US20160097275A1

US20160097275A1 - Optical Interface System For Communicating With A Downhole Tool

Info

Publication number: US20160097275A1
Application number: US14/892,304
Authority: US
Inventors: David Santoso
Original assignee: Schlumberger Technology Corp
Current assignee: Schlumberger Technology Corp
Priority date: 2013-06-29
Filing date: 2014-06-27
Publication date: 2016-04-07
Also published as: EP3014065A1; EP3014065A4; WO2014210513A1

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.

Description

CROSS-REFERENCE TO RELATED APPLICATION

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

1. Technical Field
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.
2. Background Information
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.
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.
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.
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.
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.
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.
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

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.
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.
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.
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

Various aspects of this disclosure may be better understood upon reading the following detailed description and upon reference to the drawings in which:

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;

FIG. 2 shows a prior art surface communication system for exchanging data between a surface computing system and a downhole tool;

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;

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;

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;

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

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

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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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).
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
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).
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.
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.
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.
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.
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.

Claims

What is claimed is:

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.