Patent Publication Number: US-2023151729-A1

Title: Fluid particulate concentrator for enhanced sensing in a wellbore fluid

Description:
TECHNICAL FIELD 
     The disclosure generally relates to the field of equipment utilized and operations performed in conjunction with a subterranean well and to (e.g., magnetic) sensing in well tools. 
     BACKGROUND 
     Reverse circulation cementing (hereinafter “reverse cementing”) involves displacing fluids between the outside of a casing and a formation wall in a subterranean well operation. A sensor on the inner or outer diameter of the casing at or near the bottom of the wellbore detects when the cementing fluids reach the bottom of the wellbore and begin entering the inside of the casing through a flow port. In response, a signal is sent downhole to close a valve to prevent cementing fluids from ascending the inside of the casing. During reverse cementing operations, the cementing fluids are aided by gravity in reaching the bottom of the wellbore. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       Embodiments of the disclosure may be better understood by referencing the accompanying drawings. 
         FIG.  1 A  is a schematic side view of a flow diverter coupled with a tubular, according to embodiments of this disclosure; 
         FIG.  1 B  is a cross section of the flow diverter of  FIG.  1 A ; 
         FIG.  2 A  is a schematic side view of a flow diverter, according to embodiments of this disclosure; 
         FIG.  2 B  is a perspective view of the flow diverter of  FIG.  2 A ; 
         FIG.  3    is a schematic diagram of a flow diverter according to embodiments of this disclosure being utilized in conjunction with a magnetic permeability sensor in a reverse cementing operation with a permanent magnetic field; 
         FIG.  4    is a schematic diagram of a magnetic field sensor for detecting slurries with varying concentrations of high magnetic permeability materials with a permanent magnet suitable for use with a flow diverter according to embodiments of this disclosure; 
         FIG.  5    is a schematic diagram of a permanent magnet with a tension measuring device to measure magnetic permeability of a slurry suitable for use with a flow diverter according to embodiments of this disclosure; 
         FIG.  6    is a flowchart of example operations for detecting cementing fluid downhole using a flow diverter according to embodiments of this disclosure with a permanent magnet and stopping fluid flow; 
         FIG.  7    depicts an example computer system with a sensing apparatus comprising a flow diverter according to embodiments of this disclosure and a permanent magnet and a magnetic field sensor; 
         FIG.  8    is a schematic diagram of a drilling rig system with a flow diverter according to embodiments of this disclosure and a magnetic field sensor and a permanent magnet; 
         FIG.  9    is a schematic diagram of a wireline system with a flow diverter according to embodiments of this disclosure and a permanent magnet and magnetic field sensor; 
         FIG.  10    is a schematic diagram of a flow diverter according to embodiments of this disclosure and a magnetic permeability sensor in a reverse cementing operation without a non-ferromagnetic plug; and 
         FIG.  11    is a schematic of a reverse cementing operation with a flow diverter according to embodiments of this disclosure and a magnetic permeability sensing apparatus. 
     
    
    
     DESCRIPTION OF EMBODIMENTS 
     The description that follows includes example systems, methods, techniques, and program flows that embody embodiments of the disclosure. However, it is understood that this disclosure may be practiced without these specific details. For instance, this disclosure refers to measuring magnetic permeability of slurry during a reverse cementing operation in illustrative examples. Embodiments of this disclosure can be instead applied to measuring magnetic permeability of fluids or slurries during other subterranean wellbore operations including traditional cementing operations. In other instances, well-known instruction instances, protocols, structures, and techniques have not been shown in detail in order not to obfuscate the description. 
     In some downhole sensing systems, a sensor is built into the side wall of a downhole tool. The sensor can be utilized to sense solids distributed in the well fluids being pumped. Once sensed, sensing system can trigger a subsequent action, such as closing of a valve to prevent further flow. In such sensing systems, a certain concentration of detectable particulates is needed for accuracy of the sensor. Herein disclosed is a flow diverter (or “fluid particulate concentrator”) configured to divert fluid flow toward a sensor of a sensing apparatus and thus increase a number of detectable particles within a detection range of a sensor of a sensing system. The flow diverter of this disclosure can be utilized to increase an effective concentration of detectable particles in proximity to the sensor (e.g., within a sensing range X of the sensor, described with reference to  FIG.  1 A  hereinbelow) to more reliably determine a triggering point (e.g., when to close the valve or take other subsequent action). 
     The shape of the disclosed flow diverter is designed to radially divert the fluid being pumped outward from the center of a tubular or tool in which the flow diverter is disposed toward an inside wall of the tubular or housing of the tool in which a sensor is disposed. Thus, the flow diverter diverts fluid flow into closer proximity to the interior wall of the tool and closer to the sensor of the sensing apparatus. The fluid flowing past the flow diverter can contain particulates that are to be detected by the sensor. By diverting the fluid toward the inside diameter of the tool or tubular housing the sensor, a higher concentration of the particulates pass in a nearer proximity to (e.g., to within a detectable range of) the sensor, relative to applications absent the flow diverter. A higher effective concentration of particulates within the detection range of the sensor will increase the potential signal created by passing of the particulates. 
     Description of a flow diverter of this disclosure will now be provided with reference to  FIG.  1 A , which is a schematic side view of a flow diverter  100  coupled with a tubular or other housing  180  (referred to hereinafter simply as “tubular”  180 ), according to embodiments of this disclosure, and  FIG.  1 A , which is a cross section view of the flow diverter  100  of  FIG.  1 A  coupled with tubular  180 . Flow diverter  100  comprises a first conical section  110 , a second conical section  120 , and support structure or “support legs”  140 . The first conical section  110  and the second conical section  120  are substantially conical in shape to facilitate flow of fluids thereover and direct fluids flowing thereover toward a sensor S of a sensing apparatus (e.g., a sensing apparatus as described hereinbelow with reference to  FIGS.  3 - 11   ). Flow diverter  100  can further comprise an intermediate section  130  comprises a substantially cylindrical outer surface  131  extending from the second end  113  of the first conical section  110  to the second end  123  of the second conical section  120  (e.g., and having a diameter D 1 ), or the second end  113  of the first conical section  110  can be integrated with the second end  223  of the second conical section  120 . 
     The first conical section  110  can comprise an outside surface  111  tapering from a first end  112  of the first conical section  110  to a second end  113  of the first conical section  110 . The first end  112  of the first conical section  110  can comprise a rounded nose  115 . The second end  113  of the first conical section  110  can be substantially planar, in embodiments, or integrated with or contacting second end  223  of second conical section  120  or intermediate section  130 . The second conical section  120  can comprise an outside surface  121  tapering from a first end  122  of the second conical section to a second end  123  of the second conical section. The first end  122  of the second conical section  120  can comprise a rounded nose  125 . The second end  123  of the second conical section  120  can be substantially planar, in embodiments, or can be integrated with or contacting second end  113  of first conical section  120  or intermediate section  130 . The intermediate section  130  or the section of flow diverter  100  where the first conical section  110  and the second conical section  120  meet, can have an outside diameter D 1 , which is the widest part of first conical section  110 , second conical section  120 , and/or intermediate section  130 . Intermediate section  130  can comprise a substantially cylindrical outer surface  131  extending from the second end  113  of the first conical section  110  to the second end  123  of the second conical section  120 . 
     The support legs  140  are configured to fixedly couple the flow diverter  100  to a support, such as a tubular  180 . The tubular  180  can comprise a casing, a casing shoe, a tool (such as downhole tool  174  described hereinbelow with reference to  FIG.  8   ) having a body and a sensor S proximally located within the body. The support legs  140  can be configured to fixedly couple the flow diverter  100  to the tubular  180  (e.g., the support) such that a central axis  150  of the flow diverter  100  is substantially parallel to and/or coincident with a central axis  150  of the tubular  180 . 
     Although described as a first conical section  110  and a second conical section  120 , and an intermediate section  130 , the first conical section  110 , the second conical section  120 , and the intermediate section  130  can be an integrated component, for example, flow diverter  100  can comprise an egg-shaped section providing the first conical section and the second conical section  120  and, optionally, an intermediate section  130 . The intermediate section  130 , when present, can have sides or outer surfaces  131  substantially parallel with central axis  150  (as shown and described further with reference to  FIG.  2 A  and  FIG.  2 B , hereinbelow). Alternatively, the base of the cone of the first conical section  110  (e.g., second end  113  of first conical section  110 ) and the base of the cone of the second conical section  120  (e.g., second end  223  of the second conical section  120 ) can meet and/or be integrated, thus providing an intermediate section  130  having diameter D 1 . That is, intermediate section  130  is not necessarily a separate region of flow diverter  100 , but can be provided by the first conical section  110  and/or the second conical section  120 . 
     With reference now to  FIG.  2 A , which is a schematic side view of a flow diverter  100 , according to embodiments of this disclosure, and  FIG.  2 B , which is a perspective view of the flow diverter  100  of  FIG.  2 A , a flow diverter  100  of this disclosure can further comprise one or more flow diverting features  260  configured to direct fluid flowing past the flow diverting features  160  toward an inside surface  181  of the tubular  180  (e.g., support). The first conical section  110 , the second conical section  120 , or both the first conical section  110  and the second conical section  120  can comprise one or more flow diverting features  160 . The flow diverting features  160  can extend at least from the rounded nose  115  (and/or first end  112 ) of the first conical section  110  to the second end  113  of the first conical section  110 , the rounded nose  125  (and/or first end  122 ) of the second conical section  120  to the second end  123  of the second conical section  120 , or both from the rounded nose  115  (and/or first end  112 ) of the first conical section  110  to the second end  113  of the first conical section  110  and from the rounded nose  125  (and/or first end  122 ) of the second conical section to the second end  123  of the second conical section  120 . 
     In embodiments, the flow diverting features  160  can extend: on outside surface  111  of first conical section  110  past the second end  113  of the first conical section  110  to the outside surface  131  of the intermediate section  130 , on outside surface  121  of second conical section  120  past the second end  123  of the second conical section  120 , or both on outside surface  111  of first conical section  110  past the second end  113  of the first conical section  110  to the outside surface  131  of the intermediate section  130  and on outside surface  121  of second conical section  120  past the second end  123  of the second conical section  120 . 
     The flow diverting features can include any structure that facilitates diversion of fluid flowing over flow diverter  100  toward sensor S. For example, and without limitation, the flow diverting features  160  can include flutes, fins, ridges, vanes, recesses, protuberances, or a combination thereof. 
     In the embodiment of  FIG.  1 A ,  FIG.  1 B ,  FIG.  2 A , and  FIG.  2 B , flow diverter  100  comprises three support legs  140 . However, a flow diverter  100  can include any number of support legs  160 , for example, from about 1 to about 10 support legs, from about 2 to about 7 support legs, from about 3 to about 5 support legs, or 1, 2, 3, 4, 5, 6, 7, 8, 9, or 10 support legs  160 . The flow diverter  100  can comprise a plurality (e.g., 2, 3, or more) support legs  160 . The plurality of support legs  160  can be distributed substantially equidistantly around the outside surface  131  of the intermediate section  130 , in embodiments. 
     A flow diverter  100  of this disclosure can comprise one or more flow diverting features  160  distributed, between each pair of support legs  140 , about the outside surface  111  of the first conical section  110 , the outside surface  121  of the second conical section  120 , or about both the outside surface  111  of the first conical section  110  and the outside surface  121  of the second conical section  120 . 
     Flow diverter  100  can be tailorable based on the size of the base tool being used (and in which flow diverter  100  can be housed), the density and rheology of the fluids being displaced, and the base concentration of the particulates in the fluids pumped. Flow diverter  100  can be molded out of thermoset plastic, although a very broad spectrum of materials can be utilized. In applications in which flow diverter  100  is to be drilled up after use, readily drillable materials can be desirable. These readily drillable materials can include thermoplastics, nylons, phenolics, 3D-printed elastomers, cast or wrought aluminum, and ceramics, among others. In embodiments in which flow diverter  100  is to be drilled up after use, the material can be selected such that conventional drill bits, roller cone bits, PDC bits, or other removal apparatus can readily penetrate through the material. In embodiments, flow diverter  100  can comprise (e.g., be manufactured from) a material selected from plastics, aluminum (e.g., cast aluminum, wrought aluminum), steel, or a combination thereof. In embodiments, the material comprises a phenolic or thermoset plastic. 
     As discussed further hereinbelow in Comparative Example 1 and Examples 1-3, the sizing of flow diverter  100  can be selected to provide a desired concentration of detectable particles within detection range X of sensor S. That is, the sizing of flow diverter  100  can be selected such that a meaningfully increased concentration of detectable particulates is provided within the detection range X of the sensor S. The diameter (e.g., diameter D 1 ) of the cones&#39; bases (which can be integrated into a solid component) can be determined for the purpose of ensuring the concentrated amount of particulates is sufficient to be readily sensed by the sensor S. By way of example, for an 8.75 inch (″) (22.2 cm) inside diameter  181  tool, a flow diverter  100  diameter D 1  of 400 inches (10.2 cm) can provide an approximate concentration increase of 1.4 times relative to simply flowing through a tubular  180  having an inside diameter D 2  of 8.75″ (22.2 cm). Increasing the flow diverter  100  diameter D 1  to 6.00″ (15.2 cm) increases the effective concentration to approximately twice the concentration relative to simply flowing through the tubular  180  having the inside diameter D 2  of 8.75″ (22.2 cm). Utilizing a flow diverter  100  having a 7″ (17.8 cm) diameter D 1 , the effective concentration of detectable particles is nearly tripled relative to flow through the tubular  180  having the inside diameter D 2  of 8.75″ (22.2 cm). 
     Flow diverter  100  is configured to divert the flow of wellbore servicing fluids passing thereover to a nearer proximity to the sensor S. The flow diverter  100  can be configured in a number of ways to achieve this outcome. As suggested in  FIG.  1 A .  FIG.  1 B ,  FIG.  2 A , and  FIG.  2 B , the primary shape of the flow diverter or concentrator  100  can be two rounded cones (e.g., first conical section  110  and second conical section  120 ) held in place in the axial direction of a cylindrical tool housing (e.g., tubular  180 ). The bases of the two cones (e.g., second end  113  of first conical section  110  and second end  123  of second conical section  120 ) and/or the intermediate section  130 , having the (widest) diameter D 1 , can be in near proximity to the sensor S (which sensor S can be, for example, positional in the wall of the housing or tubular  180 ) (e.g., between inside surface  181  of tubular  180  and outside surface  182  of tubular  180 ). The double sided cone comprising first conical section  110  and second conical section  120  (and providing intermediate section  130 ) with rounded points or noses (e.g., nose or tip  115  of first conical section  120  and nose or tip  125  of second conical section  120 ) can be supported by 2, 3, or more supporting vanes or support legs  140  extending from the cones (e.g., of first conical section  110 , second conical section  120 ) to the inside diameter or surface  181  of the housing or tubular  180 . The leading and tailing edges of the vanes or support legs  140  can be contoured to provide the smooth flow of wellbore servicing fluid F past both the vanes or support legs  140  and the central double sided cone of the double conical concentrator or flow diverter  100 . 
     The bi-directional shape of the flow diverter  100  depicted in  FIG.  1 A ,  FIG.  2 A , and  FIG.  2 B  can be utilized when fluids will flow in both directions (e.g., in the direction indicated generally by arrow A 1  (e.g., bottom to top, passing second conical section  120  prior to first conical section  110 )) in  FIG.  1 A  and in a direction opposite the direction generally indicated by arrow A 1  in  FIG.  1 A  (e.g., top to bottom, passing first conical section  110  prior to second conical section  120 ))) during use (or “functional life”) of the flow diverter  100 . Reference to “bottom” and “top” in  FIG.  1 A  indicates relative to the page, not necessarily that the second conical section  120  is below or at a bottom relative to first conical section  110  at a top of the flow diverter  100 . Generally, second section  120  can be farther along a wellbore from a surface of the earth than first conical section  110 , regardless of the design of the wellbore (e.g., horizontal, vertical, etc.). The functional life of flow diverter  100  can be expected to last from the time flow diverter  100  is run downhole (e.g., on a casing string) into a well until flow diverter  100  has reached target depth. During running downhole (e.g., running casing) and when at full depth, fluid can be pumped downhole past the flow diverter  100  in conventional flow (e.g., with reference to  FIG.  8   , described hereinbelow, into wellbore  712  from earth surface  704 ) or in combination with a reverse flow whereby fluids are pumped from the surface ( 704 ) down an annulus ( 740 ) and into the casing (e.g., tubular string  708 ) at the bottom of the wellbore ( 712 ). Flow diverter  100  can be utilized to indicate when the leading edge of a cement slurry has reached the sensor S, thereby triggering a subsequent action, such as the closure of a valve that prevents further flow. This will be described further hereinbelow with reference to  FIGS.  3 - 11   . 
     Also provided herein is a downhole tool (e.g., downhole tool  724  of  FIG.  8   , described further hereinbelow) comprising: the flow diverter  100  as described herein fixedly coupled with the tubular  180  (e.g., the support), and sensor S adjacent the flow diverter  100 . 
     The flow diverter  100  can be fixedly coupled with the tubular  180  via one or more holes  170  on each of the support legs  140 , although numerous other coupling means are intended to be within the scope of this disclosure. For example, in embodiments, the flow diverter  100  can be fixedly coupled with the tubular  180  via a set screw in each of the one or more holes  170  on each of the support legs  140 . 
     In embodiments, the sensing apparatus is a magnetic permeability sensing apparatus comprising sensor S and further comprises a magnet. For example, as described hereinbelow with reference to  FIG.  3   , which is a schematic diagram of a flow diverter  100  according to embodiments of this disclosure being utilized in conjunction with a magnetic permeability sensor  209  in a reverse cementing operation with a permanent magnetic field, and  FIG.  10   , which is a schematic diagram of a flow diverter  100  according to embodiments of this disclosure and a magnetic permeability sensor  209  in a reverse cementing operation without a non-ferromagnetic plug  207 , the sensing apparatus can comprise a magnetic permeability sensor  209 , and a permanent magnet  211 . Alternatively, as described hereinbelow with reference to  FIG.  8   , which is a schematic diagram of a drilling rig system  764  with a flow diverter  100  according to embodiments of this disclosure and a magnetic field sensor  752  and a permanent magnet  750 , the sensing apparatus can comprise a permanent magnet  750  and a magnetic field sensor  752  as sensor S. 
     In embodiments, sensor S is a component of a low-cost magnetic permeability sensing apparatus (“sensing apparatus”) that can withstand hostile subterranean environments and can be utilized for activating devices downhole based on magnetic permeability sensing, including activating a valve during reverse cementing operations. At designated stages of reverse cementing operations, a material with high magnetic permeability is added to a slurry to be sent downhole to enable a magnetic sensor S to detect the magnetic permeability of the slurry. The sensing apparatus is situated downhole near a flow port to detect the presence of a slurry with known magnetic permeability corresponding to the slurry sent downhole and to send a signal to close a valve (e.g., a sliding sleeve, ball valve, etc.) either at the flow port or across the cross section of an oilfield tubular. Once the known slurry is detected, an additional signal (e.g., a wired signal like through electric line or fiber optics, or a wireless signal such as a pressure rise, an acoustic signal, or the like) is sent by the sensing apparatus to a controller of the reverse cementing operations at the surface to stop flow of the current slurry and/or commence flow of a different slurry. In one application, the additional signal is a pressure rise associated with the increased flow resistance from the valve closing. The sensing apparatus comprises a magnet source (e.g., a permanent magnet or an electromagnet) and a magnetic sensor. The sensing apparatus is configured to detect specific ranges of magnetic permeability by inducing a magnetic field in the slurry to be read by the magnetic sensor. The magnetic sensor detects different slurries downhole based on different concentrations of the high magnetic permeability material in the slurry which results in magnetic fields with different strengths at the sensor. This sensing apparatus can be constructed from low cost materials even for operational conditions downhole and detects multiple types of cementing fluids using accurate measurements of magnetic permeability. 
     By way of example,  FIG.  3    is a schematic diagram of a flow diverter  100  according to embodiments of this disclosure being utilized in conjunction with a magnetic permeability sensor  209  in a reverse cementing operation with a permanent magnetic field. The magnetic permeability sensing apparatus comprises, as sensor S, the magnetic permeability sensor  209 , and further comprises a permanent magnet  211 . During reverse cementing operations, a slurry  200  of wellbore servicing fluid F ( FIG.  1 A ) of cementing fluids flows outside an oilfield tubular  180 , adjacent to a formation wall  202 , and into a flow port  215  after which it is detected by the sensing apparatus. The sensing apparatus comprises a permanent magnet  211 , a magnetic sensor  209 , a computing device  213  coupled to the magnetic sensor  209 , and a sensor housing  205  comprising an optional plug  207  made of a non-ferromagnetic material. The illustrated sensing apparatus also comprises a shield  203  that protects the sensing apparatus from the slurry  200  on the outside of the oilfield tubular  180 . The magnetic sensor  209  is situated between the permanent magnet  211  and the sensor housing  205 . In alternate embodiments, the magnetic sensor  209  is placed anywhere in the magnetic flux path. Flow diverter  100  is positioned within tubular  180  such that fluid flow over flow diverter  100  is directed toward sensor  209 . The permanent magnet  211  is mechanically connected to the shield  203  (e.g., with an adhesive, magnetic attraction, threaded, press fit, etc.), to the sensor housing  205 , or to the magnetic sensor  209  and positioned within the sensor housing  205  to induce a magnetic field outside of the sensor housing  205  into the interior of the oilfield tubular  180 . The magnetic sensor  209  can be mechanically connected to the plug  207 , the shield  203 , the permanent magnet  211 , or to the sensor housing  205  (e.g., with a fixture, adhesive, threaded connection, press fit, adhesive, etc.). The sensing apparatus is attached to or integrated into the oilfield tubular  180  and positioned so that the plug  207  creates a window to the interior of the oilfield tubular  180 . The sensor housing  205  is positioned near the flow port  215  so that the presence of the slurry  200  is detected as the slurry  200  enters the interior of the oilfield tubular  180 . In some cases, there is no separate plug  207  because the entire sensor housing  205  is non-ferromagnetic and serves as a magnetic window for the magnetic field. The window created by the plug  207  allows the magnetic sensor  209  to measure the magnetic permeability of the slurry  200  outside of the sensor housing  205 , which experiences the magnetic field induced by the permanent magnet  211  through the plug  207  as it flows past the sensing apparatus. Once a permeability change from the cementing fluid is detected, the computing device  213  sends a signal to an actuating mechanism  219  to close a valve  217  at a flow port  215  in the oilfield tubular  180 . The sensing apparatus pictured in  FIG.  3    can be integrated into the oilfield tubular  180  prior to deployment downhole and can be powered on deployment of the oilfield tubular  180  to preserve battery power. 
     The plug  207  comprises any low-cost non-ferromagnetic material that allows the passage of the magnetic field (e.g., has low magnetic permeability) of the permanent magnet  211  as it passes through the plug  207  and into the slurry  200 . For instance, the non-ferromagnetic material can be steel, titanium, aluminum, any alloys thereof such as INCONEL® alloy 718, plastics, composites, ceramics, glass, etc. The sensor housing  205  and shield  203  comprise any low-cost material that can protect the sensing apparatus under operational conditions (e.g., carbon steel, steel alloys, et cetera). The magnetic sensor  209  can be any sensor that detects the strength of a magnetic field or magnetic flux such as a giant magnetoresistance (GMR) sensor, Hall effect sensor, a microelectromechanical magnetic field sensor, magnetic force sensor, etc. A magnetic force sensor will be described during the exposition of  FIG.  5   . The measurements taken by the magnetic sensor  209  will increase in strength as the magnetic permeability of the slurry  200  increases due to the increased concentration of a high magnetic permeability material in the slurry  200 . The slurry  200  comprises a detection slurry having a plurality of particles with a high magnetic permeability such as suspended iron particles, martensitic stainless-steel particles, ferritic particles, iron oxide particles, ferrofluid particles, or other particles with a high magnetic permeability in a fluid. As the magnetic permeability of the slurry  200  increases, the magnetic flux detected by the magnetic sensor  209  increases. In some applications, the particle size is between 1 nm and 2 mm. 
     In some applications, the computing device  213  can be calibrated to detect ranges or differences of magnetic permeability for the slurry  200 . The accuracy of the calibration can be increased by simulating downhole conditions (temperature, pressure, flow rate, etc.) with different cementing fluids having different magnetic permeability. The computing device  213  can be programmed to detect each cementing fluid based on the magnetic strength measured by the magnetic sensor  209  during calibration. Once the computing device  213  detects a cementing fluid in the slurry  200 , it sends a signal to the actuating mechanism  219  at the flow port  215  to stop fluid flow. In some embodiments, the computing device  213  may include a time delay before sending the signal to the actuating mechanism  219 . Detection occurs when the computing device  213  determines that the measurements taken by the magnetic sensor  209  satisfy a detection criterion. This detection criterion can be that the magnetic flux is in a predetermined range as described above or that the magnetic field changes by a predetermined amount, indicating that a fluid of a different magnetic permeability is present (the amount of magnetic field can also be pre-calibrated). In response to a signal to stop fluid flow, the actuating mechanism  219  causes the valve  217  to close over the flow port  215  or across the diameter of the inside of the oilfield tubular  180 . This valve  217  can be a sliding sleeve, a flapper, a ball valve, or any valve that can stop or can variably restrict fluid flow into the inside of the oilfield tubular  180  at operational conditions downhole. The valve  217  can be actuated by opening a flow port that allows the sleeve to shift into a closed position. For example, the sliding sleeve can be hydraulically locked in the open position and the actuation of an electronic rupture disc removes the hydraulic lock and allows the sleeve to close. The actuating mechanism  219  can be open or close a flow valve and this change in restriction in the valve results in a change in the flow port (either increased or decreased flow). In another application, the valve is on the inner diameter (ID) of the tubing and prevents axial flow up the tubing. In these applications, the valve on the ID of the tubing may be a ball valve or a flapper valve. In yet another application, the valve is on the outer diameter (OD) of the tubing and prevents axial flow down the annular space between the tubing and the formation. In this application, the valve on the OD of the tubing may be a packer. 
     Although depicted as a magnet, the permanent magnet  211  can be any source of magnetic flux and, in some embodiments, can be an electromagnet. For embodiments where the permanent magnet  211  is an electromagnet, the magnetic sensor  209  can detect inductance on the electromagnet (e.g., the electromagnet itself is the sensor) because the inductance of the electromagnet will vary with the magnetic permeability of the slurry  200 . For instance, a capacitor placed in electrical series with the electromagnet will resonate at a frequency of hertz, where L is the inductance and C is the capacitance. Therefore, the magnetic permeability of the slurry  200  influences the resonant frequency of this circuit. The resonant frequency of the circuit can be measured, for example, by applying an electrical voltage pulse to the electromagnet, measuring the frequency of the induced voltage oscillations, and sending the frequency measurements to the computing device  213 . The computing device can be pre-calibrated to detect ranges of resonant frequencies corresponding to different cementing fluids, or to detect changes in the resonant frequency that indicates a change of fluid downhole. 
       FIG.  4    is a schematic diagram of using a magnetic source (permanent magnet or an electromagnet) with a magnetic sensor for detecting slurries with varying concentrations of high magnetic permeability materials. A magnetic sensor  301  detects a high-permeability slurry  300  and a low-permeability slurry  302  via a magnetic field generated by a permanent magnet  307  that flows through a barrier  305  and is guided by flux return conduits  303 A and  303 B. The high-permeability slurry  300  comprises a cementing fluid that has been modified by adding a high magnetic permeability material such as an iron powder to distinguish it from the low-permeability slurry  302 . The low-permeability slurry  302  can be a distinct cementing fluid from the high-permeability slurry  300  or can be an ambient fluid downhole (e.g., a completion brine or a drill mud). Typically, downhole fluids such as the low-permeability slurry  302  have a relative magnetic permeability μ 1  of approximately 1, whereas the high-permeability slurry  300  has a higher relative magnetic permeability μ 2  (e.g., 2 or greater) due to the addition of a ferromagnetic material. More than two cementing fluids corresponding to more than two magnetic permeability values are possible. The cementing fluids can be a cement, a spacer, a brine, a gel, a mud, or other fluids used in the cementing process. 
     The barrier  305  is made of a non-ferromagnetic material (e.g. austenitic steel, titanium, polymers, composites, aluminum, any alloys thereof such as INCONEL® alloy, etc.) so that it doesn&#39;t interfere with the magnetic field generated by the permanent magnet  307 . The flux return conduits  303 A and  303 B are made of a ferromagnetic material and guide the magnetic field generated by the permanent magnet  307  in the direction of the magnetic sensor  301 . When the slurry has a high magnetic permeability, such as the high-permeability slurry  300 , an increased amount of the magnetic field will flow through the high-permeability slurry  300  and to the magnetic sensor  301 , which will have a higher reading. Prior to deployment, the magnetic sensor  301  can be configured to detect ranges of magnetic strength (e.g., determine that measurement satisfies a detection criterion) for both the high-permeability slurry  300  and the low-permeability slurry  302  for the particular configuration of the barrier  305 , the permanent magnet  307 , and the flux return conduits  303 A and  303 B relative to the slurry at operational conditions downhole. Alternatively, the magnetic sensor  301  can be configured to detect a change in flux of the measured magnetic field sufficiently large to indicate the presence or absence of a cementing fluid. The magnetic sensor  301  is communicatively coupled to a computing device (not shown) that sends a signal to an actuating mechanism (not shown) that enables a valve to close that prevents flow or restricts flow of the slurry in response to the detection of a cementing fluid. The high-permeability slurry  300  and low-permeability slurry  302  can be inside an oilfield tubular or outside an oilfield tubular facing a formation wall, sufficiently close to a flow port to detect cementing fluid and send a signal to the actuating mechanism to stop fluid flow before or shortly after cementing fluid starts to run up the inside of the oilfield tubular. 
       FIG.  5    is a schematic diagram of a magnet source with a magnetic sensor for measuring magnetic permeability of a slurry where the magnetic sensor is a magnetic force sensor. A magnet source  403  (e.g., a permanent magnet or an electromagnet) generates a magnetic field that flows through a barrier  401  to a slurry  400  and returns through the barrier  401  to the magnet source  403 . When the slurry  400  has a high magnetic permeability, the magnet source  403  experiences an attractive force towards the slurry  400  that is measured by a magnetic force sensor  405 . A spring  407  counteracts the attractive force acting on the magnet source  403  due to the increased magnetic field passing through the higher permeability fluid. The spring  407  keeps the magnet source  403  in place as indicated by the downwards arrow in  FIG.  5   . The magnetic force sensor  305  is communicatively coupled to a computing device  409  that receives tension measurements from the magnetic force sensor  405 . 
     Although depicted as a spring  407 , the magnetic source  403  can be affixed to a shield or housing, affixed to the barrier  401 , or affixed to any other stationary component, or the spring  407  can be integrated into any other component that adds an opposing (downward) force to the magnet source  403 . In some embodiments the spring  407  is replaced with another magnet, or with the stiffness of the magnetic force sensor  405 . A compression measuring device could be used as a variation on the tension measurement device. Instead of the single magnet source  403 , two magnets can be implemented with the magnetic force sensor  405  between them. Alternatively, a piece of iron or other ferromagnetic material can be placed under the magnetic force sensor  405  and the magnetic source  403  can be situated on top towards the ferromagnetic slurry  400 . These embodiments allow the magnetic source  403  to be situated closer to the ferromagnetic slurry  400 , resulting in a higher sensitivity to force of the magnetic flux through the ferromagnetic slurry  400 . 
     The magnetic force sensor  405  can be any device that can measure the strength of the attractive force on the magnetic source  403 . For example, the tension measuring device can comprise four strain gauges in a Wheatstone bridge configuration. The barrier  401  can be made of a non-ferromagnetic material, as described variously above. The computing device  409  is configured to detect the magnetic permeability of the ferromagnetic slurry  400  based on tension measurements received from the tension measuring device. A higher tension measurement means the magnetic source  403  experiences a stronger attractive force to the ferromagnetic slurry  400 , because a higher magnetic force is exerted upon the magnetic source  403  indicating a higher magnetic permeability of the ferromagnetic slurry  400 . The computing device  409  is calibrated to detect cementing fluids corresponding to certain ranges of force measurements (e.g., that the tension measurements satisfy a detection criterion) at operational conditions downhole or corresponding to an increase or decrease in the force measurements where the change is above or below thresholds. When a cementing fluid is detecting corresponding to the end of reverse cementing operations, the computing device  409  sends a signal to an actuating mechanism (not pictured) to stop the fluid flow. 
       FIG.  6    is a flowchart of example operations for monitoring for undesired fluid invasion into a downhole oilfield tubular. This monitoring uses the disclosed flow diverter  100  with sensing apparatus, which includes a magnet source and a magnetic sensor. In the context of reverse cementing operations, the undesired fluid invasion is by a cementing mixture within a slurry. In the context of gravel packing, the undesired fluid invasion is a gravel-laden slurry. In the context of wellbore cleanup, the undesired fluid invasion is a mud. The operations in  FIG.  6    are described with reference to a magnetic field sensor and a computing device. These names are for reading convenience and the operations in  FIG.  6    can be performed by any component with the functionality described herein. 
     At block  501 , the magnetic sensor measures a magnetic field(s) through a window into the downhole oilfield tubular  180  containing flow diverter  100 . The flow diverter  100  effectively increases the number of detectable particles in the fluid F (e.g., the slurry  200 ) within a detection range X of the sensor S (e.g., magnetic permeability sensor  209  as described herein with reference to  FIG.  3    and  FIG.  10   , magnetic sensor  301  as described herein with reference to  FIG.  4   , magnetic force sensor  405  as described herein with reference to  FIG.  5   , or a magnetic field sensor  752  as described herein with reference to  FIG.  8   ). Note that one or more magnetic field sensors could be used. In one application, a plurality of magnetic field sensors is used in order to determine the flow direction. The magnetic field is generated by a permanent magnet or by an electromagnetic. The magnetic field sensor measures the magnetic field that flows from the magnetic source, through the window, and back to the magnetic field sensor. The strength of the measured magnetic field is correlated with the magnetic permeability of the nearby fluid—a fluid with a higher magnetic permeability increases the strength of the magnetic field measured by the magnetic field sensor. The magnetic field sensor can continuously measure magnetic fields or can take measurements according to a schedule (e.g., every minute). The sensing apparatus can begin monitoring for undesired fluid invasion in response to a control signal, a change in temperature, an acoustic signal, or equivalent. For instance, the magnetic sensor or the computing device can receive a signal from the surface to begin measurements at the beginning of reverse cementing operations to preserve battery power. In another instance, the magnetic sensor or the computing device could note a change in the ambient temperature or note a change in the ambient acoustic noise that indicates a need to start measurements, such as from the circulation of a cementing fluid that has a temperature lower than the formation temperature. 
     At block  503 , a computing device communicatively coupled to the magnetic sensor determines whether the magnetic measurement satisfies a criterion for changing the restriction of a valve. As examples, a valve closure criterion can indicate a specified value(s) or a specified range(s) of magnetic field strength. The magnetic sensor transmits measurements of the magnetic strength to the computing device. The computing device receives the measurements and determines whether the target cementing fluid (e.g., a spacer fluid) is present proximate the magnetic sensor. This determination can be based on magnetic field strength being within a certain range of magnetic field strengths known to correspond to a cementing fluid for operational conditions downhole. Alternatively, the determination can be based on a change in magnetic flux above a threshold magnitude. Alternatively, the determination can be based on a pattern of an increase in the magnetic flux followed by a decrease in the magnetic flux during a specified time interval. The computing device can be calibrated to detect multiple types of cementing fluids corresponding to multiple ranges of magnetic flux or based on changes of measured magnetic flux. For instance, the computing device can detect a first cementing fluid and, after an increase of measured magnetic flux above a threshold, can detect a second cementing fluid. Alternatively, after detecting a first cementing fluid the computing device can detect a second cementing fluid based on a decrease of measured magnetic flux above a first threshold and below a second threshold. If the magnetic field measurement satisfies the valve closure criterion, operations continue to block  505 . Otherwise, operations continue to block  507 . 
     At block  505 , the computing device sends a signal to an actuating mechanism to restrict the fluid flow downhole. The actuating mechanism is located proximate a radial flow port that allows fluid to flow from outside an oilfield tubular to inside the oilfield tubular during reverse cementing operations. The computing device is communicatively coupled to the actuating mechanism and, preferably, in close proximity to the actuating mechanism to minimize delay in the signal and to reduce the chance of communication malfunction. In one embodiment, the actuating mechanism can be as close as 1 inch away from the radial flow port or as far away as 100 feet from the flow port. 
     At block  507 , the computing device determines whether the sensing apparatus should continue to monitor for changes in the magnetic permeability of the fluid. The block  507  is depicted with a dashed line since this determination may be implicit or may be based on an interrupting event (e.g., a message or signal to terminate the monitoring). In some embodiments, determination of whether to continue monitoring may be based on a timing mechanism or a predefined schedule. In some embodiments, there may be a plurality of radial flow ports and plurality of actuating mechanisms. 
     The flowcharts are provided to aid in understanding the illustrations and are not to be used to limit scope of the claims. The flowcharts depict example operations that can vary within the scope of the claims. Additional operations may be performed; fewer operations may be performed; the operations may be performed in parallel; and the operations may be performed in a different order. For example, the operations depicted in blocks  501  and  503  can be performed in parallel or concurrently. It will be understood that each block of the flowchart illustrations and/or block diagrams, and combinations of blocks in the flowchart illustrations and/or block diagrams, can be implemented by program code. The program code may be provided to a processor of a general-purpose computer, special purpose computer, or other programmable machine or apparatus. 
     As will be appreciated, aspects of the disclosure may be embodied as a system, method or program code/instructions stored in one or more machine-readable media. Accordingly, aspects may take the form of hardware, software (including firmware, resident softvare, micro-code, etc.), or a combination of software and hardware aspects that may all generally be referred to herein as a “circuit,” “module” or “system.” The functionality presented as individual modules/units in the example illustrations can be organized differently in accordance with any one of platform (operating system and/or hardware), application ecosystem, interfaces, programmer preferences, programming language, administrator preferences, etc. 
     Any combination of one or more machine-readable medium(s) may be utilized. The machine-readable medium may be a machine-readable signal medium or a machine-readable storage medium. A machine-readable storage medium may be, for example, but not limited to, a system, apparatus, or device, that employs any one of or combination of electronic, magnetic, optical, electromagnetic, infrared, or semiconductor technology to store program code. More specific examples (a non-exhaustive list) of the machine-readable storage medium would include the following: a portable computer diskette, a hard disk, a random access memory (RAM), a read-only memory (ROM), an erasable programmable read-only memory (EPROM or Flash memory), a portable compact disc read-only memory (CD-ROM), an optical storage device, a magnetic storage device, or any suitable combination of the foregoing. In the context of this document, a machine-readable storage medium may be any tangible medium that can contain or store a program for use by or in connection with an instruction execution system, apparatus, or device. A machine-readable storage medium is not a machine-readable signal medium. 
     A machine-readable signal medium may include a propagated data signal with machine-readable program code embodied therein, for example, in baseband or as part of a carrier wave. Such a propagated signal may take any of a variety of forms, including, but not limited to, electromagnetic, optical, or any suitable combination thereof. A machine-readable signal medium may be any machine-readable medium that is not a machine-readable storage medium and that can communicate, propagate, or transport a program for use by or in connection with an instruction execution system, apparatus, or device. 
     Program code embodied on a machine-readable medium may be transmitted using any appropriate medium, including but not limited to wireless, wireline, optical fiber cable, RF, etc., or any suitable combination of the foregoing. 
     Computer program code for carrying out operations for aspects of the disclosure may be written in any combination of one or more programming languages, including an object oriented programming language such as the Java® programming language, C++ or the like; a dynamic programming language such as Python; a scripting language such as Perl programming language or PowerShell script language, and conventional procedural programming languages, such as the “C” programming language or similar programming languages. The program code may execute entirely on a stand-alone machine, may execute in a distributed manner across multiple machines, and may execute on one machine while providing results and or accepting input on another machine. 
     The program code/instructions may also be stored in a machine-readable medium that can direct a machine to function in a particular manner, such that the instructions stored in the machine-readable medium produce an article of manufacture including instructions which implement the function/act specified in the flowchart and/or block diagram block or blocks. 
       FIG.  7    depicts an example computer system with a sensing apparatus comprising a magnet (e.g., a permanent magnet) and a sensor S (e.g., a magnetic field sensor), and a flow diverter  100  of this disclosure utilized to divert fluid flowing over the flow diverter toward the sensor S. The computer system includes a processor  601  (possibly including multiple processors, multiple cores, multiple nodes, and/or implementing multi-threading, etc.). The computer system includes memory  607 . The memory  607  may be system memory or any one or more of the above already described possible realizations of machine-readable media. The computer system also includes a bus  603  and a network interface  605 . The system communicates via transmissions to and/or from remote devices via the network interface  605  in accordance with a network protocol corresponding to the type of network interface, whether wired or wireless and depending upon the carrying medium. In addition, a communication or transmission can involve other layers of a communication protocol and or communication protocol suites (e.g., transmission control protocol, Internet Protocol, user datagram protocol, virtual private network protocols, etc.). The system also includes a sensing apparatus  611  with a magnet (e.g., a permanent magnet) and magnetic sensor S positioned proximal a flow diverter  100  of this disclosure such that fluid flow over flow diverter  100  is directed closer to sensor S. The sensing apparatus  611  detects the presence of ferromagnetic material in a slurry based on the magnetic field emitted by the permanent magnet and magnetic flux readings by the magnetic field sensor as described variously above. Any one of the previously described functionalities may be partially (or entirely) implemented in hardware and/or on the processor  601 . For example, the functionality may be implemented with an application specific integrated circuit, in logic implemented in the processor  601 , in a co-processor on a peripheral device or card, etc. Further, realizations may include fewer or additional components not illustrated in  FIG.  7    (e.g., video cards, audio cards, additional network interfaces, peripheral devices, etc.). The processor  601  and the network interface  605  are coupled to the bus  603 . Although illustrated as being coupled to the bus  603 , the memory  607  may be coupled to the processor  601 . 
       FIG.  8    is a schematic diagram of a drilling rig system with a sensing system including a permanent magnet and a magnetic field sensor positioned proximal a flow diverter  100  of this disclosure. For example, in  FIG.  8    it can be seen how a system  764  may also form a portion of a rig  702  located at the surface  704  of a well  706 . Drilling, testing, and production of oil and gas wells is commonly carried out using a string of pipes connected together so as to form a tubular string  708  that is lowered through a rotary table  710  into a wellbore or borehole  712 . Here a rig platform  786  is equipped with a derrick  788  that supports a hoist. 
     The rig  702  may thus provide support for the tubular string  708 . The tubular string  708  may operate to penetrate the rotary table  710  for drilling the borehole  712  through subsurface formations  714 . The tubular string  708  may include a Kelly  716 , drill pipe  718 , and a bottom hole assembly  720 , perhaps located at the lower portion of the drill pipe  718 . 
     The bottom hole assembly  720  may include drill collars  722 , a downhole tool  724 , and a drill bit  726 . The drill bit  726  may operate to create a borehole  712  by penetrating the surface  704  and subsurface formations  714 . The downhole tool  724  may comprise any of a number of different types of tools including MWD tools, LWD tools, and others. 
     During drilling operations, the tubular string  708  (perhaps including the Kelly  716 , the drill pipe  718 , and the bottom hole assembly  720 ) may be rotated by the rotary table  710 . In addition to, or alternatively, the bottom hole assembly  720  may also be rotated by a motor (e.g., a mud motor) that is located downhole. The drill collars  722  may be used to add weight to the drill bit  726 . The drill collars  722  may also operate to stiffen the bottom hole assembly  720 , allowing the bottom hole assembly  720  to transfer the added weight to the drill bit  726 , and in turn, to assist the drill bit  726  in penetrating the surface  704  and subsurface formations  714 . 
     During drilling operations, a mud pump  732  may pump drilling fluid (sometimes known by those of ordinary skill in the art as “drilling mud”) from a mud pit  734  through a hose  736  into the drill pipe  718  and down to the drill bit  726 . The drilling fluid can flow out from the drill bit  726  and be returned to the surface  704  through an annular area  740  between the drill pipe  718  and the sides of the borehole  712 . The drilling fluid may then be returned to the mud pit  734 , where such fluid is filtered. In some embodiments, the drilling fluid can be used to cool the drill bit  726 , as well as to provide lubrication for the drill bit  726  during drilling operations. Additionally, the drilling fluid may be used to remove subsurface formation  714  cuttings created by operating the drill bit  726 . It is the images of these cuttings that many embodiments operate to acquire and process. The drill pipe further comprises a permanent magnet  750  and a magnetic field sensor  752  configured to measure magnetic flux of a slurry inside of the tubular string  708  generated by the magnetic field of the permanent magnet  750  and detect cementing fluids or other operational fluids downhole. Flow diverter  100  is positioned within tubular string  708  such that fluid flow over flow diverter  100  is directed toward magnetic field sensor  752 , thus concentrating an amount of detectable particles of taggant T ( FIG.  1 A ) within a detection range X ( FIG.  1 A ) of the magnetic field sensor  752 . 
       FIG.  9    depicts a schematic diagram of a wireline system with a permanent magnet and magnetic field sensor positioned proximal a flow diverter  100  of this disclosure. A system  800  can be used in an illustrative logging environment with a drill string removed, in accordance with some embodiments of the present disclosure. 
     Subterranean operations may be conducted using a wireline system  820  once the drill string has been removed, though, at times, some or all of the drill string may remain in a borehole  814  during logging with the wireline system  820 . The wireline system  820  may include one or more logging tools  826  that may be suspended in the borehole  814  by a conveyance  815  (e.g., a cable, slickline, or coiled tubing). The logging tool  826  may be communicatively coupled to the conveyance  815 . The conveyance  815  may contain conductors for transporting power to the wireline system  820  and telemetry from the logging tool  826  to a logging facility  844 . Alternatively, the conveyance  815  may lack a conductor, as is often the case using slickline or coiled tubing, and the wireline system  820  may contain a control unit  834  that contains memory, one or more batteries, and/or one or more processors for performing operations and storing measurements. A sensing apparatus  850  comprising a permanent magnet and a magnetic field sensor are affixed to the logging tool  826  and can measure magnetic flux of slurry downhole. The logging tool  826  can detect the presence of a ferromagnetic material based on the measured magnetic flux, as described variously above. 
     In certain embodiments, the control unit  834  can be positioned at the surface, in the borehole (e.g., in the conveyance  815  and/or as part of the logging tool  826 ) or both (e.g., a portion of the processing may occur downhole and a portion may occur at the surface). The control unit  834  may include a control system or a control algorithm. In certain embodiments, a control system, an algorithm, or a set of machine-readable instructions may cause the control unit  834  to generate and provide an input signal to one or more elements of the logging tool  726 , such as the sensors along the logging tool  826 . The input signal may cause the sensors to be active or to output signals indicative of sensed properties. The logging facility  844  (shown in  FIG.  9    as a truck, although it may be any other structure) may collect measurements from the logging tool  826 , and may include computing facilities for controlling, processing, or storing the measurements gathered by the logging tool  826 . The computing facilities may be communicatively coupled to the logging tool  826  by way of the conveyance  815  and may operate similarly to the control unit  834 . In certain example embodiments, the control unit  834 , which may be located in logging tool  826 , may perform one or more functions of the computing facility. 
     The logging tool  826  includes a mandrel and a number of extendible arms coupled to the mandrel. One or more pads are coupled to each of the extendible arms. Each of the pads have a surface facing radially outward from the mandrel. Additionally, at least sensor disposed on the surface of each pad. During operation, the extendible arms are extended outwards to a wall of the borehole to extend the surface of the pads outward against the wall of the borehole. The sensors of the pads of each extendible arm can detect image data to create captured images of the formation surrounding the borehole. Flow diverter  100  is positioned in logging tool  826  such that fluid flow over flow diverter  100  is directed toward the sensor(s), thus concentrating an amount of detectable particles of taggant T ( FIG.  1 A ) within a detection range X ( FIG.  1 A ) of the sensors. 
       FIG.  10    is a schematic diagram of a magnetic permeability sensor proximal a flow diverter  100  of this disclosure in a reverse cementing operation without a non-ferromagnetic plug. The schematic diagram depicted in  FIG.  10    is substantially similar to the schematic diagram depicted in  FIG.  3   , except that the sensor housing  205  does not comprise a plug made of a non-ferromagnetic material. Unlike the sensor housing  205  of  FIG.  3   , the sensor housing  205  of  FIG.  10    does not have a hole or thread to insert a plug. In some embodiments, the sensor housing  205  comprises a non-ferromagnetic material instead of a plug, and magnetic flux generated by the permanent magnet  211  flows through the sensor housing  205 , the slurry  200 , and back to the magnetic sensor  209 . Alternatively, when the sensor housing  205  is not made of a non-ferromagnetic material, the permanent magnet  211  can be a source of stronger magnetic flux so that magnetic flux generated by the permanent magnet is able to flow through the sensor housing  205 , to the slurry  200 , and back to the magnetic sensor  209 . As described with reference to  FIG.  3   , flow diverter  100  is positioned within tubular  180  such that fluid flow over flow diverter  100  is directed toward sensor  209 . 
       FIG.  11    is a schematic of a reverse cementing operation with a flow diverter  100  according to this disclosure proximal a magnetic permeability sensor S of a magnetic permeability sensing apparatus  930 . An oilfield tubular  904  runs down a borehole  901  that has been drilled into the earth and that has a borehole wall  902 . During cementing operations in the borehole  901 , a slurry  900  circulates down the outside of the oilfield tubular  904  and inside the borehole wall  902  towards a valve  918  at the bottom of the oilfield tubular  904 . A measurement unit  914  at the surface is communicatively coupled via a wire  908  to various sensors that include a magnetic permeability sensing apparatus  930 . The oilfield tubular  904  is formed from lengths of tubing joined by threaded joints  906  and runs the wire  908  downhole with straps  910 . As the slurry  900  of wellbore servicing fluid F (e.g., cementitious fluid containing taggant T) enters the inside of the oilfield tubular  904 , the magnetic permeability sensing apparatus  930  sends a signal to the measurement unit  914  indicating the presence of the slurry  900  inside of the oilfield tubular  904 . Flow of the slurry  900  over the flow diverter  100  increases a concentration of detectable particles within sensing range of the sensor S of magnetic permeability sensing apparatus  930 . In response, the measurement unit  914  sends a signal to an actuating mechanism to close the valve  918  and/or terminate/suspend cementing operations. Additionally, the measurement unit  914  can send a signal to an inner liner  928  that runs down the inside of the oilfield tubular  904 . The signal causes the inner liner  928  to circulate unnecessary slurry  900  out of the inside of the oilfield tubular  904 . 
     Although depicted with a wire  908  communicatively coupled to the magnetic permeability sensing apparatus  930  and the measurement unit  914 , the magnetic permeability sensing apparatus  930  can be communicatively coupled to an actuating mechanism for the valve  918  and can be configured to send a signal to the actuating mechanism to close the valve  918  in response to detecting the presence of the slurry  900 . Furthermore, the inner liner  928  can be communicatively coupled to the magnetic permeability sensing apparatus  930  downhole. The magnetic permeability sensing apparatus  930  can send a signal to circulate excess slurry  900  out of the oilfield tubular  904  with the inner liner  928 . The wire  908  can run downhole with small diameter tubing or a rigid housing, and multiple wires can be implemented for redundancy. In embodiments where the magnetic permeability sensing apparatus  930  is coupled to the valve  918 , the wire  908  is not required. 
     The slurry  900  of wellbore servicing fluid F ( FIG.  1 A ) can comprise a cementing fluid such as a cement slurry, a spacer, a brine, a mud, or any fluid used during the cementing process (e.g. to cement the outside of the oilfield tubular  904  or to clean cuttings out of the borehole due to drilling). Each cementing fluid in the slurry  900  has a magnetic permeability and the magnetic permeability of each fluid can be modified by adding ferromagnetic material of a prespecified concentration. Modifying one of the cementing fluids, two of the cementing fluids, or all of the cementing fluids are all anticipated by the present disclosure. The measurement unit  914  can be further communicatively coupled to an array of sensors downhole that can measure temperature, pressure, strain, acoustic (noise) spectra, acoustic coupling, chemical (e.g., hydrogen or hydroxyl) concentration, etc. and the wire  908  can be an optic fiber configured for distributed acoustic sensing. Measurements taken by sensors downhole can be used by a controller to guide reverse cementing operations. The magnetic permeability sensing apparatus  930  is depicted as facing towards the inside of the oilfield tubular  904 , however the magnetic permeability sensing apparatus  930  can alternatively face the outside of the oilfield tubular  904  to detect the slurry  900  before it enters the inside of the oilfield tubular  904 . 
     With reference now back to  FIG.  1   , also provided herein is a method comprising: during a wellbore servicing operation, introducing a wellbore servicing fluid F ( FIG.  1 A ) containing taggant T downhole; detecting when the wellbore servicing fluid containing the taggant T arrives at a location within the tubular  180  via a sensing system including a sensor S positioned adjacent an inside surface  181  of the tubular  180 , wherein the sensor S is sensitive to the taggant T; and changing an operating condition of the wellbore servicing operation in response to the detecting. Detecting when the wellbore servicing fluid containing the taggant T arrives at the location within the tubular  180  comprises increasing a number of particles of the taggant T within a detection range X (exaggerated in  FIG.  1 A ) of the sensor S by flowing the wellbore servicing fluid past a flow diverter  100  configured to increase the number of the taggant particles within the detection range X of the sensor S. The flow diverter  100  is a flow diverter as described herein. 
     The taggant T can comprise a magnetic component, such as, and without limitation, hematite, magnetite, or a combination thereof. The sensing system can comprise a magnet that produces a magnetic field in the detection range X and a magnetic sensor S. The sensor S can comprise any sensor as described hereinabove, such as a magnetic permeability sensor, such as magnetic permeability sensor  209  as described with reference to  FIG.  3    and  FIG.  10   , a magnetic sensor  301  as described with reference to  FIG.  4   , a magnetic force sensor  405  as described with reference to  FIG.  5   , or a magnetic field sensor  752  as described with reference to  FIG.  8   . 
     The flow diverter  100  reduces an amount of taggant T needed in the wellbore servicing fluid to provide a detectable amount of the taggant T particles in the detection range X relative to a same method that does increase the number of taggant T particles within the detection range X of the sensor S. Although not particularly limited, the detection range X can be within about ½″ (12.7 mm) to about 1″ (25.4 mm) of the inside surface  181  of the tubular  180 . 
     The wellbore servicing operation can comprise a cementing operation, such as, without limitation, a reverse cementing operation. The wellbore servicing fluid F containing the taggant T can comprise a cement slurry (e.g., slurry  200  of  FIG.  3   ). The method can further comprise introducing the cement slurry into an annulus (e.g., such as annulus  740  of  FIG.  8   ) between a wellbore wall (e.g.,  712  of  FIG.  8   ) and an outside surface of the tubular  180  (e.g., tubular string  708  of  FIG.  8   ), whereby the cement slurry (e.g., slurry  200  of  FIG.  3   ) enters a downhole end ( 727  of  FIG.  8   ) of the tubular  180  (e.g., tubular string  708  of  FIG.  8   ). 
     The flow diverter  100  can be positioned in the tubular  180  with a central axis  150  of the flow diverter  100  substantially parallel and/or coincident with a central axis  150  of the tubular  180 . The second conical section  120  can be closer to the downhole end  727  of the tubular  180  than the first conical section  110 , for example in embodiments such as depicted in  FIG.  2 A  and  FIG.  2 B , wherein the second conical section  120  comprises flow diverting features  160  configured to direct fluid flowing past the flow diverting features  160  (e.g., during a reverse cementing operation) toward the sensor  209 . In such embodiments, the first conical section  110  may not comprise flow diverting features  160 . Alternatively, a flow diverter  100  can be utilized to detect fluid flow during conventional flow down tubular string  708  and out annulus  740 . In such embodiment, flow diverter  100  can comprise a first conical section  110  having flow diverting features  160  and a second conical section  120  having or not having flow diverting features  160 . 
     The flow diverter  100  of this disclosure can be utilized with a tubular  180  or downhole tool having an inside diameter  181  sufficient for the further drilling of a wellbore ( 712 ,  FIG.  8   ). The difficulty in sensing a strong enough presence of particulate or taggant T with sensor S can be based upon the concentration of the particulate or taggant T in the fluid F. Because the particulates of taggant T being considered can be heavy in comparison to the carrier or base fluid, there are limitations as to how high a concentration of particulates can be employed while maintaining the particulates suspended within the carrier fluid. Too high of a concentration of particulates may also be deleterious to other components found in the casing string. Via this disclosure, rather than further complicating the rheological hierarchies of the fluids being pumped so that increasing concentrations can be utilized, the flow diverter  100  acts as a mechanical concentrator that enables a smaller concentration of particulates to appear much greater as it passes near to the sensor S. That is, a concentration of detectible particulates of taggant T within detection range X of the sensor S is effectively increased via diversion of flow caused by flow diverter  100 . 
     Accordingly, flow diverter  100  reduces the global concentration of particles required for detection by concentrating them near to the sensor S in the wall of the tool. Reducing the initial concentration (e.g., the concentration of taggant in the wellbore servicing fluid F introduced downhole) can improve available options for rheological support of the particles in the fluid F being used for detection by the sensor S. The flow diverter  100  can thus increase a signal strength and reliability of the sensor S to detect the particles of taggant T. 
     EXAMPLES 
     The embodiments having been generally described, the following examples are given as particular embodiments of the disclosure and to demonstrate the practice and advantages thereof It is understood that the examples are given by way of illustration and not intended to limit the specification or the claims in any manner. 
     Comparative Example 1 
     In this Comparative Example 1, a tubular  180  (e.g. a casing) has an inside diameter D 1  of 8.75 inches (22.2 cm), providing a flow area of 60.13 in 2  (388 cm 2 ). 
     Example 1 
     In this Example, by a flow diverter  100  having a diameter D 1  of 4.00 in (10.2 cm) is utilized to reduce the flow area around the flow diverter  100  within tubular  180  (e.g., the casing flow area minus the area of the solid flow diverter  100 ) to 48 in 2  (310 cm 2 ), thus providing an effective increase in particle density of 1.4 times relative to the unobstructed casing (e.g., casing having no flow diverter therein). 
     Example 2 
     In this Example 2, a flow diverter  100  having a diameter D 1  of6 inches (15.2 cm) is utilized to reduce the flow area inside tubular  180  to 32 in 2  (206 cm 2 ), thus providing a two-fold increase in particle density. 
     Example 3 
     In this Example 3, a flow diverter  100  having a diameter D 1  of 7 inches (17.8 cm) is utilized within tubular  180  to reduce the flow area to 22 in 2  (142 cm 2 ), thus providing a three-fold increase in particle density. 
     As seen when comparing the flow area of Example 1, Example 2, and Example 3 to the flow area of Comparative Example 1, the flow area within tubular  180  can be adjusted by selecting a flow diverter  100  of a certain size (e.g., a certain outside diameter D 1 ) to create a denser population of taggant T (e.g., magnetite) particles (e.g., a greater number of detectable particles) within detection range X of sensor S. 
     ADDITIONAL DISCLOSURE 
     The following are non-limiting, specific embodiments in accordance with the present disclosure: 
     In a first embodiment, a flow diverter  100  comprises: a first conical section  210 ; a second conical section  120 ; and support legs  140 , wherein the first conical section  110  comprises an outside surface  111  tapering from a first end  112  to a second end  113  of the first conical section  110 , wherein the first end  112  of the first conical section  110  comprises a rounded nose  115 , (and optionally, wherein the second end  113  of the first conical section  110  is substantially planar), wherein the second conical section  120  comprises an outside surface  121  tapering from a first end  122  to a second end  123  of the second conical section, wherein the first end  122  of the second conical section  120  comprises a rounded nose  125 , (and optionally, wherein the second end  123  of the second conical section  120  is substantially planar), and wherein the support legs  140  are configured to fixedly couple the flow diverter  100  to a tubular  180 . 
     A second embodiment can include the flow diverter of the first embodiment, wherein the support legs  140  are configured to fixedly couple the flow diverter to the tubular such that a central axis  150  of the flow diverter  100  is substantially parallel to a central axis of the tubular. 
     A third embodiment can include the flow diverter of the first or the second embodiment further comprising flow diverting features  160  configured to direct fluid flowing past the flow diverting features  160  toward an inside surface of the tubular. 
     A fourth embodiment can include the flow diverter of the third embodiment, wherein the first conical section  110 , the second conical section  120 , or both comprise the flow diverting features  160 , and wherein the flow diverting features  160  extend at least from the rounded nose  115  of the first conical section  110 , the rounded nose  125  of the second conical section  120 , or both to the second end  113  of the first conical section  110 , the second end  123  of the second conical section  120 , or both, respectively. 
     A fifth embodiment can include the flow diverter of the fourth embodiment, wherein the flow diverting features extend past the second end  113  of the first conical section  110 , the second end  123  of the second conical section  120 , or both to the outside surface  131  of an intermediate section  130 , wherein the intermediate section  130  comprises a substantially cylindrical outer surface  131  extending from the second end  113  of the first conical section  110  to the second end  123  of the second conical section  120  (e.g., and having a diameter D 1 ). 
     A sixth embodiment can include the flow diverter of any one of the third to fifth embodiments, wherein the flow diverting features  160  include flutes, fins, ridges, vanes, recesses, protuberances, or a combination thereof. 
     A seventh embodiment can include the flow diverter of any one of the first to sixth embodiments comprising from about 3 to about 5 support legs. 
     An eighth embodiment can include the flow diverter of any one of the first to seventh embodiments, wherein the support legs are distributed substantially equidistantly around the outside surface  131  of the intermediate section  130 , the first conical section  110 , and/or the second conical section  120 . 
     A ninth embodiment can include the flow diverter of any one of the first to eighth embodiments comprising one or more flow diverting features  160  distributed, between each pair of support legs  140 , about the outside surface  111  of the first conical section  110 , the outside surface  121  of the second conical section  120 , or about both the outside surface  111  of the first conical section  110  and the outside surface  121  of the second conical section  120 . 
     A tenth embodiment can include the flow diverter of any one of the first to tenth embodiments, wherein the flow diverter comprises a material selected from plastics, aluminum (e.g., cast aluminum, wrought aluminum), steel (e.g., in applications of a well structure not requiring drillout), or a combination thereof. 
     An eleventh embodiment can include the flow diverter of the tenth embodiment, wherein the material comprises a phenolic or thermoset plastic. 
     In a twelfth embodiment, a downhole tool comprises: the flow diverter of any one of the first to eleventh embodiments fixedly coupled with the tubular; and a sensor adjacent the flow diverter. 
     A thirteenth embodiment can include the downhole tool of the twelfth embodiment, wherein the tubular comprises a casing, a casing shoe, a tool having a body, and a sensor proximally located within the body (e.g., between maximum outside diameter  182  and minimum inside diameter  181  of the tubular  180  of the tool body configuration). 
     A fourteenth embodiment can include the downhole tool of any one of the twelfth or thirteenth embodiment, wherein the flow diverter  100  is fixedly coupled with the tubular via one or more holes  170  on each of the support legs  140 . 
     A fifteenth embodiment can include the downhole tool of the fourteenth embodiment, wherein the flow diverter  100  is fixedly coupled with the tubular via a set screw in each of the one or more holes  170  on each of the support legs  140 . 
     A sixteenth embodiment can include the downhole tool of anyone of the twelfth to fifteenth embodiments, wherein the sensor comprises a magnet. 
     A seventeenth embodiment can include the downhole tool of the sixteenth embodiment, wherein the sensor comprises a magnetic permeability sensor, and the magnet comprises a permanent magnet. 
     In an eighteenth embodiment, a method comprises: during a wellbore servicing operation, introducing a wellbore servicing fluid containing taggant downhole; detecting when the wellbore servicing fluid containing the taggant arrives at a location within the tubular via a sensor positioned adjacent an inside surface of the tubular, wherein the sensor is sensitive to the taggant; and changing an operating condition of the wellbore servicing operation in response to the detecting, wherein detecting when the wellbore servicing fluid containing the taggant arrives at the location within the tubular comprises increasing a number of particles of the taggant within a detection range of the sensor by flowing the wellbore servicing fluid past a flow diverter configured to increase the number of the taggant particles within the detection range of the sensor. 
     A nineteenth embodiment can include the method of the eighteenth embodiment, wherein the flow diverter is a flow diverter according to any one of the first to eleventh embodiments. 
     A twentieth embodiment can include the method of any one of the eighteenth or nineteenth embodiments, wherein the taggant comprises a magnetic component. 
     A twenty first embodiment can include the method of the twentieth embodiment, wherein the taggant comprises hematite, magnetite, or a combination thereof. 
     A twenty second embodiment can include the method of any one of the eighteenth to twenty first embodiments, wherein the sensor comprises a magnet that produces a magnetic field in the detection range. 
     A twenty third embodiment can include the method of any one of the eighteenth to twenty second embodiments, wherein the flow diverter reduces an amount of taggant needed in the wellbore servicing fluid to provide a detectable amount of the taggant particles in the detection range relative to a same method that does increase the number of taggant particles within the detection range of the sensor. 
     A twenty fourth embodiment can include the method of any one of the eighteenth to twenty third embodiments, wherein the detection range is within about ½″ (12.7 mm) to about 1″ (25.4 mm) of the inside surface of the tubular. 
     A twenty fifth embodiment can include the method of any one of the eighteenth to twenty fourth embodiments, wherein the wellbore servicing operation comprises cementing operation. 
     A twenty sixth embodiment can include the method of the twenty fifth embodiment, wherein the cementing operation comprises a reverse cementing operation. 
     A twenty seventh embodiment can include the method of any one of the twenty fifth or twenty sixth embodiments, wherein the wellbore servicing operation comprising the taggant comprises a cement slurry. 
     A twenty eighth embodiment can include the method of the twenty seventh embodiment further comprising introducing the cement slurry into an annulus between a wellbore wall and an outside surface of the tubular, whereby the cement slurry enters a downhole end of the tubular. 
     A twenty ninth embodiment can include the method of any one of the twenty seventh or twenty eighth embodiments, wherein the flow diverter is positioned in the tubular with a central axis  250  of the flow diverter substantially parallel with a central axis of the tubular, and with the second conical section closer to the downhole end of the tubular than the first conical section, and wherein the second conical section comprises flow diverting features configured to direct fluid flowing past the flow diverting features toward the sensor. 
     A thirtieth embodiment can include the method of the twenty ninth embodiment, wherein the first conical section does not comprise flow diverting features. 
     While embodiments have been shown and described, modifications thereof can be made by one skilled in the art without departing from the spirit and teachings of this disclosure. The embodiments described herein are exemplary only, and are not intended to be limiting. Many variations and modifications of the embodiments disclosed herein are possible and are within the scope of this disclosure. Where numerical ranges or limitations are expressly stated, such express ranges or limitations should be understood to include iterative ranges or limitations of like magnitude falling within the expressly stated ranges or limitations (e.g., from about 1 to about 10 includes, 2, 3, 4, etc.; greater than 0.10 includes 0.11, 0.12, 0.13, etc.). For example, whenever a numerical range with a lower limit, Rl, and an upper limit, Ru, is disclosed, any number falling within the range is specifically disclosed. In particular, the following numbers within the range are specifically disclosed: R=Rl+k*(Ru−Rl), wherein k is a variable ranging from 1 percent to 100 percent with a 1 percent increment, i.e., k is 1 percent, 2 percent, 3 percent, 4 percent, 5 percent, . . . 50 percent, 51 percent, 52 percent, . . . , 95 percent, 96 percent, 97 percent, 98 percent, 99 percent, or 100 percent. Moreover, any numerical range defined by two R numbers as defined in the above is also specifically disclosed. Use of broader terms such as comprises, includes, having, etc. should be understood to provide support for narrower terms such as consisting of, consisting essentially of, comprised substantially of, etc. When a feature is described as “optional,” both embodiments with this feature and embodiments without this feature are disclosed. Similarly, the present disclosure contemplates embodiments where this “optional” feature is required and embodiments where this feature is specifically excluded. Use of the phrase “at least one of” preceding a list with the conjunction “and” should not be treated as an exclusive list and should not be construed as a list of categories with one item from each category, unless specifically stated otherwise. A clause that recites “at least one of A. B, and C” can be infringed with only one of the listed items, multiple of the listed items, and one or more of the items in the list and another item not listed. 
     Accordingly, the scope of protection is not limited by the description set out above but is only limited by the claims which follow, that scope including all equivalents of the subject matter of the claims. Each and every claim is incorporated into the specification as embodiments of the present disclosure. Thus, the claims are a further description and are an addition to the embodiments of the present disclosure. The discussion of a reference herein is not an admission that it is prior art, especially any reference that can have a publication date after the priority date of this application. The disclosures of all patents, patent applications, and publications cited herein are hereby incorporated by reference, to the extent that they provide exemplary, procedural, or other details supplementary to those set forth herein.