Abstract:
A telemetry system having: a pipe; a SCADA box acoustically coupled to the pipe; and a gauge inserted in the pipe, the gauge comprising: an acoustic wave generator; a coupler mechanically connected to the acoustic wave generator, wherein the coupler is engageable and disengageable with the pipe, wherein the coupler defines an acoustic transmission path between the acoustic wave generator and the pipe when engaged with the pipe; and a signal controller in communication with the acoustic wave generator. A method for communicating information in a wellbore from a downhole location to the surface, the method having the following steps: running a downhole gauge into a pipe within the wellbore, wherein the downhole gauge comprise an acoustic wave generator; setting the downhole gauge in the pipe; and communicating an acoustic signal between the downhole gauge and the pipe.

Description:
FIELD OF THE INVENTION  
       [0001]     The present invention relates to oil field communication and telemetry systems. More particularly the invention relates to an acoustic wireless communications system through the production tubing.  
       BACKGROUND OF THE INVENTION  
       [0002]     As new processes for drilling, completion, production, hydrocarbon enhancement, and reservoir management are developed, advancements in technologies related to temperature, pressure, and flow monitoring and downhole device control are required. Reservoir development systems must be constantly monitored to ensure maximum production. For example, with gravel-packed production systems, perforations become clogged over time, so that optimum flow rates are not maintained. To restore the production of the well, it has heretofore been a common practice to pull the entire length of production tubing out of the casing to clear the obstructed tubing perforations, or replace the perforated tubing section, and then re-install the production tubing within the casing. This task is laborious, time-consuming and expensive. Thus, to ensure more efficient production and prevent clogs or blockages, downhole monitor and control systems have been developed. Similar issues arise from artificial lift optimization, reservoir pressure monitoring, etc.  
         [0003]     In some systems, surface controllers are hardwired to downhole sensors which transmit information to the surface. For example, wire line production logging tools are used to provide downhole data on pressure, temperature, flow, gamma ray and pulse neutron using a wire line surface unit. The data is processed by surface computer equipment and control signals are then transmitted back down the same wire or an alternative wire to manipulate the operating configuration of the system downhole.  
         [0004]     Other downhole control systems use a remote computer control system with microprocessor controllers, electromechanical control devices and sensors. The microprocessor controllers transmit control signals only upon actuation by receipt of an actuation signal from an outside source, such as a surface transmitter.  
         [0005]     Downhole control systems interface with surface control systems by both wireless and hardwired transmission mediums. Wireless acoustic signals are transmitted down a tubing string, such as production pipe or coiled tubing. Acoustic transmission is also done through the casing stream, electrical line, slick line, subterranean soil around the well, tubing fluid and annulus fluid. Acoustic transmitters and receivers are well known.  
         [0006]     Acoustic downhole control systems require a solid mechanical connection between the transducer and the transmission medium. Thus, acoustic downhole control systems are permanently installed into the downhole apparatus to enable good communication between the acoustic transmitter and the acoustic transmission medium.  
         [0007]     A known system for monitoring a formation surrounding a borehole in a production well includes a formation evaluation sensor permanently located downhole in a production well having at least two boreholes, wherein at least one of the boreholes is a branch borehole, the sensor sensing a formation parameter which is not normally present within the borehole. Automatic control is initiated downhole without an initial control signal from the surface or from some other external source. The system has downhole sensors, downhole electromechanical devices, and downhole computerized control electronics whereby the control electronics automatically control the electromechanical devices based on input from the downhole sensors.  
         [0008]     The system has sensors which monitor a variety of actual downhole condition parameters, such as pressure, temperature, flow, gas influx, etc. The system is also preprogrammed to determine whether the actual condition parameters fall within an acceptable or optimal range. When the actual environmental conditions fall outside the acceptable or optimal range, the system is preprogrammed to operate a sliding sleeve, shut off device, valve, variable choke, penetrator, perf valve or gas lift tool. The system has a remote power source and operates independently of any control from the surface. Thus, the only way to change the systems operating parameters, is to pull the entire production apparatus, completion system, or drilling apparatus with the incorporated control system from the wellbore, reconfigure the control system, and reinsert the entire apparatus back into the wellbore.  
         [0009]     Permanent downhole systems may only be modified, reconfigured or serviced by pulling the entire downhole apparatus out of the wellbore. As noted above, it is laborious, time-consuming and expensive to pull the entire length of production tubing out of the casing to service and re-install a downhole control system. Further, once a permanent downhole control system is installed in a wellbore, the control system is fixed and operates from only one location during the entire time that the production system is in the wellbore. In some applications it is desirable to operate the control system at various locations and for shorter periods of time relative to the life of the entire production system.  
       SUMMARY OF THE INVENTION  
       [0010]     A first aspect of the present invention is a through tubing system which uses electronics, sensors and acoustic generators to acquire production and formation data for communication transmitted through the tubing to the surface.  
         [0011]     According to an aspect of the invention, there is provided a gauge for transmitting acoustic signals through a pipe to a receiver, the gauge having: an acoustic wave generator; a coupler mechanically connected to the acoustic wave generator, wherein the coupler is engageable and disengageable with the pipe, wherein the coupler defines an acoustic transmission path between the acoustic wave generator and the pipe when engaged with the pipe; and a signal controller in communication with the acoustic wave generator, wherein the gauge is insertable into the inside diameter of the pipe.  
         [0012]     Another aspect of the invention provides a telemetry surface system having: a pipe; a SCADA box acoustically coupled to the pipe; and a gauge inserted in the pipe, the gauge having: an acoustic wave generator; a coupler mechanically connected to the acoustic wave generator, wherein the coupler is engageable and disengageable with the pipe, wherein the coupler defines an acoustic transmission path between the acoustic wave generator and the pipe when engaged with the pipe; and a signal controller in communication with the acoustic wave generator.  
         [0013]     According to a further aspect of the invention, there is provided a method for communicating information in a wellbore from a downhole location to the surface, the method including the steps of: running a downhole gauge into a pipe within the wellbore, wherein the downhole gauge comprise an acoustic wave generator; setting the downhole gauge in the pipe; and communicating an acoustic signal between the downhole gauge and the pipe.  
         [0014]     The objects, features, and advantages of the present invention will be readily apparent to those skilled in the art upon a reading of the description of the preferred embodiments which follows. 
     
    
     BRIEF DESCRIPTION OF THE DRAWINGS  
       [0015]     The present invention is better understood by reading the following description of non-limitative embodiments with reference to the attached drawings wherein like parts of each of the several figures are identified by the same referenced characters, and which are briefly described as follows:  
         [0016]      FIG. 1  is a cross-sectional diagram of a wellbore with a wireless elementary system installed therein.  
         [0017]      FIG. 2  is an exploded, perspective view of a downhole gauge wherein a sleeve is disassembled from a main body.  
         [0018]      FIG. 3  is a cross-sectional, side view of a downhole gauge with the sleeve assembled to the main body, wherein three sections are identified: an upper section, a middle section, and a lower section.  
         [0019]      FIG. 4  is an enlarged, cross-sectional, side view of the upper section of the downhole gauge shown in  FIG. 3 .  
         [0020]      FIG. 5  is an enlarged, cross-sectional, side view of the middle section of the downhole gauge shown in  FIG. 3 .  
         [0021]      FIG. 6  is an enlarged, cross-sectional, side view of the lower section of the downhole gauge shown in  FIG. 3 . 
     
    
       [0022]     It is to be noted, however, that the appended drawings illustrate only typical embodiments of this invention and are therefore not to be considered limiting of its scope, as the invention may admit to other equally effective embodiments.  
       DETAILED DESCRIPTION OF THE INVENTION  
       [0023]     Referring to  FIG. 1 , a cross-sectional side view of a mineral production well is shown. A wireless wellbore digital data communications and sensing system (wireless telemetry system  10 ) of the present invention communicates through a production pipe  6  using compressional stress waves to transmit digital data from inside a wellbore  1  to the surface  9 . The system is composed of wireless transmission hardware, acoustic generator, microprocessor system for data acquisition, processing and power management, pressure and temperature gauges, a battery pack unit and a surface receiver/transmitter box  7  for surface data acquisition and processing. A description of the basic system, surface module and communications is disclosed in patent application Ser. No. 10/381,766, incorporated herein by reference. The surface receiver/transmitter box  7  may operate using SCADA software. The acoustic waves travel up the production pipe  6  to the surface  9  in a compression mode minimizing losses related to fluid coupling and tubing threads. The data is detected at the surface  9  using accelerometers or hydrophones. The data is processed using a surface data processing unit. The information is then displayed and stored in a personal computer  8  that interfaces to the surface system.  
         [0024]     In particular, the wellbore  1  extends below the earth&#39;s surface  9 . Casing  2  is installed in the wellbore  1  and extends from the surface  9  down into the wellbore  1 . A wellhead  3  is attached to the casing  1  above the surface  9 . The wellhead  3  is equipped with a blow out preventer  4 , in typical fashion. A flow line  5  extends from the wellhead  3  for withdrawing production fluids from the well. The production pipe  6  extends from the wellhead  3 , down through the casing  2  and into the lowest portion of the wellbore  1 .  
         [0025]     The wireless telemetry system  10  of the present invention is shown installed in the wellbore  1 . In particular, the receiver/transmitter box  7  is attached to the wellhead  3  for receiving acoustic transmissions through the wellhead. The receiver/transmitter box  7  communicates with a computer  8  via any means of transmission. For example, these devices may be connected by cables, wires, infrared, LED, microwave, acoustic, or any other transmission medium.  
         [0026]     The wireless telemetry system  10  also comprises a downhole gauge  20  which is installed in the inside diameter of the production pipe  6 . Communications between the downhole gauge  20  and the receiver/transmitter box  7  may be accomplished by any wireless transmission method, including: acoustic waves, acoustic stress waves, optical, electro-optical, electrical, electromechanical force, electromagnetic force (“EMF”), any combination of these, or any other transmission medium. The wireless data communication may be one way or bi-directional.  
         [0027]     Where acoustic telemetry devices are used to transmit communication signals, vibration frequencies are used that are unaffected by pump noise or other noise in the system. In one embodiment, piezo wafers are used to generate the acoustic signal. Alternatively, magneto-restrictive material may be used to generate the acoustic signal. The receiver/transmitter box  7  may also comprise a transceiver which receives acoustic signals transmitted from the downhole gauge  20  up through the production pipe  6 . The transceiver may include both data receivers and data transceivers which may be of any type known to persons of skill in the data transmission art.  
         [0028]     Depending on the depth of the wellbore  1 , one or more repeaters (not shown in the figures) may be positioned at various intervals between the downhole gauge  20  and the receiver/transmitter box  7 . In one embodiment of the invention, the acoustic downhole gauge  20  has a transmission range of 8,500 feet without a repeater, transmitting at 7 bits per second.  
         [0029]     The wireless telemetry system  10  may be used to monitor downhole production pressures and temperatures using wireless communications. The system may also provided a reliable transmission system for digital data from downhole to the surface using the production pipe  6  as the medium for data transfer. Further, the system may be installed at relatively low cost, because the need to pull tubing from the well is eliminated, for example, the tool may be lowered in the wellbore through the inside of the tubing. The system also provides real time communications that allow an operator to maintain complete control of the production of hydrocarbon by monitoring the downhole data. Depending on the embodiment of the invention, the tool may be retrieved from the wellbore using wireline, slickline or coil tubing. Cables, clamps, feedthrough connectors and wellhead penetrators are not required with the system of the present invention.  
         [0030]     Referring to  FIG. 2 , a perspective view of the downhole gauge  20  is shown with a sleeve  21  disassembled from a main body  22 . The main body  22  contains sensors, electronic equipment, and acoustic signal generators. It is also made up of various components for setting the downhole gauge  20  in the production pipe  6  so that an acoustic signal may be communicated from the downhole gauge  20  to the production pipe  6 . The sleeve  21  is slidingly mounted to the exterior of the main body  22  and connected by shear pins  38 ,  39 ,  58 ,  59 . Shear pins  58  mate with slots  25 , shear pins  59  mate with slots  26 , shear pins  38  mate with slots  27 , and shear pins  39  mate with slots  28 , as described more fully below. The main body  22  has two sets of slips, upper slips  36  and lower slips  56 . When the sleeve  21  is assembled on the main body  22 , the upper and lower slips  36  and  56  are exposed through upper and lower windows  23  and  24 , respectively.  
         [0031]     Referring to  FIG. 3 , a cross-sectional side view of the downhole gauge  20  is shown with the sleeve  21  assembled with the main body  22 . The downhole gauge  20  is described herein with reference to three sections, including: an upper section  30 , a middle section  40 , and a lower section  50 .  
         [0032]     Referring to  FIG. 4 , an enlarged, cross-sectional, side view of the upper section  30  of the downhole gauge  20  is shown. The upper section  30  has an upper sub  31  to which many components are attached. A fishing neck  32  is attached to the upper end of the upper sub  31 . Below the fishing neck  32 , an upper cone  35  is assembled to the upper sub  31 . A cone lock nut  34  is threaded onto the upper sub  31  immediately behind the upper cone  35 . An upper end cap  33  is slidingly attached to the upper sub  31  between the cone lock nut  34  and the fishing neck  32 . The upper sub  31  is sufficiently long to allow the upper end cap  33  to slide in the axial direction between the fishing neck  32  and the cone lock nut  34 . The sleeve  21  is attached to the upper end cap  33 . Upper slips  36  are set in an upper connector ring  37 , wherein the upper connector ring  37  is slidingly mounted on the upper sub  31 . As shown in  FIG. 2 , shear pins  38  mate with slots  27  to connect the upper connector ring  37  to the sleeve  21 . As shown in  FIG. 4 , when the sleeve  21  is assembled with the main body  22 , the upper slips  36  are exposed through upper windows  23  in the sleeve  21 .  
         [0033]     Referring to  FIG. 5 , an enlarged cross-sectional side view of the middle section  40  of the downhole gauge  20  is illustrated. The bottom portion of the upper sub  31  extends into the top of the middle section  40 , and the upper portion of a lower sub  51  extends into the bottom of the middle section  40 . The upper sub  31  and the lower sub  51  are structurally connected to each other by a spacer tube  41 . The spacer tube  41  mates with both the upper sub  31  and the lower sub  51  so as to transmit compressive forces between the subs. In particular, ends of the spacer tube  41  are tapered so that spacer tube  41  is longer at the inside diameter than at the outside diameter. The tapered ends of the spacer tube  41  mate with shoulders  45  and  46  in the upper sub  31  and lower sub  51 , respectively. The shoulders  45  and  46  are angled toward the spacer tube  41  so that when the spacer tube  41  is compressed between the upper sub  31  and the lower sub  51 , the ends of the spacer tube  41  are retained by the shoulders  45  and  46 . The sleeve  21  is shown assembled concentrically around the outside of the other components.  
         [0034]     A piezoelectric crystal  42  is positioned within the spacer tube  41  in direct contact with the bottom surface of the upper sub  31 . A lock hub  43  abuts against the lower end of the piezoelectric crystal  42  and locks or threads into the spacer tube  41 . Thus, the piezoelectric crystal  42  is securely squeezed between the upper sub  31  and the lock hub  43 . Because the piezoelectric crystal  42  is compressed between the upper sub  31  and the lock hub  43 , acoustic signals from the piezoelectric crystal  42  are effectively transmitted to the upper sub  31  and spacer tube  41 . Seals  44  are positioned between the upper sub  31  and the spacer tube  41 . Similarly, seals  44  are position between the lower sub  51  and the spacer tube  41 , so that the interior of the spacer tube  41  is isolated from formation fluids.  
         [0035]     A lower connector ring  57  is positioned concentrically about the lower sub  51 . The lower sub  51  has two shoulders for engaging the lower connector ring  57 . The lower connector ring  57  has a flange which extends radially inward to engage a shoulder of the lower sub  51 , so that the upper end of the lower connector right  57  engages one of the shoulders on the lower sub  51  and the flange engages the other shoulder of the lower sub  51 . The shoulders on the lower sub  51  limit movement by the lower connector ring  57  in the upward, axial direction.  
         [0036]     Referring to  FIG. 6 , an enlarged cross-sectional side view of the lower section  50  of the downhole gauge  20  is shown. Lower slips  56  are retained in the lower connector ring  57  on opposite sides of the lower sub  51 . A lower cone  55  is positioned concentrically about the lower sub  51  below the lower connector ring  57  and lower slips  56 . As shown in  FIG. 2 , the lower slips  56  are exposed by the sleeve  21  through lower windows  24 . Further, shear pins  58  extend from the lower cone  55  through slots  25  to connect the lower cone  55  to the sleeve  21 . Shear pins  59  extend from the lower connector ring  57  through slots  26  to connect the lower connector right  57  to the sleeve  21 .  
         [0037]     Referring again to  FIG. 6 , the lower section  50  also includes a spring holder  52  which is positioned below the lower cone  55 . A ratchet ring  53  resides concentrically in an exterior recess of the spring holder  52 . The ratchet spring  53  is biased so as to expand radially outward from the spring holder  52 . Further, the ratchet spring  53  has teeth on its exterior surface to engage with teeth on the interior surface of the sleeve  21 . When the sleeve  21  is moved in an upward, axial direction relative to the spring holder  52 , the ratchet spring  53  jumps over the teeth on the sleeve  21 . However, the ratchet spring  53  engages the teeth to prevent the sleeve  21  from moving in a downward, axial direction relative to the spring holder  52 .  
         [0038]     The lower section  50  also has an electronics module  54  which is positioned below the spring holder  52 . A cross-over tool  60  is attached to the bottom of the electronics module  54 . The lower sub  51  has a hollow bore  61  which extends along the entire longitudinal axis. The hollow bore  61  enables electrical conductors to pass through the lower sub  51  from the electronics module  54  and cross-over tool  60  up to the piezoelectric crystal  42 . Thus, command signals from the electronics module  54  are communicated to the piezoelectric crystal  42  through the lower sub  51 . The cross-over tool  60  also contains batteries, a transformer, and a data acquisition module. The electronics module  54  may be located in a separate housing from the slip section in alternative embodiments. The electronics module  54  is composed of a microprocessor circuit, analog to digital converter section and an acoustic generator drive.  
         [0039]     The downhole gauge  20  is run into the production pipe  6  on a setting tool (not shown), such as an E4 setting tool or hydraulic setting tool. In the run-in position, the upper sub  31  is extended from the upper end cap  33  and the upper slips  36  and lower slips  56  are retained within the windows  23  and  24  of the sleeve  21 . When the downhole gauge  20  reaches a desired location within the production pipe  6 , the operator sets the downhole gauge  20  by manipulating the setting tool (not shown). The setting tool pushes downward on the fishing neck  32  and pulls upward on the upper end cap  33  so that upper sub  31 , spacer tube  41 , and lower sub  51  move downwardly relative to the sleeve  21 . This relative movement causes the upper slips  36  to ride up the upper cone  35  and the lower slips  56  to ride up the lower cone  55 . Thereby, the slips  36  and  56  are pushed radially outward by the cones  35  and  55  to engage the slips  36  and  56  with the inside diameter of the production pipe  6 . The lengths of the slots  25 ,  26 ,  27  and  28  are precisely defined to ensure that both the upper and lower slips  36  and  56  engage the production pipe  6  while the upper and lower subs  31  and  51  are compressed between.  
         [0040]     In particular, slots  28  and  26  are long enough to allow sleeve  21  to move freely in the longitudinal direction to set the slips. Thus, the shear pins  39  and  59  extend into the slips  28  and  26  to restrict rotational movement by the sleeve  21 , but not axial movement. Slots  27  are shorter than slots  25  so that the upper slips  36  are set before the lower slips  56 . In particular, as the sleeve  21  moves upwardly relative to the main body  22 , the shear pins  38  are first engage by in the slots  27  to lift the upper connector ring  37 . After the upper slips have already begun to expand radially over the upper cone  35 , the shear pins  58  are engaged by the slot  25  to lift the lower cone  55  and set the lower slips  56 . Also, when the lower cone  55  slides upward relative to the lower connector ring  57  and lower slips  56 , the lower cone  55  exerts an upward force on the lower sub  31  through the lower connector ring  57 . As noted above, the lower connector ring  57  engages shoulders on the lower sub  51 . This upward force further compresses the spacer tube  41  between the upper and lower subs  31  and  51  to ensure that acoustic waves generated by the piezoelectric crystal  42  are effectively conducted through the subs  31  and  51 , to the slips  36  and  56 , and into the production pipe  6 .  
         [0041]     The downhole gauge  20  is locked in the “set” configuration by the ratchet spring  53 . As the sleeve  21  moves upwardly relative to the spring holder  52 , the ratchet spring  53  jumps over the teeth on the inside of the sleeve  21 . Thus, when the downhole gauge  20  is fully set in the production pipe  6 , the ratchet spring  53  engages the teeth on the inside of the sleeve  21  to retain the downhole gauge  20  in a “set” configuration.  
         [0042]     The downhole gauge  20  may use two sets of slips for multiple functions. They are used to hold the tool in place by securing the tool against the production pipe  6 . The upper slips  36  prevent the gauge from moving downwards while the lower slips  56  prevent the gauge from moving upwards. The second function of the slips is to couple the acoustic signals from the tool to the production pipe  6 . The slips exert a significant amount of force against the gauge to hold the gauge in place. In one embodiment of the invention, the force is created by springs located inside the gauge that are compressed when the setting tool pulls the upper end cap  33  of the gauge while pushing the fishing neck  32 . Set screws located in the sleeve are sheared by the setting forces allowing the slips to be released from the tool. In alternative embodiments of the invention, as single set of upper slips are used with no lower slips, or a single set of lower slips are used with no upper slips.  
         [0043]     In some embodiments of the invention, the outside diameter of the downhole gauge  20  is sufficiently smaller than the inside diameter of the production pipe  6  to allow production fluids to flow through the production pipe  6  even after the downhole gauge  20  is installed. For production pipe sizes between 2⅞ inches and 3½ inches, the outside diameter of the downhole gauge  20  may be about 2.08 inches. In one embodiment of the invention, the gauge is about 12 feet long.  
         [0044]     The downhole gauge  20  may also comprise sensors  29 . As shown in  FIG. 5 , the sensors  29  may be located in the lower connector ring  57 . Alternatively, the sensors  29  may be deployed at predetermined locations in the wellbore  1 . For example, the sensors  29  may be embedded in the production pipe  6  or may be connected to the downhole gauge  20  by wire lines. Further, multiple wireless tools, sensors, and gauges may be deployed in the production pipe  6  which may be controlled by the downhole gauge  20 . The downhole gauge  20  may communicate with these devices by a variety of data transmission techniques which are known. In particular, each tool, sensor, and gauge may have a unique data address for communication via single channel or broadband transmission. Further, master/slave data communications may be used to communicate with individually addressed tools, sensors, and gauges. Alternatively, different data transmission frequencies may be used to communicate with individual tools, sensors, and gauges in a broadcast transmission scheme.  
         [0045]     Tools, sensors, and gauges may be used to monitor physical characteristics of the wellbore  1 , the surrounding formation, and fluids passing through the production pipe  6 . Physical characteristics include temperature, pressure and flow rates. The sensors may comprise fiberoptic sensors, which monitor oil, water, or gas. Alternative sensors capable of monitoring chemical, mechanical, electrical or heat energy may also be used. Further, the sensors may also monitor pressure, temperature, fluid flow, fluid type, resistivity, cross-well acoustics, cross-well seismic, perforation depth, fluid characteristics, logging data, and vibration. The sensors themselves may be magneto-resistive sensors, piezoelectric sensors, quartz sensors, fiberoptic sensors, sensors fabricated from silicon on sapphire, or any other sensor known. A sapphire pressure gauge may be used. Pressure gauges capable of monitoring pressures between 0 and 15,000 psi with a pressure gauge resolution of 1.2 psi for a 5,000 psi gauge (0.3 psi resolution, alternative) may be used. For temperature sensors, temperature compensation may be built into the tool.  
         [0046]     The electronics module  54  may comprise a data acquisition tool which obtains data from the sensors and gauges. It may also comprise volatile or nonvolatile memory which stores data gathered from the sensors or gauges, or processes data to be transmitted. The memory may also be used to buffer data for transmission protocols. In one embodiment, 500 kilobytes of random access memory is provided.  
         [0047]     One embodiment of the invention enables through tubing deployment and retrievability capabilities reducing installation costs using a downhole gauge to production pipe mechanical coupling. An embodiment of the invention uses a broadband transmission technique that is immune to the acoustic impedance of the tubing i.e., the system will operate properly in most well conditions without the need to tune the transmission system. The transmission system is immune from pump noise.  
         [0048]     One embodiment of the downhole gauge utilizes extremely low power electronics requiring electrical current consumption of less than 100 micro amps during sleep mode. This extends battery life expectancy to 3 years with a 30 Ampere-Hour battery pack. High efficiency acoustic power generator technology may be used that extends the life of the battery pack to 3 years with transmission every 2 minutes. In particular, high efficiency communications encoding to reduce the number of bits transmitted to the surface from downhole minimizes battery power utilization. High speed data rate may also be used to provide a data point update every 4 seconds. The battery pack may utilize solid lithium technology that is safe for surface handling. A description of a battery pack is disclosed in patent application Ser. No. 10/381,766, incorporated herein by reference.  
         [0049]     In some embodiments of the invention, all components, including electrical components are capable of operation in temperatures between −20 and 125 degrees Celsius. These embodiments may also be able to withstand external pressures of 10,000 psi. The downhole gauge may be operated in a wellbore, transmitting data for 3 years with a single battery pack.  
         [0050]     The downhole gauge can be retrieved from the wellbore by releasing the slips from the pipe. The fishing neck located on the top of the downhole gauge can be latched to a retrieval tool on wireline, slickline or electric line allowing a surface unit to pull the tool. The slips may be released when shear screws located on the lower section of the tool are ruptured.  
         [0051]     A downhole gauge of the invention was set in 2⅞ inch tubing, at a position 500 feet below the surface. The tubing was full of water and there was no other noise in the system. After the downhole gauge was set in the tubing, the downhole gauge monitored temperature and pressure and acoustically transmitted results to the surface through the tubing. The gauge updated the temperature and pressure data every 30 seconds for about 48 minutes. The system used an XP-IO personal computer program (version 85556TA250) bedded with XP-IO (version 75099TH100). A surface system and a personal computer to acquire and process the data received from the downhole tool. Throughout the entire test, the downhole gauge transmitted a temperature of 86.6 degrees F. For the first fourteen minutes and the last twenty-eight minutes, the downhole gauge transmitted a pressure of 124.55 psi. Between minutes fourteen and twenty-eight, the downhole gauge transmitted a pressure of 123.45 psi.  
         [0052]     While the invention has been illustrated and described in detail in the drawings and foregoing description, the same is to be considered as illustrative and not restrictive in character, it being understood that only the preferred embodiment has been shown and described and that all changes and modifications that come within the spirit of the invention are desired to be protected.