Note: Descriptions are shown in the official language in which they were submitted.
CA 02501736 2000-08-04
APPLICATION FOR LETTERS PATENT
TITLE: CONTINUOUS WELLBORE DRILLING SYSTEM WITH
STATIONARY SENSOR MEASUREMENTS
INVENTOR: Volker Krueger
SPECIFICATION
BACKGROUND OF THE INVENTION
JI
1. Field of the Invention
The present invention relates to a system for drilling welibores and more
particularly to drill strings that include a bottomhole assembly that has a
force
application system that continuously or almost-continuously applies force on
the
drill bit to provide for continuous drilling and further has at least one
housing or
collar, which remains stationary with respect to the welibore inside during
the
continuous drilling process. A set of sensors whose measurements are sensitive
to the axial movement of the bottomhole assembly are integrated into the
collar,
which sensors take measurements while the collar is stationary while the
drilling
is continuing. This invention also relates to a downhole thruster system that
includes an integrated steering system for drilling the wellbore along a
prescribed
trajectory.
2. Descriptiqn of the Related Art
Wellbores are drilled in subsurface formations to recover oil and gas.
Drilling is usually performed by a driiling assembly (also referred to as the
"bottomhole assembly" or "BHA") conveyed into the welibore by a tubing,
usually
a coiled tubing or a jointed pipe tubing. The BHA contains a drill bit at the
bottom end of the BHA. The drill bit is rotated by a mud motor in the BHA
and/or
by rotating the drill pipe from the surface. For effective penetration of the
drill bit
into the formation, weight on bit ("WOB") must be maintained within an
acceptabie range. Excessive WOB can cause the drill bit to become wedged in
CA 02501736 2000-08-04
the wellbore bottom or damage the mud motor and other BHA components,
while relatively small WOB can reduce the drilling rate or the rate of
penetration
("ROP") to a level which impajrs drilling effectiveness.
A thruster in the drill string (usually a part of the BHA) is sometimes used
to apply force on the drill bit and to maintain and control the desired WOB.
Such
thrusters usually are hydrauiically-operated. A thruster usually has a housing
connected to the drill pipe and a mandrel or piston connected to the lower
part
of the BHA. The hydraulic pressure generated in the BHA is applied to the
piston, which moves the piston axially (i.e. along the wellbore axis) thereby
applying force and thus WOB on the drill bit during the drilling process.
There are basically two methods utilized for drilling with the hydraulic axial
force generated by a thruster: The first case is when the drill pipe above the
thruster can be continuously lowered, i.e., moved into the wellbore. If the
axial
stick slip motion of the drill pipe does not exceed the available travel
distance of
the piston, then the drill pipe is continuously lowered. The rate of lowering
the
drill pipe must, however, be the same as the rate of penetration of the drill
bit into
the rock formation. The second case is when the stick slip motion is such that
it intermittently causes the thruster to fully extend and then collapse, then
the so-
calied "stepwise" process is more appropriate. During the stepwise process
each time after the piston has been fully, it shifted into the initial or the
collapsed
position lowering of the drill pipe. The thruster piston is continuously
extended
to drill the welibore until the piston is fully extended. The drill string is
then
lowered by the travel distance of the piston and the process is repeated. This
method can be aided by stopping and starting the pumps or at least lowering
the
drilling fluid flow rate and subsequently resuming the rate to the normal
level.
The stepwise process allows drilling under different stick slip conditions but
has
the disadvantage of changes of the feeding rate of the drill pipe and also,
potentially, changes of the flow rate.
In order to further reduce the stick slip effects on the drilling assembly, to
eliminate the reactive force on the drill pipe, and to dynamically uncouple
the drill
string from the BHA, the thruster can be combined with a locking device that
connects the upper part of the thruster to the drill pipe. The same stepwise
process for moving or lowering the drill pipe would be applied with the
additional
locking and unlocking of the thruster top-end or with the drill pipe
positioned on
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top of the thruster to the borehole wall. Stopping and starting the pumps
provides the additional advantage of applying only the axial force to the
drill bit
which is needed to axially move the drill pipe without the need to apply the
incrementally larger force to create the WOB.
It is desirable to have thruster systems which can continuously apply force
on the drill bit and carry out downhole measurements. Intemational Application
No. WO 99/09290 describes a drill string with a thruster system for drilling
wellbores. Such a system, however, does not allow for continuous drilling of
the
weilbore. International Patent Application No. WO 97/08418 describes a drill
string which includes two serially coupled thrusters which cooperate with each
other to substantially continuously apply force on the drill bit but does not
provide
the desired downhole sensors. The trend in the oil drilling industry has been
to
incorporate a variety of sensors in the drilling assembly to take a variety of
j
measurements-while-drilling the wellbore. Such sensors are usually referred to
as measurement-while-drilling or ("MWD") devices. Logging devices, such as
formation resistivity sensors, acoustic sensors, etc., are sometimes referred
to
as the logging-while-driiling or ("LWD") sensors. For the purpose of this
invention, the terms MWD and LWD are used interchangeably.
It is known that some of the MWD measurements are relatively sensitive
to motion, i.e., it is either preferable or necessary to make such
measurements
while such sensors are not moving in the wellbore. For the purpose of this
invention, such measurements are referred to as the motion sensitive
measurements. Additionally, it is preferable to have a continuous motion drill
string that can be steered downhole so as to drill the weilbore along a
preselected or desired well path. Such a steering system may be a closed loop
system based on a preprogrammed well trajectory or wherein the drilling course
is adjusted by sending commands from the surface. The present invention
provides a drilling system wherein a thruster system continuously or near
continuously applies force on the drill bit while allowing the motion
sensitive
sensors to make stationary measurements. The present invention further
incorporates a steering device for automatically maintaining the drilling
along a
prescribed well path.
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SUMMARY OF THE INVENTION
The prevent invention provides continuous or near continuous motion drill
strings which include motion sensitive and other MWD sensors which take
stationary measurements while the drilling assembly is continuing to drill the
wellbore. For simultaneous continuous drilling and stationary measurements,
the present invention provides a drilling assembly wherein a force application
system almost-continuously applies force on the drill bit while maintaining a
housing or drill collar section stationary. Motion sensitive sensors carried
by the
drill collar take stationary measurements. A steering device between the drill
bit
and the force application system maintains drilling of the welibore along a
prescribed well path.
To drill a wellbore, the drilling assembly of the present invention is
conveyed by a tubing into the wellbore from a surface location. The drilling
assembly, in one embodiment, includes two serially coupled thrusters, each
having a housing that can be locked on to the wellbore and a force application
member that can be moved from a first retracted position to a second extended
position. The housing of the first force application device is locked in the
wellbore. The force application member moves from the retracted position to
the
extended position applying force on the drill bit, which causes the drill bit
to
penetrate the formation. The force application member continues the
application
of the force until it is fully extended. The second force application device
is then
locked onto the wellbore and the first force application device unlocked from
the
weilbore. The second force application device applies pressure on the first
force
application member, causing it to move to its retracted position. After the
first
force application member has moved to its retracted or coilapsed position, it
is
again locked to the borehole wall and the second force application is unlocked
from the borehole. Either by continuously lowering of the drill pipe or
through a
stepwise lowering of the second force application member, the first force
application member is then moved into its retracted position. The above
process
is repeated to continue the drilling process. The force applied on the drill
bit by
the first force application device may be constant and continuous.
In an alternative embodiment, a single continuous motion traction device
is utilized to continuously apply force on the drill bit. A housing above or
uphole
of the continuous motion traction device remains stationary with respect to
the
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wellbore for a predetermined travel of the traction device. In each of the
drilling
assemblies according to the present invention, at least one housing or drill
collar
remains stationary relative to the wellbore, while drilling continues. One or
more
motion sensitive sensors are provided on one or more of the housings of the
force application system. Such sensors take measurements when the housing
carrying such sensors is stationary. The present invention preferably
integrates
such sensors into the housings. Such sensors include a nuclear magnetic
resonance sensor which is particularly susceptibie to movement. The stationary
housing can provide a stable platform for such sensors. Other sensors that can
be integrated include a direction measuring sensor or directional sensor
system,
which would include at least one or more accelerometers and at least one
gyroscope or a magnetometer. The combination of the measurements from the
accelerometers and the gyroscopes orthe magnetometers provide full directional
measurement capability. Preferably three axis accelerometers are used in the
directional sensor of the present invention. An acoustic sensor system may be
incorporated in one of the housings. Such a sensor system would include at
least one transmitter and one or more acoustic detectors spaced apart from the
transmitter. Acoustic sensors provide porosity measurements and bed bound
any information. A nuclear sensor may be incorporated into a housing of the
present system to determine the density and the nuclear porosity of the
formation surrounding the wellbore. A formation testing device usually
requires
extracting a fluid sample from the formation which requires the tool to remain
stationary. In the present invention, a formation testing device is included
in one
of the housings. The above described sensors tend to be particularly sensitive
to the axial movement of the sensor. However, other sensors, such as a
pressure sensor may be used to determine the reservoir pressure. Stabilizers
may be incorporated in the housings to reduce the vibration of the housings,
thereby providing more stable platform for the motion sensitive sensors.
Thus, the present invention provides a drilling assembly that continuously
exerts force on the drill bit to cause the drill bit to continuously drill the
well while
making selected measurements in a stationary mode. A variety of other sensors
may also be incorporated into the housings and/or in other sections of the
drilling
assembly.
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The continuous motion drilling assembly of the present invention, in one
embodiment, also includes a steering device, preferably below or downhole of
any
thruster in the drilling assembly. Such a steering device includes one or more
independently adjustable force application members or ribs. Each such member
extends outward from the drilling assembly to apply selected amount of force
on the
wellbore wall. A control unit controls the applied force to maintain the
drilling assembly
along a presented or predetermined well trajectory or path.
Each embodiment of the drilling assembly of the present invention preferably
includes a processor (also referred to as the "control unit" or a "processing
unit") that
includes one or more microprocessor-based circuits to process measurements
made by
the sensors in the drilling assembly at least in part, downhole during
drilling of the
wellbore. The processed signals or the computed results are transmitted to the
surface
by a telemetry unit in the drilling assembly. The desired downhole trajectory
may be
programmed into a memory of the processor. The processor then controls the
force
applied by the force application members to steer the drilling assembly along
the
prescribed well path. The processor also controls the operation of the sensors
and
other devices in the drilling assembly.
Accordingly, in one aspect of the present invention there is provided a
drilling
assembly for drilling a wellbore in a subsurface formation, comprising:
(a) a drill bit at an end of said drilling assembly;
(b) a force application device; and
(c) a slidable assembly uphole of the force application device and having a
slidable
drill collar, said drill collar having a locking device, said force
application device capable
of continuously applying force on the drill bit to move the drill bit in the
wellbore to drill
said wellibore, the locking device engaging the drill collar with the wellbore
inside to
maintain the drill collar stationary relative to the wellbore while the force
application
device travels a predetermined distance from an initial position in the
wellbore and
thereafter disengages from the wellbore inside and allows the drill collar to
move toward
the force application device by the predetermined distance, wherein the force
application device includes a traction device that continuously moves toward
the drill bit
while being engaged with the weilbore inside to continuousiy apply force on
the drill bit.
According to another aspect of the present invention there is provided a
drilling
assembly for drilling a wellbore in a subsurface formation, comprising:
a drill bit at an end of said drilling assembly;
a force application device for continuously applying force on the drill bit to
move
the drill bit in the wellbore to drill said wellbore; and
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a slidable assembly uphole of the force application device and having a
slidable drill
collar, said drill collar having a locking device, wherein the locking device
engages the
drill collar with the wellbore inside to maintain the drill collar stationary
relative to the
wellbore while the force application device travels a predetermined distance
from an
initial position in the wellbore and thereafter disengages from the wellbore
inside and
allows the drill collar to move toward the force application device by the
predetermined
distance, said force application device comprising a traction device that
continuously
moves toward the drill bit while being engaged with the wellbore inside to
continuously
apply force on the drill bit.
According to yet another aspect of the present invention there is provided a
drilling assembly for drilling a wellbore in a subsurface formation,
comprising:
(a) a drill bit at an end of said drilling assembly;
(b) a force application device capable of continuously applying force on the
drill bit
to move the drill bit in the wellbore to drill said wellbore, wherein the
force application
device includes a traction device that continuously moves toward the drill bit
while being
engaged with the wellbore inside to continuously apply force on the drill bit;
(c) a slidable assembly uphole of the force application device and having a
slidable
drill collar, said drill collar having a locking device, wherein the locking
device engages
the drill collar with the wellbore inside to maintain the drill collar
stationary relative to the
wellbore while the force application device travels a predetermined distance
from an
initial position in the wellbore and thereafter disengages from the wellbore
inside and
allows the drill collar to move toward the force application device by the
predetermined
distance; and
(d) a steering device downhole of the force application device, said steering
device
selectively applying force to the wellbore inside to steer the drill bit in a
particular
direction.
According to still yet another aspect of the present invention there is
provided a
drilling assembly for drilling a wellbore in a subsurface formation,
comprising:
(a) a drill bit at an end of said drilling assembly;
(b) a force application device capable of continuously applying force on the
drill bit
to move the drill bit in the welibore to drill said wellbore, wherein the
force application
device includes a traction device that continuously moves toward the drill bit
while being
engaged with the wellbore inside to continuously apply force on the drill bit;
(c) a slidable assembly uphole of the force application device and having a
slidable
drill collar, said drill collar having a locking device, wherein the locking
device engages
the drill collar with the wellbore inside to maintain the drill collar
stationary relative to the
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wellbore while the force application device travels a predetermined distance
from an
initial position in the wellbore and thereafter disengages from the wellbore
inside and
allows the drill collar to move toward the force application device by the
predetermined
distance; and
(d) a steering device downhole of the force application device, said steering
device
selectively applying force to the wellbore inside to steer the drill bit in a
particular
direction, wherein the steering device comprises a plurality of independently
controlled
ribs, each said rib capable of extending outward from the drilling assembly to
appiy a
different amount of force on the wellbore inside.
Examples of the more important features of the invention thus have been -
summarized rather broadly in order that the detailed description thereof that
follows may
be better understood, and in order that the contributions to the art may be
appreciated.
There are, of course, additional features of the invention that will be
described
hereinafter and which will form the subject of the claims appended hereto.
BRIEF DESCRIPTION OF THE DRAWINGS
For detailed understanding of the present invention, references should be made
to the following detailed description of the preferred embodiment, taken in
conjunction
with the accompanying drawings, in which like elements have been given like
numerals
and wherein:
Figure 1 show a schematic diagram of a drill string having a drilling assembly
with two force application devices that alternately apply substantially
constant force on
the drill a plurality of motion sensitive sensors carried by the
6b
CA 02501736 2000-08-04
force application devices that provide measurements while a force application
device not applying force on the drill bit.
Figures 1A-1D shows functional block diagrams of selected motion
sensitive sensors for use in the drilling assemblies made according to the
presented invention.
Figures 2A-2D depict sequence of operation during one cycle of the
operation of the force application members of the drilling assembly of Figure
1.
Figure 3 shows an exemplary block functional diagram of a processor for
processing measurement signals from the sensor in the drilling assemblies made
according to the present invention.
Figure 4 shows an embodiment of a drilling assembly having a single
force application member for continuously applying substantially constant
force
on the drill bit.
Figure 5 shows an embodiment of a drilling assembly that includes a
single force application device for continuously applying force on the drill
bit and
a drill collar carrying one or more motion sensitive sensors which remain
stationary while the drill bit penetrates a preselected distance into the
formation.
Figure 6 is shows a drilling system that utilizes the drilling assemblies of
Figure 1-5 for drilling wellbores.
DESCRIPTION OF THE PREFERRED EMBODIMENT
The present invention provides drill strings for drilling welibores that
include a drilling assembly (also referred herein as the bottom hole assembly
or
"BHA") at its bottom end. The BHA includes a drilling motor that rotates a
drill
bit and a force application system that continuously or substantially
continuously
applies force on the drill bit to provide substantially continuous drilling of
the
wellbore. The reactive force from drilling is directed into the borehole at a
location above or uphole of the BHA instead of the drill pipe. The force
application system includes at least one housing or drill collar that remains
stationary relative to the wellbore at least periodically while the drilling
assembly
is penetrating the formation, i.e. moving downhole. One or more motion
sensitive sensors carried by one or more housings provide measurement data
or signals indicative of one or more downhole parameters when the housing is
stationary and the drilling assembly is moving in the wellbore. The one or
more
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sensors preferably are those whose measurements tend to provide more
accurate results when such sensors are stationary compared to when such
sensors are moving. Such sensors are referred herein as the "motion sensitive
sensors." In a preferred embodiment, a steering device disposed in the
drilling
assembly near the driil bit can maintain the drilling assembly along a
prescribed
or predetermined well path. The drilling assembly includes one or more
processors that control the operation of the sensors and the steering device
downhole and process sensor data, at least partially.
Figure 1 show a schematic diagram of one embodiment of a drill string
100 according to the present invention which includes a drilling assembly 110
that contains (i) force application system that includes two force application
devices 140 and 150 in series that alternately operate to provide continuous
or
substantially continuous drilling of the wellbore and maintain at least one
housing
stationary relative to the wellbore while the drilling is continuing, and (ii)
a
plurality of motion sensitive sensors carried by the housings of the force
application devices to provide measurements whiie such housings are
stationary.
The drilling assembly 110 is attached to a drill pipe 105 at bottom end 106
of the drill pipe by a suitable connector 107. The drill pipe 105 is made by
joining
solid pipe sections, usually 30-40 feet iong, at the rig site or surface. A
coupling
or swivel 108 between the drill pipe 105 and the drilling assembly 110
selectively
allows the rotating drill pipe 105 to engage with or disengage from the
drilling
assembly 110. This allows the drilling assembly 110 to be non-rotational while
allowing the drill pipe to be rotated from the surface to reduce friction
losses. In
the engaged mode, the drilling assembly 110 rotates when the drill pipe 105
rotates and in the disengaged mode, the rotation of the drill pipe 122 does
not
rotate the drilling assembly 110.
The drilling assembly 110 carries a drill bit 112 at its bottom end. A
driiling motor 116 disposed above or uphole of the drill bit 112 rotates the
drill bit
112. The drilling motor 116 is preferably a positive displacement motor that
operEltes when a fluid 122 (such as the drilling fluid or "mud") is supplied
under
pressure from a surface location to the drill pipe 105. Such motors are also
referred to in the art as "mud motors." A mud motor usually includes a power
section 116a and a bearing assembly section 116b. The power section 116a
includes a rotor 117 that is rotatably disposed in a stator 118. When the
drilling
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fluid 122 is supplied to the drilling motor 116 under pressure from the
surface or
the well site, the rotor 117 rotates in the stator 118. The rotor 117 rotates
a
hollow shaft 119 whose bottom end is fixedly connected to the drill bit 112,
thereby rotating the drill bit 112. The shaft 119 extends through the bearing
assembly section 116b. The bearing assembly section 116a includes radial and
axial bearings (not shown) which respectively provide lateral and axial
stability to
the drill shaft 119 during drilling of the wellbore. Drilling motors are in
common
use in the oil and gas industry and are, thus, not described herein in detail.
Any
suitable drilling motor, whether a mud motor or a turbine or any other kind
may
be utilized in the drilling assembly 110 of the present invention.
Still referring to Figure 1, the driiiing assembly 110 includes a lower or the
first force application device 140 (also referred to herein as the "lower
thruster"
or the "first thruster") and an upper or second force application device 150
(also
referred to herein as the "upper thruster" or the "second thruster"). The
upper
thruster 150 is disposed above or uphole of the lower thruster 140. The lower
thruster 140 inGudes a housing 142 (also referred to as a drill collar or
drill collar
portion) wherein a force application member 144 reciprocates in the thruster
140
between a first (also referred to as the initial or the retracted position)
and a
second (also referred to as the extended) position. The force application
member
144 may be a piston that reciprocates in a piston chamber in the thruster 140
upon the supply of a fluid under pressure to the chamber. A number of
mechanical thrusters for supplying axial force have been utilized in drilling
applications. A hydraulically-operated mechanical thruster that can apply
constant or variable force on to the drill or any other mechanical thruster
may be
utilized in the drilling assembly 110 as the lower thruster 140.
A locking device 146 is disposed on the periphery of the thruster housing
142. The locking device 146 may be an expandable packer or a mechanical
anchor or any other suitable device that can be extended radially outward from
the thruster housing 142 to lock the thruster housing 142 onto the wellbore
inside
and retracted to unlock or detach the thruster housing 142 from the wellbore
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inside. A hydraulicaliy-operated device, such as a packer, is the preferred
locking device in the drilling assembly 110. When the lower thruster 140 is
locked in position and a fluid under pressure is supplied to the thruster, the
force
application member 144 starts to extend axially downward or in the downhole
direction, i.e., it starts to move toward the drill bit 112, thereby exerting
force on
the drill bit 112. The thruster 140 may be configured to apply a constant or a
variable amount of force on the drill bit 112 during drilling of the welibore.
The upper thruster 150 has a body or housing 152 and a second force
application member 154. A second locking device 156 is provided on the upper
thruster 150 which can releasably lock the upper thruster housing 152 in the
wellbore. When the upper thruster housing 152 is locked onto the wellbore and
pressure is applied on the force application member 154, it starts to move
downward, exerting pressure on the lower thruster 140, which causes the force
application member 144 of the lower thruster to collapse or retract to its
initial
position. The upper thruster 150 may be the same type as the lower thruster
140 or it may be any other type of force application device that is adapted to
exert pressure on the lower thruster to cause the force application member 144
of lower thruster 140 to move from its extended position to its retracted
position
downhole.
The drilling assembly 110 further may include one or more independently
adjustable stabilizers, such as stabilizers 120a and 120b, near the drill bit
112
for maintaining and/or changing the drilling direction. These stabilizers
preferably include a plurality of radially extendable members (also referred
to
herein as "ribs"), each such member being adapted to independently exert force
on the wellbore. Preferably, the lower stabilizer 120a is arranged around the
drilling motor section 116 near the drill bit 112 and spaced apart from the
upper
stabilizer 120b which is disposed near the upper end of the driliing motor
section
116. These stabilizers also provide lateral support and stability to the
drilling
assembly 110, which reduces the vibration effects during drilling of the
wellbore.
Each adjustable member 120a' and 120b' is independentiy controlled by the
downhole controller 132. Such force application members are preferably
hydraulically-operated, but may be operated by electric motors or electro-
mechanical devices. The desired wellbore trajectory may be stored in downhole
memory. The controller 132 adjusts the force applied by the force application
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members 120a' and 120b' so that drilling direction is maintained along the
prescribed or predetermined well trajectory or path.
Still referring to Figure 1, the drilling assembly 110 includes a number of
sensors and devices which aid the drilling operation and provide information
about the subsurface formations. The drilling assembly 110 may include any
number of sensors to provide measurements about the drilling direction and the
location or depth of the drill bit 112 or the drilling assembly relative to a
known
location, such as a surface location or true north. Such sensors may include
inclinometer, accelerometers, magnetometers and gyroscopic devices. Nuclear
sensors, such as gamma ray devices, may also be utilized. In Figure 1, some
of such sensors are denoted by numeral 124 and are shown disposed in the
mud motor 116. A variety of position and direction sensors are known and are
commercialiy utilized in the oil and gas industry and are thus not described
in
detail here.
The drilling assembly 110 includes a number of formation evaluation
sensors for providing information about the various characteristics of the
formation, directional sensors for providing information about the drilling
direction, formation testing sensors for providing information about the
characteristics of the reservoir fluid and for evaluating the reservoir
conditions.
The formation evaluation sensors may include resistivity sensors for
determining
the formation resistivity, dielectric constant and the presence or absence of
hydrocarbons, acoustic sensors for determining the acoustic porosity of the
formation and the bed boundary in formation, nuclear sensors for determining
the formation density, nuclear porosity and certain rock characteristics,
nuclear
magnetic resonance sensors for determining the porosity and other
petrophysical
characteristics of the formation. The direction and position sensors
preferably
include a combination of one or more acceierometers and one or more
gyroscopes or magnetometers. The accelerometers preferably provide
measurements along three axes. The formation testing sensors provide a
device for collecting formation fluid samples while drilling of the weilbore
is
continuing and determines the properties of the formation fluid, which include
physical properties and chemical properties. Pressure measurements of the
formation provide information about the reservoir characteristics.
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It is known that some of the above described sensors are sensitive to
motion, i.e., such sensors provide more accurate information about the
intended
parameters if the measurements are made when the sensor is stationary
compared to when the sensor is moving in the wellbore. In the prior art
methods
such sensors either take measurements while the drilling assembly is in motion
or the driiling is temporarily stopped to make the measurements. In the
present
invention the motion sensitive sensors are preferably placed in the housings
142
and 152 of the force application devices 140 and 150, respectively. These
sensors are activated when the housing carrying such sensors is stationary
relative to the wellbore. Nuclear magnetic resonance sensors can be greatly
affected by motion. Nuclear sensors and acoustic sensor measurements also
are affected by motion. It is also preferred that gyroscopic measurement be
made when the tool is stationary. Formation testing sensors can not be used in
motion as fluid samples must be withdrawn from the formation by placing a
probe against the wellbore wall for a period of time. In the present
invention, one
or more of the motion sensitive sensors are carried by the sections of the
drilling
assembly 110 that will remain stationary for a period of time while the
drilling is
continuing. In the embodiment of Figure 1, such sensors may be placed in one
or both of the housings 142 and 152. Some of such sensors, however may be
placed in other sections of the drilling assembly. They also may be integrated
in the mud motor 116.
Still referring to Figure 1, the drilling assembly 110 is shown to include a
nuclear magnetic resonance ("NMR") sensor 15 in the upper housing 152. Any
suitable NMR sensor may be utilized for the purpose of this invention. Figure
IA shows a structure of an NMR sensor 15 that may be incorporated in the
drilling assembly 110. The NMR sensor 15 includes a magnet system 16 that
induces a static magnetic field and a region of investigation 18 in the
formation.
A radio frequency ("RF") antenna 17 produces radio frequency signals
orthogonal to the static magnetic field in the region of investigation 18. A
control
circuit (not shown) processes the radio frequency signals detected in response
to the RF signals to determine a property of the formation.
A nuclear sensor 20 is shown carried by the upper housing 152.
Referring to Figure 1 B, the nuclear sensor 20 includes a nuclear source 21
which generates nuclear energy into the formation surrounding the drilling
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assembly 110. A detector 22 detects the nuclear rays from the formation
responsive to nuclear energy generated by the nuclear source 21. A processor
24 processes the detected rays to determine the nuclear porosity and the
density
of the formation.
An acoustic sensor 30 is shown carried by the lower housing 142. It
includes an acoustic transmitter T that generates acoustic signals in the
formation surrounding the wellbore. One or more acoustic detectors such as RI
and R2 placed spaced apart from the transmitter T detect acoustic signals
propagated through the formation as well as signals reflected from reflection
points in the formation in response to the transmitted signals. A processor,
such
as processor 132 processes the detected signals to determine a characteristic
of the formation, such as the acoustic velocity of the formation and the bed
boundary information.
A formation tester 40 is shown carried by the upper housing 152. Figure
1 C, shows a functional block diagram of an exemplary formation testing device
that includes a probe 41 for collecting formation fluid, which passes through
a
chamber 42. One or more sensors, such as sensor 43, provides in-situ
information about one or more properties of the collected fluid. Such
properties
may include a chemical property of the fluid, composition of the collected
fluid
and/or a physical property of the collected fluid. A sample collection chamber
45 can be used to collect the sample under formation conditions for laboratory
testing. A pressure sensor 46 in the probe or at any other suitable location
provides the pressure of the formation.
A direction measuring sensor 50 is shown carried by the lower housing
142. Figure 1 D shows a block functional diagram of an exemplary directional
sensor 50. It preferably includes a three component accelerometer 51 which
provides acceleration measurements along the three axes (x, y, and z axes) and
one or more gyroscopes or magnetometers 52. The measurements of the
accelerometer and the gyroscope or the magnetometer are combined to
determine the direction of the drilling assembly.
The driiling assembly 110 inciudes one or more downhole controllers or
processors, such a processor 132. The processor 132 can process signals from
the various sensors in the drilling assembly and also controls their
operation. It
also can control devices , such as devices 120a, 120b and 130. A separate
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processor may be used for each sensor or device. Each sensor may also have
additional circuitry for its unique operations. The downhole controller is
used
herein in the generic sense for simplicity and ease of understanding and not
as
a limitation because the use and operation of such controllers is known in the
art. The controller 132 preferably contains one or more microprocessors or
micro-controllers for processing signals and data and for performing control
functions, solid state memory units for storing programmed instructions,
models
(which may be interactive models) and data, and other necessary control
circuits.
The microprocessors control the operations of the various sensors, provide
communication among the downhole sensors and provide two-way data and
signal communication between the drilling assembly 110 and the surface
equipment via a two-way telemetry 134.
Figure 3 shows an exemplary functional block diagram 340 of the major
elements of the bottom hole assembly 110 of Figure 1 and further illustrates
with
arrows the paths of cooperation between such elements. It should be
understood that Figure 3 illustrates only one arrangement of certain elements
and one system for cooperation between such elements. Other equally effective
arrangements may be utilized to practice the invention. A predetermined
number of discrete data point outputs from the sensors 352 (S1-S3) are stored
within a buffer which, in Figure 3, is included as a partitioned portion of
the
memory capacity of a computer 350. The computer 350 preferably comprises
commercially available solid state devices which are applicable to the
borehole
environment. Alternatively, the buffer storage can comprise a separate memory
element (not shown). The interactive models are stored within memory 348. In
addition, other reference data such as calibration compensation models and
predetermined drilling path also are stored in the memory 348. A two way
communication link exists between the memory 348 and the computer 350. The
responses from sensors 352 are transmitted to the computer 350 and or the
surface computer 40 (see Figure 6) wherein they are transformed into
parameters of interest using known methods.
The computer 350 also is operatively coupled to certain downhole
controllable devices d, - d,, such as thrusters 140 and 150, adjustable
stabilizers 120a and 120b and kick-off subassembly for geosteering and to a
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flow control device for controlling the fluid flow through the drill motor for
controlling the drill bit rotational speed.
The power sources 344 supply power to the telemetry element 342, the
computer 350, the memory modules 346 and 348 and associated control circuits
(not shown), and the sensors 352 and associated control circuits (not shown).
Information from the surface is transmitted over the downlink telemetry path
illustrated by the broken line 329 to the downhole receiving element of
downhole
telemetry unit 342, and then transmitted to the storage device 348. Data from
the downhole components is transmitted uphold via link 327. In the present
invention, the parameters of interest such as toolface, inclination and
azimuth
are preferably computed downhole and only the answers are transmitted to the
surface. The formation evaluation measurements may be partially of fully
processed downhole and stored for later use or transmitted to the surface.
The operation of the driiling assembly of Figure 1 will now be described
in reference to Figures 2A-2D, which depict the sequence of operation during
one cycle of operation of the force application system 140 and 150. Figure 2A
shows the drill string 100 extending from a surface location 12 and
terminating
with the drill bit 112 at the bottom 11 of a wellbore 10. Drilling fluid 122
is
continuously supplied under pressure from a source thereof (see Figure 6) at
the surface 12 to the drilling assembly 110 via the drill pipe 105. The
drilling fluid
122 rotates the rotor 119 of the mud motor 116, which rotates the drill bit
112.
To drill the wellbore 10, the lower locking device 146 is set or expanded
to lock the lower thruster 140 in the wellbore 10 at location 10a (see Figure
2B).
Pressure is supplied to the thruster 140, which causes the force application
members 144 to move downward, thereby exerting force on the driil bit 112. The
drilling motor continuously rotates the drill bit 112 while the lower thruster
140 is
exerting force on the drill bit 112. The lower thruster 140 may be configured
to
apply constant force on the drilt bit 112 regardless of the rate of
penetration of
the drill bit 112 into the formation 10 or it may be configured to apply
variable
force based on drilling factors. A sensor 149 may be provided in the thruster
to
determine the travel distance of the force application member 146 and the rate
of penetration. Once the force application member 144 has fully extended or
extended by a desired distance (as determined by the sensor 149), as shown in
Figure 2B, the lower locking device 146 is retracted or collapsed to release
or
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unlock the lower thruster 140 from the wellbore 10, while the upper tocking
device 156 is expanded to lock the upper thruster 150 in position. As the
upper
thruster body is locked in the wellbore 10, the force application member 154
of
the upper thruster 150 starts to move downward, causing the lower thruster
body
142 to move toward the drill bit 112, thereby causing the lower thruster's
force
application member 144 to return to its initial or retracted position, as
shown in
Figure 2C. The lower locking device 146 is then engaged with or locked onto
the wellbore 10 and the upper locking device 156 is disengaged from the
wellbore 10. The drill pipe 105 is pushed downhole by the length of the stroke
or the travel distance of the lowerforce application member 144, completing
one
cycle of operation of the thruster 140. The drilling is continued by repeating
the
process described above. The drill pipe sections are added while the drilling
of
the welibore is in progress, since the drill string 100 itself is not used to
provide
the desired WOB. A coiled tubing may be used instead of the drill pipe.
When the lower thruster body 142 is locked onto the wellbore, both
thruster housings 142 and 152 are stationary and remain such until the force
application member has been fully extended. The sensors SL carried by the
lower thruster housing 142 and the sensors S, carried by the upper thruster
housing are activated to take measurements. For ease of explanation SL
represents any or all of the sensors utilized in the upper housing while S.
represents any or all of the sensors utilized in the lower housing 142. The
measurements taken by the sensors SL and S, are processed by a downhole
controller as described above. When the upper housing 152 is locked in
position
in the wellbore 10, the upper housing remains stationary while the lower
housing
142 moves. During this time, sensors SL take measurements. It should be
noted that the sensors SL, S,, and other sensors are capable of taking
measurements while they are in motion and may be activated to take
measurements continuously, except that certain sensors, such as the sample
collection-type sensors described above need to be operated when they are
stationary. Thus, the above described process provides substantially
continuous
application of force on the drill bit, thereby providing substantially
continuous
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drilling of the wellbore, while allowing stationary measurements of the motion
sensitive sensors. Additional stabilizers may be used on the housings to
reduce
the vibration effects caused by the drill bit motion.
Thus, the above-described system and method of the present invention
utilizes a drill pipe drill string, wherein a mud motor rotates the drill bit
and a
thruster system continuously or near continuously applies constant force on
the
drill bit. Constant force applied to the drill bit and the continuous motion
of the
thruster piston significantly reduce the vibration of the drill string. The
drill pipe
may be rotated during drilling by disengaging the swivel 108 from the drilling
assembly 110 for hole cleaning, to reduce friction, and to avoid the drill
pipe
becoming wedged in the wellbore.
Figure 4 shows an alternative embodiment of a drilling assembly 200 for
continuously applying force on the drill bit according. The drilling assembly
200
is similar to the drilling assembly 100 of Figure 1, but includes a tractor or
traction device 220 for providing continuous force on the drill bit 112. The
tractor
220 has a traction device that includes traction members 222 and 224. The
traction member 222 has traction elements 222a and 222b that generate
downward force while urging against the wellbore inside. Traction member 224
includes traction elements 224a and 224b which operate in the same manner as
the traction elements 222a and 222b. The traction members 222 and 224
continuously apply force on the drifi bit. The downward motion of the tractor
220
is the same as the rate of penetration of the driil bit 112 into the
formation. The
traction elements may be rollers or an endless track that can be continuously
moved by gears or rollers.
In some applications, the traction device 220 may not be able to apply
constant force on the drill bit 112. For such applications, a thruster 230,
which
may be the same type as the thruster 140 shown in Figure 1, can be provided
below the traction device 220 to exert constant force on the drill bit 112. ln
such
a configuration, the traction device 220 provides pressure to collapse the
thruster
230 from its extended position to its initial position during each cycle of
operation. In this configuration, the tractor housing 221 and the thruster
housing
235 remain stationary during the time thruster 230 is locked onto the wellbore
inside. The motion sensitive sensors carried by such housings, generally
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denoted by S,n, take measurements while such housings are stationary. These
measurements are processed in the manner described earlier.
Figure 5 shows yet another embodiment of a drilling assembly 400 placed
in a wellbore 401. The drilling assembly 400 includes a traction device 402
that
continuously applies force on the drill bit 412. A slidable housing 406 that
can
be locked onto the welibore inside 403 is provided above the traction device
402.
The lockable housing 406 may be a part of a thruster 410 such as described in
Figure 1. At the start of the operation, the piston 408 of the thruster 410 is
in the
collapsed position. The housing 406 is locked onto the wellbore 401 by a
stabilizer or anchor 415. Additionai stabilizers or anchors, such as
stabilizer 417,
may be used to reduce the effect of drill bit vibrations. When the housing 406
is locked in position, the traction device 402 applies force on the drill bit
until the
piston 408 fully extends, as shown in Figure 4. The motion sensitive sensors
S. carried by the housing 406 take measurements during the time the housing
406 is locked on to the wellbore 401. Once the piston 408 has fully extended,
the housing 406 is unlocked from the wellbore 401 by retracting the
stabilizers
415 and 417. The tubing 422 is then pushed down by a length equal to the
travel distance of the piston 408, thereby causing the piston 408 to attain
its
initial collapsed position. The above process is then repeated. A steering
device
420, having independently adjustable ribs 420a, is placed below the traction
device to steer the drilling assembly along the desired wellbore path.
Thus, in the above described exemplary embodiments of the drilling
assembly, a housing or drill collar is maintained stationary relative to the
weUbore
while continuously or nearly continuously applying force on the drill bit to
obtain
substantially continuous drilling of the welibore. One or more motion
sensitive
MWD or other type of sensors carried by such a housing take measurement
when the housing is stationary. The drilling systems of the present invention
provide near continuous drilling and allow more accurate downhole
measurements. Thrusters can allow drilling of deeper horizontal wellbores and
stationary measurements provide more accurate information about the
formation, which are critical to the recovery of hydrocarbons from subsurface
formations.
Figure 6 shows a schematic diagram of a an exemplary drilling system
600 that can utilize a drilling assembly 690 made according to an embodiment
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CA 02501736 2000-08-04
of the present invention. A drill string 620 that has the drilling assembly
690
attached to a bottom end thereof is conveyed in a borehole 626 by a tubing 607
from a surface location 609. The drilling system 600 includes a conventional
derrick 611 erected on a floor 612 which supports a rotary table 614 that is
rotated by a prime mover such as an electric motor (not shown) at a desired
rotational speed. The drill string 620 includes a tubing (drill pipe or coiled-
tubing)
622 extending downward from the surface 612 into the borehole 626. A drill bit
650, attached to the drill string 620 bottom end, disintegrates the geological
formations when it is rotated to drill the borehole 626. The drill string 620
is
coupled to a drawworks 630 via a kelly joint 621, swivel 628 and line 629
through
a pulley 623. . Drawworks 630 is operated to lower the drill pipe 622 and to
control the hook board. A tubing injector 614a and a reel (not shown) are used
instead of the rotary table 614 to inject the BHA into the wellbore when a
coiled-
is used as the tubing 622. The operations of the drawworks 630 and the
tubing
tubing injector 614a are known in the art and are thus not described in detail
herein.
During drilling, a suitable drilling fluid 631 from a mud pit (source) 632 is
circulated under pressure through the drill string 620 by a mud pump 634. The
drilling fluid passes from the mud pump 634 into the drill string 620 via a
desurger 636 and the fluid line 638. The drilling fluid 631 discharges at the
borehole bottom 651 through openings in the drill bit 650. The drilling fluid
631
circulates to the surface though the annular space 627 between the drill
string
620 and the borehole 626 and returns to the mud pit 632 via a return line 635
and drill cutting screen 685 that removes the drill cuttings 686 from the
returning
drilling fluid 631 b. A sensor S{ in line 38 provides information about the
fluid flow
rate. A surface torque sensor S, and a sensor S. associated with the drill
string
620 respectively provide information about the torque and the rotational speed
of the drill string 620. Tubing injection speed is determined from the sensor
S,,
while the sensor S, provides the hook load of the drill string 620.
A downhole motor 655 (mud motor) is disposed in the drilling assembly
690 to rotate the drill bit 650. The ROP for a given BHA largely depends on
the
WOB or the trust force on the drill bit 650 and its rotational speed. The mud
motor 655 is coupled to the drill bit 650 via a drive shaft 666 disposed in a
bearing assembly 657. The mud motor 655 rotates the drill bit 650 when the
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driiling fluid 631 passes through the mud motor 655 under pressure. The
bearing assembly 657 supports the radial and axial forces of the drill bit
650, the
downthrust of the mud motor 655 and the reactive upward ioading from the
applied weight on bit. A lower stabilizer 658 coupled to the bearing assembly
657 acts as a centralizer for the lowermost portion of the drill string 620.
A surface control unit or processor 640 receives signals from the
downhole sensors and devices via a sensor placed in the fluid line 638 and
signals from other sensors used in the system 600 and processes such signals
according to programmed instructions provided to the surface control unit 640.
The surface control unit 640 displays desired drilling parameters and other
infomtiation on a display/monitor 642 that is utilized by an operator to
control the
drilling operations. The surface control unit 640 contains a computer, memory
for storing data, recorder for recording data and other necessary peripherals.
The surface control unit 640 also may include a simulation model and processes
data according to programmed instructions. The control unit 640 is preferably
adapted to activate alarms 644 when certain unsafe or undesirable operating
conditions occur. The surface control unit 640 communicates with the downhole
controllers described above via a two way communication link. It can provide
command signals to the downhole controfler, alterthe downhole stored programs
and process data received from the downhole controllers. The downhole
controllers and the surface controller 640 cooperate with each other to
optimize
the drilling of the welibore.
The foregoing description is directed to particular embodiments of the
present invention for the purpose of illustration and explanation. It will be
apparent, however, to one skilled in the art that many modifications and
changes
to the embodiment set forth above are possible without departing from the
scope
and the spirit of the invention. It is intended that the following claims be
interpreted to embrace all such modifications and changes.
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