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WO2016085506A1 - Systèmes et procédés permettant de réduire les effets de bruit du boîtier - Google Patents

Systèmes et procédés permettant de réduire les effets de bruit du boîtier Download PDF

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Publication number
WO2016085506A1
WO2016085506A1 PCT/US2014/067754 US2014067754W WO2016085506A1 WO 2016085506 A1 WO2016085506 A1 WO 2016085506A1 US 2014067754 W US2014067754 W US 2014067754W WO 2016085506 A1 WO2016085506 A1 WO 2016085506A1
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WO
WIPO (PCT)
Prior art keywords
casing
tool body
metal casing
sensor pad
interior wall
Prior art date
Legal status (The legal status 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 status listed.)
Ceased
Application number
PCT/US2014/067754
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English (en)
Inventor
Robert E. Maute
Feroze J. SIDWA
Current Assignee (The listed assignees may be inaccurate. Google has not performed a legal analysis and makes no representation or warranty as to the accuracy of the list.)
REM Scientific Enterprises Inc
Original Assignee
REM Scientific Enterprises Inc
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 REM Scientific Enterprises Inc filed Critical REM Scientific Enterprises Inc
Priority to PCT/US2014/067754 priority Critical patent/WO2016085506A1/fr
Publication of WO2016085506A1 publication Critical patent/WO2016085506A1/fr
Anticipated expiration legal-status Critical
Ceased legal-status Critical Current

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Classifications

    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK 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
    • E21B47/113—Locating fluid leaks, intrusions or movements using electrical indications; using light radiations
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01F—MEASURING VOLUME, VOLUME FLOW, MASS FLOW OR LIQUID LEVEL; METERING BY VOLUME
    • G01F15/00—Details of, or accessories for, apparatus of groups G01F1/00 - G01F13/00 insofar as such details or appliances are not adapted to particular types of such apparatus
    • G01F15/18—Supports or connecting means for meters
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01F—MEASURING VOLUME, VOLUME FLOW, MASS FLOW OR LIQUID LEVEL; METERING BY VOLUME
    • G01F1/00—Measuring the volume flow or mass flow of fluid or fluent solid material wherein the fluid passes through a meter in a continuous flow
    • G01F1/56—Measuring the volume flow or mass flow of fluid or fluent solid material wherein the fluid passes through a meter in a continuous flow by using electric or magnetic effects
    • G01F1/58—Measuring the volume flow or mass flow of fluid or fluent solid material wherein the fluid passes through a meter in a continuous flow by using electric or magnetic effects by electromagnetic flowmeters

Definitions

  • the present invention relates generally to measurement of fluid flow, and more particularly to systems and methods for reducing casing noise effects while measuring fluid flow.
  • FIG. 1 An oil and gas well is shown in Figure 1 generally at 60.
  • Well construction involves drilling a hole or borehole 62 in the surface 64 of land or ocean floor.
  • the borehole 62 may be several thousand feet deep, and drilling is continued until the desired depth is reached.
  • Fluids such as oil, gas and water reside in porous rock formations 68.
  • a casing 72 is normally lowered into the borehole 62.
  • the region between the casing 72 and rock formation 68 is filled with cement 70 to provide a hydraulic seal.
  • tubing 74 is inserted into the hole 62, the tubing 74 including a packer 76 which comprises a seal.
  • a packer fluid 78 is disposed between the casing 72 and tubing 74 annular region.
  • Perforations 80 may be located in the casing 72 and cement 70, into the rock 68, as shown.
  • Production logging involves obtaining logging information about an active oil, gas or water- injection well while the well is flowing.
  • a logging tool instrument package comprising sensors is lowered into a well, the well is flowed and measurements are taken.
  • Production logging is generally considered the best method of determining actual downhole flow.
  • a well log a collection of data from measurements made in a well, is generated and is usually presented in a long strip chart paper format that may be in a format specified by the American Petroleum Institute (API), for example.
  • API American Petroleum Institute
  • the general objective of production logging is to provide information for the diagnosis of a well.
  • a wide variety of information is obtainable by production logging, including determining water entry location, flow profile, off depth perforations, gas influx locations, oil influx locations, non-performing perforations, thief zone stealing production, casing leaks, crossflow, flow behind casing, verification of new well flow integrity, and floodwater breakthrough, as examples.
  • the benefits of production logging include increased hydrocarbon production, decreased water production, detection of mechanical problems and well damage, identification of unproductive intervals for remedial action, testing reservoir models, evaluation of drilling or completion effectiveness, monitoring Enhanced Oil Recovery (EOR) process, and increased profits, for example.
  • An expert generally performs interpretation of the logging results.
  • measurements are typically made in the central portion of the wellbore cross-section, such as of spinner rotation rate, fluid density and dielectric constant of the fluid mixture. These data may be interpreted in an attempt to determine the flow rate at any point along the borehole. Influx or exit rate over any interval is then determined by subtracting the flow rates at the two ends of the interval.
  • the wellbore In most producing oil and gas wells, the wellbore itself generally contains a large volume percentage or fraction of water, but often little of this water flows to the surface. The water that does flow to the surface enters the wellbore, which usually already contains a large amount of water. The presence of water already in the wellbore, however, makes detection of the additional water entering the wellbore difficult and often beyond the ability of conventional production logging tools.
  • one fluid flow measurement approach involves using an electromagnetic sensing device disposed adjacent the borehole wall to measure radial flow of conductive fluid entering or leaving the borehole.
  • An embodiment method of measuring fluid flow through an interior wall of a metal casing includes traversing the casing with a tool body having an electronic sensor pad and positioning the sensor pad adjacent to the interior wall of the metal casing during the traversing.
  • the method includes measuring, adjacent to the interior wall of the metal casing, a radial flow of conductive fluid through the interior wall of the metal casing.
  • the method further includes generating a measurement signal induced by the radial flow of conductive fluid through the interior wall of the metal casing and reducing a casing noise effect in the measurement signal.
  • Figure 1 illustrates a cross-sectional view of an oil or gas well
  • Figure 2 illustrates an embodiment of a logging tool string
  • Figure 3 illustrates a block diagram of electronics for processing array sensor data
  • Figures 4A-4B illustrate the shield for the current wires wired to the sensor coil
  • Figures 5A-5H illustrate the sensor pad interfacing with the metal casing wall
  • Figures 6A-6H illustrate electrical connections from the tool to the casing wall
  • Figures 7A-7C illustrate isolation couplings to the measurement electronics
  • Figures 8A-8B illustrate measurement signals and noise effects
  • Figure 9 illustrates the use of a filter in the analog processing electronics
  • Figure 10 illustrates electrical isolation of the sensor
  • Figure 1 1 is a block diagram of a computing device in accordance with an embodiment of the present invention. DETAILED DESCRIPTION OF ILLUSTRATIVE EMBODIMENTS
  • the present invention will be described with respect to preferred embodiments in a specific context, namely fluid flow measurement in a wellbore.
  • the invention may also be applied, however, to other applications where the detection of conductive fluid flow is useful, such as pipes, casings, drill shafts, tanks, and swimming pools.
  • the measurement tool may be used in vertical, deviated, and horizontal wells, and may be used in tubing, casing, slotted screens, slotted liners, and almost any well completion. Any type of conduit, wellbore, cylinder, pipe, shaft, tube, etc. is referred to herein generally as a casing.
  • a downhole measuring device for a wellbore is shown as sonde or tool string 100, which is configured to traverse a casing 102 with sensor pad 113.
  • tool 100 typically is lowered into and raised out of casing 102 on a wireline 101.
  • the tool 100 azimuthally sweeps or rotates the sensor pad 1 13 on arm assembly 1 11 about the inner circumference 103 of the casing 102 as the tool 100 axially traverses the casing 102.
  • sensor pad 113 is maintained in contact or in close proximity to the wellbore wall 103.
  • Tool 100 includes stationary tool segments 104 and rotatable tool segment 110.
  • a majority of the components of the tool bodies are preferably non-magnetic and preferably corrosion resistant materials, such as stainless steel, titanium, and the like.
  • Stationary tool body 104 is preferably non-rotating, and is connected to rotating tool segment 1 10 by rotating joint 107, which allows for electrical communications (signals and power) to pass between the rotating tool segment 1 10 and at least one of the stationary tool segments 104.
  • Rotating joint 107 may constitute slip rings or a wireless (e.g., radio frequency) transceiver pair for communication, as examples.
  • Stationary tool body 104 may include one segment or preferably two segments with one being below the rotating tool body 1 10 and the other being above it and attached to wireline cable 101.
  • Slip rings may be added at the bottom rotating joint 107 if other measurement tools are desired to be located below rotating tool segment 110.
  • Attached to stationary tool body 104 is at least one, but preferably two, three, four or more centralizers 105.
  • Centralizers 105 generally maintain a long axis of the tool body 100 substantially parallel to the axis of casing 102, as well as substantially in the center of casing 102, thus generally maintaining sensor pad 1 13 in proximity to the wellbore wall 103 and substantially parallel to the axis of casing 102. Additionally, the centralizers generally keep rotation of stationary tool body 104 to a minimum while rotating tool body 110 rotates.
  • Centralizers 105 may be made of metal ribbons or wires for example.
  • Rotating tool body 1 10 (along with arm assembly 11 1 and sensor pad 1 13) may be rotated by motor 106 located within stationary tool body 104.
  • the rotating tool body may be rotated by other mechanisms such as gears driven by axial motion of the tool body 100 through casing 102.
  • motor 106 or other rotating mechanism may be located in another part of the tool 100, such as within the rotating tool body 110, or outside of the tool such as higher up on the wireline 101 or above ground.
  • a clutch may be used with the motor for protection in case the sensor pad hangs up during rotation and stops rotating.
  • substantially all exposed parts of sonde 100 are smoothed and rounded to prevent sonde 100 from hanging up or snagging against any protrusions, tubular ends, tubular lips, seating nipples, gas lift mandrels, packers, etc., within a borehole.
  • a sensor(s) within the sensor pad 113 detects the radial component of conductive fluid, such as water, entering or leaving the wellbore through the wellbore wall.
  • tool 100 is slowly moved axially at a speed such that, while sensor pad 1 13 is rotating, generally the entire or substantially all of the inner area of the wellbore wall portion to be measured is covered by the sensor area of sensor pad 113.
  • the sensor may sweep across overlapping swaths of the detected spiral area to ensure full coverage of the borehole wall, even if the axial speed of the tool varies.
  • Tool 100 may make one, two or more axial passes through a wellbore while logging measurements made with sensor pad 113. Normally logging may be performed from the bottom upward, but logging also may be performed while moving in the downward direction.
  • Various embodiments sum the outputs from the entire multitude of flow channels, e.g., 15 flow channels, in a sensor, while other embodiments detect, output and analyze the measurements from each flow channel individually. This was found by laboratory experiment to be very useful, such as when gas was flowing up from below the current position of the measurement, the gas caused an actual movement of water back and forth in each of the multitude of flow channels. The sensor detected this water movement, which manifests itself as a large background noise, which effect is referred to herein as water sloshing. When the sensor output was summed in this situation of gas flowing up from below, the output detected the sloshing in all the channels, but any actual water inflow through the casing is typically only one or two channels.
  • the measurement of water inflow or water outflow includes the capability to measure the other.
  • each flow channel is detected individually.
  • each flow channel is measured and processed completely independently of the other flow channels.
  • subsets of the full set of flow channels may be summed and detected. While an embodiment is described below with 15 flow channels, but any number of flow channels could be used, such as a larger or smaller number than 15. For example, any specific number of flow channels between 2 and 30 may be used, or a number of flow channels outside this range may be used.
  • subsets of the flow channels may be summed and then each subset detected individually.
  • the flow channels may be exclusive to each subset, or the subsets of flow channels may overlay with each other.
  • the sensor providing multiple measurements may be referred to as an array sensor, in distinction from a summed output sensor.
  • FIG. 3 is a block diagram illustrating the signal conditioning and control circuitry 300 for the array sensor data.
  • the system comprises an analog signal conditioner 302 coupled between the array sensor electrode pairs and a microcontroller unit 304 containing a microcontroller 306 and an analog-to-digital converter 308.
  • the analog signal conditioner 302 for each of flow channels 1 -15 comprises two leads input to a differential amplifier 310. The two leads are coupled to one electrode pair in one flow channel, and provide the basic measurement voltage signal from that flow channel.
  • the analog signal conditioner circuitry is repeated for as many channels as exist, which in this embodiment is 15 channels, and thus there are 15 analog signal conditioner circuits 302.
  • the analog signal conditioner circuit 302 operates as follows.
  • the voltage signal from the flow channel measurement is input to a differential amplifier 310 with a relatively low gain, for example about 2 in this embodiment. This low gain generally keeps the noise relatively low.
  • the gain may be any value between about 1.1 and about 3.0 or higher.
  • the signal is input to a low pass filter 312 to reduce the noise before further amplification.
  • the signal is amplified 314 with a sizable gain, for example a gain of about 201, after the noise has been reduced by the filter.
  • this gain may be any value between about 50 and about 400 or a value outside this range.
  • the signals from the plurality of flow channels are input to the microcontroller board 304 for analog-to-digital conversion.
  • the analog signals are buffered 316, and then connected to the inputs of the analog multiplexer (MUX) 318.
  • the MUX 318 upon command from the microcontroller 306, outputs the analog signal from the appropriate channel to an amplifier 320 (with a gain of 10 in this embodiment). Alternatively, this gain may be any value between about 2 and about 50 or more.
  • the signal then is buffered in the buffer 322, and input to the analog-to-digital converter (ADC) 308.
  • the ADC 308 converts the incoming analog signal into a digital signal, which is output for use in computing the measurement value.
  • the measurement value is the difference of the two ADC outputs from a given flow channel (1 to 15), when the electrical current in the coil is going in opposite directions.
  • the user can be provided the option of reading ADC values a user-set number of times, such as 4 times, and averaging the results, which generally reduces the noise.
  • the noise reduction takes place due to the averaging of the true signal and noise, because the signal is present repeatedly and noise is random, thus canceling itself out.
  • the signal may be averaged any number of times between about 2 and about 100 or more.
  • Various embodiments disclosed herein include systems and methods for reducing this casing noise effect when using an electromagnetic flowmeter sensor in a casing.
  • the casing noise effect is due to the contact with and moving of the metal sensor pad over the metal steel casing.
  • Galvanic voltages occur when two dissimilar metals are both in an electrolyte, such as water in oil well casings, which is very common. Galvanic voltage is the principle behind flashlight batteries and other batteries.
  • the phrase reducing casing noise, and its forms indicates the lessening or diminishing of the casing noise to such an extent that usable or valid signal measurements may be made of the fluid flow, and includes complete elimination or removal of the casing noise.
  • FIG. 4A illustrates a prior method of wiring the shield 400 for the current wires to the sensor coil that resulted in casing effect noise.
  • the shield is connected to soft iron core at one end and to the analog processing board ground at the other end.
  • Figure 4B illustrates an embodiment implementation of wiring the shield 402 for the current wires to the sensor coil that greatly reduces the casing effect noise.
  • the shield is not connected to soft iron core at one end, but continues to be connected to analog processing board ground at the other end. This method simply disconnects one prior connection.
  • Another implementation is to place an insulator of some type on the face of the sensor pad, so the sensor pad does not make metal to metal contact with the casing, but rather insulator to metal contact. This virtually eliminates the casing noise, by preventing metal to metal contact.
  • This can be implemented in numerous ways, such as by placing a wear resistant ceramic strip on the outer face of the sensor pad, except not over the sensor flow channels so flow can go through the flow channels.
  • the ceramic strip can have a thickness of the order of 1/8 inch.
  • Another alternative is to use insulating bumps. These can have a variety of shapes. Their thickness can be of the order of 1/8 inch.
  • Another alternative is the use of several insulating rollers, such as roller balls. The roller balls can have a radius of the order of 1/8 inch.
  • Another alternative is use of an insulating wear resistant coating on the sensor pad face. This coating can be very thin, or the order of tens of mils (0.010 inch). Other alternatives are also available.
  • FIG. 5A and 5B illustrate the basic situation with a wellbore with the sensor pad and sensor.
  • Figure 5A illustrates a top view of the sensor pad 500 in contact with casing inner wall and rotating around casing inner wall.
  • Figure 5B illustrates a side view of the metal sensor pad 500 touching metal casing wall.
  • the sensor itself that detects inflowing or outflowing water. The sensor is only a part of the sensor pad.
  • Figures 5C - 5H illustrate some of the various embodiments of this implementation.
  • Figure 5C illustrates a side view and a front view of the sensor pad with strips of insulating material 502, preferably wear resistant, to prevent pad metal to casing metal contact.
  • Figure 5C illustrates that strips of an insulating material can be used to prevent sensor pad metal to casing metal contact.
  • the insulating strips would preferably be of some wear resistant material, such as certain types of ceramic. The strips would not cover the sensor itself, in order to allow water flow detection by the sensor.
  • Figure 5D illustrates that several sensor bumps of an insulating material 504, preferably wear resistant, can be used.
  • the bumps can be of various shapes, rectangular, round, mounds, etc.
  • Figure 5E illustrates that insulating roller balls 506, such as made from ceramic, can be used to prevent the metal to metal contact of the sensor pad face to the metal casing. Roller balls also would help the sensor pad move more easily around the casing. Other types of rollers, such as wheels or cylinders, can be used.
  • Figure 5F illustrates that an insulating coating 508, preferably wear resistant, can be used to prevent metal to metal contact of the sensor pad face to the casing inner wall. This coating can be very thin.
  • Figure 5G illustrates that the centralizers used on the entire logging string can have insulation 510 over the intervals where they can contact the metal casing.
  • This insulation can be any of the aforementioned types (strips, bumps, rollers, coatings, etc.). This would further reduce metal to metal contact and help reduce any casing contact noise.
  • Figure 5H illustrates that the centralizers used on the logging string can have insulation 512 over the intervals where they contact the metal logging tool body itself, so the centralizers do not have electrical contact with the logging tool body.
  • Another implementation is to make a good ground (low resistance or low ohm) connection of the well's casing to the logging tool's instrument ground. This can be done at the surface at the well head, or by a device such as a metal scraper or other device to make such a connection downhole generally in the vicinity of the measurement pad.
  • Fig 6A illustrates a good electrical connection 600 of the casing (at the wellhead here) to the logging tool's instrument ground.
  • Figure 6B illustrates the making of a good electrical connection 602 with the casing downhole in the vicinity of the logging tool.
  • the casing is likely corroded. Any corrosion will have to be cut through so a proper electrical connection can be made. That casing connection will then be connected to the logging tool's instrument ground.
  • Various methods can be used to cut through any casing corrosion and make a good electrical contact with the casing.
  • Figure 6C illustrates a cutting wheel 604 with a sharp bladed outer edge in contact with the casing to cut through any corrosion on the casing interior.
  • the cutting wheel can be held against the casing by numerous means, such as spring force, motorized, positioned on a centralizer, etc.
  • the cutting wheel can rotate to help with both cutting and keeping the various edges sharp for good cutting. Rotation of the cutting wheel can be done by natural rotation during movement along the casing if the cutting wheel is built to rotate about a center axis, or it can be motorized to rotate.
  • the cutting edge would be electrically connected to the logging tool's instrument ground.
  • Figure 6D illustrates a knife blade like sharp cutting edge 606 in contact with the casing to cut through any corrosion on the casing interior.
  • the cutting edge can be held against the casing by numerous means, such as spring force, motorized, positioned on a centralizer, etc.
  • the cutting edge can be serrated also, like a wood saw or hack saw. The cutting edge would be electrically connected to the logging tool's instrument ground.
  • Figure 6E illustrates a sharp cutting point 608, perhaps on the end of a rod and perhaps similar to an ice pick, whereas the sharp end is in contact with the casing to cut through any corrosion on the casing interior.
  • the cutting point can be held against the casing by numerous means, such as spring force, motorized, positioned on a centralizer, etc.
  • the cutting point would be electrically connected to the logging tool's instrument ground.
  • Figure 6F illustrates a wire brush 610 with metal (conductive) brushes whereas the wire brushes are in contact with the casing to cut through any corrosion on the casing interior.
  • the wire brush can be held against the casing by numerous means, such as spring force, motorized, positioned on a centralizer, etc.
  • the wire brush would be electrically connected to the logging tool's instrument ground.
  • Figure 6G illustrates a circular wire brush 612 with metal (conductive) brushes.
  • the wire brushes are in contact with the casing to cut through any corrosion on the casing interior.
  • the wire brush can be held against the casing by numerous means, such as spring force, motorized, positioned on a centralizer, etc.
  • the circular brush can be rotationally fixed, allowed to rotate, or forced to rotate, to cut through corrosion.
  • the wire brush would be electrically connected to the logging tool's instrument ground.
  • Figure 6H illustrates a generic electrical contactor 614 disposed partially around the casing.
  • the contactor can also be disposed entirely around the casing. Any of the various methods already mentioned, or others, can be used, or with multiple units or larger units around part or all of the inner circumference of the casing.
  • the casing electrical connector would be electrically connected to the logging tool' s instrument ground.
  • FIG. 7A illustrates a transformer type coupling (isolation) 700. Such a coupling would leave the measurement electronics electrically floating relative to instrument ground.
  • Figure 7B illustrates optical coupling (optical isolation) 702. Such a coupling would leave the measurement electronics electrically floating relative to instrument ground.
  • Figure 7C illustrates capacitive coupling (isolation) 704. Such a coupling would leave the measurement electronics electrically floating relative to instrument ground.
  • FIG. 8A illustrates the present measurement system wherein a square wave of about 80HZ is used to drive the coil and hence gives an 80 HZ signal.
  • the measurement signal 800 is the voltage difference between a pair of electrodes between the positive and negative going current in the coils. Taking this voltage difference will cancel slowly changing exterior spurious voltages between the electrode pair (slowly changing relative to the drive frequency of 80HZ).
  • Figure 8B illustrates how an external and rapidly changing spurious voltage in additional to the real voltage signal will cause the output measurement signal 802 to be affected by the rapidly changing external spurious voltage.
  • FIG. 9 illustrates that a filter can be put in the analog processing electronics to reject the frequencies of the casing noise.
  • a digital filter can be used after the data is digitized.
  • FIG. 10 Another implementation is to put electrical isolators 1000 into the tool string to electrically isolate the other sections of the logging tool string from the sensor section.
  • Figure 10 illustrates that two non-conducting electrical isolator sections can be put in the tool string to electrically isolate the sensor portion of the logging tool from the rest of the logging tool.
  • all digital electronic functions described herein may be performed in either hardware or software, or some combination thereof.
  • the data analysis functions are performed by a processor such as a computer or an electronic data processor in accordance with code such as computer program code, software, and/or integrated circuits that are coded to perform such functions, unless otherwise indicated.
  • Figure 1 1 is a block diagram of a computing system 1300 that may also be used in accordance with an embodiment. It should be noted, however, that the computing system 1300 discussed herein is provided for illustrative purposes only and that other devices may be used.
  • the computing system 1300 may comprise, for example, a desktop computer, a workstation, a laptop computer, a personal digital assistant, a dedicated unit customized for a particular application, or the like. Accordingly, the components of the computing system 1300 disclosed herein are for illustrative purposes only and other embodiments of the present invention may include additional or fewer components.
  • the computing system 1300 comprises a processing unit 1310 equipped with one or more input devices 1312 (e.g., a mouse, a keyboard, or the like), and one or more output devices, such as a display 1314, a printer 1316, or the like.
  • the processing unit 1310 includes a central processing unit (CPU) 1318, memory 1320, a mass storage device 1322, a video adapter 1324, an I/O interface 1326, and a network interface 1328 connected to a bus 1330.
  • the bus 1330 may be one or more of any type of several bus architectures including a memory bus or memory controller, a peripheral bus, video bus, or the like.
  • the CPU 1318 may comprise any type of electronic data processor.
  • the CPU 1318 may comprise a processor (e.g., single core or multi-core) from Intel Corp. or Advanced Micro Devices, Inc., a Reduced Instruction Set Computer (RISC), an Application-Specific Integrated Circuit (ASIC), or the like.
  • the memory 1320 may comprise any type of system memory such as static random access memory (SRAM), dynamic random access memory (DRAM), synchronous DRAM (SDRAM), read-only memory (ROM), a combination thereof, or the like.
  • the memory 1320 may include ROM for use at boot-up, and DRAM for data storage for use while executing programs.
  • the memory 1320 may include one of more non-transitory memories.
  • the mass storage device 1322 may comprise any type of storage device configured to store data, programs, and other information and to make the data, programs, and other information accessible via the bus 1328.
  • the mass storage device 1322 is configured to store the program to be executed by the CPU 1318.
  • the mass storage device 1322 may comprise, for example, one or more of a hard disk drive, a magnetic disk drive, an optical disk drive, or the like.
  • the mass storage device 1322 may include one or more non-transitory memories.
  • the video adapter 1324 and the I/O interface 1326 provide interfaces to couple external input and output devices to the processing unit 1310.
  • input and output devices include the display 1314 coupled to the video adapter 1324 and the mouse/keyboard 1312 and the printer 1316 coupled to the I/O interface 1326.
  • the network interface 1328 which may be a wired link and/or a wireless link, allows the processing unit 1310 to communicate with remote units via the network 1332.
  • the processing unit 1310 is coupled to a local-area network or a wide-area network to provide communications to remote devices, such as other processing units, the Internet, remote storage facilities, or the like.
  • Other devices may be coupled to the processing unit 1310 through I/O interface 1326 or network interface 1328, or otherwise.
  • the microcontroller board of Figure 3 may be directly or indirectly coupled to processing unit 1310 for analysis of the output data from the microcontroller board.
  • the data may be received and analyzed in real-time while a well is being logged or immediately thereafter, or in a delayed or batch manner any time after a well has been logged.
  • the coupling may include a wired and/or wireless connection, and processing unit 1310 may be located at the site of the well or remote from the well.
  • the circuitry and functions performed by the microcontroller board may be located in or with the processing unit 1310 at a well site, with the analog signal conditioner transmitting the data from the well to the collocated processing unit 1310/microcontroller board.
  • the computing system 1300 may include other components.
  • the computing system 1300 may include power supplies, cables, a motherboard, removable storage media, network interface, and the like. These other components, although not shown, are considered part of the computing system 1300.
  • any one of the components of the computing system 1300 may include multiple components.
  • the CPU 1318 may comprise multiple processors
  • the display 1314 may comprise multiple displays, and/or the like.
  • the computing system 1300 may include multiple computing systems directly coupled and/or networked.
  • one or more of the components may be remotely located.
  • a display may be remotely located from the processing unit.
  • display information e.g., flow rates and other analysis results, may be transmitted via the network interface to a display unit or a remote processing unit having a display coupled thereto.

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Abstract

La présente invention concerne des systèmes et des procédés permettant de réduire les effets de bruit du boîtier lorsqu'on effectue des mesures de l'écoulement d'un fluide conducteur dans un boîtier métallique à l'aide d'un capteur électromagnétique.
PCT/US2014/067754 2014-11-26 2014-11-26 Systèmes et procédés permettant de réduire les effets de bruit du boîtier Ceased WO2016085506A1 (fr)

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Cited By (1)

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US4794322A (en) * 1985-11-01 1988-12-27 Schlumberger Technology Corp. Method, system, and tool for investigating borehole casings
US4747451A (en) * 1987-08-06 1988-05-31 Oil Well Automation, Inc. Level sensor
US20060265168A1 (en) * 2003-09-05 2006-11-23 Patten Andrew T Flow meter filter system and method
US20100222652A1 (en) * 2007-09-07 2010-09-02 Ok Kyung Cho Diagnostic sensor unit
US20090101503A1 (en) * 2007-10-18 2009-04-23 Denso Corporation Gas sensor and method of manufacturing thereof
US20120169334A1 (en) * 2010-12-29 2012-07-05 Schlumberger Technology Corporation Microcoil nmr for downhole microfluidics platform
WO2012166627A2 (fr) * 2011-05-27 2012-12-06 Rem Scientific Enterprises, Inc. Capteur de mesure d'écoulement de fluide, procédé et analyse
US20140084927A1 (en) * 2012-09-21 2014-03-27 Vista Clara Inc. Surface-based nmr measurement
WO2014085894A1 (fr) * 2012-12-03 2014-06-12 Evolution Engineering Inc. Centreur de sonde de forage

Cited By (1)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US11933167B2 (en) * 2017-11-03 2024-03-19 Expro North Sea Limited Deployable electrical contact device

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