Abstract:
The present invention generally relates to methods for drilling a subsea wellbore and landing a casing mandrel in a subsea wellhead. In one aspect, a method of drilling a subsea wellbore with casing is provided. The method includes placing a string of casing with a drill bit at the lower end thereof in a riser system and urging the string of casing axially downward. The method further includes reducing the axial length of the string of casing to land a wellbore component in a subsea wellhead. In this manner, the wellbore is formed and lined with the string of casing in a single run. In another aspect, a method of forming and lining a subsea wellbore is provided. In yet another aspect, a method of landing a casing mandrel in a casing hanger disposed in a subsea wellhead is provided.

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS  
       [0001]     This application is a continuation of co-pending U.S. patent application Ser. No. 10/319,792, filed Dec. 13, 2002. The aforementioned related patent application is herein incorporated by reference. 
     
    
     BACKGROUND OF THE INVENTION  
       [0002]     1. Field of the Invention  
         [0003]     The present invention relates to wellbore completion. More particularly, the invention relates to methods for drilling with casing and landing a casing mandrel in a subsea wellhead.  
         [0004]     2. Description of the Related Art  
         [0005]     In a conventional completion operation, a wellbore is formed in several phases. In a first phase, the wellbore is formed using a drill bit that is urged downwardly at a lower end of a drill string while simultaneously circulating drilling mud into the wellbore. The drilling mud is circulated downhole to carry rock chips to the surface and to cool and clean the bit. After drilling a predetermined depth, the drill string and bit are removed.  
         [0006]     In a next phase, the wellbore is lined with a string of steel pipe called casing. The casing is inserted into the newly formed wellbore to provide support to the wellbore and facilitate the isolation of certain areas of the wellbore adjacent to hydrocarbon bearing formations. Generally, a casing shoe is attached to the bottom of the casing string to facilitate the passage of cement that will fill an annular area defined between the casing and the wellbore.  
         [0007]     A recent trend in well completion has been the advent of one-pass drilling, otherwise known as “drilling with casing”. It has been discovered that drilling with casing is a time effective method of forming a wellbore where a drill bit is attached to the same string of tubulars that will line the wellbore. In other words, rather than run a drill bit on smaller diameter drill string, the bit or drillshoe is run at the end of larger diameter tubing or casing that will remain in the wellbore and be cemented therein. The advantages of drilling with casing are obvious. Because the same string of tubulars transports the bit as it lines the wellbore, no separate trip into the wellbore is necessary between the forming of the wellbore and the lining of the wellbore.  
         [0008]     Drilling with casing is especially useful in certain situations where an operator wants to drill and line a wellbore as quickly as possible to minimize the time the wellbore remains unlined and subject to collapse or the effects of pressure anomalies. For example, when forming a subsea wellbore, the initial length of wellbore extending downwards from the ocean floor is subject to cave in or collapse due to soft formations at the ocean floor. Additionally, sections of a wellbore that intersect areas of high pressure can lead to damage of the wellbore between the time the wellbore is formed and when it is lined. An area of exceptionally low pressure will drain expensive drilling fluid from the wellbore between the time it is intersected and when the wellbore is lined. In each of these instances, the problems can be eliminated or their effects reduced by drilling with casing.  
         [0009]     While one-pass drilling offers obvious advantages over a conventional completion operation, there are some additional problems using the technology to form a subsea well because of the sealing requirements necessary in a high-pressure environment at the ocean floor. Generally, the subsea wellhead comprises a casing hanger with a locking mechanism and a landing shoulder while the string of casing includes a sealing assembly and a casing mandrel for landing in the wellhead. Typically, the subsea wellbore is drilled to a depth greater than the length of the casing, thereby allowing the casing string and the casing mandrel to easily seat in the wellhead as the string of casing is inserted into the subsea wellbore. However, in a one-pass completion operation, the casing is rotated as the wellbore is formed and landing the casing mandrel in the wellhead would necessarily involve rotating the sealing surfaces of the casing mandrel and the sealing surfaces of the wellhead. Additionally, in one-pass completion an obstruction may be encountered while drilling with casing, whereby the casing hanger may not be able to move axially downward far enough to land in the subsea wellhead, resulting in the inability to seal the subsea wellhead.  
         [0010]     A need therefore exists for a method of drilling with casing that facilitates the landing of a casing hanger in a subsea wellhead. There is a further need for a method that prevents damage to the seal assembly as the casing mandrel seats in the casing hanger. There is yet a further need for a method for landing a casing hanger in a subsea wellhead after an obstruction is encountered during the drilling operation.  
       SUMMARY OF THE INVENTION  
       [0011]     The present invention generally relates to methods for drilling a subsea wellbore and landing a casing mandrel in a subsea wellhead. In one aspect, a method of drilling a subsea wellbore with casing is provided. The method includes placing a string of casing with a drill bit at the lower end thereof in a riser system and urging the string of casing axially downward. The method further includes reducing the axial length of the string of casing to land a wellbore component in a subsea wellhead. In this manner, the wellbore is formed and lined with the string of casing in a single run.  
         [0012]     In another aspect, a method of forming and lining a subsea wellbore is provided. The method includes disposing a run-in string with a casing string at the lower end thereof in a riser system, the casing string having a casing mandrel disposed at an upper end thereof and a drill bit disposed at a lower end thereof. The method further includes rotating the casing string while urging the casing string axially downward to a predetermined depth, whereby the casing mandrel is at a predetermined height above a casing hanger. Additionally, the method includes reducing the length of the casing string thereby seating the casing mandrel in the casing hanger.  
         [0013]     In yet another aspect, a method of landing a casing mandrel in a casing hanger disposed in a subsea wellhead is provided. The method includes placing a casing string with the casing mandrel disposed at the upper end thereof into a riser system and drilling the casing string into the subsea welihead to form a wellbore. The method further includes positioning the casing mandrel at a predetermined height above the casing hanger and reducing the axial length of the casing string to seat the casing mandrel in the casing hanger. 
     
    
     BRIEF DESCRIPTION OF THE DRAWINGS  
       [0014]     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.  
         [0015]      FIG. 1  is a partial section view and illustrates the formation of a subsea wellbore with a casing string having a drill bit disposed at a lower end thereof.  
         [0016]      FIG. 2  is a cross-sectional view illustrating the string of casing prior to setting a casing mandrel into a casing hanger of the subsea wellhead.  
         [0017]      FIG. 3  is an enlarged cross-sectional view illustrating a collapsible apparatus of the casing string in a first position.  
         [0018]      FIG. 4  is a cross-sectional view illustrating the casing assembly after the casing mandrel is seated in the casing hanger.  
         [0019]      FIG. 5A  is an enlarged cross-sectional view illustrating the collapsible apparatus in a second position after the casing mandrel is set into the casing hanger.  
         [0020]      FIG. 5B  is a cross-sectional view taken along line  5 B-- 5 B of  FIG. 5A  illustrating a torque key engaged between the string of casing and a tubular member in the collapsible apparatus.  
         [0021]      FIG. 6A  is a cross-sectional view of an alternative embodiment illustrating pre-milled windows in the casing assembly.  
         [0022]      FIG. 6B  is a cross-sectional view illustrating the casing assembly after alignment of the pre-milled windows.  
         [0023]      FIG. 6C  is a cross-sectional view illustrating a diverter disposed adjacent the pre-milled windows.  
         [0024]      FIG. 6D  is a cross-sectional view illustrating a drilling assembly diverted through the pre-milled windows.  
         [0025]      FIG. 7A  is a cross-sectional view of an alternative embodiment illustrating a hollow diverter in the casing assembly.  
         [0026]      FIG. 7B  is a cross-sectional view illustrating a lateral bore drilling operation.  
         [0027]      FIGS. 8A  is a cross-sectional view illustrating the casing assembly with a casing drilling shoe.  
         [0028]      FIG. 8B  is a cross-sectional view illustrating the casing assembly with a casing drilling shoe. 
     
    
     DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT  
       [0029]     The present invention generally relates to drilling a subsea wellbore using a casing string.  FIG. 1  illustrates a drilling operation of a subsea wellbore with a casing assembly  170  in accordance with the present invention. Typically, most offshore drilling in deep water is conducted from a floating vessel  105  that supports the drill rig and derrick and associated drilling equipment. A riser pipe  110  is normally used to interconnect the floating vessel  105  and a subsea wellhead  115 . A run-in string  120  extends from the floating vessel  105  through the riser pipe  110 . The riser pipe  110  serves to guide the run-in string  120  into the subsea wellhead  115  and to conduct returning drilling fluid back to the floating vessel  105  during the drilling operation through an annulus  125  created between the riser pipe  110  and run-in string  120 . The riser pipe  110  is illustrated larger than a standard riser pipe for clarity.  
         [0030]     A running tool  130  is disposed at the lower end of the run-in string  120 . Generally, the running tool  130  is used in the placement or setting of downhole equipment and may be retrieved after the operation or setting process. The running tool  130  in this invention is used to connect the run-in string  120  to the casing assembly  170  and subsequently release the casing assembly  170  after the wellbore  100  is formed.  
         [0031]     The casing assembly  170  is constructed of a casing mandrel  135 , a string of casing  150  and a collapsible apparatus  160 . The casing mandrel  135  is disposed at the upper end of the string of casing  150 . The casing mandrel  135  is constructed and arranged to seal and secure the string of casing  150  in the subsea wellhead  115 . As shown on  FIG. 1 , a collapsible apparatus  160  is disposed at the bottom of the string of casing  150 . However, it should be noted that the collapsible apparatus  160  is not limited to the location illustrated on  FIG. 1 , but may be located at any point on the string of casing  150 .  
         [0032]     A drill bit  140  is disposed at the lowest point on the casing assembly  170  to form the wellbore  100 . In the embodiment shown, the drill bit  140  is rotated with the casing assembly  170 . Alternatively, mud motor (not shown) may be used near the end of the string of casing  150  to rotate the bit  140 . In another embodiment, a casing drilling shoe  370  may be employed at the lower end of the casing assembly  170 , as illustrated in  FIGS. 8A and 8B . An example of a casing drilling shoe is disclosed in Wardley, U.S. Pat. No. 6,443,247 which is incorporated herein in its entirety. Generally, the casing drilling shoe disclosed in &#39;247 includes an outer drilling section constructed of a relatively hard material such as steel, and an inner section constructed of a readily drillable material such as aluminum. The drilling shoe further includes a device for controllably displacing the outer drilling section to enable the shoe to be drilled through using a standard drill bit and subsequently penetrated by a reduced diameter casing string or liner.  
         [0033]     As illustrated by the embodiment shown in  FIG. 1 , the wellbore  100  is formed as the casing assembly  170  is rotated and urged downward. Typically, drilling fluid is pumped through the run-in string  120  and the string of casing  150  to the drill bit  140 . A motor (not shown) rotates the run-in string  120  and the run-in string  120  transmits rotational torque to the casing assembly  170  and the drill bit  140 . At the same time, the run-in string  120 , the running tool  130 , the casing assembly  170  and drill bit  140  are urged downward. In this respect, the run-in string  120 , the running tool  130  and the casing assembly  170  act as one rotationally locked unit to form a predetermined length of wellbore  100  as shown on  FIG. 2 .  
         [0034]      FIG. 2  is a cross-sectional view illustrating the casing assembly  170  prior to setting the casing mandrel  135  into a casing hanger  205 . Generally, the wellbore  100  is formed to a predetermined depth and thereafter the rotation of the casing assembly  170  is stopped. Typically, the predetermined depth is a point where a lower surface  215  on the casing mandrel  135  is a predetermined height above an upper portion of the casing hanger  205  in the subsea wellhead  115  as shown in  FIG. 2 .  
         [0035]     The casing mandrel  135  is typically constructed and arranged from steel that has a smooth metallic face. However, other types of materials may be employed, so long as the material will permit an effective seal between the casing mandrel  135  and the casing hanger  205 . The casing mandrel  135  may further include one or more seals  220  disposed around an outer portion of the casing mandrel  135 . The one or more seals  220  are later used to create a seal between the casing mandrel  135  and the casing hanger  205 .  
         [0036]     As shown in  FIG. 2 , the casing hanger  205  is disposed in the subsea surface. Typically, the casing hanger  205  is located and cemented in the subsea surface prior to drilling the wellbore  100 . The casing hanger  205  is typically constructed from steel. However, other types of materials may be employed so long as the material will permit an effective seal between the casing mandrel  135  and the casing hanger  205 . The casing hanger  205  includes a landing shoulder  210  formed at the lower end of the casing hanger  205  to mate with the lower surface  215  formed on the lower end of the casing mandrel  135 .  
         [0037]      FIG. 3  is an enlarged cross-sectional view illustrating the collapsible apparatus  160  in a first position. Generally, the collapsible apparatus  160  moves between the first position and a second position allowing the overall length of the casing assembly  170  to be reduced. As the casing assembly  170  length is reduced, the casing mandrel  135  may seat in the casing hanger  205  sealing the subsea wellhead  115  without damaging the one or more seals  220 . In another aspect, reducing the axial length of the casing assembly  170  also provides a means for landing the casing mandrel  135  in the casing hanger  205  after an obstruction is encountered during the drilling operation, whereby the casing assembly  170  can no longer urged axially downward to seal off the subsea wellhead  115 .  
         [0038]     As illustrated, the collapsible apparatus  160  includes one or more seals  305  to create a seal between the string of casing  150  and a tubular member  315 . The tubular member  315  is constructed of a predetermined length to allow the casing mandrel  135  to seat properly in the casing hanger  205 .  
         [0039]     The tubular member  315  is secured axially to the string of casing  150  by a locking mechanism  310 . The locking mechanism  310  is illustrated as a shear pin. However, other forms of locking mechanisms may be employed, so long as the locking mechanism will fail at a predetermined force. Generally, the locking mechanism  310  is short piece of metal that is used to retain tubular member  315  and the string of casing  150  in a fixed position until sufficient axial force is applied to cause the locking mechanism to fail. Once the locking mechanism  310  fails, the string of casing  150  may then move axially downward to reduce the length of the casing assembly  170 . Typically, a mechanical or hydraulic axial force is applied to the casing assembly  170 , thereby causing the locking mechanism  310  to fail. Alternatively, a wireline apparatus (not shown) may be run through the casing assembly  170  and employed to provide the axial force required to cause the locking mechanism  310  to fail. In an alternative embodiment, the locking mechanism  310  is constructed and arranged to deactivate upon receipt of a signal  380  from the surface, as illustrated in  FIG. 4 . The signal  380  may be axial, torsional or combinations thereof and the signal  380  may be transmitted through wire casing, wireline, hydraulics or any other means well known in the art.  
         [0040]     In addition to securing the tubular member  315  axially to the string of casing  150 , the locking mechanism  310  also provides a means for a mechanical torque connection. In other words, as the string of casing  150  is rotated the torsional force is transmitted to the collapsible apparatus  160  through the locking mechanism  310 . Alternatively, a spline assembly may be employed to transmit the torsional force between the string of casing  150  and the collapsible apparatus  160 . Generally, a spline assembly is a mechanical torque connection between a first and second member. Typically, the first member includes a plurality of keys and the second member includes a plurality of keyways. When rotational torque is applied to the first member, the keys act on the keyways to transmit the torque to the second member. Additionally, the spline assembly may be disengaged by axial movement of one member relative to the other member, thereby permitting rotational freedom of each member.  
         [0041]      FIG. 4  is a cross-sectional view illustrating the casing assembly  170  after the casing mandrel  135  is seated in the casing hanger  205 . A mechanical or hydraulic axial force was applied to the casing assembly  170  causing the locking mechanism  310  to fail and allow the string of casing  150  to move axially downward and slide over the tubular member  315 . It is to be understood, however, that the casing apparatus  160  may be constructed and arranged to permit the string of casing  150  to slide inside the tubular member  315  to obtain the same desired result.  
         [0042]     As illustrated on  FIG. 4 , the lower surface  215  has contacted the landing shoulder  210 , thereby seating the casing mandrel  135  in the casing hanger  205 . As further illustrated, the one or more seals  220  on the casing mandrel  135  are in contact with the casing hanger  205 , thereby creating a fluid tight seal between the casing mandrel  135  in the casing hanger  205  during the drilling and cementing operations. In this manner, the length of the casing assembly  170  is reduced allowing the casing mandrel  135  to seat in the casing hanger  205 .  
         [0043]      FIG. 5A  is an enlarged cross-sectional view illustrating the collapsible apparatus  160  in the second position after the casing mandrel  135  is seated in the casing hanger  205 . As illustrated, the locking mechanism  310  has released the connection point between the string of casing  150  and the tubular member  315 , thereby allowing the string of casing  150  to slide axially downward toward the bit  140 . The axial downward movement of the string of casing  150  permits an inwardly biased torque key  330  to engage a groove  320  at the lower end of the tubular member  315 . The torque key  330  creates a mechanical torque connection between the string of casing  150  and the collapsible apparatus  160  when the collapsible apparatus  160  is in the second position. Alternatively, a mechanical spline assembly may be used to create a torque connection between the string of casing  150  and the collapsible apparatus  160 .  
         [0044]     In another aspect, the axial movement of the collapsible apparatus  160  from the first position to the second position may be used to activate other downhole components. For example, the axial movement of the collapsible apparatus  160  may displace an outer drilling section of a drilling shoe (not shown) to allow the drilling shoe to be drilled therethrough, as discussed in a previous paragraph relating to Wardley, U.S. Pat. No. 6,443,247. In another example, the axial movement of the collapsible apparatus  160  may urge a sleeve in a float apparatus (not shown) from a first position to a second position to activate the float apparatus.  
         [0045]      FIG. 5B  is a cross-sectional view taken along line  5 B- 5 B of  FIG. 5A  illustrating the torque key  330  engaged between the string of casing  150  and the tubular member  315 . As shown, the torque key  330  has moved radially inward, thereby establishing a mechanical connection between the string of casing  150  and the tubular member  315 .  
         [0046]     In an alternative embodiment, the casing assembly  170  may be drilled down until the lower surface  215  of the casing mandrel  135  is right above the upper portion of the casing hanger  205 . Thereafter, the rotation of the casing assembly  170  is stopped. Next, the run-in string  120  is allowed to slack off causing all or part of the string of casing  150  to be in compression, which reduces the length of the string of casing  150 . Subsequently, the reduction of length in the string of casing  150  allows the casing mandrel  135  to seat into the casing hanger  205 .  
         [0047]     In a further alternative embodiment, a centralizer  385 , as illustrated in  FIG. 4 , may be disposed on the string of casing  150  to position the string of casing  150  concentrically in the wellbore  100 . Generally, a centralizer is usually used during cementing operations to provide a constant annular space around the string of casing  150 , rather than having the string of casing  150  laying eccentrically against the wellbore  100  wall. For straight holes, bow spring centralizers are sufficient and commonly employed. For deviated wellbores, where gravitational force pulls the string of casing  150  to the low side of the hole, more robust solid-bladed centralizers are employed.  
         [0048]      FIG. 6A  is a cross-sectional view of an alternative embodiment illustrating pre-milled windows  325 ,  335  in the casing assembly  170 . In the embodiment shown, the pre-milled window  325  is formed in a lower portion of the string of casing  150 . Pre-milled window  325  is constructed and arranged to align with pre-milled window  335  formed in the tubular member  315  after the collapsible apparatus  160  has moved to the second position. Additionally, a plurality of seals  340  are disposed around the string of casing  150  to create a fluid tight seal between the string of casing  150  and the tubular member  315 .  
         [0049]      FIG. 6B  is a cross-sectional view illustrating the casing assembly  170  after alignment of the pre-milled windows  325 ,  335 . As shown, the locking mechanism  310  has failed in a manner discussed in a previous paragraph, and the collapsible apparatus  160  has moved to the second position permitting the axial alignment of the pre-milled windows  325 ,  335 . Additionally, the inwardly biased torque key  330  has engaged the groove  320  formed at the lower end of the tubular member  315 , thereby rotationally aligning the pre-milled windows  325 ,  335 . In this manner, the pre-milled windows  325 ,  335  are aligned both axially and rotationally to provide an access window between the inner portion of the casing assembly  170  and the surrounding wellbore  100 .  
         [0050]      FIG. 6C  is a cross-sectional view illustrating a diverter  345  disposed adjacent the pre-milled windows  325 ,  335 . The diverter  345  is typically disposed and secured in the string of casing  150  by a wireline assembly (not shown) or other means well known in the art. Generally, the diverter  345  is an inclined wedge placed in a wellbore  100  to force a drilling assembly (not shown) to start drilling in a direction away from the wellbore  100  axis. The diverter  345  must have hard steel surfaces so that the drilling assembly will preferentially drill through rock rather than the diverter  345  itself. In the embodiment shown, the diverter  345  is oriented to direct the drilling assembly outward through the pre-milled windows  325 ,  335 .  
         [0051]      FIG. 6D  is a cross-sectional view illustrating a drilling assembly  350  diverted through the pre-milled windows  325 ,  335 . As shown, the diverter  345  has directed the drilling assembly  350  through the pre-milled windows  325 ,  335  to form a lateral wellbore.  
         [0052]      FIG. 7A  is a cross-sectional view of an alternative embodiment illustrating a hollow diverter  355  in the casing assembly  150 . Prior to forming the wellbore  100  with the string of casing  150 , the hollow diverter  355  is disposed in the string of casing  150  at a predetermined location. The hollow diverter  355  may be oriented in a particular direction if needed, or placed into the string of casing  150  blind, with no regard to the direction. In either case, the hollow diverter  355  functions in a similar manner as discussed in the previous paragraph. However, a unique aspect of the hollow diverter  355  is that it is constructed and arranged with a fluid bypass  360 . The fluid bypass  360  permits drilling fluid that is pumped from the surface of the wellbore  100  to be communicated to the drill bit  140  during the drilling by casing operation. In other words, the installation of the hollow diverter  355  in the string of casing  150  prior to drilling the wellbore  100  will not block fluid communication between the surface of the wellbore  100  and the drill bit  140  during the drilling operation.  
         [0053]      FIG. 7B  is a cross-sectional view illustrating a lateral bore drilling operation using the hollow diverter  355 . As shown, the hollow diverter  355  has directed the drilling assembly  350  away from the wellbore  100  axis to form a lateral wellbore.  
         [0054]     In operation, a casing assembly is attached to the end of a run-in string by a running tool and thereafter lowered through a riser system that interconnects a floating vessel and a subsea wellhead. The casing assembly is constructed from a casing mandrel, a string of casing and a collapsible apparatus. After the casing assembly enters the subsea wellhead, the casing assembly is rotated and urged axially downward to form a subsea wellbore.  
         [0055]     Typically, a motor rotates the run-in string and subsequently the run-in string transmits the rotational torque to the casing assembly and a drill disposed at a lower end thereof. At the same time, the run-in string, the running tool, the casing assembly and drill bit are urged axially downward until a lower surface on the casing mandrel of the casing assembly is positioned at a predetermined height above an upper portion of the casing hanger. At this time, the rotation of the casing assembly is stopped. Thereafter, a mechanical or hydraulic axial force is applied to the casing assembly causing a locking mechanism in the collapsible apparatus to fail and allows the string of casing to move axially downward to reduce the overall length of the casing assembly permitting the casing mandrel to seat in the casing hanger. Additionally, the axial downward movement of the string of casing permits an inwardly biased torque key to engage a groove at the lower end of the tubular member to create a mechanical torque connection between the string of casing and the collapsible apparatus. Thereafter, the string of casing is cemented into the wellbore and the entire run-in string is removed from the wellbore.  
         [0056]     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.