Anti-Balling Drill Bit and Method of Making Same

Abstract

A drill bit for drilling a wellbore penetrating a subterranean formation is disclosed. The drill bit includes a bit body having a surface about a working end thereof, ribs extending from the surface of the bit body with channels defined therebetween, cutting elements positionable on the ribs to cuttingly engage the subterranean formation and release cuttings therefrom, and an anti-balling composition. The anti-balling composition includes a hardphase having a chemical potential that is more electronegative than the surface. The anti-balling composition is disposed on a surface of the bit body whereby the cuttings from the wellbore are prevented from collecting on the bit body.

Description

BACKGROUND

This present disclosure relates generally to drilling equipment used in wellsite operations. More specifically, the present disclosure relates to drill bits and/or cutting elements used for drilling wellbores.

Various oilfield operations may be performed to locate and gather valuable downhole fluids. Oil rigs are positioned at wellsites and downhole tools, such as drilling tools, are deployed into the ground to reach subsurface reservoirs. The drilling tool may include a drill string with a bottom hole assembly, and a drill bit advanced into the earth to form a wellbore.

The drill bit may be connected to a downhole end of the bottom hole assembly and driven by drill-string rotation from surface and/or by mud flowing through the drilling tool. Examples of drill bits are disclosed in U.S. Pat. Nos. 5,330,016, 5,562,171, 5,732,783, 6,450,271, 8,141,664 and U.S. Pat. App. Pub. Nos. 2011/0167734, 2011/0174548, 2012/0205162, and 2014/0102809.

As the drill bit is advanced into the wellbore, the earth along the wellbore is torn away and forms cuttings. The cuttings may be carried away by the mud flowing out of the drilling tool, and back up the wellbore through an annulus between the drilling tool and the wellbore.

SUMMARY

In at least one aspect the present disclosure relates to a drill bit for drilling a wellbore penetrating a subterranean formation. The drill bit includes a bit body having a surface about a working end thereof, ribs extending from the surface of the bit body with channels defined therebetween, cutting elements positionable on the ribs to cuttingly engage the subterranean formation and release cuttings therefrom, and an anti-balling composition. The anti-balling composition includes a hardphase having a chemical potential that is more electronegative than the surface. The anti-balling composition is disposed on a surface of the bit body whereby the cuttings from the wellbore are prevented from collecting on the bit body.

The hardphase may include a chromium carbide. The hardphase may comprise a first hardphase material and a second hardphase material. The first hardphase material may comprise chromium, tantalum carbides, zirconium carbides, aluminas, chromium carbides, beryllium carbides, titanium carbides, silicon carbides, aluminum borides, and/or boron carbides. The first hardphase material may comprise Cr, Cr3C2 or a mixture thereof. The second hardphase material may comprise tungsten carbide.

The chemical potential of the first hardphase material is from 5% to 75% less than the chemical potential of the second hardphase material. The second hardphase material has a hardness greater than the hardness of the first hardphase material. The first hardphase material has a hardness from 900 Pa to 4000 Pa and the hardness of the second hardphase material is between 1500 Pa to 3000 Pa.

The first hardphase material has a kinetic coefficient of friction that is 85% to 95% the kinetic coefficient of friction of tungsten carbide and the second hardphase material has a kinetic coefficient of friction that is greater than the kinetic coefficient of friction of the first hardphase material. The second hardphase material has a kinetic coefficient of friction that is 105% to 150% the kinetic coefficient of friction of the first hardphase material.

The first and the second hardphase materials of the drill bit may comprise hardphase particles with a tap density of 10.0 g/mL. The first and the second hardphase particles comprise a particle size distribution of 177 μm to 20 μm.

The drill bit is one of a matrix drill bit or an infiltrated drill bit. The drill bit has cutting elements which may comprise polycrystalline and/or single crystal diamond grains. The drill bit may further have nozzles.

The anti-balling composition is disposed along the channels. The anti-balling composition may be formed into the bit body. The surface of the drill bit may be polished to an average surface roughness of less than 4 μm to 10 μm.

In another aspect, the disclosure relates to a method of manufacturing a drill bit for drilling a wellbore penetrating a subterranean formation. The method involves providing a mold having a bit pattern with channel-forming regions defined therein, and providing an anti-balling composition in the channel-forming regions of the mold. The anti-balling composition comprises a hardphase having a chemical potential that is more electronegative than the surface. The method further involves providing a matrix forming composition, forming the drill bit by heating the mold; and removing the mold from the formed drill bit.

The method may further involve providing an infiltrant in the mold. The heating may comprise heating the mold to between 1040° C. to 1175° C. for 1 to 5 hours. The method may further involve polishing the drill bit.

In another aspect, the disclosure relates to an anti-balling composition for a drill bit for drilling a wellbore penetrating a subterranean formation. The anti-balling composition may comprise one or more first hardphase materials selected from the group consisting of chromium, tantalum carbides, zirconium carbides, aluminas, chromium carbides, beryllium carbides, titanium carbides, silicon carbides, aluminum borides, and boron carbides.

The first hardphase material may comprise Cr, Cr3C2 or a mixture thereof. The anti-balling composition may further involve one or more second hardphase materials, wherein the first hardphase has a chemical potential that is more negative than the chemical potential of the second hardphase. The second hardphase material may comprise tungsten carbide.

The composition comprises from greater than 0 to 25 wt % combined one or more second hardphase materials and from 75 to less than 100 wt % combined one or more first hardphase materials, based on the total weights of the first and second hardphase materials. The chemical potential of the first hardphase material is from 5% to 75% less than the chemical potential of the second hardphase material.

BRIEF DESCRIPTION OF THE DRAWINGS

Embodiments of compositions, devices, and methods for use with downhole tools are described with reference to the following figures. Like numbers are used throughout the figures to reference like features and components. It is to be noted, however, that the figures are not to be considered limiting of with regard to the scope of the invention. The figures are not necessarily to scale and certain features and certain views of the figures may be shown exaggerated in scale or in schematic in the interest of clarity and conciseness.

FIG. 1 is a schematic diagram of a wellsite including a rig with a downhole tool having an anti-balling drill bit advanced into the earth to form a wellbore.

FIG. 2 is a side view of an anti-balling drill bit.

FIG. 3 is an end view of the anti-balling drill bit of FIG. 2.

FIG. 4A is a flow diagram of a method of making a drill bit according to the invention.

FIG. 4B is a schematic view of the anti-balling drill bit during operation.

FIG. 5 is an electron micrograph of the anti-balling composition of Example 1.

FIG. 6 is an electron micrograph of the anti-balling composition of Example 2.

FIG. 7 is an electron micrograph of the anti-balling composition of Example 3.

DETAILED DESCRIPTION

In the following description, numerous details are set forth to provide an understanding of the present disclosure. However, it will be understood by those skilled in the art that the present disclosure may be practiced without these details and that numerous variations or modifications from the described embodiments are possible.

This disclosure is directed to anti-balling compositions suitable for use about at least a portion of a drill bit. The anti-balling composition has a chemical potential that has electronegative features to prevent balling of wellbore material (e.g., cuttings, wellbore fluids, etc.) about the drill bit during drilling. The anti-balling composition may be more electronegative than tungsten carbide, e.g., cast tungsten carbide, and may form part of the drill bit.

‘Anti-balling’ as used herein refers to the prevention of balling, such as accumulation, clogging, and/or sticking (“collection”) of wellbore materials to the drill bit or other portions of the downhole tool during drilling. Balling may occur, for example, along cavities, such as waterways and junk slots along the drill bit. Rough and/or raised surfaces may increase surface area which may escalate adhesive Vander Waal forces. Wellbore material involved in balling may have an overall negative charge due to presence of certain chemicals, such as Mg, Fe, and Al. The negative features of the anti-balling compositions may include, for example, chrome or chrome carbide to offset such negative charges in an attempt to resist balling.

For reference, FIG. 1 schematically depicts a wellsite 100 in which the anti-balling composition and/or drill bits described herein may be used. As generally shown, a drill bit 112 with cutting elements 101 may be deployed at a downhole end of a downhole tool 102 into a subterranean formation 106 to form a wellbore 104, by any suitable means, such as by a rotary drill string 108 operated from a drilling rig 110 to rotate the drill bit 112. A mud pit 111 is provided at the wellsite 100 to pass drilling fluid through the downhole tool 102 and out the drill bit 112 to cool the drill bit 112 and carry away cuttings during drilling. Drill bit 112 includes an anti-balling composition 114 as is described herein.

The “drill string” may be made up of tubulars secured together by any suitable means, such as mating threads, and the drill bit may be secured at or near an end of the tubulars. As used throughout this description, the term “wellbore” is synonymous with borehole and means the open hole or uncased portion of a subterranean well including the rock face which bounds the drilled hole. The wellbore may have any suitable subterranean configuration, such as generally vertical, generally deviated, generally horizontal, or combinations thereof, as will be evident to a skilled artisan.

While FIG. 1 depicts a land-based wellbore with a downhole drilling tool, it will be appreciated that the anti-balling composition and/or drill bit may be used with any wellsite, downhole tool or other equipment. The anti-balling composition is depicted as being positioned about a drill bit, and may also be positioned about other portions of the downhole tool.

Exemplary Drill Bit Structure

The anti-balling drill bit 112 described herein may be, for example, a “matrix drill bit” or an “infiltrated drill bit.” Such drill bits may be utilized in conjunction with any downhole tool to form a wellbore 104. An exemplary drill bit 200, depicted in FIGS. 2 and 3, comprises a matrix-type bit body 203. The bit body 203 may comprise tungsten carbide, e.g., cast tungsten carbide, into which cutting elements 204 may be embedded or impregnated.

The cutting elements 204 may be made of, for example, polycrystalline and/or single crystal diamond grains, that may abrade the formation upon rotation of the drill bit 200 and generate the cuttings. Example drill bits and methods for forming such drill bits are shown in U.S. Pat. Application No. 2011/0167734, previously incorporated by reference herein.

The drill bit 200 has a leading face 202 with a plurality of blades 206 upstanding from the leading face 202 of the bit body 203 and extending outwardly away from the central axis of rotation 208. As described above, the bit body 203 also includes one or more channels 207, sometimes referred to as “waterways” or “junk slots” formed between the blades 206. Portions of the drill bit 200, such as along the channels 207 as shown, may comprise an anti-balling composition 212 to facilitate removal of the abraded material.

The drill bit 200 also has a shank 210 for connection to a drill string, and rotation about a central axis 208. The shank 210 may optionally be a threaded end adapter to mate with the end of the drill string. The matrix bit body 203 may be arranged to include other features, such as nozzles 214. The nozzles 214 may be used, for example, to allow drilling fluid to be supplied to the channels 207 between the blades 206. The fluid may be used for the purposes of cooling and cleaning of the cutting elements 204 and to carry material (e.g., cuttings) abraded, gouged or otherwise removed from the formation during drilling away from the drill bit 200.

While FIGS. 2 and 3 show the anti-balling composition 212 on a portion of the drill bit 200 along the channels 207, it will be appreciated that anti-balling composition 212 may be provided in a variety of configurations about the drill bit and/or other portions of the downhole tool. For example, the anti-balling composition 212 may be applied along a surface of the drill bit 202 (e.g., about the blades 206) and/or be formed into the body 203 of the drill bit 200.

Anti-Balling Composition

The anti-balling composition 212 may be used in forming one or more parts of a downhool tool, e.g., the drill bit, drill collars, and/or portions thereof. For example, portions of the drill bit 200 about the channels 207 may comprise the anti-balling composition 212. The anti-balling composition 212 may be selected for use with a bit body, and have any composition suitable for use with wellbore materials (e.g., cuttings, drilling muds, production fluids, etc.) The anti-balling composition 212 may be selected to achieve reduced balling of the wellbore materials along the drill bit 200 during drilling.

The anti-balling composition 212 may include, for example, a first hardphase and optionally a second hardphase. The first hardphase has a chemical potential that is more negative than the chemical potential of the second hardphase. The chemical potential μ of a substance B in a mixture of substances B, C, . . . is related to the Gibbs energy, G, of the mixture by:

$\begin{array}{cc}{\mu }_B={\left(\frac{\partial G}{\partial n_B}\right)}_{T,p,n_{C\ne B}}& \mathrm{Eqn}.1\end{array}$

where T is the thermodynamic temperature, p is the pressure and n_B, n_c, . . . are the amounts of substance of B, C, . . . For a pure substance B, the chemical potential, μ*_B, is given by:

$\begin{array}{cc}{\mu }_B^{*}=\left(\frac{G^{*}}{n_B}\right)=G_m^{*}& \mathrm{Eqn}.2\end{array}$

where G*_m is the molar Gibbs energy, and where the superscript * attached to a symbol denotes the property of the pure substance.

The superscript Θ or ° attached to a symbol may be used to denote a standard thermodynamic quantity. The chemical potential may also be determined according to the formula:

μ_i=μ^Θ_i+RTlna_i   Eqn. 3

where R is the gas constant, T is the temperature, μ_i^Θ is the value of μ_i, under standard conditions, and a_i is the activity (approximately 1 for solid mixtures). Chemical potentials usable with the anti-balling compositions herein can be calculated as described, for example, in IUPAC, Compendium of Chemical Terminology, 8th ed. (the “Gold Book”) (2014) and Kaufman, Myron Principles of thermodynamics, CRC Press, p. 213 (2002), the entire contents of each of which is incorporated herein by reference.

Anti-balling properties may occur when μ_Hρι<μHP2, where μHPι is the chemical potential of the first hardphase and μ_Hρ₂ is the chemical potential of the second hardphase. The percentage difference between the chemical potential of the first hardphase and the chemical potential of the second hardphase, i.e.

$\left(\frac{{\mu }_{\mathrm{HP}2}-{\mu }_{\mathrm{HP}1}}{{\mu }_{\mathrm{HP}2}}\times 100\%\right),$

may be ≧about 5%, e.g., >about 6%, >about 8%, >about 10%, >about 15%, >about 20%, >about 30%, >about 40%, >about 50%, >about 75%, >about 100%, or >about 200%. Additionally (or alternatively), the percentage difference may be <about 150%, <about 125%, <about 100%, <about 80%, <about 60%, <about 40%, <about 25%, <about 15%, <about 10%, <about 8%), or <about 6%. Exemplary ranges of the percent difference between the chemical potentials may include about 5% to about 200%, about 6% to about 150%, about 8% to about 125%, about 10 to about 100%, about 15 to about 80%, about 20 to about 60%, about 30 to about 40%, etc.

The chemical potential of the first hardphase may be about 5% less, about 6% less, about 8% less, about 10%, less, about 15% less, about 20% less, about 30% less, about 40% less, about 50% less, or about 75% less, than the chemical potential of the second hardphase, particularly where the second hardphase is a tungsten carbide, e.g., WC, cast tungsten carbide, etc. For the purposes of this disclosure, where the anti-balling composition does not include a second hard phase, the chemical potential and differences described herein may be determined with respect to tungsten carbide, WC.

In particular anti-balling compositions 212, anti-balling properties may be provided by materials that are relatively hard. Hardness may be measured, for example, according to Microhardness test procedure, ASTM E-384. The first hardphase may have a Knoop Value determined from a Microhardness test procedure of >about 900 Pascals (Pa), >about 1200 Pa, >about 1500 Pa, >about 1900 Pa, e.g., >about 2000 Pa, >about 2100 Pa, >about 2300 Pa, >about 2500 Pa, >about 2750 Pa, or >about 3000 Pa. Additionally or alternatively, the first hardphase may have a Knoop Value <about 4000 Pa, e.g., <about 3000 Pa, <about 2750 Pa, <about 2500 Pa, <about 2500 Pa, <about 2100 Pa, <about 2000 Pa, <about 1900 Pa, <about 1500 Pa, or <about 1200 Pa. Exemplary first hardphases may have a Knoop Value of about 1900 to about 4000 Pa, about 2000 to about 3000 Pa, about 2100 to about 2750 Pa, or 2300 to about 2500 Pa.

The first hardphase may also have a kinetic coefficient of friction CoF_Hp1<than the kinetic coefficient of friction of tungsten carbide CoF_wc, e.g., CoF_Hp1≦0.95×CoF_Hp1<0.925×CoF_wc, CoF_Hp1<0.90×CoF_wc, CoF_Hp1<0.875×CoF_wc, or CoF_Hp1<0.85×CoF_wc. Exemplary ranges include, but are not limited to, CoF_Hp1 of from 0.85×CoF_wc to 0.95×CoF_wc, 0.875×CoF_wc to 0.925×CoF_wc, or about 0.90×CoF_wc.

Exemplary first hardphase materials may include tantalum carbides, e.g., TaC, zirconium carbides, e.g., ZrC, aluminas, e.g., Al2O3, chromium carbides, e.g., Cr3C2, beryllium carbides, e.g., Be2C, titanium carbides, e.g., TiC, silicon carbides, SiC, aluminum borides. e.g., AlB, and boron carbides, e.g., B4C. Chromium, chromium carbides, and mixture thereof, e.g., Cr, Cr3C2, and Cr/Cr3C2, may be used.

The anti-balling composition may also optionally include a second hardphase having, for example, a Knoop Value greater than that of the first hardphase. The second hardphase may have a Knoop value >about 1500 Pa, e.g., >about 1750 Pa, >about 1900 Pa, >about 2000 Pa, >about 2100 Pa, >about 2300 Pa, >about 2500 Pa, >about 2750 Pa, or >about 3000 Pa. Additionally or alternatively, the second hardphase may have a Knoop Value <about 3000 Pa, e.g., <about 2750 Pa, <about 2500 Pa, <about 2500 Pa, <about 2100 Pa, <about 2000 Pa, <about 1900 Pa or <about 1750 Pa. Exemplary second hardphases may have a Knoop Value of about 1800 to about 2500 Pa, about 1900 to about 2200 Pa, or about 1900 to about 2100 Pa. The particle size distributions may be optimized to provide high powder packing with tap densities of about 10.0 g/cc and hardphase particle size distributions having a range, for example, from about 80 Mesh (177 μπι) to about 625 Mesh (20 μπι).

The second hardphase preferably may also have a kinetic coefficient of friction CoF_Hp2>than the kinetic coefficient of friction of the first hardphase CoF_Hp1, e.g., CoF_Hp2>1.05×CoF_Hp1, CoF_Hp2>1.10×CoF_Hp1, CoF_Hp2>1.15×CoF_Hp1, CoF_Hp2>1.20×CoF_Hp1, or CoF_Hp2≧1.5×CoF_Hp1. Exemplary ranges include, but are not limited to, CoF_Hp2 of from 1.05×CoF_Hp1 to 1.5×CoF_Hp1, 1.10×CoF_Hp1 to 1.20×CoF_Hp1, or about 1.15×CoF_Hp1.

Thus, the anti-balling composition may comprise a first hardphase and optionally a second hardphase in any convenient amounts. Certain anti-balling compositions comprise >about 25.0 wt % of a first hardphase, e.g., >about 50.0 wt %, >about 60.0 wt %, >about 75.0 wt %, >about 90.0 wt %, >about 95.0 wt %, >about 99.0 wt %, >about 99.5 wt %, based on the total weight of the first and second hard phases. Additionally or alternatively, the first hardphase may be present in an amount <about 100.0 wt %, e.g., <about 99.5 wt %, <about 99.0 wt %, <about 95.0 wt %, <about 90.0 wt %, <about 75.0 wt %, <about 60.0 wt %, <or about 50.0 wt %. Exemplary anti-balling compositions include about 25 to 100.0 wt %, about 50.0 to about 99.5 wt %, about 60.0 to about 99.0 wt %, about 75.0 to about 95.0 wt %, or about 90.0 wt % of the first hardphase and optionally 0 to about 75.0 wt %, about 0.5 to about 50.0 wt %, about 1.0 to 40.0 wt %, about 5.0 to about 25.0 wt %, or about 10.0 wt % of a second hardphase.

Matrix-Forming Composition

The bit body and other elements of the drill bit may be formed from a matrix-forming composition comprising particles of a second hardphase. As described above, the second hardphase may have a hardness greater than that of the first hardphase. Particular second hardphases useful as the matrix-forming composition may have a Knoop Value of >about 1500 Pa, e.g., >about 1750 Pa, >about 1900 Pa, >about 2000 Pa, >about 2100 Pa, >about 2300 Pa, >about 2500 Pa, >about 2750 Pa, or >about 3000 Pa.

Additionally or alternatively, the second hardphase may have a Knoop Value <about 3000 Pa, e.g., <about 2750 Pa, <about 2500 Pa, <about 2500 Pa, <about 2100 Pa, <about 2000 Pa, <about 1900 Pa or <about 1750 Pa. Exemplary second hardphases may have a Knoop Value of about 1800 to about 2500 Pa, about 1900 to about 2200 Pa, or about 1900 to about 2100 Pa. The particle size distributions may be optimized to provide high powder packing with tap densities of about 10.0 g/cc and hardphase particle size distributions ranging from about 80 Mesh (177 μm) to about 625 Mesh (20 μm).

Infiltrant

Components of the drill bit may also include an infiltrant in addition to the matrix forming material and the anti-balling composition. For example, a copper alloy may be used as the infiltrant. An example infiltrant is a Cu/Mn/Ni/Zn alloy composition (or binder alloy) comprising about 49 wt % Cu, about 25 wt % Mn, about 13 wt % Ni, and about 13 wt % Zn. Another suitable alloy comprises about 53 wt % Cu, about 24 wt % Mn, about 15 wt % Ni, and about 8 wt % Zn. Other infiltrants include non-magnetic chromium-rich infiltrants. As described further herein, the infiltrant may be melted, and the matrix composition and the anti-balling composition may be infiltrated with the molten infiltrant. Upon cooling, the infiltrant may bond the particles of the matrix composition and anti-balling composition into an integral unit.

While non-magnetic chromium-rich infiltrants are provided, portions of the compositions about the drill bit may include binders, such as magnetic and/or chromium rich infiltration binders (e.g., 53CU, 24MN, 15 NI, 8Zn).

Method of Making an Anti-Balling Drill Bit

The anti-balling drill bit (or infiltrated body) may be made using various methods, such as molding in any one of a number of types of molds. A method of making drill bits having anti-balling features is illustrated in FIGS. 4A and 4B. As shown in FIG. 4A, the method 400 involves start 410. Start 410 may involve any procedure prior to subsequent procedures, e.g., selecting and/or preparing the matrix composition, selecting and/or preparing the anti-balling composition, etc.

The method also includes 420 providing a mold having channel-forming regions, such as mold 411 as shown for example, in FIG. 4B. The mold 411 may be a canister or other container made of any material suitable for the manufacture of drill bits, e.g., graphite. The mold 411 may have a cavity 415 therein shaped in a negative impression of an outer surface of the drill bit 200 to receive materials therein to form the drill bit 200.

The method may also involve 430 providing the anti-balling composition 417 to one or more of the channel-forming regions 425 of the mold 411. The matrix-forming composition 419 may also be provided 440 to the mold. An infiltrant 421(e.g., powder binder) may also be provided 450 to the mold 411. The method may also include various options, such as providing one or more components (e.g., a steel blank) and/or positioning one or more additional components in the mold 411. Various combinations of layers of the various components in various order and/or depth may optionally be provided (e.g., from about 1 mm to about 10 mm of one or more of the components).

The mold 411 may be heated (H) 460 as indicated by the wavy lines to a temperature sufficient to melt the components and/or alloy causing the infiltrant to infiltrate the matrix-forming composition and the anti-balling composition as indicated by the dashed arrows in FIG. 4B. The mold 411 may be heated to temperatures of, e.g., about 1900 to about 2200° F. (e.g., about 1040 to about 1205° C.), 1950 to 2150° F. (e.g., about 1065 to about 1175° C.), or about 2100° F. (e.g., about 1150° C.). Times sufficient for heating the mold may be about 1 to about 5 hrs. (e.g., about 1 to about 3 hr., or about 2 hrs.) Optionally, prior to and/or during heating, the mold 411 may be vibrated as indicated by wave V to facilitate the packing of the contents in the mold 411.

Once formed, the drill bit may be removed from the mold 470. The mold 411 may be given time to cool, and the drill bit may be removed from the mold at any convenient temperature. The method 400 ends at 480. End 480 may additionally include one or more additional processes, such as finishing the drill bit 200 and/or fabrication (e.g., securing a steel shank 210 to the bit body 203 as shown in FIG. 2), bonding one or more cutting elements (e.g., cutting elements 204 on blades e.g., blades 206 of the bit body 203).

The drill bit 200 may be polished, for example, along the anti-balling material. Such polishing may be performed to provide a machinist finish to the drill bit 200 along the channel regions 207 where the anti-balling composition is placed. The finish may have, for example, an average surface roughness of <about 10 μm, e.g., <about 9 μm, <about 8 μm, <about 7 μm, <about 6 μm, <about 5 μm, or <about 4 μm. Additionally (or alternatively), the average surface roughness may be >about 3 μm, e.g., >about 4 μm, >about 5 μm, >about 6 μm, >about 7 μm, >about 8 μm, or >about 9 μm.

Portions of the method 400 (e.g., 430 to 450) may be performed in any convenient order provided that the resulting order produces a matrix drill bit as provided herein.

While FIGS. 4A and 4B show a specific method and arrangement of making the drill bit using the anti-balling composition 417 alone or in combination with the matrix compound 419 and/or infiltrant 421, the drill bit herein may be formed using a variety of combinations of the compositions described herein and at various configurations about the mold 411.

In an example method, a graphite mold is provided and a chromium carbide mix is created to form the drill bit. Junk slots and waterways in the mold are coated with the anti-balling compound. Cast carbide bits and binder are loaded into the mold. The mold is loaded into a furnace and infiltrated at 2100 degrees F. (1148.89 degrees C.) for 2 hours. The furnace is cooled to room temperature. The mold is broken and breaker slots on the molded bit are milled. The cutting elements are brazed onto the drill bit. The junk slots and waterways on the drill bit are ground and polished. The drill bit is then inspected.

Test Methods

Coefficient of Friction values herein may be determined using, for example, a Kyowa Automatic Friction Abrasion Analyzer Triboster, model TS501. The material to be tested is placed on a limestone, shale or sandstone surface under a load of 100 gf using a sliding speed 2 mm/s and a stroke length of 10 mm. Whatever stone surface is selected should be used for all measurements. Distilled water is used as a lubricant. Measurements are made at 26% humidity and 76° F. (25° C.).

EXAMPLES

Example 1

In Example 1, a matrix drill bit is prepared by providing an anti-balling composition to the channel forming regions of a graphite bit mold (see, e.g., 411FIG. 4B). The anti-balling composition comprises about 25 wt % chromium carbide, Cr₃C₂, and about 75 wt % tungsten carbide, WC. A matrix forming composition comprising tungsten carbide particles is also provided. After adding the Cu-containing infiltrant and causing the components to settle, the mold is heated in an electric furnace to about 2100° C. for about 2 hours to allow the infiltrant to permeate the matrix forming composition and the anti-balling composition. The mold is removed from the furnace and cooled before removing the mold from the matrix bit formed therein.

FIG. 5 shows a cross-sectional electron micrograph 500 of the anti-balling composition of Example 1. In FIG. 5, the micrograph 500 shows the anti-balling composition 417 applied along the channel regions and the underlying portions or the bit body 203 of the drill bit (see, e.g., FIGS. 2 and 4B). The anti-balling composition 417 includes tungsten carbide shown in the darker regions 580 represent tungsten carbide, chromium carbide particles shown as lighter regions 582, and the infiltrant 421 shown as the lightest gray.

The anti-balling composition, including the tungsten carbide and chromium carbide, may vary in thickness. As FIG. 5 shows the thickness at one point is about 1.65 mm while at other points the thickness is about 2.13 mm. Thus, the channel region including the anti-balling composition is different from a coating since coatings are generally uniform in thickness.

Example 2

FIG. 6 depicts a cross-sectional view of an electron micrograph 600 of the anti-balling composition as described in Example 1. As in FIG. 5, in FIG. 6, the tungsten carbide appears as the darkest gray regions 580, the chromium carbide is the lighter gray regions 582, and the infiltrant 421 is the lightest. As also shown in Example 1, the thickness of the anti-balling composition 417 varies significantly across the channel region.

Example 3

FIG. 7 depicts a cross-sectional micrograph 700 of the anti-balling composition. FIG. 7 is formed as described in Example 1, except that the anti-balling composition comprises about 75 wt % chromium carbide and about 25 wt % tungsten carbide. In this micrograph 700, the darker regions 580 represent the chromium, while the lighter regions 582 are the infiltrant 421 and the tungsten carbide.

Without wishing to be held to any particular theory, it is believed that the presence of the second hardphase may lower the tendency of balling in soft clays and shale due to the more negative electrochemical potential of the hard phase. The drill bit herein can be made to include the anti-balling composition in various regions, such as in the channel regions in essentially a single process, i.e., without the need for complicated layer-forming processes.

Although a few example embodiments have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible in the example embodiments without materially departing from this disclosure. Accordingly, such modifications are intended to be included within the scope of this disclosure as defined in the following claims.

In the claims, means-plus-function clauses are intended to cover the structures described herein as performing the recited function and not simply structural equivalents, but also equivalent structures. Thus, although a nail and a screw may not be structural equivalents in that a nail employs a cylindrical surface to secure wooden parts together, whereas a screw employs a helical surface, in the environment of fastening wooden parts, a nail and a screw may be equivalent structures. It is the express intention of the applicant not to invoke 35 U.S.C. §112, paragraph 6 for any limitations of any of the claims herein, except for those in which the claim expressly uses the words ‘means for’ together with an associated function.

It will be appreciated by those skilled in the art that the techniques disclosed herein can be implemented for automated/autonomous applications via software configured with algorithms to perform the desired functions. These aspects can be implemented by programming one or more suitable general-purpose computers having appropriate hardware. The programming may be accomplished through the use of one or more program storage devices readable by the processor(s) and encoding one or more programs of instructions executable by the computer for performing the operations described herein. The program storage device may take the form of, e.g., one or more floppy disks; a CD ROM or other optical disk; a read-only memory chip (ROM); and/or other forms of the kind well known in the art or subsequently developed. The program of instructions may be “object code,” i.e., in binary form that is executable more-or-less directly by the computer; in “source code” that requires compilation or interpretation before execution; or in some intermediate form such as partially compiled code. The precise forms of the program storage device and of the encoding of instructions are immaterial here. Aspects of the invention may also be configured to perform the described functions (via appropriate hardware/software) solely on site and/or remotely controlled via an extended communication (e.g., wireless, internet, satellite, etc.) network.

The above description is illustrative of the preferred embodiment and many modifications may be made by those skilled in the art without departing from the invention whose scope is to be determined from the literal and equivalent scope of the claims that follow.

While the embodiments are described with reference to various implementations and exploitations, it will be understood that these embodiments are illustrative and that the scope of the inventive subject matter is not limited to them. Many variations, modifications, additions and improvements are possible, such as such as amount, composition, location, and shape of the anti-balling composition and/or the optional matrix compound and/or infiltrant about the drill bit and/or other downhole components.

Plural instances may be provided for components, operations or structures described herein as a single instance. In general, structures and functionality presented as separate components in the exemplary configurations may be implemented as a combined structure or component. Similarly, structures and functionality presented as a single component may be implemented as separate components. These and other variations, modifications, additions, and improvements may fall within the scope of the inventive subject matter.

For the sake of brevity, only certain ranges are explicitly disclosed herein. However, ranges from any lower limit may be combined with any upper limit to recite a range not explicitly recited, as well as, ranges from any lower limit may be combined with any other lower limit to recite a range not explicitly recited, in the same way, ranges from any upper limit may be combined with any other upper limit to recite a range not explicitly recited. Additionally, within a range includes every point or individual value between its end points even though not explicitly recited. Thus, every point or individual value may serve as its own lower or upper limit combined with any other point or individual value or any other lower or upper limit, to recite a range not explicitly recited.

All documents described herein are incorporated by reference herein, including any priority documents and/or testing procedures to the extent they are not inconsistent with this text, provided however that any priority document not named in the initially filed application or filing documents is NOT incorporated by reference herein. As is apparent from the foregoing general description and the specific embodiments, while forms of the invention have been illustrated and described, various modifications can be made without departing from the spirit and scope of the invention. Accordingly, it is not intended that the invention be limited thereby. Likewise, the term “comprising” is considered synonymous with the term “including” for purposes of Australian law. Likewise whenever a composition, an element or a group of elements is preceded with the transitional phrase “comprising”, it is understood that we also contemplate the same composition or group of elements with transitional phrases “consisting essentially of,” “consisting of, “selected from the group of consisting of,” or “is” preceding the recitation of the composition, element, or elements and vice versa.

Claims

1. A drill bit for drilling a well bore penetrating a subterranean formation, the drill bit

2. The drill bit of claim 1, wherein the first hardphase material comprises a chromium carbide.

3. (canceled)

4. (canceled)

5. The drill bit of claim 1, wherein the first hardphase material comprises Cr, Cr3C2 or a mixture thereof.

6. (canceled)

7. The drill bit of claim 1, wherein the chemical potential of the first hardphase material is 5% to 75% less than the chemical potential of the second hardphase material.

8. The drill bit of claim 1, wherein the second hardphase material has a hardness greater than a hardness of the first hardphase material.

9. The drill bit of claim 1, wherein the first hardphase material has a hardness from 900 Pa to 4000 Pa and a hardness of the second hardphase material is between 1500 Pa to 3000 Pa.

10. The drill bit of claim 1, wherein the first hardphase material has a kinetic coefficient of friction that is 85% to 95% of the kinetic coefficient of friction of tungsten carbide and the second hardphase material has a kinetic coefficient of friction that is greater than the kinetic coefficient of friction of the first hardphase material.

11. The drill bit of claim 10, wherein the kinetic coefficient of friction of the second hardphase material is 105% to 150% of the kinetic coefficient of friction of the first hardphase material.

12. The drill bit of claim 1, wherein the first and the second hardphase materials comprise hardphase particles with a tap density of 10.0 g/mL.

13. The drill bit of claim 1, wherein the first and the second hardphase particles comprise a particle size distribution of 177 μm to 20 μm.

14. The drill bit of claim 1, wherein the drill bit is one of a matrix drill bit or an infiltrated drill bit.

15. (canceled)

16. (canceled)

17. The drill bit of claim 1, wherein the anti-balling composition is disposed along the channels.

18. The drill bit of claim 1, wherein the anti-balling composition is formed into the bit body.

19. The drill bit of claim 1, wherein the anti-balling composition defines an outer surface of the drill bit, wherein the outer surface has an average surface roughness of less than 4 μm to 10 μm.

20. A method of manufacturing a drill bit for drilling a wellbore penetrating a subterranean formation, the method comprising: providing a mold having a bit pattern including channel-forming regions defined therein;providing an anti-balling composition in the channel-forming regions of the mold, wherein the anti-balling composition comprises a first hardphase material and a second hardphase material, wherein the first hardphase material has a chemical potential that is more electronegative than the second hardphase material;wherein the first hardphase material comprises one or more of the group consisting of chromium, tantalum carbides, zirconium carbides, aluminas, chromium carbides, beryllium carbides, titanium carbides, silicon carbides, aluminum borides, and boron carbides;wherein the second hardphase material comprises tungsten carbide;providing a matrix forming composition;forming the drill bit by heating the mold; andremoving the mold from the formed drill bit.

21. The method of claim 20, further comprising providing an infiltrant in the mold.

22. The method of claim 20, wherein the heating comprises heating the mold to between 1040° C. to 1175° C. for 1 to 5 hours.

23. The method of claim 20, further comprising polishing the drill bit.

24. An anti-balling composition for a drill bit for drilling a wellbore penetrating a subterranean formation, the anti-balling composition comprising: one or more first hardphase materials selected from the group consisting of chromium, tantalum carbides, zirconium carbides, aluminas, chromium carbides, beryllium carbides, titanium carbides, silicon carbides, aluminum borides, and boron carbides; anda second hardphase material comprising tungsten carbide.

25. The anti-balling composition of claim 24, wherein the first hardphase material comprises Cr, Cr3C2 or a mixture thereof.

26. The anti-balling composition of claim 24, wherein the first hardphase material has a chemical potential that is more electronegative than a chemical potential of the second hardphase material.

27. (canceled)

28. The anti-balling composition of claim 26, wherein the composition comprises from greater than 0 to 25 wt % of the second hardphase material and from 75 to less than 100 wt % of the combined one or more of the first hardphase materials, based on the total weights of the first and the second hardphase materials.

29. The anti-balling composition of claim 26, wherein the chemical potential of the first hardphase material is from 5% to 75% less than the chemical potential of the second hardphase material.

30. The drill bit of claim 1, wherein the anti-balling composition comprises 50 to 99.5 wt % of the first hardphase material and 0.5 to 50 wt % of the second hardphase material.

31. The method of claim 20, wherein the first hardphase material comprises Cr, Cr3C2 or a mixture thereof.

32. The method of claim 20, wherein the chemical potential of the first hardphase material is 5% to 75% less than the chemical potential of the second hardphase material.

33. The method of claim 20, wherein the second hardphase material has a hardness greater than a hardness of the first hardphase material.

34. The method of claim 20, wherein matrix forming composition includes the second hardphase material.

35. The method of claim 20, wherein the anti-balling composition comprises 50 to 99.5 wt % of the first hardphase material and 0.5 to 50 wt % of the second hardphase material.