Downhole Drilling Motor and Method of Use
BACKGROUND OF THE INVENTION
The present disclosure relates generally to the field of drilling wells and more
particularly to downhole drilling motors.
In progressive cavity drilling motors, the motor rpm is directly related to the fluid
flow rate through the motor. Each motor size is designed to accommodate a range of fluid
flow rates. In some downhole drilling scenarios, there is a need for changing the fluid
flow rate and/or the rotational speed of bit 150, outside of the design range for the drilling
motor in the drill string. A change out of the motor may be required with the attendant
removal of the drill string from the wellbore. Such changes are costly in terms of rig time.
BRIEF DESCRIPTION OF THE DRAWINGS
FIG. 1 shows a schematic diagram of a drilling system;
FIG. 2 shows a diagram of one embodiment of a downhole motor;
FIG. 3A shows one example of fluid flow through a power section of a downhole
motor;
FIG. 3B shows another example of fluid flow through a power section of a
downhole motor; and
FIG. 4 shows an example of a clutch section of a downhole motor.
DETAILED DESCRIPTION
FIG. 1 shows a schematic diagram of a drilling system 110 having a downhole
assembly according to one embodiment of the present disclosure. As shown, the system
110 includes a conventional derrick 111 erected on a derrick floor 112, which supports a
rotary table 114 that is rotated by a prime mover (not shown) at a desired rotational
speed. A drill string 120 that comprises a drill pipe section 122 extends downward from
rotary table 114 into a directional borehole 126. Borehole 126 may travel in a threedimensional
path. A drill bit 150 is attached to the downhole end of drill string 120 and
disintegrates the geological formation 123 when drill bit 150 is rotated. The drill string
120 is coupled to a drawworks 130 via a kelly joint 121, swivel 128 and line 129 through
a system of pulleys (not shown). During the drilling operations, drawworks 130 is
operated to control the weight on bit 150 and the rate of penetration of drill string 120
into borehole 126. The operation of drawworks 130 is well known in the art and is thus
not described in detail herein.
During drilling operations a suitable drilling fluid (also referred to in the art as
"mud") 131 from a mud pit 132 is circulated under pressure through drill string 120 by a
mud pump 134. Drilling fluid 131 passes from mud pump 134 into drill string 120 via
fluid line 138 and kelly joint 121. Drilling fluid 131 is discharged at the borehole bottom
151 through an opening in drill bit 150. Drilling fluid 131 circulates uphole through the
annular space 127 between drill string 120 and borehole 126 and is discharged into mud
pit 132 via a return line 135. Preferably, a variety of sensors (not shown) are
appropriately deployed on the surface according to known methods in the art to provide
information about various drilling-related parameters, such as fluid flow rate, weight on
bit, hook load, etc.
In one example embodiment of the present disclosure, a bottom hole assembly
(BHA) 159 may comprise a measurement while drilling (MWD) system 158 comprising
various sensors to provide information about the formation 123 and downhole drilling
parameters. BHA 159 may be coupled between the drill bit 150 and the drill pipe 122.
MWD sensors in BHA 159 may include, but are not limited to, a sensors for
measuring the formation resistivity near the drill bit, a gamma ray instrument for
measuring the formation gamma ray intensity, attitude sensors for determining the
inclination and azimuth of the drill string, and pressure sensors for measuring drilling
fluid pressure downhole. The above-noted sensors may transmit data to a downhole
telemetry transmitter 133, which in turn transmits the data uphole to the surface control
unit 140. In one embodiment a mud pulse telemetry technique may be used to
communicate data from downhole sensors and devices during drilling operations. A
transducer 143 placed in the mud supply line 138 detects the mud pulses responsive to
the data transmitted by the downhole transmitter 133. Transducer 143 generates electrical
signals in response to the mud pressure variations and transmits such signals to a surface
control unit 140. Surface control unit 140 may receive signals from downhole sensors and
devices via sensor 143 placed in fluid line 138, and processes such signals according to
programmed instructions stored in a memory, or other data storage unit, in data
communication with surface control unit 140. Surface control unit 140 may display
desired drilling parameters and other information on a display/monitor 142 which may be
used by an operator to control the drilling operations. Surface control unit 140 may
contain a computer, a memory for storing data, a data recorder, and other peripherals.
Surface control unit 140 may also have drilling, log interpretation, and directional models
stored therein and may process data according to programmed instructions, and respond
to user commands entered through a suitable input device, such as a keyboard (not
shown).
In other embodiments, other telemetry techniques such as electromagnetic and/or
acoustic techniques, or any other suitable technique known in the art may be utilized for
the purposes of this invention. In one embodiment, hard-wired drill pipe may be used to
communicate between the surface and downhole devices. In one example, combinations
of the techniques described may be used. In one embodiment, a surface transmitter
receiver 180 communicates with downhole tools using any of the transmission techniques
described, for example a mud pulse telemetry technique. This may enable two-way
communication between surface control unit 140 and the downhole tools described
below.
In one embodiment, a downhole drilling motor 190 is included in drill string 120.
Downhole drilling motor 190 may be a fluid driven, progressive cavity drilling motor of
the Moineau type that uses drilling fluid to rotate an output shaft that is operatively
coupled to drill bit 150. These devices are well known in the art and have a helical rotor
within the cavity of a stator that is connected to the housing of the motor. As the drilling
fluid is pumped down through the motor, the fluid rotates the rotor. In some
embodiments, the rotation of bit 150 may be the combination of rotation of drill string
120 and the rotation of the motor shaft. In progressive cavity drilling motors, the motor
rpm is directly related to the fluid flow rate through the motor. Each motor size is
designed to accommodate a range of fluid flow rates. In some downhole drilling
scenarios, there is a need for changing the fluid flow rate and/or the rotational speed of
bit 150, outside of the design range for the drilling motor in the drill string. A change out
of the motor may be required with the attendant removal of the drill string from the
wellbore. Such changes are costly in terms of rig time.
In one embodiment of the present disclosure, see FIG. 2, drilling motor 190
comprises a power section 191 that provides two different rotor/stator combinations.
Housing 200 is connected in drill string 122. An elastomer stator 201 is adhered to the
inner surface of housing 200. Stator 201 has an inner helically shaped cavity 221 with a
first number 1 of lobes 222 formed along the cavity 221. A dual purpose, helical
shaped, hollow shaft 202 is positioned in the cavity 221. The dual purpose hollow shaft
202 is formed with a second number N2 of lobes 225 on an outer surface to form a first
rotor 260, where N2=N1-1. There is an interference seal between the stator lobes 222 of
the first stator 201 and the lobes 225 of the first rotor 260. When drilling fluid 131A
flows through the passages between the first stator 201 and the first rotor 260, rotor 260
is forced to rotate relative to first stator 201 . Dual purpose hollow shaft 202 may be
formed from a metallic material, for example, steel, stainless steel, nickel based alloys,
aluminum, and titanium.
The dual purpose hollow shaft 202 also has a second elastomer stator 203 adhered
on an inner surface thereof, forming a second cavity 240, where the second elastomer
stator has a third number N3 of lobes 224 where N3 is the same as the number of lobes
N2 of the first rotor 260. Similarly, there is a second helical shaped rotor 204 positioned
within cavity 240 of second stator 203. Second rotor 204 has a fourth number N4 of lobes
241 where N4= N3-1. There is an interference seal between the stator lobes 224 of the
second stator 203 and the lobes 241 of the second rotor 204. When drilling fluid 13 IB
flows through the passages between the second stator 203 and the second rotor 204,
second rotor 260 is forced to rotate relative to second stator 203. Second rotor 204 may
be formed from a metallic material, for example, steel, stainless steel, nickel based alloys,
aluminum, and titanium.
Drilling fluid 131 may be diverted to one of: first flow cavity 221, second flow
cavity 240, and both first flow cavity 221 and second flow cavity 240 simultaneously, by
a controllable flow selector 210 in the upstream flow passage. Dual purpose hollow shaft
202 has a flexible conduit 205 that extends form the end of shaft 202 to controllable flow
selector 210. Flexible conduit 205 may be coupled to controllable flow selector 210 by a
rotating fluid coupling (not shown). This allows conduit 205 to rotate with shaft 202
while maintaining a flow separation between cavities 221 and 240, when desired. A first
controller 230 may be operably connected to flow selector 210 to control the flow
selection. In one embodiment, controller 230 may receive instructions from the surface
via telemetry from the surface as described above. In another example, first controller
230 may receive instructions via a flowable device, for example a radio frequency
identification device (RFID) 291 that is inserted in the flow stream. RFID 291 may
contain instructions that are transmitted to RFID receiver 290 operably connected to first
controller 230. RFID's are known in the art and are not described herein in detail.
Controllable flow selector 210 may comprise internal flow channeling through the use of
sliding sleeves and/or actuatable valve elements to suitably divert the fluid flow, as
directed. This capability provides for a wider range of suitable RPM and bit torques over
a wider range of fluid flow rates than would be possible with a single configuration
drilling motor.
FIGS. 3A and 3B show axial views of power section 190 with the fluid flowing
through the two different flow cavities. FIG. 3A demonstrates flow through first flow
cavity 221 . Here, the first stator 201 has three lobes 222, and the first rotor 260 has two
lobes 225. Fluid flows only through first flow cavity 221, and first rotor 260 rotates with
respect to first stator 201 at a rotational speed of RPM 1. In FIG. 3B, second rotor 204 has
a single lobe while second stator 203 has 2 lobes. Fluid flows only through second flow
cavity 240, and only second rotor 204 rotates with respect to second stator 203 at a
rotational speed RPM2. Second stator 203 does not rotate with respect to housing 200.
When fluid flows through both flow cavities 221, 240 each rotor 260, 204 rotates with
respect to its related stator 201, 203. This causes rotor 204 to rotate at an additive speed
of RPM3=RPM 1+RPM2.
Flexible shafts 206 and 207 couple first rotor 260 and second rotor 204,
respectively, through a controllable clutch 220 to output shaft 270 that is operably
coupled to bit 150. In one example, see FIG. 4, controllable clutch 220 comprises a
positive engagement clutch, sometimes referred to as a dog clutch. As shown in FIG. 4,
flexible shafts 206 and 207 are selectably engaged with engagement collar 403.
Engagement collar 403 has an internal spline 409 that is engageable with spline 415 on
the end of output shaft 270. In addition, engagement collar 403 has an external spline
formed on an end closes to power sectionl91. Flexible shaft 207 has an external spline
408 formed thereon. Flexible shaft 206 has an internal spline 401 formed thereon. By
controllably axially moving engagement collar 403, either shaft 206 or shaft 207 may be
selectably engaged with output shaft 270 to drive drill bit 150.
Engagement collar 403 is axially movable by extension and retraction of yoke
405. Yoke 405 is coupled to linear actuator 406 that is operably connected to second
controller 407. Controller 407 may be in data communication with first controller 290 to
coordinate the operation of flow selector 210 and clutch 220 to provide the appropriate
output to drill bit 150. Communication may be by any short hop communication system
known on the art, for example, acoustic communication, radio frequency communication,
and hard wired communication.
In one embodiment, a conductive coil may be placed around the inner
circumference of housing 200 such that the rotation of first rotor 260 and/or second rotor
204 induce a voltage that may be used for powering downhole controllers 407 and/or 290
and other downhole tools and sensors.
Numerous other modifications, equivalents, and alternatives, will become
apparent to those skilled in the art once the above disclosure is fully appreciated. It is
intended that the following claims be interpreted to embrace all such modifications,
equivalents, and alternatives where applicable.

Claims
1. A downhole drilling motor comprising:
a tubular housing in a drillstring;
a first elastomer stator molded to an inner surface of the housing, the first
elastomer stator having a first helical shaped cavity with a first number of lobes formed
therein;
a dual purpose, helical shaped hollow member positioned within the first
elastomer stator, the dual purpose hollow member having a second number of lobes
formed on an external surface to form a first rotor where the second number of lobes of
the first rotor is one less than the first number of lobes of the first stator;
a second elastomer stator molded to an inner surface of the dual purpose
helical shaped hollow member, the second elastomer stator having a second helical
shaped cavity with the second number of lobes; and
a second helical shaped rotor positioned within the second helical cavity,
the second helical shaped rotor having a third number of lobes wherein the third number
of lobes is one less than the second number of lobes.
2. The progressive cavity drilling motor of claim 1 further comprising a flow
selector in a top end of the housing, the flow selector operable to direct drilling fluid
through at least one of: the first helical shaped cavity; the second helical shaped cavity;
and both the first helical shaped cavity and the second helical shaped cavity.
3. The progressive cavity drilling motor of claim 2 further comprising a first flexible
shaft operably connected to a lower end of the helical shaped hollow member, and a
second flexible shaft operably connected to a lower end of the helical shaped second
rotor.
4. The progressive cavity drilling motor of claim 3 further comprising a controllable
clutch operably coupled to the first flexible shaft and the second flexible shaft, the clutch
actuatable to operably couple at least one of the first flexible shaft and the second flexible
shaft to an ouput shaft.
5. The progressive cavity drilling motor of claim 4 further comprising at least one
controller operably controller connected to at least one of the flow selector and the clutch.
6. The progressive cavity drilling motor of claim 5 further comprising at least one
radio frequency identification device receiver operably coupled to the at least one
controller.
7. The progressive cavity drilling motor of claim 1 further comprising a conductive
coil positioned around an inner circumference of the housing to generate electricity when
at least one of the first rotor and the second rotor rotates.
8. A method of drilling a well with a downhole drilling motor comprising:
positioning a tubular housing in a drillstring;
molding a first elastomer stator to an inner surface of the housing, the first
elastomer stator having a first helical shaped cavity with a first number of lobes formed
therein;
positioning a dual purpose, helical shaped hollow member within the first
elastomer stator, the dual purpose hollow member having a second number of lobes
formed on an external surface to form a first rotor where the second number of lobes of
the first rotor is one less than the first number of lobes of the first stator;
molding a second elastomer stator to an inner surface of the dual purpose
helical shaped hollow member, the second elastomer stator having a second helical
shaped cavity with the second number of lobes; and
positioning a second helical shaped rotor within the second helical cavity,
the second helical shaped rotor having a third number of lobes wherein the third number
of lobes is one less than the second number of lobes.
9. The method of claim 8 further comprising directing a drilling fluid through at
least one of: the first helical shaped cavity; the second helical shaped cavity; and both the
first helical shaped cavity and the second helical shaped cavity, to rotate at least one of
the first rotor and the second rotor.
10. The method of claim 9 further comprising operably connecting a first flexible
shaft to a lower end of the helical shaped hollow member, and a second flexible shaft to a
lower end of the helical shaped second rotor.
11. The method of claim 10 further comprising a operably coupling a controllable
clutch to the first flexible shaft and the second flexible shaft, the clutch actuatable to
operably couple at least one of the first flexible shaft and the second fiexible shaft to an
output shaft.
12. The method of claim 11 further comprising operably controlling at least one of
the flow selector and the clutch.
13. The method of claim 1 further comprising operating at least one the flow
selector and the clutch according to instructions received from at least one radio
frequency identification device transported in the wellbore.
14. The method of claim 8 further comprising generating electrical power from a
conductive coil positioned around an inner circumference of the housing when at least
one of the first rotor and the second rotor rotates.