SUMMARY
The present invention is directed to a well service system comprising a first tool assembly and a second tool assembly. The first tool assembly has a central passage extending therethrough and opposed ends. Each end is configured to be attached to separate sections of a work string such that the first tool forms a portion of the work string. The first tool is defined by an annular seat and a lock profile. The annular seat is formed within the walls surrounding the central passage and has a first inside diameter. The lock profile is formed within the walls surrounding the central passage.
The second tool assembly is receivable in the first tool and configured to be delivered to the central passage of the first tool assembly using fluid. The second tool assembly comprises a locking mandrel and a work tool. The locking mandrel is configured for attachment to the lock profile. The locking mandrel has a shoulder with an outside diameter greater than the first inside diameter. The work tool is attached to the locking mandrel.
In another aspect, the present invention is directed to a kit. The kit is for use with a first tool having an internal shoulder and an internally-oriented lock profile. The kit comprises a work tool, a locking mandrel attached to the work tool, a first deformable ball and a second deformable ball.
The locking mandrel comprises a tubular outer body, an inner body, and a plurality of keys. The tubular outer body has a plurality of slots and a stop shoulder. The stop shoulder has a diameter greater than the internal shoulder of the first tool. The inner body is movable within the tubular outer body from a first position to a second position. The inner body comprises a funnel, the funnel having a minimum inner diameter. The plurality of keys are positioned such that they extend from the plurality of slots when the inner body is in the second position. A first force is required to move the inner body from the first position to the second position.
The first deformable ball has a diameter greater than the minimum inner diameter of the funnel, and is deformable to a diameter less than the minimum inner diameter when a second force is applied to the first deformable ball. The second deformable ball has a diameter greater than the minimum inner diameter of the funnel, and is deformable to a diameter less than the minimum inner diameter when a third force is applied to the second deformable ball. The third force is greater than the first force, and the first force is greater than the second force.
BRIEF DESCRIPTION OF THE DRAWINGS
FIG. 1 is a cross-sectional view of a horizontal well. A work string, or production string is disposed through the well, with a bottom hole assembly at a terminal end.
FIG. 2 is an enlarged view of area A, shown in FIG. 1. This is the bottom hole assembly of the production string.
FIG. 3 is an enlarged view of area B, shown in FIG. 1. This figure shows a larger diameter area within the work string.
FIG. 4 is a cross-sectional view of the work string with a no-go landing nipple and adapter sub installed within the larger diameter area shown in FIG. 3, taken along line C-C. The casing is omitted for clarity.
FIG. 5 is a perspective view of a jar tool assembly of a multi-function well service system.
FIG. 6 is a cross-sectional view of the jar tool assembly shown in FIG. 5, taken along line D-D.
FIG. 7 is a perspective view of a locking mandrel used in the jar tool assembly shown in FIG. 5. The locking mandrel is shown in the unlocked state.
FIG. 8 is a perspective view of the locking mandrel shown in FIG. 7, shown in the locked state.
FIG. 9 is a cross-sectional view of the locking mandrel shown in FIG. 7, taken along the line E-E.
FIG. 10 is a cross-sectional view of the locking mandrel shown in FIG. 8, taken along line F-F.
FIG. 11 is a perspective view of a partial cross-section of the check valve used in the jar tool assembly shown in FIG. 5, taken along line D-D. The flappers are not sectioned. The check valve is shown with the flappers in the open state. The other components of the multi-function well service system are omitted for clarity.
FIG. 12 is the check valve shown in FIG. 11 with the flappers in the closed state.
FIG. 13 is a perspective view of a jar used in the jar tool assembly shown in FIG. 5.
FIG. 14 is a cross-sectional view of the jar shown in FIG. 13, taken along line G-G.
FIG. 15 is a perspective view of a partial cross-section of the multi-function well service system, having a jar tool assembly, within a work string. The jar tool assembly is not sectioned. The locking mandrel is shown in the unlocked state.
FIG. 16 is an enlarged view of area H, shown in FIG. 15. This figure shows the interface between an internal seat and the shoulder off the locking mandrel
FIG. 17 is an enlarged view of area I, shown in FIG. 15. This figure shows the shows the locking mandrel in a first condition, with locking keys in place but not expanded
FIG. 18 is FIG. 15 with the locking mandrel shown in the second condition—that is, in the locked state.
FIG. 19 is an enlarged view of area J shown in FIG. 18, which is the locking mandrel with extended keys.
FIG. 20 is a perspective view of a perforating tool assembly of a multi-function well service system.
FIG. 21 is a cross-sectional view of the perforating tool assembly shown in FIG. 20, taken along line K-K.
FIG. 22 is a perspective view of a partial cross-section of the multi-function well service system, having a perforating tool assembly, within a work string. The perforating tool assembly is not sectioned. The locking mandrel is shown in the locked state.
FIG. 23 is an elevation view of the multi-function well service system shown in FIG. 22 with all components sectioned. Fluid flow is indicated by the arrows.
FIG. 24 is an enlarged view of area L, shown in FIG. 23. Abrasive fluid is shown impacting the inside wall of the work string.
FIG. 25 is an enlarged view of area L, shown in FIG. 23. Abrasive fluid is shown having eroded a passage through the work string.
FIG. 26 is a perspective view of the work string after the completed perforation process.
FIG. 27 is a perspective view of a cutoff tool assembly of a multi-function well service system.
FIG. 28 is a cross-sectional view of the cutoff tool assembly shown in FIG. 27, taken along line M-M.
FIG. 29 is a cross-sectional view of the cutoff tool assembly shown in FIG. 27, taken along line N-N.
FIG. 30 is a perspective view of a partial cross-section of the multi-function well service system, having a cutoff tool assembly, within a work string. The cutoff tool assembly is not sectioned. The locking mandrel is shown in the locked state.
FIG. 31 is an enlarged view of area O, shown in FIG. 30. Abrasive fluid is shown impacting the inside wall of the work string.
FIG. 32 is an enlarged view of area O, shown in FIG. 30. Abrasive fluid is shown having severed the wall of the work string.
FIG. 33 is a perspective view of the work string after the completed cutoff process.
DETAILED DESCRIPTION
A typical horizontal well 100, shown in FIG. 1, comprises a derrick 101 with a platform 102, a well head 103, and a bore hole 104. The bore hole 104 comprises a vertical section 105, and a horizontal section 106. The bore hole 104 may also comprise a casing 107 that lines all or a portion of the bore hole 104.
During the drilling, completion, and production phases of the horizontal well 100 it may be necessary to insert a work string 108 to perform the various tasks associated with each phase. While performing these various tasks the work string 108 may encounter or create numerous issues that prevent or complicate attempts to perform the various tasks. One example of such an issue is a stuck bottom hole assembly, BHA, 109 shown in FIG. 2. More solutions are needed in the industry to address these numerous issues once they occur.
Referring now to FIGS. 3-33, a multi-function well service system 110 is shown. The multi-function well service system 110 comprises an inside diameter profile 111 or inside diameter restriction 111 within the work string 108 and a plurality of tool assemblies 112, 113, and 114. The multi-function well service system 110 may further comprise an adapter sub 115 or plurality of adapter subs 115 if needed.
In this embodiment there is an inside diameter restriction 111 that comprises a no-go landing nipple 116 installed intentionally within the work string 108. However, the inside diameter profile 111 or restriction 111 may instead be created by the problem encountered by the work string 108 after the work string 108 is inserted in the bore hole 104. Alternatively, the inside diameter profile 111 or restriction 111 may instead be created by the work string 108 and/or operator and/or bore hole environment at any time. As long as the inside diameter profile 111 or restriction 111 can be inferred and/or measured within a range of values and/or above and/or below a target value or values the tool assemblies 112, 113, 114 may be deployed.
Referring now to FIG. 4, the no-go landing nipple 116 is shown installed within the work string 108 along with an adapter sub 115. The no-go landing nipple 116 comprises a no-go landing seat 117, a seal area 118, and a lock profile 119. The components of the no-go landing nipple 116 are typical of other no-go landing nipples in the industry, however, the no-go landing nipple 116 has an outer diameter that is larger than is standard in the industry. The no-go landing nipple 116 will typically be installed in the first joint above the bottom hole assembly 109.
One of the plurality of tool assemblies 112, 113, and 114, is the jar tool assembly 112 shown in FIGS. 5-19. The jar tool assembly 112 comprises a locking mandrel 120, a check valve 121, and a jar 122. The check valve 121 may not be included.
Referring now to FIGS. 7-10 the locking mandrel 120 comprises a fish neck assembly 123, seal tube 124, body 125, a plurality of keys 126, and seal 127. The fish neck assembly 123 comprises the funnel 128 and the ramp tube 129. The seal tube 124 comprises a no-go shoulder 130. Typical locking mandrels trap the keys within the body using component features such as shoulders and order of assembly to accomplish the task, this locking mandrel 120 is no different. In operation the fish neck assembly 123 may be extended and retracted in relation to the body 125. As can be seen in FIGS. 7 and 9, when the fish neck assembly 123 is extended, the smaller diameter section 131 of the ramp tube 129 is aligned with the inside diameter of the keys 126. This positioning allows the keys 126 to retract back into the body 125 configuring the locking mandrel 120 in the unlocked position. Referring now to FIGS. 8 and 10, when the fish neck assembly 123 is retracted the larger diameter section 132 of the ramp tube 129 is aligned with the inside diameter of the keys 126. This positioning forces the keys 126 out thorough the key slots 133 of the body 125 configuring the locking mandrel 120 in the locked position. The keys 126 are prevented from going all the way through the key slots 133 by a lower flange that is wider than the key slots 133. The fish neck assembly 123 may be moved from the extended to the retracted position which will be discussed later.
Referring now to FIGS. 11-12, a check valve 121 is shown. The check valve 121 comprises a body 134 and a plurality of flappers 135. This is a dual flapper check valve 121 as is typical in the industry. In operation the flappers 135 are biased to the closed position as shown in FIG. 12. When fluid, shown by the arrows in FIG. 11, is pumped downhole the flappers 135 open allowing fluid downhole. If the pressure is greater downhole than uphole the fluid in the bore hole 104 will attempt to flow uphole. The flappers 135 then close preventing flow uphole as shown by the arrows in FIG. 12.
Referring now to FIGS. 13-14, a jar 122 is shown. The jar 122 comprises a funnel sub 136, a fluid release sub 137, a receiver sub 138, and an end cap 139. The jar 122 is described in greater detail in U.S. Pat. No. 10,267,114 the entirety of which is incorporated herein by reference.
Referring now to FIGS. 15-17, the jar tool assembly 112 is shown inserted in the no-go landing nipple 116. Referring now to FIG. 16, once inserted in the no-go landing nipple 116 the no-go shoulder 130 of the seal tube 124 of the locking mandrel 120 abuts the no-go landing seat 117 of the no-go landing nipple 116. Also, the seals 127 of the locking mandrel 120 engage the seal area 118 of the no-go landing nipple 116. Additionally, the keys 126 are aligned with the lock profile 119 of the no-go landing nipple 116 as shown in FIG. 17. This condition is referenced herein as a “first condition” of each of the tool assemblies 112, 113, 114.
In operation, when the work string 108 is experiencing one of the numerous possible issues that prevent or complicate attempts by the work string 108 to perform the various tasks required of it, an analysis is performed. If the analysis concludes a jar 122 will be the best option to solve the issue, then the jar tool assembly 112 is prepared for deployment. Preparation is done by inserting a first deformable ball 140 in the funnel sub 136 of the jar 122 and then assembling the jar 122 to the check valve 121 and the check valve 121 to the locking mandrel 120 trapping the first deformable ball 140 in the jar tool assembly 112, as shown in FIGS. 6 and 14. The jar tool assembly 112 is then inserted in the work string 108 at the well head 103 and fluid is pumped downhole. The first deformable ball 140 prevents flow through the jar tool assembly 112 so the jar tool assembly 112 is carried downhole by the fluid until it reaches the no-go landing nipple 116. Once the locking mandrel 120 enters the no-go landing nipple 116 the seals 127 will likely provide enough resistance to stop the movement of the jar tool assembly 112. The drilling operator can see that there is resistance by the increase of fluid pressure in the bore hole 104. The operator will increase fluid pressure until the first deformable ball 140 is extruded through the funnel sub 136 of the jar 122 and caught in the receiver sub 138. The desired pressure needed to extrude the first deformable ball 140 is 2,000-2,500 pounds per square inch. Once the first deformable ball 140 is extruded the jar tool assembly 112 has moved all the way into the no-go landing nipple 116, the no-go shoulder 130 has engaged the no-go landing seat 117, and the jar tool assembly 112 is positioned correctly in the no-go landing nipple 116, as shown in FIGS. 15-17.
Once the jar tool assembly 112 is set in the no-go landing nipple 116 it must be locked in place. The jar tool assembly 112 is locked in place by inserting a second deformable ball 141 in the work string 108 at the well head 103. The second deformable ball 141 is pumped downhole until it lands in the funnel 128 of the fish neck assembly 123 of the locking mandrel 120, as shown in FIG. 6. Once the second deformable ball 141 is in the funnel 128 of the fish neck assembly 123 the operator will increase fluid pressure. The increase in fluid pressure will create a force in the downhole direction moving the fish neck assembly 123 within the body 125 of the locking mandrel 120. As the fish neck assembly 123 moves downhole relative to the body 125 of the locking mandrel 120 the larger diameter section 132 of the ramp tube 129 will engage the inside diameter of the keys 126 forcing the keys 126 radially outward, as shown in FIGS. 18-19. This condition is referred to herein as a “second condition.”
The outer profile of the keys 126 will engage the lock profile 119 of the no-go landing nipple 116. Pressure is increased until the second deformable ball 141 is extruded through the funnel 128. The desired pressure to extrude the second deformable ball 141 is higher than that desired to extrude the first deformable ball 140 typically 4,000-4,500 pounds per square inch. It should be understood that in order to use the second deformable ball 141 to move the ramp tube 129 to the second condition, the pressure (and thus the force) on the second ball 141 and the funnel 128 must be less than the pressure to extrude the second deformable ball (or else the ball would extrude before moving the ramp tube 129) but greater than the pressure to extrude the first deformable ball 140 (or else the first ball would move the ramp tube 129 to the second condition).
When the second deformable ball 141 is extruded the ball 141 will be travelling at supersonic speeds and will pass through the funnel sub 136 of the jar 122 before expanding and be captured in the receiver sub 138. The jar 122 may now be used as described in the previously referenced patent.
Another of the plurality of tool assemblies 112, 113, and 114, is the perforating tool assembly 113 shown in FIGS. 20-26. The perforating tool assembly 113 comprises a locking mandrel 120, a check valve 121, and a perforating tool 142. The check valve 121 may or may not be included.
Referring now to FIG. 21, the perforating tool 142 comprises a body 143, and an end cap 139. The perforating tool 142 may further comprise a plurality of nozzles 144. The body 143 comprises a plurality of holes 145 through the wall of the body 143 oriented at a non-zero angle to the longitudinal axis of the body 143. In the embodiment shown the holes 145 are perpendicular to the longitudinal axis of the body 143 and are threaded to accept replaceable nozzles 144. Also, in the embodiment shown the holes 145 are oriented the same radially but may be oriented at different radial positions about the longitudinal axis. Additionally, in the embodiment shown there are two holes 145 but there may be only one hole 145 or more than two.
If the analysis mentioned above concludes a perforating tool 142 will be the best option to solve the issue, the perforating tool assembly 113 is pumped downhole and locked in the no-go landing nipple 116, as shown in FIG. 22. The perforating tool assembly 113 may be pumped down as any other tool and known to have reached the restriction 111, again in this embodiment the no-go landing nipple 116, after allowing for an appropriate time of travel based on fluid flow rate and/or by an increase in fluid pressure. The locking mandrel 120 may be locked using the second deformable ball 141 as described above.
Referring now to FIGS. 23-26, in operation, once the perforating tool assembly 113 is locked in place, abrasive fluid, or fluid with abrasive additives, is pumped downhole from the well head 103, as shown in FIG. 23. The abrasive fluid is forced through the small holes 145 or small orifices of the nozzles 144 if used. The small holes 145 or small orifices of the nozzles 144 increase the velocity of the abrasive fluid which impacts the inner wall of the work string 108, as shown in FIG. 24. Continued application of the abrasive fluid stream to the inner wall of the work string 108 eventually erodes the wall of the work string 108 to the point a hole 146 is created in the wall of the work string 108, as shown in FIGS. 25-26. The holes 146 in the wall of the work string 108 may then allow fluid to flow from the formation into the work string 108 and be removed through the well head 103. It is anticipated that the abrasive fluid stream may be combined with or replaced by a chemical fluid stream that will erode the inner wall through chemical interaction. It is also anticipated that a locking mandrel 120 may not be used and only the perforating tool 142 be pumped downhole. If no locking mandrel 120 is used then a no-go shoulder 130 will be formed on the uphole end of the body 143 of the perforating tool 142.
Another of the plurality of tool assemblies 112, 113, and 114, is the cutoff tool assembly 114 shown in FIGS. 27-33. The cutoff tool assembly 114 comprises a locking mandrel 120, a check valve 121, and a cutoff tool 147. The check valve 121 may not be included.
Referring now to FIGS. 27-29, the cutoff tool 147 comprises a body 148, and a rotating cap 149. The cutoff tool 147 may further comprise a nozzle 144. The rotating cap 149 comprises a hole 150 through the wall of the rotating cap 149 oriented at a non-zero angle to the longitudinal axis of the rotating cap 149, as shown in FIG. 29, and at a non-zero angle to the transverse axis of the rotating cap 149 as shown in FIG. 28. The hole 150 may be threaded to accept nozzles 144. In the embodiment shown, the hole 150 is perpendicular to the longitudinal axis of the rotating cap 149 and at an angle of 30-35 degrees relative to the transverse axis. Also in this embodiment, there is one hole 150. There may be a plurality of holes 150.
If the analysis mentioned above concludes a cutoff tool 147 will be the best option to solve the issue, the cutoff tool assembly 114 is pumped downhole and locked in the no-go landing nipple 116, as shown in FIG. 30. The cutoff tool assembly 114 may be pumped down as any other tool and known to have reached the restriction 111, again in this embodiment the no-go landing nipple 116, after allowing for an appropriate time of travel based on fluid flow rate and/or by an increase in fluid pressure. The locking mandrel 120 may be locked using the second deformable ball 141 as described above.
Once the cutoff tool assembly 114 is locked in the no-go landing nipple 116 the cutoff tool assembly 114 will not rotate. However, the connection between the rotating cap 149 and the body 148 of the cutoff tool 147 permits rotation of the rotating cap 149 relative to the body 148 of the cutoff tool 147.
Referring now to FIGS. 30-33, in operation, once the cutoff tool assembly 114 is locked in place, abrasive fluid, or fluid with abrasive additives, is pumped downhole from the well head 103. The abrasive fluid is forced through the small hole 150 or the small orifices of the nozzle 144 if used. The small hole 150 or orifice of the nozzle 144 increases the velocity of the abrasive fluid which impacts the inner wall of the work string 108, as shown in FIG. 31. The angle of the hole 150 relative to the transverse axis also imparts a torsional force about the longitudinal axis causing the rotating cap 149 to rotate. As the rotating cap 149 rotates the abrasive fluid impacts the inner wall of the work string 108 in a path 151 that goes around the entire circumference of the inner wall of the work string 108, as shown in FIG. 31. Continued application of the abrasive fluid stream to the inner wall of the work string 108 eventually erodes the wall of the work string 108 to the point the entire wall of the work string 108 is severed, as shown in FIGS. 32-33. The uphole section of work string 108 which is still attached to the well head 103 may then be removed from the bore hole 104 leaving the downhole portion of the work string 108 in the bore hole 104. It is anticipated that the abrasive fluid stream may be combined with or replaced by a chemical fluid stream that will erode the inner wall through chemical interaction. It is also anticipated that a locking mandrel 120 may not be used and only the cutoff tool 147 be pumped downhole. If no locking mandrel 120 is used then a no-go shoulder 130 will be formed on the uphole end of the body 148 of the cutoff tool 147. Also, if no locking mandrel 120 is used then friction between the no-go shoulder 130 on the body 148 of the cutoff tool 147 and no-go landing seat 117 caused by the fluid pressure will prevent the body 148 of the cutoff tool 147 from rotating.
While the multi-function well service system 110 has been enabled showing the use of three separate tool assemblies 112, 113, 114, it is anticipated that a plurality of additional tool assemblies be used in the multi-function well service system 110. The additional tool assemblies may not include a locking mandrel 120 or a funnel sub 136. In such cases the tool assembly may be pumped down and set within the known inside diameter profile 111 or restriction 111 using momentum imparted by fluid flow. A non-limiting list of other tool assemblies that may be used in the multi-function well service system 110 includes: an extended reach tool, any tool using abrasive material and/or methods to achieve the desired result, any tool using chemicals and/or chemical reactions to achieve the desired result, any tool using mechanical manipulation to achieve the desired result, any tool using nuclear material and/or methods to achieve the desired result, any tool using dynamically energized components, such as from an explosion or explosive substance, to achieve the desired result, and any combination of the above.
It is also anticipated that kits may be created that include the no-go landing nipple 116 and only the tool assemblies that are expected to be needed based on the type of well or the geology of the well. This allows the operator to purposely install a known inside diameter restriction 111 and customize kits for specific applications.
The various features and alternative details of construction of the apparatuses described herein for the practice of the present technology will readily occur to the skilled artisan in view of the foregoing discussion. It is to be understood that even though numerous characteristics and advantages of various embodiments of the present technology have been set forth in the foregoing description, together with details of the structure and function of various embodiments of the technology, this detailed description is illustrative only, and changes may be made in detail. Changes may especially be made in matters of structure and arrangements of parts within the principles of the present technology to the full extent indicated by the broad general meaning of the terms in which the appended claims are expressed.
Patent Application
20250075575
