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HYDROCRACKING AND PRODUCT TREATING AND BLENDING
Publication date:2Q 2019
Hydrocracking and Product Treating and Blending
Hydrocracking (HC) is utilized in refineries to upgrade a variety of feeds that range from coker naphtha to various heavy gas oils and residual fractions into lighter molecules. The hydrocracking process has emerged as the primary diesel producer in many refinery configurations, and as environmental regulations on transportation fuels continue to tighten, the hydrocracker will be one of the tools available to refiners to meet new product specifications. Unlike FCCU processes, hydrocrackers can effectively yield ultra-low sulfur diesel (ULSD) streams whereas middle-distillate range FCC products (i.e. light cycle oil, LCO) will regularly require additional treating to meet product blending specifications.
Hydrocracking units can also offer improved flexibility to shift production modes between gasoline and diesel (or called gas oil) products based on process selection, operating conditions, and catalysts used. The severity (e.g., temperature, H2 partial pressure, LHSV, process configuration, catalyst type, etc.) of the unit is set based upon the composition and properties of the feedstock processed and the desired conversion level and/or product distribution. Certain feeds (e.g., paraffinic) may be difficult to crack and thus require a higher operating temperature, while others (e.g., aromatic feeds) may have a high tendency for coke formation and, thus, require special catalyst formulations. Hydrocracker operators have been looking to increase the profitability of the unit by processing heavier feedstreams, including heavy vacuum gas oil (HVGO), FCC LCO, coker gas oil, visbroken gas oil, deasphalted oil, and resid feeds, while minimizing the hydrogen consumption and boosting overall energy efficiency. Residual feeds present the problems of increased H2 consumption, lower product yields and quality, and reduction in cycle length. Technology developers have been searching for methods to allow for hydrocracking units to continue normal operation while processing these difficult-to-handle feeds. These optimized parameters include higher liquid-gas distribution and reactor volume efficiency. Along with optimized process parameters, catalyst companies are also developing novel formulations that aim to increase process performance while dealing with these challenging feeds. These novel catalysts may be paired with state-of-the-art reactor internals to maximize performance.
Typical yields for a full conversion hydrocracker using a flexible catalyst to swing between maximum diesel and naphtha modes are: 0.2-0.4 wt% dry gas, 6.0-13.0 vol% LPG, 28.0-48.0 vol% naphtha, and 54.0-85.0 vol% diesel and jet fuel combined. If the unit is designed to make maximum naphtha, the total naphtha yield could be as high as 115.0 vol%. Light naphtha from a hydrocracker often can be blended directly into gasoline pool. The heavy naphtha is typically sent to reforming unit for octane boost. The reformer generates hydrogen but a hydrogen plant is likely required to supplement the hydrogen requirement of the hydrocracker. The diesel and jet fuel require no further processing, as these often exceed the cetane and smoke point requirements, respectively.
Process designers and catalyst manufacturers are feverishly developing cost-effective and energy-efficient hydrocracking technology and revamp options to satisfy the refining industry around the world. Hydrocracking technology licensers are looking at new ways to remove heavy polynuclear aromatics (HPNAs) from the unit as the buildup of HPNAs can lead to increased catalyst deactivation and fouling. Multiple-phase hydroprocessing units have also been developed to minimize hydrogen consumption while also reducing unit severity. Finally, the utilization of hydrocracking technologies to upgrade resid and/or renewable feeds to produce additional supplies of high-quality liquid products has been covered extensively through commercial projects and R&D work over the past several years.
Additionally, the hydrocracking section features the latest trends and technology offerings, including:
Product Treating and Blending
Regulatory specifications for the acceptable levels of various compounds (e.g., sulfur, benzene, aromatics, etc.) in transportation fuels have been put in place in many regions around the world. Additionally, legislation regarding more stringent specifications in many countries and first-time regulations in developing nations are imminent. To deal with this situation, refiners spend a great deal of time and capital modifying distilled products before sending them to the marketplace. Hydrotreating is the dominant technology used to remove undesirable compounds from end products, but it is often not ideal.
Non-hydrogen product treating technologies for sulfur removal can be separated into three general categories: (1) mercaptan sweetening/extraction, (2) bulk sulfur removal, and (3) selective removal of refractory sulfur for polishing and niche treating applications. Besides sulfur removal, gasoline benzene reduction is also a critical treatment requirement as benzene is known to be a carcinogen. Refiners have four primary options: (1) benzene saturation with hydrogen, (2) benzene alkylation, (3) benzene extraction, and (4) removal of benzene precursors from the catalytic reformer feed.
Many refiners have already committed large capital investments to hydroprocessing technologies to meet current and future specs. However, the combined implementation of non-hydrogen product treating technologies can still be useful in the current market place for "niche application" (e.g., treating diesel streams with a high concentration of DBT) and for easing the burden of HDS in a hydrogen-constrained refinery. Additionally, the use of these technologies for product polishing to meet current and future "near-zero" sulfur specifications for transportation fuels remains an attractive area.
Mercaptan sweetening/extraction techniques have been commercially available for quite some time, and have proven to be advantageous over hydrotreating technologies when treating mercaptans. The removal or conversion of the odorous organic sulfur compounds via product treatment technologies will help to avoid mercaptan recombination that can occur in hydrotreating schemes. Other commercial product treating technologies utilize oxidative desulfurization, adsorption, emulsification and electric field separation, membrane desulfurization, and olefin alkylation.
Product blending is also important as refiners attempt to meet fuel specifications and remain economically competitive. This is particularly the case for marine fuels as the implementation of the International Maritime Organization (IMO)'s 2020 0.5%-sulfur spec looms closer. One option to meet this requirement is to use a custom fuel oil blended from various refining streams such as low-sulfur straight-run, residue, cutter stock, treated light distillate, unconverted hydrotreated oil, and even a small amount of kerosene.
In regards to gasoline, many countries are utilizing ethanol as a blending component as a way to cut dependence on imported oil and lower CO2 emissions. The inclusion of additional quantities of ethanol into the gasoline supplies around the world is, however, not without its challenges, most notably in relation to the negative impact that ethanol blending has on the gasoline pool's RVP value. Thus, to offset the increase in fuel volatility that occurs when ethanol is added to the gasoline pool, refiners and fuel blenders must increase the use of expensive, low-RVP components (e.g., alkylate).
Also, the ongoing shale boom in the US has created abundant stocks of cheap butane. Profit increases can be realized through gasoline blending when a cheaper blending component like butane is utilized. While butane can increase the knock resistance of gasoline, it also has a significant impact on the vapor pressure of the fuel and its use is therefore limited by RVP specifications.
A number of companies offer automated equipment for monitoring and controlling refinery blending plants to improve economics and enhance efficiency of product blending applications. The technologies incorporate modeling programs, tank monitors, blend analyzers, and comprehensive oil movement systems that will provide efficient planning and scheduling and ensure consistent operations in the blending plant. These systems minimize giveaway and the need to reblend by continuously analyzing the properties of blendstocks and controlling the flow of every component into each batch of product. The control units of today make extensive use of non-linear programming to meet the constraints of the models (e.g. created by the US EPA) with the least costly blending components. The technology offered by commercial companies has evolved in response to tighter fuel specifications around the world.
Additionally, the product treating and blending section features the latest trends and technology offerings, including:
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Keywords: hydrogen, hydrocracking, middle distillates, diesel, ULSD, heavy oil, tight oil, ebullated-bed, slurry-bed, fixed-bed, single-stage, two-stage, two-stage with recycle, jet fuel, kerosene, gasoil, gas oil, coker gas oil, coker naphtha, DAO, VGO, HVGO, LCO, mild hydrocracking, resid hydrocracking, renewable hydrocracking, renewable jet fuel, renewable diesel, biodiesel, dewaxing, cold flow properties, cloud point, pour point, cetane, platinum, palladium, NiMo, CoMo, NiW, heavy polynuclear aromatics, HPNAs, Fischer-Tropsch, F-T, sulfur specification, benzene limits, aromatics specification, light distillate, middle distillate, fuel oil, non-hydrogen desulfurization, mercaptan sweetening, extraction, sulfur adsorption, refractory sulfur, benzene alkylation, caustic treatment, pervaporation membrane, oxidative desulfurization, bio-desulfurization, olefin alkylation, automated blending, color degradation, biofuels, ethanol blending, IMO 2020, bunker fuel, bunker blends