US3469642A - Hydraulic drilling bit and nozzle - Google Patents

Hydraulic drilling bit and nozzle Download PDF

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US3469642A
US3469642A US3469642DA US3469642A US 3469642 A US3469642 A US 3469642A US 3469642D A US3469642D A US 3469642DA US 3469642 A US3469642 A US 3469642A
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nozzles
nozzle
inch
inches
bit
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Robert J Goodwin
Joseph L Pekarek
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Chevron Research and Technology Co
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Gulf Research and Development Co
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    • EFIXED CONSTRUCTIONS
    • E21EARTH DRILLING; MINING
    • E21BEARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B10/00Drill bits
    • E21B10/60Drill bits characterised by conduits or nozzles for drilling fluids
    • E21B10/61Drill bits characterised by conduits or nozzles for drilling fluids characterised by the nozzle structure
    • BPERFORMING OPERATIONS; TRANSPORTING
    • B05SPRAYING OR ATOMISING IN GENERAL; APPLYING LIQUIDS OR OTHER FLUENT MATERIALS TO SURFACES, IN GENERAL
    • B05BSPRAYING APPARATUS; ATOMISING APPARATUS; NOZZLES
    • B05B1/00Nozzles, spray heads or other outlets, with or without auxiliary devices such as valves, heating means
    • B05B1/02Nozzles, spray heads or other outlets, with or without auxiliary devices such as valves, heating means designed to produce a jet, spray, or other discharge of particular shape or nature, e.g. in single drops, or having an outlet of particular shape
    • B05B1/10Nozzles, spray heads or other outlets, with or without auxiliary devices such as valves, heating means designed to produce a jet, spray, or other discharge of particular shape or nature, e.g. in single drops, or having an outlet of particular shape in the form of a fine jet, e.g. for use in wind-screen washers
    • EFIXED CONSTRUCTIONS
    • E21EARTH DRILLING; MINING
    • E21BEARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B10/00Drill bits
    • E21B10/60Drill bits characterised by conduits or nozzles for drilling fluids
    • EFIXED CONSTRUCTIONS
    • E21EARTH DRILLING; MINING
    • E21BEARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B7/00Special methods or apparatus for drilling
    • E21B7/18Drilling by liquid or gas jets, with or without entrained pellets

Description

Sept. 30, 1969 R. J. GOODWIN ET AL HYDRAULIC DRILLING BIT AND NOZZLE Filed Oct. 15, 1968 HIGH " PRESSURE PUMPS DRILLING SLURRY TREATMENT 3 Sheets-Sheet 1 INVENTORS ROBERT J. GOODWIN v JOSEPH L. PEKAREK p 0,1969 R. J. eooowlN erm. 3,469,642

HYDRAULIC DRILLING BIT AND NOZZLE Filed Oct. 15, 1968 3 Sheets-Sheet 5 FIG.60 lzzq United States Patent U.S. Cl. 175-393 13 Claims ABSTRACT ()F THE DISCLOSURE Nozzles for drill bits used in the hydraulic jet drilling of wells. The nozzles have a long converging entrance section formed by a convex surface of large radius of curvature opening at its outlet end into a throat section of constant diameter. Data are presented showing reduced rates of wear of the nozzles and increased rates of penetration as compared with nozzles heretofore used.

This application is a continuation-in-part of our copending application Ser. No. 591,758, filed Nov. 3, 1966, now abandoned and entitled Hydraulic Drilling Bit and Nozzle.

This invention pertains to improvements in bits and nozzles for use in hydraulic jet drilling of wells by use of a high-velocity jet carrying an abrasive,

In hydraulic jet drilling, several advantages are obtained over prior mechanical methods. These advantages include the elimination of substantially all mechanical cutting elements, which permits construction of drill bits which operate more efiiciently and for longer periods of time. Such jet drilling bits also permit use of lighter drilling apparatus, thus effecting economies throughout the process, such as in power requirements, cost of drill collars, and the like. The number of drill collars can be reduced to reduce weight because the jet drilling process does not depend upon heavy weight on the bit to help the cutting action as do mechanical processes. In the jet drilling method, hydraulics are used to create grooves to leave only small ridges which are easily removed by a small mechanical force.

For many years, most oil and gas wells have been drilled by the rotary drilling method in which a bit mounted on the lower end of drill pipe is rotated against the bottom of the borehole while a fluid, usually referred to as drilling mud, is circulated down the drill pipe and upwardly through the annulus bet-ween the drill pipe and the borehole wall to carry cuttings from the borehole. The penetration into the bottom of the borehole is by means of mechanical elements of the bit which break off chips and/or crush the formation. For example, in a fishtail bit, blades extend downward from the bottom of the bit. Rock bits comprise rollers having cutting teeth extending from their outer surface. With both these bits, a substantial weight, on the order of 3,000 to 10,000 pounds per inch of bit diameter, is applied to increase the force of the cutting elements against the formation.

In hydraulic jet drilling, an abrasive-laden slurry is directed in narrow streams at extremely high velocities against the bottom of the hole from nozzles in the rotating bit to penetrate the formation by the abrasive action of the suspended particles, rather than by mechanical cutting or grinding elements. Hydraulic jet drilling allows substantially higher penetration rates of hard formations than are obtainable with conventional bits. However, the highly erosive nature of the process severe-1y limits the life of both the bit and the nozzles. When the nozzles become so eroded and enlarged that the pumping equipment is no longer able to develop the required cutting jet velocity through the nozzle exits because of the pressure losses associated with the higher flow rates through the drill pipe required to maintain the necessary high velocity through the enlarged nozzles, then the bit must be replaced. In the present state of the art, the life of the bit is determined by the life of the nozzles. Replacing a bit is an expensive operation because it requires pulling the entire string of drill pipe out of the hole, and the drill string can be thousands of feet long. Thus, drill bit replacement requires a large amount of time, which lost time costs many thousands of dollars, depending on the depth of the hole.

It is therefore an object of this invention to provide jet drilling bits and nozzles having increased life; to reduce the number of bit and nozzle replacements required during the drilling of a well; to provide high drilling rates; and to allow a high rate of penetration, at a minimum power consumption.

This invention comprises a novel bit for drilling wells with hydraulic jets of abrasive-laden fluid, comprising a hollow bit body closed at its lower end and having a plurality of nozzles extending through the lower end and opening downwardly in position to cut a plurality of concentric grooves in the bottom of the borehole as the bit is rotated. Each of the nozzles comprises an elongated body formed with an internal profile embodying the invention which will operate in jet drilling bits for long periods of time without excessive erosion. An important and essential feature of the present invention resides in the novel internal profile of the nozzles embodying the invention. This profile comprises an arcuate entrance section and a cylindrical throat portion tangent to the arcuate entrance section. The arcuate section is in the form of an arc of a circle of large diameter. Nozzles embodying the invention will have an increased life characteristic to further increase the advantages of hydraulic jet drilling.

In the attached drawings forming a part of this disclosure, except as specifically pointed out hereinafter:

FIGv 1 is a diagrammatic view, partially in cross section, of apparatus for drilling wells with the drill bit and nozzle of this invention; FIG. 2 is a vertical sectional view of the drill bit attached to an adapter for connection to the lower end of drill pipe; FIG. 3, is a bottom view of the embodiment of the drill bit illustrated in FIG. 2; FIG. 4 is an outlet end view of a nozzle embodying the invention; FIG. 5 is a longitudinal, cross-sectional view taken on line 55 of FIG. 4; and FIGS. 60 through 6d are diagrammatic representations of other nozzles not embodying the invention having various different internal profiles which were tested, and which show the improved life characteristic of nozzles embodying the present invention.

Referring to FIG. 1, a derrick 10 is shown in place above a well having casing 14 and drill pipe 16 therein. A drill bit 18 is connected to the lower end of drill pipe 16 and rests on the bottom of the well.

The upper end of casing 14 is closed by a casing head 20, which usually includes blowout preventers and other conventional wellhead equipment well known to those skilled in this art. A discharge line 22 delivers drilling slurry carrying abrasive and entrained cuttings to apparatus labeled, Drilling Slurry Treatment. Such treatment consists of removal of cuttings and excessive fine particles, cooling, and adding slurry treating materials, fresh slurry to make up any losses, and fresh abrasive. The slurry is then delivered to the High Pressure Pumps, and discharged by the pumps through line 26 into the upper end of drill pipe 16. Means are provided to rotate the drill pipe in the usual manner. In hydraulic jet drilling, in contrast to conventional rotary drilling, the weight on the drill bit is not substantial; 1,000 pounds per inch of bit diameter, or less, approximately one-fifth the weight used in conventional rotary drilling, is adequate.

The drilling slurry contains an abrasive such as sand, ferrous grit, or ferrous shot which is discharged at extremely high velocities from the nozzles. This velocity is at least 500, and preferably 600 to 900 feet per second. The particle size of abrasive depends upon the exit openings of the nozzles. It is desirable to use the largest abrasive particles that will pass through the nozzles and pumps because drilling rate is faster with larger particles. In a typical operation in which the nozzles have an internal diameter of inch, abrasive particles having a size in the range of to 80 mesh, and preferably to 40 mesh, can be used.

Bit 18 comprises a lower cylindrical section 28 joined to the lower end of a central adapter section 30 which is joined to the lower end of an upper cylindrical section 32. Bit 18 is closed at the lower end by a bottom member 34, and at the upper end by a top 36 having a threaded, centrally positioned, upwardly opening box 38 to receive the threaded lower end of drill pipe 16. Bit 18 illustrated in FIG. 2 of the drawings comprises an elongated internal chamber 40 of relatively large diameter, provided with an internal strengthening web 42. Means are provided to permit flow of slurry and cuttings upwardly around the bit, and comprise diametrically opposed fiutes 44 in alignment with web 42.

Secured to the bottom member 34 by means of a suitable silver solder, bolts, or other suitable means, is a backsplash plate 46 of a hard abrasive and impact resistant material such as tungsten carbide. Plate 46 should have a substantial thickness, at least 1 inch and preferably 1 to 2. inches, to prevent erosion of the sides of the drill bit. Abrasives and cuttings carried upwardly around the drill bit do not cause serious erosion; hence, a backsplash plate thicker than 2 inches is not needed.

Protruding downwardly from the lower surface of plate 46, and preferably integral therewith, are a pair of standofi bars 48 which determine the distance between the outlets of the nozzles and the bottom of the borehole. Stand-off bars 48 project downwardly a distance of about 4 inch to about 1% inches, and preferably a distance in the range of about inch to about 1 inch. At lower thicknesses, erosion of the bottom and side walls of the bit is severe because of backsplash from the hole bottom, and at thicknesses greater than about 1% inches, the rate of cutting is seriously reduced because the nozzles are too far from the hole bottom.

Stand-off bars 48 are positioned directly below the flutes 44, since that space cannot be occupied by nozzles, to thus make the most eflfective use of the space available.

Bottom member 34 and backsplash plate 46 are drilled or otherwise formed to receive a plurality of nozzles 50. The lower ends of the receptacles for the nozzles 50 are tapered to match taper 15 on the nozzles, described below, to prevent downward movement of the nozzles during drilling. Leakage is prevented by a suitable sealant, such as an epoxy cement or silver solder. The taper at the lower end of the receptacles positions the nozzles with their outlet faces substantially in the plane of the lower surface of plate 46.

Nozzles 50 are substantially entirely within the bit body in that the outlet ends of the nozzles are substantially flush with the bottom surface of the backsplash plate. The nozzles are positioned and oriented in the drill bit to accomplish several purposes. The total number of nozzles and their individual location and orientation is dependent upon the size of borehole to be drilled. Some nozzles are positioned to cut a groove having an outer diameter about to /2 inch larger than the largest diameter of the drill bit. For this purpose, outwardly slanting nozzles 50a are positioned near the outer edge of the backsplash plate. Other nozzles are positioned to cut grooves in the bottom of the borehole spaced apart a small enough distance to allow the stand-off bars to break the intervening ridges. A plurality of outwardly slanting nozzles 50b are positioned at a smaller distance from the center of rotation of the drill bit than nozzles 50a, see FIG. 3. Still closer to the center of rotation are outwardly slanting nozzles 50c adapted to cut a groove spaced inwardly from the groove cut by nozzles 50b. Still nearer the center of rotation is a nozzle 50d slanting inwardly to cut a hole in the center of the borehole extending outwardly beyond the inner ends 52 of the stand-off bars 48. Nozzle 50d is positioned to direct the slurry between the inner ends of the stand-off bars so as not to erode them. A vertical nozzle 50e is positioned to cut a groove between the groove cut by nozzles 50c and the hole cut by nozzles 50d to reduce the width of the ridge created by nozzles 50d and 500. In general, the number of nozzles at any particular radial distance from the center of rotation of the bit increases, but not necessarily directly, as the radial distance increases because of the larger amount of rock that must be removed in the outer grooves, to cut grooves of substantially the same depth below the bit.

The extension of nozzles 50 above the upper surface of bottom member 34 has been found to reduce nozzle plugging. The extension also positions the inlet ends of the nozzles nearer the center of the bit body to cause flow at substantially uniform rates through all the nozzles. In this manner, the depth of grooves cut can be made substantially the same, and optimum stand-ofif from the bottom of the hole for all of the nozzles is obtained to give a high rate of penetration.

In FIGS. 4 and 5 there is shown one nozzle 50, which could be any one of nozzles 50a to 50a, which is not drawn to scale, and represents a relatively large family of nozzles embodying the invention and which have been found to be particularly advantageous.

Nozzles embodying the invention and having the greatly increased life characteristic comprise an internal profile, which consists of an entrance section whose profile is an arc of a circle, the outlet end of which iS tangent to the inlet end of a cylindrical throat section. The combination of the arcuate entrance section profile, and the cylindrical throat with its entrance end tangent to the exit end of the entrance section, imparts increased life to nozzles embodying the invention. It is thought that this advantageous result at least partially resides in the provision of a particular radius of curvature in the entrance section which prevents the creation of localized areas of high wear which prematurely end the life of the nozzle. The arcuate entrance section thus increases life by causing the entire entrance section of the nozzle to wear uniformly. The provision of the cylindrical throat tangent to the exit end of the entrance section aids in increasing life by delaying the time at which the wearing action of the abrasive particles reaches the exit diameter in the outlet face of the nozzle. The nozzle can function with reasonable wear rearwardly of that exit diameter,

since it determines the final cross-sectional area of the jet. It has been found that a high wear region tends to be created at the point in the nozzle at which the decreasing cross-sectional area of the entrance section changes to the constant cylindrical cross-sectional area of the throat. By providing a throat, as opposed to having no throat, this region of high wear tends to walk" toward the exit diameter in the outlet face of the nozzle, thus prolonging the life of the nozzle.

Thus, it is the combination of the arcuate entrance section of a particular radius with the cylindrical throat section of a particular length which yields the advantages of increased life to nozzles embodying the invention.

Nozzle 50 is cylindrical and comprises an entrance diameter D, an exit diameter d, an entrance length L, a cylindrical throat portion of diameter d and length T, an outside diameter OD, and an external taper 15, described above. The cross-sectional shape of the nozzle between the entrance end of the throat and the entrance diameter D is an arc of a circle having a radius R. One end of this are is tangent to the cylindrical throat at its entrance end, and the other end intersects the entrance diameter D.

Nozzle life increases in proportion to increase in length L. Practical considerations, such as manufacturing problems, increased cost, increased fragility, and the necessity to set a plurality of nozzles into the bit without interference with each other and the outside wall of the bit, determine an upper limit to the increase of length L. Also, as length increases at a given outside diameter, the internal profile will approach a cylinder, which profile is not as long lived as the profile of the invention, as will appear more clearly from the test data below. Also as length increases, the pressure loss increases, which comprises another practical limitation on length L. Lengths L within the range of about 1% inches to about 4 /2 inches are suitable, and length L in the range of about 2%. inches to about 3 /2 inches are preferred.

Throat T increases nozzle life as explained above. However, there appears to be a maximum length of throat T for any particular nozzle beyond which the nozzle wears permaturely. The reason for this is thought to be that in such long throats, the abrasive particles bulfet about, which causes them to lose momentum, and which also causes them to enlarge diameter throughout throat T as well as in the outlet face of the nozzle. It is also thought that the flow stream passing through an overly long throat may experience a vena contracta, and the resultant downstream expansion will cause excessive wear at the outlet face, the most critical area. Throat lengths T in the range of about /2 inch to about 1V2 inch are suitable, and throat lengths T in the range of about 4 inch to about 1% inches are preferred for nozzles having an outlet diameter of inch.

It has been found that drilling rate alone is relatively insensitive to changes in nozzle exit diameter. The considerations in establishing a lower limit to the size of exit diameter 0. includes the fact that if the diameter is made smaller, the size of abrasive particles used must be made smaller, and very small abrasive particles have been found to reduce drilling rate. Also, it has been found that very small nozzles do not drill efficiently because they are very sensitive to interference between their flow streams, and also very sensitive to stand-off. An increase in dimension d causes an increase in the exit cross-sectional area proportional to the square of the radius, zi/ 2; therefore, a relatively small increase in dimension d of each nozzle will generate a relatively large total increase in the pump output requirement. In addition, the drill bit carries a plurality of nozzles, as described above. In hydraulic jet drill bits the number of nozzles ranges from 12 to 30. The total flow is thus broken into a relatively large number of relatively small jets. For most efiicient drilling by the hydraulic jet method exit diameters d in the range of about inch to about A inch have been found to be suitable, and exit diameters d in the range of about of an inch to about of an inch are preferred.

The entrance diameter D is the largest internal opening of the nozzle. Entrance diameters D in the range of about inch to about /2 inch are suitable, and entrance diameters D in the range of about inch to /2 inch are preferred. Dimension OD, described below, determines an upper limit to dimension D'.

The profile of the entrance section of the nozzle is a circular arc tangent to the cylindrical throat T where it joins length L, and which passes through entrance diameter D. The radius R of this circle is shown in FIG. 5. Nozzles having values of R within the range of about 30 inches to 175 inches are suitable. Nozzles having values of R between about 50 inches and about 140 inches are preferred in nozzles restricted to lengths L in its preferred range.

As is clear from the geometry of the nozzle, the interrelationship between d, D, L, and R, is such that if any three of these parameters are selected, the fourth parameter can have but one value. The principal parameters in the design of a nozzle are d, T, L, and R.

Another parameter is the dimension OD. It is desirable to have OD as small as possible to avoid interference between nozzles in the drill head, and to conserve the material of which the nozzle is fabricated. The dimension OD is controlled by the internal configuration or profile of the nozzle and by manufacturing considerations; for example, an excessively high slimness ratio will cause warping of the nozzle during manufacture. A cylindrical external shape is preferred because of ease of insertion into the bit, and because of economy of use of material. ODs in the range of about A inch to about inch are suitable, and ODs in the range of about inch to about /2 inch are preferred. In some cases, where the entrance diameter D is large, the entrance end can be made somewhat bell-shaped, with the remainder of the nozzle remaining cylindrical.

Tapered portion 15 may describe a relatively small included angle; an angle of from 6 to 8 has been found satisfactory. This tapered portion is used to hold the nozzle wedged in the drill bit, as described above. As will be clear to one skilled in the art, other means, such as cooperating shoulders, sealants, or the like, could be used to hold the nozzle in the bit.

From the ranges of dimensions of the various parameters given above, certain dimensionless ratios can be drawn for use in fabricating other nozzles embodying the invention. These ratios are suitable ranges. One preferred range is given for each ratio.

Preferred 50ZZ l5 20-32 In FIG. 6a is shown a nozzle 121, which comprises a cylinder. The outside diameter was about /2 inch, d was about /a inch, and L was about 1 inch. Nozzle 121 and all the nozzles in the following figures were fabricated from the same grade of sintered tungsten carbide. This nozzle was tested for 60 minutes by discharging water containing 6% of 20-40 mesh sand through the nozzle at a rate resulting in a pressure drop through the nozzle of 5000 psi. Measurements were taken about every 5 minutes for the first l5, and about every 15 minutes thereafter.

In FIG. 6b is shown a nozzle 122 having an internal profile which was formed by portions of two circles, the centers of which were located on apposite sides of the profile to produce an inflection point along the profile. d was about inch, L was about .700 inch, and D was about .800 inch. This nozzle ran only 30 minutes, and measurements were taken as for nozzle 121.

In FIG. 60 is shown a nozzle 123, having an internal profile which was generated by a quarter section of an ellipse, the remainder of the ellipse being indicated by the dotted line. Nozzle 123 had a d of about A; inch, D about inch, and L about inch. This nozzle was run for minutes, and measurements were taken as for nozzle 121'.

The following tables sums up the testing of the above nozzles to wear rate. The term wear as used herein refers to the enlargement of dimension d in the outlet face of the nozzle.

Nozzle: Wear rate, mils/ hr. 121 15.2 122 103.0 123 12.3

Similar tests were run on the nozzles 50 of this invention with a wear rate of 1.62 mils/hr. The figures summarizing the testing of nozzles 121, 122 and 123 cannot be directly compared to the wear rate figures above for the nozzles 50 because the grade of tungsten carbide used in fabricating nozzles 121, 122, and 123 was ditferent than that used in fabricating the nozzles 50. 'However, addi tional testing not presented herein has shown that the grade of tungsten carbide used for nozzles 121, 122, and 123 consistently wore twice as fast as the grade used for the nozzles 50. Therefore, the two sets of figures can accurately be compared by merely doubling: the wear rates for the nozzles 50, or halving the wear rates for the three nozzles above. Making this correction, it can be seen that the nozzles embodying the internal profile of the invention have significantly lower Wear rates than the other internal profiles tested.

In FIG. 6b is shown a nozzle 124. A group of nozzles similar to nozzle 124 were used in comparative tests with nozzles embodying the invention, and show that a longer life is obtained from nozzles embodying the invention.

In the following tests all nozzles used had a T equal to about /2 inch, L equal to about 2 /2 inches, and d equal to about A; inch. The arcuate profile nozzles had an R of about inches. In all these tests, the slurry used was water based, and comprised 2% to 3% Flosal (a type of asbestos fiber), and 3% to 4% Bentonite, under a working pressure across the nozzle of 5,000 p.s.i. Two percent of each of the abrasives was included. In the first group of tests, the abrasive was 5-230 cast iron shot, having a hardness of about 63 on the R scale, and a size of 20 to mesh. In the second group of tests, G40 cast iron grit having the same hardness and a size of 20 to 40 mesh was used. In the third group of tests, the abrasive was the shot used in the first group of tests plus 6% of 2040 mesh sand, which is a higher sand content than would normally be found in field use with presently available separating equipment. Each group of tests was run with the same nozzles made of two different kinds of sintered tungsten carbide.

Linear Arcuate Material Material A B A B Time, Minutes Min. Max. Min. Max. Min. Max. Min Max.

'lotalNVear (.001 in.) 7. 25 6.0 5. 75 3. 5

Wear Rate, mils/hr 0. 363 0.30 288 0 175 2% 5-230 Cast Iron Shot.

Linear Arcuate Material Material A B A B Time, Minutes Min Max. Min. Max. Min Max. Min. Max

TotalWear (.001 in.) 13. 0 7. 25 6. 75 3. 5

Wear Rate, mils/1n 0. 86 484 45 23 2% G-40 Cast Iron Grit.

Linear Arcuate Material Material A B A B Time, Minutes Min. Max. Min. Max. Min. Max. Min. Max 124 1245 1225 .1235 .119 1195 1215 122 125 125 1235 124 120 .120 1225 1225 .126 126 1245 .125 121 .122 123 1235 128 128 1265 1265 1235 1235 124 1245 129 1295 1275 1275 124 124 125 125 130 1305 128 1285 1255 1255 1255 1255 131 129 129 1255 1255 126 126 130 130 126 126 127 127 1305 .1305 1265 .1265 127 127 .131 131 127 127 1275 128 131 1315 1275 .1275 128 1285 132 1325 129 129 129 1295 134 .1345 130 130 130 130 135 135 131 131 .1305 .131 1355 1355 131 131 131 131 136 136 131 1315 131 1315 1315 1315 1315 132 TotalWear (.001 in.) 13. 25 13. 0 12. 25 10. 0

Wear Rate mils/hr 1. 71 1. 35 1. 22 1. 00

2% S-230 Cast Iron Shot Plus Sand.

The above data show that with shot the wear rate for the linear taper is about 71% greater than that for the arcuate profile with material B, and about 26% for material A. When grit is used as the abrasive, the linear taper wears approximately 110% and 91% faster for the two materials, and when shot plus sand is used as the abrasive, the linear taper wears about 40% and 35% faster for the A and B materials, respectively. Also the wear rates of nozzles embodying the invention were significantly lower than those of the other profiles tested, although slightly diiferent abrasives were used. It can also be seen that the type of material has an etfect on life, but this parameter does not form a part of the present invention.

The wear rate of arcuate profile nozzles can be reduced below those rates obtained during the tests reported by increasing the radius R of the arcuate profile. For example, nozzles having an L=2 /2", T= /2", d=%", and R=60 were found to wear at a rate in a 46-hour test approximately 70% of the wear rate of the nozzles having the same dimensions but an R=30". Nozzles having an L=2 /2 inches, T=1 inch, d=% inch and R=100 inches were found to wear at a rate 40% of the wear rate of nozzles of the same dimensions except R=30 inches.

In addition to having a low wear rate, it is also highly desirable that nozzles 50 used in bit 18 have as high a cutting or penetration rate as possible. The two factors of wear rate and cutting rate are basically independent yet interrelated. That is, a nozzle must both run for a reasonable time without excessive Wear, and also cut a reasonable speed, to be economically practical. Either a high cutting rate or a low wear rate alone is not sufficient.

A nozzle having the arcuate profile of nozzle 50 of FIGS. 4 and 5 was tested against three other nozzles having other internal profiles, and the results are reproduced below:

Drilling Rate, Volume Removal in. see. Rate, cc./sec.

Nozzle 1 was of the type shown in FIG. 5 R=30% inches, T= /2 inch, L=2 /2 inches, d=% inch, D=.330, and OD= /z inch. Nozzle 2 was a plain cylinder, L=3 inches, d= Aa inch. Nozzle 3 was of the type shown in FIGS. 6d, d=% inch, D=% inch, T= /z inch, L=3 inches, and OD:% inch. Nozzle 4 was of the type shown in FIG. 60, L= /z inch, OD=% inch, d= As inch.

All parameters of the test were constant except grades of tungsten carbide used. Grade of material was not a factor however, because all the tests were of short duration, less than 1 minute, and none of the nozzles experienced any measurable wear. The test constants were: Black Granite target, nozzle rotated at 26 r.p.rn. on 1 /2 inch radius thus cutting 3 inch circle, working pressure of 5 000 p.s.i., /2 inch standoff nozzle to target, slurry was Flosal Bentonite with a 1% concentration of abrasive, and the abrasive was .028 inch average diameter steel shot with a hardness of 63.8 R

These tests show that nozzles embodying the invention will drill on the average of 30% faster than the other nozzles tested.

While the invention has been described in some detail above, it is to be understood that the protection granted is to be limited only within the spirit of the invention and the scope of the following claims.

We claim:

1. A nozzle for use in hydraulic jet drilling comprising an elongated body, said body being formed with a longitudinal opening extending through its length, the inlet end of said opening comprising an entrance orifice, the outlet end of said opening comprising an exit orifice having a diameter in the range of to 7 inch, said entrance orifice being of larger cross-sectional area than said exit orifice, said opening comprising a constant cross-sectional area throat portion extending from said exit orifice for a predetermined distance in the range of /2 inch to 1 /2 inches toward said entrance orifice, the profile of said opening between said entrance orifice and the inlet end of said throat portion being formed by a convex curved surface having a length in the range of 1 /2 inches to 4 /2 inches that is substantially an arc of a circle having one end tangent to the inlet end of said throat portion, and the radius of said are being in the range of about 30' inches to about 175 inches.

2. The combination of claim 1, wherein the length of said nozzle between said entrance orifice and the inlet end of said throat portion is in the range of about 2 /2 inches to about 3 inches.

3. The combination of claim 1, wherein said body is cylindrical and said opening is of circular cross section in all planes prependicular to the axis of said body.

4. The combination of claim 3, wherein the diameter of said entrance orifice is in the range of about inch to about /2 inch.

5. The combination of claim 1, wherein the radius of said are is in the range of about 50 inches to inches.

6. The combination of claim 1, wherein the radius of said are is in the range of about 50 inches to 140 inches, the length of the nozzle between the entrance orifice and the inlet end of the throat portion is about 2 /2 inches to 3 /2 inches, and the length of the throat portion is about 4 inch to 1% inches.

7. A drill bit for use in hydraulic jet drilling comprising a hollow drill bit body closed at its lower end by a bottom member having a plurality of nozzles extending through the bottom member, each of said nozzles comprising an elongated body, said body being formed with a longitudinal opening extending through its length, the inlet end of said opening comprising an entrance orifice, the outlet end of said opening comprising an exit orifice having a diameter in the range of inch to inch, said entrance orifice being of larger cross-sectional area than said exit orifice, said opening comprising a constant crosssectional area throat portion extending from said exit orifice for a predetermined distance in the range of /2 inch to 1 /2 inches toward said entrance orifice, the profile of said opening between said entrance orifice and the inlet end of said throat portion being formed by a convex curved surface having a length in the range of 1 /2 inches to 4 /2 inches that approximates an arc of a circle having one end tangent to the inlet end of said throat portion, and the radius of said an are being in the range of about 30 inches to about 175 inches.

8. The combination of claim 7, wherein the length of said nozzle between said entrance orifice and the inlet end of said throat portion is in the range of about 2 inches to about 3 /2 inches.

9. The combination of claim 7, wherein said body is cylindrical and said opening is of circular cross-section in all planes perpendicular to the axis of said body.

10. A drill bit for use in hydraulic jet drilling compris ing a bit member having a plurality of nozzles mounted in the lower end thereof, said bit member comprising an elongated tubular body adapted to be connected to the lower end of a drill string, said tubular body having a central opening extending downwardly therethrough cornmunicating with the drill string and with said nozzles, each of said nozzles comprising an elongated nozzle body, said nozzle body being formed with a longitudinal opening defining an entrance orifice at its inlet end and an exit orifice having a diameter in the range of inch to 7 inch at its outlet end, said opening further comprising a constant cross-sectional area throat portion extending for a predetermined distance in the range of /2 inch to 1 /2 inches from said exit orifice toward said entrance orifice, the profile of said opening between said entrance orifice and the inlet end of said throat portion being formed by a convex curved surface having a length in the range of 1 /2 inches to 4 /2 inches that is substantially an arc of a circle having one end tangent to the inlet end of said throat portion, and the radius of said arc being in the range of about 30 inches to about 175 inches; said nozzles being positioned in said bit member to cut an outer groove having a diameter slightly larger than the outside diameter of the drill bit, a central hole, at least one intermediate groove between the central hole and the outer groove, the lower end of said bit member comprising a bottom member and a backsplash plate on the outside side surface of said bottom member, said nozzles passing through said bottom member and said backsplash plate, said entrance orifices of said nozzles being positioned at a predetermined distance from the inside surface of said bottom member within said bit body, and said exit orifices of said nozzles being positioned substantially in the plane of the outer surface of said backsplash plate.

11. The combination of claim 10, and stand-off means extending downwardly from the outer surface of said backsplash plate, said stand-off means being positioned to overlap both the central hole cut by the inner nozzle and the outer groove cut by the outer nozzle.

12. The combination of claim 3, the ratio of the length of said nozzle between said entrance orifice and the entrance of said throat portion to the diameter of said throat portion being in the range of about 15 to about 40'.

13. The combination of claim 3, the ratio of the radius of said are to the diameter of said throat portion being in the range of about to about 400.

References Cited UNITED STATES PATENTS 1,104,965 7/1914 ColeS 239-589 2,583,726 1/1952 Chalom 23960l 3,066,735 12/1962 Zingg -422 3,112,800 12/1963 Bobo 175-422 3,178,121 4/1965 Wallace 239-601 3,300,142 1/1967 Brown 23960l JAMES A. LEPPINK, Primary Examiner US. Cl. X.R.

US3469642D 1968-10-15 1968-10-15 Hydraulic drilling bit and nozzle Expired - Lifetime US3469642A (en)

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US4111261A (en) * 1977-03-14 1978-09-05 Halliburton Company Wellhead isolation tool
US4262743A (en) * 1979-09-04 1981-04-21 Halliburton Company Diffuser for wellhead isolation tool
US4852800A (en) * 1985-06-17 1989-08-01 Flow Systems, Inc. Method and apparatus for stablizing flow to sharp edges orifices
US5199512A (en) * 1990-09-04 1993-04-06 Ccore Technology And Licensing, Ltd. Method of an apparatus for jet cutting
US5251817A (en) * 1991-09-16 1993-10-12 Ursic Thomas A Orifice assembly and method providing highly cohesive fluid jet
US5291957A (en) * 1990-09-04 1994-03-08 Ccore Technology And Licensing, Ltd. Method and apparatus for jet cutting
US5542486A (en) * 1990-09-04 1996-08-06 Ccore Technology & Licensing Limited Method of and apparatus for single plenum jet cutting
US5862871A (en) * 1996-02-20 1999-01-26 Ccore Technology & Licensing Limited, A Texas Limited Partnership Axial-vortex jet drilling system and method
US20060011386A1 (en) * 2003-04-16 2006-01-19 Particle Drilling Technologies, Inc. Impact excavation system and method with improved nozzle
US20060016622A1 (en) * 2003-04-16 2006-01-26 Particle Drilling, Inc. Impact excavation system and method
US20060180350A1 (en) * 2003-04-16 2006-08-17 Particle Drilling Technologies, Inc. Impact excavation system and method with particle trap
US20060191717A1 (en) * 2003-04-16 2006-08-31 Particle Drilling Technologies, Inc. Impact excavation system and method with two-stage inductor
US7383896B2 (en) 2003-04-16 2008-06-10 Particle Drilling Technologies, Inc. Impact excavation system and method with particle separation
US20080230275A1 (en) * 2003-04-16 2008-09-25 Particle Drilling Technologies, Inc. Impact Excavation System And Method With Injection System
US20090038856A1 (en) * 2007-07-03 2009-02-12 Particle Drilling Technologies, Inc. Injection System And Method
US20090126994A1 (en) * 2007-11-15 2009-05-21 Tibbitts Gordon A Method And System For Controlling Force In A Down-Hole Drilling Operation
US20090200080A1 (en) * 2003-04-16 2009-08-13 Tibbitts Gordon A Impact excavation system and method with particle separation
US20090200084A1 (en) * 2004-07-22 2009-08-13 Particle Drilling Technologies, Inc. Injection System and Method
US20090205871A1 (en) * 2003-04-16 2009-08-20 Gordon Tibbitts Shot Blocking Using Drilling Mud
US20100155063A1 (en) * 2008-12-23 2010-06-24 Pdti Holdings, Llc Particle Drilling System Having Equivalent Circulating Density
US7798249B2 (en) 2003-04-16 2010-09-21 Pdti Holdings, Llc Impact excavation system and method with suspension flow control
US20100294567A1 (en) * 2009-04-08 2010-11-25 Pdti Holdings, Llc Impactor Excavation System Having A Drill Bit Discharging In A Cross-Over Pattern
US7987928B2 (en) 2007-10-09 2011-08-02 Pdti Holdings, Llc Injection system and method comprising an impactor motive device
US8037950B2 (en) 2008-02-01 2011-10-18 Pdti Holdings, Llc Methods of using a particle impact drilling system for removing near-borehole damage, milling objects in a wellbore, under reaming, coring, perforating, assisting annular flow, and associated methods

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US3066735A (en) * 1960-05-25 1962-12-04 Dow Chemical Co Hydraulic jetting tool
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Cited By (38)

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Publication number Priority date Publication date Assignee Title
US4111261A (en) * 1977-03-14 1978-09-05 Halliburton Company Wellhead isolation tool
US4262743A (en) * 1979-09-04 1981-04-21 Halliburton Company Diffuser for wellhead isolation tool
US4852800A (en) * 1985-06-17 1989-08-01 Flow Systems, Inc. Method and apparatus for stablizing flow to sharp edges orifices
US5199512A (en) * 1990-09-04 1993-04-06 Ccore Technology And Licensing, Ltd. Method of an apparatus for jet cutting
US5291957A (en) * 1990-09-04 1994-03-08 Ccore Technology And Licensing, Ltd. Method and apparatus for jet cutting
US5542486A (en) * 1990-09-04 1996-08-06 Ccore Technology & Licensing Limited Method of and apparatus for single plenum jet cutting
US5251817A (en) * 1991-09-16 1993-10-12 Ursic Thomas A Orifice assembly and method providing highly cohesive fluid jet
US5862871A (en) * 1996-02-20 1999-01-26 Ccore Technology & Licensing Limited, A Texas Limited Partnership Axial-vortex jet drilling system and method
US7909116B2 (en) 2003-04-16 2011-03-22 Pdti Holdings, Llc Impact excavation system and method with improved nozzle
US20060016622A1 (en) * 2003-04-16 2006-01-26 Particle Drilling, Inc. Impact excavation system and method
US20060180350A1 (en) * 2003-04-16 2006-08-17 Particle Drilling Technologies, Inc. Impact excavation system and method with particle trap
US20060191717A1 (en) * 2003-04-16 2006-08-31 Particle Drilling Technologies, Inc. Impact excavation system and method with two-stage inductor
US7383896B2 (en) 2003-04-16 2008-06-10 Particle Drilling Technologies, Inc. Impact excavation system and method with particle separation
US7398839B2 (en) 2003-04-16 2008-07-15 Particle Drilling Technologies, Inc. Impact excavation system and method with particle trap
US20080230275A1 (en) * 2003-04-16 2008-09-25 Particle Drilling Technologies, Inc. Impact Excavation System And Method With Injection System
US8342265B2 (en) 2003-04-16 2013-01-01 Pdti Holdings, Llc Shot blocking using drilling mud
US7503407B2 (en) * 2003-04-16 2009-03-17 Particle Drilling Technologies, Inc. Impact excavation system and method
US8162079B2 (en) 2003-04-16 2012-04-24 Pdti Holdings, Llc Impact excavation system and method with injection system
US20090200080A1 (en) * 2003-04-16 2009-08-13 Tibbitts Gordon A Impact excavation system and method with particle separation
US20060011386A1 (en) * 2003-04-16 2006-01-19 Particle Drilling Technologies, Inc. Impact excavation system and method with improved nozzle
US20090205871A1 (en) * 2003-04-16 2009-08-20 Gordon Tibbitts Shot Blocking Using Drilling Mud
US7798249B2 (en) 2003-04-16 2010-09-21 Pdti Holdings, Llc Impact excavation system and method with suspension flow control
US7757786B2 (en) 2003-04-16 2010-07-20 Pdti Holdings, Llc Impact excavation system and method with injection system
US7793741B2 (en) 2003-04-16 2010-09-14 Pdti Holdings, Llc Impact excavation system and method with injection system
US8113300B2 (en) 2004-07-22 2012-02-14 Pdti Holdings, Llc Impact excavation system and method using a drill bit with junk slots
US7997355B2 (en) 2004-07-22 2011-08-16 Pdti Holdings, Llc Apparatus for injecting impactors into a fluid stream using a screw extruder
US20090200084A1 (en) * 2004-07-22 2009-08-13 Particle Drilling Technologies, Inc. Injection System and Method
US20090038856A1 (en) * 2007-07-03 2009-02-12 Particle Drilling Technologies, Inc. Injection System And Method
US7987928B2 (en) 2007-10-09 2011-08-02 Pdti Holdings, Llc Injection system and method comprising an impactor motive device
US7980326B2 (en) 2007-11-15 2011-07-19 Pdti Holdings, Llc Method and system for controlling force in a down-hole drilling operation
US20090126994A1 (en) * 2007-11-15 2009-05-21 Tibbitts Gordon A Method And System For Controlling Force In A Down-Hole Drilling Operation
US8353367B2 (en) 2008-02-01 2013-01-15 Gordon Tibbitts Methods of using a particle impact drilling system for removing near-borehole damage, milling objects in a wellbore, under reaming, coring perforating, assisting annular flow, and associated methods
US8037950B2 (en) 2008-02-01 2011-10-18 Pdti Holdings, Llc Methods of using a particle impact drilling system for removing near-borehole damage, milling objects in a wellbore, under reaming, coring, perforating, assisting annular flow, and associated methods
US8186456B2 (en) 2008-02-01 2012-05-29 Pdti Holdings, Llc Methods of using a particle impact drilling system for removing near-borehole damage, milling objects in a wellbore, under reaming, coring, perforating, assisting annular flow, and associated methods
US8353366B2 (en) 2008-02-01 2013-01-15 Gordon Tibbitts Methods of using a particle impact drilling system for removing near-borehole damage, milling objects in a wellbore, under reaming, coring, perforating, assisting annular flow, and associated methods
US20100155063A1 (en) * 2008-12-23 2010-06-24 Pdti Holdings, Llc Particle Drilling System Having Equivalent Circulating Density
US20100294567A1 (en) * 2009-04-08 2010-11-25 Pdti Holdings, Llc Impactor Excavation System Having A Drill Bit Discharging In A Cross-Over Pattern
US8485279B2 (en) 2009-04-08 2013-07-16 Pdti Holdings, Llc Impactor excavation system having a drill bit discharging in a cross-over pattern

Also Published As

Publication number Publication date
DE1951964A1 (en) 1970-09-17
BE739981A (en) 1970-03-16
GB1266050A (en) 1972-03-08
FR2020716A6 (en) 1970-07-17

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