Drill protector assembly and method

Abstract

A drill bit protector assembly has an internal valve sleeve that is actuated when the drill bit's pressure on the bit (WOB) exceeds a threshold to overcome a counteracting force provided by the internal flow pressure of drilling fluid in the area of ​​a spring housed within the drill bit protector assembly and the internal valve sleeve. Actuation of the internal valve sleeve opens a fluid passage to the wellbore annulus, resulting in a reduction in drilling fluid flow pressure and stretching of the drill string, thereby reducing the BOB of the drill bit without operator assistance.

Description

Technical Field

[0001] This invention relates to a bit saver assembly and method for managing weight-on-bit (WOB) during wellbore drilling operations and notifying the drilling rig when the WOB limit has been reached. More specifically, this invention relates to a bit saver assembly and method for managing WOB by changing internal flow pressure. Background of the Invention

[0003] During the drilling of oil and gas wells, force is applied to the drill bit to break the rock at the bottom of the wellbore. This force is applied by drill collars within the drill string. Drill collars are thick-walled tubes machined from solid steel bars. They are positioned on the drill string, close to the drill bit. Together with the drill bit, drill bit joint, mud motor, stabilizer, heavy-duty drill pipe, slammer ("jar"), and various threaded crossovers, the drill collars constitute an assembly known as the "bottom drill string assembly." The bottom drill string assembly must transfer force to the drill bit to break the rock (bit pressure), withstand harsh mechanical conditions, and provide directional control of the well for the drilling rig. Gravity acts on the drill collars to apply the downward force required for the drill bit to effectively break the rock. Bit pressure, or WOB, is the magnitude of the axial force applied to the drill bit. To control bit pressure, the drilling rig monitors and measures the surface weight (the weight suspending the drill string) as the drill bit just leaves the bottom of the wellbore. The drilling rig lowers the drill string until the drill bit contacts the bottom of the wellbore. As the drill string is lowered further, the drill bit receives more drilling pressure. Less weight is measured when suspended from the surface. For a vertical wellbore, if surface measurements during drilling show a 2000 kg reduction in drill string weight, then 2000 kg of force should be transmitted to the drill bit.

[0004] Drilling fluid, or mud, is pumped from the surface through a center borehole extending from the drill string to the drill bit. The drilling fluid lubricates and cools the drill bit during drilling to prevent wear. The drilling fluid also returns to the surface through the annulus, carrying drill cuttings away from the drill bit.

[0005] There exists an optimal range of drill pressure (DBP) values ​​based on the type, size, and brand of the drill bit used, the drilling depth, the weight of the drilling mud, and the characteristics of the geological formation to be drilled. If the DBP exceeds the upper limit of the optimal range, the drill bit is more likely to suffer excessive wear or damage. If the DBP is below the lower limit of the optimal range, the permeability into the geological formation decreases, leading to increased drilling time and costs. Drill bit manufacturers typically specify the maximum DBP for a particular drill bit. Invention Overview

[0007] This invention relates to one embodiment of a drill bit protector assembly, which may include an outer housing comprising an inner bore defined by an inner bore wall. The outer housing may include one or more orifices for allowing drilling fluid to flow into an annular space of the wellbore. The assembly may also have an outer valve sleeve comprising an inner bore defined by an inner bore wall. The outer valve sleeve may be received within the inner bore of the outer housing and may be secured to the inner bore wall of the outer housing. The outer valve sleeve may include one or more orifices for allowing drilling fluid to flow into one or more orifices of the outer housing. The assembly may also have an inner assembly that is selectively axially movable relative to the outer valve sleeve and is partially received within the inner bore of the outer housing. The inner assembly may include an inner valve sleeve positioned within the inner bore of the outer valve sleeve. The inner valve sleeve may include one or more orifices for allowing drilling fluid to flow selectively into one or more orifices of the outer valve sleeve. The internal valve sleeve can have a non-actuated position and an actuated position. In the non-actuated position, one or more orifices of the internal valve sleeve are not in fluid communication with one or more orifices of the external valve sleeve. In the actuated position, one or more orifices of the internal valve sleeve are in fluid communication with one or more orifices of the external valve sleeve. The internal assembly can have a spring positioned within the inner bore of the outer housing and operatively connected to the internal valve sleeve. The spring can have a preload force. The internal assembly can be operatively connected to the drill bit and configured to place one or more orifices of the internal valve sleeve in the non-actuated position based on the wobble force (WOB) on the drill bit being less than the preload force including the spring plus the counteracting force of the drilling fluid flow pressure in the region near the internal valve sleeve, and to place one or more orifices of the internal valve sleeve in the actuated position based on the WOB force being greater than the counteracting force.

[0008] In another embodiment of the drill bit protector assembly, the internal component may include a spring spindle positioned within the inner bore of the outer housing. The spring spindle may be operatively connected to an internal valve sleeve and a spring. The spring may be positioned about a portion of the spring spindle.

[0009] In another embodiment of the drill bit protector assembly, the internal component may include a splined mandrel. The splined mandrel may be partially positioned within the bore of the outer housing. The splined mandrel may have an upper end portion operably contacting a lower end portion of a spring mandrel, and the splined mandrel may have a lower end portion operably connected to the drill bit.

[0010] In another embodiment of the drill bit protector assembly, the internal component may include a mandrel nut operably positioned within the inner bore of the outer housing between the upper end of the splined mandrel and the inner wall of the outer housing. The mandrel nut may be directly connected to and movable with the upper end of the splined mandrel. The mandrel nut may be configured to hold the lower end of the spring mandrel onto the upper end of the splined mandrel.

[0011] In another embodiment of the drill bit protector assembly, the internal component may include a lower spring spacer operably positioned within the inner bore of the outer housing between the spring spindle and the inner wall of the outer housing. The bottom end of the lower spring spacer may contact the upper end of the spindle nut and is movable together with the upper end of the spindle nut. The upper end of the spring spacer may contact the lower end of the spring.

[0012] In another embodiment of the drill bit protector assembly, the assembly may further include an upper spring spacer operably positioned within an inner bore of the outer housing. The upper spring spacer may be attached to the outer housing. The lower end of the upper spring spacer may contact the upper end of a spring.

[0013] In another embodiment of the drill bit protector assembly, the internal component may include a spring nut, which is partially operably positioned within the inner bore of the outer housing between the spring spindle and the inner wall of the outer housing. The spring nut may be directly connected to the upper end of the spring spindle.

[0014] In another embodiment of the drill bit protector assembly, the assembly may further include a compression nut that is securely attached to the inner bore wall of the outer housing. The compression nut may have an inner bore defined by the inner bore wall. The inner bore of the compression nut may be sized to receive the upper section of the spring nut when the internal valve sleeve is in the actuated position.

[0015] In another embodiment of the drill bit protector assembly, the upper section of the spring nut can be directly connected to the lower end of the internal valve sleeve.

[0016] In another embodiment of the drill bit protector assembly, the upper end of the splined mandrel may include a seal. The seal provides a sealed connection between the splined mandrel and the mandrel nut.

[0017] In another embodiment of the drill bit protector assembly, the upper end of the outer valve sleeve may include a seal, and the lower end of the outer valve sleeve may also include a seal. The seals provide a sealing connection between the outer valve sleeve and the outer housing. One or more orifices of the outer valve sleeve may be positioned between the seals at the upper and lower ends of the outer valve sleeve.

[0018] In another embodiment of the drill bit protector assembly, the portion of the lower end of the splined mandrel that is not received within the inner bore of the outer housing includes a rib. The rib may have an upper shoulder that abuts the lower terminating edge of the outer housing when the inner valve sleeve is in the actuated position.

[0019] In another embodiment of the drill bit protector assembly, the outer housing may include an upper body, a spring housing, and a splined body. The lower end of the upper body may be directly connected to the upper end of the spring housing. The lower end of the spring housing may be directly connected to the upper end of the splined body.

[0020] The present invention also relates to embodiments of a method for managing the bit bit's pressure on the drill bit (WOB) during drilling operations. The method may include the steps of: (a) advancing a drill string down the wellbore, terminating at a bottom drill assembly (BHA) including the drill bit. The drill string may include a bit guard assembly as described above, operably positioned above the bottom drill assembly. The method may include step (b) positioning the drill bit in contact with the bottom of the wellbore. The method may further include step (c) drilling the drill bit into the bottom of the wellbore, subjecting the drill bit to the WOB force. The method may further include step (d) increasing the WOB force on the drill bit as it penetrates the bottom of the wellbore by moving an internal valve sleeve from a non-actuated position to an actuated position when the WOB force becomes greater than a counteracting force.

[0021] In another embodiment of the method, as part of step (d), the inner valve sleeve may be moved upward relative to the outer valve sleeve to align one or more orifices of the inner valve sleeve with one or more orifices of the outer valve sleeve.

[0022] In another embodiment of the method, drilling fluid flow from the inner bore of the outer housing to the annular space can result in a reduction in the drilling fluid flow pressure acting on the bottom drill string assembly.

[0023] In another embodiment of the method, a pressure gauge on the drilling ring can indicate a decrease in drilling fluid pressure acting on the bottom drill string assembly.

[0024] In yet another embodiment of the method, the method may further include step (e) when the drilling pressure becomes less than the counteracting force, lifting the drill bit away from the bottom of the wellbore to return the internal valve sleeve to the non-actuated position.

[0025] In another embodiment of the method, the drill bit protector assembly can further reduce dynamic drill pressure due to drill bit bounce and stick-slip by providing a reverse spring load. For example, regarding the drill bit protector assembly: an internal component includes a spring mandrel positioned within the inner bore of the outer housing, operably connected to an internal valve sleeve and a spring positioned about a portion of the spring mandrel; the internal component includes a splined mandrel partially positioned within the inner bore of the outer housing, having an upper end portion operably contacting a lower end portion of the spring mandrel, the splined mandrel having a lower end portion operably connected to the drill bit; the internal component includes a mandrel nut, the mandrel nut being positioned within the splined mandrel. The upper end of the splined mandrel is operably positioned within the inner bore of the outer housing, between the upper end of the splined mandrel and the inner wall of the outer housing. A mandrel nut is directly connected to and movable with the upper end of the splined mandrel. The mandrel nut is configured to hold the lower end of the spring mandrel onto the upper end of the splined mandrel. The method may include a step whereby the drill bit protector assembly generates a damping effect during drilling, which minimizes dynamic changes in drilling pressure and drill bit bounce to prevent unintentional movement of the internal valve sleeve from a non-actuated position to an actuated position. The damping effect can be activated by the travel of drilling fluid trapped in a cavity at the region of the spring through a first annular gap between the mandrel nut and the spring housing, and again through a second annular gap between the splined mandrel and the splined body. Brief description of the attached diagram

[0027] Figure 1 This is a cross-sectional view of an embodiment of a drill bit protector assembly with a drill bit-free configuration.

[0028] Figure 2 yes Figure 1 A partial cross-sectional view of the lower section of an embodiment of the drill bit protector assembly.

[0029] Figure 3 yes Figure 1 A partial cross-sectional view of the lower central section of an embodiment of the drill bit protector assembly.

[0030] Figure 4 yes Figure 1 A partial cross-sectional view of the upper section of an embodiment of the drill bit protector assembly.

[0031] Figure 5 This is a cross-sectional view of an embodiment of a drill bit protector assembly in the first drill pressure configuration (some drill pressure).

[0032] Figure 6 yes Figure 5 A partial cross-sectional view of the lower section of an embodiment of the drill bit protector assembly.

[0033] Figure 7 yes Figure 5A partial cross-sectional view of the upper section of an embodiment of the drill bit protector assembly.

[0034] Figure 8 This is a cross-sectional view of an embodiment of a drill bit protector assembly in the second drill pressure configuration (crack-open).

[0035] Figure 9 yes Figure 8 A partial cross-sectional view of the lower section of an embodiment of the drill bit protector assembly.

[0036] Figure 10 yes Figure 8 A partial cross-sectional view of the upper section of an embodiment of the drill bit protector assembly.

[0037] Figure 11 This is a cross-sectional view of an embodiment of a drill bit protector assembly in the maximum drill pressure configuration (latched-open).

[0038] Figure 12 yes Figure 11 A partial cross-sectional view of the lower section of an embodiment of the drill bit protector assembly.

[0039] Figure 13 yes Figure 11 A partial cross-sectional view of the upper section of an embodiment of the drill bit protector assembly.

[0040] Figure 14 It utilizes an operably connected connection to the drill string. Figure 11 A schematic diagram of a wellbore drilling operation of an embodiment of a drill bit protector assembly.

[0041] Figure 15 It is a table of formulas for travel distance.

[0042] Figure 16 It is a graph showing the relationship between the valve position of the simulated drill bit protector setup and the applied drill pressure and average bottom drill string assembly pressure.

[0043] Detailed Description of Preferred Embodiments

[0044] Referring to the accompanying drawings, similar elements are given similar numerical designations to facilitate understanding of the invention, and in particular to... Figures 1-4 An embodiment of the drill bit protector subassembly 10 depicted herein is shown, wherein the assembly 10 is configured to be free of pressure on drill (WOB), i.e., when the drill bit leaves the bottom of the wellbore.

[0045] like Figure 1 and Figure 4As shown, assembly 10 may include an upper body 12. The upper body 12 may be tubular in design, having an inner bore 40 defined by an inner bore wall 42. The upper body 12 may have an upper boxend 44 and a lower pinend 46. The upper boxend 44 may receive, in an operative connection (e.g., a threaded connection), drill pipe or coiled tubing (not shown) (or referred to herein as a drill string) extending from the drilling rig through the wellbore to assembly 10. The lower pinend 46 may be operatively connected (e.g., threadedly connected) to the upper boxend 48 of the spring housing 26.

[0046] Reference Figure 1 and Figure 3 The spring housing 26 may be tubular in design, having an inner bore 50 defined by an inner bore wall 52. The lower box-shaped end 54 of the spring housing 26 may receive the upper pin-shaped end 56 of the spline body 34 in an operative connection (e.g., a threaded connection).

[0047] like Figures 1-3 As shown, the spline body 34 may be tubular in design, having an inner bore 58 defined by an inner bore wall 60. The lower end 62 of the spline body 34 may terminate at a lower edge 64. The inner bore wall 60 may be divided into a lower section 66 and an upper section 68. The lower section 66 may have an inner diameter larger than that of the upper section 68. The transition from the enlarged inner diameter of the lower section 66 to the smaller inner diameter of the upper section 68 may occur at a tapered shoulder 70.

[0048] Further reference Figures 1-3Component 10 may include a splined mandrel 36. The splined mandrel 36 may be generally tubular in design, having an inner bore 72 defined by an inner bore wall 74. The splined mandrel 36 may include an outer surface 76. The splined mandrel 36 may include an upper section 78, a middle section 80, and a lower section 82. The lower section 82 may include a pin-type end 84 operatively connected (e.g., threaded) to a bottom drill assembly (BHA) (which terminates at the drill bit). The lower section 82 may also include a rib 86 extending outward from the outer surface 76. The upper edge 88 of the rib 86 may include a shoulder 90. The outer surface 76 may also include an enlarged outer diameter section 92 at the lower section 82. The outer surface 76 may include a smaller outer diameter section 94 at the middle section 80. The transition between the enlarged outer diameter section 92 and the smaller outer diameter section 94 may occur at the tapered shoulder 96. The enlarged outer diameter section 92 may be sized to accommodate within the enlarged inner diameter of the lower section 66 of the spline body 34. The smaller outer diameter section 94 may be sized to accommodate within the smaller inner diameter of the upper section 68 of the spline body 34. The outer surface 76 of the spline mandrel may be profiled together with the spline (not shown), which engages with a spline recess (not shown) formed in the inner bore wall 60 of the spline body 34 to provide an operative connection between the spline body 34 and the spline mandrel 36, while allowing axial movement of the spline mandrel 36 relative to the spline body 34.

[0049] As in Figure 1 and Figure 3As seen, the mandrel nut 32 may be of a tubular design, having an inner bore 98 defined by an inner bore wall 100. The mandrel nut 32 may be positioned within the inner bore 50 of the spring housing 26, between the inner bore wall 52 of the spring housing 26 and the outer surface 76 of the upper section 78 of the splined mandrel 36. The inner bore wall 100 may include an upper section 102 and a lower section 104. The lower section 104 may include an inner diameter that is enlarged relative to the inner diameter of the upper section 102. A tapered shoulder 106 may transition between the upper section 102 and the lower section 104. The upper section 102 may include an upper edge section 108. The inner diameter of the upper edge section 108 may be reduced relative to the inner diameter of the upper section 102. A shoulder 110 may transition between the upper section 102 and the upper edge section 108. The mandrel nut 32 may also include an upper end 112 and a lower end 114. The lower end 114 may abut the upper pin end 56 of the spline body 34. The mandrel nut 32 may be operatively connected (e.g., by thread) to the spline mandrel 36. For example, the lower section 104 may contain threads that mate with threads contained on the outer surface 76 of the upper section 78 of the spline mandrel 36. The mandrel nut 32 and the spline mandrel 36 may be hermetically connected. For example, a seal (such as an O-ring 116) may be positioned on the outer surface 76 of the upper section 78 of the spline mandrel 36 and hermetically engage with the upper section 102 of the mandrel nut 32.

[0050] Figure 1 and Figure 3 The illustration shows that spring 24 can be positioned within the inner hole 50 of spring housing 26 and sandwiched between upper spring spacer 22 and lower spring spacer 30. The lower end 118 of lower spring spacer 30 can abut against the upper end 112 of spindle nut 32. The upper end 120 of upper spring spacer 22 can abut against the lower pin end 46 of upper body 12. The upper end 122 of spring 24 can press against the lower end 124 of upper spring spacer 22. The lower end 126 of spring 24 can press against the upper end 128 of lower spring spacer 30.

[0051] Reference Figure 1 , Figure 3 and Figure 4The spring spindle 28 may be tubular in design, having an inner bore 130 defined by an inner bore wall 132. The spring spindle 28 may have an outer surface 134. The spring spindle 28 may include an upper section 136, a middle section 138, and a lower section 140. The lower section 140 may terminate at a flange end section 142. The flange end section 142 may include a lower end 144 abutting against the top edge 146 of the upper section 78 of the splined spindle 36. The lower section 140 and the middle section 138 may be positioned within the inner bore 50 of the spring housing 26. The outer surface 134 at the flange end section 142 may be configured adjacent to the upper section 102 of the spindle nut 32, wherein the upper end 148 of the flange end section 142 abuts against the shoulder 110 of the spindle nut 32. The intermediate section 138 may extend through the lower spring spacer 30 and the upper spring spacer 22, terminating at the upper section 136 located above the upper spring spacer 22. The spring 24 may extend around the outer surface 134 of the intermediate section 138. The intermediate section 138 may include an outer diameter section 150 that is enlarged relative to the outer diameter of each end portion 152 of the intermediate section 138. The upper section 136 may be positioned within the inner bore 40 of the upper body 12 and may be operatively connected to the spring nut 20.

[0052] Figure 1 and Figure 4 A spring nut 20 is depicted. The spring nut 20 may be tubular in design, having an inner bore 154 defined by an inner bore wall 156. The spring nut 20 may include an outer surface 158. The inner bore wall 156 may be divided into an upper section 162 and a lower section 164 by a shoulder 160. The lower section 164 may be operatively connected (e.g., by thread) to an upper section 136 of a spring spindle 28. For example, the lower section 164 may contain threads that mate with threads on the upper section 136. The shoulder 160 may include a top edge 166 and a bottom edge 168. The upper edge 170 of the upper section 136 of the spring spindle 28 abuts against the bottom edge 168 of the shoulder 160. The upper section 162 terminates at the top edge 172. The spring nut 20 may be operatively positioned within an inner bore 40 of an upper body 12.

[0053] As in Figure 1 and Figure 4 As seen, the compression nut 18 can be operatively positioned within the inner bore 40 of the upper body 12. The compression nut 18 may include an outer surface 174 and an inner bore 176 defined by an inner bore wall 178. The outer surface 174 of the compression nut 18 can be securely attached to the inner bore wall 42 of the upper body 12. The compression nut 18 may be sized to receive the upper section 162 of the spring nut 20. The compression nut 18 may include an upper edge 180 and a bottom edge 182.

[0054] Figure 1 and Figure 4 An outer valve sleeve 14 is shown. The outer valve sleeve 14 may be tubular in design, having an inner bore 184 defined by an inner bore wall 186. The outer valve sleeve 14 may include an outer surface 188. The outer valve sleeve 14 may include an upper section 190, a middle section 192, and a lower section 194. The outer diameter of each of the upper section 190 and the lower section 194 may be the same, and may be enlarged relative to the outer diameter of the middle section 192. The outer valve sleeve 14 may be operatively positioned within the inner bore 40 of an upper body 12. The upper section 190 may terminate at an upper edge 196 abutting against a shoulder 198 in the inner bore wall 42 of the upper body 12, wherein the outer surface 188 of the upper section 190 abuts against the inner bore wall 42 of the upper body 12. The lower section 194 terminates at a bottom edge 200, which abuts against the upper edge 180 of the compression nut 18. The intermediate section 192 may include one or more orifices 202 providing a fluid flow passage from the inner bore 184 to the space 204 between the outer surface 188 of the intermediate section 192 and the inner bore wall 42 of the upper body 12. The upper body 12 may include one or more orifices 206 providing a fluid flow passage from the space 204 to an annular space in the wellbore (not shown). Each of the upper section 190 and the lower section 194 may be hermetically connected to the inner bore wall 42 of the upper body 12. For example, the outer surface 188 at each of the upper section 190 and the lower section 194 may include a recess 195 for accommodating a seal such as an O-ring 197.

[0055] like Figure 1 and Figure 4 Referring to this, the inner valve sleeve 16 may be of a tubular design, having an inner bore 208 defined by an inner bore wall 210. The inner valve sleeve 16 may include an outer surface 212. The inner valve sleeve 16 may include an upper end 214 and a lower end 216. The inner valve sleeve 16 may be operably positioned such that it extends from the inner bore 184 of the outer valve sleeve 14 through the inner bore 176 of the compression nut 18 and into the inner bore 154 of the spring nut 20. The lower end 216 abuts against the top edge 166 of the shoulder 160 of the spring nut 20. The inner valve sleeve 16 is operably secured to the spring nut 20. Figure 1The “no-drilling” position of component 10 is shown as follows: the outer surface 212 of the upper section 218 of the inner valve sleeve 16 abuts against the inner bore wall 42 of the upper body 12; the outer surface 212 of the middle section 220 of the inner valve sleeve 16 is positioned adjacent to the inner bore wall 178 of the compression nut 18; and the outer surface 212 of the lower section 222 of the inner valve sleeve 16 abuts against the inner bore wall 156 of the upper section 162 of the spring nut 20. The upper section 218 may include one or more orifices 224 that, when aligned with orifices 202, provide a fluid passage from the inner bore 208 to orifices 202 in the outer valve sleeve 14. The inner valve sleeve 16 can be hermetically engaged with the outer valve sleeve 14. For example, the inner bore wall 186 of the outer valve sleeve 14 may include a recess 199 operably positioned above and below the orifice 202, wherein a seal such as an O-ring 201 is partially accommodated in the corresponding recess 199 for forming a seal between the inner bore wall 186 of the outer valve sleeve 14 and the outer surface 212 of the inner valve sleeve 16.

[0056] As mentioned above, Figures 1-4 The assembly 10 is depicted in a configuration where the drill bit is not at the bottom of the wellbore and there is no pressure to drill. Therefore, the movable internal assembly (including the internal valve sleeve 16, spring nut 20, spring spindle 28, lower spring spacer 30, spindle nut 32, and splined spindle 36) is in either its fully extended position or a pressure-free position relative to the non-moving parts of assembly 10 (i.e., the upper body 12, outer valve sleeve 14, compression nut 18, upper spring spacer 22, spring housing 26, and splined body 34). In the pressure-free position, the spring 24 is fully expanded to its preload setting, thereby forcing the movable internal assembly to move downwards relative to the bottom of the wellbore. Therefore, the shoulder 90 of the splined mandrel 36 is located at the farthest point of the splined mandrel 36 from the lower edge 64 of the splined body 34, the top edge 172 of the upper section 162 of the spring nut 20 is located below the bottom edge 182 of the compression nut 18, and the orifice 224 in the upper section 218 of the inner valve sleeve is completely below the orifice 202 of the outer valve sleeve 14. In this pressure-free configuration, the drilling fluid pumped down the drill string and into the orifice 40 of the upper body 12 flows to the drill bit through the inner bore 208 of the inner valve sleeve 16, the inner bore 50 of the spring housing 26, and the inner bore 72 of the splined mandrel 36, without being diverted through the orifice 224 of the inner valve sleeve 16 and the orifice 202 of the outer valve sleeve 14. Without this diversion, the internal flow pressure of the drilling fluid is at its pressure-free value.

[0057] Figures 5-8The diagram shows assembly 10 in a configuration where the drill bit has reached the bottom of the wellbore, and some initial drilling pressure is applied to the drill bit, sufficient to overcome the extension force of spring 24 and the bottom hole assembly (BHA) pressure generated as drilling fluid is pumped through the drill string and assembly 10 to the drill bit. Consequently, the movable inner assembly has moved upward relative to the fixed portion of assembly 10, causing the shoulder 90 of the spline mandrel 36 to move along the direction of the lower edge 64 of the spline body 34 and closer to the lower edge 64 of the spline body 34, the top edge 172 of the upper section 162 of the spring nut 20 to partially move into the inner bore 176 of the compression nut 18, and the orifice 224 in the upper section 218 of the inner valve sleeve to move along the direction of the orifice 202 of the outer valve sleeve 14 and closer to the orifice 202 of the outer valve sleeve 14.

[0058] Figures 9-11 The assembly 10 is shown in such a configuration that the drill pressure on the drill bit has been increased sufficiently to move the internal movable component portion further to a partially open valve position (split). Accordingly, the shoulder 90 of the spline mandrel 36 has moved even closer to the lower edge 64 of the spline body 34, the top edge 172 of the upper section 162 of the spring nut 20 has moved further upward into the inner bore 176 of the compression nut 18, and the orifice 224 in the upper section 218 of the inner valve sleeve has moved upward and is partially aligned with the orifice 202 of the outer valve sleeve 14 (i.e., the top of the orifice 224 is aligned with the bottom of the orifice 202, so that some confined fluid flow can now be realized through the orifice 224, the orifice 202, and through the orifice 206 in the upper body 12 into the annular space (not shown)). The confined fluid flow into the annular space (not shown) causes an initial drop in the bottom drill assembly pressure, thereby reducing the effective reaction force and allowing the drill pressure to further overcome the extension force of spring 24 and the bottom drill assembly pressure to achieve full valve opening.

[0059] Figures 11-14 The diagram shows assembly 10 in a configuration where the drill pressure on drill bit 232 has been increased, combined with a decrease in pressure on the bottom drill assembly, to further move the internal movable assembly portion to the fully open valve position (lock-on or maximum drill pressure). Accordingly, the shoulder 90 of spline mandrel 36 has contacted the lower edge 64 of spline body 34, spring 24 is fully compressed, the top edge 172 of upper section 162 of spring nut 20 has moved further upward into the inner bore 176 of compression nut 18, and the orifice 224 in upper section 218 of inner valve sleeve has moved upward and is fully aligned with the orifice 202 of outer valve sleeve 14. (As shown in...) Figure 14As seen in the diagram, as some drilling fluid flows through orifice 224, orifice 202, and then through orifice 206 in the upper body 12 into the annular space 236, the pressure of the bottom drill string assembly decreases to its minimum value.

[0060] Figure 14 This is a schematic diagram of a drilling operation using component 10. Drill rig 226 is positioned at the well surface 228. Drill string 230 extends from drill rig 226 into wellbore 234 and terminates at bottom drill string assembly 237, which includes drill bit 232 positioned at the bottom of wellbore 240. Component 10 is operatively coaxially (in-line) connected to drill string 230. As shown, component 10 is configured in its fully open position (lock-on). Drilling fluid 238 is pumped down along drill string 230, partially diverted as described above, and enters annular space 236. It should be understood that drill string 230 can be interconnected drill tubing or coiled tubing.

[0061] It should be understood that Figures 11-14 The fully open valve configuration of component 10 shown can return to a pressure-free configuration by minimizing the applied drilling pressure. For example, drill string 230 can be lifted by drill rig 226 such that drill bit 232 is lifted away from the bottom of wellbore 240 to reduce or eliminate drilling pressure. Accordingly, the movable internal component portion will return (moving downward relative to the fixed portion of component 10) to the pressure-free position by the extension force of spring 24 and bottom drill assembly pressure.

[0062] Figure 15 A formula is described to determine the distance traveled by the internal valve sleeve 16 (or any part including the internal movable components) based on values ​​of drill pressure, flow pressure, valve area, spring stiffness, and preload distance. This formula can be used to determine the valve area (nozzle size), the initial spring, the size of the initial spring spacer for spring preload, and therefore the spring force required to set the drill bit protector for a specific drill pressure.

[0063] Figure 16 It is drawing Figure 15 The table provides representative graphs of the formula data and results (such as the relationship between valve position and applied drill pressure and average bottom drill string assembly pressure). This table can be used as a visual aid to observe the functionality of the invention in a specific configuration.

[0064] All parts of component 10 can be made of any material that is durable enough to operate in a downhole environment. For example, component 10 can be made of metal, such as steel except for the inner valve sleeve 14 and the outer valve sleeve 16. The inner valve sleeve 14 and the outer valve sleeve 16 are made of a highly wear-resistant material, such as cermet (tungsten carbide) or ceramic (silicon nitride). The dimensions of the parts of component 10 can vary depending on the operating parameters associated with a particular drilling operation.

[0065] When the applied drilling pressure exceeds (1) the preload force of spring 24 and (2) the flow pressure of the inner valve sleeve 16 * effective area, the movable internal assembly (including splined mandrel 36, mandrel nut 32, lower spring spacer 30, spring mandrel 28, spring nut 20, and inner valve sleeve 16) begins to move upward relative to the fixed portion of assembly 10, while compressing spring 24. Once the orifice 224 in the upper section 218 of the inner valve sleeve 16 reaches and partially aligns with the orifice 202 in the outer valve sleeve 14, drilling fluid 238 begins to be bypassed into the annular space 236, resulting in a decrease in bottom hole assembly pressure (psi). As the pressure flow decreases, the resultant force acting on the effective area of ​​the inner valve sleeve 16 decreases significantly, causing the movable internal assembly to move the inner valve sleeve 16 to the fully open position (lock-on). When fully open, the decrease in flow pressure reduces the effective drilling pressure by reducing the internal pressure acting on the bottom hole assembly. The resulting pressure change can be observed by the operator on drilling rig 226 at well surface 228.

[0066] Damping occurs during normal drilling, thus minimizing any dynamic changes in drilling pressure and "bit bounce," preventing unintentional tool activation. The damping effect prevents the tool from reacting too quickly, and the damping effect occurs when fluid trapped in the cavity of the spring region attempts to escape through the small annular gap between the mandrel nut 32 and the spring housing 26, and then through the second annular gap between the spline mandrel 36 and the spline body 34.

[0067] Component 10 operates automatically (without operator input); the operator sees a significant pressure drop. When the operator lifts the drill string 230 (e.g., drill pipe or coiled tubing), the drilling pressure decreases to below the spring force required to achieve a “crack” (minus the force acting on the internal valve sleeve 16 (piston), which is lost when the internal valve sleeve 16 is activated), and the pressure increases again.

[0068] By reducing internal flow pressure and thus reducing tension on the drill string 230 when the internal valve sleeve 16 opens, assembly 10 reduces drill pressure independently of the operator on the surface. Normally, closed-loop latching (open-close, bistable, or position-biased) valves utilize a decrease in internal pressure to transition to full opening. Assembly 10 sends a signal to the surface notifying the operator of excessive drill pressure. The operator reduces drill pressure by raising the drill string 230, causing the bypass to automatically close (i.e., the expansion of spring 24, combined with pressure on the bottom drill string assembly, causes the internal valve sleeve 16 to move downward relative to the external valve sleeve 14, thereby misaligning and closing orifices 224 and 202).

[0069] While preferred embodiments of the invention have been described, it should be understood that the described embodiments are merely illustrative, and the scope of the invention is limited only by the appended claims, which impose the full scope of their equivalents. Many variations and modifications will naturally occur to those skilled in the art upon careful reading of the invention.

Claims

1. A drill bit protector assembly, comprising: An outer housing including an inner bore defined by an inner bore wall, the outer housing including one or more orifices for allowing drilling fluid to pass through an annular space of the wellbore; An external valve sleeve includes an inner bore defined by an inner bore wall, the external valve sleeve being received within the inner bore of the outer housing and fixed to the inner bore wall of the outer housing, the external valve sleeve including one or more orifices, the one or more orifices of the external valve sleeve being for allowing drilling fluid to pass through the one or more orifices of the outer housing; An internal component, selectively axially movable relative to the external valve sleeve and partially housed within the inner bore of the outer housing, the internal component including an internal valve sleeve positioned within the inner bore of the external valve sleeve, the internal valve sleeve including one or more orifices for selectively directing drilling fluid to the one or more orifices of the external valve sleeve, the internal valve sleeve having a non-actuated position and an actuated position, in the non-actuated position being in no fluid communication with the one or more orifices of the external valve sleeve, and in the actuated position being in fluid communication with the one or more orifices of the external valve sleeve; A spring, positioned within the inner bore of the outer housing and operably connected to the inner valve sleeve, the spring having a preload force; and The internal component is operatively connected to the drill bit and configured to place one or more orifices of the internal valve sleeve in the non-actuated position based on the drill bit's WOB force being less than the counteracting force, and to place one or more orifices of the internal valve sleeve in the actuated position based on the WOB force being greater than the counteracting force, the counteracting force comprising the preload force of the spring plus drilling fluid flow pressure in the region near the internal valve sleeve.

2. The drill bit protector assembly according to claim 1, wherein, The internal component includes a spring spindle positioned within the inner bore of the outer housing, the spring spindle being operatively connected to the internal valve sleeve and the spring, the spring being positioned about a portion of the spring spindle.

3. The drill bit protector assembly according to claim 2, wherein, The internal component includes a splined mandrel partially positioned within the inner bore of the outer housing, the splined mandrel having an upper end portion operably contacting a lower end portion of the spring mandrel, and the splined mandrel having a lower end portion operably connected to the drill bit.

4. The drill bit protector assembly according to claim 3, wherein, The internal component includes a mandrel nut operably positioned within the inner bore of the outer housing between the upper end of the spline mandrel and the inner bore wall of the outer housing. The mandrel nut is directly connected to the upper end of the spline mandrel and is movable together with the upper end of the spline mandrel. The mandrel nut is configured to hold the lower end of the spring mandrel onto the upper end of the spline mandrel.

5. The drill bit protector assembly according to claim 4, wherein, The internal component includes a lower spring spacer, which is operably positioned within the inner bore of the outer housing between the spring spindle and the inner bore wall of the outer housing. The bottom end of the lower spring spacer contacts the upper end of the spindle nut and is movable together with the upper end of the spindle nut. The upper end of the spring spacer contacts the lower end of the spring.

6. The drill bit protector assembly of claim 5 further includes an upper spring spacer operably positioned within the inner bore of the outer housing, the upper spring spacer being attached to the outer housing, and the lower end of the upper spring spacer contacting the upper end of the spring.

7. The drill bit protector assembly according to claim 6, wherein, The internal component includes a spring nut that is partially operably positioned within the inner bore of the outer housing between the spring spindle and the inner bore wall of the outer housing, the spring nut being directly connected to the upper end of the spring spindle.

8. The drill bit protector assembly of claim 7 further includes a compression nut fixedly attached to the inner bore wall of the outer housing, the compression nut having an inner bore defined by the inner bore wall, the inner bore of the compression nut being sized to receive the upper section of the spring nut when the inner valve sleeve is in the actuated position.

9. The drill bit protector assembly according to claim 8, wherein, The upper section of the spring nut is directly connected to the lower end of the inner valve sleeve.

10. The drill bit protector assembly according to claim 4, wherein, The upper end of the splined mandrel includes a seal that provides a sealed connection between the splined mandrel and the mandrel nut.

11. The drill bit protector assembly according to claim 1, wherein, The upper end of the outer valve sleeve includes a seal and the lower end of the outer valve sleeve includes a seal, the seals providing a sealed connection between the outer valve sleeve and the outer housing, and wherein the one or more orifices of the outer valve sleeve are positioned between the seals at the upper end of the outer valve sleeve and the seals at the lower end of the outer valve sleeve.

12. The drill bit protector assembly according to claim 3, wherein, The portion of the lower end of the splined mandrel that is not contained within the inner bore of the outer housing includes a rib having an upper shoulder that abuts the lower terminating edge of the outer housing when the inner valve sleeve is in the actuated position.

13. The drill bit protector assembly according to claim 1, wherein, The outer housing includes an upper body, a spring housing, and a spline body. The lower end of the upper body is directly connected to the upper end of the spring housing, and the lower end of the spring housing is directly connected to the upper end of the spline body.

14. A method for managing the pressure on the drill bit (WOB) during drilling operations, comprising the following steps: a) The drill string is advanced down the wellbore, terminating at a bottom drill assembly (BHA) including the drill bit, the drill string including a bit protector assembly operably positioned above the BHA, the bit protector assembly comprising: an outer housing including an inner bore defined by an inner bore wall, the outer housing including one or more orifices for allowing drilling fluid to pass through an annular space of the wellbore; and an outer valve sleeve including an inner bore defined by an inner bore wall, the outer valve sleeve being received within the outer housing. An outer valve sleeve, which is fixed to the inner wall of the outer housing within an inner bore, includes one or more orifices for allowing drilling fluid to pass through. An inner assembly, selectively axially movable relative to the outer valve sleeve and partially housed within the inner bore of the outer housing, includes an inner valve sleeve positioned within the inner bore of the outer valve sleeve, the inner valve sleeve including one or more orifices. The one or more orifices are used to selectively direct the drilling fluid to the one or more orifices of the outer valve sleeve. The inner valve sleeve has a non-actuated position and an actuated position. In the non-actuated position, the one or more orifices of the inner valve sleeve are not in fluid communication with the one or more orifices of the outer valve sleeve. In the actuated position, the one or more orifices of the inner valve sleeve are in fluid communication with the one or more orifices of the outer valve sleeve. A spring is positioned within the inner bore of the outer housing and is capable of... The spring is operatively connected to the internal valve sleeve and has a preloaded force; and wherein the internal assembly is operatively connected to the drill bit and configured to place one or more orifices of the internal valve sleeve in the non-actuated position based on the WOB force on the drill bit being less than the counteracting force, and to place one or more orifices of the internal valve sleeve in the actuated position based on the WOB force being greater than the counteracting force, the counteracting force comprising the preloaded force of the spring plus drilling fluid flow pressure in the region adjacent to the internal valve sleeve; b) Position the drill bit to contact the bottom of the wellbore; c) The drill bit is driven into the bottom of the wellbore, and the drill bit is subjected to the WOB force; d) Increase the WOB force on the drill bit as the drill bit penetrates the bottom of the wellbore by moving the inner valve sleeve from the non-actuated position to the actuated position when the WOB force becomes greater than the counteracting force.

15. The method according to claim 14, wherein, In step (d), the inner valve sleeve moves upward relative to the outer valve sleeve to align the one or more orifices of the inner valve sleeve with the one or more orifices of the outer valve sleeve.

16. The method according to claim 15, wherein, The flow of drilling fluid from the inner hole of the outer housing to the annular space results in a reduction in the drilling fluid flow pressure acting on the BHA.

17. The method according to claim 16, wherein, The pressure gauge on the drilling ring indicates a decrease in the pressure of the drilling fluid flow acting on the BHA.

18. The method of claim 14, further comprising the step of: e) When the WOB force becomes less than the counteracting force, the drill bit is lifted away from the bottom of the wellbore so that the internal valve sleeve returns to the non-actuated position.

19. The method of claim 14, wherein, The internal assembly includes a spring mandrel positioned within the inner bore of the outer housing, operably connected to the internal valve sleeve and the spring, the spring being positioned about a portion of the spring mandrel; wherein the internal assembly includes a spline mandrel partially positioned within the inner bore of the outer housing, the spline mandrel having an upper end portion operably contacting a lower end portion of the spring mandrel, the spline mandrel having a lower end portion operably connected to the drill bit; wherein the internal assembly includes a mandrel nut operably positioned within the inner bore of the outer housing between the upper end portion of the spline mandrel and the inner bore wall of the outer housing, the mandrel nut being directly connected to and movable with the upper end portion of the spline mandrel, the mandrel nut being configured to hold the lower end portion of the spring mandrel onto the upper end portion of the spline mandrel; and The method includes the step of the drill bit protector assembly generating a damping effect during drilling, the damping effect minimizing dynamic changes in the WOB and drill bit bounce to prevent the internal valve sleeve from unintentionally moving from the non-actuated position to the actuated position.

20. The method according to claim 19, wherein, The damping effect is activated by the drilling fluid, which is trapped in the cavity in the region of the spring, traveling through the first annular gap between the mandrel nut and the spring housing and again through the second annular gap between the spline mandrel and the spline body.

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