AUTOMATED OPTIMAL PATH DESIGN FOR DIRECTIONAL DRILLING
BACKGROUND
[0001 ] The present disclosure relates generally to earth formation drilling operations
and, more particularly, to systems and methods of drilling control.
[0002] In drilling operations, typical drilling processes may be relatively complex
and involve considerable expense. Most of these operations are done by hand with
experienced operators running the drilling platform. There is a continual effort in the
industry to develop improvement in safety, cost minimization, and efficiency. The
advancements of computerized and automated systems in drilling processes are the next step
in achieving these goals. With robotic and automated systems for drilling processes in early
stages of development for the industry, there is a need for more efficient, improved, and
optimized drilling processes.
BRIEF DESCRIPTION OF THE DRAWINGS
[0003] These drawings illustrate certain aspects of some of the examples of the
present invention, and should not be used to limit or define the invention.
[0004] Figure 1A is a diagram of an example system;
[0005] Figure IB is a diagram of a simplified block of an example automated
optimal path design drilling program.
[0006] Figure 2 is a detailed schematic drawing of an example automated optimal
path design drilling program.
[0007] Figure 3 is an example chart, illustrating the operational scope of adaptive
constraints system.
[0008] Figure 4 illustrates the current system as used by the drilling industry to
reach a point below the earth's surface.
[0009] Figure 5A illustrates an example drilling operation being optimized as it
descends into the earth to a target area.
[001 0] Figure 5B illustrates an example drilling operation that is constantly
optimizing its descent into the earth, to a target area.
DETAILED DESCRIPTION
[001 1] The present disclosure relates generally to earth formation drilling
operations and, more particularly, to systems and methods of drilling control. Described
below, the disclosure describes a system that automatically designs an adaptive optimal
drilling path based on the real-time surveys and dynamic model based drilling path
prediction. The system may replace the driller manipulation to track an offline designed
drilling path. It may also automatically re-design the drilling path based on the current state
of drilling, formation types, updated drilling model, path deviations, and other information in
a manner that is optimal to reach a target area. The optimization cost functions take
downhole conditions, equipment wear and efficiencies, surface input constraints, model
based path predictions, and other input factors to design or re-design a path that increases
drilling efficiency and decreases cost per foot of drilling.
[00 12] Certain examples of the present disclosure may be implemented at least in
part with an information handling system. For purposes of this disclosure, an
information handling system may include any instrumentality or aggregate of
instrumentalities operable to compute, classify, process, transmit, receive, retrieve,
originate, switch, store, display, manifest, detect, record, reproduce, handle, or utilize any
form of information, intelligence, or data for business, scientific, control, or other
purposes. For example, an information handling system may be a personal computer,
a network storage device, or any other suitable device and may vary in size, shape,
performance, functionality, and price. The information handling system may include
random access memory (RAM), one or more processing resources such as a central
processing unit (CPU) or hardware or software control logic, ROM, and/or other types of
nonvolatile memory. Additional components of the information handling system may
include one or more disk drives, one or more network ports for communication with
external devices as well as various input and output ( 1/0) devices, such as a keyboard,
a mouse, and a video display. The information handling system may also include one or
more buses operable to transmit communications between the various hardware
components.
[001 3] Certain examples of the present disclosure may be implemented at least
in part with non-transitory computer-readable media. For the purposes of this disclosure,
non-transitory computer-readable media may include any instrumentality o r aggregation
o f instrumentalities that may retain data and/or instructions for a period of time. Nontransitory
computer-readable media may include, for example, without limitation, storage
media such as a direct access storage device (e.g., a hard disk drive or floppy disk
drive), a sequential access storage device (e.g., a tape disk drive), compact disk, CDROM,
DVD, RAM, ROM, electrically erasable programmable read-only memory
(EEPROM), and/or flash memory; as well as communications media such wires, optical
fibers, microwaves, radio waves, and other electromagnetic and/or optical carriers; and/or
any combination of the foregoing.
[001 4] Certain examples of the present disclosure may provide for automatically
controlling a drilling process. Certain examples may make all or a subset of decisions
during a drilling process and may control one or more of a top drive, a draw works, and
pumps. Certain examples may optimize a drilling process and provide command inputs
to one or more drill string control subsystems. The optimization may be updated
dependent on a drilling parameter model, which may include, but not be limited to, a
bit model, as it changes with time. Certain examples may overcome non-linearity in a
drilling process and remove or minimize them as needed.
[001 5] Figure A shows one non-limiting example drilling system 2, in
accordance with certain examples of the present disclosure. Drilling system 2 may
include a drilling rig 4 disposed atop a borehole 6 . A logging tool 8 may be carried by
a sub 10, typically a drill collar, incorporated into a drill string 2 and disposed within
the borehole 6. A drill bit 4 may be located at the lower end of the drill string 12 and
carves a borehole 6 through the earth formations 6 . Drilling mud 8 may be pumped
from a storage reservoir pit 20 near the wellhead 2 2 , down an axial passageway (not
illustrated) through the drill string 12, out of apertures in the bit 14 and back to the
surface through the annulus 2 3 . Casing 2 4 may be positioned in the borehole 6 above
the drill bit 14 for maintaining the integrity of an upper portion of the borehole 6.
[001 6] The annulus 2 3 between the drills string 12 , sub 10, and the sidewalls
26 of the borehole 6 may form the return flow path for the drilling mud 8. Drilling mud
18 may be pumped from the storage re servo ir pit 2 0 near the well head 22 by
pumping system 28. The drilling mud 1 8 may travel through a mud supply line 3 0
which a y b e coupled to a central passageway extending throughout the length of
drill string 2 . Drilling mud 8 is, in this manner, may b e forced down drill string 1 2
and exit into the borehole 6 through apertures in the drill bit 14 for cooling and
lubricating the drill bit and carrying the formation cuttings produced during the drilling
operation back to the surface. A fluid exhaust conduit 3 2 may be connected from the
annulus 23 at the well head 2 2 for conducting the return drilling mud 8 from the
borehole 6 to the storage reservoir pit 20.
[001 7] The logging tool 8 can be any conventional logging instrument such as
acoustic (sometimes referred to as sonic), neutron, gamma ray, density, photoelectric,
nuclear magnetic resonance, or any other conventional logging instrument, or
combinations thereof, which can be used to measure lithology or porosity of formations
surrounding an earth borehole. The logging data can be stored in a conventional
downhole recorder (not illustrated), which can be accessed at the earth's surface when
drill string 2 is retrieved, or can be transmitted to the earth's surface using telemetry
such as the conventional mud pulse telemetry systems. The logging data from the
logging tool 8 may be communicated to a surface measurement device processor 34 to
allow the data to be processed for use in accordance with the examples in the
present disclosure as described herein. In addition to WD instrumentation, wireline
logging instrumentation may also be used. The wireline instrumentation may include any
conventional logging instrumentation which can be used to measure the Iithology and/or
porosity of formations surrounding an earth borehole, for example, such as acoustic,
neutron, gamma ray, density, photoelectric, nuclear magnetic resonance, or any other
conventional logging instrument, or combinations thereof, which can be used to measure
Iithology.
[001 8] An information handling system 36 may be communicatively coupled to
one or more components of drilling system 2 in any suitable manner. The information
handling system 36 may be configured to implement one or more of the examples
described herein. The information handling system 36 may include a device, referred
to herein as computer/controller 38, that may include any suitable computer, controller, or
data processing apparatus, further being programmed for carrying out the method and
apparatus as further described herein. Computer/controller 38 may include at least one
input for receiving input information and/or commands, for instance, from any suitable
input device (or devices) 44. Input device (devices) 44 may include a keyboard, keypad,
pointing device, or the like, further including a network interface or other communications
interface for receiving input information from a remote computer or database. Still further,
computer/controller 38 may include at least one output for outputting information signals
and/or equipment control commands. Output signals can be output to a display device
46 via signal lines 40 for use in generating a display of information contained in the
output signals. Output signals can also be output to a printer device 48 for use in
generating a printout 5 0 of information contained in the output signals. Information
and/or control signals 52 may also be output via any suitable means of communication,
for example, to any device for use in controlling one or more various drilling operating
parameters of drilling rig 4, as further discussed herein. In other words, a suitable device
or means is provided for controlling a parameter in an actual drilling of a well bore (or
interval) with the drilling system in accordance with certain examples described herein.
For example, drilling system 2 may include equipment such as one of the following types
of controllable motors selected from a down hole motor 5 4 , a top drive motor 56, or
a rotary table motor 58, further in which a given rpm of a respective motor may be
remotely controlled. The parameter may also include any other suitable drilling system
control parameter described herein.
[001 9] Computer/controller 38 may provide a means for generating a geology
characteristic of the formation per unit depth in accordance with a prescribed geology
model. Computer/controller 38 may provide for outputting signals on signal lines 40, 42
representative of the geology characteristic. Computer/controller 38 may be programmed
for performing functions a s described herein, using programming techniques known in
the art. n one embodiment, a non~ transitory computer-readable medium may be
included, the medium having a computer program stored thereon. The computer program
for execution by computer/controller 38 may be used to optimize a drilling parameter of
the drill string in accordance with examples described herein. The programming of the
computer program for execution by computer/controller 38 may further be accomplished
using known programming techniques for implementing the examples as described and
discussed herein.
[0020] Computer/controller 38 may operate automated drilling program 60 (e.g.,
Figure IB, 2, etc.). Automated drilling program 60 may be installed, may function, and may
operate autonomously on computer/controller 38 or other information handling system.
Figure IB illustrates an example basic system overview of automated drilling program 60.
During operation, automated drilling program 60, may function using a system identification
module 66, an optimization function 68, and a fast time scale implementation 64.
[002 1] System identification module 66 may create a path/drilling dynamics model
based upon the information collected from the real drilling 64. System identification module
66 may operate as an independent information handling system, separate and apart from
other information handling systems. The information handling system operating system
identification module 66 may communicate with other information handling systems by any
suitable means of communication. Suitable means of communication may be, but is not
limited to, any form of wireless communication and any form of cable communication. In
examples, system identification module 66 may operate as one of many software programs,
communicating with other software programs within the same information handling system.
The system identification module 66 may automatically identify and calibrate the drilling
process dynamics model and the drill path model based on survey/logging, surface inputs
(hook load, torque), and real-time MWD data. System identification module 66 aims at
modeling the drilling path/dynamics as a function of the surface inputs, bit wear, and rock
mechanics, which can be calibrated by surveys and real-time MWD data. Updating the
model may be performed in real time during drilling and the updated model may be adopted
in optimization function 68.
[0022] Optimization function 68 may take into account the measured/estimated bit
position and compare it to the current path plan. A future drilling path may be predicted
using the model created by system identification module 66. When a deviation is detected in
the drilling path, optimization function 68 may update/recalculate the best path to reach a
target area 92. Optimization function 68 may function separate and apart from system
identification module 66 or optimization function 68 may be part of system identification
module 66. An information handling system may run and support optimization function 68
and system identification module 66. Or, in further examples, optimization function 68 may
operate an information handling system which may be separate and apart from another
handling system operating system identification module 66. Both information handling
systems may communicate with each other by any suitable means of communication.
Suitable means of communication may be, but is not limited to, any form of wireless
communication and any form of cable communication. The path chosen by optimization
function 68 may be constrained by the user to take into account specific underground
formations, surface operations, and/or anti-collision requirements. Furthermore,
optimization function 68 may calculate the optimal starting point to maneuver a bit (such as
drill bit 14 shown on Figure 1A), the optimal entry angle to formations, the optimal dogleg
severity/length of turn section, and the optimal surface operation inputs, such as hookload,
torque, and pump rate. Taking into account the constraints, a hybrid cost function may be
constructed as a weighted summation of various optimization merits. The cost function may
be defined as below,
Cost a2 d
2 - a wb
2 - a4wRSS
2 + a - a u2 + 7h
+ a (Quantified path geometry) 2]
wherein
u = surface inputs
ROP = Rate of Penetration
rd = energy dissipation ratio
wb = bit wear
w rss = wear of the rotary sterrable system
hole cleaning efficiency volume of chips removed
ROP
, 2, a3, ... = the weighted value of each cost
[0023] Quantified Path Geometry may include, but is not limited to, path costs
that user desires. For example, the user may want to have the least deviation from the
planned path or have the path such that it involves least number of turns (e.g., longest
possible hold sections) or have lowest dogleg severity or a combination of these. For
example, an equation that may be used to have the least deviation may be defined as follows:
Cost = f(plan ora (N, E,H - plannew N,E,H 2 dH
where, N,E,Hrepresent North, East and Height respectively and planorg and plannew are
the original plan and the updated plan.
[0024] An example of an equation involving the least number of turns (i.e., more
hold sections) may be defined as follows:
Cost2 = j CL oid
where, is the course length of the hold section.
[0025] The optimization of the cost function may take several constraints into
account. For example, the input u may have physical limitations that become a set of
constraints on the optimization. The constraints may also be user defined, for example
specifying upper and lower thresholds to dogleg severity or turn rate. Information used to
update the model in system identification module 66 or optimization function 68 may be
received from slow time scale downhole survey/logging 78 or from a fast time scale
implementation 64.
[0026] During drilling, the bit position may be estimated from the WD data
through an observer algorithm through fast time scale implementation 64. Fast time scale
implementation 64 may function using sensors on drilling system 2 to send information to
automated drilling program 60, which may allow automated drilling program 60 to alter the
drilling path quickly. Comparing the estimated bit position (may be represented using north,
east, and height - "NEH") with the profile derived by optimization function 68, the desired
drilling/maneuvering parameters at the current bit position may be found. The looked-up
maneuvering parameters may then be automatically implemented through a local controller
82 (e.g., Figure 2), while the drilling operation parameters are transmitted to the surface. As
only few drilling parameters may be transmitted, a very limited bandwidth may be used. The
transmission delay may be compensated by the prediction of the bit position. Bit position
may be predicted using a drilling process model. The model may be physics based, statistics
based or a combination of both. Alterations to the model using information provided by fast
time scale implementation 64 may automatically update the direction of automated drilling
program 60, placing automated drilling program 60 on an optimized path to reach a
designated target area, such as designated target area 92 discussed below with reference to
Figure 6. Optimizing a path may occur when a path deviation is detected or when a reoptimization
command is received. System identification module 66 may take the
information obtained by fast time scale implementation 64 and identify the real drill path
model. Optimizing using the identified drill path model may be repeated adaptively with the
previous steps, until the automated drilling program 60 reaches its target area. Optimization
of the drill path model may be done automatically using computer/controller 38 (e.g., Figure
1A), which may significantly reduce the costs associated with drilling.
[0027] Figure 2 illustrates a detailed schematic drawing of the example automated
drilling program 60. As described above, automated drilling program 60 may function using
system identification module 66, an optimization function 68, and a fast time scale
implementation 64. Initially a desired drilling path may be entered into computer/control 38
(e.g., Figure 1). Computer/control 38 may identify the model of the real drilling
path/dynamics using automated drilling program 60. Automated drilling program 60 may
optimize a desired drilling path based on the identified model, the original desired path and
the constraints entered into computer/controller 38. The optimized path may be
automatically programed into drilling system 2 to drill below the earth's surface. Automated
drilling program 60 may further automatically calibrate the drilling path/dynamics model to
match the real drilling path/process. During drilling, the path may deviate from the original
planned path, which automated drilling program 60 may automatically detect. An observer
may function to predict the position of the bit and the drilling path. Automated drilling
program 60 may then optimize the drilling path based on the calibrated model and the
predicted path, to reach the target area without using additional resources.
[0028] Automated drilling program 60 may process drilling data in real-time, allowing for
an immediate and real-time correction to the drilling path. Properly processing information
in real-time may require automated drilling program 60 to be partitioned into two distinct
time scales. A slow time scale 62 which may operate in semi-real-time and a fast time
scale 64 which may operate in real-time. For example, slow time scale 62 may update
every thirty feet of drilling and fast time scale 64 may update every one foot of drilling. It
should be noted that these depths are arbitrary and may change based on a user's
requirements or available drilling equipment. n general, the fast time scale 64 updates at a
faster rate than the slow time scale 62. Furthermore, depth of drilling may be replaced by
time periods. For example, slow time scale 62 may update every ten seconds and fast time
scale 64 may update ever second. Times and depths at which automated drilling program
60 updates may be arbitrary and base upon underground formations, user knowledge of the
area, and current drilling operations.
[0029] During drilling operations, slow time scale 62 may comprise a variety of functions
that act as both inputs and outputs to optimized drilling operations. Slow time scale 62
may obtain measurements from sensors, not illustrated, around or within drilling system 2.
With additional reference to Figure 1A, these measurements may be communicated to the
surface or taken when drill stem 12 is removed from borehole 6 for maintenance.
Individual functions found in slow time scale 62 may comprise system identification
module 66, optimization function 68, surface control 74, model evaluation/residue
estimation 76, and logging/survey 78. When beginning drilling operations, a user may
identify a path for drilling system 2 to follow. In other examples, a target may be identified
by the user and the path may be designed by automated drilling program 60. The chosen
path may be placed as an input into computer/controller 38 (e.g., Figure 1), which may
model the path using system identification module 66. System identification module 66,
during drilling operations, may further update the drilling path/dynamics model. However,
at the beginning of drilling operations, the drilling model produced by system identification
module 66 may be transferred to drilling system 2, which may begin drilling operations.
During drilling operations, system identification module 66 may constantly receive inputs
from logging/survey 78, MWD/observer 84, surface control 74, and model
evaluation/residue estimation 76. These inputs may be used to automatically calibrate and
alter the drill path, drill path model and/or dynamics model. For example, surface
operation inputs comprising information regarding the dogleg severity, tool face, and bit
walk rate may be used to update the drilling model. Bit walk rate may be a function of the
formation, bit type and wear, path orientation, surface inputs, and bottomhole assembly
("BHA") dynamics. Furthermore, surface operation inputs may comprise bit dynamics,
vibration and position of the bit, bit ware, and the rock mechanics. System identification
module 66 aims at automatically modeling and calibrating the drilling path/dynamics as a
function of the surface inputs, bit ware, and rock mechanics. With additional reference to
Figure A, these inputs may update the original model to replicate the location of drilling
system 2 within the earth's surface and it's relation to the originally modeled path. The
information may be evaluated by model evaluation/residue estimation 76 to determine
acceptability of drilling system 2 current position and originally modeled path.
[0030] Model evaluation/residue estimation 76 may calculate the error between predictions
of states estimated by the newly identified model and compare it to inputs received from
MWD/observer 84 and logging survey 78. Inputs comprising of downhole tool position,
orientation, acceleration, formation data, and other like information may be used to
determine residue. A residue, or error rate, may be produced.
[003 1] Optimization function 68 may be divided into two separate functions, a drilling
path prediction 72 and a path optimization 70. Drilling path prediction 72 may compare
inputs from logging/survey 78 and outputs from path optimization 70. Both may be used to
calibrate the drilling path. The predicted drilling path may provide information such as
estimated speed, estimated revolutions per minute (RP ), estimated weight on bit (WOB),
and predicted direction. Sensors, not pictured may be used to obtain information needed to
determine RPM, WOB, and direction of bit 14. This information may be sent to path
optimization 70. Path optimization 70 may take inputs from surface control 74 and
logging/survey 78 to produce and/or update an optimized path based of the predicted
drilling path and selected target area 92. Design of an optimized path may also take into
account constraints from surface control 74.
[0032] Illustrated in Figure 3 is a graphical representation of the operating constraints
placed upon drilling system 2. Constraints placed upon drilling system 2 may be, and not
limited to, RPM, WOB, and total vertical depth (TVD) of the drill bit ranges in which
drilling system 2 may operate. Together they may form an operational space 86, as
illustrated in Figure 3. Operational space 86 may prevent excessive wear, vibrations, or
failure of drilling system 2. To optimize the drilling path to reach target area 92, path
optimization 70 may design optimal path constrained by the operational space 86. For
example, if drilling system 2 has a TVD of one hundred feet with one hundred and fifty
pounds WOB, surface control 74 may choose from the appropriate RPM within operational
space 86 using the graph in Figure 3. Information regarding a drilling system's 2 RPM,
WOB, and TVD are may be provided by sensors around drilling system 2. Information
may be sent from the sensors to surface control 74. Referring back to Figure 2, surface
control 74 may distribute the sensor information to system identification module 66 and/or
path optimization 70. This information, as described above, may optimize and/or update
the path of drilling system 2.
[0033] Once a path has been optimized, path optimization 70 may transfer the optimized
path to fast time scale 64 functions. Fast time scale 64 functions may comprise a plan
profile lookup table 80, a local controller 82, and a MWD/observer 84. Plan profile lookup
table 80 may receive the optimized path from path optimization 70 and further may receive
information from MWD/observer 84 as to the position of bit 14. The bit position and
optimized path may be compared and the maneuvering parameters used to place bit 14
along the optimized path may then be transferred to local controller 82. Furthermore, plan
profile lookup table 80 may update and/or add drilling parameters to surface control 74.
These may change operational space 86 produced by surface control 74, which may further
optimize the drilling path through each optimization of the drill path.
[0034] Local controller 82 may control the drilling direction of drilling system 2.
Receiving input from plan profile lookup table 80, local controller 82 may maneuver
drilling system 2 along the optimized path. Feedback from sensors along the drill system 2
may be fed to local controller 82, allowing local controller 82 to maneuver drilling system
2 along the optimized path. The direction, location, speed, RPM, WOB, and TVD may be
recorded and updated, accordingly, by WD/observer 84 and logging/survey 78. All
updated information may be recycled through automated drilling program 60, allowing
automated drilling program 60 to continuously optimize the drilling path on its way to
target area 92. Optimization may allow automated drilling program 60 to reduce cost, time,
material, and error in drilling.
[0035] How cost is reduced in drilling may further be illustrated in Figure 4. Figure 4
illustrates a planar perspective of a chosen drill path and an actual drill path, the actual drill
path being performed by current methods using a human operator. The current system of
drilling may require human operators with years of experience to guide drilling system 2
along selected path 88 to target area 92. As drilling system 2 shifts and moves due to
formation changes, downhole vibrations and the rotation of the drill bit, an operator must
manually move drill bit 4 back onto selected path 88. Experience plays a large role in the
ability of an operator to successfully guide drilling system 2 back along selected path 88.
Figure 4 illustrates a manually drilled path 90 with selected path 88. As illustrated,
manually drilled path 90 may be erratic and filled with many twists and turns as the human
operator tries to maneuver drilling system 2 back on selected path 88. Twist and turns adds
length to the wellbore, increasing cost and time to reach target area 92. While manually
drilled path 90 may not be as erratic as others, manually drilled path 90 may tend to have
more corrections on the way to target area 92. It should be understood that the manually
drilled path 90 shown on Figure 4 is hypothetical but is provided to illustrate the difficulty
in successfully guiding drilling system 2 along the selected path 88.
[0036] Figure 5 illustrates a path optimization case with the objective of a path with least
turning effort/maneuvering frequency. Figures 5A and 5B illustrate automated drilling
program 60 as it guides drilling system 2 (e.g., Figure 1) along selected path 88 to target
area 92. Automated path 94 illustrates the drilling direction of drilling system 2 as
controlled by automated drilling program 60. n Figure 5A, automated path 94 starts to
deviate from selected path 88. Due to the deviation, automated drilling program 60 may
optimize a first optimized path 96 in which drilling system 2 may take to get to target area
92. As drilling system 2 moves along the first optimized path 96, automated drilling
program 60 optimizes the drill path again, based on current conditions and parameters. As
illustrated in Figure 5B, second optimized path 98 is produced and modeled from the
optimization of automated drilling program 60. Drill system 2 may then be guided to the
second optimized path 98 using automated drilling program 60. Second optimized path 98
may be used as a final path to target area 92. The optimization of selected path 88 by
automated drill system 60 may happen many times during drilling. Optimization leads to a
reduction in cost, time, and material used to reach target area 92.
[0037] A method of operating an automated drilling program may comprise drilling to a
target location along a drill path, updating a drilling path module based at least on data
obtained during the step of drilling to the target location, creating a modified drill path to
the target location based on at least the drilling path model in real-time as the step of
drilling to the target location along the drill path is being performed, and drilling to the
target location along the modified drill path. The method may further comprise creating a
modified drill path bound by an operational space. The operational space may be
constrained by factors including, but not limited by, weight on bit, revolutions per minute,
and total vertical depth. The method may further comprise comparing the drill path to an
original drill path. The step of comparing the drill path to the original drill may produce an
error. A modified drill path may be created if the error exceeds a predetermined value. The
steps of updating a drill path model and creating a modified drill path may be repeated
continuously while drilling to the target location. The modified drill path may be created
based on a current position of a drill bit as compared to where the drill bit should be on the
original drill path.
[0038] An automated drilling system may comprise a drilling assembly, wherein the
drilling assembly may comprise a drilling rig, a drill stem, or a drill bit. The automated
drilling system may further comprise an information handling system coupled to the
drilling assembly, the information handling system may comprise an automated drilling
program that may be configured to update a drilling path model based at least on data
obtained from the drilling assembly, and create a modified drill path to a target location
based at least on the drilling path model in real-time as the drilling assembly is drilling to
the target location. The drilling path model may comprise an optimization function that
includes a drilling path prediction function and a path optimization function. The drilling
path prediction function may compare inputs from a logging and/or a survey or outputs
form the path optimization. The drilling path prediction function may provide information
regarding speed of the drill bit, revolutions per minute of the drill bit, weight on bit, or
direction of the bit. The drilling assembly may further comprise sensors communicatively
coupled to the information handling system. The automated drilling program may
comprise at least one of a model evaluation function, a system identification module, a
surface control function, a logging function, or an optimization function. The optimization
function may comprise a path optimization function or a drilling path prediction function.
The drilling path prediction function may use a plurality of sensors on the drill assembly to
establish where location of the drill bit of the drill assembly. The drilling path prediction
function may model a new path based on a current position of the drill bit as compared to
where the drill bit may be on the original modeled path, where the path optimization may
be bound by an operational space. The operational space may comprise weight on bit,
revolutions per minute, or total vertical depth. The optimization function may calculate an
optimal path to the target location that includes an optimal starting point to maneuver the
drill bit of the drill assembly. The system may further comprise a local controller that may
control the drill stem and guide the drill bit to a target area based on the drilling path
model.
[0039] Therefore, the present invention is well adapted to attain the ends and advantages
mentioned as well as those that are inherent therein. The particular examples disclosed
above are illustrative only, as the present invention may be modified and practiced in
different but equivalent manners apparent to those skilled in the art having the benefit of
the teachings herein. Although individual examples are discussed, the invention covers all
combinations of all those examples. Furthermore, no limitations are intended to the details
of construction or design herein shown, other than as described in the claims below. It is
therefore evident that the particular illustrative examples disclosed above may be altered or
modified and all such variations are considered within the scope and spirit of the present
invention. All numbers and ranges disclosed above may vary by some amount. Whenever
a numerical range with a lower limit and an upper limit is disclosed, any number and any
included range falling within the range are specifically disclosed. Moreover, the indefinite
articles "a" or "an," as used in the claims, are defined herein to mean one or more than one
of the element that it introduces. Also, the terms in the claims have their plain, ordinary
meaning unless otherwise explicitly and clearly defined by the patentee. If there is any
conflict in the usages of a word or term in this specification and one or more patent or other
documents that may be incorporated herein by reference, the definitions that are consistent
with this specification should be adopted for the purposes of understanding this invention.

Claims
What is claimed is:
. A method for operation of an automated drilling program comprising:
drilling to a target location along a drill path;
updating a drilling path model based at least on data obtained during the step
of drilling to the target location;
creating a modified drill path to the target location based on at least the
drilling path model in real-time as the step of drilling to the target location along the drill
path is being performed; and
drilling to the target location along the modified drill path.
2. A method according to claim 1, wherein creating a modified drill path is
bound by an operational space.
3. A method according to claim 2, wherein the operational space uses
constraints comprising weight on bit, revolutions per minute, and total vertical depth.
4. A method according to any preceding claim, further comprising comparing
the drill path to an original drill path.
5. A method according to claim 4, wherein the comparing the drill path to the
original drill path produces an error.
6. A method according to claim 5, wherein the modified drill path is created if
the error exceeds a predetermined value.
7. A method according to any preceding claim, wherein the steps of updating a
drill path model and creating a modified drill path are repeated continuously while drilling to
the target location.
8. A method according to any preceding claim, wherein the modified drill path
is created based on a current position of a drill bit as compared to where the drill bit should
be on the original drill path.
9. An automated drilling system comprising:
a drilling assembly, wherein the drilling assembly comprises a drilling rig, a
drill stem, and a drill bit; and
an information handling system coupled to the drilling assembly, wherein the
information handling system comprises an automated drilling program that is configured to
update a drilling path model based at least on data obtained from the drilling assembly, and
create a modified drill path to a target location based at least on the drilling path model in
real-time as the drilling assembly is drilling to the target location.
9. A system according to claim 8, wherein the drilling path model comprises an
optimization function that includes a drilling path prediction function and a path
optimization function.
0. A system according to claim 9, wherein the drilling path prediction function
compares inputs from a logging and/or a survey and outputs from the path optimization.
11. A system according to claim 9 or claim 10, wherein the drilling path
prediction function provides information regarding speed of the drill bit, revolutions per
minute of the drill bit, weight on bit, and direction of the bit.
12. A system according to any one of claims 9 to 12, wherein the drilling
assembly further comprises sensors communicatively coupled to the information handling
system.
14. A system according to any one of claims 9 to 13, wherein the automated
drilling program comprises at least one of a model evaluation function, a system
identification module, a surface control function, a logging function, or an optimization
function.
5. A system according to claim 14, wherein the optimization function comprises
a path optimization function and a drilling path prediction function.
6. A system according to claim , wherein the drilling path prediction function
uses a plurality of sensors on the drill assembly to establish where location of the drill bit of
the drill assembly.
7. A system according to claim 5, wherein the drilling path prediction function
models a new path based on a current position of the drill bit as compared to where the drill
bit should be on the original modeled path, wherein path optimization is bound by an
operational space.
18. A system according to claim 17, wherein the operational space comprises
weight on bit, revolutions per minute, and total vertical depth.
19. A system according to any one of claims 4 to 8, wherein the optimization
function calculates an optimal path to the target location that includes an optimal starting
point to maneuver the drill bit of the drill assembly.
20. A system according to any one of claims 9 to 19, further comprising a local
controller that controls the drill stem and guides the drill bit to a target area based on the
drilling path model.