U.S. patent application number 14/076698 was filed with the patent office on 2015-05-14 for motor integrated reamer.
This patent application is currently assigned to BAKER HUGHES INCORPORATED. The applicant listed for this patent is Jan Lukas Herlitzius, Thorsten Regener. Invention is credited to Jan Lukas Herlitzius, Thorsten Regener.
Application Number | 20150129311 14/076698 |
Document ID | / |
Family ID | 53042186 |
Filed Date | 2015-05-14 |
United States Patent
Application |
20150129311 |
Kind Code |
A1 |
Regener; Thorsten ; et
al. |
May 14, 2015 |
Motor Integrated Reamer
Abstract
In one aspect, an apparatus for use in a wellbore is disclosed
that in one non-limiting embodiment may include a drive system
coupled to a drill bit by a drive sub for drilling a wellbore,
wherein the drive system has an associated bend for directional
drilling of the wellbore, and a reamer driven by the drive sub,
wherein the reamer reams a ledge formed at a transition from a
larger diameter wellbore to a smaller diameter of the wellbore
during directional drilling of the wellbore.
Inventors: |
Regener; Thorsten;
(Wienhausen, DE) ; Herlitzius; Jan Lukas;
(Hannover, DE) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Regener; Thorsten
Herlitzius; Jan Lukas |
Wienhausen
Hannover |
|
DE
DE |
|
|
Assignee: |
BAKER HUGHES INCORPORATED
HOUSTON
TX
|
Family ID: |
53042186 |
Appl. No.: |
14/076698 |
Filed: |
November 11, 2013 |
Current U.S.
Class: |
175/61 ; 175/57;
175/92 |
Current CPC
Class: |
E21B 4/006 20130101;
E21B 7/00 20130101; E21B 7/28 20130101; E21B 4/003 20130101; E21B
4/02 20130101; E21B 7/067 20130101; E21B 7/04 20130101; E21B 3/00
20130101 |
Class at
Publication: |
175/61 ; 175/92;
175/57 |
International
Class: |
E21B 4/00 20060101
E21B004/00; E21B 7/04 20060101 E21B007/04; E21B 7/00 20060101
E21B007/00; E21B 3/00 20060101 E21B003/00 |
Claims
1. An apparatus for use in a wellbore, comprising: a drive system
coupled to a drill bit by a drive sub for drilling a wellbore,
wherein the apparatus includes an associated bend for directional
drilling of the wellbore; and a reamer driven by the drive sub,
wherein the reamer reams a ledge formed at a transition from a
larger diameter wellbore to a smaller diameter of the wellbore
during directional drilling of the wellbore.
2. The apparatus of claim 1 further comprising a reamer drive
coupled to the drive sub that rotates the reamer as the drive sub
rotates.
3. The apparatus of claim 2 further comprising a bearing section on
the drive sub and wherein the reamer drive is placed on the bearing
section.
4. The apparatus of claim 2, wherein the reamer drive comprises: a
first gear wheel coupled to the drive sub, wherein the first gear
wheel rotates when the drive sub rotates; and a second gear wheel
coupled to the first gear wheel and the reamer, wherein the second
gear wheel rotates when the first gear wheel rotates to cause the
reamer to rotate.
5. The apparatus of claim 4, wherein rotational speed of the reamer
is defined at least in part by sizes of the first gear wheel and
the second gear wheel.
6. The apparatus of claim 1 further comprising: a stabilizing
device uphole of the reamer; and wherein outside diameter of the
reamer is equal to or less than outside diameter of the stabilizing
device and less than outside diameter of the drill bit.
7. The apparatus of claim 4, wherein the reamer drive contains
seals separating the pressure level inside the bearing assembly
from the pressure level inside the annulus between the reamer and
the wellbore.
8. The apparatus of claim 4, wherein the second gear is in a sealed
housing with a lubricant therein.
9. The apparatus of claim 1, wherein the drive system includes one
of: a drilling motor and a turbine.
10. The apparatus of claim 4, wherein the second gear wheel is
placed inside a housing that is sealed to the inside of the bearing
assembly and includes at least one mud port to allow passage of a
coolant through the bearing assembly.
11. The apparatus of claim 10 further comprising additional seals
to generate an encapsulated cavity for the gear wheels to contain a
lubricant to provide lubrication to the reamer drive.
12. A drilling system for directional drilling of a wellbore,
comprising; a drilling assembly conveyable by a rotatable conveying
member, wherein the drilling assembly includes: a drive system
coupled to a drill bit by a drive sub for drilling a wellbore,
wherein the drilling assembly has an associated bend for
directional drilling of the wellbore; and a reamer driven by the
drive sub, wherein the reamer reams a ledge formed at a transition
from a larger diameter wellbore to a smaller diameter of the
wellbore during directional drilling of the wellbore.
13. The drilling system of claim 12 further comprising a reamer
drive coupled to the drive sub that rotates the reamer as the drive
sub rotates.
14. The drilling system of claim 13, wherein the reamer drive
comprises: a first gear wheel coupled to a drive sub, wherein the
first gear wheel rotates when the drive shaft rotates; and a second
gear wheel coupled to the first gear wheel and the reamer, wherein
the second gear wheel rotates when the first gear wheel rotates to
cause the reamer to rotate.
15. The drilling system of claim 12 further comprising a sensor for
providing measurements relating to a property of interest during
drilling of the wellbore.
16. The drilling system of claim 12, wherein the drive system
includes one of a motor and a turbine.
17. A method of drilling a wellbore, the method comprising:
conveying a drilling assembly by a rotatable conveying member into
a wellbore, the drilling assembly including a drive system coupled
to a drill bit, an associated bend, and a reamer downhole of the
stabilizing device; drilling the wellbore by rotating the drill bit
with the rotatable conveying member and the drive system to form a
first section having a first size; and drilling the wellbore by
rotating the drill bit by only the drive system to form a second
section of the wellbore, wherein transition from the first section
to the second section includes a ledge; and utilizing the reamer to
reduce the ledge to form the wellbore.
18. The method of claim 17 further comprising determining one or
more downhole parameters of interest during drilling of the
wellbore and utilizing the determined one or more parameters of
interest to form a deviated wellbore.
19. The method of claim 17, wherein the drilling assembly includes
a stabilizing device and the outside diameter of the reamer is
equal to or less than the outside diameter of the stabilizing
device and less than the outside diameter of the drill bit.
20. The method of claim 17, wherein the reamer is driven by a
reamer drive that includes: a first gear wheel coupled to the drive
sub, wherein the first gear wheel rotates when the drive sub
rotates; and a second gear wheel coupled to the first gear wheel
and the reamer, wherein the second gear wheel rotates when the
first gear wheel rotates to cause the reamer to rotate.
Description
BACKGROUND
[0001] 1. Field of the Disclosure
[0002] This disclosure relates generally to drilling assemblies for
drilling directional wellbore.
[0003] 2. Background of the Art
[0004] To obtain hydrocarbons, such as oil and gas, boreholes or
wellbores are drilled by rotating a drill bit attached to a drill
string end. A large proportion of the current drilling activity
involves drilling deviated and horizontal wellbores (directional
wellbores) for hydrocarbon production. Drilling systems include a
drill string that has a drilling assembly (commonly referred to as
bottomhole assembly or "BHA") that includes a drill bit attached to
an end thereof. The BHA includes a number of sensors, such as
pressure, temperature, vibration and azimuthal sensors (commonly
referred to a measurement-while-drilling (MWD) sensors) and tools
for determining various properties of the earth formation (commonly
referred to as logging-while-drilling "LWD" tool). BHA often
includes a directional drilling device, which may be a bent sub or
force application devices, such as ribs. For directional drilling,
the BHA typically includes a motor, such as a positive displacement
motor, driven by a drilling fluid (also referred to herein as the
"mud motor" or "drilling motor") to rotate the drill bit. Typically
a bent sub is integrated in the motor. There are two operating
modes for directional drilling with bent motors. The first is mode
is the slide mode. In the slide mode, the drill string is not
rotated. The motor drills a curved section (in-gauge hole). The
bend generates a side force at the drill bit, deflecting the drill
string. The second mode is the tangent mode. In the tangent mode,
the drill string is rotated. The bend and the side force do not
have a deflecting impact on the drill string. The motor drills
straight ahead, but due to the bend, the hole is slightly
oversized. If the next section is drilled in the slide mode, a
ledge may be generated at the transition from the oversized hole to
the in-gauge hole, which may cause a stabilizer commonly used on a
bearing housing to hang up. This phenomenon has led to the use of
slick motors, which however, provide less directional control.
[0005] The disclosure herein provides apparatus and methods that
reduce or eliminates the ledge and, thus, the potential hanging of
the bearing housing stabilizer.
SUMMARY OF THE DISCLOSURE
[0006] In one aspect, an apparatus for use in a wellbore is
disclosed that in one non-limiting embodiment may include a motor
coupled to a drill bit by a drive sub for drilling a wellbore,
wherein the motor has an associated bend for directional drilling
of the wellbore, and a reamer driven by the drive sub, wherein the
reamer reams a ledge formed at a transition from a larger diameter
wellbore to a smaller diameter of the wellbore during directional
drilling of the wellbore.
[0007] In another aspect, a method of drilling a wellbore is
disclosed that in one non-limiting embodiment may include:
conveying a drilling assembly by a rotatable conveying member into
a wellbore, the drilling assembly including a motor coupled to a
drill bit, wherein the motor has an associated bend, a stabilizer,
and a reamer downhole of the stabilizer; drilling the wellbore by
rotating the drill bit by the rotatable conveying member and the
motor to form a first section having a first size; and drilling the
wellbore by rotating the drill bit by the motor only to form a
second section of the wellbore, wherein transition from the first
section to the second section includes a ledge; and utilizing the
reamer to reduce the ledge to form the wellbore.
[0008] Examples of certain features of the apparatus and method
disclosed herein are summarized rather broadly in order that the
detailed description thereof that follows may be better understood.
There are, of course, additional features of the apparatus and
method disclosed hereinafter that will form the subject of the
claims appended hereto.
BRIEF DESCRIPTION OF THE DRAWINGS
[0009] The disclosure herein is best understood with reference to
the accompanying figures in which like numerals have generally been
assigned to like elements and in which:
[0010] FIG. 1 is an elevation view of a drilling system that
includes a motor integrated reamer according to one non-limiting
embodiment of the disclosure drilling a wellbore;
[0011] FIG. 2 shows placement of the motor and reamer on a drill
collar, according to one non-limiting embodiment of the
disclosure;
[0012] FIG. 3 shows an isometric cut-away view of the mechanism for
driving the rotor by the motor, according to one non-limiting
environment of the disclosure; and
[0013] FIG. 4 shows a simplified cross-section view of the device
shown in FIG. 3.
DESCRIPTION OF THE EMBODIMENTS
[0014] FIG. 1 is a schematic diagram of an exemplary drilling
system 100 that includes a drill string 120 having a drilling
assembly or a bottom hole assembly 190 attached to its bottom end.
Drill string 120 is shown conveyed in a wellbore or borehole 126
being formed in a subsurface formation 195. The drilling system 100
includes a conventional derrick 111 erected on a platform or floor
112 that supports a rotary table 114 that is rotated by a prime
mover, such as an electric motor (not shown), at a desired
rotational speed. A tubing (such as jointed drill pipe) 122, having
the drilling assembly 190 attached at its bottom end, extends from
the surface to the bottom 151 of the borehole 126. A drill bit 150,
attached to drilling assembly 190, disintegrates the geological
formations when it is rotated to drill the borehole 126. The drill
string 120 is coupled to a draw works 130 via a Kelly joint 121,
swivel 128 and line 129 through a pulley. Draw works 130 is
operated to control the weight on bit ("WOB"). The drill string 120
may be rotated by a top drive 114a rather than the prime mover and
the rotary table 114.
[0015] In one aspect, the drill bit 150 is rotated by rotating the
drill pipe 122. In another aspect, a drive system, such as downhole
motor 160 (mud motor) disposed in the drilling assembly 190 is
utilized to rotate the drill bit 150 alone or in addition to the
drill string rotation. The drilling motor 160 includes a rotor that
rotates a drive sub connected to the drill bit 150 (described later
in reference to FIG. 2). Alternatively, the drive system may
include any other suitable device, including, but not limited to, a
turbine.
[0016] In one aspect, a suitable drilling fluid 131 (also referred
to as the "mud") from a source 132 thereof, such as a mud pit, is
circulated under pressure through the drill string 120 by a mud
pump 134. The drilling fluid 131 passes from the mud pump 134 into
the drill string 120 via a desurger 136 and a fluid line 138. The
drilling fluid 131a from the drilling tubular 122 discharges at the
borehole bottom 151 through openings in the drill bit 150. The
returning drilling fluid 131b circulates uphole through the annular
space or annulus 127 between the drill string 120 and the borehole
126 and returns to the mud pit 132 via a return line 135 and a
screen 185 that removes the drill cuttings from the returning
drilling fluid 131b. A sensor S.sub.1 in line 138 provides
information about the flow rate of the fluid 131. Surface torque
sensor S.sub.2 and a sensor S.sub.3 associated with the drill
string 120 provide information about the torque and the rotational
speed of the drill string 120. Rate of penetration of the drill
string 120 may be determined from sensor S.sub.5, while the sensor
S.sub.6 may provide the hook load of the drill string 120. Other
sensors may be utilized to provide information about other
parameters of interest.
[0017] Still referring to FIG. 1, a surface control unit or
controller 140 receives signals from downhole sensors and devices
or tools via a sensor 143 placed in the fluid line 138 and signals
from sensors S.sub.1-S.sub.6 and other sensors used in the system
100 and processes such signals according to programmed instructions
provided by a program to the surface control unit 140. The surface
control unit 140 displays desired drilling parameters and other
information on a display/monitor 141 that is utilized by an
operator to control the drilling operations. The surface control
unit 140 may be a computer-based unit that may include a processor
142 (such as a microprocessor), a storage device 144, such as a
solid-state memory, tape or hard disc, etc., and one or more
computer programs 146 in the storage device 144 accessible to the
processor 142 for executing instructions contained in such
programs. The surface control unit 140 may further communicate with
a remote control unit 148. The surface control unit 140 may process
data relating to the drilling operations, data from the sensors and
devices on the surface, data received from downhole devices and may
control one or more operations of the drilling system 100.
[0018] Still referring to FIG. 1, the drilling assembly 190 may
also contain formation evaluation sensors or devices (also referred
to as measurement-while-drilling, "MWD," or logging-while-drilling,
"LWD," sensors) various properties of interest, such as
resistivity, density, porosity, permeability, acoustic properties,
nuclear-magnetic resonance properties, corrosive properties of the
fluids or the formation, salt or saline content, and other selected
properties of the formation 195 surrounding the drilling assembly
190. Such sensors are generally known in the art and for
convenience are collectively denoted herein by numeral 165. The
drilling assembly 190 may further include a variety of other
sensors and communication devices 159 for controlling and/or
determining one or more functions and properties of the drilling
assembly 190 (such as velocity, vibration, bending moment,
acceleration, oscillations, whirl, stick-slip, etc.) and drilling
operating parameters, such as weight-on-bit, fluid flow rate,
pressure, temperature, rate of penetration, azimuth, tool face,
drill bit rotation, etc. The drill string 120 further includes a
power generation device 178 configured to provide electrical power
or energy to sensors 165 and other devices 159 and other devices. A
downhole controller 170 may be provided to process signals from the
various sensors and devices in the drilling assembly 190 and to
provide information about various parameters of interest and to
provide two-way communication with the surface controller 140. In
one aspect, the downhole controller 170 may include a processor
172, such as a microprocessor, one or more storage devices 174,
such as solid state memories, and programs 176 accessible to the
processor 172 for executing instructions contained therein.
[0019] Still referring to FIG. 1, the drilling motor 160 includes a
bend 180, known in the art, for drilling a deviated wellbore
(directional drilling). Drilling motor 160 also includes a
stabilizing device 182 on a housing 183 of the drilling motor 160
below the power section 155. The stabilizing device may include any
suitable device known in the art, including, but not limited to, a
stabilizer and kick pads. The power section 155 is connected to a
drive sub (described later), which is connected to the drill bit
150. In one non-limiting embodiment, the drilling motor 160 further
includes a reamer 185 below the stabilizer 182 to prevent or reduce
the forming of a ledge during directional drilling described in
more detail in reference to FIGS. 2-4.
[0020] FIG. 2 shows a section of the motor (160, FIG. 1) that
includes the power section 155 that drives a drive sub 225 inside
the stabilizer 182 and reamer 185. As shown in FIG. 2, the power
section 155 includes an outer housing 212 that may be lined with an
elastomeric stator 214 having a number of internal lobes 214a and a
solid rotor 216 having external lobes 216a that rotate inside the
stator 214. When a fluid 250, such as drilling fluid or drilling
mud, under pressure is supplied to the motor 155, the fluid passes
through cavities 218 formed between the stator 214 and the rotor
216, causing the rotor 216 to rotate. The rotor 216 is coupled to a
drive sub 225 by a transmission element (not shown). The drill bit
150 is connected to the drive sub 225 via a box end, known in the
art. In the particular configuration of the device of FIG. 2, the
stabilizer 182 is provided below the power section 155 and the
reamer 185 below or downhole of the stabilizer 182. The reamer 185
includes suitable cutters 240 configured to cut the rock formation.
Cutters of various types are known in the art and are thus not
described in any detail herein. In one configuration, the reamer
185 may have the shape of a ring, as shown in FIG. 2. The reamer
185, however, may be configured to have any other suitable shape
and may include any one or more types of cutters, known in the art.
In one aspect, the reamer 185 is rotated by a mechanism (also
referred to herein as the "reamer drive" or "drive mechanism")
operated by the power section 155 via the drive sub 225, as
described below in more detail in reference to FIGS. 3 and 4.
[0021] FIG. 3 shows a cut-away view of a non-limiting embodiment of
a reamer drive 300 driven by the power section 155 via the drive
sub 225. FIG. 4 shows a simplified cross-section view of the device
shown in FIG. 3. The drive sub 225 is connected to the rotor (216,
FIG. 2) of the power section (155, FIG. 2) and, thus, it rotates as
the motor rotates. The drive shaft is supported by axial bearings
327 (only downhole side bearings shown) and radial bearings (not
shown) of a bearing assembly 329 inside a housing 302 of the
drilling motor 160. In one non-limiting embodiment, the reamer
drive 300 includes a first or inner gear wheel 310 on the drive sub
225. The inner gear wheel has outer teeth 312 and it rotates when
the drive sub 225 rotates. Thus, rotating the drive sub 225 by the
motor rotates the inner wheel 310 and hence teeth 312. The reamer
drive 300 also includes a second or outer gear wheel 330 disposed
in a gear wheel housing 342 containing a number of seals 344,
separating the drilling fluid 250 under high pressure inside the
bearing assembly 329 from the drilling fluid 250 under lower
pressure in the annulus. Thus, in one aspect, the reamer drive
contains seals that the pressure level inside the bearing assembly
from the pressure level inside the annulus between the reamer and
the wellbore. In an alternative embodiment, the gear wheel housing
342 may be completely sealed from the drilling fluid 131 allowing
to use a lubricant such as oil. The outer gear wheel 330 includes
teeth 332 that on one end 332a engage with the teeth 312 of the
inner gear wheel 310 and on the other end 332b engage with teeth
387 on the inside of the reamer 185. Thus, when the drive sub 225
rotates, the inner wheel 310 on the drive sub 225 rotates, which
rotates the outer wheel 330 and which in turn rotates the reamer
185. The ratio of the gears or teeth of inner gear wheel 310, the
outer gear wheel 330 and the reamer 185 may be adjusted to provide
a desired rotational speed (rpm) of the reamer 185 relative to the
rotation of the drive sub 225. In one aspect, the gear wheel
housing 342 includes one or more ports or fluid passages 350 on
opposite sides 336a and 336b of the gear wheel housing 342 to allow
for the flow of the drilling fluid or mud 250 through the reamer
drive 300. Flow of the fluid 250 through the reamer drive 300 is
shown by arrows 360. The seals 344 separate the pressure level
inside the bearing assembly from the pressure in the annulus.
[0022] Thus, in one aspect, a motor integrated reamer 185 is
disclosed that in one non-limiting embodiment may be disposed on or
integrated in a bearing assembly 329 below a stabilizer 182. The
reamer 185 also herein is referred to as the motor integrated
reamer. In one aspect, the reamer 185 is rotated by the power
section 155 via a first gear wheel 310 on the drive sub 225, which
rotates a second gear wheel 330 engaged to an inner teeth on the
reamer 185. The second gear wheel 330 sits inside a housing 342,
but has mud ports 350 integrated in the gear wheel housing 342 to
allow passage of a coolant through the bearing assembly. The
cutters 240 on the downhole side of the reamer 185 ream the ledge
formed at the transition of the over-gauge wellbore (wellbore
formed when the drill string is rotating) to the in-gauge wellbore
(wellbore formed when the drill string is not rotating). Once the
reamer 185 and the stabilizer 182 have passed the ledge, the
contact to the borehole is on the stabilizer 182 and the reamer
rotates idle, because the reamer outside diameter is less than the
diameter of the stabilizer.
[0023] While the foregoing disclosure is directed to the certain
non-limiting exemplary embodiments of the disclosure, various
modifications will be apparent to those skilled in the art. It is
intended that all variations within the scope and spirit of the
appended claims be embraced by the foregoing disclosure.
* * * * *