according to the embodiment illustrated in fig1 , a fiber optic cable 16 is secured to a production tubing 12 and disposed in a wellbore 14 . the cable is preferably supported on the tubing such that a fluid flowing in the wellbore past the cable will cause a deformation in the fiber optic cable , regardless the state of deformation of the casing 12 . referring briefly to fig2 , a wellbore 8 is drilled in a formation 5 . to prevent wellbore 8 from collapsing and / or to otherwise line or reinforce wellbore 8 , wellbore 8 includes a string of casings 2 that are inserted and cemented in wellbore 8 . cement 3 is pumped up an annulus 4 between casing 2 and the wall of wellbore 8 to provide a bonded cement sheath that secures casing 2 in wellbore 8 . a plurality of perforations i , ii , iii extend through the casing 2 and the cement 3 and into the formation 5 . for purpose of illustration a plug 7 inserted in casing 2 . plug 7 functions as isolation between the upper part of the well conduit ( a , b & amp ; c ) and the lower part of the well conduit ( d & amp ; e ) if by design the production casing is not cemented in place , packers around / outside the production casing can be placed to isolate the different entry point to the formation ( not illustrated in the figures ) and simple holes in the casing will suffice instead of perforations . an optical cable 9 is preferably supported on the casing 2 by the cement 3 and / or by cable clamps ( not illustrated in the fig2 ) such that a fluid flowing in the adjacent wellbore will cause a deformation in the fiber optic cable . in accordance with the present invention , a downhole fluid flow sensing system is provided in which at least one fiber optic cable 9 is deployed downhole , either outside of casing , as shown in fig2 , or otherwise , such as on production tubing , as shown in fig1 . the fiber optic cable may alternatively be deployed on a velocity string , or any other downhole component that is capable of supporting the fiber optic cable . in preferred embodiments , the fiber optic cable is affixed to casing or the like , so that it is in place throughout the life of the well and is already in place whenever it becomes desirable to measure flow into the wellbore . it will be understood that discussions herein relating to fiber optic cable and measurements made therewith are made without limitation on the positioning or mode of deployment of the cable in the well . a light transmission means disposed at a first end of the fiber optic cable transmits at least one light pulse from a light source through the fiber optic cable . the cable may be double - ended , i . e . may be bent in the middle so that both ends of the cable are at the surface , or may be single - ended , with one end in the hole and one end at the surface . in the latter case , measurements can be based solely on backscattered light . in the case of a double - ended cable , a light receiving means is preferably provided at the second end , to measure the intensity of light at the second end of the fiber optic cable . when the fiber optic cable is in place in a well , fluid flowing into the well will cause acoustic vibrations , or “ noise .” when these vibrations pass through the fiber , they cause minute but detectable strain , which in turn affects the transmission and backscattering of light in the cable . thus , fluid flow can be measured using measurements of the intensity and timing of the backscattered light , intensity of the light received at the second cable end , or a combination of both . thus , in various embodiments , the system includes at least one of a detector that receives backscattered light from the second cable end and a detector that receives transmitted light at the second end . according to one embodiment , in the system illustrated in fig1 , a fiber optic cable 16 is secured to a production tubing 12 and disposed in a wellbore 14 . the cable is preferably supported on the tubing such that a fluid flowing past the cable will cause a deformation in the fiber optic cable , regardless the state of deformation of the tubing 12 . the deformation causes a detectable attenuation in the intensity of the light signal that passes through the fiber and also causes a detectable increase in the backscattered light intensity that is received by the photodetector for that point along the fiber optic cable . if cable 9 or 16 is a double - ended cable having a first end 18 and a second end 22 at the surface , as shown , a first light source 24 preferably emits light through first end 18 . a first photodetector 26 disposed at second end 22 receives the emitted light . the level or intensity of light received by the first photodetector 26 is compared to a base level , where the base level is the intensity that is received at the first photodetector 26 when the system is in normal operation with no corruption to the fiber optic cable 16 . in some embodiments , when the intensity of light detected at the first photodetector 26 falls below the base level by a predetermined amount , internal circuitry triggers a second light source that is inherent in an optical time domain reflectometer 32 ( otdr ) to transmit light into fiber optic cable 16 or 9 . if the frequency of the second light source is the same as the frequency from the first light source 24 then the first light source 24 must shut down . using otdr technology , which is known in the art , it is possible to determine an amount of backscattered light at each point along the fiber optic cable 16 . a fiber optic cable 16 inherently contains an even distribution of impurities which forces a reflection of light back toward the light source . the otdr preferably utilizes a second photodetector ( not shown ) that receives the backscattered light . in one embodiment , the otdr 32 continuously samples the amount of backscattered light at each point along the fiber optic cable 9 or 16 and compares the backscattered light intensity at along the fiber optic cable 9 or 16 with a previous sample to determine where a sufficient change in backscattered light intensity has occurred . in another embodiment , the otdr 32 is actuated by a detection of a loss in light intensity at the second end 28 of the fiber optic cable 9 or 16 . therefore , a deformation in the fiber optic cable 16 results in a loss of light intensity at the second end 28 of the fiber optic cable 16 . further , the location of the deformation along the fiber optic cable 16 can be readily determined using the otdr 32 . thus , localized flowing of liquid or gas into or out of the well will cause a deformation in fiber optic cable 16 . by determining the location of the deformation , the location of the fluid inflow can be determined . it is anticipated that the peak frequency of a signal associated with a low fluid flow rate will be lower than the peak frequency of a signal associated with a high fluid flow rate . nonetheless , it is also anticipated that various factors may affect the peak frequency and other properties of the detected signals and preferred methods will include analyzing the signals using calibration , comparison , and other techniques in order to optimally assess the received data . one or more fiber optic cables may be wrapped around the casing or tubing or otherwise mounted on or affixed to it so as to provide the desired level of sensitivity to fluid flow . at least one light source and at least one detector are preferably provided for each fiber optic cable . alternatively , an otdr having an optical switcher can operate to monitor multiple fiber optic cables . the present otdr technique as previously described is responsive to deformation ; therefore it does not have the same response as a conventional microphone . correlations of the “ noise ” from flow past a fiber in a downhole setting have not been previously known . separating out signal that is not due to flow requires data processing steps . the present otdr system preferably records signals across broad bandwidths such as less than 1 hz to larger than 5000 hz , long time frames from minutes to years , and along nearly the full length of the fibered wellbore , which enables the application of improved modeling and processing routines . the recording of data simultaneously across multiple channels and wide frequency bands allows the practitioner to identify areas that have “ clean ” signal characteristic of an identified flow regime to which a reliable correlation can be applied . correlations applied to noise due to axial flow ( for example fig2 well conduit sections a , b , c and d ) are considerably different from correlations for noise due to a localized in - or outflow point ( for example fig2 perforations i , ii and iii ) that would occur at an orifice . calculations of fluid flow for both of these regimes can be made and compared so that errors are minimized . we analyse the signals at various frequencies and ascribe meaning to the combination of frequencies and amplitudes over time and along the wellbore . by way of example only , the following steps may be carried out : 1 . input : intensity - modulated signal from otdr across multiple channels and well information 2 . assess amplitude and frequency spectra across array of channels 3 . condition data by removing signal not related to flow . this may be carried out , by way of example only , by selective frequency filtering or by identification and exclusion of data contaminated signal due to other processes . 4 . assess flow regimes across depths and times . 4 . 1 . calculate axial flow / s within conduit using relationships for axial flow . depending on the inflow / outflow contributions from the perforations i and ii , there will be a difference in the axial flow conditions for the wellbore sections a and b . the difference in axial flow will show - up as a difference in frequency spectra as well as amplitude . by way of example only , in fig2 . plug 7 is set to prevent flow between wellbore section a / b / c and d / e . unless plug 7 is leaking or a channel exists in the cement 3 , then by applying steps 3 and 4 will then show no flow conditions in wellbore section d and e . 4 . 2 . calculate inflow / outflow / s at flow points using relationships for flow through an orifice . continuing the foregoing example , for perforations i and ii , there will be a difference in frequency spectra as well as amplitude for different flow rates . in fig2 . plug 7 is set to prevent flow between wellbore section a / b / c and d / e . unless plug 7 is leaking or a channel exist in the cement 3 then by applying steps 3 and 4 will then show no flow rates at perforations iii . 5 . ( optionally ) compare results of two methods and minimize errors using additional constraining information if available ( wellhead flowrates , temperature measurements , etc .). for example , the present techniques can be used to identify during hydraulic fracturing when sand arrives at the perforations downhole . likewise , the present techniques can be used to monitor the flow into each set of perforations and identify instances of erosion . conversely , the gathered data could be used to identify the build - up of scale that might tend to close or restrict perforations during production . there are some situations in which the present system is particularly advantageous . for example , in wellbores in which a velocity string has been installed for the purpose of ensuring sufficient gas velocity , conventional techniques for measuring in - flow entail pulling the velocity string and running a production logging tool into the well . however , this technique has the drawback of changing the geometry of the well , as a result of removal of the velocity string , which in turn may affect the in - flow of fluid . in addition , this technique entails a costly removal and replacement of the velocity string . if a flow measurement system in accordance with the present invention were in place , fluid in - flow can be measured continuously , regardless of the presence or absence of a velocity string . similarly , it is often difficult to run fluid measurements devices into wells that are highly deviated , as gravity alone is not sufficient to overcome friction in the well . if a portion of the well is horizontal , it may be impossible to lower a measurement device to the bottom of the hole , or it may be necessary to use a downhole tractor to do so . in contrast , if a system in accordance with the present invention were installed during drilling or completion of the well , such efforts would not be necessary . still further , the techniques taught herein can be used in conjunction with other known techniques , such as the of a distributed temperature log , to provide more detailed or more accurate information about fluid in - flows . the present invention has been disclosed and described with respect to preferred embodiments . it will be understood , however , that various modifications can be made to the systems described herein without departing from the scope of the claims below .