Patent Publication Number: US-11041352-B2

Title: Advancement of a tubular string into a wellbore

Description:
CROSS-REFERENCE TO RELATED APPLICATION 
     This application claims the benefit of the filing date of U.S. provisional application No. 62/164,786 filed on 21 May 2015. The entire disclosure of this prior application is incorporated herein by this reference. 
    
    
     BACKGROUND 
     This disclosure relates generally to equipment utilized and operations performed in conjunction with a subterranean well and, in an example described below, more particularly provides for advancement of a tubular string into a wellbore. 
     It can sometimes be difficult to convey a tubular string with a bottom hole assembly into a wellbore. For example, if a wellbore section is horizontal or substantially inclined, friction between the tubular string and the wellbore section can prevent further displacement of the tubular string into the wellbore, even if a weight of the tubular string in a vertical section of the wellbore acts to bias the tubular string into the wellbore. Therefore, it will be appreciated that advancements are continually needed in the art of conveying tubular strings and bottom hole assemblies into wellbores. Such advancements may be useful, regardless of whether the tubular strings and bottom hole assemblies are positioned in horizontal wellbore sections. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         FIG. 1  is a representative partially cross-sectional view of an example of a well system and associated method which can embody principles of this disclosure. 
         FIG. 2  is an enlarged scale representative partially cross-sectional view of an example of a bottom hole assembly being conveyed into a wellbore utilizing the principles of this disclosure. 
         FIG. 3  is a representative partially cross-sectional view of another example of the bottom hole assembly, in which the bottom hole assembly includes a perforator. 
         FIG. 4  is a representative partially cross-sectional view of another example of the bottom hole assembly, in which the bottom hole assembly includes a cutting device. 
         FIGS. 5A-F  are further enlarged scale representative cross-sectional views of successive axial sections of another example of a bottom hole assembly that can incorporate the principles of this disclosure. 
         FIGS. 6A  &amp; B are representative cross-sectional views of successive axial sections of the bottom hole assembly, depicting release of an annular restrictor from the bottom hole assembly. 
         FIGS. 7A  &amp; B are representative cross-sectional views of successive axial sections of the bottom hole assembly, depicting activation of an abrasive perforator of the bottom hole assembly. 
         FIGS. 8A  &amp; B are representative cross-sectional views of successive axial sections of the bottom hole assembly, depicting activation of a back pressure valve of the bottom hole assembly. 
     
    
    
     DETAILED DESCRIPTION 
     Representatively illustrated in  FIG. 1  is a system  10  for use with a well, and an associated method, which system and method can embody principles of this disclosure. However, it should be clearly understood that the system  10  and method are merely one example of an application of the principles of this disclosure in practice, and a wide variety of other examples are possible. Therefore, the scope of this disclosure is not limited at all to the details of the system  10  and method described herein and/or depicted in the drawings. 
     In the  FIG. 1  example, a tubular string  12  is conveyed into a wellbore  14  lined with casing  16  and cement  18 . Although multiple casing strings would typically be used in actual practice, for clarity of illustration only one casing string  16  is depicted in the drawings. 
     Although the wellbore  14  is illustrated as being vertical, sections of the wellbore could instead be horizontal or otherwise inclined relative to vertical. Although the wellbore  14  is completely cased and cemented as depicted in  FIG. 1 , any sections of the wellbore in which operations described in more detail below are performed could be uncased or open hole. Thus, the scope of this disclosure is not limited to any particular details of the system  10  and method. 
     The tubular string  12  of  FIG. 1  comprises coiled tubing  20  and a bottom hole assembly  22 . As used herein, the term “coiled tubing” refers to a substantially continuous tubing that is stored on a spool or reel  24 . The reel  24  could be mounted, for example, on a skid, a trailer, a floating vessel, a vehicle, etc., for transport to a wellsite. Although not shown in  FIG. 1 , a control room or cab would typically be provided with instrumentation, computers, controllers, recorders, etc., for controlling equipment such as an injector  26  and a blowout preventer stack  28 . 
     As used herein, the term “bottom hole assembly” refers to an assembly connected at or near a distal end of a tubular string in a well. It is not necessary for a bottom hole assembly to be positioned or used at a “bottom” of a hole or well. 
     When the tubular string  12  is positioned in the wellbore  14 , an annulus  30  is formed radially between them. Fluid, slurries, etc., can be flowed from surface into the annulus  30  via, for example, a casing valve  32 . One or more pumps  34  may be used for this purpose. Fluid can also be flowed to surface from the wellbore  14  via the annulus  30  and valve  32 . 
     Fluid, slurries, etc., can also be flowed from surface into the wellbore  14  via the tubing  20 , for example, using one or more pumps  36 . Fluid can also be flowed to surface from the wellbore  14  via the tubing  20 . 
     Referring additionally now to  FIG. 2 , an enlarged scale cross-sectional view of one example of the bottom hole assembly  22  is representatively illustrated in a generally horizontal section of the wellbore  14 . The bottom hole assembly  22  example of  FIG. 2  may be used with the system  10  and method of  FIG. 1 , or it may be used with other systems and methods. 
     In the  FIG. 2  example, the bottom hole assembly  22  includes an annular restrictor  40 . The annular restrictor  40  is connected at a distal end of the bottom hole assembly  22  in the  FIG. 2  example, but in other examples the annular restrictor could be otherwise positioned or separate from the bottom hole assembly (such as, connected in the tubular string  12  above the bottom hole assembly). 
     The annular restrictor  40  restricts flow of fluid  42  through the annulus  30 . The fluid  42  may be pumped through the annulus  30  from the earth&#39;s surface, for example, using the pump  34  of  FIG. 1 . However, other means of pressurizing or displacing the fluid  42  through the annulus  30  may be used, if desired. 
     The annular restrictor  40  in the  FIG. 2  example does not completely prevent flow through the annulus  30  at the annular restrictor (that is, the annular restrictor does not completely seal off the annulus between the tubular string  12  and an inner surface of the casing  16 ). Instead, there is some leakage of the fluid  42  past the annular restrictor  40 . However, in other examples, the annular restrictor  40  could completely seal off the annulus  30 , if desired. 
     Although the annular restrictor  40  does not completely seal off the annulus  30  in the  FIG. 2  example, it does restrict flow of the fluid  42  through the annulus sufficiently to create a pressure differential across the annular restrictor. In this manner, the annular restrictor  40  is similar to a piston, and the differential pressure across the annular restrictor results in a biasing force being applied to the bottom hole assembly  22 . This biasing force acts to displace the bottom hole assembly  22  further into the wellbore  14 . 
     In order for the differential pressure to be created across the annular restrictor  40 , fluid  44  in the casing  16  below the annular restrictor should be able to displace (e.g., so that the fluid is not significantly compressed in the casing below the annular restrictor, as the annular restrictor advances through the casing). In some examples, the casing  16  may be perforated below the bottom hole assembly  22 , thereby allowing the fluid  44  to exit the casing via perforations. 
     However, in the  FIG. 2  example, a plug  46  seals off the casing  16  so that, even if the casing is perforated below the plug, the fluid  44  cannot displace out of the casing via the perforations. Instead, the fluid  44  is allowed to flow into and through the bottom hole assembly  22  and coiled tubing  20  of the tubular string  12 . The fluid  44  may flow to the surface via the tubular string  12 . 
     Note that the fluid  44  can comprise the fluid  42  and any fluid in the wellbore  14  displaced by the bottom hole assembly  22  as it advances into the wellbore. If the annular restrictor  40  completely seals off the annulus  30 , then the fluid  44  may not include any of the fluid  42 , but may only include the fluid in the wellbore  14  displaced by the bottom hole assembly  22  as it advances into the wellbore. 
     In the  FIG. 2  example, the bottom hole assembly  22  also includes a vibratory tool  48  that generates vibrations in response to flow of the fluid  44  through the tool. These vibrations can assist in displacing the bottom hole assembly  22  through the wellbore  14 , especially if the bottom hole assembly is positioned in a horizontal or substantially inclined wellbore section. However, it is not necessary for the bottom hole assembly  22  to include the vibratory tool  48 , or for the bottom hole assembly to include any particular tool(s) or combination of tools. 
     At an appropriate time, the annular restrictor  40  can be released from the tubular string  12 , if desired. For example, the annular restrictor  40  may be released prior to retrieving the tubular string  12  from the well. In this manner, the annular restrictor  40  will not hinder retrieval of the tubular string  12 , and will not “swab” the well (e.g., create a significant pressure reduction below the annular restrictor) as the tubular string is retrieved. 
     Referring additionally now to  FIG. 3 , another example of the bottom hole assembly  22  is representatively illustrated. In this example, the bottom hole assembly  22  includes a perforator  50  and a firing head  52 . The perforator  50  and firing head  52  are connected below the annular restrictor  40 , but in other examples the annular restrictor could be connected below the perforator and firing head. 
     The perforator  50  is used to form perforations  54  through the casing  16  and cement  18 , and into an earth formation  56  penetrated by the wellbore  14 . The firing head  52  is used to fire the perforator  50  which, in this example, may include explosive shaped charges to form the perforations  54 . The firing head  52  may fire the perforator  50  in response to any of various stimuli, such as, pressure pulses, flow manipulations, time or temperature levels, electromagnetic signals, acoustic signals, etc. 
     However, other types of perforators may be used in other examples. An abrasive jet perforator may be used, in which case the firing head  52  would not be necessary. 
     The pressure differential across the annular restrictor  40  due to the flow of the fluid  42  through the annulus  30  may be used to convey the perforator  50  to a desired position for forming the perforations  54 . The perforations  54  can then be formed by activating the firing head  52  to fire the perforator  50 . After the perforations  54  are formed, the annular restrictor  40 , firing head  52  and perforator  50  can be released from the tubular string  12 , and the tubular string can be retrieved from the well, if desired. 
     Note that, after the perforations  54  are formed, fluid in the casing  16  below the annular restrictor  40  can be displaced into the formation  56  via the perforations. Thus, if the annular restrictor  40  is positioned sufficiently far above the perforator  50  (or multiple perforators), the pressure differential across the annular restrictor can be used to convey the perforator(s) to multiple locations for forming perforations. For example, multiple zones could be perforated in a single trip of the tubular string  12  into the well. 
     Prior to forming the perforations  54 , any of the fluid  42  that flows past the annular restrictor  40 , and fluid in the casing  16  below the annular restrictor, can flow to the surface via the tubular string  12 . For example, a valve or ported sub  58  may be used to allow fluid flow into the tubular string  12  below the annular restrictor  40 . 
     Referring additionally now to  FIG. 4 , another example of the bottom hole assembly  22  is representatively illustrated. In this example, the bottom hole assembly  22  includes a fluid motor  60  and a cutting device  62 . 
     The fluid motor  60  operates in response to flow of the fluid  42  through the motor. The fluid motor  60  may be a turbine-type drilling or milling motor. Alternatively, the fluid motor  60  may be a Moineau-type progressive cavity drilling or milling motor. Any type of fluid motor may be used in keeping with the scope of this disclosure. 
     The cutting device  62  is rotated by the fluid motor  60 . The cutting device  62  may be a mill used, for example, to cut through the plug  46  or the casing  16  (e.g., to form a window for drilling a lateral or branch wellbore). Alternatively, the cutting device  62  may be a drill bit used to elongate the wellbore  14 . Any type of cutting device may be used in keeping with the scope of this disclosure. 
     A valve or ported sub  64  may be used to allow the fluid  42  to flow from the annulus  30  above the annular restrictor  40 , into the bottom hole assembly  22 , and through the fluid motor  60 . Another valve or ported sub  66  may be used to allow the fluid  42  that exits the cutting device  62  (as well as any fluid in the casing  16  below the annular restrictor  40 ) to flow into the bottom hole assembly  22  below the annular restrictor  40 , for return to the surface via the tubular string  12 . 
     After the plug  46  has been milled through (or after drilling or other cutting operations are concluded), the annular restrictor  40  can be released from the tubular string  12 . The tubular string  12  can then be retrieved from the well. 
     In some examples, the annular restrictor  40  could be made of a dispersible or degradable material, so that the annular restrictor no longer substantially restricts flow through the annulus  30 . Thus, instead of releasing the annular restrictor  40  from the tubular string  12 , the annular restrictor could be dissolved (e.g., by flowing a particular fluid, such as acid, into contact with the annular restrictor) or otherwise degraded or dispersed, prior to retrieving the tubular string. 
     However, in some examples the tubular string  12  may not be retrieved from the well (e.g., in certain completion or workover operations). Thus, the scope of this disclosure is not limited to releasing, dissolving, degrading or dispersing the annular restrictor  40  prior to retrieving the tubular string  12 . 
     The force generated by the pressure differential across the annular restrictor  40  may result in an immediate displacement of the bottom hole assembly  22 , or the force may be “stored” for later use. In the  FIG. 4  example, a compressible biasing device (such as, a compression spring, a pressurized gas chamber, a resilient member, etc.) could be connected between the annular restrictor  40  and the cutting device  62 , so that the force generated by flow of the fluid  42  through the annulus  30  is stored in the biasing device. The stored force can then be used to continually bias the cutting device  62  into contact with the plug  46  (or other structure being cut) while the fluid motor  60  rotates the cutting device. 
     Referring additionally now to  FIGS. 5A-F , another example of the bottom hole assembly  22  is representatively illustrated in successive axial sections. The bottom hole assembly  22  in this example is similar in some respects to the example of  FIG. 3 , in that it includes an annular restrictor  40  and a perforator  50 . However, the annular restrictor  40  and perforator  50  are differently configured in the  FIGS. 5A-F  example. 
     The annular restrictor  40  is connected below the perforator  50  in the  FIGS. 5A-F  example. In addition, the annular restrictor  40  is capable of sealingly engaging the interior surface of the casing  16  and completely preventing flow of the fluid  42  past the annular restrictor, thereby sealing off the annulus  30  in the system  10 . However, the  FIGS. 5A-F  bottom hole assembly  22  may be used with other systems and methods, and it is not necessary for the annular restrictor  40  of the  FIGS. 5A-F  bottom hole assembly to completely seal off an annulus, in keeping with the scope of this disclosure. 
     The perforator  50  in the  FIGS. 5A-F  example is an abrasive jet perforator, instead of an explosive shaped charge perforator. However, any type of perforator may be used in the  FIGS. 5A-F  bottom hole assembly  22 , in keeping with the scope of this disclosure. 
     Beginning with  FIG. 5A , it may be seen that the bottom hole assembly  22  includes an upper connector  68  for connecting the bottom hole assembly to the tubing  20 . A separate tubing connector (not shown) may also be used, if desired. 
     A back pressure valve  70  is positioned below the upper connector  68 . The back pressure valve  70  in this example includes two pivotably mounted flappers  72  that are biased toward sealing engagement with annular seats  74  encircling a central longitudinal flow passage  76 . 
     However, a sleeve  78  positioned in the passage  76  prevents the flappers  72  from rotating toward the seats  74 . Shear members  80  releasably retain the sleeve  78  in this position. 
     In  FIG. 5B , it may be seen that a castellated support  82  is provided for the sleeve  78 . When the sleeve  78  displaces downward (as described more fully below), the castellated support  82  allows flow through the passage  76  around a lower end of the sleeve. 
     In  FIG. 5C , an upper section of the perforator  50  can be seen. Nozzles  84  can be used to accelerate an abrasive fluid flow outward from the perforator  50 , in order to form perforations (such as the perforations  54  of  FIG. 3 ). 
     An inner sleeve  86  initially prevents fluid in the passage  76  from flowing to the nozzles  84 , and so the perforator  50  is initially inactive. The sleeve  86  is releasably retained in this position by one or more shear members  88 , visible in  FIG. 5D . 
     In  FIG. 5E , the annular restrictor  40  may be seen. In this example, the annular restrictor  40  includes a resilient (such as, elastomeric) cup packer  90 , sometimes referred to as a “swab cup” by those skilled in the art. 
     The packer  90  is connected below a release mechanism  92 . The release mechanism  92  in this example includes an inner support sleeve  94  that initially radially outwardly supports multiple circumferentially distributed threaded collets  96 . The support sleeve  94  is releasably retained in this position by shear members  98 . 
     In  FIG. 5F , it may be seen that ports  100  are provided through a distal end of the bottom hole assembly  22 . The ports  100  allow fluid communication between the flow passage  76  and an exterior of the bottom hole assembly  22  below the annular restrictor  40 . In the system  10 , the ports  100  will allow the fluid  44  to flow into the passage  76  as the bottom hole assembly  22  advances into the wellbore  14  in response to the pressure differential created across the annular restrictor  40  due to flow of the fluid  42  through the annulus  30 . 
     Referring additionally now to  FIGS. 6A  &amp; B, the annular restrictor  40  is being released from the bottom hole assembly  22 . To accomplish this result, a plug  102  (such as a ball or dart, etc.) is sealingly engaged with a tapered seat  104  in the sleeve  94 , and increased pressure is applied to the passage  76  above the plug. 
     For example, the plug  102  could be dropped into the tubular string  12  at the surface, and the pump  36  (see  FIG. 1 ) could be used to displace the plug through the tubular string and into sealing engagement with the seat  104 . The pump  36  may also be used to apply increased pressure to the flow passage  76 , in order to shear the shear members  98  and displace the sleeve  94  downward, so that it no longer outwardly supports the collets  96 . 
     Instead of the collets  96 , balls  106  received in openings  108  could be outwardly supported by the sleeve  94 , so that the balls engage an annular recess  110 , and so that displacement of the sleeve would allow the balls to disengage from the recess. Thus, the scope of this disclosure is not limited to use of any particular type of release mechanism. 
     The annular restrictor  40  may be released from the bottom hole assembly  22  after the perforator  50  is appropriately positioned for forming perforations. In other examples, the annular restrictor  40  may be released (or dispersed or otherwise degraded) at any time it is no longer desired to utilize the annular restrictor to displace the bottom hole assembly  22  in response to a pressure differential across the annular restrictor. 
     Referring additionally now to  FIGS. 7A  &amp; B, the bottom hole assembly  22  is representatively illustrated with the perforator  50  activated after the annular restrictor  40  has been released. An abrasive slurry  112  can now be pumped from the surface (for example, using the pump  36 ), through the flow passage  76 , and outward from the nozzles  84 . 
     To accomplish this result, a plug  114  (such as a ball or dart, etc.) is sealingly engaged with a tapered seat  116  in the sleeve  86 , and increased pressure is applied to the passage  76  above the plug. The plug  114  can be dimensioned larger than the plug  102  used to release the annular restrictor  40 . 
     For example, the plug  114  could be dropped into the tubular string  12  at the surface, and the pump  36  could be used to displace the plug through the tubular string and into sealing engagement with the seat  116 . The pump  36  may also be used to apply increased pressure to the flow passage  76 , in order to shear the shear members  88  and displace the sleeve  86  downward. 
     Referring additionally now to  FIGS. 8A  &amp; B, the bottom hole assembly is representatively illustrated with the back pressure valve  70  activated. The back pressure valve  70  can be activated after perforating operations are concluded, in order to prevent flow of fluids (such as formation hydrocarbons) upward through the tubular string  12 . 
     To activate the back pressure valve  70 , a plug  118  (such as a ball or dart, etc.) is sealingly engaged with a tapered seat  120  in the sleeve  78 , and increased pressure is applied to the passage  76  above the plug. The plug  118  can be dimensioned larger than the plug  114  used to activate the perforator  50 . 
     For example, the plug  118  could be dropped into the tubular string  12  at the surface, and the pump  36  could be used to displace the plug through the tubular string and into sealing engagement with the seat  120 . The pump  36  may also be used to apply increased pressure to the flow passage  76 , in order to shear the shear members  80  and displace the sleeve  78  downward. 
     It may now be fully appreciated that the above disclosure provides significant advancements to the art of conveying tubular strings and bottom hole assemblies into wellbores. In various examples described above, an annular restrictor  40  can be used to displace a tubular string  12  into a wellbore  14 , in response to flow of fluid  42  through an annulus  30  and a resulting pressure differential across the annular restrictor. 
     This disclosure describes tools and methods for advancing well tool assemblies into a wellbore. One concept is to use an annular element on an outside of a bottom hole assembly. The annular element supplies downward force on the bottom hole assembly and tubing when fluid is pumped down an annulus between the tubing and the wellbore. 
     When fluid is pumped down the annulus, it creates a downward hydraulic force on the element, which tends to advance the bottom hole assembly and tubing into the wellbore. The fluid which is displaced below the annular element by the advancing bottom hole assembly can either flow into an opening in the casing below the bottom hole assembly, or if no openings below the bottom hole assembly exist, the fluid can flow to the surface through the tubing (similar to reverse circulation). The displaced fluid can be fluid displaced below the bottom hole assembly, but separated from the annulus above by the annular element, or it can be a combination of displaced fluid combined with annular flow that passes around or through the annular element. 
     This method allows large downward forces to be applied to the bottom hole assembly, making it possible to convey tools on flexible tubing strings, such as coiled tubing, to much greater depths than can be achieved by “pushing” tubing into the wellbore from the surface. 
     Optional configurations include (but are not limited to):
         Abrasive perforating gun deployed with annular element.   Explosive shaped charge perforating gun deployed with annular element.   Fluid motor deployed with annular element—
           The motor can be continuously operated with annular flow to element while displacement fluid flows up through the tubing string.   The motor can be continuously operated with annular flow while displacement fluid exits the casing through an opening below the bottom hole assembly.   The motor can be operated with flow through the tubing string during cutting, but annular flow can be used to advance the bottom hole assembly into the wellbore when not cutting.   
           Fishing bottom hole assembly deployed with annular element.   Any other bottom hole assembly deployed with annular element.   Annular element can be disconnected to prevent swabbing on trip out of well.   A back pressure valve which stays open during deployment to allow flow of displacement fluid through the bottom hole assembly can be utilized. The back pressure valve can be activated by pumping down a plug when back pressure protection is desired (such as, after perforating).       

     Some specific concepts described above include (but are not limited to):
         Use of annular flow and annular element to “pump down” a bottom hole assembly.   Use of annular flow and annular element, while returning displacement flow through a tubing string.   Disconnecting annular element after the bottom hole assembly is advanced into the wellbore (for example, to prevent well swabbing when tubing is withdrawn from the well).   Perforating a well in which there are no openings in the casing to receive displacement flow.   Operating and/or advancing a motor with annular flow.   Advancing any bottom hole assembly or tool with annular flow, with displacement fluid being returned through the tubing string.   Use of this system and method with single trip multiple zone “perforate, fracture and plug” techniques.       

     One specific operating method can include the following steps:
         1. Pump fluid down annulus to create downward force on an annular element to advance a bottom hole assembly to a location within a well, while either flowing displacement fluid back through tubing string or causing it to exit through a hole in the casing.   2. Disconnect annular element from bottom hole assembly.   3. Activate perforator (either explosive shaped charge or abrasive, etc.) to perforate a zone in the well.   4. Perforate additional locations within the well if desired.   5. Remove bottom hole assembly from the well, or activate reverse flow back pressure valve to eliminate the possibility of reverse flow through tubing string (e.g., for safety purposes).   6. Remove bottom hole assembly from well.       

     One very useful application of this system and method is to position an abrasive or pyrotechnic (explosive) perforator deep within a wellbore to perforate a “toe” of the well (at or near a distal end of a generally horizontal or substantially inclined wellbore section). In one configuration, an abrasive perforator can be deployed above the annular element. In another configuration, an explosive shaped charge perforator can be deployed below the annular element. 
     A system  10  for advancing a tubular string  12  into a wellbore  14  can include an annular restrictor  40  connected in the tubular string. The annular restrictor  40  restricts flow through an annulus  30  formed between the tubular string  12  and the wellbore  14 . Restriction to the flow through the annulus  30  biases the tubular string  12  into the wellbore  14 , and fluid in the wellbore displaces into at least one of: a) a formation  56  penetrated by the wellbore and b) the tubular string. 
     The annular restrictor  40  may be connected at a distal end of the tubular string  12  in the wellbore  14 . The annular restrictor  40  may permit restricted flow past the annular restrictor. 
     The system  10  may include a vibratory tool  48  that generates vibrations in response to displacement of the fluid  44  in the wellbore  14  into the tubular string  12 . 
     The annular restrictor  40  may be connected between a perforator  50  and a tubing  20  extending to surface (e.g., at or near the earth&#39;s surface, as depicted in  FIG. 1 ). The system  10  may include a ported sub  58  connected between the annular restrictor  40  and the perforator  50 . The ported sub  58  can permit the fluid  44  in the wellbore  14  to displace into the tubular string  12 . 
     A perforator  50  may be connected between the annular restrictor  40  and a tubing  20  extending to surface. 
     The annular restrictor  40  may be connected between a fluid motor  60  and a tubing  20 . The system  10  may include a ported sub  66  connected between the annular restrictor  40  and the fluid motor  60 . The ported sub  66  can permit the fluid  42  in the wellbore  14  to displace into the tubular string  12  and flow through the fluid motor  60 . 
     The system of claim  1 , further comprising a release mechanism that releases the annular restrictor from the tubular string. 
     A method of advancing a tubular string  12  into a wellbore  14  can include connecting an annular restrictor  40  in the tubular string  12 , and flowing a first fluid  42  through an annulus  30  formed between the tubular string  12  and the wellbore  14 , thereby causing a differential pressure across the annular restrictor  40 , the differential pressure biasing the tubular string  12  into the wellbore  14 . 
     The method may include flowing a second fluid  44  from the wellbore  14  into the tubular string  12  as the tubular string advances into the wellbore. At least a portion of the first fluid  42  may flow with the second fluid  44  into the tubular string  12 . The step of flowing the second fluid may include generating vibrations in response to the second fluid  44  flowing from the wellbore  14  into the tubular string  12 . 
     The method may include flowing a second fluid  44  from the wellbore  14  into a formation  56  penetrated by the wellbore as the tubular string  12  advances into the wellbore. 
     The method may include rotating a cutting device  62  in response to the first fluid  42  flowing from the wellbore  14  into the tubular string  12 . The method may also include releasing the annular restrictor  40  from the tubular string  12  after the cutting device  62  rotating step. 
     The method may include, after the flowing step, perforating a casing  16  that lines the wellbore  14 . The method may also include releasing the annular restrictor  40  from the tubular string  12  prior to the perforating step. 
     The method may include degrading the annular restrictor  40  in the wellbore  14  prior to retrieving the tubular string  12  from the wellbore. 
     Another method of advancing a tubular string  12  into a wellbore  14  can include connecting an annular restrictor  40  in the tubular string  12 , flowing a fluid  42  through an annulus  30  formed between the tubular string  12  and the wellbore  14 , thereby biasing the tubular string  12  into the wellbore  14 , and then causing the annular restrictor  40  to cease restricting flow through the annulus  30 . 
     The causing step may be performed prior to retrieving the tubular string  12  from the wellbore  14 . 
     The causing step may be performed by releasing the annular restrictor  40  from the tubular string  12 . 
     The causing step may be performed by at least one of: dissolving the annular restrictor  40 , degrading the annular restrictor  40  and dispersing the annular restrictor  40 . 
     The causing step may be performed prior to, or after, perforating a casing  16  that lines the wellbore  14 . 
     The causing step may be performed after rotating a cutting device  62  in response to the fluid  42  flowing step. 
     The causing step may be performed prior to rotating a cutting device  62  in the wellbore  14 . 
     The method may include closing a back pressure valve  70  after the causing step. 
     The method may include permitting flow from the wellbore  14  into the tubular string  12  as the tubular string advances into the wellbore. 
     Although various examples have been described above, with each example having certain features, it should be understood that it is not necessary for a particular feature of one example to be used exclusively with that example. Instead, any of the features described above and/or depicted in the drawings can be combined with any of the examples, in addition to or in substitution for any of the other features of those examples. One example&#39;s features are not mutually exclusive to another example&#39;s features. Instead, the scope of this disclosure encompasses any combination of any of the features. 
     Although each example described above includes a certain combination of features, it should be understood that it is not necessary for all features of an example to be used. Instead, any of the features described above can be used, without any other particular feature or features also being used. 
     It should be understood that the various embodiments described herein may be utilized in various orientations, such as inclined, inverted, horizontal, vertical, etc., and in various configurations, without departing from the principles of this disclosure. The embodiments are described merely as examples of useful applications of the principles of the disclosure, which is not limited to any specific details of these embodiments. 
     In the above description of the representative examples, directional terms (such as “above,” “below,” “upper,” “lower,” etc.) are used for convenience in referring to the accompanying drawings. In general, the term “above” is used to indicate a direction toward the earth&#39;s surface along a wellbore, and the term “below” is used to indicate a direction away from the earth&#39;s surface along a wellbore. However, it should be clearly understood that the scope of this disclosure is not limited to any particular directions described herein. 
     The terms “including,” “includes,” “comprising,” “comprises,” and similar terms are used in a non-limiting sense in this specification. For example, if a system, method, apparatus, device, etc., is described as “including” a certain feature or element, the system, method, apparatus, device, etc., can include that feature or element, and can also include other features or elements. Similarly, the term “comprises” is considered to mean “comprises, but is not limited to.” 
     Of course, a person skilled in the art would, upon a careful consideration of the above description of representative embodiments of the disclosure, readily appreciate that many modifications, additions, substitutions, deletions, and other changes may be made to the specific embodiments, and such changes are contemplated by the principles of this disclosure. For example, structures disclosed as being separately formed can, in other examples, be integrally formed and vice versa. Accordingly, the foregoing detailed description is to be clearly understood as being given by way of illustration and example only, the spirit and scope of the invention being limited solely by the appended claims and their equivalents.