WO2020087084A1

WO2020087084A1 - Downhole tools with high yield torque connections

Info

Publication number: WO2020087084A1
Application number: PCT/US2019/058403
Authority: WO
Inventors: Sean Matthew DONALD
Original assignee: National Oilwell DHT, L.P.
Priority date: 2018-10-27
Filing date: 2019-10-28
Publication date: 2020-04-30

Abstract

A friction reducing tool (FRT) for reciprocating a drill string, the FRT including an outer housing having a central axis, a first end, a second end opposite the first end, and a passage extending axially from the first end to the second end, wherein the first end includes a rig connection configured to directly connect to a first drill pipe and the second end includes a rig connection configured to directly connect to a second drill pipe, wherein the outer housing includes a plurality of tubular members connected end-to-end with a plurality of single-shouldered body connections, wherein each single-shouldered body connection has a bending strength ratio (BSR) between 1.8 and 2.5.

Description

DOWNHOLE TOOLS WITH HIGH YIELD TORQUE CONNECTIONS

CROSS-REFERENCE TO RELATED APPLICATIONS

[0001] The present application claims benefit of U.S. provisional patent application No. 62/751 ,563 filed October 27, 2018, entitled“Downhole Tools with High Torque Body Connections,” which is incorporated herein by reference in its entirety for all purposes.

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

[00G2] Not applicable.

BACKGROUND

[0003] The disclosure relates generally to downhole tools used in drilling systems. More particularly, the disclosure relates to downhole friction reduction tools disposed along a drill string uphoie of a bottomhole assembly of the drilling system. Still more particularly, the disclosure relates to downhole friction reduction tools that include high yield torque rig connections on the terminal ends of the friction reduction tool and high- yield torque body connections located between the terminal ends of the friction reduction tool.

[0004] Drilling systems are utilized to locate and recover hydrocarbons from subterranean earthen formations. In some drilling systems, an earth-boring drill bit is mounted on the lower end of a drill string of the drilling system and rotated to penetrate into the earthen formation. The drill bit may be rotated by rotating the drill string at the surface and/or by actuating a downhole motor or turbine of the drilling system that is connected between the drill bit and the lower end of the drill string. With weight applied to the drill string, the rotating drill bit engages the earthen formation and thereby forms a borehole along a predetermined path toward a target zone located in the earthen formation.

[0005] During drilling, the drill string may frictionally engage or rub against a sidewall of the borehole, thereby reducing the rate of penetration (ROP) of the drill bit through the earthen formation and/or increasing the necessary weight-on-bit (WOB) applied to the drill bit. A reduction of ROP and/or an increase in the required WOB applied to the drill bit may lead to a condition known as“stick slip” whereby the drill string cyclically sticks to and releases from the borehole wall, generating potentially damaging vibrations through the drill string. Accordingly, various downhole tools that induce vibration and/or axial reciprocation may be included in the drill string to reduce friction between the drill string and the wall of the borehole. One such friction reducing tool is an oscillation tool, which typically includes a pressure pulse generator and a shock tool. The pressure pulse generator of the oscillation tool produces pressure pulses in drilling fluid flowing through the pressure pulse generator and the shock tool converts the pressure pulses generated in the drilling fluid into axial reciprocation of at least a portion of the drill string to thereby prevent the drill string from sticking to the borehole wail.

SUMMARY

[0006] An embodiment of a drilling assembly for drilling a borehole in a subterranean earthen formation comprises a drill string rotatable in the borehole, a friction reducing tool coupled to the drill string, wherein the friction reducing tool comprises an outer housing having a central axis, a first end, a second end opposite the first end, and a passage extending axially from the first end to the second end, wherein the first end comprises a rig connection configured to directly connect to a drill pipe and the second end comprises a rig connection configured to directly connect to a drill pipe, wherein the outer housing comprises a plurality of tubular members connected end-to-end with a plurality of body connections, wherein each body connection has a yield torque of at least 30,000 foot-pounds, a bottomhole assembly (BHA) coupled to the friction reducing tool, wherein the BHA comprises a drill bit configured to drill into the subterranean earthen formation. In some embodiments, the yield torque of each body connection of the friction reducing tool is at least 40,000 foot-pounds. In some embodiments, the friction reducing tool is positioned along the drill string such that a portion of the drill string extends between the friction reducing tool and the BHA. In certain embodiments, the friction reducing tool comprises an outer housing having a central axis, a first end, a second end opposite the first end, and a passage extending axially from the first end to the second end, wherein the first end comprises a rig connection configured to directly connect to a first drill pipe of the driilstring and the second end comprises a rig connection configured to directly connect to a second drill pipe of the drill string, wherein the outer housing comprises a plurality of tubular members connected end-to-end with a plurality of single-shouldered body connections, wherein each single-shouldered body connection has a bending strength ratio (BSR) between 1.8 and 2.5. In certain embodiments, the BSR of each single- shouldered body connection of the friction reducing tool is between 2.0 and 2.2. In certain embodiments, the friction reducing too! comprises an outer housing having a central axis, a first end, a second end opposite the first end, and a passage extending axially from the first end to the second end, wherein the first end comprises a rig connection configured to directly connect to a first drill pipe of the drill string and the second end comprises a rig connection configured to directly connect to a second drill pipe of the drill string; wherein the outer housing comprises a plurality of tubular members connected end-to-end with at least one double-shouldered body connection, wherein the double-shouldered body connection has a bending strength ratio (BSR) between 0.8 and 1.4. In some embodiments, the BSR of each double-shouldered body connection of the friction reducing fool is between 1.10 and 1.15. In some embodiments, the friction reducing tool is coupled between a lower end of the drill string and the BHA. In some embodiments, the friction reducing tool comprises a pressure pulse generator configured to cyclically generate pressure pulses in a drilling fluid, and a shock tool configured to translate the pressure pulses generated by the pressure pulse generator into reciprocation of the drill string.

[0007] An embodiment of a friction reducing tool for reciprocating a drill string comprises an outer housing having a central axis, a first end, a second end opposite the first end, and a passage extending axially from the first end to the second end, wherein the first end comprises a rig connection configured to directly connect to a first drill pipe and the second end comprises a rig connection configured to directly connect to a second drill pipe, wherein the outer housing comprises a plurality of tubular members connected end-to-end with a plurality of single-shouldered body connections, wherein each single-shouldered body connection has a bending strength ratio (BSR) between 1.8 and 2.5. In some embodiments, the BSR of each single- shouldered body connection of the friction reducing tool is between 2.0 and 2.2. In some embodiments, each single-shouldered body connection has a first outer diameter and a first BSR corresponding to an initial condition of the single-shouldered body connection, and a second outer diameter and a second BSR corresponding to a worn condition of the sing!e-shou!dered body connection, and wherein the first outer diameter is greater than the second outer diameter and the first BSR is greater than the second BSR. In certain embodiments, the first BSR is approximately 2.1 and the second BSR is approximately 1.8. In certain embodiments, the plurality of tubular members are connected end-to-end with at least one double-shouldered body connection, wherein the double-shouldered body connection has a BSR between 0.8 and 1.4. In some embodiments, the BSR of the double-shouldered body connection has a BSR between 1.10 and 1.15.

[0008] An embodiment of a friction reducing tool for reciprocating a drill string comprises an outer housing having a central axis, a first end, a second end opposite the first end, and a passage extending axially from the first end to the second end, wherein the first end comprises a rig connection configured to directly connect to a first drill pipe and the second end comprises a rig connection configured to directly connect to a second drill pipe, wherein the outer housing comprises a plurality of tubular members connected end-to-end with at least one double-shouldered body connection, wherein the double-shouldered body connection has a bending strength ratio (BSR) between 0 8 and 1.4. In some embodiments, the BSR of the double-shouldered body connection has a BSR between 1.10 and 1.15. In some embodiments, the plurality of tubular members are connected end-to-end with a plurality of single-shouldered body connections, wherein each single-shouldered body connection has a BSR between 1.8 and 2.5 In certain embodiments, the BSR of each single-shouldered body connection of the friction reducing tool is between 2.0 and 2.2. In certain embodiments, the friction reducing tool comprises a pressure pulse generator configured to cyclically generate pressure pulses in a drilling fluid, and a shock tool configured to translate the pressure pulses generated by the pressure pulse generator into reciprocation of the drill string.

BRIEF DESCRIPTION OF THE DRAWINGS

[0G09] For a detailed description of exemplary embodiments of the disclosure, reference will now be made to the accompanying drawings in which:

[0010] Figure 1 is a schematic view of a drilling system including an embodiment of a friction reducing tool in accordance with the principles described herein;

[0011] Figure 2 is a side view of the friction reducing tool of Figure 1 ;

[0012] Figure 3 is a side cross-sectional side view of a first portion of the friction reducing tool of Figure 2;

[0013] Figure 4 is a side cross-sectional side view of a second portion of the friction reducing tool of Figure 2; [0014] Figure 5 is a side cross-sectional side view of a third portion of the friction reducing too! of Figure 2;

[0015] Figure 8 is zoomed-in, side cross-sectional view of an embodiment of a first body connection of the friction reducing tool of Figure 2; and

[0016] Figure 7 is zoomed-in, side cross-sectional view of an embodiment of a second body connection of the friction reducing tool of Figure 2

DETAILED DESCRIPTION

[0617] The following discussion is directed to various exemplary embodiments. However, one skilled in the art will understand that the examples disclosed herein have broad application, and that 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.

[0018] Certain terms are used throughout the following 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. The drawing figures are not necessarily to scale. Certain features and components herein may be shown exaggerated in scale or in somewhat schematic form and some details of conventional elements may not be shown in interest of clarity and conciseness.

[0019] In the following discussion and in the claims, the terms “including” and “comprising” are used in an open-ended fashion, and thus should be interpreted to mean“including, but not limited to... Also, the term“couple” or“couples” is intended to mean either an indirect or direct connection. Thus, if a first device couples to a second device, that connection may be through a direct connection of the two devices, or through an indirect connection that is established via other devices, components, nodes, and connections. In addition, as used herein, the terms“axial” and“axially” generally mean along or parallel to a particular axis (e.g., central axis of a body or a port), while the terms “radial” and “radially” generally mean perpendicular to a particular axis. For instance, an axial distance refers to a distance measured along or parallel to the axis, and a radial distance means a distance measured perpendicular to the axis. Any reference to up or down in the description and the claims is made for purposes of clarity, with“up”,“upper”,“upwardly”,“uphole", or“upstream” meaning toward the surface of the borehole and with “down”, lower, “downwardly”, “downhole”, or “downstream” meaning toward the terminal end of the borehole, regardless of the borehole orientation. As used herein, the terms“approximately,” “about,”“substantially,” and the like mean within 10% (i.e., plus or minus 10%) of the recited value. Thus, for example, a recited angle of“about 80 degrees” refers to an angle ranging from 72 degrees to 88 degrees.

[0020] In general, tools positioned along the drill string between the BHA and the drilling rig may experience higher torques and bending loads as compared to tools positioned in the BHA. Friction reducing tools (FRTs) such as oscillation tools and jars are often positioned along the drill string uphole of the bottomhole assembly (BHA) (between the BHA and the drilling rig). Other types of tools such as circulation subs may also be positioned along the drillstring, particularly in drilling applications including horizontal or deviated boreholes. Accordingly, such tools must be forsionally robust enough to survive placement in the drill string.

[0021] The plurality of joints (i.e., drill pipe joints) connected end-to-end to form the drill string are often outfitted with premium rig connections at their ends, which are typically double-shouldered connections that possess relatively high torque capacity as compared to the connections between the downhole tools and the drill string, as well as the body connections within the interconnected tubulars within the downhole tools themselves. Accordingly, embodiments disclosed herein are intended to equip downhole tools, including FRTs, with body connections with a yield torque or strength that is as great or greater than the maximum Make-Up Torque (MUT) of the rig connections on high strength drill pipe (e.g., at least S-135 grade).

[0022] Referring now to Figure 1 , a schematic view of an embodiment of a drilling system 10 is shown. In the embodiment of Figure 1 , drilling system 10 includes a derrick 11 positioned at the surface 3 and having a floor 12 supporting a rotary table 14 and a drilling assembly 90 for drilling a borehole 28 from derrick 11 , where borehole 26 extends through a subterranean earthen formation 5. Rotary table 14 is rotated by a prime mover such as an electric motor (not shown) at a desired rotational speed and controlled by a motor controller (not shown). In other embodiments, the rotary table (e.g., rotary table 14) may be augmented or replaced by a top drive suspended in the derrick (e.g., derrick 1 1 ) and connected to the drill siring (e.g., drill string 20). [0023] Drilling assembly 90 of drilling system 10 includes a drill string 20, a mud motor 55, a bottomhole assembly (BHA) 56, and a downhole tool 100. Drill string 20 is made of a plurality of pipe joints 22 connected end-to-end with premium high torque rig connections (pin and box ends), and extends downward from the rotary table 14 through a pressure control device 15, such as a blowout preventer (BOP), into the borehole 26 As used herein, the term“rig connection” is defined as a threaded connection formed at a terminal end of a downhole tool. Rig connections are used, for instance, to connect downhole tools to a drill string (e.g., drill string 20 of drilling system 10) or a BHA (e.g., BHA 56 of drilling system 10). Conversely, as used herein, the term “body connection” is defined as a threaded connection formed within a downhole tool itself and located between terminal ends of the downhole tool. Body connections are generally not used to connect a terminal end of a downhole tool to a drill string or BHA, but rather are provided to ease the process of assembling/disassembling the downhole tool prior to its connection to the drill string or BHA.

[0024] As shown in Figure 1 , downhole tool 100 is connected between a lower end of drill string 20 and BHA 56 of drilling assembly 90. In this embodiment, downhole tool 100 is a friction reducing tool (FRT), and more specifically an oscillation tool. Accordingly, tool 100 may be referred to herein as FRT 100 or oscillation tool 100. The bottomhole assembly 56 of drilling assembly 90 includes a drill bit 21 coupled to the lower end of drill string 20 below FRT 100 and mud motor 55. Although in this embodiment FRT 100 is coupled between the lower end of drill string 20 and BHA 56, in other embodiments, FRT 100 may be disposed at other positions along the drill string 20 such that a portion of drill string 20 extends between FRT 100 and BHA 56 Additionally, in some embodiments, a plurality of FRTs 100 may be positioned along drill string 20. Drill bit 21 is rotated with weight-on-bit (WOB) applied thereto drill the borehole 26 through earthen formation 15. Drill string 20 is also coupled to a drawworks 30 positioned at the surface 3 via a kelly joint 21 , swivel 28, and a line or cable 29 from which swivel 28 is suspended.

[0025] During drilling operations, drawworks 30 is operated to control the WOB applied to drill bit 21 , which impacts the rate-of-penetration (ROP) of drill bit 21 through earthen formation 15. Drill bit 21 may be rotated from the surface 3 by drill string 20 using rotary table 14, and or by the mud motor 55 disposed proximal drill bit 21. For instance, drill bit 21 may be rotated by both rotary table 14 via drill string 20 and mud motor 55. Rotation of drill bit 21 using downhole motor 55 may be employed to supplement the rotational power of rotary table 14, if required, and/or to effect changes in the drilling process. In either case, the rate-of- penetration (ROP) of the drill bit 21 into the borehole 26 for a given formation and a given drilling assembly largely depends upon the WOB and the rotational speed of drill bit 21. In some embodiments, drill hit 21 may be rotated by drill string 20 using a top drive positioned at the surface 3 rather than the rotary table 14 shown in Figure 1. Particularly, drill bit 21 may rotated from the surface using rotary table 14 when drilling system 10 is in a straight or rotary drilling mode; and drill bit 21 may be rotated by downhole motor 55 when drilling system 10 is in a directional drilling mode.

[0026] In this embodiment, during drilling operations a suitable drilling fluid 31 is pumped under pressure from a mud tank 32 positioned at the surface 3 through the drill string 20 by a mud pump 34 positioned at the surface 3. Drilling fluid 31 passes from the mud pump 34 into the drill string 20 via a desurger 36, fluid line 38, and the kelly joint 21. The drilling fluid 31 pumped down drill string 20 flows through mud motor 55 and is discharged at the bottom of borehole 26 through nozzles formed in a face of drill bit 21 Once discharged from drill bit 21 , the drilling fluid 31 circulates to the surface 3 through an annulus 27 radially positioned between an outer surface of drill string 20 and a sidewall of borehole 26, and then returns to mud tank 32 via a solids control system 36 and a return line 35 positioned at the surface 3. Solids control system 36 may include any suitable solids control equipment known in the art including, without limitation, shale shakers, centrifuges, and/or automated chemical additive systems. Control system 36 may include sensors and automated controls for monitoring and controlling, respectively, various operating parameters of drilling system 10. It should be appreciated that much of the surface equipment for handling the drilling fluid is application specific and may vary on a case-by-case basis.

[0027] Referring to Figures 2-5, the FRT 100 of the drilling system of Figure 1 is shown. While drilling, one or more portions of drill string 20 may contact and slide along the sidewall of borehole 26. FRT 100 is provided along drill string 20 above mud motor 55 and BHA 56 to reduce friction between drill string 20 and the sidewall of borehole 26 As described above, FRT 100 has a central or longitudinal axis 105 (Figures 3-5) and includes a pressure pulse generator 110 coupled to motor 55 and a shock tool 150 coupled to pulse generator 110. Pulse generator 110 generates cyclical pressure pulses in the drilling fluid flowing down drill string 20 and shock tool 150 cyclically and axially extends and retracts as will be described in more detail below. With bit 21 disposed on the bottom of the borehole, the axial extension and retraction of shock tool 150 induces axial reciprocation in the portion of drill string above FRT 100, which reduces friction between drill string 20 and the sidewall of borehole.

[0028] The pulse generator 110 of FRT 100 has a terminal first or upper end 112 and a terminal second or lower end 114 opposite upper end 112 and defining a terminal lower end of FRT 100. In the embodiment of Figures 1-5, pulse generator 110 generally includes a pulse generator assembly or mechanism 116 housed within an outer housing 118. Pulse generator assembly 116 of pulse generator 110 comprises components configured to generate pressure pulses receivable by the shock tool 150 positioned above pulse generator 110. In this embodiment, pulse generator assembly 116 generally includes a rotor 120 rotatably disposed in outer housing 118 and a valve assembly 122 for creating and transmitting fluid pressure pulses to the shock tool 150; however, in other embodiments, the configuration of pulse generator assembly 116 may vary.

[0029] Outer housing 118 of pulse generator 110 includes a plurality of tubular members threadably connected end-to-end, where at least one of the tubular members comprises a stator housing 124 in which rotor 120 is received. In this embodiment, outer housing 118 of pulse generator 110 includes a plurality of body pin connectors 200 and a plurality of mating body box connectors 230 each axially spaced from the ends 112, 114 of pulse generator 110. In this embodiment, body pin connectors 200 and body box connectors 230 each comprise single-shouldered threaded connectors, and thus, may also referred to herein as single-shouldered pin connectors 200 and single-shouldered box connectors 230. The outer housing 118 of pulse generator 100 also includes a rig pin connector 250 that defines the lower end 114 of pulse generator 110. Rig pin connector 250 comprises a double shouldered connector and forms a rig connection with a mating double-shouldered, rig box connector of mud motor 55.

[0030] As best shown in Figures 2-4, the shock tool 150 of FRT 100 has a first or upper terminal end 152 and a second or lower terminal end 154 opposite upper end 152. In this embodiment, shock tool 150 generally includes a mandrel 156 that extends at least partially through a surrounding outer housing 158. Mandrel 116 is permitted to travel axially relative to outer housing 158 to thereby permit drill string 20 to reciprocate relative to outer housing 158. In this embodiment, shock tool 150 also includes an annular biasing member 160 positioned radially between mandrel 156 and outer housing 158 for assisting in the transmission of reciprocating motion to drill string 20. Although in this embodiment shock tool 150 comprises mandrel 156 and biasing member 160, in other embodiments, the configuration of shock tool 150 may vary.

[0031] Outer housing 158 of shock tool 150 includes a plurality of tubular members coupled end-to-end, where at least one of the tubular members comprises a biasing member housing 162 in which biasing member 160 is received. In this embodiment, outer housing 158 of shock tool 150 includes a plurality of body pin connectors 200 and a plurality of mating body box connectors 230, each connector 200, 230 axially spaced from the ends 152, 154 of shock tool 150. Additionally, mandrel 156 of shock tool 150 includes a rig box connector 270 that defines the upper end 152 of shock tool 150. Rig box connector 270 comprises a double-shouldered connector and forms a rig connection with a corresponding double-shouldered, rig pin connector positioned at the lower end of drill string 20.

[0032] In this embodiment, as shown particularly in Figure 4, along with pulse generator 1 10 and shock tool 150, FRT 100 includes a pair of intermediate tubular members or subs 170, 180 coupled between pulse generator 110 and shock tool 150 A first intermediate sub 170 of the intermediate subs 170, 180 includes a first or upper end defined by a body pin connector 200 and a second or lower end defined by a body pin connector 290 that comprises a double-shouldered threaded connector, and thus, may also be referred to herein as double-shouldered pin connector 290. A second intermediate sub 180 of the intermediate subs 170, 180 includes a first or upper end defined by a body box connector 310 and a second or lower end defined by a body pin connector 200. Body box connector 310 of the second intermediate sub 180 comprises a double-shouldered threaded connector, and thus, is also referred to herein as double-shouldered box connector 310. In this configuration, body box connector 310 of second intermediate sub 180 to threadab!y connects to the body pin connector 290 of first intermediate sub 170 to form a double-shouldered, rotary threaded connection therebetween.

[0G33] Referring to Figure 6, one body pin connector 200 and the mating body box connector 230 of the FRT 100 is shown. Particularly, Figure 6 illustrates the upper end of first intermediate sub 170 including the body boxy connector 230 of first intermediate sub 170, and a lowermost tubular member 159 of the outer housing 158 of shock tool 150, including the body pin connector 200 which defines a lower end of lowermost tubular member 159. Figure 6 illustrates first intermediate sub 170 and lowermost tubular member 159 in a disassembled configuration; in an assembled configuration, the body box connector 230 of first intermediate sub 170 threadably connects to the mating body pin connector 200 of the lowermost tubular member 159 of outer housing 158 to form a body connection 215. Although Figure 6 only illustrates the body pin connector 200 of lowermost tubular member 159 and the body box connector 230 of first intermediate sub 170, the other body pin connectors 200 and body box connectors 230 of FRT 100 are configured similarly as the connectors 200, 230 shown in Figure 8.

[0034] Referring still to Figure 6, body pin connector 200 of lowermost tubular member 159 includes a generally frustoconical outer surface 202 extending between a terminal end 204 of body pin connector 200 and an annular, planar primary shoulder 206. The outer surface 202 of body pin connector 200 comprises a threaded connector 208 formed thereon including one more helically extending threads. In addition, body pin connector 200 has an outer diameter 210 defined by the radially outer end of shoulder 206. Body pin connector 200 also includes a thread root diameter (indicated schematically by arrow 212 in Figure 6) of the threaded connector 208. In accordance with American Petroleum Institute (API) Recommended Practice 7G, the thread root diameter 212 of threaded connector 208 is defined by the outer diameter of the portion of threaded connector 208 positioned approximately 0.75 inches (19.05 millimeters) from the primary shoulder 206 of body pin connector 200. Body pin connector 200 further includes a central passage 214 defined by a generally cylindrical inner surface 216 extending axially from terminal end 204. Inner surface 214 of body pin connector 200 defines a bore diameter 218 of central passage 214.

[0035] The lowermost tubular member 159 additionally includes a tubular body 161 coupled to body pin connector 200. In some embodiments, body pin connector 200 may be attached or coupled (e.g., welded) to a tubular body 161 of lowermost tubular member 159, while in other embodiments, tubular body 161 and body pin connector 200 may comprise an integral, monoiithicaily formed structure. Tubular body 161 of lowermost tubular member 159 generally Includes a central bore or passage defined by a generally cylindrical inner surface 163 and a generally cylindrical outer surface 165. Surfaces 163, 165 of tubular body 161 define a radial wall thickness 167 of the tubular body 161 , which is measured radially between surfaces 163, 165.

[0036] Referring still to Figure 6, in this embodiment, body box connector 230 of first intermediate sub 170 includes a generally cylindrical inner surface 232 extending from a terminal end 234 of body box connector 230. Terminal end 234 defines an annular primary shoulder of body box connector 230 configured to axially abut and matingly engage the primary shoulder 206 of body pin connector 200. The inner surface 232 of body box connector 230 comprises a threaded connector 236 formed thereon including one more helically extending threads configured to threadabiy couple with the threaded connector 208 of body pin connector 200. Body box connector 230 comprises an outer diameter 238 defined by a generally cylindrical outer surface 240 of body box connector 230. In this embodiment, outer diameter 238 of body box connector 230 is equal to the outer diameter 210 of body pin connector 200. Additionally, body box connector 230 comprises a thread root diameter (indicated schematically by arrow 242 in Figure 6) of the threaded connector 236. In accordance with API Recommended Practice 7G, the thread root diameter 242 of threaded connector 236 is defined by the outer diameter of the portion of threaded connector 236 axially aligned with the terminal end 204 of body pin connector 200 when body pin connector 200 is threadabiy coupled with body box connector 230.

[0637] The first intermediate sub 170 additionally Includes a tubular body 172 coupled to body box connector 230. In some embodiments, body box connector 230 may be attached or coupled (e.g., welded) to a tubular body 172 of first intermediate sub 170, while in other embodiments, tubular body 172 and body box connector 230 may comprise an integral, monolithlcally formed structure. Tubular body 172 of first intermediate sub 170 generally includes a central bore or passage defined by a generally cylindrical inner surface 174 and a generally cylindrical outer surface 176. Surfaces 174, 176 of tubular body 172 define a radial wall thickness 178 of the tubular body 170, which is measured radially between surfaces 174, 176.

[0638] Body connection 215 may be formed between the body pin connector 200 and body box connector 230 when connectors 200, 230 are threadabiy connected. Body connection 215 exhibits or is characterized by a bending strength ratio (BSR) that describes and quantifies the relative stiffness of body pin connector 200 and body box connector 230, and the balance of stiffness between connectors 200, 230. More specifically, the BSR of body connection 215 is the ratio of the section modulus of body box connector 230 at the axial location (relative central axis 105) of the terminal end 204 of body pin connector 200 divided by the section modulus of the body pin connector 200 at the axial location of the last engaged thread of the body pin connector 200. Not intending to be bound by any particular theory, in at least some embodiments, the BSR of a single-shouldered threaded connection, such as body connection 215, is determined from the following computation, where Z_box represents the section modulus of body box connector 230, Z_pin represents the section modulus of body pin connector 200, D represents the outer diameter 238 of body box connector 230, b represents the thread root diameter 242 of body box connector 230, R represents the thread root diameter 212 of body pin connector 200, and d represents the bore diameter 218 of body pin connector 200:

[0039] In some embodiments, the body connection 215 formed between body pin connector 200 and body box connector 230 is specifically balanced such that body connection 215 has a BSR of approximately between 1.8 and 2.5. In preferred embodiments, the BSR of body connection 215 is approximately between 2.0 and 2.2; however, in other embodiments, the BSR of body connection 215 may vary. By providing body connection 215 with a BSR of approximately 1.8-2.5 the stresses imparted to connectors 200, 230 are substantially equally balanced therebetween, permitting body connection 215 to receive higher torsional loads before yielding.

[0040] In at least some embodiments, body connection 215 comprises a BSR that provides a connection that is initially (prior to the deployment of FSR 100 info borehole 26)“box strong.” In other words, in an initial or“run-in” condition (i.e., before experiencing frictional wear), body pin connector 200 will torsional!y yield prior to body box connector 230 in response to the application of a sufficiently large torque applied to body connection 215.

[0041] However, during downhole operations, body connection 215 of FRT 100 is exposed to the borehole environment and frictional!y engages the wall of borehole 26, thereby wearing or abrading the outer surface 240 of body box connector 230 and reducing outer diameter 238 of body box connector 230. The reduction in outer diameter 238 of body box connector 230 reduces the section modulus Z_box of body box connector 230, thereby torsiona!ly weakening body box connector 230 relative to body pin connector 200 such that body connection 215 becomes“box weak” in the “worn” condition and body box connector 230 will iorsionaily yield prior to body pin connector 200 in response to the application of a sufficiently large torque applied to body connection 215 Given that body box connection 230 is exposed to greater wear and degradation as compared to the body pin connector 200 during downhole operation of drilling system 10, the balance in torsional strength between connectors 200, 230 may be maximized over the operational life of body connection 215 by configuring the BSR of body connection 215 to provide a“box strong” configuration when body connection 215 is in the run-in condition. In this embodiment, at a“half way” point or condition of body connection 215 that is midway between the run-in condition and worn condition, body connection 215 comprises a balanced BSR having a body pin connector 200 that is substantially equally in strength to the body box connector 230 with respect to withstanding torsional loads. In this configuration, both the body pin connector 200 and body box connector 230 are prevented from becoming too strong (Le., unbalanced with respect to body connection 215) during the operational life of FRT 100, thereby promoting stress-sharing between connectors 200, 230 throughout the operational life of FRT 100.

[0042] Referring to Figure 7, one body pin connector 290 and the mating body box connector 310 of FRT 100 is shown. Particularly, Figure 7 illustrates the lower end of first intermediate sub 170 including the body pin connector 290, and an upper end of second intermediate sub 180, including body box connector 310. Figure 7 illustrates intermediate subs 170, 180 in a disassembled configuration; in an assembled configuration, the body pin connector 290 of first intermediate sub 170 threadably couples with the body box connector 310 of second intermediate sub 180 to form a body connection 217. Although Figure 7 only illustrates the body box connector 290 of first intermediate sub 170 and the body box connector 310 of second intermediate sub 180, in at least some embodiments, the rig box connector 270 and rig pin connector 250 of FRT 100 is configured similarly as body pin connector 290 and body box connector 310, respectively

[0G43] In the embodiment of Figure 7, body pin connector 290 of first intermediate sub 170 includes a generally frustoconical outer surface 292 extending between a terminal end 294 and an annular planar shoulder 296. Annular shoulder 296 defines a primary shoulder 296 of body pin connector 290 and terminal end 294 defines an annular secondary shoulder 294 of body pin connector 290. The outer surface 292 of body pin connector 290 comprises a threaded connector 298 formed thereon including one more helically extending threads. Body pin connector 290 also includes a central passage 300 defined by a generally cylindrical inner surface 302 extending axially from terminal end 294. Surfaces 292, 302 of body pin connector 290 define an annular cross-sectional area in a plane oriented perpendicular to axis 105 (indicated schematically by arrow 304 in Figure 7) of body pin connector 290 which varies along the axial length of connector 290 as surface 292 tapers towards surface 302 moving axially toward terminal end 294. As will be discussed in more detail below, body pin connector 290 also includes a gauge point cross-sectional area in a plane oriented perpendicular to axis 105 (indicated scbematicaily by arrow 304G) and axially located at the“gauge point” 306, which is positioned at the first full and engaged thread of threaded connector 292 relative primary shoulder 296 when body pin connector 290 is engaged by and threadabiy coupled with body box connector 310.

[0044] In this embodiment, body box connector 310 of second intermediate sub 180 includes a generally frustoconical inner surface 312 extending axially from a terminal end 314 of body box connector 310 to an annular planar shoulder 316 of connector 310 Terminal end 314 defines an annular primary shoulder 314 of body box connector 310 configured to axially abut and matingly engage the primary shoulder 296 of body pin connector 290. Additionally, the annular shoulder 316 of body box connector 310 comprises a secondary shoulder 316 configured to axially abut and matingly engage the terminal end or secondary shoulder 294 of body pin connector 290.

[0045] The inner surface 312 of body box connector 310 comprises a threaded connector 318 formed thereon including one more helically extending threads configured to mate and threadabiy couple with the threaded connector 298 of body pin connector 290. Body box connector 310 also includes a generally cylindrical outer surface 320. Surfaces 312, 320 of body pin connector 290 define an annular cross-sectional area in a plane oriented perpendicular to axis 105 (indicated schematically by arrow 322 in Figure 7) of body box connector 310 which varies along the axial length of connector 310 as inner surface 312 tapers toward outer surface 320 moving axially toward terminal end 314. Body box connector 310 particularly includes a gauge point cross-sectional area in a plane oriented perpendicular to axis 105 (indicated schematically by arrow 322G) axially located at the“gauge point” 324 which is positioned at the first full and engaged thread of threaded connector 318 relative terminal end or primary shoulder 314 when body box connector 310 is engaged by and threadabiy coupled with body pin connector 290

[0046] The second intermediate sub 180 additionally includes a tubular body 182 coupled to body box connector 310. In some embodiments, body box connector 310 may be attached or coupled (e.g., welded) to a tubular body 182 of second intermediate sub 180, while in other embodiments, tubular body 182 and body box connector 310 may comprise an integral, mono!ithica!ly formed structure. Tubular body 182 of second intermediate sub 180 generally includes a central bore or passage defined by a generally cylindrical inner surface 184 extending axially from shoulder 316 and a generally cylindrical outer surface 186. Surfaces 184, 186 of tubular body 182 define a radial wail thickness 188 of the tubular body 180, which is measured radially between surfaces 184, 186.

[0047] Body connection 217 may be formed between the body pin connector 290 and body box connector 310 when connectors 290, 310 are threadabiy connected, where body connection 217 exhibits or is characterized by a BSR that describes and quantifies the relative stiffness of body pin connector 290 and body box connector 310, and the balance of stiffness between connectors 290, 310. Not intending to be bound by any theory, in at least some embodiments, the BSR of double-shouldered threaded connections, including body connection 217, is determined from the following computation, where A_box represents the cross-sectional area 322G of body box connector 310 at the gauge point 324, and A_pjn represents the cross-sectional area 304G of the body pin connector 290 at the gauge point 306:

[GG48] In some embodiments, the body connection 217 formed between body pin connector 290 and body box connector 310 is approximately between 0.8 and 1.4. In preferred embodiments, the BSR of body connection 217 is approximately between 1.10-1.15; however, in other embodiments, the BSR of body connection 217 may vary. By providing body connection 217 with a BSR of approximately 0.8- 1.4 the stresses imparted to connectors 290, 310 are substantially equally balanced therebetween, permitting body connection 217 to receive higher torsional loads before yielding.

[0049] In at least some embodiments, body connection 217 comprises a BSR that provides a connection that is initially (prior to the deployment of FSR 100 into borehole 26)“box strong” as described above with respect to body connection 215. Thus, in an initial or run-in condition of body connection 217 (i.e., before experiencing frictional wear), body pin connector 290 will torsionally yield prior to body box connector 310 in response to the application of a sufficiently large torque applied to body connection 217. However, in a worn condition following deployment of body connection 217 into borehole 26, body box connector 310 will torsionally yield prior to body pin connector 290 in response to the application of a sufficiently large torque applied to body connection 217. In this embodiment, at a“half-way” point or condition of body connection 217 that is midway between the run-in condition and worn condition, body connection 217 comprises a balanced BSR having a body pin connector 290 that is substantially equally strong to body box connector 310 with respect to withstanding torsional loads.

[0050] Referring generally to Figures 1-7, as described above, in a rotary drilling mode of drilling system 10 drill bit 21 of drilling assembly 90 may be rotated from the surface 3 by drill string 20 using rotary table 14. Particularly, in some embodiments an upper end of drill string 21 is rotated at the surface by an operator of drilling system 10 in a specific torque range defined by the maximum and minimum Make-Up Torque (MUT) as specified by the manufacturer of the drill pipe joints of which drill string 21 is comprised As a non-limiting example, the current edition of the International Association of Drilling Contractors (IADC) Drilling Manual advises that rotary drilling should not exceed 80% of the maximum MUT of the drill string (e.g., drill string 21 of drilling system 10); nonetheless, situations may arise where the operator of the drilling system must temporarily rotate the drill string at maximum MUT. If this situation occurs, one or more FRTs (e.g., FRT 100) positioned along the drill string should each be torsionally robust enough to survive operation at the drill pipe maximum MUT.

[0051] In other words, the FRT (e.g., FRT 100) should possess a yield torque rating that exceeds the maximum MUT of the drill pipe joint (e.g., the lowermost drill pipe joint of drill string 20 shown in Figure 1 ) to which the FRT is connected when the maximum MUT is applied to the drill pipe joint. Generally, the yield torque is the torque at which plastic deformation attributable to only torque occurs (i.e., the threaded connection yields and undergoes plastic deformation). This is particularly important if the operator of the drilling system drills a curved section of the borehole with the FRT positioned along the drill string because bending stress due to the curvature of the borehole is imparted to the FRT in addition to torsional stresses. In addition, FRTs positioned along the drill string are also generally required to directly connect to the drill string to avoid the use of crossovers. Thus, FRTs positioned along the drill string may be required to directly host premium rig connections on the terminal ends of the FRT.

[0052] Embodiments disclosed herein include FRTs (e.g., FRT 100) having body connections the yield torque of which are as high or higher than the maximum MUT of the rig connection hosted by the FRT. As described above, the maximum MUT may be defined by the manufacturer of the rig connection as it pertains to high strength drill pipe (e.g., at least S-135 grade). This is the case even if the outer diameter of the FRT has worn down to the minimum OD as specified by the tool manufacturer. This also applies when the FRT and rig connection are of relatively similar sizes. This design approach is intended to prevent the downhole tool from suffering premature torsional-related failure caused by rotating the drill string at high torque.

[0053] In at least some embodiments, the maximum MUT of the rig connection hosted by the downhole tool or FRT (e.g., the rig connection formed between rig box connector 270 of shock tool 150 and a corresponding rig pin connector 250 of drill string 20) comprises a percentage of the yield strength of the rig connection, which is dependent upon the outer diameters, wall thicknesses, and materials of composition the tubular members forming the connection, as well as the BSR of the connection. Thus, in at least some embodiments, the housings 118, 158 of FRT 100 each comprise an outer diameter and wail thickness equal to or greater than the outer diameter and a minimum wall thickness of the drill pipe joint of drill string 20 coupled to the upper end 152 of the shock tool 150 of FRT 100. Additionally, the housings 118, 158 of FRT 100 each comprise a material having similar material properties, including resiliency in withstanding torque, as the material comprising the drill pipe joint of drill string 20 coupled to the upper end 152 of shock tool 150. Further, in at least some embodiments, the BSR of each body connection 215, 217 of FRT 100 is as or more balanced as the BSR of the rig connection formed between the upper end 152 of shock tool 150 and the lowermost drill pipe joint of drill string 20 connected therewith. For example, in an embodiment where the BSR of the rig connection formed between the upper end 152 of shock tool 150 and the lower end of drill string 20 is approximately between 1.10-1.15, then in at least some embodiments each double- shouldered body connection 217 of FRT 100 comprises a BSR of approximately between 1.10-1.15.

[0054] In a non-limiting example, rig box connection 270 comprises a Delta 425 rig connection having an outer diameter of approximately between 4.91 inches (12.47 centimeters) and 5.38 inches (13.67 centimeters) and a maximum MUT of approximately 29,900 foot-pounds (40,539 Newton-meters), and the outer diameter of each outer housing 118, 158 of FRT 100 (housings 118, 158 each comprising a material having a 150,000 pounds per square inch yield strength) is approximately between 5.00 inches (12.70 centimeters) to 5.38 inches (13.67 centimeters), thereby matching or exceeding the outer diameter of rig box connection 270. In this non- iimiting example, each body connection 215, 217 of FRT 100 has a maximum MUT of approximately 29,900 foot-pounds (40,539 Newton-meters) or greater.

[0055] Additionally, in this non-limiting example, the BSR of each body connection 215 of FRT 100 is approximately 2.08 when in the run-in condition with a yield torque of approximately 42,110 foot-pounds (57,093 Newton-meters), and approximately 1.83 when in the worn condition following deployment into borehole 20 with a yield torque of approximately 35,690 foot-pounds (48,389 Newton-meters). Thus, in at least this non-limiting example, the yield torque of each body connection 215 of FRT 100 is above the maximum MUT of the rig box connection 270 irrespective of whether each body connection 215 is in the run-in condition or worn condition. In at least some embodiments, the yield torque of each body connection 217 of FRT 100 is also above the maximum MUT of rig box connection 270 in both the run-in condition and the worn condition.

[0056] While exemplary embodiments have been shown and described, modifications thereof can be made by one skilled in the art without departing from the scope or teachings herein. The embodiments described herein are exemplary only and are not limiting. Many variations and modifications of the systems, apparatus, and processes described herein are possible and are within the scope of the disclosure. For example, the relative dimensions of various parts, the materials from which the various parts are made, and other parameters can be varied. Accordingly, the scope of protection is not limited to the embodiments described herein, but is only limited by the claims that follow, the scope of which shall include all equivalents of the subject matter of the claims. Unless expressly stated otherwise, the steps in a method claim may be performed in any order. The recitation of identifiers such as (a), (b), (c) or (1 ), (2), (3) before steps in a method claim are not intended to and do not specify a particular order to the steps, but rather are used to simplify subsequent reference to such steps.

Claims

What is claimed is:

1. A drilling assembly for drilling a borehole in a subterranean earthen formation, comprising:

a drill string rotatable in the borehole;

a friction reducing tool coupled to the drill string, wherein the friction reducing tool comprises:

an outer housing having a central axis, a first end, a second end opposite the first end, and a passage extending axially from the first end to the second end;

wherein the first end comprises a rig connection configured to directly connect to a drill pipe and the second end comprises a rig connection configured to directly connect to a drill pipe;

wherein the outer housing comprises a plurality of tubular members connected end-to-end with a plurality of body connections, wherein each body connection has a yield torque of at least 30,000 foot-pounds;

a bottomhole assembly (BHA) coupled to the friction reducing tool, wherein the BHA comprises a drill bit configured to drill Into the subterranean earthen formation.

2. The drilling assembly of claim 1 , wherein the yield torque of each body connection of the friction reducing tool is at least 40,000 foot-pounds.

3. The drilling assembly of claim 1 , wherein the friction reducing tool is positioned along the drill string such that a portion of the drill string extends between the friction reducing tool and the BHA.

4. The drilling assembly of claim 3, wherein the friction reducing tool comprises: an outer housing having a central axis, a first end, a second end opposite the first end, and a passage extending axially from the first end to the second end;

wherein the first end comprises a rig connection configured to directly connect to a first drill pipe of the drilistring and the second end comprises a rig connection configured to directly connect to a second drill pipe of the drill string; wherein the outer housing comprises a plurality of tubular members connected end-to-end with a plurality of single-shouldered body connections, wherein each single-shouldered body connection has a bending strength ratio (BSR) between 1.8 and 2.5.

5. The drilling assembly of claim 4, wherein the BSR of each single-shouldered body connection of the friction reducing tool is between 2.0 and 2.2.

6. The drilling assembly of claim 3, wherein the friction reducing tool comprises: an outer housing having a central axis, a first end, a second end opposite the first end, and a passage extending axially from the first end to the second end;

wherein the first end comprises a rig connection configured to directly connect to a first drill pipe of the drill string and the second end comprises a rig connection configured to directly connect to a second drill pipe of the drill string;

wherein the outer housing comprises a plurality of tubular members connected end-to-end with at least one double-shouldered body connection, wherein the double- shouldered body connection has a bending strength ratio (BSR) between 0.8 and 1.4.

7. The drilling assembly of claim 6, wherein the BSR of each double-shouldered body connection of the friction reducing tool is between 1.10 and 1.15.

8. The drilling assembly of claim 1 , wherein the friction reducing tool is coupled between a lower end of the drill string and the BHA.

9. The drilling assembly of claim 1 , wherein the friction reducing tool comprises a pressure pulse generator configured to cyclically generate pressure pulses in a drilling fluid, and a shock tool configured to translate the pressure pulses generated by the pressure pulse generator into reciprocation of the drill string.

10. A friction reducing tool for reciprocating a drill string, the friction reducing tool comprising:

an outer housing having a central axis, a first end, a second end opposite the first end, and a passage extending axially from the first end to the second end; wherein the first end comprises a rig connection configured to directly connect to a first drill pipe and the second end comprises a rig connection configured to directly connect to a second drill pipe;

wherein the outer housing comprises a plurality of tubular members connected end-to-end with a plurality of single-shouldered body connections, wherein each single-shouldered body connection has a bending strength ratio (BSR) between 1.8 and 2.5.

11. The friction reducing tool of claim 10, wherein the BSR of each single- shouldered body connection of the friction reducing tool is between 2 0 and 2.2.

12. The friction reducing tool of claim 10, wherein each single-shouldered body connection has a first outer diameter and a first BSR corresponding to an initial condition of the single-shouldered body connection, and a second outer diameter and a second BSR corresponding to a worn condition of the single-shouldered body connection, and wherein the first outer diameter is greater than the second outer diameter and the first BSR is greater than the second BSR

13. The friction reducing tool of claim 12, wherein the first BSR is approximately 2.1 and the second BSR is approximately 1.8.

14. The friction reducing tool of claim 10, wherein the plurality of tubular members are connected end-to-end with at least one double-shouldered body connection, wherein the double-shouldered body connection has a BSR between 0 8 and 1.4.

15. The friction reducing tool of claim 14, wherein the BSR of the double shouldered body connection has a BSR between 1.10 and 1.15.

16. A friction reducing tool for reciprocating a drill string, the friction reducing tool comprising:

wherein the outer housing comprises a plurality of tubular members connected end-to-end with at least one double-shouldered body connection, wherein the double shouldered body connection has a bending strength ratio (BSR) between 0 8 and 1.4.

17. The friction reducing tool of claim 18, wherein the BSR of the double shouldered body connection has a BSR between 1.10 and 1.15.

18. The friction reducing tool of claim 18, wherein the plurality of tubular members are connected end-to-end with a plurality of single-shouldered body connections, wherein each single-shouldered body connection has a BSR between 1.8 and 2.5.

19. The friction reducing tool of claim 18, wherein the BSR of each single- shouldered body connection of the friction reducing tool is between 2.0 and 2.2.

20. The friction reducing tool of claim 16, wherein the friction reducing tool comprises a pressure pulse generator configured to cyclically generate pressure pulses in a drilling fluid, and a shock tool configured to translate the pressure pulses generated by the pressure pulse generator into reciprocation of the drill string.