[0001] The present invention relates generally to a downhole telemetry system for facilitating
the transfer of borehole and drilling data to the surface for inspection and analysis.
More particularly, the invention relates to a measurement-while-drilling ("MWD") system
that senses and transmits data measurements from a downhole location to an uphole
location.
[0002] Deep wells of the type commonly used for petroleum or geothermal exploration are
typically less than 30 cm (12 inches) in diameter and on the order of 2 km (1.5 miles)
long. These wells are drilled using drill strings assembled from relatively light
sections (either 30 or 45 feet (9.1 or 13.7m) long) of drill pipe that are connected
end-to-end by tool joints, additional sections being added to the uphole end as the
hole deepens. The downhole end of the drill string typically includes a drill collar,
a dead weight assembled from sections of relatively heavy lengths of uniform diameter
collar pipe having an overall length on the order of 300 meters (1000 feet). A drill
bit is attached to the downhole end of the drill collar, the weight of the collar
causing the bit to bite into the earth as the drill string is rotated from the surface.
Sometimes, downhole mud motors or turbines are used to turn the bit. Drilling mud
or air is pumped from the surface to the drill bit through an axial hole in the drill
string. This fluid removes the cuttings from the hole, provides hydrostatic head which
controls the formation gases, and sometimes provides cooling for the bit.
[0003] Communication between downhole sensors of parameters such as pressure or temperature
and the surface has long been desirable. There are a number of systems in the prior
art which seek to transmit information regarding parameters downhole up to the surface.
There prior systems may be descriptively characterized as: (1) mud pressure pulse;
(2) hard-wire connection; (3) acoustic wave; and (4) electromagnetic waves.
[0004] In a mud pressure pulse system, the drilling mud pressure in the drill string is
modulated by means of a valve and control mechanism mounted in a special pulsar collar
above the drill bit and motor (if one is used). The pressure pulse travels up the
mud column at or near the velocity of sound in the mud, which is approximately 4000-5000
feet per second (1200-1500 m/s). The rate of transmission of data, however, is relatively
slow due to pulse spreading, modulation rate limitations, and other disruptive forces,
such as the ambient noise in the drill string. A typical pulse rate is on the order
of a pulse per second. A representative example of mud pulse telemetry systems may
be found in U.S. Patent Nos. 3,949,354, 3,964,556, 3,958,217, 4,216,536, 4,401,134,
4,515,225, 4,787,093 and 4,908,804.
[0005] Hard-wire connectors have also been proposed to provide a hard wire connection from
the bit to the surface. There are a number of obvious advantages to using wire or
cable systems, such as the ability to transmit at a high data rate; the ability to
send power downhole; and the capability of two-way communication. Examples of hard
wire systems may be found in U.S. Patent Nos. 3,879,097, 3,918,537 and 4,215,426.
[0006] The transmission of acoustic or seismic signals through a drill pipe or the earth
(as opposed to the drilling mud) offers another possibility for communication. In
such a system, an acoustic or seismic generator is located downhole near or in the
drill collar. Typically a large amount of power is required downhole to generate a
signal with sufficient intensity to be detected at the surface. One way to provide
sufficient power downhole (other than running a hard wire connection downhole) is
to provide a large power supply downhole. Further, one reason for the large power
requirement is that when the acoustic transmitter is located downhole near the bit
a large acoustic signal is required to overcome the acoustic noise generated by the
bit during drilling so that the transmitted acoustic signal can be distinguished from
the downhole acoustic noise. An example of an acoustic telemetering system is Cameron
Iron Works' CAMSMART downhole measurement system, as published in the Houston Chronicle
on May 7, 1990, page 3B. Other examples of acoustic telemetry systems are found in
U.S. Patent Nos. 5,050,132, 5,056,067, 5,124,953, 5,128,901, 5,128,902 and 5,148,408.
[0007] The last major prior art technique involves the transmission of electromagnetic ("EM")
waves through a drill pipe and the earth. In this type of system, downhole data is
input to an antenna positioned downhole in a drill collar. Typically, a large pickup
assembly or loop antenna is located around the drilling rig, at the surface, to receive
the EM signal transmitted by the downhole antenna.
[0008] The major problem with the prior art EM systems is that a large amount of power is
necessary to transmit a signal that can be detected at the surface. Propagation of
EM waves is characterized by an increase in attenuation with an increase in distance,
data rate and earth conductivity. The distance between the downhole antenna and the
surface antenna may be in the range of 5,000 to 10,000 feet (1500 to 3000m). As a
result, a large amount of attenuation occurs in the EM signal, thereby necessitating
a more powerful EM wave. The conductivity of the earth and the drilling mud also may
vary significantly along the length of the drill string, causing distortion and/or
attenuation of the EM signal. In addition, the large amount of noise in the drilling
string causes interference with the EM wave.
[0009] The primary way to supply the requisite amount of power necessary to transmit the
EM wave to the surface is to provide a large power supply downhole or to run a hard
wire conductor downhole. Representative examples of EM systems can be found in U.S.
Patent Nos. 2,354,887, 3,967,201, 4,215,426, 4,302,757, 4,348,672, 4,387,372, 4,684,946,
4,691,203, 4,710,708, 4,725,837, 4,739,325, 4,766,442, 4,800,385 and 4,839,644.
[0010] There have been attempts made in the prior art to reduce the effects of attenuation
which occur during the transmission of an EM signal from down near the downhole drilling
assembly to the surface. U.S. Patent No. 4,087,781, issued to Grossi, et al., for
example, discloses the use of repeater stations to relay low frequency signals to
and from sensors near the drilling assembly. Similarly, U.S. Patent No. 3,793,632
uses repeater stations to increase data rate and, in addition, suggests using two
different modes of communication to prevent interference. U.S. Patent Nos. 2,411,696
and 3,079,549 also suggest using repeater stations to convey information from downhole
to the surface. None of these systems has been successful, based primarily on the
varying conditions encountered downhole, where conductivity may range over several
orders of magnitude.
[0011] Another method of transmitting MWD information to the surface using electromagnetic
transmission is described in an article entitled Air-Drilling Electromagnetic, MWD
System Development, IADC/SPE, 1990 by W.H. Harrison et al, which is incorporated herein
by reference. One problem with electromagnetic transmission is the high attenuation
of EM signals in highly conductive formations. Referring to FIGURE 1 herein the attenuation
against source receiver distance is plotted for a 0.2 ohm-meter formation for frequencies
of 1, 5, 10, 15 and 20 Hertz. These calculations are made using the method described
in an article entitled Theory of Transmission of Electromagnetic Waves Along a Drill
Rod in Conducting Rock, 1979 by James R. Wait and David A. Hill, which is incorporated
herein by reference.
[0012] In practice an acceptable total attenuation is about 90 dB. However, in the Harrison
et al article it is erroneously claimed that 120 dB of attenuation is practical. The
slope of the curves (FIGURE 1) at 5000' (1500m) distance is noted on the plot. This
attenuation slope for 20 Hz is 53 dB per 1000 feet (300m) which is clearly too high
for practical transmission for any large distance. At 10 Hz the attenuation of 37
dB per 1000 feet (300m) is still very high, but it would at least allow about 2000
feet (600m) of effective transmission. The reduction of the frequency of operation
to 1 Hz (11.86 dB per 1000 feet (300m)) or perhaps 2 Hz would be required for long
distance communication at resistivities as low as 0.2 ohm-meters. At such a low frequency
the electric transmission method has no real advantage over current mud pulse technology.
[0013] The above-discussed and other problems and deficiencies of the prior art are overcome
or alleviated by the method and apparatus for electric/acoustic telemetry of the present
invention, which relates to a MWD system that senses and electrically transmits data
measurements from a downhole location to an electric/acoustic repeater which acoustically
transmits the data measurements to an acoustic receiver at an uphole location. In
the present invention, one of the drill collar sections of a drill string (i.e., at
the downhole end of the drill string) includes an electric transmitter/receiver assembly
which communicates with an electric/acoustic repeater assembly which communicates
with an acoustic transmitter/receiver assembly uphole of the drill string by the transmission
and receipt of electric and acoustic signals through the drill string. With drill
strings that include downhole motors the electric transmitter/receiver assembly may
be positioned above or below the motor.
[0014] In accordance with one aspect of the present invention, there is provided an apparatus
for transmitting information through a drill string having an upper end and a lower
end with a drill bit disposed at the lower end, comprising: means for transmitting
an electromagnetic data signal from a first location near the lower end of the drill
string; means for receiving said electromagnetic data signal at a second location
between the lower and upper ends of the drill string; means for transmitting an acoustic
data signal from said second location in response to said electromagnetic data signal
received; and means for receiving said acoustic data signal at third location at or
near the upper end of the drill string.
[0015] In the present invention, uphole telemetry comprises an electric current induced
in the drill string by the downhole electric transmitter. The electric current contains
encoded information of downhole conditions and travels up the drill string where it
is detected at the electric receiver of the electric/acoustic repeater. The received
signal is processed to drive the acoustic transmitter of the electric/acoustic repeater.
An acoustic signal containing the encoded information is induced into the drill string
by this acoustic transmitter and permeates up the drill string to the uphole acoustic
receiver. This received signal is processed and utilized to evaluate and/or optimize
the drilling process.
[0016] In the present invention, downhole telemetry comprises an acoustic signal induced
in drill string by the uphole acoustic transmitter. The acoustic signal contains encoded
information of uphole commands and travels down the drill string where it is detected
at the acoustic receiver of the electric/acoustic repeater. The received signal is
processed to drive the electric transmitter of the electric/acoustic repeater. An
electric signal containing the encoded information is induced in the drill string
by this electric transmitter and travels down the drill string to the downhole electric
receiver. This received signal is processed and utilized to command a downhole processor
(i.e., computer).
[0017] The present invention resolves the prior art problems encountered with electromagnetic
and acoustic telemetry by utilizing: (1) electric telemetry (electromagnetic telemetry)
downhole, thereby avoiding the problem of detection at the surface; and (2) acoustic
telemetry uphole, thereby avoiding the problem of acoustic noise near the bit (i.e.,
downhole).
[0018] The above-discussed and other features of and advantages of the present invention
will be appreciated, and understood by those skilled in the art from the following
detailed description and drawings.
[0019] A number of preferred embodiments of the present invention will now be described
by way of example only and with reference to the accompany drawings wherein like elements
are numbered alike in the several FIGURES, and in which:
FIGURE 1 is a plot of amplitude versus source receiver distance for a 0.2 ohm-meter
formation in accordance with the Wait et al model;
FIGURE 2A is a perspective view of a prior art rotary drilling system;
FIGURE 2B is a partially sectional front elevation of a prior art steerable drilling
system;
FIGURE 3 is a cross-sectional elevation view depicting a downhole drilling apparatus
and drill string employing an electric/acoustic telemetry system in accordance with
the present invention;
FIGURE 4 is a cross-sectional elevation view depicting a downhole drilling apparatus
and drill string employing an electric/acoustic telemetry system in accordance with
an alternate embodiment of the present invention;
FIGURE 5 is a cross-sectional elevation view depicting a downhole drilling apparatus
and drill string employing an electric/acoustic telemetry system in accordance with
still another alternate embodiment of the present invention;
FIGURE 6 is a cross-sectional elevation view of the downhole electromagnetic antenna;
FIGURE 7 is a plot of amplitude versus source receiver distance for a 1.0 ohm-meter
formation in accordance with the Wait et al model;
FIGURE 8 is a plot of amplitude versus source receiver distance for a 10.0 ohm-meter
formation in accordance with the Wait et al model;
FIGURE 9 is a plot of amplitude versus source receiver distance for a 1.0 ohm-meter
formation in accordance with an electric dipole model; and
FIGURE 10 is a plot of amplitude versus source receiver angle for a 1.0 ohm-meter
formation in accordance with the electric dipole model.
[0020] During the course of the following description, the terms "uphole", "upper", "above"
and the like are used synonymously to reflect position in a well path, where the surface
of the well is the upper or topmost point. Similarly, the terms "bottomhole", "downhole",
"lower", "below" and the like are also used to refer to position in a well path where
the bottom of the well is the furthest point drilled along the well path from the
surface, and the term "subsurface" indicates a downhole location remote from the surface
of the well. As one skilled in the art will realize, a well may vary significantly
from the vertical, and, in fact, may at times be horizontal. Thus, the foregoing terms
should not be regarded as relating to depth or verticality, but instead should be
construed as relating to the position in the path of the well between the surface
and the bottom of the well.
[0021] Two prior art drilling systems are shown in FIGURES 2A and 2B. FIGURE 2A illustrates
a prior art drilling system that operates solely in a rotary mode, while FIGURE 2B
depicts a prior art steerable system that permits both straight and directional drilling.
The rotary drilling system shown in FIGURE 2A includes a drill bit with a telemetry
device for relaying data to the surface. Above the telemetry device is a sensor sub
which includes a variety of sensors for measuring parameters in the vicinity of the
drill collar, such as resistivity, gamma, weight-on-bit, and torque-on-bit. The sensors
transmit data to the telemetry device, which in turn, transmits a signal to the surface.
[0022] A non-magnetic drill collar typically is located above the sensor modules. Typically,
the drill collar includes a directional sensor probe. The drill collar connects to
the drill string, which extends to the surface.
[0023] Drilling occurs in a rotary mode by rotation of the drill string at the surface,
causing the bit to rotate downhole. Drilling fluid (e.g., drilling mud) is forced
through the interior of the drill string to lubricate the bit and to remove cuttings
at the bottom of the well. The drilling mud then circulates back to the surface by
flowing on the outside of the drill string.
[0024] The prior art steerable system shown in FIGURE 2B has the added ability to drill
in either a straight mode or in a directional or "sliding" mode, as shown in U.S.
Patent No. 4,667,751, which is incorporated herein by reference. The steerable system
includes a motor which functions to operate the bit. In a prior art motor, such as
that disclosed in U.S. Patent No. 4,667,751, the motor includes a motor housing, a
bent housing, and a bearing housing. The motor housing preferably includes a stator
constructed of an elastomer bonded to the interior surface of the housing and a rotor
mating with the stator. The stator has a plurality of spiral cavities, n, defining
a plurality of spiral grooves throughout the length of the motor housing. The rotor
has a helicoid configuration, with n-1 spirals helically wound about its axis (e.g.,
see U.S. Patent Nos. 1,892,217, 3,982,858 and 4,051,910).
[0025] During drilling operations, drilling fluid is forced through the motor housing into
the stator. As the fluid passes through the stator, the rotor is forced to rotate
and to move from side to side within the stator, thus creating an eccentric rotation
at the lower end of the rotor.
[0026] The bent housing includes an output shaft or connecting rod, which connects to the
rotor by a universal joint or knuckle joint. According to conventional techniques,
the bent housing facilitates directional drilling (e.g. see U.S. Patent Nos. 4,299,296
and 4,667,751). To operate in a directional mode, the bit is positioned to point in
a specific direction by orienting the bend in the bent housing in a specific direction.
The motor then is activated by forcing drilling mud therethrough, causing operation
of the drill bit. As long as the drill string remains stationary (it does not rotate),
the drill bit will drill in the desired direction according to the arc of curvature
established by the degree of bend in the bent housing, the orientation of the bend
and other factors such as weight-on-bit. In some instances, the degree of bend in
the bent housing may be adjustable to permit varying degrees of curvature (e.g., see
U.S. Patent Nos. 4,067,404 and 4,077,657). Typically, a concentric stabilizer also
is provided to aid in guiding the drill bit (e.g. see U.S. Patent No. 4,667,751).
[0027] To operate in a straight mode, the drill string is rotated at the same time the motor
is activated, thereby causing a wellbore to be drilled with an enlarged diameter (e.g.
see U.S. Patent No. 4,667,751). The diameter of the wellbore is directly dependent
on the degree of bend in the bent housing and the location of the bend. The smaller
the degree of bend and the closer the placement of the bend is to the drill bit, the
smaller will be the diameter of the drilled wellbore.
[0028] Referring to FIGURE 3, a schematic of a drill string utilizing an electric/acoustic
telemetry system of the present invention is shown. A drilling rig 10 is positioned
on the surface 12 above a borehole 14 which is traversed by a drill string 16. Drill
string 16 is assembled from sections of drill pipe 18 that are connected end-to-end
by tool joints 20. It will be appreciated that additional sections of drill pipe 18
are added to the uphole end of drill string 16 as the hole deepens. The downhole end
of the drill string includes a drill collar 22 comprised of drill collar pipe having
a diameter which is relatively larger than the diameter of drill pipe sections 18.
Drill collar section 22 includes a bottom hole assembly 23 which terminates at a drill
bit 24 and which may include several drill collar sections housing downhole sensors
for sensing parameters such as pressure, position, resistivity or temperature. In
accordance with the present invention, one of the drill collar sections 25 includes
an electric transmitter/receiver assembly 26 which communicates with an electric/acoustic
repeater assembly 28 which communicates with an acoustic transmitter/receiver assembly
29 uphole of drill string 16 by the transmission (and receipt) of electric and acoustic
signals through the drill string.
[0029] Referring to FIGURE 4, in accordance with an alternate embodiment the downhole end
of the drill string includes drill collar 22 and a motor 30 with an extended sub 32
connected to a drill bit 34. Electric transmitter/receiver assembly 26 is disposed
at sub 32 along with at least one downhole sensor. In this embodiment electric transmitter/receiver
assembly 26 and at least one downhole sensor are located downhole of motor 30.
[0030] Referring to FIGURE 5, in accordance with still another alternate embodiment the
downhole end of the drill string includes drill collar 22 with one of the drill collar
sections 35 including electric transmitter/receiver assembly 26 and motor 30 connected
to drill bit 34. Downhole sensors are disposed at a drill collar section 36. In this
embodiment electric transmitter/receiver assembly 26 and the downhole sensors are
located uphole of motor 30.
[0031] Motor 30, for example, comprises a Dyna-Drill positive displacement motor with a
bent housing, made by Smith International, Inc. as described hereinbefore and as shown
in U.S. Patent No. 4,667,751. Other motors, including mud turbines, mud motors, Moineau
motors, creepy crawlers and other devices that generate motion at one end relative
to the other, may be used without departing from the principles of the present invention.
[0032] Referring again to FIGURE 4, motor 30 in accordance with the preferred embodiment,
connects to extended sub 32 which houses at least one sensor module and communicates
via electric transmitter/receiver assembly 26. One particular advantage of this embodiment
is that the extended sub 32 may be removed and used interchangeably in a variety of
downhole assemblies.
[0033] Referring to FIGURE 6 electric transmitter/receiver assembly 26 comprises a sensor
antenna 38 (e.g. a toriod) mounted in an annular channel 40 of the drill collar section
25 (FIGURE 3), 32 (FIGURE 4), 35 (FIGURE 5). As is well known in the art, the toriod
includes a core 42 and an electrical conductor 44 wrapped around the core. Core 42
is preferably comprised of a highly permeable material, such as an iron/nickel alloy.
In the preferred construction, the alloy is formed into laminated sheets coated with
insulation such as magnesium oxide, wound about a mandrel to form the core, and heat
treated for maximum initial permeability.
[0034] The electrical conductor 44 is wound about the core 42 to form the coils of the antenna
38 (i.e., the toriod). The conductor 44 is preferably sheathed in CAPTON, or any other
suitable dielectric material. The sensor antenna 38 preferably is vacuum-potted in
an insulating epoxy 46. In the preferred embodiment, the epoxy comprises TRA-CON TRA-BOND
F202 or equivalent. Electrical leads of conductor 44 pass through a passage 48 to
a sealed hatch 50 in the drill collar, as is known in the art. Hatch 50, for example,
houses the electronics for providing transmitting signals to and/or receiving signals
from antenna 38. The electronics is in communication with downhole sensors, a power
source, downhole memory and signal processor, as is well known. An electric field
generated by the toroid couples a current into the drill string.
[0035] Further, electric transmitter/receiver assembly 26 may be of the type described in
U.S. Patent No. 5,160,925 which is expressly incorporated herein by reference (e.g.,
antenna 25 and associated hardware). Alternatively, an electric field applied across
an insulating joint as a source, may be used to generate a current in the drill string
(i.e., direct-coupled) as is known in the art.
[0036] Electric/acoustic repeater assembly 28 comprises an electric transmitter/receiver
in communication with an acoustic transmitter/receiver. The electric transmitter/receiver
is preferably the same type as electric transmitter/receiver 26 described hereinbefore.
The acoustic transmitter/receiver is preferably the same type as described in U.S.
Patent No. 5,128,901 which is expressly incorporated herein by reference. Electrical
communication is provided between the electric transmitter/receiver and the acoustic
transmitter/receiver. These interfacing signals may require processing in accordance
with the prior art teachings incorporated above.
[0037] Acoustic transmitter/receiver 29 is also preferably of the same type as described
in U.S. Patent No. 5,128,901. Further, it will be appreciated the method of acoustic
transmission may be in accordance with any of the methods taught in U.S. Patent Nos.
5,128,901, 5,128,902 and 5,148,408.
[0038] One advantage of the present invention is that the electric transmission is only
needed at large depth from the surface. The resistivities are usually not as low at
large depths because the porosity is reduced due to the high pressure. By using the
model described in Wait et al the attenuation against source receiver distance is
plotted in FIGURE 7 for a 1.0 ohm-meter formation for frequencies of 1, 5, 10, 15
and 20 Hertz. At 1.0 ohm-meter, a 10 Hz signal is attenuated at the rate of only 16.8
dB per 1000 feet (300m). This attenuation rate should allow for at least 5000 feet
(1500m) of transmission. If greater distances are required the frequency can be lowered
or an electric to electric repeater can be added, as is known. Unfortunately, the
addition of an electric-electric repeater would reduce the data rate by a factor of
two, because the repeater can not transmit and receive at the same time. In any case,
the electric-acoustic repeater 28 is the upper most repeater in the drill string and
is expected to have a range of at least 7000 feet (2100m). With the acoustic signal
covering the top 7000 feet (2100m) and the electric signal covering the bottom 5000
feet (1500m) the telemetry system of the present invention can operate to 12000 feet
(3600m) even under difficult conditions. Again using the Wait et al model the attenuation
against source receiver distance is plotted in FIGURE 8, for a 10.0 ohm-meter formation
for frequencies of 1, 5, 10, 15 and 20 Hertz. The attenuation rate is 6.7 dB per 1000
feet (300m) at 10 Hz so the electric signal can travel about 13000 feet (3900m) giving
a total depth of 20000 feet (6000m) in this more resistive formation (i.e., 7000 feet
(2100m) acoustic transmission and 13000 feet (3900m) electric transmission). The same
depth can be achieved in more conductive formations by either adding electric-electric
repeaters or reducing the frequency, both of which would reduce the data rate.
[0039] In the case of horizontal drilling, the angle between the electric transmitter and
the electric receiver could be as high as 90 degrees. A drill string having a changing
dip can be modeled using an electric dipole source. The electric dipole is a very
poor approximation near the source, but it is correct for large distances as the current
on the surface of the drill string will die off faster than the field of the electric
dipole. This limit will be reached faster in conductive formations or for the higher
frequencies. Referring to FIGURE 9, an electric dipole model for the attenuation against
source receiver distance is plotted for a 1.0 ohm-meter formation for frequencies
of 1, 5, 10, 15 and 20 Hertz. Near the source (i.e., small distances) the electric
dipole plot markedly differs from the equivalent Wait et al model shown in FIGURE
7. However, at 5000 feet (1500m) the attenuation rates for both models are nearly
the same for the higher frequencies. This indicates that the model with the drill
string (i.e., FIGURE 7) has nearly reached the limit where it acts much like a dipole
source. Therefore, we have used the dipole source model (FIGURE 9) to develop the
attenuation against source-receiver angle plot (FIGURE 10) for a source-receiver separation
of 2000 feet (600m) and a resistivity of 1.0 ohm-meter. This clearly indicates that
a null angle in the data does not occur. Further, for situations where the dipole
approximation is not valid there can be no null angle because the electric current
to the drill string is still a dominant component and this current will follow the
drill string around any corner.
[0040] In summary, uphole telemetry in accordance with the present invention comprises an
electric current induced in drill string 16 by electric transmitter 26. The electric
current contains encoded information of downhole conditions as is well known. This
electric current travelling up drill string 16 is detected at the electric receiver
of assembly 28. The received signal is processed to drive the acoustic transmitter
of assembly 28. An acoustic signal containing the encoded information is induced into
drill string 16 by the acoustic transmitter of assembly 28 and permeates up the drill
string to acoustic receiver 29. This received signal is processed and utilized to
evaluate and/or optimize the drilling process, as is known. As described hereinbefore,
an electric-electric repeater may be employed for greater depths. Also, an acoustic-acoustic
repeater may be employed for greater depths.
[0041] Downhole telemetry in accordance with the present invention comprises an acoustic
signal induced in drill string 16 by acoustic transmitter 29. The acoustic signal
contains encoded information of uphole commands as is well known. The acoustic signal
travelling down drill string 16 is detected at the acoustic receiver of assembly 28.
The received signal is processed to drive the electric transmitter of assembly 28.
An electric signal containing the encoded information is induced in the drill string
by the electric transmitter of assembly 28 and travels down the drill string to electric
receiver 26. This received signal is processed and utilized to command a downhole
processor (i.e., computer) as is known.
[0042] It is an important feature of the present invention that the acoustic telemetry is
located away from the noisy downhole environment. The downhole noise presents a significant
problem in efficient acoustic telemetry. It is further an important feature of the
present invention that the electric telemetry is not located uphole where detection
at the surface has posed a significant problem. The present invention resolves these
problems by utilizing: (1) electric telemetry downhole, thereby avoiding the problem
of detection at the surface; and (2) acoustic telemetry uphole, thereby avoiding the
problem of acoustic noise near the bit (i.e., downhole).
[0043] While preferred embodiments have been shown and described, various modifications
and substitutions may be made thereto without departing from the scope of the invention.
Accordingly, it is to be understood that the present invention has been described
by way of illustrations and not limitation.
1. An apparatus for transmitting information through a drill string (16) having an upper
end and a lower end with a drill bit (23;34) disposed at the lower end, comprising:
means (26) for transmitting an electromagnetic data signal from a first location
near the lower end of the drill string;
means (28) for receiving said electromagnetic data signal at a second location
between the lower and upper ends of the drill string;
means (28) for transmitting an acoustic data signal from said second location in
response to said electromagnetic data signal received; and
means (29) for receiving said acoustic data signal at third location at or near
the upper end of the drill string.
2. An apparatus for transmitting commands through a drill string having an upper end
and a lower end with a drill bit (24;34) disposed at the lower end, comprising:
means (29) for transmitting an acoustic command signal from a third location at
or near the upper end of the drill string;
means (28) for receiving said acoustic command signal at a second location between
the upper and lower ends of the drill string;
means (28) for transmitting an electromagnetic command signal from said second
location in response to said acoustic command signal received; and
means (26) for receiving said electromagnetic command signal at a first location
near the lower end of the drill string.
3. The apparatus of claim 1 further comprising:
means (29) for transmitting an acoustic command signal from said third location;
means (28) for receiving said acoustic command signal at said second location;
means (28) for transmitting an electromagnetic command signal from said second
location in response to said acoustic command signal received; and
means (26) for receiving said electromagnetic command signal at said first location.
4. The apparatus of claim 1, 2, or 3 wherein the drill string further includes a motor
(30) in communication with the drill bit (34) and wherein said first location is between
the motor and the drill bit.
5. The apparatus of claim 1, 2 or 3 wherein the drill string further includes a motor
(30) in communication with the drill bit (34) and wherein said first location is above
the motor.
6. The apparatus of any preceding claim further comprising:
means for repeating said electromagnetic data signal at a fourth location between
said first and second locations.
7. A method for transmitting information through a drill string having an upper end and
a lower end with a drill bit (24;34) disposed at the lower end, comprising the steps
of:
transmitting an electromagnetic data signal from a first location (26) near the
lower end of the drill string;
receiving said electromagnetic data signal at a second location (28) between the
lower and upper ends of the drill string;
transmitting an acoustic data signal from said second location (28) in response
to said electromagnetic data signal received; and
receiving said acoustic data signal at a third location (29) near the upper end
of the drill string.
8. A method for transmitting commands through a drill string having an upper end and
a lower end with a drill bit disposed at the lower end, comprising the steps of:
transmitting an acoustic command signal from a third location (29) at or near the
upper end of the drill string;
receiving said acoustic command signal at a second location (28) between the upper
and lower ends of the drill string;
transmitting an electromagnetic command signal from said second location (28) in
response to said acoustic command signal received; and
receiving said electromagnetic command signal at a first location (26) near the
lower end of the drill string.
9. The method of claim 7 further comprising the steps of:
transmitting an acoustic command signal from said third location (29);
receiving said acoustic command signal at said second location (28);
transmitting an electromagnetic command signal from said second location (28) in
response to said acoustic command signal received; and
receiving said electromagnetic command signal at said first location (26).
10. The method of claim 7, 8 or 9 wherein the drill string further includes a motor (30)
in communication with the drill bit (34) and wherein said first location is between
the motor and the drill bit.
11. The method of claim 7, 8 or 9 wherein the drill string further includes a motor (20)
in communication with the drill bit (34) and wherein said first location is above
the motor.
12. The method of claim 7, 8, 9, 10 or 11 further comprising the step of:
repeating said electromagnetic data signal at a fourth location between said first
and second locations.