Patent Application
20060164918
1. Technical Field
The present subject matter relates to transmitting and receiving telemetry. More particularly, the subject matter relates to transmitting and receiving a discrete multi-tone modulated telemetry signal propagated in a fluid.
2. Background Information
Modern petroleum drilling and production operations demand a great quantity of information relating to parameters and conditions downhole. Such information typically includes characteristics of the earth formations traversed by the wellbore, along with data relating to the size and configuration of the borehole itself. The collection of information relating to conditions downhole is referred to as “logging.”
Logging frequently is done during the drilling process, eliminating the necessity of removing or “tripping” the drilling assembly to insert a wireline logging tool to collect the data. Data collection during drilling also allows the driller to make accurate modifications or corrections as needed to optimize performance while minimizing down time. Designs for measuring conditions downhole, including the movement and location of the drilling assembly contemporaneously with the drilling of the well, have come to be known as “measurement-while-drilling” techniques, or “MWD”. Similar techniques, concentrating more on the measurement of formation parameters, commonly have been referred to as “logging while drilling” techniques, or “LWD”. While distinctions between MWD and LWD may exist, the terms MWD and LWD often are used interchangeably. For purposes of this disclosure, the term LWD will be used with the understanding that this term encompasses both the collection of formation parameters and the collection of information relating to the movement and position of the drilling assembly.
Sensors or transducers are located within “tools” at the lower end of the drillstring in LWD systems. In particular, sensors employed in LWD applications are positioned in a cylindrical drill collar that is positioned close to the drill bit. While drilling is in progress these sensors continuously or intermittently monitor predetermined drilling parameters and formation data, and the tools transmit the information to a surface detector by some form of telemetry. There are a number of communication schemes in the related art that transmit information regarding downhole parameters to the surface, such as mud pulse telemetry systems.
Mud pulse telemetry systems create pressure pulses in the drilling fluid within the drillstring. The information that is acquired by the downhole sensors is transmitted by suitably timing pressure pulses in the drilling fluid. The information is received and decoded by a pressure transducer and computer at the surface. Data transmission rates achievable through mud pulse systems have generally been limited to around 1 Hz, restricting the amount of information that can be transmitted real-time as drilling is taking place. Accordingly, a downhole telemetry system capable of higher data rates is desirable.
The problems noted above are addressed in large part by methods and systems for transmitting and receiving a discrete multi-tone (DMT) modulated signal in a fluid. Some illustrative embodiments may be a method comprising transforming an input data series into an information-carrying signal (the information-carrying signal carrying input data from the input data series as modulations of at least one of a plurality of evenly spaced frequency bins), and applying the information-carrying signal to a transducer that converts the information-carrying signal into pressure variations within a fluid.
Other illustrative embodiments may be a method comprising detecting pressure variations propagated through a fluid, converting detected pressure variations into an information-carrying signal, and extracting an output data series from the information-carrying signal (the information-carrying signal carrying output data from the output data series as modulations of at least one of a plurality of evenly spaced frequency bins).
Yet further illustrative embodiments may be a telemetry system comprising a downhole tool comprising a sensor that generates downhole data, a subsurface telemetry transmitter coupled to the downhole tool (the subsurface telemetry transmitter generates a first pressure-modulated signal in a fluid that comprises a plurality of evenly spaced frequency bins), and a surface telemetry receiver that detects the first pressure-modulated signal and regenerates the downhole data collected by the downhole tool. The downhole data modulates at least one of the plurality of evenly spaced frequency bins.
Yet further illustrative embodiments may be a subsurface telemetry transmitter comprising a fluid modulation valve, and servo control logic coupled to the fluid modulation valve (the servo control logic causes the fluid modulation valve to generate discrete multi-tone (DMT) modulated pressure waves in a fluid). Collected subsurface data is used to modulate sub-channel carriers within a DMT modulated information-carrying signal. The information-carrying signal is used by the servo control logic to actuate the fluid modulation valve.
Yet further illustrative embodiments may be a subsurface telemetry transmitter comprising a fluid modulation valve, and servo control logic coupled to the fluid modulation valve (the servo control logic causes the fluid modulation valve to generate discrete multi-tone (DMT) modulated pressure waves in a fluid). Collected subsurface data modulates an information-carrying signal using DMT modulation. The information-carrying signal is used by the servo control logic to actuate the fluid modulation valve.
Yet further illustrative embodiments may be a surface telemetry receiver comprising a pressure sensor that generates an information-carrying signal, and sensor signal processing logic coupled to the pressure sensor. Variations in the information-carrying signal correspond to pressure variations in a fluid that are detected by the pressure sensor. The sensor signal processing logic demodulates the information-carrying signal using discrete multi-tone (DMT) demodulation and recovers subsurface data encoded in the information-carrying signal.
Yet further illustrative embodiments may be a bottom hole assembly comprising a downhole tool comprising a downhole sensor that generates downhole data, and a mud modulator coupled to the downhole tool and configured to couple to a drillstring. The mud modulator generates a discrete multi-tone (DMT) modulated pressure signal propagated in drilling fluid within the drillstring (the DMT modulated pressure signal comprising the downhole data).
For a detailed description of embodiments of the invention, reference will now be made to the accompanying drawings in which:
Certain terms are used throughout the following discussion and claims to refer to particular system components. This document does not intend to distinguish between components that differ in name but not function.
In the following discussion and in the claims, the terms “including” and “comprising” are used in an open-ended fashion, and thus should be interpreted to mean “including but not limited to . . . ” Also, the term “couple” or “couples” is intended to mean either an indirect or direct connection. Thus, if a first device couples to a second device, that connection may be through a direct connection, or through an indirect connection via other devices and connections. The term “system” refers to a collection of two or more parts and may be used to refer to a telemetry system or a portion of a telemetry system. The term “software” includes any executable code capable of running on a processor, regardless of the media used to store the software. Thus, code stored in non-volatile memory, and sometimes referred to as “embedded firmware,” is included within the definition of software.
The term “fluid” is intended to mean all fluid mediums, including liquids and gases. The terms “upstream” and “downstream” refer, in the context of this disclosure, to the transmission of information from subsurface equipment to surface equipment, and from surface equipment to subsurface equipment, respectively. The terms “surface,” “subsurface” and “downhole” are relative terms. The fact that a particular piece of hardware is described as being on the surface does not necessarily mean it must be physically above the surface of the Earth; but rather, describes only the relative placement of the surface, subsurface and downhole pieces of equipment.
The term “noise,” as used in this disclosure, is meant to indicate a signal that is largely unrelated to the desired information and interferes with the reception or decoding of a signal comprising desired information. Thus, even though an interfering signal may not be random or spurious in nature, and may in fact contain coherent information, the interfering signal is considered noise if the signal is not the desired signal or information, and it interferes with the desired signal or with decoding of the desired information.
Turning now to the figures,
Drilling fluid, sometimes termed mud, is pumped by mud recirculation equipment 16 through supply pipe 18, through standpipe 9, through drilling kelly 10, and down through the drillstring 8 at high pressures and volumes (e.g., 3000 p.s.i. at flow rates of up to 1400 gallons per minute) to emerge through nozzles or jets in the drill bit 14. The drilling fluid then travels back up the hole via the annulus formed between the exterior of the drillstring 8 and the borehole wall 20, through the blowout preventer 22, and into a mud pit 24 on the surface. On the surface, the drilling fluid is cleaned and then recirculated by recirculation equipment 16. The drilling fluid is used to cool the drill bit 14, to carry cuttings from the base of the bore to the surface, and to balance the hydrostatic pressure in the rock formations. The drilling fluid within the drillstring may also be used as a medium for transmitting telemetry from downhole to the surface.
Downhole tool 26 couples to a telemetry transmitter 300 that transmits telemetry (e.g., information-carrying) signals in the form of pressure variations within the fluid flowing through the inside of the drillstring 8. A telemetry receiver 400 is coupled to the standpipe 9 and receives transmitted telemetry signals.
The modulator servo control logic 340 generates actuation signal 369, used to actuate the fluid modulator 370 and generate the discrete multi-tone signal propagated up the drillstring 8 through the drilling fluid. The actuation signal 369 is generated based on the transmitter DMT signal 338, and adjusted based on a feedback signal provided by the fluid modulator 370 (e.g., pressure signal 371 and position signal 373). The feedback signal allows the fluid modulator 370 to be controlled using a closed-loop control configuration. This improves the overall response of the fluid modulator 370 (as compared to an open-loop control configuration), increasing the speed at which the fluid modulator 370 may be operated, and decreasing the degree of variation in the magnitude of the pressure pulse induced by the fluid modulator 370, given a particular level of the actuation signal 369. In alternative embodiments where the fluid modulator 370 has substantially linear control characteristics, open-loop control may be used.
As already noted, transmitter DMT signal 338 comprises a plurality of individual modulated carriers, each of which may be modulated using a variety of modulation techniques (e.g., 2-bit quadrature phase-shift keying modulation, 4-bit quadrature amplitude modulation, and 6-bit quadrature amplitude modulation). The modulation technique used with a particular carrier may depend on the type and amount of noise at or near the frequency of the carrier. These modulated carriers are distributed over the available bandwidth as shown in
As illustrated, more than one band may be defined, each comprising one or more frequency bins 337. Multiple bands (e.g. bands 334 and 336) may be defined to avoid frequencies where noise is present (e.g., noise 335) or in order to support full duplex communications. Where full duplex communication is implemented, one or more bands may be dedicated to downstream communications (e.g., band 334), while other bands may be dedicated to upstream communications (e.g., band 336). Full duplex communications may be achieved through the use of discrete multi-tone fluid modulation transmitters and receivers both downhole and at the surface, allowing simultaneous transmission and reception of telemetry both upstream and downstream. Although the embodiments described in the present disclosure illustrate only upstream transmission and reception of telemetry so as not to unduly complicate the disclosure, it is intended that both upstream and downstream telemetry transmission and reception be encompassed by the present disclosure.
Error correction encoder 314 couples to tone mapper 316, which takes bits from the data stream generated by error correction encoder 314 and assigns them to frequency bins, sometimes referred to as sub-channels. For each frequency bin, the bits are used to determine a Discrete Fourier Transform coefficient that specifies a frequency amplitude. The number of bits assigned to each frequency bin by the tone mapper 316 may vary (i.e., the number may be different for each bin, and the number for each bin may change over time), and the number may depend on the estimated error rate for each frequency bin.
Tone mapper 316 couples to IFDT block 318, with the tone mapper 316 providing the coefficients that are processed by IFDT block 318. The IFDT block 318 generates a time-domain signal carrying the desired information at each frequency. IFDT block 318 couples to cyclic prefix block 320, and the cyclic prefix block 320 duplicates the end portion of the time-domain signal generated by IFDT block 318 and prepends it to the beginning of the time-domain signal. This permits later frequency domain equalization of the signal at the telemetry receiver 400 (as described below). Cyclic prefix block 320 couples to DAC/filters/driver block 322, which transforms the signal-with-prefix generated by cyclic prefix block 320 into analog form, and then filters and amplifies the analog signal, producing transmitter discrete multi-tone signal 338. The DMT modulator 310 may be implemented in software, hardware, or a combination of the two, and the present disclosure is intended to encompass all such embodiments.
The fluid modulator 370 also comprises several sensors capable of generating signals that may be used by a closed-loop control circuit such as modulator servo control logic 340 (not shown in
Continuing to refer to
In yet other embodiments, the moveable member 376 may be manufactured using a magnetostrictive material. The actuation signal 369 is applied as a magnetic field (e.g., using an induction coil) that causes the moveable member to expand or contract and correspondingly vary the pressure differential across the orifice 374. In yet other embodiments, the moveable member 376 may be manufactured using a piezoelectric material. The moveable member 376 may be made to expand or contract by the application of an electric field to the moveable member 376, again causing differential pressure variations across the orifice 374 that are proportional to the applied actuation signal 369. The degree of expansion or contraction of the various embodiments of the moveable member 376 described may be measured by position sensor 380.
The discrete multi-tone modulated pressure variations generated by the fluid modulator 370 are propagated up the drillstring 8 against the direction of drilling fluid flow, and eventually reach the telemetry receiver 400.
Referring again to
Filters/ADC/TDEQ block 442 couples to strip cyclic prefix block 444, which processes the output signal generated by the Filters/ADC/TDEQ block 44, removing the cyclic prefixes that were added by the downhole cyclic prefix block 320 (though trailing intersymbol interference from the cyclic prefix remains in the output signal). Cyclic prefix block 444 couples to DFT block 446, which performs a Discrete Fourier Transform on the output signal from cyclic prefix block 444 to obtain the frequency coefficients. DFT block 446 couples to FDEQ block 448, which may then perform frequency-domain equalization on the output signal from DFT block 446 to compensate for the remaining intersymbol interference. It is noted that frequency-domain equalization on DFT coefficients is a cyclic convolution operation that would lead to incorrect results had the cyclic prefix not been transmitted.
FDEQ block 448 couples to constellation decode 450, which operates on the output signal of FDEQ block 448 to extract the data bits from the frequency coefficients using an inverse mapping of the downhole tone mapper 316. Constellation decode 450 couples to error correction decode 452, which decodes the data stream from constellation decode 450 and corrects such errors as are within its correcting ability. Error correction decode 452 couples to CRC/data de-framer 454, which identifies and removes synchronization information from the output signal of error correction decode 452, determining if the cyclic redundancy code indicates the presence of any errors. If error free, the recovered downhole data represented by receiver data signal 441 is ready to be processed and analyzed. Otherwise the recovered downhole data may be flagged as suspect and additional error processing may be performed by a system (not shown) coupled to telemetry receiver 400 by receiver data signal 441. The DMT demodulator 440 may be implemented in software, hardware, or a combination of the two, and the present disclosure is intended to encompass all such embodiments.
Telemetry transmissions from the telemetry transmitter 300 may comprise data sent as it is collected (“continuous” or “real-time” data), data stored and transmitted after a delay (“buffered” or “historical” data), or a combination of both. LWD data collected during actual drilling may be collected at a relatively high resolution (e.g., one sample for every six inches of penetration), and saved locally in memory (e.g., within the bottom hole assembly 28). This high-resolution data may be needed in order to perform a meaningful analysis of the downhole formations. But because of the limited bandwidth of downhole telemetry systems, the data may have to be transmitted at a much lower resolution (e.g., one sample every four feet). In at least some embodiments the data may be saved at a higher resolution as described above, and transmitted to the surface at a later time when the tool is still downhole, but while drilling is not taking place (e.g., when a tool gets stuck or when the hole is being conditioned). This historical transmission may be at a sample resolution higher than the resolution used for real-time data transmission.
When drilling is not taking place, there may be little or no real-time data being transmitted. During this time selected portions of saved data may be transmitted or retransmitted to the surface. Since this is not real-time data, the only time restriction on the transmission is the time available before drilling and real-time data transmission resume. Thus, for example, a selected, one-hour window of data saved in memory and collected at a resolution of one sample every six inches may be transmitted to the surface, even though it may take multiple hours to transmit the data.
The data may be transmitted in chronological or reverse chronological order, and may be transmitted at any resolution desired. For example, all the data may be transmitted for maximum resolution, or every other sample may be transmitted for better but not maximum resolution. The resolution selected represents a trade-off between the time available to retrieve the saved data and the resolution needed to properly analyze the data. Also, any start and stop point may be selected within the memory where the data is saved (each location in memory correlating to a measured parameter sampled at a specific drilling time and depth).
The bottom hole assembly 28 may receive commands transmitted from the surface. These commands may control the suspension of real-time data collection and/or transmission, the selection of saved data, the selection of the desired resolution of data transmission, the initiation of saved data transmission, the suspension of saved data transmission, and the resumption of real-time data collection and/or transmission.
The above disclosure is meant to be illustrative of the principles and various embodiments of the present invention. Numerous variations and modifications will become apparent to those skilled in the art once the above disclosure is fully appreciated. It is intended that the following claims be interpreted to embrace all such variations and modifications.
