Patent Document

BACKGROUND OF THE INVENTION 
     The present disclosure relates generally to the field of telemetry systems for transmitting information through a flowing fluid. More particularly, the disclosure relates to the field of signal detection in such a system. 
     Sensors may be positioned at the lower end of a well drilling, string which, while drilling is in progress, continuously or intermittently monitor predetermined drilling parameters and formation data and transmit the information to a surface detector by some form of telemetry. Such techniques are termed “measurement while drilling” or MWD. 
     MWD may result in a major savings in drilling time and improve the quality of the well compared, for example, to conventional logging techniques. The MWD system may employ a system of telemetry in which the data acquired by the sensors is transmitted to receiver located on the surface. Fluid signal telemetry is one of the most widely used telemetry systems for MWD applications. 
     Fluid signal telemetry creates pressure signals in the drilling fluid that is circulated under pressure through the drill string during drilling operations. The information that is acquired by the downhole sensors is transmitted by suitably timing the formation of pressure signals in the fluid stream. The pressure signals are commonly detected by a pressure transducer tapped into a high pressure flow line at the surface. Access to, and penetration of the high pressure flow line may be restricted due to operational and/or safety issues. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       A better understanding of the present invention can be obtained when the following detailed description of example embodiments are considered in conjunction with the following drawings, in which: 
         FIG. 1  shows schematic example of a drilling system; 
         FIG. 2  shows an example block diagram of the acquisition of downhole data and the telemetry of such data to the surface in an example drilling operation; 
         FIGS. 3A-3D  show examples of pressure signal transmitter assemblies suitable for use in a fluid telemetry system; 
         FIG. 4  shows an example embodiment of an optical interferometer system used to detect downhole transmitted pressure signals; 
         FIG. 5  shows an example of a measurement section fiber adhered to a pliant substrate; 
         FIG. 6  is a block diagram showing an example of the processing of a received optical signal; and 
         FIG. 7  is a chart of laboratory test data showing raw interferometer data and integrated interferometer data compared to conventional pressure sensor data for pressure signal detection. 
     
    
    
     While the invention is susceptible to various modifications and alternative forms, specific embodiments thereof are shown by way of example in the drawings and will herein be described in detail. It should be understood, however, that the drawings and detailed description thereto are not intended to limit the invention to the particular form disclosed, but on the contrary, the intention is to cover all modifications, equivalents and alternatives falling within the scope of the present invention as defined by the appended claims. 
     DETAILED DESCRIPTION 
     Referring to  FIG. 1 , a typical drilling installation is illustrated which includes a drilling derrick  10 , constructed at the surface  12  of the well, supporting a drill string  14 . The drill string  14  extends through a rotary table  16  and into a borehole  18  that is being drilled through earth formations  20 . The drill string  14  may include a kelly  22  at its upper end, drill pipe  24  coupled to the kelly  22 , and a bottom hole assembly  26  (BHA) coupled to the lower end of the drill pipe  24 . The BHA  26  may include drill collars  28 , an MWD tool  30 , and a drill bit  32  for penetrating through earth formations to create the borehole  18 . In operation, the kelly  22 , the drill pipe  24  and the BHA  26  may be rotated by the rotary table  16 . Alternatively, or in addition to the rotation of the drill pipe  24  by the rotary table  16 , the BHA  26  may also be rotated, as will be understood by one skilled in the art, by a downhole motor (not shown). The drill collars add weight to the drill bit  32  and stiffen the BHA  26 , thereby enabling the BHA  26  to transmit weight to the drill bit  32  without buckling. The weight applied through the drill collars to the bit  32  permits the drill bit to crush the underground formations. 
     As shown in  FIG. 1 , BHA  26  may include an MWD tool  30 , which may be part of the drill collar section  28 . As the drill bit  32  operates, drilling fluid (commonly referred to as “drilling mud”) may be pumped from a mud pit  34  at the surface by pump  15  through standpipe  11  and kelly hose  37 , through drill string  14 , indicated by arrow  5 , to the drill bit  32 . The drilling mud is discharged from the drill bit  32  and functions to cool and lubricate the drill bit, and to carry away earth cuttings made by the bit. After flowing through the drill bit  32 , the drilling fluid flows back to the surface through the annular area between the drill string  14  and the borehole wall  19 , indicated by arrow  6 , where it is collected and returned to the mud pit  34  for filtering. The circulating column of drilling mud flowing through the drill string may also function as a medium for transmitting pressure signals  21  carrying information from the MWD tool  30  to the surface. In one embodiment, a downhole data signaling unit  35  is provided as part of MWD tool  30 . Data signaling unit  35  may include a pressure signal transmitter  100  for generating the pressure signals transmitted to the surface. 
     MWD tool  30  may include sensors  39  and  41 , which may be coupled to appropriate data encoding circuitry, such as an encoder  38 , which sequentially produces encoded digital data electrical signals representative of the measurements obtained by sensors  39  and  41 . While two sensors are shown, one skilled in the art will understand that a smaller or larger number of sensors may be used without departing from the principles of the present invention. The sensors  39  and  41  may be selected to measure downhole parameters including, but not limited to, environmental parameters, directional drilling parameters, and formation evaluation parameters. Such parameters may comprise downhole pressure, downhole temperature, the resistivity or conductivity of the drilling mud and earth formations, the density and porosity of the earth formations, as well as the orientation of the wellbore. 
     The MWD tool  30  may be located proximate to the bit  32 . Data representing sensor measurements of the parameters discussed may be generated and stored in the MWD tool  30 . Some or all of the data may be transmitted in the form of pressure signals by data signaling unit  35 , through the drilling fluid in drill string  14 . A pressure signal travelling in the column of drilling fluid may be detected at the surface by a signal detector unit  36  employing optical fiber loop  230 . The detected signal may be decoded in controller  33 . The pressure signals may be encoded binary representations of measurement data indicative of the downhole drilling parameters and formation characteristics measured by sensors  39  and  41 . Controller  33  may be located proximate the rig floor. Alternatively, controller  33  may be located away from the rig floor. In one embodiment, controller  33  may be incorporated as part of a logging unit. 
       FIG. 2  shows a block diagram of the acquisition of downhole data and the telemetry of such data to the surface in an example drilling operation. Sensors  39  and  41  acquire measurements related to the surrounding formation and/or downhole conditions and transmit them to encoder  38 . Encoder  38  may have circuits  202  comprising analog circuits and analog to digital converters (A/D). Encoder  38  may also comprise a processor  204  in data communication with a memory  206 . Processor  204  acts according to programmed instructions to encode the data into digital signals according to a pre-programmed encoding technique. One skilled in the an will appreciate that there are a number of encoding schemes that may be used for downhole telemetry. The chosen telemetry technique may depend upon the type of pressure signal transmitter  100  used. Encoder  38  outputs encoded data  208  to data signaling unit  35 . Data signaling unit  35  generates encoded pressure signals  21  that propagate through the drilling fluid in drill string  14  to the surface. Pressure signals  21  are detected at the surface by signal detector  36  and are transmitted to controller  33  for decoding. In one example embodiment, signal detector  36  may be a fiber optic signal detector, described below. Controller  33  may comprise interface circuitry  65  and a processor  66  for decoding pressure signals  21  into data  216 . Data  216  may be output to a user interface  218  and/or an information handling system such as logging unit  220 . Alternatively, in one embodiment, the controller circuitry and processor may be an integral part of the logging unit  220 . 
       FIGS. 3A-3D  show example embodiments of pressure signal transmitter  100 .  FIG. 3A  shows a pressure signal transmitter  100   a  disposed in data signaling unit  35   a . Pressure signal transmitter  100   a  has drilling fluid  5  flowing therethrough and comprises an actuator  105  that moves a gate  110  back and forth against seat  115  allowing a portion of fluid  5  to intermittently pass through opening  102  thereby generating a negative pressure signal  116  that propagates to the surface through drilling fluid  5 . 
       FIG. 3B  shows a pressure signal transmitter  100   b  disposed in data signaling unit  35   b . Pressure signal transmitter  100   b  has drilling fluid S flowing therethrough and comprises an actuator  122  that moves a poppet  120  back and forth toward orifice  121  partially obstructing the flow of drilling fluid  5  thereby generating a positive pressure signal  126  that propagates to the surface through drilling fluid  5 . 
       FIG. 3C  shows a pressure signal transmitter  100   c  disposed in data signaling unit  35   c . Pressure signal transmitter  100   c  has drilling fluid  5  flowing therethrough and comprises an actuator  132  that continuously rotates a rotor  130  in one direction relative to stator  131 . Stator  131  has flow passages  133  allowing fluid  5  to pass therethrough. Rotor  130  has flow passages  134  and the movement of flow passages  134  past flow passages  133  of stator  131  generates a continuous wave pressure signal  136  that propagates to the surface through drilling fluid  5 . Modulation of the continuous wave pressure signal may be used to encode data therein. Modulation schemes may comprise frequency modulation and phase shift modulation. 
       FIG. 3D  shows a pressure signal transmitter  100   d  disposed in data signaling unit  35   d . Pressure signal transmitter  100   d  has drilling fluid  5  flowing there through and comprises an actuator  142  that rotates a rotor  140  back and forth relative to stator  141 . Stator  141  has flow passages  143  allowing fluid  5  to pass therethrough. Rotor  140  has flow passages  144  and the alternating movement of flow passages  144  past the flow passages  143  of stator  141  generates a continuous wave pressure signal  146  that propagates to the surface through drilling fluid  5 . Modulation of the continuous wave pressure signal may be used to encode data therein. Modulation schemes may comprise frequency modulation and phase shift modulation. 
       FIG. 4  shows an example of signal detector  36  configured as an optical interferometer  200  for detecting pressure signals in conduit  211 . Interferometer  200  comprises a light source  202 , an optical fiber loop  230 , an optical coupler/splitter  215 , and an optical detector  210  Light source  200  may be a laser diode, a laser, or a light emitting diode that emits light into optical coupler/splitter  215  where the light is split into two beams  231  and  232 . Beam  231  travels clockwise (CW) through loop  230 , and beam  232  travels counterclockwise (CCW) through loop  230 . 
     Loop  230  has a length, L, and comprises measurement section  220  and delay section  225 . In one embodiment, measurement section  220  may be 2-10 meters in length. In this example, measurement section  220  is wrapped at least partially around conduit  211 , which may be standpipe  11  of  FIG. 1 . Alternatively, measurement section  220  may be wrapped around any section of flow conduit that has pressure signals travelling therein. The length of measurement section  220  is designated by X in  FIG. 4 , and represents the length of fiber that reacts to hoop strains in standpipe  11  caused by the pressure signals therein. The optical fibers of measurement section  220  may be physically adhered to conduit  211 . Alternatively, see  FIG. 5 , measurement section  220  may comprise a length, X, of optical fiber  302  adhered in a folded pattern to a pliant substrate  300  that is attachable to a conduit. In one embodiment, pliant substrate  300  may be a biaxially-oriented polyethylene terephthalate material, for example a Mylar® material manufactured by E. I. Dupont de Nemours &amp; Co. Pliant substrate  300  may be adhesively attached, for example, to standpipe  11  of  FIG. 1  using any suitable adhesive, for example an epoxy material or a cyanoacrylate material. 
     Delay section  225  may be on the order of 500-3000 meters in length. The small diameter of optical fibers contemplated (on the order of 250 μm) allows such a length to be wound on a relatively small spool. As shown in  FIG. 4 , delay section  225  comprises a length identified as L−X. It will be seen that L is a factor in the sensitivity of the sensor. 
     Counter-propagating beams  231 ,  232  traverse loop  230  and recombine through coupler/splitter  215 , and detected by photo-detector  210 . Under uniform (constant in time) conditions, beams  231 ,  232  will recombine in phase at the detector  240  because they have both traveled equal distances around loop  230 . Consider counter-propagating beams  231 ,  232  and a time varying pressure P(t) in standpipe  11 . Beams  231 ,  232  will be in phase after they have traveled the distance X in their two paths, and they will be in phase after they have continued through the distance L−X as well. Now, let the pressure within the pipe be changing at a rate of dP/dt during the time Δt while beams  231 ,  232  travel the distance L−X, then
 
 Δt =( L−X ) n/c,  
 
where c is the speed of light, and n is the refractive index of the optical fiber. During this time interval, the pressure within the pipe changes by an amount ΔP, which acts to radially expand standpipe  11 . This expansion results in a change ΔX in the length. X, of the measurement section  220  of optical fiber  230  wrapped around conduit  211 . Although at the end of the interval Δt the two beams are in phase, they will go out of phase for the last portion of the circuit before they recombine, because the length of measurement section  220  has changed during the previous interval Δt. For the final leg of the trip around the loop, the counter-clockwise beam  232  will travel a distance that is different by an amount ΔX from the clockwise rotating beam  231 . When the beams combine at detector  210 , they will be out of phase by a phase difference, Δφ, where
 
Δφ=2π(Δ X )/ n λ,
 
where λ is the wavelength of the light emitted by source  202 . As beams  231 ,  232  are combined, it can be shown that a factor in the signal will be cos(Δφ2). Thus, counter propagating beams  231 ,  232  will be out of phase when ΔX λ.
 
     The change of the pressure in the pipe during the interval Δt is given by
 
Δ P= ( dP/dt )Δ t =( dP/dt )( L−X )( n/c ).
 
Let K be the sensitivity of the pipe to internal pressure; that is, the change in circumference of the pipe ΔC due to a change in pressure ΔP given by,
 
Δ C=K (Δ P )
 
K can be computed from dimensions and material properties of the pipe materials. For example, for a thin-wailed pipe, where D pipe &gt;10* pipe thickness, t, it can be shown that
 
 K=πD   2   pipe /2Et
 
where E is the modulus of elasticity of the pipe material. For a thick walled pipe, where D pipe ≦10* pipe thickness, t, it can be shown that
 
 K= 2π D   o   D   i   2   /E ( D   o   2   −D   i   2 )
 
where D o  and D i  are the outer and inner pipe diameters, respectively. if N coil  is the number of turns of fiber around the pipe, then
 
Δ X=N (Δ C )= N   coil   K ( dP/dt )( L−X )( n/c ).
 
     Thus, the change in length indicated by the interferometer is a function of the time derivative of the pressure signal, the number of turns N coil  of fiber on the pipe, and the length L of the delay portion of the fiber. 
       FIG. 6  is a block diagram showing an example of the processing of a received optical signal using interferometer  200 . Counter propagating beams  231 ,  232  travel through optical fiber  230  comprising measurement section  220  and delay section  225 . In this example, delay section  225  comprises multiple loops of optical fiber around a spool. Pressure signal  21  causes a lengthening of measurement section  220  which produces a phase shift in the recombined beams at detector  210 , as described previously. Detector  210  outputs a phase shift signal that is conditioned by signal conditioner  312  and outputs as an analog signal proportional to the time derivative of pressure dp/dt at  314 . The signal  314  is transmitted to A/D in block  316  where the dp/dt signal is digitized. The digitized dp/dt signal is integrated in block  318  to produce a digital signal similar to the original pressure signal P(t). The P(t) signal is then decoded in block  320  to produce data  216 . Data  216  may be used in log modules  324  to produce logs  326 . In one embodiment, optical source  202 , optical detector  210 , and signal conditioner  312  may be physically located close to conduit  211  in signal detector  36 . Alternatively, some of these items may be located away from conduit  211 , for example in controller  33 . The functional modules  316 ,  318 ,  320 ,  324 , and  326  may comprise hardware and software and may be located in controller  33 . In one embodiment, controller  33  may be a stand alone unit located in a separate location, for example a logging unit. Alternatively, controller  33  may be an integral part of a logging, unit using shared hardware and software resources. While described above with reference to a single optical signal detector on a conduit, it is intended that the present disclosure cover any number of such detectors space out along such a conduit. 
       FIG. 7  is a chart of laboratory test data showing, raw interferometer data and integrated interferometer data compared to conventional pressure sensor data for pressure signal detection. Pressure signals are generated in a flowing fluid in a flow loop. A pressure signal transmitter generates pressure signals into the flowing fluid. An interferometer similar to interferometer  200  is installed on a section of conduit. A conventional strain gauge pressure sensor is mounted within 2 m of the interferometer.  FIG. 7  shows the raw interferometer data proportional to dp/dt in curve  700 . The raw data is processed as described above to produce an integrated interferometer curve  710 . Curve  705  is the reading from the conventional pressure transducer. As shown in  FIG. 7 , integrated interferometer curve  710  is substantially similar to conventional pressure transducer curve  705 . 
     Numerous variations and modifications will become apparent to those skilled in the art. It is intended that the following claims be interpreted to embrace all such variations and modifications.

Technology Category: g