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METHODS AND APPARATUSES FOR TRANSMISSION OF LONGITUDINAL AND TORQUE
PULSE DATA FROM DRILL STRING IN WELL WHILE DRILLING
Two methods and two mechanisms for carrying out the methods are disclosed.
The methods of (1) generating longitudinal or torque pulses at the lower
end of a drilling assembly in the bottom of a wellbore at the natural
frequency of the drilling assembly, and (2) monitoring the top of the
drilling assembly for the longitudinal or torque pulses therein may be
practiced by (1) a drill collar rotatably and detachably mounted on a
drill bit on the lower end of a drilling assembly in a wellbore for being
momentarily and precisely coupled and uncoupled during drilling for
generation of longitudinal pulses in the drilling assembly at the natural
frequency of the drilling assembly for being monitored at the surface, and
(2), respectively, a drill collar rotatable by a plurality of controllable
jets exhausting tangentially of the drill collar outer periphery for
generating torque pulses in the drilling assembly at the natural frequency
thereof for being monitored at the surface.
Barnes et al., "Passhands For Acoustic Transmission is an Idealized Drill String," 5/72, Pg 1606-1608, Journ. Acoust. Soc. of Amer., Vol. 51,
No. 5 (Part 2)..
Primary Examiner: Wilbur; Maynard R.
Assistant Examiner: Moskowitz; N.
Attorney, Agent or Firm:Whaley; T. H.
Reis; C. G.
1. A method for transmission of data from the bottom portion of a drilling assembly including a drill collar rotatable on a drill bit to a detector at the surface while drilling a
wellbore comprising the steps of,
a. measuring data on the bottom portion of the drilling assembly,
b. forming a bump on the upper end of the drill bit,
c. forming a roller on the lower end of the drill collar for rolling over the bump as the drill collar rotates relative to said drill bit,
d. rotating the roller over the bump for generating longitudinal pulses in the bottom of the drilling assembly at the longitudinal natural frequency of the drilling assembly, and
e. modulating the time duration of the generated longitudinal pulses proportional to the measured data for receiving at the surface of the wellbore.
2. A system for transmission of data from the lower end of a drill string of a drilling assembly in a wellbore to the top of the wellbore during drilling comprising,
a. a drill string including a drill collar means rotatably mounted on a drill bit means,
b. said drill bit means having a bump on the top thereof and said drill collar means having a roller on the bottom thereof for rolling over said bump,
c. data measuring means on the lower end of said drill string,
d. said drill bit means and said drill collar means comprising drill bit longitudinal pulse generating means on the lower end of said drill string for generating longitudinal pulses in said drill string at the longitudinal natural frequency of
the drilling assembly proportional to the measured data, and
e. monitoring means on the upper end of said drill string for monitoring said drill bit longitudinal pulses in said drill string.
3. A system as recited in Claim 2 wherein the drill bit longitudinal pulse generating means comprises,
a. controllable coupling means between said drill bit means and said drill string,
b. control means for said controllable coupling means, and
c. said coupling means being responsive to said control means for controlled coupling and uncoupling of said drill bit means from said drill string for generating said drill bit torque pulses at the longitudinal natural frequency of the drilling
4. A method for transmission of data from the bottom of a drilling assembly to the surface while drilling a wellbore comprising the steps of,
a. measuring data at the bottom of the drilling assembly,
b. determining the natural frequency of the drilling assembly, and
c. ejecting drilling fluid from a nozzle tangentially from the outer periphery of the bottom of the drilling assembly for generating torque pulses relative to the measured data in the drilling assembly at the torsional natural frequency of the
drilling assembly for receiving at the surface of the wellbore.
5. A system for transmission of data from the lower end of a drill string of a drilling assembly in a wellbore to the top of the wellbore during drilling comprising,
a. data measuring means on the lower end of the drill string,
b. drill collar torque pulse generating means also on the lower end of a drill string for generating torque pulses in said drill string at the torsional natural frequency of the drilling assembly, and
c. said controllable torque pulse generating means comprises a controlled valve operated nozzle for ejecting drilling fluid tangential to said drill string for generating torque pulses proportional to the measured data at the torsional natural
frequency of the drilling assembly.
6. A system for transmission of data from the lower end of a drill string of a drilling assembly in a wellbore to the top of the wellbore during drilling comprising,
a. data measuring means on the lower end of the drill string,
b. drill collar in the drill string,
c. controllable torque pulse generating ejection nozzle means on said drill collar,
d. control means for said controllable torque pulse generating ejection nozzle means, and
e. said controllable torque pulse generating ejection nozzle means being responsive to said control means for generating said torque pulses relative to the measured data at the torsional natural frequency of the drilling assembly.
7. A method for transmission of data from the bottom of a drill string including a drill collar to a detector at the surface while drilling a wellbore comprising the steps of,
a. measuring data at the bottom of the drill string,
b. forming a drilling mud ejecting nozzle in the drill collar for controlled ejecting of drilling mud tangentially to the outer periphery of the drill collar,
c. ejecting the drilling mud in torque pulses at the torsional natural frequency of the drill string,
d. modulating the time duration of the generated torque pulses relative to the measured data for receiving at the surface of the wellbore.
8. A system for transmission of data in a drilling assembly from the bottom of a wellbore to the top of the wellbore while drilling comprising,
a. a drilling assembly for being lowered into a wellbore including a drill bit at the bottom with a drill collar connected between said drill bit and a string of drill pipes to the surface, and means on the surface for rotating said drill pipes,
b. data measuring means on the lower end of said drilling assembly,
c. fluid nozzle means projecting tangentially from the periphery of said drill collar for generating torque forces in the bottom of said drill pipes at the natural frequency of the drilling assembly,
d. control means for said fluid nozzle means for modulating the pulses generated relative to data to be transmitted to the surface,
e. torque pulse monitoring means at the top of the drill pipes, and
f. said torque pulse monitoring means being responsive to said modulated pulses in said drill pipes for monitoring said data at the surface from said control means at the bottom of the wellbore.
BACKGROUND OF THE INVENTION
While drilling wells, such as wells for the recovery of petroleum from subsurface petroleum containing formations, there are many measurements which are desired by people doing the drilling for determining the lithology being encountered as the
wellbore progresses deeper and deeper into the earth. The usual practice today during the drilling of oil and gas wells is to interrupt the drilling operation periodically, to pull the entire drill string from the wellbore, and to run logging tools down
into the wellbore for determining the types of earth formations which have been penetrated by the wellbore and the characteristics of such formation layers indicative of the presence of petroleum deposits, and for collecting other information as desired
prior to running the entire drill string back into the wellbore. As the well gets deeper and deeper, the time required for the removal and rerunning of this drill string, known in the industry as a trip, becomes greater and greater. Some wells are so
deep as to require 24 hours to make a trip, plus many additional hours for the running of a logging tool into the formation. Further it has long been realized that it would be highly desirable to perform certain basic logging operations during the
course of the drilling operation, and to transmit such information back up to the surface either periodically or continually. If this were possible, it would permit a complete record of the subsurface lithology to be accumulated as the drilling proceeds
and would not necessitate the delay of drilling operations for the running of logs.
Thus it would be very advantageous, during drilling operations of a wellbore, to possess a signal system for the transmission of information from the area of the bottom of the wellbore or the drill bit to the surface using the most convenient
continuous communications line available, the drill string, as the communication medium. For many types of information, the signal does not have to be transmitted continuously during drilling, but can be transmitted at certain intervals. Exemplary
information that is needed very urgently at the surface during drilling are borehole deviation, information from drilling tests stored in a memory unit or a warning signal, as a pressure difference detected and stored when drilling through a gas zone.
Thus during drilling it would be desirous to obtain this information as soon as possible.
While a prior signal transmission system comprises modulation of mud pressure or mud flow by a variable valve in the mud conduit in the bottom of the drill pipe, as in U. S. Pat. Nos. 2,930,137; 3,327,527; or 3,345,867; this system is not
reliable due to sticking of the valve because of the solids in the mud and due to failure of the valve because of the abrasion thereof by the mud per se. Another prior but different data transmission system comprises a controllable wellbore wall
engaging means extendable transversely from the sides of the drill stem for momentarily increasing the drag or torque in the drill pipe while rotating the drill pipe for sending torque pulses to the surface through the drill string. This latter system
is disclosed in patent application Ser. No. 279,899 filed Aug. 11, 1972, by Assignee of record. Others, as in U. S. Pat. No. 3,520,375, have detected the mechanical characteristics of rocks being drilled by comparing the vertical vibrations and axial
movement of the drilling assembly for comparison with known rock properties and apparently any resultant torsional accelerations as the drill bits roll over and grind up the rocks.
OBJECTS OF THE INVENTION
Accordingly, a primary object of this invention is to provide at least two reliable methods for transmission of data from the bottom of a wellbore to the top while drilling.
Another primary object of this invention is to provide a data transmission system for practicing one of the new methods utilizing a longitudinal pulse signal generator that may be coupled and uncoupled to the drill string for precise interruption
of pulse generation therein when drilling for transmitting longitudinal pulses for detection at the top of the drill string.
Still another object of this invention is to provide a data transmission system utilizing a roller rotating on an annular surface with a bump thereon that is coupled and uncoupled to a drill string with a mud pressure actuated spring clutch while
Another object of this invention is to provide a data transmission system utilizing a torque jet pulse generator for generating torque pulses at the natural frequency of the drilling assembly, the jet pulses being controlled with a controller in
the drill collar while drilling;
A still further object of this invention is to provide a data transmission system for continuous transmission of data from a downhole tool while drilling which is easy to operate, is of simple configuration, is economical to build and assemble,
and is of greater efficiency for generating signals at the natural frequency of the drilling assembly from a rotating drill bit deep in a well to the surface.
BRIEF DESCRIPTION OF THE DRAWINGS
The drawings diagrammatically illustrate by way of example, not by way of limitation, two forms or mechanisms for carrying out the methods of the invention wherein like reference numerals have been employed to indicate similar parts in the
several views in which:
FIG. 1 is a schematic vertical view of the invention when incorporated in an oil or gas well being drilled;
FIG. 2 is a schematic vertical sectional view of the invention as mounted in a drill collar of the drill string of FIG. 1;
FIG. 3 discloses a longitudinal natural frequency curve for a typical spring-mass system of a drilling assembly; and
FIGS. 4 and 5 discloses a modification of FIG. 1 having a plurality of controllable jets for generating torque pulses illustrated schematically in section.
DESCRIPTION OF THE INVENTION
The invention disclosed herein, the scope of which being defined in the appended claims, is not limited in its application to the details of construction and arrangements of parts shown and described for carrying out the disclosed methods, since
the invention is capable of other embodiments for carrying out other methods and of being practiced or carried out in various other ways. Also, it is to be understood that the phraseology or terminology employed herein is for the purpose of description
and not of limitation. Further, many modifications and variations of the invention as hereinbefore set forth will occur to those skilled in the art. Therefore, all such modifications and variations which are within the spirit and scope of the invention
herein are included and only such limitations should be imposed as are indicated in the appended claims.
DESCRIPTION OF THE METHODS
A method is set forth for transmitting data from the bottom of a drill string of a drilling assembly in a wellbore to the top of the wellbore during drilling thereof comprising the steps of,
1. generating signal pulses in the lower end of the drill string at the natural frequency of the drilling assembly, and
2. monitoring the top of the drill string for the natural frequency signal pulses therein.
A more specific method comprises a method for transmission of data from the bottom of a drill string of a drilling assembly in a wellbore during drilling thereof to a detector at the surface including the steps of,
1. sensing the desired parameter of information at the bottom of the wellbore,
2. generating longitudinal pulses at the longitudinal frequency of the drilling assembly in the bottom of the drilling assembly,
3. modulating the time duration of the longitudinal pulses proportional to the desired parameter of information sensed, and
4. detecting the modulated pulses at the surface of the wellbore.
An additional and different method for transmission of data from the bottom of a drill string of a drilling assembly in a wellbore during drilling thereof to a detector at the surface comprises the steps of,
1. sensing the desired parameter of information at the bottom of the wellbore,
2. generating torque pulses at the torsional natural frequency of the drilling assembly in the bottom of the drilling assembly,
3. modulating the time duration of the torque pulses proportional to the desired parameter of information sensed, and
4. detecting the modulated pulses at the surface of the wellbore.
DESCRIPTION OF APPARATUS OR SYSTEMS OF DATA TRANSMISSION FROM A WELLBORE WHILE DRILLING
The drawings disclose two embodiments of the invention for carrying out or practicing the above described methods for transmitting intelligence from the bottom of a wellbore of conditions at the bottom to the surface, either while drilling is in
progress or during a lull in drilling.
FIG. 1 discloses schematically a system for carrying out the basic methods of data transmission from a wellbore during drilling operations.
In the drilling rig illustrated in FIG. 1, a drilling assembly 10 is disclosed comprising a derrick 11 for supporting a traveling block 12 with lines 13 having a dead line 14. A hook 15 on the bottom of the traveling block has a swivel 16 on the
bottom thereof for supporting the drill string 17, the latter comprising a kelly 18 slideable therethrough, and many interconnected drill pipes 19 for supporting a drill collar 20 having a drill bit 21 connected to the bottom thereof. Drill string 17 is
rotated by rotary table 22 driven by a suitable rotary drive or engine 24 with a sensitive torque meter 23b connected therebetween. Likewise an analog recorder or sensitive force meter 23a is connected to the fast line of drilling line 13 for detection
of longitudinal pulses through the lines 13.
Field experiments have shown that as the three cone drill bit rotates it generates longitudinal vibrations with a predominant frequency of three times the rotational speed. A bit rotating at 100 rpm will generate a longitudinal vibration with a
predominant frequency of 300 cycles per minute or 5 cycles per second.
It has been found that very strong longitudinal vibrations occur in the drill string when the rotational speed of the three cone drill bit, and accordingly the whole drill string, is such that the three times rotary speed longitudinal vibration
generated by the bit is at the longitudinal natural frequency of the surface spring-mass system of the drilling assembly (composed of the drilling lines, as the "spring" and the hook, swivel, traveling block, and drill string as the "mass"). In fact a
formula has been derived for calculating or generating the most important longitudinal natural frequency or critical RPM (revolutions per minute) of the drill string in the drilling assembly comprising:
RPM = (10/11) K (32.2)/M
K = combined stiffness of drilling lines (springs) in lb/ft
M = mass of hook, swivel, traveling block, and drilling lines in lb
As the stiffness of the drilling lines depends on their length, this stiffness and thus the critical RPM will vary slightly as each joint of pipe is drilled down. The above formula applies when three pulses per revolution are generated. When
any other number (n) of pulses per revolution are generated, the required speed is merely the above speed multiplied by 3/n.
Also the natural frequency may be determined experimentally, if so desired.
FIG. 3 illustrates the resultant curve 24 for a typical drilling assembly, which while illustrated as sitting on the ground, it is actually the drilling assembly sitting on the Texaco drilling barge "Caillou" for drilling off the shores of Texas
and Louisiana. This curve illustrates the variation of longitudinal vibratory forces developed from a three cone drill bit and detected at the top of the drill string through rotary speeds from 40 rpm to 200 rpm for this drilling assembly comprising a
189 foot tall derrick 11, FIG. 1, 15,550 pound traveling block 12, 1 l/2 inch, 4.16 pound per foot drilling line 13, 14 9,950 pound hook 15, 5,400 pound swivel 16, 11,463 foot, 5 inch, 19.5 pound per foot steel drill pipe 19, and a 637 foot, 7 3/4 inch
steel drill collar 20. It is seen that between 80 and 100 rpm, the natural frequency of this particular drilling assembly, small longitudinal vibrations are magnified and transmittable great distances, as up through a few miles of drill string.
Accordingly, with a longitudinal pulse generator for generating pulses longitudinally in the drill pipe from the location of the drill collar and drill bit at the natural frequency of the drilling assembly relative to data desired to be transmitted to
the surface and a longitudinal pulse monitoring device at the surface connected to the top of the drill string, an apparatus for transmission of data from the bottom of the well is produced.
Likewise, the torsional natural frequency, RPM, was found of the above disclosed drilling assembly, it being found by trial and error or by being calculated from the formula:
tan (wLp/a) tan (wLc/a) = Jp/Jc
w = torsional natural frequency of the drill string in radians per second
Lp = length of drill pipe, inches
Lc = length of drill collars, inches
a = .sqroot.Gg/.gamma.
G = material shear modulus of elasticity
g = gravitational acceleration
.gamma. = weight per unit volume of the drill string
Jp = polar moment of inertia of the drill pipe
Jc = polar moment of inertia of the drill collars
Accordingly, by generating longitudinal pulses in the drill bit at the longitudinal natural frequency of the drilling assembly, it can be assured that the pulses may be detectable at the surface for any length of drill string with a minimum of
input energy at the drill bit. And by modulating the time sequence of pulses at the natural frequency relative to, or equal to a function of the measured parameter, as temperature or pressure of the formation, wellbore deviation, etc., intelligent data
from the bottom of the wellbore is easily and efficiently received at the surface.
Further, by generating torque pulses in the drill collar or drill bit at the torsional natural frequency of the drilling assembly, a pulse is easily detectable at the surface from any depth with a minimum of input energy at the drill bit.
In each case, the transmitter or pulse generator is adjustable (1) to operate at different frequencies and thus operate at the natural frequency for different drilling rigs and (2) to operate for different lengths of time relative or proportional
to the measured signal at the bottom of the wellbore.
EMBODIMENT OF FIG. 2
A feature of the invention illustrated in the expanded longitudinal sectional view of the upper end of the drill bit 21, FIG. 2, rotatably connected internally to a lower end of the drill collar 20 is the longitudinal natural frequency pulse
generator comprising basically a plurality of rollers rotatable over a plurality of bumps and controllable with a quick disconnect clutch between the drill collar and the drill bit for generating longitudinal pulses at the natural frequency of the
drilling assembly in the drill string.
Specifically, the pulse generating mechanism comprises two rollers 25a, 25b, FIG. 2, rotatably mounted on the lower end of the drill collar for rolling on an inclined annular surface 26 having four bumps 90.degree. apart, only two bumps 27a and
27b positioned 180.degree. opposite of each other being illustrated. Controllable connections, pistons, or dogs 28a, 28b in the inner portion of the drill bit 21 are slideable into the respective recesses 29a and 29b in the outer lower portion of the
drill collar 20 as controlled by a conventional electromagnetic valve 30 responsive to signal inputs from a conventional transducer and valve control system or controller 31. In the absence of mud pressure in line 33, tension springs 32a and 32b retract
dogs 28a and 28b from the recesses to permit relative rotation between the drill collar 20 and the drill bit 21. While only two dogs 28 and two recesses 29 are illustrated, any suitable number may be utilized around the outer periphery of the upper
drill bit portion 21 as required.
Controller 31 is a conventional detector of temperature, pressure, weight on the bit, and of other logging parameters such as SP (self potential) or resistivity for operating the clutch dogs 28a, 28b in and out for permitting the drill collar to
rotate and generate torque pulses at the natural frequency and time modulated in proportion to the data transmitted, such as but not limited to a conventional logging pulse generator, all positioned in a measurement and instrumentation module portion of
controller 31, FIG. 2. Likewise, the controller may incorporate therein any suitable downhole tape recorder system as disclosed in U.S. Pat. No. 3,566,597, for playback when desired.
The sensitive meter 23a, FIG. 1, for detecting longitudinal energy pulses at the longitudinal natural frequency of the drilling assembly may be any suitable meter, such as but not limited to a conventional weight indicator coupled to an analog
recorder for producing, for example, a sine wave plot of amplitude versus time.
While only two dogs 28a, 28b, FIG. 2, two rollers 25a, 25b, and four bumps 27a - 27d are described or illustrated, the desired number of each must be utilized in order that the range of number of bumps per second per revolution of the drilling
string will include the predetermined natural frequency of the particular drilling assembly being operated, as the number of drill pipes is increased during drilling.
In the practice of my invention, the logging instrument or other measuring device performs the desired measurement and the data are converted into electrical analog signals with the measurements represented by the length of the pulse signal.
This is a common form of modulation frequently employed in transmitting scientific data. Power for operation of the measurement devices and electronics is supplied by conventional batteries (not shown). If desired, the measurement and data transmission
operation may continue more or less continually during the drilling operation, with the periodic signal pulses being generated and transmitted to indicate the desired parameters being monitored. Actually drilling is interrupted momentarily during actual
transmission. In some instances it is desirable to interrupt the normal drilling operation and activate the subsurface equipment to have it make measurements and transmit the measurements back to the surfaceby the signal pulses. One very satisfactory
method of accomplishing this is to include a centrifugal switch in the measurement and electronics assembly, which senses the cessation of rotation of the drill string. When a measurement is desired, the pumps are stopped and the drill bit rotation is
stopped. The centrifugal switch will close when the drill string rotation is stopped, and the measurement devices are activated thereby. Thereafter the measurement is encoded into pulsed analog electrical signals which are used to activate the wellbore
engaging apparatus as is described hereinabove. Rotation of the drill string must be resumed for transmission of the signal back to the surface.
Still another method of activating the measurement and data transmission systems, where it is not desired to transmit data continually during the drilling cycle, involves the use of conventional strain gauges applied to a section of the drill
collar to sense the amount of weight being applied to the bit, which are activated when the drill string is raised a sufficient distance so that the bit no longer contacts the bottom of the wellbore. Either type of switch or both may be used to activate
the measurement and data transmission functions.
Thus in operation of the embodiment of FIG. 2 in practicing the method set forth above of transmitting data from the bottom of a wellbore during drilling to a detector at the surface, controller 31 detects or receives the information to be
transmitted, as pressure, average weight on the drill bit, deviation, etc., which is measured and electrically stored and transmitted at the predetermined time set in the system.
The system, FIG. 2, is shown in drilling position wherein drill mud pressure from mud conduit 34a in the center of the drill string for supplying mud to the drill bit, forces diaphragm 35 inwardly and with the help of hydraulic reservoir 36
maintain dogs 28a, 28b extended into recesses 29a, 29b to lock the drill collar 20 to the drill bit 21 for normal drilling. Then at the time of transmission, which may be controlled from above, as by stopping and starting rotation of the drill string a
predetermined number of times, electromagnetic valve 30 is rotated counterclockwise 90 degrees to cut off the hydraulic pressure to allow the hydraulic fluid to flow into air reservoir 37 and as the dogs instantly retract due to the tension force of
springs 32a, 32b the drill bit becomes disconnected from the drill collar, and with a constant load maintained on the bit of between 10,000 and 50,000 pounds, friction holds the bit stopped while the rollers 25a, 25b rotate over the bumps 27a - 27d as
the drill string and drill collar are rotated at the proper and predetermined speed to generate the longitudinal pulses at the known natural frequency of the drilling assembly. The predetermined speed of rotation of the drill string depends on the
number of longitudinal pulses generated by each turn of the drill string. For example, if four pulses per turn are generated, the speed of rotation is merely three-fourths of that speed determined for a conventional three cone roller bit and described
by the above longitudinal natural frequency formula or determined experimentally. As controlled by the control valve, the pulses are generated at the natural frequency for a length of time proportional to the signal, which pulses are easily detected at
the surface by the sensitive force meter 23a.
In the disclosed example of four bumps 27a, 27b, 27c, and 27d (only the first two being illustrated on FIG. 2) spaced circumferentially 90.degree. apart on the upper end of the annular drill bit surface, as the drill collar and its two opposite
rollers 25a, 25b rotate over the bumps there would be four longitudinal bumps or excitation at a frequency of four times the rotary speed. Thus rotating the drill string at one-fourth the predetermined speed generates the longitudinal natural frequency
for that particular drilling rig having that length of drill string.
Thus at the proper preset time or at the time when sections of drill pipe are to be added, signal pulses at the drilling assembly natural frequency may be generated only for the length of time relative to the data being transmitted.
Accordingly, the drill string is used as the signal transmission system at the natural frequency of the drilling assembly to overcome drilling mud damping which is circulated continually down the middle of the drill string to the lower end of the
drill bit and back up the annular space externally of the drill string to the surface again. Thus an efficient signal system is required to overcome all of this damping.
Additional advantages are:
Valve 30 is the only single electromechanical part of this transmission system and thus the only part to be intelligently controlled.
Likewise, all energy for the excitation comes from the rotary drive to accordingly eliminate the requirement for a large downhole power source.
Further, energy to actuate the dogs into locking engagement comes from the mud pumps and the natural hydrostatic mud pressure.
EMBODIMENT OF FIGS. 4 AND 5
FIG. 4 is a schematic elevational view of the lower section of a drill collar having a plurality of controllable mud jets for generating torque pulses at the lateral natural frequency of a drilling assembly as another embodiment for practicing
the above disclosed methods.
FIG. 5 is a section at 5--5 on FIG. 4.
As the drilling mud is pumped down the interior passage 34b, FIG. 4, of the drill collar 20b at an examplar pressure of 2,200 psi and circulating at a typical rate of 400 gallons per minute, a suitable electromagnetic conventional fluid control
valve 30b bleeds off a portion of this flow to eject it from opposite nozzles 39a and 39b, FIG. 5, in pulses having the torsional natural frequency of the drilling assembly as determined experimentally or by the formula above, in short periods of time
proportional to the data being transmitted at the bottom of the well-bore to the sensitive meter 23b, FIG. 1, at the surface. A conventional signal measurement and storage system 41, FIG. 5, as for detecting and storing the bottom hole temperature, bit
temperature, weight on the bit, pressure, etc., transmits its information to a controller 42 for maintaining a sine wave generator 43 on for a length of time proportional to the signal. The sine wave generator 43 is battery powered and is frequency
adjustable for controlling the electromagnetic valve 30b for generating the tortional pulses at the natural frequency of the drilling assembly for being received by the torque meter 23b described above. These nozzles 39a and 39b eject the high pressure,
high velocity mud substantially tangentially from the periphery of the drill collar from cavities 40a and 40b respectively.
Accordingly, the mud jet nozzles of FIGS. 4 and 5 as controlled by variable control valve 30b generate lateral or torque pulses at the lateral natural frequency of the drilling assembly for periods of time proportional to the data to be
Obviously other methods may be utilized for transmission of signals with the embodiments of either FIG. 2 or FIG. 4 than those listed above, depending on the particular information desired to be transmitted.
Accordingly, it will be seen that while drilling is in progress, the disclosed methods and two data transmission systems will transmit information from the bottom of a wellbore to the surface and will operate in a manner which meets each of the
objects set forth hereinbefore.
While only two methods of the invention and two mechanisms for carrying out the methods have been disclosed, it will be evident that various other methods and modifications are possible in the arrangement and construction of the disclosed methods
and data transmission systems without departing from the scope of the invention and it is accordingly desired to comprehend within the purview of this invention such modifications as may be considered to fall within the scope of the appended claims.