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CROSS-REFERENCE TO RELATED APPLICATIONS 
   This application claims benefit of U.S. Provisional Patent Application Ser. No. 60/655,289,filed Feb. 22, 2005,which is herein incorporated by reference. 

   BACKGROUND OF THE INVENTION 
   1.Field of the Invention 
   The present invention generally relates to systems and methods for drilling and completing a wellbore. More particularly, the invention relates to systems and methods for mitigating trouble zones in a wellbore in a managed pressure condition and completing the wellbore in the managed pressure condition. 
   2.Description of the Related Art 
   Historically, wells have been drilled with a column of fluid in the wellbore designed to overcome any formation pressure encountered as the wellbore is formed. This “overbalanced condition” restricts the influx of formation fluids such as oil, gas or water into the wellbore. Typically, well control is maintained by using a drilling fluid with a predetermined density to keep the hydrostatic pressure of the drilling fluid higher than the formation pressure. As the wellbore is formed, drill cuttings and small particles or “fines” are created by the drilling operation. Formation damage may occur when the hydrostatic pressure forces the drilling fluid, drill cuttings and fines into the reservoir. Further, drilling fluid may flow into the formation at a rate where little or no fluid returns to the surface. This flow of fluid into the formation can cause the “fines” to line the walls of the wellbore. Eventually, the cuttings or other solids form a wellbore “skin” along the interface between the wellbore and the formation. The wellbore skin restricts the flow of the formation fluid during a production operation and thereby damages the well. 
   Another form of drilling is called managed pressure drilling. An advantage of managed pressure drilling is the ability to make bottom hole pressure adjustments with minimal interruptions to the drilling progress. Another related drilling method of managed pressure drilling is underbalanced drilling. In this drilling method, the column of fluid in the wellbore is designed to be less than the formation pressure encountered as the wellbore is formed. Typically, well control is maintained by using a drilling fluid with a predetermined density to keep the hydrostatic pressure of the drilling fluid lower than the formation pressure. As the wellbore is formed, drill cuttings and small particles or “fines” are created by the drilling operation and circulated out of the wellbore resulting in minimal formation damage. 
   Managed pressure drilling and underbalanced drilling maximizes the production of the well by reducing skin effect and/or formation damage during the drilling operation. However, the maximization of production is negated when the well has to be killed in order to mitigate a trouble zone encountered during the managed pressure or underbalanced drilling operation. Further, the maximization of production is negated when the well has to be killed in order to complete the wellbore after the drilling operation. Presently, snubbing is a method for tripping a drill string in a constant underbalanced state. Snubbing removes the possibility of damaging the formation, but increases rig up/rig down and tripping times, adding to the operational expense. In addition, the snubbing unit cannot seal around complex assemblies, such as a solid expandable drilling liner which is typically used to mitigate a trouble zone encountered during a drilling operation. Further snubbing units cannot seal around slotted liners or conventional sand screens which are typically used in completing a wellbore. 
   There is a need, therefore, for an effective method and system to mitigate trouble zones encountered during an underbalanced or managed pressure drilling operation. There is a further need, therefore, for an effective method and system to complete the wellbore in an underbalanced or managed pressure condition. 
   SUMMARY OF THE INVENTION 
   The present invention generally relates to methods and systems for mitigating trouble zones in a wellbore in a preferred pressure condition and completing the wellbore in the preferred pressure condition. In one aspect, a method of reinforcing a wellbore is provided. The method includes locating a valve member within the wellbore for opening and closing the wellbore. The method further includes establishing a preferred pressure condition within the wellbore and closing the valve member. The method also includes locating a tubular string having an expandable portion in the wellbore and opening the valve member. Additionally, the method includes moving the expandable portion through the opened valve member and expanding the expandable portion in the wellbore at a location below the valve member. 
   In another aspect, a method of forming a wellbore is provided. The method includes separating the wellbore into a first region and a second region by closing a valve member disposed in the wellbore. The method also includes reducing the pressure in the first region and lowering a tubular string having an earth removal member and an expandable portion into the first region of the wellbore to point proximate the valve member. The method further includes establishing and maintaining a preferred pressure condition in the wellbore and opening the valve member. Additionally, the method includes moving the earth removal member and the expandable portion through the opened valve member and forming the wellbore. 
   In yet another aspect, a system for drilling a wellbore is provided. The system includes a tubular string having an earth removal member and an expandable portion. The system also includes a valve member located within the wellbore for substantially opening and closing the wellbore. Additionally, the system includes a fluid handling system for maintaining a portion of the wellbore in one of a managed pressure condition and an underbalanced pressure condition. 

   
     BRIEF DESCRIPTION OF THE DRAWINGS 
     So that the manner in which the above recited features of the present invention can be understood in detail, a more particular description of the invention, briefly summarized above, may be had by reference to embodiments, some of 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 view of a drilling assembly being lowered in a wellbore on a drill string. 
       FIG. 2  is a view of the wellbore with a valve member in a closed position. 
       FIG. 3  illustrates the drilling assembly forming another section of the wellbore during an underbalanced or a managed pressure drilling operation. 
       FIG. 4  illustrates the drilling assembly forming another section of the wellbore after an expandable portion has isolated a trouble zone from the surrounding wellbore. 
       FIG. 5  illustrates the placement of a second expandable portion at another trouble zone. 
       FIG. 6  illustrates a portion of the wellbore being formed by drilling with a string of casing. 
       FIG. 7  illustrates a completed wellbore with an expandable filter member. 
       FIGS. 8A-8D  illustrate different forms of the expandable portion. 
   

   DETAILED DESCRIPTION 
   In general, the present invention relates to systems and methods for completing a wellbore in a preferred pressure condition in order to reduce wellbore damage. As will be described herein, the systems and methods are employed in a wellbore having a preferred pressure condition, such as an underbalanced or managed pressure condition. It must be noted that aspects of the present invention are not limited to these conditions, but are equally applicable to other types of wellbore conditions. Additionally, the present invention will be described as it relates to a vertical wellbore. However, it should be understood that the invention may be employed in a horizontal or deviated wellbore without departing from the principles of the present invention. To better understand the novelty of the apparatus of the present invention and the methods of use thereof, reference is hereafter made to the accompanying drawings. 
     FIG. 1  is a view of a drilling assembly  100  being lowered in a wellbore  10  on a drill string  105 . The drilling assembly  100  includes a drill bit  110  or other earth removal member, a first carrying assembly  115  with an expandable portion  125  and a second carrying assembly  120  with an expandable portion  130 . As illustrated, the wellbore  10  is lined with a string of steel pipe called casing  15 . The casing  15  provides support to the wellbore  10  and facilitates the isolation of certain areas of the wellbore  10  adjacent hydrocarbon bearing formations. The casing  15  typically extends down the wellbore  10  from the surface of the well to a designated depth. An annular area  20  is thus defined between the outside of the casing  15  and the wellbore  10 . This annular area  20  is filled with cement  25  pumped through a cementing system (not shown) to permanently set the casing  15  in the wellbore  10  and to facilitate the isolation of production zones and fluids at different depths within the wellbore  10 . 
   At the surface of the wellbore  10 , a rotating control head  75  is disposed on a blow out preventer (BOP) stack  80 . Generally, the rotating control head  75  isolates pressurized annular returns and diverts flow away from the surface of the wellbore  10  to a choke manifold (not shown) and a separator (not shown). The rotating control head  75 , which is mounted on top of the BOP stack  80 , seals the drill string  105  creating a pressure barrier on the annulus side of the drill string  105  while the drill string  105  is being tripped in or out of the wellbore  10  or while it is being rotated during drilling operations. Additionally, the rotating control head  75  and the choke manifold together act as a fluid control system and are used to manage the wellbore&#39;s annular pressure, such as in a managed pressure condition or an underbalanced pressure condition. 
   During the underbalanced drilling operation, the reservoir fluids are allowed to flow. Therefore a surface pressure is ever present in the annulus formed between the drill string  105  and the casing  15 . The rotating control head  75  is used to control the pressure at the surface of the wellbore  10 . As tripping begins, and the drill string  105  is stripped through the rotating control head  75 , the pressure must be managed to prevent well pressures uncontrollably forcing the drill string out  105  of the wellbore in a pipe-light situation. Generally pipe-light occurs at the point where the formation pressure across the pipe cross-section creates an upward force sufficient to overcome the downward force created by the pipe&#39;s weight. 
   A downhole deployment valve  50  is disposed at the lower end of the casing  15 . The downhole deployment valve  50  is commonly used to shut-in oil and gas wells. The downhole deployment valve  50  may be installed in the casing  15  as shown in  FIG. 1  or the downhole deployment valve  50  may be installed on a tie-back string which can be retrieved following the drilling operation. Generally, the downhole deployment valve  50  is configured to selectively block the flow of formation fluids upwardly through the casing  15  should a failure or hazardous condition occur at the well surface. Additionally, the downhole deployment valve  50  allows a wide range of systems and bottom hole assemblies to be safely and effectively deployed in an underbalanced or a mangaged pressure drilling operation. Typically, the downhole deployment valve  50  is maintained in an open position by the application of hydraulic fluid pressure transmitted to an actuating mechanism. The actuating mechanism (not shown) is charged by application of hydraulic pressure. The hydraulic pressure is commonly a clean oil supplied from a surface fluid reservoir through a control line. A pump (not shown) at the surface of the wellbore  10  delivers regulated hydraulic fluid under pressure from the surface of the wellbore  10  to the actuating mechanism through the control line. Typically, the bore through the downhole deployment valve  50  is equal to or greater than the drift diameter of the casing  15  when the downhole deployment valve  50  is in the open position. 
   As illustrated in  FIG. 1 , the drilling assembly  100  is lowered into the wellbore  10  on the drill string  105  to a point proximate the downhole deployment valve  50 . Pressure within the drill string  105  is controlled by closing an inner diameter of the drill string using a valve member within the drill string or a retrievable plug. Thereafter, the downhole deployment valve  50  is closed as illustrated in  FIG. 2  by applying hydraulic pressure from the surface fluid reservoir through the control line. 
   After the downhole deployment valve  50  is closed, the wellbore  10  is separated into a first region  85  and a second region  90 . The wellbore pressure in the first region is then reduced to substantially zero by manipulating the rotating control head  75  and the choke manifold system. In one embodiment, the downhole deployment valve  50  is equipped with downhole sensors  250 , as shown in  FIG. 1 , that transmit an electrical signal to the surface, allowing measurement and reading of real-time downhole pressures. 
   When the wellbore pressure in the first region  85  is reduced to substantially zero, the balance of the drill string  105  is tripped out of the wellbore  10  in a similar manner as the procedure for tripping pipe in a dead well. During the trip into the wellbore  10 , the drill string  105  is rerun to a depth directly above the downhole deployment valve  50 , where a pipe-heavy condition exists. Subsequently, pressure is applied to the wellbore  10  to equalize the pressure in the first region  85  and the second region  90 . When the pressures in the regions  85 ,  90  are substantially equal, hydraulic pressure from the surface fluid reservoir is applied through the control line to open the downhole deployment valve  50 , thereby opening the pathway into region  90  of the wellbore  10 . 
     FIG. 3  illustrates the drilling assembly  100  forming another section of the wellbore  10  during an underbalanced or a managed pressure drilling operation. Generally, the wellbore  10  is formed by rotating the drill bit  110  while urging the drilling assembly  100  downward away from the mouth of the wellbore  10 . Typically, the drill bit  110  is rotated by the drill string  105  or by a downhole motor arrangement (not shown). 
   The wellbore  10  will be formed by the drilling assembly  100  until the drilling assembly  100  encounters a trouble zone  160 . The trouble zone is a section or zone of the wellbore that negativity affects the drilling operation and/or subsequent production operation. For instance, the trouble zone may be a permeable pay zone which drains the drilling fluid from the wellbore  10 . The trouble zone may also be a high pressure water flow zone which communicates high pressure water into the wellbore  10 . The trouble zone may consist of a loss circulation zone that causes sloughing intervals or pressure transistions. 
   Once the trouble zone  160  is encountered during the drilling operation, the trouble zone  160  must be mitigated in order to effectively continue the drilling operation. In one embodiment, the trouble zone is mitigated by isolating the trouble zone from the wellbore by placing the expandable portion  125  over the trouble zone  160 . The expandable portion  125  may be an expandable clad member, an expandable liner as shown in  FIGS. 8A-8C , or any other form of expandable member. 
   As illustrated in  FIG. 3 , the drilling assembly  100  is positioned in the wellbore  10  such that the first carrying assembly  115  is positioned proximate a trouble zone  160 . In one embodiment, the portion of the wellbore  10  by the trouble zone  160  is enlarged or under-reamed by an under-reamer (not shown) or an expandable drill bit (not shown) prior to placing the carrying assembly  115  proximate the trouble zone  160 . Thereafter, the carrying assembly  115  is activated and the expandable portion  125  is expanded radially outward into contact with the under-reamed portion of the wellbore  10 . Next, the expandable portion  125  is released from the carrying assembly  115  and the drilling operation is continued. 
   The expandable portion  125  isolates the trouble zone  160  without loss of wellbore diameter. In other words, after expansion of the expandable portion  125 , the inner diameter of the expandable portion  125  is greater than or equal to the inner diameter of the casing  15 , thereby resulting in a monobore configuration. Further, the expandable portion  125  may have an anchoring member on an outside surface to allow the expandable portion  125  to grip the wellbore  10  upon expansion of the expandable portion  125 . The expandable portion  125  may also have a seal member  135  disposed on an outside surface to create a sealing relationship with the wellbore  10  upon expansion of the expandable portion  125 . Additionally, the expandable portion  125  may be set in the wellbore  10  with or without the use of cement. 
   The carrying assembly  115  may include a hydraulically activated expansion member  145  with extendable members  140  (see  FIG. 3 ) or another type of expansion member known in the art such as solid swage or a rotary tool. Additionally, the expansion member may expand the expandable portion  125  in a top to bottom expansion or in a bottom to top expansion without departing from principles of the present invention. 
   In one embodiment, the expandable portion  125  is a pre-shaped or profiled tubular. After the carrying assembly  115  is positioned proximate the trouble zone  160 , the carrying assembly  115  applies an internal pressure to the expandable portion  125  to substantially deform or reshape the expandable portion  125  to its original round shape and into contact with the wellbore  10 . Thereafter, a rotary expansion tool or another type of expansion tool may be used to further radially expand the expandable portion  125 . 
     FIG. 4  illustrates the drilling assembly  100  forming another section of the wellbore  10  after the expandable portion  125  has been placed in the wellbore  10 . As shown, the drilling assembly  100  is urged further into the wellbore  10  and the expandable portion  130  moves through the inner diameter of the expandable portion  125 . The drilling assembly  100  continues to form the wellbore  10  until another trouble zone  165  is encountered. At that point, the trouble zone  165  is mitigated by isolating the trouble zone  165  from the wellbore by placing the expandable portion  130  over the trouble zone  165  as illustrated in  FIG. 5 . 
   Similar to the process described above, the carrying assembly  120  is located in the wellbore  10  such that the expandable portion  130  is positioned proximate the trouble zone  165 . Thereafter, an expansion member  150  in the carrying assembly  120  is activated and the expandable portion  130  is expanded radially outward into contact with the under-reamed portion of the wellbore  10  by extendable members  155  in the expansion member  150  (see  FIG. 5 ) and then the expandable portion  130  is released from the carrying assembly  120 . Similar to expandable portion  125 , the expandable portion  130  isolates the trouble zone  165  without loss of wellbore diameter. In other words, after expansion of the expandable portion  130 , the inner diameter of the expandable portion  130  is greater than or equal to the inner diameter of the casing  15  and the inner diameter of the expandable portion  125 , thereby resulting in a monobore configuration. 
   After both expandable portions  125 ,  130  have been deployed, the drill string  105  is retrieved from the wellbore  10  until the lower end of the drilling assembly  100  is above the deployment valve  50 . The deployment valve  50  is then closed and the annular seal is then disengaged. Thereafter, the drill string may be removed from the wellbore  10 . Although the deployment of only two expandable portions has been described, more than two may be drilled in and deployed using the steps described without departing from principles of the present invention. Additionally, the Figures illustrate the drill bit  110  and the expandable portions  125 ,  130  lowered on the drill sting  105  at the same time. It should be understood, however, that the drill bit  110  and the expandable portions  125 ,  130  may be used independently without departing from principles of the present invention. In other words, the drill bit  110  may be used to form the wellbore  10  and then removed from the wellbore  10  while maintaining the preferred pressure condition. Thereafter, the expandable portion  125  may be lowered and disposed in the wellbore  10  as described herein while maintaining the preferred pressure condition. 
   In another embodiment the drill string  105  is deployed as described above until the first expandable portion  125  deployment is complete. At that point the drill string  105  is retrieved from the wellbore  10  until the lower end of the drill string  105  is above the deployment valve  50 . The deployment valve  50  is then closed and the annular seal is then disengaged. Retrieval of the drill string  105  is then continued until the carrying assembly  115  of the drill string  105  is accessible. A second expandable portion  130  is then affixed to the carrying assembly  115 . 
   The deployment valve  50  is then closed and the drill string  105  is reinserted into the wellbore  10  until at least the drilling assembly  100  is within the wellbore  10 . The annular seal is engaged between the wellbore inner diameter and the drill string  105  and the deployment valve  50  is opened. The drill string  105  is progressed into the wellbore through the deployment valve  50  and the drill bit  110  engaged in drilling below the previously deployed expandable portion  125 . The second expandable portion  130  is deployed proximate a second formation requiring control when drilling has progressed to that point. Following deployment of the second expandable portion  130  drilling may progress further or the drilling assembly  100  may be retrieved as previously described herein. 
     FIG. 6  illustrates a portion of the wellbore  10  formed by drilling with a string of casing  175 . Another type of trouble zone is a sloughing shale zone. One cause of unstable hole condition can occur in certain formations when the hydrostatic pressure of the fluid column is not sufficient to hold back the formation, resulting in sloughing of the wall of the wellbore  10 . For this reason sloughing formations, especially shale sections, are somewhat common in underbalanced drilling operations. There are several different methods of remediating these type of trouble zones, such as managed pressure drilling techniques, solid expandable liners (either tied-back or not) through the use of conventional liners, or by drilling with casing or liners. Each method has its own limitations. However, drilling with casing technology has been used for both drilling through problem formations and ensuring the casing or liner can be set on bottom through unstable hole conditions. 
   Drilling with casing (or liners) are useful tools for drilling in difficult drilling conditions. Drilling with casing can be a relatively simple operation if the operator knows of a problem zone. For instance, a conventional assembly can be used to drill the wellbore  10  to a point just above a trouble zone  170 . Thereafter, the conventional assembly may be removed and a casing string  175  with a drill bit  180  attached is introduced into the wellbore  10 . Similar to the procedure previously discussed, the casing string  175  and the drill bit  180  are lowered into the wellbore  10  on the drill string  105  to a point proximate the downhole deployment valve  50 . Thereafter, the downhole deployment valve  50  is closed. Next, the wellbore pressure in the first region above the valve  50  is reduced to substantially zero by manipulating the rotating control head  75  and the choke manifold system. When the wellbore pressure in the first region  85  is reduced to substantially zero, the balance of the drill string  105  is tripped out of the wellbore  10  in a similar manner as the procedure for tripping pipe in a dead well. During the trip into the wellbore  10 , the drill string  105  is rerun to a depth directly above the downhole deployment valve  50 , where a pipe-heavy condition exists. Subsequently, pressure is applied to the wellbore  10  to equalize the pressure in the first region and the second region below the valve  50 . When the pressures in the regions are substantially equal, hydraulic pressure from the surface fluid reservoir is applied through the control line to open the downhole deployment valve  50 , thereby opening the pathway into the region of the wellbore  10  below the valve  50 . Then the casing string  175  and the drill bit  180  are lowered into the wellbore  10  past the expandable portions  125 ,  130  to form another portion of the wellbore  10  and isolate the trouble zone  170 . 
   Generally, drilling with casing entails running the casing string  175  into the wellbore  10  with the drill bit  180  attached. The drill bit  180  is operated by rotation of the casing string  175  from the surface of the wellbore  10 . Once the wellbore  10  is formed, the attached casing string  175  is cemented in the wellbore  10 . Thereafter, a drilling assembly (not shown) may be employed to drill through the drill bit  180  at the end of the casing string  175  and subsequently form another portion of the wellbore  10 . 
   In drilling the wellbore  10 , the drilling assembly  100  with a directional drilling member (not shown) is tripped into the wellbore  10  through the valve  50  (and hole angle is built to horizontal). The reservoir is drilled underbalanced to a total depth. Pressure while drilling and gamma ray sensors in the guidance system, in addition to the normal directional tool face, inclination and azimuth readings, aid in maintaining proper underbalance margin and geologic settings. Multiphase flow modeling prior to and during the drilling operation insures desired equivalent circulating density (ECD) and sufficient circulation rates required for cuttings removal and good hole cleaning during Under Balanced Drilling operations. Additionally, fluid density may be adjusted, as can the injection rates of nitrogen and liquid to achieve the desired mixture density. 
     FIG. 7  illustrates the wellbore  10  with an expandable filter member  185  or a screen. For purposes of sand control, the expandable filter member  185  commonly referred to as an Expandable Sand Screen (ESS®) is useful in controlling sand and enhancing the productivity of both vertical and horizontal wells. In a similar manner as previously discussed, the expandable filter member  185  is lowered into the wellbore  10  on the drill string  105  to a point proximate the downhole deployment valve  50 . Thereafter, the downhole deployment valve  50  is closed. Next, the wellbore pressure in the first region above the valve  50  is reduced to substantially zero by manipulating the rotating control head  75  and the choke manifold system. When the wellbore pressure in the first region  85  is reduced to substantially zero, the balance of the drill string  105  is tripped out of the wellbore  10  in a similar manner as the procedure for tripping pipe in a dead well. During the trip into the wellbore  10 , the drill string  105  is rerun to a depth directly above the downhole deployment valve  50 , where a pipe-heavy condition exists. Subsequently, pressure is applied to the wellbore  10  to equalize the pressure in the first region and the second region below the valve  50 . When the pressures in the regions are substantially equal, hydraulic pressure from the surface fluid reservoir is applied through the control line to open the downhole deployment valve  50 , thereby opening the pathway into the region of the wellbore  10  below the valve  50 . Then the expandable filter member  185  is lowered into the wellbore  10  past the expandable portions  125 ,  130  and the casing string  175  to a previously formed section of the wellbore  10  in a completion operation. The ability of performing a drilling operation and completion operation in an underbalanced environment will cause less damage to the reservoir formations. 
   Generally, the expandable filter member  185  comprises an overlapping mesh screen, sized for the particular sieve analysis solution and sandwiched between two slotted metal tubulars, an inner base pipe and an outer shroud that covers and protects the screen. As expandable filter member  185  is expanded, the pre-cut slots in both the base and shroud pipes expand and the screen material slides over itself to provide an uninterrupted screen surface on the wellbore  10 . The expandable filter member  185  maybe expanded by a rigid cone expander, a variable compliant expansion, or any other type expansion device. 
   In the past the greatest challenge of completing an underbalanced well using the expandable filter member  185  is deploying the porous unexpanded sand screen into a live, pressured wellbore  10 . Conventional snubbing options available to solid pipe will not work with the expandable filter member  185 . Killing the well to deploy the completion hardware likewise does not work because that defeats the objective of the underbalanced completion. The underbalanced drilling was possible, using snubbing equipment to trip under pressure to avoid pipe light conditions, but running sand screens was the challenge. However, the development of the valve  50  made the use of the expandable filter member  185  as an underbalanced completion system possible. As previously discussed, the valve  50  is used to drill the well underbalanced and to deploy the expandable filter member  185 . Typically, the expandable filter member  185  employs a modified Axial Compliant Expansion (ACE) tool for underbalanced compliant expansion. The modified Cardium liner hanger or an expandable liner hanger is used to hang the expandable filter member  185  before expansion begins. Membrane nitrogen or another gas is used to set the hanger and then to expand the screen using the pressure translation sub between the gas and the ACE tool. 
     FIGS. 8A-8D  illustrate the different forms of the expandable portion. For instance,  FIG. 8A  illustrates an expandable portion  205  disposed at an end of a casing string  200 . As shown, the expandable portion  205  has an inner diameter (D 1 ) smaller than an inner diameter (D 0 ) of the casing string  200 .  FIG. 8B  illustrates an expandable portion  210  disposed in a shoe portion of the casing string  200 . As shown, the expandable portion  210  has an inner diameter (D 1 ) substantially equal to an inner diameter (D 0 ) of the casing string  200 , thereby resulting in a monobore configuration.  FIG. 8C  illustrates an expandable portion  220  disposed in a shoe portion of the casing string  215  which is mounted in a shoe portion of the casing string  200 . As shown, the expandable portion  220  has an inner diameter (D 2 ) substantially equal to an inner diameter (D 1 ) of the casing string  215  and an inner diameter (D 0 ) of the casing string  200 , thereby resulting in a sequential monobore configuration. 
     FIG. 8D  illustrates an expandable portion  225  disposed below an end of the casing string  200 . As shown, the expandable portion  225  has an inner diameter (D 1 ) smaller than an inner diameter (D 0 ) of the casing string  200 . Similar to expandable portions  125 ,  130  as shown in  FIGS. 1-7 , one advantage of this embodiment is that only the trouble zone is being remediated rather than forcing the expandable casing to be installed from the trouble zone all the way back to the previous string of casing. Therefore, the expandable portion  225  requires a much shorter liner to be installed, creating a more cost effective expandable system to cure the trouble zone. 
   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.

Summary:
The present invention generally relates to methods and systems for mitigating trouble zones in a wellbore in a preferred pressure condition and completing the wellbore in the preferred pressure condition. In one aspect, a method of reinforcing a wellbore is provided. The method includes locating a valve member within the wellbore for opening and closing the wellbore. The method further includes establishing a preferred pressure condition within the wellbore and closing the valve member. The method also includes locating a tubular string having an expandable portion in the wellbore and opening the valve member. Additionally, the method includes moving the expandable portion through the opened valve member and expanding the expandable portion in the wellbore at a location below the valve member. In another aspect, a method of forming a wellbore is provided. In yet another aspect, a system for drilling a wellbore is provided.