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CROSS-REFERENCE TO RELATED APPLICATIONS 
   This application claims the benefit of U.S. Provisional Application No. 60/738,488, filed Nov. 21, 2005 which is incorporated herein by reference. 

   FIELD OF INVENTION 
   The present invention relates to a method for monitoring fluid properties with a distributed sensor in a wellbore. 
   BACKGROUND 
   In the oil and gas industry, there is considerable value in the ability to monitor the flow properties of fluid in a well. Many wells consist of several hydrocarbon-producing zones that vary in permeability and are perforated or otherwise left open to permit production. It is desirable to obtain flow data from each of these zones to make operational decisions regarding production rate, stimulation, remediation, and other issues that arise in well operation. In addition to production flow data, injection flow data is also valuable as it can reveal how much fluid is being injected into a particular zone of and how this fluid is being absorbed by the formation. 
   To address this need, the industry has developed an array of “intelligent well” technologies that are designed to measure flow properties in a producing well. Frequently measured properties include but are not limited to temperature, pressure, composition, and flow rate. Some measurement tools are installed in the well permanently for long term monitoring while others are run into the well during an intervention to obtain a temporary measurement. Despite advances in these intelligent well technologies, the tools currently available are limited by technical challenges. Some challenges include building a sensing device that is durable enough to withstand the harsh conditions of the downhole environment, providing power to such a device, increasing reliability of downhole sensing systems, and developing a tool that measures the properties of the flow in the wellbore without interfering with the production. Although numerous downhole gauges for measuring temperature, pressure, and other properties have been developed, discrete measurements at several points in the well only reveal limited details about the flow conditions downhole. Ideally, an operator would like to obtain a real time continuous profile of the flow properties along the length and circumference of the wellbore as well as radially into the formation. 
   A promising new development in the area of downhole sensing is distributed temperature sensing or DTS. See James J. Smolen and Alex van der Spek,  Distributed Temperature Sensing: A DTS Primer for Oil  &amp;  Gas Production , Shell International Exploration and Production B.V. (May 2003). A DTS system works by utilizing a distributed sensor as the sensing mechanism. Once the distributed sensor is installed in the well, a pulse of laser light is sent along the fiber so that it collides with the lattice structure and atoms of the fiber causing them to emit small bursts of light, which are “backscattered” or returned to the beginning of the fiber. These bursts of light are returned at slightly shifted frequencies. Because of this frequency shift, the backscattered light provides information, which can be used to determine the temperature at the point from which the backscatter originated. Because the velocity of light is constant, one can determine the distance from the surface to the point where the temperature was recorded using the elapsed travel time of the light pulse. By continually monitoring backscattered light, one can obtain a continuous profile of temperature along the length of the fiber. 
   US Patent Application US 2005/0034873 A1 (hereafter Coon) discloses a method for placing a fiber optic sensor line in a wellbore. The method in Coon includes providing a tubular in the wellbore, the tubular having a first conduit operatively attached thereto, whereby the first conduit extends substantially the entire length of the tubular. The method further includes aligning the first conduit with a second conduit operatively attached to a downhole component and forming a hydraulic connection between the first conduit and the second conduit thereby completing a passageway for the fiber optic sensor line to be urged through with a fluid pump and a hose. Although this method can provide flow data along the entire length of the well, the measurements are limited to a single side of the wellbore. Ideally, operators would like to obtain a complete profile of the inflow and outflow of the well along its depth and circumference. 
   U.S. Pat. No. 5,804,713 (hereafter Kluth) discloses an apparatus for installation of fiber optic sensors in wells. Kluth discloses an apparatus with a first channel containing at least one sensor location arrangement so that at least one sensor can be pumped through the first channel to the sensor location arrangement with at least one turn such that the physical disposition of the sensor after it has been pumped to the sensor location arrangement is not linear, and the turn comprises a loop of hydraulic conduit. Essentially, the sensor is installed by pumping the line through a hydraulic conduit, which is wrapped around the production tubing. Some parts of the conduit allow the fiber optics cable to be wrapped circumferentially around the pipe while others provide a linear configuration. Generally, a low viscosity fluid must be maintained at a particular flow rate in order to locate the fiber at a specific sensor location. In some applications, a load is applied to the fiber optic line, which could cause potential damage to its sensing capabilities. 
   U.S. Pat. No. 6,959,604 (hereinafter Bryant) discloses an apparatus for measuring an unsteady pressure within a pipe comprising an optical sensor including at least one optical fiber disposed circumferentially around at least a portion of a circumference of the pipe. The optical fiber provides an optical signal indicative of the length of the fiber. An optical instrument determines a signal indicative of the unsteady pressure in response to the optical signal. In this system the fiber is wrapped circumferentially around the outside of the pipe. 
   SUMMARY OF THE INVENTION 
   The present inventions include a method for monitoring fluid properties with a distributed sensor in a wellbore having an inner surface, a top and a bottom comprising causing the distributed sensor to assume a helical shape, pulling the distributed sensor towards the bottom of the wellbore, while retaining the helical shape of the distributed sensor, feeding the distributed sensor into the wellbore so that the distributed sensor is in substantially continuous contact with the inner surface, and allowing the distributed sensor to become at least partially supported by friction at the inner surface. 
   The present inventions include a wellbore with a producing interval comprising a distributed sensor at least partially supported by friction. 
   The present inventions include a method for producing oil comprising providing a wellbore with a distributed sensor installed in the wellbore such that the distributed sensor is at least partially supported by friction, measuring fluid properties with the distributed sensor, and producing oil from the wellbore. 

   
     BRIEF DESCRIPTION OF THE DRAWINGS 
     The present invention is better understood by reading the following description of non-limitative embodiments with reference to the attached drawings, wherein like parts of each of the figures are identified by the same reference characters, and which are briefly described as follows: 
       FIG. 1  shows a cross-sectional view of a distributed sensor with a rectangular cross-section. 
       FIG. 2  shows a cross sectional view distributed sensor with a streamlined cross-section. 
       FIG. 3  shows a side view of a distributed sensor being installed in production tubing of a cased hole completion. 
       FIG. 4  shows a side view of the distributed sensor in the cased hole completion. 
       FIG. 5  shows a side view of the distributed sensor installed in the cased hole completion. 
       FIG. 6  shows a side view of the distributed sensor installed in the cased hole completion coupled to a surface control system. 
       FIG. 7  shows a side view of the distributed sensor deployed in a cased hole completion without production tubing. 
       FIG. 8  shows a side view of the distributed sensor deployed in an open hole completion. 
       FIG. 9  shows a side view of the distributed sensor deployed in an open hole completion with production tubing. 
       FIG. 10  shows a side view of a distributed sensor deployed across the production interval of a completion. 
       FIG. 11  shows a side view of a multilateral well with the distributed sensor installations across production intervals. 
   

   DETAILED DESCRIPTION 
   The present invention relates to a method for monitoring fluid properties with a distributed sensor in a wellbore. In this application, the term “fluid properties” is intended to refer to pressure, temperature, flow rate, density, strain, conductivity, sonic velocity, composition, presence of particles or any other characteristic related to wellbore fluid. The term “distributed sensor” is used to refer to any sensor capable of obtaining distributed measurements. Examples include but are not limited to fiber optics, distributed temperature sensors, and MEMS (micro electromechanical systems). 
   Turning to the drawings,  FIGS. 1 and 2  depict embodiments of the types of distributed sensors that may be used in the present invention. Although these figures depict sensors configured to measure flow rate, the method should not be limited to use with these types of sensor.  FIG. 1  shows distributed sensor  100  with a rectangular cross-section; in this case a fiber optic sensor is depicted. Distributed sensor  100  comprises upstream sensor  101  and downstream sensor  102 . Heating element  103  is placed between upstream sensor  101  and downstream sensor  102 . Upstream sensor  101 , downstream sensor  102  and heating element  103  are bundled together in tube  104 , which is covered with protective member  105  to isolate the equipment from fluid  106 . Item  106  depicts the direction of the fluid flowing across distributed sensor  100 . 
   Distributed sensor  100  works in a manner similar to a hot element anemometer as described in U.S. Pat. No. 6,705,158 B1 and U.S. Pat. No. 4,011,756 which are both hereby incorporated by reference. When fluid  106  flows across distributed sensor  100 , the temperature at upstream sensor  101  is slightly cooler than the temperature at downstream sensor  102 . By subtracting the temperature at upstream sensor  101  from the temperature at downstream  102 , one can determine the temperature rise in proportion to the heat absorbed along distributed sensor  100 . From this value, the local flow rate of fluid  106  can be derived. 
     FIG. 2  shows distributed sensor  200  with a streamlined cross-section. In this drawing, upstream sensor  201  and downstream sensor  202  are shown encased in tube  204  with heating element  203  and intermittently placed. Protective member  205  encases the equipment to shield it from fluid  206 . Distributed sensor  200  in  FIG. 2  works in substantially the same manner as distributed sensor  100  in  FIG. 1  described above. 
   In addition to the configurations depicted, many other sensor configurations may be used. For example, a tri-core fiber optic distributed sensor could be used. In this case, the sensor could have a triangular shape. In addition, one sensor which measures temperature, one which measures pressure, and one which measures strain could be bundled together in a single tube. 
   The present invention is intended for use in a variety of downhole environments (e.g. cased hole, open hole, multi-lateral).  FIGS. 3-7  show embodiments of the present invention installed in cased hole completion  300 . Turning to  FIG. 3 , wellbore  302  is shown drilled into formation  301 . Wellbore  302  is lined with casing  303  and optionally cemented in place. Fluid communication is established with formation  301  by forming perforations  304  using traditional methods known in the art of well completion. Production tubing  305  is installed in wellbore  302  inside of casing  303 . 
   This embodiment of the present invention utilizes a distributed sensor to monitor the fluid properties the wellbore. In order to provide enough data points to construct a production profile along the length and circumference of the wellbore, a coiled distributed sensor is wrapped around the inside of the wellbore. Installation of the distributed sensor in this coiled manner enables the operator to obtain a circumferential profile along the entire length of the wellbore. In addition, this configuration may increase vertical resolution and minimize drag, thereby enabling the sensor to better withstand the velocity of the flow. 
   Before installation, distributed sensor  306  is wound around spool  307 , causing it to retain a helical shape. After distributed sensor  306  is wound, it is pulled into wellbore  302 . The embodiment in  FIG. 3  illustrates distributed sensor  306  being pulled into wellbore  302  by attaching weight  309  to the end of distributed sensor  306  and drawing it downwards. Any type of weight or mechanism for pulling distributed sensor  306  into wellbore  302  could be used as an alternative to sinker bar  309 . 
   Sheave assembly  308  is used to feed distributed sensor  306  into wellbore  302 . As distributed sensor  306  is being fed into wellbore  302 , sheave assembly  308  measures the tension at the top of wellbore  302 . Sinker bar  309  is attached to the bottom of distributed sensor  306 . Sinker bar  309  is used to pull distributed sensor  306  into wellbore  302 , partially straightening it but retaining the spiral cast from spool  307 . 
   After distributed sensor  306  is fully inserted into wellbore  302 , sinker bar  309  is lowered below last perforation  304  into bottom of wellbore  302  as shown in  FIG. 4 . As this is done, the tension at top of wellbore  302  begins to fall and distributed sensor  306  begins to assume a more coiled shape from the bottom of wellbore  401  upward due to the effects of the distributed sensor  306  weight. Distributed sensor  306  begins to coil near bottom of production tubing  402  and increases in radius, reaching the wall of production tubing  305 . As more distributed sensor is fed from the top, the coiled portion touching the wall of production tubing  305  begins to increase. 
   As shown in  FIG. 5 , eventually the tension felt at the top of the wellbore  302  reduces to zero as distributed sensor  306  becomes supported by friction at the wall of production tubing  305 . As shown in  FIG. 6 , more of the distributed sensor  306  is pushed into the wellbore  302  to assure that the coiled distributed sensor  306  reaches the top of the well and that friction will hold it in place as the well begins to flow. Optionally, in the case where the distributed sensor is a fiber optic cable, pressure may be applied to the member containing the fiber. Applying pressure causes the coiled sensor to straighten; however, it is constrained by the wall of production tubing  305 . This increases the friction between the sensor and the wall of the production tubing. 
   To insure that the distributed sensor is the correct length to reach the entire depth of the wellbore and cover the entire circumference, the length of the distributed sensor must be greater than the depth of the wellbore by a factor of 
             1   +       (       π   ⁢           ⁢   D     P     )     2             
where D is the diameter of the wellbore and P is the diameter of the spool. Ideally after installation, distributed sensor  306  should be a coiled sheath covering substantially the entire length and circumference of wellbore  302 .
 
   After distributed sensor  306  is installed, it is then connected to surface controls  601 , the well is sealed, and sheave assembly  308  is disconnected. Distributed sensor  306  now provides a mechanism for obtaining a distributed profile of flow around the circumference and length of wellbore  302 . 
     FIG. 7  shows an alternative embodiment of the cased hole completion where distributed sensor  306  is pulled into wellbore  302  by sheave assembly  308 . In this embodiment, there is no production tubing and the distributed sensor is deployed in casing  303 . Here friction between the casing and the distributed sensor holds the distributed sensor in place. 
     FIGS. 8-9  show embodiments of the present invention installed in open hole completion  800 . The figures show open hole well  800  consisting of wellbore  801  drilled into formation  802  and left uncased. Optionally production tubing (not shown) can be installed in wellbore  302 . If production tubing is installed, the distributed sensor can be deployed in the production as shown in the cased hole embodiments. 
   Alternatively the distributed sensor can be deployed directly into the wellbore. In these embodiments, distributed sensor  306  is fed into wellbore  801  using spool  307  and sheave assembly  308 . Distributed sensor  306  is pulled into wellbore  701  by the weight of sinker bar  309 .  FIG. 8  shows distributed sensor  306  fully installed in open hole completion  800 . As shown, distributed sensor  306  forms a tight coil against formation  802  in wellbore  801 .  FIG. 9  shows production tubing  901  installed in open hole completion  800 . Here distributed sensor  306  forms a tight coil against the inner surface of production tubing  901  in a manner similar to that shown in  FIGS. 3-6  depicting the cased hole application. The distributed sensor is supported by friction against the wellbore. 
   Once the distributed sensor is installed in a cased or open hole completion, the operator can produce oil while monitoring fluid properties in the wellbore. As discussed earlier, an embodiment of the invention is directed at measuring flow properties; one frequently useful flow property if low rate. Monitoring of flow rate is performed by measuring the temperature of the fluid at the upstream sensor to obtain a first value measuring the temperature of the fluid at the downstream sensor to obtain a second value, subtracting the first value from the second value to obtain a third value corresponding to the temperature rise in proportion to heat absorbed along the distributed sensor; and deriving flow rate from the third value. In this embodiment, if the thermal properties of the distributed sensor, heat input per unit length, and heating element resistivity are known, one can derive flow rate because the measured temperature change will be proportional to the flow rate carrying heat into the fluid. This calculation may be performed using finite element steady state analysis. 
     FIG. 10  shows another embodiment of the invention wherein a distributed sensor is deployed across only the production interval of a completion. This embodiment could be particularly useful in horizontal wells, multilateral wells, or situations in which there are cost or data transmission limitations. In this embodiment, wellbore  900  is divided into horizontal section  901  and vertical section  902 . Wellbore  900  is lined with casing  903 , which is perforated as shown by drawing element  904 . The casing is made up of several joints, one of which is sensor joint  905 . Sensor joint  905  contains distributed sensor  906 , which is coiled on the inner surface of the joint. In addition to being a joint of casing, sensor joint  905  could also be a sand control screen, a section of liner, or any other downhole component. Joints of traditional tubing  907  are installed in casing  903  along with sensor joint  905 , which is placed at a depth corresponding to the production interval of the well. At a specified time, operator may uncoil distributed sensor  906  thereby deploying the sensor over the producing internal. 
   This embodiment may also be adapted for use in multilateral wells as shown in  FIG. 11 .  FIG. 11  shows multilateral well  1100  drilled into formation  1101 . Multilateral well  110  consists of leg one  1102  (lined with casing  1103  and perforated at  1104 ) and leg two  1105  (lined with casing  1106  and perforated at  1107 ). First distributed sensor  1108  and second distributed sensor  1109  are provided. First tubing  1110  is installed in leg one  1102 , and second tubing  1111  is installed in leg two  1105 . First distributed sensor  1108  is coiled inside of first tubing  1110 , and second distributed sensor  1109  is coiled inside of second tubing  1111 . Connectors  1112  and  1113  connect first distributed sensor  1108  and second distributed sensor  1109  to surface control  114 . At a specified time, an operator may choose to deploy either first distributed sensor  1108  over the producing interval of leg one  1102  and/or to deploy second distributed sensor  1109  over the producing interval of leg two  1105 . 
   Those of skill in the art will appreciate that many modifications and variations are possible in terms of the disclosed embodiments, configurations, materials, and methods without departing from their spirit and scope. Accordingly, the scope of the claims appended hereafter and their functional equivalents should not be limited by particular embodiments described and illustrated herein, as these are merely exemplary in nature.

Summary:
A method for monitoring fluid properties with a distributed sensor in a wellbore having an inner surface, a top and a bottom comprising causing the distributed sensor to assume a helical shape, pulling the distributed sensor towards the bottom of the wellbore, while retaining the helical shape of the distributed sensor, feeding the distributed sensor into the wellbore so that the distributed sensor is in substantially continuous contact with the inner surface, and allowing the distributed sensor to become at least partially supported by friction at the inner surface.