel, such as a tension mandrel or setting mandrel. The plug can be introduced into the wellbore and positioned at a desired location within a tubing string. The “tubing string” can also be a casing. The plug can be set after being placed at the desired location. As used herein, the term “set” and all grammatical variations means one or more components of the plug are actuated to keep the plug at the desired location and substantially diminish or restrict fluid flow past the outside of the plug. For example, the spacer ring can be mechanically actuated to move a top slip into engagement with the inner diameter (I.D.) of the tubing string. A mule shoe, which is typically pinned and/or threaded to the inner plug mandrel, can also be mechanically actuated to move a bottom slip into engagement with the I.D. of the tubing string. Movement of the top and bottom slips can cause top and bottom wedges to mechanically actuate the rubber sealing element to expand and engage with the I.D. of the tubing string. The rubber sealing element also expands inwardly and engages with the outer diameter of the inner plug mandrel. This expansion of the rubber sealing element creates zonal isolation by substantially diminishing or restricting fluid flow around the outside of the plug. A ball can then be seated onto the plug whereby after being seated, the ball restricts fluid flow through the inner plug mandrel. 
     One significant disadvantage to traditional plugs is that the inner mandrel cannot be removed after setting because the inner mandrel functions to not only support the slip wedges, but also supports the rubber sealing element via direct engagement with the sealing element. The diameter of the fluid flow path through the plug can be smaller than desired because of the presence of the inner mandrel. 
     Isolation devices can be classified as permanent, retrievable, or drillable. While permanent isolation devices are generally designed to remain in the wellbore after use, retrievable devices are capable of being removed after use, and drillable devices are drilled or milled after use. Removal of an isolation device from the wellbore can be accomplished by milling at least a portion of the device or the entire device. Another disadvantage to traditional plugs is an increased cost and time required to mill the plug&#39;s components. Moreover, few if any of the components can be reused after milling. As such, there is a need and ongoing industry concern for improved isolation devices. 
     Novel plugs are disclosed. The plug can include a packer element that is actuated to engage with an I.D. of a tubing string to set the plug. Top and bottom slip props of the plug can be self-supporting and can be shaped such that the packer element is inhibited or prevented from engaging with an inner mandrel. Thus, the slip props do not require the inner mandrel for support and the inner mandrel can be removed from the plug after setting and can be reused in other downhole tools. One of the many advantages of the novel plug is that the inner diameter of the plug is enlarged due to removal of the inner mandrel. The enlarged inner diameter creates a larger fluid flow path through the plug, which allows a greater volume of fluid to flow through the plug. Moreover, if the plug needs to be milled in order to restore fluid communication into another zone, then fewer parts require milling; thus, saving time and money. The plug can be used for zonal isolation to treat a zone of interest within a subterranean formation. The treatment can be a fracturing operation. The fracturing operation can include introducing a fracturing fluid into the zone to be treated, wherein the fracturing fluid creates or enhances one or more fractures in the subterranean formation. 
     A zonal isolation device can include: a top slip; a top slip prop in engagement with the top slip; a bottom slip; a bottom slip prop in engagement with the bottom slip; a packer element positioned between the top slip prop and bottom slip prop, wherein movement of the top slip prop and the bottom slip prop towards each other causes the packer element to expand into engagement with an inner diameter of a tubing string; and an inner mandrel, wherein the inner mandrel is removable from the zonal isolation device after engagement of the packer element with the inner diameter of the tubing string. 
     Methods of isolating a zone of a subterranean formation can include: setting an isolation device within a tubing string at a desired location comprising: mechanically actuating a top slip and a bottom slip into engagement with an inner diameter of the tubing string; and causing movement of a top slip prop and a bottom slip prop towards each other, wherein the movement causes a packer element located between the top slip prop and bottom slip prop to become engaged with the inner diameter of the tubing string; and removing an inner mandrel of the isolation device after setting the isolation device within the tubing string at the desired location. 
     It is to be understood that the discussion of any of the embodiments regarding the plug is intended to apply to all of the method and apparatus embodiments without the need to repeat the various embodiments throughout. Any reference to the unit “gallons” means U.S. gallons. 
     Turning to the Figures,  FIG. 1  shows an isolation device  100  in a run-in position according to any of the embodiments. As used herein, the terms “run into” and “run in” mean the isolation device plug is capable of being moved within a tubing string to a desired location and/or the time during which the isolation device is being introduced into a wellbore at a desired location. The isolation device  100  can be a plug. The plug can be used in an oil and gas operation. The oil or gas operation can be a fracturing operation or for zonal isolation. The isolation device  100  can be a frac plug, bridge plug, or zonal isolation plug. There can also be more than one isolation device  100  that is run into a tubing or casing string to provide zonal isolation. 
     As shown in  FIG. 1 , the isolation device  100  can include top slips  120 , a top slip prop  122 , a packer element  130 , a bottom slip prop  126 , bottom slips  124 , an inner mandrel  114  (shown in  FIG. 2 ), and a mule shoe  140 . The components of the plug can be made from a variety of materials including, but not limited to, metals, metal alloys, dissolvable materials, molded hardened polymers, resins, or resin/glass composites. Examples of metals or metal alloys that can be used include, but are not limited to, cast iron and aluminum. The packer element  130  can be made from elastomeric materials including, but not limited to, natural rubbers, styrene-butadiene block copolymers, polyisoprene, polybutadiene, ethylene propylene rubber, ethylene propylene diene rubber, silicone elastomers, fluoroelastomers, polyurethane elastomers, nitrile rubbers, and dissolvable, elastomeric materials. The components of the isolation device can have a variety of dimensions that are selected for the particular wellbore operation in which the isolation device is used. 
     The isolation device  100  can include a slip system located on the outside of the inner mandrel  114 . As shown in the Figures, the inner mandrel  114  can extend from an area below the mule shoe  140 , through the inner diameter of the device, and to an area above the top slips  120 . The slip system includes the top slips  120  and the bottom slips  124 . The slips  120 / 124  can be made from a single cylinder of material, a set of slips retained in a groove on the slip prop, or a single cylinder of material containing a plurality of slots or grooves. The slips  120 / 124  can be located around a portion of the outside of the inner mandrel  114  and radially biased towards the outside of the inner mandrel  114 . The slips  120 / 124  can have buttons or teeth on its face. As used herein, the terms “button” and “teeth” include one or more elements that are capable of grippingly engaging an inner diameter (I.D.)  161  of a tubing string or casing  160  to retain the isolation device  100  in a set position. The buttons or teeth can include sharp ridges machined onto the face of the slips  120 / 124  or sharp elements, for example, rounded or other geometric shapes that are attached to the face of the slips  120 / 124 . The slip system can further include slip props. 
     As shown in  FIG. 2 , an upper and a lower end of each of the slips  120 / 124  can be formed having a conical or ramped surface. The surfaces of the slips  120 / 124  allow a parallel, angled surface  123   a  of a top slip prop  122  and a parallel, angled surface  127   a  of a bottom slip prop  126  to slidingly engage with the ramped surfaces of the slips  120 / 124 . In one position, the slips  120 / 124  can be positioned substantially adjacent to the inner mandrel  114  and axially separated from the top slip prop  122  and bottom slip prop  126  so that the outer diameter (O.D.) of the slips  120 / 124  is less than or equal to the O.D. of the slip props  122 / 126 . As used herein, the term “slip prop” includes a wedge, cone, or any device that can support the slips  120 / 124  when the isolation device  100  is set. 
     After the isolation device  100  is run in the wellbore to a desired location, it can be set.  FIG. 3  shows the isolation device  100  after setting. The isolation device  100  can be mechanically set using wireline or hydraulic setting tools, for example. Unlike conventional isolation device plugs that are set using a spacer ring, the isolation device  100  according to any of the embodiments can also include a setting sleeve  110 . The setting sleeve  110  can be attached to a setting tool (not shown). The inner mandrel  114  can also be attached to the setting tool, such that after setting, the inner mandrel  114  and the setting sleeve  110  can be removed from the wellbore—leaving only the slip system and the packer element within the wellbore. 
     Setting the isolation device  100  can involve applying compression to a slip system to move the slips  120 / 124  axially towards and along the face of the slip props  122 / 126  and radially away from the inner mandrel  114  and into engagement with the I.D.  161  of the tubing string or casing  160  and to allow the top slips  120  to maintain engagement with the tubing string or casing  160 . The setting sleeve  110  can be mechanically actuated. The force applied to the device can increase the load on the slips  120 / 124  causing them to break via the slots or grooves (shown in  FIG. 1 ) and ramp up the angled surfaces  123   a / 127   a  of the slip props  122 / 126  towards each other. Compression that is applied to the slip system causes the top slips  120  to move along the top slip prop  122 , which in turn causes a lower end of the mule shoe  140  to move towards the top slips  120 . Movement of the mule shoe  140  causes the bottom slips  126  to move along the bottom slip prop  126 . The slip props  122 / 126  can support the slips  120 / 124  in an expanded position outward from the inner mandrel  114  such that the slips  120 / 124  engage the I.D.  161  of the tubing string or casing  160  when the isolation device  100  is set. The slip props  122 / 126  can prevent the slips  120 / 124  from retracting and releasing from the I.D.  161  of the tubing string once the isolation device  100  is set. When the slips  120 / 124  are engaged with the tubing string or casing  160 , the isolation device  100  has substantially limited or no vertical movement within the wellbore. 
     Setting the isolation device  100  can further involve causing the packer element  130  to expand radially away from the inner mandrel  114  to form a pressure tight annular seal. The packer element  130  can radially expand outwardly away from the inner mandrel  114  to engage with an inner diameter  161  of the tubing string or casing  160  when the isolation device  100  is set. Downward movement of the setting sleeve  110  and the upward movement of the mule shoe  140  causes the slip props  122 / 126  to move towards each other and axially compresses the packer element  130  to cause it to expand into engagement with the I.D.  161  of the tubing string or casing  160 . Engagement of the packer element  130  with the inside of the tubing string or casing  160  can preferably restrict fluid flow past the packer element. 
     As shown in  FIG. 2 , the packer element  130  has a width  131  between the top slip prop  122  and the bottom slip prop  126  adjacent to the inner mandrel  114 . During setting of the isolation device  100 , movement of the slip props  122 / 126  towards each other decreases the width  131  after setting as shown, for example, in  FIG. 3 . 
     According to any of the embodiments, the packer element  130  does not engage the inner mandrel  114  after the isolation device  100  is set. Still with reference to  FIGS. 2 and 3 , the top slip prop  122  can include a second angled surface  123   b  and the bottom slip prop  126  can include a second angled surface  127   b . The angle denoted in the drawings as θ (theta) of the angled surfaces  123   b / 127   b  can be selected such that after setting, the packer element  130  is inhibited or prevented from engaging with the inner mandrel  114 . By way of example, the angle θ can be in the range of 100° to 170°. In this manner, expansion of the packer element  130  is in a direction away from the inner mandrel  114 , and the packer element  130  is substantially prevented from being in direct engagement with the inner mandrel  114 . Traditional plugs generally have an angle θ that is greater than 180°—that is, the slip prop&#39;s angle in an opposite direction as shown in the Figures. An angle θ greater than 180° allows the packer element to expand towards the inner mandrel and engage with the inner mandrel after setting. 
     As shown in  FIG. 4 , the mule shoe  140  can include threads  141  for connecting the mule shoe  140  to the inner mandrel  114  via threads  115  on the inner mandrel  114 . As also shown, the slip props  122 / 126  can include threads to connect to the inner mandrel  114  during the run-in position. The threads on the slip props  122 / 126  can be located on the slip props as shown in one embodiment in  FIG. 4  and in a second embodiment in  FIG. 5 —although the threads can be located in a different area from shown in the Figures. The slip props  122 / 126  do not have to include threads for connecting to the inner mandrel  114 . Continued force applied to the slip system can cause the slip props  122 / 126  to shear from the inner mandrel  114  when threads are included. The shear force required to shear the slip props  122 / 126  from the inner mandrel  114  can be less than the force required to shear the mule shoe  140  from the inner mandrel  114 . Continued force applied to the slip system also causes movement of the slips  120 / 124 , the slip props  122 / 126 , and the packer element  130 . When the slips  120 / 124 , the slip props  122 / 126 , and the packer element  130  have moved into the fully set position, for example as shown in  FIGS. 3 and 4 , the force being applied no longer causes movement of the components. The system then reaches a predetermined force that shears the mule shoe  140  from engagement with the inner mandrel  114 , for example as shown in  FIG. 4 . After the isolation device  100  has been set and the mule shoe  140  has been sheared, the setting sleeve  110  and the inner mandrel  114  can be removed from the wellbore. The step of removing can include removing the setting tool (not shown) that is connected to the setting sleeve and inner mandrel. The setting sleeve  110  and inner mandrel  114  can be removed, in part, because the packer element  130  is not in direct engagement with the inner mandrel  114  after setting. 
     The isolation device  100  can include a fluid flow path defined by an inner diameter  101  of the isolation device  100 . The flow path through the inner diameter of the isolation device can allow fluids to flow from or into the subterranean formation via a conduit defined by the tubing string or casing  160 . According to any of the embodiments, the isolation device  100  has a substantially (i.e., +/−10%) uniform inner diameter after removal of the inner mandrel. By way of example, the top slip prop  122  and the bottom slip prop  126  can have substantially the same dimensions and form a substantially straight line that forms an inner diameter of the device after removal of the inner mandrel  114 . Accordingly, the inner diameter of the device after removal of the inner mandrel is not tapered or staggered. 
     The isolation device  100  can include a staggered or tapered inner diameter  101 . The inner diameter  101  can be smaller at an area downstream of the direction of fluid flow. In this manner a ball  150  (e.g., a frac ball) can be flowed through the tubing string or casing  160  into the isolation device  100  and become seated within the isolation device  100  when the ball  150  encounters the smaller inner diameter. 
     The slip props  122 / 126  are self-supporting after removal of the inner mandrel  114 . As used herein, the term “self-supporting” means the slip props do not require a reinforcing element, such as a mandrel, in order to maintain structural integrity and a fixed position. Thus, the slip props are able to maintain the slips in engagement with the I.D. of the tubing string without the need for a mandrel or other component to support the slip props from the inside of device. This self-support can be achieved by increasing the thickness (as measured from the I.D. to the O.D.) of the slip props  122 / 126 . Traditional plugs that require an inner mandrel to support the slip props in a set position necessitate use of thinner slip props in order to accommodate the inner mandrel while still providing a fluid flow path through the plug. The novel device disclosed allows a larger diameter fluid flow path due to removal of the inner mandrel  114  after setting, while still providing thicker slip props  122 / 126  that are self-supporting. 
     The fluid flow path through the device can be closed. As seen in  FIG. 5 , a ball  150  can become seated onto the top slip prop  122  when fluid flow is in the direction D 1 . According to these embodiments, the ball  150  can have an outer diameter that is greater than the inner diameter  161  of a top end of the top slip prop. According to certain embodiments, the ball does not seat within the isolation device after the inner mandrel is removed. It is to be understood that the relative terms “top” and “bottom” are used for convenience purposes and are not meant to indicate a specific orientation. For example, the ball  150  can seat against the bottom slip prop  126  if fluid flow is in a direction opposite of D 1 . 
     When desired, fluid flow can be restored through the inner diameter of the isolation device  100 . By way of example, if the ball  150  is seated by flowing the ball in the direction D 1 , then fluid flow can be restored by flowing a fluid in the opposite direction, which will unseat the ball  150 . One of the many advantages to the novel isolation device  100  is that fluid flow through the device is increased compared to conventional plugs because the inner diameter of the plug is greater without the inner mandrel  114  being present after setting. 
     All or a portion of the isolation device  100  can be removed from the tubing string when desirable. Removal can be accomplished by drilling, milling, or dissolving the components of isolation device  100 . Another advantage to the novel device is the time for removal is decreased because there are fewer components (e.g., the setting sleeve and inner mandrel) to remove compared to conventional plugs. 
     Methods of providing zonal isolation can include some or all of the following: introducing the isolation device  100  into a tubing string or casing  160 ; setting the isolation device  100  at a desired location within the tubing string or casing  160 ; shearing the mule shoe  140 ; removing the setting sleeve  110  and the inner mandrel  114 ; seating a ball  150  against the isolation device  100 ; performing a treatment operation within the isolated zone; unseating the ball  150 ; and removing all or a portion of the isolation device  100 . 
     The methods can further include fracturing a portion of a subterranean formation that is penetrated by the wellbore. The step of fracturing can include introducing a fracturing fluid into a zone of the formation, wherein the fracturing fluid creates or enhances a fracture in the formation. 
     An embodiment of the present disclosure is a zonal isolation device comprising: a top slip; a top slip prop in engagement with the top slip; a bottom slip; a bottom slip prop in engagement with the bottom slip; a packer element positioned between the top slip prop and bottom slip prop, wherein movement of the top slip prop and the bottom slip prop towards each other causes the packer element to expand into engagement with an inner diameter of a tubing string; an inner mandrel, wherein the inner mandrel is removable from the zonal isolation device after engagement of the packer element with the inner diameter of the tubing string; and a ball, wherein the ball is seated onto the top slip prop. Optionally, the device further comprises wherein the isolation device is a frac plug, bridge plug, or zonal isolation plug. Optionally, the device further comprises a setting sleeve, wherein the setting sleeve and the inner mandrel are connecting to a setting tool. Optionally, the device further comprises wherein the top slip prop comprises a first angled surface for engaging with the top slip and a second angled surface, and wherein the bottom slip prop comprises a first angled surface for engaging with the bottom slip and a second angled surface. Optionally, the device further comprises wherein the packer element is located between the second angled surface of the top slip prop and the second angled surface of the bottom slip prop. Optionally, the device further comprises wherein the second angled surface of the top slip prop and the bottom slip prop forms an angle, and wherein the angle is in the range of 100° to 170°. Optionally, the device further comprises a mule shoe, and wherein the mule shoe comprises threads for connecting the mule shoe to a bottom end of the inner mandrel via threads on the inner mandrel. Optionally, the device further comprises wherein the top slip prop and the bottom slip prop are self-supporting after removal of the inner mandrel. Optionally, the device further comprises wherein the zonal isolation device has a substantially uniform inner diameter after removal of the inner mandrel. 
     Another embodiment of the present disclosure is a method of isolating a zone of a subterranean formation comprising: setting an isolation device within a tubing string at a desired location comprising: mechanically actuating a top slip and a bottom slip into engagement with an inner diameter of the tubing string; and causing movement of a top slip prop and a bottom slip prop towards each other, wherein the movement causes a packer element located between the top slip prop and bottom slip prop to become engaged with the inner diameter of the tubing string; removing an inner mandrel of the isolation device after setting the isolation device within the tubing string at the desired location; and causing a ball to seat onto the top slip prop. Optionally, the method further comprises wherein mechanically actuating the top slip and the bottom slip comprises applying compression to a slip system to move the top slip and the bottom slip axially towards and along a first angled surface of the top slip prop and a first angled surface of the bottom slip prop and radially away from the inner mandrel. Optionally, the method further comprises wherein movement of the top slip along the first angled surface of the top slip prop causes a mule shoe that is connected to a bottom end of the inner mandrel to move towards the top slip. Optionally, the method further comprises wherein the top slip prop further comprises a second angled surface, wherein the bottom slip prop further comprises a second angled surface, and wherein the packer element is located between the second angled surface of the top slip prop and the second angled surface of the bottom slip prop. Optionally, the method further comprises wherein the second angled surface of the top slip prop and the bottom slip prop forms an angle, and wherein the angle is in the range of 100° to 170°. Optionally, the method further comprises a mule shoe, and wherein the mule shoe comprises threads for connecting the mule shoe to a bottom end of the inner mandrel via threads on the inner mandrel. Optionally, the method further comprises shearing the mule shoe from engagement with the inner mandrel, wherein after the isolation device has been set within the tubing string at the desired location, continued application of the compression shears the mule shoe. Optionally, the method further comprises wherein the inner mandrel is removed from the tubing string after the mule shoe has sheared. Optionally, the method further comprises wherein the top slip prop and the bottom slip prop are self-supporting after removal of the inner mandrel. Optionally, the method further comprises wherein the isolation device has a substantially uniform inner diameter after removal of the inner mandrel. Optionally, the method further comprises wherein the ball has a larger outer diameter than the inner diameter of a top end of the top slip prop. 
     Therefore, the various 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 various 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. Furthermore, no limitations are intended to the details of construction or design herein shown, other than as described in the claims below. 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 invention. 
     As used herein, the words “comprise,” “have,” “include,” and all grammatical variations thereof are each intended to have an open, non-limiting meaning that does not exclude additional elements or steps. While compositions, systems, and methods are described in terms of “comprising,” “containing,” or “including” various components or steps, the compositions, systems, and methods also can “consist essentially of” or “consist of” the various components and steps. It should also be understood that, as used herein, “first,” “second,” and “third,” are assigned arbitrarily and are merely intended to differentiate between two or more surfaces, slips, etc., as the case may be, and does not indicate any sequence. Furthermore, it is to be understood that the mere use of the word “first” does not require that there be any “second,” and the mere use of the word “second” does not require that there be any “third,” etc. 
     Whenever a numerical range with a lower limit and an upper limit is disclosed, any number and any included range falling within the range is 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. Also, the terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee. Moreover, the indefinite articles “a” or “an,” as used in the claims, are defined herein to mean one or more than one of the element that it introduces. If there is any conflict in the usages of a word or term in this specification and one or more patent(s) or other documents that may be incorporated herein by reference, the definitions that are consistent with this specification should be adopted.