Abstract:
A method and system for evaluating both fluid type and fluid flow downhole by applying thermal energy in a flow of the fluid, and monitoring downstream temperature over time to generate a temperature profile. The type of fluid being evaluated can be determined by comparing the measured temperature profile to profiles over time of known fluids because these profiles depend upon these fluids&#39; thermal diffusivities and flow rates. Further, stratified flow in a deviated wellbore can be analyzed by conducting the fluid evaluation at different radial locations in the flow stream so that the presence of water, liquid hydrocarbons, and gas can he identified. The system can include a pivoting arm that selectively spans the wellbore diameter, and which includes multiple thermal sources, each with corresponding thermal sensor, that are spaced along the arm. A frame can be provided for each of the sources and sensors, which is automatically self-oriented along the direction of fluid flow like a weather vane.

Description:
BACKGROUND 
     1. Field of Invention 
       [0001]    The invention relates generally to a system and method for evaluating a multiphase flow of wellbore fluids in a tubular. More specifically, the system and method introduces thermal energy into the flow and monitors downstream heating of the fluid to estimate both fluid phase and flow velocity. 
       2. Description of Related Art 
       [0002]    Flowmeters are often used for measuring flow of fluid produced from hydrocarbon producing wellbores. Flowmeters may be deployed downhole within a producing wellbore, a jumper or caisson used in conjunction with a subsea wellbore, or a production transmission line used in distributing the produced fluids. Monitoring fluid produced from a wellbore is useful in wellbore evaluation and to project production life of a well. The produced fluid may include water and/or gas mixed with liquid hydrocarbon. Knowing the water fraction is desirable to ensure adequate means are available for separating the water from the produced fluid. Additionally, the amount and presence of gas is another indicator of wellbore performance, and vapor mass flow impacts transmission requirements. In wells having a network of wellbores. It is useful to estimate which bores produce different types of fluid. 
         [0003]    Flowmeters can be employed that provide information regarding total flow, water cut amount and gas fractions. However, these often require periodic analysis of the fluid entering the flowmeter. This may involve deploying a sample probe upstream of the flowmeter, which can produce inaccuracy, and may interrupt or temporarily halt fluid production. The types of flowmeters range from pressure differential, spinner type meters, thermal poise, and capacitive sensors. 
       SUMMARY OF THE INVENTION 
       [0004]    The present disclosure includes a method and apparatus for evaluating flow of a fluid downhole. An example of o method for evaluation downhole fluid flow includes applying thermal energy to the flow of fluid at a position in the flow of fluid, sensing a temperature of the fluid stream downstream of the position over time, and estimating a type of fluid in the flow of fluid based on the step of sensing temperature downstream. The method can further include generating a temperature profile based on the step of sensing a temperature. The steps of applying thermal energy to the flow of fluid can be performed at different radial positions in the flow of fluid, and temperatures downstream of the different radial positions can be sensed, this example can further include generating a temperature profile of fluid alter application of thermal energy at each of the different radial positions, and identifying different phases of fluid within the flow of fluid at the different radial positions based on the step of generating the temperature profiles. The different phases of fluid can be water, liquid hydrocarbon, and gas. In an example, the thermal energy is applied upstream and spaced axially away from where the temperature is sensed at each radial position. The method can further include estimating a flow rate of the flow of fluid based on an elapsed time between when the thermal energy is applied and when a peak temperature is measured downstream. In an example, the position is first position, and wherein the step of sensing a temperature of the fluid stream downstream of the first position over time is performed at a second position, the method can further include sensing a temperature of the fluid stream at a third position that is downstream of the second position temperature profiles obtained at the second and third positions can be compared, this comparison can be used to identify a phase of the fluid being sensed at the second and third positions. 
         [0005]    Another example of a method of evaluating flow of a fluid downhole includes applying thermal energy to the flow of fluid at a position in the flow of fluid, sensing a temperature of the fluid stream downstream of the position over time at a first downstream location, sensing a temperature of the fluid stream downstream of the position over time at a second downstream location that is downstream of the first downstream location, and estimating a type of fluid in the (low of fluid based on a comparison of temperature profiles obtained by sensing temperatures at the first and second downstream locations. In one example, the method further includes estimating fluid flow based on a measurement of a time lapse between when the thermal energy is applied to the fluid, and when a peak of temperature is observed at the first downstream location, the method also optionally further involves repeating the steps of applying thermal energy and sensing temperature of the fluid stream al radial positions in the flow of fluid. The method optionally further includes identifying different phases of fluid within the flow of fluid. 
         [0006]    Also disclosed herein is a system for evaluating fluid flow in a downhole wellbore, and which includes, a thermal source module that is selectively disposed in a flow of fluid in the wellbore and energized to apply thermal energy to the flow of fluid, a thermal sensor module disposed axially away from the thermal source module and disposed in the flow of the fluid in the wellbore downstream of the thermal source module, and that selectively monitors a temperature profile of the fluid over time, and a controller in communication with the thermal sensor module and that selectively identifies a phase of fluid in the (low of fluid based on an analysis of the temperature profile monitored by the thermal sensor module. The thermal sensor module can be a first thermal sensor module, the system further having a second thermal sensor module disposed downstream of the first thermal sensor module and that selectively monitors a temperature profile of the fluid over time. In an example, the controller is in communication with the second thermal sensor module. The system can also include an elongate frame to which the thermal source module and the sensor modules are coupled, and an arm having a length, a width, and a height, and a slot formed radially through the arm, and wherein the frame is coupled in the slot and pivotable about a line that projects along the height of the arm. In an embodiment, the arm mounts to a housing and is pivotal between an orientation substantially parallel with a length of the housing and to an orientation oblique to the length of the housing and that spans across a substantial portion of a diameter of the wellbore. The system can further include an arm having a plurality of thermal source modules each having a corresponding thermal sensor module disposed downstream and each along paths that intersect the thermal source modules and are substantially parallel with an axis of the wellbore. 
     
    
     
       BRIEF DESCRIPTION OF DRAWINGS 
         [0007]    Some of the features and benefits of the present invention having been stated, others will become apparent as the description proceeds when taken in conjunction with the accompanying drawings, in which: 
           [0008]      FIG. 1  is a side partial sectional view of an embodiment of a downhole tool having a fluid sensor assembly and disposed in a wellbore. 
           [0009]      FIGS. 2 and 3  are side views of an embodiment of the fluid sensor assembly of  FIG. 1  disposed in a deviated portion of production tubing. 
           [0010]      FIG. 4  is a side view of a portion of the fluid sensor assembly of  FIG. 1 . 
           [0011]      FIG. 5  is a graphical illustration of an example of a temperature profile over time of a stationary fluid after an instantaneous thermal energy pulse. 
           [0012]      FIG. 6  is a graphical illustration of an example of a temperature profile over time of a moving fluid after an instantaneous thermal energy pulse. 
           [0013]      FIG. 7  is a graphical illustration of an example of a temperature profile over time of a moving fluid after a prolonged thermal energy pulse. 
           [0014]      FIG. 8  is a graphical illustration of an example of fluid temperature profiles at where thermal energy is applied to the fluid, and downstream at a temperature sensor. 
       
    
    
       [0015]    While the invention will be described in connection with the preferred embodiments, it will be understood that it is not intended to limit the invention to that embodiment. On the contrary, it is intended to cover all alternatives, modifications, and equivalents, as may be included within the spirit and scope of the invention as defined by the appended claims, 
       DETAILED DESCRIPTION OF INVENTION 
       [0016]    The method and system of the present disclosure will now be described more fully hereinafter with reference to the accompanying drawings in which embodiments are shown. The method and system of the present disclosure may be in many different forms and should not be construed as limited to the illustrated embodiments set forth herein; rather, these embodiments are provided so that this disclosure will be thorough and complete, and will fully convey its scope to those skilled in the art. Like numbers refer to like elements throughout. 
         [0017]    It is to be further understood that the scope of the present disclosure is not limited to the exact details of construction, operation, exact materials, or embodiments shown and described, as modifications and equivalents will be apparent to one skilled in the art. In the drawings and specification, there have been disclosed illustrative embodiments and, although specific terms are employed, they are used in a generic and descriptive sense only and not for the purpose of limitation. Accordingly, the improvements herein described are therefore to be limited only by the scope of the appended claims. 
         [0018]      FIG. 1  is a side partial sectional view of an example of a downhole tool  10  disposed in a wellbore  12 . In this example, wellbore  12  intersects a formation  14  which includes hydrocarbons that are being produced through wellbore  12 . Production tubing  16  is shown inserted within wellbore  12  and which may be coaxially disposed within casing (not shown) cemented within wellbore  12 . Downhole tool  10  includes a housing  17  shown suspended on wireline  18 , where wireline  18  is supported by a wellhead assembly  20  on its upper end. Included in housing  17  is a fluid sensor assembly  22  for monitoring and-or analyzing a flow of fluid F shown flowing within production tubing  16  towards wellhead assembly  20  and over housing  17 . A controller  24  is shown above surface and which is in communication with downhole tool  10  and fluid sensor assembly  22  via a communication means  26 . Examples exist wherein controller  24  is provided within an operations vehicle (not shown) on surface and above the opening of the wellbore  12 . Although communication means  26  is illustrated as being hardwired, other embodiments exist for communication means  26  such as wireless, fiber optic, and any other form of transmitting and/or receiving signals. 
         [0019]      FIG. 2  shows in a side sectional view an example of a segment of downhole tool  10  disposed in a length of tubing  16  that resides in a deviated portion of wellbore  12 . In this example fluid sensor assembly  22  includes an elongate arm  28  that couples to an extension  30  shown depending downward from housing  17  ( FIG. 1 ). In this embodiment, arm  28  selectively rotates with respect to extension  30  about a pin  32  that pivotingly couples arm  28  to extension  30 . In this deviated portion of well bore  12 , fluid V is made up of different types of fluid that arc in multiple phases. More specifically, a water layer  34  is shown in a lower portion of fluid F adjacent a lower section of tubing  16 , and a liquid hydrocarbon layer  36  is shown disposed above water layer  34  in a mid-portion of tubing  16 . In the space above liquid hydrocarbon layer  36  is a gas layer  38 , that occupies the space between an upper border of liquid hydrocarbon layer  36  and the upper inner surface of tubing  16 . A series of elongate slots  40   1-6  are shown formed laterally through the arm  28 . Each of the slots  40   1-6  includes a thermal source module  42   1-6 , which in one example of operation transmits thermal energy into fluid F flowing in tubing  16  and past wellbore tool  10 . Also disposed within each of the slots  40   1-6  are thermal sensor modules  44   1-6  that monitor temperature within the flow of fluid F. In an example, the thermal source modules  42   1-6  are heating elements, such as elongate wires, across which current is conducted to generate thermal energy, which is then transferred into the fluid F flowing past the thermal source modules  42   1-6 . In an embodiment, the thermal sensor modules  44   1-6  are thermocouples and when exposed to a (low of the fluid F, emit signals representative of temperature within the fluid F flowing past the thermal sensor modules  44   1-6 , wherein the signals can be correlated to an actual temperature of the fluid F so the temperature of the fluid F can be monitored. 
         [0020]      FIG. 3  illustrates an example of operation wherein arm  28  is no longer substantially parallel with axis A X  of tubing  16 , but instead has been rotated to an orientation that is oblique to axis A X . In this example, at least one of each of the slots  40   1-6  are each of the separate phase layers. More specifically, slot  40   1  is in the water layer  34  and slot  40   6  is disposed in the gas layer  38 . Each of slots  40   2-5  are in the liquid hydrocarbon layer  36 . Alternate embodiments of use exist where an equal number of slots  40   1-6  are disposed in each of the fluid layers  34 ,  36 ,  38 . i.e. slots  40   1,2  in water layer  34 , slots  40   3,4  in liquid hydrocarbon layer  36 , and slots  40   5,6  in gas layer  38 . In this example, the thermal source modules  42   1-6  are energized to create heating within the fluid F. Moreover, the corresponding thermal sensor modules  44   1-6  are disposed directly downstream of their corresponding thermal source modules  42   1-6  so that the fluid F heated by a one of the modules  42   1-6  is sensed by its corresponding sensor  44   1-6 . Accordingly, heating created by the thermal source modules  42   1-6  can be monitored by the respective thermal sensor modules  44   1-6 . As will be described in more detail below, analyzing the temperature profile over time of the fluid F can then help identity in which phase of fluid  34 ,  36 ,  38  the individual thermal sensor modulus  44   1-6  is disposed. Optionally, a proximity sensor system  45  can be included that provides for measurement of the angular displacement of arm  28  so that the location of each of the slots  40   1-6  can be estimated based on signal output from the proximity sensor  45 . In an example, the locution of the slots  40   1-6  can include either how far from the extension  30  is the specific one of the slots  40   1-6 , or a value of angle Θ of the arm  28  with respect to the extension  30 . Thus, the ability to ascertain the phase of fluid F based on temperature readings from the sensor modules  44   1-6 , coupled with output from proximity sensor  45 , can provide information about the amount of the particular fluid phases  34 ,  36 ,  38  disposed within tubing  16 . 
         [0021]    Referring now to  FIG. 4 , shown in a side view is one example of an alternate embodiment of sensor assembly  22 A and which includes an aft thermal sensor module  46   n  disposed downstream of the thermal sensor module  44   n . In this example, a module frame  48   n  is provided in slot  40   n , and on which each of the formal source module  42   n , thermal sensor module  44   n , and aft thermal sensor module  46   n  are coupled. Module frame  48   n  includes an elongate upper frame member  50   n  that is shown extending obliquely to a length of slot  40   N  and a lower frame member  51   n  that also extends obliquely along a length of slot  40   n . Upper and lower frame members  50   n ,  51   n  project along paths that diverge from one another. Pins  52   n ,  53   n  respectively couple the upper and lower frame members  50   n ,  51   n  to the edge of the slot  40   n . Forward ends of the upper and lower frame members  50   n ,  51   n  are coupled to one another via a forward frame member  54   n , which is an elongate member and extends generally perpendicular to a length of slot  40   n . The rearward ends of the upper and lower frame members  50   n ,  51   n  are coupled to one another by an elongate aft frame member  56   n , which is generally parallel with forward frame member  54   n . As the upper and lower frame members  50   n ,  51   n  diverge from one another along their respective lengths, the all frame member  56   n  is longer than forward frame member  54   n . Accordingly, frame  48   n  has a weather vane type look and with a height that increases along its length, and the pins  52   n ,  53   n  are closer to the forward frame member  54   n  than to the art frame member  56   n . As such, when placed in a flowing stream of fluid, the enlarged aft portion of frame  48   n  will direct the frame  48   n  that is in a path substantially parallel with the path of any flow of fluid F flowing past the arm  28 . Pins  52   n    53   n  have a pivoting coupling with frame  48   n  which allows this weather vane type action in the flow of fluid F. Mounting brackets  58   n ,  60   n ,  62   n  respectively mount the thermal source module  42   n , thermal sensor module  44   n , and aft thermal sensor module  46   n  within frame  48   n . Accordingly, the modules  42   n ,  44   n ,  46   n  are each aligned in a path P of any fluid F that flows across arm  28 . Thus, the sensor modules  44   n ,  46   n  are strategically located in path P to detect healing of fluid F introduced by operation of the source module  42   n . These modules  42   n ,  44   n ,  46   n  are all in communication with controller  24  via communication means  26 A, that in this embodiment is illustrated as a wireless device or system. 
         [0022]      FIGS. 5 through 7  graphically illustrate temperature profiles over time in fluids and depict differences between an instantaneous thermal energy pulse versus one that is prolonged. More specifically shown in  FIG. 5  is a coordinate system  64  where the abscissa represents axial distance in a body of fluid and the ordinate represents temperature T. Profile  66  represents temperature in the fluid and where the value of X equals zero represents the location where in the fluid a thermal energy input is applied. Temperature profiles  68 ,  70 ,  72  show how the temperature changes over time and becomes flatter with a reduced maximum value of temperature T. Each of the profiles  66 ,  68 ,  70 ,  72  follow a Gaussian profile. In the example of  FIG. 5 , the fluid F in which the thermal energy impulse is applied is generally stationary. 
         [0023]      FIG. 6  illustrates one example of introducing a thermal energy impulse into a flowing body of fluid. In this example, the thermal energy input is a pulse which may last up to a few milliseconds. Shown plotted on coordinate system  64 A are temperature profiles taken over time. i.e.,  66 A,  68 A,  70 A,  72 A. More specifically, profiles  68 A,  70 A,  72 A, which represent temperature distribution at t=0+, have corresponding peaks (hat move along the abscissa and in the direction of fluid flow. Moreover, as can be seen, the profiles  68 A,  70 A,  72 A all have respective peaks that diminish over time and are less than the peak of profile  66 A. Similarly,  FIG. 7  illustrates coordinate system  64 B on which are plotted a series of profiles  66 B,  68 B,  70 B,  72 B, wherein the thermal energy input is applied not as a pulse, but over a period of time, such as one that may exceed a few hundred milliseconds. In this example, the Gaussian distribution resembles that of a sum of individual Gaussian profiles. 
         [0024]      FIG. 8  represents one example of a temperature profile  76 ,  78 ,  80  that may be recorded respectively at the thermal source module  42   n , thermal sensor module  44   n , and aft thermal sensor  46   n . An advantage of multiple sensor modules  44   n ,  46   n  is that additional data may be recorded that illustrates the respective profiles  78 ,  80  and provides information about how quickly the temperature dissipates. Thus, studying either or both of temperature profile  78 ,  80 , in comparison to temperature profile  76 , not only can the velocity of the fluid flowing past the modules  42   n ,  44   n ,  46   n  be estimated, so may the type of fluid that flows past the sensor modules  44   n ,  46   n . For example, the rate at which the thermal energy making up the temperature profiles dissipates can be estimated and used to identify the particular type of fluid. It is known that the Gaussian profile will become flatter in water over a time period less than that for liquid hydrocarbon. Thus, comparing the measured temperature profile and comparing that to a known temperature profile for either water or liquid hydrocarbon, the corresponding fluid being monitored may be identified. 
       EXAMPLE 
       [0025]    Table 1 below illustrates values of thermal conductivity, density, heat capacity, density heat capacity, thermal diffusivity, and diffusivity ratio for crude oil, water, and methane over a range of temperature and pressure conditions. 
         [0000]    
       
         
               
               
               
               
               
               
               
             
               
               
               
               
               
               
               
             
           
               
                 TABLE 1 
               
               
                   
               
               
                   
                   
                   
                   
                   
                 k/(ρεγ) 
                   
               
               
                   
                 Thermal Conductivity 
                 Density 
                 Heat Capacity 
                 Density * Heat Capacity 
                 Thermal Diffusivity, 
                 Diffusivity Ratio 
               
               
                   
                 k [Wm −3 K −1 ] 
                 ρ [kg/m 3 ] 
                 c p  [jkg −1 K −1 ] 
                 ρ [kg/m 3 ] * c p  [jkg −1 K −1 ] 
                 α [m −2 sec −2 ] 
                 α/α CRUDE   
               
               
                   
               
             
             
               
                   
               
             
          
           
               
                 Crude Oil 
                 0.125 
                 850 
                 1800 
                 1530000 
                 8.16993E−08 
                 1.000 
               
               
                 Water 
                 0.580 
                 1000 
                 4180 
                 4180000 
                 1.38756E−07 
                 1.698 
               
               
                 Methane (125 C., 8000 psi) 
                 0.098 
                 213 
                 3299 
                 702094 
                 1.40010E−07 
                 1.714 
               
               
                 Methane (150 C., 8000 psi) 
                 0.101 
                 200 
                 3293 
                 659331 
                 1.53754E−07 
                 1.882 
               
               
                 Methane (175 C., 8000 psi) 
                 0.099 
                 189 
                 3306 
                 623926 
                 1.58477E−07 
                 1.940 
               
               
                 Methane (125 C., 5000 psi) 
                 0.088 
                 178 
                 3294 
                 586891 
                 1.49757E−07 
                 1.833 
               
               
                 Methane (150 C., 5000 psi) 
                 0.084 
                 145 
                 3246 
                 469050 
                 1.78149E−07 
                 2.181 
               
               
                 Methane (175 C., 5000 psi) 
                 0.085 
                 135 
                 3243 
                 436633 
                 1.95640E−07 
                 2.395 
               
               
                 Methane (125 C., 10000 psi) 
                 0.108 
                 240 
                 3279 
                 786721 
                 1.37346E−07 
                 1.681 
               
               
                 Methane (150 C., 10000 psi) 
                 0.107 
                 227 
                 3290 
                 747057 
                 1.43455E−07 
                 1.756 
               
               
                 Methane (175 C., 10000 psi) 
                 0.107 
                 216 
                 3311 
                 713622 
                 1.50273E−07 
                 1.839 
               
               
                   
               
             
          
         
       
     
         [0026]    Additionally, in combination with providing multiple sets of the modules  42   1-6 ,  44   1-6 ,  46   1-6  at multiple radial locations within the bore hole ( FIG. 3 ), the location at the interface of multiple phase fluids can also be identified. More specifically, in a deviated wellbore, it will be known that the uppermost portion of the tubing will contain a gas, so that in situations when the temperature profile of gas is similar to that of water, the spatial location of where the temperature profile is being measured can provide an indication of whether or not the fluid is water or gas. Velocity can be obtained if the time between the thermal energy input and when that thermal energy is detected by the sensor modules  44   n ,  46   n  in combination with the respective distances between the modules  42   n ,  44   n ,  46   n  are known. It should be pointed out, that although the profiles in  FIG. 7  might appear to emulate a distorted Gaussian, the respective peak movement can still be used to obtain flow velocity of the fluid. An advantage of using a line source for the thermal energy input, i.e., a thin resistively heated wire, is so that the system can be modeled as a one-dimensional problem. One reason why the temperature profile in water is flatter is that water has higher thermal diffusivity than oil. Thermal diffusivity is typically defined as thermal conductivity divided by the product of mass density and heat capacity. Therefore, for the same flow rate, the fluid temperature profile after pulse heating becomes wider and shorter quicker for water than it does for oil. To visualize this phenomenon, imagine being in the frame of reference of the fluid (by traveling alongside it at the same speed) with a thermal imaging camera and seeing the injected thermal pulse diffusing left and right of where it had been injected much more quickly for water than it would for oil because water has approximately 1.7 times the thermal diffusivity of oil. In this example, in the frame of reference of the tool, the measured temporal thermal profile is compressed in time because of the relative motion between the moving fluid and the temperature sensors that are attached to the stationary tool Because in many downhole conditions the natural gas is at a high pressure and temperature, it can have a thermal diffusivity comparable to that of water, which is why the actual radial locations of the sensor modules  44   n ,  46   n  in relationship to the directions of up and down may be required in order to differentiate the type of fluid being monitored by these modules  44   n ,  46   n . That is, in laminar flow, gas will be on top, oil in the middle, and water on the bottom, providing an additional way to distinguish fluid types when thermal diffusivities are comparable. 
         [0027]    The present invention described herein, therefore, is well adapted to carry out the objects and attain the ends and advantages mentioned, as well as others inherent therein. While a presently preferred embodiment of the invention has been given for purposes of disclosure, numerous changes exist in the details of procedures for accomplishing the desired results. These and other similar modifications will readily suggest themselves to those skilled in the art, and are intended to be encompassed within the spirit of the present invention disclosed herein and the scope of the appended claims.