Patent Grant
11619098
Drilling an oil or gas well includes using a drill string to break down a formation to create and extend the depth of a wellbore. The drill string may have a lower portion, called a bottom hole assembly (BHA), which may include a drill bit, string reamers, directional drilling equipment, and other drilling tools. A specially formulated fluid (known in the art as drilling mud) is continuously circulated through the BHA and into the wellbore to aid in drilling operations and lubricate the BHA. Drilling mud also aids in drilling operations by removing cuttings from the wellbore, controlling formation pressures, and maintaining wellbore stability.
Lost circulation of drilling mud is one of the challenges encountered when drilling a wellbore, and may be the result of naturally fractured formations, improper drilling conditions, or excessive downhole pressure. Due to the time and expense of replacing the drilling mud lost to the formation, lost circulation increases the amount of time and cost to drill the wellbore. In addition, lost circulation may cause an abrupt decrease in the hydrostatic pressure of the wellbore, which may cause the wellbore to collapse. When a wellbore collapses, the drill string may become stuck and potential fishing operations or abandonment of the well may occur.
This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.
This disclosure presents, in one or more embodiments, a tool for building a wellbore that includes a tool body with a flow passage extending axially therethrough, a piston chamber formed radially through the tool body that intersects the flow passage of the tool body, a piston disposed in the piston chamber, at least one actuation element that exerts a force between the piston and the piston chamber, and a sleeve disposed within the flow passage of the tool body that includes at least one cutout. When the sleeve is in a first position within the tool body, the cutout is axially offset from the piston, and when the sleeve is in a second position, the cutout is axially aligned with the piston.
This disclosure also presents, in one or more embodiments, a method of hammering cuttings into a sidewall of a wellbore created by drilling into a formation with a bottom hole assembly. The bottom hole assembly includes a drill bit configured to drill the wellbore and create the cuttings and a double acting tool configured to hammer the cuttings into the sidewall of the wellbore. The double acting tool may include a tool body having a flow passage extending axially therethrough, a piston chamber formed radially through the tool body and intersecting the flow passage of the tool body, a piston assembled to the piston chamber, at least one actuation element provided in the piston assembly, and a sleeve that includes at least one cutout. The sleeve may restrain the piston from being actuated and is disposed in the tool body. The method further includes actuating the sleeve from a first position where the cutout is offset from the piston to a second position where the cutout is aligned with the piston to release the piston into the cutout and hammering the cuttings into the wellbore using the release of the piston while drilling.
This disclosure further presents, in one or more embodiments, a bottom hole assembly attached to a drill string. The bottom hole assembly includes a drill bit positioned at an end of the bottom hole assembly opposite the drill string, a sleeve that includes a plurality of cutouts, and a double acting tool. The double acting tool may include a tool body and a plurality of piston assemblies provided along different axial and circumferential positions around the tool body. Each piston assembly may include a piston retained in a piston chamber and at least one actuation element provided between the piston and the piston chamber. When the sleeve is in a first position around the tool body the cutouts are offset from the piston assemblies and when the sleeve is in a second position around the tool body the cutouts are aligned with the piston assemblies.
Other aspects and advantages will be apparent from the following description and the appended claims.
Specific embodiments of the disclosed technology will now be described in detail with reference to the accompanying figures. Like elements in the various figures are denoted by like reference numerals for consistency. The sizes and relative positions of elements in the drawings are not necessarily drawn to scale. For example, the shapes of various elements and angles are not necessarily drawn to scale, and some of these elements may be arbitrarily enlarged and positioned to improve drawing legibility.
Specific embodiments of the disclosure will now be described in detail with reference to the accompanying figures. In the following detailed description of embodiments of the disclosure, numerous specific details are set forth in order to provide a more thorough understanding of the disclosure. However, it will be apparent to one of ordinary skill in the art that the disclosure may be practiced without these specific details. In other instances, well known features have not been described in detail to avoid unnecessarily complicating the description.
Throughout the application, ordinal numbers (e.g., first, second, third, etc.) may be used as an adjective for an element (i.e., any noun in the application). The use of ordinal numbers is not intended to imply or create any particular ordering of the elements nor to limit any element to being only a single element unless expressly disclosed, such as using the terms “before”, “after”, “single”, and other such terminology. Rather, the use of ordinal numbers is to distinguish between the elements. By way of an example, a first element is distinct from a second element, and the first element may encompass more than one element and succeed (or precede) the second element in an ordering of elements.
In addition, throughout the application, the terms “upper” and “lower” may be used to describe the position of an element in a well. In this respect, the term “upper” denotes an element disposed closer to the surface of the Earth than a corresponding “lower” element when in a downhole position, while the term “lower” conversely describes an element disposed further away from the surface of the well than a corresponding “upper” element. Likewise, the term “axial” refers to an orientation substantially parallel to the well, while the term “radial” refers to an orientation orthogonal to the well.
In general, one or more embodiments of the disclosure may include a device and a method for drilling in a lost circulation region, e.g., a total-loss region or a partial-loss region, where some or all of the drilling mud used during drilling is lost in the formation. When drilling in a total-loss region, no drilling mud is returned to the surface of the well when drilling, which leads to the height of the fluid column to be reduced, thereby reducing the pressure in the well and potentially leading to a catastrophic loss of well control. When drilling in a partial-loss region, an amount of drilling mud (e.g., greater than about 20 barrels/minute) that significantly affects the drilling operation may be lost in the surrounding formation, but some drilling mud will still return to the surface. Lost circulation may occur, for example, when drilling through a formation having fractures or caverns, which may be naturally occurring or may also occur from the drilling operation. Accordingly, the systems, devices, and methods disclosed herein may be used for the continuation of a drilling operation with a reduced flow rate when drilling in a total or partial loss region.
A drilling operation at the well site 1 may include drilling a borehole into a subterranean formation 5. For the purpose of drilling a new section of well, equipment on a drilling rig 2 may suspend and rotate a drill string 3 within the wellbore 11. The drill string 3 may include a series of connected drill pipes, and a bottom hole assembly 9 (hereinafter “BHA”) may be disposed at the downhole end of the drill string 3. The BHA 9 may include a drill bit 7 and a double acting tool 23 according to embodiments of the present disclosure. The drill string 3 may be rotated relative to the wellbore 11, while the weight from the drill string 3 and BHA 9 is applied to the drill bit 7 to enable the drill bit 7 to break the surrounding formation 5 and lengthen the wellbore 11.
While cutting rock with the drill bit 7, drilling mud may be pumped through the drill string 3. The drilling mud may flow down the drill string 3 and exit into the bottom of the wellbore 11 through nozzles in the drill bit 7. The drilling mud in the wellbore 11 may then flow back up to the surface with entrained cuttings in the annular space between the drill string 3 and the wellbore 11. The cuttings may be removed from the drilling mud at the surface of the well, and the drilling mud may be reconditioned before pumping the drilling mud back into the drill string 3.
In total-loss and partial-loss drilling, drilling mud is lost in the surrounding formation 5, where the lost drilling mud cannot be recirculated through the well. For example, when a drill bit 7 drills through a total-loss region 4 in a formation 5, loss of drilling mud return, a drop in bottomhole pressure, and/or other indicators, may indicate, in real time, a total-loss occurrence. In such scenarios, the double acting tool 23 may be activated to hammer cuttings produced from the drill bit 7 into the wellbore 11 wall around the total or partial loss region 4, thereby saving the amount of drilling mud necessary to return the cuttings to the surface. Once the cuttings have been compacted into the wellbore 11, the drilling operation may be resumed to reach the final total casing depth. Therefore, instead of circulating the cuttings to surface, the drilled cuttings may be hammered into the wellbore 11, and at the same time, the amount of water consumption and drilling mud necessary when drilling in a total or partial loss region 4 may be reduced.
The double acting tool 23 may have a tool body 17 and one or more piston(s) 21 that are disposed in piston chambers 22 of the tool body 17. The pistons 21 may be made of any rigid material, such as steel, iron, or an alloy, that may withstand and transmit the expected impact force applied by the head 24 of the piston 21 into the wellbore 11. The pistons 21 may be partially retained within piston chambers 22 formed in the tool body 17, such that the pistons 21 may move radially outward from the tool body 17 without falling out of the tool body 17.
As shown in
Turning to
The sleeve 25 may further have at least one cutout 19 that extends radially into the body of the sleeve 25. When the sleeve 25 is in a first position within the tool body 17, such as shown in
As the sleeve 25 is moved from the first position shown in
As shown in
Continuing with
In order to facilitate the radial extension of a piston 21, the piston 21 may be actuated by an actuation element and may extend and withdraw from a piston chamber 22 formed in the tool body 17, such that the piston 21 extends from being fully disposed within the sleeve 25 to being partially extended out of the sleeve 25, and any number of intermediary positions.
A piston 21 may be mechanically actuated, hydraulically actuated, electrically actuated, or any combination thereof, but each of these embodiments of the piston 21 operate similarly by extending and retracting the piston 21 from the piston chamber 22 of the tool body 17. Additionally, at least one retention mechanism may be used to retain the piston 21 to the tool body 17, such that the piston 21 may extend and retract from the tool body 17 but not fall out of or be removed from the tool body 17.
For example,
The piston 21 may have a piston body with a head 24, a tail 26, and a fluid passage 29 extending through the height of the piston 21, where the fluid passage 29 of the piston 21 may extend parallel to the flow passage 28 of the tool body 17. The piston 21 may be generally cylindrical in shape with the head 24 having a relatively larger diameter than the remaining piston body. However, a person of ordinary skill in the art would appreciate that the piston 21 could have a multitude of shapes and sizes without deviating from the spirit of the invention. For example, the piston 21 may be a rectangular or hexagonal prism in order to hinder the rotation of the piston 21 within the piston chamber 22. As described above, the piston 21 may be made of any rigid material, such as steel, that may withstand and transmit the expected impact force applied by the head 24 to the wellbore 11. In the case of
An inset 39 may be formed in an upper portion of the fluid passage 29, where the inset 39 may be a slit or recess formed in an upper surface of the fluid passage 29 to form a different geometry in the upper portion of the fluid passage 29. For example, as shown, the fluid passage 29 may have a first inner diameter 60 that is uniform along a first portion of the fluid passage 29 without the inset 39, where the first portion of the fluid passage 29 may be cylindrically shaped. In the inset 39 of the fluid passage 29, the fluid passage 29 may have a second inner diameter 61 greater than the first inner diameter 60 and may have a non-cylindrical geometry.
In order to attach the cap 31 to the tail 26 of the piston 21, the cap 31 may be inserted into the rear opening of the piston chamber 22 and fastened to a tail 26 of the piston 21 by a fastening device 33. In one or more embodiments, the fastening device 33 may be a screw, bolt, or other equivalent fasteners known to one of ordinary skill in the art.
Actuation elements may be provided in the piston chamber 22 to extend and retract the piston 21 in the piston chamber 22. In one or more embodiments, actuation elements may include a first spring 35 disposed proximate to the head 24 of the piston 21 and a second spring 37 disposed proximate to the tail 26 of the piston 21. The first spring 35 may be compressed between the head 24 and the piston chamber 22, while the second spring 37 may be restrained between the cap 31 and the piston chamber 22. For example, in the embodiment shown in
As seen in
In order to assemble the piston 21 into the piston chamber 22 to create a piston assembly, the piston 21 may be inserted into the piston chamber 22 tail end first, with the head 24 being positioned proximate to a front opening of the piston chamber 22 and a tail 26 of the piston 21 being positioned proximate to the rear opening of the piston chamber 22. Prior to the insertion of the piston 21 into the piston chamber 22, the first spring 35 and second spring 37 may be inserted respectively into the front and rear openings of the piston chamber 22. Following the insertion of the piston 21 into the piston chamber 22, the cap 31 may be attached and retain the second spring 37 between the interfacing second ledge 63 and the cap 31. Similarly, the first spring 35 may be retained between the interfacing first ledge 62 and the head 24. After the piston 21 is fully assembled within the piston chamber 22, the sleeve 25 may be inserted into the fluid passage 29 of the piston 21 such that a cutout 19 (e.g., shown in
When the piston 21 extends outwardly from the piston chamber 22, the second spring 37 may compress and apply a compression force to the second ledge 63 of the piston chamber 22, where the cap 31 may retract into the piston chamber 22 in a withdrawn position shown in
As seen in
As the piston 21 extends outwardly from the piston chamber 22, the increased constriction between the flow passage 28 of the tool body 17 and the fluid passage 29 of the piston 21 may cause the force of the drilling mud on the piston 21 to increase. Due to this constriction, as drilling mud flows through the fluid passage 29 of the piston 21, a portion of the drilling mud may strike the inset 39 and impart a force upon the inset 39. Because the inset 39 is disposed opposite of the first spring 35, the force from the drilling mud on the inset 39 may counteract the force applied by the first spring 35 and add to the spring force of the second spring 37.
Once the combination of force from the second spring 37 and the fluid force from the drilling mud is greater than the spring force of the first spring 35, the piston 21 may begin to retract within the piston chamber 22. When the piston 21 is retracted into the piston chamber 22, the opening formed by the flow passage 28 and the fluid passage 29 of the piston 21 may expand, and the fluid force from the drilling mud on the piston 21 may decrease.
Accordingly, as seen in
Conversely, as seen in
Therefore, the piston 21 may be configured to extend and retract from the piston chamber 22 at least in part due to the varying amount of force that the drilling mud may apply to the inset 39 formed in the fluid passage 29. The cap 31 (or a different retaining element) and the varying shape of the piston chamber 22 along its length (e.g., the second ledge 63 of the piston chamber 22) may prevent the piston 21 from moving completely out of the piston chamber 22. The extension distance that the piston 21 may extend outwardly from the tool body 17 may depend on the length of the piston 21, the length of the piston chamber 22, the length of the second spring 37, and the depth of the cap 31, as well as the diameter of the sleeve 25 and the width of the cutout 19.
The extension distance of the piston 21 may be designed based on the outer diameter of the double acting tool 23 and the diameter of the wellbore 11, such that when the piston 21 is extended, the piston 21 may impact the wellbore 11. By way of example, for a tool body 17 diameter of six and a half inches, the piston 21 may be configured to protrude one inch from the tool body 17 when withdrawn and travel two inches during actuation for a total extension length of three inches from the tool body 17. In another example, for tool body 17 diameter of sixteen inches, the piston 21 may be configured to protrude two inches from the body when withdrawn and travel four inches during actuation for a total extension length of six inches. Other extension distances may be designed depending on the sizes of the double acting tool 23, drill bit 7, and wellbore 11, for example, extension distances ranging between 1 and 10 inches, or more.
Referring now to
Following the actuation of the sleeve 25 from the first position to the second position, the upper sleeve fingers 45 may be biased against a side wall of the flow passage 28 and form a second upper opening (e.g., shown in
As shown in
Once the sleeve 25 is actuated to the second position, the sleeve 25 may remain in the second position until an operator retrieves the sleeve 25. For this purpose, the sleeve 25 may have one or more latching holes 53 (shown in
Initially, a wellbore 11 may be drilled with a BHA 9 including a drill bit 7 and a double acting tool 23. As described above, the double acting tool 23 may have a tool body 17, a piston 21 assembled in at least one piston chamber 22 formed in the tool body 17, at least one actuation element (e.g., springs) provided in the piston chamber 22, and a sleeve 25 disposed within the tool body 17 that has at least one cutout 19.
The piston 21 may be restrained by the sleeve 25. Specifically, the sleeve 25 may be in a first position in which a cutout 19 of the sleeve 25 is offset from the piston 21. Due to the force applied to the piston 21 by the actuation element, the piston 21 may be biased against an outer surface of the sleeve 25.
During a time in which total-loss or partial-loss drilling may be suspected, an operator can release a ball 55 into a flow passage 28 of the tool body 17, and the sleeve 25 may then be actuated from a first position in which the cutout 19 may be offset from the piston 21 to a second position in which the cutout 19 may be aligned with the piston 21. Actuating the sleeve 25 from the first position to the second position may involve releasing upper sleeve fingers 45 from an upper groove 49 formed in the tool body 17 and catching lower sleeve fingers 47 in a lower groove 51 formed in the tool body 17. Following the actuation of the sleeve 25 from the first position to the second position, the ball 55 may then be caught in a ball catcher 57.
Because the piston 21 was biased against the outer surface of the sleeve 25 with a spring force in the first position, when the cutout 19 is aligned with the piston 21, the piston 21 may move into the cutout 19 and extend outwardly from the tool body 17 and piston chamber 22. The BHA 9 may continue to rotate, and therefore the double acting tool 23 may also be rotating while the piston 21 is released into the cutout 19.
In order to create a repeated hammering force, drilling mud moving through the tool body 17 may be utilized to apply a fluid force to an inset 39 formed inside the piston 21, where the applied fluid force may retract the piston 21 into the piston chamber 22. The varying force of the mud applied to the inset 39 (which may vary depending on the degree to which the inset 39 interfaces with the drilling mud) may extend and retract the piston 21 into the cutout 19. This allows the piston 21, and thus the double acting tool 23, to hammer the cuttings produced by the drill bit 7 into a side wall of the wellbore 11.
This process may be repeated any number of times if the sleeve 25 is returned to a first position. If the process is to be completed more than once, then the piston 21 may be withdrawn within the piston chamber 22 and a hook or similar tool may be attached to a latching hole 53 of the sleeve 25 in order to return the sleeve 25 to the first position. When the sleeve 25 is returned to the first position, the cutout 19 is offset from the piston chamber 22, and the sleeve 25 may restrain the piston 21 from expanding outwardly.
Accordingly, the aforementioned embodiments as disclosed relate to devices and methods useful to reduce the amount of wasted drilling mud associated with drilling in a total or partial loss region.
As noted above, the lost circulation of drilling mud is a common challenge encountered when drilling a wellbore. Lost circulation of drilling mud may be the result of naturally fractured formations, improper drilling conditions, or excessive downhole pressure. Excessive downhole pressures may induce fractures in the wellbore, which causes drilling mud to be lost to the surrounding formation. While some fluid loss may be expected, total loss can include loss of wellbore control, wellbore instability, stuck equipment, and formation damage due to plugging of pores and pore throats by mud particles. In extreme cases, lost circulation problems may force the abandonment of the well.
The drilling industry has made several advances to prevent lost circulation including the use of lost-circulation materials (LCM) and formation integrity tests (FIT) to diagnose and mitigate potential total loss zones. Conventional methods of sending LCMs to plug a lost circulation zone include designing the fluid parameters to activate or solidify at the predicted time it takes for the chemicals or cement to reach the lost circulation zone. However, activation may sometimes be off, and when activation or solidification happens at a time which differs from the time it takes for the chemicals or cement to reach the lost circulation zone, the LCMs may be lost inside the fractures away from the lost circulation region. In addition, while FITs are useful indications of the strength of the wellbore, FITs may result in a significant loss of drilling time while the test is being performed. Finally, drilling mud that is lost in the lost circulation zone is often unrecoverable, and significant economic and resource waste may occur due to the loss of the drilling mud. Double acting tools disclosed herein may address the challenges from previous techniques of reducing the amount of drilling mud lost in a lost circulation zone by hammering the cuttings into the formation wall as the drilling operation continues.
Although only a few embodiments of the invention have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible in the example embodiments without materially departing from this invention. Accordingly, all such modifications are intended to be included within the scope of this disclosure as defined in the following claims.
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