COKING PROCESS AND SYSTEM FOR ENHANCED CATALYTIC REACTIONS TO IMPROVE PROCESS OPERATION AND ECONOMICS
Heavy gas oil components, coking process recycle, and heavier hydrocarbons in the delayed coking process are cracked in the coking vessel by injecting a catalytic additive into the vapors above the gas/liquid-solid interface in the coke drum during the coking cycle. The additive may comprise cracking catalyst(s) and quenching agent(s), alone or in combination with seeding agent(s), excess reactant(s), carrier fluid(s), or any combination thereof to modify reaction kinetics to preferentially crack these components. The quenching effect of the additive may be effectively used to condense the highest boiling point compounds of the traditional recycle onto the catalyst(s), thereby focusing the catalyst exposure to these target reactants. Exemplary embodiments of the present invention may also provide systems and methods to (1) reduce coke production, (2) reduce fuel gas production, and (3) increase liquids production.
This application claims the benefit of U.S. Provisional Application No. 61/908,446, filed Nov. 25, 2013, which is hereby incorporated by reference in its entirety. This application is also a continuation-in-part of PCT/US2014/031114, filed Mar. 18, 2014, which claims the benefit of U.S. Provisional Application No. 61/794,192, filed Mar. 15, 2013, each of which is hereby incorporated by reference in its entirety.
BACKGROUND AND SUMMARY OF THE INVENTIONExemplary embodiments of the invention relate generally to the field of thermal coking processes, and more specifically to modifications of petroleum refining thermal coking processes to selectively and/or catalytically crack or coke components of the coker feed, recycle, and gas oil process streams and increase production of more valuable product streams. Exemplary embodiments of the invention also relate generally to the production of various types of petroleum coke with unique characteristics for fuel, anode, electrode, or other specialty carbon products and markets.
Thermal coking processes have been developed since the 1930s to help crude oil refineries process the “bottom of the barrel.” In general, modern thermal coking processes employ high-severity, thermal decomposition (or “cracking”) to maximize the conversion of very heavy, low-value residuum feeds to lower boiling hydrocarbon products of higher value. Feedstocks for these coking processes normally consist of refinery process streams which cannot economically be further distilled, catalytically cracked, or otherwise processed to make fuel-grade blend streams. Typically, these materials are not suitable for catalytic operations because of catalyst fouling and/or deactivation by ash and metals. Common coking feedstocks include atmospheric distillation residuum, vacuum distillation residuum, catalytic cracker residual oils, hydrocracker residual oils, and residual oils from other refinery units.
There are three major types of modern coking processes currently used in crude oil refineries (and upgrading facilities) to convert the heavy crude oil fractions (or bitumen from shale oil or tar sands) into lighter hydrocarbons and petroleum coke: delayed coking, fluid coking, and flexicoking. These thermal coking processes are familiar to those skilled in the art. In all three of these coking processes, the petroleum coke is considered a by-product that is tolerated in the interest of more complete conversion of refinery residues to lighter hydrocarbon compounds, referred to as ‘cracked liquids’ throughout this discussion. These cracked liquids range from pentanes to complex hydrocarbons with boiling ranges typically between 350 and 950 degrees F. In all three of these coking processes, the ‘cracked liquids’ and other products move from the coking vessel to the fractionator in vapor form. The heavier cracked liquids (e.g. gas oils) are commonly used as feedstocks for further refinery processing (e.g. Fluid Catalytic Cracking Units or FCCUs) that transforms them into transportation fuel blend stocks.
Crude oil refineries have regularly increased the use of heavier crudes in their crude blends due to greater availability and lower costs. These heavier crudes have a greater proportion of the ‘bottom of the barrel’ components, increasing the need for coker capacity. Thus, the coker often becomes the bottleneck of the refinery that limits refinery throughput. Also, these heavier crudes often contain higher concentrations of large, aromatic structures (e.g. asphaltenes and resins) that contain greater concentrations of sulfur, nitrogen, and heavy metals, such as vanadium and nickel. As a result, the coking reactions (or mechanisms) are substantially different and tend to produce a denser, shot (vs. sponge) coke crystalline structure (or morphology) with higher concentrations of undesirable contaminants in the pet coke and coker gas oils. Consequently, these three coking processes have evolved through the years with many improvements in their respective technologies.
Many refineries have relied on technology improvements to alleviate the coker bottleneck. Some refineries have modified their vacuum crude towers to maximize the production of vacuum gas oil (e.g. <1050 degrees F.) per barrel of crude to reduce the feed (e.g. vacuum reduced crude or VRC) to the coking process and alleviate coker capacity issues. However, this is not generally sufficient and improvements in coker process technologies are often more effective. In delayed coking, technology improvements have focused on reducing cycle times, recycle rates, and/or drum pressure with or without increases in heater outlet temperatures to reduce coke production and increase coker capacity. Similar technology improvements have occurred in the other coking processes, as well.
In addition, coker feedstocks are often modified to alleviate safety issues associated with shot coke production or ‘hot spots’ or steam ‘blowouts’ in cutting coke out of the coking vessel. In many cases, decanted slurry oil, heavy cycle oil, and/or light cycle oil from the FCCU are added to the coker feed to increase sponge coke morphology (i.e., reduce shot coke production). This increase in sponge coke is usually sufficient to alleviate the safety problems associated with shot coke (e.g. roll out of drum, plugged drain pipes, etc.). Also, the increase in sponge coke may provide sufficient porosity to allow better cooling efficiency of the quench to avoid ‘hot spots’ and steam ‘blowouts’ due to local areas of coke that are not cooled sufficiently before coke cutting. However, the addition of these materials to coker feed reduces coking process capacities. Alternatively, many refineries limit the use of crudes in their refinery crude slate that cause components in the coker feed that neither crack or coke in the traditional coking process and cause ‘hot spots’ and/or steam ‘blowouts’ due to insufficient cooling of these hot liquids at the end of the coking cycle.
Unfortunately, many of these technology improvements have substantially decreased the quality of the resulting pet coke. Most of the technology improvements and heavier, sour crudes tend to push the pet coke from porous ‘sponge’ coke to ‘shot’ coke (both are terms of the art) with higher concentrations of undesirable impurities: Sulfur, nitrogen, vanadium, nickel, and iron. In some refineries, the shift in coke quality may require a major change in coke markets (e.g. anode to fuel grade) and dramatically decrease coke value. In other refineries, the changes in technology and associated feed changes have decreased the quality of the fuel grade coke with lower volatile matter (VM), gross heating value (GHV), and Hardgrove Grindability Index (GHI). All of these factors have made the fuel grade coke less desirable in the United States, and much of this fuel grade coke is shipped overseas, even with a coal-fired utility boiler on adjacent property. In this manner, the coke value is further decreased.
More importantly, many of these coker technology improvements have substantially reduced the quality of the gas oils that are further processed in downstream catalytic cracking units. That is, the heaviest or highest boiling components of the coker gas oils (often referred to as the ‘heavy tail’ in the art) are greatly increased in many of these refineries (particularly with heavier, sour crudes). In turn, these increased ‘heavy tail’ components cause significant reductions in the efficiencies of downstream catalytic cracking units. In many cases, these ‘heavy tail’ components contain polycyclic aromatic hydrocarbons (or PAHs) that have a high propensity to coke and contain much of the remaining, undesirable contaminants of sulfur, nitrogen, and metals. In downstream catalytic cracking units (e.g. FCCUs), these undesirable contaminants of the ‘heavy tail’ components may significantly increase contaminants in downstream product pools, consume capacities of refinery ammonia recovery/sulfur plants, and increase emissions of sulfur oxides and nitrous oxides from the FCCU regenerator. In addition, these problematic ‘heavy tail’ components of coker gas oils may significantly deactivate cracking catalysts by increasing coke on catalyst, poisoning of catalysts, and/or blockage or occupation of active catalyst sites. Also, the increase in coke on catalyst may require a more severe regeneration, leading to suboptimal heat balance and catalyst regeneration. Furthermore, the higher severity catalyst regeneration often increases FCCU catalyst attrition, leading to higher catalyst make-up rates, and higher particulate emissions from the FCCU. As a result, not all coker gas oil is created equal. In the past, refinery profit maximization computer models (e.g. Linear Programming Models) in many refineries assumed the same value for gas oil, regardless of quality. This tended to maximize gas oil production in the cokers, even though it caused problems and decreased efficiencies in downstream catalytic cracking units. Some refineries are starting to put vectors in their models to properly devalue these gas oils that reduce the performance of downstream process units.
In addition, prior art of the coking process has been dedicated to technologies that improve the economics of the coking process, particularly improvements in the product yields (i.e. higher values). In this regard, crude oil companies have attempted to introduce catalysts in the coker feed to increase distillate yield and reduce coke production in the delayed coking process.
U.S. Pat. No. 4,394,250 describes a delayed coking process in which small amounts of cracking catalyst and hydrogen are added to the hydrocarbon feedstock before it is charged to the coking drum to increase distillate yield and reduce coke make. The catalyst settles out in the coke and does not affect the utility of the coke.
U.S. Pat. No. 4,358,366 describes a delayed coking process in which small amounts of hydrogen and a hydrogen transfer catalyst, a hydrogenation catalyst, and/or a hydrocracking catalyst are added to a coker feed consisting of shale oil material and a petroleum residuum to enhance yields of liquid product.
This known prior art adds catalyst to the coker feed, which has chemical and physical characteristics that create challenging problems and disadvantages. The coker feed of the known art is typically comprised of very heavy aromatics (e.g. asphaltenes, resins, etc.) that have theoretical boiling points greater than 1050° F. As such, the primary reactants exposed to the catalysts of the known art are heavy aromatics with a much higher propensity to coke (vs. crack), particularly with the exposure to high vanadium and nickel content in the coker feed. Furthermore, mineral matter in the coker feed tends to act as a seeding agent that further promotes coking. Calcium, sodium, and iron compounds/particles in the coker feed have been known to increase coking, particularly in the coker feed heater. From a physical perspective, the primary reactants of the known art are a very viscous liquid (some parts semi-solid) at the inlet to the coker feed heater. Throughout the heater and into the coke drums the feed becomes primarily hot liquid, solids (from feed minerals and coking), and vapors (from coker feed cracking and vaporization of some coker feed components). The temperature of the multi-phase material at the inlet to the coke drum is typically between 900 and 950 degrees Fahrenheit. Consequently, the catalyst particles in the coker feed of the known art are exposed to a severe coking environment with coker feed components that have a high propensity to coke. Since the catalyst tends to act as a seeding agent, the catalyst of the known art would likely be surrounded by coke before it has an opportunity to perform its intended purpose to promote cracking of coker feed materials. In commercial applications of the known art (i.e. catalyst in the delayed coker feed), excessive coking problems have been noted. The known art attempts to have the catalyst generally address all of the coker feed as its target reactants. Many of these chemical compound (e.g. coker feed components) have a high propensity to coke or readily crack in the traditional thermal environment of the delayed coking process. However, a more prudent approach may be to focus the use of catalyst in the liquid and foam layers, where coker feed components and cracked intermediates have difficulty either cracking or coking in the traditional thermal environment of the delayed coking process. As such, an active catalyst with proper characteristics can be more effective in these reaction zones, but getting active catalyst to these moving layers in an efficient and cost effective manner is very challenging. Injecting catalyst from the bottom apparently doesn't work. Injecting active catalyst from above of the foam/liquid layers has its own challenges, as well. Injecting catalyst alone form the top of the drum would likely create substantial vapor overcracking with much greater production of low value fuel gas due to direct exposure of cracking catalyst to the product vapors. Initially, the Applicant developed an option using a modified drill stem that would inject an active catalytic additive into the foam/liquid layers from close proximity (e.g. within 5-10 feet) by leading these rising layers up the coking vessel (e.g. ‘coke drum’ is herein defined as a type of coking vessel in the delayed coking process technology). However, this approach became somewhat cumbersome and costly with significant safety concerns associated with consistent sealing the modified drill stem with high coke drum operating pressures (e.g. >15 psig).
It has been discovered that a more efficient approach is to use carrier fluid(s) and/or quench agent(s) with the catalyst to take advantage of the condensation of traditional recycle components to limit exposure of catalyst(s) to the product vapors and protect its activity until it reaches the foam/liquid layers. An added benefit is the potential cracking of these traditional recycle materials to favorably change the reaction equilibriums to offset the reduction in liquid yields associated with lower coking vessel (e.g. coke drum) outlet temperatures. In addition, the quench also provides added benefits of reducing external recycle, while terminating vapor overcracking reactions and reducing the production of low value fuel gas.
In contrast, an exemplary embodiment of a catalyst of the present invention may only be exposed to target reactants downstream of the primary coking zone of the coking process, which has substantially different chemical and physical characteristics than the target reactants of the known art. These target reactants include coker feed components (or cracked intermediate hydrocarbons) in the liquid layer above the coke that have difficulty cracking or coking in the thermal operating environment of the traditional coking process. In an exemplary embodiment of the present invention, a catalytic additive reduces the activation energy required to crack (preferably) or coke these coker feed components (or cracked intermediate hydrocarbons). In this manner, the catalyst reduces the amount of heat needed for similar endothermic cracking (preferably) and/or coking reactions (i.e. same reactants and same products) and promotes cracking (preferably) and/or coking reactions for coker feed components (or cracked intermediate hydrocarbons) that have difficulty cracking or coking in the thermal operating environment of the traditional coking process.
In an exemplary embodiment of the present invention, a catalytic additive is introduced into the coking process in a manner differentiated over the known art that reduces coke production and increases the yields of ‘cracked liquids,’ while addressing problems noted above and improving operations and maintenance of the coking process. Though examples of the present invention may primarily address issues of the delayed coking process, some utility and advantages of exemplary embodiments of the present invention may also be applied to the fluid coking and flexicoking processes.
Accordingly, exemplary embodiments of the present invention may improve product yields, operations, and maintenance of a coking process, while alleviating problematic operational and product issues. Exemplary embodiments are described herein, which may address or provide examples of (1) the benefits of introducing effective catalyst(s) into the primary reaction zones of a delayed coking process, (2) the primary advantages of exemplary embodiments of the present invention, and (3) the broad coverage of the intellectual property associated with the exemplary embodiments. U.S. Publication No. 2006/0032788 is incorporated herein by reference in its entirety.
One exemplary embodiment of the present invention may improve product yields of a coking process: (1) Reduce coke production, (2) Increase ‘cracked liquids’ (e.g. distillates), (3) Increase high-value gases (e.g. BBs and PPs), and/or (4) Decrease low-value fuel gas.
One exemplary embodiment of the present invention may provide control of the amounts of problematic components in the coker recycle to the coker heater and/or ‘heavy tail’ components going to the fractionators of these coking processes and into the resulting gas oils of the coking processes, while maintaining high coker process capacities. By doing so, an exemplary embodiment of the present invention may significantly reduce catalyst deactivation in downstream catalytic units (cracking, hydrotreating, and otherwise) by significantly reducing coke on catalyst and the presence of contaminants that poison or otherwise block or occupy catalyst reaction sites. An exemplary embodiment of the present invention may more effectively use the recycle and/or gas oil ‘heavy tail’ components by (1) selective catalytic cracking them to increase ‘cracked liquids’ yields and/or (2) selective catalytic coking of them in a manner that improves the quality of the pet coke for anode, electrode, fuel, or specialty carbon markets. In addition, an exemplary embodiment of the present invention may reduce excess cracking of hydrocarbon vapors (commonly referred to as ‘vapor overcracking’ in the art) by quenching such cracking reactions, that convert valuable ‘cracked liquids’ to less valuable gases (butanes and lower) that are typically used as fuel (e.g. refinery fuel gas).
One exemplary embodiment of the present invention selectively cracks or cokes the highest boiling hydrocarbons in the product vapors to reduce coking and other problems in the coker and downstream units. An exemplary embodiment of the present invention may also reduce vapor overcracking in the coker product vapors. Both of these properties of an exemplary embodiment of the present invention may lead to improved yields, quality, and value of the coker products.
In addition, an exemplary embodiment of the present invention may provide a superior means to increase coking process capacity without sacrificing coker gas oil quality. In fact, an exemplary embodiment of the present invention may improve gas oil quality, the quality of the petroleum coke, and/or the quality of downstream products, while increasing coker capacity. The increase in coking capacity also leads to an increase in refinery throughput capacity in refineries where the coking process is the refinery bottleneck.
An exemplary embodiment of the present invention may increase sponge coke morphology to avoid safety issues with shot coke production and ‘hot spots’ and steam ‘blowouts’ during coke cutting. In many cases, this may be done without using valuable capacity to add slurry oil or other additives to the coker feed to achieve these advantages. Another exemplary embodiment of the present invention may catalytically crack and/or catalytically coke components in the coker feed that neither crack or coke in the traditional coking process and avoid ‘hot spots’ and/or steam ‘blowouts’ due to inefficient cooling of these hot liquids at the end of the coking cycle
In addition, an exemplary embodiment of the present invention may also be used to enhance the quality of the petroleum coke by selective catalytic coking of the highest boiling hydrocarbons in the coke product vapors to coke with preferred quantities and qualities of the volatile combustible materials (VCMs) contained therein.
An exemplary embodiment of the present invention may also allow crude slate flexibility for refineries that want to increase the proportion of heavy, sour crudes without sacrificing coke quality, particularly with refineries that currently produce anode grade coke. Furthermore, an exemplary embodiment of the present invention may reduce shot coke in a manner that may improve coke quality sufficiently to allow sales in the anode coke market.
Finally, an exemplary embodiment of the present invention may provide a superior means to improve the coking process performance, operation, and maintenance, as well as the performance, operation, and maintenance of downstream catalytic processing units.
All of these factors potentially improve the overall refinery profitability. Further utility and advantages of this invention will become apparent from consideration of the drawings and ensuing descriptions.
In view of the foregoing, an exemplary embodiment of the present invention may be an improvement of coking processes that adds an additive to the coking vessel of a coking process to convert (e.g. via catalytic cracking) intermediate, heavy hydrocarbon species (i.e. created by thermal cracking of coker feed) of the coking process to improve the quality and/or value of the products of the coking process. The basic technology contemplated in U.S. Provisional Application No. 60/866,345 uses this additive (often containing catalyst) to crack or coke high boiling point compounds in the coking vessel of a coking process. As indicated, ‘conversion includes cracking these high boiling point compounds to lighter hydrocarbons,’ including ‘naphtha, gas oil, gasoline, kerosene, jet fuel, diesel fuel, & heating oil.’ In U.S. application Ser. No. 12/377,188, various other exemplary embodiments are discussed, including the use of the additive (with or without catalyst) as a quenching agent to reduce vapor overcracking reactions. Much discussion is devoted to what is considered one of the best modes of operation for the present invention, which uses the additive (with catalyst) to selectively convert (preferably cracking) the highest boiling point materials in the product vapors of the coking process to minimize the coker recycle and/or significantly improve the quality of the heavy coker gas oil. By converting these problematic components to lighter liquid products and/or higher quality petroleum coke, this exemplary embodiment of the present invention potentially provides the greatest upgrade in value for the coking process: (1) increasing liquid yields, while decreasing coke yields, (2) minimizing coker recycle by creating an ‘internal recycle,’ (3) improving quality of coker gas oil and/or petroleum coke, (3) reducing ‘vapor overcracking’ and associated loss of liquids to lower value gases, (4) reducing totspots' and/or ‘blowouts’ & associated safety issues and costs, (5) increasing coker capacity and potentially refinery capacity, (6) increasing crude slate flexibility, and/or (7) improving operation & maintenance of the coking process and downstream processing units.
In this application, further information is provided to help differentiate the present invention over known art, including comparative data from pilot plant tests. In these pilot plant tests, the injection of the catalyst additive into the coking vessel of the current invention and the addition of catalyst to the coker feed of the known art were compared to a common baseline with no catalyst. In two sets of test data, the catalyst addition of the known art showed a substantial increase in coking and a significant reduction in liquid yields. In contrast, the injection of the catalytic additive in an exemplary embodiment of the present invention showed a substantial reduction in coke yield and a significant increase in liquids production. Thus, these tests clearly demonstrate differentiation of the present invention over the known art. These results are likely due to the major differences in the chemical and physical nature of the primary reactants, exposed to the catalyst in the known art versus the current invention. That is, the catalyst in the coker feed of the known art is exposed to coker feed components that have a high propensity to coke. In contrast, the catalyst of an exemplary embodiment of the present invention is only exposed to target reactants downstream of the primary coking zone. These target reactants include coker feed components (or cracked intermediate hydrocarbons) in the liquid layer above the coke that have difficulty cracking or coking in the thermal operating environment of the traditional coking process. In an exemplary embodiment of the present invention, a catalytic additive reduces the activation energy required to crack (preferably) or coke these coker feed components (or cracked intermediate hydrocarbons). In this manner, the catalyst reduces the amount of heat needed for similar endothermic cracking (preferably) and/or coking reactions (i.e. same reactants and same products) and promotes cracking (preferably) and/or coking reactions for coker feed components (or cracked intermediate hydrocarbons) that have difficulty cracking or coking in the thermal operating environment of the traditional coking process. Further analyses are provided in this regard. Finally, an improvement to the present invention is claimed relative to the use of the quenching effect of the additive to condense the highest boiling point compounds onto the catalyst(s), thereby improving the catalyst selectivity. That is, the additive can focus the catalysts exposure to the highest boiling point compounds in the product vapors. With a properly designed catalyst to crack these highest boiling point materials, this mechanism can effectively increase the catalyst's selectivity, thereby increasing its efficiency and reducing catalyst requirements and costs.
An exemplary embodiment of the present invention is a coker process technology that effectively introduces a low-cost catalyst(s) in a manner that improves production of valuable transportation fuels and product gases, while reducing low-value fuel gas and petroleum coke by-products. In many cases, an exemplary embodiment of the present invention can also help resolve certain problems with the operation and maintenance of traditional, refinery coker process units. In some cases, an exemplary embodiment of the present invention can increase the coker capacity by effectively debottlenecking coker sections without major capital costs. The remainder of this introduction will describe the impact of the catalyst and its unique injection on the delayed coking process, including thermodynamic and reaction kinetic perspectives. As discussed below, the presence of a catalyst from an exemplary embodiment of the present invention in the delayed coking process can favorably change the chemical reaction mechanisms, the coke drum temperature profile, and the vapor-liquid equilibriums in the coke drum during the coking cycle of the traditional delayed coking process.
The operational principles of exemplary embodiments of the present invention, as well as technical and economic viability, have been proven in pilot plant tests, designed to demonstrate, improve, and optimize the Technology. These pilot plant tests showed substantial reductions of coke (6-12+ wt. %) and fuel gas (up to 15 wt. %). In many tests, these reductions translated primarily into increases in gas oil and naphtha production with some increases in higher value gases (e.g. PPs and BBs with higher olefin content).
One of the key features of an exemplary embodiment of the present invention is the unique injection of the active catalyst(s) to achieve its desired benefits. In the past, catalyst has been introduced into the coking process through addition to the coker feed. Apparently, the catalyst was not effective for cracking the heaviest components of the coker feed (that have a very high propensity to coke) and the catalyst particles acted as seeding agents and caused more coke production, rather than less. In contrast, the exemplary embodiments of the present invention have several injection options, but introduce the active catalyst above the rising coke level in reaction zones, where the catalyst can be more effective. The preferred arrangement injects the active catalyst with a carrier oil that maintains catalyst activity and acts as partial quench that condenses traditional recycle components onto the catalyst, creating intimate contact for desired cracking reactions.
First and foremost, a properly designed catalyst lowers activation energies for both cracking and coking reactions in the coking vessel (e.g. coke drum) during the coking cycle. With an exemplary embodiment of the present invention, catalysts can preferentially lower cracking reaction activation energies by up to one third in repetitive reactions in both the vapor and liquid phases of the coking vessel. With the long residence time of the coking cycle (up to hours), each catalyst particle can conceivably reduce the activation energy for many repetitive cracking reactions in the vapor and preferably in the liquid phase, until the catalyst particle participates in enough coking reactions to consume it in the coke. In the preferred injection option, the an exemplary embodiment of the present invention also quenches excessive cracking of the vapor products (i.e. vapor overcracking) while condensing the heaviest recycle components onto the catalyst, creating an internal recycle and intimate contact with the catalyst to provide more selective use of the catalyst. Since these recycle components are catalytically cracked to smaller hydrocarbon molecules with higher vapor pressures, most of these traditional recycle components exit the coking vessel even at lower drum outlet temperatures.
In many cases, the catalyst of an exemplary embodiment of the present invention will also lower the activation energy for coking reactions in an advantageous manner. For example, certain heavy hydrocarbons in some coker feeds are resistant to cracking or coking in the strictly thermal reactions environment of the traditional delayed coking process. As the coking cycle proceeds, these materials tend to increase in concentration and pool in the liquid layer on top of the coke. At the end of the coking cycle much of this material has neither cracked or coked, and has been noted to cause problems with dangerous ‘hot spots’ in the decoking cycle. Since these heavy hydrocarbons tend to have a much greater propensity to coke (vs. crack), the catalyst of an exemplary embodiment of the present invention (designed to preferentially crack) would also reduce the activation energy for coking reactions, resulting in the coking of these materials, and mitigating ‘hot spot’ issues. In addition, coking these materials also has the advantage of substantially reducing the concentration of these materials in the liquid layer, improving the reaction equilibriums and the kinetics of other thermal and catalytic reactions in the liquid layer.
The lower activation energies provided by the catalyst also increases the efficiency of the delayed coker operation, particularly in the use of heat. In general, the catalyst can be used to perform the same degree of cracking and coking reactions (catalytically and thermally) with less heat input or perform more of these endothermic reactions (preferably cracking vs. coking) with the same heat input. In most cases, the latter would be preferred. In some cases, the catalyst in an exemplary embodiment of the present invention would also help promote polymerization coking, a type of exothermic coking that polymerizes the aromatic sheet derivatives of the asphaltenes present in the coker feed. The catalyst tends to crack off asphaltene side chains more quickly and efficiently to allow the derivative aromatic sheets close enough physical proximity to promote their polymerization. All of these thermodynamic and reaction kinetic properties of this new reactor system in the coking vessel can have favorable effects on the heat balance and the temperature profile in the coking vessel during the coking cycle.
With more efficient use of heat and the possible increase in heat in the coking vessel via exothermic reactions, an exemplary embodiment of the present invention can favorably affect the temperature profile of the coking vessel. As noted before, the preferred injection option uses the carrier oil as a quench that reduces vapor overcracking and the excess production of low-value gas and creates an internal recycle with intimate contact with the catalyst. Though this causes a slightly lower temperature at the coking vessel outlet, the additional catalytic reactions (e.g. catalytically cracking of traditional recycle components) create a different reaction chemistry and chemical equilibrium, that provides improved product yields (e.g. less fuel gas & more transport fuels) even with a slightly lower coking vessel outlet temperature. This phenomenon is not suggested by traditional delayed coking models and operations. In addition, the more efficient use of heat and possible exothermic reaction heat may create higher temperatures in the liquid layer, but more likely is consumed in additional endothermic, thermal reactions.
Reaction Equilibriums, Thermodynamics, and Kinectics:
Thermodynamics/Kinetics: Present Invention Vs. Traditional Delayed Coking
All of the analyses above are based on the thermodynamic and kinetic principles of traditional delayed coking. A fair evaluation of test data should also consider the impact of the catalyst on thermodynamic and kinetic models for traditional delayed coking processes. After all, the presence of a catalyst from an exemplary embodiment of the present invention in the delayed coking process can substantially change the chemical reaction mechanisms, the coke drum (e.g. a type of coking vessel) temperature profile, and the vapor-liquid equilibriums in the coke drum during the coking cycle of the traditional delayed coking process.
First and foremost, the properly designed catalyst will lower activation energies for both cracking and coking reactions in the coking vessel during the coking cycle. With the an exemplary embodiment of the present invention, catalysts can preferentially lower cracking reaction activation energies by up to one third in repetitive reactions in both the vapor and liquid phases in the coking vessel (e.g. coke drum). With the long residence time of the coking cycle (hours), each catalyst particle can conceivably reduce the activation energy for many repetitive cracking reactions in the vapor and preferably in the liquid phase, until the catalyst particle participates in enough coking reactions to consume it in the coke. In its preferred embodiment, the present invention also quenches excessive cracking of the vapor products (i.e. vapor overcracking) while condensing the heaviest recycle components onto the catalyst, creating an internal recycle and intimate contact with the catalyst to provide more selective use of the catalyst. Since these recycle components are catalytically cracked to smaller hydrocarbon molecules with higher vapor pressures, most of these traditional recycle components exit the coking vessel even at lower drum outlet temperatures.
In many cases, the catalyst of an exemplary embodiment of the present invention will also lower the activation energy for coking reactions in an advantageous manner. For example, certain heavy hydrocarbons in some coker feeds are resistant to cracking or coking in the strictly thermal reactions environment of the traditional delayed coking process. As the coking cycle proceeds, these materials tend to increase in concentration and pool in the liquid layer on top of the coke. At the end of the coking cycle much of this material has neither cracked or coked, and has been noted to cause problems with dangerous ‘hot spots’ in the decoking cycle. Since these heavy hydrocarbons tend to have a much greater propensity to coke (vs. crack), the catalyst of an exemplary embodiment of the present invention (designed to preferentially crack) would still reduce the activation energy for coking reactions to have this material coke, and mitigate ‘hot spot’ issues. In addition, coking these materials would also have the advantage of substantially reducing its concentration in the liquid layer to improve reaction equilibriums and kinetics of other thermal and catalytic reactions in the liquid layer.
The lower activation energies provided by the catalyst in an exemplary embodiment of the present invention makes the delayed coker operation more efficient, particularly in the use of heat. In general, the catalyst could be used to perform the same degree of cracking and coking reactions (catalytically and thermally) with less heat input or perform more of these endothermic reactions (preferably cracking vs. coking) with the same heat input. In most cases, the latter would be preferred. In some cases, the catalyst of an exemplary embodiment of the present invention would also help promote polymerization coking, a type of exothermic coking that polymerizes the aromatic sheet derivatives of the asphaltenes present in the coker feed. The catalyst tends to crack off asphaltene side chains more quickly and efficiently to allow the derivative aromatic sheets close enough physical proximity to promote their polymerization. All of these thermodynamic and reaction kinetic properties of this new reactor system in the coking vessel can have favorable effects on the heat balance and the temperature profile in the coking vessel during the coking cycle.
With more efficient use of heat and the possible increase in heat in the drum via exothermic reactions, an exemplary embodiment of the present invention can favorably affect the temperature profile of the coking vessel. As noted before, the preferred embodiment uses the carrier oil as a quench that reduces vapor overcracking and the excess of low-value gas and creates an internal recycle with intimate contact with the catalyst. Though this causes a lower temperature at the coking vessel outlet, the additional catalytic reactions (e.g. catalytically cracking traditional recycle components) create a different reaction chemistry and chemical equilibrium, that provides improved product yields (e.g. less fuel gas & more transport fuels) even with a lower coking vessel outlet temperature. This phenomenon would not be suggested by traditional delayed coking models. In addition, the more efficient use of heat and possible exothermic reaction heat may create higher temperatures in the liquid layer, but more likely would be consumed in additional endothermic, thermal reactions. If the temperature would become too high for any reason, the outlet temperature of the coker feed heater could be cut back slightly and gain associated operational and maintenance benefits.
The catalyst of an exemplary embodiment of the present invention in the delayed coking process not only favorably changes the reaction mechanisms and the temperature profile, but may also favorably impacts the chemical reaction equilibriums and kinetics. As noted above, the catalytic cracking of traditional recycle components to smaller molecules with higher vapor pressures changes the vapor-liquid equilibrium at the coking vessel outlet in such a way that these materials still exit the coking vessel, even at lower coking vessel exit temperatures. In addition, the catalytic coking of the feed components that resist thermal cracking or thermal coking reduces the concentration of these materials in the liquid layer, improving the chemical reaction equilibriums and kinetics for other thermal and catalytic cracking or coking reactions. Other examples of improved chemical reaction equilibriums and kinetics exist, as well.
In conclusion, traditional thermodynamic models of the delayed coking process may not be sufficient to accurately predict what happens in the delayed coking process using an exemplary embodiment of the present invention due to the factors described above. These traditional coker models will not likely have accurate thermodynamic assumptions (vectors) as well as reaction activation energies. These traditional thermodynamic coker models may need to be modified with additional vectors or modified coefficients to address the substantially different chemical reactions and environment associated with an exemplary embodiment of the present invention.
The catalyst of an exemplary embodiment of the present invention in the delayed coking process not only favorably changes the reaction mechanisms and the temperature profile, but also favorably impacts the chemical reaction equilibriums and kinetics. As noted above, the catalytic cracking of traditional recycle components to smaller molecules with higher vapor pressures changes the vapor-liquid equilibrium at the coking vessel outlet in such a way that these materials still exit the coking vessel, even at slightly lower coking vessel exit temperatures. In addition, the catalytic coking of the feed components that resist thermal cracking or thermal coking reduces the concentration of these materials in the liquid layer, improving the chemical reaction equilibriums and kinetics for other thermal and catalytic cracking or coking reactions. Other examples of improved chemical reaction equilibriums and kinetics include better reaction conditions for catalytic cracking of aromatics.
In conclusion, an exemplary embodiment of the present invention introduces an active catalyst to the delayed coking process in a manner that substantially changes the chemical reactions and environment.
In addition to the novel features and advantages mentioned above, other benefits will be readily apparent from the following descriptions of the drawings and exemplary embodiments.
The desired additive components consist of catalyst(s) alone or in combination with seeding agent(s) 220, excess reactant(s) (222), quenching agent(s) (224), carrier fluid(s) (226) or any combination thereof. This example of the current invention may include a means 300 to produce catalysts of the desired properties and characteristics for the purposes of exemplary embodiments of the current invention, including appropriate physical and chemical properties and/or characteristics. The means to produce catalysts of the desired properties and characteristics are shown as 300 in
Means of controlling the temperature, pressure, flow rate, and additive introduction characteristics are provided to regulate the injection of the additive into the coking vessel above the vapor/liquid interface in the coking vessel during the coking cycle. An exemplary embodiment of the current invention may include a means 320 to control temperature(s) of the additive, including simply as comprising a heating coil in a mixing tank with heat media (e.g. steam, hot liquids, etc.) flow control and insulated piping. Means of additive temperature control 320 is shown in
An exemplary embodiment of the current invention may also include a means 330 to pressurize the additive above the coking vessel pressure, and may be simply various types of pumps (e.g. positive displacement pumps, progressive cavity pumps, etc.). Means of pressurizing additive 330 is shown in
An exemplary embodiment of the current invention may also include a means 340 to control additive pressure(s), such as simply as a pressure meter with a feedback control system. Means of controlling additive pressure 340 is shown in
An exemplary embodiment of the current invention may also include a means 350 to control flow rate(s), including a pressurized injection system, such as simply as comprising a pump and/or a flow meter with a feedback control system and/or a modified anti-foam system. Means of controlling additive flow rate(s) 350 is shown in
An exemplary embodiment of the current invention may also include a means 360 to control the “additive introduction,” which may be a part of a pressurized injection system, such as simply as comprising various spray nozzle(s) for these purposes. Means of controlling additive introduction(s) 360 is shown in
An exemplary embodiment of the current invention may also include a means 370 to control the “additive introduction characteristics.” Means of controlling additive introduction characteristic(s) 370 is shown in
Exemplary embodiments of the current invention anticipate the development and improvements of various means (represented by means 300, 310, 320, 330, 340, 350, 360, 370, and any combination thereof) to implement and/or improve the quality, efficiency, and/or utility of embodiments of the current invention over time. These various means to implement/improve embodiments of the current invention are (1) not all requirements to achieve the basic advantages of embodiments of the current invention in every application, (2) may be implemented in a different order than shown in
In addition, hydrogen and/or hydrogen generating compound(s) are optionally injected (218) into the coker feed between the fractionator and the process heater, in the heater, between the heater and the coking vessel, in the coking vessel, or any combination thereof. The hydrogen and/or hydrogen released is then transferred to the primary reaction zone in the coking vessel (preferably the liquid layer) to enhance catalytic reactions (preferably cracking reactions). In this manner, the coke yields are reduced further relative to the prior art and liquid yields are increased further relative to the prior art.
An exemplary embodiment of the current invention may also include a means of selecting or minimizing additive system size to locate the system as close to the coke drums as possible to limit line pressure drop and settling of catalyst in the injection system. Other means of minimizing system size to locate it as close to coking vessels as possible include, but should not be limited to, (1) providing continuous mixing device in additive injection system, (2) design additive injection system with major injection components, having optimal weight and system footprint (e.g. vertical pump mounting) to allow locating close to coking vessels (e.g. on drilling deck), (3) using modified anti-foam system to limit new components or systems, and/or (4) any combination thereof.
DETAILED DESCRIPTION OF EXEMPLARY EMBODIMENT(S)Catalyst Benefits in a Delayed Coker:
In this section, the benefits of catalyst in a delayed coker are discussed. First, the definition of a catalyst is a substance that increases the rate of a chemical reaction by reducing the activation energy, preferably without being consumed by the reactions. Catalysts can be a solid, a liquid, and/or a gas, and normally is not changed by the reaction process. In
In the traditional delayed coking process, most of the chemical reactions occur in the coke drums. Cracking, Coking, Polymerization, Hydrogenation, and Dehydrogenation reactions occur to a certain degree. Of these, cracking and coking are the predominant reactions. The reaction mechanisms in the cracking and coking reactions are similar, with both being endothermic, free-radical reactions. Again, the introduction of an effective catalyst will reduce the energy required to complete these reactions.
In the traditional delayed coking process, complex chemical changes occur in the coke drums. Competing chemical reactions can basically classified into thermal cracking reactions and various type of coking reactions. The thermal cracking reactions can be further classified into thermal liquids cracking and thermal vapor overcracking. Thermal liquids cracking is basically the thermal cracking of very heavy hydrocarbons in the coker feed to gas oils, naphtha, PPs (Propanes & propenes), and BBs (butanes and butenes), which are typically the most valuable products in the coker. Thermal vapor overcracking is basically the excessive thermal cracking of these valuable products to lower valued fuel gas. Coking reactions can be classified into thermal coking, asphaltic coking, and polymerization coking. Thermal coking is purely endothermic, free radical condensation of heavy hydrocarbons (typically aromatic) to form needle coke. Asphaltic coking are isothermic reactions, involving the desolutation of asphatenes from the cracking of their solvent (resins/aromatic oils), resulting in shot coke. The combination of thermal coking and asphaltic coking results in sponge coke. The ratio of asphaltic to thermal coking determines the degree of sponge vs. shot coke, which depends on the chemical composition of the reactants involved. Finally, polymerization coking is an exothermic coking reaction that results in shot coke or dense sponge coke, depending on the characteristics of the reactants.
Coking reactions can be classified into thermal coking, asphaltic coking, and polymerization coking. Thermal coking is purely endothermic, free radical condensation of heavy hydrocarbons (typically aromatic) to form needle coke. Asphaltic coking are isothermic reactions, involving the desolutation of asphaltenes from the cracking of their solvent (resins/aromatic oils), resulting in shot coke. The combination of thermal coking and asphaltic coking results in sponge coke. The ratio of asphaltic to thermal coking determines the degree of sponge vs. shot coke, which partially depends on the chemical composition of the reactants involved. That is, a low ratio produces sponge coke; high ratio produces shot coke; and near zero produces needle coke, from a highly aromatic coker feed with minimal asphaltene content. Finally, polymerization coking is an exothermic coking reaction that results in shot coke or dense sponge coke, depending on the characteristics of the reactants.
Polymerization coking can occur with coker feeds having high asphaltene content. The macrostructure of asphaltenes vary considerably, but can be characterized by layers of aromatic sheets that are connected by aliphatic chains. In traditional delayed coking, the thermal cracking of the asphaltenes is somewhat slow and inefficient, leaving aliphatic chains on the aromatic sheets. That is, the asphaltene derivatives in the traditional delayed coker typically retain sufficient aliphatic chains that don't allow the aromatic sheets to get close enough with the proper orientation to promote polymerization coking. As such, the residual aliphatic chains keep the aromatic sheets separated and prevent polymerization coking coking. In the presence of effective catalyst(s), the activation energy for the initial cracking of asphaltenes is significantly reduced. Thus, catalytic cracking significantly increases the speed and efficiency of removing aliphatic side chains from the aromatic sheets of the asphaltenes. As a result, the aromatic sheets can achieve the proper distance (e.g. <4 A°) and orientation to increase polymerization coking significantly.
In an exemplary embodiment of the present invention, introducing an effective catalyst to the proper reaction zones modifies the reaction chemistry and creates a new set of competing reactions in the coke drum of the delayed coking process during the coking cycle. In this manner, an exemplary embodiment of the present invention adds catalytic cracking and catalytic coking, as well as polymerization coking in the coke drums.
If the heat input remains constant, the catalyst reduces the amount of heat required to complete the same reactions that occur in the traditional delayed coker with only thermal reactions (vs. catalytic). As such, the catalytic cracking reduces the amount of heat used in thermal cracking making it available for additional reactions or increase temperature in the drum. Additional reactions, preferably catalytic cracking vs. thermal cracking and thermal coking, would likely occur.
As discussed previously, catalytic cracking of asphaltenes and their derivatives promotes exothermic polymerization coking that will increase the heat available for additional reactions or increase local temperatures. This increase in polymerization coking will likely decrease the levels of endothermic, thermal coking and isothermic, asphaltic coking of the traditional coker. Thus, the promotion of polymerization coking (caused by the efficient catalytic cracking of asphaltenes and their derivatives) has an added benefit of additional heat for additional endothermic reactions: catalytic cracking, thermal cracking, catalytic coking, and thermal coking.
Even catalytic coking can be very advantageous relative to the traditional delayed coking process. That is, catalytic coking reduces the amount of energy that would otherwise be needed in thermal coking, increasing heat available for other reactions to be completed.
In addition, an effective catalyst of an exemplary embodiment of the current invention can cause a significant reduction in coke hot spots, a dangerous operational problem at many delayed coking units handling troublesome coker feeds. Apparently, this happens when: (1) Certain liquid compounds from the coker feed or derivatives of other chemical compounds have high activation energies that do not allow either cracking or coking. (2) These chemicals tend to increase in concentration in the liquid layer throughout the coking cycle, and reduce the concentration of other chemical compounds that would normally have activation energies that are sufficiently low to crack or coke but their concentration has been lowered by the chemical compounds of item (1) and these reactions are inhibited. (3) Chemical compounds (regardless of source) that do not crack or coke during the coking cycle may have vapor pressures that don't allow them to escape the coke drum. Thus, these chemical compounds tend to remain liquid as the coke cools and form hot spots in the coke, when cooling media comes in contact with masses of these chemical compounds (4) Thus, the presence of the appropriate catalyst can lower the activation energies to allow coking or preferably cracking of these materials before the end of the coking cycle and substantially reduce coke hot spots. Also, the reduction of these materials (Caused by an effective catalyst) is believed to cause indirect, positive impacts (reducing the concentration of essentially inert chemicals in the liquid layer) on chemical equilibriums of certain chemical reactions, increasing the driving force for these favorable reaction improving the completion of cracking and coking reactions. In this manner, even catalytic coking can be helpful in the coking vessel.
As discussed previously, effective catalyst(s) of an exemplary embodiment of the present invention (introduced to the coke drum of the delayed coker during the coking cycle) cause reduction of activation energies for either coking and preferably cracking reactions. These catalytic cracking and catalytic coking reaction require substantially less heat (e.g. 30%) than their thermal cracking and thermal coking counterparts in the traditional delayed coker for the same reactions. With the potential increase in heat available from the exothermic polymerization coking, the net increase in available heat can increase the liquid temperature, particularly for the same levels of cracking and coking. Preferably, the additional heat available will be used in additional cracking reactions in most cases, instead of increasing the liquid layer temperature.
In summary, the basic benefit of introducing effective catalyst(s) in the primary reaction zones of the coke drum of the delayed coking process during its coking cycle is the increase in available heat in the coke drum, primarily the liquid layer. This increase in available heat will likely lead to an increase in coke drum temperature and/or a significant increase in endothermic chemical reactions of heavy hydrocarbons in the liquid/foaming layers that would otherwise form coke into lighter hydrocarbon products of higher value.
As will be seen later, incremental catalyst addition (e.g. 0.1-0.3 wt. % of coker feed) creates incremental improvements in conversion of coke yields to higher yields of gas oils, naphtha, and/or Liquid Petroleum Gas (LPG), comprising propanes and propenes (PPs) and/or butanes and butenes (BBs). The optimal amount of catalyst will depend on many factors at each refinery, including catalyst costs. Commercial demonstrations of the present invention with the use of refinery Linear Programming (LP) model will be most productive in determining the most effective catalyst and proper usage.
Also, not just any catalyst will work. In fact, off the shelf FCCU catalysts with substantial zeolite concentrations (e.g. high Z/M ratios) will likely be counterproductive. That is, high activity and small pore size (e.g. 6-9 microns) in any catalyst will likely cause more cracking of lighter liquids to less valuable gasses. For example, a normal FCCU catalyst would likely crack LCGO to fuel gas. In addition, the best performing catalyst (higher yields conversion) with higher costs may not be the most cost effective catalyst.
Primary Advantages of Exemplary Embodiments of the Present InventionAdvantages of exemplary embodiments of the present invention include its use of various process options, system design, and operating flexibility to maximize value for each refinery, according to its LP model results. Of course, refinery models vary considerably from refinery to refinery due to various factors, including refinery process configuration, crude slate, etc. Within the delayed coker, the maximum value typically includes (1) maximizing cracking (thermal & catalytic) of the coker feed and its derivatives that would otherwise form coke, (2) minimizing conversion (e.g. vapor overcracking) of gas oils and coker naphtha to low-value fuel gases (e.g. fuel gas), and (3) maximizing cracking of traditional recycle components on the first pass to reduce external recycle. Finally, it should be noted that an exemplary embodiment of the present invention may not create a mini fluid catalytic cracking unit (FCCU) in the coker. Most refineries already have sufficient capacity to crack gas oils to naphtha in a more efficient manner, the FCCU. However, it is recognized that many of the same reactions that occur in an FCCU may also occur in an exemplary embodiment of the present invention, and some of them are not desirable (e.g. consuming catalyst activity for reactions that the FCCU performs more efficiently). In contrast, a major focus of an exemplary embodiment of the present invention may be catalytic cracking of the heavier hydrocarbons (not necessarily aromatic in nature or the highest boiling point compounds) in the gas and liquid phases that would otherwise form coke
In order to achieve the maximum value, the catalyst(s) must be used efficiently. In this regard, an advantage of an exemplary embodiment of the invention is to introduce effective, active catalyst(s) with the desired characteristics to the liquid and foaming layers. At the same time, the exposure of the active catalyst to the vapors needs to be optimized. The conversion of gas oils and naphtha to lower value fuel gas must be limited. However, an increase in olefins production (PPs and BBs) can be very advantageous in many refineries with LPG recovery or nearby chemical plants that require light olefins as feedstocks. In addition, an increase in light olefins (e.g. higher octane) may help improve coker naphtha quality and value.
Desired characteristics for the optimal catalyst(s) are not limited to a particular type of catalyst. In fact, the present invention anticipates that effective catalyst(s) may be developed for this purpose. Key factors should be considered
(1) Catalyst with higher porosity for intimate contact with larger hydrocarbons (and maintain passageways for cracked components). In this regard, Lower Z/M ratio is often preferable. Due to different reaction conditions in the coker liquid layer (e.g. the longer residence time, temperature, etc.), the traditional relationship of Z/M in the FCCU do not necessarily apply in this application.
(2) Due to the difference in chemical reaction conditions, the optimal activity level of the catalyst will likely be different (vs. FCCU) for various chemical compounds (e.g. chemical equilibrium for the cracking of aromatics is often favored at lower temperatures (800-850° F.) and longer residence time).
(3) Inexpensive catalysts can include regeneration and/or treatment of used catalysts. For example, FCCU catalysts (Particularly for heavy feeds) are typically regenerated before being flushed from the unit as equilibrium catalyst (e.g. as fresh catalyst is added). Also, this equilibrium catalyst can be further treated (e.g. thermally) to increase the porosity for the larger hydrocarbon molecules.
(4) Catalyst fluidization in the liquid layer can maximize residence time (e.g. contact with fluids). The liquid layer in the delayed coker tends to be fairly turbulent due to the velocity of the product vapors and liquids as they rise through the restricted flow areas at the top of the coke (e.g. branches). As a result, catalyst that has characteristics (e.g. density, particle size distribution (PSD), etc.) to maintain fluidization are preferable. Optimal PSD is preferable to maintain fluidization vs. product vapor entrainment.
In many cases, off the shelf catalysts can be counter-productive. For example, FCCU catalyst with high Z/M ratios has low porosity that is more conducive to creating excessive vapor overcracking than cracking very heavy hydrocarbons.
Preventing catalyst entrainment in the coker product vapors is usually a major concern with refineries. Characteristics of the catalyst(s) and injection are key. Most commercial cokers are designed with very low vapor velocity in the upper drum to create a disengagement section to limit the entrainment of coke fines. In many cases, catalyst with sufficient density can inhibit catalyst entrainment by classifying catalyst size over 60 microns. In addition, injection nozzle design and operating conditions can play a substantial role in limiting entrainment. Injection nozzle manufacturers can use Computational Fluid Dynamics to determine the proper catalyst size and injection characteristics to minimize carryover. Other tests can also be used for assistance in injection nozzle design.
As is common with many patent applications, this application seeks the broadest coverage that distinguishes over the known art. A preferred embodiment may be viewed to be a most favorable application of the present invention. Various other embodiments are provided as alternative means to achieve the stated advantages of exemplary embodiments of the present invention.
In previous patents by this inventor, broad coverage of various facets has been achieved. Previous patents have covered a combination of various components in the catalytic additive. Also, a variety of catalyst types and treatments have been covered, along with a variety of process options and locations for the additive additions. A chemical means of adding the additive has been shown to be effective in getting the active catalyst to the desired reaction zones, without creation of excess fuel gas. In exemplary embodiments of the present invention, a mechanical means of introducing the catalytic additive directly to the primary reaction zone (preferably in the liquid layer) of the coke drum and introducing hydrogen and/or hydrogen generating compounds into those same primary reaction zones to substantially enhance the catalytic reactions caused by the introduction of the catalytic additive to the coke drum of the delayed coking process during the coking cycle.
The chemical means of adding active catalyst(s) to the liquid/foaming layers uses a carrier oil that acts as a quench to limit the exposure of the product vapors to the active catalyst(s). The localized quench caused by the partial evaporation of this carrier oil does two things. First, it condenses the heaviest hydrocarbons on the catalyst, (which act as a seeding agent) creating intimate contact between the traditional recycle materials (e.g. target reactants) and the catalyst, increasing selectivity of the catalyst reactions. This condensed recycle material also serves to protect the active catalyst until it settles to the liquid layer, where the condensed recycle materials tend to revaporize and crack to smaller, more valuable hydrocarbons. Secondly, this localized cooling quenches (thermally and chemically) the vapor overcracking reactions and minimizing the conversion of gas oils and naphtha to excessive fuel gas.
In an example of a preferred embodiment, the catalyst with the condensed recycle components settle to the liquid layer, which is significantly hotter than the product vapors above it. As such, the heavy recycle components tend to revaporize and catalytically crack to significantly smaller hydrocarbons that have sufficiently higher vapor pressures to exit the coking vessel even with lower drum outlet temperatures. In this manner, the quench effect of the carrier oil favorably impacts two reaction mechanisms and changes the reaction equilibriums, kinetics and thermodynamics.
Even after cracking these traditional recycle components, the catalyst will typically continue to settle into the liquid layer that has sufficient turbulence to keep the properly designed catalyst(s) in a fluidized state for significant portions of time. With this longer residence time, the catalysts will likely have sufficient contact and time to promote catalytic cracking of other heavy hydrocarbons that would otherwise form coke.
In the implementation of an example of a preferred embodiment, proper injection of the catalytic additive into the coking vessel above the liquid layer is key to create the contact and proper conditions for the desired catalytic reactions.
Thus, an example of a preferred embodiment of the present invention favorably modifies the reaction chemistry in the coke drum of the traditional delayed coking process. First, the condensation of the traditional recycle components onto the catalyst creates and internal recycle that causes catalytic cracking of this recycle materials. Second, the intimate, turbulent contact with the heavy hydrocarbons in the liquid/foam layers, causing catalytic cracking of feed components that would otherwise form coke. Thirdly, catalytic coking of heavy hydrocarbons that normally resists both cracking and coking can significantly reduce ‘coke hot spots.’ Both catalytic cracking and catalytic coking make more heat available for additional cracking and coking reactions, both thermal and catalytic. Finally, the quench effect also reduces vapor overcracking, creating less fuel gas and more gas oils and naphtha.
In the preferred embodiment of the present invention, the changes in reaction chemistry (e.g. equilibriums) changes the traditional coker relationship between product distribution and drum outlet temperature. In the traditional delayed coking operation, the drum outlet temperature is controlled to the highest level possible with a given heat balance. This is done to maintain the process equilibrium that provides highest level of gas oil and recycle escaping the coking vessel and avoiding coke formation. However, the introduction of catalyst changes this process equilibrium by lowering the activation energy required to crack the traditional recycle components. Thus, the traditional recycle (with intimate catalyst contact) cracks to smaller, lighter hydrocarbons the have a high enough vapor pressure to exit the coking vessel even at lower coking vessel outlet temperatures. Finally, the quench reduces vapor overcracking by terminating undesirable thermal cracking reactions.
Based on actual data from a test run in a west coast U.S. refinery, the quench effect is roughly 10.7 of for every 1 wt. % of the coker feed. This was based on 1700 BPD of Light Coker Gas Oil (LCGO) used in the vapor line quench in a 52,100 BPD of coker feed. In this case, the drum outlet temperature was cooled from 806° F. to a fractionator inlet temperature of 771° F.
The preferred carrier oils with their estimated quench effect are shown below:
FCCU Decanted Slurry Oil: Available at 30% U.S.Chemically Inert?: <60% Vaporized: <6° F./1 Wt.%
FCCU Heavy Cycle Oil: Available at >75% U.S.?Chemically Inert?: >85% Vaporized: 9° F./1 Wt.%
Heavy Coker Gas Oil: Available at 100% U.S.Loss of Activity: 100% Vaporized: 10.7° F./1 Wt.%
If needed, the vapor line quench is reduced to offset this coking vessel quench and maintain proper heat balance in the delayed coking units.
Another way of evaluating the change in the traditional relationship of coking vessel outlet temperature and coker product distribution is to estimate the change in coking vessel outlet temperature for the same level of cracking and coking reactions. That is, the coking vessel outlet temperature would actually go up at a constant yield rate due to the excess heat available from the reduction in activation energies attributed to the catalyst(s).
The drum outlet temperature can be estimated by calculating the heat in the feed which is primarily dependent on the heater outlet temperature. In the traditional coking unit, the coking vessel outlet temperature is roughly determined by the heat in the feed minus the heat absorbed by the endothermic reactions and add the heat gained from exothermic polymerization coking. In the preferred embodiment of the present invention, the catalytic cracking and catalytic coking absorbs less heat than the thermal cracking and thermal coking, and exothermic heat from polymerization coking is more likely to be gained. Thus, the coking vessel outlet temperature would be higher for a constant reaction rate.
In conclusion, the net effect of the preferred embodiment of the present invention is very positive. That is, the increase in LP Model value from the changes in product distribution far outweigh the negative impact of decreasing the coking vessel outlet temperatures. This was confirmed in the pilot plant studies, where improved product yields were achieved despite drum outlet temperatures reduced by >15° F. due to the carrier oil quench effect.
Additive PackageExemplary embodiments of the present invention typically include an additive package to be injected in the coke drum of a delayed coking process, during the coking cycle. Said additive package comprises of (1) catalyst(s), (2) seeding agent(s), (3) excess reactant(s), (4) quenching agent(s), (5) carrier fluid(s), or (6) any combination thereof. The optimal design of additive package may vary considerably from refinery to refinery due to differences including, but not limited to, coker feed blends, coking process design & operating conditions, coker operating problems, refinery process scheme & downstream processing of the heavy coker gas oil, and the pet coke market & specifications.
In view of the foregoing description, the following presents further detailed description of exemplary embodiments of the present invention. This description of exemplary embodiments is divided into two major subjects: General Exemplary Embodiment and Other Embodiments. These embodiments discuss and demonstrate the ability to modify (1) the quality or quantity of the additive package and/or (2) change the coking process operating conditions to optimize the use of an exemplary embodiment of the present invention to achieve the best results in various coking process applications.
Description and Operation of Exemplary Embodiments of the Invention General Exemplary EmbodimentDescription of Drawings:
The specific design of this system and the optimal blend of additive components will vary among refineries due to various factors. The optimal blend may be determined in pilot plant studies or commercial demonstrations of this invention (e.g. using an existing anti-foam system, modified for higher flow rate). Once this is determined, one skilled in the art may design an exemplary system to reliably control the quality and quantity of the additive components to provide a consistent blend of the desired mixture. This may be done on batch or continuous basis. One skilled in the art may also design and develop operating procedures for the proper piping, injection nozzles, and pumping system, based on various site specific factors, including (but not limited to) (1) the characteristics of the additive mixture (e.g. viscosity, slurry particle size, etc.), (2) the requirements of the additive injection (e.g. pressure, temperature, etc.) and (3) facility equipment requirements in their commercial implementation (e.g. reliability, safety, etc.).
Description of Additive:
The additive in an exemplary embodiment of the present invention may be a combination of components that have specific functions in achieving the utility of a respective exemplary embodiment. As such, the additive is not just a catalyst in all applications of the present invention, though it can be in many of them. In some embodiments, there may be no catalyst at all in the additive. In certain applications, an embodiment of the present invention would use a quench agent to quench the vapor overcracking in the product vapors to decrease the production of low value fuel gas. In other applications, another embodiment of the present invention would include the injection of only quench agent(s) and/or carrier fluid(s) that may improve the distillate yield of the coking process. Thus, the term ‘catalytic additive’ does not apply in all embodiments, but could in many embodiments. The following discussion provides further breadth of the possible additive components, their utility, and potential combinations.
Said additive package comprises of (1) catalyst(s), (2) seeding agent(s), (3) excess reactant(s), (4) quenching agent(s), (5) carrier fluid(s), or (6) any combination thereof. The optimal design of additive package may vary considerably from refinery to refinery due to differences including, but not limited to, coker feed blends, coking process design & operating conditions, coker operating problems, refinery process scheme & downstream processing of the heavy coker gas oil, and the pet coke market & specifications.
Catalyst(s):
In general, the catalyst comprises any chemical element(s) or chemical compound(s) that reduce the energy of activation for the initiation of the catalytic cracking or catalytic coking reactions of the high boiling point hydrocarbons (e.g. heavy coker gas oil or side chains of polycyclic aromatic hydrocarbons) in the product vapors and liquid layer in the coking vessel. In general, the catalyst(s) may be a solid, a liquid, a gas, and/or a multi-phase component. The catalyst may be designed to favor cracking (preferably) or coking reactions and/or provide selectivity in the types of heavy hydrocarbons that are cracked or coked. For the sake of this discussion throughout the Description, ‘heavy hydrocarbons’ refer to hydrocarbons that are heavier than at least the highest 50 weight percent (e.g. boiling point of simulated distillation laboratory results) of the heavy coker gas oil with average boiling points exceeding 700 degrees Fahrenheit. In addition, the catalyst may be designed to aid in coking heavy hydrocarbons to certain types of coke, including coke morphology, quality & quantity of volatile combustible materials (VCMs), concentrations of contaminants (e.g. sulfur, nitrogen, and metals), or combinations thereof. Finally, the catalyst may be designed to preferentially coke via an exothermic, asphaltene polymerization reaction mechanism (vs. endothermic, free-radical coking mechanism). In this manner, the temperature in the coking vessel may increase, and potentially increase the level of thermal and/or catalytic cracking or coking.
In an exemplary embodiment of the present invention, characteristics of this catalyst typically include a catalyst substrate with a chemical compound or compounds that perform the function stated above. In many cases, the catalyst will have acid catalyst sites that initiate the propagation of positively charged organic species called carbocations (e.g. carbonium and carbenium ions), which participate as intermediates in the coking and cracking reactions. Since both coking and cracking reactions are initiated by the propagation of these carbocations, catalyst substrates that promote a large concentration of acid sites are generally appropriate. Also, the porosity characteristics of the catalyst would preferably allow the large, aromatic molecules easy access to the acid sites (e.g. Bronsted or Lewis). For example, fluid catalytic cracking catalyst for feeds containing various types of residua often have higher mesoporosity to promote access to the active catalyst sites. In addition the catalyst is preferably sized sufficiently large (e.g. >40 microns) to avoid entrainment in the vapors exiting the coking vessel. Preferably, the catalyst and condensed heavy hydrocarbons have sufficient density to settle to the vapor/liquid interface. In this manner, the settling time to the vapor/liquid interface may provide valuable residence time in cracking the heavy hydrocarbons, prior to reaching the vapor/liquid interface. For heavy aromatics with the high propensity to coke, catalytic coking may take place during this settling period and/or after reaching the vapor/liquid interface. At the vapor/liquid interface, an active catalyst may preferably continue promoting catalytic cracking (preferably) and/or coking reactions to produce desired cracked liquids and coke (e.g. asphaltene polymerization). Sizing the catalyst (e.g. 40 to >200 microns) to promote fluidization for the catalyst in the coking vessel may enhance the residence time of the catalyst in the vapor zone.
Many types of catalysts may be used for this purpose. Catalyst substrates may be comprised of various porous natural or man-made materials, including (but should not be limited to) alumina, silica, zeolite, activated carbon, crushed coke, or combinations thereof. These substrates may also be impregnated or activated with other chemical elements or compounds that enhance catalyst activity, selectivity, or combinations thereof. These chemical elements or compounds may include (but should not be limited to) nickel, iron, vanadium, iron sulfide, nickel sulfide, cobalt, calcium, magnesium, molybdenum, sodium, associated compounds, or combinations thereof. For selective coking, the catalyst will likely include nickel, since nickel strongly enhances coking. For selective cracking, many of the technology advances for selectively reducing coking may be used. Furthermore, increased levels of porosity, particularly mesoporosity, may be beneficial in allowing better access by these larger molecules to the active sites of the catalyst. Though the catalyst in the additive may improve cracking of the heavy hydrocarbons to lighter liquid products, the catalyst ultimately ends up in the coke. As such, the preferred catalyst formulation would initially crack heavy hydrocarbons to maximize light products (e.g. cracked liquids) from gas oil ‘heavy tail’ components, but ultimately promote the coking of other heavy aromatics to alleviate pitch materials (with a very high propensity to coke vs. crack) in the coke that cause ‘hot spots.’ It is anticipated that various catalysts will be designed for the purposes above, particularly catalysts to achieve greater cracking of the highest boiling point materials in the liquid layer in the coking vessel and coking process product vapors. With certain chemical characteristics of these materials and properly designed catalysts, substantial catalytic conversion of these materials to cracked liquids may be accomplished (e.g. >50 Wt. %).
The optimal catalyst or catalyst combinations for each application will often be determined by various factors, including (but not limited to) cost, catalyst activity and catalyst selectivity for desired reactions, catalyst size, and coke specifications (e.g. metals). For example, coke specifications for fuel grade coke typically have few restrictions on metals, but low cost may be the key issue. In these applications, spent or regenerated FCCU catalysts or spent, pulverized, and classified hydrocracker catalysts (sized to prevent entrainment) may be the most preferred. On the other hand, coke specifications for anode grade coke often have strict limits for sulfur and certain metals, such as iron, silicon, and vanadium. In these applications, cost is not as critical. Thus, new catalysts designed for high catalyst activity and/or selectivity may be preferred in these applications. Alumina or activated carbon (or crushed coke) impregnated with nickel may be most preferred for these applications, where selective coking is desirable.
An exemplary embodiment of the current invention may include a means (e.g., 300 in
The amount of catalyst used will vary for each application, depending on various factors, including the catalyst's activity and selectivity, coke specifications and cost. In many applications, the quantity of catalyst will be less than 15 weight percent of the coker feed. Most preferably, the quantity of catalyst would be between 0.05 weight percent of the coker feed input to 3.0 weight percent of the coker feed input. Above these levels, the costs will tend to increase significantly, with diminishing benefits per weight of catalyst added. As described, this catalyst may be injected into the vapors in the coking vessel (e.g. above the vapor/liquid interface in the coke drum during the coking cycle of the delayed coking process) by various means, including pressurized injection with or without carrier fluid(s): hydrocarbon(s), oil(s), inorganic liquids, water, steam, nitrogen, or combinations thereof.
Injection of cracking catalyst alone may cause undesirable effects in the coker product vapors. That is, injection of a catalyst without excess reactant(s), quenching agent(s), or carrier oil(s), may actually increase vapor overcracking and cause negative economic impacts.
Seeding Agent(s):
In general, the seeding agent comprises any chemical element(s) or chemical compound(s) that enhance (1) the intimate contact of condensed heavy hydrocarbons from the coker product vapors with the catalytic components of the additive, (2) the settling of components of the additive (e.g. catalytic components) to the liquid layer, and/or (3) the formation of coke by providing a surface for the coking reactions or the development of coke crystalline structure (e.g. coke morphology) to take place. The seeding agent may be a liquid droplet, a semi-solid, solid particle, or a combination thereof. The seeding agent may be the catalyst itself or a separate entity. Sodium, calcium, iron, and carbon particles (e.g. crushed coke or activated carbon) are known seeding agents for coke development in refinery processes. These and other chemical elements or compounds may be included in the additive to enhance coke development in the coking vessel, if appropriate.
The amount of seeding agent(s) used will vary for each application, depending on various factors, including (but not limited to) the amount of catalyst, catalyst activity and selectivity, coke specifications and cost. In many applications, catalytic cracking will be more desirable than catalytic coking. In these cases, seeding agents that enhance catalytic coking will be minimized, and the catalyst will be the only seeding agent. However, in some cases, little or no catalyst may be desirable in the additive. In such cases, the amount of seeding agent will be less than 15 weight percent of the coker feed. Most preferably, the quantity of seeding agent would be between 0.05 weight percent of the coker feed input to 3.0 weight percent of the coker feed input. In many cases, the amount of seeding agent is preferably less than 3.0 weight percent of the coker feed. As described, this seeding agent may be injected into the coking vessel (e.g. above the vapor/liquid interface in the coke drum during the coking cycle of the delayed coking process) by various means, including (but not limited to) pressurized injection with or without carrier fluid(s): hydrocarbon(s), oil(s), inorganic liquids, water, steam, nitrogen, or combinations thereof.
Excess Reactant(s):
In general, the excess reactant comprises of any chemical element(s) or chemical compound(s) that react with the heavy hydrocarbons (1) to promote mechanisms (e.g. catalytic or thermal) for cracking the heavy hydrocarbons and/or (2) to form petroleum coke. In the additive, the excess reactant may be a gas, liquid, a semi-solid, solid particle or a combination thereof. In the promotion of catalytic cracking, hydrogen and/or other light hydrocarbons may be very effective as an excess reactant. In an exemplary embodiment of the present invention, hydrogen may be injected with the additive (or as separate streams) in the target reaction zone(s) (e.g. modified drill stem). Alternatively, compounds that release hydrogen (e.g. at higher temperatures) may be added to the coker feed (e.g. before or after the coker feed heater). It is also anticipated that other chemical compounds that react with the target reactants to promote cracking reaction mechanisms (e.g. catalytic or thermal) could be developed for these purposes, as well.
In the case of hydrogen and/or hydrogen generating compounds, getting the hydrogen to the primary reaction zone prior to reacting is a key issue. In many cases, adding hydrogen to the additive package may be counterproductive, because the hydrogen may likely participate in vapor overcracking in the upper part of the coking vessel. For this reason special options to add hydrogen separately from the additive need to be seriously considered. This is why several options are noted in
In the promotion of coke formation, various types of excess reactants may be used for this purpose. Ideally, the excess reactant would contain very high concentrations of chemical elements or chemical compounds that react directly with the heavy hydrocarbons in the liquid layer and vapors within the coking vessel. Availability or cost issues may make the use of existing process streams with high aromatics content desirable, preferably over 50 weight percent aromatics. In addition, the characteristics of the excess reactant would preferably include (but not require), high boiling point materials, preferably greater than 800 degrees Fahrenheit and high viscosity materials, preferably greater than 5000 centipoise. Excess reactant(s) of choice may include carbon or aromatic organic compounds. However, in many cases, the practical choice for excess reactant(s) would be decanted slurry oil from the refinery's Fluid Catalytic Cracking Unit (FCCU). In certain cases, the slurry oil may still contain spent FCCU catalyst (i.e., not decanted). Also, slurry oil could be brought in from outside the refinery (e.g. nearby refinery). Other excess reactants would include, but should not be limited to, gas oils, extract from aromatic extraction units (e.g. phenol extraction unit in lube oil refineries), coker feed, bitumen, other aromatic oils, crushed coke, activated carbon, or combinations thereof. These excess reactants may be further processed (e.g. distillation) to increase the concentration of desired excess reactants components (e.g. aromatic compounds) and reduce the amount of excess reactant required and/or improve the reactivity, selectivity, or effectiveness of excess reactants with the targeted heavy hydrocarbons.
The amount of excess reactant used will vary for each application, depending on various factors, including (but not limited to) the amount of catalyst, catalyst activity and selectivity, coke specifications and cost. In many applications, the quantity of excess reactant will be sufficient to provide more than enough moles of reactant to coke all moles of heavy hydrocarbons that are not cracked to more valuable liquid products. Preferably, the molar ratio of excess reactant to uncracked heavy hydrocarbons would be 0.5:1 to 3:1. However, in some cases, little or no excess reactant may be desirable in the additive. In many cases, the amount of excess reactant will be less than 15 weight percent of the coker feed. Most preferably, the quantity of excess reactant would be between 0.05 weight percent of the coker feed input to 3.0 weight percent of the coker feed input. For gaseous hydrogen, the quantity should be in the range of about 30 to about 600 SCF per barrel of the coker feed. As described, this excess reactant may be injected into the coking vessel (e.g. above the vapor/liquid interface in the coke drum during the coking cycle of the delayed coking process), the coker feed, and/or the transfer line between the heater and coking vessel by various means, including (but not limited to) pressurized injection with or without carrier fluid(s): gas oils hydrocarbon(s), oil(s), inorganic liquids, water, steam, nitrogen, hydrogen, or combinations thereof.
Carrier Fluid(s):
In general, a carrier fluid comprises any fluid that makes the additive easier to inject into the coking vessel. The carrier may be a liquid, gas, hydrocarbon vapor, or any combination thereof. The preferred carrier fluid(s) for each application will often be determined by various factors, including (but not limited to) cost, refinery process scheme, proximity to the additive addition system, and carrier fluid(s) characteristics (e.g. boiling range, viscosity, density). In many cases, the carrier will be a fluid available at the coking process, such as gas oils, lighter liquid process streams, or even coker feed. In many cases, gas oil at the coking process is the preferable carrier fluid. However, preferred carrier fluid(s) may include process streams from other process units at the refinery. In many cases, decanted slurry oil from the Fluid Catalytic Cracking Unit (FCCU) provides very good carrier oil characteristics (e.g. boiling range and high aromatic content), and many cokers already have this process stream previously piped up to the coking process unit for coker feed additive to control coke morphology. Similarly, FCCU heavy Cycle Oil (HCO) and FCCU Light Cycle Oil (LCO) often provide good carrier oil characteristics, and is already piped to many coker units for flush oil for seals on many pumps in the coking process unit. In certain refineries other factors may make other carrier fluid(s) desirable. As such, carrier fluid(s) would include, but should not be limited to, gas oils, other hydrocarbon(s), other oil(s), inorganic liquids, water, steam, nitrogen, or combinations thereof. With all carrier fluid(s), additional quench agent(s) (described below) can be added, as needed.
In an exemplary embodiment using a catalytic additive of the present invention, the ‘Ideal’ carrier fluid(s) would primarily (1) protect the activity of the catalyst until the catalyst reaches its targeted reactants (e.g. heavy hydrocarbons in the liquid layer, the foam layer, and product vapors). (2) limit exposure of active catalyst to high value product vapors that could be catalytically cracked (i.e. catalytic overcracking) to low value fuel gas, (3) quench thermal vapor overcracking reactions as it evaporates to prevent the conversion of valuable ‘cracked liquids’ (e.g. gas oils, naphtha, etc.) in the product vapors to low value fuel gas, and (4) condense highest boiling point compounds in the product vapors (e.g. traditional coker recycle) as it evaporates onto the catalyst to create intimate contact between the catalyst and these target heavy hydrocarbon reactants. With the intimate contact with the catalyst, the condensed coker recycle components will likely crack to smaller molecules that have sufficiently high vapor pressure to escape the coking vessel, even at lower coking vessel outlet temperatures. The evaporation of these reaction products may cause a localized temperature drop that condenses the highest boiling point compounds in the product vapors (e.g. traditional coker recycle) creating intimate contact with the catalyst. Ideally, this process (condensation, cracking reaction, evaporation, condensation, cracking reaction, evaporation, etc.) will be repeated many times as the catalyst settles to the foam/liquid layers. As such, the ‘ideal’ carrier fluid(s) may assist in these processes, to the extent possible, and optimize the functions described above.
With experience over time, for a given application, one skilled in the art is anticipated to be able to create the ‘ideal’ carrier fluid(s) in the coker unit, elsewhere in the refinery, outside the refinery or any combination thereof. That is, the ‘ideal’ carrier fluid(s) for a given application may actually be created in the refinery in various process units or the combining of different refinery process streams. For example, an ‘ideal’ carrier oil for an exemplary embodiment of the present invention may have a boiling range of 800 to 830 degrees Fahrenheit from the coker fractionator or other fractionator/distillation towers in nearby process unit. In many cases, this carrier oil would provide high coverage of the active catalyst sites until it evaporated as the catalyst settled toward the liquid/foam layers, where temperatures typically exceed 830° F. However, this carrier oil would have less vaporization in the upper coking vessel to quench the vapor overcracking and cause less condensation of internal recycle of the heavy recycle materials. Another alternative may be the ‘extra heavy coker gas oil’ produced by a technology that has extra fractionator trays and a separate draw for traditional recycle components or the heaviest components of the heavy coker gas oil (HCGO). Similarly, an extra product draw-off could be added to the vacuum distillation column that would provide a carrier oil with a boiling range of 800 to 830 degrees Fahrenheit. The use of a condensed liquid from the vapor line between the coking vessels and the fractionator may also provide an ‘ideal’ carrier oil that contains primarily traditional coker recycle material, along with some condensed vapor line quench oil. This type of carrier oil could provide the protection of the catalyst from coking vessel vapors, while creating intimate contact between a target reactant and the catalyst with a lower quench level than other carrier oils. Other examples of the production and use of the ‘Ideal Carrier Oil’ may include (but should not be limited to) the use of crude oil and/or coker feed, alone or combined with other process streams. These examples of ‘ideal carrier oils’ may be appropriate for limited applications.
The amount of carrier fluid(s) used will vary for each application, depending on various factors, including (but not limited to) the amount of catalyst, catalyst activity and selectivity, coker process limitations, coke specifications, and cost. In many applications, little or no carrier is actually required, but desirable to make it more practical or cost effective to inject the additive into the coking vessel. The quantity of carrier fluid(s) will be sufficient to improve the ability to pressurize the additive for injection via pump or otherwise. In many cases, the amount of excess reactant will be less than 15 weight percent of the coker feed. Most preferably, the quantity of carrier fluid would be between 0.5 weight percent of the coker feed input to 3.0 weight percent of the coker feed input. As described, this carrier may help injection of the additive into the coking vessel (e.g. above the vapor/liquid interface in the coke drum during the coking cycle of the delayed coking process) by various means, including (but not limited to) pressurized injection with or without carrier fluid(s): gas oils hydrocarbon(s), oil(s), inorganic liquids, water, steam, nitrogen, or combinations thereof.
Quenching Agent(s):
In general, a quenching agent comprises any fluid that has a net effect of further reducing the temperature of the product vapors in the coking vessel. The quenching agent(s) may be a liquid, gas, hydrocarbon vapor, or any combination thereof. Many refinery coking processes use a quench in the vapors downstream of the coking vessel (e.g. coke drum). In some cases, this quench may be moved forward into the coking vessel. In many cases, a commensurate reduction of the downstream quench may be desirable to maintain the same heat balance in the coking process. In many cases, gas oil available at the coking process will be the preferred quench. However, quenching agents would include, but should not be limited to, gas oils, FCCU slurry oils, FCCU cycle oils, other hydrocarbon(s), other oil(s), inorganic liquids, water, steam, nitrogen, or combinations thereof.
The amount of quench used will vary for each application, depending on various factors, including (but not limited to) the temperature of the vapors in the coking vessel, the desired temperature of the vapors exiting the coking vessel, and the quenching effect of the additive without quench, characteristics and costs of available quench options. In many applications, the quantity of quench will be sufficient to finish quenching the vapors from the primary cracking and coking zone(s) in the coking vessel to the desired temperature. In some cases, little or no quench may be desirable in the additive. In many cases, the amount of quench will be less than 15 weight percent of the coker feed. Most preferably, the quantity of quench would be between 0.5 weight percent of the coker feed input to 3.0 weight percent of the coker feed input. As described, this quench may be injected into the coking vessel (e.g. above the vapor/liquid interface in the coke drum during the coking cycle of the delayed coking process) as part of the additive by various means, including (but not limited to) pressurized injection with or without carrier fluid(s): gas oils hydrocarbon(s), oil(s), inorganic liquids, water, steam, nitrogen, or combinations thereof. This quench may also be added to the coking vessel separately from the additive.
Additive Combination and Injection:
In an exemplary embodiment of the present invention, an additive mixing system would be used to properly mix the additive components to the desired concentrations and blend consistency. The additive mixing system would combine the 5 components to the degree determined to be desirable in each application (e.g. some components may not be used in a particular application of the additive blend). The additive mixing system may be continuous, batch, periodic, intermittent (e.g. middle of coking cycle only), other operational basis, or any combination thereof. In some applications, certain additive components may be injected separately. In other applications, the additive formulation (e.g. component concentrations) may not be constant and may change throughout the coking cycle or injection period.
An exemplary embodiment of the current invention may include a means (e.g., 310 in
In many cases, all of the additive components would be blended by mixing device(s), preferably to a homogeneous consistency, and heated to the desired temperature (e.g. heated, mixing tank) by a temperature regulation system. For example, the desired temperature (>150 degrees Fahrenheit) of the mixture may need to be increased to maintain a level of viscosity for proper pumping characteristics and fluid nozzle atomization characteristics.
An exemplary embodiment of the current invention may also include a means (e.g., 320 in
The mixed additive, at the desired temperature, may be pressurized (e.g. via pump or pressurized fluid) to a pressure level sufficiently higher than the coking vessel operating pressure to allow for the proper pressure drop across the piping and atomizing nozzle to achieve the desired flow and spray characteristics.
An exemplary embodiment of the current invention may also include a means (330 in
In an exemplary embodiment of the present invention, the additive addition system will effectively use measurement device(s) and control(s) to maintain the appropriate profiles throughout the addition system for temperature, pressure, and flow rates.
An exemplary embodiment of the current invention may also include a means (e.g., 340 in
An exemplary embodiment of the current invention may also include a means (e.g., 350 in
At the desired operating pressure, the mixed additive may be injected (e.g. via atomizing injection nozzle) into the coking vessel at the desired level above the primary cracking and coking zones. The additive addition system may be continuous, intermittent, periodic (e.g. middle of coking cycle only), batch injection (all at once per coking cycle), other operational basis, or any combination thereof. An exemplary embodiment of the current invention may also include a means (e.g., 360 in
An exemplary embodiment of the current invention may also include a means (e.g., 370 in
The injection points into the coking vessel can vary from coking unit to coking unit, due to site specific factors, including (but not limited to) (1) current coking vessel design and operation, (2) coking vessel mechanical configuration, (3) additive addition system design and operation, and (4) piping distance (e.g. pipe rack path) from additive addition system to the coking vessel. An exemplary embodiment of the current invention may also include a means of selecting or minimizing additive system size to locate the system as close to the coking vessels as possible to limit line pressure drop and settling of catalyst in the injection system. Other means of selecting or minimizing system size to locate it as close to coking vessels as possible include, but should not be limited to, (1) providing continuous mixing device in additive injection system, (2) designing additive injection system with major injection components, having optimal weight and system footprint (e.g. vertical pump mounting) to allow locating close to coking vessels (e.g. on drilling deck), (3) using modified anti-foam system to limit new components or systems, and/or (4) any combination thereof.
In many cases, insulated piping will be desirable to keep the additive at the desired temperature. In certain applications, heat tracing or steam jacketing of pipes may be necessary to maintain the desired temperature from the addition system to the coking vessel. Also, injection nozzles (though not required) will be desirable in many cases to evenly distribute the additive across the cross sectional profile of the product vapor stream in the coking vessel. The injection nozzles should also be designed to provide the proper droplet size (e.g. 50 to 150 microns) to prevent entrainment of non-vaporized components (e.g. catalyst) in the vapor product gases, exiting the top of the coking vessel (e.g. coke drum). Typically, these injection nozzles would be aimed countercurrent to the flow of the product vapors. The injection velocity should be sufficient to penetrate the vapors and avoid direct entrainment into the product vapor stream. However, the injection nozzles design and metallurgy must take into account the potential for plugging and erosion from the solids (e.g. catalyst) in the additive package, since the sizing of such solids must be sufficient to avoid entrainment in the product vapor stream. Furthermore, the additive addition system can be set up to provide continuous injection, intermittent injection, periodic injection (e.g. middle of coking cycle only), batch injection (all at once per coking cycle), other operational basis, or any combination thereof. Finally, the additive addition system in an exemplary embodiment of the present invention may require additional measurement device(s) and control device(s) to coordinate the injection of two or more additive streams, and/or the use of two or more additive mixing/addition systems.
In another embodiment, said additive components can be added to the coker product vapors in separate process streams. For example, the catalyst can be added separately from a quench agent to selectively condense the highest boiling components in the product vapors. The carrier fluid(s) in said additive may no longer carry other additive components, but may simply become quench oil. This may be preferable in applications (1) where the catalyst is more easily injected in a dry form and/or (2) where a catalyst of a higher temperature is desirable. In this example, the coincidental injection of both the quench agent(s) and the catalyst(s) near the same location may be desirable in a manner that enhances the intimate contact of the catalyst and condensed highest boiling point components of the coker product vapors to increase selectivity of the desired reactions. In another example, hydrogen may be added as a separate process stream, as well. That is, the addition of hydrogen as a separate process stream may be preferable, whether the remaining additive is injected in one process stream or multiple process streams.
In another exemplary embodiment of the present invention, a separate addition of colder catalyst may also be desirable in certain applications. The colder catalyst may be sufficient to condense the highest boiling materials in the product gases to achieve a desired intimate contact with the coke (e.g. selective reaction with catalyst), but the drop in temperature would not normally be sufficient to condense a higher level of the highest boiling materials due to the lack of substantial heat loss from the heat of vaporization in a carrier/quench oil.
In another embodiment of the present invention, the addition of said additive into the vapor line (line 38 in
In another exemplary embodiment of the present invention, part of the said additive could be introduced in the transfer line (see 218 in
In another embodiment, said additive of the present invention could also be added by various mechanical system(s) to the foaming and/or liquid layers below the product vapors of the delayed coker. These mechanical system(s) of adding said additive could be continuous injection, intermittent or periodic injection (e.g. middle of coking cycle only), batch injection (all at once per coking cycle), or any combination thereof. One exemplary mechanical system to achieve this may be a modified drill stem, as shown in
The additive package of an exemplary embodiment of the present invention may also include anti-foam solution that is used by many refiners to avoid foamovers. These antifoam solutions are high density chemicals that typically contain siloxanes to help break up the foam at the vapor/liquid interface by its affect on the surface tension of the bubbles. In many cases, the additive package of an exemplary embodiment of the present invention may provide some of the same characteristics as the antifoam solution; significantly reducing the need for separate antifoam. In addition, the existing antifoam system may no longer be necessary in the long term, but may be modified for commercial trials of an exemplary embodiment of the present invention. In an exemplary embodiment of the present invention, the additive may have substantial anti-foam characteristics on its own and may act as a suitable replacement of traditional anti-foams used in delayed coker applications. In other applications the combination of the additive and traditional anti-foams may be very effective. Among other reasons, the additive of an exemplary embodiment of the present invention may act as a carrier for the traditional anti-foams to carry anti-foam to the foam and liquid surface (vs. going out the drum outlet with product vapor entrainment). In addition, other, more desirable anti-foams may be developed to be combined with the additive to provide a more cost effective solution.
Theory of Operation: Said additive of an exemplary embodiment of the present invention is believed to selectively convert the highest boiling point materials in the product vapors of the coking process by (1) condensing vapors of said highest boiling point materials and increasing the residence time of these chemical compounds in the coking vessel, (2) providing a catalyst to reduce the activation energy of cracking for condensed vapors that have a higher propensity to crack (vs. coke), and (3) providing a catalyst and excess reactant to promote the cracking and/or coking of these materials that have a higher propensity to coking (vs. cracking). That is, the localized quench effect of the additive would cause the highest boiling point components (e.g. heavy hydrocarbons) in the product vapors to condense on the catalyst and/or seeding agent, and cause selective exposure of the heavy hydrocarbons to the catalysts' active sites. If the heavy hydrocarbons have a higher propensity to crack, selective cracking will occur, the cracked liquids of lower boiling point will vaporize and leave the catalyst active site. This vaporization causes another localized cooling effect that condenses the next highest boiling point component. Conceivably, this repetitive process continues until the catalyst reaches the liquid/foam layers of the coking vessel. In the liquid/foam layers, the catalyst (e.g. with or without excess reactant(s)) may continue to promote catalytic cracking of heavy hydrocarbons until its active sites encounter a condensed component that has a higher propensity to coke (vs. crack) in the particular coking vessel's operating conditions or the coking cycle ends. Equilibrium for the catalytic cracking (vs. coking) of heavy aromatics has been shown to favor lower temperatures (e.g. 800 to 850° F. vs. 875 to 925° F.), if given sufficient residence time and optimal catalyst porosity and activity levels. The additive settling time and the time at or below the vapor/liquid interface provide much longer residence times than encountered in other catalytic cracking units (e.g. FCCU). Thus, the ability to crack heavy aromatics may be enhanced by this method of catalytic cracking. Ideally, the additive's active sites in many applications would crack many molecules of heavy hydrocarbons, prior to and after reaching the vapor/liquid interface, before selectively coking heavy aromatic components and being integrated into the petroleum coke. This invention should not be limited by this theory of operation. However, both the injection of this type of additive package and the selective cracking and coking of heavy aromatics are contrary to conventional wisdom and current trends in the petroleum coking processes.
Enhancement of Additive Effectiveness:
It has also been discovered that minor changes in coking process operating conditions may enhance the effectiveness of the additive package. The changes in coker operating conditions include, but should not be limited to, (1) reducing the coking vessel outlet temperature, (2) increasing the coking vessel outlet pressure, (3) reducing the coking feed heater outlet temperature, or (4) any combination thereof. The first two operational changes represent additional means to condense the highest boiling point materials in the product vapors to increase their residence time in the coking vessel. In many cases, the additive package is already lowering the temperature of the product vapors by its quenching effect and the intentional inclusion of a quenching agent in the additive package to increase this quenching effect. However, many coking units have a substantial quench of the product vapors in the vapor line between the coking vessel and the fractionator to prevent coking of these lines. In many cases, it may be desirable to move some of this quench upstream into the coking vessel. In some coking units, this may be accomplished by simply changing the direction of the quench spray nozzle (e.g. countercurrent versus cocurrent). As noted previously, a commensurate reduction in the downstream vapor quenching is often desirable to maintain the same overall heat balance in the coking process unit. If the coking unit is not pressure (compressor) limited, slightly increasing the coking vessel pressure may be preferable in many cases due to less vapor loading (caused by the quenching effect) to the fractionator and its associated problems. Finally, slight reductions of the feed heater outlet temperature may be desirable in some cases to optimize the use of the additive in exemplary embodiments of the present invention. In some cases, reduction of the cracking of heavy aromatics and asphaltenes to these ‘heavy tail’ components may reduce the amount of additive required to remove the ‘heavy tail’ and improve its effectiveness in changing coke morphology from shot coke to sponge coke crystalline structure. In some cases, other operational changes in the coking process may be desirable to improve the effectiveness of some exemplary embodiments of the present invention.
In the practical application of an exemplary embodiment of the present invention, the optimal combination of methods and embodiments will vary significantly. That is, site-specific, design and operational parameters of the particular coking process and refinery must be properly considered. These factors include (but should not be limited to) coker design, coker feedstocks, coker operating conditions (e.g. temperature and pressure profiles in the coking vessel) and effects of other refinery operations.
Use of Additive to Increase Selectivity of Additive Components:
It has been discovered that an additive may be introduced into the vapors of coking vessel of traditional coking processes to condense the vapors of highest boiling point compounds and facilitate contact with components of the additive. Intimate contact of the highest boiling point compounds with catalyst(s), seeding agent(s), excess reactant(s), or any combination of these components contained in the additive will facilitate selective conversion of these highest boiling point compounds of the product vapors. In effect, this condensation mechanism would reduce the amount of the highest boiling point materials in the product vapors from the primary cracking and coking reaction zone(s), which would otherwise pass through as recycle to the coking process heater (potentially reducing coking process capacity) and/or to the fractionation portion of the coking process as the ‘heavy tail’ of the heavy coker gas oil, which potentially reduces the catalyst activity and causes operational problems in downstream catalytic cracking units.
In this discussion and throughout this application, the term ‘highest boiling point compound’ recognizes that the order of boiling points of the condensed compounds or the coking vessel operating temperature at which these compounds condense will not necessarily follow in strict numerical order (e.g. 830 degrees Fahrenheit, 829 degrees Fahrenheit, 828 degrees Fahrenheit, etc.). In practical application, the distribution of additive may not be uniform, causing localized heat conditions that are not uniformly distributed in the vapor space of the coking vessel. Other heat distribution factors will also come into play, as well. Thus, some of the condensed vapors in the coking vessel may actually have lower boiling points than some of the vapors that do not condense, and remain vapors.
In one exemplary embodiment of the present invention, the quenching effect of the additive can be used to condense the highest boiling point compounds of the product vapors onto the catalyst(s) in the additive, thereby improving the catalyst selectivity. That is, the additive can focus the catalysts exposure to the highest boiling point compounds in the product vapors. With a properly designed catalyst to crack these highest boiling point materials, this mechanism can effectively increase the catalyst's selectivity, thereby increasing its efficiency and reducing catalyst requirements and costs.
In another exemplary embodiment of the present invention, the contact of highest boiling point compounds of the product vapors with catalyst(s), seeding agent(s), excess reactant(s), or any combination of these components of the additive can facilitate selective conversion of these highest boiling point compounds. The selective conversion could include catalytic cracking, catalytic coking, thermal cracking, thermal coking, or any combination of these reactions. In some cases, selective coking of these highest boiling point materials to an optimal extent can improve the coke quality sufficiently to leverage the total value of the coke over the lost value of these materials that can reduce coker capacity or cause operating problems and loss of efficiency in downstream processing units. In other cases, maximizing or optimizing coke production may be desirable, such as needle coke or anode coke production facilities.
By condensing these highest boiling point materials of the product vapors, exemplary embodiments of the present invention can essentially create an ‘internal recycle’ that increases the residence time of the heaviest components of the coker recycle and/or part of the HCGO. In addition, this ‘internal recycle’ may also be used to provide intimate contact with the catalyst and make it more selective and efficient, thereby lowering catalyst requirements and costs. However, the catalyst must be designed to effectively crack these very large molecules in the liquid phase, or crack in the gas phase after the catalyst settles to a level in the coking vessel where these highest boiling point materials revaporize due to the higher temperatures or other local sources of heat (e.g. release of heat from condensation of adjacent molecules). The quantity of ‘internal recycle’ depends on various factors, including (1) the coking vessel outlet temperature of the known art, (2) the quantity of catalytic additive and its associated quenching effect, and (3) the quality and quantity of coker recycle and Heavy Coker Gas Oil.
In exemplary embodiments of the present invention, catalytic cracking of the highest boiling point materials in the product vapors of the coking vessel may allow one skilled in the known art to reduce the quantity of traditional coker recycle (i.e. external) and/or reduce the amount of ‘heavy tail’ components in the HCGO. Where the reduction shows up can be optimized by adjusting the end point of the HCGO in the fractionator operation.
This additive selectively removes these highest boiling components from the product vapors in a manner that encourages further conversion (e.g., cracking or coking) of these materials in the coking vessel. Minor changes in coking process operating conditions may enhance the effectiveness of the additive package. The amount of highest boiling point materials that are converted in this manner is dependent on (1) the quality and quantity of the additive package, (2) the existing design and operating conditions of the particular coking process, (3) the types and degree of changes in the coking process operating conditions, and (4) the coking process feed characteristics.
Typically, these highest boiling point materials in the product vapors have the highest molecular weight, have a propensity to coke, and are comprised primarily of heavy hydrocarbons with boiling points exceeding 700° F. These heavy hydrocarbons typically come from the thermal cracking of asphaltenes, resins, and other aromatics in the coker feed. The highest boiling point materials have traditionally ended up in the coker recycle, where it often would coke in the heater or possibly crack some additional side chains. However, with minimal recycle rates to increase coker capacities, many of these materials are destined to be the highest boiling components of the heavy coker gas oil, though some many will still end up in be in the coker recycle. That is, the split between heavy coker gas oil and recycle will depend on the quantity of recycle, which are essentially these materials. As such, the coker operator may modify the coker operation to affect the fate of these highest boiling components: recycle vs. ‘heavy tail’ of the heavy coker gas oil. (For simplicity, the highest boiling materials in the product vapors may be referred to as gas oil ‘heavy tail’ components throughout the remaining discussion, even though some of these materials may go into the coker recycle stream). Furthermore, many other coking process technology improvements have increased the quantity and boiling points of these materials in the gas oil and substantially decreased the quality of the gas oils that are further processed in downstream catalytic cracking units. That is, the heaviest or highest boiling components of the coker gas oils (often referred to as the ‘heavy tail’ in the art) are greatly increased in many of these refineries (particularly with heavier, sour crudes). These increased ‘heavy tail’ gas oil components cause significant reductions in the efficiencies of downstream catalytic cracking units. In many cases, these ‘heavy tail’ components contain much of the remaining, undesirable contaminants of sulfur, nitrogen, and metals. In downstream catalytic units, these additional ‘heavy tail’ components tend to significantly deactivate cracking catalysts by increasing coke on catalyst and/or poisoning of catalysts via blockage or occupation of active sites. In addition, these problematic ‘heavy tail’ components of coker gas oils also may increase contaminants in downstream product pools, consume capacities of refinery ammonia recovery and sulfur plants, and increase FCCU catalyst attrition, catalyst make-up rates, and environmental emissions.
Selective, catalytic conversion of the highest boiling point materials in the coking process product vapors (coker recycle and/or ‘heavy tail’ of the heavy coker gas oil) may be accomplished with exemplary embodiments of the present invention in varying degrees. The selective conversion of these heavy hydrocarbon components may be optimized in an exemplary embodiment of the present invention by (1) proper design and quantity of the additive package and (2) enhancement via changes in the coking process operating conditions.
Description of Additive Reactants:
Exemplary embodiments of the present invention generally introduce a catalytic additive into the coking vessel of the coking process at or above the vapor/liquid interface or, alternatively, at or above the coking interface (i.e. the coke/liquid interface). In this manner, the primary reactants exposed to the catalyst in exemplary embodiments of the present invention are (1) the vapor products resulting from the thermal cracking and thermal coking of the coker feed and (2) essentially coker feed derivatives (also from thermal cracking and thermal coking) in the liquid, emulsion, and foam layers (below the vapor/liquid interface), after the catalyst has settled there. As such, the primary catalytic reactants in exemplary embodiments of the present invention have substantially different chemical and physical characteristics than the reactants of the known art, wherein catalyst is added to the coker feed of the coking process.
The hydrocarbon feed of the coking process is typically a residuum process stream (e.g. vacuum tower bottoms), comprised of very heavy aromatics (e.g. asphaltenes, resins, etc.) that have theoretical boiling points greater than 1050 degrees Fahrenheit. Typical ranges (Wt.%) of SARA for the coker feed components are as follows: 1-10% Saturates, 10-50% Aromatics, 30-60% Resins, and 15-40% Asphaltenes. As such, the primary reactants exposed to the catalysts of the known art are heavy aromatics with a substantially higher propensity to coke, particularly with the exposure to high vanadium and nickel content in the coker feed. Furthermore, mineral matter in the coker feed tends to act as a seeding agent that further promotes coking. Calcium, sodium, and iron compounds/particles in the coker feed have been known to increase coking, particularly in the coker feed heater. Similarly, the catalyst may act as a seeding agent, as well.
From a physical perspective, the primary reactants of the known art (i.e. catalyst in the feed) are a very viscous liquid (some parts semi-solid) at the inlet to the coker feed heater. Throughout the heater and into the coking vessels the feed becomes primarily hot liquid, some solids (from feed minerals and coking), and vapors (e.g. from coker feed cracking). The temperature of the multi-phase material at the inlet to the drum is typically between 900 and 950 degrees Fahrenheit.
In contrast, the catalyst reactants in an exemplary embodiment of the present invention are primarily derivatives (or partially cracked portions) of the coker feed. That is, the reactants that are exposed to the catalyst additive in exemplary embodiments of the present invention are mostly the products of the thermal cracking and thermal coking of the coker feed. The catalyst additive of the exemplary embodiments of the present invention have very limited exposure to coking process feed components, when the catalyst settles to the liquids above the coking interface (e.g. coke/liquid interface) and becomes part of the solid coke. Even here, most of the coker feed has been converted to smaller compounds with lower propensity to coke (vs. coking process feed). Thus, reactants exposed to the catalyst additive of an exemplary embodiment of the present invention are substantially more likely to crack than the components of the coker feed that are exposed to catalysts introduced into the coking process feed in the known art.
The product vapors at or above the vapor/liquid interface in the coking vessel comprise various derivatives of the coker feed components, that are thermally cracked upstream of this point in the coking vessel. In the known art, these product vapors continue to thermally crack until they exit the coking vessel, where they are typically quenched in the vapor line to stop coking and cracking reactions. After fractionation, these product vapors (many condensed) are normally classified by boiling point range into the following groups: gas (less than 90 degrees Fahrenheit), light naphtha (roughly 90 to 190 degrees Fahrenheit), heavy naphtha (roughly 190 to 330 degrees Fahrenheit), Light Coker Gas Oil—LCGO (roughly 330 to 610 degrees Fahrenheit), Heavy Coker Gas Oil—HCGO (roughly 610 to 800 degrees Fahrenheit), and coker recycle (greater than roughly 800 degrees Fahrenheit). The vapor products in the coking vessel can be thought of as having the same boiling point classifications at any point in time that it is exposed to a catalytic additive of an exemplary embodiment of the present invention. However, the vapor products are recognized to have higher proportions of heavier products than what comes from the fractionator due to further thermal cracking in the vapors prior to the vapor line quench and the fractionator. In other words, the further upstream from the fractionator, the higher the proportions of heavier products.
Below the vapor/liquid interface (down to the coking interface and below), the solids, liquids, and vapors comprise mostly chemical compounds of converted coker feed components. As the catalyst in an exemplary embodiment of the present invention settles into the foam and liquid layers, it may be exposed to these solids, liquids and vapors. In many cases, the solid portions represent coke from thermal coking of the coker feed components. The liquid and some semi-solid portions in these layers may contain components of the coker feed, but many of the liquids are likely derivatives (or cracked) components of the coker feed at this point, particularly toward the end of the coking cycle. At this level, the vapors emerging from the coking interface are essentially cracked coker feed components, derivatives of the heavier saturates, aromatics, resins, and asphaltenes in the coking process feed that have theoretical boiling points greater than 1050 degrees Fahrenheit. Conceivably, the catalyst of exemplary embodiments of the present invention can still facilitate cracking and coking reactions, even as the catalyst becomes part of the coke layer. At this level, the catalyst is still exposed primarily to derivatives of the coker feed: coke and vapor/liquids passing through the coke layer. In conclusion, even after settling to the vapor/liquid interface and below, the catalyst in exemplary embodiments of the present invention can still facilitate cracking and coking reactions (inherent aspects of the present invention). Even at these levels, the overall exposure of the catalyst to coker feed components with a higher propensity to coke is limited.
In the known art of the refining industry, the product classifications have broader classification of low boiling point, middle boiling point, and high boiling point materials or products. Typically, the classification of low boiling point products comprises the chemical compounds that are in the gas phase at ambient temperatures and pressures, including methane, ethane, propanes, butanes, and the corresponding olefins. These compounds typically have boiling points less than roughly 90 degrees Fahrenheit, and are commonly referred to as C4—in the industry, referring to the number of carbon atoms in each molecule. The middle boiling point products are typically liquids at ambient temperatures and pressures, and boiling points between roughly 90 and 610 degrees Fahrenheit. Most of these middle boiling point products, including middle distillates, are blended into liquid transportation fuels either directly or after further processing (e.g. hydrotreating, reforming, isomerization) to improve product qualities. Typically, high boiling point materials are considered to be refinery process streams with boiling point ranges greater than the middle distillates. These process streams normally require further processing (e.g. hydrocracker or fluid catalytic cracking unit) to lower their boiling point range before they can be blended into liquid transportation fuels. Generally, these materials have boiling points greater than the highest end point of the middle distillates; typically the end point of light gas oils or approximately 610 degrees Fahrenheit.
Applying this known art to a coking process, the coker recycle and Heavy Coker Gas Oil (HCGO) would be classified as ‘high boiling point materials’ in the product vapors in the coking vessel. As discussed in other parts of this description, some exemplary embodiments of the present invention can use the catalytic additive in to quench the vapor products and condense the ‘highest boiling point’ materials in the product vapors. By condensing these highest boiling point materials, exemplary embodiments of the present invention can essentially create an ‘internal recycle’ that increases the residence time of the heaviest components of the coker recycle and/or part of the HCGO. In addition, this ‘internal recycle’ may also be used to provide intimate contact with the catalyst and make it more selective and efficient, thereby lowering catalyst makeup requirements and costs. However, the catalyst must be designed to crack effectively with these very large molecules in the liquid phase, until the catalyst settles to a level in the coking vessel where these highest boiling point materials revaporize due to the higher temperatures or other local sources of heat (e.g. release of heat from condensation of adjacent molecules). The quantity of ‘internal recycle’ depends on various factors, including (1) the coking vessel outlet temperature of the known art, (2) the quantity of catalytic additive and its associated quenching effect, and (3) the quality and quantity of coker recycle and Heavy Coker Gas Oil. In exemplary embodiments of the present invention, catalytic cracking of the highest boiling point materials in the product vapors of the coking vessel may allow one skilled in the known art to reduce the quantity of traditional coker recycle (i.e. external) and/or reduce the amount of ‘heavy tail’ components in the HCGO. Where the reduction shows up can be optimized by adjusting the end point of the HCGO in the fractionator operation.
From a physical perspective, the primary catalytic reactants of the present invention are primarily vapors, condensed liquids of the highest boiling point vapors, and liquids, semi-solids and solids at the coking interface (after the catalyst settles to the vapor/liquid interface and below). The temperature of the primary reactants is typically <875° F., which is normally more conducive to aromatic cracking (vs. coking) with high residence time and reaction equilibrium, favoring these lower temperatures. Physically, the primary catalytic reactants of exemplary embodiments of the present invention are substantially different from the primary catalytic reactants of the known art and much less conducive to coking.
In summary, the chemical and physical characteristics of the catalyst reactants are vastly different for an exemplary embodiment of the present invention, when compared to the chemical characteristics of the catalytic reactants of the known art. That is, the catalyst additive of an exemplary embodiment of the present invention is typically added to the coking vessel downstream of the primary cracking and coking zones of the coking process. In these cases, the primary reactants are derivatives of the coker feed after extensive cracking and coking of the coker feed: coker recycle, heavy coker gas oil (HCGO), light coker gas oil (LCGO), naphtha, and various gases with less than 5 carbon atoms per molecule. The highest boiling point materials (e.g. greater than roughly 800 degrees Fahrenheit) in the coker product vapors are the coker recycle and the ‘heavy tail’ of the heavy coker gas oil. Consequently, the primary reactants exposed to the catalyst of an exemplary embodiment of the present invention are substantially smaller molecules that are more conducive to cracking (vs. coking) than the known art. Chemically, the primary catalytic reactants of an exemplary embodiment of the present invention are substantially different and much less conducive to coking than the primary catalytic reactants of the known art.
The physical and chemical characteristics of the primary reactants in an exemplary embodiment of the present invention may be more similar to those in a fluid catalytic cracking unit (FCCU). That is, a typical FCCU further processes the HCGO generated by the coking process. The FCCU is typically used to convert (catalytically crack) the high boiling point materials (e.g. greater than roughly 610 degrees Fahrenheit) of the HCGO in a similar operating environment with low pressure, limited hydrogen, and slightly higher temperatures. However, the substantially longer residence time for the catalyst in exemplary embodiments of the present invention (potentially hours vs. seconds) is advantageous in achieving efficient use of the catalyst with reaction kinetics that may more closely approach equilibrium values.
Hydrogen Addition EmbodimentAn advantage of an exemplary embodiment of the present invention is to get active catalyst of desired characteristics down to the liquid/emulsion and foaming layers above the coke to convert heavier hydrocarbons (that would otherwise form coke) to lighter hydrocarbons with high enough vapor pressure (low enough boiling point) to escape the coking vessel (even at lower coking vessel outlet temperatures), and be separated into process streams in the coker fractionator.
The thermal and catalytic cracking vapor/liquid equilibria for various reactions of an exemplary embodiment of the present invention at various temperatures at the top of the coke drum are more favorable than the thermal cracking vapor/liquid equilibria of traditional delayed coking at various temperatures at the top of the coke drum. Part of this has to do with many of the reactions are reaction rate limited, and/or the concentration of the desired reactants are increased by removing an excess of chemical compounds from the reaction zone that don't react in the traditional delayed coking environment. Though the delayed coker reaches a somewhat steady state operation the reaction kinetics are still dynamic (not at equilibrium). However, these reaction equilibria driving forces for various reactions push the coker product yields more favorably toward the Technology at a given coke drum vapor exit temperature.
Catalyst can be fluidized for extended periods of time due to turbulent mix zones in the liquid/emulsion and foaming layers on top of the coke due to the channels in the coke that cause higher localized velocity (vs. vapor flow of <1-2 fps above the foam layer designed for disengagement of coke solids from the overhead vapors).
Catalyst can have characteristics of FCCU catalyst, hydroprocessing catalyst (HPC), other catalysts, and any combination thereof to optimize reactions in liquid/emulsion and foaming layers to reduce the chemical compounds that would otherwise form coke.
If the degree of catalytic cracking is limited by the concentration of hydrogen, the current Intellectual Property (IP) already contemplates the injection of hydrogen to the target reaction zone(s) by catalyst impregnation on the catalyst or otherwise. The IP also contemplates other means of adding hydrogen to the reaction chemistry, including the addition of hydrogen as an excess reactant in the form of a gas or a chemical compound that releases hydrogen when heated or reacted with another chemical compound.
Addition of Hydrogen to catalyst slurry may become desirable once you reach the equilibria limits due to hydrogen reactant concentration: This can be in the form of hydrogen gas bubbled through slurry but more likely impregnated on the catalyst to increase probability that hydrogen will be available at the target reaction zone. This may be accomplished by increasing the proton donor or electron receptor activity sites of the catalyst, catalyst impregnation, other methods, or any combination thereof
Use of catalyst to promote exothermic reactions in the coking vessel or elsewhere (e.g. heater or vapor line) is often desirable: Catalytic Coking: Polymerization coking, Other exothermic Coking Mechanisms; Catalytic Cracking: Promote exothermic cracking mechanisms.
If possible, the addition of catalyst to promote asphaltene coking with exothermic reactions (preferably after cracking off chains between aromatic plates of asphaltenes) would also increase the temperature of the coking vessel, preferably at the liquids level to help promote additional desired cracking reactions of chemical compounds that would otherwise form coke
Catalysts promote the same reactions (cracking or coking) with less heat of reaction required: As a result, the heater outlet temperature is reduced less for the same reactions, and the coking vessel vapor outlet temperature is increased, if this available heat is not consumed in additional endothermic reactions. In addition, the temperature at the liquid/emulsion and foam layers would be increased, as well. This can be estimated by the evaluation of the change in the heats of reactions and the quantity of catalyst used.
Said additive of the Technology may also be added in the vapor line between the coking vessel and the fractionator (e.g. downstream of the coke drum), but is typically not a preferred embodiment due to the potential lower heat (less effective use of the catalyst) and the potential problems associated with catalyst (if used) or seeding agents (if used) getting into the fractionator or being recycled through the process heater. Also, the said additive could be introduced in the feed line between the heater and the coking vessel (e.g. upstream of the coke drum), but would likely encounter similar problems with catalyst being injected in the feed prior to the process heater (i.e. catalyst and other materials act as seeding agent that promotes more catalyst formation, not less) and would not be as effective use of the catalyst.
Said additive of the Technology may also be added by various mechanical means to the foaming and/or liquid layers below the product vapors of the delayed coker. One means of accomplishing this is to use the modified drill stem discussed in previous patent filings. These mechanical means of injecting the said additive could be continuous injection, intermittent or periodic injection, and/or batch injection (all at once per coking cycle). If the status of current technologies (e.g. high-pressure drum sealing technology, metallurgy of components, etc.) are not prohibitive at the current time, the use of the modified drum stem which can reliably follow the upward movement of the foaming and/or liquid layers throughout the coking cycle would provide a preferred embodiment to introduce active catalyst into the foaming and/or liquid layers.
Novel Use of Internal RecycleAs with the previous patent applications, the traditional delayed coker operation is modified by injecting an additive comprised of carrier oil and catalyst (with other options previously noted) into the coking vessel above the liquid layer. Though I believe these ideas have been discussed in previous patent applications and time stamped e-mails in some form or another, I am submitting the following embodiments in the stated form to be time stamped to assure clarity in their use in this manner:
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- 1. Internal Recycle w/Various Options: In this embodiment, the quench oil in the vapor line of a traditional delayed coking operation downstream of the coke drum is decreased by the equivalent amount of heat capacity (temperature reduction) as the said additive injection. In this manner, the heat balance in the coker is maintained. In addition, the components with the highest boiling points in the product vapors that traditionally exit the coke drum are condensed in the coke drum creating an internal recycle (vs. becoming part of the external recycle that goes through the coker fractionator and back to the inlet to the coke charge heater and passing through the coke drum once more). These product vapor components of highest boiling points are preferentially condensed in a manner (e.g. catalyst as seeding agent) that provides intimate contact with the catalyst for increase selectivity of the desired reactions of these vapor components. In this embodiment, the internal recycle allows various process options and operational flexibility:
- a. External recycle can be reduced and debottleneck the coker charge heaters to allow more coker feed to be processed, allowing more coker throughput. If the coker is the refinery bottleneck, this may allow more refinery throughput, as well.
- b. If the external recycle is not reduced by the full amount of said internal recycle (e.g. maintained at existing level or a level in between), the heavy coker gas oil draw temperature will be reduced accordingly. In this manner, the heavy coker gas oil quality can be improved by reducing the amount of ‘Heavy tail’ components in the heavy coker gas oil. This quality improvement typically leads to more efficient processing of the heavy coker gas oil in downstream units (e.g. Less coke on catalyst in downstream FCCU) or better characteristics for alternative uses (e.g. better combustion characteristics for fuel).
- c. Combination of benefits from partial or combination of a and b above. For example, some of the internal recycle amount is used for increased coker heater throughput with associated increases in coker throughput and refinery throughput (e.g. used to the extent that the coker heater is no longer the bottleneck of the coker) and some of the internal recycle amount is used for improvement of the heavy coker gas oil quality.
- 1. Internal Recycle w/Various Options: In this embodiment, the quench oil in the vapor line of a traditional delayed coking operation downstream of the coke drum is decreased by the equivalent amount of heat capacity (temperature reduction) as the said additive injection. In this manner, the heat balance in the coker is maintained. In addition, the components with the highest boiling points in the product vapors that traditionally exit the coke drum are condensed in the coke drum creating an internal recycle (vs. becoming part of the external recycle that goes through the coker fractionator and back to the inlet to the coke charge heater and passing through the coke drum once more). These product vapor components of highest boiling points are preferentially condensed in a manner (e.g. catalyst as seeding agent) that provides intimate contact with the catalyst for increase selectivity of the desired reactions of these vapor components. In this embodiment, the internal recycle allows various process options and operational flexibility:
Reducing the heater outlet temperature and various other means to reduce the overhead vapor line temperature may achieve similar benefits, with or without the use of the quench oil. In addition, these benefits (utility) may be sufficient to justify the implementation of the technology even without a reduction (or lower levels of reduction) in the production of coke.
Injection of Additive Components in Separate Process Streams: In another embodiment, said additive components can be added to the coker product vapors in separate process streams. For example, the catalyst can be injected separately from the carrier oil that acts as a quench oil to selectively condense the highest boiling components in the product vapors. The carrier oil in said additive may no longer carry other additive components, but simply become quench oil. This may be preferable in applications (1) where the catalyst is more easily injected in a dry form and/or (2) where a catalyst of a higher temperature is desirable. In this example, the coincidental injection of both the quench oil and the catalyst near the same location may be desirable in a manner that enhances the intimate contact of the catalyst and condensed highest boiling point components of the coker product vapors to increase selectivity of the desired reactions. In another example, hydrogen may be added as a separate process stream, as well. That is, the addition of hydrogen as a separate process stream may be preferable, whether the remaining additive is injected in one process stream or multiple process streams.
In addition, a separate addition of colder catalyst may also be desirable in certain applications. The colder catalyst may be sufficient to condense the highest boiling materials in the product gases to achieve a desired intimate contact with the coke (selective reaction with catalyst), but the drop in temperature would not normally be sufficient to condense a higher level of the highest boiling materials due to the lack of substantial heat loss from the heat of vaporization in a carrier/quench oil.
Injection in the Vapor Line vs. Coking vessel w/Optional Catalyst collection with Coke Particles: In this embodiment, the injection of the said additive into the vapor line between coking vessel and the coker fractionator may be desirable in some applications of the technology. Though this embodiment would not have the benefit of higher temperatures associated with the reheat of the internal recycle (e.g. as the catalyst/condensed coker product vapors sink to the liquid coking layer in the coke drum), some enhanced chemical reactions may still provide sufficient benefits to justify its application. For example, said additive in the form of heated catalyst could be injected into the vapor line and achieve desired benefits. In this case, quench oil injection in said vapor line may already exist in the coker of said application to condense the highest boiling components of the coker product vapors. In addition, some applications may already have particulate collection devices near the inlet to the coker fractionator (e.g. before the coker product vapors entrance to the coker fractionator) to collect coke particles. These existing particulate collection devices may be sufficient to collect additional particulates from (1) solid components of said additive (e.g. catalyst) or (2) solid derivatives from reactions caused by injection of said additive. Otherwise, the particulate collection devices may be modified and/or new collection devices added to handle the additional particulate loading and different particle characteristics.
Improvement of Coker Naphtha: In this embodiment, the said injection of additive may be used to improve the quality of the coker naphtha process stream. For example, the increased production of olefins caused by the presence of the catalytic cracking can be optimized to produce naphtha more similar to naphtha process streams from other refinery process units (e.g. Fluid catalytic Cracking Unit: FCCU). In this manner, the coker naphtha stream in some applications may be treated similar to other naphtha process streams in the refinery, requiring less additional processing and providing more value.
In another embodiment, the carrier oil and/or quench oil can be increased to increase the quantity of highest boiling materials (e.g. recycle) that is condensed. In many cases, for each 1 wt. % of feed that is injected into the top of the coke drum, roughly 10° F. drop in the product vapors temperature can be expected. In this example, 1 wt. % could be increased to 3 wt. % to achieve a 30° F. drop in the product vapor to increase the quantity of highest boiling materials condensed (e.g. recycle). This increase in carrier and/or quench oil can often be done without any increase in cost or impact on the coker heat balance, since the quenching is simply moved forward (or transferred) from the vapor line to the top of the coking vessel and the quench oil in either case is recovered in the fractionator. In these cases, the catalyst concentration can also be varied to achieve the desired level of injection. For example, the catalyst concentration can be reduced by ⅓ while raising the quench oil injection level by 3 to maintain the same level of total catalyst going into the coker system.
Differentiation Over Fluid Catalytic Cracking Process:
The known art of fluid catalytic cracking in the refining industry is very different from the introduction of a catalytic additive in the coking vessel of a coking process in exemplary embodiments of the present invention. The fluid catalytic cracking (FCC) process typically introduces high boiling point hydrocarbon feed(s) into fluidized catalyst particles in a specially designed reactor (e.g. combinations of feed-riser and dense-bed reactors). The high boiling point feeds typically include heavy atmospheric gas oil, vacuum gas oil, and/or heavy coker gas oil (HCGO). The catalyst sufficiently lowers the activation energy of cracking reactions to preferably promote the catalytic cracking of these high boiling point materials to lower boiling point hydrocarbon products, including gasoline and middle distillates. In addition, FCC catalysts typically increase some coking reactions, as well. Thus, the FCC process also produces coke that remains on the catalyst and rapidly lowers its activity. Consequently, the catalyst is circulated to a regeneration vessel, where the coke is burned off of the catalyst to regenerate catalyst activity to acceptable levels.
The reaction conditions of the FCC reactor are also substantially different from the vapor zone of the coking vessel. The catalytic reactants in both processes typically include heavy coker gas oil, but the vapor products in the coking vessel of the coking process also include higher boiling point compounds in the coker recycle component and lower boiling point compounds in the components of light coker gas oil, naphtha, and gases. Typically, the FCC reactor pressure (e.g. 8-12 psig) is slightly lower than the coking vessel (e.g. 12-25 psig). The FCC reactor temperature (e.g. 900 to 1000 degrees Fahrenheit) is substantially higher than the coking vessel (e.g. 800 to 900 degrees Fahrenheit). Furthermore, the residence time of catalyst exposure to the reactants is substantially different: FCC typically measured in seconds, where the catalyst in the coking vessel can conceivably continue to catalyze reactions for minutes to hours, depending on various factors including fluidization in the coking vessel product vapors. Though they both have low partial pressures of hydrogen, the much higher residence time and lower temperatures can favor substantially more cracking of aromatic compounds in the coking vessel.
In conclusion, the catalytic cracking in the coking vessel in exemplary embodiments of the present invention is substantially differentiated over the known art of fluid catalytic cracking. Various types of FCC catalyst (e.g. equilibrium, fresh, etc.) have been noted to be a type of catalyst that has the desired characteristics for various embodiments of the present invention. In this regard, the catalytic cracking and coking reactions of certain reactants (e.g. HCGO) are expected to have similar characteristics. However, the basic reactor design and reaction conditions are substantially different.
Utility of Exemplary Embodiments of the Present Invention:
Refinery computer optimization models can be used to establish the utility of various exemplary embodiments of the present invention. Most refineries currently use refinery optimization models (e.g. LP Models) to optimize refinery process operations to maximize profit (or other objectives), based on the refinery process scheme, refinery crude blend, and market values for final products. The optimization model typically contains individual models for each refinery process in its refinery process scheme to assess the optimal operation to best utilize its capabilities and capacity. These refinery models typically estimate values of various process streams, including the feed and products of a coking process. In some models, the value of the ‘internal recycle’ in some exemplary embodiments of the present invention of a coking process can be valued based on its effects on process capacity and associated products. These values are typically generated in a dollars per barrel basis (i.e. $/Bbl.), but can be readily converted to cents per pound (c/Lb.), as well. Typically, the relative rankings (lowest to highest value in c/Lb) of the coker process streams are as follows: coke (lowest), recycle, feed, refinery fuel gas, HCGO, LCGO, Naphtha, LPGs, and gaseous olefins (highest). The HCGO, LCGO, and naphtha values are comparable and actually can have different relative rankings from refinery to refinery, due to differences in refinery process scheme and refinery crude blend. For example, the FCC capacity and/or capacities of downstream processing units for LCGO and naphtha can have effects on their relative values. In refineries where the FCC capacity is limited, opportunities may exist to use an exemplary embodiment of the present invention to use the coking process as incremental capacity for cracking HCGO to LCGO, naphtha, and lighter components. In many refineries, the refinery fuel gas value is often over ten times higher in value than the coke, and the other process streams are valued at 15 to 20 times higher. Consequently, most exemplary embodiments of the present invention that crack high boiling point materials that would otherwise form coke have very high utility. An exception to this general rule exists in refineries where coking small portions of HCGO or heavier material can improve operations of coking process or downstream processes (e.g. FCC due to better quality HCGO), and provide greater value. In addition, an exemplary embodiment of the present invention that cokes undesirable materials in the HCGO can lead to improvement of coke quality and sufficiently leverage the coke value, while improving HCGO quality to reduce operating problems in downstream processing equipment (e.g. FCC).
In conclusion, the most favorable exemplary embodiment of the present invention will depend on its economic or upgrade value. In many refineries, the highest product upgrade value will be cracking the highest boiling point materials that would otherwise form coke. Thus, exemplary embodiments of the present invention that produce less coke and more liquids may provide the best upgrade value.
Description of an Example of Process Operation:
The operation of the equipment in
In the general exemplary embodiment, the additive package is designed with first priority given to selectively crack the high boiling point components in the coking vessel product vapors. Then, second priority is given to selectively coke the remaining high boiling point components. In other words, the additive will condense and selectively remove these high boiling point components from the product vapors and help them either crack or coke, with preference given to cracking versus coking. This is primarily achieved by the choice of catalyst. For example, residua cracking catalysts that are traditionally used for cracking in catalytic cracking units (e.g. Fluid Catalytic Cracking Unit or FCCU) may be very effective in this application to crack the heavy aromatics molecules into lighter ‘cracked liquids’. These catalysts have a higher degree of mesoporosity and other characteristics that allow the large molecules of the high boiling point components to have better access to and from the catalyst's active cracking sites. In addition, the other components of the additive package may influence cracking reactions over coking reactions, as well. As described previously, it is anticipated that various catalysts will be designed for the purposes above, particularly catalysts to achieve greater cracking of the highest boiling point materials in the coking process product vapors. In many cases, conversion of the highest boiling point product vapors to coke may predominate (e.g. >70 Wt. %) due to their higher propensity to coke (vs. crack). However, with certain chemical characteristics of these materials, properly designed catalysts, and the proper coker operating conditions, substantial conversion of these materials to cracked liquids may be accomplished (e.g. >50 Wt. %). Conceivably, cracking of heavy hydrocarbons (that would otherwise become coke, recycle material, or ‘heavy tail’ of the heavy coker gas oil) could be sufficient to reduce overall coke production, reduce coker recycle, and/or reduce heavy gas oil production, particularly the ‘heavy tail’ components.
In many cases, the achievement of additional cracking of these highest boiling point materials in the product vapors to ‘cracked liquids’ products is worth the cost of fresh cracking catalyst versus spent or regenerated catalyst. This economic determination will depend on the chemical structures of the high boiling point components. That is, many of the highest boiling point components often have a high propensity to coke and will coke rather than crack, regardless of the additive package design. If sufficient high boiling point components are of this type, the economic choice of catalyst may include spent, catalyst(s), regenerated catalyst(s), fresh catalyst(s), or any combination thereof. In a similar manner, cracking catalysts, in general, may not be desirable in cases where almost all of the highest boiling point components have very high propensities to coke, and inevitably become coke, regardless of the additive package design.
In its preferred embodiment, this additive selectively cracks the heavy coker gas oil's heaviest aromatics that have the highest propensity to coke, while quenching cracking reactions in the vapor, facilitating cracking reactions in the condensed vapors, and/or provides antifoaming protection.
WORKING EXAMPLES OF GENERAL EXEMPLARY EMBODIMENTSIn order to more thoroughly describe the present invention, the following working examples are presented. The data presented in these examples was obtained in a pilot-scale, batch coker system. The primary component of this pilot-scale coker system is a stainless steel cylindrical reactor with an internal diameter of 3.0 inches and a height of 39 inches. A progressive cavity pump transfers the coker feed from the heated feed tank with mixer to the preheater and coker reactor. The nominal feed charge for each test is 4000 to 5000 grams over a 4-5 hour period. The preheater and coker temperatures are electronically controlled in an insulated furnace to the desired set points. A back pressure controller is used to maintain the desired reactor pressure. This pilot-scale system was used to generate data to demonstrate the benefits of the current invention over the known art. That is, the injection of the catalyst additive into the coking vessel of the current invention and the addition of catalyst to the coker feed of the known art were compared to a common baseline with no catalyst.
Comparative Test Examples 1 and 2Coker feed from a commercial refinery was used to generate data for two tests with equivalent amounts of catalyst B. The operating conditions and the test results are shown in the following table.
In the foregoing table, the catalyst addition of the known art showed a substantial increase in coking and a significant reduction in liquid yields. In contrast, the injection of the catalytic additive of an exemplary embodiment of the present invention showed a substantial reduction in coke yield and a significant increase in liquids production. Thus, these tests clearly demonstrate differentiation of the present invention over the known art. As described above, these results are likely due to the major differences in the chemical and physical nature of the primary reactants, exposed to the catalyst.
Comparative Test Examples 2, 3, and 4Similarly, the coker feed from the same commercial refinery was used to generate data for 3 tests with equivalent amounts of catalyst C. The operating conditions and the test results are shown in the following table.
In the foregoing table, the catalyst addition of the known art showed a substantial increase in coking and a significant reduction in liquid yields. In contrast, the injection of the catalytic additive of an exemplary embodiment of the present invention showed a substantial reduction in coke yield and a significant increase in liquids production. Thus, these tests clearly demonstrate differentiation of the present invention over the known art. As described above, these results are likely due to the major differences in the chemical and physical nature of the primary reactants, exposed to the catalyst.
Description and Operation of Alternative Exemplary Embodiments Delayed Coking ProcessThere are various ways exemplary embodiments of the present invention may improve the delayed coking process. A detailed description of how the invention is integrated into the delayed coking process is followed by discussions of its operation in the delayed coking process and alternative exemplary embodiments relative to its use in this common type of coking process.
Traditional Delayed Coking Integrated with Exemplary Embodiments of the Present InventionIn general, delayed coking is an endothermic reaction with the furnace supplying the necessary heat to complete the coking reaction in the coke drum. The exact mechanism of delayed coking is so complex that it is not possible to determine all the various chemical reactions that occur, but three distinct steps take place:
1. Partial vaporization and mild cracking of the feed as it passes through the furnace
2. Cracking of the vapor as it passes through the coke drum
3. Successive cracking and polymerization of the heavy liquid trapped in the drum until it is converted to vapor and coke.
In the coking cycle, coker feedstock is heated and transferred to the coke drum until full. Hot residua feed 10 (most often the vacuum tower bottoms) is introduced into the bottom of a coker fractionator 12, where it combines with condensed recycle. This mixture 14 is pumped through a coker heater 16, where the desired coking temperature (normally between 900 degrees F. and 950 degrees F.) is achieved, causing partial vaporization and mild cracking. Steam or boiler feed water 18 is often injected into the heater tubes to prevent the coking of feed in the furnace. Typically, the heater outlet temperature is controlled by a temperature gauge 20 that sends a signal to a control valve 22 to regulate the amount of fuel 24 to the heater. A vapor-liquid mixture 26 exits the heater, and a control valve 27 diverts it to a coking drum 28. Sufficient residence time is provided in the coking drum to allow thermal cracking and coking reactions to proceed to completion. By design, the coking reactions are “delayed” until the heater charge reaches the coke drums. In this manner, the vapor-liquid mixture is thermally cracked in the drum to produce lighter hydrocarbons, which vaporize and exit the coke drum. The drum vapor line temperature 29 (i.e., temperature of the vapors leaving the coke drum) is the measured parameter used to represent the average drum outlet temperature. Petroleum coke and some residuals (e.g. cracked hydrocarbons) remain in the coke drum. When the coking drum is sufficiently full of coke, the coking cycle ends. The heater outlet charge is then switched from the first coke drum to a parallel coke drum to initiate its coking cycle. Meanwhile, the decoking cycle begins in the first coke drum. Lighter hydrocarbons 38 are vaporized, removed overhead from the coking drums, and transferred to a coker fractionator 12, where they are separated and recovered. Coker heavy gas oil (HGO) 40 and coker light gas oil (LGO) 42 are drawn off the fractionator at the desired boiling temperature ranges: HGO: roughly 610-800 degrees F.; LGO: roughly 400-610 degrees F. The fractionator overhead stream, coker wet gas 44, goes to a separator 46, where it is separated into dry gas 48, water 50, and unstable naphtha 52. A reflux fraction 54 is often returned to the fractionator.
In the decoking cycle, the contents of the coking drum are cooled down, remaining volatile hydrocarbons are removed, the coke is drilled from the drum, and the coking drum is prepared for the next coking cycle. Cooling the coke normally occurs in three distinct stages. In the first stage, the coke is cooled and stripped by steam or other stripping media 30 to economically maximize the removal of recoverable hydrocarbons entrained or otherwise remaining in the coke. In the second stage of cooling, water or other cooling media 32 is injected to reduce the drum temperature while avoiding thermal shock to the coke drum. Vaporized water from this cooling media farther promotes the removal of additional vaporizable hydrocarbons. In the final cooling stage, the drum is quenched by water or other quenching media 34 to rapidly lower the drum temperatures to conditions favorable for safe coke removal. After the quenching is complete, the bottom and top heads of the drum are removed. The petroleum coke 36 is then cut, typically by a hydraulic water jet, and removed from the drum. After coke removal, the drumheads are replaced, the drum is preheated, and otherwise readied for the next coking cycle.
Exemplary embodiments of the present invention may be readily integrated into the traditional, delayed coker system, both new and existing. As shown in
In traditional delayed coking, the optimal coker operating conditions have evolved through the years, based on much experience and a better understanding of the delayed coking process. Operating conditions have normally been set to maximize (or increase) the efficiency of feedstock conversion to cracked liquid products, including light and heavy coker gas oils. More recently, however, the cokers in some refineries have been changed to maximize (or increase) coker throughput.
In general, the target operating conditions in a traditional delayed coker depend on the composition of the coker feedstocks, other refinery operations, and coker design. Relative to other refinery processes, the delayed coker operating conditions are heavily dependent on the feedstock blends, which vary greatly among refineries (due to varying crude blends and processing scenarios). The desired coker products and their required specifications also depend greatly on other process operations in the particular refinery. That is, downstream processing of the coker liquid products typically upgrades them to transportation fuel components. The target operating conditions are normally established by linear programming (LP) models that optimize the particular refinery's operations. These LP models typically use empirical data generated by a series of coker pilot plant studies. In turn, each pilot plant study is designed to simulate the particular refinery's coker design. Appropriate operating conditions are determined for a particular feedstock blend and particular product specifications set by the downstream processing requirements. The series of pilot plant studies are typically designed to produce empirical data for operating conditions with variations in feedstock blends and liquid product specification requirements. Consequently, the coker designs and target operating conditions vary significantly among refineries.
In common operational modes, various operational variables are monitored and controlled to achieve the desired delayed coker operation. The primary independent variables are feed quality, heater outlet temperature, coke drum pressure, and fractionator hat temperature. The primary dependent variables are the recycle ratio, the coking cycle time and the drum vapor line temperature. The following target control ranges are normally maintained during the coking cycle for these primary operating conditions:
1. Heater outlet temperatures in range of about 900 to about 950 degrees Fahrenheit,
2. Coke drum pressure in the range of about 15 psig to 100 psig: typically 20-30 psig,
3. Hat Temperature: Temperature of vapors rising to gas oil drawoff tray in fractionator
4. Recycle Ratio in the range of 0-100%; typically 10-20%
5. Coking cycle time in the range of about 12 to 24 hours; typically 15-20 hours
6. Drum Vapor Line Temperature 50 to 100 degrees Fahrenheit less than the heater outlet temperature: typically 850-900 degrees Fahrenheit.
These traditional operating variables have primarily been used to control the quality of the cracked liquids and various yields of products. Throughout this discussion, “cracked liquids” refers to hydrocarbon products of the coking process that have 5 or more carbon atoms. They typically have boiling ranges between 97 and 870 degrees Fahrenheit, and are liquids at standard conditions. Most of these hydrocarbon products are valuable transportation fuel blending components or feedstocks for further refinery processing. Consequently, cracked liquids may be a primary objective of a coking process.
Over the past ten years, some refineries have switched coker operating conditions to maximize (or increase) the coker throughput, instead of maximum efficiency of feedstock conversion to cracked liquids. Due to processing heavier crude blends, refineries often reach a limit in coking throughput that limits (or bottlenecks) the refinery throughput. In order to eliminate this bottleneck, refiners often change the coker operating conditions to maximize (or increase) coker throughput in one of three ways:
1. If coker is fractionator (or vapor) limited, increase drum pressure (e.g. 15 to 20 psig.)
2. If coker is drum (or coke make) limited, reduce coking cycle time (e.g. 16 to 12 hours)
3. If Coker is heater (or feed) limited, reduce recycle (e.g. 15 wt. % to 12 wt. %)
All three of these operational changes increase the coker throughput. Though the first two types of higher throughput operation reduce the efficiency of feedstock conversion to cracked liquids (i.e., per barrel of feed basis), they may maximize (or increase) the overall quantity (i.e., barrels) of cracked liquids produced. These operational changes also tend to increase coke yield and coke VCM. However, any increase in drum pressure or decrease in coker cycle time is usually accompanied by a commensurate increase in heater outlet and drum vapor line temperatures to offset (or limit) any increases in coke yield or VCM. In contrast, the reduction in recycle is often accomplished by a reduction in coke drum pressure and an increase in the heavy gas oil end point (i.e., highest boiling point of gas oil). The gas oil end point is controlled by refluxing the trays between the gas oil drawoff and the feed tray in the fractionator with partially cooled gas oil. This operational mode increases the total liquids and maintains the efficiency of feedstock conversion to cracked liquids (i.e., per barrel of feed basis). However, the increase in liquids is primarily highest boiling point components (i.e., ‘heavy tail’) that are undesirable in downstream process units. In this manner, ones skilled in the art of delayed coking may adjust operation to essentially transfer these highest boiling point components to either the recycle (which reduces coker throughput) or the ‘heavy tail’ of the heavy gas oil (which decreases downstream cracking efficiency). An exemplary embodiment of the present invention provides the opportunity to (1) increase coker throughput (regardless of the coker section that is limiting), (2) increase liquid yields, and (3) may substantially reduce highest boiling point components in either recycle, heavy gas oil, or both. In this manner, each application of an exemplary embodiment of the present invention may determine which process is preferable to reduce the undesirable, highest boiling point components.
There are various ways examples of the present invention may improve existing or new delayed coking processes in crude oil refineries and upgrading systems for synthetic crudes. These novel improvements include, but should not be limited to, (1) catalytic cracking of heavy hydrocarbons that would otherwise become pet coke, recycle, or heavy tail′ components of the heavy gas oil, (2) catalytic coking of heavy aromatics in a manner that promotes sponge coke morphology and reduces ‘hotspots’ in coke cutting, (3) quenching drum outlet gases that reduce ‘vapor overcracking’, (4) debottlenecking all major sections of the delayed coking process (i.e., heater, drum, & fractionator sections, and (5) reducing recycle and vapor loading of fractionator.
In all the examples for delayed coking processes, an exemplary embodiment of the present invention may achieve one or more of the following: (1) improved coker gas oil quality, (2) improved coke quality and market value, (3) less gas production, (4) less coke production, (5) increased coker and refinery capacities, (6) increased use of cheaper, lower quality crudes and/or coker feeds, (7) increased efficiency and run time of downstream cracking units, (8) decreased operation & maintenance cost of coker and downstream cracking units, and (9) reduced incidents of ‘hotspots’ in pet coke drum cutting, and (10) reduced catalyst make-up and emissions in downstream cracking units.
Example 1In fuel grade coke applications, the delayed coking feedstocks are often residuals derived from heavy, sour crude, which contain higher levels of sulfur and metals. As such, the sulfur and metals (e.g. vanadium and nickel) are concentrated in the pet coke, making it usable only in the fuel markets. Typically, the heavier, sour crudes tend to cause higher asphaltene content in the coking process feed. Consequently, the undesirable ‘heavy tail’ components (e.g. PAHs) are more prominent and present greater problems in downstream catalytic units (e.g. cracking). In addition, the higher asphaltene content (e.g. >15 wt. %) often causes a shot coke crystalline structure, which may cause coke cutting ‘hot spots’ and difficulties in fuel pulverization.
In these systems, an example of the present invention provides the selective cracking and coking of the ‘heavy tail’ components (e.g. Heavy hydrocarbons) in coker gas oil of the traditional delayed coking process. Typically, gas oil end points are selectively reduced from over 950 degrees of Fahrenheit to 900 degrees of Fahrenheit or less (e.g. preferably <850 degrees of Fahrenheit in some cases). With greater amounts of additive, additional heavy components of the heavy coker gas oil and the coker recycle will be selectively cracked or coked. This improves coker gas oil quality/value and the performance of downstream cracking operations. In addition, the selective cracking of Heavy hydrocarbons and quench (thermal & chemical) of the vapor overcracking improves the value of the product yields and increases the ‘cracked liquids’ yields. Also, the reduction of heavy components that have a high propensity to coke reduces the buildup of coke in the vapor lines and allows the reduction of recycle and heater coking.
With a properly designed additive package (e.g. catalyst & excess reactants), an example of the present invention may also be effectively used to alleviate problems with ‘hot spots’ in the coke drums of traditional delayed coking. That is, the heavy liquids that remain in the pet coke and cause the ‘hot spots’ during the decoking cycle (e.g. coke cutting) are encouraged to further crack (preferable) or coke by the catalyst and excess reactants in the additive package. To this end, catalyst(s) and excess reactant(s) for this purpose may include, but should not be limited to, FCCU catalysts, hydrocracker catalysts, activated carbon, crushed coke, FCCU slurry oil, and coker heavy gas oil.
In fuel grade applications, the choice of catalyst(s) in the additive package has greater number of options, since the composition of the catalyst (e.g. metals) is less of an issue in fuel grade pet coke specifications (e.g. vs. anode). Thus, the catalyst may contain substrates and exotic metals to preferentially and selectively crack (vs. coke) the undesirable, heavy hydrocarbons (e.g. PAHs). Again, catalyst(s) and excess reactant(s) for this purpose may include, but should not be limited to, FCCU catalysts, hydrocracker catalysts, iron, activated carbon, crushed coke, FCCU slurry oil, and coker heavy gas oil. The most cost effective catalyst(s) may include spent or regenerated catalysts from downstream units (e.g. FCCU, hydrocracker, and hydrotreater) that have been sized and injected in a manner to prevent entrainment in coking process product vapors to the fractionator. In fact, the nickel content of hydrocracker catalyst may be very effective in selectively coking the undesirable, heavy components (e.g. PAHs) of coker gas oil. The following example is given to illustrate a cost effective source of catalyst for an exemplary embodiment of the present invention. A certain quantity of FCCU equilibrium catalyst of the FCCU is normally disposed of on a regular basis (e.g. daily) and replaced with fresh FCCU catalyst to keep activity levels up. The equilibrium catalyst is often regenerated prior to disposal and could be used in an exemplary embodiment of the present invention to crack the heavy hydrocarbons, particularly if the FCCU catalyst is designed to handle residua in the FCCU feed. If the equilibrium catalyst does not provide sufficient cracking catalyst activity, it could be blended with a new catalyst (e.g. catalyst enhancer) to achieve the desired activity while maintaining acceptable catalyst costs.
When applied to greater degrees, an example of the present invention may also be used to improve the coke quality while improving the value of coke product yields and improved operations and maintenance of the coker and downstream units. That is, continually increasing the additive package will incrementally crack or coke the heaviest remaining vapors. The coking of these components will tend to push coke morphology toward sponge coke and increased VCM. In addition, with the proper additive package the additional VCM will be preferentially greater than 950 degrees Fahrenheit theoretical boiling point.
Example 2In anode grade coke applications, examples of the present invention may provide substantial utility for various types of anode grade facilities: (1) refineries that currently produce anode coke, but want to add opportunity crudes to their crude blends to reduce crude costs and (2) refineries that produce pet coke with sufficiently low sulfur and metals, but shot coke content is too high for anode coke specifications. In both cases, examples of the present invention may be used to reduce shot coke content to acceptable levels, even with the presence of significant asphaltenes (e.g. >15 wt. %) in the coker feed.
With an exemplary embodiment of the present invention, refineries that currently produce anode quality coke may often add significant levels of heavy, sour opportunity crudes (e.g. >5 wt. %) without causing shot coke content higher than anode coke specifications. That is, an exemplary embodiment of the present invention converts the highest boiling point materials in the product vapors in a manner that preferably produces sponge coke crystalline structure (coke morphology) rather than shot coke crystalline structure. Thus, these refineries may reduce crude costs without sacrificing anode quality coke and its associated higher values.
With an exemplary embodiment of the present invention, refineries that currently produce shot coke content above anode coke specifications may reduce shot coke content to acceptable levels in many cases. That is, an exemplary embodiment of the present invention converts the highest boiling point materials in the product vapors in a manner that preferably produces sponge coke crystalline structure (coke morphology) rather than shot coke crystalline structure. Thus, these refineries may increase the value of its petroleum coke while maintaining or improving coker product yields and coker operation and maintenance.
In both anode coke cases, the additive package must be designed to minimize any increases in the coke concentrations with respect to sulfur, nitrogen, and metals that would add impurities to the aluminum production process. Thus, the selection of catalyst(s) for these cases would likely include alumina or carbon based (e.g. activated carbon or crushed coke) catalyst substrates.
In both anode coke cases, the additive package must be designed to minimize the increase in VCMs and/or preferably produces additional VCMs with theoretical boiling points greater than 1250 degrees Fahrenheit. Thus, catalyst(s) and excess reactants for this additive package would be selected to promote the production of sponge coke with higher molecular weights caused by significant polymerization of the highest boiling point materials in the product vapors and the excess reactants. In these cases, an optimal level of VCMs greater than 1250 degrees Fahrenheit may be desirable to (1) provide volatilization downstream of the upheat zone in the coke calciner and (2) cause recoking of these volatile materials in the internal pores of the calcined coke. The resulting calcined coke will preferably have a substantially greater vibrated bulk density and require less pitch binder to be adsorbed in the coke pores to produce acceptable anodes for aluminum production facilities. In this manner, a superior anode coke may be produced that lowers anode production costs and improves their quality. Beyond this optimal level of VCMs greater than 1250 degrees Fahrenheit, any coke produced by an exemplary embodiment of the present invention will preferably not contain any VCMs. That is, any further coke produced will all have theoretical boiling points greater than 1780 degrees Fahrenheit, as determined by the ASTM test method for VCMs.
Example 3In needle coke applications, the coking process uses special coker feeds that preferably have high aromatic content, but very low asphaltene content. These types of coker feeds are necessary to achieve the desired needle coke crystalline structure. These delayed coker operations have higher than normal heater outlet temperatures and recycle rates. With an exemplary embodiment of the present invention, these coking processes may maintain needle coke crystalline structure with higher concentrations of asphaltenes and lower concentrations of aromatics in the coker feed. Also, an exemplary embodiment of the present invention may reduce the recycle rate required to produce the needle coke crystalline structure, potentially increasing the coker capacity and improving coker operations and maintenance. In this manner, an exemplary embodiment of the present invention may decrease coker feed costs, while potentially increasing needle coke production and profitability.
Example 4Some delayed coker systems have the potential to produce petroleum coke for certain specialty carbon products, but do not due to economic and/or safety concerns. These specialty carbon products include (but should not be limited to) graphite products, electrodes, and steel production additives. An exemplary embodiment of the present invention allows improving the coke quality for these applications, while addressing safety concerns and improving economic viability. For example, certain graphite product production processes require a petroleum coke feed that has higher VCM content and preferably sponge coke crystalline structure. An exemplary embodiment of the present invention may be optimized to safely and economically produce the pet coke meeting the unique specifications for these applications. Furthermore, the quality of the VCMs may be adjusted to optimize the graphite production process and/or decrease process input costs.
CONCLUSION, RAMIFICATIONS, AND SCOPE OF THE INVENTIONThus the reader will see that the coking process modification of the invention provides a highly reliable means to catalytically crack or coke the high boiling point components (e.g. heavy hydrocarbons) in the product vapors in the coking vessel. This novel coking process modification provides the following advantages over traditional coking processes and recent improvements: (1) improved coker gas oil quality, (2) improved coke quality and market value, (3) less gas production, (4) less coke production, (5) increased coker and refinery capacities, (6) increased use of cheaper, lower quality crudes and/or coker feeds, (7) increased efficiency and run time of downstream cracking units, (8) decreased operation & maintenance cost of coker and downstream cracking units, and (10) reduced catalyst make-up and emissions in downstream cracking units.
While my above description contains many specificities, these should not be construed as limitations on the scope of the invention, but rather as an exemplification of embodiments thereof. Many other variations are possible.
Any embodiment of the present invention may include any of the optional or preferred features of the other embodiments of the present invention. The exemplary embodiments herein disclosed are not intended to be exhaustive or to unnecessarily limit the scope of the invention. The exemplary embodiments were chosen and described in order to explain the principles of the present invention so that others skilled in the art may practice the invention. Having shown and described exemplary embodiments of the present invention, those skilled in the art will realize that many variations and modifications may be made to the described invention. Many of those variations and modifications will provide the same result and fall within the spirit of the claimed invention. Accordingly, the scope of the invention should be determined not by the embodiment(s) illustrated, but by the claims and their legal equivalents.
Claims
1. A process comprising:
- introducing: 1) excess reactant(s) containing hydrogen into a coker feed between a fractionator and a coker feed heater, in the coker feed heater, into a transfer line between a coker heater and coking vessel(s), into said coking vessel(s) of a delayed coking process, or any combination thereof; and 2) an additive comprising catalyst(s) into said coking vessel(s) of the delayed coking process during a coking cycle;
- wherein said process promotes conversion of heavy hydrocarbons in said coking vessel(s).
2. The process of claim 1 where said additive further comprises seeding agent(s), excess reactant(s), quenching agent(s), carrier fluid(s), anti-foam fluid(s), or any combination thereof.
3. The process of claim 1 wherein said excess reactant(s) containing hydrogen comprises gaseous hydrogen, chemical compounds adapted to release reactive hydrogen at higher temperatures, Lewis Acids, Bronstead Acids, or any combination thereof.
4. The process of claim 3 wherein said excess reactant(s) containing hydrogen provides a 0.5:1 to 3:1 molar ratio of reactive hydrogen to coker feed.
5. The process of claim 3 wherein said excess reactant(s) containing hydrogen provides hydrogen to a targeted reaction zone at a rate of 30 to 600 Standard Cubic Feet per barrel of coker feed.
6. The process of claim 1 wherein said excess reactant(s) containing hydrogen promotes catalytic cracking, thermal cracking, or any combination thereof.
7. The process of claim 1 wherein said additive is added to vapors above a vapor-liquid interface in said coking vessel(s).
8. The process of claim 1 wherein said additive is added to said coking process by pressurized injection.
9. The process of claim 8 wherein a pressurized injection system is provided for adding said additive to said coking process that is selected from the group consisting of a pump with a feedback control system; a flow meter with a feedback control system; a modified anti-foam system; and any combination thereof.
10. The process of claim 8 wherein a pressurized injection system is provided for adding said additive to said coking process that is selected from the group consisting of positive displacement pumps; progressive cavity pumps; variable shearing mixing pumps; pumps with other control logic; pressure pots with pressurized fluid supplied by a host coker to push slurry into a coke drum; other devices adapted to increase slurry pressure in a tank or lines; and any combination thereof.
11. The process of claim 8 wherein a pressurized injection system is provided for adding said additive to said coking process that is a pump with control logic related to a pressure of said coking vessel(s).
12. The process of claim 8 wherein additive pressure is controlled such as to be above coking vessel(s) pressure.
13. The process of claim 12 wherein additive pressure is controlled by a pressure meter with a feedback control system.
14. The process of claim 12 wherein an additive pressure control is provided that is selected from the group consisting of a pressure feedback controller with a pressure indicator; pumps with a pressure measuring device to provide input to other control logic; pressure pots with pressurized fluid supplied by a host coker to push slurry into said coking vessel(s) with a pressure measuring device to control pressure of said pressurized fluid, additive(s), and/or any combination thereof; other devices to increase and/or control slurry pressure in a tank or lines; and any combination thereof.
15. The process of claim 12 wherein additive pressure is controlled by a variable shear mixing pump with a pressure measuring device that provides input to control logic related to a pressure of said coking vessel(s).
16. The process of claim 1 wherein additive introduction is controlled by a pressurized injection system comprising at least one spray nozzle.
17. The process of claim 16 wherein said at least one spray nozzle is selected from the group consisting of nozzles for slurry spray shapes; nozzles for slurry spray angles; nozzles for slurry droplet sizes; nozzles for slurry velocities; nozzles for slurry size openings; and any combination thereof.
18. The process of claim 1 wherein a control for additive introduction is provided that is selected from the group consisting of vertical or horizontal injection lances from top of drum with or without spray nozzle(s); modified drill stem adapted to precede a vapor/liquid interface as it moves upward in said coking vessel(s); modified drill stem with adjustable, movable nozzle to assure coverage of vapor/liquid interface at various vessel levels; retractable, horizontal or vertical injection lances in various drum locations; and any combination thereof
19. The process of claim 1 wherein components of said additive are combined by mixing that provides a sufficient level of blending said components prior to addition to said coking vessel(s) of said coking process.
20. The process of claim 19 wherein said components of said additive are mixed by a mixing device selected from the group consisting of a mixing tank with impeller; variable shear mixing pumps; static in-line mixers; pump inlet mixing devices; and any combination thereof.
21. The process of claim 19 wherein said components of said additive are mixed by a mixing device selected from the group consisting of continuous mixing devices; semi-continuous mixing devices; batch mixing devices; and any combination thereof.
22. The process of claim 1 wherein a temperature of said additive is regulated by a temperature control that provides a predetermined temperature level of said additive prior to addition to said coking vessel(s) of said coking process.
23. The process of claim 22 wherein said temperature control is selected from the group consisting of a heating coil in a mixing tank with heat media flow control and insulated piping; steam tracing or steam-jacketed additive lines with temperature control(s); electric heat tracing of additive lines with temperature control(s); temperature controls on each additive component or any combination thereof; and any combination thereof.
24. The process of claim 1 wherein a flow rate of said additive is controlled by a pressurized injection system; other flow meter(s) with other control logic; flow meter(s) with complex computer control logic; separate flow meters on additive components with control logic to achieve a desired combination of additive components; or any combination thereof.
25. The process of claim 24 wherein said flow rate of said additive is controlled by flow meters with complex control logic related to a feed rate of said coking vessel(s).
26. The process of claim 1 wherein said catalyst(s) lowers an energy required for cracking reactions, coking reactions, or any combination thereof.
27. The process of claim 1 wherein said catalyst(s) provides propagation of carbon based free radicals that facilitate cracking and coking reactions.
28. The process of claim 1 wherein said catalyst(s) comprises alumina, silica, zeolite, calcium, activated carbon, crushed pet coke, or any combination thereof.
29. The process of claim 1 wherein said catalyst(s) comprises new catalyst, FCCU equilibrium catalyst, spent catalyst, regenerated catalyst, pulverized catalyst, classified catalyst, impregnated catalysts, treated catalysts, or any combination thereof.
30. The process of claim 1, wherein said catalyst(s) has particle size characteristics to prevent entrainment in vapors, to achieve fluidization in said coking vessel(s) and increase residence time in vapors, or any combination thereof.
31. The process of claim 1 wherein said catalyst(s) provides desired physical and chemical properties and/or characteristics selected from the group consisting of size to optimize catalyst settling characteristics in said coking vessel(s); porosity and activity combinations to optimize catalytic cracking of heavy hydrocarbons in liquid/foam layer(s) of a coking cycle; porosity and activity combinations to optimize catalytic cracking of hydrocarbons in product vapors in said coking vessel(s) during a coking cycle; and any combination thereof
32. The process of claim 1 wherein said catalyst(s) provides size distribution to optimize settling versus plugging of said catalyst(s).
33. The process of claim 1 further comprising cracking of said heavy hydrocarbons in said coking vessel(s) to lighter hydrocarbons that leave the coking vessel(s) as vapors and enter a downstream fractionator where said lighter hydrocarbons are separated into process streams that are useful in oil refinery product blending.
34. The process of claim 33 wherein said lighter hydrocarbon streams comprise naphtha, gas oil, gasoline, kerosene, jet fuel, diesel fuel, heating oil, or any combination thereof.
35. The process of claim 1 further comprising selecting or minimizing size of an additive system to locate as close to said coking vessel(s) as possible to limit line pressure drop and settling of catalyst in an injection system.
36. The process of claim 35 wherein said selection or minimization of size of said additive system includes: providing continuous mixing device in an additive injection system; designing additive injection system with major injection components, having optimal weight and system footprint to allow locating close to said coking vessel(s); using modified anti-foam system to limit new components or systems; or any combination thereof.
37. The process of claim 35 wherein said additive injection system is provided with vertical pump mounting to allow location close to said coking vessel(s) on a drilling deck.
38. A process comprising:
- introducing: excess reactant(s) containing hydrogen into a coker feed between a fractionator and a coker feed heater, in the coker feed heater, into a transfer line between a coker heater and a coking vessel(s), into said coking vessel(s) of a delayed coking process, or any combination thereof; and an additive by pressurized injection into said coking vessel(s) during a coking cycle of the delayed coking process to promote cracking of heavy hydrocarbons, wherein said additive comprises cracking catalyst(s), alone or in combination with seeding agent(s), excess reactant(s), quenching agent(s), carrier fluid(s), or any combination thereof;
- wherein said hydrogen from said excess reactant(s) promotes cracking of the heavy hydrocarbons.
Type: Application
Filed: Nov 25, 2014
Publication Date: Mar 19, 2015
Inventor: Roger G. ETTER (Delaware, OH)
Application Number: 14/553,959
International Classification: C10G 47/32 (20060101); C10G 47/12 (20060101);
