Abstract:
A downhole telemetry system that transmits a burst-QAM uplink signal to the surface of the well is disclosed. In a preferred embodiment, a downhole instrument coupled to a pair of conductors in a wireline or composite tubing string transmits a burst-QAM uplink signal to a surface system. The burst-QAM signal preferably comprises a series of data frames carrying telemetry data. Each data frame is preferably preceded by a quiet interval (when no signal is present), a timing synchronization sequence, and a training sequence. The timing synchronization sequence is designed for easy timing recovery at the surface, and the training sequence is designed to aid the adaptation of the equalizer. The data frame itself preferably includes a synchronization field, a data count, and a checksum in addition to the data. Direct digital synthesis is preferably employed to modulate the uplink signal.

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS  
       [0001]    The present application is a continuation-in-part of U.S. patent application Ser. No. 09/599,343, filed Jun. 22, 2000, and entitled “Burst QAM Downhole Telemetry System” by inventors Michael Wei and William Trainor. 
     
    
     
       BACKGROUND OF THE INVENTION  
         [0002]    1. Field of the Invention  
           [0003]    The present invention relates to a telemetry system for transmitting data from a downhole drilling assembly to the surface of a well. More particularly, the present invention relates to a system and method for signaling over information conduits coupled between a downhole transmitter and an uphole receiver.  
           [0004]    2. Description of the Related Art  
           [0005]    Modem 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, which commonly is referred to as “logging”, can be performed by several methods.  
           [0006]    In conventional oil well wireline logging, a probe or “sonde” housing formation sensors is lowered into the borehole after some or all of the well has been drilled, and is used to determine certain characteristics of the formations traversed by the borehole. The upper end of the sonde is attached to a conductive wireline that suspends the sonde in the borehole. Power is transmitted to the sensors and instrumentation in the sonde through the conductive wireline. Similarly, the instrumentation in the sonde communicates information to the surface by electrical signals transmitted through the wireline.  
           [0007]    The problem with obtaining downhole measurements via wireline is that the drilling assembly must be removed or “tripped” from the drilled borehole before the desired borehole information can be obtained. This can be both time-consuming and extremely costly, especially in situations where a substantial portion of the well has been drilled. In this situation, thousands of feet of tubing may need to be removed and stacked on the platform (if offshore). Typically, drilling rigs are rented by the day at a substantial cost. Consequently, the cost of drilling a well is directly proportional to the time required to complete the drilling process. Removing thousands of feet of tubing to insert a wireline logging tool can be an expensive proposition.  
           [0008]    As a result, there has been an increased emphasis on the collection of data during the drilling process. Collecting and processing data during the drilling process eliminates the necessity of removing or tripping the drilling assembly to insert a wireline logging tool. It consequently 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 the purposes of this disclosure, the term MWD 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.  
           [0009]    When oil wells or other boreholes are being drilled, it is frequently necessary or desirable to determine the direction and inclination of the drill bit and downhole motor so that the assembly can be steered in the correct direction. Additionally, information may be required concerning the nature of the strata being drilled, such as the formation&#39;s resistivity, porosity, density and its measure of gamma radiation. It is also frequently desirable to know other downhole parameters, such as the temperature and the pressure at the base of the borehole, for example. Once this data is gathered at the bottom of the borehole, it is typically transmitted to the surface for use and analysis by the driller.  
           [0010]    Sensors or transducers typically are located at the lower end of the drill string in LVVD systems. While drilling is in progress these sensors continuously or intermittently monitor predetermined drilling parameters and formation data and transmit the information to a surface detector by some form of telemetry. Typically, the downhole sensors employed in MWD applications are positioned in a cylindrical drill collar that is positioned close to the drill bit. The MWD system then employs a system of telemetry in which the data acquired by the sensors is transmitted to a receiver located on the surface. There are a number of telemetry systems in the prior art which seek to transmit information regarding downhole parameters up to the surface without requiring the use of a wireline cable. Of these, the mud pulse system is one of the most widely used telemetry systems for MWD applications.  
           [0011]    The mud pulse system of telemetry creates “acoustic” pressure signals in the drilling fluid that is circulated under pressure through the drill string during drilling operations. The information that is acquired by the downhole sensors is transmitted by suitably timing the formation of pressure pulses in the mud stream. The information is received and decoded by a pressure transducer and computer at the surface.  
           [0012]    In a mud pressure pulse system, the drilling mud pressure in the drill string is modulated by means of a valve and control mechanism, generally termed a pulser or mud pulser. The pulser is usually mounted in a specially adapted drill collar positioned above the drill bit. The generated pressure pulse travels up the mud column inside the drill string at the velocity of sound in the mud. Depending on the type of drilling fluid used, the velocity may vary between approximately 3000 and 5000 feet per second. The rate of transmission of data, however, is relatively slow due to pulse spreading, distortion, attenuation, modulation rate limitations, and other disruptive forces, such as the ambient noise in the drill string. A typical pulse rate is on the order of a pulse per second (1 Hz).  
           [0013]    Given the recent developments in sensing and steering technologies available to the driller, the amount of data that can be conveyed to the surface in a timely manner at 1 bit per second is sorely inadequate. As one method for increasing the rate of transmission of data, it has been proposed to transmit the data using vibrations in the tubing wall of the drill string rather than depending on pressure pulses in the drilling fluid. However, the presence of existing vibrations in the drill string due to the drilling process severely hinders the detection of signals transmitted in this manner.  
         SUMMARY OF THE INVENTION  
         [0014]    Accordingly, there is disclosed herein a downhole telemetry system that transmits a burst-QAM uplink signal to the surface of the well. In a preferred embodiment, a downhole instrument coupled to a pair of conductors transmits a burst-QAM uplink signal to a surface system similarly coupled to the pair of conductors. The burst-QAM signal preferably comprises a series of data frames carrying telemetry data. Each data frame is preferably preceded by a quiet interval (when no signal is present), a timing synchronization sequence, and a training sequence. The timing synchronization sequence is designed for easy timing recovery at the surface, and the training sequence is designed to aid the adaptation of the equalizer. The data frame itself preferably includes a synchronization field, a data count, and a checksum in addition to the data. Direct digital synthesis is preferably employed to modulate the uplink signal. 
       
    
    
     BRIEF DESCRIPTION OF THE DRAWINGS  
       [0015]    A better understanding of the present invention can be obtained when the following detailed description of the preferred embodiment is considered in conjunction with the following drawings, in which:  
         [0016]    [0016]FIG. 1 is a schematic view of an oil well in which the telemetry system may be employed;  
         [0017]    [0017]FIG. 2A is an isometric schematic of a composite tubing section having helically wound information conduits contained within;  
         [0018]    [0018]FIG. 2B is an isometric view of a tubing section having a wireline cable contained within;  
         [0019]    [0019]FIG. 3 is a schematic of the circuits that couple the telemetry signals to the tubing;  
         [0020]    [0020]FIG. 4 is a functional block diagram of a surface computer system;  
         [0021]    [0021]FIG. 5 is a functional block diagram of a downhole communications module in the supervisory sub;  
         [0022]    [0022]FIG. 6 is an exemplary implementation of an uplink telemetry data frame;  
         [0023]    [0023]FIG. 7 is a functional block diagram of an uplink telemetry transmitter;  
         [0024]    [0024]FIG. 8 is a functional block diagram of an uplink telemetry receiver;  
         [0025]    [0025]FIG. 9 is a schematic view of a wireline system in which the telemetry system may be employed;  
         [0026]    [0026]FIG. 10 shows a cross-section of a seven-conductor wireline cable; and  
         [0027]    [0027]FIG. 11 shows a cross-section of a single-conductor wireline cable. 
     
    
       [0028]    While the invention is susceptible to various modifications and alternative forms, specific embodiments thereof are shown by way of example in the drawings and will herein be described in detail. It should be understood, however, that the drawings and detailed description thereto are not intended to limit the invention to the particular form disclosed, but on the contrary, the intention is to cover all modifications, equivalents and alternatives falling within the spirit and scope of the present invention as defined by the appended claims.  
       DETAILED DESCRIPTION OF PREFERRED EMBODIMENTS  
       [0029]    Turning now to the figures, FIG. 9 shows a well during wireline logging operations. A drilling platform  902  is equipped with a derrick  904  that supports a hoist  906 . Drilling of oil and gas wells is commonly carried out by a string of drill pipes connected together by “tool” joints so as to form a drilling string that is lowered through a rotary table  912  into a wellbore  914 . In FIG. 9, the drilling string has been temporarily removed from the wellbore  914  to allow a sonde  916  to be lowered by wireline  908  into the wellbore  914 . Typically, the sonde  916  is lowered to the bottom of the region of interest and subsequently pulled upward at a constant speed. During the upward trip, the sonde  916  performs measurements on the formations  919  adjacent to the wellbore as they pass by. The measurement data is communicated to a logging facility  920  for storage, processing, and analysis. In an alternative situation (e.g. a highly deviated or horizontal well), a threaded or continuous tubing string may be employed to convey the sonde through the hole. In this circumstance the wireline may be run through the interior of the tubing string or attached to the exterior of the tubing string.  
         [0030]    [0030]FIG. 10 shows a cross-section of a typical wireline cable having multiple conductors  1002 . Each of the conductors is surrounded by an insulating jacket  1004 . The insulated conductors may be bundled together in a poorly-conductive wrap  1005 , which is surrounded by two layers of counterwound metal armor wire  1006 . Being made of metal, the armor wires are conductive and may be used as an eighth conductor. In wireline logging of cased and cemented wells, a single conductor logging cable such as that shown in FIG. 11 may be preferred. The single conductor cable typically has a single, multi-stranded conductor  1102  encased in insulative material  1104  and wound within a fabric liner  1106  which is in turn wound within a double layer of counter wound metal armor wires  1108 . Power and telemetry are typically conveyed together on a single cable. In single conductor cables, the power is generally transmitted as a low frequency signal, whereas the telemetry signal(s) are transmitted in a higher frequency band. In multi-conductor cables, the signal isolation is further improved by the use of orthogonal transmission modes. Orthogonal modes and the circuitry therefor are discussed in much greater detail in co-pending application Ser. No. 09/437,594, entitled “High-Power Well Logging Method And Apparatus” by inventors G. Baird, C. Dodge, T. Henderson and F. Velasquez, which is hereby incorporated herein by reference.  
         [0031]    Accordingly, there are at least two methods for establishing a communications channel for downhole communications. One of several orthogonal transmission modes may be used to carry the telemetry signal on a multiconductor cable, or a single conductor cable may be used to carry the telemetry signal in the normal fashion. FIG. 1 shows a third method that employs conductors embedded in the walls of composite tubing.  
         [0032]    [0032]FIG. 1 shows a well having a spool  102  of composite or steel tubing  104  being injected into a wellbore by an injector  106 . The tubing  104  is injected through a packer  108  and a blowout preventer  110 , and passes through casing  112  into the wellbore. In the well, a downhole instrument  114  may be coupled to the composite tubing  104  and configured to communicate to a surface computer system  116  via information conduits embedded contained in the composite tubing  104 . Alternatively for steel tubing  104 , the downhole instrument may be configured to communicate to the surface computer system  116  via a wireline cable contained in the interior of the tubing  104 . A power supply  118  may be provided to supply power to downhole instrument  114  via power conduits in composite tubing  104  or wireline cable.  
         [0033]    Surface computer system  116  is configured to communicate with downhole instrument  114 . Downhole instrument  114  may, for example, be a supervisory sub for a bottom-hole drilling assembly. The sub may be coupled to downhole sensors and/or control devices configurable to measure and set, respectively, downhole parameters. Examples of sensors include temperature, pressure, density, and flow-rate sensors. Examples of control devices include valves, variable-aperture ports, heaters, and artificial lift devices.  
         [0034]    Surface computer system  116  is preferably configured by software  120  to monitor and control downhole instrument  114 . System  116  may include a display device- 122  and a user-input device  124  to allow a human operator to interact with the system control software  120 .  
         [0035]    An isometric representation of composite tubing  104  is shown in FIG. 2A. As the name suggests, composite tubing  104  is a tube having walls  202  made primarily of a composite material such as, e.g. fiberglass or carbon fiber, although other suitable materials are known and contemplated. Conduits  204  may be embedded in the walls of composite tubing. To reduce the probability of conduit breakage, the conduits are preferably wound helically around the tubing bore within the walls of the composite tubing. The winding angle is preferably a function of the stress coefficient differential between the conduit material and the composite material.  
         [0036]    In a preferred embodiment, the conduits  204  contained in the composite tubing are electrical conductors, although one or more of the conduits may alternatively be optical fibers or hydraulic conduits. Preferably, six circumferentially-spaced conductors are provided, with two adjacent conductors dedicated to carrying telemetry signals. The electrical conductors for carrying telemetry in the wireline cable may similarly be replaced with telemetry conduits of different form, such as, for example, optical fibers or hydraulic conduits.  
         [0037]    An isometric view of steel tubing  104  is shown in FIG. 2B. In this instance, a wireline cable is shown extending through the interior of the tubing. This reduces the possibility of conduit breakage from abrasion or “pinching” of the cable in the wellbore. The information conduits may be electrical or optical conductors.  
         [0038]    [0038]FIG. 3 shows one circuit configuration which allows the uplink telemetry signal to share electrical conductors with the downlink telemetry signal. In the downhole portion of the coupling circuit configuration, an isolation transformer  302  preferably couples the telemetry signal conductors of the wireline or tubing to the downhole instrument. A center-tapped secondary winding has one terminal end coupled to a high pass filter (HPF)  304  via a transmit resistance R T , and the other terminal end coupled to a low pass filter (LPF)  306  with a shunt resistance R R  to ground. The center tap is coupled to ground via an impedance block  308  for impedance matching purposes.  
         [0039]    HPF  304  blocks signals below the uplink signal cutoff frequency, thereby preventing any uplink signal energy from interfering with the downlink signal. The uplink signal energy is screened off from the downlink signal by LPF  306 , which blocks any signal energy above the cutoff frequency of the downlink signal.  
         [0040]    It is noted that the energy of the uplink and downlink signals is expected to be comparable downhole. This is not the case at the surface, where the downlink signal energy is expected to be substantially greater than the uplink signal energy. To prevent the downlink signal from overwhelming the uplink signal detectors, a bridge arrangement is used in the uphole portion of the coupling circuit configuration.  
         [0041]    The surface portion of the coupling circuit configuration preferably uses an isolation transformer  310  to couple to the telemetry signal conductors of the wireline or tubing. One terminal of the secondary winding is coupled to ground, while the other terminal is coupled to a transmit signal node  312  via a resistance R. A matching impedance  314  also has one terminal coupled to ground and the other terminal coupled to node  312  via a second, identical resistance R. The downlink signal is provided to node  312  via a low pass filter  316  and a power amplifier  318 . The downlink signal voltage on node  312  causes similar currents to flow in the two branches, with a small difference caused by the uplink signal. This uplink signal difference can be detected in the form of a voltage difference between the intermediate nodes of the branches. A differential amplifier  320  amplifies this difference and provides it to a high pass filter  322  for filtering. The discrimination of the high pass filter  322  in filtering out the downlink signal is aided by the common mode rejection of the differential amplifier.  
         [0042]    Although a specific coupling circuit configuration has been described, it is recognized that other coupling techniques may be used. Other suitable “4-wire to 2-wire” coupling configurations are known in the art and may be used. Alternatively, the uplink and downlink signals may be carried on separate sets of conductors, or may be transformed into optical signals or pressure signals for other conduit types.  
         [0043]    [0043]FIG. 4 shows one embodiment of surface computer system  116  (which may be contained in surface facility  920 ). System  116  includes a central processing unit  402  coupled to a system memory  404  via a bridge  406 . System memory  404  stores software  408  for execution by processor  402 . Bridge  406  also couples processor  402  to a peripheral bus  410 . Peripheral bus  410  supports the transfer of data to and from the processor  402 . Peripheral devices connected to peripheral bus  410  can thereby provide the processor  402  with access to the outside world. In the shown embodiment, a signal conditioning board  412  and a digital decoder board  414  are coupled to the peripheral bus  410 .  
         [0044]    Signal conditioning board  412  is also coupled to the telemetry conduits. Downlink data that the processor  402  wishes to send to the downhole instrument  114  is provided to bus interface logic  422  of the signal conditioning board  412 . The interface logic  422  handles compliance with the bus protocol and extracts the downlink data from the bus signals to be provided to frequency-shift key (FSK) modulator  424 . FSK modulator  424  converts the data into an analog downlink signal which is then provided to LPF  316  to screen out any high frequency components. Isolation transformer  310  puts the downlink signal onto the telemetry conduits and extracts the uplink signal, passing it to HPF  322  which screens out any low frequency components. The uplink signal is amplified by amplifier  432  and provided to an analog-to-digital converter (ADC)  442  on digital decoder card  414 .  
         [0045]    ADC  442  preferably provides the digitized signal to a digital signal processor (DSP)  444  for filtering and decoding. DSP  444  is configured by software to perform bandpass or matched filtering  446  and equalization and timing recovery  448  to extract the uplink data symbols. The data symbols are decoded  450  and the decoded uplink data is provided to processor  402  for analysis. Details of the uplink telemetry signal format and decoding will be discussed further below.  
         [0046]    [0046]FIG. 5 shows one embodiment of the downhole instrument telemetry module. A DSP  502  is configured by software to format and encode  504  uplink data for transmission to the surface. The encoded digital data is preferably modulated in quadrature amplitude modulation (QAM) form by a direct digital synthesis (DDS) chip  506  to provide an analog uplink signal. The analog uplink signal is high pass filtered  304  and provided to isolation transformer  302 . Isolation transformer couples the uplink signal to the telemetry conduits and couples the downlink signal from the telemetry conduits to low pass filter  306 . LPF  306  screens out the signal energy above the cutoff frequency, and a demodulator  508  converts the downlink signal into digital baseband form for decoding by DSP  502 .  
         [0047]    In a preferred embodiment, the downlink signal is a FSK modulated signal using the 2.4-9.6 kHz frequency band. This signal is preferably used to transmit commands and configuration parameters to the downhole instrument. The uplink signal is preferably a burst-QAM modulated signal using the 16-48 kHz frequency band. This signal is preferably used to transmit measurement data to the surface.  
         [0048]    The DSP may optionally be a chip from the ADSP-2100 Family of DSP Microcomputers manufactured and sold by Analog Devices, a company doing business in Norwood, Mass. The DDS chip may optionally be an AD7008 CMOS DDS Modulator manufactured and sold by the same company.  
         [0049]    It is noted that the uplink link preferably employs burst-QAM to achieve increased channel capacity without a commensurate increase in receiver complexity. In one embodiment, the burst-QAM communication is done in the form of uplink data frames  602 , each frame being preceded by a quiet interval  604  and a timing synchronization sequence  606 , as shown in FIG. 6. An equalization training sequence  608  may also be provided immediately before the data frame  602 . It is contemplated that the uplink communication be done in terms of 16-bit words, each of which are transmitted as four 4-bit (16-QAM) symbols. The quiet interval  604  is contemplated to be 30 words (120 symbol periods), the timing sequence  606  is contemplated to be 20 words (80 symbols), the training sequence  608  to be 126 words (504 symbols), and the frame  602  to be a maximum of 1024 words (4096 symbols). It is recognized, however, that other configurations may also be suitable. For example, other word lengths may be employed, and the QAM constellation may be made larger (e.g. 32, 64, 128, 256, 512, 1024, or more constellation points), or smaller (i.e. 2, 4, or 8 constellation points).  
         [0050]    Data frame  602  preferably begins with two synchronization words, a data count word, up to 1020 words of data, and ends with a checksum word. The data count word preferably indicates the number of data words. The number of data words per frame may be adjusted according to system requirements and according to a desired rate of recurrence of the resynchronization and re-training sequences. For example, if the number of data words per frame is 1020 in the above described embodiment, the timing resynchronization and retraining will occur over 10 times per second. However, in some conditions it may be desired to increase the resynchronization frequency to over 20 times per second. This may be achieved by reducing the number of data words per frame to about 512. Alternatively, the number of bits per QAM symbol may be increased to reduce the number of symbols per frame.  
         [0051]    [0051]FIG. 7 shows, in functional block form, the uplink signal transmit path  700 . In block  702  the data frame  602  is “scrambled” by bit-by-bit XOR-ing it with a pseudorandom sequence. The pseudorandom sequence is an easily reproduced mask which “randomizes” the data frame to remove predictable, periodic patterns that often occur in measurement data. Such patterns, if not removed, may cause undesirable spectral lines that interfere with adaptive equalization in the receiver.  
         [0052]    The scrambled data is then, in block  704 , divided into symbols that are mapped to signal points in the QAM constellation. In block  706 , the symbols are modulated onto a carrier frequency, filtered and amplified in block  710 , and coupled to the telemetry conduits. A preamble generator block  708  is shown parallel to the data path. Preamble generator  708  generates the quiet period  604 , timing synchronization sequence  606 , and training sequence  608 , and inserts them into the transmit signal ahead of each data frame. Referring momentarily to FIG. 5, blocks  702  and  704  may be part of encoder software  504 , blocks  706  and  708  may be implemented by the DDS chip  506 , and block  710  may be implemented by HPF  304 .  
         [0053]    [0053]FIG. 8 shows, in functional block form, the uplink signal receive path  800 . In block  802 , the signal received from the telemetry conduits is filtered to screen out signal energy below the uplink signal cutoff frequency. The uplink signal is then digitized in block  804 , and match-filtered in block  806  to maximize the signal-to-noise ratio. In block  808 , a timing recovery algorithm operates to lock the receiver timing to the timing synchronization sequence. In block  810 , the uplink signal is equalized to correct for channel effects. During the equalization of the training sequence, knowledge of the training sequence is used to adapt the equalizer to the telemetry channel. The equalizer consequently exhibits improved equalization performance on the data frame. The equalizer output is a sequence of QAM symbols. In block  812 , the symbol sequence is converted to a 16-bit word sequence, with proper alignment achieved from knowledge of the training sequence. Block  814  blocks the extraneous words from the quiet interval, the timing sequence, and the training sequence, and passes on only the data frame. In block  816 , the scrambling operation is reversed, the check sum verified, and the data count, along with the data words, provided as output. Referring momentarily to FIG. 4, block  802  corresponds to block  322 , block  804  to block  442 , block  806  to block  446 , blocks  808  and  810  to block  448 , and blocks  812 - 816  to block  450 .  
         [0054]    The exemplary embodiments described above provide for telemetry through conduits in wireline and composite tubing. In the case of electrical conductors in composite tubing, the telemetry channel is expected to have a range of up to 50,000 ft with an attenuation of 40-45 dB in the frequency ranges under consideration. The framing structure employed in burst-QAM signaling is expected to provide regularly recurring opportunities for timing resynchronization and equalizer retraining. This is expected to significantly improve the reliability of the uplink channel.  
         [0055]    It is noted that the telemetry system disclosed herein may have multiple applications, including, for example, smart wells. Smart wells are production wells that may have sensors and controllable mechanisms downhole. The sensors may, for example, be used to detect density and flow rates. An uphole system may use this information to operate the controllable mechanisms (e.g. variable aperture ports and heaters or other artificial lift mechanisms) to optimize the production of the well.  
         [0056]    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.