Abstract:
A method of utilizing fiber-optic cables either previously installed in adjacent wells or currently installed as part of the drilling or milling process to sense vibrations or acoustic signatures within an adjacent or the currently drilled wellbore. The vibrations or acoustic signatures may then be used to determine the location, including the depth, of a tool run into the well on coil tubing. In addition to determining the location of any tools run into the well on coil tubing, a determination of the operating condition of the tools may also be made based upon the vibrations or acoustic signatures of the tools received via the fiber-optic cables.

Description:
CROSS-REFERENCE TO RELATED APPLICATIONS 
       [0001]    This application claims priority to U.S. Provisional Patent Application No. 62/049,129 that was filed on Sep. 11, 2014. 
     
    
     BACKGROUND 
       [0002]    Coil tubing milling currently comprises over 70% of the coil tubing market in North America. Milling a single frac plug can take anywhere from less than 5 minutes to a couple of hours. 
         [0003]    Milling efficiency is a function of downward pressure on the mill, debris in the mill face which may include pieces from upper plugs that spin with the bit, mill or bit sharpness or condition, and motor stalls. 
         [0004]    When a coil tubing mill motor stalls, there is a brief pressure fluctuation that can be observed on surface. The pressure gauge is potentially the only indication that the motor may have stalled provided we are pumping single phase liquid milling fluids. However if  2  phase milling fluids are used, a motor stall may not be detectable by pressure fluctuations on the surface. 
         [0005]    Currently, it takes and experienced operator to determine if the mill motor is stalled. Usually such a determination is made by noticing that the mill bit is not advancing within a certain period of time. In such a case the operator will usually pull out of the hole some slight amount, re-engage the motor, and start back down. 
         [0006]    There are smart coil bottom hole assemblies that can be used to communicate the weight on the bit, differential pressure, vibration, and torque to surface. These tools provide for a complicated bottom hole assembly and require substantial training to operate. Certain technologies are able to record drilling parameters but these tools do not communicate with surface while milling. 
       SUMMARY 
       [0007]    Wells with smart completions are becoming more commonplace these days. These wells typically have fiber optic cables permanently installed in them. When fiber optic cables are installed in a well or even in a nearby well the fiber optic cables may be used as a distributed acoustic sensor, a distributed temperature sensor, or a distributed vibration sensor. All of these sensors will be referred to together as distributed sensors. 
         [0008]    In general a distributed sensor is able to measure the true acoustic field every 1 m over up to 50 km of fiber optic cable. An optical signal is pulsed into the fiber optic cable. Reflections, caused by acoustic waves vibrating the fiber optic cable are scattered back all along the fiber optic cable. By analyzing these reflections, and measuring the time between the laser pulse being launched and the signal being received, the distributed sensor can measure the acoustic signal at virtually any point along the fiber optic cable. 
         [0009]    More specifically, when a pulse of light travels down a fiber optic cable, a small amount of the light is naturally scattered, through Rayleigh, Brilliouin and Raman scattering, and returns to the sensor unit. By comparing the returning signal against a time a measurement of the light generated as well as comparing the frequency of the returning signal to the signal generated the location and frequency of temperature, and acoustic signals all along the fiber optic cable can be determined. The returning and generated signals may be compared to one another by such tools as an optical time domain reflectometer or an optical phase domain reflectometer. 
         [0010]    In other instances light pulses are sent down the fiber optic cable where the fiber optic cable includes a number of selectively placed fiber Bragg gratings and wherein the fiber optic cable is acoustically coupled to the coil tubing to allow the acoustic signals to affect the physical status of at least one Bragg grating. The change in the physical status of the Bragg grating, to determine the acoustic signature of the mill motor or mill head, may then be derived at the surface from the change in the frequency, phase, or timing of the transmitted light. Bragg gratings may be used alone or in conjunction with the distributed sensors. 
         [0011]    By listening to the acoustic signal generated by the mill motor, mill tool, or drill bit a number of conditions may be determined with great precision. Such conditions include, but are not limited to, the mill condition (a worn mill will have a differently acoustic signature than a new mill), a motor stall (a stalled motor will sound differently than a motor that is turning), debris within the wellbore (a mill not making effective contact or spinning in place without cutting will sound differently from a mill in effective engagement with the target), and the motor condition (prior to failing, or even after failure, bearings and other components generate a particular acoustic signal allowing the operator to determine if the mill motor required maintenance). 
         [0012]    By listening or otherwise monitoring the information generated by the distributed sensors while milling with coil tubing in real time conditions that may negatively impact milling efficiency can be easily detected and corrected before causing damage or wasted time. 
         [0013]    Additionally because of the extreme accuracy of distributed sensors very accurate coil depth may be determined. In many instances accuracy within 10 cm over 6000 m is possible. 
         [0014]    In those instances where fiber optic cable has not been run into the particular well that is being milled with coil tubing, the operator may utilize the fiber optic cable in a nearby well as a distributed sensor. The operator may also use a permanent fiber optic cable or a temporary fiber optic cable that has been conveyed with coil tubing, slickline, casing, or any other means of transport into one or more adjacent wells as a distributed sensor to determine milling efficiency in a well without fiber optic cable installed. 
     
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         [0015]      FIG. 1  depicts a side view of coil tubing in a well with adjacent wells having fiber optic cables. 
           [0016]      FIG. 2  depicts a top view of coil tubing in a well with adjacent wells having fiber optic cables. 
       
    
    
     DETAILED DESCRIPTION 
       [0017]      FIG. 1  depicts a coil tubing rig  20  on the surface  22  with the fiber optic line  24  connected to an optical source and detector  26 . In this instance the fiber optic line  24  is wrapped around the coil tubing  30  as the coil tubing  30  is lowered into the wellbore. In certain instances the coil tubing  30  may be manufactured or otherwise constructed such that the fiber optic line  24  is within the interior or a wall of the coil tubing  30 . Additionally the fiber optic line  24  may be attached to the coil tubing  30  without wrapping the fiber optic line  24  around the coil tubing  30 . The coil tubing rig  20  is on spooling a length of coil tubing  30 . At the lower end  32  of the coil tubing  30  is a drilling motor  34  attached to drill bit  36 . Where drill bit  36  is drilling and is located within wellbore  40 . A second wellbore  50  is located adjacent wellbore  40 . Within second wellbore  50  is a second fiber optic line  52  and a second optical source and detector  54 . A third wellbore  60  is located adjacent wellbore  40 . Within third wellbore  60  is a third fiber optic line  62  and a third optical source and detector  64 . 
         [0018]    As drilling motor  34  turns drill bit  36  the drill bit  36  detaches rock or other material from the lower end  37  of wellbore  40 . Typically during the drilling process any of the drill bit  36  or the drilling motor  34  may vibrate. Such vibrations may be caused by the normal operation of the drill bit  36  and the drilling motor  34  as the drill bit cuts through rock. While vibrations have been described as being caused by the drill bit  36  or the drilling motor  34 , any such vibrations may be caused by fluid flow, any tool, device, or portion thereof moving within the wellbore  40 . Vibrations may also be caused by the imminent failure of the drilling motor  34  or bit, by a dull or damaged drill bit  36 , or as the drill bit  36  moves in place without removing rock cuttings or other material from the lower end  37  of wellbore  40 . Any such vibrations such as vibrations  70  or  72  will pass through the earth  80  to reach fiber-optic cables  52  and  62 . The vibrations  70  or  72  will typically vary as a function of what causes the vibrations whether it was the drill bit  36  or drilling motor  34  and whether each was functioning properly or not. 
         [0019]    As the vibrations  70  and  72  reach the fiber-optic cables  52  and  62  the vibrations cause physical changes to occur within the fiber-optic cables  52  and  62 . The physical changes in the fiber-optic cables  52  and  62  allow the optical source and detectors  54  and  64  to locate the depth  90  of the device such as drilling motor  34  that is causing the vibrations. Additionally the frequency of any vibrations such as vibrations  70  and  72  coupled with the now known location of any such device causing vibrations will allow the operator to determine the exact location of the drilling motor  34  and drill bit  36  as well as knowing whether any device within the wellbore  40  is functioning properly, nearing a failure mode, or has failed. 
         [0020]    While  FIG. 1  depicts three different fiber-optic lines  62 ,  52 , and  24  being used to detect vibrations within wellbore  40  any of the fiber-optic lines  62 ,  52 , or  24  may be used singly, as a group, or in conjunction with any other existing and nearby fiber-optic line. Typically as long as a fiber-optic line such as  52  or  64  are near enough to detect vibrations from a device in a wellbore such as wellbore  40  the fiber-optic line may be used to locate devices within wellbore  40  and to determine the devices operating parameters based upon a pre-existing acoustic signature. 
         [0021]      FIG. 2  is a top-down view of a well field having a first existing wellbore  150  and a second existing wellbore  160 . A third wellbore  140  is being drilled using a coil tubing rig  122  insert coil tubing  130  into the wellbore  140 . At the lower end of coil tubing  130  is a drilling motor and a drill bit. A first fiber-optic line  124  is wrapped around the coil tubing  130  as the coil tubing  130  is lowered into wellbore  140 . The fiber-optic line  124  is attached to a first optical source and detector  126 . The first existing wellbore  150  is located adjacent wellbore  140 . Within first existing wellbore  150  is a second fiber-optic line  152  attached to a second optical source and detector  154 . The second existing wellbore  160  is located adjacent wellbore  140 . Within second existing wellbore  160  is a third fiber-optic line  162  attached to a third optical source and detector  164 . 
         [0022]    During the drilling process any of the drill bit or the drilling motor may vibrate or be caused to vibrate. Additionally, vibrations have been described may be caused by any tool, device, or portion thereof moving within the wellbore  140  or fluid flow through the wellbore or the coil tubing. Vibrations may also because to buy the imminent failure or improper operation of tools within the wellbore  140 . Any vibrations, such as vibrations  170  or  172 , will pass through the earth  180  to reach fiber-optic cables  152 ,  162 , or  124 . The vibrations  170  or  172  will typically vary as a function of what causes the vibrations whether caused by fluid flow, the drill bit. or drilling motor and whether or not each was functioning properly. 
         [0023]    As the vibrations  170  and  172  reach the fiber-optic cables  124 ,  152 , and  162  the vibrations cause physical changes to occur within the fiber-optic cables  124 ,  152 , and  162 . The physical changes in the fiber-optic cables  124 ,  152 , and  162  allow the optical source and detectors  126 ,  154 , and  164  to locate the distance  190  and  192  of the device such as drilling motor that is causing the vibrations from the detecting fiber optic cable. Additionally the frequency of any vibrations such as vibrations  170  and  172  coupled with the now known location of any such device causing vibrations will allow the operator to determine the exact location of the drilling motor and drill bit as well as knowing whether any device within the wellbore  140  is functioning properly, nearing a failure mode, or has failed. In many instances the optical source and detectors will merely supply data and the data will be used to determine location, distance, and operation of the equipment within the wellbore. 
         [0024]    While the embodiments are described with reference to various implementations and exploitations, it will be understood that these embodiments are illustrative and that the scope of the inventive subject matter is not limited to them. Many variations, modifications, additions and improvements are possible. 
         [0025]    Plural instances may be provided for components, operations or structures described herein as a single instance. In general, structures and functionality presented as separate components in the exemplary configurations may be implemented as a combined structure or component. Similarly, structures and functionality presented as a single component may be implemented as separate components. These and other variations, modifications, additions, and improvements may fall within the scope of the inventive subject matter.