Patent Application
20240328273
Hydrocarbon resources are typically located below the surface of the earth in subterranean porous rock formations, often called reservoirs. These hydrocarbon-bearing reservoirs can be found in depths of tens of thousands of feet below the surface. In order to extract the hydrocarbon fluids, also referred to as oil and/or gas, wells may be drilled to gain access to the reservoirs. Wells may be drilled vertically from the surface, deviated from vertical, or vertical to horizontal in order to most effectively and efficiently access the subsurface hydrocarbon reservoirs.
A step in the drilling operations, or well construction, involves casing the wellbore with tubulars and cementing the tubulars in place. This isolates the internal conduit or well from the surrounding formations that may be prone to collapse or have undesirable hazards present such as shallow gas. Each section of the well is typically drilled with a drill bit that is attached to a length of drill string that extends from the bottom of the wellbore to a drilling rig at surface. Upon completion of drilling a section of well bore, the drill string and the drill bit are pulled out of the wellbore and a section of casing is deployed and cemented into place to create the desired isolation from the newly drilled formation.
In well construction it is often necessary to alter an existing wellbore trajectory. This is typically called “side-tracking.” Scenarios that may require side-tracking include, but are not limited to, a need to avoid subsurface hazards (faults, shallow gas, etc.), planned multi-lateral wells, failure of an existing wellbore, missed geological targets, and reuse of an existing wellbore that has depleted reservoir production. A whipstock is a device that is commonly deployed to facilitate the altering of a wellbore trajectory. The whipstock has a longitudinal tubular body with an inclined plane that when deployed into the wellbore can serve as a deflection surface or ramp to alter the trajectory of the drill bit and, thus, the wellbore.
Typically, a whipstock is deployed and set at a predetermined “casing window” or “side-track” depth inside the wellbore either within a casing section or section without casing referred to as an open hole section. The mechanism that anchors the whipstock and isolates the wellbore section below can be either permanent (cement) or retrievable (slips, seals, elastomeric element.) In operation, a mill bit or drill bit is often integrated with the whipstock and deployed as an assembly. This permits the milling of a window in the casing or open hole, to commence immediately following the setting of the whipstock. The milling operation typically includes milling a window in the casing and a short section of new formation before the mill bit is changed out for a drill bit that is better suited for drilling longer formation sections. Upon completion of drilling operations, the whipstock is retrieved by a dedicated trip into the wellbore with a dedicated whipstock retrieving tool, which is a separate assembly from the mill bit or drill bit.
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.
In some aspects, the techniques described herein relate to a system including a retrieving tool component with a first engagement element disposed at a first radial distance from a retrieving tool centerline. The system includes an uphole component with a second engagement element and a downhole component coupled to the uphole component and releasably connected to a wellbore. The retrieving tool component is configured to retrieve the uphole component and the downhole component from the wellbore using a connection component to release an axial lock thereby allowing an axial movement of the downhole component out of the wellbore.
In some aspects, the techniques described herein relate to a method for retrieving an uphole component coupled to a downhole component deployed in a wellbore. The method includes deploying into the wellbore a retrieving tool component with a first engagement element. The method includes drilling a lateral wellbore section with the retrieving tool component and then extending a second engagement element disposed on the uphole component and engaging the second engagement element with the first engagement element. The method includes applying an uphole tension on the second engagement element to unlock the downhole component from the wellbore. The method includes removing the retrieving tool component connected to the uphole component and the downhole component from the wellbore.
Other aspects and advantages of the claimed subject matter 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.
Regarding the figures described herein, when using the term “down” the direction is toward or at the bottom of a respective figure and “up” is toward or at the top of the respective figure. “Up” and “down” are oriented relative to a local vertical direction. However, in the oil and gas industry, one or more activities take place in a vertical, substantially vertical, deviated, substantially horizontal, or horizontal well. Therefore, one or more figures may represent an activity in deviated or horizontal wellbore configuration. “Uphole” may refer to objects, units, or processes that are positioned relatively closer to the surface entry in a wellbore than another. “Downhole” may refer to objects, units, or processes that are positioned relatively farther from the surface entry in a wellbore than another. True vertical depth is the vertical distance from a point in the well at a location of interest to a reference point on the surface.
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 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 may succeed or precede the second element in an ordering of elements.
Embodiments disclosed herein relate to a system and method for retrieving a whipstock with a whipstock retrieval system using a retrieving tool component that supports the drilling of a new wellbore, and recovery of a retrievable whipstock without the need for a dedicated retrieving tool or a dedicated trip into the wellbore. This saves the operator time and cost by reducing the number of trips into the wellbore. Typically, a whipstock is set at a predetermined depth inside an oil and gas wellbore creating a deflection surface or ramp for the bit to change the wellbore trajectory and drill a new wellbore section. When drilling has been completed and it has been decided that the whipstock will be recovered, a separate dedicated trip into the wellbore with a dedicated retrieving tool is required. This additional trip into the wellbore can be a time-consuming operation, especially for deeper or extended reach wellbores, which can translate to a high-cost operation when factoring in rig day rates and daily rates of other services supporting the overall well construction operation. Furthermore, in conventional applications, a full-gauge drill bit coupled adjacent to the whipstock would comprise an assembly that is too large to come up out of the hole together, side-by-side.
In accordance with one or more embodiments a whipstock is modified to allow it to be retrieved by a full-gauge drill bit when the drill bit is being pulled out of hole. The whipstock is configured to accept an electronics sensor package and an actuation module which operates a latch when desired by the driller. (The electronics sensor package may include, for example, an RFID reader, hall effect sensor, etc.) A latch on the whipstock holds down a drill bit catching mechanism (a catch) in a pocket within the body of the whipstock. The electronics sensor package may be self-powered, such as with the use of batteries. In addition, a drill bit is fitted with a passive, wireless, non-contact, object identifier which may be an RFID tag, a magnet, or other such embedded object (a tag) which can be detected by the electronics sensor package (e.g., the RFID reader of the electronics sensor package) in the whipstock.
When the tag on the bit and whipstock sensor (RFID reader) are in a predetermined close proximity, the latch is released, and the catch extends out of the pocket and into the retrieval position. To prevent unwanted or premature activation a logic function within the electronics module may control the energization of the latch. For example, a time duration for which the bit and sensor are in the predetermined close proximity may trigger the device. Alternatively, a certain number of passes (a logic code such as quantity of passes, duration of each pass, pattern of set of passes, etc.) between the sensor and bit within a specific time window may also be used. The orientation of the drill bit will also be considered, and operation may only be possible when the drill bit is aligned correctly with the hook in the downward position, i.e., facing the whipstock face (the whipface, e.g., deflection surface). This would allow the bit to pass over the sensor without activating the mechanism to avoid an unwanted situation.
When the latch is retracted the catch is hinged upwards away from the whipface out of its pocket and into the path of the hook on the drill bit. One bit blade of the bit blades has a different geometry to the rest which forms the hook. Here the issue arises when trying to recover the whipstock with a full-gauge bit. The internal diameter of the last section drilled, and the casing shoe internal diameter may be the size of the outside diameter (OD) of the bit currently in use, therefore there is no additional space to accommodate the bit OD and whipstock ramp (whipface) thickness if they are being pulled up into the uphole stacked together.
With the catch hinged upwards, the hook tripping past the catch engages with the catch. When the catch is caught by the hook, the motion of the drill string in the uphole direction shears out hinge pins and the catch is pulled out away from the whipface of the whipstock body. Attached to the catch are cables which run through the whipstock body and into the whipstock anchor and which are drawn out along with the catch. The cables would not be strong enough to exert the normally required force of 50,000-100,000 pounds (lbs) to overcome the anchor and recover a whipstock. Therefore, the cables are used to operate a release mechanism in the anchor to shift the slips from a locked position to an unlocked position. The action of drawing out the cables causes a slips-retaining mechanism in the anchor to release and the slips to collapse inwards from the locked position to the unlocked position thereby freeing the anchor. The cables allow the bit to clear the uphole end of the whipstock so that the bit and whipstock are not stacked side-by-side on top of one another during the pull out of hole, and therefore the drill bit, whipstock, and anchor can pass through wellbore internal diameter restrictions. The cables carry the weight of the assembly as it is pulled out of the hole.
The geometry of the catch (i.e., the inner diameter and the outer diameter) matches that of the drill bit so that the catch sits flush on the drill bit after it has been removed from its pocket in the whipstock. The anchor release cables may be attached to the catch. The action of pulling the catch from the whipstock applies tension to the cables. The tension in turn releases the anchor slips retaining mechanism, shifting the slips from an extended and locked position to a retracted and unlocked position and allows the whipstock and anchor to be pulled out of hole. The cables pay out a short distance allowing the drill bit to clear the end of the whipstock ensuring that the bit and whipstock do not enter uphole restrictions together.
The drill string (112) may be suspended in wellbore (102) by a derrick structure (101). A crown block (106) may be mounted at the top of the derrick structure (101). A traveling block (108) may hang down from the crown block (106) by means of a cable or drill line (103). One end of the drill line (103) may be connected to a drawworks (104), which is a reeling device that can be used to adjust the length of the drill line (103) so that the traveling block (108) may move up or down the derrick structure (101). The traveling block (108) may include a hook (109) on which a top drive (110) is supported. The top drive (110) is coupled to the top of the drill string (112) and is operable to rotate the drill string (112). Alternatively, the drill string (112) may be rotated by means of a rotary table (not shown) on the surface (114). Drilling fluid (commonly called mud) (not shown) may be pumped from a mud system (130) into the drill string (112). The mud may flow into the drill string (112) through appropriate flow paths in the top drive (110) or through a rotary swivel, if a rotary table is used (not shown). Details of the mud flow path have been omitted for simplicity, but would be readily understood by a person of ordinary skill in the art.
During a drilling operation at the well site (100), the drill string (112) is rotated relative to the wellbore (102) and weight is applied to the drill bit (128) to enable the drill bit (128) to break rock as the drill string (112) is rotated. In some cases, the drill bit (128) may be rotated independently with a drilling motor (not shown). In other embodiments, the drill bit (128) may be rotated using a combination of a drilling motor (not shown) and the top drive (110) (or a rotary swivel if a rotary table is used instead of a top drive) to rotate the drill string (112). While cutting rock with the drill bit (128), mud is pumped into the drill string (112). The mud flows down the drill string (112) and exits into the bottom of the wellbore (102) through nozzles in the drill bit (128). The mud in the wellbore (102) then flows back up to the surface (114) in an annular space between the drill string (112) and the wellbore (102) carrying entrained cuttings to the surface (114). The mud with the cuttings is returned to the mud system (130) to be recycled and circulated back again into the drill string (112). Typically, the cuttings are removed from the mud and the mud is reconditioned as necessary before pumping the mud again into the drill string (112).
Drilling operations are completed upon the retrieval of the drill string (112), the BHA (124), and the drill bit (128) from the wellbore (102). In some embodiments of wellbore (102) construction, the production casing operations may commence. A casing string (116), which is made up of one or more larger diameter tubulars that have a larger inner diameter than the drill string (112) but a smaller outer diameter than the wellbore (102), is lowered into the wellbore (102) on the drill string (112). Generally, the casing string (116) is designed to isolate the internal diameter of the wellbore (102) from the formation (126). Once the casing string (116) is in position, it is set and cement is pumped down through the internal space of the casing string (116), out of the bottom of the casing shoe (120), and into the annular space between the wellbore (102) and the outer diameter of the casing string (116). This secures the casing string (116) in place and creates the desired isolation between the wellbore (102) and the formation (126). At this point, drilling of the next section of the wellbore (102) may commence.
The slip (222) engages the anchor (206) to a wall (224) of the wellbore (102). A slip energizer (226) applies radial and/or lateral force away from the centerline or axis of the anchor (206) (e.g., anchor centerline (252)) extending the slip toward the wall (224). A slip lock (228) maintains the radial force of the slip (222) against the wall (224) thereby maintaining the slip in the locked position. A slip release (230) disengages the slip lock (228) to remove the radial force of the slip (222) against the wall (224). The slip (222) retracts from the locked position to the unlocked position. The slip release (230) may operate with a slip release minimum force, i.e., the slip lock may be released when or after a release force applied to the slip release meets or exceeds the slip release minimum force.
The slip energizer (226) may apply the radial force using power from the force of the drill string (112) being applied to the slip energizer (226). The slip energizer (226) may apply the radial force using power from hydraulic force provided through the drill string (112), or through a hydraulic control line supplying hydraulic pressure from a hydraulic pressure source on the surface (114), or from a hydraulic pump integrated downhole. The slip energizer (226) may apply the radial force using power from electricity provided through an electrical power line supplying electrical power from an electrical power source on the surface (114) or from an electrical power source integrated downhole. The slip energizer may use power and/or mechanical connection from other sources such as a spring, a hydraulic cylinder, an electromagnet, an electro-magnetic solenoid, an electric motor, or any combination of those. The mechanical connection may include one or more of a lever, a shaft, an axle, a plunger, or any combination thereof. The lower anchoring mechanism, such as the anchor (206), may be a hydraulic or mechanical anchor configured to be able to release the releasable connection, such as the slip (222), following a drilling operation.
During whipstock operations an initial step is to install the whipstock (200). The whipstock (200), a drilling assembly, and a bit, typically a milling bit (i.e., a mill bit (216) also known in the art as a window mill, typically followed by a watermelon mill), are deployed into the wellbore (102) as an assembly. Upon reaching the planned setting depth, the anchoring mechanism (e.g., anchor 206) is activated and attaches the whipstock to the wall (224) inside of the wellbore.
Next, the whipstock (200) is disconnected from the drill string (112), thereby releasing the drilling assembly and the mill bit (216) from the whipstock (200). With the drilling assembly and mill bit (216) now freed from the whipstock (200), drilling may commence. Alternatively, the whipstock may be deployed in the wellbore (102) by a separate running tool (not shown) such that the whipstock (200) is anchored in the wellbore without being attached to the drilling assembly. In either configuration, once placed, the whipstock (200) is anchored in the wellbore (102) independent of the drilling assembly such that the drilling assembly moves freely within the wellbore (102).
As the mill bit (216) begins milling a window (258) in the casing, the deflection surface (202) of the whipstock (200) is used as a ramp to deflect the mill bit (216) away from the existing wellbore (the wellbore 102) so as to commence drilling of a new wellbore with a new trajectory, (e.g., a lateral (220) see
The mill bit (216) may be a fixed-style bit that is designed for milling through metal or steel. This type of bit is commonly used in the oil and gas industry for milling the window (258) in the casing string (116) when there is a need to sidetrack or change the trajectory of a wellbore (102) such as for drilling a lateral. The mill bit (216) is commonly constructed from tungsten carbide, however one of ordinary skill in the art would appreciate that a mill bit (216) may be constructed from steel, a high strength alloy, and have a bonded polycrystalline diamond compact (PDC) layer.
In one or more embodiments, a first engagement element may have an engagement hook such as a hook (205) (see
In addition,
The drilling assembly (210) includes a bottom hole assembly (BHA) connection (a BHA connection (213)), a drilling housing (214), and the mill bit (216).
The second engagement element, the catch (204) may be embedded into the whipstock (200) in a pocket on the longitudinal body of the whipstock and the catch (204) may be selectively shifted from a catch-recessed position to a catch-extended position and back by an operator such as a driller providing a command to actuate. In the catch-recessed position, the catch may be flush with the deflection surface (202). The catch may be actuated hydraulically, electrically, electro-hydraulically, electro-mechanically, or by another means known to a person of ordinary skill in the art.
To achieve the required catch driving force, the extending driver (234) may be powered by a power supply (244) that stores power for downhole use such as in an electrical power storage component, a hydraulic power storage component, and/or a compressed gas power storage component. Electrical power storage examples include batteries and capacitors. Hydraulic power storage examples include pressurized hydraulic fluid stored in an accumulator. Compressed gas power storage examples include nitrogen-charged cylinders. The power supply (244) may be integrated in the longitudinal body (218).
The catch may be retained in the catch-recessed position by a retainer such as a latch (404) (see
In order to shift the retainer, in accordance with some embodiments, a latch driving force may be applied to the retainer via the retainer driver (232) causing the retainer to shift from the latch-extended position to the latch-retracted position, or from the latch-retracted position to the latch-extended position. The retainer driver (232) may use power and/or mechanical connection from sources such as a spring, a hydraulic cylinder, an electromagnet, an electro-magnetic solenoid, an electric motor, or any combination of those. To achieve the required driving force, the retainer driver (232) may be powered by the power supply (244). The mechanical connection may include one or more of a lever, a shaft, an axle, a plunger, or any combination thereof.
The extending driver (234) and/or the retainer driver (232) may extend and/or retract upon receipt of a signal to activate. In accordance with one or more embodiments, upon receipt of an unlatch signal, the retainer driver (232) may retract the retainer (e.g., the latch (404)) (see
The extending driver (234) and/or the retainer driver (232) may be operatively controlled by the electronics module (236). In accordance with one or more embodiments the electronics module (236) includes the reader (238), the power supply (244), a computer processor (246), and a retainer driver (232) such as an electro-hydraulic actuator. Each of these components may be powered by the power supply (244). In one or more embodiments, the retainer driver (232) includes a pump (248) that is operatively controlled by the computer processor (246). The pump (248) may be an electric pump, gear pump, or diaphragm pump that is configured to compress hydraulic fluid inside of the retainer driver (232).
To actuate the catch (204), the tag (240) is configured to emit a signal that is sensed by the reader (238). Upon sensing the signal from the tag (240), the reader (238) sends a catch-extend command to the computer processor (246).
When or soon after receiving a catch-extend command from the reader (238), the computer processor (246) commands the retainer driver (232) to retract the latch to the latch-retracted position and/or the computer processor (246) commands the extending driver (234) to extend the catch (204) from the catch-recessed position to the catch-extended position. In order to actuate the latch, the pump (248) may compress the hydraulic fluid, causing hydraulic pressure to build in the retainer driver (232). This hydraulic pressure is applied to the retainer driver (232), which retracts the latch (404) from the latch-extended position to the latch-retracted position thereby unlatching the catch from the catch-recessed position to the catch-extended position.
Electronics module (236) may be included in the whipstock (200). The sensor package (e.g., the reader (238)) of the electronics module (236) may be one or more of a radio frequency identification tag reader, a global system for mobile communications or groupe special mobile (GSM) chip reader, a general packet radio service (GPRS) chip reader, a magnet detector, a hall effect sensor, or other equivalent reader known to one of ordinary skill in the art. The reader (238) may be disposed in the longitudinal body and the reader (238) may be powered by the power supply (244).
The reader (238) may be configured with a capability to cooperate with a non-contact wireless object identification tag (hereafter, a tag (240)) to send the signal to the retainer driver (232) to activate the retainer driver (232) to shift the retainer to unlatch the catch. The tag may be mounted on a retrieving tool component (e.g., drill bit (128)) in a location such as a shank (242) of the retrieving tool component. The tag (240) may be a radio frequency identification tag, a Bluetooth® low energy beacon, a magnetic tag, or other equivalent tag known to one of ordinary skill in the art.
The reader (238) may be configured with a capability for detecting a proximity of the tag (a detection) and for not detecting the tag (a non-detection.) The reader (238) may be configured with a capability for detecting an orientation of the tag. Detecting the proximity may include detecting the tag and meeting the requirements of a logic function. The electronics module (236) may include a computer processor for determining conformance to the requirements of the logic function.
Example logic functions include detecting the tag and meeting a predetermined time duration within a predetermined time range for which the tag is within a predetermined proximity. For example, detecting the tag within one foot distance away from the reader (238) and meeting a duration of one minute (within a time range, for example, of fifty-five seconds to sixty-five seconds, or for a duration of at least one minute) that the tag stays within the one-foot distance (within a proximity range, for example of ten inches to fourteen inches.)
Another example logic function is meeting one or more predetermined characteristics of proximity detections such as a quantity of detections, e.g., three detections within three minutes. The quantity of detections may be, for example, a duration or durations of each of the quantity of detections in a pattern of the duration of each of the quantity of detections. For example, one ten-second duration followed by a thirty-second non-detection, followed by two twenty-second durations separated by a thirty-second non-detection, all within the predetermined proximity.
The reader (238) detecting the proximity of the tag may include a capability for detecting an orientation of the tag with respect to the reader (238). In this manner the logic function may include detecting a predetermined orientation of the tag with respect to the reader (238). The predetermined orientation may have an orientation range, such as range of coordinates to the reader (238). For example, the logic function may include an orientation range defined by ranges of coordinates such as Cartesian (x, y, z) or spherical (r, θ, φ). The orientation of the bit as inferred from the orientation of tag (240) may be used to ensure operation, such as shifting the catch (204) to the catch-extended position, may only be possible when the drill bit (128) is aligned correctly such that the hook (205) is in a position oriented toward the catch (204). This orientation detection capability may be beneficial for allowing the drill bit (128) to pass over the sensor (e.g., reader 238) without activating the retainer driver (232) and/or extending driver (234) to avoid an unwanted situation such as the catch (204) shifting to the catch-extended position.
The computer processor (246) may be coupled to a communication interface (254). The communication interface (254) may be coupled to the sensor package of the electronics module (236). A memory (256) may be coupled to the computer processor (246). The memory (256) may include instructions configured to perform an unlatch method for shifting the latch (404) from the latch-extended position to the latch-retracted position. The memory may include instructions to perform the unlatch method such as obtaining a command to unlatch the latch, sending a signal to the retainer driver (232) to actuate, and unlatching the latch using the reader (238), the tag (240), and the actuation module (e.g., retainer driver 232). The unlatch method may include obtaining a command to actuate (e.g., from the driller). In response to obtaining a command to unlatch the latch, the electronics module (236) may generate sensor data using the reader (238) and the tag (240). Generating sensor data may include detecting a proximity and/or an orientation of the tag (240) and/or detecting a series of detections and/or non-detections and/or orientations within a predetermined time duration within a predetermined time range using the reader (238) and the tag (240), determining conformance to the requirements of a logic function, and sending a signal to the actuation module (e.g., retainer driver 232) to actuate.
While in the catch-extended position, upon retrieval, the hook (205) engages with the catch (204) of the whipstock (200) creating a connection that may be used to retrieve the whipstock (200) from the mainbore (203) without necessitating a second trip or a dedicated retrieval tool. In addition, one of ordinary skill in the art would appreciate that the mill bit (216) may be a drill bit when the wellbore (102) is not cased, meaning the casing string (116) is not present.
The bit blade (308) of the drill bit (128) into which the hook (205) is integrated may be a reduced bit blade (314). Reduced bit blade (314) may have a reduced diameter segment such that the length (310) has a reduced bit blade diameter that has an outside surface that is smaller in diameter than the diameter of the outside surfaces of the lengths of each bit blade (308) of the plurality of the other blades. The reduced bit blade (314) may have an outside surface that may be at a reduced distance from the retrieving tool centerline (207), such as a reduced diameter segment (e.g., the reduced bit blade diameter), relative to each bit blade (308) of the plurality of other blades.
The bit blade (308) of the drill bit (128) into which the hook (205) is integrated may be a tapered bit blade (316). Tapered bit blade (316) may have a tapered profile such that length (310) has a tapered bit blade length that tapers from a first bit blade diameter at the downhole end to a second bit blade diameter toward an uphole end in comparison to each bit blade (308) of the plurality of the other blades. The tapered bit blade (316) may have an outside surface that may be at a first distance from the retrieving tool centerline (207), such as the first bit blade diameter, at the downhole end, to a second distance from the retrieving tool centerline (207), such as a second bit blade diameter, at the uphole end.
The bit blade (308) of the drill bit (128) into which the hook (205) is integrated may be a short bit blade (318). Short bit blade (318) may have a length reduction such that length (310) has a shortened bit blade length that is shorter overall than the lengths of each bit blade (308) of the plurality of the other blades.
The bit blade (308) of the drill bit (128) into which the hook (205) is integrated may have features from none, some, or all of the set of features of reduced bit blade (314), tapered bit blade (316), and/or short bit blade (318).
Catch (204) also has an inner shear element aperture (414). The inner shear element aperture (414) has a corresponding aperture (e.g., an outer shear element aperture 416) in the whipstock (200). A shear element (420) may couple the catch (204) to the pocket (402) by being installed in the outer shear element aperture and the inner shear element aperture. The shear element (420) may couple the catch with the pocket (402) so that the shear element (420) prevents axial movement of the catch (204) relative to the pocket (402). The shear element (420) may be a press-in shear element, such as a shear pin that is press-fit into one or both of the apertures, or it may be a threaded shear element such as a shear pin that is a threaded fit into one or both of the apertures or is threaded outside the apertures. The shear element (420) may be a pinned shear element such as a shear pin that has a hole for an obstruction such as a smaller pin, a hairpin clip, a cotter pin, a screw and nut, or the like. The obstruction may prevent the shear element (420) from being removed from one or both of the apertures. The shear element (420) may be configured to shear when exposed to a shearing force such as force received by the catch (204) from the hook (205).
As depicted in
The deflection surface (202) includes an engaged element that, in this embodiment, is a cutout (250). This cutout (250) may be embodied as a tapered, oblong, or rounded shape and is configured to engage with a conventional whipstock retrieval tool (not shown) if the whipstock is not removed using the catch (204) following a sidetracking operation. Cutout (250) may extend through deflection surface (202) of the whipstock (200). Cutout (250) may be configured to engage the conventional whipstock retrieval tool as the conventional whipstock retrieval tool is being pulled out of the wellbore (102).
In operation, conventional whipstock retrieval tool engages the cutout (250) and the whipstock (200), and the conventional whipstock retrieval tool are pulled out of the wellbore (102) together. This conventional retrieval method requires a dedicated trip into the wellbore (102). In some embodiments, the cutout (250) has a tapered shape formed in the deflection surface (202). The tapered shape may be an elongated tapered shape, a triangular shape, a double-point shape, or other similar shape that permits the engagement between the cutout (250) and the conventional whipstock retrieval tool. The double-point shape may comprise an elongated cutout that divides into two points at the end toward the top of the whipstock, which may be used with a similarly shaped conventional whipstock retrieval tool.
In accordance with a first embodiment, the connection component (502) may be connected to the slip release with two cables. In a first embodiment the connection component (502) may have a first cable (510) connected at a first cable slip end (512) to the slip release (230) and connected at a first cable catch end (514) to the second engagement element (e.g., catch 204), and a second cable (520) connected at a second cable slip end (522) to the slip release (230) and connected at a second cable catch (524) end to the second engagement element (e.g., catch 204).
In accordance with a second embodiment, the connection component (502) may have a through-cable (530) disposed in the second engagement element (e.g., catch 204) and connected at a first through-cable slip end (532) and at a second through-cable slip end (534) to the slip release (230). Connection component (502) may have any combination of a first cable, second cable, and/or through-cable.
While
In step (802) the whipstock (200) with catch (204) and the drill bit (128) configured with hook (205) are deployed into the wellbore (102) inside the casing string (116) on the drill string (112) to the planned setting depth.
In step (804), the drill bit (128) with hook (205) is used to drill the section through a cut window and perform any necessary wiper trips, and then is positioned below the cut window.
In step (806), the drill bit (128) is oriented so that the hook (205) is in the retrieval position facing the deflection surface (202) of the whipstock (200) the drill bit (128) is pulled uphole to activate the latch and release the catch block. Activating the latch may include placing the drill bit (128) in close proximity to the sensor package (e.g., the RFID reader of the electronics module (236)) and waiting a period of time or by moving the drill bit (128) over the sensor a predetermined number of times in a predetermined time window with a predetermined time window tolerance, for example ten detections in two minutes plus or minus ten seconds. The sensor should be able to detect the direction of the bit travel and only release on a downward stroke to be caught on the next upward stroke.
In step (808), the second engagement element is engaged with the first engagement element. In this manner the hook engages the catch.
In step (810), the drill bit (128) is pulled uphole thereby applying an uphole tension on the second engagement element to shear the pins (e.g., shear element (420)) that prevent axial movement of the catch in the whipstock (200). The catch (204) is released from the Whipstock and the cables are pulled out to unlock the downhole component from the wellbore. The uphole tension applies a slip release force to the slip release (230) to release the slip (222) of the anchor (206). The weight on hook may increase by the weight of the whipstock (200) and anchor (206) thereby indicating a successful catch.
In step (812), the retrieving tool component connected to the uphole component and the downhole component are pulled out of the hole; i.e., drill bit (128) and whipstock (200) are pulled out of the wellbore.
Although only a few example embodiments 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. In the claims, means-plus-function clauses are intended to cover the structures described herein as performing the recited function and not only structural equivalents, but also equivalent structures. Thus, although a nail and a screw may not be structural equivalents in that a nail employs a cylindrical surface to secure wooden parts together, whereas a screw employs a helical surface, in the environment of fastening wooden parts, a nail and a screw may be equivalent structures. It is the express intention of the applicant not to invoke (35) U.S.C. § 112(f) for any limitations of any of the claims herein, except for those in which the claim expressly uses the words ‘means for’ together with an associated function.
