Patent Application
20150308196
The present disclosure relates generally to downhole drilling assemblies and methods for their use in oilfield exploration and production operations. More particularly, the present disclosure relates to under reamers for use in oilfield drilling operations.
Historically, subterranean (and subsea) wellbores have been constructed substantially the same way-an earth-boring drill bit is rotated at the end of a string of threaded drill pipe and is engaged further into the earth as the bore is cut. A drilling fluid, typically in the form of a gas or a combination of liquids and entrained solids known colloquially as drilling mud, is pumped from the surface to the bit through a central bore of the drill pipe. Upon being pumped to the bottom, the mud exits the bit at high pressure through nozzles and is used to cool, clean, and lubricate the cutting surfaces of the bit and the wellbore formation before returning to the surface (carrying formation cuttings entrained in the fluid) in the annular space located between the outer profile of the drill string and the bore of the as-cut wellbore.
Often, wellbores are drilled in multiple stages such that a lead or “pilot” bit drills an initial or pilot bore to a desired depth, with one or more larger drill bits increasing the diameter or “opening” the hole on successive passes. Increasingly, such opening operations involve more than merely increasing the nominal diameter of the wellbore—certain bits and cutting tools can be deployed to not only alter the size of the wellbore, but also to impart a particular treatment (e.g., a surface finish favorable to production, completions, or the like) to the surface of the wellbore, depending on the ultimate desired wellbore design. Because the process of drilling a borehole with a first bit, removing the bit and drillstring (in a process known in the industry as “tripping out”), and opening and/or finishing the borehole with a second bit can involve a time and labor intensive process of removing and re-installing several km of drill pipe in 20 m (60 feet) “stands,” the industry has long favored the use of deploying a wellbore reamer a specified distance behind the bit to “under-ream” or open the borehole behind the primary bit so that a single pass of the drilling mechanism, or Bottom Hole Assembly (“BHA”), may accomplish what would otherwise have taken multiple passes.
More recently, with the advent of deviated boreholes in “directional” drilling operations, a downhole device known as a mud motor may be included in the BHA to provide rotation and torque to the drill bit at the end of the drill pipe. Because it is often difficult to rotate an entire string of drill pipes through a bend in the borehole trajectory, drilling operations beyond such bends may be performed by the downhole motor using the pressurized drilling fluid as a working medium to rotate and apply torque to the drill bit. Referred to in the industry as “sliding mode” drilling, operations proceed with the rotation of the drill bit being provided by the mud motor at the bottom of the drill string, with the remaining drill pipe string being slid further into the as-drilled borehole behind the rotating assembly. While the drill pipe may be held stationary during sliding mode drilling operations, the pipe is frequently “rocked” back and forth in an oscillatory fashion or rotated relatively slowly to help prevent the drill pipe from “sticking” in the formation. Typically, the initial and substantially vertical portion of the directional wellbore is be drilled in “rotating mode” with the drillstring providing some or all of the rotary torque to the drill bit below, with the deviated and subsequent portions (e.g., horizontal or s-curve) being drilled in sliding mode primarily using torque from the mud motor.
In constructing a wellbore, operators will often drill the borehole to a large nominal diameter for an upper or first portion, and drill second and subsequent portions at one or more smaller diameters. Typically, when a portion of a wellbore is drilled to its final desired gauge, a string of coupled tubing sections having an outer diameter slightly undersize of the nominal borehole diameter and known in the industry as casing is deployed to the finished portion. With the casing in position, cement is pumped from the bore of the casing and allowed to travel up the annulus between the casing and the finished wellbore portion so that it may harden and form a permanent mechanical bond between the steel casing and the formation. With the finished section of borehole “cased” in this fashion, subsequent drilling operations to further deepen the wellbore may be performed.
Because the casing operations effectively reduce the useful diameter of the borehole, subsequent drilling operations below the cased wellbore are either performed using BHA configurations having outer profiles that are small enough to fit through the cased borehole, such that subsequent boreholes must either have a smaller nominal outer diameter, or must be drilled using a BHA having one or more collapsible cutting structures. Because drill bits having collapsible cutting structures are often characterized as having less durability compared to their non-collapsible counterparts, expandable under reamers are frequently used with a pilot drill bit to drill (or open) large diameter sections of borehole below reduced diameter obstructions such as casing strings and the like. Using a smaller diameter bit ahead of an expandable under reamer, the driller is able to pass the BHA beyond the diameter restriction to drill and open a larger borehole than would otherwise be possible with a fixed-diameter BHA. An example of an expandable under reamer may be found in U.S. Pat. No. 6,732,817, which is hereby incorporated by reference in its entirety herein.
Recently, technological advances in wellbore drilling and casing operations have resulted in relatively new systems, to drill and/or case a wellbore simultaneously, known as casing drilling or casing-while-drilling. Contrary to the former practice of drilling a wellbore (e.g., using drill pipe) and retrieving the BHA followed by installing and cementing casing in place, casing drilling operations use the large-diameter casing string itself as the mechanical link to rotate and provide drilling fluids to the BHA. Because the casing is used in place of the aforementioned drill pipe, the wellbore can be drilled and cased using fewer “trip out” operations to complete a cased section of wellbore. When drilling with casing, the BHA must have the ability to be withdrawn into the casing string to return it to surface. The BHA must also drill a large enough hole through which the casing must pass. In order to achieve these two requirements, the cutting structure on the BHA must be collapsible, therefore an under reamer is required to both cut the enlarged hole for the casing to pass, and collapse to allow the BHA to pass inside the casing string.
While rotating the bit and/or BHA from the surface using the casing is possible, particularly for shallow and/or substantially vertical boreholes, the amount of friction between the borehole wall and the outer profile of the casing string would be too large to drill at great depths, or to use a casing string having an outside diameter too close to the nominal wellbore diameter.
In some examples of casing drilling, a BHA may be connected to a distal end of a string of casing using a mechanism known as a drill lock assembly (“DLA”) to releasably secure the BHA to the end of the casing string so that components of the BHA (e.g, a drill bit, reamer, mud motor, measurement and/or telemetry tools, etc.) may be easily retrieved once the casing is ready to be cemented in place. Typically, the DLA functions to secure the BHA to the distal end of the casing string so that rotary torque and axial loads from the surface may be driven through the casing to the BHA. Examples of one type of DLA may be found in U.S. Pat. No. 8,146,672, which is hereby incorporated by reference in its entirety herein.
In one aspect, the present disclosure relates to an apparatus to drill a wellbore including a cutting structure attached to a distal end of a drilling string, and a bottom hole assembly including a drill bit, a reamer drive sub, and a downhole motor. The bottom hole assembly is configured to pass through a central bore of the drilling string and the cutting structure at the distal end of the drilling string, such as a casing or liner string. The reamer drive sub is configured to releasably engage the cutting structure, and the bottom hole assembly is configured to rotate the cutting structure through the reamer drive sub. When engaged, the cutting structure is axially decoupled from the drilling string.
In another aspect, the present disclosure relates to a method to drill a wellbore including: positioning a cutting structure proximal to a distal end of a drilling string; deploying a bottom hole assembly through a central bore of the distal end of the drilling string and the cutting structure, engaging the cutting structure with the bottom hole assembly, axially decoupling the cutting structure from the drilling string, and rotating the cutting structure with the bottom hole assembly.
In another aspect, the present disclosure relates to an under reamer assembly to be used in a drilling operation including a reamer shoe configured to be positioned proximal a distal end of a drilling string; and a cutting structure releasably coupled to the reamer shoe. The cutting structure is configured to be engaged by a bottom hole assembly, decoupled from the reamer shoe, and displaced axially from the casing or liner string. The cutting structure is configured to rotate with the bottom hole assembly to enlarge a pilot bore cut by a drill bit of the bottom hole assembly.
In another aspect, the present disclosure relates to an apparatus to drill a wellbore including a drilling string, a bottom hole assembly, and a reamer shoe. The bottom hole assembly may include a drill bit, a reamer drive sub comprising one or more torque dogs, and a downhole motor. The reamer shoe assembly may include: a sleeve rotatably attached to a distal end of the drilling string; a cutting head, configured to be rotated by the reamer drive sub, having one or more inner recesses configured to be releasably engaged by the one or more torque dogs of the reamer drive sub; and a biasing spring and a bushing intermediate the cutting head and the distal end of the drilling string configured to permit relative rotation and axial movement between the cutting head and the drilling string.
In another aspect, the present disclosure relates to a method to drill a wellbore including: disposing a reamer shoe assembly proximal to a distal end of a drilling string, the reamer shoe configured to rotate freely with respect to and move axially relative to the drilling string; deploying a bottom hole assembly through a central bore of the distal end of the drilling string and the reamer shoe assembly; and releasably engaging and rotating the reamer shoe assembly with the bottom hole assembly.
In another aspect, the present disclosure relates to an under reamer assembly to be used in a drilling operation including: a sleeve configured to be attached to a distal end of the drilling string; a cutting head attached to the sleeve, the cutting head configured to be rotated by a reamer drive sub and comprising one or more inner recesses configured to be releasably engaged by one or more torque dogs of the reamer drive sub; a biasing spring and a bushing configured to be disposed intermediate the cutting head and the distal end of the drilling string, the biasing spring and bushing permitting relative rotation and axial movement between the cutting head and the drilling string. The cutting head is configured to enlarge a pilot bore cut by a drill bit of a bottom hole assembly
Features of the present disclosure will become more apparent from the following description in conjunction with the accompanying drawings.
Historically, under reamers have typically performed two functions. The first function is to enlarge a borehole that has been drilled by a smaller first or pilot bit. The second function has been to collapse, so that the under reamer, drill bit, and bottom hole assembly can be retrieved to the surface through a geometric restriction in the wellbore above. As such, pilot bit/under reamer combinations have been frequently used to drill wellbores beneath strings of cemented casing, below wellbore valves and packers, and to drill large diameter “pay zone” bores where larger amounts of formation surface area in the wellbore advantageously affect the amount and rate of production.
Because casing drilling is analogous to drilling beneath cemented casing, collapsible under reamers have been used in the industry to drill boreholes using casing strings as the drilling string. As described above, in casing drilling operations, the BHA including the drill bit, mud motor, and under reamer should not only be sized small enough to clear through the inner diameter of the casing string through and upon which it is delivered, but may also be capable of drilling a borehole that is large enough for the outer diameter of the casing string to be engaged there-behind. While embodiments described herein are described in reference to their applicability to casing drilling operations, it should be understood that the embodiments disclosed and claimed herein may be used in conjunction with conventional, liner, and other drilling techniques as well, where “drilling string” as used herein may refer to drill strings, liner strings, casing strings, etc.
As disclosed herein, one or more embodiments includes an under reamer cutting structure, that is configured to be selectively coupled to and decoupled from a bottom hole assembly, located at or near a distal end of the drilling string. For example, the under reamer cutting structure may be configured to be selectively coupled to and decoupled from a reamer drive sub, and in some embodiments may additionally be selectively coupled to and decoupled from the drilling string. In selected embodiments, when coupled, the cutting structure may be locked with the drilling string such that as the drilling string is rotated about its axis (e.g., from top drive or rotary table above), the under reamer cutting structure is also rotated. However, in selected embodiments, once decoupled, the cutting structure is free to rotate independent of the remainder of the drilling string.
Thus, in one or more embodiments, a BHA containing a drill bit, a downhole motor, a reamer drive sub, and a DLA may be deployed through the inner diameter of the drilling string until the BHA reaches the distal end of the drilling string. Once reached, the reamer drive sub of the BHA may engage the coupled under reamer cutting structure and de-couple it from the drilling string. With the cutting structure engaged by the reamer drive sub and decoupled from the drilling string, and with the DLA anchored into the lock nipple, in one or more embodiments, the downhole motor may be operated to rotate both the drill bit and the under reamer cutting structure relative to the drilling string to drill the formation deeper. Depending on the relative size of the as-under reamed wellbore compared to the outer diameter of the drilling string, the drilling string may be thrust further into the wellbore behind the BHA (in either sliding or rotating mode) from the surface.
When retrieval of the BHA is desired, the DLA may be disengaged so that the reamer drive sub may be used to re-couple the cutting structure back to the reamer shoe and then disengage the cutting structure. With the cutting structure coupled to the reamer shoe and disengaged from the reamer drive sub, the BHA may be retrieved (using wireline, coiled tubing, drill pipe, or the like) from the bore of the drilling (i.e., casing) string. The drill bit and other components of the bottom hole assembly may then be repaired or replaced, and re-deployed downhole to resume drilling operations. Alternatively, with the casing string and reamer cutting structure remaining in the borehole, a cementing operation may be performed to cement both the in-situ cutting structure and the casing string in place. Following cementation, additional drilling operations beneath the cemented casing may be performed to further deepen the wellbore.
Referring now to
Referring now to
As would be appreciated by those having ordinary skill, the locking engagements and disengagements between DLA 120 and corresponding lock nipple 112 and between reamer drive sub 124 and cutting structure 118 may be accomplished through any number of mechanisms knows to those skilled in downhole oil tools. For example, in one or more embodiments, signals sent from a surface location to BHA I04 may instruct locking dogs of either DLA 120 or reamer drive sub 124 to extend and engage corresponding structures in their drilling string assembly 102, namely profiles (i.e., receptacles) within lock nipple 112 or cutting structure 118. Such signals may include, but are not limited to, hydraulic, electrical, or mechanical activation signals (e.g., picking up or setting down the delivery string) sent from the surface to instruct BHA 104 to perform specified engagement and/or disengagement tasks.
Similarly, the decoupling and coupling of cutting structure 118 from reamer drive sub 124 may be accomplished as a result of signals sent from the surface. Alternatively, cutting structure 118 may be configured to be de-coupled and coupled from reamer shoe 116 through a specified rotation or axial load following engagement of reamer drive sub 124 within cutting structure 118 as described above. For example, once engaged with reamer drive sub 124 of BHA 104, cutting structure 118 may be decoupled from reamer shoe 116 (i.e., drilling string 110) by rotation of BHA 104 in a specified direction for a specified number of turns. Alternatively, cutting structure 118 may be decoupled from reamer shoe 116 by rotation of drilling string assembly 102 a specified direction for a specified number of turns. Alternatively still, cutting structure 118 may be decoupled by axially thrusting the BHA downward or upward while cutting structure 118 is engaged by reamer drive sub 124. Alternatively still, cutting structure 118 may be decoupled by axially thrusting the BHA downward or upward while rotating to the left or right while cutting structure 118 is engaged by reamer drive sub 124.
With cutting structure decoupled from reamer shoe 116 and engaged by reamer drive sub 124, cutting structure 118 may be axially separated from reamer shoe 116 so that BHA 104 may drill the formation. Referring briefly now to
Following the engagement and decoupling of reamer cutting structure 118 from reamer shoe 116, the aforementioned DLA 120 of BHA 104 may axially align with and engage lock nipple 112 of the drilling string assembly 102. With DLA 120 locked into engagement with lock nipple 112, rotary torque and axial loads may be transmitted between the distal end of drilling string assembly 102 and the proximal ends of BHA 104. Furthermore, with DLA 120 locked into nipple 112, downhole motor 122 is free to rotate the distal end of BHA 104 relative to drilling string assembly 102. In one or more embodiments, downhole motor 122 is a “mud motor” in that the pressurized drilling fluid (e.g., mud) is used as the working fluid and is converted into mechanical energy. However, those having ordinary skill will appreciate that additional types of motors (e.g., electrical motors, inductive motors, alternative hydraulic motors) may be used without departing from the disclosure as presented or claimed. Additionally, downhole motor, as a “mud” operated motor may take the form of a positive displacement (PDM) type mud-motor or a centrifugally operated turbine-type mud motor, depending on the types of formation to be drilled and/or the types of bits and/or reamer cutting structures to be used.
Thus, with DLA 120 engaged into the distal end of drilling string assembly 102, a stator (not shown) of the downhole motor is anchored to drilling string 110 so that a rotor (not shown) of downhole motor 122 may apply torque to rotate bit 128, MWD assembly 126, and under reamer (reamer drive sub 124 and cutting structure 118) together. Such rotation allows BHA 104 to drill (with bit 128) and enlarge (with cutting structure 118 engaged by reamer drive sub 124) the borehole to allow drilling string 110 (i.e., casing string) to be engaged farther into the drilled wellbore.
With the wellbore drilled and drilling string positioned to the desired depth, DLA 120 may be disengaged from lock nipple 112 so that cutting structure 118 may again be coupled to reamer shoe 116. Once coupled, reamer drive sub 124 may disengage cutting structure 118, thereby allowing BHA 104 to be retrieved from drilling string 110 and returned to the surface. Following retrieval of BHA 104 from drilling string 110, components of the BHA may be repaired or replaced, or, if desired, the entire drilling string assembly 102 (including stabilizer 114, reamer shoe 116, and cutting structure 118) may be cemented in place. Once cemented, further depths (if necessary) may be drilled beneath the cemented-in-place drilling string 110.
Cutting structures 118 that may be axially coupled/decoupled from the drill string, as illustrated and described with respect to
The cutting structures 118, when axially decoupled from the drill string, may be rotated independent of the drill string by the mud motor. As an alternative manner for rotating under reamer cutting structures independent of the drill string, a reamer shoe assembly, such as illustrated in
Referring now to
As depicted, coupling between cutting head 204 and shoe assembly 200 of
Embodiments disclosed herein, such as illustrated in
Advantageously, embodiments disclosed herein permit wellbore sections that would otherwise be drilled and cased using multiple trips with conventional drilling and casing tools to be drilled in a single pass using a casing drilling or casing-while-drilling operation. Additionally, embodiments disclosed herein advantageously permit operations to simultaneously drill and case boreholes to full gauge using non-collapsible devices such that their cutting structures may be optimized for cutting effectiveness rather than dually optimized for cutting effectiveness and collapsibility. As such, embodiments disclosed herein permit a fuller, more robust under reamer cutting structure that may be more preferably matched and optimized to work with a particular drill bit and/or on a particular formation to be drilled, while avoiding the structural and geometric constraints of currently available collapsible under reamer designs
While the disclosure has been presented with respect to a limited number of embodiments, those skilled in the art, having benefit of this disclosure, will appreciate that other embodiments may be devised which do not depart from the scope of the present disclosure. Accordingly, the scope of the invention should be limited only by the attached claims.
The present application claims priority to U.S. Provisional Patent Application 61/985,666, filed Apr. 29, 2014, the entirety of which is incorporated by reference.
| Number | Date | Country | |
|---|---|---|---|
| 61985666 | Apr 2014 | US |
