Abstract:
A method and system are presented for transmitting data along tubing in a borehole, comprising generating an acoustic signal using a transmitter at a first location on the tubing, and receiving the acoustic signal at a receiver at a second location on the tubing. The method and system further comprise: (i) generating the acoustic signal at the transmitter at a first frequency and bit rate; (ii) receiving the acoustic signal at the first frequency at the receiver and attempting to synchronize the receiver at the first frequency, and (iiia) if the synchronization is successful, continuing to transmit the acoustic signal so as to pass the data from the transmitter to the receiver; or (iiib) if the synchronization is unsuccessful, adjusting the frequency and/or bit rate of the signal and repeating steps (i)-(iii) on the basis of the adjusted signal.

Description:
CROSS-REFERENCE TO RELATED APPLICATION 
     The present application is based on and claims priority to European Patent Application No. EP08162855, filed Aug. 22, 2008. 
     TECHNICAL FIELD 
     The present invention relates to telemetry systems for use with installations in oil and gas wells or the like. In particular, the present invention relates to the synchronization of transmitters and receivers for transmitting data and control signals between a location down a borehole and the surface, or between downhole locations themselves. 
     BACKGROUND ART 
     One of the more difficult problems associated with any borehole is to communicate measured data between one or more locations down a borehole and the surface, or between downhole locations themselves. For example, in the oil and gas industry it is desirable to communicate data generated downhole to the surface during operations such as drilling, perforating, fracturing, and drill stem or well testing; and during production operations such as reservoir evaluation testing, pressure and temperature monitoring. Communication is also desired to transmit intelligence from the surface to downhole tools or instruments to effect, control or modify operations or parameters. 
     Accurate and reliable downhole communication is particularly important when complex data comprising a set of measurements or instructions is to be communicated, i.e., when more than a single measurement or a simple trigger signal has to be communicated. For the transmission of complex data it is often desirable to communicate encoded digital signals. 
     Downhole testing is traditionally performed in a “blind fashion”: downhole tools and sensors are deployed in a well at the end of a tubing string for several days or weeks after which they are retrieved at surface. During the downhole testing operations, the sensors may record measurements that will be used for interpretation once retrieved at surface. It is only after the downhole testing tubing string is retrieved that the operators will know whether the data are sufficient and not corrupted. Similarly when operating some of the downhole testing tools from surface, such as tester valves, circulating valves, packer, samplers or perforating charges, the operators do not obtain a direct feedback from the downhole tools. 
     In this type of downhole testing operations, the operator can greatly benefit from having a two-way communication between surface and downhole. However, it can be difficult to provide such communication using a cable since inside the tubing string it limits the flow diameter and requires complex structures to pass the cable from the inside to the outside of the tubing. A cable inside the tubing is also an additional complexity in case of emergency disconnect for an offshore platform. Space outside the tubing is limited and a cable can easily be damaged. Therefore a wireless telemetry system is preferred. 
     A number of proposals have been made for wireless telemetry systems based on acoustic and/or electromagnetic communications. Examples of various aspects of such systems can be found in: U.S. Pat. No. 5,050,132; U.S. Pat. No. 5,056,067; U.S. Pat. No. 5,124,953; U.S. Pat. No. 5,128,901; U.S. Pat. No. 5,128,902; U.S. Pat. No. 5,148,408; U.S. Pat. No. 5,222,049; U.S. Pat. No. 5,274,606; U.S. Pat. No. 5,293,937; U.S. Pat. No. 5,477,505; U.S. Pat. No. 5,568,448; U.S. Pat. No. 5,675,325; U.S. Pat. No. 5,703,836; U.S. Pat. No. 5,815,035; U.S. Pat. No. 5,923,937; U.S. Pat. No. 5,941,307; U.S. Pat. No. 5,995,449; U.S. Pat. No. 6,137,747; U.S. Pat. No. 6,147,932; U.S. Pat. No. 6,188,647; U.S. Pat. No. 6,192,988; U.S. Pat. No. 6,272,916; U.S. Pat. No. 6,320,820; U.S. Pat. No. 6,321,838; U.S. Pat. No. 6,912,177; EP0550521; EP0636763; EP0773345; EP1076245; EP1193368; EP1320659; EP1882811; WO96/024751; WO92/06275; WO05/05724; WO02/27139; WO01/39412; WO00/77345; WO07/095111. 
     Because of the repetitive structure of piping structure used, the characteristic of the acoustic propagation along pipes is such that the frequency response of the channel is complex.  FIG. 13  shows the experimental and theoretical frequency response of a piping structure comprising two pipes below the wave source and eight pipes above. The spectrum has numerous peaks and troughs which are difficult to predict beforehand. Given the spectrum and the use of a mono-carrier modulation scheme, choosing a peak for the carrier frequency of the transmitted modulated signal where noise is incoherent with the signal is advantageous in term of signal to noise ratio. Choosing a carrier frequency around a locally flat channel response, i.e. no distortion, is advantageous to maximize the bit rate. In any case, choosing the carrier frequency in situ is a requirement, and the process of choosing the right frequency may take time and computing resources and has to be as simple as possible. 
     US 2006/0187755 by Robert Tingley discloses a method and system for communicating data through a drill string by transmitting multiple sets of data simultaneously at different frequencies. The Tingley reference attempts to optimize the opportunity of successful receipt despite the acoustic behavior of the drill string, and thereby avoiding the problem of selecting a single frequency. 
     Moreover, U.S. Pat. No. 5,995,449 by Clark Robison et al. discloses a method and apparatus for communicating in a wellbore utilizing acoustic signals. However, the Robison et al. disclosure relates specifically to an apparatus and method for transmitting acoustic waves through the completion liquid as a transmission medium, rather than the tubing or pipe string. 
     It is an object of the present invention to provide a system that allows automatic synchronization of transmitters and receivers on an appropriate frequency for reliable data transmission along tubing in a borehole. 
     BRIEF DISCLOSURE OF THE INVENTION 
     A first aspect of the present invention provides a method of transmitting data along tubing in a borehole, comprising generating a modulated acoustic signal using a transmitter at a first location on the tubing, and receiving the acoustic signal at a receiver at a second location on the tubing; the method further comprising: 
     (i) generating the acoustic signal at the transmitter at a first frequency and bit rate; 
     (ii) receiving the acoustic signal at the first frequency at the receiver and attempting to synchronize the receiver at the first frequency; and 
     (iiia) if the synchronization is successful, continuing to transmit the acoustic signal so as to pass the data from the transmitter to the receiver; or 
     (iiib) if the synchronization is unsuccessful, adjusting the frequency and/or bit rate of the acoustic signal and repeating steps (i)-(iii) on the basis of the adjusted signal. 
     Preferably, step (iiib) comprises adjusting the frequency to one of a predetermined set of frequencies. The predetermined set of frequencies can comprise the first frequency and more than two further frequencies, the method further comprising iterating steps (i)-(iii) though the set of frequencies until synchronization is successful. 
     Step (iiib) may also comprise adjusting the bit rate of the signal to a lower bit rate. In one embodiment, the step of adjusting the bit rate follows adjustment of frequency. 
     A preferred embodiment of the present invention further comprises retransmitting the data received by the receiver from the second location to a third location. This can be as an acoustic or electromagnetic signal. 
     A second aspect of the present invention provides a system for transmitting data along tubing in a borehole, comprising: 
     a transmitter at a first location on the tubing for generating an acoustic signal in the tubing; and 
     a receiver at a second location on the tubing for receiving the acoustic signal; wherein the transmitter is configured to transmit data at a first frequency and bit rate; and the receiver is configured to attempt to synchronize at the first frequency, such that if the synchronization is successful, the transmitter continues to transmit the signal so as to pass the data from the transmitter to the receiver; or if the synchronization is unsuccessful, the transmitter transmits the signal with an adjusted frequency and/or bit rate and the receiver attempts to synchronize on the basis of the adjusted signal. 
     The transmitter and receiver typically operate in accordance with the method according to the first aspect of the present invention. 
     Preferably, the system comprises a further transmitter at the second location for sending a signal to the transmitter at the first location to confirm synchronization. 
     A transmitter can be provided at the second location for transmitting the signal to a third location as an acoustic or electromagnetic signal. 
     The transmitter and receiver are preferably both configured to synchronize to frequencies selected from a predetermined set of frequencies. 
     The transmitter can also adjust to lower the bit rate of the transmitted signal in the event that the receiver fails to synchronize. 
     A third aspect of the present invention provides a method for demodulating a mono-carrier acoustic signal representative of particular data, wherein the modulated acoustic signal is transmitted along tubing in a borehole, the method comprising the steps of: 
     (i) transmitting a modulated acoustic signal on a predetermined carrier frequency and bit rate from a transmitter located at a first location on the tubing; 
     (ii) attempting to synchronize the modulated acoustic signal on multiple predetermined frequencies at a receiver located at a second location on the tubing; and 
     (iiia) if the synchronization is successful for one of the transmitted frequencies, decoding the data on the synchronized frequency and transmitting an acknowledgement signal on the synchronized frequency to the transmitter; or 
     (iiib) if the synchronization is unsuccessful for one of the transmitted frequencies, adjusting the carrier frequency and/or bit rate, and repeating steps (i)-(iii) on the basis of the adjusted modulated acoustic signal. 
     According to an embodiment of the third aspect, step (iiia) may further comprise transmitting the modulated acoustic signal to a receiver located at a third location on the tubing. In another preferred embodiment, step (iiib) may comprise adjusting the carrier frequency to one of a predetermined set of frequencies, and moreover the bit rate of the modulated acoustic signal may be adjusted to a lower bit rate. The adjustment of the bit rate may follow adjusting the carrier frequency. 
     In accordance with another embodiment of the present invention, step (i) comprises transmitting a modulated acoustic signal on multiple predetermined carrier frequencies. Step (iiia) of this embodiment may further comprise selecting the best synchronized frequency for transmitting an acknowledgement signal to the transmitter. 
     The predetermined carrier frequency for each embodiment may be chosen from a frequency sweep at a predetermined time where at least one frequency is chosen based on quality indicators determined at a receiver located on the tubing. 
     Further aspects, characteristics, and advantages of the present disclosure will be apparent from the following detailed description. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       Certain embodiments of the present invention will hereafter be described with reference to the accompanying drawings, wherein like reference numerals denote like elements, and: 
         FIG. 1  shows a schematic view of an acoustic telemetry system according to an embodiment of the present invention; 
         FIG. 2  shows a schematic of a modem as used in accordance with the embodiment of  FIG. 1 ; 
         FIG. 3  shows a variant of the embodiment of  FIG. 1 ; 
         FIG. 4  shows a hybrid telemetry system according to an embodiment of the present invention; 
         FIG. 5  shows a schematic view of a modem; 
         FIG. 6  shows a detailed view of a downhole installation incorporating the modem of  FIG. 5 ; 
         FIG. 7  shows one embodiment of mounting the modem according to an embodiment of the present invention; 
         FIG. 8  shows one embodiment of mounting a repeater modem according to an embodiment of the present invention; 
         FIG. 9  shows a dedicated modem sub for mounting according to an embodiment of the present invention; 
         FIGS. 10 ,  11  and  12  illustrate applications of a hybrid telemetry system according to an embodiment of the present invention; 
         FIG. 13  depicts an acoustic frequency response of a pipe structure; 
         FIG. 14  illustrates a flow diagram of a method according to an embodiment of the present invention; and 
         FIG. 15  shows a flow diagram of a receiver architecture for use in an embodiment of the present invention. 
     
    
    
     DETAILED DESCRIPTION 
     The present invention is particularly applicable to testing installations such as are used in oil and gas wells or the like.  FIG. 1  shows a schematic view of such a system. Once the well has been drilled through a formation, the drill string can be used to perform tests, and determine various properties of the formation though which the well has been drilled. In the example of  FIG. 1 , the well  10  has been lined with a steel casing  12  (cased hole) in the conventional manner, although similar systems can be used in unlined (open hole) environments. In order to test the formations, it is preferable to place testing apparatus in the well close to the regions to be tested, to be able to isolate sections or intervals of the well, and to convey fluids from the regions of interest to the surface. This is commonly done using a jointed tubular drill pipe, drill string, production tubing, or the like (collectively, tubing  14 ) which extends from the well-head equipment  16  at the surface (or sea bed in subsea environments) down inside the well to the zone of interest. The well-head equipment  16  can include blow-out preventers and connections for fluid, power and data communication. 
     A packer  18  is positioned on the tubing  14  and can be actuated to seal the borehole around the tubing  14  at the region of interest. Various pieces of downhole test equipment  20  are connected to the tubing  14  above or below the packer  18 . Such downhole equipment  20  may include, but is not limited to: additional packers; tester valves; circulation valves; downhole chokes; firing heads; TCP (tubing conveyed perforator) gun drop subs; samplers; pressure gauges; downhole flow meters; downhole fluid analyzers; and the like. 
     In the embodiment of  FIG. 1 , a sampler  22  is located above the packer  18  and a tester valve  24  located above the packer  18 . The downhole equipment  20  is connected to a downhole modem  26  which is mounted in a gauge carrier  28  positioned between the sampler  22  and tester valve  24 . The modem  26 , also referred to as an acoustic transceiver or transducer, operates to allow electrical signals from the equipment  20  to be converted into acoustic signals for transmission to the surface via the tubing  14 , and to convert acoustic tool control signals from the surface into electrical signals for operating the downhole equipment  20 . The term “data,” as used herein, is meant to encompass control signals, tool status, and any variation thereof whether transmitted via digital or analog. 
       FIG. 2  shows a schematic of the modem  26  in more detail. The modem  26  comprises a housing  30  supporting a piezo electric actuator or stack  32  which can be driven to create an acoustic signal in the tubing  14  when the modem  26  is mounted in the gauge carrier  28 . The modem  26  can also include an accelerometer  34  or monitoring piezo sensor  35  for receiving acoustic signals. Where the modem  26  is only required to act as a receiver, the piezo actuator  32  may be omitted. Transmitter electronics  36  and receiver electronics  38  are also located in the housing  30  and power is provided by means of a battery, such as a lithium rechargeable battery  40 . Other types of power supply may also be used. 
     The transmitter electronics  36  are arranged to initially receive an electrical output signal from a sensor  42 , for example from the downhole equipment  20  provided from an electrical or electro/mechanical interface. Such signals are typically digital signals which can be provided to a micro-controller  43  which modulates the signal in one of a number of known ways PSK, QPSK, QAM, and the like. The resulting modulated signal is amplified by either a linear or non-linear amplifier  44  and transmitted to the piezo stack  32  so as to generate an acoustic signal in the material of the tubing  14 . 
     The acoustic signal that passes along the tubing  14  as a longitudinal and/or flexural wave comprises a carrier signal with an applied modulation of the data received from the sensors  42 . The acoustic signal typically has, but is not limited to, a frequency in the range 1-10 kHz, preferably in the range 2-5 kHz, and is configured to pass data at a rate of, but is not limited to, about 1 bps to about 200 bps, preferably from about 5 to about 100 bps, and more preferably about 50 bps. The data rate is dependent upon conditions such as the noise level, carrier frequency, and the distance between the repeaters. A preferred embodiment of the present invention is directed to a combination of a short hop acoustic telemetry system for transmitting data between a hub located above the main packer  18  and a plurality of downhole tools and valves below and/or above said packer  18 . Then the data and/or control signals can be transmitted from the hub to a surface module either via a plurality of repeaters as acoustic signals or by converting into electromagnetic signals and transmitting straight to the top. The combination of a short hop acoustic with a plurality of repeaters and/or the use of the electromagnetic waves allows an improved data rate over existing systems. The system may be designed to transmit data as high as 200 bps. Other advantages of the present system exist. 
     The receiver electronics  38  are arranged to receive the acoustic signal passing along the tubing  14  produced by the transmitter electronics of another modem. The receiver electronics  38  are capable of converting the acoustic signal into an electric signal. In a preferred embodiment, the acoustic signal passing along the tubing  14  excites the piezo stack  32  so as to generate an electric output signal (voltage); however, it is contemplated that the acoustic signal may excite an accelerometer  34  or an additional piezo stack  35  so as to generate an electric output signal (voltage). This signal is essentially an analog signal carrying digital information. The analog signal is applied to a signal conditioner  48 , which operates to filter/condition the analog signal to be digitalized by an A/D (analog-to-digital) converter  50 . The A/D converter  50  provides a digitalized signal which can be applied to a microcontroller  52 . The microcontroller  52  is preferably adapted to demodulate the digital signal in order to recover the data provided by the sensor  42  connected to another modem, or provided by the surface. The type of signal processing depends on the applied modulation (i.e. PSK, QPSK, QAM, and the like). 
     The modem  26  can therefore operate to transmit acoustic data signals from the sensors in the downhole equipment  20  along the tubing  14 . In this case, the electrical signals from the equipment  20  are applied to the transmitter electronics  36  (described above) which operate to generate the acoustic signal. The modem  26  can also operate to receive acoustic control signals to be applied to the downhole equipment  20 . In this case, the acoustic signals are demodulated by the receiver electronics  38  (described above), which operate to generate the electric control signal that can be applied to the equipment  20 . 
     In order to support acoustic signal transmission along the tubing  14  between the downhole location and the surface, a series of repeater modems  56   a ,  56   b , etc. may be positioned along the tubing  14 . These repeater modems  56   a  and  56   b  can operate to receive an acoustic signal generated in the tubing  14  by a preceding modem and to amplify and retransmit the signal for further propagation along the drill string. The number and spacing of the repeater modems  56   a  and  56   b  will depend on the particular installation selected, for example on the distance that the signal must travel. A typical spacing between the modems is around 1,000 ft, but may be much more or much less in order to accommodate all possible testing tool configurations. When acting as a repeater, the acoustic signal is received and processed by the receiver electronics  38  and the output signal is provided to the microcontroller  52  of the transmitter electronics  36  and used to drive the piezo stack  32  in the manner described above. Thus an acoustic signal can be passed between the surface and the downhole location in a series of short hops. 
     The role of a repeater is to detect an incoming signal, to decode it, to interpret it and to subsequently rebroadcast it if required. In some implementations, the repeater does not decode the signal but merely amplifies the signal (and the noise). In this case the repeater is acting as a simple signal booster. However, this is not the preferred implementation selected for wireless telemetry systems of the present invention. 
     Repeaters are positioned along the tubing/piping string. A repeater will either listen continuously for any incoming signal or may listen from time to time. 
     The acoustic wireless signals, conveying commands or messages, propagate in the transmission medium (the tubing) in an omni-directional fashion, that is to say up and down. It is not necessary for the modem to know whether the acoustic signal is coming from another repeater above or below. The direction of the message is preferably embedded in the message itself. Each message contains several network addresses: the address of the transmitter (last and/or first transmitter) and the address of the destination modem at least. Based on the addresses embedded in the messages, the repeater will interpret the message and construct a new message with updated information regarding the transmitter and destination addresses. Messages will be transmitted from repeaters to repeaters and slightly modified to include new network addresses. 
     Referring again to  FIG. 1 , a surface modem  58  is provided at the well head  16  which provides a connection between the tubing  14  and a data cable or wireless connection  60  to a control system  62  that can receive data from the downhole equipment  20  and provide control signals for its operation. 
     In the embodiment of  FIG. 1 , the acoustic telemetry system is used to provide communication between the surface and the downhole location.  FIG. 3  shows another embodiment in which acoustic telemetry is used for communication between tools in multi-zone testing. In this case, two zones A, B of the well are isolated by means of packers  18   a ,  18   b . Test equipment  20   a ,  20   b  is located in each isolated zone A, B, corresponding modems  26   a ,  26   b  being provided in each case. Operation of the modems  26   a ,  26   b  allows the equipment  20   a ,  20   b  in each zone to communicate with each other as well as allowing communication from the surface with control and data signals in the manner described above. 
       FIG. 4  shows an embodiment of the present invention with a hybrid telemetry system. The testing installation shown in  FIG. 4  comprises a lower section  64  which corresponds to that described above in relation to  FIGS. 1 and 3 . As before, downhole equipment  66  and packer(s)  68  are provided with acoustic modems  70 . However, in this case, the uppermost modem  72  differs in that signals are converted between acoustic and electromagnetic formats.  FIG. 5  shows a schematic of the modem  72 . Acoustic transmitter and receiver electronics  74 ,  76  correspond essentially to those described above in relation to  FIG. 2 , receiving and emitting acoustic signals via piezo stacks  32  (or accelerometers). Electromagnetic (EM) receiver and transmitter electronics  78 ,  80  are also shown, each of which having an associated microcontroller  82 ,  84 ; however, it should be appreciated, that the EM receiver and transmitter electronics  78 ,  80  may also share a single microcontroller. A typical EM signal will be a digital signal typically in the range of 0.25 Hz to about 8 Hz, and more preferably around 1 Hz. This signal is received by the receiver electronics  78  and passed to an associated microcontroller  82 . Data from the microcontroller  82  can be passed to the acoustic receiver microcontroller  86  and on to the acoustic transmitter microcontroller  88  where it is used to drive the acoustic transmitter signal in the manner described above. Likewise, the acoustic signal received at the receiver microcontroller  86  can also be passed to the EM receiver microcontroller  82  and then on to the EM transmitter microcontroller  84  where it is used to drive an EM transmitter antenna to create the digital EM signal that can be transmitted along the well to the surface. In an alternative embodiment (not shown), the acoustic transmitter and receiver electronics  74 ,  76  may share a single microcontroller adapted for modulating and demodulating the digital signal. A corresponding EM transceiver (not shown) can be provided at the surface for connection to a control system. 
       FIG. 6  shows a more detailed view of a downhole installation in which the modem  72  forms part of a downhole hub  90  that can be used to provide short hop acoustic telemetry X with the various downhole tools  20  (e.g. test and circulation valves (i), flowmeter (ii), fluid analyzer (iii) and packer (iv), and other tools below the packer (iv)), and long hop EM telemetry Y to the surface. It should be understood that while not show, the EM telemetry signal may be transmitted further downhole to another downhole hub or downhole tools. 
       FIG. 7  shows the manner in which a modem  92  can be mounted in downhole equipment. In the case shown, the modem  92  is located in a common housing  94  with a pressure gauge  96 , although other housings and equipment can be used. The housing  94  is positioned in a recess  97  on the outside of a section of tubing  98  provided for such equipment and is commonly referred to as a gauge carrier  97 . By securely locating the housing  94  in the gauge carrier  97 , the acoustic signal can be coupled to the tubing  98 . Typically, each piece of downhole equipment will have its own modem for providing the short hop acoustic signals, either for transmission via the hub and long hop EM telemetry, or by long hop acoustic telemetry using repeater modems. The modem is hard wired into the sensors and actuators of the equipment so as to be able to receive data and provide control signals. For example, where the downhole equipment comprises an operable device such as a packer, valve or choke, or a perforating gun firing head, the modem will be used to provide signals to set/unset, open/close or fire as appropriate. Sampling tools can be instructed to activate, pump out, etc.; and sensors such as pressure and flow meters can transmit recorded data to the surface. In most cases, data will be recorded in tool memory and then transmitted to the surface in batches. Likewise tool settings can be stored in the tool memory and activated using the acoustic telemetry signal. 
       FIG. 8  shows one embodiment for mounting the repeater modem  100  on tubing  104 . In this case, the modem  100  is provided in an elongate housing  102  which is secured to the outside of the tubing  104  by means of clamps  106 . Each modem  100  may be a stand-alone installation, the tubing  104  providing both the physical support and signal path. 
       FIG. 9  shows an alternative embodiment for mounting the repeater modem  108 . In this case, the modem  108  is mounted in an external recess  110  of a dedicated tubular sub  112  that can be installed in the drill string between adjacent sections of drill pipe, or tubing. Multiple modems can be mounted on the sub for redundancy. 
     The preferred embodiment of the present invention comprises a two-way wireless communication system between downhole and surface, combining different modes of electromagnetic and acoustic wave propagations. It may also include a wired communication locally, for example in the case of offshore operations. The system takes advantage of the different technologies and combines them into a hybrid system, as presented in  FIG. 4 . 
     The purpose of combining the different types of telemetry is to take advantage of the best features of the different types of telemetry without having the limitations of any single telemetry means. The preferred applications for embodiments of the present invention are for single zone and multi-zone well testing in land and offshore environments. In the case of the deep and ultra-deep offshore environments, the communication link has to be established between the floating platform (not shown) and the downhole equipment  66  above and below the packer  68 . The distance between the rig floor (on the platform) and the downhole tools can be considerable, with up to 3 km of sea water and 6 km of formation/well depth. There is a need to jump via a ‘Long Hop’ from the rig floor to the top of the downhole equipment  66  but afterwards it is necessary to communicate locally between the tools  66  (sensors and actuators) via a ‘Short Hop’ within a zone or across several zones. The Short Hop is used as a communication means that supports distributed communication between the Long Hop system and the individual tools that constitute the downhole equipment  66 , as well as between some of these tools within the downhole installation. The Short Hop communication supports: measurement data; gauge pressure and temperature; downhole flowrates; fluid properties; and downhole tool status and activation commands, such as but not limited to: IRDV; samplers (multiple); firing heads (multiple); packer activation; other downhole tools (i.e., tubing tester, circulating valve, reversing valve); and the like. 
     All telemetry channels, being wireless or not, have limitations from a bandwidth, deployment, cost or reliability point of view. These are summarized in  FIG. 10 . 
     At low frequency (˜1 Hz), electromagnetic waves  120  propagate very far with little attenuation through the formation  122 . The higher the formation resistivity, the longer the wireless communication range. The main advantages of electromagnetic wave communication relate to the long communication range, the independence of the flow conditions and the tubing string configuration  124 . 
     Acoustic wave propagation  126  along the tubing string  124  can be made in such a way that each element of the system is small and power effective by using high frequency sonic wave (1 to 10 kHz). In this case, the main advantages of this type of acoustic wave communication relate to the small footprint and the medium data rate of the wireless communication. 
     Electrical or optical cable technology  128  can provide the largest bandwidth and the most predictable communication channel. The energy requirements for digital communication are also limited with electrical or optical cable, compared to wireless telemetry systems. It is however costly and difficult to deploy cable over several kilometers in a well (rig time, clamps, subsea tree) especially in the case of a temporary well installation, such as a well test. 
     In the case of deep-offshore single zone or multi-zone well testing, an appropriate topology for the hybrid communication system is to use a cable  128  (optical or electrical) from the rig floor to the seabed, an electromagnetic wireless communication  120  from the seabed to the top of the downhole equipment and an acoustic communication  126  for the local bus communication. 
     Another way to combine the telemetry technologies is to place the telemetry channels in parallel to improve the system reliability through redundancy. 
       FIGS. 11 and 12  represent two cases where two or three communication channels are placed in parallel. In  FIG. 11 , both electromagnetic  120  and acoustic  126  wireless communication is used to transmit data to the wellhead; and a cable  128  leads from the wellhead to the rig floor (not shown). In such configurations, common nodes  130  to the different communication channels can be used. Such nodes  130  have essentially the similar functions to the hub described above in relation to  FIG. 6 . In  FIG. 12 , electromagnetic  120  and acoustic  126  wireless, and cable  128  are all provided down to the downhole location, the acoustic wireless signal being used between the downhole tools. The selection of the particular communication channel used can be done at surface or downhole or at any common node between the channels. Multiple paths exist for commands to go from surface to downhole and for data and status to go from downhole to surface. In the event of communication loss on one segment of one channel, an alternate path can be used between two common nodes. 
     A preferred embodiment of the present invention is based on a protocol in which a transmitter transmits a message (i.e., a control signal or data signal) on sequential frequencies belonging to a predetermined set S f  of N frequencies until the communication succeeds. The embodiment preferably uses a receiver for parallel synchronization which simultaneously tries to demodulate the incoming signals transmitted by another tool/modem on the predetermined frequencies S f . The protocol is illustrated in  FIG. 14 , in which S f  is shown to comprise four frequencies F 1 -F 4 , however, the predetermined set of frequencies may include much more or much less. A scheme of the parallel receiver is shown in  FIG. 15 . 
     In the example illustrated in  FIG. 14 , the transmitter initially transmits a signal at frequency F 1 . The receiver attempts to synchronize at multiple frequencies, F 1 -F 4 , but due to attenuation or distortion of the signal at this frequency, is unable to synchronize with this signal on F 1  as so does not send any acknowledgement signal back to the transmitter. When starting to transmit at a given frequency, the transmitter starts a timing routine. If no acknowledgement is received from the receiver within a predetermined time interval, the transmitter times out and switches to the next frequency F 2 . This process is repeated until an acknowledgement signal is received from the receiver on the same frequency, at which time the transmitter begins data transmission. One advantage of the parallel synchronization illustrated in the example of  FIG. 14  is the robustness of the process, and the removal of the need for frequency detection. In the example of  FIG. 14 , synchronization occurs at frequency F 3 . It is contemplated that while one carrier frequency may be chosen for transmission from modem A to modem B, a different second carrier frequency may be chosen for transmission from modem B to modem A. 
     The selection of an initial transmission frequency is preferably chosen from a set of frequencies based on past experience, but may also include an automatic mechanism at the beginning of the communication. This mechanism could consists in having all the transmitters transmitting frequency sweeps at a predetermined time and all the receivers in the tubing string recording the incoming frequency sweeps, then determining the N best frequencies based on quality indicators such as amplitude, signal-to-noise ratio and spectrum flatness. 
     Based on the spectral estimate of the communication channel in various cases and assuming the set S f  is well chosen, it is very likely that there is at least one carrier frequency out of N (N being small, such as 4 or 5, but may be much more) with limited attenuation and distortion. 
       FIG. 15  shows schematically the receiver architecture used for parallel synchronization. This corresponds to the signal processing preferably implemented in the micro-controller of the receiver electronics, depicted in  FIG. 2 . After the analog signal is digitalized by the A/D converter, the resulting digitalized signal is simultaneously demodulated by the micro-controller on the predetermined set of frequencies belonging to Sf. The demodulation process preferably comprises two steps. 
     In the first step, the micro-controller simultaneously attempts to synchronize on the frequencies Sf. Where the incoming signal only has one frequency, the micro-controller attempts to synchronize on multiple frequencies, but may only succeed to synchronize on this signal frequency (the “synchronized frequency”). A synchronization process is based on correlation; where parallel synchronization consists of multiple, simultaneous correlations. If the synchronization is successful on the synchronized frequency, the beginning of the received signal is well known as well as its frequency. However, certain parameters, such as the phase and carrier frequency offset, can be estimated. In a second step, the modulated signal is decoded and the data recovered. Where the incoming signal is transmitted on multiple frequencies, the micro-controller selects the best frequency based on the highest correlation ratio and proceeds to decode the data on the best frequency. 
     In the example of  FIG. 14 , the messages are all transmitted at the same bit rate and the receiver tries to synchronize on different frequencies at a single given bit rate. In another embodiment of the present invention, the bit rate can be varied. If the signal channel is unusually very noisy and none of the transmitted signals is recovered by the receiver, the system of  FIG. 14  will not work. In order to avoid this, the receiver can also synchronize at a lower bit rate for each of the frequencies belonging to S f . 
     The transmitter will first try to transmit its messages at high bit rate. In case of failure, it will transmit them at successively lower bit rates. Since the energy per bit becomes higher as the bit rate decreases, the bit energy-to-noise ratio (Eb/N 0 ) is increased. In addition, since the signal bandwidth is reduced, the received acoustic signal is less distorted by the channel. Though this adds more complexity to the receiver and decreases the data rate, the communication becomes more robust. 
     A particularly preferred embodiment of the present invention relates to multi-zone testing (see  FIG. 4 ). In this case, the well is isolated into separate zones by packers  68 , and one or more testing tools are located in each zone. A modem is located in each zone and operates to send data to the hub  72  located above the uppermost packer. In this case, the tools in each zone operate either independently or in synchronization. The signals from each zone are then transmitted to the hub for forwarding to the surface via any of the mechanisms discussed above. Likewise, control signals from the surface can be sent down via these mechanisms and forwarded to the tools in each zone so as to operate them either independently or in concert. Signals may be transmitted to different zones utilizing multiple, redundant telemetry paths (i.e. acoustic or EM) based on a predetermined set of quality indicators related to the communication. Based on the quality indicators, the best communication path can be selected. 
     Although only a few embodiments of the present invention have been described in detail above, those of ordinary skill in the art will readily appreciate that many modifications are possible without materially departing from the teachings of the present invention. Accordingly, such modifications are intended to be included within the scope of the present invention as defined in the claims.