GB2147722A - Signal recovery for logging while drilling system - Google Patents

Abstract

Two closely spaced pressure sensors (30,32) at the surface measure drilling mud pressure pulsations in a mud line (34) representing subsurface measurements. Both of the measured pressure pulsation signals are time shifted an amount equal to the travel time of the upwardly and downwardly propagation acoustic velocity in the mud between the two pressure sensors by separate time delay circuits (84,86). Summing circuits (88,90) separately combine the original and delayed signals to cancel the respective upwardly and downwardly propagating energy from the two pressure data signals. An estimator circuit (92) and a deconvolution circuit (94) process the composite signals to derive an estimated primary signal representing upward traveling energy. The resulting pressure data signal is then processed by each of n matched filters (98,100) to determine the presence or absence of one of n symbols in the residual data signal. Each output of the filtered data signals is then input to a "Largest of" Bayesian detector (102) to identify either the presence of a symbol or absence of the data signal. <IMAGE>

Description

SPECIFICATION Signal recovery method and apparatus for logging while drilling system This invention relates to a method of and apparatus for reducing interference and noise contamination of logging signals from a downhole logging tool.

The desirability and usefulness of a logging measurement while drilling system that will measure downhole well drilling parameters such as physical and geological characteristics and transmit them to the earth's surface while the well is being drilled has been recognized. In such measurement while drilling systems one of the major problems is the telemetry of data from the downhole sensors and associated transmitting apparatus to a receiving system at the earth's surface. Several telemetry and data transmission systems have been developed with each having its particular strong points.

This invention is concerned with a telemetry system that transfers the information by means of pulsations of the drilling fluid or mud that is normally associated with rotary and non rotary operations. Modulated waves that are representative of the data signal of a particular parameter may be generated by a downhole apparatus near the drilling bit as pressure waves, and pass upward through mud in the drill string to a signal detector at the earth's surface. In this system the pressure waves are passed upward through the interior of the drill string via the medium of the circulating drilling mud.

Pressure wave transmission through the drilling mud in the interior of a drill string encounters certain difficulties or contaminations due to extraneous sources of noise such as pressure waves and pulses that are placed in this fluid system by operation of the drilling equipment. Some of these pressure waves and pulses and noises are of a magnitude at least as great as the transmitted pressure wave from the downhole transmitting equipment and they occur at frequencies of the transmitted signal. Also these pressure waves are reflected within the drilling fluid flow data at certain locations presenting a significant impedance change in the pressure pulses wave guide provided by the drill string. These reflected pressure waves and pulses are also passed through the drill string and additionally reflected to further complicate identification of the transmitted signal.All of this pressure wave, pulsation, pressure pulsation noise generation and reflection within the drill string creates a noisy enviroment in which the data signal is traveling and from which it must be recovered.

In prior recovering devices they rely on mechanical receiving devices in the drilling fluid flow path and other associated mechanical devices in the signal recovery system to extract the data signals. These mechanical devices present some problems in signal recovery due to their basic mechanical nature. One problem is that transmitted pressure pulse and waves can be a source of interference by establishing resonant frequency disturbances within the mechanical devices that are extracting and processing the data.

Another difficulty with these mechanical devices is their inability to separate upwardly and downwardly traveling waves within the drilling fluid medium when reflecting boundaries are involved. Because the signals are difficult to separate from the noise and reflections (due to the similar frequencies), these reflected pressure waves can be mistaken for real data and additional data processing is needed to extract valid data from the available data.

The preferred embodiments of the present invention provide a method and apparatus for receiving and processing telemetry data that passes through the drill string of a borehole drilling rig from a measurement while drilling apparatus in the drill string. The receiving apparatus is designed to eliminate or substantially reduce the contaminating noise that is superposed on the pressure measurement signal as it is passed through the mud strem in the drilling string. The signal receiving apparatus includes a pair of spaced detectors in a mud flow conduit between the mud circulating pump and the drill string.Additionally the receiving apparatus is constructed to extract the intelligence data from the signal by time shifting the signals relative to each other, then combining the signals thereby cancelling energy propagating in one direction while passing energy propagating in the other direction for each set. The signals are then mathematically deconvolved and the primary signal (transmitted) is recovered. This novel technique passes the energy, but in a form that is not in its original form, but a time difference form of the transmitted energy. Further processing apparatus extracts the intelligence carrying data without necessarily reconstructing the originally transmitted signal. With this technique it is possible to reconstruct the signal form by applying an inverse filter but it is not necessary.

In the following description the invention is described with reference to pressure measurements taken at selected locations in the mud flow system. However it is to be understood that velocity measurements of the mud flow could also be used in an equivalent manner without departing from the scope of the invention Mud flow velocity measurements can be used as well as pressure measurements to selectively analyze travelling energy in the drilling fluid flow whether it is drilling mud or air.

The preferred embodiment of the invention provides a signal recovery apparatus for use with a logging while drilling system that uses pressure pulses or waves in drilling mud as the data carrying medium and has a pair of relatively closely spaced sensors in the mud flow conduit to recover the signal and pass it to processing equipment for removal of interferring noise and extraction of intelligence carrying data.

The preferred recovery apparatus will extract the intelligence carrying data from the mud pressure pulse signal where the pump noise and the transmitted signals are not disjoint in frequency by sampling the signal flow path to selectively extract the data signals depending on their direction of travel.

The preferred signal processing apparatus does not require regeneration of the transmitted data signal in order to extract the intelligence carrying data therefrom; it will also adaptively decompose the data to reduce the influence of noise thereon; and it will identify the actual data from the reflected signals by means of actively filtering the signal.

Various advantages and features of this invention will become apparent to those skilled in the art from the following description of a preferred embodiment thereof, given by way of example only, and taken in conjunction with the accompanying drawings, in which: Figure 1 is a schematic and pictorial representation of a well drilling rig having a measurement while drilling system incorporating this invention wherein the system uses pulsations of the mud column through the drill string as the medium for transmission of the telemetry and data signal; Figure 2 is a schematic block diagram of a portion of the data receiving and processing portion of this system illustrating the cooperative relationship of the elements of the present invention; Figure 3 is a reflection diagram illustrating the signals being reflected at two impedance changes in the mud flow stream; and Figure 4 is a series of connected graphs illustrating the signals at several identified locations in signal processing sequence as illustrated in Figure 2.

The following is a discussion and description of preferred specific embodiments of the method and apparatus for signal recovery of this invention, such being made with reference to the drawings whereupon the same reference numerals are used to indicate the same or similar parts and/or structure. It is to be understood that such discussion and description is not to unduly limit the scope of the invention.

Detailed description of the preferred embodiments The apparatus and method of this invention can be used with a borehole measurement while drilling system as incorporated in a drilling rig such as that illustrated in Figure 1. As shown, the measurement while drilling system is used with a conventional rotary type well drilling rig wherein a drill string 10 comprised of a plurality of segments of drilling pipe with a drilling bit 12 at the bottom end thereof is rotated to drill a borehole 14 through the earth formations 16. The measurement while drilling apparatus includes downhole equipment including a sensor package 18 in the lower portion of drill string 10. Sensor package 18 can contain a plurality of devices adapted to measure geophysical conditions within the borehole and the surrounding formations.For example, sensor package 18 can contain an orientation device to sense the direction and inclination of the borehole at that location or it can contain devices to measure temperature, pressure, weight as that may be desired.

Information or data that is generated by any of the element or elements in sensor package 18 is communicated within the downhole equipment to a transmitter 20 in the lower portion of the drill string.

Transmitter 20 is adapted to encode this data into pressure pulsations of the drilling fluid or mud that is contained in the drill string 10. These pressure pulsations impart energy into the drilling fluid flow that results in traveling pressure waves that are detectable by differential pressure measurements and by fluid velocity change measurements. These pressure pulsations can be either positive pressure pulsations or negative pressure pulsations of the mud in the drill string. Positive pressure pulsations are preferred for use with this invention however it can be used with other modulation techniques. Pressure pulsations introduced into the drill string mud column travel upward from transmitter 20 toward the earth's surface.As these pressure pulsations travel upward through the drill string in the interior of the drill string it functions as a wave guide to contain and direct the pressure pulsations.

Pressure pulsations originating at transmitter 20 also cause velocity changes or pertubations in the drilling fluid flow that transmit the intelligence carrying data. These velocity changes also travel upward through the drill string just as the pressure pulsations do. And they are influenced by the interior of the drill string as are the pressure pulses.

Reflections of these pressure pulsations occur within the drill string at locations in the drill string's interior and which represent a significant impedance change in the wave guide formed by the drilled string. Such occurences of these reflections boundaries are the junctures inthe fluid path at the swivel connection 27, the kelly hose 24, and its connection with the standpipe 26 as well as other fluid couplings and the like in the mud flow conduit between mud pump 28 and swivel 27. Pressure pulsations traveling upward through the mud flow stream in the drill string are detected at a pair of pressure sensors 30 and 32 that are mounted at a selected location within the conduit 34 between mud pump 28 and swivel 27.

Pressure sensors 30 and 32 are operably connected with conduit 34 to directly sense the fluid pressure therein or depending upon the character of the specific pressure sensors utilized they provide a signal indicative of the fluid within conduit 34. It is to be noted that pressure sensors 30 and 32 can be of a mechanical design that is fluidically connected with the interior of conduit 34 to provide access to the mud in order to provide the presure signal data necessary for extracting the intelligence from the encoded pressure pulsations in the mud flow stream. These pressure sensors or pressure transducers can be of any other configuration internal to the conduit or external that provides an electrical output representative of the fluid pressure in the mud filled conduit. Where velocity of the mud flow is monitored an appropriate fluid velocity sensing device is connected into the mud filled conduit so velocity measurements at that particular location can be observed.

Placement of pressure sensors 30 and 32 is selected with them being relatively closely spaced and along a segment of flow line conduit 34 that is substantially without internal obstructions and is of a substantially uniform cross sectional area so that fluid flow is substantially undisturbed between the segment of a conduit. Spacing between pressure sensors 30 and 32 can vary between about three (3) feet (about 0.9 meters) and about one hundred (100) feet (about 30.5 meters). It has been found that a preferred spacing of pressure sensors 30 and 32 is between about five (5) feet (about 1.5 meters) and about forty (40) feet (about 12.4 meters). The most preferred and practical spacing of pressure sensors 30 and 32 is between twenty (20) to forty (40) feet (about 6 to 12.4 meters). Pressure sensors 30 and 32 are electrically connected to a receiver 36.Receiver 36 functions to receive data from pressure sensors 30 and 32 then process this received signal data in order to transform it into data usable in other portions of this system.

A data processor and display apparatus 40 is operably to the output of receiver 36. The data processor and display apparatus 40 is adapted to process the received and processed data thereby extracting the intelligence information carried therein and display this information and provide for its storage if desired.

Figure 2 shows in a schematic representation the apparatus for recovering the mud pressure pulse data from the mud pressure pulse data from the mud flow stream and the associated apparatus for processing the received signals. Pressure transducers 30 and 32 are spaced apart a distance "d" on conduit 34 to extract the pressure pulse data from the mud stream. Considering the conduit segment 34 as shown, the mud flow is from left to right or in the opposite relation from pump 28 to the well as shown in Figure 1. The relative position of transducers 30 and 32 are reversed in Figures 2 and 3 from the pictorial view in Figure 1.

Discussions below refer to the orientation shown in Figures 2 and 3. The intelligence carrying transmitted signal ST iS moving from the right to the left. The pump noise signal Sp is shown moving in the opposite direction on the left side of the figure moving toward the right.

The conduit 34 is preferably a segment of pipe, tubing or other flow conduit in the mud line or flow path between the mud circulating pump 28 and swivel 27. Preferably conduit 34 is a segment of uniform internal diameter material that is substantially rigid and mounted with the drilling rig structure in a secure position so that flow conditions of the mud at and between two pressure sensors will not be substantially different. It is desirable that flow conditions at and between the pressure sensors be substantially the same so that flow conditions of the pressure signal at one of the pressure sensors will be substantially the same as the other pressure sensor and any modification of the flow conditions and propagating signals between the pressure sensors can be neglected.

Pressure sensors 30 and 32 can be any commercially available type of pressure transducer that will within a predetermined accuracy measure pressure of the presence of the pressure wave in the mud at the appropriate point in the signal that can be expressed as a function with a reference to time. Also the pressure sensors could be any type which will provide an electrical signal corresponding to and representative of fluid pressure pulse or the pulse pressure wave in the mud at defined location in conduit 34. The outputs from pressure sensors 30 and 32 are preferably matched or adjusted so the relative output signal magnitudes or the two pressure transducers are the same for similar static and dynamic measurements.Apparatus and circuitry for this matching is not illustrated in Figure 2 because it is not essential to understanding of this invention but basically a technical adaptation necessary to implement the invention.

Referring to Figure 2, pressure sensors 30 and 32 function to measure the fluid pressure in conduit 34 as it is effected by the pressure pulses carried in the mud. The time dependent signal from pressure sensor 32 is designated as Y1(t) and the time dependent signal from pressure transducer 30 is designated as Y2(t). At any point in time, t, the signal at either of the pressure sensors 30 or 32 is representative of the transmitted signal, the pump generated signal, their multiple reflections, and a noise pressure signal. The noise pressure signal is a background noise factor including miscellaneous pressure fluctuations that appear as uncorrelated fluctuations at the output of the pressure sensors.

Referring to Figure 3 it shows the reflection diagram with the primary transmitted signal ST, the primary pump signal Sp and their reflections between and past the two spaced apart reflectors rO,+1, & r01. The solid lines indicate the primary transmitted signal S1 and its direction of travel through its several reflections. It must be emphasized that noise signals coming from pump 28 and from transmitter 20 are not disjoint in frequency thus all primary and reflected signals shown are at substantially the same frequency band. Two reflectors are shown in this system for modeling and simplicity purposes. One of the reflectors, a downstream reflector, is assumed to be at the downstream end of kelly hose 24 joining standpipe 26 to swivel 27 as illustrated in Figure 1.The other reflector, an upstream reflector, is assumed to be at a flexible hose 24 connection between mud pump 28 and a rigid segment of the mud flow conduit. The pressure pulse signal is sampled at the location of pressure sensors 30 and 32 in conduit segment 34. This corresponds to the crossing of the vertical axis labeled "t" in Figure 3 with the horizontal X axis.

As primary transmitted signal ST (indicated by solid line 50) moves upward in the drill string from transmitter 20 and the measurement while drilling apparatus at the bottom of the well bore it passes the downstream reflector and continues upward passed the sampling location at a time designated at T, and continues toward the upstream reflector whereupon a portion of this signal continues upward (line 52) and a portion of this signal (line 54) is reflected in the downward direction. This reflected signal (line 54) continues in the downward direction to the downstream reflector whereupon a portion of this signal is passed on downward (line 56) and a portion of the signal is reflected upward again (line 58). This upwardly direr.ted reflected signal (line 58) makes a second crossing of the sample location while moving in the upward direction toward the upstream reflector whereupon it is again reflected toward the downstream direction (line 60) and partially passed the upward direction (line 62). This reflection of the transmitted signal continues to occur between the upstream and downstream reflectors until the strength of this signal is attenuated to a magnitude that places it within the realm of the background noise or white noise level.

Primary pump signal S, (dashed line 70) originates at the mud pump 26 and passes through various conduits connected to the flexible hose segment of conduit 24 which theoretically forms the upstream reflector in the drilling mud flow stream system. This primary pump signal passes the sample location at a time designated as T2 and continues on in the downward direction toward the downstream reflector. The primary pump signal Sp (line 70) continues in the downward direction to the downstream reflector whereupon a portion of this signal is passed on downward (line 72) and a portion of the signal is reflected upward (line 74).This signal (line 74) continues in the upward direction and makes a second reflection at the upstream reflectorwhereupon a portion of the signal (line 76) continues upward and reflected portion of the signal (line 78) is reflected into the downward direction. This signal (line 78) makes a second passing of the sample location in the downward direction and continued to the downstreanm reflector whereupon a portion of the signal is again reflected to the upward direction (line 80) and a portion of the signal (line 82) continues in a downward direction.

The reflections indicated in Figure 3 are only a portion of the total number of pressure reflections signals traveling through the mud flow stream at any particular given instant during normal operation of the drilling rig. Signals depicted are the major pressure signals present in this system as they reflected from the major reflectors. The other pressure signals in this sysem are caused by bouncing of the drill string during the drilling operation and various valves, dampeners, etc. associated with the mud pump system. Each of the pressure signal generators creates noise pressure pulses that travel through the drilling fluid system.Only two major reflectors are shown in Figure 3 however it is to be understood that this drilling system contains a plurality of other reflectors assumed negligible that also reflect the pressure pulse signals passing through the drilling fluid flow stream. These reflectors are created by pressure pulse impedance changes in the flow system and are a result of area changes or conduit wall compliance changes or other discrete changes in the fluid flow stream such as are occasioned in tool joint connections in the drill string and piping connections at the earth surface between the swivel and outlet ports of the mud pump. Each of these impedance changes provides a reflecting medium that will reflect a portion of the signals passing through the flow stream at each of the impedance changes.The impedance changes discussed herein can be thought of as being the change in the transmission medium impedance between one segment of the mud flow stream and an adjoining segment thereof due to the differences in the wave guide transmission medium characteristics of the flow path.

In defining the relationships of the signals involved and the primary signal recovery, it is first appropriate to examine the receiving relationship of the pressures as seen by the pressure sensors on conduit segment 34. The relationship of the pressure signals present in this system as seen by a single pressure placed along the conduit between the reflective boundaries may be expressed as:: Y(t) = ST(t) + Sp(t) + N(t) (1) + rO,1 ' Sr(t - 2At1) + rO.+1 Sp(t - 2At2) + r0,-1 6 rO.+1 ST(t - 2(At1 + At2)) + r0,-1 r0,1 Sp(t - 2(At1 +(t2)) + r0,-1 r0,+1 ST(t - 2(2At1 + At2)) + r0,1 r0,+12 Sp(t - 2(At1 + 2At2)) where:: Y(t) is the extracted pressure pulse signal from the mud flow line conduit 34, ST(t) is the attenuated and dispersed transmitted signal coming from the downhole transmitter as it is seen by the pressure transducer, Sp(t) is the pump generated signal, N(t) is the noise observed by the pressure transducer, and: real is the first reflection coefficient downstream of the transducers r0,-1 is the first reflection coefficient upstream of the transducers For the two spatially separated sensors, the signal Y1 (t) at pressure sensor 32 will differ from that of the signal Y2(t) at pressure transducer 30 with respect to time because of the distance d separating the two pressure sensors and the associated delay in pressure wave propagation time.The actual time differential involved depends upon the propagation time between the separate pressure sensors which is a function of the velocity of the pressure wave within conduit 34 and the separation distanced.

The signal Y1(t) at pressure transducer 32 can be expressed as: Y1(t) = ST(t) + Sp(t) + N1(t) (2) + r0,-1 . ST(t-2(t'+T-1)) + r0,+1 - Sp(t-2T+1) + r0,-1 . r0,+1 . ST(t-2(t'+T-1+T+1)) + r0,-1 . r0,+1 . Sp(t'+T-1+T+1)) + r0, 2i r0,+1 - ST(t-2(2t'+2T-1+T+1)) + r0,-1 . r0,+ 2/1 . Sp(t-2(t'+T-1+2T+1)) And the signal Y2(t) at pressure transducer 30 can be expressed as: Y2(t) = ST(t-t') + Sp(t+t') + N2(t) (3) + r0,-1 . ST(t-t'-2T-1)) + r0,-1 . Sp(t-t'-2T+1)) + r0,-1 . r0,+1 . ST(t-t'-2(t'+T-1+T+1)) + r0, 2i r0,+1 ST(t-t'-2(t'+2T-1+T+1)) + r0,-1 . r0,+1 . Sp(t-t'-2(t'+T-1+2T+1)) where: rig is the reflection coefficient of wave moving from medium i of impedance Zi into another medium j of impedance Zj.

t' is the propagation time between transducers 30 and 32, the locations of observing Y2(t) and Y1(t) respectively.

T-1 is the propagation time from transducer 30, (Y2(t)), to the boundary between mediums -1 and 0.

T+1 is the propagation time from transducer 32, (Y1lt)), the boundary between mediums 0 and +1.

In order to timewise align the signals coming from pressure sensors 30 and 32 it is necessary to account for the time shift taking place as a pressure wave moves between the pressure sensors. The propagation time between the pressure sensors t' can be used to shift the signal coming from either pressure sensor in order that a reference point for analyzing the well to surface traveling pressure signals can be established. In this system both Y1(t) and Y2(t) are delayed by time t' through separate time delay elements 84 and 86 as shown in Figure 2. In these time delay elements the polarity or sign of each signal is changed. The sign change is necessary so that noise canceling will take place when the signals Y1(t) and Y2(t) are combined by their respective summing circuits 88 and 90.

Y2(t) as it is delayed by time t' can be expressed as follows: Y2(t-t') = ST(t-2t') + Sp(t) + N2(t-t') (4) + r0,-1 . ST(t-2(t'+T-1)) + r0,+1 - Sp(t-2(t'+T+1)) + r0,-1 . r0,+1 . ST(t-2(2t'+T-1+T+1)) + r0,-1 . r0,+1 . Sp(t-2(t'+T-1+T+1)) + r0,-1 . r0,+1 . ST(t-2(2t'+2T-1+T+1)) + r0,-1 . r0,+1 . Sp(t-2(2t'+T-1+2T+1)) + Summing circuit 90 combines the two signals Y1(t) and Y2(t-t') into a composite signal Z+(t) representative of the positive or upwardly traveling energy traveling at the acoustic velocity including both the primary transmitted signals and the upwardly traveling reflected signals.This composite signals Z+(t) may be expressed as: Z+(t) = Y1(t) - Y2(t-t') (5) = [ST(t) - ST(t) - ST(t-2t')] + [N1(t)-N2(t-t')] + r0,-1 . [Sp(t-2T+1) - Sp(t-2)t'+T+1))] + r0,-1 . r0,-1 . [ST(t-2(t'+T-1+T+1)) - ST(t-2(2t'+T-1+T+1))] + r0,-1 . r0,-1 . [Sp(t-2(t'+T-1+2T+1)) - Sp(t-2(2t'+T-1+2T+1))] + From this it can be observed that Z+(t) is comprised of the time difference of the primary passage of the transmitted signal; and the reflected time difference of the transmitted signal, the pump signal, and the noise.

Likewise Y1(t) as it is delayed by time t' can be expressed as: Y1(t-t') = ST(t-t') + Sp(t-t') + N1(t-t') (6) + r0,-1 . ST(t-t'-2(t'+T-1)) + r0,-1 . Sp(t-t'-2T+1) + r01 r01 +1 . ST(t-t'-2(t'+T-1+T+1)) + r0,-1 . r0,+1 . Sp(t-t'-2(t'+T-1+T+1)) + r0,-1 . r0,+1 . ST(t-t'-2(2t'+2T-1+T+1)) + r0,-1 . r0,+1 . Sp(t-t'-2(t'+T-1+2T+1)) Summing circuit 88 combines Y2(t) and Y1(t-t') to form composite signal Z-(t). This composite signal Z (t) is representative of the negative or downwardly traveling energy in the mud flow stream including both the primary pump signals and the downwardly traveling reflected signals.This composite Z-(t) may be expressed as: Z-(t) = Y2(t) - Y1(t-t') (7) = [Sp(t+t') - Sp(t-t')] + [N2(t)-N1(t-t')] + r0,-1 . [ST(t-t'-2T-1)-ST(t-t'-2(t'+T-1))] + r0,-1 . r0,+1 . [Sp(t-t'-2(t'+T-1+T+1))-Sp(t-t'-2(t'+T-1+T+1))] + r0,-1 . r0,+1 . r0,+1 . [ST(t-t'-2(t'+2T-1+T+1))-ST(t-t'-2(2t'+2T-1+T+1))] + ...

Once the Z+(t) and Z-(t) have been obtained the upwardly traveling energy of the transmited signals can be extracted by applying deconvolution operators to the Z+(t) and Z~(t) signals to eliminate unwanted reflected signals. This procedure includes forming a deconvolution operator H- from an estimation of a time delay T+1 and a reflection coefficient ro,+1 then applying it to the negatively traveling energy Z~(t) and combining it with the positively traveling energy Z+(t) and a unity deconvolution operator for the reflection case. The result of this is a resultant signal, designated as R+(t), containing the representations of upwardly traveling primary transmitted signal plus a component of background noise.

An estimator circuit 92 is used to generate the deconvolution operator H- by receiving Z-(t) and Z+(t) from summing circuits 88 and 90 respectively. This operator H - is a function of the time delay from the Y1 sample location and the downstream reflector plus the time delay from the downstream reflector back to the Y2 sample location and the downstream reflection coefficient r0,1. Application of this to the downwardly traveling energy can be expressed as: H-(Z-(t)) = r0,+1 .Z-(t-t'-2T+1) = + r0,-1 . [Sp(t-2T+1) - Sp(t-2(t'+T+1))] + r0,-1 . [N2(t-t'-2T+1) - N(t-2(t'+T+1))] + r0,-1 . r0,+1 . [ST(t-2(t'+T-1+T+1-ST(t-2(2t'+T-1+T+1))] + r0,-1 . r0,+1 . [Sp(t-2(t'+T-1+2T+1))-Sp(t-2(2t'+T-1+2T+1))] + r0,-2/1 - r0,# [ST(t-4(t'+T-i+T+1)) +ST(t-2t'-4(t'+T-i+T+i))) In order to complete the deconvolution process and recover the composite signal R+(t) the Z+(t) signal must have the He Z~(t) signal representation removed therefrom as follows: R+(t) = Z+(t) - H-(Z-(t)) (9) = [ST(t) - ST(t-2t')] + [N1(t) - N2(t-t')] + r0,+1 . [N2(t-t'-2T+1) - N1(t-2(t'+T+1))] = ST(t) - ST(t-2t') + + N+(t) Operationally the output H - estimator 92 is combined with the output Z(t) of summing circuit 88 in multiplier circuit element 94.The output of multiplier circuit with delay element 94 is a negative He Z~(t) so that it can be combined with Z+(t) in summing circuit 96 to form composite signal R.+ (t).

The determination of the values for the output estimator can be accomplished by pursuing several mathematical and theoretical paths of development. What is required is an estimation of the values of the relection coefficient and the time delay; r0+1, and T+1. The determination of these is needed in order to arrive at the estimated values. This technique is included in order to illustrate one manner in which the estimated values can be arrove at in order to proceed with the object of this invention in recovering the data.

This technique is summarized from a book entitled: Geophysical Signal Analysis by Messrs. Enders A.

Robinson and Sven Treitel. The first step is to compute a cross correlation function of the portion of the sample signals within a specified time gate. Then apply a set of weighting factors to the cross correlation for different locations in the time spectrum. For such a cross correlation function the coefficients X(tj) can be derived from the following formula:

where i is a time indices in the time gate where j is a time shift index The weighted auto correlation function is defined by: P(tj) = Wj X(ti) (11) where w is a weighting factor that can be determined by separate relationship based on the time index.

For triangle weighting factors the equation is as follows:

where: (2N + 1) t is the width of the correlation window The next step in the estimation procedure is to compute the coefficients of the prediction operation from a time to to a designated time tm. Determining the coefficients of the prediction operator can also be done by several methods as is known in the mathematical art. For numerical work methods based on the Gauss method of least squares determination have certain advantages. In following this method of estimating the coefficients, a prediction operator is determined by minimizing a mean square prediction error. A set of simultaneous linear equations are generated and solved in orderto determine the cross correlation function coefficients designated as km.These linear equations are defined in the following matrix equation: Pok=pa (13)

P0P1P2 .... k0 P&alpha; P1P0P1 .... k1 P&alpha;+1 P2P1P0 .... k2 = P&alpha;+2 (14) . . . ....

Pn-1 P0 km-1 P&alpha;+m-1 where a is the prediction distance between the reflectors and n is the number of coefficients.

The next step is to solve this set of linear equations. One method of solving the equations is to use the Toeplitz recursive procedure because of its adaptability to solving the equations by use of a digital computer in a manner requiring less time than other methods of solving the equations. Solution of the equations will yield a set of weighted coefficients {k}m that can be used as the reflection coefficients and time delays used in determining a resultant signal containing the primary signal traveling in the desired direction from the composite signals Z+(t) and Z~(t) described above.

Now that resultant signal R (t) has been generated it is next fed into separate matched filters 98 and 100 for further signal processing. The matched filters are somtimes referred to as correlation filters wherein a sample signal is convolved with a desired signal (time-reversed) that is to be found in the sample signal.

Each of the matched filters 98 and 100 function similarly with the differences being in the input of the known functions A(t) and B(t) respectively for each of n = 2 symbols as shown here. Functions A(t) and B(t) are chosen to have a magnitude that output signals, go(t) and g1 (t), from the matched filters are normalized. In matched filter 98 resultant sigfnal R+(t) is convolved with signal A(t). The signal g(t) resulting from matched filter 98 is then provided as one input to a threshold detector circuit 102. The other matched filter 100 receives as one input the resultant signal R(t) and convolves it with the known signal B)t). The output signal gO(t) of matched filter 100 is then supplied as another input to detector circuit 102.

Detector circuit 102 performs several functions on the filtered signals it receives. The separate input filtered signals go(t) and 91 (t) are introduced into detector circuit 102 for evaluation in comparison. Each of the signals arriving at detector circuit 102 are compared to a threshold value Lto determine as a function of time whether or not a desired signal is present in that given received signal. Considering the input signal g(t) if it is greater than L then it is probable that the desired symbol is present in this input signal and similarly for gO(t). However if g(t) is less than Lit is probable that the desired symbol is not present.If neither one of gO(t) or g(t) are greater than L, then it is probable that then neither of the sought after symbols are present in the received signal. In the event that both g1 (t) and gO(t) are greater than L then it is assumed that the larger of these two is most probably the sought after signal. Because the representation A(t) and B(t) are normalized functions then the magnitudes of gO(t) and g,(t) provide meaningful criteria upon which to detect the larger of the responses, thereby indicating the most probable signal.

When a symbol is detected, the maximum of the signal in gO(t) or g1(t) represents the most likely synchronization point of the detection process relative to the incoming data symbols. Detector circuit 102 includes circuitry by which it adaptably tracks the incoming filtered signals to maintain synchronization. This adaptive tracking of the incoming filtered signals gO(t) and g(t) utilizes the time location of the selected prior peaks in the incoming data signals as well as its magnitude to synchronize the next timewise location for observing the next expected symbol. In this tracking process, the filtered signal strength or amplitude is weighted in a factor having an effect on detecing the succeeding symbol.

The output from detector circuit 102 is identified as X(t) and illustrated graphically in Figure 4. The output of detector circuit 102 is supplied to data processor and display 40 shown in Figure 1 for further manipulation and for presentation in data representative for the downwhole measurements taken in the earth borehole. In other words the filtered and processed data display in Figure 4 is representative of the intelligence carrying information originally derived by the measuring equipment and formatted for use by the transmitter of the downhole measurement while drilling equipment. This data can be decoded to extract its intelligence carrying information by the data processor and in turn provide a human intelligible output from this system.

In the original processing apparatus of this invention the elements contained in the dashed line box in Figure 2 can be constructed from discrete electronic circuit elements to accomplish the identified tasks. Each of these identified elements can be constructed of discrete circuits to receive, process and pass on the signal data as described above to achieve the desired result. In an alternative to this construction a special purpose digital computer can be used to functionally simulate each of the identified elements. In this construction of the invention electrical signals from the pressure sensors 30 and 32 are necessarily converted to digitized electrical signals usable by the digital computer.Also in this construction the digital computer would be configured to accomplish the several tasks or operational steps designated in Figure 2 as the signal data is received from pressure sensors 30 and 32.

In practicing this invention, several important features are to be noted; such as, the signals Y1 (t) and Y2(t) are processed to remove downwardly traveling energy in the form of reflections and primary signals and to remove upwardly traveling reflected signals. Thus data extracted in signal R (t) is representative of the primary transmitted signal. If desired the R~(t) or downwardly traveling signal can be determined through established the deconvolution operators for this direction of energy travel. Also, noise cancellation in processing extracts the intelligence information from the downhole created signal without the necessity for recreating the transmitted signal as it was leaving the downhole transmitter.Another important feature is that by using this technique, it is possible to place the pressure sensors or velocity sensors or transducers substantially closer together than is indicated in prior art in data transmission systems where the original signal is a phase modulated carrier two wave length considerations. The receiver and received signal processor portion of this apparatus prepares a composite signal with respect to the real time form of the signals that are expected from the pressure pulses within the mud carrying conduit. The received signal processor portion of this apparatus filters the composite data signal R+(t) so that an output signal X(t) is derived thereby maximizing the signal to noise power ratio of the pressure signal within which the data is communicated. From the receiver as shown schematically in Figure 2, the output signal X(t) can be utilized by additional data processing equipment (not shown) to extract the intelligence information carried by this data signal and from that reproduce representations of the measurements made by the downhole equipment.

Claims (29)

1. A method of substantially reducing reflected interference and noise contamination of a downhole transmitted signal in a logging-while-drilling system where the transmitted signal originates from a subsurface source in the form of modulated pressure waves propagating in the drilling fluid of said system, the method comprising:: (a) measuring fluid pressure in the drilling fluid at a plurality of spatially distinct locations along a portion of the drilling fluid flow path and converting such pressure measurements to corresponding electrical signals indicative of measured pressures; (b) filtering said electrical pressure measurement signals such that the output of said filtering is functionally related to that energy in said fluid pressure measurement signals which is propagating at the acoustic velocity of said drilling fluid within said portion of said drilling fluid flow path in a direction away from said transmitted signal source and further such that another output of said filtering is functionally related to that energy in said fluid pressure measurement signals that is propagating at said acoustic velocity of said drilling fluid in said portion of said drilling fluid flow path in a direction toward the subsurface transmitted signal source; (c) deconvolving said first and said second filter outputs to produce a resultant signal that is functionally related to that energy in said fluid pressure measurements corresponding to the primary passage of said transmitted signal through said portion of said drilling fluid flow path; and (d) further processing said resultant signal to maximize the signal to noise ratio thereof, and produce a recovered data signal.

2. The method of claim 1, wherein the step of filtering additionally includes: (a) time shifting one of said electrical pressure measurement signals by a time interval corresponding to the upward propagation travel time of the modulated pressure wave within the drilling fluid flow path between locations at which said pressure measurements are taken; (b) combining said time shifted electrical pressure measurement signal with the other said electrical pressure measurement signal to produce a residual electrical pressure measurement signal that has the upward propagating energy removed therefrom; (c) time shifting the other of said electrical pressure measurement signals by a time interval equivalent to the downward directed propagation travel time within said drilling fluid flow path between the locations at which the pressure measurements are taken; and (d) combining said other time shifted signal with said other electrical pressure measurement signals to produce a second residual electrical pressure measurement signal having the downward propagating energy removed therefrom.

3. The method of claim 1,wherein said step ofdeconvolving includes: (a) estimating first and second deconvolution operators from said first and said second outputs of said filtering; (b) applying said first deconvolution operator to said first output of said filtering to produce a first intermediate signal; (c) applying said second deconvolution operator to said second output of said filtering to produce a second intermediate signal; and (d) combining said first and said second intermediate signals to produce said resultant signal.

4. The method of claim 1, wherein said step of further processing additionally includes.

(a) filtering said resultant signal in a matched filter to identify actual data in the electrical pressure measurement signals from noise present in said resultant signal to produce at least one filtered resultant signal; (b) further processing said filtered resultant signal by detecting within said filtered resultant signal the presence of data that is within a predetermined range of a set of permissible values in order to produce a recovered data signal that has one value if no signal is detected, a first set of values if the filtered resultant signal exceeds a threshold value, and a second set of values if the filtered resultant signal exceeds another threshold value; and (c) synchronizing said detecting with selected substantially periodically reoccuring characteristics of said filtered resultant signals.

5. The method of claim 2 wherein the step of combining each of said time shifted electrical pressure measurement signals with the other of said electrical pressure measurement signals additionally includes generating said residual signals representative of the time difference between said time shifted electrical pressure measurement signal and said other electrical pressure measurement signal.

6. The method of claim 2 wherein said step of combining each of said time shifted electrical pressure measurement signals with the other said electrical pressure measurement signals additionally includes: (a) reversing the polarity of each said time shifted electrical measurement signals; and (b) adding each said polarity reversed and time shifted electrical pressure measurement signal to each said other pressure measurement signal thereby producing each of said residual signals.

7. The method of claim 4 wherein said filtering additionally includes convolving said composite signal with a time reverse signal representative of the said that is sought to be recovered and thereby generating said filtered electrical pressure measurement signal.

8. The method of claim 4 wherein said further processing additionally includes: (a) testing each said filtered resultant signals for a threshold determination of the filtered resultant signals for a threshold determination of the filtered signal between predeterminable values and passing signals that are determined to exceed the predetermined threshold of permissible signal values; (b) discriminating the filtered signals to determine those which are the largest of the signal value within a predetermined time interval from those signals which are not the largest or within the predetermined time interval and thereby producing a recovered data signal that is representative of the information contained in the transmitted downhole signal; and (c) said synchronizing including testing said filtered resultant signals for timewise occurence of said selected characteristics being above a predetermined value in order to predict to determine the time of synchronizing said identification of actual data from noise.

9. The method of claim 4, wherein: (a) said filtering of the resultant signal is done in time synchronization with the time occurences of the maximums of selected pressure measurement filtered signals exceeding said threshold values; and (b) said synchronization is adjusted timewise to compensate for time variations in said maximums of pressure measurement signals in order to maintain the taking of said pressure measurements in synchronization with expected occurences of selected pressure pulses.

10. A method of substantially reducing reflected interference and noise contamination of a downhole transmitted signal in a logging-while-drilling system where the transmitted signal originates from a subsurface source in the form of modulated pressure waves propagating in the drilling fluid of said system, the method comprising:: (a) measuring fluid velocity in the drilling fluid at a plurality of spatially distinct locations along a portion of the drilling fluid flow path and converting such velocity measurements to corresponding electrical signals indicative of measured velocities; (b) filtering said electrical velocity measurement signals such that the output of said filtering is functionally related to that energy in said fluid velocity measurement signals which is propagating at the acoustic velocity of said drilling fluid within said portion of said drilling fluid flow path in a direction away from said transmitted signal source and further such that another output of said filtering is functionally related to that energy in said fluid velocity measurement signals that is propagating at said acoustic velocity of said drilling fluid in said portion of said drilling fluid flow path in a direction toward the subsurface transmitted signal source; (c) deconvolving said first and second filter outputs to produce a resultant signal that is functionally related to that energy in said fluid velocity measurements corresponding to the primary passage of said transmitted signal through said portion of said drilling fluid flow path; and (d) further processing said resultant signal to maximize the signal to noise ratio thereof and produce a composite signal.

11. the method of claim 10, wherein the step of filtering additionally includes: (a) time shifting one of said electrical velocity measurement signals by a time interval corresponding to the upward propagation travel time of the modulated pressure wave within the drilling fluid flow path between locations at which said velocity measurements are taken; (b) combining said time shifted electrical velocity measurement signal with the other said electrical velocity measurement signal to produce a residual electrical velocity measurement signal that has the upward propagating energy removed therefrom; (c) time shifting the other of said electrical velocity measurement signals by a time interval equivalent to the downward directed propagation travel time within said drilling fluid flow path between the locations at which the velocity measurements are taken; and (d) combining said other time shifted signal with said other electrical velocity measurement signals to produce a second residual electrical velocity measurement signal having the downward propagating energy removed therefrom.

12. The method of claim 10, wherein said step of deconvolving includes: (a) estimating first and second deconvolution operators from said first and said second outputs of said filtering; (b) applying said first deconvolution operator to said first output of said filtering to produce a first intermediate signal; (ct applying said second deconvolution operator to said second output of said filtering to produce a second intermediate signal; and (d) combining said first and said second intermediate signals to produce said resultant signal.

13. The method of claim 10, wherein said step of further processing additionally includes: (a) filtering said resultant signal in a matched filter to identify actual data in the electrical pressure measurement signals from noise present in said resultant signal to produce a filtered resultant signal; (b) further processing said filtered resultant measurement signal by detecting within said filtered resultant signal the presence of data that is within a predetermined range of a set of permissible values in order to produce a recovered data signal that has one value is no signal is detected, a first set of values if the filtered resultant signal exceeds a threshold value, and a second set of values if the filtered resultant signal exceeds another threshold value;; (c) synchronizing said detecting with selected substantially periodically reoccuring characteristics of said filtered resultant signal to optimize the detection of the signals sought to be recovered.

14. An apparatus for substantially reducing interference and noise contamination of a downhole transmitted signal in a logging-while-drilling system where the transmitted signal originates a subsurface system in the form of modulated pressure waves propagating in the drilling fluid of said system, the apparatus comprising:: (a) means for measuring fluid pressure waves in the drilling fluid at a plurality of spatially distinct locations along a portion of the drilling fluid flow path and converting such fluid measurements to corresponding electrical signals indicative of the measured fluid pressure waves; (b) means for filtering said electrical fluid measurement signals such that the output of said filtering is functionally related to that energy in said fluid measurement signals which is propagating at the acoustic velocity of said drilling fluid within said portion of said drilling fluid flow path in a direction away from said transmitted signal source and further such that another output of said filtering is functionally related to that energy in said fluid measurement signals that is propagating at said acoustic velocity of said drilling fluid in said portion of said drilling fluid flow path in a direction toward the subsurface transmitted signal source; (c) means for deconvolving said first and said second filter outputs to produce a resultant signal that is functionally related to that energy in said fluid measurements corresponding to the primary passage of said transmitted signal through said portion of said drilling fluid flow path; and (d) means for further processing said resultant signal to maximize the signal to noise ratio thereof and produce a recovered data signal.

15. The apparatus of claim 14 wherein the step of means for filtering additionally includes: (a) means for time shifting one of said electrical fluid measurement signals by a time interval corresponding to the upward propagation travel time of the modulated pressure wave within the drilling fluid flow path between locations at which said fluid measurements are taken; (b) means for combining said time shifted electrical fluid measurement signal with the other said electrical fluid measurement signal to produce a residual electrical fluid measurement signal that has the upward propagating energy removed therefrom; (c) means for time shifting the other of said electrical fluid measurement signals by a time interval equivalent to the downward directed propagation travel time within said drilling fluid flow path between the locations at which the fluid measurements are taken; and (d) means for combining said other time shifted signal with said other electrical fluid measurement signals to produce a second residual electrical fluid measurement signal having the downward propagating energy removed therefrom.

16. The apparatus of claim 14 wherein said means for deconvolving further includes: (a) means for estimating first and second deconvolution operators from said first and said second outputs of said filtering; (b) means for applying said first deconvolution operator to said first output of said filtering to produce a first intermediate signal; (c) means for applying said second deconvolution operator to said second output of said filtering to produce a second intermediate signal;and (d) means for combining said first and said second intermediate signals to produce said resultant signal.

17. The apparatus of claim 14wherein said means for further processing additionally includes: (a) means for filtering said resultant signal in a matched filter to identify actual data in the electrical fluid measurement signals from noise present in said resultant signal to produce a filtered electrical fluid measurement signal; (b) another means for further processing said filtered resultant measurement signal by detecting within said filtered resultant signal the presence of data that is within a predetermined range of a set of permissible values in order to produce a recovered data signal that has one value if no signal is detected, a first set of values if the filtered resultant signal exceeds a threshold value, and a second set of values if the filtered resultant signal exceeds another threshold value;; (c) means for synchronizing the detecting of data in said filtered resultant signal with selected data characteristics that reoccur substantially periodically in order to optimize the detection of signals sought to be recovered.

18. The apparatus of claim 14 wherein said means for measuring fluid pressure waves has a means to measure fluid pressure in the drilling fluid at said distinct locations.

19. The apparatus of claim 14 wherein said means for measuring fluid pressure waves has a means to measure fluid velocity in the drilling fluid at said distinct locations.

20. In a logging-while-drilling system wherein a down hole signal representative of a measured downhole parameter is transmitted to the earth surface in the form of pressure modulations in the drilling fluid of the drilling system, an apparatus for substantially reducing the influence of pressure pulsation interferring noise on the downhole signal, comprising:: (a) conduit means for conducting drilling fluid from a source of drilling fluid at the earth surface to a subsurface location of the well in which the downhole signal is originating; (b) a first pressure transducer means at a first location on said conduit means for measuring the fluid pressure in said conduit means at said first location and for converting said pressure into a corresponding first electrical pressure measurement signal; (c) a second transducer means at a second location on said conduit means, spaced from said first location for measuring said fluid pressure in said conduit means at said second location and for converting said pressure into a corresponding second electrical pressure signal measurement;; (d) means for time shifting said second electrical pressure measurement signal by an amount corresponding with the upward pressure wave propagation travel time in said drilling fluid from said first transducer means to said second transducer means; (e) means for generating a first residual electrical measurement signal representative of the upward traveling time difference energy between said first and said second electrical pressure measurement signals and indicative of the primary passage of the downhole transmitted pressure pulse and reflected energy; (f) means for time shifting said first electrical pressure measurement signal by an amount corresponding to the downward pressure wave propagation travel time in said drilling fluid between said first and second presure transducer means;; (g) means for generating a second residual electrical measurement signal representative of the downward traveling time difference between said first and second electrical pressure measurement signals and indicative of the primary downward passage of the pressure pulses from said source of drilling fluid and reflected energy; (h) means for deconvolving said first residual electrical measurement signal with said second residual electrical measurement signal to derive a composite signal indicative of the primary downhole transmitted signal and to minimize reflected energy; (i) means for filtering said electrical pressure measurement signals to identify valid pressure measurement signals in said composite signals to derive a filtered signal; and (j) means for processing said filtered signal including determining the presence of a signal that is between predetermined limits and to distinguish these signals as being valid or invalid, whereupon the detection of the valid signal is made probable and the detection of the invalid signal is made improbable, and for adaptively determining detetor synchronization with the received data.

21. The logging-while-drilling system of claim 7, additionally including a means for synchronizing detection of the timewise presence of a selected characteristic of said filtered signal occurring within a selected time period spaced by a predetermined time interval in order to coordinate processing of said filtered signal to identify valid pressure measurement signals occuring at said predetermined time interval, said means for synchronizing has means to timewise adjust the detection of said selected characteristic in order to compensate for time variations in pressure pulsations in the downhole signal.

22. The apparatus of claim 20 wherein the spacing of said first and second transducer means is no closer than approximately three feet and no greater than about approximately one hundred feet.

23. The apparatus of claim 20 wherein the spacing of said first and second transducer means is no closer than about five feet and no greater than approximately about forty feet.

24. The apparatus of claim 20 wherein said filter means includes a convolving means to convolve said composite signal with a signal indicative of a signal that is sought to be recovered.

25. The apparatus of claim 24 wherein said means for processing said filtered signal includes a threshold detector means to determine of said filtered signals being between established limits, and a discriminator operable to determine whether the signal passed by the processor means should be the largest signal of those passing the threshold detector or no signal.

26. The apparatus of claim 25 wherein said synchronization means has a detector operable to detect pulse execursions in said filtered signal that are timewise within a predetermined time period and amplitude wise above a predetermined value and in relation to such signals detected respectively adjust said means for further processing to determine the presence of valid signals.

27. The apparatus of claim 20 wherein said means for deconvolving said first residual electrical measurement with said second residual electrical measurement signal includes means to repetitively use said generated second residual signal and derive said composite signal and regenerate said second residual electrical signal producing a re-estimation thereof and again deconvolving said first residual signal with said regenarated residual signal in order to obtain an improved estimate of said composite signal.

28. In a logging-while-drilling system of an earth borehole drilling system wherein a downhole signal representative of a measured downhole parameter is transmitted to the earth surface in the form of a pulse modulated pressure wave in the drilling fluid of the drilling system, an apparatus for substantially reducing the influence of interferring noise from the downhole signal, comprising:: (a) conduit means for conducting drilling fluid from a drilling fluid mud pump at the earth surface through a drill string of a well in which the downhole signal is originating; (b) a first transducer means at a first location on said conduit measn for measuring the fluid pressure therein at said first location and for converting said pressure measurement to a correpsonding first electrical pressure measurement signal; (c) a second transducer means at a second location on said conduit means, spaced downstream from said first point for measuring said fluid pressure at said second location in said conduit means and for converting said pressure measurement to a corresponding second electrical pressure signal measurement; ; (d) means for time shifting said second electrical pressure measurement signal by an amount corresponding with the pressure wave upward propagation travel time in said drilling fluid between said second transducer means and said first transducer means; (e) means for generating a first residual electrical measurement signal representative of the difference between said first and said second electrical pressure measurement signals for upwardly traveling pressure pulses in said drilling fluid; (f) means for time shifting said electrical pressure measurement signal by an amount corresponding to the downward pressure wave propagation travel time in said drilling fluid between said first and second pressure transducer means;; (g) means for generating a second residual electrical measurement signal representative of the downward traveling time difference between said first and second electrical pressure measurement signals and indicative of the downward traveling pressure waves; (h) means for deconvolving said first residual electrical measurement signal with said second residual electrical measurement signal to derive a composite signal indicative of the primary downhole transmitted signal;; (i) a filter means having a plurality of matched filter segments with one matched filter segment adapted to receive said composite signal and convolve it with a signal representative of at least one signal that is sought to be recovered, and another of said matched filter segments being adapted to receive said composite signal and convolve it with another signal representative of another signal sought to be recovered thereby producing a plurality of filtered output signals;; (j) means for processing said plurality of said filtered output signals separately including means for determining whether the amplitude of each of the signals individually exceeds predetermined limits and whether each of the signals individually occurs within predetermined time period and means for discriminating between the filtered output signals to provide an output signal representative of the measured downhole parameter; and (k) means for synchronizing said predetermined time periods for the next expected occurences of selected characteristics of said filtered output signals occurring within said time periods and at selected time intervals and being above predetermined signal values in order to optimize detection of the signals sought to be recovered.

29. In a logging-while-drilling system wherein a downhole signal representative of a measured downhole parameter is transmitted to the earth surface in the form of pressure modulations in the drilling fluid of the drilling system, an apparatus for substantially reducing the influence of pressure pulsation interferring noise on the downhole signal as received at the earth surface, comprising:: (a) conduit means for conducting drilling fluid from a source of drilling fluid at the earth surface to the bottom of the well in which the downhole signal is originating; (b) a first fluid velocity transducer means at a first location on said conduit means for measuring the fluid velocity in said conduit means at said first location and for converting said measurement into a corresponding first electrical measurement signal; (c) a second transducer means at a second location on said conduit means, spaced from said first location for measuring said fluid velocity in said conduit means at said second location and for converting said measurement into a corresponding second electrical signal measurement;; (d) means for time shifting said second electrical measurement signal by an amount corresponding with the upward pressure wave propagation travel time in said drilling fluid from said first transducer means to said second transducer means; (e) means for generating a first residual electrical measurement signal representative of the upward traveling time difference energy between said first and said second electrical pressure measurement signals and indicative of the primary passage of the downhole transmitted pressure pulse and reflected energy; (f) means for time shifting said first electrical measurement signal by an amount corresponding to the downward pressure wave propagation travel time in sais drilling fluid between said first and second pressure transducer means;; (g) means for generating a second residual electrical measurement signal representative of the downward traveling time difference between said first and second electrical measurement signals and indicative of the primary passage of the pressure pulses from said source of drilling fluid and reflected energy; (h) means for deconvoiving said first residual electrical measurement signal with said second residual electrical measurement signal to derive a composite signal indicative of the primary downhole transmitted signal and to minimize reflected energy; (i) means for filtering said electrical measurement signals to identify valid measu rement signals in said composite signals to derive a filtered signal; and (j) means for processing said filtered signal including determining the presence of a signal that is between predetermined limits and to distinguish these signals as being valid or invalid, whereupon the detection of the valid signal is made probable and the detection of the invalid signal is made improbable, and for adaptively determining detector synchronization with the received data.