U.S. patent application number 10/065080 was filed with the patent office on 2004-03-18 for downhole closed loop control of drilling trajectory.
Invention is credited to Downton, Geoff, Pirovolou, Dimitrios K..
Application Number | 20040050590 10/065080 |
Document ID | / |
Family ID | 28673463 |
Filed Date | 2004-03-18 |
United States Patent
Application |
20040050590 |
Kind Code |
A1 |
Pirovolou, Dimitrios K. ; et
al. |
March 18, 2004 |
Downhole closed loop control of drilling trajectory
Abstract
A method for drilling a borehole, comprising transmitting a
directional signal to a downhole processor, and maintaining the
desired drill bit azimuthal direction by using the downhole
processor to evaluate an actual drill bit azimuthal direction
relative to the desired drill bit azimuthal direction, and using
the downhole processor to adjust the actual drill bit azimuthal
direction by controlling the directional drilling device.
Inventors: |
Pirovolou, Dimitrios K.;
(Houston, TX) ; Downton, Geoff; (Minchinhampton,
GB) |
Correspondence
Address: |
TIM CURINGTON
SCHLUMBERGER, BRUNEL WAY
STROUDWATER PARK
STONEHOUSE, GLOUCESTERSHIRE
ENG
GL103SX
GB
|
Family ID: |
28673463 |
Appl. No.: |
10/065080 |
Filed: |
September 16, 2002 |
Current U.S.
Class: |
175/61 ;
175/45 |
Current CPC
Class: |
E21B 7/04 20130101 |
Class at
Publication: |
175/061 ;
175/045 |
International
Class: |
E21B 007/04 |
Claims
What is claimed is:
1. A method for drilling a borehole, comprising: transmitting a
directional signal to a downhole processor; and maintaining the
desired drill bit azimuthal direction by using the downhole
processor to evaluate an actual drill bit azimuthal direction
relative to the desired drill bit azimuthal direction, and using
the downhole processor to adjust the actual drill bit azimuthal
direction by controlling a directional drilling device.
2. The method of claim 1, further comprising maintaining the
desired drill bit inclination by using the downhole processor to
evaluate an actual drill bit inclination relative to the desired
drill bit inclination, and using the downhole processor to adjust
the actual drill bit inclination by controlling the directional
drilling device.
3. The method of claim 2, wherein the directional signal comprises
a desired drill bit inclination and a desired drill bit azimuthal
direction.
4. The method of claim 2, wherein the directional signal is
transmitted to the downhole processor before the downhole processor
is placed in the borehole.
5. A method for drilling a borehole, comprising: transmitting a
directional signal to a downhole processor; and maintaining the
desired drill bit azimuthal rate of curvature per unit time by
using the downhole processor to evaluate an actual drill bit
azimuthal rate of curvature per unit time relative to the desired
azimuthal rate of curvature per unit time and using the downhole
processor to adjust the actual drill bit azimuthal rate of
curvature per unit time by controlling a directional drilling
device.
6. The method of claim 5, further comprising maintaining the
desired drill bit inclination rate of curvature per unit time by
using the downhole processor to evaluate an actual drill bit
inclination rate of curvature per unit time relative to the desired
inclination rate of curvature per unit time and using the downhole
processor to adjust the actual drill bit inclination rate of
curvature per unit time by controlling the directional drilling
device.
7. The method of claim 6, wherein the directional signal comprises
a desired drill bit inclination rate of curvature per unit time and
a desired drill bit azimuthal rate of curvature per unit time.
8. The method of claim 6, wherein the directional signal is
transmitted to the downhole processor before the downhole processor
is placed in a borehole.
9. A bottom hole assembly, comprising: a drill bit; a directional
drilling device operatively coupled to the drill bit; a first
orientation sensor set disposed proximate to the drill bit; and a
second orientation sensor set disposed at a known axial distance
from the first orientation sensor set.
10. The bottom hole assembly of claim 11, further comprising a
processor operatively coupled to the directional drilling device,
the first orientation sensor set, and the second orientation sensor
set, and adapted to control the directional drilling device.
11. The bottom hole assembly of claim 12, wherein the processor is
operatively coupled to at least one of the first orientation sensor
set and the second orientation sensor set by a short-hop telemetry
device.
12. The bottom hole assembly of claim 11, wherein the directional
drilling device comprises a bent housing and a mud motor.
13. The bottom hole assembly of claim 11, wherein the directional
drilling device comprises a rotary steerable system.
14. A method for drilling a curved well path, comprising:
transmitting a directional signal to a downhole processor
operatively coupled to a bottom hole assembly, the bottom hole
assembly comprising a plurality of sensors spaced by a known axial
distance and a directional drilling device; and maintaining an at
least one of an inclination rate of curvature per unit distance and
an azimuthal rate of curvature per unit distance by using the
downhole processor to control the at least one of the inclination
rate of curvature per unit distance and an azimuthal rate of
curvature per unit distance.
15. The method of claim 14, wherein the directional signal
comprises a desired drill bit inclination rate of curvature per
unit distance and a desired drill bit azimuthal rate of curvature
per unit distance.
16. The method of claim 14, wherein the directional signal is
transmitted to the downhole processor before the processor is
placed in a borehole.
17. The method of claim 14, wherein the directional drilling device
comprises a bent housing and a mud motor.
18. The method of claim 14, wherein the directional drilling device
comprises a rotary steerable system.
19. The method of claim 14, wherein maintaining at least one of the
inclination rate of curvature per unit distance and the azimuthal
curvature per unit distance comprises using the downhole processor
to evaluate an actual drill bit inclination rate of curvature per
unit distance relative to the desired inclination rate of curvature
per unit distance and using the downhole processor to adjust the
actual drill bit inclination rate of curvature per unit distance by
controlling the directional drilling device.
20. The method of claim 14, wherein maintaining at least one of the
inclination rate of curvature per unit distance and the azimuthal
curvature per unit distance comprises using the downhole processor
to evaluate an actual drill bit azimuthal rate of curvature per
unit distance relative to the desired azimuthal rate of curvature
per unit distance and using the downhole processor to adjust the
actual drill bit azimuthal rate of curvature per unit distance by
controlling the directional drilling device.
21. A method for drilling a borehole, comprising: loading
trajectory data for each of a plurality of drilling segments into a
downhole processor; maintaining a desired drill bit inclination by
using the downhole processor to evaluate an actual drill bit
inclination relative to the trajectory data for each of the
plurality of drilling segments and by using the downhole processor
to control a directional drilling device; and maintaining a desired
drill bit azimuthal direction by using the downhole processor to
evaluate an actual drill bit azimuthal direction relative to the
trajectory data for each of the plurality of drilling segments and
using the downhole processor to control the directional drilling
device.
Description
BACKGROUND OF INVENTION
[0001] In underground drilling, a drill bit is used to drill a
borehole into underground earth formations. Typically, the drill
bit is attached to sections of pipe that stretch back to the
surface. The attached sections of pipe are called the "drill
string." The section of the drill string that is located near the
bottom of the bore hole is called the "bottom hole assembly"
("BHA"). The BHA typically includes the drill bit, sensors,
batteries, telemetry devices, and various other equipment located
near the drill bit. A drilling fluid, called "mud," is pumped from
the surface to the drill bit through the pipe that forms the drill
string. The primary functions of the mud are to cool the drill bit
and carry drill cuttings away from the bottom of the borehole and
up through the annulus between the drill pipe and the borehole.
[0002] Because of the high cost of setting up drilling rigs and
equipment, it is desirable to be able to explore formations other
than those located directly below the drilling rig, without having
to move the rig or set up another rig. In off-shore drilling
applications, the expense of drilling platforms makes directional
drilling even more desirable. "Directional drilling" refers to the
intentional deviation of a wellbore from a vertical path. A driller
can drill to an underground target by pointing the drill bit in a
desired drilling direction.
[0003] Directional drilling can be accomplished with several types
of equipment. One type is a bent housing and a steerable mud motor.
A "bent housing" is a coupling in the drill string that has a
natural bend in it, so that the end of the drill string bends away
from the axis of the rest of the drill string. The bent housing
typically is located just above the drill bit in the BHA. A "mud
motor" is a positive displacement motor disposed in the BHA that
uses the hydraulic power of the drilling mud to rotate the drill
bit.
[0004] The combination of a bent housing and a mud motor can be
used to steer the drill bit. The bent housing is positioned so that
it points in the desired drilling direction, and the mud motor
drives the drill bit. The drill string does not rotate during
drilling. So long as the drill string remains stationary, the bent
housing will cause the drill bit to drill in the direction of the
bend in the bent housing. Straight drilling can be accomplished by
rotating the entire drill string, including the BHA. The bent
housing will rotate along with the drill string, and the drill bit
will drill a straight, but oversized, borehole. An example of a
bent housing drilling device is disclosed in U.S. Pat. No.
6,047,784 issued to Dorel, which is assigned to the assignee of the
present invention.
[0005] Another directional drilling device is a rotary steerable
system ("RSS"). An RSS is a tool designed to steer the drill bit
while the entire drill string is rotated. There are several types
of RSS devices that use various methods to steer the drill bit. One
type of RSS device uses pads to push the drill string in the
desired direction. Another type of RSS device has a section that
rotates in an opposite direction from the drill string so that the
section is stationary relative to the borehole. The stationary
section can cause the drill string to bend in the desired
direction. Because it continuously rotates, an RSS device drills a
smoother, less tortuous borehole than a mud motor/bent housing
arrangement. An example of an RSS is disclosed in U.S. Pat. No.
6,092,610 issued to Kosmala et al., which is assigned to the
assignee of the present invention.
[0006] A directional driller needs information about the
orientation and position of the drill bit to make decisions and
corrections during the drilling process. This information includes
the depth of the dill bit, and its inclination and azimuthal
direction. "Inclination" refers to the drill bit's angle of offset,
or deviation, from the vertical, irrespective of the bit's compass
direction. At zero degrees, the drill bit points straight down, and
at 90.degree. the drill bit is horizontal. The "azimuthal
direction" is the rotational angle around the axis of the
borehole/BHA with reference to a particular direction, such as the
magnetic pole of the Earth or any direction relative to the Earth's
coordinate.
[0007] The inclination may be measured with accelerometers disposed
in the BHA. Accelerometers measure the direction of the Earth's
gravity and determine the drill bit's deviation from that
direction. Accelerometers typically are disposed in a
measurement-while-drilling ("MWD") or logging-while-drilling
("LWD") collar that forms part of the BHA. An MWD or LWD collar
typically includes other sensors for formation evaluation and drill
bit health evaluation.
[0008] The azimuthal direction of the drill bit can be measured
with magnetometers or gyroscopes. Magnetometers measure the
direction of the Earth's magnetic field relative to the drill bit.
The accuracy of a magnetometer, however, is affected by the
presence of ferrous materials near the drill bit. Gyroscopes are
rotating devices that measure the direction of the Earth's rotation
about its axis. The azimuthal direction of the drill bit can then
be determined from the gyroscopic measurement. Magnetometers and
gyroscopes may also be disposed in an MWD or LWD collar.
[0009] Other information that a directional driller uses when
orienting a drill bit includes the drill bit depth. Knowing the
drill bit depth enables the driller to know when the well plan
requires a change of direction. This information is not measured by
sensors in the BHA, but is determined at the surface based on the
length of the drill string that has been inserted into the well
head.
[0010] The orientation and position information measured by the
downhole sensors is transmitted, via any method known in the art,
to a directional driller at the surface. A directional driller uses
information about the inclination, azimuthal direction, and depth
of a drill bit to guide a drill bit to the desired target. The
sensors provide information so that the driller knows whether the
drill bit is following the planned well path or not. In those cases
where the drill bit is not following the planned path, the driller
can make corrections to get the drill bit back on course.
[0011] These directional drilling methods rely on communications
between the driller on the surface and the BHA downhole. In a
typical drill string, the bandwidth for communication is limited.
Surface-to-BHA communications are further complicated by the
distance between the surface and the BHA, which can exceed several
miles. Therefore, it is desirable to have methods for directional
drilling that are less dependent on such communications.
SUMMARY OF INVENTION
[0012] One aspect of the invention relates to methods for drilling
a borehole comprising transmitting a directional signal to a
downhole processor and maintaining a desired drill bit azimuthal
direction by using the downhole processor to evaluate an actual
drill bit azimuthal direction relative to the desired drill bit
azimuthal direction, and using the downhole processor to adjust the
actual drill bit azimuthal direction by controlling the directional
drilling device. In some embodiments, the downhole processor may be
used to maintain a drill bit inclination.
[0013] Another aspect of the invention relates to methods for
drilling a borehole comprising transmitting a directional signal to
a downhole processor, and maintaining a desired drill bit azimuthal
rate of curvature per unit time by using the downhole processor to
evaluate an actual drill bit azimuthal rate of curvature per unit
time relative to the desired azimuthal rate of curvature per unit
time and using the downhole processor to adjust the drill bit
azimuthal rate of curvature per unit time by controlling the
directional drilling device. In some embodiments, the method
includes maintaining an inclination rate of curvature per unit time
by using the downhole processor to control a directional drilling
device.
[0014] Another aspect of the invention relates to methods for
drilling a borehole comprising transmitting a directional signal to
a downhole processor, and maintaining a desired drill bit azimuthal
rate of curvature per unit distance by using the downhole processor
to evaluate an actual drill bit azimuthal rate of curvature per
unit distance relative to the desired azimuthal rate of curvature
per unit distance and using the downhole processor to adjust the
drill bit azimuthal rate of curvature per unit distance by
controlling the directional drilling device. In some embodiments,
the method includes maintaining an inclination rate of curvature
per unit distance by using the downhole processor to control a
directional drilling device.
[0015] Yet another aspect of the invention relates to a bottom hole
assembly comprising a drill bit, a directional drilling device
operatively coupled to the drill bit, a first orientation sensor
set disposed proximate to the drill bit, and a second sensor set
disposed at a known axial distance from the first orientation
sensor set.
[0016] In another aspect, the invention relates to methods for
drilling a borehole, comprising transmitting a directional signal
to a downhole processor operatively coupled to a bottom hole
assembly, the bottom hole assembly comprising a plurality of
sensors spaced by a known axial distance and a directional drilling
device, maintaining an at least one of an inclination rate of
curvature per unit distance and an azimuthal rate of curvature per
unit distance by using the downhole processor to control the at
least one of the inclination rate of curvature per unit distance
and an azimuthal rate of curvature per unit distance.
[0017] Still another aspect of the invention relates to methods for
drilling a borehole comprising loading trajectory data for each of
a plurality of drilling segments into a downhole processor,
maintaining a desired drill bit inclination by using the downhole
processor to evaluate an actual drill bit inclination relative to
the trajectory for each of the plurality of drilling segments and
by using the downhole processor to control a directional drilling
device, and maintaining a desired azimuthal direction by using the
downhole processor to evaluate an actual drill bit azimuthal
direction relative to the trajectory data for each of the plurality
of drilling segments and using the downhole processor to control
the directional drilling device.
[0018] Other aspects and advantages of the invention will be
apparent from the following description and the appended
claims.
BRIEF DESCRIPTION OF DRAWINGS
[0019] FIG. 1 shows an drilling rig and a borehole through an Earth
formation.
[0020] FIG. 2A shows a prior art drilling trajectory control
loop.
[0021] FIG. 2B shows a downhole closed loop trajectory control
according to an embodiment of the invention.
[0022] FIG. 3 shows a method for drilling a borehole according to
one aspect of the invention.
[0023] FIG. 4 shows a method for drilling a borehole according to
another aspect of the invention.
[0024] FIG. 5 shows a perspective view of a bottom hole assembly
according to one embodiment of the invention.
[0025] FIG. 6 shows a method for drilling a borehole according to
another aspect of the invention.
[0026] FIG. 7 shows a method for drilling a borehole according to
another aspect of the invention.
DETAILED DESCRIPTION
[0027] The present invention relates to downhole closed loop
systems and methods that control the trajectory of drill bits. In
certain embodiments, the invention relates to a method for drilling
a borehole by transmitting a signal to a downhole processor that
controls the drill bit trajectory. In certain other embodiments,
the invention relates to a BHA that includes two sensor sets and
enables the determination of the rate of curvature per unit
distance.
[0028] FIG. 1 shows a rig and drill string assembly. A rig 101 is
located at the surface and a drill string 102 is suspended from the
rig 101. A drill bit 105 disposed on a BHA 104 drills a borehole
103 through an Earth formation 106. Using directional drilling, the
borehole 103 can be made to deviate from the vertical
direction.
[0029] FIG. 2A shows a block diagram of a prior art drilling
control process. A directional driller 201 at the surface controls
the drilling process. The driller 201 selects a "well plan," which
represents the desired path that the drill bit will bore through
the Earth to the planned target. The driller 201 controls the drill
bit 204 so that the drill bit 204 will drill along the well
plan.
[0030] In order to steer the drill bit 204 along the well plan, the
driller 201 needs information about the drill bit's position and
orientation. The driller 201 can estimate the depth of the drill
bit 204 based on the length of drillpipe or coiled tubing that has
been sent downhole. Information about the orientation, that is, the
inclination and the azimuthal direction, of the drill bit 204 can
be acquired from the orientation sensors 203 on the BHA. Thus,
continuous communication between the orientation sensors 203 and
the surface is required. Once the depth and orientation of the
drill bit 204 are known, the driller 201 selects a drill bit
inclination and azimuthal direction that will result in the drill
bit 204 drilling along the well plan. The driller 201 transmits the
desired inclination and azimuth to the directional drilling device
202, which controls the orientation of the drill bit 204. The
driller 201 monitors the orientation of the drill bit 204 and sends
new orientation instructions any time the drill bit 204 strays from
the well plan or when the well plan requires a different
orientation. This requires frequent communication between the
driller and the directional drilling device.
[0031] FIG. 2B shows a block diagram of a downhole closed loop
trajectory control according to one aspect of the invention. The
directional driller 251 determines the well plan and ultimately
controls the drilling process, but the primary drill bit trajectory
control is performed by a downhole processor 252.
[0032] The driller 251 transmits a directional instruction to a
processor 252 disposed in the BHA. The processor 252 receives the
directional signal, and from that point on, the processor 252
controls the trajectory of the drill bit 255 through a downhole
closed loop, with minimal or no further input from the driller 251.
The processor 252 acquires drill bit 255 orientation information
from the orientation sensors 253, such as the drill bit's
inclination and azimuthal direction. Based on the directional
instruction and the orientation information, the processor 252
determines how the drill bit 255 should be oriented during drilling
so that it will drill along the desired path. The processor 252
transmits instructions to the directional drilling device 254,
which, in turn, steers the drill bit 255.
[0033] In some embodiments, the processor 252 also transmits a
signal back to the surface so that the driller 251 can monitor
drilling progress. The rate of communication may be at a much
slower rate than is required in open-loop methods where the driller
251 controls the drill bit 255.
[0034] The lines representing communications between the driller
251 and the processor 252 are shown as dashed lines because they
are not continuous communications. A downhole closed-loop
trajectory control according to the invention enables the processor
252 disposed down hole to control the drill bit 255 with minimal
communication between the processor 252 and the driller 251.
[0035] In some embodiments, a directional signal comprises a simple
instruction to drill along a straight path by maintaining the
present orientation. In other embodiments, the directional signal
comprises a desired inclination and azimuthal direction. In still
other embodiments, the directional signal comprises a instruction
to follow a curved path. A curved path directional signal may
comprise a curvature rate per unit time, or it may comprise a
curvature rate per unit distance. Various directional signals are
described in more detail in the description of different
embodiments that follow.
[0036] The directional drilling device can be any device used to
control the direction of a drill bit. Many such devices are known
in the art. For example, a bent housing and a mud motor could be
used as a directional drilling device. Also, a rotary steerable
system could be used as a directional drilling device. The
invention is not limited by the exact directional drilling device
used.
[0037] The processor 252 in FIG. 2B may be any device adapted to
interpret sensor set data or control the directional drilling
device 254. The processor 252 may also be a more complex computer
that is also adapted to interpret and store data from MWD or LWD
sensors on the BHA that investigate formation properties or drill
bit health status.
[0038] Advantages of the present invention include the elimination
of human error from the drilling process. The processor uses
objective criteria to evaluate the position to the drill bit in
relation to a desired position. The downhole closed loop does not
include subjective evaluation by a driller, thereby reducing the
human error in the drilling process.
[0039] Further, the present invention reduces the effect of off
trajectory drilling. Because the trajectory control is a downhole
closed loop, the processor can make adjustments based on
orientation data in real time. Orientation data is analyzed
downhole, and the processor makes correction as soon as a deviation
from the desired path is detected. There is no need to transmit
orientation data to the surface and await a response from the
driller. Even in embodiments where orientation data are transmitted
back to the surface for monitoring, it is only so that the driller
can monitor the process. The processor does not need to await a
response. The result is a more accurately drilled well path that is
less tortuous than open loop methods.
[0040] Other advantages of a downhole closed loop trajectory
control according to the present invention include a substantial
reduction in the amount of data that must be transmitted between
the driller and the BHA. Any telemetry devices may then be used to
transmit other data, such as formation data collected by MWD or LWD
sensors.
[0041] FIG. 3 shows a method of drilling a borehole according to
one embodiment of the invention. The method first includes
transmitting (shown as 301) a directional signal to a downhole
processor. In some embodiments, the directional signal comprises a
signal that instructs the processor to maintain the present drill
bit inclination and azimuthal direction. In other embodiments, the
signal may comprise a desired inclination and azimuthal direction
of the drill bit. Those having skill in the art will realize that
there are many types of signals that may constitute a directional
signal.
[0042] In some embodiments, the directional signal is transmitted
to the downhole processor before the processor is placed in a
borehole. That is, the directional signal is pre-loaded into the
processor at the surface, and then the BHA is lowered into the
borehole.
[0043] The method next includes maintaining (shown as 302) a
desired drill bit azimuthal direction. The processor acquires
azimuthal direction data from the orientation sensors and evaluates
the drill bit azimuthal direction in relation to the desired
azimuthal direction, determined from the directional signal. The
processor controls the directional drilling device to make any
necessary corrections to the drill bit azimuthal direction.
[0044] In some embodiments, the method also includes maintaining
(shown as 303) the desired drill bit inclination. Once the
processor has received a directional signal from the driller, the
processor acquires inclination data from orientation sensors and
evaluates the drill bit's actual inclination relative to the
desired inclination. The processor then makes any necessary
corrections to the drill bit's inclination by controlling the
directional drilling device.
[0045] The method is not limited by the order of maintaining the
azimuthal direction and maintaining the inclination. The
maintaining the azimuthal direction may be a continuous process, or
a process that is repeated at relatively small time intervals.
Maintaining the inclination is a similar process.
[0046] FIG. 4 shows a method of maintaining a curve according to
another aspect of the invention. The method includes transmitting a
directional signal to a downhole processor (shown at 401). The
directional signal according to this aspect of the invention
comprises a rate of curvature per unit time. In some embodiments,
the signal comprises both an azimuthal rate of curvature per unit
time, expressed as degrees per hour, and an inclination rate of
curvature per unit time, also expressed as degrees per hour. Note
that the units of degrees per hour are used merely as a matter of
convention. Any units of curvature per unit time may be used, for
example, radians per day, without departing from the scope of the
invention.
[0047] The method next includes maintaining an azimuthal rate of
curvature (shown as 402). The directional signal, which may include
a desired azimuthal rate of curvature, enables the processor to
determine a desired azimuthal direction as a function of time. The
actual azimuthal rate of curvature, determined using orientation
data from the orientation sensors, is compared with the desired
azimuthal rate of curvature. The processor controls the directional
drilling device to maintain the drill bit azimuthal rate of
curvature.
[0048] The method may also include maintaining an inclination rate
of curvature (shown as 403). The directional signal, which may
include a desired inclination rate of curvature per unit time,
enables the processor to determine the desired inclination as a
function of time. The actual inclination rate of curvature,
determined from the orientation sensors, is compared with the
desired inclination at that particular time, and the processor
controls the directional drilling device to make corrections to the
actual drill bit inclination.
[0049] As an example, a driller may transmit a directional signal
to a drill bit comprising an inclination curvature of
+3.degree./hour and an azimuthal direction curvature of
-1.degree./hour. If the drill bit's initial position, that is, the
drill bit's orientation when the signal was received, was at an
inclination of 3.degree. and an azimuthal direction of 0.degree.,
the processor can compute the desired orientation at any future
time. Thus, after 3 hours have elapsed, the processor will have
maintained the curved path and the orientation of the drill bit
will be an inclination of 12.degree. and an azimuthal direction of
3.degree. (in a counter-clockwise direction, looking down the
borehole).
[0050] Even though control of the drill bit trajectory is
transferred downhole, it is not necessary that the downhole
processor knows the drill bit depth to maintain a constant curve.
Using a downhole closed loop to maintain a rate of curvature per
unit time enables the driller to monitor only the
rate-of-penetration ("ROP") of the drill bit. If the driller
maintains a constant ROP, the curvature of the drilled wellbore
will be constant over the length of the curve and will closely
match the well plan.
[0051] FIG. 5 shows another aspect of the invention. A BHA 501
comprises a drill bit 503, a directional drilling device 502, and
two sets of orientation sensors 511 and 512. The first set of
orientation sensors 511 is disposed proximate to the drill bit and
enables the determination of the drill bit's orientation. The
second set of orientation sensors 512 is located farther up the
drill string, at a known axial distance from the first set of
orientation sensors 511.
[0052] The two sets of orientation sensors separated by a known
axial distance enables the determination of the curvature per unit
distance by acquiring orientation data from each set of sensors.
Along a curved well path, the axially spaced orientation sensors
will detect different orientations at their respective axial
locations. By dividing the difference between similar orientation
measurements at each sensor set location by the distance between
the sensor sets, a rate of curvature per unit distance is
determined.
[0053] A sensor set is a plurality of sensors that are able to
determine the inclination and azimuthal direction of the BHA at
that axial position. A sensor set may include accelerometers,
magnetometers, or gyroscopes. In some embodiments, a sensor set
comprises three accelerometers and three magnetometers. In other
embodiments, a sensor set may comprise three accelerometers and a
combination of magnetometers and gyroscopes. U.S. Pat. No.
6,405,808 issued to Edwards et al. discloses a method for improving
the quality of data from orientation sensors.
[0054] In some embodiments, the BHA 501 may include a processor 521
to enable a downhole closed loop trajectory control. The
directional drilling device 502 can be any suitable device known in
the art, including a rotary steerable system or a bent housing with
a mud motor. In some other embodiments, the BHA 501 includes a
short-hop telemetry system (not shown). The short-hop telemetry
system enables communication between the processor 521 and the
sensor sets 511 and 512. Many short-hop telemetry devices are known
in the art.
[0055] As an example, if the first sensor set 511 indicates an
inclination of 15.degree. and the second set of orientation sensors
512 indicates an inclination of 10.degree., the difference would be
5.degree.. When that difference is divided by the axial distance
between the first sensor set 511 and the second sensor set 512, for
example, 100 feet, an inclination curvature rate of 1.degree./20
feet would be determined.
[0056] FIG. 6 shows a method according to another aspect of the
invention. The method first transmits (shown as 601) a directional
signal to the BHA. The BHA may comprise a processor and a plurality
of orientation sensor sets spaced apart by a known axial distance.
The directional signal may comprise a desired rate of curvature per
unit distance. The desired rate of curvature may include an desired
inclination rate of curvature and a desired azimuthal rate of
curvature.
[0057] The processor controls the directional drilling device so as
to maintain (shown as 602) at least one of the inclination rate of
curvature per unit distance and the azimuthal rate of curvature per
unit distance. In some embodiments, the processor acquires
orientation data from the orientation sensors and evaluates the
actual inclination rate of curvature relative to the desired rate
of curvature. The processor makes corrections to the inclination
rate of curvature by controlling the directional drilling
device.
[0058] In other embodiments, the processor also acquires
orientation data from the orientation sensors and evaluates the
actual azimuthal rate of curvature relative to the desired rate of
curvature. The processor makes any necessary corrections to the
actual azimuthal rate of curvature by controlling the directional
drilling device.
[0059] FIG. 7 shows an embodiment according to another embodiment
of the invention. The method includes loading (shown as 701)
trajectory data for a plurality of drilling segments into a
downhole processor. The trajectory data may include data for
straight line segments of a well path as well as data for curved
segments of a well path. For example, a driller may desire to drill
straight down for certain distance, then change the inclination by
15.degree., then drill another straight path, and finally change
the azimuth by 25.degree.. Each of these segments could be
programmed into the downhole processor so that the processor could
control drilling to the target without any further
instructions.
[0060] The straight line segments may be represented by trajectory
data indicating a desired inclination and the azimuthal direction,
as well as the time required to drill the straight line segment.
The driller regulates the ROP so that the drill bit would drill the
desired distance in the specified time.
[0061] Curved segments may be specified by either a curvature rate
per unit time or a curvature rate per unit distance. In either
case, the trajectory data for a curved segment may include a final
orientation. Once the final orientation is achieved, the processor
begins drilling the next segment. In some embodiments, the
trajectory data do not include a time duration, but the driller
transmits a short signal instructing the processor to drill the
next segment.
[0062] The method next includes maintaining (shown at 702) a
desired drill bit inclination using a downhole processor to
evaluate an actual drill bit inclination relative to the trajectory
data for each segment. The actual drill bit inclination is
determined using data from orientation sensors, and the trajectory
data for each segment enable the processor to determine a desired
inclination.
[0063] The method also includes maintaining (shown at 703) a
desired azimuthal direction using the downhole processor to
evaluate an actual drill bit azimuthal direction relative to the
trajectory data for each segment. Similarly, the actual drill bit
azimuthal direction is determined using data from the orientation
sensors, and it is compared to the trajectory data.
[0064] While the invention has been described with respect to a
limited number of embodiments, those skilled in the art, having
benefit of this disclosure, will appreciate that other embodiments
can be devised which do not depart from the scope of the invention
as disclosed herein. Accordingly, the scope of the invention should
be limited only by the attached claims.
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