REMOVAL OF ORGANIC SILICON COMPOUNDS FROM REFINERY HYDROCARBON STREAMS

Abstract

A method, process, and system are disclosed for removing silicon-containing compounds from refinery hydrocarbon streams using alkaline treatment. The refinery stream, which may originate from units such as a crude stream, delayed coker, or other process unit, is contacted with an alkaline agent, such as a solid or an aqueous solution of sodium hydroxide, potassium hydroxide, or an amine. This treatment extracts at least a portion of the silicon-containing compounds, including organic silicon species, from the hydrocarbon stream. The process may be applied to whole streams or specific fractions such as LPG, naphtha, kerosene, diesel, or coker gas oil. Following alkaline treatment, the hydrocarbon stream may be directed to a hydrotreating unit, where reduced silicon content reduces catalyst poisoning.

Claims

1. A method of extracting silicon-containing compounds from a refinery stream, the method comprising: contacting a refinery stream with an alkaline agent, wherein the refinery stream comprises a mixture of hydrocarbons and silicon-containing compounds, wherein the alkaline agent extracts the silicon-containing compounds from the refinery stream.

2. The method of claim 1, wherein the refinery hydrocarbon stream comprising the silicon-containing compound is separated into two or more fractions before contacting with the alkaline agent.

3. The method of claim 2, wherein the two or more fractions comprise a liquefied petroleum gas (LPG) fraction, a naphtha fraction, a kerosene fraction, a diesel fraction, coker gas oil, or a combination of two or more thereof.

4. The method of claim 1, wherein the alkaline agent comprises a solid, a powder, or an aqueous solution.

5. The method of claim 1, wherein the alkaline agent is within an alkaline scrubbing bed, a packed bed, or a trayed column.

6. The method of claim 1, wherein the silicon-containing compound is an organic silicon-containing compound.

7. A process for extracting a silicon-containing compound from a refinery hydrocarbon stream, the process comprising: providing a refinery hydrocarbon stream from an upstream process unit, wherein the refinery hydrocarbon stream comprises a silicon-containing compound; and contacting the refinery hydrocarbon stream comprising the silicon-containing compound with an alkaline agent in an alkaline bed, thereby extracting at least a portion of the silicon-containing compound from the refinery hydrocarbon stream; and hydrotreating the refinery hydrocarbon stream after the contacting.

8. The process of claim 7, wherein the upstream process unit is a delayed coker unit.

9. The process of claim 7, wherein the refinery hydrocarbon stream comprising the silicon-containing compound is separated into two or more fractions before passing through the alkaline bed.

10. The process of claim 9, wherein the two or more fractions comprise an LPG fraction, a naphtha, a kerosene fraction, a diesel fraction, coker gas oil, or a combination of two or more thereof.

11. The process of claim 7, wherein the alkaline bed comprises a solid, a powder, or an aqueous solution.

12. The process of claim 7, wherein the silicon-containing compound is an organic silicon-containing compound.

13. The process of claim 7, wherein an alkaline agent is circulated within the alkaline bed to maintain a concentration of the alkaline agent throughout the process.

14. The process of claim 7, wherein the alkaline bed is an alkaline scrubbing bed, a packed bed, or a trayed column.

15. A system for extracting a silicon-containing compound from a refinery hydrocarbon stream, the system comprising: an upstream process unit, an alkaline bed, and a hydrotreater, wherein, the alkaline bed is upstream of the hydrotreater, and wherein the alkaline bed is configured to receive a refinery hydrocarbon stream comprising the silicon-containing compound from the upstream process unit such that the refinery hydrocarbon stream comprising the silicon-containing compound contacts the alkaline bed, thereby removing the silicon-containing compound from the refinery hydrocarbon stream before hydrotreating.

16. The system of claim 15 further comprising a distillation unit upstream of the alkaline bed.

17. The system of claim 15, wherein the upstream process unit is a delayed coker unit.

18. The system of claim 15, wherein the alkaline bed comprises an alkaline agent, and the alkaline agent is provided as a solid, a powder, or an aqueous solution.

19. The system of claim 15, wherein the silicon-containing compound is an organic silicon-containing compound.

20. The system of claim 15, wherein the alkaline bed is an alkaline scrubbing bed, an amine bed, a packed bed, or a trayed column.

Description

BRIEF DESCRIPTION OF THE FIGURES

[0013] FIG. 1 is a flow chart depicting a method of reducing or removing silicon from a hydrocarbon stream, according to an embodiment.

[0014] FIG. 2 is a process diagram for a petroleum refining process, according to an embodiment.

[0015] FIG. 3A is a process diagram for a portion of a delayed coking process wherein a product of the delayed coker is subjected to an alkaline treatment after coking, according to an embodiment.

[0016] FIG. 3B is a process diagram for a portion of a delayed coking process wherein an alkaline treatment is performed within the delayed coker, according to an embodiment.

DETAILED DESCRIPTION

[0017] The present invention provides methods for removing or extracting silicon-containing compounds from refinery hydrocarbon streams. The present invention may be applied to reduce silicon poisoning of catalysts in various refinery processes.

[0018] Silicon is a known catalyst poison for hydrotreating and/or reforming catalysts. These catalysts may include active metal sites. Zeolites, which form a tight crystal lattice having small pore sizes, may also be used. Silicon can deposit on the surface of the catalyst support, blocking pores and limiting access to active metal sites, thereby greatly reducing the effectiveness of the catalyst. Traditional silicon removal efforts include the use of silicon capture catalysts designed to capture the silicon in a stream before the stream is provided to a hydrotreating or reforming catalyst. The silicon capture catalysts are able to capture a significant portion of silicon, however the silicon capture catalyst beds require additional reactor volume and negatively affect the overall catalytic activity of the system. They also require frequent shut down of the reactor so that the silicon capture catalyst can be replaced or regenerated, reducing the reactor cycle time. The methods, systems, and devices provided herein may be used to reduce or remove silicon from a hydrocarbon stream, thereby reducing or eliminating the need for a silicon capture catalyst bed.

[0019] Silicon compounds can enter a petroleum or hydrocarbon refining stream from various sources, potentially affecting downstream processes. One potential source is from upstream oil production, where polydimethylsiloxanes (PDMS) are employed as antifoaming agents to manage foaming during crude oil extraction and handling. As a result, the initial crude oil received by refiners may inherently contain silicon-based contaminants. In addition to their role as antifoaming agents, PDMS and similar silicon-based solvents are utilized in deasphalting processes, including propane deasphalting and residual oil supercritical extraction (ROSE). These processes yield deasphalted oils (DAO), which similarly retain silicon impurities initially present in the crude or introduced during processing. Even though they may be present at low levels, the persistence of silicon compounds in these streams poses challenges for refining, as they can lead to catalyst poisoning and reduced efficiency in subsequent treatment stages.

[0020] Another significant source of silicon in petroleum refining is the delayed coker unit, a process unit used for upgrading heavy residues into more valuable lighter fractions. Within the delayed coker, the full range effluent from a coke drum undergoes separation in the main fractionator. This fractionator typically yields various products, including, but not limited to, liquefied petroleum gas (LPG), full-range naphtha, and a distillate range fraction containing kerosene and/or diesel, along with coker gas oils encompassing both light and heavy fractions. Silicon-containing antifoam agents, such as polydimethylsiloxanes (PDMS), are injected into the coke drum to manage foaming. Much of the silicon-based antifoam agent injected into the coke drum breaks down into lower molecular weight organic silicon compounds. These silicon-containing compounds are carried into the fractionator and are separated in the various product streams.

[0021] Silicon compounds may also enter a refinery stream through use as a lubricant. In refinery operations, silicon-based lubricants, particularly those containing PDMS or other organosilicon compounds, are often used in high-temperature or high-pressure equipment due to their thermal stability, low volatility, and excellent lubricity. These lubricants can be applied in compressor seals, pump systems, and rotating equipment where traditional hydrocarbon-based lubricants may degrade. However, when these silicon-containing substances degrade or leak into process streams, they can introduce trace silicon contamination, which poses challenges for the downstream catalysts, especially in hydroprocessing and fluid catalytic cracking (FCC) units.

[0022] Silicon-containing compounds are typically present in refinery hydrocarbon streams at low levels, on the range of part per million (whether by mass, mole, or volume) or less than 1 wt. %. The presence and concentration of silicon-containing compounds can be determined by various testing methods, including, for example, ASTM D7757. Silicon-containing compounds frequently exhibit enriched concentrations in the naphtha fraction due to their volatility but can also be detected across the distillate range products. The presence of these compounds in multiple product streams presents a challenge, as they require careful management to prevent catalyst poisoning and deactivation and to ensure optimal product quality and process efficiency in subsequent refining operations.

[0023] The concepts presented are applicable to extracting silicon-containing compounds from refinery hydrocarbon streams. The process involves providing a refinery hydrocarbon stream derived from an upstream process unit, wherein the stream contains silicon compounds that may impair downstream catalytic operations. The refinery hydrocarbon stream is then passed through an alkaline bed prior to hydrotreating, effectively extracting silicon compounds and reducing their concentration in the stream. This pre-treatment step ensures the protection and optimal performance of downstream catalysts by minimizing silicon-induced poisoning.

[0024] Turning to FIG. 1, a method 100 presented herein includes a step 110 providing a refinery hydrocarbon stream carrying silicon compounds, a step 112 of contacting the refinery hydrocarbon stream with an alkaline agent, a step 114 of separating the silicon compounds from the hydrocarbon stream. The step 110 of providing the hydrocarbon stream can be performed by locating or otherwise preparing a hydrocarbon stream. The hydrocarbon stream does not need to be pure hydrocarbon. Contaminants such as water, salts, sulfur species, acids, metals, and other oil contaminants. For example, the refinery hydrocarbon stream may be a crude or partially treated oil stream, a partially refined oil stream, a full range effluent from a preheater, a desalter, a crude unit, a distillation column, a vacuum distillation unit, an asphalt production unit, or a coker, or may be one or more fractioned streams (e.g., light hydrocarbons (C1-C4), naphtha, gasoline, kerosene, diesel, light coker gas oil, heavy coker gas oil, a mixture of any two or more thereof).

[0025] The step 112 of contacting the hydrocarbon stream with the alkaline material may be performed in a column or bed, or any other suitable vessel. The refinery hydrocarbon stream comprises a generally hydrophobic phase, while the alkaline agent may be provided in a hydrophobic phase, an aqueous phase, as a slurry, or as a solid (crystals, powders, granular, or other forms). Thus, contacting the refinery hydrocarbon stream may require mixing of the alkaline agent with the stream. The step 112 of contacting the refinery hydrocarbon stream with an alkaline agent effectively reduces the concentration of silicon-containing compounds within the stream, which is crucial for maintaining downstream catalytic efficiency.

[0026] In various embodiments, the alkaline bed is housed in a vessel designed to maximize contact between the alkaline agent and the hydrocarbon stream. Suitable configurations include alkaline scrubbing beds, packed beds, or trayed columns. Additionally, conventional liquid-liquid extraction systems may be employed, including mixer-settler systems (e.g., in-line mixers with downstream settlers), spray columns, Karr columns, or rotating disc contactors. These systems facilitate efficient separation of silicon compounds by enhancing phase interaction. Other methods for alkaline-hydrocarbon contact may involve the use of fiber film contactors or mechanical agitation techniques, akin to those used in mixer-settler setups, to further optimize extraction efficacy.

[0027] The alkaline bed comprises an alkaline agent selected based on the specific requirements of the refining process and the composition of the hydrocarbon stream. The choice of alkaline material is not particularly limited, allowing for flexibility in formulation. Suitable alkaline agents include, but are not limited to, strong bases such as sodium hydroxide (NaOH) and potassium hydroxide (KOH), which may be applied in various forms including aqueous solutions, slurries, dry powders, flakes, or crystals. In certain embodiments, an aqueous solution of NaOH or KOH is used to promote effective interaction with silicon-containing compounds, such as siloxanes or silanols. Alternatively, solid forms of these bases may be employed for applications without the increasing the water content of the refinery stream. Additional alkaline materials that may be used include alkaline earth metal hydroxides such as calcium hydroxide (Ca(OH).sub.2) and magnesium hydroxide (Mg(OH).sub.2), which offer lower solubility and may be advantageous in specific process configurations. Organic amines, such as monoethanolamine (MEA), diethanolamine (DEA), or triethylenetetramine (TETA), can also serve as alkaline agents, particularly in systems where selective reactivity or compatibility with downstream catalysts is desired. The amine material may also provide secondary support for capturing other contaminants in the stream. In some embodiments, weak bases such as sodium carbonate (Na.sub.2CO.sub.3) or ammonium hydroxide (NH.sub.4OH) may be used to facilitate controlled extraction of silicon compounds under milder conditions or over longer time scales. The selection of the alkaline agent can be tailored to balance reactivity, handling characteristics, and compatibility with existing refinery infrastructure.

[0028] The concentration of the alkaline agent within the treatment vessel or alkaline bed is carefully controlled to ensure consistent and effective extraction of silicon-containing compounds. In various embodiments, the alkaline concentration is maintained within a range of approximately 1 to 30 wt. %, with preferred sub-ranges including 5 to 20 wt. % and 10 to 15 wt. %, depending on the specific process conditions and desired reactivity. In some embodiments, the alkaline agent is circulated within the alkaline bed to maintain a consistent alkalinity across the bed. To enhance the efficiency and sustainability of the process, a recycling strategy is employed, allowing the alkaline agent to be reused multiple times. Despite this recycling, a portion of the alkaline agent is periodically purged from the system to prevent the buildup of silicon reaction byproducts, such as silicates or silanolates, which could otherwise lead to precipitation and fouling in the alkaline bed or other equipment. An equivalent volume of fresh alkaline agent is introduced as makeup to maintain the desired concentration and reactivity.

[0029] The separation of silicon-containing compounds from the hydrocarbon stream (step 114) may be performed in the same equipment used for contacting with the alkaline agent (step 112), or in a separate downstream unit. Separation can be achieved using any suitable technique known in the art, including but not limited to filtration, membrane separation, or liquid-liquid separation. In various embodiments, the process achieves a reduction in silicon content ranging from approximately 50 to 100 wt. %, with typical reductions falling within the range of 65 to 95 wt. %, and in some cases, 75 to 90 wt. %. Without being bound by theory, it is believed that the alkaline agent facilitates silicon removal by converting silicon-containing compounds into silicon saltssuch as silanolates or silicateswhich are either soluble in the aqueous alkaline phase, precipitate as solids, or otherwise become extractable from the hydrocarbon phase. For example, treatment with potassium hydroxide (KOH) may result in the formation of potassium silanolates, which can be separated from the hydrocarbon phase via phase separation techniques. By removing silicon compounds upstream of sensitive catalytic reactors, the process significantly reduces or eliminates the risk of catalyst poisoning. This pre-treatment step enables full utilization of the reactor volume with active catalyst, thereby improving reactor performance, extending catalyst cycle life, and enhancing the overall economic and operational efficiency of the hydroprocessing system.

[0030] The refinery hydrocarbon stream may be effectively treated with an alkaline agent at various stages of the refining process to facilitate the removal of silicon-containing compounds and thereby protect downstream catalyst beds from deactivation. The strategic integration of alkaline treatment units within the refining process enables targeted protection of catalytic systems that are particularly vulnerable to silicon poisoning. For illustrative purposes, FIG. 2 depicts a simplified petroleum refining process 200, which serves to contextualize the application of silicon removal techniques. It should be understood that the present disclosure is not limited to the specific process configuration shown, and may be applied to a wide range of refining schemes, as would be readily appreciated by a person of ordinary skill in the art.

[0031] Referring to FIG. 2, the simplified refining process 200 begins with a crude oil feed 202 introduced into a desalter unit 204. The resulting desalted crude stream 206 is optionally preheated using one or more heaters 208, producing a heated crude feed 209. This feed is then directed to a separation unit 210, such as an atmospheric distillation column. From the top of the separation unit 210, a light gas stream 222 is withdrawn and routed to a light separation vessel 224. Light hydrocarbon gases 228, such as C.sub.1-C.sub.4 gas components, are recovered from the top of the light separation vessel 224. A condensed liquid stream 226 is returned to the separation unit 210 for further fractionation, while a light naphtha stream 220 is collected for further processing.

[0032] The separation unit 210 may also produce additional hydrocarbon fractions at various draw points, including, but not limited to, a heavy naphtha stream 218, a distillate stream 216, a gas oil stream 214, a heavy fuel oil stream 240, and a bottoms stream 212. The number and composition of these product streams may vary depending on the specific configuration and operating conditions of the refining process, all of which are within the scope of the present disclosure.

[0033] The light naphtha stream 220 may be subjected to hydrotreatment and/or isomerization reactions 246, which involve the use of one or more catalysts, to produce a blending stock stream 248. Similarly, the heavy naphtha stream 218 may undergo hydrotreatment or catalytic reforming reactions 250, also utilizing catalysts, to generate a reformate stream 252. The distillate stream 216 may be processed through hydrotreatment and/or sweetening via mercaptan oxidation or other catalytic reactions 254 to produce a jet fuel and/or diesel stream 256. The resulting blending stock 248, reformate 252, and jet/diesel stream 256 may be used in downstream blending operations or as final product streams 284.

[0034] 1The bottoms stream 212 from the separation unit 210, which contains the heaviest hydrocarbon fractions, is directed to a vacuum distillation unit 260 for further separation. A light vacuum gas oil (LVGO) stream 264 may optionally be combined with the gas oil stream 214 to form a combined gas oil stream 266, which is then processed in a fluidized catalytic cracking (FCC) unit to produce a fuel oil stream 270. The heavy vacuum gas oil (HVGO) fraction 281 is subjected to hydrocracking 280 in the presence of one or more catalysts to yield diesel 278 and gasoline 282 product streams, which may be used in blending or as final products 284. The heaviest residual material is collected as a bottoms stream 272 from the vacuum distillation unit 260, a portion of which is subsequently routed to a deasphalter unit 274 to produce a deasphalted oil stream 276.

[0035] The remainder of the bottoms 272 is provided to a delayed coker unit 286. The delayed coker unit may utilize silicon compounds, such as polydimethylsiloxane (PDMS) to control foaming of the material in the coker. A coker gas oil stream 288 is produced by the delayed coker unit 286 and is provided to a distillation unit 290 or other separation unit for fractionation. The lighter component stream 294 is separated using a separation vessel 299, which separates coker light gases 296 from the return liquid 298 and light coker naphtha streams 297. Heavy coker naphtha 293 and coker distillate 292 may be combined with the heavy naphtha stream 218 and the distillate stream 216, respectively, and then further processed. Alternatively, the heavy coker naphtha 293 and coker distillate 292 may be hydrotreated or reformed separately from the heavy naphtha stream 218 and the distillate stream 216. Heavy coker gas oil 291 is provided to a fluidized catalytic cracker (FCC) for cracking.

[0036] It may be advantageous to treat fractionated hydrocarbon streams with alkaline either directly or indirectly upstream of catalysts prone to deactivation, such as those used in hydrotreating units, including light naphtha, heavy naphtha, and distillate hydrotreaters, as well as fluid catalytic cracking (FCC) units. Specifically, a fractionated naphtha stream laden with silicon compounds can pass through an alkaline treatment vessel, such as an alkaline bed, where it can interact with the alkaline agent before entering naphtha hydrotreating or reforming reactors. Similar treatment setups can be applied to other streams, such as fractionated distillate, diesel, gasoline, and kerosene streams, as applicable, ensuring alkaline interaction prior to catalytic hydrotreating or reforming stages. With reference to FIG. 2, such an implementation could include providing an alkaline bed (or other suitable alkaline contactor unit) on any one or more of the heavy naphtha stream 218, the distillate stream 216, and the gas oil stream 214. Similarly, alkaline beds could be provided on one or more of the coker light gases stream 296, the light coker naphtha stream 297, the heavy coker naphtha stream 293, and the coker distillate stream 292. This strategic placement protects catalysts while optimizing alkaline material utilization by only applying alkaline treatment to streams that will be exposed to vulnerable catalyst.

[0037] In other embodiments, it may be preferable to implement alkaline contacting through a source-based approach, i.e., positioning it immediately after units employing silicon compounds, such as PDMS. For example, an alkaline bed can be positioned to accept hydrocarbon streams containing silicon compounds from sources such as crude delivered to the refinery, delayed coker units, deasphalter units, or other relevant process units. With reference to FIG. 2, such a strategy could be implement by providing an alkaline bed to an incoming crude oil feed 202, a desalted crude stream 206, or a preheated crude stream 209. This strategy could also be implemented by positioning an alkaline bed on the coker gas oil stream 288 or the deasphalted oil stream 276. This strategy offers the advantage of centralizing silicon reduction efforts, thereby decreasing the silicon content in hydrocarbon streams near PDMS-using production units and prior to potential further separation or downstream processing. However, this source-based approach might require a greater volume of alkaline material compared to methods that treat hydrocarbon streams immediately before catalyst exposure in reactor environments, as larger volumes of hydrocarbon material may be treated.

[0038] In certain embodiments, a coker naphtha fraction from a coker unit is contacted with an alkaline agent to reduce the concentration of silicon-containing compounds. This treatment approach may differ from that applied to the coker distillate fraction. Some delayed coker units are equipped with diolefin saturation reactors (not shown), which are used to treat one or more of the coker naphtha fractions prior to their transfer to downstream refinery units. In some embodiments, a coker naphtha fraction is first routed through a diolefin saturation reactor before being contacted with the alkaline agent. In alternative embodiments, a coker naphtha fraction is treated with the alkaline agent prior to entering the diolefin saturation reactor. Due to the relatively mild operating conditions of the diolefin saturation reactor, the presence of silicon-containing compounds in the coker naphtha stream does not significantly contribute to catalyst poisoning within the reactor. As a result, the sequence of alkaline treatment and diolefin saturation can be flexibly configured based on process design and operational considerations.

[0039] In some embodiments, mixed or unfractionated hydrocarbon product stream can be contacted with the alkaline agent. Such contact could be provided directly after production of the unfractionated hydrocarbon stream. For example, in some embodiments, an alkaline contacting vessel is positioned downstream of a delayed coker unit. In some embodiments, the alkaline contacting vessel is located within a portion of an upstream process unit, such as a delayed coker unit, to remove organic silicon compounds from the hydrocarbon stream as it is produced and before the hydrocarbon stream is fractionated. In some embodiments, the alkaline contacting vessel is located downstream from or within a portion of a deasphalting unit, to remove organic silicon compounds from the deasphalted oil (DAO) stream as it is produced and before the DOA stream is fractionated.

[0040] As shown in FIG. 3A, an alkaline treatment unit 312such as an alkaline bedis configured to receive a coker gas oil stream 321 originating from a delayed coker unit 310. The coker gas oil stream 321 may contain silicon-based compounds, such as polydimethylsiloxane (PDMS), which are introduced during the coking process to mitigate foaming. Within the alkaline treatment unit 312, the coker gas oil stream 321 is contacted with an alkaline agent, facilitating the removal or reduction of silicon-containing compounds. Fresh alkaline material 326 is provided to the alkaline treatment unit 312. Captured silicon material is ejected from the unit as a waste stream 328. The treatment yields a cleaned hydrocarbon stream 322 with a significantly reduced silicon content. The cleaned hydrocarbon stream 322 is subsequently directed to a hydrotreatment unit 314, which contains a catalyst material, to produce a hydrotreated product 324. The reduction in silicon content in the feed stream minimizes catalyst deactivation or poisoning in the hydrotreatment unit 314, thereby enhancing catalyst longevity and process efficiency.

[0041] In some embodiments, the distillate fraction is contacted with the alkaline agent within the upstream unit, such as a coker or deasphalter, before it is routed to other units in the refinery. In this embodiment, a relatively small volume of distillate is contacted with the alkaline agent compared to the full refinery volume with the highest concentration of silicon containing compounds. In such an embodiment, instead of contacting 100% of the feed to the downstream hydrotreater, a smaller stream can be contacted with the alkaline agent. In this embodiment, smaller equipment size can be used to extract the majority of the silicon containing compounds.

[0042] As illustrated in FIG. 3B, a delayed coker unit 310 may be configured to include an integrated alkaline treatment section 312. A coker gas oil stream, generated within the delayed coker unit 310 and carrying silicon-based compounds, is provided to the alkaline treatment section 312 of the coker. Within the coker unit 310, the coker gas oil stream is contacted with an alkaline agent in the integrated treatment section 312, facilitating the removal or reduction of silicon-containing compounds. This in-situ treatment produces a cleaned hydrocarbon stream 322 with a reduced silicon content. The cleaned hydrocarbon stream 322 is then directed to a hydrotreatment unit as described for FIG. 3A. By incorporating the alkaline treatment directly into the coker unit, the process eliminates the need for a separate treatment vessel, thereby reducing capital investment and space requirement, and simplifying system design.

Definitions

[0043] As used herein, about will be understood by persons of ordinary skill in the art and will vary to some extent depending upon the context in which it is used. If there are uses of the term which are not clear to persons of ordinary skill in the art, given the context in which it is used, about will mean up to plus or minus 10% of the particular term.

[0044] The use of the terms a and an and the and similar referents in the context of describing the elements (especially in the context of the following claims) are to be construed to cover both the singular and the plural, unless otherwise indicated herein or clearly contradicted by context. Recitation of ranges of values herein are merely intended to serve as a shorthand method of referring individually to each separate value falling within the range, unless otherwise indicated herein, and each separate value is incorporated into the specification as if it were individually recited herein. All methods described herein can be performed in any suitable order unless otherwise indicated herein or otherwise clearly contradicted by context. The use of any and all examples, or exemplary language (e.g., such as) provided herein, is intended merely to better illuminate the embodiments and does not pose a limitation on the scope of the claims unless otherwise stated. No language in the specification should be construed as indicating any non-claimed element as essential.

[0045] As used herein, comparative terms as used herein, such as higher, lower, increase, decrease, reduce, or any grammatical variation thereof, can refer to certain variation from the reference. In some embodiments, such variation can refer to about 10%, or about 20%, or about 30%, or about 40%, or about 50%, or about 60%, or about 70%, or about 80%, or about 90%, or about 1 fold, or about 2 folds, or about 3 folds, or about 4 folds, or about 5 folds, or about 6 folds, or about 7 folds, or about 8 folds, or about 9 folds, or about 10 folds, or about 20 folds, or about 30 folds, or about 40 folds, or about 50 folds, or about 60 folds, or about 70 folds, or about 80 folds, or about 90 folds, or about 100 folds or more higher than the reference. In some embodiments, such variation can refer to about 1%, or about 2%, or about 3%, or about 4%, or about 5%, or about 6%, or about 7%, or about 8%, or 0%, or about 10%, or about 20%, or 30%, or 40%, or 50%, or 60%, or 70%, or 75%, or 80%, or 85%, or 90%, or about 95%, or about 96%, or about 97%, or about 98%, or about 99% of the reference.

[0046] Optional or optionally means that the subsequently described circumstance may or may not occur, so that the description includes instances where the circumstance occurs and instances where it does not.

[0047] As used herein, and/or refers to and encompasses any and all possible combinations of one or more of the associated listed items, as well as the lack of combinations when interpreted in the alternative (or).

[0048] Various embodiments are described herein. It should be noted that the specific embodiments are not intended as an exhaustive description or as a limitation to the broader aspects discussed herein. One aspect described in conjunction with a particular embodiment is not necessarily limited to that embodiment and can be practiced with any other embodiment(s).

[0049] The present invention, thus generally described, will be understood more readily by reference to the following examples, which are provided by way of illustration and are not intended to be limiting of the present invention.

[0050] While certain embodiments have been illustrated and described, it should be understood that changes and modifications can be made therein in accordance with ordinary skill in the art without departing from the technology in its broader aspects as defined in the following claims.

[0051] The embodiments, illustratively described herein may suitably be practiced in the absence of any element or elements, limitation or limitations, not specifically disclosed herein. Thus, for example, the terms comprising, including, containing, etc. shall be read expansively and without limitation. Additionally, the terms and expressions employed herein have been used as terms of description and not of limitation, and there is no intention in the use of such terms and expressions of excluding any equivalents of the features shown and described or portions thereof, but it is recognized that various modifications are possible within the scope of the claimed technology. Additionally, the phrase consisting essentially of will be understood to include those elements specifically recited and those additional elements that do not materially affect the basic and novel characteristics of the claimed technology. The phrase consisting of excludes any element not specified.

[0052] The present disclosure is not to be limited in terms of the particular embodiments described in this application. Many modifications and variations can be made without departing from its spirit and scope, as will be apparent to those skilled in the art. Functionally equivalent methods and compositions within the scope of the disclosure, in addition to those enumerated herein, will be apparent to those skilled in the art from the foregoing descriptions. Such modifications and variations are intended to fall within the scope of the appended claims. The present disclosure is to be limited only by the terms of the appended claims, along with the full scope of equivalents to which such claims are entitled. It is to be understood that this disclosure is not limited to particular methods, reagents, compounds, or compositions, which can of course vary. It is also to be understood that the terminology used herein is for the purpose of describing particular embodiments only, and is not intended to be limiting.

[0053] In addition, where features or aspects of the disclosure are described in terms of Markush groups, those skilled in the art will recognize that the disclosure is also thereby described in terms of any individual member or subgroup of members of the Markush group.

[0054] As will be understood by one skilled in the art, for any and all purposes, particularly in terms of providing a written description, all ranges disclosed herein also encompass any and all possible subranges and combinations of subranges thereof. Any listed range can be easily recognized as sufficiently describing and enabling the same range being broken down into at least equal halves, thirds, quarters, fifths, tenths, etc. As a non-limiting example, each range discussed herein can be readily broken down into a lower third, middle third and upper third, etc. As will also be understood by one skilled in the art all language such as up to, at least, greater than, less than, and the like, include the number recited and refer to ranges which can be subsequently broken down into subranges as discussed above. Finally, as will be understood by one skilled in the art, a range includes each individual member.

[0055] All publications, patent applications, issued patents, and other documents referred to in this specification are herein incorporated by reference as if each individual publication, patent application, issued patent, or other document was specifically and individually indicated to be incorporated by reference in its entirety. Definitions that are contained in text incorporated by reference are excluded to the extent that they contradict definitions in this disclosure. Other embodiments are set forth in the following claims.