Patent Application
20240410230
The unconventional market is very competitive. The market is trending towards longer horizontal wells to increase reservoir contact. Multilateral wells offer an alternative approach to maximize reservoir contact. Multilateral wells include one or more lateral wellbores (e.g., secondary wellbores) extending from a main wellbore (e.g., primary wellbore). A lateral wellbore is a wellbore that is diverted from the main wellbore or another lateral wellbore.
Lateral wellbores are typically formed by positioning one or more deflector assemblies (e.g., whipstock assemblies) at desired locations in the main wellbore (e.g., an open hole section or cased hole section) with a running tool. The deflector assemblies are often laterally and rotationally fixed within the primary wellbore using an anchoring assembly.
Reference is now made to the following descriptions taken in conjunction with the accompanying drawings, in which:
In the drawings and descriptions that follow, like parts are typically marked throughout the specification and drawings with the same reference numerals, respectively. The drawn figures are not necessarily to scale. Certain features of the disclosure may be shown exaggerated in scale or in somewhat schematic form and some details of certain elements may not be shown in the interest of clarity and conciseness. The present disclosure may be implemented in embodiments of different forms.
Specific embodiments are described in detail and are shown in the drawings, with the understanding that the present disclosure is to be considered an exemplification of the principles of the disclosure, and is not intended to limit the disclosure to that illustrated and described herein. It is to be fully recognized that the different teachings of the embodiments discussed herein may be employed separately or in any suitable combination to produce desired results.
Unless otherwise specified, use of the terms “connect,” “engage,” “couple,” “attach,” or any other like term describing an interaction between elements is not meant to limit the interaction to a direct interaction between the elements and may also include an indirect interaction between the elements described. Unless otherwise specified, use of the terms “up,” “upper,” “upward,” “uphole,” “upstream,” or other like terms shall be construed as generally away from the bottom, terminal end of a well; likewise, use of the terms “down,” “lower,” “downward,” “downhole,” “downstream,” or other like terms shall be construed as generally toward the bottom, terminal end of a well, regardless of the wellbore orientation. Use of any one or more of the foregoing terms shall not be construed as denoting positions along a perfectly vertical axis. Unless otherwise specified, use of the term “subterranean formation” shall be construed as encompassing both areas below exposed earth and areas below earth covered by water, such as ocean or fresh water.
The disclosure addresses the challenge of running a whipstock assembly on a mill, for example in an effort to reduce trip count. With this in mind, the present disclosure provides a two part drilling and running tool (e.g., including a smaller assembly and a larger bit assembly) that may be used to run a whipstock assembly downhole. In at least one embodiment, the larger bit assembly (e.g., uphole/larger bit assembly) is connected to the whipstock assembly, for example proximate an uphole end of the whipstock assembly. At a desired point in time, the smaller assembly may pull back uphole and connect to the larger bit assembly, thereby forming a new combined bit assembly (e.g., that looks and functions like a conventional lead mill). For purposes of the present disclosure, the term bit assembly is intended to encompass both mill assemblies and drill bit assemblies. Following the successful creation of the exit and the drilling of the lateral, the lateral completion could be installed and then tied together with the main bore by installing a junction (e.g., level 5 junction in one embodiment).
In accordance with at least one embodiment of the disclosure, the smaller assembly is a smaller bit assembly having one or more cutting features (e.g., teeth, blades, etc.) thereon. The smaller assembly, in one embodiment, could be connected to a conveyance that extends through the larger bit assembly and is then connected to the rest of the drill string, or perhaps to a downhole motor directly. In at least one embodiment, the smaller assembly is sized such that it can wholly or partially fit into a bore of the whipstock assembly, such that in one embodiment it may connect to the whipstock assembly or there below. In at least one embodiment, the larger bit assembly and/or smaller assembly are coupled to the whipstock assembly or other downhole device there below using a shear feature, a collection of lugs and/or slots or other connecting mechanism.
With the smaller assembly free from the whipstock assembly or other downhole device there below, the smaller assembly is free to slide back uphole and into the larger bit assembly. In one or more embodiments, the smaller assembly has a spline or slot located along an entire length (Ls) thereof, and the larger bit assembly includes an associated other of the slot or spline. In at least one embodiment, the spline or slot in the smaller assembly and the associated other of the slot or spline in the larger bit assembly are configured to engage one another to rotationally fix the smaller assembly relative to the larger bit assembly as the smaller assembly and the larger bit assembly slidingly engage one another to form the combined bit assembly. In one or more embodiments, the spline or slot in the smaller assembly is a spline and the other of the slot or spline in the larger bit assembly is a slot, but the opposite may also be true.
In one or more other embodiments, the spline or slot is a first smaller assembly spline or slot and the other of the slot or spline is a first larger bit assembly other of the slot or spline. In at least this embodiment, the smaller assembly has a second spline or slot located along less than the entire length (LS) thereof, and the larger bit assembly has a second other of the slot or spline located along less than an entire length (LL) thereof. In accordance with this embodiment, the second spline or slot is configured to engage with the second other of the slot or spline to prevent the smaller assembly from sliding out of the larger bit assembly as the conveyance is being retracted uphole.
Once the smaller assembly has been fully retracted into the larger bit assembly it can be secured to the larger bit assembly for the milling operation. In at least one embodiment, a simple snap ring falls into a groove in the smaller assembly, thereby securing (e.g., laterally securing) the smaller assembly within the larger bit assembly. Many alternate methods are possible, such as spring-loaded pins, locking dogs, or an interference fit between the two bit assemblies. In at least one embodiment, the spline or slot located in the smaller assembly and the other of the slot or spline located in the larger bit assembly rotationally lock the two bit assemblies together (e.g., torsionally securing the smaller assembly and the larger bit assembly), while the snap ring or other feature axially locks the two bit assemblies together.
At this point the larger bit assembly may be disconnected from the whipstock assembly tip and a normal window can be milled in the casing and/or formation as is current industry practice. As is sometimes the practice with milling windows, secondary mills (e.g., watermelon mills) may be added to follow the lead mill to ensure proper window geometry. Likewise multiple trips may be required to successfully mill a window. In those cases, extra mills or trips could be performed as is done today. Thereafter, the remainder of the multilateral construction may be completed, for example including placing a multilateral junction including a mainbore leg and a lateral bore leg at the junction between the main wellbore and the lateral wellbore.
Up to this point, the use of a two part drilling and running tool has been discussed for creating an exit window from a cased mainbore. An alternate use for this new technology is to sidetrack from an open-hole main bore. In this alternate use, the bit assembly would be more appropriately called a drill bit, as it would be drilling formation to exit the main bore rather milling casing. This would be useful for simple sidetracking where the main bore may need to be abandoned, or it may be used during the construction of an open-hole multilateral junction. In this use, the smaller assembly and larger bit assembly would be designed differently than what is shown here, for example to closely resemble a drill bit instead of a mill bit. This would necessitate certain changes to the external cutting features, which should be understood to not deviate from the core features described herein.
As shown, a main wellbore 150 has been drilled through the various earth strata, including the subterranean formation 110. The term “main” wellbore is used herein to designate a primary wellbore from which another secondary wellbore is drilled. It is to be noted, however, that a main wellbore 150 does not necessarily extend directly to the earth's surface, but could instead be a branch of yet another lateral wellbore. A casing string 160 may be at least partially cemented within the main wellbore 150. The term “casing” is used herein to designate a tubular string used to line a wellbore. Casing may actually be of the type known to those skilled in the art as a “liner” and may be made of any material, such as steel or composite material and may be segmented or continuous, such as coiled tubing. The term “lateral” wellbore is used herein to designate a wellbore that is drilled outwardly from its intersection with another wellbore, such as a main wellbore. Moreover, a lateral wellbore may have another lateral wellbore drilled outwardly therefrom.
A whipstock assembly 170 according to one or more embodiments of the present disclosure may be positioned at a location in the main wellbore 150. Specifically, the whipstock assembly 170 could be placed at a location in the main wellbore 150 where it is desirable for a lateral wellbore 180 to exit. Accordingly, the whipstock assembly 170 may be used to support a drilling/milling tool used to penetrate a window in the main wellbore 150. In at least one embodiment, once the window has been milled and a lateral wellbore 180 formed, the whipstock assembly 170 may be retrieved and returned uphole by a retrieval tool, in some embodiments in only a single trip.
In some embodiments, an anchoring assembly 190 may be placed downhole in the wellbore 150 to support and anchor downhole tools, such as the whipstock assembly 170, for keeping the whipstock assembly 170 in place while milling the casing 160 and/or drilling the lateral wellbore 180. The anchoring assembly 190, in accordance with the disclosure, may be employed in a cased section of the main wellbore 150, or may be located in an open-hole section of the main wellbore 150, as is shown. As such, the anchoring assembly 190 in at least one embodiment may be configured to resist at least 6,750 newton meters (Nm) (e.g., about 5,000 lb-ft) of torque. In yet another embodiment, the anchoring assembly 190 may be configured to resist at least 13,500 newton meters (Nm) (e.g., about 10,000 lb-ft) of torque, and in yet another embodiment configured to resist at least 20,250 newton meters (Nm) (e.g., about 15,000 lb-ft) of torque. Similarly, the anchoring assembly 190 may be configured to resist at least 1814 kg (e.g., about 4,000 lb) of axial force. In yet another embodiment, the anchoring assembly 190 may be configured to resist at least 4536 kg (e.g., about 10,000 lb) of axial force, and in yet another embodiment the anchoring assembly 190 may be configured to resist at least 6804 kg (e.g., about 15,000 lb) of axial force.
In the illustrated embodiment, the anchoring assembly 190 may be a hydraulically activated anchoring assembly. In this embodiment, once the anchoring assembly 190 reaches a desired location in the main wellbore 150, fluid pressure may be applied to set the hydraulic anchoring assembly. In at least one embodiment, the hydraulically activated anchoring assembly includes two or more hydraulic activation chambers, and the activation fluid is supplied to the two or more hydraulic activation chambers (e.g., through a two-part milling assembly coupled to the whipstock assembly 170) to move the two or more hydraulic activation chambers from the first collapsed state to the second activated state and engage a wall of the main wellbore 150. The anchoring assembly 190 may also include, in some embodiments, an expandable medium positioned radially about the two or more hydraulic activation chambers. In some aspects, the expandable medium may be configured to grip and engage the wall of the main wellbore 150 when the two or more hydraulic activation chambers are in the second activated state. Notwithstanding, other fluid activated anchoring assemblies (e.g., other than those having two or more hydraulic activation chambers) may be used and remain within the scope of the disclosure. In at least one other embodiment, the hydraulically activated anchoring assembly includes one or more hydraulic activation slips, and the activation fluid is supplied to the one or more hydraulic activation slips (e.g., through a two-part milling assembly coupled to the whipstock assembly 170) to move the one or more hydraulic activation slips from the first collapsed state to the second activated state and engage the wall of the main wellbore 150.
Furthermore, mechanical activated anchoring assemblies could also be used and remain within the scope of the disclosure. For instance, in yet other embodiments, the anchoring assembly 190 is a latch coupling. In this embodiment, the latch coupling (e.g., a profile in the casing engages with a reciprocal profile in the whipstock assembly 170) anchors the whipstock assembly 170, and any other features hanging there below (e.g., screens, valves, etc.) in the casing string 160. Once the anchoring assembly 190 reaches a desired location in the main wellbore 150, the reciprocal profile in the whipstock assembly 170 may be activated to engage with the latch coupling profile in the casing string 160, thereby setting the anchoring assembly 190. Thus, in at least one embodiment, the anchoring assembly 190 is not hydraulically activated, but is mechanically activated.
In at least one embodiment, a multilateral junction is positioned at an intersection between the resulting main wellbore 150 and the resulting lateral wellbore 180. In accordance with one embodiment, the multilateral junction might include a main bore leg forming a first pressure tight seal with the main bore completion and a lateral bore leg forming a second pressure tight seal with the lateral bore completion, such that the main bore completion and the lateral bore completion are hydraulically isolated from one another. What results, in one or more embodiments, is an open hole TAML Level 5 pressure tight junction.
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As will be discussed in greater detail below, the two part milling and running tool 200 may be used to deploy a whipstock assembly, and thus may be coupled to the whipstock assembly when running downhole. Accordingly, the smaller assembly 250 may be coupled to one of the whipstock assembly, the anchoring assembly or the wellbore liner, in at least one embodiment, which would prevent the smaller assembly 250 from sliding toward the larger bit assembly 220 during the run-in-hole phase. Only when the smaller assembly 250 is decoupled from the whipstock assembly, the anchoring assembly or the wellbore liner, would the smaller assembly 250 be allowed to slide toward the larger bit assembly 220.
In the illustrated embodiment, the smaller assembly 250 has a spline or slot 251 located along an entire length (LS) thereof, and the larger bit assembly 220 has an associated other of a slot or spline 221. For example, when the spline or slot 251 is a spline, the other of the slot or spline 221 would be a slot. Alternatively, when the spline or slot 251 is a slot, the other of the slot or spline 221 would be a spline. In at least one embodiment, the length (LS) is at least 0.1meters, if not at least 0.2 meters. In yet another embodiment, the length (LS) is at least 0.5 meters if not at least 1 meter.
In one or more embodiments, the spline or slot 251 is a smaller assembly spline or slot 251a and the other of the slot or spline 221 is a larger bit assembly other of the slot or spline 221a. In such an embodiment, the conveyance 210 may include a conveyance spline or slot 211 located along a length (L1) of the conveyance and substantially aligned with the smaller assembly spline or slot 251a. The term “substantially aligned,” as used in this paragraph, means that the conveyance spline or slot 211 and the smaller assembly spline or slot 251a are radially aligned within 3 degrees. In certain embodiments, the conveyance spline or slot 211 and the smaller assembly spline or slot 251a are ideally radially aligned within 2 degrees, or extremely radially aligned within 1 degree. In at least one embodiment, the conveyance spline or slot 211 and the smaller assembly spline or slot 251a are identically radially aligned. In at least this one embodiment, the conveyance spline or slot 211 and the larger bit assembly other of the slot or spline 221a are configured to engage one another to rotationally fix the conveyance 210 relative to the larger bit assembly 220. In one or more embodiments, the length (L1) is at least 1 meter, if not at least 2 meters. In yet another embodiment, the length (L1) is at least 4 meters, if not at least 5 meters or 8 meters or more.
In one or more embodiments, the spline or slot 251 is a first smaller assembly spline or slot 251a and the other of the slot or spline 221 is a first larger bit assembly other of the slot or spline 221a, and the smaller assembly 250 has a second spline or slot 251b located along less than the entire length (LS) thereof, and the larger bit assembly 220 has a second other of the slot or spline 221b located along less than an entire length (LL) thereof. In one or more embodiments, the second spline or slot 251b and the second other of the slot or spline 221b are located at a downhole end of the smaller assembly 250 and the larger bit assembly 220, respectively. In this embodiment, the second spline or slot 251b is configured to engage with the second other of the slot or spline 221b to prevent the smaller assembly 250 from sliding out of the larger bit assembly 220 as the conveyance 210 is being retracted uphole.
In one or more embodiments, the second spline or slot 251b has a length (L2) and the second other of the slot or spline 221b has a length (L3), and further wherein the length (L2) and the length (L3) are substantially the same. The term “substantially the same,” as used in this paragraph, means that the length (L2) and the length (L3) are within 25 percent of each other. In yet another embodiment, the length (L2) and the length (L3) are ideally the same, which means that the length (L2) and the length (L3) are within 10 percent of each other. In yet even another embodiment, the length (L2) and the length (L3) are extremely the same, which means that the length (L2) and the length (L3) are within 2 percent of each other. In yet even another embodiment, the length (L2) and the length (L3) are exactly the same, which means that the length (L2) and the length (L3) are within 0.5 percent of each other. In one last embodiment, the length (L2) and the length (L3) are identical.
Notwithstanding the foregoing, in at least one embodiment, the length (L2) and the length (L3) are less than 0.8 meters. In at least one other embodiment, the length (L2) and the length (L3) are less than 0.5 meters, if not less than 0.1 meters, if not less than 0.05 meters. In yet another embodiment, the length (L2) and the length (L3) are less than 75 percent of the length (LS). In an even other embodiment, the length (L2) and the length (L3) are less than 50 percent of the length (LS), if not less than 40 percent.
In the illustrated embodiment, the first smaller assembly spline or slot 251a and the first larger bit assembly other of the slot or spline 221a are rotationally offset from the second smaller assembly spline or slot 251b and the second larger bit assembly other of the slot or spline 221b, for example by at least 5 degrees. In yet another embodiment, the two are radially offset by at least 10 degrees, if not at least 15 degrees. In yet another embodiment, ones of the first smaller assembly spline or slot 251a and the first larger bit assembly other of the slot or spline 221a are positioned equal distance from the second smaller assembly spline or slot 251b and the second larger bit assembly other of the slot or spline 221b.
The embodiment of
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The smaller assembly 250, in the illustrated embodiment, may further include an associated lock ring profile 258. Accordingly, the lock ring profile 258, as well as the associated lock ring profile 228 and lock ring (not shown) of the larger bit assembly 220, may be used to linearly fix the larger bit assembly 220 and the smaller assembly 250. Additionally, the first smaller assembly spline or slot 251a of the smaller assembly 250, as well as the first larger bit assembly other of the slot or spline 221a of the larger bit assembly 220, may be used to rotationally fix the larger bit assembly 220 and the smaller assembly 250.
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In yet another embodiment, a wellbore liner 855 is coupled to a downhole end of the anchoring assembly 845, and thus may also be run in the wellbore 810 with the two part drilling and running tool 830. The wellbore liner 855, in at least one embodiment, might be a lower mainbore completion assembly that might include one or more screens, one or more control valves, etc.
The two part drilling and running tool 830 may be similar to the two part drilling and running tool discussed above. Accordingly, the two part drilling and running tool 830 may include a larger bit assembly 860 and a smaller assembly 870. As shown in the embodiment of
Aspects disclosed herein include:
Aspects A, B, C and D may have one or more of the following additional elements in combination: Element 1: wherein the spline or slot is a smaller assembly spline or slot and the other of the slot or spline is a larger bit assembly other of the slot or spline, and further including a conveyance spline or slot located along a length (L1) of the conveyance and substantially aligned with the smaller assembly spline or slot, the conveyance spline or slot and the larger bit assembly other of the slot or spline configured to engage one another to rotationally fix the conveyance relative to the larger bit assembly. Element 2: wherein the length (L1) is at least 2 meters. Element 3: wherein the length (L1) is at least 4 meters. Element 4: wherein the length
(LS) is at least 0.1 meters. Element 5: wherein the spline or slot is a first smaller assembly spline or slot and the other of the slot or spline is a first larger bit assembly other of the slot or spline, and further wherein the smaller assembly has a second spline or slot located along less than the entire length (LS) thereof and the larger bit assembly has a second other of the slot or spline located along less than an entire length (LL) thereof, the second spline or slot configured to engage with the second other of the slot or spline to prevent the smaller assembly from sliding out of the larger bit assembly as the conveyance is being retracted uphole. Element 6: wherein the second spline or slot has a length (L2) and the second other of the slot or spline has a length (L3), and further wherein the length (L2) and the length (L3) are substantially the same. Element 7: wherein the length (L2) and the length (L3) are less than 0.8 meters. Element 8: wherein the first smaller assembly spline or slot and the first larger bit assembly other of the slot or spline are rotationally offset from the second smaller assembly spline or slot and the second larger bit assembly other of the slot or spline by at least 15 degrees. Element 9: wherein the spline or slot in the smaller assembly is a spline and the other of the slot or spline in the larger bit assembly is a slot. Element 10: wherein the smaller bit assembly includes one of a lock ring profile or a lock ring, and the larger bit assembly includes an other of the lock ring or the lock ring profile, the lock ring profile and lock ring configured to engage with one another to slidingly fix the smaller bit assembly with the larger bit assembly when the two are slidingly engaged together. Element 11: wherein the smaller bit assembly includes the lock ring profile and the larger bit assembly includes the lock ring. Element 12: further including: an anchoring assembly coupled downhole of the whipstock assembly; and a wellbore liner coupled downhole of the anchoring assembly.
Those skilled in the art to which this application relates will appreciate that other and further additions, deletions, substitutions and modifications may be made to the described embodiments.
