CA2901894C - Rotating fluid measurement device and method - Google Patents
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- CA2901894C CA2901894C CA2901894A CA2901894A CA2901894C CA 2901894 C CA2901894 C CA 2901894C CA 2901894 A CA2901894 A CA 2901894A CA 2901894 A CA2901894 A CA 2901894A CA 2901894 C CA2901894 C CA 2901894C
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Abstract
A method of measuring a conductive fluid flow, the method comprising: traversing a casing with a tool, the tool comprising a tool body and an arm assembly pivotably attached to the tool body, wherein a pivot axis of the arm assembly is orthogonal to a long axis of the tool body, wherein the arm assembly supports a sensor pad comprising an electromagnetic sensor, wherein a sensor pad long axis is parallel to the tool body long axis, wherein a first pair of opposite inner angles of the arm assembly are acute angles, and wherein a second pair of opposite inner angles of the arm assembly are obtuse angles; azimuthally rotating the sensor pad along an inner circumference of the casing; and measuring a speed and direction of radial conductive fluid flow through a wall of the casing.
Description
Rotating Fluid Measurement Device and Method This is a division of copending Canadian Patent Application 2,781,625 filed November 9, 2007. The '625 application being a division of CA 2,667,498, issued on January 15, 2013.
TECHNICAL FIELD
The present invention relates generally to a device and method for fluid flow measurement and more particularly to a device and method for electromagnetic fluid flow measurement.
BACKGROUND
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. Usually, 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 easing 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.
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.
In current practice, 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.
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.
Furthermore, in deviated and horizontal wells with multiphase flow, and also in some vertical wells, conventional production logging methods are frequently misleading due to complex and varying flow regimes or patterns that cause misleading and non-representative readings. Generally, prior art production logging is performed in these complex flow regimes in the central area of the borehole and yields frequently misleading results, or may possess other
TECHNICAL FIELD
The present invention relates generally to a device and method for fluid flow measurement and more particularly to a device and method for electromagnetic fluid flow measurement.
BACKGROUND
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. Usually, 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 easing 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.
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.
In current practice, 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.
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.
Furthermore, in deviated and horizontal wells with multiphase flow, and also in some vertical wells, conventional production logging methods are frequently misleading due to complex and varying flow regimes or patterns that cause misleading and non-representative readings. Generally, prior art production logging is performed in these complex flow regimes in the central area of the borehole and yields frequently misleading results, or may possess other
-2-severe limitations. Often the location of an influx of water, which is usually the information = desired from production logging, is not discernable due to the small change in current measurement responses superimposed upon large variations caused by the multiphase flow conditions.
As described in commonly owned U.S. Patent No. 6,711,947, entitled "Fluid Flow Measuring Device and Method of Manufacturing Thereof," issued March 30, 2004, and WO
Publ. No. 2005/033633 A2, entitled "Apparatus and Method for Fluid Flow Measurement with Sensor Shielding," filed March 31, 2006, one fluid flow measurement implementation approach involves using one or more coils of wire in an approximate elliptical shape with an expanding loop of wire of the same shape as the coil(s). The loop may allow the wire coil(s) to constrict and elongate to run a measurement tool into a wellbore through smaller diameter tubulars and then expand upon entry into larger diameter casings. This approach, however, may have a difficulty in some applications in that a coil of wire with multiple turns of wire may be mechanically difficult to constrict, and also may be mechanically difficult to expand.
As described in commonly owned U.S. Patent No. 6,711,947, entitled "Fluid Flow Measuring Device and Method of Manufacturing Thereof," issued March 30, 2004, and WO
Publ. No. 2005/033633 A2, entitled "Apparatus and Method for Fluid Flow Measurement with Sensor Shielding," filed March 31, 2006, one fluid flow measurement implementation approach involves using one or more coils of wire in an approximate elliptical shape with an expanding loop of wire of the same shape as the coil(s). The loop may allow the wire coil(s) to constrict and elongate to run a measurement tool into a wellbore through smaller diameter tubulars and then expand upon entry into larger diameter casings. This approach, however, may have a difficulty in some applications in that a coil of wire with multiple turns of wire may be mechanically difficult to constrict, and also may be mechanically difficult to expand.
-3-=
These and other problems are generally solved or circumvented, and technical advantages are generally achieved, by embodiments of the invention that provide fluid flow detection and measurement for a wellbore, casing, or other conduit.
Implementations disclosed by U.S. Pat. No. 6,711,947, in addition to the sensor loop, include electromagnetic flow measurement utilizing one pair of electrodes on a rotating arm to sweep around the casing inner wall, and a plurality of small individual electromagnetic sensors (e.g. one electrode pair) used on each of a multiply-armed caliper tool.
Embodiments disclosed herein provide improvements to tool body, tool arm and sensor devices and methods for fluid flow measurement.
Certain exemplary embodiments can provide a method of measuring a conductive fluid flow, the method comprising: traversing a casing with a tool, the tool comprising a tool body and an arm assembly pivotably attached to the tool body, wherein a pivot axis of the arm assembly is orthogonal to a long axis of the tool body, wherein the arm assembly supports a sensor pad comprising an electromagnetic sensor, wherein a sensor pad long axis is parallel to the tool body long axis, wherein a first pair of opposite inner angles of the arm assembly are acute angles, and wherein a second pair of opposite inner angles of the arm assembly are obtuse angles; azimuthally rotating the sensor pad along an inner circumference of the casing; and measuring a speed and direction of radial conductive fluid flow through a wall of the casing.
Certain exemplary embodiments can provide a method for borehole logging comprising: traversing a borehole with a tool having a tool long axis, the tool comprising a first stationary tool segment, a rotatable tool segment having a first end rotatably coupled to the first stationary tool segment, a sensor pad having a pad long axis parallel to the tool long axis, and an arm assembly coupling the sensor pad to the rotatable tool segment, wherein the arm assembly is pivotably attached to the rotatable tool segment with a pivot axis of the arm assembly that is orthogonal to the tool long axis; azimuthally rotating the rotatable tool segment around the tool long axis with respect to the first stationary tool segment to move the sensor pad along an inner wall of the borehole; moving the sensor pad radially inward toward or outward from the rotatable tool segment as the arm assembly is pivoted on the pivot axis; and electromagnetically sensing radial conductive fluid flow through the inner wall of the borehole with the sensor pad.
These and other problems are generally solved or circumvented, and technical advantages are generally achieved, by embodiments of the invention that provide fluid flow detection and measurement for a wellbore, casing, or other conduit.
Implementations disclosed by U.S. Pat. No. 6,711,947, in addition to the sensor loop, include electromagnetic flow measurement utilizing one pair of electrodes on a rotating arm to sweep around the casing inner wall, and a plurality of small individual electromagnetic sensors (e.g. one electrode pair) used on each of a multiply-armed caliper tool.
Embodiments disclosed herein provide improvements to tool body, tool arm and sensor devices and methods for fluid flow measurement.
Certain exemplary embodiments can provide a method of measuring a conductive fluid flow, the method comprising: traversing a casing with a tool, the tool comprising a tool body and an arm assembly pivotably attached to the tool body, wherein a pivot axis of the arm assembly is orthogonal to a long axis of the tool body, wherein the arm assembly supports a sensor pad comprising an electromagnetic sensor, wherein a sensor pad long axis is parallel to the tool body long axis, wherein a first pair of opposite inner angles of the arm assembly are acute angles, and wherein a second pair of opposite inner angles of the arm assembly are obtuse angles; azimuthally rotating the sensor pad along an inner circumference of the casing; and measuring a speed and direction of radial conductive fluid flow through a wall of the casing.
Certain exemplary embodiments can provide a method for borehole logging comprising: traversing a borehole with a tool having a tool long axis, the tool comprising a first stationary tool segment, a rotatable tool segment having a first end rotatably coupled to the first stationary tool segment, a sensor pad having a pad long axis parallel to the tool long axis, and an arm assembly coupling the sensor pad to the rotatable tool segment, wherein the arm assembly is pivotably attached to the rotatable tool segment with a pivot axis of the arm assembly that is orthogonal to the tool long axis; azimuthally rotating the rotatable tool segment around the tool long axis with respect to the first stationary tool segment to move the sensor pad along an inner wall of the borehole; moving the sensor pad radially inward toward or outward from the rotatable tool segment as the arm assembly is pivoted on the pivot axis; and electromagnetically sensing radial conductive fluid flow through the inner wall of the borehole with the sensor pad.
-4-Certain exemplary embodiments can provide a method for borehole logging comprising: traversing a borehole with a tool, the tool comprising a tool body having a tool body long axis, a sensor pad having a pad long axis parallel to the tool body long axis, a first min having a first end pivotably coupled to the tool body and a second end coupled to the sensor pad, and a second arm having a first end pivotably coupled to the tool body and a second end coupled to the sensor pad, wherein pivot axes of the ends of the arms are orthogonal to the tool body long axis; azimuthally rotating the tool around the tool body long axis to move the sensor pad along an inner wall of the borehole; moving the sensor pad radially inward toward or outward from the tool body as the arms are pivoted on their pivot axes, while maintaining a first vertical angle between the first arm and the tool body at a substantially same magnitude and direction as a second vertical angle between the second arm and the tool body; and electromagnetically sensing radial conductive fluid flow through the inner wall of the borehole with the sensor pad.
An advantage of certain embodiments is that mechanical contraction or expansion of a multiple-turn wire coil may be avoided through the use of one or more sensor pads disposed on one or more arm assemblies.
An advantage of other embodiments is that an arm assembly may maintain a sensor pad proximate to the sides of the casing so that fluid flow at the sides of the casing may be measured without interference from the fluids in the middle of the casing.
Additionally, the aim assembly may maintain the sensor proximate to the inner circumference of the casing when the casing deviates from a vertical alignment.
An advantage of yet other embodiments is that a sensor may generate a large magnetic field which generally enables better detection of fluid flow. Also, the sensor generally distinguishes between conductive fluid flow and non-conductive fluid flow.
An advantage of certain embodiments is that mechanical contraction or expansion of a multiple-turn wire coil may be avoided through the use of one or more sensor pads disposed on one or more arm assemblies.
An advantage of other embodiments is that an arm assembly may maintain a sensor pad proximate to the sides of the casing so that fluid flow at the sides of the casing may be measured without interference from the fluids in the middle of the casing.
Additionally, the aim assembly may maintain the sensor proximate to the inner circumference of the casing when the casing deviates from a vertical alignment.
An advantage of yet other embodiments is that a sensor may generate a large magnetic field which generally enables better detection of fluid flow. Also, the sensor generally distinguishes between conductive fluid flow and non-conductive fluid flow.
-5-BRIEF DESCRIPTION OF THE DRAWINGS
For a more complete understanding of the present invention, and the advantages thereof, reference is now made to the following descriptions taken in conjunction with the accompanying drawing, in which:
Figure 1 is a cross-sectional view of an oil or gas well;
Figure 2A illustrates an embodiment of a logging tool string;
Figures 2B & 2C show embodiments of a logging tool arm assembly;
Figures 3A & 3B show various views of an embodiment of an arm assembly carrier;
Figure 4 illustrates a non-rotating, multiple arm embodiment; and Figures 5A, 5B, and 5C show different views of an embodiment of a sensor housing;
Figures 6A ¨ 6K show various views and components of flow sensor embodiments;
Figures 7A ¨ 7E illustrate various views of a sensor housing;
Figures 8A ¨ 8E illustrate various components of a sensor housing;
Figures 9 ¨ 9C show various views of a sensor housing; and Figures 10A ¨ 10C illustrate various electrode/resistor network embodiments.
Corresponding numerals and symbols in the different figures generally refer to corresponding parts unless otherwise indicated. The figures are drawn to clearly illustrate the relevant aspects of the illustrative embodiments; while some figures are drawn to scale, other figures are not necessarily drawn to scale.
For a more complete understanding of the present invention, and the advantages thereof, reference is now made to the following descriptions taken in conjunction with the accompanying drawing, in which:
Figure 1 is a cross-sectional view of an oil or gas well;
Figure 2A illustrates an embodiment of a logging tool string;
Figures 2B & 2C show embodiments of a logging tool arm assembly;
Figures 3A & 3B show various views of an embodiment of an arm assembly carrier;
Figure 4 illustrates a non-rotating, multiple arm embodiment; and Figures 5A, 5B, and 5C show different views of an embodiment of a sensor housing;
Figures 6A ¨ 6K show various views and components of flow sensor embodiments;
Figures 7A ¨ 7E illustrate various views of a sensor housing;
Figures 8A ¨ 8E illustrate various components of a sensor housing;
Figures 9 ¨ 9C show various views of a sensor housing; and Figures 10A ¨ 10C illustrate various electrode/resistor network embodiments.
Corresponding numerals and symbols in the different figures generally refer to corresponding parts unless otherwise indicated. The figures are drawn to clearly illustrate the relevant aspects of the illustrative embodiments; while some figures are drawn to scale, other figures are not necessarily drawn to scale.
-6-DETAILED DESCRIPTION OF ILLUSTRATIVE EMBODIMENTS
The making and using of the presently preferred embodiments are discussed in detail below. It should be appreciated, however, that the present invention provides many applicable inventive concepts that can be embodied in a wide variety of specific contexts. The specific embodiments discussed are merely illustrative of specific ways to make and use the invention, and do not limit the scope of the invention.
The present invention will be described with respect to preferred embodiments in a specific context, namely a fluid flow measurement tool used 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.
Referring to Figure 2A, 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. The general features of a measurement tool and the basic operation of an electromagnetic fluid flow sensor are disclosed in U.S. Pat. No. 6,711,947 and WO Publ. No. 2005/033633 A2. With respect to the embodiment of Figure 2A, 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 113 on arm assembly 111 about the inner circumference 103 of the casing 102 as the tool 100 axially traverses the casing 102. Preferably, 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 110 by rotating joint 107, which allows for electrical communications (signals and power) to pass between the rotating tool segment 110 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
The making and using of the presently preferred embodiments are discussed in detail below. It should be appreciated, however, that the present invention provides many applicable inventive concepts that can be embodied in a wide variety of specific contexts. The specific embodiments discussed are merely illustrative of specific ways to make and use the invention, and do not limit the scope of the invention.
The present invention will be described with respect to preferred embodiments in a specific context, namely a fluid flow measurement tool used 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.
Referring to Figure 2A, 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. The general features of a measurement tool and the basic operation of an electromagnetic fluid flow sensor are disclosed in U.S. Pat. No. 6,711,947 and WO Publ. No. 2005/033633 A2. With respect to the embodiment of Figure 2A, 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 113 on arm assembly 111 about the inner circumference 103 of the casing 102 as the tool 100 axially traverses the casing 102. Preferably, 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 110 by rotating joint 107, which allows for electrical communications (signals and power) to pass between the rotating tool segment 110 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
-7-with one being below the rotating tool body 110 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 113 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 110 (along with arm assembly 111 and sensor pad 113) may be rotated by motor 106 located within stationary tool body 104. In other embodiments, 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. In addition, 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.
Generally, substantially all exposed parts of sonde 100, including rotating tool segment 110 and sensor pad 113, 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.
In operation, 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.
Preferably, tool 100 is slowly moved axially at a speed such that, while sensor pad 113 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. Alternatively, 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.
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 113 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 110 (along with arm assembly 111 and sensor pad 113) may be rotated by motor 106 located within stationary tool body 104. In other embodiments, 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. In addition, 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.
Generally, substantially all exposed parts of sonde 100, including rotating tool segment 110 and sensor pad 113, 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.
In operation, 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.
Preferably, tool 100 is slowly moved axially at a speed such that, while sensor pad 113 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. Alternatively, 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.
-8-In one embodiment, the rotation rate of the rotating tool segment may be measured, so that a computer or log interpreter can determine if the tool stops rotating and thus determine the portion of the borehole inner wall not logged and over what depth interval that occurs.
Figure 2B shows an embodiment of arm assembly 111, which includes upper arm and lower arm 208. Upper arm 207 and lower arm 208 are pivotably connected at one end to rotating tool body 110. The other ends of arm 207 and arm 208 are connected to opposite ends of sensor pad 113, thus generally forming a parallelogram. Alternatively, the other ends of the arms may be connected to a mounting arm or bracket providing a mounting surface for sensor =
pad 113. The mounting bracket preferably comprises an open area behind the sensor area of sensor pad 113 to allow for the free flow of fluid into sensor pad 113 and out the back of the mounting bracket. Any type of mechanical connector that allows pivoting of the arms 207, 208 may be used to attach the arms to rotating tool body 110 and sensor pad 113.
Connector types such as hinges, pin and slot, or combinations of these are some examples. This arm arrangement generally keeps sensor pad 113 substantially parallel to the axis of the casing, which may enable accurate measurements. In another embodiment, sensor pad 113 may be connected to the rotating tool body by only a single arm.
In other embodiments, the arm assembly 111 connections with upper arm 207, lower arm=
208, rotating tool body 110, and sensor pad 113 may create a quadrilateral shape or a substantially oval or circular shape, as examples. While this embodiment and the descriptions of other embodiments that follow refer to arm assembly 111 as connected to rotating tool body 110, the arm assembly also could be connected to stationary tool body 104.
Alternatively, in some embodiments of tool 100, the rotating tool body 110 may be omitted. As another alternative, there may be two, three, four or more arm assemblies in any of the above configurations.
Maintaining the arm assembly 111 against a casing wall may be accomplished in many different ways. In one embodiment, springs 203, 204 are used to exert outward force on upper arm 207 and lower arm 208 to push them away from rotating tool body 110. A
torsion spring is one example of a type of spring which may be used for springs 203, 204. The angle 201 between upper arm 207 and rotating tool body 110 is preferably maintained between about 15 and about 45 degrees, more preferably between about 20 and about 40 degrees, still more preferably between about 25 and about 35 degrees, and most preferably at about 30 degrees, depending on the specific application. Limiting the maximum deviation from vertical of angle 201 helps to
Figure 2B shows an embodiment of arm assembly 111, which includes upper arm and lower arm 208. Upper arm 207 and lower arm 208 are pivotably connected at one end to rotating tool body 110. The other ends of arm 207 and arm 208 are connected to opposite ends of sensor pad 113, thus generally forming a parallelogram. Alternatively, the other ends of the arms may be connected to a mounting arm or bracket providing a mounting surface for sensor =
pad 113. The mounting bracket preferably comprises an open area behind the sensor area of sensor pad 113 to allow for the free flow of fluid into sensor pad 113 and out the back of the mounting bracket. Any type of mechanical connector that allows pivoting of the arms 207, 208 may be used to attach the arms to rotating tool body 110 and sensor pad 113.
Connector types such as hinges, pin and slot, or combinations of these are some examples. This arm arrangement generally keeps sensor pad 113 substantially parallel to the axis of the casing, which may enable accurate measurements. In another embodiment, sensor pad 113 may be connected to the rotating tool body by only a single arm.
In other embodiments, the arm assembly 111 connections with upper arm 207, lower arm=
208, rotating tool body 110, and sensor pad 113 may create a quadrilateral shape or a substantially oval or circular shape, as examples. While this embodiment and the descriptions of other embodiments that follow refer to arm assembly 111 as connected to rotating tool body 110, the arm assembly also could be connected to stationary tool body 104.
Alternatively, in some embodiments of tool 100, the rotating tool body 110 may be omitted. As another alternative, there may be two, three, four or more arm assemblies in any of the above configurations.
Maintaining the arm assembly 111 against a casing wall may be accomplished in many different ways. In one embodiment, springs 203, 204 are used to exert outward force on upper arm 207 and lower arm 208 to push them away from rotating tool body 110. A
torsion spring is one example of a type of spring which may be used for springs 203, 204. The angle 201 between upper arm 207 and rotating tool body 110 is preferably maintained between about 15 and about 45 degrees, more preferably between about 20 and about 40 degrees, still more preferably between about 25 and about 35 degrees, and most preferably at about 30 degrees, depending on the specific application. Limiting the maximum deviation from vertical of angle 201 helps to
-9-ensure smoother passage of the tool 100 into smaller diameter casings from larger diameter casings, and around obstacles.
Alternatively, springs may be implemented at the interface of the arras to the sensor pad, in addition or in place of the above springs. Preferably, the hinges and springs have sufficient strength to withstand the rotational torque during operation, including during rotational hang up.
Furthermore, the hinges and springs preferably are debris resistant.
Figure 2C shows another embodiment of arm assembly 111 with spring 210 and bar 211.
Spring 210 is connected to the rotating tool body 110 and to bar 211, which is connected to one of the assembly arms 207 or 208. Preferably, bar 211 comprises a groove to maintain spring 210 substantially in the center of bar 211. As an example, an extension spring is one type of spring which may be used for spring 210. Spring 210 exerts an outward force on arm assembly 111 to maintain sensor pad 113 in contact with or in close proximity to a casing wall.
Alternatively, the arm assembly may be motorized and use the force of a motor to maintain the sensor pad against the sensor wall. A feedback loop may be implemented to assist in controlling the motor. As yet another alternative, a force system on the arm assembly provides a close to a constant force of the sensor pad against the inner wall of the borehole, independent of the diameter that the arm assembly is open. This may be achieved, for example, by a counter spring to the torsional or extension spring that has about the same force characteristics but with an inverse direction of movement. Other alternatives include a non-uniformly shaped spring, a second spring that initiates at some position in the movement of the arm assembly, or a many-turn torsional spring.
Referring back to Figure 2B, arm assembly 111 additionally may comprise a long arm 115 connected to the lower end of lower aiiii 208 or sensor pad 113. Long arm 115 is pivotably coupled to rotating tool body 110. The angle 202 between long arm 115 and rotating tool body 110 is preferably between about 4 and about 10 degrees, more preferably between about 5 and about 9 degrees, more preferably between about 6 and about 8 degrees, and most preferably about 7 degrees, depending on the specific application. Maintaining the small angle assists with smoother passage of tool 100 through smaller diameter casings, around obstacles and restrictions, and also assists in collapsing the tool into its reduced diameter mode (described below). Long arm 115 may be coupled to rotating tool body 110 by any mechanism that allows the angles between long aim 115 and rotating tool body 110 to change.
Preferably, long arm 115
Alternatively, springs may be implemented at the interface of the arras to the sensor pad, in addition or in place of the above springs. Preferably, the hinges and springs have sufficient strength to withstand the rotational torque during operation, including during rotational hang up.
Furthermore, the hinges and springs preferably are debris resistant.
Figure 2C shows another embodiment of arm assembly 111 with spring 210 and bar 211.
Spring 210 is connected to the rotating tool body 110 and to bar 211, which is connected to one of the assembly arms 207 or 208. Preferably, bar 211 comprises a groove to maintain spring 210 substantially in the center of bar 211. As an example, an extension spring is one type of spring which may be used for spring 210. Spring 210 exerts an outward force on arm assembly 111 to maintain sensor pad 113 in contact with or in close proximity to a casing wall.
Alternatively, the arm assembly may be motorized and use the force of a motor to maintain the sensor pad against the sensor wall. A feedback loop may be implemented to assist in controlling the motor. As yet another alternative, a force system on the arm assembly provides a close to a constant force of the sensor pad against the inner wall of the borehole, independent of the diameter that the arm assembly is open. This may be achieved, for example, by a counter spring to the torsional or extension spring that has about the same force characteristics but with an inverse direction of movement. Other alternatives include a non-uniformly shaped spring, a second spring that initiates at some position in the movement of the arm assembly, or a many-turn torsional spring.
Referring back to Figure 2B, arm assembly 111 additionally may comprise a long arm 115 connected to the lower end of lower aiiii 208 or sensor pad 113. Long arm 115 is pivotably coupled to rotating tool body 110. The angle 202 between long arm 115 and rotating tool body 110 is preferably between about 4 and about 10 degrees, more preferably between about 5 and about 9 degrees, more preferably between about 6 and about 8 degrees, and most preferably about 7 degrees, depending on the specific application. Maintaining the small angle assists with smoother passage of tool 100 through smaller diameter casings, around obstacles and restrictions, and also assists in collapsing the tool into its reduced diameter mode (described below). Long arm 115 may be coupled to rotating tool body 110 by any mechanism that allows the angles between long aim 115 and rotating tool body 110 to change.
Preferably, long arm 115
-10-is coupled to rotating tool body 110 by pin 206 and slot 205 connector. This connection allows for pin 206 to slide within slot 205 allowing long arm 115 to pivot and to expand out or fold flat against or into rotating tool segment 110.
Figures 3A and 3B illustrate side and front views, respectively, of an embodiment of rotating tool body 110 with an added feature of carrier 501. Carrier 501 allows arm assembly 111 and long arm 115 to fold into hollow regions of rotating tool body 110 when compressed. In one embodiment, arm assembly 111 folds into upper hollow section 502 and long arm 115 folds into lower hollow section 503. The middle of carrier 501 has fluid flow cutout 504 and debris cutouts 505. Fluid flow cutout 504 is aligned with sensor pad 113 to allow for fluid passing through the sensor area of sensor 113 to exit through the back of carrier 501.
Carrier 501 generally may permit tool 100 and sensor pad 113 to operate even when arm assembly 111 is compressed into carrier 501. Debris cutouts 505 allow for debris and fluid to be pushed out of the carrier 501 so there will not be any obstructions as arm assembly 111 and long arm 115 compress into carrier 501. Carrier 501 also may provide mechanical strength to keep the more delicate portions of the tool intact, for example, when tagging bottom or when running into an obstacle.
Figure 4 illustrates an alternative embodiment non-rotating multiple arm tool 600. Tool 600 utilizes multiple bow spring arms 604 that passively or actively expand or contract to accommodate any changes in the borehole inner diameters, such as when traversing from tubing to casing or vice versa. For the bow spring arms, bowed (or othet shape) wire-like flexible expandable and contractible wires may be used like bow springs. A small sensor pad 606 with transverse (to the borehole axis) flow channels is disposed on a part of the bow spring that is farthest radially outward. The bow spring maintains the sensor pad against a casing inner wall.
Each sensor pad 606 may cover a swath of the inner wall of the borehole. With a selected number of bow springs and sensor pads used in a selected offset pattern, generally the entire or substantially all of the inner area of the borehole portion to be measured may be covered.
Alternatively, a series of bow spring tool segments 602, each section offset azimuthally with respect to the others, may be used to cover substantially the entire inner area of the borehole.
While Figure 4 shows two segments 602, alternatively, in some embodiments, there may be only one segment, or there may be three, four, five, six or more segments, depending upon the specific application. In addition, while Figure 4 shows three bow springs on each segment,
Figures 3A and 3B illustrate side and front views, respectively, of an embodiment of rotating tool body 110 with an added feature of carrier 501. Carrier 501 allows arm assembly 111 and long arm 115 to fold into hollow regions of rotating tool body 110 when compressed. In one embodiment, arm assembly 111 folds into upper hollow section 502 and long arm 115 folds into lower hollow section 503. The middle of carrier 501 has fluid flow cutout 504 and debris cutouts 505. Fluid flow cutout 504 is aligned with sensor pad 113 to allow for fluid passing through the sensor area of sensor 113 to exit through the back of carrier 501.
Carrier 501 generally may permit tool 100 and sensor pad 113 to operate even when arm assembly 111 is compressed into carrier 501. Debris cutouts 505 allow for debris and fluid to be pushed out of the carrier 501 so there will not be any obstructions as arm assembly 111 and long arm 115 compress into carrier 501. Carrier 501 also may provide mechanical strength to keep the more delicate portions of the tool intact, for example, when tagging bottom or when running into an obstacle.
Figure 4 illustrates an alternative embodiment non-rotating multiple arm tool 600. Tool 600 utilizes multiple bow spring arms 604 that passively or actively expand or contract to accommodate any changes in the borehole inner diameters, such as when traversing from tubing to casing or vice versa. For the bow spring arms, bowed (or othet shape) wire-like flexible expandable and contractible wires may be used like bow springs. A small sensor pad 606 with transverse (to the borehole axis) flow channels is disposed on a part of the bow spring that is farthest radially outward. The bow spring maintains the sensor pad against a casing inner wall.
Each sensor pad 606 may cover a swath of the inner wall of the borehole. With a selected number of bow springs and sensor pads used in a selected offset pattern, generally the entire or substantially all of the inner area of the borehole portion to be measured may be covered.
Alternatively, a series of bow spring tool segments 602, each section offset azimuthally with respect to the others, may be used to cover substantially the entire inner area of the borehole.
While Figure 4 shows two segments 602, alternatively, in some embodiments, there may be only one segment, or there may be three, four, five, six or more segments, depending upon the specific application. In addition, while Figure 4 shows three bow springs on each segment,
-11 -alternatively, in some embodiments, there may be one or two bow springs per segment, or there may be four, five, six, seven, eight or more bow springs per segment, depending upon the specific application. Alternatively, one or more of the segments may rotate.
Figures 5A, 5B and 5C illustrate side, front and top views, respectively of sensor pad 113. The sensor pad includes sensor housing 301 which has rounded front face 304, flow channel 303, and sensor 302 within flow channel 303. Sensor housing 301 generally moves along the inner circumference of casing 102 allowing fluid entering or leaving the casing wall to flow along a flow axis of flow channel 303 past sensor 302. Flow channel 303 is preferably between about 3 and about 10 inches long, more preferably between about 4 and about 9 inches long, still more preferably between about 5 and about 8 inches long, and most preferably between about 6 and about 7 inches long, but may be longer or shorter depending on the length of sensor 302 used in a particular application. As explained in more detail below, flow channel 303 and sensor 302 preferably comprise multiple individual flow channels and associated sensors.
Rounded front face 304 of sensor housing 301 generally allows for smoother passage through tubulars and around obstructions. Additionally, all-direction ball rollers 305 may be incorporated on face 304 of housing 301 to aid in passage around obstacles and to reduce friction and wear on the surface of sensor housing 301. Preferably, several rollers may be used, so that if any one rolled over a perforation hole it would not lodge in the perforation hole and hang up the sensor pad from moving. Other options for reducing pad wear also may be used, such as a sheath that holds the sensor arm assembly fully closed, and then automatically drops off or is removed when entering a region with a larger-than-tubing size diameter, such as a casing.
Another alternative is a sacrificial ring or sleeve that wears on the trip into the hole and drops off when in the casing, taking the wear on the trip into the hole instead of the pad face taking the wear. Sensor pad 113, the sensor pad face or the ball rollers may be configured so as to be easily replaceable.
Sensor pad 113, including sensor housing 301 and sensor 302 within sensor housing 301, may be a permanent or removable component of arm assembly 111. The sides and back of the sensor pad preferably are shaped so as to provide a large volume for the sensor itself inside the pad and yet still allow the pad to fit inside a carrier. The carrier generally will be mechanically stronger than the sensor components, and may assist in withstanding large axial and other forces that may be placed upon the tool string in practice. While throughout this discussion sensor 302
Figures 5A, 5B and 5C illustrate side, front and top views, respectively of sensor pad 113. The sensor pad includes sensor housing 301 which has rounded front face 304, flow channel 303, and sensor 302 within flow channel 303. Sensor housing 301 generally moves along the inner circumference of casing 102 allowing fluid entering or leaving the casing wall to flow along a flow axis of flow channel 303 past sensor 302. Flow channel 303 is preferably between about 3 and about 10 inches long, more preferably between about 4 and about 9 inches long, still more preferably between about 5 and about 8 inches long, and most preferably between about 6 and about 7 inches long, but may be longer or shorter depending on the length of sensor 302 used in a particular application. As explained in more detail below, flow channel 303 and sensor 302 preferably comprise multiple individual flow channels and associated sensors.
Rounded front face 304 of sensor housing 301 generally allows for smoother passage through tubulars and around obstructions. Additionally, all-direction ball rollers 305 may be incorporated on face 304 of housing 301 to aid in passage around obstacles and to reduce friction and wear on the surface of sensor housing 301. Preferably, several rollers may be used, so that if any one rolled over a perforation hole it would not lodge in the perforation hole and hang up the sensor pad from moving. Other options for reducing pad wear also may be used, such as a sheath that holds the sensor arm assembly fully closed, and then automatically drops off or is removed when entering a region with a larger-than-tubing size diameter, such as a casing.
Another alternative is a sacrificial ring or sleeve that wears on the trip into the hole and drops off when in the casing, taking the wear on the trip into the hole instead of the pad face taking the wear. Sensor pad 113, the sensor pad face or the ball rollers may be configured so as to be easily replaceable.
Sensor pad 113, including sensor housing 301 and sensor 302 within sensor housing 301, may be a permanent or removable component of arm assembly 111. The sides and back of the sensor pad preferably are shaped so as to provide a large volume for the sensor itself inside the pad and yet still allow the pad to fit inside a carrier. The carrier generally will be mechanically stronger than the sensor components, and may assist in withstanding large axial and other forces that may be placed upon the tool string in practice. While throughout this discussion sensor 302
-12-is typically described as a flow sensor, tool 100 and arm assembly 111 also may be used with other types of sensors such as temperature, pressure, conductivity, orientation, imaging, and the like.
Sensor pad 113 may also comprise other types of sensors, such as one or more temperature sensors. For example, an array of temperature sensors may be used to image the borehole temperature distribution.
Figure 6A illustrates flow sensor 400, which includes core body 401. Inside core body or shell 401 are first and second pole sections 402 preferably extending about the length of core enclosure 401. Core body 401 and pole sections 402 preferably comprise a material of high magnetic permeability such as iron (e.g., 1015 iron), steel (e.g., 1018 steel), and the like. The length of core body 401 is preferably between about 4 inches and about 10 inches, more preferably between about 5 inches and about 8 inches, and most preferably about six inches long.
The two pole sections 402 preferably are separated by gap 403. Alternatively, only one pole section 402 may be used such that the gap 403 exists between the single pole piece and the core.
The width of gap 403 is preferably less than 0.5 inches, more preferably less than 0.4 inches, still more preferably between 0.1 and 0.3 inches, and most preferably about 0.2 inches, depending on the specific application. These preferred distances also apply to the spacing between the two electrodes 404 in an electrode pair disposed in each flow channel.
At least one, and preferably both, of the pole pieces 402 are surrounded by wire coil 405, which carries electrical current to generate a substantially constant magnetic flux along the faces of pole pieces 402, and concentrated primarily between the two pole pieces.
The coil may be coated in enamel or other waterproof material. As another alternative, the coil may be coiled around the outer portion of the core, that is, the coil may be wound around from the inside to the outside of the core. As another alternative, permanent magnets may be used instead of the magnetic pieces and wire coil.
Electrodes 404 are situated in gap 403 between the two pole pieces 402, with two electrodes disposed in each flow channel. The electrode pairs preferably are spaced along first pole piece 402 at a distance of preferably less than about 0.25 inches apart, more preferably less than about 0.2 inches apart, still preferably less than about 0.1 inches apart, and most preferably about 0.05 inches apart, depending on the specific application. Alternatively the electrode pairs may not be evenly spaced along the pole piece.
Sensor pad 113 may also comprise other types of sensors, such as one or more temperature sensors. For example, an array of temperature sensors may be used to image the borehole temperature distribution.
Figure 6A illustrates flow sensor 400, which includes core body 401. Inside core body or shell 401 are first and second pole sections 402 preferably extending about the length of core enclosure 401. Core body 401 and pole sections 402 preferably comprise a material of high magnetic permeability such as iron (e.g., 1015 iron), steel (e.g., 1018 steel), and the like. The length of core body 401 is preferably between about 4 inches and about 10 inches, more preferably between about 5 inches and about 8 inches, and most preferably about six inches long.
The two pole sections 402 preferably are separated by gap 403. Alternatively, only one pole section 402 may be used such that the gap 403 exists between the single pole piece and the core.
The width of gap 403 is preferably less than 0.5 inches, more preferably less than 0.4 inches, still more preferably between 0.1 and 0.3 inches, and most preferably about 0.2 inches, depending on the specific application. These preferred distances also apply to the spacing between the two electrodes 404 in an electrode pair disposed in each flow channel.
At least one, and preferably both, of the pole pieces 402 are surrounded by wire coil 405, which carries electrical current to generate a substantially constant magnetic flux along the faces of pole pieces 402, and concentrated primarily between the two pole pieces.
The coil may be coated in enamel or other waterproof material. As another alternative, the coil may be coiled around the outer portion of the core, that is, the coil may be wound around from the inside to the outside of the core. As another alternative, permanent magnets may be used instead of the magnetic pieces and wire coil.
Electrodes 404 are situated in gap 403 between the two pole pieces 402, with two electrodes disposed in each flow channel. The electrode pairs preferably are spaced along first pole piece 402 at a distance of preferably less than about 0.25 inches apart, more preferably less than about 0.2 inches apart, still preferably less than about 0.1 inches apart, and most preferably about 0.05 inches apart, depending on the specific application. Alternatively the electrode pairs may not be evenly spaced along the pole piece.
-13-Openings in the front and back of core 401 create flow channels 410. The flow channels may be holes, slots, a mixture thereof, a continuous slot, or of any other shape which allows fluid to through past the electrodes. Alternatively, the configuration may be different on the front and back of the core. Flow channels 410 may be formed with straight walls into core 401 or the channels may be tapered or scalloped. Preferably the flow channels 410 are funneled or tapered from the outside toward the inside to allow inflow from a larger area to pass through the flow sensor 400 and yet leave enough core material to keep the magnetic flux high and substantially constant. Alternatively, the same area of a casing wall may be sensed with fewer sensors by using larger funnels tapered and directing fluid from a larger area to the sensors. The number of flow channels generally is less than fifty, more preferably is between one and about thirty, more preferably is between about five and about twenty-five, still more preferably is between about ten and about twenty, and most preferably is about fifteen. Preferably, the individual flow channels are separated from each other with dielectric shielding as disclosed in WO Publ. No.
2005/033633 A2. Moreover, any of the shield shapes and configurations disclosed in the above reference may be implemented as the flow channels in the present application.
All open volumes within sensor 400 except for the flow channels 410 preferably are filled with a dielectric potting material such as an epoxy , plastic, enamel, composite, or the like. In addition to assisting with formation of the flow channels, the potting material can enable the sensor to better handle the extreme pressures and temperatures found downhole in a wellbore.
Preferably, all or most surfaces are protected by a protective layer of potting or another material, except for the conductive surfaces of the electrodes exposed to fluid flow in the flow channels.
Figure 6B shows another embodiment of flow sensor 400. Electrodes 404 protrude through openings 407 in one side of core 401. One electrode pair is disposed in flow channel 410. Electrodes 404 are electrically connected to a printed wiring board (PWB) 412 (also known as a printed circuit board (PCB)) located outside of core 401. Preferably PWB
412 is mounted on a side of sensor housing 301, and is protected from the ambient environment by a covering of potting material or some other form of protective enclosure or housing. PWB
412 could alternatively be mounted inside core 401.
In a preferred embodiment, each electrode pair is connected by resistor 406, and adjacent electrode pairs are connected in series by direct electrical connection 408 (e.g., wire or circuit trace). Alternatively, electrodes 404 may be directly connected to a resistor network or wiring
2005/033633 A2. Moreover, any of the shield shapes and configurations disclosed in the above reference may be implemented as the flow channels in the present application.
All open volumes within sensor 400 except for the flow channels 410 preferably are filled with a dielectric potting material such as an epoxy , plastic, enamel, composite, or the like. In addition to assisting with formation of the flow channels, the potting material can enable the sensor to better handle the extreme pressures and temperatures found downhole in a wellbore.
Preferably, all or most surfaces are protected by a protective layer of potting or another material, except for the conductive surfaces of the electrodes exposed to fluid flow in the flow channels.
Figure 6B shows another embodiment of flow sensor 400. Electrodes 404 protrude through openings 407 in one side of core 401. One electrode pair is disposed in flow channel 410. Electrodes 404 are electrically connected to a printed wiring board (PWB) 412 (also known as a printed circuit board (PCB)) located outside of core 401. Preferably PWB
412 is mounted on a side of sensor housing 301, and is protected from the ambient environment by a covering of potting material or some other form of protective enclosure or housing. PWB
412 could alternatively be mounted inside core 401.
In a preferred embodiment, each electrode pair is connected by resistor 406, and adjacent electrode pairs are connected in series by direct electrical connection 408 (e.g., wire or circuit trace). Alternatively, electrodes 404 may be directly connected to a resistor network or wiring
-14-harness without a printed circuit board. A voltage measured at V is representative or indicative of the presence or absence, as well as the direction (from the sign, + or -, of the voltage) and extent (e.g., quantity or velocity), of the flow of conductive fluid through one or more of flow channels 410. In this embodiment, each opening 407 has only one electrode, and so the electrodes 404 are paired in every other flow channel 410. Alternatively, an electrode pair is associated with each flow channel, in which case each opening 407 (except for the outermost openings) would have two electrodes in it, one for each of the adjacent flow channels.
Alternatively, there may be additional openings 407 to accommodate the additional electrodes.
Figures 6C and 6D illustrate alternative embodiments for the core pole pieces 402. In Figure 6C, each pole piece 402 is a continuous block running the length of the sensing area. In Figure 6D, each pole piece has portions removed such that the two pole pieces have individual pole projections or teeth that may be aligned with each flow channel. The reduced core pole material of each pole piece in close proximity to the other piece has the effect of concentrating the magnetic flux at the flow channel, providing a stronger magnetic field and improved measurement sensitivity. Alternatively, a non-rectangular shape of the core, such as oval or circular, may be used. As another alternative, portions of the core interior not otherwise used may be filled with a waterproof material such as epoxy, enamel, plastic, composite or the like, except in the flow channels.
The implementation of the pole pieces of Figure 6D is shown in Figure 6E. This embodiment is similar to that shown in Figure 6A, except that the core pole pieces 402 with pole projections or teeth are used, and both pole pieces 402 are surrounded by coils 405. For the sake of clarity, only one of the pole projections for the upper pole piece 402 is shown, and the electrodes are not shown. Fluid flow is funneled into flow channel 410, which passes between the faces of corresponding pole teeth on the two pole pieces 402. Figure 6F
illustrates similar components and features with additional pole projections shown for the upper pole piece.
Figure 6G is a combination schematic and cross section showing the relationship of electrodes 404 to the other components. In this embodiment, electrode pairs are implemented in every flow channel. Poles 409 are shown at the end of each core pole piece adjacent the flow channel. Figure 6H illustrates similar components, with electrode pair 414 shown disposed at each side of a flow channel 410. In addition, potting material 416 surrounding the flow channels and filling in all other open spaces in the sensor is shown.
Alternatively, there may be additional openings 407 to accommodate the additional electrodes.
Figures 6C and 6D illustrate alternative embodiments for the core pole pieces 402. In Figure 6C, each pole piece 402 is a continuous block running the length of the sensing area. In Figure 6D, each pole piece has portions removed such that the two pole pieces have individual pole projections or teeth that may be aligned with each flow channel. The reduced core pole material of each pole piece in close proximity to the other piece has the effect of concentrating the magnetic flux at the flow channel, providing a stronger magnetic field and improved measurement sensitivity. Alternatively, a non-rectangular shape of the core, such as oval or circular, may be used. As another alternative, portions of the core interior not otherwise used may be filled with a waterproof material such as epoxy, enamel, plastic, composite or the like, except in the flow channels.
The implementation of the pole pieces of Figure 6D is shown in Figure 6E. This embodiment is similar to that shown in Figure 6A, except that the core pole pieces 402 with pole projections or teeth are used, and both pole pieces 402 are surrounded by coils 405. For the sake of clarity, only one of the pole projections for the upper pole piece 402 is shown, and the electrodes are not shown. Fluid flow is funneled into flow channel 410, which passes between the faces of corresponding pole teeth on the two pole pieces 402. Figure 6F
illustrates similar components and features with additional pole projections shown for the upper pole piece.
Figure 6G is a combination schematic and cross section showing the relationship of electrodes 404 to the other components. In this embodiment, electrode pairs are implemented in every flow channel. Poles 409 are shown at the end of each core pole piece adjacent the flow channel. Figure 6H illustrates similar components, with electrode pair 414 shown disposed at each side of a flow channel 410. In addition, potting material 416 surrounding the flow channels and filling in all other open spaces in the sensor is shown.
-15-Figure 61 illustrates an alternative embodiment in which the coil and magnetic material have been replaced with permanent magnets 430 and 432. The magnets may be used with or without a surrounding core, so long as flow channels exist for guiding fluid to flow between the magnets. In this example the lower side of magnet 430 is the south pole face and the upper side of magnet 432 is the north pole face. The electromagnetic sensing operation of conductive fluid flow with electrodes 404 is essentially the same as before. Figure 6J
illustrates another embodiment with permanent magnets 430, 432. Electrodes 404 are disposed in the gap between the north and south poles through openings 407 in permanent magnet 432. As discussed previously, the electrode pair is electrically connected by resistor 406 and a voltage measured across the two electrodes is representative of conductive fluid flow in the gap between the two electrodes.
Figure 6K illustrates another embodiment with permanent magnets 430, 432. In this embodiment the magnets are disposed within core 401 and have ferromagnetic projections or teeth 434 on either side of flow channel 410. For clarity, electrodes are not shown in this figure, but may be implemented as shown in other embodiments disclosed herein. The permanent magnets may comprise materials such as rare earth magnets (e.g., neodymium magnets, or samarium cobalt magnets), alnico magnets, ceramic magnets, and the like. The ferromagnetic teeth may comprise the same materials as the core material described hereinabove.
Figure 7 illustrates a preferred embodiment sensor housing 301, with Figure 7A
showing the front, Figure 7B showing the top, Figure 7C showing the bottom, Figure 7D
showing one side, and Figure 7E showing the back. The side opposite the side shown in Figure 7D is the mirror image of Figure 7D. Flow channels 410 pass through sensor housing 301 from the front shown in Figure 7A to the back shown in Figure 7E. In addition, wire bundle 420 is shown projecting from the top of sensor housing 301, which provides for external electrical connections.
Figures 8A through 8E show further details of the sensor housing of Figure 7.
The potting material is not shown in any of these figures so that other components can be seen. In Figure 8A, PWB 412 is shown mounted on a side of sensor housing 301. In addition, portions of coils 405 and electrodes 404 are visible inside flow channels 410. Also visible is insulation 422 insulating portions of electrodes 404. In Figure 8B, half of the sensor housing 301 has been removed, along with its associated pole piece and coil, to better observe the housing's inner
illustrates another embodiment with permanent magnets 430, 432. Electrodes 404 are disposed in the gap between the north and south poles through openings 407 in permanent magnet 432. As discussed previously, the electrode pair is electrically connected by resistor 406 and a voltage measured across the two electrodes is representative of conductive fluid flow in the gap between the two electrodes.
Figure 6K illustrates another embodiment with permanent magnets 430, 432. In this embodiment the magnets are disposed within core 401 and have ferromagnetic projections or teeth 434 on either side of flow channel 410. For clarity, electrodes are not shown in this figure, but may be implemented as shown in other embodiments disclosed herein. The permanent magnets may comprise materials such as rare earth magnets (e.g., neodymium magnets, or samarium cobalt magnets), alnico magnets, ceramic magnets, and the like. The ferromagnetic teeth may comprise the same materials as the core material described hereinabove.
Figure 7 illustrates a preferred embodiment sensor housing 301, with Figure 7A
showing the front, Figure 7B showing the top, Figure 7C showing the bottom, Figure 7D
showing one side, and Figure 7E showing the back. The side opposite the side shown in Figure 7D is the mirror image of Figure 7D. Flow channels 410 pass through sensor housing 301 from the front shown in Figure 7A to the back shown in Figure 7E. In addition, wire bundle 420 is shown projecting from the top of sensor housing 301, which provides for external electrical connections.
Figures 8A through 8E show further details of the sensor housing of Figure 7.
The potting material is not shown in any of these figures so that other components can be seen. In Figure 8A, PWB 412 is shown mounted on a side of sensor housing 301. In addition, portions of coils 405 and electrodes 404 are visible inside flow channels 410. Also visible is insulation 422 insulating portions of electrodes 404. In Figure 8B, half of the sensor housing 301 has been removed, along with its associated pole piece and coil, to better observe the housing's inner
-16-components. PWB 412 also is more visible in this figure, with electrode connections 424 shown on the surface of PWB 412.
Figure 8C illustrates a side section of sensor housing 301 with the PWB
removed. The PWB connection portion of electrodes 404 can be seen protruding through openings 407 in the side of housing 301. Furthermore, each electrode pair 414 is aligned with its associated flow channel 410. Alternatively, the electrodes may be mounting differently, such as on a side piece that goes out and down into a holder.
Figure 8D shows the interior of the side section of sensor housing 301. In this figure, sections of core 402 are visible adjacent electrode pair 414, and a majority of coil 405 is visible surrounding core 402. Figure 8E is an expanded view of a portion of Figure 8D, providing a more detailed view of the relationships between electrodes 404, insulator 422, core 402, coil 405, and flow channel 410.
Figures 9 ¨ 9C illustrates another preferred embodiment of sensor housing 301 and its associated components, along with example dimensions of various features. Of course, many other dimensions are possible for many different embodiments, all of which are within the scope and spirit of the present invention. Figure 9 is an external view of the front of sensor housing 301. Figure 9A is a cross section of sensor housing 301 from an end perspective. Pole 426 is shown for one of the pole piece projections, and potting material 428, such as molded epoxy, is shown surrounding most components. Figure 9B is a cross section of sensor housing 301 from a side perspective, while Figure 9C is an expanded view of a portion of the assembly of Figure 9B.
Figures 10A ¨ 10C illustrate various alternative embodiments for the electrode/resistor network. In previously discussed embodiments, each electrode pair and its associated resistor were connected to other such elements in series, or there may be an additional resistor between each adjacent electrode pair. Alternatively, the electrode pairs may be connected in series without any resistors. Alternatively, the electrode pairs may be connected to each other in parallel, with the voltage V measured across all the electrode pairs in parallel. Figure 10A
illustrates one such embodiment, where electrode pair 414 has a resistor R1 electrically connected between the two electrodes. One electrode is connected to one side of a network ladder through resistor R2, while the other electrode is connected to the other side of the network ladder through resistor R3. Resistor R1 helps make the output voltage substantially insensitive to the presence of a non-conductive fluid, such as oil or gas, in the flow channel. Resistors R2
Figure 8C illustrates a side section of sensor housing 301 with the PWB
removed. The PWB connection portion of electrodes 404 can be seen protruding through openings 407 in the side of housing 301. Furthermore, each electrode pair 414 is aligned with its associated flow channel 410. Alternatively, the electrodes may be mounting differently, such as on a side piece that goes out and down into a holder.
Figure 8D shows the interior of the side section of sensor housing 301. In this figure, sections of core 402 are visible adjacent electrode pair 414, and a majority of coil 405 is visible surrounding core 402. Figure 8E is an expanded view of a portion of Figure 8D, providing a more detailed view of the relationships between electrodes 404, insulator 422, core 402, coil 405, and flow channel 410.
Figures 9 ¨ 9C illustrates another preferred embodiment of sensor housing 301 and its associated components, along with example dimensions of various features. Of course, many other dimensions are possible for many different embodiments, all of which are within the scope and spirit of the present invention. Figure 9 is an external view of the front of sensor housing 301. Figure 9A is a cross section of sensor housing 301 from an end perspective. Pole 426 is shown for one of the pole piece projections, and potting material 428, such as molded epoxy, is shown surrounding most components. Figure 9B is a cross section of sensor housing 301 from a side perspective, while Figure 9C is an expanded view of a portion of the assembly of Figure 9B.
Figures 10A ¨ 10C illustrate various alternative embodiments for the electrode/resistor network. In previously discussed embodiments, each electrode pair and its associated resistor were connected to other such elements in series, or there may be an additional resistor between each adjacent electrode pair. Alternatively, the electrode pairs may be connected in series without any resistors. Alternatively, the electrode pairs may be connected to each other in parallel, with the voltage V measured across all the electrode pairs in parallel. Figure 10A
illustrates one such embodiment, where electrode pair 414 has a resistor R1 electrically connected between the two electrodes. One electrode is connected to one side of a network ladder through resistor R2, while the other electrode is connected to the other side of the network ladder through resistor R3. Resistor R1 helps make the output voltage substantially insensitive to the presence of a non-conductive fluid, such as oil or gas, in the flow channel. Resistors R2
-17-=
and R3 are used to reduce noise in the voltage measurements. The resistor values may be selected to be between about 1K ohms and about 100M ohms, more preferably between about 10K ohms and about 10M ohms, still more preferably between about 50K
ohms and 5M ohms, and most preferably about 100 ohms.
Alternatively, as shown in Figure 10B, the resistors may only be used to connect to one side of the network ladder, while the other electrode is connected directly to the other side of the ladder. As another alternative, difference ones of the various electrode pairs may be connected in the same network with both, one or the other, or neither of the ladder resistors, in any combination, as shown in Figure 10C. As yet another alternative, for either the serial or parallel network, voltages for each electrode pair or a sub-group of the electrode pairs may be measured separately to provide even greater precision in determining the location of conductive fluid flow through the casing wall.
Although the present invention and its advantages have been described in detail, it should be understood that various changes, substitutions and alterations can be made. For example, many of the features detailed herein may be combined with the applicable features described in previously referenced U.S. Pat. No. 6,711,947 and WO
Publ.
No. 2005/033633 A2.
Moreover, the scope of the present application is not intended to be limited to the particular embodiments of the process, machine, manufacture, composition of matter, means, methods and steps described in the specification.
and R3 are used to reduce noise in the voltage measurements. The resistor values may be selected to be between about 1K ohms and about 100M ohms, more preferably between about 10K ohms and about 10M ohms, still more preferably between about 50K
ohms and 5M ohms, and most preferably about 100 ohms.
Alternatively, as shown in Figure 10B, the resistors may only be used to connect to one side of the network ladder, while the other electrode is connected directly to the other side of the ladder. As another alternative, difference ones of the various electrode pairs may be connected in the same network with both, one or the other, or neither of the ladder resistors, in any combination, as shown in Figure 10C. As yet another alternative, for either the serial or parallel network, voltages for each electrode pair or a sub-group of the electrode pairs may be measured separately to provide even greater precision in determining the location of conductive fluid flow through the casing wall.
Although the present invention and its advantages have been described in detail, it should be understood that various changes, substitutions and alterations can be made. For example, many of the features detailed herein may be combined with the applicable features described in previously referenced U.S. Pat. No. 6,711,947 and WO
Publ.
No. 2005/033633 A2.
Moreover, the scope of the present application is not intended to be limited to the particular embodiments of the process, machine, manufacture, composition of matter, means, methods and steps described in the specification.
-18-
Claims (20)
1. A method of measuring a conductive fluid flow, the method comprising:
traversing a casing with a tool, the tool comprising a tool body and an arm assembly pivotably attached to the tool body, wherein a pivot axis of the arm assembly is orthogonal to a long axis of the tool body, wherein the arm assembly supports a sensor pad comprising an electromagnetic sensor, wherein a sensor pad long axis is parallel to the tool body long axis, wherein a first pair of opposite inner angles of the arm assembly are acute angles, and wherein a second pair of opposite inner angles of the arm assembly are obtuse angles;
azimuthally rotating the sensor pad along an inner circumference of the casing; and measuring a speed and direction of radial conductive fluid flow through a wall of the casing.
traversing a casing with a tool, the tool comprising a tool body and an arm assembly pivotably attached to the tool body, wherein a pivot axis of the arm assembly is orthogonal to a long axis of the tool body, wherein the arm assembly supports a sensor pad comprising an electromagnetic sensor, wherein a sensor pad long axis is parallel to the tool body long axis, wherein a first pair of opposite inner angles of the arm assembly are acute angles, and wherein a second pair of opposite inner angles of the arm assembly are obtuse angles;
azimuthally rotating the sensor pad along an inner circumference of the casing; and measuring a speed and direction of radial conductive fluid flow through a wall of the casing.
2. The method of claim 1, wherein the tool further comprises a long aim having a first end coupled to the tool body and a second end coupled to the arm assembly, and wherein the long aim and tool body form a first acute angle facing the arm assembly.
3. The method of claim 2, wherein the first acute angle between the long arm and the tool body is between about 0 and about 10 degrees.
4. The method of claim 1, further comprising pivoting the arm assembly on the pivot axis to move the sensor pad radially inward toward or outward from the tool body in response to a diameter variation of the casing.
5. The method of claim 1, wherein the tool body comprises a first stationary tool segment and a rotatable tool segment coupled to the first stationary tool segment, wherein the arm assembly is mounted to the rotatable tool segment, and wherein azimuthally rotating the sensor pad comprises:
azimuthally rotating the rotatable tool segment around the tool body long axis with respect to the first stationary tool segment.
azimuthally rotating the rotatable tool segment around the tool body long axis with respect to the first stationary tool segment.
6. The method of claim 5, further comprising passing electrical measurement signals of the measured speed and direction from the sensor pad to the first stationary tool segment using one or more slip rings.
7. The method of claim 5, further comprising centralizing the tool body in the casing using one or more centralizers disposed on the first stationary tool segment.
8. A method for borehole logging comprising:
traversing a borehole with a tool having a tool long axis, the tool comprising a first stationary tool segment, a rotatable tool segment having a first end rotatably coupled to the first stationary tool segment, a sensor pad having a pad long axis parallel to the tool long axis, and an arm assembly coupling the sensor pad to the rotatable tool segment, wherein the arm assembly is pivotably attached to the rotatable tool segment with a pivot axis of the arm assembly that is orthogonal to the tool long axis;
azimuthally rotating the rotatable tool segment around the tool long axis with respect to the first stationary tool segment to move the sensor pad along an inner wall of the borehole;
moving the sensor pad radially inward toward or outward from the rotatable tool segment as the arm assembly is pivoted on the pivot axis; and electromagnetically sensing radial conductive fluid flow through the inner wall of the borehole with the sensor pad.
traversing a borehole with a tool having a tool long axis, the tool comprising a first stationary tool segment, a rotatable tool segment having a first end rotatably coupled to the first stationary tool segment, a sensor pad having a pad long axis parallel to the tool long axis, and an arm assembly coupling the sensor pad to the rotatable tool segment, wherein the arm assembly is pivotably attached to the rotatable tool segment with a pivot axis of the arm assembly that is orthogonal to the tool long axis;
azimuthally rotating the rotatable tool segment around the tool long axis with respect to the first stationary tool segment to move the sensor pad along an inner wall of the borehole;
moving the sensor pad radially inward toward or outward from the rotatable tool segment as the arm assembly is pivoted on the pivot axis; and electromagnetically sensing radial conductive fluid flow through the inner wall of the borehole with the sensor pad.
9. The method of claim 8, wherein electromagnetically sensing further comprises measuring a speed and direction of the radial conductive fluid flow through the inner wall of the borehole.
10. The method of claim 8, further comprising pivoting the aim assembly to move the sensor pad at least partially within a hollowed region in the rotatable tool segment.
11. The method of claim 8, further comprising centralizing the tool in the borehole using one or more first centralizers disposed on the first stationary tool segment.
12. The method of claim 11, wherein the tool further comprises a second stationary tool segment rotatably coupled to a second end of the rotatable tool segment, and wherein the method further comprises centralizing the tool in the borehole using one or more first centralizers disposed on the first stationary tool segment and one or more second centralizers disposed on the second stationary tool segment.
13. The method of claim 8, wherein the aim assembly further comprises a first atm having a first end pivotably coupled to the rotatable tool segment and a second end pivotably coupled to the sensor pad, a second arm having a first end pivotably coupled to the rotatable tool segment and a second end pivotably coupled to the sensor pad, and a long arm having a first end slideably coupled to the rotatable tool segment and a second end rotatably coupled to the sensor pad, and wherein the method further comprises:
sliding the first end of the long arm away from the aim assembly as the sensor pad moves radially inward toward the rotatable tool segment; and sliding the first end of the long arm toward the arm assembly as the sensor pad moves radially outward from the rotatable tool segment.
sliding the first end of the long arm away from the aim assembly as the sensor pad moves radially inward toward the rotatable tool segment; and sliding the first end of the long arm toward the arm assembly as the sensor pad moves radially outward from the rotatable tool segment.
14. The method of claim 8, wherein the sensor pad comprises two or more ball rollers disposed on a face of the sensor pad, and wherein the method further comprises rolling the ball rollers on the inner wall of the borehole to move the sensor pad along the inner wall of the borehole.
15. A method for borehole logging comprising:
traversing a borehole with a tool, the tool comprising a tool body having a tool body long axis, a sensor pad having a pad long axis parallel to the tool body long axis, a first aim having a first end pivotably coupled to the tool body and a second end coupled to the sensor pad, and a second arm having a first end pivotably coupled to the tool body and a second end coupled to the sensor pad, wherein pivot axes of the ends of the arms are orthogonal to the tool body long axis;
azimuthally rotating the tool around the tool body long axis to move the sensor pad along an inner wall of the borehole;
moving the sensor pad radially inward toward or outward from the tool body as the arms are pivoted on their pivot axes, while maintaining a first vertical angle between the first arm and the tool body at a substantially same magnitude and direction as a second vertical angle between the second arm and the tool body; and electromagnetically sensing radial conductive fluid flow through the inner wall of the borehole with the sensor pad.
traversing a borehole with a tool, the tool comprising a tool body having a tool body long axis, a sensor pad having a pad long axis parallel to the tool body long axis, a first aim having a first end pivotably coupled to the tool body and a second end coupled to the sensor pad, and a second arm having a first end pivotably coupled to the tool body and a second end coupled to the sensor pad, wherein pivot axes of the ends of the arms are orthogonal to the tool body long axis;
azimuthally rotating the tool around the tool body long axis to move the sensor pad along an inner wall of the borehole;
moving the sensor pad radially inward toward or outward from the tool body as the arms are pivoted on their pivot axes, while maintaining a first vertical angle between the first arm and the tool body at a substantially same magnitude and direction as a second vertical angle between the second arm and the tool body; and electromagnetically sensing radial conductive fluid flow through the inner wall of the borehole with the sensor pad.
16. The method of claim 15, wherein electromagnetically sensing further comprises measuring a speed and direction of the radial conductive fluid flow through the inner wall of the borehole.
17. The method of claim 15, further comprising pivoting the arms to move the sensor pad at least partially within a hollowed region in the tool body to traverse a tubing in the borehole.
18. The method of claim 15, wherein the tool body comprises a first stationary tool segment, a second stationary tool segment, and a rotatable tool segment having a first end coupled to the first stationary tool segment and a second end coupled to the second stationary tool segment, wherein the first and second aims are coupled to the rotatable tool segment;
wherein azimuthally rotating the tool comprises azimuthally rotating the rotatable tool segment around the tool body long axis with respect to the first and second stationary tool segments; and the method further comprises centralizing the tool in the borehole using one or more first centralizers disposed on the first stationary tool segment and one or more second centralizers disposed on the second stationary tool segment.
wherein azimuthally rotating the tool comprises azimuthally rotating the rotatable tool segment around the tool body long axis with respect to the first and second stationary tool segments; and the method further comprises centralizing the tool in the borehole using one or more first centralizers disposed on the first stationary tool segment and one or more second centralizers disposed on the second stationary tool segment.
19. The method of claim 15, wherein the second end of the first aim is rotatably coupled to the sensor pad, wherein the second end of the second arm is rotatably coupled to the sensor pad, and wherein the method further comprises maintaining a third vertical angle between the first aim and the sensor pad at a substantially same magnitude and direction as a fourth vertical angle between the second arm and the sensor pad.
20. The method of claim 15, wherein the tool further comprises a long arm having a first end slideably coupled to the tool body and a second end rotatably coupled to the sensor pad, and wherein the method further comprises:
sliding the first end of the long arm away from the first and second arms as the sensor pad moves radially inward toward the tool body; and sliding the first end of the long arm toward the first and second arms as the sensor pad moves radially outward from the tool body.
sliding the first end of the long arm away from the first and second arms as the sensor pad moves radially inward toward the tool body; and sliding the first end of the long arm toward the first and second arms as the sensor pad moves radially outward from the tool body.
Applications Claiming Priority (3)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| US86518406P | 2006-11-10 | 2006-11-10 | |
| US60/865,184 | 2006-11-10 | ||
| CA2781625A CA2781625C (en) | 2006-11-10 | 2007-11-09 | Rotating fluid measurement device and method |
Related Parent Applications (1)
| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| CA2781625A Division CA2781625C (en) | 2006-11-10 | 2007-11-09 | Rotating fluid measurement device and method |
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| Publication Number | Publication Date |
|---|---|
| CA2901894A1 CA2901894A1 (en) | 2008-05-22 |
| CA2901894C true CA2901894C (en) | 2017-04-18 |
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ID=54070624
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| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| CA2901894A Expired - Fee Related CA2901894C (en) | 2006-11-10 | 2007-11-09 | Rotating fluid measurement device and method |
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| Country | Link |
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| CA (1) | CA2901894C (en) |
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| Publication number | Priority date | Publication date | Assignee | Title |
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| CN116122803B (en) * | 2023-02-02 | 2023-08-22 | 山东省煤田地质局第三勘探队 | Drilling inner side direction geological exploration testing device and testing method |
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| CA2901894A1 (en) | 2008-05-22 |
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