Patent Publication Number: US-2011069583-A1

Title: Apparatus and method for acoustic telemetry measurement of well bore formation debris accumulation

Description:
CROSS-REFERENCE TO RELATED APPLICATION 
     This application claims the benefit of U.S. provisional application No. 61/244,336, filed Sep. 21, 2009, which is incorporated herein by reference. 
    
    
     FIELD 
     The present invention relates generally to an apparatus and a method for acoustic telemetry measurement of well bore formation debris accumulation. 
     BACKGROUND 
     Acoustic telemetry is a method of communication used, for example, in the well drilling and production industry. In a typical drilling environment, acoustic extensional carrier waves from an acoustic telemetry device are modulated in order to carry information via the drillpipe as the transmission medium to the surface. Upon arrival at the surface the waves are detected, decoded and displayed in order that drillers, geologists and others helping steer or control the well are provided with drilling and rock formation data. Downhole information can similarly be transmitted via the well casings in production wells. 
     The device that typically generates the telemetry signal (usually a PZT piezoelectric stack) causes extensional or similar waves to be introduced into the steel walls of the drill pipe, whence they travel to the surface. The walls are thereby caused to move, either axially, radially or both in the transmission of acoustic energy. The attenuation of such waves is dependent on a number of factors, including pipe non-uniformities, pipe geometry and tally, mode conversion, wall contact, drilling fluid type, formation cuttings, cavings, and so on. 
     When drilling, one of the major problems is how to remove cuttings and cavings from the well bore as drilling proceeds. If this is not adequately solved, a well may be drilled ahead without issue but withdrawing the drill pipe and the bottom hole assembly (BHA) may be impossible and the well may have to be abandoned. It is therefore important that the amount of cuttings or cavings and their position in the well be known or accurately inferred in order that appropriate and timely action (called hole cleaning) is taken. Cavings are generally defined as formation debris in the wellbore that does not originate due to the action of the drill bit but at other sites within the well. The position of these sites can be anywhere. Cavings can be large (perhaps 10 centimeters) or small, whereas cuttings are usually small (from a few millimetres to a few centimetres). The size issue will be seen to have importance later. For our purposes we group both cavings and cuttings together as formation debris. 
     The conventional method for assessing the build-up of formation debris that may cause drilling problems is to make use of a technique called ‘equivalent circulating density’ (ECD). ECD makes use of the fact that the drilling fluid&#39;s density is increased by the presence of generally greater density particles from the drilled formation that are suspended in the fluid. There are numerous references discussing ECD. The usefulness of ECD is reduced the higher the angle the well is drilled from vertical, and is of no use if the drilling fluid is air (by which in this context we mean nitrogen or diesel exhaust or similar non-explosive gases). Thus high angle or horizontal wells drilled with air are at risk due to the possibility of formation debris beds being difficult to remove. 
     SUMMARY 
     According to one aspect, there is provided a system for measuring formation debris accumulation in a wellbore, comprising an acoustic telemetry transmitter disposed at a first location on a drill string, an acoustic telemetry receiver disposed at a second location on the drill string spaced from the first location or at a third location on the surface, and configured to receive an acoustic signal sent along the drill string from the transmitter via a wall of the drill string, and a processor. The processor is communicative with the receiver and has a memory that can store information comprising: an amplitude of an acoustic signal launched by the transmitter, and parameters related to the properties, motion, and inclination angle of a drill-string section between the transmitter and receiver. The memory is further encoded with instructions executable by the processor to use the stored information and an acoustic signal transmitted by the transmitter and received by the receiver, to calculate an intrinsic signal level loss along the drill string section between the transmitter and receiver, an actual signal level loss of the transmitted acoustic signal, and the difference between the actual signal level loss and intrinsic signal level loss. This calculated difference is indicative of the debris accumulation in the drill string section. 
     The acoustic telemetry transmitter can be a bottomhole assembly transmitter located in a bottomhole assembly of the drill string. In such case, the system can further include a bottomhole assembly processor in communication with the bottomhole assembly transmitter and having a memory encoded with information comprising at least one of: an amplitude of an acoustic signal launched by the bottomhole transmitter, and parameters related to one or more of the properties, motion, and inclination angle of a drill-string section between the bottomhole transmitter and the receiver; this memory is further encoded with instructions for the bottomhole transmitter processor to cause the bottomhole transmitter to transmit this information to the receiver. 
     The system can further include a surface transmitter communicative with the processor and located at surface. In such case, the acoustic telemetry receiver can be a surface receiver located at surface and the processor can be further programmed to cause the surface transmitter to transmit a control signal to the bottomhole assembly when the difference between the actual and intrinsic signal level losses exceeds a threshold value. 
     In an alternative configuration, the system can include a plurality of telemetry nodes, in which case the aforementioned transmitter is a part of a first node, and the aforementioned receiver is part of a second node, and the drill string section is between the first and second nodes. At least one node can comprise a sensor for measuring the inclination angle of a drill string section in the vicinity of the node. 
     In yet another alternative configuration, the system can include a surface receiver, a bottomhole transmitter, and one or more telemetry nodes each disposed on the drill string between the surface receiver and the bottom hole assembly transmitter. At least one of the nodes can comprise a node receiver configured to receive acoustic signals sent along the drill string from another node or from the bottom hole assembly transmitter, and a node transmitter for transmitting an acoustic signal along the drill string to the surface receiver. The at least one node can further comprise a node processor in communication with the node transmitter and node receiver and have a memory encoded with information comprising at least one of: an amplitude of an acoustic signal launched by a transmitter of another node or by the bottomhole assembly transmitter, and parameters related to one or more of the properties, motion, and inclination angle of a drill-string section in the vicinity of the node. The memory can be further encoded with instructions for the node processor to cause the node transmitter to transmit this information. The memory of the node processor can be further encoded with instructions for the node processor to calculate the intrinsic signal level loss along the drill string section in the vicinity of the node, the actual signal level loss of an acoustic telemetry signal received by the node receiver which was transmitted across the drill string section in the vicinity of the node, and the difference between the actual signal level loss and intrinsic signal level loss across the drill string section in the vicinity of the node, and to cause the node transmitter to transmit this information. 
     The node transmitter can be configured to transmit this information to the surface receiver. In such case, the surface processor is further programmed to cause the surface transmitter to transmit a control signal to the bottomhole assembly when the difference between the actual and intrinsic signal level losses as calculated by the node processor exceeds a threshold value. Alternatively, the memory of the node processor can be encoded with instructions executable by the node processor to cause the node transmitter to transmit a control signal to the bottomhole assembly when the difference between the actual and intrinsic signal level losses across the drill string section as calculated by the node processor exceeds a threshold value. In this latter case, the memory of the node processor can be further encoded with instructions executable by the node processor when the threshold value is exceeded to cause the associated node transmitter to acoustically transmit motor control instructions selected from the group consisting of: changes to drill bit rotation speed, drill bit angle, weight on bit, and flow rate control. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       In the accompanying drawings, which illustrate the principles of the present invention and an exemplary embodiment thereof: 
         FIG. 1(   a ) is a schematic view of an annular space between a well bore and a drilling tubular containing formation debris in a well drilled with conventional liquid drilling fluid (known as mud) where the well bore inclination varies from 0° (vertical) to &lt;45°. 
         FIG. 1(   b ) is a schematic view of an annular space between a well bore and a drilling tubular containing formation debris in a directional well where the angle with vertical is &gt;45° but &lt;=65°. 
         FIG. 1(   c ) is a schematic view of an annular space between a well bore and a drilling tubular containing formation debris settled in a 65° to horizontal 90° well. 
         FIG. 2  shows a simplified and idealized view of a BHA comprising a drilling motor and bit, a means of generating acoustic signals, and drill pipe extending to the surface. 
         FIG. 3  is a schematic view of a simple directional well comprising a vertical section, a build section and a horizontal section, and which shows an acoustic telemetry wave launched from the BHA toward the surface for detection by a rig. 
         FIG. 4  is a schematic view of the well shown in  FIG. 3  and three cross sectional views of the well A, B, C, in which:
         cross sectional view A shows a relatively dispersed formation debris in the vertical well bore section;   cross sectional view B shows more formation debris in contact with both the drill pipe and the formation; and   cross sectional view C shows the horizontal section where a large build-up of formation debris provides comprehensive contact between a drill pipe and an adjacent formation.       

         FIG. 5(   a ) is a schematic view of an acoustic telemetry system comprising a bottomhole transmitter and a surface receiver according to one embodiment. 
         FIG. 5(   b ) shows an acoustic telemetry system according to another embodiment comprising a bottomhole transmitter, a surface receiver and a pair of acoustic telemetry nodes on a drill string. 
         FIG. 6(   a ) is a schematic of a surface telemetry assembly comprising the surface receiver, a surface transmitter and a processor having a memory with instructions encoded thereon for execution by the processor to process acoustic telemetry measurement data relating to well bore formation debris accumulation. 
         FIG. 6(   b ) is a schematic of a node assembly located at a downhole location on the drill string and comprising a node receiver, node transmitter, and a node processor. 
     
    
    
     DETAILED DESCRIPTION 
     Embodiments described herein introduce a new method and apparatus for the oil and gas drilling industry which quantifies the effect of formation debris in fluid filled wells with a specific attenuation factor associated with the passage of acoustic telemetry signals in drill pipe and other downhole tubular members. 
     One embodiment comprises a system that carries out a method of measuring debris formation accumulation in a wellbore. The system comprises an acoustic telemetry transmitter near a drilling bit of a BHA of a drill string, a surface acoustic telemetry receiver configured to receive an acoustic signal sent along the drill string from the transmitter via the walls of the drill string, a processor communicative with the receiver and a memory encoded with instructions executable by the processor to determine the intrinsic signal loss along the drill string between the transmitter and receiver (i.e. the loss due to acoustic waves travelling along steel drillpipe, the loss due to passband filtering, mode shifts and other similar irreducible effects), measure the actual loss between said transmitter and receiver from the received acoustic signal, then subtract the actual and intrinsic losses to determine the build-up of drilling formation debris in the well bore. This determined build up of formation debris can be relayed to a person or to a device able to store, indicate or implement the perceived need for reduction of formation debris within the well being drilled. 
     In another embodiment, the sections of the well can be delineated by the positions of several acoustic telemetry devices; such devices can comprise at least one device being an acoustic transmitter near the drill bit, at least one device being both an acoustic receiver and an acoustic transmitter such as a telemetry node, and at least one device being a surface acoustic receiver. The devices utilize the acoustic telemetry signals propagating within the walls of the drill pipe. In particular, the system can comprise multiple telemetry devices each at select sections of the well; the devices in these multiple sections can comprise a receiver, a transmitter and a processor. Each receiver can receive the transmitted acoustic signals arriving at its location, said signals having incorporated decodeable data such as transmitter amplitude and its local angle of inclination; each associated processor can thereby determine the value of the actual acoustic signal loss minus the expected intrinsic acoustic signal loss at each selected location in the well to obtain multiple values—its own and those received from other segments. Each associated transmitter can send the determined value upstring to the surface. Once received at the surface, an operator can use these multiple values to determine if there is a need for well cleaning within each of the multiple sections of the well. 
     In one embodiment, one or more processors can be programmed to automatically assess the acoustic signal attenuation between drill string sections, wherein the sections are defined by the placement of acoustic transmitters and receivers. The processor(s) can be programmed to telemeter the attenuations to the surface on a preset timed basis. One or more of these processors can be programmed to determine the difference between, or ratio of, acoustic signal attenuations assessed for individual sections, wherein such assessments are determined as the well progresses. An alteration in the downhole drilling process can be effected without surface intervention in order to automate the hole cleaning process, thereby improving the process. 
     In another embodiment, one or more processors can be further programmed to automatically assess acoustic signal attenuation between sections between drill string sections, wherein the sections are defined by the placement of acoustic transmitters and receivers. The processor(s) can be programmed to telemeter the attenuations to the surface whenever preset attenuation thresholds are exceeded. One or more of these processors can be programmed to determine the difference between, or ratio of, acoustic signal attenuations assessed for individual sections, wherein such assessments are determined as the well progresses. 
     When drilling a well, formation debris is removed from the drill position to the surface by travelling along an annular cavity between a drill pipe and BHA and the well bore. Referring now to the Figures,  FIG. 1(   a ) shows how the drilling fluid  2  returning to the surface carries said formation debris  1  in a reasonably uniform manner throughout the annulus  3 . This is because the fluid flow profile is reasonably uniform horizontally across the available annular area, except close to the walls defining the annulus, where the flow is reduced. If the mud flow is reduced to zero, the formation debris will settle vertically under gravity, at a rate determined in part by the fluid viscosity. Hole cleaning is determined in large part simply by mud flow rate and mud viscosity. The hole can be cleaned with stationary (non-rotating) pipe. This generally holds true for deviations from vertical up to 45°. 
     If the well deviation is between 45° and 65°, as shown in  FIG. 1B , the formation debris will move up the hole on the low side, but less efficiently than in a vertical well. In order to help their movement greater flow rate may be required, or utilizing the rotation of the drill pipe so as to stir them into the annular region of higher flow, as shown as arrow  5 . When the mud pumps are turned off the hole angle is too high for practical fluid viscosities to have a significant effect in keeping the formation debris in suspension. They will slide (avalanche) downhole, forming ‘dunes’. 
     In all high angle wells (&gt;65° to 90°) the formation debris will move as sand on a beach, settling  6  in the lowest part of the well bore, with almost no formation debris being lifted into the high flow area (shown as arrow  7 ). Mechanical agitation is necessary for formation debris movement, independent of flow rate and mud viscosity. This is indicated in  FIG. 1C , where we show the substantial mud flow rate occurring above the formation debris, the formation debris settling  6  out in the short distance to the lower side of the well. 
     When the formation debris is held in suspension the effective density of the fluid increases (rock specific gravity with respect to water is typically 2.2 to 2.6, and mud specific gravity is typically 1.1 to 1.3). This can be measured by ECD techniques and hole cleaning efforts can be applied accordingly. Once the formation debris is supported by the well bore the mud density returns to normal and ECD is ineffective. 
     The normal technique to introduce formation debris into the higher velocity portion of the mud flow is to rotate the drill pipe. Directional drilling usually requires a section of each drill pipe advance (typically ˜30 ft) to be a combination of rotating and sliding in order to maintain a required inclination. Formation debris beds form in high angle wells while sliding, which may be dissipated during the rotation section. If the drilling fluid viscosity is minimal—for instance when the fluid is air—it can be seen that formation debris build-up can be a serious issue. High speed pipe rotation and ‘working the pipe’ (maximum flow rate, slowly moving the drill string up and down over a length of drill pipe for tens of minutes to several hours) may be the only ways to ensure formation debris is adequately removed. 
     It is generally accepted in the industry that hole cleaning enhancement using the rotation movement of the drill pipe alone is due to one or both of two effects—viscous coupling of the rotating pipe to the drilling fluid, and the tendency of the drill pipe to form a helical shape in the axial direction (corkscrew). Viscous coupling is thought to help formation debris rotate into the areas of higher fluid flow, thereby helping their movement out of the hole. The corkscrew deviation of the drill pipe from simple axially-straight curves can be at a maximum when there is significant weight on the bit due to the drill string&#39;s own self-weight. Rotation of the drill string will cause now cause further mechanical agitation that can help sweep the formation debris into a higher speed fluid location in the annulus, helping the debris to be transported uphole. It is apparent that moving formation debris away from the drill bit, BHA or drill string at any location in a high angle well to the surface depends significantly on the flow rate, density and viscosity of the drilling fluid. 
     ECD as a means of determining how much formation debris is in the well is of no use in air drilling as the air is relatively ineffective in holding formation debris in suspension. Mechanical motion that induces formation debris to be blown past pipe connection joints (or upsets) must be relied upon, and is very much less efficient than when the drilling fluid significantly comprises a liquid. 
       FIG. 2  in very simplified form shows the configuration of a typical drill string  10 . At the bottom of the drill string is a bottom hole assembly (BHA)  20  comprising a drilling motor and drill bit  21 , and a telemetry device  22  upstring from the motor and bit  21 . In this embodiment the telemetry device  22  is an acoustic telemetry tool that measures certain drilling parameters and transmits this data encoded onto an acoustic telemetry signal, this signal moving primarily along the steel walls of the drill string&#39;s tubular members and towards the surface  24 . The BHA components are attached to drill pipe  23  that forms a link to the surface  24  and the rig (not shown). The drill pipe  23  are usually tubes that have a means of being screwed together, their main purpose being to transport drilling fluid to the motor and bit  21 , and to form a durable mechanical link between rig and the BHA  10 . 
       FIG. 3  is a representation of the drill string  10  in a simple 3-section horizontal well. The first section drilled is a vertical section  31 ; following is a build section  32 , finally followed by a horizontal section  33 . As these sections are drilled they typically have progressively smaller diameters. For instance the vertical section  31  may be drilled with a 12.25″ bit while the horizontal section  33  may be drilled with a 6.25″ bit. The formation debris  1  would accumulate in the vertical section  31  and up to 45° of the build section  32  as indicated in  FIG. 1A . From 45° to 65° of the build section  32  the formation debris  1  would form dunes as shown in  FIG. 1B . Finally, moving to the horizontal section  33  the formation debris  1  would form as shown in  FIG. 1C . A well drilled with a liquid is reasonably effective in moving formation debris in the scenarios considered, except perhaps for extended reach wells where particular care has to be taken in long horizontal sections. But a well drilled with air is much more difficult to clean. The only method that works is to rotate the drill pipe at a rate that mechanically agitates the formation debris into the high flow rate regime within the annulus. The rotation rate is often very limited by torque as the higher friction of the drillstring in air is significantly greater than in liquid. This is not always appropriate for directional drilling control, so formation debris can build up much more quickly than with a liquid drilling fluid. 
     An acoustic telemetry signal  34  is generated close to the bit  21  by the telemetry device  22  and is propagated towards the rig at the surface  24 . As noted previously, the signal  34  is launched within the steel of the BHA  20  and continues in the steel walls of the drill pipe  23 . The drill pipe  23  forms frequency passbands and stopbands so for the signal  34  to travel any substantial distance along the pipe  23  it must lie within one of these passbands. The acoustic signals are usually in the form of extensional waves, thereby causing the walls of the pipe  23  to alternately expand and contract in an axial direction. If the pipe  23  is constrained in this movement by the local presence of formation debris  1 , such formation debris  1  can form an attenuation mechanism, the size of which is in proportion to the extent of the formation debris  1  surrounding the pipe  23 , and the force with which they connect the drill pipe to the surrounding rock formation. The size of the debris particles is also important because if they were large in comparison to the diameter of the pipe  23  there would be fewer points of contact from pipe  23  to formation through the medium of the debris, affording less opportunity for the movement of the pipe forming the extensional waves to be limited. Worst case would be close-packed debris completely surrounding or packing the drill pipe  23 .  FIG. 4  show the formation debris accumulations as appropriate for vertical (A), build (B) and horizontal (C) sections of a typical well bore  41 , wherein formation debris in these respective sections are labelled as  42 ,  45 , and  46  respectively. In the vertical section the drill pipe  23  can be in any position within the bore  41 , but the formation debris  42  are expected to be of low concentration around the pipe  43 , and dispersed reasonably uniformly within the bore (view A), thus causing relatively low signal attenuation via the mechanism latterly presented. In the 45° to 65° section of the build the formation debris  45  are expected to be of higher concentration around the drill pipe due to the formation of dunes (view B); thus the attenuation here will be greater than previously. In the 65° to 90° section of the well the formation debris  46 , particularly in an air-drilled well, will fall uniformly to the bottom of the well bore, and in poorly-cleaned wells will completely cover the drill pipe (view C). Inspection of  FIG. 2  indicates that drill pipe  23  comprises sections of narrow diameter pipe  23  joined to shorter sections of larger diameter that enable the pipe  23  to be screwed together. These larger diameter sections—upsets—generally hold the thinner pipe  23  away from the formation  44 . Thus in a clean horizontal hole the only contact would be through the upsets. If the formation debris bed (or beds) extends along the horizontal path, it is possible that the whole length of the drillstring  10  in this section and also some of the build section are in much closer formation contact due to the packing of the formation debris, as indicated in view C of  FIG. 4 . 
     The foregoing explains how formation debris may accumulate within a well bore to the possible detriment of drill pipe removal, generally leading to very costly well remediation efforts. The unique properties of acoustic telemetry are utilized in order to predict the build-up of formation debris in various sections of the well before the problem becomes a serious issue via the utility of measuring the loss in extensional wave amplitude caused by significant packing of said formation debris around the drill pipe and BHA. 
     Drill Pipe Attenuation 
     As already mentioned, the signal attenuation along the pipe has many causes. Once the pipe tally defining the length of each individual pipe and its specific geometry is known it is possible to simulate the passage of an acoustic wave along such a drillstring and predict its attenuation/unit length using known techniques, which can be completely theoretical, or can be augmented by field measurements. From the latter we have measured attenuations of 8 dB/km along 500 m of good quality 4.75″ drill pipe, and 14 dB/km along 500 m of well-used but similar type drill pipe (several thread recuts per pipe), both sections being suspended horizontally in air. Using data like this, and applying it to an actual rig&#39;s tally provides a basis for assessing the irreducible signal loss between an acoustic transmitter relatively close to the bit, and a receiver located at surface within the rig structure. 
     In practise the attenuations measured in such situations show greater signal attenuation than would be expected from the air-based measurements. For instance, loss due to coupling between the pipe and the formation via liquid drilling fluid has a significant effect. The extent to which there is direct wall contact also has an effect of signal loss. It is found that the loss/unit length in different sections of a well are also important—in the horizontal section as shown in  FIG. 5(   a ) for example, the wall contact due to the pipe lying at the bottom of the bore under gravity provides a greater attenuation than that of the build section. Further, the loss/unit length in section c of  FIG. 5(   a ) is found to be less than the other two sections. These attenuations can be directly measured or inferred. Indeed, the different sections drilled provide a direct calibration given that the hole is reasonably clear of formation debris. 
     As the well is drilled ahead, the actual signal level loss can be determined from the actual reception of signal + noise at the rig receiver (surface receiver) minus the known signal level strength outputted by the transmitter, once the appropriate filtering has taken place. The change in the intrinsic value of signal attenuation can be estimated by modeling and compared with reality, using known methods; in other words, the intrinsic signal loss or attenuation can be predicted using the known properties of the pipe and operating conditions such as the drillpipe placement in the hole, incorporating factors such as the angle of inclination, pipe rotation speed etc. 
     In one embodiment and as shown in  FIGS. 5(   a ) and  6 , a processor  48  is at the surface  24  in the rig structure and is communicative with a surface receiver  52 , which receives the acoustic telemetry signal  34  transmitted by a single acoustic telemetry transmitter  51 , which is in the telemetry device  22  of the BHA  20  (henceforward “BHA transmitter”). The processor has a memory  49  which stores information including: the strength (amplitude) of a signal launched by the transmitter  51 , parameters related to one or more of the properties, motion, and inclination angle of a drill string section between the BHA transmitter  51  and the surface receiver. The properties of the drill string can be predetermined and stored on the memory. The inclination angle can be measured by an inclination sensor in a telemetry node on the drill string, or at another location on the drill string. The transmitter signal strength can be transmitted by the transmitter  51  or be previously stored on the memory. In this case, a BHA processor  53  is provided which can instruct the BHA transmitter  51  to send telemetry signals to the receiver  52  that include the strength of the signal launched by the BHA transmitter  51 . 
     The memory also has stored thereon a program that is executable by the processor  48  to calculate a predicted intrinsic signal attenuation data according to known techniques and using at least some of the aforementioned stored information. The memory  49  also has stored thereon a program executable by the processor  48  to calculate the actual signal level loss from an acoustic telemetry signal transmitted by the BHA transmitter  51  and received by the surface receiver  52 , by subtracting the transmitter signal strength stored in the memory  49  from the measured strength of the acoustic telemetry signal received by the surface receiver  52 . This calculated difference represents the actual signal level loss including the attenuation of the formation debris, and is also stored on the memory  49 . 
     The program stored on the memory  49  also includes a set of instructions that are executed by the processor  48  and which perform a step of subtracting the determined actual signal level loss from the predicted intrinsic signal level loss for the horizontal, the build and the vertical sections stored on the memory  49 . The calculated difference, i.e. any excess signal level loss above the intrinsic signal level loss, would be attributed to extra loss mechanisms. We attribute this extra loss mainly due to the build-up of formation debris, as has been explained. Therefore, these programmed steps executed by the processor  48  determine the signal loss caused by build-up of formation debris. This program can thus be referred to as a formation build-up determination program. 
     When the hole cleaning techniques as known in the art are implemented, the observed signal level loss reduces as expected, and further corroborates the link between signal strength changes due to the presence or absence of the amount of formation debris and their placement in the well bore. It is also reasonable to correlate the amount of formation debris that actually reach surface due to hole cleaning with the likelihood of pipe withdrawal problems and with the excess attenuation seen. Thus one useful application of this programmed method executed by the processor  48  is to predict the build-up of a ‘dangerous’ amount of formation debris via acoustic signal attenuation occurring along the drill pipe walls before it becomes a significant issue. 
     Referring to  FIG. 5(   b ) and according to another embodiment, the formation build-up determination program can be adapted to handle more complicated well configurations. In this embodiment, the system comprises multiple distributed acoustic telemetry nodes  53  located at spaced intervals along the drill string, and which augment the transfer of acoustic telemetry signals from the BHA transmitter  51 . Referring to  FIG. 6(   b ) each node  53  is provided with a node transmitter  59  for transmitting an acoustic signal through the drill pipe, and a node receiver  61  for receiving an acoustic signal transmitted through the drill pipe. Each node can also be provided with an inclination sensor  62  to measure inclination angle data used to calculate the intrinsic signal level loss. 
     The segment of the drill string between the BHA transmitter  51  and the deepest node  53  (“first node”) is referred to as “Section h” in  FIG. 5(   b ); we can estimate the attenuation along this segment according to the technique described above. Similarly, we can estimate the attenuation along different sections along the drill string, such as “Section g” between the first node  53  and the adjacent upstream node  53  (“second node”), and “Section f” between the second node  53  and the surface receiver  52 . While the attenuation value will vary in each section as the well progresses from surface to the target, the attenuation for each well section is assessed and the excess noted, providing valuable inferential formation debris knowledge to the driller. 
     It will be understood that the information may be associated with the absolute value of attenuation or attenuation/unit length, or simply the forgoing being greater than a preset threshold. 
     Each node  53  can further comprise a node processor  63  with a memory that stores data including the intrinsic signal loss of an associated drill string section and the transmitter signal strength of an adjacent node&#39;s transmitter  59 , and a program for execution by the node processor  63  and which calculates the excess attenuation of a drill string section in the vicinity of the node  53 . The time-varying information thus achieved as the well proceeds can be used to determine potential formation debris problems along significant sections of the well, thereby enabling hole cleaning procedures to be undertaken before the problems as discussed occur. 
     Each node  53  will thus calculate the actual signal level loss from a received signal transmitted by a transmitter  59  or  51  at the other end of the drill pipe section, and subtract the estimated intrinsic signal loss of that section from the actual signal loss to come up with a value that represents the excess attributed to cutting in that section (this section being the drill pipe section in the vicinity of the node  53 ). This information will be sent up-string, node  53  to node  53 , to the surface such that the driller can then take appropriate action. In an alternate embodiment, and instead of having each node  53  process and determine the formation build-up in its associated section, each node  53  can simply send the signal level each node  53  receives with its associated incoming ‘launched’ signal level of the node&#39;s transmitter and its inclination, then pass these data in an increasingly longer string to the surface where the surface processor  52  does the excess/segment calculations and alerts the driller. 
     As is well known in the industry, two-way communication is a useful feature in distributed telemetry nodes. This feature can be used to communicate relative attenuations from various sections of the drill string to the others. This can be utilized as a referential approach to the need for hole cleaning, as the following example explains. 
     By referring to  FIG. 5(   b ) we can see that section f is expected to be relatively free of excess attenuation due to formation debris build-up, thus its attenuation/unit length can be measured at timed or triggered intervals and this information be passed on to the nodes  53  at sections g and h. Section g may be suffering from too much formation debris reducing the expected signal between nodes  53 , and this section&#39;s attenuation/unit length can be related to that of section f. If the ratio (or similar) of these is above a specified amount, one of the nodes  53 , preferably though not necessarily the uppermost, can relay this information to the surface receiver  52  where appropriate action can be initiated. This approach has a specific value in that it incorporates a certain ‘calibration’ effect, where one section of the well is expected to have similar attenuation characteristics as others (same pipe type, same drilling fluid, etc.), apart from the amount of pipe contact with the wall in vertical compared to horizontal sections, and the extent of formation debris build-up. Of these two attenuators it is the latter that will significantly dominate attenuation/unit length because it is only the short sections of upsets in the drill pipe  23  (shown in  FIG. 2)  that that are normally able to touch the wall; formation debris can run the whole length of the section. Thus if the sections lengths are telemetered as necessary, or inferred via well planning data, attenuation/section above a planned threshold can be determined at regular intervals or, indeed, when a threshold is reached. This threshold would be chosen before the amount of formation debris presented a danger to the well, and before the telemetered signal was significantly compromised in amplitude at a receiving station, either downhole or at surface. 
     Given that it is possible to assess the formation debris build-up downhole in individual sections and compare via telemetry means their relative amounts of build-up, the method can be extended to control the production of formation debris via changes to, for instance, the operating parameters of the drilling motor (as would be apparent to one reasonably skilled in the art of drilling motor control), again by telemetry means. For instance, rotary steerable tools (RST) are able to semi-autonomously steer a well without surface intervention. Extensions of this capability include drill bit rotation speed, drill bit angle and flow rate control. Acoustic telemetry, as described herein, is inherently a two-way technique with extension waves able to travel both up and down the well. A surface transmitter  55  is communicative with the processor  48 , which generates a motor control signal based on the calculated debris formation in each pipe section. A simple acoustic receiver  57  (“bottomhole assembly receiver”) associated with a motorized controllable drilling means (e.g. an air hammer, a rotary steerable tool, variable orifice bit, circulating sub, combinations of same etc.) can be caused to respond to the motor control signal. Its response can therefore be to cause the drilling means system to modify its production of formation debris (either increasing or reducing as appropriate) in order to satisfy preset well drilling parameters. 
     In yet another embodiment, the local calculations performed at each node  53  are not sent to the surface receiver  52  and processor  49  are instead are used to change the drilling parameters in the BHA and control drilling operation in a manner than can offset the deleterious build-up of formation cuttings, without need of the driller&#39;s intervention. In other words, one of more nodes  53  can calculate a suitable motor control signal and send this signal to the BHA receiver  47  to control the motorized controllable drilling means, without the involvement of the surface processor  48 . 
     In summary, there are three basic embodiments that can deal with the excess signal loss due to downhole cuttings: 
     (i) The signal from the BHA transmitter  51  (closest to the drill bit) is transmitted directly to surface as shown in  FIG. 5(   a ) or by multiple nodes  53  as shown in  FIG. 5(   b ), received by the surface receiver  52  and processed entirely by the processor  48 . The calculations carried out by the processor  48  compare actual signal loss with the predicted intrinsic signal loss along the drill string, the difference being ascribed to the build-up of cuttings. This information is directly relayed to the driller to take remediative action, or to enable a surface-to-downhole motor control signal to be automatically sent by the surface transmitter  55  in order to take remediative action.
 
(ii) The acoustic signal levels in a multimode system as depicted by  FIG. 5(   b ) may be processed at each node  53 ; either the received acoustic signal and other data (such as the launched transmission level and the local drillpipe inclination, the pipe rotation speed etc.) are relayed on to the surface receiver  52  or are locally processed at the node  53  and then are relayed on to the surface receiver  52 , thereby enabling the driller to take remediative action, or to enable a surface-to-downhole signal to be automatically sent by the surface transmitter  55  in order that remediative action is taken downhole.
 
(iii) The acoustic signal levels in a multimode system as depicted by  FIG. 5(   b ) may be processed at each node  53 , utilizing data such as the launched transmission level and the local drillpipe inclination, the pipe rotation speed etc. Once processed, the cuttings excess is calculated by the node processor  63  and if greater than a specific threshold a telemetry signal is launched from that node  53  primarily for downhole reception in order that remediative action is taken, without the need for surface intervention. This method enables automatic capability of hole cleaning, without the specific necessity for surface intervention (although this can be additionally incorporated in the procedure). In effect the telemetry determination of excess attenuation relating to the sectional formation debris build-up and their values relative to each section affords a means that does not require human or surface intervention in order to keep the well clear of formation debris according to a predetermined change or series of changes in how the well is drilled. In effect the coupling of acoustic telemetry attenuation with the build-up of formation debris can form a closed-loop system for preventative hole cleaning within the scope of this invention.
 
     We do not limit the preferred embodiments of this invention to wells drilled with only or predominantly gaseous drilling fluids, in contrast to wells drilled predominantly with liquid drilling fluids, as the method has utility in both. We have merely pointed out that hole cleaning is more difficult with air than with liquid. Formation debris build-up has a generally equivalent effect on the excess attenuation of extensional acoustic waves travelling along steel pipe walls whether the fluid is air or liquid. Thus the utility of the invention applies to both cases. 
     By the utilization of the apparatus and methods described herein there is now a new tool in the oil &amp; gas drilling industry that can make drilling faster, more efficient and safer, derived from the unexpected convergence of knowledge from the mechanisms of formation debris build-up, particularly in air drilled wells, and the acoustic signal loss along the walls of drill pipe. 
     The components shown in  FIGS. 5(   a ) and  5 ( b ) are to be understood as exemplary; the technique for using these components as described are intended to apply to the multiplicity of wells that can be drilled with acoustic telemetry methods wherein the signal is launched and mainly travels along the walls of the drill pipe. 
     While particular embodiments have been described in the foregoing, it is to be understood that other embodiments are possible and are intended to be included herein. It will be clear to any person skilled in the art that modifications of and adjustments to the foregoing embodiments, not shown, are possible.