In the drilling of oil and gas wells, concentric casing strings are installed and cemented in the wellbore as drilling progresses to increasing depths. Each new casing string may run from the surface or may include a liner suspended from a previously installed casing string. The new casing string may be within the previously installed casing string, thereby limiting the annular area available for the cementing operation. Further, as successively smaller diameter casing strings are used, the flow area for the production of oil and gas is reduced. To increase the annular space for the cementing operation, and to increase the production flow area, it may be desirable to enlarge the wellbore below the terminal end of the previously cased portion of the wellbore. By enlarging the wellbore, a larger annular area is provided for subsequently installing and cementing a larger casing string than would have been possible otherwise. Accordingly, by enlarging the wellbore below the previously cased portion of the wellbore, comparatively larger diameter casing may be used at increased depths, thereby providing more flow area for the production of oil and gas.
Various methods have been devised for passing a drilling assembly through an existing cased portion of a wellbore and enlarging the wellbore below the casing. One such method is the use of an underreamer, which has two basic operative states. A first state is a closed, retracted, or collapsed state, where the diameter of the tool is sufficiently small to allow the tool to pass through the existing cased portion of the wellbore. The second state is an open, active, or expanded state, where arms or cutter blocks extend from the body of the tool. In this second state, the underreamer enlarges the wellbore diameter as the tool is rotated and lowered and moved axially in the wellbore.
According to some embodiments of the present disclosure, a cutting apparatus includes a cutter arm having first and second stabilizer portions adjacent reaming portions of the cutter arm. The first stabilizer portion is adjacent a first reaming portion and the second stabilizer portion is between first and second reaming portions. A gauge portion of the cutter arm is positioned adjacent the second reaming portions and either has no stabilizer portion or has a third stabilizer portion that is shorter than the first stabilizer portion, the second stabilizer portion, or both. Cutting elements are located in the first and second reaming portions of the cutter arm.
According to additional embodiments of the present disclosure, a downhole assembly may include a bit and a cutting tool uphole of the bit. The cutting tool may have expandable cutter arms. An expandable cutter arm can include a stabilizer portion with a radial position that is about the same as the gauge of the bit when the expandable cutter arm is in an expanded position.
In additional embodiments, a cutter arm for a downhole tool includes a body defining a formation facing surface, a leading side surface, and a trailing side surface. Cutting elements are coupled to the formation facing surface. A spline on the leading side surface or a spline on the trailing side surface intersects the formation facing surface and forms a lateral extension of the formation facing surface.
In another example embodiment, a method for expanding a diameter of a wellbore includes tripping an underreamer into a wellbore while the underreamer is in a retracted position. Cutter blocks are expanded to transition the underreamer into an expanded position, and expanding the cutter blocks includes expanding a cutter blocks that include one or more features. Example features include a spline extension at a stabilizer pad, the spline extension rotationally leading or trailing a cutting structure of a cutter block; a stabilizer pad that, when the cutter block is expanded, has a radial position about equal to a pilot size of the wellbore; cutting structure that, when the cutter block is expanded, has a radial position less than the pilot size of the wellbore; or multiple stages of reaming portions separated by stabilizer pads, a gauge of the a cutter block including no stabilizer pad or a stabilizer pad having a length less than the length of another stabilizer pad. The formation is also degraded around the wellbore by moving the underreamer axially and rotationally within the wellbore.
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, embodiments disclosed herein relate generally to cutting structures for use on drilling tool assemblies. More specifically, some embodiments disclosed herein relate to cutting structures for an underreamer or other tool used to enlarge a wellbore.
According to some aspects of the disclosure, there is provided a downhole cutting apparatus, such as an underreamer, which may include a cutter block. The cutter block may have an underreaming portion or edge, a backreaming portion or edge, or both. In one or more embodiments, the downhole cutting apparatus may be an expandable tool and the cutter block may be radially movable between any combination of a retracted position, partially expanded positions, and a fully expanded position. In one or more other embodiments, the downhole cutting apparatus may be a downhole cutting tool that is not expandable. For example, in one or more embodiments, the downhole cutting apparatus may be a hole opener having a fixed cutter block.
Referring now to
The drill string 104 includes several joints of drill pipe 104-1 connected end-to-end through tool joints 104-2. The drill string 104 may be used to insert or trip the BHA 105 into the wellbore 103. The drill string 104 may transmit drilling fluid (e.g., through a bore extending through hollow tubular members), transmit rotational power from the drilling rig 101 to the BHA 105, transmit weight to the BHA 105 (e.g., using weight of the drill string 104), move the BHA 105 axially within the wellbore, or combinations of the foregoing. In some embodiments, one or more of the drill string 104 or the BHA 105 further includes additional components such as subs, pup joints, valves, actuation assemblies, etc.
The BHA 105 in
Referring to
In the expanded position shown in
In one or more embodiments, optional depth of cut limiters 224 on pad 222 may be formed from polycrystalline diamond, tungsten carbide, titanium carbide, cubic boron nitride, other superhard materials, or some combination of the foregoing. Depth of cut limiters 224 may include inserts with cutting capacity, such as back-up cutting elements or cutters, diamond impregnated inserts with less exposure than primary cutting elements, diamond enhanced inserts, tungsten carbide inserts, semi-round top inserts, or other inserts that may or may not have a designated cutting capacity. Optionally, the depth of cut limiters 224 may not primarily engage formation during reaming; however, after wear of primary cutting elements, depth of cut limiters 224 may engage the formation to protect the primary cutting elements from increased loads as a result of worn primary cutting elements. In one or more embodiments, depth of cut limiters 224 may be positioned above or uphole from primary cutting elements on a shoulder of the cutter block 220. The axial and/or radial distance from the primary cutting elements may be selected such that depth of cut limiters 224 may remain largely unengaged with formation until wear of other cutting elements occurs, or the depth of cut limiters 224 may engage the formation initially, before wear of the cutting elements. Depth of cut limiters 224 may aid in maintaining a desired wellbore gauge by providing increased structural integrity to the cutter block 220.
Drilling fluid may flow along path 225, through ports 226 in a lower retainer 227, along path 228 into a piston chamber 229. A differential pressure between fluid in the flowbore 212 and the fluid in the wellbore annulus 223 surrounding the underreamer 210 may cause the piston 230 to move axially upwardly from the position shown in
The underreamer 210 may be designed to remain generally concentric within a wellbore. In particular, the underreamer 210, in some embodiments, may include three extendable cutter blocks 220 spaced apart circumferentially at the same axial location on the tool body 211. In some embodiments, the circumferential spacing may be approximately 120°. A three-block design may provide a full gauge underreamer 210 that remains centralized in the wellbore. Embodiments disclosed herein are not limited to tool embodiments having three extendable cutter blocks 220. For example, in one or more embodiments, the underreamer 210 may include different configurations of spaced cutter blocks (e.g., spaced axially, circumferentially, or both), or other types of arms, for example, one arm, two arms, four arms, five arms, or more than five arm designs. Thus, in some embodiments, the circumferential spacing of the cutter blocks or other arms may vary from the 120° spacing described herein. For example, in other embodiments, the circumferential spacing may be 90°, 60°, or the cutter blocks 220 may be circumferentially spaced in unequal increments. Further, in some embodiments, one or more of the cutter blocks 220 may be axially offset from one or more other cutter blocks 220. Accordingly, the cutting structure designs disclosed herein may be used with any number of cutting structures and tools.
The body 337 of the cutter block 320 may further include or define a formation facing surface 341 arranged to abut, engage, or be positioned against or toward the formation within a wellbore. The cutter block 320 may be rotated in the wellbore, and the body 337 may define a leading side surface 342 facing the direction of rotation, and a trailing side surface 343 facing away from the direction of rotation. The formation facing surface 341 may generally extend laterally between the leading and trailing side surfaces 342, 343 and longitudinally in the direction of the longitudinal axis 338. A bottom surface 344 may also extend laterally between the leading and trailing side surfaces 342, 343 and longitudinally in the direction of the longitudinal axis 338, but may face away from the formation. Optionally, the bottom face 344 may be planar. In other embodiments, the bottom face 344 may be curved, have an arc, have some contour, or some combination of the foregoing.
In some embodiments, one or more splines or channels (collectively designated splines 345) may be formed on the leading side surface 342, the trailing side surface 343, or both, and used in selectively expanding or retracting the cutter block 320. For instance, the splines 345 may engage corresponding splines of a reamer body (e.g., splines 233 in
In one or more embodiments, the body 337 may be formed from a metal material, a matrix material, other materials, or a combination of the foregoing. For instance, the body 337 may be formed of or include steel, tungsten carbide, titanium carbide, or any other material known in the art. The cutter block 320 may be configured to be coupled to a downhole tool (e.g., the underreamer 230 shown in
As shown, the cutting elements 335 coupled to the body 337 (e.g., within the downhole portion 339, the uphole portion 340, or both) may be arranged in one or more rows. In the example illustrated embodiment, for instance, a single row of cutting elements 335 is shown as extending along the leading face 342 in both the downhole portion 339 and the uphole portion 340 of the cutter block 320. In some embodiments, the row may be continuous along a full length of the row, along the downhole portion 339, along the uphole portion 340, or any combination of the forgoing. In
In some embodiments, and as clearly shown in
Optionally, one or more additional or other stabilizer pads may be included on the cutter block 320. For instance, an additional stabilizer pad may be located downhole of the first underreamer portion 347-1. In some embodiments, such a stabilizer pad may have a relatively constant radial position similar to stabilizer pads 322-1, 322-2, although in other embodiments the stabilizer pad downhole of the first reaming portion 347-1 may be inclined (e.g., angled inwardly and downwardly). In some embodiments, a stabilizer pad may be located at a gauge portion of the cutter block 320 (e.g., at a transition between the downhole end portion 339 and the uphole end portion 340). In at least some embodiments, the length of a stabilizer pad at a gauge portion of the cutter block 320 may be less than the length of the stabilizer pad 322-1, the stabilizer pad 322-2, other stabilizer pads on the cutter block 320, or any combination of the foregoing. In still other embodiments, the length of a stabilizer pad in the gauge portion of the cutter block 320 may be the same length as, or longer than, the length of the stabilizer pad 322-1, the stabilizer pad 322-2, other stabilizer pads on the cutter block 320, or any combination of the foregoing. In still other embodiments, additional or other stabilizer pads may be located within the uphole end portion 340, in other locations, or at other locations.
In accordance with some embodiments of the present disclosure, the cutter block 320 may be used in an expandable tool such as an underreamer or other downhole tool. In at least one embodiment, the expandable tool may be tripped into a wellbore while the cutter block 320 (or multiple cutter blocks 320) are in a retracted state. In the retracted state, the formation facing surface 341 of the cutter block 320 may be radially within a body of the expandable tool, or slightly radially outward of the body of the expandable tool. For instance, the radially position of the facing surface 341 may be less than or about equal to the pilot diameter of the wellbore (e.g., the pilot diameter of a bit used to form the wellbore). Upon reaching a desired location within the wellbore, the expandable tool may be activated and the cutter block 320 may be fully or partially expanded and the downhole tool may be rotated to cut or otherwise degrade the formation or other workpiece around the wellbore. In at least some embodiments, the cutter block 320 may have a staged construction. In the expanded state, the formation facing surface 341 may be expanded beyond the pilot diameter of the wellbore.
According to some embodiments, at least a portion of the formation facing surface 341 may be within or about equal to the pilot diameter of the wellbore. For instance, when the cutter block 320 is expanded, the underreaming portion 347-1 may be configured to remain within the pilot diameter of the wellbore. Cutting elements 335, 350 on the underreaming portion 347-1 may therefore not be arranged, designed, or otherwise configured for use in expanding the wellbore beyond the pilot diameter. Rather, such cutting elements 335, 350 may be used to clean irregularities within the pilot wellbore (e.g., as a result of swelling or shifting). Such an operation may reduce erratic loading on leading cutting elements 335, increase wellbore quality and consistency, improve stability of the expandable tool, contribute to other factors, or any combination of the foregoing. In some embodiments, the first stabilizer pad 322-1 may be configured to be at the pilot diameter of the wellbore when the cutter block 320 is expanded (e.g., fully expanded). Thus, in a BHA that includes a drill bit and an expandable tool, the stabilizer pad 322-1 (or optionally another stabilizer pad) may have about the same radial position as the gauge of the drill bit.
The cutting elements 335 are shown as optionally being oriented along the leading side surface 342 of the cutter block 320, and about parallel to the longitudinal axis 338; however, in other embodiments, the cutting elements 335 may be otherwise configured. For instance, the cutting elements 335 may in whole or in part be oriented in angled rows across a width of the cutter block 320, in a helical pattern, in other manners, or in a combination of the foregoing. In some embodiments, cutting elements 335 may be leading cutting elements, and additional cutting elements 335 may be trailing cutting elements 335 located laterally in one or more rows or positions nearer the trailing side surface 343. Trailing cutting elements 335 may be of the same type as the cutting elements 335 (e.g., shear or planar cutting elements), or they may be different.
In
As shown by the dotted lines in
The trailing cutting elements 350 may be arranged in any suitable manner on the cutter block 320, and in some embodiments are positioned in one or more rows in the formation facing surface 341 of the cutter block 320. Any rows of trailing cutting elements 350 may be about parallel to rows of leading cutting elements 335, although in other embodiments, rows of trailing cutting elements 350 may not be parallel to the leading cutting elements 335. For instance, one or more of the trailing cutting elements in
The formation facing surface 341 of the cutter block 320 may have a constant or variable width (i.e., distance between leading and trailing side surfaces 341, 342). In other embodiments, such as that shown in
The splines 345 may extend a full or partial height of the cutter block. In at least some embodiments, a spline 345 may terminate adjacent a stabilizer pad 322. When such a spline 345 also extends to or near the radial position of a stabilizer pad 322, the spline 322 may intersect the formation facing surface 341. In such embodiments, the splines 345 may form an extension 353 on the stabilizer pad 322. The extensions 353 may extend laterally and may rotationally lead the cutting elements 335, 350 when at or near the leading side surface 342, or may rotationally follow the cutting elements 335, 350 when at or near the trailing side surface 343. An extension 353 to the stabilizer pad 322 that leads cutting elements 335 can, in some embodiments, reduce an amount by which the cutting elements 335 dig into the side of a wellbore wall, thereby acting as a horizontal depth of cut limiter and improving stability. In the same or other embodiments, the extensions 353 can increase a percentage of a wellbore wall that is in contact with the cutter block 320, without a corresponding change to a nominal width of the cutter block 320 (and without a change to openings for mating splines in a tool body), which can further increase stability of a tool.
Stabilizer pads 322 of the present disclosure optionally include one or more gauge protection elements 354. The gauge protection elements 354 may be arranged, designed, or otherwise configured to restrict or even prevent wear of the body 337 and the formation facing surface 341 on the stabilizer pad 322. For instance, as the cutter block 320 is used to cut or degrade formation in a wellbore, the formation may contact the gauge protection elements 354. The gauge protection elements 354 may be formed from polycrystalline diamond, tungsten carbide, titanium carbide, cubic boron nitride, other superhard materials, or some combination of the foregoing. In some embodiments, the gauge protection elements 354 have higher wear resistance properties than the materials of the body 337 (e.g., steel). The gauge protection elements 354 may include diamond enhanced inserts, diamond impregnated inserts, tungsten carbide inserts, semi-round top inserts, inserts with cutting capacity, other inserts or elements, hardfacing, or combinations of the foregoing. For instance, the gauge protection elements 354 may include tungsten carbide inserts.
The gauge protection elements 354 may be arranged in any suitable arrangement or pattern. In
Cutter blocks, arms, or other elements of a tool may be arranged, designed, or otherwise configured in any number of manners. For instance, the types of cutting elements, arrangements of cutting elements, materials for cutting elements, and the like may be changed from one design to another, varied within a single design or tool, or otherwise varied. In some embodiments, one or more cutter blocks, arms, or other elements may be different from one or more other cutter blocks, arms, or other elements (or each may be different). For instance, each cutter block 320 for a downhole tool may have a different arrangement of: cutting elements 335, 350 (e.g., different positions or numbers of cutting elements to allow multiple cutter blocks to form, in aggregate, a continuous cutting profile with suitable axial overlaps, radial overlaps, etc.); stabilizer pads (e.g., width, axial position, gauge protection element layout, etc.); reaming portions (e.g., number, position, profile, or type of reaming portions); other characteristics, or combinations of the foregoing.
Each cutting element 435, 450 may have the same exposure, or each cutting element 435, 450 may have no exposure. In other embodiments, the exposure may be varied such that one or more cutting elements 435, 450 have a different exposure from one or more other cutting elements 435, 450. In
Optionally, the exposure 455 of the leading cutting elements 435 may gradually change. In
Optionally, the exposure 455 may gradually increase when moving axially away from the uphole end portion 440. In such an embodiment, the exposure 455 of a leading cutting element 435 may be greater than the exposure 455 of an adjacent leading cutting element 435 that is axially nearer the uphole end portion 440. In other embodiments, the exposure 455 may gradually or otherwise decrease when moving axially away from the uphole end portion 440. In still other embodiments, adjacent leading cutting elements 435 may have the same exposure. Optionally, the leading cutting elements 435 with a higher depth of cut (and higher volume of material removed) may have higher exposure 455, and leading cutting elements 435 with lower depth of cut and lower removal volume may have a lower depth of cut. For instance, leading cutting elements 435 nearer the uphole end portion 440 and at a greater radial position may have a lower depth of cut and a lower removal volume, while leading cutting elements 435 farther from the uphole end portion 440 and at a lesser radial position may have a greater depth of cut and a greater removal volume. In at least some embodiments, leading cutting elements 435 near the uphole end portion 440 or at greater radial positions may be protected against increased impact damage from high lateral vibrations by reducing the exposure 455 of such leading cutting elements 435. Reduced exposure 455 at greater radial positions, gradual changes to exposure 455, or combinations thereof, may allow vibrations to be distributed across the body of the cutter block 420. In some embodiments, a variable exposure may further reduce stick-slip tendencies, whirl tendencies, or both, that could result from a side cutting element taking a sudden high depth of cut due to lateral vibrations, which could result in an eccentric pivot point.
In some embodiments, the cutting elements 435, 450 of the cutter block 420 may have multiple exposure gradients or variations. For instance, the cutter block 420 may have multiple tiers or stages of reaming portions (e.g., reaming portions 347-1, 347-2, 347-3 and uphole end portion 340). One or more of these reaming portions may have a gradient. For instance, uphole end portion 340 may have an exposure gradient, the second reaming portion 347-2 may start or have a different exposure gradient, the third reaming portion 347-2 may have another exposure gradient, the first reaming portion 347-1 may also have another exposure gradient when including multiple cutting elements 325 or cutting elements 350, or a combination of the foregoing. Each exposure gradient may gradually change from left-to-right or right-to-left in the view shown in
The amount each leading cutting element 435 is exposed may be different in various embodiments, and may be based on a number of factors, including the type or shape of the leading cutting elements 435, the type and shape of the cutter block 420, the type of formation or other material to be cut by the cutter block 420, the amount of vibration anticipated in a downhole operation, the rate of penetration that is desired, other factors, or combinations of the foregoing. For instance, in some embodiments, the exposure 455 of each leading cutting element 435 (and potentially between different leading cutting elements 435 in embodiments with a variable exposure 455) may be within a range having lower limits, upper limits, or both lower and upper limits including any of 0.000 in. (0.0 mm), 0.005 in. (0.1 mm), 0.01 in. (0.3 mm), 0.025 in. (0.6 mm), 0.05 in. (1.3 mm), 0.075 in. (1.9 mm), 0.1 in. (2.5 mm), 0.125 in. (3.2 mm), 0.15 in. (3.8 mm), 0.175 in. (4.4 mm), 0.2 in. (5.1 mm), 0.225 in. (5.7 mm), 0.25 in. (6.4 mm), 0.275 in. (7.0 mm), 0.3 in. (7.6 mm), 0.4 in. (10.2 mm), 0.5 in. (12.7 mm), or values therebetween. For instance, the exposure 455 of the leading cutting elements 435 of the downhole end portion 439 may be between 0.000 in. (0.0 mm) and 0.4 in. (10.2 mm), between 0.005 in. (0.1 mm) and 0.25 in. (6.4 mm), or between 0.005 in. (0.1 mm) and 0.2 in. (5.1 mm). In other embodiments, the exposure 455 may be negative or may be greater than 0.5 in. (12.7 mm).
Varying the exposure 455 of leading cutting elements 435 may be used where the downhole end portion 439 is an underreaming portion or a backreaming portion. A variable exposure 455 may therefore be present on an underreaming portion, on a backreaming portion, or on both an underreaming portion and a backreaming portion. Additionally, the trailing cutting elements 450 may have a constant exposure 455 or a variable exposure 455. For instance, trailing cutting elements 450 may have the same gradient or changes in exposure 455 as leading cutting elements 435. In some embodiments, the trailing cutting elements 450 are in a back-up position directly behind a leading cutting element 435, or in another trailing position (e.g., when axially offset from leading cutting elements 435, on a second blade on the cutter block 420, etc.).
The trailing cutting element 550 may have the same exposure as the corresponding leading cutting element 535. In other embodiments, however, the leading and trailing cutting elements 535 may have different exposures relative to a formation facing surface 541. For instance, in
The cutter block 520 may have multiple leading cutting elements 535, multiple trailing cutting elements 550, or combinations of the foregoing. The leading cutting elements 535, trailing cutting elements 550, or both, may have a variable exposure as described herein. In some embodiments, for instance, the leading cutting elements 535 and the trailing cutting elements 550 may have a variable exposure. In other embodiments, the leading cutting elements 535 may have a variable exposure while the trailing cutting elements 550 each have the same exposure (i.e., a fixed or constant exposure). In still other embodiments, each of the leading cutting elements 535 may have the same, fixed or constant exposure while the trailing cutting elements 550 have a variable exposure. In still other embodiments, one or more leading cutting elements 535 may have a different exposure than other leading cutting elements 535 having the same exposure as each other. Similarly, one or more trailing cutting elements 550 may have a different exposure than other trailing cutting elements 550 having the same exposure as each other.
The term “cutting element” as used herein generically refers to any type of cutting element, unless otherwise specified. Cutting elements may have a variety of configurations, and in some embodiments may have a planar cutting face (e.g., similar to cutting elements 535 of
As used herein, the term “conical cutting elements” refers to cutting elements having a generally conical cutting end 660 (including either right cones or oblique cones), i.e., a conical side wall 661 that terminates in a rounded apex 662, as shown in the cutting element 635 of
The term “ridge cutting element” refers to a cutting element that has a cutting crest (e.g., a ridge or apex) extending a height above a substrate (e.g., cylindrical substrate 964 of
Orientations of planar cutting elements (or shear cutting elements) on an underreamer may be referenced using terms such as “side rake” and “back rake.” While non-planar cutting elements may be described as having a back rake and side rake in a similar manner as planar cutting elements, non-planar cutting elements may not have a cutting face or may be oriented differently (e.g., out from a formation facing surface rather than toward a leading edge), and thus the orientation of non-planar cutting elements should be defined differently. When considering the orientation of non-planar cutting elements, in addition to the vertical or lateral orientation of the cutting element body, the non-planar geometry of the cutting end also affects how and the angle at which the non-planar cutting element strikes the formation. Specifically, in addition to the back rake affecting the aggressiveness of the interaction of the non-planar cutting element with the formation, the cutting end geometry (specifically, the apex angle and radius of curvature) may greatly affect the aggressiveness that a non-planar cutting element attacks the formation. In the context of a pointed cutting element, as shown in
In addition to the orientation of the axis with respect to the formation, the aggressiveness of pointed or other non-planar cutting elements may also be dependent on the apex angle or specifically, the angle between the formation and the leading portion of the non-planar cutting element. Because of the cutting end shape of the non-planar cutting elements, there does not exist a leading edge as found in a planar/shear cutting element; however, the leading line of a non-planar cutting surface may be determined to be the first points of the non-planar cutting element at each axial point along the non-planar cutting end surface as the attached body (e.g., body of an underreamer cutter block) rotates around a tool axis. Said in another way, a cross-section may be taken of a non-planar cutting element along a plane in the direction of the rotation of the tool, as shown in
For polycrystalline diamond compact cutting elements (e.g., shear cutters), side rake is conventionally defined as the angle between the cutting face and the radial plane of the downhole tool (x-z plane). Non-planar cutting elements do not have a planar cutting face and thus the orientation of pointed cutting elements should be defined differently. In the context of a non-planar cutting element such as the pointed cutting elements 1335, shown in
As shown in
It should be understood that while elements are described herein in relation to depicted embodiments, each element may be combined with other elements of other embodiments. For example, any or each of the planar cutting elements 335 of
While embodiments of underreamers and cutter blocks have been primarily described with reference to wellbore enlargement operations, the devices described herein may be used in applications other than the drilling or enlargement of a wellbore. In other embodiments, underreamers and cutter blocks according to the present disclosure may be used outside a wellbore or other downhole environment used for the exploration or production of natural resources. For instance, tools and assemblies of the present disclosure may be used in a wellbore used for placement of utility lines, in a medical procedure (e.g., to clear blockages within an artery), in a manufacturing industry (e.g., to expand a diameter of a bore within a component), or in other industries (e.g., aquatic, automotive, etc.). Accordingly, the terms “wellbore,” “borehole” and the like should not be interpreted to limit tools, systems, assemblies, or methods of the present disclosure to any particular industry, field, or environment.
The articles “a,” “an,” and “the” are intended to mean that there are one or more of the elements in the preceding descriptions. The terms “comprising,” “including,” and “having” are intended to be inclusive and mean that there may be additional elements other than the listed elements. Additionally, it should be understood that references to “one embodiment” or “an embodiment” of the present disclosure are not intended to be interpreted as excluding the existence of additional embodiments that also incorporate the recited features. Numbers, percentages, ratios, or other values stated herein are intended to include that value, and also other values that are “about” or “approximately” the stated value, as would be appreciated by one of ordinary skill in the art encompassed by embodiments of the present disclosure. A stated value should therefore be interpreted broadly enough to encompass values that are at least close enough to the stated value to perform a desired function or achieve a desired result. The stated values include at least the variation to be expected in a suitable manufacturing or production process, and may include values that are within 5%, within 1%, within 0.1%, or within 0.01% of a stated value. Where a range of values includes various lower or upper limits, any two values may define the bounds of the range, or any single value may define an upper limit (e.g., up to 50%) or a lower limit (at least 50%).
A person having ordinary skill in the art should realize in view of the present disclosure that equivalent constructions do not depart from the spirit and scope of the present disclosure, and that various changes, substitutions, and alterations may be made to embodiments disclosed herein without departing from the spirit and scope of the present disclosure. Equivalent constructions, including functional “means-plus-function” clauses are intended to cover the structures described herein as performing the recited function, including both structural equivalents that operate in the same manner, and equivalent structures that provide the same function. It is the express intention of the applicant not to invoke means-plus-function or other functional claiming for any claim except for those in which the words ‘means for’ appear together with an associated function. Each addition, deletion, and modification to the embodiments that falls within the meaning and scope of the claims is to be embraced by the claims.
The terms “approximately,” “about,” and “substantially” as used herein represent an amount close to the stated amount that still performs a desired function or achieves a desired result. For example, the terms “approximately,” “about,” and “substantially” may refer to an amount that is within less than 5% of, within less than 1% of, within less than 0.1% of, and within less than 0.01% of a stated amount. Further, it should be understood that any directions or reference frames in the preceding description are merely relative directions or movements. For example, any references to “up” and “down” or “above” or “below” are merely descriptive of the relative position or movement of the related elements. It should be understood that “proximal,” “distal,” “uphole,” and “downhole” are relative directions. As used herein, “proximal” and “uphole” should be understood to refer to a direction toward the surface, rig, operator, or the like. “Distal” or “downhole” should be understood to refer to a direction away from the surface, rig, operator, or the like. When the word “may” is used herein, such term should be interpreted as meaning that the identified feature, function, characteristic, or the like is present in some embodiments, but is not present in other embodiments. Numerical terms such as “first,” “second,” “third,” “fourth,” and the like when used to identify certain components or features are used to distinguish similar components (or similarly referenced components) and are not used to limit any component to a specific embodiment or numerical reference. For instance, a component referred to as a “first” component in the claims may refer to or include a “first,” “second,” “third,” “fourth,” or other component from the specification, based on the context in the claim.
The present disclosure may be embodied in other specific forms without departing from its spirit or characteristics. The described embodiments are to be considered as illustrative and not restrictive. The scope of the disclosure is, therefore, indicated by the appended claims rather than by the foregoing description. Changes that come within the meaning and range of equivalency of the claims are to be embraced within their scope.
This application is a U.S. national phase of International Patent Application No. PCT/US2017/014005, filed Jan. 19, 2017, and entitled “Staged Underreamer Cutter Block,” which claims the benefit of, and priority to, U.S. Patent Application No. 62/288,214, filed Jan. 28, 2016, which applications are expressly incorporated herein by this reference in their entireties.
Filing Document | Filing Date | Country | Kind |
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PCT/US2017/014005 | 1/19/2017 | WO | 00 |
Publishing Document | Publishing Date | Country | Kind |
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WO2017/132033 | 8/3/2017 | WO | A |
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