Abstract:
The present invention provides a semi-passive two-way borehole communication system and method. The system includes a surface source signal generator for generating an acoustic signal. The acoustic source signal is transmitted downhole, and a downhole controllable reflector reflects a portion of the source signal back toward the surface. The reflector is controlled such that an echo signal is created, which contains information to be carried to the surface. A surface receiver is used to detect the echo signal, and a surface controller is used to decode the echo signal.

Description:
BACKGROUND OF THE INVENTION  
         [0001]    1. Field of the Invention  
           [0002]    The present invention generally relates to communications systems for use in oilfield applications and more particularly to an apparatus and method for transmitting acoustic signals between a surface location and a downhole location in a well.  
           [0003]    2. Description of the Related Art  
           [0004]    The control of oil and gas production wells constitutes an on-going concern of the petroleum industry due, in part, to the enormous monetary expense involved as well as the risks associated with environmental and safety issues.  
           [0005]    One type of conventional production system utilizes electrical submersible pumps (ESP) for pumping fluids from downhole. In addition, there are two other general types of productions systems for oil and gas wells, namely plunger lift and gas lift. Plunger lift production systems include the use of a small cylindrical plunger which travels through tubing extending from a location adjacent the producing formation down in the borehole to surface equipment located at the open end of the borehole. In general, fluids that collect in the borehole and inhibit the flow of fluids out of the formation and into the well borehole are collected in the tubing. Periodically, the end of the tubing is opened at the surface and the accumulated reservoir pressure is sufficient to force the plunger up the tubing. The plunger carries with it to the surface a load of accumulated fluids that are ejected out the top of the well thereby allowing gas to flow more freely from the formation into the borehole to be delivered to a distribution system at the surface. After the flow of gas has again become restricted due to the further accumulation of fluids downhole, a valve in the tubing at the surface of the well is closed so that the plunger then falls back down the tubing and is ready to lift another load of fluids to the surface upon the reopening of the valve.  
           [0006]    A gas lift production system includes a valve system for controlling the injection of pressurized gas from a source external to the well, such as another gas well or a compressor, into the borehole. The increased pressure from the injected gas forces accumulated formation fluids up a central tubing extending along the borehole to remove the fluids and restore the free flow of gas and/or oil from the formation into the well. In wells where liquid fall back is a problem during gas lift, plunger lift may be combined with gas lift to improve efficiency.  
           [0007]    In both plunger lift and gas lift production systems, there is a requirement for the periodic operation of a motor valve at the surface of the wellhead to control either the flow of fluids from the well or the flow of injection gas into the well to assist in the production of gas and liquids from the well. These motor valves are conventionally controlled by timing mechanisms and are programmed in accordance with principles of reservoir engineering which determine the length of time that a well should be either “shut in” and restricted from the flowing of gas or liquids to the surface and the time the well should be “opened” to freely produce. Generally, the criterion used for operation of the motor valve is strictly one of the elapse of a preselected time period. In most cases, measured well parameters, such as pressure, temperature, etc. are used only to override the timing cycle in special conditions.  
           [0008]    It will be appreciated that relatively simple, timed intermittent operation of motor valves and the like is often not adequate to control either outflow from the well or gas injection to the well so as to enhance well production. As a consequence, sophisticated computerized controllers have been positioned at the surface of production wells for control of downhole devices such as the motor valves.  
           [0009]    In addition, such computerized controllers have been used to control other downhole devices such as hydro-mechanical safety valves. These typically microprocessor based controllers are also used for zone control within a well and, for example, can be used to actuate sliding sleeves or packers by the transmission of a surface command to downhole microprocessor controllers and/or electromechanical control devices.  
           [0010]    In recent years, production well control systems have evolved to include complex communication requirements for controlling downhole tools such as various pumps and valves. Many control systems utilize information gathered by downhole sensors and transmitted uphole for determining proper valve and pump control settings. The control settings are transmitted then downhole to control the downhole devices.  
           [0011]    Telemetry between the surface controllers and downhole sensors and devices is accomplished using a two-way telemetry system. A two-way system is generally required so that information from the sensors such as pressure, temperature and flow can be sent to the surface for use by the controllers. This data is then processed at the surface by the computerized control system. Electrically submersible pumps use pressure and temperature readings received at the surface from downhole sensors to change the speed of the pump in the borehole.  
           [0012]    A signal transmitted to the surface from deep within the well requires sufficient power to ensure a signal-to-noise (S/N) ratio capable or providing useful decoding at the surface. The conventional two-way telemetry system suffers in that sufficient power supplies generally require a relatively large volume. Thus requiring complex and/or expensive downhole power supply designs. Therefore a need exists for a two-way telemetry system that provides good S/N ratio and relatively low downhole power requirements.  
         SUMMARY OF THE INVENTION  
         [0013]    The present invention addresses one or more of the above-identified problems found in conventional well communications systems by providing a semi-passive two way communications apparatus and method sending an acoustic signal using controlled reflected acoustic energy.  
           [0014]    One aspect of the invention is an apparatus for transmitting an acoustic signal between a well borehole first location and a second location comprising a signal generator located at the first location for generating an acoustic source signal. A transmitting medium is operatively associated with the signal generator for carrying the acoustic source signal to the second location. A controllable signal reflector disposed at the second location is used to reflect at least a portion of the source signal, the reflected signal being indicative of a parameter of interest. And a receiver is disposed at the first location for receiving the reflected signal.  
           [0015]    The transmitting medium may be fluid in a pipe, fluid between the pipe and borehole wall, the pipe itself or even the earth. A signal generator and receiver are selected according to the desired transmitting medium.  
           [0016]    The signal generator might be a fluid pump adapted to transmit acoustic energy into the fluid, or the generator might be a device for transmitting acoustic energy into the pipe or the earth.  
           [0017]    The receiver might include a hydrophone, a geophone or an accelerometer depending upon the transmitting medium selected.  
           [0018]    The reflected signal may be a bi-level echo signal representing a string of binary states or the reflected signal may be a multi-level echo signal.  
           [0019]    Another aspect of the present invention is a method for transmitting an acoustic signal between a well borehole first location and a second location comprising generating a source signal from the first location using signal generator. The method includes carrying the source signal to the second location along a transmitting medium operatively associated with the signal generator and reflecting at least a portion of the source signal with a controllable signal reflector disposed at the second location, the reflected signal being indicative of a parameter of interest. The method also includes detecting the reflected signal at the first location with a receiver disposed at the first location for receiving the reflected signal. 
       
    
    
     BRIEF DESCRIPTION OF THE DRAWINGS  
       [0020]    For detailed understanding of the present invention, references should be made to the following detailed description of the preferred embodiment, taken in conjunction with the accompanying drawings, in which like elements have been given like numerals and wherein:  
         [0021]    [0021]FIG. 1 is an elevation view of a production well system having a communication apparatus according to the present invention;  
         [0022]    [0022]FIG. 2 is a schematic representation of a communications method according to the present invention;  
         [0023]    FIGS.  3 A-C are plots showing characteristics of various reflection signals;  
         [0024]    FIGS.  4 A-B are alternative embodiments of controllable acoustic reflectors according to the present invention;  
         [0025]    [0025]FIG. 5 is a partial elevation view of the system of FIG. 1 showing alternative placements of surface elements of the present invention; and  
         [0026]    [0026]FIG. 6 is and alternative MWD embodiment of the present invention. 
     
    
     DESCRIPTION OF THE PREFERRED EMBODIMENT  
       [0027]    An embodiment of a production well telemetry system according to the present invention is shown in FIG. 1. The production well system  100  includes a production pipe  102  disposed in a well borehole  104 . At the surface a conventional wellhead  106  directs produced fluids through a flow line  108 . A control valve  110  and a regulator  112  coupled to the flow line  108  are used to control fluid flow to a separator  114 . The separator  114  separates the produced fluid into its component parts of gas  116  and oil  118 .  
         [0028]    Various downhole controllable devices such as hydro-mechanical safety valves  122 , and sliding sleeves or packers  124  are used for zone control within the well. These devices are preferably operated by downhole microprocessor based controllers  126  or directly controlled by a surface controller  128 . The surface controller  128  is used to transmit, for example, a command to the downhole microprocessor controllers  126  and/or the various electromechanical control devices  122  and  124 .  
         [0029]    The surface controller  128  includes a source signal generator  130  to generate an acoustic source signal comprising a series of acoustic energy pulses. The source signal is transmitted to the downhole devices via the fluid in the annulus between the production pipe and borehole wall or via a fluid line  132  the fluid within the production pipe  102 .  
         [0030]    A low power signal reflector device  134  such as a controllable diaphragm or a variable volume Helmholz resonator is used to reflect a portion of the source signal as an encoded message containing the parameters measured downhole and/or commands from the downhole microprocessor  126 .  
         [0031]    The measured parameters originate at downhole sensors  120  coupled to the production pipe  102  to sense parameters such as pressure, temperature, and flow rate, etc. for use in determining automatically control settings for the downhole controllable devices  122  and  124 .  
         [0032]    An acoustic sensor  136  is located at a selected location, preferably at the surface near or on the wellhead  106 . In a preferred embodiment, the sensor  136  is a hydrophone receiver coupled to the wellhead  106  and adapted to detect acoustic energy in the production pipe fluid or annulus fluid. Those skilled in the art would appreciate, however, that other sensors would be useful in detecting acoustic energy as well. For example, accelerometer-type sensors and geophones may also be used as a surface receiver, when the transmission medium is the production pipe or the earth as will be discussed later.  
         [0033]    The hydrophone  106  will produce an output indicative of the echo signal sensed. The output of the hydrophone is thus coupled to the surface controller such that the sensed signal is decoded and used by the surface controller to determine and set well control settings. The hydrophone is preferably coupled to the controller via an electrically conductive wire, but the coupling may be any suitable known method of data coupling, such as radio frequency (RF) or inductive coupling.  
         [0034]    [0034]FIG. 2 is a schematic representation of a signal transmitting method  200  used in the system of FIG. 1. Shown is a source signal  202  transmitted to a downhole location via the fluid  204  in a production pipe  206 . A downhole control unit  210  controls a downhole controllable reflector  208  to reflect a portion of the source signal  202  as an encoded message intended for transmission to the surface as an echo signal  212 . The echo signal  212  is sensed at the surface with a suitable receiver  214  and then decoded using the surface controller described above and shown in FIG. 1.  
         [0035]    [0035]FIG. 3A is an experimentally derived plot  300  of reflected signal amplitude  302  with respect to time  304 . Tests have shown that a reflected signal is adequately distinguishable over background noise in a production well environment over several reflection cycles. A series of reflection pulses  306   a - d  are generated by reflecting a source signal as described above and shown in FIG. 2. Although each successive reflection pulse exhibits a loss in amplitude, tests have shown as many as eight distinguishable reflection signals resulting from a single source signal pulse reflected at a depth of 8000 feet. This characteristic us used according to the present invention to transmit bi-level or multi-level acoustic signals as will now be described.  
         [0036]    [0036]FIG. 3B is an exemplary plot  320  showing bi-level signal transmission. A bi-level signal comprises approximately two amplitude states  322   a - b  of predetermined duration representing binary states of 0 and 1. This transmission method is easily conducted using a two-position diaphragm reflector or a Helmholz volume including a two-position internal volume control device such as a controllable plate or flapper valve. Using either of the diaphragm or controllable volume Helmholz resonator, one position or volume provides a large reflected portion of the source signal, while the second position or volume provides relatively little reflection of the source signal. These two distinct reflections represent binary states of “1” and “0”, respectively. Message signals can thus be sent in serial fashion by simply controlling the position of the signal reflector.  
         [0037]    As discussed above with respect to FIG. 2, the source signal is a series of pulses at a predetermined frequency. Consequently, any reflected signal will likewise be a multi-pulse signal at the predetermined frequency. The reflected signal, however, might be phase shifted.  
         [0038]    Referring back to FIG. 1, the surface receiver  136  detects the reflected signal and transmits the signal to the surface controller  128 . The received signal is decoded using a counter (not separately shown) in the controller to count reflected signal pulses or by determining the time during which a reflection remains at one of the two states. For example, a binary string such as 1010 will be encoded by the downhole reflector such that a series of large echo pulses are alternated with a series of lower amplitude echo pulses as shown in FIG. 2.  
         [0039]    [0039]FIG. 3C is a plot  330  illustrating multi-level transmitting. Multi-level transmitting is conducted by using a downhole reflector according to the present invention for reflecting the source signal to provide a reflected signal comprising multiple amplitude states  332   a - e . For example, a reflector controllably positioned to one of five different states may transmit signal states of 0, 1, 2, 3, and 4. These several states may be used to transmit multiple messages thereby increasing channel capability e.g. the number of sensor output data handling capability. This provides increased capacity for data telemetry. One skilled in the art would appreciate the fact that controlling signal duration  334  at any particular level as shown in FIG. 3 or at any particular state as shown in FIG. 3B is accomplished by control of the reflector position.  
         [0040]    [0040]FIGS. 4A and 4B are alternative embodiments for the downhole reflector of FIGS. 1 and 2. FIG. 4A is a controllable diaphragm  400 , which as shown, may utilize independently controlled pistons  402 ,  404 . Each piston is controllable to assume a number of positions. In one embodiment, the pistons  402  and  404  each include a corresponding diaphragm element  406  and  408 . Each diaphragm element  406  and  408  is a hydraulic-controlled fin-shaped member coupled to the piston and operated by a source pump (not shown) via hydraulic lines  410  and  412 . The hydraulic lines  410  and  412  are preferably integral to the tool body  414 . The fins  406  and  408  are thus controllable to one of two or more positions to effect the desired reflection characteristic. The source signal will be reflected, and at each fin position, the reflected signal will have distinguishable characteristics such as the amplitude of the signal. The length of time the fin is maintained in a particular position will determine the duration of a reflected signal.  
         [0041]    [0041]FIG. 4B is an alternative embodiment of a reflector  420  according to the present invention. The downhole reflector  420  includes a tool body  422  having an integral resonator  424 . The resonator  424  is, for example, a Helmholz resonator by which reflected signal amplidude and duration are controlled by controlling the volume of the resonator  424 .  
         [0042]    [0042]FIG. 4B shown one embodiment of such a resonator having a two-position flap  426 . The flap  426  is mounted to the body  422  on a controllable pivot  428  that allows the flap  426  to be controlled to at least two positions  426   a  and  426   b . A downhole controller and a stepper motor or solenoid (not shown) are used to control position of the flap  426 . The controller moves the flap  426  to a desired position in response to a downhole sensor output.  
         [0043]    One position  426   a  of the flap  426  results in little or no reflection of a source signal. A second position  426   b  of the flap  426  results in a substantial reflection of the source signal. Thus a binary string message is easily created that is passively transmitted to the surface as an echo signal by control of the flapper  426 .  
         [0044]    [0044]FIG. 5 shows alternative embodiments of the present invention with several locations for the surface receiver  136   a - b  and source signal generator  130   a - b  described above. As discussed above, the fluid in the annulus  502  may used as the transmission medium in these several embodiments of the present invention. The source generator  130   a  may be positioned at the surface to transmit the source signal or the source generator  130   b  may be position within the borehole  504 .  
         [0045]    In one embodiment the receiver  136   a  is located at a suitable surface location to detect a reflected signal from the main well borehole  504 . In another embodiment the receiver  136   b  is located at a surface location to sense a reflected signal using a sensing borehole  506 . The sensing borehole  506  is a small borehole drilled to meet the main borehole  504  at a suitable point downhole of all surface equipment associated with the main well operations. In this manner, noise typically generated by such surface equipment is substantially removed from the received echo signal at the sensor  136   b.    
         [0046]    The signal-transmitting medium in an alternative embodiment is not necessarily limited to using the fluid as described above. For example, the transmitting medium might be the production pipe or the earth itself. Well know techniques of inducing an acoustic signal into a pipe include the use of magnetostrictive devices, ceramics and mechanical actuators such as solenoids. Well known techniques using acoustic energy sources such as vibrator trucks, explosives and air guns may be used to induce an acoustic source signal in the earth.  
         [0047]    In either case, i.e. using the pipe or earth as the transmission medium, a hydrophone is not used as a receiver. Alternative receivers for these applications include geophones and accelerometers.  
         [0048]    Downhole signal reflectors for these alternative embodiments include any suitable controllable device for interrupting the source signal path. One possible technique is to control fluid in a fluid reservoir in the pipe. Changing the fluid pressure or volume in such a reservoir will cause a change in the pipe stiffness, thus effecting a controlled reflection or echo according to the present invention.  
         [0049]    Another embodiment includes controlling the one or more downhole packers  124  to interrupt the transmission path. This technique according to the present invention might be employed when using either the pipe  104  or earth as the transmission medium.  
         [0050]    The description of the present invention provided thus far has focused on embodiments used in a production well system. The invention, however, is useful in other applications. For example, a measurement-while-drilling system could include a two-way borehole communication apparatus according to the present invention. FIG. 6 is one MWD embodiment according to the present invention. FIG. 6 is an elevation view of a drilling system  600  in a measurement-while-drilling (MWD) arrangement according to the present invention. As would be obvious to one skilled in the art, a completion well system would require reconfiguration; however the basic components would be the same as shown. A conventional derrick  602  supports a drill string  604 , which can be a coiled tube or drill pipe. The drill string  604  carries a bottom hole assembly (BHA)  606  and a drill bit  608  at its distal end for drilling a borehole  610  through earth formations.  
         [0051]    Drilling operations include pumping drilling fluid or “mud” from a mud pit  622 , and using a circulation system  624 , circulating the mud through an inner bore of the drill string  604 . The mud exits the drill string  604  at the drill bit  608  and returns to the surface through the annular space between the drill string  604  and inner wall of the borehole  610 . The mud drives the drilling motor (when used) and it also provides lubrication to various elements of the drill string.  
         [0052]    A sensor  612  and a controllable reflector  614  are positioned on the BHA  606 . The sensor  612  may be any sensor suited to obtain a parameter of interest of the formation, the formation fluid, the drilling fluid or any desired combination or of the drilling operations. Characteristics measured to obtain to desired parameter of interest may include pressure, flow rate, resistivity, dielectric, temperature, optical properties tool azimuth, tool inclination, drill bit rotation, weight on bit, etc. The output of the sensor  612  is sent to and received by a downhole control unit (not shown separately), which is typically housed within the BHA  606 . Alternatively, the control unit may be disposed in any location along the drill string  604 . The controller further comprises a power supply (not shown) that may be a battery or mud-driven generator, a processor for processing the signal received from the sensor  612 . The reflector  614  may be any of the embodiments as described with respect to FIGS.  4 A-B, or any other configuration meeting the intent of the present invention.  
         [0053]    The downhole controller controls the acoustic reflector  614  to induce in the drill pipe  604  an acoustic wave signal representative of the sensed parameter. The reflected acoustic wave travels through the drill pipe fluid  604 , and is received by an acoustic receiver  616  disposed at a desired location on the drill string  604 , but which is typically at the surface. The receiver  616 , preferably a hydrophone when the transmitting medium is fluid, converts the acoustic wave to an output representative of the wave, thus representative of the measured downhole parameter. The converted output is then transmitted to a surface controller  620 , either by wireless communication or by any conductor suitable for transmitting the output of the receiver  616 . The surface controller  620  further comprises a processor  622  for processing the output using a program and an output device  624  such as a display unit for real-time monitoring by operating personnel, a printer, or a data storage device.  
         [0054]    The foregoing description is directed to particular embodiments of the present invention for the purpose of illustration and explanation. It will be apparent, however, to one skilled in the art that many modifications and changes to the embodiment set forth above are possible without departing from the scope and the spirit of the invention. It is intended that the following claims be interpreted to embrace all such modifications and changes.