Patent Document

BACKGROUND OF THE INVENTION  
         [0001]    1. Field of the Invention  
           [0002]    The present invention generally relates to downhole tools for use in a wellbore. More particularly, the invention relates to a downhole tool for sealing a wellbore, such as a hydrocarbon wellbore. More particularly still, the invention relates to an expandable tubular for sealing a hydrocarbon wellbore.  
           [0003]    2. Description of the Related Art  
           [0004]    Typically, a wellbore is formed using a drill bit that is urged downwardly at a lower end of a drill string. After drilling to a predetermined depth, the drill string and bit are removed, and the wellbore is lined with a string of casing. Generally, it is desirable to provide a flow path for hydrocarbons from the surrounding formation into the newly formed wellbore. Therefore, after all casing has been set and cemented, perforations are formed in a wall of the liner string at a depth that equates to the anticipated depth of hydrocarbons. Alternatively, a lower portion of the wellbore may remain uncased, which is commonly referred to as an open-hole completion, so that the formation and fluids residing therein remain exposed to the wellbore.  
           [0005]    A downhole packer is generally used to isolate a specific portion of a wellbore whether it is employed in a cased or uncased wellbore. There are many different types of packers; however, a recent trend in cased wellbore completion has been the advent of expandable tubular technology. It has been discovered that expandable packers can be expanded in situ so as to enlarge the inner diameter. This, in turn, enlarges the path through which both fluid and downhole tools may travel. Also, expansion technology enables a smaller tubular such as the expandable packer to be run into a larger tubular, and then expanded so that a portion of the smaller tubular is in contact with the larger tubular therearound. Expandable packers are expanded through the use of a cone-shaped mandrel or by an expansion tool with expandable, fluid actuated members disposed on a body and run into the wellbore on a tubular string. During the expansion operation, the walls of the expandable packer are expanded past their elastic limit. The use of expandable packers allows for the use of larger diameter production tubing, because the conventional slip mechanism and sealing mechanism are eliminated.  
           [0006]    An expandable packer is typically run into the wellbore with a running assembly disposed at an end of a drill string. The running assembly includes an expansion tool, a swivel, and a running tool. Generally, the expansion tool is disposed at the bottom end of the drill string. Next, the swivel is disposed between the expansion tool and the running tool to allow the expansion tool to rotate while the running tool remains stationary. Finally, the running tool is located below the swivel, at the bottom end of the running assembly. The running tool is mechanically attached to the expandable packer through a mechanical holding device.  
           [0007]    After the expandable packer is lowered to a predetermined point in the well, the expandable packer is ready to be expanded into contact with the wellbore or casing. Subsequently, the expansion tool is activated when a hydraulic isolation device, like a ball, is circulated down into a seat in the expansion tool. Thereafter, fluid is pumped from the surface of the wellbore down the drill string into the expansion tool. When the fluid pressure builds up to a predetermined level, the expansion tool is activated, thereby starting the expansion operation. During the expansion operation, the swivel allows the expansion tool to rotate while the packer and the running tool remain stationary. After the expandable packer has been expanded against the wellbore or casing, the running assembly is deactivated and removed from the well.  
           [0008]    While expanding tubulars in a wellbore offer obvious advantages, there are problems associated with using the technology to create a packer through the expansion of one tubular into a wellbore or another tubular. For example, an expanded packer with no gripping structure on the outer surface has a reduced capacity to support the weight of the entire packer. This is due to a reduced coefficient of friction on the outer surface of the expandable packer. More importantly, the expansion of the expandable packer in an open-hole wellbore may result in an ineffective seal between the expanded packer and the surrounding wellbore.  
           [0009]    An alternative to the expandable packer is an inflatable packer. Typically, the inflatable packer utilizes an expandable bladder to create a fluid seal within the surrounding wellbore or casing. In some instances, the bladder is expanded through actuation of a downhole pump. In other instances, the bladder is expanded through injection of hydraulic pressure into the tool. Inflation of the bladder forces a surrounding packing element to be inflated into a sealed engagement with the surrounding wellbore or string of casing.  
           [0010]    The packer element in a typical inflatable packer is comprised of two separate portions. The first portion is an expandable rib assembly. Typically, the rib assembly defines a series of vertically overlaid reinforcing straps that are exposed to the surrounding casing. The straps are placed radially around the bladder in a tightly overlapping fashion. The second portion of the inflatable packer is an expandable sealing cover with a valve system. The sealing cover is a pliable material that surrounds a portion of the reinforcing straps. As the bladder and straps are expanded, the sealing cover expands and engages the surrounding pipe in order to effectuate a fluid seal. Thus, the rib assembly and the sealing cover portion of the packing element combine to effectuate a setting and sealing function.  
           [0011]    While an inflatable packer offers an increased sealing capability over the expandable packer, there are potential problems associated with the inflatable packer. In one example, the inflatable packer rib assembly may be complex and costly to manufacture. In another example, the valve system is complex and may not function properly. More importantly, the inflatable packer reduces the hole size of the wellbore, thereby limiting the further drilling or exploration of the wellbore.  
           [0012]    There is a need, therefore, for a packer that will create an effective seal by exerting pressure against a cased wellbore or an open-hole wellbore. There is a further need for a packer that will not reduce the diameter of the wellbore. There is yet a further need for a cost effective packer. Finally, there is a need for a liner assembly that will effectively isolate a zone within an open-hole or a cased wellbore.  
         SUMMARY OF THE INVENTION  
         [0013]    The present invention generally relates to an apparatus and method for sealing a wellbore. In one aspect an apparatus for sealing a wellbore is provided. The apparatus includes a tubular body having an inner surface and an outer surface. The tubular body contains one or more apertures in a wall thereof to allow selective fluid communication between the inner surface and the outer surface. The apparatus further includes a swelling elastomer disposed around the outer surface of the tubular body. The swelling elastomer is isolated from wellbore fluid in an annulus. However, upon the application of an outwardly directed force to the inner surface of the tubular body, the tubular body expands radially outward causing the swelling elastomer to contact the wellbore while exposing the swelling elastomer to an activating agent via the one or more apertures, thereby causing the swelling elastomer to create a pressure energized seal with one or more adjacent surfaces in the wellbore.  
           [0014]    In another aspect, a liner assembly for isolating a zone in a wellbore is provided. The liner assembly includes a deformable tubular and an upper and lower sealing apparatus disposed at either end of the deformable tubular. The upper and lower sealing apparatus comprises a tubular body, a swelling elastomer, and a deformable portion.  
           [0015]    In yet another aspect, a method for sealing a wellbore is provided. The method includes running an expandable liner assembly on a drill string into the wellbore. The expandable liner assembly includes a deformable tubular and a sealing apparatus disposed at either end of the deformable tubular. The method further includes applying an outwardly directed force to the inner surface of a tubular body and causing the tubular body to expand radially outward. The method also includes exposing the swelling elastomer to an activating agent, thereby causing the swelling elastomer to expand outward deforming the deformable portion to create a pressure energized seal with one or more adjacent surfaces in the wellbore. The method includes expanding the deformable tubular. 
       
    
    
     BRIEF DESCRIPTION OF THE DRAWINGS  
       [0016]    So that the manner in which the above recited features of the present invention, and other features contemplated and claimed herein, are attained and can be understood in detail, a more particular description of the invention, briefly summarized above, may be had by reference to the embodiments thereof which are illustrated in the appended drawings. It is to be noted, however, that the appended drawings illustrate only typical embodiments of this invention and are therefore not to be considered limiting of its scope, for the invention may admit to other equally effective embodiments.  
         [0017]    [0017]FIG. 1 is a cross-sectional view of a wellbore prepared to accept an expandable sealing assembly that includes an upper and lower sealing apparatus of the present invention.  
         [0018]    [0018]FIGS. 2A and 2B are cross-sectional views illustrating the expandable liner assembly and a running assembly being lowered into the wellbore on a work string.  
         [0019]    [0019]FIG. 3A is a cross-sectional view illustrating the upper sealing apparatus partially expanded into contact with the wellbore by an expansion tool.  
         [0020]    [0020]FIG. 3B is an enlarged cross-sectional view illustrating the expansion of the swelling elastomer in the upper sealing apparatus.  
         [0021]    [0021]FIG. 4 is a cross-sectional view illustrating the lower sealing apparatus expanded into contact with the wellbore by the expansion tool.  
         [0022]    [0022]FIG. 5 is a cross-sectional view illustrating the blades on the expansion tool cutting an upper portion of the expandable liner assembly.  
         [0023]    [0023]FIG. 6 is a cross-sectional view illustrating the removal of the upper tubular from the wellbore.  
         [0024]    [0024]FIG. 7 is a cross-sectional view of the liner assembly fully expanded into contact with the surrounding wellbore. 
     
    
     DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT  
       [0025]    [0025]FIG. 1 is a cross-sectional view of a wellbore  100  prepared to accept an expandable liner assembly (not shown) that includes an upper and lower sealing apparatus (not shown) of the present invention. As depicted, wellbore  100  does not contain casing. An uncased wellbore is known in the industry as an open-hole wellbore. It should be noted that this invention is not limited for use with uncased wellbore, but rather can be also be used with a cased wellbore. In a cased wellbore, the casing is typically perforated at a predetermined location near a formation to provide a flow path for hydrocarbons from the surrounding formation. Thereafter, the perforations may be closed by employing the present invention in a similar manner as described below for an open-hole wellbore.  
         [0026]    As shown in FIG. 1, the wellbore  100  is a vertical well. However, it should be noted that the present invention may also be employed in horizontal or deviated wellbores. As illustrated in FIG. 1, a prepared section  105  has an enlarged diameter relative to the wellbore  100 . Typically, the prepared section  105  is enlarged through the use of an under-reamer (not shown). However, other methods of enlarging the wellbore  100  may be employed, such as a bi-center bit, so long as the method is capable of enlarging the diameter of the wellbore  100  for a predetermined length.  
         [0027]    In a typical under-reaming operation, the wellbore  100  is enlarged past its original drilled diameter. The under-reamer generally includes blades that are biased closed during run-in for ease of insertion into the wellbore  100 . The blades may subsequently be activated by fluid pressure to extend outward and into contact with the wellbore walls. Prior to the under-reaming operation, the under-reamer is located at a predetermined point in the wellbore  100 . Thereafter, the under-reamer is activated, thereby extending the blades radially outward. A rotational force supplied by a motor causes the under-reamer to rotate. During rotation, the under-reamer is urged away from the entrance of the wellbore  100  toward a downhole position for a predetermined length. As the under-reamer travels down the wellbore, the blades on the front portion of the under-reamer contact the diameter of the wellbore  100 , thereby enlarging the diameter of the wellbore  100  to form the prepared section  105 .  
         [0028]    [0028]FIGS. 2A and 2B are cross-sectional views illustrating the expandable liner assembly  150  and a running assembly  170  being lowered into the wellbore  100  on a work string  120 . Additionally, the work string  120  acts as a conduit for hydraulic fluid that is pumped from the surface of the wellbore  100  to the various components on the running assembly  170 . As shown, the work string  120  extends through the entire length of the running assembly  170  and connects to a drillable plug  190  at the lower end of the running assembly  170 . During the run-in operation, the drillable plug  190  prevents wellbore fluid from entering an annulus  165  created between the expandable liner assembly  150  and the running assembly  170 . As depicted, the plug  190  includes an aperture  195  to allow hydraulic fluid to exit the work string  120  during the expansion operation.  
         [0029]    The running assembly  170  further includes an upper torque anchor  160  to provide a means to secure the running assembly  170  and expandable liner assembly  150  in the wellbore  100 . As shown on FIG. 2A, the upper torque anchor  160  is in a retracted position to allow the running assembly  170  to place the expandable liner assembly  150  in the desired location for expansion of the liner assembly  150  in the prepared section  105 . The upper torque anchor  160  illustrates one possible means of securing the running assembly  170  and expandable liner assembly  150  in the wellbore  100 . It should be noted, however, that other securing means well known in the art may be employed so long as they are capable of securing the running assembly  170  and expandable liner assembly  150  in the wellbore  100 . Additionally, a lower torque anchor  125 , which is disposed below the upper torque anchor  160 , is used to attach the expandable liner assembly  150  to the running assembly  170 . At the lower end of the torque anchor  125 , a motor  145  is disposed to provide the rotational force to turn the expansion tool  115 .  
         [0030]    [0030]FIG. 2A depicts the expansion tool  115  with rollers  175  retracted, so that the expansion tool  115  may be easily moved within the expandable liner assembly  150  and placed in the desired location for expansion of the liner assembly  150 . When the expansion tool  115  has been located at the desired depth, hydraulic pressure is used to actuate the pistons (not shown) and to extend the rollers  175  so that they may contact the inner surface of the liner assembly  150 , thereby expanding the liner assembly  150 . Generally, hydraulic fluid (not shown) is pumped from the surface to the expansion tool  115  through the work string  120 . Additionally, the expansion tool includes blades  155  to cut the liner assembly at a predetermined location.  
         [0031]    As illustrated in FIG. 2A, the expandable liner assembly  150  includes an upper tubular  180 . The upper tubular  180  includes a plurality of slots  140  formed on the surface of the upper tubular  180 . Generally, the slots  140  are a plurality of longitudinal slots in the upper tubular  180  to provide a point where an upper and lower portion of the liner assembly  150  may separate after the expansion process is complete. The expandable liner assembly  150  further includes the upper sealing apparatus  200  and the lower sealing apparatus  300 . Generally, the upper and lower sealing apparatus  200 ,  300  are used in conjunction with a lower tubular  185  to seal off a portion of the prepared section  105  in order to isolate a zone of the wellbore  100 . As shown in FIGS. 2A and 2B, the components for the sealing apparatus  200 ,  300  are identical. Therefore, the following paragraphs describing the components in the upper sealing apparatus  200  will also be applicable to the lower sealing apparatus  300 .  
         [0032]    As depicted on FIG. 2A, the expandable liner assembly  150  also includes the lower tubular  185  disposed between the upper and lower sealing apparatus  200 ,  300 . Generally, the lower tubular  185  is expanded into the prepared section  105  by the expansion tool  115 . In the embodiment shown, the lower tubular  185  is an expandable liner that works in conjunction with the upper and lower sealing apparatus  200 ,  300  to isolate a portion of the prepared section  105  from other portions of the wellbore  100 . However, other forms of expandable tubulars may be employed, such as expandable screens or metal skin, so long as they are capable of isolating a zone of the wellbore  100 .  
         [0033]    [0033]FIGS. 3A and 3B are cross-sectional views illustrating the upper sealing apparatus  200  partially expanded into contact with the wellbore  100  by the expansion tool  115 . As shown on FIG. 3B, the upper sealing apparatus  200  includes an expandable tubular  205 . The expandable tubular  205  has an inner surface  245  and an outer surface  255 . The expandable tubular  205  further includes a plurality of apertures  260  that are equally spaced around the circumference of the expandable tubular  205  and act as passageways between the inner surface  245  and the outer surface  255 . In the embodiment shown, the apertures  260  are tapped and plugged by a plurality of plug members  210  to initially prevent communication between the inner surface  245  and the outer surface  255 . Additionally, a plurality of fine mesh screens  275  are disposed on outer surface  255  around the plurality of apertures  260 . In another embodiment, the apertures  260  remain unplugged, thereby allowing communication between the inner surface  245  and the outer surface  255 .  
         [0034]    The upper sealing apparatus  200  further includes an upper end member  215  and a lower end member  240  disposed around the outer surface  255  of the expandable tubular  205 . The upper and lower end members  215 ,  240  are machined out of a composite material which allows the end members  215 ,  240  to expand radially outward while maintaining a clamping force and structural integrity. However, other types of material may be used to machine the end members  215 ,  240 , so long as they are capable of expanding radially outward while maintaining a clamping force and structural integrity.  
         [0035]    The upper end member  215  is disposed at the upper end of the sealing apparatus  200 . The primary function of the upper end member  215  is to secure one end of a plurality of upper ribs  220  and an upper end of a sealing element  225  to the expandable tubular  205 . Preferably, the upper ribs  220  are equally spaced around the outer surface  255  of the expandable tubular  205 . The upper ribs  220  are embedded in the sealing element  225  to provide support during the expansion of the upper sealing apparatus  200 . The upper ribs  220  are fabricated out of deformable material such as aluminum. However, other types of deformable material may be employed, so long as the material is capable of providing support while deforming due to pressure. Additionally, the lower end member  240  secures one end of a plurality of lower ribs  235  and the lower end of sealing element  225  to the tubular  205  in the same manner as the upper end member  215 .  
         [0036]    The upper sealing apparatus  200  further includes the sealing element  225 . The sealing element  225  is disposed around the tubular  205  to increase the ability of the sealing apparatus  200  to seal against an inner surface of the wellbore  100  upon expansion. In the preferred embodiment, the sealing element  225  is fabricated from an elastomeric material. However, other materials may be used, so long as they are suitable for enhancing the fluid seal between the expanded portion of the sealing apparatus  200  and the wellbore  100 . The sealing element  225  is secured at the upper end of the sealing apparatus  200  by the upper end member  215  and the lower end by the lower end member  240 . Another function of the sealing element  225  is to contain a swelling elastomer  230  that is disposed between the outer surface  255  of the expandable tubular  205  and the sealing element  225 .  
         [0037]    The swelling elastomer  230  is a cross-linked polymer that will swell multiple times its initial size upon activation by an activating agent. Generally, the activating agent stimulates the polymer chains to expand the swelling elastomer  230  both radial and axially. In the preferred embodiment, an activating agent such as a proprietary fluid or some form of water-based liquid activates the swelling elastomer  230 . However, other embodiments may employ different types of swelling elastomers that are activated by other forms of activating agents. In the preferred embodiment, the swelling elastomer  230  is wrapped around the outer surface  255  of the expandable tubular  205  in an inactivated state. The plug members  210  disposed in the apertures  260  act as a fluid barrier to prevent any fluid or activating agent from contacting the swelling elastomer  230  during the run-in procedure. Further, the swelling elastomer  230  is contained laterally by the upper and lower end members  215 ,  240  and contained radially by the deformable sealing element  225  and the deformable upper and lower ribs  220 ,  235 . In this manner, the swelling elastomer  230  is substantially enclosed and maintained within a predefined location in an inactivated state and thereafter, within a controlled location in an activated state.  
         [0038]    As depicted on FIG. 3A, the upper torque anchor  160  is energized to ensure the running assembly  170  and the expandable liner assembly  150  will not rotate during the expansion operation. Thereafter, at a predetermined pressure, the pistons (not shown) in the expansion tool  115  are actuated and the rollers  175  are extended until they contact the inner surface  245  of the expandable tubular  205 . The rollers  175  of the expansion tool  115  are further extended until the rollers  175  plastically deform the expandable tubular  205  into a state of permanent expansion. The motor  145  rotates the expansion tool  115  during the expansion process, and the tubular  205  is expanded until the outer surface of the sealing element  225  contacts the inner surface of the wellbore  100 . As the expansion tool  115  translates axially downward during the expansion operation, the rollers  175  knock off an upper portion of the plug members  210 , thereby removing the fluid barrier to allow fluid in the annulus  165  to travel through the apertures  260  and the fine mesh screen  275  into contact with the swelling elastomer  230 . As the fluid or activating agent contacts the swelling elastomer  230 , the polymer chains change positions, thereby expanding the swelling elastomer  230  laterally and radially to create a pressure energized seal with one or more adjacent surfaces in the wellbore  100  as shown in FIG. 3B.  
         [0039]    [0039]FIG. 3B is an enlarged cross-sectional view illustrating the expansion of the swelling elastomer  230  in the upper sealing apparatus  200 . As shown in the upper portion of the sealing apparatus  200 , the tubular  205  has been plastically deformed and the plug members  210  removed by the expansion tool  115 . Additionally, fluid in the annulus  165  has entered the apertures  260  and activated an upper portion of the swelling elastomer  230 . As the swelling elastomer  230  continues to expand, the upper and lower end members  215 ,  240  limit any lateral expansion while the fine mesh screen  275  limits any expansion through the apertures  260 , thereby causing the majority of the expansion forces to act radially outward to deform the upper and lower ribs  220 ,  235  and the sealing element  225 . As both the tubular  205  and the swelling elastomer  230  are expanded, the sealing element  225  engages the surrounding wellbore  100  and creates a pressure energized seal. After the entire upper sealing apparatus  200  is expanded radially outward, the expansion tool  115  continues laterally downward expanding the lower tubular  185 .  
         [0040]    [0040]FIG. 4 is a cross-sectional view illustrating the lower sealing apparatus  300  expanded into contact with the wellbore  100  by the expansion tool  115 . As shown, the expansion tool  115  has expanded the lower tubular  185  and the lower sealing apparatus  300  in the same manner as described in the previous paragraph regarding the upper sealing apparatus  200 . Thereafter, the expansion tool  115  is moved to a predetermined point near the slots  140  as illustrated on FIG. 5.  
         [0041]    [0041]FIG. 5 is a cross-sectional view illustrating the blades  155  on the expansion tool  115  cutting an upper portion of the expandable liner assembly  150 . As shown, the expansion tool  115  has moved laterally upward to a predetermined point below the slots  140  on the upper tubular  180 . As further shown, the rollers  175  have been retracted and the blades  155  have been extended outward until they contact the inner surface of the upper tubular  180 . As the motor  145  rotates the expansion tool  115  during the cutting operation, the lower ends of the slots  140  are cut to create finger-like members.  
         [0042]    [0042]FIG. 6 is a cross-sectional view illustrating the removal of the upper tubular  180  from the wellbore  100 . For clarity, the running assembly  170  has been removed in FIG. 6. As shown, the lower end slots  140  have been cut by the expansion tool  115 . Upon upward movement, as shown by arrow  198 , the finger-like members collapse radially inward to allow the upper portion of the tubular  180  to be removed from the wellbore  100 .  
         [0043]    [0043]FIG. 7 is a cross-sectional view of the liner assembly  150  fully expanded into contact with the surrounding wellbore  100 . As depicted, a portion of the upper tubular  180 , lower tubular  185  and the upper and lower sealing apparatus  200 ,  300  of this present invention are expanded into the prepared section  105  of the wellbore  100 . As shown, the inner diameter of liner assembly  150  is comparable to the inner diameter of the wellbore  100  above and below the liner assembly  150 . In this manner, the liner assembly  150  may isolate a zone within the wellbore  100  without restricting the inner diameter of the wellbore  100 , thereby allowing further exploration or unrestricted drilling of the wellbore  100 .  
         [0044]    In operation, the running assembly and liner assembly are lowered by the workstring to a predetermined point in the wellbore. Thereafter, the upper torque anchor on the running assembly is energized to secure the running assembly and expandable liner assembly in the wellbore. Subsequently, at a predetermined pressure, the pistons in the expansion tool are actuated and the rollers are extended until they contact the inner surface of the liner assembly. The rollers of the expansion tool are further extended until the rollers plastically deform the liner assembly into a state of permanent expansion. The motor rotates the expansion tool during the expansion process, and the liner assembly is expanded until the outer surface of the sealing element on the sealing apparatus contacts the inner surface of the wellbore. As the expansion tool translates axially downward during the expansion operation, the rollers knock off the upper portion of the plug members, thereby removing the fluid barrier to allow fluid in the annulus to travel through the apertures into contact with the swelling elastomer. As the fluid or activating agent contacts the swelling elastomer, the polymer chains change positions, thereby expanding the swelling elastomer laterally and radially to create a pressure energized seal with one or more adjacent surfaces in the wellbore.  
         [0045]    The expansion tool continues to move axially downward expanding the entire length of the liner assembly. Thereafter, the expansion tool moves laterally upward to a predetermined point below the slots on the upper tubular. Subsequently, the blades on the expansion tool extend radially outward until they contact the inner surface of the upper tubular. As the motor rotates the expansion tool during the cutting operation, the lower ends of the slots are cut to create finger-like members on a portion of the upper tubular. Thereafter, the running assembly and the portion of the upper tubular are removed from the wellbore.  
         [0046]    While the foregoing is directed to embodiments of the present invention, other and further embodiments of the invention may be devised without departing from the basic scope thereof, and the scope thereof is determined by the claims that follow.

Technology Category: y