Thermal Cracking of Condensates to Produce Olefins and Diesel

Embodiments of the present disclosure generally relate to processes and systems for the separation, steam cracking, and hydro-processing of condensate to produce olefins, diesel, pyrolysis oil, and VLSFO.

The processing of condensate feedstock to produce diesel currently involves the use of a crude distillation column (CDU) where condensate is fractionated on many trays. The CDU requires a high capital investment due to its many trays and operationally requires the heating of a reboiler and the cooling of a reflux drum, and thus poses significant energy demands. Additionally, the processing of condensate feedstock to produce diesel may also require the operation of steam cracking reactors which consume high quantities of fuel to operate.

This disclosure presents, in accordance with one or more embodiments, processes and systems for processing a condensate feedstock to produce one or more products.

The process includes contacting a condensate feedstock with steam to volatilize a portion of the hydrocarbons; recovering a vapor phase comprising volatilized hydrocarbons with a boiling point of less than 300° C. and a liquid phase comprising unvaporized hydrocarbons with a boiling point of greater than 300° C. in a volatilization device; fractionating the liquid phase in a vacuum distillation column into one or more distillate fractions comprising a light VGO fraction, a heavy VGO fraction, and a vacuum residue fraction; hydroprocessing the light VGO fraction and the heavy VGO fraction in a hydroprocessing system to produce a hydroprocessed light VGO fraction, a hydroprocessed heavy VGO fraction, and a diesel fraction; collecting the vacuum residue of the vacuum distillation column; and feeding the hydroprocessed light VGO fraction, the hydroprocessed heavy VGO fraction, and the vapor phase to a steam cracking reactor to convert at least a portion of the hydrocarbons therein to a steam cracker effluent comprising one or more olefins and a pyrolysis oil stream.

The system includes a volatilization device comprising a steam inlet, a hydrocarbon inlet, a vapor phase outlet and a liquid phase outlet, the volatilization device separating a condensate feedstock into a vapor phase and a liquid phase; a vacuum distillation column for separating the liquid phase into one or more distillate fractions comprising a light VGO fraction with boiling point in the range of 300 to 370° C., a heavy VGO fraction with a boiling point in the range of 370 to 500° C., and a vacuum residue with a boiling point greater than 500° C.; a hydroprocessing system configured to hydroprocess the light VGO fraction producing a hydroprocessed light VGO fraction and hydroprocess the heavy VGO fraction producing a hydroprocessed heavy VGO fraction and a diesel fraction; and a steam cracking reactor for converting the hydrocarbons in the vapor phase, the hydroprocessed light VGO fraction, and the hydroprocessed heavy VGO fraction to form a steam cracker effluent comprising one or more olefins and a pyrolysis oil stream.

Other aspects and advantages will be apparent from the following description and the appended claims.

There is a commercial need to maximize EURO-V diesel production and minimize very low sulfur fuel oil (VLSFO) production from the heavy fraction of condensate with reduced financial investment and increased energy efficiency.

In one or more embodiments disclosed are processes and systems for processing a condensate feedstock in a separator including a heavy oil processing scheme (HOPS) tower, steam cracking the vapor phase in a steam cracking reactor, separating the liquid phase in a vacuum distillation tower, hydroprocessing a heavy vacuum gas oil and a light vacuum gas oil fraction, and producing diesel as a desired product. In one or more embodiments, disclosed are systems and processes of producing diesel from condensate with higher energy efficiency, reduced COemissions, and reduced capital investment.

In one or more embodiments, the condensate feedstock may have an API between 40 and 75. Thus, the condensate feedstock may include between 30 wt % and 40 wt %, 40 wt % and 50 wt %, 50 wt % and 60 wt %, 60 wt % and 70 wt %, 70 wt % and 80 wt %, 80 wt % and 90 wt %, and 90 wt % and 99 wt % of hydrocarbons with a boiling point of less than 300° C. In one or more embodiments, the condensate feedstock may include between 1 wt % and 10 wt %, 10 wt % and 20 wt %, 20 wt % and 30 wt %, 30 wt % and 40 wt %, 40 wt % and 50 wt %, 50 wt % and 60 wt %, 60 wt % and 70 wt % of hydrocarbons with a boiling point of more than 300° C.

In one or more embodiments, the condensate feedstock may include between 1 wt % and 5 wt %, 5 wt % and 10 wt %, 10 wt % and 15 wt %, and 15 wt % and 20 wt % of hydrocarbons with a boiling point of greater than 500° C. Boiling point as defined herein may include one measured using ASTM D86 or ASTM D2887, or it may be a True Boiling Point (TBP) analysis according to ASTM D2892.

The process may include recovering a first stream containing hydrocarbons in a vapor phase and steam from a second stream containing hydrocarbons in a liquid phase, and steam cracking hydrocarbons in the vapor phase in a steam cracking reactor.

In one or more embodiments disclosed is a process for processing all or a portion of a condensate feedstock to produce one or more products including olefins, diesel, pyrolysis oil, and VLSFO. Pyrolysis oil as defined herein may include one or more pyrolysis gasoline, pyrolysis gasoil, and pyrolysis fuel oil. The pyrolysis gasoline may contain any species of pentanes, hexanes, heptanes, octanes, and nonanes of any species with a boiling point of 205° C. The process may include contacting a condensate feedstock with steam to volatilize a portion of the hydrocarbons therein. In one or more embodiments, the condensate feedstock may be preheated to a temperature below its bubble point temperature prior to the contacting step, through direct addition of steam, an electric heater, a super high pressure (SHP) steam heat exchanger, a high pressure (HP) steam heat exchanger, or the flue gas of the convection section of a steam cracking reactor.

In some embodiments, the contacting of steam and condensate feedstock may include mixing the steam and the condensate feedstock in co-current flow, and recovering may include separating the vapor phase from liquid phase in a cyclonic separator, instead of a HOPS tower. In other embodiments, the steam and the condensate may be contacted counter-currently. In some embodiments, the process may include controlling a steam temperature and steam feed rate sufficient to volatilize 5 to 90 wt % of hydrocarbons in the condensate feedstock. In other embodiments, the process may include controlling a steam temperature and steam feed rate sufficient to volatilize 10 to 30 wt % of hydrocarbons in the condensate feedstock.

In some embodiments, after steam and the condensate feedstock have been contacted, volatilization may occur within a volatilization device, such as separation device including a heavy oil processing system (HOPS) tower. In one or more embodiments, the steam may be injected into condensate feedstock of the HOPS tower directly. Alternatively, the steam may be injected directly into the HOPS tower. The embodiments disclosed include recovering a vapor phase containing volatilized hydrocarbons and steam from a liquid phase containing unvaporized hydrocarbons and water from the HOPS tower. The liquid phase may include hydrocarbons with a boiling point of approximately greater than 300° C., or 300° C.+ cut hydrocarbons. The vapor phase may include hydrocarbons with a boiling point of approximately less than 300° C., or 300° C.− cut hydrocarbons. Relative to higher temperature cut points, the 300° C.− cut may provide for higher hydrogen content, higher paraffins content, and lower coke precursor content, and better selectivity to olefins production in a steam cracking reactor. The liquid phase, which includes the 300° C.+ cut hydrocarbons is sent downstream for vacuum distillation.

In some embodiments, olefins plant recycle streams including butanes, pentanes, hexanes, heptanes, and octanes and cyclic paraffins and olefinic species of butanes, pentanes, hexanes, heptanes, and octanes may be optionally recycled in a recycle line into the condensate feedstock of the volatilization device. In one or more embodiments, olefins plant recycle streams including butanes, pentanes, hexanes, heptanes, and octanes and corresponding cyclic paraffins and olefinic species of butanes, pentanes, hexanes, heptanes, and octanes may optionally be fed to one or more vaporizers and then successively to the overhead of the volatilization device which includes the uncracked vapor phase. These recycle streams may also include products from the steam cracking.

In some embodiments, separation of the condensate feedstock into the desired fractions may be performed using one or more separators including but not limited to distillation columns and flash drums. In some embodiments, separation of the condensate feedstock may be performed in an integrated separation device (ISD), such as disclosed in US20130197283, which is incorporated herein by reference. In the ISD, an initial separation of a low boiling fraction is performed in the ISD based on a combination of centrifugal and cyclonic effects to separate the desired vapor fraction from liquid. An additional separation step may then be used to separate a middle boiling fraction from high boiling components. In one or more embodiments, steam may be injected into condensate feedstock of the ISD directly. In some embodiments, the steam may be injected directly into the ISD.

Contact of the steam and condensate feedstock according to embodiments herein may minimize or eliminate volatilization of any residues, coke precursors, and/or entrainment of coke precursors. For example, for a given cut point temperature, embodiments herein may efficiently volatilize predominantly hydrocarbons having a normal boiling point equal to or less than the intended cut point temperature. For example, the hydrocarbon “cut” may be relatively clean, meaning the vaporized fraction may not have any substantial amount (>10 wt % as used herein) of compounds boiling above the intended boiling temperature target. For example, a 300° C.− cut may not have any substantial amount of hydrocarbon compounds boiling above 300° C. (i.e., >10 wt %). In other embodiments, the intended target “cut” temperatures may be a 95% boiling point temperature, or in other embodiments as an 85% boiling point temperature, such as may be measured using ASTM D86 or ASTM D2887, or a True Boiling Point (TBP) analysis according to ASTM D2892, for example. In such embodiments, there may be up to 5 wt %, up to 15 wt %, or up to 25 wt % of compounds above the indicated “cut” point temperature.

In another aspect, the embodiments disclosed herein relate to a process for steam cracking a condensate feedstock or a portion thereof to produce one or more products including olefins, diesel, and pyrolysis oil. The vapor phase may be fed to a steam cracking reactor to convert at least a portion of the hydrocarbons therein to a one or more products including olefins and pyrolysis oil. In other embodiments, the one or more products of the steam cracking reactor may have a boiling point of less than 300° C.

In another aspect, the embodiments disclosed herein relate to a process of distilling the liquid phase including unvaporized hydrocarbons with a 300° C.+ cut point. The distillates from the vacuum distillation column may include one or more distillate fractions including straight run vacuum light gas oil (“light VGO”), straight run vacuum heavy gas oil (“heavy VGO”), and vacuum residue. In one or more embodiments, light VGO may have boiling point between approximately 300° C. and approximately 370° C., the heavy VGO may have a boiling point of 370° C. to 500° C., and the vacuum residue may have a boiling point of greater than 500° C. The heavy VGO may be source of the EURO-V diesel production after being hydroprocessed in a hydroprocessing system. In some embodiments, the vacuum residue of the vacuum distillation column may be collected to be sent for VLSFO production downstream.

In another aspect, the embodiments disclosed herein relate to the hydroprocessing of the light VGO fraction and the heavy VGO fraction from the vacuum distillation column in a hydroprocessing system to produce a hydroprocessed light VGO fraction and a hydroprocessed heavy VGO fraction. In one embodiment, the hydroprocessing system may include one single hydroprocessing unit used for both the light VGO fraction and the heavy VGO fraction. In another embodiment, the hydroprocessing system may include two parallel hydroprocessing units, wherein a first hydroprocessing unit is configured to hydroprocess the light VGO fraction and a second hydroprocessing unit is configured to hydroprocess the heavy VGO fraction. In one embodiment, there may be a stream recycling from a gasoline fractionator to the first hydroprocessing unit, which may include nonane and the corresponding cyclic paraffins, olefinic species, and aromatics of nonane, and have a boiling point of between 195 and 205° C., 205 and 215° C., and 215 and 220° C. The stream recycling from the gasoline fractionator, or the gasoline fractionator recycle stream, may include an aromatics composition between 60 and 70 wt %, 70 and 80 wt %, 80 and 90 wt %, and 90 and 100 wt %. Depending on the operating conditions of the gasoline fractionator, the gasoline fractionator recycle stream may contain octane and the corresponding cyclic paraffins, olefinic, and aromatic species. The gasoline fractionator recycle stream may have been further processed in a fuel oil stripper prior to being recycled into the first hydroprocessing unit and have a boiling point of between 195 and 205° C., 205 and 215° C., and 215 and 220° C.

The hydroprocessing of the light VGO fraction and the heavy VGO fraction may occur in one or more ebullated bed residue hydrocracking reaction units. For example, the light VGO fraction may be hydroprocessed in a first ebullated bed hydrocracking reaction unit, and separately the heavy VGO fraction may be hydroprocessed in a second ebullated bed hydrocracking reaction unit. In one or more embodiments, either the heavy VGO fraction, the light VGO fraction, or both may be fed into a single ebullated bed residue hydrocracking reaction unit. In one or more embodiments, the first, second, or single hydrocracking reaction unit may include a single reaction stage having a single hydrocracking reactor, such as an ebullated bed hydrocracking reactor or a fluidized bed hydrocracking reactor. In another embodiment, the first, second, or single hydrocracking reaction unit may include one or more ebullated bed reactors operated in series or in parallel. The ebullated bed hydrocracking reactor may perform one or more of metals removal, denitrogenation, desulfurization, hydrogenation, conradson carbon residue (CCR) reduction, and/or other hydroconversion reactions in addition to hydrocracking. The reactivity for varied reactions noted may be provided by a single hydrocracking catalyst or multiple hydrocracking catalysts.

In one or more embodiments, the light VGO fraction or the heavy VGO fraction, or a mixture of both, are contacted with heated hydrogen and a hydroprocessing catalyst in the ebullated bed residue hydrocracking reactor. In one or more embodiments, the ebullated bed residue hydrocracking reaction unit may include a catalyst system with fresh catalyst delivery to the ebullated bed residue hydrocracking reactors and a spent catalyst withdrawal. The spent catalyst may be further processed in a catalyst recovery and handling system. The ebullated bed residue hydrocracking reaction unit may generate a quantity of spent or partially spent catalyst.

Catalysts useful in the ebullated bed residue hydrocracking reaction unit, ebullated bed reactors, or hydrocracking reactors may include any catalyst useful in the hydroconversion processes of hydrotreating or hydrocracking a hydrocarbon feedstock. A hydrotreating catalyst, for example, may include catalyst compositions that may be used to catalyze the hydrogenation of hydrocarbon feedstocks, wherein hydrogenation means increasing its hydrogen content and/or removing heteroatom contaminants. A hydrocracking catalyst, for example, may include any catalyst composition that may be used to catalyze the addition of hydrogen to large or complex hydrocarbon molecules. A hydrocracking catalyst composition may be used to crack molecules to obtain smaller, lower molecular weight molecules.

Following the hydrocracking, the hydroprocessed hydrocarbon mixture effluent from the ebullated bed residue hydrocracking reaction unit may be separated in a fractionation unit into one or more hydroprocessed distillate fractions including diesel. In an embodiment, there may be three hydroprocessed distillate fractions including a hydroprocessed light VGO fraction, a hydroprocessed heavy VGO fraction, and a diesel fraction. In other embodiments, the hydroprocessed distillate fractions may include among other possible fractions an offgas fraction, a light naphtha fraction, a heavy naphtha fraction, a kerosene fraction, a diesel fraction, a light VGO fraction, and a heavy VGO fraction. In one or more embodiments, the diesel fraction may include EURO-V diesel. EURO-V diesel may include a maximum sulfur content limit of 10 ppm, which is lower than for instance EURO-II which may have up to a maximum of 500 ppm. Generally, engines combusting fuel with lower sulfur content emit less toxic emissions than other more conventional diesel specifications. In one or more embodiments, EURO-V diesel may be collected as the desired product. In some embodiments, EURO-V diesel may be optionally combined with vacuum residue and together collected separately from the EURO-V diesel product.

In another aspect, the embodiments disclosed include feeding the hydroprocessed light VGO fraction, the hydroprocessed heavy VGO fraction, and the vapor phase to a steam cracking reactor to convert at least a portion of the hydrocarbons therein to a steam cracker effluent. In some embodiments, the feed of the steam cracking may include the vapor phase including one or more chemicals such as ethane, ethylene, propane, propylene, butane, butylene, pentane, and pentylene, hexane, hexene, heptane, heptene, octane, octene, nonane, nonene, decane, decene, naphtha, kerosene, and other higher linear alpha olefins. The steam cracker effluent may include olefins and a pyrolysis oil stream.

In another aspect, the embodiments disclosed include separating the steam cracker effluent in a distillation column. The distillation column may separate the steam cracker effluent into two or more distillate fractions, where a first steam cracker effluent fraction may include ethane, ethylene, propane, propylene, butane, butylene, pentane, and pentylene, hexane, hexene, heptane, heptene, octane, octene, nonane, nonene, and other higher linear alpha olefins and a second steam cracker effluent fraction includes a pyrolysis oil stream. In one or more embodiments, all or a portion of the first steam cracker effluent fraction may optionally be recycled back to the HOPS tower directly or to the HOPS tower condensate feedstock stream prior to introduction into the HOPS tower. In one or more embodiments, the steam cracker effluent recycle line may include from other sources butane, pentane, hexane, heptane, and octane and corresponding olefinic, naphthenic and paraffinic species of butane, pentane, hexane, heptane, and octane. In one or more embodiments, the steam cracker effluent recycle line may be fed from sources other than the steam cracker such as streams from BTX units extracting benzene, toluene, and xylene from pyrolysis gasoline. In some embodiments, the BTX units may include a hydrogenation process and produce a recycle stream containing olefins, acetylenes, and dienes. In one or more embodiments, the steam cracker effluent recycle line may be fed butanes and olefinic, naphthenic, and paraffinic species of butanes. In one or more embodiments, all or a portion of the second steam cracker effluent fraction may be collected and mixed with the vacuum residue fraction from the vacuum distillation column and sent downstream to VLSFO production.

Referring now to, a simplified flow diagram of system and processes for processing a condensate feedstock or a portion thereof to produce one or more products including chemicals, olefins, diesel, pyrolysis oil, and VLSFO. The condensate feedstock streamis introduced into a HOPS towerand the steam cracking reactor and is further illustrated in.

Optionally, olefins plant recycle streams (not shown) may be recycled either directly into the HOPS tower or to the condensate feedstock lineto produce a mixed feed stream. In another option, the steam cracker effluent recycle linemay send steam cracker effluent to be recycled either directly into the HOPS tower or to the condensate feedstock lineto produce a mixed feed stream. Although not shown in the figure, the steam cracker effluent linemay be fluidly connected to other streams, such that the steam cracker effluent is not the exclusive source feeding the steam cracker effluent line. Therefore, one or more of the condensate feedstock stream, the olefins plant recycle streams (not shown), and the steam cracker effluent recycle linemay be mixed together to form a mixed feed streaminto block. In addition to the hydrocarbon streams feeding block, steammust be fed into blockas it is required for HOPS tower operation.

Finally, the vapor phasehaving a boiling point of <300° C. and a liquid phaseare recovered. Alternatively, the vapor phasemay be a vapor phase that has been cracked in a steam cracking reactor not shown in. The liquid phasemay be a hydrocarbon stream having a boiling point of >300° C. The liquid phasemay be sent to a vacuum distillation towerto be separated into three distillate fractions including the light VGO fraction, the heavy VGO fraction, and the vacuum residue fraction. Optionally, the light VGO fractionmay additionally include one or more hydrocarbons boiling in the range of LPG, naphtha, or both.

Downstream of the vacuum distillation tower, the light VGO fractionand the heavy VGO fractionare sent to hydroprocessing system. The hydroprocessing systemincludes a first hydroprocessing unitand a second hydroprocessing unit. Although not featured in, the first hydroprocessing unitmay be fluidly connected to a downstream fractionation unit and the second hydroprocessing unitmay be fluidly connected to a separate downstream fractionation unit. Then the light VGO fractionis hydroprocessed in the first hydroprocessing unit, the heavy VGO fractionis hydroprocessed in the second hydroprocessing unit, and the vacuum residue fraction is separately collected downstream for VLSFO production.

Optionally, the first hydroprocessing unitmay receive a gasoline fractionator recycle streamincluding nonane and corresponding cyclic paraffins, olefinic species, and aromatics of nonane having a boiling point of 205° C. The gasoline fractionator recycle streammay also include more than 60 wt % aromatics. Finally, the gasoline fractionator recycle streammay include octanes and corresponding cyclic paraffins, olefinic species, and aromatic species of octane.

Hydroprocessed light VGO fractionis collected from the first hydroprocessing unitand sent downstream to the steam cracking reactor. Hydroprocessed heavy VGO fractionand EURO-V dieselare collected from the second hydroprocessing unitand sent to a fractionation unit (not shown) that separates the EURO-V diesel from the heavy hydroprocessed VGO fraction. Dependent upon operational conditions and the composition of mixed feed stream, additional processing equipment not shown in the figure may be required to bring the diesel streamwithin EURO-V diesel specification. The EURO-V dieselis collected as the desired or a target product.

Optionally, a portion of EURO-V diesel may be diverted from the EURO-V diesel streaminto a EURO-V diesel slip streamand mixed with the vacuum residue fractionfrom the vacuum distillation columnto bring the vacuum residue fractionwithin specification for VLSFO production. Together EURO-V diesel slip streamand vacuum residue fractionmay be collected for downstream VLSFO production.

Together, the hydroprocessed heavy VGO fraction, the light VGO fraction, and the vapor phasehaving a boiling point of <300° C.is sent to the steam cracking reactorto be cracked. The steam cracker effluent includes a mixture of one or more olefins and pyrolysis oil. The steam cracker effluent may also include a small percentage of non-olefins chemicals such as ethane, propane, butane, pentane, hexane, heptane, octane, nonane, and other higher normal hydrocarbon chains within the olefins stream. The mixed feed steam cracker effluent may be sent to a fractionation unit (not shown) to separate the one or more olefins streaminto various fractions (not shown) and the pyrolysis oil. Depending on the needs of downstream VLSO production, all or a portion of the pyrolysis oil streamis optionally diverted into pyrolysis oil slip streamand mixed with the vacuum residue fractionfrom the vacuum distillation towerto bring the mixture within specification. If none or just a portion of the pyrolysis oil streamis diverted into pyrolysis oil slip stream, then the remaining flow of the pyrolysis oil streammay be collected separately as a pyrolysis oil product.

Referring now to,is a simplified flow diagram of processes and systems for feeding a mixed feed streamincluding one or more of condensate feedstock, steam cracker effluent from steam cracker effluent recycle line, and olefins plant recycle streams into a HOPS towerand recovering a first stream containing hydrocarbons in a vapor phase and steamfrom a second stream containing hydrocarbons in a liquid phase.

Starting at mixed feed stream, a mixture of one or more of condensate feedstock stream, steam cracker effluent recycle line, and olefins plant recycle streams is preheated by an electric or steam-heated preheaterto a temperature below the bubble point of the stream to form a preheated mixed feed stream. The preheated mixed feed streamis then flowed into hydrocarbon inletof the HOPS tower. In addition to the preheater, steamheats the mixed feed streamthrough direct contact. Vapor phasehaving a boiling point of <300° C. is recovered from vapor outletand a liquid phasehaving a boiling point of >300° C. out of liquid outlet.

Optionally, the steam cracker effluent recycle lineand olefins plant recycle streams may be fed directly to the HOPS towerto the condensate feedstock stream, the pre-heated mixed feed streamor the vapor phase. If either the steam cracker effluent recycle lineor the olefins plant recycle streams are fed to the vapor phase, then one or more vaporizers (not shown) may be required in order to ensure the stream remains in the vapor phase.

Steammay be injected directly into steam inlet. Optionally, steammay be injected into the steam inletof the vapor phasein order to volatilize the hydrocarbons from the liquid phase. Finally, steammay also be injected at the pre-heated mixed feed streaminto steam inlet.

After the vapor phasehaving a boiling point of <300° C. may be heated by steamthrough the steam inlet, the vapor phase may be steam cracked in a cracker (not shown) downstream of the HOPS tower prior to being further processed in. In addition to the vapor phase, the liquid phaseis further processed as previously described in.

Traditionally, a CDU has been utilized to initially process the condensate feedstock requiring significant energy for both cooling a reflux drum or heating a reboiler. By contrast, utilizing a HOPS tower allows steam to be introduced directly into the hydrocarbon feed stream or the vessel itself resulting in the reductio of the hydrocarbon partial pressure and required energy to separate hydrocarbon fractions. Thus, a HOPS tower may operate at a relatively lower temperature than the CDU allowing for an advantageously lower saturated water content, rendering the heavier fraction of the condensate easier to process in a hydroprocessing system downstream. This reduction in energy requirement as compared to a CDU allows for high energy efficiency. Additionally, because a HOPS tower does not require as many trays as a CDU, capital expense is reduced upon installation. Advantageously, in one or more embodiments energy is saved due to the preheating of condensate feedstock with various heaters inclusive to electric, super high-pressure steam, high-pressure steam, or by cross-exchange with the steam cracking reactor effluent.

Unless defined otherwise, all technical and scientific terms used have the same meaning as commonly understood by one of ordinary skill in the art to which these systems, apparatuses, methods, processes and compositions belong.

The singular forms “a,” “an,” and “the” include plural referents, unless the context clearly dictates otherwise.

As used here and in the appended claims, the words “comprise,” “has,” and “include” and all grammatical variations thereof are each intended to have an open, non-limiting meaning that does not exclude additional elements or steps.

“Optionally” means that the subsequently described event or circumstances may or may not occur. The description includes instances where the event or circumstance occurs and instances where it does not occur.

When the word “approximately” or “about” are used, this term may mean that there can be a variance in value of up to +10%, of up to 5%, of up to 2%, of up to 1%, of up to 0.5%, of up to 0.1%, or up to 0.01%.

Ranges may be expressed as from about one particular value to about another particular value, inclusive. When such a range is expressed, it is to be understood that another embodiment is from the one particular value to the other particular value, along with all particular values and combinations thereof within the range.

While the disclosure includes a limited number of embodiments, those skilled in the art, having benefit of this disclosure, will appreciate that other embodiments may be devised which do not depart from the scope of the present disclosure. Accordingly, the scope should be limited only by the attached claims.