U.S. patent application number 16/019033 was filed with the patent office on 2018-12-27 for control of drilling system operations based on drill bit mechanics.
The applicant listed for this patent is Fracture ID, Inc.. Invention is credited to James D. Lakings, Kevin J. Morgan, R. Christopher Neale.
Application Number | 20180371901 16/019033 |
Document ID | / |
Family ID | 64692069 |
Filed Date | 2018-12-27 |
United States Patent
Application |
20180371901 |
Kind Code |
A1 |
Lakings; James D. ; et
al. |
December 27, 2018 |
CONTROL OF DRILLING SYSTEM OPERATIONS BASED ON DRILL BIT
MECHANICS
Abstract
Implementations described and claimed herein are directed to
systems and methods for controlling operations of a drilling system
based on drill bit mechanics. During a drilling operation, sensor
signals corresponding to mechanics of a drill bit are collected and
processed to generate drill bit mechanics data and corresponding
mechanical rock property data. A drilling measurement system is
then operated based on whether the rock property data indicates the
drill bit is actively engaged with or disengaged from a
subterranean formation. The mechanical rock property data may also
be used to detect characteristics of the subterranean formation and
to control the drilling system based on the presence and/or nature
of the characteristics.
Inventors: |
Lakings; James D.;
(Evergreen, CO) ; Morgan; Kevin J.; (Westminster,
CO) ; Neale; R. Christopher; (Denver, CO) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Fracture ID, Inc. |
Denver |
CO |
US |
|
|
Family ID: |
64692069 |
Appl. No.: |
16/019033 |
Filed: |
June 26, 2018 |
Related U.S. Patent Documents
|
|
|
|
|
|
Application
Number |
Filing Date |
Patent Number |
|
|
62525009 |
Jun 26, 2017 |
|
|
|
Current U.S.
Class: |
1/1 |
Current CPC
Class: |
E21B 7/06 20130101; E21B
44/00 20130101; E21B 47/18 20130101; E21B 49/003 20130101 |
International
Class: |
E21B 49/00 20060101
E21B049/00; E21B 7/06 20060101 E21B007/06; E21B 44/00 20060101
E21B044/00; E21B 47/18 20060101 E21B047/18 |
Claims
1. A method of controlling a drilling measurement system during a
drilling operation to form a wellbore in a subterranean formation
using a drill bit, the method comprising: receiving sensor signals
corresponding to mechanics of the drill bit from one or more
sensors; processing the sensor signals to generate drill bit
mechanics data; and operating the drilling measurement system in a
first mode when the drilling measurement system determines, based
on the drill bit mechanics data, that the drill bit is actively
engaged with the subterranean formation, wherein in the first mode
the drilling measurement system at least one of transmits drilling
data to a remote receiver and stores drilling data in
non-transitory memory of the drilling measurement system, the
drilling data including at least one of the drill bit mechanics
data and mechanical rock property values derived from the drill bit
mechanics data.
2. The method of claim 1, further comprising: operating the
drilling measurement system in a second mode when the drilling
measurement system determines, based on the drill bit mechanics
data, that the drill bit is disengaged from the subterranean
formation, wherein in the second mode the drilling measurement
system deactivates functionality corresponding to at least one of
transmitting the drilling data to a remote and storing the drilling
data in the non-transitory memory of the drilling measurement
system.
3. The method of claim 1, wherein in the first mode the drilling
measurement system transmits the drilling data to a remote receiver
using mud pulse telemetry.
4. The method of claim 1, wherein in the first mode, the drilling
measurement system transmits the drilling data to a mud pulser
using a short hop wireless communication protocol for transmission
to the remote receiver.
5. The method of claim 1, wherein operating in the first mode
further comprises: transmitting at least a portion of the drill bit
mechanics data to a digital signal processing (DSP) module; and
transforming the drill bit mechanics data, using the DSP module,
from a time domain format to a frequency domain format.
6. The method of claim 1, further comprising transitioning from the
second mode to the first mode in response to determining the drill
bit is actively engaged with the subterranean formation, wherein
transitioning from the second mode to the first mode includes
energizing at least one of a memory module including the
non-transitory memory, a digital signal processing (DSP) module
configured to transform the drill bit mechanics data from a time
domain format to a frequency domain format, and an interface module
for transmitting the drilling data to the remote receiver.
7. The method of claim 1, further comprising transitioning from the
first mode to the second mode in response to determining the drill
bit is disengaged from the subterranean formation, wherein
transitioning from the first mode to the second mode includes
deenergizing at least one of a memory module including the
non-transitory memory, a digital signal processing (DSP) module
configured to transform the drill bit mechanics data from a time
domain format to a frequency domain format, and an interface module
for transmitting the drilling data to the remote receiver.
8. The method of claim 1, wherein the drilling measurement system
determines whether the drill bit is actively engaged with the
subterranean formation by: deriving a mechanical property value
from the drill bit mechanics data; and determining the mechanical
property value is within a predetermined range indicating active
engagement with the subterranean formation.
9. The method of claim 1, wherein the drill bit mechanics data
includes an axial acceleration of the drill bit and a lateral or
rotary acceleration of the drill bit.
10. A drilling measurement system configured to be disposed
adjacent a drill bit of a drill string, the drilling measurement
system comprising: one or more sensors configured to measure
mechanics of the drill bit during a drilling operation to form a
wellbore in a subterranean formation using the drill bit; an
acquisition module communicatively coupled to each of the one or
more sensors and the computer readable memory, wherein the
acquisition module is in communication with at least one first
tangible machine readable media including computer executable
instructions to perform the operations of: receiving sensor signals
corresponding to mechanics of the drill bit from the one or more
sensors; and processing the sensors signals to generate drill bit
mechanics data; and a control module in communication with the
acquisition module that selectively activates one or more functions
of the drilling measurement system based on whether the drill bit
mechanics data indicates that the drill bit is one of actively
engaged with the subterranean formation and disengaged from the
subterranean formation.
11. The drilling measurement system of claim 10, wherein the first
tangible machine readable media further includes computer
executable instructions to perform the operation of: deriving a
mechanical rock property value from the drill bit mechanics data,
wherein determining the drill bit mechanics data indicates the
drill bit is actively engaged with the subterranean formation
includes determining the mechanical rock property value is within a
predetermined range and determining the drill bit mechanics data
indicates the drill bit is disengaged from the subterranean
formation includes determining the mechanical rock property value
is outside the predetermined range.
12. The apparatus of claim 10, wherein the sensor signals
correspond to an axial acceleration of the drill bit and a lateral
or rotary acceleration of the drill bit.
13. The drilling measurement system of claim 10 further comprising:
at least one of a communication module, a memory module, and a
digital signal processing (DSP) module communicatively coupled to
the control module, wherein the control module is in communication
with at least one second tangible machine readable media including
computer executable instructions to perform the operations of
activating the at least one of the communication module, the memory
module, and the digital signal processing (DSP) module in response
to the drill bit being actively engaged with the subterranean
formation.
14. The drilling measurement system of claim 13, wherein the second
tangible machine readable media further includes computer
executable instructions to perform the operations of deactivating
the at least one of the communication module, the memory module,
and the digital signal processing (DSP) module in response to the
drill bit being disengaged from the subterranean formation.
15. The drilling measurement system of claim 13, wherein the
drilling measurement system comprises the communication module and,
when activated, the communication module transmits drilling data to
a remote receiver, the drilling data including at least one of the
drill bit mechanics data and mechanical property values of the
subterranean formation derived from the drill bit mechanics
data.
16. The drilling measurement system of claim 15, wherein: the
communication module is communicatively coupleable to a mud pulser
for communication of the drilling data to the remote receiver using
mud pulse telemetry, and the communication module is configured to
transmit the drilling data to the mud pulser using a short hop
communication protocol.
17. The drilling measurement system of claim 13, wherein the
drilling measurement system comprises the memory module and, when
activated, the memory module stores drilling data, the drilling
data including at least one of the drill bit mechanics data and
mechanical property values of the subterranean formation derived
from the drill bit mechanics data.
18. The drilling measurement system of claim 13, wherein the
drilling measurement system comprises the DSP module, the DSP
module communicatively coupled to the one or more accelerometers
and, when activated, the DSP module receives time-domain drill bit
mechanics data from the acquisition module and converts the
time-domain drill bit mechanics data into frequency-domain drill
bit mechanics data.
19. An acquisition unit for use in a drilling measurement system
configured to be coupled to a drill string, the drill string
including a drill bit, the acquisition unit communicatively
coupleable to one or more sensors, the acquisition module
comprising: at least one processor; and at least one tangible
machine readable media communicatively coupled to the at least one
processor, the at least one tangible machine readable media
including computer executable instructions that, when executed by
the at least one processor, perform the operations of: receiving
sensor signals corresponding to mechanics of the drill bit from the
one or more sensors; processing the sensor signals to generate
drill bit mechanics data; and determining a drilling state based on
the drill bit mechanics data, the drilling state corresponding to
whether the drill bit is actively engaged with the subterranean
formation or disengaged from the subterranean formation; and
updating a drilling state variable in accordance with the drilling
state.
20. The acquisition unit of claim 19, wherein the sensor signals
correspond to an axial acceleration of the drill bit and a lateral
or rotary acceleration of the drill bit.
21. The acquisition unit of claim 20, further comprising at least
one integrator communicatively coupled to the at least one
processor, the at least one integrator configured to derive at
least one of an axial velocity of the drill bit, a lateral velocity
of the drill bit, a rotary velocity of the drill bit, an axial
displacement of the drill bit, a lateral displacement of the drill
bit, and a rotary displacement of the drill bit from the sensor
signals.
22. The acquisition unit of claim 20, wherein determining the
drilling state includes obtaining the root mean square of drill bit
mechanics data corresponding to the axial acceleration of the drill
bit and the root mean square of drill bit mechanics data
corresponding to the lateral or rotary acceleration of the drill
bit.
23. The acquisition unit of claim 19, wherein determining the
drilling state includes: deriving a mechanical property value from
the drill bit mechanics data; determining the drill bit is actively
engaged with the subterranean formation when the mechanical
property value is within a predetermined range; and determining the
drill bit is disengaged from the subterranean formation when the
mechanical property is outside the predetermined range.
24. The acquisition unit of claim 23, wherein the mechanical
property value is at least one of Poisson's ratio and Young's
Modulus of Elasticity.
25. The acquisition unit of claim 19, further comprising an
amplifier communicatively coupled to the at least one processor,
wherein determining the drilling state includes amplifying the
sensor signals using the amplifier.
26. The acquisition unit of claim 19, further comprising at least
one filter communicatively coupled to the at least one processor,
wherein determining the drilling state includes at least one of
low-pass filtering, high-pass filtering, and band-pass filtering
one of the sensor signals or a secondary signal derived from the
sensor signals using the at least one filter.
27. The acquisition unit of claim 19 further comprising at least
one analog-to-digital converter communicatively coupled to the at
least one processor, wherein the sensor signals are analog signals
and determining the drilling state includes converting the sensor
signals or a secondary signal derived from the sensor signals into
a digital signal using the analog-to-digital converter.
28. The acquisition unit of claim 19 further comprising a decimator
communicatively coupled to the at least one processor, wherein the
sensor signals are an analog signal and determining the drilling
state includes decimating a digital signal derived from the sensor
signals using the decimator.
29. The acquisition unit of claim 19, wherein the drilling state
variable is stored in at least one of the at least one tangible
machine readable media and a remote memory communicatively coupled
to the acquisition module.
30. A method of controlling a drilling system during a drilling
operation to form a wellbore in a subterranean formation using a
drill bit, the method comprising: receiving sensor signals
corresponding to mechanics of the drill bit from one or more
sensors; processing the sensor signals to generate drill bit
mechanics data; deriving mechanical rock property data from the
drill bit mechanics data; identifying a characteristic of the
subterranean formation based on the mechanical rock property data;
and in response to identifying the characteristics of the
subterranean formation, modifying an operational parameter of the
drilling system to change a drilling system behavior.
31. The method of claim 30, wherein the characteristic of the
subterranean formation is a geological feature of the subterranean
formation.
32. The method of claim 31, wherein the geological feature includes
at least one of a fracture, a boundary, a bedding plane, or a
discontinuity within the subterranean formation.
33. The method of claim 30, wherein modifying the operational
parameter of the drilling system includes modifying a direction of
the drill bit.
34. The method of claim 33, wherein modifying the direction of the
drill bit includes rotating a bent sub coupled to the drill
bit.
35. The method of claim 33, wherein the characteristic of the
subterranean formation is a geological feature of the subterranean
formation and the direction of the drill bit is modified to
maintain the drill bit at a predetermined distance relative to the
geological feature.
36. The method of claim 33, wherein the characteristic of the
subterranean formation is a geological feature of the subterranean
formation and the direction of the drill bit is modified to
maintain the drill bit at a predetermined orientation relative to
the geological feature.
37. The method of claim 30, wherein modifying the operational
parameter includes modifying a rotational rate of at least one of
the drill bit and a top drive of the drilling system.
38. The method of claim 30, wherein modifying the operational
parameter includes changing between a rotational drilling mode in
which each of a downhole motor and a top drive of the drilling
system rotate and a slide drilling mode in which the top drive does
not rotate.
37. The method of claim 30, wherein identifying the characteristic
of the subterranean formation includes predicting a bias to which
the drill bit will be subjected to when drilling through the
formation.
38. The method of claim 37, wherein modifying the operational
parameter includes modifying a direction of the drill bit to offset
the bias.
39. The method of claim 30, wherein the characteristics of the
subterranean formation is a susceptibility of the subterranean
formation to a fracturing operation, the method further comprising
at least one of modifying or supplementing the mechanical rock
property data to include an identifier indicating the
susceptibility.
40. The method of claim 30, wherein modifying the operational
parameter of the drilling system includes stopping a drilling
operation.
41. The method of claim 31 further comprising, in response to
identifying the formation property, generating a message and
transmitting the message to a remote computing device.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] This application is related to and claims priority under 35
U.S.C. .sctn. 119(e) from U.S. Patent Application No. 62/525,009,
filed Jun. 26, 2017 entitled "CONTROL OF DRILLING MEASUREMENT
SYSTEM OPERATIONS BASED ON DRILL BIT MECHANICS," the entire
contents of which is incorporated herein by reference for all
purposes.
TECHNICAL FIELD
[0002] The present disclosure involves control of drilling systems,
including control of drilling system behavior, during drilling
operations and, more specifically, control of drilling systems and
drilling system behavior based on drill bit mechanics measured
during drilling operations.
BACKGROUND
[0003] The production of hydrocarbons (oil or gas) can be generally
distilled into two primary steps: drilling a borehole in a
subterranean formation to intersect hydrocarbon bearing formations
or oil and gas reservoirs in the formation, and then completing the
well in order to flow the hydrocarbons back to the surface. The
ability of a well to flow hydrocarbons that are commercially
significant requires that the borehole be connected to oil and gas
bearing formations with sufficient permeability to support the flow
rates that are needed to account for the costs of developing the
field. In many instances, however, commercially viable flow rates
cannot be obtained without the use of various advancements
including horizontal drilling and hydraulic stimulation due to the
type of formation or reservoir being developed.
[0004] More specifically, unconventional resource plays are areas
where significant volumes of hydrocarbons are held in reservoirs
with low primary permeability (generally in the nanodarcy to
microdarcy range) and low primary porosity (generally 2-15%) such
as shales, chalks, marls, and cemented sandstones that generally do
not have sufficient primary permeability to yield commercial
quantities of hydrocarbons. Compared to "conventional" reservoirs,
unconventional reservoirs have a much lower hydrocarbon density per
unit volume of rock and much lower unstimulated hydrocarbon flow
rates, making commercial development impossible without hydraulic
stimulation of the reservoir rock fabric. Fortunately,
unconventional reservoirs are often regionally extensive, covering
thousands of square miles and containing billions of barrel of oil
equivalent (BOE) of potentially recoverable hydrocarbons.
[0005] The economically viable production from unconventional
resources has only been made possible by the improvement and
combination of horizontal drilling, wellbore isolation, and
hydraulic fracture stimulation treatment technologies, among other
techniques. Generally speaking, horizontal drilling involves first
vertically drilling down close to the top of the unconventional
reservoir and then using directional drilling tools to change the
orientation of the wellbore from vertical to horizontal in order to
contact greater areas of the reservoir per well. The term
"horizontal" drilling as used herein is meant to refer to any form
of directional (non-vertical) drilling. Horizontal drilling,
although having been performed for many decades prior to intensive
unconventional resource development in the early 2000's, has
evolved to provide cost effective provisioning of the long
horizontal borehole sections (including sections ranging from
5,000' to over 10,000') required to contact commercially viable
volumes of hydrocarbon bearing reservoir rock. Hydraulic fracture
stimulation involves pumping high volumes of pressurized fluid into
the borehole and into perforations extending from the wellbore into
the adjacent formation. The pressure of the fluid creates large
networks of cracks (fractures) in the formation that create
enhanced reservoir permeability and so stimulate greater quantities
of oil and gas production. Proppant is usually pumped along with
the fluid to fill the fractures so permeability is maintained after
the pumping is stopped and the fractures close due to reservoir
stresses. Proppant can range from simple quarried sand to
engineered man-made materials.
[0006] Isolation generally involves the use of some form of
technology to focus where fracturing occurs at specific locations
along the well bore rather than stimulating the entire length of an
open wellbore. In the development of unconventional resources it is
desirable to drill horizontal wells perpendicular to the direction
of maximum horizontal compressive stress, because hydraulically
induced fractures will grow primarily in the direction of maximum
horizontal stress. When the wellbore is oriented perpendicular to
the maximum horizontal compressive stress, this geometry allows for
the shortest, and hence least expensive, well bore length for the
volume of reservoir stimulated.
[0007] Rapidly evolving wellbore isolations techniques, such as
swellable packers, sliding sleeves, and perforation cluster
diversion have all assisted in reducing the cost of isolating
sections of the wellbore for more targeted and more concentrated
hydraulic stimulation. Hydraulic fracture stimulation has been
utilized on low permeability wells for decades, as well. But the
use of low viscosity, simple fluids pumped in very high volumes and
rates, and with large volumes of associated proppant, has been the
most important aspect of contacting the greatest amount of low
permeability, low hydrocarbon density reservoir rock.
[0008] Various suites of drill string or wireline conveyed well
logs such as dipole sonic or natural fracture image logs can
identify and quantify this variability on a scale that is useful to
completions design, but existing tools are currently too expensive
to run on anything but a very small fraction of unconventional
wells drilled. Conventional techniques, such as dipole sonic and
natural fracture image logs, are based on inferred information and
do not involve direct measurement of the interaction of the drill
bit with the formation. Instead, dipole sonic involves the
transmission of acoustic signals (waves) from a controlled active
acoustic source, through the rock formation in the areas of the
well bore to a receiver typically several feet from the source, to
measure the velocity of the waves through the formation. Natural
fracture image logs involve measuring the resistivity of the
formation along the walls of the wellbore. Natural fracture logs
are of limited use in wells using oil based mud, which has an
inherently high resistivity and masks some fractures. These
techniques are often cost prohibitive and limited in effectiveness.
As a result, almost all wells are completed using geometrically
equal spacing of zones (referred to as stages) that are isolated
and stimulated. Thus, for example, hydraulic fracturing is
routinely and inadvertently performed on individual stages with
significantly varying rock properties along the isolated section,
which may result in failure to initiate fractures in less conducive
rock, potentially bypassing substantial volumes of hydrocarbon
bearing rock. In such instances, post stimulation testing of
individual zones or stages shows that a significant percentage of
the hydraulically stimulated zones are not contributing to
hydrocarbon production from the well. Variations in the density,
size and orientation of natural fractures can have a major
influence on overall well initial production, long term decline
rates, and stage-to-stage contributions. Formation hydrocarbons are
transported from the rock matrix to the producing wellbore through
some combination of induced hydraulic fractures and natural
occurring in-situ fractures.
[0009] Currently, less than 1% of all wells drilled and completed
have suitable data to adequately quantify reservoir heterogeneity
on a scale that can be used for targeting individual stimulation
intervals.
[0010] It is with these observations in mind, among others, that
aspects of the present disclosure have been conceived and
developed.
SUMMARY
[0011] Aspects of the present disclosure involve a method of
controlling drilling systems in relation to a drilling measurement
system during a drilling operation to form a wellbore in a
subterranean formation using a drill bit. The method includes
receiving sensor signals corresponding to mechanics of the drill
bit from one or more sensors and processing the signals to generate
drill bit mechanics data. The method further includes operating the
drilling measurement system in a first mode when the drilling
measurement system determines, based on the drill bit mechanics
data, that the drill bit is actively engaged with the subterranean
formation. In the first mode the drilling measurement system
transmits drilling data, which may include values of the drill bit
mechanics data and mechanical rock property values derived from the
drill bit mechanics data, to a remote receiver and/or stores
drilling data in non-transitory memory of the drilling measurement
system.
[0012] The mechanical rock property data obtained by the drilling
system may also be used to identify characteristics of the
surrounding subterranean formation. Such characteristics may
include, without limitation, one or more of properties of the
formation and the presence of fractures within the subterranean
formation. Such features may include, without limitation, rock
boundaries, bedding planes, or discontinuities. In certain
implementations, the characteristics may be used to identify
portions of the subterranean formation that may be particularly
susceptible to subsequent fracturing operations. In other
implementations, the characteristics may be used to control the
drilling system and, by controlling the drilling system, to
influence the drilling system behavior. For example, and without
limitation, such control may include modifying one or more of a
drilling direction, a rate of penetration, or a drilling mode
(e.g., slide drilling or rotational drilling) based on the
characteristics of the subterranean formation inferred from the
mechanical rock property data.
[0013] Another aspect of the present disclosure involves a drilling
measurement system configured to be disposed adjacent a drill bit
of a drill string. The drilling measurement systems includes one or
more sensors configured to measure mechanics of the drill bit
during a drilling operation to form a wellbore in a subterranean
formation using the drill bit. The drilling measurement system
further includes an acquisition module communicatively coupled to
the sensors. The acquisition module is also in communication with
at least one first tangible machine readable media that includes
computer executable instructions to perform various operations. The
operations include receiving sensor signals corresponding to
mechanics of the drill bit from the one or more sensors and
processing the sensor signals to generate drill bit mechanics data
The drilling measurement system further includes a control module
in communication with the acquisition module that selectively
activates one or more functions of the drilling measurement system
based on the drill bit mechanics data and, more specifically,
whether the drill bit mechanics data indicates the drill bit is
actively engaged with or disengaged from the subterranean
formation. In certain implementations, the control module may be
further adapted to identify characteristics of the formation and to
modify operation and behavior of a drilling system in response to
the formation characteristics. Such characteristics may include,
without limitation, the presence, location, and/or presence of
features within the formation or characteristics of the formation,
such as the susceptibility of the subterranean formation to
hydraulic fracture stimulation treatment operations.
[0014] Yet another aspect involves an acquisition module for use in
a drilling measurement system configured to be coupled to a drill
string, the drill string including a drill bit. The acquisition
module is communicatively coupleable to one or more sensors and
includes at least one processor and at least one tangible machine
readable media. The tangible machine readable media includes
computer executable instructions that, when executed by the at
least one processor, perform the operations of receiving sensor
signals corresponding to mechanics of the drill bit from the one or
more sensors, processing the sensor signals to generate drill bit
mechanics data; and determining a drilling state based on the drill
bit mechanics data. The drilling state corresponds to whether the
drill bit is actively engaged with the subterranean formation or
disengaged from the subterranean formation. When executed, the
computer executable instructions further perform the operation of
updating a drilling state variable in accordance with the drilling
state.
[0015] Another implementation involves an acquisition module for
use in controlling drilling system behavior. The acquisition module
is communicatively coupleable to one or more sensors and includes
at least one processor and at least one tangible machine readable
media. The tangible machine readable media includes computer
executable instructions that, when executed by the at least one
processor, perform the operations of receiving sensor signals
corresponding to mechanics of the drill bit from the one or more
sensors, processing the sensor signals to generate drill bit
mechanics data, and determining mechanical rock property values of
the formation within which the bit is currently engaged from the
mechanics of the drill bit. In certain implementations, the rock
property values indicate whether the drill bit is actively engaged
with or disengaged from the subterranean formation. The computer
executable instructions further perform the operation of updating a
drilling state variable in accordance with the drilling state with
respect to whether the formation is conducive to hydraulic fracture
stimulation treatment operations. In some implementations, the rock
property values may be used to infer characteristics of the
subterranean formation, including, without limitation, the presence
of fractures or other discontinuities within the formation. Based
on such characteristics, the acquisition module may, in certain
implementations, classify or identify portions of the subterranean
formation as being susceptible to hydraulic fracture stimulation
treatments or other stimulation operations.
[0016] Another implementation involves an acquisition module for
use in controlling a drilling system and, as a result of such
control, modifying behaviors of the drilling system. The
acquisition module is communicatively coupleable to one or more
sensors and includes at least one processor and at least one
tangible machine readable media. The tangible machine readable
media includes computer executable instructions that, when executed
by the at least one processor, perform the operations of receiving
sensor signals corresponding to mechanics of the drill bit from the
one or more sensors, processing the sensor signals to generate
drill bit mechanics data, and determining mechanical rock property
values of the formation within which the bit is currently engaged
from the mechanics of the drill bit. In certain implementations,
the rock property values may be used to determine a propensity for
a bottom hole assembly (BHA) of the drilling system to hold or be
biased away from a predetermined trajectory. Such biasing may
include, for example, building a dog leg out of or away from the
predetermined trajectory or dropping and drilling down and away
from the predetermined trajectory. In response to identifying a
bias, one or more operational parameters of the drilling system may
be updated to orient the drill bit or modify drilling operations to
mitigate or offset the bias.
[0017] These and other aspects are disclosed in further detail in
the description set out below.
BRIEF DESCRIPTION OF THE FIGURES
[0018] The foregoing and other objects, features, and advantages of
the present disclosure set forth herein should be apparent from the
following description of particular embodiments of those inventive
concepts, as illustrated in the accompanying drawings. The drawings
depict only typical embodiments of the present disclosure and,
therefore, are not to be considered limiting in scope.
[0019] FIG. 1 is a schematic illustration of a drilling environment
including a drill string having a bottom hole assembly including a
drilling measurement system;
[0020] FIG. 2 is a schematic illustration of a drill bit of the
bottom hole assembly of FIG. 1;
[0021] FIG. 3 is a schematic illustration of a drilling measurement
system for use in the bottom hole assembly of FIG. 1;
[0022] FIG. 4 is a schematic illustration of an acquisition board
that may be used in the drilling measurement system of FIG. 3;
[0023] FIG. 5 is a flow chart illustrating a method for controlling
a drilling measurement system;
[0024] FIG. 6 is a first example data output of the drilling
measurement system of FIG. 3;
[0025] FIG. 7 is a flow chart illustrating a method of controlling
a drilling system in response to characteristics of a subterranean
formation identified using drill bit mechanics;
[0026] FIG. 8 is a graphical representation of biases that may be
encountered during drilling of a subterranean formation and
corresponding directional offsets that may be applied by systems in
accordance with this disclosure to account for such biases; and
[0027] FIG. 9 is a schematic diagram of a computing module that may
be used to implement functions disclosed herein.
DETAILED DESCRIPTION
[0028] Aspects of the present disclosure are directed to systems
and methods for controlling drilling systems and drilling system
behavior in relation to operations of drilling measurement systems
during drilling operations. More specifically, aspects of the
present disclosure systems and methods are directed to selectively
controlling activation of components and functions of a drilling
measurement system by monitoring mechanics of a drill bit during a
drilling operation. The drill bit mechanics are analyzed to
determine, among other things, one or more of whether the drill bit
is actively engaged with a subterranean formation, whether the
subterranean formation is conducive to hydraulic fracture treatment
stimulation operations and whether the formation is favorable to
undertake a steering or directional drilling operation.
[0029] In response to determining the drill bit is actively engaged
with the subterranean formation, the drilling measurement system
may enter a first mode in which certain functionalities and/or
components of the drilling measurement are activated. Such
functions may include, but are not limited to, data processing,
data storage, and data transmission. In contrast, in response to
determining the drill bit is disengaged from the subterranean
formation, the drilling measurement system may enter a second mode
in which functionalities and/or components of the drilling
measurement system are deactivated. By selectively activating and
deactivating components based on engagement of the drill bit with
the subterranean formation, resources of the drilling measurement
system, such as processing power, battery life, and onboard memory,
may be conserved for times corresponding to active drilling.
Moreover, by collecting data only during active drilling the
drilling measurement system reduces the amount of irrelevant data
collected during the drilling operation.
[0030] In response to determining whether the drill bit is actively
engaged with a subterranean formation conducive to hydraulic
fracture stimulation treatment operations the drilling measurement
system may enter into a mode in which certain functionalities,
components, and/or behaviors of the drilling system are activated
or deactivated. Functions of the drilling system may include, but
are not limited to, changing from a rotational drilling mode to a
slide drilling mode or changing from a slide drilling mode to a
rotational drilling mode. Further, based on the rock properties,
one or more operational parameters of the drilling system to
control the drilling system and modify the drilling system
behavior. For example, in one implementation, the drilling system
may be controlled in response to the rock property information to
orient the bit based on whether the subterranean formation is
likely to hold, build, drop, turn, or otherwise be subjected to a
bias based on the mechanical properties of the formation through
which the bit is drilling. Orienting the bit in such a manner may
include, for example, operating the drilling system in a slide
rotational drilling mode while maintaining a bent sub (and as a
result the drill bit) at an angular orientation to offset the
build, drop, turn, or other deviation that may occur as a result of
the rock properties of the formation. Other examples of control of
the drilling system and corresponding modifications to the drilling
system behavior are discussed further in later portions of this
disclosure.
[0031] Many modern wells are drilled and completed without
obtaining adequate data regarding the heterogeneity of the
subterranean formations through which the wells extend. Although
systems to determine and log formation properties during drilling
are available, such equipment is often expensive to procure and
operate.
[0032] One significant cost associated with such systems is related
to power supply and management. Measurement-while-drilling (MWD)
and logging-while-drilling (LWD) systems are generally powered
using one of a cable coupled to a surface power source and an
onboard battery system. Regarding cable-based systems, significant
costs are associated with purchasing and managing the necessary
cabling, the various pieces of ancillary equipment required to
generate and transmit power over the substantial distances that may
exists between the measurement system and the surface power system,
and the power losses caused by the overall resistance of the cables
during transmission. Battery-based systems, on the other hand, can
become depleted during drilling operations, thereby requiring
multiple, costly drill string runs to sustain meaningful levels of
formation data collection during drilling of a given wellbore.
Power issues associated with MWD and LWD systems are further
compounded by the fact that conventional MWD and LWD systems
generally consume significant amounts of power when operational and
lack mechanisms for intelligently energizing and de-energizing
components of the MWD or LWD system. As a result, conventional LWD
and MWD systems often inefficiently consume power by collecting and
processing unnecessary data during periods in which no actual
drilling is occurring, such as during connection of segments of
drill pipe.
[0033] In light of the foregoing, among other things, the present
disclosure is directed to systems and methods for controlling a
drilling measurement system, such as by selectively energizing and
deenergizing components of the drilling measurement system, based
on a drilling state. More specifically, the systems and methods
include receiving and processing signals from sensors, such as
accelerometers, disposed near a drill bit of a drill string and
configured to measure mechanics of the drill bit. Based on the
signals, the drilling measurement system determines a drilling
state corresponding to whether the drill is actively engaged with
or disengaged from a subterranean formation. In certain
implementations, additional measurements and signals, such as but
not limited to one or more of weight-on-bit, rate-of-penetration,
or differential pressure measurements, may be collected and further
used in determining the drilling state. Depending on the drilling
state, the drilling measurement system operates in one or more
modes in which functions of the drilling measurement system and
power-consuming components for performing such functions are
enabled or disabled, accordingly. Such functions include, without
limitation, writing drilling data to onboard memory of the drilling
measurement system, transmitting drilling data to a remote receiver
(such as by mud pulse telemetry), and performing high-speed digital
signal processing using a dedicated digital signal processor of the
drilling measurement system.
[0034] The present disclosure is further directed to systems and
methods that receive and process signals from sensors, such as
accelerometers, disposed near a drill bit of a drill string and
configured to measure mechanics of the drill bit. Based on the
signals, the drilling measurement system determines characteristics
of the subterranean formation including, without limitation, the
presence of fractures or other features within the subterranean
formation and properties of the formation, such as a susceptibility
to hydraulic fracturing operations. The characteristics of the
formation may then be used to control the drilling system and
modify the drilling system behavior. Such modifications may
include, without limitation, changing one or more of drilling mode
(e.g., between a slide drilling mode and a rotational drilling
mode, which are described below), a rate of rotation of the drill
bit and/or drill string, a rate of penetration, and a direction of
drilling. In one example implementation, the mechanical rock
properties may indicate that the subterranean formation is likely
to cause the drill bit to build, drop, turn, or otherwise deviate
from a predetermined trajectory. In response, the drilling system
may automatically enter a slide drilling mode with the drill bit
oriented at an angle that compensates for the deviation induced by
the subterranean formation. Alternatively, the drilling system may
operate in a rotational drilling mode but modify the power provided
by the mud motor and/or the top drive to account for the
undesirable deviation. In another example, the drilling system may
automatically track or otherwise follow a path based on a feature
of the subterranean formation identified from the mechanical rock
property data. For example, the drilling system may cause a bit to
follow a path within a predetermined distance range from the
feature or maintain the bit at a particular orientation (e.g.,
perpendicular) relative to the feature. In yet another example,
identification of a feature within the subterranean formation or
portions of the subterranean formation having particular properties
may cause drilling operations to cease and for the drilling system
to generate and transmit alert messages to relevant personnel.
[0035] The term "drill bit mechanics" is used herein to generally
describe the behavior of the drill bit during drilling operations.
Accordingly, the term drill bit mechanics is intended to encompass
both the kinematics and dynamics of the drill bit including,
without limitation, the position, velocity, and acceleration of the
drill bit; the orientation and changes in the orientation of the
drill bit; forces generated by and acting upon the drill bit. Drill
bit mechanics may be a result of one or both of the physical
characteristics of the drill bit and interaction of the drill bit
with a subterranean formation. With respect to interaction of the
drill bit with a subterranean formation, drill bit mechanics may
result from deformation or failure of rock within the subterranean
formation.
[0036] The term "drilling system" is used to designate the
equipment used to drill a well and includes a drill bit that breaks
the rock by generating forces that are sufficient to overcome the
strength of the rock either through mechanical or a combination of
mechanical and hydraulic energy. The forces at the bit are
generated either from the surface through a drive string or
downhole through a motor. The drilling system uses fluids to power
the motor and further to circulate the cuttings from the breakage
of the rock to the surface. The drilling fluids also act to cool
the bit and to provide pressure to stabilize to the walls of the
borehole from collapse.
[0037] The term "drilling system behavior" is used to describe
actions of the drilling system that occur during a drilling
operation. Accordingly, control of the drilling system generally
includes modifying or maintaining one or more drilling system
behaviors by modifying or maintaining various operational
parameters of the drilling system. One action of particular
importance is the steering of the bit. In some instances, the
drilling system may be engaging the bit with the formation through
a combination of forces generated by the downhole motor and a top
drive used to rotate the drill string. This is generally referred
to as rotational drilling. Alternatively, the driller may choose
not to rotate the string and opt to provide energy to the drill bit
through the downhole motor only. This is referred to as slide
drilling. In certain implementations, slide drilling may be used to
control the direction of the well. For example, in order to steer
or orient the direction of drilling during a slide, the bottom hole
assembly may be fitted with a specialized sub, commonly referred to
as a "bent sub". The bent sub generally includes a bend at a small
angle offset from the axis of the drill string and a measurement
device to determine the direction of the offset. As a result, a
driller may rotate the drill string to point the drill bit and
operate the drilling system in a sliding mode (e.g., with the mud
motor activated but without rotation applied by the top drive) to
drill in the direction in which the bit points. Accordingly, by
controlling the amount of hole drilled in the sliding versus the
rotating mode and the direction of the drill bit when drilling in
the sliding mode, the wellbore trajectory can be controlled
precisely.
[0038] In one particular implementation, the system may orient the
bit to drill in a certain direction with respect to the
orientations of the natural fracture systems within a subterranean
formation. Alternatively or additionally, orientation may be made
based on whether the rock properties and rock property
relationships of the formation are likely to impart a bias on the
drill bit during drilling that cause a hold, build, drop, turn, or
other change in the direction of the bit, and, in particular, to
counteract or offset such effects on the bit. Additionally or
independently, the system may refer to mechanical rock property
data for the target interval of interest and adjacent layers of the
formation (e.g., above and/or below), and automatically orient the
bit or change between sliding and rotating modes to maintain
positioning within the formation of interest using rock properties
of the adjacent layers as thresholding information.
[0039] The term "drilling measurement system" is used herein to
encompass any system that collects data during a drilling
operation. As a result, drilling measurement systems include, but
are not limited to, MWD and LWD systems. Notably, drilling
measurement systems described herein collect and process data
corresponding to both drill string/drill bit dynamics and
subterranean rock formation data and, as a result, combine at least
a portion of the data collection functionality included in MWD and
LWD systems, respectively.
[0040] Also, for purposes of this disclosure the term "mechanical
rock property" or "rock property" is used generally used to
describe physical properties of rock within a particular portion of
the subterranean formation. Accordingly, the term is intended to
include both specific properties (e.g., Poisson's ratio or Young's
modulus of elasticity) for a particular portion of rock and
properties of relationships between different portions of rock
within the subterranean formation.
[0041] Implementations of the present disclosure include an
acquisition module or board. The acquisition module is generally a
microprocessor-based device in connection with a sensor array that
performs various digital signal processing operations on signals
received from the sensor array. In certain implementations, the
acquisition module determines mechanical rock property values based
on the signals and, based on the mechanical rock property values,
determines whether active drilling is currently underway. For
example, the acquisition module determines mechanical rock property
values and compares those values to one or more predetermined
ranges of values corresponding to different types of rock and
subterranean formations. If the mechanical property values fall
within one of the predetermined ranges of values, the acquisition
module determines the drill bit is actively engaged with the
subterranean formation. In response, the drilling measurement
system selectively activates components configured to perform
functions including, without limitation, storing, transmitting, and
processing the sensor signals and/or data derived therefrom. If, on
the other hand, the acquisition module determines the drill bit is
disengaged from the subterranean formation (e.g., by determining
the mechanical property value falls outside the one or more
predetermined ranges), the drilling measurement system selectively
deactivates the components, thereby conserving power. Data derived
from the sensor signals, such as the mechanical rock property
values, may be stored on board the drilling measurement system to
facilitate additional computations and analysis, such as those that
may be used to further control the drilling measurement system. The
drilling measurement system may also be configured to upload or
otherwise transmit the data to a remote receiver. In certain
implementations, such transmission occurs in real-time during
active drilling. Alternatively, the drilling measurement system may
upload bulk data at a later time, for example, according to a
predetermined uploading schedule, in response to a request received
from the remote receiver, and the like.
[0042] If, on the other hand, the acquisition module determines the
drill bit is disengaged from the subterranean formation (e.g., by
determining mechanical property values fall outside the one or more
predetermined ranges, that the formation mechanical rock properties
indicate that the formation does not contain natural fractures, or
the orientation of the well with respect to the orientation of the
natural fractures is not conducive to hydraulic fracture
stimulation treatments), the drilling measurement system
selectively adjusts the drilling state variables to deactivate the
rotating components, thereby conserving power, and steering the
drill using just the motor. The steering of the motor may be based
on the rock properties and rock property relationships and may
continue until the rock properties again fall within ranges
indicating a subterranean formation conducive to hydraulic fracture
stimulation treatment operations. In both instances the drilling
measurement system may change the mode of acquisition to
accommodate the change in the drilling behavior accordingly.
[0043] In certain implementations, the acquisition module may use
the mechanical property values to identify characteristics of the
subterranean formation. Such characteristics may include features
of the formation, such as fractures (e.g., natural fractures or
fractures resulting from treatment of other nearby wells), or
properties of the subterranean formation. In one example, the
characteristics may include a relative susceptibility of the
subterranean formation to fracturing operations. In response to the
characteristics identified based on the mechanical property values,
components of the drilling system may be selectively
activated/deactivated or otherwise controlled to modify a behavior
of the drilling system. For example, the drilling system may be
switched between a slide drilling mode and a rotational drilling
mode by deactivating or activating a top drive of the drilling
system, respectively. Other examples of control of the drilling
system based on the formation characteristics include, without
limitation, one or more of changing a rotational speed of the drill
bit or top drive, a direction of the drill bit, and a rate of
penetration.
[0044] More generally, the characteristics of the subterranean
formation may be used to determine the location, presence, or
nature of features (such as boundaries, fractures, or other
discontinuities) within the subterranean formation that may be used
to control drilling operations and/or properties of the
subterranean formation. In certain implementations, the
identification or detection of certain features or properties of
the subterranean formation may be used as a triggering event by the
drilling system. In such implementations, one or more operational
parameters of the drilling system may be automatically changed in
response to detecting the characteristics. In other
implementations, the characteristics of the subterranean formation
may be used as a means of continuous feedback for the drilling
system. For example, the mechanical rock properties may be used to
infer an approximate distance from a boundary or other feature
within the formation that is undesirable to cross. The drilling
system may then control a drilling mode, rate, direction, etc., to
maintain the drill bit at a predetermined distance (or within a
predetermined range) from the boundary to avoid crossing the
boundary.
[0045] Certain drill bit mechanics, such as vibrations, may
attenuate rapidly and may generally have high frequency and low
amplitude. Such mechanics may be best recorded as near to the drill
bit as possible. Accordingly, in certain implementations, the
acquisition module is included in a bit-sub, which is a short
length of drill collar or similar tubular that can be used to mount
the acquisition module behind the drill bit to facilitate data
acquisition. Conventional measurement systems are generally
deployed as part of a bottom hole assembly (BHA) when drilling a
lateral or vertical well to send near-bit data and information to
surface receivers in real-time. However, there is limited space for
tools available in a near-bit environment. Colloquially, this is
referred to as "first class" in the parlance of the BHA. Moreover,
it is desirable to minimize the "bit-to-bend distance" especially
when geo-steering lateral wells. As such, in practice, the length
of the bit sub limits the space available for electronics and
batteries and subsequently the power available to process and
transmit the data. As a result, measurement systems in accordance
with this disclose may generally be more compact and efficient than
conventional systems, thereby reducing bit sub lengths and
facilitating reduction in bit-to-bend distances.
[0046] In certain implementations, when the acquisition module
determines drilling is occurring, real-time mechanical rock
property information is obtained from the acquisition module using
a radio frequency transmission system to "short hop" the mechanical
rock property data to a mud pulser or similar transmission system
for transmission of the mechanical rock property data to a remote
receiver, such as a surface receiver. As a result, the short hop
generally requires sufficient resources to power a signal over the
length of a mud motor. In implementations including a mud pulser,
the mud pulser is a more powerful transmission system than the
short hop system disposed higher up in the BHA. The mud pulser
generally includes sufficient resources to transmit binary encoded
records of mechanical rock properties or other data to a surface
receiver/acquisition system. The surface receiver detects and
decodes the binary signal and extracts the data within the binary
signal. The data is then stored, displayed, or otherwise made
accessible using a computer in communication with the receiver
system.
[0047] Other mechanisms to transfer data from a near-bit
environment across a motor to the mud pulser may include a wired
motor. In such applications, electrical impulses may be carried
across the motor by the circuitry and connections of the motor
between the below-motor, near-bit acquisition system, and the
above-motor mud pulser.
[0048] One advantage of systems and methods of the present
disclosure is the ability to differentiate drilling times from
non-drilling times. When using a fast mud motor, for example, the
rate of penetration (ROP) can proceed at rates as high as 330 feet
per hour in some formations and basins. For these high-ROP wells,
the time taken to make a connection between drill string sections
can be a significant amount of rig time. That is, less time is
taken to drill through the formation than preparing to drill. By
obtaining drill bit mechanics signals and/or mechanical rock
property values derived from such signals, it is possible to
identify periods of time when the drill bit is actively engaged
with a subterranean formation and is extending the wellbore. At
other times, when the drill bit is disengaged from the subterranean
formation, battery power, memory storage, processing power, and the
like can be conserved by formulating and sending instructions to
de-energize or deactivate components of the drilling measurement
system for performing such functions.
[0049] Another advantage of systems and methods of the present
disclosure is the ability to identify characteristics of a
subterranean formation, such as susceptibility to hydraulic
fracture stimulation treatment operations or particular features
within the subterranean formation, and to rapidly control drilling
operations in response. When using a fast mud motor, for example,
the rate of penetration (ROP) can proceed at rates as high as 330
feet per hour in some formations and basins. For these high-ROP
wells, the time taken to adjust the trajectory of the well by
changing from rotational drilling to slide drilling or vice versa
can be a significant amount of rig time. By obtaining drill bit
mechanics signals and/or mechanical rock property values derived
from such signals, it is possible to identify periods of time when
the drill bit is within or adjacent portions of the subterranean
formation having certain characteristics and to control the
drilling system accordingly. For example, such data may be used to
control the drill bit (e.g., by controlling a drilling mode or
direction) such that the drill bit is maintained within a
particular interval of the subterranean formation, in a certain
direction relative to a feature of the subterranean formation
(e.g., perpendicular to a natural fracture), within a predetermined
range of distances from a feature, and the like.
[0050] The characteristics may also be used to control other
operations, of the drilling system including, without limitation,
activating, deactivating, or modifying operational parameters of
other components of the drilling system. For example, and without
limitation, characteristics of the subterranean formation may be
used to activate, deactivate, or modify parameters of a data
acquisition module in response to characteristics of the
subterranean formation. For example, the data acquisition may be
automatically activated or operated at a relatively higher
resolution when in the presence of certain features of the
subterranean formation but may be deactivated or operated at a
relatively lower resolution in the absence of those same
features.
[0051] As previously noted, implementations of methods and systems
according to this disclosure include the derivation of mechanical
rock property values from drill bit sensor signals corresponding to
drill bit mechanics and associated data derived from such signals.
Methods and apparatuses for performing such analysis, as well as
details regarding the mechanics of drill bits during drilling
operations, are provided in more detail in U.S. patent application
Ser. No. 14/850,710, filed Sep. 10, 2015 and titled "Apparatus and
Method Using Measurements Taken while Drilling to Map Mechanical
Boundaries and Mechanical Rock Properties Along a Borehole" and
U.S. patent application Ser. No. 15/182,012, filed Jun. 14, 2016,
also titled "Apparatus and Method Using Measurements Taken while
Drilling to Map Mechanical Boundaries and Mechanical Rock
Properties Along a Borehole," both of which are hereby incorporated
by reference in their entirety.
[0052] FIG. 1 is a schematic illustration of a drilling environment
100 including a surface 102, a subterranean formation 104, and a
wellbore 105 including a vertical wellbore section 106 and a
horizontal wellbore section 108. The drilling environment 100
depicts the drilling of the horizontal wellbore section 108 using a
bottom hole assembly (BHA) 110 coupled to a drill string 112. The
BHA 110 includes a drill bit 114, a mud motor 116, a bit sub 118
including various measurement components positioned between the
drill bit 114 and the mud motor 116, and sections of drill pipe
120, 150 within the horizontal wellbore section 108.
[0053] Systems and methods in accordance with this disclosure
determine a drilling state of the drill bit 114 and, more
specifically, whether the drill bit 114 is engaged with or
disengaged from the subterranean formation 104 based on mechanics
of the drill bit 114. The signals used to determine the drilling
state may be recorded as close to the drill bit 114 as practical to
avoid attenuation through the BHA 110. Accordingly, one possible
location for recording mechanics of the drill bit 114 is in the bit
sub 118, which is disposed directly behind the drill bit 114 and
ahead of the mud motor 116. The drill string 112 shown in FIG. 1
includes one bit sub, namely bit sub 118. However, in other
implementations, multiple bit subs may be used along the drill
string 112 for additional processing or transmission of the desired
signal.
[0054] Drilling a wellbore generally involves using a portion of
the weight of the drill string 112, known as weight-on-bit (WOB),
to push the drill bit 114 into the subterranean formation 104. In
addition to the WOB, a rotating force, known as torque-on-bit (TOB)
is also applied to the drill bit 114. In certain drilling
operations, TOB is generated by rotating the drill string 112 using
a motor-driven turntable, or similar rotary device, located at the
surface 102. In other drilling operations, such as that depicted in
FIG. 1, TOB is generated by the mud motor 116. During drilling,
drilling mud is pumped down the drill string 112 until it
encounters the mud motor 116 and, more specifically, a power drive
section (not shown) of the mud motor 116. The power drive section
of the mud motor 116, which is mechanically coupled to the drill
bit 114, converts a portion of the mud pressure and flow into a
rotational force, thereby applying rotational torque on the drill
bit 114.
[0055] The objective of the drilling process is to break rock of
the subterranean formation 104 into fragments that are small enough
they can be lifted and evacuated from the wellbore 105 with
drilling fluids. Doing so accommodates the forward motion of the
drill bit 114. It should be noted that the action of the drill bit
114 on the subterranean formation 104 fractures the subterranean
formation 104 along the wellbore 105 and also in a region of the
subterranean formation 104 immediately adjacent the wellbore 105.
During drilling, the drill bit 114 may encounter existing
fractures, such as fracture 122.
[0056] In FIG. 1 the bit sub 118 is shown between the drill bit 114
and the mud motor 116. More specifically, the bit sub 118 is
operably coupled between the drill bit 114 and the mud motor 116
such that the mud motor 116 turns the drill bit 114 when mud is
supplied to the mud motor 116 through drill string 112. The bit sub
118 provides a housing, typically in a cylindrical shape, or
similar component to support various possible measurement
components 124. Such measurement components include, without
limitation, strain gauges, accelerometers, pressure sensors (which
may measure the pressure of the mud flow), temperature sensors
(which may measure the circulating temperature of the mud or other
temperatures and which may be used to provide correction or offset
of measurements or calculations that vary with temperature),
gyroscopes (which may be used to measure inclination and/or
directional changes of the drill bit 114 and the drill string 112),
and other components to measure or derive data discussed herein. In
one example, as shown in FIG. 1, strain gauges 128 are mounted on
the bit sub 118 to determine WOB and TOB of the drill bit 114
(i.e., the force pushing the drill bit 114 and the force turning
the drill bit 114 into the rock formation). Various possible ways
of mounting the strain gauges, or combinations of strain gauges,
are possible.
[0057] Additionally, as shown in FIG. 2, which is a representative
front view of the drill bit 114, one or more accelerometers, such
as accelerometer 126, may be placed to measure axial, rotary,
and/or lateral acceleration of the drill bit 114. More
specifically, the one or more accelerometers generate signals
corresponding to the axial, rotary, and/or lateral acceleration of
the drill bit 114 and transmit the signals to signal and data
processing components disposed within the bit sub 118. Notably, the
axis of rotation of the drill bit 114 is generally in center of the
drill bit 114, but axial acceleration may be measured somewhat
offset from the axis depending on the placement of the
accelerometer 126.
[0058] As described below in more detail, the bit sub 118 or other
such component, may house a drilling measurement system configured
to process the signals received from the sensors, to determine
mechanical rock property values based on the signals, to determine
a drilling state based on the mechanical rock property values, and
to transmit drilling data corresponding to one of the vibration
signals and the mechanical rock property values to a remote
receiver. In FIG. 1, for example, the bit sub 118 includes a "short
hop" transmitter 128 that wirelessly transmits drilling data to a
mud pulser 130 of the BHA 110 which then transmits the drilling
data to a surface receiver 132 using mud pulse telemetry. Other
systems such as a wired motor may be used to transmit data from the
below-motor acquisition system to the above-motor mud pulser. Mud
pulse telemetry is only an example method for transmitting the
drilling data to the surface receiver 132. Other telemetry systems,
such as wireline systems, wireless communication systems, and the
like, may also be used to communicate the drilling data to the
surface receiver 132.
[0059] FIG. 3 is a schematic illustration of a drilling measurement
system 200, such as may be contained, at least in part, within the
bit sub 118 shown in FIG. 1. Generally, the drilling measurement
system 200 is configured to receive signals from a sensor array and
to process the signals to determine one or more mechanical rock
property values. The drilling measurement system 200 may be further
configured to at least one of transmit to a remote receiver (such
as the remote receiver 132 of FIG. 1) and store drilling data
corresponding to the signals and/or the mechanical property
values.
[0060] The drilling measurement system 200 generally includes a
plurality of modules configured to perform various functions of the
drilling measurement system 200. In FIG. 3, for example, each
module is represented as a separate circuit board coupled to a
central bus 202 that facilitates communication between the
different modules/boards. The modules/circuit boards included in
the drilling measurement system 200 include a control board 204, a
data acquisition board 206, a digital signal processing (DSP) board
208, a mass memory board 210, and an interface board 212. Although
illustrated as physically separate boards, which each may include a
printed circuit board with various hardware elements mounted and
interconnected thereon, any or all of the control board 204, the
data acquisition board 206, the digital signal processing (DSP)
board 208, the mass memory board 210, and the interface board 212
may be integrated into a single board or otherwise provided in any
number of boards. Moreover, functions of the various modules/boards
of the drilling measurement system 200 may be performed using
dedicated hardware or software. For example, the drilling
measurement system 200 may include one or more application-specific
integrated circuits (ASICs) or similar custom integrated circuits
that are programmed to perform the various functions described
herein.
[0061] The control board 204 includes a control board
microprocessor 214. The control board microprocessor 214 is
communicatively coupled to the bus 202 and facilitates
communication between the various components of the drilling
measurement system 200. In certain implementations, the control
board microprocessor 214 is configured to selectively activate or
deactivate functions of other boards, such as the DSP board 208,
the mass memory board 210, and the interface board 212, based on a
drilling state. For example, the control board microprocessor 214
may selectively energize one or more the boards 208-212 or
components of the one or more boards. In other implementations, the
control board 214 selectively changes one or more boards or
components thereof between a low-power state, such as a "sleep"
state, and an active state.
[0062] The data acquisition board 206 includes an acquisition
microprocessor 226 that receives signals from a sensor array 250
communicatively coupled to the data acquisition board 206. The data
acquisition board 206 generally includes components and/or software
for processing signals received from the sensor array 250 to
generate drill bit mechanics data and mechanical rock property
values based on the drill bit mechanics data. Processing of the
signals received from the sensors to generate drill bit mechanics
data may include, without limitation, (i) amplifying the signals
using one or more amplifiers 236; (ii) integrating the vibration
signals using one or more integrators 232; (iii) filtering the
vibration signals using one or more filters 234; (iv) converting
the signals to a digital form using an analog-to-digital converter
228; and (v) down-sampling or decimating a digital form of the
signals using a decimator 230. The data acquisition board 206 may
further include (or otherwise have access to) a memory 227 that
stores computer executable instructions for execution by the
acquisition microprocessor 226 to perform or coordinate performance
of the various processing functions of the acquisition board
206.
[0063] In certain implementations, the acquisition microprocessor
226 executes instructions to determine mechanical rock property
values based on the drill bit mechanics data. The process of
determining mechanical rock properties based on drill bit mechanics
data is provided in detail in U.S. patent application Ser. Nos.
14/850,710 and 15/182,012, both of which are titled "Apparatus and
Method Using Measurements Taken while Drilling to Map Mechanical
Boundaries and Mechanical Rock Properties Along a Borehole,"
however, a summary of the process is provided below.
[0064] In one implementation, mechanical rock properties are
determined by deriving stress-strain relationships by
systematically relating forces acting on the formation. The forces
acting on the formation are generally ascertained from the drill
bit mechanics measured during the cutting action of the bit. This
approach allows elastic coefficients (K) to be derived in
accordance with the following equation:
S=K e
where (e) is the general deformation (strain) of a rock formation
in response to the forces acting on a rock formation (S)
(stress).
[0065] Strain can generally be derived from motion of the drill
bit. For example, one or more accelerometers may be disposed near
the drill bit to provide acceleration signals in response to
vibrations of the drill bit during active drilling. Integration of
the acceleration signals can then be applied to determine the
corresponding velocity and position of the drill bit and, as a
result, the strain behavior of the formation. Stress, on the other
hand, is generally derived from forces acting on the bit. For
example, in various implementations, stress may be determined from
any of (i) downhole measurements of torque and/or weight on bit;
(ii) surface measurements of torque and/or weight on bit; or (iii)
the accelerations of the drill bit as the acceleration is a
representation of force per unit mass. Such forces can be converted
to stresses with knowledge of the effective contact area of the
drill bit and formation and the effective rock volume the drill bit
is acting on. Conversely, forces can be substituted for stresses
with the understanding that a geometric correction in relation to
the effective contact area is required to obtain absolute values
for the mechanical rock properties. One example of such a contact
area is the area of the drill bit.
[0066] Equations of linear elasticity are useful for describing the
relationship between the changes in shape and position of a
material in relation to the forces acting on the material. Such
stress-strain relationships are known in general as Hooke's law
where the coupling of the stress-strain relationship behavior is
described through a matrix of coefficients whose values depend on
the conditions used to load the material in relation to the
structural symmetry of the material being loaded. These
coefficients (colloquially known as the cij's) can be arranged in
well-known and convenient forms to represent various mechanical
properties including, without limitation, Young's Modulus of
Elasticity (YME) and Poisson's Ratio (PR).
[0067] In one specific implementation, linear elasticity equations
are uniquely expressed through the application and use of drill bit
mechanics data to (i) populate the variables of the constitutive
equations of linear elasticity and (ii) undertake an analysis of
the constitutive equations to obtain measurements of near-wellbore
mechanical rock properties, such as YME and PR. Further, variations
in the mechanical rock properties (e.g., YME and PR) are used to
identify the nature and occurrence of mechanical boundaries or
discontinuities in the subsurface such as fractures.
[0068] Techniques to determine near-wellbore mechanical rock
properties from drill bit mechanics data may involve processing
drill bit mechanics data including, without limitation, the weight
on bit, torque on bit, annular fluid pressure, angular bit speed,
and components of motion describing the acceleration of the drill
bit, including axial and rotary or tangential accelerations to: (i)
obtain sets of MWD data corresponding to known temporal and spatial
positions along the borehole; (ii) calculate the forces acting on
the rock formation in connection with the drilling apparatus and
drilling fluids, (iii) calculate the displacements of the drill bit
as it is accommodated by the deformation of the rock formation;
(iv) inform the terms and loading conditions (variables) of a
linear, elastic stress-strain relationship that describes the
constitutive behavior of the rock formation in relation to the
orientation of the well; (v) calculate mechanical rock properties
using the constitutive linear elastic equations as determined
through the application and use of the drill bit mechanics data;
and (vi) analyze the mechanical rock properties with respect to the
axis of material symmetry in relation to the orientation of the
well to identify the nature and occurrence of mechanical boundaries
and discontinuities such as fractures and bedding planes among
other things.
[0069] Typical values for mechanical rock properties and mechanical
rock property relationships have been well established and are well
known with respect to various formations typically encountered when
drilling. The values of YME typically range between 1-20 Mpsi and
PR typically falls between 0.1 and 0.45. By systematically
comparing the rock properties obtained using systems and methods in
accordance with this disclosure to typical values or ranges of
values expected for a given formation, it is possible to determine
when the bit is interacting or otherwise engaged with the
formation. By systematically comparing the mechanical rock
properties with respect to the axis of material symmetry in
relation to the orientation of the well it is possible to predict
the nature and occurrence of mechanical boundaries and
discontinuities such as fractures and bedding planes in the
formation, among other things.
[0070] In certain implementations, after determining the mechanical
rock property values corresponding to the drill bit mechanics data,
the acquisition microprocessor 214 determines whether the
calculated mechanical rock property values indicate that the drill
bit is actively engaged with or disengaged from a subterranean
formation. For example, in certain implementations the acquisition
microprocessor 214 calculates values corresponding to mechanical
rock properties, such as Poisson's ratio (PR) and Young's modulus
of elasticity (YME), and compares the calculated values to one or
more predetermined ranges of the mechanical rock properties
corresponding to known subterranean formations. If the calculated
value falls within one of the one or more predetermined ranges, it
is likely that the drill bit is actively engaged with the
subterranean formation. Alternatively, if the calculated value
falls outside of each of the one or more predetermined ranges, it
is likely that the drill bit is disengaged from the subterranean
formation.
[0071] In addition to determining whether the drill bit is engaged
with or disengaged from the subterranean formation, the mechanical
rock property values may be used to infer characteristics of the
subterranean formation. The properties and characteristics may
include, without limitation, one or more of the occurrence,
location, and nature of features within the formation such as
fractures, boundaries, and bedding planes. Such features may be
naturally occurring within the formation or may be the result of
other activity, such as drilling and fracturing activity, within
the formation. For example, and without limitation, the mechanical
rock properties may be used to identify fractures within the
formation that may be the result of fracturing operations conducted
on a nearby well.
[0072] The characteristics of the subterranean formation inferred
from the mechanical rock property data may be used in various ways
including, without limitation, monitoring the current drilling
operations and controlling the drilling system to modify a drilling
system behavior. For example, in one implementation, detecting a
feature of the subterranean formation within the mechanical rock
property data may be used to confirm the location of the drill bit
within the formation, such as by cross-referencing the location of
the feature with previously obtained seismic or similar geologic
data. In another example implementation, the formation
characteristics may be stored in addition to seismic or other
geological data to supplement or verify the geological data.
[0073] In still other implementations, drilling operations may be
controlled in various ways in response to the formation
characteristics. Control of drilling operations may include,
without limitation, one or more of changing a drilling mode (e.g.,
slide drilling or rotational drilling); altering a direction of the
drill bit (such as by altering an orientation of a bent sub of the
drilling system); altering a rotational speed of a drill bit or top
drive; and increasing or decreasing a rate of penetration of the
drill bit. In a first example implementation, the drilling
operations may be controlled to maintain the drill bit at a
predetermined distance or within a range of predetermined distances
relative to a feature of the formation. So, for example, the
drilling system may automatically modify one or more of an
orientation of the drill bit, a rotational speed of the drill bit,
a rotational speed of a top drive, or a drilling mode in response
to detecting certain features of the formation. In another example
implementation, the drilling operations may be controlled to
maintain the drill bit at a predetermined orientation relative to a
feature, such as maintaining the drill bit substantially
perpendicular to a natural fracture within the formation.
[0074] In yet another example implementation, the drilling system
may automatically adjust one or more drilling parameters to reduce
deviation from a predetermined drilling trajectory that may result
from a bias induced on the drill bit during drilling. More
specifically, certain properties of the formation may cause the
drill bit to hold, bend, drop, turn, or other otherwise deviate
from a predetermined trajectory due to the interaction of the drill
bit with the rock face during drilling. Accordingly, based on the
mechanical rock properties and corresponding characteristics of the
formation, the drilling system may automatically adjust drilling
parameters to offset or otherwise account for the bias caused by
the formation. For example and without limitation, the drilling
system may automatically adjust one or more of the orientation of a
drill bit (e.g., by adjusting the orientation of a bent sub when in
a slide drilling mode), a drilling mode (e.g., by changing between
a slide drilling mode and a rotational drilling mode), the amount
of weight-on-bit, a rotational speed of the mud motor or top drive,
or any other operational parameter that may affect the drilling
direction.
[0075] In the foregoing examples, the information regarding the
formation is used as a means of continuous feedback for controlling
the drilling system. In still other implementations, the
information regarding the formation may be used as triggers for
transitions between different phases of a drilling operation. For
example, a drilling operation may proceed in a first direction and
at a first rate until a certain feature of the formation (e.g., a
fracture) is detected. Following detection of the feature, the
drilling operation may continue in a second direction at a second
rate. Similarly, detection of a certain feature or characteristics
of the formation based on the mechanical rock property data may be
used to trigger a stoppage or shutdown of drilling operations. So,
for example, if the mechanical rock property data indicates the
presence of a fracture or discontinuity in close proximity, the
drilling operations may be automatically stopped to avoid breaching
the feature.
[0076] In certain implementations, the information regarding the
formation and, more specifically, the characteristics of the
formation may also be used to trigger the generation and
transmission of one or more messages. Such messages may be used,
for example, to inform personnel regarding the detection of
features of characteristics of the formation or the progress of the
drilling operations and may be provided in various forms including,
without limitation, one or more of text messages, email,
prerecorded voice messages, and the like.
[0077] In certain implementations, the information regarding the
subterranean formation inferred from the mechanical rock property
data may also be used to modify, supplement, or classify the
mechanical rock property data collected and/or transmitted by the
drilling measurement system. For example, in certain
implementations, the system may determine that a portion of the
subterranean formation is particularly susceptible to hydraulic
fracturing or similar treatment operations and classify the
corresponding mechanical rock property data accordingly. Such
classification may include, among other things, tagging the data
with a corresponding identifier or maintaining a separate log
including coordinates or other information for relevant portions of
the subterranean formation.
[0078] After determining whether the drill bit is actively engaged
with the subterranean formation and/or whether the drill bit is
actively engaged with the subterranean formation that is conducive
or otherwise susceptible to hydraulic fracture stimulation
treatment operations, the acquisition microprocessor 214 may
communicate the drilling state to the control board 204. In certain
implementations, the acquisition microprocessor 214 transmits a
message containing the current drilling state to the control board
204. In other implementations, a shared memory may be used to store
a drilling state variable that is updateable by the acquisition
microprocessor 214 and retrievable by the control board 204. Based
on the drilling state, the control board 204 activates or
deactivates functions of the other components of the drilling
measurement system 200. More specifically, when the drilling state
indicates the drill bit is actively engaged with the subterranean
formation and/or that the drill bit is actively engaged with the
subterranean formation that is conducive or otherwise susceptible
to hydraulic fracture stimulation treatment operations, the control
board 204 operates the drilling measurement system 200 in a first
mode and when the drilling state indicates the drill bit is
disengaged from the subterranean formation, the control board 204
operates the drilling measurement system 200 in a second mode. The
second mode generally corresponds to a low power consumption mode
in which one or more components or functions of the drilling
measurement system 200 are deactivated. For example, the component
or functions deactivated in the first mode may correspond to
components or functions configured to perform processing, store
data, or transmit data. Accordingly, the second mode corresponds to
a mode in which the drilling measurement system 200 monitors
signals from the accelerometer array 250 to identify when drilling
has begun. In contrast, when operating in the first mode, one or
more of the components or functions deactivated in the second mode
are activated. For example, when operating in the first mode, the
drilling measurement system 200 may be configured to perform at
least one of additional signal processing, data storage, and data
transmission using the DSP board 206, the mass memory board 210,
and the interface board 212, respectively.
[0079] The data acquisition board 206 generally includes sufficient
computing power and computing modules to perform processing of at
least a portion of the signals received from the sensor array 250
or derived from the received signals by the acquisition board 206.
In certain operational modes, however, additional processing power
may be required to generate greater quantities of drilling data.
Such processing power may be provided by the DSP board 208 or a
similar data processing module. For example, in certain
implementations, the DSP board 208 includes a DSP control
microprocessor 238, a DSP math processor 240, and one or more
memories, such as a DSP primary memory 242 and a DSP scratchpad
memory 244. In such implementations, the DSP control microprocessor
238 provides control of the DSP board 208, including managing data
flow into and out of the DSP math processor 240, by executing
instructions stored in the DSP primary memory 242. The DSP math
processor 240, on the other hand, is a high-speed math processor
configured to transform time-domain vibration signals received from
the accelerometer array 250 into the frequency domain, such as by
performing a fast Fourier transform (FFT) on the received
time-domain signals. Such an FFT performed by the DSP board 208 may
transform n points (for example, n=1024 points) of time domain
information into n/2 (n/2=512) points of frequency domain data,
which include the amplitude and frequency components present in the
originally received signals. To facilitate processing by the DSP
math processor 240, the DSP math processor 240 may store
calculations, data, and other work in the DSP scratchpad memory
244. In certain implementations, the various filtering functions
described above as being performed on the acquisition board 226 may
instead be performed by the DSP board 208.
[0080] During operation, the control board 204 may selectively
activate and deactivate the DSP board 208 or components of the DSP
board 208 based on the drilling state as determined by the data
acquisition board 206. If the data acquisition board 206 determines
that active drilling is underway, the control board 204 may
energize the DSP board 208 or otherwise send a message to the DSP
board 208 to begin transformation of time-domain data received from
the acquisition board 206 into the frequency domain.
[0081] The mass memory board 210 stores drilling data received from
the acquisition board 206. More specifically, the mass memory board
210 generally includes a memory microprocessor or microcontroller
216 and one or more memory modules 218-224. The memory
microprocessor/microcontroller 216 generally performs memory
management functions including, without limitation, reading,
writing, and deleting data in the memory modules 218-224. In
certain implementations, each of the memory modules 218-224 are
dynamic random access memory (DRAM) modules or any other suitable
type of memory for storing data associated with the signals
received from the sensor array 250. Such data includes, without
limitation, drill bit mechanics data generated by the acquisition
board 206 from the sensor signals during active drilling and
mechanical rock property data derived from the drill bit mechanics
data. The mass memory board 210 may store the data for remote
retrieval, such as by the remote receiver 132 of FIG. 1. For
example, the mass memory board 210 may be configured to provide, in
response to a data retrieval request, at least a portion of the
drilling data stored in one or more of the memory module 218-224.
In certain implementations, the memory board 210 is configured to
deenergize or otherwise deactivate write functionality when the
drill bit is disengaged from a subterranean formation, thereby
conserving memory resources of the drilling measurement system
200.
[0082] The interface board 212 communicates data from the drilling
measurement system 200 to one or more external devices. In certain
implementations the interface board 212 is configured to
communicate with a downhole telemetry device, such as a mud pulser
in proximity to the drilling measurement system 200. For example,
the interface board 212 may be directly wired to or communicate
wirelessly with a mud pulser disposed on the BHA. In wireless
implementations, the interface board 212 may be configured to
transmit data to the mud pulser using a short hop wireless system.
The mud pulser may then transmit the data from the interface board
212 to a remote receiver.
[0083] The sensor array 250 includes one or more sensors that
generate electrical signals in response to motion of the drill bit
and/or forces experienced by the drill bit. The sensor array 250
may include sensors of different types and configured to measure
different behavior of the drill bit. Sensors of the sensor array
250 may include, but are not limited to, accelerometers, gyros,
strain gauges, pressure switches, load cells, potentiometers,
encoders, optical switches, tachometers, Hall effect sensors, and
the like. In certain implementations, the sensor array 250 includes
one or more single or multi-axis accelerometers each of which may
produce signals over one or more channels. In certain
implementations, accelerometers of the sensor array 250 are
low-power accelerometers selected to have performance
characteristics conducive to a drill bit vibration measurement
application. For example, such performance characteristics may
include, without limitation, having an accuracy of .+-.5% from 100
to 10000 Hz and .+-.3 dB up to 30 kHz, being able to operate at
temperatures up to 150 degrees Celsius, and having a turn-on
settling time of less than a few minutes. The accelerometers may
also be selected to have particular bandwidths and dynamic ranges
conducive to drill bit vibration monitoring. For example, in
certain applications, accelerometers may be selected to have a
bandwidth of 10-50000 Hz and dynamic ranges of +/-300 g's and
+/-100 g's for measuring motion in the radial or tangential
direction and axial direction, respectively. The accelerometers of
the sensor array 250 may be arranged in a recording configuration
to simultaneously measure the axial and lateral or tangential and
radial or centripetal components of motion about the axis of
drilling. The accelerometers of the sensor array 250 may also be
placed in an orthogonal arrangement of channels sufficient to
cancel linear motions of the drill bit using summations of the
accelerometer signals.
[0084] During operation, the drilling measurement system 200 may
collect drill bit mechanics data in various data collection modes.
In general, the data collection modes are designed to accommodate a
native sample rate for obtaining signals from the accelerometer
array 250 that is above or equal to the rate at which such signals
can be processed and stored by the other components of the drilling
measurement system 200. To the extent the drilling measurement
system 200 stores data, data storage may be at a predetermined
resolution that provides meaningful differentiation. For example,
in one implementation, the drilling measurement system 200 has a
native sample rate of 50 kHz and is configured to process and store
data at a minimum of 5 kHz at a resolution of no less than 16-bits.
In certain implementations, the drilling measurement system 200 is
configured to automatically enter one of the data collection modes
after the occurrence of predetermined events, such as the drill bit
reaching a specified depth or a particular amount of time elapsing,
such as the time required to introduce the drilling measurement
system 200 into a wellbore.
[0085] A first possible data collection mode, referred to herein as
"native mode," involves continuous sampling and storage of signals
from the accelerometer array 250 at the native sample rate and at
full resolution until memory is full. As such, the native mode may
be useful for testing and troubleshooting the drilling measurement
system 200.
[0086] In a second possible data collection mode, referred to
herein as "burst mode," the accelerometer array 250 is sampled and
the corresponding data is stored at the native sample rate during
discrete time windows that occur at regular intervals. For example,
in one implementation, the accelerometer array 250 is sampled and
the corresponding data is processed and stored at the native sample
rate for an 8 second "burst" that occurs every 120 seconds. The
length of the discrete time windows may vary depending on the
native sample rate and the available memory. The burst mode may be
appreciated in instances when accurate determination of formation
properties requires a relatively high sampling rate but power
available to the drilling measurement system 200 is sufficiently
limited that continuous sampling at the high sampling rate would
detrimentally impact overall drilling time. In certain
implementations, the burst mode may be used to determine what
bandwidth would be sufficient to retrieve information related to
the accelerations of the bit and the motions of the bit that would
be most representative of the mechanical rock properties. For
example, the burst mode may be used with different settings (e.g.,
number of measurements per burst, time between measurements within
a given burst, time between bursts) to identify the optimal
settings for a given drilling application.
[0087] In a third possible data collection mode, referred to herein
as "continuous mode," the accelerometer array 250 is continuously
sampled at the native sample rate, but only a decimated or
down-sampled form of the signals or corresponding data are stored.
For example, in one implementation of continuous mode, 1 out of
every 10 samples retrieved form the accelerometer array 250 is
processed and stored. Notably, this mode allows post-processing of
the stored data for discrete fracture detection. In certain
implementations, the down-sampling rate may be based on data
previously obtained during operation of the drilling measurement
system 200 in burst mode. For example, an operator may perform a
first drilling run in which the drilling measurement system 200 is
operated in burst mode. The operator may then analyze the data
collected during the first drilling run may be evaluated to
determine the frequency of samples required to accurately assess
the heterogeneity of the formation and its mechanical properties. A
subsequent drilling run may then be performed using the drilling
measurement system 200 in continuous mode with a down-sampling rate
corresponding to the frequency determined from the first drilling
run.
[0088] In a fourth possible data collection mode, referred to
herein as "continuous-plus-burst mode," the drilling measurement
system 200 alternates between the previously described continuous
and burst modes at regular intervals. For example, the drilling
measurement system 200 may generally process signals and store data
corresponding to 1 out of every 10 samples, except for regular
intervals of time in which the drilling measurement system 200
operates in burst mode. During the burst mode intervals, the
drilling measurement system 200 samples and stores data at the
native sample rate. An example time window and interval of the
burst mode could be 10 seconds every 600 seconds. In other words,
the drilling measurement system 200 would operate in continuous
mode for 590 seconds and then would switch to burst mode for 10
seconds before returning to continuous mode. In certain
implementations, the continuous-plus-burst mode is the standard
operational mode for the drilling measurement system 200.
[0089] Any of the foregoing data collection modes benefit from
operating only when the drill bit is engaged with a formation
and/or engaged with a formation that is specifically conducive to
hydraulic fracture stimulation treatment operations as determined
by the data acquisition board 206. More specifically, by limiting
power consumption and memory usage to periods corresponding to only
active drilling or when the drilling mechanics indicates the
presence of natural fractures, such resources may be more
effectively used to capture a greater proportion of relevant
drilling data and/or drilling data at a higher resolution. For
example, when operating in burst mode, additional memory that would
otherwise be used to store irrelevant (i.e., non-active) drilling
data) may be used to accommodate longer burst durations and/or
increased burst frequencies as compared to a drilling measurement
system that does not differentiate between active and non-active
drilling periods and, as a result, constantly collects data in
burst mode. Similarly, when operating in continuous mode, the
additional memory that would otherwise be used to store irrelevant
drilling data may instead be used to decrease the rate of
decimation (e.g., reducing decimation from 1 in 10 samples to 1 in
5 samples) as compared to a drilling measurement system that does
not differentiate between active and non-active drilling periods.
For example, when drilling through a reservoir that is naturally
fractured, the ability to determine the nature and occurrences of
natural fractures from the processing and analysis of the drilling
dynamics data may benefit from a continuous mode of
acquisition.
[0090] In addition to the collecting and storing data, the drilling
measurement system 200 may also be configured to transmit drilling
data to a remote receiver. For example, the drilling measurement
system 200 may transmit data using a short hop communication system
to a mud pulser or other telemetry unit that then transmits the
data to a remote receiver. In certain implementations, the
transmission of data to the remote received occurs in real-time.
Alternatively, the drilling measurement system 200 may store data,
such as in the memory board 210, and transmit the data to the
remote server in batches at regular intervals or in response to
receiving a request from the remote receiver.
[0091] The data transmitted from the drilling measurement system
200 to the remote receiver may correspond to a reduced set of the
data generated by and/or stored by the drilling measurement system
200. Such reduced data sets may be useful for obtaining real-time
data and feedback from the drilling measurement system 200 during a
drilling operation. For example, the drilling measurement system
200 may sample the sensor array 250 at the native sample rate but
only transmit (and also possibly store) a band-limited root mean
square (RMS) average of the drill bit mechanics data corresponding
to a specific time window or record of the data. The RMS or other
attributes of the data could be further processed to obtain
mechanical rock property values. The mechanical rock property
measurements, or an average thereof over a particular period of
time, may then be transmitted to the remote receiver. Similarly,
the drilling measurement system 200 may be configured to retrieve
data from the memory board 210, perform further processing on the
retrieved data, and transmit the further processed data to the
remote receiver. For example, in one implementation, the drilling
measurement system 200 retrieves decimated/down-sampled data
obtained during operation in the continuous mode and processes the
data to obtain band-limited RMS measurements or mechanical rock
property values corresponding to the retrieved data. The
band-limited RMS measurements or mechanical rock property
measurements may then be transmitted to the remote receiver.
[0092] FIG. 4 is a schematic illustration of a data acquisition
board 300 that may be used in the drilling measurement system 200
of FIG. 3. The data acquisition board 300 includes an acquisition
microprocessor 326 in communication with one or more components
configured to receive and process signals from an accelerometer
array, such as the sensor array 250 of FIG. 3. More specifically,
the acquisition board 300 generally consists of digital selectable
circuits to amplify, integrate, filter and otherwise process
signals received from the sensor array 250.
[0093] To maintain low power consumption, the acquisition
microprocessor 326 may utilize a relatively slow microprocessor,
particularly as compared to the DSP math processor 240 of the DSP
board 208 shown in FIG. 3. The data acquisition board 300 may
include a read-only memory (ROM) 372, such as a PROM, for storing
instructions executable by the acquisition microprocessor 326 and a
random access memory (RAM) 374 for transitory storage of data used
by the acquisition microprocessor 326 during execution of the
instructions stored in the ROM 372. In general, the acquisition
microprocessor 326 is configured to perform functions, such as
obtaining RMS averages of digitized and filtered signals held in
the RAM 374, and arithmetic functions such as multiplication,
division, addition, and subtraction, including performing such
arithmetic functions on the calculated RMS averages.
[0094] The data acquisition board 300 is communicatively coupled,
such as by a bus, to a control board, such as the control board 204
of FIG. 3. During operation, the control board 204 communicates
data and instructions to the acquisition microprocessor 326 such as
a mode of operation and a time during which the data acquisition
board 300 is to be acquiring data from the sensor array. The data
and instructions from the control board 204 are generally used as
inputs during execution of the instructions stored in the ROM 372
by the acquisition microprocessor 326. For example, the
instructions stored in the ROM 372 may cause the acquisition
microprocessor 326 to digitally control, without limitation, one or
more of the rate at which the sensor array is sampled, the gain
applied to signals received from the sensor array, the parameters
of any filtration performed on signals received from the sensor
array, and other parameters related to signal processing.
[0095] In one implementation, the data acquisition board 300
supplies excitation current to the sensors of the sensor array
through a power supply 376 and determines the status of the
sensors. To determine the status of the sensors, the data
acquisition board 300 may first test for short and open circuits of
each of the channels of the sensor array. For example, under
control of the acquisition microprocessor 326 and prior to
sampling, the acquisition board 300 may examine the DC component of
signals from sensors of the sensor array. If the DC component of
the signals is found to be too near the voltage of a supply rail,
the circuit between the corresponding sensor and the acquisition
board 300 may be deemed to be open. Conversely, if the DC component
of a signal received from the sensor array is too near ground, the
corresponding circuit may be considered shorted. If the sensor
status test indicates either an open or short circuit condition
exists, the acquisition board 300 may be configured to transmit a
corresponding notification message or update a global sensor status
variable in response. The control board 204 may then receive the
message or retrieve the global variable identifying the abnormal
state and proceed with remedial measures including, without
limitation, activating or deactivating components of the drilling
measurement system 200 and transmitting an alarm or similar message
to an operator. Such an alarm or message may cause, without
limitation, illumination of a light emitting diode, a color change
of an icon or similar indicator of a system interface, generation
of an audible alarm, and the like.
[0096] In certain implementations, the sensor array consists of one
or more tri-axial mounted accelerometers where the axis of the
accelerometers are oriented to (i) the drilling face, (ii) the axis
of drilling, and (iii) the drilling collar. Accordingly, one
component (the axial channel) is perpendicular to the drilling
face, a second component (the lateral channel) is tangential to the
drilling collar and perpendicular to the direction of drilling, and
a third component (the radial channel) is oriented perpendicular to
each of the drilling collar and the drilling face. Multiple pairs
of accelerometers may be arranged in this configuration. In such
implementations, the lateral and radial channels of accelerometers
may be oriented perpendicular to each other, thereby forming an
accelerometer "dipole." By doing so, the lateral and radial
components of the accelerometers of the dipole may be summed, such
as by a summer 352 to produce a measurement of the angular
acceleration. In the implementation of FIG. 4, the summer 352
receives signals from the sensor array over multiple channels 382.
The summer 352 then combines the channels 382 to produce two
signals; the first signal (a) corresponding to the linear
acceleration of the drill bit and the second signal (a)
corresponding to the angular acceleration of the drill bit.
[0097] After summation of the sensor signals, the data acquisition
board 300 may perform gain ranging on each received signal using
one or more amplifiers 354. The amplifiers 354 amplify the signals
received from the accelerometers, which may be in the range of a
few millivolts, into higher voltage signals, which may span several
volts. Doing so aids in attenuating noise components of the
accelerometer signals and facilitates later processing of the
accelerometer signals.
[0098] In certain applications, drill bit mechanics, such as
drilling-induced vibrations, may be expected to have a wide dynamic
range. To enhance the resolution of the data, automatic gain
switching of the analog amplifiers may be used. In such
implementations, the amplifiers 354 may be digitally controlled
amplifiers under control of the acquisition microprocessor 326.
During operation, the acquisition microprocessor 326 may adjust the
gain applied by the amplifier 354 such that the highest suitable
gain is applied to the incoming accelerometer signals. For example,
at the beginning of each data collection, the amplifiers 354 are
initially set to maximum gain and the incoming vibration signals
are sampled. If the amplified signals equal or exceed a
predetermined threshold, the amplifier gain may be reduced by a
predetermined amount, for example, by use of a gain select bit
operating switch to change the feedback impedance of the gain
amplifier. In certain implementations, the corresponding gain
setting is attached or otherwise associated with data generated
from the amplified signals and stored with the data for future
reference.
[0099] After amplification, each of the sensor signals may be
passed through one or more integrators 356. For example, in
implementations in which the sensor signals include acceleration
signals received from one or more accelerometers, the accelerometer
signals may be passed through a first integrator circuit, which
converts the acceleration signals into velocity signals. The output
of the first integrator circuit is then passed through a second
integrator circuit, thereby converting the velocity signals into
position signals. Such conversion may be performed for each
incoming channel of the accelerometers of the sensor array.
Accordingly, in implementations in which there are two input
channels, one corresponding to angular acceleration and one
corresponding to axial acceleration, a minimum of six signals may
be generated using a two-integrator arrangement. Referring to the
implementation of FIG. 4, the integrators 356 receive an axial
acceleration signal (a) and an angular acceleration signal (a) as
amplified by the amplifiers 354. The acceleration signals are then
integrated using the integrators 356 to generate corresponding
velocity and displacement signals. More specifically, the axial
acceleration signal (a) is integrated to obtain an axial velocity
or rate of penetration signal (ROP), which is then integrated to
obtain an axial displacement signal (d). Similarly, the angular
acceleration signal (.alpha.) is first integrated to obtain an
angular velocity signal (.omega.), which is then integrated to
obtain an angular displacement signal (.theta.).
[0100] Each of the axial signals (a, ROP, d) and the angular
signals (.alpha., .omega., .theta.) may then be filtered using one
or more filters. Filtering conditions the signals prior to
digitization and limits the bandwidths over which data averaging
calculations, such as calculations for obtaining a band-limited RMS
measure of the signals, are obtained. In certain implementations,
filtering may be conducted using two successively cascaded switch
capacitive filter networks, the cutoff frequency of which may be
digitally controlled by the acquisition microprocessor 326. For
example, the acquisition board 300 may include two cascaded switch
capacitive filters, a high-pass filter 358 and a low-pass filter
360, which form the high- and a low-pass elements, respectively, of
a band pass filter 362. In certain implementations, each filter
stage is implemented using a four-pole capacitive filter network
set at preselected frequencies. For example, the frequencies could
be 150 Hz for the high pass stage and 1500 Hz for the low pass
stage. The low pass element of the band-pass filter 364 may
facilitate anti-aliasing of the vibration signals. Alternatively, a
separate anti-aliasing filter 380, such as a separate low pass
filter, may be used to reduce aliasing. The output of the band pass
filter 362 may also be fed into an additional filter for removing
spiking transients associated with the switch capacitive filters.
For example, one such additional filter may be a low-pass two-pole
Butterworth filter.
[0101] The acquisition board 326 may also include a filter channel
selector 366 and a filter signal selector 368. The filter channel
selector 366 and filter signal selector 368 may control the flow of
signals to and from the various filters of the acquisition board
300. For example, filter channel selector 366, under control of the
acquisition microprocessor 326, may select a particular one of the
signals generated by the integrators 356 and a corresponding one or
more of the filters of the acquisition board 326. Similarly, the
filter signal selector 368, under control of the acquisition
microprocessor 326, may selectively choose one or more filtered
signals to pass to an analog-to-digital (A/D) converter 370.
[0102] After filtration, the filtered signals are sent to the A/D
converter 370 for conversion into a digital format. For example, in
certain implementations, the A/D converter 370 is configured to
convert an analog signal into a 16-bit digital signal. In other
implementations, the A/D converter 370 may selectively convert the
analog signal to different resolutions based on commands received
from the acquisition microprocessor 326. For example, the
acquisition microprocessor may increase the resolution to 32-bit in
certain operational modes. The A/D conversion may also include a
track-and-hold circuit. Such a converter with 15-bit digitization
enables a dynamic range of 32768:1 (90 dB). When the last bit is
combined with the additional 20 dB of dynamic range that results
from the use of switchable gains in the analog amplifier, the
result is an overall data acquisition dynamic range of 110 dB.
[0103] After A/D conversion, the digitized time-domain data is
stored temporarily in a memory coupled to the acquisition
microprocessor 326, such as the RAM 374. After a predetermined
number of samples are acquired to form a record of a specified
length, such as the time required for a full rotation of the
corresponding drill bit, and depending on the mode of operation of
the drilling measurement system, the collected data is one or more
of (i) processed using the acquisition microprocessor 326; (ii)
transferred to storage, such as in the memory board 210 shown in
FIG. 3; or (iii) transferred to a DSP module for processing.
[0104] In embodiments in which the collected data is processed
using the acquisition microprocessor 326, such processing may
include, without limitation, one or more of: (i) taking
band-limited RMS averages of the drill bit mechanics; (ii) using
the RMS averages to inform mathematical functions related to the
"zero-frequency" level of the bit displacements, the motion of the
bit, and/or the forces on the bit, where the zero-frequency level
corresponds to mechanics of the drill bit when it is disengaged
from a subterranean formation; (iii) scaling the mechanics to
stress and strain experienced by the drill bit; (iv) processing the
stress and strain measurements to obtain mechanical rock property
values; (v) verifying that the mechanical rock property values fall
within a reasonable range of values for the formation being
drilled; and (vi) determining the status of drilling from the
mechanical rock property values. In certain implementations, the
mechanical rock property values obtained by the acquisition
microprocessor 326 may be stored in the memory 370 to enable taking
an average of mechanical rock property values obtained from several
consecutive records.
[0105] In certain implementations, the drilling status may be
determined without comparing the calculated mechanical rock
properties to known rock property values. More specifically, the
drilling status may be derived from the sensor signals or a
statistical attribute derived therefrom. For example, in certain
implementations, measurements of drill bit mechanics during a
drilling operation may be compared to empirical drill bit mechanics
data, such as drill bit mechanics data collected during previous
drilling operations. Notably, one benefit of using mechanical rock
properties derived from drill bit mechanics measurements is that
derivation of mechanical rock properties generally requires a
multivariate analysis that includes multiple drill bit mechanics
measurements. The multivariate nature of the analysis reduces the
likelihood of an ambiguous result regarding the drilling state.
Accordingly, in implementations in which drilling state is
determined based on an empirical analysis of drill bit mechanics
data, such an analysis may include comparing multiple signals or
corresponding statistical attributes.
[0106] If the mechanical rock property values are outside of a
specified range, the acquisition microprocessor 326 may determine
that the drill bit is not actively engaged with a subterranean
formation and may update a corresponding drilling state. For
example, the acquisition microprocessor 326 may transmit a drilling
state message to the control board 204 or may update a global
drilling state variable accessible by the control board 204. In
certain embodiments, the acquisition microprocessor 326 only
updates the drilling state to a new drilling state if a
predetermined number of cycles or a predetermined amount of time
has passed during which the new drilling state is maintained. By
doing so, the acquisition microprocessor 326 avoids inadvertently
changing drilling states. Depending on the mode of operation of the
drilling measurement system, the acquisition microprocessor 326 may
also send one or more of the processed drill bit mechanics data,
the mechanical rock property values, or summary data corresponding
to either of the drill bit mechanics data and the mechanical rock
property values to an interface board, such as interface board 212,
for transmission to a remote receiver.
[0107] FIG. 5 is a flow chart illustrating a method 400 for
controlling functions of a drilling measurement system for use in
drilling operations. Such a drilling measurement system may be
disposed in a bottom hole assembly (BHA) that further includes a
drill bit. The drilling measurement system may be configured to
measure and process mechanics of the drill bit during the course of
drilling operations and to selectively control components and/or
functions of the drilling measurement system based on a drilling
status that indicates whether the drill bit is actively
engaged/disengaged with a subterranean formation and/or
engaged/disengaged with a subterranean formation having specific
structural characteristics, such as natural fractures. The method
400 may be executed by an acquisition board, such as the
acquisition board 300 of FIG. 3. For example, the method 400 may be
stored as instructions in the read-only memory 372 of the
acquisition board 300 and executed by the acquisition
microprocessor 326.
[0108] The method 400 of FIG. 5 is directed to controlling a
drilling measurement system based on drill bit mechanics measured
using a sensor array and, more specifically, accelerometers within
a sensor array. Accelerometers are used merely as an example and,
as a result, the method 400 may be readily adapted for use with
other types of sensors. More specifically, although accelerometers
may be used to measure both motion of the drill bit and forces
acting on the drill bit, such information may also be obtained
using other combinations of sensors.
[0109] At operation 402, the acquisition microprocessor 326 updates
a drilling state to "not drilling." A "not drilling" state
generally corresponds to an operational state in which the drill
bit is not engaged with a subterranean formation. The current
drilling state is generally accessible by the acquisition board 300
and a control board, such as the control board 206 of FIG. 3, of
the drilling measurement system. The drilling state may take
several forms and may be implemented in various ways. For example,
in certain implementations, the drilling state is stored in a
global memory accessible by each of the acquisition board 300 and
the control board 206. Alternatively, each of the acquisition board
300 and the control board 206 may have local memories that include
a drilling state variable. In such implementations, the acquisition
board 300 may send messages or otherwise communicate changes to the
drilling state to the control board 206 and, in response to such
messages, the control board may update its local memory to reflect
the new drilling state.
[0110] At operation 404, the acquisition board 300 samples one or
more accelerometers of a sensor array, such as the sensor array 250
of FIG. 2. More specifically, the sensor array 250 may include one
or more accelerometers coupled to the BHA and configured to
generate signals in response to vibrations of the drill bit. In
certain implementations, the sensor array 250 includes at least one
accelerometer configured to generate a first signal in response to
axial acceleration of the drill bit and at least one accelerometer
configured to generate a second signal in response to rotational or
tangential acceleration of the drill bit. Each of the signals may
be communicated to the acquisition board 300 over a respective
channel.
[0111] At operation 406, the signals received from the sensor array
250 are processed and digitized into drill bit mechanics data. For
example, in certain implementations, the vibration signals are
processed by amplifying the signals, integrating the amplified
signals, and filtering, digitizing, and decimating each of the
signals obtained from the integration. Regarding integration, each
of the amplified signals, which may correspond to acceleration of
the drill bit, may undergo a first integration to obtain velocities
of the drill bit and a second integration to obtain displacements
of the drill bit.
[0112] At operation 408, the acquisition board 300 determines
whether the current drilling state is "drilling," indicating that
the drill bit is actively engaged with the subterranean formation.
As previously discussed in the context of FIG. 3, the control board
206 selectively activates and deactivates components and/or
functions of the drilling measurement system based on the current
drilling state. These components and functions may interact
directly with the acquisition board 300. For example, as shown in
FIG. 3, the drilling measurement system 200 may include each of a
mass memory board 210 for onboard data storage, a DSP board 208 for
additional signal processing of signals received by an acquisition
board 206, and an interface board 212 for transmitting data to a
remote receiver. Whether such components/functions are active may
generally be ascertained by the current drilling state. As a
result, to the extent any components or functions that depend on
drill bit mechanics data derived from signals provided by the
sensor array are active, the acquisition board 300 transmits the
drill bit mechanics data to the modules corresponding to the active
components/functions (operation 410).
[0113] In certain implementations, the acquisition board 300 is
configured to determine mechanical rock properties based on the
drill bit mechanics data. To do so, the acquisition board 300 may
collect multiple samples of the drill bit mechanics data and
generate a root mean square (RMS) value corresponding to the
sampled data. Accordingly, the acquisition board 300 generally
determines whether sufficient samples for the RMS calculation have
been collected (operation 412). If not, the current drill bit
mechanics data is stored in memory (operation 414), such as the RAM
374 shown in FIG. 3, and a subsequent signal is sampled from the
accelerometers of the sensor array 250. If sufficient drill bit
mechanics data has been collected, the acquisition board 300
calculates an RMS value for the collected data (operation 416). The
calculated RMS value may then be used by the acquisition board 300
to determine mechanical rock property values (operation 418). The
process of determining rock property values from the digitized
vibration data and RMS values obtained therefrom are provided in
more detail in U.S. patent application Ser. No. 14/850,710, filed
Sep. 10, 2015 and titled "Apparatus and Method Using Measurements
Taken while Drilling to Map Mechanical Boundaries and Mechanical
Rock Properties Along a Borehole" and U.S. patent application Ser.
No. 15/182,012, filed Jun. 14, 2016, also titled "Apparatus and
Method Using Measurements Taken while Drilling to Map Mechanical
Boundaries and Mechanical Rock Properties Along a Borehole."
[0114] After determining the mechanical rock property value, the
acquisition board may again determine whether the current drilling
state is "drilling," indicating that the drill bit is actively
engaged with the subterranean formation (operation 420). If so, the
acquisition board 300 may transmit the mechanical rock property
values to other modules of the drilling measurement system
(operation 422). For example, in certain implementations, the
mechanical rock property values may be transmitted to the mass
memory board 210 for storage or to the interface board 212 for
transmission to a remote server.
[0115] The mechanical rock property values may then be compared to
a range of mechanical rock property values (operation 424). More
specifically, the mechanical rock property values may be compared
to one or more predetermined ranges of mechanical rock property
values corresponding to known subterranean formations. For example,
in certain implementations the acquisition board 300 determines the
Young's modulus of elasticity (YME) and Poisson's ratio (PR)
corresponding to the calculated RMS value and compares the YME and
PR values to known values for one or more types of rock formations.
If the calculated mechanical rock property values will fall outside
the known range, the acquisition board 300 determines that the
drill bit is not currently engaged with a subterranean formation
and updates the current drilling state accordingly (return to
operation 402). If, on the other hand, the acquisition board 300
determines the mechanical rock property values fall within a known
range, the acquisition board 300 updates the drilling state to
indicate the drill bit is drilling (operation 426) and the process
of sampling the accelerometers begins again.
[0116] In the example method of FIG. 5, the mechanical rock
property data is used to determine a drilling state of the drilling
system (e.g., drilling v. not drilling) and to control storage and
transmission of data accordingly. In other implementations of the
present disclosure, the mechanical rock property values generated
by the drilling system (such as during operation 418) may be used
to control other drilling operations in addition to or instead of
controlling operations related to the storage and transmission of
data. For example, the calculated mechanical rock property values
may be used to identify features (e.g., fractures, boundaries,
bedding planes, etc.) or other characteristics of the subterranean
formation. Based on such characteristics, one or more operating
parameters of the drilling operation may be modified to change the
drilling system behavior.
[0117] As previously discussed herein, control of the drilling
system and corresponding drilling system behavior may include,
without limitation changes to a drilling mode, a drilling
direction, a drilling speed, a rotational speed of a drill bit or
top drive, a rate of penetration of the drill bit, or various other
drilling parameters. The characteristics of the formation may be
used as continuous feedback for controlling the drilling system or
may be used to indicate the occurrence of a particular event for
triggering a change in the operational parameters of the drilling
system. In the feedback context, for example, information regarding
the formation may be used to maintain the drill bit within a
particular section of the formation (such as by maintaining the
drill bit within a predetermined distance of a feature or
maintaining the drill bit within a portion of the formation having
particular characteristics), to maintain the drill bit at a
particular orientation relative to a feature or portion of the
formation having particular characteristics, or to preemptively
adjust the direction of the drill bit to account for deviations
that may result from drilling into the formation.
[0118] In certain implementations, the characteristics of the
subterranean formation inferred from the mechanical rock property
data may also be used to modify, supplement, or classify the
mechanical rock property data collected and/or transmitted by the
drilling measurement system. For example, in certain
implementations, the system may determine that a portion of the
subterranean formation is particularly susceptible to hydraulic
fracturing or similar treatment operations and classify the
corresponding mechanical rock property data accordingly. Such
classification may include, among other things, tagging the data
with a corresponding identifier or maintaining a separate log
including coordinates or other information for relevant portions of
the subterranean formation.
[0119] FIG. 6 is an example data output 600 of a drilling
measurement system in accordance with this disclosure, such as the
drilling measurement system 200 of FIG. 3. The data output 600 may
correspond to an output of a computing device communicatively
coupled to a surface receiver, such as the surface receiver 132 of
FIG. 1, the computing device adapted to collect and display data
received from the drilling measurement system 200.
[0120] The example data output 600 includes a drilling state plot
602, a Young's modulus of elasticity (YME) plot 604, and a
Poisson's ratio (PR) plot 610. The drilling state plot 602
indicates whether a drill bit coupled to the drilling measurement
system 200 is engaged with a subterranean formation over time. More
specifically, the drilling state plot 602 indicates a value of "1"
when the drill bit is determined to be engaged with the
subterranean formation and a value of "0" when the drill bit is
determined to be disengaged from the subterranean formation.
[0121] The drilling state indicated in the drilling state plot 602
is based, at least in part, on YME and PR values calculated by the
drilling measurement system 200 based on sensor signals, which are
displayed in the YME plot 604 and the PR plot 606, respectively.
The YME plot 604 includes a high YME line 606 and a low YME line
608 indicating the limits of YME values indicative of engagement of
the drill bit with the subterranean formation. Similarly, the PR
plot 610 includes a high PR line 612 and a low PR line 614
indicating the limits of PR values indicative of engagement of the
drill bit with the subterranean formation. As illustrated in FIG.
6, the drilling state plot 602 indicates that the drill bit is
engaged with a subterranean formation when each of the YME plot 604
and the PR plot 606 indicate that the calculated YME value is
between the high YME line 606 and the low YME line 608 and the PR
plot 606 is between the high PR line 612 and the low PR line
614.
[0122] The data output 600 of FIG. 6 is intended to illustrate
merely one possible output corresponding to data and measurements
collected using the drilling measurement system 200. In other
implementations, the data output 600 may include more or fewer data
plots for displaying data relevant to the drilling operation. Such
data may include one or more of the measurements or signals
collected by the data acquisition board 206 from the sensor array
250 and/or data derived therefrom. Data plots may also be used to
display measurements or signals corresponding to other sensors of a
bottom hole assembly into which the drilling measurement system 200
is integrated, such as a weight-on-bit or torque measurement. Data
plots may also be used to illustrate downhole conditions, such as
temperature and pressure, and diagnostic information, such as
memory usage, power consumption, remaining battery life, and the
like of the drilling measurement system 200 or any other component
of a bottom hole assembly including the drilling measurement system
200.
[0123] FIG. 7 is a flow chart illustrating a method 700 of
controlling a drilling system during a drilling operation in which
a drill bit is used to form a wellbore in a subterranean formation.
The method 700 may be executed by a system including a drilling
measurement system, such as the drilling measurement system 200 of
FIG. 2. In general and as described below in more detail, the
method 700 includes deriving mechanical rock property data based on
drill bit mechanics data (e.g., vibration measurements) obtained
during drilling of a subterranean formation using a drill bit. The
mechanical rock property data is then used to identify
characteristics of the subterranean formation which may include,
without limitation, features of the subterranean formation or
properties of the subterranean formation. Based on the
characteristics of the subterranean formation, the drilling system
modifies an operational parameter, resulting in a change in the
behavior of the drilling system. In response to identifying
particular characteristics of the subterranean formation the
drilling system may, for example, change one or more of a drilling
direction, a drilling speed, or a drilling mode of the drilling
system.
[0124] Referring now to FIG. 7, at operation 702, the system
receives sensor signals from one or more sensors, the sensor
signals corresponding to mechanics of the drill bit. For example,
and with reference to the drilling measurement system 200 of FIG.
2, one or more signals may be generated by the sensor array 250 and
transmitted to the acquisition board 206. As previously discussed,
the sensor array 250 may include, among other things,
accelerometers or similar sensors adapted to measure vibration and
other mechanics of the drill bit. The sensor signals received at
operation 702 may also include signals received from sensors of the
drilling system. For example the drilling system may further
include sensors adapted to measure and generate signals
corresponding to, among other things, one or more of a weight on
bit, a torque on bit, a rotational speed of the drill bit, a
rotational speed of a drill string coupled to the drill bit,
downhole pressure, downhole temperature, and operational
characteristics of a downhole motor or other bottom hole assembly
component. By processing the received sensor signals, the system
generates drill bit mechanics data (operation 704).
[0125] At operation 706, the system derives mechanical rock
property data from the drill bit mechanics data. The mechanical
rock property data may include, among other things, a Young's
modulus of elasticity (YME) or a Poisson's ratio (PR) of the
subterranean formation through which the drill bit drilled during
recordation of the drill bit mechanics, as previously described in
this disclosure. The mechanical rock properties may also include
relationships between different properties of the formation and/or
properties of different portions of the formation.
[0126] At operation 708, the system identifies a characteristic of
the subterranean based on the mechanical rock property data. As
previously noted in this disclosure, such characteristics may, in
certain implementations, include a geological feature of the
subterranean formation. Such geological features may include, among
other things, fractures (whether natural or the result of
fracturing operations), bedding planes, boundary layers, voids,
discontinuities, or other similar features that may be located
within the subterranean formation. The characteristics of the
subterranean formation may also include properties of the
subterranean formation related to drilling and/or other operations
that may be conducted on the subterranean formation. For example,
in one implementation, the property of the subterranean formation
may be a susceptibility of the subterranean formation to a
subsequent fracturing operation. As another example, discussed
below in more detail, the property of the subterranean formation
derived from the mechanical rock properties may include a direction
and/or degree of a predicted bias that the drill bit is likely to
experience as the drilling system continues to drill through the
subterranean formation.
[0127] At operation 710, the system modifies an operational
parameter of the drilling system to modify the drilling system
behavior based on the identified characteristic of the subterranean
formation. The operational parameter of the drilling system may
include, without limitation, an operational state of the drilling
system (e.g., on/off, drilling/not drilling), a drilling mode of
the drill system (e.g., slide drilling, rotational drilling), a
rotational speed of the drill bit, a rotational speed of a top
drive assembly, a direction or orientation of the drill bit, a
weight on bit, a rate of penetration, or any other similar
parameter of the drilling system that may be controlled. By
changing such operational parameters the behavior of the drilling
system can be modified accordingly.
[0128] In a first example, the characteristic of the subterranean
formation may be a geological feature such as a fracture or bedding
plane. In such cases, upon identifying the feature, the operational
parameters of the drilling system may be modified such that the
drill bit is maintained within at predetermined distance or within
a predetermined range of distances relative to the feature.
Alternatively, the system may be configured to maintain the drill
bit at a predetermined orientation relative to the feature. In
another example in which the characteristic of the subterranean
formation is a geological feature, the system may be configured to
automatically cease drilling operations if the drill bit is within
a certain range or the feature. Upon ceasing drilling operations,
the system may be further configured to generate and transmit an
alarm or alert message (e.g., an email, an automated voice message,
a text message, etc.) to relevant personnel.
[0129] In yet another implementation, the characteristic of the
subterranean formation may be a predicted bias that may be
experienced by the drill bit during a drilling operation. As the
drill bit is rotated to drill through a subterranean formation, the
drill bit generally experiences counter forces from the interaction
of the drill bit with the rock face. Such forces can result in a
deviation of the drill bit from an intended drilling trajectory
and, as a result, can cause unintended drift of the drill bit.
[0130] The nature of the counter forces experienced by the drill
bit and the resulting bias imposed on the drill bit may vary based
on variables of the drilling operation. For example and without
limitation, operational parameters of the drilling system, such as
the direction of drilling, the rotational speed of the drill bit,
the rotational speed of a top drive, and the amount of weight on
bit, each contribute to the nature of the interaction between the
drill bit and the rock face and, as a result, contribute to any
deviation from the intended drilling trajectory resulting from
drilling into the rock face. The characteristics of the
subterranean formation also contribute to the degree and direction
of bias experienced during drilling. For example, the YME and PR of
the rock being drilled may, at least in part, change each of the
degree and direction of bias likely to be experienced during drill.
Other characteristics of the subterranean formation, such as the
presence of fractures or other geological features, the direction
of the rock, the presence of certain deposits within the formation,
and the like, may similarly contribute to the degree and direction
of the bias.
[0131] In response to predicting a bias based on characteristics of
the subterranean formation, the drilling system may be controlled
to change one or more operational parameters of the drilling system
to offset or otherwise account for the bias. For example, in
response to determining a predicted bias, one or more of a
direction of the drill bit, a drilling mode (e.g., rotational
versus sliding drilling), a weight on bit, or similar parameter may
be modified to offset or otherwise account for the predicted
bias.
[0132] This general concept of offsetting a predicted bias derived
from mechanical rock properties is illustrated in more detail in
FIG. 8. FIG. 8 is a graphical representation 800 of biases and
offsets experienced by a drill bit of a drilling system. The
graphical representation 800 includes a first axis 802 and a second
axis 804 extending perpendicular to the first axis 802. The first
axis 802 and the second axis 804 indicate degrees of deviation in a
build/drop direction (the first axis 802) or a right/left direction
(the second axis 804). Accordingly, the intersection 806 of the
first axis 802 and the second axis 804 generally corresponds to a
straight ahead or "hold" condition.
[0133] The graphical representation 800 includes a plurality of
bias circles 808A-808D indicating the predicted bias resulting from
a particular combination of subterranean formation characteristics.
The location of the bias circles 808A-808D may also be based, at
least in part, on operational parameters of the drilling system,
such as the current drilling direction, rotational speeds of the
drill bit/top drive, weight on bit, and the like.
[0134] As illustrated, each of the bias circles 808A-8080 represent
different combinations of formation characteristics and/or
operational parameters resulting in varying degrees and directions
of biases in a rightward and building direction. Similarly, the
bias circle 808D corresponds to a combination of formation
characteristics and/or operational parameters resulting in a
leftward and dropping direction.
[0135] For each of the bias circles 808A-808D, the graphical
representation 800 also includes a corresponding offset circle
810A-810D. In general, each of the offset circles 810A-810D
indicates a drilling direction for correcting the bias associated
with the respective bias circles 808A-808D. For example, the offset
circle 810A indicates a leftward and dropping direction intended to
offset the rightward and building bias indicated by the bias circle
808A. Accordingly, if the drilling system is made to drill in the
direction indicated by the offset circle 810A, the bias represented
by the bias circle 808A may be overcome such that the drill bit is
maintained along a preferred drilling trajectory.
[0136] In summary, for a predicted bias resulting from a particular
combination of formation characteristics and/or operational
parameters, the system may determine a corresponding offset
intended to account for the bias such that the drill bit is
maintained along a desired drilling trajectory. As illustrated in
FIG. 8, the offset may simply be a "mirror" of the corresponding
predicted bias. For example, a leftward and dropping offset in a
first direction and having a first magnitude may be used to offset
a rightward and building bias in a second direction opposite the
first direction of the same magnitude. In other implementations,
the characteristics of the subterranean formation as determined by
the drill bit mechanics and/or operational parameters of the
drilling system may be such that the appropriate offset may require
correction or modification to properly account for the bias. For
example, the subterranean formation may be
non-uniform/heterogeneous such that the offset required to account
for the predicated bias is not simply a mirror of the predicted
bias. In such cases, the mechanical rock properties may be further
used to determine any modification or correction of the offset
required to properly account for the bias.
[0137] FIG. 9 is an example schematic diagram of a computing module
900 that may implement various methodologies discussed herein. For
example, the computing module 900 may correspond to one or more
circuit boards discussed herein, such as the acquisition board 300
of FIG. 3. The computing module 900 includes a bus 901, at least
one processor 902 or other computing element, at least one
communication port 903, a main memory 904, a removable storage
media 905, a read-only memory 906, and a mass storage device 907.
Processor(s) 902 can be any known processor, such as, but not
limited to, an Intel.RTM. Itanium.RTM. or Itanium 2.RTM.
processor(s), AMD.RTM. Opteron.RTM. or Athlon MP.RTM. processor(s),
or Motorola.RTM. lines of processors. Communication port 903 can be
any known communication port, such as, but not limited to an RS-232
port for use with a modem based dial-up connection, a 10/100
Ethernet port, a Gigabit port using copper or fiber, or a USB port.
Communication port(s) 903 may be chosen depending on a network such
as a Local Area Network (LAN), a Wide Area Network (WAN), or any
network to which the computing module 900 connects. The computing
module 900 may further include a transport and/or transit network
955, a display screen 960, an I/O port 940, and an input device 945
such as a mouse or keyboard.
[0138] The main memory 904 can be Random Access Memory (RAM) or any
other dynamic storage device(s) commonly known in the art. The
read-only memory 906 can be any static storage device(s) such as
Programmable Read-Only Memory (PROM) chips for storing static
information such as instructions for processor 902. The mass
storage device 907 can be used to store information and
instructions. For example, hard disks such as the Adaptec.RTM.
family of Small Computer Serial Interface (SCSI) drives, an optical
disc, an array of disks such as Redundant Array of Independent
Disks (RAID), such as the Adaptec.RTM. family of RAID drives, or
any other mass storage devices, may be used.
[0139] The bus 901 communicatively couples the processor(s) 902
with the other memory, storage, and communications blocks. The bus
901 can be any known bus, such as a PCI/PCI-X, SCSI, or Universal
Serial Bus (USB) based system bus depending on the storage devices
used. The removable storage media 905 can be any kind of external
hard drives, thumb drives, Compact Disc-Read Only Memory (CD-ROM),
Compact Disc-Re-Writable (CD-RW), Digital Video Disk-Read Only
Memory (DVD-ROM), and the like.
[0140] Embodiments herein may be provided as a computer program
product, which may include a machine-readable medium having stored
thereon instructions which may be used to program a computer (or
other electronic devices) to perform a process. The
machine-readable medium may include, but is not limited to optical
discs, CD-ROMs, magneto-optical disks, ROMs, RAMs, erasable
programmable read-only memories (EPROMs), electrically erasable
programmable read-only memories (EEPROMs), magnetic or optical
cards, flash memory, or other type of media/machine-readable medium
suitable for storing electronic instructions. Moreover, embodiments
herein may also be downloaded as a computer program product,
wherein the program may be transferred from a remote computer to a
requesting computer by way of data signals embodied in a carrier
wave or other propagation medium via a communication link (e.g.,
modem or network connection).
[0141] As shown, the main memory 904 is encoded instructions
executable by the processor 902 for performing the functionality
discussed herein. For example, in one embodiment, the executable
instructions may include or otherwise implement functions for
processing analog vibration signals to generate corresponding
digitized data, determine mechanical rock property values from the
digitized data, store or transmit any of the digitized data and the
mechanical rock property data, and selectively activate other
components based on a drilling state. At least a portion of the
executable instructions can be embodied as software code such as
data and/or logic instructions (e.g., code stored in the memory or
on another computer readable medium such as a disk) that support
processing functionality according to different embodiments
described herein. During operation of one embodiment, the
processor(s) 902 accesses the main memory 904 via use of the bus
901 in order to launch, run, execute, interpret, or otherwise
perform processes, such as through logic instructions, executing on
the processor(s) 902 and associated software modules stored in the
main memory 904 or otherwise tangibly stored.
[0142] The description above includes example systems, methods,
techniques, instruction sequences, and/or computer program products
that embody techniques of the present disclosure. However, it is
understood that the described disclosure may be practiced without
these specific details. In the present disclosure, the methods
disclosed may be implemented as sets of instructions or software
readable by a device. Further, it is understood that the specific
order or hierarchy of steps in the methods disclosed are instances
of example approaches. Based upon design preferences, it is
understood that the specific order or hierarchy of steps in the
method can be rearranged while remaining within the disclosed
subject matter. The accompanying method claims present elements of
the various steps in a sample order, and are not necessarily meant
to be limited to the specific order or hierarchy presented.
[0143] The described disclosure may be provided as a computer
program product, or software, that may include a machine-readable
medium having stored thereon instructions, which may be used to
program a computer system (or other electronic devices) to perform
a process according to the present disclosure. A machine-readable
medium includes any mechanism for storing information in a form
(e.g., software, processing application) readable by a machine
(e.g., a computer). The machine-readable medium may include, but is
not limited to optical storage medium (e.g., CD-ROM);
magneto-optical storage medium, read only memory (ROM); random
access memory (RAM); erasable programmable memory (e.g., EPROM and
EEPROM); flash memory; or other types of medium suitable for
storing electronic instructions.
[0144] It is believed that the present disclosure and many of its
attendant advantages should be understood by the foregoing
description, and it should be apparent that various changes may be
made in the form, construction, and arrangement of the components
without departing from the disclosed subject matter or without
sacrificing all of its material advantages. The form described is
merely explanatory, and it is the intention of the following claims
to encompass and include such changes.
[0145] While the present disclosure has been described with
reference to various implementations, it will be understood that
these implementations are illustrative and that the scope of the
disclosure is not limited to them. Many variations, modifications,
additions, and improvements are possible. More generally,
implementations in accordance with the present disclosure have been
described in the context of particular implementations.
Functionality may be separated or combined in blocks differently in
various embodiments of the disclosure or described with different
terminology. These and other variations, modifications, additions,
and improvements may fall within the scope of the disclosure as
defined in the claims that follow.
* * * * *