Method and apparatus for hole cleaning enhancement

Abstract

A hole cleaning enhancement tool includes an elongated tool mandrel having a first connection on one longitudinal end and a second connection on another longitudinal end. A first stage extends along the mandrel between the first connection and one side of a center section on the mandrel. A second stage extends along the mandrel between another side of the center section and the second connection. A plurality of circumferentially spaced helical channels extends along the first stage and the second stage. The center section defines a curved profile having a largest outer diameter in a longitudinal center thereof, the longitudinal center defining a largest outer diameter along the tool mandrel. A drill string may comprise a plurality of such hole cleaning enhancement tools at spaced apart locations between pipe segments in a string of pipe segments.

Description

METHOD AND APPARATUS FOR HOLE CLEANING ENHANCEMENTBACKGROUND

[0001] This disclosure relates to the field of rotary drilling of subsurface wells. More particularly, the disclosure relates to apparatus and methods for enhancing removal of cuttings during well drilling and reducing drill string-wellbore friction during well construction operations.

[0002] In rotary drilling operations, a drilling tool assembly (string) comprising lengths of pipe, various well boring and conditioning tools and a drill bit are axially urged and rotated to advance drilling a wellbore through subsurface formations. Fluid is pumped through the drill string during drilling to perform various functions including lifting drill cuttings from the bit to the surface, generally within an annular space between the drill string and the wellbore. Both the fluid and rock fragments (cuttings) are thereby moving in the annulus. Cuttings transport is complicated by the fact that the fluid velocity varies from zero at the wellbore wall and the exterior surface of the drill string to a maximum at a point between the drill string outer wall and the wellbore wall. In addition, the rotation of the drill pipe and consequent viscous imparted rotation of the fluid imparts centrifugal force on the rock fragments, which affects their relative location in the annulus. Because of the extreme complexity of this flow behavior, drilling personnel have relied primarily on observation and experience for determining the cuttings lifting ability of the fluid. In practice, either the flow rate or effective viscosity of the fluid is increased, if problems related to inefficient cuttings removal are encountered. The result is a natural tendency toward thick (viscous) fluids and high annular flow velocities. However, increasing the fluid viscosity or flow rate can be detrimental to the wellbore (hole) cleaning action beneath the drill bit, and cause a reduction in the drilling penetration rate.

[0003] There may also be a considerable economic penalty associated with the use of a higher flow rate or fluid viscosity than necessary. Increasing the mud viscosity will not necessarily improve the cuttings transport efficiency in directional and horizontal sections as well. Usually, transport is usually not a problem, if the well is near vertical. However,considerable difficulties can occur when the well is being drilled directionally, because cuttings may accumulate either as a stationary bed at hole angles above about 50° from vertical or in a moving, churning bed at lower hole angles. Torque and drag are quite common problems in these situations of horizontal and deviated wells. Cuttings resting on the low side of the wellbore in these wells are the main factor for these problems.

[0004] Various devices known in the art to attempt to address the foregoing include the following. A tool known by the trade name, “The Remover” comprises features claimed to provide a "turbopump" effect that occurs during drill string rotation. Hydraulic models of the foregoing tool suggest that decreased annular velocity of the fluid take place as the fluid passes a lower "hard banding"; such velocity reduction would increase the effects of debris accumulation in this area. Wear protection banding may decrease the capability of important components that contribute to debris evacuation to be effective, such as drill pipe tool joints which are proven to remove less cuttings from wellbore. Also, tapered cuttings removal blades on the foregoing tool may limit effectiveness and contact of the tool to wellbore surface.

[0005] Another device known in the art called the Cuttings Bed Removal Tool may have limited cuttings bed contact due to the blade length on the tool. For such tool to be effective, many of them would have to be placed in the drill-string to effectively move cuttings up a deviated wellbore. Limitations of such tool may include one or more of the following:Limited impeller length (limited contact with cuttings beds);Would have to utilize many such tools in a drill string to work effectively;Complex design (competency is unproven); andIncreased cost of repair of multiple tools.

[0006] Another tool known as the Cuttings Bed Mobilizer has more wellbore contact than the foregoing tools, the size and distribution of the impellers would still crate less agitation and effective removal than may be desirable. Also, the high friction design and the length of the tool may make it impractical for sustained drilling operations

[0007] There continues to be a need for better tools to enhance drill cuttings transport during well drilling.SUMMARY

[0008] One aspect of the present disclosure relates to a hole cleaning enhancement tool. A hole cleaning enhancement tool according to this aspect includes an elongated tool mandrel having a first connection on one longitudinal end and a second connection on another longitudinal end. A first stage extends along the mandrel between the first connection and one side of a center section on the mandrel. A second stage extends along the mandrel between another side of the center section and the second connection. A plurality of circumferentially spaced helical channels extends along the first stage and the second stage. The center section defines a curved profile having a largest outer diameter in a longitudinal center thereof, the longitudinal center defining a largest outer diameter along the tool mandrel.

[0009] In another aspect of the present disclosure, a drill string includes a plurality of pipe segments coupled end to end. A plurality of hole cleaning enhancement tools according to the previous aspect may be disposed at spaced apart locations between segments of pipe. In both the foregoing aspects, certain implementations may include one or more of the following.

[0010] In some implementations, the largest outer diameter is at least 0.25 inches (6.3 mm) larger than an outer diameter of the first connection and the second connection.

[0011] In some implementations, blades defined circumferentially between the helical channels on the first stage and the second state define a same outer diameter as an outer diameter of the first connection and the second connection.

[0012] In some implementations, the helical channels on the first stage and the second stage have a semi-circular cross section.

[0013] In some implementations, a maximum depth of the channels is 0.67 times a width of the channels on the first stage and the second stage.

[0014] In some implementations, a maximum depth of the channels is limited such that bending strength, tensile strength and torsional strength of the tool each remain above a respective threshold.

[0015] In some implementations, the first connection and the second connection comprise threaded connections.

[0016] Some implementations further comprise a stress relief formed in the mandrel between the first connection and the first stage and between the second connection and the second stage.

[0017] In some implementations, the mandrel is formed from a single piece of material.

[0018] In some implementations, the mandrel comprises at least one of steel, titanium or non-magnetic alloy.

[0019] In some implementations, the first connection and the second connection comprise American Petroleum Institute standard tool joints for drill pipe.

[0020] Another aspect of the present disclosure is a drill string comprising a plurality of pipe segments coupled longitudinally end to end, and a plurality of hole cleaning enhancement tools according to any or all implementations of the previous aspect of the present disclosure.

[0021] A drill string according to another aspect of the present disclosure includes a plurality of pipe segments coupled longitudinally end to end. The drill string further includes a plurality of hole cleaning enhancement tools disposed at longitudinally spaced apart locations between pipe segments. Each of the plurality of hole cleaning enhancement tools comprises an elongated tool mandrel having a first connection on one longitudinal end and a second connection on another longitudinal end. The first and second connections are adapted to couple the elongated tool mandrel within to adjacent pipe segments, a first stage of the hole cleaning enhancement tool extends along the mandrel between the first connection and one side of a center section on the mandrel. A second stage extends along the mandrel between another side of the center section and the second connection. A plurality of circumferentially spaced helical channels extends along the first stage and thesecond stage, wherein the center section defines a curved profile having a largest outer diameter in a longitudinal center of the center section. The largest outer diameter of the center section is a largest outer diameter of the elongated tool mandrel

[0022] Some implementations further comprise a drill bit at a longitudinal end of the plurality of pipe segments.

[0023] In some implementations, the largest outer diameter is at least 0.25 inches (6.3 mm) larger than an outer diameter of the first connection and the second connection.

[0024] In some implementations, blades defined circumferentially between the helical channels on the first stage and the second state define a same outer diameter as an outer diameter of the first connection and the second connection.

[0025] In some implementations, the helical channels on the first stage and the second stage have a semi-circular cross section.

[0026] In some implementations, a maximum depth of the channels is 0.67 times a width of the channels on the first stage and the second stage.

[0027] In some implementations, a maximum depth of the channels is limited such that bending strength, tensile strength and torsional strength of the tool each remain above a respective threshold.

[0028] In some implementations, the first connection and the second connection comprise threaded connections.

[0029] Some implementations further comprise a stress relief formed in the mandrel between the first connection and the first stage and between the second connection and the second stage.

[0030] In some implementations, the mandrel is formed from a single piece of material.

[0031] In some implementations, the mandrel comprises at least one of steel, titanium or non-magnetic alloy.

[0032] In some implementations, the first connection and the second connection comprise American Petroleum Institute standard tool joints for drill pipe.

[0033] Other aspects and possible advantages will be apparent from the description and claims that follow.BRIEF DESCRIPTION OF THE DRAWINGS

[0034] FIG. 1 shows a side view of an example implementation of a tool according to the present disclosure

[0035] FIG. 2 shows a graph of expected hole cleaning enhancement using a tool according to the present disclosure with respect to rotary drill string speed.

[0036] FIG. 3 shows a graph of well fluid annulus flow rate increase across various sections of a tool according to the present disclosure with respect to rotary drill string speed.

[0037] FIG. 4 shows a view similar to that of FIG. 1 to illustrate certain dimensions on the tool.

[0038] FIG. 5 shows a possible implementation using a plurality of tools according to the present disclosure to enhance cuttings removal and reduce drill string friction in an extended reach well.DETAILED DESCRIPTION

[0039] To address issues noted in the Background section herein, and to improve well drilling performance, the present disclosure sets forth a novel hole cleaning enhancement tool (hereinafter “HCE tool” for convenience), shown generally at 10 in FIG. 1 and to be explained in more detail below. The HCE tool 10 is designed to provide improved drilling performance and flexible handling in horizontal or highly deviated (e.g., high inclination) wells. The HCE tool 10 may be used as a rotating torque reduction tool and may be useful in reducing torque and drag during well drilling by removing drill cuttings that accumulate on the gravitationally low side of the wellbore, while strategic placements of different outer diameter segments on the HCE tool 10 are provided in the tool to assist in cuttings agitation. Reduction of the ECD (equivalent circulating density) by keeping the wellbore more clear of drill cuttings, while substantially reducing drag are some of the possible benefits of using the HCE tool 10. The HCE tool 10 may reduce torque needed to rotate the drill string, mayminimize contact of parts of the drill string with well casing or liner, forms an integral part of the drill string and has a fail-safe design. The HCE tool 10 can be beneficial in managed pressure drilling (MPD) applications. The HCE tool 10 may be made entirely from metal with no rubbers, elastomers, bearings or moving parts.

[0040] Unique features of the HCE tool 10 may comprise one of more of the following. A lower (in this sense lower means closer to the drill bit during well drilling) set of generally helically shaped cuttings removal blades forming a “first stage” are shaped to pick cuttings up off the gravitational low side of the wellbore and to transport them longitudinally to a central torque and drag reducing center section, which provides flow turbulence to fluid flowing in the annular space between the wall of the wellbore and the drill string. An upper (meaning furthest from the drill bit along the HCE tool) set of generally helically shaped cuttings removal blades forms a “second stage” that accelerates and provides circulation of drill cuttings, moving them off the gravitational low side of the wellbore. The upper and lower blade sets have the same hand wrap (helical wind direction) to enhance hole cleaning and to avoid sudden fluid deceleration. The torque and drag reducing “central oval section” (center section) has the maximum overall outer diameter of the HCE tool 10, to reduce the effect of wellbore spiraling and to enhance drag reduction during tripping (moving the entire drill string into or out of the wellbore) and / or slide drilling (drilling using only a drilling motor on the drill string while the drill string remains rotationally fixed).

[0041] When drilling fluid passes through the annular space between the HCE tool 10 and the wellbore wall, the lower set of blades (“first stage”) can accelerate the fluid movement from 125.73% to 187.47% of its unassisted flow rate, depending on the drill string rotation rate (RPM); e.g., at 50-170 RPM, the acceleration enhances drill cuttings removal in a direction toward the surface.

[0042] The center section design, low friction, oval profile shape can allow fluid to be accelerated smoothly through the relatively small annular space, allowing drill cuttings to move with high momentum and thereby to avoid settling of cuttings to the gravitationally lower part of the wellbore. The center section may enhance movement of the fluid from130.70% to 204.37% of its unassisted value, depending on the drill string RPM (e.g., 50 - 170 RPM).

[0043] The fluid then smoothly passes through the “second stage” which will accelerate the fluid movement further from 186.01% to 331.23%, thereby ensuring a turbine-like effect on the well fluid occurs. An HCE tool according to the present disclosure may have one or more of the following features and possible benefits.

[0044] The HCE tool 10 may be compatible with any American Petroleum Institute (API) standard drill pipe connection. Polished metal carbide wellbore wall contact surfaces may provide less friction and lower casing wear than conventional drill pipe wear banding materials. Optimized tool joint spacing and length may be provided for efficient and safe handling and in-derrick racking capability with most well drilling rigs. The HCE tool 10 outer diameter distribution provides a non-aggressive diameter profile and can enhance debris evacuation (drill cuttings transport) while substantially reducing toque and drag.

[0045] The overall length of the HCE tool 10 in some implementations is relatively short and easy to handle on the drilling unit (rig) floor. The dual agitation mechanism picks cuttings up off the bottom (gravitational low side) of the wellbore and transports the cuttings to the gravitational high side, where high velocity circulation takes place. The torque and drag reducer (center section) is disposed so as to mitigate torque and drag during rotation and sliding events, ensuring minimum contact with casing or the wellbore wall; additionally the center section provides turbulence and higher fluid velocities, which assist in the transport of the cuttings off the gravitational low side of the wellbore. The blades on the center section are positioned to ensure concentric motion at the flow accelerator and impeller to assist in hole cleaning. Both the axial upper and lower blade sections comprise helical blades to improve borehole clearing and help prevent abrupt fluid deceleration.Possible benefits include one or more of the following. More weight may be transferred to the drill bit because along-string tool joints are not forced to push cuttings during slide drilling (using only a drilling motor along the drill string to rotate the drill bit). Higher rate of penetration and lower rotary torque may be provided. Increased tripping speeds and less or no overpull on drill string trips may be provided. Enhanced distribution of mechanicalspecific energy may be provided. Enhanced hole cleaning and mud quality may be provided. Longer bit life may be provided due to avoidance of re-drilling drill cuttings. Reduced risk of stuck pipe or packing off may be provided. Reduced slip-stick motion incidence may occur. Drill string stand-off enhancement may be provided. Reduced overall material losses may be provided. Mitigation of and reduction of drill string vibration may be provided. The HCE tool may be designed and built as one robust metal (e.g., steel) component piece with no moving parts. Using the HCE tool may lower ECD by enhancing the hole cleaning and low solid content in the active mud system. Lower drill-string and BHA failure rates may result due to lower friction and solids content.

[0046] An example implementation of the HCE tool 10 may be better understood with reference to FIG. 1. The HCE tool 10 may be formed from a single piece of material, e.g., metal, such as steel, titanium or non-magnetic alloys such as INCONEL brand alloy. INCONEL is a registered trademark of Huntington Alloys Corp., Huntington, WV. The HCE tool 10 may comprise a generally cylindrically shaped mandrel 11 having connections 12, such as threaded connections on each longitudinal end of the HCE tool 10. The type of connection is not a limitation on the scope of the present disclosure; it is contemplated that the connections 12 should be made to standards set by the American Petroleum Institute (API) in one or more Recommended Practices (RP) so that the HCE tool 10 is compatible with a wide range of drill string components as are known to be used in subsurface well drilling. The connections 12 may define an outer diameter (see FIG. 4) consistent with API defined outer diameters for specific pipe string connections, and the connections 12 may be referred to herein for convenience as “tool joints.” The connections 12 may each comprise a stress relief 12A at a place where the respective tool joint 12 is adjacent to, respectively, a first stage 16 and a second stage 18. The first stage 16 may comprise a plurality of generally helically shaped, generally semicircular cross-section channels 22. The channels 22 may extend longitudinally from the stress relief 12A (or the edge of the tool joint 12 where no stress relief is provided), to one longitudinal edge of a center section 20.

[0047] In some implementations, the channels 22, 24 may have a substantially circular cross-section; depth of each channel (distance from the blade surfaces to the deepest pointin each channel) may be at most 0.67 times the width of each channel. A maximum depth of each channel 22, 24 may be limited such that the overall bending strength, tensile strength and torsional strength of the HCE tool 10 remain above a respective threshold, that is, in some implementations, the channels 22, 24 should be no deeper than would compromise the integrity of the HCE tool 10 for the drilling conditions in which it is expected to be used.

[0048] It should also be understood that the gender of the connections 12 in any implementation is a matter of discretion for the tool designer depending on intended placement of the HCE tool 10 within the drill string; the gender of the connections is not intended to limit the scope of the present disclosure. In the present example implementation, one of the connections 12 may be, for example, a male (pin) connection, and the other connection 12 may be female (box) connection. In some implementations, both connectors 12 may be pin, or both may be box.

[0049] An opposed longitudinal edge of the center section 20 may be adjacent to the second stage 18, which itself longitudinally terminates adjacent to the other stress relief 12A or tool joint 12. The second stage 18 may also comprise channels 24 as does the first stage 16 having similar shape and longitudinal extent as the channels 22 in the first stage 16.

[0050] Spaces between the respective channels 22, 24 thus define corresponding blades 23 between adjacent channels 22, 24. The blades 23 may have an external diameter the same as that of the tool joints 12, as will be further explained with reference to FIG. 4.

[0051] The center section 20 may define the largest outer diameter on the HCE tool 10, generally in the longitudinal center 20A of the center section 20. The outer diameter of the center section 20 may monotonically decrease from the longitudinal center 20A to the points adjacent to the respective stages 16, 18. At such points, the outer diameter of the center section 20 may be the same as those of the corresponding stage blades 23. The diameter change of the center section 20 may define an approximate oval or elliptical crosssection, i.e., have a curved profile to, among other things, minimize drilling fluid pressurespiking when the HCE tool 10 is moved through a well annulus fluid closure device such as a rotating control device (RCD).

[0052] FIG. 2 shows a graph of expected hole cleaning (drill cuttings transport) increase using the HCE tool 10 at 23 compared to that of drill strings not having such HCE tool, at 21, with respect to to drill string rotation rate (RPM).

[0053] FIG. 3 shows a graph of hole cleaning increase provided by each of the first stage (16 in FIG. 1) at 30A through 38 A, the center section (20 in FIG. 1) at 30B through 38B and the second stage (18 in FIG. 1) 30C through 38C with respect to the drill string RPM, for RPM values of 170, 140, 110, 80 and 50, respectively.

[0054] FIG. 4 shows a view of the HCE tool 10 similar to the view shown in FIG. 1, wherein certain dimensions are defined. It is contemplated that the maximum outer diameter C of the center section is at least 0.25 inches more than the maximum outer diameter B of the blades and tool joints; for purposes of defining the scope of the present disclosure, it is only necessary for the diameter at C to be the largest diameter along the HCE tool 10. Internal diameter of the HCE tool 10 is shown at F, and the lengths of the first stage and second stage are shown at D and E, respectively.

[0055] Example dimensions that may be used in some drill strings are shown, and without limitation to the scope of the present disclosure, in TABLE 1.TABLE 1

[0056] Other dimensions may be given the following considerations. The considerations are intended only as examples and do not limit the scope of the present disclosure.

[0057] All rotary shouldered connection strengths and make up torque values to be used as a guide only. Values to be confirmed by client per system of work (tool mandrel at 110 ksi minimum yield strength). Recommended make-up torque taken as 60% of the maximum stress condition to yield a RSC per API, API RP7G (4.8.1, A.9.2). Connections are considered to have stress relief grooves. Tool strength values are identified based on connection strength or structural strength, whichever is lower. Structural strength is calculated across the mandrel neck per API RP7G (A.8.1 and A.7) and includes a 1.5 safety factor. The material from which the HCE tool 10 is made may have a minimum yield strength of 110 ksi (758423 kPa). Connection strength values may be taken from National Oilwell Varco 19 / 04 / 11. Modified equation for double shouldered connections HT, XT outside of API RP7G. 1.5 SF from ref. Connection strength estimates may be calculated from Baker Hughes, Technical Engineering Handbook 2009, Section 2, p33: Vallourec and Mannesmann, Sept. 2005 original source data. 1.5 safety factor from the reference. The geometry above represents typical production strategy. Mandrel IDs and tool joint ODs can be supplied to meet application specific requirements. Values taken to suit 5.5” (170 mm) OD and 2-7 / 16” (61.9 mm) ID. Values taken to suit 3.5” (89 mm) ID. Values taken to suit 4.75” (120.7 mm) ID. Connections evaluated as standard full hole thread tooljoints. Bending Strength Ratio evaluated as per API Recommended Practice (RP) 7G (A.11).

[0058] Bending Strength Ratio information was not available or did not conform to API RP 7G (A.11) calculations. Shoulder to shoulder lengths are approximate values only. These lengths may depend on connection re-cuts and production series. Recommended make-up torque was provided by National Oilwell Varco (NOV)-Grant Prideco connection performance sheets for XT, HT connections. Connection strength: values taken from NOV- Grant Prideco connection performance sheets for XT, HT connections. Recommended make-up torque and connection strength values taken from Vallourec Group connection performance sheets for NC38 VAM EIS connection.

[0059] The foregoing examples are described in more detail in TABLE 2.TABLE 2

[0060] In some uses, and referring to FIG. 5, a plurality of HCE tools 10 as explained with reference to FIGS. 1 and 4 may be disposed at spaced apart locations along a drill string 25. The drill string 25 may comprise a plurality of pipe segments 35 coupled longitudinally end to end e.g., by threaded connections known in the art. The drill string 25 may terminate in special drilling tools including a drill bit 30 at the longitudinal end of the drill string. The drill string 25 may be rotated and axially urged by a drilling unit 28 of types known in the art. In some implementations, the HCE tools 10 as explained above may be disposed at axially spaced apart locations between pipe segments 35. In some implementations, the HCE tools 10 may be disposed only in that part of the drill string 25 disposed below a depth, shown at 26, wherein the wellbore trajectory begins being deviated from vertical, known in the art as the “kickoff point” (KOP). Depending on lateral lengths, the number of HCE tools utilized in the drill string can range from one tool per two stands (stands being assemblies of typically three segments or “joints” of pipe) or one tool per three stands spaced out along the drill string 25.

[0061] Using a tool made according to the various aspects of the present disclosure, well operators may experience one of more of the following: More of the total drill string weight is applied to the drill bit because tool joints in the drill string are not forced to push drill cuttings when the drill string is moving through a highly inclined wellbore. Higher drilling progress rates (ROP) and lower torque to rotate the drill string may be obtained. Increased “tripping” speeds and less or no overpull on trips may be obtained. Enhanced distribution of mechanical specific energy along the drill string may be obtained. Enhanced hole cleaning and mud quality may be obtained. Longer bit life may occur due to reduced redrilling of drill cuttings. Reduced risk may obtain of stuck pipe or packing off (closure of the annular space by settled drill cuttings. Reduced slip-stick motion of the drill string may take place. The center section (oval donut) design ensures its effectiveness during managed pressure drilling (MPD) operations. Drill string stand-off from the wellbore wall may be enhanced. Overall material losses may be reduced. Vibration in the drill string may be reduced. The tool may be formed as one robust piece, e.g., from metal, with no moving parts. Lower equivalent circulating density (ECD) may be obtained by enhancing the hole cleaning and by lowering solids content in the drilling fluid circulating system. Lowerfriction with casing and wellbore wall may be obtained. Lower drill-string and BHA failure rates could be expected due to lower friction and drilling mud solids content.

[0062] The overall length of the tool is relatively short and therefore is easy to handle on the rig floor. The dual agitation mechanisms (first stage and second stage) pick drill cuttings up off the bottom of the hole and transports them to the high side where high velocity circulation exists. A torque and drag reducer is embedded which mitigate the torque and drag during rotation and sliding events ensuring minimum contact points with casing or wellbore wall, additionally it provides turbulence and higher fluid velocities which assist in the transportation of the cuttings off the low side of the hole. The blades are positioned to ensure concentric motion at the flow accelerator and impeller to assist in hole cleaning. Both the first stage and second stage blades feature identical helical configurations to improve borehole clearing and prevent abrupt fluid deceleration.

[0063] The lower set of cuttings removal blades (i.e., the first stage) are tailored to pick cuttings up off the bottom of the hole and transports them to central torque and drag reducer center section which is embedded as an integral part of the tool to provide mud flow turbulence. The upper set of cuttings removal blades (i.e., the second stage) accelerates the flow and provides circulation to the drill cuttings moving them off the low side of the hole. The first state and second stage blades have the same helical hand wrap to enhance hole cleaning and avoid sudden fluid de-acceleration. The central oval section has the maximum outer diameter of the tool to reduce the effect of borehole spiraling and enhance drag reduction during tripping and / or sliding. The tool according to the present disclosure is compatible with any API-specification drill pipe connection. A polished carbide wellbore wall contact surface may provide less friction and lower casing wear than Drill Pipe wear banding materials. The length of the tool is at the discretion of the designer and may be optimized to provide tool joint spacing and length for efficient and safe handling and inderrick racking capability with most drilling rigs. The unique design and outer diameter distribution (non-aggressive profile) may enhance debris evacuation while dramatically reducing toque and drag. The profile of the center section is tailored to be the most effective torque reduction tool for MPD applications by reducing the fluid pressure impact on the rubber of a rotating control head or rotating control device.

[0064] In light of the principles and example implementations described and illustrated herein, it will be recognized that the example implementations can be modified in arrangement and detail without departing from such principles. The foregoing discussion has focused on specific implementations, but other configurations are also contemplated. In particular, even though expressions such as in “an implementation," or the like are used herein, these phrases are meant to generally reference implementation possibilities, and are not intended to limit the disclosure to particular implementation configurations. As used herein, these terms may reference the same or different implementations that are combinable into other implementations. As a rule, any implementation referenced herein is freely combinable with any one or more of the other implementations referenced herein, and any number of features of different implementations are combinable with one another, unless indicated otherwise. Although only a few examples have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible within the scope of the described examples. Accordingly, all such modifications are intended to be included within the scope of this disclosure as defined in the following claims.

Claims

CLAIMSWhat is claimed is:

1. A hole cleaning enhancement tool, comprising: an elongated tool mandrel having a first connection on one longitudinal end and a second connection on another longitudinal end, the first and second connections adapted to couple the elongated tool mandrel within a drill string; a first stage extending along the mandrel between the first connection and one side of a center section on the mandrel; a second stage extending along the mandrel between another side of the center section and the second connection; a plurality of circumferentially spaced helical channels extending along the first stage and the second stage; and wherein the center section defines a curved profile having a largest outer diameter in a longitudinal center thereof, the largest outer diameter of the center section being a largest outer diameter of the elongated tool mandrel.

2. The hole cleaning enhancement tool of claim 1 wherein the largest outer diameter is at least 0.25 inches (6.3 mm) larger than an outer diameter of the first connection and the second connection.

3. The hole cleaning enhancement tool of claim 1 wherein blades defined circumferentially between the helical channels on the first stage and the second state define a same outer diameter as an outer diameter of the first connection and the second connection.

4. The hole cleaning enhancement tool of claim 1 wherein the helical channels on the first stage and the second stage have a semi-circular cross section.

5. The hole cleaning enhancement tool of claim 1 wherein a maximum depth of the helical channels is 0.67 times a width of the helical channels on the first stage and the second stage.

6. The hole cleaning enhancement tool of claim 1 wherein a maximum depth of the helical channels is limited such that bending strength, tensile strength and torsional strength of the hole cleaning enhancement tool each remain above a respective threshold.

7. The hole cleaning enhancement tool of claim 1 wherein the first connection and the second connection comprise threaded connections.

8. The hole cleaning enhancement tool of claim 1 further comprise a stress relief formed in the mandrel between the first connection and the first stage and between the second connection and the second stage.

9. The hole cleaning enhancement tool of claim 1 wherein the mandrel is formed from a single piece of material.

10. The hole cleaning enhancement tool of claim 1 wherein the mandrel comprises at least one of steel, titanium or non-magnetic alloy.

11. The hole cleaning enhancement tool of claim 1 wherein the first connection and the second connection comprise American Petroleum Institute standard tool joints for drill pipe.

12. A drill string comprising a plurality of pipe segments coupled longitudinally end to end, and a plurality of hole cleaning enhancement tools according to any of claims 1 through 11 disposed at longitudinally spaced apart locations between pipe segments.

13. A drill string, comprising: a plurality of pipe segments coupled longitudinally end to end; and a plurality of hole cleaning enhancement tools disposed at longitudinally spaced apart locations between pipe segments, each of the plurality of hole cleaning enhancement tools comprising, an elongated tool mandrel having a first connection on one longitudinal end and a second connection on another longitudinal end, the first and second connections adapted to couple the elongated tool mandrel to adjacent pipe segments, a first stage extending along the mandrel between the first connection and one side of a center section on the mandrel, a second stageextending along the mandrel between another side of the center section and the second connection, a plurality of circumferentially spaced helical channels extending along the first stage and the second stage, and wherein the center section defines a curved profile having a largest outer diameter in a longitudinal center thereof, the largest outer diameter of the center section being a largest outer diameter of the elongated tool mandrel14. The drill string of claim 13 further comprising a drill bit at a longitudinal end of the plurality of pipe segments.

15. The drill string of claim 13 wherein the largest outer diameter is at least 0.25 inches (6.3 mm) larger than an outer diameter of the first connection and the second connection.

16. The drill string of claim 13 wherein blades defined circumferentially between the helical channels on the first stage and the second state define a same outer diameter as an outer diameter of the first connection and the second connection.

17. The drill string of claim 13 wherein the helical channels on the first stage and the second stage have a semi-circular cross section.

18. The drill string of claim 13 wherein a maximum depth of the channels is 0.67 times a width of the channels on the first stage and the second stage.

19. The drill string of claim 13 wherein a maximum depth of the channels is limited such that bending strength, tensile strength and torsional strength of the tool each remain above a respective threshold.

20. The drill string of claim 13 wherein the first connection and the second connection comprise threaded connections.

21. The drill string of claim 13 further comprise a stress relief formed in the mandrel between the first connection and the first stage and between the second connection and the second stage.

22. The drill string of claim 13 wherein the mandrel is formed from a single piece of material.

23. The drill string of claim 13 wherein the mandrel comprises at least one of steel, titanium or non-magnetic alloy.

24. The drill string of claim 13 wherein the first connection and the second connection comprise American Petroleum Institute standard tool joints for drill pipe.

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