Chapter 8 : Desulfurization - Desulfurization.pdf · Petroleum Refining – Chapter 8: Desulfurization 8-3 • The hydrogen requirements of the reaction are jointly met by ARDS purge

Petroleum Refining – Chapter 8: Desulfurization

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Chapter 8 : Desulfurization

Introduction

Table 8-1: Desulfurization units in Kuwait.

Unit Feed Location

1. Merox Naphtha, gasoline, Kerosene MAA, MAB

2. Hydrotreaters Naphtha, kerosene, diesel, gasoil MAA, MAB, ZOR

3. ARDS Atmospheric & Vacuum residue MAA, MAB, ZOR

1. Hydrotreating Units (HTU)

Introduction

• Hydrotreating is a mild catalytic process (with moderate temperature and pressure).

• Objectives:

1. Reduce objectionable materials like sulfur and nitrogen, oxygen, halides, and

trace metals content.

2. Saturate olefins and (gum-forming unstable) diolefins.

3. Hydrogenate aromatic rings into paraffins (to meet environmental regulations).

• It does not alter the initial and final boiling points.

• There are about 30 hydrotreating processes available for licensing. Most of them have

essentially the same process flow.

Feeds and Products

• The feed ranges from Naphtha to reduced crude (residue).

• The heavier the feed the more severe the process is (higher T & P).

Table 8-2; Hydrotreating capacity in Kuwait.

Refinery HTU Capacity

(BPSD) Feeds

MAA Kerosene desulfurization Unit-43

Gasoil desulfurization unit-44

20,800

55,500

SR kerosene from CDU

Raw gasoil from CDU

MAB Naphtha HTU-15

Kerosene HTU-16

Diesel HTU-17

7,500

35,000

35,000

ARDS & coker naphtha

SR & coker kerosene

SR, coker & RCD Unibon

diesel

ZOR Naphtha Hydrotreater

Kerosene Hydrotreater

Diesel Hydrotreater

Prof. Tareq A. Albahri 2018 Kuwait University Chemical Engineering

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Table 8-3: Hydrotreating Units in Kuwait Refineries feed and product properties.

Refinery HTU Feed Product

API S, w% API S, w% max

MAA Kerosene desulfurization Unit-43

Gasoil desulfurization unit-44

49

36.4

0.2

1.1

49.7

37.4

0.05

0.1

MAB Naphtha HTU-15

Kerosene HTU-16

Diesel HTU-17

0.1

0.33

1.4

0.05

0.1

0.1

ZOR Naphtha Hydrotreater

Kerosene Hydrotreater

Diesel Hydrotreater

PROCESS DESCRIPTION

• The process is basically the same for all HTU’s with some variations.

Kerosene HTU

• The Process flow diagram (PFD) for kerosene HTU is shown in Figure 8-2.

• The oil feed is mixed with hydrogen-rich gas consisting of both recycle and fresh

make-up hydrogen.

• It is then preheated, utilizing hot streams within the unit and a fired heater, to the

reactor inlet temperature of 500 – 800 ºF depending on the feedstock1.

- Reactor inlet temperature for Kerosene HTU: SOR-624ºF / EOR-700ºF.

- Reactor inlet temperature Gasoil HTU: SOR-626ºF / EOR-698ºF.

• The feed mixture enters the top of a fixed-bed reactor.

• In the presence of the metal-oxide catalyst, the hydrogen reacts with the objectionable

materials in the oil to produce hydrogen sulfide (H2S), ammonia (NH3), saturated

hydrocarbons, and free metals.

• The metals remain on the surface of the catalyst and other products leave the reactor

with the oil-hydrogen stream.

• The reactor outlet is cooled (by heating the feed) before separating the oil from the

H2-rich gas.

• The H2-rich gas is recycled and supplemented with fresh make-up H2 before it is

mixed with the fresh feed again.

• Some gas is purged continuously from recycle gas section to H2 recovery unit

maintain the required hydrogen purity and partial pressure in the reactor.

• The desulfurized oil is stripped of any remaining hydrogen sulfide (and light ends to

adjust the flash point) in a steam stripper.

• A small quantity of wild naphtha is produced from the top of the stripper and is sent

to the Naphtha HTU (via CDU fractionator or ARDS stabilizer) for recovery as

stabilized naphtha product.

• The stripped oil is fed to a vacuum dryer (operating at 80 mmHg, using a two-stage

steam jet ejector system) where moisture is removed.

• The treated final product from the dryer bottom is cooled then sent to storage.

• Product is Aviation Turbine Kerosene (ATK) or illuminating Kerosene (IK).

• The major improvements for the product quality will be with respect to smoke point

(23 to 25) sulfur and olefin to (0.05 wt% max).

• The reaction pressure is 668 psig & H2 consumption 235 SCF/B feed.

1 Most hydrotreating reactions are carried out below 800 ºF to avoid cracking.


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• The hydrogen requirements of the reaction are jointly met by ARDS purge gas and

high purity hydrogen make up gas.

• A two-bed reactor with quench gas is provided.

Naphtha HTU

• The Process flow diagram (PFD) for kerosene HTU is shown in Figure 8-3.

• NHTU is designed to meet the olefins, nitrogen & sulfur content requirements for

blending into Petrochemical Naphtha (PCN) pool or into Motor Gasoline pool.

• The unsaturated coker naphtha is first mixed with make-up H2 gas, heated up and sent

to the first reactor where a liquid phase hydrogenation reaction is carried out to take

care of the diolefins and gums in coker naphtha (which would otherwise cause severe

fouling problems in vapor phase naphtha hydrotreating reaction).

• The saturated naphtha feed from ARDS is preheated then combined with first reactor

effluent and recycle gas and vaporized totally in a heater before sending to the second

reactor.

• The hydrotreating reactions are completed in the second reactor which has 2 types of

catalysts for hydrodesulfurization and denitrification.

• The distillation section consists of a naphtha stabilizer to achieve required RVP &

H2S content on naphtha product.

• The reaction pressure is 415 psig.

• Hydrogen consumption is about 415 scf/bbl.

Diesel HTU

• The process is basically the same as NHTU & KHTU but with only one reactor for

hydrotreating and a coalescer2 is used instead of dryer for the final diesel product.

• The major improvements for the product quality are with respect to sulfur content and

reduction of Conradson carbon (from 0.22 % to 0.05 wt%).

• A two-bed reactor with quench gas is provided for desulfurization and denitrification.

• The reaction pressure is 668 psig and H2 consumption about 277 SCF/B feed.

• The hydrogen requirements of the reaction are jointly met by ARDS purge gas and

high purity hydrogen make up gas.

HYDROTREATING CATALYSTS

• Hydrotreating catalysts:

- Cobalt and molybdenum oxides on silica alumina base (CoMo).

- Nickel oxide.

- Nickel thiomolybdate.

- Tungsten and nickel sulfides.

- Vanadium oxide.

• Desulfurization CoMo catalysts are more common because:

- High selectivity.

- Easy to regenerate.

- Resistant to poisons.

• Denitrification (denitrification) requires the more efficient

• Nickel-molybdenum (NiMo) catalyst on silica alumina base.

• For middle distillates, 10% nickel-tungsten catalyst is added to NiMo catalyst

to treat high nitrogen concentration.

2 Coalescer is a filter type strainer for removing water from diesel product.


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• NiMo catalyst has a higher hydrogenation activity than CoMo catalyst (at the same

T&P) which results in a greater saturation of aromatic rings.

• Both CoMo and NiMo catalysts can remove sulfur and nitrogen. However, CoMo is

more selective for sulfur removal and NiMo is more selective to nitrogen removal.

• Usually both desulfurization and denitrification are necessary and a nickel-cobalt-

molybdenum (NiCoMo) catalyst over silica alumina base is used. Alternatively,

COMO and NIMO catalysts are layered inside the reactor at pre-calculated levels.

• Since nitrogen is more difficult to remove than sulfur, any treatment which reduces

excess nitrogen to a satisfactory level will also remove excess sulfur.

• Hydrotreating gasoil (400-1050 ºF) requires larger pore-size catalyst (than naphtha for

example) to overcome diffusion restrictions at both SOR and EOR conditions.

- Pores that are larger than necessary decreases the catalyst surface area.

- Pores that are smaller than necessary will cause diffusion restrictions.

- Highest activity is maintained if pore volume is concentrated in a very narrow

range of pore diameters.

• Catalyst consumption varies from 1 to 7 PTB of feed depending on operation severity

(T&P) and feed (API & S, N, halides, and metal content).

Figure 8-1: hydrotreating catalysts

Catalyst Activation (Sulfiding)

• Hydrotreating catalyst requires activation by converting the hydrogenation metals

from the oxide form to the sulfide form every time a new catalyst is added, or the unit

is shut down for maintenance (catalyst is exposed to air).

• Nickel containing catalysts require activation by pre-sulfiding with carbon disulfide,

mercaptans, or dimethyl sulfide before bringing up to reaction temperature.

• Some refineries activate cobalt-moly catalysts by injecting the sulfiding chemical into

the oil feed during startup.

• If the feed is high in sulfur then the feed is enough for the sulfiding operation.

• The sulfiding reaction is highly exothermic and care must be taken to prevent

excessive reactor temperature during activation.

Aromatics Reduction

• Aromatics reduction catalysts are nickel-tungsten on gamma-alumina.

• Most important controlling parameter is H2 partial pressure.

• Require 1500 psig pressure for diesel.


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• Hydrogenation is exothermic.

• Reaction rate increase with temperature while maximum aromatic reduction is

favored by low temperature. Optimum temperature of 705-725ºF must be used to

compromise.

REACTIONS

• Typical hydrotreating reactions are

1. Desulfurization

a. Mercaptans: R-SH + H2 → RH + H2S

b. Sulfides: R-S-R + 2H2 → 2RH + H2S

c. Disulfides: R-S-S-R' + 3H2 → RH + R'H + 2H2S

d. Thiophenes:

2. Denitrification

a. Pyrrole: C4H4NH + 4H2 → C4H10 + NH3

b. Pyridine: C5H5N + 5H2 → C5H12 + NH3

3. Oxidation

a. Phenol: C6H5OH + H2 → C6H6 + H2O

b. Peroxides: C7H13OOH + 3H2 → C7H16 + 2H2O

4. Dehalogenation

a. Chlorides: RCl + H2 → RH + HCl

5. Hydrogenation

a. Pentene: C5H10 + H2 → C5H12

6. Hydrocracking (Breaking of large molecules / minor)

a. Decane: C10H22 + H2 → C4H10 + C6H14

• Smaller compounds are desulfurized more easily than larger ones.

• Difficulty of sulfur removal increases in the order; paraffins, naphthenes, then aromatics.

• Nitrogen removal requires more severe conditions (T&P) than sulfur removal.

• Hydrogen consumption;

Desulfurization → 70 scf/bbl feed (per % S removed)

Deoxygenation → 180 scf/bbl feed (per % O removed)

Denitrification → 230 scf/bbl feed (per % N removed)

Cracking → V. high H2 required (if operations are sever enough).

Olefin/Aromatic saturation → use stoichiometry.

• Because of solubility losses, makeup H2 is usually 2–10 times the stoichiometric amount

required.

• All reactions are exothermic and a temperature rise through the reactor of 5 to 20 ºF is

normal.

Ex:

How much H2 is required to reduce the sulfur of 20,000 BPD gasoil from 0.33% to 0.1%?

S

+ 4H2 C4H10 + H2S


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Solution:

Hydrogen required = 70 [scf/bbl feed (per % S removed)] /(0.33% - 0.1%) = 304 scf/bbl feed.

= 20,000 (BPD) 304 (scf/bbl feed) = 6.08 MMSCFD

PROCESS VARIABLES

• Increasing T and H2 partial pressure increases S and N removal, and hydrogen

consumption.

• Excessive T increases coke formation (and should be avoided).

• Increasing pressure increases hydrogen saturation and reduces coke formation.

Table 8-4: Typical ranges of process variables in hydrotreating.

Variable Units Values

Temperature

Pressure

Hydrogen Recycle

Hydrogen Consumption

Space velocity

ºF

psig

scf/bbl

scf/bbl

LHSV

500 – 650

100 – 3,000

2,000

200 – 800

1.5 – 8

¹ Determined by hydrogen partial pressure in the reactor


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Figure 8-2: Kerosene hydrotreating Unit


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Figure 8-3: Naphtha Hydrotreating Unit


8-9

2. Merox (Mercaptan Oxidation) Unit

Introduction

• Two major types of Merox3

1. Conventional Merox for extraction of mercaptans from refinery gas, LPG, and

light naphtha.

2. Conventional Merox for sweetening jet fuels and kerosene

• Both require the removal of H2S from feed, otherwise, any it would react with the

circulating caustic solution and interfere with the Merox reactions.

• The overall oxidation reaction in both types converts mercaptans to disulfides

4 R-SH + O2 → 2 R-S-S-R + 2 H2O

(mercaptans) (disulfides)

• Merox catalyst is caustic (or ammonia and water) on metal-impregnated charcoal

granules.

• Mercaptans are undesirable due to their acidity and offensive odor.

• The most common mercaptans removed are: - Methanethiol - CH3SH [m-mercaptan]

- Ethanethiol - C2H5SH [e-mercaptan]

- 1-Propanethiol - C3H7SH [n-P mercaptan]

- 2-Propanethiol - CH3CH(SH)CH3 [2C3 mercaptan]

- Butanethiol - C4H9SH [n-butyl mercaptan]

- tert-Butyl mercaptan - C(CH3)3SH [t-butyl mercaptan]

- Pentanethiol - C5H11SH [pentyl mercaptan]

• Merox process is more economical than catalytic hydrodesulfurization process (has low

capital, operation and maintenance costs).

Table 8-5: Merox units in Kuwait.

Unit Capacity Feed Location

1. Merox ZOR

2. Merox (two trains) 2 x 1,600 Coker Naphtha MAB

3. FCC LPG Merox 12,254 LPG

MAA

4. Naphtha Merox 2 x 8,000 Lt SRN

5. ATK Merox 5,000 ATK

6. Lt Gasoline Merox Lt gasoline

7. Hvy Gasoline Merox Hvy gasoline

Total Capacity = ??? BPD

Types of Merox Units

• The units are based on UOP’s licensed conventional Fixed Bed MEROX process.

[A] Conventional Merox for extracting mercaptans from LPG

• Can be used to extract and remove mercaptans from LPG, propane, butanes and

mixtures of propane, butanes, and light naphtha.

• It is a two-step process.

1. The feedstock is contacted in the trayed extractor vessel with an aqueous caustic

solution containing UOP's proprietary liquid catalyst. The caustic solution reacts

with mercaptans and extracts them. The reaction that takes place in the extractor is:

2 R-SH + 2 NaOH → 2 Na-S-R + 2 H2O

3 Wikipedia (https://en.wikipedia.org/wiki/Merox).


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2. The regeneration step involves heating and oxidizing of the caustic solution leaving

the extractor. The oxidation results in converting the extracted mercaptans to

organic disulfides (RSSR) The reaction that takes place in the regeneration step is:

4 Na-S-R + O2 + 2 H2O → 2 R-S-S-R + 4 NaOH

• Organic disulfides are water-insoluble liquids which can be separated from the

aqueous caustic solution.

• After separating the disulfides, the regenerated "lean" caustic solution is recirculated

back to the top of the extractor to continue extracting mercaptans.

• The net overall Merox reaction covering the extraction and the regeneration step may

be expressed as:

4 R-SH + O2 → 2 R-S-S-R + 2 H2O

• The feedstock entering the extractor must be free of any H2S. Otherwise, any H2S

entering the extractor would react with the circulating caustic solution and interfere

with the Merox reactions. Therefore, the feedstock is first "prewashed" by flowing

through a batch of aqueous caustic to remove any H2S. The reaction that takes place

in the prewash vessel is:

H2S + NaOH → Na-SH + H2O

• The batch of caustic solution in the prewash vessel is periodically discarded as "spent

caustic" and replaced by fresh caustic as needed.

Flow diagram (Figure 8-4)

• The LPG (or light naphtha) feedstock enters the prewash vessel and flows upward

through a batch of caustic which removes any H2S that may be present in the

feedstock.

• The coalescer at the top of the prewash vessel prevents caustic from being entrained

and carried out of the vessel.

• The feedstock then enters the mercaptan extractor and flows upward through the

contact trays where the LPG intimately contacts the downflowing caustic that extracts

the mercaptans from the LPG.

• The sweetened LPG exits the tower and flows through:

- a caustic settler vessel to remove any entrained caustic,

- a water wash vessel to further remove any residual entrained caustic and

- a vessel containing a bed of rock salt to remove any entrained water.

• The dry sweetened LPG exits the Merox unit.

• The caustic solution leaving the bottom of the mercaptan extractor ("rich" Merox

caustic) flows through a control valve which maintains the extractor pressure needed

to keep the LPG liquified.

• It is then injected with UOP's proprietary liquid catalyst (on an as needed basis), flows

through a steam-heated heat exchanger and is injected with compressed air before

entering the oxidizer vessel where the extracted mercaptans are converted to

disulfides.

• The oxidizer vessel has a packed bed to keep the aqueous caustic and the water-

insoluble disulfide well contacted and well mixed.

• The caustic-disulfide mixture then flows into the separator vessel where it forms a

lower layer of "lean" Merox caustic and an upper layer of disulfides. The vertical

section of the separator is for the disengagement and venting of excess air and

includes a Raschig ring section to prevent entrainment of any disulfides in the vented

air.

• The disulfides are withdrawn from the separator and routed to fuel storage or to a

hydrotreater unit.


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• The regenerated lean Merox caustic is then pumped back to the top of the extractor

for reuse.

Figure 8-4 Flow diagram of a conventional Merox process unit for extracting mercaptans from LPG

[B] Conventional Merox for sweetening jet fuel or kerosene

• The conventional Merox process for the removal of mercaptans (i.e., sweetening) of

jet fuel or kerosene is a one-step process.

Flow diagram (Figure 8-5)

• The jet fuel or kerosene feed is first prewashed in a caustic prewash vessel to remove any H2S that

would interfere with the sweetening. The following reaction takes place:

H2S + NaOH → Na-SH + H2O

The rich caustic, containing the extracted mercaptans in the form of sodium mercaptides, is later

regenerated as shown in the equation given below:

4 Na-S-R + O2 + 2 H2O → 2 R-S-S-R + 4 NaOH

• The jet fuel or kerosene feed from the top of the caustic prewash vessel is injected with

compressed air and enters the top of the Merox reactor vessel along with any injected caustic.

• The pressure maintained in the reactor is chosen so that the injected air will completely dissolve

in the feed at the operating temperature.

Removes

entrained

caustic Removes

entrained

water

Removes

entrained

disulfides


8-12

• The Merox reactor is a vertical vessel containing a fixed bed of charcoal granules that have been

impregnated with the UOP proprietary catalyst.

• The mercaptan oxidation reaction takes place in an alkaline environment provided by caustic

being pumped into the reactor on an intermittent (as needed) basis.

Figure 8-5: Conventional Merox process unit for sweetening jet fuel or kerosene

• The mercaptan oxidation reaction takes place as the feedstock percolates downward over the

catalyst. The reaction is:

4 R-SH + O2 → 2 R-S-S-R + 2H2O

• The reactor effluent flows through a caustic settler vessel where it forms a bottom layer of

aqueous caustic solution and an upper layer of water-insoluble sweetened product.

• The caustic solution remains in the caustic settler so that the vessel contains a reservoir for the

supply of caustic that is intermittently pumped into the reactor to maintain the alkaline

environment.

• The sweetened product from the caustic settler vessel flows through a water wash vessel to

remove any entrained caustic as well as any other unwanted water-soluble substances

• The water-washed product flows through a salt bed vessel to remove any entrained water.

• The salt filtered product flows through a clay filter vessel to remove any oil-soluble substances,

organometallic compounds (especially copper) and particulate matter, to meet jet fuel product

specifications.


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MAB Merox Process Description

• Merox process achieve the following objectives;

1. Improve the odor of the naphtha.

2. Reduce mercaptans sulfur so it cannot be detected (to pass doctor test4).

• Two Merox units, each of 1600 BPSD capacity, are provided. Each unit serves a coker

train. See Figure 8-6.

• The unit treats light naphtha produced in the coker unit (along with some of the coker

heavy naphtha).

• The coker naphtha entering the unit passes through a guard caustic scrubber which

insures complete removal of H2S (if any) from the naphtha.

• The naphtha is then mixed with a controlled quantity of air in a mixer before entering the

Merox reactor.

• The Merox reactor contains a bed of specially selected activated charcoal impregnated

with Merox catalyst and wetted with caustic solution.

• While the naphtha air mixture passes through the reactor, the mercaptans in the naphtha

are converted to disulfides.

• The naphtha effluent from the reactor is sent to a caustic settler to separate the caustic and

the naphtha.

• A caustic circulation pump provides intermittent circulation of caustic from the settler to

wet the catalyst bed.

• The naphtha then passes through a sand filter (to reduce alkalinity and caustic haze)

before sending to storage.

Figure 8-6: Merox Unit Simplified Process Flow Diagram.

4 A qualitative test for the presence of hydrogen sulfide or mercaptans (in the absence of

hydrogen sulfide) in gasoline, jet fuel, kerosene and similar petroleum products.

Coker LightNaphtha

Coker HeavyNaphtha

Air

AirCompressor

Mixer

CausticPrewash

(Scrubber)

To Remove H2S

from Naphtha

MeroxReactor

Mercaptans Disulfides

Caustic Settler

Sand Filter

Reduce alkalinityand caustic haze

Treated Naphthato storage

Caustic


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3. Atmospheric Residue Desulfurization (ARDS) Unit

Figure 8-7: ARDS Unit at MAB refinery

INTRODUCTION

• ARDS is a fixed bed catalytic process for hydrotreating a variety of feedstocks (heavy

oils like atmospheric residue and some vacuum residues).

• Objectives

1. In the reaction section: To reduce the sulfur content of CDU atmospheric

residue from 4.5 to 0.5-0.7 wt% and metal content from 88 to 21 ppmw in

addition to nitrogen and residual carbon in the presence of hydrogen for

meeting quality criteria of the feed/products to the downstream processing

units.

2. In the fractionation section: To obtain lighter (more valuable) products such as

LPG and Naphtha, in addition to middle distillate and low-sulfur fuel oil

which are excellent feedstocks for other process units like fluid catalytic

crackers (FCC), hydrocrackers (HCR), and vacuum unit (VRU) and delayed

coker.

• Commercial Name → Unicracking/HDS Process.

• Licensor → Jointly licensed by Unocal5 and UOP

CAPACITY

Table 8-6: ARDS capacity in Kuwait.

Refinery Name Throughput

(BPSD)

Feed

MAB ARDS 65,900 High sulfur atmospheric

residue from crude units MAA ARDS 4 x 33,000

ZOR ARDS 3 x ???

Total ???

5 Unocal Science and Technology Division. Unocal processes have been licensed for use

worldwide.


8-15

Feedstock Guidelines

Table 8-7: Restrictions on a typical ARDS unit feed specifications

Specification Restriction

Sodium.

Ni + V

Carbon residue.

Sulfur.

Nitrogen.

Specific gravity

API min.

< 3 wppm

< 600 wppm

< 20 W%

< 6 W%

< 10,000 wppm

< 1.1

- 3

• Because of problems related to flow and product instability, feeds with very high

viscosities (e.g., Heavy Iranian vacuum residue) are difficult to upgrade with fixed-

bed residue hydrotreating processes. However, if diluent such as light or heavy cycle

oil are added, even feedstocks such as these can be handled successfully.

• Example of an ARDS unit feed (atmospheric residue from CDU) is shown in Table

8-8.

Table 8-8: Feed to the ARDS unit in MAA refinery

Feed Property Unit Max.

Atm Residue API gravity

Sulfur

N2

CCR

Metals (Ni+V)

Na

API

W%

W%

W%

ppmw

ppmw

12.5 min

4.5

0.028

12.2

88

3

Hydrogen

Methane

CO + CO2

V%

V%

ppm

97

3

50

Product Properties

• ARDS units are designed to meet a given refiner’s particular process objectives.

• ARDS unit can achieve:

> 95% removal of sulfur & metals.

> 70% removal of carbon residue.

> 60% removal of nitrogen.

> 60% conversion of Vacuum Residue.

• An example of an ARDS Unit yield pattern of products is given below;

Table 8-9: Yield pattern of products from the ARDS unit 12 in MAB refinery.

PRODUCT YIELD V% ON FEED °API DESTINATION

SOR EOR

Gas (C4)

Stab Naphtha (C5-320)

Diesel (320 - 680)

LS AR (680+)

1.2

12.58

88.64

2.6

14.8

84.75

57

32.6

21.6

Gas treating.

Naphtha HTU/storage

Storage.

Vacuum Unit/HOC & storage


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Table 8-10: Yield pattern of products from the ARDS unit in MAA refinery.

PRODUCT YIELD V% ON FEED °API DESTINATION

SOR EOR

Gas (C4)

Stab Naphtha (C5-375)

Distillate (375 - 680)

LSFO (680+)

1.3

1.0

14.5

75

1.6

2.5

20

75

52.5

34

22.6

Gas treating.

Naphtha HTU/storage.

Storage.

Vacuum Unit/HOC & storage

PROCESS DESCRIPTION

A. Reactor Section:

• The reactor section has two parallel trains (i.e. the feed is split between the 2 trains).

• Each train consists of a guard reactor (chamber) and 3 more reactors in series, and has

independent recycle gas scrubbing facilities (MEA).

• The feed is pumped to over 2000 psi pressure by charge pumps.

• The feed charge is preheated by the hot effluent residue and further heated in a charge-

heater to the reaction temperature.

• The feed is mixed with the recycle hydrogen which has been preheated in a separate

(recycle-gas) heater.

• The feed enters a guard chamber (a small reactor that contains a relatively small quantity

of ARDS catalyst) to remove particulate matter and residual salt from the feed to protect

the three following reactors.

• The catalyst in the reactors is chosen such that demetallization is achieved in the first two

reactors and the desulfurization is achieved in the third and fourth reactors.

• A substantial fraction of the VR feed (1050+ ºF material) is converted into gas oil.

• The hydrogen consumption is about 610 - 670 scf/bbl of feed.

• The reactor effluent (two phase) is separated to liquid and vapor in a HPHS (high

pressure hot separator). The pressure is 1740 psig at SOR and 1720 psig at EOR.

• The vapor is cooled to 500 ºF and sent to HPWS (high pressure warm separator) where

the heavy HCs (which condensate because of cooling) are removed because they might

cause emulsions in the HPCS (high pressure cold separator) where water will be

condensed.

• The liquid from HPWS is mixed with the liquid from the HPHS and sent to LPHS (low

pressure hot separator).

• In the HPCS the three phase mixture comprising sour water (containing ammonium

sulfide), hydrocarbon liquid, and H2 gas is separated.

1. The sour water is sent to the sour water treating unit.

2. The hydrocarbon liquid is sent to the low pressure cold separator No.1 (LPCS1)

3. The gas (H2-rich) is washed with water to remove traces of ammonia then it is

contacted with ADIP solution in ‘recycle gas ADIP scrubber’ to remove H2S.

• Part of the recycle H2-rich gas is purged (to increase the purity of the recycle gas) and

sent to the Hydrogen Production (HP) unit. The rest is compressed after KO then mixed

with make-up hydrogen and returned to the reactors.

• Most of the hydrogen gas is preheated before mixing with the oil feed to the guard

chamber. However, part of cold recycle hydrogen is sent directly to the reactor to

maintain nearly constant temperature by quenching.

• In LPCS1 the dissolved gases are flashed off and sent to the hydrogen production (HP)

unit after treatment (in ammonia removal scrubber) and the liquid is sent to the

fractionator section.


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B. Fractionator Section:

• The fractionation section is common for both reactor trains.

• Dissolved vapors released in the LPHS are cooled then separated in the LPCS2 into gas,

HC liquid, and water.

- The HC liquid is fed separately to the fractionator.

- Gas (rich in H2) is sent after ammonia removal to either HP or Hydrogen

Sulfide Removal (HSR) unit.

- Water is sent to SWT unit.

• Liquids from the LPHS of both trains are sent to the flash zone of the fractionator after

preheat in the main heater.

• The fractionator operates in the same manner as a conventional crude unit distillation

column.

• Naphtha produced from the fractionator overhead is sent to a debutanizer to control its

IBP, flash point, and RVP by removing C4 and lighter gases. Both debutanizer top (LPG)

and bottom (naphtha) products are sent to storage.

• Distillate is drawn as a side stream from the fractionator to a steam side stripper to adjust

its IBP then sent to storage.

• The fractionator bottoms LSFO (low sulfur fuel oil) is sent to storage after cooling.

Catalyst

• There are catalysts for demetallization, desulfurization, denitrification, and conversion

of residual oils.

• A client’s objectives determine which combination of catalysts is best for a particular

plant.

• To convert a high-metals residue into low-sulfur fuel oil, a bed of demetallization

catalyst might be used followed by a bed of desulfurization catalyst.

• To achieve substantial conversion and denitrification, the above catalysts might be

followed by a hydrotreating or mild hydrocracking catalyst.

• Desulfurization catalyst life cycle ranges from one to two years.

• Demetallization catalysts must be reclaimed or disposed of once or twice per year.

• Desulfurization catalyst can be regenerated if protected by a demetallization catalyst.

ECONOMICS

(1) Investment Costs

• For typical ARDS units, investment costs range between US $3,200 and US $5,000

per daily barrel of capacity in 1992.

- in 1992 MAB 66,000 BPSD costs $ 211,000,000 to US$ 330,000,000.

- in 1992 MAA 4 X 33,000 BPSD costs $ 422,000,000 to US$ 660,000,000.

• Feedstock properties and process objectives determine the cost of an ARDS unit.

• High-metals feeds containing 250-400 ppmw Ni+V require large volumes of

hydrodemetallization catalyst, which in turn require relatively large reactors.


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Figure 8-8: MAB ARDS Unit

Documents

Chapter 8 : Desulfurization - Desulfurization.pdf · Petroleum Refining – Chapter 8: Desulfurization 8-3 • The hydrogen requirements of the reaction are jointly met by ARDS purge