Patent Publication Number: US-11643882-B2

Title: Tubular string with load distribution sleeve for tubular string connection

Description:
BACKGROUND 
     This section is intended to provide relevant background information to facilitate a better understanding of the various aspects of the described embodiments. Accordingly, these statements are to be read in this light and not as admissions of prior art. 
     Hydrocarbons, such as oil and gas, are commonly obtained from subterranean formations that may be located onshore or offshore. In most cases, the formations are located thousands of feet below the surface, and a borehole must intersect the formations before the hydrocarbon can be recovered. Drilling tools and equipment used to reach the formations typically include multiple segments that are coupled using threads. These threaded connections may be subject to high torque and bending loads that the threaded connections must be able to handle without breaking or loosening. However, the size of the borehole and the drilling tools needed to pass through the borehole constrains the outer diameter of the connections between the segments and thus the amount of material available to add structural integrity to the connections. Thus, there is a challenge of minimizing the overall outer diameter (OD) while providing enough structural integrity to enable a connection to withstand large bending moments and torque. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       Embodiments of the tubular string with load distribution sleeve for tubular string connection are described with reference to the following figures. The same or sequentially similar numbers are used throughout the figures to reference like features and components. The features depicted in the figures are not necessarily shown to scale. Certain features of the embodiments may be shown exaggerated in scale or in somewhat schematic form, and some details of elements may not be shown in the interest of clarity and conciseness. 
         FIG.  1    is a diagram of an example drilling system, according to aspects of the present disclosure; 
         FIG.  2    is a diagram of a tubular string using connections for tubular members, according to aspects of the present disclosure; 
         FIG.  3    is a diagram of a connection for a tubular string, according to aspects of the present disclosure; 
         FIG.  4    is a diagram of a connection for a tubular string, according to aspects of the present disclosure; and 
         FIG.  5    is a diagram of an alternative embodiment of a connection for a tubular string, according to aspects of the present disclosure. 
     
    
    
     DETAILED DESCRIPTION 
     Illustrative embodiments of the present disclosure are described in detail herein. In the interest of clarity, not all features of an actual implementation may be described in this specification. It will of course be appreciated that in the development of any such actual embodiment, numerous implementation-specific decisions are made to achieve the specific implementation goals, which will vary from one implementation to another. Moreover, it will be appreciated that such a development effort might be complex and time-consuming, but would be a routine undertaking for those of ordinary skill in the art having the benefit of the present disclosure. 
     To facilitate a better understanding of the present disclosure, the following examples of certain embodiments are given. In no way should the following examples be read to limit, or define, the scope of the disclosure. Embodiments of the present disclosure may be applicable to horizontal, vertical, deviated, or otherwise nonlinear boreholes in any type of subterranean formation. Embodiments may be applicable to injection wells as well as production wells, including hydrocarbon wells. Embodiments may be applicable to both surface wells and subsea wells. Embodiments may be implemented using a tool that is made suitable for testing, retrieval and sampling along sections of the formation. Embodiments may be implemented with tools that, for example, may be conveyed through a flow passage in tubular string or using a wireline, slickline, coiled tubing, downhole robot or the like. 
     The terms “couple” or “couples” as used herein are intended to mean either an indirect or a direct connection. Thus, if a first device couples to a second device, that connection may be through a direct connection or through an indirect mechanical connection via other devices and connections. 
     The present disclosure is directed to a tubular string with at least two tubulars connected with a threaded connection with high bend and torque capacities. For the remainder of this disclosure, the threaded connection will be described with respect to downhole tools used in hydrocarbon recovery and drilling operations. Threaded connections incorporating aspects of the present disclosure are not limited to uses in hydrocarbon recovery and drilling operations, however. Rather, the threaded connections may be used in a variety of other applications that would be appreciated by one of ordinary skill in the art in view of this disclosure. The tubular members being connected have two different sized outer diameters. One reason for one tubular being smaller is to be able to fit equipment around the tubular but still fit within the borehole. To distribute the load created by making up the threaded connection, a load distribution sleeve is inserted between the tubular members. The outer diameters of each end of the load distribution sleeve match the size of the respective outer diameters of the external load shoulders of the tubular members of the connection. In this way, the load distribution sleeve provides enough contact area to distribute the make-up load across the contact surface areas of each of the tubular member external load shoulders and adequately withstand drilling conditions. 
       FIG.  1    is a diagram of an example steerable drilling system  100 , according to aspects of the present disclosure. The drilling system  100  may comprise a drilling platform  102  positioned at the surface  104 . In the embodiment shown, the surface  104  comprises the top of a formation  106  containing one or more rock strata or layers  106   a - d . Although the surface  104  is shown as land in  FIG.  1   , the drilling platform  102  of some embodiments may be located at sea, in which case the surface  104  would be separated from the drilling platform  102  by a volume of water. 
     The drilling system  100  includes a rig  108  mounted on the drilling platform  102 , positioned above a borehole  110  within the formation  106 , and having a traveling block  138  for raising and lowering a drilling assembly  112  partially positioned within the borehole  110 . The drilling assembly  112  comprises a drill string  114  with multiple drill pipe segments that are threadedly engaged. A kelly  136  supports the drill string  114  as it is lowered through a rotary table  142 . A drill bit  118  is coupled to the drill string  114  via a threaded connection, and driven by a downhole motor and/or rotation of the drill string  114  by the rotary table  142 . As the bit  118  rotates, it extends the borehole  110 . A pump  130  circulates drilling fluid through a feed pipe  134  to the kelly  136 , downhole through the interior of the drill string  114 , through orifices in the drill bit  118 , back to the surface via the annulus around the drill string  114 , and into a retention pit  132 . The drilling fluid transports cuttings from the borehole  110  into the pit  132  and aids in maintaining integrity of the borehole  110 . 
     The drilling assembly  112  may further comprise a bottom-hole assembly (BHA)  116 . The BHA  116  is coupled to the drill string  114  through at least one threaded connection, as may the drill bit  118  to the BHA  116 . The BHA  116  may include tools such as logging-while-drilling (LWD)/measurement while drilling (MWD) elements  122 , a steering assembly  124 , and a telemetry system  120 . The LWD/MWD elements  122  may comprise downhole instruments, including sensors, that may continuously or intermittently monitor downhole drilling parameters and downhole conditions. The telemetry system  120  may provide communication with a surface control unit  144  over various channels, including wired and wireless communications channels as well as mud pulses through a drilling mud within the borehole  110 . In certain embodiments, each of the LWD/MWD elements  122 , the steering assembly  124 , and the telemetry system  120  may be coupled together via threaded connections. Additionally, smaller elements within each of the LWD/MWD elements  122 , the steering assembly  124 , and the telemetry system  120  may be coupled together via threaded connections. The LWD/MWD elements  122  may include at least one resistivity logging tool, which may comprise two co-located coil antennas capable of transmitting and/or receiving one or more electromagnetic (EM) signals to and from the subterranean formations  106 . 
     As the drill bit  118  extends the borehole  110  through the formations  106   a - c , the resistivity logging tool may continuously or intermittently collect azimuthally-sensitive measurements relating to the resistivity of the formations  106   a - c , i.e., how strongly the formations  106   a - c  oppose a flow of electric current. The resistivity logging tool and other sensors of the LWD/MWD  122  elements may be communicably coupled to the telemetry system  120  used to transfer measurements and signals from the BHA  116  to surface control unit  144  and/or to receive commands from the surface control unit  144 . The telemetry system  120  may encompass any known means of downhole communication including, but not limited to, a mud pulse telemetry system, an acoustic telemetry system, a wired communications system, a wireless communications system, or any combination thereof. In certain embodiments, some or all of the measurements taken at the resistivity logging tool may also be stored within the resistivity logging tool or the telemetry system  120  for later retrieval at the surface upon retracting the drill string  114 . 
     The steering assembly  124  may also comprise a bit sub  170  that is coupled to the drill bit  118  via a threaded connection and that transmits torque to the drill bit  118  for the purposes of extending the borehole  110  in the formation  106 . The bit sub  170  also may be used by the steering assembly  124  to alter or maintain a drilling direction of the drilling system by altering or maintaining a longitudinal axis  128  of the drill bit  118 . For example, the steering assembly  124  may impart lateral forces on the bit sub  170 , which are transmitted then to the drill bit  118  to alter its longitudinal axis with respect to an axis  126  of the borehole  110 . The bit sub  170  may also receive opposite lateral forces from the drill bit  118  when the drill bit  118  contacts the formation, which form a bending load on the bit sub  170 . Thus, the bit sub  170  must withstand and transmit both torque and bending loads to the drill bit  118 . 
       FIGS.  2 - 4    are diagrams illustrating example threaded connections  250  that are part of a tubular string, such as the drill string  114  of  FIG.  1   , according to aspects of the present disclosure. The threaded connection  250  will be described below with respect to one of the tubular members being an antenna that is one of the LWD/MWD  122  elements, but the threaded connection  250  is equally applicable to other downhole applications where high torque and bending loads are present. 
     As shown in  FIG.  2   , the BHA  216  includes multiple tubular members  270  that make up the BHA  216 , come of which are connected using the threaded connections  250 . Any type of downhole threaded connection style can be used (HAL, API, etc.). Additionally, it should be appreciated that any suitable materials for downhole connections may be used. Some of the tubular members  270  include formation measurement equipment such as resistivity antennae for formation logging. Resistivity antennae are preferably located as close to the wall of the borehole as possible and thus on the outside of the tubular member  270  on which the antenna is located. To protect the antennae, each antenna is covered by an antenna sleeve  272  that slides over the outer diameter OD of the tubular members  270  with the antennae and held in place using securing rings  274 . Wear bands  276  may also be slid over the OD of the tubulars for overall protection of the BHA tools. 
     Because the OD of the entire BHA  216  must be small enough to fit within a given size borehole, the OD of the tubular members  270  with the antennae must be small enough to accommodate the antenna sleeves  272  yet remain within the OD specifications of the BHA  216  for the borehole. Thus, the portion of the connection  250  on these tubular members  270  will be a smaller OD than the portion of the connection  250  on other tubular members  270  not needing to accommodate the antenna sleeves  272  and smaller than would otherwise be specified for the tubular members  270  with the larger OD. If the smaller OD portion of the connection  250  were to connect directly with the larger OD, there is a risk that there would not be enough contact area between the two portions to ensure that stress distribution on the contact surfaces would be adequate to withstand drilling conditions. 
     To distribute stresses across the connections  250  to withstand drilling conditions, the connections  250  further include load distributions sleeves  280 . As shown more clearly in  FIGS.  3  and  4   , the threaded connection  250  comprises a pin end  251  with a threaded portion  254  on a cylindrical outer surface of a first tubular member  270 . The threaded connection  250  also includes a box end  258  with a threaded portion  260  on a cylindrical inner surface of a second tubular member  270 , the threaded portion  260  configured to threadedly engage with threaded portion  254 . Each tubular member  270  also includes an inner diameter (ID) for the flow of drilling fluid to a drill bit below the BHA  216 . 
     The first tubular member pin end  251  comprises a cylindrical tubular element having a first pin end OD  252 . The first tubular member pin end  251  also includes a neck section  253  with a neck OD  255  smaller than the first pin end OD  252 , thus creating a pin end external load shoulder  256  with a pin external load shoulder OD the same as the first pin end OD  252 . The length of the neck section  253  provides space for the load distribution sleeve  280  to slide over the pin end  251  and engage the pin end external load shoulder  256 . The length of the neck section  253  and the neck OD  255  also affect the stiffness of the pin end  251  and thus the first tubular member  270  and the connection  250 . The length of the neck section  253  may also be selected to provide allowance for re-machining the threads of threaded portion  254  of the pin end  251  to repair damage that may occur through operation. 
     The second tubular member  270  also may comprise a cylindrical tubular component, characterized by a box end OD  259  that is larger than the first pin end OD  253 . The second tubular member  270  also includes a box external load shoulder  262  formed by a face between the box end OD  259  and the second tubular member  270  ID. Thus, the box external load shoulder  262  has a box external load shoulder OD the same as the box OD  259  and different from the pin external load shoulder OD. Although the box external load shoulder OD is shown and being larger than the pin external load shoulder OD, it should be appreciated that the box external load shoulder OD may instead be smaller than the pin external load shoulder OD. 
     The connection  250  further includes a load distribution sleeve  280  located between the first and second tubular members  270  when threaded together. The load distribution sleeve  280  includes a first end  282  facing the first tubular member  270  and having an OD  284  matching the OD of the pin external load shoulder  256 . The load distribution sleeve  280  also includes a second end  286  facing the second tubular member  270  and having an OD  288  matching the OD of the box external load shoulder  262 . 
     The load distribution sleeve  280  is sized and positioned between the first and second tubular members  270  to contact the pin external load shoulder  256  on one side and the box external load shoulder  262  on the other side. The load distribution sleeve  280  thus receives axial make-up loads from the first and second tubular members  270  when the threads  204  and  210  are fully engaged, as is shown in  FIG.  4   . The magnitude of the make-up loads distributed by the load distribution sleeve  280  depends, in part, on the contact surface area between the ends of the load distribution sleeve  280  and the respective pin and box external load shoulders  256 ,  262 , and positively correlates with the torque limit of the threaded connection  250 . With the load distribution sleeve  280  having different ODs at each end, the contact surface area of the box end can be increased, as can be the torque limit of the threaded connection  250 . In addition to accommodating the load requirements for the connection  250 , the tubular members  270  and the load distribution sleeve  280  may also be designed to control overall joint stiffness control by controlling the ratio of the box end  258  stiffness to pin end  251  stiffness. 
     The connection  250  may comprise a “loaded” or “made up” connection between the threaded portion  254  with the threaded portion  260 , and the load distribution sleeve  280  contacting the respective pin and box external load shoulders  256 ,  262 . The combined frictional, axial, and radial forces acting on the first and second tubular members  270  and their corresponding parts may provide the interference fit and loaded connection that may improve the bending and torque load limit of the threaded connection  250 . 
     While any suitable materials may be used for the tubular members  270  and the load distribution sleeve  280 , there may be applications for the where the first tubular member  270  with a smaller pin end OD  253  may require enlargement of the ID for clearance of internal components while not being able to enlarge the pin end OD  253 . With less material, the strength of the connection  250  is weakened by the pin end  251 . If desired or needed, the yield strength of the pin end  251  material may be increased relative to the box end  258  material, thus increasing the torque capacity and, depending on material fatigue properties of the pin end  251 , the fatigue strength for the pin end  251  and for the overall connection  250 . The load distribution sleeve  280  with a higher yield strength allows the first tubular member  270  with a smaller OD with a higher yield strength to be balanced in strength with the lower strength tubular member  270  with the larger OD. Additionally, load distribution sleeve  280  may be a material selected to control galling. If the pin end  251  and the box end  258  are made from materials that tend to gall when moving against each other with a high contact force, damage can occur at the faces of the pin end external load shoulder  256  and the box external load shoulder  262 . To mitigate this galling, the load distribution sleeve  280  may be made of a self-lubricating material, for example a copper-beryllium alloy. 
       FIG.  5    is a diagram illustrating an alternative example threaded connection  550 . The threaded connection  550  is similarly between two tubular members  570  with a load distribution sleeve  580  that distributes make-up load when the connection  550  is made-up. Similarly, the pin end OD  553  is smaller than the box end OD  559 . However, the second tubular member  270  also includes a section with a decreased OD  557  that is smaller than the box end OD  559  as well as smaller than the first tubular member OD  553 . 
     Examples of the above embodiments include the following numbered examples: 
     Example 1 is a tubular string comprising a first tubular member comprising a pin end comprising pin threads and a pin external load shoulder. The tubular string also comprises a second tubular member comprising a box end comprising a box external load shoulder and box threads, the pin threads threadable into the box threads to form a connection, wherein the pin external load shoulder has an outer diameter (OD) that is different than an OD of the box external load shoulder. The tubular string also comprises a load distribution sleeve locatable between the first and second tubular members when threaded together and comprising a first end facing the first tubular member and a second end facing the second tubular member, wherein ODs of the load distribution sleeve first and second ends match the ODs of the pin and box external load shoulders respectively. Further, the load distribution sleeve contacts the pin and box external load shoulders and distributes a make-up load between the pin and box external load shoulders when the connection is made up. 
     Example 2. The tubular string of Example 1, wherein the OD of the pin external load shoulder is smaller than the OD of the box external load shoulder. 
     Example 3. The tubular string of Example 1, wherein the OD of the pin external load shoulder is larger than the OD of the box external load shoulder. 
     Example 4. The tubular string of Example 1, further comprising a protective sleeve slidable over the first tubular member. 
     Example 5. The tubular string of Example 4, wherein the protective sleeve has a sleeve OD matching the OD of the box external load shoulder. 
     Example 6. The tubular string of Example 1, wherein the first tubular member comprises a resistivity antennae and the tubular string further comprises an antennae sleeve slidable over the first tubular member. 
     Example 7. The tubular string of Example 1, wherein the tubular string comprises a drill string. 
     Example 8. The tubular string of Example 7, wherein the tubular string comprises a bottom-hole assembly. 
     Example 9. A method of forming a tubular string, comprising engaging a load distribution sleeve with a first tubular member comprising a pin end comprising pin threads and a pin external load shoulder such that a first end of the load distribution sleeve engages the pin external load shoulder. The method also comprises threading the pin threads into a box end of a second tubular member, the box end comprising a box external load shoulder and box threads, to engage a second end of the load distribution sleeve with the box external load shoulder and make up a connection and distribute a make up load between the pin and box external load shoulders with the load distribution sleeve. Further, the outer diameters (ODs) of the pin and box external load shoulders are different and ODs of the load distribution sleeve first and second ends match the ODs of the pin and box external load shoulders respectively. 
     Example 10. The method of Example 9, wherein the OD of the pin external load shoulder is smaller than the OD of the box external load shoulder. 
     Example 11. The method of Example 9, wherein the OD of the pin external load shoulder is larger than the OD of the box external load shoulder. 
     Example 12. The method of Example 9, further comprising sliding a protective sleeve over the first tubular member before the connection is made up. 
     Example 13. The method of Example 12, wherein the protective sleeve has a sleeve OD matching the OD of the box external load shoulder. 
     Example 14. The method of Example 9, wherein the tubular string comprises a drill string. 
     Example 15. The method of Example 14, further comprising at least one of drilling a borehole through a formation using the drill string or measuring properties of the formation using a sensor on the drill string. 
     Example 16. A threadable connection comprising a first tubular member comprising a pin end comprising pin threads and a pin external load shoulder. The connection also comprises a second tubular member comprising a box end comprising a box external load shoulder and box threads, the pin threads threadable into the box threads to form a connection, wherein the pin external load shoulder has an outer diameter (OD) that is different than an OD of the box external load shoulder. The connection also comprises a load distribution sleeve locatable between the first and second tubular members when threaded together and comprising a first end having an OD matching the OD of the box external load shoulder and a second end having an OD matching the OD of the pin external load shoulder. Further, the load distribution sleeve distributes a make up load between the pin and box external load shoulders when the connection is made up. 
     Example 17. The threadable connection of Example 16, wherein the OD of the pin external load shoulder is smaller than the OD of the box external load shoulder. 
     Example 18. The threadable connection of Example 16, wherein the OD of the pin external load shoulder is larger than the OD of the box external load shoulder. 
     Example 19. The threadable connection of Example 16, wherein the first and second tubulars are part of a drill string. 
     Example 20. The threadable connection of Example 16, wherein at least one of the first and second tubulars is part of a bottom-hole assembly. 
     Unless otherwise indicated, all numbers expressing quantities of ingredients, properties such as molecular weight, reaction conditions, and so forth used in the present specification and associated claims are to be understood as being modified in all instances by the term “about.” 
     The embodiments and examples disclosed are illustrative only and should not be interpreted, or otherwise used, as limiting the scope of the disclosure, including the claims. It is to be fully recognized that the different teachings of the embodiments discussed may be employed separately or in any suitable combination to produce desired results. In addition, one skilled in the art will understand that the description has broad application, and the discussion of any embodiment is meant only to be exemplary of that embodiment, and not intended to suggest that the scope of the disclosure, including the claims, is limited to that embodiment. Also, the terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee. The indefinite articles “a” or “an,” as used in the claims, are defined herein to mean one or more than one of the component that it introduces.