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Publication numberUS2958821 A
Publication typeGrant
Publication dateNov 1, 1960
Filing dateApr 1, 1957
Priority dateApr 1, 1957
Publication numberUS 2958821 A, US 2958821A, US-A-2958821, US2958821 A, US2958821A
InventorsWebb David L
Original AssigneeDresser Operations Inc
Export CitationBiBTeX, EndNote, RefMan
External Links: USPTO, USPTO Assignment, Espacenet
Turbodrill tachometer
US 2958821 A
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Description  (OCR text may contain errors)

Nov. 1, 1960 D. L. WEBB 2,958,821

TURBODRILL TACHOMETER Filed April 1,1957 2 Sheets-Sheet 1 DAV] D l... WEBE5 INVENTOR.

FIG. 1. BYW%/ A TTORNEY Nov. 1, 1960 D. L. WEBB TURBQDRILL TACHOMETER Filed April 1, 195'? 2 Sheets-Sheet 2 INVEVTOR.

A TTOFPNEV u BY)! FIG. 6

United States Patent TURBODRILL TACHOMETER David L. Webb, Dallas, Tex., assignor to Dresser Operations, Inc., Dallas, Tex, a corporation of California Filed Apr. 1, 1957, Ser. No. 649,781

3 Claims. (Cl. 324-70) This invention relates to improvements in the method and apparatus for determining the rotary speed of a mud driven turbine which is in operation at the bottom of a well, more particularly of the type of deep oil or' water wells.

It has been found, in the drilling of deep wells with the so called mud turbine as a source of rotational energy for the bit that it is essential for economical operation to know rather precisely the revolutions per minute of the rotor which is directly proportional to the revolutions per minute of the bit. It will be apparent that the rate of penetration of the drill which is actually the measure of effectiveness of the drilling operation, is a function of the load on the drill and its rotary speed.

When it is appreciated that the operator of the drill rig is operating the bit which may be several thousand feet to several miles deep in a comparatively small well, it will be realized that his only controls are mud pressure and rate of flow and the actual load on the bit. It is essential, therefore, that he be constantly advised as to the rotary speed of the bit.

While the need of such information has been recognized and some inventors have suggested solutions as for example requiring the use of electrical cables, it is quite apparent that these solutions are not feasible, either because of excessive cost, technical complications, or mere incomplete or inaccurate reporting.

More recently a well logging system has been disclosed in which signals at the bottom of the well could be encoded through actuating means and, using the drilling fluid as the transmission medium, could be decoded at the top of the well. Thus not only are the results constantly available to the drilling operator but there isno need for auxiliary conductors, cables or the like.

An adaptation and improvement on this invention is shown in the Otis et a1. Patent 2,700,131 in which the signals impressed on the drilling fluid are at spaced intervals of such a type that the interval is integrated to show a characteristic related to the original signal. While such a system is effective for the intermittent reporting of various electrical conditions, it is considered too elaborate for routine reporting of the variable rotary speed of a device such as a mud turbine and its bit. It would be too slow for normal operating conditions as a drilling operator might lose his bit due to changes of speed between reporting intervals.

My invention, while specifically concerned with the continuous and highly accurate measure of the revolutions per minute of a bit (or turbine rotor) at the bottom of a hole which is rapidly deepening, is necessarily rugged, simple and of low cost. It is primarily intended for the single purpose and embodies only those elements which make an accurate and direct reading possible. It is to be noted however that recognition must be made of the environment of the drill and the recording device and the presence of surface interferences such as the mud The following description taken in connection with the attached drawings is a disclosure of a preferred form of embodiment of my invention.

In the drawings:

Figure 1 is an elevational view, partly schematic and partly in longitudinal section illustrating the general arrangement of the apparatus as employed in connection with a typical drilling well.

Figure 2 is a central, vertical, partial cross-sectional view of the upper part of a mud driven turbine.

Figure 3 is a transverse cross-section through Figure 2 substantially on the line 3-3 thereof.

Figure 4 is a central, vertical, partial cross-sectional view of the upper part of a modified type of mud driven turbine.

Figure 5 is a transverse cross-section taken substantially on the line 55 of Figure 4.

Figure 6 is a transverse cross-section substantially on the line 6--6 of Figure 4.

Referring to Figure 1 in which the general disposition of the apparatus of the invention is shown in relation to a conventional drilling rig and drilling well, 10 is the lower uncased portion of the bore hole and 11 the upper portion of the bore hole in which the usual surface string or conductor string of casing 12 has been set. Within the bore hole and at the surface above the bore hole is shown a conventional drilling rig comprising a drill bit 13, a turbodrill 14 and a drill stern composed of drill pipe 15 connected at its upper end to a swivel 17 which in turn is suspended from a traveling block hook 18, traveling block 19, drilling line 20 and crown block located in the top of the derrick 22.

The mud circulation passage extending through the drill bit 13, turbodrill 14 and drill stem 15 extends through the swivel 17 and is connected through suitable flexible connections or hose 31 to the discharge connection 35 of a drilling fluid circulating pump 36. The drilling fluid circulating pump 36 takes suction through pipe 38 from a body of drilling fluid contained in a mud reservoir or sump 40. The upper end of the surface casing 12 which provides a return path for circulating drilling fluid there below is provided with a lateral outlet pipe 42 which extends to and discharges into the fluid reservoir 40. A surge chamber 45 is preferably connected to the discharge 35 of the drilling fluid circulating pump 36 for the purpose of smoothing out or reducing the pump discharge pressure fluctuations.

In normal operations with the turbodrill, the drilling mud is pumped from pump 36 through the drill pipe 15 and the turbodrill 14 in such a manner as to rotate the bit 13. The discharge from the Well bore as before mentioned not only carries the cuttings out of the hole but tends to plaster up the wall in the usual manner.

In accordance with present practice, the turbodrill operates in such a manner as to rotate the bit at approximately 450 to 800 revolutions per minute under optimum conditions. The pump 36 which is a high pressure, low speed pump usually of the triplex type normally operates at approximately 60 to 70 revolutions per minute.

In accordance with my invention, the rotational speed of the turbine may be continuously reported at the drill rig by the following means.

Within the turbodrill casing 14 is normally mounted a rotor member generally designated at 50 in Figure 2. This is diagrammatically shown and is a part which can be attached directly to the rotor shaft or may be a part of the rotor itself. The rotor member 50 has a cap 51 and is provided with one or more openings 52 as shown in Figure 3 through which the mud flows from the drill pipe 15 through the turbodn'll casing 14 into the turbine mounted below.

Adjacent the mud opening 52 I provide one or more flow interrupter or restrictor elements generally indicated at 54 in such a manner that as the rotor turns there will be some obstruction to flow as the opening 52 passes the interrupter head. This in turn will generate a pressure pulse on the fluid stream which is substantially instantaneous. Bearings 56 tend to center the rotor member 50 in the turbodrill casing 14.

If two interrupter bodies 54 and 54A as shown in Figures 2 and 3 are used, there will normally be two pressure pulses per revolution. It will be apparent that if there were more than two there would be an increasing number in proportion to the revolutions per minute. If there is only one, the pressure pulses are equal to the revolutions per minute.

The detection of these pressure pulses at the surface of the well is accomplished by a suitable pressure pick up device 47 which may be of any suitable type such as Consolidated Engineering Corporation pressure transducer model No. 4-311 adapted to convert fluid pressure communicated to it from pipe 35 into corresponding values of electrical current or potential. This transducer may be energized by a suitable electrical current supply and when so energized is capable of producing an electrical output signal which is a direct function of the instantaneous fluid pressure applied to it which pressure in the present case is that appearing in pipe 35.

The pressure pick up device 47 is, in turn, connected through insulated conductors 48 to a suitable meter unit 56 which may be adapted to indicate the revolutions per minute of the rotor. While the details of such meter unit are not considered a part of this disclosure, it is known that it will normally include an amplifier, a band pass filter and usually a frequency meter. The amplifier and band pass filter may not always be necessary, especially where the pulse is strong and sharp.

With a frequency of 450 to 800 revolutions (or pulses) per minute, or multiples thereof, a General Radio Corporation direct reading frequency meter Type 1178-A may be used. The band pass filter will be designed in the usual manner to discriminate against frequencies outside the range of interest. A General Radio Corporation unit amplifier Type 1206-B may be used. A tuned circuit may be automatically or manually adjusted to the resonant frequency.

The matter of attenuation of the hydraulic signals must be taken into consideration based on the nature of the mud pump 36. It will be apparent that if a triplex pump operates at 70 revolutions per minute, it generates approximately 420 pulses per minute. This might tend to interfere with reception of signals if the rotor of the turbine was operating at the low end of its scale and the single pulse only were sent out per revolution. While it is known that attenuation increases rapidly with frequency, some rate of pulse generation in proportion to turbine (or bit) rotation is usually desirable.

There is however an alternate method of sending out pulses by which the strongest signals are received. If, for example, the mud flow interrupter is operated at a ratio of less than one under some conditions which will be hereinafter described, better results will be obtained. In this form of embodiment of the invention as shown in Figure 4, the turbodrill body 14 is similarly adapted to receive a turbine rotor 50 having the mud openings 52 but is surmounted by a modified type of cap 60. In this case as will be seen from the cross-sectional view Figure 5, the shaft of the cap is eccentric and is adapted to receive an internal gear 61 which in turn meshes with an external gear 62 suitably secured to the wall of the turbodrill 14. The pinion gear 61 is provided with a fluid passage generally indicated at 64. A suitable interrupter 65 is mounted below the internal ring gear in such a position that it will interrupt the flow of mud downwardly through the turbodrill body 14 and into the opening 52. V

In view of the fact that the internal gear is eccentrically mounted with respect to the turbine rotor there will be a gear reduction depending upon such eccentricity so that the number of interruptions of flow can be established as some fraction of the rate of rotation of the rotor.

In other words a frequency of interruption of one interruption for each ten revolutions or more or less depending upon the desired frequency and the approximate rotational rate can be obtained. With a normal rotational speed of the turbine from 450 to 800 revolutions per minute would be reflected by as low as 45 to interruptions or cycles per minute.

While it may not be possible to use the same electrical equipment as shown in the unit 56 for either the high frequency or the low frequency operations due to the electrical limitations of the equipment, it is of course possible to substitute appropriately balanced circuits which will operate in the range of less than one cycle per second to several cycles per second as well as operating in the range ten to a hundred cycles per second.

It is thus to be understood that I am not limited to either the direct frequency of rotation which may interfere with the frequency of pulse of the pump but can operate with either a fraction of such frequency or a multiple of such frequency.

As heretofore mentioned there are advantages in using multiple frequencies because of the simplicity of the electrical equipment whereas there are advantages in using a fraction of the frequency not only because of the much stronger pulse, but the sharper recognition of the pulse and less attenuation in the well.

While I have shown a simplified and schematic construction of interrupter it will be appreciated that modifications in design will be made to fit the particular type of turbodrill construction. The invention is applicable to either the direct driven bit or to the gear driven bit except that the number of responses is preferably in accordance with the bit rotation which is critical rather than the turbine rotation if it should happen to be of the gear driven type.

I claim:

1. A method for continuously measuring the rotational speed of a fluid-driven turbine mounted adjacent the lower end of a drill pipe and while located adjacent the bottom of a drill hole which comprises: circulating drilling fluid down the drill pipe to drive said turbine; periodically varying the resistance to flow of said fluid, at a point adjacent said turbine, at a frequency which bears a simultaneous, predetermined relation to the rotational speed of said turbine and which frequency is a multiple fraction greater than one of the rotational speed of the turbine thereby generating pressure pulses in the flowing drilling fluid having a frequency which is a multiple fraction greater than one of the rotational speed of the turbine and which pulses are transmitted through the flowing drilling fluid to a point adjacent the top of such drill pipe; and intercepting said pusles at said point to obtain thereby a signal bearing a substantially simultaneous, predetermined relationship to the frequency of said pulses.

2. Apparatus for making turbodrill rotational speed measurements while drilling comprising: a drill stern having a fluid circulating duct therethrough; a turbodrill member, including a non-rotating housing and a rotatable turbine, attached to said drill stem; pump means for circulating fluid down through said duct to said turbine; a cylindrical rotor member coupled to said turbine for rotation therewith and positioned within said housing; means forming an opening in the curved surface of said rotor member; inwardly extending fluid flow restriction means formed on the wall of said housing adjacent said rotor member; transducer means for detecting the variations of resistance to flow of fluid through said duct pro duced as the opening in said rotor member passes said restriction means upon rotation of said rotor means by said turbine and for producing electrical signals of a 5 frequency bearing a predetermined relation to the rotational speed of said rotor; and means for indicating said signals.

3. Apparatus for making turbodrill speed measurements while drilling comprising: a drill stem having a fluid circulating duct therethrough; a turbodrill member, includ ing a non-rotating housing and a rotatable turbine, attached to said drill stem; pump means for circulating fluid down through said duct to said turbine; a cylindrical rotor coupled to said turbine for rotation therewith; means forming an opening in the curved surface of said rotor; a pinion gear eccentrically mounted on the top of said rotor for the rotation therewith; gear means secured to the inner wall of said housing to mesh with said pinion References Cited in the file of this patent UNITED STATES PATENTS Hassle-r July 31, 1945 Arps Oct. 3, 1950

Patent Citations
Cited PatentFiling datePublication dateApplicantTitle
US2380520 *Mar 25, 1944Jul 31, 1945Shell DevBorehole indicating apparatus
US2524031 *Oct 1, 1945Oct 3, 1950Arps Jan JApparatus for logging wells
Referenced by
Citing PatentFiling datePublication dateApplicantTitle
US3090439 *Jun 6, 1960May 21, 1963Halliburton CoControl of well formation fracturing operations
US3400327 *Feb 23, 1966Sep 3, 1968Mobil Oil CorpBorehole tool rotational switching system controlled by detector of earth's magnetic field
US3739331 *Jul 6, 1971Jun 12, 1973Mobil Oil CorpLogging-while-drilling apparatus
US3766992 *Dec 2, 1971Oct 23, 1973Inst Francais Du PetroleDevice for automatic regulation of the running speed of a drilling turbine through elastic accumulator means
US3908770 *May 13, 1974Sep 30, 1975Texaco IncMethods and apparatus for driving a means in a drill string while drilling
US3949354 *May 15, 1974Apr 6, 1976Schlumberger Technology CorporationApparatus for transmitting well bore data
US4387774 *May 4, 1981Jun 14, 1983Smith International, Inc.Time recorder for in-hole motors
US4545241 *Jun 25, 1982Oct 8, 1985Smith International, Inc.For use with fluid-driven in-hole turbines
US4698794 *Jul 22, 1985Oct 6, 1987Eastman ChristensenDevice for remote transmission of information
US4914637 *Jul 25, 1989Apr 3, 1990Positec Drilling Controls (Canada) Ltd.Measure while drilling system
US5073877 *May 16, 1990Dec 17, 1991Schlumberger Canada LimitedFor use in a pipe string having a bore suspended in a well
US5321981 *Feb 1, 1993Jun 21, 1994Baker Hughes IncorporatedMethods for analysis of drillstring vibration using torsionally induced frequency modulation
USRE30055 *Apr 5, 1978Jul 24, 1979Schlumberger Technology CorporationApparatus for transmitting well bore data
USRE30246 *Sep 26, 1977Apr 1, 1980Texaco Inc.Methods and apparatus for driving a means in a drill string while drilling
Classifications
U.S. Classification324/166, 367/83, 175/40, 175/107, 73/152.1
International ClassificationE21B4/00, E21B47/18, E21B47/12, E21B4/02
Cooperative ClassificationE21B47/182, E21B4/02
European ClassificationE21B4/02, E21B47/18C