Note: Descriptions are shown in the official language in which they were submitted.
SURFACE STEERABLE DRILLING SYSTEM
FOR USE WITH ROTARY STEERABLE SYSTEM
RELATED APPLICATIONS
[0001] This application is a division of Canadian Patent Application Serial
No. 2,967,324,
filed 02 October 2015, and which has been submitted as the Canadian national
phase
application corresponding to International Patent Application No.
PCT/US2015/053846, filed
02 October 2015.
.. TECHNICAL FIELD
[0002] This application is directed to the creation of wells, such as oil
wells, and more
particularly to the planning and drilling of such wells.
BACKGROUND
[0003] Drilling a borehole for the extraction of minerals has become an
increasingly
complicated operation due to the increased depth and complexity of many
boreholes, including
the complexity added by directional drilling. Drilling is an expensive
operation and errors in
drilling add to the cost and, in some cases, drilling errors may permanently
lower the output of
a well for years into the future. Current technologies and methods do not
adequately address
the complicated nature of drilling. Accordingly, what is needed are a system
and method to
improve drilling operations and minimize drilling errors.
SUMMARY OF THE INVENTION
10003a] In one aspect of the invention, there is provided a method for
drilling, including:
receiving, by a surface steerable system coupled to a drilling rig, bottom
hole assembly (BHA)
information associated with a rotary steerable BHA at a first location in a
borehole, wherein
the rotary steerable BHA further includes a pad on an exterior surface of the
rotary steerable
BHA or a bent main shaft; receiving, by the surface steerable system,
geological information
associated with a geological formation through which the borehole extends;
calculating, by the
surface steerable system, forecasted information including torsional and
spatial forces that are
predicted to act on a drill bit attached to the rotary steerable BHA, wherein
the torsional and
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spatial forces are predicted to be caused by actuator forces associated with
the pad or the bent
main shaft, and wherein the forecasted information is calculated using the BHA
information
and the geological information; calculating, by the surface steerable system,
a first vector
representing a convergence path from the first location of the rotary
steerable BHA to a target
drilling path based on the forecasted information; causing, by the surface
steerable system, at
least one drilling parameter to be modified in order to enable drilling using
the rotary steerable
BHA according to the first vector, wherein the drilling rig is enabled for the
drilling according
to the at least one drilling parameter using the rotary steerable BHA; and
drilling the borehole
using the rotary steerable BHA according to the at least one drilling
parameter.
[0003b] In another aspect of the invention, there is provided a surface
steerable system for
use with a drilling rig, the surface steerable system including: a processor;
a non-transitory
memory accessible by the processor, the memory storing instructions for
execution by the
processor, the instructions including instructions for: receiving, by the
surface steerable system,
bottom hole assembly (BHA) information associated with a rotary steerable BHA
at a first
location in a borehole, wherein the rotary steerable BHA further includes a
pad on an exterior
surface of the rotary steerable BHA or a bent main shaft; receiving, by the
surface steerable
system, geological information associated with a geological formation through
which the
borehole extends; calculating, by the surface steerable system, forecasted
information
including torsional and spatial forces that are predicted to act on a drill
bit attached to the rotary
steerable BHA, wherein the torsional and spatial forces are predicted to be
caused by actuator
forces associated with the pad or the bent main shaft, and wherein the
forecasted information
is calculated using the BHA information and the geological information;
calculating, by the
surface steerable system, a first vector representing a convergence path from
the first location
of the rotary steerable BHA to a target drilling path based on the forecasted
information; and
causing, by the surface steerable system, at least one drilling parameter to
be modified in order
to enable drilling using the rotary steerable BHA in alignment with the first
vector, wherein the
drilling rig is enabled for the drilling according to the at least one
drilling parameter using the
rotary steerable BHA.
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[0003c] In a
further aspect of the invention, there is provided a drilling system,
including:
a rotary steerable bottom hole assembly (BHA) for drilling a borehole through
a geological
formation responsive to steering control signals, wherein the rotary steerable
BHA further
includes a pad on an exterior surface of the rotary steerable BHA or a bent
main shaft; a drilling
rig for driving the rotary steerable BHA coupled to a drill string; a surface
steerable system
enabled to control the drilling rig for generating the steering control
signals to control the rotary
steerable BHA; and wherein the surface steerable system is configured to:
receive BHA
information associated with the rotary steerable BHA at a first location in
the borehole;
calculate, based on the BHA information, forecasted information including
torsional and spatial
forces that are predicted to act on the rotary steerable BHA, wherein the
forecasted information
is calculated using the BHA information and the geological information, and
wherein the
torsional and spatial forces are predicted to be caused by actuator forces
associated with the
pad or the bent main shaft; calculate a first vector representing at least a
portion of a
convergence path from the location of the rotary steerable BHA to a target
drilling path based
on the forecasted information; and modify at least one drilling parameter in
order to enable
drilling using the rotary steerable BHA according to the first vector, wherein
the drilling rig is
enabled for the drilling according to the at least one drilling parameter
using the rotary steerable
BHA.
[0003d] In yet another aspect of the invention, there is provided a method
for drilling,
including: (a) receiving, by a surface steerable system coupled to a drilling
rig, bottom hole
assembly (BHA) information associated with a rotary steerable BHA at a first
location in a
borehole, wherein the rotary steerable BHA further includes a pad on an
exterior surface of the
rotary steerable BHA or a bent main shaft; (b) calculating, by the surface
steerable system,
forecasted information including torsional and spatial forces that are
predicted to act on a drill
bit attached to the rotary steerable BHA responsive to actuator forces
associated with the pad
or the bent main shaft, wherein the forecasted information is calculated using
the BHA
information and the geological information; (c) calculating, by the surface
steerable system
responsive to the BHA information, the first location of the rotary steerable
BHA with respect
to a target drilling path; (d) calculating, by the surface steerable system, a
first vector from the
first location of the rotary steerable BHA to the target drilling path, the
first vector representing
a convergence path from the first location of the rotary steerable BHA to the
target drilling path
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based on the forecasted information; (e) causing, by the surface steerable
system, at least one
drilling parameter to be modified in order to enable drilling using the rotary
steerable BHA
according to the first vector, wherein the drilling rig is enabled for the
drilling according to the
at least one drilling parameter using the rotary steerable BHA; (f) drilling
the borehole using
.. the rotary steerable BHA according to the at least one drilling parameter;
and (g) repeating
steps (a)-(f) at least one time during drilling until the rotary steerable BHA
substantially
converges with the target drilling path.
BRIEF DESCRIPTION OF THE DRAWINGS
[0004] For a more complete understanding, reference is now made to the
following
description taken in conjunction with the accompanying drawings in which:
100051 Fig. lA illustrates one embodiment of a drilling environment in
which a surface
steerable system may operate;
[0006] Fig. 1B illustrates one embodiment of a more detailed portion of
the drilling
environment of Fig. 1A;
[0007] Fig. 1C illustrates one embodiment of a more detailed portion of
the drilling
environment of Fig. 1B;
[0008] Fig. 2A illustrates one embodiment of the surface steerable system
of Fig. lA and
how information may flow to and from the system;
[0009] Fig. 2B illustrates one embodiment of a display that may be used
with the surface
steerable system of Fig. 2A;
[0010] Fig. 3 illustrates one embodiment of a drilling environment that
does not have the
benefit of the surface steerable system of Fig. 2A and possible communication
channels within
the environment;
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[0011] Fig. 4 illustrates one embodiment of a drilling environment that
has the benefit of
the surface steerable system of Fig. 2A and possible communication channels
within the
environment;
[0012] Fig. 5 illustrates one embodiment of data flow that may be supported
by the surface
steerable system of Fig. 2A;
[0013] Fig. 6 illustrates one embodiment of a method that may be executed
by the surface
steerable system of Fig. 2A;
[0014] Fig. 7A illustrates a more detailed embodiment of the method of
Fig. 6;
[0015] Fig. 7B illustrates a more detailed embodiment of the method of
Fig. 6;
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L
[0016] Fig. 7C illustrates one embodiment of a convergence plan
diagram with multiple
convergence paths;
[0017] Fig. 8A illustrates a more detailed embodiment of a portion of
the method of Fig.
7B;
[0018] Fig. 8B illustrates a more detailed embodiment of a portion of the
method of Fig.
6;
[0019] Fig. 8C illustrates a more detailed embodiment of a portion of
the method of Fig.
6;
[0020] Fig. 8D illustrates a more detailed embodiment of a portion of
the method of Fig.
6;
[0021] Fig. 9 illustrates one embodiment of a system architecture that
may be used for the
surface steerable system of Fig. 2A;
[0022] Fig. 10 illustrates one embodiment of a more detailed portion of
the system
architecture of Fig. 9;
[0023] Fig. 11 illustrates one embodiment of a guidance control loop that
may be used
within the system architecture of Fig. 9;
[0024] Fig. 12 illustrates one embodiment of an autonomous control loop
that may be
used within the system architecture of Fig. 9;
[0025] Fig. 13 illustrates one embodiment of a computer system that may
be used within
the surface steerable system of Fig. 2A;
[0026] Fig. 14 illustrates the use of a surface steerable system with a
rotary steerable
system; and
[0027] FIG. 15 illustrates one embodiment of a rotary steerable drilling
rig.
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DETAILED DESCRIPTION
[0028] Referring now to the drawings, wherein like reference numbers are
used herein to
designate like elements throughout, the various views and embodiments of a
system and
method for surface steerable drilling are illustrated and described, and other
possible
embodiments are described. The figures are not necessarily drawn to scale, and
in some
instances the drawings have been exaggerated and/or simplified in places for
illustrative
purposes only. One of ordinary skill in the art will appreciate the many
possible applications
and variations based on the following examples of possible embodiments.
[0029] Referring to Fig. 1A, one embodiment of an environment 100 is
illustrated with
multiple wells 102, 104, 106, 108, and a drilling rig 110. In the present
example, the wells
102 and 104 are located in a region 112, the well 106 is located in a region
114, the well 108
is located in a region 116, and the drilling rig 110 is located in a region
118, Each region
112, 114, 116, and 118 may represent a geographic area having similar
geological formation
characteristics. For example, region 112 may include particular formation
characteristics
identified by rock type, porosity, thickness, and other geological
information. These
formation characteristics affect drilling of the wells 102 and 104. Region 114
may have
formation characteristics that are different enough to be classified as a
different region for
drilling purposes, and the different formation characteristics affect the
drilling of the well
106. Likewise, formation characteristics in the regions 116 and 118 affect the
well 108 and
drilling rig 110, respectively.
[0030] It is understood the regions 112, 114, 116, and 118 may vary in
size and shape
depending on the characteristics by which they are identified. Furthermore,
the regions 112,
114, 116, and 118 may be sub-regions of a larger region. Accordingly, the
criteria by which
the regions 112, 114, 116, and 118 are identified is less important for
purposes of the present
disclosure than the understanding that each region 112, 114, 116, and 118
includes geological
characteristics that can be used to distinguish each region from the other
regions from a
drilling perspective. Such characteristics may be relatively major (e.g., the
presence or
absence of an entire rock layer in a given region) or may be relatively minor
(e.g., variations
in the thickness of a rock layer that extends through multiple regions).
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[0031] Accordingly, drilling a well located in the same region as other
wells, such as
drilling a new well in the region 112 with already existing wells 102 and 104,
means the
drilling process is likely to face similar drilling issues as those faced when
drilling the
existing wells in the same region. For similar reasons, a drilling process
performed in one
region is likely to face issues different from a drilling process performed in
another region.
However, even the drilling processes that created the wells 102 and 104 may
face different
issues during actual drilling as variations in the formation are likely to
occur even in a single
region.
[0032] Drilling a well typically involves a substantial amount of human
decision making
during the drilling process. For example, geologists and drilling engineers
use their
knowledge, experience, and the available information to make decisions on how
to plan the
drilling operation, how to accomplish the plan, and how to handle issues that
arise during
drilling. However, even the best geologists and drilling engineers perform
some guesswork
due to the unique nature of each borehole. Furthermore, a directional driller
directly
responsible for the drilling may have drilled other boreholes in the same
region and so may
have some similar experience, but it is impossible for a human to mentally
track all the
possible inputs and factor those inputs into a decision. This can result in
expensive mistakes,
as errors in drilling can add hundreds of thousands or even millions of
dollars to the drilling
cost and, in some cases, drilling errors may permanently lower the output of a
well, resulting
in substantial long term losses.
[0033] In the present example, to aid in the drilling process, each well
102, 104, 106, and
108 has corresponding collected data 120, 122, 124, and 126, respectively. The
collected
data may include the geological characteristics of a particular formation in
which the
corresponding well was formed, the attributes of a particular drilling rig,
including the bottom
hole assembly (BHA), and drilling information such as weight-on-bit (WOB),
drilling speed,
and/or other information pertinent to the formation of that particular
borehole. The drilling
information may be associated with a particular depth or other identifiable
marker so that, for
example, it is recorded that drilling of the well 102 from 1000 feet to 1200
feet occurred at a
first ROP through a first rock layer with a first WOB, while drilling from
1200 feet to 1500
feet occurred at a second ROP through a second rock layer with a second WOB.
The
collected data may be used to recreate the drilling process used to create the
corresponding
well 102, 104, 106, or 108 in the particular formation. It is understood that
the accuracy with
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which the drilling process can be recreated depends on the level of detail and
accuracy of the
collected data.
[00341 The collected data 120, 122, 124, and 126 may be stored in a
centralized database
128 as indicated by lines 130, 132, 134, and 136, respectively, which may
represent any
wired and/or wireless communication channel(s). The database 128 may be
located at a
drilling hub (not shown) or elsewhere. Alternatively, the data may be stored
on a removable
storage medium that is later coupled to the database 128 in order to store the
data. The
collected data 120, 122, 124, and 126 may be stored in the database 128 as
formation data
138, equipment data 140, and drilling data 142 for example. Formation data 138
may include
any formation information, such as rock type, layer thickness, layer location
(e.g., depth),
porosity, gamma readings, etc. Equipment data 140 may include any equipment
information,
such as drilling rig configuration (e.g., rotary table or top drive), bit
type, mud composition,
etc. Drilling data 142 may include any drilling information, such as drilling
speed, WOB,
differential pressure, toolface orientation, etc. The collected data may also
be identified by
well, region, and other criteria, and may be sortable to enable the data to be
searched and
analyzed. It is understood that many different storage mechanisms may be used
to store the
collected data in the database 128.
[00351 With additional reference to Fig. 1B, an environment 160 (not to
scale) illustrates
a more detailed embodiment of a portion of the region 118 with the drilling
rig 110 located at
the surface 162. A drilling plan has been formulated to drill a borehole 164
extending into
the ground to a true vertical depth (TVD) 166. The borehole 164 extends
through strata
layers 168 and 170, stopping in layer 172, and not reaching underlying layers
174 and 176.
The borehole 164 may be directed to a target area 180 positioned in the layer
172. The target
180 may be a subsurface point or points defined by coordinates or other
markers that indicate
where the borehole 164 is to end or may simply define a depth range within
which the
borehole 164 is to remain (e.g., the layer 172 itself). It is understood that
the target 180 may
be any shape and size, and may be defined in any way. Accordingly, the target
180 may
= represent an endpoint of the borehole 164 or may extend as far as can be
realistically drilled.
For example, if the drilling includes a horizontal component and the goal is
to follow the
layer 172 as far as possible, the target may simply be the layer 172 itself
and drilling may
continue until a limit is reached, such as a property boundary or a physical
limitation to the
length of the drillstring. A fault 178 has shifted a portion of each layer
downwards.
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Accordingly, the borehole 164 is located in non-shifted layer portions 168A-
176A, while
portions 168B-176B represent the shifted layer portions.
[00361 Current drilling techniques frequently involve directional
drilling to reach a target,
such as the target 180. The use of directional drilling generally increases
the amount of
reserves that can be obtained and also increases production rate, sometimes
significantly. For
example, the directional drilling used to provide the horizontal portion shown
in Fig. 1B
increases the length of the borehole in the layer 172, which is the target
layer in the present
example. Directional drilling may also be used alter the angle of the borehole
to address
faults, such as the fault 178 that has shifted the layer portion 172B. Other
uses for directional
drilling include sidetracking off of an existing well to reach a different
target area or a missed
target area, drilling around abandoned drilling equipment, drilling into
otherwise inaccessible
or difficult to reach locations (e.g., under populated areas or bodies of
water), providing a
relief well for an existing well, and increasing the capacity of a well by
branching off and
having multiple boreholes extending in different directions or at different
vertical positions
.. for the same well. Directional drilling is often not confined to a straight
horizontal borehole,
but may involve staying within a rock layer that varies in depth and thickness
as illustrated by
the layer 172. As such, directional drilling may involve multiple vertical
adjustments that
complicate the path of the borehole.
[00371 With additional reference to Fig. 1C, which illustrates one
embodiment of a
portion of the borehole 164 of Fig. 1B, the drilling of horizontal wells
clearly introduces
significant challenges to drilling that do not exist in vertical wells. For
example, a
substantially horizontal portion 192 of the well may be started off of a
vertical borehole 190
and one drilling consideration is the transition from the vertical portion of
the well to the
horizontal portion. This transition is generally a curve that defines a build
up section 194
beginning at the vertical portion (called the kick off point and represented
by line 196) and
ending at the horizontal portion (represented by line 198). The change in
inclination per
measured length drilled is typically referred to as the build rate and is
often defined in
degrees per one hundred feet drilled. For example, the build rate may be 6
/100ft, indicating
that there is a six degree change in inclination for every one hundred feet
drilled. The build
rate for a particular build up section may remain relatively constant or may
vary.
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[00381 The build rate depends on factors such as the formation through
which the
borehole 164 is to be drilled, the trajectory of the borehole 164, the
particular pipe and drill
collars/BHA components used (e.g., length, diameter, flexibility, strength,
mud motor bend
setting, and drill bit), the mud type and flow rate, the required horizontal
displacement,
stabilization, and inclination. An overly aggressive built rate can cause
problems such as
severe doglegs (e.g., sharp changes in direction in the borehole) that may
make it difficult or
impossible to run casing or perform other needed tasks in the borehole 164.
Depending on
the severity of the mistake, the borehole 164 may require enlarging or the bit
may need to be
backed out and a new passage formed. Such mistakes cost time and money.
However, if the
build rate is too cautious, significant additional time may be added to the
drilling process as it
is generally slower to drill a curve than to drill straight. Furthermore,
drilling a curve is more
complicated and the possibility of drilling errors increases (e.g., overshoot
and undershoot
that may occur trying to keep the bit on the planned path).
[00391 Two modes of drilling, known as rotating and sliding, are commonly
used to form
the borehole 164. Rotating, also called rotary drilling, uses a topdrive or
rotary table to rotate
the drillstring. Rotating is typically used when drilling is to occur along a
straight path.
However, directional drilling can also be accomplished with rotary steerable
drilling, as
described hereinbelow. Sliding, also called steering, uses a downhole mud
motor with an
adjustable bent housing and does not rotate the drillstring. Instead, sliding
uses hydraulic
power to drive the downhole motor and bit. Sliding is used in order to control
well direction.
[00401 To accomplish a slide, the rotation of the drill string is
stopped. Based on
feedback from measuring equipment such as a MWD tool, adjustments are made to
the drill
string. These adjustments continue until the downhole toolface that indicates
the direction of
the bend of the motor is oriented to the direction of the desired deviation of
the borehole.
Once the desired orientation is accomplished, pressure is applied to the drill
bit, which causes
the drill bit to move in the direction of deviation. Once sufficient distance
and angle have
been built, a transition back to rotating mode is accomplished by rotating the
drill string.
This rotation of the drill string neutralizes the directional deviation caused
by the bend in the
motor as it continuously rotates around the centerline of the borehole.
[00411 Referring again to Fig. 1A, the formulation of a drilling plan for
the drilling rig
110 may include processing and analyzing the collected data in the database
128 to create a
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more effective drilling plan. Furthermore, once the drilling has begun, the
collected data may
be used in conjunction with current data from the drilling rig 110 to improve
drilling
decisions. Accordingly, an on-site controller 144 is coupled to the drilling
rig 110 and may
also be coupled to the database 128 via one or more wired and/or wireless
communication
channel(s) 146. Other inputs 148 may also be provided to the on-site
controller 144. In some
embodiments, the on-site controller 144 may operate as a stand-alone device
with the drilling
rig 110. For example, the on-site controller 144 may not be communicatively
coupled to the
database 128. Although shown as being positioned near or at the drilling rig
110 in the
present example, it is understood that some or all components of the on-site
controller 144
may be distributed and located elsewhere in other embodiments.
[00421 The on-site controller 144 may form all or part of a surface
steerable system. The
database 128 may also form part of the surface steerable system. As will be
described in
greater detail below, the surface steerable system may be used to plan and
control drilling
operations based on input information, including feedback from the drilling
process itself.
The surface steerable system may be used to perform such operations as
receiving drilling
data representing a drill path and other drilling parameters, calculating a
drilling solution for
the drill path based on the received data and other available data (e.g., rig
characteristics),
implementing the drilling solution at the drilling rig 110, monitoring the
drilling process to
gauge whether the drilling process is within a defined margin of error of the
drill path, and/or
calculating corrections for the drilling process if the drilling process is
outside of the margin
of error.
[0043] Referring to Fig. 2A, a diagram 200 illustrates one embodiment of
information
flow for a surface steerable system 201 from the perspective of the on-site
controller 144 of
Fig. 1A. The surface steerable system 201 may be used in directional drilling
operations
employing either rotary steerable drilling or slide drilling. In the present
example, the drilling
rig 110 of Fig. lA includes drilling equipment 216 used to perform the
drilling of a borehole,
such as top drive or rotary drive equipment that couples to the drill string
and BHA and is
configured to rotate the drill string and apply pressure to the drill bit. The
drilling rig 110
may include control systems such as a WOB/differential pressure control system
208, a
positional/rotary control system 210, and a fluid circulation control system
212. The control
systems 208, 210, and 212 may be used to monitor and change drilling rig
settings, such as
CA 3031827 2019-01-28
the WOB and/or differential pressure to alter the ROP or the radial
orientation of the toolface,
change the flow rate of drilling mud, and perform other operations.
100441 The drilling rig 110 may also include a sensor system 214 for
obtaining sensor
data about the drilling operation and the drilling rig 110, including the
downhole equipment.
For example, the sensor system 214 may include measuring while drilling (MWD)
and/or
logging while drilling (LWD) components for obtaining information, such as
toolface and/or
formation logging information, that may be saved for later retrieval,
transmitted with a delay
or in real time using any of various communication means (e.g., wireless,
wireline, or mud
pulse telemetry), or otherwise transferred to the on-site controller 144. Such
information may
include information related to hole depth, bit depth, inclination, azimuth,
true vertical depth,
gamma count, standpipe pressure, mud flow rate, rotary rotations per minute
(RPM), bit
speed, ROP, WOB, and/or other information. It is understood that all or part
of the sensor
system 214 may be incorporated into one or more of the control systems 208,
210, and 212,
and/or in the drilling equipment 216. As the drilling rig 110 may be
configured in many
different ways, it is understood that these control systems may be different
in some
embodiments, and may be combined or further divided into various subsystems.
[0045] The on-site controller 144 receives input information 202. The
input information
202 may include information that is pre-loaded, received, and/or updated in
real time. The
input information 202 may include a well plan, regional formation history, one
or more
drilling engineer parameters, MWD tool face/inclination information, LWD
gamma/resistivity information, economic parameters, reliability parameters,
and/or other
decision guiding parameters. Some of the inputs, such as the regional
formation history, may
be available from a drilling hub 216, which may include the database 128 of
Fig. IA and one
or more processors (not shown), while other inputs may be accessed or uploaded
from other
sources. For example, a web interface may be used to interact directly with
the on-site
controller 144 to upload the well plan and/or drilling engineer parameters.
The input
information 202 feeds into the on-site controller 144 and, after processing by
the on-site
controller 144, results in control information 204 that is output to the
drilling rig 110 (e.g., to
the control systems 208, 210, and 212). The drilling rig 110 (e.g., via the
systems 208, 210,
212, and 214) provides feedback information 206 to the on-site controller 144.
The feedback
information 206 then serves as input to the on-site controller 144, enabling
the on-site
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controller 144 to verify that the current control information is producing the
desired results or
to produce new control information for the drilling rig 110.
[00461 The on-site controller 144 also provides output information 203.
As will be
described later in greater detail, the output information 203 may be stored in
the on-site
controller 144 and/or sent offsite (e.g., to the database 128). The output
information 203 may
be used to provide updates to the database 128, as well as provide alerts,
request decisions,
and convey other data related to the drilling process.
[00471 Referring to Fig. 2B, one embodiment of a display 250 that may be
provided by
the on-site controller 144 is illustrated. The display 250 provides many
different types of
information applicable to rotary steerable drilling or slide drilling in an
easily accessible
format. For example, the display 250 may be a viewing screen (e.g., a monitor)
that is
coupled to or forms part of the on-site controller 144.
[0048] The display 250 provides visual indicators such as a hole depth
indicator 252, a bit
depth indicator 254, a GAMMA indicator 256, an inclination indicator 258, an
azimuth
indicator 260, and a TVD indicator 262. Other indicators may also be provided,
including a
ROP indicator 264, a mechanical specific energy (MSE) indicator 266, a
differential pressure
indicator 268, a standpipe pressure indicator 270, a flow rate indicator 272,
a rotary RPM
indicator 274, a bit speed indicator 276, and a WOB indicator 278.
100491 Some or all of the indicators 264, 266, 268, 270, 272, 274, 276,
and/or 278 may
include a marker representing a target value. For putposes of example, markers
are set as the
following values, but it is understood that any desired target value may be
representing. For
example, the ROP indicator 264 may include a marker 265 indicating that the
target value is
fifty ft/hr. The MSE indicator 266 may include a marker 267 indicating that
the target value
is thirty-seven lcsi. The differential pressure indicator 268 may include a
marker 269
indicating that the target value is two hundred psi. The ROP indicator 264 may
include a
marker 265 indicating that the target value is fifty ft/hr. The standpipe
pressure indicator 270
may have no marker in the present example. The flow rate indicator 272 may
include a
marker 273 indicating that the target value is five hundred gpm. The rotary
RPM indicator
274 may include a marker 275 indicating that the target value is zero RPM (due
to sliding).
The bit speed indicator 276 may include a marker 277 indicating that the
target value is one
12
CA 3031827 2019-01-28
, =
hundred and fifty RPM. The WOB indicator 278 may include a marker 279
indicating that
the target value is ten klbs. Although only labeled with respect to the
indicator 264, each
indicator may include a colored band 263 or another marking to indicate, for
example,
whether the respective gauge value is within a safe range (e.g., indicated by
a green color),
within a caution range (e.g., indicated by a yellow color), or within a danger
range (e.g.,
indicated by a red color). Although not shown, in some embodiments, multiple
markers may
be present on a single indicator. The markers may vary in color and/or size.
100501 A log chart 280 may visually indicate depth versus one or more
measurements
(e.g., may represent log inputs relative to a progressing depth chart). For
example, the log
chart 280 may have a y-axis representing depth and an x-axis representing a
measurement
such as GAMMA count 281 (as shown), ROP 283 (e.g., empirical ROP and
normalized
ROP), or resistivity. An autopilot button 282 and an oscillate button 284 may
be used to
control activity. For example, the autopilot button 282 may be used to engage
or disengage
an autopilot, while the oscillate button 284 may be used to directly control
oscillation of the
drill string or engage/disengage an external hardware device or controller via
software and/or
hardware.
[00511 A circular chart 286 may provide current and historical toolface
orientation
information (e.g., which way the bend is pointed). For purposes of
illustration, the circular
chart 286 represents three hundred and sixty degrees. A series of circles
within the circular
chart 286 may represent a timeline of toolface orientations, with the sizes of
the circles
indicating the temporal position of each circle. For example, larger circles
may be more
recent than smaller circles, so the largest circle 288 may be the newest
reading and the
smallest circle 289 may be the oldest reading. In other embodiments, the
circles may
represent the energy and/or progress made via size, color, shape, a number
within a circle,
etc. For example, the size of a particular circle may represent an
accumulation of orientation
and progress for the period of time represented by the circle. In other
embodiments,
concentric circles representing time (e.g., with the outside of the circular
chart 286 being the
most recent time and the center point being the oldest time) may be used to
indicate the
energy and/or progress (e.g., via color and/or patterning such as dashes or
dots rather than a
solid line).
13
CA 3031827 2019-01-28
100521 The circular chart 286 may also be color coded, with the color
coding existing in a
band 290 around the circular chart 286 or positioned or represented in other
ways. The color
coding may use colors to indicate activity in a certain direction. For
example, the color red
may indicate the highest level of activity, while the color blue may indicate
the lowest level
of activity. Furthermore, the arc range in degrees of a color may indicate the
amount of
deviation. Accordingly, a relatively narrow (e.g., thirty degrees) arc of red
with a relatively
broad (e.g., three hundred degrees) arc of blue may indicate that most
activity is occurring in
a particular toolface orientation with little deviation. For purposes of
illustration, the color
blue extends from approximately 22-337 degrees, the color green extends from
approximately 15-22 degrees and 337-345 degrees, the color yellow extends a
few degrees
around the 13 and 345 degree marks, and the color red extends from
approximately 347-10
degrees. Transition colors or shades may be used with, for example, the color
orange
marking the transition between red and yellow and/or a light blue marking the
transition
between blue and green.
[0053] This color coding enables the display 250 to provide an intuitive
summary of how
narrow the standard deviation is and how much of the energy intensity is being
expended in
the proper direction. Furthermore, the center of energy may be viewed relative
to the target.
For example, the display 250 may clearly show that the target is at ninety
degrees but the
center of energy is at forty-five degrees.
[0054] Other indicators may be present, such as a slide indicator 292 to
indicate how
much time remains until a slide occurs and/or how much time remains for a
current slide. For
example, the slide indicator may represent a time, a percentage (e.g., current
slide is fifty-six
percent complete), a distance completed, and/or a distance remaining. The
slide indicator
292 may graphically display information using, for example, a colored bar 293
that increases
or decreases with the slide's progress. In some embodiments, the slide
indicator may be built
into the circular chart 286 (e.g., around the outer edge with an
increasing/decreasing band),
while in other embodiments the slide indicator may be a separate indicator
such as a meter, a
bar, a gauge, or another indicator type.
[00551 In another embodiment, the slide indicator 292 is not an indicator
that slide
drilling is being utilized to accomplish the directional drilling operation.
Rather, the drilling
rig might be set up to undertake directional drilling operations employing
rotary steerable
14
CA 3031827 2019-01-28
drilling. In such an embodiment, the slide indicator 292 would still function
in a similar
manner, i.e., to detail the time remaining until a directional change occurs
and/or how much
time remains for a direction currently being drilled. The slide indicator 292
could also
indicate a vector direction for the drilling direction change and a force
vector indicating the
amount of force to be applied in the vector direction. Thus, the slide
indicator 292 may
represent a time, a percentage, a distance completed, and/or distance
remaining for a
particular drilling direction. For example, if the slide indicator 292
displays a percentage,
and the percentage is intended in the particular embodiment to display the
percent complete
for the current drilling direction, once the percentage reaches 100% there may
then occur a
directional change performed by the rotary steerable system wherein the
direction of the
current drilling operation is altered according to methods specific to rotary
steerable drilling
operations, as described hereinbelow. Additionally, the slide indicator 292
may display a
different tag for the parameter other than that of "slide" as shown in FIG.
2B, such as
"directional" or other tags.
[00561 An error indicator 294 may be present to indicate a magnitude and/or
a direction
of error. For example, the error indicator 294 may indicate that the estimated
drill bit
position is a certain distance from the planned path, with a location of the
error indicator 294
around the circular chart 286 representing the heading. For example, Fig. 2B
illustrates an
error magnitude of fifteen feet and an error direction of fifteen degrees. The
error indicator
294 may be any color but is red for purposes of example. It is understood that
the error
indicator 294 may present a zero if there is no error and/or may represent
that the bit is on the
path in other ways, such as being a green color. Transition colors, such as
yellow, may be
used to indicate varying amounts of error. In some embodiments, the error
indicator 294 may
not appear unless there is an error in magnitude and/or direction. A marker
296 may indicate
an ideal slide direction. Although not shown, other indicators may be present,
such as a bit
life indicator to indicate an estimated lifetime for the current bit based on
a value such as time
and/or distance.
[0057] It is
understood that the display 250 may be arranged in many different ways. For
example, colors may be used to indicate normal operation, warnings, and
problems. In such
cases, the numerical indicators may display numbers in one color (e.g., green)
for normal
operation, may use another color (e.g., yellow) for warnings, and may use yet
another color
(e.g., red) if a serious problem occurs. The indicators may also flash or
otherwise indicate an
CA 3031827 2019-01-28
(-
alert. The gauge indicators may include colors (e.g., green, yellow, and red)
to indicate
operational conditions and may also indicate the target value (e.g., an ROP of
100 ft/hr). For
example, the ROP indicator 264 may have a green bar to indicate a normal level
of operation
(e.g., from 10-300 ft/hr), a yellow bar to indicate a warning level of
operation (e.g., from 300-
360 ft/hr), and a red bar to indicate a dangerous or otherwise out of
parameter level of
operation (e.g., from 360-390 ft/hr). The ROP indicator 264 may also display a
marker at
100 ft/hr to indicate the desired target ROP.
[0058] Furthermore, the use of numeric indicators, gauges, and similar
visual display
indicators may be varied based on factors such as the information to be
conveyed and the
personal preference of the viewer. Accordingly, the display 250 may provide a
customizable
view of various drilling processes and information for a particular individual
involved in the
drilling process. For example, the surface steerable system 201 may enable a
user to
customize the display 250 as desired, although certain features (e.g.,
standpipe pressure) may
be locked to prevent removal. This locking may prevent a user from
intentionally or
accidentally removing important drilling information from the display. Other
features may
be set by preference. Accordingly, the level of customization and the
information shown by
the display 250 may be controlled based on who is viewing the display and
their role in the
drilling process.
[0059] Referring again to Fig. 2A, it is understood that the level of
integration between
the on-site controller 144 and the drilling rig 110 may depend on such factors
as the
configuration of the drilling rig 110 and whether the on-site controller 144
is able to fully
support that configuration. One or more of the control systems 208, 210, and
212 may be
part of the on-site controller 144, may be third-party systems, and/or may be
part of the
drilling rig 110. For example, an older drilling rig 110 may have relatively
few interfaces
with which the on-site controller 144 is able to interact. For purposes of
illustration, if a knob
must be physically turned to adjust the WOB on the drilling rig 110, the on-
site controller
144 will not be able to directly manipulate the knob without a mechanical
actuator. If such
an actuator is not present, the on-site controller 144 may output the setting
for the knob to a
screen, and an operator may then turn the knob based on the setting.
Alternatively, the on-
site controller 144 may be directly coupled to the knob's electrical wiring.
16
CA 3031827 2019-01-28
(
,
100601 However, a newer or more sophisticated drilling rig 110, such
as a rig that has
electronic control systems, may have interfaces with which the on-site
controller 144 can
interact for direct control For example, an electronic control system may have
a defined
interface and the on-site controller 144 may be configured to interact with
that defined
interface. It is understood that, in some embodiments, direct control may not
be allowed even
if possible. For example, the on-site controller 144 may be configured to
display the setting
on a screen for approval, and may then send the setting to the appropriate
control system only
when the setting has been approved.
100611 Referring to Fig. 3, one embodiment of an environment 300
illustrates multiple
communication channels (indicated by arrows) that are commonly used in
existing directional
drilling operations that do not have the benefit of the surface steerable
system 201 of Fig. 2A.
The communication channels couple various individuals involved in the drilling
process. The
communication channels may support telephone calls, emails, text messages,
faxes, data
transfers (e.g., file transfers over networks), and other types of
communications.
[00621 The individuals involved in the drilling process may include a
drilling engineer
302, a geologist 304, a directional driller 306, a tool pusher 308, a driller
310, and a rig floor
crew 312. One or more company representatives (e.g., company men) 314 may also
be
involved. The individuals may be employed by different organizations, which
can further
complicate the communication process. For example, the drilling engineer 302,
geologist
304, and company man 314 may work for an operator, the directional driller 306
may work
for a directional drilling service provider, and the tool pusher 308, driller
310, and rig floor
crew 312 may work for a rig service provider.
[00631 The drilling engineer 302 and geologist 304 are often located at
a location remote
from the drilling rig (e.g., in a home office/drilling hub). The drilling
engineer 302 may
develop a well plan 318 and may make drilling decisions based on drilling rig
information.
The geologist 304 may perform such tasks as formation analysis based on
seismic, gamma,
and other data. The directional driller 306 is generally located at the
drilling rig and provides
instructions to the driller 310 based on the current well plan and feedback
from the drilling
engineer 302. The driller 310 handles the actual drilling operations and may
rely on the rig
floor crew 312 for certain tasks. The tool pusher 308 may be in charge of
managing the
entire drilling rig and its operation.
17
,
CA 3031827 2019-01-28
[00641 The following is one possible example of a communication process
within the
environment 300, although it is understood that many communication processes
may be used.
The use of a particular communication process may depend on such factors as
the level of
control maintained by various groups within the process, how strictly
communication
channels are enforced, and similar factors. In the present example, the
directional driller 306
uses the well plan 318 to provide drilling instructions to the driller 310.
The driller 310
controls the drilling using control systems such as the control systems 208,
210, and 212 of
Fig. 2A. During drilling, information from sensor equipment such as downhole
MWD
equipment 316 and/or rig sensors 320 may indicate that a formation layer has
been reached
twenty feet higher than expected by the geologist 304. This information is
passed back to the
drilling engineer 302 and/or geologist 304 through the company man 314, and
may pass
through the directional driller 306 before reaching the company man 314.
100651 The drilling engineer 302/well planner (not shown), either alone
or in conjunction
with the geologist 306, may modify the well plan 318 or make other decisions
based on the
received information. The modified well plan and/or other decisions may or may
not be
passed through the company man 314 to the directional driller 306, who then
tells the driller
310 how to drill. The driller 310 may modify equipment settings (e.g.,
toolface orientation)
and, if needed, pass orders on to the rig floor crew 312. For example, a
change in WOB may
be performed by the driller 310 changing a setting, while a bit trip may
require the
involvement of the rig floor crew 312. Accordingly, the level of involvement
of different
individuals may vary depending on the nature of the decision to be made and
the task to be
performed. The proceeding example may be more complex than described. Multiple
intermediate individuals may be involved and, depending on the communication
chain, some
instructions may be passed through the tool pusher 308.
[00661 The environment 300 presents many opportunities for communication
breakdowns
as information is passed through the various communication channels,
particularly given the
varying types of communication that may be used. For example, verbal
communications via
phone may be misunderstood and, unless recorded, provide no record of what was
said.
Furthermore, accountability may be difficult or impossible to enforce as
someone may
provide an authorization but deny it or claim that they meant something else.
Without a
record of the information passing through the various channels and the
authorizations used to
approve changes in the drilling process, communication breakdowns can be
difficult to trace
18
CA 3031827 2019-01-28
and address. As many of the communication channels illustrated in Fig. 3 pass
information
through an individual to other individuals (e.g., an individual may serve as
an information
conduit between two or more other individuals), the risk of breakdown
increases due to the
possibility that errors may be introduced in the information.
[0067] Even if everyone involved does their part, drilling mistakes may be
amplified
while waiting for an answer. For example, a message may be sent to the
geologist 306 that a
formation layer seems to be higher than expected, but the geologist 306 may be
asleep.
Drilling may continue while waiting for the geologist 306 and the continued
drilling may
amplify the error. Such errors can cost hundreds of thousands or millions of
dollars.
However, the environment 300 provides no way to determine if the geologist 304
has
received the message and no way to easily notify the geologist 304 or to
contact someone else
when there is no response within a defined period of time. Even if alternate
contacts are
available, such communications may be cumbersome and there may be difficulty
in providing
all the information that the alternate would need for a decision.
[0068] Referring to Fig.
4, one embodiment of an environment 400 illustrates
communication channels that may exist in a directional drilling operation
having the benefit
of the surface steerable system 201 of Fig. 2A. In the present example, the
surface steerable
system 201 includes the drilling hub 216, which includes the regional database
128 of Fig.
IA and processing unit(s) 404 (e.g., computers). The drilling hub 216 also
includes
communication interfaces (e.g., web portals) 406 that may be accessed by
computing devices
capable of wireless and/or wireline communications, including desktop
computers, laptops,
tablets, smart phones, and personal digital assistants (PDAs). The on-site
controller 144
includes one or more local databases 410 (where "local" is from the
perspective of the on-site
controller 144) and processing unit(s) 412.
[0069] The drilling
hub 216 is remote from the on-site controller 144, and various
individuals associated with the drilling operation interact either through the
drilling hub 216
or through the on-site controller 144. In some embodiments, an individual may
access the
drilling project through both the drilling hub 216 and on-site controller 144.
For example, the
directional driller 306 may use the drilling hub 216 when not at the drilling
site and may use
the on-site controller 144 when at the drilling site.
19
CA 3031827 2019-01-28
[0070] The drilling engineer 302 and geologist 304 may access the surface
steerable
system 201 remotely via the portal 406 and set various parameters such as rig
limit controls.
Other actions may also be supported, such as granting approval to a request by
the directional
driller 306 to deviate from the well plan and evaluating the performance of
the drilling
operation. The directional driller 306 may be located either at the drilling
rig 110 or off-site.
Being off-site (e.g., at the drilling hub 216 or elsewhere) enables a single
directional driller to
monitor multiple drilling rigs. When off-site, the directional driller 306 may
access the
surface steerable system 201 via the portal 406. When on-site, the directional
driller 306 may
access the surface steerable system via the on-site controller 144.
[0071) The driller 310 may get instructions via the on-site controller 144,
thereby
lessening the possibly of miscommunication and ensuring that the instructions
were received.
Although the tool pusher 308, rig floor crew 312, and company man 314 are
shown
communicating via the driller 310, it is understood that they may also have
access to the on-
site controller 144. Other individuals, such as a MWD hand 408, may access the
surface
steerable system 201 via the drilling hub 216, the on-site controller 144,
and/or an individual
such as the driller 310.
[00721 As illustrated in Fig. 4, many of the individuals involved in a
drilling operation
may interact through the surface steerable system 201. This enables
information to be
tracked as it is handled by the various individuals involved in a particular
decision. For
example, the surface steerable system 201 may track which individual submitted
information
(or whether information was submitted automatically), who viewed the
information, who
made decisions, when such events occurred, and similar information-based
issues. This
provides a complete record of how particular information propagated through
the surface
steerable system 201 and resulted in a particular drilling decision. This also
provides revision
tracking as changes in the well plan occur, which in turn enables entire
decision chains to be
reviewed. Such reviews may lead to improved decision making processes and more
efficient
responses to problems as they occur.
100731 In some embodiments, documentation produced using the surface
steerable system
201 may be synchronized and/or merged with other documentation, such as that
produced by
third party systems such as the WellView product produced by Peloton Computer
Enterprises
Ltd. of Calgary, Canada. In such embodiments, the documents, database files,
and other
CA 3031827 2019-01-28
information produced by the surface steerable system 201 is synchronized to
avoid such
issues as redundancy, mismatched file versions, and other complications that
may occur in
projects where large numbers of documents are produced, edited, and
transmitted by a
relatively large number of people.
[00741 The surface steerable system 201 may also impose mandatory
information formats
and other constraints to ensure that predefined criteria are met. For example,
an electronic
form provided by the surface steerable system 201 in response to a request for
authorization
may require that some fields are filled out prior to submission. This ensures
that the decision
maker has the relevant information prior to making the decision. If the
information for a
required field is not available, the surface steerable system 201 may require
an explanation to
be entered for why the information is not available (e.g., sensor failure).
Accordingly, a level
of uniformity may be imposed by the surface steerable system 201, while
exceptions may be
defined to enable the surface steerable system 201 to handle various
scenarios.
[00751 The surface steerable system 201 may also send alerts (e.g., email
or text alerts) to
notify one or more individuals of a particular problem, and the recipient list
may be
customized based on the problem. Furthermore, contact information may be time-
based, so
the surface steerable system 201 may know when a particular individual is
available. In such
situations, the surface steerable system 201 may automatically attempt to
communicate with
an available contact rather than waiting for a response from a contact that is
likely not
available.
[0076] As described previously, the surface steerable system 201 may
present a
customizable display of various drilling processes and information for a
particular individual
involved in the drilling process. For example, the drilling engineer 302 may
see a display
that presents information relevant to the drilling engineer's tasks, and the
geologist 304 may
see a different display that includes additional and/or more detailed
formation information.
This customization enables each individual to receive information needed for
their particular
role in the drilling process while minimizing or eliminating unnecessary
information.
[0077] Referring to Fig. 5, one embodiment of an environment 500
illustrates data flow
that may be supported by the surface steerable system 201 of Fig. 2A. The data
flow 500
begins at block 502 and may move through two branches, although some blocks in
a branch
21
CA 3031827 2019-01-28
may not occur before other blocks in the other branch. One branch involves the
drilling hub
216 and the other branch involves the on-site controller 144 at the drilling
rig 110.
[0078] In block 504, a geological survey is performed. The survey
results are reviewed
by the geologist 304 and a formation report 506 is produced. The formation
report 506
details formation layers, rock type, layer thickness, layer depth, and similar
information that
may be used to develop a well plan. In block 508, a well plan is developed by
a well planner
524 and/or the drilling engineer 302 based on the formation report and
information from the
regional database 128 at the drilling hub 216. Block 508 may include selection
of a BHA and
the setting of control limits. The well plan is stored in the database 128.
The drilling
engineer 302 may also set drilling operation parameters in step 510 that are
also stored in the
database 128.
[0079] In the other branch, the drilling rig 110 is constructed in block
512. At this point,
as illustrated by block 526, the well plan, BHA information, control limits,
historical drilling
data, and control commands may be sent from the database 128 to the local
database 410.
Using the receiving information, the directional driller 306 inputs actual BHA
parameters in
block 514. The company man 314 and/or the directional driller 306 may verify
performance
control limits in block 516, and the control limits are stored in the local
database 410 of the
on-site controller 144. The performance control limits may include multiple
levels such as a
warning level and a critical level corresponding to no action taken within
feet/minutes.
[0080] Once drilling begins, a diagnostic logger (described later in
greater detail) 520 that
is part of the on-site controller 144 logs information related to the drilling
such as sensor
information and maneuvers and stores the information in the local database 410
in block 526.
The information is sent to the database 128. Alerts are also sent from the on-
site controller
144 to the drilling hub 216. When an alert is received by the drilling hub
216, an alert
notification 522 is sent to defined individuals, such as the drilling engineer
302, geologist
304, and company man 314. The actual recipient may vary based on the content
of the alert
message or other criteria. The alert notification 522 may result in the well
plan and the BHA
information and control limits being modified in block 508 and parameters
being modified in
block 510. These modifications are saved to the database 128 and transferred
to the local
database 410. The BHA may be modified by the directional driller 306 in block
518, and the
changes propagated through blocks 514 and 516 with possible updated control
limits.
22
CA 3031827 2019-01-28
Accordingly, the surface steerable system 201 may provide a more controlled
flow of
information than may occur in an environment without such a system.
[0081] The flow charts described herein illustrate various exemplary
functions and
operations that may occur within various environments. Accordingly, these flow
charts are
not exhaustive and that various steps may be excluded to clarify the aspect
being described.
For example, it is understood that some actions, such as network
authentication processes,
notifications, and handshakes, may have been performed prior to the first step
of a flow chart.
Such actions may depend on the particular type and configuration of
communications
engaged in by the on-site controller 144 and/or drilling hub 216. Furthermore,
other
communication actions may occur between illustrated steps or simultaneously
with illustrated
steps.
[0082] The surface steerable system 201 includes large amounts of data
specifically
related to various drilling operations as stored in databases such as the
databases 128 and 410.
As described with respect to Fig. 1A, this data may include data collected
from many
different locations and may correspond to many different drilling operations.
The data stored
in the database 128 and other databases may be used for a variety of purposes,
including data
mining and analytics, which may aid in such processes as equipment
comparisons, drilling
plan formulation, convergence planning, recalibration forecasting, and self-
tuning (e.g.,
drilling performance optimization). Some processes, such as equipment
comparisons, may
not be performed in real time using incoming data, while others, such as self-
tuning, may be
performed in real time or near real time. Accordingly, some processes may be
executed at
the drilling hub 216, other processes may be executed at the on-site
controller 144, and still
other processes may be executed by both the drilling hub 216 and the on-site
controller 144
with communications occurring before, during, and/or after the processes are
executed. As
described below in various examples, some processes may be triggered by events
(e.g.,
recalibration forecasting) while others may be ongoing (e.g., self-tuning).
[0083] For example, in equipment comparison, data from different drilling
operations
(e.g., from drilling the wells 102, 104, 106, and 108) may be normalized and
used to compare
equipment wear, performance, and similar factors. For example, the same bit
may have been
used to drill the wells 102 and 106, but the drilling may have been
accomplished using
different parameters (e.g., rotation speed and WOB). By normalizing the data,
the two bits
23
CA 3031827 2019-01-28
can be compared more effectively. The normalized data may be further processed
to improve
drilling efficiency by identifying which bits are most effective for
particular rock layers,
which drilling parameters resulted in the best ROP for a particular formation,
ROP versus
reliability tradeoffs for various bits in various rock layers, and similar
factors. Such
.. comparisons may be used to select a bit for another drilling operation
based on formation
characteristics or other criteria. Accordingly, by mining and analyzing the
data available via
the surface steemble system 201, an optimal equipment profile may be developed
for
different drilling operations. The equipment profile may then be used when
planning future
wells or to increase the efficiency of a well currently being drilled. This
type of drilling
optimization may become increasingly accurate as more data is compiled and
analyzed.
[0084] In drilling plan formulation, the data available via the surface
steerable system
201 may be used to identify likely formation characteristics and to select an
appropriate
equipment profile. For example, the geologist 304 may use local data obtained
from the
planned location of the drilling rig 110 in conjunction with regional data
from the database
128 to identify likely locations of the layers 168A-176A (Fig. 1B). Based on
that
information, the drilling engineer 302 can create a well plan that will
include the build curve
of Fig. IC,
[0085] Referring to Fig. 6, a method 600 illustrates one embodiment of an
event-based
process that may be executed by the on-site controller 144 of Fig. 2A. For
example, software
instructions needed to execute the method 600 may be stored on a computer
readable storage
medium of the on-site controller 144 and then executed by the processor 412
that is coupled
to the storage medium and is also part of the on-site controller 144.
[0086] In step 602, the on-site controller 144 receives inputs, such as a
planned path for a
borehole, formation information for the borehole, equipment information for
the drilling rig,
and a set of cost parameters. The cost parameters may be used to guide
decisions made by
the on-site controller 144 as will be explained in greater detail below. The
inputs may be
received in many different ways, including receiving document (e.g.,
spreadsheet) uploads,
accessing a database (e.g., the database 128 of Fig. 1A), and/or receiving
manually entered
data.
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CA 3031827 2019-01-28
[0087] In step 604, the planned path, the formation information, the
equipment
information, and the set of cost parameters are processed to produce control
parameters (e.g.,
the control information 204 of Fig. 2A) for the drilling rig 110. The control
parameters may
define the settings for various drilling operations that are to be executed by
the drilling rig
110 to form the borehole, such as WOB, flow rate of mud, toolface orientation,
and similar
settings. In some embodiments, the control parameters may also define
particular equipment
selections, such as a particular bit. In the present example, step 604 is
directed to defining
initial control parameters for the drilling rig 110 prior to the beginning of
drilling, but it is
understood that step 604 may be used to define control parameters for the
drilling rig 110
even after drilling has begun. For example, the on-site controller 144 may be
put in place
prior to drilling or may be put in place after drilling has commenced, in
which case the
method 600 may also receive current borehole information in step 602.
[00881 In step 606, the control parameters are output for use by the
drilling rig 110. In
embodiments where the on-site controller 144 is directly coupled to the
drilling rig 110,
outputting the control parameters may include sending the control parameters
directly to one
or more of the control systems of the drilling rig 110 (e.g., the control
systems 210, 212, and
214). In other embodiments, outputting the control parameters may include
displaying the
control parameters on a screen, printing the control parameters, and/or
copying them to a
storage medium (e.g., a Universal Serial Bus (USB) drive) to be transferred
manually.
[00891 In step 608, feedback
information received from the drilling rig 110 (e.g., from
one or more of the control systems 210, 212, and 214 and/or sensor system 216)
is processed.
The feedback information may provide the on-site controller 144 with the
current state of the
borehole (e.g., depth and inclination), the drilling rig equipment, and the
drilling process,
including an estimated position of the bit in the borehole. The processing may
include
extracting desired data from the feedback information, normalizing the data,
comparing the
data to desired or ideal parameters, determining whether the data is within a
defined margin
of error, and/or any other processing steps needed to make use of the feedback
information.
[0090i In step 610, the on-
site controller 144 may take action based on the occurrence of
one or more defined events. For example, an event may trigger a decision on
how to proceed
with drilling in the most cost effective manner. Events may be triggered by
equipment
malfunctions, path differences between the measured borehole and the planned
borehole,
CA 3031827 2019-01-28
1/-
upcoming maintenance periods, unexpected geological readings, and any other
activity or
non-activity that may affect drilling the borehole. It is understood that
events may also be
defined for occurrences that have a less direct impact on drilling, such as
actual or predicted
labor shortages, actual or potential licensing issues for mineral rights,
actual or predicted
political issues that may impact drilling, and similar actual or predicted
occurrences. Step
610 may also result in no action being taken if, for example, drilling is
occurring without any
issues and the current control parameters are satisfactory.
[0091] An event may be defined in the received inputs of step 602 or
defined later.
Events may also be defined on site using the on-site controller 144. For
example, if the
drilling rig 110 has a particular mechanical issue, one or more events may be
defined to
monitor that issue in more detail than might ordinarily occur. In some
embodiments, an
event chain may be implemented where the occurrence of one event triggers the
monitoring
of another related event. For example, a first event may trigger a
notification about a
potential problem with a piece of equipment and may also activate monitoring
of a second
event. In addition to activating the monitoring of the second event, the
triggering of the first
event may result in the activation of additional oversight that involves, for
example, checking
the piece of equipment more frequently or at a higher level of detail. If the
second event
occurs, the equipment may be shut down and an alarm sounded, or other actions
may be
taken. This enables different levels of monitoring and different levels of
responses to be
assigned independently if needed.
[00921 Referring to Fig. 7A, a method 700 illustrates a more detailed
embodiment of the
method 600 of Fig. 6, particularly of step 610. As steps 702, 704, 706, and
708 are similar or
identical to steps 602, 604, 606, and 608, respectively, of Fig. 6, they are
not described in
detail in the present embodiment. In the present example, the action of step
610 of Fig. 6 is
based on whether an event has occurred and the action needed if the event has
occurred.
[0093) Accordingly, in step 710, a determination is made as to whether an
event has
occurred based on the inputs of steps 702 and 708. If no event has occurred,
the method 700
returns to step 708. If an event has occurred, the method 700 moves to step
712, where
calculations are performed based on the information relating to the event and
at least one cost
parameter. It is understood that additional information may be obtained and/or
processed
prior to or as part of step 712 if needed. For example, certain information
may be used to
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CA 3031827 2019-01-28
determine whether an event has occurred, and additional information may then
be retrieved
and processed to determine the particulars of the event.
[0094] In step 714, new control parameters may be produced based on the
calculations of
step 712. In step 716, a determination may be made as to whether changes are
needed in the
current control parameters. For example, the calculations of step 712 may
result in a decision
that the current control parameters are satisfactory (e.g., the event may not
affect the control
parameters). If no changes are needed, the method 700 returns to step 708. If
changes are
needed, the on-site controller 144 outputs the new parameters in step 718. The
method 700
may then return to step 708. In some embodiments, the determination of step
716 may occur
before step 714. In such embodiments, step 714 may not be executed if the
current control
parameters are satisfactory.
[0095] In a more detailed example of the method 700, assume that the on-
site controller
144 is involved in drilling a borehole and that approximately six hundred feet
remain to be
drilled. An event has been defined that warns the on-site controller 144 when
the drill bit is
predicted to reach a minimum level of efficiency due to wear and this event is
triggered in
step 710 at the six hundred foot mark. The event may be triggered because the
drill bit is
within a certain number of revolutions before reaching the minimum level of
efficiency,
within a certain distance remaining (based on strata type, thickness, etc.)
that can be drilled
before reaching the minimum level of efficiency, or may be based on some other
factor or
factors. Although the event of the current example is triggered prior to the
predicted
minimum level of efficiency being reached in order to proactively schedule
drilling changes
if needed, it is understood that the event may be triggered when the minimum
level is actually
reached.
100961 The on-site controller 144 may perform calculations in step 712
that account for
various factors that may be analyzed to determine how the last six hundred
feet is drilled.
These factors may include the rock type and thickness of the remaining six
hundred feet, the
predicted wear of the drill bit based on similar drilling conditions, location
of the bit (e.g.,
depth), how long it will take to change the bit, and a cost versus time
analysis. Generally,
faster drilling is more cost effective, but there are many tradeoffs. For
example, increasing
the WOB or differential pressure to increase the rate of penetration may
reduce the time it
takes to finish the borehole, but may also wear out the drill bit faster,
which will decrease the
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CA 3031827 2019-01-28
drilling effectiveness and slow the drilling down. If this slowdown occurs too
early, it may
be less efficient than drilling more slowly. Therefore, there is a tradeoff
that must be
calculated. Too much WOB or differential pressure may also cause other
problems, such as
damaging downhole tools. Should one of these problems occur, taking the time
to trip the bit
or drill a sidetrack may result in more total time to finish the borehole than
simply drilling
more slowly, so faster may not be better. The tradeoffs may be relatively
complex, with
many factors to be considered.
[00971 In step 714, the on-site controller 144 produces new control
parameters based on
the solution calculated in step 712. In step 716, a determination is made as
to whether the
current parameters should be replaced by the new parameters. For example, the
new
parameters may be compared to the current parameters. If the two sets of
parameters are
substantially similar (e.g., as calculated based on a percentage change or
margin of error of
the current path with a path that would be created using the new control
parameters) or
identical to the current parameters, no changes would be needed. However, if
the new
control parameters call for changes greater than the tolerated percentage
change or outside of
the margin of error, they are output in step 718. For example, the new control
parameters
may increase the WOB and also include the rate of mud flow significantly
enough to override
the previous control parameters. In other embodiments, the new control
parameters may be
output regardless of any differences, in which case step 716 may be omitted.
In still other
embodiments, the current path and the predicted path may be compared before
the new
parameters are produced, in which case step 714 may occur after step 716.
1[00981 Referring to Fig. 7B and with additional reference to Fig. 7C, a
method 720 (Fig.
7B) and diagram 740 (Fig. 7C) illustrate a more detailed embodiment of the
method 600 of
Fig. 6, particularly of step 610. As steps 722, 724, 726, and 728 are similar
or identical to
steps 602, 604, 606, and 608, respectively, of Fig. 6, they are not described
in detail in the
present embodiment. In the present example, the action of step 610 of Fig. 6
is based on
whether the drilling has deviated from the planned path.
[0099) In step 730, a comparison may be made to compare the estimated bit
position and
trajectory with a desired point (e.g., a desired bit position) along the
planned path. The
estimated bit position may be calculated based on information such as a survey
reference
point and/or represented as an output calculated by a borehole estimator (as
will be described
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CA 3031827 2019-01-28
later) and may include a bit projection path and/or point that represents a
predicted position
of the bit if it continues its current trajectory from the estimated bit
position. Such
information may be included in the inputs of step 722 and feedback information
of step 728
or may be obtained in other ways. It is understood that the estimated bit
position and
trajectory may not be calculated exactly, but may represent an estimate the
current location of
the drill bit based on the feedback information. As illustrated in Fig. 7C,
the estimated bit
position is indicated by arrow 743 relative to the desired bit position 741
along the planned
path 742.
[0100] In step 732, a determination may be made as to whether the
estimated bit position
743 is within a defined margin of error of the desired bit position. If the
estimated bit
position is within the margin of error, the method 720 returns to step 728. If
the estimated bit
position is not within the margin of error, the on-site controller 144
calculates a convergence
plan in step 734. With reference to Fig. 7C, for purposes of the present
example, the
estimated bit position 743 is outside of the margin of error.
[0100a] In some embodiments, a projected bit position (not shown) may also
be used. For
example, the estimated bit position 743 may be extended via calculations to
determine where
the bit is projected to be after a certain amount of drilling (e.g., time
and/or distance). This
information may be used in several ways. If the estimated bit position 743 is
outside the
margin of error, the projected bit position 743 may indicate that the current
bit path will bring
the bit within the margin of error without any action being taken. In such a
scenario, action
may be taken only if it will take too long to reach the projected bit position
when a more
optimal path is available. If the estimated bit position is inside the margin
of error, the
projected bit position may be used to determine if the current path is
directing the bit away
from the planned path. In other words, the projected bit position may be used
to proactively
detect that the bit is off course before the margin of error is reached. In
such a scenario,
action may be taken to correct the current path before the margin of error is
reached.
[0100b] The convergence plan identifies a plan by which the bit can be moved
from the
estimated bit position 743 to the planned path 742. It is noted that the
convergence plan may
bypass the desired bit position 741 entirely, as the objective is to get the
actual drilling path
back to the planned path 742 in the most optimal manner. The most optimal
manner may be
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CA 3031827 2019-01-28
defined by cost, which may represent a financial value, a reliability value, a
time value,
and/or other values that may be defined for a convergence path.
[0100c] As illustrated in Fig. 7C, an infinite number of paths may be selected
to return the
bit to the planned path 742. The paths may begin at the estimated bit position
743 or may
begin at other points along a projected path 752 that may be determined by
calculating future
bit positions based on the current trajectory of the bit from the estimated
bit position 752. In
the present example, a first path 744 results in locating the bit at a
position 745 (e.g., a
convergence point). The convergence point 745 is outside of a lower limit 753
defined by a
most aggressive possible correction (e.g., a lower limit on a window of
correction). This
.. correction represents the most aggressive possible convergence path, which
may be limited
by such factors as a maximum directional change possible in the convergence
path, where
any greater directional change creates a dogleg that makes it difficult or
impossible to run
casing or perform other needed tasks. A second path 746 results in a
convergence point 747,
which is right at the lower limit 753. A third path 748 results in a
convergence point 749,
which represents a mid-range convergence point. A third path 750 results in a
convergence
point 751, which occurs at an upper limit 754 defined by a maximum convergence
delay
(e.g., an upper limit on the window of correction).
[0101] A fourth path 756 may begin at a projected point or bit position
755 that lies along
the projected path 752 and result in a convergence point 757, which represents
a mid-range
convergence point. The path 756 may be used by, for example, delaying a
trajectory change
until the bit reaches the position 755. Many additional convergence options
may be opened
up by using projected points for the basis of convergence plans as well as the
estimated bit
position.
[0102] A fifth path 758 may begin at a projected point or bit position
760 that lies along
the projected path 750 and result in a convergence point 759. In such an
embodiment,
different convergence paths may include similar or identical path segments,
such as the
similar or identical path shared by the convergence points 751 and 759 to the
point 760. For
example, the point 760 may mark a position on the path 750 where a slide
segment begins (or
continues from a previous slide segment) for the path 758 and a straight line
path segment
begins (or continues) for the path 750. The surface steerable system 144 may
calculate the
paths 750 and 758 as two entirely separate paths or may calculate one of the
paths as
CA 3031827 2019-01-28
deviating from (e.g., being a child of) the other path. Accordingly, any path
may have
multiple paths deviating from that path based on, for example, different slide
points and slide
times.
101031 Each of these paths 744, 746, 748, 750, 756, and 758 may present
advantages and
disadvantages from a drilling standpoint. For example, one path may be longer
and may
require more sliding in a relatively soft rock layer, while another path may
be shorter but may
require more sliding through a much harder rock layer. Accordingly, tradeoffs
may be
evaluated when selecting one of the convergence plans rather than simply
selecting the most
direct path for convergence. The tradeoffs may, for example, consider a
balance between
ROP, total cost, dogleg severity, and reliability. While the number of
convergence plans may
vary, there may be hundreds or thousands of convergence plans in some
embodiments and
the tradeoffs may be used to select one of those hundreds or thousands for
implementation.
The convergence plans from which the final convergence plan is selected may
include plans
calculated from the estimated bit position 743 as well as plans calculated
from one or more
.. projected points along the projected path.
[0104] In some embodiments, straight line projections of the convergence
point vectors,
after correction to the well plan 742, may be evaluated to predict the time
and/or distance to
the next correction requirement. This evaluation may be used when selecting
the lowest total
cost option by avoiding multiple corrections where a single more forward
thinking option
might be optimal. As an example, one of the solutions provided by the
convergence planning
may result in the most cost effective path to return to the well plan 742, but
may result in an
almost immediate need for a second correction due to a pending deviation
within the well
plan. Accordingly, a convergence path that merges the pending deviation with
the correction
by selecting a convergence point beyond the pending deviation might be
selected when
considering total well costs.
[0105] It is understood that the diagram 740 of Fig. 7C is a two
dimensional
representation of a three dimensional environment. Accordingly, the
illustrated convergence
paths in the diagram 740 of Fig. 7C may be three dimensional. In addition,
although the
illustrated convergence paths all converge with the planned path 742, is it
understood that
some convergence paths may be calculated that move away from the planned path
742
(although such paths may be rejected). Still other convergence paths may
overshoot the
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CA 3031827 2019-01-28
=
actual path 742 and then converge (e.g., if there isn't enough room to build
the curve
otherwise). Accordingly, many different convergence path structures may be
calculated.
[01061 Referring again to Fig. 7B, in step 736, the on-site controller
144 produces revised
control parameters based on the convergence plan calculated in step 734. In
step 738, the
revised control parameters may be output. It is understood that the revised
control
parameters may be provided to get the drill bit back to the planned path 742
and the original
control parameters may then be used from that point on (starting at the
convergence point).
For example, if the convergence plan selected the path 748, the revised
control parameters
may be used until the bit reaches position 749. Once the bit reaches the
position 749, the
original control parameters may be used for further drilling. Alternatively,
the revised
control parameters may incorporate the original control parameters starting at
the position
749 or may re-calculate control parameters for the planned path even beyond
the point 749.
Accordingly, the convergence plan may result in control parameters from the
bit position 743
to the position 749, and further control parameters may be reused or
calculated depending on
the particular implementation of the on-site controller 144.
[01071 Referring to Fig. 8A, a method 800 illustrates a more detailed
embodiment of step
734 of Fig. 7B. It is understood that the convergence plan of step 734 may be
calculated in
many different ways, and that 800 method provides one possible approach to
such a
calculation when the goal is to find the lowest cost solution vector. In the
present example,
cost may include both the financial cost of a solution and the reliability
cost of a solution.
Other costs, such as time costs, may also be included. For purposes of
example, the diagram
740 of Fig. 7C is used.
[0108] In step 802, multiple solution vectors are calculated from the
current position 743
to the planned path 742. These solution vectors may include the paths 744,
746, 748, and
750. Additional paths (not shown in Fig. 7C) may also be calculated. The
number of
solution vectors that are calculated may vary depending on various factors.
For example, the
distance available to build a needed curve to get back to the planned path 742
may vary
depending on the current bit location and orientation relative to the planned
path. A greater
number of solution vectors may be available when there is a greater distance
in which to
build a curve than for a smaller distance since the smaller distance may
require a much more
aggressive build rate that excludes lesser build rates that may be used for
the greater distance.
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CA 3031827 2019-01-28
In other words, the earlier an error is caught, the more possible solution
vectors there will
generally be due to the greater distance over which the error can be
corrected. While the
number of solution vectors that are calculated in this step may vary, there
may be hundreds or
thousands of solution vectors calculated in some embodiments.
[0109] In step 804, any solution vectors that fall outside of defined
limits are rejected,
such as solution vectors that fall outside the lower limit 753 and the upper
limit 754. For
example, the path 744 would be rejected because the convergence point 745
falls outside of
the lower limit 753. It is understood that the path 744 may be rejected for an
engineering
reason (e.g., the path would require a dogleg of greater than allowed
severity) prior to cost
considerations, or the engineering reason may be considered a cost.
[01101 In step 806, a cost is calculated for each remaining solution
vector. As illustrated
in Fig. 7C, the costs may be represented as a cost matrix (that may or may not
be weighted)
with each solution vector having corresponding costs in the cost matrix. In
step 808, a
minimum of the solution vectors may be taken to identify the lowest cost
solution vector. It
is understood that the minimum cost is one way of selecting the desired
solution vector, and
that other ways may be used. Accordingly, step 808 is concerned with selecting
an optimal
solution vector based on a set of target parameters, which may include one or
more of a
fmancial cost, a time cost, a reliability cost, and/or any other factors, such
as an engineering
cost like dogleg severity, that may be used to narrow the set of solution
vectors to the optimal
solution vector.
[0111] By weighting
the costs, the cost matrix can be customized to handle many
different cost scenarios and desired results. For example, if time is of
primary importance, a
time cost may be weighted over financial and reliability costs to ensure that
a solution vector
that is faster will be selected over other solution vectors that are
substantially the same but
somewhat slower, even though the other solution vectors may be more beneficial
in terms of
financial cost and reliability cost. In some embodiments, step 804 may be
combined with
step 808 and solution vectors falling outside of the limits may be given a
cost that ensures
they will not be selected. In step 810, the solution vector corresponding to
the minimum cost
is selected.
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CA 3031827 2019-01-28
[0112] Referring to Fig. 8B, a method 820 illustrates one embodiment of
an event-based
process that may be executed by the on-site controller 144 of Fig. 2A. It is
understood that an
event may represent many different scenarios in the surface steerable system
201. In the
present example, in step 822, an event may occur that indicates that a
prediction is not correct
based on what has actually occurred. For example, a formation layer is not
where it is
expected (e.g., too high or low), a selected bit did not drill as expected, or
a selected mud
motor did not build curve as expected. The prediction error may be identified
by comparing
expected results with actual results or by using other detection methods.
[0113] In step 824, a reason for the error may be determined as the
surface steerable
system 201 and its data may provide an environment in which the prediction
error can be
evaluated. For example, if a bit did not drill as expected, the method 820 may
examine many
different factors, such as whether the rock formation was different than
expected, whether the
drilling parameters were correct, whether the drilling parameters were
correctly entered by
the driller, whether another error and/or failure occurred that caused the bit
to drill poorly,
and whether the bit simply failed to perform. By accessing and analyzing the
available data,
the reason for the failure may be determined.
[0114] In step 826, a solution may be determined for the error. For
example, if the rock
formation was different than expected, the database 128 may be updated with
the correct rock
information and new drilling parameters may be obtained for the drilling rig
110.
Alternatively, the current bit may be tripped and replaced with another bit
more suitable for
the rock. In step 828, the current drilling predictions (e.g., well plan,
build rate, slide
estimates) may be updated based on the solution and the solution may be stored
in the
database 128 for use in future predictions. Accordingly, the method 820 may
result in
benefits for future wells as well as improving current well predictions.
[0115] Referring to Fig. 8C, a method 830 illustrates one embodiment of an
event-based
process that may be executed by the on-site controller 144 of Fig. 2A. The
method 830 is
directed to recalibration forecasting that may be triggered by an event, such
as an event
detected in step 610 of Fig. 6. It is understood that the recalibration
described in this
embodiment may not be the same as calculating a convergence plan, although
calculating a
convergence plan may be part of the recalibration. As an example of a
recalibration
triggering event, a shift in ROP and/or GAMMA readings may indicate that a
formation layer
34
CA 3031827 2019-01-28
_
(e.g., the layer 170A of Fig. 1B) is actually twenty feet higher than planned.
This will likely
impact the well plan, as build rate predictions and other drilling parameters
may need to be
changed. Accordingly, in step 832, this event is identified.
[0116] In step
834, a forecast may be made as to the impact of the event. For example,
the surface steerable system 201 may determine whether the projected build
rate needed to
land the curve can be met based on the twenty foot difference. This
determination may
include examining the current location of the bit, the projected path, and
similar information.
[0117] In step
836, modifications may be made based on the forecast. For example, if the
projected build rate can be met, then modifications may be made to the
drilling parameters to
address the formation depth difference, but the modifications may be
relatively minor.
However, if the projected build rate cannot be met, the surface steerable
system 201 may
determine how to address the situation by, for example, planning a bit trip to
replace the
current BHA with a BHA capable of making a new and more aggressive curve.
[0118] Such
decisions may be automated or may require input or approval by the drilling
engineer 302, geologist 304, or other individuals. For example, depending on
the distance to
the kick off point, the surface steerable system 201 may first stop drilling
and then send an
alert to an authorized individual, such as the drilling engineer 302 and/or
geologist 304. The
drilling engineer 302 and geologist 304 may then become involved in planning a
solution or
may approve of a solution proposed by the surface steerable system 201. In
some
embodiments, the surface steerable system 201 may automatically implement its
calculated
solution. Parameters may be set for such automatic implementation measures to
ensure that
drastic deviations from the original well plan do not occur automatically
while allowing the
automatic implementation of more minor measures.
[0119] It is understood that such recalibration forecasts may be performed
based on many
different factors and may be triggered by many different events. The
forecasting portion of
the process is directed to anticipating what changes may be needed due to the
recalibration
and calculating how such changes may be implemented. Such forecasting provides
cost
advantages because more options may be available when a problem is detected
earlier rather
than later. Using the previous example, the earlier the difference in the
depth of the layer is
identified, the more likely it is that the build rate can be met without
changing the BHA.
CA 3031827 2019-01-28
(.--
[0120] Referring to Fig. 8D, a method 840 illustrates one embodiment of
an event-based
process that may be executed by the on-site controller 144 of Fig. 2A. The
method 840 is
directed to self-tuning that may be performed by the on-site controller 144
based on factors
such as ROP, total cost, and reliability. By self-tuning, the on-site
controller 144 may
execute a learning process that enables it to optimize the drilling
performance of the drilling
rig 110. Furthermore, the self-tuning process enables a balance to be reached
that provides
reliability while also lowering costs. Reliability in drilling operations is
often tied to
vibration and the problems that vibration can cause, such as stick-slip and
whirling. Such
vibration issues can damage or destroy equipment and can also result in a very
uneven
surface in the borehole that can cause other problems such as friction loading
of future
drilling operations as pipe/casing passes through that area of the borehole.
Accordingly, it is
desirable to minimize vibration while optimizing performance, since over-
correcting for
vibration may result in slower drilling than necessary. It is understood that
the present
optimization may involve a change in any drilling parameter and is not limited
to a particular
piece of equipment or control system. In other words, parameters across the
entire drilling
rig 110 and BHA may be changed during the self-tuning process. Furthermore,
the
optimization process may be applied to production by optimizing well
smoothness and other
factors affecting production. For example, by minimizing dogleg severity,
production may
be increased for the lifetime of the well.
[01211 Accordingly, in step 842, one or more target parameters are
identified. For
example, the target parameter may be an MSE of 50 ksi or an ROP of 100 ft/hr
that the on-
site controller 144 is to establish and maintain. In step 844, a plurality of
control parameters
are identified for use with the drilling operation. The control parameters are
selected to meet
the target MSE of 50 lcsi or ROP of 100 ft/hr. The drilling operation is
started with the
control parameters, which may be used until the target MSE or ROP is reached.
In step 846,
feedback information is received from the drilling operation when the control
parameters are
being used, so the feedback represents the performance of the drilling
operation as controlled
by the control parameters. Historical information may also be used in step
846. In step 848,
an operational baseline is established based on the feedback information.
[0122) In step 850, at least one of the control parameters is changed to
modify the drilling
operation, although the target MSE or ROP should be maintained. For example,
some or all
of the control parameters may be associated with a range of values and the
value of one or
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CA 3031827 2019-01-28
more of the control parameters may be changed. In step 852, more feedback
information is
received, but this time the feedback reflects the performance of the drilling
operation with the
changed control parameter. In step 854, a performance impact of the change is
determined
with respect to the operational baseline. The performance impact may occur in
various ways,
such as a change in MSE or ROP and/or a change in vibration. In step 856, a
determination
is made as to whether the control parameters are optimized. If the control
parameters are not
optimized, the method 840 returns to step 850. If the control parameters are
optimized, the
method 840 moves to step 858. In step 858, the optimized control parameters
are used for the
current drilling operation with the target MSE or ROP and stored (e.g., in the
database 128)
for use in later drilling operations and operational analyses. This may
include linking
formation information to the control parameters in the regional database 128.
[0123] Referring to Fig. 9, one embodiment of a system architecture 900
is illustrated that
may be used for the on-site controller 144 of Fig. IA. The system architecture
900 includes
interfaces configured to interact with external components and internal
modules configured to
process information. The interfaces may include an input driver 902, a remote
synchronization interface 904, and an output interface 918, which may include
at least one of
a graphical user interface (GUI) 906 and an output driver 908. The internal
modules may
include a database query and update engine/diagnostic logger 910, a local
database 912
(which may be similar or identical to the database 410 of Fig. 4), a guidance
control loop
(GCL) module 914, and an autonomous control loop (ACL) module 916. It is
understood
that the system architecture 900 is merely one example of a system
architecture that may be
used for the on-site controller 144 and the functionality may be provided for
the on-site
controller 144 using many different architectures. Accordingly, the
functionality described
herein with respect to particular modules and architecture components may be
combined,
further separated, and organized in many different ways.
[0124] For instance, the on-site controller 144 may be configured to be
placed downhole
somewhere along the drill string in order to provide for the functions
described hereinabove
as part of an embedded downhole system, such as in the embodiment shown in
FIG. 15,
described hereinbelow. The on-site controller 144 may perform methods such as
the methods
600 of Fig. 6, 700 of Fig. 7A, 720 of Fig. 7B, 800 of Fig. 8A, 820 of Fig. 8B,
830 of Fig. 8C,
and 840 of Fig. 8D. Thus, the embedded downhole on-site controller 144 would
execute
downhole instead of at the surface to provide for rapid calculations
concerning drilling path
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CA 3031827 2019-01-28
adjustments, economic cost analysis, and other calculations included in the
methods
described hereinabove.
[0125] It is understood that the surface steerable system 201 may
perform certain
computations to prevent errors or inaccuracies from accumulating and throwing
off
calculations. For example, as will be described later, the input driver 902
may receive
Wellsite Information Transfer Specification (WITS) input representing absolute
pressure,
while the surface steerable system 201 needs differential pressure and needs
an accurate zero
point for the differential pressure. Generally, the driller will zero out the
differential pressure
when the drillstring is positioned with the bit off bottom and full pump flow
is occurring.
However, this may be a relatively sporadic event. Accordingly, the surface
steerable system
201 may recognize when the bit is off bottom and target flow rate has been
achieved and zero
out the differential pressure.
[0126] Another computation may involve block height, which needs to be
calibrated
properly. For example, block height may oscillate over a wide range, including
distances that
may not even be possible for a particular drilling rig. Accordingly, if the
reported range is
sixty feet to one hundred and fifty feet and there should only be one hundred
feet, the surface
steerable system 201 may assign a zero value to the reported sixty feet and a
one hundred
foot value to the reported one hundred and fifty feet. Furthermore, during
drilling, error
gradually accumulates as the cable is shifted and other events occur. The
surface steerable
system 201 may compute its own block height to predict when the next
connection occurs
and other related events, and may also take into account any error that may be
introduced by
cable issues.
[0127] Referring specifically to Fig. 9, the input driver 902 provides
output to the GUI
906, the database query and update engine/diagnostic logger 910, the GCL 914,
and the ACL
916. The input driver 902 is configured to receive input for the on-site
controller 144. It is
understood that the input driver 902 may include the functionality needed to
receive various
file types, formats, and data streams. The input driver 902 may also be
configured to convert
formats if needed. Accordingly, the input driver 902 may be configured to
provide flexibility
to the on-site controller 144 by handling incoming data without the need to
change the
internal modules. In some embodiments, for purposes of abstraction, the
protocol of the data
38
CA 3031827 2019-01-28
stream can be arbitrary with an input event defined as a single change (e.g.,
a real time sensor
change) of any of the given inputs.
[0128] The input driver 902 may receive various types of input, including
rig sensor input
(e.g., from the sensor system 214 of Fig. 2A), well plan data, and control
data (e.g.,
engineering control parameters). For example, rig sensor input may include
hole depth, bit
depth, toolface, inclination, azimuth, true vertical depth, gamma count,
standpipe pressure,
mud flow rate, rotary RPMs, bit speed, ROP, and WOB. The well plan data may
include
information such as projected starting and ending locations of various
geologic layers at
vertical depth points along the well plan path, and a planned path of the
borehole presented in
a three dimensional space. The control data may be used to define maximum
operating
parameters and other limitations to control drilling speed, limit the amount
of deviation
permitted from the planned path, define levels of authority (e.g., can an on-
site operator make
a particular decision or should it be made by an off-site engineer), and
similar limitations.
The input driver 902 may also handle manual input, such as input entered via a
keyboard, a
mouse, or a touch screen. In some embodiments, the input driver 902 may also
handle
wireless signal input, such as from a cell phone, a smart phone, a PDA, a
tablet, a laptop, or
any other device capable of wirelessly communicating with the on-site
controller 144 through
a network locally and/or offsite.
[0129] The database query and update engine/diagnostic logger 910
receives input from
the input driver 902, the GCL 914, and ACL 916, and provides output to the
local database
912 and GUI 906. The database query and update engine/diagnostic logger 910 is
configured
to manage the archiving of data to the local database 912. The database query
and update
engine/diagnostic logger 910 may also manage some functional requirements of a
remote
synchronization server (RSS) via the remote synchronization interface 904 for
archiving data
that will be uploaded and synchronized with a remote database, such as the
database 128 of
Fig. 1A. The database query and update engine/diagnostic logger 910 may also
be
configured to serve as a diagnostic tool for evaluating algorithm behavior and
performance
against raw rig data and sensor feedback data.
[0130] The local database 912 receives input from the database query and
update
engine/diagnostic logger 910 and the remote synchronization interface 904, and
provides
output to the GCL 914, the ACL 916, and the remote synchronization interface
904. It is
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CA 3031827 2019-01-28
understood that the local database 912 may be configured in many different
ways. As
described in previous embodiments, the local database 912 may store both
current and
historic information representing both the current drilling operation with
which the on-site
controller 144 is engaged as well as regional information from the database
128.
[01311 The GCL 914 receives input from the input driver 902 and the local
database 912,
and provides output to the database query and update engine/diagnostic logger
910, the GUI
906, and the ACL 916. Although not shown, in some embodiments, the GCL 906 may
provide output to the output driver 908, which enables the GCL 914 to directly
control third
party systems and/or interface with the drilling rig alone or with the ACL
916. An
embodiment of the GCL 914 is discussed below with respect to Fig. 11.
[01321 The ACL 916 receives input from the input driver 902, the local
database 912, and
the GCL 914, and provides output to the database query and update
engine/diagnostic logger
910 and output driver 908. An embodiment of the ACL 916 is discussed below
with respect
to Fig. 12.
101331 The output interface 918 receives input from the input driver 902,
the GCL 914,
and the ACL 916. In the present example, the GUI 906 receives input from the
input driver
902 and the GCL 914. The GUI 906 may display output on a monitor or other
visual
indicator. The output driver 908 receives input from the ACL 916 and is
configured to
provide an interface between the on-site controller 144 and external control
systems, such as
the control systems 208, 210, and 212 of Fig. 2A.
101341 It is understood that the system architecture 900 of Fig. 9 may be
configured in
many different ways. For example, various interfaces and modules may be
combined or
further separated. Accordingly, the system architecture 900 provides one
example of how
functionality may be structured to provide the on-site controller 144, but the
on-site controller
144 is not limited to the illustrated structure of Fig. 9.
[01351 Referring to Fig: 10, one embodiment of the input driver 902 of the
system
architecture 900 of Fig. 9 is illustrated in greater detail. In the present
example, the input
driver 902 may be configured to receive input via different input interfaces,
such as a serial
CA 3031827 2019-01-28
f
input driver 1002 and a Transmission Control Protocol (TCP) driver 1004. Both
the serial
input driver 1002 and the TCP input driver 1004 may feed into a parser 1006.
[0136] The parser 1006 in the present example may be configured in
accordance with a
specification such as WITS and/or using a standard such as Wellsite
Information Transfer
Standard Markup Language (WITSML). WITS is a specification for the transfer of
drilling
rig-related data and uses a binary file format. WITS may be replaced or
supplemented in
some embodiments by WITSML, which relies on eXtensible Markup Language (XML)
for
transferring such information. The parser 1006 may feed into the database
query and update
engine/diagnostic logger 910, and also to the GCL 914 and GUI 906 as
illustrated by the
example parameters of block 1010. The input driver 902 may also include a non-
WITS input
driver 1008 that provides input to the ACL 916 as illustrated by block 1012.
[0137j Referring to Fig. 11, one embodiment of the GCL 914 of Fig. 9 is
illustrated in
greater detail. In the present example, the GCL 914 may include various
functional modules,
including a build rate predictor 1102, a geo modified well planner 1104, a
borehole estimator
1106, a slide estimator 1108, an error vector calculator 1110, a geological
drift estimator
1112, a slide planner 1114, a convergence planner 1116, and a tactical
solution planner 1118.
In the following description of the GCL 914, the term external input refers to
input received
from outside the GCL 914 (e.g., from the input driver 902 of Fig. 9), while
internal input
refers to input received by a GCL module from another GCL module.
[01381 The build rate
predictor 1102 receives external input representing BHA and
geological information, receives internal input from the borehole estimator
1106, and
provides output to the geo modified well planner 1104, slide estimator 1108,
slide planner
1114, and convergence planner 1116. The build rate predictor 1102 is
configured to use the
BHA and geological information to predict the drilling build rates of current
and future
sections of a well. For example, the build rate predictor 1102 may determine
how
aggressively the curve will be built for a given formation with given BHA and
other
equipment parameters. In a rotary steerable system, the slide estimator 1108
and the slide
planner 1114 may still be utilized in a similar fashion as that described
hereinbelow in order
to estimate and plan a directional drilling path. In a rotary steerable
system, the slide
estimator 1108 and the slide planner 1114 may be referred to as "direction
estimator,"
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CA 3031827 2019-01-28
"direction planner," or something else that denotes that the components deal
with rotary
steerable directional drilling, but not slide drilling.
[01391 The build rate predictor 1102 may use the orientation of the BHA
to the formation
to determine an angle of attack for formation transitions and build rates
within a single layer
of a formation. For example, if there is a layer of rock with a layer of sand
above it, there is a
formation transition from the sand layer to the rock layer. Approaching the
rock layer at a
ninety degree angle may provide a good face and a clean drill entry, while
approaching the
rock layer at a forty-five degree angle may build a curve relatively quickly.
An angle of
approach that is near parallel may cause the bit to skip off the upper surface
of the rock layer.
Accordingly, the build rate predictor 1102 may calculate BHA orientation to
account for
formation transitions. Within a single layer, the build rate predictor 1102
may use BHA
orientation to account for internal layer characteristics (e.g., grain) to
determine build rates
for different parts of a layer.
[01401 The BHA information may include bit characteristics, mud motor
bend setting,
stabilization and mud motor bit to bend distance. The geological information
may include
formation data such as compressive strength, thicknesses, and depths for
formations
encountered in the specific drilling location. Such information enables a
calculation-based
prediction of the build rates and ROP that may be compared to both real-time
results (e.g.,
obtained while drilling the well) and regional historical results (e.g., from
the database 128)
to improve the accuracy of predictions as the drilling progresses. Future
formation build rate
predictions may be used to plan convergence adjustments and confirm that
targets can be
achieved with current variables in advance.
101411 The geo modified well planner 1104 receives external input
representing a well
plan, internal input from the build rate predictor 1102 and the geo drift
estimator 1112, and
provides output to the slide planner 1114 and the error vector calculator
1110. The geo
modified well planner 1104 uses the input to determine whether there is a more
optimal path
than that provided by the external well plan while staying within the original
well plan error
limits. More specifically, the geo modified well planner 1104 takes geological
information
(e.g., drift) and calculates whether another solution to the target may be
more efficient in
terms of cost and/or reliability. The outputs of the geo modified well planner
1104 to the
slide planner 1114 and the error vector calculator 1110 may be used to
calculate an error
42
CA 3031827 2019-01-28
1,
vector based on the current vector to the newly calculated path and to modify
slide
predictions.
[0142] In some embodiments, the geo modified well planner 1104 (or
another module)
may provide functionality needed to track a formation trend. For example, in
horizontal
wells, the geologist 304 may provide the surface steerable system 201 with a
target
inclination that the surface steerable system 201 is to attempt to hold. For
example, the
geologist 304 may provide a target to the directional driller 306 of 90.5-91
degrees of
inclination for a section of the well. The geologist 304 may enter this
information into the
surface steerable system 201 and the directional driller 306 may retrieve the
information from
the surface steerable system 201. The geo modified well planner 1104 may then
treat the
target as a vector target, for example, either by processing the information
provided by the
geologist 304 to create the vector target or by using a vector target entered
by the geologist
304. The geo modified well planner 1104 may accomplish this while remaining
within the
error limits of the original well plan.
[0143] In some embodiments, the geo modified well planner 1104 may be an
optional
module that is not used unless the well plan is to be modified. For example,
if the well plan
is marked in the surface steerable system 201 as non-modifiable, the geo
modified well
planner 1104 may be bypassed altogether or the geo modified well planner 1104
may be
configured to pass the well plan through without any changes.
[0144] The borehole estimator 1106 receives external inputs representing
BHA
information, measured depth information, survey information (e.g., azimuth and
inclination),
and provides outputs to the build rate predictor 1102, the error vector
calculator 1110, and the
convergence planner 1116. The borehole estimator 1106 is configured to provide
a real time
or near real time estimate of the actual borehole and drill bit position and
trajectory angle.
This estimate may use both straight line projections and projections that
incorporate sliding.
The borehole estimator 1106 may be used to compensate for the fact that a
sensor is usually
physically located some distance behind the bit (e.g., fifty feet), which
makes sensor readings
lag the actual bit location by fifty feet. The borehole estimator 1106 may
also be used to
compensate for the fact that sensor measurements may not be continuous (e.g.,
a sensor
measurement may occur every one hundred feet).
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CA 3031827 2019-01-28
[0145] The borehole estimator 1106 may use two techniques to accomplish
this. First,
the borehole estimator 1106 may provide the most accurate estimate from the
surface to the
last survey location based on the collection of all survey measurements.
Second, the borehole
estimator 1106 may take the slide estimate from the slide estimator 1108
(described below)
and extend this estimation from the last survey point to the real time drill
bit location. Using
the combination of these two estimates, the borehole estimator 1106 may
provide the on-site
controller 144 with an estimate of the drill bit's location and trajectory
angle from which
guidance and steering solutions can be derived. An additional metric that can
be derived
from the borehole estimate is the effective build rate that is achieved
throughout the drilling
.. process. For example, the borehole estimator 1106 may calculate the current
bit position and
trajectory 743 in Fig. 7C.
[0146] The slide estimator 1108 receives external inputs representing
measured depth and
differential pressure information, receives internal input from the build rate
predictor 1102,
and provides output to the borehole estimator 1106 and the geo modified well
planner 1104.
The slide estimator 1108, which may operate in real time or near real time, is
configured to
sample toolface orientation, differential pressure, measured depth (MD)
incremental
movement, MSE, and other sensor feedback to quantify/estimate a deviation
vector and
progress while sliding.
[0147] Traditionally, deviation from the slide would be predicted by a
human operator
based on experience. The operator would, for example, use a long slide cycle
to assess what
likely was accomplished during the last slide. However, the results are
generally not
confirmed until the MWD survey sensor point passes the slide portion of the
borehole, often
resulting in a response lag defined by the distance of the sensor point from
the drill bit tip
(e.g., approximately fifty feet). This lag introduces inefficiencies in the
slide cycles due to
over/under correction of the actual path relative to the planned path.
[0148] With the slide estimator 1108, each toolface update is
algorithmically merged with
the average differential pressure of the period between the previous and
current toolfaces, as
well as the MD change during this period to predict the direction, angular
deviation, and MD
progress during that period. As an example, the periodic rate may be between
ten and sixty
seconds per cycle depending on the tool face update rate of the MWD tool. With
a more
accurate estimation of the slide effectiveness, the sliding efficiency can be
improved. The
44
CA 3031827 2019-01-28
output of the slide estimator 1108 is periodically provided to the borehole
estimator 1106 for
accumulation of well deviation information, as well to the geo modified well
planner 1104.
Some or all of the output of the slide estimator 1108 may be output via a
display such as the
display 250 of Fig. 2B.
[0149] The error vector calculator 1110 receives internal input from the
geo modified
well planner 1104 and the borehole estimator 1106. The error vector calculator
1110 is
configured to compare the planned well path to the actual borehole path and
drill bit position
estimate. The error vector calculator 1110 may provide the metrics used to
determine the
error (e.g., how far off) the current drill bit position and trajectory are
from the plan. For
example, the error vector calculator 1110 may calculate the error between the
current position
743 of Fig. 7C to the planned path 742 and the desired bit position 741. The
error vector
calculator 1110 may also calculate a projected bit position/projected path
representing the
future result of a current error as described previously with respect to Fig.
7B.
[0150] The geological drift estimator 1112 receives external input
representing geological
information and provides outputs to the geo modified well planner 1104, slide
planner 1114,
and tactical solution planner 1118. During drilling, drift may occur as the
particular
characteristics of the formation affect the drilling direction. More
specifically, there may be a
trajectory bias that is contributed by the formation as a function of drilling
rate and BHA.
The geological drift estimator 1112 is configured to provide a drift estimate
as a vector. This
vector can then be used to calculate drift compensation parameters that can be
used to offset
the drift in a control solution.
[0151] The slide planner 1114 receives internal input from the build rate
predictor 1102,
the geo modified well planner 1104, the error vector calculator 1110, and the
geological drift
estimator 1112, and provides output to the convergence planner 1116 as well as
an estimated
time to the next slide. The slide planner 1114 is configured to evaluate a
slide/drill ahead
cost equation and plan for sliding activity, which may include factoring in
BHA wear,
expected build rates of current and expected formations, and the well plan
path. During drill
ahead, the slide planner 1114 may attempt to forecast an estimated time of the
next slide to
aid with planning. For example, if additional lubricants (e.g., beads) are
needed for the next
slide and pumping the lubricants into the drill string needs to begin thirty
minutes before the
CA 3031827 2019-01-28
(..
slide, the estimated time of the next slide may be calculated and then used to
schedule when
to start pumping the lubricants.
[01521 Functionality for a loss circulation material (LCM) planner may be
provided as
part of the slide planner 1114 or elsewhere (e.g., as a stand-alone module or
as part of another
module described herein). The LCM planner functionality may be configured to
determine
whether additives need to be pumped into the borehole based on indications
such as flow-in
versus flow-back measurements. For example, if drilling through a porous rock
formation,
fluid being pumped into the borehole may get lost in the rock formation. To
address this
issue, the LCM planner may control pumping LCM into the borehole to clog up
the holes in
the porous rock surrounding the borehole to establish a more closed-loop
control system for
the fluid.
[0153] The slide planner 1114 may also look at the current position
relative to the next
connection. A connection may happen every ninety to one hundred feet (or some
other
distance or distance range based on the particulars of the drilling operation)
and the slide
.. planner 1114 may avoid planning a slide when close to a connection and/or
when the slide
would carry through the connection. For example, if the slide planner 1114 is
planning a fifty
foot slide but only twenty feet remain until the next connection, the slide
planner 1114 may
calculate the slide starting after the next connection and make any changes to
the slide
parameters that may be needed to accommodate waiting to slide until after the
next
connection. This avoids inefficiencies that may be caused by starting the
slide, stopping for
the connection, and then having to reorient the toolface before finishing the
slide. During
slides, the slide planner 1114 may provide some feedback as to the progress of
achieving the
desired goal of the current slide.
[01541 In some embodiments, the slide planner 1114 may account for
reactive torque in
the drillstring. More specifically, when rotating is occurring, there is a
reactional torque wind
up in the drillstiing. When the rotating is stopped, the drillstring unwinds,
which changes
toolface orientation and other parameters. When rotating is started again, the
drillstring starts
to wind back up. The slide planner 1114 may account for this reactional torque
so that
toolface references are maintained rather than stopping rotation and then
trying to adjust to an
optimal tool face orientation. While not all MWD tools may provide toolface
orientation
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CA 3031827 2019-01-28
when rotating, using one that does supply such information for the GCL 914 may
significantly reduce the transition time from rotating to sliding.
[0155] The convergence planner 1116 receives internal inputs from the
build rate
predictor 1102, the borehole estimator 1106, and the slide planner 1114, and
provides output
to the tactical solution planner 1118. The convergence planner 1116 is
configured to provide
a convergence plan when the current drill bit position is not within a defined
margin of error
of the planned well path. The convergence plan represents a path from the
current drill bit
position to an achievable and optimal convergence target point along the
planned path. The
convergence plan may take account the amount of sliding/drilling ahead that
has been
.. planned to take place by the slide planner 1114. The convergence planner
1116 may also use
BHA orientation information for angle of attack calculations when determining
convergence
plans as described above with respect to the build rate predictor 1102. The
solution provided
by the convergence planner 1116 defines a new trajectory solution for the
current position of
the drill bit. The solution may be real time, near real time, or future (e.g.,
planned for
implementation at a future time). For example, the convergence planner 1116
may calculate
a convergence plan as described previously with respect to Figs. 7C and 8.
[0156] The tactical solution planner 1118 receives internal inputs from
the geological
drift estimator 1112 and the convergence planner 1116, and provides external
outputs
representing information such as toolface orientation, differential pressure,
and mud flow
rate. The tactical solution planner 1118 is configured to take the trajectory
solution provided
by the convergence planner 1116 and translate the solution into control
parameters that can
be used to control the drilling rig 110. For example, the tactical solution
planner 1118 may
take the solution and convert the solution into settings for the control
systems 208, 210, and
212 to accomplish the actual drilling based on the solution. The tactical
solution planner
1118 may also perform performance optimization as described previously. The
performance
optimization may apply to optimizing the overall drilling operation as well as
optimizing the
drilling itself (e.g., how to drill faster).
[0157] Other functionality may be provided by the GCL 914 in additional
modules or
added to an existing module. For example, there is a relationship between the
rotational
position of the drill pipe on the surface and the orientation of the downhole
toolface.
Accordingly, the GCL 914 may receive information corresponding to the
rotational position
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CA 3031827 2019-01-28
of the drill pipe on the surface. The GCL 914 may use this surface positional
information to
calculate current and desired toolface orientations. These calculations may
then be used to
define control parameters for adjusting the top drive or Kelly drive to
accomplish adjustments
to the downhole toolface in order to steer the well.
[0158] For purposes of example, an object-oriented software approach may be
utilized to
provide a class-based structure that may be used with the GCL 914 and/or other
components
of the on-site controller 144. In the present embodiment, a drilling model
class is defined to
capture and define the drilling state throughout the drilling process. The
class may include
real-time information. This class may be based on the following components and
sub-
models: a drill bit model, a borehole model, a rig surface gear model, a mud
pump model, a
WOB/differential pressure model, a positional/rotary model, an MSE model, an
active well
plan, and control limits. The class may produce a control output solution and
may be
executed via a main processing loop that rotates through the various modules
of the GCL
914.
[0159] The drill bit model may represent the current position and state of
the drill bit.
This model includes a three dimensional position, a drill bit trajectory, BHA
information, bit
speed, and toolface (e.g., orientation information). The three dimensional
position may be
specified in north-south (NS), east-west (EW), and true vertical depth (TVD).
The drill bit
trajectory may be specified as an inclination and an azimuth angle. The BHA
information
may be a set of dimensions defining the active BHA. The borehole model may
represent the
current path and size of the active borehole. This model includes hole depth
information, an
array of survey points collected along the borehole path, a gamma log, and
borehole
diameters. The hole depth information is for the current drilling job. The
borehole diameters
represent the diameters of the borehole as drilled over the current drill job.
[0160] The rig surface
gear model may represent pipe length, block height, and other
models, such as the mud pump model, WOB/differential pressure model,
positional/rotary
model, and MSE model. The mud pump model represents mud pump equipment and
includes flow rate, standpipe pressure, and differential pressure. The
WOB/differential
pressure model represents drawworics or other WOB/differential pressure
controls and
parameters, including WOB. The positional/rotary model represents top drive or
other
positional/rotary controls and parameters including rotary RPM and spindle
position. The
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CA 3031827 2019-01-28
active well plan represents the target borehole path and may include an
external well plan and
a modified well plan. The control limits represent defined parameters that may
be set as
maximums and/or minimums. For example, control limits may be set for the
rotary RPM in
the top drive model to limit the maximum RPMs to the defined level. The
control output
solution represents the control parameters for the drilling rig 110.
[0161] The main processing loop can be handled in many different ways.
For example,
the main processing loop can run as a single thread in a fixed time loop to
handle rig sensor
event changes and time propagation. If no rig sensor updates occur between
fixed time
intervals, a time only propagation may occur. In other embodiments, the main
processing
loop may be multi-threaded.
[0162] Each functional module of the GCL 914 may have its behavior
encapsulated
within its own respective class definition. During its processing window, the
individual units
may have an exclusive portion in time to execute and update the drilling
model. For purposes
of example, the processing order for the modules may be in the sequence of geo
modified
well planner 1104, build rate predictor 1102, slide estimator 1108, borehole
estimator 1106,
error vector calculator 1110, slide planner 1114, convergence planner 1116,
geological drift
estimator 1112, and tactical solution planner 1118. It is understood that
other sequences may
be used.
[0163] In the present embodiment, the GCL 914 may rely on a programmable
timer
module that provides a timing mechanism to provide timer event signals to
drive the main
processing loop. While the on-site controller 144 may rely purely on timer and
date calls
driven by the programming environment (e.g., java), this would limit timing to
be exclusively
driven by system time. In situations where it may be advantageous to
manipulate the clock
(e.g., for evaluation and/or testing), the programmable timer module may be
used to alter the
time. For example, the programmable timer module may enable a default time set
to the
system time and a time scale of 1.0, may enable the system time of the on-site
controller 144
to be manually set, may enable the time scale relative to the system time to
be modified,
and/or may enable periodic event time requests scaled to the time scale to be
requested.
[0164] Referring to Fig. 12, one embodiment of the ACL 916 provides
different functions
to the on-site controller 144. The ACL 916 may be considered a second feedback
control
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=
loop that operates in conjunction with a first feedback control loop provided
by the GCL 914.
The ACL 916 may also provide actual instructions to the drilling rig 110,
either directly to
the drilling equipment 216 or via the control systems 208, 210, and 212. The
ACL 916 may
include a positional/rotary control logic block 1202, WOB/differential
pressure control logic
block 1204, fluid circulation control logic block 1206, and a pattern
recognition/error
detection block 1208.
[0165] One function of the ACL 916 is to establish and maintain a target
parameter (e.g.,
an ROP of a defined value of ft/hr) based on input from the GCL 914. This may
be
accomplished via control loops using the positional/rotary control logic block
1202,
WOB/differential pressure control logic block 1204, and fluid circulation
control logic block
1206. The positional/rotary control logic block 1202 may receive sensor
feedback
information from the input driver 902 and set point information from the GCL
914 (e.g., from
the tactical solution planner 1118). The differential pressure control logic
block 1204 may
receive sensor feedback information from the input driver 902 and set point
information from
the GCL 914 (e.g., from the tactical solution planner 1118). The fluid
circulation control
logic block 1206 may receive sensor feedback information from the input driver
902 and set
point information from the GCL 914 (e.g., from the tactical solution planner
1118).
101661 The ACL 916 may use the sensor feedback information and the set
points from the
GCL 914 to attempt to maintain the established target parameter. More
specifically, the ACL
916 may have control over various parameters via the positional/rotary control
logic block
1202, WOB/differential pressure control logic block 1204, and fluid
circulation control logic
block 1206, and may modulate the various parameters to achieve the target
parameter. The
ACL 916 may also modulate the parameters in light of cost-driven and
reliability-driven
drilling goals, which may include parameters such as a trajectory goal, a cost
goal, and/or a
performance goal. It is understood that the parameters may be limited (e.g.,
by control limits
set by the drilling engineer 306) and the ACL 916 may vary the parameters to
achieve the
target parameter without exceeding the defined limits. If this is not
possible, the ACL 916
may notify the on-site controller 144 or otherwise indicate that the target
parameter is
currently unachievable.
[0167) In some embodiments, the ACL 916 may continue to modify the
parameters to
identify an optimal set of parameters with which to achieve the target
parameter for the
CA 3031827 2019-01-28
particular combination of drilling equipment and formation characteristics. In
such
embodiments, the on-site controller 144 may export the optimal set of
parameters to the
database 128 for use in formulating drilling plans for other drilling
projects.
[0168] Another function of the ACL 916 is error detection. Error
detection is directed to
identifying problems in the current drilling process and may monitor for
sudden failures and
gradual failures. In this capacity, the pattern recognition/error detection
block 1208 receives
input from the input driver 902. The input may include the sensor feedback
received by the
positional/rotary control logic block 1202, WOB/differential pressure control
logic block
1204, and fluid circulation control logic block 1206. The pattern
recognition/error detection
block 1208 monitors the input information for indications that a failure has
occurred or for
sudden changes that are illogical.
[0169] For example, a failure may be indicated by an ROP shift, a radical
change in build
rate, or any other significant changes. As an illustration, assume the
drilling is occurring with
an expected ROP of 100 ft/hr. If the ROP suddenly drops to 50 ft/hr with no
change in
parameters and remains there for some defined amount of time, an equipment
failure,
formation shift, or another event has occurred. Another error may be indicated
when MWD
sensor feedback has been steadily indicating that drilling has been heading
north for hours
and the sensor feedback suddenly indicates that drilling has reversed in a few
feet and is
heading south. This change clearly indicates that a failure has occurred. The
changes may be
defined and/or the pattern recognition/error detection block 1208 may be
configured to watch
for deviations of a certain magnitude. The pattern recognition/error detection
block 1208
may also be configured to detect deviations that occur over a period of time
in order to catch
more gradual failures or safety concerns.
[0170] When an error is identified based on a significant shift in input
values, the on-site
controller 201 may send an alert. This enables an individual to review the
error and
determine whether action needs to be taken. For example, if an error indicates
that there is a
significant loss of ROP and an intermittent change/rise in pressure, the
individual may
determine that mud motor chunking has likely occurred with rubber tearing off
and plugging
the bit In this case, the BHA may be tripped and the damage repaired before
more serious
damage is done. Accordingly, the error detection may be used to identify
potential issues that
are occurring before they become more serious and more costly to repair.
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[01711 Another function of the ACL 916 is pattern recognition. Pattern
recognition is
directed to identifying safety concerns for rig workers and to provide
warnings (e.g., if a large
increase in pressure is identified, personnel safety may be compromised) and
also to
identifying problems that are not necessarily related to the current drilling
process, but may
impact the drilling process if ignored. In this capacity, the pattern
recognition/error detection
block 1208 receives input from the input driver 902. The input may include the
sensor
feedback received by the positional/rotary control logic block 1202,
WOB/differential
pressure control logic block 1204, and fluid circulation control logic block
1206. The pattern
recognition/error detection block 1208 monitors the input information for
specific defined
conditions. A condition may be relatively common (e.g., may occur multiple
times in a
single borehole) or may be relatively rare (e.g., may occur once every two
years).
Differential pressure, standpipe pressure, and any other desired conditions
may be monitored.
If a condition indicates a particular recognized pattern, the ACL 916 may
determine how the
condition is to be addressed. For example, if a pressure spike is detected,
the ACL 916 may
determine that the drilling needs to be stopped in a specific manner to enable
a safe exit.
Accordingly, while error detection may simply indicate that a problem has
occurred, pattern
recognition is directed to identifying future problems and attempting to
provide a solution to
the problem before the problem occurs or becomes more serious.
[01721 Referring to Fig. 13, one embodiment of a computer system 1300 is
illustrated.
The computer system 1300 is one possible example of a system component or
device such as
the on-site controller 144 of Fig. 1A. In scenarios where the computer system
1300 is on-
site, such as at the location of the drilling rig 110 of Fig. IA, the computer
system may be
contained in a relatively rugged, shock-resistant case that is hardened for
industrial
applications and harsh environments.
[0173] The computer system 1300 may include a central processing unit
("CPU") 1302, a
memory unit 1304, an input/output ("I/0") device 1306, and a network interface
1308. The
components 1302, 1304, 1306, and 1308 are interconnected by a transport system
(e.g., a bus)
1310. A power supply (PS) 1312 may provide power to components of the computer
system
1300, such as the CPU 1302 and memory unit 1304. It is understood that the
computer
system 1300 may be differently configured and that each of the listed
components may
actually represent several different components. For example, the CPU 1302 may
actually
represent a multi-processor or a distributed processing system; the memory
unit 1304 may
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CA 3031827 2019-01-28
include different levels of cache memory, main memory, hard disks, and remote
storage
locations; the I/0 device 1306 may include monitors, keyboards, and the like;
and the
network interface 1308 may include one or more network cards providing one or
more wired
and/or wireless connections to a network 1314. Therefore, a wide range of
flexibility is
anticipated in the configuration of the computer system 1300.
[0174] For instance, if the computer system 1300 is the on-site
controller 144, it may be
configured to be placed downhole somewhere along the drill string in order to
provide for the
functions described hereinabove as part of an embedded downhole system, such
as in the
embodiment shown in FIG. 15, described hereinbelow. If the computer system is
indeed the
on-site controller 144, the computer system 1300 may perform methods such as
the methods
600 of Fig. 6, 700 of Fig. 7A, 720 of Fig. 7B, 800 of Fig. 8A, 820 of Fig. 8B,
830 of Fig. 8C,
and 840 of Fig. 8D. Thus, the embedded downhole computer system 1300 would be
execute
downhole instead of at the surface to provide for rapid calculations
concerning drilling path
adjustments, economic cost analysis, and other calculations included in the
methods
described hereinabove.
[0175] The computer system 1300 may use any operating system (or multiple
operating
systems), including various versions of operating systems provided by
Microsoft (such as
WINDOWS), Apple (such as Mac OS X), UNIX, and LINUX, and may include operating
systems specifically developed for handheld devices, personal computers, and
servers
depending on the use of the computer system 1300. The operating system, as
well as other
instructions (e.g., software instructions for performing the functionality
described in previous
embodiments) may be stored in the memory unit 1304 and executed by the
processor 1302.
For example, if the computer system 1300 is the on-site controller 144, the
memory unit 1304
may include instructions for performing methods such as the methods 600 of
Fig. 6, 700 of
Fig. 7A, 720 of Fig. 7B, 800 of Fig. 8A, 820 of Fig. 8B, 830 of Fig. 8C, and
840 of Fig. 8D.
[0176] Referring now to Fig. 14, there is illustrated a surface steerable
system 1402
providing information to a drilling rig 1404 that implements a rotary
steerable system 1406.
The surface steerable system 1402 provides input 1408 to the rotary steerable
system 1406
and receives feedback 1410 from the rotary steerable system 1406 in manners
similar to that
discussed hereinabove. In this manner, the surface steerable system 1402 may
provide
continuous control of the rotary steerable system 1406 in order to achieve
desired directional
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CA 3031827 2019-01-28
(
steering results. The steerable system 1406 may comprise any number of
configurations of
rotary steerable systems and steerable system tools, one example of this is
illustrated in US
Patent No. 8,590,636.
[01771 A rotary steerable system 1406 is a form of drilling technology
used in directional
drilling. A rotary steerable system 1406 employs the use of a specialized down-
hole
equipment to replace conventional directional tools such as mud motors. The
rotary steerable
tools are generally programmed by a directional driller which transmits
commands to the
rotary steerable system 1406 using, for example, pressure fluctuations within
the mud column
or variations within the drill string rotations to transmit the information.
The rotary steerable
system 1406 responds to these instructions and gradually steers into the
desired direction.
The rotary steerable system 1406 may continue drilling while rotating the
drill string from the
surface eliminating the need to slide a mud motor utilizing slide directional
drilling
techniques.
[01781 The surface steerable system 1402 and the drilling rig 1404 may
communicate in a
similar manner as shown in FIG. 2A concerning the communication between the
surface
steerable system 201 and the drilling rig 110. Additionally, the surface
steerable system 1402
may have similar components to the surface steerable system 201, such as the
on-site
controller 144 and the drilling hub 216, with the input information 202 being
sent from the
drilling hub 216 to the on-site controller 144 and the output information 203
being sent from
the on-site controller to the drilling hub 216. Further, the drilling rig 1404
may contain
similar components as that of the drilling rig 110 shown in FIG 2A, such as
the
WOB/differential pressure control system 208, the positional/rotary control
system 210, the
fluid circulation control system 212, the sensor system 214, and the drilling
equipment 216.
[0179] The methods used within rotary steerable systems fall into two
broad categories.
These include the "push the bit" and "point the bit" techniques. Push the bit
tools use pads
on the outside of the tool which press against the wellbore thereby causing
the bit to press on
the opposite side of the wellbore causing a directional change. The pads are
typically
installed on the outer portion of the drill string somewhere above the drill
bit. The pads may
be actuated using hydraulic pistons that push the pad against the wall of the
wellbore. Point
the bit techniques cause the direction of the bit to change relative to the
rest of the tool by
bending a main shaft running through the tool. The point the bit techniques
require some
54
CA 3031827 2019-01-28
=
type of non-rotating housing or reference housing in order to create this
deflection within the
shaft. In some cases, a down-hole rotary steerable system tool can be
programmed to
maintain an angle and utilize downhole sensors and actuators to maintain the
drilling
direction, while in other situations, a user on the surface must decide
magnitude and direction
of the tool bias while drilling. These instructions adjust forces exerted by
the tool to turn the
well or overcome geo drift. The surface steerable system 1402 can also pre-
compensate for
torsional and spatial influences caused by the actuator forces to point or
push the bit. As an
example, in many cases Rotary Steerable System 1406 induced forces to gain
inclination or
induce a build in angle may cause left walk due to the side forces on the bit
combined with
the clockwise rotation of the drill bit. By forecasting the influences of
those forces a more
ideal deviation vector can be programmed into the downhole tool by the Surface
Steerable
System 1402.
[0180J The advantage of rotary steerable system tools is that they may be
continuously
rotated while creating a bias. Continuous rotation of the drill string allows
for improved
transportation of drilling cuttings to the surface resulting in better
hydraulic performance,
better weight transfer and allows a more complex bore to be drilled while
reducing bore
tortuosity due to utilizing a more steady steering model. The well geometry is
therefore less
aggressive, and the wellbore is smoother than those drilled using a mud motor.
The
disadvantages of rotary system tools arise from the fact that they are much
more expensive
and generally less reliable due to their added complexity.
[01811 The surface steerable system 1402 enables the rotary steerable
system 1406
downhole tools to be told when to rotate in line and when to deviate in a
similar manner that
a mud motor is controlled. The need to manage dog legs and prioritize economic
decisions
within the wellbore may be controlled through the surface steerable system
1402 controlling
the rotary steerable system 1406. The surface steerable system 1402 can
improve the
decisions made at every reevaluation which happens on a survey path. The
surface steerable
system 1402 can also provide more accurate projections, and the position of
the bit benefits
control of the rotatable steerable system tools 1406. Existing configurations
of rotary
steerable system 1406 require directional drillers on location to make the 3D
geometry
decisions and operating parameter adjustments. The surface steerable system
1402 can
optimize both decisions and simultaneously enable communication and
collaboration on and
offsite.
CA 3031827 2019-01-28
[0182] All geo steering tools provided by the surface steerable system
1402 are
applicable to both mud motors and rotary steerable system tools and if rotary
steerable system
tools provide additional sensors such as bit inclination, the surface
steerable system 1404 can
utilize the additional data points to further optimize its instructions.
Control of the Rotary
Steerable System 1406 can be by indirect recommendation to a directional
driller or direct
control by inducing mud pulse telemetry, pump cycling or other means to
downlink to the
Rotary Steerable System tool and change to the desired configuration.
[0183] By placing this complex control logic in a surface environment,
failures due to
temp, vibration and other challenges can be significantly reduced.
Additionally, new forms
of rotary steerable system targeting a lower cost of operation rely more
heavily on surface
decisions made by humans. These tools can be optimized by using the
methodology of the
surface steerable system by removing the variability of the human competency
and
simultaneously making all decision based on the best economic solution for the
operator.
[0184] In some modes of operation, variation of forces is needed to
accomplish deviation
of the BHA using the rotary steerable activation mechanism (i.e. the push
pads). The relative
forces needed to accomplish the deviation provides information about the
formation being
drilled, the effectiveness or health of the BHA and drill bit as well as
information about the
relative position of the downhole tools to the formations bed dip. Interfaces
to harder zones
or stringers can be recognized with this approach as well.
[0185] The potential deviation rate of the rotary steerable system can be
evaluated while
drilling to continuously calibrate the potential of the BHA and provide an
accurate projection
to the bit on a continuous basis from the last survey station to the location
of the bit. This
allows for an accurate starting point for future directional tasks but also
allows early warning
when a desired deviation is not possible.
[0186] All value driven functions of the surface steerable system are
applicable with use
of rotary steerable systems. For example, the decision to deviate the well and
the
aggressiveness of that deviation can be balanced with the proximity to ideal
pay zone defined
by cost curves. Likewise planning to avoid hard limits, property lines or high
risk zones in
3D space can be factored into all steering decisions being made.
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[0187] It is common amongst rotary steerable tools that a slower RPM or
Rate Of
Penetration is needed when deviation the well and so there is a drilling time
tradeoff linked to
the amount of deviation required of the rotary steerable tools. This manifests
itself as a time
impact to steering decisions similar to that when using a traditional mud
motor assembly in a
rotary vs slide mode.
[0188] Tortuosity driven costs/risks can also be factored in as deviation
of a well using
rotary steerable tools creates doglegs or tortuosity similar to a mud motor
when sliding.
Although the impacts are still generally less with a continuous arc on a
rotary steerable tool,
there is still a rate of change that can be set to be more or less aggressive.
This tortuosity can
.. be evaluated as a cost/risk for the operator and used to select an ideal
convergence plan.
[0189] With these
examples of key surface steerable cost components, Time Cost,
Tortuosity Cost, and Proximity to Pay zone Cost, are all applicable when using
high end and
low cost rotary steerable system.
[0190] Referring
now to FIG. 15, there is illustrated one embodiment of a rotary steerable
drilling rig 1500. In the present embodiment, the rotary steerable drilling
rig 1500 includes a
derrick 1502 on a surface 1504. The derrick 1502 includes a crown block 1506.
A top drive
1508 is coupled to the crown block 1506 via a drilling line 1510. The top
drive 1508
provides the rotational force needed for drilling and rotates a drill string
1512. The rotating
drill string 1512 in turn rotates a drill bit 1514 of a BHA 1516 in a borehole
1518 in a
formation 1520. In this particular embodiment, the rotary steerable drilling
rig 1500 further
includes a plurality of hydraulic pads 1522. The plurality of hydraulic pads
1522 serves to
provide a "push the bit" rotary steerable technique. To accomplish the
technique, each of the
plurality of hydraulic pads 1522 includes a plurality of pistons 1524 that
actuate when needed
in order to push the particular pad against the borehole 1518. For example, if
a drilling
operation was currently drilling straight down into the formation 1520, and a
decision was
made to begin drilling in a horizontal direction, one of the plurality of
hydraulic pads 1522
would have its plurality of pistons 1524 actuated in order to push the
hydraulic pad against
the wall of the borehole 1518. This would angle the drill string 1512, and
thus the drill bit
1514, in a direction away from the wall of the borehole 1518 that was pressed
by the actuated
hydraulic pad. It will be appreciated by those skilled in the art that other
methods of
performing rotary steerable drilling may be employed, such as "point the bit"
techniques,
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CA 3031827 2019-01-28
without deviating from the present inventive concept. It will be further
appreciated by those
skilled in the art that other components may be included in the rotary
steerable drilling rig
1500 in order to perform drilling operations and that the current described
embodiment is for
illustrative purposes.
[01911 As described hereinabove, the computer system 1300, or the on-site
controller
144, may be configured to be placed downhole as part of the BHA 1516 or
somewhere else
along the drill string in order to provide for the functions described
hereinabove as part of an
embedded downhole system. If the computer system is indeed the on-site
controller 144, the
computer system 1300 may perform methods such as the methods 600 of Fig. 6,
700 of Fig.
7A, 720 of Fig. 7B, 800 of Fig. 8A, 820 of Fig. 8B, 830 of Fig. 8C, and 840 of
Fig. 8D.
Thus, still referring to FIG. 15, a controller 1526 akin to the computer
system 1300 or the on-
site controller 144 may also be included as part of the BHA 1516 of the rotary
steerable
drilling rig 1500. Thus, the controller 1526 could execute various methods
downhole instead
of at the surface to provide for rapid calculations concerning drilling path
adjustments,
economic cost analysis, and other calculations included in the methods
described
hereinabove. The controller 1526 may control the plurality of hydraulic pads
1524 as well,
actuating one or more of the plurality of hydraulic pads 1524 when methods
performed by the
controller 1526 call for a change in drilling direction. In other embodiments
that do not
utilize hydraulic pads for rotary steering, the controller 1526 may similarly
control the
particular steering component, such as a bendable main shaft in other rotary
steering
embodiments, or other steering methods. As the controller 1526 may be akin to
the computer
system 1300 or the on-site controller 144, the controller 1526 may further be
configured to
communicate, either by a wired or wireless connection, with the network 1314
and/or other
components shown in the surface steerable system 201, and the drilling rig
110. It will be
appreciated that such a configuration utilizing the controller 1526 is not
limited to the
embodiment shown in FIG. 15, and may also be incorporated into other
embodiments
described hereinabove.
[0192] It will be appreciated by those skilled in the art having the
benefit of this
disclosure that this system and method for surface steerable drilling provides
a way to plan a
drilling process and to correct the drilling process when either the process
deviates from the
plan or the plan is modified. It should be understood that the drawings and
detailed
description herein are to be regarded in an illustrative rather than a
restrictive manner, and are
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CA 3031827 2019-01-28
not intended to be limiting to the particular forms and examples disclosed. On
the contrary,
included are any further modifications, changes, rearrangements,
substitutions, alternatives,
design choices, and embodiments apparent to those of ordinary skill in the
art, without
departing from the spirit and scope hereof, as defined by the following
claims. Thus, it is
intended that the following claims be interpreted to embrace all such further
modifications,
changes, rearrangements, substitutions, alternatives, design choices, and
embodiments.
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