CA2184856C - Fluid holdup tool and flow meter for deviated wells - Google Patents

Abstract

A production logging tool is provided for use within a well to directly measure a velocity profile of a multiphase fluid flow within a cross-section of a well. The production logging tool includes a tool housing from which a plurality of arms are radially extensible. The plurality of arms are rotatably mounted to the tool housing for rotating around a tool axis extending longitudinally through the tool housing. At least one Doppler flow sensor is fixedly mounted to one of the plurality of arms for moving with the arm to dispose the Doppler flow sensor within different localized regions within a cross-section of the well.
The localized regions of the cross-section are located at different radial distances from and at different angular displacements around the tool axis of the tool housing, at points distal from the tool axis. The Doppler flow sensor has a depth of investigation for detecting flow velocities of a multiphase fluid flow proximate to the Doppler flow sensor, within the localized regions of the cross-section of the well. The plurality of arms are rotated about the tool housing to dispose the Doppler flow sensor within different ones of the localized regions disposed throughout the cross-section for measuring a velocity profile of the multiphase fluid flow through the cross-section of the well. Flow velocities are also preferably detected within localized regions disposed within the boundary layer of the multiphase fluid flow.

Description

s BACKGROUND OF THE INVENTION

7 2. Field of the Invention:
_ m 9 This invention relates in general to logging tools for detecting parameters of fluid flows, and in particular to a 11 logging tool for detecting flow parameters of multiphase fluid 12 flow.

14 3. Description of the Prior Art:
16 Prior art production logging tools have been utilized for 17 detecting flow velocities of multiphase fluid flows within oil 18 and gas wells. Prior art production logging tools have included 19 spinner type flowmeters which rotate when immersed within a flowstream. Spinner type flowmeters include fullbore flowmeters 21 and deflector flowmeters. Fullbore flowmeters typically detect 22 fluid flow within a central region of cross-section of a well.
23 Deflector flowmeters typically restrict the fluid flow through 24 part of a cross-section of the well, causing the fluid flow to pass through an unrestricted region of the well in which the flow 26 is detected. One type of deflector flowmeter restricts the flow 27 in a central region of the well, causing the flow to pass into 28 an annulus and by a plurality of spinner type of flowmeters which 29 detect the fluid flow. Deflector types of flowmeters detest fluid flows in either a central, or an outer annulus region of ' 31 a well cross-section.

33 Prior art production logging tools also usually include 34 other types of tools which detect downhole densities, pressures and fluid holdup of production fluids. Flow data measured with 36 prior art flowmeters is usually combined with data from these 218~~~~

1 other types of tools, and then a total flow rate of various 2 components of the multiphase fluid flow through the well is 3 computed. The computed flow values are typically approximated 4 by assuming that the multiphase fluid flow has a velocity profile of a particular shape. Typically, the velocity profile shape is 6 assumed to be uniform to simplify the calculations. However, all 7 wells are deviated to some extent. This usually causes the 8 actual velocity profile shapes of fluid flow within the wells to 9 differ from that used for the calculations.
11 In highly deviated wells and horizonal wells the f luid f low 12 may become stratified across a cross-sectional area of the well.
13 This may result in prior art fullbore spinner type flowmeters 14 detecting only a small portion of the stratified flow, such as only one phase, and not the other portions of the flow of 16 produced fluids. Very often, locating an entry point for only 17 a small portion of the multiphase fluid flow is desired. If the 18 small portion of the fluid flow is located along the outer 19 periphery of the cross-section of the well, it may not be detected by a full bore flowmeter. Further, the relative 21 proportion of the small portion of the fluid flow with respect 22 to the total fluid flow may be so small that it will not be 23 detected by either a full bore or deflector types of flowmeters, 24 since they typically average readings for the total flow of the multiphase fluid flow through wells.

27 Different types of flow patterns may be present in 28 multiphase fluid flows, both within vertical flow and horizontal.
29 flow. These different types of flow patterns further complicate the problem of determining the flow velocities of multiphase 31 fluid flows. In horizontal flow, very often bubble flow and 32 elongated bubble flow will occur. Additionally, stratified flow, 3 3 wave f low, slug f low, annular and annular mist f low and dispersed 34 froth flow may occur depending on the different flow parameters and flow velocities encountered. Vertical flow patterns may also ~%
36 include bubble flow, froth flow, annular, annular mist flow and Docket No. 0140D-034-CIP

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slug flow. These different flow patterns occur depending on the 2 velocities, the cross-sectional diameter, and other such 3 parameters affecting flow rate. Typically, the volumetric 4 proportions which occur at downhole well conditions are much different than those that occur further uphole, and those that 6 occur on the surface. Differences between uphole and downhole 7 volumetric proportions of multiphase fluid flows which include 8 a gas phase are often affected by the amount of gas which stays 9 in solution uphole as compared to the amount of gas which stays in solution downhole, and other such similar type of phenomenon.
11 These other types of f low patterns decrease the accuracy of these 12 approximations and i assumptions, further decreasing the 13 reliability of f low velocity flow determinations made with prior 14 art production logging tools.
16 Typically, different densities, frictional parameters and 17 different phases of different constituents of segregated 18 multiphase fluid flow result in the different constituents having 19 different flow velocities. For example, in a segregated, multiphase flow in a producing well having flow constituents 21 which consist of oil, gas and water, the gas phase may flow 22 faster than the oil phase, which may flow faster than a water 23 phase. In fact, in some sections of wells having multiple zones 24 of production, one phase may flow in an opposite direction within the well to that of a net flow of fluids. When annular type of 26 flow segregation occurs, such as with slug, annular mist and 27 froth flow, only the flow occurring within the central portion 28 of a cross-sectional area of a well is detected. Prior art.
29 production logging tools typically only measure flow parameters of multiphase fluid flows within a single particular limited 31 region of a cross-sectional area of a well, requiring 32 approximations and assumptions of flow characteristics. The flow 33 occurring around an outer circumference of the well is very often 34 not detected by prior art well logging tools, such as either fullbore spinner or deflector types of flow meters discussed 36 above.
Docket No. 0140D-034-CIP

1 SUI~ff~IARY OF THE INVENTION

3 It is one objective of the present invention to provide a 4 production logging tool for use to measure flow velocities and fluid parameters of a multiphase fluid flow in different 6 localized regions of a cross-section of a well, with the 7 different localized regions dispersed throughout the cross-8 section of the well.

It is another objective of the present invention to provide 11 a production logging tool for directly measuring the velocity 12 profile of a multiphase fluid flow in highly deviated wells at 13 a plurality of measurement points disposed in localized regions 14 about a cross-sectional area of a well, wherein the measurement points are distal from a central portion of the well.

17 It is further still another objective of the present 18 invention to provide a production logging tool having Doppler and 19 fluid parameter sensors which are distally disposed around the exterior of a tool housing of the production logging tool, and 21 which are angularly displaced about a satellite path extending 22 around the tool housing for measuring flow velocities and flow 23 parameters of different flow constituents of a multiphase fluid 24 flow at a plurality of measurement points located along the satellite path.

27 The above objectives are achieved as is now described. A
28 production logging tool is provided for use within a well to 29 directly measure a velocity profile of a multiphase fluid flow within a cross-section of a well. The production logging tool 31 includes a tool housing from which a plurality of arms are 32 radially extensible. The plurality of arms are rotatably mounted 33 to the tool housing for rotating around a tool axis extending 34 longitudinally through the tool housing. At least one Doppler 3 5 f low sensor and fluid f low parameter sensors are fixedly mounted 36 to separate ones of the plurality of arms for moving with the 1 plurality of arms to dispose the flow sensors within different 2 localized regions within a cross-section of the well. The 3 localized regions of the cross-section are located at different 4 radial distances from and at different angular displacements around the tool axis of the tool housing, at points distal from 6 the tool axis. The Doppler flow sensor has a depth of 7 investigation for detecting flow velocities of a multiphase fluid 8 flow proximate to the Doppler flow sensor, within the localized 9 regions of the cross-section of the well. The plurality of arms are rotated about the tool housing to dispose the Doppler flow 11 and fluid parameter sensors within different ones of the 12 localized regions disposed throughout the cross-section for 13 measuring a velocity profile of the multiphase fluid flow through 14 the cross-section of the well. Flow velocities are also preferably detected within localized regions disposed within the 16 boundary layer of the multiphase fluid flow.

18 In the preferred embodiment of the present invention, three 19 arms radially extend from the tool housing for disposing three flow sensors at three equally spaced points about the exterior 21 of the flowstream. At least one of the flow sensors is a Doppler 22 flow sensor. The Doppler flow sensor preferably includes a pair 23 of transducers, an ultrasonic transmitter transducer and receiver 24 transducer, and the transducer pair is mounted to the same arm.
An encoder means is used to monitor the angular rotation of the 26 arms about the tool axis. A caliper detection means determines 27 the radial extension of the plurality of arms from the tool 28 housing. Flow velocities and fluid parameters can be determined 29 in highly deviated and even horizontal wells.

_ 7 _ 3 The novel features believed characteristic of the invention 4 are set forth in the appended claims. The invention itself however, as well as a preferred mode of use, further objects and 6 advantages thereof, will best be understood by reference to the 7 following detailed description of an illustrative embodiment when 8 read in conjunction with the accompanying drawings, wherein:

Figure 1 is a perspective view of a production logging tool 11 string which includes the fluid holdup tool o~ the present 12 invention;

14 Figure 2 is a cross-sectional view of a casing within a deviated well within which the fluid holdup tool of the present 16 invention is being operated to measure relative volumes for flow 17 constituents of production fluids flowing in a multiphase fluid 18 flow passing within the casing;
19 ' Figures 3a - 3c together comprise a cross-sectional view 21 depicting an upper section of the fluid holdup tool of the 22 present invention;

24 Figures 4a - 4f together comprise a longitudinal section view of a lower section of the fluid holdup tool of the present 26 invention;

28 Figure 5 is a schematic diagram depicting electronic 29 components which are utilized for operating the fluid holdup tool in the preferred embodiment of the present invention;

32 Figure 6 is a side view of an electrical conductivity sensor 33 for use in the fluid holdup tool of the present invention;

Figure 7 is an end view of the electrical conductivity 36 sensor of Figure 6;
Docket No. 0140D-034-CIP

_ g _ 1 Figure 8 is a schematic diagram depicting electronic 2 components used for operating with the electrical conductivity 3 sensor of Figures 6 and 7;

Figure 9 is a side view of a thermal conductivity sensor for 6 use in the present invention;

8 Figure 10 is a schematic diagram depicting electrical 9 components for operating the thermal conductivity sensor of Figure 9;

12 Figure 11 is a side view depicting an acoustic piezoelectric 13 sensor for use in the present invention;

Figure 12 is a schematic diagram depicting electronic 16 components for operating the acoustic sensor of Figure 11;

18 Figure 13 is a graph which depicts the electrical response 19 characteristics of the acoustic sensor of Figure 11 when immersed in gas;

22 Figure 14 is a graph which depicts the electrical response 23 characteristics of the acoustic sensor of Figure 11 when immersed 24 in water;
26 Figure 15 is a diagram of the lower end of a Doppler flow 27 sensor of a flow meter of the present invention, as would be 28 viewed looking uphole from beneath the Doppler flow sensor;

Figure 16 is a schematic diagram depicting an electronics 31 circuit for use with the Doppler flow sensor of Figure 15; and 33 Figure 17 is a transverse cross-section of a well within 34 which a flow meter of the present invention is being operated, and depicts a plurality of measurement points for measuring of _ g _ 1 flow velocities of a multiphase fluid flow within several localized regions of the cross-section of the well.

~1 DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT

3 With reference to Figure 1, a perspective view depicts 4 production logging tool string 11 for use to analyze a multiphase fluid f low within a well . Tool string 11 includes cable head 13 , 6 telemetry section 15, density tool 19, deflector flowmeter 21 and 7 full bore flowmeter 23. Bow spring centralizers 25 are included 8 along tool string 11 for centering tool string 11 within a well.
9 Included within production logging tool string il of the present invention is production logging tool 17, which includes upper 11 section 27 and lower section 29. Three caliper arms 31 radially 12 extend from lower section 29 of production logging tool 17 of the 13 present invention.

Referring now to Figure 2, a sectional view depicts 16 production logging tool 17 within a well. Arms 31 radially 17 extend from tool 17 and include sensors 33. Production logging 18 tool 17 is shown within casing 35, which is depicted herein for 19 a deviated well, such as a horizontal well. Production fluids flowing within casing 35 include brine 37, oil emulsions 39 and 21 gas 41. Arms 31 and sensors 33 are rotated in the direction of 22 arrow 43 between stationary measurement positions for detecting 23 flow velocities of constituents 39, 41 and 37. Production 24 logging tool 17 is preferably of a slim design which has an outside diameter of 1 11/16 inches, with arms 31 retracted, so 26 that tool 17 will not substantially disturb the flow of 27 production fluids 37, 39 and 41.

29 With references to Figure 3a - 3c, a longitudinal section view depicts upper section 27 of tool 17. Upper section 27 31 includes upper pressure housing 45. Connector 47 extends from 32 the upper end of housing 45 for securing tool 17 within a tool 33 string, such as tool string 11 shown in Figure 1. Electronics 34 section 49 is disposed within the top of upper pressure housing 45. Rotation motor 51 is secured within housing 45 by motor 36 bracket means 53. Output shaft 55 extends from motor 51 to - 21$4g~~
_ - 11 -1 provide a rotation means. Rotary encoder section 61 extends 2 below rotation motor 51 to provide a means for detecting rotation 3 of shaft 63. Shaft 63 is secured to output shaft 55 by shaft 4 coupling 65. Bearings 67 and 69 support shaft 63 within housing 45. Floating nut 71 is secured to shaft 63 between limit 6 switches 73 and 75. Encoder wheel 77 is secured to shaft 63 for 7 rotating therewith between L.E.D. 79 and photodiode 81. Encoder 8 wheel 77 includes slots, or holes, so that L.E.D. 79 will pass 9 light through the slots in encoder wheel 77 and to photodiode 81 l0 as encoder wheel 77 rotates. Photodiode 81 emits electric pulses 11 in response to receiving light pulses from L.E.D.~ 79 which pass 12 through the slots of encoder wheel 77. The electric pulses from 13 photodiode 81 correspond to angular rotation of shaft 63, which 14 corresponds to rotation of lower section 29 of production logging tool 17.

17 Shaft 83 is coupled to shaft 63 by shaft coupling 85. Shaft 18 83 includes wireway 87 which extends therein for passing wiring 19 between upper section 27 and lower section 29 of logging tool 17.
Shaft 83 is rotatably supported within bearing section 89 of 21 housing 45 by bearings 91 and bearings 93. Lock nut 95 22 threadingly engages an interior of bearing section 89 for 23 retaining bearings 91 and shaft 83 within bearing section 89.
24 Seals 97 seal between shaft 83 and bearing section 89, and shaft 83 and housing coupling 99. Housing coupling 99 is threadingly 26 secured to the lower end of shaft 83 for rotating therewith 27 relative to bearing section 89 of upper housing 45. It should 28 be noted that upper housing 45 is typically held in place by.
29 centralizers within the upper portions of a production logging string as housing coupling 99 and lower section 29 are rotated 31 within a well by rotation motor 51. The lower end of housing 32 coupling 99 is threaded and has a seal surface for securing to 33 a lower section 29 of logging tool 17.

Referring now to Figures 4a - 4f, a longitudinal section 36 view depicts lower section 29 of production logging tool 17, with Docket No. 0140D-034-CIP

~184~~u 1 bull nose 117 secured to the lower end of lower section 29.
2 Lower section 29 includes lower pressure housing 101. Connector 3 103 is secured in the upper end of housing 101 for connecting 4 lower section 29 to upper section 27. Lower pressure housing 101 includes pressure sleeve 105, centralizes sleeve 107, pressure 6 sleeve 109, pressure coupling 111, about which is secured 7 centralizes sleeve 113 and slotted sleeve 115. Bull nose 117 is 8 depicted as secured in the lower end of production logging tool 9 17 rather than density tool 19 for illustrative purposes in order to depict how tool 17 appears when not run above other components il in a production logging tool string. In other embodiments of the 12 present invention, a tool connection may be provided rather than 13 bull nose 117 for connecting other tools to the lower end of 14 production logging tool 17, such as shown in tool string 11 of Figure 1. Centralizes sleeves 107 and 113 rotatably support one 16 of centralizers 29 about lower pressure housing 101 so that 17 housing 101 may rotate therein as centralizes 29 is held 18 stationary within a well.

The upper end of housing 101 has electronics section 121 21 disposed therein. Motor bracket means 123 secures caliper motor 22 125 within housing 101. Output shaft 125, together with caliper 23 motor 125, provides a caliper extension and retraction means.
24 Shaft 131 is coupled to output shaft 127 by coupling 129.
Bearing 133 supports shaft 131 within housing 101. Worm gear 135 26 is secured to the lower end of shaft 131 for moving therewith.
27 Ball nut assembly 136 includes balls 137, bracket 138 and nut 140 28 for moving linearly, in a longitudinal direction within housing.
29 101, as worm gear 135 is rotated by caliper motor 125.
31 Linear variable differential transformer (LVDT) 141 has core 32 142 and provides a means for determining the amount by which 33 caliper arms 31 are' extended during operation of production 34 logging tool 17. Shoulders 143 and 145 are provided to secure limit switches within housing 101 to limit opening and closing 36 of caliper arms 31. Bias spring 147 extends between coupling 151 Docket No. 0140D-034-CIP

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1 and retaining bracket 145 for biasing coupling 151 towards the 2 lower end of lower pressure housing 101. Bias spring 147 may be 3 compressed when caliper arms 31 encounter a restriction within 4 a well. Lugs 153 extend from coupling 151 within slots 155 and sleeve 157. Lugs 153 within slots 155 provide a means for 6 preventing rotation of coupling 151 within lower pressure housing 7 101.

9 Tube 159 is secured to the lower end of coupling 151. Tube 159 has wireway 160 extending therein for passing wiring through 11 the lower most end of lower pressure housing 101 and downward to 12 other tools which may be connected beneath production logging 13 tool 17 in a production logging tool string such as tool string 14 il shown in Figure 1. Seals 161 seal between pressure coupling 111 and tubing 159. Bearings 163 and 165 support tube 159 within 16 slotted sleeve 115 for linear movement relative to housing 101 17 along a longitudinal axis of housing 101. Seal 167 seals between 18 bull nose 117 and tube 159. As mentioned above, bull nose 117 19 may be replaced with a connector having a 'profile such as the lower end of housing coupling 99 for securing to a connector for 21 a production logging tool run beneath tool 17, such as connector 22 103 shown in Figure 4a.

24 Tube 181~extends from pressure coupling 111 and is secured to one of caliper arms 31. Tube 181 has wireway 183 extending 26 therein for passing conductor wires to one of sensors 33 (shown 27 in Figure 2). Member 185 extends between tube 159 and arm 31.
28 Arm 31 is movably connected to slotted sleeve 115 at pivot point.
29 187. Member 185 is movably connected to arm 31 at pivot point 189. Member 185 is movably connected to tube 159 at pivot point 31 191 by coupling 193. Coupling 193 is threadingly secured to tube 32 189. Ring 195 is secured to slotted sleeve 115 and coupling 197 33 is secured to tube 159 with bias spring 199 disposed therebetween 34 for biasing tube 159 to move downward and into cavity 205 of bullnose 117. Sensor sockets 207 are provided in each of arms 36 31 for receipt of sensors 33 (shown in Figure 2).
Docket No. 0140D-034-CIP

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1 ~ It should be noted that tube 159 is machined so that outside 2 diameter 201, shown in Figure 4d, is smaller than outside 3 diameter 203, which is shown in Figure 4f. This provides a 4 larger cross-sectional area at outside diameter 203 than that which cross-sectional area which is defined by outside diameter 6 201. When exposed to well fluids, the pressure within cavity 205 7 of bullnose 117 is atmospheric, and the pressure within pressure 8 sleeve 109 is also atmospheric. The difference between cross-9 sectional areas defined by outside diameter 201 and outside diameter 203 results in a net downward force being applied to 11 tube 159 when exposed to downhole well pressures.. For example, 12 in the preferred embodiment of the present invention, outside 13 diameter 201 is ten thousandths (.010) inches smaller than 14 outside diameter 203, which results in 80 pounds downward force at a downhole operating pressure of 20,000 pounds. Thus, the 16 difference between outside diameters 201 and 203 provides a 17 biasing means in addition to bias spring 199. This downward 18 pressure results in a much smoother operating linkage over a full 19 range of downhole pressure, which does not j erk and thus provides a much more easily moved apparatus. Further, since less force 21 is required to urge tube 159 downwards, much smaller springs such 22 a bias spring 199, shown in Figure 4f, and bias spring 147, shown 23 in Figure 4c, may be utilized in the well logging tool of the 24 present invention. It should also be noted that bias spring 149 provides a means by which caliper arms 31 can press against to 26 collapse if a restriction is encountered within a well.

28 With reference to Figure 5, a schematic diagram depicts 29 electronics 221 utilized for operating production logging~tool 17 of the present invention. Electronics 221 includes 31 rotation/encoder section 223 and caliper/sensor section 225.
32 Through wire 227 is shown extending within electronics 221.
33 Production logging tool 17 may be operated on a monocable for use 34 in wells having high surface pressures, such as those often found on producing wells. It should be noted that through wire 227 Docket No. 0140D-034-CIP

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1 extends through production logging tool 17 for operating other 2 downhole logging tools beneath tool 17.

4 Rotation/encoder section 223 includes motor driver board 229 and rotation motor windings 231. Rotation motor windings 231 are 6 included within rotation motor 51 (shown in Figure 3a).
7 Optoelectronic sensor boards 233 and optoelectronic logic board 8 235 are provided for operating encoder wheels 77, L.E.D. 79, and 9 photodiode 81 (shown in Figure 3b). As discussed above, the l0 optoelectronics encoder of the present invention dgtects angular 11 rotation of arms 33 of production logging tool 17 (shown in 12 Figure 2). Angular position of tool 17 within a well is utilized 13 in combination with sensor readings for determining the relative 14 volumetric proportions of f luid f low constituents f lowing within the well. Communications board 237 is provided for coupling 16 motor driver board 265 and optoelectronic logic board 235 to 17 through wire 227 for emitting and receiving data signals.

19 Caliper/sensor section 225 includes motor driver board 241 which is coupled to through wire 227 for receiving power from an 21 uphole power supply. Motor driver board 241 controls power 22 applied to caliper motor windings 243, which are included within 23 caliper motor 125 (shown in Figure 4b). Linear variable 24 differential transformer (LVDT) board 245 is coupled to LVDT
components 247, which are included within LVDT assembly 141 26 (shown in Figure 4c). Resistive thermonic device (RTD) sensor 27 249 is provided to detect the temperature of LVDT components Z47 28 for applying temperature corrections to LVDT readings.-29 Temperature measurement board 251 is. provided for operating RTD
sensor 249. Communications boards 253 and 255 are provided for 31 passing data signals between motor driver board 241, LVDT board 32 245, and uphole data processing unit 267.

34 Fluid sensor board 257 is provided for operating sensor transducers 33. Communications board 261 and 263 are connected 36 to fluid sensor board 257 for passing data signals between sensor Docket No. 0140D-034-CIP

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1 board 257 and uphole data processing unit 267. In the preferred 2 embodiment of the present invention, ground 265 is provided by 3 tool housings 45 and 101 shown in Figures 3a - 4f.

It should be noted that in the present invention, several 6 types of sensors may be used within production logging tool 17 7 for detecting fluid flow parameters of fluid f low constituents 8 of multiphase fluid flows. For example, sensors 33 may comprise 9 either electrical conductivity sensors, thermal conductivity to sensors, or an acoustic type of sensor, such as a Doppler flow 11 sensor or an acoustic attenuation type of f low sensor . There are -12 also other types of sensors which may be utilized in logging tool 13 17. Several types of sensors are disclosed herein and discussed 14 below to illustrate examples of different types of transducers which may be utilized for sensors 33.

17 Referring now to Figure 6 a side view depicts electrical 18 conductivity sensor 271 for use as one of sensors 33 of the 19 present invention. Sensor 271 includes conductive body 273 from which sensor pin 275 extends with an insulator material 277 21 extending therebetween (shown in Figure 7). O-ring seal grooves 22 279 are provided within body 273. Roller bearing surface 281 is 23 provided for receipt within roller bearing 282 (shown in Figure 24 4f) for allowing body 273 to rotate within roller bearing 282 (shown in Figure 4f). Snap ring retainer groove 283 is provided 26 to retain body 273 within one of sockets 287. End face 285 of 27 conductive body 273 provides a ground for current to return from 28 sensor pin 275.

With reference to Figure 7, an end view depicts the end of 31 electrical conductivity sensor 271 as viewed from section 7-7 of 32 Figure 6. As shown therein, electrical conductivity sensor 271 33 includes end face 285 within which are concentrically disposed 34 sensor pin 275 and insulator material 277. Insulator material 277 provides an insulation barrier between conductive body 273 36 and sensor pin 275. End face 285 provides a current ground for Docket No. 0140D-034-CIP

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_ - 17 -1 current to pass from sensor pin 275, through the well bore fluid 2 between sensor pin 275 and end face 285, and into end face 285.

4 Referring now to Figure 8, a schematic diagram depicts sensor circuit 287 which is included within sensor board 257 6 (shown in Figure 5) for operating three of electrical 7 conductivity sensors 271. Power source 289 provides a 2 kHz 8 power supply which provides voltage to impedances 291, sensors 9 271 and amplifier means 293. The amount of current passed through electrical conductivity sensors 271 determines the 11 voltages applied to amplifier means 293. Amplifier means 293 12 each emit an output signal which varies in response to the 13 conductivity of fluid components at sensors 271, and which are 14 passed to multiplexer 295. Control signals applied to sensor select inputs 297 select between the output signals from the 16 three different amplifier means 293 which are passed through to 17 sensor circuit output 299. Communications boards 261 and 263 are 18 utilized to couple sensor circuit output 299 to throughwire 227 19 for passing data signals uphole to data processing unit 267 (shown in Figure 5).

22 With reference to Figure 9, a partial view depicts thermal 23 conductivity sensor 301, three of which may be utilized for 24 providing three sensors 33 in the present invention. Thermal conductivity sensor 301 includes RTD sensor 303, which in this 26 embodiment of the present invention is formed from platinum.~It 27 should be noted that conductive body 273 is used for housing RTD
28 sensor 303, as is discussed above for electrical conductivity.
29 sensor 271.
31 Referring now to Figure l0, a schematic diagram depicts 32 sensor circuit 305 for use within fluid sensor board 257 (shown 33 in Figure 5) . It should be noted that as depicted herein, sensor 34 circuit 305 is for use to operate only one of sensors 301.
Sensor circuit 305 includes power source 307 and switch 309.
36 Switch 309 is selectively operated to pass. current through to RTD
Docket No. 0140D-034-CIP

_ ~1$:~~'~' _ lg _ 1 sensor 303 for heating RDT sensor 303 to a temperature which is 2 above the temperature of downhole well fluids within which RDT
3 sensor 303 is immersed. Measurement circuitry 303 is provided 4 to selectively open switch 309 and then detect the temperature decay of RDT sensor 303 after power source 307 is disconnected 6 therefrom. Sensor circuit output 313 corresponds to the decay 7 rate of the temperature of RDT sensor 303. Measurement circuitry 8 311 measures the electrical resistance of RDT sensor 303, which 9 varies in response to temperature. The decay rate of the temperature of thermal conductivity sensor 301 is utilized to 11 determine the thermal conductivity of fluids within which RTD
12 sensor 303 is emerged.

14 With reference to Figure 11, a partial view depicts acoustic sensor 321, which may be utilized to provide sensors 33 of an 16 alternative embodiment of the present invention. Acoustic sensor-17 321 includes conductive body 273. Piezoelectric element 323 18 extends from body 321 for passing acoustic energy to well fluids 19 within which piezoelectric element 323 is immersed.
Piezoelectric element 323 of this embodiment of the present 21 invention is sized so that it is adapted for use to emit acoustic 22 energy at a frequency of approximately 500 kHz.

24 Referring now to Figure 12, a schematic diagram depicts sensor circuit 325 for use within fluid sensor board 257 (shown 26 in Figure 5), for operating one of acoustic sensors 321. It 27 should be noted that if three of acoustic sensors 321 are 28 utilized in a production logging tool 17 of the present-29 invention, three of sensor circuits 325 will be required. Sensor circuit 325 includes power source 327 for operating piezoelectric 31 element 323 at a frequency of approximately 500 kHz. Firing 32 signal gate 329 is provided by a field effect transistor for 33 selectively applying power from power source 327 to element 323.
34 One terminal end of piezoelectric element 323 is connected to ground, and the other is connected to amplifier means 335 with 36 diodes 331 and 333 bridging therebetween.as shown. The output Docket No. 0140D-034-CIP

1 from amplifier means 335 passes to rectifier and integrator means 2 337 which emits a data signal on sensor circuit output 339 in 3 response thereto.

Sensor circuit 325 operates to selectively pass a pulse of 6 electrical energy through firing signal gate 279 and to 7 piezoelectric element 323. A sharp pulse of electrical energy 8 applied to piezoelectric element 323 causes resonance frequency 9 vibrations within element 323. As discussed above, piezoelectric element 323 in this embodiment of the present invention is sized 11 so that an acoustic signal of approximately 500 kHz is emitted.
12 The rate of decay of the acoustic signal emitted from 13 piezoelectric element 323 will vary depending on the well fluid 14 within which element 323 is immersed. The resonance vibrations within piezoelectric element 323 cause a voltage to be applied 16 to amplifier means 335, which emits an output signal in response 17 thereto for passing to rectifier integrator means 337, which in 18 turn emits a data signal to sensor circuit output 339.

With reference to Figures 13 and 14, graphs of voltage 21 versus time depict operational characteristics of acoustic sensor 22 321 of Figures 11 and 12. Curve 341 of Figure 13 is a plot of 23 the output voltage from piezoelectric element 323 which occurs 24 in response to dampening of the resonance vibrations. In particular, curve 341 depicts the output voltage of element 323 26 when immersed in gas.

28 Curve 343 in Figure 14 depicts the output voltage from 29 piezoelectric element 323 when immersed in water. As seen by comparison of curves 341 and 343, water is capable of 31 transmitting much more acoustic energy over a particular period 32 of time than gas, so the resonance frequency vibrations within 33 piezoelectric element 323 are dampened much more quickly when 34 element 323 is immersed in water rather than gas. It should also be noted, that the rate of attenuation from an oil or oil 36 emulsion would be intermediate of that between curve 341 and 343.
Docket No. 0140D-034-CIP

1 Referring to Figure 15, a diagram depicts the lower end of 2 Doppler flow sensor 345 of a flow meter of the present invention, 3 as would be viewed when looking uphole toward the lower end of.
4 flow sensor 345. Doppler flow sensor 345 senses travelling boundary layers between different phases of flow constituents and 6 particular matter moving within a well. Doppler flow sensor 345 7 includes an ultrasonic transmitter transducer 347 and an 8 ultrasonic receiver transducer 349 made of lead zirconate 9 titanate (PZT). Transducers 347 and 349 are preferably provided by cutting a single ceramic disc in half. Transducers 347, 349 11 are then potted in viton rubber pad 354 to mount the transducers 12 in a vibration damping member. A section 351 of viton pad 354 13 extends between transducers 347, 349. The diameter 353 of the 14 disc, and transducers 347 and 349, is approximately one-quarter of an inch in the preferred embodiment. The thickness of 16 transducers 347, 349 are determined by the frequency at which 17 they are to operate. Transducers 347, 349 preferably operate in 18 a thickness mode of vibration, providing larger contact surface 19 area with the fluids adjacent to transducers 347 and 349.
21 The thickness of transducers 34.7 and 349 can be selected for 22 operating over a frequency range of one-hundred (100) kHz to ten 23 (10) MHz, with a frequency of approximately one (1) Mhz being 24 preferred. In most well fluids, a frequency of one (1) Mhz will provide a depth of investigation ranging from approximately one 26 (1) to two (2) inches. At a frequency range of 100 kHz, the 27 depth of investigation will be 1 1/2 feet to 2 feet, which is to 28 large to measure a velocity flow profile within wells of typical.
29 sizes. At a frequency range of 10 MHz, the depth of investigation will be approximately 1/2 inch. A depth of 31 investigation of 1/2 inch or less may have problems which arise 32 from bubbles in the flow becoming trapped on the bottom surface.
33 of sensor 345, and from a trapped boundary layer on the bottom 34 surface of flow sensor 345 being the primary fluid detected. A
frequency of one (1) Mhz is preferred. A 1 Mhz signal has a 36 depth of investigation of approximately one to two inches, Docket No. 0140D-034-CIP

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' - 21 -1 providing a reasonable compromise between increased flow 2 resolution and detecting static fluids which are trapped on the 3 lower end of sensor 345 masking fluid velocity readings. Sensor 4 345 may also be canted from a longitudinal axis within the well to prevent fluids from being trapped on the bottom of sensor 345.

7 With reference to Figure 16, a schematic diagram depicts 8 electronics circuit 355 for use with Doppler flow sensor 345.
9 Transmitter transducer 347 and receiver transducer 349 are schematically depicted within circuit 355. A frequency generator 11 357 preferably generates a 1 Mhz signal, which is connected to 12 transmitter transducer 347, causing transducer 347 to emit an 13 ultrasonic signal of 1 MHz. Ultrasonic return signals are 14 detected at receiver transducer 349, which emits a high frequency data signal at the frequency of the detected return signal.
16 Frequency generator 359 provides a 1 khz signal, which is mixed 17 in mixer 361 with the 1 Mhz signal from frequency generator 357.
18 A mixed data signal of 1001 Khz from mixer 361 passed to mixer 19 363, where it is mixed with the data signal from receiver transducer 349. The output from mixer 363 is then fed into band 21 pass filter 365. Band pass filter 365 includes capacitor 367, 22 resistor 369 and capacitor 371. The signal from band pass filter 23 365 represents the frequency shift of the return signal from the 24 ultrasonic signal transmitted into the well, and is connected to output 373. A f low velocity is calculated based upon the value 26 of the frequency shift.

28 Production logging tool 17 of the present invention may be.
29 used with three of either electrical conductivity sensors 271, thermal conductivity sensor 301, acoustic attenuation sensor 321 31 or Doppler f low sensor 345. Additionally, tool 17 may be used 32 with any combination of the above sensors, including other 33 sensors which are not specifically mentioned herein. This can 34 easily be accomplished by providing different fluid sensor boards 257 (shown in Figure 5) which are tailored for the combination 36 of sensors desired for use within production logging tool 17.
Docket No. 0140D-034-CIP

218~8~
~ - 22 -1 Referring to Figure 17, operation of well logging tool 17 2 utilizing three Doppler flow sensors 345 for measuring flow 3 velocities of a multiphase fluid flow is now described. As 4 discussed above, Doppler flow sensors 345 actually measure travelling boundary layers. The term sensing flow velocities of 6 fluids will be used herein to include measuring moving boundary 7 layers within wells.

9 Figure 17 is a schematic diagram of transverse cross-section 375 of a well through which a multiphase fluid flow is passing.
11 A plurality of stationary measurements points 381 are spaced 12 apart about cross-section 375, and define localized regions 387.
13 Values of fluid flow velocities are measured within the localized 14 regions 387 of cross-section 375. Tool housing 377 is depicted as centered within cross-section 375, with a central, 16 longitudinal tool axis 379 of tool housing 377 extending 17 transverse to cross-section 375. Multiple stationary measurement 18 points 381 are shown as being dispersed uniformly throughout 19 cross-section 375, along radial directions 383 from tool axis 379 and angularly displaced around tool axis 379 in angular 21 directions 385. Fluid flow velocities are sequentially measured 22 within localized regions 387 of cross-section 375, which extend 23 proximately around different ones of corresponding measurement 24 points 381. Localized regions 387 are separately disposed, and may overlap depending on the depth of investigation of Doppler 26 flow sensor 345.

28 Flow velocities are simultaneously measured at three.
29 separate sets of points by the flow sensors 345 on each of the three arms 31, wherein the flow proximate to three of points is 31 measured at one time. The order, or sequence, at which 32 stationary readings are sequentially taken at measurement point 33 381 may be either manually controlled or programmed into uphole 34 data processing unit 267 (depicted in Figure 5), and need not occur as a continuous sequence. Additionally, in other 36 embodiments, measurements may be sequentially taken at points 381 Docket No. 0140D-034-CIP

~18~g5~
' - 23 -1 by continuously moving arms 31, without taking stationary 2 readings. However, the sensors 345 are preferably momentarily 3 stopped in localized regions 387 and stationary readings are 4 taken.
6 Once flow velocities are measured within various regions 7 387, the velocity flow profile of the fluid flow within cross-8 section 375 may be directly determined. Readings for the flow 9 velocities within regions 387 are plotted across cross-section l0 375 according to various angular displacements 385 and radial 11 distances 383 from tool axis 379. Radial distances 383 from and 12 angular displacements 385 around tool axis 379 for each of 13 measurement points 381 may be monitored by either taking actual 14 tool measurements for rotation and extension of arms 31, or by keeping track of the radial distances 383 and angular 16 displacements 383, or positions 381, to which arms 31 of tool 17 17 are selectively moved.

19 Operation of production logging too1,17 of the present invention is now described for determining fluid holdup.
21 Referring now to Figures 3a - 3c, and Figure 4a - 4f, once 22 production logging tool 17 is lowered within a well, caliper 23 motor 125 is operated to rotate worm gear 135 so that tube 159 24 is moved towards the lower end of tool 17. This urges caliper arms 31 to extend radially outward from slotted housing 115.
26 LVDT 141 determines relative movement of coupling 151.
27 Centralizers 29 center production logging tool 17 within the 28 well, and prevent upper pressure housing 45 from rotating within.
29 the well.
31 Rotator motor 51 then rotates shaft 83 which is coupled to 32 housing coupling 99 for rotation therewith. Housing coupling 99 33 is coupled to the lower pressure housing 101 to urge pressure 34 housing 101 to rotate within centralizes 209. Referring to Figure 2, this urges arms 131 to rotate within well fluids 37, 36 39, and 41, which moves sensors 33 therein. Referring to Figure Docket No. 0140D-034-CIP

1 3b, rotary encoder section 61 detects angular rotation of shaft 2 83, and thus arms 36, with respect to upper pressure housing 45.
3 Upper pressure housing 45 is held in place within the well by 4 centralizers 29, which are depicted in Figure 1. It should be noted that in the preferred method of operation stationary 6 readings are taken. However, production logging tool 17 may be 7 utilized to provide a well log while being moved within a well.
8 If stationary readings are not taken, but rather the f luid holdup 9 tool is being moved within a well on a wireline, it would be advantageous for well log analysis to include a device to detect 11 the angular position of tool 17 with respect to either the high 12 or low side of the hole, or a gyroscope type device for detecting 13 total angular movement of upper section 27 of fluid holdup tool 14 17 for processing data.

17 With reference to Figure 5, electronics section 221 controls 18 downhole operation of production logging tool 17. Commands from 19 uphole data processing unit 267 are passed downhole via throughwire 227 to communication board 253 for controlling 21 operation of caliper motor 125. Communicat»n board 253 is 22 connected to motor driver board 241 for determining when arms 31 23 are extended radially outward or retracted radially inward. It 24 should be noted that when arms 31 are extended radially outward, they still may be pressed inward when restrictions are 26 encountered as discussed above. LVDT 141 detects the extent of 27 radial extension of arms 31. RTD 249 detects the temperature 28 within LVDT 141. Communication board 253 emits a data signal.
29 through wire 227 and to uphole data processor 267 in response to output signals from LVDT board 245. Sensor board 257 is coupled 31 to throughwire 227 for providing power for operating both sensor 32 board 257, and sensors 33. Sensor board 257 emits a data signal 33 through wire 227 to uphole data processor 267 in response to 34 output signals from sensor 33 and temperature board 251, which detects the temperature within LVDT 141. Operation of three 36 particular sensors which may be utilized for sensors 33 in this Docket No. 0140D-034-CIP

1 preferred embodiment of the present invention are discussed above 2 in reference to Figures 6 - 14.

4 Communication board 237 is connected to throughwire 227 for receiving command signals from data processor 267. Communication 6 board 237 emits control signals to motor driver board 265 to 7 control the power applied to windings 231 for controlling 8 operation of rotation motor 51 in response thereto.
9 Optoelectronic logic board 235 and optoelectronic sensor board 233 provides power to LED 79 and photodiode 81 for controlling 11 operation thereof (shown in Figures 3a and 3b). Rotation of 12 encoder wheel 77 passes slots in wheel 77 between LED 79 and 13 photodiode 81 which causes light to be pulsed to photodiode ei.
14 Photodiode 81 emits electrical pulses in response to the light pulses emitted by LED 79. 'The electric pulses from photodiode 16 81 are detected by optoelectronic sensor board 233.
17 Optoelectronic sensor board 233 and optoelectronic logic board 18 235 are coupled to communication board 237, which emits a data 19 signal which corresponds to the angular 'rotation of encoder wheel 77. The data signal from communication board 237 is 21 coupled to throughwire 227 for passing uphole to data processing 22 unit 267.

24 Data processing unit 267 is then utilized for processing the different output signals passed uphole from communication boards 26 237, 261 and 253 to determine volumetric proportions of flow 27 constituents within a fluid flow stream as sensors 33 are rotated 28 within the f low stream. Data from production logging tool 17 i.s-29 analyzed along with data from density tool 19, deflector flowmeter 21, and fullbore flowmeter 23 for determining the 31 different flow rates of fluid flow constituents within a well 32 when production logging tool 17 is utilized in combination with 33 a full assembly of production logging tools in a producing well.
34 It should also be noted that tool 17 may be run without other types of production logging tools.

Docket No. 0140D-034-CIP

218~185G

1 Referring again to Figure 2, it should be noted that as 2 sensors 33 are rotated within a flowstream such as that shown 3 therein, each sensor will emit a periodic signal when passing 4 between brine 37, oil 39 and gas 41. Thus, unlike prior art devices, production logging tool 17 of the preferred embodiment 6 of the present invention may be utilized within deviated or even 7 horizontal wells for detecting the volumetric proportions of the 8 different flow constituents such as brine 37, oil 39, and gas 41.
9 It should also be noted that production logging tool 17 of the present invention may also be utilized for analyzing segregated 11 and segmented fluid flow in other applications such as vertical, 12 or for non-deviated wells, or detecting flow through surface 13 pipes. Further, logging readings may be recorded without 14 operating rotation motor 151.
16 After logging readings are recorded, and caliper motor 125 17 may be operated to retract arms 131 radially inward for removal 18 of tool string 11 from the well.

The present invention offers several advantages over prior 21 art production logging tools. Sensors are secured within caliper 22 arms which extend radially outward from a tool housing to points 23 which are spaced apart from a tool housing to detect flow 24 velocities and volumetric proportions of f luid f low constituents .
Thus, fluid holdup may be determined and actual fluid flow 26 velocities may be measured without relying upon data acquired 27 from only a central portion of the well. Additionally, sensors 28 are rotated about a longitudinal axis of the flowpath through a~
29 well for passing around the edge exterior of a cross-sectional area of the flow for much more accurately determining flow 31 parameters. This allows actual flows within boundary layers at 32 the outer periphery of the well to be measured. Since fluid flow 33 sensors are rotated about a longitudinal axis of the well, the 34 production logging tool of the present invention may be used in deviated, and even horizontal wells, since they will each pass 36 through the different flow constituents rather than just Docket No. 0140D-034-CIP

_ -_-___. --'Z1~~~~

1 detecting the flow components within a particular portion of a 2 cross-sectional area of the well . Actual f low velocities of f low 3 profiles for multiphase fluid flow may be directly measured.

Although the invention has been described with reference to 6 specific embodiments, this description is not meant to be 7 construed in a limiting sense. Various modifications of the 8 disclosed embodiments as well as other alternative embodiments 9 of the invention will become apparent to persons skilled in the art upon reference to the description of the invention. It is 11 therefore contemplated that the appended claims will cover any 12 such modifications or embodiments that fall within the true scope 13 of the invention.
Docket No. 0140D-034-CIP

Claims (20)

1. A production logging tool for use to determine flow velocities of a multiphase fluid flow through a cross-section of a well, said production logging tool comprising:
a tool housing having a tool axis which extends longitudinally through said tool housing;
an arm extensibly and rotatably mounted to said tool housing;
a flow sensor mounted to said arm and having a depth of investigation for measuring flow velocities of said multiphase fluid flow within localized regions of a cross-section of said well which are proximate to said flow sensor;
means for rotating said arm to pass said flow sensor through a satellite path about said tool axis at different radial distances from and different angular displacements about said tool axis for moving said flow sensor between separate ones of said localized regions of said cross-section;
actuator means for selectively controlling said radial distance between said flow sensor and said tool housing;
means for monitoring said radial distances from and said angular displacements about said tool axis of said flow sensor;
and wherein said flow sensor measures said f low velocities within said separate ones of said localized regions of said cross-section for determining said flow velocities of a velocity profile of said multiphase fluid flow through said cross-section of said well.

2. The production logging tool of claim 1, wherein said localized regions are separately dispersed throughout said cross-section of said well.

3. The production logging tool of claim 1, wherein said flow sensor is fixedly mounted to said arm, proximate to a radially outermost end of said arm.

4. A production logging tool for use to determine flow velocities of a multiphase fluid flow through a cross-section of a well, said production logging tool comprising:
a tool housing having a tool axis which extends longitudinally through said tool housing;
an arm extensibly and rotatably mounted to said tool housing;
a flow sensor mounted to said arm and having a depth of investigation for measuring flow velocities of said multiphase fluid flow within localized regions of a cross-section of said well which are proximate to said flow sensor;
said flow sensor comprising an ultrasonic Doppler flow sensing means;
means for rotating said arm to pass said flow sensor through a satellite path about said tool axis at different radial distances from and different angular displacements about said tool axis for moving said flow sensor between separate ones of said localized regions of said cross-section;
actuator means for selectively controlling said radial distance between said flow sensor and said tool housing;
means for monitoring said radial distances from and said angular displacements about said tool axis of said flow sensor;
and wherein said flow sensor measures said flow velocities within said separate ones of said localized regions of said cross-section for determining said flow velocities of a velocity profile of said multiphase fluid flow through said cross-section of said well.

5. The production logging tool of claim 4, wherein said flow sensor comprises an ultrasonic Doppler flow sensing means operates at a frequency between 100 kHz and 10 MHz.

6. The production logging tool of claim 4, wherein said ultrasonic Doppler flow sensing means further comprises an ultrasonic transducer pair which includes:
a transmitter transducer for emitting ultrasonic signals of a first frequency into said multiphase fluid flow at said separate ones of said localized regions of said cross-section;
a receiver transducer for receiving ultrasonic return signals of a second frequency which is frequency shifted from said first frequency by an amount proportional to the component of said fluid flow velocities along said tool axis, reflected and back-scattered from said multiphase fluid flow at said separate ones of said localized regions in response to said ultrasonic signals being emitted into said separate ones of said localized regions; and wherein said ultrasonic returns of said second frequency are processed to determine said flow velocities within said separate ones of said localized regions.

7. The production logging tool of claim 4, wherein said ultrasonic Doppler flow sensing means further comprises an ultrasonic transducer pair which includes:

a transmitter transducer for emitting ultrasonic signals of a first frequency of approximately one MHz into said multiphase fluid flow at said separate ones of said localized regions of said cross-section;
a receiver transducer for receiving ultrasonic return signals of a second frequency, which is frequency shifted from said first frequency of approximately one MHz by an amount proportional to the component of said fluid flow velocities along said tool axis, reflected and back-scattered from said multiphase fluid flow at said separate ones of said localized regions in response to said ultrasonic signals being emitted into said separate ones of said localized regions; and wherein said ultrasonic returns of said second frequency are processed to determine a value for an amount which the second frequency is shifted from one MHz from which said flow velocities within said separate ones of said localized regions are determined.

8. The logging tool of claim 1, wherein said depth of investigation of said flow sensor is within a range of approximately one to two inches.

9. A production logging tool for use to determine flow velocities of a multiphase fluid flow within a cross-section of a well, said production logging tool comprising:
a tool housing having a tool axis which extends longitudinally through said tool housing;
a plurality of arms extensibly mounted to said tool housing, said arms being radially extendable from said tool housing for moving radially outward from said tool axis;
a Doppler flow sensor mounted to at least one of said arms for moving with said one of said arms to position said at least one Doppler flow sensor at points which are disposed at different radial distances from said tool axis of said tool housing for measuring said flow velocities of said multiphase fluid flow within localized regions of said cross-section which are proximate to said at least one Doppler flow sensor;
means for rotating said arms to pass said at least one Doppler flow sensor through a satellite path about said tool axis at different radial distances from and different angular displacements about said tool axis for moving said at least one Doppler flow sensor between separate ones of said localized regions of said cross-section;
actuator means for selectively controlling said radial distance between said at least one Doppler flow sensor and said tool housing;
means for monitoring said radial distances of said at least one Doppler flow sensor from said tool axis;
wherein said at least one Doppler flow sensor is moved to different ones of said radial distances from said tool axis and disposed within said localized regions of said cross-section for measuring said flow velocities of said multiphase fluid flow within said localized regions of said cross-section of said well.

10. The production logging tool of claim 9, further comprising:
said plurality of arms being rotatably mounted to said tool housing for rotating around said tool axis;
two fluid flow parameter sensors for measuring fluid flow parameters, the fluid flow parameters being at least one of density, thermal conductivity and temperature mounted to separate ones of said arms, which are different ones of said arms than said arm to which said Doppler flow sensor is mounted;
means for sequentially moving said plurality of arms around said tool axis to angularly displace said Doppler flow sensor and said fluid flow parameter sensors around said tool axis into said localized regions of said cross-section;
means for monitoring angular displacements of said Doppler flow sensor and said fluid flow parameter sensors around said tool axis; and wherein said at least one Doppler flow sensor and said fluid flow parameter sensors are angularly displaced around said tool axis for sequentially measuring said flow velocities and said flow parameters within said localized regions of said cross-section of said well.

11. The production logging tool of claim 9, wherein said at least one Doppler flow sensor is fixedly mounted to said one of said arms, proximate to a radially outermost end of said one of said arms.

12. The production logging tool of claim 9, wherein said at least one Doppler flow sensor comprises an ultrasonic transducer pair which includes:
a transmitter transducer for emitting ultrasonic signals of a first frequency into said multiphase fluid flow at said localized regions of said cross-section;
a receiver transducer for receiving ultrasonic return signals of a second frequency which is frequency shifted from said first frequency by an amount proportional to the component of said fluid flow velocities along said tool axis, reflected and back-scattered from said multiphase fluid flow in response to said ultrasonic signals being emitted into said localized regions; and wherein said ultrasonic returns of said second frequency are processed to determine said flow velocities within said localized regions.

13. The production logging tool of claim 9, wherein said depth of investigation of said at least one Doppler flow sensor is approximately within a range of from one inch to two inches.

14. The production logging tool of claim 9, further comprising:
said plurality of arms being rotatably mounted to said tool housing for rotating around said tool axis;
means for moving said plurality of arms around said tool axis to angularly displace said at least one Doppler flow sensor around said tool axis;
means for monitoring angular displacements of said at least one Doppler flow sensor around said tool axis;
wherein said at least one Doppler flow sensor comprises an ultrasonic transmitter transducer and receiver transducer pair for emitting ultrasonic signals of a first frequency into said multiphase fluid flow at said localized regions of said cross-section and receiving ultrasonic return signals of a second frequency which is frequency shifted from said first frequency by an amount proportional to the component of said fluid flow velocities along said tool axis, reflected and back-scattered from said multiphase fluid flow in response to said ultrasonic signals being emitted into said localized regions;

said transmitter transducer and receiver transducers pair being fixedly mounted to a radially outermost end of said one of said arms; and wherein said ultrasonic returns of said second frequency are processed to determine said flow velocities of said multiphase fluid flow at said localized regions.

15. A method for using a production logging tool to determine flow velocities of a multiphase fluid flow through a cross-section of a well, said method comprising the steps of:
providing a production logging tool having a tool axis, which longitudinally extends within said production logging tool, and at least one flow sensor for measuring flow velocities of a multiphase fluid flow at localized regions of a cross-section of said well, said localized regions being dispersed within said cross-section at different radial distances from and different angular displacements about said tool axis;
disposing said production logging tool within said well, with said tool axis extending transversely through said cross-section;
physically moving the flow sensor relative to the axis about a plurality of points within a multitude of regions in the multiphase fluid flow passing through the cross-section of such well by rotating the flow sensor relative to the tool axis and extending the flow sensor at different radial distances from the tool axis;
measuring said flow velocities of said multiphase fluid flow at said localized regions of said cross-section;
monitoring said radial distances from and said angular displacements about said tool axis at which said flow velocities are measured within said localized regions; and then, plotting said flow velocities at corresponding ones of said radial distances from and said angular displacements about said tool axis to provide a flow velocity profile of said multiphase fluid flow through said cross-section of said well.

16. The method of claim 15, wherein said localized regions are dispersed throughout said cross-section of said well.

17. The method of claim 15, further comprising:
providing said production logging tool with an arm which is radially extensible away from said tool axis, and said at least one flow sensor being mounted to said arm;
radially extending said arm to dispose said at least one flow sensor at different ones of said radial distances from said tool axis; and wherein at least a portion of said flow velocities are measured by said at least one flow sensor when disposed at said different ones of said radial distances.

18. The method of claim 15, further comprising:
providing said production logging tool with an arm which is radially extensible away from and rotatable about said tool axis, and said at least one flow sensor being mounted to said arm;
radially extending said arm to dispose said at least one flow sensor at different ones of said radial distances from said tool axis;
rotating said arm to dispose said at least one flow sensor at different ones of said angular displacements about said tool axis; and wherein at least a portion of said flow velocities are measured by said at least one flow sensor when disposed at said different ones of said radial distances and different ones of said angular displacements.

19. A method for using a production logging tool to determine flow velocities of a multiphase fluid flow through a cross-section of a well, said method comprising the steps of:
providing a production logging tool having a tool axis, which longitudinally extends within said production logging tool, and at least one flow sensor for measuring flow velocities of a multiphase fluid flow at localized regions of a cross-section of said well, said localized regions being dispersed within said cross-section at different radial distances from and different angular displacements about said tool axis;
disposing said production logging tool within said well, with said tool axis extending transversely through said cross-section;
physically moving the flow sensor relative to the axis about a plurality of points within a multitude of regions in the multiphase fluid flow passing through the cross-section of such well by rotating the flow sensor relative to the tool axis and extending the flow sensor at different radial distances from the tool axis;
providing an ultrasonic transmitter transducer and receiver transducer pair for said flow sensor;
measuring said flow velocities of said multiphase fluid flow at said localized regions of said cross-section by emitting ultrasonic signals of a first frequency from said transmitter transducer into said multiphase fluid flow at said localized regions of said cross-section of said well;

receiving ultrasonic return signals of a second frequency with said receiver transducer which is frequency shifted from said first frequency by an amount proportional to the component of said fluid flow velocities along said tool axis, reflected or back-scattered in response to said ultrasonic signals being emitted into said multiphase fluid flow at said localized regions;
processing said ultrasonic returns of said second frequency to determine flow velocities of said multiphase fluid flow at said localized regions;
monitoring said radial distances from and said angular displacements about said tool axis at which said flow velocities are measured within said localized regions; and then, plotting said flow velocities at corresponding ones of said radial distances from and said angular displacements about said tool axis to provide a flow velocity profile of said multiphase fluid flow through said cross-section of said well.

20. A method for using a production logging tool to determine flow velocities of a multiphase fluid flow through a cross-section of a well, said method comprising the steps of:
providing a production logging tool having a tool axis, which longitudinally extends within said production logging tool, and at least one flow sensor for measuring flow velocities of a multiphase fluid flow at localized regions of a cross-section of said well, said localized regions being dispersed within said cross-section at different radial distances from and different angular displacements about said tool axis;
disposing said production logging tool within said well, with said tool axis extending transversely through said cross-section;

providing said production logging tool with an arm which is radially extensible away from and rotatable about said tool axis, and said at least one flow sensor being mounted to said arm;
radially extending said arm to dispose said at least one flow sensor at different ones of said radial distances from said tool axis;
rotating said arm to dispose said at least one flow sensor at different ones of said angular displacements about said tool axis;
wherein at least a portion of said flow velocities are measured by said at least one flow sensor when disposed at said different ones of said radial distances and different ones of said angular displacements;
physically moving the flow sensor relative to the axis about a plurality of points within a multitude of regions in the multiphase fluid flow passing through the cross-section of such well by rotating the flow sensor relative to the tool axis and extending the flow sensor at different radial distances from the tool axis;
measuring said flow velocities of said multiphase fluid flow at said localized regions of said cross-section;
wherein said at least one flow sensor comprises an ultrasonic transmitter transducer and receiver transducer pair, and the step of measuring said flow velocities comprises:
emitting ultrasonic signals of a first frequency from said transmitter transducer into said multiphase fluid flow at said localized regions of said cross-section of said well;
receiving ultrasonic return signals of a second frequency with said receiver transducer which second frequency is frequency shifted from said first frequency by an amount proportional to the component of, said fluid flow velocities along said tool axis, reflected or back-scattered in response to said ultrasonic signals being emitted into said multiphase fluid flow at said localized regions;
processing said ultrasonic returns of said second frequency to determine flow velocities of said multiphase fluid flow within said localized regions;
monitoring said radial distances from and said angular displacements about said tool axis at which said flow velocities are measured within said localized regions; and then, plotting said flow velocities at corresponding ones of said radial distances from and said angular displacements about said tool axis to provide a flow velocity profile of said multiphase fluid flow through said cross-section of said well.