NO338841B1 - Identification of channel frequency response using pulse compression and incremental frequencies - Google Patents

Description

BACKGROUND OF THE INVENTION

Field of the invention

[0001] The present invention relates to telemetry systems for communicating information from a place down in a well to a place on the surface, and more specifically a method for determining channel properties in a mechanical telemetry system such as a mud pulse-based telemetry system. By "mechanical" here is meant telemetry that is controlled by or according to the principles of mechanics, including acoustic and fluid-mechanical.

Description of Related Art

[0002] US 5,055,837 deals with the analysis and identification of a drilling fluid column based on the decoding of measurement-during-drilling signals. Drilling fluid-based telemetry systems, generally referred to as mud pulse systems, are particularly suitable for telemetry of information from the bottom of a borehole to the ground surface during the drilling of oil wells. The information that is transmitted often includes, but is not limited to, parameters such as pressure, temperature, direction and deviation for the well drilling. Other parameters include log data, such as the resistivity of the different layers, acoustic density, porosity, induction, self-potential and pressure gradients. This information is of crucial importance for the efficiency of the drilling operation.

[0003] MWD telemetry is necessary for communication between the MWD components in the well and the MWD components on the surface in real time, and to handle most drilling-related operations without delays. The system to support this is relatively advanced, with downhole and surface components working synchronously.

[0004] In any telemetry system there is a transmitter and a receiver. In MWD telemetry, different transmitter and receiver technologies are often used for downlinking and uplinking of information. When uplinking, the transmitter is often called the mud pulsator (or just the pulsator), and is an MWD tool in the downhole unit capable of creating pressure fluctuations in the mud flow. The receiver system on the surface consists of sensors that measure the pressure fluctuations and/or flow fluctuations, as well as signal processing modules that interpret these measurements.

[0005] Downlinking is done either by periodically varying the flow amount of mud in the system or by periodically varying the rotation speed of the drill string. In the first case, the flow rate is controlled using a diversion actuator and a control unit, and the signal is received by the MWD system down the well using a sensor that is affected by either flow or pressure. In the second case, the speed of rotation on the surface is controlled manually, and the signal is received through a sensor which is affected by this.

[0006] For uplink telemetry, a suitable pulsator is described in US 6,626,253 to Hahn et al., which is assigned to the same as this application and which is incorporated herein by reference in its entirety. Hahn describes in '253 an oscillating shear valve system for creating pressure fluctuations in a flowing drilling fluid which includes a fixed stator and an oscillating rotor, both with axial flow paths. The rotor oscillates close to the stator, and at least partially blocks the flow through the stator and generates oscillating pressure pulses. The rotor passes through two zero-speed positions during each cycle, which facilitates rapid changes in the signal's phase, frequency and/or amplitude, which in turn results in better data encoding.

[0007] US RE38,567 to Gruenhagen et al., which is assigned to the same as the present invention and which is hereby incorporated by reference in its entirety, and US 5,113,379 to Scherbatskoy, show methods for downlink telemetry where the flow rate is controlled by means of a diversion actuator and a control unit .

[0008] There are two groups of signals used when transmitting information: baseband and passband. Transmission of information in a sequence of pressure pulses is known as baseband signaling. If the pulses are further modulated by a carrier signal, which shifts the transmission bandwidth higher in frequency, it is known as passband signaling. The concrete examples shown in Gruenhagen are baseband signaling. Hahn in '253, on the other hand, also shows the use of passband signaling with different types of modulation techniques, such as FSK (Frequency Shift Keying), PSK

(Phase Shift Keying) and ASK (Amplitude Shift Keying). US patent application 10/223,169 to Hahn et al., which is assigned to the same as the present invention and which is incorporated herein by reference in its entirety, further shows the use of multi-value coding and chirp signals for uplink telemetry. It should be noted that passband signaling can also be used for downlink telemetry with the method of Gruenhagen. Scherbatksoy describes a system in which a narrowband signal is modulated using square pulses representing the data to be transmitted.

[0009] Baseband signaling is affected by rotational noise and the jerky movement of the drill string. By using passband signalling, we can move the signal away from this noise source. However, the bandwidth of the passband frequency is also not free from noise sources; for example, pump noise can be a major cause of signal distortion. If the noise is created by the pumps, however, we can quantify it independently and filter it out from the measurements. In short, by using passband signalling, we can control the frequency band used by the information signal, and can more easily cancel noise that can degrade this signal.

[0010] In passband filtering, one of the central problems is the choice of which frequencies the signal is to be transmitted over. The present invention solves this problem.

[0011] Another problem solved by this invention is not limited to borehole telemetry, and occurs when mechanical vibrator elements are used to generate frequency-varying signals. This problem is harmonic distortion, where the mechanical vibrator element generates one or more harmonics of the fundamental frequencies. The received signals are cross-correlated with the frequency-varying reference signal to obtain an impulse response for the channel. In the presence of harmonics, the processed signal can be heavily affected by harmonic distortion. A method for damping harmonic correlation noise caused by harmonic energy created by seismic vibrator elements has been developed by Reitsch, as described in US 4,042,910. The method comprises the step of generating several frequency-varying signals in sequence and with the phase of each successive signal shifted relative to the previous one by a predetermined phase angle, which is a proportion of 2B. The generated signals are individually recorded and transformed by inverse phase shift before being added or superimposed in a traditional way. Generating multiple signal passes (sweeps) is time-consuming, and the phase coding increases the system's complexity. The problem of harmonic distortion also occurs (but is not resolved) in US 2003/0151975 to Thomann et al. for SWD (Seismic-While-Drilling). The problem also occurs in well-to-well tomography where frequency-varying signal sources are used. The present invention solves the problem of harmonic distortion without the need for multiple signal passes or phase coding of the signals.

SUMMARY OF THE INVENTION

[0012] The main features of the invention appear from the independent claims. Further features of the invention are indicated in the independent claims. The present invention relates to a method for communicating signals in a well bore between a place on the surface and a place down in the well. A mechanical signal is generated at one of the locations on the surface and the location down the well. A signal representing the generated signal is received at the second of the surface location and the downhole location. A property of the communication channel between the location on the surface and the location down the well is determined from the received signal and the generated mechanical signal. The generated mechanical signal can be a change of a fluid flow and/or a pressure pulse. The received signal may comprise a measurement of a pressure and/or a fluid flow. In one embodiment of the invention, the generated mechanical signal can be a step frequency signal. Alternatively, a chirp reference signal can be used as the basis for the generated mechanical signal. The communication channel can be a mud flow path. The property being determined can be a transfer function. The transfer function can be determined by cross-correlating the received signal with the chirp reference signal, using the frequency spectrum of the received signal and using the frequency spectrum of the chirp reference signal. Once the property of the channel is determined, it can be used to select a frequency for communicating instructions from the location on the surface to the location down the well, and data from the location down the well to the location on the surface. The determination of the transfer function can be made based on signals transmitted during an interruption in drilling operations.

[0013] Another embodiment of the invention is a system for communicating signals in a well bore between a place on the surface and a place down in the well. The system comprises a mechanical source which generates a mechanical signal at one of the locations on the surface and the location down the well. A receiver at the second of the locations receives a signal representing the generated mechanical signal. A processor determines from the received signal and the generated mechanical signal a property of a communication channel between the location on the surface and the location down in the well. The mechanical source can be a pulsator with an oscillating shear valve. The mechanical signal generated by the source may be a change of a fluid flow and/or a pressure pulse. The receiver can be a hydrophone, a dual pressure transducer and/or a flow meter. The generated mechanical signal may be a stepped frequency signal or may be derived from a chirp signal. The communication channel can be a mud flow path. The characteristic of the communication channel that is determined may be a transfer function. The processor determines the property through at least one of cross-correlation of the received mechanical signal with the reference signal, determination of the frequency spectrum of the received signal, and determination of the frequency spectrum of the reference signal. Based on the found property, the processor selects a frequency for communication between the location on the surface and the location down the well. The processor may be located at the downhole location and the mechanical source may be part of a bottom hole assembly (BHA). The determination of the property can be done by generating the mechanical signal during an interruption in drilling operations.

[0014] Another embodiment of the invention is a computer-readable medium for use with a system for communicating signals between a location on the surface and a location down a well. The system comprises a mechanical source that generates a mechanical signal, and a receiver that receives a signal representing the generated signal. The medium includes instructions that enable a processor to estimate based on the received signal and the generated mechanical signal a property of the communication channel between the location on the surface and the location down the well. The computer-readable medium may be at least one of a ROM, an EPROM, an EAROM, a flash memory, and an optical disc storage.

[0015] Another embodiment of the invention is a method for determining a property of a communication channel linked to an earth formation. A signal with varying frequency is generated using a mechanical device and propagates along the channel. The propagating signal includes a harmonic distortion. The propagating signal is received and is affected by the property of the channel. The received signal is then processed to estimate the characteristic at the channel using a signal processing method comprising a chirp transform. The communication channel can be a borehole in the soil formation. The property can be the impulse response of the channel. The mechanical device can be located somewhere on the surface, in a body of water, in a borehole in the soil formation and/or on a downhole unit that is driven in a borehole in the soil formation. The chirp transformation may comprise correlation with the conjugate of the frequency-varying signal, a low-pass filtering and a correlation with the frequency-varying signal. The parameters of the low-pass filtering can be based on the chirp frequency of the frequency-varying signal and a maximum delay in the channel.

[0016] Another embodiment of the invention is a system for determining a property of a communication channel linked to an earth formation. The system comprises a mechanical device which generates a signal of varying frequency which propagates along the channel, and the propagating signal comprises a harmonic. A receiver generates a receiver signal that is affected by the characteristic of the channel. A processor estimates the characteristic of the channel from the received signal by applying chirp transformation in the processing. The communication channel can be a borehole in the soil formation. The property can be the impulse response of the channel. The mechanical device can be arranged somewhere on the surface, in a body of water, in a borehole in the soil formation and/or on a bottom hole unit which is guided in a borehole in the soil formation. The processor can apply the chirp transformation by further doing a correlation with the conjugate of the frequency-varying signal, a low-pass filtering and a correlation with the frequency-varying signal. The processor may select the chirp frequency for the low-pass filtering based on the chirp frequency of the frequency-varying signal and a maximum delay in the channel.

BRIEF DESCRIPTION OF THE FIGURES

[0017] For a detailed understanding of the present invention, reference is made to the following detailed description of the preferred embodiment, taken together with the attached figures, where like elements are given like reference numbers and where: Figure 1 (prior art) is a schematic illustration of a drilling system suitable for use with the present invention; Figures 2a-2c (prior art) are a schematic illustration of an oscillating shear valve suitable for use with the present invention; Figure 3 is an illustration of the channel transfer function; Figures 4a and 4b are representations of a chirp signal in the time and frequency domains respectively; Figures 5a and 5b illustrate some characteristics of a chirp signal; Figure 6 shows an example channel transfer function for a mud pulse telemetry system derived using a chirp signal; Figures 7a and 7b are representations of a stepwise frequency signal in the time and frequency domains, respectively; Figure 8 shows a channel transfer function derived using a stepped frequency signal; Figure 9 is a flow diagram illustrating the use of a method according to the present invention during drilling of a borehole; Figures 10a and 10b show respectively the real part of Cc/,/^(f,t?) in the time domain and its fourier-transformed (FFT); and Figure 11 is a flow diagram illustrating the method for determining channel transfer functions with chirp signals.

DETAILED DESCRIPTION OF THE INVENTION

[0018] Figure 1 shows a schematic diagram of a drilling system 10 with a drill string 20 carrying a drilling unit 90 (also referred to as a bottom hole unit or "BHA") which is guided in a "wellbore" or "borehole" 26 to drill the well drilling. The drilling system 10 comprises a traditional drilling tower 11 standing on a deck 12 which supports a rotary table 14 which is rotated by a main driving force such as an electric motor (not shown) at a desired rotational speed. The drill string 20 comprises a pipe such as a drill pipe 22 or a coiled pipe that goes from the surface into the borehole 26. The drill string 20 is pressed into the wellbore 26 when a drill pipe 22 is used as a pipe. When using coiled tubing, a tubing injector, such as an injector (not shown), is used to feed the tubing from a source, such as a drum (not shown), into the wellbore 26. The drill bit 50 attached to the end of the drill string breaks up the geological the formations when it is rotated to drill the borehole 26. If a drill pipe 22 is used, the drill string 20 is connected to a winch 30 via a rotation pipe 21, a swivel 28 and a cable 29 through a pulley 23. During drilling operations, the winch 30 is used to control the drill bit pressure, which is an important parameter for influencing the drilling speed. The operation of the winch is well known to the person skilled in the art, and is thus not described in detail here.

[0019] During drilling operations, a suitable drilling fluid 31 from a mud tank (source) 32 is circulated under pressure through a channel in the drill string 20 by a mud pump 34. The drilling fluid flows from the mud pump 34 into the drill string 20 via a "desurger" (not shown), a fluid channel 38 and the rotation tube 21. The drilling fluid 31 flows out in the bottom 51 of the borehole through an opening in the drill bit 50. The drilling fluid 31 circulates uphole through the annulus 27 between the drill string 20 and the borehole 26 and returns to the mud tank 32 via a return channel 35. The drilling fluid serves to lubricate the drill bit 50 and to move cuttings or drill chips away from the drill bit 50. A sensor S1, typically arranged in the channel 38, provides information about the fluid flow rate. A torque sensor S2 and a sensor S3 associated with the drill string 20 on the surface provide information respectively about the torque on and the rotation speed of the drill string. In addition, a sensor (not shown) connected to the channel 29 is used to measure the hook load on the drill string 20.

[0020] In one embodiment of the invention, the drill bit 50 is rotated by only rotating the drill pipe 22. In another embodiment of the invention, a downhole motor 55 (mud motor) is arranged in the drilling unit 90 to rotate the drill bit 50, while the drill pipe 22 is usually rotated to increase the rotational force, if necessary, and to change the drilling direction.

[0021] In the embodiment in Figure 1, the mud motor 55 is connected to the drill bit 50 via a drive shaft (not shown) arranged in a bearing unit 57. The mud motor rotates the drill bit 50 when the drilling fluid 31 flows through the mud motor 55 under pressure. The bearing unit 57 takes up the radial and axial forces on the drill bit. A stabilizer 58 connected to the bearing unit 57 functions as a centralizer for the lower part of the mud motor unit.

[0022] In one embodiment of the invention, a drill sensor module 59 is placed near the drill bit 50. The drill sensor module contains sensors, circuits and software and algorithms linked to the dynamic drilling parameters. These parameters typically include bit bounce, jerky movement of the drill unit, back rotation, torque, impact, borehole and annulus pressure, acceleration measurements and other measurements of the condition of the drill bit. A suitable telemetry or communication unit 72, which for example uses two-way telemetry, is also provided as illustrated in the drilling unit 90. The drilling sensor module processes the information from the sensors and sends it to the surface management unit 40 via the telemetry system 72.

[0023] The communication module 72, a power unit 78 and an MWD tool 79 are all connected one behind the other in the drill string 20. Bending pieces, for example, are used to connect the MWD tool 79 to the drilling unit 90. Such bending pieces and tools form the bottom hole unit 90 between the drill string 20 and the drill bit 50. The drilling unit 90 takes various measurements including pulsating nuclear magnetic resonance measurements while the borehole 26 is drilled. The communication module 72 receives the signals and measurements and transmits the signals, for example using two-way telemetry for processing on the surface. Alternatively, the signals can be processed by a processor in the drilling unit 90.

[0024] The control unit or processor 40 on the surface also receives signals from other sensors and devices in the well and signals from the sensors SrS3 and other sensors used in the system 10, and processes these signals according to programmed instructions provided in the surface control unit 40. The surface control unit 40 shows desired drilling parameters and other information on a display device/monitor 42 which is used by an operator to control the drilling operations. The surface control unit 40 typically comprises a computer or a microprocessor-based processing system, memory for storing programs or models and data, a recorder for recording data and other external devices. The control unit 40 is typically arranged to activate alarms 44 in the event of predetermined dangerous or undesirable operating conditions. The system also includes a downhole processor, a sensor unit for formation evaluation and an orientation sensor. These can be arranged anywhere on the bottom hole assembly.

[0025] Figure 2a is a schematic sketch of the pulsator, also called an oscillating one

shear valve 19, for sludge pulse telemetry. The pulsator unit 19 is located inside the internal bore in the tool housing 101. The housing 101 can be a hollow weight tube in the bottom hole unit 10, or alternatively a separate housing designed to fit inside the bore in a weight tube. The drilling fluid 31 flows through the stator 102 and the rotor 103 and passes through the annulus between the pulsator housing 108 and the internal diameter of the tool housing 101.

[0026] The stator 102, see figures 2a and 2b, is fixed in relation to the tool housing 101 and to the pulsator housing 108 and has several longitudinal flow paths 120. The rotor 103, see figures 2a and 2c, is disk-shaped with notched blades 130 that form flow paths 125 with similar in size and shape to the flow paths 120 in the stator 102. Alternatively, the flow paths 120 and 125 can be holes respectively through the stator 102 and the rotor 103. The rotor passages 125 are arranged so that they can be aligned, in one angular position, with the stator passages 120 and form a rectilinear flow path. The rotor 103 is arranged close to the stator 102 and is arranged for oscillating rotation. An angular displacement of the rotor 103 relative to the stator 102 changes the effective flow area and creates pressure fluctuations in the circulated sludge column. To effect one pressure cycle, it is necessary to open and close the flow channel by changing the angular position of the rotor blades 130 relative to the flow path 120 in the stator. This can be done with an oscillating movement of the rotor 103. The rotor blades 130 are rotated in a first direction until the flow area is completely or partially closed or restricted. This creates a pressure increase. They are then rotated in the opposite direction to open the flow path. This creates a pressure reduction. The required angular displacement depends on the design of the rotor 103 and the stator 102. The more flow paths in the rotor 103, the less angular displacement is required to create a given pressure fluctuation. A small offset angle to create the pressure drop is desirable. The force required to accelerate the rotor 103 is proportional to the angular displacement. The smaller the angular displacement, the smaller the actuation force required to accelerate or decelerate the rotor 103. As an example, with eight flow openings on the rotor 103 and on the stator 102, an angular displacement of about 22.5° is used to create the pressure drop. This keeps the activation energy at a relatively low level at high frequencies. Note that it is not necessary to block the flow completely to create a pressure pulse, and consequently different degrees of blocking, or angular rotation, will create different pulse amplitudes.

[0027] The rotor 103 is attached to a shaft 106. The shaft 106 stands through a flexible bellows 107 and passes through bearings 109 which retain the shaft radially and axially in relation to the housing 108. The shaft is connected to an electric motor 104, which can be a reverser-bar, brushless DC motor, a servo motor or a stepper motor. The motor 104 is electronically controlled by circuits in the electronics module 135, so that the rotor 103 can be moved precisely in one or the other direction. The precise control of the position of the rotor 103 enables specific shaping of the generated pressure pulse. Such engines are generally available and are not described further. The electronics module 135 may include a programmable processor that may be pre-programmed to transmit data using any of a number of encoding methods, including but not limited to Amplitude Shift Keying (ASK), Frequency Shift Keying (FSK), or Phase Shift Keying (PSK) Shift Keying), or any combination of these methods.

[0028] In one embodiment of the invention, the tool housing 101 has pressure sensors, not shown, arranged above and below the pulsator unit, with the measuring surface exposed to the fluid inside the bore in the drill string. These sensors are operated by the electronics module 135, and can be provided to receive pressure pulses sent from the surface. The processor in the electronics module 135 may be programmed to change the data encoding parameters based on pressure pulses sent from the surface. The coding parameters may include the type of coding scheme, the amplitude of the basic pulse, the frequency of the basic pulse or other parameters that affect the data coding.

[0029] The entire pulsator housing 108 is filled with a suitable lubricant 111 to lubricate the bearings 109 and to compensate the pressure inside the pulsator housing 108 with the downhole pressure in the drilling mud 31. The bearings 109 are typically anti-friction bearings known to those skilled in the art, and are not described additional. In one embodiment, the seal 107 is a flexible bellows seal that is connected directly to the shaft 106 and the pulsator housing 108 and hermetically seals the oil-filled pulsator housing 108. The rotational movement of the shaft 106 causes the flexible material in the bellows seal 107 to twist and thus adapt to the rotational movement. The flexible bellows material can be an elastic material or alternatively a fibre-reinforced elastic material. It is necessary to keep the angular movement relatively small so that the bellows material will not experience excessive stress due to the twisting movement. In an alternative preferred embodiment, the seal 107 can be an elastic rotating shaft seal or a mechanical flat seal.

[0030] In one embodiment, the motor 104 is equipped with a shaft with two ends or alternatively a hollow shaft. One end of the motor shaft is attached to the shaft 106, and the other end of the motor shaft is attached to a torsion spring 105. The other end of the torsion spring 105 is attached to the end cover 115. The torsion spring 105, together with the shaft 106 and the rotor 103, form a mechanical spring/mass system. The torsion spring 105 is arranged so that this spring/mass system has its fundamental frequency at, or close to, the pulsator's desired oscillation pulse frequency. The procedure for constructing a resonant torsional spring/mass system is well known to those skilled in the art, and is not described here. The advantage of a resonant system is that when the system is in resonance, the motor only needs to supply enough power to overcome external forces and system damping, while rotational inertial forces are balanced by the resonant system.

[0031] As indicated above, with passband signaling it will be desirable to select one or more frequency bands where the noise is small and the attenuation of the signal in the channel is smaller. By selecting the frequency band(s) based on this criterion, the signal-to-noise ratio (SNR) can be maximized for a given power consumption of the pulsator.

[0032] This choice can be based on the transmission function of a channel, i.e. what happens to the signal from the time it is fed into the mud channel downhole until it is received at the surface. This can be modeled as a "black box"; we feed a signal into one end of the box and receive a signal at the other end. By comparing the input signal and the output signal, we develop a model of the system that describes how it changes signals.

[0033] The system transfer function is shown schematically in Figure 3. An input signal 201 with frequency spectrum X(f) is shown. In this example, this is a known signal generated by the mud pulsator. The mud channel 203 has a transfer function H(f) in the frequency domain. The received signal 205 has spectrum Y(f). The different spectra are connected through:

or equivalently, in the time domain, where <8> represents the convolution operator. The convolution operation is given by:

The idea of a transfer function to represent a telemetry channel is described in connection with electromagnetic telemetry in US 6,781,521 to Gardner. Gardner's method is not based on determining the transfer function, but on the use of adaptive filters that correct for electromagnetic noise. There are several methods for determining the transfer function H(f) that characterizes the channel.

[0034] In one embodiment of the invention, the signal X(t) is a chirp signal. An example of a chirp signal is one that lasts a period of time where the frequency is continuously increased or decreased; the frequency runs continuously between a start frequency and an end frequency. An upward frequency sweep in the time domain is illustrated at 205 in Figure 4a. The equivalent in the frequency domain is shown at 207 in Figure 4b. As can be seen in Figure 4b, the frequency in this example increases linearly from an angular frequency ©1 to an angular frequency a>2- It is not necessary that the frequency changes linearly in time; non-linear pass-through frequencies can be used to selectively emphasize the energy in some frequency bands over others. Other criteria that can be used are having a spectrum with reduced side lobes; see, for example, US 5,347,494 to Andersen.

[0035] In one embodiment of the invention, a chirp signal X(t) with the properties in figures 4a-4b is generated by the pulsator. Somewhere on the surface, the signal Y(t) is measured after having propagated through the mud channel. The cross-correlation between X(t) and Y(t) is given by:

Comparison of this cross-correlation with the autocorrelation of the chirp signal, Rxx( t ), gives the transfer function H( t ) or H( f ) using known methods. One possible method is to calculate the frequency spectra of the cross-correlation and divide by the frequency spectrum of the autocorrelation: #*(/) = J?2^2 (5).

An important advantage of using a chirp signal in the well is that if the frequency bands ©i and ©2 are large enough, the autocorrelation is a unity spike in the time domain. For band-limited chirp signals, the autocorrelation is the sync function. Alternatively, a traditional frequency analysis of the emitted and transmitted signal can be carried out and a spectral ratio determined.

[0036] Chirp signals have the important property that they can be compressed both in the time domain and in the frequency domain. Chirp compression is done through the correlation operation. The autocorrelation of a chirp signal results in a very sharp pulse with a high amplitude. See 211 in Figure 5a. The same operation in the frequency domain gives a high peak at the frequency 0 Hz. See 213 in Figure 5b. The autocorrelation function collects (compresses) most of the energy in the chirp signal in one point. By chirp compression is meant a projection of the frequency curve onto the vertical axis for correlation in the time domain, and onto the horizontal axis for correlation in the frequency domain.

[0037] Figure 6 shows the results of a determination of the transfer function using a 1-40 Hz chirp signal. As can be seen, there are bands 251, 253 around 15 Hz and 28.5 Hz where the channel is strongly attenuating. Consequently, signals in these frequency bands should be avoided.

[0038] In an alternative embodiment of the invention, instead of using a chirp signal, a stepped frequency sweep lasts a period of time where the frequency is increased step by step, and each frequency step is maintained for a defined time interval. Such a stepped frequency signal with three different frequency steps is shown in Figure 7a, while Figure 7b shows how the frequencies increase over a period of time. The time scale in Figure 7b is different from that in Figure 4b. The duration of each step and the number of steps between defined start frequencies and end frequencies are all programmable. The sequences are known in advance. With this method, the transfer function is determined with discrete bands defined by the different steps. One advantage of the step method is that it is less sensitive to synchronization errors and InterSymbol Interference (ISI) since each frequency is maintained over a long time interval T (see Figure 7b). If the time interval is chosen sufficiently large, there will be windows where the ISI disturbance is small or zero. A disadvantage of the step method is that the frequency cycle takes place over a longer period of time and thus cannot be used if real-time data is required. With the chirp method, the duration can be made shorter, but the estimates are not as robust. The Chirp method has the advantage that it provides a denser sampling in the frequency domain. The use of a stepped frequency signal to determine optimal frequencies for acoustic telemetry through a drill string is described in US 5,124,953 to Grosso; in Grosso, however, the choice is made based on a modeled transfer function for the drill string, not on a measured transfer function.

[0039] In yet another embodiment of the invention, a pseudorandom sequence is used, possibly a pseudorandom binary sequence. Such sequences have the characteristic of having an autocorrelation which is essentially a unit spike. Using such sequences, it is possible to determine the channel properties.

[0040] Figure 8 shows a plot of the channel transfer function calculated using the stepwise frequency method. Curves 291 and 293 correspond to a sensor for dynamic pressure and a sensor for static pressure. Curve 295 is a theoretical curve estimated based on knowledge of the properties of the drill string, the well and the mud. The agreement between the theoretical curve and the estimated transfer function is good. They also agree with Figure 6 in terms of the unwanted bands around 15 Hz and 28 Hz.

[0041] The use of determining the channel's transmission function by telemetry during drilling operations is illustrated in the flowchart in Figure 9. Drilling is started 301 and simultaneously with the drilling operations, downlink telemetry is used to send instructions downhole, and uplink telemetry is used to send data uphole. The initial choice of frequencies may be based on past experience, or on modeling based on the known physical properties of the drill string, mud and borehole. Upon appropriate interruption 303 during drilling operations, such as when a new drill pipe section is added, the channel transfer function is determined 305 using any of the methods described above. Based on this determination, the driving frequencies of the downlink and uplink sources can be changed 307. The channel is generally not symmetrical since the boundary condition at the pulsator end is essentially an open channel while the channel is closed at the surface. However, with the use of dual pressure transducers (DPT - Dual Pressure Transducers) it is possible to isolate the upward signal (from pump noise and the reflected downward signal) and to derive a transfer function that can also be used for downward communication. 309 drilling is then resumed. In this way, the telemetry system's driving characteristics are adapted dynamically based on measured channel characteristics.

[0042] In one embodiment of the invention, the receiver is a device that reacts to mud flow. This can be a traditional flow meter, or in the case of downlink telemetry, a turbine down in the well. Pressure transducers such as hydrophones can be used. For uplink telemetry, dual pressure transducers (DPT - Dual Pressure Transducers) can be used as an alternative or in addition to a single hydrophone. Double pressure transducers comprise at least two pressure transducers arranged at a distance from each other. The signals from the dual pressure transducer can be processed to remove signals propagating in a selected direction, for example from a pump. This capability of a double pressure transducer makes it more suitable than a single pressure transducer; however, a simple pressure transducer can be used in the present invention.

[0043] The present invention also solves a problem that occurs with any type of mechanical vibrator element that is controlled by a chirp signal, namely harmonic distortion. Simply put, in addition to generating signals at the frequency of the chirp reference signal, vibrator elements will also generate signals at harmonics (multiples of the fundamental frequency). When the received signal is correlated with the chirp signal, errors will occur if the chirp signal's frequency band exceeds one octave. A signal processing method that solves this problem is described below.

[0044] A chirp signal in the form of a linear frequency modulated pulse with start frequency fs and chirp frequency y is expressed mathematically as: The channel can be considered as a linear FIR filter with complex coefficients otj and time delays ^(i=1,2, ..).

The pressure signal at the pulsator is assumed to be non-linear, and the second harmonic of the chirp signal is attenuated by a factor p relative to the fundamental frequency:

The pressure signal at the surface is a convolution of the pressure signal with the mud channel's impulse response: which gives:

[0045] We will now describe an "overtone cancellation". Overtone cancellation involves multiplying the received signal by a chirp reference signal, filtering the resulting signal, and multiplying it by the complex conjugate of the chirp reference signal. The product of a chirp signal of duration Tcurp with its complex conjugate and time-shifted by v gives:

CChirp( t, rj) is an ASK-modulated square pulse with frequency = - y. w,. Figures 10a and 10b show respectively the real part of CChirp(t, r) in the time domain and its Fourier-transformed.

[0046] The chirp reference signal is the complex conjugate of the transmitted "ideal" chirp signal:

The compressed received signal is:

The compression of the signal with the chirp reference signal results in a sum of exponential waves with frequencies fj= -y Ti.

[0047] The second part of the last equation represents the compression of the chirp reference signal with the first harmonic of the chirp signal. It is a sum of chirp signals with chirp frequency y and starting frequencies:

For a linear pulsator (p = 0), the coefficients a\ and the time delays t\ of the channel filter can be calculated directly with the amplitude and frequency of the compressed signal

Zcomp( t) (for example using FFT). For a non-linear transmitter, i.e. where the transmitter generates harmonics, the spectra of the compressed signals (the fundamental frequency and the first harmonic) can overlap and degrade the channel estimation. The following condition ensures that the two spectra do not overlap:

The highest frequency of the delayed chirp signal after compression must be lower than the highest frequency of the first harmonic after compression, i.e.:

[0048] As an example, with y = 40 Hz/s, Tmax = 0.1s, fs > 12 Hz. This condition ensures that there is no overlap between the two spectra. Since the signal energy decreases with increasing delay, a certain overlap of the two spectra can be allowed depending on the delay profile of the transmission channel. If, for example, most of the reflected energy lies within 50% of the maximum delay of 0.1 seconds, chirp signals with a starting frequency fs=6 Hz can be used.

[0049] After compression, the compressed signal will be filtered by a low-pass filter that filters out the chirp signals that arise as a result of the non-linearity of the pulsator. If the condition above is met, the following signal is obtained after filtering:

The channel coefficients a-, and the time delays v, can then be determined by transforming the signal ZcomP, m( V into the frequency domain and calculating the spectral lines (see fig. 10). The amplitude and frequency of the spectral lines determine the delays and coefficients. The filtering of the compressed signal not only reduces the impact of harmonics, but also of other noise within the transmission band.

[0050] After compression and filtering, the signal will be projected to the chirp reference signal. The signal z(t) is equal to the received signal y(t) if the pulsator is linear and the transmission is noise-free. The channel transfer function can then be estimated by dividing the Fourier transform of the signal z(t) by the Fourier transform of the reference signal xæf(t). Figure 11 is a flowchart illustrating the channel estimation algorithm.

[0051] Figure 11 shows an input signal 401, which is given by y(t) in Eq. (10). The input signal 401 is compressed (cross-correlated) in 403 with the complex conjugate of the chirp reference signal as given in Eq. (13)-(17). The result is filtered by a low-pass filter in 405 which filters out the chirp signals that have arisen as a result of the non-linearity of the pulsator. If the condition given by Eq. (20) is fulfilled, the result is given by Eq. (21). 407 is the projection of the compressed filtered signal onto the chirp signal. The steps represented by 403, 405 and 407 may be called a chirp transform. The Fourier transform of the chirp-transformed output signal is taken in 409 and the transfer function is estimated in 413 using the Fourier transform of the chirp reference signal.

[0052] The use of the chirp transform for attenuation of harmonic distortion is not limited to communication in a sludge channel with sludge pulse telemetry. The problem of harmonic distortion also occurs when a variable frequency signal source is used in seismic operations, SWD® (Seismic While Drilling) operations and well-to-well tomography. In all these applications, harmonic distortion can be reduced using the method described above. As the person skilled in the art will know, seismic operations use a mechanical vibrator (on land) and a marine vibrator (offshore) to generate a chirp signal that propagates into the subsoil. Signals detected by receivers located on the surface or in a wellbore are cross-correlated with a chirp reference signal to obtain an impulse response for the ground that is determined by the geometry of subsurface interfaces and the elastic properties of the ground. In the case of SWD®, the source may be a mechanical vibrator which is carried by a drill string on a downhole unit. In well-to-well tomography, the sources and receivers are inside boreholes. The soil formation through which the signals propagate can be considered the communication channel. As will be known to those skilled in the art, the transfer function can be determined from a response to an impulse, but can also be determined from the response to a step function. For the purpose of the present invention, the term "impulse response" is intended to include the response of a step function.

[0053] The operation of the transmitter and the receivers can be controlled by the downhole processor and/or the surface processor. Implied in the management and processing of data is the use of a computer program on a suitable machine-readable medium which enables the processor to effect management and data processing. The machine-readable medium may include one or more ROMs, EPROMs, EAROMs, flash memories and optical disc storage.

[0054] The preceding description is aimed at concrete embodiments of the present invention for purposes of illustration and explanation. However, it will be clear to the person skilled in the art that many modifications and changes to the embodiment described above are possible within the scope and idea of the invention according to the patent requirements. It is therefore intended that the following requirements shall be interpreted to include all such modifications and changes.

Claims (38)

1. Method for communicating signals in a wellbore between a location on the surface and a location down the well, where the method comprises: (a) generating a mechanical signal at one of the location on the surface and the location down the well, where the generated mechanical the signal is selected from the group consisting of: (A) a step-frequency signal, (B) a linear chirp signal, (C) a nonlinear chirp signal, (D) a pseudorandom sequence, and (E) a pseudorandom binary sequence , (b) receiving a signal representing the generated mechanical signal at the other of the surface location and the downhole location, and (c) based on the received signal and the generated mechanical signal, estimating a property of a communication channel between the location on the surface and the place down in the well. 2. Method according to claim 1, where the mechanical signal that is generated is at least one of: (i) a change of a fluid flow, and (ii) a pressure pulse. 3. Method according to claim 1, where the signal received comprises a measurement of at least one of: (i) a pressure, and (ii) a fluid flow. 4. Method according to claim 1, where the generated mechanical signal is generated at the location down in the well during an interruption in drilling operations. 5. Method according to claim 1, where the communication channel comprises a sludge flow path. 6. Method according to claim 1, where the characteristic of the communication channel comprises a transfer function. 7. Method according to claim 1, wherein estimating the property further comprises at least one of: (i) cross-correlating the received signal with the generated mechanical signal, (ii) applying the frequency spectrum of the received signal, and (iii) applying the frequency spectrum of the generated mechanical signal. 8. The method of claim 1, further comprising using the feature determined to select a drive frequency for communication of at least one of: (i) instructions from the surface location to the downhole location, and (ii) data from the downhole location the well to the location on the surface. 9. Method according to claim 1, where the mechanical signal further comprises a chirp signal, and where estimating the property comprises applying a chirp transformation to the received signal. 10. Method according to claim 9, wherein applying the chirp transformation further comprises low-pass filtering at least partially based on the chirp frequency of the mechanical signal and a maximum delay in the channel. 11. System for communicating signals in a well bore between a location on the surface and a location down the well, where the system comprises: (a) a mechanical source that generates a mechanical signal at one of the location on the surface and the location down the well, where the generated mechanical signal is selected from the group consisting of: (A) a step frequency signal, (B) a linear chirp signal, (C) a non-linear chirp signal, (D) a pseudorandom sequence, and (E ) a pseudorandom binary sequence; (b) a receiver that produces a signal representing the generated mechanical signal at the other of the surface location and the downhole location; and (c) a processor which, based on the received signal and the generated mechanical signal, determines a property of a communication channel between the surface location and the downhole location. 12. System according to claim 11, where the mechanical source comprises a pulsator with an oscillating shear valve. 13. System according to claim 11, where the generated mechanical signal further comprises at least one of: (i) a change of a fluid flow, and (ii) a pressure pulse. 14. System according to claim 11, where the receiver is selected from the group consisting of: (i) a hydrophone, (ii) a pressure transducer, (iii) a dual pressure transducer, and (iv) a flow meter. 15. System according to claim 11, where the source of the mechanical signal is located downhole, and the mechanical signal is generated during an interruption in drilling operations at the location down in the well. 16. System according to claim 11, where the communication channel comprises a sludge flow path. 17. System according to claim 11, where the characteristic of the communication channel comprises a transfer function. 18. System according to claim 11, wherein the processor determines the property by at least one of: (i) cross-correlation of the received mechanical signal with the generated signal, (ii) determination of a frequency spectrum for the received signal, and (iii) determination of a frequency spectrum for the generated mechanical signal. 19. The system of claim 11, wherein the processor further uses the found property to select a frequency for communicating at least one of: (i) instructions from the surface location to the downhole location, and (ii) data from the downhole location to the location on the surface. 20. System according to claim 11, where the processor is located at the location down in the well. 21. System according to claim 11, wherein the mechanical source is part of a bottom hole assembly (BHA). 22. System according to claim 11, where the generated mechanical signal comprises a chirp signal, and where the processor determines the characteristic of the communication channel by applying a chirp transformation. 23. Computer-readable medium for use with a system for communicating signals in a wellbore between a location on the surface and a location downhole, the system comprising: (a) a mechanical source that generates a mechanical signal at one of the locations on the surface and the downhole location, where the generated mechanical signal is selected from the group consisting of: (A) a stepped frequency signal, (B) a linear chirp signal, (C) a non-linear chirp signal, (D ) a pseudorandom sequence, and (E) a pseudorandom binary sequence; (b) a receiver that produces a signal representing the generated mechanical signal at the other of the surface location and the downhole location, the medium further comprising instructions enabling a processor to estimate from the received signal and the generated mechanical signal a property of the communication channel between the location on the surface and the location down the well. 24. Computer-readable medium according to claim 23, further comprising at least one of: (i) a ROM, (ii) an EPROM, (iii) an EAROM, (iv) a flash memory, and (v) an optical disc storage. 25. Method for determining a property of a communication channel associated with an earth formation, the method comprising: (a) using a mechanical device to generate a signal of varying frequency that propagates in the channel, the propagating signal comprising a harmonic distortion ; (b) receiving the propagating signal at at least one receiver to generate a receiver signal affected by the characteristic of the channel; (c) processing the received signal to estimate the characteristic of the channel, the processing comprising applying a chirp transform. 26. Method according to claim 25, where the communication channel further comprises a borehole in the soil formation. 27. Method according to claim 25, where the property further comprises an impulse response for the channel. 28. Method according to claim 25, further comprising arranging the mechanical device at a location selected from: (i) a location on the surface, (ii) inside a body of water, (iii) inside a borehole in the soil formation, and (iv) ) on a downhole unit that is driven into a borehole in the soil formation. 29. The method of claim 25, further comprising arranging the at least one receiver at a location selected from (i) a location on the surface, (ii) inside a body of water, (iii) inside a borehole in the soil formation, and (iv) ) on a downhole unit that is driven into a borehole in the soil formation. 30. Method according to claim 25, wherein the chirp transformation further comprises: (i) a correlation with the conjugate of the frequency-varying signal; (ii) a low-pass filtering; and (iii) a correlation with the frequency-varying signal. 31. Method according to claim 30, further comprising selecting a parameter for the low-pass filtering at least partially based on the chirp frequency of the frequency-varying signal and a maximum delay in the channel. 32. System for determining a property of a communication channel associated with an earth formation, the system comprising: (a) a mechanical device that generates a frequency-varying signal propagating in the channel, the propagating signal comprising a harmonic; (b) a receiver which generates a receiver signal which is influenced by the characteristic of the channel; (c) a processor which estimates the characteristic of the channel from the received signal through data processing comprising applying a chirp transform. 33. System according to claim 32, where the communication channel further comprises a borehole in the soil formation. 34. System according to claim 32, wherein the property further comprises an impulse response for the channel. 35. System according to claim 32, wherein the mechanical device is arranged at a location selected from: (i) a location on the surface, (ii) inside a body of water, (iii) inside a borehole in the soil formation, (iv) on a downhole unit that is guided into a borehole in the soil formation. 36. System according to claim 32, wherein the at least one receiver is arranged at a location selected from: (i) a location on the surface, (ii) inside a body of water, (iii) inside a borehole in the soil formation, (iv ) on a downhole unit that is driven into a borehole in the soil formation. 37. The system of claim 34, wherein the processor applies the chirp transformation by further performing: (i) a correlation with the conjugate of the frequency varying signal; (ii) a low-pass filtering; and (iii) a correlation with the frequency-varying signal. 38. System according to claim 37, where the processor selects a parameter for the low-pass filtering at least partially based on a chirp frequency for the frequency-varying signal and a maximum delay in the channel.