• 专利附录
  • 专利说明
  • 权利要求
  • 类似技术
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    • 专利摘要:
    METHOD. Apparatus and methods for determining downhole fluid parameters are disclosed in this document. An example method includes placing a downhole tool in a well. The downhole tool has a sensor including a heater and a temperature sensor. The example method further includes flowing a fluid into the well. The example method also includes determining a first fluid velocity at a first depth via the sensor and, based on the first fluid velocity, a first well parameter at the first depth is determined.
    公开号:BR112013032100B1
    申请号:R112013032100-8
    申请日:2012-06-13
    公开日:2021-05-25
    发明作者:Abdur Rahman Adil；Elena Borisova；Tullio Moscato
    申请人:Prad Research And Development Limited；
    IPC主号:
    专利说明:

    BACKGROUND
    [001] A well can be drilled through an underground formation to extract hydrocarbons. A dimension (for example, a cross-sectional area) of the well can vary with a depth of the well. Additionally, conditions in the well can be severe. For example, temperatures inside the well can be approximately minus 25°C to approximately 150°C and pressures can be up to 12,500 psi or greater. SUMMARY
    [002] This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify fundamental or essential characteristics of the claimed subject matter, nor should it be used as an aid in limiting the scope of the claimed subject matter.
    [003] An exemplary method disclosed herein includes placing a downhole tool in a well. The downhole tool includes a sensor that has a heater and a temperature sensor. The exemplary method further includes flowing a fluid into the well. The exemplary method also includes determining a first fluid velocity at a first depth via the sensor and, based on the first fluid velocity, determining a first well parameter at the first depth.
    [004] Another exemplary method disclosed herein includes determining a first depth of a sensor of a downhole tool disposed in a wellbore. The sensor includes a heater and a temperature sensor. The exemplary method further includes determining a first velocity of a fluid in the well via the sensor and determining a first parameter of the well based on the first velocity of the fluid. The exemplary method also includes associating the first parameter with the first depth and generating a well profile based on the first parameter.
    [005] Another exemplary method disclosed herein includes placing a heater and temperature sensor at a first depth. The exemplary method further includes heating the fluid via the heater and determining a temperature of the fluid via the temperature sensor. Based on a thermal property between the heater and the fluid, a first fluid velocity at the first depth is determined. The exemplary method also includes determining a first well parameter at the first depth based on the first fluid velocity. BRIEF DESCRIPTION OF THE DRAWINGS
    [006] Modalities of methods and apparatus for determining downhole parameters are described with reference to the following figures. The same numbers are used throughout the figures to reference similar features and components.
    [007] Figure 1A illustrates an exemplary system in which the modalities of methods and apparatus for determining downhole parameters can be implemented.
    [008] Figure 1B illustrates various components of an exemplary device that can implement modalities of methods and apparatus for determining downhole parameters.
    [009] Figure 1C illustrates various components of the exemplary device of Figure 1B that may implement embodiments of the exemplary methods and apparatus for determining downhole parameters.
    [0010] Figure 1D illustrates various components of another exemplary device that can implement modalities of methods and apparatus for determining downhole parameters.
    [0011] Figure 2A illustrates various components of an exemplary device that can implement modalities of methods and apparatus for determining downhole parameters.
    [0012] Figure 2B illustrates various components of the exemplary device of Figure 2A that may implement modalities of methods and apparatus for determining downhole parameters.
    [0013] Figure 2C illustrates various components of the exemplary device of Figure 2A that may implement modalities of methods and apparatus for determining downhole parameters.
    [0014] Figure 2D illustrates various components of another exemplary device that can implement modalities of methods and apparatus for determining downhole parameters.
    [0015] Figure 2E illustrates various components of yet another exemplary device that can implement modalities of methods and apparatus for determining downhole parameters.
    [0016] Figure 3 is a graph illustrating sensor measurements made using the exemplary device of Figure 2B.
    [0017] Figure 4A illustrates various components of an exemplary device that can implement modalities of methods and apparatus for determining downhole parameters.
    [0018] Figure 4B illustrates various components of an exemplary device that can implement modalities of methods and apparatus for determining downhole parameters.
    [0019] Figure 5A is a graph illustrating sensor measurements.
    [0020] Figure 5B is another graph illustrating sensor measurements.
    [0021] Figure 6 is a graph of sensor measurements and fluid flow based on sensor measurements.
    [0022] Figure 7 illustrates various components of an exemplary device that can implement modalities of methods and apparatus for determining downhole parameters.
    [0023] Figure 8 illustrates various components of the exemplary device of Figure 2E that can implement modalities of methods and apparatus for determining downhole parameters.
    [0024] Figure 9 illustrates various components of the exemplary device of Figure 8 that can implement modalities of methods and apparatus for determining downhole parameters.
    [0025] Figure 10 illustrates the exemplary method(s) for determining downhole parameters according to one or more modalities.
    [0026] Figure 11 illustrates the exemplary method(s) for determining downhole parameters according to one or more modalities. DETAILED DESCRIPTION
    [0027] It should be understood that the following disclosure provides many different embodiments or examples for implementing different features of various embodiments. Specific examples of components and arrangements are described below to simplify the present disclosure. These are, of course, only examples and are not intended to be limiting. In addition, the present disclosure may repeat reference numerals and/or letters in the various examples. This repetition is intended for simplicity and clarity and does not in itself determine a relationship between the various modalities and/or configurations discussed. In addition, the formation of a first feature in relation to or over a second feature in the following description may include modalities in which the first and second features are formed in direct contact, and may also include modalities in which additional features can be formed by interposing the first and second features such that the first and second features may not be in direct contact.
    [0028] Although some fluid detection systems, examples disclosed herein are discussed as being positioned on treatment tools of a spiral piping system, other examples are employed with and/or without treatment tools. For example, a fluid sensing element can be employed apart from the spiral piping system. Thus, in some examples, the fluid detection system can be installed by a drill pipe, drill string or any other suitable transport device.
    [0029] Exemplary apparatus and methods disclosed herein can be used to determine downhole parameters. An exemplary method disclosed herein may include placing a downhole tool in a well. In some examples, the downhole tool includes a sensing element including a heater and temperature sensor. The exemplary method may include flowing a fluid into a well and determining a depth of the sensing element. In some examples, the heater heats the fluid and a fluid temperature is determined via the temperature sensor. Based on the thermal property between the heater and the fluid, a fluid velocity at depth can be determined. A parameter (eg a width, diameter, cross-sectional area, etc.) of the well depth can be determined based on velocity. In some examples, the parameter is associated with depth and recorded (eg stored in a database). Based on the well parameter, a profile (eg diagram, graph, map, model, table etc.) of the well can be generated.
    [0030] Figure 1A is a schematic illustration of a well location 100 with a spiral piping system 102 installed in a well 104. The spiral piping system 102 includes supply and surface equipment 106, including a spiral piping truck 108 with spool 110, positioned adjacent to well 104 at well location 100. Spiral tubing system 102 also includes spiral tubing 114. In some examples, a pump 115 is used to pump a fluid into well 104 via spiral tubing . With coiled tubing 114 lowered through a conventional gooseneck type injector 116 supported by a mast 118 over well 104, coiled tubing 114 can be advanced into well 104. That is, coiled tubing 114 can be forced. down through the pressure control equipment and valves 120 and into the well 104. In the spiral piping system 102, as shown, a treatment device 122 is provided to supply the fluids to the downhole during a treatment application. Treatment device 122 can be installed in well 104 to transport fluids, such as an acidifying agent or other treatment fluid, and disperse the fluids through at least one injection port 124 of treatment device 122.
    [0031] The exemplary treatment device 122 is optional and its use will depend on various applications. The coiled tubing system 102 of Figure 1A is illustrated as having a fluid sensing system 126 positioned around the injection port 124 to determine the parameters of the fluids in well 104. The fluid sensing system 126 is configured to determine the fluid parameters such as fluid direction and/or velocity. In other examples, other downhole parameters are determined.
    [0032] In some examples, spiral piping system 102 includes a logging tool 128 to collect downhole data. Profiling tool 128 as shown is provided near a downhole end of coiled tubing 114. Profiling tool 128 acquires a variety of profiling data from well 104 and adjacent formation layers 130, 132 such as those illustrated in Figure 1A. The logging tool 128 is provided with a host of well logging equipment or implements configured to produce logging to acquire well formation and fluid measurements from which an overall production profile can be developed. Other logging, data acquisition, monitoring, imaging and other devices and/or capabilities can be provided to acquire data in relation to a variety of well characteristics. Compiled information can be acquired on the surface in a form at high speed and, where appropriate, put to immediate real-time use (eg via a treatment application). Some examples do not employ profiling tool 128.
    [0033] Still referring to Figure 1A, the spiral pipe 114, with the treatment device 122, the fluid detection system 126, and the profiling tool 128 therein, are installed in the downhole. When these components are installed, treatment, detection and/or profiling applications can be directed via a control unit 136 on the surface. For example, treatment device 122 can be activated to release fluid from injection port 124; fluid detection system 126 can be activated to collect fluid measurements; and/or the logging tool 128 can be activated to record downhole data as desired. The treatment device 122, the fluid detection system 126 and the profiling tool 128 are in communication with the control unit 136 via a communication link (Figures 1B-1D) which carries the signals (e.g. , energy, communication, control etc.) between them. In some examples, the communication link is located in the profiling tool 128 and/or any other suitable location. As described in more detail below, the communication link can be either a physical link link or an optical link.
    [0034] In the illustrated example, the control unit 136 is computerized equipment attached to the truck 108. However, the control unit 136 may be portable computerized equipment such as, for example, a smartphone, a laptop computer, etc. Additionally, mechanical application control can be hydraulic, pneumatic and/or electrical. In some examples, the control unit 136 controls the operation, even in circumstances where different, subsequent application sets are installed in the downhole. That is, subsequent mobilization of control equipment may not be included.
    [0035] The control unit 136 can be wirelessly configured to communicate with a transceiver concentrator 138 of the spiral tubing reel 110. The receiver concentrator 138 is configured for on-site communication (surface and/or downhole ) and/or off-site as desired. In some examples, the control unit 136 communicates with the detection device 126 and/or profiling tool 128 to drive the data between them. The control unit 136 may be provided with, and/or coupled to, databases, processors and/or communicators to collect, store, analyze and/or process the data collected from the detection system and/or profiling tool.
    [0036] In one example, the communication link between the treatment device 122, fluid detection system 126 and/or profiling tool 128 and the surface or control unit 136 can be implemented using a wired telemetry system or of fiber optics. As such, the link/communication system may include tubing that provides and/or has a certain degree of rigidity in compression, similar to spiral tubing. In some such examples, a fiber optic tube is disposed within the coiled tubing. In some examples, a cross-sectional area of the fiber optic tube may be small relative to an internal area defined by the coiled tubing to limit a physical influence of the fiber optic tube on the mechanical behavior of the coiled tubing during installation and recovery, thereby preventing “entanglement” or bunching within the spiral pipe. In some instances, fiber optic-equipped coiled tubing is installed in a well and retrieved from the well at a greater rate than coiled cable tubing.
    [0037] Figure 1B illustrates an exemplary communication link 200 between the treatment device 122, the fluid detection system 126, the profiling tool 128 and/or the surface or control unit 136. In the illustrated example, the communication link 200 includes a tubular element 105 within which a duct or tube 203 is disposed. In the illustrated example, an optical fiber 201 is disposed in the tube 203. In some examples, more than one optical fiber is disposed in the tube 203. In the illustrated example, a surface termination 301 and a downhole termination 207 are provided to couple optical fiber 201 to one or more devices or sensors 209. In some examples, optical fiber 201 is a multimode optical fiber. In other examples, optical fiber 201 is a single-mode optical fiber. Devices or sensors 209 are, for example, meters, valves, sampling devices, temperature sensors, pressure sensors, distributed temperature sensors, distributed pressure sensors, flow control devices, flow rate measuring devices, oil/water/gas ratio measuring devices, crust detectors, triggers, latches, release mechanics, equipment sensors (eg vibration sensors), sand detection sensors, water detection sensors, water loggers data, viscosity sensors, density sensors, bubbling point sensors, composition sensors, resistivity array devices and sensors, acoustic devices and sensors, other telemetry devices, near-infrared sensors, gamma ray detectors, detectors H2S, CO2 detectors, downhole memory units, downhole controllers, drilling devices, shape loads to, firing heads, locators, and other devices.
    [0038] Figure 1C is a cross-sectional view of the communication link 200 of Figure 1B. Within tube 203, an inert gas such as nitrogen can be used to fill the space between fiber or optical fibers 201 and the interior of tube 203. In some instances, fluid is pressurized to prevent tube 203 from bulging. In some examples, a laser welding technique is performed in an enclosed environment filled with an inert gas such as nitrogen to avoid exposing the 201 fiber optic to water or hydrogen during fabrication. In some examples, tube 203 is constructed by bending a strip of metal around optical fiber 201 and then welding that strip to form tube 203. An exemplary laser welding technique is described in U.S. Patent 4,852. 790, which is incorporated herein by reference in its entirety. In some examples, gel including palladium or tantalum is inserted into one end of tube 203 to separate hydrogen ions from optical fiber 201 during transport from communication link 200.
    [0039] Suitable materials for use in tube 203 provide rigidity to tube 203, are resistant to fluids found in oil field applications, and/or are rated to withstand the high temperature and high pressure conditions found in some well environments. In some examples, tube 203 is a metallic material and tube 203 may include metallic materials such as, for example, Inconel™, stainless steel, or Hasetloy™.
    [0040] In some examples, tube 203 has an outside diameter of approximately 0.071 inches to approximately 0.125 inches. In some examples, tube 203 is less than or equal to approximately 0.020 inches (0.508 mm) thick. The dimensions mentioned above are exemplary only and thus other dimensions may be used without departing from the scope of this disclosure.
    [0041] Figure 1D illustrates another exemplary communication link 212. In the illustrated example, the communication link 212 includes a tubular element 105 and a first tube 203 and a second tube 203. A first optical fiber 201 is disposed in the first tube. A second optical fiber 201 and a third optical fiber 201 are disposed in the second tube 203. In one example, the first optical fiber 201 is coupled to one of the devices 209, and the second optical fiber 201 and the third optical fiber 201 are coupled to one or more than one of the devices 209. In some examples, more than one of the devices 209 may be coupled to a single optical fiber 201.
    [0042] Figures 2A-2C are schematic views of a portion of a spiral piping system 202 with a treatment device 222 and fluid detection system 226 in a spiral piping 214 thereof, which can be used to implement the system of coiled tubing 102, treatment device 122, and/or fluid detection system 126 of Figure 1A. Figure 2A is a longitudinal view, partially in cross-section, illustrating fluid sensing system 226 positioned around treatment device 222. As shown, treatment device 222 has injection openings 224 for dispersing injection fluids within. of a well 204 as illustrated schematically by the dashed arrows.
    [0043] Injection fluid may be arranged to treat a portion of a well 204, such as production zone 240 to optimize fluid production therefrom. As illustrated in Figure 2A, stimulation fluid such as acid can be injected into well 204 near the production (or oil production) zone 240 via treatment tool 222. The acid is destined for the production zone 240, but is shown positioned at the bottom of the well from that place. Exactly positioning the injection openings 224 against a zone of interest can be a challenging task due to the uncertainties that can exist regarding the target depth and/or tool position. Sensing system 226 around injection port 224 can be made specifically to measure a split flow upstream and downstream from injection port 224 in well 204. Fluid movement can be used to indicate where production zone 240 is located relative to injection port 224. When known, the position of treatment device 222 and injection port 224 can be located to carry out treatment as desired.
    [0044] When fluid is released from the treatment device 222, the fluid flow is split with an upstream portion of the fluid moving upstream and a downstream portion of the injection fluid moving downstream. The upstream portion of the injection fluid moves upstream at a given speed as indicated by the arrows labeled V1. The downstream portion of the injection fluid travels downstream at a given speed as indicated by arrows labeled V2. Although fluid is illustrated as flowing in a specific direction, it will be appreciated that fluid flow may vary with operating conditions.
    [0045] Although the exemplary detection system 226 illustrated in Figures 1 and 2A-2C is described in conjunction with the coiled tubing system 102 to determine fluid parameters, the detection system 226 can also be used in other flow applications. such as eg fluid cross-flow detection between zones, production profiling (eg for single-phase velocity or in conjunction with Flow Scanner Imaging, FSI) complementary to a centrifuge in a low speed range), downhole or surface testing in conjunction with the use of a flowmeter (eg low speed Venturi based flowmeter applications), leak detection (by with dynamic seals) with other tools where flow velocity measurements are desired, among others. Detection system 226 can be positioned on any surface, downhole and/or other mobile equipment, such as a downhole tool, and/or on fixed equipment, such as a casing (not shown).
    [0046] The detection system 226 is illustrated in Figure 2A as having a plurality of sensor elements 242a,b positioned around the treatment device 222. In some examples, one or more sensor elements 242a,b are positioned around of spiral piping system 102 to perform fluid measurements and/or other downhole measurements. In some such examples, sensor elements 242a,b are positioned around injection port(s) 224 to measure fluid parameters. The measured fluid is the injection fluid dispersed from the treatment device 222, but may also include other fluids in the well (eg, water, hydrocarbons, gases, etc.) that mix with the injection fluid when it is dispersed.
    [0047] An upstream portion of the sensor elements 242a is illustrated as being positioned in the treatment device 222 at a distance upstream of that place. A downhole portion of sensor elements 242b is illustrated as being positioned in treatment device 222 at a distance downstream of that location. The upstream sensor elements 242a and/or the downstream sensor elements 242b may be arranged radially around the treatment apparatus 222. In the illustrated example of Figure 2B, the sensor elements 242a,b are positioned at various radial locations x ,y,z around the treatment apparatus 222. Although a specific configuration for the sensor elements 242a,b is illustrated in Figures 2A and 2B, it will be appreciated that one or more sensor elements may be positioned at various locations (longitudinally and /or radially) around spiral piping system 202 and/or well 204.
    [0048] At least some of the sensor elements 242a,b are capable of sensing fluid parameters such as fluid direction and velocity. In some examples, more than one of the sensor elements 242a,b may be capable of measuring fluid parameters. In some examples, at least one of the sensor elements 242a for measuring fluid parameters is positioned upstream of the injection port 224, and at least one of the sensor elements 242b for measuring fluid parameters is positioned downstream of the injection port. injection 224. In this configuration, measurements from upstream and downstream fluid sensors 242a,b can be compared to determine fluid parameters such as fluid direction and/or fluid velocity. The ratio of the upper and lower velocities and fluid direction obtained from the measurements of the upstream and downstream sensing elements 242a,b can be used to generate real-time monitoring of where the fluid is flowing during treatment, as will be further described here. Other downhole parameters can also be optionally measured with the fluid detection system 226 and/or other sensors positioned around the downhole.
    [0049] Comparison of multiple detection elements 242a,b can be used to account for differences in measurements made by the various detection elements 242a,b. In some examples, multiple detection elements 242a,b are used to provide redundancy and sufficient certainty in the measurement results. This redundancy can also reduce the severity of impact where one or more 242a,b sensor elements fail, such as in severe downhole environments involving the use of acids. The multiple sensing elements 242a,b can also be used to generate fluid direction and/or velocity information. In such cases, at least one upstream sensor element 242a and at least one downstream sensor element 242b can be used. In some examples, additional sensor elements 242a,b are provided to improve the reliability of the generated values.
    [0050] In some examples, it may be useful to consider the position of the detection element 242a,b around the processing tool 222. The number of arrays (or sets of detection elements 242a,b), as well as the number of elements detection rate 242a,b per array may vary. As shown in Figure 2A, sensing elements 242a,b are positioned upstream and downstream to measure fluid as it passes upstream and downstream from injection pillars 224. In some examples, when using upstream and downstream sensing elements downstream corresponding 242a,b, corresponding sensing elements 242a,b, are positioned at equal distances from injection port 224. In some examples, corresponding sensing elements 242a,b are identically combined. Combined sensing elements can be spaced at equal distances.
    [0051] In the illustrated example, multiple sensing elements 242a,b are also positioned around the circumference of the tool at intervals of 90 degrees x, y and z, as shown in Figure 2B. As shown in Figure 2B, sensing elements 242b are positioned at radial locations x, y, and z around treatment device 222. Sensing element 242b at position x is against a wall 205 of well 204. 242a,b detection at x, y and z positions provides redundancy in case one side of the measurements is impeded.
    [0052] A problem may arise when the tool body (eg treatment tool 222) is eccentric (or non-concentric) with the well 204 as shown in Figure 2B. In the illustrated example, the sensing element 242bx located closest to the wall 205 of the well 204 can read a lower flux value than the sensing elements 242by, 242bz positioned further from the wall. In such cases, it may be desirable to ignore or remove measurements from potentially obstructed sensing elements, such as the 242bx sensing element.
    [0053] As shown in Figure 2B, the sensing elements 242b are positioned on an outer surface 223 of the treatment tool 222. The sensing elements 242b can be flush with the outer surface 223, recessed below the outer surface 223, or extended by a distance from that place. In some examples, sensing elements 242b are positioned such that each sensing element 242b contacts the fluid for its measurement, but remains protected. To prevent damage in severe downhole conditions, protrusion of sensing elements 242b from the treatment tool can be reduced. As shown in Figure 2C, sensing elements 242b may also be positioned within the treatment tool 222, for example, or on an inner surface 225 thereof.
    [0054] Figures 2D and 2E illustrate other portions of the spiral piping system 202 including the fluid sensing system 226 which can be used to implement the exemplary spiral piping system 102 of Figure 1A. In Figure 2D, the exemplary detection system 226 is disposed at a lower end of the coiled tubing 114.
    [0055] In Figure 2E, the exemplary detection system 226 is disposed between the profiling tool 128 and the processing tool 122. In the illustrated example, the profiling tool 128 is disposed above the detection system 226 and the processing tool 122 is disposed below the detection system 226 in the orientation of Figure 2E. In some examples, fluid enters well 104 as shown by arrows V3. In other examples, detection system 226 is disposed at one or more other locations in coiled tubing 114.
    [0056] Figure 3 is a graph 350 illustrating sensor data collected from the sensing elements, exemplars 242b of Figure 2B. Graph 350 shows the flow velocity (x-axis) as a function of the sensor output (y-axis) for sensing elements 242bx, 242by, and 242bz at the x, y, and z positions, respectively. As illustrated by graph 350, the flow velocity of the sensing elements 242by and 242bz at the y and z positions is different from the flow velocity of the sensing element 242bx at the x position. In other words, the readings of the upper sensing element 242bz and the 90-degree sensing element 242by are substantially consistent in determining the flow velocity. However, the lower sensing element 242bx has a flow rate that is lower.
    [0057] Graph 350 indicates that sensing element 242bx at position x is pressed against wall 205 of well 204 and is unable to obtain proper readings. Thus, the measurements illustrated by line 242bx made by sensing element 242b at position x can be disregarded. The measurements illustrated as 242by and 242bz lines made by the 242b sensing elements at the y and z positions, respectively, can be combined using conventional analytical techniques (eg, curve fitting, averaging, etc.) to generate the imposed flow 244. Thus, by placing several sensing elements 242a,b azimuthally around the circumference of a tool and detecting the lowest reading sensing element (e.g., 242bx), the azimuth of a flow obstruction can be determined. The sensing element located opposite the lowest reading sensing element (eg 242by), or combinations of other sensing elements, can then be used to perform the flow measurement.
    [0058] Figures 4A and 4B are schematic views of the detection elements 442p and 442q usable as the detection elements 242a,b of Figures 2A and 2B. Each of the 442p,q sensing elements has a 454p,q heater and a 456p,q sensor, respectively, positioned on a 452 sensor base. In the illustrated example, the 456p,q sensor is a temperature sensor (or temperature sensor ) able to measure the temperature of the fluid.
    [0059] In some examples, the 442p,q sensor elements are calorimetric type flow sensors (or flow meters) that have two sensing elements such as, for example, a sensor for measuring speed (scalar sensor) and a sensor for directional measurement (vector sensor). The 454p,q heater and the 456p,q temperature sensor interact to operate as velocity (or scalar) and directional (or vector) sensors.
    [0060] To determine the fluid velocity, the 442p,q sensing elements act as calorimetric sensors. The 454p,q heater (or hot body) of each 442p,q sensor element is placed in thermal contact with the fluid in well 104. The rate of heat loss from the 454p,q heater to the fluid is a function of the velocity of the fluid as well as thermal properties. A heater heat dissipation rate 454p,q can be measured, and a flow velocity can be determined for a known fluid. The 454p,q heater generates heat (eg from electricity), and dissipates heat to the fluid in contact. Heat generation rate and temperature can be readily measurable during operation.
    [0061] The 456p,q temperature sensor can be used to monitor the ambient temperature of the fluid, while the 454p,q heater measures its own temperature during heating. The difference between the heater temperature 454p,q and the fluid's ambient temperature is defined as the temperature excursion. The temperature excursion, ΔT, can be written as follows:

    [0062] In Equation 1, Ta represents the ambient fluid temperature as measured by the temperature sensor, Th represents the heater temperature, and the temperature excursion is proportional to the heater capacity at a given flow condition. A thermal property between the heater and the fluid such as, for example, the thermal conductance, if Gth can be calculated according to the following expression:

    [0063] In Equation 2, P represents the constant state heater capacity. The inverse of this proportionality (or thermal conductance) correlates the flow velocity Vflow because Vflow is a function of Gth. As provided by Equation 1, thermal conductance is determined from three quantities: P (the heater capacity), Th (the heater temperature), and Ta (the fluid ambient temperature). Quantities can be measured in steady state. Theoretically, the amount of energy or temperature excursion used during the measurement is not important to the resulting thermal conductance. However, the temperature and energy excursion can affect accuracy because physical measurements have limits. In some cases, such as the configuration in Figure 4B, a ΔT and a few degrees in Kelvin(K) may be considered appropriate.
    [0064] In other examples, other thermal properties are calculated such as, for example, a normalized energy dissipation to determine the flow velocity. Normalized energy dissipation can be calculated according to the following expression:

    [0065] In Equation 3, the normalized energy dissipation is calculated by dividing the heater energy by the temperature excursion and an area of a sensor heating surface, S.
    [0066] Measurements made by the 454p,q calorimetric detection elements can be used to obtain the heater-fluid thermal conductance, normalized dissipated energy, and/or other thermal properties. A measurement technique may involve either constant excursion or constant energy. For the constant excursion technique, the energy sent by the heater can be regulated electronically (eg, control unit 136) such that the heater temperature can be maintained at a constant excursion above the ambient temperature of the fluid. In the steady state, the measured energy is monotonic related to thermal conductance, normalized energy dissipation, and/or other thermal properties. For the constant energy technique, the heater can be supplied with a constant and predetermined energy, while the heater temperature Th varies and can be determined by the flow rate.
    [0067] Figure 5A is a graph 657 illustrating a flow response of a calorimetric sensor, such as sensing elements 442a,b illustrated in Figures 4A and 4B. The resulting thermal conductance versus flux curve 658 demonstrates that the thermal conductance is non-linear with respect to the velocity of flux. However, the curve of thermal conductance versus fluxes 658 is monotonic. Therefore, a correlation can be established to reverse the measurement, and the flow velocity can be obtained as described in conjunction with Equations 1-2.
    [0068] Flow velocity measurement is a measurement of thermal conductance, normalized energy dissipation, and/or other thermal properties between the 454p,q heater and the fluid. The measurement of thermal conductance and/or normalized energy dissipation can be determined with constant temperature excursion (ΔT) or constant heater energy. Constant temperature excursion can regulate temperature. Constant heater power can regulate power. Any one measurement technique can involve the 454p,q heater and the 456p,q temperature sensor.
    [0069] Referring back to Figures 4A and 4B, the sensing elements 442p,q can also act as scalar sensors to determine fluid direction. In the illustrated example, the 442p,q sensing elements are capable of acting as calorimetric sensors to determine fluid velocity and also as vector sensors to measure flow direction. Calorimetric sensors may be unable to determine fluid direction. In such examples, calorimetric sensors can respond to fluid velocity regardless of direction. Fluid direction may be required for a second measurement, such as using vector sensors capable of detecting fluid direction. Fluid direction can also be acquired, for example, by sensing elements 442p,q of Figures 4A and 4B configured for measuring fluid velocity as well as direction. The physics that enable directional detection may also involve the detection of temperature asymmetry between the upstream and downstream sensing elements (e.g., caused by heat from the 454p heater of the upstream sensing element), such as the elements sensing elements 242a and the downstream sensing elements 242b of Figure 2A.
    [0070] Figures 4A and 4B illustrate configurations of the sensing element 442p,q capable of detecting the fluid flow rate and direction. Figure 4A illustrates a 442p thermocouple (TC) thermocouple detection element. Figure 4B illustrates a dual sensing element 442q. The 452 base for each 442p,q sensing element is sized to host the 454p,q heater, 456p,q sensor and/or other devices in that location.
    [0071] In some examples, the base 452 has a minimum thickness, or is recessed into the downhole tool, to prevent damage to the well 104. The sensor base 452 can be positioned in the downhole, for example, on the device treatment stations 122, 222 and/or spiral tubing 114, 214 (Figures 1, 2A, 2B). The base 452 can be round as shown in Figure 4A or rectangular as shown in Figure 4B. Base 452 can be made from epoxy, PEEK molding and/or any other material.
    [0072] Heater 454p,q and temperature sensor 456p,q can be positioned in close proximity on base 452, but are thermally insulated from each other. In the example illustrated, as the 454p,q heater creates a temperature gradient in the fluid, the 456p,q temperature sensor is provided with sufficient thermal insulation from the 454p,q heater to prevent the 456p,q temperature sensor from being disturbed by heat flow from the 454p,q heater or thermal coupling with the 454p,q heater, which may result in an erroneous measurement value. The 456p,q temperature sensor can optionally be placed in a separate package spaced from the 454p,q heater.
    [0073] The TC sensing element 442p of Figure 4A is illustrated as having a pair of TC junctions (or sensors) 456p1,2 on either side of a heating element (or heater) 454p. The 456p1,2 TC junctions are connected by a 460 metal wire. Each 456p1,2 TC junction has a TC element with 462a,b conductors extending therefrom. In some examples, conductors 462 are also wires operatively coupled to a controller 436 for operation therewith.
    [0074] The 456p TC junctions positioned on either side of the 454p heater can be used to detect a temperature imbalance between them, and convert this into a TC voltage. A small voltage is present if the two TC 456p1,2 junctions are at different temperatures. The 456p1,2 TC junctions are placed very close to the 454p heater (one on each side) for maximum temperature contrast. At zero flow, the 454p heater can heat the two TC 456p1,2 junctions. However, heating does not produce voltage.
    [0075] Two 464p metal elements are illustrated as supporting the 456p1,2 TC joints. The 464p metal elements can be provided to improve the thermal contact between the 456p1,2 TC junctions and the fluid. The 464p metal elements can be useful in cases where the TC 456p1,2 joints are of a small size. The 464p metal elements and the 456p1,2 TC joints can be held together by thermal adhesives such as silver epoxies and any other thermally conductive adhesives. The 464p metal elements are positioned in alignment with the 454p heater, thus defining a 466p flow line along the 442p sensing element as indicated by the arrow.
    [0076] The voltage TC (y-axis) as a function of the flow velocity (x-axis) is shown in a graph 659 of Figure 5B. Graph 659 presents an odd function of the flow velocity measured by the 456p1,2 TC junctions. The magnitude of an almost zero maximum flux is tapered gradually with increasing velocity. At zero crossing, the TC signal output undergoes a sudden change in polarity from negative to positive as indicated by curves 661a,b, respectively. This change in signal polarity can be used to detect fluid direction as described in more detail below.
    [0077] The temperature profile along a flux stream of eg 442p sensing element is shown schematically in Figure 6. Figure 6 is a 663 graph illustrating temperature (y-axis) versus velocity (x-axis). As illustrated by this graph, the 454p heater generates a constant heat Th measurable by the 456p1,2 TC junction on either side of it. Heat from the heater 454p is carried downstream by the fluid forming a hot stream. Velocities V1, V2 and V3 are measured, for example, at different time intervals. The visibility of the thermal gradient may depend on speed. The thermal gradient between upstream and downstream can be detected with sensor element 442p. This creates a temperature contrast between the 456p1,2 upstream and downstream TC junctions. This indicates that the flow is moving towards the TC 456p2 junctions, thereby indicating the direction of fluid flow. Upon detection of asymmetry between the TC 456p1,2 junctions, the fluid direction can be determined as indicated by the arrow.
    [0078] The dual element detection element 442q of Figure 4B is illustrated as having two identical elements (sensors/heaters) 446q/454q. 456q/454q sensors/heaters are illustrated as Element M and Element N in the 442q sensing element. In some examples, the 454q heater and 456q sensor (and therefore M and N elements) are interchangeable in function and operation. In some of these cases, the 456q sensor is capable of performing the heater functions and the 454q heater is capable of performing the sensor functions. Elements M and N are operatively connected via connections 455 to controller 436 for operation therewith.
    [0079] In some examples, a desired measurement can be operated in self-referenced mode in which a single M or N element performs a dual function, both as a heater and as a temperature sensor. In some of these cases, the heater and temperature sensor may use a time multiplexing technique. In some examples, the 454q heater and 456q temperature sensor function can be reassigned at any time. This measurement scheme can be used to provide flexibility in the design and/or operation of the 442q sensor element, which can be made specifically for a specific application.
    [0080] A temperature asymmetry between identical elements M and N is detectable by the dual element sensor 442q. The two identical elements M and N are positioned along a fluid flow line as indicated by the arrow. Elements M and N can be positioned in close proximity, for example, within the same base (or pack) 452.
    [0081] The measurement by the sensor element of Figure 4B can be obtained using several methods. A first method involves measuring heater energy in flow using Element M as the heater and Element N as the temperature sensor. After a stable reading is obtained, the functions of the M and N Elements are exchanged and the measurement repeated. By comparing the energy of the two measurements, the direction of flow can be ascertained. The heater that consumes the most energy is located upstream as long as the flow does not vary in the meantime. A second method that can be used involves measuring by heating both elements, M and N, simultaneously with the same amount of energy. The measurements of each element can be compared. Whichever element shows a higher temperature is downstream in the direction of fluid flow. A third method that can be used involves observing the temperature of Element M while turning Element N on and off at a certain energy level. If a change in temperature is perceived, it can be assumed that element N is upstream of element M. No change can suggest otherwise.
    [0082] With the first two methods, where quantities are compared through the elements M and N, a good combination of characteristics of the two elements M, N reduces potential errors. The combination of elements can be achieved through calibration and normalization. The third method, on the other hand, can be used without such a good combination. Dual element sensors are usable, for example, for bidirectional flow.
    [0083] When the 456p,q temperature sensor and the 454p,q heater of Figures 4A and 4B reside in the same package (for example, due to space limitation), the 456p,q temperature sensor is positioned upstream of the 454p heater, q (or the M element is upstream of the N element). If the flow goes in both directions, the 456p,q temperature sensor and the 454p,q heater (or M and N elements) can be positioned in a side-by-side (or flowline) configuration in line with the fluid flow as shown in the detection elements 442p,q of Figures 4A and 4B.
    [0084] Although Figure 4A illustrates a single 454p heater with a pair of TC 456p junctions and Figure 4B illustrates a single 454p heater with a single 456q temperature sensor, other examples employ multiple 454p,q and/or 456p,q sensors . Additional sensors and/or other devices can be incorporated into the 442p,q sensing elements and/or used in combination with them. In sensor systems including multiple 454p,q heaters, a 456p,q temperature sensor can serve multiple 454p,q heaters. Some multi-element sensors have more than two elements (eg M, N, P, D...). As shown in Figure 4B, a third element O can be provided. In another measurement method, the three or more elements (eg, M, N, O) can be used to detect fluid direction by heating an intermediate element and comparing the temperature between the surrounding upstream and downstream elements. the same.
    [0085] As shown, the detection elements 442p,q of Figures 4A and 4B (and/or the sensors, heaters, elements and/or other components used in this place and/or with it) are operatively coupled to the controller 436 to providing power, collecting data, controlling and/or otherwise operating the sensing element 442p,q. Controller 436 may be, for example, profiling tool 128, control unit 136 and/or other electronics capable of providing power, collecting data, controlling and/or otherwise operating temperature sensors 456p,q, heater 456p,q and/or other elements of the 442p,q detection elements. Power sources can be batteries, power supplies and/or other devices internal and/or external to the sensing elements. In some cases, other devices such as the profiling tool 128 of Figure 1A can power them. Such electronic devices can be internal and/or external to the sensing elements. Communication devices may be provided for wired and/or wireless coupling of the sensing elements to downhole and/or surface communication devices for communication therewith. In some cases, communication devices such as transceivers can be provided on the detection elements. In other cases, the sensing elements can be connected to the profiling tool 128 (Figure 1A) or other devices for communication as desired.
    [0086] The detection elements are also operatively coupled to, and/or in communication with, databases, processors, analyzers, and/or other electronic devices to manipulate the data thus collected. Power, electronic and/or communication devices can be used to manipulate data from sensing elements as well as other sources. The analyzed data can be used to make decisions regarding the well location and its operation. In some cases, data can be used to control well operation. Some such controls can be done automatically and/or manually as desired.
    [0087] Although the elements of the heater and the temperature sensor can be physically identical, the sensor can have different types, shapes and/or shapes. Figure 7 illustrates sensor 770 usable as an element of the sensor elements 454p,q of Figures 4A and/or 4B. Figure 7 illustrates the sensor 770 usable as the heater 454q and/or the temperature sensor 456q, as elements M, N and/or O, or in combination therewith. As shown, sensor 770 can be positioned on base 452. Sensor 770 can be operatively coupled to controller 436 via wires 774 for operation therewith in the same manner as previously described for sensor elements 442p,q.
    [0088] The exemplary sensor 770 of Figure 7 is an RTD-type sensor with a resistance that varies with temperature. In some examples, the 770 sensor is used for the purpose of temperature detection. However, the 770 sensor can generate heat when current passes through the 770 sensor. Thus, an exemplary sensor 770 can be used both as a heater and as a temperature sensor (eg, 454p,q and 456p,q of Figure 4B).
    [0089] A thin film type RTD capable of use as both a temperature sensor and heater can be used so that it can operate interchangeably like the M, N and/or O element of Figure 4B. As shown in Figure 7, sensor 770 positioned on base 452 has a front surface (or contact surface) 772 that can be positioned adjacent to the fluid to take measurements therefrom. In some examples, the sensor 770 employs platinum in the form of wire or thin film (or resistor) 774 deposited on a heat-conducting substrate 776, such as sapphire or ceramic. Wire 774 is positioned on film 776 and extends therefrom for operative connection with controller 436. Heat-conducting substrate 776 may be adhered or bonded to a thin element 778 (made, for example, of Inconel or ceramic substrate ) by a thermally conductive 780 adhesive such as silver epoxy or by brazing. In some examples, such a bond provides low thermal resistance.
    [0090] In the illustrated example, the sensor 770 is wrapped in protective packaging, however they may differ in thermal mass and therefore response time. The shape of element 778 can be square, circular, or any other shape capable of supporting the RTD at the base 452. In some examples, element 778 is approximately 10mm (or so) in size, and is thick enough for practicality. mechanics. The thickness and material selected can determine the thermal contact performance of a heater fluid.
    [0091] The exemplary sensor 770 can be configured with a large surface area for contact with the fluid and/or large thermal mass for passing heat through it. A larger thermal mass can result in relatively slower measurement response. However, thermal mass can also help to reduce (eg averaging) spurious variations in readings caused by turbulence. Sensor electronics can also be provided to reduce spurious variations.
    [0092] The 770 sensor and/or the 442q sensing element can be configured in a surface (or non-intrusive) shape with a low profile (or thickness) as shown in Figures 7 and 4B. The 770 sensor and/or the 442q sensing element can be positioned in the downhole by means of a downhole tool (e.g. spiral piping system 102 of Figure 1A) extending a short distance (if any) from that place. This low profile or non-intrusive surface shape can be provided to reduce disturbance of fluid flowing through the sensor, while still allowing fluid measurement. In addition, the low profile surface shape can also be configured to limit the amount of protrusion from the downhole tool and therefore potential damage to it.
    [0093] Figure 8 illustrates the exemplary detection system 226, which can be used to determine a parameter of the well 104 (e.g., a cross-sectional area of the well 104, a width of the well 104, a distance from the exemplary detection system 226 to the wall 205 of the well 104, a diameter of the well 104, etc.) at a given depth. In some examples, a shape (eg, a well shape such as, for example, round, oblong, asymmetrical, irregularly formed, etc.) of well 104 varies with depth. As a result, well dimensions may vary with depth. In the illustrated example, a first cross-sectional area of well 104 at a first depth 800 is greater than a second cross-sectional area of well 104 at a second depth 802.
    [0094] In some examples, pump 115 pumps fluid through well 104. In the illustrated example, fluid flows through well 104 in one direction of arrow 804. In other examples, fluid flows in other directions (eg, towards a surface of the Earth). In some examples, pump 115 pumps fluid through well 104 at a substantially constant flow rate. In some examples, fluid is pumped into the well via spiral tubing 806 and/or any other transport tool. In some such examples, fluid is pumped through a sealed portion of well 104 (eg, a portion of well 104 in which fluid is not leaking into a production zone). As a result, the velocity of fluid flowing through well 104 varies as a function of the shape and/or one or more dimensions of well 104 such as, for example, the cross-sectional area of well 104. cross-sectional area of well 104 at first depth 800 is greater than cross-sectional area of well 104 at second depth, fluid velocity at first depth 800 is less than fluid velocity at second depth 802.
    [0095] Figure 9 is a cross-sectional view of the exemplary well 104 of Figure 8 at first depth 800. In the illustrated example, the well 104 has an amoebic cross-sectional shape. Other examples have other shapes (eg circular). Exemplary sensing system 226 includes four of sensing elements 242a disposed around a circumference of coiled tubing system 102. Other examples include other numbers of sensing elements 242a (e.g., 1, 2, 3, 5, 6, etc.), which can be arranged around the circumference of the spiral piping system 102 in other positions.
    [0096] The parameter of the well 104 at a given depth can be determined by means of one or more of the detection elements 242a,b of the exemplary detection system 226 of Figure 8. For example, the detection system 226 can be lowered to inside well 104 such that sensing element 242a is positioned at first depth 800. In some examples, sensing element 242a includes a heater and a temperature sensor (e.g., the exemplary heater 454 of Figure 4, the exemplary temperature sensor 456 of Figure 4, exemplary RTD sensor 770 of Figure 7), which are used to determine a first fluid velocity at first depth 800. Based on the first fluid velocity, a first well parameter 104 at first depth 800 is determined. In some examples, the first well parameter is associated with the first depth 800. The first depth 800 of the exemplary sensing element 242a can be determined based on a quantity (e.g., length) of coiled tubing 114 installed in the well 104 and /or via any suitable depth measuring device.
    [0097] In some examples, the exemplary detection system 226 can be used to determine a plurality of parameters from well 104 at a plurality of depths. Based on the plurality of parameters at the plurality of depths, a profile (e.g., an image, a map, a model, a graph, a diagram, a record, a table, etc.) of a portion of well 104 can be generated.
    [0098] Figures 10-11 are representative flowcharts of the exemplary methods disclosed herein. At least some of the exemplary methods of Figures 10-11 can be performed by a processor, profiling tool 128, controller 436, and/or any other suitable processing device. In some examples, at least some of the exemplary methods of Figures 10-11 are incorporated into encoded instructions stored in an accessible or machine-readable, tangible medium such as flash memory, a ROM, and/or RAM random access memory associated with a processor. Some of the exemplary methods in Figures 10-11 can be implemented using any combination(s) of application-specific integrated circuit(s) (ASIC(s)), programmable logic device(s) (PLD(s)), device(s) ) field programmable logic (FPLD(s)), discrete logic, hardware, firmware, etc. Furthermore, one or more of the operations illustrated in Figures 10-11 may be implemented manually or as any combination of any of the preceding techniques, for example, any combination of firmware, software, discrete logic and/or hardware.
    [0099] Additionally, although the exemplary methods are described with reference to the flowcharts illustrated in Figures 10-11, many other methods of implementing the exemplary methods can be employed. For example, the execution order of blocks can be changed, and/or some of the described blocks can be swapped, removed, subdivided or combined. Additionally, any of the exemplary methods of Figures 10-11 may be performed sequentially and/or performed in parallel, e.g., by means of separate processing execution streams, processors, devices, discrete logic, circuitry, etc.
    [00100] Figure 10 illustrates an exemplary method 1000 disclosed herein that can be used to determine one or more fluid parameters. In block 1002, a downhole system such as, for example, spiral pipe system 100 of Figure 1A is installed in a well with a sensor (e.g., one of the sensor elements, examples 242a,b of Figure 2A ) about the same. In some examples, the sensor includes a heater (eg, the exemplary 454 heater of Figure 4, the exemplary 770 RTD sensor of Figure 7) and a temperature sensor (eg, the exemplary 456 temperature sensor of Figure 4, the exemplary RTD sensor 770 of Figure 7). In block 1004, fluid is injected from the downhole system into the well through an injection port (eg, example injection port 224 of Figure 2) of the downhole system.
    [00101] In block 1006, a first measurement (eg a fluid temperature) is made with the temperature sensor. At block 1008, a second measurement (eg, energy dissipated through the heater, a heater temperature, etc.) is taken with the heater. In block 1010, a fluid parameter (eg, a fluid velocity, a fluid flow direction) is determined based on the first measurement and the second measurement. In block 1012, the fluid parameter is analyzed. In some examples, measurements and/or the parameter are stored, processed, reported and/or manipulated, etc.
    [00102] Figure 11 illustrates another exemplary method 1100, disclosed herein, which can be used to generate a profile of well 104. Exemplary method 1100 of Figure 11 begins by arranging a sensor (e.g., the exemplary sensor element 242a) of a downhole tool (e.g., the exemplary coiled tubing system 102) in a well (block 1102). The sensor includes a heater (eg, the exemplary 454 heater of Figure 4) and a temperature sensor (eg, the exemplary 456 temperature sensor of Figure 4). In block 1104, fluid is drained into the wellbore. In some examples, fluid is drained (eg via pump 115) in a substantially constant flow regime. In block 1106, a sensor depth is determined. In some instances, the sensor depth is determined based on an amount (eg length) of coiled tubing installed in the well and/or via any suitable depth measuring device. In block 1108, the fluid is heated by means of the heater, and in block 1110, the temperature of the fluid is determined by means of the temperature sensor. A thermal property (eg normalized energy dissipation, thermal conductance, thermal resistance, etc.) between the heater and the fluid is determined (block 1112) and, based on the thermal property, a fluid velocity at depth is determined ( block 1114).
    [00103] Fluid velocity varies as a function of a shape (eg shape) of the well and/or one or more dimensions (eg a cross-sectional area) of the well. Thus, in block 1116, a well parameter (eg a cross-section, cross-sectional area, a width, a diameter, etc.) at depth is determined based on velocity. The well parameter is associated with depth (block 1118). For example, if a well width is one foot in a thousand feet below the surface, the one foot width is associated with a thousand feet depth. In block 1120, the parameter associated with depth is recorded. For example, the parameter associated with depth can be stored in a database. In block 1122, a well profile is generated based on the parameter. In some examples, an image, a map, a model, a graph, a diagram, a table and/or any other profile of the well is generated based on the parameter associated with the depth stored in the database and/or any other information . At block 1124, the downhole tool is moved to position the sensing element at another depth in the wellhole, and the exemplary method returns to block 1106. Thus, the downhole tool can be moved by a portion of the wellhole and used to determine a first well parameter at a first depth, a second well parameter at a second depth, a third well parameter at a third depth, etc. As a result, a profile of the portion of the downhole through which the downhole tool is traversed can be generated.
    [00104] Although only a few exemplary modalities have been described in detail above, those skilled in the art will readily consider that many modifications are possible in the exemplary modalities without materially departing from this disclosure. Accordingly, such modifications are to be included within the scope of the disclosure as defined in the following claims. In the claims, half-plus-function clauses shall cover the structures described here as performing the cited function and not only structural equivalents, but equivalent structures as well. Thus, although a nail and a screw may not be structural equivalents in that a nail employs a cylindrical surface to fasten pieces of wood together, whereas a screw employs a helical surface, in the environment of fastening pieces of wood, a nail and a screw they can be equivalent structures. Applicant's express intent is not to invoke 35 U.S.C. §112, paragraph 6 for any limitations on any of the claims set forth herein, except those in which the claim expressly uses the terms “means to” in conjunction with an associated function.
    [00105] The Abstract at the end of this disclosure is provided in accordance with 37 C.F.R. §1.72(b) to allow the reader to quickly ascertain the nature of the technical disclosure. It is submitted with the understanding that it will not be used to interpret or limit the scope or meaning of the claims.
    权利要求:
    Claims (20)
    [0001]
    1. Method, characterized in that it comprises: arranging a downhole tool (222) at a depth in a well (104) on a conveyor, the downhole tool (222) including a calorimetric sensor having a heater ( 454) and a temperature sensor (456), the heater (454) and the temperature sensor (456) positioned and level with an outer surface of the downhole tool (222); flowing a fluid in the well, the heater (454) and the temperature sensor (456) in thermal contact with the fluid; determine a first fluid velocity at a first depth via the calorimetric sensor; and determining a first well parameter at the first depth based on the first fluid velocity.
    [0002]
    2. Method according to claim 1, characterized in that the determination of the first fluid velocity at the first depth comprises heating the fluid and determining a fluid temperature.
    [0003]
    3. Method according to claim 2, characterized in that it further comprises determining a thermal property between the heater (454) and the fluid.
    [0004]
    4. Method according to claim 1, characterized in that it further comprises determining the first depth and associating the first depth with the first parameter.
    [0005]
    5. The method of claim 1, further comprising: moving the transport tool and the downhole tool (222) to move the calorimetric sensor from the first depth to a second depth; determining a second fluid velocity at the second depth; determining a second well parameter at the second depth based on the second fluid velocity; determine the second depth; and associate the second depth with the second parameter.
    [0006]
    6. Method according to claim 1, characterized in that it further comprises generating a well profile (104) based on the first parameter.
    [0007]
    7. Method according to claim 1, characterized in that the first parameter is a cross-sectional area of the well (104).
    [0008]
    8. Method, characterized in that it comprises: arranging a downhole tool (222) in a well in a transport; determine a first depth of a calorimetric sensor of the downhole tool (222) disposed in a well, the sensor including a heater (454) and a temperature sensor (456), the heater (454) and the temperature sensor ( 456) positioned and level with an outer surface of the downhole tool (222); determining a first velocity of a fluid in the well via the calorimetric sensor, the heater (454) and the temperature sensor (456) in thermal contact with the fluid; determining a first well parameter based on the first fluid velocity; associate the first parameter with the first depth; and generating a well profile (104) based on the first parameter.
    [0009]
    9. Method according to claim 8, characterized in that determining the first fluid velocity comprises heating the fluid by means of the heater (454) and determining a fluid temperature by means of the temperature sensor (456).
    [0010]
    10. Method according to claim 8, characterized in that it further comprises determining a thermal property between the heater (454) and the fluid.
    [0011]
    11. Method according to claim 8, characterized in that it further comprises flowing the fluid in the well at a constant rate.
    [0012]
    12. Method according to claim 8, characterized in that the first parameter is a cross-sectional area of the well.
    [0013]
    13. The method of claim 8, further comprising: moving the carriage and the downhole tool (222) to move the sensor from the first depth to a second depth; determine the second depth; determining a second fluid velocity by means of the calorimetric sensor; determining a second well parameter based on the second velocity; and associate the second parameter with the second depth.
    [0014]
    14. Method according to claim 13, characterized in that it further comprises generating a well profile (104) based on the second parameter.
    [0015]
    15. Method, characterized by the fact that it comprises: disposing, in a well, by means of spiral piping, a calorimetric sensor comprising a heater (454) and a temperature sensor (456) of a downhole tool (222) at a first depth, the heater (454) and temperature sensor (456) positioned on a sensor base and flush with an outer surface of the downhole tool (222); heating a fluid in the well by means of the heater (454), the heater (454) and the temperature sensor (456) in thermal contact with the fluid; determining a fluid temperature by means of the temperature sensor (456); determining a first fluid velocity at the first depth based on a thermal property between the heater (454) and the fluid; and determining a first well parameter at the first depth based on the first fluid velocity.
    [0016]
    16. Method according to claim 15, characterized in that it further comprises flowing a fluid through the well at a constant flow rate.
    [0017]
    17. Method according to claim 15, characterized in that it further comprises: determining the first depth; and associate the first speed with the first depth.
    [0018]
    18. The method of claim 15, further comprising: moving the spiral pipe and downhole tool (222) from the first depth to a second depth; determining a second fluid velocity at the second depth; and determining a second well parameter at the second depth based on the second velocity.
    [0019]
    19. Method according to claim 18, characterized in that it further comprises: determining the second depth; and associate the second speed with the second depth.
    [0020]
    20. Method according to claim 15, characterized in that it further comprises generating a well profile (104) based on the first parameter.
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    同族专利:
    公开号 | 公开日
    WO2012174034A3|2014-05-08|
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    EP2718543B1|2017-08-09|
    US20140165715A1|2014-06-19|
    WO2012174038A3|2014-05-08|
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    WO2012174034A2|2012-12-20|
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    DK2718544T3|2016-04-25|
    WO2012174051A2|2012-12-20|
    BR112013032103B1|2020-07-14|
    US20140150546A1|2014-06-05|
    WO2012174036A2|2012-12-20|
    BR112013032103B8|2020-07-28|
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    WO2012174048A2|2012-12-20|
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    MX2013014651A|2014-02-11|
    WO2012174051A3|2014-01-16|
    US10365400B2|2019-07-30|
    EP2718543A4|2015-01-14|
    BR112013032100A2|2020-11-10|
    WO2012174038A2|2012-12-20|
    EP2718544B1|2016-01-20|
    MX2013014652A|2014-03-27|
    WO2012174036A3|2013-12-19|
    BR112013032103A2|2019-09-10|
    WO2012174046A3|2014-05-01|
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    WO2012174048A3|2013-11-07|
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    法律状态:
    2020-11-17| B06U| Preliminary requirement: requests with searches performed by other patent offices: procedure suspended [chapter 6.21 patent gazette]|
    2021-03-09| B09A| Decision: intention to grant [chapter 9.1 patent gazette]|
    2021-05-25| B16A| Patent or certificate of addition of invention granted|Free format text: PRAZO DE VALIDADE: 20 (VINTE) ANOS CONTADOS A PARTIR DE 13/06/2012, OBSERVADAS AS CONDICOES LEGAIS. |
    优先权:
    申请号 | 申请日 | 专利标题
    US201161496180P| true| 2011-06-13|2011-06-13|
    US61/496,180|2011-06-13|
    PCT/US2012/042147|WO2012174046A2|2011-06-13|2012-06-13|Methods and apparatus for determining downhole parameters|
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