• 专利附录
  • 专利说明
  • 权利要求
  • 类似技术
  • 同族专利
  • 引用文献
  • 法律状态
  • 优先权
    • 专利摘要:
    sensor element for determining at least one parameter of a fluid in a well having a downhole system deploying thereto, system for determining at least one parameter of a fluid in a well, and method for determining at least one parameter of a fluid in a well systems and methods for determining at least one parameter of a fluid in a well are provided. the system has an implantable downhole system in the well and sensing elements to measure fluid parameter(s) of the fluid in the well. each of the sensing elements is provided with a base and sensors. the base is positionable in the spiral piping system around the injection port. sensors are positionable on the base. each of the sensors is thermally insulated from one another and is capable of functioning both as a heater to heat the fluid and as a temperature sensor to measure the fluid's temperature. the sensors are operatively interchangeable so the sensors can selectively heat and measure fluid temperature whereby fluid fluid parameters are determined.
    公开号:BR112012031689B1
    申请号:R112012031689-3
    申请日:2011-06-23
    公开日:2021-07-20
    发明作者:Tullio Moscato；Robert Van Kuijk；Xu Wu；Jacques Jundt
    申请人:Prad Research And Development Limited；
    IPC主号:
    专利说明:

    BACKGROUND OF THE INVENTION 1. Field of Invention
    The present invention relates to techniques for determining fluid parameters. More particularly, the present invention relates to techniques for determining downhole fluid parameters such as fluid direction and fluid velocity. 2. Background of the Related Art
    Oil rigs are positioned at well locations to perform a variety of oilfield operations, such as drilling a well, performing in-well tests and producing localized hydrocarbons. Downhole drilling tools are advanced into the earth from a surface rig to form a well. During or after drilling, casing is generally cemented in place to line at least a portion of the well. Once the cavity is formed, production tools can be positioned over the well to draw fluids to the surface.
    Oilfield operations are often complicated, time-consuming and very expensive. In recognition of these expenses, added emphasis was placed on well logging, characterization and monitoring of well conditions. Over the years, detection and monitoring of well conditions has become a more sophisticated and critical part of managing well operations. During these operations, initial collection of information regarding the well and the conditions of the surrounding formation can be accomplished by passing a logging tool to the well. The logging tool can be configured to acquire temperature, pressure, acidity, viscosity, resistivity, composition and/or other well parameters that provide information on well condition. A map of the acquired information can be generated, which results in an overall profile of the well that can be of great value in subsequent monitoring and well functioning.
    Oil field operations often involve well maintenance through spiral piping applications, particularly in the case of deviated wells. Spiral piping applications involve deploying a spiral piping column, which is capable of supplying the treatment fluids and performing a variety of downhole service applications, in the well. It can be helpful during such operations to know various downhole parameters. In particular, knowledge of the characteristics of various downhole fluids, such as hydrocarbons, water, drilling muds, gases, etc., and related fluid parameters, such as temperature and pressure, can be useful in monitoring performance, security, features, etc. In particular, knowledge of fluid and other parameters can be used to assist in locating and treating underground reservoirs containing valuable hydrocarbons. Reservoir treatment may involve, for example, production logging (for production logging, PL) and/or fluid diversion and placement.
    In order to determine fluid parameters in the well, fluid sensors are often used for fluid measurements. Examples of fluid sensors that have been used are automatic screwdrivers, electromagnetic (EM) flowmeters, ultrasonic (Doppler-based) flowmeters, and various types of markers (eg, radioactive). In some cases, fluid sensors can be heat-based sensors, such as time of flight, anemometry, calorimetric, etc. Examples of existing fluid sensors and/or measurement techniques are described in US patents/applications Nos. US20090204346, US20090090176, US6801039, US20090153155, US20090266175, US20090038410, US20100089571, US20090271129, US7644611, US7637167, US7258005, US6832527, US5457396, US6527923, US4608983, German Nos. DE3213902, DE3820025, DE4017877, and European Nos. EP592888 and EP 0908712. Some cases involve the use of fluid sensors to measure fluid flow rates, as described, for example, in UK patent applications GB 2159631 and GB 2201001. Other processes involve the use of sensors of fluids in well applications as described, for example, in U.S. Patents/Application Nos. US 20100084132, 7707898, 6860325, and 6854341.
    Despite the development of fluid measurement techniques using fluid sensors, there continues to be a need to provide advanced techniques for determining fluid parameters usable in downhole applications. It may be desirable to provide techniques that determine fluid parameters related to fluid flow. It may still be desirable to provide techniques that are capable of performing accurate measurements even under adverse conditions (eg in severe conditions, low flow rates, etc.), preferably such techniques involve one or more of the following, among others. : measurement accuracy, optimized measurement processes, minimized components, reduced size, robust capabilities, reliability, operability even in severe downhole conditions, non-intrusive positioning, good response at even very low flow rates and speeds, detection of flow parameters across wider measurement range, simple packaging, resistance to aggressive environments (eg acid and downhole conditions), measurement methodologies adapted to the equipment used, adjustment to sensor size, operability in conditions of downhole (eg at elevated temperatures and/or pressures), etc. The present invention aims to meet these needs. SUMMARY OF THE INVENTION
    In one aspect, the present invention relates to a sensing element for determining at least one parameter of a fluid in a well with a downhole system deployed therein. The sensing element has a base that can be positioned over the downhole system, and a plurality of sensors that can be positioned on the base. Each of the sensors is thermally isolated from one another. Each of the sensors is capable of operating both as a heater to heat the fluid and as a temperature sensor to measure the fluid's temperature. The sensors are operatively interchangeable so that the sensors can selectively heat and measure the fluid temperature through which at least one fluid fluid parameter is determined.
    The downhole system may be a spiral piping system having an injection port for injecting fluid into the well, the base positioned over the injection port. The base can be positioned on an outer surface of the downhole system, or recessed beneath the outer surface of the downhole system. The outer surface of the base can also be flush with the outer surface of the downhole system, or it can be positioned on an inner surface of the downhole system to measure fluid passing therethrough.
    At least one of the sensors can be an RTD sensor comprising a resistor and a substrate. The RTD sensor can be encapsulated in the base, adhered to a thermally conductive pad, welded onto the thermally conductive pad, and/or glued onto the thermally conductive pad. The sensors can comprise a heater and a pair of thermocouple junctions. Thermocouple junctions can be connected by a conductor. The sensor system can further have at least one additional sensor for measuring at least one downhole parameter, such as viscosity, pressure, resistivity, acidity, and/or composition. Measured fluid parameters can be fluid direction or fluid velocity. Sensors can be operatively connected to a power source, such as a battery.
    In another aspect, the invention relates to a system for determining at least one parameter of a fluid in a well. The system has an implantable downhole system into the well, and a plurality of sensing elements for measuring at least one fluid parameter of the fluid in the well. Each of the plurality of sensor elements has a base that can be positioned over the downhole system and a plurality of sensors can be positioned on the base of the sensor. Each of the sensors is thermally isolated from one another. Each of the sensors is capable of operating both as a heater to heat the fluid and as a temperature sensor to measure the fluid's temperature. The sensors are operatively interchangeable so the sensors can selectively heat and measure the fluid temperature through which the fluid fluid parameters are determined.
    The downhole system may be a spiral piping system comprising an injection tool that has an injection port for injecting fluid into the well. The sensor elements may comprise at least one upstream sensor element positionable upstream of the injection opening and at least one downstream sensor element positionable downstream of the injection opening. The fluid parameter can be calculated from the fluid measurements taken by the upstream and downstream sensing elements. The fluid parameter can be the fluid direction and/or fluid velocity. The system and/or at least one of the sensing elements can further comprise at least one additional sensor for measuring downhole parameters. The downhole system may comprise a logging tool. The sensing elements are preferably capable of taking redundant measures for cross checking between them.
    Finally, in another aspect, the present invention relates to a method for determining at least one parameter of a fluid in a well. The method involves deploying a downhole system into the well with a plurality of sensing elements therein, each of the plurality of sensing elements comprising at least one heater and at least one temperature sensor. The method further involves taking at least one primary fluid measurement of the fluid in the well with a first portion of a plurality of sensing elements that operate as a heater and a second portion of a plurality of sensing elements that operate as a temperature sensor, having at least one secondary fluid measurement of the fluid in the well with the second portion of the plurality of sensing elements operating as a heater and the first portion of a plurality of sensing elements operating as a temperature sensor and determining at least one fluid parameter from the at least one primary and secondary fluid measurement.
    The determination step may involve calculating the fluid direction from measurements of primary and secondary fluids. The determination step may involve calculating a fluid velocity from measurements of primary and secondary fluids. The downhole system may comprise a spiral piping system and the method further involves injecting fluid from the spiral piping system into the well through an injection point of the spiral piping system. At least one of the sensing elements can be positioned upstream of the injection opening and at least one of the sensing elements can be positioned downstream of the injection opening. The method may further involve determining at least one fluid parameter by comparing the measurements taken by the fluid upstream and downstream of the sensing elements. The method may further involve measuring additional fluids for comparison with measurements of primary and secondary fluids.
    Techniques (eg, methods and systems) of the present invention will become more apparent upon review of the brief description of the drawings, the detailed description of the invention, and the claims that follow. BRIEF DESCRIPTION OF THE DRAWINGS
    So that the features and advantages of the present invention can be understood in detail, a more particular description of the invention can be had by reference to the embodiments thereof, which are illustrated in the accompanying drawings. These drawings are used to illustrate only typical embodiments of the present invention, and are not to be construed as limiting its scope, the invention may admit other equally effective embodiments. Figures are not necessarily to scale and certain views of the figures may be shown exaggerated in scale or schematic in the interest of clarity and brevity.
    Figure 1 is a schematic representation of a well site with a spiral piping system deployed within a well, the spiral piping system having a fluid detection system therein for determining fluid parameters.
    Figures 2A - 2C are schematic views of a portion of a spiral piping system, with its fluid sensing system positioned in a well, the fluid sensing system comprising a plurality of sensing elements. Figure 2A is a longitudinal view, partially in cross section, of the portion of the spiral piping system placed in the well. Figure 2B is a horizontal cross-sectional view of the portion of the spiral piping system placed in the well against a wall thereof with the sensing elements on an outer surface thereof. Figure 2C is a horizontal cross-sectional view of another part of the spiral piping system placed in the well with the sensing elements of an inner surface thereof.
    Figure 3 is a graph representing sensor measurements taken from the fluid detection system of Figure 2B.
    Figures 4A and 4B are schematic views of sensing elements. Figure 4A is a thermocouple detection element. Figure 4B is a dual element sensing element.
    Figures 5A and 5B are graphs illustrating sensor measurements.
    Figure 6 is a schematic graphical representation of the sensor measurements and the fluid flow generated therefrom.
    Figure 7 is a schematic view of a sensor.
    Figure 8 is a flowchart describing a method for determining fluid parameters. DETAILED DESCRIPTION OF THE INVENTION
    Presently preferred embodiments of the invention are shown in the above-identified figures and described in detail below. Embodiments are described with reference to certain characteristics and techniques of fluid detection systems deployed within a well of a spiral piping system. As such, the modalities described focus on advantages, such as fluid sensing capabilities, made available through the use of sensor systems positioned on treatment tools of the spiral piping system. However, a variety of configurations can be employed, with and without treatment tools. That is, a fluid sensing element can be used in addition to the spiral piping system. Regardless, the embodiments described herein are employed which include a well-delivered fluid sensing system via spiral piping, by employing a fluid sensing element for measuring fluid parameters. Thus, at a minimum, fluid parameters such as fluid direction (or fluid direction) and/or fluid velocity (or fluid velocity) can be determined.
    Figure 1 is a schematic representation of a well site 100 with a spiral piping system 102 deployed in a well 104. Spiral piping system 102 includes surface distribution equipment 106, including a spiral piping truck 108 with coil 110, positioned adjacent to well 104 at the location of well 100. Spiral tubing system 102 also includes coiled tubing 114 that can be used to pump a fluid into well 104. With spiral tubing 114 executed through a conventional flex-tube injector 116 supported by a mast 118 over the well 104, the spiral tubing 114 can then be advanced into the well 104. That is, the spiral tubing 114 can be forced down by means of valves and pressure control equipment 120 and into the well 104.
    In the spiral piping system 102, as shown, a treatment device 122 is provided for supplying fluid to the bottom of the well during application of treatments. Treatment device 122 is preferably detachable within 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.
    The spiral piping system 102 of Figure 1 is described as having a fluid sensing system 126 positioned over the injection port 124 for determining fluid parameters in well 104. The fluid sensing system 126 is preferably , set to determine fluid parameters such as fluid direction and/or velocity. Other well parameters can also be determined if desired.
    Continuing with reference to Figure 1, spiral piping system 102 may optionally be provided with a profiling tool 128 for downhole data collection. Profiling tool 128 as shown is provided near a downhole end of spiral pipe 114. Profiling tool 128 is preferably configured to obtain a variety of logging data from well 104 and formation layers surroundings 130, 132, such as those depicted in Figure 1. The logging tool 128 is preferably provided with a set of well log generating equipment or implements configured for production logging directed at the acquisition of well fluids and training measurements from which a global production profile can be developed. Other logging, data acquisition, tracking, imaging and/or other devices and/or capabilities can be provided to acquire data relating to a range of well characteristics. The collected information can be acquired on the surface at a high speed, and, where appropriate, subject to immediate use in real time (for example, through a treatment application).
    Referring still to Figure 1, spiral tubing 114 with treatment device 122, fluid sensing system 126 and profiling tool 128 is implanted therein at the bottom of the well. Once these components are used, the treatment, detection and/or profiling applications can be carried out by means of a control unit 136 on their surface. For example, treatment device 122 can be activated to release fluid from injection port 124, fluid sensing system 15/43 126 can be activated to collect fluid measurements, and/or profiling tool 128 can be activated. activated to record downhole data as desired. Treatment device 122, fluid detection system 126 and profiling tool 128 are preferably in communication with control unit 136 via a communication link (not shown) for pass signals (e.g. , energy, communication, control, etc.) between them.
    Control unit 136 is shown as computerized equipment attached to vehicle 108. However, control unit 136 may be of a more mobile variety, such as a portable computer. In addition, the application powered control can be pneumatic, hydraulic and/or electrical. Regardless, the nature of wireless communication allows the control unit 136 to control operation, even in circumstances where subsequent sets of different applications may be deployed downhole. That is, the need for a subsequent mobilization of control equipment can be eliminated.
    The control unit 136 can be configured to communicate wirelessly with a transceiver hub 138 of the coil of spiral pipe 110. The receiver hub 138 is configured for local (surface and/or downhole) and/or external, communication as wished. Preferably, the control unit 136 communicates with the detection system 126, and/or the profiling tool 128 for passing data between them. The control unit 136 can be provided with and/or coupled to databases, processors, and/or communicators for the collection, storage, analysis and/or processing of data collected from the detection system and/or the detection tool. profiling.
    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 as the system. of spiral tubing 102, treatment device 122, and fluid sensing system 126 of Figure 1. Figure 2A is a longitudinal view, partially in cross-section, showing fluid sensing system 226 positioned over the fluid sensing device. treatment 222. As shown, treatment device 222 has injection ports 224 for dispersing injection fluids into well 204, as schematically represented by the dashed arrows.
    Injection fluid may be dispersed in the treatment of a portion of well 204, such as payment zone 240, to increase fluid production therefrom.
    As illustrated in Figure 2A, stimulation fluid, such as acid, can be injected into well 204 near payment zone 240 (or oil production) by means of treatment tool 222. goes to pay zone 240, but is shown positioned at the bottom of the well from it. Precisely positioning injection ports 224 against the zone of interest can be a challenging task due to uncertainties that may exist in target depth and/or tool position. Sensing system 226 around injection port 224 can be adapted to measure the split flow upstream and downstream of injection ports 224 in the well. The determined fluid movement can be used to indicate where payment zone 240 is positioned relative to injection port 224. Once known, the position of treatment device 222 and injection ports 224 can be positioned to effect treatment , as wished.
    As fluid is released from the treatment device 222, the fluid flow is divided with an upstream portion of the injection fluid moving upstream and a downstream portion of the injection fluid moving downstream. The upstream part of the injection fluid moves upstream at a given speed, as indicated by the arrows marked V1. The downstream portion of the injection fluid travels downstream at a given speed, as indicated by the arrows marked V2. While fluid is described as flowing in a specific direction, it will be appreciated that fluid flow may vary according to given operating conditions.
    Although detection system 226 is shown in Figures 1 and 2A-2C as being positioned in a spiral piping system 102 to determine fluid parameters over an injection port 224, it should be noted that detection system 226 can also be used in other fluid flow applications such as detection of cross fluid flow between zones, production profiling (eg for single-phase velocity, or in conjunction with Flow Scanner Imaging (FSI) complementary to an automatic screwdriver in a low speed range), surface or downhole testing as part of a flow meter (eg low speed Venturi based flow meter applications), detection of leaks (eg with dynamic seals), with other tools where flow velocity measurements are desired, among others. The 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 casing (not shown).
    The detection system 226 is illustrated in Figure 2A as having a plurality of sensing elements 242a,b positioned over the treatment device 222. One or more sensing elements 242a,b are preferably positioned over the piping system at spiral 102 for taking fluid and/or other downhole measurements. Preferably, sensor elements 242a,b are positioned over injection port(s) 224 for measuring 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 once which is scattered.
    An upstream portion of the sensor elements 242a are described as being positioned on the treatment device 222 at a distance upstream thereto. A downstream portion of sensor elements 242b are described as being positioned on the treatment device 222 at a distance downstream thereof. The upstream sensing elements 242a and/or the downstream sensing elements 242b may be disposed radially around the treatment device 222. As shown in Figure 2B, the sensing elements 242a,b are preferably positioned at various radial locations x , y, z over the treatment device 222. While a specific configuration for the sensor elements 242a, b is shown in Figures 2A and 2B, it will be appreciated that one or 20/43 more sensor elements can be positioned at various locations (longitudinally and /or radially) over the spiral piping system 102, and/or well 104.
    At least some of the sensing elements 242a,b are preferably capable of sensing fluid parameters such as fluid direction and velocity. Preferably, more than one of the sensor elements 242a,b are capable of measuring fluid parameters. At least one of the sensor elements for measuring fluid parameters 242a is preferably positioned upstream of the injection opening 224, and at least one of the sensor elements for measuring fluid parameters 242b is preferably positioned downstream of the opening injection port 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 relationship between the upper and lower velocities and fluid direction obtained from measurements of the upstream and downstream sensing elements 242a, b can be used to generate real-time monitoring of where the fluid is going during treatment, such as will be described later. Other downhole parameters can also optionally be measured with the fluid detection system 226 and/or other sensors positioned over the wellbore.
    Comparison of multiple sensing elements 242a,b can be used to account for differences in measurements made by different sensing elements 242a,b. Preferably, a number of sensor elements 242a,b are used to provide sufficient redundancy and confidence in the measurement results. This redundancy can also reduce the seriousness of the impact where one or more sensing elements 242a,b can fail, such as in aggressive downhole environments that involve the use of acids. Multiple sensing elements 242a,b can also be used to generate desired 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. Additional sensing elements 242a,b are preferably provided to increase the reliability of the generated values.
    In some cases, it may be useful to consider the position of sensing elements 242a, b on the processing tool 222. The number of arrays (or sets of sensing elements 242a, b) as well as the number of sensing elements 242a, b per array , may vary as needed. As shown in Figure 2A, sensing elements 242a, b are positioned upstream and downstream to measure fluids as they pass upstream and downstream from injection ports 224. When using corresponding upstream and downstream sensing elements 242a, b, corresponding sensing elements 242a,b, are preferably positioned at equal distances from injection opening 224. Also, corresponding sensing elements 242a,b are also preferably identically matched. Corresponding sensing elements are preferably spaced at equal distances to eliminate any measurement differences.
    Multiple sensing elements 242a, b are also preferably positioned about the circumference of the tool at 90 degree x, y, z intervals, as shown in Figure 2B. As shown in Figure 2B, sensing elements 242b are positioned at radial locations x, y, and z over treatment device 222. Sensing element 242b at position x is against a wall 205 of well 204. The azimuthal arrangement of sensing elements 242a , b at x, y, z positions provides redundancy in case one side of the measurements is impeded.
    A problem can arise when the tool body (eg, treatment tool 222) is eccentric (or non-concentric) with the well 204 as shown in Figure 2B. In this case, some sensor elements 242bx located closer to the wall 205 of the well 204 may read a lower value than the flow of sensor elements 242by, 242bz positioned further away from the wall. In such cases, it may be desirable to eliminate measurements from potential clogged sensing elements, such as 242bx sensing elements.
    As shown in Figure 2B, sensor elements 242b are positioned on outer surface 223 of treatment tool 222. Sensor elements 242b may be flush with outer surface 223, a recess beneath outer surface 223, or extended a distance therefrom. . Preferably, sensing elements 242b are positioned such that each sensing element 242b contacts fluid for measurement thereof, but remains protected. To avoid damage in harsh downhole conditions, it may be preferred to reduce the protrusion of the sensing elements 242b of the treatment tool. As shown in Figure 2C, sensor elements 242b may also be positioned within the treatment tool 222, for example, on an inner surface 225 thereof.
    Figure 3 is a graph representing data from sensor 350 taken from sensor elements 242b, as illustrated in Figure 2B. Graph 350 represents the flow velocity (x-axis) as a function of the sensor output (y-axis) for sensor elements 242bx, 242by, and 242bz at the x, y, and z positions, respectively. As represented by the graph, the flow velocity of the 242by and 242bz sensing elements at the Y and Z positions are very different from the flow velocity of the 242bx sensing element at the x position. In other words, the readings from both the top sensing element 242bz and the 90 degree sensing element 242by are substantially consistent in determining flow velocity. However, the 242bx background sensing element has a flow velocity that is significantly lower.
    This graph indicates that sensor element 242bx at position x is pressed against wall 205 of well 204 and is unable to take proper readings. Thus, measurements described by line 242bx taken by element sensors 242b at position x can be ignored. Line measurements represented as 242by and 242bz taken by sensor elements 242b at y and z positions, respectively, can be combined using conventional analytical techniques (eg, curve fitting, flattening, etc.) to generate an imposed 244 flow. by placing multiple sensing elements 242a, b azimuthally around the circumference of a tool and detecting the lowest reading sensor (eg 242bx), the azimuth of the flow obstruction can be determined. The sensing element located opposite the lowest reading sensing element (eg 242by), or other combinations of sensing elements can then be used to perform the flow measurement.
    Figures 4A and 4B are schematic views of usable sensing elements 442p and 442q as the sensing elements 242a,b of Figures 2A and 2B. Each of the 442p,q sensor elements has a 454p,q heater and a 456p,q sensor, respectively, positioned on a 452 sensor base. The 456p,q sensor is preferably a capable temperature sensor (or temperature sensor) of measuring the temperature of the fluid.
    The 442p,q sensor elements are preferably calorimetry-type flow sensors (or flow meters) that have two sensor elements, that is, a sensor for the measurement of velocity (scalar sensor) and a sensor for the measurement directional (vector sensor). The 454p,q heater and 456p,q temperature sensors interact to operate as velocity (or scalar) and directional (or vector) sensors.
    To determine fluid velocity, the 442p,q sensing elements function as calorimetric sensors. The 454p,q heater (or hot body) of each 442p,q sensing 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 fluid velocity , as well as thermal properties. The heat dissipation rate of the 454p,q heater can be measured, and a flow velocity can be determined for a known fluid. The 454p,q heater generates heat (typically electricity), and dissipates heat to the fluid in contact. Heat generation rate and temperature are preferably easily measurable during operation.
    The 456p,q temperature sensor can be used to monitor the ambient temperature of the fluid, while the 454p,q heater is preferably capable of measuring its own temperature during heating. The difference between the heater temperature of 454p,q and the fluid's ambient temperature is defined as the temperature excursion. The AT temperature excursion can be written as follows:
    where: Ta - represents the ambient fluid temperature measured by the temperature sensor; Th - represents the heater temperature, and
    The temperature excursion is proportional to the heater power at a given flow condition.
    The thermal conductance Gth can be calculated according to the following expression:
    I where: P - represents the heating power at steady state.
    The inverse of this proportionality (or thermal conductivity) correlates with the velocity of the flow Vflow, since Vflow is a function of Gth.
    The measurements taken by the 454p,q calorimetric sensor elements essentially obtain the thermal conductance of the heater fluid. As predicted by Equation 1, thermal conductance is determined from three quantities: P (the heater power), Th (the heater temperature) and Ta (the fluid ambient temperature). All are preferably measured in steady state. Theoretically, the amount of energy or temperature excursion used during the measurement should be irrelevant to the resulting thermal conductivity. However, energy excursion and temperature can affect accuracy as all physical measurements usually have limits. In some cases, such as the configuration in Figure 4B, a ΔT of a few degrees in Kelvin (K) may be considered adequate.
    A measurement strategy may involve constant excursion or constant power. For the constant excursion strategy, the energy sent to the heater can be regulated by electronics (eg control unit 136) such that the heater temperature can be maintained at a constant excursion above the fluid environment. In the steady state, the measured energy is directly proportional to the thermal conductivity. For the constant power strategy, the heater can be powered with a constant, predetermined power, while the heater temperature Th varies and can be determined by the flow rate. In the steady state, the temperature excursion is inversely proportional to the thermal conductivity.
    Figure 5A is a graph 657 which depicts a typical flow response of a calorimetric sensor, such as sensor elements 442a,b depicted in Figures 4A and 4B. The resulting thermal conductance versus flow curve 658 demonstrates that thermal conductivity is considered non-linear with flow velocity. The thermal conductance versus flow curve 658 is, however, monotonic. Therefore, the correlation can be established to reverse the measurement and the flow velocity can thus be obtained as described in Equations 1 3.
    The flow velocity measurement is a measure of the thermal conductivity between the 454p,q heater and the fluid. The thermal conductivity measurement can be determined with constant temperature excursion (ΔT) or constant heater power. The constant temperature excursion can regulate the temperature. Constant heating power can regulate the power. The two are preferably equivalent, as both can be used to measure thermal conductivity. In any case, the measurement preferably involves two sensor elements, such as the 454p,q heater and the 456p,q temperature sensor.
    Returning to Figures 4A and 4B, the sensing elements 442p,q can also act as scalar sensors to determine the direction of the fluid. The 442p,q sensor elements are preferably capable of acting as both calorimetric sensors for determining fluid velocity and vector sensors for measuring fluid direction. Calorimetric sensors are typically blind to the direction of the fluid. Typical calorimetric sensors can respond to fluid velocity regardless of direction. The fluid direction can be acquired by a second measurement, such as vector sensors capable of detecting the fluid direction. The fluid direction can also be acquired, for example, the sensor elements 442p,q of Figures 4A and 4B configured for measuring both fluid velocity and directions. Physics enabling directional detection may also involve detecting asymmetry in temperature between upstream and downstream sensing elements, such as upstream sensing elements 242a and downstream sensing elements 242b of Figure 2A.
    Figures 4A and 4B show sensing element 442p,q configurations capable of sensing both fluid flow and direction. Figure 4A shows a thermocoupler (TC) sensing element of 442p dual sensing elements. Figure 4B depicts a dual sensing element 442q. The base 452 for each sensor element 442p,q is preferably sized to accommodate the heater 454p,q, the sensor 456p,q and/or other devices therein.
    Preferably, the base 452 has a minimum thickness, or a recess in the downhole tool, to prevent damage to the well 104. The base of the sensor 452 is positionable in the downhole, for example, over the treatment device 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. The base can be made of epoxy, PEEK molding or other material.
    Heater 454p,q and temperature sensors 456p,q are preferably positioned in proximity to base 452, but are thermally insulated from each other. Since the 454p,q heater creates a temperature anomaly in the fluid, the 456p,q temperature sensor is preferably provided with sufficient thermal insulation from the 454p,q heater to prevent the 456p,q temperature sensors, q are disturbed by heat flow from the 454p,q heater or thermal coupling with the 454p,q heater, which can result in a measurement value that may otherwise be erroneous. The temperature of the 456p,q sensor can optionally be placed in a separate package away from the 454p,q heater.
    The TC sensor element 442p of Figure 4A is depicted as having a pair of TC junctions (or sensors) 456p1,2 on each side of a heating pad (or heater) 454p. The TC 456p1,2 junctions are connected by a 460 metallic wire. Each TC 456p1,2 junction has a TC 458p pad with conduits 462a, b extending therefrom. Conduits 462 are also preferably wires operatively connected to a controller 436 for operation therewith.
    The 456p TC junctions positioned on either side of the 454p heater can be used to detect a temperature imbalance between them and convert it to a TC voltage. A small voltage will be present if the two TC 456p1,2 junctions are at different temperatures. The 456p1,2 TC junctions are preferably positioned very close to the 454p heater (one on each side) for maximum temperature contrast. At zero flow, the 454p heater can heat both TC 456p1 junctions. Heating, however, preferably does not produce voltage as TC 456p1, 2 junctions, preferably only respond to temperature differences between the TC 456p1 junctions. two.
    Two small 464p metal pads are described as supporting each of the 456p1 TC joints, 2. 464p metal pads can be provided to improve the thermal contact between the 456p1, 2 TC joints and the fluid. The 464p metal pads can be useful, especially in cases where the TC 456p1,2 joints are small in size. The 464p metal pads and 456p1 TC joints can be held together using thermal adhesives such as silver epoxies. The metal pads 464p are preferably positioned in alignment with the heater 454p, thus defining a flow line 466p along the sensor elements 442p, as indicated by the arrow.
    Typical TC voltage (y-axis) as a function of flow velocity (x-axis) is shown in graph 659 of Figure 5B. The graph presents an odd function of the flow velocity, as measured by the TC 456p1,2 junctions. The magnitude of the maximum value near zero flow gradually decreases with increasing velocity. At zero crossing, the output of the TC signal undergoes a sharp change from negative to positive polarity, as indicated by curves 661a, b, respectively. Signal polarity can be used to detect the direction of the fluid, and can be particularly useful, especially around zero flow.
    The temperature profile along a flux stream of eg 442p sensing element is shown schematically in Figure 6. Figure 6 is a graph representing 663 temperature (y-axis) versus velocity (x-axis). As depicted by this graph, the heater 454p generates a constant heat Th measurable by the TC junction 456p 1, 2 on either side of it. Heat from the 454p heater is carried by the downstream fluid forming a hot current. Velocities V1, V2 and V3 are measured in, for example, different time intervals. The visibility of the thermal gradient may depend on speed. The thermal gradient between upstream and downstream is detectable with the 442p sensor element. This creates a temperature contrast between the upstream and downstream 456p1 TC junctions. This indicates that flow is advancing towards the 456p1,2 TC junctions, thus providing direction. By detecting asymmetry between the TC 456p1, 2 junctions, the fluid direction can be determined as indicated by the arrow.
    The dual element sensor element 442q of Figure 4B is shown as having two identical elements (sensors/heaters) 456q/454q. The 456q/454q sensors / heaters are pictured as an M element and an N element in the 442q sensor element. Preferably, heater 454q and sensor 456q (and therefore elements of M and N) are interchangeable in function and operation. In such cases, sensor 456q is preferably capable of performing heater functions and heater 454q is capable of performing sensor functions. Elements M and N are operatively connected via connections 455 to controller 436 for operation therewith.
    In some configurations, the desired measurement can be operated in a self-referenced mode in which a single M or N element plays a dual role, both as a heater and as a temperature sensor. In such cases, the heater and temperature sensor can use a time multiplexing system. Preferably, the role of the 454q heater and the 456q temperature sensor can be reassigned as needed 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 adapted to the requirements of the particular application.
    A temperature asymmetry between identical elements M and N is preferably detectable by the dual sensing element 442q. The two identical elements M and N are preferably positioned along a fluid flow line, as indicated by the arrow. Elements M and N are also preferably positioned in close proximity, for example, within the same base (or pack) 452.
    The measurement by the sensing element of Figure 4B can be accomplished using various methods. A first method involves measuring the heater power in flow using element M as the heater and element N as the temperature sensor. After a stable reading is achieved, the roles of the M and N elements are swapped and the measurement is repeated. By comparing the power of the two measurements, the direction of the fluid can be determined. The heater that consumes the most energy is located upstream, as long as the flow does not vary during it. This strategy may be less reliable at low speed as power decreases in both cases. A second method that can be used involves measuring both heating elements M and N simultaneously with the same amount of power. The measurements of each element can be compared. Whichever element reveals higher temperature points in the fluid direction. A third method that can be used involves observing the temperature of element M while turning element N on and off with a certain amount of power. If a change in temperature is noted, element N can be assumed to be element M upstream. No change can suggest otherwise.
    With the first two methods, in which quantities are compared across the elements M and N, a good combination of the characteristics of the two elements M, N is preferred to eliminate potential errors. The combination of elements can be achieved by calibration and normalization. The third method, on the other hand, may not need as good as a match. Two sensor elements are usable, for example, for bidirectional flow.
    When the 456p,q temperature sensor and the 454p heater, of Figures 4A and 4B, preferably reside in the same package (e.g., due to space constraints), the 456p,q temperature sensor is preferably positioned upstream of the 454p heater, q (or Element M is upstream of element N). If the flow goes in both directions, the temperature sensor, 456p,q, and the heater 454p,q, (or M and N elements) can be positioned in a side-by-side (or flow line) configuration according to the flow of the fluid, as shown in sensing elements 442p,q of Figures 4A and 4B.
    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, it should be noted that multiple 454p,q and/or 456p,q sensors can be provided. Additional sensors and/or other devices can be incorporated into the sensor elements and/or used in combination with them. In multiple sensor systems involving heaters, one 456p,q temperature sensor can serve multiple 454p,q heaters. For example, in some cases where more complex flow exists, multiple sensing elements with more than two elements (eg M, N, P, D...) is preferred. As shown in Figure 4B, a third element S can optionally be provided. In another measurement method, the three or more elements (eg M, N, 0) can be used to detect fluid direction by heating a middle element and compare the temperature between upstream and downstream elements between they.
    As shown, the sensing elements 442p,q of Figures 4A and 4B (and/or the heaters, sensing elements and/or other components used in and/or with the same) are preferably operatively connected to the controller 436 for supply. power, data collection, control and/or otherwise operate the sensor element 442p,q. Controller 436 may be, for example, profiling tool 128, control unit 136 and/or other electronics capable of providing power, data collection, control and/or otherwise operating temperature sensors 456p,q , heater 456p,q, and/or other elements of sensing elements 442p,q. 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 1 can provide power to it. Such electronic devices can be internal and/or external to the sensing elements. Communication devices can be provided for wired and/or wireless, sensing elements coupled to the bottom of the well and/or surface communication devices for communicating therewith. In some cases, communication devices such as transmitters (not shown) may be provided in sensing elements. In other cases, the sensing elements can be connected to the profiling tool 128 (Figure 1) or other communication devices, as desired.
    The sensing elements are also preferably operatively linked to and/or in communication with databases, processors, analyzers, and/or other electronic devices that allow manipulating and collecting data in this way. Power, communication devices and/or electronics can be used to manipulate data from sensing elements as well as other sources. The analyzed data can be used to decide on well location and well operation. In some cases, data can be used to control well operation. Some such control can be done automatically and/or manually as desired.
    While the heater and temperature sensor elements may be physically identical, the sensor itself can come in a variety of types, shapes and/or shapes. Figure 7 depicts a sensor 770 usable as an element of the sensor elements 454p,q of Figure 4A and/or 4B. Figure 7 shows a 770 sensor can be used as the 454q heater and/or 456q temperature sensors, as M, N and/or O elements, or in combination with the same. As shown, sensor 770 can be positioned on base 452. Sensor 770 can be operatively connected to controller 436 via wires 774 for operation with the same in the same manner as described above for sensor elements 442p,q.
    Preferably, the 770 sensor is an RTD type sensor with a resistance that varies with temperature. RTD are mainly used for temperature sensor purposes. However, sensor 770 preferably can also generate heat when currents pass through. Thus, a temperature sensor can be used for both a heater and a temperature sensor (for example, 454p,q, and 456p,q of Figures 4B). A thin-film type RTD capable of being used both as a heater and a temperature sensor is preferably used so that it can alternately function as the M, N and/or O element of figure 4B, when necessary.
    As shown in Figure 7, surface sensor 770 positioned on base 452 has a forward (or contact surface) 772 positionable adjacent to the fluid for taking measurements therefrom. A common type of RTD employs platinum in the form of a wire or thin film (or resistance) 774 deposited onto a heat conducting substrate 776, such as sapphire, or ceramic d. Wire 774 is positioned on film 776 and extends therefrom for operative connection with controller 436. Heat-conducting substrate 776 can be glued or bonded to a thin layer 778 (made of, for example, Inconel or ceramic substrate) by a thermally conductive adhesive 780, such as epoxy, silver, or by brazing. Preferably such a bond provides low thermal resistance.
    As illustrated, RTDs are wrapped in protective packaging, but they can differ by thermal mass and therefore response time. The shape of the pad 778 can be square, circular, or other shape capable of supporting the RTD in the base 452. The pad 778 is preferably about 10 mm (or more or less) in size, and of sufficient thickness for the mechanical feasibility. The thickness and material selected can determine the thermal contact performance of the heater fluid.
    The surface sensor 770 can be configured with a large surface area for fluid contact and/or large thermal mass for the passage of heat therethrough. The greater thermal mass can result in a relatively slower response. However, thermal mass can also help to reduce (for example, averaging) variations in spurious readings caused by turbulence. Sensor electronics can also be provided to reduce spurious variations.
    The 770 sensor and/or the 442q sensor elements may be configured on a surface (or non-intrusive) that forms with a low profile (or thickness) as shown in Figures 7 and 4B. The 770 sensor and/or 442q sensor elements are preferably positioned in the downhole through a downhole tool (e.g., spiral piping system 102 of Figure 1) that extends only a short distance (if any) from the same. This low profile or non-intrusive surface shape can be provided to reduce disturbance from the fluid flowing through the sensor, while allowing fluid measurement. In addition, the shape of the low profile surface can also be configured to eliminate the amount of overhang from the downhole tool, and therefore the potential damage to it.
    Figure 8 is a flowchart describing a method for determining fluid parameters 800. The method can be used, for example, to determine at least one parameter of a fluid in the well of Figure 1. The method involves deploying an 880 downhole system, such as a spiral piping system, to a well. with a plurality of sensing elements in it. Where the downhole system is a spiral piping system, the method may also involve injecting 882 fluid from the spiral piping into the well through an injection port of the spiral piping.
    The method may further involve taking 884 at least one primary fluid measurement of the fluid in the well with a first portion of a plurality of sensing elements that operate as a heater and a second portion of a plurality of sensing elements that operate as a temperature sensor. , and taking 866 at least one secondary fluid measurement of the fluid in the well with the second portion of a plurality of sensing elements operating as a heater and the first portion of a plurality of sensing elements operating as a temperature sensor .
    Various combinations of primary and secondary fluid measurements can be determined from the collected measurements. At least one fluid measurement can be determined (or calculated) 888 based on the initial and secondary fluid measurements. The method may also involve comparing the primary and secondary fluid measurements 890 taken by at least one upstream element and at least one downstream sensing element, taking 892 additional fluid measurements for comparison with the measurements of at least one of the primary and secondary fluids and 894 analysis of the fluid measurements.
    The method may also involve steps to calibrate the storage, processing, analysis of information, and/or manipulating measurements and/or other data collected by the sensing and/or sensing elements. The process can also be repeated 896 as desired.
    It should be understood from the above description that various modifications and alterations can be provided. For example, the one or more fluid and/or other sensing elements may be positioned around the spiral piping system and/or other portions of the well location to measure and/or collect data.
    The foregoing description has been presented with reference to presently preferred embodiments. Those skilled in the art and technology to which these modalities belong will appreciate that alterations and modifications to the described structures and methods of operation can be practiced without significantly departing from the principle and scope of these modalities. Furthermore, the foregoing description should not be read as including only the precise structures described and shown in the accompanying drawings, but should be interpreted as consistent with, and in support of, the following claims, which should be more complete in scope and more fair.
    This description is intended for illustrative purposes only and should not be interpreted in a limiting sense. The scope of the present invention is to be determined solely by the language of the following claims. The term "comprising" in the claims is intended to mean "including at least" such that the recited listing of elements of a claim are an open group. "An", "an" and other singular terms are intended to include the plural forms thereof, unless specifically excluded.
    权利要求:
    Claims (13)
    [0001]
    1. SENSOR ELEMENT (242 a,b) TO DETERMINE AT LEAST ONE PARAMETER OF A FLUID IN A WELL (104) HAVING A WELL BOTTOM SYSTEM IMPLANTED IN IT, the sensing element (242 a,b) comprising: a base ( 452) positionable over the downhole system, wherein the base (452) is flush with an outer surface (223) of the downhole system (222); and a plurality of sensors (442 p,q) coupled to the base (452); wherein each of the plurality of sensors is thermally isolated from one another, each of the plurality of sensors operating both as a heater (454) to heat the fluid and as a temperature sensor (456) to measure a temperature of the fluid, the the plurality of sensors (442 p,q) operatively interchangeable so that the plurality of sensors (442 p,q) can selectively heat and measure the temperature of the fluid, whereby at least one fluid parameter of the fluid is determined; the sensor element (242 a, b) characterized in that the downhole system is a spiral piping system (102) having an injection opening (224) for injecting fluid into the well (104), the base (452) positionable around the injection opening (224).
    [0002]
    Sensor element (242a,b) according to claim 1, characterized in that at least one of the plurality of sensors comprises an RTD sensor (770), wherein the RTD sensor comprises a resistor (774) positioned on a substrate ( 776).
    [0003]
    Sensor element (242a,b) according to claim 1, characterized in that at least one of the plurality of sensors comprises an RTD sensor (770), and wherein the RTD sensor is encapsulated in the base (452) or wherein the RTD sensor is adhered to a thermally conductive pad (778).
    [0004]
    Sensor element (242a,b) according to claim 1, characterized in that the at least one fluid parameter comprises fluid direction or fluid velocity.
    [0005]
    Sensor element (242a,b) according to claim 1, characterized in that the downhole system comprises a logging tool (128).
    [0006]
    Sensor element (242a,b) according to claim 1, characterized in that the plurality of sensor elements (242a,b) comprise at least one sensor element (242a) upstream and positionable upstream of the injection opening (224 ) and at least one downstream sensor element (242b) positionable downstream of the injection opening (224).
    [0007]
    Sensor element (242a,b) according to claim 6, characterized in that the fluid parameter is calculated from the temperature measured by the at least one sensor element (242a) upstream and the at least one sensor element (242b ) downstream.
    [0008]
    Sensor element (242a,b) according to claim 1, characterized in that it further comprises an additional sensor (242a,b) for measuring an additional downhole parameter.
    [0009]
    Sensor element (242a,b) according to claim 1, characterized in that at least one of the sensor elements further comprises an additional sensor (242a,b) for measuring an additional downhole parameter.
    [0010]
    10. Sensor element (242 a, b), according to claim 1, characterized in that the sensor elements perform redundant measurements.
    [0011]
    11. METHOD FOR DETERMINING AT LEAST ONE PARAMETER OF A FLUID IN A WELL, the method comprising: deploying a downhole system (102) in the well with a plurality of sensing elements (242 a,b) in it, each of the plurality of sensing elements comprising at least one heater (454) and at least one temperature sensor (456); taking at least one primary fluid measurement of the fluid in the well with a first portion of the plurality of sensing elements operating as a heater (454) and a second portion of the plurality of sensing elements operating as a temperature sensor (456); taking at least one secondary fluid measurement of the fluid in the well with the second portion of the plurality of sensing elements operating as a heater (454) and the first portion of the plurality of sensing elements operating as a temperature sensor (456); and characterized in that the method further comprises determining a fluid direction or fluid velocity from the at least one primary and secondary fluid measurements.
    [0012]
    12. The method of claim 11, wherein the downhole system comprises a spiral piping system (102) and the method further comprises injecting fluid from the spiral piping system into the well through an opening injection (224) of the spiral piping system.
    [0013]
    The method of claim 11, further comprising taking additional fluid measurements for comparison with the at least one primary and secondary fluid measurements.
    类似技术:
    公开号 | 公开日 | 专利标题
    BR112012031689B1|2021-07-20|SENSOR ELEMENT TO DETERMINE AT LEAST ONE PARAMETER OF A FLUID IN A WELL HAVING A WELL BOTTOM SYSTEM IMPLEMENTED IN IT AND METHOD TO DETERMINE AT LEAST ONE PARAMETER OF A FLUID IN A WELL
    BR112013032103B1|2020-07-14|METHOD
    US7240547B2|2007-07-10|Method and apparatus for measuring fluid properties
    US10309814B2|2019-06-04|Methods and apparatus for determining downhole fluid parameters
    US9790782B2|2017-10-17|Identification of thermal conductivity properties of formation fluid
    CN104568226A|2015-04-29|Ocean floor heat flow long-time observing probe and using method thereof
    US9791595B2|2017-10-17|Identification of heat capacity properties of formation fluid
    CA2794364A1|2013-04-28|A downhole logging tool
    同族专利:
    公开号 | 公开日
    US8616282B2|2013-12-31|
    MX2012008311A|2012-08-03|
    EP2572171B1|2021-05-12|
    BR112012031689A2|2016-11-08|
    WO2012000654A1|2012-01-05|
    US20110315375A1|2011-12-29|
    EP2572171A1|2013-03-27|
    MY179596A|2020-11-11|
    DK2572171T3|2021-08-16|
    引用文献:
    公开号 | 申请日 | 公开日 | 申请人 | 专利标题
    DE3213902C2|1982-04-15|1987-09-24|Eckart Dr.Rer.Nat. 2300 Kiel De Hiss|
    DE3316837C2|1983-05-07|1986-06-26|Dornier System Gmbh, 7990 Friedrichshafen|Device for generating shock waves by means of a spark gap for the contact-free crushing of concrements in the bodies of living beings|
    DE3419504A1|1984-05-25|1986-01-23|Günther Dipl.-Ing. 2201 Kollmar Weber|FLOW GUARD|
    DE3820025C2|1988-06-13|1992-01-02|Eckart Dr. 2300 Kiel De Hiss|
    DE4017877C2|1990-06-02|1996-07-25|Hiss Eckart|Sensor for monitoring the flow of a flowing medium|
    JP3094170B2|1991-03-27|2000-10-03|株式会社小松製作所|Electrode structure of metal particle detection sensor|
    DE4232804C1|1992-09-30|1994-02-03|Hiss Eckart|Safety sensor|
    US5551287A|1995-02-02|1996-09-03|Mobil Oil Corporation|Method of monitoring fluids entering a wellbore|
    US5984641A|1997-05-05|1999-11-16|1273941 Ontario Inc.|Controller for oil wells using a heated probe sensor|
    DE59812891D1|1997-09-16|2005-08-04|Siemens Schweiz Ag Zuerich|temperature sensor|
    US6227045B1|1999-09-16|2001-05-08|Us Army Corps Of Engineers As Represented By The Secretary Of The Army|Groundwater flow measuring system|
    US6629564B1|2000-04-11|2003-10-07|Schlumberger Technology Corporation|Downhole flow meter|
    CA2329672C|2000-12-27|2009-12-22|Donald W. Kirk|Bifurcated electrode of use in electrolytic cells|
    GB2383136B|2001-12-14|2004-01-14|Schlumberger Holdings|Flow characteristic measuring apparatus and method|
    US6801039B2|2002-05-09|2004-10-05|Baker Hughes Incorporated|Apparatus and method for measuring mud resistivity using a defocused electrode system|
    EP1439388A1|2003-01-20|2004-07-21|Ecole Polytechnique Fédérale de Lausanne |Device for measuring the quality and/or the degradation of a fluid, especially of edible oil|
    DE10302251B4|2003-01-22|2013-03-07|Sensorentechnologie Gettorf Gmbh|Flow Sensor|
    US7258005B2|2004-02-06|2007-08-21|David Scott Nyce|Isolated capacitive fluid level sensor|
    US9540889B2|2004-05-28|2017-01-10|Schlumberger Technology Corporation|Coiled tubing gamma ray detector|
    US8522869B2|2004-05-28|2013-09-03|Schlumberger Technology Corporation|Optical coiled tubing log assembly|
    US7891416B2|2005-01-11|2011-02-22|Amp-Lift Group Llc|Apparatus for treating fluid streams cross-reference to related applications|
    US8122951B2|2005-02-28|2012-02-28|Schlumberger Technology Corporation|Systems and methods of downhole thermal property measurement|
    US7654318B2|2006-06-19|2010-02-02|Schlumberger Technology Corporation|Fluid diversion measurement methods and systems|
    US7412881B2|2006-07-31|2008-08-19|Chevron U.S.A. Inc.|Fluid flowrate determination|
    US7644611B2|2006-09-15|2010-01-12|Schlumberger Technology Corporation|Downhole fluid analysis for production logging|
    US7731421B2|2007-06-25|2010-06-08|Schlumberger Technology Corporation|Fluid level indication system and technique|
    GB2451818B|2007-08-11|2010-03-31|Schlumberger Holdings|Open bore turbine flowmeter|
    US7520160B1|2007-10-04|2009-04-21|Schlumberger Technology Corporation|Electrochemical sensor|
    US8027794B2|2008-02-11|2011-09-27|Schlumberger Technology Corporaton|System and method for measuring properties of liquid in multiphase mixtures|
    US7640133B2|2008-04-25|2009-12-29|Schlumberger Technology Corporation|Method, apparatus and system for characterizing two phase fluid flow in an injection well|
    US7637167B2|2008-04-25|2009-12-29|Schlumberger Technology Corporation|Apparatus and method for characterizing two phase fluid flow|
    EP2341214A1|2009-12-29|2011-07-06|Welltec A/S|Thermography logging tool|US20140130591A1|2011-06-13|2014-05-15|Schlumberger Technology Corporation|Methods and Apparatus for Determining Downhole Parameters|
    RU2577568C1|2011-12-06|2016-03-20|Шлюмбергер Текнолоджи Б.В.|Method for interpreting well yield measurements during well treatment|
    WO2013171721A1|2012-05-18|2013-11-21|Services Petroliers Schlumberger|Methods and apparatus for determining downhole fluid parameters|
    BR102014011707B1|2013-05-17|2021-06-15|Schlumberger Technology B.V.|MEASUREMENT DEVICE, WELL BOTTOM TOOL, AND METHOD|
    US11149505B2|2013-08-22|2021-10-19|Halliburton Energy Services, Inc.|Drilling fluid flow measurement in an open channel fluid conduit|
    EP3049618B1|2013-09-27|2018-05-09|National Oilwell Varco, L.P.|Downhole temperature sensing of the fluid flow in and around a drill string tool|
    US9631474B2|2013-11-25|2017-04-25|Baker Hughes Incorporated|Systems and methods for real-time evaluation of coiled tubing matrix acidizing|
    EP2985409A1|2014-08-12|2016-02-17|Services Petroliers Schlumberger|Methods and apparatus of adjusting matrix acidizing procedures|
    EP2985410A1|2014-08-12|2016-02-17|Services Petroliers Schlumberger|Methods and apparatus for determining downhole fluid parameters|
    RU2599740C1|2015-06-29|2016-10-10|Общество с ограниченной ответственностью "МИКС"|Method of measuring flow rate of fluid in the well and a self-contained well thermal anemometer for its implementation|
    US10934822B2|2016-03-23|2021-03-02|Petrospec Engineering Inc.|Low-pressure method and apparatus of producing hydrocarbons from an underground formation using electric resistive heating and solvent injection|
    US10301903B2|2016-05-16|2019-05-28|Schlumberger Technology Corporation|Well treatment|
    EP3258060B1|2016-06-13|2019-12-11|Services Petroliers Schlumberger|Fluid component determination using thermal properties|
    US10689979B2|2016-06-16|2020-06-23|Schlumberger Technology Corporation|Flowline saturation pressure measurement|
    US10704379B2|2016-08-18|2020-07-07|Schlumberger Technology Corporation|Flowline saturation pressure measurements|
    法律状态:
    2018-12-26| B06F| Objections, documents and/or translations needed after an examination request according [chapter 6.6 patent gazette]|
    2019-08-13| B06U| Preliminary requirement: requests with searches performed by other patent offices: procedure suspended [chapter 6.21 patent gazette]|
    2020-04-07| B06A| Patent application procedure suspended [chapter 6.1 patent gazette]|
    2020-10-13| B07A| Application suspended after technical examination (opinion) [chapter 7.1 patent gazette]|
    2021-05-11| B09A| Decision: intention to grant [chapter 9.1 patent gazette]|
    2021-07-20| B16A| Patent or certificate of addition of invention granted [chapter 16.1 patent gazette]|Free format text: PRAZO DE VALIDADE: 20 (VINTE) ANOS CONTADOS A PARTIR DE 23/06/2011, OBSERVADAS AS CONDICOES LEGAIS. PATENTE CONCEDIDA CONFORME ADI 5.529/DF, QUE DETERMINA A ALTERACAO DO PRAZO DE CONCESSAO. |
    优先权:
    申请号 | 申请日 | 专利标题
    US12/824,474|2010-06-28|
    US12/824,474|US8616282B2|2010-06-28|2010-06-28|System and method for determining downhole fluid parameters|
    PCT/EP2011/003184|WO2012000654A1|2010-06-28|2011-06-23|System and method for determining downhole fluid parameters|
    [返回顶部]