Rotating fluid flow measurement device and method

Fluid flow measurement device and method. In one embodiment, a tool comprises a rotating arm with a sensor pad to measure fluid flow into or out of the casing wall. The arm maintains the sensor pad in close proximity to the casing inner wall. The tool diameter is variable to allow the tool to traverse variable diameter casings and pass obstacles. The sensor pad comprises flow channels to direct the flow of fluid by electromagnetic sensors configured to detect conductive fluid flow.

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 inFIG. 1generally at60. Well construction involves drilling a hole or borehole62in the surface64of land or ocean floor. The borehole62may 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 formations68. A casing72is normally lowered into the borehole62. The region between the casing72and rock formation68is filled with cement70to provide a hydraulic seal. Usually, tubing74is inserted into the hole62, the tubing74including a packer76which comprises a seal. A packer fluid78is disposed between the casing72and tubing74annular region. Perforations80may be located in the casing72and cement70, into the rock68, 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 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. Pat. No. 6,711,947, entitled “Fluid Flow Measuring Device and Method of Manufacturing Thereof,” issued Mar. 30, 2004, and WO Publ. No. 2005/033633 A2, entitled “Apparatus and Method for Fluid Flow Measurement with Sensor Shielding,” filed Mar. 31, 2006, all of which are hereby incorporated herein by reference, 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.

SUMMARY OF THE INVENTION

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.

In accordance with an embodiment of the present invention, a logging tool for a borehole comprises a tool body having a long axis, a sensor pad, and an arm assembly coupling the sensor pad to the tool body, wherein the arm assembly is pivotably attached to the tool body, wherein a pivot axis of the arm assembly is orthogonal to the long axis of the tool body, and wherein the sensor pad is movable radially inward toward or outward from the tool body as the arm assembly is pivoted on the pivot axis.

In accordance with an embodiment of the present invention, a conductive fluid flow measurement device comprises a core enclosure having first, second, third and fourth sides, a first pole piece having a first face and disposed inside the first side the core enclosure, a second pole piece having a second face and disposed inside the second side of the core enclosure opposite the first side, wherein the first and second faces face each other and are separated by a gap, one or more flow channels disposed from the third side of the core, through the gap, to the fourth side of the core opposite the fourth side, and one or more electrode pairs, wherein each electrode pair is disposed in a respective one of the one or more flow channels adjacent the gap, and wherein, for each electrode pair, an imaginary line between the two electrodes in the electrode pair is substantially parallel to the faces and substantially orthogonal to a flow axis of the respective flow channel.

In accordance with an embodiment of the present invention, a conductive fluid flow measurement device comprises a core enclosure, first and second permanent magnets disposed adjacent the core enclosure, a first pole projection and a second pole projection disposed on the first and second permanent magnets, respectively, within the core enclosure and separated by a gap, a flow channel disposed within the core enclosure proximate to the gap such that a conductive fluid flowing through the flow channel passes through the gap, and an electrode pair disposed in the flow channel adjacent the gap, wherein a voltage difference is generated between electrodes in the electrode pair when the conductive fluid flows through the flow channel.

In accordance with an embodiment of the present invention, a conductive fluid flow measurement device comprises two permanent magnets with opposite poles facing each other and separated by a gap, a plurality of flow channels disposed within the device proximate to the gap such that a conductive fluid flowing through at least one of the flow channels passes through the gap, and a plurality of electrode pairs disposed adjacent the gap along a length of the permanent magnets, wherein a voltage difference occurs between the electrodes when the conductive fluid flows through at least one of the flow channels.

In accordance with an embodiment of the present invention, a method of measuring a conductive fluid flow comprises traversing a casing with a tool body having a quadrilateral arm assembly supporting a sensor pad comprising an electromagnetic sensor, azimuthally rotating the sensor pad along an inner circumference of the casing, and measuring a speed and direction of radial conductive fluid flow.

An advantage of an embodiment of the present invention 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 another embodiment of the present invention 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 arm 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 another embodiment of the present invention 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.

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.

DETAILED DESCRIPTION OF ILLUSTRATIVE EMBODIMENTS

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 toFIG. 2A, a downhole measuring device for a wellbore is shown as sonde or tool string100, which is configured to traverse a casing102with sensor pad113. 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, incorporated by reference above, which may be referenced for an understanding of these general concepts. With respect to the embodiment ofFIG. 2A, tool100typically is lowered into and raised out of casing102on a wireline101. The tool100azimuthally sweeps or rotates the sensor pad113on arm assembly111about the inner circumference103of the casing102as the tool100axially traverses the casing102. Preferably, sensor pad113is maintained in contact or in close proximity to the wellbore wall103.

Tool100includes stationary tool segments104and rotatable tool segment110. 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 body104is preferably non-rotating, and is connected to rotating tool segment110by rotating joint107, which allows for electrical communications (signals and power) to pass between the rotating tool segment110and at least one of the stationary tool segments104. Rotating joint107may constitute slip rings or a wireless (e.g., radio frequency) transceiver pair for communication, as examples. Stationary tool body104may include one segment or preferably two segments with one being below the rotating tool body110and the other being above it and attached to wireline cable101. Slip rings may be added at the bottom rotating joint107if other measurement tools are desired to be located below rotating tool segment110.

Attached to stationary tool body104is at least one, but preferably two, three, four or more centralizers105. Centralizers105generally maintain a long axis of the tool body100substantially parallel to the axis of casing102, as well as substantially in the center of casing102, thus generally maintaining sensor pad113in proximity to the wellbore wall103and substantially parallel to the axis of casing102. Additionally, the centralizers generally keep rotation of stationary tool body104to a minimum while rotating tool body110rotates. Centralizers105may be made of metal ribbons or wires for example.

Rotating tool body110(along with arm assembly111and sensor pad113) may be rotated by motor106located within stationary tool body104. In other embodiments, the rotating tool body may be rotated by other mechanisms such as gears driven by axial motion of the tool body100through casing102. In addition, motor106or other rotating mechanism may be located in another part of the tool100, such as within the rotating tool body110, or outside of the tool such as higher up on the wireline101or 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 sonde100, including rotating tool segment110and sensor pad113, are smoothed and rounded to prevent sonde100from 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 pad113detects the radial component of conductive fluid, such as water, entering or leaving the wellbore through the wellbore wall. Preferably, tool100is slowly moved axially at a speed such that, while sensor pad113is 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 pad113. 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. Tool100may make one, two or more axial passes through a wellbore while logging measurements made with sensor pad113. Normally logging may be performed from the bottom upward, but logging also may be performed while moving in the downward direction.

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.

FIG. 2Bshows an embodiment of arm assembly111, which includes upper arm207and lower arm208. Upper arm207and lower arm208are pivotably connected at one end to rotating tool body110. The other ends of arm207and arm208are connected to opposite ends of sensor pad113, 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 pad113. The mounting bracket preferably comprises an open area behind the sensor area of sensor pad113to allow for the free flow of fluid into sensor pad113and out the back of the mounting bracket. Any type of mechanical connector that allows pivoting of the arms207,208may be used to attach the arms to rotating tool body110and sensor pad113. Connector types such as hinges, pin and slot, or combinations of these are some examples. This arm arrangement generally keeps sensor pad113substantially parallel to the axis of the casing, which may enable accurate measurements. In another embodiment, sensor pad113may be connected to the rotating tool body by only a single arm.

In other embodiments, the arm assembly111connections with upper arm207, lower arm208, rotating tool body110, and sensor pad113may 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 assembly111as connected to rotating tool body110, the arm assembly also could be connected to stationary tool body104. Alternatively, in some embodiments of tool100, the rotating tool body110may be omitted. As another alternative, there may be two, three, four or more arm assemblies in any of the above configurations.

Maintaining the arm assembly111against a casing wall may be accomplished in many different ways. In one embodiment, springs203,204are used to exert outward force on upper arm207and lower arm208to push them away from rotating tool body110. A torsion spring is one example of a type of spring which may be used for springs203,204. The angle201between upper arm207and rotating tool body110is 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 angle201helps to ensure smoother passage of the tool100into smaller diameter casings from larger diameter casings, and around obstacles.

Alternatively, springs may be implemented at the interface of the arms 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.

FIG. 2Cshows another embodiment of arm assembly111with spring210and bar211. Spring210is connected to the rotating tool body110and to bar211, which is connected to one of the assembly arms207or208. Preferably, bar211comprises a groove to maintain spring210substantially in the center of bar211. As an example, an extension spring is one type of spring which may be used for spring210. Spring210exerts an outward force on arm assembly111to maintain sensor pad113in 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 toFIG. 2B, arm assembly111additionally may comprise a long arm115connected to the lower end of lower arm208or sensor pad113. Long arm115is pivotably coupled to rotating tool body110. The angle202between long arm115and rotating tool body110is 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 tool100through smaller diameter casings, around obstacles and restrictions, and also assists in collapsing the tool into its reduced diameter mode (described below). Long arm115may be coupled to rotating tool body110by any mechanism that allows the angles between long arm115and rotating tool body110to change. Preferably, long arm115is coupled to rotating tool body110by pin206and slot205connector. This connection allows for pin206to slide within slot205allowing long arm115to pivot and to expand out or fold flat against or into rotating tool segment110.

FIGS. 3A and 3Billustrate side and front views, respectively, of an embodiment of rotating tool body110with an added feature of carrier501. Carrier501allows arm assembly111and long arm115to fold into hollow regions of rotating tool body110when compressed. In one embodiment, arm assembly111folds into upper hollow section502and long arm115folds into lower hollow section503. The middle of carrier501has fluid flow cutout504and debris cutouts505. Fluid flow cutout504is aligned with sensor pad113to allow for fluid passing through the sensor area of sensor113to exit through the back of carrier501.

Carrier501generally may permit tool100and sensor pad113to operate even when arm assembly111is compressed into carrier501. Debris cutouts505allow for debris and fluid to be pushed out of the carrier501so there will not be any obstructions as arm assembly111and long arm115compress into carrier501. Carrier501also 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.

FIG. 4illustrates an alternative embodiment non-rotating multiple arm tool600. Tool600utilizes multiple bow spring arms604that 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 other shape) wire-like flexible expandable and contractible wires may be used like bow springs. A small sensor pad606with 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 pad606may 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 segments602, each section offset azimuthally with respect to the others, may be used to cover substantially the entire inner area of the borehole.

WhileFIG. 4shows two segments602, 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, whileFIG. 4shows three bow springs on each segment, 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.

FIGS. 5A,5B and5C illustrate side, front and top views, respectively of sensor pad113. The sensor pad includes sensor housing301which has rounded front face304, flow channel303, and sensor302within flow channel303. Sensor housing301generally moves along the inner circumference of casing102allowing fluid entering or leaving the casing wall to flow along a flow axis of flow channel303past sensor302. Flow channel303is 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 sensor302used in a particular application. As explained in more detail below, flow channel303and sensor302preferably comprise multiple individual flow channels and associated sensors.

Rounded front face304of sensor housing301generally allows for smoother passage through tubulars and around obstructions. Additionally, all-direction ball rollers305may be incorporated on face304of housing301to aid in passage around obstacles and to reduce friction and wear on the surface of sensor housing301. 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 pad113, the sensor pad face or the ball rollers may be configured so as to be easily replaceable.

Sensor pad113, including sensor housing301and sensor302within sensor housing301, may be a permanent or removable component of arm assembly111. 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 sensor302is typically described as a flow sensor, tool100and arm assembly111also may be used with other types of sensors such as temperature, pressure, conductivity, orientation, imaging, and the like.

Sensor pad113may 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.

FIG. 6Aillustrates flow sensor400, which includes core body401. Inside core body or shell401are first and second pole sections402preferably extending about the length of core enclosure401. Core body401and pole sections402preferably 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 body401is 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 sections402preferably are separated by gap403. Alternatively, only one pole section402may be used such that the gap403exists between the single pole piece and the core. The width of gap403is 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 electrodes404in an electrode pair disposed in each flow channel.

At least one, and preferably both, of the pole pieces402are surrounded by wire coil405, which carries electrical current to generate a substantially constant magnetic flux along the faces of pole pieces402, 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.

Electrodes404are situated in gap403between the two pole pieces402, with two electrodes disposed in each flow channel. The electrode pairs preferably are spaced along first pole piece402at 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.

Openings in the front and back of core401create flow channels410. 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 channels410may be formed with straight walls into core401or the channels may be tapered or scalloped. Preferably the flow channels410are funneled or tapered from the outside toward the inside to allow inflow from a larger area to pass through the flow sensor400and 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, incorporated by reference hereinabove. 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 sensor400except for the flow channels410preferably 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.

FIG. 6Bshows another embodiment of flow sensor400. Electrodes404protrude through openings407in one side of core401. One electrode pair is disposed in flow channel410. Electrodes404are electrically connected to a printed wiring board (PWB)412(also known as a printed circuit board (PCB)) located outside of core401. Preferably PWB412is mounted on a side of sensor housing301, and is protected from the ambient environment by a covering of potting material or some other form of protective enclosure or housing. PWB412could alternatively be mounted inside core401.

In a preferred embodiment, each electrode pair is connected by resistor406, and adjacent electrode pairs are connected in series by direct electrical connection408(e.g., wire or circuit trace). Alternatively, electrodes404may be directly connected to a resistor network or wiring 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 channels410. In this embodiment, each opening407has only one electrode, and so the electrodes404are paired in every other flow channel410. Alternatively, an electrode pair is associated with each flow channel, in which case each opening407(except for the outermost openings) would have two electrodes in it, one for each of the adjacent flow channels. Alternatively, there may be additional openings407to accommodate the additional electrodes.

FIGS. 6C and 6Dillustrate alternative embodiments for the core pole pieces402. InFIG. 6C, each pole piece402is a continuous block running the length of the sensing area. InFIG. 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 ofFIG. 6Dis shown inFIG. 6E. This embodiment is similar to that shown inFIG. 6A, except that the core pole pieces402with pole projections or teeth are used, and both pole pieces402are surrounded by coils405. For the sake of clarity, only one of the pole projections for the upper pole piece402is shown, and the electrodes are not shown. Fluid flow is funneled into flow channel410, which passes between the faces of corresponding pole teeth on the two pole pieces402.FIG. 6Fillustrates similar components and features with additional pole projections shown for the upper pole piece.

FIG. 6Gis a combination schematic and cross section showing the relationship of electrodes404to the other components. In this embodiment, electrode pairs are implemented in every flow channel. Poles409are shown at the end of each core pole piece adjacent the flow channel.FIG. 6Hillustrates similar components, with electrode pair414shown disposed at each side of a flow channel410. In addition, potting material416surrounding the flow channels and filling in all other open spaces in the sensor is shown.

FIG. 6Iillustrates an alternative embodiment in which the coil and magnetic material have been replaced with permanent magnets430and432. 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 magnet430is the south pole face and the upper side of magnet432is the north pole face. The electromagnetic sensing operation of conductive fluid flow with electrodes404is essentially the same as before.FIG. 6Jillustrates another embodiment with permanent magnets430,432. Electrodes404are disposed in the gap between the north and south poles through openings407in permanent magnet432. As discussed previously, the electrode pair is electrically connected by resistor406and a voltage measured across the two electrodes is representative of conductive fluid flow in the gap between the two electrodes.

FIG. 6Killustrates another embodiment with permanent magnets430,432. In this embodiment the magnets are disposed within core401and have ferromagnetic projections or teeth434on either side of flow channel410. 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.

FIG. 7illustrates a preferred embodiment sensor housing301, withFIG. 7Ashowing the front,FIG. 7Bshowing the top,FIG. 7Cshowing the bottom,FIG. 7Dshowing one side, andFIG. 7Eshowing the back. The side opposite the side shown inFIG. 7Dis the mirror image ofFIG. 7D. Flow channels410pass through sensor housing301from the front shown inFIG. 7Ato the back shown inFIG. 7E. In addition, wire bundle420is shown projecting from the top of sensor housing301, which provides for external electrical connections.

FIGS. 8A through 8Eshow further details of the sensor housing ofFIG. 7. The potting material is not shown in any of these figures so that other components can be seen. InFIG. 8A, PWB412is shown mounted on a side of sensor housing301. In addition, portions of coils405and electrodes404are visible inside flow channels410. Also visible is insulation422insulating portions of electrodes404. InFIG. 8B, half of the sensor housing301has been removed, along with its associated pole piece and coil, to better observe the housing's inner components. PWB412also is more visible in this figure, with electrode connections424shown on the surface of PWB412.

FIG. 8Cillustrates a side section of sensor housing301with the PWB removed. The PWB connection portion of electrodes404can be seen protruding through openings407in the side of housing301. Furthermore, each electrode pair414is aligned with its associated flow channel410. Alternatively, the electrodes may be mounting differently, such as on a side piece that goes out and down into a holder.

FIG. 8Dshows the interior of the side section of sensor housing301. In this figure, sections of core402are visible adjacent electrode pair414, and a majority of coil405is visible surrounding core402.FIG. 8Eis an expanded view of a portion ofFIG. 8D, providing a more detailed view of the relationships between electrodes404, insulator422, core402, coil405, and flow channel410.

FIGS. 9-9Cillustrates another preferred embodiment of sensor housing301and 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.FIG. 9is an external view of the front of sensor housing301.FIG. 9Ais a cross section of sensor housing301from an end perspective. Pole426is shown for one of the pole piece projections, and potting material428, such as molded epoxy, is shown surrounding most components.FIG. 9Bis a cross section of sensor housing301from a side perspective, whileFIG. 9Cis an expanded view of a portion of the assembly ofFIG. 9B.

FIGS. 10A-10Cillustrate 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.FIG. 10Aillustrates one such embodiment, where electrode pair414has a resistor R1electrically 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 R1helps make the output voltage substantially insensitive to the presence of a non-conductive fluid, such as oil or gas, in the flow channel. Resistors R2and R3are 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 100K ohms.

Alternatively, as shown inFIG. 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 inFIG. 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 herein without departing from the spirit and scope of the invention as defined by the appended claims. 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.