U.S. patent application number 16/760553 was filed with the patent office on 2021-12-30 for drilling system.
This patent application is currently assigned to HALLIBURTON ENERGY SERVICES, INC.. The applicant listed for this patent is HALLIBURTON ENERGY SERVICES, INC.. Invention is credited to Eric BIVENS, Philippe QUERO.
Application Number | 20210404312 16/760553 |
Document ID | / |
Family ID | 1000005884813 |
Filed Date | 2021-12-30 |
United States Patent
Application |
20210404312 |
Kind Code |
A1 |
QUERO; Philippe ; et
al. |
December 30, 2021 |
DRILLING SYSTEM
Abstract
A system is provided which includes a bottomhole assembly, a
cable assembly, and a controller. The bottomhole assembly is
disposed in a wellbore traversing a subterranean formation from a
surface of the earth, and includes a drill tool. The cable assembly
includes a fiber optic line coupled with the bottomhole assembly.
The fiber optic line has a length that traverses a length of the
wellbore from the bottomhole assembly to the surface. The fiber
optic line is a distributed sensor and measures one or more
downhole parameters along the length of the fiber optic line during
the drilling of the wellbore. The controller is coupled with the
cable assembly, and receives data from the fiber optic line during
the drilling of the wellbore by the drill tool.
Inventors: |
QUERO; Philippe; (Houston,
TX) ; BIVENS; Eric; (Littleton, CO) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
HALLIBURTON ENERGY SERVICES, INC. |
Houston |
TX |
US |
|
|
Assignee: |
HALLIBURTON ENERGY SERVICES,
INC.
Houston
TX
|
Family ID: |
1000005884813 |
Appl. No.: |
16/760553 |
Filed: |
June 19, 2019 |
PCT Filed: |
June 19, 2019 |
PCT NO: |
PCT/US2019/037976 |
371 Date: |
April 30, 2020 |
Current U.S.
Class: |
1/1 |
Current CPC
Class: |
E21B 47/07 20200501;
E21B 44/00 20130101; E21B 47/107 20200501; E21B 47/135
20200501 |
International
Class: |
E21B 44/00 20060101
E21B044/00; E21B 47/07 20060101 E21B047/07; E21B 47/107 20060101
E21B047/107; E21B 47/135 20060101 E21B047/135 |
Claims
1. A system comprising: a bottomhole assembly disposed in a
wellbore traversing a subterranean formation from a surface of the
earth, the bottomhole assembly having a drill tool; a cable
assembly including a fiber optic line coupled with the bottomhole
assembly, the fiber optic line having a length that traverses a
length of the wellbore from the bottomhole assembly to the surface,
the fiber optic line being a distributed sensor and measuring one
or more downhole parameters along the length of the fiber optic
line during the drilling of the wellbore; and a controller coupled
with the cable assembly, the controller receiving data from the
fiber optic line during the drilling of the wellbore by the drill
tool.
2. The system of claim 1, wherein the cable assembly includes a
conductor line transmitting power to the bottomhole assembly.
3. The system of claim 1, wherein the bottomhole assembly includes
a battery providing power to the bottomhole assembly.
4. The system of claim 1, further comprising a conduit coupled with
the bottomhole assembly.
5. The system of claim 4, wherein the cable assembly is disposed
within an annulus of the conduit.
6. The system of claim 4, wherein the cable assembly is coupled
with the conduit.
7. The system of claim 4, wherein the cable assembly is external to
the conduit.
8. The system of claim 1, wherein the fiber optic line is one or
more of the following: a distributed temperature sensor, a
distributed acoustic sensor, and a distributed pressure sensor; and
wherein the one or more downhole parameters includes temperature,
acoustic signals, and/or pressure.
9. The system of claim 1, wherein the controller receives the data
from the fiber optic line and adjusts the drilling of the wellbore
based on the data.
10. The system of claim 1, wherein the bottomhole assembly includes
one or more sensors, and the data includes measurements from the
one or more sensors.
11. A drilling device comprising: a bottomhole assembly having a
drill tool operable to drill a wellbore; a cable assembly including
a fiber optic line coupled with the bottomhole assembly, the fiber
optic line having a length and being a distributed sensor and
operable to measure one or more downhole parameters along the
length of the fiber optic line during drilling of the wellbore; and
a controller coupled with the cable assembly, the controller
operable to receive data from the fiber optic line during the
drilling of the wellbore.
12. The drilling device of claim 11, wherein the cable assembly
includes a conductor line operable to transmit power to the
bottomhole assembly.
13. The drilling device of claim 11, wherein the bottomhole
assembly includes a battery operable to provide power to the
bottomhole assembly.
14. The drilling device of claim 11, wherein the fiber optic line
is one or more of the following: a distributed temperature sensor,
a distributed acoustic sensor, and a distributed pressure sensor;
and wherein the one or more downhole parameters includes
temperature, acoustic signals, and/or pressure.
15. The drilling device of claim 11, wherein the controller
receives the data from the fiber optic line and is operable to
adjust the drilling of the wellbore based on the data.
16. The drilling device of claim 11, wherein the bottomhole
assembly includes one or more sensors, and the data includes
measurements from the one or more sensors.
17. A method comprising: drilling, by a bottomhole assembly having
a drill tool, a wellbore in a formation; measuring, by a fiber
optic line having a length and coupled with the bottomhole assembly
during the drilling, one or more downhole parameters along the
length of the fiber optic line; and transmitting, to a controller
during the drilling, data from the fiber optic line, wherein the
fiber optic line is a distributed sensor and the length of the
fiber optic line traverses the length of the wellbore from the
bottomhole assembly to the surface.
18. The method of claim 17, further comprising: adjusting, by the
controller, the drilling of the wellbore based on the data from the
fiber optic line.
19. The method of claim 17, wherein the fiber optic line is one or
more of the following: a distributed temperature sensor, a
distributed acoustic sensor, and a distributed pressure sensor; and
wherein the one or more downhole parameters includes temperature,
acoustic signals, and/or pressure.
20. The method of claim 17, wherein the bottomhole assembly
includes one or more sensors, and the data includes measurements
from the one or more sensors.
Description
FIELD
[0001] The present disclosure relates generally to drilling
systems. In at least one example, the present disclosure relates to
drilling systems including a cable assembly to measure drilling
parameters during drilling.
BACKGROUND
[0002] Wellbores are drilled into the earth for a variety of
purposes including accessing hydrocarbon bearing formations. A
variety of bottomhole assemblies may be used within a wellbore in
connection with accessing and extracting such hydrocarbons. To
access the hydrocarbon bearing formations, the wellbore is drilled
to a desired depth and location.
BRIEF DESCRIPTION OF THE DRAWINGS
[0003] Implementations of the present technology will now be
described, by way of example only, with reference to the attached
figures, wherein:
[0004] FIG. 1 is a diagram illustrating an exemplary environment
for a drilling system according to the present disclosure;
[0005] FIG. 2 is a diagram of a processing system which may be
employed as shown in FIG. 1;
[0006] FIG. 3A is a diagram illustrating a cross-sectional view of
an exemplary cable;
[0007] FIG. 3B is a diagram illustrating a cross-sectional view of
another exemplary cable;
[0008] FIG. 3C is a diagram illustrating a cross-sectional view of
another exemplary cable;
[0009] FIG. 4 is a diagram illustrating an exemplary drilling
operation;
[0010] FIG. 5 is a diagram illustrating an exemplary drilling
operation;
[0011] FIG. 6 is a diagram illustrating an exemplary drilling
operation;
[0012] FIG. 7 is a diagram illustrating an exemplary drilling
operation; and
[0013] FIG. 8 is a flow chart of a method for utilizing an acoustic
telemetry system.
DETAILED DESCRIPTION
[0014] It will be appreciated that for simplicity and clarity of
illustration, where appropriate, reference numerals have been
repeated among the different figures to indicate corresponding or
analogous elements. In addition, numerous specific details are set
forth in order to provide a thorough understanding of the
embodiments described herein. However, it will be understood by
those of ordinary skill in the art that the embodiments described
herein can be practiced without these specific details. In other
instances, methods, procedures and components have not been
described in detail so as not to obscure the related relevant
feature being described. Also, the description is not to be
considered as limiting the scope of the embodiments described
herein. The drawings are not necessarily to scale and the
proportions of certain parts may be exaggerated to better
illustrate details and features of the present disclosure.
[0015] Disclosed herein is a system to measure downhole parameters
along a length of the wellbore during drilling of the wellbore. The
system includes a bottomhole assembly which drills a wellbore in a
formation. A cable assembly is coupled with the bottomhole assembly
and includes a fiber optic line. The fiber optic line traverses a
length of the wellbore from the bottomhole assembly to the surface.
As the fiber optic line is a distributed sensor, the fiber optic
line can measure downhole parameters along the length of the
wellbore during drilling of the wellbore by the bottomhole
assembly. A controller is coupled with the cable assembly 100 and
receives data from the fiber optic line during the drilling of the
wellbore.
[0016] Conventionally, to make measurements of downhole parameters
during the process of drilling a wellbore, drilling is stopped and
the drill string is removed from the wellbore. Then, a logging
string is inserted into the wellbore, measurements are taken, and
after removal, the drill string is re-inserted into the wellbore
again to continue drilling. As a result, there is no true
understanding of whether there is a problematic issue present, what
the issue may be, and where the issue is located. The process is
very time consuming, and if occurring too late in the process,
excessive resources may be wasted. However, with the fiber optic
line measuring downhole parameters during drilling, a determination
may be made whether there are any issues during drilling and make
corresponding adjustments as needed without removing the drill
string, thereby avoiding substantial delay or further drilling. For
example, if fluid is being lost into the formation, the data from
the fiber optic line can inform that the issue is present as well
as inform of the location and depth of the issue. Accordingly, the
drilling can be paused or adjusted, without removal of the drill
string, to correct the issue such that the damage is mitigated.
Additionally, in some examples, the data from the fiber optic line
can inform of the type of issue that is present.
[0017] The system can be employed in an exemplary wellbore system
10 shown, for example, in FIG. 1. The wellbore system 10 can
include a wellhead 30 extending over and around a wellbore 14. The
wellbore 14 is within an earth formation 22 and, in at least one
example, can have a casing 20 at least partially lining the
wellbore 14. In at least one example, the casing 20 can be held
into place by cement. In at least one example, the casing 20 can be
at least partially made of an electrically conductive material, for
example steel. In another example, the casing 20 can be at least
partially made of a non-electrically conductive material, for
example fiberglass or PEEK, or of a low-conductivity material, for
example carbon composite, or a combination of such materials. A
bottomhole assembly 50 coupled with a conduit 18 can be disposed
within the wellbore 14 and moved down the wellbore 14 via the
conduit 18 to a desired location. As illustrated in FIG. 1, the
conduit 18 is coiled tubing. In other examples, the conduit 18 can
be, for example, tubing-conveyed, wireline, slickline, work string,
joint tubing, jointed pipe, pipeline, and/or any other suitable
means.
[0018] The bottomhole assembly 50 can include, for example,
downhole sensors, chokes, and valves. The chokes and valves may
include actuatable flow regulation devices, such as variable chokes
and valves, and may be used to regulate the flow of the fluids into
and/or out of the conduit 18. The bottomhole assembly 50 also
includes a drill tool 52 to drill the wellbore 14 in the formation
22. For example, the drill tool 52 can include a drill bit, a mill,
and/or an auger. One or more assembly sensors 54 can be disposed in
the bottomhole assembly 50 and provide measurements and data of the
wellbore 14, the formation 22, and/or the bottomhole assembly 50.
For example, the assembly sensors 54 can include a directional
sensor which can determine the direction that the bottomhole
assembly 50 is drilling in the formation 22. In some examples, as
illustrated in FIG. 1, the bottomhole assembly 50 can include a
power source 56. The power source 56 can provide power to the
components of the bottomhole assembly 50, for example the assembly
sensors 54 and/or a motor to actuate the drill tool 52.
[0019] A cable assembly 100 can be coupled with the bottomhole
assembly 50. The cable assembly 100 traverses a length of the
wellbore 14 from the bottomhole assembly 50 to the surface. In at
least one example, the cable assembly 100 can be disposed within an
annulus of the conduit 18. In some examples, the cable assembly 100
can be coupled with the conduit 18, for example by fasteners and/or
adhesives. In some examples, the cable assembly 100 can be external
to the conduit 18 within the wellbore 14. As will be discussed in
further detail in FIGS. 3A-3C, the cable assembly 100 can include a
fiber optic line 310. The fiber optic line 310, along with the
cable assembly 100, can traverse the length of the wellbore 14 from
the bottomhole assembly 50 to the surface. The fiber optic line 310
can be a distributed sensor such that the fiber optic line 310 can
measure one or more downhole parameters along the length of the
fiber optic line 310 traversing the length of the wellbore 14
during drilling of the wellbore 14 by the bottomhole assembly 50.
For example, the fiber optic line 310, as a distributed sensor, can
measure one or more downhole parameters along the entire length of
the fiber optic line 310, such as any distance from an optical
source 19 along the fiber optic line 310. The fiber optic line 310
can be a distributed temperature sensor, a distributed acoustic
sensor, and/or a distributed pressure sensor, and the one or more
downhole parameters can include temperature, acoustic signals,
and/or pressure. Additionally or alternately, the fiber optic line
310 has the ability to transmit large amounts of information
quickly without electric power.
[0020] The wellhead 30 can include a blowout preventer 36, a
stripper 34, and/or an injector 32. The injector 32 can inject the
conduit 18 into the wellbore 14. For example, the conduit 18 can be
stored in a reel 12, and the conduit 18 passes from the reel 12
through the injector 32 into the wellbore 14. In other examples,
the injector 32 can pull the conduit 18 to retrieve the conduit 18
from the wellbore 14. The stripper 34 can provide a pressure seal
around the conduit 18 as the conduit 18 is being run into and/or
pulled out of the wellbore 14. The blowout preventer 36 can seal,
control, and/or monitor the wellbore 14 to prevent blowouts, or
uncontrolled and/or undesired release of fluids from the wellbore
14. In other examples, different systems can be utilized based on
the type of conduit 18 and/or the environment such as subsea or
surface operations.
[0021] An optical source 19 can be optically coupled with the fiber
optic line 310 in the cable assembly 100. In at least one example,
the optical source 19 can be disposed in a surface unit 40 which
can be equipped with data analysis capability and communicatively
coupled with a controller 200. As illustrated in FIG. 1, the
surface unit 40 and the controller 200 are located adjacent to the
wellbore 14. In some examples, the surface unit 40 and/or the
controller 200 can be located at a separate location and the data
can be transferred by either wired or wireless transmission. The
surface unit 40 can include a vehicle 11, as illustrated in FIG. 1.
In some examples, the surface unit 40 can include a derrick, a
building structure, and/or any other suitable structure. The
optical source 19 can emit light signals through the fiber optic
line 310, and the light signals can reflect back to the optical
source 19 and provide data such as the measurements of the one or
more downhole parameters at any and/or all lengths along the fiber
optic line 310. The modulation of the intensity, phase,
polarization, wavelength, and/or transit time of the light signals
in the fiber optic line 310 can communicate the data in the
wellbore 14.
[0022] The optical source 19 can be coupled with the controller 200
which can receive the data from the fiber optic line 310 during the
drilling of the wellbore 14. The controller 200, as discussed in
further detail in FIG. 2, can adjust the drilling of the wellbore
14 based on the data from the fiber optic line 310. For example,
the data can include the measurements of the one or more downhole
parameters. In some examples, the data can also include signals
from the assembly sensors 54 from the bottomhole assembly 50. The
controller 200 can receive the data in substantially real time and
make adjustments automatically and/or indicate the need for
adjustments of the drilling process based on such data without
substantial delay. Accordingly, any issues may be handled without
excessive loss in time and/or resources. As the fiber optic line
310 can indicate the distance of any measurements along the fiber
optic line 310 from the optical source 19, the depth and location
of the issues in the wellbore 14 can also be known. Accordingly,
time and resources can be saved by not needing to search for the
issues in the wellbore 14.
[0023] It should be noted that while FIG. 1 generally depicts a
land-based operation, those skilled in the art would readily
recognize that the principles described herein are equally
applicable to operations that employ floating or sea-based
platforms and rigs, without departing from the scope of the
disclosure. Also, even though FIG. 1 depicts an L-shaped wellbore,
the present disclosure is equally well-suited for use in wellbores
having other orientations, including horizontal wellbores, slanted
wellbores, multilateral wellbores or the like.
[0024] FIG. 2 is a block diagram of an exemplary controller 200.
Controller 200 is configured to perform processing of data and
communicate with the cable assembly 100, for example as illustrated
in FIG. 1. In operation, controller 200 communicates with one or
more of the above-discussed components, and may also be configured
to communication with remote devices/systems.
[0025] As shown, controller 200 includes hardware and software
components such as network interfaces 210, at least one processor
220, sensors 260 and a memory 240 interconnected by a system bus
250. Network interface(s) 210 can include mechanical, electrical,
and signaling circuitry for communicating data over communication
links, which may include wired or wireless communication links.
Network interfaces 210 are configured to transmit and/or receive
data using a variety of different communication protocols, as will
be understood by those skilled in the art.
[0026] Processor 220 represents a digital signal processor (e.g., a
microprocessor, a microcontroller, or a fixed-logic processor,
etc.) configured to execute instructions or logic to perform tasks
in a wellbore environment. Processor 220 may include a general
purpose processor, special-purpose processor (where software
instructions are incorporated into the processor), a state machine,
application specific integrated circuit (ASIC), a programmable gate
array (PGA) including a field PGA, an individual component, a
distributed group of processors, and the like. Processor 220
typically operates in conjunction with shared or dedicated
hardware, including but not limited to, hardware capable of
executing software and hardware. For example, processor 220 may
include elements or logic adapted to execute software programs and
manipulate data structures 245, which may reside in memory 240.
[0027] Sensors 260 typically operate in conjunction with processor
220 to perform measurements, and can include special-purpose
processors, detectors, transmitters, receivers, and the like. In
this fashion, sensors 260 may include hardware/software for
generating, transmitting, receiving, detection, logging, and/or
sampling magnetic fields, seismic activity, and/or acoustic waves,
temperature, pressure, or other parameters. Additionally, sensors
260 may include the fiber optic line 310 and/or the assembly
sensors 54 as disclosed herein.
[0028] Memory 240 comprises a plurality of storage locations that
are addressable by processor 220 for storing software programs and
data structures 245 associated with the embodiments described
herein. An operating system 242, portions of which may be typically
resident in memory 240 and executed by processor 220, functionally
organizes the device by, inter alia, invoking operations in support
of software processes and/or services 244 executing on controller
200. These software processes and/or services 244 may perform
processing of data and communication with controller 200, as
described herein. Note that while process/service 244 is shown in
centralized memory 240, some examples provide for these
processes/services to be operated in a distributed computing
network.
[0029] It will be apparent to those skilled in the art that other
processor and memory types, including various computer-readable
media, may be used to store and execute program instructions
pertaining to the fluidic channel evaluation techniques described
herein. Also, while the description illustrates various processes,
it is expressly contemplated that various processes may be embodied
as modules having portions of the process/service 244 encoded
thereon. In this fashion, the program modules may be encoded in one
or more tangible (non-transitory) computer readable storage media
for execution, such as with fixed logic or programmable logic
(e.g., software/computer instructions executed by a processor, and
any processor may be a programmable processor, programmable digital
logic such as field programmable gate arrays or an ASIC that
comprises fixed digital logic. In general, any process logic may be
embodied in processor 220 or computer readable medium encoded with
instructions for execution by processor 220 that, when executed by
the processor, are operable to cause the processor to perform the
functions described herein. Data may also be transmitted or
streamed for viewing from a remote location via network interfaces
210.
[0030] FIGS. 3A-3C are cross-sectional views of exemplary cables
100 in a plane perpendicular to a central axis. Any of the
components discussed in FIGS. 3A-3C can be interchanged amongst the
exemplary cables 100 without departing from the scope of the
present disclosure.
[0031] FIG. 3A illustrates a cable assembly 100 that may have
separate optical and electrically conductive pathways that are used
for separate optical and electrical signal communication as further
described below. The cable assembly 100, as illustrated in FIG. 3A
can include an outer tube 350 forming an inner core 315 of the
cable assembly 100. At least one fiber optic line 310 and at least
one conductor line 330 are disposed within the inner core 315 of
the cable assembly 100. The conductor line 330 can be operable to
transmit power to the bottomhole assembly 50. The fiber optic line
310 can have a polymer coating such as an acrylate based polymer.
The fiber optic line 310 may be bend insensitive, and may be single
mode or multi-mode. Multi-mode optical fibers permit the optical
fibers to carry out more than one function, such as carrying out
two or more of communication, temperature or pressure sensing
whereas single mode may be limited to one of such functions.
Although FIG. 3A illustrates the cable assembly 100 having a fiber
optic line 310 with a single optical fiber, the cable assembly 100
may alternatively have a plurality of optical fibers, such as two
to ten, or alternatively two to five optical fibers. The use of a
plurality of optical fibers may permit separate control or
redundancy. For instance, some optical fibers may be used for
communicating control to the bottomhole assembly 50 whereas others
are used for communicating or taking measurements of pressure or
temperature. Further, by use a plurality of optical fibers, if one
or more optical fibers become damaged or inoperable, the remaining
optical fibers may still be used.
[0032] FIG. 3B illustrates another exemplary cable assembly 100.
The cable assembly 100 as illustrated in FIG. 3B includes a fiber
optic line 310 disposed within an inner core 315 of the cable
assembly 100. An inner tube 320 can be positioned around the inner
core 315 so as to surround and contain the contents of the inner
core 315. The inner tube 320 may be a metal tube, such as steel, in
which case together with the fiber optic line 310 it may be
referred to in the field as fiber in metal tube (FIMT). The inner
core 315 can be filled with a viscous substance 316 to provide
protection for the fiber optic line 310. The viscous substance 316
can be liquids, gels, foams, or any other material capable of
limiting quick or sudden movement within the tube which may damage
the optical fibers. The fiber optic line 310 provides optical
communication between the bottomhole assembly 50 and surface
equipment, for example the controller 200. For instance, the fiber
optic line 310 can be used to transmit information gathered
downhole to the surface equipment. For example, the fiber optic
line 310 can measure one or more downhole parameters along the
length of the wellbore 14 during drilling of the wellbore 14. In
some examples, the fiber optic line 310 can transmit data from
assembly sensors 54 to the surface equipment. Additionally, the
fiber optic line 310 can be used to transmit commands from surface
equipment to components in the bottomhole assembly 50. A conductor
line 330, as illustrated in FIG. 3B, can be an electrical
conducting material. The conductor line 330 can be positioned
circumferentially around the inner tube 320, such that the entire
external surface of the inner tube 320 is covered and surrounded by
the conductor line 330. The conductor line 330 may be positioned
such that no portion of the conductor line 330 overlaps itself as
it wraps around the inner tube 320. The conductor line 330 can
function as a conductor line and provide a pathway for electrical
communication between the bottomhole assembly 50 and the surface
equipment. The conductor line 330 can be any conductive material
suitable for transferring electrical signals and capable of
withstanding temperatures downhole, including conductive metals
such as copper. The e conductor line 330 may be a thin conductive
layer which may be wrapped about the inner tube 320, and may be a
conductive tape, including copper tape. For example, the copper
tape can provide power from the surface to the bottomhole assembly
50. Accordingly, the conductor line 330 may be provided along the
entire length of the inner tube 220.
[0033] The conductor line 330 can be enclosed by an insulation
material 340. Positioned around the insulation material 340 is an
outer tube 350. The insulation material 340 can be any suitable
temperature resistant material capable of withstanding temperatures
downhole and may be corrosion resistant. In at least one example,
the insulation material 340 can be a polymer such as fluorinated
ethylene propylene (FEP) and formed in the shape of tubing. The
insulation material 340 can provide protection and spacing between
the outer tube 350 and the conductor line 330 to prevent contact
which may cause a short. The outer tube 350 can be any suitable
metal or metal alloy which is capable of grounding electricity and
serves as a protective outer layer for the entire cable assembly
100. A particular metal alloy may include iron or steel, and may be
nickel-iron-chromium alloy such as Alloy 825 (UNS designation
N08825).
[0034] FIG. 3C illustrates an exemplary cable assembly 100 which
does not include a conductor line 330. The cable assembly 100 can
include an outer tube 350 forming an inner core 315 of the cable
assembly 100. The cable assembly 100, as illustrated in FIG. 3C,
includes a fiber optic line 310 disposed within an inner core 315
of the cable assembly 100. In such an example, the power source 56
of the bottomhole assembly 50 may include a battery such that the
bottomhole assembly 50 does not require power to be transmitted
from the surface.
[0035] FIG. 4 illustrates an exemplary drilling operation. As
illustrated in FIG. 4, four formations 400, 402, 404, 406 may be
present. The system 10, similar to the system as illustrated in
FIG. 1, is in operation drilling a wellbore 14. In the exemplary
scenario as illustrated in FIG. 4, the drilling plan is to drill
into formation 404. However, as shown, the bottomhole assembly 50
has drilled the wellbore 14 into formation 406. As the cable
assembly 100 includes the fiber optic line 310, for example as
discussed above, the fiber optic line 310 measures one or more
downhole parameters during drilling. The controller 200 can receive
the data from the fiber optic line 310 and characterize the
formation 406 to help evaluate if the wellbore 14 is drilled on
target. The controller 200 can determine that the bottomhole
assembly 50 has drilled into the wrong formation 406. Then, without
removing the bottomhole assembly 50 and the conduit 18 and
inserting a logging tool, the system 10 can determine that there is
an issue and address that issue by adjusting the drilling, for
example adjusting the direction of the bottomhole assembly 50 to
drill into the desired formation 404. In at least one example, for
example as illustrated in FIG. 7, the assembly sensors 54 can
include a camera 700 such that formation boundaries may be
physically viewed.
[0036] FIG. 5 illustrates another exemplary drilling operation. As
illustrated in FIG. 5, fluid, as denoted by the arrows, is flowing
out of the wellbore 14 into the formation 22. The system 10,
similar to the system as illustrated in FIG. 1, is in operation
drilling a wellbore 14. In the exemplary scenario as illustrated in
FIG. 5, it is intended for the fluid to flow to the surface through
the wellbore 14. However, as shown, losses are experienced as fluid
flows out of the wellbore 14 through one or more loss zones 500. As
the cable assembly 100 includes the fiber optic line 310, for
example as discussed above, the fiber optic line 310 measures one
or more downhole parameters during drilling, and the controller 200
can determine that losses are occurring. For example, the fiber
optic line 310 may measure temperature, pressure, and/or acoustics
(which may be indicative of flow characteristics), and determine
that the temperature becomes warmer due to lack of fluid cooling
the annulus past a certain point and/or the flow parameters change
at a specific location in the wellbore 14. Additionally, sensors in
the bottomhole assembly 50 may detect a drop in pressure at a
specific location if a loss zone is encountered. Accordingly,
without removing the bottomhole assembly 50 and the conduit 18 and
inserting a logging tool, the system 10 can determine that there is
an issue and address that issue by adjusting the drilling, for
example blocking the loss zones 500 such that the fluid loss is
reduced and/or eliminated. In at least one example, for example as
illustrated in FIG. 7, the assembly sensors 54 can include a camera
700 such that the nature of the loss zones 500 can be physically
viewed and the nature of the loss zones 500 can be characterized to
plan an appropriate remediation.
[0037] FIG. 6 illustrates another exemplary drilling operation. As
illustrated in FIG. 6, undesired and/or unplanned fluid, as denoted
by the arrows, is flowing from the formation 22 into the wellbore
14. In some examples, influx solids can be brought into the
wellbore 14. In some examples, influx fluid mixed with influx
solids can be brought into the wellbore 14. The system 10, similar
to the system as illustrated in FIG. 1, is in operation drilling a
wellbore 14. In the exemplary scenario as illustrated in FIG. 6,
fluid should not be flowing into the wellbore 14 at one or more
influx locations 600. As the cable assembly 100 includes the fiber
optic line 310, for example as discussed above, the fiber optic
line 310 measures one or more downhole parameters during drilling,
and the controller 200 can determine that influxes are occurring.
For example, the fiber optic line 310 may measure temperature,
pressure, and/or acoustics, and determine that the temperature
becomes warmer at a specific point from fluid influx, or cooler at
a specific point from gas influx and/or the flow characteristics
change at a specific location in the wellbore 14. Additionally,
sensors in the bottomhole assembly 50 may detect an increase in
pressure at a specific location if an influx zone is encountered.
The exact location of the influx locations 600 can be pinpointed
without wasting resources searching for the influx locations 600.
Accordingly, without removing the bottomhole assembly 50 and the
conduit 18 and inserting a logging tool, the system 10 can
determine that there is an issue and address that issue by
adjusting the drilling, for example blocking the influx locations
600 to reduce and/or eliminate the influx fluid. In at least one
example, for example as illustrated in FIG. 7, the assembly sensors
54 can include a camera 700 such that the nature of the influx
locations 600 can be physically viewed and the nature of the influx
locations 600 can be characterized to plan an appropriate
remediation.
[0038] Referring to FIG. 8, a flowchart is presented in accordance
with an example embodiment. The method 800 is provided by way of
example, as there are a variety of ways to carry out the method.
The method 800 described below can be carried out using the
configurations illustrated in FIGS. 1-7, for example, and various
elements of these figures are referenced in explaining example
method 800. Each block shown in FIG. 8 represents one or more
processes, methods or subroutines, carried out in the example
method 800. Furthermore, the illustrated order of blocks is
illustrative only and the order of the blocks can change according
to the present disclosure. Additional blocks may be added or fewer
blocks may be utilized, without departing from this disclosure. The
example method 800 can begin at block 802.
[0039] At block 802, a wellbore is drilled in a formation by a
bottomhole assembly. The bottomhole assembly can be coupled with a
cable. The cable assembly can include a fiber optic line. The fiber
optic line can be a distributed sensor and traverse the length of
the wellbore from the bottomhole assembly to the surface. For
example, the fiber optic line can be a distributed temperature
sensor, a distributed acoustic sensor, and/or a distributed
pressure sensor, and measure one or more downhole parameters which
can include temperature, acoustic signals, and/or pressure. The
bottomhole assembly can include one or more assembly sensors which
can measure parameters of the wellbore, the formation, and/or the
bottomhole assembly. For example, the assembly sensors can include
a camera which can provide images of the wellbore and/or the
formation. In some examples, the cable assembly can include a
conductor line which can provide electric signals and/or power to
the bottomhole assembly from the surface. In some examples, the
cable assembly may not include a conductor line, and the bottomhole
assembly may include a battery to provide power.
[0040] At block 804, the fiber optic line, during the drilling, can
measure the one or more downhole parameters along a length of the
wellbore. As the fiber optic line can be a distributed sensor, the
fiber optic line can obtain measurements of the one or more
downhole parameters at any location along the length of the
wellbore. Accordingly, any issues can be pinpointed in the wellbore
during drilling.
[0041] At block 806, data from the fiber optic line can be
transmitted to a controller during the drilling. The data can
include the measurements of the one or more downhole parameters by
the fiber optic line. In some examples, the data can include
measurements or data from the bottomhole assembly, for example the
assembly sensors, as the fiber optic line can provide telemetry
between the bottomhole assembly and the surface.
[0042] The controller can adjust the drilling of the wellbore based
on the data from the fiber optic line. For example, the direction
of the drilling may be adjusted. In some examples, the drilling may
be paused to address any influx to the wellbore and/or outflow from
the wellbore of fluid and/or solids. In some examples, the
controller can adjust the drilling of the wellbore automatically,
for example without any human assistance or input.
[0043] Numerous examples are provided herein to enhance
understanding of the present disclosure. A specific set of
statements are provided as follows.
[0044] Statement 1: A system is disclosed comprising: a bottomhole
assembly disposed in a wellbore traversing a subterranean formation
from a surface of the earth, the bottomhole assembly having a drill
tool; a cable assembly including a fiber optic line coupled with
the bottomhole assembly, the fiber optic line having a length that
traverses a length of the wellbore from the bottomhole assembly to
the surface, the fiber optic line being a distributed sensor and
measuring one or more downhole parameters along the length of the
fiber optic line during the drilling of the wellbore; and a
controller coupled with the cable assembly, the controller
receiving data from the fiber optic line during the drilling of the
wellbore by the drill tool.
[0045] Statement 2: A system is disclosed according to Statement 1,
wherein the cable assembly includes a conduct line transmitting
power to the bottomhole assembly.
[0046] Statement 3: A system is disclosed according to Statements 1
or 2, wherein the bottomhole assembly includes a battery providing
power to the bottomhole assembly.
[0047] Statement 4: A system is disclosed according to any of
preceding Statements 1-3, further comprising a conduit coupled with
the bottomhole assembly.
[0048] Statement 5: A system is disclosed according to Statement 4,
wherein the cable assembly is disposed within an annulus of the
conduit.
[0049] Statement 6: A system is disclosed according to Statements 4
or 5, wherein the cable assembly is coupled with the conduit.
[0050] Statement 7: A system is disclosed according to any of
preceding Statements 4-6, wherein the cable assembly is external to
the conduit.
[0051] Statement 8: A system is disclosed according to any of
preceding Statements 1-7, wherein the fiber optic line is one or
more of the following: a distributed temperature sensor, a
distributed acoustic sensor, and a distributed pressure sensor; and
wherein the one or more downhole parameters includes temperature,
acoustic signals, and/or pressure.
[0052] Statement 9: A system is disclosed according to any of
preceding Statements 1-8, wherein the controller receives the data
from the fiber optic line and adjusts the drilling of the wellbore
based on the data.
[0053] Statement 10: A system is disclosed according to any of
preceding Statements 1-9, wherein the bottomhole assembly includes
one or more sensors, and the data includes measurements form the
one or more sensors.
[0054] Statement 11: A drilling device is disclosed comprising: a
bottomhole assembly having a drill tool operable to drill a
wellbore; a cable assembly including a fiber optic line coupled
with the bottomhole assembly, the fiber optic line having a length
and being a distributed sensor and operable to measure one or more
downhole parameters along the length of the fiber optic line during
drilling of the wellbore; and a controller coupled with the cable
assembly, the controller operable to receive data from the fiber
optic line during the drilling of the wellbore.
[0055] Statement 12: A drilling device is disclosed according to
Statement 11, wherein the cable assembly includes a conductor line
operable to transmit power to the bottomhole assembly.
[0056] Statement 13: A drilling device is disclosed according to
Statements 11 or 12, wherein the bottomhole assembly includes a
battery operable to provide power to the bottomhole assembly.
[0057] Statement 14: A drilling device is disclosed according to
any of preceding Statements 11-13, wherein the fiber optic line is
one or more of the following: a distributed temperature sensor, a
distributed acoustic sensor, and a distributed pressure sensor; and
wherein the one or more downhole parameters includes temperature,
acoustic signals, and/or pressure.
[0058] Statement 15: A drilling device is disclosed according to
any of preceding Statements 11-14, wherein the controller receives
the data from the fiber optic line and is operable to adjust the
drilling of the wellbore based on the data.
[0059] Statement 16: A drilling device is disclosed according to
any of preceding Statements 11-15, wherein the bottomhole assembly
includes one or more sensors, and the data includes measurements
from the one or more sensors.
[0060] Statement 17: A method is disclosed comprising: drilling, by
a bottomhole assembly having a drill tool, a wellbore in a
formation; measuring, by a fiber optic line having a length and
coupled with the bottomhole assembly during the drilling, one or
more downhole parameters along the length of the fiber optic line;
and transmitting, to a controller during the drilling, data from
the fiber optic line, wherein the fiber optic line is a distributed
sensor and the length of the fiber optic line traverses the length
of the wellbore from the bottomhole assembly to the surface.
[0061] Statement 18: A method is disclosed according to Statement
17, further comprising: adjusting, by the controller, the drilling
of the wellbore based on the data from the fiber optic line.
[0062] Statement 19: A method is disclosed according to Statements
17 or 18, wherein the fiber optic line is one or more of the
following: a distributed temperature sensor, a distributed acoustic
sensor, and a distributed pressure sensor; and wherein the one or
more downhole parameters includes temperature, acoustic signals,
and/or pressure.
[0063] Statement 20: A method is disclosed according to any of
preceding Statements 17-19, wherein the bottomhole assembly
includes one or more sensors, and the data includes measurements
from the one or more sensors.
[0064] The disclosures shown and described above are only examples.
Even though numerous characteristics and advantages of the present
technology have been set forth in the foregoing description,
together with details of the structure and function of the present
disclosure, the disclosure is illustrative only, and changes may be
made in the detail, especially in matters of shape, size and
arrangement of the parts within the principles of the present
disclosure to the full extent indicated by the broad general
meaning of the terms used in the attached claims. It will therefore
be appreciated that the embodiments described above may be modified
within the scope of the appended claims.
* * * * *