Patent Publication Number: US-6988557-B2

Title: Self sealing expandable inflatable packers

Description:
BACKGROUND OF THE INVENTION 
   1. Field of the Invention 
   Aspects of the present relate to a sealing apparatus. Particularly, the present invention relates to an expandable sealing apparatus. More particularly, the present invention relates to an expandable sealing apparatus for isolating sections of a wellbore. 
   2. Description of the Related Art 
   In the oil and gas exploration and production industry, boreholes are drilled through rock formations to gain access to hydrocarbon-bearing formations, to allow the hydrocarbons to be recovered to surface. During drilling of a typical borehole, which may be several thousand feet in length, many different rock formations are encountered. 
   Rock formations having problematic physical characteristics, such as high permeability, may be encountered during the drilling operation. These formations may cause various problems such as allowing unwanted water or gases to enter the borehole; crossflow between high and low pressure zones; and fluid communication between a highly permeable formation and adjacent formations. In instances where a sub-normal or over-pressured formation is sealed off, the permeability of the formation may be such that high pressure fluids permeate upwardly or downwardly, thereby re-entering the borehole at a different location. 
   Damage to rock formations during drilling of a borehole may also cause problems for the drilling operation. Damage to the formation may be caused by the pressurized drilling fluid used in the drilling operation. In these situations, drilling fluid may be lost into the formation. Loss of drilling fluid may cause the drilling operation to be halted in order to take remedial action to stabilize the rock formation. Loss of drilling fluid is undesirable because drilling fluids are typically expensive. In many cases, drilling fluids are re-circulated and cleaned for use in subsequent drilling procedures in order to save costs. Therefore, loss of high quantities of drilling fluid is unacceptable. 
   One method of overcoming these problems involves lining the borehole with a casing. This generally requires suspending the casing from the wellhead and cementing the casing in place, thereby sealing off and isolating the damaged formation. However, running and cementing additional casing strings is a time-consuming and expensive operation. 
   Furthermore, due to the installation of the casing, the borehole drilled below the casing has a smaller diameter than the sections above it. As the borehole continues to be extended and casing strings added, the inner diameter of the borehole continues to decrease. Because drilling operations are carefully planned, problematic formations unexpectedly encountered may cause the inner diameter of the borehole to be overly restricted when additional casing strings are installed. Although this may be accounted for during planning, it is generally undesired and several such occurrences may cause a reduction in final bore diameter, thereby affecting the future production of hydrocarbons from the well. 
   Alternatively, inflatable packers may be used to seal off a portion of a wellbore. Typically, the inflatable packer utilizes an inflatable elastomeric bladder to create a fluid seal within the surrounding wellbore or casing. The bladder may be inflated by injecting fluid under pressure into the bladder. In this manner, the bladder is inflated into contact with the wellbore. Typically, the pressure in the bladder is increased to greater than that of the pore pressure of the formation. In this respect, a net seal load is created, thereby sealing off the wellbore. 
   While the inflatable packer is a viable method of sealing a wellbore, there are potential problems associated with its application. For example, the actuation of the inflatable packer is operated through a complex valve system that may not function properly. Also, like the casing strings, the inflatable packer reduces the inner diameter of the wellbore, thereby potentially limiting the production capacity of the wellbore. 
   More recently, expandable tubular technology has been developed to install casing strings without significantly decreasing the inner diameter of the wellbore. Generally, expandable technology enables a smaller diameter tubular to pass through a larger diameter tubular, and thereafter be expanded to a larger diameter. In this respect, expandable technology permits the formation of a tubular string having a substantially constant inner diameter, otherwise known as a monobore. Accordingly, monobore wells have a substantially uniform through-bore from the surface casing to the production zones. 
   A monobore well features each progressive borehole section being cased without a reduction of casing size. The monobore well offers the advantage of being able to start with a much smaller surface casing but still end up with a desired size of production casing. Further, the monobore well provides a more economical and efficient way of completing a well. Because top-hole sizes are reduced, less drilling fluid is required and fewer cuttings are created for cleanup and disposal. Also, a smaller surface casing size simplifies the wellhead design as well as the blow out protectors and risers. Additionally, running expandable liners instead of long casing strings will result in valuable time savings. 
   Expandable tubular technology has recently been applied to cased hole packers. 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. 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 expandable packer may be expanded against an existing casing to hang a string of casing or seal off an annular area. Consequently, expandable packers allow for the use of larger diameter production tubing, because the conventional slip mechanism and sealing mechanism are eliminated. 
   An expandable packer is typically run into the wellbore with a running assembly disposed at an end of a drill string. The running assembly generally includes an expansion tool, a swivel, and a running tool. 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. 
   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. 
   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. Also, the expandable packer may not expand sufficiently to contact the wellbore and form a seal therewith. 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. 
   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 packer that will expand sufficiently to form a seal with the wellbore. 
   SUMMARY OF THE INVENTION 
   The present invention generally relates to a sealing apparatus for isolating a wellbore. In one aspect, the present invention provides an expandable sealing apparatus having an expandable tubular and a sealing element disposed around the tubular. A chamber for maintaining a fluid is defined between the sealing element and the tubular. The sealing apparatus also includes a self-isolating layer disposed in the chamber, wherein the self-isolating layer is adapted and arranged to regulate fluid flow through the chamber. Fluid supplied to the chamber may inflate the sealing element, thereby urging the sealing element into contact with the wellbore. The pressure in the chamber causes the self-isolating layer to close off, thereby retaining the pressure in the chamber. 
   In another aspect, the present invention provides a method for isolating a wellbore. The method includes running a sealing apparatus into the wellbore. The sealing apparatus having a tubular body; a sealing element disposed around the tubular body; and a self-isolating layer disposed between the tubular body and the sealing element. The method further includes expanding the sealing apparatus and inflating the sealing element. Preferably, the pressure in the inflated sealing element is greater than the pore pressure of the formation. 
   In another embodiment, the method may also include supplying fluid into a chamber defined by the tubular body and the sealing element to expand the sealing apparatus. The fluid may be regulated to create a pressure differential between the chamber and the tubular body. The pressure differential causes the self-isolating screen to close, thereby retaining the pressure necessary to inflate the sealing element. 
   In another aspect still, the present invention provides a seal assembly. The seal assembly includes an expandable tubular and a sealing member disposed at each end of the tubular. The sealing members may straddle a section of the wellbore to isolate that section from other sections of the wellbore. 

   
     BRIEF DESCRIPTION OF THE DRAWINGS 
     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. 
       FIG. 1  is a schematic cross-sectional view of a partially completed wellbore. 
       FIG. 2  is a schematic view of a seal assembly according to aspects of the present invention disposed in the wellbore of FIG.  1 . The seal assembly is shown in the unexpanded configuration. 
       FIG. 3  is a partial cross-sectional view of one embodiment of the sealing member of the present invention. The sealing member is shown in the unactuated configuration. 
       FIG. 4  is a schematic view of the seal assembly of  FIG. 2  in the expanded, uninflated configuration. 
       FIG. 5  is a partial cross-sectional view of the sealing member of  FIG. 3  during inflation. 
       FIG. 6  is a schematic view of the seal assembly of  FIG. 2  in the expanded, inflated configuration. 
       FIG. 7  is a partial cross-sectional view of the sealing member of  FIG. 3  in the actuated configuration. 
       FIG. 8  is a partial cross-sectional view of another embodiment of the sealing member of the present invention. The sealing member is shown in the unactuated configuration. 
       FIG. 9  is a partial cross-sectional view of the sealing member of  FIG. 8  during inflation. 
       FIG. 10  is a partial cross-sectional view of the sealing member of  FIG. 8  in the actuated configuration. 
       FIG. 11  is a partial cross-sectional view of another embodiment of the sealing member of the present invention. The sealing member is shown in the unactuated configuration. 
       FIG. 12  is a schematic view of another embodiment of the seal assembly of the present invention. 
   

   DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT 
     FIG. 1  is a schematic illustration of a partially completed wellbore  10 . The wellbore  10  is initially drilled to a first depth  12  and may be logged to determine certain geological characteristics of the rock formations in the region of the wellbore  10 . As shown, a casing  14  has been installed in an upper portion  18  of the wellbore  10  and cemented  16  into place. Thereafter, the wellbore  10  is extended by drilling a smaller diameter wellbore section  20  below the casing  14  through a number of rock formations illustrated at  22 - 26 . 
   In this example, during drilling of the wellbore section  20 , the rock formation  24  was unexpectedly found to be highly permeable, and drilling fluid has been lost into the formation  24 . Loss of drilling fluid may be detected by a loss of circulation and a drop in the pit volume of drilling fluid. As a result, drilling operations have been suspended. 
   To prevent further loss of drilling fluid into the formation  24  and continue well completion operations, a seal assembly  50  according to aspects of the present invention is located in the wellbore  10  as illustrated in FIG.  2 . The seal assembly  50  includes a first sealing member  100 A and a second sealing member  100 B disposed at each end of an expandable tubular  110 . In this embodiment, each of the sealing members  100 A,  100 B are similarly constructed. It is understood that the expandable tubular  110  may include one or more tubulars connected together. Additionally, the expandable tubular  110  may include any suitable expandable tubular for wellbore operations, including expandable solid tubulars, expandable slotted tubulars, and expandable screens. 
   Initially, the wellbore  10  is underreamed to form a larger bore diameter  42  before the seal assembly  50  is installed as illustrated in FIG.  2 . Thereafter, the seal assembly  50  is located in the wellbore  10  to isolate the rock formation  24 . Specifically, the seal assembly  50  is positioned such that the sealing members  100 A,  100 B straddle the formation  24  to be blocked off. The seal assembly  50  is run into the wellbore  10  on an upper string of expandable solid tubular  48  adapted and arranged to locate the seal assembly  50  in the underreamed section  42 . The upper string  48  is suspended from the casing  14  by an expandable liner packer  49 . A lower string of tubular  51  may be attached below the seal assembly  50  to facilitate other operations downhole. 
     FIG. 3  depicts a sectional view of a sealing member  100  suitable for use with the seal assembly  50  according to aspects of the present invention. The sealing member  100  includes an expandable mandrel  115  and an inflatable sealing element  120  mounted on the mandrel  115 . The sealing element  120  may be made from any suitable expandable material, including an elastomeric material such as a swelling elastomer or a rubber material such as natural rubber. A chamber  125  is defined between the sealing element  120  and the mandrel  115 . One or more ports  117  may be formed in the mandrel  115  to provide fluid communication between the bore  118  of the mandrel  115  and the chamber  125 . Fluid supplied to the chamber  125  may serve to inflate the sealing element  120 . A series of reinforcing ribs  127  are disposed at each end of the sealing element  120  to provide support for the sealing element  120  after inflation. The ribs  127  may be made of metal, composite, carbon-fiber or other suitable material as is known to a person of ordinary skill in the art.  FIG. 3  depicts the sealing member  100  in the run-in uninflated position. 
   In one aspect, the sealing member  100  may include a self-isolating mechanism to maintain the sealing element  120  in an inflated state. In one embodiment, a permeable membrane  130  may be disposed between the mandrel  115  and the sealing element  120 . The membrane  130  may be made of Teflon or an elastomeric material such as rubber. The permeable membrane  130  may include one or more openings  135  for fluid communication. 
   A self-isolating screen  140  may be disposed around the permeable membrane  130 . The self-isolating screen  140  is adapted and arranged to maintain the pressure in the chamber  125  after the sealing element  120  is inflated. The screen  140  includes one or more apertures  142  for fluid communication. Each of the apertures  142  is provided with a flow control member  143  to regulate the flow of fluid therethrough. An exemplary flow control member  143  includes a flap  143  connected to the screen  140  at one end and unsecured at another end as shown in FIG.  3 . Preferably, the flap  143  is located interior to the chamber  125  and is of sufficient size to cover or close off the respective aperture  142 . The flaps  143  are actuatable by a pressure differential between the bore  118  and the chamber  125 . During inflation, the flap  143  may be caused to flex away from aperture  142  to allow fluid to flow into the chamber  125 , thereby inflating the sealing element  120 . Conversely, the flap  143  may flex toward the aperture  142  to seal off the chamber  125 , thereby isolating the pressure in the chamber  125 . In one embodiment, self-isolating screen  140  may be made of metal. In another embodiment, a sealing material may be disposed around the perimeter of the flap  143  to facilitate closure of the aperture  142 . 
   In operation, the seal assembly  50  is formed by connecting a sealing member  100 A,  100 B at each end of an expandable tubular  110 . The seal assembly  50  is disposed in the wellbore as shown in FIG.  2 . Thereafter, an expander tool is employed to expand the seal assembly  50 . Expansion of the seal assembly  50  brings the sealing members  100 A,  100 B closer to the wall  42  of the wellbore (or into contact with the wall  42 ), as illustrated in FIG.  4 . Particularly, the expandable mandrels  115  are expanded to a greater internal diameter, thereby causing a corresponding expansion of the sealing elements  100 A,  100 B. It is understood that the sealing elements  100 A,  100 B may be expanded into contact with the wellbore wall without deviating from the aspects of the present invention. 
   Any suitable expander tool known to a person of ordinary skill in the art may be utilized to expand the seal assembly  50 . An exemplary expander tool is disclosed in Simpson, U.S. Pat. No. 6,457,532, issued on Oct. 1, 2002, which patent is herein incorporated by reference in its entirety. In one embodiment, the expander tool may include a rotary expander tool acting outwardly against the inside surface of the seal assembly  50 . The expander tool has a body, which is hollow and generally tubular with connectors and for connection to other components of a downhole assembly. The connectors are of a reduced diameter compared to the outside diameter of the longitudinally central body part of the expander tool. The central body part of the expander tool has three recesses, each holding a respective roller. Each of the mutually identical rollers is somewhat cylindrical and barreled. Each of the rollers is mounted by means of an axle at each end of the respective roller and the axles are mounted in slidable pistons. The rollers are arranged for rotation about a respective rotational axis that is parallel to the longitudinal axis of the expander tool and radially offset therefrom at 120-degree mutual circumferential separations around the central body. The pistons are sealed within each recess and are radially extendable therein. The inner end of each piston is exposed to the pressure of fluid within the core of the tool by way of the radial perforations in the core. In this manner, pressurized fluid provided from the surface of the well, can actuate the pistons and cause them to extend outward whereby the rollers contact the inner wall of the seal assembly  50  to be expanded. Other exemplary expander tools include a cone-shaped mandrel that can be axially traversed to expand the seal assembly  50 . The expander tool is retrieved at the completion of the expansion. 
   The sealing members  100 A,  100 B may now be inflated to seal off the wellbore  10 . A fluid from the surface is supplied to the chambers  125  of the sealing members  100 A,  100 B to inflate the sealing elements  120 . Preferably, the fluid is inert to the well and drilling fluids. An inflation tool may be used to supply the fluid under pressure to the chambers  125 . The fluid is initially forced through the ports  117  of the mandrel  115  and then through the openings  135  of the permeable membrane  130 . Thereafter, the fluid flow past the apertures  142  of the self-isolating screen  140  and exit into the chamber  125 , thereby inflating the chamber  125 .  FIG. 5  illustrates the seal  100  during the inflation process. As shown, the pressurized fluid causes the flap  143  to flex away from the aperture  142 , thereby opening the aperture  142  for fluid communication. Consequently, the sealing element  120  is expanded into contact with the wellbore  10 . In this respect, a large pressure energized seal load is generated between the sealing member  100  and the wellbore  10  to provide the desired zone isolation. 
   After the sealing members  100 A,  100 B have been sufficiently inflated, the pressurized fluid is released.  FIG. 6  illustrates the seal assembly  50  after inflation. As a result, a pressure differential is created between the chamber  125  and the bore  118  of the mandrel  115 . Particularly, the chamber  125  has a higher pressure than the hydrostatic pressure in the mandrel  115 . As the fluid in the chamber  125  tries to equalize the pressures by flowing out of the chamber  125  toward the mandrel  115 , the self-isolating screen  140  closes off and the pressure in the chamber  125  is applied against the permeable membrane  130 , as illustrated in FIG.  7 . Particularly, the pressurized fluid causes the flap  143  to flex toward the aperture  142 , thereby closing off the aperture  142  for fluid communication. Moreover, the pressure in the chamber  125  causes the screen  140  to press against the membrane  130  to further close off the apertures  142 . In this respect, the pressure is trapped in the chamber  125  to maintain the energized seal load. In this manner, the seal assembly  50  may be actuated to provide zone isolation. 
   In another aspect, an isolation plug  160  may be inserted into the ports  117  of the mandrel  115  prior to run-in, as illustrated in FIG.  3 . The isolation plugs  160  may prevent premature inflation of the sealing element  127 . Preferably, the isolation plugs  160  include a hollow interior. During expansion, the expander tool may break the isolation plugs  160 , thereby opening the ports  117  for fluid communication. In this manner, the seals  100  may be adapted to prevent premature inflation. 
     FIG. 8  illustrates another embodiment of a sealing member  800  suitable for use with the seal assembly  50  according to aspects of the present invention. The sealing member  800  includes an expandable mandrel  815  and an inflatable sealing element  820  mounted on the mandrel  815 . The sealing element  820  may be made from any suitable expandable material, including an elastomeric material such as a swelling elastomer or a rubber material such as natural rubber. A chamber  825  is defined between the sealing element  820  and the mandrel  815 . One or more ports  817  may be formed in the mandrel  815  to provide fluid communication between the bore  818  of the mandrel  815  and the chamber  825 . Fluid supplied to the chamber  825  may serve to inflate the sealing element  820 . A series of reinforcing ribs  827  are disposed at each end of the sealing element  820  to provide support for the sealing element  820  after inflation.  FIG. 8  shows the sealing member  800  in the run-in uninflated position. 
   The sealing member  800  is provided with a self-isolating layer  840  disposed around mandrel  815 . The self-isolating layer  840  includes a series of flow control members  843  to regulate the flow of fluid through the ports  817 . An exemplary flow control member  843  includes a flap  843  secured at one end to the mandrel and unsecured at another end, as shown in FIG.  8 . The series of flaps  843  are located interior to the chamber  825  and are adapted and arranged to block off fluid communication through the ports  817 . In one embodiment, the secured ends of adjacent flaps  843 ,  843 A straddle a port  817 . The free end of each flap  843  contacts or lies against a secured end of the adjacent flap  843 A. Preferably, the flaps  843 ,  843 A overlap sufficiently such that the adjacent flaps  843 ,  843 A remain in contact after expansion. The free end may be covered or impregnated with a sealing material  850  that allows a seal to be formed between the adjacent flaps  843 ,  843 A. The flaps  843  are actuatable by a pressure differential between the bore  818  and the chamber  825 . During inflation, the flap  843  may flex away from port  817  to allow fluid to flow into the chamber  825 , thereby inflating the sealing element  820 . Conversely, when the pressure in the bore  818  is released, the flap  843  may bend toward the port  817  to seal off the chamber  825 , thereby isolating the pressure in the chamber  825 . 
   In operation, the seal assembly  50  is initially expanded to a greater diameter. As shown, the seal assembly  50  is expanded against a casing  805  in a wellbore  10 . Thereafter, the sealing members  800  are inflated to seal off the wellbore  10 . A fluid from the surface is supplied to the chambers  825  of the sealing members  800  to inflate the sealing elements  820 . The fluid is initially forced through the ports  817  of the mandrel  815  and flows past the flaps  843  in the chamber  825 , as illustrated in FIG.  9 . As shown, the pressurized fluid causes the flap  843  to flex away from the adjacent flap  843 A, thereby opening the port  817  for fluid communication. Pressurized fluid in the chamber  825  expands the sealing element  820  into contact with the wellbore  10 . In this respect, a large pressure energized seal load is generated between the sealing member  820  and the wellbore  10  to provide the desired zone isolation. 
   After the sealing members  800  have been sufficiently inflated, the pressurized fluid is released.  FIG. 10  shows the sealing member  800  after inflation. As a result, a pressure differential is created between the chamber  825  and the bore  818  of the mandrel  815 . Particularly, the chamber  825  has a higher pressure than the hydrostatic pressure in the mandrel  815 . As the fluid in the chamber  825  tries to equalize the pressures by flowing out of the chamber  825  toward the bore  818 , the pressurized fluid causes the unsecured end of the flap  843  to contact the adjacent flap  843 , thereby closing off the port  817  for fluid communication. In this respect, the self-isolating layer  840  traps the pressure in the chamber  825  to maintain the energized seal load. In this manner, the seal assembly  50  may be actuated to provide zone isolation. 
   Although the flow control members  143 ,  843  in the above embodiments are arranged axially along the mandrel  115 ,  815 , it is understood that the flow control members may also be arranged radially around the mandrel as illustrated in FIG.  11 .  FIG. 11  shows a cross-sectional view of an embodiment of the sealing member  900  in which the flow control members  943  are arranged radially around the mandrel  915 . The series of flow control members  943  overlap each other to regulate fluid flow through the ports  917  in the mandrel  915 . 
   In another aspect, a solid granular filler material may be provided in the chamber. An exemplary filler material may include a mixture of bentonite (absorbent aluminum silicate clay) and a dry, powdered water soluble polymer such as polyacrylamide, as disclosed in U.S. Pat. No. 3,909,421, which patent is incorporated herein by reference. The filler material may react with the fluid supplied to the chamber to form a viscous fluid-solid mixture that cannot pass through the self-isolating screen. Additionally, the filler material increases in size as it absorbs fluid. Accordingly, the applied pressure may be relaxed once the sealing member has been inflated. As the mixture solidifies over a period of time, the pressure in the inflated chamber is retained, thereby maintaining the seal load on the wellbore. 
   When the filler is a bentonite/polyacrylamide mixture, water is used as the reactant fluid. When mixed with water downhole, a clay is formed, and the water soluble polymer flocculates and congeals the clay to form a much stronger and stiffer cement-like plug. Various filler materials, such as those disclosed in U.S. Pat. Nos. 4,633,950; 4,503,170; 4,475,594; 4,445,576; 4,442,241; and 4,391,925, which are herein incorporated by reference, are also suitable for use without deviating from the aspects of the present invention. 
   It has been observed that the seal load may change over time. This loss of seal load may be offset in several ways. First, a sealing element made of a swelling elastomer or natural rubber tends to expand as it adsorbs hydrocarbons or other fluids over a period of time. This further expansion of the sealing element enhances the seal load on the wellbore over time. Second, in situations where the sealing member is set in an unstable formation, such as an unstable formation tending to collapse inwardly over time, the re-stressed formation exert a force against the sealing element to offset the loss of seal load, thereby retaining the seal load on the formation. Third, the sealing member may be inflated to a pressure above the pore pressure of the formation. This over-pressurization maintains an effective seal load over time. Fourth, the relatively high temperatures experienced downhole tend to cause the sealing member to swell. 
   In another aspect, the seal assembly  50  may be located in the wellbore in a manner as to avoid or minimize restriction of the wellbore. The assembly  50  may be self-hanging by expanding the sealing members  100  into contact with the wellbore. Alternatively, an expandable anchor may be used to locate and hang the assembly  50  in the wellbore. 
   In another aspect, the seal assembly  750  may be arranged and constructed to isolate more than one zone.  FIG. 12  is a schematic view of a seal assembly  750  designed to isolate a plurality of producing and non-producing zones  701 ,  702 , respectively. The seal assembly  750  may include a first and second sealing members  700 A,  700 B positioned to isolate the producing zone  701 . An expandable sand screen  720  connecting the sealing members  700 A,  700 B allows the recovery of hydrocarbons from the producing zone  701 . The seal assembly  750  may further include expandable solid tubulars  730  positioned along non-producing zones  702 . As shown, a solid tubular  730  cooperate with the second and third sealing members  700 B,  700 C to isolate the non-producing zone  702 . Furthermore, migration of fluids from the non-producing zone  702  along the wellbore annulus to the producing zone  701  is prevented. In this manner, aspects of the present invention provide a seal assembly  750  for managing multiple zones. 
   In another aspect, the ports, apertures, and channels in the sealing members may be of any suitable shape other than circular. For example, part of the mandrel may be slotted or otherwise perforated and on expansion may form diamond or other shaped openings. 
   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.