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RELATED APPLICATIONS 
       [0001]    This application claims the benefit of U.S. Provisional Application No. 61/105,075, filed Oct. 14, 2008, the contents of which are herein incorporated by reference. 
     
    
     BACKGROUND 
       [0002]    1. Field of the Invention 
         [0003]    Embodiments of the claimed invention may relate generally to the characterization of fluid flow in downhole applications, and more particularly to downhole annular measurement systems. However, embodiments may not be limited to these fields and applications of aspects of the various concepts recited herein may be applied to other related and unrelated fields. 
         [0004]    2. Description of the Related Art 
         [0005]    The following descriptions and examples are not admitted to be prior art by virtue of their inclusion in this section. 
         [0006]    Hydrocarbon fluids such as oil and natural gas are obtained from a subterranean geologic formation, referred to as a reservoir, by drilling a well that penetrates the hydrocarbon-bearing formation. However, measurement of fluid either produced from the well or injected into the well can present problems for accurately determining the flow of fluid through the well without significantly impeding access through the main production tubing bore. In addition, precise measurement of the individual contributions of various zones in a multi-zone well or various branches in a multi-lateral well can also be difficult, but important in determining the balance and productivity of the well system. 
         [0007]    Therefore, one purpose among many proposed for various embodiments described herein is to configure a downhole annular measurement system adapted to characterize parameters of the fluids produced from or injected into a given zone. The measurement may be done without any restriction in the main bore, accordingly leaving full bore access in the tubing. Various embodiments may be more particularly designed for multi-zone Intelligent Completion (IC) systems but the concepts are applicable to single zone wells. 
         [0008]    An illustrative result of the measurements provided by some of the embodiments of the downhole system may be to characterize the flow contribution from each zone in a producer well. Characterization may include measuring the flow rate and possibly identifying the proportion and physical properties of the different phases of the constituent fluid (e.g., such as oil, water and gas), prior to the fluid joining the main bore production. Alternatively, in an injector well, an illustrative result may be to measure the quantity of fluid separated out from the main bore and injected into a given zone. 
         [0009]    In order to characterize the production of a multi-zone completion, downhole measurement devices, such as a flowmeter system, may be installed in each producing/injecting zone. The downhole system may be integrated to the rest of the completion string and is installed along with the completion. 
       SUMMARY 
       [0010]    In accordance with one embodiment of a downhole measurement system, a downhole system may comprise a flow conditioning section configured to produce a substantially homogenized mixture of a fluid flow. At least a portion of the fluid flow may enter into a measuring section configured to measure the fluid flow portion. The measuring section may characterize a parameter of the fluid flow. In some embodiments, the flow conditioning section may include a labyrinth flow pathway. 
         [0011]    In another embodiment of a downhole measurement system, a method for characterizing a parameter of a fluid flow may comprise directing the fluid flow to a flow conditioning section and conditioning the fluid flow to a substantially homogenized state. The method may further include measuring the parameter for at least a portion of the fluid flow. The measured parameter may be used to characterize the fluid flow. 
         [0012]    Other or alternative features will become apparent from the following description, from the drawings, and from the claims. 
     
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         [0013]    Certain embodiments of the invention will hereafter be described with reference to the accompanying drawings, wherein like reference numerals denote like elements. It should be understood, however, that the accompanying drawings illustrate only the various implementations described herein and are not meant to limit the scope of various technologies described herein. The drawings are as follows: 
           [0014]      FIG. 1  is a schematic illustration of a prior art intelligent completion zone of a well system; 
           [0015]      FIG. 2  is a schematic illustration and partial cross-sectional representations of a zone of a completion according to an embodiment of a downhole measurement system; 
           [0016]      FIG. 3  is a schematic illustration and cross-sectional view of a fluid inlet section according to an embodiment of a downhole measurement system; 
           [0017]      FIGS. 4A &amp; 4B  are side and top schematic illustrations of a flow conditioning section including a labyrinth flow path according to an embodiment of a downhole measurement system; 
           [0018]      FIG. 4C  is a side schematic illustration of a flow conditioning section including a spiral flow path according to an embodiment of a downhole measurement system; 
           [0019]      FIG. 5  is a schematic illustration and cross-sectional view of a measuring section according to an embodiment of a downhole measurement system; 
           [0020]      FIG. 6  is a schematic illustration and partial cross-sectional representation of a zone of a completion according to an embodiment of a downhole measurement system; and 
           [0021]      FIG. 7  is a schematic illustration of a multi-zone well system according to an embodiment of a downhole measurement system. 
       
    
    
     DETAILED DESCRIPTION 
       [0022]    In the following description, numerous details are set forth to provide an understanding of the present invention. However, it will be understood by those skilled in the art that the present invention may be practiced without these details and that numerous variations or modifications from the described embodiments may be possible. 
         [0023]    In the specification and appended claims: the terms “connect”, “connection”, “connected”, “in connection with”, and “connecting” are used to mean “in direct connection with” or “in connection with via another element”; and the term “set” is used to mean “one element” or “more than one element”. As used herein, the terms “up” and “down”, “upper” and “lower”, “upwardly” and downwardly”, “upstream” and “downstream”; “above” and “below”; and other like terms indicating relative positions above or below a given point or element are used in this description to more clearly describe some embodiments of the invention. 
         [0024]    Referring generally to  FIG. 1 , in a multiple zone intelligent (or selective) completion, a well system  10  may be drilled through the surface  20  to create a wellbore  30 . The wellbore  30  may be lined with casing or unlined (not shown). Within the wellbore  30 , a completion comprising production tubing  40  and a completion zone system  50  may run to access a fluid reservoir  60 . The completion zone system  50  may comprise one or more packers  51  sealing the completion zone system  50  to the interior of the wellbore  30 . 
         [0025]    Access to the reservoir  60  may be provided via perforations  52  in the casing of the wellbore  30 . As shown by the arrows in the figure, desired fluid, such as hydrocarbon fluid for example, may enter the annulus between the completion zone system  50  and the interior wall of the wellbore  30 . The fluid may further flow to the interior of the production tubing  40  via a flow control valve  53  such as an inflow control device. The flow control valve  53  may be hydraulically controlled via control lines  54  and a hydraulic surface system  24 , for example. Once inside the production tubing  40 , the pressure may be measured with a gauge mandrel  55  and the results communicated with the surface via a communications line  56  and a surface communication system  26 . 
         [0026]    Turning generally to  FIG. 2 , an illustrative embodiment of a downhole measurement system  200  is shown. This downhole measurement system  200  may replace or can be used in conjunction with the downhole gauge mandrel  55  (see  FIG. 1 ). The downhole measurement system  200  may be installed between the flow control valve  500  and the producing/injecting zone  60 , accessed via perforations  252 . The portion of flow that is measured is the one produced/injected from/to the corresponding zone  60 . 
         [0027]    As shown in  FIG. 2 , this drawing represents an example of a producer version of an embodiment of the downhole measurement system  200 . In some embodiments, the downhole measurement system  200  may be composed of three subassembly sections, a fluid inlet section  210 , a flow conditioning section  300 , and a measuring section  400 , as described below. The descriptions follow from right to left as viewed in the figure. The downhole measuring system  200  may be provided upstream of a flow control valve  500  actuated by hydraulic control lines  554 . In addition, the reservoir zone  60  may be segmented in the wellbore  30  via a zone sectioning device, such as one or more isolation packers  251 , sealing the annulus located between the exterior of the production tubing  40  and an interior surface of the wellbore  30 . In some cases, a series of downhole measurement systems  200  may be provided in a string in which the upstream packer  251  of one downhole measurement system  200  is the downstream packer  251  of an adjacent downhole measurement system  200 . In this case, the zone sectioning device would only use a single packer  251  per downhole measurement system  200 . 
         [0028]    In a production system, the first section of the downhole measurement system  200  may be the fluid inlet section  210 . The fluid inlet section  210  is optional and may be integral to the flow conditioning section  300 . As shown in this illustrative embodiment and more readily seen in  FIG. 3 , the fluid inlet section  210  may comprise an optional fluid barrier  214  and one or more inlet passageways  212  (three are shown in this example). 
         [0029]    The optional fluid barrier  214  may be configured to prevent any portion of the produced fluids from by-passing the rest of the downhole measurement system  200 . This fluid barrier  214  may be a classical packer with or without slips, with a compressed element, or a cup, for example. This fluid barrier  214  may also be achieved with a swellable packer, among other components. In some embodiments, the fluid barrier  214  may be replaced by a shroud (described later) or even be completely removed if it is determined that the amount of fluid by passing the downhole measurement system  200  is negligible with regard to the precision required. 
         [0030]    The fluid inlet section  210  may direct the fluid produced from the reservoir  60  via the perforations  252  into flow conditioning section  300 . As more readily seen in  FIG. 4 , the flow conditioning section  300  may function to mix the produced fluids (e.g., oil, water and gas) into a substantially macroscopically homogenous mixture. Mixing the fluids may be performed in order to reduce or remove the slippage that may occur between phases (i.e., differences of speed or velocity) and thereby ease the measurement in the measuring section. 
         [0031]    Among other functions, the flow conditioning section  300  may also be configured to diffuse this mixture to the next section of the downhole measurement system  200  at a speed that is substantially equal to the speed of fluid flowing into the zone. The resultant homogenous flow allows the next section to be configured so as to take a representative “sample” in order to characterize the overall flow measurements. Various design principles may be incorporated into the flow conditioning section  300  in order to achieve a substantially homogenized fluid flow. 
         [0032]    For example, one of the design principles used in some cases for achieving a diffuse, homogenous flow is a 3D labyrinth fluid pathway, such as that shown in the side and top views of  FIGS. 4A and 4B . The flow trajectory may be forced in as many as 4 different directions while traversing the fluid pathway, for example. The direction changes cause the fastest phase (i.e., gas) to interfere with the slowest ones (i.e., oil and water) multiple times. The number of direction changes, the flowing section area, and the length of the conditioning sub, should be dimensioned in order to produce a homogenous mixture independent of the initial azimuthal orientation of the tool in the well and the flow regime entering in the tool (e.g. laminated). In non-modified flow regimes, the fastest phases such as gas may rise to an uppermost portion of a horizontal wellbore, resulting in a velocity differential across the area of the flow tube. 
         [0033]    Alternatively, other designs, such as spirals (shown in  FIG. 4C ) for example, can be used for the flow conditioning section  300  and adapted to the expected conditions, such as the type of flow and the number of phases. If permitted by the expected flowing conditions (e.g. homogenized) and the type of characterization required, the flow conditioning section  300  could also be considered as optional with regard to the overall downhole measurement system  200  (see  FIG. 2 ). For example, injection wells typically have homogenized fluid flows and would accordingly not require a flow conditioning section  300 , among others. 
         [0034]    Turning now to  FIG. 5 , this drawing generally illustrates the measuring section  400  of the downhole measurement system  200  (see  FIG. 2 ). This section may be composed of one or more flow channels  410  (four are shown in this example). The measurements used to characterize the overall zone contribution may be made in at least one of the flow channels  410 . Sensors  420  may be incorporated in at least one of the flow channels  410  in order to perform the various measurements required to characterize the fluid flow contribution from the corresponding zone. Due at least in part to the flow conditioning section  300  providing a homogenized fluid flow to the measuring section  400 , a representative sample of the fluid flow can be measured in at least one of the flow channels  410  and the results processed to characterize the total fluid flow. 
         [0035]    Measuring just a sample/part of the overall fluid flow via one or more sensors  420  may be considered as a valid method when the mixture flowing in that flow channel  410  is representative of the overall zone fluid flow contribution. In some cases, the total production rate of the overall zone may be simply determined by multiplying the results of the measured or sampled flow channel  410  by the total number of flow channels  410 , or normalized using the proportional area of the sample flow channel(s)  410  relative to the overall flow area. Of course, alternatively, such as for redundancy purposes, the measurements can be made in more than one or even all the channels. 
         [0036]    In some embodiments, flow characterization may comprise the measuring of the total mass flow. The flow characterization can then be complemented by other measurements in order to determine the fraction and the physical properties of each phase present in the fluid flow. 
         [0037]    This characterization may be achieved with a combination of sensors  420  integrated in the measuring flow channel(s)  410 . Sensors  420  may comprise, but are not limited to the following parameters and exemplary configurations:
       Mass flow rate: Venturi or plate profile with 2 absolute pressure gauges or a pressure delta sensor   Volume flow rate   Speed of the flow: Doppler sensor, acoustic sensor, thermal anometer, spinner   Water Cut: Capacitive and Resistive sensor, acoustic sensor   Density: Gamma ray detector and source   Viscosity: Piezoelectric   Temperature sensors   Radioactive tracer detector       
 
         [0046]    Turning again to  FIG. 2 , once the fluid exits the downhole measurement system  200 , the fluid flow may flow through a flow control valve  500  before entering into the main production tubing  40 . In the main production tubing  40 , the fluid flow from the reservoir zone  60  may be combined with other fluids produced by the zones from previous sections of the well. 
         [0047]    For an injector wells, the downhole measurement system  200  may be inverted in order to measure the flow coming out from the flow control valve  500 . The function of the flow conditioning section  300  may be simplified since a single phase of fluid is typically injected (e.g., such as water or gas) and therefore, there is no need for mixing to produce a homogenized fluid flow. In such cases, the flow conditioning section  300  may simply ensure a substantially homogenous fluid flow prior to entering into the fluid measuring section  400 . 
         [0048]    Use of some embodiments of the downhole measurement system  200  may allow for full bore access in the main production tubing  40 . When compared to a venturi type of flowmeter, some embodiments of the downhole measurement system  200  simplify intervention by eliminating an extra trip downhole to remove and reinstall a venturi lock. Reduced need for intervention may result in operational cost saving, reduced production deferment and overall reduced risks. In addition, full bore access reduces the risk of debris accumulation in front of restrictions (such as may be present with venturi types of flowmeters) in horizontal wells. Embodiments of the downhole measurement system  200  may be installed in each producing/injecting zone with a relatively minimal impact on the completion design and well inflow performances. 
         [0049]    The use of some embodiments of a downhole measurement system  200  incorporating sampling of the total fluid flow may allow for a reduction in the size of sensors  420  (see  FIG. 5 ). The sensors  420  themselves may be adapted specifically to the size of the measuring flow channels  410 . Sensor miniaturization may reduce the cost of packaging and help to drive the overall system cost down. The same size of measurement flow channel  410  may be used from one main production tubing size 40 to another. The cost of engineering and development time for implementation to other tubing sizes may be reduced. In addition, an increased number of common parts between downhole measurement systems  200  configured for various sizes of production tubing  40  may simplify the overall manufacturing process, ease inventory, and reduce the overall lead time and manufacturing costs. 
         [0050]    Referring now to  FIG. 6 , this drawing generally shows another exemplary embodiment of a downhole measurement system  600 . In this illustrative embodiment, the optional fluid inlet section  610  does not have a separate barrier system to seal with the interior surface of the wellbore  30 . Instead, the fluid inlet section  610  comprises one or more inlet passageways  612  (two passageways can be seen in this view). However, in order to keep fluid that may flow around the outer circumference of the fluid inlet section  610  and enter into the flow control valve  500  without being accounted for by the fluid measuring section  400 , a shroud  700  may be placed around the flow control valve  500  to limit access to the interior of the main production tubing  40 . 
         [0051]    The shroud  700  may direct fluid flow exiting from the flow conditioning section  300  and the fluid measuring section  400  into the flow control valve  500 . In addition, the shroud  700  may restrict fluid in the annulus around the downhole measurement system  600  from entering into the main production tubing  40 . The shroud  700  may reduce the complexity and cost of the overall downhole measurement system  600  by eliminating a fluid barrier from the fluid inlet system  610  and any sealing requirements associated there with. 
         [0052]    Turning now to  FIG. 7 , another illustrative embodiment of a well system  800  incorporating downhole measurement systems  200  is shown in this drawing. In this situation, two reservoirs  60  and  62  are shown interacting with three downhole measurement systems  200 . In some cases, the use of different downhole measurement systems  200  from individual reservoirs  60  and  62  can be used to determine the contribution of each reservoir  60  and  62  to the overall production of the well system  800 . In other cases, the use of more than one downhole measurement systems  200  in a single reservoir  62  can allow for a more efficient and effective management of the reserves located within that reservoir  62 . For example, if one of the downhole measurement systems  200  detects an increase in water cut or other evidence of water breakthrough, the impacted downhole measurement system  200  may be shut down while production continues with the non-impacted downhole measurement system  200 . 
         [0053]    Although single and multi-zone well systems have been shown with horizontal, terrestrial wells, embodiments of downhole measurement systems may not be limited to this application. Both production and injector wells, sub-sea and terrestrial wells, and vertical, horizontal, deviated, and multilateral wells may be suitable to apply aspects of embodiments of downhole measurement systems described herein. 
         [0054]    While the downhole measurement system has been disclosed with respect to a limited number of embodiments, those skilled in the art, having the benefit of this disclosure, will appreciate numerous modifications and variations there from. It is intended that the appended claims cover such modifications and variations as fall within the true spirit and scope of the invention.

Summary:
A downhole measurement system may comprise an optional fluid inlet section configured to accommodate fluid flow between a well and a zone surrounding the well. The system may further comprise a flow conditioning section configured to receive the fluid from the fluid inlet section. The flow conditioning section may be configured to produce a substantially homogenized fluid flow. In addition, a measuring section may be provided and configured to measure at least a portion of the fluid flow from the flow conditioning section. The measuring section characterizes a parameter of the fluid flow. In other embodiments, there may be a method for characterizing a parameter of a fluid flow comprising the steps of directing the fluid flow to a flow conditioning section. Other steps may be conditioning the fluid flow to a substantially homogeneous state and measuring a parameter for at least a portion of the fluid flow.