Helical blade stabilizer with line-of-sight faces

A stabilizer for use in a wellbore may include a downhole tubular configured to couple to a downhole conveyance in a wellbore, as well as two or more helical blades extending radially outward from the downhole tubular. The two or more helical blades are oriented about the downhole tubular to form respective flow paths between adjacent blades. Further, each blade of the two or more helical blades may include a line-of-sight face and a gauge ramp. The line-of-sight face is formed adjacent a leading inner blade wall of the blade at a lower end of the blade and is angularly offset from the leading inner blade wall. The gauge ramp extends from an outer surface of the downhole tubular toward an outer blade surface of the blade proximate the lower end of the blade.

CROSS-REFERENCE TO RELATED APPLICATIONS

The present application is a non-provisional conversion of U.S. Provisional Application Ser. No. 63/186,729, filed May 10, 2021, which is herein incorporated by reference in its entirety.

BACKGROUND

In downhole drilling operations, wellbores are drilled into subterranean formations for the recovery of hydrocarbons. As a drill bit moves drills through the formation to form the wellbore, a drill string connecting the drill bit to the surface may contact the walls of the wellbore. Friction resulting from such contact may lead to vibration, stick-slip, and/or whirl of the drill string. As such, straight blade and/or spiral blade stabilizers may be used to reduce these effects by helping to centralize the drill string within the wellbore. Spiral blade stabilizers may be generally more effective than straight blade stabilizers at reducing vibrations and stresses in the drill string as they provide support along a greater portion of the circumference of the drill string (e.g., wrap angle). Unfortunately, spiral blade stabilizers are more likely to cause pressure losses in the wellbore such that cuttings may become trapped in the channels formed between the blades of the stabilizers. Pressure losses in the wellbore, stick-slip, and whirl of the drill string may hinder downhole drilling operations.

DETAILED DESCRIPTION

Disclosed herein are helical blade stabilizers having helical blades configured to reduce pressure losses, as well as stick slip and whirl of the drill string during drilling operations. The helical blades may include line-of-sight (e.g., cutout) faces configured to improve flow paths (e.g., flow areas) formed between the blades of the stabilizers while maintaining a high wrap angle to provide support along a greater portion of the circumference of the drill string. As set forth below the line-of-sight faces are positioned at leading and trailing ends of each helical blade. In some embodiments, the line-of-sight faces may provide for a line-of-sight through the flow paths along an axial direction of the stabilizer. Accordingly, having the line-of-sight faces may reduce pressure losses, as well as stick slip and whirl of the drill string during drilling operations. Further, the helical blades may include blade ramps (e.g., gauge ramps) at the downhole and uphole ends of each helical blade. The blade ramps may be configured to reduce an axial force needed to overcome friction and slide the stabilizer downhole during drilling operations. Accordingly, helical blades configured to reduce pressure losses, as well as stick slip and whirl of the drill string during drilling operations.

FIG.1illustrates a well system100including an exemplary operating environment where the apparatuses, systems, and methods disclosed herein may be employed. For example, the well system100could use a stabilizer122according to any of the embodiments, aspects, applications, variations, designs, etc. disclosed in the following paragraphs. As illustrated, the well system100includes a rig102extending over and around a wellbore104formed in a subterranean formation106. As those skilled in the art appreciate, the wellbore104may be fully cased, partially cased, or an open hole wellbore. In the illustrated embodiment, the wellbore104is partially cased, and thus includes a cased region108and an open hole region110. The cased region108, as is depicted, may employ casing112that is held into place by cement114.

The well system100additionally includes a downhole conveyance116deploying a downhole tool assembly118within the wellbore104. The downhole conveyance116may be, for example, tubing-conveyed, wireline, slickline, drill pipe, production tubing, work string, or any other suitable means for conveying the downhole tool assembly118into the wellbore104. In one embodiment, the downhole conveyance116may include American Petroleum Institute “API” pipe.

Moreover, as illustrated, the downhole tool assembly118includes a downhole tool120and a stabilizer122(e.g., a helical blade stabilizer). The downhole tool120may comprise any downhole tool that could be positioned within a wellbore. Certain downhole tools120that may find particular use in the well system100include, without limitation, drilling and logging tools, rotary steerable tools, instrumented logging systems, MLWD tools, mud motors and drill string stabilizers (e.g., collars with stabilizer blades), drill bits, bottom hole assemblies (BHAs), sealing packers, elastomeric sealing packers, non-elastomeric sealing packers (e.g., including plastics such as PEEK, metal packers such as inflatable metal packers, as well as other related packers), liners, an entire lower completion, one or more tubing strings, one or more screens, one or more production sleeves, or some combination thereof.

FIGS.2A and2Billustrate a side view and a cross-sectional view, respectively, of a helical blade stabilizer with line-of-sight faces, in accordance with some embodiments of the present disclosure. Referring toFIG.2A, the stabilizer122, in accordance with one embodiment of the disclosure, includes a downhole tubular200couplable to the downhole conveyance116(shown inFIG.1). Further, the stabilizer122includes two or more helical wellbore stabilizing elements (e.g., helical blades202) extending radially outward from the downhole tubular200. In some embodiments, the stabilizer122may have two, three, four, or more helical blades202. In the illustrated embodiment, the stabilizer122includes four helical blades202(e.g., a first blade204, a second blade206, a third blade208, and a fourth blade210) that each extend radially outward from the downhole tubular200.

The two or more helical blades202may be oriented about the downhole tubular200to form respective flow paths212between adjacent blades of the two or more blades202. For example, a first flow path214of the respective flow paths212may be formed between a leading face216of the first blade204and a trailing face218of the fourth blade210. In some embodiments, at least a portion of each of the respective flow paths212may have a direct axial flow path between the adjacent blades202along a blade length of the two or more helical blades202. Further, the respective flow paths212formed between leading faces216and trailing faces218of adjacent blades202may have variable widths along the blade length of the two or more helical blades202. For example, a lower width of the first flow path214proximate a downhole end224(e.g., lower end) of the first blade204may be larger than a middle width of the first flow path214proximate a middle portion228of the first blade204. Having variable widths of the flow paths212along the blade length may reduce pressure losses during drilling operations.

Moreover, having spiral or helical blades202may reduce drill string vibrations and stresses, as compared to straight blades, by reducing an amount of a circumference of the downhole tubular200that is unsupported by the two or more helical blades202. Specifically, straight blades are unsupported at the respective flow paths212formed between the adjacent straight blades as the blades do not wrap around the downhole tubular200to even partially support the downhole tubular200at the respective flow paths212. Gaps in support about the circumference of the stabilizer122may lead to vibrations and stresses. Thus, as illustrated, the two or more helical blades202are wrapped about the downhole tubular200to at least partially support the stabilizer122at the respective flow paths212; thereby, supporting about a larger percentage of the circumference of the stabilizer122than a straight blade stabilizer. However, helical blade stabilizers122generally increase pressure losses in the annulus, which may create other issues as a threshold pressure in the wellbore104may be required to move cuttings away from the two or more helical blades202. As such, pressure losses may trap cuttings, resulting in increased erosion of a drill string (e.g., the downhole conveyance116) and the stabilizer122. Accordingly, the present stabilizer122comprises at least one line-of-sight (LOS) face230to reduce pressure losses in the annulus while maintaining high wrap angle (e.g., discussed inFIG.2B) to provide support about the circumference of the stabilizer122.

The wrap angle is the total angular extent of full blade diameter, summed across all blades202of the stabilizer122. The wrap angle is calculated by summing, for all blades202, the angular distances (e.g., in degrees) between a leading downhole corner232of a blade and a trailing uphole corner234of the blade202. The leading downhole corner232may be a full-blade diameter portion of the blade202positioned furthest downhole at a leading edge236of the blade202. Similarly, the trailing uphole corner234may be a full-blade diameter portion of the blade positioned furthest uphole at a trailing edge238of the blade202. The leading downhole corner232and the trailing uphole corner234may not be positioned at a tapered portion of the blade as tapered portions are not full-blade diameter portions of the blade.

FIG.2Billustrates a cross-sectional view of the helical blade stabilizer122having the plurality of line-of-sight faces230such that the stabilizer122may have a high wrap angle without generating excessive pressure loss in the wellbore. As illustrated, the two or more helical blades202may be oriented about the downhole tubular200to form a wrap angle between 350-360 degrees. For example, the first blade204may wrap circumferentially about the downhole tubular200from 0-88 degrees. That is, the leading downhole corner232of the first blade204may be positioned at zero degrees and the trailing uphole corner234of the first blade204may be positioned at eighty-eight degrees. Further, the second blade206may wrap circumferentially about the stabilizer122from 90-178 degrees, the third blade208may wrap circumferentially about the stabilizer122from 180-268 degrees, and the fourth blade210may wrap circumferentially about the stabilizer122from 270-358 degrees, such that the two or more helical blades202may form a wrap angle of 352 degrees. Accordingly, each respective flow path212(e.g., the first flow path214, a second flow path240, a third flow path242, and a fourth flow path244) in this example has two degrees of clear line of sight along the longitudinal direction of the downhole tubular200.

FIG.3illustrates a detailed view of a helical blade stabilizer122comprising helical blades with respective line-of-sight faces230, in accordance with some embodiments of the present disclosure.

As illustrated, each blade of the two or more helical blades202may comprise a lower line-of-sight (LOS) face300formed adjacent a leading inner blade wall302of the blade202at the lower (e.g., downhole) end224of the blade202. Further, each blade of the two or more helical blades202may comprise an upper line-of-sight face304formed adjacent a trailing inner blade wall306of the blade at an upper (e.g., uphole) end308of the blade. As such, the lower LOS face300and the upper LOS face304may be formed on opposite sides of the blade202. Moreover, as illustrated, the line-of-sight faces230may be planar (e.g., flat). Further, the line-of-sight faces230may be angularly offset from corresponding inner blade walls302and306such that the line-of-sight faces230are more aligned with the longitudinal axis310of the downhole tubular than corresponding inner blade walls302and306. As such, the two or more helical blades202may form a high wrap angle (e.g., between 350-360 degrees) while still providing a clear line of sight for each respective flow path212.

As illustrated, the line-of-sight faces230each comprise a LOS surface390that extends radially outward from an outer surface312of the downhole tubular200toward a respective gauge surface314and gauge ramp316of the blade202. The line-of-sight faces230may extend directly outward in the radial direction. However, in some embodiments, the line-of-sight faces230may comprise a pitch angle between negative twenty to twenty degrees such that a radially inner portion318of the LOS faces230may be rotated about the circumference of the downhole tubular200with respect to a radially outer portion320of the LOS faces230. Moreover, with respect to the lower LOS face300, the lower LOS face300extends radially outward from a leading inner LOS edge322formed at an interface between the lower LOS face300and the outer surface312of the downhole tubular200proximate the leading inner blade wall302of the blade202. A portion of the lower LOS face300extends radially outward to a leading outer LOS edge324formed at an interface between the lower LOS face300and a lower gauge surface326. Another portion of the lower LOS face300extends radially outward to a lower ramp LOS edge328formed at an interface between the lower LOS face300and the lower gauge ramp330. In some embodiments, the lower ramp LOS edge328may intersect with a lower end332of the leading inner LOS edge322at the outer surface312of the downhole tubular200. Moreover, the lower LOS face300extends upward to a leading blade LOS edge334formed at an interface between the lower LOS face300and the leading inner blade wall302of the blade202.

Similarly, the upper LOS face extends radially outward from a trailing inner LOS edge336formed at an interface between the upper LOS face304and the outer surface312of the downhole tubular200proximate the trailing inner blade wall306. A portion of the upper LOS face304extends radially outward to a trailing outer LOS edge338formed at an interface between the upper LOS face304and the upper gauge surface340. Another portion of the upper LOS face304extends radially outward to an upper ramp LOS edge342formed at an interface between the upper LOS face304and the upper gauge ramp344. In some embodiments, the upper ramp LOS edge342may intersect with an upper end346of the trailing inner LOS edge336at the outer surface312of the downhole tubular200. Moreover, the upper LOS face304extends downward to a trailing blade LOS edge348formed at an interface between the upper LOS face304and the trailing inner blade wall306of the blade202.

As illustrated, the leading inner LOS edge322of the lower LOS face300may transition to a leading inner blade edge350at an upper end of the leading inner LOS edge352. Similarly, the trailing inner LOS edge336of the upper LOS face304may transition to a trailing inner blade edge354at a lower end of the upper inner LOS edge356. Moreover, in some embodiments, the inner LOS edges322,336may be aligned parallel to the longitudinal axis310of the stabilizer122. Alternatively, the inner LOS edges322,336may be offset from the longitudinal axis310by a LOS helix angle such that the inner LOS edges322,336wrap around a portion of the circumference of the downhole tubular. For example, a lower end of the leading inner LOS edge322may be rotated circumferentially about the downhole tubular200by a first LOS helix angle between −15.0 and 15.0 degrees. However, the first LOS helix angle may be less than a blade helix angle362of the leading inner blade edge350such that the leading inner LOS edge322of the lower LOS face300is oriented more axially downward than the leading inner blade edge350with respect to the longitudinal axis of the stabilizer122. The blade helix angle362may be greater than fifteen degrees. In the illustrated embodiment, the first LOS helix angle is about zero degrees and the blade helix angle362is about twenty degrees. Moreover, the LOS helix angle may be any suitable angle that maintains an adequate line of sight for the respective flow paths212along the longitudinal direction of the stabilizer122. In another example, the leading inner LOS edge322may be anchored at the lower end of the leading inner LOS edge322and the upper end of the leading inner LOS edge352may be rotated circumferentially by a second LOS helix angle between −15.0 and 15.0 degrees. Moreover, the first LOS helix angle and second LOS helix angle may be between −5.0 and 5.0 degrees, −3.0 and 3.0 degrees, or −1.0 and 1.0 degrees. Moreover, in the illustrated embodiment, the leading inner LOS edge322of the lower LOS face300is straight between the upper and lower ends of the leading inner LOS edge322. However, in some embodiments, the leading inner LOS edge322may be curved such that the lower LOS face300may be curved (e.g.,FIG.6).

Moreover, as set forth above, each blade of the two or more blades202may include at least one gauge ramp316(e.g., a lower gauge ramp330, an upper gauge ramp344) and at least one gauge surface314(e.g., a lower gauge surface326, an upper gauge surface340). The at least one gauge surface314is disposed between the corresponding at least one gauge ramp316and an outer blade surface364of the blade202. For example, the lower gauge ramp330may be positioned downhole from the lower gauge surface326such that the lower gauge surface326is disposed between the lower gauge ramp330and the outer blade surface364. Moreover, as illustrated, the at least one gauge surface314is coplanar with the outer blade surface364. However, in some embodiments, the at least one gauge surface314may comprise a gauge taper angle366. The gauge taper angle366may be between 25-35 degrees with respect to the outer blade surface364. Alternatively, the gauge taper angle366may be between 0-25 degrees with respect to the outer blade surface364. In the illustrated embodiment, the gauge taper angle366is about zero degrees.

The at least one gauge surface314transitions to the at least one gauge ramp316at an outer ramp edge368(e.g., a lower outer ramp edge370, an upper outer ramp edge372). An outer transition radius of the outer ramp edge368(e.g., from the at least one gauge ramp316to the at least one gauge surface314) is between 20-60% of the height of the blade. For example, the outer transition radius may be 0.3 inches (0.76 cm) for a blade height of 0.85 inches (2.16 cm), such that the outer transition radius from at least one gauge ramp316to the at least one gauge surface314is about 35% of the blade height of the blade202. In another example, the outer transition radius may be 0.06 inches (0.15 cm) for a blade height of 0.25 inches (0.64 cm) such that the outer transition radius from the at least one gauge ramp316to the at least one gauge surface314is about 24% of the height of the blade202. Moreover, at an opposite end of the at least gauge ramp316, the at least one gauge ramp316may transition to the outer surface312of the downhole tubular200at an inner ramp edge374(e.g., a lower inner ramp edge376, an upper inner ramp edge378). An inner transition radius of the at the inner ramp edge374(e.g., from the at least one gauge ramp316to the outer surface312of the downhole tubular200) is between 5-50% of the height of the blade. For example, the inner transition radius may be 0.06 inches (0.15 cm) for a blade height of 0.25 inches (0.64 cm) such that the inner transition radius from the at least one gauge ramp316to the outer surface312of the downhole tubular200is about 24% of the blade height of the blade202.

The at least one gauge ramp316may comprise a tapered or curved surface that extends axially from the inner ramp edge374to the outer ramp edge368proximate the at least one gauge surface314. As set forth above, each blade comprises at least one gauge ramp316. For example, in the illustrated embodiment, the first gauge ramp of the first blade204extends from the lower inner ramp edge376toward the lower outer ramp edge370proximate the downhole end224of the first blade204, and the second gauge ramp of the first blade204extends from the upper inner ramp edge378toward the upper outer ramp edge372proximate the upper end308of the first blade204. A ramp taper angle380of the at least one gauge ramp316may be constant along the at least one gauge ramp316. The ramp taper angle380may be between 25-35 degrees. Alternatively, the ramp taper angle380may be between 15-60 degrees. In some embodiments, the ramp taper angle380may vary along the at least one gauge ramp316. For example, a first ramp portion of the at least one gauge ramp316disposed proximate the outer surface312of the downhole tubular200may have a first taper angle (e.g., a 45-degree angle) and a second ramp portion of the at least one gauge ramp316disposed proximate the at least one gauge surface314may have a second taper angle (e.g., a 30-degree angle). In another embodiment, any combination of a taper or curved surface, either convex or concave, could be used to facilitate the transition from the body radius to the maximum gauge ramp radius. Moreover, the ramp taper angle380may vary between the upper gauge ramp344and the lower gauge ramp330.

A ramp width382of the at least one gauge ramp316may be greater than 1.2 inches (3.05 cm) and less than 3.2 inches (8.13 cm). The ramp width382may be scaled based at least in part on an outer diameter of the stabilizer122as well as a number of blades202on the stabilizer122. For example, the ramp width382may be smaller for a stabilizer having four blades than for another stabilizer having three blades. Further, the ramp width382may be smaller for a stabilizer122with an 8.25-inch outer diameter than for another stabilizer with a 12.00-inch outer diameter. Generally, the ramp width382of the gauge ramp is between 10-27% of the blade diameter of the two or more helical blades202(e.g., the outer diameter of the stabilizer). Moreover, in some embodiments, the ramp width382may be greater than a minimum contact width384of the at least one gauge surface314. Moreover, the blade height (e.g., a distance that the outer blade surface is offset from the outer surface312of the downhole tubular200in the radial direction) may be between 0.25-1.0 inches (0.64-2.54 cm). However, in some embodiments, the blade height may be up to 12.0 inches (30.48 cm) or more.

FIG.4illustrates a perspective view of a lower end of a helical blade having a lower line-of-sight (LOS) face, in accordance with some embodiments of the present disclosure. As set forth above, the lower LOS face300may extend radially outward from the outer surface312of the downhole tubular200toward the lower gauge surface326and the lower gauge ramp330of the blade202. Specifically, a portion of the lower LOS face300extends radially outward to the leading outer LOS edge324formed at the interface between the lower LOS face300and the lower gauge surface326, and another portion of the lower LOS face300extends radially outward to the lower ramp LOS edge328formed at the interface between the lower LOS face300and the lower gauge ramp330. Although the downhole end224of the blade202is primarily described herein with respect toFIG.4, similar features may be included for the upper end of the blade202.

The leading outer LOS edge324and/or the lower ramp LOS edge328may comprise a rounded edge surface. The rounded edge surface may comprise a LOS radius between 0.13-0.38 inches (0.33-0.97 cm). In some embodiments, the rounded edge surface may comprise a LOS radius between 0.05-0.75 inches (0.13-1.91 cm). Alternatively, the rounded edge surface may be defined by a radius between 0.25-0.5 inches (0.64-1.27 cm). Further, in some embodiments, the rounded edge surface of the leading outer LOS edge324and/or the lower ramp LOS edge328may comprise a 20 degree to 50 degree chamfer. However, in some embodiments, the rounded edge surface of the leading outer LOS edge324and/or the lower ramp LOS edge328may include any suitable splined surface, chamfer, partially arced surface, or non-straight edged surface. The rounded edge surface may reduce vibration, whirl, or other issues that may be caused by the stabilizer during drilling operations. Indeed, the rounded edge surface may reduce occurrences of the stabilizer catching on portions of the wellbore wall. Further, the rounded edge surface may reduce wear to other drilling equipment during handling.

Moreover, the lower gauge surface326may comprise a minimum contact length386and a minimum contact width384. The minimum contact length386may be defined as a length of the leading outer LOS edge324formed at the interface between the lower LOS face300and the lower gauge surface326. The minimum contact length386may be between 0.2-1.5 inches (0.51-3.81 cm). Further, the minimum contact width384may be defined as a distance between the leading outer LOS edge324and an opposite edge388of the lower gauge surface326. The minimum contact width384may be measured along the lower outer ramp edge370. The minimum contact width384may be between 0.5-3.0 inches (1.27-7.62 cm). Further, the minimum contact width384may be greater than 30% of a blade width of the blade202. The blade width may be measured at an axially center portion of the blade202.

Moreover, in contrast to traditional helical wellbore stabilizers having point loads, the leading outer LOS edge324may define a longitudinal load line for the leading outer blade edge400of the blade202during drilling operations. The longitudinal load line may create a distributed load area on the leading outer LOS edge324. Indeed, a contact pressure on the leading outer blade edge400of the blade may be based at least in part on the shape of the leading outer blade edge400of the blade. The ranges set forth above for the lower LOS face300, the lower gauge ramp330, the lower gauge surface326, and/or the leading outer LOS edge324may be configured to minimize contact pressure on the blade202to reduce wear on the stabilizer122, as well as reduce vibrations, whirl, and/or other issues that may be caused by the stabilizer122during drilling operations.

FIG.5illustrates a cutaway view of rig tongs500engaging the helical blade stabilizer122via the line-of-sight faces230of the helical blades202, in accordance with some embodiments of the present disclosure. As set forth above, having helical blades202with LOS faces may provide a high wrap angle, as well as flow paths212(e.g., unobstructed axial flow paths) between adjacent blades202along the length of the helical blades202. The flow paths212may reduce pressure losses such that there is sufficient clearance for flow and cuttings, and the high wrap angle may ensure that the stabilizer122provides the drill string (e.g., the downhole conveyance116) with support in all rotational positions. Additionally, the present stabilizer122addresses complications associated with traditional spiral stabilizers. Generally, stabilizers with high wrap angles may be difficult to install and or replace at the rig site as there is not a convenient location for the rig tongs500to grasp the spiral stabilizer. The rig tongs500may not be used on the stabilizer blades themselves as the blades are typically coated with a hard-wearing material such as coatings consisting of tungsten carbide, polycrystalline diamond compacts (PDC), and/or thermally stable polycrystalline (TSP) diamond, or some combination thereof, and engaging these traditionally spiral blades surfaces with the rig tongs500may damage a coating on the blades and/or slip during rotation. However, the present LOS faces230may provide a suitable surface for the rig tongs500to engage, turn, and torque the stabilizer122.

FIG.6illustrates a perspective view of a helical blade stabilizer122with a radially curved line-of-sight face, in accordance with some embodiments of the present disclosure. As illustrated, the LOS face230may comprise a curved profile. In particular, the LOS face230may be curved along a radial direction with respect to the downhole tubular200. In the illustrated embodiment, the curved profile of the lower LOS face300is concave. However, in some embodiment, the curved profile may be convex. The curved profile is configured to reduce stress concentrations on the blade and provide for ease of manufacturability. The radius of the curved profile may be dependent on the blade geometry (gauge size, bypass, etc.) of the two or more helical blades202, thus the present disclosure should not be limited in any way.

Moreover, as set forth above, the leading outer LOS edge324may be curved to reduce vibrations and reduce stabilizer damage due to the borehole/blade interaction that would occur if the edge was square. As illustrated, the leading outer LOS edge324may be convex with a radius between 0.05-0.75 inches (0.13-1.91 cm). However, the leading outer LOS edge324may include any suitable splined surface, chamfer, partially arced surface, or non-straight edged surface for reducing vibration, whirl, or other issues that may be caused by the stabilizer122during drilling operations.

FIG.7illustrates a side view of a helical blade stabilizer122with longitudinally curved line-of-sight faces, in accordance with some embodiments of the present disclosure. In particular, the LOS faces230may be curved along the longitudinal axis310of the downhole tubular200. In particular the leading inner LOS edge322may be curved along the longitudinal axis310such that the leading inner LOS edge322may wrap about the downhole tubular200. In the illustrated embodiment, the leading inner LOS edge322is curved to wrap about the downhole tubular200in a trailing direction700. Alternatively, the leading inner LOS edge322may be curved to wrap about the downhole tubular200in a leading direction702. Similarly, the trailing inner LOS edge336is curved to wrap about the downhole tubular200in the leading direction702but may alternatively be curved to wrap about the downhole tubular200in the trailing direction700. Further, in the illustrated embodiment, the lower LOS face300and the upper LOS face304are convex. However, in some embodiments, the lower LOS face300and the upper LOS face304may be concave or some combination thereof. As set forth above, the curved profiles of the lower LOS face300and the upper LOS face304may configured to reduce stress concentrations on the blade202and provide for ease of manufacturability. The radius of the curved profile may be dependent on the blade geometry (gauge size, bypass, etc.) of the two or more helical blades202, thus the present disclosure should not be limited in any way.

Moreover, the helical blade stabilizers122may be manufactured using any suitable manufacturing techniques. For example, additive manufacturing methods to directly generate or print the blades202onto the downhole tubular200. Alternatively, manufacturing techniques such as machining, flow forming, die extrusions, etc. can be used to manufacture the helical blade stabilizer122. Further, the blade shapes may be prone to erosion so coatings such as those containing hard materials like tungsten carbide may be applied using methods like high velocity oxyacetylene spray, thermal spray, laser cladding, PTA and standard torch welding methods. The exact coating would be dependent on the substrate, blade shape, and available materials/processes.

Although stabilizers have been predominantly mentioned here in this disclosure, the stabilizer features could also be applied to reamers as well. Reamers are used to enlarge bore holes and these features could be used in those applications as well to facilitate debris removal. Similarly, it should be noted that the term stabilizer as used herein is intended to encompass all types of stabilizers and centralizers as might be used in an oil/gas wellbore. 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.

Accordingly, the present disclosure may provide a helical blade stabilizer having line of sight faces, gauge ramps, and a gauge surfaces configured to reduce pressure losses in the wellbore, as well as reduce vibrations, stick-slip, and whirl during drilling operations. The systems may include any of the various features disclosed herein, including one or more of the following statements.

Statement 1. A stabilizer for use in a wellbore, comprising: a downhole tubular configured to couple to a downhole conveyance in a wellbore; and two or more helical blades extending radially outward from the downhole tubular, wherein the two or more helical blades are oriented about the downhole tubular to form respective flow paths between adjacent blades, and wherein each blade of the two or more helical blades comprises: a line-of-sight face formed adjacent a leading inner blade wall of the blade at a lower end of the blade, wherein the line-of-sight face is angularly offset from the leading inner blade wall; and a gauge ramp extending from an outer surface of the downhole tubular toward an outer blade surface of the blade proximate the lower end of the blade.

Statement 2. The stabilizer of statement 1, wherein the line-of-sight face is oriented at a first helix angle with respect to a longitudinal axis of the downhole tubular, wherein the first helix angle is less than a blade helix angle of the leading inner blade wall such that the line-of-sight face is oriented more angularly downward than the inner blade wall with respect to a longitudinal axis of the downhole tubular.

Statement 3. The stabilizer of statement 1 or statement 2, wherein the first helix angle is between −15 and 15 degrees, and wherein the blade helix angle is greater than 15 degrees.

Statement 4. The stabilizer of any preceding statement, wherein the two or more helical blades are oriented about the downhole tubular to form a wrap angle between 350 degrees to 360 degrees.

Statement 5. The stabilizer of any preceding statement, wherein the two or more helical blades comprises a first blade, a second blade, a third blade, and a fourth blade.

Statement 6. The stabilizer of any preceding statement, wherein the gauge ramp comprises a ramp taper angle between 25 degrees and 35 degrees.

Statement 7. The stabilizer of any preceding statement, wherein a ramp width of the gauge ramp is between 10% to 27% of a blade diameter of the two or more helical blades.

Statement 8. The stabilizer of any preceding statement, further comprising a gauge surface disposed between the gauge ramp and the outer blade surface of the respective helical blade proximate the lower end.

Statement 9. The stabilizer of any preceding statement, wherein the gauge surface comprises a minimum contact length defined as a minimum length of an outer line-of-sight (LOS) edge formed at an interface between the line-of-sight face and the gauge surface, and wherein the minimum contact length is between 0.2 inches to 1.5 inches.

Statement 10. The stabilizer of any preceding statement, wherein the gauge surface comprises a minimum contact width defined as a minimum distance between a line-of-sight (LOS) edge, formed at an interface between the line-of-sight face and the gauge surface, and an opposite edge of the gauge surface, wherein the minimum contact width is between 0.5 inches to 3.0 inches.

Statement 11. The stabilizer of any preceding statement, wherein an outer line-of-sight (LOS) edge, formed at an interface between the line-of-sight face and the gauge surface, comprises a LOS radius between 0.13 inches to 0.38 inches.

Statement 12. The stabilizer of any of statements 1-10, wherein an outer line-of-sight (LOS) edge, formed at an interface between the line-of-sight face and the gauge surface, comprises a 20 degree to 50 degree chamfer.

Statement 13. The stabilizer of any preceding statement, wherein the gauge surface comprises a gauge taper angle between 25 degrees to 35 degrees with respect to the outer blade surface.

Statement 14. The stabilizer of any preceding statement, wherein the respective flow paths each comprise an unobstructed axial flow path between adjacent blades of the two or more helical blades and along longitudinal lengths of the two or more helical blades.

Statement 15. The stabilizer of any preceding statement, wherein the line-of-sight face is planar.

Statement 16. A stabilizer for use in a wellbore, comprising: a downhole tubular configured to couple to a downhole conveyance in a wellbore; and two or more helical blades extending radially outward from the downhole tubular, wherein the two or more helical blades are oriented about the downhole tubular to form respective flow paths between adjacent blades and to form a wrap angle between 350 degrees to 360 degrees, and wherein each blade of the two or more helical blades comprises: a curved line-of-sight face formed adjacent a leading inner blade wall of the blade at a lower end of the blade, wherein the curved line-of-sight face is angularly offset from the leading inner blade wall; and a gauge ramp extending from an outer surface of the downhole tubular toward an outer blade surface of the blade proximate the lower end.

Statement 17. The stabilizer of statement 16, wherein the curved line-of-sight face is curved along a radial direction with respect to the downhole tubular.

Statement 18. The stabilizer of statement 16 or 17, wherein an inner transition radius from the gauge ramp to a surface of the downhole tubular is between 5% to 50% of a blade height of the respective blade.

Statement 19. The stabilizer of any of statements 16-18, wherein an outer transition radius from the gauge ramp to the outer blade surface of the blade proximate the lower end is between 20% to 60% of a blade height of the respective blade.

Statement 20. A stabilizer for use in a wellbore, comprising: a downhole tubular configured to couple to a downhole conveyance in a wellbore; and two or more helical blades extending radially outward from the downhole tubular, wherein the two or more helical blades are oriented about the downhole tubular to form respective flow paths between adjacent blades and to form a wrap angle between 350 degrees to 360 degrees, and wherein each blade of the two or more helical blades comprises: a lower line-of-sight face formed adjacent a leading inner blade wall of the blade at a lower end of the blade, wherein the lower line-of-sight face is angularly offset from the leading inner blade wall; a lower gauge ramp extending from an outer surface of the downhole tubular toward an outer blade surface of the blade proximate the lower end; an upper line-of-sight face formed adjacent a trailing inner blade wall of the blade at an upper end of the blade, wherein the upper line-of-sight face is angularly offset from the trailing inner blade wall; and an upper gauge ramp extending from the outer surface of the downhole tubular toward the outer blade surface of the blade proximate the upper end.

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, but may be, 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. Moreover, all statements herein reciting principles and aspects of the disclosure, as well as specific examples thereof, are intended to encompass equivalents thereof. Additionally, the term, “or,” as used herein, refers to a non-exclusive or, unless otherwise indicated.

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 direct interaction between the elements and may also include 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 toward the surface of the well; likewise, use of the terms “down,” “lower,” “downward,” “downhole,” 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 or horizontal 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.

Therefore, the present embodiments are well adapted to attain the ends and advantages mentioned as well as those that are inherent therein. The particular embodiments disclosed above are illustrative only, as the present embodiments may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Although individual embodiments are discussed, all combinations of each embodiment are contemplated and covered by the disclosure. Furthermore, no limitations are intended to the details of construction or design herein shown, other than as described in the claims below. Also, the terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee. It is therefore evident that the particular illustrative embodiments disclosed above may be altered or modified and all such variations are considered within the scope and spirit of the present disclosure.