Patent Grant
11480020
The present invention relates to the field of directional drilling, and in particular to a system for activating and deactivating tools for use in downhole drilling operations.
Directional drilling involves controlling the direction of a wellbore as it is being drilled. Directional drilling typically utilizes a combination of three basic techniques, each of which presents its own special features. First, the entire drill string may be rotated from the surface, which in turn rotates a drilling bit connected to the end of the drill string. This technique, sometimes called “rotary drilling,” is commonly used in non-directional drilling and in directional drilling where no change in direction during the drilling process is required or intended. Second, the drill bit may be rotated by a downhole motor that is powered, for example, by the circulation of fluid supplied from the surface. This technique, sometimes called “slide drilling,” is typically used in directional drilling to effect a change in direction of a wellbore, such as in the building of an angle of deflection, and almost always involves the use of specialized equipment in addition to the downhole drilling motor. Third, rotation of the drill string may be superimposed upon rotation of the drilling bit by the downhole motor. Additionally, a new method of directional drilling has emerged which provides steering capability while rotating the drill string, referred to as a rotary steerable system.
When drilling deep boreholes in the earth, sections of the borehole can cause drag or excess friction which may hinder weight transfer to the drill bit, or cause erratic torque in the drill string. Frictional engagement of the drill string and the surrounding formation can reduce the rate of penetration of the drill bit, increase the necessary weight-on-bit, and lead to stick-slip. These effects may have the result of slowing down the rate of penetration, creating borehole deviation issues, or even damaging drill string components. These problems exist in all drilling methods including rotary drilling and when using a rotary steerable system. However, they are particularly pronounced while slide drilling where significant friction results from the lack of rotation of the drill string.
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 drill 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 and amplitude of vibrations generated by the friction tool—may be affected by the flow rate of drilling fluid pumped through the string. Controlling the vibrations thus may involve varying the flow rate of the drilling fluid at the surface and to cease operation of the friction tool the flow of drilling fluid must be cut off at the surface. Varying or cutting off the drilling fluid flow, however, will impact the operation of the entire drill string.
Furthermore, running a friction tool during the entirety of a drilling operation is not always desirable. For instance, it may be unnecessary or undesirable to run the tool while the drill bit is at a shallow depth, within casing or cement, 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 borehole is reached where the need for a friction tool is evident, pulling the downhole assembly to the surface to reassemble the drill string to include the friction tool and then returning the drill string to the drill point can consume several very expensive work hours.
A first general aspect provides a downhole tool for inclusion in a drill string, including a dart-catching section disposed on an uphole end of the downhole tool. wherein the dart catching section includes a guide section forming a guide for receiving a dart when dropped from uphole, and a keyed profile, configured to engage with a corresponding key section of the dart, catching the dart, and configured to allow darts having a different key section to pass through the downhole tool. The downhole tool further includes a power section, coupled to the dart catching section, configured to power the downhole tool when activated by catching the dart in the dart catching section.
A second general aspect provides a dart for use downhole that includes a key section disposed on an outer surface of the dart, the key section including a sequence of keys for engaging a corresponding keyed profile on an inner surface of a downhole tool, a dart body, open for fluid flow through the dart, a nozzle retainer affixed in a bore of the dart body, wherein the nozzle retainer is separable from the dart body upon engagement with an object dropped downhole, a dart nozzle attached to the nozzle retainer configured for a predetermined amount of fluid flow diversion, and a basket section having openings for fluid flow through the dart, coupled to the dart body, wherein the basket section retains the nozzle retainer and dart nozzle upon separation of nozzle retainer from the dart body.
A third general aspect is a method of controlling a first downhole tool that includes flowing drilling fluid through a bore of the first downhole tool, pumping downhole a first dart, engaging a key section of the first dart with a corresponding keyed profile of a dart catching section of the first downhole tool, diverting drilling fluid flow from the bore by a nozzle of the first dart, and activating a power section of the first downhole tool responsive to diverting drilling fluid flow.
The accompanying drawings, which are incorporated in and constitute a part of this specification, illustrate an implementation of apparatus and methods consistent with the present invention and, together with the detailed description, serve to explain advantages and principles consistent with the invention. In the drawings,
In the following description, for purposes of explanation, numerous specific details are set forth in order to provide a thorough understanding of the invention. It will be apparent, however, to one skilled in the art that the invention may be practiced without these specific details. In other instances, structure and devices are shown in block diagram form to avoid obscuring the invention. References to numbers without subscripts are understood to reference all instances of subscripts corresponding to the referenced number. Moreover, the language used in this disclosure has been principally selected for readability and instructional purposes, and may not have been selected to delineate or circumscribe the inventive subject matter, resort to the claims being necessary to determine such inventive subject matter. Reference in the specification to “one embodiment” or to “an embodiment” means that a particular feature, structure, or characteristic described in connection with the embodiments is included in at least one embodiment of the invention, and multiple references to “one embodiment” or “an embodiment” should not be understood as necessarily all referring to the same embodiment.
The terms “a,” “an,” and “the” are not intended to refer to a singular entity unless explicitly so defined, but include the general class of which a specific example may be used for illustration. The use of the terms “a” or “an” may therefore mean any number that is at least one, including “one,” “one or more,” “at least one,” and “one or more than one.”
The term “or” means any of the alternatives and any combination of the alternatives, including all of the alternatives, unless the alternatives are explicitly indicated as mutually exclusive.
The phrase “at least one of” when combined with a list of items, means a single item from the list or any combination of items in the list. The phrase does not require all of the listed items unless explicitly so defined.
In this description, the term “couple” or “couples” means either an indirect or direct connection. Thus, if a first device couples to a second device, that connection may be through a direct connection or an indirect connection via other devices and connections. The recitation “based on” means “based at least in part on.” Therefore, if X is based on Y, X may be a function of Y and any number of other factors.
A downhole agitator tool is described below that utilizes pressure pulses and an accompanying shock tool to translate pressure changes into axial movement thereby causing vibration of the drill string. The disclosed tool incorporates a through bore throughout the entire tool measuring 2″ or greater, which allows for the retrieval of some Measurement While Drilling (MWD) tools and allows for usage of free point and backoff equipment to facilitate removal of stuck drill strings. The disclosed tool does not require special equipment, such as a safety joint, to be installed in the drill string. However, a safety joint may be included if required for the operator's other equipment.
In one embodiment darts may be pumped downhole to activate the operation of the tool selectively. The dart lands in a dart catcher at the top of a rotor of the tool and restricts flow through the bypass, thereby causing the flow to go between the rotor and stator. This flow path causes the assembly to rotate and activates a control valve. The darts may incorporate different sized nozzles to allow for fine-tuning of the pulse frequency and pulse amplitude. The darts may be retrieved if necessary, using wireline or tubing fishing techniques. If for any reason an operator wants to modify the pulse frequency, another dart can be launched that causes a change in the frequency or enables operators to maintain the frequency they have previously been running under new flow parameters. As lateral sections of drill pipe get longer, standpipe pressure issues can occur, and often the flow rate has to be reduced. In that situation, a second dart may be launched to maintain or increase the pulse frequency at the reduced flow rate.
When in standby mode, flow proceeds through the bore of the power section, past (but not through) the control valve, and out the bottom of the tool. This reduces wear on the tool components, reduces standpipe pressure, and allows the operator to decide when they want the tool to start vibrating the drill string.
When in operational mode, the tool functions using a downhole power section with a rotating cap that has radial ports. This cap rests within a carbide sleeve that has a predetermined number of radial ports. Rotation of the cap thus causes an alternating flow restriction that creates an alternating pressure pulse. The nozzle in the dart allows for control of the pulse size and frequency. Further, this nozzle allows for protection against an overly aggressive pulse. Should the restriction at the valve be too tight, the flow will instead flow through the rotor, protecting other tools and equipment on the rig.
In one embodiment, the tool uses a robust polycrystalline diamond compact (PDC) bearing assembly that significantly reduces the required maintenance on the tool and provides great reliability.
To complement the pulsing tool, a double-acting shock tool may be included in a downhole assembly. In one embodiment, the shock tool incorporates Belleville springs and a telescoping mandrel. The geometry of the tool is designed so that changes in pressure cause the tool to extend and contract which imparts an axial motion on the adjacent drill string. This motion breaks static friction, which improves weight transfer, reduces stick-slip, and improves drill string dynamics. When assembled with the pulse tool, the shock tool amplifies the pulses produced by the pulse tool. The shock tool maximizes the pump open area and the properties of the Belleville spring stack are tuned for use with the pulse tool. The spring configuration may be adjusted on the surface to modify the axial movement of the mandrel.
Turning now to
The shock tool 110 is designed for threaded connection to the drill string using box thread section 205. An open bore 270 maximizes the open volume for fluid flow through the shock tool 110. In operation, a first mandrel 280 moves longitudinally relative to an outer housing 285, imparting the axial motion to the adjacent drill string.
A polished carbide seal outer surface area 210 provides a reduced friction surface for relative movement between first mandrel 280 and outer housing 285. An upper seal assembly 215 seals between the first mandrel 280 and outer housing 285, preventing fluid flow between them. The first mandrel, as shown in cross-section 225 taken at line A—A, may be formed with splines or other anti-rotation elements to allow transmission of torque from the drill string through the first mandrel 280 to the outer housing 285, preventing rotation of the first mandrel 280 relative to the outer housing 285.
A spacer ring 230 surrounding a second mandrel 232 coupled to the first mandrel 280 provides axial loading from a collection of Belleville springs 245 between mandrels and housings. The Belleville springs 245 are configured to allow spring compression under expected downhole loads. The spacer ring 230 provides axial loading when the shock tool 110 is in compression, and an upper spring load surface 240 provides axial loading when the shock tool 110 is in tension. A lower spring load surface 255 provides axial loading when the shock tool 110 is in tension. A lower spring load surface 250 provides axial loading when the shock tool 110 is in compression. Although described in terms of Belleville springs, other types of springs can be used as desired.
A balance piston 260 compensates for oil expansion and reduces pressure at the moving seals of the sealed area 275. Fill ports for the oil chamber are located at 220 and 295. A vent port 265 provides venting to the outside of the shock tool 110, so that fluid pressure through the vent port 265 on the sealed area 275 allows changes in pressure in the fluid internal to the shock tool 110 to open or lengthen the shock tool 110, resulting in axial movement of the first mandrel 280 relative to the outer housing 285, resulting in axial movement of the connected drill string.
An amplifier mandrel 292 provides an upward force on the shock mandrel whenever a pressure difference is experienced between internal and external volumes. An amplifier housing 294 adds an improved pump open area for enhanced tool performance. A high-pressure fluid area 296 in communication with internal fluid is affected by pulses from the pulse generator section, while a low-pressure fluid area 297 is vented to the annulus. Multiple amplifier stages can be added as required, limited by the total pump open force, which cannot exceed the Belleville spring 245 force plus the weight on bit experienced. This design does not require the amplifier components to be assembled onto the base shock tool.
A coupling 290 allows coupling the shock tool 110 to the agitator tool 120.
Although illustrated for controlling an agitator tool 120, the dart catching techniques described herein may be used for controlling other types of downhole tools.
Although three dart-catching sections 410, 420, and 430 and three key sections 510, 520, and 530 are illustrated in
In an alternate embodiment illustrated in plan view in
A removable nozzle retainer 640 affixed in a bore of the dart 600 by one or more shear pins 680 allows for modification of tool performance while the tool is already downhole. The shear pins are configured to shear at a predetermined pumping pressure on the nozzle retainer 640, separating the nozzle retainer 640 from the dart body 690. Other techniques for holding the nozzle retainer 640 in place until the predetermined pumping pressure may be used. The nozzle retainer 640 has attached a nozzle 645 that diverts fluid flow for controlling an agitator tool 120 or other downhole tools containing a corresponding dart catching section 410. As described below, the removable nozzle retainer 640 is separable from the dart body, allowing the nozzle retainer 640 to move downhole into the basket section 650, where the nozzle retainer 640 and nozzle 645 are retained, allowing fluid to flow downhole through an array of openings 660 and basket nose port 670 without the diversion caused by nozzle 645.
The nozzle 645 may be set on the surface to control the frequency of rotation to be performed by the power section 300 of the agitator tool 120, based on the amount of diversion of the fluid flow rate through the bore 360 created by the nozzle 645. For example, the greater the restriction of flow the greater the diversion into the power section 300, resulting in faster rotation of the inner mandrel 350 and a higher frequency of the resulting vibrations in the agitator tool 120. Other tools may use changes in fluid flow for other purposes. In some embodiments, the nozzle 645 may completely block fluid flow through the bore 360, but generally, some flow remains with the dart 600 in place. Until the dart 600 is pumped into the dart catching section 410, 420, 430, fluid flows unrestricted through the bore 360 because of its large size. Once the dart 600 has engaged with the dart catching sections 410, 420, 430, nozzle 645 diverts flow from the bore 360, so that fluid flows around the inner mandrel 350, causing rotation of the inner mandrel 350.
Similar darts can be deployed with key sections 610A, 610B that are configured to engage with dart-catching sections 420 or 430. Although
In some situations, an operator having pumped the dart 600 into place as described above may wish to modify the flow through the agitator tool 120 to change the frequency of the vibrations produced or through another downhole tool to change its operating parameters. In that situation, a second dart may be dropped or pumped downhole to be captured by an uphole end of the dart 600.
In
Instead of using a ball as illustrated in
By the use of the techniques illustrated in
As described above and illustrated in
In some scenarios, an operator could run the shock and agitator tool assembly 100 with full fluid flow, then drop a dart 600 to cause the agitator tool 120 to begin vibration, with the dart 600 configured for a predetermined vibration rate or frequency. When agitation is no longer needed, the dart 600 may be withdrawn uphole, returning to full bore fluid flow. A second dart 910, 1210 can be used to adjust the vibration frequency, as described above. In addition, the original dart 600 may simply be pulled back uphole and a new dart 600 dropped with the nozzle 645 configured for a different vibration frequency.
Similarly, as illustrated in
The shock and agitator tool assembly 100 may be used as a single sub. Alternately, the agitator tool 120 may be made up by itself in the drill string if the shock tool 110 is not needed. In normal operation, the agitator tool 120 begins with full through bore fluid flow, pumping down a dart 600 only when agitation or vibration of the agitation tool 120 is needed, then returning to full through bore fluid flow when vibration is no longer needed by removing dart 600.
As described above, two darts may be used to control the agitator tool 120. In some embodiments, additional darts can be used, with each successive dart engaging with the previous dart, and further affecting flow through the bore 360 of the power section 300, allowing additional adjustment of the frequency of rotation and thus the vibrations produced by the agitator tool 120. Each successive dart would be smaller than its predecessor. In one embodiment, the additional dart may seal the first and second darts, fully activating the power section and thus the agitator tool 120. In yet another embodiment, a dart can be pumped into the drill string that causes a breakup up or complete dislodging of the dart 600, allowing the dart 600 to be pumped through the bore 360, restoring full fluid flow through the bore 360.
The tools, darts, and techniques described above allow flow through the bore of the downhole tool. The downhole tool can thus be activated, deactivated, or have its operational parameters changes while downhole without wireline intervention. The operator can continue drilling while the downhole tool is deactivated, then reactivate the tool when desired.
The large bore 360 of the shock and agitator tool assembly 100 allows the use of other tools, such as MWD or well intervention tools, that might not be usable downhole of previous vibration tools that have restricted fluid flow and smaller bores. The vibrations created by the agitator tool 120 do not interfere with MWD operations, and the agitator tool 120 provides a minimal pressure drop until a dart 600 is pumped downhole to engage the agitator tool 120.
In addition, unlike conventional agitator tools, the large bore 360 of the shock and agitator tool assembly 100 would allow an operator to make up a drill string with multiple agitator tools 120, whether separate subs or combined with a shock tool 110 as a shock and agitator tool assembly 100. Each agitator tool 120 in the drill string could have the same bore 360 as the next agitator tool 120 downhole, so that darts 600 for a desired agitator tool 120 would pass through uphole agitator tools 120, but engage with the proper dart catching section 410, 420, 430 of the desired agitator tool 120 in the drill string.
Alternate dart designs may replace or modify the nozzle retainer 640, nozzle 645, and basket section 650. For example, as illustrated in U.S. Pat. No. 10,989,004, which is incorporated by reference in its entirety herein, an alternative design uses a nozzle carrier with an external seal, a seal sleeve with bypass slots, and a Belleville spring stack for a similar purpose. The dart 600 may be configured with this or other alternate designs but continue to use the key sections 510, 520, and 530 for engagement with dart catching sections 410, 420, and 430 to allow independent activation, deactivation, and modification of operating parameters of multiple downhole tools in a string.
To deactivate the downhole tool, an object such as a ball or plug is pumped downhole in block 1360, which engages with the nozzle retainer of the first dart. In block 1370, increased pump pressure on the nozzle retainer causes the nozzle retainer to separate from the dart. The separated dart and the object are retained in block 1380 in the basket of the first dart. The downhole tool may then run deactivated for a significant amount of time, until the operator desires to reactivate the downhole tool.
A second dart may now be pumped downhole in block 1390, engaging with the first dart in block 1395. A nozzle in the second dart again diverts fluid flow, activating the downhole tool or modifying its operational parameters.
The actions identified in
Although only a second dart is illustrated and described above, one of skill in the art would understand that additional darts and cycles of deactivating and reactivating the downhole tool may be employed.
The following examples pertain to further embodiments.
Example 1 is a downhole tool for inclusion in a drill string, comprising: a dart-catching section disposed on an uphole end of the downhole tool, comprising: a guide section forming a guide for receiving a dart when dropped from uphole; and a keyed profile, configured to engage with a corresponding key section of the dart, catching the dart, and configured to allow darts having a different key section to pass through the downhole tool; and a power section, coupled to the dart catching section, configured to power the downhole tool when activated by catching the dart in the dart catching section.
In Example 2 the subject matter of Example 1 optionally includes wherein the downhole tool is an agitator tool.
In Example 3 the subject matter of any of Examples 1-2 optionally includes wherein the power section of the downhole tool comprises: an outer housing forming a stator of a fluid-driven motor; and an inner mandrel forming a rotor of the fluid-driven motor that rotates relative to the outer housing to power the downhole tool.
Example 4 is a dart for use downhole, comprising: a key section disposed on an outer surface of the dart, comprising a sequence of keys for engaging a corresponding keyed profile on an inner surface of a downhole tool; a dart body, open for fluid flow through the dart; a nozzle retainer affixed in a bore of the dart body, wherein the nozzle retainer is separable from the dart body upon engagement with an object dropped downhole; a dart nozzle attached to the nozzle retainer configured for a predetermined amount of fluid flow diversion; and a basket section having openings for fluid flow through the dart, coupled to the dart body, wherein the basket section retains the nozzle retainer and dart nozzle upon separation of nozzle retainer from the dart body.
In Example 5 the subject matter of Example 4 optionally includes wherein the object is a ball.
In Example 6 the subject matter of Example 4 optionally includes wherein the object is a plug.
In Example 7 the subject matter of any of Examples 4-6 optionally includes wherein the key section is urged radially outward.
In Example 8 the subject matter of any of Examples 4-7 optionally includes wherein the dart passes through dart-catching sections of downhole tools with a different keyed profile.
In Example 9 the subject matter of any of Examples 4-8 optionally further comprises a shear pin for holding the nozzle retainer in place, the shear pin configured to shear at a predetermined pumping pressure, separating the nozzle retainer from the dart body.
In Example 10 the subject matter of any of Examples 4-9 optionally further comprises: a dart retrieval section configured for wireline retrieval uphole of the dart.
In Example 11 the subject matter of Example 4 optionally includes wherein the dart body is configured to capture a second dart dropped from uphole after the nozzle retainer has been separated from the dart body, and wherein the second dart contains a second nozzle that modifies fluid flow downhole for modifying an operating parameter of the downhole tool.
Example 12 is a method of controlling a first downhole tool, comprising: flowing drilling fluid through a bore of the first downhole tool; pumping downhole a first dart; engaging a key section of the first dart with a corresponding keyed profile of a dart catching section of the first downhole tool; diverting drilling fluid flow from the bore by a nozzle of the first dart; and activating a power section of the first downhole tool responsive to diverting drilling fluid flow.
In Example 13 the subject matter of Example 12 optionally includes wherein the first dart passes through a dart catching section of a second downhole tool having a different keyed profile.
In Example 14 the subject matter of any of Examples 12-13 optionally further comprises: pumping an object downhole for engaging with a nozzle retainer of the first dart; separating the nozzle retainer of the first dart engaged with the object under increased pumping pressure, deactivating the first downhole tool; and catching the object, the nozzle retainer, and nozzle in a basket section of the first dart.
In Example 15 the subject matter of Example 14 optionally includes wherein the object is a ball.
In Example 16 the subject matter of Example 14 optionally includes wherein the object is a plug.
In Example 17 the subject matter of any of Examples 12-16 optionally further comprises: pumping a second dart downhole, wherein the second dart contains a nozzle configured for a predetermined diversion of fluid flow through the second dart; and engaging the second dart with the first dart, further modifying fluid flow through the first dart.
In Example 18 the subject matter of any of Examples 12-17 optionally further comprises: retrieving the first dart with a wireline tool; and deactivating the power section of the downhole tool responsive to retrieving the first dart.
In Example 19 the subject matter of any of Examples 12-18 optionally further comprises: independently controlling a second downhole tool uphole of the first downhole tool having a dart catching section that engages with a different key section of a second dart.
In Example 20 the subject matter of Example 19 optionally further comprises: independently controlling a third downhole tool uphole of the second downhole tool having a dart catching section that engages with a different key section of a third dart.
The above description is intended to be illustrative, and not restrictive. For example, the above-described embodiments may be used in combination with each other. Many other embodiments will be apparent to those of skill in the art upon reviewing the above description. The scope of the invention therefore should be determined with reference to the appended claims, along with the full scope of equivalents to which such claims are entitled.
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