Patent Publication Number: US-11655678-B2

Title: Mud motor bearing assembly for use with a drilling system

Description:
BACKGROUND 
     Directional drilling involves drilling a borehole that deviates from a vertical path, such as drilling horizontally through a subterranean formation. Rotary steerable systems are employed to control the direction of a drill bit while drilling. In a point-the-bit rotary steerable system, an internal shaft within the system is deflected to direct the drill bit. In a push-the-bit rotary steerable system, a pad pushes against the subterranean formation to direct the bit. 
     A push-the-bit rotary steerable system includes a motor with a bearing section. The bearing section may be sealed and lubricated by internal oil, or unsealed and lubricated by drilling fluid flowing through the mud motor to the drill bit. For an unsealed bearing section, loss of drilling fluid to the annulus is inevitable due to bearing tolerances, manufacturing constraints, and erosive wear from the flowing mud. The fluid flow to annulus can be used to lubricate the bearing section, but the flow must be controlled to provide pad force to steer the drill bit while avoiding excess erosion. A need exists, therefore, for a means of controlling the bypass flow of drilling fluid to the annulus 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       Embodiments of the systems for plugging a well are described with reference to the following figures. The same 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 schematic view of a drilling system, according to one or more embodiments; 
         FIG.  2    is a portion of a drill string disposed in a borehole, according to one or more embodiments; 
         FIG.  3    is a cross-sectional view of the stator and rotor of  FIG.  2   ; 
         FIG.  4    is a bearing assembly, according to one or more embodiments; 
         FIG.  5    is a choke assembly positioned within the bearing assembly of  FIG.  4   ; and 
         FIG.  6    is a choke assembly for use with a bearing assembly, according to one or more embodiments. 
     
    
    
     DETAILED DESCRIPTION 
     The present disclosure provides a mud motor bearing assembly for use with a drilling system. The bearing assembly includes radial bearings, thrust bearings, and/or ball bearings or roller bearings that support a driveshaft that extends between the mud motor and a drillbit. The bearing assembly also includes a fluid flowpath through the bearings and into an annulus surrounding the bearing assembly that allows drilling fluid to pass through the bearings, lubricating and cooling the bearings. The bearing assembly also includes a choke assembly that restricts the flow of drilling fluid through the bearings. 
     Although the bearing assembly may be used with many types of drilling systems having a mud motor, the bearing assembly is particularly applicable to a motor-assisted rotary steerable system (“MARSS”). An MARRS utilizes drilling fluid that has passed through the mud motor and the bearing assembly, to extend pads to push the drill bit in a desired direction. By restricting the flow of drilling fluid through the bearings of the bearing assembly, the choke assembly maintains the drilling fluid passing through the bearing assembly to the pads at a sufficient pressure to extend the pads. 
     A subterranean formation containing oil or gas hydrocarbons may be referred to as a reservoir, in which a reservoir may be located on-shore or off-shore. Reservoirs are typically located in the range of a few hundred feet (shallow reservoirs) to tens of thousands of feet (ultra-deep reservoirs). To produce oil, gas, or other fluids from the reservoir, a well is drilled into a reservoir or adjacent to a reservoir. 
     A well can include, without limitation, an oil, gas, or water production well, or an injection well. As used herein, a “well” includes at least one borehole having a borehole wall. A borehole can include vertical, inclined, and horizontal portions, and it can be straight, curved, or branched. As used herein, the term “borehole” includes any cased, and any uncased, open-hole portion of the borehole. Further, the term “uphole” refers a direction that is towards the surface of the well, while the term “downhole” refers a direction that is away from the surface of the well. 
       FIG.  1    is a schematic view of a drilling system  100 , according to one or more embodiments. The drilling system  100  of the present disclosure will be specifically described below such that the system is used to direct a drill bit in drilling a wellbore, such as a subsea well or a land well. Further, it will be understood that the present disclosure is not limited to only drilling an oil well. The present disclosure also encompasses natural gas wellbores, other hydrocarbon wellbores, or wellbores in general. Further, the present disclosure may be used for the exploration and formation of geothermal wellbores intended to provide a source of heat energy instead of hydrocarbons. 
       FIG.  1    shows a drill string  102  disposed in a directional borehole  104 . The drill string  102  includes a push-the-bit rotary steerable system (“RSS”)  106  that provides full 3D directional control of the drill bit  108 . A drilling platform  110  supports a derrick  112  having a traveling block  114  for raising and lowering a drill string  102 . A kelly  116  supports the drill string  102  as the drill string  102  is lowered through a rotary table  118 . Alternatively, a top drive can be used to rotate the drill string  102  in place of the kelly  116  and the rotary table  118 . A drill bit  108  is positioned at the downhole end of the drill string  102  and is driven by rotation of the entire drill string  102  from the surface and/or by a downhole motor  120  positioned on the drill string  102 . As the bit  108  rotates, the bit  108  forms the borehole  104  that passes through various formations  122 . A pump  124  circulates drilling fluid through a feed pipe  126  and downhole through the interior of drill string  102 , through orifices in drill bit  108 , back to the surface via the annulus  128  around drill string  102 , and into a retention pit  130 . The drilling fluid transports cuttings from the borehole  104  into the pit  130  and aids in maintaining the integrity of the borehole  104 . The drilling fluid also drives the downhole motor  120 , as discussed in more detail below. 
     The drill string  102  may include one or more logging while drilling (LWD) or measurement-while-drilling (MWD) tools  132  that collect measurements relating to various borehole and formation properties as well as the position of the bit  108  and various other drilling conditions as the bit  108  extends the borehole  104  through the formations  122 . The LWD/MWD tool  132  may include a device for measuring formation resistivity, a gamma ray device for measuring formation gamma ray intensity, devices for measuring the inclination and azimuth of the drill string  102 , pressure sensors for measuring drilling fluid pressure, temperature sensors for measuring borehole temperature, etc. 
     The drill string  102  may also include a telemetry module  134 . The telemetry module  134  receives data provided by the various sensors of the drill string  102  (e.g., sensors of the LWD/MWD tool  132 ), and transmits the data to a surface unit  136 . Data may also be provided by the surface unit  136 , received by the telemetry module  134 , and transmitted to the tools (e.g., LWD/MWD tool  132 , rotary steering tool  106 , etc.) of the drill string  102 . Mud pulse telemetry, wired drill pipe, acoustic telemetry, or other telemetry technologies known in the art may be used to provide communication between the surface control unit  136  and the telemetry module  134 . The surface unit  136  may also communicate directly with the LWD/MWD tool  132  and/or the rotary steering tool  106 . The surface unit  136  may be a computer stationed at the well site, a portable electronic device, a remote computer, or distributed between multiple locations and devices. The unit  136  may also be a control unit that controls functions of the equipment of the drill string  102 . 
       FIGS.  2  and  3    are a broken side view and a cross section view of a drill string  202  disposed in a borehole  204  and that includes a downhole motor  220  connected to a drill bit  208 . The downhole motor  220  includes a tubular housing  200  that encloses a power unit  210 . The power unit  210  is connected to a bearing assembly  212  via a transmission unit  214 . The bearing assembly  212  supports a driveshaft (not shown) extending between the downhole motor  220  and the drill bit  208  to rotate the drill bit  208 . Referring to  FIG.  3   , the power unit  210  includes a stator  300  and a rotor  302 . The stator  300  includes multiple (e.g., five) lobes  304  extending along the stator  300  in a helical configuration and defining a cavity  306 . The rotor  302  also includes lobes  308  extending along the rotor  302  in a helical configuration. The stator  300  and rotor  302  can also have more or fewer lobes where the difference between the rotor lobes  308  and stator lobes  304  is one extra stator lobe  304  for the number of rotor lobes  308 . 
     The rotor  302  is operatively positioned in the cavity  306  such that the rotor lobes cooperate with the stator lobes  304  in that applying fluid pressure to the cavity  306  by flowing fluid within the cavity  306  causes the rotor  302  to rotate within the stator  300 . For example, referring to  FIGS.  2  and  3   , pressurized drilling fluid (e.g., drilling mud)  216  can be introduced at an upper end of the power unit  210  and forced down through the cavity  306 . The pressurized drilling fluid entering cavity  306 , in cooperation with the lobes  304  of the stator  300  and the geometry of the stator  300  and the rotor  302  causes the rotor  302  to turn to allow the drilling fluid  216  to pass through the motor  220 , thus rotating the rotor  302  relative to the stator  300 . The drilling fluid  216  subsequently exits through ports (e.g., jets) in the drill bit  208  and travels upward through an annulus  228  between the drill string  202  and the borehole  204  and is received at the surface where it is captured and pumped down the drill string  202  again. 
     As shown in  FIG.  2   , a RSS  206  is positioned on the drill string  202  downhole of the downhole motor  220 . Drilling fluid  216  passes through the downhole motor  220  and then through the bearing assembly  212 , where a portion of the drilling fluid  216  is diverted and used to cool and lubricate the bearings within the bearing assembly  212 , as described in more detail below. The diverted drilling fluid  216  passes through the bearings and into the annulus  228 . After the drilling fluid that was not diverted passes through the bearing assembly  212 , the drilling fluid  216  provides the hydraulic pressure necessary to extend pads (one indicated,  218 ) of the RSS  206  to direct the drill bit  208 . In order to provide sufficient pressure to extend the pads  218  of the RSS  206 , the amount of drilling fluid  216  diverted through the bearings must be controlled to maintain the amount of hydraulic pressure available to extend the pads  218  above an appropriate amount. 
     Turning now to  FIG.  4   ,  FIG.  4    is a bearing assembly  412 , according to one or more embodiments. The bearing assembly  412  includes radial bearing assemblies  400  and ball bearings  402  or roller bearings (not shown) that are positioned circumferentially around a driveshaft  404  that extends between a downhole motor (not shown) and a drill bit (not shown) to support the driveshaft  404 . The bearing assembly  412  may also include thrust bearings (not shown). 
     A fluid flowpath  406  extends from the bore of the driveshaft  404 , through the bearings  400 ,  402 . As discussed above, a portion of drilling fluid passing through the driveshaft  404  is diverted through the fluid flowpath  406  to cool and lubricate the bearings  400 ,  402 . A choke assembly  408 , discussed in more detail below, is disposed within the fluid flowpath  406 . The choke assembly  408  controls the amount of fluid that passes through the fluid flowpath  406  and into an annulus  428  surrounding the bearing assembly  412 , for example, by restricting flow out of the flowpath  406  and into the annulus. By controlling the amount of drilling fluid passing into the annulus via the fluid flowpath  406 , sufficient hydraulic pressure is maintained in the drilling fluid flowing through the driveshaft  404  to extend the pads of the RSS (not shown). 
     In at least one embodiment, one or both of the radial bearing assemblies  400  may also act to restrict the flow of fluid through the fluid flowpath  406 . Specifically, a gap  410  formed between an inner cylinder  414  and an outer cylinder  416  may be sized to restrict the flow of fluid through the gap  410  and, thus, the fluid flowpath  406 . 
     Turning now to  FIG.  5   ,  FIG.  5    is the choke assembly  408  positioned within the fluid flowpath  406  of the bearing assembly  412  of  FIG.  4   . The choke assembly  408  includes a choke  500  that contacts a seat  502  to restrict the amount of drilling fluid passing through the fluid flowpath  406 . A biasing mechanism  504 , such as a spring, exerts a biasing force on the choke  500  in a downhole direction based on the expected pressure of the drilling fluid and the pressure within the borehole annulus. In other embodiments, the seat  502  may be uphole of the choke  500  and the biasing mechanism  504  may exert a biasing force on the choke in an uphole direction based on the expected pressure of the drilling fluid and the pressure within the borehole annulus. 
     The choke  500  and the seat  502  control the amount of drilling fluid that is diverted from the driveshaft to cool and lubricate the bearings. The baising force shifts the choke  500  into contact with the seat such that the exemplary choke assembly  408  maintains hydraulic pressure available for pads. For example, the choke assembly may only allow a range between approximately 1% and approximately 7% of the drilling fluid passing through the driveshaft  404  to be diverted into the fluid flowpath  406 . Additionally, the choke  500  and/or the seat may include channels (not shown) extending axially through the choke  500  and/or the seat  502  to ensure that between approximately 1% and approximately 7% of the drilling fluid can pass through the choke assembly  408  when the choke  500  contacts the seat. However, other choke assemblies  408  may allow less than 1% or more than 7% of the drilling fluid to pass through the fluid flowpath  406  as appropriate. 
     The choke assembly  408  also includes one or more keys  506  coupled to or integral with the choke  500  that engage with one or more respective slots  508  formed in an inner housing  510  surrounding the driveshaft  404  or the driveshaft  404  itself. Once the choke  500  is installed around the inner housing  510 , the key  506  and slot  508  allow relative axial movement between the choke  500  and the inner housing  510  such that the choke  500  can contact the seat  502 , but prevent relative rotational movement between the choke  500  and the inner housing  510 , since relative rotation between the choke  500  and the seat  502  can cause increased wear on the choke  500  and/or seat  502 . 
     Turning now to  FIG.  6   ,  FIG.  6    is another embodiment of a choke assembly  608  for use with a bearing assembly, according to one or more embodiments.  FIG.  6    includes features that are similar to the features described above with reference to  FIG.  5   . Accordingly, such features will not be described again in detail, except as necessary for the understanding of the choke assembly  608  shown in  FIG.  6   . 
     The choke assembly  608  includes a tortuous flowpath  600  created between an outer labyrinth choke portion  602  coupled to or integral with an outer housing  612  surrounding a driveshaft  604  and an inner labyrinth choke portion  614  coupled to or integral with an inner housing  610  surrounding the driveshaft  604 . The tortuous flowpath  600  controls the amount of drilling fluid that is diverted from the driveshaft to cool and lubricate the bearings. As there is no key assembly within the choke assembly  608 , the inner labyrinth choke may rotate relative to the outer labyrinth choke. Similar to the choke assembly  408  described above with reference to  FIG.  5   , the exemplary choke assembly  608  is shaped to only allow a range between approximately 1% and approximately 7% of the drilling fluid passing through the driveshaft  604  to be diverted into the fluid flowpath  606 . However, other choke assemblies  608  may allow less than 1% or more than 7% of the drilling fluid to pass through the fluid flowpath  606 . 
     Further examples include: 
     Example 1 is a drilling system for drilling a borehole. The drilling system includes a drill string, a drill bit coupled to the drill string, a mud motor coupled to the drill string uphole of the drill bit and operable to rotate the drill bit via a driveshaft, a bearing assembly coupled to a downhole end of the mud motor and operable to support the driveshaft, and a rotary steerable system (“RSS”) operable to push the drill bit in a desired direction via pads extended using drilling fluid flowing through the driveshaft and to the RSS. The bearing assembly includes bearings positioned circumferentially around a bore of the bearing assembly, a fluid flowpath through the bearings to allow drilling fluid to pass through the bearings, and a choke assembly positioned in the fluid flowpath and operable to restrict a flow of the drilling fluid through the fluid flowpath. 
     In Example 2, the embodiments of any preceding paragraph or combination thereof further include wherein the choke assembly includes a choke axially movable within the fluid flowpath to contact a seat and restrict fluid flow through the fluid flowpath and a biasing mechanism positioned within the fluid flowpath to bias the choke into contact with the seat. 
     In Example 3, the embodiments of any preceding paragraph or combination thereof further include wherein the choke assembly further includes a key coupled to the choke and positioned in a slot formed in an inner housing surrounding the driveshaft to prevent relative rotational movement between the inner housing and the choke and allow relative axial movement between the inner housing and the choke. 
     In Example 4, the embodiments of any preceding paragraph or combination thereof further include wherein the bearings comprise a radial bearing assembly shaped to restrict the flow of the drilling fluid through the fluid flowpath. 
     In Example 5, the embodiments of any preceding paragraph or combination thereof further include wherein the choke assembly includes a tortuous flowpath to restrict the flow of drilling fluid through the fluid flowpath. 
     In Example 6, the embodiments of any preceding paragraph or combination thereof further include wherein an outer labyrinth choke portion and an inner labyrinth choke portion are positioned within the fluid flowpath to form the tortuous flowpath. 
     In Example 7, the embodiments of any preceding paragraph or combination thereof further include wherein the fluid flowpath exits the bearing assembly to an annulus surrounding the bearing assembly. 
     In Example 8, the embodiments of any preceding paragraph or combination thereof further include wherein the choke assembly allows a range between approximately 1% and approximately 7% of the drilling fluid flowing through the drill string to be diverted into the fluid flowpath. 
     In Example 9, the embodiments of any preceding paragraph or combination thereof further include wherein the choke assembly is operable to restrict the flow of drilling fluid such that a pressure of the drilling fluid flowing through the driveshaft is sufficient to extend the pads of the RSS. 
     Example 10 is a method of drilling a borehole. The method includes pumping drilling fluid down a drill string within the borehole to a mud motor, a bearing assembly, a RSS, and a drill bit. The method also includes rotating a drill bit with the mud motor via a driveshaft. The method further includes extending pads of the RSS via the drilling fluid passing through the driveshaft to push a drill bit in a desired direction using the drilling fluid. The method also includes diverting a portion of the drilling fluid through bearings of the bearing assembly. The method further includes restricting a flow of the drilling fluid through the bearings via a choke assembly. 
     In Example 11, the embodiments of any preceding paragraph or combination thereof further include wherein restricting the flow of the drilling fluid through the bearings via the choke assembly includes biasing a choke of the choke assembly positioned within a fluid flowpath through the bearings against a seat of the choke assembly positioned within the fluid flowpath. 
     In Example 12, the embodiments of any preceding paragraph or combination thereof further include preventing relative rotational movement between the choke and an inner housing of the choke assembly. 
     In Example 13, the embodiments of any preceding paragraph or combination thereof further include restricting the flow of the drilling fluid through the bearings via the choke assembly includes restricting the flow of the drilling fluid through the bearings via a tortuous flowpath formed by the choke assembly. 
     In example 14, the embodiments of any preceding paragraph or combination thereof further include flowing the portion of the fluid from the bearings to an annulus surrounding the bearing assembly. 
     In Example 15, the embodiments of any preceding paragraph or combination thereof further include wherein restricting the flow of the drilling fluid through the bearings via the choke assembly includes restricting the flow of the drilling fluid through the bearings via the choke assembly such that a pressure of the drilling fluid flowing through the driveshaft is sufficient to extend the pads of the RSS. 
     Example 16 is bearing assembly for use with a downhole motor rotated via drilling fluid. The bearing assembly includes bearings positioned circumferentially around a bore of the bearing assembly to support a driveshaft extending from the downhole motor, a fluid flowpath through the bearings to allow drilling fluid to pass through the bearings, and a choke assembly positioned in the fluid flowpath and operable to restrict a flow of the drilling fluid through the fluid flowpath. 
     In Example 17, the embodiments of any preceding paragraph or combination thereof further include wherein the choke assembly includes a choke axially movable within the fluid flowpath to contact a seat and restrict fluid flow through the fluid flowpath and biasing mechanism positioned within the fluid flowpath to bias the choke into contact with the seat. 
     In Example 18, the embodiments of any preceding paragraph or combination thereof further include wherein the choke assembly further includes a key coupled to the choke and positioned in a slot formed in an inner housing surrounding the driveshaft to prevent relative rotational movement between the inner housing and the choke and allow relative axial movement between the inner housing and the choke. 
     In Example 19, the embodiments of any preceding paragraph or combination thereof further include wherein the choke assembly includes a tortuous flowpath to restrict the flow of drilling fluid through the fluid flowpath. 
     In Example 20, the embodiments of any preceding paragraph or combination thereof further include wherein the fluid flowpath exits the bearing assembly to an annulus surrounding the bearing assembly. 
     Certain terms are used throughout the description and claims to refer to particular features or components. As one skilled in the art will appreciate, different persons may refer to the same feature or component by different names. This document does not intend to distinguish between components or features that differ in name but not function. 
     As used herein, a range that includes the term between is intended to include the upper and lower limits of the range; e.g., between 50 and 150 includes both 50 and 150. Additionally, the term “approximately” includes all values within 5% of the target value; e.g., approximately 100 includes all values from 95 to 105, including 95 and 105. Further, approximately between includes all values within 5% of the target value for both the upper and lower limits; e.g., approximately between 50 and 150 includes all values from 47.5 to 157.5, including 47.5 and 157.5. 
     Reference throughout this specification to “one embodiment,” “an embodiment,” “embodiments,” “some embodiments,” “certain embodiments,” or similar language means that a particular feature, structure, or characteristic described in connector with the embodiment may be included in at least one embodiment of the present disclosure. Thus, these phrases or similar language throughout this specification may, but do not necessarily, all refer to the same embodiment. 
     The embodiments disclosed 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.