Exploring, drilling and completing hydrocarbon and other wells are generally complicated, time consuming and ultimately very expensive endeavors. In recognition of these expenses, added emphasis has been placed on efficiencies associated with well completions and maintenance over the life of the well. Along these lines, added emphasis has been placed on well logging, profiling and monitoring of conditions from the outset of well operations. Whether during interventional applications or at any point throughout the life of a well, detecting and monitoring well conditions has become a more sophisticated and critical part of well operations.
Such access to the well is often provided by way of coiled tubing. Coiled tubing may be used to deliver interventional or monitoring tools downhole and it is particularly well suited for being driven downhole through a horizontal or tortuous well, to depths of perhaps several thousand feet, by an injector at the surface of the oilfield. Thus, with these characteristics in mind, the coiled tubing will also generally be of sufficient strength and durability to withstand such applications.
In addition to providing access generally, coiled tubing may be utilized as a platform for carrying passive sensing capacity. For example, a fiber optic line may be run through the coiled tubing interior and utilized to acquire distributed measurements, such as distributed temperature, pressure, vibration, and/or strain measurements from within the well. This may be referred to as providing distributed temperature sensing (DTS) and/or heterodyne distributed vibration sensing (hDVS) capacity. In this manner, the deployment of coiled tubing into the well for a given application may also result in providing such additional information in a relatively straight forward manner without any undue requirement for additional instrumentation or effort.
By the same token, given the capacity of the coiled tubing to carry a telemetric line, fiber optics may be utilized for sake of communication, for example, between oilfield equipment and a downhole application tool (e.g. at the bottom or downhole end of the coiled tubing). That is, while a more conventional electric cable may also be utilized for communications, there may be circumstances where a fiber optic line is preferred. For example, an electric cable capable of providing two-way communications between oilfield equipment and a downhole application tool may be of comparatively greater size, weight, and slower communication speeds as compared to a fiber optic telemetric line. This may not be of dramatic consequence when the application run is brief and/or the well is of comparatively shallower depths, say below about 10,000 feet. However, as wells of increasingly greater depths, such as beyond about 20,000 feet or so, become more and more common, the difference in time required to run the application as well as the weight of the extensive electrical cable may be quite significant.
As alluded to above, utilizing a fiber optic line in place of an electric cable may increase communication or data transmission rates as well as reduce the weight of the overall deployed coiled tubing assembly. Once more, a fiber optic line may be more durable than the electric cable in certain respects. For example, where the application to be carried out downhole involves acid injection for sake of cleaning out a downhole location, acid will be pumped through the coiled tubing coming into contact with the telemetric line therethrough. In such circumstances, the line may be more resistant to acid where fiber optics are utilized for the telemetry, given the greater susceptibility of electric lines to damage upon acid exposure.
In spite of the variety of advantages, utilizing a fiber optic line to provide telemetry through the coiled tubing in lieu of an electric line does present certain challenges. For example, given the more common deeper wells of today, it is likely that the fiber optic line would be of an extensive length and require a heat resistant capacity. Indeed, high temperature fiber optic lines are available which are rated for use at over 150° C. However, such fiber optic lines are substantially more expensive on a per foot basis. Once more, with well depths commonly exceeding 20,000 feet and susceptible to extreme temperatures, this means that the line cost is likely to be very expensive. By way of example, in today's dollars it would not be uncommon to see a 22,000 foot fiber optic line with two-way communications approach about $250,000 in cost.
In an effort to reduce the cost of a fiber optic line through a coiled tubing as described above, it is feasible to eliminate certain threads of the line. That is, a conventional two-way fiber optic line would include multiple fiber optic threads. Specifically, one or more threads may provide a downlink for data from the oilfield surface, for example to command a downhole tool whereas one or more threads would provide an uplink for data back to the surface from the tool. Thus in theory, for two-way fiber optic communication, the total threads may be reduced to a total of no more than two (e.g. one dedicated for downlink and the other for uplink).
While some cost reduction might be seen in reducing the number of fiber optic threads perhaps by as much as $60,000 per thread eliminated in the 22,000 foot example, the ability to reduce the line down to a single fiber may not be a practical undertaking at present. For example, it might be feasible to utilize the dedicated thread for uplink communications from the tool and send downlink commands through another mode such as pressure pulse actuation. However, this would result in a downlink signal that might be of poorer quality and require its own dedicated surface controls, therefore driving up equipment cost. Thus, as a practical matter, coiled tubing operators are generally left with the option of either more expensive fiber optic communications or less desirable electric communications.
A telemetric coiled tubing system. The system includes a surface assembly and a downhole assembly each of which including a fiber optic transmitter, receiver and coupler. Further, a surface unit is coupled to the surface assembly for directing an application in a well over the system whereas a downhole tool is coupled to the downhole assembly for performing the application in the well. Additionally, a fiber optic thread may be run through the coiled tubing of the system and coupled to each of the couplers for simultaneously transmitting fiber optic data from each transmitter to each receiver.
In the following description, numerous details are set forth to provide an understanding of the present disclosure. This includes description of the surrounding environment in which embodiments detailed herein may be utilized. In addition to the particular surrounding environment detail provided herein, that of U.S. Pat. Nos. 7,515,774 and 7,929,812, each for Methods and Apparatus for Single Fiber Optical Telemetry may be referenced as well as U.S. application Ser. No. 14/873,083 for an Optical Rotary Joint in Coiled Tubing Applications, each of which is incorporated herein by reference in their entireties. Additionally, it will be understood by those skilled in the art that the embodiments described may be practiced without these and other particular details. Further, numerous variations or modifications may be employed which remain contemplated by the embodiments as specifically described.
Embodiments are described with reference to certain tools and applications run in a well over coiled tubing. The embodiments are described with reference to particular cleanout applications utilizing acid and a cleanout tool at the end of a coiled tubing line. However, a variety of other applications may take advantage of embodiments of coiled tubing telemetry assemblies as detailed herein. Indeed, so long as the system includes surface and downhole assemblies each outfitted with a fiber optic transmitter, receiver and coupler; a single fiber optic thread may be run therebetween for two-way communications and allowing appreciable benefit to be realized as a result.
Referring specifically now to
Each coupler 101, 110 may be equipped with a common fitting 130, 170 for securing the single thread 180 at the well side thereof. Further, the uphole coupler 101 includes a dedicated downlink channel 105 coupled to the light transmitter 129 and a dedicated uplink channel 109 coupled to the receiver 127. Similarly, the downhole coupler 110 includes a dedicated downlink channel 115 coupled to a receiver 177 and a dedicated uplink channel 119 coupled to a fiber optic transmitter 179. Ultimately, this means that downlink fiber optic light or signal 140 may pass from the uphole fiber optic light transmitter 129 and into the shared fiber optic thread 190 eventually emerging at the downhole receiver 177 via the couplers 101, 110. As noted, the thread 190 is shared for two-way communications as described further below. Thus, uplink fiber optic light or signal 160 may simultaneously be transmitted from the downhole fiber optic light transmitter 179 and into the thread 190 eventually emerging at the uphole receiver 127 via the couplers 101, 110. As a practical matter, this means that surface equipment 125 of the uphole assembly may send data to a downhole tool 175 and the tool 175 may send data back to the equipment 125 over the very same fiber optic thread 190, simultaneously.
The above described couplers 101, 110 allow for the passage of fiber optic light 140, 160 in both directions over the thread 190 at the same time. For example, the channels 105, 115 supporting downlink light 140 need not be structurally maintained separate and apart from the channels 109, 119 supporting uplink light 160 throughout the entire length of the system 100. Instead, within the uphole coupler 101 the uphole channels 105, 115 may be brought to interface with one another and physically merge with the single fiber optic thread 190. Similarly, within the downhole coupler 110, the downhole channels 115, 119 may also be brought into physical interface with one another and merge with the same thread 190 at the downhole end thereof.
Unlike electrical current, or other forms of data transfer, merging the optical pathways of both the downlink light 140 and uplink light 160 into the same shared thread 190 does not present an interference issue. That is, the two different lights 140, 160, each headed in opposite directions do not impede one another.
Other measures may be taken to ensure that the downlink light 140 reaches the downhole receiver 177 and the uplink light 160 reaches the uphole receiver 127. These measures may include tuning the receivers 127, 177 to particular wavelengths of light detection or interfacing each receiver 127, 177 with filters to substantially eliminate the detection of unintended light or both. For example, in a non-limiting embodiment, the downlink light 140 may be emitted by the uphole transmitter 129 at 1550 nm of wavelength whereas the uplink light 160 may be emitted by the downhole transmitter 179 at a 1310 nm wavelength. In this case, the transmitters 129, 179 may be conventional laser diodes suitable for emitting such wavelengths. Regardless, even if 1550 nm light 140 from the uphole transmitter 129 reflects back toward the uphole receiver 127, detection thereof may be substantially avoided due to tuning of the receiver 127 to receive 1310 nm light and filter out 1550 nm light.
Even the use of wavelengths that are 200 or more nm apart in wavelength may further aid in avoiding such crosstalk detections by the receiver 229. Indeed, in an embodiment, the wavelengths may be even further separated, for example with the uplink light 160 being 810 nm in contrast to the downlink light 140 of 1550 nm (or vice versa). Of course, in this same embodiment, the downhole receiver 177 is afforded the same type of tuning and/or filtering to help ensure proper detection of 1550 nm light 140 to the substantial exclusion of 1310 nm light.
Continuing with reference to
Referring now to
With added reference to
As with the surface components, separate downhole fiber optic channels 115, 119 emerge from downhole features, for example in communication with a downhole tool 175. Again though, these separate channels 115, 119 come into interface with one another and the fiber optic thread 190 within the body of the downhole coupler 110. Thus, as the thread 190 emerges from the downhole common fitting 170, it carries light 160 from a downhole transmitter 179 as detailed above while also serving as a platform for downlink light 140 headed toward the downhole receiver 177.
Continuing with reference to
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With added reference to
While the coupler embodiments 101, 110 depicted in
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As shown in
With added reference to
In other embodiments, additional fiber optic threads may be utilized beyond the two-way communication thread 190 running through the coiled tubing 410. For example, a fiber optic thread dedicated to acquiring passive distributed readings such as, but not limited to, DTS readings, for relay to the control unit 450 may be incorporated into the system 100. Nevertheless, these communications remain fiber optic in nature. Thus, not only is the weight kept to a minimum which is particularly beneficial over the span of several thousand feet, but this also means that the equipment interfaces may remain of single type. That is, the surface equipment 125 may utilize consistent fiber optic interfacing for all communications and not require dedicated fiber optic interface for some communications while requiring alternative circuitry for other communication types.
With the above in mind, in yet another embodiment, the surface coupler 101 may be provided with a third channel for accommodating this added DTS (or similar distributed measurement) thread. In this embodiment, this added dedicated DTS thread may be employed as opposed to utilizing the two-way communication thread 190 of
Referring now to
Embodiments of a telemetric coiled tubing system are detailed herein which allow for a practical, cost saving implementation. More specifically, two-way telemetry may be achieved over a single fiber optic thread running several thousand feet through a well during a coiled tubing application. Once more, the two-way communication substantially eliminates cross-talk and other issues that might render sharing a single fiber optic thread less reliable. Ultimately, this allows for two-way communications over a single thread in a cost-effective and reliable manner. Thus, the size and weight of the communication line through the coiled tubing may be kept to a minimum while allowing for high-speed two-way communication. Additionally, the cost of added threads may be avoided or opted for, such as to provide passive distributed readings, such as distributed temperature, distributed pressure, distributed vibration, distributed strain or the like, at the operator's own discretion. Ultimately, the operator now has a reliable and more cost effective option where two-way telemetry over a coiled tubing system is desired.
The preceding description has been presented with reference to presently preferred embodiments. Persons skilled in the art and technology to which these embodiments pertain will appreciate that alterations and changes in the described structures and methods of operation may be practiced without meaningfully departing from the principle, and scope of these embodiments. Regardless, the foregoing description should not be read as pertaining only to the precise structures described and shown in the accompanying drawings, but rather should be read as consistent with and as support for the following claims, which are to have their fullest and fairest scope.