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Petroleum Refining – Chapter 8: Desulfurization
8-1
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
8-2
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.
Petroleum Refining – Chapter 8: Desulfurization
8-3
• 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.
Prof. Tareq A. Albahri 2018 Kuwait University Chemical Engineering
8-4
• 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.
Petroleum Refining – Chapter 8: Desulfurization
8-5
• 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
Prof. Tareq A. Albahri 2018 Kuwait University Chemical Engineering
8-6
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
Petroleum Refining – Chapter 8: Desulfurization
8-7
Figure 8-2: Kerosene hydrotreating Unit
Prof. Tareq A. Albahri 2018 Kuwait University Chemical Engineering
8-8
Figure 8-3: Naphtha Hydrotreating Unit
Petroleum Refining – Chapter 8: Desulfurization
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).
Prof. Tareq A. Albahri 2018 Kuwait University Chemical Engineering
8-10
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.
Petroleum Refining – Chapter 8: Desulfurization
8-11
• 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
Prof. Tareq A. Albahri 2018 Kuwait University Chemical Engineering
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.
Petroleum Refining – Chapter 8: Desulfurization
8-13
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
Prof. Tareq A. Albahri 2018 Kuwait University Chemical Engineering
8-14
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.
Petroleum Refining – Chapter 8: Desulfurization
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
Prof. Tareq A. Albahri 2018 Kuwait University Chemical Engineering
8-16
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.
Petroleum Refining – Chapter 8: Desulfurization
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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.
Prof. Tareq A. Albahri 2018 Kuwait University Chemical Engineering
8-18
Figure 8-8: MAB ARDS Unit