Choosing a hydroprocessing scheme

Hydroprocessing technologies are well established in the refining industry for the

production of clean fuels. However, increased competition within the industry mandates a greater focus on awareness of the right tech-nology and catalysts to achieve the products and performance needed in the market.

For refiners to sustain their profit margins, economical access to state-of-the-art technology is a must. Refinery management needs to plan for the future to maintain long- term growth, maximise asset performance, formulate an effective response to changing environ-mental legislation and incorporate sufficient flexibility to withstand business cycles while crude supplies are becoming increasingly heavy and sour. Increased operational excellence is a priority for refineries, which leads refiners to look at more innovative ways of maintaining reasonable margins in new projects, to quickly recover the investments they have made and to justify additional investment to cope with a changing market.

Hydrotreating, the workhorse of the refinery, serves to meet several significant product quality specifi-cations. Increasingly stringent regulations for fuel (for instance, 10–15 ppm sulphur in diesel and gasoline), the processing of lower-quality, higher-sulphur crudes, tightening site emissions standards (SOx and NOx reduction), and rising gasoline and diesel consumption are all factors that make significant demands of a hydroprocessing unit in a refinery. In addition, a hydro-processing unit helps refiners to

A systematic approach to selecting hydroprocessing technology meets process objectives with optimal operating and capital costs

AlpesH GurjArFluor Daniel India

reduce nitrogen and aromatic content, and enhance cetane number, API gravity and smoke point. Hydroprocessing of middle distil-lates also plays a key role in improving cold flow properties such as pour point, cloud point and cold filter plug point. This enables refiners to meet the stringent product specifi-cations determined by regulatory bodies.

The established refinery configur-ation includes a minimum of three or four hydroprocessing units for upgrading light, middle and heavy

distillates. Upgrading light distillate involves the use of proven technology for the desulphurisation of FCC naphtha with minimum octane loss, as this stream contri-butes significantly to the refinery gasoline pool. Upgrading middle distillate (kerosene and diesel) focuses on managing hydrogen and energy consumption, while produc-ing ultra-low sulphur products. The gas oils and residue upgrading technology, such as hydrocracking and residual oil desulphurisation

(RDS), should be flexible enough to process a wide range of feed qualities, of diverse origin, at different conversion levels.

Basis of technology evaluationAll technologies work well within a specific context and under certain conditions. The total investment costs for a hydroprocessing unit increase with unit size, feedstock sulphur, nitrogen and quantity of cracked stocks. The evaluation of new technology should be based on detailed technical and economic analysis.

The total on-site capital cost estimate for a new hydrotreater unit varies, depending on the licensed and proprietary technology. The overall system can be broadly classified in three parts: a reactor system, hydrogen make-up/recycle gas compressor and other separation equipment. The cost of the reactor system and compressor depends on the percentage of cracked stock present in the hydrotreater feed. The cost of the separation equipment is a function of unit capacity. The basic difference in the capital costs of a unit at a given capacity level is the result of variations in the fractions of the different types of feed; for example, straight-run vs cracked stock and the sulphur level of the feed as well as the catalyst.

The major items of focus during the evaluation of hydroprocessing technology are process configur-ation, reactor operating conditions, number and size of high-pressure items, quantity and type of catalyst used, catalyst deactivation rate, make-up hydrogen purity and design pressure level, depending

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The total investment costs for a hydroprocessing unit increase with unit size, feedstock sulphur, nitrogen and quantity of cracked stocks

process severity/variablesA key factor to be considered in establishing an effective hydro-processing technology is the level of conversion required for achieving the desired objective. This level of conversion effectively sets the level of process severity required, from mild hydrofinishing for removing contaminants such as sulphur and nitrogen containing compounds, to complex molecular reconstructions associated with hydrocracking and aromatic saturation reactions. The operating conditions of a hydro-processing unit are a function of feedstock characteristics based on origin. The operating and capital cost of the unit increases with the severity of the unit. The proper combination of process parameters should be in accordance with the optimal use of hydrogen and the available utilities, such as fuel, cooling water and steam. The key process variables are liquid hourly space velocity (LHSV), hydrogen partial pressure, temperature and gas-to-oil ratio.

liquid hourly space velocity LHSV is a measure of the residence time in the reactor. The lower the LHSV, the higher the residence time. The lower the LHSV, the bigger the reactor and the higher the capital cost. Typically, the LHSV require-ment depends on the boiling range of the hydrocarbons. A heavy feed contains higher amounts of sulphur and nitrogen impurities with a complex ring structure. The removal of such compounds requires more residence time in a reactor and therefore lower LHSV. LHSV can be adjusted by either reducing the feed throughput, which is not economical, or by the addition of a new reactor or more catalyst in the same reactor, which requires substantial capital investment. An optimal design is usually one that takes advantage of a higher-activity, commercially proven catalyst to set reactor catalyst volumes and pressure levels for a target run length. Figure 1 shows the effect of a decrease in LHSV on polyaromatic saturation levels.

Hydrogen partial pressureThe type of feed to be processed,

on the product quality requirements. In determining the compatibility of the licensor’s technology with existing facilities it is essential to check its capability with regard to variations in feed qualities and the effect of product slate for blending.

The key process objectives to define in order to establish a transparent and consistent evalu-ation methodology are:• Desired function of the hydro-processing unit in the refinery, such as hydrodesulphurisation (HDS), hydrodenitrification (HDN), olefin saturation, aromatic saturation and metals removal• Feed and product specifications• Minimum catalyst cycle length • Hydrogen utilisation• Availability of the unit (on-stream operating factor per year)• Unit turndown capacity.

Criteria for selecting technology No single process technology solution can be applied to all refineries because of their widely different configurations and objec-tives. A comprehensive, site-specific study is needed to identify the most suitable process scheme under given scenarios. The evaluation should be based on the criteria developed and approved by project management and the client during the planning phase.

Technical evaluation of a licensor’s technology is of prime importance when it comes to customising its unique features, amplifying its reliability, flexibility and operational performance, and so meet current needs and future requirements. The key points that significantly influence the hydroprocessing unit’s process design follow.

Feed characterisation Good feedstock characterisation, including off-design variations, is essential for the proper selection of catalyst, reaction conditions and process configuration. A study of feedstock at the micro level provides a thorough understanding of feedstock reactivity and the subsequent processing conditions needed to meet process objectives. The distribution and nature of

sulphur and nitrogen compounds in a feed depends on the feedstock’s boiling range, prior processing history (whether thermally or catalytically cracked) and the crude oil type from which it is derived. The olefin content associated with cracked stock gives an idea of anticipated exotherms, the configuration of efficient quenching, heat recovery and the separation system. It also enables a refiner to choose a reactor catalyst bed arrangement. The aromatic content of a feed and its saturation requirements fixes the partial pressure of a distillate hydrotreating unit, which plays an important role in the operating and capital cost of the unit. The prediction of

unit dynamics caused by feed quality changes is of prime importance during the design phase of the unit.

process chemistry An understanding of the chemistry involved in the removal of sulphur and nitrogen compounds is essential when defining the operating severity, based on varying relative rates of reactions of different com-pounds. Desulphurisation, denitrifi-cation and olefin saturation are kinetically controlled reactions. Increasing the process severity, such as raising the temperature, usually allows these reactions to approach near complete conversion. However, the aromatic saturation reaction is thermodynamically limited, so a careful balancing of kinetic and thermodynamic equilibrium is required when deciding on pressure level and catalyst volume.

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The prediction of unit dynamics caused by feed quality changes is of prime importance during the design phase of the unit

product quality requirements, yield and the amount of conversion for a specific catalyst cycle life determine the hydrogen partial pressure required for the operation of a hydroprocessing unit. The hydrogen partial pressure must be high enough to accomplish the desired level of denitrification and partial saturation of heavy aromatic molecules. At higher partial pressures, the desulphurisation and denitrification process is “easier”; however, the unit becomes more expensive because of the need for thicker-walled reactors. The minimum pressure required typically rises with the required severity of the unit. A higher hydrogen partial pressure decreases catalyst deactivation and, therefore, increases the predicted cycle length for a fixed quantity of catalyst.

The importance of maintaining adequate hydrogen partial pressure increases as sulphur levels approach the sub-ppm level, because the primary HDS reaction shifts from a predominantly non-reversible, single-step reaction to a reversible, equilibrium-limited, two-step reac-tion. As the unit approaches a higher operating temperature at end-of-run (EOR) conditions, the lower-pressure unit may struggle to meet 10 wppm sulphur requirements because of the effects of thermodynamic equilibrium.

At lower sulphur levels, the remaining species behave like polyaromatics and, therefore, the chemistry of their removal obeys similar rules to the saturation of polyaromatics. Figure 1 shows that an increase in total pressure/hydrogen partial pressure increases the absolute level of polyaromatic saturation.

Temperature (WABT)For most hydrotreating units, the only parameter that typically varies once the unit is built is the start-of-run (SOR) temperature, depending on catalyst activity. Since the EOR temperature is usually fixed, based on the specification or unit hardware constraints, a higher-activity catalyst will help to start the reaction at a colder temperature, thereby increasing the temperature

span, and so will benefit from a longer run, increased unit throughput or the ability to process a challenging feed mix. The operating temperature should be high enough to facilitate faster kinetic reaction rates, but not so high as to promote undesirable side reactions or to exceed the metal-lurgical limits of high-pressure vessels.

As the end point of hydrocarbon feed increases, there is an increase in the concentration of recalcitrant sulphur and nitrogen species in the form of dibenzothiophenes, which necessitates a higher SOR temper-ature. For grassroots units, a higher-

activity catalyst may be employed to optimise the unit design temper-ature and pressure requirements in order to save capital investment.

Hydrogen/hydrocarbon ratio andrecycle gas rateThe choice of recycle gas rate is governed by economic consider-ations. Recycle hydrogen is used to enable flow distribution and uniform physical contact of the hydrogen with oil-soaked catalyst to ensure adequate conversion and removal of impurities, while minimising carbon deposition. For high-activity hydrotreating catalysts, there may be a minimum treat gas circulation requirement to preserve catalyst

activity. There is a minor boost in hydrogen partial pressure as well with increasing gas circulation rates. However, above a certain gas rate, the increase in hydrogen partial pressure will be relatively small and incur extra heating and cooling costs.

In addition to affecting hydrogen partial pressure, the gas rate is important because it acts to strip volatile products from the reactor liquids, and thus affects the concentration of various components in the reactive liquid phase. It also maintains proper mass velocity in the catalyst bed, thus reducing the possibilities of channelling in the

bed, and carries the reaction heat. It is prudent to maintain a healthy hydrogen-to-oil ratio to prevent coking and subsequent deactivation of the catalyst. As a guide, the available hydrogen at the top of the reactor should be two-and-a-half to three times the chemical hydrogen consumption for easier feedstocks and three to four times the chemical hydrogen consumption for cracked feedstocks.

Catalyst selectionHydrotreating catalysts consist of a hydrogenation component dis-persed on a porous, fairly inert material. For hydrotreating, catalysts with weak acidity are used, since

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Thermodynamic effects

Increasing pressureDecreasing

LHSV

LHSV effects

Figure 1 The impact of process conditions on polyaromatic saturation

is high, a NiMo catalyst system may be the right choice. Recent advances include staging or stacking both CoMo and NiMo catalysts within a single fixed-bed reactor.

Hydrocracking catalysts serve dual functions, containing both hydrogenation and cracking sites. The cracking sites are usually the result of using a porous support of an acidic nature, such as amorphous silica-alumina and crystalline aluminosilicates or zeolites. The best choice of catalyst for a specific objective requires a particular balance between the cracking and hydrogenation functions.

In addition to the chemical nature of the catalyst, which dictates its

hydrogenation and cracking capa-bilities, its size, shape and pore structure are very important, as they govern the pressure drop, surface-to-volume ratio and diffusion rate.

Different shapes of catalyst are often used to take advantage of their high surface-to-volume ratio, while still maintaining a reasonable reactor pressure drop. The reaction kinetics are usually diffusion limited; a small catalyst with a high surface-to-volume ratio has better diffusion for the relatively heavy feed. The pore diameter for the residuum hydrotreating catalyst needs to be quite large relative to a catalyst for light feed. The increase in pore size decreases the surface area and the catalyst activity. To overcome the limitations of small vs large pore trade-off, catalysts are layered to increase activity; for example, large pore-sized catalyst in the top section of the reactor, followed by smaller pore-sized catalyst. Typical pore sizes of 75–85 Å for light/heavy gas oil feed and 150–250 Å for residue feed can be used.

Feed filtration Feed filtration is important to mitigate exchanger and reactor plugging. An appropriate feed filtration system can reduce the build of pressure drop in the reaction section of the unit, which results in a significant reduction in operating costs. A cartridge or wedge wire backwash filter with 25 micron retention is typical for this application. Cracked feeds should feed the hydrotreater hot from the upstream facilities or from inert gas blanketed storage. The use of steam-stripped feed that contains a significant amount of water requires the installation of a feed coaleaser upstream of the feed filter. However, traces of water can be removed by using a horizontal feed surge drum with associated water boot, eliminating the need for a coaleaser.

Feed heating section This section comprises a series of heat exchangers followed by a charge heater. Hydroprocessing reactions are exothermic in nature. The reactor feed effluent exchanger must recover as much heat as is

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cracking and the associated production of light ends and lighter liquid product(s) are usually undesirable. A combination of base metals, such as NiMo and CoMo, is used to achieve deep HDS and HDN activity. Feed composition and product quality requirements define the required chemical composition and quantity of the catalyst. Typically, a CoMo catalyst may be the right choice where the feed is straight-run distillate with very little nitrogen content and the operating pressure is low to moderate. On the other hand, if the feed contains a high percentage of cracked stock that has a significant nitrogen content and the operating pressure

Di-olefinreactor

Start-upheater

HDS/HDNreactor withsilica guard

Co-current orcounter-currentAroSat reactor

Hydrotreatingreactor

Stripper

Figure 3 ULSD unit with AroSat option

Figure 2 Naphtha hydrotreater unit co-processing cracked stocks

economically practical to minimise the heat input in the charge furnace to typically less than 15–20% for heat balance and emergency operation. Off-design cases such as cold start-up or loss of feed results in a high design duty and thus a higher capital cost. The proper selection of exchangers enables a maximum recovery of heat of reaction, minimises the probability of leakage and increases the unit’s reliability. If the feed to the charge heater is a two-phase stream, to avoid coking/hotspot in the charge heater tube passes, it is recommended to have pass balancing to maintain equal flow distribution. Bypassing the heat exchanger train should be considered in the case of an uncontrollable increase in the reactor bed temperature when processing large amounts of cracked stocks.

reactor configuration The number of reactors and their configuration depends on factors such as catalyst volume, mass and volumetric flux, reactor pressure drop, reactor dimensions and materials of construction. A typical pressure drop of about 0.7–1.5 psi/ft of catalyst bed (SOR to EOR) is desirable to promote uniform flow through the catalyst bed to have a uniform radial temperature profile. An excessive pressure drop will increase the recycle gas compressor power consumption and could challenge the mechanical integrity of the reactor catalyst support trays. Other factors are flexibility in fabrication and transportation from workshop to refinery site. In special cases, the refinery’s ground conditions may also preclude the installation of a single heavy weight reactor.

If the feed contains a high level of olefins, to avoid fouling in the heat exchangers, in the heater and in the top catalyst bed it is advisable to saturate the olefins at a lower reactor temperature. A separate olefin saturation reactor may be added upstream of the HDS reactor (see Figure 2). For a unit where deep aromatic saturation is required, a two-stage reactor approach using HDS/HDN catalyst in the first reactor and a noble metal catalyst in

the second reactor, with a stripper in between, may be the preferred configuration (see Figure 3). For hydrocrackers, depending on capacity, conversion and product specification targets, it may be best to investigate two-stage reactor systems that allow staging of the HDS/HDN reactions in a sour, ammoniacal environment and HDA reactions in a sweet, colder environment to capitalise on kinetic reaction rates.

The reactors selected for light feeds differ markedly from those selected for heavy feeds. Fixed-bed reactors have been traditionally used for light feeds. High asphaltene and high metal content feeds, such as vacuum residue, are successfully

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processed using moving-bed and/or ebullated-bed reactors. Recent pilot work includes slurry-based reactors for deep-conversion residue hydrocracking. Multireactor systems consisting of moving- and/or ebullated-bed reactors integrated with fixed-bed reactors can be used to process difficult feeds.

reactor internals Reactor internals are exceptionally important for the safe, reliable and profitable operation of a hydro-processing unit and may have a major effect on reactor performance in terms of catalyst utilisation efficiency and unit availability. For a gas-phase reaction such as naphtha

CHPS

Figure 4 For straight-run feed (naphtha hydrotreater)

CHPS

HHPS

Intermediatepressurebreak-up drum

Figure 5 For cracked stock feed (high-severity ULSD unit)

hydrotreating, a distribution tray is not necessary, but for a trickle-bed reactor, processing middle/heavy distillates, specially designed gas liquid distributors to achieve small-scale contacting of process gas and liquid are mandatory. An ideal liquid distributor should have a high distribution element density, low pressure drop, large spray angle, turndown flexibility and be easy to clean. This enables full catalyst utilisation and thermal uniformity across the catalyst bed, so that the lowest possible SOR temperature is achieved in conjunction with minimisation of the catalyst deactivation rate.

The use of robust reactor internals improves radial temperature distrib-ution and catalyst utilisation, which ultimately translates into a better yield, longer catalyst life and more efficient use of limited hydrogen resources. Some of the best-in- class reactor internals help to achieve less than 5°C radial temperature spread at the bottom of deep catalyst beds. Additionally, tightly designed high-capacity trays and quench systems help to reduce reactor heights in multibed reactors.

product cooling and separation A typical configuration in any hydrotreater includes a feed/effluent heat exchanger train, a large air-cooled heat exchanger and one, two or more flash drums, depending on unit heat balance and hydrogen recovery requirements.

A straight-run feed with alumina-based catalyst produces fewer light ends, so a single, cold, high-pressure separator (CHPS) may be adequate for smaller-capacity units (see Figure 4). If the feed contains a large percentage of cracked stock, which generates large exotherms in a reactor catalyst bed, the use of a hot, high-pressure separator (HHPS), with a gas component that will be routed to a CHPS via an air cooler/trim cooler, and a liquid component routed to the stripping section, may be justified (see Figure 5). This facilitates enhanced heat integration and lower air cooler duty, but increases the hydrogen loss and results in a higher capital cost of the unit.

Limited resources of hydrogen necessitate further separation of HHPS liquid to a hot, low-pressure separator (HLPS) followed by a CLPS (see Figure 6). This process

schemes ensures the efficient recovery of hydrogen from hydro-carbon, reduces the relief load of the system and facilitates a lower design pressure for the downstream columns. The configuration of the separation system depends on the economic balance between operating and capital cost, in addition to feed quality and hydrogen availability.

High-pressure amine absorptionFeed with a higher sulphur content results in the accumulation of H2S in the recycle gas loop. H2S inhibits HDS reactions and lowers the purity of the recycle gas and thus the partial pressure of hydrogen. A high H2S concentration in the recycle gas (typically >2–3 vol%) will influence catalyst selectivity in an undesirable way. To compensate, a higher unit pressure may be needed. A high sulphur content in the feed and ultra-low sulphur products may require an amine scrubbing system in a recycle gas loop to prevent H2S build-up and improve catalyst activity. The high-pressure amine absorber increases the partial pressure of hydrogen, which, in turns, results in lower operating and capital costs for the unit.

CHPS

CLPS

HHPS

HLPS

Figure 6 Classic four-drum separation system (hydrocracker unit)

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Additionally, it increases catalyst life, reduces hydrogen losses through purge and requires lower power consumption in the recycle gas compressor because of the increased purity of the gas.

Gas compression system The choice of recycle and make-up gas compressor depends on gas purity. The make-up gas flow is typically 25–40% of the recycle gas flow. High-purity make-up gas compression requires more stages. The multistage reciprocating com-pressor works well for this service. A sparing arrangement is necessary to ensure reliability and availability. The lower purity of make-up gas increases both the capital and operating cost of the compressor. The high purity of recycle gas requires a lower gas circulation rate, but the lower molecular weight of gas requires more head and potentially more compression stages. The recycle gas acts as a major heat sink in a reactor and avoids excursion probability. Typically, a centrifugal compressor is used for this service in view of its higher reliability and efficiency over a reciprocating compressor.

stripping section The stripping section of a middle distillate hydroprocessing unit mainly removes H2S and light hydrocarbons from the hydrotreated product and stabilises the product to meet the flashpoint specification. If lighter components are present in the feed, to offload the light products, distillation can be carried out in two steps: H2S steam stripping at a higher pressure, followed by lower-pressure stabilising. This will increase operational flexibility and enable the use of a smaller column size with a low design pressure.

Use of heavy feed and less cracking in the reactor means a standalone, low-pressure stripper column can be employed. It may be one of two types: attached fired reboiler or steam stripping. For kerosene and diesel boiling-range hydrocarbon, a fired heater reboiler is more suitable, as it is hard to achieve a higher temperature with steam.

Hydrogen managementLower-purity (<85%) hydrogen make-up gas increases the design pressure of the unit, and increases both the capital and operating costs of the unit. A supply of high-purity hydrogen increases the partial pressure of the hydrogen in the reactor in conjunction with a lower total operating pressure, and so results in lower operating and capital costs. Additionally, it increases catalyst selectivity, stability and overall cycle length. Optimis-ation of the hydrogen system may provide additional H2 availability, while avoiding capital investment. Pressure swing adsorption or semi-permeable membrane technology could be considered for the purification of the H2 purge and make-up hydrogen streams from the catalytic reforming unit.

The cascading of H2 purge streams for use as H2 make-up streams to other HDT units increases the purge rate for higher recycle gas purity and is more economical. Quench hydrogen rates between the catalyst beds should be minimised consistent with safe operation, the ability to maintain the required hydrogen partial pressure and desired catalyst life.

summary Hydroprocessing plays an increas-ingly important role in oil refining and is key to the production of clean transportation fuels. Selection of the right technologies, the right combin-ation of high-activity catalysts, appropriate reactor system arrange-ment, operating conditions and advanced reactor internals provides refiners with a range of advantages. These include low operating and capital costs, improved hydrogen utilisation, greater flexibility, more scalability and high reliability for the processing of a range of feedstocks.

Alpesh Gurjar is an Associate Process Specialist at Fluor Daniel India Pvt Ltd. He has six years’ experience in process design, technical services and operation of various refinery hydroprocessing units. He has worked with Essar Oil refinery and has a degree in chemical engineering from M S University of Baroda, India. Email: alpesh_gurjar@yahoo.co.in

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