Note: Descriptions are shown in the official language in which they were submitted.
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DRILL BIT TRACKING APPARATUS AND METHOD
Field of the Invention
This invention relates to the field of tracking objects in a subterranean
medium.
Such objects may include drill bits.
Background of the Invention
The determination of the location of a distant subterranean object may be of
considerable commercial importance in the fields of well drilling, tunnel
boring, pipeline
laying under rivers or other surface obstructions, hard rock mining, and so
on. In
hydrocarbon extraction, a drill string may be 3 to 6 inches in diameter, and
yet may extend
many thousands of feet into the ground. Given the non-homogeneity of the
underlying
geological structure, and the tendency for drill bits to wander, it may be
difficult to know
with reasonable accuracy precisely where the drill bit may be. This issue may
tend to have
enhanced importance in the context of, for example, directional drilling,
where it may be
desired to follow a relatively narrow and possibly undulating geological
feature, such as a
coal seam, a hydrocarbon payzone for oil or gas extraction, an ore vein or
pipe, such as a
kimberlite pipe from which a mineral or other resource is to be extracted, or
the boring of a
utility conduit in an urban area.
There are known methods of addressing these issues, sometimes termed borehole
telemetry. A typical system might involve magnetic sensors that indicate
azimuth angle (i.e.,
compass direction relative to North) and angle of dip. Gyroscopic (i.e.,
inertial) and
magnetic sensors have been used for some time. Adjustments in drilling may
occur on the
basis of these signals. It may also be noted that while borehole telemetry may
pertain to the
absolute position of a drill head, it may also refer to, and have significant
commercial
importance in relation to, the relative position of one bore hole to another,
as in steam
assisted gravity drainage (SAGD) or of bore position relative to a geological
boundary
structure. This problem is discussed in US Patent 7,084,782 of Davies et al.,
issued August
1, 2006, generally from col. 1, line 16 to col. 5, line 17, and particularly
at column 2, lines 3
¨ 53. Among other items, Davies at el., note that:
(a) The drilling operation, and mud motor life, may be optimized by the real
time
transmission of, and adjustment of drilling operations in response to,
measurement data of
natural gamma rays, borehole inclination, borehole pressure, resistivity of
the formation and,
mud motor bearing temperature, and weight on the bit.
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(b) When used with a downhole motor, the mud pulse telemetry system is
typically
located above the mud motor so that it is spaced a substantial distance from
the drilling bit to
protect the electronic components from the effects of vibration. As a result,
the measured
environmental data may not necessary correlate with the actual conditions at
the drilling bit.
A conventional telemetry system may have a depth lag (i.e., a distance offset)
of up to or
greater than 60 feet. It is possible to drill out of a hydrocarbon producing
formation before
detecting the exit, resulting in the need to drill several meters of borehole
to get back into the
pay zone. The interval drilled outside of the pay zone results in lost
production revenue and
may include wasted costs for completing that non-producing interval.
(c) Near bit sensor systems have been developed to provide early detection
of
changes to the formation while drilling, but may still be located a spaced
distance from the
drill bit assembly, giving a lag in determination of formation changes.
Mounting sensors in a
mud motor may be very costly and may reduce system reliability.
(d) Systems permitting relatively high rate, bi-directional, data
transmission have
been developed for sending data to the surface through an electrical line.
However, a drill
string wireline or cable is subject to stress at pipe connections; may be
prone to wear,
damage or destruction during normal drilling operations; and may be somewhat
unreliable
and prone to failure.
(e) Systems have also been developed for the downhole generation and
transmission of acoustic or seismic signals or waves through the drill string
or surrounding
formation. However, a relatively large amount of downhole power is typically
required to
generate sufficient signal strength for surface detection. A relatively large
power source must
be provided or repeaters can be used at intervals along the string to boost
the signal as it
propagates.
This problem is also discussed in US Patent 7,035,165 of Tang, at col. 1, line
35 to
col. 2, line 5: "Recently, horizontal boreholes, extending several thousand
meters ("extended
reach" boreholes), have been drilled to access hydrocarbon reserves at
reservoir flanks and to
develop satellite fields from existing offshore platforms. Even more recently,
attempts have
been made to drill boreholes corresponding to three-dimensional borehole
profiles. Such
borehole profiles often include several bends and turns along the drill path.
Such three
dimensional borehole profiles allow hydrocarbon recovery from multiple
formations and
allow optimal placement of wellbores in geologically intricate formations."
"Hydrocarbon recovery can be maximized by drilling the horizontal and complex
wellbores along optimal locations within the hydrocarbon-producing formations
(payzones).
Crucial to the success of these wellbores is (1) to establish reliable
stratigraphic position
control while landing the wellbore into the target formation and (2) to
properly navigate the
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drill bit through the formation during drilling. In order to achieve such
wellbore profiles, it is
important to determine the true location of the drill bit relative to the
formation bed
boundaries and boundaries between the various fluids, such as the oil, gas and
water. Lack of
such information can lead to severe "dogleg" paths along the borehole
resulting from hole or
drill path corrections to find or to reenter the payzones. Such wellbore
profiles usually limit
the horizontal reach and the final wellbore length exposed to the reservoir.
Optimization of
the borehole location within the formation can also have a substantial impact
on maximizing
production rates and minimizing gas and water coning problems. Steering
efficiency and
geological positioning are considered in the industry among the greatest
limitations of the
current drilling systems for drilling horizontal and complex wellbores.
Availability of
relatively precise three-dimensional subsurface seismic maps, location of the
drilling
assembly relative to the bed boundaries of the formation around the drilling
assembly can
greatly enhance the chances of drilling boreholes for maximum recovery. Prior
art downhole
lack in providing such information during drilling of the boreholes".
"Modern directional drilling systems usually employ a drill string having a
drill bit at
the bottom that is rotated by a drill motor (commonly referred to as the "mud
motor"). A
plurality of sensors and MWD devices are placed in close proximity to the
drill bit to
measure certain drilling, borehole and formation evaluation parameters. Such
parameters are
then utilized to navigate the drill bit along a desired drill path. Typically,
sensors for
measuring downhole temperature and pressure, azimuth and inclination measuring
devices
and a formation resistivity measuring device are employed to determine the
drill string and
borehole-related parameters. The resistivity measurements are used to
determine the presence
of hydrocarbons against water around and/or a short distance in front of the
drill bit.
Resistivity measurements are most commonly utilized to navigate or "geosteer"
the drill bit.
However, the depth of investigation of the resistivity devices usually extends
to 2-3 meters.
Resistivity measurements do not provide bed boundary information relative to
the downhole
subassembly. Furthermore, error margin of the depth-measuring devices, usually
deployed on
the surface, is frequently greater than the depth of investigation of the
resistivity devices.
Thus, it is desirable to have a downhole system which can relatively
accurately map the bed
boundaries around the downhole subassembly so that the drill string may be
steered to obtain
optimal borehole trajectories."
"Thus, the relative position uncertainty of the wellbore being drilled and the
important near-wellbore bed boundary or contact is defined by the accuracy of
the MWD
directional survey tools and the formation dip uncertainty. MWD tools are
deployed to
measure the earth's gravity and magnetic field to determine the inclination
and azimuth.
Knowledge of the course and position of the wellbore depends entirely on these
two angles.
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Under normal operating conditions, the inclination measurement accuracy is
approximately
plus or minus 0.2° Such an error translates into a target location
uncertainty of about
3.0 meters per 1000 meters along the borehole. Additionally, dip rate
variations of several
degrees are common. The optimal placement of the borehole is thus very
difficult to obtain
based on the currently available MWD measurements, particularly in thin pay
zones, dipping
formation and complex wellbore designs."
Commentary on downhole telementry is provided in US Patent 6,781,521, of
Gardner
et al., which issued on August 24, 2004 in the context of transmitting
downhole data to the
surface during measurement while drilling (MWD) (See col. 1, line 46 to col.
2, line 57), as
follows: "Heretofore, in this field, a variety of communication and
transmission techniques
have been attempted to provide real time data from the vicinity of the bit to
the surface
during drilling. The utilization of MWD with real time data transmission
provides substantial
benefits during a drilling operation. For example, continuous monitoring of
downhole
conditions allows for an immediate response to potential well control problems
and improves
mud programs."
"Measurement of parameters such as bit weight, torque, wear and bearing
condition
in real time provides for more efficient drilling operations. In fact, faster
penetration rates,
better trip planning, reduced equipment failures, fewer delays for directional
surveys, and the
elimination of a need to interrupt drilling for abnormal pressure detection is
achievable using
MWD techniques."
"At present, there are four major categories of telemetry systems that have
been used
in an attempt to provide real time data from the vicinity of the drill bit to
the surface; namely,
mud pressure pulses, insulated conductors, acoustics and electromagnetic
waves."
"In a mud pressure pulse system, the resistance of mud flow through a drill
string is
modulated by means of a valve and control mechanism mounted in a special drill
collar near
the bit. This type of system typically transmits at 1 bit per second as the
pressure pulse
travels up the mud column at or near the velocity of sound in the mud. It is
well known that
mud pulse systems are intrinsically limited to a few bits per second due to
attenuation and
spreading of pulses."
"Insulated conductors, or hard wire connection from the bit to the surface, is
an
alternative method for establishing downhole communications. This type of
system is
capable of a high data rate and two way communication is possible. It has been
found,
however, that this type of system requires a special drill pipe and special
tool joint
connectors which substantially increase the cost of a drilling operation.
Also, these systems
are prone to failure as a result of the abrasive conditions of the mud system
and the wear
caused by the rotation of the drill string."
"Acoustic systems have provided a third alternative. Typically, an acoustic
signal is
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generated near the bit and is transmitted through the drill pipe, mud column
or the earth. It
has been found, how ever, that the very low intensity of the signal which can
be generated
downhole, along with the acoustic noise generated by the drilling system,
makes signal
detection difficult. Reflective and refractive interference resulting from
changing diameters
and thread makeup at the tool joints compounds the signal attenuation problem
for drill pipe
transmission."
"The fourth technique used to telemeter downhole data to the surface uses the
transmission of electromagnetic waves through the earth. A current carrying
downhole data
signal is input to a toroid or collar positioned adjacent to the drill bit or
input directly to the
drill string. When a toroid is utilized, a primary winding, carrying the data
for transmission,
is wrapped around the toroid and a secondary is formed by the drill pipe. A
receiver is
connected to the ground at the surface where the electromagnetic data is
picked up and
recorded. It has been found, however, that in deep or noisy well applications,
conventionals
electromagnetic systems are unable to generate a signal with sufficient
intensity to be
recovered at the surface."
"In general, the quality of an electromagnetic signal reaching the surface is
measured
in terms of signal to noise ratio. As the ratio drops, it becomes more
difficult to recover or
reconstruct the signal. While increasing the power of the transmitted signal
is an obvious way
of increasing the signal to noise ratio, this approach is limited by batteries
suitable for the
purpose and the desire to extend the time between battery replacements. It is
also known to
pass band filter received signals to remove noise out of the frequency band of
the signal
transmitter. These approaches have allowed development of commercial borehole
electromagnetic telemetry systems which work at data rates of up to four bits
per second and
at depths of up to 4000 feet without repeaters in MWD applications. It would
be desirable to
transmit signals from deeper wells and with much higher data rates which will
be required
for logging while drilling, LWD, systems."
The problem of transmitting encoded data by acoustic signals is also discussed
in US
Patent 6,614,360 of Leggett et al., issued September 2, 2003, who suggest that
much
preliminary data processing may occur downhole (See col. 3, line 60 to col. 4,
line 30):
"Wireline acoustic technology has been particularly difficult to adapt to MWD
applications. In addition to road noise generated by the drilling assembly
dragging against
the wall of the borehole, there is an additional source of noise generated by
the rotation of the
drill bit and the drill string. Further, the slotted isolation sub technique
used to isolate
transmitters and receivers in wireline applications can not be used in MWD
applications in
that such slots would mechanically weaken the MWD acoustic subassembly to the
failing
point. In addition, the previously described full wave wireline acoustic
measurement
generates tremendous amounts of digital data. These data exceed the telemetry
rates and
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storage capacities of current MWD systems thereby eliminating the option of
processing full
wave acoustic data at the surface. This problem is compounded when other types
of sensors,
comparable in sophistication to corresponding wireline applications, are run
in combination
with full wave acoustic devices. As an example, it is not feasible using
current MWD
telemetry capacity to transmit simultaneously a plurality of full acoustic
wave forms or
gamma ray energy spectra or electromagnetic wave attenuation and phase shift
data, or a
combination thereof, to the surface for processing to determine parameters of
interest at
depth intervals sufficient to obtain the required vertical resolution of the
penetrated
formations. The simultaneous transmission of drilling management sensor
information such
as directional information, weight on the drill bit, and other non formation
evaluation type
measurements still further overloads current MWD telemetry transmission rates
which are of
the order of 2 to 60 bits per second. Furthermore, it is not feasible to store
copious amounts
of raw data downhole sensor data for subsequent retrieval and processing due
to relatively
limited storage capacity of current MWD systems. Acoustic and other MWD
methods for
making multiple formation and borehole evaluation type parametric
determinations
comparable to current wireline measurements require the computation of the
desired
parameters downhole, and the transmission of the computed parameters of
interest to the
surface. By using downhole computational methods, the transmission
requirements are
reduced by orders of magnitude in that only "answers" are telemetered rather
than raw data.
This type of downhole computation is also applicable to other types of non
formation
evaluation type measurements such as signals indicative of the operational
characteristics of
the downhole equipment as well as measurements indicative of drilling
direction and
efficiency."
In summary, the downhole environment may not be benign. It may be relatively
hot.
There may be abrasive and reactive fluids. Equipment used to drill rock may be
subject to
unhelpfully harsh shock and vibration spectra. Consequently, the use of
electrical sensing
and telecommunication equipment and electrical connections in a downhole
environment
may not always work well. Second, the sensing equipment may tend to be
relatively fragile,
and so may tend to be placed behind the mud motor in a coiled tubing system.
The use of
acoustic signal transmission is known, but so too are problems with acoustic
attenuation, and
with the rather limited data transmission rate. Further, it may be difficult
to send acoustic
signals in an acoustically noisy environment given the very significant noise
generation of
the bit itself.
The present inventor has taken a different approach.
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Summary of the Invention
In an aspect of the invention there is a subterranean position detection
apparatus for
detecting the position of a drill bit of a drill string. It includes an
acoustic signal generator
(ASG), the ASG being mounted in proximity to the drill bit. The ASG has a
known acoustic
signature. Sensors are mounted remote from the drill bit. The sensors are
mounted to
monitor subterranean sound in the neighbourhood of the drill string. The
sensors include a
number of sensors sufficient to triangulate position. A signal processor is
connected to
receive observations from the sound sensors. The processor is operable to
establish a
correlation between (a) data from a first, or reference, sensor and (b) the
reference signature.
The processor is operable to apply the correlation to data received at others
of the sensors and
to measure respective phase shifts and total travel time therebetween. The
processor is
operable to employ the computed results to estimate position of the drill bit.
In another feature, of that aspect of the invention, the ASG is a control
sound
generator. In a further feature, the drill string includes a mud motor, and
the ASG is located
between the mud motor and the drill bit. In another feature the ASG is powered
by a flow of
drilling mud. In another feature the ASG has two signatures, or a signature
with two parts.
In another feature the ASG includes a first portion and a second portion, and
the signature
includes a first component emitted by the first portion and a second component
emitted by
the second component. In still another feature the first component is emitted
at a different
rate than the second component. In a further feature the signature includes a
waveform of
varied wavelengths. In still another feature the first and second components
each include a
waveform of varied wavelengths. In another feature the signature is an
acoustic signature
and the first sensor is mounted to monitor sound transmitted in the drill
string. In still yet
another feature the array of sensors includes at least three sensors other
than the first sensor.
In again a further feature the array of sensors includes at least four sensors
other than the first
sensor. In still yet another further feature the apparatus includes a
satellite communications
data uplink and a remote data processing facility. In another feature the
apparatus includes a
mount for the drill bit. In still another feature the apparatus is mounted
within a mud motor
sub. In yet a further feature the apparatus is operable to impose a pressure
wavetrain in
drilling mud supplied to the drill bit. In again another feature the apparatus
includes a piston
and cam follower operable to produce at least a portion of the signature. In a
still further
feature the signature includes a first key having a first number of
oscillations, the oscillations
having different wavelengths from each other; a second key having a second
number of
oscillations, the oscillations having different wavelengths from each other;
and the first and
second keys are emitted at different rates. In a further additional feature,
the rates have a
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prime number relationship. In another feature, the ASG includes at least one
speed reduction
apparatus.
In another aspect of the invention there is a method of locating a drill bit
of a drill
string in a subterranean location. The method includes providing a drill
string having a drill
bit and an ASG in a location proximate to the drill bit, the ASG being
provided with a known
reference acoustic signature; providing an array of subterranean acoustic
sensors; operating
the ASG to emit the acoustic signature during operation of the drill bit;
comparing data from
a first sensor with the known reference acoustic signature; computationally
creating a
modified reference acoustic signal matching the acoustic signature as emitted
from the bit;
comparing data from a plurality of other ones of the sensors with the modified
reference
acoustic signal to find the emitted acoustic signature in the data from the
plurality of other
ones of the sensors; determining phase shift of the emitted acoustic signature
at each of the
other sensors relative to the first sensor; and estimating (i.e., by
calculation) the position of
the drill bit based on comparison of the phase shifts.
In a feature of that aspect of the invention, the signature includes first and
second
components, the first component and the second component being emitted at
first and second
rates, the first and second rates being different. In another feature, the
different rates differ
by a prime number relationship. In still another feature, at least one of the
acoustic signature
includes first and second parts, each of the parts having a non-repeating
series of pulses, and
the method includes repeatedly emitting the non-repeating series of pulses.
In another feature, the first part of the signature is a part having fewer
pulses per unit
of time than the second part, and comparing data from the first sensor
includes comparing the
data with the first part of the signature, adjusting the modified reference
signature on that
comparison, modifying the second part of the modified reference signal
according to
adjustments made to the first part, and looking for the second part of the
modified reference
signal amongst data received at each of the other sensors. In another
additional feature, the
method includes the use of fourier transforms. In another feature, the method
includes
sampling at successive time slices, multiplying the modified reference signal
by the data
observed at those time slices, squaring and summing the results, finding the
phase shift of the
observed data yielding the largest such summed result, and recording the time
difference
between that slice and the corresponding largest summed result slice obtained
from data
received at the first sensor. In another feature, the correction factors
determined in matching
observed data to reference data are reverse applied to produce a plot of drill
bit rotational
speed as a function of time.
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In another aspect of the invention, there is an acoustic signal generator for
use in
subterranean formations remote from an operator. The acoustic signal generator
has at least
a first moving member connected to be driven and at least a first schedule,
the schedule
defining a mechanical noise signature. The moving member being mounted to move
according to the schedule, and, in so doing, to emit a time varying mechanical
signal having
a known signature corresponding to the schedule.
In a feature of that aspect of the invention, there is a fitting to connect
the moving
member to a revolving shaft, whereby power to operate the acoustic signal
generator is
transmitted predominantly through the shaft. In another feature, the first
schedule has the
form of a cam, and one of (a) the moving member is driven to follow the cam;
and (b) the
cam is driven and the moving member moves in consequence of motion of the cam.
In yet
another feature the acoustic signal generator also includes at least a second
schedule, the first
and second schedules being different.
In another feature the generator includes speed altering apparatus operable to
drive
the at least a first moving member at a first speed relative to the first
schedule and a second
speed relative to the second schedule, the first and second speeds being
different. In a further
feature the acoustic signal generator includes a housing mountable to a drill
string of a drill
rig between a mud motor and a drill bit, motion transmission members connected
to drive at
least one of (a) the first moving member and (b) the first schedule, from an
output shaft
driven by the mud motor. In still yet another feature the signal generator
includes a chamber
for containing a fluid, and at least the first moving member is operable to
imposes pressure
fluctuations in the fluid.
In a further aspect of the invention, there is an acoustic signal generator
for use in
subterranean formations. The acoustic signal generator has an enclosure
defining a chamber
for accommodating a fluid; at least one member operable to impose pressure
fluctuations in
the fluid; and at least one schedule. The member is mounted to be driven
according to the at
least one schedule, thereby to impose pressure variations in the fluid having
a known
signature.
In a feature of that aspect of the invention, the apparatus includes fittings
for
mounting the acoustic signal generator in a drill string between a mud motor
and a drill bit.
In another feature, the enclosure has a port to permit fluid to move in and
out of the chamber.
In still another feature the chamber has a connection fitting permitting the
chamber to
mounted in fluid communication with a supply of drilling mud. In a further
feature, the
generator includes at least the first schedule and a second schedule and a
speed altering
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member, the at least one moving member being connected to impose pressure
fluctuations in
the fluid according to at least the first schedule and the second schedule,
the speed altering
member being mounted to cause the at least one moving member to move at a
first speed
relative to the first schedule and a second speed relative to the second
schedule. In still
another feature the signal generator has a housing defining the enclosure, the
housing being
mountable to a mud motor of a drill string, the signal generator has drive
fitting by which to
drive the generator from a shaft output of the mud motor, the chamber having
ports by which
drilling mud from the mud motor can communicate with the chamber, and the at
least one
member operable to impose pressure fluctuations includes at least one
reciprocating piston,
the at least one schedule includes a cam, and the piston is driven by a cam
follower co-
operably mounted to the cam.
In yet another feature, there is the use of the subject matter of any of the
apparatus or
methods to provide an estimate of location of a subterranean drill bit. And,
still another
feature includes the method of using any of the apparatus of any of the
aspects or features to
provide an estimate of location of a subterranean drill bit, whether according
to the method
aspect or features noted above in their various possible permutations and
combinations, or
according to other features and aspects described herein below.
Brief Description of the Illustrations
The invention may be explained with the aid of the accompanying illustrations,
in
which:
Figure la is a general representation in cross-section of a geological
formation establishing
an example of a context to which the description that follows may apply, and
includes an embodiment of drill rig incorporating aspects of the present
invention;
Figure lb is a plan view of the geological formation of Figure la;
Figure 2a is a side view of an end portion of a drill string of the drill rig
of Figure la;
Figure 2b shows a sectional detail of the drill string end portion of Figure
2a including an
acoustic signal generator;
Figure 3a shows a cross-sectional view of an acoustic signal generator for the
end portion of
the drill string of Figure 2b;
Figure 3b shows an alternate embodiment of acoustic signal generator to that
of Figure 3a;
Figure 3c shows a further alternate embodiment of acoustic signal generator to
that of Figure
3a;
Figure 3d shows another alternate embodiment of acoustic signal generator to
that of Figure
3a;
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Figure 4a shows a first schedule for the a cam of the acoustic signal
generator of Figure 2b;
and
Figure 4b shows a second schedule for another cam of the ASG of Figure 2b.
Detailed Description
The description that follows, and the embodiments described therein, are
provided by
way of illustration of an example, or examples, of particular embodiments of
the principles
of the present invention. These examples are provided for the purposes of
explanation, and
not of limitation, of those principles and of the invention. In the
description, like parts are
marked throughout the specification and the drawings with the same respective
reference
numerals. The drawings are not necessarily to scale and in some instances
proportions may
have been exaggerated, the more clearly to depict certain features of the
invention.
The terminology used in this specification is thought to be consistent with
the
customary and ordinary meanings of those terms as they would be understood by
a person of
ordinary skill in the art in North America. While not excluding
interpretations based on other
sources that are generally consistent with the customary and ordinary meanings
of terms or
with this specification, or both, on the basis of other references, the
Applicant expressly
excludes all interpretations that are inconsistent with this specification,
and, in particular,
expressly excludes any interpretation of the claims or the language used in
this specification
unless supported by this specification or in objective evidence of record,
such as may
demonstrate how the terms are used and understood by persons of ordinary skill
in the art, or
by way of expert evidence of a person or persons of experience in the art.
In terms of general orientation and directional nomenclature, two types of
frames of
reference may be employed. First, inasmuch as this description pertains to
drill bits that most
typically are driven rotationally about an axis of rotation, and that advance
along that axis,
and although a well may not necessarily be drilled vertically, terminology may
be employed
assuming a cylindrical polar co-ordinate system in which the nominally
vertical, or z-axis,
may be taken as running along the bore of the well, and may be defined by the
axis of
rotation of the drill bit or the centerline of the bore. The circumferential
direction is that
through which angles, angular velocity, and angular accelerations, (typically
theta, omega
and alpha) may be measured, often from an angular datum, or angular direction,
in a plane
perpendicular to the axial direction. The radial direction is defined in the
plane to which the
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axial direction is normal, may be taken as having the centerline of the bore
as the origin, that
bore being taken as being, at least locally, the center of a cylinder whose
length is many
times its width, with all radial distances being measured away from that
origin.
The second type of terminology uses the well head as a point of reference. As
may
be appreciated, while there is a local polar-cylindrical co-ordinate system,
the bore need not
be straight, and in horizontal or directional drilling is unlikely to be
straight, but may tend to
curve or deviate, and may do so deliberately according to deliberate steering.
In this context,
the bore may have an azimuth or compass direction, an angle of inclination
(i.e., a dip angle),
and may proceed on a given radius of curvature, which itself may vary. In this
frame of
reference, "upstream" may generally refer to a point that is further away from
the outlet of
the well, and "downstream" may refer to a location or direction that is closer
to, or toward,
the outlet of the well. In this terminology, "up" and "down" may not
necessarily be vertical,
given that slanted and horizontal drilling may occur, but may be used as if
the well bore had
been drilled vertically, with the well head being above the bottom of the
well. In this
terminology, it is understood that production fluids flow up the well bore to
the well head at
the surface. Finally, it may be desired to convert from this frame of
reference to a grid or
map reference with a depth, which, though formally a polar co-ordinate system
(latitude,
longitude, and depth) is, at the scale of interest essentially Cartesian (two
horizontal grid
references, pus a vertical reference for depth).
Considering Figure la, which is not drawn to scale, and which is intended to
convey
conceptual understanding, by way of a broad, general overview and only for the
purposes of
illustration, a geological formation is indicated generally as 20. Geological
formation 20 may
include a first mineral producing region 22, and a second mineral producing
region 24 (and
possibly other regions above or below regions 22 and 24). Region 22 may be
below region
24, possibly significantly below. For example, region 22 may generally lie
perhaps 1000-
7000 m below the surface, whereas region 24 may tend to lie rather less than
1000 m from
the surface.
Region 22 may include one or more pockets or strata 23, 25 that may contain a
fluid
that is trapped in a layer 26 by an overlying layer 28 that may be termed a
cap. The cap layer
28 may be substantially impervious to penetration by the fluid. In some
instances the fluid in
layer 26 may be a mixture having a significantly, or predominantly,
hydrocarbon based
component, and may include impurities whether brine, mud, sand, sulphur or
other material
which may be found in various types of crude oil. It may also include
hydrocarbon gases,
such as natural gas, propane, butane, and so on, and various impurities as may
be. The fluid
may be under low, modest, or quite high pressure. The vertical through
thickness of the
CA 02806516 2013-02-19
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potential or actual production zone of region 22 may be of the order of less
than 10 ft, to
several hundred feet, or perhaps even a few thousand feet. The overburden
pressures in this
zone may be quite substantial, possibly well in excess of 10,000 psi.
Region 24 may include one or more mineral bearing seams, indicated generally
as 30,
and individually in ascending order as 32, 34, 36, and 38. It may be
understood that Figure 1
is intended to be generic in this regard, such that there may only be one such
seam, or there
may be many such seams, be it a dozen or more. Seams 32, 34, 36, and 38 are
separated by
interlayers indicated generally as 40, and individually in ascending order as
42, 44, 46, and
an overburden layer 48 (each of which may in reality be a multitude of various
layers), the
interlayers and the overburden layer being relatively sharply distinct from
the mineral
bearing seams 30, and relatively impervious to the passage of fluids such as
those that may
be of interest in seams 32, 34, 36 and 38. It may be noted that seams 30 may
be of varying
thickness, from a few inches thick to several tens of feet thick. Seams 30
may, for example,
be coal seams. One or more of those mineral bearing seams may be porous, to a
greater or
lesser extent such that, in addition to the solid mineral, (which may be coal,
for example),
one or more of those seams may also be a fluid bearing stratum (or strata, as
may be), the
fluid being trapped, or preferentially contained in, that layer by the
adjacent substantially
non-porous interlayers. The entrapped fluid may be a gas. Such gas may be a
hydrocarbon
based gas, such as methane. The entrapped fluid may be under modest pressure,
or may be
under relatively little pressure. It may be that the operator wishes to drill
along one of these
relatively thin stratified formations in an attempt to enhance recovery.
Alternatively, the
operator may wish to drill a path from one relatively small potential
production pocket 23 to
another 25, so linking and making economically viable, the recovery from
deposits that
would not otherwise merit recovery.
In directional drilling, the drill bit may typically be mounted at the end of
a coil that
is conveyed down the bore from a drill rig located at the surface. The drill
string is most
typically 3 IA, 4, 4 IA, or 5 inches in diameter, and is made of sections of
hollow pipe, usually
1/2 inch thick. Cutting fluid, in the nature of water or drilling mud is
forced down the inside
of the hollow drill string under pressure, and flows back up the generally
annular space about
the drill string, and back to the surface. The deeper the well, the higher
proportion of drilling
mud as opposed to water. The drilling mud is driven by pumps, which are
usually duplex or
triplex pumps. A duplex pump is a double acting reciprocating pump. A triplex
pump is a
positive displacement, reciprocating pump that has three plungers. Triplex
pumps are the
most commonly used pump configuration for drilling and well service
operations. Both
duplex and triplex pumps tend to yield a vibrating or pulsating effect in the
drilling fluid, an
effect that may be more pronounced when duplex pumps are used. A duplex pump
running
CA 02806516 2013-02-19
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at 60 r.p.m. will emit 240 pulsations per minute, a triplex single acting pump
will emit 180
pulses per minutes. These pulses can be observed in the drill string. Output
flow may be of
the order of 1.0 to 2.0 cubic meters per minute, or roughly 4 to 8 U.S.
gallons per second.
More commonly the flow rate may be in the range of 1.3 to 1.6 cubic meters per
minute. For
a hollow pipe having an internal bore of 2 1/4 or 2 'A inches, this will give
a velocity of
roughly 20 to 30 ft/s. The pressure at the outlet of the pump may be in the
range of about
400 or 500 to about 1500 p.s.i., and may run in the narrower band of about 800
p.s.i. to about
1000 p.s.i.
A drill string may have a very high aspect ratio of length to diameter, and a
certain
overall springiness or resilience both longitudinally and torsionally. The
lower end of the
drill string may include a number of sections of drill collars. Drill collars
are often thick
walled steel pipe sections about 30 ft long, and may have an inside diameter
of 2 1/4 or 2 1/2
inches, and an outside diameter of 5 or 6 inches. A drill string may have
e.g., 18 or 24 such
drill collars at the bottom end. These drill collars may tend to function
somewhat like a
plumb bob. A conveyed drill string may include a mud motor, which may be
mounted below
the drill collars. The mud motor is a kind of hydraulic motor driven by the
flowing drilling
mud. The rotational speed of the bit itself is then the sum of the rotational
speed of the drill
string (if it is rotating), plus the rotational speed of the mud motor. The
drill bit is mounted
below the mud motor. Drill bit speeds employed with the drill bits described
herein may be
in the range of about 100 or 120 r.p.m. to about 150 r.p.m.
Not all of the weight of the drill string bears upon the drill bit. The upper
end of the
drill string is held back, or held in tension, such that a portion of the
weight of the drill
collars bears on the drill bit, forcing it forward at the bottom of the well
bore. That portion is
typically about a third or less, and may be about 1/4 or 1/5. That is, where a
set of drill collars
weighs 36,000 to 50,000 lbs, the string may be held back such that perhaps
only about
10,000 to 12,000 lbs bears on the bit.
Given that the drill string is quite long, and given that torque at the drill
bit face is
reacted by twist in the drill string, the orientation of the body of the mud
motor may vary.
Also, given that the bit may catch and release, or run slower and then break
free, neither the
speed of rotation of the drill bit, nor the actual angular position of the mud
motor body (i.e.,
the end of the supposedly non-rotating part of the drill string) is constant.
Further still, in
addition to noise made by the pumps, the engagement of the drill bit with the
end of the
borehole and mud motor operation may tend to generate acoustic noise.
CA 02806516 2013-02-19
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In one example, as in Figures 2a, 2b and the somewhat conceptual illustration
of
Figure 3a, there may be a drill string 50, that extends from head end
apparatus 52, which
may be a drill rig 54 or a drilling truck, or similar equipment. In this
example, the drill string
may include conveying pipe 58 that is hollow, and through which drilling mud
is pumped
under pressure. There may be a regular pipe region 60, and a drill collar
region 62. A mud
motor 64 may be mounted at the downhole end of drill string 50. In one
embodiment, the
mud motor may have an inlet for drilling mud, a torque conversion section,
which may
include a helical impeller, or similar device, which impeller may drive an
output shaft 70. A
drill bit 72 may be rigidly mounted to the end of output shaft 70, so that
when shaft 70 turns,
drill bit 72 also turns. The mud motor body 74 is rigidly mounted to the end
of the drill
string. In this embodiment mud motor body 74 is a stator, having the same
angular
orientation about the longitudinal axis of the drill string as does the end of
the drill string to
which it is mounted. I.e., there is no relative rotation between the two. An
acoustic
emission member, or module, 80 may be mounted between mud motor 64 and drill
bit 72.
Output shaft 70 is hollow, and carries drilling mud, M, in the direction of
arrow 'A' to bit 72.
The drilling mud exits through tubes , or bores, or jets, 76 mounted in the
face of drill bit 72,
between cutters 78, and carries cuttings away from the cutting face and back
toward the
surface along the annular space defined between the drill string and the
borehole wall.
Module 80 may include a body 82 that may be rigidly mounted to the lower end
of
the mud motor body 74. In this embodiment body 82 may also be a stator. Body
82 may be
hollow, and may include a first signal generator assembly 84 and a second
signal generator
assembly 86, encased within an outer peripheral wall 90, which may be a
circular cylindrical
wall. Body 82 may also include two transverse end walls, or bulkheads that
extend cross
wise in the form of annular discs. A first, or upper, transverse wall 88 may
provide a flanged
interface for connection to the lower end of the mud motor body. The radially
outer
peripheral margin of wall 88 mates with one end of cylindrical peripheral wall
90. Wall 88
has a central aperture, or penetration 94 through which shaft 70 extends.
Penetration 94 may
be provided with appropriate seals 96 and bearings or bushings such as may
tend to exclude
drilling mud. At the far, or lower, end of wall 90 there may be a second
transverse wall, or
bulkhead, 92, having a radially outer peripheral margin mated with the
downhole end of
cylindrical peripheral wall 90. This may be a welded connection, or bulkhead
92 and wall 90
may be machined from a single solid part. Bulkhead 92 may have a central
aperture 98
through which shaft 70 extends. Seals and suitable bearings or bushings are
mounted
adjacent aperture 98 to discourage the entry of drilling mud. Cylindrical wall
90 may include
an axially extending skirt 100 that extends to sit in close proximity to the
axially rearwardly
facing annular backface of drill bit 72. In use, inasmuch as there ought to be
no pressure
difference across the small space, drilling mud may tend to flow rearwardly
along the outer
CA 02806516 2013-02-19
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generally cylindrical face of the rearward portion of the rotation drill bit,
and then over the
outside of the skirt face, as at arrow `13'.
A third member or wall assembly 102 may be located intermediate upper wall 88
and
lower wall 92. Assembly 102 may, in effect, define a cylinder block. Assembly
102 may
include upper and lower axially spaced apart plates 104 and 106. A cylinder
108
accommodates reciprocation of first and second opposed pistons 110, 112.
Cylinder 108 is
perforated as at 114 in locations between pistons 110, 112, such that motion
of those pistons
will tend variably to draw in or expel fluid from the space defined within
cylinder 108 and
pistons 110, 112. An inner, annular chamber wall or diaphragm 116 extends
circumferentially about shaft 70 at a radial distance between shaft 70 and
cylinder 108. An
annular chamber 118 is then defined radially outside diaphragm 116, radially
inside wall 90,
and axially between plates 104 and 106. This chamber may be filled with a
relatively clean
incompressible fluid, such as silicon oil. Shaft 70 may be reinforced by a
doubler collar 120
that extends between plates 104, 106. Plates 104, 106 may have annular flanges
122, 124
that have seals that engage collar 120. Another chamber, 126, is thus defined
axially
between plates 104, 106, radially inwardly of diaphragm 116, and radially
outwardly of
doubler collar 120. Both doubler collar 120 and shaft 70 have apertures formed
therein, as at
128, 130 permitting fluid communication between chamber 126 and the hollow
interior of
shaft 70. Motion of either or both of pistons 110, 112 will tend to cause
diaphragm 116 to
flex, and thus to alter the volume of chamber 126, urging drilling mud either
into or out of
chamber 126. This motion may tend to result in pressure pulses being imposed
upon, and
being transmitted by, the mud M flowing along shaft 70 and out jets 76.
Chamber 126 may
be a resonating chamber, or a flexing chamber.
Pistons 110 and 112 are driven by cam followers 132, 134, whose connecting
rods
133 may be carried in guides 136. First signal generator apparatus or assembly
84 may
include a radially extending cam carrier disc 138 is mounted to shaft 70 and
extends radially
outwardly therefrom. A peripheral cylindrical cam plate 140 is mounted about
disc 138.
Cam plate 140 has first and second cam edges 142, 144, upon which upper and
lower rollers
143 of cam followers 132, 134 ride. Rotation of shaft 70 will then cause
rotation of plate 140
with respect to the (relatively) stationary angular positions of cam followers
132, 134, and
will thus cause axial reciprocation of piston 110. Piston 110 may have
appropriate seals
riding inside the walls of cylinder 108. While piston 110 and cylinder 108
maybe circular in
cross-section, they may also be non-circular. To the extent that chamber 120
is filled with a
substantially incompressible fluid, reciprocation of pistons 110 may cause
flexing of the
chamber, and the emission of acoustic pressure waves.
CA 02806516 2013-02-19
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Second signal generator assembly 86, which drives piston 112 in substantially
the
same manner as piston 110 is driven, is substantially similar to first signal
generator
apparatus or assembly 84, but may differ therefrom in having cam edges 146,
148 that may
have a different profile or schedule than those of cam edges 142, 144.
Further, second signal
generator assembly 86 may include a gear reducer, shown schematically and
identified as
150. Gear reducer 150 may have a speed reduction ratio that is a prime number
fraction of
the rotational speed of shaft 70 more generally, such as 1/7 or 1/11, and so
on, with a
corresponding ratio of rotational speed to the other signal generator
assembly.
Although the cams or cam profiles defined by cam edges 142, 144 and 146, 148
may
have different shapes or schedules, they may also be the same, as, for example
where a gear
reducer such as a speed reducer or gear reducer 150 is used. In any case, a
first pair of cam
schedules 152, 154 are shown in Figures 4a and 4b respectively, which may
correspond,
respectively to the shapes of cam edges 142, 144 and 146, 148. These schedules
are shown
in terms of rotational angle, one turn of shaft 70 corresponding to 360
degrees of rotation. In
both of Figures 4a and 4b, which show the cam schedules in developed views
(i.e., as if
unrolled and laid flat), the rotational position with respect to shaft 70,
taken at an arbitrary
angular datum, is indicated relative to angle in degrees, 0, 90, 180, 270 and
360 being shown.
The waves of the schedules of reciprocation of the pistons are labelled in
radians, 0, it, 2n,
3n, 4n, 5n, 6n, 7n, 8n, and 9n, with the maxima and minima of amplitude
occurring at
integer multiples of it. In this annotation, then, the one rotation (i.e., 360
degrees of rotation)
of shaft 70 in Figure 3a equates to 10n , or five cycles, of oscillation or
reciprocation of the
driven piston, be it 110 or 112, with the waves being of non-uniform
wavelength. Cam
schedule 152 (Figure 4a) may be one having a relatively larger number of waves
or
excursions per cycle than cam schedule 154 (Figure 4b) of cam 146, as
suggested by the
difference between Figures 4a and 4b, in which schedule 152 has five cycles in
360 degrees,
and schedule 154 has one cycle (i.e., in the zone annotated 0, it, 2n). It may
be noted that
even this cycle may not be a true sinusoid, but rather one having the
mechanical equivalent
of frequency modulation, the first half of the cycle from 0 to it having, in
effect, a different
wavelength from the second half of the cycle from n to 2n. The waves need not
be sinusoids
or quasi-sinusoids, but could be other shapes. The choice of cam shape is
somewhat
arbitrary, and is, in essence, the selection of the shape of an acoustic "key"
or signature. The
number of cycles chosen is to some extent arbitrary. Although the amplitude of
all of the
cycles may be equal, this need not necessarily be so. The amplitude of each
wave could be
different. It may, however, be convenient that the amplitudes be the same, or
substantially
the same.
CA 02806516 2013-02-19
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In one embodiment, both assemblies 84 and 86 used the same cam schedule, that
of
Figure 4a. This schedule 154 of cam 142 may includes a waveform that has waves
of
different wavelength, as at 156, 158, 160, 162 and 164. It may be that no two
consecutive
waves of cam schedule 132 are of the same wavelength, or it may be that
several waves are
of the same wavelength, with one or another waves having a distinctly
different wavelength.
In each case cam 142 may tend to have a characteristic signature, or key, of a
time varying
waveform in which the waveform itself is, in a sense, frequency modulated so
that a listener
(or one having appropriate listening apparatus in the form of sensors and
signal processors)
may correlate the sound of the wave crests with a particular point in the
cycle. As may be
appreciated, where the schedules of Figures 4a and 4b are used together,
without gear
reduction, the single distortion of schedule 152 may tend to add a low
frequency bump to the
higher frequency ripple of schedule 154 once per revolution. It may be that a
single cam,
cam follower and piston arrangement could be supplied with the combined
waveform of both
schedule 132 and schedule 134. It may be noted that acoustic emission module
80 is located
very close to the drill bit ¨ i.e., it is immediately behind the drill bit,
perhaps 2, or 3 feet
away, as opposed to as much as 20, 30 or 50 feet away, and the pressure pulses
are carried to
the work face by jets 76.
Considering wavelengths 156, 158, 160, 162, and 164, again, it may be that
these
wavelengths vary by a non-harmonic amount. For example, using the first half
of
wavelength 156 as a datum (i.e., the portion from 0 to 70, the second half
wavelength (the
portion from IT to 2n) may be a certain amount shorter. In one embodiment it
may be 7 % of
the datum length shorter. The first half of wavelength 158 (from 2n to 3n) may
be still
shorter, this time 14% shorter than the datum length. The second half of
wavelength 158
may be shorter again, this time 21 % shorter than the datum, and so on by 7 %
decrements
until the last half of wavelength 164 (from 9n back to 0) is 70 % shorter.
If the same pattern is used on a gear reducer at a gear reduction of 7:1, the
pattern of
superimposed waves will not repeat itself for 49 revolutions of drill shaft
70. For a shaft
turning at 150 r.p.m. (relatively fast) this corresponds to roughly 20
seconds. In terms of
acoustic sampling and data processing, this is a very long time, and may tend
to assist the
signal processing equipment in identifying unique points in the pattern. It
may also help to
keep in mind that the key signatures, both the slow signature of assembly 86
and the fast
signature of assembly 84, are repeating signatures of known shape.
The embodiment of Figure 3b is intended to illustrate an ASG module 170 in
which
the cylinder need not be between the two wave generation assemblies, but
rather could be at
one end, with wave generator assemblies 172, 174 (which correspond to 84 and
86) stacked
CA 02806516 2013-02-19
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at one end of body 90, and driving separate pistons 176, 178 in separate
cylinders 180, 182 at
the other. While this embodiment could be mounted on the end of the mud motor,
such an
installation, or a conceptually analogous installation could also be mounted
within the end of
the mud motor sub at or near the location at which the drilling mud re-enters
drill shaft 70.
The embodiment of Figure 3c is intended to illustrate an ASG module 190, which
may otherwise be substantially the same as that of either Figure 3a or 3b, in
which each of
the wave generators is provided with a gear reducer, be it 192 or 194. These
gear reducers
may have relatively close gear ratios, such that a beating phenomenon is
produced. For
example, one gear ratio might be at a reduction of 6.7: 1, while the other
might be at a
reduction of 7.3:1. In another embodiment, one ratio may be 7:1, and other may
be 11:1, and
so on. As before, the choice of speed ratios may be based on prime numbers
(7,11, and 67,73
in the above examples). This might tend to produce a slowly repeating
signature, with the
characteristic signature sequence of each cam repeating over and over within
that longer
beating.
The embodiment of Figure 3d is intended conceptually to illustrate an ASG 200
in
which pistons 202 and 204 are driven by solenoids 206 and 208. Solenoids 206
and 208 are
in turn driven according to known electronic schedules (the electronic
schedules being
analogous to the cams discussed above, and therefore providing the
characteristic signature
key) from a processor 207 (or from a suitable analogue device) by accumulated
charge from
positive and negative charge storage devices in the form of capacitor banks
210, 212, which
are in turn charged from a de generator 218 driven by shaft 70 (to which the
rotor is
mounted) turning within housing 90 (to which the stator is mounted).
In each of these embodiments the mechanical fluid power available in the
drilling
mud stream is used to drive a mechanical energy conversion device that
converts a portion of
the energy of the flow into an emitted waveform, the sounds of that wave form
(a) being
detectable at the surface; and (b) being characteristic, with a known key or
signature, that
repeats over time.
An array of listening sensors 220 may be located on the surface. Array 220 may
include a first listening sensor 222 located at the well head to pick up the
acoustic signal
emitted by module 80 (or 170, 190 or 200, as may be). There may also be other
listening
sensors, spaced well away from sensor 222. That is, there may be second,
third, fourth and
fifth sensors 224, 226, 228 and 230. There may be more than a total of 5
sensors, as broadly
illustrated in Figures la and lb. The sensors may, for example, be located in
a square or
diamond shape with sensor 222 at the center. The location of these sensors may
be very
CA 02806516 2013-02-19
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accurately known, i.e., to the accuracy of laser operated devices. Also quite
accurately
known is the length of the drill string and its mechanical properties. The
drill string
penetrates through all variations in geological structure between the wellhead
sensor 222 and
drill bit 72, and is itself is a relatively effective carrier of acoustic
pressure waves. Hence
sensor 222 may be mounted to monitor sound in the drill string, and may be
used as a
reference or datum reading.
The observations of acoustic signals may be fed from sensors 222, 224, 226,
228 and
230 (and any others) to a signal processing apparatus or facility. While this
facility may be
located in a mobile unit, such as the drill rig truck 232, it may also be
remote, and connected
by a telecommunications uplink and transmitted by satellite 234 to a distant
location. That is,
the signal processing facility may be far away in a city or other fixed
facility, and need not
necessarily be in the field, or even in the same country, as the drilling rig
and sensors.
The cam schedules of assemblies 84, 86 (as may be) are known. The signal
processor
first considers the acoustic signal received at sensor 222, and seeks to find
the acoustic
signature that would be associated with cam schedules of assemblies 84,86
based on their
assumed speed of rotation according to the recorded shaft speed and rotation,
and on the first
order assumption of a relatively constant speed of rotation of shaft 70. On
this assumption,
most of the background acoustic noise may be filtered out, leaving the
relatively weak
emitted signal of cam schedules. The signal processor may start by seeking the
slow or
coarse signal of assembly 86, may process and refine that signal by digital
methods (e.g., by
fourier analysis), and may, using those corrections, then seek the fast, or
fine, signal of
assembly 84. After the initial coarse filtering, the signal processor then
makes a fine analysis
of the asynchronous variation in period of the signals emitted according to
the coarse cam
schedule be it 152, 154 or some other as may be. The locations of maxima
(points of
maximum sound emission) and minima (points of intersection with the time axis
at
magnitude zero) and the phase shift may be determined. Since the correct
proportions of the
relative spacing of the maxima and minima is known from the reference key,
(the known
profile of the waveform of the cam, be it 152 or some other) a time correction
factor may be
obtained for each portion (e.g., each quarter cycle) of the asynchronous wave
form of the
key, and the data between the successive maxima and minima stretched (or
compressed, as
may be) temporally to yield a modified, or adjusted, curve that fits the data
to the shape of
the reference key. This allows a correction to be made such as may tend to
account for
twisting, sticking and jumping of the drill bit. Once corrected on this scale,
a more accurate
approximation of bit rotational speed as a function of time may be made. With
this corrected
approximation, the signal processing apparatus searches the received downhole
acoustic data
for the modified frequency modulated signature, or key, of the higher speed
cam schedule,
CA 02806516 2013-02-19
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applying the corrections previously derived by analysing the variation of the
coarse or slow
signal as compared to the expected coarse waveform. The received data is
analysed again,
wave by wave, and the presumed signature is stretched or shrunk, or otherwise
modified to
match the time variation in the actual signal. From this wave relaxation and
fitting process,
the signal processor establishes the actual (or close to the actual) shape of
the acoustic
waveform signal that may be expected to be observed at the other sensors.
Again, the
background noise of the drill rig is filtered out, tending to leave the
desired, relatively higher
frequency signal. Although this signal may be relatively weak compared to the
background
noise of the drilling operation more generally, the ability to perform a
signal processing
analysis on a waveform of a known shape allows that noise to be filtered out,
and allows
repetitions of the higher frequency forms to be digitally overlaid, or
synthesized to build up a
stronger output result. Once filtered, or adjusted in this way, the signal
processor analyses
the observed waveforms at each sensor working forward in time from the signal
received at
sensor 222. The signal processor can work in very fine slices of time (of the
order of
millionths of seconds) and can then work forward until it finds a signal that
superimposes
well on the signal it seeks. This permits a signal phase shift and travel time
to be calculated
relative to the signal received at sensor 222. This phase shift in time is a
proxy for distance
from the drill bit to the sensor in question. This same phase shift
determination can be made
for each of the sensors. From this phase shift information, and knowing the
speed of wave
propagation in the underlying geological formation, the signal processor can
determine the
location of the drill bit to a reasonable level of approximation or accuracy.
This is
particularly so if such data is recorded and analysed continuously from the
time the bit enters
the bore at the well head.
In operation, a drill bit may turn at perhaps 100 ¨ 150 r.p.m., and may
advance a few
meters per hour into the geological formation. For example, if the drill bit
advances 3.6 m
per hour, the advance may be of the order of 1 mm per second, or about half a
millimetre per
revolution. Thus taking a sampling over a period of a minute may give a number
of cycles of
data corresponding to that generated by 100 to 150 revolutions of the drill
shaft, with an
advance of perhaps 6 cm (i.e., less than 3 in.), and rather less than one
diameter of the drill
bore. Even at twice or thrice this speed of forward advance, the introduction
of a locational
error due to the advance of the bit may tend to be small. For a continuously
monitored
process, even this source of error may be considered, and an adjustment in the
output data
made accordingly to improve the approximation. The use of a repeating key, and
of digital
relaxation of the observed data to match the known shape of the key, may tend
to permit
many dozens, or hundreds, of data points to be overlaid and summed, yielding a
synthesized
output signal that is, in effect, computationally enhanced somewhat as if it
had been an
CA 02806516 2013-02-19
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analogue signal passed through an amplifier, giving an equivalent of a signal
hundreds (or
perhaps even thousands) of times more powerful than a single pulse.
Furthermore, in traditional electronic telemetry systems, the electrical power
available at the downhole location may tend to be quite limited, and may
result in signal
strengths of 5 or 10 W. Even if the signal strength were 40 of 50 W, that
pales in comparison
to the power available in the drilling mud, which may be driven by a duplex or
triplex pump
running at perhaps a few hundred kW. In the embodiment described, the
reciprocating
position assembly my be running at 4 or 5 hp, i.e., 3 ¨ 4 kW. This may tend to
give a rather
large potential signal strength. Furthermore, the point at which this signal
strength becomes
most apparent is at the head of the drill string where the drilling mud that
is subject to the
pressure pulse fluctuation exits the face of the drill bit. That is, as
compared to past
downhole signal emitting apparatus, this arrangement may tend to provide a
signal
comparatively closer to the actual location of the drill bit.
The art discusses efforts to address the downhole signal strength or signal
attenuation
issue either by using acoustic repeaters, or by filtering out, or cancelling
out either acoustic
or EM noise. US Patent 6,781,521 of Gardner appears to be fairly sophisticated
in this
regard. Techniques of the nature of those described by Gardner tend to be
directed toward
the problem of identifying a signal where the signal to noise ratio is very
small, perhaps of
the order of a few thousandths. The signal is encoded, and may tend to be more
difficult to
find because it is unknown. In the present instance, unlike the prior art, the
surface sensors
are not looking for a wave of unknown shape, and the wave they are seeking
does not carry
encoded data. Rather, the shape of the key is known. The listening equipment
at the surface
can use relatively simple mathematical techniques to hunt for that signal,
because (unlike the
prior art) the listening equipment in effect, already knows the wavelength and
shape of the
waveform it is seeking. Taking advantage of the mutual orthogonality of waves
of different
wavelengths, by working on data from one slice of time at a time, and taking
many slices of
the observed data per second (the processing equipment has a clock pulse rate
in the range of
gigahertz, the key has signal cycles, or partial cycles whose effective
equivalent frequency is
of the order of 1 to 20 Hz, perhaps) multiplying the observed data value by
the reference
value at each time slice, and summing the squares over the time period of one
cycle of the
signature, the signal processor can find the best fit, and hence the phase
shift of the key (i.e.,
the signature), and can relax the data (i.e., modify by stretching or
shortening the time
duration of portions of the wave according to calculated correction factors)
until it matches
the key fairly closely. That correction or relaxation may then be applied to
the data observed
at the other listening locations, and the same curve matching algorithm
applied. In an
alternate embodiment, another technique is to take several periods of data,
each having a
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periodic time duration the length of one cycle of the key signal at the
nominal rate of rotation
of the drill bit, and repetitively to overlay the data of successive time
slices that are spaced
apart in time by the period of the cycle, such that the successive key signals
sit, at least
roughly, on top of one another. In that method, the repetitive key signals may
tend to sum
continuously, whereas the noise signals, being random, may tend, on average,
to sum to zero.
As such the key signal may tend to "emerge" from the data, permitting the
locations of
maxima and minima to be detected, and the phase shift to be determined. Much
as before,
from this information, first order correction factors may calculated, and then
back applied to
the raw data, and honed as may be suitable.
The relaxation adjustment factors, or coefficients, may be used to back-
calculate a
time history of actual, as opposed to nominal, rotation of the drill bit. They
may also permit
correlation of the signature signals to significant events, or singularities,
or perturbations in
drill bit operation that may tend to stand out from more random noise. The
presence of
singularities in the raw data observed at the various sensors of the sensing
array may also
serve as a further check on the phase shifted matching of the data observed at
the various
sensors, and of location or other operational parameters. That is, the sound
spectrum, or
history, of the bit in operation is itself an historically unique record, or
fingerprint, of drill bit
activity. The identification of the key signal amongst that historically
unique record, which
on the face may appear to be random, may also permit digital time shifting of
the overall
sound recorded at the various sensors, such that the record of the bit itself
may then be
analysed and information extracted therefrom, whether to reinforce
calculations of location,
or to gain insight into the dynamic operation of the bit, such as acoustic
indications of
damage or wear on the bit, resonances, whether desirable or undesirable, or of
general
dullness indicating a time for replacement, or sounds characteristic of
passing into a different
geological zone or body. That is, once the adjustment coefficients for the
various cycles of
the signature key are known, and the respective phase shift to be applied at
each of the
sensors is known, those same coefficients and phase shifts can be applied to
the entire sound
spectrum of data observed at each of those locations. Since the data observed
is not truly
random, and notable singularities in the data may stand out, it may be that
further
information about the actual progress of the bit in the formation may be
extracted.
The assumption is made that the speed of the acoustic wave through the various
geological strata to the various sensors is approximately the same. That is,
the assumption is
that the type, number, and relative thicknesses of the strata between the
signal source and
each listening sensor are at least roughly similar. While this may not be
precisely accurate, it
may serve as an adequate approximation. Further, to the extent that the
geological formation
may have been surveyed prior to the commencement of drilling, even differences
in the
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geological medium through which the signals are carried may be the subject of
correction
factors applied to the observed signals according to the previously gathered
data. Further
still, even those values can be modified (i.e., updated or made more accurate)
on the basis of
additional information obtained and recorded as the drilling process proceeds.
It may be noted that the same techniques applied to looking for the key may
also be
applied to looking for echoes of the key. The echo information provides a
second check on
the location of the drill bit, and also a check on previous geological data
that may have been
obtained by seismic surveying prior to drilling. That is, the echoes are
indicators of the
proximity of the drill bit to formation boundaries. The echo signals are
identifiable as echoes
because they will be weaker than the primary signals observed.
The presently described apparatus for generating acoustic signals, for
observing those
signals, for processing those signals, and for extracting information of a
practical nature from
those observed signals by the application of both classical and digital (i.e.,
numerical
methods) mathematics may occur in conjunction with the collection and
transmission of data
by means of sensors and coded pulses up the drill string as well. That is,
while position may
be inferred from the data, temperature may still be sensed downhole, and
transmitted back up
the drill string. To the extent that nuclear radiation, resistivity, or other
sensors for
measuring characteristics of the geological formation are desired, one or more
or all of those
may also be used in conjunction with the present apparatus.
It may be noted that by this process, the depth, latitude, and longitude of
the drill bit
may be obtained. The pressure at the drill bit may tend to be that of the
water column (i.e.,
drilling mud column) from the surface to that depth and may be comparatively
easily
determined. The observed data also permits the amount of twist in the drill
string to be
determined, and the actual speed and rotational displacement of the drill bit
to be calculated
as a function of time. That is, the phase shift of the signal, and the
distortion of the signal in
terms of the relaxation required at any observation point, effectively
determined as an "error"
function, is an indication of both the instantaneous speed of the drill bit as
compared to the
relatively steady input rotation at the well head, and of the variation in
torque applied to the
drill bit. The mechanical nature of the drill string may tend to be reasonably
well known,
both in terms of the length of the drill string, the stretch of the drill
string (the weight of the
drill collars, the weight of the string generally, and the longitudinal
tension or hold-back
applied at the well head being known). Further, the flow rate of the drilling
mud, and the
power input of the drilling mud pump are also known. From this known
information, and the
positional fix on the drill head, much of the information that might otherwise
have been
transmitted from the sensors at the drill bit is either no longer required, or
inferable through
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other means. For example, there may no longer be a need to collect or transmit
the
inclination and azimuth data. To the extent that geological boundary data that
might
formerly have been collected by sensors mounted to the lower end of the drill
string may be
collected by surface sensors, the need for those sensors and the collection of
that data may be
reduced or eliminated. This may yield the benefit of reducing the number of
relatively
fragile downhole sensors required, and also of reducing the volume of encoded
signals to be
sent up the drill string. Thus the limit of the low rate of data transmission
up the drill string
may be a less severe problem, because the need to translate such as volume of
data may be
correspondingly reduced.
To summarise, the process or method of locating the subterranean tool, such as
a drill
bit, may include establishing a signal key, i.e., providing an apparatus that
has a known, pre-
determined key or signature signal, the apparatus including a generator that
is operable to
cause that characteristic signal to be emitted repeatedly. The key may include
a non-
harmonic or frequency modulated waveform of, in a sense, unique form. The key
may
include two or more parts, or portions, and those portions may be emitted on a
non-harmonic
basis, such that the resultant wave form has an extended period of emission
before repetition.
The extended period may be obtained by emitting sounds on the basis of sound
emission
schedules for those portions, whose periods of repetition vary as a ratio of
prime numbers.
The method also includes provision of sensors, or an array of sensors in
sufficient numbers,
and establishing, or placing, or distributing, those sensors in an appropriate
manner to permit
location of the drill bit to be calculated. This calculating may be referred
to as triangulation.
(The word "triangulation" may tend to imply three sensors. However,
"triangulation" is used
here in a broader sense, namely that of providing a number of sensors, be it
three, four, five,
or more, such as may be suitable for establishing a fix of position, e.g., by
back calculation
from the observed data). The method includes conveying, or placing, or
locating, the drill bit
in the bore in a subterranean location (which, perforce, may include using the
drill bit to form
the bore), and rotating the bit as it progresses at the cutting face. This
drilling includes the
use of drilling mud. The emission of the key signal may include emitting a
realtively high
power signal (e.g., a signal driven by a power source in excess of about 1/2
h.p. (about 375
W) or 1 h.p., (about 750 W) or more) To that end the emission of the key
signal may include
employing an hydraulic power source to drive the signal generator. That
hydraulic power
source may include the use of drilling mud (which may be predominantly, or in
some cases
entirely, water), under pressure, as the power transmission medium, as
opposed, for example,
to an electrical power transmission system obtaining electrical power from a
surface source
outside the well bore. The method includes monitoring signals at a reference
sensor, such as
an acoustic sensor, at a known location. The method includes listening for (or
monitoring, or
sensing) signals emitted during the operation of the bit at the various
sensors of the array,
CA 02806516 2013-02-19
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including the datum or reference sensor. The reference sensor may be at the
wellhead (or,
more generically, at the pithead, or the head or start of the bore, however it
may be termed).
The method may include analysing the observed sounds at the reference sensor
to locate or
isolate the key signature signal in the observed data. The method may include
comparing the
observed key signal with the known reference datum key signal. The method may
include
the determination and application of correction factors to the data to improve
the effective
quality of the observed signal, or to cause it to match even more closely the
known reference
of the key signal, and recording the factors or coefficients applied to
modify, or refine, the
observed signals. The method may include finding the emitted key signal in the
sound data
observed or sensed at each of the other sensors, and applying the calculated
corrections, or
correction factors or coefficients to the data observed at those sensors, and
from such
application to determine the relative phase shift, or relative time delay
between the arrival of
the signals at the various sensors. The method may include digital
determination of location
on the basis of relative time delay between the sensors (whose positions are
in any case
known). The method may include the correction or adjustment of the observed
data
according to variations in the geological structure, either on the basis of
data obtained during
the current drilling process being observed, or on the basis of previous
observations of
geological properties. The method may include adjusting the orientation of the
drill bit on a
real time basis in response to location (and rate of change of location)
information obtained
by calculation. The method may include listening at the various sensors for
echoes of the
key signal such as may reveal further information concerning the relative
location of the bit
to geological feature such as strata boundaries or other formation features.
The method may
further include the employment of the key signal as a marker, or trace, or
datum, against
which to correlate features of the sound profile emitted by the drill bit as
observed at the
various sensors.
Various embodiments have been described in detail. Since changes in and or
additions to the above-described examples may be made, the invention is not to
be limited to
those details but only by the claims as purposively construed.
