Patent Publication Number: US-10787881-B2

Title: Drill string apparatus with integrated annular barrier and port collar, methods, and systems

Description:
BACKGROUND 
     Wellbore integrity is almost always a consideration when conveying a casing or liner-while-drilling downhole. Wellbore integrity may be affected by reservoir depletion, complex drilling trajectory, tectonics, fault formation, or reactive formations. 
     In a weak geological formation, the drill bit may be combined with the casing or liner during the drilling operation. Thus, a wellbore with weak walls is lined while the wellbore is drilled. However, this may present issues with cementing the casing or liner in place due to weak formations not being able to withstand the heavier cement column, getting into a loss of cement circulation and jeopardizing the cement and borehole integrity. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         FIG. 1  is a diagram of a drilling system including a drill string apparatus in a borehole, according to various aspects of the present disclosure. 
         FIG. 2  is a diagram showing a more detailed view of the drill string apparatus, according to various aspects of the present disclosure. 
         FIG. 3  is a diagram showing the casing after the drilling apparatus has been removed and the casing is in place for cementing, according to various aspects of the present disclosure. 
         FIG. 4  is a diagram of the lower section of the casing showing a latch plug  400  used to pressurize the casing and then open and inflate the packer, according to various aspects of the present disclosure. 
         FIG. 5  is a diagram of the lower section of the casing showing the process of opening the port and circulating the cement above the casing packer, according to various aspects of the present disclosure. 
         FIG. 6  is a flowchart showing a method for drilling and cementing, according to various aspects of the present disclosure. 
     
    
    
     DETAILED DESCRIPTION 
     To address some of the challenges described above, such as the need to maintain wellbore integrity and rotate the casing/liner during drilling, as well as others, apparatus, systems, and methods are described herein that may operate to improve cementing of casings or liners in a wellbore that have been conveyed into the wellbore coupled to a drill bit. Examples of such embodiments are now described in detail. 
       FIG. 1  is a diagram of a drilling system including a drill string apparatus  100  in a borehole, according to various aspects of the present disclosure. The drill string apparatus is shown in greater detail in  FIG. 2  and discussed subsequently. 
     Methods, systems, and apparatuses are disclosed for effecting directional (i.e., steerable) drilling. The directional drilling may include casing-while-drilling operations and/or liner-while-drilling operations. 
     In casing-while-drilling operations, a casing string is used as the drill string (i.e., instead of drilling pipe, the casing string itself is rotated and imparts rotation to a drill bit disposed at a downhole or lower end of the casing string, such that as drilling proceeds, the casing string is lowered into the borehole). A “liner” is a particular kind of casing string which does not extend to the top of the borehole. Thus, in liner-while-drilling operations, the drill string may comprise drill pipe coupled to the liner, which in turn is coupled to a rotary steerable system (RSS) (which likewise may be part of or otherwise included in a bottom hole assembly (BHA)). 
     In the interest of brevity, subsequent discussions refer only to casings and casing-while-drilling. Due to the similarity of casings and liners, it will be assumed that all references to casings and casing-while-drilling are also references to liners and liner-while-drilling. 
     Directional drilling may be accomplished by the RSS that may include a mechanism to deviate a drill bit radially from the axis of a drill string in a “point-the-bit” manner. The RSS is disposed in an RSS housing that is coupled to the casing or liner string such that the RSS is disposed within the casing or liner string. The RSS, in some embodiments, may be part of, or otherwise included in, a BHA. The RSS may be coupled to an underreamer and/or a drill bit disposed at the downhole or lower end of the casing string. As described subsequently with reference to  FIG. 2 , the RSS is rotationally fixed with respect to a lower section  153  of a casing string  150 . At the same time, the lower section  153  anchors and grabs the borehole, thus keeping the RSS and electronics stationary for tracking toolface. 
     Referring to  FIG. 1 , the drill string apparatus  100  is disposed at a lower or downhole end of the casing string  150  being used as the drill string. The drill string apparatus  100  may include an underreamer  110  and drill bit  111  disposed at the lower or downhole end of the casing string. 
       FIG. 1  shows the drill bit  111  and underreamer  110  as separate elements with the underreamer  110  mounted to an internal shaft of the RSS behind the drill bit. However, a drill bit  111  may itself comprise a reamer and/or a drill bit  111  may comprise any suitable device for boring or enlarging a hole to be substantially larger than the outer diameter of a casing string  150  (e.g., a bi-center bit). 
     The drill string apparatus  100  further includes an RSS  105  disposed within the casing string  150 . Some part or parts of the RSS  105  may be operatively coupled to the casing string  150  such that rotational forces from the casing string  150  are imparted only to the operationally coupled parts of the RSS  105 , and in turn to the underreamer  110  and/or drill bit  111 . In such embodiments, some portions of the RSS  105  (e.g., its housing and components disposed thereon) may be operated as substantially non-rotating portions. 
     In some embodiments, the BHA  100  may include a mud motor (not references in  FIG. 1  references in  FIG. 2  ( 201 )), which may be actuated or otherwise activated so as to impart rotational forces upon the drill bit, as will be apparent to one having skill in the art with the benefit of this disclosure. In such embodiments, the rotation from the mud motor may be either in addition to or instead of the rotation imparted to the drill bit by rotating the casing string  150 . The mud motor includes a rotor and a stator that together use the Moineau principle to rotate the drillstring as a result of the pumping of a fluid (e.g., drilling mud) through the mud motor. 
     The casing string  150  may further comprise multiple casing joints  151 . Each casing joint  151  may be a segment of casing pipe serially coupled to one or more other casing joints  151 . Casing joints  151  may, in some instances, be of approximately equal length, and include mechanisms for coupling to other casing joints on either end (e.g., threading for threaded connection either directly to another casing joint or for connection to a casing joint connector capable of receiving threaded ends of two casing joints). 
     The casing string  150  may extend from the top of the borehole  160  (e.g., point  161 ) to a downhole point  163  of the borehole  160 . Some wells drilled according to certain embodiments of the present disclosure may involve the use of multiple casing strings, in which case each casing string would extend from the top of the borehole  160  to a point downhole, which downhole point may be different for each casing string. 
     The drill string apparatus  100  includes a swivel, illustrated by the stylized representation of a swivel  170  shown in  FIG. 1 . The swivel  170  may include any suitable mechanism for coupling two casing joints  151  in a manner that rotational forces from casing joints  151  above the swivel  170  are not transferred to a casing joint or joints  151  below the swivel (e.g., the casing joints  151  below the swivel  170  could be thought of as hanging freely from the portion of the casing string  150  above the swivel  170 ). Thus, in embodiments wherein the casing string  150  includes a swivel  170 , the casing string  150  may be defined to include an upper section (e.g., upper casing section  152 ) and a lower section (e.g., lower casing section  153 ), wherein the upper section includes the casing joint or joints above the swivel  170  and the lower section includes the casing joint or joints below the swivel  170 . In such embodiments, the RSS  105  may be disposed at least in part within, and/or coupled to, the lower section  153  of the casing string  150 . 
     In some embodiments including a swivel, the casing string  150  may additionally include one or more centralizers  125  disposed along a portion of the casing string  150  within which the RSS  105  is disposed. These centralizers may help the casing string  150  maintain an approximately centered position in the borehole  160 . 
     As noted, the swivel  170  may include one or more mechanisms that enable coupling of two casing joints  151  in a manner that rotational forces from casing joints  151  above the swivel  170  are not transferred to a casing joint or joints  151  below the swivel. For instance, the swivel  170  may include one or more radial force bearing components, one or more axial force bearing components, and a sealing mechanism. 
       FIG. 2  is a diagram showing a more detailed view of the drill string apparatus  100 , according to various aspects of the present disclosure. As discussed previously with reference to  FIG. 1 , the drill string apparatus  100  includes the underreamer  110  and drill bit  111  disposed at the lower or downhole end of the casing string that includes the upper section  152  above the swivel  170  and the lower section  153  below the swivel  170 . The drill string apparatus  100  further includes the RSS  105  disposed within the casing string  150 . The RSS housing  105  may be coupled to the casing string  150  by, for example, one or more sets of latches  101 . 
     The drilling string apparatus, in an embodiment, may further include a mud motor  201  operatively coupled to a driveshaft  214  and to the upper section of the upper casing section  152  (e.g., by latches  101 ). The mud motor  201  may be located above the swivel  170 , as shown in  FIG. 2 . In other embodiments, the mud motor  201  may be located below the swivel  170  connected to a tubular component across the swivel and couple to the upper casing by latches  101 . The mud motor  201  may be capable of actuation (e.g., by passing drilling mud through the motor, by sending an electrical signal, or by any other mechanism) so as to impart rotation to the driveshaft  214  and, in turn, the underreamer  110  and bit  111 . The mud motor  201  provides rotational forces to the driveshaft  214  and, in turn, the internal shaft of the RSS provides rotational forces to the underreamer  110  and/or drill bit  111 ). 
       FIG. 2  further shows the substantially non-rotating (with respect to the lower casing section  153  and upper casing section  152 ) RSS  105  coupled to the casing (here, lower section of casing  153 ) using a first set of RSS latches  210  and a second set of RSS latches  215 . Thus, the sets of RSS latches  210 ,  215  rotationally fix the RSS  105  to the lower section of casing  153 . 
     The driveshaft  214  is coupled to the internal shaft of the RSS  105 . The internal shaft of the RSS  105  is operatively coupled to the underreamer  110  and/or drill bit  111  so as to enable radial diversion of the underreamer  110  and/or drill bit  111  with respect to the longitudinal axis  250  of the casing string. 
     The drill string apparatus  100  further includes an integrated annular barrier (e.g., external casing packer)  257  and casing pads  255 , external to and disposed on the lower casing section  153 . In an embodiment, the external casing packer  257  is disposed below the casing pads  255  on the lower casing section  153  The casing packer  257  may be used later during cementing process to withstand the hydrostatic cement column. 
     The packer  257  may be inflated with a fluid (e.g., drilling mud) that is injected into the packer  257  prior to cementing in the casing cement method, as discussed subsequently. 
     The casing pads  255  provide friction with the side of the wellbore in order to hold the lower casing section  153  substantially rotationally stationary in the wellbore. Other mechanisms besides casing pads  255  may be used for this purpose. 
     A port collar  260  is incorporated in the drill string apparatus  100  above the swivel  170 . The port collar  260  is disposed in the upper casing section  152  and may comprise a controllable opening from an interior of the upper casing section  152  to the annulus around the upper casing section  152 . The port  260  may be opened for a cementing method as discussed subsequently with reference to the flowchart of  FIG. 6 . The drill string apparatus  100  also supports a more conventional cementing method, if the geological formation is able to support the hydrostatic pressure of the cement, by keeping the port  260  closed. Thus, during the cementing method of  FIG. 6 , the port  260  is open allowing cement to flow through the ports and in to the upper section of casing  152  and, during a conventional cementing method, the ports are closed so that the cement flows out the end of the lower section of casing  153 . These concepts are shown subsequently and discussed in greater detail with reference to  FIGS. 3-5  in combination with the method illustrated in  FIG. 6 . 
       FIG. 3  is a diagram showing the casing after the drilling apparatus has been removed and the casing is in place for cementing, according to various aspects of the present disclosure.  FIG. 4  is a diagram of the lower section of the casing showing a latch plug  400  used to pressurize the casing and then open and inflate the packer, according to various aspects of the present disclosure.  FIG. 5  is a diagram of the lower section of the casing showing the process of opening the port and circulating the cement above the casing packer, according to various aspects of the present disclosure.  FIG. 6  is a flowchart showing a method for drilling and cementing, according to various aspects of the present disclosure. The cement injection method will now be described with reference to the drill string apparatus  100  of  FIGS. 1-5 . 
     In block  601 , a casing-while-drilling operation (e.g., steerable casing-while-drilling) is performed. For example, this operation may be performed as illustrated in  FIG. 1 . In block  603 , once the hole is drilled, the BHA is disengaged and retrieved by fishing with wireline or drill pipe. In directional drilling liner applications, the BHA may be retrieved by temporarily hanging the liner in the parent casing and disengaging the inner string to pull the BHA out of the hole.  FIG. 3  illustrates the BHA removed, the upper and lower sections of casing  152 ,  153  in the borehole  300 , and the external packer  257  in a contracted state (i.e., not expanded). 
     In block  605 , it is determined whether the cement process for casing is to be completed in a conventional way (e.g., port  260  closed) or the presently disclosed method with the port  260  open. This decision depends on the wellbore  300  integrity. If the geological formation is determined to be strong enough to withstand a cement column, a conventional cement process can be performed (e.g., port  260  closed). If the geological formation is weaker and may be fractured by the cement column, the present cement method, with the port  260  open, is performed. 
     When the conventional cement method is used, the ports are left closed  607 , in block  607 . In block  608 , an upper float valve is launched downhole. In block  609 , the cement slurry is pumped downhole with a displacement plug that may be landed at the upper float valve in the casing. The result of the conventional cement method is not illustrated in  FIGS. 3-5 . 
     In block  611 , if the presently disclosed cement method is performed, the external packer  257  is expanded against the wellbore wall  300  and the port  260  is opened. The results of this operation are illustrated in  FIG. 4  and  FIG. 5 . It can be seen that the external packer  257  is now substantially blocking (e.g., sealing) the annulus around the lower section of casing  153 . 
     The casing pads  255  substantially reduce or eliminate the rotation of the lower section of casing  153  with the RSS such that the lower section of casing  153  is substantially, rotationally stationary with respect to the upper section of casing  152 . 
     In block  612 , after opening the port, a cement retainer can be run into the hole to be cemented with an inner string or by pumping a float valve plug to be landed on one of the latches  101  in the upper section of the casing. The float valve will prevent cement from performing a U tube effect inside the casing. A plug  400  is used to open the port of the external casing plug. 
     In block  613 , cementing begins by the cement slurry being pumped downhole through the casing with a cement displacement plug that is landed at the upper float valve. The flow of cement is shown in  FIG. 5  traveling down the upper casing section  152  and out the port  260 . The displacement plug and float valve  500  are illustrated in  FIG. 5 . During cementing, the upper casing section  152  can be rotated to improve the cement coverage and adherence. The displacement plug and float valve  500  may avoid the occurrence of U-Tubing. U-Tubing is explained subsequently.  FIG. 5  now shows the completed cement method with a column of cement  500  in place in the upper casing section  152 . Subsequent drilling may use a drill bit to remove the cement within the casing. 
     The occurrence of U-Tubing may be explained by assuming that a column Y of the tube represents the annulus and a column X represents the pipe (drill string) in the well. The bottom of the U-tube represents the bottom of the well. In most cases, fluids create hydrostatic pressures in both the pipe and annulus. Atmospheric pressure can be ignored, since it works the same on both columns. If the fluid in both the pipe and annulus are of the same density, hydrostatic pressures will be equal and the fluid will remain in static equilibrium on both sides of the tube. If the fluid in the annulus is heavier, it will exert pressure downward and will flow into the drill string, displacing some of the lighter fluid out of the string and causing a flow at surface. The fluid level will fall in the annulus until pressures equalize. This is because a difference in hydrostatic pressures urges the fluid to move until a balance point is reached. This phenomenon is typically referred to as U-tubing and it explains why there may be flow from the pipe when making connections. 
     The method of  FIG. 6  may be used for placing a steerable liner. In such an embodiment, the RSS is latched or coupled to the lower part of the liner. 
     Example 1 is a directional drill string apparatus, comprising: 
     an upper casing section comprising a port collar that provides an opening from the upper casing section to an annulus around the upper casing section; and a lower casing section coupled to the upper casing section through a swivel, the lower casing section comprising: an annular barrier coupled to an external portion of the lower casing section; and a casing pad coupled to an external portion of the lower casing section; wherein the external casing packer is expandable to an annulus around the lower casing section prior to cementing. 
     In Example 2, the subject matter of Example 1 can further include a rotary steerable system (RSS) and RSS housing disposed within the lower casing section. 
     In Example 3, the subject matter of Examples 1-2 can further include wherein the RSS housing is coupled to the lower casing with at least one set of latches such that the RSS housing is substantially rotationally stationary with respect to the upper casing section. 
     In Example 4, the subject matter of Examples 1-3 can further include wherein the lower casing section is configured to be stationary while the upper casing section is configured to rotate with the port collar open during the cementing. 
     In Example 5, the subject matter of Examples 1-4 can further include a drill bit coupled to an internal shaft of the RSS. 
     In Example 6, the subject matter of Examples 1-5 can further include a mud motor coupled to a driveshaft wherein the driveshaft is coupled to the internal shaft of the RSS. 
     In Example 7, the subject matter of Examples 1-6 can further include an underreamer coupled to the internal shaft of the RSS between the drill bit and the RSS. 
     In Example 8, the subject matter of Examples 1-7 can further include wherein the drill bit further comprises an underreamer. 
     In Example 9, the subject matter of Examples 1-8 can further include wherein the annular barrier comprises an external casing packer that is configured to expand with fluid. 
     In Example 10, the subject matter of Examples 1-9 can further include wherein the upper casing section comprises an upper liner section and the lower casing section is a lower liner section. 
     Example 11 is a method for drilling and cementing comprising: performing a drilling operation, with a bottom hole assembly, to create a wellbore; opening ports in an upper section of a casing; expanding an external packer in a lower section of a casing, coupled to the upper section of the casing, against the wellbore wall; and pumping a cement slurry and a cement displacement plug downhole through the casing wherein the open ports are configured to allow the cement slurry to exit the upper section of the casing to an annulus and the external packer is configured to stop the cement slurry from continuing downhole past the external packer. 
     In Example 12, the subject matter of Example 11 can further include wherein the drilling operation comprises a directional casing-while-drilling operation. 
     In Example 13, the subject matter of Examples 11-12 can further include wherein the drilling operation comprises a directional liner-while-drilling operation. 
     In Example 14, the subject matter of Examples 11-13 can further include rotating the upper section of the casing while pumping the cement slurry. 
     In Example 15, the subject matter of Examples 11-14 can further include maintaining a lower section of casing, coupled to the upper section of casing through a swivel, in a substantially rotationally stationary manner with respect to the upper section of casing. 
     In Example 16, the subject matter of Examples 11-15 can further include wherein the drilling operation comprises a steerable drilling operation. 
     In Example 17, the subject matter of Examples 11-16 can further include removing the bottom hole assembly prior to pumping the cement slurry. 
     Example 18 is a drilling system comprising: a drill string apparatus comprising: an upper casing section comprising a port collar that provides a controllable opening from an interior of the upper casing section to an annulus surrounding the upper casing section; and a lower casing section coupled to the upper casing section through a swivel, the lower casing section comprising: an external casing packer, coupled to an external portion of the lower casing section, the external casing packer configured to expand against a wellbore wall before cement operation; wherein the upper casing section is configured to rotate during the cement operation while the lower casing section is substantially rotationally stationary with respect to the upper casing section. 
     In Example 19, the subject matter of Example 18 can further include a casing pad coupled to the lower casing section above the external casing packer and configured to hold the lower casing section rotationally stationary in a borehole. 
     In Example 20, the subject matter of Examples 18-19 can further include a point the bit rotary steerable system (RSS) disposed within the lower casing section, the RSS housing coupled to the lower casing section with at least one set of latches. 
     Although specific embodiments have been illustrated and described herein, it will be appreciated by those of ordinary skill in the art that any arrangement that is calculated to achieve the same purpose may be substituted for the specific embodiments shown. Various embodiments use permutations and/or combinations of embodiments described herein. It is to be understood that the above description is intended to be illustrative, and not restrictive, and that the phraseology or terminology employed herein is for the purpose of description. Combinations of the above embodiments and other embodiments will be apparent to those of skill in the art upon studying the above description.