U.S. patent application number 14/892304 was filed with the patent office on 2016-04-07 for optical interface system for communicating with a downhole tool.
The applicant listed for this patent is Schlumberger Technology Corporation. Invention is credited to David Santoso.
Application Number | 20160097275 14/892304 |
Document ID | / |
Family ID | 52142729 |
Filed Date | 2016-04-07 |
United States Patent
Application |
20160097275 |
Kind Code |
A1 |
Santoso; David |
April 7, 2016 |
Optical Interface System For Communicating With A Downhole Tool
Abstract
An optical interface system is disclosed. In accordance with an
embodiment, such a system includes an optical interface. A surface
control system is coupled to a first end of the optical interface,
and a logging tool coupled to an opposite second end of the optical
interface. Data and/or power can be exchanged between the logging
tool and the optical interface by converting electrical signals
into corresponding optical signals which can be transmitted over
the optical interface. Corresponding methods are also disclosed
herein.
Inventors: |
Santoso; David; (Sugar Land,
TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Schlumberger Technology Corporation |
Sugar Land |
TX |
US |
|
|
Family ID: |
52142729 |
Appl. No.: |
14/892304 |
Filed: |
June 27, 2014 |
PCT Filed: |
June 27, 2014 |
PCT NO: |
PCT/US2014/044674 |
371 Date: |
November 19, 2015 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
61841314 |
Jun 29, 2013 |
|
|
|
Current U.S.
Class: |
340/854.7 |
Current CPC
Class: |
E21B 47/135
20200501 |
International
Class: |
E21B 47/12 20060101
E21B047/12 |
Claims
1. A system comprising: an optical interface; a surface control
system coupled to a first end of the optical interface; and a
logging tool coupled to a second end of the optical interface, the
first and second ends being opposite ends of the optical interface;
wherein data is exchanged between the surface control system and
the downhole tool using optical signals sent over the optical
interface.
2. The system of claim 1, wherein the surface control system
comprises a surface interface module having a first converter
configured to convert electrical signals into corresponding optical
signals for transmission over the optical interface and to convert
optical signals received via the optical interface into
corresponding electrical signals; and wherein the logging tool
comprises a second converter configured to convert electrical
signals into corresponding optical signals for transmission over
the optical interface and to convert optical signals received via
the optical interface into corresponding electrical signals.
3. The system of claim 2, wherein the logging tool comprises an
adapter that mates with a read-out port on the logging tool,
wherein the second converter is located in the adapter and the
adapter is coupled to the second end of the optical interface.
4. The system of claim 2, wherein the surface interface module
comprises a photonic power module configured to deliver power to
the logging tool as an optical signal.
5. The system of claim 4, wherein the logging tool comprises a
photovoltaic power converter that converts the optical signal
produced by the photonic power module into electrical power.
6. The system of claim 5, wherein the logging tool comprises an
adapter that mates with a read-out port on the logging tool,
wherein the photovoltaic power converter is located in the adapter
and the adapter is coupled to the second end of the optical
interface.
7. The system of claim 4, wherein the optical interface comprises a
fiber-optic cable comprising at least one optical fiber.
8. The system of claim 7, wherein optical signals corresponding to
the power and the data are transmitted over the same optical fiber
using different optical wavelengths.
9. The system of claim 7, wherein optical signals corresponding to
the power and the data are transmitted over first and second
optical fibers, respectively, of the fiber-optic cable.
10. The system of claim 4, wherein optical signals corresponding to
the data are sent over multiple optical fibers of the fiber-optic
cable in parallel, with each optical fiber representing a
respective data channel.
11. The system of claim 1, comprising an external power source that
supplies power to the logging tool.
12. The system of claim 1, comprising an internal power source that
supplies power to the logging tool.
13. The system of claim 1, wherein the data is exchanged between
the surface control system and the downhole tool using the optical
interface at a transfer rate of at least 1 gbps.
14. The system of claim 1, wherein the data is exchanged between
the surface control system and the downhole tool using the optical
interface at a transfer rate of at least 57.6 kbps.
14. The system of claim 1, wherein the downhole tool is not
deployed in a borehole.
15. The system of claim 1, wherein the downhole tool comprises at
least one of a logging-while-drilling tool, a
measurement-while-drilling tool, a sampling tool, a wireline
logging tool, or a slickline logging tool.
16. The system of claim 1, wherein the downhole tool comprises a
memory storing log data, and wherein the exchange of data between
the surface control system and the downhole tool comprises the
transmitting log data stored in the memory of the downhole tool to
the surface control system over the optical interface using the
optical signals.
17. The system of claim 1, wherein the data exchanged between the
surface control system and the downhole tool comprises at least one
of diagnostic data, calibration data, software updates, or
initialization data.
18. The system of claim 16, wherein the initialization data
comprises at least one of instructions for synchronizing a clock of
the logging tool to a clock of the surface control system,
instructions for selection of measurement points and/or types, or
instructions for selection of data compression parameters.
19. A method comprising: establishing an optical interface between
a surface control system and a downhole tool located at a surface
location; and exchanging data between the downhole tool and the
surface control system using a first optical signal sent over the
optical interface.
20. The method of claim 19, comprising delivering power from the
surface control system to the downhole tool using a second optical
signal sent over the optical interface.
21. The method of claim 19, wherein establishing the optical
interface further comprises connecting a fiber-optic cable between
the surface control system and the downhole tool.
22. The method of claim 20, wherein delivering power from the
surface control system to the downhole tool comprises using a
photonic power module of the surface control system to generate the
second optical signal.
23. The method of claim 19, wherein delivering power from the
surface control system to the downhole tool comprises using a
plurality of photonic power modules each configured to generate a
respective optical signal, wherein the combined energy of the
respective optical signal represents the power delivered by the
surface control module.
Description
CROSS-REFERENCE TO RELATED APPLICATION
[0001] This application claims priority from U.S. Provisional
Patent Application 61/841,314, filed Jun. 29, 2013, which is
incorporated herein by reference in its entirety.
BACKGROUND
[0002] 1. Technical Field
[0003] The present disclosure relates generally to downhole tools.
More specifically, the present disclosure relates to an optical
interface system for communicating with a downhole tool.
[0004] 2. Background Information
[0005] This section is intended to introduce the reader to various
aspects of art that may be related to various aspects of the
subject matter described and/or claimed below. This discussion is
believed to be helpful in providing the reader with background
information to facilitate a better understanding of the various
aspects of the present disclosure. Accordingly, it should be
understood that these statements are to be read in this light, not
as admissions of prior art.
[0006] Downhole tools are used in the oilfield industry to perform
various tasks and functions downhole, i.e., in a borehole at a
location beneath the surface of the earth. For instance, logging
tools are a type of downhole tool that have long been used in
wellbores to make, for example, formation evaluation measurements
to infer properties of the formations surrounding the borehole and
the fluids in the formations. Common logging tools include
electromagnetic tools, nuclear tools, and nuclear magnetic
resonance (NMR) tools, though various other types of tools for
evaluating formation properties are also available. As an example,
electromagnetic logging tools typically measure the resistivity (or
its reciprocal, conductivity) of a formation and may include
galvanic, induction, and propagation electromagnetic tools.
[0007] Early logging tools were run into a wellbore on a wireline
cable after the wellbore had been drilled. Modern versions of such
wireline tools are still used extensively. However, as the demand
for information while drilling a borehole continued to increase,
measurement-while-drilling (MWD) tools and logging-while-drilling
(LWD) tools have since been developed. MWD tools typically provide
drilling parameter information such as weight on the bit, torque,
temperature, pressure, direction, and inclination. LWD tools
typically provide formation evaluation measurements such as
resistivity, porosity, NMR distributions, and so forth. MWD and LWD
tools often have characteristics common to wireline tools (e.g.,
transmitting and receiving antennas), but MWD and LWD tools are
designed and constructed to endure and operate in the harsh
environment of drilling.
[0008] MWD/LWD tools are located on the drill string, typically in
a bottom hole assembly (BHA), and thus are capable of obtaining
data pertaining to measurement of drilling parameters and/or
characteristics about a formation while a borehole is being
drilled. The acquired data can be stored in memory located on the
MWD/LWD tool, and can also be communicated uphole using any
suitable type of telemetry method, such as mud pulse telemetry or
acoustic telemetry methods to name just a few types. However, since
current telemetry techniques have bandwidth constraints that limit
the amount of data that can be sent uphole while drilling,
typically a relatively small fraction of the data acquired by
MWD/LWD tools is actually sent uphole during the drilling
process.
[0009] The entirety of the data acquired during the drilling
process (or at least the portion not sent uphole during drilling)
may be subsequently retrieved after the MWD/LWD tools are tripped
out of the borehole, i.e., brought back to the surface, and the
retrieval of such data is sometimes referred to as a "dump" of the
recorded data. In conventional systems, an electronic communication
interface is typically established between the tool and a surface
computing system, such as by way a cable containing one or more
electronic conductors communicatively and electronically coupling
the surface computing system to the tool. Thus, the data dump from
the tool can be transmitted from the tool to the surface computing
system over the electronic interface. Conversely, the surface
computing system and also send data to the tool over the electronic
interface in some instances, such as for diagnostics, calibration,
or initialization.
[0010] However, electronic interfaces can be subject to bandwidth
limitations, which may constrain data transfer rates. Bandwidth may
depend on the type of communication protocol being used. For
example, in some conventional systems, a transfer rate of between
10 to 30 megabits per second (mbps) can be achieved over an
electrical interface. Other times, such transfers over an
electrical interface can be much slower, such as 50-60 kilobits per
second, depending on various factors. Further, the length of the
cable containing the electronic conductor(s) forming the interface
(which represents the distance that signals representing the data
travel) can also be a factor that limits bandwidth. Thus is due to
signal losses that may increase proportionately as the distance the
signal travels increases. As an example, this is particularly
problematic in offshore systems, where the surface computing system
may be located on the rig and the tool may be located on a marine
vessel several hundred feet away from the computing system.
[0011] In recent years, the amount of recorded data in MWD/LWD
tools has steadily increased. This is due at least in part to
increasing complexity in drilling jobs (e.g., directional drilling
where steering decisions rely on real time data) as well as
increased complexity of BHAs. For instance, BHAs today can include
multiple LWD tools (e.g., a resistivity tool, an NMR tool, a
density tool, and so forth), each of which may be designed to
obtain certain types of measurements. Due to the increased amount
of data, data dumps from the tools are taking longer and longer.
Accordingly, an enhanced communication interface system that can
provide faster data transfer rates while experiencing little signal
loss is highly desirable.
SUMMARY
[0012] A summary of certain embodiments disclosed herein is set
forth below. It should be understood that these aspects are
presented merely to provide the reader with a brief summary of
certain embodiments and that these aspects are not intended to
limit the scope of this disclosure. Indeed, this disclosure may
encompass a variety of aspects that may not be set forth in this
section.
[0013] In accordance with one embodiment, a system includes an
optical interface, a surface control system coupled to a first end
of the optical interface, and a logging tool coupled to a second
end of the optical interface, with the first and second ends being
opposite ends of the optical interface. Data is exchanged between
the surface control system and the downhole tool using optical
signals sent over the optical interface.
[0014] In accordance with another embodiment, a method includes
establishing an optical interface between a surface control system
and a downhole tool located at a surface location. The method
further includes exchanging data between the downhole tool and the
surface control system using an optical signal sent over the
optical interface.
[0015] Again, the brief summary presented above is intended to
familiarize the reader with certain aspects and contexts of
embodiments of the present disclosure without limitation to the
claimed subject matter.
BRIEF DESCRIPTION OF THE DRAWINGS
[0016] Various aspects of this disclosure may be better understood
upon reading the following detailed description and upon reference
to the drawings in which:
[0017] FIG. 1 is a well site system that may include an optical
interface system exchanging data between a surface computing system
and a logging tool in accordance with an embodiment of the present
disclosure;
[0018] FIG. 2 shows a prior art surface communication system for
exchanging data between a surface computing system and a downhole
tool;
[0019] FIG. 3 shows an optical communication system for exchanging
data between a surface computing system and a downhole tool using
optical signals, in accordance with an embodiment of the present
disclosure;
[0020] FIG. 4 shows a fiber-optic cable through which the optical
signals of FIG. 3 may be transmitted in accordance with an
embodiment of the present disclosure;
[0021] FIG. 5 a fiber-optic cable through which the optical signals
of FIG. 3 may be transmitted in accordance with another embodiment
of the present disclosure;
[0022] FIG. 6 shows another embodiment of an optical communication
system for exchanging data between a surface computing system and a
downhole tool using optical signals; and
[0023] FIG. 7 is a flow chart that shows a method for exchanging
data and/or powering a logging tool using an optical interface and
corresponding optical signals.
DETAILED DESCRIPTION
[0024] One or more specific embodiments of the present disclosure
are described below. These embodiments are merely examples of the
presently disclosed techniques. Additionally, in an effort to
provide a concise description of these embodiments, all features of
an actual implementation may not be described in the specification.
It should be appreciated that in the development of any such
implementation, as in any engineering or design project, numerous
implementation-specific decisions are made to achieve the
developers' specific goals, such as compliance with system-related
and business-related constraints, which may vary from one
implementation to another. Moreover, it should be appreciated that
such development efforts might be complex and time consuming, but
would nevertheless be a routine undertaking of design, fabrication,
and manufacture for those of ordinary skill having the benefit of
this disclosure.
[0025] When introducing elements of various embodiments of the
present disclosure, the articles "a," "an," and "the" are intended
to mean that there are one or more of the elements. The embodiments
discussed below are intended to be examples that are illustrative
in nature and should not be construed to mean that the specific
embodiments described herein are necessarily preferential in
nature. Additionally, it should be understood that references to
"one embodiment" or "an embodiment" within the present disclosure
are not to be interpreted as excluding the existence of additional
embodiments that also incorporate the recited features.
[0026] As discussed further below, the present disclosure relates
to an optical interface system that, when established between a
logging tool located at a surface location (e.g., not deployed in a
borehole) and a surface control system, can be used to deliver
power to the logging tool via an optical signal, and can also
provide for the exchange of data between the logging tool and the
surface control system using optical signals. When compared to
existing electrical interfaces, an optical interface system of this
type provides certain advantages. For instance, optical interfaces,
i.e., a fiber-optic cable, can typically transmit data and much
higher transfer rates. Further, optical interfaces typically
experience much less signal attenuation over distance and are
generally immune to electromagnetic interference, adverse
environmental conditions, and crosstalk, any of which can
negatively affect an electrical interface.
[0027] As used herein, the term "downhole tool" or the like shall
be understood to refer to a type of tool that can be used downhole
in a borehole drilled in an earth formation. For instance, many
types of downhole tools exist, such as logging tools for formation
evaluation, steering tools, telemetry tools, sampling tools, and so
forth. That is to say, the term "downhole" in this sense is meant
to describe that the tool can be used in a downhole environment to
perform one or more desired functions. The term "downhole tool" is
not intended to convey that the tool is necessarily presently
deployed downhole, unless other specified. Indeed, as will be
discussed herein, the optical interface system embodiments of the
present disclosure can be used with downhole tools at a surface
location, i.e., when the tool is not deployed in a borehole.
[0028] With the foregoing in mind, FIG. 1 represents a simplified
view of a well site system in which various embodiments can be
employed. The well site system depicted in FIG. 1 can be deployed
in either onshore or offshore applications. In this type of system,
a borehole 11 is formed in subsurface formations by rotary drilling
in a manner that is well known to those skilled in the art. Some
embodiments can also use directional drilling.
[0029] A drill string 12 is suspended within the borehole 11 and
has a BHA 100 which includes a drill bit 105 at its lower end. The
surface system includes a platform and derrick assembly 10
positioned over the borehole 11, with the assembly 10 including a
rotary table 16, kelly 17, hook 18 and rotary swivel 19. In a
drilling operation, the drill string 12 is rotated by the rotary
table 16 (energized by means not shown), which engages the kelly 17
at the upper end of the drill string. The drill string 12 is
suspended from a hook 18, attached to a traveling block (also not
shown), through the kelly 17 and a rotary swivel 19 which permits
rotation of the drill string 12 relative to the hook 18. As is well
known, a top drive system could be used in other embodiments.
[0030] In this example embodiment, the surface system further
includes drilling fluid or mud 26 stored in a pit 27 formed at the
well site. A pump 29 delivers the drilling fluid 26 to the interior
of the drill string 12 via a port in the swivel 19, which causes
the drilling fluid 26 to flow downwardly through the drill string
12, as indicated by the directional arrow 8 in FIG. 1. The drilling
fluid exits the drill string 12 via ports in the drill bit 105, and
then circulates upwardly through the annulus region between the
outside of the drill string 12 and the wall of the borehole, as
indicated by the directional arrows 9. In this known manner, the
drilling fluid lubricates the drill bit 105 and carries formation
cuttings up to the surface as it is returned to the pit 27 for
recirculation.
[0031] The drill string 12 includes a BHA 100. In the illustrated
embodiment, the BHA 100 is shown as having one MWD module 130 and
multiple LWD modules 120 (with reference number 120A depicting a
second LWD module 120). As used herein, the term "module" as
applied to MWD and LWD devices is understood to mean either a
single tool or a suite of multiple tools contained in a single
modular device. Additionally, the BHA 100 includes a rotary
steerable system (RSS) and motor 150 and a drill bit 105.
[0032] The LWD modules 120 may be housed in a drill collar, as is
known in the art, and can include one or more types of logging
tools. The LWD modules 120 may include capabilities for measuring,
processing, and storing information, as well as for communicating
with the surface equipment. By way of example, the LWD module 120
may include at least one of a resistivity, nuclear magnetic
resonance (NMR), nuclear (e.g., neutron density/porosity), or
acoustic logging tool, or a combination of such logging tools.
[0033] The MWD module 130 is also housed in a drill collar, as is
known in the art, and can contain one or more devices for measuring
characteristics of the drill string and drill bit. In the present
embodiment, the MWD module 130 can include one or more of the
following types of measuring devices: a weight-on-bit measuring
device, a torque measuring device, a vibration measuring device, a
shock measuring device, a stick/slip measuring device, a direction
measuring device, and an inclination measuring device (the latter
two sometimes being referred to collectively as a D&I package).
The MWD tool 130 further includes an apparatus (not shown) for
generating electrical power for the downhole system. For instance,
power generated by the MWD tool 130 may be used to power the MWD
tool 130 and the LWD tool(s) 120. In some embodiments, this
apparatus may include a mud turbine generator powered by the flow
of the drilling fluid 26. It is understood, however, that other
power and/or battery systems may be employed.
[0034] The operation of the assembly 10 of FIG. 1 may be controlled
using control system 152 located at the surface. The control system
152 may include one or more processor-based computing systems. In
the present context, a processor may include a microprocessor,
programmable logic devices (PLDs), field-gate programmable arrays
(FPGAs), application-specific integrated circuits (ASICs),
system-on-a-chip processors (SoCs), or any other suitable
integrated circuit capable of executing encoded instructions
stored, for example, on tangible computer-readable media (e.g.,
read-only memory, random access memory, a hard drive, optical disk,
flash memory, etc.). Such instructions may correspond to, for
instance, workflows and the like for carrying out a drilling
operation, algorithms and routines for performing various
inversions using acquired logging data (e.g., for determining
formation models), and so forth.
[0035] The control system 152 may further include a surface
interface module (not shown in FIG. 1) that may connect to a
logging tool (e.g., MWD tool 130 or LWD tool(s) 120) to establish a
communication interface that enables the control system to receive
a data dump from the tool. This is typically performed when the
tool is retrieved from the borehole and returned to the surface. In
addition to obtaining a data dump from the logging tool, the
control system 152 may also communicate with logging tool to
execute one or more diagnostic tests, for calibration purposes,
software updates, and/or for initialization purposes (e.g.,
synchronization of a system clock of the tool with a control system
152 clock, selection of measurement types/points, data compression
parameters).
[0036] As will be discussed in more detail below, a communication
interface system in accordance with the present disclosure includes
an optical communication interface in which data is transmitted
between the control system 152 and the logging tool as optical
signals. Optical signals, which are based on light, can typically
provide a higher bandwidth compared to electrical signals.
Additionally, optical signals, which can be transmitted over
optical fiber, are typically much less susceptible to signal loss
as the transmission distance increases when compared to electrical
signals being sent over a comparable distance. This type of
transmission interface is sometimes referred to as "fiber-optic"
communications.
[0037] Before discussing in more detail some of the features that
an optical communication interface system in accordance with
embodiments the present disclosure may include, the reader is
referred first to FIG. 2, which shows a typical prior art surface
communication system 158 for dumping data from a downhole tool. The
prior art system 158 provides an electronic communication interface
166 for use in providing an electronic communication path between
surface control system 152 and a downhole tool, such as an LWD tool
120, typically when the tool is not deployed in the borehole, i.e.,
prior to deployment into a borehole or when the returned to the
surface after a drilling job is completed.
[0038] The electronic communication interface 166 is established
between control system 152 and the tool 120 by way of an electrical
conductor 180, such as copper wire, which may be housed in a cable.
For example, the control system 152 includes one or more surface
computers or workstations 162 and a surface interface module (SIM)
160. The SIM 160 acts as an intermediate interface between the
surface computer(s) 162 and the LWD tool 120, and can also function
as a source of power for the tool 120. For instance, if the tool
120 is typically powered downhole by a BHA (e.g., by a mud turbine
generator) and/or by a separate power source on a drill string, the
tool 120 may not be capable of powering itself when it is not in
use downhole and/or removed from a drill string. Accordingly, the
electrical conductor 180 may include a cable having suitable
connectors for connecting to the SIM and a read-out port (ROP) 170
of LWD tool 120 to provide a bi-directional path for data exchange
between the tool 120 and the SIM 160 (arrow 182) as well as a path
by which power can be supplied to the tool 120 by the SIM 160
(arrow 184). In some prior art systems, power and data may be sent
via separate respective electrical conductors, or power and data
may be sent over the same conductor, with power being sent as a DC
signal and data as an AC signal.
[0039] The simplified block diagram of the tool 120 shows it as
including a controller 172 and a memory device 174. During
drilling, log data, which may represent certain types of
measurements made with respect to the formation in which a borehole
is drilled, may be stored in memory device 174. Accordingly, when
the interface 166 is established, the tool 120 receives power. To
obtain a dump of the log data stored in memory device 174, a
command can be sent from the computer 162 to the tool 120 (by way
of SIM 160). The controller 172 receives the command through the
ROP 170 and may then write the log data stored in memory 174 onto a
bus, where it is sent to the SIM 170 over the electrical interface
166 (via conductor 180). The controller 172 may include a suitable
processor, such as a microprocessor or field gate programmable
array (FPGA) capable of executing instructions, such as firmware or
other suitable embedded software operating systems that drive the
functions of the tool.
[0040] As discussed in the Background Section, electrical
interfaces can be subject to bandwidth and transfer rate limits
due, for example, on communication protocol type and distance
traveled. For instance, with electrical conductors, a degree of
signal loss is typically experienced as the distance that a signal
travels through the conductor increases. In data dumping
applications, the distance between the surface control system 152
and a given tool (e.g., 120, 130) at the surface may be several
hundred feet (e.g., 500 feet or more). This is particularly true in
offshore sites, where the tool at the surface is sometimes stored
on a marine vessel proximate to but separate from the offshore rig
where the surface control system 152 is typically located. Thus, as
the amount of data acquired downhole continues to increase, the
duration of such data dumps is also increasing. Moreover,
communications over electrical interfaces are also susceptible to
additional draw backs, such as electromagnetic interference (EMI)
or RF interference (RFI), cross talk, electrical and magnetic
fields, and/or adverse environmental conditions, i.e., extreme
temperature, moisture, etc. Any of these factors can further
negatively affect electrical signals transmitted through an
electrical interface.
[0041] With the foregoing in mind, an optical communication
interface system 200 in accordance with embodiments of the present
disclosure is illustrated in more detail with respect to FIG. 3.
Referring to FIG. 3, the optical communication interface system 200
may have a similar set up to that of the electrical communication
interface system 158 of FIG. 2, but with the signals exchanged
between the surface control system 152 and the tool 120 being
optical signals.
[0042] The surface control system 152 in FIG. 3 also includes an
SIM (referred to here as reference number 202 to differentiate it
from the SIM 160 of FIG. 2) and one or more surface computers or
workstations. In the present embodiment, the SIM 202 includes a
photonic power module (PPM) 204 and an electrical-optical converter
206. The PPM 204 includes a power system that is capable of
delivering electrical power to another location (e.g., to the tool
120) by light over optical fiber. The PPM 204 may include a light
source (e.g., a laser), and driving circuitry for driving the light
source. It can thus provide an electrically isolated power source
that can drive electronics by delivering power to a remote
location. As an example, in one embodiment, the PPM 204 can provide
between 0.5 to 1 watt of electrical power over a distance of 500
meters or more.
[0043] The electrical-optical converter (EOC) 206 is designed or
otherwise configured such that it can convert electrical signals
into optical signals and also convert optical signals back into
electrical signals. Thus, the EOC 206 can convert electrical
signals from the SIM 202 or computer 162 into optical signals for
transmission to the tool 120 over an optical cable 210, which may
contain one or more optical fibers. The EOC 206 can also convert
optical signals received via the cable 210 into corresponding
electrical signals. For example, the optical signals may be sent as
a series of light pulses that can be converted into a corresponding
electrical signal, i.e. a digital binary signal. These optical
signals representing data are depicted as arrow 232 in FIG. 3.
[0044] The optical cable 210 connects the SIM 202 to an adapter 220
connected to the ROP 170. The adapter 220 includes a photovoltaic
power converter (PPC) 222 and an EOC 224, which may substantially
identical to the EOC 206 in the SIM 202. The optical energy in the
optical signal sent by the PPM 204 can be converted back into an
electrical output, thus providing electrical power to both the
electronic components of the adapter 220 and of the tool 120. This
type of power delivery (represented by arrow 230) over
non-conductive optical fiber is sometimes referred to as
"power-over-fiber." Thus, both data and power can be sent over the
optical interface 208.
[0045] Like the EOC 206, the EOC 224 of the adapter 220 can convert
optical signals received via the cable 210 into corresponding
electrical signals, and also converts electrical signals that are
to be sent to the SIM 206 into optical signals. For instance, in
the case of a data dump, electrical signals representing log data
that is being dumped from the memory 174 of the tool 120 is
converted into optical signals (by EOC 224) for transmission over
the optical cable 210 to the SIM 202, where the optical signals are
then converted back into corresponding electrical signals (by EOC
206). Further, in a data dump, the data retrieved from memory 174
can be stored in one or more storage devices of the surface
computer 162, such as a hard drive, optical disc drive, flash
drive, or any other suitable type of storage medium.
[0046] Further, while the LWD tool 120 is used an example in FIG.
3, it will be understood that the optical interface system 200 can
be usable with any type of downhole logging tools, such as MWD
tools (e.g., 130), telemetry tools, sampling tools, and so forth.
The optical interface system 200 can also be used with wireline or
slickline tools. Moreover, while discussed in this example in the
context of performing data dumps, the optical interface system 200
shown in FIG. 3 can also be used for other purposes, such as for
running tool diagnostic tests, for calibration of a tool (e.g.,
calibration of sensors and/or antennas), and/or for initialization
of the tool while tool is on the rig floor, a proximate marine
vessel (for offshore applications) or in a workshop/lab setting.
Initialization can include syncing the tool clock with the surface
control system clock and/or initializing other parameters. For
example, where the tool is capable of multiple types of measurement
points (e.g., acoustic, resistivity, density, etc.), initialization
data may include selection of the measurement types that are to be
recorded into the tool memory and/or telemetered to the surface
during drilling. For each selected measurement point, specific
measurement types can also be specified during initialization. For
example, if acoustic measurements are selected and the tool is
capable of both monopole and dipole acoustic measurements, the
initialization data can further specify that monopole acoustic
measurements are to be recorded, that dipole acoustic measurements
are to be recorded, or that both types of measurements are to be
recorded. The initialization data can also include selection of
data compression parameters. For instance, for telemetry purposes,
data can be compressed to reduce the number of bits that are
transmitted uphole. The degree or type of compression, or even the
decision not to compress the data, can be selected as part of
initialization. Still further, data exchanged over the optical
interface system 200 can also include software updates, such as a
firmware update, for the tool 120. Accordingly, data exchanged
between as optical signals may include software updates,
diagnostic, initialization, and/or calibration commands/data.
[0047] With respect to the embodiment of FIG. 3, the adapter 220
allows for the optical interface system 200 to be used with
existing read-out ports 170 on tools that may have originally been
designed for electrical signals without substantial modification to
the tool itself. That is, the adapter 220 receives the optical
signals sent via the optical cable 210 and converts them into
electrical power and electronic data signals. In other embodiments,
the adapter 220 can be omitted, and the photovoltaic power
converter 222 and electrical-optical converter 224 may be
integrated into the tool. Thus, in such cases, the ROP 170 may be
designed to connect or otherwise interface directly with the
optical cable 210 to pass the optical signals to the PPC 222 and
the EOC 224 within the tool 120.
[0048] As can be appreciated, an optical interface can typically
provide bandwidth and data transfer rates that exceed that of an
electrical interface. For example, in some systems, like the prior
art system 158 shown in FIG. 2, data transfer rates over an
electrical interface may be limited to between approximately 10 to
30 mbps, and may be affected by other factors, such as the distance
of the signal transmission (e.g., the length of the electrical
conductor 180), electromagnetic and/or RF interference, crosstalk,
adverse environmental factors, and so forth. As noted above, in
some conventional electrical interfaces, data may be transferred at
even slower rates, such as 50-60 kbps (e.g., approximately 57.6
kbps in one example). Optical interfaces, in some embodiments can
offer data transfer rates that are up to or exceed 1 gigabit per
second (gbps), i.e., 1 to 10 gbps or more. Further, optical signals
that propagate through fiber-optic cables generally experience
noticeably less attenuation (and thus less signal loss) than that
typically experienced when transmitting electrical conductors over
a comparable distance. Fiber-optic cables are also generally immune
to effects of electromagnetic/RF interference, cross talk, and
environmental factors.
[0049] Accordingly, when performing operations at the surface, such
as tool data dumps, the increased bandwidth and resiliency to
interference offered by optical interfaces may reduce the time
spent to download log data from the tool 120. As an example, a data
dump that may take 30 minutes over an electrical interface (e.g.,
interface 166 of FIG. 2) might take much less time, i.e., a few
minutes, or even less than 1 minute or a matter of seconds, using
an optical interface (e.g., optical interface 208 of FIG. 3). Thus,
in this regard, optical interfaces of this type can offer notable
benefits as the amount of recorded data in drilling operations
(particularly logging- and/or measurement-while drilling or MWD
applications) continues to increase.
[0050] Several examples embodiments of the optical cable 210 from
FIG. 3 (which can also be referred to as a fiber-optic cable) are
depicted in greater detail in FIGS. 4 and 5. Particularly, FIG. 4
shows an embodiment in which the fiber-optic cable 210 includes a
single optical fiber 250 having connectors 252 (for connecting to
the SIM 202) and 254 (for connecting to the adapter 220 or directly
to the tool 120, i.e., via read-out port 170) on opposite ends. In
various embodiments, the fiber 250 may include a single-mode and/or
multi-mode optical fiber. In this embodiment shown in FIG. 4, both
power and data can be delivered over the same fiber 250 using
optical signals having different wavelengths. Further, data can
also be sent over the fiber 250 using multiple wavelengths, each
representing an independent channel, to increase overall data
throughput.
[0051] As can be appreciated, an optical fiber is generally a
flexible transparent fiber and can be made of silica or plastic. It
functions as a light pipe or waveguide to transmit optical signals
(e.g., light) between the two ends of the fiber 250. The optical
fiber 250 may include a transparent core surrounded by a cladding
layer that is also transparent, but has a lower index of refraction
relative to the core. In this manner, optical signals are kept in
the core via the principle of total internal reflection. A buffer
layer may surround the cladding layer to provide a protective outer
coating. These components may be encased by a jacket layer
(sometimes just called a "jacket") that may serve to protect the
fiber-optic cable from the environment.
[0052] FIG. 5 shows another embodiment where power and
communication/data signals are sent using separate respective
optical fibers 250A and 250B. Here, each fiber 250A and 250B may
have a core, a cladding layer, and a buffer layer, as described
above. In the illustrated embodiment, the fibers 250A and 250B may
be coupled to the same connectors 252 and 254 at each end and be
disposed in a single jacket, thus providing a single physical
optical cable with two optical fibers contained therein. In another
embodiment, each of the fibers 250A and 250B may be provided in
separate respective optical cables, with each of the fibers 250A
and 250B being disposed in separate respective jackets and being
coupled to their own respective connectors at each end.
[0053] In some further embodiments, multiple fibers may be used for
either power or data. For instance, with respect to power delivery,
the number of fibers may depend on the amount of power that is to
be delivered to the adapter 220 and/or tool 120 (or 130). For
instance, if it is assumed that 2 W is the desired wattage for
powering the tool 120 and electronics of the adapter 220 and that a
given optical fiber and light source of the photonic power module
204 is capable of delivering 500 mW of power over a single cable,
then four such optical fibers may be provided with each delivering
500 mW to achieve the desires 2 W. In such an embodiment, a
separate respective PPM (e.g., four PPMs in this example) may be
provided for each optical fiber delivering power. The multiple
optical fibers used in such an embodiment can be contained in a
single fiber-optic cable, or separate respective fiber-optic
cables.
[0054] As discussed above, an embodiment can include data being
transmitted over a single fiber using multiple light wavelengths,
each representing a separate respective data channel. This can
increase data transfer rates, as optical signals at the different
wave lengths can be sent in parallel through the optical fiber. In
a further embodiment, multiple optical fibers can be used for data
transmission over the fiber-optic cable 210. In such an embodiment,
each optical fiber for data transmission may represent a separate
data channel, enabling data to be sent in parallel over these
optical fibers. Here, data may be transmitted through each
respective optical fiber can have the same or different wavelength.
Where multiple data channels are provided, the electronic-optical
converter on the receiving end of the interface 208 can include a
parallel-to-serial converter to serialize the data transmitted in
parallel, and the electronic-optical converter on the transmitting
end of the interface 208 can include a serial-to-parallel converter
to de-serialize the data so that it can be transmitted in parallel.
Here again, the multiple optical fibers used in such an embodiment
can be contained in a single fiber-optic cable, or separate
respective fiber-optic cables.
[0055] FIG. 6 shows a further embodiment of the optical interface
system 200 which is similar to the earlier-described embodiment of
FIG. 3, but in which power is not delivered to the adapter 220 and
tool 120 by way of the surface interface module 202. Instead, power
for powering the tool 120 and the electronic components of the
adapter 220 (e.g., those that make up the converter 224) can be
supplied by one or both of an internal power source 270 or an
external power source 260.
[0056] For instance, in one embodiment, the external power source
260 is present and the internal power source 270 may be omitted.
The external power source 260 may include a generator or some other
suitable type of power generation device, such as an external
battery unit. In such an embodiment, the external power source 260,
as indicated by reference number 266, supplies power to the adapter
electronics (e.g., EOC 224) and the tool 120 to power the
controller 172, memory 174, and any other components that operate
on electrical power. Accordingly, since power is provided by the
external power source 260 in this example, power is not transmitted
over the optical interface 208. Instead, the optical interface 208
may be reserved for transferring data 232. Further, it can be seen
that in such an embodiment, the surface interface module 202 does
not include a photonic power module (e.g., 204) and the adapter 220
does not include a photovoltaic power converter (e.g., 222).
[0057] In another embodiment, the external power source 260 can be
omitted and the internal power source 270 can be present. For
instance, the internal power source 270 can include one or more
rechargeable battery units. Here, the internal power source 270 can
power the tool 120 and the adapter electronics. For example, the
converter 224 can be powered as indicated by the conductive path
266 for electrical, which can be external to the tool or can be
routed through the tool, i.e., through the read-out port 170.
Further, in such an embodiment, the external power source 260, if
present, may be used to recharge the internal power source 270.
[0058] In further embodiments, both the external power source 260
and the internal power source 270 can be used. For instance, the
internal power source 270 may be used to power the tool 120, and
the external power source 260 can be used to power the converter
224, as well as to recharge the internal power source 270. With
respect to the various embodiments described with reference to FIG.
6, it will be understood that if the read-out port 170 is designed
to connect directly to the fiber-optic cable 201 and with the
converter 224 being located within the tool, then the adapter 220
can be omitted and powering the tool 120 will also power the
converter 224. Moreover, while described in the context of a well
site application, it should be appreciated that the foregoing
systems can be used in any application for providing data
communications and/or power delivery between two devices.
[0059] FIG. 7 is a flow chart that depicts a method 300 for using
an optical interface to exchange data between a surface control
system of a well site and a downhole logging tool located at a
surface location, in accordance with an embodiment of the present
disclosure. The method 300 begins at 302 where an optical interface
is established between a surface control system and a downhole
logging tool located at a surface location. That is, the downhole
logging is not presently deployed in a borehole. For example, the
downhole logging tool can be located at the surface in the vicinity
of a wellsite, or may be in a testing lab or field workshop for
testing, diagnostics, calibration, maintenance, and/or
initialization. In the latter cases, the surface control system may
not necessarily be on a rig, but may be located in or near a lab or
workshop.
[0060] At 304, upon establishment of the optical interface, data
can be exchanged between the downhole logging tool and the surface
control system using optical signals sent over the optical
interface. As described above, the optical signals can be converted
back into electrical signals at the receiving end of the interface
by an electrical-optical converter. For instance, the optical
signals representative of data to be sent can be expressed using
pulses or flashes of light which can then be converted into a
digital electrical signal. In some embodiment, such as that shown
in FIG. 3, power can also be delivered from the surface control
system to the downhole logging tool using an optical signal sent
over the optical interface. Other embodiments, such as that shown
in FIG. 6, may power the logging tool using a separate external
power source or a power source internal to the logging tool.
Accordingly, this is shown in FIG. 7 at 306 as being optional
(indicated by the dashed line), depending on how power is being
supplied to the downhole logging tool. It should be understood that
while MWD/LWD logging tools 130 and 120 are used in the specific
examples described herein, the presently disclosed optical
interface system can be used in conjunction with any suitable
downhole tools, such as telemetry tools, sampling tools, and so
forth.
[0061] While the specific embodiments described above have been
shown by way of example, it will be appreciated that many
modifications and other embodiments will come to the mind of one
skilled in the art having the benefit of the teachings presented in
the foregoing description and the associated drawings. Accordingly,
it is understood that various modifications and embodiments are
intended to be included within the scope of the appended
claims.
* * * * *