Patent Grant
11788382
The present disclosure relates to downhole drilling assemblies for use in horizontal and vertical drilling operations, and in particular valve control within a drilling string.
In oil and gas production and exploration, downhole drilling can be accomplished with a downhole drill powered by a mud motor. The drilling fluid used to drive the motor also assists the drilling process in other ways, for example by dislodging and removing drill cuttings, cooling the drill bit, and providing pressure to prevent formation fluids from entering the wellbore.
Stalling and slip-stick issues can result in damage to drilling string components. It is believed that applying a vibrational or oscillating effect to the drill string components can improve performance of a downhole drill, and/or mitigate or reduce incidences of stalling and slip-stick.
Further, when drilling deep bore holes in the earth, sections of the bore hole can cause drag or excess friction which may hinder proper weight transfer to the drill bit or causes erratic torque in the drill string. These effects may have the result of slowing down the rate of penetration, creating bore hole deviation issues, or even damaging drill string components.
Friction tools are often used to overcome these problems by vibrating a portion of the drill string to reduce friction or hole drag. Friction tools may form part of the downhole assembly of the drilling string, and can be driven by the flow of drilling fluid through the friction tool. Accordingly, the operation of a friction tool may be constrained by the flow rate of drilling fluid pumped through the string. Controlling the frequency of operation of the friction tool may therefore require varying or stopping the flow rate of the drilling fluid at the surface.
It is not always desirable to run a friction tool during the entirety of a drilling operation. For instance, it may be unnecessary or undesirable to run the tool while the drill bit is at a shallow depth, or at other stages of the drilling operation where the added vibration of the friction tool is problematic or not required. During those stages, the drill string may be assembled without the friction tool. However, when a location in the bore hole is reached where the need for a friction tool is evident, it may then necessary to pull the downhole assembly to the surface to reassemble the drilling string to include the friction tool, then return the drilling string to the drill point. This process can consume several work hours.
In drawings which illustrate by way of example only embodiments of the present disclosure, in which like reference numerals describe similar items throughout the various figures,
As is generally understood by those skilled in the art, in prior art downhole assemblies employing a power section (motor), drilling fluid passes from a bore or passage above the motor and into the motor to thereby activate the motor. This may be achieved by causing a rotor to rotate, and consequently drive any downhole tools linked to the rotor, such as a friction tool. Fluid passing through the motor enters the bore or passage downstream of the rotor. As can be seen in the particular example assembly 10 illustrated in
The rotation speed and horsepower of the motor is determined in part by the flow rate of drilling fluid through the motor. In a Moineau motor (“mud motor”), the particular lobe configuration of the motor and the drilling fluid type and properties will affect the motor output as well. In practice, once a drilling string is assembled and in place in the wellbore, the rotation speed and power of a motor such as a Moineau power section are changeable only by varying the flow rate of drilling fluid or else by retracting the drilling string from the bore hole, disassembling it, and reassembling it with a differently configured motor. However, it may not be desirable to vary the flow rate of the drilling fluid in this manner, and disassembling and reassembling a drilling string can consume several hours of labour.
Accordingly, a flow-through assembly 10 with a selectively activatable motor and rotating variable choke assembly is provided for use in a downhole drilling string. The flow-through assembly 10 provides a system that can be inserted into the bore hole and then selectively activated or deactivated to control the flow of drilling fluid through the motor assembly, and from the motor to any tools or other features controlled or activated by the motor assembly. When the assembly 10 includes the rotating variable choke assembly, the variable choke assembly can be selectively activated or deactivated to provide a pulsing fluid flow for use in operating friction reduction tools or other types of tools. In these embodiments, activation of the motor can include starting the motor from a stopped or stalled state (i.e., no rotation of the rotor), to an “on” state in which the rotor rotates, or from a lower output state (i.e., a lower rate of rotation or lower torque output), to an increased or higher output state (i.e., a higher rate of rotation or higher torque output).
The structure of the flow-through assembly 10 is generally illustrated in
In the particular illustrated example, component 100 is a “ball catch” sub 100 comprising ball catch components used to catch and retain a ball dropped into the drilling string by an operator (as illustrated in
Turning to
The ball catch seat 120 is supported within the interior of the ball catch retainer 130, below the ball catch head 110. A lower face of the ball catch seat 120 rests on the spring 138, and is able to reciprocate up and down within the ball catch retainer 130 as the degree of compression in the spring 138 changes under the force of drilling fluid flow when a ball 50, as shown in
When the ball catch assembly is not engaged, fluid entering the ball catch assembly can pass through the ball catch head 110, the bores 116, 122, and 134 and into other components of the assembly 10 below the ball catch assembly. Some fluid may pass through the bypass ports 114 and around the exterior of the ball catch assembly, but most fluid is expected to pass through the head 110 and bores. Thus, fluid entering the ball catch head 110 from above can pass down through the bore 116, or through the bypass ports 114 and thus pass over the outside of the ball catch head 110 and the ball catch retainer 130. When the ball catch assembly is engaged, a projectile such as the ball 50 blocks passage of fluid at the ball catch seat 120; therefore, fluid entering the ball catch assembly will flow through the ports 114 and down around the exterior of the ball catch head 110 and retainer 130 in the space defined between these components and the housing 105, and down to other components of the assembly 10 below the ball catch assembly that are in fluid communication with the exterior of the ball catch head 110 and retainer 130.
Other ball catch assemblies can be used in place of the ball catch sub 100 described above. Other examples of ball catch subs are described in International Applications No. PCT/CA2016/050950, “Selective Activation of Motor in a Downhole Assembly”, and PCT/CA2016/051096, “Selective Activation of Motor in a Downhole Assembly and Hanger Assembly”, the entireties of which are incorporated herein by reference. Furthermore, implementations of the flow-through assembly 10 may exclude a ball catch sub positioned above the valve section 400.
In the example assembly 10 shown in
Returning to
The drive section 300 comprises a housing 305 enclosing at least a substantial part of a flow-through drive shaft 310, thus defining an annular space between the interior diameter of the housing 305 and the outer diameter of the drive shaft 310. The drive shaft 310, which is illustrated in further detail in
Returning again to
The stationary and rotary components 430, 410 are illustrated in further detail in
The flow ports 424 are provided at or around the midsection of the rotary valve component 410, and are generally laterally aligned with the bypass ports 422; as can be seen in the illustrated examples, the flow ports 424 are located directly below the bypass ports 422. As may be better appreciated with reference to
Fluid access to the bypass ports 422 and flow ports 424 from above the rotary component 410 can be enhanced by further angling or tapering of the upper portion of the component 422; for example, the remaining upper exterior surfaces 418 of the component 410 are likewise angled towards the top of the component 410, as can be seen in
In the “choked” or “restricted” position, the outlets of the flow ports 424 are substantially blocked because the interior face 436 of the stationary component 430 contacts the exterior of the rotary component 410 above the flow ports 424, thereby cutting off fluid access to the flow ports 424. However, even in the “choked” state, the bypass ports 422 will still remain unblocked since the outlets of those ports 422 are disposed on a recessed upper portion of the rotary component 410, as discussed above. In addition, regardless whether the variable choke assembly is in the “choked” or “open” state, the bore 416 still permits passage of drilling fluid, drilling string instruments, and blocking projectiles to the downhole portions of the drilling string (assuming that the ball catch assembly is not engaged and blocking through passage), even when the rotary component 410 is rotating.
In the “open” position, as shown in
The operation of the flow-through assembly 10 can be understood by referring to
The fluid then passes into the bore 416 of the rotary component 410. Most drilling fluid entering the ball catch assembly will pass through the centre bore 212 of the rotor, then bores 314 and 416. However, if any fluid happens to reach the exterior of the rotary component 410, it may enter one of the bypass ports 422 and enter the bore 416 in that way; and if the rotary component 410 is in an “open” or partially-“open” position, some fluid may even enter the bore 416 via the flow ports 424 to the extent they are not blocked off. Thus, when the ball catch assembly is in the non-engaged state, the substantial part of the drilling fluid flows through the communicating bores of the various components with minimal variation in fluid pressure.
On the other hand, when the ball catch assembly is in the engaged state as in
The varying rate of fluid consequently entering the bore 416 will produce variations in the fluid pressure above the rotary component 410. The fluid pressure will vary between a minimum and maximum value, as the rotary valve component 410 rotates from the “choked” to “open” position. The resultant pressure variations can be used to operate an oscillation, friction, or impulse tool in the drilling string. It will be appreciated that even while pressure variations are being generated by the variable choke assembly, the assembly 10 still permits a significant amount of fluid to flow downstream to other drilling string components, such as the bottom hole assembly. This is because the rotary component of the variable choke assembly includes the bypass ports 422, permitting drilling fluid to bypass flow ports 424 even when the flow ports 424 are closed.
Where the assembly 10 as depicted in
When the ball catch assembly is not engaged, no projectile 50 is in place on the ball catch seat 120, and drilling fluid entering the rotary component 410 passes through the rotary component bore 416, the ball catch assembly, the drive shaft bore 314, the rotor bore 212 in a manner similar to that described above. Minimal pressure variation is produced by the assembly 10. When the ball catch assembly is engaged, the projectile 50 blocks passage of drilling fluid down the central bores 314 and 212. Drilling fluid enters the bore 416 from above, but the blockage of the bores 314 and 212 causes fluid to flow out through the bypass ports 422, which remain unblocked as described above, and through the ports 424 provided exit from the ports 424 is not blocked by the stationary component 430. This results in drilling fluid flow downwards around the exterior of the drive shaft 310, and into the motor. This activates the motor, generating torque, which is transmitted from the rotor 210 to the ball catch assembly and rotary component 410 by the drive shaft 310. As the rotary component 410 rotates, it will move between the “choked” and “open” positions described above, thereby varying the fluid pressure above the rotary component 410. Again, the pressure variations generated by the assembly 10 can be used to operate an oscillation, friction, or impulse tool.
In some implementations, the ball 50 can be manufactured of a durable, shatter-resistant material, such as stainless steel. In that case, once in place, the ball 50 is removable by retracting the assembly 10 to the surface, and disassembling a sufficient portion of the assembly 10 to retrieve the ball 50. If the ball 50 has a sufficiently magnetic composition, then the ball may be retrieved by passing a rod or probe with a magnet affixed thereto to attract and withdraw the ball 50 from the assembly.
In other implementations, the ball 50 can be manufactured of a breakable material, such as Teflon®. When such a ball 50 is in place as in
It will be appreciated by those skilled in the art that modifications can be made to the ball catch component 100. For example, as shown in
In the foregoing example, plug 500 is received in what was previously described as the upper portion of the rotary component 410, above. Thus, in this modified example, end of the modified component 410′ is connected to a rotor at the opposing end. When assembled in the drilling string, the valve section containing the modified valve component 410′ would be located uphole from the motor section 200, rather than downhole as illustrated in the earlier example. In this example, the ball catch component 100 is not required; the modified valve component 410′ operates to selectively activate or deactivate an oscillation or impulse tool in the string.
Another variant in the ball catch component 100 is illustrated in
In the embodiment illustrated in
The stationary component 650 is provided with one or more ports 652 passing through the body of the component 650, around the through bore 656. The ports are aligned to be substantially, but not necessarily, parallel to the through bore 656. The cross-sectional shape and area of each port 652 may be the same, or different, depending on the desired pulsing effect of the variable choke assembly 600. Similarly, they need not be spaced in regular intervals around the bore 656. In the illustrated embodiment, each port 652 has a rounded arcuate cross-sectional opening, as discussed below. The rotary component 630 is provided with one or more ports 632 in its body, spaced around the through bore 636. Again, the ports in the rotary component 630 need not be identically shaped or regularly spaced around the through bore 636, depending on the desired pulsing effect; but in this example, the ports are identically shaped and arranged at regular intervals around the bore 636. The ports 632 have a cross-sectional shape similar to, but shorter in length than, the ports 652 in the stationary component 650. As can be seen in
In the embodiment illustrated in the figures, the adaptor shaft and rotary components 610, 630 are also provided with at least one bypass port 614, 634 respectively. These ports 614, 634 also align with each other when the adaptor shaft component 610 is mounted to the rotary component 630. A carbide insert 615 is inserted in the bypass port 614 to reduce its circumference to control flow through the bypass port 634. In the illustrated embodiment, four bypass ports 614, 634 alternate with the ports 612, 632. In the illustrated configuration, when the ports 652 and 632 are in complete alignment, as illustrated by the bottom view of
Those skilled in the art will appreciated that the foregoing examples not only provide for selective activation of tools in the drilling string by permitting the operator to selectively activate, and optionally deactivate, the valve section 400 using the ball catch component 100, but also provides a pathway for other tools and components to pass through the entire assembly 10 to downhole locations. The ball catch component 100, motor section 200, drive section 300, and valve section 400 all provide a substantially continuous pathway, which can be adequately sized to permit wireline gear to pass through the entire assembly 10 while it is still downhole. In addition, the pathway can permit the passage of other balls or similar projectiles through the assembly 10 and down to other tools located below the assembly 10, such as other ball catch components, friction reduction tools, PBL subs, lost circulation subs, jars, reamers and the like.
Furthermore, the examples provided above provide for selective activation and deactivation by creating a pathway for the bypass of drilling fluid through the assembly 10 with components that present less of an obstacle to fluid flow in the drilling string as compared to the prior art. As those skilled in the art appreciate, fluid pressure and flow in drilling is critical to successful removal of cuttings from the wellbore, and to successful operation of the drill bit and other pressure-dependent tools in the string. While a number of factors impact the flow rate within a well, such as drilling fluid properties, system and formation pressure limits, the inclusion of different components in the drilling string restricting the effective cross-sectional area of the pathway available for fluid flow can impede the drilling operation by causing pressure drops in the system. Prior art solutions providing for fluid bypass can include several “layers” of cooperating components that effectively reduce the cross-section available for drilling fluid flow. The examples described above, on the other hand, provide a more optimal use of the cross-sectional space in the drilling string. Moreover, the examples above can function satisfactorily without altering the flow rate of drilling fluid into the assembly 10.
Throughout the specification, terms such as “may” and “can” are used interchangeably and use of any particular term should not be construed as limiting the scope or requiring experimentation to implement the claimed subject matter or embodiments described herein. Various embodiments of the present invention or inventions having been thus described in detail by way of example, it will be apparent to those skilled in the art that variations and modifications may be made without departing from the invention(s). The inventions contemplated herein are not intended to be limited to the specific examples set out in this description. For example, where appropriate, specific components may be arranged in a different order than set out in these examples, or even omitted or substituted. As another example, the number, sizes, and profiles of the ports 424, 422 in the rotary valve component 410 and the corresponding recesses 438 in the stationary valve component 430 can be varied as appropriate to accomplish a desired frequency or pulsation effect, or to accommodate particular equipment or drilling fluid. The inventions include all such variations and modifications as fall within the scope of the appended claims.
This application is a continuation of U.S. patent application Ser. No. 16/241,029, filed Jan. 7, 2019, which is a continuation of International Application No. PCT/CA2017/050828, filed Jul. 7, 2017, which claims priority to U.S. Provisional Application No. 62/359,683, filed Jul. 7, 2016, the entireties of which are incorporated herein by reference.
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| Number | Date | Country | |
|---|---|---|---|
| 20210198979 A1 | Jul 2021 | US |
| Number | Date | Country | |
|---|---|---|---|
| 62359683 | Jul 2016 | US |
| Number | Date | Country | |
|---|---|---|---|
| Parent | 16241029 | Jan 2019 | US |
| Child | 17197896 | US | |
| Parent | PCT/CA2017/050828 | Jul 2017 | US |
| Child | 16241029 | US |
