Note: Descriptions are shown in the official language in which they were submitted.
CA 02342594 2001-04-03
Patent
19.0276
DIRECTIONAL DRILLING SYSTEM
This application claims priority to the following U.S. patent applications:
Serial No.
09/542,607 filed on April 4, 2000, Serial No. 60/200,941 filed May 1, 2000,
and Serial No.
09/563,801 filed May 2, 2000.
BACKGROUND OF THE INVENTION
Field of the Invention
to The present invention provides a variable gauge stabilizer for use in
directional drilling of
wells used to recover oil and gas, and a method for directionally drilling a
well to recover oil and
gas.
This invention relates generally to an apparatus and system for making
downhole measurements
during the drilling of a wellbore. In particular, it relates to an apparatus
and system for making
t 5 downhole measurements at or near the drill bit during directional drilling
of a wellbore.
The Related Art
Wells are generally drilled to recover natural deposits of hydrocarbons and
other
desirable, naturally occurring materials trapped in geological formations in
the earth's crust. A
2o slender well is drilled into the ground and directed to the targeted
geological location from a
drilling rig at the surface. In conventional "rotary drilling" operations, the
drilling rig rotates a
drillstring comprised of tubular joints of drill pipe connected together to
turn a bottom hole
assembly (BHA) and a drill bit that are connected to the lower end of the
drillstring. The BHA
typically comprises a number of downhole tools including stabilizers, drill
collars and mud
25 motors, and is generally within 30 feet of the drill bit at the end of the
drillstring. During drilling
operations, a drilling fluid, commonly referred to as drilling mud, is pumped
down the interior of
the drillpipe, through the BHA and the drill bit, and back to the surface in
the annulus around the
drillpipe. Mud motors are often used to turn the drill bit without rotation of
the drillstring.
Pressurized mud pumped down the interior of the drillstring is used to power
the mud motor that
3o is mechanically coupled to and turns the nearby drill bit. Mud motors offer
increased flexibility
for directional drilling because they can be used with stabilizers or bent
subs which impart an
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angular deviation to the BHA in order to deviate the well from its previous
path and in the
desired direction.
Stabilizers are generally heavy downhole tools that make up part of the BHA
and are
35 typically connected either above the mud motor and the drill bit or between
the mud motor and
the drill bit. Stabilizers are designed to promote smooth, continuous drilling
action at the drill bit
by limiting lateral movement of the BHA that could otherwise result from
disruptive forces
transferred from the teeth of the rapidly turning drill bit violently breaking
pieces of rock from
the bottom of the wellbore. Stabilizers are also designed to accommodate the
flow of drilling
4o mud from the drillstring to the mud motor and drill bit connected downhole.
Pressurized drilling
mud pumped down the drillstring provides a flowing fluid to power the drill
motor, suspend and
remove drill cuttings from the well, and lubricate the drill bit for better
drilling.
Importantly, a stabilizer that can be adjusted from the surface to a greater
or lesser
diameter can be used to influence the drop or build angle of the boring
direction of the drill bit.
45 The slender BHA is substantially rigid, and the angle of attack of the
drill bit can be guided using
the adjustable stabilizer. The outer diameter of the stabilizer substantially
influences the axial
alignment of the lower portion of the BHA from the stabilizer to the drill
bit. Controllably
affecting this alignment relative to the existing wellbore determines the
angle at which the rotary
drill bit engages the bottom of the wellbore.
5o Before adjustable stabilizers, deviating the wellbore from its existing
path required
removing the drillstring from the well, inserting a stabilizer with an outer
diameter that provided
the desired angular deviation, and running the entire drillstring back into
the well. Once the
newly configured BHA containing a non-adjustable stabilizer was in place at
the bottom of the
existing well, drilling was resumed in the desired deviated path. When the
desired deviation in
55 the path of the well had been achieved, the non-adjustable stabilizer was
removed by pulling the
entire drillstring from the well, replacing the stabilizer with another, and
running the entire
drillstring back into the well to resume drilling along the adjusted path.
Figure lA shows an inactive adjustable diameter stabilizer connected above the
mud
motor and the drill bit and imparting a slight upward angular deviation to the
BHA, thereby
6o influencing the drill bit to build angle, or turn upwardly, from its
existing path. Figure 1B shows
an inactive adjustable diameter stabilizer connected between the mud motor and
the drill bit and,
again, imparting a build angle to the drill bit. Figure 2A shows how a
deployed adjustable
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stabilizer connected above the mud motor and the drill bit has a larger
effective outer diameter
and imparts a slight downward angular deviation thereby influencing the drill
bit to drop angle,
65 or turn downwardly, from its existing path. Figure 2B shows a deployed
adjustable stabilizer
connected between the mud motor and the drill bit and imparting a drop angle
to the drill bit. It
is well known in the drilling industry how to obtain reliable three-
dimensional location data for
the bottom of the well being drilled. The driller compares this information
with the target
bottom hole location to determine needed adjustments in the path of the well,
and the
70 adjustments may be made using the present invention.
Anderson's U.S. Patent No. 4,848,490 provides a variable downhole stabilizer
that is
actuated (outer diameter increased by radially outward deployment of spacers)
by reverse
telescoping action; that is, the driller actuates the tool by increasing the
weight on bit to impart
an axially compressing force tending to reverse telescope the stabilizer tool.
When the weight on
75 the bit reaches or exceeds a threshold force determined by the strength of
an opposing spring, the
mandrel engages the spacers thereby deploying the spacers radially outward to
increase the
diameter of the tool and affect angular deviation to the drill bit. However,
Anderson's stabilizer
requires the driller to slide the entire drillstring in the well in order to
reverse telescope and
actuate the tool. In directionally drilled wells having long horizontal or
inclined portions, the
go frictional resistance to sliding of the drillstring in the well is a
function of the co-efficient of
friction and the weight of the drillstring supported by the wall of the
wellbore. The frictional
resistance to sliding the drillstring within the well can be extremely large
and unpredictable due
to the roughness of the bore wall of the well. Difficulties in obtaining
controlled movement of
the lower end of the drillstring can cause problems in tool actuation,
especially as the length of
g5 the drillstring and the horizontal deviation of wells continues to
increase. Consequently,
actuating a variable stabilizer by reciprocating the drillstring is
problematic.
Lee's U.S. Patent No. 5,339,914 provides a variable downhole stabilizer that
is
hydraulically actuated (outer diameter increased by radially outward
deployment of tool
elements). However, Lee's variable downhole stabilizer requires that the
driller lower the entire
9o drillstring into the well in order to lock the deployable tool elements in
their deployed position.
Like Anderson's stabilizer, sliding the entire drillstring against the rough
wall of the wellbore is
required to operate Lee's stabilizer. In order to retract the tool elements of
Lee's stabilizer, the
entire drillstring must be raised to unlock the stabilizer and adjust the
stabilizer.
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What is needed is a surface-operated variable gauge stabilizer that can be
deployed or
95 retracted solely by accurately controllable changes in hydraulic mud
pressure in the drillstring
without cumbersome reciprocations of the entire drillstring. What is needed is
a surface-
operated variable gauge stabilizer that can be adjusted without the use of
wired or cabled control
systems that complicate drilling operations. What is needed is a reliable
variable gauge stabilizer
that is easy and simple to deploy and retract. What is needed is a surface-
operated variable
too gauge stabilizer that, once locked into its deployed position, allows the
driller freedom to change
the position of the drillstring and the rate of the mud pumps, within a pre-
defined pressure range,
without affecting the deployed condition of the tool. What is needed is a
surface-operated
variable gauge stabilizer that provides the driller with reliable detection of
the deployed or
retracted status of the tool.
1o5 In drilling a directional well, it is common to use a bottom hole drilling
assembly (BHA) that is
attached to a drill collar as part of the drill string. This BHA typically
includes (from top down), a
drilling motor assembly, a drive shaft system including a bit box, and a drill
bit. In addition to the
motor, the drilling motor assembly includes a bent housing assembly which has
a small bend angle in
the lower portion of the BHA. This angle causes the borehole being drilled to
curve and gradually
1 ~ o establish a new borehole inclination and/or azimuth. During the drilling
of a borehole, if the drill string
is not rotated, but merely slides downward as the drill bit is being driven by
only the motor, the
inclination and/or the azimuth of the borehole will gradually change due to
the bend angle. Depending
upon the "tool face" angle, that is, the angle at which the bit is pointing
relative to the high side of the
borehole, the borehole can be made to curve at a given azimuth or inclination.
If however, the rotation
t 15 of the drill string is superimposed over that of the output shaft of the
motor, the bend point will simply
travel around the axis of the borehole so that the bit normally will drill
straight ahead at whatever
inclination and azimuth have been previously established. The type of drilling
motor that is provided
with a bent housing is normally referred to as a "steerable system". Thus,
various combinations of
sliding and rotating drilling procedures can be used to control the borehole
trajectory in a manner such
i2o that eventually the drilling of a borehole will proceed to a targeted
formation. Stabilizers, a bent sub,
and a "kick-pad" also can be used to control the angle build rate in sliding
drilling, or to ensure the
stability of the hole trajectory in the rotating mode.
Referring initially to the configuration of Fig. 9, a drill string 210
generally includes lengths of
drill pipe 211 and drill collars 212 as shown suspended in a borehole 213 that
is drilled through an earth
CA 02342594 2001-04-03
Patent
19.0276
t 25 formation 209. A drill bit 214 at the lower end of the drill string is
rotated by the drive shaft 215
connected to the drilling motor assembly 216. This motor is powered by
drilling mud circulated down
through the bore of the drill string 210 and back up to the surface via the
borehole annulus 213a. The
motor assembly 216 includes a power section (rotor/stator or turbine) that
drives the drill bit and a bent
housing 217 that establishes a small bend angle at its bend point which causes
the borehole 213 to curve
t 3o in the plane of the bend angle and gradually establish a new borehole
inclination. As noted above, if
rotation of the drill string 210 is superimposed over the rotation of the
drive shaft 215, the borehole 213
will be drilled straight ahead as the bend point merely orbits about the axis
of the borehole. The bent
housing can be a fixed angle device, or it can be a surface adjustable
assembly. The bent housing also
can be a downhole adjustable assembly as disclosed in U.S. Patent 5,117,927
which is incorporated
135 herein by reference. Alternately, the motor assembly 216 can include a
straight housing and can be used
in association with a bent sub well known in the art and located in the drill
string above the motor
assembly 216 to provide the bend angle.
Above the motor in this drill string is a conventional measurement while
drilling (MWD) tool
218 which has sensors that measure various downhole parameters. Drilling,
drill bit and earth formation
i4o parameters are the types of parameters measured by the MWD system.
Drilling parameters include the
direction and inclination (D&I) of the BHA. Drill bit parameters include
measurements such as weight
on bit (WOB), torque on bit and drive shaft speed. Formation parameters
include measurements such as
natural gamma ray emission, resistivity of the formations and other parameters
that characterize the
formation. Measurement signals, representative of these downhole parameters
and characteristics, taken
t45 by the MWD system are telemetered to the surface by transmitters in real
time or recorded in memory
for use when the BHA is brought back to the surface.
As shown in Fig. 9, when an MWD tool 218, such as the one disclosed in
commonly-assigned
U.S. Patent 5,375,098, is used in combination with a drilling motor 216, the
MWD tool 218 is located
above the motor and a substantial distance from the drill bit. Including the
length of a non-magnetic
t 5o spacer collar and other components that typically are connected between
the MWD tool and the motor,
the MWD tool may be positioned as much as 20 to 40 feet above the drill bit.
These substantial
distances between the MWD sensors in the MWD tool and the drill bit mean that
the MWD tool's
measurements of the downhole conditions, related to drilling and the drill bit
at a particular drill bit
location, are made a substantial time after the drill bit has passed that
location. Therefore, if there is a
t55 need to adjust the borehole trajectory based on information from the MWD
sensors, the drill bit will
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have already traveled some additional distance before the need to adjust is
apparent. Adjustment of the
borehole trajectory under these circumstances can be a difficult and costly
task. Although such large
distances between the drill bit and the measurement sensors can be tolerated
for some drilling
applications, there is a growing desire, especially when drilling directional
wells, to make the
16o measurements as close to the drill bit as possible.
Two main drilling parameters, the drill bit direction and inclination are
typically calculated by
extrapolation of the direction and inclination measurements from the MWD tool
to the bit position,
assuming a rigid BHA and drill pipe system. This extrapolation method results
in substantial error in the
borehole inclination at the bit especially when drilling smaller diameter
holes ( less than 6 inches) and
t 65 when drilling short radius and re-entry wells.
Another area of directional drilling that requires very accurate control over
the borehole
trajectory is "extended reach" drilling applications. These applications
require careful monitoring and
control in order to ensure that a borehole enters a target formation at the
planned location. In addition to
entering a formation at a predetermined location, it is often necessary to
maintain the borehole drilling
t 7o horizontally in the formation. It is also desirable for a borehole to be
extended along a path that
optimizes the production of oil, rather than water which is found in lower
portions of a formation, or gas
found in the upper portion of a formation.
In addition to making downhole measurements which enable accurate control over
borehole trajectory, such as the inclination of the borehole near the bit, it
is also highly desirable
175 to make measurements of certain properties of the earth formations through
which the borehole
passes. These measurements are particularly desirable where such properties
can be used in
connection with borehole trajectory control. For example, identifying a
specific layer of the
formation such as a layer of shale having properties that are known from logs
of previously
drilled wells, and which is known to lie a certain distance above the target
formation, can be used
t 8o in selecting where to begin curving the borehole to insure that a certain
radius of curvature will
indeed place the borehole within the targeted formation. A shale formation
marker, for example,
can generally be detected by its relatively high level of natural
radioactivity, while a marker
sandstone formation having a high salt water saturation can be detected by its
relatively low
electrical resistivity. Once the borehole has been curved so that it extends
generally horizontally
~ 85 within the target formation, these same measurements can be used to
determine whether the
borehole is being drilled too high or too low in the formation. This
determination can be based
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on the fact that a high gamma ray measurement can be interpreted to mean that
the hole is
approaching the top of the formation where a shale lies, and a low resistivity
reading can be
interpreted to mean that the borehole is near the bottom of the formation
where the pore spaces
19o typically are saturated with water. However, as with D&I measurements,
sensors that measure
formation characteristics are located at large distances from the drill bit.
One approach, by which the problems associated with the distance of the D&I
measurements,
borehole trajectory measurements and other tool measurements from the drill
bit can be alleviated, is to
bring the measuring sensors closer to the drill bit by locating sensors in the
drill string section below the
t95 drilling motor. However, since the lower section of the drill string is
typically crowded with a large
number of components such as a drilling motor power section, bent housing,
bearing assemblies and one
or more stabilizers, the inclusion of measuring instruments near the bit
requires the addressing of several
major problems that would be created by positioning measuring instruments near
the drill bit. For
example, there is the major problem associated with telemetering signals that
are representative of such
Zoo downhole measurements uphole, through or around the motor assembly, in a
practical and reliable way.
A concept for moving the sensors closer to the drill bit was implemented in
Orban et. al, U.S.
Patent 5,448,227. This patent is directed to a sensor sub or assembly that is
located in the drill string at
the bottom of the motor assembly, and which includes various transducers and
other means for
measuring parameters such as inclination of the borehole, the natural gamma
ray emission and electrical
205 resistivity of the formations, and variables related to the performance of
the drilling motor. Signals
representative of such measurements are telemetered uphole, through the wall
of the drill string or
through the formation, a relatively short distance to a receiver system that
supplies corresponding
signals to the MWD tool located above the drilling motor. The receiver system
can either be connected
to the MWD tool or be a part of the MWD tool. The MWD tool then relays the
information to the
2t0 surface where it is detected and decoded substantially in real time.
Although the techniques of this
patent make substantial progress in moving sensors closer to the drill bit and
overcoming some of the
major telemetry concerns, the sensors are still approximately 6 to 10 feet
from the drill bit. In addition,
the sensors are still located in the motor assembly and the integration of
these sensors into the motor
assembly can be a complicated process.
215 A technique that attempts to address the problem of telemetering the
measured signals uphole
around the motor assembly to the MWD tool uses an electromagnetic transmission
scheme to transmit
measurements from behind the drill bit. In this system, a fixed frequency
current signal is induced
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through the drill collar by a toroidal coil transmitter. As a result, the
current flows through the drill
string to the receiver with a return path through the formation. The
propagation mode is known as a
220 Transverse Magnetic (TM) mode. In this propagation mode, transmission is
unreliable in extremely
resistive formations, in formations with very resistive layers alternating
with conductive layers, and in
oil-based mud with poor bit contact with the formation.
Therefore, there still remains a need for a system that can improve the
accuracy of bit
measurements by placing sensors at the drill bit and reliably transmitting
these signals uphole to MWD
225 equipment for transmission to the earth's surface.
As earlier stated there can be a substantial distance between the drilling
motor and the drill bit.
This distance is caused by several pieces of equipment that are necessary for
the drilling operation. One
piece of equipment is the shaft used to connect the motor rotor to the drill
bit. The motor rotates the
shaft which rotates the drill bit during drilling. The drill bit is connected
to the shaft via a bit box. The
23o bit box is a metal holding device that fits into the bowl of a rotary
table and is used to screw the bit to
(make up) or unscrew (break out) the bit from the drill string by rotating the
drill string. The bit box is
sized according to the size of the drill bit. In addition, the bit box has the
internal capacity to contain
equipment.
Fig. 10 illustrates a conventional drilling motor system. A bit box 219 at the
bottom portion of
235 the drive shaft 215 connects a drill bit 214 to the drive shaft 215. The
drive shaft 215 is also connected
to the drilling motor power section 216 via the transmission assembly 216a and
the bearing section 220.
The shaft channel 215a is the means through which fluid flows to the drill bit
during the drilling process.
The fluid also carries formation cuttings from the drill bit to the surface.
In the drilling system of Fig.
10, no instrumentation is located in or near the bit box 219 or drill bit 214.
The closest that the
24o instruments would be to the drill bit would be in the lower portion of the
motor power section 216 as
described in U.S. Patent 5,448,227 or in the MWD tool 218. As previously
stated, the sensor location is
still approximately 6 to 10 feet from the drill bit. The positioning of
measurement instrumentation in the
bit box would substantially reduce the distance from the drill bit to the
measurement instrumentation.
This reduced distance would provide an earlier reading of the drilling
conditions at a particular drilling
245 location. The earlier reading will result in an earlier response by the
driller to the received measurement
information when a response is necessary or desired.
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SUMMARY OF THE INVENTION
The present invention provides a system for directionally drilling a wellbore
using a drill
25o string having a mud motor, a drill bit, and a drive shaft for transmitting
torque from the mud
motor to the drill bit, the system including: a tool carried in the drill
string that is adjustable for
varying the direction of the drill bit and the wellbore; an instrument for
measuring data while
drilling, the instrument being carried within a drill bit connecting means for
connecting the drill
bit to the drill string; and a telemetry system for transmitting the measured
data to a driller at the
255 surface, the telemetry system including: a transmitter disposed in the
drill string beneath the mud
motor for transmitting a signal corresponding to the measured data; and a
receiver disposed in
the drill string above the mud motor for receiving the signal and recovering
the measured data
from the signal.
26o BRIEF DESCRIPTION OF DRAWINGS
So that the features and advantages of the present invention can be understood
in detail, a
more particular description of the invention, briefly summarized above, may be
had by reference
to the embodiments thereof that are illustrated in the appended drawings. It
is to be noted,
however, that the appended drawings illustrate only typical embodiments of
this invention and
265 are therefore not to be considered limiting of its scope, for the
invention may admit to other
equally effective embodiments.
Figure 1 A is an elevation view of an inactive variable gauge stabilizer using
the mud
motor as a fulcrum to impart an upward angle to the drill bit to build angle,
or turn the well
upwardly, from its existing path.
27o Figure 1B is an elevation view of a deployed variable gauge stabilizer
using the mud
motor as a fulcrum to impart a downward angle to the drill bit to drop angle,
or turn the well
downwardly, from its existing path.
Figure 2A is an elevation view of an inactive variable gauge stabilizer
imparting an
downward angle to the drill bit to drop angle, or turn the well downwardly,
from its existing
275 path.
Figure 2B is an elevation view of a deployed variable gauge stabilizer
imparting an
upward angle to the drill bit to build angle, or turn the well upwardly, from
its existing path.
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Figure 3 is a cross-sectional side view of a variable gauge stabilizer in the
inactive
position.
28o Figure 4 is a side view, partially in section, of a four-stroke rotating
position control
collar.
Figures SA through 5D are a sequential series of side views, partially in
section, showing
a cycle of a control collar and its interaction with a guide finger.
Figure 6 is a cross-sectional side view of the variable gauge stabilizer in
its intermediate
285 position.
Figure 7 is a cross-sectional side view of the variable gauge stabilizer in an
active,
deployed position.
Figure 8A through 8C are magnified side views of the beveled portion of the
deployment
mandrel of the variable gauge stabilizer deploying a stabilizer element
through a stabilizer port in
29o the housing.
Figure 9 is a schematic view that shows a deviated extended reach borehole
with a string
of measurement and drilling tools therein according to the prior art;
Figure 10 is a cross-section of the lower portion of another prior art
drilling assembly;
Figure I 1 is a schematic view of an extended bit box embodiment for near-bit
communication of
295 MWD data according to the present invention;
Figure 12 is a schematic view of an extended sub embodiment for near-bit
communication of
MWD data according to the present invention;
Figure 13 is a cross-section view of the lower portion of a drilling assembly
incorporating the
extended bit box embodiment;
3oo Figure 14 is a detailed, cross-section view of the extended bit box
embodiment;
Figure I 5 is a perspective view of the extended bit box embodiment;
Figure 16 is a cross-section view of the batteries and the sensing
instrumentation mounted inside
the channel of the drive shaft of the extended bit box embodiment;
Figure 17 is a cross-section view of the transmitter and control circuitry of
the extended bit box
305 embodiment;
Figure 18 is a schematic view of the lower portion of a drilling string with
an
instrumented drill bit embodiment for near-bit communication of MWD data;
I1
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Figures 19 and 20 are schematic illustrations of a drill strings utilizing
wireless telemetry
means and near-bit data communication according to present invention;
31 o Figure 21 is a diagram of an unaltered continuous carrier signal;
Figure 22 illustrates a modulated carrier signal containing drilling and
logging
information;
Figure 23 is a flow diagram of the operation of determining borehole
inclination in
accordance with the present invention;
3t5 Figure 24 is an illustration of a 27 bit word for data transmission
uphole;
Figure 25 is an illustration of a pulse position modulated data frame
transmitted to a
receiver;
Figure 26 is a diagram of the pulse positions in a data region of the data
frame of Figure
25;
32o Figures 27a, 27b, and 27c illustrate various pulse positions within a data
region based on
various bit sequences;
Figure 28 is a schematic of the circuit used to extract the carrier signal
portion of the
transmitted signal during demodulation and to detect peak amplitude;
Figures 29a and 29b illustrate respectively modulated signals as transmitted
and as
325 received in the present invention;
Figure 30 is a cross-sectional view of the transmitter of the present
invention;
Figure 31 is a plot of the signal amplitude resistivity transform for a two-
coil deep
resistivity measurement system of the present invention;
Figures 32a, 32b, 32c, and 32d are plots of the real and imaginary signal
resistivity
33o transform at various signal levels and transmitter to receiver spacings;
Figure 33 is a schematic illustration of a tool according to the present
invention
approaching a resistivity contrast boundary at an apparent dip angle of 90
degrees;
Figure 34a is a graph of the formation resistivity signal response as the tool
of Figure 33
travels from a low resistivity formation to a high resistivity formation;
335 Figure 34b is a graph of the formation resistivity signal response as the
tool of Figure 33
travels from a high resistivity formation to a low resistivity formation;
Figure 35 is a schematic illustration of a tool according to the present
invention
approaching a resistivity contrast boundary at an apparent dip angle of 0
degrees;
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Figure 36a is a graph of the formation resistivity signal response as the tool
of Figure 18
34o travels from a low resistivity formation to a high resistivity formation;
and
Figure 36b is a graph of the formation resistivity signal response as the tool
of Figure 18 travels
from a high resistivity formation to a low resistivity formation.
DETAILED DESCRIPTION OF THE INVENTION
345 Figure 3 shows the general configuration of a preferred embodiment of the
present
invention, a variable gauge stabilizer 10. The stabilizer 10 has a housing 12
with a threaded
proximal connection 22 disposed at one end of the stabilizer 10 for connection
to a drillstring 30
(not shown), a threaded distal connection 24 disposed at the other end of the
stabilizer 10 for
connection to drill collars 32 (not shown), and an axis 26 generally defined
by the centers of the
35o threaded connections 22 and 24. The housing 12 also has a plurality of
stabilizer ports 14
disposed radially about the axis 26 that receive the stabilizer elements 16 so
that the elements
radially reciprocate within and through the stabilizer ports 14. The
stabilizer elements 16 can be
radially outwardly deployed against opposing stabilizer springs 18 by
actuation of the
deployment mandrel 140 to its deployed position (shown in Figure 7), and
radially inwardly
355 retracted by springs when the deployment mandrel 140 returns to its
inactive position (shown in
Figure 3). The stabilizer elements 16 may be any support members such as
pistons, stems or
rods. Figure 3 shows the positioning mandrel 40, the deployment mandrel 140
and the stabilizer
elements 16 all in their inactive and retracted positions. Figure 6 shows the
positioning mandrel
40 distally displaced against the force of the positioning mandrel spring 36
to its intermediate
36o position, the deployment mandrel 140 remaining in its inactive position as
urged by the
deployment mandrel spring 136, and the stabilizer elements 16 still in their
retracted position as
urged by the stabilizer element springs 18. Figure 7 shows the positioning
mandrel 40, the
deployment mandrel 140 and the stabilizer elements 16 all in their active and
deployed positions.
Figures 8A through 8C show a magnified view of the beveled portion 46 of the
deployment
365 mandrel 140 engaging and disposing the stabilizer element 16 radially
outwardly through the
stabilizer port 14 in the housing 12 to overcome the opposing force of the
stabilizer element
spring 18.
Figures 3, 6 and 7 show the positioning mandrel 40 with the rotating position
control
collar 42 rotatably received thereon, with both the positioning mandrel 40 and
the rotatably
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37o attached control collar 42 disposed within a chamber in the housing 12.
The positioning
mandrel 40 has an axis 44 and an annular drillstring pressure sensing surface
48. The
positioning mandrel 40 and the control collar 42 axially reciprocate together
within the chamber
of the housing 12 along their axis 44 that is generally aligned with the axis
26 of the housing 12.
The positioning mandrel 40 controllably and cyclically moves between three
positions as
375 determined by the angular orientation of the control collar relative to
the housing 12. The
positions of the positioning mandrel are the inactive position (first position
- Figure 3), the
intermediate position (second position - Figure 6), back to the inactive
position (Figure 3), and
the deployed position (third position - Figure 7), in that order. In its
deployed position shown in
Figure 7, the positioning mandrel 40 axially engages and displaces the
deployment mandrel 140
38o towards the distal connection 24 of the housing 12. The positioning
mandrel 40 and the
deployment mandrel 140 both reciprocate within the chamber generally along the
axis 44 of the
housing 12, but the positioning mandrel 40 reciprocates within a greater axial
range of motion
than does the deployment mandrel 140. The deployment mandrel 140 reciprocates
only when
displaced from its inactive position by force applied through the positioning
mandrel 40. The
3g5 movement of the positioning mandrel 40 is determined by the summation of
axial forces acting
thereon. The forces acting on the positioning mandrel 40 include the force of
the positioning
mandrel spring 36 and the forces applied by drilling mud pressure on various
exposed surfaces.
The responsiveness of the positioning mandrel 40 can be enhanced through
strategic placement
of circumferential seals and equalization ports to provide a net differential
force on the
39o positioning mandrel.
Figures 3, 6 and 7 show a proximal positioning mandrel seal 38 and a distal
positioning
mandrel seal 39 disposed on the positioning mandrel 40 for sliding contact
with the housing 12,
and a proximal deployment mandrel seal 138 and a distal deployment mandrel
seal 139 disposed
on the deployment mandrel 140 for sliding contact with the housing 12. The
portion of the
395 chamber of the housing 12 proximal to the proximal positioning mandrel
seal 38 is in fluid
communication with the drilling mud pressure in the drillstring 30 and in the
tubular interior of
the positioning mandrel 140. The portion of the chamber of the housing 12
between the
proximal positioning mandrel seal 38 and the distal positioning mandrel seal
39 is isolated from
the interior of drillstring 30, but is in fluid communication with the annular
mud pressure outside
40o the housing 12 through equalization port 173. The portion of the chamber
of the housing 12
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between the distal positioning mandrel seal 39 and the proximal deployment
mandrel seal 138 is
in fluid communication with the tubular interior of the positioning mandrel
40. The portion of
the chamber of the housing 12 between the proximal deployment mandrel seal 138
and the distal
deployment mandrel seal 139 is isolated from the interior of drillstring 30,
but is in fluid
405 communication with the annular pressure outside the housing 12 through
equalization port 273.
The pressure in the drillstring 30 results from drilling mud being forcefully
pumped down
the drillstring 30 from the discharge of the mud pumps at the surface and out
the bit nozzles.
The pressure in the drillstring 30, the pressure in the annulus 34, the force
of the positioning
mandrel spring 36 and force of the deployment mandrel spring 136 all combine,
along with
410 friction of the seals, to determine the net axial forces acting separately
on the positioning
mandrel 40 and the deployment mandrel 140. For example, the pressure in the
drillstring 30
bears on the exposed surfaces of the positioning mandrel 40 to provide a net
force acting on the
annular pressure sensing surface 48 of the positioning mandrel 40 and urging
the positioning
mandrel 40 from its inactive position towards either its intermediate or its
deployed positions,
4t5 depending on the orientation of the control collar 42 relative to the
housing 12.
The positioning mandrel spring 36 is disposed in contact with the housing 12
at a first
circumferential spring shoulder 13 and with the positioning mandrel 40 at a
first circumferential
ridge 15. The positioning mandrel spring 36 is placed under compression to
urge the positioning
mandrel 40 towards its inactive position shown in Figure 3. The deployment
mandrel spring 36
42o is designed to elastically compress when the pressure in the drillstring
30 is sufficient to provide
a force on the positioning mandrel 40 greater than a first threshold actuation
force. This design
secures the positioning mandrel 40 in the desired intermediate or deployed
position during
normal drilling operations as long as the drillstring pressure is above the
first threshold pressure
necessary to overcome and compress the positioning mandrel spring 36. For
example, the first
425 threshold actuation pressure may be any pressure that is great enough to
compress the
positioning mandrel spring 36. It should be recognized that the first
threshold actuation pressure
is primarily determined by the amount of resistance in the positioning mandrel
spring 36 and the
net surface area of the annular pressure sensing surface 48, but is also
influenced by the shape of
the positioning mandrel 40 and the annular pressure outside the housing 12
adjacent to the
43o equalization ports 173 and 273.
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As shown in Figure 4, the control collar 42 has a proximal end 41 disposed
toward the
proximal end of the housing 12 and a distal end 43 disposed toward the
deployment mandrel 140
and the distal connection 24 of the housing 12. The control collar 42 is the
device that enables
the driller to controllably deploy and retract the stabilizer elements 16 by
varying the pressure in
435 the drillstring 30 to reciprocate the positioning mandrel 40. A series of
interconnected grooves
are machined into the radially outer surface of the control collar 42. In a
simple four-stroke
design, these grooves comprise two return grooves 50 and 52 and two rotation
grooves 51 and
53. The control collar 42 is axially fixed to the positioning mandrel 40 and
reciprocates within
the housing 12 with the positioning mandrel 40, but it is free to rotate about
the axis 44 of the
440 positioning mandrel 40 as guided by a protruding guide finger 55 in a
fixed relationship to the
housing 12. Throughout the inactive-to-intermediate-to-inactive-to-deployed
position cycle of
the positioning mandrel 40, the guide finger 55 is maintained in rolling or
sliding contact with
the grooves in the control collar 42. As the control collar 42 and the
positioning mandrel 40
reciprocate within the housing 12, the guide finger 55 traverses the grooves
in a path as dictated
445 by the intersections of the grooves.
The position of the positioning mandrel 40 is controlled by manipulation of
pressure in
the drillstring 30. As shown in Figure 6, when the pressure of the drilling
mud in the drillstring
30 is sufficient to overcome the opposing axial forces urging the positioning
mandrel 40 towards
the inactive position, the positioning mandrel 40 is axially displaced towards
its intermediate
45o position. Following an intervening low mud pressure that allows the
positioning mandrel 40 to
return to its inactive position as shown in Figure 3, when the pressure of the
drilling mud in the
drillstring 30 is again sufficient to overcome the opposing forces urging the
positioning mandrel
40 towards its inactive position, the positioning mandrel 40 is axially
displaced towards the
deployed position shown in Figure 7. Although it is preferred that the
pressure sensing surface
455 48 be disposed at the proximal end of the positioning mandrel 40 adjacent
to the proximal
connection 22 of the housing 12 to the drillstring 30, the pressure sensing
surface 48 can be
located at the distal end of the positioning mandrel 40 or, using a proper
arrangement of seals, at
any point therebetween. It should also be recognized that by strategic
placement of seals, fluid
communication passages and the pressure sensing surface, the positioning
mandrel 40 may
46o actuate in either the proximal or the distal (uphole or downhole)
directions.
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The positioning mandrel 40 rotationally cycles through a multiple position
cycle as it
axially reciprocates within the housing 12. The description that follows
assumes that the control
collar 42 is a four-stroke collar. The invention may be used with a six-
stroke, eight-stroke or
higher number of cycles, and the explanation of the four-stroke cycle does not
limit the
465 applicability or adaptability of the invention.
When the stabilizer is in its inactive position shown in Figure 3, the guide
finger 55 is in
rolling or sliding contact in the first actuation groove 50 near the distal
end 43 of the control
collar 42 shown in Figure SA. The positioning mandrel 40 begins its cycle from
its inactive
position shown in Figure 3. From the inactive position, the positioning
mandrel 40 is proximally
47o actuated against the positioning mandrel spring 36, by exposure of the
pressure sensing surface
48 to a first threshold pressure, to its intermediate position shown in Figure
6. As the first
actuation stroke of the positioning mandrel 40 begins, the guide finger 55
rolls or slides
(actually, guide finger 55 is substantially stationary relative to housing 12,
but since collar 42
moves relative to housing 12, guide finger 55 "rolls or slides" relative to
collar 42) toward the
4'75 proximal end 41 of the control collar 42 within the second leg 253 of the
second actuation
groove 53 to the intersection of the second actuation groove 53 and the first
leg 150 of the first
actuation groove 50. When the guide finger 55 reaches that intersection, it
slides or rolls into the
first leg 150 of the first actuation groove 50 toward the intersection of the
first actuation groove
50 and the first leg 151 of the first return groove 51. The first leg 150 of
the first actuation
48o groove 50 is not aligned with the axis 44 of the control collar 42, and
the sliding or rolling
contact between the guide forger 55 and the first leg 150 imparts a moment
causing the control
collar 42 to rotate about its axis 44. The second leg 250 is non-linear to the
first leg 150 and is
generally aligned with the axis 44. When the guide finger 55 leaves the first
leg 150 and enters
the second leg 250, the guide finger 55 slides or rolls within the second leg
250 to a point near
4g5 the proximal end 41 of the control collar 42 to the intermediate position
shown in Figure SB.
Since the second leg 250 is generally aligned with the axis 44 of the control
collar 42, there is
little or no rotation of the control collar 42 as the guide finger 55 slides
within the second leg
250.
At the intermediate position shown in Figure SB, the protruding collar spacers
74 distally
49o extending from the distal end 43 of the control collar 42 engage the
second circumferential
shoulder 75 on the inside wall of the housing 12. The spacers 74 thereby limit
the movement of
17
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the control collar 42 and the rotatably attached positioning mandrel 40 from
actuating beyond the
intermediate position to displace the deployment mandrel 140.
When the pressure in the drillstring 30 is reduced to below the first
threshold pressure,
495 the positioning mandrel 40 reverses direction and moves in the direction
of the force applied by
the positioning mandrel spring 36. This reversal begins the first return
stroke of the control
collar 42. As the positioning mandrel spring 36 returns the positioning
mandrel 40 to or near its
inactive position, the guide finger 55 slides or rolls within the second leg
250 toward the
intersection of the first actuation groove 50 and the first leg 151 of the
first return groove 51.
50o The first leg 151 of the first return groove 51 is not aligned with the
axis 44 of the positioning
mandrel 40, and sliding or rolling contact between the fixed guide finger 55
in the first leg 151
causes the control collar 42 to further rotate about the axis 44. The rotation
of the control collar
42 during the first return stroke is in the same angular direction as the
rotation caused by the
guide finger 55 sliding or rolling within the first leg 150 during the first
actuation stroke. The
505 intersection of the first actuation groove 50 and the first leg 151 of the
first return groove 51
directs the guide finger 55 from the second leg 250 of the first actuation
groove into the first leg
151 of the first return groove 51. As the positioning mandrel 40 is displaced
by the force of the
positioning mandrel spring 36 toward its inactive position, the guide finger
55 slides or rolls
within the first leg 151 of the first return groove 51 towards the
intersection of the first return
51 o groove 51 and the first leg 152 of the second actuation groove 52. The
second leg 251 of the
first return groove 51 is generally aligned with the axis 44 of the
positioning mandrel, and as the
guide finger 55 moves from the first leg 151 to the second leg 251, there is
little or no rotation of
the control collar 42. As the positioning mandrel 40 returns to its inactive
position under the
force of the return spring 36, the guide finger 55 slides or rolls within the
second leg 251 of the
t 5 first return groove 51 to a point near the distal end 43 of the control
collar 42. As the positioning
mandrel 40 returns to or near its inactive position, the rotational moment
imparted to the control
collar 42 by interaction with the tracking guide finger 55 causes the control
collar 42 to rotate
into the position shown in Figure 5C. This inactive position occurs between
the intermediate
position and the deployed position, and the rotation of the control collar 42
has rotatably aligned
52o the spacers 74 to be received within the recesses 75 when the tool is next
actuated.
When the pressure in the drillstring 30 is again raised above the first
threshold pressure
necessary to overcome the positioning mandrel return spring 36, the
positioning mandrel 40 is
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19.0276
distally displaced to begin the second actuation stroke to deploy the
stabilizer 10. The second
actuation stroke begins as the axial movement of the control collar 42
reverses and the guide
525 finger 55 slides or rolls within the second leg 251 of the first return
groove 51 toward the
proximal end 41 of the control collar 42. The second leg 251 intersects the
first leg 152 of the
second actuation groove 52. The first leg 152 is not aligned with the axis 44
of the control collar
42, and as the guide finger 55 passes into the first leg 152 of the second
actuation groove 52, it
contacts and slides along the edge of the first leg 152 that is disposed
towards the proximal end
530 41 of the control collar 42. The first leg 152 is not aligned with the
axis of the positioning
mandrel 40, and as the guide finger 55 slides or rolls within the first leg
152, the control collar 42
rotates about its axis 44. The rotation of the control collar 42 during the
second actuation stroke
in the same angular direction as its previous rotation during the first
actuation stroke and the first
return stroke. The rotation of the control collar 42 as the guide finger 55
slides or rolls within the
535 first leg 152 causes the spacers 74 to become rotatively aligned with, and
received into, the
recesses 77 in the second circumferential shoulder 75 on the inside wall of
the housing 12. The
guide finger 55 enters the intersection of the first leg 152 and the second
leg 252 of the second
actuation groove 52 and the first leg 153 of the second return groove 53. The
motion of the
positioning mandrel 40 towards the distal end of the housing 12 causes the
guide finger 55 to
54o enter into the second leg 252 of the second actuation groove 52 of the
control collar 42. The
second leg 252 of the second actuation groove 52 is generally aligned with the
axis 44 of the
positioning mandrel 40, and there is little or no rotation of the control
collar 42 as the guide
finger 55 slides within the second leg 252 to the point near the proximal end
41 of the control
collar 42 shown in Figure 5D.
545 At the end of this second actuation stroke the spacers 74 extending from
the distal end 43
of the control collar 42 are received within the recesses 77 in the second
circumferential shoulder
75 of the housing 12. The alignment of the spacers 74 and the recesses 77
allow the control
collar 42 and the positioning mandrel 40 to actuate beyond the intermediate
position shown in
Figure 5B to the deployed position shown in Figure 5D. The position of the
control collar 42
55o and the positioning mandrel 40 shown in Figure 5D correspond to the
deployed position of the
stabilizer shown in Figure 7. As the spacers 74 are received into the recesses
77, the positioning
mandrel 40 engages and displaces the deployment mandrel 140 toward the distal
connection 24
to overcome the force of the deployment mandrel spring 136. As the positioning
mandrel 40
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displaces the deployment mandrel 140 of the housing 12, the beveled portion 46
of the
555 deployment mandrel 140 slidingly engages the contact surface 17 of each
stabilizer element 16 to
displace it radially outward to overcome the force of the stabilizer springs
18.
The positioning mandrel 40, the deployment mandrel 140 and the stabilizer
elements 16
all remain in their deployed positions shown in Figure 7 as drilling in the
deviated direction
progresses. The flow of pressurized drilling mud passes through the tubular
interior of the
56o positioning mandrel 40 and the deployment mandrel 140, and perhaps through
other longitudinal
passages within the housing 12, to the mud motor 90 and the drill bit 80.
When the pressure in the drillstring 30 is reduced below the second threshold
pressure,
this begins the second return stroke, the final stroke of the cycle. At the
onset of the second
return stroke, the positioning mandrel 40 again reverses direction and returns
to its original
565 inactive position shown in Figure 5A. The return of the positioning
mandrel 40 is initially under
the force of both the deployment mandrel spring 136 and the positioning
mandrel spring 36.
After the deployment mandrel 140 reaches it's inactive position, the force of
just the positioning
mandrel spring 36 further returns the positioning mandrel 40 to its original
inactive position
shown in Figure 5A.
5~o On the second return stroke, the guide finger 55 slides or rolls within
the second leg 252
of the second actuation groove 52 toward the distal end 43 of the control
collar 42 toward the
intersection of the second actuation groove 52 and the first leg 153 of the
second return groove
53. The guide finger 55 passes from the second leg 252 of the second actuation
groove 52 into
the first leg 153 of the second return groove 53. The first leg 153 is not
aligned with the axis 44
575 of the positioning mandrel 40, and as the control collar 42 and
positioning mandrel 40 are axially
displaced relative to the guide finger 55, the guide finger 55 slides or rolls
along the edge of the
first leg 153 disposed towards the distal end 43 of the control collar 42. As
the guide finger 55
slides or rolls within the first leg 153, the control collar 42 angularly
rotates in the same angular
direction as its previous rotations during the first actuation stroke, the
first return stroke and the
5go second actuation stroke. As the guide finger 55 passes through the
intersection of the second
return groove 53 and the first leg 150 of the first return groove 50, the
guide finger 55 enters the
second leg 253 of the second return stroke 53. The second leg 253 is generally
aligned with the
axis 44 of the positioning mandrel 40, and little or no rotation of the
control collar 42 as the
guide finger 55 slides or rolls within the second leg 253 to a point near the
distal end 43 of the
CA 02342594 2001-04-03
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585 control collar 42 shown in Figure SA. This completes the four cycles of
the control collar 42
selected for this embodiment.
The position of the deployment mandrel 140 controls the deployment of the
stabilizer 10.
The stabilizer 10 has a position indicator that provides a flow restriction
when the deployment
mandrel 140 is in its deployed position. The position of the deployment
mandrel 140 determines
59o the position of the stinger 63 attached to the distal end of the
deployment mandrel 140. The
stinger 63 is connected to the distal end of the deployment mandrel 140 using
a slotted disk 62.
The slotted disk 62 allows drilling mud flow from the interior of the
deployment mandrel 140
while providing structural support for the stinger 63, which is axially
aligned with the axis 26 of
the housing 12. When the deployment mandrel 140 is distally actuated by the
positioning
595 mandrel 40, the stinger 63 approaches a flow-restricting orifice 64. The
obstacle to flow
presented by the stinger 63 as it approaches the orifice 64 causes increased
backpressure in the
drillstring 30. The increased backpressure resulting from deployment of the
stabilizer is detected
at the surface and provides a reliable means of tracking the cycling of the
stabilizer. When the
positioning mandrel 40 is in its inactive position, the deployment mandrel 140
remains biased
60o towards the positioning mandrel 40 by the deployment mandrel spring 136.
The deployment
mandrel spring 136 contacts the deployment mandrel 140 at a third
circumferential shoulder 23.
The beveled portions 46 of the deployment mandrel 140 are located adjacent to
the contact
surface 17 on the radially inward side of the stabilizer elements 16.
While in the intermediate position shown in Figure 6, drilling mud flows
through the
605 annular pressure sensing surface 48, through the tubular interior of the
positioning mandrel 40,
through the interior of the deployment mandrel 140, through the slotted
support disk 62, out the
proximal end of the housing 12 through the distal connection 24 to the mud
motor 90 and drill bit
80 below. When the positioning mandrel 40 is moved from the position shown in
Figure SA to
the intermediate position shown in Figure SB, and then returned to the
inactive position shown in
61o Figure SC , the four stroke control collar 42 angularly rotates about one-
half of a revolution. As
further angular rotation of the control collar 42 occurs, the spacers 74
extending from the distal
end 43 of the control collar 42 are rotatively aligned with recesses 77 in the
second
circumferential shoulder 75 on the inside wall of the housing 12. The
alignment of these
recesses 77 allow the positioning mandrel 40, displaced by the drilling mud
pressure bearing on
615 the pressure sensing surface 48, to move beyond its intermediate position
to its deployed
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position. As shown in Figure 7, upon second actuation of the positioning
mandrel 40 from its
inactive position, the positioning mandrel 40 engages and displaces the
deployment mandrel 140
toward its deployed position. The beveled portions 46 of the deployment
mandrel 140 slidably
engage the contact surface 17 of the stabilizer elements 16. As the deployment
mandrel 140
62o approaches its farthest displacement toward the distal end of the housing
12, the beveled portions
46 displace the stabilizer elements 16 radially outward to their deployed
position.
Figures 8A through 8C show an enlarged view of the beveled portions 46 of the
deployment mandrel 140. Figure 8A shows the beveled portion 46 adjacent to,
but not engaging
or deploying, the stabilizer element 16. Figure 8B shows the beveled portion
46 engaging and
625 partially deploying the stabilizer element 16 radially outward through the
stabilizer port 14 and
against stabilizer element spring 18 that biases the stabilizer element 16
radially inwardly to its
retracted, inactive position. Figure 8C shows the stabilizer element 16 in its
fully deployed
position.
The deployment of the stabilizer elements 16 increases the effective diameter
or gauge of
63o the housing 12 to produce the desired angular deviation of the lower
portion of the BHA and the
drill bit 80 at the extreme end of the well.
As discussed above, Figure 4 shows a plan view of the four-stroke rotating
collar having
two actuation grooves, a first actuation groove 50 and a second actuation
groove 52, and two
return grooves, a first return groove 51 and a second return groove 53. This
configuration is
635 referred to as a four-stroke control collar 42 because of the total number
of interconnected
grooves being four. By its nature as a cylindrical shape, the outside surface
of the control collar
42 into which the grooves are machined provides 360 degrees of angular
rotation. Equal spacing
of the four distinct strokes provides about 90 degrees per stroke. For a four
stroke configuration
described above, it is preferable to angularly space the first actuation
groove and the first return
64o groove within about 180 degrees of the outside angular surface of the
collar and the second
actuation groove and the second return groove within the remaining 180
degrees. In a four
stroke configuration, the control collar 42 "toggles" the positioning mandrel
40 between the two
actuated positioning mandrel positions, the intermediate position shown in
Figure 6 and the
deployed position shown in Figure 7.
64s The stabilizer 10 may be modified to include a greater number of deployed
positions in
the cycle. For example, the control collar 42 could be modified to operate in
six cycles by
22
CA 02342594 2001-04-03
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including a third actuation groove immediately followed by a third rotation
groove angularly
inserted between the second return groove 53 and the first actuation groove
50. In this six cycle
configuration, each actuation groove and return groove pair will preferably
comprise
65o approximately 120 degrees of the outside angular surface of the control
collar 42 so that the
control collar 42 accommodates three actuated positioning mandrel positions
instead of only two.
The six-cycle collar would require a second set of spacers, corresponding to a
partially deployed
stabilizer position, extending from the distal end 43 of the control collar 42
and angularly spaced
from the first set of spacers 74 corresponding to the first deployed position.
The second set of
655 spacers may be longer or shorter than the first set of spacers 74 to make
the effective diameter of
the housing 12 corresponding to the partially deployed position different from
the effective
diameter of the housing 12 corresponding to the fully deployed position.
Conversely, a second
set of recesses of different depth than the first set of recesses 77 in the
second circumferential
shoulder 75 may receive a second set of spacers in order to make the
corresponding partially
66o deployed position impart a different diameter to the housing 12 than that
of the fully deployed
position. Additional deployment positions and stabilizer diameters can be
created by inclusion
of additional spacers, actuation grooves and return grooves in correspondingly
smaller angular
portions of the collar.
By further "compressing" the pairs of actuation grooves and return grooves
into angularly
665 smaller portions of the collar, the control collar can be modified to
provide more than one cycle
of the stabilizer per revolution of the collar. For example, an eight stroke
control collar wherein
each pair of actuation grooves and return grooves are disposed within 45
degrees of the angular
rotation of the collar may provide strokes 5 through 8 as a mirror image of
strokes 1 through 4.
That is, the control collar 42 may be designed such that the first actuation
stroke and the third
67o actuation stroke displace the positioning mandrel to identical
intermediate positions, and the
second actuation stroke and the fourth actuation stroke displace the
positioning mandrel 40 to
identical deployed positions. The design of the control collar 42, in other
words, the number of
deployed positions and the number of cycles per revolution, should take into
consideration
several factors affecting the operation of the rotating position control
collar 42. These factors
6'75 include, but are not limited to, the diameter of the control collar 42,
the thickness of the grooves,
the friction between the guide finger 55 and non-aligned portions of the
grooves and the overall
displacement of the reciprocation of the positioning mandrel 40 within the
housing 12 .
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The stabilizer 10 may also be integrated with other tools to provide
additional benefits for
improved drilling performance. For example, it is desirable to dispose
instruments for
68o monitoring and communicating weight-on-bit, azimuth, depth, inclination
and location as close
as possible to the drill bit 80. As the distance between the drill bit 80 and
data-gathering
instrumentation increases, the ability to monitor and correct the path of the
well to achieve the
targeted bottom-hole location is diminished.
Data gathered by downhole instrumentation are typically communicated to the
surface
685 using mud pulse telemetry systems. A mud pulse telemetry communication
system for
communicating data from downhole instruments to the surface has been developed
and has
gained widespread acceptance in the industry. Mud pulse telemetry systems have
no cables or
wires for carrying data to the surface, but instead use a series of pressure
pulses that are
transmitted to the surface through flowing, pressurized drilling fluid. One
such system is
69o described in U.S. Patent 4,120,097. Ideally, these instruments are
disposed at or immediately
adjacent to the drill bit 80. However, because mud telemetry systems require a
continuous,
uninterrupted column of drilling mud for communicating collected data to the
surface,
instruments are typically disposed above the mud motor 90, thereby undesirably
spacing the
instruments away from the drill bit 80. This problem can be solved by
disposing data-gathering
695 instrumentation (not shown) and a data transmitter (not shown) at or
immediately adjacent to the
drill bit 80 in a bit box (not shown) connected to the drill bit 80 and
communicating collected
data via the adjacent earth formation to a receiver (not shown) located above
the mud motor 90.
The receiver may then feed collected data to the mud telemetry system for
communication to the
surface. The receiver or the transmitter may be integrated with the variable
gauge stabilizer 10
'700 of the present invention to provide a tool that not only enables control
and adjustment of the path
of the well, but also provides more accurate data related to the bottom-hole
location of the well,
thereby enabling more accurate adjustment and improved acquisition of bottom-
hole target
locations.
The meaning of "groove", as that term is used herein, includes, but is not
limited to, a
705 groove, slot, ridge, key and other mechanical means of maintaining two
parts moving relative
one another in a fixed rotational, axial or aligned relationship. Further, the
meaning of
"mandrel", as that term is used herein, includes, but is not limited to,
mandrels, pistons, posts,
push rods, tubular shafts, discs and other mechanical devices designed for
reciprocating
24
CA 02342594 2001-04-03
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19.0276
movement within a defined space. The term "gauge" means diameter, thickness,
girth, breadth
7to and extension. The term "collar" means collars, rims, sleeves, caps and
other mechanical
devices rotating about an axis and axially fixed relative to the positioning
mandrel. "Slender"
means little width relative to length. An "appendage" is a part that is joined
or attached to a
principal object. The term "port" means a passageway, slot, hole, channel,
tunnel or opening.
The term "finger" means a protruding or recessed guide member that allows
rolling or sliding
715 engagement between the housing 12 and the control collar 43 that maintains
the housing 12 and
the control collar 42 within a desired orientation one to the other, and
includes a key and groove
and rolling ball and socket.
As mentioned above, near-bit data gathering instrumentation may be used to
verify a desired
setting of stabilizer 10, as well as other directional determining tools, and
to feed back D&I information
72o for selecting a proper drilling heading. An extended bit box of the near-
bit data communication aspect of
the present invention is shown in Fig. 11. This extended bit box 221 connects
the drill bit to drilling
motor 216 via drive shaft 215 which passes through bearing section 220. The
bit box contains
instrumentation 225 to take measurements during drilling of a borehole. The
instrumentation can be any
arrangement of instruments including accelerometers, magnetometers and
formation evaluation
725 instruments. The bit box also contains telemetry means 222 for
transmitting the collected data via the
earth formation to a receiver 223 in the MWD tool 218. Both transmitter 222
and receiver 223 are
protected by shields 226. Data is transmitted around the drilling motor 216 to
the receiver.
An extended sub embodiment of the invention is shown in Fig. 12. The extended
sub 224
connects to a standard bit box 219. The use of an extended sub does not
require modifications to the
73o currently used bit box 219 described in Fig. 10. The extended sub contains
the measurement
instrumentation 225 and a telemetry means 222. (For the purpose of this
description, the measurement
instrumentation 225 shall be referred to as an accelerometer 225a.) These
components and others are
arranged and operate in a similar manner to the extended bit box embodiment.
Fig. 13 is a cross-section view of the present invention modified from Fig.
10. The bit box 219
735 of Fig. 10 has been extended as shown to form extended bit box 221.
Transmitter 222 is now located in
the bit box. The bit box now has the capability of containing measurement
equipment not located in the
bit box in prior tools.
The extended bit box embodiment of the present invention is shown in more
detail in the cross-
section view of Fig. 14. An accelerometer 225a for measuring inclination is
located within a housing
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740 227 which is made of a light weight and durable metal. The housing is
attached to the inner wall of the
drive shaft 215 by a bolt 228 and a through hole bolt 229. A wire running
through the bolt 229
establishes electrical communication between the accelerometer 225a and
control circuitry in the
electronic boards 236. The housing containing the accelerometer is positioned
in the drive shaft channel
215a. Since drilling mud flows through the drive shaft channel, the housing
227 will be exposed to the
745 mud. This exposure could lead to the eventual erosion of the housing and
the possible exposure of the
accelerometer to the mud. Therefore, a flow diverter 230 is bolted to the
upper end of the accelerometer
housing 227 and diverts the flow of mud around the accelerometer housing. A
conical cap 231 is
attached to the housing, via threads in the housing, at the drill bit end of
the housing. This cap seals that
end of the housing to make the accelerometer fully enclosed and protected from
the borehole elements.
75o Contained in the accelerometer housing 227 is a filtering circuit 232 that
serves to filter detected data.
This filtering process is desirable to improve the quality of a signal to be
telemetered to a receiver in the
MWD tool. Annular batteries 233 are used to provide power to the accelerometer
225a, the filtering
circuit 232 and the electronic boards 236. A standard API joint 234 is used to
attach different drill bits
214 to the extended bit box. A pressure shield 235 encloses the various
components of the invention to
755 shield them from borehole pressures. This shield may also serve as a
stabilizer. Electronic boards 236,
located between the drive shaft 215 and the transmitter 222, control the
acquisition and transmission of
sensor measurements. These boards contain a microprocessor, an acquisition
system for accelerometer
data, a transmission powering system and a shock sensor. This electronic
circuitry is common in
downhole drilling and data acquisition equipment. In this embodiment of the
present invention, the
76o electronics are placed on three boards and recessed into the outer wall of
the drive shaft 215 so as to
maintain the strength and integrity of the shaft wall. Wires connect the
boards to enable communication
between boards.
A shock sensor 237, which can be an accelerometer, located adjacent to one of
the electronic
boards 236 provides information about the shock level during the drilling
process. The shock
765 measurement helps determine if drilling is occurring. Radial bearings 238
provide for the rotation of the
shaft 215 when powered by the drilling motor. A read-out port 239 is provided
to allow tool operators
to access the electronic boards 236.
As discussed previously, a transmitter 222 has an antenna that transmits
signals from the bit box
221 through the formation to a receiver located in or near the MWD tool in the
drill string. This
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transmitter 222 has a protective shield 226 covering it to protect it from the
borehole conditions. The
antenna and shield will be discussed below.
Fig. 15 gives a perspective view of the present invention and provides a
better view of some of
the components. As shown, a make-up tool 240 covers a portion of the bit box.
The ports 240a in the
drive shaft 215 serve to anchor the make-up tool 240 on the drive shaft. This
make-up tool is used when
775 connecting the drill bit 214 to the bit box. Also shown is the protective
shield 226 around the transmitter
222. The shield has slots 241 that are used to enable electro-magnetic
transmission of the signal.
Fig. 16 provides a cross-section view of the batteries and the sensing
instrumentation mounted
inside the drive shaft of the present invention. As shown, the measuring
instruments are located in the
channel 215a of the drive shaft 215. The annular batteries 233 surround the
drive shaft and supply
78o power to the accelerometer 225a. The housing 227 surrounds the
accelerometer. The housing is secured
to the drive shaft by a bolt 229. A connector 242 attaches the accelerometer
225a to the housing 227. A
fixture 243 holds the bolt 229. The pressure shield 235 surrounds the annular
batteries 233.
Fig. 17 shows a cross-section view of the transmitter 222 in an extended bit
box implementation.
A protective shield 226 encloses the antenna 222a. This shield has slots 241
that provide for the electro-
785 magnetic transmission of the signals. In this embodiment, the antenna 222a
is comprised of a pressure
tight spindle 244. Ferrite bars 245 are longitudinally embedded in this
spindle 244. Around the ferrite
bars is wiring in the form of a coil 247. The coil is wrapped by the VITON
rubber ring 246 for
protection against borehole fluids. An epoxy ring 248 is adjacent the coil and
ferrite bars. A slight void
249 exists between the shield 226 and the VITON rubber ring 246 to allow for
expansion of the ring 246
79o during operations. Inside the spindle 244 is the drive shaft 215. The
electronic boards 236 are located
between the spindle 244 and the drive shaft 215. Also shown is the channel
215a through which the
drilling mud flows to the drill bit.
In another embodiment of the invention, the instrumentation for measuring
drilling and drilling
tool parameters and formation characteristics is placed directly in the drill
bit. This instrumented drill
795 bit system is shown schematically in Fig. 18. The drill bit 214 contains
an extension 251 that connects
the drill bit to the bit box and drill string. As shown, the extension 251
comprises the upper portion of
the drill bit. The accelerometer 225a and the transmitter 222 are positioned
in the extension in a manner
similar to the extended bit box and extended sub embodiments. This
instrumented drill bit would fit into
a tool such as the one described in Fig. 9. The instrumented drill bit 214 is
connected to the bit box 219.
soo As with the other embodiments, the bit box 219 is attached to a drive
shaft 215 that is connected to the
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drilling motor 216 via the bearing section 220. Drilling fluid flows through
the drive shaft channel 215a
to the drill bit. A receiver 223 is located above the drilling motor and
usually in an MWD tool 218. It
should be mentioned that the drilling motor is not essential to the operation
of this embodiment.
As previously mentioned, the earth formation properties measured by the
instrumentation in the
go5 present invention preferably include natural radioactivity (particularly
gamma rays) and electrical
resistivity (conductivity) of the formations surrounding the borehole. As with
other formation
evaluation tools, the measurement instruments must be positioned in the bit
box in a manner to allow for
proper operation of the instruments and to provide reliable measurement data.
The preferred embodiment of the wireless telemetry aspect of the present
invention is illustrated
gto in Figs. 19 and 20. A bottom-hole assembly (BHA) 370 for drilling a
straight or directional borehole 309
in an earth formation 310 is suspended by means of a drill string 371 which is
supported at the earth's
surface by a drilling rig (not shown). The drilling rig provides power to
rotate the drill string 371 and
includes a mud pump to force pressurized drilling fluid downward through the
bore of the drillstring
371. The drilling fluid exits the BHA 370 through ports in the drill bit 372
and returns to the earth's
gts surface for reinjection by the mud pump. The BHA 370 typically comprises a
measurement while
drilling (MWD) tool 373 and a positive displacement drilling motor 374 which
drives a bit shaft 375.
The bit shaft 375 is supported by bearings 376 and includes at its downhole
end an extended bit box 377
into which drill bit 372 is threaded. Additionally, the drilling motor 374 may
incorporate a bent housing,
or a variable gauge stabilizer, as described above, to facilitate the
directional drilling of wells. It will be
82o understaood that the BHA 370 may comprise other components in addition to
those enumerated above,
such as, for example stabilizers and logging while drilling (LWD) tools.
Mounted within the extended bit box 377, which partially extends, at least in
one embodiment
(see Fig. 19), within a rotating near bit stabilizer sleeve 377a and a
transmitter/antenna sleeve 379, is an
instrumentation and electronics package 378 which is battery powered. The
instrumentation and
825 electronics package 378 contains instruments for making measurements
during drilling and may include
magnetometers for monitoring the direction of the borehole, accelerometers for
monitoring the
inclination of the borehole, and/or formation evaluation instruments. Mounted
on the extended bit box
377 (or sleeve 377a) is a transmitter coil 379 for transmitting telemetry
signals carrying encoded data
from the various measuring instruments through the earth formation 310 to a
receiver coil 380 mounted
83o in the MWD tool 373. It will be understood by those skilled in the art
that the transmitter coil 379 may
be mounted in a separate sub and that MWD tool 373 may be placed at various
locations within the
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BHA 370, such placement determining the depth to which the transmitted
telemetry signals penetrate the
earth formation 10 before being received. The transmitter coil 379 and
receiver coil 380 are protected
from damage by shields 381, and are each loaded with a ferrite core 382 to
increase the transmission
835 range of the system. The instrumentation and electronics package 378 also
carries the electronics
necessary to encode the data from the measuring instruments and actuate the
transmitter coil 379.
The invention uses the amplitude of the induction telemetry signal that
transmits logging
and drilling data obtained during the drilling of a borehole to verify the
setting of variable gauge
stabilizer 10, among other things such as determining earth formation
resistivity as described in
84o U.S. Application Serial No. 09/148,013, the entirre contents of which are
incorporated herein by
reference. The transmitter coil 379 induces a signal in earth formation 310
that corresponds to
the measured logging and drilling data, including inclination data from a
single-axis
accelerometer mounted to the drive shaft of the mud motor within extended bit
box 377 in a
preferred embodiment. The receiver coil 380 detects this signal and
electronics associated with
845 the receiver coil 380 recover the measured data for transmission to the
earth's surface by means
of a mud pulse telemetry system in the MWD tool 373 or in a separate sub. Such
a mud pulse
telemetry system is described in U.S. Patent 5,375,098, which is incorporated
herein by
reference. Before proceeding with the description of the invention, and to
assist in understanding
the invention, some basic concepts related to signal transmission are
reviewed.
g5o As shown in Fig. 21, signal transmission begins with the use of a
continuous oscillating
signal of arbitrary amplitude and frequency that carries no intelligence. This
continuous signal is
called a "carrier signal" or simply a "carrier". The carrier may be
interrupted or the signal
amplitude altered so it becomes similar to a series of pulses that correspond
to some known code
as shown in Fig. 22. At this point the oscillating interrupted signal can
carry some intelligence.
sss In the present case, the intelligence is the measurement data. There are
many ways to alter the
carrier signal. Modulation is the process of altering a carrier signal in
order to transmit
meaningful information. The type of modulation that is utilized in the present
invention is Pulse
Position Modulation (PPM). PPM uses a pulse time arrival position in a data
train to represent
quantitized values of data. The characteristics of pulses within a pulse train
may also be
86o modified to convey the information.
Focusing again on the present invention, Fig. 23 shows the sequence of
operations used
to determine borehole inclination. Data is gathered from accelerometer
measurements taken
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during a drilling operation. The first step 311 is to generate a signal
representative of the
measured parameters. This signal is in digital form and is a conversion of an
analog
865 measurement. To transmit this signal to the uphole receiver it is
necessary to encode the signal
(box 312). The encoding process produces a 27 bit word for transmission.
Fig. 24 illustrates a 27 bit word 322 that is ready for transmission to an
uphole receiver.
As shown, this word may comprise several fields containing various types of
data. In this
example, a 2 bit field 324 serves as a frame counter of the number of frames
transmitted uphole.
87o This field identifies each transmitted frame to permit better tracking of
the transmitted data.
Field 323 is a 2 bit field that serves as the frame type field and identifies
the type of
measurement data in the word. This data could be one of several measured
characteristics such
as temperature or bit inclination. Field 325 is an eleven bit field that
contains the actual
measurement data. For example, an inclination measurement of 238 mini-g, which
equals 76.2
875 degrees, would be 00011101110 in field 325. Field 326 has two bits and
indicates, for example,
the shock level at bit. In addition to the transmission of measurement data,
the bit stream may
contain error detection bits. These additional bits of the bit stream help
detect if an error
occurred during the transmission of the data stream and verifies that the data
sent was the data
received. Error detection schemes are commonly used in digital transmissions.
The particular
88o error detection scheme may vary from using only one bit to several bits
depending upon the
desired level of detection. The last field 327 in this word is a ten bit error
checking field that
assists in verifying accurate transmission of the data.
Referring again to Fig. 23, the next step 313 is to transmit the signal
uphole. This
transmission involves modulating the signal using PPM techniques. As will be
discussed in
885 detail below, the 27 bit word is transmitted uphole in a data frame.
Encoded pulses contain the
information of the 27 bit word. Each pulse contains a 10 kHz signal. The
position of each pulse
in the data frame represents a portion of the data in the 27 bit word.
Fig. 25 illustrates the format of the transmitted and detected data in a PPM
scheme. The
transmitter sends one data frame approximately every two minutes. The data
frame 328 consists
890 of eleven 10 kHz pulses. The data is encoded by using pulse position. The
first pulse 329 and
last pulse 330 are synchronization pulses that indicate the beginning and end
of the data frame
328. The remaining pulses occur in data regions 331a-331i. The data regions
are separated by
intervals 332 of two seconds in length as shown. Referring to Fig. 26, each
data region
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comprises multiple positions within the region in which a pulse 334 may occur.
Each data pulse
g95 position corresponds to one of eight symbols whose value corresponds to
the pulse delay
position. There are seven possible delay positions of 30 milliseconds or eight
possible pulse
positions I, II, III, IV, V, VI, VII, and VIII. In an example of the
transmission of the 27 bit word
of Fig. 24, each of the nine information pulses represents three bits of the
27 bit word. The data
frame 328 contains these nine pulses plus the two synchronization pulses 329
and 330. As
90o shown in Fig. 27a, if the first three digits of the 27 bit word are "101"
the first data region would
have a pulse 334 in the sixth position. A three digit sequence of "011" in
Fig. 27b would result
in a pulse 334 in the fourth data region. A sequence of "000" in Fig. 27c
would result in a pulse
334 in the first position of the data region.
Referring once again to Fig. 23, the modulated signal is received (box 314)
and
905 demodulated (box 315) to obtain the data contained in the signal. As part
of this demodulation
function, the carrier is extracted from the modulated signal. Fig. 28 shows a
schematic of the
demodulation and carrier extraction process. The signal sampled from the
analog-to-digital
(A/D) converter of the receiver electronics is first continuously multiplied
by a reference 10 kHz
cosine function and its quadrature sine function. Both results are then summed
over 10
91 o milliseconds, squared, and the results are added. The resulting square
root corresponds to a
phase insensitive cross correlation of the incoming signal with a 10
millisecond, 10 kHz
reference pulse. As shown in Fig. 23, after demodulation the next step 316 is
to detect a data
peak. A peak threshold applied to the cross correlated signal defines a peak
or pulse whose time
of occurrence and amplitude correspond to a maximum correlation amplitude.
915 Referring to Fig. 25, the transmitter sends data frame 328 to the
receiver. As previously
mentioned, each data frame includes a first pulse 329 and a last pulse 330
(synchronization
pulses) that indicate the beginning and the end of the data frame. In step
316, the receiver is
constantly in a search mode attempting to detect amplitude peaks. When the
receiver detects a
peak amplitude, the receiver begins a search for a valid data frame 328. The
search for a valid
92o data frame is necessary to determine if the detected peak amplitude was
data or random noise.
To search for a valid frame the receiver checks for the presence of
synchronization pulses. Since
a data frame has a duration of approximately 21 seconds, the receiver checks
the previous 21
seconds for synchronization pulses and valid time of arrival for all
intermediate data bearing
pulses.
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925 After the detection of a valid data frame, the next step 317 is to
reconstruct the 27 bit
word at the receiver. This step is a decoding of the pulses positioned in the
data frame.
Conventional burst mode (27, 17) error detection techniques are now used (box
318) to
determine the validity of the transmitted word. Once it has been determined
that the
transmission is valid, the data is extracted (box 319) from the 27 bit word.
In the interpretation
930 of the demodulated signal, the measurement data transmitted in the signal
is determined from the
positions of the pulses. After step 319, the focus of the procedure turns to
the process of
determining the formation resistivity. Step 320 measures the amplitude of the
carrier signal used
during the transmission of the data. Formation resistivity is determined (box
321) by comparison
of the amplitude of the received signal with that of the transmitted signal.
935 Fig. 29a illustrates the signal 338 as transmitted. Fig. 29b illustrates
the signal 339 as
received. As shown, the received signal 339 resembles the transmitted signal
338. However,
because the surrounding earth formation attenuates the carrier signal, the
received signal 339 has
a much smaller amplitude than the transmitted signal. The formation
resistivity, for example,
may be calculated from a resistivity transform that is dependent upon
transmitter to receiver
940 spacing in a homogeneous formation as shown in Fig. 31. Where the well
trajectory is at a
relatively low apparent dip angle within geometrically complicated formation
layers, the signal
amplitude and a forward modeling of the formation layers must be used to
estimate a resistivity
representation of the layers.
As previously stated, in order to increase the transmission range of the
signal and
945 therefore the depth of investigation of the resistivity measurement, both
the transmitter and
receiver are loaded with a ferrite core. Ferrite, or any material with high
longitudinal magnetic
permeability, has a focusing effect on the longitudinal magnetic field used by
the induction
transmission of the present invention. Fig. 30 shows a cross-sectional view of
the transmitter
340 of the present invention. A protective electromagnetic transparent shield
341 encloses the
95o antenna 342. This shield has slots 343 that provide for the electro-
magnetic transmission of the
signals. In this embodiment, the antenna 342 is comprised of a pressure tight
spindle 344.
Ferrite bars 345 are longitudinally embedded in the spindle 344. Around the
ferrite bars is
wiring in the form of a coil 346. An epoxy ring 348 is adjacent the coil and
ferrite bars. The coil
is sealed by a VITON rubber ring 347 for protection against borehole fluids. A
slight void 349
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955 exists between the shield 341 and the VITON rubber ring 347 to allow for
expansion of the ring
347 during operation.
The resistivity response or resistivity transform of the system of the present
invention is
shown in Fig. 31 for a signal amplitude measurement. Fig. 31 shows the signal
amplitude versus
formation resistivity for 25 foot (7.62 meter) and 40 foot (12.19 meter) 350
and 351,
96o respectively, transmitter to receiver spacings. As shown, the 40 foot
(12.19 meter) measurement
351 can discriminate resistivity over a larger signal amplitude range. In both
measurements, the
ability to measure resistivity based on signal amplitude is minimal above
approximately 20 ohm-
meters.
One method for extending the range of measurable formation resistivities above
20 ohm-
965 meters is to use the complex composition of the signal as in the standard
induction technique.
The resistivity measurement includes the real component 354 (VR) and the
imaginary component
353 (V,) of the signal as shown in Figs. 32a and 32b. As indicated in Figs.
32b and 32d, the real
component 354 has a greater sensitivity to formation resistivity than the
imaginary component
353 and can discriminate resistivity as a function of signal amplitude over a
greater range. Since
97o the present measurement is an amplitude measurement 352 (VA) represented
by the equation
vR + ~~z
and does not involve synchronizing of transmitted and received signals, a
determination of the
real part of the signals is not possible. However, in this asynchronous system
the range of
formation resistivity discrimination may be extended beyond 20 ohm-meters by
using a higher
975 frequency signal, such as 100 kHz, which moves the resistivity transforms
350 and 351 of Fig.
31 to the right towards higher resistivity (approximately 100 ohm-meters).
Additionally, the
resistivity of the formation at different depths of investigation may be
determined from a single
transmitted signal by transmitting the signal pulses at different frequencies,
each frequency
yielding a measurement at a different depth. In the present invention three
frequencies,
98o approximately 2, 10, and 100 kHz are preferred. However, frequencies in
the range from about 1
kHz to 300 kHz may be used.
Because of its large transmitter to receiver spacing, the present invention
provides a deep
depth of investigation of formation resistivity. This feature is particularly
useful in detecting
formation boundaries. Fig. 33 schematically illustrates a tool according to
the present invention
985 operating at 10 kHz approaching a resistivity contrast boundary 356 at an
apparent dip angle of
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90 degrees. Figs. 34a and 34b show the resistivity signal response as the tool
approaches and
crosses resistivity boundary 356 at an apparent dip angle of 90 degrees. As
shown in Fig. 34a, at
200 ohm-meters 357, there is no change in resistivity across the boundary 356,
and therefore no
change in the signal. At a contrast of 20 ohm-meters to 200 ohm-meters 358,
there is virtually
990 no change in the signal, mainly because of the limited ability to
distinguish resistivities above 20
ohm-meters when operating at 10 kHz. At a contrast of 2.0 ohm-meters to 200
ohm-meters 359,
there is a slight movement in the signal approximately ten feet (3 meters)
before the tool reaches
the boundary 356 and more movement after it crosses the boundary. At 0.2 ohm-
meters to 200
ohm-meters 360, the signal begins to change rapidly approximately five feet (
1.5 meters) before
995 the tool crosses the boundary 356. Fig. 34b shows that the responses are
the opposite when
moving from a high resistivity formation to a low resistivity formation. There
is a 10 to 15 foot
(3 - 4.5 meter) look ahead 361 when approaching the boundary 356 from a
resistive to a
conductive formation.
Fig. 35 schematically illustrates a tool according to the present invention
operating at 10
1000 kHz approaching a resistivity contrast boundary 356 at an apparent dip
angle of 0 degrees. Fig.
36a illustrates the resistivity signal response as the tool moves from a low
resistivity formation to
a high resistivity formation at an apparent dip angle of 0 degrees. There is
of course no change
in the 200 ohm-meter response 362 across the boundary. Again, the 20 ohm-meter
response 363
shows virtually no change across the boundary 356. The 2.0 ohm-meter response
364 begins to
t 005 respond at approximately 40 feet ( 12.2 meters) from the boundary. The
0.2 ohm-meter response
365 begins to show a drastic change at about 25 feet (7.6 meters) from the
boundary. The well
known horizontal or high angle horning effect when crossing a formation
boundary causes the
0.2 ohm-meter response to exceed the 200 ohm-meter level and then return to
the 200 ohm-meter
level. As shown in Fig. 36b, the tool response when moving from a high
resistivity formation to
t of o a low resistivity formation is essentially the opposite of that shown
in Fig. 36a.
The present invention therefore provides a formation resistivity measurement
with the
following characteristics: 1 ) deep resistivity radial depth of investigation
proportional to the
distance between the transmitter and receiver; 2) vertical resolution also
proportional to the
distance between the transmitter and receiver; 3) formation resistivity
sensitivity of up to
1 o t 5 approximately 20 ohm-meters when using the pulse amplitude resistivity
transform at 10 kHz
operating frequency, or sensitivity up to approximately 100 ohm-meters at 100
kHz operating
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frequency; 4) the capability to detect formation boundaries based on changes
in formation
resistivity; 5) look-ahead capability when the bit is crossing from a low
resistivity formation to a
high resistivity formation; and 6) look-around capability in wells drilled
approximately parallel
t 02o to formation boundaries of any significant resistivity contrast. This
application is significant for
landing wells and staying within a predefined formation layer during
directional drilling.
It now will be recognized that new and improved methods and apparatus have
been disclosed
which meet all the objectives and have all the features and advantages of the
present invention. Since
certain changes or modifications may be made in the disclosed embodiments
without departing from the
t o25 inventive concepts involved, it is the aim of the appended claims to
cover all such changes and
modifications falling within the true scope of the present invention.
