WO2016025435A1 - Procédés et appareil pour déterminer des paramètres de fluide de fond - Google Patents

Procédés et appareil pour déterminer des paramètres de fluide de fond Download PDF

Info

Publication number
WO2016025435A1
WO2016025435A1 PCT/US2015/044582 US2015044582W WO2016025435A1 WO 2016025435 A1 WO2016025435 A1 WO 2016025435A1 US 2015044582 W US2015044582 W US 2015044582W WO 2016025435 A1 WO2016025435 A1 WO 2016025435A1
Authority
WO
WIPO (PCT)
Prior art keywords
fluid
temperature
heater
sensor
downhole
Prior art date
Application number
PCT/US2015/044582
Other languages
English (en)
Inventor
Elena BORISOVA
Tullio Moscato
Alain NGUYEN-THUYET
Patrice Ligneul
Original Assignee
Schlumberger Canada Limited
Services Petroliers Schlumberger
Schlumberger Holdings Limited
Schlumberger Technology B.V.
Prad Research And Development Limited
Schlumberger Technology Corporation
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Application filed by Schlumberger Canada Limited, Services Petroliers Schlumberger, Schlumberger Holdings Limited, Schlumberger Technology B.V., Prad Research And Development Limited, Schlumberger Technology Corporation filed Critical Schlumberger Canada Limited
Publication of WO2016025435A1 publication Critical patent/WO2016025435A1/fr

Links

Classifications

    • E—FIXED CONSTRUCTIONS
    • E21—EARTH DRILLING; MINING
    • E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B47/00—Survey of boreholes or wells
    • E21B47/10—Locating fluid leaks, intrusions or movements
    • E21B47/103—Locating fluid leaks, intrusions or movements using thermal measurements
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH DRILLING; MINING
    • E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B47/00—Survey of boreholes or wells
    • E21B47/06—Measuring temperature or pressure
    • E21B47/07—Temperature

Definitions

  • This disclosure relates generally to hydrocarbon production and exploration and, more particularly, to methods and apparatus to determine downhole fluid parameters.
  • An example method includes measuring a first temperature of a downhole fluid and providing power to a heater comprising a surface exposed to the downhole fluid to heat the surface to a second temperature. The second temperature higher than the first temperature. The example method also includes monitoring the following parameters:an amount of power provided to the heater; and a temperature excursion between the first and second temperatures. The example method includes, based on at least one of these parameters, identifying a composition of the downhole fluid.
  • An example apparatus comprising a downhole tool; at least a sensor to be exposed to a downhole fluid and a processor to cause the or one of the sensors to measure a first temperature of the downhole fluid and, to heat a surface of the or one of the sensors exposed to the downhole fluid to a second temperature.
  • the processor to monitor an amount of power provided to the heating sensor and a temperature excursion between the first and second temperatures, and based on at least one of the amount of power provided or the temperature excursion, the processor to identify a composition of the downhole fluid.
  • FIG. 1 illustrates an example system in which embodiments of the methods and apparatus to determine downhole fluid parameters can be implemented.
  • FIG. 2 illustrates an example system in which embodiments of the methods and apparatus to determine downhole fluid parameters can be implemented.
  • FIG. 3 illustrates an example system in which embodiments of the methods and apparatus to determine downhole fluid parameters can be implemented.
  • FIG. 4 illustrates an example system in which embodiments of the methods and apparatus to determine downhole fluid parameters can be implemented.
  • FIG. 5 illustrates an example system in which embodiments of the methods and apparatus to determine downhole fluid parameters can be implemented.
  • FIG. 6 illustrates an example system in which embodiments of the methods and apparatus to determine downhole fluid parameters can be implemented.
  • FIG. 7 illustrates an example system in which embodiments of the methods and apparatus to determine downhole fluid parameters can be implemented.
  • FIG. 8 shows a graph of natural convection near a vertical isothermal wall generated based on the examples disclosed herein.
  • FIG. 9 shows results obtained using the examples disclosed herein.
  • FIG.10 illustrates an example system in which embodiments of the methods and apparatus to determine downhole fluid parameters can be implemented.
  • FIG. 11 shows results obtained using the examples disclosed herein.
  • FIGS. 12 and 13 are example processes that can be implemented using the methods and apparatus to determine downhole fluid parameters.
  • FIG. 14 is a schematic illustration of an example processor platform that may be used and/or programmed to implement any or all of the example methods and apparatus described herein.
  • downhole fluids such as oil, gas and/or water may be differentiated and/or identified by exposing a thermal sensor to a fluid, measuring a temperature of the fluid using the thermal sensor and heating the fluid using the thermal sensor.
  • the methods according to the disclosed examples can be used in connection with a fluid having substantially a zero velocity (also referred to as “stagnant”) or with a fluid having a non-negligible velocity.
  • the disclosed examples may be used in connection with fluids have any velocity (e.g., zero velocity, non-negligible velocity, non-zero velocity, etc.).
  • fluid having a non-negligible velocity may be a fluid in which global movement or convection of the downhole fluid is forced with the help of a pump or other injection or suction device(s).
  • stagnant fluid may be fluid in which local movements are induced based on interactions of the fluid with its surroundings.
  • the fluid thermally expands and its density changes causing gravity driven convection, natural convection and/or buoyancy driven flow.
  • the rate of heat transfer between the thermal sensor and the fluid may vary. For example, if the downhole fluid is a gas, a relatively small amount of heat may dissipate from the thermal sensor. If the if the downhole fluid were a gas. If the downhole fluid is water, more heat may dissipate from the thermal senor than if the downhole fluid were a gas or an oil.
  • a substantially constant temperature is within about 5-degrees or units of a given temperature.
  • the more heat that dissipates from the thermal sensor the lower the temperature the thermal sensor will be if a constant amount of power is supplied to the thermal sensor.
  • properties of the fluid may be determined using the examples disclosed herein.
  • FIG. 1 is a schematic illustration of an example
  • the wellsite 100 including an example coiled tubing system 102 deployed into a well 104 that can be used to implement the examples disclosed herein.
  • the coiled tubing system 102 has surface delivery equipment 106 including a coiled tubing truck 108 with a reel 110.
  • the surface delivery equipment 106 is positioned adjacent the well 104 at the wellsite 100.
  • the example coiled tubing system 102 also includes coiled tubing 114 that may be used to pump fluid into the well 104.
  • the coiled tubing 114 By running the coiled tubing 114 through a gooseneck injector 116, the coiled tubing 114 may be advanced into the well 104. That is, the coiled tubing 114 may be forced down through valving and pressure control equipment 120 and into the well 104.
  • the gooseneck injector 116 is supported by a mast 118 over the well 104.
  • an example treatment device 122 is provided for delivering fluids downhole during a treatment application.
  • the treatment device 122 is deployable into the well 104 to carry fluids such as, for example, an acidizing agent or other treatment fluid.
  • the example treatment device 122 may disperse the fluids through at least one injection port or nozzle 124 of the treatment device 122 into, for example, the formation.
  • the coiled tubing system 102 of FIG. 1 is depicted as having a fluid sensing system 126 positioned about the injection port 124 for determining parameters of fluids in the well 104.
  • the fluid sensing system 126 may be positioned within the coiled tubing 114 for determining parameters of fluids in the coiled tubing 112.
  • the fluid sensing system 126 is preferably configured to determine fluid parameters, such as the composition of the downhole fluid (e.g., oil, water, gas), the state of the downhole fluid and/or fluid direction and/or velocity. Other downhole parameters (e.g., temperature) may also be determined using the fluid sensing system 126, if desired.
  • the example fluid sensing system 126 determines parameters of the fluid within the well 104.
  • the example fluid sensing system 126 determines parameters of the fluid within a flowline and/or chamber of the coiled tubing system 102.
  • the coiled tubing system 102 is optionally provided logging tool 128 is positioned adjacent a downhole end of the coiled tubing 114.
  • the example logging tool 128 may be configured to acquire a variety of logging data from the well 104 and surrounding formation layers 130, 132 such as those depicted in FIG. 1.
  • the example logging tool 128 may be provided with well profile generating equipment or implements configured for production logging directed at acquiring well fluids and formation measurements from which an overall production profile may be developed.
  • Other logging, data acquisition, monitoring, imaging and/or other devices and/or capabilities may be provided to acquire data relative to a variety of well characteristics. Information gathered may be acquired at the surface in a high speed manner and, where appropriate, put to immediate real-time use (e.g. via a treatment application).
  • the coiled tubing 114 of FIG. 1 including the treatment device 122, the fluid sensing system 126 and the logging tool 128 is shown as being deployed downhole.
  • treatment, sensing and/or logging applications may be directed by an example control unit 136 at the surface.
  • the example control unit 136 may cause the treatment device 122 to be activated to release fluid from the injection port 124; the example control unit 136 may cause the fluid sensing system 126 to be activated to collect fluid
  • the example control unit 136 may cause the logging tool 128 to be activated to log downhole data, as desired.
  • the treatment device 122, the fluid sensing system 126 and/or the logging tool 128 communicate with the control unit 136 via a communication link for passing signals (e.g., power, communication, control, etc.) therebetween.
  • the example control unit 136 of FIG. 1 is depicted as computerized equipment secured to a truck 108. However, the control unit 136 may be a laptop computer or any other type of mobile or stationary computing and/or processing device at the wellsite 100 or remote to the wellsite 100.
  • the coiled tubing system 102 may be controlled by hydraulic, pneumatic and/or electrical signals. Regardless, the wireless nature of the communication enables the control unit 136 to control the operation of the coiled tubing system 102, even in circumstances where subsequent different application assemblies may be deployed downhole. That is, in some examples, the need for a subsequent mobilization of control equipment may be eliminated.
  • the example control unit 136 may be configured to wirelessly communicate with an example transceiver hub 138 of the coiled tubing reel 110.
  • the transceiver hub 138 may be configured for communication onsite (surface and/or downhole) and/or offsite as desired.
  • the control unit 136 communicates with the sensing system 126 and/or the logging tool 128 to pass data therebetween.
  • the control unit 136 may be provided with and/or coupled to databases, processors, and/or communicators for collecting, storing, analyzing, and/or processing data collected from the sensing system and/or logging tool.
  • FIG. 2 illustrates a wellsite system in which the examples disclosed example system, a borehole 211 is formed in subsurface formations by rotary drilling.
  • the examples disclosed herein can also use directional drilling, for example.
  • a drill string 212 is suspended within the borehole 211 and has a bottom hole assembly 200 that includes a drill bit 205 at its lower end.
  • the surface system includes a platform and derrick assembly 210 positioned over the borehole 211.
  • the assembly 210 includes a rotary table 216, a kelly 217, a hook 218 and a rotary swivel 219.
  • the drill string 212 is rotated by the rotary table 216.
  • the rotatory table 216 may be energized by a device or system not shown.
  • the rotary table 216 may engage the kelly 217 at the upper end of the drill string 212.
  • the drill string 212 is suspended from the hook 218, which is attached to a traveling block.
  • the drill string 212 is positioned through the kelly 217 and the rotary swivel 219, which permits rotation of the drill string 212 relative to the hook 218. Additionally or alternatively, a top drive system may be used to impart rotation to the drill string 212.
  • the surface system further includes drilling fluid or mud 226 stored in a pit 227 formed at the well site.
  • a pump 229 delivers the drilling fluid 226 to the interior of the drill string 212 via a port in the swivel 219, causing the drilling fluid 226 to flow downwardly through the drill string 212 as indicated by the directional arrow 208.
  • the drilling fluid 226 exits the drill string 212 via ports in the drill bit 205, and then circulates upwardly through the annulus region between the outside of the drill string 212 and the wall of the borehole 211, as indicated by the directional arrows 209. In this manner, the drilling fluid 226 lubricates the drill bit 205 and carries formation cuttings up to the surface as it is returned to the pit 227 for recirculation.
  • the bottom hole assembly 200 of the example illustrated in FIG. 2 includes a logging-while-drilling (LWD) module 220, a measuring-while- drilling (MWD) module 230, a roto-steerable system and motor 250, and the drill bit 205.
  • LWD logging-while-drilling
  • MWD measuring-while- drilling
  • the LWD module 220 may be housed in a special type of drill collar and can contain one or more logging tools.
  • the bottom hole assembly 200 may include additional LWD and/or MWD modules.
  • references throughout this description to reference numeral 220 may additionally or alternatively include 220A.
  • the LWD module 220 may include capabilities for measuring, processing, and storing information, as well as for communicating with the surface equipment. Additionally or alternatively, the LWD module 220 includes a sonic measuring device.
  • the MWD module 230 may also be housed in a drill collar and can contain one or more devices for measuring characteristics of the drill string 212 and/or drill bit 205.
  • the MWD module 230 may further include an apparatus for generating electrical power for at least portions of the bottom hole assembly 200.
  • the apparatus for generating electrical power may include a mud turbine generator powered by the flow of the drilling fluid.
  • the MWD module 230 includes one or more of the following types of measuring devices: a weight-on-bit measuring device, a torque measuring device, a vibration measuring device, a shock measuring device, a stick slip measuring device, a direction measuring device and/or an inclination measuring device.
  • FIG. 2 Although the components of FIG. 2 are shown and described as being implemented in a particular conveyance type, the examples disclosed herein are not limited to a particular conveyance type but, instead, may be implemented in connection with different conveyance types including, for example, coiled tubing, wireline wired drillpipe and/or any other conveyance types known in the industry.
  • FIG. 3 is a simplified diagram of a sampling-while-drilling logging device and/or apparatus 300 of a type described in U.S. Patent 7,114,562, incorporated herein by reference in its entirety, that can be used to implement the LWD tools 220 or 220A and, more generally, can be used to implement the examples disclosed herein.
  • the example apparatus of FIG. 3 is provided with a probe 306 for establishing fluid communication with the formation and drawing fluid 321 into the tool, as indicated by the arrows.
  • the probe 306 may be positioned, for example, in a stabilizer blade 323 of the apparatus 300 and extend therefrom to engage a borehole wall 302.
  • the stabilizer blade 323 comprises one or more blades that are in contact with the borehole wall 302.
  • the fluid drawn into the apparatus 300 using the probe 306 may be measured to determine, for example, pretest and/or pressure parameters.
  • the apparatus 300 may include one or more sensors (e.g., a thermal sensor, a temperature sensor, a heater) that are used to differentiate between and/or identify the composition of downhole fluids.
  • the sensors may implemented by separately-spaced devices.
  • one or more of these sensors are positioned adjacent a chamber or flowline of the apparatus 300 to determine properties of the fluid within the chamber or flowline.
  • one or more of these sensors may be positioned adjacent an exterior surface of the apparatus 300 to determine properties of the fluid within the borehole 211.
  • the fluid being analyzed may or may not be moving (e.g., zero- velocity, negligible velocity, non-zero velocity). Additionally or alternatively, the apparatus 300 may be provided with devices, such as sample chambers for collecting fluid samples for retrieval at the surface. Backup pistons 381 may also be provided to assist in applying force to push the drilling tool and/or probe against the borehole wall 302.
  • FIG. 4 shows an example wireline tool 400 that may be another environment in which aspects of the present disclosure may be implemented.
  • the example wireline tool 400 is suspended in a wellbore 402 from the lower end of a multiconductor cable 404 that is spooled on a winch at the Earth’s surface.
  • the cable 404 is communicatively coupled to an electronics and processing system 406.
  • the example wireline tool 400 includes an elongated body 408 that includes a formation tester 414 having a selectively extendable probe assembly 416 and a selectively extendable tool anchoring member 418 that are arranged on opposite sides of the elongated body 408. Additional components (e.g., 410) may also be included in the tool 400.
  • the extendable probe assembly 416 is configured to selectively seal off or isolate selected portions of the wall of the wellbore 402 to fluidly couple to the adjacent formation F and/or to draw fluid samples from the formation F.
  • the extendable probe assembly 416 may be provided with a probe having an embedded plate, for example.
  • the electronics and processing system 406 and/or a downhole control system are configured to control the extendable probe assembly 416 and/or the drawing of a fluid sample from the formation F.
  • the formation fluid may be expelled through a port or it may be sent to first and/or second fluid collecting chambers 426 and 428.
  • a first sensor acting as a heater and/or a temperature sensor 430 and a second sensor acting as a temperature sensor and/or a heater 432 are positioned within the first fluid collecting chamber 426 and/or the second fluid collecting chamber 428.
  • the temperature sensor 430 and the heater 432 may be incorporated into a thermal sensor
  • a single sensor module may be positioned within the fluid collection chamber 426 or 428. Alternatively, multiple modules may be included in the fluid collection chamber 426 or 428.
  • the temperature sensor 430 and/or the heater 432 and/or the sensor module may be used to determine a property of the fluid (e.g., gas, water, oil, etc.) and/or a composition of the fluid. For example, based on the temperature of the fluid, a rate of heat dissipated into the fluid, , and/or an amount of power, , consumed by the heater 432 when heating the fluid, the different fluids may be identified.
  • One or more of the sensors 430, 432 may be a Resistance
  • the RTD sensor can be used as a temperature detector and as a heater because the electrical resistance of the RTD sensor is a function of temperature and because the temperature of the filament of the RTD sensor increases up when subjected to a large current.
  • a thermal sensor e.g., sensor module
  • PCT publication WO2012/000654 which is hereby incorporated herein by reference in its entirety.
  • the first temperature sensor 430 may measure a first temperature of the fluid and the heater 432 may be provided power, , to heat the heater 432 to a second temperature greater than the first temperature.
  • the first temperature sensor 430 may measure a first temperature of the fluid before, while and/or after power is provided to the heater 432.
  • a second temperature may be measured at the heater 432.
  • the heater 432 and/or another sensor adjacent thereto measures a first temperature before power is provided to the heater 432 and measures a second temperature after power is provided to the heater 432.
  • the heater 432 also includes a temperature sensor and may be, for example, a RTD sensor.
  • the electronics and processing unit 406 monitors an amount of power, , consumed by the heater 432 to maintain the heater 432 at a particular temperature. In other examples, the electronics and processing unit 406 monitors temperature, , of the heater 432 when being provided a
  • the amount of power consumed by the heater 432 to maintain the heater 432 at a substantially constant temperature and/or the temperature of the heater 432 after being provided a substantially constant amount of power relates to a rate of heat dissipation of the heater 432.
  • the electronics and processing system 406 may reference a look-up table and/or a database to compare data and identify the composition, type and/or parameters of the corresponding fluid .
  • the electronics and processing system 406 compares a magnitude of the values (e.g., a temperature value, a power consumed value, a velocity of the fluid, etc.) obtained by the sensors (e.g., a single thermal sensor, a sensor module, the temperature sensor 430, the heater 432) to the magnitude of values for reference fluids to identify the composition, parameters and/or other characteristics of the corresponding fluid.
  • the comparison may be used to determine if the fluid is associated with a gas, an oil-based fluid or a water-based fluid.
  • FIG. 5 illustrates an example downhole tool 500 that can be used to downhole tool 500 is positioned within a borehole 502 and includes a thermal sensor 504 positioned on and/or adjacent an exterior surface 506 of the downhole tool 500.
  • the thermal sensor 504 may be exposed to fluid within the borehole 502 to determine properties of the fluid.
  • the thermal sensor 504 may include a temperature sensor such as the temperature sensor 430 and/or a heater such as the heater 432.
  • Equation 1 shows a linear approximating relationship of density, ⁇ , as a function of temperature, T, that may apply to fluids such as aqueous solutions, oils and/or gasses encountered in oilfield applications.
  • ⁇ is a reference temperature of the downhole fluid
  • T is the density of the fluid at the temperature, , and is the thermal volume expansion coefficient.
  • Equation 1 describes a realistic model for the behavior of a stagnant fluid.
  • stagnant fluids may be modeled by other models and equations, which can be used to implement the examples disclosed herein.
  • Equation 2 shows the rate of heat transfer from the surface 508 of the thermal sensor 504 to the fluid, in the dimensionless form where , represented by Equation 3, is the Nusselt number averaged over the surface 508, , represented by Equation 4, is the Rayleigh number and , represented by Equation 5, is the Prandtl number.
  • Equation 3 is the surface 508 of the thermal sensor 504 (e.g., m 2 ) acting as a heater, P is the power for heating the fluid, (temperature excursion) is the difference between the temperature of the surface 508 corresponding at the second temperature measured at heater 432 and the temperature of the bulk fluid corresponding to the first temperature measured at first sensor 430 and is the fluid thermal conductivity.
  • Equation 4 is the dynamic viscosity and is the fluid specific heat.
  • Equation 5 is the thermal expansion coefficient, is the characteristic size of the heated surface, is the acceleration due to gravity, is the thermal diffusivity and is the kinematic viscosity.
  • Equation 7 defines the kinematic viscosity, v, where ⁇ is the dynamic viscosity and p is the density.
  • Equation 8 shows an analytical two-dimensional similarity solution for a vertical isothermal wall when the fluid is in natural convection
  • A is a function of a Prandl number
  • Ra is a ayleigh number.
  • the model on which this similarity solution is based may be appropriate for modeling a situation where the collection chamber, the flowline and/or the borehole containing the fluid is relatively larger than the heater (e.g., the thermal sensor 504, the surface 508).
  • the heater e.g., the thermal sensor 504, the surface 508
  • Equation 8 can be used to illustrate the differences in power consumption in various fluids (e.g., water, oil, air, gas) when the surface 508 is kept at a predefined temperature excursion, &7, over the temperature of the bulk fluid.
  • Table 1 shows properties for some fluids at 23°C such as dry air, engine oil and ordinary water.
  • Equation 9 defines a ratio of dissipated power for a given temperature excursion, .
  • the dissipated amount of power for each type of downhole fluid is determined using Equation 3 relative to the rate of heat transfer and Equation 8. Therefore, in this example, the ratio of power (P 1 and P 2 ) dissipated in fluids 1 and 2 by a predetermined heater and for a predetermined temperature excursion, is given by Equation 9.
  • the theoretical values , and for a given temperature excursion, ⁇ T, for a fluid of a given composition may be used to compare the measured value of the dissipated amount of power into the fluid to identify the composition or the type of the fluid.
  • the theoretical values are calculated using properties of the respective fluids.
  • the thermal sensor 504 measures the value of the dissipated amount of power.
  • the temperature excursion may be determined by measuring the temperature of the thermal sensor 504 corresponding to the second temperature, and by measuring the temperature at the sensor 430
  • the first temperature can be determined by measuring the temperature at the heater 432 before providing power to the heater 432 (e.g., corresponding to the temperature of the fluid).
  • a value of a magnitude, P/ ⁇ T is calculated using the parameters obtained from the thermal sensor 504, the heater 432 and/or the sensor 430 and compared to characteristic values of this magnitude stored in a look-up database or table for different types of fluids (e.g. water, oil, air).
  • the fluid composition can be identified using the above- mentioned example method and/or equations.
  • heat transfer between the heated surface at temperature T heater (corresponding to the second temperature measured by the sensor 432) and the fluid at temperature T fluid (corresponding to the first temperature measured by the sensor 430) is governed by the Newton’s law of cooling.
  • the heat dissipation into the fluid is proportional to the temperature excursion, as is shown by Equation 10 below, in which Q is the rate of heat dissipation into the fluid, S is the surface of the sensor and is the heat transfer coefficient.
  • the heat transfer coefficient depends on the flow geometry, the fluid properties and the fluid velocity where the flow geometry is known and the [0072]
  • a magnitude, P/ ⁇ T may be determined by, for example, either choosing constant and measuring variation of P or by choosing P constant and measuring variations of ⁇ T.
  • Q depends on P even if P includes the back leakage (portion of the energy wasted to heat the sensor body), which depends on the properties of the sensor. Therefore, the magnitude, P/ ⁇ T, is a function of the known sensor properties; the known flow geometry; the fluid velocity; and the fluid properties.
  • the fluid velocity may be determined using an appropriate sensor such as an ultrasonic or electromagnetic velocity sensor.
  • the measured value of the magnitude of the power provided to the heater 432 and/or the thermal sensor 504 and/or the temperature excursion can be compared with a value stored in a database for each type or composition of fluid to identify the type of composition of fluid based on the comparison.
  • the database stores different values of the magnitude for different fluids or different velocities and/or stores an expression of the magnitude for each fluid as a function of the velocity.
  • the reference values may be compared to the measured values to determine the composition of the measured fluid. For example, the characteristic value of the magnitude for each type of fluid being calculated for the measured velocity before may be compared to the measured value of the magnitude.
  • FIG. 6 illustrates a portion of an example downhole tool 600 that example, the downhole tool 600 includes the thermal sensor 504 positioned within and/or adjacent a flowline 602.
  • the thermal sensor 504 may be used to identify the fluid within the flowline 602 drawn from the formation and/or a borehole in which the downhole tool 600 is positioned.
  • the thermal sensor 504 measures the fluid in the flowline 602
  • the fluid may be moving (e.g., non-zero velocity) or the fluid may not be moving (e.g., zero velocity).
  • FIG. 7 illustrates a portion of an example downhole tool 700 that may be used to implement any of the examples disclosed herein.
  • the downhole tool 700 includes the thermal sensor 504 positioned within and/or adjacent a chamber 702.
  • the thermal sensor 504 may be used to determine properties of the fluid within the chamber 702.
  • the fluid within the chamber 702 may be obtained by drawing fluid from the formation and/or a borehole in which the downhole tool 700 is positioned.
  • FIG. 8 shows a graph 800 of natural convection occurring near a linear vertical isothermal wall when using a heater in a stagnant fluid where arrows 802, 804 represent the flow of the fluid relative to a heated wall 806.
  • FIG. 9 shows a graph 900 of results of placing a thermal sensor in various stagnant fluids one after another where the x-axis 902 corresponds to time and the y-axis 904 corresponds to Power, , over a temperature difference, .
  • the temperature difference is the difference in the temperature between the temperature of the heated surface 508, 806 and the bulk fluid temperature.
  • the thermal sensor was of placing the thermal sensor in the water prior to being exposed to oil (e.g., uncontaminated water) and then after being exposed to oil (e.g., contaminated water) are approximately the same.
  • the measurements obtained by the thermal sensor remains substantially constant even if the thermal sensor is repeatedly exposed to different fluid types (e.g., oil, water, etc.).
  • FIG. 10 illustrates a portion of an example downhole tool 1000 that may be used to implement the examples disclosed herein when fluid has a non-negligible velocity.
  • FIG. 11 shows results obtained using the example downhole tool 1000 of FIG. 10.
  • the downhole tool 1000 includes a first thermal sensor 1002 and a second thermal sensor 1004 positioned within and/or adjacent a flowline 1006.
  • the thermal sensors 1002, 1004 each include a heater and a temperature sensor.
  • the flowline 1006 is filled with water 1008 and an oil slug 1010.
  • the fluid velocity is initially zero as represented by reference number 1102 of FIG. 11.
  • the mean fluid velocity is approximately 9 centimeters / second, as represented by reference number 1104 of FIG. 11.
  • the oil slug 1010 passes the second thermal sensor 1004 after approximately 425 seconds and, thereafter, passes the first thermal sensor 1002 as represented by reference number 1106.
  • the magnitude P/ ⁇ T determined in view of the measurements taken by the sensor(s) 1002, 1004 decreases as represented by reference number 1108 of FIG. 11.
  • Equation 10 When the velocity of the fluid is caused by the pump 1012, the heat transfer between the heated surface of the sensors 1002, 1004 at temperature, T heater , is governed by Newton’s law of cooling where the heat dissipated into the fluid is proportional to the temperature excursion represented by Equation 10, where, Q is the rate of heat dissipation into the fluid, [W] and is the heat transfer coefficient, [W/m 2 K]. As shown in Equation 11 , the heat transfer coefficient is a function of the thermo-physical properties of the fluid (e.g., thermal conductivity, viscosity, etc.) and the mean fluid velocity.
  • Equation 10 the heat transfer coefficient is a function of the thermo-physical properties of the fluid (e.g., thermal conductivity, viscosity, etc.) and the mean fluid velocity.
  • the fluid type can be identified by measuring and comparing the result against the values in a look-up table or in a database.
  • the sensors 1002, 1004 instead of measuring the heat dissipated into the fluid, the sensors 1002, 1004 measure the power consumption, P, which includes the back leakage (portion of energy wasted to heat the sensor body).
  • the sensor window, S remains constant and the shape of the flow conduit remains constant.
  • the relationship between power consumption and the temperature difference is a function of the fluid properties and the fluid density.
  • FIGS. 12 and 13 While an example manner of implementing the coiled tubing system 100 of FIG. 1, the apparatus 300 of FIG. 3, the wireline tool 400 of FIG. 4 and/or the downhole tools 500, 600, 700 and 1000 of FIGS. 5– 7 and 10 are illustrated in FIGS. 12 and 13, one or more of the elements, processes and/or devices illustrated in FIGS. 12 and 13 may be combined, divided, re-arranged, omitted, eliminated and/or implemented in any other way. Further, one or more aspects of the coiled tubing system 100 of FIG. 1, the apparatus 300 of FIG. 3, the wireline tool 400 of FIG. 4 and/or the downhole tools 500, 600, 700 and 1000 of FIGS.
  • 5– 7 and 10 may be implemented by hardware, software, firmware and/or any combination of hardware, software and/or firmware.
  • one or more aspects of the coiled tubing system 100 of FIG. 1, the apparatus 300 of FIG. 3, the wireline tool 400 of FIG. 4 and/or the downhole tools 500, 600, 700 and 1000 of FIGS. 5– 7 and 10 could be implemented by one or more analog or digital circuit(s), logic circuits, programmable processor(s), application specific integrated circuit(s)
  • ASIC application-specific integrated circuit
  • PLD programmable logic device
  • FPLD field programmable logic device
  • At least one or more aspects of the coiled tubing system 100 of FIG. 1, the apparatus 300 of FIG. 3, the wireline tool 400 of FIG. 4 and/or the downhole tools 500, 600, 700 and 1000 of FIGS. 5– 7 and 10 is/are hereby expressly defined to include a tangible computer readable storage device or storage disk such as a memory, a digital versatile disk (DVD), a Further still, one or more aspects of the coiled tubing system 100 of FIG. 1, the apparatus 300 of FIG. 3, the wireline tool 400 of FIG. 4 and/or the downhole tools 500, 600, 700 and 1000 of FIGS. 5– 7 and 10 may include one or more elements, processes and/or devices in addition to, or instead of, those illustrated in FIGS. 12 and 13, and/or may include more than one of any or all of the illustrated elements, processes and devices.
  • a tangible computer readable storage device or storage disk such as a memory, a digital versatile disk (DVD), a
  • FIGS. 12 and 13 A flowchart representative of example methods for implementing the coiled tubing system 100 of FIG. 1, the apparatus 300 of FIG. 3, the wireline tool 400 of FIG. 4 and/or the downhole tools 500, 600, 700 and 1000 of FIGS. 5– 7 and 10 are shown in FIGS. 12 and 13.
  • the methods may be implemented using machine readable instructions that comprise a program for execution by a processor such as the processor 1412 shown in the example processor platform 1400 discussed below in connection with FIG. 14.
  • the program may be embodied in software stored on a tangible computer readable storage medium such as a CD-ROM, a floppy disk, a hard drive, a digital versatile disk (DVD), a Blu-ray disk, or a memory associated with the processor 1412, but the entire program and/or parts thereof could alternatively be executed by a device other than the processor 1412 and/or embodied in firmware or dedicated hardware.
  • a tangible computer readable storage medium such as a CD-ROM, a floppy disk, a hard drive, a digital versatile disk (DVD), a Blu-ray disk, or a memory associated with the processor 1412, but the entire program and/or parts thereof could alternatively be executed by a device other than the processor 1412 and/or embodied in firmware or dedicated hardware.
  • FIGS. 12 and 13 many other methods of implementing the coiled tubing system 100 of FIG. 1, the apparatus 300 of FIG. 3, the wireline tool 400 of FIG. 4 and/or the downhole tools 500, 600, 700 and 1000 of FIGS
  • FIGS. 12 and 13 may be implemented using coded instructions (e.g., computer and/or machine readable instructions) stored on a tangible computer readable storage medium such as a hard disk drive, a flash memory, a read-only memory (ROM), a compact disk (CD), a digital versatile disk (DVD), a cache, a random-access memory (RAM) and/or any other storage device or storage disk in which information is stored for any duration (e.g., for extended time periods, permanently, for brief instances, for temporarily buffering, and/or for caching of the information).
  • coded instructions e.g., computer and/or machine readable instructions
  • a tangible computer readable storage medium such as a hard disk drive, a flash memory, a read-only memory (ROM), a compact disk (CD), a digital versatile disk (DVD), a cache, a random-access memory (RAM) and/or any other storage device or storage disk in which information is stored for any duration (e.g., for extended time periods, permanently, for brief instances,
  • tangible computer readable storage medium is expressly defined to include any type of computer readable storage device and/or storage disk and to exclude propagating signals and transmission media.
  • tangible computer readable storage medium and “tangible machine readable storage medium” are used interchangeably.
  • FIGS. 12 and 13 may be implemented using coded instructions (e.g., computer and/or machine readable instructions) stored on a non-transitory computer and/or machine readable medium such as a hard disk drive, a flash memory, a read-only memory, a compact disk, a digital versatile disk, a cache, a random-access memory and/or any other storage device or storage disk in which information is stored for any duration (e.g., for extended time periods, permanently, for brief instances, for temporarily buffering, and/or for caching of the information).
  • coded instructions e.g., computer and/or machine readable instructions
  • a non-transitory computer and/or machine readable medium such as a hard disk drive, a flash memory, a read-only memory, a compact disk, a digital versatile disk, a cache, a random-access memory and/or any other storage device or storage disk in which information is stored for any duration (e.g., for extended time periods, permanently, for brief instances, for temporarily buffering, and
  • the example method of FIG. 12 begins by measuring a first temperature at the surface of a heater using the temperature sensor 432 or at another location remote from the heater using the temperature sensor 430 (block 1202). If the sensor is remote from the heater, the sensor 430 may be chosen so that it is in the vicinity of the first location but not influenced by the heater.
  • the fluid is a wellbore fluid and/or formation fluid within the coiled tubing system 100, the apparatus 300, the wireline tool 400, the downhole tools 500, 600, 700 and 1000 of FIGS.
  • the fluid collecting chamber 426 and/or 428, the flowline 602 and/or the chamber 702 and, thus, the temperature sensor 430 and/or the thermal sensor 504 are positioned within the coiled tubing system 100, the apparatus 300, the wireline tool 400 and/or the downhole tools 500, 600, 700 and 1000 of FIGS. 5– 7 and 10 adjacent, for example, the fluid collecting chamber 426 and/or 428, the flowline 602 and/or the chamber 702.
  • the fluid is a fluid within the borehole 211, 402 and, thus, the temperature sensor 430 and/or the thermal sensor 504 are positioned on and/or adjacent an exterior surface of the coiled tubing system 100, the apparatus 300, the wireline tool 400 and/or the downhole tools 500, 600, 700 and 1000 of FIGS. 5– 7 and 10.
  • Power may be provided to the heater 432 and/or the thermal sensor 504 predefined second temperature greater than the first temperature (block 1204).
  • the difference between the first and second temperatures is approximately ten degrees (e.g., +/- 3 degrees and/or units).
  • the difference between the first and second temperatures may be any suitable temperature difference (e.g., 5-degrees, 13-degrees, 22-degrees, 27-degrees, etc.).
  • the example control unit 136, a logging and control system 252 and/or the electronics and processing system 406 may be used to monitor an amount of power consumed by the heater 432 and/or the thermal sensor 504 to maintain the heater at the second temperature (block 1206).
  • the amount of power consumed by the temperature sensor 430 and/or the thermal sensor 504 is higher to maintain the temperature sensor 430 and/or the thermal sensor 504 at the second temperature.
  • the example control unit 136, the logging and control system 252 and/or the electronics and processing system 406 may reference a look-up table and/or a database to compare a magnitude obtained from the amount of power dissipated P and/or the temperature excursion (block 1208) to characteristic values of this magnitude for reference fluids and identify the type or composition of the fluid.
  • the logging and control system 252 and the electronic and processing system 406 may use the value of the amount of power consumed by the thermal sensor 504, to differentiate between the fluid being a gas, an oil-based fluid or a water-based fluid.
  • the example method of FIG. 13 begins by determining a velocity of the fluid (block 1301 ). The velocity may be determined using a sensor. WO 2012/174078, which is hereby incorporated herein by reference in its entirety, describes an exemplary process of determining velocity of the fluid. Other methods and sensors for determining the velocity of a fluid may of course be used. The method then measures a temperature at the surface of a heater using the temperature sensor 432 or at another location remote from the heater using the temperature sensor 430 (blocks 1302).
  • the sensor 430 may be positioned so that it is in the vicinity of the first location but not influenced by the heater.
  • the fluid is a wellbore fluid and/or a formation fluid within the coiled tubing system 100, the apparatus 300, the wireline tool 400, the downhole tools 500, 600, 700 and/or 1000, the fluid collecting chamber 426 and/or 428, the flowline 602 and/or the chamber 702 and, thus, the temperature sensor 430 and/or the thermal sensor 504 are positioned within the apparatus 300, the wireline tool 400 and/or the downhole tool 500, 600, 700 and/or 1000 adjacent, for example, the fluid collecting chamber 426 and/or 428, the flowline 602 and/or the chamber 702.
  • the fluid is a fluid within the borehole 211 , 502 and, thus, the temperature sensor 430 and/or the thermal sensor 504 are positioned on and/or adjacent an exterior surface of the coiled tubing system 100, the apparatus 300, the wireline tool 400 and/or the downhole tool 500, 600, 700 and/or 1000.
  • a substantially constant amount of power may be provided to the heater 432 and/or the thermal sensor 504 (block 1304).
  • a power means between about +/- 50 milliWatts and/or +/-5% of a particular wattage).
  • a constant amount of power is provided to the heater 432 and/or the thermal sensor 504, different amounts of heat may dissipate from the heater 432 and/or the thermal sensor 504 into the fluid. For example, if the fluid is water, more heat will dissipate into the fluid than if the fluid is a gas.
  • control unit 136, the logging and control system 252 and/or the electronics and processing system 406 may be used to monitor a temperature of the heater 432 and/or the thermal sensor 504 (block 1306).
  • a temperature excursion in view of the monitored temperature at the second location may be determined and the control unit 136, the logging and control system 252 and/or the electronics and processing system 406 may reference a look-up table and/or a database to compare a magnitude obtained from the amount of power dissipated P and/or the temperature excursion and/or the measured velocity to characteristic values of this magnitude for reference fluids and identify the type or composition of the fluid (block 1308).
  • the characteristic values of the magnitude for the reference fluids are calculated as a function of the measured velocity of the fluid.
  • FIG. 14 is a block diagram of an example processor platform 1400 capable of executing the instructions to implement the methods of FIG. 12 and 13 and one or more aspects of the apparatus 300 of FIG. 3, the wireline tool processor platform 1400 can be, for example, a server, a personal computer, a mobile device (e.g., a cell phone, a smart phone, a tablet such as an iPad TM ), a personal digital assistant (PDA), an Internet appliance, or any other type of computing device.
  • a server e.g., a cell phone, a smart phone, a tablet such as an iPad TM
  • PDA personal digital assistant
  • the processor platform 1400 of the illustrated example includes a processor 1412.
  • the processor 1412 of the illustrated example is hardware.
  • the processor 1412 can be implemented by one or more integrated circuits, logic circuits, microprocessors or controllers from any desired family or manufacturer.
  • the processor 1412 of the illustrated example includes a local memory 1413 (e.g., a cache).
  • the processor 1412 of the illustrated example is in communication with a main memory including a volatile memory 1414 and a non-volatile memory 1416 via a bus 1418.
  • the volatile memory 1414 may be implemented by Synchronous Dynamic Random Access Memory (SDRAM), Dynamic Random Access Memory (DRAM), RAMBUS Dynamic Random Access Memory (RDRAM) and/or any other type of random access memory device.
  • the non-volatile memory 1416 may be implemented by flash memory and/or any other desired type of memory device. Access to the main memory 1414, 1416 is controlled by a memory controller.
  • the processor platform 1400 of the illustrated example also includes an interface circuit 1420.
  • the interface circuit 1420 may be implemented by any type of interface standard, such as an Ethernet interface, a universal serial bus (USB), and/or a PCI express interface.
  • one or more input devices 1422 are connected to the interface circuit 1420.
  • the input device(s) 1422 permit(s) a user to enter data and commands into the processor 1412.
  • the input device(s) can be implemented by, for example, an audio sensor, a microphone, a camera (still or video), a keyboard, a button, a mouse, a touchscreen, a track-pad, a trackball, and/or a voice recognition system.
  • One or more output devices 1424 are also connected to the interface circuit 1420 of the illustrated example.
  • the output devices 1424 can be implemented, for example, by display devices (e.g., a light emitting diode (LED), an organic light emitting diode (OLED), a liquid crystal display, a cathode ray tube display (CRT), a touchscreen, a tactile output device, a light emitting diode (LED), a printer and/or speakers).
  • the interface circuit 1420 of the illustrated example thus, typically includes a graphics driver card, a graphics driver chip or a graphics driver processor.
  • the interface circuit 1420 of the illustrated example also includes a communication device such as a transmitter, a receiver, a transceiver, a modem and/or network interface card to facilitate exchange of data with external machines (e.g., computing devices of any kind) via a network 1426 (e.g., an Ethernet connection, a digital subscriber line (DSL), a telephone line, coaxial cable, a cellular telephone system, etc.).
  • a communication device such as a transmitter, a receiver, a transceiver, a modem and/or network interface card to facilitate exchange of data with external machines (e.g., computing devices of any kind) via a network 1426 (e.g., an Ethernet connection, a digital subscriber line (DSL), a telephone line, coaxial cable, a cellular telephone system, etc.).
  • DSL digital subscriber line
  • the processor platform 1400 of the illustrated example also includes one or more mass storage devices 1428 for storing software and/or data.
  • mass storage devices 1428 include floppy disk drives, hard drive disks, compact disk drives, Blu-ray disk drives, RAID systems, and digital versatile disk (DVD) drives.
  • Coded instructions 1432 to implement the methods of FIGS. 12 and 13 may be stored in the mass storage device 1428, in the volatile memory 1414, in the non-volatile memory 1416, and/or on a removable tangible computer readable storage medium such as a CD or DVD.
  • a property of a fluid within a chamber, a flowline, borehole, etc. can be determined by measuring the fluid temperature using a temperature sensor and determining an amount of power consumed by the heater to maintain the heater at a predetermined temperature above the measured temperature of fluid. Based on the amount of power consumed, the velocity of the fluid and/or the geometry of the chamber and/or flowline, a processor may reference a look-up table and/or a database to determine if the fluid is an oil-based fluid, a gas or a water-based fluid.
  • an example method includes measuring a first temperature of a downhole fluid and providing power to a heater to maintain substantially constant temperature of a surface of a heater exposed to the downhole fluid at a second temperature. The second temperature higher than the first temperature.
  • the method also includes monitoring an amount of power provided to the heater and, based on the amount of power provided, determining a property of the downhole fluid.
  • determining the property comprises identifying the downhole fluid as a water-based fluid, an oil-based fluid, or a gas.
  • determining the property is further based on a velocity of the downhole fluid.
  • the dowhole fluid is within a chamber, a flowline, or a borehole.
  • providing the power includes varying the amount of power based on an amount of heat that dissipates into the downhole fluid.
  • the amount of power provided to the heater is associated with heat dissipating from the surface into the downhole fluid.
  • determining the property of the downhole fluid comprises referencing a look-up table or a database.
  • An example method includes measuring a first temperature of a downhole fluid, providing a substantially constant amount of power to a heater to heat a surface of a heater exposed to the downhole fluid and monitoring a second temperature of the surface. The method includes, based on the second temperature of the surface, determining a property of the downhole fluid. In some examples, determining the property includes identifying the downhole determining the property is further based on the velocity of the downhole fluid. In some examples, the dowhole fluid is within a chamber, a flowline, or a borehole. In some examples, the temperature of the surface is based on heat dissipating into the downhole fluid. In some examples, determining the property comprises referencing a look-up table or a database.
  • An example apparatus includes a downhole tool and a first sensor and a second sensor.
  • the first and second sensors are to be exposed to a downhole fluid.
  • the apparatus includes a processor to cause the first sensor to measure a first temperature of the downhole fluid. Based on the first temperature, the processor is to maintain a temperature of a surface of the second sensor exposed to the downhole fluid at a second temperature.
  • the processor is to monitor an amount of power provided to the second sensor to substantially maintain the temperature of the surface at the second
  • the processor determines a property of the downhole fluid.
  • the processor is to reference a look-up table or a database to determine the property of the downhole fluid.
  • the first sensor and the second sensor are positioned adjacent a flowline of the downhole tool, the downhole fluid to be within the flowline.
  • the first sensor and the second sensor are positioned adjacent a chamber of the downhole tool where he downhole fluid to be within the chamber.
  • the first sensor and the second sensor are positioned adjacent an exterior surface of the downhole tool, the downhole second sensor are the same sensor.
  • the first sensor and the second sensor are part of a single sensor module (RTD sensor).
  • the first sensor and the second sensor are immediately adjacent one another.
  • the first sensor and the second sensor are spaced apart from one another.
  • An example apparatus includes a first sensor and a second sensor where the first and second sensors to be exposed to a downhole fluid.
  • the apparatus includes a processor to cause the first sensor to measure a first temperature of the downhole fluid and, based on the first temperature, to provide a substantially constant amount of power to the second sensor to heat a surface of the second sensor exposed to the downhole fluid.
  • the processor is to monitor a second temperature of the surface and, based on the second temperature, the processor to determine a property of the downhole fluid.
  • the processor is to reference a look-up table or a database to determine the property of the downhole fluid.
  • the first sensor and the second sensor are the same sensor.
  • the first sensor and the second sensor are part of a single sensor module (RTD sensor).
  • the first sensor and the second sensor are immediately adjacent one another.
  • the first sensor and the second sensor are spaced apart from one another.

Abstract

La présente invention concerne des procédés et un appareil pour déterminer l'invention concerne également des paramètres de fluide de fond de trou. Un exemple de procédé comprend la mesure d'une première température d'un fluide de fond et la fourniture d'énergie à un dispositif de chauffage comprenant une surface exposée au fluide de fond de trou pour chauffer la surface à une deuxième température. La deuxième température est supérieure à la première température. L'exemple de procédé comprend en outre la surveillance des paramètres suivants : une quantité d'énergie fournie au dispositif de chauffage ; et une excursion de température entre les première et deuxième températures. L'exemple de procédé comprend, sur la base d'au moins un de ces paramètres, l'identification d'une composition du fluide de fond.
PCT/US2015/044582 2014-08-12 2015-08-11 Procédés et appareil pour déterminer des paramètres de fluide de fond WO2016025435A1 (fr)

Applications Claiming Priority (2)

Application Number Priority Date Filing Date Title
EP14290247.7 2014-08-12
EP14290247.7A EP2985410A1 (fr) 2014-08-12 2014-08-12 Procédés et appareil permettant de déterminer les paramètres de fluides de fond de trou

Publications (1)

Publication Number Publication Date
WO2016025435A1 true WO2016025435A1 (fr) 2016-02-18

Family

ID=51429227

Family Applications (1)

Application Number Title Priority Date Filing Date
PCT/US2015/044582 WO2016025435A1 (fr) 2014-08-12 2015-08-11 Procédés et appareil pour déterminer des paramètres de fluide de fond

Country Status (2)

Country Link
EP (1) EP2985410A1 (fr)
WO (1) WO2016025435A1 (fr)

Cited By (2)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
CN109736797A (zh) * 2019-01-17 2019-05-10 西南石油大学 一种智能扇叶齿轮齿条支腿抽吸式取样器
CN109763816A (zh) * 2019-01-17 2019-05-17 西南石油大学 一种智能叶片丝杆弹簧支腿真空式取样器

Families Citing this family (1)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
EP3258060B1 (fr) * 2016-06-13 2019-12-11 Services Petroliers Schlumberger Détermination de composant de fluide au moyen de propriétés thermiques

Citations (5)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US5984641A (en) * 1997-05-05 1999-11-16 1273941 Ontario Inc. Controller for oil wells using a heated probe sensor
US20050109538A1 (en) * 2003-11-24 2005-05-26 Schlumberger Technology Corporation [apparatus and method for acquiring information while drilling]
US20110315375A1 (en) * 2010-06-28 2011-12-29 Tullio Moscato System and method for determining downhole fluid parameters
WO2013171721A1 (fr) * 2012-05-18 2013-11-21 Services Petroliers Schlumberger Procédés et appareil permettant de déterminer les paramètres d'un fluide de fond de trou
US20140151032A1 (en) * 2011-06-13 2014-06-05 Schlumberger Technology Corporation Methods and Apparatus for Determining Downhole Fluid Parameters

Family Cites Families (6)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
GB2401430B (en) * 2003-04-23 2005-09-21 Sensor Highway Ltd Fluid flow measurement
GB2416394B (en) * 2004-07-17 2006-11-22 Sensor Highway Ltd Method and apparatus for measuring fluid properties
RU2306416C1 (ru) * 2006-06-09 2007-09-20 Schlumberger Technology B.V., Способ определения параметров потока флюида и устройство для его реализации
GB2484990A (en) * 2010-11-01 2012-05-02 Zenith Oilfield Technology Ltd Distributed Fluid Velocity Sensor and Associated Method
US8627751B2 (en) 2011-06-16 2014-01-14 Leonard Paul Parkin Device for loosening and untying knots
GB201122027D0 (en) * 2011-12-20 2012-02-01 Bp Exploration Operating Estimating flow in production well

Patent Citations (5)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US5984641A (en) * 1997-05-05 1999-11-16 1273941 Ontario Inc. Controller for oil wells using a heated probe sensor
US20050109538A1 (en) * 2003-11-24 2005-05-26 Schlumberger Technology Corporation [apparatus and method for acquiring information while drilling]
US20110315375A1 (en) * 2010-06-28 2011-12-29 Tullio Moscato System and method for determining downhole fluid parameters
US20140151032A1 (en) * 2011-06-13 2014-06-05 Schlumberger Technology Corporation Methods and Apparatus for Determining Downhole Fluid Parameters
WO2013171721A1 (fr) * 2012-05-18 2013-11-21 Services Petroliers Schlumberger Procédés et appareil permettant de déterminer les paramètres d'un fluide de fond de trou

Cited By (4)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
CN109736797A (zh) * 2019-01-17 2019-05-10 西南石油大学 一种智能扇叶齿轮齿条支腿抽吸式取样器
CN109763816A (zh) * 2019-01-17 2019-05-17 西南石油大学 一种智能叶片丝杆弹簧支腿真空式取样器
CN109736797B (zh) * 2019-01-17 2022-01-28 西南石油大学 一种智能扇叶齿轮齿条支腿抽吸式取样器
CN109763816B (zh) * 2019-01-17 2022-01-28 西南石油大学 一种智能叶片丝杆弹簧支腿真空式取样器

Also Published As

Publication number Publication date
EP2985410A1 (fr) 2016-02-17

Similar Documents

Publication Publication Date Title
US8434356B2 (en) Fluid density from downhole optical measurements
CA2805460C (fr) Trepan a corps reduit et d'analyse en tant qu'outil de mesure pendant le forage
US11513063B2 (en) Multivariate statistical contamination prediction using multiple sensors or data streams
US10731460B2 (en) Determining formation fluid variation with pressure
US10012074B2 (en) Asphaltene content of heavy oil
WO2010036599A2 (fr) Système et procédé permettant la modélisation de profils d’écoulement de fluide dans un puits de forage
AU2014287672B2 (en) System and method for operating a pump in a downhole tool
US10087741B2 (en) Predicting pump performance in downhole tools
CN105793515A (zh) 用于套管厚度估算的方法和设备
BR112020011751A2 (pt) métodos e sistemas para monitoramento de características reológicas de fluido de perfuração
MX2014015010A (es) Metodos de analisis para determinar la viscosidad de fluidos agujero abajo.
WO2016025435A1 (fr) Procédés et appareil pour déterminer des paramètres de fluide de fond
MX2014008639A (es) Aparatos, sistemas y metodos acondicionadores de sensor.
US10458233B2 (en) Sensors for in-situ formation fluid analysis
CN111386383B (zh) 一种用于确定井下流体的热响应的工具
US20230108851A1 (en) Downhole pressure calculation based on strain gauge measurements
US10358917B2 (en) Generating relative permeabilities and capillary pressures
US20230058017A1 (en) Remediation Of A Formation Utilizing An Asphaltene Onset Pressure Map
CA2961722C (fr) Augmentation de la permeabilite de la paroi d'un trou de forage afin de faciliter l'echantillonnage du fluide
US10436019B2 (en) Methods and apparatus of adjusting matrix acidizing procedures
US20190368339A1 (en) Wellbore Skin Effect Calculation using Temperature Measurements
US20160123953A1 (en) Evaluating Reservoir Oil Biodegradation

Legal Events

Date Code Title Description
121 Ep: the epo has been informed by wipo that ep was designated in this application

Ref document number: 15832652

Country of ref document: EP

Kind code of ref document: A1

NENP Non-entry into the national phase

Ref country code: DE

122 Ep: pct application non-entry in european phase

Ref document number: 15832652

Country of ref document: EP

Kind code of ref document: A1