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CROSS REFERENCE TO RELATED APPLICATIONS 
   This application claims the benefit of an earlier filing date from U.S. Provisional Application Ser. No. 60/323,780 filed Sep. 20, 2001, the entire disclosure of which is incorporated herein by reference. 

   BACKGROUND 
   Related Art  
   Fluid flow in a wellbore is typically measured such that an overall or average fluid velocity is ascertained from pressure-sensing instrumentation placed downhole in the wellbore. The analyses of the dynamics of fluid flow in a wellbore typically rely on complex mathematical models that generally predict flow characteristics and do not necessarily accurately depict the fluid flow in the wellbore in real-time. Previous methods for the measurement of flow characteristics in wellbore applications utilized “indirect” measurements of skin friction; however, such methods presuppose some a priori knowledge of the flow, such as data that can be used to establish correlative or theoretical principles. Various examples of such methods include measurement of wall heat transfer, measurement of heat transfer from a hot wire, or thinning of an oil film on the surface of the fluid for which the flow characteristics are to be predicted. Such methods work for cases where the flows of the fluid are already well understood. They are generally not, however, well-suited or reliable for complex situations in which the flows include eddies or are otherwise three dimensional, are at unsteady state, flow near or around rough or curved walls, flow subject to injection or suction, or mix with foreign fluid injection or high-speed flows, especially those with impinging shock waves, high enthalpies, and/or combustive tendencies. 
   SUMMARY 
   An apparatus and method for monitoring and characterizing the fluid flow in and around the tubing string in a wellbore using signal sensors is disclosed herein. The apparatus includes a signal sensing demodulator device and a skin friction sensing device positionable within the wellbore. Both devices are in informational communication with each other. In a preferred embodiment, both devices are configured with fiber optic componentry and utilize fiber optic transmission lines to transmit the information therebetween. The skin friction sensing device is typically mounted within a surface of a tubing string in the wellbore and is engagable by a fluid flowing adjacent to the tubing string. A plurality of skin friction sensing devices may be circumferentially arranged about both the inside surface and the outside surface of the tubing string to engage fluids flowing adjacent to either or both of the corresponding surfaces. The signal sensing demodulator device may be located either at the surface of the wellbore, at a downhole location in the wellbore, or at a point distant from the wellbore. 
   The method for determining fluid flow characteristics in the wellbore includes exposing the skin friction sensing device to a fluid flow, transmitting a signal obtained as a result of a movement of the skin friction sensing device from the fluid flow to a signal sensing demodulator device, converting the signal to a numerical value, and computing a parameter of the fluid flow in the wellbore from the numerical value. Exposure of the skin friction sensing device to the fluid flow is attained by mounting the skin friction sensing device in the tubing string wall such that it can be engaged by the fluid flow and measuring the direction and drag force associated with the fluid flow. In a preferred embodiment, fiber optic componentry is utilized to sense the skin friction, transmit information, and receive the information in the demodulator device. 
   Such an apparatus and method allows for the quantification of shear force and direction of force of a fluid at a multitude of points along the flow path of the fluid, which in turn allow for the characterization of non-uniform flows associated with oil wells in which the tubing is non-vertical. 

   
     BRIEF DESCRIPTION OF THE DRAWINGS 
     Referring now to the drawings wherein like elements are numbered alike in the several FIGURES: 
       FIG. 1  is a perspective view of a cross section of a fiber optic skin friction sensor; 
       FIG. 2  is a schematic view of a cross section of a tubing string through which a fluid flows; 
       FIG. 3  is a schematic view of a cross section of a tubing string through which a first fluid flows concentrically disposed within a casing to define an annulus through which a second fluid flows; 
       FIG. 4A  is an elevation view of a cross section of a tubing string having a plurality of fiber optic skin friction sensors disposed therearound configured to monitor a fluid flow within the tubing string; 
       FIG. 4B  is an elevation view of a cross section of a tubing string having a plurality of fiber optic skin friction sensors disposed therearound configured in an alternating pattern to monitor a first fluid flow within the tubing string and a second fluid flow outside the tubing string; and 
       FIG. 5  is a schematic view of a wellbore incorporating a fiber optic flow characterization system for monitoring fluid flow in the wellbore. 
   

   DETAILED DESCRIPTION 
   The characteristics of the flow rate and the fluid flow direction of downhole wellbore fluids can be determined through the use of a fiber optic skin friction sensor, as shown and described below. Skin friction sensors measure the shear force (which is proportional to a velocity gradient of the fluid flow) associated with fluid flow past the sensor. As flow rate increases, the shear force of the flow applied to the sensor increases. The shear force of the flow effectuates a positional change in the sensor, which is translated into a quantitative value that is used to determine the rate of flow past the sensor. The direction of the flow can also be derived by resolving the direction of the applied shear force. 
   The ability to quantify shear force and the direction of force at several points along the flow path can be used to characterize non-uniform flows of downhole wellbore fluids in non-vertical environments. Additional parameters such as fluid density and viscosity can also be calculated based on data developed from liquid flow characterization tests. Furthermore, complex flow fields involving fluids of different phases or due to different types of fluids can also be quantified when other fluid parameters such as fluid density, fluid capacitance and fluid resistivity are known. For example, average flow rate for single or multi-phase fluids flowing through the tubular where the sensing devices are located, and the percentage of each fluid phase at the cross-section where the sensing devices are located, can be determined. 
   Referring to  FIG. 1 , a typical fiber optic skin friction sensor is shown generally at  10  and is referred to hereinafter as “sensor  10 ”. Sensor  10  includes a floating head  12  (also called a moving wall) that is capable of making a direct measurement of a force exerted thereon by the flow of a fluid (not shown) engaging floating head  12 . Floating head  12  is mounted to a first end of a rod  14  such that floating head  12  “floats” within an opening in a body portion  16  of sensor  10 . A second end of rod  14  is pivotally secured inside body portion  16  of sensor  10 . A disk  17  is fixedly secured at a point intermediate the first and second ends of rod  14  to define a gap  20  between disk  17  and body portion  16 . Movement of floating head  12  and disk  17  occurs in response to the effects of the shear force exerted by the flow of the fluid. 
   A reflective surface  18  is fixedly disposed on a surface of disk  17  that is adjacent to gap  20 . Reflective surface  18  is configured and positioned such that light introduced into gap  20  through optical fibers  22  is reflected off reflective surface  18  and is returned through optical fibers  22 . The position of disk  17  relative to the position of sensors (not shown) disposed on a surface opposing reflective surface  18  is a function of the shear force applied to floating head  12 . Using interferometric techniques, the sensors measure the angular position of disk  17  relative to the point at which light is introduced into gap  20 . As the position of floating head  12  is altered by the shear force of the fluid flow, the characteristics of the light transmitted back to the sensors off reflective surface  18  from optical fibers  22  are altered. Changes in these characteristics are interpreted as distances that floating head  12  is displaced from a non-flow position, from which the fluid dynamics of the system can be discerned. 
   Referring to  FIG. 2 , a wellbore is shown generally at  24 . Wellbore  24  comprises a tubing string  26  through which a fluid (not shown) flows. A flow profile for the fluid in tubing string  26  is shown at  28 . Flow profile  28  may be in either direction or both directions within tubing string  26 , as evidenced by opposing arrows radiating from a cross sectional slice of wellbore  24 . Tubing string  26  is defined by a continuous wall that forms a tubular structure through which the fluid moves. Sensor  10  is placed in the inside diameter (ID) of tubing string  26  such that a floating head of sensor  10  is adjacently positioned to the general plane of the fluid flow and such that pressure gradients or shear gradients within tubing string  26  caused by the fluid flow can cause movement of the floating head. As the fluid flows across sensor  10 , the direction and drag force of the flow are measured at the inner wall of tubing string  26  and are used to calculate the velocity of the fluid. In a preferred embodiment, a plurality of sensors  10  is distributed around the circumference of tubing string  26  to interpret the shear forces exerted on the surface of the tubing string  26  by the fluid at a particular cross sectional slice of wellbore  24 . 
   In  FIG. 3 , an alternate embodiment of a wellbore is shown generally at  124 . Wellbore  124  comprises a tubing string  126  disposed substantially concentrically within a casing  125  to define an annulus therebetween. Fluids (not shown) flow within both the annulus and tubing string  126 . A first flow profile, shown at  128 , is characteristic of a first fluid flow within tubing string  126 , and a second flow profile, shown at  129 , is characteristic of a second fluid flow within the annulus. In a manner similar to that as stated above with reference to  FIG. 2 , a first sensor  110  is placed within a wall of tubing string  126  such that a floating head thereof is engagable by the fluid flow within tubing string  126 . A second sensor  111  is then placed within the wall of tubing string  126  such that a floating head thereof is engagable by the fluid flow within the annulus. In a preferred embodiment, a plurality of first sensors  110  is distributed around the inner circumference of tubing string  126  to interpret the shear forces of the fluid flow within tubing string  126  at a particular cross sectional slice of wellbore  124 , while a plurality of second sensors  111  is distributed around the circumference of tubing string  126  to interpret the shear forces of the fluid flow within the annulus. Although depicted as being longitudinally displaced from each other in  FIG. 3 , first sensors  110  and second sensors  111  may be arranged such that sensors  110 ,  111  are disposed within a single cross sectional slice of the wall of tubing string  126 , and may be arranged in a variety of patterns. 
   Referring now to  FIGS. 4A and 4B , arrangements of sensors  10  and alternating configurations of first sensors  110  and second sensors  111  are shown on cross sections of tubing strings  26 ,  126 . In  FIG. 4A , an arrangement of sensors  10  is illustrated in which sensors  10  are each positioned to respond to a fluid flow (not shown) within tubing string  26 . Although only eight sensors are depicted, any number of sensors may be incorporated into any particular cross section of tubing string  26 . In  FIG. 4B , an arrangement of alternating first sensors  110  and second sensors  111  is shown in which first sensors  110  are positioned to respond to a fluid flow (not shown) within tubing string  126  and second sensors  111  are positioned to respond to a fluid flow (not shown) adjacent to the outside surface of tubing string  126 . In either  FIG. 4A  or  FIG. 4B , at least one of the sensors of the arrangement may be another type of sensor configured to measure various parameters of downhole fluids including, but not limited to, chemical species, pressure, temperature, and density. 
   Referring to  FIG. 5 , a fiber optic flow characterization system for a wellbore is shown generally at  30  and is hereinafter referred to as “system  30 ”. System  30  comprises a fiber optic sensing demodulator instrument  32 , flow monitoring equipment  34  disposed within wellbore  24 , and a fiber optic communications cable  36  connecting fiber optic sensing demodulator instrument  32  and flow monitoring equipment  34  to provide informational communication therebetween. Flow monitoring equipment  34  typically includes sensing locations distributed about the circumference of tubing string  26  within wellbore  24 , as described with reference to the foregoing  FIGS. 4A and 4B . In system  30 , the sensing locations of flow monitoring equipment  34  preferably include fiber optic skin friction sensors  10  (sensors  10 ), as described above with reference to  FIG. 1 through 4 . 
   Fiber optic demodulator instrument  32  provides a light source to sensors  10  and converts a return signal from each sensor  10  to the required measurement data, which is typically drag force and direction of drag force. From such data, analysis software associated with fiber optic demodulator instrument  32  manipulates the measurement data to provide fluid flow characteristics data to the operator. Fiber optic demodulator instrument  32  is preferably located at the well head or at least at the surface of wellbore  24 , but may, however, be located downhole proximate flow monitoring equipment  34  or at any point between flow monitoring equipment  34  and the surface. Alternately, fiber optic demodulator instrument  32  may be located at any point distant from wellbore  24 . 
   In alternate embodiments of system  30  (reference made to  FIG. 1  as the device appears identical wherein each of the fiber optic connectors and implements are substituted by electrical conductors and implements), the fiber optic configurations may be substituted with electrical sensors and electrical systems. For example, the movement of floating heads of electrical Sensors may be converted into electrical signals, which in turn may be transmitted through conventional electrical wiring to a non-fiber optic demodulator instrument that converts die electrical signal to the required measurement data. 
   In any of the foregoing embodiments, the required measurement data typically includes the fluid flow rate and direction of flow at each sensing point around the circumference of the tubing string. This data can be determined and characterized in order to provide accurate modeling of fluid flow in the downhole environment. In particular, for known viscosity and density of the fluid, the flow rate of the fluid in the tubing string can be quantified. On the other hand, if the total flow rate of the fluid is known (a value that is typically obtained from a flow metering device) or if fractional flow is derived from individual or combined sensor data, then the viscosity and density of the fluid in the tubing string can be quantified. For more complex fluid flow situations involving multiple phases or particulate matter, multiple sensing points may be installed within the fiber optic flow characterization system for the wellbore to provide data sufficient for the calculation of the desired measurement data. 
   While preferred embodiments have been shown and described, various modifications and substitutions may be made thereto without departing from the spirit and scope of the invention. Accordingly, it is to be understood that the present invention has been described by way of illustration and not limitation.

Summary:
An apparatus and method for monitoring and characterizing the fluid flow in and around the tubing string in a wellbore, preferably using fiber optic componentry. The apparatus includes a signal sensing demodulator device and a skin friction sensing device positionable within the wellbore. Both devices are in informational communication with each other. The method includes exposing the skin friction sensing device to a fluid flow, transmitting a signal obtained as a result of a movement of the skin friction sensing device from the fluid flow to a signal sensing demodulator device, converting the signal to a numerical value, and computing a parameter or parameters of the fluid flow in the wellbore from the numerical value.