U.S. patent application number 16/707420 was filed with the patent office on 2020-06-18 for systems and methods to control drilling operations based on formation orientations.
This patent application is currently assigned to Baker Hughes, a GE company, LLC. The applicant listed for this patent is Stefan Bartetzko Wessling. Invention is credited to Anne Claudia Maria Bartetzko, Imed Ben Brahim, Michael Neubert, Stefan Wessling.
Application Number | 20200190960 16/707420 |
Document ID | / |
Family ID | 71071121 |
Filed Date | 2020-06-18 |
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United States Patent
Application |
20200190960 |
Kind Code |
A1 |
Wessling; Stefan ; et
al. |
June 18, 2020 |
SYSTEMS AND METHODS TO CONTROL DRILLING OPERATIONS BASED ON
FORMATION ORIENTATIONS
Abstract
Systems and methods for controlling drilling operations are
provided. The methods include performing a drilling operation using
a bottomhole assembly having a disintegrating device located at an
end of a drill string. Detecting and monitoring formation layer
orientations with one or more sensors is performed to obtain
formation layer orientation information indicative of a formation
layer orientation. Monitoring of a drilling operational performance
of at least one of the disintegrating device and the bottomhole
assembly is performed. A change in the drilling operational
performance is detected and adjustment of a steering command is
performed to set an angle of attack by the disintegrating device to
the formation layer orientation based on the formation layer
orientation information.
Inventors: |
Wessling; Stefan; (Hannover,
DE) ; Bartetzko; Anne Claudia Maria; (Celle, DE)
; Brahim; Imed Ben; (Isernhagen, DE) ; Neubert;
Michael; (Braunschweig, DE) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Wessling; Stefan
Bartetzko; Anne Claudia Maria
Brahim; Imed Ben
Neubert; Michael |
Hannover
Celle
Isernhagen
Braunschweig |
|
DE
DE
DE
DE |
|
|
Assignee: |
Baker Hughes, a GE company,
LLC
Houston
TX
|
Family ID: |
71071121 |
Appl. No.: |
16/707420 |
Filed: |
December 9, 2019 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
62778360 |
Dec 12, 2018 |
|
|
|
Current U.S.
Class: |
1/1 |
Current CPC
Class: |
E21B 44/00 20130101;
E21B 49/003 20130101; E21B 44/04 20130101; E21B 47/026 20130101;
E21B 45/00 20130101; E21B 7/04 20130101; G01V 11/00 20130101; E21B
49/08 20130101; E21B 44/02 20130101 |
International
Class: |
E21B 44/04 20060101
E21B044/04; E21B 45/00 20060101 E21B045/00; E21B 49/00 20060101
E21B049/00; E21B 7/04 20060101 E21B007/04; G01V 11/00 20060101
G01V011/00 |
Claims
1. A method for controlling a drilling operation comprising:
performing a drilling operation using a bottomhole assembly having
a disintegrating device located at an end of a drill string;
detecting and monitoring formation layer orientations with one or
more sensors to obtain formation layer orientation information
indicative of a formation layer orientation; monitoring a drilling
operational performance of at least one of the disintegrating
device and the bottomhole assembly; detecting a change in the
drilling operational performance; and adjusting a steering command
to set an angle of attack by the disintegrating device to the
formation layer orientation based on the formation layer
orientation information.
2. The method of claim 1, wherein the drilling operational
performance comprises at least one of rate of penetration,
revolutions per minute, downhole pressure, drilling vibration,
torque, weight-on-bit, and bending moment.
3. The method of claim 1, wherein the one or more sensors for
detecting formation layer orientations comprise one or more of
acoustic sensors, ultrasonic sensors, resistivity sensors, gamma
ray sensors, density sensors, radiation sensors, or dipmeters.
4. The method of claim 1, wherein the steering command is adjusted
to have an angle of attack of the disintegrating device relative to
the formation layer orientation to be 50.degree. or greater.
5. The method of claim 1, wherein the change in drilling
operational performance is indicative of a change in the formation
layer orientation.
6. The method of claim 1, wherein at least one sensor of the one or
more sensors is located within the bottomhole assembly.
7. The method of claim 1, further comprising at least one of
transmitting the formation layer information to a surface control
unit for processing and transmitting an adjusted steering command
from the surface control unit the bottomhole assembly.
8. The method of claim 1, further comprising automatically
performing the monitoring, detecting, and adjusting with a downhole
controller of the bottomhole assembly.
9. The method of claim 1, further comprising moving the drill
string away from bottomhole prior to adjusting the steering
command.
10. The method of claim 1, wherein the angle of attack is generated
by setting a steering force perpendicular to the formation layer
orientation.
11. The method of claim 1, further comprising estimating a
formation layer orientation based on at least one of the formation
layer orientation information, offset well data, and historical
data.
12. A system for controlling a drilling operation comprising: a
drill string; a bottomhole assembly having a disintegrating device
disposed at an end of the drill string, wherein the disintegrating
device is used to perform a drilling operation and wherein the
bottomhole assembly is configured to drill into a formation based
on a steering command; and one or more sensors configured to detect
and monitor formation layer orientations and obtain formation layer
orientation information indicative of a formation layer
orientation; wherein a drilling operational performance of at least
one of the disintegrating device and the bottomhole assembly is
monitored by one or more associated sensors to detect a change in
the drilling operational performance, and wherein a steering
command is adjusted to set an angle of attack of the disintegrating
device relative to the detected formation layer orientation when a
change in the drilling operational performance is detected.
13. The system of claim 12, wherein the drilling operational
performance comprises at least one of rate of penetration,
revolutions per minute, downhole pressure, drilling vibration,
torque, weight-on-bit, and bending moment.
14. The system of claim 12, wherein the one or more sensors for
monitoring formation layer orientations comprise one or more of
acoustic sensors, ultrasonic sensors, resistivity sensors, gamma
ray sensors, density sensors, radiation sensors, or dipmeters.
15. The system of claim 12, wherein the steering command is
adjusted to have an angle of attack of the disintegrating device to
the formation change to be 50.degree. or greater.
16. The system of claim 12, wherein the angle of attack is
generated by setting a steering force perpendicular to the
formation layer orientation.
17. The system of claim 12, wherein at least one sensor of the one
or more sensors for monitoring formation layer orientations is
located within the bottomhole assembly.
18. The system of claim 12, wherein the bottomhole assembly further
comprises at least one of a transmitter to transmit the formation
layer information to a surface control unit for processing and a
receiver for receiving an adjusted steering command from the
surface control unit.
19. The system of claim 12, wherein the bottomhole assembly is
configured to perform the monitoring, detecting, and adjusting
automatically.
20. The system of claim 12, wherein the bottomhole assembly
comprises an imaging unit, a measurement-while-drilling unit, and a
steering unit.
Description
CROSS REFERENCE TO RELATED APPLICATIONS
[0001] This application claims the benefit of an earlier filing
date from U.S. Provisional Application Ser. No. 62/778,360 filed
Dec. 12, 2018, the entire disclosure of which is incorporated
herein by reference.
BACKGROUND
1. Field of the Invention
[0002] The present invention generally relates to subsurface
operations and more particularly to controlling drilling operations
based on formation orientations.
2. Description of the Related Art
[0003] Boreholes are drilled deep into the earth for many
applications such as carbon dioxide sequestration, geothermal
production, and hydrocarbon exploration and production. In all of
the applications, the boreholes are drilled such that they pass
through or allow access to energy or a material (e.g., heat, a gas,
or fluid) contained in a formation located below the earth's
surface. Different types of tools and instruments may be disposed
in the boreholes to perform various tasks and measurements.
[0004] Changes in rock properties, in particular hardness, may
cause complications with drilling operations (e.g., rates of
penetration). In particular, unexpected, thin layers of harder
rocks can slow rates of penetration, impact wear on bits, or cause
other issues during drilling. Often, these are called "stringers"
in the rock description. Stringers are loosely-defined inclusions
of sedimentary material which is deposited during the sedimentation
process with significantly different rock properties compared to
the rock material of adjacent sediments. Stringers may also be
portions of a sandstone with calcite cement and/or fractures or
veins filled with calcite of quartz. Additionally, stringers may be
layers with a high content of pebbles, such as (cemented)
conglomerates. Thus, as will be appreciated by those of skill in
the art, stringers may take many different forms, but are typically
a layer that is much harder than adjacent layers. In the present
disclosure, the term "stringer" is employed to refer to any hard
layer in the formation, independent of its particular nature and
origin.
[0005] During a drilling operation, contact with the stringers may
drastically reduce the rate of penetration (ROP) and cause
inappropriate drilling parameters. Such inappropriate drilling
parameters (e.g., unfavorable conditions) can deteriorate the bit,
reamers, and the performance of a bottomhole assembly. Therefore,
knowledge of such stringers and appropriate actions taken in
response may be advantageous.
SUMMARY
[0006] Disclosed herein are systems and methods for controlling a
drilling operation. The systems and methods include performing a
drilling operation using a bottomhole assembly having a
disintegrating device located at an end of a drill string;
monitoring formation layer orientations with one or more sensors
located remote from the disintegrating device to obtain formation
layer orientation information; monitoring an operational
performance of the disintegrating device; detecting a change in
drilling operational performance indicative of a formation change;
estimating a formation orientation of the formation change based on
the formation layer orientation information obtained from at least
one of the one or more sensors, offset well data, and historical
data; and adjusting a drilling trajectory to set an angle of
approach by the disintegrating device to the formation change.
[0007] In accordance with some embodiments, the methods and systems
can include performing a drilling operation using a bottomhole
assembly having a disintegrating device located at an end of a
drill string. Detecting and monitoring formation layer orientations
with one or more sensors is performed to obtain formation layer
orientation information indicative of a formation layer
orientation. Monitoring of a drilling operational performance of at
least one of the disintegrating device and the bottomhole assembly
is performed. A change in the drilling operational performance is
detected and adjustment of a steering command is performed to set
an angle of attack by the disintegrating device to the formation
layer orientation based on the formation layer orientation
information.
BRIEF DESCRIPTION OF THE DRAWINGS
[0008] The subject matter, which is regarded as the invention, is
particularly pointed out and distinctly claimed in the claims at
the conclusion of the specification. The foregoing and other
features and advantages of the invention are apparent from the
following detailed description taken in conjunction with the
accompanying drawings, wherein like elements are numbered alike, in
which:
[0009] FIG. 1 is an example of a system for performing subsurface
operations that can employ embodiments of the present
disclosure;
[0010] FIG. 2 includes schematic illustrations of a structural
Earth model around a well trajectory and a density image of the
borehole track;
[0011] FIGS. 3A-3E are illustrative consecutive measured depth
plots as an image sensor passes along a well trajectory;
[0012] FIG. 4 is an illustrative Earth formation model obtained
from a plurality of measurements and/or images in accordance with
an embodiment of the present disclosure;
[0013] FIG. 5 is a flow process for controlling a drilling
operation in accordance with an embodiment of the present
disclosure; and
[0014] FIG. 6 is a schematic illustration of an adjusted drilling
trajectory as achieved in accordance with an embodiment of the
present disclosure.
DETAILED DESCRIPTION
[0015] FIG. 1 shows a schematic diagram of a system for performing
subsurface operations (e.g., downhole, within the earth or below
other surface and into a formation). As shown, the system is a
drilling system 10 that includes a drill string 20 having a
drilling assembly 90, also referred to as a bottomhole assembly
(BHA), conveyed in a borehole or borehole 26 penetrating an earth
formation 60. The drilling system 10 includes a conventional
derrick 11 erected on a floor 12 that supports a rotary table 14
that is rotated by a prime mover, such as an electric motor (not
shown), at a desired rotational speed. The drill string 20 includes
a drill pipe 22 or drilling tubular extending downward from the
rotary table 14 into the borehole 26. A disintegrating device 50,
such as a drill bit attached to the end of the drilling assembly
90, disintegrates the geological formations when it is rotated to
drill the borehole 26. The drill string 20 is coupled to a
drawworks 30 via a kelly joint 21, swivel 28, traveling block 25,
and line 29 through a pulley 23. During the drilling operations,
the drawworks 30 is operated to control the weight-on-bit (WOB),
which affects the rate of penetration. The operation of the
drawworks 30 is well known in the art and is thus not described in
detail herein.
[0016] During drilling operations a suitable drilling fluid 31
(also referred to as the "mud") from a source or mud pit 32 is
circulated under pressure through the drill string 20 by a mud pump
34. The drilling fluid 31 passes into the drill string 20 via a
desurger 36, fluid line 38 and the kelly joint 21. Fluid line 38
may also be referred to as a mud supply line. The drilling fluid 31
is discharged at the borehole bottom 51 through an opening in the
disintegrating device 50. The drilling fluid 31 circulates uphole
through the annular space 27 between the drill string 20 and the
borehole 26 and returns to the mud pit 32 via a return line 35. A
sensor S1 in the line 38 provides information about the fluid flow
rate. A surface torque sensor S2 and a sensor S3 associated with
the drill string 20 respectively provide information about the
torque and the rotational speed of the drill string. Additionally,
one or more sensors (not shown) associated with line 29 are used to
provide the hook load of the drill string 20 and about other
desired parameters relating to the drilling of the borehole 26. The
system may further include one or more downhole sensors 70 located
on the drill string 20 and/or the drilling assembly 90.
[0017] In some applications the disintegrating device 50 is rotated
by rotating the drill pipe 22. However, in other applications, a
drilling motor 55 (such as a mud motor) disposed in the drilling
assembly 90 is used to rotate the disintegrating device 50 and/or
to superimpose or supplement the rotation of the drill string 20.
In either case, the rate of penetration (ROP) of the disintegrating
device 50 into the formation 60 for a given formation and a
drilling assembly largely depends upon the weight-on-bit and the
rotational speed of the disintegrating device 50. In one aspect of
the embodiment of FIG. 1, the drilling motor 55 is coupled to the
disintegrating device 50 via a drive shaft (not shown) disposed in
a bearing assembly 57. If a mud motor is employed as the drilling
motor 55, the mud motor rotates the disintegrating device 50 when
the drilling fluid 31 passes through the drilling motor 55 under
pressure. The bearing assembly 57 supports the radial and axial
forces of the disintegrating device 50, the downthrust of the
drilling motor and the reactive upward loading from the applied
weight-on-bit. Stabilizers 58 coupled to the bearing assembly 57
and at other suitable locations on the drill string 20 act as
centralizers, for example for the lowermost portion of the drilling
motor assembly and other such suitable locations.
[0018] A surface control unit 40 receives signals from the downhole
sensors 70 and devices via a sensor 43 placed in the fluid line 38
as well as from sensors S1, S2, S3, hook load sensors, sensors to
determine the height of the traveling block (block height sensors),
and any other sensors used in the system and processes such signals
according to programmed instructions provided to the surface
control unit 40. For example, a surface depth tracking system may
be used that utilizes the block height measurement to determine a
length of the borehole (also referred to as measured depth of the
borehole) or the distance along the borehole from a reference point
at the surface to a predefined location on the drill string 20,
such as the disintegrating device 50 or any other suitable location
on the drill string 20 (also referred to as measured depth of that
location, e.g. measured depth of the disintegrating device 50).
Determination of measured depth at a specific time may be
accomplished by adding the measured block height to the sum of the
lengths of all equipment that is already within the borehole at the
time of the block-height measurement, such as, but not limited to
drill pipes 22, drilling assembly 90, and disintegrating device 50.
Depth correction algorithms may be applied to the measured depth to
achieve more accurate depth information. Depth correction
algorithms, for example, may account for length variations due to
pipe stretch or compression due to temperature, weight-on-bit,
borehole curvature and direction. By monitoring or repeatedly
measuring block height, as well as lengths of equipment that is
added to the drill string 20 while drilling deeper into the
formation over time, pairs of time and depth information are
created that allow estimation of the depth of the borehole 26 or
any location on the drill string 20 at any given time during a
monitoring period. Interpolation schemes may be used when depth
information is required at a time between actual measurements. Such
devices and techniques for monitoring depth information by a
surface depth tracking system are known in the art and therefore
are not described in detail herein.
[0019] The surface control unit 40 displays desired drilling
parameters and other information on a display/monitor 42 for use by
an operator at the rig site to control the drilling operations. The
surface control unit 40 contains a computer that may comprise
memory for storing data, computer programs, models and algorithms
accessible to a processor in the computer, a recorder, such as tape
unit, memory unit, etc. for recording data and other peripherals.
The surface control unit 40 also may include simulation models for
use by the computer to process data according to programmed
instructions. The control unit responds to user commands entered
through a suitable device, such as a keyboard. The control unit 40
can output certain information through an output device, such as a
display, a printer, an acoustic output, etc., as will be
appreciated by those of skill in the art. The control unit 40 is
adapted to activate alarms 44 when certain unsafe or undesirable
operating conditions occur.
[0020] The drilling assembly 90 may also contain other sensors and
devices or tools for providing a variety of measurements relating
to the formation 60 surrounding the borehole 26 and for drilling
the borehole 26 along a desired path. Such devices may include a
device for measuring formation properties, such as the formation
resistivity or the formation gamma ray intensity around the
borehole 26, near and/or in front of the disintegrating device 50
and devices for determining the inclination, azimuth and/or
position of the drill string. A logging-while-drilling (LWD) device
for measuring formation properties, such as a formation resistivity
tool 64 or a gamma ray device 76 for measuring the formation gamma
ray intensity, made according an embodiment described herein may be
coupled to the drill string 20 including the drilling assembly 90
at any suitable location. For example, coupling can be above a
lower kick-off subassembly 62 for estimating or determining the
resistivity of the formation 60 around the drill string 20
including the drilling assembly 90. Another location may be near or
in front of the disintegrating device 50, or at other suitable
locations. A directional survey tool 74 that may comprise means to
determine the direction of the drilling assembly 90 with respect to
a reference direction (e.g., magnetic north, vertical up or down
direction, etc.), such as a magnetometer, gravimeter/accelerometer,
gyroscope, etc. may be suitably placed for determining the
direction of the drilling assembly, such as the inclination, the
azimuth, and/or the toolface of the drilling assembly. Any suitable
direction survey tool may be utilized. For example, the directional
survey tool 74 may utilize a gravimeter, a magnetometer, or a
gyroscopic device to determine the drill string direction (e.g.,
inclination, azimuth, and/or toolface). Such devices are known in
the art and therefore are not described in detail herein.
[0021] Direction of the drilling assembly may be monitored or
repeatedly determined to allow for, in conjunction with depth
measurements as described above, the determination of a borehole
trajectory in a three-dimensional space. In the above-described
example configuration, the drilling motor 55 transfers power to the
disintegrating device 50 via a shaft (not shown), such as a hollow
shaft, that also enables the drilling fluid 31 to pass from the
drilling motor 55 to the disintegrating device 50. In alternative
embodiments, one or more of the parts described above may appear in
a different order, or may be omitted from the equipment described
above.
[0022] Still referring to FIG. 1, other LWD devices (generally
denoted herein by numeral 77), such as devices for measuring rock
properties or fluid properties, such as, but not limited to,
porosity, permeability, density, salt saturation, viscosity,
permittivity, sound speed, etc. may be placed at suitable locations
in the drilling assembly 90 for providing information useful for
evaluating the subsurface formations 60 or fluids along borehole
26. Such devices may include, but are not limited to, acoustic
tools, nuclear tools, nuclear magnetic resonance tools,
permittivity tools, and formation testing and sampling tools.
[0023] The above-noted devices may store data to a memory downhole
and/or transmit data to a downhole telemetry system 72, which in
turn transmits the received data uphole to the surface control unit
40. The downhole telemetry system 72 may also receive signals and
data from the surface control unit 40 and may transmit such
received signals and data to the appropriate downhole devices. In
one aspect, a mud pulse telemetry system may be used to communicate
data between the downhole sensors 70 and devices and the surface
equipment during drilling operations. A sensor 43 placed in the
fluid line 38 may detect the mud pressure variations, such as mud
pulses responsive to the data transmitted by the downhole telemetry
system 72. Sensor 43 may generate signals (e.g., electrical
signals) in response to the mud pressure variations and may
transmit such signals via a conductor 45 or wirelessly to the
surface control unit 40. In other aspects, any other suitable
telemetry system may be used for one-way or two-way data
communication between the surface and the drilling assembly 90,
including but not limited to, a wireless telemetry system, such as
an acoustic telemetry system, an electro-magnetic telemetry system,
a wired pipe, or any combination thereof. The data communication
system may utilize repeaters in the drill string or the borehole.
One or more wired pipes may be made up by joining drill pipe
sections, wherein each pipe section includes a data communication
link that runs along the pipe. The data connection between the pipe
sections may be made by any suitable method, including but not
limited to, electrical or optical line connections, including
optical, induction, capacitive or resonant coupling methods. A data
communication link may also be run along a side of the drill string
20, for example, if coiled tubing is employed.
[0024] The drilling system described thus far relates to those
drilling systems that utilize a drill pipe to convey the drilling
assembly 90 into the borehole 26, wherein the weight-on-bit is
controlled from the surface, typically by controlling the operation
of the drawworks. However, a large number of the current drilling
systems, especially for drilling highly deviated and horizontal
boreholes, utilize coiled-tubing for conveying the drilling
assembly subsurface. In such application a thruster is sometimes
deployed in the drill string to provide the desired force on the
disintegrating device 50. Also, when coiled-tubing is utilized, the
tubing is not rotated by a rotary table but instead it is injected
into the borehole by a suitable injector while a downhole motor,
such as drilling motor 55, rotates the disintegrating device 50.
For offshore drilling, an offshore rig or a vessel is used to
support the drilling equipment, including the drill string.
[0025] Still referring to FIG. 1, a resistivity tool 64 may be
provided that includes, for example, a plurality of antennas
including, for example, transmitters 66a or 66b or and receivers
68a or 68b. Resistivity can be one formation property that is of
interest in making drilling decisions. Those of skill in the art
will appreciate that other formation property tools can be employed
with or in place of the resistivity tool 64.
[0026] Liner drilling or casing drilling can be one configuration
or operation used for providing a disintegrating device that
becomes more and more attractive in the oil and gas industry as it
has several advantages compared to conventional drilling. One
example of such configuration is shown and described in commonly
owned U.S. Pat. No. 9,004,195, entitled "Apparatus and Method for
Drilling a Borehole, Setting a Liner and Cementing the Borehole
During a Single Trip," which is incorporated herein by reference in
its entirety. Importantly, despite a relatively low rate of
penetration, the time of getting a liner to target is reduced
because the liner is run in-hole while drilling the borehole
simultaneously. This may be beneficial in swelling formations where
a contraction of the drilled well can hinder an installation of the
liner later on. Furthermore, drilling with liner in depleted and
unstable reservoirs minimizes the risk that the pipe or drill
string will get stuck due to hole collapse.
[0027] One or more sensors of the systems may be configured to
sense amplitudes of vibrations or oscillations over time may be
disposed on the drill string or the BHA. In one or more
embodiments, one or more of the sensors may be disposed near the
drill bit or disintegrating device so as to sense vibrations or
oscillations at a point of excitation of the drill string. The
drill bit may be considered a point of excitation due to
interaction of the drill bit with a formation rock as the formation
rock is being drilled. Alternatively, or in addition thereto, one
or more sensors may be configured to sense torque. Sensed data from
the one or more sensors may be transmitted to a surface receiver or
a surface computer processing system for processing. Alternatively,
or in addition thereto, sensor data may be processed downhole by
downhole electronics, which may also provide an interface with a
telemetry system.
[0028] Although FIG. 1 is shown and described with respect to a
drilling operation, those of skill in the art will appreciate that
similar configurations, albeit with different components, can be
used for performing different subsurface operations. For example,
wireline, coiled tubing, and/or other configurations can be used as
known in the art. Further, production configurations can be
employed for extracting and/or injecting materials from/into earth
formations. Thus, the present disclosure is not to be limited to
drilling operations but can be employed for any appropriate or
desired subsurface operation(s).
[0029] Disclosed herein are systems and methods for controlling
drilling and reaming operations, and particularly to optimize
and/or improve efficiencies thereof. More particularly, embodiments
disclosed herein are directed to optimization of a drilling
operation with respect to and through a "hard" formation (e.g., a
stringer or other formation change). Such drilling operations and
methods described herein can include conducting a drilling or
reaming operation, monitoring the orientation of formation
beds/boundaries using images of a borehole wall or dipmeters,
monitoring parameters indicative of the drilling progress,
anticipating and detecting a decrease in the drilling progress,
defining an attack angle based on the orientation of formation
beds, and setting a steering command to drill at the attack angle
with respect to a formation layer/bed. Embodiments described herein
aid in drilling operations through a formation stringer or hard
layer with optimum performance, and at a preferred angle which can
minimize dogleg, which in turn reduces the risk in drilling and
completion challenges (e.g., stuck pipe and the like).
[0030] As described above, stringers or formation changes which
create challenges for the drilling operational performance are hard
formation beds which originate from the local deposition (like
spills) of sediment material such as calcite or may form from other
processes. Stringers are loosely-defined inclusions of sedimentary
material which is deposited during the sedimentation process with
significantly different rock properties compared to the rock
material of adjacent sediments. Stringers may also be portions of a
sandstone with calcite cement and/or fractures or veins filled with
calcite of quartz. Additionally, stringers may be layers with a
high content of pebbles, such as (cemented) conglomerates. Thus, as
will be appreciated by those of skill in the art, stringers may
take many different forms, but are typically a layer that is much
harder than adjacent layers. In the present disclosure, the term
"stringer" is employed to refer to any hard layer in the formation,
independent of its particular nature and origin.
[0031] Stringers and other formation changes are typically aligned
parallel to the other formation beds, and thus an extrapolation of
the orientation of detected formation layers may be employed to
estimate an orientation of a stringer. That is, currently and/or
previously drilled through layers may be monitored for orientation
to extrapolate an orientation of a stringer that may be encountered
in the future of the drilling operation. Embodiments provided
herein are directed to a process that uses images of the borehole
wall and/or other finite element logs that are indicative of the
orientation of formation beds to adjust an attack angle with
respect to a stringer. The detected orientation is employed to
drill at and through a stringer at a specific target angle (i.e.,
attack angle) by either applying a force normal to the stringer
orientation, as soon as the stringer has been detected, or by
drilling the optimal stringer attack angle, as soon as the stringer
and its orientation can be anticipated.
[0032] Stringers and other formation changes are usually detected
by measuring drilling operational parameters such as weight-on-bit
(WOB), torque, rate of penetration (ROP), revolutions per minute
(RPM), downhole pressure, drilling vibration, bending moment, etc.,
which exhibit a drastic change as soon as the bit or other
disintegrating device contacts a stringer. Such parameters thus
indicate the drilling operation performance. Typically, an abrupt
decrease in ROP is experienced in combination with downhole torque
and downhole WOB increases. Further, the bit and the steering unit
may begin to slip along the stringer, such that no penetration into
or through the stringer is achieved. That is, the bit may "bounce"
or "skip" along the surface of the stringer as the drilling
operation is not optimized to drill into the harder material of the
stringer. The slipping may create well rugosity, tortuosity, and/or
high local doglegs of the well trajectory proximate the stringer.
Such impacts on the well can have negative impact on the
continuation of drilling operations (e.g., high bending moments
wear on the BHA components, higher vibrations, etc.) and also on
the completion of the borehole after drilling operation is
completed. The slipping can be mitigated or even avoided if the bit
and steering units are oriented in a preferred attack angle
relative to the orientation of the stringer.
[0033] In accordance with embodiments of the present disclosure,
the orientation of a formation change (e.g., a stringer) relative
to the well trajectory can be determined from an image of the
borehole wall or a dipmeter. Images of the borehole wall can be
used to identify formation or bed boundaries as the formation
sensors pass these boundaries. A variety of formation sensors may
be used to acquire images of the formation wall, including, but not
limited to, acoustic/ultrasonic sensors, resistivity sensors, gamma
sensors, density or radiation sensors, etc. These sensors are
typically positioned within the BHA behind at least the bit and the
steering unit (i.e., remote or a distance from the bit and thus the
bottom of the drilled borehole).
[0034] Turning to FIG. 2 an illustrative formation 200 having a
plurality of formation layers 202 including a formation change 204
(e.g., a stringer) is shown. A borehole 206 is drilled within the
formation 200 using a drilling system 208 having a drill string 210
and a bottomhole assembly (BHA) 212. The BHA 212 includes a
disintegrating device 214, a steering unit 216, a
measurement-while-drilling unit 218, and an imaging unit 220. The
top image of FIG. 2 represents a schematic illustration of the
formation 200 and the drilling system 208 disposed therein. The
lower image of FIG. 2 represents a density image of a borehole
track, which has been created by acquiring density properties of
the formation azimuthally using the imaging unit 220. The upper
image of FIG. 2 represents a structural Earth model around the well
trajectory as obtained from the density image of the borehole
track.
[0035] In logging-while-drilling acquisitions, e.g., using
measurement-while-drilling unit 218, the BHA 212 is rotating, so
that the data acquisition is continuously conducted while drilling.
The collected data, e.g., images, is used to detect and mark
formation or bed boundaries 222 shown in the image illustration on
the bottom of FIG. 2. The boundaries 222 show up as sinusoidal
shapes at density contrasts. The marked formation boundaries 222
may then be used to create the structural Earth model around the
well trajectory (upper image in FIG. 2). The Earth model may be
color-coded (or otherwise coded) by the average density acquired
along the well trajectory. Because stringers and other formation
changes typically have a higher density than the surrounding rock,
the formation change 204 may be identified through the density
imaging.
[0036] The continuous acquisition of an image of the borehole wall
along the well trajectory can be used to monitor the orientation or
change in orientation of formation bed boundaries relative to the
drilled well trajectory.
[0037] For example, turning to FIGS. 3A-3E, five consecutive images
are illustratively shown to illustrate a scenario of consecutive
measured depths as an image sensor passes along a well trajectory.
The images of FIGS. 3A-3E are representative of images captured
from the imaging unit 220 as the borehole 206 is formed. The plots
of FIGS. 3A-3E provide a cross-sectional view of the Earth model
(e.g., the Earth model shown in the top plot of FIG. 2)
perpendicular to the well trajectory. The plots are disc plots that
illustrate how formation bed boundaries are represented by the
Earth model as the image sensor detects the boundaries of various
formation layers. Formation layer orientations 300 are
illustratively shown in FIGS. 3A-3E.
[0038] With the assumption that at least some consecutive formation
boundaries are parallel to each other, the orientation of a
formation change (e.g., stringer) relative to the well trajectory
may be extrapolated to the bit depth, which provides the expected
orientation of a formation boundary at the bit. For example, as
shown in FIGS. 3A-3E, the illustrative orientation 300 of the
various formation layer boundaries are all substantially similar.
As such, due to the extrapolation, even though an orientation of
the formation change (at the bit) is not visible to the imaging
unit which is remote from the bit, the orientation of the formation
change can be extrapolated from the imaged formation boundaries
orientations 300 (e.g., previously drilled formations).
[0039] Embodiments of the present disclosure are directed to
systems and methods for extrapolating the orientation of a
formation change and adjusting a drilling operation (e.g.,
trajectory, angle of attack, etc.) with respect to the formation
change. The formation changes may be identified during a drilling
operation, and as the formation change is identified, the
extrapolated orientation process may be performed and an updated or
adjusted drilling trajectory may be implemented based on the
extrapolation. In some embodiments, the entire process may be
automated such that monitored drilling characteristics can be used
to determine contact with a formation change (e.g., downhole
monitoring tools) and upon detection of such criteria, a correction
process can be performed to optimize the drilling operation
relative to the formation change. For example, a drilling direction
can be adjusted such that the bit or other disintegrating device
will attack or contact that formation change at an optimized angle
to efficiently drill or cut through the formation change.
[0040] Different approaches may be applied for the extrapolation of
the orientation of formation bed boundaries to estimate the
orientation of a formation change. In one embodiment, the
orientation of a number of drilled boundaries may be assumed
parallel, so that an average orientation may be calculated in case
a number of boundaries are not parallel. In another embodiment, a
rotation or trend in the orientation of formation boundaries may be
encountered for consecutive boundaries, and the trend may be
extrapolated to the drill bit depth to predict the orientation of a
formation change relative to the well trajectory. In another
embodiment, the orientation of the formation boundaries which has
been drilled latest (i.e., most recent imaging capture) may be
extrapolated to the bit depth and used to predict a formation
change orientation.
[0041] An illustrative embodiment of the present disclosure is
shown in FIG. 4. In FIG. 4, a BHA 400 is disposed within a
formation 402, the BHA 400 including an imaging unit 404, a
steering unit 406, and a disintegrating device 408. The
disintegrating device 408 is operated to drilling a borehole
through the formation 402, with the steering unit 406 operated to
control a drilling direction of the disintegrating device 408. As
shown, a drilling trajectory 410 may be representative of a planned
drilling operation to form the borehole within the formation 402.
The formation 402 illustratively shown in FIG. 4 may be an Earth
formation model obtained from a plurality of measurements and/or
images, as described above.
[0042] As shown, a disc plot 412 is shown which may be captured or
obtained by the imaging unit 404. A series of disc plots may be
used to generate the Earth formation model. The disc plot 412
illustrates an orientation 414 of a boundary 416. The orientation
414 may be used to determine the application of a steering force,
using the steering unit 406, to the BHA 400 in a way that the
maximum bit force is oriented perpendicular to the orientation of a
formation change, with the formation change orientation being
extrapolated from formation bed boundary orientations detected
behind the bit using imaging technologies, from offset well
measurements, and/or historical data. That is, as described above,
the orientation of a formation change may be extrapolated from
formation layer boundary orientations that are remote from the
drill bit (but previously drilled through) and/or from prior
identification of formation changes in a region (e.g., offset well
data and/or historical data). Using an offset well and/or
historical data can enable the adjustment of the drilling
trajectory based on a drilled depth and anticipation of a formation
change at such depth.
[0043] As will be appreciated by those of skill in the art, a
steering force is defined as a vector, and thus setting the
steering force includes setting a steering direction. That is, an
angle of approach or attack of the disintegrating device toward a
formation change (e.g., a stringer) may be set or generated by
setting a steering force that is perpendicular to the formation
change.
[0044] Turning now to FIG. 5, a flow process 500 for adjusting a
drilling operation based on a formation change (e.g., stringer) in
accordance with an embodiment of the present disclosure is shown.
The flow process 500, and associated commands, may be applied or
executed by a directional driller (e.g., steering unit) of a BHA.
The flow process 500 may be performed entirely as an automated
process that occurs downhole using downhole electronics, processing
equipment, sensors, etc., as will be appreciated by those of skill
in the art.
[0045] At block 502, a drilling operation is performed wherein a
portion of a borehole is drilled using a drill bit or other
disintegrating device.
[0046] At block 504, during the drilling operation of block 502, an
imaging unit of the BHA may be employed to monitor formation layer
orientations (e.g., bed orientation). The monitoring process of
block 504 may be performed continuously during a drilling
operation, with bed formation orientation information stored within
a memory of the BHA. The information collected at block 504 may be
obtained at a position that is separated from/a distance from the
bit or disintegrating device. Thus, the information of block 504 is
reflective of formation layers that have already been drilled
through by the drill bit or other disintegrating device (at block
502). Various types of monitoring may include, but is not limited
to, density measurements, gamma ray interrogation, resistivity
measurements, dipmeter, deep shear imaging (e.g., acoustic
interrogation), etc.
[0047] At block 506, a drilling operational performance may be
monitored. To monitor drilling operational performance, one or more
drilling characteristics and/or properties may be monitored. For
example, in some embodiments, weight-on-bit (WOB), torque, rate of
penetration (ROP), and bending moment may be monitored using
sensors as known in the art. The drilling properties may be
monitored for variations or deviations from an expected value
and/or may be monitored to determine if one or more thresholds are
passed (i.e., either greater than or less than a set threshold or
criteria, depending on specific drilling property being
monitored).
[0048] At block 508, a decrease in drilling operational performance
may be detected. The decrease in performance may be detected
through the monitoring performed at block 506. That is, when a
specific threshold or criteria is passed (greater than or less than
a predetermined value), such crossing of the threshold may be
indicative of a decrease in drilling operational performance. For
example, a reduced rate of penetration may indicate a reduction in
drilling operational performance. However, in some instances an
increased rate of penetration may be indicative of a decrease in
drilling operational performance. Thus, in some embodiments, a
plurality of different drilling properties or characteristics may
be monitored to enable a more accurate determination of a reduction
in drilling operational performance. Reduce drilling operational
performance may be the result of interaction with a formation
change (e.g., stringer or other hard material/formation).
Alternative, the reduction in drilling operational performance may
be the results in rapid or repeated changes in formation layer
hardness (e.g., hard layer, soft layer, hard layer, etc., in
series).
[0049] At block 510, when the drilling operational performance is
determined to have decreased, an extrapolation of formation layer
orientations may be performed, with an extrapolated formation
change orientation being determined. The extrapolation may be based
on the information obtained at block 504. The extrapolation may be
based on an assumption that all formation layers are parallel, thus
extrapolating that the formation change is oriented at the same
angle as all other layers that have preceded the formation change
during the drilling process. However, in some embodiments, the
angle or orientation of a series of formation layers may be
different as depth increases. For example, in some situations, a
formation may have increasing angle of orientation layers. The
progressive change in orientation may be extrapolated from the
information obtained at block 504.
[0050] The extrapolation performed at block 510 is made with
respect to the currently drilled well trajectory. That is the
orientation of the formation change is extrapolated with respect to
the borehole trajectory. Accordingly, at block 510, an orientation
or angle of a formation change relative to the current drilling
trajectory may be estimated.
[0051] At block 512, based on the extrapolated formation change
orientation from block 510, a steering command may be set, or other
adjustment to a drilling trajectory or operation may be performed.
Because formation changes (e.g., stringers) are typically a hard
material, the most efficient drilling direction is one that is
perpendicular to the formation change orientation. That is, an
attack angle of 90.degree. is preferred for an efficient drilling
through the formation change. However, a perpendicular attack angle
may not always be possible, and thus the adjustment to the drilling
trajectory may be to achieve the greatest possible angle in the
most efficient manner. The adjustment at block 512 may require the
BHA to be moved upward or backward along the borehole such that the
angle of attack relative to a formation change may be adjusted.
[0052] After adjustment, the drilling process may be continued at
the new drilling trajectory to drill through the formation change.
After completion of drilling through the formation change, the
drilling trajectory may be reset back to the original trajectory to
adhere to a pre-set drilling plan. The flow process 500 is
continuously performed such that any formation change may be
accounted for and efficient drilling operations may be
achieved.
[0053] Turning now to FIG. 6, a schematic illustration of a
drilling operation employing an embodiment of the present
disclosure is shown. As shown, a formation 600 includes a formation
change 602 (e.g., a stringer) as a formation layer therein. A
planned drilling trajectory 604 is shown as a substantially
straight path through the formation 600. However, when the flow
process described above is performed, and it is determined that the
formation change 602 is being approached (or attempted to be
drilled into), an adjusted drilling trajectory 606 may be set to
enable an optimized or improved angle of attack relative to the
formation change 602.
[0054] Although described above as a specific imaging or monitoring
of formation layer orientations, various mechanisms for monitoring
formation orientation may be employed without departing from the
scope of the present disclosure. For example, in some embodiments,
rather than imaging the Earth formation itself, a monitoring device
may image the borehole wall. Data collected with the borehole wall
may be interpreted automatically in order to detect formation bed
boundaries. The automatic interpretation may provide the existence
and orientation of the boundaries, so that the steering command can
be immediately applied as soon as a formation change is detected by
measurements-while-drilling sensors.
[0055] In one embodiment, the steering command or adjustment to the
drilling trajectory may be transmitted via a downlink to the BHA
from the surface. The command can ensure that the steering unit
steers in an optimum angle against the formation change. Further,
as noted above, the flow process of FIG. 5 may be implemented in
the technologies of the BHA, so that the detection of formation
changes, monitoring of formation bed boundary orientation, and
setting of steering commands can be conducted automatically as a
downhole process with no interaction or delay associated with
communication with the surface.
[0056] In another embodiment, the existence and orientation of
formation changes for a planned well trajectory may be correlated
from nearby offset wells where formation changes were already
detected and drilled. The expected formation change location and
orientation from offset wells may be used either for updating the
well plan in order to anticipate the formation change and plan for
an optimal attack angle or for the steering command as soon as a
formation change is hit while drilling the planned well trajectory
or while geosteering. In some embodiments, the expected formation
change location and orientation may be updated using imaging
sensors within the BHA. An update of the location and orientation
of formation changes may then be used as the basis for steering
commands and/or adjustment to the drilling trajectory.
[0057] As described herein, embodiments of the present disclosure
are directed to optimizing a drilling trajectory relative to a
"hard" formation (e.g., a stringer) which may require a more direct
contact with a drilling bit, as compared to "soft" formations that
are not as difficult to drill through. As discussed above, "hard"
formations can be either thick layers or beds of hard material or
composition or thin intercalations within a soft formation, and as
used herein have been referred to generically as a "stringer." To
optimize drilling operations, particularly with respect to
formation changes (e.g., stringers), imaging of formation layers
are taken (using one or more techniques for monitoring layer
orientation), and the measured orientations are extrapolated to
estimate the orientation of a formation change.
[0058] The drilling trajectory can be adjusted to have the drill
string and drill bit approach/contact the formation change at about
a 90.degree. angle (or at relatively steep angle of approach, e.g.,
greater than 50.degree.), thus maximizing drilling ROP and drilling
efficiency through the formation change. In operation, formation
layer orientation data is collected (e.g., imaged) and from such
data, the formation orientation can be understood. From the
formation orientation, the orientation of the formation change can
be extrapolated or predicted. Based on the predicted formation
change orientation, the drilling trajectory is adjusted to optimize
drilling efficiency.
[0059] As discussed herein, in some embodiments, the entire process
may be performed downhole, in real-time, and automatically. In some
embodiments, based on prior-knowledge from companion/offset wells,
and imaging in real-time, detection of orientations and adjusting
of the drilling trajectory may be achieved. In embodiments having a
single well, if a formation change is detected by monitoring
drilling parameters, the drill string can be pulled back (e.g.,
away from the formation change) and the drilling trajectory may be
adjusted based on the imaging and extrapolation of the orientation
of the formation change.
[0060] Advantageously, some embodiments provided are directed to
automation of drilling trajectory based on determination of an
orientation of a formation change (e.g., stringer). The formation
change orientation may be obtained from extrapolation of formation
orientations that are remote from the bit. Further, the systems may
automatically adjust a drilling trajectory and/or steering
parameters (e.g. steering direction and steering force) based on
the determined or extrapolated orientation of the formation
change.
[0061] While embodiments described herein have been described with
reference to specific figures, it will be understood that various
changes may be made and equivalents may be substituted for elements
thereof without departing from the scope of the present disclosure.
In addition, many modifications will be appreciated to adapt a
particular instrument, situation, or material to the teachings of
the present disclosure without departing from the scope thereof.
Therefore, it is intended that the disclosure not be limited to the
particular embodiments disclosed, but that the present disclosure
will include all embodiments falling within the scope of the
appended claims or the following description of possible
embodiments.
Embodiment 1
[0062] A method for controlling a drilling operation comprising:
performing a drilling operation using a bottomhole assembly having
a disintegrating device located at an end of a drill string;
detecting and monitoring formation layer orientations with one or
more sensors to obtain formation layer orientation information
indicative of a formation layer orientation; monitoring a drilling
operational performance of at least one of the disintegrating
device and the bottomhole assembly; detecting a change in the
drilling operational performance; and adjusting a steering command
to set an angle of attack by the disintegrating device to the
formation layer orientation based on the formation layer
orientation information.
Embodiment 2
[0063] The method of any prior embodiment, wherein the drilling
operational performance comprises at least one of rate of
penetration, revolutions per minute, downhole pressure, drilling
vibration, torque, weight-on-bit, and bending moment.
Embodiment 3
[0064] The method of any prior embodiment, wherein the one or more
sensors for detecting formation layer orientations comprise one or
more of acoustic sensors, ultrasonic sensors, resistivity sensors,
gamma ray sensors, density sensors, radiation sensors, or
dipmeters.
Embodiment 4
[0065] The method of any prior embodiment, wherein the steering
command is adjusted to have an angle of attack of the
disintegrating device relative to the formation layer orientation
to be 50.degree. or greater.
Embodiment 5
[0066] The method of any prior embodiment, wherein the change in
drilling operational performance is indicative of a change in the
formation layer orientation.
Embodiment 6
[0067] The method of any prior embodiment, wherein at least one
sensor of the one or more sensors is located within the bottomhole
assembly.
Embodiment 7
[0068] The method of any prior embodiment, further comprising at
least one of transmitting the formation layer information to a
surface control unit for processing and transmitting an adjusted
steering command from the surface control unit the bottomhole
assembly.
Embodiment 8
[0069] The method of any prior embodiment, further comprising
automatically performing the monitoring, detecting, and adjusting
with a downhole controller of the bottomhole assembly.
Embodiment 9
[0070] The method of any prior embodiment, further comprising
moving the drill string away from bottomhole prior to adjusting the
steering command.
Embodiment 10
[0071] The method of any prior embodiment, wherein the angle of
attack is generated by setting a steering force perpendicular to
the formation layer orientation.
Embodiment 11
[0072] The method of any prior embodiment, further comprising
estimating a formation layer orientation based on at least one of
the formation layer orientation information, offset well data, and
historical data.
Embodiment 12
[0073] A system for controlling a drilling operation comprising: a
drill string; a bottomhole assembly having a disintegrating device
disposed at an end of the drill string, wherein the disintegrating
device is used to perform a drilling operation and wherein the
bottomhole assembly is configured to drill into a formation based
on a steering command; and one or more sensors configured to detect
and monitor formation layer orientations and obtain formation layer
orientation information indicative of a formation layer
orientation; wherein a drilling operational performance of at least
one of the disintegrating device and the bottomhole assembly is
monitored by one or more associated sensors to detect a change in
the drilling operational performance, and wherein a steering
command is adjusted to set an angle of attack of the disintegrating
device relative to the detected formation layer orientation when a
change in the drilling operational performance is detected.
Embodiment 13
[0074] The system of any prior embodiment, wherein the drilling
operational performance comprises at least one of rate of
penetration, revolutions per minute, downhole pressure, drilling
vibration, torque, weight-on-bit, and bending moment.
Embodiment 14
[0075] The system of any prior embodiment, wherein the one or more
sensors for monitoring formation layer orientations comprise one or
more of acoustic sensors, ultrasonic sensors, resistivity sensors,
gamma ray sensors, density sensors, radiation sensors, or
dipmeters.
Embodiment 15
[0076] The system of any prior embodiment, wherein the steering
command is adjusted to have an angle of attack of the
disintegrating device to the formation change to be 50.degree. or
greater.
Embodiment 16
[0077] The system of any prior embodiment, wherein the angle of
attack is generated by setting a steering force perpendicular to
the formation layer orientation.
Embodiment 17
[0078] The system of any prior embodiment, wherein at least one
sensor of the one or more sensors for monitoring formation layer
orientations is located within the bottomhole assembly.
Embodiment 18
[0079] The system of any prior embodiment, wherein the bottomhole
assembly further comprises at least one of a transmitter to
transmit the formation layer information to a surface control unit
for processing and a receiver for receiving an adjusted steering
command from the surface control unit.
Embodiment 19
[0080] The system of any prior embodiment, wherein the bottomhole
assembly is configured to perform the monitoring, detecting, and
adjusting automatically.
Embodiment 20
[0081] The system of any prior embodiment, wherein the bottomhole
assembly comprises an imaging unit, a measurement-while-drilling
unit, and a steering unit.
[0082] In support of the teachings herein, various analysis
components may be used including a digital and/or an analog system.
For example, controllers, computer processing systems, and/or
geo-steering systems as provided herein and/or used with
embodiments described herein may include digital and/or analog
systems. The systems may have components such as processors,
storage media, memory, inputs, outputs, communications links (e.g.,
wired, wireless, optical, or other), user interfaces, software
programs, signal processors (e.g., digital or analog) and other
such components (e.g., such as resistors, capacitors, inductors,
and others) to provide for operation and analyses of the apparatus
and methods disclosed herein in any of several manners
well-appreciated in the art. It is considered that these teachings
may be, but need not be, implemented in conjunction with a set of
computer executable instructions stored on a non-transitory
computer readable medium, including memory (e.g., ROMs, RAMs),
optical (e.g., CD-ROMs), or magnetic (e.g., disks, hard drives), or
any other type that when executed causes a computer to implement
the methods and/or processes described herein. These instructions
may provide for equipment operation, control, data collection,
analysis and other functions deemed relevant by a system designer,
owner, user, or other such personnel, in addition to the functions
described in this disclosure. Processed data, such as a result of
an implemented method, may be transmitted as a signal via a
processor output interface to a signal receiving device. The signal
receiving device may be a display monitor or printer for presenting
the result to a user. Alternatively or in addition, the signal
receiving device may be memory or a storage medium. It will be
appreciated that storing the result in memory or the storage medium
may transform the memory or storage medium into a new state (i.e.,
containing the result) from a prior state (i.e., not containing the
result). Further, in some embodiments, an alert signal may be
transmitted from the processor to a user interface if the result
exceeds a threshold value.
[0083] Furthermore, various other components may be included and
called upon for providing for aspects of the teachings herein. For
example, a sensor, transmitter, receiver, transceiver, antenna,
controller, optical unit, electrical unit, and/or electromechanical
unit may be included in support of the various aspects discussed
herein or in support of other functions beyond this disclosure.
[0084] The use of the terms "a" and "an" and "the" and similar
referents in the context of describing the invention (especially in
the context of the following claims) are to be construed to cover
both the singular and the plural, unless otherwise indicated herein
or clearly contradicted by context. Further, it should further be
noted that the terms "first," "second," and the like herein do not
denote any order, quantity, or importance, but rather are used to
distinguish one element from another. The modifier "about" or
"substantially" used in connection with a quantity is inclusive of
the stated value and has the meaning dictated by the context (e.g.,
it includes the degree of error associated with measurement of the
particular quantity). For example, the phrase "substantially
constant" is inclusive of minor deviations with respect to a fixed
value or direction, as will be readily appreciated by those of
skill in the art.
[0085] The flow diagram(s) depicted herein is just an example.
There may be many variations to this diagram or the steps (or
operations) described therein without departing from the scope of
the present disclosure. For instance, the steps may be performed in
a differing order, or steps may be added, deleted or modified. All
of these variations are considered a part of the present
disclosure.
[0086] It will be recognized that the various components or
technologies may provide certain necessary or beneficial
functionality or features. Accordingly, these functions and
features as may be needed in support of the appended claims and
variations thereof, are recognized as being inherently included as
a part of the teachings herein and a part of the present
disclosure.
[0087] The teachings of the present disclosure may be used in a
variety of well operations. These operations may involve using one
or more treatment agents to treat a formation, the fluids resident
in a formation, a borehole, and/or equipment in the borehole, such
as production tubing. The treatment agents may be in the form of
liquids, gases, solids, semi-solids, and mixtures thereof.
Illustrative treatment agents include, but are not limited to,
fracturing fluids, acids, steam, water, brine, anti-corrosion
agents, cement, permeability modifiers, drilling muds, emulsifiers,
demulsifiers, tracers, flow improvers etc. Illustrative well
operations include, but are not limited to, hydraulic fracturing,
stimulation, tracer injection, cleaning, acidizing, steam
injection, water flooding, cementing, etc.
[0088] While embodiments described herein have been described with
reference to various embodiments, it will be understood that
various changes may be made and equivalents may be substituted for
elements thereof without departing from the scope of the present
disclosure. In addition, many modifications will be appreciated to
adapt a particular instrument, situation, or material to the
teachings of the present disclosure without departing from the
scope thereof. Therefore, it is intended that the disclosure not be
limited to the particular embodiments disclosed as the best mode
contemplated for carrying the described features, but that the
present disclosure will include all embodiments falling within the
scope of the appended claims.
[0089] Accordingly, embodiments of the present disclosure are not
to be seen as limited by the foregoing description, but are only
limited by the scope of the appended claims.
* * * * *