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CHAPTER 7.2UOP UNICRACKING PROCESS

FOR HYDROCRACKING

Donald AckelsonUOP LLC

Des Plaines, Illinois

INTRODUCTION

Hydrotreating and hydrocracking are among the oldest catalytic processes used in petro-leum refining. They were originally employed in Germany in 1927 for converting ligniteto gasoline and later used to convert petroleum residues to distillable fractions. The firstcommercial hydrorefining installation in the United States was at Standard Oil Companyof Louisiana in Baton Rouge in the 1930s. Following World War II, growth in the use ofhydrocracking was slow. The availability of Middle Eastern crude oils reduced the incen-tive to convert coal to liquid fuels, and new catalytic cracking processes proved more economical for converting heavy crude fractions to gasoline. In the 1950s, hydrodesulfur-ization and mild hydrogenation processes experienced a tremendous growth, mostlybecause large quantities of by-product hydrogen were made available from the catalyticreforming of low-octane naphthas to produce high-octane gasoline.

The first modern hydrocracking operation was placed on-stream in 1959 by StandardOil Company of California. The unit was small, producing only 1000 barrels per stream-day (BPSD). As hydrocracking units were installed to complement existing fluid catalyticcracking (FCC) units, refiners quickly recognized that the hydrocracking process had theflexibility to produce varying ratios of gasoline and middle distillate. Thus, the stage wasset for rapid growth in U.S. hydrocracking capacity from about 3000 BPSD in 1961 toabout 120,000 BPSD in just 5 years. Between 1966 and 1983, U.S. capacity grew eight-fold, to about 980,000 BPSD.

Outside the United States, early applications involved production of liquefied petrole-um gas (LPG) by hydrocracking naphtha feedstocks. The excellent quality of distillatefuels produced when hydrocracking gas oils and other heavy feedstocks led to the choiceof the hydrocracking process as a major conversion step in locations where diesel and jetfuels were in demand. Interest in high-quality distillate fuels produced by hydrocrackinghas increased dramatically worldwide. As of 2002, more than 4 million BPSD of hydroc-racking capacity is either operating or is in design and construction worldwide.

7.23

Source: HANDBOOK OF PETROLEUM REFINING PROCESSES

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PROCESS APPLICATIONS

Hydrocracking is one of the most versatile of all petroleum refining processes. Any frac-tion from naphtha to nondistillables can be processed to produce almost any desired prod-uct with a molecular weight lower than that of the chargestock. At the same time thathydrocracking takes place, sulfur, nitrogen, and oxygen are almost completely removed,and olefins are saturated so that products are a mixture of essentially pure paraffins, naph-thenes, and aromatics. Table 7.2.1 illustrates the wide range of applications of hydroc-racking by listing typical chargestocks and the usual desired products.

The first eight chargestocks are virgin fractions of petroleum crude and gas conden-sates. The last four are fractions produced from catalytic cracking and thermal cracking.All these streams are being hydrocracked commercially to produce one or more of theproducts listed.

This flexibility gives the hydrocracking process a particularly important role as refiner-ies attempt to meet the challenges of today’s economic climate. The combined influencesof low-quality feed sources, capital spending limitations, hydrogen limitations, environ-mental regulatory pressures, and intense competition have created a complex optimizationproblem for refiners. The hydrocracking process is uniquely suited, with proper optimiza-tion, to assist in solving these problems. UOP, with its broad background and researchcapabilities, has continued to develop both catalyst and process capabilities to meet thechallenges.

PROCESS DESCRIPTION

The UOP* Unicracking* process is carried out at moderate temperatures and pressuresover a fixed catalyst bed in which the fresh feed is cracked in a hydrogen atmosphere.Exact process conditions vary widely, depending on the feedstock properties and the prod-ucts desired. However, pressures usually range between 35 and 219 kg/cm2 (500 and 3000lb/in2 gage) and temperatures between 280 and 475°C (536 and 887°F).

7.24 HYDROCRACKING

TABLE 7.2.1 Applications of the Unicracking Process

Chargestock Products

Naphtha Propane and butane (LPG)Kerosene NaphthaStraight-run diesel Naphtha and/or jet fuelAtmospheric gas oil Naphtha, jet fuel, and/or distillatesNatural gas condensates NaphthaVacuum gas oil Naphtha, jet fuel, distillates, lubricating oilsDeasphalted oils and demetallized oils Naphtha, jet fuel, distillates, lubricating oilsAtmospheric crude column bottoms Naphtha, distillates, vacuum gas oil, and

low-sulfur residual fuelCatalytically cracked light cycle oil NaphthaCatalytically cracked heavy cycle oil Naphtha and/or distillatesCoker distillate NaphthaCoker heavy gas oil Naphtha and/or distillates

*Trademark and/or service mark of UOP.

UOP UNICRACKING PROCESS FOR HYDROCRACKING



UOP UNICRACKING PROCESS FOR HYDROCRACKING 7.25

Chemistry

Hydrocracking chemistry is bifunctional catalytic chemistry involving acid-catalyzed iso-merization and cracking reactions as well as metal-catalyzed hydrogenation reactions. Theresulting products are lower in aromatics and contain naphthenes and highly branchedparaffins due to the higher stability of the tertiary carbenium ion intermediate. For paraf-fins, the reaction network, shown in Fig. 7.2.1, is postulated to begin with a dehydrogena-tion step at a metal site forming an olefin intermediate, which is quickly protonated at anacid site to yield a carbenium ion. This is quickly followed by a series of isomerizationreactions to the most stable tertiary carbenium ions and subsequent cracking to smallerparaffin, which evolves off the catalyst surface and smaller carbenium ion intermediate.The carbenium ion can then eliminate a proton to form an olefinic intermediate, which getshydrogenated at a metal site or directly abstract a hydride ion from a feed component toform a paraffin and desorb from the surface.

A typical hydrocracking reaction for a cycloparaffin (Fig. 7.2.2) is known as a paringreaction, in which methyl groups are rearranged and then selectively removed from thecycloparaffin without severely affecting the ring itself. Normally the main acyclic productis isobutane. The hydrocracking of multiple-ring naphthene, such as decalin, is more rap-id than that of a corresponding paraffin. Naphthenes found in the product contain a ratioof methylcyclopentane to methylcyclohexane that is far in excess of thermodynamic equi-librium.

Reactions during the hydrocracking of alkyl aromatics (Fig. 7.2.3) include isomeriza-tion, dealkylation, paring, and cyclization. In the case of alkylbenzenes, ring cleavage isalmost absent, and methane formation is at a minimum.

FIGURE 7.2.1 Postulated paraffin-cracking mechanism.




Catalyst

Hydrocracking catalysts combine acid and hydrogenation components in a variety of typesand proportions to achieve the desired activity, yield structure, and product properties.Noble metals as well as combinations of certain base metals are employed to provide thehydrogenation function. Platinum and palladium are commonly used noble metals whilethe sulfided forms of molybdenum and tungsten promoted nickel or cobalt are the most

7.26 HYDROCRACKING

FIGURE 7.2.2 Postulated cracking mechanism for naphthenes.

FIGURE 7.2.3 Postulated aromatic-dealkyla-tion mechanism. Isobutane is also formed follow-ing butyl carbenium ion isomerization, olefinformation, and hydrogenation.




common base-metal hydrogenation agents. The cracking function is provided by one or acombination of zeolites and amorphous silica-aluminas selected to suit the desired operat-ing and product objectives.

A postulated network of reactions that occur in a typical hydrocracker processing aheavy petroleum fraction is shown in Fig. 7.2.4. The reactions of the multiring speciesshould be noted. These species, generally coke precursors in nonhydrogenative cracking,can be effectively converted to useful fuel products in a hydrocracker because the aromat-ic rings can be first hydrogenated and then cracked.

Amorphous silica-alumina was the first catalyst support material to be used extensive-ly in hydrocracking service. When combined with base-metal hydrogenation promoters,these catalysts effectively converted vacuum gas oil (VGO) feedstocks to products withlower molecular weight. Over three decades of development, amorphous catalyst systemshave been refined to improve their performance by adjustment of the type and level of theacidic support as well as the metal function. Catalysts such as UOP’s DHC-2 and DHC-8have a well-established performance history in this service, offering a range of activity andselectivity to match a wide range of refiners’ needs.

Crystalline catalyst support materials, such as zeolites, have been used in hydrocrack-ing catalysts by UOP since the mid-1960s. The combination of selective pore geometryand varying acidity has allowed the development of catalysts that convert a wide range offeedstocks to virtually any desired product slate. UOP now offers catalysts that will selec-tively produce LPG, naphtha, middle distillates, or lube base oils at high conversion activ-ity using molecular-sieve catalyst support materials. The UOP zeolite materials used inhydrocracking service are often grouped according to their selectivity patterns. Base met-al catalysts utilized for naphtha applications are HC-24, HC-34, and HC-170. Flexible basemetal catalysts (naphtha, jet, diesel) include DHC-41, HC-43, HC-33, HC-26, and HC-29.The distillate catalysts, which offer a significantly enhanced activity over amorphous cat-alysts while maintaining the excellent middle-distillate selectivity, are HC-110, HC-115,DHC-32, and DHC-39. Noble metal catalysts are also available for both naphtha (HC-28)and jet/naphtha (HC-35) service. Unlike the amorphous-based catalysts, the zeolite-con-taining materials are usually more selective to lighter products and thus more suitablewhen flexibility in product choice is desired. In addition, zeolitic catalysts typically


FIGURE 7.2.4 Hydrocracking reactions.




employ a hydroprocessing catalyst upstream, specifically designed to remove nitrogen andsulfur compounds from the feed prior to conversion. UOP catalysts such as HC-P, HC-R,HC-T, UF-210, and UF-220 are used for this service. These materials are specificallydesigned with high hydrogenation activity to effectively remove these compounds, ensur-ing a clean feed and optimal performance over the zeolitic-based catalyst.

One important consideration for catalyst selection is regenerability. Hydrocracking cat-alysts typically operate for cycles of 2 years between regenerations but can be operated forlonger cycles, depending on process conditions. When end-of-run conditions are reached,as dictated by either temperature or product performance, the catalyst is typically regener-ated. Regeneration primarily involves combusting the coke off the catalyst in an oxygenenvironment to recover fresh catalyst surface area and activity. Regenerations can be per-formed either with plant equipment if it is properly designed or at a vendor regenerationfacility. Both amorphous and zeolitic catalysts supplied by UOP are fully regenerable andrecover almost full catalyst activity after carbon burn.

Hydrocracking Flow Schemes

Single-Stage. The single-stage flow scheme involves full conversion through recyclingof unconverted product and is the most widely used because of its efficient designresulting in minimum cost for a full-conversion operation. This scheme can employ acombination of hydrotreating and cracking catalysts or simply amorphous crackingcatalysts depending on the final product required.

Once-Through. Unlike the single-stage flow scheme, the once-through flow scheme isa partial conversion option that results in some yield of unconverted material. Thismaterial is highly saturated and free of feed contaminants but is similar in molecularweight to the feed. If a refinery has a use for this unconverted product, such as FCC feedor high-quality lube base oil, this flow scheme may be preferred.

Two-Stage. In the two-stage flow scheme, feedstock is treated and partially convertedonce-through across a first reactor section. Products from this section are then separatedby fractionation. The bottoms from the fractionation step are sent to a second reactorstage for complete conversion. This flow scheme is most widely used for large unitswhere the conversion in the once-through first stage allows high feed rates withoutparallel reactor trains and the added expense of duplicate equipment.

Separate-Hydrotreat. The separate-hydrotreat flow scheme is similar to single-stage,but is configured to send reactor effluent that has been stripped of hydrogen sulfide andammonia to the cracking catalyst. This configuration allows the processing of feedstockswith very high contaminant levels or the use of contaminant-sensitive catalysts in thecracking reactor if dictated by product demands.

The single-stage flow scheme is the most widely used hydrocracking flow scheme incommercial service. The flow scheme allows the complete conversion of a wide range offeedstocks and product recovery designed to maximize virtually any desired product. Thedesign of this unit configuration has been optimized to reduce capital cost and improveoperating performance. Greater than 95 percent on-stream efficiency is typical.

Figure 7.2.5 illustrates a typical single-stage flow scheme. Feedstock, recycle oil, andrecycle gas are exchanged against reactor effluent to recover process heat and are then sentthrough a final charge heater and into the reactor section. The reactor section contains cat-alysts that allow maximum production of the desired product slate. In virtually all hydro-cracking systems, the combined reactions are highly exothermic and require cold hydrogen

7.28 HYDROCRACKING




quench injection into the reactors to control reactor temperatures. This injection is accom-plished at quench injection points with sophisticated reactor internals that both mix reac-tants and quench and redistribute the mixture. Proper mixing and redistribution are criticalto ensure good temperature control in the reactor and good catalyst utilization throughacceptable vapor or liquid distribution.

In this typical configuration, reactor effluent is sent through exchange to a hot separator,where conversion products are flashed overhead and heavy unconverted products are takenas hot liquid bottoms. The use of a hot separator improves the energy efficiency of theprocess by allowing hot liquid to go to the fractionation train and prevents polynuclear aro-matic (PNA) fouling of cold parts of the plant. The overhead from the hot separator goes toa cold separator, where recycle gas is separated from the product. The product is then sent tofractionation, and recycle gas is returned to the reactor via the recycle compressor.

The fractionation train typically starts with a stripper column to remove hydrogen sul-fide, which is in solution with the products. The removal ensures a relatively clean prod-uct in the main fractionator column, thus reducing column costs and metallurgyrequirements. The stripper is followed by a main fractionating column with appropriatestages and sidedraws to remove the desired products. The bottoms from this main columnis recycled back to the reactor section for complete feed conversion.

To allow complete conversion without PNA fouling or excessive catalyst coking, UOPhas developed several techniques to selectively remove PNAs from the recycle oil stream.Some PNA removal is critical for successful operation at complete conversion. In earlierdesigns, the unit was simply purged of PNAs by taking a bottoms drag stream. In newerunits, PNAs may be selectively removed by either fractionation or adsorption. The resultis an increased yield of valuable liquid product.

HyCycle. HyCycle typically uses back-staged, series-flow cracking and hydrotreatingreactors. The products and unconverted oil (UCO) from the hydrotreating reactor areseparated in the high-pressure section, creating the recycle oil for the cracking reactor.Similar to separate-hydrotreat and two-stage configurations, the recycle oil iscontaminant-free. Because of the efficient separation of UCO from products, the recycleoil rate can be increased above typical hydrocracking levels, allowing the crackingcatalyst to operate at lower severity and produce higher yields. The HyCycleconfiguration provides the lowest operating and equipment cost for many operations.


FIGURE 7.2.5 Typical flow diagram of a single-stage Unicracking unit.




The HyCycle process uses a combination of several unique, patented design features tofacilitate an economic full (99.5 percent) conversion operation at low (20 to 40 percent)conversion per pass. Another important feature of the process is reduced operating pres-sure. Relative to current practice, HyCycle Unicracking designs are typically 25 percentlower in design pressure. The key benefits of the process are lower hydrogen consumptionand higher selectivity to heavier product. For example, up to 5 vol % more middle distil-late yield with as much as a 15 percent shift toward diesel fuel can be achieved when com-pared to other full conversion maximum distillate designs. This shift in selectivity coupledwith a more selective saturation of feed aromatics results in as much as a 20 percent reduc-tion in process hydrogen requirement.

In the process, cracked products and unconverted oil are separated in the HyCycleenhanced hot separator (EHS) at reactor pressure. The separated products are then hydro-genated in a posttreat reactor. This unique processing step maximizes the quality of the dis-tillate product for a given design pressure. It also provides a more efficient means ofrecycling UCO to the cracking reactor, enabling a less severe (lower) per pass conversionthat results in improved selectivity and yield. The hydrocracking catalyst zone configura-tion is referred to as back-staged because recycle oil is routed first to a hydrocracking cat-alyst zone and then to a hydrotreating catalyst zone. The benefits of back-staging includecleaner feedstock to the cracking catalyst and higher hydrogen partial pressure. The netresult is higher catalyst activity per unit volume, hence a lower catalyst volume require-ment. The reactors use a common series flow recycle gas loop to maintain the economicefficiency of a single-stage design. In addition, UOP low-temperature catalysts are used inthe reactor(s) to enable higher combined feed rates without increasing reactor diameter orpressure drop. Figure 7.2.6 illustrates a typical HyCycle flow scheme.

Products from Hydrocracking

Hydrocracking units process lower-value, sulfurous feedstocks such as vacuum distillatesand cracked stocks to produce higher-value fuels. There is tremendous flexibility, throughchoice of catalysts and unit configuration, to optimize product quality and yield structure.

The hydrocracking process has a well-demonstrated versatility. This can be shown inthe yield and product quality information shown in Table 7.2.2 for processing a MiddleEast VGO for maximum distillate and for maximum naphtha, the two extremes of hydro-cracking operation.

Improvements in Yield-Activity Relationships

One of the difficult decisions refiners face when selecting hydrocracking technology iswhether to sacrifice activity to gain yield, or sacrifice yield to gain activity. Many refinersin North America, for example, would like to increase C6� naphtha yield, but not at thecost of lower activity. They may also like a flexible catalyst for seasonal shifts in theirproduct slate. Refiners in Europe and the Far East often ask for higher-activity distillatecatalysts.

To meet the needs of refiners around the world, UOP continues to develop catalysts thatprovide enhanced performance without sacrificing yield or activity. Figure 7.2.7 shows rel-ative activity-selectivity curves for previous and current generations of UOP hydrocrack-ing catalysts. Selectivity to diesel product is shown on the vertical axis, and the catalyst’sactivity is shown on the horizontal axis. Each symbol on the curves represents a catalystin the UOP portfolio. New generations of catalysts are currently being developed toimprove these relationships.

7.30 HYDROCRACKING





ProductFractionator

0.5%UCO

To LPGRecovery

FeedGas

H2

AmineScrubber

HPS S

CF

HF

PTRx

EnhancedHot

Separator

HCRx

HTRx

Feed

FIGURE 7.2.6 HyCycle Unicracking process schematic flow diagram.

TABLE 7.2.2 Typical Hydrocracker Yields*

Distillate Naphtha

Yield:NH3, wt % 0.1 0.1H2S, wt % 2.6 2.6C2-, wt % 0.6 0.8C3, wt % 1.0 3.3C4, vol % 3.5 21.4Light naphtha, vol % 7.5 39.1Heavy naphtha, vol % 11.4 68.9Distillate, vol % 94.0 —

Product properties:Jet fuel cut:

Smoke point, mm 29 —Freeze point, °C (°F) �59 (�74) —Aromatics, vol % 9 —

Diesel fuel cut:Cetane no. 60 —

Total naphtha:P/N/A, vol — 33/55/12Research octane no. — 70

*Basis: Feedstock, Middle East VGO; density, 22.2 °API; sulfur,2.5 wt %.

Note: P/N/A � paraffins/naphthenes/aromatics; °API �degrees on American Petroleum Institute scale.




INVESTMENT AND OPERATING EXPENSES

Capital investment and operating expenses for a hydrocracker are sensitive to

● The processibility of the feedstock● The desired product slate● The desired product specifications

The desired product slate has a profound effect on the arrangement of equipment, as dis-cussed in the previous section. If the feed has demetallized oil or is more difficult toprocess for some other reason, operating conditions can be more severe than in hydroc-racking a VGO. This additional severity can be manifested in equipment, hydrogen con-sumption, utilities, and additional catalyst. In general, a jet fuel operation is more severethan an operation producing a full-range diesel product. Naphtha production requires ahigher hydrogen consumption than either jet fuel or diesel production.

Only typical examples can be given; not every case can be covered. The figures in theaccompanying tables are for illustrations only; variation may be expected for specific cas-es. Typical capital investment guidelines are given in Table 7.2.3. Typical utility guidelinesare given in Table 7.2.4.

AKNOWLEDGMENTS

I wish to acknowledge Dr. Suheil Abdo for his comments on the chemistry and catalystsections of this chapter.

7.32 HYDROCRACKING

Dis

tilla

tes

Sele

ctiv

ity

Activity

MaxDiesel Distillates

MaxNaphthaFlexible

Previous GenerationsCurrent Generation

FIGURE 7.2.7 New generation Unicracking catalysts offer enhanced per-formance.





TABLE 7.2.3 Hydrocracker Capital Investment*

Operation Distillate Naphtha

Estimated erected cost, $/BPSD CF 2500–3500 2000–3000

*As of January 1, 2002, based on combined-feed (CF) rate; includes 20 per-cent of material and labor as design engineering plus construction engineeringcost; does not include hydrogen plant; BPSD � barrels per stream-day.

TABLE 7.2.4 Typical Hydrocracker Utilities

Power, kW 200–450Fired fuel, 106 Btu/h 2–6Cooling water, gal/min 40–120Medium-pressure steam, MT/h (klb/h) 0.11–0.22 (0.25–0.50)Condensate, MT/h (klb/h) 0.08 (0.2)

Note: Based on 1000-BPSD fresh feed; MT/h � metric tons per hour.




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