GB1598340A

GB1598340A - Telemetry system

Info

Publication number: GB1598340A
Application number: GB5413977A
Authority: GB
Original assignee: Sperry Sun Inc
Current assignee: Sperry Sun Inc
Priority date: 1976-12-30
Filing date: 1977-12-29
Publication date: 1981-09-16
Also published as: DE2758770C2; FR2376288B1; JPS622113B2; JPS53101453A; DE2758770A1; FR2376288A1; BR7708730A; CA1098202A

Description

(54) TELEMETRY SYSTEM (71) We, SPERRY SUN INC., a corporation organised under the laws of the State of Delaware of P.O. Box YO, Sugar Land, Texas 77478, United States of America, do hereby declare the invention, for which we pray that a patent may be granted to us, and the method by which it is to be performed, to be particularly described in and by the following statement: This invention relates to a drill stem telemetry system, and, more particularly, to a means for transmitting data through a drill stem from the bottom of a wellbore to the surface, and vice versa, utilizing acoustic telemetry. In the context of the present invention, the term "telemetry" also includes the transmission of signals for remote control between the surface and a downhole location.The need for means of transmitting downhole data to the surface during the process of a drilling operation has been recognized in the oil industry since the inception of modern drilling techniques. However, in recent years, with the advent of deeper drilling operations and technical innovations which permit the detection of downhole parameters useful at the surface during a drilling operation, the need for such a telemetry system has increased, and, as a result, the effort expended by the oil industry towards developing such systems has increased proportionately. An example of this need occurs when the driller needs a form of communicating from downhole to the surface information as to the type of formation which is being drilled.Since the optimum combination of rotary speed and weight on a drill bit changes significantly with the type of formation being drilled (e.g. sand, shale, limestone or chert), a driller is unable to optimize the penetration rate without this corresponding information. Attempts have been made to develop logging while drilling systems, one such device being set forth in U.S. Patent No.

2.755.431, but at present no system has found widespread acceptance in the industry for various reasons. Some systems have utilized cables for transmitting information from downhole to the surface but require complete withdrawal of the cable or making of connections in the cable at the surface each time a section of pipe is added. This is a cumbersome and time-consuming operation and has not received acceptance. Attempts have been made to develop electrically conductive paths within a string of pipe by the use of pipe couplings which incorporate electrical conductors. Again, such systems have not been developed in this country to an acceptable commercial use level. Even though the technical feasibility of such a system has been demonstrated, it requires a special drill string at greatly increased cost.

Hole deviation from the vertical and in what direction such deviation takes place are other parameters of importance in drilling operation. Such directional survey information is most important on wells which are intentionally deviated, in order to drain reservoir locations which are inaccessible or extremely costly to reach by vertical drilling. Early examples of this type of drilling are the Huntington Beach and Ventura fields in California.

These fields are located on the Pacific shoreline, with most of the area of the reservoir beneath the ocean. In the 1930's and early 1940's when these fields were being drilled, it was necessary to devise techniques and to develop tools for controlling directional drilling so that land-based rigs could tap the oil beneath the ocean. The directional drilling process, then as well as now, was made more complex and expensive because of the lack of any means for telemetering these data from the bottom of the hole to the surface. As a result, such data were taken by photographic or chemical means onto instruments which were retrieved to the surface either through pulling the pipe or locating such instruments at the end of a wire line or cable which was retrieved from the wellbore after discontinuing the drilling operation.This was, of course, a costly and time-consuming operation which is aggravated in modern drilling times because of the sometimes extreme depth of wells which necessarily involves a long time factor when retrieving data by means of a wire line. Also, the high expense of operating drilling rigs, particularly in hostile environments such as offshore areas where rig time is extremely expensive becomes a very important factor since, as indicated above, the cessation of drilling is necessary in order to retrieve data.

During the 1940's a number of companies recognized the economic potential of a telemetry system and initiated research to develop one. Most of this work was carried on by these companies independently but, invariably, after studying many of the possible transmission methods, they arrived at the same conclusion that sound transmission through the metal of the drill pipe was most promising. Electromagnetic (radio) transmission was considered a poor second because of rapid attenuation of such signals in the formations of the earth. Since the rate of attenuation of sound in steel was known to be quite low, it was logical to assume that sound signal transmission through the metal wall of the drill pipe would be relatively simple. However, this turned out to be far from the case.In 1948, the Sun Oil Co., built a system for testing the feasibility of drill pipe acoustic telemetry, which consisted of a downhole impulse sound source and a surface package designed to receive transmitted sound and to measure its amplitude in each of three frequency bands. The sound source contained a battery-powered motor which wound up a spring. When fully wound, the spring was released and drove a weight to deliver a sharp hammer blow to the end of the drill pipe. The receiving equipment consisted of an accelerator attached to the drill pipe having its output connected to an amplifier which in turn fed three band pass filters for separating the energy spectrum into low, medium and high frequency bands, respectively. The results of this feasibility study were very disappointing.The attentuation rate varied somewhat between the three bands, but was so high even in the best range as to discourage any further efforts along this line. Sun Oil concluded that acoustic telemetry was not feasible within the state of the art existing in 1948. This telemetry research project was dropped and was not reinstated until about 1969 when it was considered practical to use repeaters to overcome the high attenuation rate.

Another company doing research at that time was in the principal business of gun perforation of casing. Perforating casing is an essential step in completing oil and gas wells in which the well was drilled and cased through the producing sand as opposed to the earlier and less satisfactory practice of setting the casing just above the producing sand and drilling in for an open hole completion. This company became interested in radioactive (gamma ray) logging as a means of logging cased holes, first in order to control their perforating guns more precisely, but also as a means of locating other potential producing zones behind the casing. This company established a well logging research laboratory around 1948 and one of the major projects was that of downhole telemetry. Their research programme began in a very similar way to that of the Sun Oil Co.After examining the alternatives, they chose drill pipe acoustic telemetry as the most promising course and set out as did Sun to measure the acoustic attenuation rate of the drill pipe. The final tests in this programme were convincing that drill stem acoustic telemetry was not possible. This latter test was conducted as follows: the downhole sound source consisted of a set of jars which were arranged to drop a section of drill collar about 3 feet each time the jars were actuated. On the surface, a geophone was used as the detector and was probably fed into a seismic amplifier and recorder system. The attenuation rate measured by this method was so high as to convince the experimenter that sound transmission through the drill pipe was impractical.They felt it necessary to switch their efforts to a mud pulse transmission method and to accept the greatly reduced rate of data transmission which was implied by a mud pulse system. The company continued work on the mud pulse telemetry system until the technology was sold to another party which attempted to market the system as a means of logging while drilling. In any event, the conclusion of this company that mud pulse telemetry was the only way to go, apparently influenced much of the subsequent telemetry research so that much of the research currently taking place in the field of drill stem telemetry is centred about a technique known as mud pulse telemetry. The mud pulse system involves much more complex hardware and a slower data rate over the potentially cheaper and faster acoustic drill pipe system.

The Sun Oil Co. resumed research on drill pipe acoustic telemetry in 1968, fully aware that attenuation rates would be high, but hoping to overcome this difficulty by using a number of repeater stations. Based on the attentuation measurements made in 1948. of about 12 decibels per thousand feet, it appeared feasible to use a system of repeaters spaced along the drill pipe, each receiving data from the station below at one frequency and re-transmitting at another frequency to the next station above. A transmitter and repeater system was built up to operate in this manner. In order to achieve maximum discrimination against noise, the transmission was digital and used either a single crystal controlled frequency which was turned on for one and off for zero, or in some cases a pair of closely spaced frequencies with one frequency representing a one and the other frequency a zero.

Thus, the new system differed from the 1948 experiment only in that discrete frequencies were used rather than a broad band source such as the weight and spring. In order to use the multiple repeater system, three transmission frequencies were needed for the on-off logic or six for the two-frequency logic. Therefore, an arbitrary selection was made. For the two-frequency logic system, the following pairs of frequencies were chosen: 860-880 Hertz (Hz), 1060-1080 Hz and 1260-1280 Hz. All of these frequencies were within a band for which the 1948 test indicated the attenuation rate should be in the 10-12 decibels per thousand feet range. The first field test was run using the 860-880 Hz band. This test confirmed the 10-12 decibel per thousand feet anticipated as an attenuation rate and indicated the feasibility of the repeater system as planned.

However, when it was attempted to transmit in the 1060 to 1080 Hz band, attenuation was found to be so great that no satisfactory data could be received in order to measure the exact attenuation rate. In a period of a little over a year from these first tests, a number of other frequencies were tried, but none was found to equal the 860 Hz band. It is to be remembered that there was no basis for selecting one frequency over any other, the choice being entirely random. Furthermore, it was found that the attenuation rate at the 860 Hz varied greatly from one test to another. It appeared to be dependent on the condition of the drill pipe, but in a way that was not understood.On drill pipe that was new, or in very good condition, the attenuation rate at 860 Hz was in the 10-12 decibels per thousand foot range while, on badly worn drill pipe, the attenuation rate was often 30 decibels or more per thousand feet. In a search for an explanation of these results, a technical publication was studied entitled: "PASS-BANDS FOR ACOUSTIC TRANSMISSION IN AN IDEAL IZED DRILL STRING" by Barnes and Kirkwood, published in the Journal of the Acoustical Society of America, Volume 51, No. 5, (1972), pages 1606-1608. This article described a theoretical analysis of the drill pipe string as an acoustic filter and indicated that there should be a number of relatively narrow passbands separated by wider rejection bands in which no sound transmission could occur. This publication seemed to offer some explanation for the strange results of the Sun Oil tests.However, it was disappointing to find that the most successful frequency in the Sun test, i.e. 860 Hz, fell squarely in one of the rejection bands of the Barnes Kirkwood paper. Also, other frequencies that had been tried by Sun, for example 760 Hz, should have been in good transmission passbands, which was contrary to the experimental data. Consequently, interest was lost in the Barnes and Kirkwood theoretical analysis and a resumption of the random choice attempts to find the three transmission bands was revived. However, this random choice technique was turning out to be a very expensive, frustrating and time-consuming process.

It is readily seen from the background information above that prior attempts at acoustical telemetry in a drill pipe have met with difficulties. Therefore, it is an object of the present invention to provide an acoustic transmission system for use in a borehole, which system utilizes natural passbands within an elongated pipe string, and selects acoustic frequencies which are adaptable to such passbands and the environment of a wellbore and more particularly the environment of a drilling operation.

With these and other objects in view, the present invention contemplates an acoustical transmission system for use in pipe suspended in a wellbore wherein an acoustical signal is introduced into a pipe, transmitted through the pipe and received at another spaced position along the pipe, such signal moving in the pipe at a frequency falling within a passband of the pipe string and being adapted to conform to other selective parameters of a borehole environment. The acoustical signal is arranged so that it may be coded or modulated in such a way as to transmit information from one position to another along the pipe.

Reference is now made to the accompanying drawings in which: Figure I is a schematic diagram of pipe string acoustic telemetry test procedure; Figure 2 is a graphic representation of observed test data from the procedure shown in Figure 1; Figures 3 and 4 are graphic representations of acoustic passbands derived from observed test results as compared to theoretical data; Figures 5, 6 and 7 are graphic representations of the effects of tool joint compliance on acoustic passbands; Figure 8 is a schematic block diagram of a drill pipe telemetry system utilizing the present invention and showing bottomhole and surface electronics associated with the system; Figure 9 is a schematic block diagram of a repeater station for use in the telemetry system of Figure 8; and Figure 10 is a schematic diagram illustrating the use of multiple repeater stations and frequency mix for use in the telemetry system of Figures 8 and 9.

Theoretical data set forth in the above-mentioned paper entitled "Passbands for Acoustic Transmission In An Idealized Drill String" by Barnes and Kirkwood describe a theoretical analysis of a drill pipe string as an acoustic filter and indicate that the pipe string exhibits a number of relatively narrow passbands separated by wider rejection bands in which no sound transmission can occur. In the evolution of circumstances leading to the present invention, it was found that the theoretical data from the above paper did not correlate with data obtained from actual tests and therefore it was decided to conduct additional tests to find the ever elusive solution to the problem of acoustic transmission in a drill string.

It was considered that, if drill pipe was to act as a tuned transmission line, capable of passing certain frequencies and rejecting others, this property could be measured in a transient test analysis as is done for electrical transmission lines. An impulse test was designed to introduce a sharp sound pulse of short duration into one end of a drill stem suspended vertically in a borehole. This test set up is shown schematically in Figure 1 where the upper end of a pipe string 11 is fitted with the pin end 13 of a tool joint having a plate 15 welded to its upper end to provide a sound coupling into the string of pipe as will be described below. The lower end of the pipe string was similarly fitted with the box end 17 of a tool joint having a plate 19 at its lower end. A chamber formed from a section of pipe 21 is attached to the plate.A threaded cap 23 having an 0 ring seal 25 is attached to the lower end of the chamber. A conventional crystal accelerometer 27 is mounded directly to the plate 19 and extends downwardly into, and is housed within, the chamber 21. A preamplifier 29 is connected with the output of the crystal 27 to match the low level output of the crystal to the relatively low impedance input of a cassette tape recorder 31 also located in the chamber 21.

A cassette tape having a playing time of 60 minutes on one side was used in the recorder.

The recorder was turned on at the surface and run into the wellbore on the pipe, thus limiting the total duration of test time from that point to 60 minutes. After initially making up 313 feet of pipe in the hole, the first sound transmission test was made. The sound impulse was provided by sharply striking a ball peen hammer 33 against the plate 15 at the upper end of the test string in the following manner. One pulse was made, then several seconds elapsed before a series of 10 pulses spaced by one second were imparted to the plate. The ball peen hammer, when struck sharply and allowed to bounce, produces a sharp pulse (less than one millisecond) and a relatively high level of energy.After the first series of pulses, additional sections of pipe were added to the string to place the recorder at 527 ft., and after an initial two pulse code to signify a second test, the 10 pulse count was repeated. This procedure was repeated at 919 ft., 1253 ft., and 1566 ft., whereupon lapsed time on the tape cassette would not permit additional data to be taken. It is pointed out that the impulse test provides a pulse having energy up to a maximum frequency determined by the sharpness or duration of the pulse. For example, if the hammer pulse is one millisecond in duration, the pulse will contain energy having all frequencies from D.C. up to 1000 Hz.

The ball peen hammer technique in these tests provided frequencies above 1000 Hz.

Now that the pulse data had been recorded downhole, the recorder was retrieved by pulling the pipe. However, once the raw data had been recorded on tape, the problem of data analysis had just begun. The sound signal recorded on the cassette tape was in what acoustic engineers refer to as the "time domain", i.e. the tape recorded signal was a continuous record of the amplitude versus time.

In order to analyse the frequency spectrum of the recording, it was necessary to convert the record to the frequency domain by a mathematical process known as a Fourier Transform. This is a process far too complex to be done by hand calculations, and from a practical standpoint requires the use of high-speed digital computers. Therefore, it was necessary to convert the "time domain" data to digital form for entry into a computer.

Seismic data processing facilities frequently utilize the Fourier Transform technique.

Therefore, many geophysical data processing centers have equipment for digitising and analysing seismic records. However, there is a problem in the use of such equipment to analyse the acoustical data of the present situation in that seismic records characteristically contain frequencies only in the range of zero to 100 Hz with little or no useful data above 100 Hz. In digitising any type of data there is a requirement that the time increment between points of digitisation must be short enough to provide at least two points per complete cycle at the highest frequency contained in the record. Otherwise, errors are introduced which cannot be corrected by later processing.Geophysical data are typically digitised every 2 milliseconds. If any frequency has a cycle which is completed in less than two digitising intervals, then you get less than two points on a frequency cycle and this will not adequately describe the wave shape. This go-no go frequency level is called the Nyquist frequency and is at 500 Hz in geophysical data processing equipment. Therefore, in order to minimize the number of digital values which it is required to record and to eliminate any chance of exceeding the Nyquist frequency, all seismic digitizing equipment passes the input data through a very sharp low pass filter designed essentially to eliminate all frequencies above about 250 Hz before digitisation. Since, in the present application, it was desired to study possible passbands as high as 2500 Hz, this frequency filtering limitation was prohibitive.

There was no other known source of digitising equipment and the cost of building a special digitiser for this application was prohibitive. It was discovered that the recordings made of the sound pulses in the present situation could be scaled down into the seismic frequency range by recording the pulses at a tape speed of 7 1/2 inches per second after which this tape could be played at 1 7/8 inches per second and recorded again on the cassette tape. By this procedure, all the frequencies on the first tape were reduced by a factor of 4. However, this was still not enough to bring the 2500 Hz band below the 250 Hz seismic digitising limit.Therefore, the second cassette record was again recorded at a speed of 7 1/2 inches per second and played back onto cassette tape at both 3 3/4 inches per second and 1 7/8 inches per second to get two sets of records with overall frequency divisions of 8 to 1 and 16 to 1, respectively. It was necessary to digitise and process at both of these latter tape speeds because the 16 to 1 frequency division caused the lower frequencies of interest (below 500 Hz) to fall below the low frequency response of tape recorders (approximately 30 Hz). On the other hand, the 8 to 1 reduction was not sufficient to bring the 2500 Hz region into the passband of the seismic digitiser.

With this unorthodox procedure, it was possible to get the impulse test data shifted into the seismic frequency range and digitised so that they could be transformed into the frequency domain and analysed by conventional seismic data processing techniques, provided that the appropriate frequency multiplier was applied to the processed data to compensate for the slow-down process. This lengthy process was applied to the series of impulse test recordings made during the tests set forth above.

Referring next to Figure 2, the computer output of this analytical process was printed out in the form of a spectral energy density versus frequency curve for each of the five depths.

The results of this analytical process are most interesting. Even at the shallowest depth of 313 feet, there was clear evidence of preferred frequency passbands as evidenced by the peaks on the curves in Figure 2. As more pipe was added to the string, up to a maximum of 1566 feet, these passbands became sharper and the transmission outside these bands fell very nearly to zero.

Barnes and Kirkwood were qualitatively right in predicting that drill pipe behaves as a mechanical filter, passing certain bands of frequency and rejecting others. Figure 3 shows a comparison of the Chaney and Cox observed data with the Barnes and Kirkwood theoretical data for 31 ft. of drill pipe. In comparing the theoretical band pass frequencies with measured data from the impulse test as shown in Figure 3, it was found that the band locations of the Barnes and Kirkwood paper were almost totally out of phase with the measured data. This is true particularly in the frequency range from about 600 Hz to 1500 Hz, which is the preferred range for acoustic telemetry, where there is almost total disagreement between the Barnes and Kirkwood prediction and the measured data.In this respect, it turns out that, in the range of from 480 Hz to 1740 Hz, all of the reject bands in the measured data lie completely within passbands as predicted by Barnes and Kirkwood.

Similarly, reject bands predicted by Barnes and Kirkwood are almost totally within the passbands observed in actual drill pipe tests. Since the passbands in each case are wider than the adjacent reject bands, there is of necessity some overlap in the observed and theoretical passbands. This is obviously coincidental in view of the total disagreement between observed and calculated reject bands.

As might be expected, the boundaries between pass and reject bands were not at sharply defined in the test data as in the Barnes and Kirkwood theoretical treatment. This was most evident in that considerable attenuation occurred at the edges of each passband. While only five passbands were clearly identified in the observed data, there is a pattern in the location thereof which indicates that others exist. For example, the lowest frequency of each passband is closely approximated by the multiples of a frequency computed by the formula 17450 2 x pipe joint length where 17450 represents the velocity of sound in drill pipe in feet per second. Thus, this fundamental frequency is such that one length of drill pipe is a half-wave length at that frequency. The average joint length of the drill pipe used in the test was 30.8 feet, excluding the thread.Thus, the above formula yields a basic frequency of 17,450 2 x 30.8 = 283 Hz.

It will be observed that the lower frequency ends of the five passbands observed in the experiments fall very nearly to 1, 2, 3, 4 and 5 times this frequency.

In view of this reoccurring pattern, it is evident that a lower transmission band with a starting frequency of zero x 283 Hz must also exist. This band must extend to 0 Hz, because it is obvious that the drill pipe transmits "DC" displacements without attenuation. This "fundamental" passband was lost in the analytical procedure as a result of dividing the frequency by 8 or 16 as explained earlier. Even a division by 8 would place the appropriate center frequency of this lowest passband at 17 Hz which is far below the low frequency response capability of the cassette tape recorder used for this procedure. It would also be expected that transmission bands would occur at higher multiples than 5 times the basic frequency. These transmission bands would be weaker because the natural attenuation increases with increasing frequency.

In a separate experiment, satisfactory transmission was observed to a depth of 700 feet using a frequency of 2304 Hz which lies in the passband with the lowest frequency of 2264 Hz corresponding to the 8th multiple of 283 Hz.

The width of the transmission bands is somewhat inexact because of the gradual decay rather than a sharp boundary which exists in the definition of the passbands. In each case the preferred operating range is in a 150 Hz band beginning at a base which is 20 Hz above the starting frequency of each passband as calculated by the formula above. The 20 Hz gap moves the base of the band past the slope found at the edges of the passbands, it being understood that telemetry might be practical in this gap but less attenuation takes place in the 150 Hz band above this gap. Due to less attenuation at lower frequencies, thelower frequency passbands are somewhat broader and therefore some transmission would be expected beyond plus or minus 100 Hz from the center frequency, while passbands above 2000 Hz might be narrower.

It should be noted that the location of the starting frequency of each passband is not fixed but rather is a function of the length of the individual joints of drill pipe. The starting frequency locations which are listed above are correct for the most common length of drill pipe used by the petroleum industry, i.e. 31.5 feet including tool joints. However, some offshore drilling rigs use 45 foot lengths of drill pipe. Such rigs will require a shift in the transmission frequency because there is no one set of frequencies that is optimum for both 31.5 and 45 foot lengths of pipe. For 45 foot lengths, the "fundamental frequency" is 196 Hz and the frequencies for the passbands are multiples of this frequency. Assuming again that the preferred passbands fall in the 500 Hz to 1500 Hz range, then the corresponding 3rd, 4th, 5th, 6th, 7th and 8th multiples of 196 Hz will define the lower end of passbands at frequencies of 588, 784, 980, 1176, 1372 and 1568 Hz, respectively.

In analysing discrepancies between the Barnes and Kirkwood theoretical analysis of drill pipe transmission passbands and measured data of the impulse tests, one discrepancy between the theoretical predictions and measured data is indicated by comparing the interval between the center frequencies of adjacent passbands. In the observed test data, this interval is 270 Hz for 31.5 foot pipe, while the corresponding interval by calculation from their theoretical analysis is 310 Hz. In searching for an explanation for this difference, it was discovered that Barnes and Kirkwood used a factor of 6,000 meters per second as the velocity of sound in drill pipe. This is the commonly accepted velocity for mild steel in bulk shape (where all dimensions are approximately equal).However, it is also known that the velocity of sound in long thin rods is considerably lower (about 5200 meters per second or 17,000 ft. per second). This value for the velocity of sound was substituted in the Barnes and Kirkwood equations for compressional waves, with the results shown in Figure 4. A comparison of the two curves in this figure reveals that the interval between the center frequencies of the transmission bands is now very nearly the same. However, the observed and theoretical data still disagree in that there is a large horizontal shift in the location of the center frequency of the passbands. This shift is sufficient to cause the reject bands of the theoretical data to cover close to one-half of the passband width of each of the observed passbands. No way was found to adjust the parameters in the Barnes and Kirkwood model to eliminate this error.This fact, in combination with observations in the field testing programme led to the conclusion that the model of drill pipe behaviour used in the theoretical data was fundamentally in error.

The model of the drill pipe detailed in the Barnes and Kirkwood paper consists of a length of drill pipe of uniform cross-sectional area connected by tool joints of considerably larger cross-sectional area. In this model, the tool joints are much stiffer than the pipe, and it is this regularly spaced, repeating discontinuity in rigidity which would produce the pattern of transmission and rejection bands which the theoretical data predict. While increased size and mass is the obvious difference between tool joints and pipe, there is another difference in that the tool joint contains a threaded connection. The acoustic properties of the threaded connection are very difficult to analyse but it appears that the threaded connection makes the tool joint more compliant than the drill pipe rather than stiffer.One reason for this assumption, that the thread rather than the extra metal is the controlling factor, comes from experimental observations on badly worn drill pipe. Prior to the discovery of the true location of the passbands as set forth in the procedure above, a great deal of previous experimental work was conducted at 860 Hz, which is at the lower edge of an observed passband. With pipe in good condition, tests showed that satisfactory transmissions were frequently obtained at this frequency. However, on badly worn drill pipe, the results were invariably negative. The two most noticeable effects of wear on tool joints are an appreciable reduction in the outside diameter of the joint and increased clearances in the threaded connections.The outside surfaces of the tool joints, being considerably larger than the drill pipe itself, are worn by the rotation of the pipe in contact with the walls of the wellbore during a drilling operation. If the extra metal in the tool joint were a controlling factor in rejecting certain frequencies, then the selective removal of metal from the tool joints would be expected to reduce this effect and to give more nearly constant transmission at all frequencies. On the other hand, if greater compliance in the thread were the controlling factor, then thread wear would be expected further to increase compliance. This would sharpen the boundaries of passbands and increase the rejection at other frequencies. Observed data from the tests are clearly in accord with the latter explanation rather than the former.Based on these observations and in order to confirm the theory developing from the tests, a computer programme was written to analyse the properties of a drill pipe string in which the joints were more compliant than the body of the pipe. There was no known way to compute the relative compliance of the tool joint and pipe, so that this was made out of the variables in the programme. Figure 5 shows a comparison of the observed data with the computer predictions at two different compliance ratios. At a compliance ratio of 2 to 1. the size and location of the transmission bands agree quite well with the experimental data. At a compliance ratio of 10 to 1, the transmission bands are seen to be much narrower. In fact, they are too narrow for practical telemetry with multiple repeaters.This confirms in theory the early field observations that severely worn threads would prevent transmission at frequencies near the edge of the transmission band. It is to be noted that pipe in which the threads are 10 times more compliant than the pipe body would not support itself mechanically in a drilling operation and therefore would not be likely to encounter this extreme situation in practice.

We have now found that, by utilising a more appropriate velocity for sound in a drill pipe, i.e. 5200 meters per second (17,000 feet per second) and considering that the threaded connection of a tool joint is more compliant than the drill pipe rather than being stiffer; and then substituting these differences into the Barnes and Kirkwood mathematical formulation, data are produced which more clearly match the theoretical data to the experimental data. This comparison is shown in Figure 6. While it is known that the threads of the tool joints in a pipe string are more compliant than the drill pipe, there is no way of calculating how much more compliant they are. Therefore, for the purposes of computer modelling, a number of ratios have been tried and we have found by trial and error that a compliance ratio of 7 to 1 gives a band width most closely matching the experimental data.As seen in Figure 2, it can be appreciated that it is difficult to pick an exact band width from the experimental data, because the amplitude falls off gradually at both ends of each band.

Therefore, there is a considerable margin for error in the 7 to 1 compliance ratio, and this ratio will undoubtedly vary with the age of the pipe. Threads of the pipe will increase in compliance due to wear, while the body of the pipe will not change appreciably. It should also be noted that the sound velocity used with these calculations has been adjusted upward by about 400 ft. per second. This was done so as to fine tune the calculated passbands to fit best with the measured data. This represents only a change of 2% from the handbook value of the velocity of sound in long thin rods and is in the direction of the sound velocity in bulk steel. It is not known whether this difference reflects a real difference in sound velocity in pipe as compared with thin rods or whether it indicates an error in data.A 2% error in data is quite possible in view of the multiple recording processes required to adapt measured data to the seismic data processing equipment used in analysing the frequency array.

In working with the computer model to determine the optimum compliance ratio, an interesting and surprising observation has been made. As was expected, an increase in compliance ratio narrowed the passbands but the surprise came in that the change was entirely at the high end of each passband. The low end does not change at all. This is shown by comparing the dotted lines in Figure 6 for a 20 to 1 compliance ratio with the solid line 7 to 1 curves. It turns out that the low frequency limit of each passband falls on an exact multiple of a frequency for which the length of a joint drill pipe is 1/2 the wave-length. This frequency can be calculated as follows: fundamental frequency 17450 2x30.8 = 283 Hz where 17450 is the velocity of sound in feet per second and 30.8 is the length of pipe excluding thread.It will be observed that the successive passbands begin at frequencies that are, e.g. 0, 1, 2, 3, 4, 5 and 6 times this frequency. As shown in Figure 1, this low frequency end point does not change with the compliance ratio. Only the high frequency end shifts as the compliance ratio is changed.

Figure 7 shows the effect of drill pipe length on the location and width of the calculated passbands. The bottom curve is for the 31.3 foot drill pipe as in Figure 6. The second curve for 30.0 foot drill pipe was taken as a probably lower length limit for standard drill pipe and the third curve is for 45 foot pipe which is used on some offshore rigs. It is interesting to note the location of 860 Hz on the first and second curves, in view of the erratic attenuation rates found at this frequency. For 31.3 foot pipe, 860 Hz is safely within the passband, but for 30 foot pipe, the lower limit of the band has moved up to 890 Hz. It may be that some of the so-called bad pipe which caused severe attenuation at 860 Hz in earlier tests was really only "short" pipe.

Referring now to Figure 8 of the drawings, a schematic diagram of a telemetry system for use with the present invention is shown. A string of drill pipe 35 is suspended in a wellbore and comprises a plurality of pipe sections (not shown) joined by threaded tool joints in a conventional manner.

A series of repeaters 37 (schematically illustrated) are installed in the pipe string at uniform intervals. The function of each repeater is in general to pick up (receive) an acoustic signal from the string of drill pipe, to amplify it, and to re-transmit it as an acoustic signal along the pipe.

A sensor 39 for detecting a downhole parameter develops an analog signal which is converted to digital coding by means of an analog to digital converter 41. An example of such a sensor is a device for determining the orientation of a borehole using a fluxgate steering tool as shown in U.S. Patent 2,755,431. The signal may also be generated as pulse width data which can also be converted to digital data for transmission in the system to be described. The sensor developed signal in any event is passed into an analog to digital converter (A/D) which converts the analog voltages to a digital code utilizing "1" and "0" for all information transmission. The output of the A/D converter is fed to a shift register 43 which simply receives the now digitized signal and in conjunction with a clock mechanism 45 outputs the information to be transmitted in a timed sequence. The shift register output feeds a switch 47 driven by an oscillator 49 which, in turn, is operated at the desired transmission frequency falling within the passbands described above. The output of the A/D converter and shift register is either an "on" or an "off" corresponding to the digital 1 or 0 coding. If an "on" or "1" is passed from the shift register, the switch is actuated to pass the output of the oscillator to a power amplifier 51 which in turn boosts the power of the oscillator signal, which boosted signal is fed to a sound source 53. The sound source is an electromechanical device that converts the electrical energy to acoustical energy which is then imparted to the drill pipe. Such a sound source can be a fixed frequency or crystal controlled device.One type of sound device utilizes a coil which, when excited by a source of electrical energy at say 920 Hz, causes a rod within the coil to oscillate in length at 920 Hz and this motion is directed into the pipe to generate a compressional wave having a frequency of 920 Hz. Thus, the analog data which were picked up by the detector, have been converted to a binary code which in turn has been converted to an acoustic tone which is only transmitted when a "1" or an "on" appears in the data. This transmission of the tone is for a fixed interval and in a clock timed sequence to permit decoding at the surface by means of a compatible clock times decoding mechanism to be described.

One such clocking system for use with the present invention is as follows: the time allowed for each bit of data is 200 milliseconds (ms). If a "1" is transmitted, then the signal is on for 100 ms and the remaining 100 ms is for the decay of sound in the pipe. If the next digit is also a one, then the signal is passed again for 100 ms and then is off for 100 ms. If the next signal is a "0", or "off", then the signal is not passed or is quiet for 200 ms. A sync signal is used to give a time reference. One such scheme allows 8 bits to a word so that the 200 ms intervals described above are repeated 8 times, and then the 9th position is in the form of a parity bit. The logic is arranged so that if the "1's" in the 8-bit data stream add up to an even number, then a "1" or "on" is applied to the 9th bit.If the "1's" in the 8-bit data stream add up to an odd number, then the 9th or parity bit is a zero, i.e. no signal is passed.

Thus, each word in the scheme is made up of 8 bits plus a parity. The parity bit provides a means for checking for error in that, if the odd-even scheme set forth above does not check out with the presence or absence of the parity bit, it is known that signals are being lost in the transmission. After 9 words (8 bits + parity) have been passed, a discrete sync signal is given such as a lapsed time frame, or a series of "1's" etc. The system thus far described utilizes a minimum of power since the sound source is only activated when a "1" data or parity bit is passed. Power is used continuously in the present system only to drive the clock mechanism and other devices which are lower power devices.Thus, a system which utilizes a battery power source can be operated for a much longer period of time than one for example which transmits at a passband frequency constantly with means for modulating the signal with measured data information.

After the acoustic signal is placed on the pipe, it produces a compressional wave which travels in both directions on the pipe. The repeaters 37 in the pipe string are spaced to receive the acoustic signal while it is strong enough to be readily detected. Thus, the system of repeaters functions to detect "1's" or "on" and then to re-transmit a signal at a different frequency when activated by the acoustic signal which is indicative of a "1".

Also shown in Figure 8 is a schematic diagram of surface equipment for receiving an acoustic signal emanating from a sound source either at the downhole location at the bottom of the drill string or at a repeater station 37. In either event, the acoustic signal in the form of a compressional wave on the pipe is received at the surface by a signal pick-up or acoustic receiver 71. The receiver 71 may be in the form of a crystal accelerometer which converts the acoustic signal to electrical energy. A preamplifier 73 increases the amplitude of the electrical signal from the receiver on the pipe for further processing at the surface.

This electrical signal is further passed by hard wire or radio link to a decoder or demodulation section including a narrow band filter which passes only the frequency from the preceding sound source and is selectable to such frequency to eliminate as much noise from the signal as possible. The filter 75 passes the resulting so-called clean data to a sync detecter circuit 77 which reconstructs the clock associated with the downhole circuitry to put the data into its word bit scheme as described with respect to downhole transmission.

The clock-synchronized data are now passed to a latch 79 which separates and sorts the words of data to correspond to the analog value of downhole parameters detected in the borehole which may then be read out in analog or digital form.

Referring next to Figure 9, the repeater section more specifically operates as follows: a crystal accelerometer 55 coupled with the pipe picks up the signal transmitted on the pipe at a discrete frequency, i.e. 920 Hz. The accelerometer converts the acoustic signal back into an electrical signal which contains the transmitted frequency and noise on the drill pipe.

The signal from the accelerometer may be as weak as 1 millivolt or as strong as several volts. In order to deal with such a wide variation of signal amplitudes, the accelerometer output is fed to an amplifier 57 having an AGC (automatic gain control) system 58 which regulates the signal passed to a narrow filter 59. The filter listens for only the fixed frequency (ex: 920 Hz) and is designed to operate over as narrow a band as possible taking into account uncontrollable variables. In the present example of 920 Hz transmitted frequency the filter would pass say 918-922 Hz to make sure that other frequencies used in the system, i.e. 940 and 960 Hz, are discriminated against in the filter. This narrow discrimination is possible with the use of a crystal-controlled oscillator in the transmitter section. The filter operates most efficiently when it receives a fixed amplitude signal.The AGC 58 receives the amplifier 57 output and, if it is too large, it sends a feedback signal to the amplifier which cuts down the amplifier output and vice versa. Since the repeater section also contains a transmitter section which outputs a 30 volt signal, this strong signal would activate the AGC circuit to cut down the amplifier gain too much for effective amplification of data signals. Therefore, an electronic switch 61 is placed in the circuit to cut out the amplifier and AGC control when the instant repeater sound source 62 is transmitting and is open the rest of the time to listen for the next bit of data. Each data bit received operates a reset 65 which resets a clock 63 to gate this switch device to clamp input so as not to listen to the retransmitted pulse.This clamp stays on for a sufficient period of time to prevent ringing of the sound source from disturbing the receiver.

The repeater filter thus outputs a pure 920 Hz signal which is only present when a transmission ("1" or "on") is received and is absent at all other times. The filter output is passed to a delay section 67 which delays the repeater transmitter until the receiver is off, thus phase shifting the transmission with respect to reception. In the example system, the repeater transmitter operates at 940 Hz.

Additional repeater sections are utilized in the system depending on depth. For example, if the depth of drilling, age of pipe, etc. dictates a telemetry system utilizing more than one repeater section, subsequent sections may be operated at 940 Hz and 960 Hz, alternating between the various frequencies as shown schematically in Figure 10. In this example, with a spacing of 2000 feet between repeaters 37 and utilizing three frequencies, a total of 8000 feet exists between transmitters operating at the same frequency, which provides sufficient attenuation of signal to prevent any stray signals from the same frequency stations from being confused as current data signals. In any event, distance between repeaters and frequency mix will be determined by signal loss and receiver signal lock on capability.The acoustic signal transmitted by each acoustic transmitter (sound source) does of course travel in both directions along the pipe. Thus, the transmitter which develops a 920 Hz signal near the surface in Figure 10 sends the signal downwardly as well as upwardly (the latter being the desired direction in the instance of sending data from subsurface to surface). However, the staggered-frequency arrangement described, wherein there are three different frequencies used by three different repeaters and wherein these repeaters are spaced in the drill string, discriminates in favour of the upward direction of travel of the acoustic signal.

While, for the most part, the invention herein has been described as being a telemetry system for detecting downhole data for transmission to the surface, it is readily seen that the system is equally applicable for sending data, control signals or the like from the surface to downhole such as to perform a downhole operation by surface control.

Therefore, while particular embodiments of this invention have been shown and described, it is to be understood that further modifications may now suggest themselves to those skilled in the art and it is intended to cover such modifications as fall within the scope of the appended claims.

WHAT WE CLAIM IS: 1. A telemetry (as herein defined) system for transmitting an acoustical signal over a string of drill pipe made up of sections of pipe of substantially the same length and positioned in a borehole, including: acoustical signal transmitting and receiving means positioned at first and second spaced locations on the string of pipe; and means for operating said transmitting means at a fixed frequency occurring within frequency passbands which have a lower limit that is a multiple of a frequency for which one section length of pipe in the string is substantially a half-wave length.

2. A telemetry system according to Claim 1, wherein the string of standard drill pipe has pipe sections of substantially 31.3 feet, and wherein the frequency passbands have a frequency band width of 130 Hz and base frequencies (lower limits) which are multiples of 283 Hz plus 20 Hz.

3. A telemetry system according to Claim 1, wherein the string of drill pipe has pipe sections of substantially 44.5 feet, and wherein the frequency passbands have a frequency band width of 100 Hz and base frequencies which are multiples of 196 Hz plus 20 Hz.

4. A system according to any of Claims 1 to 3, wherein said first and second locations are located on the pipe string at the bottom and at the surface of a borehole, respectively.

5. A telemetry system according to any of Claims 1 to 4, further including transducer interface means at said first and second spaced locations for transforming electrical signals into acoustical signals and vice versa.

6. A system according to any of Claims 1 to 5, and further including repeater means positioned on said string of pipe between said first and second spaced locations and having receiving and transmitting means therein for receiving said fixed frequency signal and in

**WARNING** end of DESC field may overlap start of CLMS **.

Claims

**WARNING** start of CLMS field may overlap end of DESC **. discrimination is possible with the use of a crystal-controlled oscillator in the transmitter section. The filter operates most efficiently when it receives a fixed amplitude signal. The AGC 58 receives the amplifier 57 output and, if it is too large, it sends a feedback signal to the amplifier which cuts down the amplifier output and vice versa. Since the repeater section also contains a transmitter section which outputs a 30 volt signal, this strong signal would activate the AGC circuit to cut down the amplifier gain too much for effective amplification of data signals. Therefore, an electronic switch 61 is placed in the circuit to cut out the amplifier and AGC control when the instant repeater sound source 62 is transmitting and is open the rest of the time to listen for the next bit of data.Each data bit received operates a reset 65 which resets a clock 63 to gate this switch device to clamp input so as not to listen to the retransmitted pulse. This clamp stays on for a sufficient period of time to prevent ringing of the sound source from disturbing the receiver. The repeater filter thus outputs a pure 920 Hz signal which is only present when a transmission ("1" or "on") is received and is absent at all other times. The filter output is passed to a delay section 67 which delays the repeater transmitter until the receiver is off, thus phase shifting the transmission with respect to reception. In the example system, the repeater transmitter operates at 940 Hz. Additional repeater sections are utilized in the system depending on depth. For example, if the depth of drilling, age of pipe, etc. dictates a telemetry system utilizing more than one repeater section, subsequent sections may be operated at 940 Hz and 960 Hz, alternating between the various frequencies as shown schematically in Figure 10. In this example, with a spacing of 2000 feet between repeaters 37 and utilizing three frequencies, a total of 8000 feet exists between transmitters operating at the same frequency, which provides sufficient attenuation of signal to prevent any stray signals from the same frequency stations from being confused as current data signals. In any event, distance between repeaters and frequency mix will be determined by signal loss and receiver signal lock on capability.The acoustic signal transmitted by each acoustic transmitter (sound source) does of course travel in both directions along the pipe. Thus, the transmitter which develops a 920 Hz signal near the surface in Figure 10 sends the signal downwardly as well as upwardly (the latter being the desired direction in the instance of sending data from subsurface to surface). However, the staggered-frequency arrangement described, wherein there are three different frequencies used by three different repeaters and wherein these repeaters are spaced in the drill string, discriminates in favour of the upward direction of travel of the acoustic signal. While, for the most part, the invention herein has been described as being a telemetry system for detecting downhole data for transmission to the surface, it is readily seen that the system is equally applicable for sending data, control signals or the like from the surface to downhole such as to perform a downhole operation by surface control. Therefore, while particular embodiments of this invention have been shown and described, it is to be understood that further modifications may now suggest themselves to those skilled in the art and it is intended to cover such modifications as fall within the scope of the appended claims. WHAT WE CLAIM IS:

1. A telemetry (as herein defined) system for transmitting an acoustical signal over a string of drill pipe made up of sections of pipe of substantially the same length and positioned in a borehole, including: acoustical signal transmitting and receiving means positioned at first and second spaced locations on the string of pipe; and means for operating said transmitting means at a fixed frequency occurring within frequency passbands which have a lower limit that is a multiple of a frequency for which one section length of pipe in the string is substantially a half-wave length.

response thereto transmitting an acoustical signal of a second fixed frequency within said frequency passbands.

7. A system according to Claim 6, and further including a second repeater means for receiving said second fixed frequency and in response thereto transmitting a third fixed frequency within said frequency passbands.

8. A system according to any of Claims 1 to 7, wherein the system includes: downhole means for detecting a borehole parameter; means for generating an electrical signal which is indicative of the detected parameter; and means responsive to the generated electrical signal for imparting an acoustical signal to the string of pipe at a frequency falling within said passbands.

9. A system according to Claim 8, and further including: surface means for receiving said acoustical signal, and means responsive to the received acoustical signal for generating an electrical signal which is indicative of the detected parameter.

10. A system according to Claim 9, and further including repeater means positioned in the pipe string between the downhole means and the surface of a fixed frequency and, in response to the reception thereof, transmitting another acoustical signal at another fixed frequency selected from said passbands.

11. A system according to Claim 8, wherein said downhole detecting means is adapted to produce an analog signal indicative of a detected parameter, and further including means for converting said analog signal to a digital pulse code, and means for operating an acoustical sound source in a clock-related sequence with the digital pulse to provide a fixed frequency acoustical pulse indicative of the detected parameter.

12. A system according to Claim 11, and further including transducer means at the surface for receiving said acoustical pulse and providing a surface electrical signal in response thereto, and means for synchronously relating the surface electrical signal to the clock-related downhole pulse to provide a signal at the surface which is indicative of the downhole detected parameter.

13. A method of acoustically transmitting data over an elongated member made up of individual sections of substantially equal length in a borehole and having transmitting and receiving devices acoustically coupled with the elongated member, comprising the steps of: generating a fixed frequency acoustical signal at one position on such elongated member at a discrete frequency which occurs within frequency passbands which have a lower limit that is a multiple of a frequency for which one elongated member section length is substantially a half-wave length; imparting the acoustical signal to the elongated member; and receiving such discrete frequency acoustical signal at a spaced location on such elongated member.

14. A method according to Claim 13, further including generating an electrical signal at such spaced location which is indicative of the received discrete frequency acoustical signal.

15. A method according to Claim 13 or 14, and further including detecting a borehole parameter at one such position on the elongated member, generating an electrical signal which is indicative of the detected parameter, and operating a transmitting device in response to the generated electrical signal to provide such discrete frequency acoustical signal.

16. A method according to Claim 13, and further including the steps of: detecting a borehole parameter at the one position; generating an electrical signal indicative of the detected parameter; operating a transmitting device in response to the electrical signal to provide such discrete frequency acoustical signal; receiving such acoustical signal at another spaced position on the elongated member; and generating an electrical signal in response to the received acoustical signal which electrical signal is indicative of the detected borehole parameter.

17. A method according to Claim 16, and further including generating an analog signal at the one position in response to the detected borehole parameter, converting the analog signal to a digital pulse code, and operating the transmitting device in response to the digital pulse code.

18. A method according to Claim 13, for acoustically transmitting data over a string of drill pipe comprising pipe sections of substantially equal length suspended in a borehole and having transmitting and receiving devices coupled with the pipe string at first and second spaced locations, comprising the steps of:: generating a fixed frequency electrical signal at one of the first and second spaced locations which is indicative of data to be transmitted over the string of pipe; operating an acoustical signal generating device in response to the generated electrical signal at a discrete acoustical frequency which occurs within frequency passbands, each having a lower limit that is a multiple of a frequency for which one pipe section length is substantially a half-wave length; passing the discrete acoustical signal over the string of pipe to the other of the first and second spaced locations; detecting the passed acoustical signal at such other spaced location; and generating an electrical signal at such other spaced location in response to the detected acoustical signal which is indicative of the transmitted data.

19. A method according to Claim 18, and further including generating such acoustical signal in passbands having a frequency width of 130 Hz and base frequencies which are multiple of 282 Hz plus 20 Hz.

20. A method according to Claim 18 or 19, and further including receiving such passed discrete acoustical signal at an intermediate position between the first and second spaced locations on the string of pipe; operating a repeater transmitter in response to the received discrete acoustical signal at a second discrete acoustical frequency occurring within such frequency passbands; and receiving such second discrete acoustical signal at the other of the first and second spaced locations.

21. A method according to Claim 13, for acoustically transmitting data through a drill pipe of 30.8 feet in length in a borehole comprising the steps of: generating in the drill pipe acoustic vibrations having frequencies in a 150 Hz passband selected from the detectable multiples of 283 Hz plus 20 Hz; coding such acoustic vibrations in the drill pipe to transmit data; receiving such acoustic vibrations from the drill pipe at a location spaced from the point of vibration generating thereon; and separating the data from the acoustic vibrations.

22. A method according to Claim 13, for acoustically transmitting data through a drill pipe of about 45 feet in length in a borehole comprising the steps of: generating in the drill pipe acoustic vibrations having frequencies in a 100 Hz passband selected from the detectable multiples of 196 plus 20 Hz; coding such acoustic vibrations in the drill pipe to transmit data; receiving such acoustic vibration from the drill pipe at a location spaced from the point of vibration generating thereon; and separating the data from the acoustic vibrations.

23. A telemetry system according to Claim 1, substantially as herein described with reference to the accompanying drawings.

24. A method according to Claim 13, substantially as herein described with reference to the accompanying drawings.