U.S. patent application number 09/204908 was filed with the patent office on 2001-11-15 for measurement-while-drilling assembly using gyroscopic devices and methods of bias removal.
Invention is credited to ESTES, ROBERT ALAN, KAHN, JON B., NOY, KOEN A..
Application Number | 20010041963 09/204908 |
Document ID | / |
Family ID | 22076430 |
Filed Date | 2001-11-15 |
United States Patent
Application |
20010041963 |
Kind Code |
A1 |
ESTES, ROBERT ALAN ; et
al. |
November 15, 2001 |
MEASUREMENT-WHILE-DRILLING ASSEMBLY USING GYROSCOPIC DEVICES AND
METHODS OF BIAS REMOVAL
Abstract
This invention provides a measurement-while-drilling (MWD)
downhole assembly for use in drilling boreholes which utilizes
gyroscopes, magnetometers and accelerometers for determining the
borehole inclination and azimuth during the drilling of the
borehole. The downhole assembly includes at least one gyroscope
that is rotatably mounted in a tool housing to provide signals
relating to the earth's rotation. A device in the tool can rotate
the gyroscope and other sensors on the tool at any desired degree.
A processor in the tool combines measurements from the sensors
taken at a plurality of positions at the same depth to determine
the systematic bias in the sensors before further processing.
Accelerometers in the MWD tool provide gravity measurements from
which the toolface and inclination are determined. The unbiased
gyroscopic measurements are used in conjunction with the tool face
and inclination measurements to determine the azimuth and tool face
with respect to true north. Three axially spaced apart
magnetometers may be used to correct for local magnetic
disturbances. Additionally, when measurements are made with
magnetic, accelerometer and gyroscopic measurements along three
different axes, the unbiased measurements may be combined to
provide an improved determination of the tool orientation.
Inventors: |
ESTES, ROBERT ALAN;
(TOMBALL, TX) ; NOY, KOEN A.; (ALMEREHOUT, NL)
; KAHN, JON B.; (SPRING, TX) |
Correspondence
Address: |
PAUL S MADAN
MADAN, MOSSMAN & SRIRAM, PC
2603 AUGUSTA, SUITE 700
HOUSTON
TX
77057-1130
US
|
Family ID: |
22076430 |
Appl. No.: |
09/204908 |
Filed: |
December 3, 1998 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
60067505 |
Dec 4, 1997 |
|
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Current U.S.
Class: |
702/6 |
Current CPC
Class: |
E21B 47/022 20130101;
G01C 19/38 20130101 |
Class at
Publication: |
702/6 |
International
Class: |
G01V 003/18 |
Claims
What is claimed is:
1. A method of making measurements made by at least one sensor
rotatably mounted in a measurement-while-drilling ("MWD") tool
during the drilling of a borehole, the method comprising: (a)
locating the MWD tool in the borehole at a predetermined depth; (b)
taking a measurement from the at least one sensor at a first
position of the sensor at the predetermined depth; (c) rotating the
at least one sensor a predetermined angle relative to the first
position about a known axis of the sensor to at least a second
position at the predetermined depth and taking a measurement from
the at least one sensor at the at least second position; and (d)
combining the first measurement and the at least second measurement
to determine a bias in the measurements made by the at least one
sensor.
2. The method of claim 1, further comprising correcting at least
one of the first and second measurements utilizing the determined
bias.
3. The method of claim 1 wherein the at least one sensor is
selected from the group consisting of: (i) an accelerometer, (ii) a
magnetometer, and (iii) a two-axis gyroscope.
4. The method of claim 2 further comprising determining a parameter
of interest utilizing the corrected measurement.
5. The method of claim 4, wherein the at least one sensor is a
two-axis gyroscope and the parameter of interest is selected from
the group consisting of (i) an azimuth with respect to the true
north, (ii) toolface orientation with respect to the true north,
iii) amplitude of measurements of the earth's rate vector for a
two-axis gyroscope, (iv) amplitude of measurements of the earth's
rate vector for a three-axis gyroscope, and (v) local apparent
latitude for a three-axis gyroscope.
6. The method of claim 4 wherein the at least one sensor is a
two-axis gyroscope, the method further comprising correcting
measurements of the gyroscope taken at a borehole depth at other
than the predetermined depth to monitor changes in the parameter of
interest.
7. The method of claim 1 wherein the first position corresponds to
a peak output value of the at least one sensor.
8. The method of claim 1 wherein the at least second position
further comprises at least two positions and the combining of the
measurements further comprises fitting a sinusoid to the
measurements.
9. The method of claim 1 wherein the at least one sensor further
comprises three three-axis magnetic sensors spaced axially apart on
the MWD tool, the method further comprising determining a position
and strength of a local magnetic disturbance.
10. The method of claim 1 wherein the at least one sensor further
comprises a magnetometer, a gyroscope, and an accelerometer, the
method further comprising determining a parameter of interest
utilizing the measurements made by the magnetometer, gyroscope and
accelerometer, wherein at least one of said measurements has been
corrected utilizing the determined bias.
11. The method of claim 10, wherein the parameter of interest is
selected from a group consisting of (i) an azimuth with respect to
the true north, (ii) toolface orientation with respect to the true
north, iii) amplitude of measurements of the earth's rate vector
for a two-axis gyroscope, (iv) amplitude of measurements of the
earth's rate vector for a three-axis gyroscope, (v) local apparent
latitude for a three-axis gyroscope, and, (vi) magnetic declination
at the borehole.
12. The method of claim 1 wherein the rotation of the at least one
sensor is accomplished by using a stepping motor.
13. The method of claim 1 wherein the at least one sensor further
comprises three three-axis magnetic sensors spaced axially apart on
the MWD tool, the method further comprising determining a position
where a gradient of the magnetic field is substantially zero.
14. A measurement-while-drilling (MWD) downhole assembly for use in
drilling boreholes, comprising: (a) a housing; (b) at least one
sensor rotatably mounted in the housing, said at least one sensor
providing signals relating to the motion of the tool; (c) a device
in the tool for rotating the at least one sensor about an axis of
the at least one sensor; and (d) a processor in the tool, said
processor combining signals from the at least one sensor taken at
positions corresponding to a plurality of rotational positions at
the same depth in the borehole to determine a bias present in the
measurements made by the at least one sensor during drilling of the
borehole.
15. The MWD assembly of claim 14 wherein the processor corrects at
least one measurement made by the at least one sensor using the
determined bias.
16. The MWD assembly of claim 14 wherein the at least one sensor is
selected from the group consisting of (i) an accelerometer, (ii) a
magnetometer, and (iii) a gyroscope.
17. The MWD assembly of claim 15 wherein the processor further
determines a parameter of interest utilizing the corrected
measurement.
18. The MWD assembly of claim 15, wherein the at least one sensor
is a gyroscope and the parameter of interest is selected from a
group consisting of (i) an azimuth with respect to the true north,
(ii) toolface orientation with respect to the true north, iii)
amplitude of measurements of the earth's rate vector for a two-axis
gyroscope, (iv) amplitude of measurements of the earth's rate
vector for a three-axis gyroscope, and (v) local apparent latitude
for a three-axis gyroscope.
19. The MWD assembly of claim 15 wherein the processor further
corrects measurements of the gyroscope taken at a borehole depth at
other than the predetermined depth to monitor changes in the
parameter of interest.
20. The MWD assembly of claim 15 wherein at least one of the
plurality of rotational positions corresponds to a peak output
value of the at least one sensor.
21. The MWD assembly of claim 14 wherein the at least one sensor
further comprises three magnetic sensors spaced apart axially on
the MWD tool, the processor further combining signals from the
three magnetic sensors to determine a position and strength of a
local magnetic disturbance.
22. The MWD assembly of claim 14 wherein the at least one sensor
further comprises a gyroscope and at least one additional sensor
selected from the group consisting of (i) a magnetometer, and, (ii)
an accelerometer.
23. The MWD assembly of claim 22 the processor further determining
a parameter of interest utilizing a measurement from the gyroscope
corrected for said bias, and a measurement from the at least one
additional sensor.
24. The MWD assembly of claim 23, wherein the parameter of interest
is selected from a group consisting of (i) an azimuth with respect
to the true north, (ii) toolface orientation with respect to the
true north, iii) amplitude of measurements of the earth's rate
vector for a two-axis gyroscope, (iv) amplitude of measurements of
the earth's rate vector for a three-axis gyroscope, and (v) local
apparent latitude for a three-axis gyroscope, and, (vi) magnetic
declination at the borehole
25. The MWD assembly of claim 14 further comprising a stepping
motor for rotating the at least one sensor.
26. The MWD assembly of claim 14 wherein the at least one sensor
comprises a first two-axis gyroscope with its axis of rotation
parallel to an axis of the assembly and a second two-axis gyroscope
with its axis of rotation orthogonal to the axis of rotation of the
first gyroscope.
27. The MWD assembly of claim 26 further comprising a first
stepping motor for rotating the first gyroscope and a second
stepping motor for rotating the second gyroscope.
28. The MWD assembly of claim 26 further comprising a single
stepping motor for simultaneously rotating the first gyroscope and
the second gyroscope.
Description
CROSS REFERENCE TO RELATED APPLICATIONS
[0001] This application claims priority from U.S. Provisional
Patent Application No. 60/067,505 filed on Dec. 4, 1997.
FIELD OF THE INVENTION
[0002] This invention relates generally to bottom hole assemblies
for drilling oilfield wellbores and more particularly to the use of
gyroscopic and other sensors to determine wellbore direction during
the drilling of the wellbores and to the correction of data from
such sensors.
BACKGROUND OF THE INVENTION
[0003] To obtain hydrocarbons such as oil and gas, wellbores (also
referred to as the boreholes) are drilled by rotating a drill bit
attached at the end of a drilling assembly generally referred to as
the "bottom hole assembly" or the "drilling assembly." A large
portion of the current drilling activity involves drilling highly
deviated and substantially horizontal wellbores to increase the
hydrocarbon production and/or to withdraw additional hydrocarbons
from the earth's formations. The wellbore path of such wells is
carefully planned prior to drilling such wellbores utilizing
seismic maps of the earth's subsurface and well data from
previously drilled wellbores in the associated oil fields. Due to
the very high cost of drilling such wellbores and the need to
precisely place such wellbores in the reservoirs, it is essential
to continually determine the position and direction of the drilling
assembly and thus the drill bit during drilling of the wellbores.
Such information is utilized, among other things, to monitor and
adjust the drilling direction of the wellbores.
[0004] In the commonly used drilling assemblies, the directional
package commonly includes a set of accelerometers and a set of
magnetometers, which respectively measure the earth's gravity and
magnetic field. The drilling assembly is held stationary during the
taking of the measurements from the accelerometers and the
magnetometers. The toolface and the inclination angle are
determined from the accelerometer measurements. The azimuth is then
determined from the magnetometer measurements in conjunction with
the tool face and inclination angle.
[0005] The earth's magnetic field varies from day to day, which
causes corresponding changes in the magnetic azimuth. The varying
magnetic azimuth compromises the accuracy of the position
measurements when magnetometers are used. Additionally, it is not
feasible to measure the earth's magnetic field in the presence of
ferrous materials, such as casing and drill pipe. Gyroscopes
measure the rate of the earth's rotation, which does not change
with time nor are the gyroscopes adversely affected by the presence
of ferrous materials. Thus, in the presence of ferrous materials
the gyroscopic measurements can provide more accurate azimuth
measurements than the magnetometer measurements.
[0006] U.S. Pat. No. 5,432,699 discloses a method and apparatus
measuring motion signals of gyroscopes in downhole instruments used
to determine the heading of a borehole. Accelerometer and
magnetometer data along three orthogonal axes of a measurement sub
are used to obtain unit gravitational and magnetic vectors. The
gyroscope measurements are used to correct the magnetic and gravity
measurements made by the magnetometer and the accelerometer
respectively. The calculations performed in the correction process
by this, and other prior art optimization schemes based upon least
squares methods, are valid when the measurements are corrupted by
random additive noise. As would be known to those versed in the
art, in the presence of systematic measurement errors, such
least-squares optimization methods are unreliable.
[0007] Commercially available gyroscopes contain systematic errors
or biases that can severely deteriorate accuracy of a gyroscope's
measurements and thus the azimuth. Gyroscopes have been utilized in
wireline survey applications but have not found commercial
acceptance in the measurement-while-drilling tools such as
bottomhole assemblies.
[0008] In wireline applications, the survey tool is conveyed into
the wellbore after the wellbore has been drilled, in contrast to
the MWD tools wherein the measurements are made during the drilling
of the wellbores. Wireline methods are not practical in determining
the drilling assembly position and direction during the drilling of
the wellbores. In wireline applications, the gyroscopes are used
either in a continuous mode or at discrete survey intervals.
Wireline survey methods often make it unnecessary to employ
techniques to compensate for the present-value of the gyroscope
biases. In wireline applications, the gyroscope can be powered-up
at the surface and allowed to stabilize (thermally and dynamically)
for a relatively long time period. Typically a warm-up period of
ten (10) minutes or more is taken. The power to the gyroscope is
continuously applied from the beginning at the surface, through the
actual wellbore survey and through the final check of the survey
tool at the surface at the end of the survey. Therefore, reference
alignments can be made at the surface prior to commencing the
wellbore survey to adjust or verify the alignment accuracy of the
north-seeking gyroscope. The initial independent reference can then
be used at the end of the wireline survey. Any bias in the
gyroscope in a wireline tool can be measured at the surface by
taking the difference in the alignments at the beginning and the
end of the survey runs. Furthermore, the wireline tool carrying the
gyroscope can easily be rotated at the surface to several different
toolface (roll angle) positions to determine the bias present on
either of the transverse gyroscopes (i.e., along the x and y axis
of the tool) when the tool is at the surface. This bias can be used
to verify the accuracy or to correct the gyroscope
measurements.
[0009] In the MWD environment, the above-noted advantages of the
wireline systems are not present. The MWD surveys are usually taken
during drill pipe connection times during the drilling of the
wellbore, which intervals are relatively short--generally one or
two minutes. Power in the MWD tools is generated downhole and/or
provided by batteries. To conserve the power, it is desirable to
switch off the gyroscopes when not in use because the gyroscopes
consume considerable power. For MWD tools utilizing
turbine-alternator, the power is generated by flow of the drilling
fluid ("mud") which is interrupted at each pipe connection. Even if
the power could be applied continuously, the difference in the bias
measured at the surface prior to the drilling and post drilling is
not considered an accurate measure due to the very long time
between drilling assembly trips, which are typically between 30 and
300 hours.
[0010] Bias stability from turn-on to turn-on is a major error
component for the currently available tactical grade gyroscopes.
Removing the bias by rotating the gyroscopes about a vertical axis
(long axis) has been utilized in non-drilling applications.
Toolface orientation positioning of a bottomhole assembly during
the drilling of the wellbores often is not a control variable that
can be changed as desired. The depth, hole angle, tool deviation,
and borehole condition often limit the ability to acquire sensor
data at various roll angles of the bottomhole assembly in the
wellbore. Thus, it is important to ensure that gyroscopes used for
MWD measurements are bias compensated in real time internally prior
to taking measurements at each interval. This can be achieved by
determining and removing the biases in the gyroscope in the
transverse plane using an internal indexing mechanism in the
process of taking measurements downhole at each drilling interval.
Biases may also be present in the other measurements, i.e., those
made by magnetometers and accelerometers, for the same reasons as
discussed above with reference to gyroscopes. It is desirable to
remove these biases as well in order to obtain accurate survey
information.
[0011] The present invention provides bottomhole assemblies that
utilize gyroscopes, accelerometers and magnetometers for
determining the position and direction of the bottomhole assembly
and wherein the biases in the gyroscope, the magnetometer and the
accelerometer in the transverse plane are determined and removed
downhole during the drilling operations. Once these biases are
removed, methods can be used for correction of the measured data
based upon the fact that there is a redundancy in the observations
made using the three kinds of sensors.
SUMMARY OF THE INVENTION
[0012] This invention provides a measurement-while-drilling (MWD)
downhole assembly for use in drilling boreholes that utilizes
gyroscopes and accelerometers for determining the borehole
inclination and azimuth during the drilling of the borehole. The
downhole assembly includes at least one gyroscope that is rotatably
mounted in a tool housing to provide signals relating to the
earth's rotation. A device in the tool can rotate the gyroscope
within the tool at any desired degree. In one embodiment of the
invention, a processor in the tool combines measurements from the
gyroscope taken at two opposing positions at the same depth to
determine the systematic bias in the gyroscope before further
processing of the signals. In another embodiment of the invention,
the tool includes magnetometers and accelerometers so that biases
in measurements made by these instruments can also be determined.
Additionally, using a plurality of axially spaced apart
magnetometers, the magnetic gradient may also be determined, making
it possible to correct for local magnetic sources. In another
embodiment of the invention, the processor combines measurements
taken from accelerometers in the MWD tool to provide gravity
measurements from which the toolface and inclination are
determined. The unbiased gyroscopic measurements are used in
conjunction with the toolface and inclination measurements to
determine the azimuth and true north toolface.
[0013] This invention also provides a method of eliminating a
systematic bias present in a survey instrument deployed in a
measurement-while-drill- ing tool during the drilling of a
borehole. The method comprises drilling the borehole utilizing the
MWD tool to a depth, followed by rotating the instrument through a
plurality of angles while taking measurements with the instrument
at each position, and estimating the bias from these multiple
measurements
[0014] Examples of the more important features of the invention
have been summarized rather broadly in order that the detailed
description thereof that follows may be better understood, and so
the contributions to the art may be appreciated. There are, of
course, additional features of the invention that will be described
hereinafter and which will form the subject of the claims appended
hereto.
BRIEF DESCRIPTION OF THE DRAWINGS
[0015] For detailed understanding of the present invention,
references should be made to the following detailed description of
the preferred embodiment, taken in conjunction with the
accompanying drawings, in which like elements have been given like
numerals, wherein:
[0016] FIG. 1 shows a schematic diagram of a drilling system that
employs the apparatus of the current invention in a
measurement-while-drilling embodiment;
[0017] FIG. 2A shows a schematic diagram of a portion of the
bottomhole assembly with a set of gyroscopes and a corresponding
set of accelerometers according to a preferred embodiment of the
present invention;
[0018] FIG. 2B shows a schematic diagram showing the use of a
second two-axis gyroscope in the bottomhole assembly shown in FIG.
2A;
[0019] FIGS. 2C and 2D are graphs showing sinusoidal output of a
two-axis gyroscope; and
[0020] FIG. 3 shows a functional block diagram of the major
downhole elements of the system of the present invention.
[0021] FIG. 4 shows an embodiment of the invention using two motors
to drive two gyros, one of which is coupled to the magnetometers
and the accelerometers.
[0022] FIG. 5 shows an embodiment of the invention using a single
motor to drive two gyros, one of which is coupled to the
magnetometers and the accelerometers.
DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS
[0023] FIG. 1 shows a schematic diagram of a drilling system 10
having a bottom hole assembly (BHA) or drilling assembly 90 that
includes gyroscope(s) according to the present invention. The BHA
90 is conveyed in a borehole 26. The drilling system 10 includes a
conventional derrick 11 erected on a floor 12 which supports a
rotary table 14 that is rotated by a prime mover such as an
electric motor (not shown) at a desired rotational speed. The drill
string 20 includes a tubing (drill pipe or coiled-tubing) 22
extending downward from the surface into the borehole 26. A drill
bit 50, attached to the drill string 20 end, disintegrates the
geological formations when it is rotated to drill the borehole 26.
The drill string 20 is coupled to a drawworks 30 via a kelly joint
21, swivel 28 and line 29 through a pulley (not shown). Drawworks
30 is operated to control the weight on bit ("WOB"), which is an
important parameter that affects the rate of penetration ("ROP"). A
tubing injector 14a and a reel (not shown) are used as instead of
the rotary table 14 to inject the BHA into the wellbore when a
coiled-tubing is used as the conveying member 22. The operations of
the drawworks 30 and the tubing injector 14a are known in the art
and are thus not described in detail herein.
[0024] During drilling, a suitable drilling fluid 31 from a mud pit
(source) 32 is circulated under pressure through the drill string
20 by a mud pump 34. The drilling fluid passes from the mud pump 34
into the drill string 20 via a desurger 36 and the fluid line 38.
The drilling fluid 31 discharges at the borehole bottom 51 through
openings in the drill bit 50. The drilling fluid 31 circulates
uphole though the annular space 27 between the drill string 20 and
the borehole 26 and returns to the mud pit 32 via a return line 35
and drill cutting screen 85 that removes the drill cuttings 86 from
the returning drilling fluid 31b. A sensor S.sub.1 in line 38
provides information about the fluid flow rate. A surface torque
sensor S.sub.2 and a sensor S.sub.3 associated with the drill
string 20 respectively provide information about the torque and the
rotational speed of the drill string 20. Tubing injection speed is
determined from the sensor S.sub.5, while the sensor S.sub.6
provides the hook load of the drill string 20.
[0025] In some applications the drill bit 50 is rotated by only
rotating the drill pipe 22. However, in many other applications, a
downhole motor 55 (mud motor) is disposed in the drilling assembly
90 to rotate the drill bit 50 and the drill pipe 22 is rotated
usually to supplement the rotational power, if required, and to
effect changes in the drilling direction. In either case, the ROP
for a given BHA largely depends on the WOB or the thrust force on
the drill bit 50 and its rotational speed.
[0026] The mud motor 55 is coupled to the drill bit 50 via a drive
disposed in a bearing assembly 57. The mud motor 55 rotates the
drill bit 50 when the drilling fluid 31 passes through the mud
motor 55 under pressure. The bearing assembly 57 supports the
radial and axial forces of the drill bit 50, the downthrust of the
mud motor 55 and the reactive upward loading from the applied
weight on bit. A lower stabilizer 58a coupled to the bearing
assembly 57 acts as a centralizer for the lowermost portion of the
drill string 20.
[0027] A surface control unit or processor 40 receives signals from
the downhole sensors and devices via a sensor 43 placed in the
fluid line 38 and signals from sensors S.sub.1-S.sub.6 and other
sensors used in the system 10 and processes such signals according
to programmed instructions provided to the surface control unit 40.
The surface control unit 40 displays desired drilling parameters
and other information on a display/monitor 42 that is utilized by
an operator to control the drilling operations. The surface control
unit 40 contains a computer, memory for storing data, recorder for
recording data and other peripherals. The surface control unit 40
also includes a simulation model and processes data according to
programmed instructions. The control unit 40 is preferably adapted
to activate alarms 44 when certain unsafe or undesirable operating
conditions occur.
[0028] The BHA may also contain formation evaluation sensors or
devices for determining resistivity, density and porosity of the
formations surrounding the BHA. A gamma ray device for measuring
the gamma ray intensity and other nuclear and non-nuclear devices
used as measurement-while-drilling devices are suitably included in
the BHA 90. As an example, FIG. 1 shows a resistivity measuring
device 64. It provides signals from which resistivity of the
formation near or in front of the drill bit 50 is determined. The
resistivity device 64 has transmitting antennae 66a and 66b spaced
from the receiving antennae 68a and 68b. In operation, the
transmitted electromagnetic waves are perturbed as they propagate
through the formation surrounding the resistivity device 64. The
receiving antennae 68a and 68b detect the perturbed waves.
Formation resistivity is derived from the phase and amplitude of
the detected signals. The detected signals are processed by a
downhole computer 70 to determine the resistivity and dielectric
values.
[0029] An inclinometer 74 and a gamma ray device 76 are suitably
placed along the resistivity measuring device 64 for respectively
determining the inclination of the portion of the drill string near
the drill bit 50 and the formation gamma ray intensity. Any
suitable inclinometer and gamma ray device, however, may be
utilized for the purposes of this invention. In addition, position
sensors, such as accelerometers, magnetometers or a gyroscopic
devices may be disposed in the BHA to determine the drill string
azimuth, true coordinates and direction in the wellbore 26. Such
devices are known in the art and are not described in detail
herein.
[0030] In the above-described configuration, the mud motor 55
transfers power to the drill bit 50 via one or more hollow shafts
that run through the resistivity measuring device 64. The hollow
shaft enables the drilling fluid to pass from the mud motor 55 to
the drill bit 50. In an alternate embodiment of the drill string
20, the mud motor 55 may be coupled below resistivity measuring
device 64 or at any other suitable place. The above described
resistivity device, gamma ray device and the inclinometer are
preferably placed in a common housing that may be coupled to the
motor. The devices for measuring formation porosity, permeability
and density (collectively designated by numeral 78) are preferably
placed above the mud motor 55. Such devices are known in the art
and are thus not described in any detail.
[0031] As noted earlier, a large portion of the current drilling
systems, especially for drilling highly deviated and horizontal
wellbores, utilize coiled-tubing for conveying the drilling
assembly downhole. In such application a thruster 71 is deployed in
the drill string 90 to provide the required force on the drill bit.
For the purpose of this invention, the term weight on bit is used
to denote the force on the bit applied to the drill bit during the
drilling operation, whether applied by adjusting the weight of the
drill string or by thrusters. Also, when coiled-tubing is utilized
the tubing is not rotated by a rotary table, instead it is injected
into the wellbore by a suitable injector 14a while the downhole
motor 55 rotates the drill bit 50.
[0032] A number of sensors are also placed in the various
individual devices in the drilling assembly. For example, a variety
of sensors are placed in the mud motor power section, bearing
assembly, drill shaft, tubing and drill bit to determine the
condition of such elements during drilling and to determine the
borehole parameters. The preferred manner of deploying certain
sensors in drill string 90 will now be described. The actual BHA
utilized for a particular application may contain some or all of
the above described sensors. For the purpose of this invention any
such BHA could contain one or more gyroscopes and a set of
accelerometers (collectively represented herein by numeral 88) at a
suitable location in the BHA 90. A preferred configuration of such
sensors is shown in FIG. 2A.
[0033] FIG. 2A is a schematic diagram showing a sensor section 200
containing a gyroscope 202 and a set of three accelerometers 204x,
204y and 204z disposed at a suitable location in the bottomhole
assembly (90 in FIG. 1) according to one preferred embodiment of
the present invention. The gyroscopes 202 may be a single axis
gyroscope or a two-axis gyroscope. In vertical and low inclination
wellbores, an x-axis and a y-axis gyroscope are deemed sufficient
for determining the azimuth and toolface with respect to the true
north. The configuration shown in FIG. 2A utilizes a single
two-axis (x-axis and y-axis) gyroscope that provides outputs
corresponding to the earth's rate of rotation in the two axis
(x-axis and y-axis) perpendicular to the borehole axis or the
bottomhole assembly longitudinal axis, referred to herein as the
z-axis. The sensor 202 thus measures the earth's rotation component
in the x-axis and y-axis. The accelerometers 204x, 204y and 204z
measure the earth's gravity components respectively along the x, y,
and z axes of the bottomhole assembly 90.
[0034] The gyroscope 202 and accelerometers 204x-204z are disposed
in a rotating chassis 210 that rotates about the radial bearings
212a-212b in a fixed or non-rotating housing 214. An indexing drive
motor 216 coupled to the rotating chassis 210 via a shaft 218 can
rotate the chassis 210 in the bottomhole assembly 90 about the
z-axis, thus rotating the gyroscopes 202 from one mechanical
position to another position by any desired rotational angle. A
stepper motor is preferred as the indexing drive motor 216 because
stepper motors are precision devices and provide positive feedback
about the amount of rotation. Any other mechanism, whether
electrically-operated, hydraulically-operated or by any other
desired manner, may be utilized to rotate the gyroscopes within the
bottomhole assembly 90. The gyroscope 202 may be rotated from an
initial arbitrary position to a mechanical stop (not shown) in the
tool or between two mechanical stops or from an initial peak
measurement to a second position as described later. The rotational
angle corresponding to a particular axis is selectable.
[0035] Although FIG. 2A shows a single two axis gyroscope, a
separate gyroscope may be utilized for each axis. A wiring harness
226 provides power to the gyroscope 202 and accelerometers 204x,
204y, 204z. The wiring harness 226 transmits signals from the
gyroscope and accelerometers to the processor in the bottomhole
assembly 90. Similarly, a suitable wiring harness 220 provides
power and signal linkage to the stepper motor 216 and additional
downhole equipment. A spring loaded torque limiter 240 may be used
to prevent inertial loading caused by drillstring rotation from
damaging the gearbox of the stepper motor 216.
[0036] In addition a second two-axis (x-axis and z-axis) gyroscope
230 may be rotatably mounted in the bottomhole assembly 90 in a
rotating chassis or in any other manner to measure the rate of
rotation in the z-axis and the x-axis, as shown in FIG. 2B. The
sensor 230 could be rotated about the y-axis using a bevel gear 242
and a shaft linkage 244 to the rotating chassis 210, thus
eliminating the need for an additional motor. The wiring harness
244 for the y-axis gyro 230 must be spooled around the gyro to
accommodate the space available in a small diameter housing.
[0037] As noted above, an MWD gyroscope requires optimization
and/or compensation for several parameters in order to provide the
required performance from typical gyroscopic sensors currently
available.
[0038] One of the error parameters that in some cases is too large
for adequate accuracy performance in a typical adaptation of an MWD
Gyroscope is the bias on the gyroscope's output. Some gyroscopes
have small error values for the "bias random walk" term, and
relatively stable bias values after an initial warm-up period, but
have a large instability in the bias seen from turn-on to turn-on.
The bias and bias random walk largely determine the accuracy of a
gyroscope sensor used in the gyrocompass (North-Seeking) mode of
operation. An apparatus and a method to correct for the bias error
seen after power is applied during drilling is desirable.
[0039] One embodiment of the invention accomplishes compensation
for the systematic bias error in a gyroscope in an MWD tool by
indexing the gyroscope to two positions 180 degrees apart and by
using data from these positions to determine the bias. Adding the
two measurements results in a cancellation of the positive-going
and negative-going signals and a doubling of the bias error. If all
other parameters are compensated by a calibration process done
prior to the operation of the bottomhole assembly the remaining
error in the gyroscope (the bias) is removed after calculation as
follows:
Bias ={fraction (1/2)}(("zero" reading)+("180" reading)) (1)
[0040] Mechanical stops can be used to rotate the gyroscope to an
arbitrary "zero" position, and then to the "180" position. For a
single axis gyroscope, this technique can determine the bias, which
is then used to compensate subsequent measurements from the
gyroscope, in addition to the previously determined calibration
parameters. For a 2-axis gyroscope, the technique of indexing from
the "zero" position to the "180" position can provide a measurement
of the bias for each of the two (X and Y) transverse axis
gyroscopes. Alternatively, a stepper motor or a drive motor with an
angular resolver could be used to index 180 degrees from an
arbitrary initial position on the rotating axis.
[0041] This technique is illustrated in the graph shown in FIG. 2C
by the small square symbols designated "Initial Measurement Point".
This position is shown at 62 degrees on the horizontal axis of the
chart, corresponding to a relative roll angle (or toolface angle)
of 62 degrees. A second measurement could then be obtained at
62+180, or 242 degrees, and the bias computed for Gyroscope X or
Gyroscope Y or both from the measurements at these two
positions.
[0042] But this technique of taking the first measurement at an
arbitrary roll angle position on the graph could result in a
gyroscope output occurring near null (zero on the vertical axis.)
In such a case, the output of the gyroscope has a steep slope, and
is very sensitive to variations in the position along the
horizontal axis. To get good results, the indexing from the "zero"
point to the "180" point should be done with great precision, and a
tight tolerance on the 180 degree movement must be maintained. This
tight tolerance on a mechanical indexing apparatus can be difficult
to achieve in an MWD device, because of the harsh environment, and
the need to provide vibration and shock dampening mounting of the
sensitive parts. Elastic mounts are often required, with adequate
room for deflection under dynamic loads, and mechanical stops may
be damaged by continuous impacts.
[0043] Still referring to FIG. 2C, the present invention provides a
method of establishing the initial "zero" reference position to
minimize the bias measurement errors, while allowing for a less
precise mechanical indexing apparatus. Referring to FIG. 2C, it is
clear that the output of the gyroscope is less sensitive to angular
positioning errors near the peak positive (250) and negative (252)
portions of the sinusoidal wave 255. The round points 254a and 254b
plotted near the null value of the sine wave at 85 and 90 degrees
have significantly more vertical displacement that the triangular
points 250a and 250b plotted near the peak of the sine wave 255. It
is desirable to measure the "zero" position value for the gyroscope
near the positive and negative peaks, and then the "180" degree
position near the other peak, in order to minimize the resulting
bias measurement error. This can be accomplished by monitoring the
output of the gyroscope while rotating. Finding the peak may be
done by looking for the position where the slope of the output goes
from rising to failing (or vice versa) with increasing angular
position. The initial "zero" position measurements can be made at
this position and saved for subsequent computation. The drive motor
apparatus can then be commanded to advance 180 degrees, and the
second "180" position measurements can be made. Alternatively, the
"peak finding" technique can be used for the "180" position.
[0044] For a two axis gyroscope, the peak finding technique is used
to establish the "zero" position for the X gyroscope, and then 3
more positions are used, 90 degrees apart, to make the measurements
to compute the bias on both X and Y axes. In the graph above, the
triangular points plotted near the peaks of the sinusoidal outputs
at 90, 180, 270, and 360 degrees are used to compute the biases on
X and Y.
Bias X=+E,fra 1/2(X@90+X@270)
Bias Y={fraction (1/2)}(Y@180+Y@360) (2)
[0045] Having determined the bias in the two axes by this downhole
calibration technique, the outputs of the X and Y axes can then be
corrected for this bias at any position on the angular (horizontal)
scale. Angular parameters of interest for the downhole MWD assembly
(Azimuth and Toolface) can then be computed using values at all 4
or at any of the previously recorded or subsequent indexed
positions. The average of the parameters computed at the four
indexing positions is typically used.
[0046] In summary, the triangular points plotted near the peaks of
the sinusoids are used to compute the biases, and then after
compensation, these measurements along with the measurements made
at the round points plotted near the null values of the sinusoids
are used to compute the angular parameters of interest.
[0047] Referring back to FIG. 2A, in operation, to determine the
toolface, inclination angle and the azimuth of the bottomhole
assembly 90, the drilling is interrupted or stopped. The gyroscope
is powered and the earth rate measurements from the gyroscope 202
and gravity measurements from each of the accelerometers 204x-204z
are taken. As noted-above the gyroscope rate measurements contain
systematic biases or errors. To eliminate these systematic errors,
a second set of rate measurements are made after rotating the
gyroscopes 202 180 degrees at the same wellbore depth and
bottomhole assembly position and without switching off the power to
the gyroscope 202.
[0048] The measurements relating to each axis from the gyroscope
made at each position are then differenced to determine the
respective biases. The bias corresponding to each axis is
preferably stored in a suitable memory in the processor for later
use. The biases are used to correct the gyroscopic measurements
prior to determining the azimuth or toolface with respect to the
true north in the manners described above. These methods largely
remove the systematic independent toolface errors. The remaining
errors are removed by utilizing predetermined models derived from
laboratory measurements made at the surface.
[0049] FIG. 2D illustrates another method of correcting for the
gyro output. The tool is rotated successively through angles 261a,
261b, . . . and at each rotational angle, the gyro output of the X
and Y axis gyros is taken. Denoting by Ux.sub.i the measurement of
the X gyro at an angle .theta..sub.i, the measurements in the
presence of random measurement errors .epsilon..sub.i, a bias
b.sub.x may be represented as
Ux.sub.i=A sin (.theta..sub.i+.phi.)+b.sub.x+.epsilon..sub.i
(3)
[0050] where .phi. is a phase angle and A is the amplitude of the
sinusoid. This equation has three parameters to be estimated,
namely A, .phi., and b.sub.x. If measurements are made at three
tool rotational angles, these parameters are uniquely determined.
If additional measurements are made, then the equations are
overdetermined and a solution may be obtained in a least squares
sense using methods known in the art. The same procedure may also
be used for the measurements made by the Y axis gyro. When both the
X and Y axis gyro measurements are used, then there is an
additional requirement that the phase term for the x and y
directions differ by 90.degree.. This too can be made part of the
least squares minimization procedure.
[0051] The above-described bias removal methods in realtime
downhole during the drilling of the wellbores, referred hereto as
the "mechanical-indexing methods," for gyroscopes allow great
flexibility of use, minimizing the survey time and power
consumption. It allows the determination of the systematic bias
errors that typically exist in commercially available gyroscopes,
rather than relying on the stability of the bias for such
gyroscopes. This further allows the use of gyroscopes that are
otherwise unsuitable for use in gyrocompass mode in the MWD
environment due to their poor stability or large turn-on to turn-on
bias instability. The other term affecting the accuracy of
gyroscopic measurement, namely the random walk, is minimized (a) by
selecting gyroscopes with relatively low value of random walk by
performing tests at the surface prior to their use in the
bottomhole assembly and (b) averaging the measurements of the
gyroscopes for sufficiently long time periods to remove the
statistical variations of such errors.
[0052] FIG. 3 shows a functional block diagram of the major
elements of the bottom hole assembly 90 and further illustrates
with arrows the paths of cooperation between such elements. It
should be understood that FIG. 3 illustrates only one arrangement
of the elements and one system for cooperation between such
elements. Other equally effective arrangements may be utilized to
practice the invention. A predetermined number of discrete data
point outputs from the sensors 352 (S.sub.1-S.sub.j) are stored
within a buffer which, in FIG. 3, is included as a partitioned
portion of the memory capacity of a computer 350. The computer 350
preferably comprises commercially available solid state devices
which are applicable to the borehole environment. Alternatively,
the buffer storage means can comprise a separate memory element
(not shown). The interactive models are stored within memory 348.
In addition, other reference data such calibration compensation
models and predetermined drilling path also are stored in the
memory 348. A two way communication link exists between the memory
348 and the computer 350. The responses from sensors 352 are
transmitted to the computer 350 and or the surface computer 40
wherein they are transformed into parameters of interest using
methods which will be detailed in a subsequent section hereof.
[0053] The computer 350 also is operatively coupled to certain
downhole controllable devices d1-dm, such as a thruster, adjustable
stabilizers and kick-off subassembly for geosteering and to a flow
control device for controlling the fluid flow through the drill
motor for controlling the drill bit rotational speed.
[0054] The power sources 344 supply power to the telemetry element
342, the computer 350, the memory modules 346 and 348 and
associated control circuits (not shown), and the sensors 352 and
associated control circuits (not shown). Information from the
surface is transmitted over the downlink telemetry path illustrated
by the broken line 329 to the downhole receiving element of
downhole telemetry unit 342, and then transmitted to the storage
device 348. Data from the downhole components is transmitted uphole
via link 327. In the present invention, the parameters of interest
such as toolface, inclination and azimuth are preferably computed
downhole and only the answers are transmitted to the surface.
[0055] FIG. 4 shows a sensor section 400 containing gyroscopes 404,
412, a set of three accelerometers 414x, 414y and 414z disposed at
a suitable location in the bottomhole assembly 90 according to
another embodiment of the present invention. The gyroscopes 404,
412 are preferably two-axis gyroscopes. The sensor section also
contains three three-axis magnetometers 426a, 426b, and 426c. The
instruments are enclosed in a housing 430 with a downhole coupler
432 and an uphole coupler 402. A stepper motor 408b drives the
sensors 404, 412, 414x, 414y, 414z, 426a, 426b, and 426c downhole
of the stepper motor 408b by a flex coupling 410 so that the
sensors can be stepped through a series of azimuthal positions with
respect to the tool axis. The magnetic sensors 426a, 426b, and 426c
and the magnetometer board 420 are supported on a chassis 420 by
nonmagnetic bearings 424. With this arrangement, as the gyroscope
412 is stepped through a number of angles to determined its bias,
the magnetometers and the accelerometers are being stepped in
unison with the gyroscope. Using methods described above with
reference to the gyroscope, the bias in the accelerometers 414x and
414y and the magnetometers 426a, 426b, and 426c can be determined
and subsequent survey measurements can be compensated for this
bias.
[0056] In the absence of local magnetic perturbations, such as
those caused by steel objects in the sensor assembly or in the
proximity of the sensor assembly, there should be no z-gradient of
the magnetic field, i.e., the long axis components of magnetic
sensors 426a, 426b, and 426c should all have the same value. If the
actual measurements do not satisfy this condition, then it is
indicative of a local magnetic disturbance. The magnetic field
disturbance caused by a magnetic object in the borehole or in the
vicinity of the borehole follows the well known inverse square law,
and by using known modeling techniques, the location and the
strength of the disturbance can be ascertained from a plurality of
magnetic measurements. This makes it possible to correct the
magnetometer measurements for the disturbance and also determine an
axial distance along the borehole where the z-gradient is
substantially zero and the magnetic field substantially
undisturbed.
[0057] Still referring to FIG. 4, the sensor assembly also includes
a second gyroscope 404 driven by a second stepper motor 408a
through a bevel gear 406. Using the methodology described above,
the bias of this gyro can also be determined during logging
operations, the difference being that in this case, it is the y-
and z-components of the bias that are determined by rotating the
gyro 412 through a number of different angles and making
measurements at each angle.
[0058] Once the observations have been corrected for bias, the
three sets of measurements based upon the three types of sensors
can be used to obtain an improved estimate of the tool orientation.
As discussed in U.S. Pat. No. 5,432,699, the angular velocity
.OMEGA..sup.g as measured by the gyroscopes is the sum of the
angular velocity vector .OMEGA..sup.e of the earth and the angular
velocity .OMEGA..sup.p of the tool relative to the earth
.OMEGA..sup.g=.OMEGA..sup.e+.OMEGA..sup.p (4).
[0059] The magnetometer and accelerometer measurements each give
independent measurements of the motion of the tool relative to the
earth. The equations denoted by (4) are overdetermined and may be
solved to obtain an improved estimate of the actual orientation of
the tool with respect to the earth using prior art methods. Since
the magnetometer gives an orientation with respect to the earth's
magnetic field, the method readily gives a measurement of the
magnetic declination (angle between geographic and magnetic
north).
[0060] FIG. 5 shows another embodiment of the invention using two
gyroscopes. The sensor section 500 contains gyroscopes 504, 512,
and a set of three accelerometers 514x, 514y and 514z disposed at a
suitable location in the bottomhole assembly 90. The gyroscopes
504, 512 are preferably two-axis gyroscopes. The sensor section
also contains three three-axis magnetometers 526a, 526b, and 526c.
The instruments are enclosed in a housing 530 with a downhole
coupler 532 and an uphole coupler 502. A stepper motor 508 drives
the transverse gyroscope 504 through a bevel gear 506a, the motion
of the stepper motor being further transmitted through bevel gear
506b to a shaft 518. Sensors 512, 514x, 514y, 514z, 526a, 526b, and
526c are driven in synchronization with the gyroscopic sensor 504.
The magnetic sensors 526a, 526b, and 526c and the magnetometer
board 520 are supported on a chassis 522 by non-magnetic bearings
524. Using methods described above with reference to the gyroscope,
the bias in the gyroscopes 504, 512, the accelerometers 514x, 514y
and 514z and the magnetometers 526a, 526b, and 526c can be
determined and subsequent survey measurements can be compensated
for this bias. The bias corrected measurements are then used to
obtain an improved estimate of the tool position and orientation
using the method discussed above with reference to FIG. 4.
[0061] While the foregoing disclosure is directed to the preferred
embodiments of the invention, various modifications will be
apparent to those skilled in the art. It is intended that all
variations within the scope and spirit of the appended claims be
embraced by the foregoing disclosure.
* * * * *