Note: Descriptions are shown in the official language in which they were submitted.
CA 02687739 2009-11-19
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A WIl2ED SNURT )E7.EAMER
STATEMENT REGARDING FEDERALLY SPONSORED
RESEARCH OR DEVELOPMENT 5 Not applicable.
BACKGROUND
In the drilling of oil and gas wells, it is frequently necessary or desirable
to "ream" a
borehole that has been previously created by a drill bit or other cutting tool
so as to ream out
ledges, remove sloughed areas and key seats, straighten the borehole,
stabilize the drill string,
and enlarge the borehole. For those reasons, a reamer may be positioned behind
a drill bit, or
other cutting structure, on the drilling assembly so as to ream the hole after
the bit has formed
the borehole. It is sometimes preferred that such a reaming step be performed
as the bit is being
withdrawn from the borehole, that process being referred to as "backreaming."
Also, it is
sometimes necessary to run a reamer on a subsequent trip to straighten or
clean up the borehole.
In casing drilling applications, the reamer is needed to drill the primary
hole before the casing
string.
When drilling oil and gas wells using a rotary steerable tools, it is
dcsirable to rean-i the
borehole as close to the bit as possible so as to minimize the distance
between the bit borehole
and the reamer borehole. Because rotary steerable tools commonly need to
communicate with
the measurement-while-drilling (MWD) system, it is important for all tools
located between the
rotary steerable tool and the MWD telemetry system to allow the transmission
of power and
communications through the tool.
There are three main categories of reamers. Fixed blade reamers, including
near bit
reamers, have fixed blades that do not move or expand. A fixed blade reamer
cuts a larger bore
because it has a larger outer diameter than the pilot bit. The fixed blade
reamer can be used to
enlarge a borehole by a relatively small amount. Since the reamer blade is
fixed, the borehole
opening is at the surface or adjacent a larger hole section. A fixed blade
reamer can be used to
ream out ledges, straighten boreholes, remove key seats and remove sloughed
areas. Roller
reamers have roller cutters that are mounted to a main body and caii be used
to enlarge the bore,
ream out ledges, straighten boreholes, remove key seats and sloughed areas, as
well as stabilize
a drilling string and reduce the overall torque of the drill string.
Extendable blade or expandable
reamers, including underreamers, have arms that may be extended on surface or
downhole to a
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predetermined diameter to cut a larger bore. An extendable blade reamer can be
used to enlarge
the bore by a substantial amount, ream out ledges, straighten boreholes, and
remove key seats
and sloughed areas.
Conventional underreamers are typically used in conjunction with a pilot drill
bit whieh
is positioned below or downstream of the underreamer. A underreamer can be
used to drill and
expand the borehole below a cased section or, as in casing drilling
applications, can be used to
drill the well bore from the surface or below a larger cased section. In
casing drilling
applications, a drilling assembly including at least a bit and reamer are used
to open the
borehole below the casing string. The casing string is used as a replacement
for the drill pipe,
transferring fluid and torque down to the drilling assembly. After the
borehole is completed, the
underreamer arms are retracted and the drilling assembly is recovered to
surface.
The underreamers usually have hinged arms with roller cones and PDC cutters
attached
thereto. The arms are actuated by mechanical or hydraulic forces acting on the
arms, causing i
the arms to pivot at an end opposite the cutting end of the arms and thereby
extend or retract.
These arms can be forced out against the formation by a piston or driving arm.
In conventional operations, the arms of the underreamer are retracted to allow
the tool to pass through a smaller
hole section or cased hole section. Once the tool has passed through the
smaller hole or cased
hole section, the underreamer arms are extended. The pilot bit drills the
borehole, while at the
same time, the underreamer enlarges the borehole formed by the bit. Typical
examples of these
types of underreazners are found in U.S. Patents 3,224,507, 3,425,500 and
4,055,226.
In casing drilling applications, the underreamer is opened on surface with a
casing
string connected behind the reamer. The casing string is used as a replacement
for conventional j
3
drill pipe. The underreamer needs to be able to close back to a size that will
allow the drilling
assembly to be removed from the well bore. The drilling assembly may need to
be removed if a
portion of the assembly fails or if the well bore is completed.
Conventional reamers have several disadvantages. If a reamer's cutting
structure
experiences wear, the hole geometry may not be opened to the desired size.
Also, the reamer's
cutting structure may not be selected correctly to properly stabilize a
drilling assembly.
Moreover, a conventional underreamer may fail to deploy fully or retract
fully. A conventional
underreamer typically has rotary cutter pocket recesses formed in the body for
storing the
retracted arms and roller cone cutters when the tool is in a closed state. The
pocket recesses
tend to fill with debris from the drilling operation, which hinders collapsing
of the arms. If the
arms do not fully collapse, the drill string may easily hang up in the
borehole when an attempt
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is made to remove the string from the borehole. In casing drilling
applications, if the reamer
artns do not collapse, the underreamer may hang up on the casing string.
The activation and deactivation method of the arms of an underreamers may also
create
drilling operational limitations. Some underreamers use a ball to assist with
the activation and
deactivation of the reamer arms. Although a ball drop can be used to lock the
reamer arm
position, the underreamer cannot be used below tools that have no throughbore
to permit
passage of the ball. In addition, there may be a limitation to the nunaber of
cycles that the
reamer arms can be activated and deactivated. Moreover, some underreamers are
designed to
automatically expand when drilling fluid is pumped through the drill string.
Underreamers that
actuate in response to flow alone are very sensitive to the flow. Thus, these
underreamers may
open and close every time the pumps are tumed on or off. The primary
operational limitation
may be the ability to maintain the full deployment of the reamer arms under
the required flow
rate needed for drilling. Many underreamers have limited or no indication
provided at the
surface that the underreamer is in the fu11y-expanded or collapsed position.
Thus, in some
applications, it may be desirable to control when the underreamer expands or
collapses
regardless of the flow, rather than rely on automatic expansion in response to
the drilling fluid.
It may also be desirable to vary the size of the hole being opened downhole
depending on the
well bore location.
Another method for enlarging a borehole below a previously cased borehole
section
includes using a winged reamer behind a conventional drill bit. In such an
assembly, a
conventional pilot drill bit is disposed at the lowermost end of the drilling
assembly with a
winged reamer disposed at some distance behind the drill bit_ The winged
reamer generally
comprises a tubular body with one or more longitudinally extending "wings" or
blades
projecting radially outwardly from the tubular body. Once the winged reamer
has passed
through any cased portions of the wellbore, the pilot bit rotates about the
centerline of the
drllling axis to drill a lower borehole on center in the desired trajectory of
the well path, while
the eccentric winged reamer follows the pilot bit and engages the formation to
enlarge the pilot
borehole to the desired diameter.
Yet another method for enlarging a borehole below a previously cased borehole
section
includes using a bi-center bit, which is a one-piece drilling structure that
provides a
combination underreamer and pilot bit. The pilot bit is disposed on the
lowermost end of the
drilling assembly, and the eccentric underreamer bit is disposed slightly
above the pilot bit.
Once the bi-center bit has passed through any cased portions of the wellbore,
the pilot bit
rotates about the centerline of the drilling axis and drills a pilot borehole
on center in the
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the eccentric underreamer bit follows the pilot bit and
engages the formation to enlarge the pilot borehole to the desired diameter.
The diameter of the
pilot bit is made as large as possible for stability while still being capable
of passing through
the cased borehole. Examples of bi-center bits may be found in U.S. Patents
6,039,131 and
6,269,893.
As described above, winged reamers and bi-center bits include underreamer
portions
that are eccentric. A number of disadvantages are associated with this design.
Due to
directional tendency problems, the eccentric underreamer portions have
difficulty reliably
underreaming the borehole to the desired diameter. The bore geometry has a
large amount of
spiralization which increases the borehole torque and axial friction. With
respect to a bi-center
{
bit, the eccentric underreamer bit tends to cause the pilot bit. to wobble and
undesirably deviate
off center, thereby pushing the pilot bit away from the preferred trajectory
of drilling the well
path. A similar problem is experienced with respect to wiaiged realners, which
only underream
the borehole to the desired diameter if the pilot bit remains centralized in
the borehole during
drilling.
In the oil and gas industry, it is desirable to detect and control the
operational forces that {
act on a tool in order to determine whether a tool has sustained damaged, to
limit the damage
that the tool may experiencc, and/or to ensure that a particular operation is
performed correctly.
Sensors to detect vibration, axial forces, torsional forces, and bending
forces, and to transnut
that data real-time to the surface, can be used to identify when a drilling
tool is experiencing
forces that exceed its operational parameters. Drilling operations may then be
modified to
prevent or limit damage to the tool and/or to correct an ongoing operation.
To optimize the drilling operation and/or wellbore placement, it is desirable
to be
provided with information concerning the operational parameters of the drill
string and the
environmental conditions of the surrounding formation being drilled. For
example, it is often
necessary to frequently adjust the direction of the borehole while drilling,
either to
accommodate a planned change in direction, or to compensate for unintended and
unwanted
deflection of the borehole. In addition, it is desirable that the information
concerning tool
operation, the drilling environment, and formation type or characteristics be
provided to the
operator on a real time basis. The ability to obtain real time data
measurements while drilling
permits a relatively more economical and more efficient drilling operation.
Therefore, it is
important that any tool located between the MWD or LWD sensors and the MWD
telemetry
system allow the transmission of power and/or communications through the tool.
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To obtain real time data while drilling, a collection of drilling tools and
measurement
devices commonly known as the bottom hole assembly (BHA) are positioned at the
downhole
end of the drill string. Typically, the BHA includes the drill bit, any
directional or formation
evaluation tools, deviated driIling mechanisms, mud motors, and weighted
collars that are used
in the drilling operation. A measurement while drilling (MWD) or logging while
drilling
(LWD) collar is often positioned just above the drill bit to take measurements
relating to the
borehole direction or formation properties of the borehole as it is being
drilled. Measurements
recorded from MWD and LWD systems may be transmitted to the surface in real-
time using a
variety of methods known to those skilled in the art. Once received, these
measurements will
enable those at the surface to make decisions concerning the drilling
operation. Due to the
limitations in transmitting information, it is common for the more detailed
information or the
tool reliability information to be stored for download when the tool is
recovered on the surface.
Accordingly, various systems have been developed that permit downhole sensors
to
measure real time drilling parameters and to transmit the resulting
information or data to the
surface substantially instantaneously with the measurements. For example, mud
pulse telemetry
systems transmit signals from an associated downhole sensor to the surface
through the drilling
mud in the drill string. As another example, drill pipe with built-in
telemetry, or hard wired
pipe, transmits signals from the downhole sensor to the surface through wiring
contained within
the drill pipe wall. These telemetry systems and associated sensors may be
located a significant
distance from the drilling bit. The environmental information measured by the
system may not
necessarily correlate with the actual conditions surrounding the drill bit.
Rather, the system is
responding to conditions that are substantially spaced fronl the drilling bit.
For instance, a
conventional telemetry system may have a depth lag of up to or greater than 60
feet. As a result
of this information delay, it is possible to drill out a hydrocarbon producing
formation before
detecting the exit, resulting in the need to drill several feet of borehole to
get back into the pay
zone. In response to this undesirable information delay or depth lag, various
near bit sensor
systems or packages have been developed which are designed to be placed
adjacent or near the
drilling bit. However, such near bit sensors continue to be located a spaced
distance from the
drill bit assembly that still introduces a lag in determining formation
changes.
In order to use a near bit sensor system and permit real time monitoring and
adjustment
of drilling parameters, a system or method must be provided for transmitting
the measured data
or sensed information from the downhole sensor either directly to the surface
or to a further
telemetry system for subsequent transmission to the surface. Similarly, a
system or method may
need to be provided for transmitting the required electrical power to the
downhole sensor
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system from the surface or some other power source. As a result, all of the
tools in the
directional BHA need the ability to transfer power and communications through
their body, or
the tools need to be located above the telemetry system. Conventional reamers
available today
do not have the ability to transivit power and communications tl-rough their
body, and as a
result, the placement of the underreamers has been a significant distance from
the bit. In casing
drilling applications, this means that the directional BHA below the casing
string is very long
and prone to operational issues, such as debris buildup and vibration.
Various systems have been developed for communicating or transmitting the
information directly to the surface, for example, through an electrical line,
wireline or cable to
the surface. These hard-wire connectors provide a hard-wire connection from
near the drilling
bit to the surface; however, a wireline or cable must be installed in or
otherwise attached or
connected to the drill string. This wireline or cable is subject to wear and
tear during use and
thus may be prone to damage or even destruction during normal drilling
operations. The
drilling assembly may not be particularly suited to accommodate such
wirelines, with the result
that the wireline sensors may not be able to be located in close proximity to
the drilling bit.
Wirelines and wireline connectors by their very nature create blockages in the
drillpipe, thus
precluding some types of reamer activation mechanisms.
Systems have also been developed for the transmission of acoustic or seismic
signals or
waves through the drill string or surrounding forniation. The acoustic or
seismic signals are
generated by a downhole acoustic or seismic generator. However, a relatively
large amount of
power is typically required downhole in order to generate a sufficient signal
such that it is
detectable at the surface. A relatively large power source must be provided
downhole or
repeaters used at intervals along the string to boost the sigual as it
propagates along the drill
string.
Further, systems have been developed which require the transmission of
electromagnetic signals through the surrounding formation. Electromagnetic
transmission of
the sensed information often involves the use of a toroid positioned adjacent
the drilling bit for
generation of an electromagnetic wave through the formafion. As with acoustic
and seismic
signal transmission, the transmission of electromagnetic signals through the
formation typically
requires a relatively large amount of power, particularly where the
electromagnetic signal must
be detectable at the surface. Further, attenuation of the electromagnetic
signals as they are
propagated through the formation is increased with an increase in the distance
over which the
signals must be transmitted.
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I-Iardwired drillpipe has also been developed which allows significant amounts
of data
to be transferred from downhole to the surface. These systems require that the
hardwire be run
the length of the drillstring and communicate with the drilling BHA.
Communications across
connections can be problematic, and given the large number of connections in a
typical drill
string, these systems can be prone to reliability and maintenance issues.
BRIEF DESCRIPTION OF THE DRAWINGS
For a detailed description of the preferred embodiments of the invention,
reference
will now be made to the accompanying drawings in which:
FIG. 1 is a representative schematic of a wired reamer with power and/or
communications wiring through the reamer flowbore in accordance with the
present
invention;
FIG. 2 shows the wii=ed reanier of FIG. 1 with the power and/or communications
wiring through the reamer body;
FIG. 3 is a representative schematic of a wired, adjustable blade reamer with
power
and/or comrnunications wiring through the reamer flowbore in accordance with
the present
invention;
FIG. 4 shows the wired reamer of FIG. 3 with the power and/or
coxxi.rnunications
wiring through the reamer body;
FIG. 5 shows the wired reamer of FIG. 1 with the power and/or communications
wiring to the reamer flowbore;
FIG. 6 shows the wired reamer of FIG. 2 with the power and/or communications
wiring to the reamer body;
FIG. 7 shows the wired reamer of FIG. 1 with the power and/or communications
wiring contained within the reamer flowbore;
FIG. 8 shows the wired reamer of FIG. 2 with the power and/or communications
wiring contained within the reamer body;
FIG. 9 shows the wired reamer of FIG. I with sensors;
FIG. 10 shows the wired reamer of FIG. 2 with sensors;
FIG. 11 shows the wired reamer of FIG. 3 with sensors;
FIG. 12 shows the wired reamer of FIG. 4 with sensors;
FIG. 13 shows the wired reamer of FIG. 1 with wireless sensors;
FIG. 14 shows the wired reamer of FIG. 2 with wireless sensors;
FIG. 15 shows the wired reamer with sensors of FIG. 9 with aecess to a
processor;
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FIG. 16 shows the wired reamer with sensors of FIG. 5 with sensors and access
to a
processor;
FIG. 17 shows the wired reamer of FIG. 7 with sensors and a processor;
FIG. 18 shows the wired reamer of FIG. 1 with controllers and actuators;
FIG. 19 shows the wired reamer of FIG. 2 with controller and actuators;
FIG. 20 shows the smart reamer of FIG. 15 with controllers and actuators;
FIG. 21 shows the smart reamer of FIG. 16 with controller and actuators;
FIG. 22 shows the smart reamer of FIG. 20 with controllers and actuators; and
FIG. 23 shows the smart reamer of FIG. 21 with controller and actuators.
DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS The following discussion is
directed to various embodiments of the invention.
Although one or more of these embodiments may be preferred, the embodiments
disclosed
should not be interpreted, or otherwise used, as limiting the scope of the
disclosure, including
the claims. In addition, one skilled in the art will understand that the
following description has
broad application, and the discussion of any embodiment is meant only to be
exemplary of that
embodiment, and not intended to intimate that the scope of the disclosure,
including the claims, is limited to that embod'unent.
Certain terms are used throughout the following description and claims to
refer to
particular features or components. As one skilled in the art will appreciate,
different persons
may refer to the same feature or component by different names. This document
does not intend
to distinguish between components or features that differ in name but not
function. The
drawing FIGS. are not necessarily to scale. Certain features and components
herein may be
shown exaggerated in scale or in somewhat schematic form and some details of
conventional
elements may not be shown in interest of clarity and conciseness.
In the following discussion and in the claims, the terms "including" and
"conaprising" are used in an open-ended fashion, and thus should be
interpreted to mean
"including, ~,
but not limited to... ." Also, the term "couple" or "couples" intended to mean
either an indirect or direct connection. Thus, if a first device couples to a
second device, that
connection may be through a direct com-zection, or through an indirect
connection via other
devices and connections.
A wired reamer permits power and./or communications through the reamer to
other
downhole tools, to equipment on the surface, or to the reamer itself. The
ability to pass power
and/or communications through the reamer overcomes some limitations regardi.ng
where the
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reamer may be placed in a drilling BRA. Furthermore, positioning sensors on
the reamer
permits the collection of data relating to the tool operation, borehole
geometry, drilling
environment, and evaluation of the surrounding formations being drilled. The
data may be
transmitted to the surface or other telemetry tool using the through-tool
communications and
used to optimize the drilling operation, or stored inside the tool for later
download. Moreover,
data measured by the sensors may be transmitted to a processor located at the
surface, on
another downhole tool, or on the reamer itself. In such configurations, the
reamer is "smaat",
meaning the reamer communicates with a processor for deciphering data
collected by the
sensors.
Furthermore, locating controllers and actuators on the reamer permits cont.rol
of the
reamer during drilling operations through direct command or feedback from
algorithms
developed as a function of the data measured by the sensors. Direct commands
or feedback
may be transmitted using the through-tool communications to the controllers,
directing the
controllers to actuate the actuators, as needed to optimize the drilling
operation. For example,
controllers on the reamer may extend or retract the reamer arms, or otherwise
reconfigure the
reamer to limit forces experienced by the reamer.
Monitoring the performance of the reamer may help to determine when the reamer
experiences a physical failure, such as excessive cutting structure wear,
failed roller bearings,
broken reamer arms, or when the reamer arms are not fully extended or
retracted. Monitoring of
the performance of the drilling parameters may help to determine whether the
weight on the
reamer arms is too high or too low, the vibration of the reamer is in an
unacceptable range, or
the torque through the reamer arms is in an unacceptable range.
The wired reamer may be located between a measurement while drilling (MWD)
telemetry system and an instrumented bit, rotary steerable, or logging while
drilling (LWD)
sensor. In rotary steerable drilling bottom hole assemblies (BHAs), a wired
reamer may allow
the reamer to be located closer to the bit, reducing the rat hole created. In
casing drilling
applications, a wired reamer may allow a shorter stick out of the straight or
directional BHA..
In some embodiments of a wired reamer, power and/or communications are
provided
through the bore of the reamer or the body of the reamer to the tools located
downhole of the
reamer or to the reamer itself The communication path may be through the
reamer bore or
embedded in the rewTier body. Also, the short hop power and/or communication
path may be a
conductive wire, conductive rod, fiber optic line, sonic or acoustic path,
vibration path,
electromagnetic (EM) signal, or wireless transmission. In the case of a
conductive wire or rod,
the conductor may be insulated from the reamer housing.
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FIG. 1 is a schematic of a representative embodiment of a wired reamer that
permits
power and/or communications through the reamer. Wired reamer 100 comprises a
body 105
with a flowbore 110 therethrough and a cutting structure 113 along the outer
surface of the
body 105. A feedthrough assembly 115 extends through the flowbore 110. The
feedthrough
assembly 115 further comprises a protected pathway 120 surrounding at least a
portion of the
power and/or communications wiring 125. The wiring 125 permits power and/or
communications to and/or from other tools positioned uphole or downhole of the
reamer 100.
In this representative embodiment, the pathway 120 for the power and/or
communications wiring 125 extends through the flowbore 110 of the wired reamer
100. In
other embodiments, the pathway 120 for the wiring 125 may extend through the
reamer body
105, rather than the flowbore 110. FIG. 2 shows the wired reamer 100, depicted
in FIG. 1,
with the pathway 120 for the power and/or communications wiring 125 extending
through the
body 105 of the reamer 100. Because the pathway 120 is located within the body
105, there is
no need for a feedthrough assembly to house and protect the wiring 125, as
depicted in FIG. 1.
Moreover, the representative embodiment depicted in FIG. I is a fixed blade
reamer. In
other embodiments, the reamer 100 may be another type of reamer, including an
adjustable
blade reamer. FIG. 3 is a schematic of a representative embodiment of a wired,
adjustable blade
reamer. Thus, the reamer 100 further comprises arms 130 that may retract and
extend. As
shown, the arms 130 open from the right, wliicli corresponds to the downhole
end of the reamer
100. Alternatively, the arms 130 may open from the left, or the uphole end of
the reamer 100,
or bow out from the center of the reamer 100. The arms 130 further comprise
cutting structures
113. Although depicted in FIG. 3 as positioned on the arms 130, the cutting
structures 113 may
alternatively, or additionally, be positioned on the reamer body 105 uphole or
downhole of the
arms 130.
As described above, the pathway 120 for the wiring 125 may extend through the
reamer
body 105, rather than through the flowbore 110. FIG. 4 shows the reamer 100,
depicted in FIG.
3, with the pathway 120 for power and/or communications wiring 125 extending
through the
body 105 of the reamer 100. Because the pathway 120 is located within the body
105, there is
no need for a feedthrough assembly to house and protect the wiring 125, as
depicted in FIG. 3.
Power and/or commuizications need not be contiguous through a reamer, as they
are
depicted in FIGS. 1 through 4. Instead, power or coinmunications may be
provided through the
reamer. Also, power and/or communications need not pass through the reamer,
but instead may
only be provided to the reamer. FIG. 5 shows the wired reamer 100, depicted in
FIG. 1, with
the pathway 120 for the power and/or communications wiring 125 extending to,
but not
CA 02687739 2009-11-19
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through, the flowbore I 10 of the reamer 100. Similarly, FIG. 6 shows the
wired reamer 100,
depicted in FIG. 2, with the pathway 120 for the power and/or communications
wiring 125
extending to, but not thxough, the body 105 of the reamer 100. Moreover, power
and/or
communications need not pass through or to the reamer, but instead may be
contained entirely
within the reamer. FIG. 7 shows the wired reamer 100, depicted in FIG. 1, with
the pathway
120 for the power and/or communications wiring 125 contained within the
flowbore 110 of the
reamer 100. Similarly, FIG. 8 shows the wired reamer 100, depicted in FIG. 2,
with the
pathway 120 for the power and/or communications wi.ring 125 contained within
the body 105
of the reamer 100.
To optimize a drilling operation and/or formation evaluation, it is desirable
to be
provided with information relating to the operational parameters of the reamer
as well as
formation data from the surrounding formation being drilled. Therefore, in
some embodiments,
the instrwnented, wired reamer is fitted with sensors to collect such
information. These
embodiments may be applicable to all three types of reamers, fixed blade,
adjustable, and
expandable. Power for operation of the sensors may be provided by a power
source connected
to the reamer, such as a downhole power gencrator or battery pack, or from the
surface via
wireline or hard wired tubulars. Alternatively, the power source may be
located on the wired
reamer itself.
Sensors may be positioned within the reamer as well as on its outer surface,
including
the arms. For instance, some sensors measuring formation data, are optimized
by contact of the
wellbore wall, where as other sensors work best centralized in the borehole.
Sensors may be
positioned on the reamer outer surface below or above the reamer arms and/or
on the reamer
arms. Other sensors can be used to monitor drilling or environmental data. For
instance, to
monitor the gauge and the potential smoothness of the borehole, sensors,
specifically hole
calipers, can be positioned above the arms, in the arms, or below the arms.
The hole caliper
sensors may be simple mechanical sensors such as a spring sensor, or more
complex acoustic
calipers which depend on pulse-echo, pitch/catch, or other data acquisition
techniques. In
measuring the caliper, mechanical sensors are best situated in the arms while
acoustic sensors
are best positioned in the body of the reamer. Sensors may be positioned on
the reamer to
monitor and report other information, such as the positioning, e.g. open,
closed, and partially
open, of the reamer arms and forces that act on the tool, such as vibration,
weight on the reamer
arms, torque on the reamer arms, rpm of the tool, temperature, pressure and/or
stress/strain
across the tool.
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Certain types of formation evaluation sensors may be better suited to
placement on the
body of the reamer versus the reamer arms. For instance, certain resistivity
sensors are better
suited being placed on the arms of the reamer versus the body of the reamer
whereas other
types of resistivity devices work best centered in the boreliole and thus on
the reamer body.
This is not to say, however, that these sensors will only work in these
locations. Other
formation evaluation sensors that may be positioned in the reamer include
nuclear porosity,
sonic, magnetic imaging and formation testing type sensors.
Information collected from the sensors may be stored in a memory chip located
in the
reamer. The information may be retrieved using an extemal port or wireless
communication at
the surface when the reamer is removed from downhole to the surface.
Additionally or
alternatively, the information collected may be transmitted using the through-
tool
communications to another storage device, whether located on another downhole
tool or at the
surface. Intertool communications are done either electrically through a
hardwire connection or
via other communications techniques such as short hop EM or acoustic
transmission.
Transmitting the information to the surface may be done real time using
various
communications techniques such as a mud pulse telemetry, acoustic telemetry,
electro-
magnetic induction, wireline, fiber optics, or hard wired tubulars.
FIG. 9 shows the wired reamer 100 of FIG. 1 with sensors for data collection.
Wired
reamer 100 further comprises sensors 1401ocated along the reamer 100. As
shown, the sensors
140 are positioned on the outer surface of reamer 100, uphole of the cutting
structure 113,
downhole of the cutting structure 113, and on the cutting structure 113. The
wired reamer 100
fu.rther comprises a cross-over 145, which permits data collected by sensors
140 to be
communieated to the power and/or communieations wiring 125, which, in this
embodiment,
extends through the feedthrough assembly 115 inserted through in the reamer
flowbore 110.
Similarly, FIG. 10 shows the wired reamer 100 of FIG. 2 with sensors for data
collection. In this embodiment, the patlzway 120 for the power and/or
communications wiring
125 passes through the reamer body 105. Because the wiring 125 passes through
the reamer
body 105, rather than the reamer flowbore 110, a cross-over between the
sensors 140 and the
wiring 125 is not necessary.
FIG. 9 and FIG. 10 depict fixed blade reamers. As discussed above, the reamer
may be
another type of reainer, including an adjustable blade reamer. Moreover, a
wired, adjustable
blade reamer, such as those depicted in FIG. 3 and FIG. 4, may be configured
with sensors for
data collection. FIG. 11 and FIG. 12 depict the wired, adjustable blade reamer
100 of FIG. 3
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and FIG. 4, respectively, with sensors 140 positioned on the reamer 100 and,
in the case of FIG.
11, the cross-over 145 coupled to the sensors 140 and the wiring 125.
The embodiments exemplified by FIG. 9 and FIG. 11 comprise a hard-wired
connection, namely the cross-over 145, between the sensors 140 and the power
and/or
cornmunications wiring 125. In other embodiments, this connection may be
wireless, instead of
hard-wired. For example, FIG. 13 shows the wired reamer 100 with sensors 140,
depicted in
FIG. 9, with a wireless connection 150, in place of the cross-over 145,
between the sensors 140 and the wiring 125. The wireless connection 150
fixrther comprises a source 155 and a receiver
160 for transmitting and receiving, respectively, data collected by the
sensors 140 from the
sensors 140 to the wiring 125.
Simzlarly, the hard-wired connectiozl between the sensor(s) 140 located on the
cutting
structure 113 and the power and/or communications wiring 125 extending through
the reamer
body 105 of the embodiments exemplified by FIG. 10 and FIG. 12 may be replaced
by a
wireless connection. For example, FIG. 14 shows the wired reamer 100 with
sensors 140,
depicted in FIG. 10, with a wireless connection 150, in place of a hard-wired
connection,
between the sensor(s) 140 located on the cutting structure 113 and the wiring
125. As
previously described, the wireless connection 150 further comprises the source
155 and the
receiver 160 for transmitting and receiving, respectively, data collected by
the sensors 140 from
the sensors 140 to the wiring 125.
Power and/or communications need not be contiguous through a reamer, as they
are
depicted in FIGS. 9 through 14. Instead, power or communications may be
provided through
the reamer. Also, power and/or communications need not pass through the
reamer, but instead
may only be provided to the reamer, as depicted in FIG. 5 and FIG. 6.
Moreover, power and/or
communications need not pass through or to the reamer, but instead may be
contained entirely
within the reamer, as shown in FIG. 7 and FIG. 8.
A processor may be used to collect, process, analyze and store information
measured by
downhole sensors. Therefore, in some embodiments, the wired reamer with
sensors is provided
with access to a processor via its through-tool communications. In such
embodiments, the
reamer is referred to as "smart". The processor may be positioned on the
surface, located on
another downhole tool, or in the smart reamer itseIf.
Data collected by the sensors located on the smart reamer is transmitted to
the processor
via the through-tool communications. Data collected by sensors located on
other downhole
tools may also be transmitted to the processor via the through-tool
communications of the
reamer. Altematively, information collected from the sensors, including those
located on the
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37
reamer and other downhole tools, may be stored in a memory chip located in the
reamer. The
information may be retrieved from this memory chip using an external port or
wireless
communication at the surface or when the reamer is removed from downhole to
the surface.
Additionally or alternatively, the hi.formation collected may be transmitted
using the thru-tool
communications to another storage device, whether located on the surface or on
another
downhole tool. Inter-tool communications may be accomplished either
electrically through a
hardwire connection or via other communications techniques, such as short hop
EM or acoustic
tcansmission. Transmitting the information to the surface may be done real-
time using various
communications techniques, such as mud pulse telemetry, acoustic telemetry,
electro-magnetic
induction, wireline, fiber optics, or hard-wired tubulars. However the data
may be retrieved
from the sensors, the data is ultimately transferred to the processor for
processing and analysis.
FIG. 15 shows the wired reamer with sensors of FIG. 9 with access to a
processor via
the through-tool communications of the reamer. As previously described, wired
reamer 100
comprises the flowbore 110 therethrough, the cutting structure 113 along the
outer surface of
the body 105, and the sensors 140 also positioned along the reamer 100. The
feedthrough
assembly 115 extends through the flowbore 110. The feedthrough assembly 115
further
comprises the pathway 120 surrounding at least a portion of the power andlor
communications
wiring 125. The wiring 125 permits power and/or communications to and/or from
other tools
positioned uphole or downhole of the reanier 100, including a processor 165.
The processor
165 may be located at the surface or on another downhole tool. Data collected
by sensors 140
on the reamer 100 and sensors located on other downhole tools with
connectivity to the power
andlor communications wiring 125 of the reamer 100 is transmitted to the
processor 165 via the
power and/or communications wiring 125.
FIG. 16 shows the wired reamer of FIG. 7 with sensors and access to a
processor via the
through-tool comniunications of the reamer. The sole distinction between FIG.
15 and FIG. 16
relates to the power and/or comrnunications wiring 125 of the reamer 100. In
FIG. 15, the
wiring 125 extends through the reamer 100, whereas in FIG. 16, the wiring 125
extends to, but
not through, the reamer 100. In contrast to both FIG. 15 and FIG. 16, FIG. 17
shows the wired
reamer of FIG. 5 with sensors and a processor. The embodiments exemplified by
FIG. 17
comprise the power and/or communications wiring 125 contained within the
reamer 100, rather
than extending through or to the reamer 100. Thus, in the embodiments
exemplified by FIG.
17, the processor 165 is necessarily located within the reamer 100.
As with previously described embodiments, power and/or communications need not
be
contiguous through the smart reamer, as they are depicted in FIG. 15. Instead,
power or
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communications may be provided through the smart reamer. Also, power and/or
communications need not pass through the smart reamer, but instead may only be
provided to
the reamer, as depicted in FIG. 16. Moreover, power and/or communications need
not pass
through or to the smart reamer, but instead may be contained entirely within
the reamer, as
depicted in FIG. 17. Also, as with previously described embodiments, the smart
reamer may be
a fixed blade reamer, as illustrated in FIGS. 15 through 17, an adjustable
blade reamer, or
another type of reamer. ln embodiments of the smart reamer having
communications through or
to the reamer, the processor may be located at the surface, on another
downhole tool, or on the
reamer itself. In embodiments of the smart reamer having communications
contained within the
reamer, the processor is necessarily located on the reamer itself.
To optimize a drilling operation and/or wellbore placement, it is desirable to
control the
operation of the reaaner. Therefore, in some embodiments of the wired reamer,
controllers and
actuators are positioned in the reamer. The controllers and actuators may be
electrical,
hydraulic, mechanical, or other suitable type known in the industry. A signal
may be sent to a
controller, causing the controller to actuate an actuator, thereby controlling
the operation of the
reamer. For example, a signal may be sent to a controller, causing the
controller to actuate an
actuator to extend, retract, andlor lock the reamer arms.
In some embodiments, the signal may be a direct command originating from an
operator at the surface. The direct command may be sent to a controller
located on the reamer
through any number of communication techniques, such as mud pulse, EM,
acoustic, or hard-
wired tubulars. Upon receipt of the direct command, the controller may actuate
an actuator, also
located on the reamer, causing the actuator to react in a desired manner, e.g.
to retract the
reamer arms.
The various means for actuating the actuators include, but are not limited to,
electric
motors, internally isolated hydraulic actuators, borehole fluid driven
actuators, pressure
actuated devices, or drill string driven actuator devices. For example, the
reamer arms may be
activated using hydraulic flow or pressure against an internal piston, which
in turn drives the
reamer arms out. Moreover, a ball drop device may be used to assist with
opening, closing or
locking the position of the reamer arms. As another example, an electric
actuator may be used
to limit the movement of the reainer arms and to lock the reamer in an open,
closed or
partially open position. The electrical actuator may be a solenoid, switch, or
circuit. As still
another example, the reamer arms may be actuated using an electric motor. A
sensor may be
used to determine the position of the reamer arms to confirm proper operation
of the tool. As
another alteinative, electrical valves may be used to change the piston area
of the reamer,
CA 02687739 2009-11-19
WO 2008/150290 PCT/US2007/070396
thus changing the activation flow or pressure needed to engage the reamer
arms. As still
another alternative, a swash plate pump may be used to activate the reamer
arms. Electrical
valves may control the activation of the pump or the release of the pressure
against the
reamer anms or a piston coiuaected to the reamer axms. Lastly, the reamer arms
may be
activated by temporarily connecting a motor drive rod to the reamer arms.
FIG. 1 S shows the wired reamer 100 of FIG. 1 with controllers and actuators
for
changing the position of the reamer cutting structures. Wired reamer 100
further comprises
controller-actuator assemblies 170 positioned between the reamer body 105 and
the cutting
structures 113. Each controller-actuator assembly 170 further comprise a
controller and an
actuator, where the controller, upon receiving a signal via the power and/or
communications
wiring 125, actuates the actuator to modify the position of the cutting
structures 113, for
example, to retract the cutting structures 113 to reduce the borehole diameter
or to expand the
cutting structures 113 to increase the borehole diameter.
Similarly, FIG. 19 shows the wired reamer 100 of FIG. 2 with controller and
actuators
for changing the position of the reamer cutting structures. In this
embodiment, the pathway 120
for the power and/or communications wiring 125 passes through the reamer body
105. Because
the wiring 125 passes through the reamer body 105, rather than the reamer
flowbore 110, a {
cross-over between the controller-acutator assemblies 170 and the wiring 125
is not necessary.
As witla previously described embodiments, power and/or communications need
not be
contiguous through a reamer, as they are depicted in FIGS. 18 and 19. Instead,
power or
communications may be provided through the reamer. Also, power and/or
communications
need not pass through the reamer, as depicted in FIGS. 18 and 19, but instead
may only be
provided to the reamer or contained entirely within the reamer. Also, as with
previously
described embodiments, the wired reamer may be a fixed blade reamer, as
depicted in FIGS. 18
and 19, an adjustable blade reamer, or another type of reanier.
In other embodiments of the wired reamer with controllers and actuators, the
controllers
may actuate the actuators upon receiving a signal that originates from a
processor. As described
above, a wired reamer with sensors and access to a processor via its through-
tool
communications is a "smart reamer". In some embodiments of a smarf reamer,
controllers and
actuators may be positioned on the reamer, and the controllers may be actuated
by a direct
command originating from the processor.
The direct command may originate from the operator of the smart reamer.
Alternatively, the direct command may be a signal or feedback generated by an
algorithm
developed as a function of measured data and stored on the processor. Sensors
located on other
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WO 2008/150290 PCT/US2007/070396
downhole tools may measure data, in particular, data relating to the
operational parameters of
the reamer and the formation characteristics of the surrounding formation
being driIled. The
measured data may be transmitted to the processor for use as input to the
algorithm. Upon
receiving the measure data, the processor may then execute the algorithm to
generate feedback
based on the measured data. The feedback may be transmitted in the form of a
signal to the
smart reamer via its thru-tool communications. The signal may direct a
controller on the smart reamer to actuate an actuator, causing the smart
reamer to react in a desired zn.armer.
FIG. 20 shows the smart reamer 100 of FIG. 15 with controllers and actuators
for
changing the position of the reamer cutting structures. Smart reamer 100
further comprises
controller-actuator assemblies 170 positioned between the reamer body 105 and
the cutting
structures 113. Each controller-actuator assembly 170 further comprise a
controller and an
actuator, where the controller, upon receiving a signal from the processor 165
via the power
and/flr communications wiring 125, actuates the actuator to modify the
position of the cutting
structures 113, for example, to retract the cutting structures 113 to reduce
the borehole diameter
or to expand the cutting structures 113 to increase the borehole diameter.
Similarly, FIG. 21 shows the wired reamer 100 of FIG. 16 with controller and
actuators
for changing the position of the reamer cutting structures. In this
embodiment, the pathway 120
for the power and/or communications wiring 125 passes through the reamer body
105. Because
the wiring 125 passes through the reamer body 105, rather than the reanler
flowbore 110, a
cross-over between the controller-actuator assemblies 170 and the wiring 125
is not necessary.
As with previously described embodiments, power and/or communications need not
be
contiguous through a reamer, as they are depicted in FIGS. 20 and 21. Instead,
power or
conununications may be provided through the reamer. Also, power and/or
communications
need not pass through the reamer, as depicted in FIGS. 20 and 21, but instead
may only be
provided to the reamer or contained ezitirely within the reamer. Also, as with
previously
described embodiments, the wired reamer may be a fixed blade reamer, as
depicted in FIGS. 20
and 21, an adjustable blade reamer, or another type of reamer. In embodiments
of the smart
reamer having communications through or to the reamer, the processor may be
located at the
surface, on another downhole tool, or on the reamer itself. In embodiments of
the smart reamer
having communications contained within the reamer, the processor is
necessarily located on the
reamer itself.
As yet another alternative, the direct command may be a signal or feedback
generated
by an algorithm developed as a fimction of data measured by sensors located on
the smart
reaxner. In these ernbodiments, control of the smart reamer components is
actuated in response
17
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WO 2008/150290 PCT/US2007/070396
to sensor data in a closed loop fashion. The components may be such devices as
adjustable
stabilization pads (located before and after the reamer blades), subs to
control excessive
torque applied to the reamer cutters, axial force applied to the reamer
cutters or control of the
tool rpm. Sensors monitor conditions of the reamer such as, for example, the
vibration, torque
on bit, weight on bit, formation characteristics, andzpm and a controller and
actuator may
activate the appropriate stabilizer or sub to control (limit or regulate) the
forces on the tool.
For example, the controller and actuator may extend or retract the stabilizer
pad to minimize
the vibration of the tool. As another example, the controller and actuator may
permit a clutch
to allow the string to spin, or a spring sub to temporarily absorb the high
torque, in the
situations where the reamer experiences high torque or rpm. As yet another
example, the
controller and actuator may cause a sub to extend or retract in order to
modify the weight on
the reamer cutters. As still another example, in response to data from an
imaging device on a
reamer ann indicating the reamer cutters are not cutting the fonnation wall,
the controller and
actuator may cause the reamer arm to apply more pressure on the surrounding
formation at
the cutters.
FIG. 22 shows the smart reamer 100 of FIG. 20, wherein the data measured by
the
sensors 140 is used as input to an algorithm stored and executed by the
processor 165 to
generate feedback or a signal. The signal is subsequently transmitted to the
controller-actuator
assemblies 170 of the smart reamer 100, directing the controller-actuator
assemblies 170 to
modify the position of the cutting structures 113. In this manner, the
position of the cutting
structures 113 is controlled, even optimized, in a closed-loop fashion.
Similarly, FIG. 23 shows the smart reamer 100 of FIG. 21, also operating in a
closed-
loop fashion to control the position of the cutting structures 113. In this
embodiment, the
pathway 120 for the power and/or communications wiring 125 passes through the
reamer body
105. Because the wiring 125 passes through the reamer body 105, rather than
the reamer
flowbore 110, a cross-over between the controller-actuator assemblies 170 and
the wiring 125
is not necessary.
As with previously described embodiments, power and/or communications need not
be
contiguous through a reamer, as they are depicted in FIGS. 22 and 23. Instead,
power or
communications may be provided through the reamer. Also, power and/or
communications
need not pass through the reamer, as depicted in FIGS. 22 and 23, but instead
may only be
provided to the reamer or contained entirely within the reamer. Also, as with
previously
described embodiments, the wired reamer may be a fixed blade reamer, as
depicted in FIGS. 22
and 23, an adjustable blade reamer, or another type of reamer. In embodiments
of the smart
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WO 2008/150290 PCT/US2007/070396
reamer having communications through or to the reamer, the processor may be
located at the
surface, on another downhole tool, or on the reamer itself. In embodiments of
the smart reamer
having communications contained within the reamer, the processor is
necessarily located on the
reamer itself.
While preferred embodiments have been shown and described, modifications
thereof
can be made by one skilled in the art without departing from the scope or
teachings herein. The
embodiments described herein are exemplary only and are not limiting. Many
variations and
modifications of the system and apparatus are possible and are within the
scope of the
invention. For example, the relative dimensions of various parts, the
materials from which the
E
various parts are made, and other parameters can be varied. Accordingly, the
scope of
protection is not limited to the embodiments described herein, but is only
limited by the claims
that follow, the scope of which shall include all equivalents of the subject
matter of the claims.
19
