U.S. patent application number 13/797875 was filed with the patent office on 2014-09-18 for rotary steerable system for vertical drilling.
The applicant listed for this patent is Weatherford/Lamb, Inc.. Invention is credited to Daniel Andrew Marson, John Mackinley Pagett, Daniel Mark Sullivan.
Application Number | 20140262507 13/797875 |
Document ID | / |
Family ID | 50230958 |
Filed Date | 2014-09-18 |
United States Patent
Application |
20140262507 |
Kind Code |
A1 |
Marson; Daniel Andrew ; et
al. |
September 18, 2014 |
ROTARY STEERABLE SYSTEM FOR VERTICAL DRILLING
Abstract
A rotary steerable drilling system that is operable to drill
vertical wellbores and automatically maintain a vertical wellbore
drilling path. The system includes a control module for operating
solenoid valves that control an amount of fluid pressure applied to
bias pad piston/cylinders. The control module is operable to
determine when the system is deviating from vertical, in what
direction the system is deviating, and where the bias pads are in
relation to the direction of deviation. Based on these
determinations, the control module actuates the requisite bias pads
by controlling the amount of fluid pressure applied to the bias pad
piston/cylinders to direct the system back to the vertical drilling
path.
Inventors: |
Marson; Daniel Andrew;
(Sherwood Park, CA) ; Sullivan; Daniel Mark;
(Cheltenham, GB) ; Pagett; John Mackinley;
(Birmingham, GB) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Weatherford/Lamb, Inc. |
Houston |
TX |
US |
|
|
Family ID: |
50230958 |
Appl. No.: |
13/797875 |
Filed: |
March 12, 2013 |
Current U.S.
Class: |
175/24 ;
175/325.1 |
Current CPC
Class: |
E21B 7/062 20130101;
E21B 7/10 20130101; G01D 5/145 20130101; E21B 47/18 20130101; E21B
44/00 20130101; E21B 47/024 20130101; E21B 45/00 20130101; E21B
17/1014 20130101; E21B 47/12 20130101 |
Class at
Publication: |
175/24 ;
175/325.1 |
International
Class: |
E21B 7/10 20060101
E21B007/10; E21B 17/10 20060101 E21B017/10 |
Claims
1. A drilling system, comprising: a control valve; a control module
configured to actuate the control valve; a slip ring configured to
transmit an electronic signal from the control module to the
control valve, while the control module rotates relative to the
control valve; a bias pad having a piston that is in fluid
communication with the control valve, wherein actuation of the
control valve controls an amount of fluid pressure applied to the
piston.
2. A method of forming a wellbore, comprising: drilling a wellbore
along a vertical trajectory using a drilling system; monitoring any
deviation from the vertical trajectory of the wellbore; determining
that the drilling system has deviated from the vertical trajectory;
determining a highside of the wellbore; determining a position of
bias pads of the drilling system; and actuating at least one of the
bias pads to force the drilling system toward the vertical
trajectory.
Description
BACKGROUND OF THE INVENTION
[0001] 1. Field of the Invention
[0002] Embodiments of the invention generally relate to steerable
drilling systems for drilling vertical wellbores.
[0003] 2. Description of the Related Art
[0004] Directional drilling involves varying or controlling the
direction of a wellbore as it is being drilled. Usually the goal of
directional drilling is to reach or maintain a position within a
target subterranean destination or formation with the drilling
string. For instance, the drilling direction may be controlled to
direct the wellbore towards a desired target destination, to
control the wellbore horizontally to maintain it within a desired
payzone, or to correct for unwanted or undesired deviations from a
desired or predetermined path.
[0005] Thus, directional drilling may include deflection or
deviation of a wellbore along a predetermined or desired path in
order to reach or intersect with, or to maintain a position within,
a specific subterranean formation or target. The predetermined path
typically includes a depth where initial deflection or deviation
occurs and a schedule of desired deviation angles and directions
over the remainder of the wellbore. Thus, deflection or deviation
is a change in the direction of the wellbore from the current
wellbore path.
[0006] It is often necessary to adjust the direction of the
wellbore frequently while directional drilling, either to
accommodate a planned change in direction or to compensate for
unintended or unwanted deflection or deviation of the wellbore.
Unwanted deflection or deviation may result from a variety of
factors, including the characteristics of the formation being
drilled, the makeup of the bottomhole drilling assembly, and the
manner in which the wellbore is being drilled.
[0007] Current steerable drilling systems have expensive steerable
equipment and are not cost effective when drilling generally
vertical wellbores that do not require the steerable capabilities.
It is costly for operators to have both conventional drilling
systems for drilling generally vertical wells and steerable
drilling systems for drilling deviated wellbores, and switching
between the two drilling systems as necessary. Most operators
simply use steerable drilling systems for drilling both vertical
and deviated wellbores.
[0008] There is a need, therefore, for steerable drilling systems
that are cost effective and efficient for drilling vertical
wellbores.
SUMMARY OF THE INVENTION
[0009] A rotary steerable drilling system for drilling vertical
wellbores.
BRIEF DESCRIPTION OF THE DRAWINGS
[0010] So that the manner in which the above recited features of
the invention can be understood in detail, a more particular
description of the invention, briefly summarized above, may be had
by reference to embodiments, some of which are illustrated in the
appended drawings. It is to be noted, however, that the appended
drawings illustrate only typical embodiments of this invention and
are therefore not to be considered limiting of its scope, for the
invention may admit to other equally effective embodiments.
[0011] FIGS. 1A and 1B illustrate a rotary steerable drilling
system according to one embodiment.
[0012] FIGS. 2A and 2B illustrate a steerable assembly according to
one embodiment.
[0013] FIGS. 3A-3C illustrate an outer housing assembly for
supporting bias pads.
[0014] FIGS. 4A and 4B illustrate slip ring, control valve, and
pump assemblies of the system according to one embodiment.
[0015] FIG. 5 illustrates an enlarged view of the steerable
assembly according to one embodiment.
[0016] FIG. 6 illustrates the steerable assembly and a collar of
the system according to one embodiment.
[0017] FIG. 7 illustrates an electric/hydraulic schematic of the
system according to one embodiment.
DETAILED DESCRIPTION
[0018] Embodiments of the invention relate to a rotary steerable
drilling system for drilling wellbores. The system is operable to
maintain a substantially vertical wellbore drilling path. If the
system begins to deviate from the vertical drilling path (due to
the wellbore formation characteristics for example), then the
system is operable to automatically self correct and force the
system back toward the vertical drilling path trajectory.
[0019] The system may be a self contained, electronically
controlled, push bit system. The system may be rotated from the
surface and/or may include conventional mud motors for providing
additional rotational drill bit speed. The system may include one
or more individually controllable and replaceable bias pads
operable to force or push the drill bit in a desired direction. The
bias pads may allow direction control of up to 5 percent over-gauge
of the wellbore diameter. In the event of a failure, the system is
designed to have a natural drop tendency to drill vertically.
[0020] FIGS. 1A and 1B illustrate a rotary steerable drilling
system 100 according to one embodiment. The system 100 includes a
drill string 10 for rotating a drill bit 60 from the surface, an
optional hydraulically actuated, straight housing motor 20 for
providing additional rotational speed, and a stabilizer 30 for
maintaining the system 100 within the center of a wellbore while
drilling. The drill string 10 may be coupled to a conventional mud
motor, which is coupled to a barrel collar, or if no motor is used,
the drill string 10 may be coupled to the barrel collar via a drill
collar as known in the art.
[0021] The system 100 further includes a barrel collar, referred to
herein as a control collar 40, for supporting control modules,
power supplies, mud pulsers, valves, measurement/logging while
drilling components, and/or various other components and electronic
packages known in the art. The control collar 40 may include one or
more micro-processors, memories, mass storage devices, and well
known support circuits such as power supplies, clocks, cache,
input/output circuits, and the like. The control collar 40 may
include a control module 41, a power supply 44 (such as a battery),
a pulser driver 45, and a pulser 46. The control collar 40 may be
operable to communicate information to the surface and to one or
more components of the system 100 as further described herein. In
one embodiment, the control collar 40 is operable to transmit data
to the surface via mud pulse telemetry. In one embodiment, the data
may include the inclination and/or the rotational speed of the
system 100.
[0022] The system 100 further includes a self-contained, steerable
assembly 50 having rotating sections 51, 53 and a non-rotating
section 52 disposed between the rotating sections 51, 53. The
rotating section 53 may include a tubular member coupled to the
drill bit 60. The rotating section 51 may include a tubular member
forming a drive shaft 55 that is disposed through the non-rotating
section 52 and that is coupled to the tubular member of the
rotating section 53 for transmitting rotation to the drill bit 60.
An internal bore 110 may be disposed through the system 100 from
the drill string 10 to the drill bit 60.
[0023] FIGS. 2A and 2B illustrate the steerable assembly 50
according to one embodiment. The rotating section 51 may include a
tubular member for coupling the assembly 50 to the control collar
40 via one or more tubular threaded connections. An electrical
connector 57 may be used to electrically connect the control collar
40 to the steerable assembly 50. The drive shaft 55 of the rotating
section 51 may extend through the non-rotating section 52 and may
be threadedly coupled to the tubular member of the rotating section
53. The non-rotating section 52 may include one or more replaceable
bias pads 54 that are supported by an outer housing 58. The outer
housing 58 may be coupled to balance pistons 56 (comprising
pistons/biasing members) disposed at opposite ends, which are
supported by the tubular member of the rotating section 51. The
balance pistons 56 create a sealed chamber and balance the pressure
between the internal components of the steerable assembly 50 with
respect to the surrounding wellbore pressure as known in the
art.
[0024] The steerable assembly 50 may further include a slip ring
assembly 70, a control valve assembly 80, and a pump assembly 90.
The slip ring assembly 70 is operable to communicate between the
control module 41 (illustrated in FIG. 6) in the control collar 40
and the non-rotating control valve assembly 80. The control valve
assembly 80 controls the amount of fluid pressure and thus force
that is applied to each bias pad 54. The pump assembly 90
continuously pumps fluid through the self contained steerable
assembly 50 between a fluid reservoir, the control valve assembly
80, and at least one piston 59 for biasing each bias pad 54 as
further described below.
[0025] FIGS. 3A-3C illustrate the outer housing 58 for supporting
the bias pads 54 and pistons 59 operable to bias the pads 54
radially outward. Three bias pads 54 are symmetrically and
pivotably coupled to the outer housing 58 at a first end 61. The
opposite end of each bias pad 54 may be forced radially outward
into engagement with the surrounding wellbore by the pistons 59. In
one embodiment, the bias pads 54 may be forced directly radially
outward into engagement with the surrounding wellbore as opposed to
be pivoted or rotated radially outward. Each bias pad 54 may be
engaged by one, two, or more pistons 59. The pistons 59 are forced
into engagement with the bias pad 54 using pressurized fluid that
is driven by the pump assembly 90. The amount of fluid pressure
applied to each piston 59 is controlled by the control valve
assembly 80.
[0026] FIGS. 4A and 4B illustrate the control valve assembly 80 and
the pump assembly 90 (with the outer housing 58 removed for
clarity). Each bias pad 54 may be controlled individually by one or
more control valve assemblies 80 and pump assemblies 90. The
control valve assembly 80 may include a support housing 85 for
supporting one or more solenoid valves having a coil 81 and a
plunger 82. The solenoid valves are hydraulically connected to the
pistons 59 of each bias pad 54, and are electrically connected to
the control module 41 of the control collar 40 via the slip ring
assembly 70. The amount of current flowing through the coil 81
determines the position of the plunger 82 for (at least partially)
opening and closing fluid flow into an inlet flow passage 83 and
out of an outlet flow passage 84 formed in the support housing 85.
The inlet flow passage 83 is in fluid communication with the high
pressure side of the pistons 59 acting on the bias pads 54. The
outlet flow passage 84 is in fluid communication with the lower
pressure return side of the fluid reservoir.
[0027] If no current is applied to the coil 81, then the plunger 82
may be moved to a position that permits uninhibited fluid flow from
the inlet flow passage 83 to the outlet flow passage 84, thereby
minimizing the amount of pressure applied to the pistons 59 and
thus applying a minimal, if any, amount of force to the bias pads
54. If a maximum amount of current is applied to the coil 81, then
the plunger 82 may be moved to a position that closes or
substantially restricts fluid flow from the inlet flow passage 83
to the outlet flow passage 84, thereby maximizing the amount of
pressure applied to the pistons 59 and thus applying a maximum
amount of force to the bias pads 54 radially outward into
engagement with the surrounding wellbore. The control module 41 in
the control collar 40 may control the amount of current supplied to
the coil 81 of each individual solenoid valve via the slip ring
assembly 70, thereby controlling the amount of piston force applied
by each bias pad 54 to steer the drill bit 60 in the desired
direction when drilling a wellbore. Any type of solenoid valves or
other similar control valves known in the art may be used for
controlling fluid flow in the steerable assembly 50.
[0028] FIG. 4B further illustrates an optional accumulator assembly
120 for assisting with the amount of fluid pressure applied to each
bias pad 54. The accumulator assembly 120 may include a piston 121
and a biasing member 122, such as a spring. The accumulator
assembly 120 may help dampen pressure fluctuations in the steerable
assembly 50 when actuating the solenoid valves of the control valve
assembly 80. In one embodiment, the accumulator assembly 120 may
include a sensor, such as a pressure transducer, for measuring and
monitoring the pressure applied to each bias pad 54. The sensor may
be in communication with the control module located in the control
collar 40 via the slip ring assembly 70 as further described
herein. In one embodiment, the sensor may include a Hall Effect
sensor, as known in the art, for measuring the position of the
piston 121, calculating the amount of pressure applied to each bias
pad 54, and communicating the measured pressure to the control
module 41.
[0029] Fluid flowing through the self contained steerable assembly
50 is driven by one or more pump assemblies 90 for each bias pad
54. The pump assembly 90 may include swash plate pump as known in
the art. The pump assembly 90 may include a plate member 91
supported by a body 93 that is rotationally coupled to the drive
shaft 55. The plate member 91 is arranged at an eccentric position
or angle relative to the longitudinal axis of the steerable
assembly 50. One or more piston/cylinders 92 positioned parallel to
the longitudinal axis of the steerable assembly 50 are stroked in
and out by rotation of the plate member 91 via the drive shaft 55.
In this manner, the pump assembly 90 continuously pumps fluid
through the self contained steerable assembly 50 during operation
of the system 100. As stated above, the fluid flow driven by the
pump assembly 90 is controlled by the control valve assemblies 80
to selectively actuate the bias pads 54 as desired.
[0030] Further illustrated in FIGS. 4A and 4B is the slip ring
assembly 70 for providing an electrical connection across a
rotating interface. In particular, the control module 41 in the
control collar 40 rotates with the drive shaft 55 and provides
electronic signals to the non-rotating solenoid valves of the
control valve assembly 80. The slip ring assembly 70 includes a
ring member 72 having one or more contact rings (such as copper
rings) that rotate with the drive shaft 55 and that are
electrically connected to the control module 41 of the control
collar 40. The slip ring assembly 70 further includes a support
housing 71 for supporting one or more contact members (such as
brushes) that are non-rotatively coupled to the outer housing 58
and that are electrically connected to the non-rotating solenoid
valves of the control valve assembly 80. One or more seal and/or
bearing members 73 may be disposed between the support housing 71
and the ring member 72. The non-rotating contact members of the
support housing 71 contact the contact rings of the rotating ring
member 72, thereby providing an electrical connection across a
rotating interface. In this manner, electronic signals can be sent
from the control module 41 in the rotating control collar 40 to the
solenoid valves in the non-rotating control valve assembly 80 to
control the bias of the bias pads 54 and thus the direction of the
drill bit 60.
[0031] FIG. 5 illustrates an enlarged view of the steerable
assembly 50. In particular, FIG. 5 illustrates the slip ring
assembly 70, the control valve assembly 80, and the pump assembly
90 disposed within the outer housing 58 that supports the bias pads
54. The drive shaft 55 extends through the slip ring assembly 70,
the control valve assembly 80, the pump assembly 90, and the outer
housing 58.
[0032] FIG. 6 illustrates the steerable assembly 50 coupled to the
control collar 40 by one or more threaded tubular connections. The
control collar 40 encloses the control module 41, a power supply 44
(such as a battery), and the electrical connector 57 for
controlling and continuously monitoring the operation of the system
100. In particular, the control module 41 is operable to maintain
the rotary steerable drilling system 100 in a substantially
vertical wellbore drilling path. While drilling a vertical
wellbore, if the system 100 begins to deviate from the vertical
path (due to the wellbore formation characteristics for example),
then the control module 41 is configured to sense the deviation and
actuate the bias pad 54 as necessary to direct the system 100 back
to the vertical wellbore path trajectory.
[0033] To maintain the system 100 on a vertical drilling path, the
control module 41 includes at least two accelerometers mounted
about 180 degrees apart within the control collar 40, which are
configured to identify the "highside" of the wellbore when deviated
from vertical. The highside of the wellbore is the side of the
wellbore circumference at a specific point along the wellbore that
is closest to the surface when the wellbore deviates from vertical.
When the highside of the wellbore is determined, the system 100 is
forced via the bias pads 54 toward the opposite, lowside of the
wellbore to push the system 100 back to the vertical drilling path.
In one embodiment, the sinusoidal outputs of the accelerometers may
be communicated to the control module 41, which may use the outputs
to calculate and determine where the wellbore is relative to
gravity.
[0034] In addition to determining where the highside of the
wellbore is, the control module 41 determines where each bias pad
54 is located relative to the highside of the wellbore. To
determine the position of each bias pad 54, the control module 41
receives a signal from a sensor 42 (illustrated in FIGS. 4A, 4B,
and 5) that is coupled to the rotating drive shaft 55. The sensor
42 rotates with the drive shaft 55 and senses at least one
stationary marker 43 (illustrated in FIG. 5) that is coupled to the
outer housing 58. Only one stationary marker 43 may be needed to
identify the location of one bias pad 54, while the locations of
the other bias pads 54 can be determined by being disposed about
120 degrees and about 240 degrees apart from the one bias pad 54
and/or stationary marker 43. As the sensor 42 rotates, it senses
the location of each marker 43 and thus each bias pad 54 and
communicates the location to the control module 41. In one
embodiment, the sensor 42 may include a Hall Effect device as known
in the art that produces an electronic pulse once per revolution to
sense and measure the location of the markers 43, which information
is communicated to the control module 41 to calculate and define
the rotational position of each bias pad 54 relative to the
highside of the wellbore.
[0035] Based on the determinations of the highside of the wellbore
and the position of each bias pad 54, the control module 41 can
determine which solenoid valves of the control valve system 80 to
activate to force or push the system 100 back to vertical. The
control module 41 controls the force applied to each specific bias
pad 54 by controlling the actuation of the solenoid valves of the
control valve assembly 80 for each bias pad 54 to direct the system
100 toward the opposite, lowside of the wellbore and back to the
vertical drilling path. The control module 41 can vary the amount
of force applied by each bias pad 54 by controlling the amount of
current supplied to the solenoid valves of the control valve
assembly 80 for each individual bias pad 54.
[0036] FIG. 7 illustrates an electric/hydraulic schematic of the
system 100. The control module 41 is electrically connected to the
solenoid valves of the control valve assembly 80 via the slip ring
assembly 70. The control valve assembly 80 may control the fluid
flow through the inlet and outlet flow passages 83, 84 to control
the amount of fluid pressure applied to each bias pad piston 59.
The pump assembly 90 continuously pumps fluid through the system
100 while the drive shaft 55 rotates the drill bit 60. Fluid may be
drawn from a reservoir 95 disposed in the outer housing 58. The
accumulator system 120 may be operable to dampen rapid fluid
pressure fluctuations in the system 100 to ensure that a smooth and
constant force is applied to each piston 59 of each bias pad
54.
[0037] In operation, the drill bit 60 of the rotary steerable
drilling system 100 may be rotated from the surface via the drill
string 10 and/or downhole by the hydraulically actuated motor 20 to
drill a vertical wellbore. Rotation is transmitted to the control
collar 40, the steerable assembly 50, and the drill bit 60. The
drive shaft 55 extends through the non-rotating outer housing 58
and rotates the drill bit 60. The control module 41 in the control
collar 40 continuously monitors and measures the vertical
trajectory of the wellbore using one or more sensors, such as
accelerometers. In the event that the system 100 begins to deviate
from vertical, the control module 41 determines the direction of
deviation by measuring the highside of the wellbore. The one or
more sensors 42 continuously monitor and measure the locations of
each bias pad 54 and transmit the information to the control module
41 via the slip ring assembly 70. Based on the locations of the
bias pads 54 relative to the highside of the wellbore, the control
module 41 actuates one or more of the solenoid valves of the
control valve assembly 80 to control the amount of fluid pressure
applied to the pistons 59 of each bias pad 54.
[0038] The piston/cylinders 92 of the pump assembly 90 are
continuously stroked by rotation of the drive shaft 55 to drive
pressurized fluid to the pistons 59 of each bias pad 54. The amount
of fluid pressure applied to each bias pad 54 is controlled by the
solenoid valves of the control valve assembly 80. Depending on the
amount of current supplied to the solenoid valves by the control
module 41, the control valve assembly 80 either allows fluid flow,
prevents fluid flow, or at least partially inhibits fluid flow
through the inlet and outlet flow passages 83, 84. Inhibiting or
preventing fluid flow through the inlet flow passage 83 controls
and increases the amount of fluid pressure applied to the pistons
59 of each bias pad 54.
[0039] The control module 41 will control the actuation of each
solenoid valve to obtain the requisite amount of bias force from
each bias pad 54 to force or push the drill bit 60 back to the
vertical drilling path trajectory. In this manner, the system 100
is operable to continuously monitor the vertical drilling path
trajectory and the position of each bias pad 54 relative to the
wellbore. The system 100 is further operable to self adjust its
trajectory when deviated from vertical. The system 100 may
communicate its operational characteristics (rotational speed,
inclination, etc.) to the surface via hydraulic (mud pulse)
telemetry or other communication mechanisms known in the art.
[0040] While the foregoing is directed to embodiments of the
invention, other and further embodiments of the invention may be
devised without departing from the basic scope thereof, and the
scope thereof is determined by the claims that follow.
* * * * *