Note: Descriptions are shown in the official language in which they were submitted.
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
DIRECTIONAL DRILLING CONTROL
BACKGROUND
[0001] At the outset of a drilling operation, drillers typically establish a
drilling plan
that includes a target location and a drilling path to the target location.
Once drilling
commences, the bottom hole assembly is directed or "steered" from a vertical
drilling path in
any number of directions, to follow the proposed drilling plan. For example,
to recover an
underground hydrocarbon deposit, a drilling plan might include a vertical well
to a point
above the reservoir, then a directional or horizontal well that penetrates the
deposit. The
operator may then steer the drill through both the vertical and horizontal
aspects in
accordance with the plan.
[0002] In some embodiments, such directional drilling requires accurate
orientation of
a bent segment of the downhole motor that drives the bit. In such embodiments,
rotating the
drill string changes the orientation of the bent segment and the toolface. To
effectively steer
the assembly, the operator must first determine the current toolface
orientation, such as via a
measurement-while-drilling (MWD) apparatus. Thereafter, if the drilling
direction needs
adjustment, the operator must rotate the drill string to change the toolface
orientation. In
other embodiments, such as rotary steerable systems, the operator still must
determine the
current toolface orientation.
[0003] During drilling, a "survey" identifying locational and directional data
of a
BHA in a well is obtained at various intervals or other times. Each survey
yields a
measurement of the inclination and azimuth (or compass heading) of a location
in a well
(typically the total depth at the time of measurement). In directional
wellbores, particularly,
the position of the wellbore must be known with reasonable accuracy to ensure
the correct
wellbore path. The measurements themselves include inclination from vertical
and the
azimuth of the wellbore. In addition to the toolface data, and inclination,
and azimuth, the
data obtained during each survey may also include hole depth data, pipe
rotational data, hook
load data, delta pressure data (across the downhole drilling motor), and
modeled dogleg data,
for example.
[0004] These measurements may be made at discrete points in the well, and the
approximate path of the wellbore may be computed from these discrete points.
Conventionally, a standard survey is conducted at each drill pipe connection
to obtain an
accurate measurement of inclination and azimuth for the new survey position.
However, if
1
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
directional drilling operations call for one or more transitions between
sliding and rotating
within the span of a single drill pipe joint or connection, the driller cannot
rely on the most
recent survey to accurately assess the progress or effectiveness of the
operation. For
example, the driller cannot utilize the most recent survey data to assess the
effectiveness or
accuracy of a "slide" that is initiated after the survey was obtained. The
conventional use of
surveys does not provide the directional driller with any feedback on the
progress or
effectiveness of operations that are performed after the most recent survey
measurements are
obtained.
[0005] When deviation from the planned drilling path occurs, drillers must
consider
the factors available to them to try to direct the drill back to the original
path. This typically
requires the operator to manipulate the drawworks brake, and rotate the rotary
table or top
drive quill to find the precise combinations of hook load, mud motor
differential pressure,
and drill string torque, to properly position the toolface. This can be
difficult, time
consuming, and complex. Each adjustment has different effects on the toolface
orientation,
and each must be considered in combination with other drilling requirements to
drill the hole.
Thus, reorienting the toolface in a bore is very complex, labor intensive, and
often inaccurate.
A more efficient, reliable method for steering a BHA is needed.
SUMMARY OF THE INVENTION
[0006] In one exemplary aspect, the present disclosure encompasses a method of
using a quill to steer a hydraulic motor when elongating a wellbore in a
direction having a
horizontal component, wherein the quill and the hydraulic motor are coupled to
opposing
ends of a drill string, the method including: monitoring an actual toolface
orientation of a tool
driven by the hydraulic motor by monitoring a drilling operation parameter
indicative of a
difference between the actual toolface orientation and a desired toolface
orientation, and
adjusting a position of the quill by an amount that is dependent upon the
monitored drilling
operation parameter.
[0007] In one embodiment, the amount of quill position adjustment is
sufficient to
compensate for the difference between the actual and desired toolface
orientations. In
another embodiment, adjusting the quill position includes adjusting a
rotational position of
the quill relative to the wellbore. In yet another embodiment, adjusting the
quill position
includes adjusting a vertical position of the quill relative to the wellbore.
In yet a further
embodiment, adjusting the quill position includes causing a drawworks to
adjust a weight
2
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
applied to the tool (WOB) by an amount dependent upon the monitored drilling
operation
parameter. The quill position adjustment may include more than one, or all, of
these different
embodiments.
[0008] In another embodiment, monitoring the drilling operation parameter
indicative
of the difference between the actual and desired toolface orientations
includes monitoring a
plurality of drilling operation parameters each indicative of the difference
between the actual
and desired toolface orientations, and wherein the amount of quill position
adjustment is
further dependent upon each of the plurality of drilling operation parameters.
In yet another
embodiment, monitoring the drilling operation parameter includes monitoring
data received
from a toolface orientation sensor, and wherein the amount of quill position
adjustment is
dependent upon the toolface orientation sensor data. In a preferred
embodiment, the toolface
sensor includes at least one of a gravity toolface sensor and a magnetic
toolface sensor.
[0009] In varying embodiments, the drilling operation parameter includes a
weight
applied to the tool (WOB), a depth of the tool within the wellbore, a rate of
penetration of the
tool into the wellbore (ROP), a hydraulic pressure differential across the
hydraulic motor
(AP), or a combination thereof. In a preferred embodiment, the drilling
operation parameter
is the AP and it is a corrected AP based on monitored pressure of fluid
existing in an annulus
defined between the wellbore and the drill string.
[0010] In one embodiment, monitoring the drilling operation parameter
indicative of
the difference between the actual and desired toolface orientations includes:
monitoring data
received from a toolface orientation sensor, monitoring a weight applied to
the tool (WOB),
monitoring a depth of the tool within the wellbore, monitoring a rate of
penetration of the tool
into the wellbore (ROP), and monitoring a hydraulic pressure differential
across the hydraulic
motor (AP). In a preferred embodiment, adjusting the quill position includes
adjusting the
quill position by an amount that is dependent upon at least two, preferably
three, or even all,
of the following: the monitored toolface orientation sensor data, the
monitored WOB, the
monitored depth of the tool within the wellbore, the monitored ROP, and the
monitored AP.
In another preferred embodiment, monitoring the drilling operation parameter
and adjusting
the quill position are performed simultaneously with operating the hydraulic
motor.
[0011] In another embodiment, adjusting the quill position includes adjusting
a
neutral rotational position of the quill, and wherein the method further
includes oscillating the
quill by rotating the quill through a predetermined angle past the neutral
position in clockwise
and counterclockwise directions.
3
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
[00121 The invention also encompasses a system for using a quill to steer a
hydraulic
motor when elongating a wellbore in a direction having a horizontal component,
wherein the
quill and the hydraulic motor are coupled to opposing ends of a drill string,
the system
including: a monitoring device adapted to monitor an actual toolface
orientation of a tool
driven by the hydraulic motor, including a monitoring device adapted to
monitor a drilling
operation parameter indicative of a difference between the actual toolface
orientation and a
desired toolface orientation, and an adjustment device adapted to adjust a
position of the quill
by an amount that is dependent upon the monitored drilling operation
parameter.
[00131 The invention further encompasses an apparatus for using a quill to
steer a hydraulic motor when elongating a wellbore in a direction having a
horizontal component, wherein the quill and the hydraulic motor are coupled to
opposing ends of a drill string, the apparatus including: a sensor configured
to
detect a drilling operation parameter indicative of a difference between an
actual
toolface orientation of a tool driven by the hydraulic motor and a desired
toolface
orientation of the tool, and a toolface controller configured to adjust the
actual
toolface orientation by generating a quill drive control signal directing a
quill drive
to adjust a rotational position of the quill based on the monitored drilling
operation
parameter.
4
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
BRIEF DESCRIPTION OF THE DRAWINGS
[0014] The present disclosure is best understood from the following detailed
description when read with the accompanying figures. It is emphasized that, in
accordance
with the standard practice in the industry, various features are not drawn to
scale. In fact, the
dimensions of the various features may be arbitrarily increased or reduced for
clarity of
discussion.
[0015] Fig. 1 is a schematic diagram of a drilling rig apparatus according to
one or
more aspects of the present disclosure.
[0016] Figs. 2A and 2B are flow-chart diagrams of methods according to one or
more
aspects of the present disclosure.
[0017] Fig. 3 is a schematic diagram of an apparatus according to one or more
aspects
of the present disclosure.
[0018] Figs. 4A-4C are schematic diagrams of apparatuses accordingly to one or
more aspects of the present disclosure.
[0019] Fig. 5A is a flow-chart diagram of a method according to one or more
aspects
of the present disclosure.
[0020] Fig. 5B is an illustration of a tolerance cylinder about drilling path.
[0021] Fig. 6A is a flow-chart diagram of a method according to one or more
aspects
of the present disclosure.
[0022] Fig. 6B is a schematic diagram of an apparatus according to one or more
aspects of the present disclosure.
[0023] Figs. 6C-6D are flow-chart diagrams of methods according to one or more
aspects of the present disclosure.
[0024] Figs. 7A-7C are flow-chart diagrams of methods according to one or more
aspects of the present disclosure.
[0025] Figs. 8A-8B are schematic diagrams of apparatuses according to one or
more
aspects of the present disclosure.
[0026] Fig. 8C is a flow-chart diagram of a method according to one or more
aspects
of the present disclosure.
[0027] Figs. 9A-9B are flow-chart diagrams of methods according to one or more
aspects of the present disclosure.
[0028] Figs. 1OA-10B are schematic diagrams of a display apparatus according
to one
or more aspects of the present disclosure.
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
[00291 Fig. 11 is a schematic diagram of an apparatus according to one or more
aspects of the present disclosure.
6
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
DETAILED DESCRIPTION
[00301 It is to be understood that the present disclosure provides many
different
embodiments, or examples, for implementing different features of various
embodiments.
Specific examples of components and arrangements are described below to
simplify the
present disclosure. These are, of course, merely examples and are not intended
to be limiting.
In addition, the present disclosure may repeat reference numerals and/or
letters in the various
examples. This repetition is for the purpose of simplicity and clarity and
does not in itself
dictate a relationship between the various embodiments and/or configurations
discussed.
Moreover, the formation of a first feature over or on a second feature in the
description that
follows may include embodiments in which the first and second features are
formed in direct
contact, and may also include embodiments in which additional features may be
formed
interposing the first and second features, such that the first and second
features may not be in
direct contact.
[00311 The systems and methods disclosed herein provide increased control of
BHAs,
resulting in increased BHA responsiveness and faster BHA operations compared
to
conventional systems that require significantly more manual input or pauses to
provide for
input. The invention can advantageously achieve this through the use of data
feedback and
location detection, processing received data, and optimizing a drilling path
based on the
projected actual bit location. Prior to drilling, a target location is
typically identified and an
optimal wellbore profile or planned path is established. Such proposed
drilling paths are
generally based upon the most efficient or effective path to the target
location or locations.
As drilling proceeds, the BHA might begin to deviate from the optimal pre-
planned drilling
path for one or more of a variety of factors. The systems and methods
disclosed herein are
adapted to detect the deviation from the planned path and generate corrections
to return the
BHA to the drilling path or if more effective, generate an alternative
drilling path to the target
location, each preferably in the most efficient manner possible while
preferably avoiding
over-correction.
[00321 Referring to Fig. 1, illustrated is a schematic view of apparatus 100
demonstrating one or more aspects of the present disclosure. The apparatus 100
is or
includes a land-based drilling rig. However, one or more aspects of the
present disclosure are
applicable or readily adaptable to any type of drilling rig, such as jack-up
rigs,
semisubmersibles, drill ships, coil tubing rigs, well service rigs adapted for
drilling and/or re-
7
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
entry operations, and casing drilling rigs, among others within the scope of
the present
disclosure.
[0033] Apparatus 100 includes a mast 105 supporting lifting gear above a rig
floor
110. The lifting gear includes a crown block 115 and a traveling block 120.
The crown
block 115 is coupled at or near the top of the mast 105, and the traveling
block 120 hangs
from the crown block 115 by a drilling line 125. One end of the drilling line
125 extends
from the lifting gear to drawworks 130, which is configured to reel out and
reel in the drilling
line 125 to cause the traveling block 120 to be lowered and raised relative to
the rig floor 110.
The other end of the drilling line 125, known as a dead line anchor, is
anchored to a fixed
position, possibly near the drawworks 130 or elsewhere on the rig.
[0034] A hook 135 is attached to the bottom of the traveling block 120. A top
drive
140 is suspended from the hook 135. A quill 145 extending from the top drive
140 is
attached to a saver sub 150, which is attached to a drill string 155 suspended
within a
wellbore 160. Alternatively, the quill 145 may be attached to the drill string
155 directly.
[0035] The term "quill" as used herein is not limited to a component which
directly
extends from the top drive, or which is otherwise conventionally referred to
as a quill. For
example, within the scope of the present disclosure, the "quill" may
additionally or
alternatively include a main shaft, a drive shaft, an output shaft, and/or
another component
which transfers torque, position, and/or rotation from the top drive or other
rotary driving
element to the drill string, at least indirectly. Nonetheless, albeit merely
for the sake of
clarity and conciseness, these components may be collectively referred to
herein as the
"quill."
[0036] The drill string 155 includes interconnected sections of drill pipe
165, a
bottom hole assembly (BHA) 170, and a drill bit 175. The bottom hole assembly
170 may
include stabilizers, drill collars, and/or measurement-while-drilling (MWD) or
wireline
conveyed instruments, among other components. The drill bit 175, which may
also be
referred to herein as a tool, is connected to the bottom of the BHA 170 or is
otherwise
attached to the drill string 155. One or more pumps 180 may deliver drilling
fluid to the drill
string 155 through a hose or other conduit 185, which may be connected to the
top drive 140.
[0037] The downhole MWD or wireline conveyed instruments may be configured for
the evaluation of physical properties such as pressure, temperature, torque,
weight-on-bit
(WOB), vibration, inclination, azimuth, toolface orientation in three-
dimensional space,
and/or other downhole parameters. These measurements may be made downhole,
stored in
8
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
solid-state memory for some time, and downloaded from the instrument(s) at the
surface
and/or transmitted real-time to the surface. Data transmission methods may
include, for
example, digitally encoding data and transmitting the encoded data to the
surface, possibly as
pressure pulses in the drilling fluid or mud system, acoustic transmission
through the drill
string 155, electronic transmission through a wireline or wired pipe, and/or
transmission as
electromagnetic pulses. The MWD tools and/or other portions of the BHA 170 may
have the
ability to store measurements for later retrieval via wireline and/or when the
BHA 170 is
tripped out of the wellbore 160.
[0038] In an exemplary embodiment, the apparatus 100 may also include a
rotating
blow-out preventer (BOP) 158, such as if the well 160 is being drilled
utilizing under-
balanced or managed-pressure drilling methods. In such embodiment, the annulus
mud and
cuttings may be pressurized at the surface, with the actual desired flow and
pressure possibly
being controlled by a choke system, and the fluid and pressure being retained
at the well head
and directed down the flow line to the choke by the rotating BOP 158. The
apparatus 100
may also include a surface casing annular pressure sensor 159 configured to
detect the
pressure in the annulus defined between, for example, the wellbore 160 (or
casing therein)
and the drill string 155.
[0039] In the exemplary embodiment depicted in Fig. 1, the top drive 140 is
utilized
to impart rotary motion to the drill string 155. However, aspects of the
present disclosure are
also applicable or readily adaptable to implementations utilizing other drive
systems, such as
a power swivel, a rotary table, a coiled tubing unit, a downhole motor, and/or
a conventional
rotary rig, among others.
[0040] The apparatus 100 also includes a controller 190 configured to control
or assist
in the control of one or more components of the apparatus 100. For example,
the controller
190 may be configured to transmit operational control signals to the drawworks
130, the top
drive 140, the BHA 170 and/or the pump 180. The controller 190 may be a stand-
alone
component installed near the mast 105 and/or other components of the apparatus
100. In an
exemplary embodiment, the controller 190 includes one or more systems located
in a control
room proximate the apparatus 100, such as the general purpose shelter often
referred to as the
"doghouse" serving as a combination tool shed, office, communications center,
and general
meeting place. The controller 190 may be configured to transmit the
operational control
signals to the drawworks 130, the top drive 140, the BHA 170, and/or the pump
180 via
wired or wireless transmission means which, for the sake of clarity, are not
depicted in Fig. 1.
9
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
[0041] The controller 190 is also configured to receive electronic signals via
wired or
wireless transmission means (also not shown in Fig. 1) from a variety of
sensors included in
the apparatus 100, where each sensor is configured to detect an operational
characteristic or
parameter. One such sensor is the surface casing annular pressure sensor 159
described
above. The apparatus 100 may include a downhole annular pressure sensor 170a
coupled to
or otherwise associated with the BHA 170. The downhole annular pressure sensor
170a may
be configured to detect a pressure value or range in the annulus-shaped region
defined
between the external surface of the BHA 170 and the internal diameter of the
wellbore 160,
which may also be referred to as the casing pressure, downhole casing
pressure, MWD casing
pressure, or downhole annular pressure. These measurements may include both
static annular
pressure (pumps off) and active annular pressure (pumps on).
[0042] It is noted that the meaning of the word "detecting," in the context of
the
present disclosure, may include detecting, sensing, measuring, calculating,
and/or otherwise
obtaining data. Similarly, the meaning of the word "detect" in the context of
the present
disclosure may include detect, sense, measure, calculate, and/or otherwise
obtain data.
[0043] The apparatus 100 may additionally or alternatively include a
shock/vibration
sensor 170b that is configured for detecting shock and/or vibration in the BHA
170. The
apparatus 100 may additionally or alternatively include a mud motor delta
pressure (AP)
sensor 172a that is configured to detect a pressure differential value or
range across one or
more motors 172 of the BHA 170. The one or more motors 172 may each be or
include a
positive displacement drilling motor that uses hydraulic power of the drilling
fluid to drive
the bit 175, also known as a mud motor. One or more torque sensors 172b may
also be
included in the BHA 170 for sending data to the controller 190 that is
indicative of the torque
applied to the bit 175 by the one or more motors 172.
[0044] The apparatus 100 may additionally or alternatively include a toolface
sensor
170c configured to detect the current toolface orientation. The toolface
sensor 170c may be
or include a conventional or future-developed magnetic toolface sensor which
detects
toolface orientation relative to magnetic north or true north. Alternatively,
or additionally,
the toolface sensor 170c may be or include a conventional or future-developed
gravity
toolface sensor which detects toolface orientation relative to the Earth's
gravitational field.
The toolface sensor 170c may also, or alternatively, be or include a
conventional or future-
developed gyro sensor. The apparatus 100 may additionally or alternatively
include a WOB
sensor 170d integral to the BHA 170 and configured to detect WOB at or near
the BHA 170.
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
[0045] The apparatus 100 may additionally or alternatively include a torque
sensor
140a coupled to or otherwise associated with the top drive 140. The torque
sensor 140a may
alternatively be located in or associated with the BHA 170. The torque sensor
140a may be
configured to detect a value or range of the torsion of the quill 145 and/or
the drill string 155
(e.g., in response to operational forces acting on the drill string). The top
drive 140 may
additionally or alternatively include or otherwise be associated with a speed
sensor 140b
configured to detect a value or range of the rotational speed of the quill
145.
[0046] The top drive 140, draw works 130, crown or traveling block, drilling
line or
dead line anchor may additionally or alternatively include or otherwise be
associated with a
WOB sensor 140c (WOB calculated from a hook load sensor that can be based on
active and
static hook load) (e.g., one or more sensors installed somewhere in the load
path mechanisms
to detect and calculate WOB, which can vary from rig-to-rig) different from
the WOB sensor
170d. The WOB sensor 140c may be configured to detect a WOB value or range,
where such
detection may be performed at the top drive 140, draw works 130, or other
component of the
apparatus 100.
[0047] The detection performed by the sensors described herein may be
performed
once, continuously, periodically, and/or at random intervals. The detection
may be manually
triggered by an operator or other person accessing a human-machine interface
(HMI), or
automatically triggered by, for example, a triggering characteristic or
parameter satisfying a
predetermined condition (e.g., expiration of a time period, drilling progress
reaching a
predetermined depth, drill bit usage reaching a predetermined amount, etc.).
Such sensors
and/or other detection means may include one or more interfaces which may be
local at the
well/rig site or located at another, remote location with a network link to
the system.
[0048] Referring to Fig. 2A, illustrated is a flow-chart diagram of a method
200a of
manipulating a toolface orientation to a desired orientation according to one
or more aspects
of the present disclosure. The method 200a may be performed in association
with one or
more components of the apparatus 100 shown in Fig. 1 during operation of the
apparatus 100.
For example, the method 200a may be performed for toolface orientation during
drilling
operations performed via the apparatus 100.
[0049] The method 200a includes a step 210 during which the current toolface
orientation TFM is measured. The TFM may be measured using a conventional or
future-
developed magnetic toolface sensor which detects toolface orientation relative
to magnetic
north or true north. Alternatively, or additionally, the TFM may be measured
using a
11
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
conventional or future-developed gravity toolface sensor which detects
toolface orientation
relative to the Earth's gravitational field. In an exemplary embodiment, the
TFM may be
measured using a magnetic toolface sensor when the end of the wellbore is less
than about 7
from vertical, and subsequently measured using a gravity toolface sensor when
the end of the
wellbore is greater than about 7 from vertical. However, gyros and/or other
means for
determining the TFM are also within the scope of the present disclosure.
[0050] In a subsequent step 220, the TFM is compared to a desired toolface
orientation
TFD. If the TFM is sufficiently equal to the TFD, as determined during
decisional step 230,
the method 200a is iterated and the step 210 is repeated. "Sufficiently equal"
may mean
substantially equal, such as varying by no more than a few percentage points,
or may
alternatively mean varying by no more than a predetermined angle, such as
about 5 .
Moreover, the iteration of the method 200a may be substantially immediate, or
there may be
a delay period before the method 200a is iterated and the step 210 is
repeated.
[0051] If the TFM is not sufficiently equal to the TFD, as determined during
decisional
step 230, the method 200a continues to a step 240 during which the quill is
rotated by the
drive system by, for example, an amount about equal to the difference between
the TFM and
the TFD. However, other amounts of rotational adjustment performed during the
step 240 are
also within the scope of the present disclosure. After step 240 is performed,
the method 200a
is iterated and the step 210 is repeated. Such iteration may be substantially
immediate, or
there may be a delay period before the method 200a is iterated and the step
210 is repeated.
[0052] Referring to Fig. 2B, illustrated is a flow-chart diagram of another
embodiment of the method 200a shown in Fig. 2A, herein designated by reference
numeral
200b. The method 200b includes an information gathering step when the toolface
orientation
is in the desired orientation and may be performed in association with one or
more
components of the apparatus 100 shown in Fig. 1 during operation of the
apparatus 100. For
example, the method 200b may be performed for toolface orientation during
drilling
operations performed via the apparatus 100.
[0053] The method 200b includes steps 210, 220, 230 and 240 described above
with
respect to method 200a and shown in Fig. 2A. However, the method 200b also
includes a
step 233 during which current operating parameters are measured if the TFM is
sufficiently
equal to the TFD, as determined during decisional step 230. Alternatively, or
additionally, the
current operating parameters may be measured at periodic or scheduled time
intervals, or
upon the occurrence of other events. The method 200b also includes a step 236
during which
12
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
the operating parameters measured in the step 233 are recorded. The operating
parameters
recorded during the step 236 may be employed in future calculations of the
amount of quill
rotation performed during the step 240, such as may be determined by one or
more intelligent
adaptive controllers, programmable logic controllers, artificial neural
networks, and/or other
adaptive and/or "learning" controllers or processing apparatus.
[0054] Each of the steps of the methods 200a and 200b may be performed
automatically. For example, the controller 190 of Fig. 1 may be configured to
automatically
perform the toolface comparison of step 230, whether periodically, at random
intervals, or
otherwise. The controller 190 may also be configured to automatically generate
and transmit
control signals directing the quill rotation of step 240, such as in response
to the toolface
comparison performed during steps 220 and 230.
[0055] Referring to Fig. 3, illustrated is a block diagram of an apparatus 300
according to one or more aspects of the present disclosure. The apparatus 300
includes a user
interface 305, a BHA 310, a drive system 315, a drawworks 320, and a
controller 325. The
apparatus 300 may be implemented within the environment and/or apparatus shown
in Fig. 1.
For example, the BHA 310 may be substantially similar to the BHA 170 shown in
Fig. 1, the
drive system 315 may be substantially similar to the top drive 140 shown in
Fig. 1, the
drawworks 320 may be substantially similar to the drawworks 130 shown in Fig.
1, and/or
the controller 325 may be substantially similar to the controller 190 shown in
Fig. 1. The
apparatus 300 may also be utilized in performing the method 200a shown in Fig.
2A and/or
the method 200b shown in Fig. 2B, among other methods described herein or
otherwise
within the scope of the present disclosure.
[0056] The user-interface 305 and the controller 325 may be discrete
components that
are interconnected via wired or wireless means. Alternatively, the user-
interface 305 and the
controller 325 may be integral components of a single system or controller
327, as indicated
by the dashed lines in Fig. 3.
[0057] The user-interface 305 includes means 330 for user-input of one or more
toolface set points, and may also include means for user-input of other set
points, limits, and
other input data. The data input means 330 may include a keypad, voice-
recognition
apparatus, dial, button, switch, slide selector, toggle, joystick, mouse, data
base and/or other
conventional or future-developed data input device. Such data input means may
support data
input from local and/or remote locations. Alternatively, or additionally, the
data input means
330 may include means for user-selection of predetermined toolface set point
values or
13
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
ranges, such as via one or more drop-down menus. The toolface set point data
may also or
alternatively be selected by the controller 325 via the execution of one or
more database look-
up procedures. In general, the data input means 330 and/or other components
within the
scope of the present disclosure support operation and/or monitoring from
stations on the rig
site as well as one or more remote locations with a communications link to the
system,
network, local area network (LAN), wide area network (WAN), Internet,
satellite-link, and/or
radio, among other means.
[0058] The user-interface 305 may also include a display 335 for visually
presenting
information to the user in textual, graphic, or video form. The display 335
may also be
utilized by the user to input the toolface set point data in conjunction with
the data input
means 330. For example, the toolface set point data input means 330 may be
integral to or
otherwise communicably coupled with the display 335.
[0059] The BHA 310 may include an MWD casing pressure sensor 340 that is
configured to detect an annular pressure value or range at or near the MWD
portion of the
BHA 310, and that may be substantially similar to the pressure sensor 170a
shown in Fig. 1.
The casing pressure data detected via the MWD casing pressure sensor 340 may
be sent via
electronic signal to the controller 325 via wired or wireless transmission.
[0060] The BHA 310 may also include an MWD shock/vibration sensor 345 that is
configured to detect shock and/or vibration in the MWD portion of the BHA 310,
and that
may be substantially similar to the shock/vibration sensor 170b shown in Fig.
1. The
shock/vibration data detected via the MWD shock/vibration sensor 345 may be
sent via
electronic signal to the controller 325 via wired or wireless transmission.
[0061] The BHA 310 may also include a mud motor AP sensor 350 that is
configured
to detect a pressure differential value or range across the mud motor of the
BHA 310, and that
may be substantially similar to the mud motor AP sensor 172a shown in Fig. 1.
The pressure
differential data detected via the mud motor AP sensor 350 may be sent via
electronic signal
to the controller 325 via wired or wireless transmission. The mud motor AP may
be
alternatively or additionally calculated, detected, or otherwise determined at
the surface, such
as by calculating the difference between the surface standpipe pressure just
off-bottom and
pressure once the bit touches bottom and starts drilling and experiencing
torque.
[0062] The BHA 310 may also include a magnetic toolface sensor 355 and a
gravity
toolface sensor 360 that are cooperatively configured to detect the current
toolface, and that
collectively may be substantially similar to the toolface sensor 170c shown in
Fig. 1. The
14
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
magnetic toolface sensor 355 may be or include a conventional or future-
developed magnetic
toolface sensor which detects toolface orientation relative to magnetic north
or true north.
The gravity toolface sensor 360 may be or include a conventional or future-
developed gravity
toolface sensor which detects toolface orientation relative to the Earth's
gravitational field.
In an exemplary embodiment, the magnetic toolface sensor 355 may detect the
current
toolface when the end of the wellbore is less than about 7 from vertical, and
the gravity
toolface sensor 360 may detect the current toolface when the end of the
wellbore is greater
than about 7 from vertical. However, other toolface sensors may also be
utilized within the
scope of the present disclosure, including non-magnetic toolface sensors and
non-
gravitational inclination sensors. In any case, the toolface orientation
detected via the one or
more toolface sensors (e.g., sensors 355 and/or 360) may be sent via
electronic signal to the
controller 325 via wired or wireless transmission.
[0063] The BHA 310 may also include an MWD torque sensor 365 that is
configured
to detect a value or range of values for torque applied to the bit by the
motor(s) of the BHA
310, and that may be substantially similar to the torque sensor 172b shown in
Fig. 1. The
torque data detected via the MWD torque sensor 365 may be sent via electronic
signal to the
controller 325 via wired or wireless transmission.
[0064] The BHA 310 may also include an MWD WOB sensor 370 that is configured
to detect a value or range of values for WOB at or near the BHA 310, and that
may be
substantially similar to the WOB sensor 170d shown in Fig. 1. The WOB data
detected via
the MWD WOB sensor 370 may be sent via electronic signal to the controller 325
via wired
or wireless transmission.
[0065] The drawworks 320 includes a controller 390 and/or other means for
controlling feed-out and/or feed-in of a drilling line (such as the drilling
line 125 shown in
Fig. 1). Such control may include rotational control of the drawworks (in v.
out) to control
the height or position of the hook, and may also include control of the rate
the hook ascends
or descends. However, exemplary embodiments within the scope of the present
disclosure
include those in which the drawworks drill string feed off system may
alternatively be a
hydraulic ram or rack and pinion type hoisting system rig, where the movement
of the drill
string up and down is via something other than a drawworks. The drill string
may also take
the form of coiled tubing, in which case the movement of the drill string in
and out of the
hole is controlled by an injector head which grips and pushes/pulls the tubing
in/out of the
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
hole. Nonetheless, such embodiments may still include a version of the
controller 390, and
the controller 390 may still be configured to control feed-out and/or feed-in
of the drill string.
[0066] The drive system 315 includes a surface torque sensor 375 that is
configured
to detect a value or range of the reactive torsion of the quill or drill
string, much the same as
the torque sensor 140a shown in Fig. 1. The drive system 315 also includes a
quill position
sensor 380 that is configured to detect a value or range of the rotational
position of the quill,
such as relative to true north or another stationary reference. The surface
torsion and quill
position data detected via sensors 375 and 380, respectively, may be sent via
electronic signal
to the controller 325 via wired or wireless transmission. The drive system 315
also includes a
controller 385 and/or other means for controlling the rotational position,
speed and direction
of the quill or other drill string component coupled to the drive system 315
(such as the quill
145 shown in Fig. 1).
[0067] In an exemplary embodiment, the drive system 315, controller 385,
and/or
other component of the apparatus 300 may include means for accounting for
friction between
the drill string and the wellbore. For example, such friction accounting means
may be
configured to detect the occurrence and/or severity of the friction, which may
then be
subtracted from the actual "reactive" torque, perhaps by the controller 385
and/or another
control component of the apparatus 300.
[0068] The controller 325 is configured to receive one or more of the above-
described
parameters from the user interface 305, the BHA 310, and/or the drive system
315, and utilize
such parameters to continuously, periodically, or otherwise determine the
current toolface
orientation. The controller 325 may be further configured to generate a
control signal, such
as via intelligent adaptive control, and provide the control signal to the
drive system 315
and/or the drawworks 320 to adjust and/or maintain the toolface orientation.
For example,
the controller 325 may execute the method 202 shown in Fig. 2B to provide one
or more
signals to the drive system 315 and/or the drawworks 320 to increase or
decrease WOB
and/or quill position, such as may be required to accurately "steer" the
drilling operation.
[0069] Moreover, as in the exemplary embodiment depicted in Fig. 3, the
controller
385 of the drive system 315 and/or the controller 390 of the drawworks 320 may
be
configured to generate and transmit a signal to the controller 325.
Consequently, the
controller 385 of the drive system 315 may be configured to influence the
control of the BHA
310 and/or the drawworks 320 to assist in obtaining and/or maintaining a
desired toolface
orientation. Similarly, the controller 390 of the drawworks 320 may be
configured to
16
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
influence the control of the BHA 310 and/or the drive system 315 to assist in
obtaining and/or
maintaining a desired toolface orientation. Alternatively, or additionally,
the controller 385
of the drive system 315 and the controller 390 of the drawworks 320 may be
configured to
communicate directly, such as indicated by the dual-directional arrow 392
depicted in Fig. 3.
Consequently, the controller 385 of the drive system 315 and the controller
390 of the
drawworks 320 may be configured to cooperate in obtaining and/or maintaining a
desired
toolface orientation. Such cooperation may be independent of control provided
to or from the
controller 325 and/or the BHA 310.
[0070] Referring to Fig. 4A, illustrated is a schematic view of at least a
portion of an
apparatus 400a according to one or more aspects of the present disclosure. The
apparatus
400a is an exemplary implementation of the apparatus 100 shown in Fig. 1
and/or the
apparatus 300 shown in Fig. 3, and is an exemplary environment in which the
method 200a
shown in Fig. 2A and/or the method 200b shown in Fig. 2B may be performed. The
apparatus 400a includes a plurality of user inputs 410 and at least one main
steering module
420, which may include one or more processors. The user inputs 410 include a
quill torque
positive limit 410a, a quill torque negative limit 410b, a quill speed
positive limit 410c, a
quill speed negative limit 410d, a quill oscillation positive limit 410e, a
quill oscillation
negative limit 410f, a quill oscillation neutral point input 410g, and a
toolface orientation
input 410h. Some embodiments include a survey data input from prior surveys
410p, a
planned drilling path 410q, or preferably both. These inputs may be used to
derive the
toolface orientation input 410h intended to maintain the BHA on the planned
drilling path.
However, in other embodiments, the toolface orientation is directly entered.
Other
embodiments within the scope of the present disclosure may utilize additional
or alternative
user inputs 410. The user inputs 410 maybe substantially similar to the user
input 330 or
other components of the user interface 305 shown in Fig. 3. The at least one
steering module
420 may form at least a portion of, or be formed by at least a portion of, the
controller 325
shown in Fig. 3 and/or the controller 385 of the drive system 315 shown in
Fig. 3. In the
exemplary embodiment depicted in Fig. 4A, the at least one steering module 420
includes a
toolface controller 420a and a drawworks controller 420b. In some embodiments,
it also
includes a mud pump controller.
[0071] The apparatus 400a also includes or is otherwise associated with a
plurality of
sensors 430. The plurality of sensors 430 includes a bit torque sensor 430a, a
quill torque
sensor 430b, a quill speed sensor 430c, a quill position sensor 430d, a mud
motor AP sensor
17
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
430e, and a toolface orientation sensor 430f. Other embodiments within the
scope of the
present disclosure, however, may utilize additional or alternative sensors
430. In an
exemplary embodiment, each of the plurality of sensors 430 may be located at
the surface of
the wellbore, and not located downhole proximate the bit, the bottom hole
assembly, and/or
any measurement-while-drilling tools. In other embodiments, however, one or
more of the
sensors 430 may not be surface sensors. For example, in an exemplary
embodiment, the quill
torque sensor 430b, the quill speed sensor 430c, and the quill position sensor
430d may be
surface sensors, whereas the bit torque sensor 430a, the mud motor AP sensor
430e, and the
toolface orientation sensor 430f may be downhole sensors (e.g., MWD sensors).
Moreover,
individual ones of the sensors 430 may be substantially similar to
corresponding sensors
shown in Fig. 1 or Fig. 3.
[0072] The apparatus 400a also includes or is associated with a quill drive
440. The
quill drive 440 may form at least a portion of a top drive or another rotary
drive system, such
as the top drive 140 shown in Fig. 1 and/or the drive system 315 shown in Fig.
3. The quill
drive 440 is configured to receive a quill drive control signal from the at
least one steering
module 420, if not also from other components of the apparatus 400a. The quill
drive control
signal directs the position (e.g., azimuth), spin direction, spin rate, and/or
oscillation of the
quill. The toolface controller 420a is configured to generate the quill drive
control signal,
utilizing data received from the user inputs 410 and the sensors 430.
[0073] The toolface controller 420a may compare the actual torque of the quill
to the
quill torque positive limit received from the corresponding user input 410a.
The actual
torque of the quill may be determined utilizing data received from the quill
torque sensor
430b. For example, if the actual torque of the quill exceeds the quill torque
positive limit,
then the quill drive control signal may direct the quill drive 440 to reduce
the torque being
applied to the quill. In an exemplary embodiment, the toolface controller 420a
may be
configured to optimize drilling operation parameters related to the actual
torque of the quill,
such as by maximizing the actual torque of the quill without exceeding the
quill torque
positive limit.
[0074] The toolface controller 420a may alternatively or additionally compare
the
actual torque of the quill to the quill torque negative limit received from
the corresponding
user input 410b. For example, if the actual torque of the quill is less than
the quill torque
negative limit, then the quill drive control signal may direct the quill drive
440 to increase the
torque being applied to the quill. In an exemplary embodiment, the toolface
controller 420a
18
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
may be configured to optimize drilling operation parameters related to the
actual torque of the
quill, such as by minimizing the actual torque of the quill while still
exceeding the quill
torque negative limit.
[0075] The toolface controller 420a may alternatively or additionally compare
the
actual speed of the quill to the quill speed positive limit received from the
corresponding user
input 410c. The actual speed of the quill may be determined utilizing data
received from the
quill speed sensor 430c. For example, if the actual speed of the quill exceeds
the quill speed
positive limit, then the quill drive control signal may direct the quill drive
440 to reduce the
speed at which the quill is being driven. In an exemplary embodiment, the
toolface controller
420a may be configured to optimize drilling operation parameters related to
the actual speed
of the quill, such as by maximizing the actual speed of the quill without
exceeding the quill
speed positive limit.
[0076] The toolface controller 420a may alternatively or additionally compare
the
actual speed of the quill to the quill speed negative limit received from the
corresponding
user input 410d. For example, if the actual speed of the quill is less than
the quill speed
negative limit, then the quill drive control signal may direct the quill drive
440 to increase the
speed at which the quill is being driven. In an exemplary embodiment, the
toolface controller
420a may be configured to optimize drilling operation parameters related to
the actual speed
of the quill, such as by minimizing the actual speed of the quill while still
exceeding the quill
speed negative limit.
[0077] The toolface controller 420a may alternatively or additionally compare
the
actual orientation (azimuth) of the quill to the quill oscillation positive
limit received from the
corresponding user input 410e. The actual orientation of the quill may be
determined
utilizing data received from the quill position sensor 430d. For example, if
the actual
orientation of the quill exceeds the quill oscillation positive limit, then
the quill drive control
signal may direct the quill drive 440 to rotate the quill to within the quill
oscillation positive
limit, or to modify quill oscillation parameters such that the actual quill
oscillation in the
positive direction (e.g., clockwise) does not exceed the quill oscillation
positive limit. In an
exemplary embodiment, the toolface controller 420a may be configured to
optimize drilling
operation parameters related to the actual oscillation of the quill, such as
by maximizing the
amount of actual oscillation of the quill in the positive direction without
exceeding the quill
oscillation positive limit.
19
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
[0078] The toolface controller 420a may alternatively or additionally compare
the
actual orientation of the quill to the quill oscillation negative limit
received from the
corresponding user input 410f. For example, if the actual orientation of the
quill is less than
the quill oscillation negative limit, then the quill drive control signal may
direct the quill
drive 440 to rotate the quill to within the quill oscillation negative limit,
or to modify quill
oscillation parameters such that the actual quill oscillation in the negative
direction (e.g.,
counter-clockwise) does not exceed the quill oscillation negative limit. In an
exemplary
embodiment, the toolface controller 420a may be configured to optimize
drilling operation
parameters related to the actual oscillation of the quill, such as by
maximizing the actual
amount of oscillation of the quill in the negative direction without exceeding
the quill
oscillation negative limit.
[0079] The toolface controller 420a may alternatively or additionally compare
the
actual neutral point of quill oscillation to the desired quill oscillation
neutral point input
received from the corresponding user input 410g. The actual neutral point of
the quill
oscillation may be determined utilizing data received from the quill position
sensor 430d.
For example, if the actual quill oscillation neutral point varies from the
desired quill
oscillation neutral point by a predetermined amount, or falls outside a
desired range of the
oscillation neutral point, then the quill drive control signal may direct the
quill drive 440 to
modify quill oscillation parameters to make the appropriate correction.
[0080] The toolface controller 420a may alternatively or additionally compare
the
actual orientation of the toolface to the toolface orientation input received
from the
corresponding user input 410h. The toolface orientation input received from
the user input
410h may be a single value indicative of the desired toolface orientation.
This may be
directly input or derived from the survey data files 410p and the planned
drilling path 410q
using, for example, the process described in Figs. 4C, 5A, and 5B. If the
actual toolface
orientation differs from the toolface orientation input value by a
predetermined amount, then
the quill drive control signal may direct the quill drive 440 to rotate the
quill an amount
corresponding to the necessary correction of the toolface orientation.
However, the toolface
orientation input received from the user input 410h may alternatively be a
range within which
it is desired that the toolface orientation remain. For example, if the actual
toolface
orientation is outside the toolface orientation input range, then the quill
drive control signal
may direct the quill drive 440 to rotate the quill an amount necessary to
restore the actual
toolface orientation to within the toolface orientation input range. In an
exemplary
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
embodiment, the actual toolface orientation is compared to a toolface
orientation input that is
directly input or derived from the survey data files 410p and the planned
drilling path 410q
using an automated process. In some embodiments, this is based on a
predetermined and/or
constantly updating well plan (e.g., a "well-prog"), possibly taking into
account drilling
progress path error.
[00811 In each of the above-mentioned comparisons and/or calculations
performed by
the toolface controller, the actual mud motor AP, and/or the actual bit torque
may also be
utilized in the generation of the quill drive signal. The actual mud motor AP
may be
determined utilizing data received from the mud motor AP sensor 430e, and/or
by
measurement of pump pressure before the bit is on bottom and tare of this
value, and the
actual bit torque may be determined utilizing data received from the bit
torque sensor 430a.
Alternatively, the actual bit torque may be calculated utilizing data received
from the mud
motor AP sensor 430e, because actual bit torque and actual mud motor AP are
proportional.
[00821 One example in which the actual mud motor AP and/or the actual bit
torque
may be utilized is when the actual toolface orientation cannot be relied upon
to provide
accurate or fast enough data. For example, such may be the case during "blind"
drilling, or
other instances in which the driller is no longer receiving data from the
toolface orientation
sensor 430f. In such occasions, the actual bit torque and/or the actual mud
motor AP can be
utilized to determine the actual toolface orientation. For example, if all
other drilling
parameters remain the same, a change in the actual bit torque and/or the
actual mud motor AP
can indicate a proportional rotation of the toolface orientation in the same
or opposite
direction of drilling. For example, an increasing torque or AP may indicate
that the toolface
is changing in the opposite direction of drilling, whereas a decreasing torque
or AP may
indicate that the toolface is moving in the same direction as drilling. Thus,
in this manner,
the data received from the bit torque sensor 430a and/or the mud motor AP
sensor 430e can
be utilized by the toolface controller 420 in the generation of the quill
drive signal, such that
the quill can be driven in a manner which corrects for or otherwise takes into
account any
change of toolface, which is indicated by a change in the actual bit torque
and/or actual mud
motor AP.
[00831 Moreover, under some operating conditions, the data received by the
toolface
controller 420 from the toolface orientation sensor 430f can lag the actual
toolface
orientation. For example, the toolface orientation sensor 430f may only
determine the actual
toolface periodically, or a considerable time period may be required for the
transmission of
21
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
the data from the toolface to the surface. In fact, it is not uncommon for
such delay to be 30
seconds or more in the systems of the prior art. Consequently, in some
implementations
within the scope of the present disclosure, it may be more accurate or
otherwise advantageous
for the toolface controller 420a to utilize the actual torque and pressure
data received from
the bit torque sensor 430a and the mud motor AP sensor 430e in addition to, if
not in the
alternative to, utilizing the actual toolface data received from the toolface
orientation sensor
430f. However, in some embodiments of the present disclosure, real-time survey
projections
as disclosed in Figs. 9A and 9B may be used to provide data regarding the BHA
direction and
toolface orientation.
[0084] As shown in Fig. 4A, the user inputs 410 of the apparatus 400a may also
include a WOB tare 410i, a mud motor AP tare 410j, an ROP input 410k, a WOB
input 4101,
a mud motor AP input 410m, and a hook load limit 410n, and the at least one
steering module
420 may also include a drawworks controller 420b. The plurality of sensors 430
of the
apparatus 400a may also include a hook load sensor 430g, a mud pump pressure
sensor 430h,
a bit depth sensor 430i, a casing pressure sensor 430j and an ROP sensor 430k.
Each of the
plurality of sensors 430 may be located at the surface of the wellbore,
downhole (e.g.,
MWD), or elsewhere.
[0085] As described above, the toolface controller 420a is configured to
generate a
quill drive control signal utilizing data received from ones of the user
inputs 410 and the
sensors 430, and subsequently provide the quill drive control signal to the
quill drive 440,
thereby controlling the toolface orientation by driving the quill orientation
and speed. Thus,
the quill drive control signal is configured to control (at least partially)
the quill orientation
(e.g., azimuth) as well as the speed and direction of rotation of the quill
(if any).
[0086] The drawworks controller 420b is configured to generate a drawworks
drum
(or brake) drive control signal also utilizing data received from ones of the
user inputs 410
and the sensors 430. Thereafter, the drawworks controller 420b provides the
drawworks
drive control signal to the drawworks drive 450, thereby controlling the feed
direction and
rate of the drawworks. The drawworks drive 450 may form at least a portion of,
or may be
formed by at least a portion of, the drawworks 130 shown in Fig. 1 and/or the
drawworks 320
shown in Fig. 3. The scope of the present disclosure is also applicable or
readily adaptable to
other means for adjusting the vertical positioning of the drill string. For
example, the
drawworks controller 420b may be a hoist controller, and the drawworks drive
450 may be or
22
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
include means for hoisting the drill string other than or in addition to a
drawworks apparatus
(e.g., a rack and pinion apparatus).
[0087] The apparatus 400a also includes a comparator 420c which compares
current
hook load data with the WOB tare to generate the current WOB. The current hook
load data
is received from the hook load sensor 430g, and the WOB tare is received from
the
corresponding user input 410i.
[0088] The drawworks controller 420b compares the current WOB with WOB input
data. The current WOB is received from the comparator 420c, and the WOB input
data is
received from the corresponding user input 4101. The WOB input data received
from the user
input 4101 may be a single value indicative of the desired WOB. For example,
if the actual
WOB differs from the WOB input by a predetermined amount, then the drawworks
drive
control signal may direct the drawworks drive 450 to feed cable in or out an
amount
corresponding to the necessary correction of the WOB. However, the WOB input
data
received from the user input 4101 may alternatively be a range within which it
is desired that
the WOB be maintained. For example, if the actual WOB is outside the WOB input
range,
then the drawworks drive control signal may direct the drawworks drive 450 to
feed cable in
or out an amount necessary to restore the actual WOB to within the WOB input
range. In an
exemplary embodiment, the drawworks controller 420b may be configured to
optimize
drilling operation parameters related to the WOB, such as by maximizing the
actual WOB
without exceeding the WOB input value or range.
[0089] The apparatus 400a also includes a comparator 420d which compares mud
pump pressure data with the mud motor AP tare to generate an "uncorrected" mud
motor AP.
The mud pump pressure data is received from the mud pump pressure sensor 430h,
and the
mud motor AP tare is received from the corresponding user input 410j.
[0090] The apparatus 400a also includes a comparator 420e which utilizes the
uncorrected mud motor AP along with bit depth data and casing pressure data to
generate a
"corrected" or current mud motor AP. The bit depth data is received from the
bit depth
sensor 430i, and the casing pressure data is received from the casing pressure
sensor 430j.
The casing pressure sensor 430j may be a surface casing pressure sensor, such
as the sensor
159 shown in Fig. 1, and/or a downhole casing pressure sensor, such as the
sensor 170a
shown in Fig. 1, and in either case may detect the pressure in the annulus
defined between the
casing or wellbore diameter and a component of the drill string.
23
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
[0091] The drawworks controller 420b compares the current mud motor AP with
mud
motor AP input data. The current mud motor AP is received from the comparator
420e, and
the mud motor AP input data is received from the corresponding user input
410m. The mud
motor AP input data received from the user input 410m may be a single value
indicative of
the desired mud motor AP. For example, if the current mud motor AP differs
from the mud
motor AP input by a predetermined amount, then the drawworks drive control
signal may
direct the drawworks drive 450 to feed cable in or out an amount corresponding
to the
necessary correction of the mud motor AP. However, the mud motor AP input data
received
from the user input 410m may alternatively be a range within which it is
desired that the mud
motor AP be maintained. For example, if the current mud motor AP is outside
this range,
then the drawworks drive control signal may direct the drawworks drive 450 to
feed cable in
or out an amount necessary to restore the current mud motor AP to within the
input range. In
an exemplary embodiment, the drawworks controller 420b may be configured to
optimize
drilling operation parameters related to the mud motor AP, such as by
maximizing the mud
motor AP without exceeding the input value or range.
[0092] The drawworks controller 420b may also or alternatively compare actual
ROP
data with ROP input data. The actual ROP data is received from the ROP sensor
430k, and
the ROP input data is received from the corresponding user input 410k. The ROP
input data
received from the user input 410k may be a single value indicative of the
desired ROP. For
example, if the actual ROP differs from the ROP input by a predetermined
amount, then the
drawworks drive control signal may direct the drawworks drive 450 to feed
cable in or out an
amount corresponding to the necessary correction of the ROP. However, the ROP
input data
received from the user input 410k may alternatively be a range within which it
is desired that
the ROP be maintained. For example, if the actual ROP is outside the ROP input
range, then
the drawworks drive control signal may direct the drawworks drive 450 to feed
cable in or
out an amount necessary to restore the actual ROP to within the ROP input
range. In an
exemplary embodiment, the drawworks controller 420b may be configured to
optimize
drilling operation parameters related to the ROP, such as by maximizing the
actual ROP
without exceeding the ROP input value or range.
[0093] The drawworks controller 420b may also utilize data received from the
toolface controller 420a when generating the drawworks drive control signal.
Changes in the
actual WOB can cause changes in the actual bit torque, the actual mud motor
AP, and the
actual toolface orientation. For example, as weight is increasingly applied to
the bit, the
24
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
actual toolface orientation can rotate opposite the direction of bit rotation
(due to reactive
torque), and the actual bit torque and mud motor pressure can proportionally
increase.
Consequently, the toolface controller 420a may provide data to the drawworks
controller
420b indicating whether the drawworks cable should be fed in or out, and
perhaps a
corresponding feed rate, as necessary to bring the actual toolface orientation
into compliance
with the toolface orientation input value or range provided by the
corresponding user input
410h. In an exemplary embodiment, the drawworks controller 420b may also
provide data to
the toolface controller 420a to rotate the quill clockwise or counterclockwise
by an amount
and/or rate sufficient to compensate for increased or decreased WOB, bit
depth, or casing
pressure.
[0094] As shown in Fig. 4A, the user inputs 410 may also include a pull limit
input
410n. When generating the drawworks drive control signal, the drawworks
controller 420b
may be configured to ensure that the drawworks does not pull past the pull
limit received
from the user input 410n. The pull limit is also known as a hook load limit,
and may be
dependent upon the particular configuration of the drilling rig, among other
parameters.
[0095] In an exemplary embodiment, the drawworks controller 420b may also
provide data to the toolface controller 420a to cause the toolface controller
420a to rotate the
quill, such as by an amount, direction, and/or rate sufficient to compensate
for the pull limit
being reached or exceeded. The toolface controller 420a may also provide data
to the
drawworks controller 420b to cause the drawworks controller 420b to increase
or decrease
the WOB, or to adjust the drill string feed, such as by an amount, direction,
and/or rate
sufficient to adequately adjust the toolface orientation.
[0096] Referring to Fig. 4B, illustrated is a high level schematic view of at
least a
portion of another embodiment of the apparatus 400a, herein designated by the
reference
numeral 400b. Like the apparatus 400a, the apparatus 400b is an exemplary
implementation
of the apparatus 100 shown in Fig. 1 and/or the apparatus 300 shown in Fig. 3,
and is an
exemplary environment in which the method 200a shown in Fig. 2A and/or the
method 200b
shown in Fig. 2B may be performed.
[0097] Like the apparatus 400a, the apparatus 400b includes the plurality of
user
inputs 410 and the at least one steering module 420. The at least one steering
module 420
includes the toolface controller 420a and the drawworks controller 420b,
described above,
and also a mud pump controller 420c. The apparatus 400b also includes or is
otherwise
associated with the plurality of sensors 430, the quill drive 440, and the
drawworks drive 450,
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
like the apparatus 400a. The apparatus 400b also includes or is otherwise
associated with a
mud pump drive 460, which is configured to control operation of a mud pump,
such as the
mud pump 180 shown in Fig. 1. In the exemplary embodiment of the apparatus
400b shown
in Fig. 4B, each of the plurality of sensors 430 may be located at the surface
of the wellbore,
downhole (e.g., MWD), or elsewhere.
[0098] The mud pump controller 420c is configured to generate a mud pump drive
control signal utilizing data received from ones of the user inputs 410 and
the sensors 430.
Thereafter, the mud pump controller 420c provides the mud pump drive control
signal to the
mud pump drive 460, thereby controlling the speed, flow rate, and/or pressure
of the mud
pump. The mud pump controller 420c may form at least a portion of, or may be
formed by at
least a portion of, the controller 190 shown in Fig. 1 and/or the controller
325 shown in Fig.
3.
[0099] As described above, the mud motor AP may be proportional or otherwise
related to toolface orientation, WOB, and/or bit torque. Consequently, the mud
pump
controller 420c may be utilized to influence the actual mud motor AP to assist
in bringing the
actual toolface orientation into compliance with the toolface orientation
input value or range
provided by the corresponding user input. Such operation of the mud pump
controller 420c
may be independent of the operation of the toolface controller 420a and the
drawworks
controller 420b. Alternatively, as depicted by the dual-direction arrows 462
shown in Fig.
4B, the operation of the mud pump controller 420c to obtain or maintain a
desired toolface
orientation may be in conjunction or cooperation with the toolface controller
420a and the
drawworks controller 420b.
[00100] The controllers 420a, 420b, and 420c shown in Figs. 4A and 4B may each
be
or include intelligent or model-free adaptive controllers, such as those
commercially available
from CyberSoft, General Cybernation Group, Inc. The controllers 420a, 420b,
and 420c may
also be collectively or independently implemented on any conventional or
future-developed
computing device, such as one or more personal computers or servers, hand-held
devices,
PLC systems, and/or mainframes, among others.
[00101] Fig. 4C is another high-level block diagram identifying exemplary
components of another alternative rigsite drilling control system 400c of the
apparatus 100 in
Fig. 1. In this exemplary embodiment, the block diagram includes a main
controller 402
including a toolface calculation engine 404, a steering module 420 including a
toolface
controller 420a, a drawworks controller 420b, and a mudpump controller 420f.
In addition,
26
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
the control system includes a user input device 470 that may receive inputs
410 in Fig. 4A, an
output display 472, and sensors 430 in communication with the main controller
402. In the
embodiment shown, the toolface calculation engine 404 and the steering module
420 are
applications that may share the same processor or operate using separate
processors to
perform different, but cooperative functions. Accordingly, the main controller
402 is shown
encompassing drawworks, toolface, and mudpump controllers as well as the
toolface
calculation engine 404. In other embodiments, however, the toolface
calculation engine 404
operates using a separate processor for its calculations and path
determinations. The user
input device 470 and the display 472 may include at least a portion of a user
interface, such
as the user interface 305 shown in Fig. 3. The user-interface and the
controller may be
discrete components that are interconnected via wired or wireless means.
However, they may
alternatively be integral components of a single system, for example.
[00102] As indicated above, a drilling plan includes a wellbore profile or
planned
drilling path. This is the pre-selected pathway for the wellbore to be
drilled, typically until
conditions require a change in the drilling plan. It typically specifies key
points of inflection
along the wellbore and optimum rates of curvature to be used to arrive at the
wellbore
positional objective or objectives, referred to as target locations. To the
extent possible, the
main controller 402 controls the drilling rig to steer the BHA toward the
target location along
the planned drilling path within a specified tolerance zone.
[00103] The calculation engine 404 is a controller or a part of a controller
configured
to calculate a control drilling path for the BHA. This path adheres to the
planned wellbore
drilling path within an acceptable margin of error known as a tolerance zone,
(also referred to
herein as a "tolerance cylinder" merely for exemplary purposes). Based upon
locational and
other feedback, and based upon the original planned drilling path, the
toolface calculation
engine 404 will either produce a recommended toolface angular setting between
0 and 360
degrees and a distance to drill in feet or meters on this toolface setting, or
produce a
recommendation to continue to drill ahead in rotary drilling mode. Preferably,
the angular
setting is as minimally different from the drilled section as possible to
minimize drastic
curvatures that can complicate insertion of casing. These recommendations
ensure that the
BHA travels in the desired direction to arrive at the target location in an
efficient and
effective manner.
[00104] The toolface calculation engine 404 makes its recommendations based on
a
number of factors. For example, the toolface calculation engine 404 considers
the original
27
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
control drilling path, it considers directional trends, and it considers real
time projection to bit
depth. In some embodiments, this engine 404 considers additional information
that helps
identify the location and direction of the BHA. In others, the engine 404
considers only the
directional trends and the original drilling path.
[00105] The original control drilling path may have been directly entered by a
user or
may have been calculated by the toolface calculation engine 404 based upon
parameters
entered by the user. The directional trends may be determined based upon
historical or
existing locational data from the periodic or real-time survey results to
predict bit location.
This may include, for example, the rates of curvature, or dogleg severity,
generated over user
specified drilling intervals of measured depths. These rates can be used as
starting points for
the next control curve to be drilled, and can be provided from an analysis of
the current
drilling behavior from the historical drilling parameters. The calculation of
normal plane
distance to the planned target location can be carried out from a real-time
projection to the bit
position. This real-time projection to bit depth maybe calculated by the
toolface calculation
engine 404 or the steering module 420 based upon static and/or dynamic
information
obtained from the sensors 430. If calculated by the steering module 420, the
values may be
fed to the toolface calculation engine 404 for additional processing. These
projection to bit
depth values may be calculated using any number of methods, including, for
example, the
minimum curvature arc method, the directional trend method, and the straight
line method.
Once the position is calculated, it is used as the start point for the normal
plane clearance
calculation and any subsequent control path or correction path calculations.
[00106] Using these inputs, the toolface calculation engine 404 makes a
determination
of where the actual drilling path lies relative to the planned or control
drilling path. Based on
its findings, the toolface calculation engine 404 creates steering
instructions to help keep the
actual drilling path aligned with the planned drilling path, i.e., within the
tolerance zone.
These instructions may be output as toolface orientation instructions, which
may be used in
input 410h in Fig. 4A. In some embodiments, the created steering instructions
are based on
the extent of deviation of the actual drilling path relative the planned
drilling path, as
discussed further below. An exemplary method 500 performed by the toolface
calculation
engine 404 for determining the amount of deviation from the desired path and
for
determining a corrective path is shown in Fig. 5A.
[00107] In Fig. 5A, the method 500 can begin at step 502, with the toolface
calculation
engine 404 receiving a user-input control or planned drilling path. The
control or planned
28
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
drilling path is the desired path that may be based on multiple factors, but
frequently is
intended to provide a most efficient or effective path from the drilling rig
to the target
location.
[00108] At step 504, the toolface calculation engine 404 considers the current
desired
drilling path, directional trends, and projection to bit depth. As discussed
above, the
directional trends are based on prior survey readings and the projection to
bit depth or bit
position is determined by the toolface calculation engine 404, the steering
module 420, or
other controller or module in the main controller 402. This information is
conveyed from the
calculating component to the toolface calculation engine 404 and includes a
dogleg severity
value that is used to calculate corrective curves when needed, as discussed
below. Here, as a
first iteration, the current desired drilling path may correspond to the
control or planned
drilling path defined in the drill plan received in step 502.
[00109] At step 506, the toolface calculation engine 404 determines the actual
drilling
path based upon the directional trends and the projection to bit depth. As
indicated above,
additional data may be used to determine the actual drilling path and in some
embodiments,
the directional trends may be used to estimate the actual drilling path if the
actual drilling
path measurement is suspect or the needed sensory input for the calculation is
limited. At
step 508, the toolface calculation engine 404 determines whether the actual
path is within a
tolerance zone defined by the current desired drilling path. A tolerance zone
or drill-ahead
zone is shown and described with reference to Fig. 5B.
[00110] Fig. 5B shows an exemplary planned well bore drilling path 530 as a
dashed
line. The planned well bore path 530 forms the axis of a hypothetical
tolerance cylinder 532,
an intervention zone 534, and a correction zone 536. So long as the actual
drilling path is
within the tolerance cylinder 532, the actual drilling path is within an
acceptable range of
deviation from the planned drilling path, and the drilling can continue
without steering
adjustments. The tolerance cylinder may be specified within certain
percentages of distance
from the desired path or from the borehole diameter, and can be dependent in
part on
considerations that are different for each proposed well. For example, the
correction zone
may alternatively be set at about 50% different, or about 20% different, from
the planned
path, while the intervention zone may be set at about 25%, or about 10%,
different from the
planned path. Accordingly, returning to Fig. 5A, if the toolface calculation
engine 404
determines that the actual path is within the tolerance zone about the planned
drilling path at
29
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
step 508, then the process can simply return to step 504 to await receipt of
the next
directional trend and/or projection to bit depth.
[00111] If at step 508, the toolface calculation engine 404 determines that
the actual
drilling path is outside the tolerance cylinder 532 shown in Fig. 5B, then the
toolface
calculation engine 404 determines whether the actual path is within the
intervention zone
534, where the steering module 420 may generate one or more control signals to
intervene to
keep the BHA heading in the desired direction. The intervention zone 534 in
Fig. 5B extends
concentrically about the tolerance cylinder 532. It includes an inner boundary
defined by the
tolerance cylinder 532 and an outer boundary defined by the correction zone
536. If the
actual drilling path were in the intervention zone 534, the actual drilling
path may be
considered to be moderately deviating from the planned drilling path 530. In
this
embodiment, the correction zone 536 is concentric about the intervention zone
534 and
defines the entire region outside the intervention zone 534. If the actual
drilling path were in
the correction zone 536, the actual drilling path may be considered to be
significantly
deviating from the planned drilling path 530.
[00112] Returning now to Fig. 5A, if the actual drilling path is within the
intervention
zone 534 at step 510, then the toolface calculation engine 404 can calculate a
3D curved
section path from the projected bit position towards the planned drilling path
530 at step 512.
As mentioned above, this calculation can be based on data obtained from
current or prior
survey files, and may include a projection of bit depth or bit position and a
dogleg severity
value. The calculated curved section path preferably includes the toolface
orientation
required to follow the curved section and the measured depth ("MD") to drill
in feet or
meters, for example, to bring the BHA back into the tolerance zone as
efficiently as possible
but while minimizing any overcorrection.
[00113] This corrected direction path, as one or more steering signals, is
then output to
the steering module 420 at step 514. Accordingly, one or more of the
controllers 420a, b, fin
Fig. 4C receives the desired tool face orientation data and other advisory
information that
enable the controllers to generate one or more command signals that steer the
BHA. From
the planned drilling path, the steering module 420 and/or other components of
the rigsite
drilling control system 400c can control the drawworks, the top drive, and the
mud pump to
directionally steer the BHA according to the corrected path.
[00114] From here, the process returns to step 504 where the toolface
calculation
engine 404 considers the current planned path, directional trends, and
projection to bit depth.
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
Here, the current planned path is now modified by the curved section path
calculated at step
512. Accordingly during the next iteration, the drilling path considered the
"planned" drilling
path is now the corrective path.
[00115] If at step 5 10, the actual drilling path is not within the
intervention
zone 534, then the toolface calculation engine 404 determines that the actual
drilling
path must then be in the correction zone 536 and determines whether the
planned
path is a critical drilling path at step 516. A critical drilling path is
typically one
where reasons exist that limit the desirability of creating a new planned
drilling path
to the target location. For example, a critical drilling path may be one where
a path
is chosen to avoid underground rock formations and the region outside the
intervention zone 534 includes the rock formation. Of course, designation of a
planned drilling path as a critical path may be made for any reason.
[00116] If the planned drilling path is not a critical path at step 516, then
the
toolface calculation engine 404 generates a new planned path from the
projected
current location of the bit to the target location. This new planned path may
be
independent of, or might not intersect with, the original planned path and may
be
generated based on, for example, the most efficient or effective path to the
target
from the current location. For example, the new path may include the minimum
amount of curvature required from the projected current bit location to the
target.
The new planned path might show measured depth ("MD"), inclination, azimuth,
North-South and East-West, toolface, and dogleg severity ("DLS") or curvature,
at
regular station intervals of about 100 feet or 30 meters, for example. The
path,
toolface orientation data, and other data may be output to the steering module
420
so that the steering module 420 can steer the BHA to follow the new path as
closely
as possible. This output may include the calculated toolface advisory angle
and
distance to drill. Again the process returns to step 504 where the toolface
calculation engine 404 considers the current planned path, directional trends,
and
projection to bit depth. Now the current planned path is the new planned path
calculated at step 518.
[00117] If the planned path is determined to be a critical path at step 516,
however, the
toolface calculation engine 404 creates a path that steers the bit to
intersect with the original
planned path for continued drilling. To do this, as indicated at step 520, the
toolface
calculation engine 404 calculates at least a first 3D curved section path (an
"intersection
31
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
path") from the projected bit position toward the planned drilling path or
toward the target.
Optionally, the toolface calculation engine 404 can additionally calculate a
second 3D curved
section path to merge the BHA into the planned path from the intersection path
before
reaching the target. These curved section paths may be divided by a hold, or
straight section,
depending on how far into the correction zone the BHA has strayed. Of course,
if the
intersection path is planned without a second 3D curved section path, the
revised plan will be
a hold, or straight section, from the deviation to the new target, either the
ultimate target or a
location on the original planned path.
[00118] The toolface calculation engine 404 outputs the revised steering path
including
the newly generated curve(s) as one or more steering signals to the steering
module 420 at
step 514. As above, the revised planned path might include measured depth
(MD),
inclination, azimuth, North-South and East-West, toolface, and DLS at regular
station
intervals of about 100 feet or 30 meters, for example. During the next
iteration, the toolface
calculation engine 404 considers the current planned path, directional trends,
and projection
to bit depth with the current planned path being the corrected planned path at
step 504.
[00119] The method 500 iterates during the drilling process to seek to
maintain the
actual drilling path with the planned path, and to adjust the planned path as
circumstances
require. In some embodiments, the process occurs continuously in real-time.
This can
advantageously permit expedited drilling without need for stopping to rely on
human
consultation of a well plan or to evaluate survey data. In other embodiments,
the process
iterates after a preset drilling period or interval, such as, for example,
about 90 seconds, about
five minutes, about ten minutes, about thirty minutes, or some other duration.
Alternatively,
the iteration may be a predetermined drilling progress depth. For example, the
process may
be iterated when the existing wellbore is extended about five feet, about ten
feet, about fifty
feet, or some other depth. The process interval may also include both a time
and a depth
component. For example, the process may include drilling for at least about
thirty minutes or
until the wellbore is extended about ten feet. In another example, the
interval may include
drilling until the wellbore is extended up to about twenty feet, but no longer
than about ninety
minutes. Of course, the above-described time and depth values for the interval
are merely
examples, and many other values are also within the scope of the present
disclosure.
[00120] Once calculated by the toolface calculation engine 404, typically
electronically, the correction path to the original drilling plan and the
correction path to the
target location are passed to the control components of the rigsite control
system. After
32
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
calculating a correction, the toolface calculation engine 404 or other rigsite
control
component, including the steering module 420, make tool face recommendations
or
commands that can be carried out on the rig.
[001211 In some embodiments, a user may selectively control whether the
toolface
calculation engine 404 creates a new planned path to target or creates a
corrected planned
path to the original plan when the actual drilling path is in the correction
zone 536. For
example, a user may select a default function that instructs the correction
option to calculate a
path to "target" or to "original plan." In some embodiments, the default may
be active during
only designated portions of the original drilling path.
[001221 Because directional control decisions are based on the amount of
deviation of
the drilling well from the planned path, after each survey, a normal plan
proximity scan to the
planned well can be carried out. If the drilling position is in the
intervention zone, a nudge of
the drilling well back towards the plan will typically be recommended. If the
well continues
to diverge from the plan and enters the correction zone, a re-planned path
will typically be
calculated as a correction to target or correction to original plan.
[001231 Some embodiments consider one or more variables in addition to, or in
place of, the real time projection to bit depth or directional trends. Input
variables
may vary for each calculation. In addition, the dogleg severity, or rate of
curvature,
may be used to calculate a suitable curve that limits the amount of
oscillation and
avoids drilling path overshoot. The dogleg severity, or rate of curvature, may
be
derived by analysis using the current drilling behavior of the BHA, from the
historical drilling parameters, or a combination thereof.
[001241 When creating a modified drill plan that returns the BHA to the
original bit path, as when the projected bit location is within the
intervention zone
534 or when the planned drilling path has deviated significantly and is a
critical
path, the goal is to return to the original planned drilling path prior to
arriving at the
target location. The curve profile is still a consideration, however, as the
curve
profile can influence friction, oscillation, and other factors. The dogleg
severity
value may be used to calculate one or both curve calculations as before - the
first
curve turning the bit toward the original planned path or to the target, and
the
optional second curve permitting the BHA to more rapidly align with and follow
the
planned path with a limited amount, or no amount of overshoot or
overcorrection.
One method of determining a curve profile includes calculating a curve-hold or
a
33
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
curve-hold-curve profile to the final point or target location in the original
plan, and
then re-running the calculation on the final target-minus-1 point, survey time
period,
or distance calculation, or other period. The calculating is preferably
achieved
electronically. This continues on, going to the final-minus-2 point and so on,
until
the calculation fails. The last successful calculation of the profile can be
arranged to
produce one or two arcs having the smallest acceptable rates of curvature with
associated drilled lengths. These values determine the tool face advisory
information for the first correction curve that is used to develop the new
drilling
path and that is used to steer the BHA. When the actual drilling path reaches
the
final curve to intersect the original drill plan, in the optional embodiment
where a
second, final curve back to the original drill plan is used, this final curve
is drilled at
the second calculated drilled length and rate of curvature.
[001251 It should be noted that, although the tolerance cylinder 532 and the
intervention zone 534 are shown as cylinders without a circular cross-section,
they
may have other shapes, including without limitation, oval, conical, parabolic
or
others, for example, or may be non-concentric about the planned drilling path
530.
Alternative shapes may, e.g., permits the bit to stray more in one direction
than
another from the planned path, such as depending on geological deposits on one
side
of the planned path. Furthermore, although the example described includes
three
zones (the tolerance zone, the intervention zone, and the correction zone),
this is
merely for sake of explanation. In other embodiments, additional zones may be
included, and additional factors may be weighed when considering whether to
create
a path that intersects with the original planned path, whether to create a
path that
travels directly to the target location without intersecting the original
planned
drilling path, or how gentle the DLS can be on the corrective curve(s).
[001261 In some exemplary embodiments, a driller can increase or decrease the
size of the tolerance on the fly while drilling by inputting data to the
toolface
calculation engine 404. This may help minimize or avoid overcorrection, or
excessive oscillation, in the drilling path.
[001271 Once calculated, data output from the toolface calculation engine 404
may act as the input to the steering module 420 in Fig. 4C, or the steering
module
420 in Fig. 4A. For example, the data output from the toolface calculation
engine
404 may include, among others, a toolface orientation usable as the input 410h
in
34
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
Fig. 4A. In this figure, toolface orientation 410h is an input to the
apparatus 400a
and is used by the toolface controller 420a to control the quill drive 440.
Additional data output from toolface calculation engine 404 may be used as
inputs to
the to the apparatus 400a. Using these inputs, the toolface controller 420a,
the
drawworks controller 420b, and the mudpump controller 420f can control
drilling rig
or the BHA itself to steer the BHA along the desired drilling path.
[00128] In some embodiments, an alerts module may be used to alert drillers
and/or a well monitoring station of a deviation of the bit from the planned
drilling
path, of any potential problem with the drilling system, or of other
information
requiring attention. When drillers are not at the drilling rig, i. e., the
driller(s) are
remotely located from the rig, the alerts module may be associated with the
toolface
calculation engine 404 in a manner that when the toolface calculation engine
404
detects deviation of the bit from the planned drilling path, the alerts module
signals
the driller, and in some cases, can be arranged to await manual user
intervention,
such as an approval, before steering the bit along a new path. This alert may
occur
on the drilling rig through any suitable means, and may appear on the display
472 as
a visual alert. Alternatively, it may be an audible alert or may trigger
transmission
of an alert signal via an RF signal to designated locations or individuals.
[00129] In addition to communicating the alert to the display 472 or other
location about the drilling rig, the alert module may communicate the alert to
an
offsite location. This may permit offsite monitoring and may allow a driller
to make
remote adjustments. These alerts may be communicated via any suitable
transmission link. For example, in some embodiments where the alert module
sends
the alert signal to a remote location, the alert may be through a satellite
communication system. More particularly, one or more orbital (generally fixed
position) satellites may be used to relay communication signals (potentially
bi-
directional) between a well monitoring station and the alerts module on the
offshore
platform. Alternatively, radio, cellular, optical, or hard wired signal
transmission
methods may be used for communication between the alerts module and the
drillers
or the well monitoring station. In situations where the oil drilling location
is an
offshore platform, a satellite communications system may be used, as cellular,
hard
wire, and ship to shore-type systems are in some situations impractical or
unreliable.
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
It should be noted that offsite monitoring and adjustments may be made without
specific alerts, but through using the remote access systems described.
[00130] A centralized well monitoring station may generally be a computer or
server configured to interface with a plurality of alerts modules each
positioned at a
different one of a plurality of well platforms. The well monitoring station
may be
configured to receive various types of signals (satellite, RF, cellular, hard
wired,
optical, ship to shore, and telephone, for example) from a plurality of well
drilling
locations having an alerts module thereon. The well monitoring station may
also be
configured to transmit selected information from the alerts module to a
specific
remote user terminal of a plurality of remote user terminals in communication
with
the alerts module. The well monitoring station may also receive information or
instructions from the remote user terminal. The remote user terminal, via the
well
monitoring station and the alerts module, is configured to display drilling or
production parameters for the well associated with the alerts module.
[00131] The well monitoring station may generally be positioned at a central
data hub, and may be in communication with the alerts module at the drilling
site via
a satellite communications link, for example. The monitoring station may be
configured to allow users to define alerts based on information and data that
is
gathered from the drilling site(s) by various data replication and
synchronization
techniques. As such, received data may not be truly real time in every
embodiment
of the invention, as the alerts depend upon data that has been transmitted
from a
drilling site to the central data hub over a radio or satellite communications
medium
(which inherently takes some time to accomplish).
[00132] In one embodiment, an exemplary alerts module monitors one, two, or
more specific applications or properties. The operation section and the actual
values
that the alert is setup against are also generally database and metadata
driven, and
therefore, when the property is of a particular data type, then the
appropriate
operations may be made available for the user to select.
[00133] Turning now to Fig. 6A, illustrated is a flow-chart diagram of a
method 600a
according to one or more aspects of the present disclosure. The method 600a
may be
performed in association with one or more components of the apparatus 100
shown in Fig. 1
during operation of the apparatus 100. For example, the method 600a may be
performed to
optimize drilling efficiency during drilling operations performed via the
apparatus 100, may
36
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
be carried out by any of the control systems disclosed in any of the figures
herein, including
Figs. 3 and 4A-C, among others.
[00134] The method 600a includes a step 602 during which parameters for
calculating
mechanical specific energy (MSE) are detected, collected, or otherwise
obtained. These
parameters may be referred to herein as MSE parameters and may be used as
input in Figs.
4A-C and others. The MSE parameters include static and dynamic parameters.
That is, some
MSE parameters change on a substantially continual basis. These dynamic MSE
parameters
include the weight on bit (WOB), the drill bit rotational speed (RPM), the
drill string
rotational torque (TOR), and the rate of penetration (ROP) of the drill bit
through the
formation being drilled. Other MSE parameters change infrequently, such as
after tripping
out, reaching a new formation type, and changing bit types, among other
events. These static
MSE parameters include a mechanical efficiency ratio (MER) and the drill bit
diameter
(DIA).
[00135] The MSE parameters may be obtained substantially or entirely
automatically,
with little or no user input required. For example, during the first iteration
through the steps
of the method 600a, the static MSE parameters may be retrieved via automatic
query of a
database. Consequently, during subsequent iterations, the static MSE
parameters may not
require repeated retrieval, such as where the drill bit type or formation data
has not changed
from the previous iteration of the method 600a. Therefore, execution of the
step 602 may, in
many iterations, require only the detection of the dynamic MSE parameters. The
detection of
the dynamic MSE parameters may be performed by or otherwise in association
with a variety
of sensors, such as the sensors shown in Figs. 1, 3, 4A and/or 4B.
37
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
[00136] A subsequent step 604 in the method 600a includes calculating MSE. In
an
exemplary embodiment, MSE is calculated according to the following formula:
MSE = MER x [(4 x WOB) / (it x DIA2) + (480 x RPM x TOR) / (ROP x DIA2)]
where: MSE = mechanical specific energy (pounds per square inch);
MER = mechanical efficiency (ratio);
WOB = weight on bit (pounds);
DIA = drill bit diameter (inches);
RPM = bit rotational speed (rpm);
TOR = drill string rotational torque (foot-pounds); and
ROP = rate of penetration (feet per hour).
[00137] MER may also be referred to as a drill bit efficiency factor. In an
exemplary
embodiment, MER equals 0.35. However, MER may change based on one or more
various
conditions, such as the bit type, formation type, and/or other factors.
[00138] The method 600a also includes a decisional step 606, during which the
MSE
calculated during the previous step 604 is compared to an ideal MSE. The ideal
MSE used
for comparison during the decisional step 606 may be a single value, such as
100%.
Alternatively, the ideal MSE used for comparison during the decisional step
606 may be a
target range of values, such as 90-100%. Alternatively, the ideal MSE maybe a
range of
values derived from an advanced analysis of the area being drilled that
accounts for the
various formations that are being drilled in the current operation.
[00139] If it is determined during step 606 that the MSE calculated during
step 604
equals the ideal MSE, or falls within the ideal MSE range, the method 600a may
be iterated
by proceeding once again to step 602. However, if it is determined during step
606 that the
calculated MSE does not equal the ideal MSE, or does not fall within the ideal
MSE range, an
additional step 608 is performed. During step 608, one or more operating
parameters are
adjusted with the intent of bringing the MSE closer to the ideal MSE value or
within the ideal
MSE range. For example, referring to Figs. 1 and 6A, collectively, execution
of step 608
may include increasing or decreasing WOB, RPM, and/or TOR by transmitting a
control
signal from the controller 190 to the top drive 140 and/or the draw works 130
to change
RPM, TOR, and/or WOB. After step 608 is performed, the method 600a may be
iterated by
proceeding once again to step 602.
38
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
[00140] Each of the steps of the method 600a may be performed automatically.
For
example, automated detection of dynamic MSE parameters and database look-up of
static
MSE parameters have already been described above with respect to step 602. The
controller
190 of Fig. 1 (and others described herein) may be configured to automatically
perform the
MSE calculation of step 604, and may also be configured to automatically
perform the MSE
comparison of decisional step 606, where both the MSE calculation and
comparison may be
performed periodically, at random intervals, or otherwise. The controller may
also be
configured to automatically generate and transmit the control signals of step
608, such as in
response to the MSE comparison of step 606.
[00141] Fig. 6B illustrates a block diagram of apparatus 690 according to one
or more
aspects of the present disclosure. Apparatus 690 includes a user interface
692, a draw-works
694, a drive system 696, and a controller 698. Apparatus 690 may be
implemented within the
environment and/or apparatus shown in Figs. 1, 3, and 4A-4C. For example, the
draw-works
694 may be substantially similar to the draw-works 130 shown in Fig. 1, the
drive system 696
may be substantially similar to the top drive 140 shown in Fig. 1, and/or the
controller 698
may be substantially similar to the controller 190 shown in Fig. 1. Apparatus
690 may also
be utilized in performing the method 200a shown in Fig. 2A, the method 200b
shown in Fig.
2B, the method 500 in Fig. 5A, and/or the method 600a shown in Fig. 6A.
[00142] The user-interface 692 and the controller 698 may be discrete
components that
are interconnected via wired or wireless means. However, the user-interface
692 and the
controller 698 may alternatively be integral components of a single system
699, as indicated
by the dashed lines in Fig. 6B.
[00143] The user-interface 692 includes means 692a for user-input of one or
more
predetermined efficiency data (e.g., MER) values and/or ranges, and means 692b
for user-
input of one or more predetermined bit diameters (e.g., DIA) values and/or
ranges. Each of
the data input means 692a and 692b may include a keypad, voice-recognition
apparatus, dial,
button, switch, slide selector, toggle, joystick, mouse, data base (e.g., with
offset information)
and/or other conventional or future-developed data input device. Such data
input means may
support data input from local and/or remote locations. Alternatively, or
additionally, the data
input means 692a and/or 692b may include means for user-selection of
predetermined MER
and DIA values or ranges, such as via one or more drop-down menus. The MER and
DIA
data may also or alternatively be selected by the controller 698 via the
execution of one or
more database look-up procedures. In general, the data input means and/or
other components
39
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
within the scope of the present disclosure may support system operation and/or
monitoring
from stations on the rig site as well as one or more remote locations with a
communications
link to the system, network, local area network (LAN), wide area network
(WAN), Internet,
and/or radio, among other means.
[00144] The user-interface 692 may also include a display 692c for visually
presenting
information to the user in textual, graphical or video form. The display 692c
may also be
utilized by the user to input the MER and DIA data in conjunction with the
data input means
692a and 692b. For example, the predetermined efficiency and bit diameter data
input means
692a and 692b may be integral to or otherwise communicably coupled with the
display 692c.
[00145] The draw-works 694 includes an ROP sensor 694a that is configured for
detecting an ROP value or range, and may be substantially similar to the ROP
sensor 130a
shown in Fig. 1. The ROP data detected via the ROP sensor 694a may be sent via
electronic
signal to the controller 698 via wired or wireless transmission. The draw-
works 694 also
includes a control circuit 694b and/or other means for controlling feed-out
and/or feed-in of a
drilling line (such as the drilling line 125 shown in Fig. 1).
[00146] The drive system 696 includes a torque sensor 696a that is configured
for
detecting a value or range of the reactive torsion of the drill string (e. g.,
TOR), much the
same as the torque sensor 140a and drill string 155 shown in Fig. 1. The drive
system 696
also includes a bit speed sensor 696b that is configured for detecting a value
or range of the
rotational speed of the drill bit within the wellbore (e.g., RPM), much the
same as the bit
speed sensor 140b, drill bit 175 and wellbore 160 shown in Fig. 1. The drive
system 696 also
includes a WOB sensor 696c that is configured for detecting a WOB value or
range, much
the same as the WOB sensor 140c shown in Fig. 1. Alternatively, or
additionally, the WOB
sensor 696c may be located separate from the drive system 696, whether in
another
component shown in Fig. 6B or elsewhere. The drill string torsion, bit speed,
and WOB data
detected via sensors 696a, 696b and 696c, respectively, may be sent via
electronic signal to
the controller 698 via wired or wireless transmission. The drive system 696
also includes a
control circuit 696d and/or other means for controlling the rotational
position, speed and
direction of the quill or other drill string component coupled to the drive
system 696 (such as
the quill 145 shown in Fig. 1). The control circuit 696d and/or other
component of the drive
system 696 may also include means for controlling downhole mud motor(s). Thus,
RPM
within the scope of the present disclosure may include mud pump flow data
converted to
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
downhole mud motor RPM, which may be added to the string RPM to determine
total bit
RPM.
[00147] The controller 698 is configured to receive the above-described MSE
parameters from the user interface 692, the draw-works 694, and the drive
system 696 and
utilize the MSE parameters to continuously, periodically, or otherwise
calculate MSE. The
controller 698 is further configured to provide a signal to the draw-works 694
and/or the
drive system 696 based on the calculated MSE. For example, the controller 6980
may
execute the method 200a shown in Fig. 2A and/or the method 200b shown in Fig.
2B, and
consequently provide one or more signals to the draw-works 694 and/or the
drive system 696
to increase or decrease WOB and/or bit speed, such as may be required to
optimize drilling
efficiency (based on MSE).
[00148] Referring to Fig. 6C, illustrated is a flow-chart diagram of a method
600b for
optimizing drilling operation based on real-time calculated MSE according to
one or more
aspects of the present disclosure. The data obtained may be used in
cooperation with any of
the systems disclosed herein. The method 600b may be performed via the
apparatus 100
shown in Fig. 1, the apparatus 300 shown in Fig. 3, the apparatus 400a shown
in Fig. 4A, the
apparatus 400b shown in Fig. 4B, and/or the apparatus 690 shown in Fig. 6B.
The method
600b may also be performed in conjunction with the performance of the method
200a shown
in Fig. 2A, the method 200b shown in Fig. 2B, and/or the method 600a shown in
Fig. 6A.
The method 600b shown in Fig. 6C may include or form at least a portion of the
method 600a
shown in Fig. 6A.
[00149] During a step 612 of the method 600b, a baseline MSE is determined for
optimization of drilling efficiency based on MSE by varying WOB. Because the
baseline
MSE determined in step 612 will be utilized for optimization by varying WOB,
the
convention MSEBLWOB will be used herein.
[00150] In a subsequent step 614, the WOB is changed. Such change can include
either increasing or decreasing the WOB. The increase or decrease of WOB
during step 614
may be within certain, predefined WOB limits. For example, the WOB change may
be no
greater than about 10%. However, other percentages are also within the scope
of the present
disclosure, including where such percentages are within or beyond the
predefined WOB
limits. The WOB may be manually changed via operator input, or the WOB may be
automatically changed via signals transmitted by a controller, control system,
and/or other
41
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
component of the drilling rig and associated apparatus. As above, such signals
may be via
remote control from another location.
[00151] Thereafter, during a step 616, drilling continues with the changed WOB
during a predetermined drilling interval AWOB. The AWOB interval may be a
predetermined time period, such as five minutes, ten minutes, thirty minutes,
or some other
duration. Alternatively, the AWOB interval may be a predetermined drilling
progress depth.
For example, step 616 may include continuing drilling operation with the
changed WOB until
the existing wellbore is extended five feet, ten feet, fifty feet, or some
other depth. The
AWOB interval may also include both a time and a depth component. For example,
the
AWOB interval may include drilling for at least thirty minutes or until the
wellbore is
extended ten feet. In another example, the AWOB interval may include drilling
until the
wellbore is extended twenty feet, but no longer than ninety minutes. Of
course, the above-
described time and depth values for the AWOB interval are merely examples, and
many other
values are also within the scope of the present disclosure.
[00152] After continuing drilling operation through the AWOB interval with the
changed WOB, a step 618 is performed to determine the MSEAWOB resulting from
operating
with the changed WOB during the AWOB interval. In a subsequent decisional step
620, the
changed MSEAWOB is compared to the baseline MSEBLWOB. If the changed MSEAWOB
is
desirable relative to the MSEBLWOB, the method 600b continues to a step 622.
However, if
the changed MSEAWOB is not desirable relative to the MSEBLWOB, the method 600b
continues
to a step 624 where the WOB is restored to its value before step 614 was
performed, and the
method then continues to step 622.
[00153] The determination made during decisional step 620 may be performed
manually or automatically by a controller, control system, and/or other
component of the
drilling rig and associated apparatus. The determination may include finding
the MSEAWOB
to be desirable if it is substantially equal to and/or less than the MSEBLWOB.
However,
additional or alternative factors may also play a role in the determination
made during step
620.
[00154] During step 622 of the method 600b, a baseline MSE is determined for
optimization of drilling efficiency based on MSE by varying the bit rotational
speed, RPM.
Because the baseline MSE determined in step 622 will be utilized for
optimization by varying
RPM, the convention MSEBLRPM will be used herein.
42
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
[001551 In a subsequent step 626, the RPM is changed. Such change can include
either
increasing or decreasing the RPM. The increase or decrease of RPM during step
626 may be
within certain, predefined RPM limits. For example, the RPM change may be no
greater than
about 10%. However, other percentages are also within the scope of the present
disclosure,
including where such percentages are within or beyond the predefined RPM
limits. The
RPM may be manually changed via operator input, or the RPM may be
automatically
changed via signals transmitted by a controller, control system, and/or other
component of
the drilling rig and associated apparatus.
[001561 Thereafter, during a step 628, drilling continues with the changed RPM
during
a predetermined drilling interval ARPM. The ARPM interval may be a
predetermined time
period, such as five minutes, ten minutes, thirty minutes, or some other
duration.
Alternatively, the ARPM interval may be a predetermined drilling progress
depth. For
example, step 628 may include continuing drilling operation with the changed
RPM until the
existing wellbore is extended five feet, ten feet, fifty feet, or some other
depth. The ARPM
interval may also include both a time and a depth component. For example, the
ARPM
interval may include drilling for at least thirty minutes or until the
wellbore is extended ten
feet. In another example, the ARPM interval may include drilling until the
wellbore is
extended twenty feet, but no longer than ninety minutes. Of course, the above-
described time
and depth values for the ARPM interval are merely examples, and many other
values are also
within the scope of the present disclosure.
[001571 After continuing drilling operation through the ARPM interval with the
changed RPM, a step 630 is performed to determine the MSEpM resulting from
operating
with the changed RPM during the ARPM interval. In a subsequent decisional step
632, the
changed MSEARpM is compared to the baseline MSEBLRPM. If the changed MSEAuM is
desirable relative to the MSEBLRPM, the method 600b returns to step 612.
However, if the
changed MSEpM is not desirable relative to the MSEBLRPM, the method 600b
continues to
step 634 where the RPM is restored to its value before step 626 was performed,
and the
method then continues to step 612.
[001581 The determination made during decisional step 632 may be performed
manually or automatically by a controller, control system, and/or other
component of the
drilling rig and associated apparatus. The determination may include finding
the MSEyM to
be desirable if it is substantially equal to and/or less than the MSEBLRPM.
However,
43
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
additional or alternative factors may also play a role in the determination
made during step
632.
[00159] Moreover, after steps 632 and/or 634 are performed, the method 600b
may not
immediately return to step 612 for a subsequent iteration. For example, a
subsequent
iteration of the method 600b may be delayed for a predetermined time interval
or drilling
progress depth. Alternatively, the method 600b may end after the performance
of steps 632
and/or 634.
[00160] Referring to Fig. 6D, illustrated is a flow-chart diagram of a method
600c for
optimizing drilling operation based on real-time calculated MSE according to
one or more
aspects of the present disclosure. The method 600c may be performed via the
apparatus 100
shown in Fig. 1, the apparatus 300 shown in Fig. 3, the apparatus 400a shown
in Fig. 4A, the
apparatus 400b shown in Fig. 4B, and/or the apparatus 690 shown in Fig. 6B.
The method
600c may also be performed in conjunction with the performance of the method
200a shown
in Fig. 2A, the method 200b shown in Fig. 2B, the method 600a shown in Fig.
6A, and/or the
method 600b shown in Fig. 6C. The method 600c shown in Fig. 6D may include or
form at
least a portion of the method 600a shown in Fig. 6A and/or the method 600b
shown in Fig.
6C.
[00161] During a step 640 of the method 600c, a baseline MSE is determined for
optimization of drilling efficiency based on MSE by decreasing WOB. Because
the baseline
MSE determined in step 640 will be utilized for optimization by decreasing
WOB, the
convention MSEBL_WOB will be used herein.
[00162] In a subsequent step 642, the WOB is decreased. The decrease of WOB
during step 642 may be within certain, predefined WOB limits. For example, the
WOB
decrease may be no greater than about 10%. However, other percentages are also
within the
scope of the present disclosure, including where such percentages are within
or beyond the
predefined WOB limits. The WOB may be manually decreased via operator input,
or the
WOB may be automatically decreased via signals transmitted by a controller,
control system,
and/or other component of the drilling rig and associated apparatus.
[00163] Thereafter, during a step 644, drilling continues with the decreased
WOB
during a predetermined drilling interval -AWOB. The -AWOB interval may be a
predetermined time period, such as five minutes, ten minutes, thirty minutes,
or some other
duration. Alternatively, the -AWOB interval may be a predetermined drilling
progress depth.
For example, step 644 may include continuing drilling operation with the
decreased WOB
44
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
until the existing wellbore is extended five feet, ten feet, fifty feet, or
some other depth. The -
AWOB interval may also include both a time and a depth component. For example,
the -
AWOB interval may include drilling for at least thirty minutes or until the
wellbore is
extended ten feet. In another example, the -AWOB interval may include drilling
until the
wellbore is extended twenty feet, but no longer than ninety minutes. Of
course, the above-
described time and depth values for the -AWOB interval are merely examples,
and many
other values are also within the scope of the present disclosure.
[00164] After continuing drilling operation through the -AWOB interval with
the
decreased WOB, a step 646 is performed to determine the MSE_AWOB resulting
from
operating with the decreased WOB during the -AWOB interval. In a subsequent
decisional
step 648, the decreased MSE_AWOB is compared to the baseline MSEBL_WOB. If the
decreased
MSE_AWOB is desirable relative to the MSEBL_WOB, the method 600c continues to
a step 652.
However, if the decreased MSE_AWOB is not desirable relative to the MSEBL_WOB,
the method
600c continues to a step 650 where the WOB is restored to its value before
step 642 was
performed, and the method then continues to step 652.
[00165] The determination made during decisional step 648 may be performed
manually or automatically by a controller, control system, and/or other
component of the
drilling rig and associated apparatus. The determination may include finding
the MSE_AWOB
to be desirable if it is substantially equal to and/or less than the
MSEBL_WOB. However,
additional or alternative factors may also play a role in the determination
made during step
648.
[00166] During step 652 of the method 600c, a baseline MSE is determined for
optimization of drilling efficiency based on MSE by increasing the WOB.
Because the
baseline MSE determined in step 652 will be utilized for optimization by
increasing WOB,
the convention MSEBL+WOB will be used herein.
[00167] In a subsequent step 654, the WOB is increased. The increase of WOB
during
step 654 may be within certain, predefined WOB limits. For example, the WOB
increase
may be no greater than about 10%. However, other percentages are also within
the scope of
the present disclosure, including where such percentages are within or beyond
the predefined
WOB limits. The WOB may be manually increased via operator input, or the WOB
may be
automatically increased via signals transmitted by a controller, control
system, and/or other
component of the drilling rig and associated apparatus.
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
[00168] Thereafter, during a step 656, drilling continues with the increased
WOB
during a predetermined drilling interval +AWOB. The +AWOB interval may be a
predetermined time period, such as five minutes, ten minutes, thirty minutes,
or some other
duration. Alternatively, the +AWOB interval may be a predetermined drilling
progress
depth. For example, step 656 may include continuing drilling operation with
the increased
WOB until the existing wellbore is extended five feet, ten feet, fifty feet,
or some other depth.
The +AWOB interval may also include both a time and a depth component. For
example, the
+AWOB interval may include drilling for at least thirty minutes or until the
wellbore is
extended ten feet. In another example, the +AWOB interval may include drilling
until the
wellbore is extended twenty feet, but no longer than ninety minutes.
[00169] After continuing drilling operation through the +AWOB interval with
the
increased WOB, a step 658 is performed to determine the MSE+AWOB resulting
from
operating with the increased WOB during the +AWOB interval. In a subsequent
decisional
step 660, the changed MSE+AWOB is compared to the baseline MSEBL+WOB. If the
changed
MSE+AWOB is desirable relative to the MSEBL+WOB, the method 600c continues to
a step 664.
However, if the changed MSE+AWOB is not desirable relative to the MSEBL+WOB,
the method
600c continues to a step 662 where the WOB is restored to its value before
step 654 was
performed, and the method then continues to step 664.
[00170] The determination made during decisional step 660 may be performed
manually or automatically by a controller, control system, and/or other
component of the
drilling rig and associated apparatus. The determination may include finding
the MSE+AWOB
to be desirable if it is substantially equal to and/or less than the
MSEBL+WOB. However,
additional or alternative factors may also play a role in the determination
made during step
660.
[00171] During step 664 of the method 600c, a baseline MSE is determined for
optimization of drilling efficiency based on MSE by decreasing the bit
rotational speed,
RPM. Because the baseline MSE determined in step 664 will be utilized for
optimization by
decreasing RPM, the convention MSEBL_RPM will be used herein.
[00172] In a subsequent step 666, the RPM is decreased. The decrease of RPM
during
step 666 may be within certain, predefined RPM limits. For example, the RPM
decrease may
be no greater than about 10%. However, other percentages are also within the
scope of the
present disclosure, including where such percentages are within or beyond the
predefined
RPM limits. The RPM may be manually decreased via operator input, or the RPM
may be
46
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
automatically decreased via signals transmitted by a controller, control
system, and/or other
component of the drilling rig and associated apparatus.
[00173] Thereafter, during a step 668, drilling continues with the decreased
RPM
during a predetermined drilling interval -ARPM. The -ARPM interval may be a
predetermined time period, such as five minutes, ten minutes, thirty minutes,
or some other
duration. Alternatively, the -ARPM interval may be a predetermined drilling
progress depth.
For example, step 668 may include continuing drilling operation with the
decreased RPM
until the existing wellbore is extended five feet, ten feet, fifty feet, or
some other depth. The -
ARPM interval may also include both a time and a depth component. For example,
the -
ARPM interval may include drilling for at least thirty minutes or until the
wellbore is
extended ten feet. In another example, the -ARPM interval may include drilling
until the
wellbore is extended twenty feet, but no longer than ninety minutes.
[00174] After continuing drilling operation through the -ARPM interval with
the
decreased RPM, a step 670 is performed to determine the MSE_oRpM resulting
from operating
with the decreased RPM during the -ARPM interval. In a subsequent decisional
step 672, the
decreased MSE_ARpM is compared to the baseline MSEBL_RPM. If the changed
MSE_AUM is
desirable relative to the MSEBL_RPM, the method 600c continues to a step 676.
However, if
the changed MSE_opyM is not desirable relative to the MSEBL_RPM, the method
600c continues
to a step 674 where the RPM is restored to its value before step 666 was
performed, and the
method then continues to step 676.
[00175] The determination made during decisional step 672 may be performed
manually or automatically by a controller, control system, and/or other
component of the
drilling rig and associated apparatus. The determination may include finding
the MSE_oxPM
to be desirable if it is substantially equal to and/or less than the
MSEBL_RPM. However,
additional or alternative factors may also play a role in the determination
made during step
672.
[00176] During step 676 of the method 600c, a baseline MSE is determined for
optimization of drilling efficiency based on MSE by increasing the bit
rotational speed, RPM.
Because the baseline MSE determined in step 676 will be utilized for
optimization by
increasing RPM, the convention MSEBL+RPM will be used herein.
[00177] In a subsequent step 678, the RPM is increased. The increase of RPM
during
step 678 may be within certain, predefined RPM limits. For example, the RPM
increase may
be no greater than about 10%. However, other percentages are also within the
scope of the
47
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
present disclosure, including where such percentages are within or beyond the
predefined
RPM limits. The RPM may be manually increased via operator input, or the RPM
may be
automatically increased via signals transmitted by a controller, control
system, and/or other
component of the drilling rig and associated apparatus.
[00178] Thereafter, during a step 680, drilling continues with the increased
RPM
during a predetermined drilling interval +ARPM. The +ARPM interval may be a
predetermined time period, such as five minutes, ten minutes, thirty minutes,
or some other
duration. Alternatively, the +ARPM interval may be a predetermined drilling
progress depth.
For example, step 680 may include continuing drilling operation with the
increased RPM
until the existing wellbore is extended five feet, ten feet, fifty feet, or
some other depth. The
+ARPM interval may also include both a time and a depth component. For
example, the
+ARPM interval may include drilling for at least thirty minutes or until the
wellbore is
extended ten feet. In another example, the +ARPM interval may include drilling
until the
wellbore is extended twenty feet, but no longer than ninety minutes.
[00179] After continuing drilling operation through the +ARPM interval with
the
increased RPM, a step 682 is performed to determine the MSE+ARPM resulting
from operating
with the increased RPM during the +ARPM interval. In a subsequent decisional
step 684, the
increased MSE+ARPM is compared to the baseline MSEBL+RPM. If the changed
MSE+ARPM is
desirable relative to the MSEBL+RPM, the method 600c continues to a step 688.
However, if
the changed MSE+ARPM is not desirable relative to the MSEBL+RPM, the method
600c continues
to a step 686 where the RPM is restored to its value before step 678 was
performed, and the
method then continues to step 688.
[00180] The determination made during decisional step 684 may be performed
manually or automatically by a controller, control system, and/or other
component of the
drilling rig and associated apparatus. The determination may include finding
the MSE+ARPM
to be desirable if it is substantially equal to and/or less than the
MSEBL+RPM. However,
additional or alternative factors may also play a role in the determination
made during step
684.
[00181] Step 688 includes awaiting a predetermined time period or drilling
depth
interval before reiterating the method 600c by returning to step 640. However,
in an
exemplary embodiment, the interval may be as small as 0 seconds or 0 feet,
such that the
method returns to step 640 substantially immediately after performing steps
684 and/or 686.
48
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
Alternatively, the method 600c may not require iteration, such that the method
600c may
substantially end after the performance of steps 684 and/or 686.
[00182] Moreover, the drilling intervals -AWOB, +AWOB, -ARPM and +AROM may
each be substantially identical within a single iteration of the method 600c.
Alternatively,
one or more of the intervals may vary in duration or depth relative to the
other intervals.
Similarly, the amount that the WOB is decreased and increased in steps 642 and
654 may be
substantially identical or may vary relative to each other within a single
iteration of the
method 600c. The amount that the RPM is decreased and increased in steps 666
and 678 may
be substantially identical or may vary relative to each other within a single
iteration of the
method 600c. The WOB and RPM variances may also change or stay the same
relative to
subsequent iterations of the method 600c.
[00183] As described above, one or more aspects of the present disclosure may
be
utilized for drilling operation or control based on MSE. However, one or more
aspects of the
present disclosure may additionally or alternatively be utilized for drilling
operation or
control based on AT. That is, as described above, during drilling operation,
torque is
transmitted from the top drive or other rotary drive to the drill string. The
torque required to
drive the bit may be referred to as the Torque On Bit (TOB), and may be
monitored utilizing
a sensor such as the torque sensor 140a shown in Fig. 1, the torque sensor 355
shown in Fig.
3, one or more of the sensors 430 shown in Figs. 4A and 4B, the torque sensor
696a shown in
Fig. 6B, and/or one or more torque sensing devices of the BHA.
[00184] The drill string undergoes various types of vibration during drilling,
including
axial (longitudinal) vibrations, bending (lateral) vibrations, and torsional
(rotational)
vibrations. The torsional vibrations are caused by nonlinear interaction
between the bit, the
drill string, and the wellbore. As described above, this torsional vibration
can include stick-
slip vibration, characterized by alternating stops (during which the BHA
"sticks" to the
wellbore) and intervals of large angular velocity of the BHA (during which the
BHA "slips"
relative to the wellbore).
[00185] The stick-slip behavior of the BHA causes real-time variations of TOB,
or AT.
This AT may be utilized to support a Stick Slip Alarm (SSA) according to one
or more
aspects of the present disclosure. For example, a AT or SSA parameter may be
displayed
visually with a "Stop Light" indicator, where a green light may indicate an
acceptable
operating condition (e.g., SSA parameter of 0-15), an amber light may indicate
that stick-slip
behavior is imminent (e.g., SSA parameter of 16-25), and a red light may
indicate that stick-
49
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
slip behavior is likely occurring (e.g., SSA parameter above 25). However,
these example
thresholds may be adjustable during operation, as they may change with the
drilling
conditions. The AT or SSA parameter may alternatively or additionally be
displayed
graphically (e.g., showing current and historical data), audibly (e.g., via an
annunciator),
and/or via a meter or gauge display. Combinations of these display options are
also within
the scope of the present disclosure. For example, the above-described "Stop
Light" indicator
may continuously indicate the SSA parameter regardless of its value, and an
audible alarm
may be triggered if the SSA parameter exceeds a predetermined value (e.g.,
25).
[00186] A drilling operation controller or other apparatus within the scope of
the
present disclosure may have integrated therein one or more aspects of drilling
operation or
control based on AT or the SSA parameter as described above. For example, a
controller
such as the controller 190 shown in Fig. 1, the controller 325 shown in Fig.
3, controller 420
shown in Figs. 4A or 4B, and/or the controller 698 shown in Fig. 6B may be
configured to
automatically adjust the drill string RPM with a short burst of increased or
decreased RPM
(e.g., +/- 5 RPM) to disrupt the harmonic of stick-slip vibration, either
prior to or when stick-
slip is detected, and then return to normal RPM. The controller may be
configured to
automatically step RPM up or down by a predetermined or user-adjustable
quantity or
percentage for a predetermined or user-adjustable duration, in attempt to move
drilling
operation out of the harmonic state. Alternatively, the controller may be
configured to
automatically continue to adjust RPM up or down incrementally until the AT or
SSA
parameter indicates that the stick-slip operation has been halted.
[00187] In an exemplary embodiment, the AT or SSA-enabled controller may be
further configured to automatically reduce WOB if stick slip is severe, such
as may be due to
an excessively high target WOB. Such automatic WOB reduction may include a
single
adjustment or incremental adjustments, whether temporary or long-term, and
which may be
sustained until the AT or SSA parameter indicates that the stick-slip
operation has been
halted.
[00188] The AT or SSA-enabled controller may be further configured to
automatically
increase WOB, such as to find the upper WOB stick-slip limit. For example, if
all other
possible drilling parameters are optimized or adjusted to within corresponding
limits, the
controller may automatically increase WOB incrementally until the AT or SSA
parameter
nears or equals its upper limit (e.g., 25).
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
[001891 In an exemplary embodiment, AT-based drilling operation or control
according to one or more aspects of the present disclosure may function
according to one or
more aspects of the following pseudo-code:
IF (counter <= Process Time)
IF (counter = = 1)
Minimum Torque = Realtime_Torque
PRINT ("Minimum", Minimum_Torque)
Maximum Torque = Realtime Torque
PRINT ("Maximum", Maximum Torque)
END
IF (Realtime_Torque < Minimum Torque)
Minimum Torque = RealtimeTorque
END
IF (Maximum_Torque < Realtime_Torque)
Maximum_Torque = Realtime_Torque
END
Torquecounter = (Torquecounter + Realtime Torque)
Average_Torque = (Torque_counter / counter)
counter = counter + 1
PRINT ("Process Time", Process Time)
ELSE
SSA = ((Maximum_Torque - Minimum_Torque) / Average_Torque) * 100
where Process Time is the time elapsed since monitoring of the AT or SSA
parameter
commenced, Minimum Torque is the minimum TOB which occurred during Process
Time,
Maximum Torque is the maximum TOB which occurred during Process Time,
Realtime_Torque is current TOB, Average Torque is the average TOB during
Process Time,
and SSA is the Stick-Slip Alarm parameter.
[001901 As described above, the AT or SSA parameter may be utilized within or
otherwise according to the method 200a shown in Fig. 2A, the method 200b shown
in Fig.
2B, the method 600a shown in Fig. 6A, the method 600b shown in Fig. 6C, and/or
the
method 600c shown in Fig. 6D. For example, as shown in Fig. 7A, the AT or SSA
parameter
51
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
may be substituted for the MSE parameter described above with reference to
Fig. 6A.
Alternatively, the AT or SSA parameter may be monitored in addition to the MSE
parameter
described above with reference to Fig. 6A, such that drilling operation or
control is based on
both MSE and the AT or SSA parameter.
[00191] Referring to Fig. 7A, illustrated is a flow-chart diagram of a method
700a
according to one or more aspects of the present disclosure. The method 700a
may be
performed in association with one or more components of the apparatus 100
shown in Fig. 1,
the apparatus 300 shown in Fig. 3, the apparatus 400a shown in Fig. 4A, the
apparatus 400b
shown in Fig. 4B, and/or the apparatus 690 shown in Fig. 6B, during operation
thereof.
[00192] The method 700a includes a step 702 during which current AT parameters
are
measured. In a subsequent step 704, the AT is calculated. If the AT is
sufficiently equal to
the desired AT or otherwise ideal, as determined during decisional step 706,
the method 700a
is iterated and the step 702 is repeated. "Ideal" may be as described above.
The iteration of
the method 700a may be substantially immediate, or there may be a delay period
before the
method 700a is iterated and the step 702 is repeated. If the AT is not ideal,
as determined
during decisional step 706, the method 700a continues to a step 708 during
which one or
more drilling parameters (e.g., WOB, RPM, etc.) are adjusted in attempt to
improve the AT.
After step 708 is performed, the method 700a is iterated and the step 702 is
repeated. Such
iteration may be substantially immediate, or there may be a delay period
before the method
700a is iterated and the step 702 is repeated.
[00193] Referring to Fig. 7B, illustrated is a flow-chart diagram of a method
700b for
monitoring AT and/or SSA according to one or more aspects of the present
disclosure. The
method 700b may be performed via the apparatus 100 shown in Fig. 1, the
apparatus 300
shown in Fig. 3, the apparatus 400a shown in Fig. 4A, the apparatus 400b shown
in Fig. 4B,
and/or the apparatus 690 shown in Fig. 6B. The method 700b may also be
performed in
conjunction with the performance of the method 200a shown in Fig. 2A, the
method 200b
shown in Fig. 2B, the method 600a shown in Fig. 6A, the method 600b shown in
Fig. 6C, the
method 600c shown in Fig. 6D, and/or the method 700a shown in Fig. 7A. The
method 700b
shown in Fig. 7B may include or form at least a portion of the method 700a
shown in Fig.
7A.
[00194] During a step 712 of the method 700b, a baseline AT is determined for
optimization based on AT by varying WOB. Because the baseline AT determined in
step 712
52
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
will be utilized for optimization by varying WOB, the convention ATBLWOB will
be used
herein.
[00195] In a subsequent step 714, the WOB is changed. Such change can include
either increasing or decreasing the WOB. The increase or decrease of WOB
during step 714
may be within certain, predefined WOB limits. For example, the WOB change may
be no
greater than about 10%. However, other percentages are also within the scope
of the present
disclosure, including where such percentages are within or beyond the
predefined WOB
limits. The WOB may be manually changed via operator input, or the WOB may be
automatically changed via signals transmitted by a controller, control system,
and/or other
component of the drilling rig and associated apparatus. As above, such signals
may be via
remote control from another location.
[00196] Thereafter, during a step 716, drilling continues with the changed WOB
during a predetermined drilling interval AWOB. The AWOB interval may be a
predetermined time period, such as five minutes, ten minutes, thirty minutes,
or some other
duration. Alternatively, the AWOB interval may be a predetermined drilling
progress depth.
For example, step 716 may include continuing drilling operation with the
changed WOB until
the existing wellbore is extended five feet, ten feet, fifty feet, or some
other depth. The
AWOB interval may also include both a time and a depth component. For example,
the
AWOB interval may include drilling for at least thirty minutes or until the
wellbore is
extended ten feet. In another example, the AWOB interval may include drilling
until the
wellbore is extended twenty feet, but no longer than ninety minutes. Of
course, the above-
described time and depth values for the AWOB interval are merely examples, and
many other
values are also within the scope of the present disclosure.
[00197] After continuing drilling operation through the AWOB interval with the
changed WOB, a step 718 is performed to determine the ATAWOB resulting from
operating
with the changed WOB during the AWOB interval. In a subsequent decisional step
720, the
changed ATAWOB is compared to the baseline ATBLWOB. If the changed ATAWOB is
desirable
relative to the ATBLWOB, the method 700b continues to a step 722. However, if
the changed
ATAWOB is not desirable relative to the ATBLWOB, the method 700b continues to
a step 724
where the WOB is restored to its value before step 714 was performed, and the
method then
continues to step 722.
[00198] The determination made during decisional step 720 may be performed
manually or automatically by a controller, control system, and/or other
component of the
53
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
drilling rig and associated apparatus. The determination may include finding
the ATAWOB to
be desirable if it is substantially equal to and/or less than the ATBLWOB.
However, additional
or alternative factors may also play a role in the determination made during
step 720.
[00199] During step 722 of the method 700b, a baseline AT is determined for
optimization based on AT by varying the bit rotational speed, RPM. Because the
baseline AT
determined in step 722 will be utilized for optimization by varying RPM, the
convention
ATBLRPM will be used herein.
[00200] In a subsequent step 726, the RPM is changed. Such change can include
either
increasing or decreasing the RPM. The increase or decrease of RPM during step
726 may be
within certain, predefined RPM limits. For example, the RPM change may be no
greater than
about 10%. However, other percentages are also within the scope of the present
disclosure,
including where such percentages are within or beyond the predefined RPM
limits. The
RPM may be manually changed via operator input, or the RPM may be
automatically
changed via signals transmitted by a controller, control system, and/or other
component of
the drilling rig and associated apparatus.
[00201] Thereafter, during a step 728, drilling continues with the changed RPM
during
a predetermined drilling interval ARPM. The ARPM interval may be a
predetermined time
period, such as five minutes, ten minutes, thirty minutes, or some other
duration.
Alternatively, the ARPM interval may be a predetermined drilling progress
depth. For
example, step 728 may include continuing drilling operation with the changed
RPM until the
existing wellbore is extended five feet, ten feet, fifty feet, or some other
depth. The ARPM
interval may also include both a time and a depth component. For example, the
ARPM
interval may include drilling for at least thirty minutes or until the
wellbore is extended ten
feet. In another example, the ARPM interval may include drilling until the
wellbore is
extended twenty feet, but no longer than ninety minutes. Of course, the above-
described time
and depth values for the ARPM interval are merely examples, and many other
values are also
within the scope of the present disclosure.
[00202] After continuing drilling operation through the ARPM interval with the
changed RPM, a step 730 is performed to determine the ATOM resulting from
operating
with the changed RPM during the ARPM interval. In a subsequent decisional step
732, the
changed ATARPM is compared to the baseline ATBLRPM. If the changed ATARPM is
desirable
relative to the ATBLRPM, the method 700b returns to step 712. However, if the
changed
ATOM is not desirable relative to the ATBLRPM, the method 700b continues to
step 734 where
54
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
the RPM is restored to its value before step 726 was performed, and the method
then
continues to step 712.
[00203] The determination made during decisional step 732 may be performed
manually or automatically by a controller, control system, and/or other
component of the
drilling rig and associated apparatus. The determination may include finding
the ATAPPM to
be desirable if it is substantially equal to and/or less than the OTBLRPM=
However, additional
or alternative factors may also play a role in the determination made during
step 732.
[00204] Moreover, after steps 732 and/or 734 are performed, the method 700b
may not
immediately return to step 712 for a subsequent iteration. For example, a
subsequent
iteration of the method 700b may be delayed for a predetermined time interval
or drilling
progress depth. Alternatively, the method 700b may end after the performance
of steps 732
and/or 734.
[00205] Referring to Fig. 7C, illustrated is a flow-chart diagram of a method
700c for
optimizing drilling operation based on real-time calculated AT according to
one or more
aspects of the present disclosure. The method 700c may be performed via the
apparatus 100
shown in Fig. 1, the apparatus 300 shown in Fig. 3, the apparatus 400a shown
in Fig. 4A, the
apparatus 400b shown in Fig. 4B, and/or the apparatus 690 shown in Fig. 6B.
The method
700c may also be performed in conjunction with the performance of the method
200a shown
in Fig. 2A, the method 200b shown in Fig. 2B, the method 600a shown in Fig.
6A, the
method 600b shown in Fig. 6C, the method 600c shown in Fig. 6D, the method
700a shown
in Fig. 7A, and/or the method 700b shown in Fig. 7B. The method 700c shown in
Fig. 7C
may include or form at least a portion of the method 700a shown in Fig. 7A
and/or the
method 700b shown in Fig. 7B.
[00206] During a step 740 of the method 700c, a baseline AT is determined for
optimization based on AT by decreasing WOB. Because the baseline AT determined
in step
740 will be utilized for optimization by decreasing WOB, the convention
OTBL_WOB will be
used herein.
[00207] In a subsequent step 742, the WOB is decreased. The decrease of WOB
during step 742 may be within certain, predefined WOB limits. For example, the
WOB
decrease may be no greater than about 10%. However, other percentages are also
within the
scope of the present disclosure, including where such percentages are within
or beyond the
predefined WOB limits. The WOB may be manually decreased via operator input,
or the
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
WOB may be automatically decreased via signals transmitted by a controller,
control system,
and/or other component of the drilling rig and associated apparatus.
[00208] Thereafter, during a step 744, drilling continues with the decreased
WOB
during a predetermined drilling interval -AWOB. The -AWOB interval may be a
predetermined time period, such as five minutes, ten minutes, thirty minutes,
or some other
duration. Alternatively, the -AWOB interval may be a predetermined drilling
progress depth.
For example, step 744 may include continuing drilling operation with the
decreased WOB
until the existing wellbore is extended five feet, ten feet, fifty feet, or
some other depth. The -
AWOB interval may also include both a time and a depth component. For example,
the -
AWOB interval may include drilling for at least thirty minutes or until the
wellbore is
extended ten feet. In another example, the -AWOB interval may include drilling
until the
wellbore is extended twenty feet, but no longer than ninety minutes. Of
course, the above-
described time and depth values for the -AWOB interval are merely examples,
and many
other values are also within the scope of the present disclosure.
[00209] After continuing drilling operation through the -AWOB interval with
the
decreased WOB, a step 746 is performed to determine the AT_AWOB resulting from
operating
with the decreased WOB during the -AWOB interval. In a subsequent decisional
step 748,
the decreased AT_AWOB is compared to the baseline ATBL-WOB= If the decreased
AT_AWOB is
desirable relative to the ATBL_WOB, the method 700c continues to a step 752.
However, if the
decreased AT_AWOB is not desirable relative to the ATBL_WOB, the method 700c
continues to a
step 750 where the WOB is restored to its value before step 742 was performed,
and the
method then continues to step 752.
[00210] The determination made during decisional step 748 may be performed
manually or automatically by a controller, control system, and/or other
component of the
drilling rig and associated apparatus. The determination may include finding
the AT_AWOB to
be desirable if it is substantially equal to and/or less than the ATBL-WOB=
However, additional
or alternative factors may also play a role in the determination made during
step 748.
[00211] During step 752 of the method 700c, a baseline AT is determined for
optimization based on AT by increasing the WOB. Because the baseline AT
determined in
step 752 will be utilized for optimization by increasing WOB, the convention
ATBL+WOB Will
be used herein.
[00212] In a subsequent step 754, the WOB is increased. The increase of WOB
during
step 754 may be within certain, predefined WOB limits. For example, the WOB
increase
56
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
may be no greater than about 10%. However, other percentages are also within
the scope of
the present disclosure, including where such percentages are within or beyond
the predefined
WOB limits. The WOB may be manually increased via operator input, or the WOB
may be
automatically increased via signals transmitted by a controller, control
system, and/or other
component of the drilling rig and associated apparatus.
[00213] Thereafter, during a step 756, drilling continues with the increased
WOB
during a predetermined drilling interval +AWOB. The +AWOB interval may be a
predetermined time period, such as five minutes, ten minutes, thirty minutes,
or some other
duration. Alternatively, the +AWOB interval may be a predetermined drilling
progress
depth. For example, step 756 may include continuing drilling operation with
the increased
WOB until the existing wellbore is extended five feet, ten feet, fifty feet,
or some other depth.
The +AWOB interval may also include both a time and a depth component. For
example, the
+AWOB interval may include drilling for at least thirty minutes or until the
wellbore is
extended ten feet. In another example, the +AWOB interval may include drilling
until the
wellbore is extended twenty feet, but no longer than ninety minutes.
[00214] After continuing drilling operation through the +AWOB interval with
the
increased WOB, a step 758 is performed to determine the AT+AWOB resulting from
operating
with the increased WOB during the +AWOB interval. In a subsequent decisional
step 760,
the changed AT+AwoB is compared to the baseline ATBL+WOB. If the changed
AT+owoB is
desirable relative to the ATBL+WOB, the method 700c continues to a step 764.
However, if the
changed AT+AWOB is not desirable relative to the ATBL+WOB, the method 700c
continues to a
step 762 where the WOB is restored to its value before step 754 was performed,
and the
method then continues to step 764.
[00215] The determination made during decisional step 760 may be performed
manually or automatically by a controller, control system, and/or other
component of the
drilling rig and associated apparatus. The determination may include finding
the AT+AwoB to
be desirable if it is substantially equal to and/or less than the ATBL+WOB.
However, additional
or alternative factors may also play a role in the determination made during
step 760.
[00216] During step 764 of the method 700c, a baseline AT is determined for
optimization based on AT by decreasing the bit rotational speed, RPM. Because
the baseline
AT determined in step 764 will be utilized for optimization by decreasing RPM,
the
convention ATBL_RPM will be used herein.
57
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
[00217] In a subsequent step 766, the RPM is decreased. The decrease of RPM
during
step 766 may be within certain, predefined RPM limits. For example, the RPM
decrease may
be no greater than about 10%. However, other percentages are also within the
scope of the
present disclosure, including where such percentages are within or beyond the
predefined
RPM limits. The RPM may be manually decreased via operator input, or the RPM
may be
automatically decreased via signals transmitted by a controller, control
system, and/or other
component of the drilling rig and associated apparatus.
[00218] Thereafter, during a step 768, drilling continues with the decreased
RPM
during a predetermined drilling interval -ARPM. The -ARPM interval may be a
predetermined time period, such as five minutes, ten minutes, thirty minutes,
or some other
duration. Alternatively, the -ARPM interval may be a predetermined drilling
progress depth.
For example, step 768 may include continuing drilling operation with the
decreased RPM
until the existing wellbore is extended five feet, ten feet, fifty feet, or
some other depth. The -
ARPM interval may also include both a time and a depth component. For example,
the -
ARPM interval may include drilling for at least thirty minutes or until the
wellbore is
extended ten feet. In another example, the -ARPM interval may include drilling
until the
wellbore is extended twenty feet, but no longer than ninety minutes.
[00219] After continuing drilling operation through the -ARPM interval with
the
decreased RPM, a step 770 is performed to determine the AT_Ap_pM resulting
from operating
with the decreased RPM during the -ARPM interval. In a subsequent decisional
step 772, the
decreased AT_AuM is compared to the baseline ATBL_RPM. If the changed AT-PM is
desirable
relative to the ATBL_RPM, the method 700c continues to a step 776. However, if
the changed
AT_ARFM is not desirable relative to the ATBL_PPM, the method 700c continues
to a step 774
where the RPM is restored to its value before step 766 was performed, and the
method then
continues to step 776.
[00220] The determination made during decisional step 772 may be performed
manually or automatically by a controller, control system, and/or other
component of the
drilling rig and associated apparatus. The determination may include finding
the AT_AUM to
be desirable if it is substantially equal to and/or less than the ATBL_RPM.
However, additional
or alternative factors may also play a role in the determination made during
step 772.
[00221] During step 776 of the method 700c, a baseline AT is determined for
optimization based on AT by increasing the bit rotational speed, RPM. Because
the baseline
58
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
AT determined in step 776 will be utilized for optimization by increasing RPM,
the
convention ATBL+RPM will be used herein.
[00222] In a subsequent step 778, the RPM is increased. The increase of RPM
during
step 778 may be within certain, predefined RPM limits. For example, the RPM
increase may
be no greater than about 10%. However, other percentages are also within the
scope of the
present disclosure, including where such percentages are within or beyond the
predefined
RPM limits. The RPM may be manually increased via operator input, or the RPM
may be
automatically increased via signals transmitted by a controller, control
system, and/or other
component of the drilling rig and associated apparatus.
[00223] Thereafter, during a step 780, drilling continues with the increased
RPM
during a predetermined drilling interval +ARPM. The +ARPM interval may be a
predetermined time period, such as five minutes, ten minutes, thirty minutes,
or some other
duration. Alternatively, the +ARPM interval may be a predetermined drilling
progress depth.
For example, step 780 may include continuing drilling operation with the
increased RPM
until the existing wellbore is extended five feet, ten feet, fifty feet, or
some other depth. The
+ARPM interval may also include both a time and a depth component. For
example, the
+ARPM interval may include drilling for at least thirty minutes or until the
wellbore is
extended ten feet. In another example, the +ARPM interval may include drilling
until the
wellbore is extended twenty feet, but no longer than ninety minutes.
[00224] After continuing drilling operation through the +ARPM interval with
the
increased RPM, a step 782 is performed to determine the AT+ARpM resulting from
operating
with the increased RPM during the +ARPM interval. In a subsequent decisional
step 784, the
increased AT+ARpM is compared to the baseline ATBL+RPM. If the changed AT+ARYM
is
desirable relative to the ATBL+RPM, the method 700c continues to a step 788.
However, if the
changed AT+ARpM is not desirable relative to the ATBL+RPM, the method 700c
continues to a
step 786 where the RPM is restored to its value before step 778 was performed,
and the
method then continues to step 788.
[00225] The determination made during decisional step 784 may be performed
manually or automatically by a controller, control system, and/or other
component of the
drilling rig and associated apparatus. The determination may include finding
the AT+ORpM to
be desirable if it is substantially equal to and/or less than the ATBL+RPM.
However, additional
or alternative factors may also play a role in the determination made during
step 784.
59
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
[00226] Step 788 includes awaiting a predetermined time period or drilling
depth
interval before reiterating the method 700c by returning to step 740. However,
in an
exemplary embodiment, the interval may be as small as 0 seconds or 0 feet,
such that the
method returns to step 740 substantially immediately after performing steps
784 and/or 786.
Alternatively, the method 700c may not require iteration, such that the method
700c may
substantially end after the performance of steps 784 and/or 786.
[00227] Moreover, the drilling intervals -AWOB, +AWOB, -ARPM and +AROM may
each be substantially identical within a single iteration of the method 700c.
Alternatively,
one or more of the intervals may vary in duration or depth relative to the
other intervals.
Similarly, the amount that the WOB is decreased and increased in steps 742 and
754 may be
substantially identical or may vary relative to each other within a single
iteration of the
method 700c. The amount that the RPM is decreased and increased in steps 766
and 778 may
be substantially identical or may vary relative to each other within a single
iteration of the
method 700c. The WOB and RPM variances may also change or stay the same
relative to
subsequent iterations of the method 700c.
[00228] Referring to Fig. 8A, illustrated is a schematic view of apparatus 800
according to one or more aspects of the present disclosure. The apparatus 800
may include or
compose at least a portion of the apparatus 100 shown in Fig. 1, the apparatus
300 shown in
Fig. 3, the apparatus 400a shown in Fig. 4A, the apparatus 400b shown in Fig.
4B, the
apparatus 400c in Fig. 4C, and/or the apparatus 690 shown in Fig. 6B. The
apparatus 800
represents an exemplary embodiment in which one or more methods within the
scope of the
present disclosure may be performed or otherwise implemented, including the
method 200a
shown in Fig. 2A, the method 200b shown in Fig. 2B, the method 500 in Fig. 5A,
the method
600a shown in Fig. 6A, the method 600b shown in Fig. 6C, the method 600c shown
in Fig.
6D, the method 700a shown in Fig. 7A, the method 700b shown in Fig. 7B, and/or
the
method 700c shown in Fig. 7C.
[00229] The apparatus 800 includes a plurality of manual or automated data
inputs,
collectively referred to herein as inputs 802. The apparatus also includes a
plurality of
controllers, calculators, detectors, and other processors, collectively
referred to herein as
processors 804. Data from the various ones of the inputs 802 is transmitted to
various ones of
the processors 804, as indicated in Fig. 8A by the arrow 803. The apparatus
800 also
includes a plurality of sensors, encoders, actuators, drives, motors, and
other sensing,
measurement, and actuation devices, collectively referred to herein as devices
808. Various
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
data and signals, collectively referred to herein as data 806, are transmitted
between various
ones of the processors 804 and various ones of the devices 808, as indicated
in Fig. 8A by the
arrows 805.
[00230] The apparatus 800 may also include, be connected to, or otherwise be
associated with a display 810, which may be driven by or otherwise receive
data from one or
more of the processors 804, if not also from other components of the apparatus
800. The
display 810 may also be referred to herein as a human-machine interface (HMI),
although
such HMI may further include one or more of the inputs 802 and/or processors
804.
[00231] In the exemplary embodiment shown in Fig. 8A, the inputs 802 include
means
for providing the following set points, limits, ranges, and other data:
= bottom hole pressure input 802a;
= choke position reference input 802b;
= AP limit input 802c;
= AP reference input 802d;
drawworks pull limit input 802e;
MSE limit input 802f;
= MSE target input 802g;
= mud flow set point input 802h;
= pump pressure tare input 802i;
= quill negative amplitude input 802j;
= quill positive amplitude input 802k;
= ROP set point input 8021;
= pump input 802m;
= toolface position input 802n;
= top drive RPM input 802o;
= top drive torque limit input 802p;
= WOB reference input 802q; and
= WOB tare input 802r.
However, the inputs 802 may include means for providing additional or
alternative set points,
limits, ranges, and other data within the scope of the present disclosure.
[00232] The bottom hole pressure input 802a may indicate a value of the
maximum
desired pressure of the gaseous and/or other environment at the bottom end of
the wellbore.
61
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
Alternatively, the bottom hole pressure input 802a may indicate a range within
which it is
desired that the pressure at the bottom of the wellbore be maintained. Such
pressure may be
expressed as an absolute pressure or a gauge pressure (e.g., relative to
atmospheric pressure
or some other predetermined pressure).
[00233] The choke position reference input 802b may be a set point or value
indicating
the desired choke position. Alternatively, the choke position reference input
802b may
indicate a range within which it is desired that the choke position be
maintained. The choke
may be a device having an orifice or other means configured to control fluid
flow rate and/or
pressure. The choke may be positioned at the end of a choke line, which is a
high-pressure
pipe leading from an outlet on the BOP stack, whereby the fluid under pressure
in the
wellbore can flow out of the well through the choke line to the choke, thereby
reducing the
fluid pressure (e.g., to atmospheric pressure). The choke position reference
input 802b may
be a binary indicator expressing the choke position as either "opened" or
"closed."
Alternatively, the choke position reference input 802b may be expressed as a
percentage
indicating the extent to which the choke is partially opened or closed.
[00234] The AP limit input 802c may be a value indicating the maximum or
minimum
pressure drop across the mud motor. Alternatively, the AP limit input 802c may
indicate a
range within which it is desired that the pressure drop across the mud motor
be maintained.
The AP reference input 802d may be a set point or value indicating the desired
pressure drop
across the mud motor. In an exemplary embodiment, the AP limit input 802c is a
value
indicating the maximum desired pressure drop across the mud motor, and the AP
reference
input 802d is a value indicating the nominal desired pressure drop across the
mud motor.
[00235] The drawworks pull limit input 802e may be a value indicating the
maximum
force to be applied to the drawworks by the drilling line (e.g., when
supporting the drill string
off-bottom or pulling on equipment stuck in the wellbore). For example, the
drawworks pull
limit input 802e may indicate the maximum hook load that should be supported
by the
drawworks during operation. The drawworks pull limit input 802e may be
expressed as the
maximum weight or drilling line tension that can be supported by the drawworks
without
damaging the drawworks, drilling line, and/or other equipment.
[00236] The MSE limit input 802f may be a value indicating the maximum or
minimum MSE desired during drilling. Alternatively, the MSE limit input 802f
may be a
range within which it is desired that the MSE be maintained during drilling.
As discussed
above, the actual value of the MSE is at least partially dependent upon WOB,
bit diameter,
62
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
bit speed, drill string torque, and ROP, each of which may be adjusted
according to aspects of
the present disclosure to maintain the desired MSE. The MSE target input 802g
may be a
value indicating the desired MSE, or a range within which it is desired that
the MSE be
maintained during drilling. In an exemplary embodiment, the MSE limit input
802f is a value
or range indicating the maximum and/or minimum MSE, and the MSE target input
802g is a
value indicating the desired nominal MSE.
[00237] The mud flow set point input 802h may be a value indicating the
maximum,
minimum, or nominal desired mud flow rate output by the mud pump.
Alternatively, the mud
flow set point input 802h may be a range within which it is desired that the
mud flow rate be
maintained. The pump pressure tare input 802i may be a value indicating the
current,
desired, initial, surveyed, or other mud pump pressure tare. The mud pump
pressure tare
generally accounts for the difference between the mud pressure and the casing
or wellbore
pressure when the drill string is off bottom.
[00238] The quill negative amplitude input 802j may be a value indicating the
maximum desired quill rotation from the quill oscillation neutral point in a
first angular
direction, whereas the quill positive amplitude input 802k may be a value
indicating the
maximum desired quill rotation from the quill oscillation neutral point in an
opposite angular
direction. For example, during operation of the top drive to oscillate the
quill, the quill
negative amplitude input 802j may indicate the maximum desired clockwise
rotation of the
quill past the oscillation neutral point, and the quill positive amplitude
input 802k may
indicate the maximum desired counterclockwise rotation of the quill past the
oscillation
neutral point.
[00239] The ROP set point input 8021 may be a value indicating the maximum,
minimum, or nominal desired ROP. Alternatively, the ROP set point input 8021
may be
range within which it is desired that the ROP be maintained.
[00240] The pump input 802m may be a value indicating a maximum, minimum, or
nominal desired flow rate, power, speed (e.g., strokes-per-minute), and/or
other operating
parameter related to operation of the mud pump. For example, the mud pump may
actually
include more than one pump, and the pump input 802m may indicate a desired
maximum or
nominal aggregate pressure, flow rate, or other parameter of the output of the
multiple mud
pumps, or whether a pump system is operating in conjunction with the multiple
mud pumps.
[00241] The toolface position input 802n may be a value indicating the desired
orientation of the toolface. Alternatively, the toolface position input 802n
may be a range
63
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
within which it is desired that the toolface be maintained. The toolface
position input 802n
may be expressed as one or more angles relative to a fixed or predetermined
reference. For
example, the toolface position input 802n may represent the desired toolface
azimuth
orientation relative to true North and/or the desired toolface inclination
relative to vertical.
As discussed above, in some embodiments, this is input directly, or may be
based upon a
planned drilling path. While drilling using the method in Fig. 5A, the
toolface orientation
may be calculated based upon other data, such as survey data or trend data and
the amount of
deviation from a planned drilling path. This may be a value considered in
order to steer the
BHA along a modified drilling path.
[00242] The top drive RPM input 802o may be a value indicating a maximum,
minimum, or nominal desired rotational speed of the top drive. Alternatively,
the top drive
RPM input 802o may be a range within which it is desired that the top drive
rotational speed
be maintained. The top drive torque limit input 802p may be a value indicating
a maximum
torque to be applied by the top drive.
[00243] The WOB reference input 802q may be a value indicating a maximum,
minimum, or nominal desired WOB resulting from the weight of the drill string
acting on the
drill bit, although perhaps also taking into account other forces affecting
WOB, such as
friction between the drill string an the wellbore. Alternatively, the WOB
reference input
802q may be a range in which it is desired that the WOB be maintained. The WOB
tare input
802r may be a value indicating the current, desired, initial, survey, or other
WOB tare, which
takes into account the hook load and drill string weight when off bottom.
[00244] One or more of the inputs 802 may include a keypad, voice-recognition
apparatus, dial, joystick, mouse, data base and/or other conventional or
future-developed data
input device. One or more of the inputs 802 may support data input from local
and/or remote
locations. One or more of the inputs 802 may include means for user-selection
of
predetermined set points, values, or ranges, such as via one or more drop-down
menus. One
or more of the inputs 802 may also or alternatively be configured to enable
automated input
by one or more of the processors 804, such as via the execution of one or more
database look-
up procedures. One or more of the inputs 802, possibly in conjunction with
other
components of the apparatus 800, may support operation and/or monitoring from
stations on
the rig site as well as one or more remote locations. Each of the inputs 802
may have
individual means for input, although two or more of the inputs 802 may
collectively have a
single means for input. One or more of the inputs 802 may be configured to
allow human
64
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
input, although one or more of the inputs 802 may alternatively be configured
for the
automatic input of data by computer, software, module, routine, database
lookup, algorithm,
calculation, and/or otherwise. One or more of the inputs 802 may be configured
for such
automatic input of data but with an override function by which a human
operator may
approve or adjust the automatically provided data.
[00245] In the exemplary embodiment shown in Fig. 8A, the devices 808 include:
= a block position sensor 808a;
= a casing pressure sensor 808b;
= a choke position sensor 808c;
= a dead-line anchor load sensor 808d;
= a drawworks encoder 808e;
a mud pressure sensor 808f;
= an MWD toolface gravity sensor 808g;
= an MWD toolface magnetic sensor 808h;
= a return line flow sensor 808i;
= a return line mud weight sensor 808j;
= a top drive encoder 808k;
= a top drive torque sensor 8081;
= a choke actuator 808m;
= a drawworks drive 808n;
= a drawworks motor 808o;
= a mud pump drive 808p;
= a top drive drive 808q; and
= a top drive motor 808r.
However, the devices 808 may include additional or alternative devices within
the scope of
the present disclosure. The devices 808 are configured for operation in
conjunction with
corresponding ones of a drawworks, a choke, a mud pump, a top drive, a block,
a drill string,
and/or other components of the rig. Alternatively, the devices 808 also
include one or more
of these other rig components.
[00246] The block position sensor 808a may be or include an optical sensor, a
radio-
frequency sensor, an optical or other encoder, or another type of sensor
configured to sense
the relative or absolute vertical position of the block. The block position
sensor 808a may be
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
coupled to or integral with the block, the crown, the drawworks, and/or
another component of
the apparatus 800 or rig.
[00247] The casing pressure sensor 808b is configured to detect the pressure
in the
annulus defined between the drill string and the casing or wellbore, and may
be or include
one or more transducers, strain gauges, and/or other devices for detecting
pressure changes or
otherwise sensing pressure. The casing pressure sensor 808b may be coupled to
the casing,
drill string, and/or another component of the apparatus 800 or rig, and may be
positioned at or
near the wellbore surface, slightly below the surface, or significantly deeper
in the wellbore.
[00248] The choke position sensor 808c is configured to detect whether the
choke is
opened or closed, and may be further configured to detect the degree to which
the choke is
partially opened or closed. The choke position sensor 808c may be coupled to
or integral
with the choke, the choke actuator, and/or another component of the apparatus
800 or rig.
The choke may alternatively maintain a set pressure or steady mass flow, e.g.,
based on a
casing pressure. This can be measured with an optional mass flow meter 808s.
[00249] The dead-line anchor load sensor 808d is configured to detect the
tension in
the drilling line at or near the anchored end. It may include one or more
transducers, strain
gauges, and/or other sensors coupled to the drilling line.
[00250] The drawworks encoder 808e is configured to detect the rotational
position of
the drawworks spools around which the drilling line is wound. It may include
one or more
optical encoders, interferometers, and/or other sensors configured to detect
the angular
position of the spool and/or any change in the angular position of the spool.
The drawworks
encoder 808e may include one or more components coupled to or integral with
the spool
and/or a stationary portion of the drawworks.
[00251] The mud pressure sensor 808f is configured to detect the pressure of
the
hydraulic fluid output by the mud motor, and may be or include one or more
transducers,
strain gauges, and/or other devices for detecting fluid pressure. It may be
coupled to or
integral with the mud pump, and thus positioned at or near the surface opening
of the
wellbore.
[00252] The MWD toolface gravity sensor 808g is configured to detect the
toolface
orientation based on gravity. The MWD toolface magnetic sensor 808h is
configured to
detect the toolface orientation based on magnetic field. These sensors 808g
and 808h may be
coupled to or integral with the MWD assembly, and are thus positioned
downhole.
66
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
[00253] The return line flow sensor 808i is configured to detect the flow rate
of mud
within the return line, and may be expressed in gallons/minute. The return
line mud weight
sensor 808j is configured to detect the weight of the mud flowing within the
return line.
These sensors 808i and 808j may be coupled to the return flow line, and may
thus be
positioned at or near the surface opening of the wellbore.
[00254] The top drive encoder 808k is configured to detect the rotational
position of
the quill. It may include one or more optical encoders, interferometers,
and/or other sensors
configured to detect the angular position of the quill, and/or any change in
the angular
position of the quill, relative to the top drive, true North, or some other
fixed reference point.
The top drive torque sensor 8081 is configured to detect the torque being
applied by the top
drive, or the torque necessary to rotate the quill or drill string at the
current rate. These
sensors 808k and 8081 may be coupled to or integral with the top drive.
[00255] The choke actuator 808m is configured to actuate the choke to
configure the
choke in an opened configuration, a closed configured, and/or one or more
positions between
fully opened and fully closed. It may be hydraulic, pneumatic, mechanical,
electrical, or
combinations thereof.
[00256] The drawworks drive 808n is configured to provide an electrical signal
to the
drawworks motor 808o for actuation thereof The drawworks motor 808o is
configured to
rotate the spool around which the drilling line is wound, thereby feeding the
drilling line in or
out.
[00257] The mud pump drive 808p is configured to provide an electrical signal
to the
mud pump, thereby controlling the flow rate and/or pressure of the mud pump
output. The
top drive drive 808q is configured to provide an electrical signal to the top
drive motor 808r
for actuation thereof. The top drive motor 808r is configured to rotate the
quill, thereby
rotating the drill string coupled to the quill.
[00258] The devices 808 may (things applicable to most of the sensors)
[00259] In the exemplary embodiment shown in Fig. 8A, the data 806 which is
transmitted between the devices 808 and the processors 804 includes:
block position 806a;
casing pressure 806b;
s choke position 806c;
s hook load 806d;
67
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
= mud pressure 806e;
= mud pump stroke/phase 806f,
= mud weight 806g;
= quill position 806h;
= return flow 806i;
= toolface 806j;
= top drive torque 806k;
= choke actuation signal 8061;
= drawworks actuation signal 806m;
= mud pump actuation signal 806n;
= top drive actuation signal 806o; and
= top drive torque limit signal 806p.
However, the data 806 transferred between the devices 808 and the processors
804 may
include additional or alternative data within the scope of the present
disclosure.
[002601 In the exemplary embodiment shown in Fig. 8A, the processors 804
include:
= a choke controller 804a;
= a drum controller 804b;
= a mud pump controller 804c;
= an oscillation controller 804d;
= a quill position controller 804e;
= a toolface controller 804f,
a d-exponent calculator 804g;
a d-exponent-corrected calculator 804h;
= an MSE calculator 804i;
= an ROP calculator 8041;
= a true depth calculator 804m;
= a WOB calculator 804n;
= a stick/slip detector 804o; and
= a survey log 804p.
However, the processors 804 may include additional or alternative controllers,
calculators,
detectors, data storage, and/or other processors within the scope of the
present disclosure.
68
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
[002611 The choke controller 804a is configured to receive the bottom hole
pressure
setting from the bottom hole pressure input 802a, the casing pressure 806b
from the casing
pressure sensor 808b, the choke position 806c from the choke position sensor
808c, and the
mud weight 806g from the return line mud weight sensor 808j. The choke
controller 804a
may also receive bottom hole pressure data from the pressure calculator 804k.
Alternatively,
the processors 804 may include a comparator, summing, or other device which
performs an
algorithm utilizing the bottom hole pressure setting received from the bottom
hole pressure
input 802a and the current bottom hole pressure received from the pressure
calculator 804k,
with the result of such algorithm being provided to the choke controller 804a
in lieu of or in
addition to the bottom hole pressure setting and/or the current bottom hole
pressure. The
choke controller 804a is configured to process the received data and generate
the choke
actuation signal 8061, which is then transmitted to the choke actuator 808.
[002621 For example, if the current bottom hole pressure is greater than the
bottom
hole pressure setting, then the choke actuation signal 8061 may direct the
choke actuator
808m to further open, thereby increasing the return flow rate and decreasing
the current
bottom hole pressure. Similarly, if the current bottom hole pressure is less
than the bottom
hole pressure setting, then the choke actuation signal 8061 may direct the
choke actuator
808m to further close, thereby decreasing the return flow rate and increasing
the current
bottom hole pressure. Actuation of the choke actuator 808m may be incremental,
such that
the choke actuation signal 8061 repeatedly directs the choke actuator 808m to
further open or
close by a predetermined amount until the current bottom hole pressure
satisfactorily
complies with the bottom hole pressure setting. Alternatively, the choke
actuation signal
8061 may direct the choke actuator 808m to further open or close by an amount
proportional
to the current discord between the current bottom hole pressure and the bottom
hole pressure
setting.
[002631 The drum controller 804b is configured to receive the ROP set point
from the
ROP set point input 8021, as well as the current ROP from the ROP calculator
8041. The
drum controller 804b is also configured to receive WOB data from a comparator,
summing,
or other device which performs an algorithm utilizing the WOB reference point
from the
WOB reference input 802g and the current WOB from the WOB calculator 804n.
This WOB
data may be modified based current MSE data. Alternatively, the drum
controller 804b is
configured to receive the WOB reference point from the WOB reference input
802g and the
current WOB from the WOB calculator 804n directly, and then perform the WOB
69
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
comparison or summing algorithm itself. The drum controller 804b is also
configured to
receive AP data from a comparator, summing, or other device which performs an
algorithm
utilizing the AP reference received from the AP reference input 802d and a
current AP
received from one of the processors 804 that is configured to determine the
current AP. The
current AP may be corrected to take account the casing pressure 806b.
[00264] The drum controller 804b is configured to process the received data
and
generate the drawworks actuation signal 806m, which is then transmitted to the
drawworks
drive 808n. For example, if the current WOB received from the WOB calculator
804n is less
than the WOB reference point received from the WOB reference input 802q, then
the
drawworks actuation signal 806m may direct the drawworks drive 808n to cause
the
drawworks motor 808o to feed out more drilling line. If the current WOB is
less than the
WOB reference point, then the drawworks actuation signal 806m may direct the
drawworks
drive 808n to cause the drawworks motor 808o to feed in the drilling line.
[00265] If the current ROP received from the ROP calculator 8041 is less than
the ROP
set point received from the ROP set point input 8021, then the drawworks
actuation signal
806m may direct the drawworks drive 808n to cause the drawworks motor 808o to
feed out
more drilling line. If the current ROP is greater than the ROP set point, then
the drawworks
actuation signal 806m may direct the drawworks drive 808n to cause the
drawworks motor
808o to feed in the drilling line.
[00266] If the current AP is less than the AP reference received from the AP
reference
input 802d, then the drawworks actuation signal 806m may direct the drawworks
drive 808n
to cause the drawworks motor 808o to feed out more drilling line. If the
current AP is greater
than the AP reference, then the drawworks actuation signal 806m may direct the
drawworks
drive 808n to cause the drawworks motor 808o to feed in the drilling line.
[00267] The mud pump controller 804c is configured to receive the mud pump
stroke/phase data 806f, the mud pressure 806e from the mud pressure sensor
808f, the current
AP, the current MSE from the MSE calculator 804i, the current ROP from the ROP
calculator
8041, a stick/slip indicator from the stick/slip detector 804o, the mud flow
rate set point from
the mud flow set point input 802h, and the pump data from the pump input 802m.
The mud
pump controller 804c then utilizes this data to generate the mud pump
actuation signal 806n,
which is then transmitted to the mud pump 808p.
[00268] The oscillation controller 804d is configured to receive the current
quill
position 806h, the current top drive torque 806k, the stick/slip indicator
from the stick/slip
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
detector 804o, the current ROP from the ROP calculator 8041, and the quill
oscillation
amplitude limits from the inputs 802j and 802k. The oscillation controller
804d then utilizes
this data to generate an input to the quill position controller 804e for use
in generating the top
drive actuation signal 806o. For example, if the stick/slip indicator from the
stick/slip
detector 804o indicates that stick/slip is occurring, then the signal
generated by the oscillation
controller 804d will indicate that oscillation needs to commence or increase
in amplitude.
[00269] The quill position controller 804e is configured to receive the signal
from the
oscillation controller 804d, the top drive RPM setting from the top drive RPM
input 802o, a
signal from the toolface controller 804f, the current WOB from the WOB
calculator 804n,
and the current toolface 806j from at least one of the MWD toolface sensors
808g and 808h.
The quill position controller 804e may also be configured to receive the top
drive torque limit
setting from the top drive torque limit input 802p, although this setting may
be adjusted by a
comparator, summing, or other device to account for the current MSE, where the
current
MSE is received from the MSE calculator 804i. The quill position controller
804e may also
be configured to receive a stick/slip indicator from the stick/slip detector
804o. The quill
position controller 804e then utilizes this data to generate the top drive
actuation signal 806o.
[00270] For example, the top drive actuation signal 806o causes the top drive
drive
808q to cause the top drive motor 808r to rotate the quill at the speed
indicated by top drive
RPM input 802o. However, this may only occur when other inputs aren't
overriding this
objective. For example, if so directed by the signal from the oscillation
controller 804d, the
top drive actuation signal 806o will also cause the top drive drive 808q to
cause the top drive
motor 808r to rotationally oscillate the quill. Additionally, the signal from
the toolface
controller 804d may override or otherwise influence the top drive actuation
signal 806o to
rotationally orient the quill at a certain static position or set a neutral
point for oscillation.
[00271] The toolface controller 804f is configured to receive the toolface
position
setting from the toolface position input 802n, as well as the current toolface
806j from at least
one of the MWD toolface sensors 808g and 808h. The toolface controller 804f
may also be
configured to receive AP data. The toolface controller 804f then utilizes this
data to generate
a signal which is provided to the quill position controller 804e.
[00272] The d-exponent calculator 804g is configured to receive the current
ROP from
the ROP calculator 8041, the current AP and/or other pressure data, the bit
diameter, the
current WOB from the WOb calculator 804n, and the current mud weight 806g from
the
return line mud weight sensor 808j. The d-exponent calculator 804g then
utilizes this data to
71
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
calculate the d-exponent, which is a factor for evaluating ROP and detecting
or predicting
abnormal pore pressure zones. Assuming all other parameters are constant, the
d-exponent
should increase with depth when drilling in a normal pressure section, whereas
a reversal of
this trend is an indication of drilling into potential overpressures. The
signal from the d-
exponent calculator 804g is optionally provided to the display 810, as well as
to the toolface
calculation engine 404. Consequently, the steering module 420 can cease
drilling or adjust
the planned path by treating an area causing increased values from the d-
exponent calculator
804g as a deviation from the planned path outside the tolerance zone. This can
advantageously automatically direct the main controller to drill in a
different direction to
avoid drilling into the potential overpressure area. The d-exponent calculator
is simply
another suitable method, or algorithm, for analyzing ROP and is another
calculation that can
be accomplished similar to that for MSE.
[002731 The d-exponent-corrected calculator 804h may be configured to receive
substantially the same data as received by the d-exponent calculator 804g.
Alternatively, the
d-exponent-corrected calculator 804h is configured to receive the current d-
exponent as
calculated by the d-exponent calculator 804g. The d-exponent-corrected
calculator 804h then
utilizes this data to calculate the corrected d-exponent, which corrects the d-
exponent value
for mud weight and which can be related directly to formation pressure rather
than to
differential pressure. The signal from the d-exponent calculator 804g is
provided, e.g., to the
display 810.
[002741 The MSE calculator 804i is configured to receive current RPM data from
the
top drive RPM input 802o, the top drive torque 806k from the top drive torque
sensor 8081,
and the current WOB from the WOB calculator 804n. The MSE calculator 804i then
utilizes
this data to calculate the current MSE, which is then transmitted to the drum
controller 804b,
the quill position controller 804e, and the mud pump controller 804c. The MSE
calculator
804i may also be configured to receive the MSE limit setting from the MSE
limit input 802f,
in which case the MSE calculator 804i may also be configured to compare the
current MSE
to the MSE limit setting and trigger an alert if the current MSE exceeds the
MSE limit
setting. The MSE calculator 804i may also be configured to receive the MSE
target setting
from the MSE target input 802g, in which case the MSE calculator 804i may also
be
configured to generate a signal indicating the difference between the current
MSE and the
MSE target. This signal may be utilized by one or more of the processors 804
to correct
72
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
adjust various data values utilized thereby, such as the adjustment to the
current or reference
WOB utilized by the drum controller 804b, and/or the top drive torque limit
setting utilized
by the quill position controller 804e, as described above.
[00275] The pressure calculator 804k is configured to receive the casing
pressure 806b
from the casing pressure sensor 808b, the mud pressure 806e from the mud
pressure sensor
808f, the mud weight 806g from the return line mud weight sensor 808j, and the
true vertical
depth from the true depth calculator 804m. The pressure calculator 804k then
utilizes this
data to calculate the current bottom hole pressure, which is then transmitted
to choke
controller 804a. However, before being sent to the choke controller 804a, the
current bottom
hole pressure may be compared to the bottom hole pressure setting received
from the bottom
hole pressure input 802a, in which case the choke controller 804a may utilize
only the
difference between the current bottom home pressure and the bottom hole
pressure setting
when generating the choke actuation signal 8061. This comparison between the
current
bottom hole pressure and the bottom hole pressure setting may be performed by
the pressure
calculator 804k, the choke controller 804a, or another one of the processors
804.
[00276] The ROP calculator 8041 is configured to receive the block position
806a from
the block position 808a and then utilize this data to calculate the current
ROP. The current
ROP is then transmitted to the true depth calculator 804m, the drum controller
804b, the mud
pump controller 804c, and the oscillation controller 804d.
[00277] The true depth calculator 804m is configured to receive the current
toolface
806j from at least one of the MWD toolface sensors 808g and 808h, the survey
log 804p, and
the current measured depth that is calculated from the current ROP received
from the ROP
calculator 8041. The true depth calculator 804m then utilizes this data to
calculate the true
vertical depth, which is then transmitted to the pressure calculator 804k.
[00278] The WOB calculator 804n is configured to receive the stick/slip
indicator from
the stick/slip detector 804o, as well as the current hook load 806d from the
dead-line anchor
load sensor 808d. The WOB calculator 804n may also be configured to receive an
off-
bottom string weight tare, which may be the difference between the WOB tare
received from
the WOB tare input 802r and the current hook load 806d received from the dead-
line anchor
load sensor 808d. In any case, the WOB calculator 804n is configured to
calculate the
current WOB based on the current hook load, the current string weight, and the
stick-slip
indicator. The current WOB is then transmitted to the quill position
controller 804e, the d-
73
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
exponent calculator 804g, the d-exponent-corrected calculator 804h, the MSE
calculator 804i,
and the drum controller 804b.
[00279] The stick/slip detector 804o is configured to receive the current top
drive
torque 806k and utilize this data to generate the stick/slip indicator, which
is then provided to
the mud pump controller 804c, the oscillation controller 804d, and the quill
position
controller 804e. The stick/slip detector 804o measures changes in the top
drive torque 806k
relative to time, which is indicative of whether the bit may be exhibiting
stick/slip behavior,
indicating that the top drive torque and/or WOB should be reduced or the quill
oscillation
amplitude should be modified.
[00280] The processors 804 may be collectively implemented as a single
processing
device, or as a plurality of processing devices. Each processor 804 may
include one or more
software or other program product modules, sub-modules, routines, sub-
routines, state
machines, algorithms. Each processor 804 may additional include one or more
computer
memories or other means for digital data storage. Aspects of one or more of
the processors
804 may be substantially similar to those described herein with reference to
any controller or
other data processing apparatus. Accordingly, the processors 804 may include
or be
composed of at least a portion of controller 190 in Fig. 1, the controller 325
in Fig. 3, the
controller 420 in Figs. 4A-C, and the controller 698 in Fig. 6B, for example.
[00281] Fig. 8B illustrates a system control module 812 according to one or
more
aspects of the present disclosure. The system control module 812 is one
possible
implementation of the apparatus 800 shown in Fig. 8A, and may be utilized in
conjunction
with or implemented within the apparatus 100 shown in Fig. 1, and any of the
apparatuses
300, 400a, 400b, 400c, and 790 shown respectively in Figs. 3, 4A-C, and 7B.
The system
control module 812 may also be utilized to perform one or more aspects of the
methods
shown in any of Figs. 2A, 2B, 5A, 6A, 6C, 7A, 7B, and 7C.
[00282] The system control module 812 includes an HMI module 814, a data
transmission module 816, and a master drilling control module 818. The HMI
module 814
includes a manual data input module 814a and a display module 814b. The master
drilling
control module 818 includes a sensed data module 818a, a control signal
transmission module
818b, a BHA control module 818c, a drawworks control module 420b, a top drive
control
module 420a, a mud pump control module 420f, an ROP optimization module 818g,
a bit life
optimization module 818h, an MSE-based optimization module 818i, a d-exponent-
based
74
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
optimization module 818j, a d-exponent-corrected-based optimization module
818k, -, and a
BHA optimization module 818m.
[00283] The manual data input module 814a is configured to facilitate user-
input of
various set points, operating ranges, formation conditions, equipment
parameters, and/or
other data, including a drilling plan or data for determining a drilling plan.
For example, the
manual data input module 814a may enable the inputs 802 shown in Fig. 8A,
among others.
Such data may be received by the manual data input module 814a via the data
transmission
module 816, which may include or support one or more connectors, ports, and/or
other means
for receiving data from various data input devices. The display module 814b is
configured to
provide an indication that the user has successfully entered some or all of
the input facilitated
by the manual data input module 814a. Such indication may be include a visual
indication of
some type, such as via the display of text or graphic icons or other
information, the
illumination of one or more lights or LEDs, or the change in color of a light,
LED, graphic
icon or symbol, among others.
[00284] The master drilling control module 818 is configured to receive data
input by
the user from the HMI module 814, which in some embodiments is communicated
via the
data transmission module 816 as in the exemplary embodiment depicted in Fig.
8B.
[00285] The sensed data module 818a of the master drilling control module 818
also
receives sensed or detected data from various sensors, detectors, encoders,
and other such
devices associated with the various equipment and components of the rig.
Examples of such
sensing and information obtaining devices include the devices 430 in Fig. 4A
and 806 in Fig.
8A among other figures included herein. This sensed data may also be received
by the
sensed data module 818a via the data transmission module 816.
[00286] The control signal transmission module 718b interfaces between the
control
modules of the master drilling control module 818 and the actual working
systems. For
example, it sends and receives control signals to the drawworks 130, the top
drive 140, the
mud pump 180, and in some embodiments, the BHA 170 in Fig. 1 The BHA control
module
718c may be employed when the BHA is configured to be controlled downhole.
[00287] The drawworks control module 420b, the top drive control module 420a,
and
the mud pump control module 420f are used to generate control signals sent via
the control
signal transmission module 718b to the drawworks, the top drive, and the mud
pump. These
may correspond to the controllers shown in Fig. 4C.
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
[00288] In some embodiments, the master drilling control module 818 may
include
less than all the optimization modules 818g-m shown, with each of the
optimization modules
being separately purchasable by a user. Accordingly, some embodiments may
include only
one of the optimization modules while other embodiments include more than one
of the
optimization modules. Thus, the master drilling control module 818 may be
configured so
that the available modules cooperate to arrive at optimization values
considering all the
optimization modules available in the master drilling control module. This is
further
discussed below with reference to Fig. 8C.
[00289] Still referring to Fig. 8B, the ROP optimization module 818g
determines
methods or adjustments to processes that improve the ROP of the BHA. The ROP
optimization module 818g receives data from the sensed data module 430 as well
as other
data, including data relating to toolface orientation, among others, to
determine the most
effective way to maximize ROP. After considering these and/or other factors,
the ROP
optimization module 818g communicates with the control modules 818c, 420a,
420b, and
420f so that the control modules can determine whether steering changes would
optimize
ROP in a way that maximizes productivity and effectiveness.
[00290] The bit life optimization module 818h may consider data received from
the
sensed data module 430 as well as toolface orientation data, including
azimuth, inclination
toolface orientation data, time in drilling, to determine the most effective
way to preserve bit
life without compromising effectiveness or productivity. After considering
these or other
factors, the bit life optimization module communicates with the control
modules 818c, 420a,
420b, and 420f so that the control modules can determine whether steering
changes would
preserve bit life in a way that maximizes productivity and effectiveness.
[00291] The MSE-based optimization module 818i performs the MSE based
optimization processes discussed above with reference to Figs. 6A, 6C, and 6D.
The outputs
of the optimization module 818i may be communicated to the control modules
818c, 420a,
420b, and 420f to actually implement the changes that result in the
efficiencies.
[00292] The d-exponent-based optimization module 818j may include the d-
exponent
calculator 804g to determine the d-exponent and evaluate ROP while detecting
or predicting
abnormal pore pressure zones. Accordingly, as the d-exponent module detects
variance in
normal pressure, the d-exponent module can communicate with the control
modules 818c,
420a, 420b, and 420f to consider making any steering changes necessary for
efficient and
effective drilling.
76
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
[00293] The d-exponent-corrected-based optimization module 818k may include
the d-
exponent-corrected calculator 804h. Using the data received, the optimization
module 818k
corrects the d-exponent value for mud weight which can be related directly to
formation
pressure rather than to differential pressure. This corrected value also can
be communicated
to the control modules 818c, 420a, 420b, and 420f to consider making any
steering changes
necessary for efficient and effective drilling.
[00294] The BHA optimization module 818m may consider data received from the
sensed data module 430, data input at the manual data input module 714a, and
other
obtainable data to determine optimization profiles for the BHA. In some
embodiments, the
BHA optimization module 818m processes information received from other modules
in the
master drilling control module 718. Using this information, the BHA
optimization module
818m outputs data to the control modules 818c, 420a, 420b, and 420f to
consider making any
steering changes to the BHA necessary to optimize the BHA.
[00295] As the drawworks control module 420b, the top drive control module
420a,
and the mud pump control module 420f receive information from the optimization
modules,
they process the data to determine whether the interaction of the recommended
changes
would positively or negatively affect the overall productivity of the well
system, and generate
control signals instructing the drawworks 130, the top drive 140, and the
mudpump 180 of
Fig. 1 in a manner to most effectively implement changes.
[00296] Fig. 8C shows an exemplary method 830 performed by the master drilling
control module 818 to optimize the overall drilling operation of the drilling
rig. As discussed
above, some embodiments of the master drilling control module 818 do not
include all the
optimization modules shown in Fig. 8B. Accordingly, the method 830 considers
the
circumstances where the master drilling control module includes one, more than
one, or less
than all the optimization modules shown. It is contemplated that these modules
are
exemplary and that other optimization modules may be included therein.
[00297] The method 830 includes steps that appear in parallel, and are not
necessarily
done in series. In some embodiments, these parallel method paths are
alternative paths and
may be implemented based upon the configuration of the master drilling control
module
and/or the availability of the optimization modules. For example, from step
832, the method
830 continues to steps 834, 840, 846, 852, and 858. These are each discussed
below.
[00298] Referring to Fig. 8C, at a step 832, the master drilling control
module 718
receives manual inputs and/or sensed data from the manual data input module
814a and/or the
77
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
sensed data module 430 (input or sensed data not shown). In some instances,
the master
drilling control module 718 may access trend data stored from prior surveys.
[00299] Using this information and data, the optimization modules in the
master
drilling control module 818 calculate or otherwise process data using
algorithms to determine
optimization values for any number of factors affecting drilling efficiency or
productivity,
including ROP. In some embodiments, the alternative paths in Fig. 8C are
dependent on the
availability of the optimization modules. For example, from step 832, the
method 830
continues to step 834 if the master drilling control module 818 includes only
the ROP
optimization module 818g of the optimization modules. Alternatively, from step
832, the
method 830 continues to step 840 if the master drilling control module 818
includes only one
of the MSE-based optimization module 818i, the d-exponent-based optimization
module
818j, the d-exponent-corrected-based optimization module 818k, and the BHA
optimization
module 818m. Again, alternatively, from step 832, the method 830 continues to
step 846 if
the master drilling control module 818 includes more than one optimization
module. The
method 832 continues to step 852 if the master drilling control module 818
includes the ROP
optimization module 818g and one of the MSE-based optimization module 818i,
the d-
exponent-based optimization module 818j, the d-exponent-corrected-based
optimization
module 818k, and the BHA optimization module 818m. The method 832 continues to
step
858 if the master drilling control module 818 includes the ROP optimization
module 818g
and more than one optimization module 818i, 818j, 818k, 8181, and 818m.
[00300] In alternative embodiments, the master drilling control module 818
performs
all the steps of the method rather than treating them as alternative steps as
described above.
Accordingly, although the master drilling control module includes a plurality
of optimization
modules, it still considers the ROP optimization module 818g independently at
step 834,
considers one of the other optimization modules independently at step 840, and
so on with
steps 846, 852, and 858.
[00301] In the circumstances where only the ROP optimization module 818g is
included in the master drilling control module 818, or the master control
module 818 is
configured to consider only the ROP optimization module 818g, at step 834, the
ROP
optimization module 818g determines drilling parameter changes that optimize
drilling
operation based on ROP using the manual inputs and/or sensed data. These
drilling
parameter changes are communicated to the BHA control module 818c, the
drawworks
control module 420b, the top drive control module 420a, and/or the mud pump
control
78
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
module 420f. At step 836, these control modules modify the one or more control
signals
being sent to the BHA, the drawworks, the top drive, and or the mudpump to
change the
drilling parameter(s) necessary to optimize the drilling operation based on
ROP.
[00302] In the circumstances where only one optimization module is included in
the
master drilling control module 818, or the master control module 818 is
configured to
consider only one optimization module, at step 840, using the MSE-based
optimization
module 818i, the d-exponent-based optimization module 818j, the d-exponent-
corrected-
based optimization module 818k, and the BHA optimization module 818m, the
master
drilling control module 818 can calculate one of MSE, d-exp, d-exp-corrected,
and BHA
optimization values based on data received from the sensed data module an/or
the manual
data input module 814a. Based on this data, at step 842, the master drilling
control module
818 can determine the drilling parameter changes necessary to optimize the
drilling operation
based on the calculated one of MSE, d-exp, d-exp-corrected, and BHA
optimization values.
These drilling parameter changes are communicated to the BHA control module
818c, the
drawworks control module 420b, the top drive control module 420a, and/or the
mud pump
control module 420f. At step 844, these control modules modify the control
signals being
sent to the BHA, the drawworks, the top drive, and or the mudpump to change
the drilling
parameters necessary to optimize the drilling operation based on the
calculated value.
[00303] In the circumstances where more than one optimization module is
included in
the master drilling control module, at step 846 using the optimization modules
818i, 818j,
818k, 8181, and 818m, the master drilling control module 818 preferably
calculates more than
one (typically, at least two) of MSE, d-exp, d-exp-corrected, and BHA
optimization values
based on data received form the sensed data module an/or the manual data in
put module
814a. Based on this data, at step 848, the master drilling control module 818
can determine
the drilling parameter changes necessary to optimize the drilling operation
based on the
plurality of calculated values. These drilling parameter changes are
communicated to the
BHA control module 818c, the drawworks control module 420b, the top drive
control module
420a, and/or the mud pump control module 420f and at step 850, these control
modules
modify the control signals being sent to the BHA, the drawworks, the top
drive, and or the
mudpump to change the drilling parameters necessary to optimize the drilling
operation based
on the plurality of calculated values.
[00304] In the circumstances where the ROP optimization module 818g and only
one
other optimization module are included in the master drilling control module
818, or the
79
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
master control module 818 is configured to consider only the ROP optimization
module 818g
and only one other optimization module, at step 854, the master drilling
control module 818
preferably determines the drilling parameter changes necessary to optimize the
drilling
operation based on the one calculated value and the ROP optimization value.
These values
are communicated to the control modules and at step 856, these control modules
can modify
the control signals being sent to the BHA, the drawworks, the top drive, and
or the mudpump
to change the drilling parameters necessary to optimize the drilling operation
based on the
calculated value.
[00305] In the circumstances where the ROP optimization module and more than
one
additional optimization module are included in the master drilling control
module, at step
858, using the optimization modules 818i, 818j, 818k, 8181, and 818m the
master drilling
control module 818 calculates more than one of MSE, d-exp, d-exp-corrected,
and BHA
optimization values based on data received from the sensed data module and/or
the manual
data input module 814a. Here, the master drilling control module 818 considers
ROP when
determining the drilling parameter changes necessary to optimize the drilling
operation.
Accordingly the master drilling control module 818 can consider the plurality
of calculated
values from the optimization modules, including the ROP, to determine the
optimized drilling
parameter changes. These drilling parameter changes are communicated to the
control
modules 818c, 420b, 420a, and/or 420f and at step 862, these control modules
modify the
control signals being sent to the BHA, the drawworks, the top drive, and/or
the mudpump to
change the drilling parameters necessary to optimize the drilling operation
based on the
plurality of calculated values.
[00306] Regardless of which path is used, after modified control signals are
sent from
the master drilling control module, the display module 814b preferably updates
the optional
but preferred HMI display at step 838 to reflect these new changed control
signals. The HMI
display is discussed further herein and as incorporated.
[00307] In some instances, the master drilling control module 818 performs all
or some
of the steps 834, 840, 846, 852, and 858 at the same time, or in sufficiently
rapid succession
so as to appear simultaneous, and the control signals are modified based on
multiple inputs
from the system.
[00308] Figs 9A and 9B show flow charts detailing methods of optimizing
directional
drilling accuracy during drilling operations performed via the apparatus 100
in Fig. 1. Any of
the control systems disclosed herein, including Figs. 1, 3, 4A-C, 6B, 8A, and
8B may be used
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
to execute the methods of Figs. 9A and 9B. The real-time data obtained in
these methods
may be configured as inputs in Fig. 4A to optimize drilling operations and to
calculate bit
position in order to identify and correct any deviations of the bit from the
planned drilling
path during drilling operations.
[00309] Referring first to Fig. 9A, illustrated is a flow-chart diagram of a
method 900
according to one or more aspects of the present disclosure. The method 900 may
be
performed in association with one or more components of the apparatus 100
shown in Fig. 1
during operation of the apparatus 100. For example, the method 900 may be
performed to
optimize directional drilling accuracy during drilling operations performed
via the apparatus
100.
[00310] The method 900 includes a step 910 during which real-time toolface,
hole
depth, pipe rotation, hook load, delta pressure, and/or other data are
received by a controller
or other processing device (e.g., any of the controller 190, 325, 420, 402,
698, 804, 812 or
others discussed herein). The data may be obtained from various rig
instruments and/or
sensors configured for such measurement (such as the sensors shown in Figs. 1,
4A, 8A, and
others). The step 910 may also include receiving modeled dogleg and/or other
well plan data
taken from surveys or otherwise obtained. In a subsequent step 920, the real-
time and/or
modeled data received during step 910 is utilized to calculate a real-time
survey projection
ahead of the most recent standard survey result. The real-time survey
projection calculated
during step 920 can then optionally be temporarily utilized as the next
standard survey point
during a subsequent step 930. The method 900 may also include a step 940
following step
920 and/or step 930, during which the real-time survey projection calculated
during step 920
is compared to the well plan at the corresponding hole depth. A step 950 may
follow step
930 and/or step 940, during which the directional driller is given the real-
time survey
projection calculated during step 920 and/or the results of the comparison
performed during
step 940. Consequently, the directional driller can more accurately assess the
progress of the
current drilling operation even in the absence of any direct inclination and
azimuth
measurements at hole depth.
[00311] In an exemplary embodiment within the scope of the present disclosure,
the
method 900 then repeats, such that the method flow goes back to step 910 and
begins again.
Iteration of the method 900 may be utilized to characterize the performance of
the bottom
hole assembly. Moreover, iteration may allow the real-time survey projection
calculation
model to refine itself each time a survey is received. Use of the method 900
may, at least in
81
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
some embodiments, assist the directional driller in the drilling operation by
applying build
and turn rates to the slide sections and projections across sections drilled
by rotating.
[003121 As described above, the conventional approach entails conducting a
standard
survey at each drill pipe connection to obtain a measurement of inclination
and azimuth for
the new survey position. Thus, the prior art makes measurements after the hole
is drilled. In
contrast, with the method 900 and others within the scope the present
disclosure, real-time
measurements are made ahead of the last standard survey, and can give the
directional driller
feedback on the progress and effectiveness of a slide or rotation procedure.
[003131 Referring to Fig. 9B, illustrated is a flow-chart diagram of a
simplified version
of the method 900 shown in Fig. 9A, herein designated by the reference numeral
900a. The
method 900a includes step 910 during which toolface and hole depth
measurements are
received from rig instruments. Step 910 may also include receiving model or
well plan data
corresponding to the real-time data received from the rig instruments. Such
receipt of the
real-time and/or model data may be at one or more controllers, processing
devices, and/or
other devices, such as the controller 190 shown in Fig. 1.
[003141 In a subsequent step 960, these measurements are utilized with modeled
or
calculated data from previous surveys (e.g., including build rates, doglegs,
etc.) to track the
progress of the hole by calculating a real-time survey projection and
comparing the projection
to the well plan. Steps 910 and 960 are then repeated, perhaps at rates or
intervals which
yield high granularity. Step 960 may also include averaging the received data
across depth
intervals (e.g., averaging most recently received data with previously
received data).
Consequently, the data received during step 910 and processed during step 960
may provide
precise resolution, perhaps on a foot-by-foot basis during a slide operation,
and may
demonstrate how a particular drilling operation will be or is being affected
by how precise a
particular toolface is being maintained.
[003151 A high resolution view of the current hole versus the well plan is
often key to
tracking the effectiveness of a slide operation. For example, within the span
of a single joint,
a directional driller may be required (e.g., by the well plan) to perform a 20
foot slide, 50 feet
of rotary drilling, and then another 20 foot slide. Conventionally, the
driller would not know
the effectiveness of this section until he receives his next survey, which is
performed after the
slide-rotate-slide procedure is attempted. However, according to one or more
aspects of the
present disclosure, the driller can calculate utilize realtime surveys
projections throughout the
slide-rotate-slide procedure to show the projected well path of the bit. Thus,
the accuracy
82
CA 02700258 2012-04-25
with which the slide-rotate-slide procedure is performed may be dramatically
increased, and
when used to perform the method in Fig. 5A, provides more accurate directional
correction
than conventional systems. Moreover, the methods 900 and 900a may include
updating build
rates and model on each real-time survey, thus increasing the accuracy of each
subsequent
survey, survey projection, and/or drilling stage.
[00316] Figs. I OA and I OB are exemplary illustrations of user displays
relaying
information about the bit location to a user. The display in the figures may
be any display
discussed herein, including the displays 335, 472, 692c, and 810. Turning to
Fig. 1 OA,
illustrated is a schematic view of a human-machine interface (HMI) 1000
according to one or
more aspects of the present disclosure. The HMI 100 may be utilized by a human
operator
during directional and/or other drilling operations to monitor the
relationship between
toolface orientation and quill position. In an exemplary embodiment, the HMI
1000 is one of
several display screens selectable by the user during drilling operations, and
may be included
as or within the human-machine interfaces, drilling operations and/or drilling
apparatus
described in the systems herein. The HMI 100 may also he implemented as a
series of instructions
recorded on a computer-readable medium, such as described in one or more of
these references.
[00317] The HMI 100 is used by the directional driller while drilling to
monitor the
BHA in three-dimensional space. The control system or computer which drives
one or more
other human-machine interfaces during drilling operation may he configured to
also display
the HMI 1000. Alternatively, the HMI 1000 may be driven or displayed by a
separate control
system or computer, and may be displayed on a computer display (monitor) other
than that on
which the remaining drilling operation screens are displayed.
[00318] The control system or computer driving the HMI 1000 includes a
"survey" or
other data channel, or otherwise includes means for receiving and/or reading
sensor data
relayed from the BHA, a measurement-while-drilling (MWD) assembly, and/or
other drilling
parameter measurement means, where such relay may be via the Wellsite
Information
Transfer Standard (WITS), WITS Markup Language (WITSML), and/or another data
transfer
protocol. Such electronic data may include gravity-based toolface orientation
data, magnetic-
based toolface orientation data, azimuth toolface orientation data, and/or
inclination toolface
orientation data, among others. In an exemplary, embodiment, the electronic
data includes
magnetic-based toolface orientation data when the toolface orientation is less
than about 7
relative to vertical, and alternatively includes gravity-based toolface
orientation data when the
83
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
toolface orientation is greater than about 7 relative to vertical. In other
embodiments,
however, the electronic data may include both gravity- and magnetic-based
toolface
orientation data. The azimuth toolface orientation data may relate the azimuth
direction of
the remote end of the drill string relative to true North, wellbore high side,
and/or another
predetermined orientation. The inclination toolface orientation data may
relate the inclination
of the remote end of the drill string relative to vertical.
[00319] As shown in Fig. 10A, the HMI 1000 may be depicted as substantially
resembling a dial or target shape having a plurality of concentric nested
rings 1005. The
magnetic-based toolface orientation data is represented in the HMI 1000 by
symbols 1010,
and the gravity-based toolface orientation data is represented by symbols
1015. The HMI
1000 also includes symbols 1020 representing the quill position. In the
exemplary
embodiment shown in Fig. 10A, the magnetic toolface data symbols 1010 are
circular, the
gravity toolface data symbols 1015 are rectangular, and the quill position
data symbols 1020
are triangular, thus distinguishing the different types of data from each
other. Of course,
other shapes may be utilized within the scope of the present disclosure. The
symbols 1010,
1015, 1020 may also or alternatively be distinguished from one another via
color, size,
flashing, flashing rate, and/or other graphic means.
[00320] The symbols 1010, 1015, 1020 may indicate only the most recent
toolface
(1010, 1015) and quill position (120) measurements. However, as in the
exemplary
embodiment shown in Figs. 10A and 10B, the HMI 1000 may include a historical
representation of the toolface and quill position measurements, such that the
most recent
measurement and a plurality of immediately prior measurements are displayed.
Thus, for
example, each ring 1005 in the HMI 1000 may represent a measurement iteration
or count, or
a predetermined time interval, or otherwise indicate the historical relation
between the most
recent measurement(s) and prior measurement(s). In the exemplary embodiment
shown in
Fig. 10A, there are five such rings 1005 in the dial (the outermost ring being
reserved for
other data indicia), with each ring 1005 representing a data measurement or
relay iteration or
count. The toolface symbols 1010, 1015 may each include a number indicating
the relative
age of each measurement. In other embodiments, color, shape, and/or other
indicia may
graphically depict the relative age of measurement. Although not depicted as
such in Fig.
I OA, this concept may also be employed to historically depict the quill
position data.
[00321] The HMI 1000 may also include a data legend 1025 linking the shapes,
colors,
and/or other parameters of the data symbols 1010, 1015, 1020 to the
corresponding data
84
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
represented by the symbols. The HMI 1000 may also include a textual and/or
other type of
indicator 1030 of the current toolface mode setting. For example, the toolface
mode may be
set to display only gravitational toolface data, only magnetic toolface data,
or a combination
thereof (perhaps based on the current toolface and/or drill string end
inclination). The
indicator 1030 may also indicate the current system time. The indicator 1030
may also
identify a secondary channel or parameter being monitored or otherwise
displayed by the
HMI 1000. For example, in the exemplary embodiment shown in Fig. 10A, the
indicator
1030 indicates that a combination ("Combo") toolface mode is currently
selected by the user,
that the bit depth is being monitored on the secondary channel, and that the
current system
time is 13:09:04.
[00322] The HMI 1000 may also include a textual and/or other type of indicator
1035
displaying the current or most recent toolface orientation. The indicator 1035
may also
display the current toolface measurement mode (e.g., gravitational vs.
magnetic). The
indicator 1035 may also display the time at which the most recent toolface
measurement was
performed or received, as well as the value of any parameter being monitored
by a second
channel at that time. For example, in the exemplary embodiment shown in Fig.
10A, the
most recent toolface measurement was measured by a gravitational toolface
sensor, which
indicated that the toolface orientation was -75 , and this measurement was
taken at time
13:00:13 relative to the system clock, at which time the bit-depth was most
recently measured
to be 1830 feet.
[00323] The HMI 1000 may also include a textual and/or other type of indicator
1040
displaying the current or most recent inclination of the remote end of the
drill string. The
indicator 1040 may also display the time at which the most recent inclination
measurement
was performed or received, as well as the value of any parameter being
monitored by a
second channel at that time. For example, in the exemplary embodiment shown in
Fig. 10A,
the most recent drill string end inclination was 8 , and this measurement was
taken at time
13:00:04 relative to the system clock, at which time the bit-depth was most
recently measured
to be 1830 feet. The HMI 1000 may also include an additional graphical or
other type of
indicator 1040a displaying the current or most recent inclination. Thus, for
example, the
HMI 1000 may depict the current or most recent inclination with both a textual
indicator
(e.g., indicator 1040) and a graphical indicator (e.g., indicator 1040a). In
the embodiment
shown in Fig. 10A, the graphical inclination indicator 1040a represents the
current or most
recent inclination as an arcuate bar, where the length of the bar indicates
the degree to which
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
the inclination varies from vertical, and where the direction in which the bar
extends (e.g.,
clockwise vs. counterclockwise) may indicate a direction of inclination (e.g.,
North vs.
South).
[00324] The HMI 1000 may also include a textual and/or other type of indicator
1045
displaying the current or most recent azimuth orientation of the remote end of
the drill string.
The indicator 1045 may also display the time at which the most recent azimuth
measurement
was performed or received, as well as the value of any parameter being
monitored by a
second channel at that time. For example, in the exemplary embodiment shown in
Fig. 10A,
the most recent drill string end azimuth was 67 , and this measurement was
taken at time
12:59:55 relative to the system clock, at which time the bit-depth was most
recently measured
to be 1830 feet. The HMI 1000 may also include an additional graphical or
other type of
indicator 1045a displaying the current or most recent inclination. Thus, for
example, the
HMI 1000 may depict the current or most recent inclination with both a textual
indicator
(e.g., indicator 1045) and a graphical indicator (e.g., indicator 1045a). In
the embodiment
shown in Fig. 10A, the graphical azimuth indicator 1045a represents the
current or most
recent azimuth measurement as an arcuate bar, where the length of the bar
indicates the
degree to which the azimuth orientation varies from true North or some other
predetermined
position, and where the direction in which the bar extends (e.g., clockwise
vs.
counterclockwise) may indicate an azimuth direction (e.g., East-of-North vs.
West-of-North).
[00325] In some embodiments, the HMI 1000 includes data corresponding to the
planned drilling path and the actual drilling path discussed with reference to
Figs. 4C and 5A.
This data may provide a visual indicator to a driller of the location of the
BHA bit relative to
the planned drilling path and/or the target location. In addition, the taken-
over-time data
displayed in the HMI 1000 in Fig. 10A may be considered when calculating the
position of
the BHA, whether it is deviating from the planned drilling path, and which
zone in Fig. 5B it
is located in.
[00326] Referring to Fig. 10B, illustrated is a magnified view of a portion of
the HMI
1000 shown in Fig. 10A. In embodiments in which the HMI 1000 is depicted as a
dial or
target shape, the most recent toolface and quill position measurements may be
closest to the
edge of the dial, such that older readings may step toward the middle of the
dial. For
example, in the exemplary embodiment shown in Fig. 2, the last reading was 8
minutes
before the currently-depicted system time, the next reading was 7 minutes
before that one,
and the oldest reading was 6 minutes older than the others, for a total of 21
minutes of
86
CA 02700258 2012-04-25
recorded activity. Readings that are hours or seconds old may indicate the
length/unit of time
with an "h" or an "s."
[00327] As also shown in Fig. IOB, positioning the user's mouse pointer or
other
graphical user-input means over one of the toolface or quill position symbols
1010, 1015,
1020 may show the symbol's timestamp, as well as the secondary indicator (if
any), in a pop-
up window 1050. Timestamps may be dependent upon the device settings at the
actual time
of recording the measurement. The toolface symbols 1010, 1015 may show the
time elapsed
from when the measurement is recorded by the sensing device (e.g., relative to
the current
system time). Secondary channels set to display a timestamp may show a
timestamp
according to the device recording the measurement.
[00328] In the embodiment shown in Figs. 1 OA and I OB, the HMI 1000 shows the
absolute position of the top-drive quill referenced to true North, hole high-
side, or to some
other predetermined orientation. The HMI 1000 also shows current and
historical toolface
data received from the downhole tools (e.g., MWD). The HMI 1000, other human-
machine
interfaces within the scope of the present disclosure, and/or other tools
within the scope of the
present disclosure may have, enable, and/or exhibit a simplified understanding
of the effect of
reactive torque on toolface measurements, by accurately monitoring and
simultaneously
displaying both toolface and quill position measurements to the user.
[00329] In view of the above and the Figures herein, those of ordinary skill
in the art should
readily understand that the present disclosure introduces a method of visibly
demonstrating a
relationship between toolface orientation and quill orientation, such method
including: (1) receiving
electronic data on an on-going basis, wherein the electronic data includes
quill orientation data and at
least one of gravity-based toolface orientation data and magnetic-based
toolface orientation data; and
(2) displaying the electronic data on a user-viewable display in a historical
format depicting data
resulting from a most recent measurement and a plurality of immediately prior
measurements. The
electronic data may further include toolface azimuth data, relating the
azimuth orientation of
the drill string near the bit. The electronic data may further include
toolface inclination data,
relating the inclination of the drill string near the bit. The quill position
data may relate the
orientation of the quill, top drive, Kelly, and/or other rotary drive means to
the bit and/or toolface.
The electronic data may be received from MWD and/or other downhole
sensor/measurement means.
87
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
[00330] The method may further include associating the electronic data with
time
indicia based on specific times at which measurements yielding the electronic
data were
performed. In an exemplary embodiment, the most current data may be displayed
textually
and older data may be displayed graphically, such as a dial- or target-shaped
representation.
The graphical display may include time-dependent or time-specific symbols or
other icons,
which may each be user-accessible to temporarily display data associated with
that time (e.g.,
pop-up data). The icons may have a number, text, color, or other indication of
age relative to
other icons. The icons may be oriented by time, newest at the dial edge,
oldest at the dial
center. The icons may depict the change in time from (1) the measurement being
recorded by
a corresponding sensor device to (2) the current computer system time. The
display may also
depict the current system time.
[00331] The present disclosure also introduces an apparatus including: (1)
means for
receiving electronic data on an on-going basis, wherein the electronic data
includes quill
orientation data and at least one of gravity-based toolface orientation data
and magnetic-
based toolface orientation data; and (2) means for displaying the electronic
data on a user-
viewable display in a historical format depicting data resulting from a most
recent
measurement and a plurality of immediately prior measurements.
[00332] Embodiments within the scope of the present disclosure may offer
certain
advantages over the prior art. For example, when toolface and quill position
data are
combined on a single visual display, it may help an operator or other human
personnel to
understand the relationship between toolface and quill position. Combining
toolface and
quill position data on a single display may also or alternatively aid
understanding of the
relationship that reactive torque has with toolface and/or quill position.
[00333] Referring to Fig. 11, illustrated is an exemplary system 1100 for
implementing
one or more embodiments of at least portions of the apparatus and/or methods
described
herein. The system 1100 includes a processor 1102, an input device 1104, a
storage device
1106, a video controller 1108, a system memory 1110, a display 1114, and a
communication
device 1116, all interconnected by one or more buses 1112. The storage device
1106 may be
a floppy drive, hard drive, CD, DVD, optical drive, or any other form of
storage device. In
addition, the storage device 1106 may be capable of receiving a floppy disk,
CD, DVD, or
any other form of computer-readable medium that may contain computer-
executable
instructions. Communication device 1116 may be a modem, network card, or any
other
device to enable the system 1100 to communicate with other systems.
88
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
[00334] A computer system typically includes at least hardware capable of
executing
machine readable instructions, as well as software for executing acts
(typically machine-
readable instructions) that produce a desired result. In addition, a computer
system may
include hybrids of hardware and software, as well as computer sub-systems.
[00335] Hardware generally includes at least processor-capable platforms, such
as
client-machines (also known as personal computers or servers), and hand-held
processing
devices (such as smart phones, PDAs, and personal computing devices (PCDs),
for example).
Furthermore, hardware typically includes any physical device that is capable
of storing
machine-readable instructions, such as memory or other data storage devices.
Other forms of
hardware include hardware sub-systems, including transfer devices such as
modems, modem
cards, ports, and port cards, for example. Hardware may also include, at least
within the
scope of the present disclosure, multi-modal technology, such as those devices
and/or
systems configured to allow users to utilize multiple forms of input and
output - including
voice, keypads, and stylus - interchangeably in the same interaction,
application, or interface.
[00336] Software may include any machine code stored in any memory medium,
such
as RAM or ROM, machine code stored on other devices (such as floppy disks, CDs
or DVDs,
for example), and may include executable code, an operating system, as well as
source or
object code, for example. In addition, software may encompass any set of
instructions
capable of being executed in a client machine or server - and, in this form,
is often called a
program or executable code.
[00337] Hybrids (combinations of software and hardware) are becoming more
common as devices for providing enhanced functionality and performance to
computer
systems. A hybrid may be created when what are traditionally software
functions are directly
manufactured into a silicon chip - this is possible since software may be
assembled and
compiled into ones and zeros, and, similarly, ones and zeros can be
represented directly in
silicon. Typically, the hybrid (manufactured hardware) functions are designed
to operate
seamlessly with software. Accordingly, it should be understood that hybrids
and other
combinations of hardware and software are also included within the definition
of a computer
system herein, and are thus envisioned by the present disclosure as possible
equivalent
structures and equivalent methods.
[00338] Computer-readable mediums may include passive data storage such as a
random access memory (RAM), as well as semi-permanent data storage such as a
compact
disk or DVD. In addition, an embodiment of the present disclosure may be
embodied in the
89
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
RAM of a computer and effectively transform a standard computer into a new
specific
computing machine.
[00339] Data structures are defined organizations of data that may enable an
embodiment of the present disclosure. For example, a data structure may
provide an
organization of data or an organization of executable code (executable
software).
Furthermore, data signals are carried across transmission mediums and store
and transport
various data structures, and, thus, may be used to transport an embodiment of
the invention.
It should be noted in the discussion herein that acts with like names may be
performed in like
manners, unless otherwise stated.
[00340] The controllers and/or systems of the present disclosure may be
designed to
work on any specific architecture. For example, the controllers and/or systems
may be
executed on one or more computers, Ethernet networks, local area networks,
wide area
networks, internets, intranets, hand-held and other portable and wireless
devices and
networks.
[00341] In view of all of the above and Figs. 1-11, those of ordinary skill in
the art
should readily recognize that the present disclosure introduces a method of
directionally
steering a bottom hole assembly during a drilling operation from a drilling
rig to an
underground target location. The method includes generating a drilling plan
having
a drilling path and an acceptable margin of error as a tolerance zone;
receiving data
indicative of directional trends and projection to bit depth; determining the
actual
location of the bottom hole assembly based on the direction trends and the
projection
to bit depth; determining whether the bit is within the tolerance zone;
comparing the
actual location of the bottom hole assembly to the planned drilling path to
identify
an amount of deviation of the bottom hole assembly from the actual drilling
path;
creating a modified drilling path based on the amount of identified deviation
from
the planned path including: creating a modified drilling path that intersects
the
planned drilling path if the amount of deviation from the planned path is less
than a
threshold amount of deviation, and creating a modified drilling path to the
target
location that does not intersect the planned drilling path if the amount of
deviation
from the planned path is greater than a threshold amount of deviation;
determining a
desired tool face orientation to steer the bottom hole assembly along the
modified
drilling path; automatically and electronically generating drilling rig
control signals
at a directional steering controller; and outputting the drilling rig control
signals to a
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
drawworks and a top drive to steer the bottom hole assembly along the modified
drilling path.
[00342] The present disclosure also introduces a method of using a quill to
steer a
hydraulic motor when elongating a wellbore in a direction having a horizontal
component,
wherein the quill and the hydraulic motor are coupled to opposing ends of a
drill string, the
method including: monitoring an actual toolface orientation of a tool driven
by the hydraulic
motor by monitoring a drilling operation parameter indicative of a difference
between the
actual toolface orientation and a desired toolface orientation; and adjusting
a position of the
quill by an amount that is dependent upon the monitored drilling operation
parameter. The
amount of quill position adjustment may be sufficient to compensate for the
difference
between the actual and desired toolface orientations. Adjusting the quill
position may include
adjusting a rotational position of the quill relative to the wellbore, a
vertical position of the
quill relative to the wellbore, or both. Monitoring the drilling operation
parameter indicative
of the difference between the actual and desired toolface orientations may
includes
monitoring a plurality of drilling operation parameters each indicative of the
difference
between the actual and desired toolface orientations, and the amount of quill
position
adjustment may be further dependent upon each of the plurality of drilling
operation
parameters.
[00343] Monitoring the drilling operation parameter may include monitoring
data
received from a toolface orientation sensor, and the amount of quill position
adjustment may
be dependent upon the toolface orientation sensor data. The toolface sensor
may includes a
gravity toolface sensor and/or a magnetic toolface sensor.
[00344] The drilling operation parameter may include a weight applied to the
tool
(WOB), a depth of the tool within the wellbore, and/or a rate of penetration
of the tool into
the wellbore (ROP). The drilling operation parameter may include a hydraulic
pressure
differential across the hydraulic motor (AP), and the AP may be a corrected AP
based on
monitored pressure of fluid existing in an annulus defined between the
wellbore and the drill
string.
[00345] In an exemplary embodiment, monitoring the drilling operation
parameter
indicative of the difference between the actual and desired toolface
orientations includes
monitoring data received from a toolface orientation sensor, monitoring a
weight applied to
the tool (WOB), monitoring a depth of the tool within the wellbore, monitoring
a rate of
penetration of the tool into the wellbore (ROP), and monitoring a hydraulic
pressure
91
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
differential across the hydraulic motor (AP). Adjusting the quill position may
include
adjusting the quill position by an amount that is dependent upon the monitored
toolface
orientation sensor data, the monitored WOB, the monitored depth of the tool
within the
wellbore, the monitored ROP, and the monitored AP.
[003461 Monitoring the drilling operation parameter and adjusting the quill
position
may be performed simultaneously with operating the hydraulic motor. Adjusting
the quill
position may include causing a drawworks to adjust a weight applied to the
tool (WOB) by an
amount dependent upon the monitored drilling operation parameter. Adjusting
the quill
position may include adjusting a neutral rotational position of the quill, and
the method may
further include oscillating the quill by rotating the quill through a
predetermined angle past
the neutral position in clockwise and counterclockwise directions.
[003471 The present disclosure also introduces a system for using a quill to
steer a
hydraulic motor when elongating a wellbore in a direction having a horizontal
component,
wherein the quill and the hydraulic motor are coupled to opposing ends of a
drill string. In an
exemplary embodiment, the system includes means for monitoring an actual
toolface
orientation of a tool driven by the hydraulic motor, including means for
monitoring a drilling
operation parameter indicative of a difference between the actual toolface
orientation and a
desired toolface orientation; and means for adjusting a position of the quill
by an amount that
is dependent upon the monitored drilling operation parameter.
[003481 The present disclosure also provides an apparatus for using a quill to
steer a
hydraulic motor when elongating a wellbore in a direction having a horizontal
component,
wherein the quill and the hydraulic motor are coupled to opposing ends of a
drill string. In an
exemplary embodiment, the apparatus includes a sensor configured to detect a
drilling
operation parameter indicative of a difference between an actual toolface
orientation of a tool
driven by the hydraulic motor and a desired toolface orientation of the tool;
and a toolface
controller configured to adjust the actual toolface orientation by generating
a quill drive
control signal directing a quill drive to adjust a rotational position of the
quill based on the
monitored drilling operation parameter.
[003491 The present disclosure also introduces a method of using a quill to
steer a
hydraulic motor when elongating a wellbore in a direction having a horizontal
component,
wherein the quill and the hydraulic motor are coupled to opposing ends of a
drill string. In an
exemplary embodiment, the method includes monitoring a hydraulic pressure
differential
across the hydraulic motor (AP) while simultaneously operating the hydraulic
motor, and
92
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
adjusting a toolface orientation of the hydraulic motor by adjusting a
rotational position of the
quill based on the monitored AP. The monitored AP may be a corrected AP that
is calculated
utilizing monitored pressure of fluid existing in an annulus defined between
the wellbore and
the drill string. The method may further include monitoring an existing
toolface orientation
of the motor while simultaneously operating the hydraulic motor, and adjusting
the rotational
position of the quill based on the monitored toolface orientation. The method
may further
include monitoring a weight applied to a bit of the hydraulic motor (WOB)
while
simultaneously operating the hydraulic motor, and adjusting the rotational
position of the
quill based on the monitored WOB. The method may further include monitoring a
depth of a
bit of the hydraulic motor within the wellbore while simultaneously operating
the hydraulic
motor, and adjusting the rotational position of the quill based on the
monitored depth of the
bit. The method may further include monitoring a rate of penetration of the
hydraulic motor
into the wellbore (ROP) while simultaneously operating the hydraulic motor,
and adjusting
the rotational position of the quill based on the monitored ROP. Adjusting the
toolface
orientation may include adjusting the rotational position of the quill based
on the monitored
WOB and the monitored ROP. Alternatively, adjusting the toolface orientation
may include
adjusting the rotational position of the quill based on the monitored WOB, the
monitored
ROP and the existing toolface orientation. Adjusting the toolface orientation
of the hydraulic
motor may further include causing a drawworks to adjust a weight applied to a
bit of the
hydraulic motor (WOB) based on the monitored AP. The rotational position of
the quill may
be a neutral position, and the method may further include oscillating the
quill by rotating the
quill through a predetermined angle past the neutral position in clockwise and
counterclockwise directions.
[00350] The present disclosure also introduces a system for using a quill to
steer a
hydraulic motor when elongating a wellbore in a direction having a horizontal
component,
wherein the quill and the hydraulic motor are coupled to opposing ends of a
drill string. In an
exemplary embodiment, the system includes means for detecting a hydraulic
pressure
differential across the hydraulic motor (AP) while simultaneously operating
the hydraulic
motor, and means for adjusting a toolface orientation of the hydraulic motor,
wherein the
toolface orientation adjusting means includes means for adjusting a rotational
position of the
quill based on the detected AP. The system may further include means for
detecting an
existing toolface orientation of the motor while simultaneously operating the
hydraulic motor,
wherein the quill rotational position adjusting means may be further
configured to adjust the
93
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
rotational position of the quill based on the monitored toolface orientation.
The system may
further include means for detecting a weight applied to a bit of the hydraulic
motor (WOB)
while simultaneously operating the hydraulic motor, wherein the quill
rotational position
adjusting means may be further configured to adjust the rotational position of
the quill based
on the monitored WOB. The system may further include means for detecting a
depth of a bit
of the hydraulic motor within the wellbore while simultaneously operating the
hydraulic
motor, wherein the quill rotational position adjusting means may be further
configured to
adjust the rotational position of the quill based on the monitored depth of
the bit. The system
may further include means for detecting a rate of penetration of the hydraulic
motor into the
wellbore (ROP) while simultaneously operating the hydraulic motor, wherein the
quill
rotational position adjusting means may be further configured to adjust the
rotational position
of the quill based on the monitored ROP. The toolface orientation adjusting
means may
further include means for causing a drawworks to adjust a weight applied to a
bit of the
hydraulic motor (WOB) based on the detected AP.
[00351] The present disclosure also introduces an apparatus for using a quill
to steer a
hydraulic motor when elongating a wellbore in a direction having a horizontal
component,
wherein the quill and the hydraulic motor are coupled to opposing ends of a
drill string. In an
exemplary embodiment, the apparatus includes a pressure sensor configured to
detect a
hydraulic pressure differential across the hydraulic motor (AP) during
operation of the
hydraulic motor, and a toolface controller configured to adjust a toolface
orientation of the
hydraulic motor by generating a quill drive control signal directing a quill
drive to adjust a
rotational position of the quill based on the detected AP. The apparatus may
further include a
toolface orientation sensor configured to detect a current toolface
orientation, wherein the
toolface controller may be configured to generate the quill drive control
signal further based
on the detected current toolface orientation. The apparatus may further
include a weight-on-
bit (WOB) sensor configured to detect data indicative of an amount of weight
applied to a bit
of the hydraulic motor, and a drawworks controller configured to cooperate
with the toolface
controller in adjusting the toolface orientation by generating a drawworks
control signal
directing a drawworks to operate the drawworks, wherein the drawworks control
signal may
be based on the detected WOB. The apparatus may further include a rate-of-
penetration
(ROP) sensor configured to detect a rate at which the wellbore is being
elongated, wherein
the drawworks control signal may be further based on the detected ROP.
94
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
[003521 Methods and apparatus within the scope of the present disclosure
include
those directed towards automatically obtaining and/or maintaining a desired
toolface
orientation by monitoring drilling operation parameters which previously have
not been
utilized for automatic toolface orientation, including one or more of actual
mud motor AP,
actual toolface orientation, actual WOB, actual bit depth, actual ROP, actual
quill oscillation.
Exemplary combinations of these drilling operation parameters which may be
utilized
according to one or more aspects of the present disclosure to obtain and/or
maintain a desired
toolface orientation include:
= OP and TF;
= AP, TF, and WOB;
= AP, TF, WOB, and DEPTH;
= AP and WOB;
= AP, TF, and DEPTH;
= AP, TF, WOB, and ROP;
= AP and ROP;
= AP, TF, and ROP;
= AP, TF, WOB, and OSC;
= AP and DEPTH;
= OP, TF, and OSC;
= AP, TF, DEPTH, and ROP;
= OP and OSC;
AP, WOB, and DEPTH;
AP, TF, DEPTH, and OSC;
= TF and ROP;
= AP, WOB, and ROP;
= AP, WOB, DEPTH, and ROP;
= TF and DEPTH;
= AP, WOB, and OSC;
= AP, WOB, DEPTH, and OSC;
= TF and OSC;
= AP, DEPTH, and ROP;
= AP, DEPTH, ROP, and OSC;
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
= WOB and DEPTH;
= AP, DEPTH, and OSC;
= AP, TF, WOB, DEPTH, and ROP;
= WOB and OSC;
= AP, ROP, and OSC;
= AP, TF, WOB, DEPTH, and OSC;
= ROP and OSC;
= AP, TF, WOB, ROP, and OSC;
= ROP and DEPTH; and
= AP, TF, WOB, DEPTH, ROP, and OSC;
where AP is the actual mud motor AP, TF is the actual toolface orientation,
WOB is the
actual WOB, DEPTH is the actual bit depth, ROP is the actual ROP, and OSC is
the actual
quill oscillation frequency, speed, amplitude, neutral point, and/or torque.
[003531 In an exemplary embodiment, a desired toolface orientation is provided
(e.g.,
by a user, computer, or computer program), and apparatus according to one or
more aspects
of the present disclosure will subsequently track and control the actual
toolface orientation, as
described above. However, while tracking and controlling the actual toolface
orientation,
drilling operation parameter data may be monitored to establish and then
update in real-time
the relationship between: (1) mud motor AP and bit torque; (2) changes in WOB
and bit
torque; and (3) changes in quill position and actual toolface orientation;
among other possible
relationships within the scope of the present disclosure. The learned
information may then be
utilized to control actual toolface orientation by affecting a change in one
or more of the
monitored drilling operation parameters.
[003541 Thus, for example, a desired toolface orientation may be input by a
user, and a
rotary drive system according to aspects of the present disclosure may rotate
the drill string
until the monitored toolface orientation and/or other drilling operation
parameter data
indicates motion of the downhole tool. The automated apparatus of the present
disclosure
then continues to control the rotary drive until the desired toolface
orientation is obtained.
Directional drilling then proceeds. If the actual toolface orientation wanders
off from the
desired toolface orientation, as possibly indicated by the monitored drill
operation parameter
data, the rotary drive may react by rotating the quill and/or drill string in
either the clockwise
or counterclockwise direction, according to the relationship between the
monitored drilling
96
CA 02700258 2010-03-19
WO 2009/039453 PCT/US2008/077131
parameter data and the toolface orientation. If an oscillation mode is being
utilized, the
apparatus may alter the amplitude of the oscillation (e.g., increasing or
decreasing the
clockwise part of the oscillation) to bring the actual toolface orientation
back on track.
Alternatively, or additionally, a drawworks system may react to the deviating
toolface
orientation by feeding the drilling line in or out, and/or a mud pump system
may react by
increasing or decreasing the mud motor AP. If the actual toolface orientation
drifts off the
desired orientation further than a preset (user adjustable) limit for a period
longer than a
preset (user adjustable) duration, then the apparatus may signal an audio
and/or visual alarm.
The operator may then be given the opportunity to allow continued automatic
control, or take
over manual operation.
[00355] This approach may also be utilized to control toolface orientation,
with
knowledge of quill orientation before and after a connection, to reduce the
amount of time
required to make a connection. For example, the quill orientation may be
monitored on-
bottom at a known toolface orientation, WOB, and/or mud motor AP. Slips may
then be set,
and the quill orientation may be recorded and then referenced to the above-
described
relationship(s). The connection may then take place, and the quill orientation
may be
recorded just prior to pulling from the slips. At this point, the quill
orientation may be reset
to what it was before the connection. The drilling operator or an automated
controller may
then initiate an "auto-orient" procedure, and the apparatus may rotate the
quill to a position
and then return to bottom. Consequently, the drilling operator may not need to
wait for a
toolface orientation measurement, and may not be required to go back to the
bottom blind.
Consequently, aspects of the present disclosure may offer significant time
savings during
connections.
[00356] Moreover, methods within the scope of the present disclosure may be
local or
remote in nature. These methods, and any controllers discussed herein, may be
achieved by
one or more intelligent adaptive controllers, programmable logic controllers,
artificial neural
networks, and/or other adaptive and/or "learning" controllers or processing
apparatus. For
example, such methods may be deployed or performed via PLC, PAC, PC, one or
more
servers, desktops, handhelds, and/or any other form or type of computing
device with
appropriate capability.
As used herein, the term "substantially" means that a numerical amount is
within about 20 percent, preferably within about 10 percent, and more
preferably within
about 5 percent of a stated value. In a preferred embodiment, these terms
refer to amounts
97
CA 02700258 2012-04-25
within about 1 percent, within about 0.5 percent, or even within about 0.1
percent, of a stated
value.
The term "about," as used herein, should generally be understood to refer to
both numbers in a range of numerals. For example, "about 1 to 2" should be
understood as
"about 1 to about 2." Moreover, all numerical rangcs herein should be
understood to include
each whole integer, or 1/10 of an integer, within the range.
[00357] The foregoing outlines features of several embodiments so that those
of
ordinary-skill in the art may better understand the aspects of the present
disclosure. Those of
ordinary-skill in the art should appreciate that they may readily use the
present disclosure as a
basis for designing or modifying other processes and structures for carrying
out the same
purposes and/or achieving the same advantages of the embodiments introduced
herein.
Those of ordinary-skill in the art should also realize that such equivalent
constructions do not
depart from the spirit and scope of the present disclosure, and that they may
make various
changes, substitutions and alterations herein without departing from the
spirit and scope of
the present disclosure.
98
