The present disclosure relates to downhole assemblies utilizing a motor to drive downhole tools, and selective activation of the motor.
When drilling deep bore holes in the earth, sections of the bore hole can cause drag or excess friction which may hinder weight transfer to the drill bit, or cause 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 mitigate the effect of friction or hole drag. These friction tools form part of the downhole assembly of the drilling string, and can be driven by the variations in the pressure of drilling fluid (which may be air or liquid, such as drilling mud) flowing through the friction tool. Accordingly, the operation or effectiveness of a friction tool—namely, the frequency of vibrations generated by the friction tool—may be affected by the flow rate of drilling fluid pumped through the string. Controlling the frequency of vibration thus may involve varying the flow rate of the drilling fluid at the surface, and ceasing operation of the friction tool may require cutting off the flow of drilling fluid at the surface. Varying or cutting off the drilling fluid flow, however, may impact the operation of other components in the drilling string.
Furthermore, 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. 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 is 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,
In the example assembly 10 of
In this particular example, the driveshaft 45 is coupled by another universal joint 50 to a valve assembly including a rotating valve component 65 and a corresponding stationary valve component 70. This valve assembly may be used to activate the oscillation tool 13, for example by varying the flow of drilling fluid and fluid pressure. The oscillation tool 13 can be positioned elsewhere in the downhole assembly 10 sufficiently close to the valve assembly so as to be affected by the variations in fluid pressure. Such a valve assembly includes a rotating flow head 65 and a stationary flow restrictor 70, each with ports that enter into and out of alignment as the flow head rotates against the flow restrictor so as to vary the flow of drilling fluid through the entire valve assembly during operation. Variations of such a flow-varying valve assembly are described in further detail below. As mentioned above, while this valve assembly may operate in concert with the other features of the present motor assembly to be described in further detail below, the motor assembly and the valve assembly can be used independently. In the illustrated embodiment, the downhole assembly 10 can function as a friction tool in the drilling string.
As is generally understood by those skilled in the art, in prior art downhole assemblies employing a similar motor, drilling fluid passes from a bore or passage above the motor (indicated in
The flow of drilling fluid through the motor in part determines the rotation speed and horsepower of the motor, along with the particular lobe configuration of the motor. Thus, once a drilling string is assembled, the rotation speed and power of the motor can be changed only by varying the flow 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, in the illustrated examples, the motor assembly includes a bypass system which can be selectively activated or deactivated to control the flow of drilling fluid through the motor assembly. This can be better seen in
A further component, a catch component 30 is mounted at the first end of the rotor 25. The catch 30 is configured to receive and retain a blocking implement. The blocking implement can be a substantially spherical ball or another shape configured to block passage through the catch 30 and/or rotor 25, as explained below. In the illustrated examples, the catch 30 is an insert mounted to the rotor using appropriate connectors, such as threaded joins; however, the catch 30 can alternatively be mounted using a separate connector element, not shown. In the illustrated examples, the catch 30 is configured to be inserted in the upper end of the rotor 25. As can be seen in
With reference to
Within the catch 30, the diameter of the passage 35 varies from a dimension wide enough to receive a blocking implement, such as a ball 15 (shown in
This is illustrated in greater detail in
When a ball 15 or other blocking implement is dropped into position in the catch 30, as illustrated in
The ball 15 or other blocking implement can be manufactured of a breakable material, such as Teflon®. When the ball 15 is in place as in
In some implementations, a further bypass may be included in the catch 30, as illustrated in
When the rotor assembly and motor is used in a friction tool, such as the example downhole assembly 10 illustrated in
The rotating valve component 65 is connected to the rotor 25. When the motor is inactive, the rotating valve component 65 is substantially stationary, and fluid flows through the valve components 65, 70 to the extent permitted by the alignment of the ports of the two valve components 65, 70. When the motor is active, the rotating valve component 65 is driven by the rotor 25 and the ports 67a, 67b, 67c, etc. of the rotating valve component move into and out of alignment with the ports 73a, 73b, etc. of the stationary valve component 70. In the examples shown in the figures, an optional further wear component 80 with ports 83a, 83b corresponding to the ports of the stationary valve component 70 is included. As can be seen in
As mentioned above, prior art friction tools or other tools are often driven by the flow of the drilling fluid. Consequently, control of the tool is accomplished by controlling the flow rate and pressure of drilling fluid into the tool; the tool may accordingly be stopped by halting the flow of drilling fluid. However, when drilling fluid is also required to operate the motor, it may be undesirable to simply stop pumping fluid downhole; this may halt the tool, but it will also halt the motor. For these reasons, with prior art friction tools, it is often necessary to halt drilling operations, pull the drilling string to the surface, disassemble the string, and reassemble the string to remove or add the tool, as the case may be. This activity can consume several hours of labour. Those skilled in the art will appreciate that with a downhole friction tool assembly 10 including the rotor assembly described above (i.e., the rotor 25 with integral passage 22 and catch 30), the drilling string including the downhole assembly 10 can be lowered into the well bore and drilling fluid can be pumped into the downhole assembly without engaging the catch 30 and activating the friction tool, until the operator chooses to activate the motor by dropping a ball or other blocking implement into the catch 30. In other words, the motor can be transitioned from an inactive to an active state while drilling fluid is flowing down the string without substantially varying the flow of drilling fluid entering the downhole assembly, and without pulling the drilling string to surface to add in a friction tool.
It will be appreciated that in some implementations, when the valve assembly is at rest with the rotating valve component 65 relatively stationary with respect to the stationary component 70, the ports of these components may be aligned in a manner that substantially restricts or blocks drilling fluid flow through the valve assembly and down to other lower portions of the drilling string. It may also or alternatively be desirable to delay the pressure-varying effect of the valve assembly even when the motor is active. Thus, in some embodiments, a temporary spacer ring 85 is included in the valve assembly, as shown in
While the motor of the downhole assembly 10 is inactive, drilling fluid can flow through the passage 22 of the rotor 25, and down to the valve assembly where it will pass through the ports of the rotating valve component 65, the space defined by the spacer ring, and the ports of the stationary valve component 70, without restriction caused by interference of the rotating valve component 65 with the ports of the stationary valve component 70 or vice versa. When the motor of the drilling assembly is activated as described above, the rotor 25 begins driving the rotating valve component 65. The component 65 rotates against the spacer ring 85 within the valve housing and begins to generate heat and friction against the spacer ring, which will wear down the spacer ring 85. The worn portions of the spacer ring 85 will be flushed by the drilling fluid through the stationary valve component 70, until the spacer ring 85 is effectively destroyed and no longer separates the stationary valve component 70 from the rotating valve component 65. At that stage, the valve assembly operates as originally intended to intermittently restrict fluid flow and vary fluid pressure. By selecting the material and depth of the spacing ring 85, the valve assembly and any tool driven by the valve assembly can be selectively disabled for a desired period of time during initial drilling operations. The spacer ring 85 may be used without the catch 30 described above.
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. The inventions include all such variations and modifications as fall within the scope of the appended claims.
This application claims priority to U.S. Provisional Application No. 62/205,655 filed on Aug. 14, 2015, the entirety of which is incorporated herein by reference.
Filing Document | Filing Date | Country | Kind |
---|---|---|---|
PCT/CA2016/050950 | 8/12/2016 | WO | 00 |
Publishing Document | Publishing Date | Country | Kind |
---|---|---|---|
WO2017/027964 | 2/23/2017 | WO | A |
Number | Name | Date | Kind |
---|---|---|---|
4705117 | Warren | Nov 1987 | A |
5535835 | Walker | Jul 1996 | A |
8636073 | McNeilly | Jan 2014 | B2 |
9523251 | Honekamp | Dec 2016 | B2 |
20050126828 | Pinol | Jun 2005 | A1 |
20060243493 | El-Rayes | Nov 2006 | A1 |
20090095528 | Hay | Apr 2009 | A1 |
20140199196 | Twardowski | Jul 2014 | A1 |
20140216761 | Trinh | Aug 2014 | A1 |
20150136403 | Cheng | May 2015 | A1 |
Number | Date | Country | |
---|---|---|---|
20180230750 A1 | Aug 2018 | US |
Number | Date | Country | |
---|---|---|---|
62205655 | Aug 2015 | US |