Fluid property sensors and associated methods of calibrating sensors in a subterranean well

CROSS-REFERENCE TO RELATED APPLICATION

[0001] This application claims the benefit under 35 USC §119 of the filing date of PCT Application No. PCT/US00/29254, filed Oct. 23, 2000, the disclosure of which is incorporated herein by this reference.

BACKGROUND

[0002] The present invention relates generally to fluid property measurement in a subterranean well and, in an embodiment described herein, more particularly provides fluid property sensors and methods of calibrating same.

[0003] It is very beneficial to be able to independently control production from each one of multiple zones of a well. For example, when water begins to be produced from a particular zone, it may be desired to cease production from that zone, while still producing from other zones of the well. As another example, when gas begins to be produced from a particular zone, it may be desired to decrease production from that zone, while still producing from other zones of the well. As a further example, rates of production from various zones may be independently regulated to maximize overall production from a reservoir.

[0004] However, in order to accurately determine the particular zones to regulate production from, and the manner in which production from those zones should be regulated, a well operator needs to be able to determine what fluids, and what quantities of those fluids, are being produced from each zone. Prior methods of making these determinations have relied on use of wireline conveyed tools. However, use of these tools usually requires that the well be shut in and that an intervention be made into the well.

[0005] It would be far more convenient and useful to be able to continuously monitor what fluids, and what quantities of those fluids, are being produced from each zone of a well. It is accordingly one of the objects of the present invention to provide fluid property sensors for relatively permanent installation in a well, and methods of using and calibrating those sensors.

SUMMARY

[0006] In carrying out the principles of the present invention, in accordance with embodiments thereof, fluid property sensors and associated methods are described herein. In the described embodiments, the sensors and methods are utilized to facilitate monitoring and control of production from multiple zones of a well. However, it is to be understood that the sensors and methods may also be used in other situations.

[0007] In one aspect of the present invention, sensors in fluid communication with an annulus external to a tubing string are used to measure properties of fluid flowing from a zone into the tubing string. By using such external sensors for each zone of a well, properties of the fluid produced from each zone may be determined prior to the fluid entering the tubing string. Thus, the properties measured by the external sensors are indicative of the fluid produced from a zone prior to it being commingled in the tubing string with fluid produced from other zones.

[0008] In another aspect of the present invention, an external venturi flowmeter is provided. The flowmeter is interconnected in a tubing string and positioned in a wellbore. Fluid flowing from a zone through an annulus between the wellbore and the tubing string is constrained to pass through a flow restriction due to a projection formed on a housing of the flowmeter. A differential pressure gauge measures a differential pressure between the fluid upstream of the flow restriction and the fluid flowing in the flow restriction. In this manner, a rate of flow of fluid produced from a zone may be determined before the fluid is commingled in the tubing string with fluid produced from other zones.

[0009] In yet another aspect of the present invention, a fluid density sensor is provided. The fluid density sensor uses a unique combination of gamma ray sources and detectors to enable its relatively permanent installation in a well. In the described embodiment, gamma ray sources exempt from certain regulations and Geiger-Muller gamma ray detectors are used. An additional detector is used to determine the contribution of background gamma ray sources to the measured rate of gamma rays received.

[0010] In a further aspect of the invention, the fluid density sensor is combined with other sensors in a sensor system, measurements from which may be used to determine a volumetric flow rate of each phase of fluids produced through a tubular string. The sensor system may be positioned in the string downstream of a flow control device regulating fluid flow into the string from a zone.

[0011] In a still further aspect of the invention, multiple ones of the sensor systems and flow control devices may be used in a well having multiple independently produced zones. A method of calibrating the sensor systems is provided, whereby measurements obtained from each of the sensor systems may be calibrated. The use of the calibrated multiple sensor systems enables determination of the volumetric flow rate of each phase of fluids produced from each of the zones.

[0012] These and other features, advantages, benefits and objects of the present invention will become apparent to one of ordinary skill in the art upon careful consideration of the detailed description of representative embodiments of the invention hereinbelow and the accompanying drawings.

BRIEF DESCRIPTION OF THE DRAWINGS

[0013]FIG. 1 is a schematic view of a first method of sensing fluid properties in a subterranean well, the method embodying principles of the present invention;

[0014]FIG. 2 is an enlarged scale schematic partially cross-sectional view of a first sensor system for an individual zone of a multizone completion, the first sensor system being usable in the first method of FIG. 1 and embodying principles of the present invention;

[0015]FIG. 3 is an enlarged scale schematic partially cross-sectional view of a second sensor system for an individual zone of a multizone completion, the sensor system being usable in the first method of FIG. 1 and embodying principles of the present invention;

[0016]FIG. 4 is a schematic cross-sectional view of a fluid density sensor embodying principles of the present invention;

[0017]FIG. 5 is a schematic cross-sectional view of the fluid density sensor, taken along line <b>5</b>-<b>5</b> of FIG. 4;

[0018]FIG. 6 is a schematic cross-sectional view of the fluid density sensor, taken along line <b>6</b>-<b>6</b> of FIG. 4;

[0019]FIG. 7 is a schematic cross-sectional view of the fluid density sensor, showing an alternate configuration thereof;

[0020]FIG. 8 is a schematic view of a second method of sensing fluid properties in a subterranean well utilizing a second sensor system, the second method and sensor system embodying principles of the present invention; and

[0021]FIG. 9 is a schematic view of a method of calibrating sensor systems in a multilateral well.

DETAILED DESCRIPTION

[0022] Representatively illustrated in FIG. 1 is a method <b>10</b> which embodies principles of the present invention. In the following description of the method <b>10</b> and other apparatus and methods described herein, directional terms, such as “above”, “below”, “upper”, “lower”, etc., are used only for convenience in referring to the accompanying drawings. Additionally, it is to be understood that the various embodiments of the present invention described herein may be utilized in various orientations, such as inclined, inverted, horizontal, vertical, etc., and in various configurations, without departing from the principles of the present invention.

[0023] In the method <b>10</b>, it is desired to determine properties of fluid produced from multiple zones <b>12</b>, <b>14</b>, <b>16</b> into a tubing string <b>18</b>. The tubing string <b>18</b> is positioned in a wellbore <b>20</b> intersecting the zones <b>12</b>, <b>14</b>, <b>16</b>. An annulus <b>22</b> is formed radially between the wellbore <b>20</b> and the tubing string <b>18</b>. Packers <b>24</b> isolate portions of the annulus <b>22</b> from each other. Flow control devices <b>26</b>, <b>28</b>, <b>30</b> permit selective control of fluid flow between each of the zones <b>12</b>, <b>14</b>, <b>16</b> and an interior flow passage (not visible in FIG. 1) of the tubing string <b>18</b>.

[0024] It is very beneficial to be able to determine the properties of the fluid flowing from each of the zones <b>12</b>, <b>14</b>, <b>16</b> into the tubing string <b>18</b>. For example, one of the zones <b>12</b>, <b>14</b>, <b>16</b> may begin producing water, in which case it would be beneficial to know which one of the zones is producing water, so that it may be determined which of the flow control devices <b>26</b>, <b>28</b> or <b>30</b> should be closed. As another example, it may be beneficial for purposes of maximum recovery from a reservoir to accurately regulate the flow from each zone <b>12</b>, <b>14</b>, <b>16</b>, depending at least in part on the types and relative quantities of fluids produced from the zones. In that case, the flow control devices <b>26</b>, <b>28</b>, <b>30</b> may be variable chokes which are operable to regulate a rate of fluid flow through respective ports <b>32</b>, <b>34</b>, <b>36</b> thereof, to thereby control the rate of fluid produced from each corresponding zone <b>12</b>, <b>14</b>, <b>16</b>.

[0025] Note that, although the method <b>10</b> is depicted in FIG. 1 as being performed with three zones <b>12</b>, <b>14</b>, <b>16</b> intersected by a cased and cemented wellbore <b>20</b>, it is to be clearly understood that any number of zones may be intersected by any type of wellbore, including lined or open hole wellbores, etc., in a method incorporating principles of the present invention. The principles of the present invention are not limited by the specific details of the method <b>10</b>, which is described herein as merely an example of an embodiment of the invention.

[0026] Referring additionally now to FIG. 2, an enlarged partially cross-sectional view of a portion of the well shown in FIG. 1 is representatively illustrated. Specifically, the flow control device <b>26</b> and the corresponding zone <b>12</b> are depicted in FIG. 2. In this view it may be clearly seen that the tubing string <b>18</b> is positioned in the wellbore <b>20</b> and configured so that fluid (represented by arrows <b>38</b>) flows from the zone <b>12</b>, flows externally across an exterior surface of the tubing string <b>18</b>, into the port <b>32</b>, and then into the internal flow passage <b>40</b> of the tubing string.

[0027] In the method <b>10</b>, sensors <b>42</b>, <b>44</b>, <b>46</b> are in fluid communication with the fluid <b>38</b> as it flows externally across the tubing string <b>18</b> from the zone <b>12</b> to the port <b>32</b>. In this manner, properties of the fluid <b>38</b> may be sensed before the fluid enters the tubing string <b>18</b> flow passage <b>40</b>, where the fluid may be commingled with fluid from other zones.

[0028] The sensors <b>42</b>, <b>44</b>, <b>46</b> may be any of a fluid capacitance sensor, a fluid dielectric sensor, a fluid resistivity sensor, a fluid conductivity sensor, a nuclear fluid density sensor, an acoustic fluid density sensor, a fluid pressure sensor, a temperature sensor, a fluid compressibility sensor, a fluid pH sensor, or any other type of fluid property sensor. For example, an external nuclear fluid density sensor may include a gamma ray source and a gamma ray detector, with the source vertically collimated along the axis of the tubing string <b>18</b>, and with the detector having a coincident axis of collimation, as is used in conventional wireline production logging tools. As another example, an external resistivity sensor may include two toroids (toroidally-shaped magnetic material wound with wire) located in an insulating housing, one toroid being used for excitation, and the other being used for current sensing. In addition, for each of the above sensor types, multiple sensors angularly distributed on the exterior of the tubing string <b>18</b> could be utilized.

[0029] The sensor <b>42</b> is preferably a pressure sensor which, in combination with another pressure sensor <b>48</b> in fluid communication with the internal flow passage <b>40</b>, may be used to determine a pressure differential between the flow passage <b>40</b> and the portion of the annulus <b>22</b> in which the fluid <b>38</b> flows. Alternatively, a single differential pressure sensor (such as the differential pressure sensor <b>62</b> shown in FIG. 3) may be used in place of the separate pressure sensors <b>42</b>, <b>48</b>.

[0030] In addition, internal sensors <b>50</b>, <b>52</b> may be used to sense properties of fluid in the flow passage <b>40</b> downstream of the port <b>32</b>. The sensors <b>50</b>, <b>52</b> may be any of a nuclear fluid density sensor, a nuclear magnetic resonance sensor, an optical attenuation sensor, an optical transmission sensor, an electromagnetic wave sensor or any other type of fluid property sensor.

[0031] With external sensors (such as the sensors <b>42</b>, <b>44</b>, <b>46</b> utilized for sensing properties of the fluid <b>38</b>) being utilized for fluid flowing from each of the other zones <b>14</b>, <b>16</b>, as well as for the zone <b>12</b> as shown in FIG. 2, it is possible to individually determine properties of fluid flowing from each of the zones in the method <b>10</b>. In this manner, informed decisions may be made as to whether to open, close, or to what degree to regulate fluid flow through, each of the flow control devices <b>26</b>, <b>28</b>, <b>30</b>.

[0032] Referring additionally now to FIG. 3, the method <b>10</b> is representatively illustrated wherein an external venturi flowmeter <b>54</b> is utilized as one of the external sensors for sensing properties of the fluid <b>38</b> flowing from the zone <b>12</b> into the tubing string <b>18</b>. Specifically, the flowmeter <b>54</b> is used to sense a rate of flow of the fluid <b>38</b> through the annulus <b>22</b> between the zone <b>12</b> and the port <b>32</b>.

[0033] The flowmeter <b>54</b> is configured to form a flow restriction <b>56</b> in the annulus <b>22</b>. The flow restriction <b>56</b> is defined between the wellbore <b>20</b> and a radially outwardly extending projection <b>58</b> formed on a housing <b>60</b> of the flowmeter <b>54</b>. It will be readily appreciated by one skilled in the art that a pressure of the fluid <b>38</b> decreases as it accelerates to flow through the restriction. The flow restriction <b>56</b>, therefore, creates a venturi effect external to the tubing string <b>18</b>.

[0034] Preferably, a differential pressure sensor <b>62</b> is used to sense a pressure differential between the fluid <b>38</b> upstream of the flow restriction <b>56</b> and the fluid in the flow restriction. From this information, appropriately calibrated, a flow rate of the fluid <b>38</b> may be readily determined. Alternatively, other types of sensors, such as individual pressure and temperature sensors <b>64</b>, <b>66</b>, may be used to sense properties of the fluid <b>38</b>.

[0035] Note that the sensors <b>42</b>, <b>44</b>, <b>46</b>, <b>48</b>, <b>50</b>, <b>52</b> described above in relation to FIG. 2 may also be used in conjunction with the flow meter <b>54</b> in the method <b>10</b> as depicted in FIG. 3.

[0036] Referring additionally now to FIG. 4, a fluid density sensor <b>68</b> embodying principles of the present invention is representatively illustrated. The sensor <b>68</b> may be used in the method <b>10</b> described above, in another method described below, or in any other method.

[0037] The sensor <b>68</b> uniquely utilizes a gamma ray source <b>70</b> and a Geiger-Muller gamma ray detector <b>72</b> positioned on opposing sides of a flow passage <b>74</b> extending longitudinally through a generally tubular housing assembly <b>76</b>. The source <b>70</b> and detector <b>72</b> are positioned in a sidewall of the housing <b>76</b>.

[0038] Note that it is not necessary in keeping with the principles of the invention for the sensor <b>68</b> to include the Geiger-Muller gamma ray detector <b>72</b>. For example, scintillation crystals attached to photodiodes, or another type of gamma ray detector, may be utilized in the sensor <b>68</b>.

[0039] The housing <b>76</b> is configured for interconnection as a part of a tubular string, such as a production tubing string, in a well. FIG. 5 shows a preferred orientation of the source <b>70</b> and detector <b>72</b> relative to a longitudinal axis of the flow passage <b>74</b>.

[0040] Preferably, the source <b>70</b> is a material having a gamma ray intensity which is exempt from regulations requiring periodic wipe testing thereof. In this manner, the sensor <b>68</b> may be included in a tubing string which remains in a well for a substantial length of time, perhaps many years. For example, the source <b>70</b> may include one or more individual portions having an intensity of approximately 10 microcuries or less, and may comprise barium 133 or cesium 137 material. Of course, other types of gamma ray sources may be utilized in the sensor <b>68</b>, without departing from the principles of the present invention.

[0041] Fluid flowing through the flow passage <b>74</b> will attenuate a rate of gamma rays detected by the detector <b>72</b> from the source <b>70</b>. This attenuation of gamma rays may be related to a density of the fluid flowing through the flow passage <b>74</b> upon appropriate calibration of the sensor <b>68</b> measurements. If, however, the fluid in the flow passage <b>74</b> is nonuniform, such as if the fluid is in multiple phases which have become segregated in the flow passage, the density indicated by the rate of gamma rays detected by the detector <b>72</b> from the source <b>70</b> may not be truly representative of the overall fluid density.

[0042] The inventors have solved the problem of nonuniformity in the fluid flowing through the passage <b>74</b> by including a second set of source <b>78</b> and detector <b>80</b> similar to the source <b>70</b> and detector <b>72</b> described above. The source <b>78</b> is preferably positioned 90 degrees from the source <b>70</b> relative to the flow passage, and the detector <b>80</b> is preferably positioned 90 degrees from the detector <b>72</b> relative to the flow passage. In this manner, the additional source <b>78</b> and detector <b>80</b> provide a different perspective relative to the flow passage <b>74</b> for sensing the fluid density, which aids in resolving any nonuniformity in the fluid. For example, measurements from the detectors <b>72</b>, <b>80</b> may be averaged together. Additionally, the second set of source <b>78</b> and detector <b>80</b> provide redundancy in the event that one or both of the source <b>70</b> and detector <b>72</b> should become unusable.

[0043] Other quantities of sources and detectors may be used. For example, only the single set of source <b>70</b> and detector <b>72</b> may be used, three or more sets of sources and detectors may be used, etc.

[0044] Each of the sources <b>70</b>, <b>78</b> and each of the detectors <b>72</b>, <b>80</b> is collimated by shielding <b>82</b>, <b>84</b>, <b>86</b>, <b>88</b>, respectively. The shielding <b>82</b> directs gamma rays from the source <b>70</b> toward the detector <b>72</b>, the shielding <b>84</b> directs gamma rays from the source <b>78</b> toward the detector <b>80</b>, the shielding <b>86</b> permits the detector <b>72</b> to receive gamma rays substantially only from a direction of the source <b>70</b>, and the shielding <b>88</b> permits the detector <b>80</b> to receive gamma rays substantially only <b>30</b> from a direction of the source <b>78</b>.

[0045] The shieldings <b>82</b>, <b>84</b>, <b>86</b>, <b>88</b> minimize interference between each set of source and detector. It is, however, recognized that some gamma rays originating from the source <b>70</b> may be received by the detector <b>80</b> and some gamma rays originating from the source <b>78</b> may be received by the detector <b>72</b>. In addition, some background gamma radiation from background sources, such as earth formations, scale buildup in the flow passage <b>74</b>, etc., may be received by the detectors <b>72</b>, <b>80</b>, even through their shielding <b>86</b>, <b>88</b>.

[0046] Referring additionally now to FIG. 6, a cross-sectional view of the sensor <b>68</b> is representatively illustrated, in which it may be seen that another detector <b>90</b> is positioned in the housing <b>76</b> sidewall above the source <b>78</b>. The detector <b>90</b> is similar to the other detectors <b>72</b>, <b>80</b> described above. The detector <b>90</b> is used to compensate for background gamma radiation received by the sensors <b>72</b>, <b>80</b>.

[0047] The detector <b>90</b> has shielding <b>92</b> on all sides. The shielding <b>92</b> is preferably, but not necessarily, made of the same material as used for the shielding <b>86</b>, <b>88</b>. In this manner, the detector <b>90</b> should receive approximately the same amount of background radiation through its shielding as received by the detectors <b>72</b>, <b>80</b>. However, the detector <b>90</b> could receive a different amount of background radiation, or be otherwise shielded, without departing from the principles of the present invention.

[0048] In addition, the detector <b>90</b> may receive through its shielding <b>92</b> some gamma rays originating from the sources <b>70</b>, <b>78</b>. Due to the close proximity of the detector <b>90</b> to the source <b>78</b>, a shield <b>94</b> may be positioned between the source <b>78</b> and the detector <b>90</b> to prevent any gamma rays from traveling in a straight line from the source <b>78</b> to the detector <b>90</b>. The shield <b>94</b> may be made of tungsten and may be incorporated into either or both of the shieldings <b>84</b>, <b>92</b>.

[0049] Prior to running the sensor <b>68</b> into a well, the rates of gamma rays received by the detector <b>90</b> from each of the sources <b>70</b>, <b>78</b> may be conveniently measured by merely assembling the sensor <b>68</b> and recording the gamma ray count rate from the detector <b>90</b>. Then, after the sensor <b>68</b> has been interconnected in a tubing string and positioned in a well, this gamma ray count rate due to the sources <b>70</b>, <b>78</b> may be subtracted from the gamma ray count rate from the detector <b>90</b> in the well, to obtain a measurement of the background gamma ray count rate. Of course, a more complex mathematical operation than mere subtraction may be used to compensate for the gamma ray count rate due to the sources <b>70</b>, <b>78</b> and obtain a measurement of the background count rate.

[0050] The background gamma ray count rate as determined by using the detector <b>90</b> may then be subtracted from the gamma ray count rates as measured by each of the detectors <b>72</b>, <b>80</b> to thereby determine more accurately the actual gamma ray count rates received by each of the detectors <b>72</b>, <b>80</b> from the respective one of the sources <b>70</b>, <b>78</b>. Again, a more complex mathematical operation than mere subtraction may be used to compensate for the background count rate and obtain the count rates received by the detectors <b>72</b>, <b>80</b> from the respective sources <b>70</b>, <b>78</b>.

[0051] Referring additionally now to FIG. 7, an alternate configuration of the sensor <b>68</b> is representatively illustrated. In this configuration, the sensor <b>68</b> includes a differently formed flow passage <b>96</b> extending through a housing <b>98</b>. A cross-section of the flow passage <b>96</b> taken perpendicular to its longitudinal axis is noncircular, as depicted in FIG. 7. Specifically, the flow passage <b>96</b> perimeter extends radially outward somewhat between adjacent ones of the sources <b>70</b>, <b>78</b> and detectors <b>72</b>, <b>80</b>.

[0052] The noncircular shape of the flow passage <b>96</b> provides more flow area, thereby decreasing a resistance to fluid flow therethrough and decreasing the velocity of the fluid flow. This may reduce the susceptibility of the housing <b>98</b> to erosion.

[0053] Referring additionally now to FIG. 8, another method <b>100</b> embodying principles of the present invention is representatively illustrated. In the method <b>100</b>, the fluid density sensor <b>68</b> is interconnected in a tubular string <b>102</b> as a part of an overall sensor system <b>104</b>. Of course, another type of fluid density sensor may be used in the sensor system <b>104</b>, without departing from the principles of the present invention. However, the fluid density sensor <b>68</b> is preferred for long term use in the tubular string <b>102</b>, due to its use of exempt gamma ray sources and durable long-lasting Geiger-Muller detectors.

[0054] The sensor system <b>104</b> further includes a flowmeter <b>106</b>, a pressure sensor <b>108</b>, a temperature sensor <b>110</b>, and a fluid dielectric sensor <b>112</b> and/or a fluid conductivity sensor <b>114</b>. These sensors <b>106</b>, <b>108</b>, <b>110</b>, <b>112</b>, <b>114</b> may be any of the various corresponding types of sensors well known to those skilled in the art. Of course, other types of sensors may be utilized, without departing from the principles of the present invention.

[0055] The inventors have found that, with appropriately calibrated measurements obtained from the combination of sensors <b>68</b>, <b>106</b>, <b>108</b>, <b>110</b>, <b>112</b>, <b>114</b> illustrated in FIG. 8, a volumetric flow rate of each phase of fluid flowing through an internal flow passage <b>116</b> of the tubular string <b>102</b> may be obtained.

[0056] A flow control device, such as a variable choke <b>118</b>, interconnected in the tubular string <b>102</b> may be used to regulate fluid flow between a zone <b>120</b> intersected by a wellbore <b>122</b> of the well and the flow passage <b>116</b>. This regulation of fluid produced from the zone <b>120</b> may be performed in response to measurements of fluid properties obtained from the sensor system <b>104</b>. For example, if the sensor system <b>104</b> indicates that water is beginning to be produced from the zone <b>120</b>, the flow control device <b>118</b> may be closed.

[0057] Electronic circuitry <b>124</b> converts the outputs from the sensors <b>68</b>, <b>106</b>, <b>108</b>, <b>110</b>, <b>112</b>, <b>114</b> into usable form for transmission to a remote location, such as a computer at the surface. For example, the electronic circuitry <b>124</b> may convert the outputs of the detectors <b>72</b>, <b>80</b>, <b>90</b> into a form indicating the respective gamma ray count rates (gamma ray counts per unit of time) measured by the detectors. Software on the computer at the surface may then convert the count rates into an indicator of fluid density, using known mathematical relationships. The electronic circuitry <b>124</b> and the software may be developed using techniques well known to those skilled in the art.

[0058] Referring additionally now to FIG. 9, another method <b>130</b> embodying principles of the present invention is representatively illustrated. The method <b>130</b> utilizes multiple sensor systems <b>132</b>, <b>134</b>, <b>136</b>, <b>138</b>, <b>140</b> and multiple flow control devices, such as variable chokes <b>142</b>, <b>144</b>, <b>146</b>, <b>148</b>, <b>150</b>, to monitor and control production from corresponding multiple zones <b>152</b>, <b>154</b>, <b>156</b>, <b>158</b>, <b>160</b> of a well.

[0059] The sensor systems <b>132</b>, <b>134</b>, <b>136</b>, <b>138</b>, <b>140</b> may be similar to the sensor system <b>104</b> described above, and the chokes <b>142</b>, <b>144</b>, <b>146</b>, <b>148</b>, <b>150</b> may be similar to the choke <b>118</b> described above. The sensor systems <b>132</b>, <b>134</b>, <b>136</b> and corresponding respective chokes <b>142</b>, <b>144</b>, <b>146</b> are interconnected in a tubing string <b>162</b> extending into a branch wellbore <b>164</b> of the well. The sensor systems <b>138</b>, <b>140</b> and corresponding respective chokes <b>148</b>, <b>150</b> are interconnected in another tubing string <b>166</b> extending into a wellbore <b>168</b>, which may be a branch wellbore or a portion of a main wellbore. It is to be clearly understood, however, that the particular number and arrangement of sensor systems, flow control devices, tubing strings, wellbores, etc. depicted for the method <b>130</b> in FIG. 9 are given merely as an example of one embodiment of the invention, and are not to be taken as limiting the principles of the present invention in any way.

[0060] In order to be able to determine the volumetric flow rates of each phase of fluid produced from each of the zones <b>152</b>, <b>154</b>, <b>156</b>, <b>158</b>, <b>160</b> using the sensor systems <b>132</b>, <b>134</b>, <b>136</b>, <b>138</b>, <b>140</b>, the inventors have found that the measurements obtained from each of the sensor systems should be calibrated while the fluid produced from each of the zones is flowing through the respective sensor systems. Unfortunately, each sensor system will have fluid flowing through it from its corresponding zone as well as from each zone produced upstream therefrom relative to the respective tubing string <b>162</b> or <b>166</b>. For example, the sensor system <b>132</b> will have fluid flowing through it from the zones <b>152</b>, <b>154</b>, <b>156</b> if the chokes <b>142</b>, <b>144</b>, <b>146</b> are open, making it difficult to calibrate the sensor system for the fluid flowing only from the corresponding zone <b>152</b>.

[0061] The inventors have devised the method <b>130</b> for calibrating the sensor systems <b>132</b>, <b>134</b>, <b>136</b>, <b>138</b>, <b>140</b> which resolves these problems. In the method <b>130</b>, flow is initially permitted through only a lowermost one of the flow control devices in a first one of the tubing strings. As used herein, the term “lowermost” means farthest upstream relative to fluid flow through the corresponding tubing string, or farthest from the surface along the tubing string. The sensor system corresponding to that flow control device is calibrated by measuring properties of the produced fluid at the surface and determining appropriate calibration values for measurements obtained from the corresponding sensor system.

[0062] Properties of the produced fluid measured at the surface may include flow rate, oil weight, gas gravity, water density and water salinity. The inventors have found that this combination of measured properties is sufficient to enable calibration of the sensors included in the sensor system <b>104</b> described above. Of course, other properties may be measured without departing from the principles of the present invention.

[0063] Once the calibration procedure has been performed for the sensor system corresponding to the lowermost flow control device in a tubing string, the next lowermost flow control device is opened. The sensor system corresponding to that next lowermost flow control device is calibrated using the procedure described above, that is, by measuring properties of the produced fluid at the surface and determining appropriate calibration values for measurements obtained from the corresponding sensor system.

[0064] The lowermost flow control device is not closed while the next lowermost flow control device is opened, so the fluid properties measured by the sensor system corresponding to the next lowermost flow control device will be indicative of fluid entering the tubing string from both of the two lowermost flow control devices. However, since the fluid properties of the fluid entering the tubing string from the lowermost flow control device have already been determined, appropriate adjustments may be made to the measurements obtained from the sensor system corresponding to the next lowermost flow control device to account for the contribution thereto by the fluid entering the tubing string through the lowermost flow control device.

[0065] The above process is repeated, successively opening next lowermost flow control devices in a tubing string and performing the calibration procedure, until all of the flow control devices in a tubing string have been opened and all of the corresponding sensor systems have been calibrated. Then all of the flow control devices in that tubing string are closed and the process is repeated for the next tubing string.

[0066] In the method <b>130</b>, the calibration process would begin by closing all of the chokes <b>142</b>, <b>144</b>, <b>148</b>, <b>150</b>, except for the lowermost choke <b>146</b> in the tubing string <b>162</b>. Fluid from the zone <b>156</b> would be produced into the tubing string <b>162</b> and properties of the fluid would be measured at the surface. Appropriate calibration values for the measurements obtained from the sensor system <b>136</b> would then be determined.

[0067] The next lowermost choke <b>144</b> in the tubing string <b>162</b> would then be opened and fluid from the zone <b>154</b> would be commingled with fluid from the zone <b>156</b> in the tubing string. Properties of the fluid produced into the tubing string <b>162</b> would be measured at the surface. Appropriate calibration values for the measurements obtained from the sensor system <b>134</b> would then be determined, accounting for the contribution to the measured properties of the fluid from the zone <b>156</b>.

[0068] The next lowermost choke <b>142</b> in the tubing string <b>162</b> would then be opened and fluid from the zone <b>152</b> would be commingled with fluid from the zones <b>154</b>, <b>156</b> in the tubing string. Properties of the fluid produced into the tubing string <b>162</b> would be measured at the surface. Appropriate calibration values for the measurements obtained from the sensor system <b>132</b> would then be determined, accounting for the contribution to the measured properties of the fluid from the zones <b>154</b>, <b>156</b>.

[0069] All of the chokes <b>142</b>, <b>144</b>, <b>146</b> in the tubing string <b>162</b> would then be closed and the lowermost choke <b>150</b> in the tubing string <b>166</b> would be opened. Fluid from the zone <b>160</b> would be produced into the tubing string <b>166</b> and properties of the fluid would be measured at the surface. Appropriate calibration values for the measurements obtained from the sensor system <b>140</b> would then be determined.

[0070] The next lowermost choke <b>148</b> in the tubing string <b>166</b> would then be opened and fluid from the zone <b>158</b> would be commingled with fluid from the zone <b>160</b> in the tubing string. Properties of the fluid produced into the tubing string <b>166</b> would be measured at the surface. Appropriate calibration values for the measurements obtained from the sensor system <b>138</b> would then be determined, accounting for the contribution to the measured properties of the fluid from the zone <b>160</b>.

[0071] The inventors have found that, using the sensor system <b>104</b>, and appropriately calibrating the measurements obtained by sensors in the sensor system, the volumetric flow rate of each phase of a multiphase fluid produced through a tubing string may be determined. Using multiple sensor systems and the calibration process as representatively described above for the method <b>130</b>, the volumetric flow rate of each phase of multiphase fluids from each produced zone of a well may be independently determined. This information enables significantly greater control over well production than has heretofore been possible.

[0072] Of course, a person skilled in the art would, upon a careful consideration of the above description of representative embodiments of the invention, readily appreciate that many modifications, additions, substitutions, deletions, and other changes may be made to the specific embodiments, and such changes are contemplated by the principles of the present invention. Accordingly, the foregoing detailed description is to be clearly understood as being given by way of illustration and example only, the spirit and scope of the present invention being limited solely by the appended claims.