Patent Publication Number: US-2021164908-A1

Title: Bandgap detection of reactive components in fluids

Description:
BACKGROUND 
     The present application relates sensing reactive components in fluids. 
     Hydrocarbon producing wells may contain many different formation liquids and gases such as methane, ethane, and other higher hydrocarbons, as well as carbon dioxide, hydrogen sulfide, water, and other compounds. In order to evaluate the commercial value of a hydrocarbon producing well, or as an aid in operations and well planning, it is often useful to obtain information by analyzing the component concentrations of the produced fluid from a formation or an individual well. 
     For example, certain components in downhole fluids are corrosive. In general, there are four types of corrosion: sweet, sour, oxygen, and electrochemical. Sour corrosion is found in oil and gas wells that contain hydrogen sulfide gas. Hydrogen sulfide also presents health risks that need to be addressed and planned for. Wells may also produce other undesirable corrosive components such as carbon dioxide. A good understanding of the downhole fluid and gas concentrations is desirable in an attempt to control corrosion rates and to plan for safe development and production of the hydrocarbons. 
     Spectroscopy is a known technique for analyzing downhole fluids, including drilling fluids and crude oil. For example, methods are known for analyzing drilling muds that involve reflectance or transmittance infrared (IR) spectroscopy that assays the components of the fluid directly. Spectroscopy is typically employed in wellbore environments in the near infrared-range of from 1000 to 2500 nm. Spectroscopy is typically emitted in this range because near IR emitters and sensors are known to be easier to operate at well temperatures while longer wavelength emitters have shown limited output optical power under similar well conditions. 
     Typically, spectroscopy monitoring involves obtaining a formation fluid sample downhole and bringing the sample to the surface where measurements and processing of the resultant data takes place. These measurement methods are typically utilized at relatively large time intervals and thus do not provide continuous information about wellbore condition or that of the surrounding formations. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       The following figures are included to illustrate certain aspects of the embodiments, and should not be viewed as exclusive embodiments. The subject matter disclosed is capable of considerable modifications, alterations, combinations, and equivalents in form and function, as will occur to those skilled in the art and having the benefit of this disclosure. 
         FIG. 1  illustrates a configuration for a backside reflectance sensor of the present disclosure. 
         FIG. 2  illustrates a configuration for a transmission sensor of the present disclosure. 
         FIG. 3  illustrates an alternative configuration for a transmission sensor of the present disclosure. 
         FIG. 4  illustrates a configuration for an electrical sensing component of the present disclosure. 
         FIG. 5  illustrates a configuration for a combination sensor of the present disclosure. 
         FIG. 6  illustrates a multi-sensor configuration according to at least some embodiments of the present disclosure. 
         FIG. 7  is a wellbore drilling system in accordance with at least some of the embodiments of the present disclosure. 
         FIG. 8  depicts a schematic diagram of an exemplary wireline system. 
     
    
    
     DESCRIPTION 
     The present application relates sensing reactive components in fluids by monitoring band gap changes to a material having interacted with the reactive components via physisorption and/or chemisorption. In some embodiments, the sensors of the present disclosure include the material as a reactive surface on a substrate. The band gap changes to the material may be detected by measuring conductance changes and/or spectroscopic changes. In some instances, the sensing may occur downhole during one or more wellbore operations like drilling, hydraulic fracturing, and producing hydrocarbons. 
     As used herein, the term “physisorption” and grammatical derivations thereof refer to physical adsorption of a compound to a material without the compound chemically reacting with the material. As used herein, the term “chemisorption” and grammatical derivations thereof refer to adsorption of a compound to a material where the compound and the material chemically react. As used herein, the term “reactive component” refers to the components of a fluid that when physisorbed or chemisorbed to a material cause the band structure of the material to change. As used herein, the term “reactive surface” refers to portion of the material that is monitored for band gap changes when contacted with the reactive component. The portion of the material that is the reactive surface is the distance extending across the material over an optical interaction depth for that material. For most opaque materials, this optical interaction depth would be limited to generally more than a quarter wavelength of light to a few wavelengths of light (small distances). However, for some opaque materials, the optical interaction depth can be enhanced by various evanescent enhancement techniques. For transparent materials, the optical interaction depth extends to the entire limit of diffusion distance through the material. Although this may enhance the optical activity of the material, it will generally slow the response time of the measurement. The optimal response time and diffusion characteristics of the surface material will allow a sufficient distance through the surface to be identified. Practically, optical interaction depth may be less than a few nanometers to a few microns for opaque systems, and possibly up to a few millimeters (maybe a centimeter for large systems) that are transparent. 
     The sensors described herein utilize reactive surfaces formed of materials whose electronic band structure changes when reactive components in fluids are physisorbed and/or chemisorbed thereto. The change to the reactive surfaces&#39; band structure can then be detected via reflectance spectroscopy, transmission spectroscopy, electrical measurements, or a combination thereof and used to determine the concentration of the reactive components in fluids including downhole fluids like drilling fluids, formation fluids (i.e., fluids native to the formation), acidizing fluids, hydrocarbon fluids, and the like. 
     It should be noted that the methods and systems of the present discourse are different than surface enhanced spectroscopy methods like surface enhanced Raman where the band structure of the reactive component is measured. Rather, the present methods and systems measure changes to the bands structure of reactive surfaces. Because the reactive surface is being analyzed in the methods and systems described herein, the sensor of the present disclosure may be sensitive to lower concentrations of the reactive components. 
     Additionally, the methods and systems of the present discourse are more robust than surface enhanced spectroscopy methods because the environment downhole may be hostile (e.g., high temperature, high pressure, corrosive, and the like). The hostile downhole environment would likely introduce significant error to Raman spectroscopic methods because the high temperature may shift the laser light frequency and vibrations may disturb the optics, which would increase the noise and make signal detection more difficult. 
     The reactive components in the fluid that may be analyzed with the sensors described herein may include, but are not limited to, hydrogen sulfide, mercury, carbon dioxide, acidic chemicals (e.g., hydrochloric acid, sulfuric acid, and hydrofluoric acid), caustic chemicals (e.g., sodium hydroxide and calcium hydroxide), and the like, and combinations thereof. In some instances, reactive components like mercury may be of interest because of environmental concerns. In some instances, reactive components like hydrogen sulfide and carbon dioxide may be of interest because of corrosion concerns. The sensors described herein may be useful in estimating or otherwise determining the concentration of one or more reactive components in fluids. 
     In some instances, the sensors described herein may be sensitive to a class of chemicals like acidic chemicals or caustic chemicals rather than a specific chemical. Accordingly, the sensors may be useful in estimating or otherwise determining the concentration or strength of the class of chemicals. For example, the substrate may react with acidic chemicals and be useful in determining a pH, acidic strength, or corrosive potential of the fluid. 
     Backside Reflectance Sensors 
     In some instances, the sensors may utilize a backside reflectance technique where the light used in the spectroscopy does not travel through the fluid. This eliminates the contents of the fluid from providing interference to the measurement due to unintended alteration of the light. For sufficiently transparent fluids (in the optical region of interest) a reflectance through the fluid may be advantageous. For example, the opacity of the oil-based fluid or the light scattering effect of emulsion particles in emulsified fluids may alter the light and interfere with measurements and analyses described herein. However, the backside reflectance sensors described herein may also be used in conjunction with water-based fluids and gases. 
       FIG. 1  illustrates a configuration for a backside reflectance sensor  100  of the present disclosure. The backside reflectance sensor  100  comprises a light source  102 , a sensing component  104 , and a detector  106 . The sensing component  104  includes a substrate  108  and a reactive surface  110 . Light  112  from the light source  102  passes through the substrate  108 , impinges the reactive surface  110 , and is reflected as interacted light  114 , which is detected by the detector  106 . As illustrated, the light source  102 , the sensing component  104 , and the detector  106  are contained in a housing  116 . However, in some instances, the light source  102  and the detector  106  may be outside the housing  116  where fiber optics are used to convey the light  112  and the interacted light  114  in and out of the housing  116  and to and from the sensing component  104 . 
     In use, a fluid comprising one or more reactive components contacts the sensing component  104  where the relative components physisorb or chemisorb to the reactive surface  110 , which changes the band structure of the reactive surface  110  (i.e., the material that the reactive surface  110  is composed of). The band structure changes are then measured using the detector  106  and a concentration of the reactive components may be determined, as described further below. 
     The reactive surface  110  should have a thickness sufficiently thin to observe the change to the reactive surface  110  at the substrate  108  and sufficiently thick to be robust for the measurement location (e.g., downhole). The thickness of the reactive surface  110  may depend on the composition of the reactive surface  110 , the size or diffusion rate of the reactive component relative to the porosity of the reactive surface  110 , and the like. The reactive surface  110  may have a thickness ranging from about 10 nm to about 3 mm including subsets therebetween. For example, an opaque reactive surface  110  may have a thickness ranging from about 10 nm to about 3 microns including subsets therebetween like about 10 nm to about 50 nm, about 10 nm to about 100 nm, about 50 nm to about 500 nm, about 100 nm to about 3 microns, about 500 nm to about 3 microns, or about 1 micron to about 3 microns. For a transparent reactive surface  110  where backscattered interacted light  114  is measured, the thickness of the reactive surface  110  may range from about 10 nm to about 3 mm, including subsets therebetween. In some instances, the thickness of the reactive surface  110  may vary (tapered or stepped) across the substrate  108 , which allows for an added dynamic range of the sensor. By way of nonlimiting example, a reactive surface  110  of silver may taper across the substrate  108  from 100 nm thickness to 100 micron thickness. Then, over time when interacted with hydrogen sulfide, the hydrogen sulfide diffuses deeper into the reactive surface  110  and change the gradient of total reflectivity of the silver. Driven by the total amount of hydrogen sulfide encountered, the concentration of hydrogen sulfide may be calculated based on the fluid flow rate and signal output where a large change in signal output and low flow rate, for example, would indicate a high concentration of hydrogen sulfide. 
     The reactive surface  110  may be formed on the substrate  108  by a plurality of methods. In some instances, the reactive surface  110  may be a foil or thin film that is attached (e.g., via sintering) to the substrate  108 . In some instances, the reactive surface  110  may be sputter coated, deposited via chemical vapor deposition, deposited via ion vapor deposition, or the like onto the substrate  108 . In some embodiments, the coating may be further annealed to the substrate. 
     In some embodiments, the reactive surface  110  may be formed of particles that are deposited on the substrate  108  via liquid phase deposition. Such particles may have an average diameter of about 1 nm to about 3 microns, including subsets therebetween like about 1 nm to about 100 nm, about 1 nm to about 500 nm, about 100 nm to about 1 micron, about 500 nm to about 3 microns, about 1 micron to about 3 microns, or about 500 nm to about 1 micron. In some instances, the particles may be deposited as a monolayer or substantially a monolayer (i.e., at least 90% by area being a monolayer) on the substrate  108 . Additionally, in some instances, more than one type of particle (e.g., copper particles and molybdenum particles) may be used where each react with different reactive components or with the same reactive component at different rates. 
     Exemplary materials that the reactive surface  110  may be composed of may include, but are not limited to, gold, nickel, copper, molybdenum, aluminum, tungsten, titanium, and the like, and any combination thereof. For example, copper and molybdenum turn black when exposed to hydrogen sulfide. In another example, aluminum reacts with mercury and not hydrogen sulfide. 
     The substrate  108  may be composed of materials that include, but are not limited to, sapphire (Al 2 O 3 ), germanium, zinc selenide, calcium fluoride, manganese fluoride, fused silica, quartz, and the like. The composition of the substrate  108  should be chosen to be transparent to the wavelengths of the light  112  and interacted light  114  necessary for detecting the physisorption or chemisorption of the reactive component of interest while also being inert to the reactive component of interest. 
     The light  112  may be any suitable wavelength of electromagnetic radiation for detecting changes to the band structure of the reactive surface  110 . Exemplary lights  112  may include, but are not limited to, visible light, ultraviolet light, infrared light, and the like, and any combination thereof. Exemplary light sources  102  may include, but are not limited to, a light bulb, a light emitting diode (LED), a laser, a blackbody, a photonic crystal, an X-Ray source, and the like, and any combination thereof. 
     Exemplary detectors  106  may include, but are not limited to, a thermal detector such as a thermopile or photoacoustic detector, a semiconductor detector, a piezo-electric detector, a charge coupled device (CCD) detector, a video or array detector, a split detector, a photon detector (such as a photomultiplier tube), photodiodes, and the like, and any combination thereof. 
     In some instances, the backside reflectance sensor  100  may include more than one sensing component  104  for detecting the concentration of different reactive components. For example, a single light source  102  may be used and multiple detectors for measuring the interacted light  114  corresponding to each of the sensing components  104 . In another example, each of the more than one sensing component  104  may have a corresponding light source  102  and detector  106 . In yet another example, when the interacted light  114  for two or more sensing components  104  do not interfere, a single light source  102  and detector  106  may be used with two or more sensing components  104 . 
     In some instances, the backside reflectance sensor  100  may further comprise light filters and optical computing devices (e.g., commonly owned U.S. Pat. Nos. 6,198,531, 6,529,276, 7,123,844, 7,834,999, 7,911,605, 7,920,258, and 8,049,881) anywhere along the optical path from the light source  102  to the detector  106 . 
     In some instances, backside reflectance sensor  100  may be configured for regenerating the reactive surface  110 . For example, in some instances, increasing the temperature and decreasing the concentration of the reactive components in contact with the reactive surface  110  may desorb the reactive components physisorbed or chemisorbed to the reactive surface  110 , which would return the band structure of the reactive surface  110  closer to the original band structure. Then, the reactive surface  110  after regeneration may be exposed to the fluid with reactive components therein for additional measurements. 
     Therefore, in some instances, the backside reflectance sensor  100  may optionally further include a heating element  120  for regenerating the reactive surface  110 . In some instances, the backside reflectance sensor  100  may optionally include flow paths and valves (not illustrated) that allow for stopping flow of the fluid and starting flow of a purge fluid (e.g., water, cleaning fluids, inert gases, air, and the like) for regenerating the reactive surface  110 . In some instances, the purge fluid may include scavengers that preferentially bind to or react with the reactive components to further drive desorption from the reactive surface  110 . 
     Transmission Sensors 
     In some instances, the sensors may utilize a transmission technique where the light used in the spectroscopy travels through the fluid. This sensor may be useful in analyzing reactive components in water-based fluids or gases that are sufficiently transparent and non-scattering to interfere with the spectroscopy. 
       FIG. 2  illustrates a configuration for a transmission sensor  200  of the present disclosure. The transmission sensor  200  comprises a light source  202 , a sensing component  204 , and a detector  206 . The sensing component  204  includes a substrate  208  and a reactive surface  210 . Light  212  from the light source  202  passes through the substrate  208  and reactive surface  210  to produce interacted light  214 , which is detected by the detector  206 . As illustrated, the light source  202  and the sensing component  204  are contained in a housing  216 . However, in some instances, the light source  202  may be outside the housing  216  where fiber optics are used to convey the light  212  into the housing  216  and to the sensing component  204 . 
       FIG. 3  illustrates an alternative configuration for a transmission sensor  300  of the present disclosure. The transmission sensor  300  comprises a light source  302 , a sensing component  304 , and a detector  306 . The sensing component  304  includes a substrate  308  and a reactive surface  310 . Light  312  from the light source  302  passes through the substrate  308  and reactive surface  310  to produce interacted light  314 , which is detected by the detector  306 . As illustrated, the detector  306  and the sensing component  304  are contained in a housing  316 . However, in some instances, the detector  306  may be outside the housing  316  where fiber optics are used to convey the interacted light  314  out of the housing  316  and to the detector  306 . 
     In use, a fluid comprising one or more reactive components contacts the sensing component  204 , 304  where the relative components physisorb or chemisorb to the reactive surface  210 , 310 , which changes the band structure of the material that the reactive surface  210 , 310  is composed of. The band structure changes are then measured using the detector  206 , 306  and a concentration of the reactive components may be determined, as described further below. 
     Generally, the substrate  208 , 308 , light source  202 , 302 , and detector  206 , 306  may be the same as the substrate  108 , light source  102 , and detector  106  described relative to  FIG. 1 . The reactive surface  210 , 310 , however, should be configured for transmission spectroscopy. For example, a monolayer or less of particles may be deposited on the substrate  208 , 308  in a density that allows for the light  212 , 312  to interact with the particles to form interacted light  214 , 314  that is measured by the detector  206 , 306 . In some instances, the reactive surface  210 , 310  may comprise a matrix that is nonreactive to the reactive component and is doped with a material that changes band gap when contacted/reacted with the reactive component. For example, a permeable matrix like an open cell foam polymer may be doped with copper and/or molybdenum particles that react with hydrogen sulfide. 
     The reactive surface  210 , 310  may have a thickness ranging from about 10 nm to about 3 mm, including subsets therebetween like about 10 nm to about 100 nm, about 10 nm to about 500 nm, about 100 nm to about 1 micron, about 500 nm to about 3 microns, about 1 micron to about 3 microns, or about 500 nm to about 1 micron. 
     In some instances, the transmission sensor  200 , 300  may include more than one sensing component  204 , 304  for detecting the concentration of different reactive components. Suitable configurations may include those described relative to the backside reflectance sensor  100  with more than one sensing component  104 . 
     In some instances, transmission sensor  200 , 300  may be configured for regenerating the reactive surface  210  and optionally include a heating element  220 , 320  and flow paths and valves (not illustrated) as described relative to regenerating the reactive surface  110  in  FIG. 1 . 
     Electronic Sensors 
     In some instances, the sensors may utilize an electrical technique where the conduction or resistance of the reactive surface is used to analyze the concentration of the reactive components in the fluid. 
       FIG. 4  illustrates a configuration for an electrical sensing component  404  of the present disclosure. The sensing component  404  includes a substrate  408 , a reactive surface  410 , and electrical leads  418  contacting (e.g., illustrated as embedded in) the reactive surface  410 . In use, a fluid comprising one or more reactive components contacts the sensing component  404  where the relative components physisorb or chemisorb to the reactive surface  410 , which changes the band structure of the material that the reactive surface  410  is composed of. The band structure changes are then measured using the detector  406  connected to the electrical leads  418  and a concentration of the reactive components may be determined, as described further below. 
     Generally, the substrate  408  is an insulator that does not interfere with the electrical measurements of the reactive surface  410 , which may be the same as the substrate  108  described relative to  FIG. 1 . Further, such substrate materials may further allow for simultaneously performing spectroscopic detection methods described herein. When spectroscopic methods are not employed, the substrate  408  may be an opaque, non-conductive material like polytetrafluorethylene. 
     The reactive surface  410  may be any conductive material that changes band structures when contacted by a reactive components of interest. Exemplary materials may include, but are not limited to, copper, polyethyleneimine, and the like, and any combination thereof. For example, the reactive surface  410  may comprise polyethyleneimine that selectively absorbs carbon dioxide, which cause the band structure of polyethyleneimine and, consequently, the conductance of polyethyleneimine to change. 
     The reactive surface  410  may have a thickness ranging from about 10 nm to about 3 mm, including subsets therebetween like about 10 nm to about 100 nm, about 10 nm to about 500 nm, about 100 nm to about 1 micron, about 500 nm to about 3 microns, about 1 micron to about 3 microns, or about 500 nm to about 1 micron. 
     Exemplary detectors  406  for measuring the electrical properties of the reactive surface  410  may include, but are not limited to, a voltmeter. 
     In some instances, the sensor may include more than one sensing component  404  for detecting the concentration of different reactive components. 
     In some instances, an electrical sensor may be configured for regenerating the reactive surface  410  and optionally include a heating element, flow paths, and valves (not illustrated) as described relative to regenerating the reactive surface  110  in  FIG. 1 . 
     Combination Sensors 
     In some instances, the sensors may utilize both spectroscopic and electrical techniques to analyze the concentration of the reactive components in the fluid. 
       FIG. 5  illustrates a configuration for a combination sensor  500  of the present disclosure. The combination sensor  500  comprises a light source  502 , a sensing component  504 , a conductance detector  506   c , and either spectroscopic detector  506   a  or  506   b  based on the combination sensor using backside reflectance or transmission spectroscopic techniques, respectively. The sensing component  504  includes a substrate  508 , a reactive surface  510 , and electrical leads  518  contacting the reactive surface  510  and connected to the conductance detector  506   c . The combination sensor  500  may further including a housing (not shown) similar to one of housings  116 , 216 , 316  of  FIGS. 1-3  based on the desired spectroscopic detection mode. 
     The substrate  508  may be composed of a material as described relative to the substrate  108  of  FIG. 1 , the substrate  208  of  FIG. 2 , or the substrate  308  of  FIG. 3  to allow for the spectroscopic analysis techniques or the substrate  408  of  FIG. 4  to allow for the electrical analysis techniques. 
     The reactive surface  510  should be chosen to allow for both the spectroscopic and electrical techniques. For example, copper substrates may be useful when employing backside reflection and electrical techniques. In another example, a polyethyleneimine matrix with particles of aluminum may be useful for transmission and electrical techniques in detecting and/or monitoring carbon dioxide and mercury concentrations. 
     By way of nonlimiting example, a conductance detector  506   c  may be combined with either spectroscopic detector  506   a  or  506   b  where the conductance detector  506   c  is used as an electrochemical cell to generate reagents in situ. For example, in a brine, the electrochemical cell could generate a diffusion limited volume close to the reactive surface  510 . With a sodium chloride brine, for example, a drive voltage of 1.5 V would generate sodium hydroxide at the cathode and chlorine gas at the anode. The chloride is a strong oxidizing agent that may react with a reactive component in the fluid via halogen substitution. The resultant molecule may then react with the reactive surface  510  and be measured. Additionally, the sodium hydroxide will neutralize any residual acid causing the local environment at the cathode to be caustic, which stabilized sulfide ions and allows for reaction with the reactive surface  510  and measurement of the sulfide ion concentration. 
     By way of another nonlimiting example, some oils (used as the carrier fluid) have a fair amount of residual organic acids therein that may be quantitatively neutralized with the electrochemical cell described above. 
     Systems and Methods for Analyzing the Concentration of Reactive Components 
     The sensors described herein (e.g., those described relative to  FIGS. 1-5  and variations thereof) rely on equilibrium laws to calculate a concentration of reactive components in the fluid. The sensors described herein may measure an absolute value and/or a rate of change for the spectroscopic and/or electrical measurements of the reactive surface. 
     When using the absolute value, the reactive components and reactive surface may be allowed to come to a chemical equilibrium where there is substantially no net change (less than 5% net change per minute) in the concentration of species involved in the chemical reaction. The chemical equilibrium will be reflected in a stabilization of the sensor response. As used herein, “stabilization” does not necessarily mean that no spectroscopic or electrical change is occurring but is inclusive of small changes that indicate chemical equilibrium is being approached. In some instances, a spectroscopic or electrical change of less than 20% (preferably less than 5%) per measurement cycle (e.g., a 1 millisecond measurement cycle to a 10 minute measurement cycle) may indicate stabilization of the sensor response and, consequently, an approach to chemical equilibrium. Specific sensor configurations, reactive surfaces, and reactive components may have higher or lower tolerances for sufficient equilibrium. This tolerance for stabilization of the sensor may be guided by the accuracy of the desired measurement. Measurement cycles are typically from milliseconds (for example for pressure sensing) to tens of minutes (for example for mobility measurements) for wireline testers, but may be on the order of days to weeks for pipeline monitoring. Each application will have its own defined useful measurement cycle. The absolute value at equilibrium may be compared to a known correlation between concentration of the reactive components and the spectroscopic and/or electrical measurements, which may be in the form of a table, graph, equation, or the like. The known correlation between concentration of the reactive components and the spectroscopic and/or electrical measurements may be determined experimentally or modeled mathematically. 
     The correlation between concentration of the reactive components and the spectroscopic and/or electrical measurement may be temperature dependent. Accordingly, the temperature at or near the sensor may be measured or estimated. In some instances, the sensor (e.g., those described relative to  FIGS. 1-5 ) may optionally further include a temperature sensor and or pressure sensor. 
     Further, the correlation between concentration of the reactive components and the spectroscopic and/or electrical measurement may be dependent on flow rate of the fluid across the reactive surface. For example, at higher flow rates, the reactive components have less time to interact with the reactive surface. Therefore, the absolute change of the spectroscopic and/or electrical measurements at equilibrium may be lower than for a slower flow rate. Therefore, the correlation between concentration of the reactive components and the spectroscopic and/or electrical change may account for flow rate (e.g., by including a flow rate proportionality factor). 
     Performing the analysis using the absolute value of the spectroscopic and/or electrical measurement at equilibrium may require a significant wait time (e.g., several hours) to allow the reactive components and reactive surfaces to come to equilibrium. Accordingly, the rate of change of the spectroscopic and/or electrical measurements as the reactive components and reactive surfaces to come to equilibrium may be used to determine or estimate the concentration of the reactive components in the fluid. 
     When using a rate of change of the spectroscopic and/or electrical measurements, the rate of change may be compared to an equilibrium constant of the reaction between the reactive components and the reactive surfaces, which again may be temperature and/or flow rate dependent. Similar to the absolute measurements, a correlation between concentration of the reactive components and the rate of change of the spectroscopic and/or electrical measurements may be determined experimentally or modelled mathematically and used to determine the concentration of the reactive components in the fluid. 
     In some embodiments, the sensors described herein (e.g., those described relative to  FIGS. 1-5  and variations thereof) may be coupled to control system (e.g., a processor), which may optionally be part of the sensor itself. The control system, described further below, may include the absolute and/or rate of change correlations described herein between the concentration of the reactive components and the spectroscopic and/or electrical measurements and provide an estimated concentration of the reactive components in the fluid. 
     In some instances, based on the concentration of the reactive components, an action in the present wellbore operation or a subsequent operation may be taken. For example, if a zone within a formation is determined to have a high concentration of a reactive component like hydrogen sulfide, mercury, or carbon dioxide, that zone may be isolated to mitigate production of hydrocarbon fluids with such reactive components. In another example, during drilling or stimulation, it may be determined that the fluids in the formation have a high concentration of a corrosive reactive component like hydrogen sulfide or carbon dioxide. Then, the tools used in the production operation may be composed of materials that are less susceptible to corrosion. In yet another example, sensors may be included on tools in use to monitor a cumulative amount of reactive components encountered. Then, when a threshold amount of the reactive component exposure is reached for the tool or a component thereof is reached, the tool or component thereof may be replaced, which may mitigate failure of the tool. In another example, the parameters of hydrocarbon production operations may be optimized. In yet another example, during exploration operations, the economics of a potential well may be evaluated where the presence of reactive components are taken into account, for example, by including the cost of corrosion-resistant tools and additional operations needed to properly treat or avoid reactive components. In another example, during sampling operations, the sensors described herein may be utilized to provide guidance as to how much sample to retrieve and from what depth along the wellbore to retrieve the sample. 
     Depending on where the sensors described herein are installed, the sensors may potentially be exposed to many different types of fluids over several wellbore operations. For example, sensors installed on casings or pipes may encounter oil-based muds, caustic cleaning fluids, acidic formation fluids, and hydrocarbon formation fluids. Since, as described herein, some sensors of the present disclosure are designed for specific environments (e.g., transmission techniques cannot be used with all fluids), more than one sensor may be installed. In some instances, each sensor may be associated with a flow path that opens and closes based on the fluid composition so as to mitigate wear of the sensor. 
       FIG. 6  illustrates a multi-sensor configuration  600  according to at least some embodiments of the present disclosure. The illustrated multi-sensor configuration  600  includes three sensors  602 , 604 , 606  in parallel. The multi-sensor configuration  600  includes a series of flow paths with a primary flow path  608  that separates into three secondary flow paths  610 , 612 , 614  for each of the sensors  602 , 604 , 606 , respectively. Each of the secondary flow paths  610 , 612 , 614  includes a valve  616 , 618 , 620  for allowing or stopping fluid flow to the respective sensors  602 , 604 , 606 . The valves  616 , 618 , 620  are communicably coupled to a control system  622  that opens and closes each valve  616 , 618 , 620  to provide for fluid flow to the corresponding sensors  602 , 604 , 606 . Control of which valves  616 , 618 , 620  are open and closed via the control system  622  may be done manually operated (i.e., via operator control), automatically operated (i.e., via computer control), or both. Decisions to open and close valves  602 , 604 , 606  may depend on the method of sensing the sensor is configured for, the reactive components the sensor is configured for, the composition of the fluid, the wellbore operation being undertaken, and the like. 
     In some embodiments, each of the sensors  602 , 604 , 606  may be configured for analyzing more than one reactive component (e.g., as described relative to  FIGS. 1-4 ). 
     In some instances, the three sensors  602 , 604 , 606  may be operate by different sensing techniques. For example, a backside reflectance sensor  602 , a transmission sensor  604 , and an electrical sensor  606  may be used. Then, operation of the valves may be based on the composition of the fluid passing therethrough to appropriately match the sensing technique. 
     In some instances, the three sensors  602 , 604 , 606  may be a single type of sensor (e.g., backside reflectance, transmission, electrical, or combination). For example, if a specific reactive component is of interest, the first sensor  602  may be used until equilibrium is reached, then, the second sensor  604  may be used, and so on. 
     In some instances, each of the secondary flow paths  610 , 612 , 614  may lead to one or more sensors in series each for measuring one or more reactive components of interest. Further, while only three sensors are illustrated, in alternative embodiments, any number of sensors (e.g., two to fifty) may be included where the flow path configuration allows for any desired configuration of sensors to be in series, parallel, and combinations thereof. 
     In some instances, the multi-sensor configuration  600  may optionally further include flow paths and valves (not illustrated) for regenerating the sensors  602 , 604 , 606  (e.g., as described in  FIG. 1 ). 
     In some instances, flow of the fluid to a sensor or sensor array may be facilitated by a pump fluidly coupled to the sensor. In some instances, fluid flow may rely on other mechanisms like pressure differentials resulting from temperature differences across the flow path through the sensor. 
     In some embodiments, the sensors described herein (e.g., those described relative to  FIGS. 1-5  and variations thereof) may be coupled individual or as multi-sensor configurations to a variety of downhole tools and components. The sensors may be applicable to water monitoring for industrial use and disposal, for urban use and disposal, and for agricultural use and disposal. The sensors may also be applicable for pollution monitoring, industrial waste disposal, pipeline monitoring, monitoring of cargo undergoing shipping, refinery operations, petrochemical operations, and pharmaceutical operations. 
       FIG. 7  is a wellbore drilling system  700  in accordance with at least some of the embodiments of the present disclosure. It should be noted that while  FIG. 7  generally depicts a land-based drilling assembly, those skilled in the art will readily recognize that the principles described herein are equally applicable to subsea drilling operations that employ off-shore floating or sea-based platforms and rigs, without departing from the scope of the disclosure. 
     As illustrated, the drilling assembly  700  may include a drilling platform  702  that supports a derrick  704  having a traveling block  706  for raising and lowering a drill string  708 . The drill string  708  may include, but is not limited to, drill pipe and coiled tubing, as generally known to those skilled in the art. A kelly  710  supports the drill string  708  as it is lowered through a rotary table  712 . A drill bit  714  is attached to the distal end of the drill string  708  and is driven either by a downhole motor and/or via rotation of the drill string  708  from the well surface. As the bit  714  rotates, it creates a borehole  716  that penetrates various subterranean formations  718 . 
     In the illustrated example, the borehole  716  includes two sections: a cased section  716   a  and an uncased section  716   b . The cased section  716   a  includes a casing  736  lining the wellbore  716  with a cement sheath  738  disposed therebetween. 
     A pump  720  (e.g., a mud pump) circulates drilling fluid  722  through a feed pipe  724  and to the kelly  710 , which conveys the drilling fluid  722  downhole through the interior of the drill string  708  and through one or more orifices in the drill bit  714 . The drilling fluid  722  is then circulated back to the surface via an annulus  726  defined between the drill string  708  and the walls of the borehole  716 . At the surface, the recirculated or spent drilling fluid  722  exits the annulus  726  and may be conveyed to various surface treatment systems (e.g., fluid processing units, retention pits, mixers, and the like). As illustrated, the spent drilling fluid  722  is conveyed to a fluid processing unit  728  via an interconnecting flow line  730 . Generally, the fluid processing unit  728  cleans the drilling fluid, for example, by removing drill cuttings the drilling fluid brought to the surface. The fluid processing unit  728  may include one or more of: a shaker (e.g., shale shaker), a centrifuge, a hydrocyclone, a separator (including magnetic and electrical separators), a desilter, a desander, a separator, a filter (e.g., diatomaceous earth filters), a heat exchanger, any fluid reclamation equipment, and the like, and any combination thereof. The fluid processing unit  728  may further include one or more sensors, gauges, pumps, compressors, and the like. 
     After passing through the fluid processing unit  728 , a “cleaned” drilling fluid  722  is deposited into a nearby retention pit  732  (i.e., a mud pit). While illustrated as being arranged at the outlet of the wellbore  716  via the annulus  726 , those skilled in the art will readily appreciate that the fluid processing unit  728  and retention pit  732  may be arranged at any other location in the drilling assembly  700  to facilitate its proper function, without departing from the scope of the disclosure. 
     Components of the drilling fluid  722  (e.g., weighting agents and fluid loss control additives) may be added to the drilling fluid  722  via a mixing hopper  734  communicably coupled to or otherwise in fluid communication with the retention pit  732 . The mixing hopper  734  may include, but is not limited to, mixers and related mixing equipment known to those skilled in the art. In other embodiments, however, the drilling fluid components may be added to the drilling fluid  722  at any other location in the drilling assembly  700 . In at least one embodiment, for example, there could be more than one retention pit  732 , such as multiple retention pits  732  in series. Moreover, the retention pit  732  may be representative of one or more fluid storage facilities and/or units where the drilling fluid components may be stored, reconditioned, and/or regulated until added to the drilling fluid  722 . 
     While not illustrated, the drilling assembly  700  may further include additional downhole equipment and tools that such as, but not limited to, floats, drill collars, mud motors, downhole motors and/or pumps associated with the drill string  708 , and any measurement-while-drilling or logging-while-drilling (MWD/LWD) tools and related telemetry equipment, and sensors or distributed sensors associated with the drill string  708 . 
     The drilling system  700  also includes a sensor or multi-sensor array  740  of the present disclosure coupled to the casing  736  in the cased section  716   a  of the wellbore  716 . The sensor or multi-sensor array  740  is communicably coupled to a control system  742 . Optionally, the sensor or multi-sensor array  740  may be fluidly coupled to a pump for facilitating fluid flow therethrough. 
     The control systems  742 , control systems that may optionally be an integral portion of the sensor or multi-sensor array  740 , and corresponding computer hardware used to implement the various illustrative blocks, modules, elements, components, methods, and algorithms described herein can include a processor configured to execute one or more sequences of instructions, programming stances, or code stored on a non-transitory, computer-readable medium. The processor can be, for example, a general purpose microprocessor, a microcontroller, a digital signal processor, an application specific integrated circuit, a field programmable gate array, a programmable logic device, a controller, a state machine, a gated logic, discrete hardware components, an artificial neural network, or any like suitable entity that can perform calculations or other manipulations of data. In some embodiments, computer hardware can further include elements such as, for example, a memory (e.g., random access memory (RAM), flash memory, read only memory (ROM), programmable read only memory (PROM), erasable programmable read only memory (EPROM)), registers, hard disks, removable disks, CD-ROMS, DVDs, or any other like suitable storage device or medium. 
     Executable sequences described herein can be implemented with one or more sequences of code contained in a memory. In some embodiments, such code can be read into the memory from another machine-readable medium. Execution of the sequences of instructions contained in the memory can cause a processor to perform the process steps described herein. One or more processors in a multi-processing arrangement can also be employed to execute instruction sequences in the memory. In addition, hard-wired circuitry can be used in place of or in combination with software instructions to implement various embodiments described herein. Thus, the present embodiments are not limited to any specific combination of hardware and/or software. 
     As used herein, a machine-readable medium will refer to any medium that directly or indirectly provides instructions to a processor for execution. A machine-readable medium can take on many forms including, for example, non-volatile media, volatile media, and transmission media. Non-volatile media can include, for example, optical and magnetic disks. Volatile media can include, for example, dynamic memory. Transmission media can include, for example, coaxial cables, wire, fiber optics, and wires that form a bus. Common forms of machine-readable media can include, for example, floppy disks, flexible disks, hard disks, magnetic tapes, other like magnetic media, CD-ROMs, DVDs, other like optical media, punch cards, paper tapes and like physical media with patterned holes, RAM, ROM, PROM, EPROM, and flash EPROM. 
     For example, the control system  742  described herein may be configured for receiving inputs from the sensor or multi-sensor array  740 . The processor may also be configured to perform or reference mathematical calculations, lookup tables, and offset well data comparisons that are stored on the processor to derive the concentration of one or more reactive components in the fluid in contact with the sensor or multi-sensor array  740 . In some instances, the processor may output a numerical value, graph, or the like indicative of the concentration, the concentration change over time, or the like. In some instances, the processor may change or suggest a change to the drilling fluid composition (e.g., adding additional scavengers to mitigate corrosion), the drilling operation parameters (e.g., using drill string  708  pipes that are more resistance to corrosion from the reactive components), or both based on the derived concentration of one or more reactive components in the fluid in contact with the sensor or multi-sensor array  740 . 
     In some instances, the drilling assembly  700  may further comprise other sensors (not illustrated) that are communicably coupled to the control system  738 . These sensors may provide real-time measurements of the temperature and flow rate of the fluid. These real-time measurements may optionally be used when deriving the concentration of one or more reactive components in the fluid in contact with the sensor or multi-sensor array  740  and/or when the processor makes a change or suggests a change to the drilling fluid composition, the drilling operation parameters, or both. 
     By having the sensor or multi-sensor array  740  coupled to the casing  736 , the sensor or multi-sensor array  740  may optionally be used to analyze the concentration of reactive components in the fluids associated with subsequent wellbore operations. Exemplary operations may include, but are not limited to wireline logging operations, MWD/LWD operations, hydraulic fracturing operations, acidizing operations, production operations, and the like. 
     Additionally, one or more sensors and/or multi-sensor arrays may be coupled to other components of drilling systems or systems used for other operations, for example, MWD/LWD tools, wireline tools, the drill string, other tubulars like production tubing or coiled tubing, sliding sleeves, perforation guns, screens, frac plugs, packers, and the like. For example, one or more sensors and/or multi-sensor arrays may be located in a side pocket mandrel of a tubular. 
     For example, at various times during or after the drilling process, including after stimulation operations, the drill string  708  or other apparatus extending into the wellbore (e.g., a work string for perforating the formation) may be removed from the wellbore  812 , as shown in  FIG. 8 , to conduct measurement/logging operations. More particularly,  FIG. 8  depicts a schematic diagram of an exemplary wireline system  800  that may employ the principles of the present disclosure, according to one or more embodiments. Like numerals used in  FIGS. 7 and 8  refer to the same components or elements and, therefore, may not be described again in detail. As illustrated, the wireline system  800  may include one or more wireline tools  802  that may be suspended in the wellbore  812  (illustrated as an open hole wellbore without a casing) by a cable  804 . The wireline tools  802  may include one or more sensors and/or multi-sensor arrays  810  where the wireline tools  802  and the sensors/arrays  810  are communicably coupled to the cable  804 . The cable  804  may include conductors for transporting power to the wireline tools  802  and the sensors/arrays  810  and also facilitate communication between the surface and the wireline tools  802  and the sensors/arrays  810 . A logging facility  806 , shown in  FIG. 8  as a truck, may collect measurements from the wireline tools  802 , and may include computing facilities  808  for controlling, processing, storing, and/or visualizing the measurements gathered by the wireline tools  802 . The computing facilities  808  may be communicably coupled to the wireline tools  802  by way of the cable  804 . In some instances, the computing facilities  808  may include a control system similar to the control system  742  described above. 
     Optionally, the sensors/arrays  810  may be fluidly coupled to a pump for facilitating fluid flow therethrough. For example, the wireline tools  802  may include the pump, and the computing facilities  808  may transmit instructions to the pump when to flow fluid and to the sensor when to collect data. 
     In each of the foregoing drilling and wireline systems, the methods and processes described herein (or portions thereof) that utilize the sensors and sensor arrays of the present disclosure to measure a concentration of the reactive component may be implemented on-site (e.g., at a computer or processor on-site like the computing facilities  808  illustrated in the wireline system of  FIG. 8  or a similar computing facility at the drilling system of  FIG. 7 ). Alternatively or in conjunction therewith, the methods and processes described herein (or portions thereof) that utilize the sensors and sensor arrays of the present disclosure to measure a concentration of the reactive component may be performed off-site where the data from the sensors or sensor arrays are transmitted (wired or wirelessly) or physically delivered to the off-site location. 
     While the sensors and/or multi-sensor arrays may be useful in sensing reactive components in fluids downhole, the sensors and/or multi-sensor arrays may also be implemented in surface locations like at the pump, the retention pit, the fluid processing unit, and the like. 
     In some instances, the sensors or sensor arrays of the present disclosure may be implemented. 
     Embodiments of the present disclosure include, but are not limited to, Embodiment A, Embodiment B, Embodiment C, and Embodiment D. 
     Embodiment A is a method that comprises contacting a sensing component of a sensor with a fluid comprising a reactive component, the sensing component comprising a reactive surface on a substrate; physisorbing, chemisorbing, or both the reactive component to the reactive surface thereby causing a change to a band gap of the reactive surface; measuring one selected form the group consisting of the change to the band gap of the reactive surface, a rate of the change to the band gap of the reactive surface, and a combination thereof; and deriving a concentration of the reactive component in the based on the one selected form the group consisting of the change to the band gap of the reactive surface, the rate of the change to the band gap of the reactive surface, and the combination thereof. Optionally, Embodiment A may further include one or more of the following: Element 1: wherein the sensor further comprises a light source and a detector, and wherein the method further comprises: transmitting light from the light source through the substrate to the reactive surface to produce reflected interacted light that is indicative of the band gap of the reactive surface; and measuring the reflected interacted light with the detector; Element 2: wherein the sensor further comprises a light source and a detector, and wherein the method further comprises: transmitting light from the light source through the substrate and reactive surface to produce transmitted interacted light that is indicative of the band gap of the reactive surface; and measuring the transmitted interacted light with the detector; Element 3: wherein the sensor further comprises a electrical leads contacting the reactive surface and a detector communicably coupled to the electrical leads, and wherein the method further comprises: measuring a conductance of the reactive surface that is indicative of the band gap of the reactive surface; Element 4: wherein the sensor is one of a plurality of sensors (e.g., a portion of a sensor array) where the plurality of sensors include at least one selected from the group consisting of Element 1, Element 2, Element 3, two or more of Elements 1-3 in combination to form a combination sensor, and any combination thereof; Element 5: the method further comprising regenerating the reactive surface; and repeating the method to derive a second concentration of the reactive component; Element 6: wherein the sensor is coupled to a wellbore tool within a wellbore penetrating a subterranean formation, and wherein the method further comprises: performing a wellbore operation; and changing a parameter of the wellbore operation based on the concentration of the reactive component; Element 7: wherein the sensor is coupled to a wellbore tool within a wellbore penetrating a subterranean formation, and wherein the method further comprises: calculating a cumulative amount of the reactive species based on the concentration of the reactive component over time; and replacing the wellbore tool when the cumulative amount reaches a threshold; Element 8: wherein the sensor is fluidly coupled to a pump configured to flow a fluid through the sensor for analysis; Element 9: wherein the reactive surface comprises one selected from the group consisting of gold, nickel, copper, molybdenum, aluminum, tungsten, titanium, and any combination thereof; Element 10: wherein a thickness of the reactive surface varies across the substrate; Element 11: wherein the reactive surface comprises a matrix that is nonreactive to the reactive component and is doped with particles that are reactive to the reactive component; and Element 12: wherein the reactive surface comprises particles substantially in a monolayer on the substrate. Exemplary combinations of elements may include, but are not limited to, one of Elements 1-4 in combination with one or more of Elements 5-8; one of Elements 1-4 in combination with one or more of Elements 9-12; one or more of Elements 5-8 in combination with one or more of Elements 9-12; two or more of Elements 5-8 in combination; and two or more of Elements 9-12 in combination. 
     Embodiment B is a system that comprises a wellbore tool suspended in a wellbore penetrating a subterranean formation by a cable; a sensor coupled to the wireline tool; and wherein the sensor is one selected from the group consisting of: (A) a backside reflectance sensor comprising a first light source, a first detector, and a first sensing component that itself comprises a first reactive surface on a first substrate, wherein the backside reflectance sensor is configured such that first light from the first light source passes through the first substrate to the first reactive surface to produce reflected interacted light that is indicative of a band gap of the first reactive surface and is detected by the first detector; (B) a transmission sensor comprising a second light source, a second detector, and a second sensing component that itself comprises a second reactive surface on a second substrate, wherein the transmission sensor is configured such that second light from the second light source passes through the second substrate and the second reactive surface to produce transmitted interacted light that is indicative of a band gap of the second reactive surface and is detected by the second detector; (C) an electrical sensor comprising a third detector, electrical leads, and a third sensing component that itself comprises a third reactive surface on a third substrate, wherein the electrical leads are in contact with the reactive surface and are communicably coupled to the third detector, and wherein the electrical sensor is configured such that the third detector measures a conductance of the reactive surface that is indicative of a band gap of the third reactive surface; and (D) any combination of (A), (B), and (C) as a combination sensor. Optionally, Embodiment B may further include one or more of the following: Element 8; Element 9; Element 10; Element 11; Element 12; Element 13: wherein the sensor is a component of a sensor array; and Element 14: wherein the sensor is a component of a sensor array, the sensor is a first sensor and the sensor array comprises a second sensor selected from the group consisting of (A), (B), (C), and (D). Exemplary combinations of elements may include, but are not limited to, Elements 8, 13, and 14 (alone or in any combination) in combination with one or more of Elements 9-12; two or more of Elements 9-12 in combination; and two or more of Elements 8, 13, and 14 in combination. 
     Embodiment C is a system that comprises a tubular extending into a wellbore penetrating a subterranean formation; a sensor coupled to one selected from the group consisting of: the tubular, a wellbore tool disposed in the wellbore, and a combination thereof; and wherein the sensor is one selected from the group consisting of: (A) a backside reflectance sensor comprising a first light source, a first detector, and a first sensing component that itself comprises a first reactive surface on a first substrate, wherein the backside reflectance sensor is configured such that first light from the first light source passes through the first substrate to the first reactive surface to produce reflected interacted light that is indicative of a band gap of the first reactive surface and is detected by the first detector; (B) a transmission sensor comprising a second light source, a second detector, and a second sensing component that itself comprises a second reactive surface on a second substrate, wherein the transmission sensor is configured such that second light from the second light source passes through the second substrate and the second reactive surface to produce transmitted interacted light that is indicative of a band gap of the second reactive surface and is detected by the second detector; (C) an electrical sensor comprising a third detector, electrical leads, and a third sensing component that itself comprises a third reactive surface on a third substrate, wherein the electrical leads are in contact with the reactive surface and are communicably coupled to the third detector, and wherein the electrical sensor is configured such that the third detector measures a conductance of the reactive surface that is indicative of a band gap of the third reactive surface; and (D) any combination of (A), (B), and (C) as a combination sensor. Optionally, Embodiment B may further include one or more of the following: Element 8; Element 9; Element 10; Element 11; Element 12; Element 13; Element 14; Element 15: wherein the wellbore tool is a casing lining the wellbore and the sensor is coupled to the casing; and Element 16: wherein the tubular includes a fluid entrance and the sensor is located at the fluid entrance. Exemplary combinations of elements may include, but are not limited to, Elements 8, 13, 14, 15, and 16 (alone or in any combination) in combination with one or more of Elements 9-12; two or more of Elements 9-12 in combination; and two or more of Elements 8, 13, 14, 15, and 16 in combination. 
     Unless otherwise indicated, all numbers expressing quantities of ingredients, properties such as molecular weight, reaction conditions, and so forth used in the present specification and associated claims are to be understood as being modified in all instances by the term “about.” Accordingly, unless indicated to the contrary, the numerical parameters set forth in the following specification and attached claims are approximations that may vary depending upon the desired properties sought to be obtained by the embodiments of the present invention. At the very least, and not as an attempt to limit the application of the doctrine of equivalents to the scope of the claim, each numerical parameter should at least be construed in light of the number of reported significant digits and by applying ordinary rounding techniques. 
     One or more illustrative embodiments incorporating the invention embodiments disclosed herein are presented herein. Not all features of a physical implementation are described or shown in this application for the sake of clarity. It is understood that in the development of a physical embodiment incorporating the embodiments of the present invention, numerous implementation-specific decisions must be made to achieve the developer&#39;s goals, such as compliance with system-related, business-related, government-related and other constraints, which vary by implementation and from time to time. While a developer&#39;s efforts might be time-consuming, such efforts would be, nevertheless, a routine undertaking for those of ordinary skill in the art and having benefit of this disclosure. 
     While compositions and methods are described herein in terms of “comprising” various components or steps, the compositions and methods can also “consist essentially of” or “consist of” the various components and steps. 
     Therefore, the present invention is well adapted to attain the ends and advantages mentioned as well as those that are inherent therein. The particular embodiments disclosed above are illustrative only, as the present invention may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Furthermore, no limitations are intended to the details of construction or design herein shown, other than as described in the claims below. It is therefore evident that the particular illustrative embodiments disclosed above may be altered, combined, or modified and all such variations are considered within the scope and spirit of the present invention. The invention illustratively disclosed herein suitably may be practiced in the absence of any element that is not specifically disclosed herein and/or any optional element disclosed herein. While compositions and methods are described in terms of “comprising,” “containing,” or “including” various components or steps, the compositions and methods can also “consist essentially of” or “consist of” the various components and steps. All numbers and ranges disclosed above may vary by some amount. Whenever a numerical range with a lower limit and an upper limit is disclosed, any number and any included range falling within the range is specifically disclosed. In particular, every range of values (of the form, “from about a to about b,” or, equivalently, “from approximately a to b,” or, equivalently, “from approximately a-b”) disclosed herein is to be understood to set forth every number and range encompassed within the broader range of values. Also, the terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee. Moreover, the indefinite articles “a” or “an,” as used in the claims, are defined herein to mean one or more than one of the element that it introduces.