GB2121572A - Logging while drilling system - Google Patents
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- GB2121572A GB2121572A GB08313695A GB8313695A GB2121572A GB 2121572 A GB2121572 A GB 2121572A GB 08313695 A GB08313695 A GB 08313695A GB 8313695 A GB8313695 A GB 8313695A GB 2121572 A GB2121572 A GB 2121572A
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- 238000005553 drilling Methods 0.000 title claims abstract description 52
- 230000010349 pulsation Effects 0.000 claims abstract description 21
- 238000000034 method Methods 0.000 claims abstract description 17
- 230000001902 propagating effect Effects 0.000 claims abstract description 3
- 239000012530 fluid Substances 0.000 claims description 40
- 238000009530 blood pressure measurement Methods 0.000 claims description 33
- 239000002131 composite material Substances 0.000 claims description 33
- 238000005259 measurement Methods 0.000 claims description 29
- 238000012545 processing Methods 0.000 claims description 16
- 238000001914 filtration Methods 0.000 claims description 7
- 230000005540 biological transmission Effects 0.000 claims description 6
- 238000001514 detection method Methods 0.000 claims description 5
- 230000008859 change Effects 0.000 description 5
- 230000008569 process Effects 0.000 description 4
- 244000261422 Lysimachia clethroides Species 0.000 description 3
- 238000011084 recovery Methods 0.000 description 3
- 230000015572 biosynthetic process Effects 0.000 description 2
- 230000003111 delayed effect Effects 0.000 description 2
- 230000000694 effects Effects 0.000 description 2
- 238000005755 formation reaction Methods 0.000 description 2
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- 239000000284 extract Substances 0.000 description 1
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- 230000035485 pulse pressure Effects 0.000 description 1
- 230000035939 shock Effects 0.000 description 1
- 230000003068 static effect Effects 0.000 description 1
Classifications
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- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B47/00—Survey of boreholes or wells
- E21B47/12—Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling
- E21B47/14—Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling using acoustic waves
- E21B47/18—Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling using acoustic waves through the well fluid, e.g. mud pressure pulse telemetry
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- Mining & Mineral Resources (AREA)
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- Environmental & Geological Engineering (AREA)
- Fluid Mechanics (AREA)
- Geophysics (AREA)
- Acoustics & Sound (AREA)
- General Life Sciences & Earth Sciences (AREA)
- Geochemistry & Mineralogy (AREA)
- Geophysics And Detection Of Objects (AREA)
- Measuring Fluid Pressure (AREA)
Abstract
A method for recovering data from a data signal originating from a downhole apparatus and transmitted to the earth's surface through drilling mud comprises measuring pressure pulsations in a mud flow line at the earth's surface in two spaced apart locations (30, 32). One of the measured pressure pulsation signals is time shifted an amount equal to the travel time of the group propagation acoustic velocity in the mud between the two pressure sensors (30, 32), and one of the two signals has its polarity reversed. The two signals are then combined to cancel any downward propagating energy from the combined pressure data signal. The combined pressure data signal is then processed by each of n matched filters (46, 48) in a baseband PCM system 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 detector (50) to identify either the presence of a symbol or absence of the data signal. <IMAGE>
Description
SPECIFICATION
Method and apparatus for signal recovery in a logging while drilling system
Technical field
This invention is related to measurement while drilling systems for earth boreholes. More specifically it is related to the telemetry of data signals in such systems and the reception, detection and processing of these signals at the earth's surface.
Background of the invention
The desirability and usefulness of a 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 down hole 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 particlar strong points.
This invention is directed to a telemetry system that transfers the information by means of pressure pulsations of the drilling fluid or mud that is normally associated with rotary drilling operations. The pressure pulsations that are representative of the data signal of a particular parameter are generated by a downhole apparatus near the drilling bit and the pressure pulsations pass upward through mud in the drill string to a signal detector at the earth's surface. In this system the pressure pulses are passed upward through the interior of the drill string via the medium of the circulating drilling mud.
Pressure pulse transmission through the drilling mud in the interior of a drill string encounters certain difficulties due to extraneous vibrations, shocks and pressure pulses that are placed in this fluid system by operation of the drilling equipment. Some of these pressure pulses and noises are of a magnitude at least as great as the transmitted pressure pulse from the down hole transmitting equipment. Also these pressure pulses are reflected within the drill string at certain locations that present a significant impedance change in the pressure pulse wave guide provided by the drill string. These reflected pressure pulses are also passed through the drill string to further complicate the signal identification.All of this pressure pulsation and pressure pulsation noise generation and reflection within the drill string creates a noise environment in which the data signal is traveling and from which it must be recovered.
In prior signal 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 nature. One problem is that resonances of the transmitted pressure pulse waves can be a source of interference 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. A result of this difficulty in separating signals is that reflected pressure waves can be mistaken for real data and additional data processing is needed to extract valid data from the available data.
According to one aspect of the present invention there is provided a method of substantially reducing uphole noise from a downhole signal in a logging-while-drilling system where said downhole signal is in the form of a pulse modulated pressure waves being transmitted in the drilling fluid of said system, said method comprising::
a) measuring the fluid pressure in the drilling fluid at a first point and at a second point respectively, and converting both pressure measurements to corresponding electrical signals indicative of the measured pressures, said first and second points being spaced from each other along the drilling fluid flow path between a source of drilling fluid and a downhole portion of a well in which said downhole signal is originating;
b) time shifting one of said electrical pressure measurement signals by an amount corresponding with the propagation time of the pulse modulated pressure wave within said drilling fluid flow path from one of said points to the other;;
c) combining said time shifted to the electrical pressure measurement signal with the other said electrical pressure measurement signal to produce a composite electrical measurement signal in order to substantially remove the downward propagating energy therefrom; and
d) filtering said composite electrical pressure measurement signal in a matched filter to identify actual data in the electrical signals from noise present in the composite electrical measurement signal to produce a filtered electrical pressure measurement signal and further processing said filtered electrical measurement signal by detecting within said signal the presence of data that is within a predetermined range of being within a set of permissible values to produce a recovered data signal that has one value if no signal is detected, a first set of values if the filtered electrical measurement signal exceeds a threshold value, a second set of values if the filtered electrical measurement signal exceeds another threshold value.
The invention will be better understood from the following description of a preferred embodiments thereof, given by way of example only, reference being had to the accompanying drawings, wherein:
Figure lisa 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;
Figure2 is a schematic block diagram of a portion of the data receiving portion of this system illustrating the cooperative relationship of the elements of the present invention;
Figure 3 is a graph illustrating the output signals of the received signal processor illustrated in Figure 2.
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 inciination of the borehole at that location or it can contain devices to measure temperature, pressure, weight as applied to the bit or any of a variety of other parameters 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 with drill string 10. 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 will function with baseband pulse code modulation and, with some modifications to the detection filtering exponential modulation. 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.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 drill string. Major influences on these reflections are the junctures in the fluid path at the swivel connection 22, the gooseneck 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 22. 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 from mud pump 28 to gooseneck 24.
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 pressure 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 signal representative of the fluid pressure in the mud filled conduit.
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 undisturbed between the segment of a conduit. Spacing between pressure sensors 30 and 32 can be 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). 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 connected 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 flow stream and the associated apparatus for processing the received signals. Pressure transducers 30 and 32 are spaced apart a distance don 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 intelligence carrying transmitted signal ST iS moving from the right to the left while the pump noise signal Sp is shown moving in the opposite direction on the left side of the figure moving toward the right. The output from transducer 30 passes through a time delay and polarity reversal circuit 42 and then to a summing circuit 44. The output from the other pressure transducer 32 is connected directly to summing circuit 44. Summing circuit 44 combines its two inputs to produce a single composite output signal representative of the combined received signals.
This composite signal is a signal representative of the time difference residual of the combined received signals. This composite signal is then passed to the processor portion of the apparatus, indicated generally at 40. Initially the composite signal enters a set of n detection filters that function to maximize the ability to detect a symbol (wavelet in PCM) from all other symbols and to do so in the presence of accompanying noise. After this, the resultant or filtered signals are passed to a threshold detector where they are examined for the presence of an actual signal (symbol) that is sought, then the resultant output is provided as binary coded bit stream.This output is representative of the data produced by the downhole measurement while drilling equipment and this data is appropriately coded to be indicative of geophysical parameters and other data sensed by the downhole apparatus.
Returning to the schematic of Figure 2 for discussion in further detail. The conduit 34 is for purposes of this discussion a segment of pipe, tubing or other flow conduit in the mud line or flow path between the mud circulating pump 28 and swivel 22. 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 the 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 the monitored pressure signal at one of the pressure sensors will be substantially the same as that monitored at the other pressure sensor and any modification of the flow conditions between the pressure sensors can be neglected.
Pressure sensors 30 and 32 are spaced from each other along conduit 34 at a distance d. Pressure sensors 30 and 32 can be any commercially available type of pressure transducer that will within a predetermined accuracy measure pressure or the presence of the pressure wave in the mud at the appropriate point in the conduit and convert this to a corresponding electrical 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 or the pulse pressure wave in the mud at that location in conduit 34. The outputs from pressure sensors 30 and 32 are preferably matched or adjusted so the relative output signal magnitudes of 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. Using pressure sensor 32 as a reference point the signal from it is designated as y(t). At any point in time, t, the signal at pressure sentor 32 is equal to the pressure 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.The presence of a reflected pump signal is recognized however it has been determined that this signal is of a substantially insignificant value when considered in view of the relative magnitudes and effects of the other pressure signals involved. In the following it is assumed that two (2), reflectors are present in the system. One reflector being downstream of the pressure sensors and the other being upstream of the pressure sensors.
These reflections occur as the pressure waves pass from one impedance zone of the flow path to another.
These impedance changes occur at obstructions in the waveguide formed by drill string 10 and the conduits connecting it to mud circulating pump 28. Also these impedance changes occur at junctions of the flexible conduit of gooseneck 24 with swivel 22 and standpipe 26. In the following a change in impedance is referred to as change from one impedance medium to another.The relationship of the pressure at any pressure sensor placed along the conduit may be expressed as:
Yn(t) = ST(t) + Sp(t) + Nn(t) + r0,+1 r0,-1S(t+T1) + r0,+ Sp (t+T+1) + ... where:
Yn(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 down hole transmitter,
Sp(t) is the pump generated signal,
Nn(t) is the noise observed by the nth pressure transducer, and:: rio +1 is the first reflection coefficient downstream of the transducers r0,1 is the first reflection coefficient upstream of the transducers
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 distanced separating the two pressure sensors and the associated delay in pressure wave propagation time. The actual time differential involved and depends upon the propagation time between the separate pressure sensors which is a function of the velocity of the pressure wave within conduit 34.
The signal Y1(t) at pressure transducer 32 can be expressed as:
And the signal Y2(t) at pressure transducer 30 can be expressed as:
where: rid j is the reflection coefficient of wave moving from medium i of impedance Zj into another medium j of impedance Zj.
t' is the propagation time between transducers 30 and 32, the locations of observing Y2(t) and Y,(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, (Y1(t)), 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 betwen 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 one reference point for well to surface traveling pressure signals can be established. In this system Y2(t) is delayed by time t' through time delay element 42 as shown in Figure 2.
The sign change is necessary so that noise canceling will take place when the signals are combined by summing circuit 44. Y2(t) as it is delayed by time t' can be expressed as follows:
Summing circuit 44 combines the two signals Y1(t) and Y2(t-t') into a composite signal Z+(t). This composite signal Z+(t) is representative of the combined received signal of the mud pressure sensors representative of positive or upwardly traveling energy. This composite signal is the resultant output of receiver 36 and is ready for operations of the data processor apparatus 40.This composite signal Z(t) may be expressed as:
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. By considering the reflection coefficients to be so small as to render the reflection coefficient terms neglectable then the expression of Z+(t) can be simplied to: Z+(t) = ST(t) - ST(t-2t') + N1(t) - N2(t-t') The expression can be further simplified by generalizing the noise component in terms of Gaussian noise representation. If N(t) and N2(t) are assumed to have a Gaussian distribution wherein they are uncorrelated and have an essentially equal variance.With this assumption the noise term would be represented as N*(t) with that term being a normalized Gaussian noise factor. Therefore, the composite signal can be represented as: Z+(t) = ST(t) - ST(t-2t') - N*(t) The composite signal Z+(t) that has been generated is next fed into separate matched filters 46 and 48. The matched filters are sometimes 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 46 and 48 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 such that output signals, gO(t) and g, (t), from the matched filters are normalized. In matched filter 46 composite signal Z+(t) is convolved with signal A(t). The signal g1(t) resulting from matched filter 46 is then provided as one input to a threshold and detector circuit 50. The other matched filter 48 receives as one input the composite signal Z+(t) and convolves it with the knownn signal B(t). The output signal gO(t) of matched filter 48 is then supplied as another input to detector circuit 50.
Detector circuit 50 performs several functions on the signals it receives. The separate input signals gO(t) and g(t) are introduced into detector circuit 50 for evaluation in comparison. Each of the signals arriving at detector circuit 50 are compared to a threshold value L to determine as a function of time whether or not a desired signal is present in that given received signal gO(t) or g(t). Considering the input signal g1(t) if it is greater than Lthen it is probable that the desired symbol is present in this input signal. However if g1(t) is less than Lit is probable that the desired signal is not present. if neither one of g0(t) or gl(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 L1 or L2 respectively 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 normalied functions then the magnitudes of g0(t) and g1 (t) provide meaningful criteria upon which to detect the larger of the responses, thereby indicating the most probably signal.
When a symbol is detected, the maximum of the signal represents the most likely synchronization point of the detection process relative to the incoming data symbols in gO(t) and g1(t). Detector circuit 50 includes circuitry by which it adaptably tracks the incoming data signals to maintain synchronization. This adaptive tracking of the incoming signals utilizes the time location of the selected peak in the incoming data signal as well as its magnitude to synchronize the next timewise location for observing the next expected symbol. In this tracking process, the signal strength or amplitude is weighted in a factor having an effect on detecting the succeeding symbol.
The output from detector circuit 50 is identified as X(t) and illustrated graphically in Figure 3. The output of detector circuit 50 is supplied to data processor and display 40 shown in Figure 1 for further manipulation and for presentation in data representative for the downhole measurements taken in the earth borehole. In other words the filtered and processed data displayed in Figure 3 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 practicing this invention, several important features are to be noted including the noise cancellation in processing that extracts the intelligence carrying portion of the down hole created signal without the necessity for recreating the transmitted into the modulated form that it had when leaving the down hole transmitter. Another important feature is that by using this technique, it is possible to place the pressure 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 to 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 Z+(t) so that an output signal X(t) is maximized when there is truly a data signal to be extracted, thereby minimizing the noise that is present within the measured pressure signal within which the data is communicated. From receiver 36, as shown 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 (14)
1. A method of substantially reducing uphole noise from a downhole signal in a logging-while-drilling system where said downhole signal is in the form of a pulse modulated pressure waves being transmitted in the drilling fluid of said system, said method comprising:
a) measuring the fluid pressure in the drilling fluid at a first point and at a second point respectively, and converting both pressure measurements to corresponding electrical signals indicative of the measured pressures, said first and second points being spaced from each other along the drilling fluid flow path between a source of drilling fluid and a downhole portion of a well in which said downhole signal is originating;;
b) time shifting one of said electrical pressure measurement signals by an amount corresponding with the propagation time of the pulse modulated pressure wave within said drilling fluid flow path from one of said points to the other;
c) combining said time shifted to the electrical pressure measurement signal with the other said electrical pressure measurement signal to produce a composite electrical measurement signal in order to substantially remove the downward propagating energy therefrom; and
d) filtering said composite electrical pressure measurement signal in a matched filter to identify actual data in the electrical signals from noise present in the composite electrical measurement signal to produce a filtered electrical pressure measurement signal and further processing said filtered electrical measurement signal by detecting within said signal the presence of data that is within a predetermined range of being within a set of permissible values to produce a recovered data signal that has one value if no signal is detected, a first set of values if the filtered electrical measurement signal exceeds a threshold value, a second set of values if the filtered electrical measurement signal exceeds another threshold value.
2. The method of claim 1 wherein the step of combining said time shifted electrical pressure measurement signal with the other of said electrical pressure measurement signals additionally includes;
generating a composite signal representative of the difference between said time shifted electrical pressure measurement signal and said other electrical pressure measurement signal.
3. The method of claim 1 wherein said step of combining said time shifted electrical pressure measurement signal with the other said electrical pressure measurement signal additionally includes:
a) reversing the polarity of said time shifted electrical measurement signal; and
b) adding said polarity reversed and time shifted electrical pressure measurement signal to said other pressure measurement signal thereby producing a composite signal.
4. The method of claim 3 wherein said filtering additionally includes:
convolving said composite signal with a time reverse signal representative of each of the transmitted pulse symbols that is sought to be recovered thereby generating a filtered signal.
5. The method of claim 4 wherein said processing additionally includes:
a) testing each said filtered signal for a threshold determination of the filtered signal being 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 values 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 tht is representative of the transmitted down hole signal; and
c) synchronizing said measuring the fluid pressure with the timewise occurrence of said discriminating the filtered signals to predict the time of taking said measurements of said fluid pressure.
6. The method of claim 1,wherein:
a) filtering of the composite filtered signals is done in time synchronization with the time occurrences 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 measurements in synchronization with
expected occurrences of selected pressure pulses.
7. 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 a pressure pulse in the drilling fluid of the 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 the well in which the downhole signal is originating;
b) a first transducer means at a first point on said conduit means for measuring the fluid pressure in said conduit means at said first point and for converting said pressure into a corresponding first electrical
pressure measurement signal;
c) a second transducer means at a second point on said conduit means, spaced from said first point for
measuring said fluid pressure in said conduit means at said second point 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 pressure wave propogation travel time in said drilling fluid from one of said transducer means to the other said transducer means;
e) means for generating a composite electrical measurement signal representative of the difference between said first and said second electrical pressure measurement signals;
f) means for filtering said composite electrical pressure measurement signal to identify valid pressure measurement signals in said composite signals to derive a filtered signal; and
g) means for processing said filtered signal including determining the presence of a signal that is between predetermined limits and to differentiate these signals as being valid whereupon a transmission of the valid signal is made or a transmission of no signal is made, and for adaptively determining detector synchronization with the transmitted data.
8. The logging-while-drilling system of claim 7, additionally including a means for synchronizing signals from said first and said second transducer means with said means for processing said filtered signal in order to coordinate processing of said filtered signal to identify valid pressure measurement signals, said means for synchronizing has means to timewise adjust the synchronization of the signals in order to compensate for time variations in pressure pulsations in the downhole signal.
9. The apparatus of claim 7, wherein:
the spacing of said first and second transducer means is no closer than about approximately three feet and no greater than about approximately one hundred feet.
10. The apparatus of claim 7, wherein the spacing of said first and second transducer means is no closer than about five feet and no greater than approximately about thirty feet.
11. The apparatus of claim 7, 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.
12. The apparatus of claim 11, wherein;
said processing means includes a threshold detector means to determine the presence of filtered signals 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.
13. The apparatus of claim 12,wherein: said processing means includes a synchronization means operable with said processing means said first and second transducer means and said means for generating a composite signal to optimize the detection of these signals sought to be recovered by synchronizing said means for filtering said composite signal with said discriminator.
14. 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 a pulse modulated pressure wave in the drilling fluid of the 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 source of drilling fluid at the earth surface to a drill string of the well in which the downhole signal is originating;
b) a first transducer means at a first point on said conduit means for measuring the fluid pressure at said first point in said conduit means and for convering said pressure measurement into a corresponding first electrical pressure measurement signal;
c) a second transducer means at a second point on said conduit means, spaced from said first point for measuring said fluid pressure at said second point in said conduit means and for converting said pressure measurement 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 pressure wave propogation travel time in said drilling fluid from one of said transducer means to the other said transducer means;
e) means for generating a composite electrical measurement signal respresentative of the difference between said first and said second electrical pressure measurement signals;
f) 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 indicative of 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 indicative of another signal sought to be recovered thereby producing a
plurality of filtered output signals; ;
g) 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 limits, and means for
discriminating between the filtered output signals to provide an output signal representative of the
measured down hole parameter; and
h) means for synchronizing said predetermined time limits with expected occurrences of the pulse
modulated pressure waves in the drilling fluid being detected by said first and second transducer means.
Applications Claiming Priority (1)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| US38707682A | 1982-06-10 | 1982-06-10 |
Publications (3)
| Publication Number | Publication Date |
|---|---|
| GB8313695D0 GB8313695D0 (en) | 1983-06-22 |
| GB2121572A true GB2121572A (en) | 1983-12-21 |
| GB2121572B GB2121572B (en) | 1985-12-04 |
Family
ID=23528356
Family Applications (1)
| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| GB08313695A Expired GB2121572B (en) | 1982-06-10 | 1983-05-18 | Logging while drilling system |
Country Status (4)
| Country | Link |
|---|---|
| CA (1) | CA1206089A (en) |
| DE (1) | DE3321138A1 (en) |
| FR (1) | FR2528491A1 (en) |
| GB (1) | GB2121572B (en) |
Cited By (5)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| EP0588390A1 (en) * | 1992-08-21 | 1994-03-23 | Anadrill International SA | Transmitting data at different frequencies in a logging while drilling tool |
| EP1053488A1 (en) * | 1998-01-27 | 2000-11-22 | Halliburton Energy Services, Inc. | Multiple transducer mwd surface signal processing |
| GB2438050A (en) * | 2006-05-10 | 2007-11-14 | Schlumberger Holdings | Wellbore telemetry and noise cancellation methods |
| US8629782B2 (en) | 2006-05-10 | 2014-01-14 | Schlumberger Technology Corporation | System and method for using dual telemetry |
| EP2592444A3 (en) * | 2010-06-21 | 2016-05-11 | Halliburton Energy Services, Inc. | Mud pulse telemetry |
Families Citing this family (1)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| CN106850479B (en) * | 2017-02-15 | 2020-02-14 | 中国石油大学(华东) | Drilling fluid continuous wave frequency continuous phase smooth coding modulation and demodulation system and method |
Family Cites Families (4)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US3742443A (en) * | 1970-07-27 | 1973-06-26 | Mobil Oil Corp | Apparatus for improving signal-to-noise ratio in logging-while-drilling system |
| US3747059A (en) * | 1970-12-18 | 1973-07-17 | Schlumberger Technology Corp | Electronic noise filter with means for compensating for hose reflection |
| US3716830A (en) * | 1970-12-18 | 1973-02-13 | D Garcia | Electronic noise filter with hose reflection suppression |
| NO790496L (en) * | 1978-02-27 | 1979-08-28 | Schlumberger Technology Corp | METHOD AND DEVICE FOR DEMODULATING SIGNALS IN A BURGING LOGGING SYSTEM |
-
1983
- 1983-05-11 CA CA000427966A patent/CA1206089A/en not_active Expired
- 1983-05-18 GB GB08313695A patent/GB2121572B/en not_active Expired
- 1983-06-08 FR FR8309500A patent/FR2528491A1/en not_active Withdrawn
- 1983-06-10 DE DE19833321138 patent/DE3321138A1/en not_active Withdrawn
Cited By (13)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| EP0588390A1 (en) * | 1992-08-21 | 1994-03-23 | Anadrill International SA | Transmitting data at different frequencies in a logging while drilling tool |
| EP1053488A1 (en) * | 1998-01-27 | 2000-11-22 | Halliburton Energy Services, Inc. | Multiple transducer mwd surface signal processing |
| EP1053488A4 (en) * | 1998-01-27 | 2001-09-26 | Halliburton Energy Serv Inc | Multiple transducer mwd surface signal processing |
| US9766362B2 (en) | 2005-07-05 | 2017-09-19 | Schlumberger Technology Corporation | System and method for using dual telemetry |
| US8502696B2 (en) | 2006-05-10 | 2013-08-06 | Schlumberger Technology Corporation | Dual wellbore telemetry system and method |
| US8004421B2 (en) | 2006-05-10 | 2011-08-23 | Schlumberger Technology Corporation | Wellbore telemetry and noise cancellation systems and method for the same |
| GB2438050B (en) * | 2006-05-10 | 2009-06-24 | Schlumberger Holdings | Wellbore telemetry and noise cancellation systems and methods for the same |
| US8629782B2 (en) | 2006-05-10 | 2014-01-14 | Schlumberger Technology Corporation | System and method for using dual telemetry |
| GB2438050A (en) * | 2006-05-10 | 2007-11-14 | Schlumberger Holdings | Wellbore telemetry and noise cancellation methods |
| EP2592444A3 (en) * | 2010-06-21 | 2016-05-11 | Halliburton Energy Services, Inc. | Mud pulse telemetry |
| EP2592445A3 (en) * | 2010-06-21 | 2016-05-11 | Halliburton Energy Services, Inc. | Mud pulse telemetry |
| US9638033B2 (en) | 2010-06-21 | 2017-05-02 | Halliburton Energy Services, Inc. | Mud pulse telemetry |
| US10472956B2 (en) | 2010-06-21 | 2019-11-12 | Halliburton Energy Services, Inc. | Mud pulse telemetry |
Also Published As
| Publication number | Publication date |
|---|---|
| GB8313695D0 (en) | 1983-06-22 |
| GB2121572B (en) | 1985-12-04 |
| FR2528491A1 (en) | 1983-12-16 |
| CA1206089A (en) | 1986-06-17 |
| DE3321138A1 (en) | 1983-12-15 |
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Legal Events
| Date | Code | Title | Description |
|---|---|---|---|
| PCNP | Patent ceased through non-payment of renewal fee |