HR SERIES
CATALYST HANDBOOK
FOR DISTILLATES
HYDROTREATMENT
(Naphtha, Kero, Gasoil, VGO)
Rev.
Date
1
2
3
4
Nov. 2005
Mar. 2007
Sep. 2008
July. 2009
Prepared by
Name:
N. BELLE
N. BELLE
N. BELLE
N. BELLE
Signature:
Checked by
Name:
O. LE COZ / P. FLOURY
O. LE COZ
O. LE COZ
O. LE COZ
Signature:
Approved by
Name:
F. MOREL
J. DE BONNEVILLE
J. DE BONNEVILLE
J. DE BONNEVILLE
Signature:
Comments
THIS DOCUMENT IS THE PROPERTY OF AXENS AND SHALL NOT BE REPRODUCED OR DIVULGATED WITHOUT AXENS CONSENT
HR SERIES
TABLE OF CONTENTS
1.
AXENS HYDROTREATMENT PROCESS _________________________________ 6
1.1. Objectives of the process_________________________________________________ 6
1.2. Main features of Axens Hydrotreating processes _____________________________ 6
1.3. Unit Description_________________________________________________________ 7
1.3.1 Reaction Section ______________________________________________________________7
1.3.2 Stripper section (cold scheme) ____________________________________________________8
1.3.3 Stripper section (hot scheme)_____________________________________________________8
1.3.4 Drying section_________________________________________________________________8
1.3.5 HP Amine absorption section (If any) _______________________________________________8
1.4. Process flow diagram ____________________________________________________ 8
2.
CHEMICAL REACTIONS _____________________________________________ 14
2.1. Thermodynamics and Kinetics of reactions _________________________________ 14
2.2. Description of the chemical reactions______________________________________ 14
2.2.1 Desirable reactions____________________________________________________________14
2.2.1.1. Hydrogenolysis (HDS,HDN,HDOx) ___________________________________________14
2.2.1.2. Olefins and Diolefins Hydrogenation __________________________________________14
2.2.1.3. Hydrogenation of Aromatic compounds ________________________________________14
2.2.1.4. Metals and metalloids compounds removal _____________________________________14
2.2.1.5. Hydrocracking ___________________________________________________________14
2.2.2 Adverse reaction: coking _______________________________________________________14
Rev 4
2.3. Operating parameters of the reaction section _______________________________ 14
2.3.1 Definitions___________________________________________________________________14
2.3.2 Role and impact of the operating parameters in the process ____________________________14
2.3.2.1. Temperature (WABT)______________________________________________________14
2.3.2.2. Feed rate (LHSV)_________________________________________________________14
2.3.2.3. Make-up gas rate _________________________________________________________14
2.3.2.4. Recycle gas rate _________________________________________________________14
2.3.2.5. Hydrogen partial pressure __________________________________________________14
2.3.2.6. Hydrogen sulfide partial pressure ____________________________________________14
2.3.2.7. Feed quality and impurities _________________________________________________14
2.3.3 Influence of the operating parameters on the chemical reactions ________________________14
2.3.4 Typical ranges for the main operating parameters ____________________________________14
3.
Rev 4
CATALYST ________________________________________________________ 14
3.1. Nature and role ________________________________________________________ 14
3.2. Physical properties _____________________________________________________ 14
3.3. Catalytic mechanisms___________________________________________________ 14
3.4. Characteristics towards the process_______________________________________ 14
3.5. Guidelines for HR500 catalysts choice _____________________________________ 14
3.5.1 The main characteristics of the feeds ______________________________________________14
3.5.2 The unit objectives ____________________________________________________________14
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HR SERIES
4.
SPECIAL PROCEDURES FOR CATALYST ______________________________ 14
4.1. Alumina and catalyst loading_____________________________________________ 14
4.1.1 General Policy _______________________________________________________________14
4.1.2 Special Loading Devices (Adapted for Each Reactor) _________________________________14
4.1.3 Loading_____________________________________________________________________14
4.1.4 Comparison between the two types of loading _______________________________________14
4.2. Catalyst sulfiding before feed-in __________________________________________ 14
4.2.1 General Comments ___________________________________________________________14
4.2.1.1. Catalysts delivery_________________________________________________________14
4.2.1.2. Catalysts activation modes _________________________________________________14
4.2.2 Catalyst activation or catalyst sulfiding _____________________________________________14
4.2.2.1. HR 548 GO _____________________________________________________________14
4.2.2.2. HR 526 Presulfided _______________________________________________________14
4.2.2.3. HR 538 Naphtha _________________________________________________________14
4.2.2.4. HR 506 Presulfided Naphtha ________________________________________________14
4.2.2.5. DMDS quantities and H2O produced __________________________________________14
4.3. Catalyst unloading _____________________________________________________ 14
4.4. Passivation____________________________________________________________ 14
4.4.1 Austenitic Steel Protection ______________________________________________________14
4.4.2 Polythionic Acid Attack _________________________________________________________14
4.4.3 Protection against Polythionic Acid Attack __________________________________________14
4.4.4 Preventing the formation of Polythionic Acids _______________________________________14
4.4.5 Neutralization ________________________________________________________________14
4.4.6 Application of the Neutralizing Solution ____________________________________________14
4.4.7 Neutralization after or before catalyst unloading _____________________________________14
4.4.8 Special stainless steel _________________________________________________________14
4.5. Catalyst regeneration ___________________________________________________ 14
4.5.1 Summary ___________________________________________________________________14
4.5.2 Prerequisites_________________________________________________________________14
4.5.3 Catalyst regeneration : When? – How? ____________________________________________14
4.5.4 Chemicals reactions ___________________________________________________________14
4.5.5 Precautions__________________________________________________________________14
4.5.6 Operating parameters (temperature and oxygen content) ______________________________14
4.5.7 Regeneration arrangements and facilities __________________________________________14
4.5.8 Reaction section working out ____________________________________________________14
4.5.9 Regeneration procedure outline __________________________________________________14
4.5.10 __________________________________________ Critical points and emergencies actions
14
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HR SERIES
5.
OPERATION OF THE UNIT ___________________________________________ 14
5.1. Reactor _______________________________________________________________ 14
5.1.1 Temperatures ________________________________________________________________14
5.1.2 Hydrogen Partial Pressure ______________________________________________________14
5.1.3 Recycle gas ratio _____________________________________________________________14
5.1.4 Liquid Hourly Space Velocity (LHSV) ______________________________________________14
5.1.5 H2S content of the recycle gas ___________________________________________________14
5.2. Feed quality ___________________________________________________________ 14
5.2.1 Distillation range ______________________________________________________________14
5.2.2 Impurities in the feed __________________________________________________________14
5.2.3 Conversion distillates in the feed _________________________________________________14
5.3. Wash water injection rate ________________________________________________ 14
5.4. Stripper_______________________________________________________________ 14
5.5. Dryer _________________________________________________________________ 14
5.6. Operation guideline_____________________________________________________ 14
5.6.1 Definitions___________________________________________________________________14
5.6.1.1. Feedstock characteristics __________________________________________________14
5.6.2 Unit Characterisation __________________________________________________________14
6.
SHUT-DOWN OF THE UNIT __________________________________________ 14
6.1. Normal shut-down ______________________________________________________ 14
6.1.1 Decrease feed throughput to turndown flowrate (generally 50% - 60%) ___________________14
6.1.2 Shut-off the liquid fresh feed to the unit ____________________________________________14
6.1.3 Hydrogen stripping ____________________________________________________________14
6.1.4 Temperature and pressure down _________________________________________________14
6.1.5 Stripper _____________________________________________________________________14
6.1.6 Steam-out ___________________________________________________________________14
6.2. Emergency shut-down __________________________________________________ 14
6.2.1 Fire in the unit________________________________________________________________14
6.2.2 Recycle gas compressor failure __________________________________________________14
6.2.3 Make-up gas failure ___________________________________________________________14
6.2.4 Feed failure__________________________________________________________________14
6.2.5 Utility failure _________________________________________________________________14
6.2.5.1. Steam failure ____________________________________________________________14
6.2.5.2. Instrument air failure ______________________________________________________14
6.2.5.3. Electricity failure__________________________________________________________14
6.2.5.4. Cooling water failure ______________________________________________________14
6.2.5.5. Heater failure ____________________________________________________________14
6.2.6 Washing water failure __________________________________________________________14
6.2.7 Start-up after an emergency shutdown_____________________________________________14
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HR SERIES
7.
SAFETY AND HEALTH RECOMMENDATIONS ___________________________ 14
7.1. Plant safety features ____________________________________________________ 14
7.1.1 General_____________________________________________________________________14
7.1.2 Emergency shut-down _________________________________________________________14
7.1.3 Overpressure protection ________________________________________________________14
7.1.4 Safety shower and eyes wash ___________________________________________________14
7.1.5 Operational safety ____________________________________________________________14
7.1.6 High pressure ________________________________________________________________14
7.1.7 Effluent line upstream effluent air-cooler after wash water injection_______________________14
7.2. Reactor protection______________________________________________________ 14
7.3. Personnel protection____________________________________________________ 14
7.3.1 Hydrogen ___________________________________________________________________14
7.3.2 Hydrogen Sulfide H2S _________________________________________________________14
7.3.3 Carbon Monoxide CO__________________________________________________________14
7.3.4 Carbonyls ___________________________________________________________________14
7.3.5 Regenerated catalyst __________________________________________________________14
7.3.6 Dimethyldisulfide DMDS (CH3-S-S-CH3)___________________________________________14
7.3.7 Sulfiding agent _______________________________________________________________14
7.3.8 Corrosion inhibitor ____________________________________________________________14
7.3.9 Pyrophoric materials – Iron Sulfide________________________________________________14
7.4. Catalyst Safety data sheets ______________________________________________ 14
8.
ANALYTICAL CONTROLS ___________________________________________ 14
8.1. Analytical methods _____________________________________________________ 14
8.1.1 Feed & product _______________________________________________________________14
8.1.2 Gas ________________________________________________________________________14
8.1.3 Amine ______________________________________________________________________14
8.1.3.1. Lean Amine _____________________________________________________________14
8.1.3.2. Rich Amine______________________________________________________________14
8.1.4 Sour Water __________________________________________________________________14
8.1.5 Regeneration phase ___________________________________________________________14
8.2. Catalyst analysis _______________________________________________________ 14
9.
FOLLOW-UP OF THE HDS UNIT ______________________________________ 14
9.1. Generalities ___________________________________________________________ 14
9.2. The Pseudo-Kinetic model _______________________________________________ 14
9.3. The Correlative model___________________________________________________ 14
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HR SERIES
PREFACE
This handbook is not an operating manual.
Its purpose is to provide USER with the necessary background and information to
understand how the process works with HR series Catalysts.
The information supplied here is valid for HDT units using HR series catalysts including but
not limited to HR 506, HR 526, HR 538, HR 548, HRK 558, HR 568 catalysts. The material
contained in this handbook covers the hydrotreatment processes using HR500 catalysts to
produce distillates (naphtha, kerosene, gasoil and VGO) with low sulphur, nitrogen and
aromatics contents, whilst realising also some conversion. The Feeds considered are
either straight run distillates or cracked distillates from catalytic or thermal conversion units,
generally mixed with straight run feeds.
The document describes and explains the physical and chemical phenomena, and the
operating parameters involved in catalytic hydrotreatment processes of distillates.
Additionally, it provides general instructions on how to prepare the unit for start-up, how to
start-up and operate, how to shut it down, how to regenerate the catalyst and how to
prevent or troubleshoot operational upsets.
THIS DOCUMENT CONTAINS AXENS’ CONFIDENTIAL INFORMATION.
IT SHALL NOT BE REPRODUCED IN WHOLE NOR IN PART.
IT SHALL BE USED BY AUTHORIZED STAFF WITHIN YOUR COMPANY ONLY.
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HR SERIES
1.
AXENS HYDROTREATMENT PROCESS
1.1. Objectives of the process
The Distillates cuts from crude oils atmospheric and vacuum distillations are in the
temperature boiling range of 150-550°C. Their chemical characteristics, for instance their
sulfur content, depend on the crude origin, and in most cases a catalytic
hydrotreatment process is required to improve their qualities, to meet the
commercial specifications of the finished products or to prepare feeds for downstream
processes. Most common examples sorted by product are:
pre-treatment of Catalytic Reforming feeds: sulphur and nitrogen
removal
Light Naphtha
preparation of feeds for steam cracking
Kerosene
- sweetening of kerosene cut to produce on spec Jet Fuel, burning
properties improvement.
- deep desulfurization for downstream separation of n-paraffins by
molecular sieve
Gasoil Straight run eventually blended with cracked feeds:
deep HDS to produce Ultra Low Sulfur Diesel (10 to 50 wppm sulphur
content), and eventually Cetane Number enhancement
Cracked gasoil from FCC or Thermal cracking:
sulphur reduction for blending in LSFO (Light Sulfur Fuel Oil).
VGO
- FCC feed pre-treatment : reduction of sulphur, nitrogen, metals and
aromatics contents + partial conversion into valuable light products
(naphtha and gasoil).
- Hydrocracking pre-treatment: removal of nitrogen and deep
hydrogenation of aromatics at high pressure ahead of acidic
hydrocracking catalysts.
Naphtha
1.2. Main features of Axens Hydrotreating processes
Axens HDT processes such as Naphtha HDT, Prime D+ (Diesel), Mild Hydrocracking and
Hydrocracking (VGO), have been specially designed for these objectives. To maximize the
efficiency of these processes in view of the more and more severe products specifications
and performances requirements, Axens Hydrotreatment reactors are now equipped with
latest technology of Equiflow internals, including distributor trays, quench boxes and
bottom collectors which allow the best hydrodynamic performance of the catalyst beds..
On top of it, new HR500 series catalysts have been designed to achieve deep
Hydrotreatment and especially deep HDS in Axens units as well as in competitor’s. To one
process with one set of operating conditions corresponds one optimal catalyst solution
among the HR500.
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HR SERIES
1.3. Unit Description
This description refers to the Process Flow Diagrams provided in the next pages and
corresponds to a typical HDS unit.
1.3.1 Reaction Section
Feed coming from surge drum D1 is pumped under flow control P1 and mixed with
make-up hydrogen K1 and recycle gas coming from recycle compressor K2. The mixture
is preheated by reactor effluent in the exchangers E2 and E8 and brought to reaction
temperature by the reaction heater H1.
The hydrorefining reactions occur in a fixed bed catalyst reactor R1. The reactor
operates at moderate temperature and under mixed phase. In order to control the
temperature in the catalytic beds, quenches coming from recycle compressor K2 are
injected at top of each catalytic bed. Reactor effluent is cooled down (first in the
stripper feed preheater E3 and in the feed effluent exchangers E8 for cold scheme)
and in the feed effluent exchanger E2.
At the outlet of the heat recovery system, two schemes are possible:
o The first one is called “Cold scheme”, all the effluent goes to the cold HP separator
drum: After the feed/effluent exchanger, water is injected P3 under flow control
from the washing water drum D6. This injection allows the washing of the reactors
effluent in order to avoid any salt deposits. The effluent is cooled down in the air
cooler Al before entering the high pressure separator drum D3 or cold separator
drum.
o The second one is called “Hot scheme” all the effluent is going to a hot HP
separator. After the feed/effluent exchanger, the effluent goes to a hot HP separator
drum. The gas from this drum follows the same way as the whole effluent does in
the cold scheme (Water injection + Air cooler + cold separator) and the liquid is
mixed with the liquid from the cold HP separator and sent under level control to the
stripper. This type of scheme allows saving duty on the air cooler and saving
stripping steam.
The unit pressure is controlled in this cold HP separator either by the spill-back valve of
the make-up gas compressor when the unit is operated without high pressure purge, or
when a purge is needed by the high pressure purge gas flowrate (after amine washing).
The aqueous phase is sent under interface level control partly as purge to water treatment
(sour water stripper), partly as recycle to the water drum D6. The liquid phase is sent
under level control to the stripper section. The gas phase is sent to the amine absorber KO
drum D4 before being returned to the recycle KO-drum D5 and to the recycle compressor
K2. Hydrogen make-up is injected by make-up compressor K1 in the recycle gas upstream
recycle KO-drum D5.
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HR SERIES
1.3.2 Stripper section (cold scheme)
The feed to the stripper C2, coming from the separator drum D3 contains H2S which
has to be eliminated from the product. The stripper feed is preheated against the stripper
bottom E4 and against the reactor effluent E3. A by-pass allows controlling stripper inlet
temperature. Stripping is insured by injection of medium pressure steam at the tower
bottom. The overhead is partially condensed in the air condenser A2 trim cooler E5
and received in the stripper reflux drum D7. The liquid hydrocarbon phase is used as
reflux to the stripper P4, and the excess send as wild naphtha to battery limit. The
decanted water is collected under level control in the boot of reflux drum D7, and
returned, under level control, to the water drum D6. The sour gas is sent under pressure
control to the LP amine section.
1.3.3 Stripper section (hot scheme)
The two differences with the cold case is that the stripper feed is not preheated and that
the stripper bottom is cooled down by a steam generator or by a fresh feed/stripper bottom
heat exchanger not represented here.
1.3.4 Drying section
Generally, the stripper bottom goes directly to the dryer D9. An alternate is to send the
stripper bottom to a coalescer to remove free water which appears after the cooling; it is
then sent to the dryer. In the dryer, the remaining water is removed thanks to the vacuum.
The water is condensed in the dryer overhead condenser E6 and received in the dryer
overhead drum D10 (sump drum). The oily water is sent (P7) to the oily water sewer or to
the water drum E6. A small part of gasoil is entrained in the overhead water and is
decanted in order to be sent to the gasoil storage P6 with the product. The hydrotreated
gasoil from dryer bottom P5 is sent to storage after cooling down in air cooler A3 and trim
cooler E7. The pressure is controlled by a bypass of the first steam ejector. By opening
the control valve, a flow from the outlet of the steam ejector to the first overhead
condenser is established, increasing the dryer pressure.
1.3.5 HP Amine absorption section (If any)
The gas from reaction section enters the HP amine absorber C1 at its bottom where
hydrogen sulfide is absorbed by the lean amine injected at the top of the absorber by
pump P2. The rich amine is withdrawn at the bottom under level control.
The recycle gas at the top of absorber is returned to recycle KO-drum D5.
An eventual by-pass of the absorber allows controlling the H2S content in the recycle gas.
1.4. Process flow diagram
In the next pages are presented the process flow diagrams of the four sections described
above:
ƒ Reaction cold and hot scheme,
ƒ Stripping cold and hot scheme,
ƒ Drying,
ƒ Amine absorption (if any).
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HR SERIES
2.
CHEMICAL REACTIONS
2.1. Thermodynamics and Kinetics of reactions
For any chemical reaction the thermodynamics dictates the possibility of its
occurrence and the amount of products and unconverted reactants. In fact, some
reactions are complete i.e. all the reactants are converted into products, others are in
equilibrium i.e. part of the reactants only are converted. The amount of products and
reactants at equilibrium depends upon the operating conditions and is governed by the
thermodynamic laws. Note that thermodynamics do not take into account the time
required to reach the equilibrium or the full completion of a reaction.
Kinetics dictates the rate of a chemical reaction. Kinetics is dependent upon operating
conditions but can also be widely modified through the use of properly selected catalysts.
In other words, thermodynamics dictates the ultimate equilibrium composition assuming
the time is infinite. Kinetics enables to forecast the composition after a finite time.
Since time is always limited, when several reactions proceed simultaneously,
kinetics is generally predominant.
2.2. Description of the chemical reactions
The chemical reactions involved in hydrotreatment processes can be sorted into two main
types:
Desirable reactions are reactions which enhance product refining. These are the
reactions to promote.
Adverse reactions are reactions which lead to a decrease of the refining rate, a loss in
products yield, or cause the catalyst deactivation. These are the reactions to minimise.
2.2.1 Desirable reactions
Examples are presented in the following pages of the different reactions occurring during
the HDT process.
2.2.1.1.Hydrogenolysis (HDS,HDN,HDOx)
Hydrogenolysis means the break of C-S, C-O, C-N bonds
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HR SERIES
2.2.1.1.1. Hydrogenolysis of the Sulfur compounds also called Desulfurization
Desulfurization reaction converts organic sulfur into hydrogen sulfide, this is an exothermic
reaction that consume hydrogen.
Typical distribution of sulphur compounds :
VACUUM
GASOLINE KEROSENE GAS-OIL DISTILLATE
CRUDE
RESID
R-S-H
R-S-R
S
S
Sulphur
Content
1.2
0.02
0.2
0.9
1.8
2.9
There are two reactions pathway:
1. Breaking C-S bond and H2 saturation for S in aliphatic molecules,
•
Mercaptans
R - SH + H2 → R - H + H2S
•
Sulfides
R - S - R + 2 H2 → 2 R - H + H2S
+ 2 H2 → C4 H10 + H2S
S
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HR SERIES
2. Saturation of aromatic double bonds, breaking C-S bond and saturation when S is in the
aromatic ring :
• Thiophene
+ 4 H2 → C4 H 10 + H2 S
S
• Dibenzothiophene
+ 5 H
+HS
2
2
Benzylcyclohexane
S
To get an ultra-low sulphur Diesel (ULSD), the most refractory sulphur species must be
removed. The remaining sulphur components below 50 ppm are mainly
dibenzothiophenes with alkyl groups in the fourth and sixth positions, mainly 4,6 dimethyldibenzothiophene, even through such components are present in straight run Diesel
feedstocks at “traces level”.
Most of the reactions are straight forward except for the desulphurization of the aromatic
sulphur species. This reaction is more complex because it must start with ring opening and
sulphur removal followed by saturation of the resulting olefin. As a comparison of the
relative ease of removal, thiophenes are about 15 times more difficult to treat than
sulphides.
The degree of substitution within each sulphur type (i.e. the presence of side chains and
associated rings) also has a large impact on the ease of sulphur removal. In particular,
some alkylated di-benzothiophenes are much more difficult to treat than dibenzothiophene itself.
Severity of the reaction depends on the feed structure, order of increasing difficulty:
R-S-H
>
R-S-R
>
>
S
S
>
S
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2.2.1.1.2. Hydrogenolysis of the Nitrogen compounds also called denitrification
Denitrification reaction converts nitrogen into ammonia, this is an exothermic reaction that
consume hydrogen. The denitrification rate is lower than the desulfurization rate.
(Ammonia (NH3) reacts with hydrogen sulfide (H2S) to form salts).
Typical distribution of nitrogen compounds :
Gasoline
Kerosene
Gas oil
Vacuum
R-NH2
Distillate
Resid
R
NH
R
N
N
N
N
N Content
0-5
1-20
10-300
S.R. cuts
(0-1)
(5)
(100)
(1000)
10-100
20-300
200-1000
500-3000
Pyrolysis cuts
(3000)
There are two different type of nitrogen compounds:
ƒ
Basic nitrogen
Pyridine
Quinoline
N
Acridine
N
N
R
Amines
ƒ
NH
R-NH2
R
Non Basic nitrogen (unsatured compounds)
Pyrrole
N
Indole
N
Carbazole
N
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•
Amine
R - NH2 + H2 → RH + NH3
•
Pyrole
+
4H2
+
NH3
N
Pyrrole
•
n-Butane or
iso-Butane
Pyridine
+ 3 H2
+ H2
N
C5 H12 + NH
3
N
H
Phenylamine
Pyridine
•
C5 H11 NH2 + H2
Quinoline
+7H
2
+ NH 3
N
•
Quinoleine (first: aromatic ring hydrogenation (limiting step), then C-N bond
hydrogenolysis)
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2.2.1.1.3. Hydrogenolysis of the Oxygen compounds or hydrogenation of Oxygenic
compounds
Oxygen compounds in the gasoil cuts are mainly naphthenic acids and phenols.
Chemical reaction of these compounds with hydrogen leads to the formation of water
(H2O), easily eliminated from the treated cut by decantation in the separation section.
This is an exothermic reaction and easier than a denitrification reaction.
Hydrogenation of bond C-O
•
Alcohols and phenols
R - OH + H2 → R - H + H2O
•
Acids
O
R - C = O + H2 →
OH
R - C + H2 O
H
Hydrogenation of bond C=O
•
Aldehydes
R - C = O + 2H2 → R - CH3 + H2O
H
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2.2.1.2.Olefins and Diolefins Hydrogenation
Olefins and diolefins are present only in cracked feedstock's from conversion units. Some
olefins could be present in straight run gasoil, when CDU (crude distillation unit) bottom
temperature is too high leading to some thermal cracking.
They are very exothermic reactions, occurring easily with a short residence time, the
hydrogenation rate of olefins and diolefins is faster than the hydrodesulfurization rate. The
thermodynamics shows that, in opposition to aromatics, the hydrogenation of diolefins is
almost complete at 300°C with a low hydrogen partial pressure.
Olefins and diolefins can easily polymerized and form gums which then give coke.
Only a catalyst with a neutral carrier can limit the polymerization and gums formation, this
catalyst (HR 945) has to be loaded before the hydrotreatment catalyst.
•
Olefins:
R - CH = CH2 + H2 → R - CH2 - CH3
+ H2
R
R
CYCLOOLEFINS
3 - ETHYL - 2 PENTENE
+
H2
3 - ETHYLPENTANE
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2.2.1.3.Hydrogenation of Aromatic compounds
From a general point of view, aromatics hydrogenation reactions have the following
characteristics:
o they consume H2
o they are highly exothermic
o they are reversible reactions, aromatic saturation are favored by low
temperature and high hydrogen partial pressure (thermodynamic effect)
o they help to limit coke formation by saturating the coke precursors
•
Benzene
+ 3 H2
•
C6H
12
Naphthalene
+3H
+2H
2
2
Naphalene
•
Dicyclohexane
Tetraline
Heavy polyaromatic partial hydrogenation
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2.2.1.4.Metals and metalloids compounds removal
The organometal compounds are cracked and the metals are trapped on the catalyst.
Metals are present only in heavy feeds, or in feed cross polluted with crude…. In the
present diesel HDT no metals shall be present in the feeds. If any, and if proper
demetallation catalyst is loaded, the organometalic compounds are cracked and the
metals are trapped on the catalyst pores. This may concern mainly the Ni and V but also
As, Pb, Cu, ….
This reaction occurs mainly in HMC 841 catalyst (if loaded) which pores geometry are
mainly designed for this reaction.
Structure of asphaltens :
Mechanism of metal removal (porphyrinic compounds) :
2: Metal removal
1: Hydrogenation
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2.2.1.5.Hydrocracking
Hydrocracking reactions are a combination of C-C bonds cracking and isomerisation
reactions. Both types are described here after. It must be noticed however that in HDT
units only using HR catalyst without dedicated hydrocracking catalyst, the C-C bonds
cracking reactions are predominant.
a) Hydroisomerisation and then cracking into lighter isoparaffins.
R'
R
R'
R
R
+
R'
b) Monocyclic naphthenes are dealkylated and then isomerised into light isoparaffins
and lower molecular weight naphthenes.
+
c) Bicyclic naphthenes are reacting to open one ring in order to form alkyl-substituted
monocyclic naphthenes which follow the path described in b.
d) Alkylbenzenes are dealkylated to form aromatics and isoparaffins. They are also
hydrogenated to form monocyclic naphthenes which follow the reactions described in
b.
+
+
H2
C2 H6
e) Benzonaphthenes react primarily by opening of naphthene rings to produce
alkylbenzenes which react as described in d. They may also undergo hydrogenation of
the benzene ring to form bicyclic naphthenes which follow the reaction path described
in c.
f) Polyaromatics first undergo hydrogenation of one ring to form benzonaphthenes. The
benzonaphthenes then follow the reaction path described in e.
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From a general point of view, aromatics hydrogenation reactions have the following
characteristics:
o They are thermodynamically favoured at low temperature
Rev 4
o They are exothermic
o They occur slowly requiring long residence time
o They promote coke formation when ppH2 is not high enough to insure
complete hydrogenation
Hydrocracking reactions are often desired in processes such as VGO HDT as they lead
to light Naphtha and Gasoil products which are valuable.
In other processes like Gasoil HDT, these reactions are considered as undesirable
because they produce light products, gases, LPG and Naphtha, which are less valuable
than the gasoil. Moreover, the C1 and C2 gases, and some of the LPG tend to accumulate
in the recycle gas and thus decrease the hydrogen purity of this gas and the hydrogen
partial pressure.
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2.2.2 Adverse reaction: coking
Coking is an adverse reaction of the HDT process that cannot be avoided. Heavy
molecules are adsorbed on the acidic sites of the catalyst, condense and progressively
polymerize on the catalyst and form coke. These molecules, also named coke precursors,
are polynuclear aromatics, gums and asphaltenes. Asphaltenes are never found neither in
light cuts nor in gasoil or even in light VGO, but can be found in heavy VGO. Polynuclear
aromatics and gums can be present in the feeds and can also be formed in the HDT unit
process, especially from cracked materials. The coke deposit is the main cause of catalyst
activity reduction.
Simplified coke formation scheme from Polynuclear aromatics
Cracking
….+
…..+
+ and so on ………..leading to heavier and heavier molecules, finally to coke.
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2.3. Operating parameters of the reaction section
2.3.1 Definitions
In our definition, the operating parameters of a hydrotreatment units are the parameters
which have an impact on the process: on the thermodynamics and kinetics of the chemical
reaction, and on the catalyst behaviour.
The most obvious are the operating variables which can be set independently by the
operators within the ranges allowed by the equipment design:
ƒ feed rate ;
ƒ catalyst beds inlet temperatures (or heater outlet temperature and inter-bed
quench rates) ;
ƒ unit pressure ;
ƒ H2 make-up gas rate and H2 purity. Most often the make-up gas purity is fixed and
so it is not really an operating variable ; in many cases also, the make-up gas rate
just balances the H2 consumption and so it is not an independent variable ; if
excess H2 is available the make-up gas rate can be varied independently above the
H2 consumption and a gas purge in the high pressure loop is then necessary to
control the unit pressure ;
ƒ recycle gas rate and H2 purity. Normally, the recycle gas purity is determined by
the conditions (P & T) in the separation section and so it is not an operating
variable.
For the sake of the HDT process theoretical description and modelling, these operating
variables are translated into the usual following mathematical parameters:
feed rate
Æ LHSV (Liquid Hourly Space Velocity) which is the ratio of the feed rate against
the catalyst volume, and by the way is correlated to the residence time of the feed
in the reactors;
catalyst beds temperatures
Æ WABT which is the weight average catalyst beds temperature, or in other words
the average catalyst temperature in the reactors;
unit pressure and recycle gas H2 purity
Æ H2 partial pressure which represents the gas phase hydrogen partial pressure
in the reactors ;
recycle gas rate and purity
Æ H2/HC Ratio which represents the excess of hydrogen in the reactors with
respect to the hydrocarbon feed rate.
Furthermore, for the full understanding of the process a few additional operating
parameters which are not variables must be taken into account and especially:
- feed quality;
- H2S content of the recycle gas or H2S partial pressure.
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2.3.2 Role and impact of the operating parameters in the process
2.3.2.1.Temperature (WABT)
Temperature is the main operating parameter of the unit. Increasing or decreasing the
catalyst temperatures is the most efficient way for the operator to adjust products qualities
and yields. As a matter of fact, catalyst activity is directly related to its operating
temperature.
Hydrotreatment reactions kinetics in the catalyst beds are enhanced by an increase of the
temperature.
The temperature is also the main factor that influences the coke formation and thus the
catalyst stability. High temperature favours coke build-up; in some circumstances it can
even happen that the temperature can be high enough to reach the thermodynamic
limitation of the hydrogenation reactions which also tends to favour coke formation.
(Example: aromatic hydrogenation)
The adjustment (increase) of the temperature during the catalyst cycle is the way to
compensate for the catalyst deactivation and maintain the products qualities. It means that
the temperature determines the cycle length of the catalyst in the unit: once the maximum
allowable operating temperature is reached, the cycle can be considered as finished,
except if the feed rate can be decreased, or the feed quality made easier (see the next
paragraphs).
2.3.2.2.Feed rate (LHSV)
The residence time of the feed inside the reactors is obviously a key parameter of the HDT
kinetics. To represent this residence time, actually its inverse, the LHSV for Liquid Hourly
Space Velocity has been defined:
Liquid hourly space velocity : LHSV (h −1 ) =
Feed flowrate m3 / h(@ 15°C or 60° F )
Catalyst Volume m3
The lower the LHSV (or the feed rate) the higher the residence time and so the more the
HDT reaction can progress through the reactors.
If the LHSV is increased, to keep the same HDT rate, for instance the same HDS and thus
the same sulphur in the product, the catalyst temperature must be increased to
compensate the decrease in residence time
2.3.2.3.Make-up gas rate
In hydrotreatment reactors, hydrogen is of course and by definition a necessary reactant.
The hydrogen is supplied to the HDT unit from the producing units in the refinery, directly
or through a common hydrogen network. Most usual sources are catalytic reforming units
and hydrogen plants (Steam Reformers for instance). The hydrogen streams are
sometimes purified through Pressure Swing Absorption or by membrane permeation in
order to supply as pure hydrogen gas as possible to the HDT units. The Make-up gas is
the H2 rich gas entering the HDT unit through its limit battery.
Practically and usually, the make-up gas rate is adjusted to balance the amount of H2
consumed in the reactors and so it is not an independent variable of the process. If the
refinery H2 balance allows it, the make-up gas rate may be increased and varied
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independently above the H2 consumption. A gas purge in the high pressure loop is then
necessary for an obvious reason of material balance.
Impurities in H2 make up can inhibits the catalyst activity. Please refer to the impurities
table attached at the end of this paragraph.
2.3.2.4.Recycle gas rate
In a HDT unit an excess of hydrogen is necessary in addition to the Make-up gas. This
excess is achieved by continuously recycling gas containing hydrogen around the reaction
section: practically the gas from the HP separator is sent back to the feed preheating train
by a recycle compressor. The recycle gas rate must be regarded and adjusted with
respect to the hydrocarbon feed rate. The excess of hydrogen is defined as the H2/HC
ratio which is the ratio of pure hydrogen flow in recycle gas (Normal m3/hour) to feed flow
rate (m3/h at 15°C), at the first reactor inlet.
(
)
H 2 Pure hydrogen Nm 3 / h in recycle gas (Make up excluded )
=
HC
Fresh Feed flow rate m 3 at 15°C / h
(
)
The excess of hydrogen, and so the recycle gas, are necessary for the following reasons:
1. to insure a sufficient hydrogen supply at all location of the catalysts beds, in
order that the desirable chemical reactions are not limited by a lack of H2
locally
2. to insure a sufficiently high concentration of hydrogen in the reactors gas phase
to promote the desired HDT reactions. As a matter of fact the thermodynamics
and/or kinetics of these reactions are strongly favoured by a high hydrogen
concentration combined with a high pressure (see next paragraph);
3. to inhibit or mitigate the undesired reactions of coking, by two mechanisms :
high hydrogen concentration acts against the thermodynamics and kinetics of
the coking reactions ; furthermore the recycle gas flow contributes to stripping
the heavy condensable materials which adsorb on the catalyst as coke
precursors ;
and subsequently, to maximize the catalyst stability and the cycle length and to contribute
to a good gas/liquid distribution in the catalyst beds for an optimal use of the catalyst.
The H2/HC depends on the recycle gas flowrate and hydrogen content (purity). The
recycle gas rate is basically defined in the design by the characteristics of the recycle gas
compressor which is normally run at full capacity. It is essentially composed of H2,
Methane and Ethane, H2S and small fractions of LPG; its exact composition depends on
the HP separator temperature and pressure but first and for most on the amount of light
gases (C1 and C2) in the reactors effluent. These gases are formed in the reactors by
hydrogenolysis or cracking reactions, and also brought into the unit by the Make-up gas.
This is why the recycle gas purity is strongly correlated to the Make-up gas composition.
The recycle gas purity is typically a few % (5 to 15) lower than the make-up gas purity. It
can be enhanced by purification (by membranes) or by increasing the Make-up gas rate
and purging.
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2.3.2.5.Hydrogen partial pressure
The reactors pressure plays a key part in the HDT process to promote the desired
chemical reactions instead of the adverse. Actually, the relevant factor in view of
thermodynamics and kinetics of reactions is the Hydrogen Partial Pressure in the reactors,
which results from the total Pressure P and the Hydrogen concentration XH2 in the reactors
gas phase:
H2 partial pressure = P x XH2
A high H2 partial pressure accelerates the desirable HDT reactions and thermodynamically
favours the hydrogenation reactions of aromatic cycles in the molecules, which is a
necessary path in some reaction mechanisms.
On the contrary, a high H2 partial pressure inhibits the mechanisms of coke formation and
thus strongly favours the catalyst stability and the cycle length.
For these reasons, to maximize the H2 partial pressure a HDT unit is normally operated at
the maximum pressure allowed by the equipment design. The H2 partial pressure is also
maximized by maximizing the H2/HC ratio as an increase of this ratio increases the H2
concentration in the reactors.
2.3.2.6.Hydrogen sulfide partial pressure
H2S is an inhibitor of the HDT catalyst activity, as it competes with the other reactive
compounds on the catalyst active sites. A partial pressure of H2S in the reactors can be
defined in the same manner as the H2 partial pressure.
A high H2S partial pressure will tend to decrease the catalyst activity and so to decrease
the HDT rate. This effect is temporary, which means that as soon as the H2S partial
pressure decreases the catalyst recovers a higher activity.
The main parameter influencing the H2S partial pressure except the total pressure is the
H2S content of the recycle gas. Normally, in the units where a significant amount of H2S is
produced in the reactors the H2S is almost completely eliminated from the recycle gas by
an amine absorber.
2.3.2.7.Feed quality and impurities
The quality of a feed is a factor that can impact on a great extent the performances of a
HDT unit. At design phase the operating conditions of a unit, pressure, temperature range,
recycle gas rate and purity, feed rate, are set based on a design feed case, and eventually
taken into account a few flexibility cases. But during its life the unit may treat many kinds of
feed sometimes much different from the design cases and more or less reactive towards
the HDT reactions.
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The main properties that must be first regarded are the following:
composition of the feed : fraction of cracked products
Olefins content or Bromine Number
Di-olefins content or Diene Value (naphtha)
total Sulphur content
total Nitrogen content
Density
Aromatics content and distribution of mono- / di- / tri-/ poly- aromatics cycle
molecules
o Distillation
o
o
o
o
o
o
o
As regards the Naphtha cuts, Axens today characterizes these feeds element by element.
This enables a fully analytical approach of the kinetics of the naphtha HDT processes and
especially the selective catalytic processes.
As regards the middle distillates and vacuum distillates, it is really the overall set of these
properties which defines how reactive or refractory a feedstock is the combination implicitly
contains the information about the molecular structure and composition of the feed. In this
respect, the origin of the feed, the crude origin, also is a precious indication.
For instance regarding HDS which is the main objective of a HDT unit, the total sulphur
content of a feed is necessary but not sufficient information to know how difficult it is to
achieve a certain level of sulphur in the product. The distillation range and especially its
heavy part (95% point) provides a supplementary information: the higher the 95% point is,
the more heavy and refractory sulphur compounds the feed contains, for example DiBenzothiophenes in case of a diesel feed. In addition the Nitrogen content is an indication
of the reactivity of the feed towards HDS as nitrogen compounds are inhibitors of catalyst
activity. The density with regards to the distillation range indicates the aromaticity of a feed
which also informs about its reactivity as aromatics inhibits the catalyst activity. Etc…
Today Axens is achieving more and more detailed characterization of HDT feedstocks; as
for Naphtha, Axens is able today to determine the different sulphur species in a diesel feed
and to measure the amount of each. The same can be done for Nitrogen species. This
approach is under development for heavier feeds.
Impurities in the feed
The catalyst activity and stability can be affected, either temporarily or permanently by
poisons contained in the feed. These impurities are mainly, metals and metalloids. In the
light cuts (Naphtha, Kerosene, Diesel) they are usually due to additives in upstream units;
for example, Silicon is found in coker or visbreaker gasoils. In straight run VGO some
metals such as Nickel and Vanadium are contained in heavy molecules.
Metals are trapped on the catalyst. The absorption occurs preferentially on the upper
layers of the catalytic beds and progressively extends downwards. For the catalyst part
affected by these compounds, the activity is drastically reduced.
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Another type of pollution that can be found in HDT units feeds are gums or gums
precursors (potential gums). These are compounds that have a high tendency to
polymerize at the high temperatures typically used in the HDT processes. They lead to
fouling problems in the preheat exchangers train. They can even pass through and deposit
on the catalyst beds, causing plugging, pressure drop increase and affecting the gas/liquid
distribution. Gums and potential gums are partially polymerized molecules originated from
unsaturated compounds; their formation is favoured by oxygen. It means they are very
likely found in cracked products (naphtha or gasoil) from catalytic or thermal cracking
units, and this all the more as if these products have been stored in tanks that may contain
a little oxygen or some water. For the same reason the imported HDT feedstocks can be
suspected of containing potential or actual gums.
The most common contaminants that can be found in HDT units feeds are listed in the
table hereafter.
Rev 4
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Impurities
Symbol
Contaminant type
Origin
FEED
Max. content
on catalyst
(End Of Life)
Regenerability
Criteria
Means of
removal
Notes
1-4 ppm wt
5 %wt(8)
2.5%wt(9)
--
(3) (7)
0-3 ppm wt
5 %wt(8)
2.5%wt(9)
--
(3)
0.2 %wt(8)
0.1%wt(9)
--
(3)
Typical content in feed
Naphtha
Gasoil
< 0.5
ppm wt
< 0.5
ppm wt
VGO
Nickel, Vanadium
Ni, V
Permanent
Feed
< 15 ppb wt
Iron
Fe
Pemanent
Feed / Corrosion
--
Arsenic, Antimony,
Lead, Phosphorus
As, Sb,
Pb, P
Permanent
cracked feed
0-10 ppb wt 0-50 ppb wt 0-50 ppb wt
gas condensate,
(cumulated) (cumulated) (cumulated)
external pollution
Silicium
Si
Permanent External pollution
1-5 ppm wt
<1 ppm wt
<1 ppm wt
3 %wt(8)
1.5%wt(9)
--
(3) (4)
Sodium, Calcium
Na,Ca
Permanent External pollution
--
0-50 ppb wt
0-1 ppm wt
0.5 %wt(8)
0.25%wt(9)
--
(3)
--
--
< 200 ppm
wt
--
--
Regeneration
(1)
--
--
--
Regeneration
--
--
--
Regeneration
--
--
Regeneration
Asphaltens
(nC7 insolubles)
Stability (D2274 for
GO Naphtha)
--
Inhibitor
--
Temporary
Potential Gums D873
--
Temporary
Existing Gums
(D381 for Naphtha)
--
Temporary
Free water
H2O
Chlorides and other
minerals salts
Dissolved O2
--
Storage / cracked
feed
Carbon mono/di
oxyde
Oxygen
HCl
Notes :
-< 10
mg/100 ml
NA
NA
Temporary External pollution
--
--
--
--
Permanent External pollution
1 ppm
--
--
1 %wt
0.5%wt
--
(3)
O2
Temporary
< 200 ppm
< 200 ppm
< 200 ppm
--
--
Regeneration
(6)
10 ppm vol.
--
--
50 ppm vol.
--
--
50 ppm vol.
1 ppm vol.
---
---
Storage
HYDROGENE MAKE UP
Carbon mono
< 50
mg/100 ml
< 50
mg/100 ml
--
(2)
Restore feed
spec.
Typical content
CO
Inhibitor
CO+CO2
Inhibitor
O2
HCl
Inhibitor
Inhibitor
Methanator or
PSA upset
Methanator or
PSA upset
Upstream unit
Upstream unit
(1) Asphaltens are inhibitor of the catalyst hydrogenating activity and lead to coke formation
(2) Gums cause : - clogging in the heat exchangers.- a quick increase of reactors ΔP (deposits on the top part of the catalyst bed) .
To avoid gums, an inerting of the storage tanks feeding the unit is to be provided.
(3) The contaminated catalyst must be unloaded, can not be regenerated and must be changed.
(4) Silicium coming from antifoaming additives from cokefaction units (but also Visbreaking units and FCC).
(5) Risk of ammonium chloride formation in the unit, which causes plugging problems and corrosion in the equipments.
A chlorine adsorbent pot is provided and allows a reduction in (chlorine + chloride) to 0.5 ppm vol. on the hydrogen make up.
(6) Dissolved oxygen leads to gum formation and maldistribution that create catalyst fouling.
(7) Excluding Ni contained on fresh catalyst
(8) (Ni+V+Fe + Si) + 7*(As + Na + Sb + Pb)= 5.0 wt%
(9) (Ni+V+Fe + Si) + 7*(As + Na + Sb + Pb)= 2.5 wt%
Restore
make up
spec.
(5)
NA: Not Applicable
HR SERIES
2.3.3 Influence of the operating parameters on the chemical reactions
Hydrodesulfurisation: HDS reactions are exothermic and not limited thermodynamically.
Their velocity is enhanced by an increase of the catalyst temperature and by an increase
of Hydrogen partial pressure. A decrease of the LHSV leads to an increase of the HDS
rate by increasing the residence time and so letting more time for the reactions to occur.
The effect of LHSV obviously applies to all the HDT reactions. The HDS kinetics varies
very much depending on the sulphur species: Mercaptans and Sulfides react very quickly
whereas Sulfur combined into cycles of aromatic structure are much less reactive.
Aromatics hydrogenation: HDA reactions are exothermic and they are
thermodynamically limited. Accordingly with thermodynamic laws, HDA is
thermodynamically favoured by :
- a decrease of the reactors temperature
- an increase of the H2 partial pressure
From the kinetic point of view, HDA is accelerated by an increase of the temperature and
an increase of the H2 partial pressure. HDA reactions are relatively slower than HDS and
HDN.
Finally HDA rate results of a compromise between thermodynamics and kinetics:
- at a given pressure, below a limit temperature the HDA rate increases with
temperature according to the kinetic law (Kinetic control) ;
- above the limit temperature, the HDA rate decreases because of
thermodynamic limitations ;the limit temperature increases as the H2 partial
pressure increases.
Hydrodenitrogenation : the HDN reactions are influenced by the operating parameters in
the same manner as the HDS. But the reaction mechanisms (chemical paths) are different:
the hydrogenolysis of Nitrogen atoms contained within aromatic molecules require
preliminary hydrogenation of the aromatic cycles. As a consequence, the HDN reactions
are relatively slower than the HDS. Another consequence is that they can be
thermodynamically limited at high temperatures.
Olefins hydrogenation: HDO reactions are complete and highly exothermic reactions.
They are relatively the quickest reactions of all and so they often take place on the first
layers of the catalyst beds, inducing a high exotherm. They happen quicker when the
temperature and the H2 partial pressure are high.
Oxygen compounds hydrogenation: their behaviour is similar to the Nitrogen
compounds.
Hydrocracking: Hydrocracking of C-C bonds are exothermic and complete reactions.
Hydroisomerisation are also exothermic but are thermodynamically limited. Both are
kinetically favoured by an increase of the temperature and by an increase of the hydrogen
partial pressure.
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Metal removal: in distillates the molecules containing metals are easily transformed
and the metals are trapped on the catalyst reducing its surface area and so its activity.
Therefore it is necessary to limit the metal content of the feedstock.
Coking: coking is kinetically and thermodynamically favoured by high temperature and low
hydrogen partial pressure.
The table below summarises the influences of the operating parameters on the rate of the
different reactions, the heat of reactions and their relative velocities:
H2 partial
pressure
Temperature
Hydrodesulfurisation
Hydrodenitrogenation /
deoxygenation
LHSV
Relative
velocity
Heat of
Reaction Kcal /
MoleH2
d
- 12
+ + + +
+ + +
- 10
Hydrogenation of
Aromatics
+ +
- 10
Hydrogenation of
Olefins
+ + + + +
- 30
+
- 10
Hydrocracking
Coking
2.3.4 Typical ranges for the main operating parameters
Petroleum cut
Naptha
Kerosene
Gas oil
Vacuum Gas oil
Cut
Space
Point
velocity
(°C)
(h-1)
80-150
5-8
150-240
2-4
240-350
0.5-3
350-550
0.5-2
H2
pressure
(bar)
15-30
15-30
15-50
40-70
Temperature
H2/HC
at start of run ratio
(°C)
(Nm3/m3)
280-330
300-340
150
320-360
150-300
360-380
300-500
H2
consumption
(%wt)
0.1-0.2
0.3-0.8
0.4-1
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3.
CATALYST
3.1. Nature and role
A catalyst is a “material” which by contact with the reactants increases the velocity of
chemical reactions and so make them happen within a limited period of time. One
reaction (or a family of reactions) is accelerated by a specific catalyst, and this is why a
catalyst is said to be selective.
A catalyst of chemical reactions is either homogeneous, which means its physical phase is
the same as the reactants (most often liquid in refining applications), either heterogeneous
(solid in refining applications). A heterogeneous catalyst generally consists of a support
(alumina, silica, magnesia, ...) on which (a) finely divided metal(s) is (are) dispersed.
The metal is responsible for the main catalytic action. Very often, the support has also a
catalytic action related to its chemical nature.
3.2. Physical properties
The metal atoms (i.e. active agents) are dispersed inside the porous support.
The catalytic reaction takes place on the active species, which is why good accessibility to
these species by the reactants is of prime importance.
The key parameters of the catalysts are:
ƒ the specific surface area of the support. Expressed in m2/g, it represents the area
given to the reactants per gram of catalyst. The typical range for hydrotreatment
catalyst is 150-300 m2/g.
ƒ the porosity : Porous volume and pore distribution of the support. High specific
surfaces can only be obtained from high grain porosity characterised by the porous
volume. The pores must also be judiciously distributed in a way that the catalyst
surface is effectively accessible by the reactants. To achieve that the porosity must
be distributed in a network channels in such a way that the big channel or the big
pores macropores (0.1 to 1 µm) bring the reactants towards the small channel or
the small pores micropores (0.01 µm) in order to minimize the clutters. Moreover
the catalyst grain must not be too big, in this way pores are shorter and the transfer
of reactants and products is easier.
ƒ the dispersion rate of the active agents on the support. It is linked to the catalyst
chemical nature and to its preparation.
These parameters, if they are satisfactory, tend to limit diffusion phenomena by facilitating
the access of reactants and departure of products.
The following figure provides a schematic representation of the cross-section of a grain of
catalyst. It contains macropores and micropores. The arrows show the direction taken by
reactants R to reach the internal surface of the catalyst.
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External surface
of the catalyst grain
R
R
Micropores
Gas or liquid phase
containing the reactives
R
D CH 065 B
Macropores
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The following diagram, shows a detailed description from the catalyst grain to the atomic
scale.
The catalyst:
γ-alumina supported
MET image of CoMoS catalyst @IFP
10
<L> = 3,9
<n> = 1,6
<L
layer structure of MoS2
edge decoration by Co or Ni
n
γMolybdenu
Co / Ni
Sulfu
On the macroscopic scale, the catalyst must have a good mechanical resistance which
enable it to be easily loaded without being broken and to bear pressure drops across
the catalyst bed in operation.
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3.3. Catalytic mechanisms
The catalytic reaction can be broken down into three successive steps:
ƒ adsorption of reactant molecules on certain available sites on the surface,
known as "active sites".
ƒ chemical reaction in the surface-adsorbed phase. This step is usually very
fast, since the chemical species formed by association with properly selected
sites are far more reactive than non-adsorbed molecules.
Furthermore, the catalyst brings together these reactive species locally in the
adsorbed phase, thereby considerably increasing their probability of meeting, which also
helps accelerate chemical change.
ƒ desorption of products formed by the reaction, thereby releasing the active
sites for re-use. The products migrate through the pores to the outside of the
grain towards the liquid or the gas homogeneous phase.
Rransportation
tants
Reac
P
R
Chemical
reaction
t
A d s orb e d
r e a ct a nts
t h e c a t aly st
Inside surface of
R
P
Elimination of th
P
e produc
ts
Adsorbed
products
D CH 064 B
Pore inside the catalyst grain
These various elementary steps in catalysis are summarized in the following diagram.
Active site
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3.4. Characteristics towards the process
The main characteristics of a catalyst in addition to its physical and mechanical properties
are :
The activity, which is the catalyst ability and efficiency to increase the rate of the
reactions. It is measured practically by the temperature at which the catalyst must be
operated to achieve the products specifications for given feed and operating conditions.
The selectivity, which expresses the catalyst ability to favour desirable reactions rather
than the others.
The stability characterises the change with time of the catalyst performances (i.e. activity,
selectivity) when operating conditions and feed quality are stable. It is mainly the coke
deposit which affects stability, through its inhibition of the catalyst acidity and decrease of
available catalytic surface area.
When the catalyst gets too deactivated, it does not enable anymore to achieve the
required performances. The cycle of the catalyst in the unit is then finished and the
catalyst must be changed or regenerated to be used again. The regeneration consists in
burning the coke. It can be performed inside the unit if it has been designed for that, but
generally it is done outside the unit in dedicated plants (chapter 4.5). Some impurities such
as metals (Nickel, Vanadium, Silicon, Sodium…) are not eliminated by the regeneration,
and thus modify the properties of the regenerated catalyst. Furthermore, the impurities
content on the spent catalyst must not exceed a certain level if the catalyst is to be
regenerated and reused (see paragraph 2.3.2.7 for the list of contaminants). A
representative sample of the catalyst is regenerated to allow measuring impurities
levels. It is then decided with the table below if the catalyst could be regenerated
and reused or not.
Typical regenerability criteria for HDT Catalysts
Unit
On the unregenerated
material
On lab regenerated material
Comment
compared to fresh
Non applicable
>=75%
Actually varies wth catalyst types
(wt%)
Non applicable
< 1.2
Average
(mm)
> = 2.5
Non applicable
Mechanical Strength
Bulk Strength
MPa
Non applicable
>= 0.8 MPa
(% by count)
(wt%)
< 25
Non applicable
(wt %)
(wt %)
(wt %)
(wt %)
(wt%)
(wt%)
Non applicable
Non applicable
Non applicable
Non applicable
Non applicable
Non applicable
Catalyst analyses
Surface area
Sulfur on lab regenerated
Length*
Length Distribution*
total
<2.0 mm
if the spec is not met, a length grading treatment
should be envisaged
Chemical properties
Si ex contaminant
Na
As
V+Ni+Fe
Other heavy metals
Total contaminants
Refer to< §1.5
2.3.2.7
Refer to< §0.4
2.3.2.7
Refer to
§ 2.3.2.7
< 0.25
Refer to< §1.0
2.3.2.7
Refer toNone
§ 2.3.2.7
Refer to< §2.0
2.3.2.7
Refer to Feed impurities
table
* on the catalyst preliminary sieved on a 1x1mm mesh. (Valid for a small sized catalyst (from 1.2 to 1.6 mm diameter)
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3.5. Guidelines for HR500 catalysts choice
The definition of a catalyst system for a hydrotreatment unit depends on several factors. A
non exhaustive list is given below.
3.5.1 The main characteristics of the feeds
Crude origin, directly from the crude distillation unit (CDU) or vacuum distillation unit
(VDU) generally called straight run (SR) distillates, or from the various conversion units
existing in a refinery as Visbreaker, Coker, Catalytic cracking. The SR distillates do
not contain olefins. On the contrary, olefins and few diolefins compounds are present in
conversion gasoil cuts.
3.5.2 The unit objectives
The following objectives are usually combined by two or three.
ƒ Desulfurisation (deep or not)
ƒ Nitrogen removal
ƒ Cetane improvement.
ƒ Aromatics content reduction
ƒ Feed preparation for cracking
ƒ Conversion into light fraction
To meet the unit objectives, the operating conditions must be set according to some
general rules (Refer to operating conditions paragraph).
The recommendations to choose the catalyst which suits the best to the feed
characteristics and especially to the unit objectives are attached on the graphs hereafter.
These recommendations are given as a guideline, and specific cases should be treated
in a different way.
Naphtha Application criteria
Medium
Pressure
Low
Pressure
HR 506
(target: sulfur + nitrogen)
HR 538
(target: sulfur + nitrogen)
% refractory feed
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Diesel Application criteria
High
Pressure
HR 548
(target: sulfur + cetane +
Aromatics+ conversion)
Medium
Pressure
HR 568 (target: sulfur)
Low
Pressure
HR 526 (target: sulfur ULSD)
HR 506 (target: sulfur classical)
% refractory feed
VGO Application criteria
Hydrocraking
pretreatment
Mild
Hydrocracking
FCC Feed
Preparation
HRK 558
(target: nitrogen + preconv.)
HR 548
(target : sulfur + cetane + Aromatics+conv)
HR 526 (target : sulfur)
HR 568 (target: sulfur)
% refractory feed
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4.
SPECIAL PROCEDURES FOR CATALYST
Different special procedures are applied to the catalyst:
ƒ at start-up, the catalyst is loaded and sulfided,
ƒ at shutdown, the catalyst may be unloaded under inert atmosphere for an ex situ
regeneration, or, for the non promoted catalysts, regenerated in-situ.
4.1. Alumina and catalyst loading
Correct catalyst loading is absolutely necessary for achieving the expected performance
from the unit. This section presents guidelines for the correct loading of the reactor. After
the cooling down, the reactor atmosphere should be changed to air or to nitrogen
depending on the catalyst for the catalyst loading.
This can be done by using the ejectors or by sweeping out the nitrogen with a fan.
If the reactor atmosphere is changed to air, check that the reactor is isolated by blinds to
protect the workers inside the reactor and avoid any possibility to have some inert gas
injected into the reactor during the loading period.
Before loading the catalyst inspect the reactor, the trays and internals (cleanliness, proper
mounting, …). The catalyst drums must be stored in a safe place and protected from rain.
4.1.1 General Policy
ƒ
ƒ
ƒ
ƒ
ƒ
ƒ
ƒ
Certain internal parts of mixing and quench tray will be dismantled to allow the
catalyst loading, levelling and checking.
During these operations, because the reactor’s top platform is occupied by
equipment removed from the reactor, another removable platform will be used and
installed at the level of the reactor’s top flange. The operations to be performed on
top of the reactor must be reduced to a minimum, especially drum handling shall be
done on the ground floor only.
Enough space must be provided around the reactor to allow an easy access and a
convenient catalyst handling.
Attention, avoid catalyst breakage or dusting; do not roll drums of catalysts.
Shelters shall be installed to protect the catalyst from the rain, snow, sand, and
wind at all times. In case of heavy rains stop loading.
During the catalyst loading, use safety equipment to protect the eyes and lungs
from catalyst dust: chemical goggles and approved toxic dust respirator. For
presulfided catalyst a breathing mask is mandatory. Make sure that no foreign
material is left in the reactor (pieces of sleeve, walking boards, tools, etc.).
Whenever possible a person shall be inside the reactor to level the catalyst bed and
move the loading sleeve. It will improve the distribution in the bed and avoid
channelling problems in the future. Another person must be in attendance outside
with equipment and instructions in case of emergency.
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Catalyst must be loaded carefully to minimize free fall. Maximum permissible free
fall height is 1 meter. Do not walk directly on catalyst. Use boards.
ƒ All personnel involved in the loading procedure should be briefed as to the possible
hazards upon catalyst exposure to air (magnitude of heat release and SO2 release).
ƒ Portable detectors / analyzers for H2S, SO2 and O2 should be employed in all
catalyst handling areas.
The catalyst either oxide or pre-sulfided can be loaded under air or nitrogen. If the catalyst
is loaded under air, to avoid reaction with O2 it is recommended to ensure that no air is
supplied to catalyst bed through quench lines or reactor outlet. Earth connection for
hopper and or big bags has to be foreseen.
ƒ
4.1.2 Special Loading Devices (Adapted for Each Reactor)
The loading is generally realised using one or two shuttle hopper(s).
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Special Loading Devices (see attached schemes, drawings 6 to 8 and figure 1 to 5):
ƒ
A stationary hopper to be built on site (see drawing n°7-7bis& n°8 and Figure 2).
The stationary hopper is fitted with a slide valve. The hopper legs should be long
enough to allow access into the reactor. The hopper has a connection to N2 for
continuous sweeping while pouring drums into it and covers plate to avoid air
entrance in hopper.
ƒ
Flexible sleeves (adequate length, 150mm diameter).
ƒ
A shuttle hopper containing about 4 drums of catalyst (see drawing n°8 and Figure
4). The hopper has a connection to N2 for continuous sweeping while pouring
drums into it and covers plate to avoid air entrance in hopper.
ƒ
A lifting device to lift the shuttle hopper from the ground level. This lifting device
could be either a crane or a system of winches (drawing n°6 and Figure 1). Ensure
that the crane used for the catalyst transfer hopper does not become a bottleneck in
the loading operation (especially if only one transfer hopper is used). The whole
catalyst loading system shall be able to conduct an average loading rate of 30
drums per hour.
ƒ
At ground level a temporary platform should be erected at the level of the truck
used to transfer the catalyst drums from storage to the reactor site. The drums will
be transferred from the truck to the platform, opened, and poured in the shuttle
hopper while N2 is flowing through hopper. Empty drums should be stored on site or
returned to storage facilities (see drawing n°8 and Figure 5).
ƒ
On top of the reactors a temporary platform should be installed, to allow the
operation of the shuttle hopper slide valve during loading (see drawing n°7-7bis).
ƒ
Tooling, lighting facilities, dust masks, respirators, safety harnesses, should be also
prepared. It is particularly recommended that personnel involved in handling and
loading of the catalyst be properly clothed, e.g. long-sleeved shirts, gloves and
safety glasses. Furthermore it is recommended that self-contained breathing
apparatus (SCBA) be used by any person who must handle the catalyst or enter a
closed area containing the catalyst, e.g. inside the reactor.
ƒ
Bottles should be available to take samples of the catalyst during loading.
ƒ
To protect catalyst from rain, temporary shelters should be installed on top of
reactors and ground level platform.
Note: If the catalyst is delivered in big bags, the mobile hopper and the temporary platform
are not needed.
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Drawing 6
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Drawing 7
ENSURE THAT THE
SLEEVE IS FERMELY
AND SECURILY
TIGHTEN TO THE
HOPPER
N2 CONNECTION
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Drawing 7 bis
SOCK LOADING UNDER AIR
Slide valve
Flexible sleeve
Reactor platform
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Drawing 8
ENSURE THAT THE
SLEEVE IS FERMELY
AND SECURILY
TIGHTEN TO THE
HOPPER
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CATALYST LOADING
A
figure 1
A = MOVING HOPPER (2 DEVICES) / Fig 2
B = STATIONARY HOPPER / Fig 3
C = SCAFFOLDING / Fig 4
D = SEMI-RIGID PIPE / Fig 5
B
REACTOR
D
C
A
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STATIONARY HOPPER (B) figure 2
SLIDE VALVE
figure 3
4'
3'6''
HOPPER
4'
SLIDE VALVE
END NOT
CLOSED
STATIONARY HOPPER
50°
WELD
SLIDE VALVE
diam. 6"
CLOSED
3'6''
SOCK
Semi-rigid
pipe
diam 6'
OPEN
REACTOR
SCAFFOLDING (C)
MOVING HOPPER (A) figure 4
figure 5
4'
4'
3'
MOVING HOPPER
MOVING HOPPER
50°
SLIDE VALVE
diam. 8"
50°
4'
STATIONARY HOPPER
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4.1.3 Loading
The alumina layers (3/4 inch and 1/4 inch) are loaded at reactor bottom. The level will be
carefully levelled by hand.
The catalysts beds are loaded and levelled in the same way.
ƒ When a bed is completed, the alumina layer is loaded and the tray is fitted with care
to have a good operation of the reactor: levelness, seal of the distributor tray,
mixing tray and quench injector, catalyst withdrawal pipes, catalyst support grids.
ƒ Install the scale traps if any on the upper bed and check their penetration in the
catalyst bed.
ƒ Install the top distributor tray and the inlet distributor.
ƒ Close the reactor by fitting the top elbow.
ƒ A complete check of the catalyst loading should be done by recording the drum
number and batch number the gross and net weight (these figures will be checked
on a number of drums). A sample of each drum will be collected to get a
representative sample which will be kept for further tests if necessary.
ƒ The use of a vacuum cleaner is recommended to eliminate the fines from the
internals after loading.
For the catalyst, there are two types of loading
o The sock loading is the more used type in the reactor filling. The catalyst is filled
with a canvas. With this method, there is often but not always a person who is in the
reactor to level the beds and to improve the catalyst repartition by moving the sock.
o The dense loading is a recent type of reactor filling. The catalyst is filled with a
special device that allows a regular repartition in the reactor. It has also the
advantage to increase the loading density that improves the performances, cycle
length and liquid repartition. Compared to the sock loading, it requires special
equipment's. Axens recommends a procedure and the corresponding equipment
(that are described in the following pages) for this purpose: it is the CATAPAC
dense loading procedure.
The catalyst either oxide or pre-sulfided can be loaded under air or nitrogen. If the catalyst
is loaded under air, to avoid reaction with O2 it is recommended to ensure that no air is
supplied to catalyst bed through quench lines or reactor outlet.
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PROCEDURE FOR CATALYST FILLING
PROVIDED BY AXENS
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ABOUT 3m3
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4.1.4 Comparison between the two types of loading
This table compares the two loading types:
Catalyst amount
Sock
Base
Dense
Base up to 15-25% for extrudates
and up to 8-13% for beads
Catalyst arrangement
Random
Liquid repartition
Cycle length
Performances
Delta P in compressor loop
Regular
Improved
Increased
Improved
Slightly increased in SOR and
more stable after
When there are no constraints for the recycle compressor loop, it is recommended to have
a dense loading for revamping of HDS units. For a new unit, the choice will be based on
technico-economical criteria.
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4.2. Catalyst sulfiding before feed-in
The reaction section is isolated from the other sections and is under nitrogen.
The surge drum and stripping section are lined-up by by-passing the reaction section using
the start-up lines. The start-up gasoil kerosene or naphtha is recirculated in this loop.
Please note that:
o For unit hydrotreating VGO, the catalyst activation is done with gasoil. The switch
from gasoil to VGO is realised after the sulfiding.
o For units treating kerosene, the catalyst activation is the same as for units
processing naphtha, same temperature … but using kerosene during the sulfiding.
o During the catalyst activation, high sulfur gasoil, kerosene or naphtha according to
the case has to be made available to be used in case of trouble in order to be able
to control H2S concentration in the HP loop.
4.2.1 General Comments
4.2.1.1.Catalysts delivery
The catalysts are delivered on the metal oxide form, and it is needed to change it to its
active form, the metal sulfide form before the oil-in. For this phase H2S and hydrogen are
required. So, metals initially in oxide form react to give corresponding sulfides.
If not sulfided, operating with a metal-containing catalyst will cause feedstock cracking,
coke deposition on the catalyst, and rapid deactivation of catalyst.
Reducing the catalyst before sulfiding must be avoided as it is harmful for the catalyst.
•
•
•
•
The reduction of the metallic oxide increases the sintering of the metal which tends
to agglomerate and thus the active metallic area is decreased.
For metals able to be sulfided the rate of sulfiding for a hydrogen and H2S
mixture is much higher when the initial product is under oxide form. (The diffusion
of sulfur between the metallic atoms is much easier starting from an oxide than
from a metal).
Because of the inevitable variations in specific volumes when a pre-reduction of
the catalyst is carried out, local pressure stresses (from reduction) are built up in
the grains which are immediately followed by just the opposite effect when the
catalyst is sulfided and the material expands. This contraction and expansion is
harmful to the mechanical stability of the catalyst.
In the case of incomplete sulfiding, when the feed is heated the remaining reduced
metals can cause local overheating and significant coke deposition.
The catalysts are delivered with two possible types of conditioning:
ƒ
ƒ
The un-sulfided catalyst that needs to use an external sulfiding agent to
produce H2S for the activation.
The pre-sulfided catalyst that has the sulfiding agent previously deposited
on it. H2S is produced by thermal decomposition of the coating sulfiding
agent for the catalyst activation.
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The decomposition of the sulfiding agent, H2S adsorption and reaction with metal oxide
are exothermic and there will be a temperature rise through the catalyst beds during
this step. It is important to control the catalyst temperature to prevent premature coking
in case of local temperature rise.
4.2.1.2.Catalysts activation modes
There are two ways to achieve the catalyst activation
ƒ The mixed phase activation: gas and liquid circulate in the reactor to remove the
heat of reaction and control the catalyst bed(s) temperature,
ƒ The gas phase activation: gas is recirculated in the reactor, and it is the only
medium available for heat removal. So the gas flowrate and its heat capacity
are important parameters for this activation type.
The sulfiding with circulation of gas and liquid is superior to the sulfiding with only gas
circulation because it is the best way to remove the heat of the reactions and so, it avoids
formation of hot spots in the catalyst beds.
4.2.2 Catalyst activation or catalyst sulfiding
Axens standard catalysts sulfiding procedures are presented hereafter. Four different
examples are developed, which cover a large scope of hydrotreatment units, from naphtha
to VGO :
ƒ sulfiding with DMDS and gasoil circulation (example HR548)
ƒ sulfiding a pre-sulfided catalyst with gasoil circulation (example HR526)
ƒ sulfiding with DMDS and naphtha circulation (example HR538)
ƒ sulfiding a pre-sulfided catalyst with naphtha circulation (example HR506)
These procedures apply to all the catalysts of both HR500 and HR400 series.
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4.2.2.1.HR 548 GO
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4.2.2.2.HR 526 Presulfided
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4.2.2.3.HR 538 Naphtha
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4.2.2.4.HR 506 Presulfided Naphtha
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4.2.2.5.DMDS quantities and H2O produced
HR 506
HR 526
HR 538
HR 548
HRK 558
HR 568
HR 406
HR 416
HR 426
HR 448
Catalyst Composition
CoO
NiO
MoO3
wt%
wt%
wt%
3.0
0.0
14.0
3.5
0.0
18.5
0.0
3.5
17.0
0.0
4.5
21.0
0.0
4.5
21.0
3.5
1.0
20.0
3.0
4.0
4.0
0.0
0.0
0.0
0.0
3.3
DMDS
H2O produced
Stoechio To buy
%wt
%wt
wt%
11
14
6
14
18
8
13
16
7
16
20
9
16
20
9
16
20
9
14.0
18.0
19.0
16.5
11
14
15
12
14
18
19
16
6
8
8
7
Note: HR series 400 are reminded as reference.
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4.3. Catalyst unloading
Rev 4
The used catalyst contains roughly 15 wt % coke and is sulfide form as opposed to the
new fresh catalyst. The used catalyst can be self heating or pyrophoric (due to iron
sulfides) and contact with air should be avoided, this catalyst should be unloaded under
nitrogen in drums (or bins) and sent to an outside company for regeneration.
If the catalyst is to be dumped the use of soda ash for unloading and purging before
unloading the catalyst is suitable.(Refer to § 4.3.7). It will allows to passivate reactor,
internals and catalysts. In this case, the unloading can be done under atmosphere.
All equipment used for unloading and reloading of the spent catalyst should be swept with
nitrogen. This includes the reactor, the hoppers, and the drums which have then to be
stored in a dry place. The internals will also support pyrophoric iron sulfide. An alkaline
solution (soda, …) will be prepared in which the various piece of internals especially
baskets if removed will be dropped after dismantling for passivation.
Adequate quantity of nitrogen as well as sufficient equipment should be provided to sweep
all the equipment used for the unloading (reactor, hoppers, drums). Screener, motor,
breathing apparatus line system, harness, fire protection equipment and non melting
canvas for catalyst collection under the reactor will be prepared and ready to use. CO2 fire
extinguisher must be ready for use on the top of the reactor and at ground level before the
work start.
Before unloading, the reactor should be cooled down to 40°C.
The unit is shutdown as § 6.1. The status of the unit is as § 6.1.4 with the reaction section
under nitrogen.
The recycle gas compressor is used to circulate nitrogen and cool down the reactor. This
operation will take a long time using the normal circuit due to the recycle gas compressor
discharge temperature and the exchangers (heater draft should be pulled at its maximum).
A solution to speed up this operation is to create a temporary by-pass of the exchangers,
straight from recycle gas compressor to the heater inlet to use the heater as an air
cooler. An alternate is to ask a special contractor to cool down the reactor from 100°C
to 50°C by a subcooled nitrogen flow (use of liquid N2 and evaporator TN2= 10-20°C).
When the temperatures are down to < 50°C, connect nitrogen hoses to different points
of the reactor to prevent any air entry and isolate by blinds the reactor from the rest of the
unit.
Staging will be erected at the top of the reactor to prevent water from entering in the
reactor. In addition, a plastic cover will be put on the top of the reactor to keep slightly
positive pressure of nitrogen in the reactor.
The top elbow will be pulled out and removed by a crane.
The reactor will be swept with nitrogen (cracked open valve) to prevent air from entering
into the reactor. This is to prevent air and iron sulfide exothermal reaction and subsequent
catalyst temperature increase.
Top distributor or manway will be removed.
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The unloading will be done by a specialised contractor able to work in an inert
atmosphere with air masks. Personnel entering in the reactor should be provided with full
life support including breathing apparatus set, special fire resistant equipment and harness
connected to cable to be able to extract them quickly from the reactor.
Catalyst is stored in steel drums (or bins) with a plastic bag liner after air freeing by a
nitrogen sweep.
During the catalyst unloading:
ƒ If the temperature of the catalyst increases during the unloading, stop all operations
and increase the nitrogen flow to the reactor until the temperature reach 50°C.
ƒ If thermocouples can be left in place during the dismantling of the top distributor,
thermocouples located in the bed should be carefully monitored from the control
room and any heating reported to site in order to prevent fire.
ƒ If O2 % vol > 5 % in the reactor, the operation is stopped.
The ¾” alumina balls will be removed by the mean of a bucket (alumina ball are difficult to
extract with a vacuum machine). One person is inside the reactor and one person is on the
top of the reactor to pull out the bucket and stored the balls in a drum.
After the removal of all the alumina balls is completed, the basket strainers if any and grid
support will be removed from the reactor. The baskets contain some iron sulfide and have
to be dropped in soda ash passivating solution to avoid fire.
The catalyst unloaded should be weighted as well as the alumina balls.
When the reactor is empty, to prevent any risk of polythionic corrosion the vessel is
passivated with a sodium ash solution (please refer to the following paragraph).
If the unloading has been done under nitrogen atmosphere and if there is no leak allowing
air entrance, there is no need for this washing.
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4.4. Passivation
4.4.1 Austenitic Steel Protection
Since sulfides are present during operation of the HDS unit, when the unit is exposed to
moist air during shutdown, the potential for stress corrosion cracking in the equipment
fabricated from austenitic stainless steel will exist.
4.4.2 Polythionic Acid Attack
Once a unit has been placed on stream, even if the sulfur content of the feed stock is low,
all items made of austenitic stainless steel should be considered to contain a layer of iron
sulfide scale. Even though these layers of scale in many cases may be very thin, they
represent a potential hazard to the underlying steel.
The action of water and oxygen on this sulfide scale forms weak sulphurous type acids,
commonly referred to as polythionic acids, which can attack austenitic stainless steels and
cause intergranular corrosion and cracking. These stainless steels are vulnerable to this
type of corrosion, particularly in areas of residual tensile stresses and in areas where
intergranular carbides may exist, such as the heat-affected zones adjacent to welds.
Therefore, special precautions should be taken to protect austenitic stainless steel from
this corrosive environment.
4.4.3 Protection against Polythionic Acid Attack
Protection against polythionic acid attack can be accomplished by preventing the corrosive
environment from forming or by providing an agent, which will neutralize any corrosive
acids as they are formed.
4.4.4 Preventing the formation of Polythionic Acids
Since these acids are formed by the action of water and oxygen with hydrogen sulfide or
sulfide scale, elimination of either liquid phase water or oxygen will prevent these acids
from being formed.
Since there will usually be an equilibrium amount of water vapor present during the normal
operation of a unit, during shutdown periods this water vapor can be prevented from
condensing by maintaining the temperature of the austenitic stainless steel equipment
above the dew point of water.
Under normal operations there should be essentially no oxygen present in the system. The
only other time any significant amount of oxygen might enter the system would be during a
shutdown period when the system is depressurized and the equipment is opened and
exposed to air. Under these conditions a suitable purge of nitrogen should be established
through the equipment involved to prevent any air from entering the system, and
maintained until the system is again closed. If possible, the equipment should be blinded
or blanked-off during this period and kept under a slight positive pressure of nitrogen.
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4.4.5 Neutralization
Whenever austenitic stainless steel cannot be adequately protected by maintaining
temperatures above the dew point of water or by an adequate nitrogen purge, a protective
neutralizing environment should be established in this equipment prior to exposure to air.
An effective neutralizing environment can be provided by washing with a dilute soda ash
solution.
The solution should contain 2%wt. Soda Ash (Na2CO3) in water. Water used to prepare
the solution should contain no more that 50ppm in chlorides. The resulting solution should
not contain more that 20 ppm of chloride according to NACE RP 0 0170-93.
Sodium Nitrate (0.5%wt) should also be added to the solution to give added protection
against chloride attack. Do not exceed this amount.
4.4.6 Application of the Neutralizing Solution
Washing of equipment with neutralizing solution is only expected when the contact of
stainless steel surfaces with air cannot be avoided (example: Reactor inspection) and in
the case when only this protection is effective.
The simplest method of Neutralization is to install a temporary mix/storage tank for
preparation and storage of the Soda Ash solution. This tank should be equipped with a
circulation pump. Suitably armored hoses can then be used to connect the pump
discharge to the equipment to be neutralized. The hoses should be flanged to suit the
neutralization stub flanges which will be fitted to line ends when the neutralization spool
pieces are removed. By the same method a return route can be installed back to the tank,
so allowing circulation of the solution.
It may be necessary to mix several batches of the solution in order to fill some items of
equipment. The strength of the solution should be regularly checked in order to maintain
the 2% value.
For equipment where it is possible to perform a circulation of the solution through the
equipment then 2 hours of circulation should be sufficient to perform the neutralization.
For equipment where it is only possible to completely fill the equipment and not circulate,
then 4 hours should be sufficient to neutralize the equipment if the solution is left to stand
in the equipment.
For vessels that are too large to fill completely (possibly due to foundation limitations), the
Reactors and the Hot HP Separator for example. Then the solution should be applied
internally using a high pressure hose fitted with a spray nozzle. To do this the vessel will
have to be opened for entry but kept under a nitrogen atmosphere. One man wearing fresh
air breathing apparatus will then enter the vessel and apply the solution with the hose,
taking care too wet all the surfaces. The solution is then allowed to dry before the vessel is
aerated ready for entry.
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For heater, if heater has to be open to atmosphere, the coils shall be protected the same
way as mentioned above. Then for verticals coils, they will have to be washed out using
demineralised water to remove the soda ash which may be trapped in the bottom elbows.
After water wash is performed the coils are put under nitrogen atmosphere and pilots will
be light up to dry the coils at low temperature. If the recycle gas compressor could be
started at the same time this will help to dry and to remove water which may have
accumulated in the bottom elbows.
Note on fire heater tubes external surface, the sulfur contained in the fire heater fuel-oil will
progressively lead to sulfides deposits that may lead to stress corrosion cracking. During
long term shut-down, if the heater pilots have to be stopped and the heater casing cooled
down, the external surface of the heater tubes should be sprayed with soda ash solution to
prevent polythionic acid stress corrosion cracking, taking care not to damage the
refractory.
Case of nozzles and drains included in the system which was soaked with the soda ash
solution:
A special attention must be take to the nozzles, drains where soda ash have accumulated.
These parts shall be as far as possible washed out with demineralised water to remove the
soda ash or shall be properly drained out during the plant commissioning to avoid any
soda ash to stay iddle for long duration
Warning
o O2 content of N2 used to prevent corrosion should be less than 500 ppm vol
o During the period where the work is performed, it is necessary to make sure that the
protective layer on the overlay or internals is not destroyed. This would result in
corrosion.
For process equipment that have been cleaned using the high pressure demineralised
water (less than 10 ppm chlorides content), it is much safer to spray again soda solution
on them if they are not immediately put back and kept under N2.
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4.4.7 Neutralization after or before catalyst unloading
If the catalyst is to be dumped the use of soda ash for unloading and purging before
unloading the catalyst is suitable.
But if the catalyst is to be regenerated and reused, wet dumping with soda ash should not
be performed (as some sodium will deposit on the catalyst and will affect the catalyst
properties and performances) and the catalyst has to be dumped under nitrogen, then the
reactor is filled or washed with soda ash.
Regarding the shut down procedure, the soda ash filling-in is performed after hydrogen
stripping (to remove hydrocarbons) and nitrogen introduction (for inerting and cooling
down) as in the dry unloading procedure. There is no need to fill in and purge the reactors
several times for a wet dumping. Nevertheless, the neutralisation will consume some time.
The soda ash solution should be introduced at ambient temperature, the reactors
temperature being less than 50°C.
4.4.8 Special stainless steel
Some special stainless steel as 316 or 321 type (Titanium stabilized) or 347 (Niobium
stabilized) are less susceptible to polythionic induce corrosion, nevertheless the NACE
standard does not say that passivation with soda ash shall not be done. It is therefore
advisable to passivate all equipment and piping which are going to be open to
atmosphere.
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4.5. Catalyst regeneration
4.5.1 Summary
The purpose of this procedure is to describe the main steps to be followed for
hydrotreatement in-situ catalyst regeneration. “Dry” catalyst regeneration is described. As
a general statement, steam should not be used for catalyst regeneration unless agreed by
Axens. Steam may be used for the regeneration of some specific catalysts. Promoted
hydrotreatment catalyst cannot withstand steam regeneration.
Typical criteria to assess the quality of hydrotreatment catalysts regeneration (in-situ and
ex-situ) are:
- Residual Carbon < 0.2 %wt.
- Residual Sulphur < 0.5 %wt.
This procedure is a typical procedure and it is based on Axens design of such
regeneration system. ALL operating values mentioned in this document should be
checked against the design conditions of the concerned equipment and adjusted
accordingly.
This procedure supposes the transfer of the following material:
- ammonia
- caustic
- air
- nitrogen
4.5.2 Prerequisites
-
Fresh feed to the unit is stopped.
-
The reaction section has been cooled down to 50°C and stripped using the
recycle gas compressor.
-
No more liquid hydrocarbons are recovered at the HP separator(s).
-
Unit has been depressurized and repressurised / purged with nitrogen.
-
H2 + HC content in the recycle gas is less than 0.5 % vol.
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4.5.3 Catalyst regeneration : When? – How?
When one of the following situations occurs it is time to regenerate the catalyst:
• Increase of temperature does not give on-specification products or yields are so
greatly reduced that it is no longer possible to operate the unit economically.
•
Maximum temperature in reactors is reached.
•
Pressure drop in reactors does not allow a sufficient recycle gas flowrate.
It is assumed that these situations are a result of coke deposition.
Activity of catalyst is recovered by burning the coke by a mixture of nitrogen and air.
This can be done by in-situ regeneration or off-site after catalyst unloading under inert
atmosphere.
The in-situ regeneration procedure describes the “dry” procedure with use of Nitrogen and
Air. As a general statement, steam should not be used for catalyst regeneration unless
agreed by Axens. Steam may be used for the regeneration of some specific catalysts.
4.5.4 Chemicals reactions
The chemical reactions involved in the catalyst regeneration are:
• Coke combustion
Coke is a mixture of carbon and hydrogen (about 10% weight of hydrogen in the coke).
C + O 2 → CO 2
ΔH = -94.1 kcal/mol of C at 25°C
1
ΔH = -57.8 kcal/mole of H2 at 25°C
H 2 + O 2 → H 2O
2
•
Oxidation of the metallic sulphides on the catalyst
7
O 2 → 3 NiO + 2 SO 2
2
7
MoS 2 + O 2 → MoO 3 + 2 SO 2
2
25
Co 9S8 +
O 2 → 9CoO + 8 SO 2
2
ΔH = -268.7 kcal/mol de Ni3S2
Ni 3S 2 +
ΔH = -340.4 kcal/mol de MoS2
ΔH = -1182 kcal/mol de Co9S8
Of course these reactions depend on the type of catalyst(s) loaded.
•
Oxidation of the sulfur dioxide
1
O 2 → SO 3
2
Neutralization reactions
SO 2 +
•
ΔH = - 23.7 kcal/mole of SO2 at 25°C
SO3 (oxidation of SO2) is neutralized by ammonia to give ammonium sulphate.
SO3 + 2 NH3 + H2O
(NH4)2SO4
CO2 is neutralized by caustic soda.
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CO2 + H2O
H2CO3 + NaOH
NaHCO3 + NaOH
CO2 + Na2CO3 + H2O
H2CO3
NaHCO3 + H2O
Na2CO3 + H2O
2 NaHCO3
SO2 is neutralized by caustic soda.
SO2 + H2O
H2SO3
H2SO3 + NaOH
NaHSO3 + H2O
NaHSO3 + NaOH
Na2SO3 + H2O
To neutralize one mole of CO2 or SO2 one needs two moles of NaOH.
NH3 unreacted with SO3 will react with CO2 to produce ammonium bicarbonate which can
deposit in the air cooler.
4.5.5 Precautions
a) The crystal structure of the catalyst support undergoes changes above 870°C. This
change is very exothermic and is self-sustained.
Therefore once a part of the catalyst bed is above this temperature all the surrounding
catalyst will change its structure if the temperature is not brought immediately down by
quenching. This reaction does not need air to continue.
b) Do not leave the reactors with air inside because a small pocket of unburned coke can
always ignite and provoke a structural change in the catalyst.
c) Do not open both ends of a reactor because air can enter by natural draft. Always inject
nitrogen at the bottom even when unloading the catalyst.
d) After regeneration be careful when pulling a vacuum because air can penetrate into the
reactor and ignite an unburned part of catalyst although this is very unlikely. Watch
temperatures in the reactors when pulling vacuums and have nitrogen supply ready for
immediate use.
e) Do not increase simultaneously the temperature and the oxygen concentration. Oxygen
can build up and suddenly an unburned part of the catalyst can ignite causing a
temperature runaway and no possibility of controlling it. Whenever it is necessary to
increase both oxygen content in the recycle gas and reactor inlet temperature, increase
temperature first, then oxygen.
4.5.6 Operating parameters (temperature and oxygen content)
As a significant amount of catalyst is used in the unit, it is necessary to shorten as much
as possible the time necessary for combustion and heating up of the system. This can be
achieved by operating under pressure.
N2–CO2 mixture is recirculated by the recycle gas compressor while air is injected by the
make-up compressor or directly from the network in case of Naphtha HDT regeneration.
The amount of regeneration gas circulation depends upon the recycle compressor
performance under regeneration conditions. Nitrogen flowrate should be at a minimum of 3
t/h and per m2 of reactor section in order to ensure a proper distribution across the bed
and to minimize the regeneration time.
Reactor temperature is defined as the temperature at the inlet of the reactor. For the
reactors, the temperature is obtained by increasing furnace outlet temperature.
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Oxygen is injected slowly each time to ensure that no temperature runaway can occur. For
a maximum recovery of catalyst activity it is necessary to keep the temperature to the level
indicated. If the temperature runaway begins, cut off the air introduction immediately and
quench with quench lines (USE OF STEAM IS ABSOLUTELY FORBIDDEN FOR
PROMOTED CATALYST – REFER TO AXENS IF STEAM CAN BE USED).
4.5.7 Regeneration arrangements and facilities
Typically, for catalyst regeneration, the following modification to the plant should be done:
Equipment to be by-passed
Normally, during regeneration, the following equipment items are by-passed by the
regeneration gas as it circulates:
• Each feed / effluent exchanger (tube and shell sides).
•
Stripper feed / reactor effluent exchanger.
•
HP amine absorber if any.
New discharge location of PSV
Following pressure safety valves are connected to the atmosphere:
• Reaction section safety valve.
•
Make-up compressor safety valves, if any.
•
Recycle gas compressor safety valve (if present).
Purge of the system
• Normal operation purge line to flare is blinded.
•
Regeneration purge line is connected to the atmosphere.
Note: In order to get reliable control of the heater outlet temperature the heat recovered by
the feed / effluent exchanger may be reduced by acting on a by-pass on the cold side.
As a consequence of oxidation reactions, some corrosive materials are formed (mainly
SO2 and traces of SO3) :
• SO3 is neutralized by ammonia injected at the outlet of the last reactor.
•
SO2 is neutralized by caustic injection at the outlet of the effluent air cooler or
trim cooler, if any.
•
Washing water is injected upstream the effluent air cooler in order to dissolve
salts formed by SO3 and SO2 neutralization.
•
Part of the CO2 contained in the regeneration gas is also neutralized by the
caustic soda.
From the HP separator drum two streams are purged:
• N2, CO2 and H2O (purged from HP amine absorber bleed).
•
Spent caustic.
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4.5.8 Reaction section working out
Preparation of the unit:
• After cooling down the reactors, depressurize the unit to flare.
•
Isolate the reaction section from the other sections.
•
Purge the reaction section by pressurization / depressurization with nitrogen or if
possible by vacuum to economize nitrogen.
When H2 + HC content in nitrogen is less than 0.5 % volume, proceed to next step.
• Commission the regeneration circuit.
4.5.9 Regeneration procedure outline
•
Pressure up the reaction section with nitrogen up to nitrogen header pressure.
•
Start the make-up gas compressor under nitrogen, if any, to increase the
reaction section pressure up to an operating pressure suitable for the recycle
compressor.
•
Start the recycle compressor.
•
Sample the circulating gas to check that it contains less than 0.5% vol. of H2 +
HC.
•
Then fire the heater and increase the temperature at the reactor inlet up to
250°C at a rate of 15°C/hour. Do not exceed a ΔT of 30°C (to be confirmed by
reactor manufacturer) between inlet of the reactor and any part of the catalytic
beds during all the heating phase.
•
Keep these conditions until the temperature of the whole catalytic beds reaches
250°C.
•
Start washing water pump to fill the HP separator drum until level reaches 60%.
•
Circulate this water for about 1 hour so as to ensure the proper cleaning of
effluent air cooler.
•
Ammonia and caustic soda injections are commissioned.
•
Start the caustic recirculation pump and the caustic soda make-up pump and
adjust the injection rate of make-up such that the total concentration of NaOH
circulation to HP separator drum is between 3 to 6% wt. Take sample after
regular and short intervals until the desired concentration is achieved. Check the
pH also of the circulating solution. It should be about 14.
•
Start the ammonia injection pump.
•
Start injecting progressively air in the fluid circulated to the reactor. Make steps
of 0.1% volume max and do not exceed 0.5% vol. oxygen content at the reactor
inlet.
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•
As soon as air is injected in the system, acid gas (traces of SO3) will be formed
and ammonia must be injected in the reactor effluent to neutralize acid gas.
Watch the temperature rise in the reactor. If no ΔT is observed (note that ΔT is
calculated between inlet of reactor and the higher temperature in any part of the
reactor), increase the reactor inlet temperature by step of 25°C at a rate of
25°C/h. Always increase the reactor temperature first, then the O2 concentration,
until the ΔT reaches 55°C. However do not exceed 345°C reactor inlet
temperature and 0.5% vol. oxygen content at the reactor inlet.
•
Check that outlet temperature of the last feed / effluent exchanger is always
above 180°C to avoid salts deposit.
•
Oxidation of the metal sulphides of the catalyst and of coke particles will form
SO2 and CO2 gases. To counteract these gases, caustic scrubbing of the
effluent gas is achieved on a recirculation through basis using a caustic solution
(NaOH) at 3 to 6 % wt. concentration in the liquid phase before the neutralization
reactions take place. The caustic make-up injection rate must be adjusted to
obtain pH control 7.5 to 8.0 on spent caustic.
•
Check that the temperature at HP separator inlet is below 55°C to avoid caustic
embrittlement. Check recycle gas for SO2 to be sure that complete removal is
achieved.
•
Keep the ΔT at 55 °C (for a O2 content of 0.5% vol.) until an oxygen
breakthrough occurs through the reactor.
•
Then reduce the flowrate of injected air, in order to keep the oxygen content at
reactor inlet at 0.3 % vol.
•
Now, raise the temperature at reactor inlet by 10°C at 25°C/h, and wait until
there is no longer any ΔT between inlet and any part of the catalytic beds.
•
Repeat the above step until the reactor inlet temperature is 345°C (if not yet
reached), and ΔT=0.
•
Now increase the reactor inlet temperature up to 400°C (25°C/h). When this
figure is reached, start increasing the oxygen content , until one of the following
events occurs :
− ΔT = 30°C
− O2 content = 0.5 % vol.
•
Keep the ΔT at 30°C maximum by increasing the oxygen flowrate if necessary.
When the oxygen concentration at reactor inlet reaches 0.5 % volume, watch the
ΔT gradually decrease until it reaches zero. Note that an oxygen breakthrough
could occur through the reactor, in which case the oxygen injection must be
adjusted so as to have 0.5 % volume max. at reactor inlet at any time
•
When the ΔT reaches zero, keep oxygen concentration at 0.3% vol., and
gradually increase the reactor inlet temperature up to 425 °C at 25°C/h. When
this temperature is reached, progressively raise oxygen concentration in the
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recycle gas at reactor inlet, until ΔT = 30°C or O2 content = 0.5% vol., whichever
comes first. As the ΔT decreases, gradually increase the O2 concentration up to
0.5 % (if not yet reached); when it is 0.5 %, watch the ΔT progressive reduction
until it reaches zero. Pay attention to keeping oxygen content lower than or
equal to 0.5 % volume, especially after O2 breakthrough.
•
When the ΔT is zero, progressively increase O2 content at reactor inlet up to 1 %
volume; stop increasing it if the ΔT becomes higher than 30 °C. When it reaches
1 % volume, hold these conditions until the ΔT becomes zero or during 8 hours
(whichever is the longest).
Regeneration is considered as finished if all the following three conditions are met:
− Oxygen is no longer consumed: No more air injection to maintain oxygen
concentration in the circuit.
− CO2 is not produced any more.
− There is no longer a temperature rise across any catalyst bed.
•
Make sure that air injection is stopped.
•
Keep 425°C at the inlet of the reactor.
•
Switch the make-up compressor suction to nitrogen (that will be used to maintain
reactor pressure and to purge oxygen from the loop).
•
Keep caustic soda, ammonia and washing water injections as long as SO2 is
detected in reactor effluent gas.
•
Then shut off ammonia and caustic injections.
•
Keep washing water injection to flush the caustic soda from the circuit.
•
When pH of water drained is same as pH of fresh water, stop water injection.
•
Keep reactor inlet temperature at 425°C to dry the circulation loop and drain
water at all low cold points. This period should be carried-out in about 4 hours
and should not exceed 6 hours.
•
Then start to reducing the reactor inlet temperature at a rate of 25°C/h to 70°C.
Do not exceed a ΔT of 30°C (to be confirmed by reactor manufacturer) between
inlet of the reactor and any part of the catalytic beds during all the cooling phase.
If needed quench lines can be used to homogenize temperatures in the reactor.
The cooling down rate should be confirmed by the reactor manufacturer.
•
Stop the recycle gas compressor.
•
Depressurize the circuit, and keep under slight nitrogen pressure.
•
This status is a stand-by position for the unit. It also corresponds to the normal
catalyst unloading conditions.
•
If the unit has to be restarted, the normal start-up procedure applies as for a new
catalyst with a sulfiding step.
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The recycle gas compressor is used to circulate Nitrogen and cool down the reactors.
This operation will take a long time using the normal circuit due to the recycle gas
compressor discharge temperature and the exchangers. A solution to speed up this
operation is to create a temporary by-pass of the exchangers, straight from recycle gas
compressor to the heater inlet.
A more realistic alternative is to mobilize a Special Contractor to cool down the reactors
between 100°C and 50°C by a sub-cooled Nitrogen flow.
4.5.10 Critical points and emergencies actions
Critical points:
• Make sure that all blinds are in the proper position, including isolation from flare
and all line up is correct.
•
During heating phase, make sure that quench valves are closed.
•
Watch carefully pH of spent caustic: too low pH will lead to acidic corrosion and
too high pH will eventually lead to caustic corrosion and higher caustic
consumption.
Emergency actions:
• In case of ammonia is not supplied, stop air injection until NH3 supply is
available.
•
In case of fresh caustic soda is not supplied, operate until pH reaches 7.5. At
this time, stop air injection. If fresh caustic injection is not resumed within 1 hour,
stop NH3 supply until fresh caustic supply is available. Stop the heater and cool
down the reaction section with the recycle gas compressor.
•
In case of washing water is not supplied, operate until the total dissolved salts
content reaches 10 % wt., at this time stop air injection. If water injection is not
resumed within 1 hour, stop caustic supply, stop NH3 supply until water is
available. Stop the heater and cool down the reaction section with the recycle
gas compressor.
•
In case of recycle gas compressor shutdown, stop air supply, switch make-up
gas compressor to nitrogen only, stop the heater firing (should be done
automatically through ESD actuation ), keep caustic soda circulation and
ammonia injection during 15 minutes, washing water injection during 30 minutes.
•
In case of continuously increasing pressure drop between inlet of effluent aircooler and inlet of separator, stop air injection, increase washing water flowrate.
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5.
OPERATION OF THE UNIT
5.1. Reactor
The operating parameters described in Chapter 2. have key impacts on the HDT process :
thermodynamics, kinetics and catalyst behaviour. Their individual role and impact on the
process has been explained. Practically when operating a HDT unit, these parameters
must be adjusted and optimized all together to achieve the required performances and
maximize the catalyst cycle length.
5.1.1 Temperatures
The main point is the reactor catalytic beds temperatures. They should be adjusted to get
the product specifications in accordance with the feed analysis and with the catalyst
activity. They will be increased progressively during the cycle.
The reactor inlet will be controlled by the outlet temperature of reaction heater and the
other beds inlet temperatures by the quenches gas flowrates.
The normal rule is to adjust these inlet temperatures to get both:
ƒ The same temperatures at the outlet of each catalytic bed.
ƒ The WABT for the requested desulfurization rate.
The WABT definition is given in chapter 5.6.2.
5.1.2 Hydrogen Partial Pressure
The pressure is kept constant at the HP separator by controlling the spillback around the
make-up gas compressor or by HP purge.
The hydrogen partial pressure is fixed by the hydrogen content of the recycle gas (H2 %
vol), the recycle flowrate, the total pressure of the unit, the severity of the hydrotreatment,
the temperature and the feed characteristics. The hydrogen content of the recycle gas is
used to estimate this partial pressure.
It is estimated at reactor outlet by:
ppH2 = K x Pat Rx outlet x H2 % wol of recycle gaz
(P in bar or kg/cm2 absolute)
The value of K is in the range of 0.85 to 0.90 according to H2 make-up gas purity, H2
chemical consumption, quenches and recycle rates, feedstock quality... It will be correctly
correlated after some mini test runs.
The H 2 partial pressure given in the design data is the minimum value required
for the desulfurization rate and so is determined at reactor outlet where there is the
minimum content into H2 in the reactor.
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5.1.3 Recycle gas ratio
The recycle gas has three important functions:
To keep sufficient pressure of hydrogen throughout the catalytic bed in order to limit coke
deposits by hydrogenation of the cracked material.
To control the temperature rise in each bed by using part of the recycle gas as quench.
This allows an optimum use of the catalyst and increases the cycle length.
To disperse the liquid hydrocarbon through the catalyst bed.
The recycle gas ratio is calculated by:
o At reactor inlet (usually)
H 2 Pure hydrogen Sm 3 / h in recycle
=
HC
Feed flow rate m 3 at 15°C / h
(
o At reactor outlet
(
(
)
(
)
)
H 2 Pure hydrogen Sm 3 / h in recycle & quenches
=
HC
Feed flow rate m 3 at 15°C / h
)
Periodically, this ratio should be checked and adjusted if necessary.
5.1.4 Liquid Hourly Space Velocity (LHSV)
The unit has been defined for the given Space Velocity, (feed flowrate). It defines the
average contact time between feed and catalyst to perform the reactions. When the
feed flowrate increases, it is necessary to increase the reaction temperature to
compensate the reduction of feed residence time in the reactor.
In many cases, the feed rate of a unit is actually not a true variable as it is set either by
feedstoocks availability, by storage capacities and flexibilities or by the unit hydraulic
limitations. Anyway it is normally maximized for economical reason. However there are two
main cases in which the feed rate may be decreased:
- improve the product quality (lower sulphur in the diesel for instance)
- or enhance the conversion of the feed into lighter products ; this is then done while
keeping the WABT at a reasonable level
5.1.5 H2S content of the recycle gas
The H2S content of the recycle gas is controlled by the by-pass of the amine absorber if
any. This H2S content has to be adjusted between 0.1 % vol to 0.2 % vol to maximise the
catalyst activity. (Generally, it does not exceed 3% due to corrosion problems above this
value in the compressor).
With low sulfur content naphtha, during normal operation, if needed, some DMDS will be
injected in the feed.
Note that some design, allow a few ppm of H2S in the recycle gas only.
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5.2. Feed quality
The feed quality varies very often and the unit has to cope with these variations due to
mainly three factors:
5.2.1 Distillation range
For any distillates, the sulfur compounds are easily removed in the light fraction, while they
are more refractory in the heavier fraction.
The severity (in terms of reaction temperature) is increased in the case of high final boiling
point of the feed.
5.2.2 Impurities in the feed
The catalyst activity can be reduced, either temporarily or permanently by poisons
contained in the feed. These impurities are mainly, metals and metalloids coming from
added components in previous units. For example, Silicon is found in gasoils ex-coker or
visbreaker unit.
Silicon, arsenic and metals are trapped on the catalyst. The absorption occurs on the
upper layers of the catalytic beds and progressively extends downwards. For the catalyst
layers with such impurities, the activity is drastically reduced and an increase of reaction
temperature will compensate this deactivation. In case of high metal content in the feed, it
is advised to implement a specific guard bed at top of catalyst bed in order to trap these
metals and protect downstream catalyst.
5.2.3 Conversion distillates in the feed
The conversion distillates (from coker, visbreaker and Fluid Catalytic Cracking units)
contain mainly aromatics and heterocycles compounds. The compounds are difficult to
hydrotreat, due to the mechanism of the reactions: Aromatic cycle saturation and C-S
bonds to break. It consumes more hydrogen and so it leads to a high heat of reaction.
The unit has been designed for a given conversion distillates content in the feed. So
when this content increases compared to the design one:
The reaction temperature has to be increased to achieve the same specification, but, at
the same time, the temperature rises in each catalyst bed have to be carefully controlled to
avoid premature coking. The catalyst beds inlet temperatures have to be reduced to
maintain the WABT at its correct level.
5.3. Wash water injection rate
The purpose of this wash water is to prevent any plugging by ammonium salts. The
recommended water flow must be controlled to meet whichever is the most severe
situation of the following:
ƒ the water wash flow rate must be at least 5 wt % of the feed flow to ensure efficient
dissolution of ammonium salts.
ƒ the concentration of ammonium salts in the high pressure separator water must be
a maximum of 4 wt % for solubility and corrosion issues
ƒ At least 20 to 30% of the injected water should remain as “liquid water”.
It is necessary to check the injection rate and the aircooler efficiency. Care should be
taken to run the aircoolers in a symmetrical manner to prevent any erosion-corrosion.
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5.4. Stripper
This column removes all the H2S and light ends (until wild naphtha) from the hydrotreated
product. The operating parameters are:
ƒ The inlet temperature,
ƒ The reflux ratio,
ƒ The stripping steam ratio.
Axens recommends 20 kg of steam per ton of stripper feed. Attention should be paid to the
overhead condenser, not to freeze mainly in winter.
5.5. Dryer
This vacuum column if any removes the residual solubilised water and some very light
ends from the hydrotreated product. The operating parameters are
ƒ The inlet temperature,
ƒ The vacuum level,
ƒ The light ends are recycled to the stripper feed.
5.6. Operation guideline
The question is: What are the parameters on which we can play to achieve an objective of
desulfurization when we know the feedstock and the characteristics of the unit? Axens has
correlation to determine the operating conditions versus feedstock characteristics and
catalyst ageing, around the design point of the unit.
This needs the values of six parameters that characterise the system: FEED-UNITCATALYST
FEED
UNIT
CATALYST
TMP
Disti-Conv
WABT
ppH2
LHSV
AGE
Feedstock distillation curve
Conversion distillates content in the feed
Average reactor temperature
H2 partial pressure
Space velocity
Effective cycle duration of catalyst
and to enter in the correlation : HDS = F(TMP, Disti-Conv, WABT, ppH2, LHSV, AGE)
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5.6.1 Definitions
5.6.1.1.Feedstock characteristics
TMP
From the ASTM D86 or D1160 distillation curve:
Temperature @ 5%vol T5
Temperature @ 50%vol T50
Temperature @ 95%vol T95
TMP= (T5+2 x T50+4 x T95)/7
If T5 et T95 are not available:
Temperature @ 10%vol Tl0
Temperature @ 50%vol T50
Temperature @ 90%vol T90
TMP= (T10+2 x T50+5 x T90)/8
Disti-Conv
It is, in weight %, the amount of conversion distillatel(s) in the feedstock.
5.6.2 Unit Characterisation
ƒ
WABT: Weight Average Bed Temperature (°C)
WABT= SUM (Fi x T(ave. , i )) for i =1 to n, where n is the number of catalytic beds
o T (ave. , i ) = average Temperature of bed i.
o Fi = weight fraction of catalyst in bed i.
ƒ
ppH2: H2 partial pressure (kg/cm2)
ƒ
LHSV: Space velocity (h-1)
ƒ
Feed flowrate (m3/h @ 15°C)
ƒ
CATALYST AGEING: The catalyst deactivates during the cycle, and it is measured in
term of reaction temperature increase to achieve the same performance. The
catalyst ageing is defined either by the effective cycle duration or by the ratio of
feedstock treated (volume or weight) per kilogram of catalyst. The deactivation will be
estimated correctly after some mini test runs.
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6.
SHUT-DOWN OF THE UNIT
6.1. Normal shut-down
The following guidelines are for a complete shut-down required for catalyst regeneration or
replacement, inspection, main equipment maintenance. It is assumed that this is a
scheduled shut-down.
The unit shut-down will be done in accordance with the equipment supplier’s
recommendations with special care taken for the reactor.
6.1.1 Decrease feed throughput to turndown flowrate (generally 50% 60%)
ƒ
ƒ
ƒ
ƒ
ƒ
ƒ
The feed rate and temperature are decreased.
Switch the products to the slop tanks.
Reduce the reactors temperatures stepwise (25-30°C/h) down to 40°C below
previous operating temperature..
Check that the temperature differentials disappear in the reactor.
Bypass of put out of service the amine pumps in order to build-up H2S
concentration in the recycle gas to prevent any catalyst reduction during this
transitory phase. HP purge should also be closed or at least minimized to maintain
a reasonable H2S concentration.
Wash water can be stopped at this stage. Nevertheless, if it observed that the DP
across the HP aircooler is increasing, wash water injection should be resumed.
6.1.2 Shut-off the liquid fresh feed to the unit
All the conversion gasoils (LCO, HCGO…) are removed first from the unit to limit the
unsaturated material on the catalyst. For unit processing VGO and heavier feedstock, lineup SR gasoil to the unit.
For both cases (Diesel or Residue hydrotreaters) keep SR gasoil during 6 hours to wash
completely the unit. If the catalyst is to be reused, this action is know to be beneficial to the
activity of the catalyst since the straight run gasoil will elute some of polymer laying on the
catalyst.
The recycle gas flowrate is kept at maximum and the gasoil is routed straight to the
stripper and back to feed surge drum (as per start-up circulation).
The reaction heater should be looked at closely not to overheat the coil or to put off the
burners.
Continue to decrease reactor temperature at 25°C/h. When reactor inlet temperature
reaches about 200°C, stop liquid feed circulation and maintain recycle gas flow at
maximum. Usually an exotherm is observed as soon as the feed is cut. This exotherm is
due to the sudden change of the feed / effluent exchanger heat transfer coefficient and to
some extent to the control of the heater outlet temperature.
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As the feed is stopped, the overall ΔP of the system will be reduced drastically. In case of
centrifugal recycle gas compressor, it maybe necessary to reduce the speed of the
motor/turbine to maintain the amine contactor ΔP with the mechanical design range.
Depending upon the heat integration of the plant, the stripper inlet temperature should
decrease. Then cut the stripping steam when stripper bottom temperature is at 200°C or
top temperature below water dew point at operating pressure.
6.1.3 Hydrogen stripping
The reactor temperatures are adjusted to strip the maximum hydrocarbons from the
catalyst:
ƒ to 350°C if catalyst is to be unloaded for regeneration or for disposal
ƒ to 250 °C if unit is to be further re-started without catalyst unloading nor
regeneration
The recycle gas flowrate is kept at maximum. The reaction pressure is kept at operating
level by the make-up gas compressor. The water pumps are running to remove any
deposit from the air cooler.
These conditions are maintained 24 hours.
If no intervention if foreseen on the reaction section, it is possible to keep the recycle gas
compressor in service. In order to prevent catalyst reduction, it is necessary to cool down
the reaction section to 100 – 150°C (depending upon the minimum pressurization
temperature required for the HP section vessels).
6.1.4 Temperature and pressure down
The reaction section is slowly cooled to 200°C and depressurized. Control the cooling rate
so it complies with the reactor manufacturer recommendations to allow for proper H2
desorption from the reactor wall.
The hydrogen is eliminated by vacuum from the reaction section after isolating the recycle
compressor and instrument.
The reactor is put under nitrogen as well as the recycle gas compressor.
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6.1.5 Stripper
At the end of the stripping phase, no more hydrocarbons arrives to the separator, the
stripper inlet is cooled down, the reflux is kept as long as any liquid is present in the reflux
drum.
When the whole loop is cold, the circulation is stopped keeping the vessels under positive
pressure by fuel gas injection (or nitrogen).
6.1.6 Steam-out
To allow the visit of the vessels and different equipment, the separation section (from the
low pressure separator to the stripper) will be steamed out before putting them under air.
The unit should be completely blinded at this stage and the blind list checked to be sure
none is missing.
The reaction section will not be steamed out; the hydrocarbons are removed during the
stripping step and by vacuum before nitrogen is admitted.
For visit and maintenance work of specific equipment of this reaction section, it should be
isolated by blinds and steamed or washed if necessary before air is introduced.
Remarks:
Sometimes, the unit has to be temporary shut-down without catalysts coke burning or
unloading. In this case, the hydrogen stripping is not required and the unit may be kept
under hydrogen and hydrocarbon ready for the restart.
Different points are to be kept in mind:
ƒ Not circulate H2 without H2S on the reactor above 200°C, not to reduce the catalyst.
ƒ If temperature of the reactor decreases below 150°C, the pressure should be down
to < 50 bars (this point has to be checked with the reactor supplier).
ƒ If the restart date is not known, it is better to decrease pressure and to put the
reactor under light positive nitrogen pressure (safe position).
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6.2. Emergency shut-down
In any event, the operating staff will try to follow the normal shut-down procedure as much
as possible. An emergency shut-down is an unusual way to shut-down the unit and is
always risky.
To prevent this kind of situations, spare equipment must be routinely checked and any
minor problem must be fixed and solved before it leads to an emergency.
Different cases of emergency shut-downs are considered:
6.2.1 Fire in the unit
In case of fire in the unit, the “Emergency shut-down push button” should be actuated. It
should:
ƒ Stop feed pump and close the FV on the discharge line.
ƒ Stop reaction heater.
ƒ Stop hydrogen make-up compressor.
ƒ Stop recycle gas compressor.
ƒ Depressurise the reaction section by opening the valve.
6.2.2 Recycle gas compressor failure
In this case, the heat of reaction cannot be eliminated and a temperature upset may occur
with catalyst damage. This should actuate an emergency shut-down by low recycle gas
flow without depressurising:
ƒ Stop reaction heater.
ƒ Stop hydrogen make-up compressor.
ƒ Stop feed pump and close the FV on the discharge line.
ƒ Stop the washing water pumps
The action is to try to restart as quickly as possible the recycle gas and to look closely to
the reactor temperatures. If this restart is not possible or if any reactor temperature goes
up to 400°C, the depressurisation valve must be activated by the corresponding hand
switch..
6.2.3 Make-up gas failure
The reaction pressure will decreased rapidly and if no action is done, the catalyst will coke
due to hydrogen shortage to saturate the cracked material. The feed rate has to be
decreased rapidly to 60% and temperature decrease.
If at 80 % of the normal operating pressure, the hydrogen is not restored to the reaction
the feed has to be cut by stopping the feed pump until the make-up gas is back or the
normal shutdown procedure should continue.
6.2.4 Feed failure
The loss of feed will affect the reaction heater. It is necessary to keep the reactor inlet
temperature under control and try to restore feed to the unit. If not possible the normal
shut-down procedure should apply.
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6.2.5 Utility failure
6.2.5.1.Steam failure
In case of turbine driven compressors (Recycle Gas and/or Make-up), steam failure will
result in the loss of this (these) machine. Refer to the relevant paragraph for the actions to
be taken.
The stripping steam is not available to remove H2S and light ends from the gasoil, it will be
off-spec and should be routed to off-spec tank or back to the feed surge drum (lining-up of
a close loop circulation).
The others steam consumers would be also affected, a complete list should be done with
the different actions.
6.2.5.2.Instrument air failure
The valves take their fail position: FC (fail closed), or FO (fail open). They are determined
to put the unit in a safe position:
ƒ Feed stopped.
ƒ Make-up gas stopped.
ƒ Heater switched-off.
ƒ Recycle gas kept running.
The depressurisation valve stays close due to the air reserve.
6.2.5.3.Electricity failure
The recycle gas compressor, electrically driven causes an emergency shut-down.
After power recovery, the priority restart should be:
ƒ The recycle gas compressor.
ƒ The reactor effluent air-cooler.
ƒ The stripper overhead condenser.
ƒ The stripper reflux pump.
6.2.5.4.Cooling water failure
The loss of the cooling water may lead to a shut-down of the unit due to lack of
refrigeration on the machines: recycle gas compressor, make-up gas compressor, feed
pump…
Note: The recycle compressor is kept running if the compressor has an air cooled
condenser and has a specific cooling water circuit for oil coolers etc...
Loss of cooling water may also result in the sending of hot product to storage. In that case,
fresh feed should be stopped and unit put under close loop circulation.
6.2.5.5.Heater failure
The shut-down of the heater (fuel failure...) requires an immediate stop of the feed pump.
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6.2.6 Washing water failure
Rev 4
The lack of water to the hot separator vapor cooler may lead to a plugging of the tubes by
deposition of ammonium salts. The time to reach the plugging is function of the nitrogen
content of the feed.
Furthermore, ammonia will no longer be removed from the hot separator vapor and will
begin to build-up in the recycle gas. As the concentration increases the catalyst activity will
decrease and its performances as well.
The following procedure must be applied:
1. Take action within 30 minutes maximum to start the spare washing water pump within a
short delay and restore the previous injection flow rate.
2. Monitor carefully the pressure indications across the reaction section to detect an
unexpected pressure drop build up in the separation section. The pressure difference
between the suction and the discharge of the recycle compressor is a good indicator. If
an abnormal increase of the pressure drop is observed, go directly to point 7.
Adjust the operation of the REAC to keep the normal operating temperature of the
separator drum in order to avoid an excessive temperature of the recycle gas routed to
the amine scrubber or to the suction of the recycle compressor.
3. If the spare pump cannot be put in operation within: for VGO (MHC-HCK) the
aforementioned time (30 minutes) / for Diesel 2 hours:
3.1. (For All) Reduce the unit throughput to the turndown capacity.
3.2. (For MHC & Diesel) At the same time, decrease the reaction section temperatures
and the make-up hydrogen rate accordingly with the lower throughput.
3.2. (For HCK) At the same time, decrease the reaction section temperatures and the
make-up hydrogen rate accordingly with the lower throughput : the hydrocracking
catalyst temperature must be decreased by at least 10°C to maintain a constant
level of conversion at low throughput and avoid high exotherm.
3.3. (For MHC & Diesel only) If possible, decrease operation severity further to
minimize denitrogenation reactions and thus the formation of ammonium salts.
3.4. Favor the processing of low nitrogen feed stocks: for VGO (MHC-HCK) lower the
feed EBP / for Diesel HDT: cut off cracked feedstocks).
4. Maintain operating conditions like this until washing water injection becomes available
again.
5. Route the products to their respective off-spec tanks if necessary.
6. If water washing cannot be restored within: for VGO (MHC-HCK) 4 hours, for Diesel 12
hours:
MHC: switch feed from VGO to light atmospheric straight un gasoil and decrease
reactor temperatures down to 300°C. Open the recycle gas amine absorber bypass at
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100%. Once the switch to light gasoil feed is completed put the unit in closed loop
recirculation and decrease the reactor temperatures to 200°C. The unit is set in a safe
stand-by mode, ready to restart when the washing water problem is fixed;
HCK: decrease the reactors temperatures as follows; Hydrocracking catalyst beds at
280°C, Hydrorefining catalyst beds temperatures are maximized by using quench at
maximum flow rate. Then switch feed from VGO to light atmospheric straight un gasoil.
Open the recycle gas amine absorber bypass at 100%. Once the switch to light gasoil
feed is completed put the unit in closed loop recirculation and decrease the reactor
temperatures to 200°C. The unit is set in a safe stand-by mode, ready to restart when
the washing water problem is fixed;
Diesel: put the unit in closed loop recirculation and decrease the reactor temperatures
to 200°C. The unit is set in a safe stand-by mode, ready to restart when the washing
water problem is fixed;
7. If an abnormal increase of the pressure drop can be observed, shut the unit down:
7.1. Cut off the feed to the reaction section.
7.2. Decrease the reaction section heater firing rate (stop the main burners).
7.3. Open the recycle gas amine absorber bypass at 100%.
7.4. Decrease the catalyst beds temperatures down to 180°C with recycle gas.
7.5. Then shut down the reaction section heater, stop the recycle compressor and
keep the unit in stand-by Decrease the catalyst beds temperatures down to 180°C
with recycle gas.
7.6. If the reactor skin temperatures drop close to or below the Minimum
Pressurization Temperature, decrease the reaction section pressure according to
the reactor T / P chart by opening the HP purge valve.
6.2.7 Start-up after an emergency shutdown
The emergency shut-down normally puts the unit in a safe position by acting different
valves and machines. These different actions should be checked. After normal conditions
recovered and the corrective actions completed, the unit is ready to restart. It is necessary
to check the status of the unit (homogeneous temperature on the reactor, gasoil
circulation, operating pressure, quality of the recycle gas…) before proceeding with the
start-up.
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HR SERIES
7.
SAFETY AND HEALTH RECOMMENDATIONS
7.1. Plant safety features
7.1.1 General
Safety is the first consideration for all operations in the plant. Procedures, practices, and
rules have been established as guides to insure a safe working environment. Safety also
plays a major role in the efficient operation of the refinery facilities.
This section is prepared to reemphasize the plant safety features incorporated in the unit
and equipment design.
7.1.2 Emergency shut-down
These different shut-downs are completed by different trips to protect the main equipment
and to prevent any misoperation. Alarms always precede these trips, they allow operators
to have corrective actions before the automatic shut-down.
These trips are listed in the table below:
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Safety device
Feed surge drum LSLL
LSHH
Hydrogen make- LSHH
up
Compressors
Reaction Heater PSHH/TSHH
Reactors
TSHH
TSHH
Heater
HP separator
PALL
LSLL
LSLL
HS
LP separator
FSLL
Washing
water LSLL
drum
Amine absorber
LSLL
Recycle
LSHH
compressor
Knock-out drum
Recycle gas low FSLL
flow
Stripper
FSS
Location
Low low level HC
High high level HC
On knock-out drum
Action
Stop feed pump and
close UV on discharge
line.
Close shut off valve on
the feed to surge drum
Stop feed pump and
compressor.
High high P and T in
cheminey
High high process T
High high temperature
in each thermowell and
at
reactor
outlet.
(Voting system 2out 3)
Low pressure fuel
Low low level HC
Shut-down the heater
Low low flow to feed
Stop the recycle gas
compressor.
General shut-down of the
unit
Shut-down the distillation
feed heater
Shut-down the heater
Stop feed pump and
reaction heater.
Shutdown the heater.
Close the UV between HP
and LP separator.
Low low level water
Close the UV on the water
draw-off.
Fast
and
slow Open UV and HCV to
depressurisation
blowdown
Low low HC flow
Start-up of spare pump
Low low level water
Stop water washing pump
Close UV on water
injection
Low low level of amine Close the UV on the rich
amine draw-off.
High high level
Stop the recycle gas
Condensate
compressor.
Low low flow to heater
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7.1.3 Overpressure protection
Over pressuring of equipment occurs in many ways. The basic reason of overpressure is
unbalanced in heat and material flow in one or more equipment. Pressure relief valves
have been installed after careful evaluation of conceivable over pressuring sources.
7.1.4 Safety shower and eyes wash
Safety shower and eye wash stations are located in the chemical handling areas.
7.1.5 Operational safety
The safety rules and instructions also emphasise safety hazards. Safe attitudes, practices
and habits are necessary for safe and efficient operation of the unit.
7.1.6 High pressure
On high pressure line, extreme caution must be taken when opening any sample or bleed
valve.
Improperly lining up valves and interconnecting lines may result in exceeding pressure
limits on vessels, exchangers, valves and lines.
With improper operation, the pressure limits on vessels, exchangers, valves, and lines
may be exceeded by thermal expansion of a liquid.
7.1.7 Effluent line upstream effluent air-cooler after wash water
injection
During any scheduled shut-down of the unit for inspection, the thickness of this line will be
checked to insure a safe further operation of the unit.
7.2. Reactor protection
Manufacturer of reactor will give following information necessary for the operation:
A pressure versus temperature diagram indicating where it is possible to operate the
reactors with gas containing hydrogen and H2S:
ƒ Rate of temperature increases and decreases.
ƒ Rate for pressuring and depressuring the reactor.
ƒ Risk of polythionic acids corrosion.
ƒ Maximum allowable difference between the process temperature inside the reactor
and the skin temperature.
ƒ Location and size of the defects noted on the reactor after fabrication in order to
monitor the changes in these defects over time.
ƒ Location, size and material of the metallurgical probes to install in the reactor. The
type of tests to perform on these probes will also be indicated.
ƒ Necessity of degassing the reactors wall.
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7.3. Personnel protection
A list of health and safety data sheets including the catalyst plus some of the chemicals
involved in the hydrotreatment process is given below.
Regarding chemicals, the list mentions those which are specific to the Axens technology.
Consequently, health and safety data related to well known hydrocarbons are not being
considered here.
The Material Safety Data Sheet of the catalyst is provided by Axens.
Regarding the other material safety data, the Refiner is advised to request the last issue of
the following document: Regulated Hazardous Substances published by “The
Occupational Safety and Health Organisation (OSHA) US Department of Labor”.
The refinery personnel have to be aware of the different materials involved in the process:
dangerous or toxic materials. Any chemical used in the plant should have its toxicity
recorded and the first aid labelled.
7.3.1 Hydrogen
Hydrogen is a flammable gas which in concentrations from 4.1 to 74% volume in air, is
explosive.
Care must be taken to purge the air out of the unit as required before start-up and to purge
hydrogen out of the unit for shut-down.
Tightness tests are to be made before all start-up on every vessel containing or likely to
contain hydrogen.
Each operator must continually inspect equipment and flanges for leaks.
All leaks require immediate action.
7.3.2 Hydrogen Sulfide H2S
Physical properties:
• Physical state
• Colour
:
• Boiling point:
• Melting point
• Molecular weight
• Specific gravity/air
:
Gas
Colourless
- 61.8°C
:
- 82.9°C
:
34.08
:
1.189
Chemical and hazardous properties:
Hydrogen sulfide is one of the more dangerous materials in our industry. In its handling,
two types of hazards must be taken into account, its extreme toxicity and its explosive
nature when mixed with air or sulfur dioxide.
The maximum safe concentration of hydrogen sulfide is about 13 ppm. Although, at first
this concentration can be readily recognised by its odour, hydrogen sulfide may partially
paralyse the olfactory nerves to the point at which the presence of the gas is no longer
sensed.
Therefore, though the odour of the gas is strongly unpleasant, it is neither a reliable
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safeguard nor a warning against its poisonous effects. Hydrogen sulfide in its toxic action,
attacks nerve centres. Early symptoms of poisoning are slight headache, burning eyes,
and clouded vision. A concentration of 100 ppm of hydrogen sulfide in air causes
coughing, irritation and loss of smell after 2-15 minutes and drowsiness after 15-30
minutes.
A concentration of 1000 ppm of hydrogen sulfide in air can make one unconscious at once
with early cessation of respiration and death in a few minutes.
Hydrogen sulfide is a combustible material and, when mixed with air or sulfur dioxide, may
be explosive. It is essential, therefore, to avoid such mixtures in the processing of
hydrogen sulfide. The explosive range of hydrogen sulfide in air is from 4.5 – 45%. The
ignition temperature of such mixtures is around 250°C.
Some precautions against poisoning to be taken in working with hydrogen sulfide are:
ƒ Closed in areas should be well ventilated preferably with forced draft.
ƒ Equipment containing hydrogen sulfide should be tightly sealed. Any leaks should
be repaired immediately.
ƒ At seals or stuffing boxes where leaks might occur during normal operation, means
should be provided for venting the escape gas to a safe location.
ƒ Vessels should be purged of hydrogen sulfide before being opened.
ƒ Masks furnishing purge air should be worn by personnel who are likely to be
exposed to the gas.
ƒ Personnel who may be exposed to even low concentrations of this gas should
frequently retire to areas of fresh air.
ƒ As a good safety measure, personnel should learn to recognize the early symptoms
of hydrogen sulfide poisoning.
Detection of hydrogen sulfide
A simple test with lead acetate solution on white paper will detect the presence of
hydrogen sulfide. Depending on the concentration the paper will turn yellow or brown.
Adequate Draëger tubes can be used in the same way.
Personal protection
Gas mask of appropriate type or positive air mask should be used.
First aid
A person unconscious in an atmosphere which may be contaminated with hydrogen
sulfide should be assumed to have hydrogen sulfide poisoning. This is a serious medical
emergency and requires immediate attention. The affected individual should be removed
to clean atmosphere, care being taken that rescuers too are not overcome by hydrogen
sulfide. Artificial respiration should be resorted to immediately, if necessary, and the victim
should be kept warm and at rest.
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7.3.3 Carbon Monoxide CO
Carbon oxide is most often found where incomplete combustion occurs (during
regeneration). So, it is possible to produce few volume percent of CO in regeneration
effluent gas during combustion step.
Physical properties:
• Colourless and odourless gas
• Boiling point
: - 191°C
• Melting point
: - 207°C
• Molecule weight
: 28
• Specific gravity/air
: 0.967
Chemicals and hazardous properties:
Poisonous carbon monoxide has the ability to replace oxygen in the blood. Too high a
concentration in the body may cause death in a short period of time.
CO also acts to keep the oxygen in the blood from reaching the tissues causing a type of
suffocation.
Maximum allowable concentration in air 100 ppm.
CO burns readily and is dangerous when exposed to heat or flames.
Its explosive limits range from 12.5% to 74% volume.
The auto-ignition temperature is 650°C.
Mixture of CO and air in certain proportions are flammable.
Detection of CO
CO can be detected only by a reliable detector such as an ORSAT apparatus, or a
DRAEGER tube.
Personal protection
Always wear a self-contained oxygen breathing system when entering an area or vessel
suspected of having carbon monoxide present.
First aid
Remove victim to fresh air.
If recovery is slow, bring resuscitator and give oxygen.
If the breathing has stopped, give artificial respiration until the doctor arrives.
7.3.4 Carbonyls
Formed by combining the (CO) group and metal, in particular Ni, Fe, Co, Mo, under certain
operating conditions, in presence of carbon monoxide.
During regeneration step of catalyst it is possible to produce small quantities of metal
carbonyl.
Hydrotreating catalysts can contain traces of nickel, cobalt or molybdenum carbonyl.
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Physical properties:
Ni(CO)4
Clear
liquid
43
Co2(CO)8 Fe(CO)5
Orange
Clear liquid
Crystals
Decomp. at 104.6
52
1.730
1.453
Fe(CO)9 Fe3(CO)12 Mo(CO)6
Gold plates Green
Colourless
tablets
crystals
Decomp. at Decomp. at Sublime at
100
140
30-40
2.085
1.996
1.960
Colour
and state
Boiling
point °C
Specific
1.310
gravity/air
Vapour
238 at 15° 0.72 at 15° 26 at 16°
pressure
mm Hg
Condition
of 30 to 50° 220°C 150 173°C 200 Light
on
formation
atm.
atm.
Fe(CO)5
Decomposition 50°C
1 60°C 1 atm 130°C
1
150°C
atm
atm
43 at 100°
200°C
atm
150°C
200
All the metal carbonyls are decomposed into metal and carbon monoxide.
Vapour densities are several times greater than air.
Chemical and hazardous properties:
Some of the carbonyls, nickel in particular, are very toxic, so their formation must be
avoided in the interest of safety. Whenever men are going to enter or open a catalytic
reactor, stringent precautions should be followed to assure that carbonyls are not present.
Even in closed systems where there is no safety hazard, carbonyl formation should be
prevented, since it may remove metal from the catalyst and cause a loss of activity.
The toxicity of carbonyls depends in part, but not always, on their easy decomposition
which releases carbon monoxide.
Symptoms are due in part to CO and in part to direct irritating action of the carbonyl.
Toxic concentration 1 ppb at a contact time lasts 8 hours.
They react with water or steam to produce toxic or flammable vapours and can react
vigorously with oxidising materials.
Detection of carbonyls
Infrared spectrometry can be used to detect carbonyls in the range of 1 to 10 ppb.
The flame of a Bunsen burner or alcohol lamp can be used as a simple and effective test
for carbonyls. Metal carbonyls will impart a readily observable luminosity to flames, even if
the concentration of the carbonyl is as low as 1 ppm.
Personnel protection
If it is necessary for personnel to enter a reactor where the presence of nickel carbonyl is
suspected, they should be equipped with self-contained air masks and skin protection.
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7.3.5 Regenerated catalyst
If it proves necessary to handle the regenerated catalyst, use the protective equipment
and wear an air or oxygen mask because of the possible presence of traces of carbonyls
or hydrocarbonyls which are toxic at concentrations of 0.001 ppm at a contact time lasting
8 hours.
Compare this toxicity can be with the minimum unsafe concentrations 20 ppm for H2S or
100 ppm for CO, i.e., it is much more dangerous.
Safety regulations for reactor entry must strictly enforced.
7.3.6 Dimethyldisulfide DMDS (CH3-S-S-CH3)
DMDS is used as sulfiding agent of the catalyst during start up.
Physical properties:
• Specific gravity
1.063
• Boiling point 109.6°C
• Vapour pressure (20°C) 38 mb
• Flash point 76°C
Insoluble in water Hazardous product, class IIIa. RID3.
Handle with gloves and goggles.
7.3.7 Sulfiding agent
See the safety data sheets given by manufacturer of the sulfiding agent.
7.3.8 Corrosion inhibitor
Although they are not considered highly toxic or hazardous, these chemicals do require
careful handling to avoid skin or eye damage.
First aid: water wash.
7.3.9 Pyrophoric materials – Iron Sulfide
The unregenerated catalyst is pyrophoric and has to be handled under nitrogen due to the
presence of H2S, iron sulfide is present in different part of the unit. This substance is
subject to ignition when exposed to air. Any vessel, filter, screen where iron sulfide is
collected should be kept wet until cleaned or disposed of.
7.4. Catalyst Safety data sheets
Material Safety Data Sheets (M.S.D.S.) are provided by Axens, when the catalysts are
purchased.
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8.
ANALYTICAL CONTROLS
Methods of analysis and frequencies are indicated in the tables below.
8.1. Analytical methods
8.1.1 Feed & product
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Analysis
Distillation, %vol
Distillation, %wt
Specific gravity
Sulfur (1)
Mercaptans, H2S
Nitrogen (2)
Aromatic content (3)
Olefins content
Bromine Number (g/100g)
Bromine Index (mg/100g)
Flash point
Pour point
Viscosity
Viscosity Index
Cetane index
Cetane number
Aniline Point
Maleic anhydride value
Conradson carbon
Asphaltenes
Ni, V
Na
Chlorides
As+P
Hg
Si
Dissolved O2
Color
RON
MON
RVP
GASOIL
METHOD
VGO
KERO
NAPHTHA
ASTM D 86 / D 1160 / D 5236
ASTM D 86
ASTM D 2887
ASTM D2887
ASTM D 3710
ASTM D 1298/ D 4052
ASTM D 4294 / ASTM D 2622 / ASTM D 5453 / ASTM D 3120
ASTM D 3227
ASTM D 3227 / IFP 9627
Rev 5
ASTM D 5762 / D 4629
ASTM D 4629
ASTM D 4629
ASTM D1319/D6591/D2425 / IFP 9409/SATM
IFP 9409
ASTM D 1319
ASTM D 1319 -D 2789/ IFP 9301
ASTM D 1319
ASTM D 1319
ASTM D 1159
ASTM D1492 (4)
ASTM D 2710
ASTM D 92
ASTM D 93
ASTM D 3828
ASTM D 93
ASTM D 97
ASTM D 445 / D 446
ASTM D 445 / D 446 /
ASTM D 445
D 2800
ASTM D 2270
ASTM D 976 / D 4737
ASTM D 976 / D 4737
ASTM D 613
ASTM D 613
ASTM D 611 B/E
ASTM D 611 B/E
ASTM D611
IFP 9407
IFP 9407
ASTM D189
ASTM D 4530 / D189
IFP 9313 / IP 143
ASTM D 5185 / IFP 9507
ASTM D 5863 / D 5185/ IFP 9507
ASTM D 5863
ASTM D 4929
IFP 9312
IFP 9606
ASTM D 5184
IFP Orbisphere
ASTM D 1500 / ASTM D 156 / IFP 9903 (5)
ASTM D 2699
ASTM D 2700
ASTM D323 / D 5191
ASTM D 86
ASTM D2887
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Analysis
Benzene content
Naphtalenes
CFPP
Smoke point
Freezing point
GASOIL
METHOD
VGO
IF 309 - EN 116- ASTM D6371
-
-
Storage stability at 43°C
-
-
Cloud point
Copper corosion
Doctor Test
Acidity
Stability (sediment)
Thermic stability JFTOT
ASTM D 2500
ASTM D 130
ASTM D 235
ASTM D664
ASTM D 2274
-
ASTM D664
-
Existing Gums
Potential Gums
Water Content
ASTM D 873
ASTM D 873
Rev 5
ASTM D 95 / ASTM D 6304/ D 4176 (6)
ASTM D 85
(1) : D 4294 if 5% >S > 150 ppm
D 3120 if 1000 ppm > S > 3 ppm (distillation range 26°C-274°C)
D 2622 if 5.3% > S > 3 ppm
D 5453 if 0.8% > S > 1 ppm
(2) : D 5762 if 40 < N < 10000 ppm
D 4629 if 0.3 < N < 100 ppm
(3) : D 1319 is a family analysis, IFP 9301 is a compound analysis
(4) : D 1492 end point under 288°C and no olefins for Bromine Index below 500.
(5) : If product darker than Saybolt Color -16 : use D1500
If product lighter than ASTM color 0.5 : use D156
(6) : D95 if 0 %vol < H2O < 25 % vol
D 6304 if 10 ppm < H2O < 25 ppm (interferences with H2S and RSH)
D 4176 : Clear and bright ~ 40 ppm
Rev 5
KERO
NAPHTHA
ASTM D 1840
ASTM D 1322
ASTM D 2386 / D4305 /
D5901
Ageing + filtration ASTM
D 4625
-
ASTM D 2267 / D5063
-
ASTM D 873
ASTM D 6304
ASTM D 381
ASTM D 873
ASTM D 6304 / ASTM E 203-E 1064
-
ASTM D 130
ASTM D 235 / ASTM D 4952
ASTM D 3242
ASTM D664
ASTM D 2274
ASTM D 3241
-
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HR SERIES
ASTM
ASTM
ASTM
ASTM
ASTM
ASTM
ASTM
ASTM
ASTM
ASTM
ASTM
ASTM
ASTM
ASTM
ASTM
ASTM
ASTM
ASTM
ASTM
ASTM
ASTM
ASTM
ASTM
ASTM
ASTM
ASTM
ASTM
D
D
D
D
D
D
D
D
D
D
D
D
D
D
D
D
D
D
D
D
D
D
D
D
D
D
D
85
86
92
93
97
130
156
189
235
323
381
445
446
512
611B/E
613
664
873
976
1068
1159
1160
1293
1298
1319
1322
1426
ASTM D
1492
ASTM
ASTM
ASTM
ASTM
ASTM
ASTM
ASTM
ASTM
ASTM
ASTM
ASTM
1500
1840
2008
2267
2270
2274
2386
2500
2622
2699
2700
D
D
D
D
D
D
D
D
D
D
D
Atmospheric Distillation
Cleveland Open Cup
Pensky-Martens Close Cup
Pour point
Copper Strip Tarnish Test
Saybolt Color
Conradson Carbon Residue
Reid Vapor Pressure
Existent Gums in fuels by Jet evaporation
Kinematic Viscosity
Glass Capillary Kinematic Viscometers
Cl in Sour Water
Aniline Point (B&E are different methods)
Acid Number by Potentiometric Titration
Oxidation Stability for Aviation Fuels
Calculated Cetane Index
Fe in Sour Water
Bromine Number by Electrometric Titration
Distillation at reduced pressure
pH of Sour Water
Density, specific gravity, API gravity
Hydrocarbon Types by Fluorescent Indicator Absorption (FIA)
Smoke Point
Ammonia in Sour Water
Standard Test Method for Bromine Index of Aromatic Hydrocarbons
by Coulometric Titration
ASTM Color
Naphthalene Hydrocarbons by Ultraviolet Spectrophotometry
Ultraviolet Absorbance and Absorptivity
Calculating Viscosity Index
Oxidation Stability of Distillates Fuel Oil (Accelerated Method)
Freezing Point Aviation Fuels
Cloud Point
Sulfur by X-Ray Spectrometry
RON
MON
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HR SERIES
ASTM
ASTM
ASTM
ASTM
D
D
D
D
2710
2789
2887
3120
Bromine Index by Electrometric Titration
Hydrocarbon Types in Low Olefinic gasoline by Mass Spectrometry
Boiling Range Distribution by Gas Chromatography
Trace Quantities of sulfur in Light Liquid Petroleum Hydrocarbons by
Oxidative Microcoulometry
ASTM
ASTM
ASTM
ASTM
ASTM
ASTM
D
D
D
D
D
D
3227
3241
3242
3710
3828
4052
ASTM D
4176
ASTM
ASTM
ASTM
ASTM
D
D
D
D
4294
4530
4625
4629
Mercaptans Sulfur (Potentiometric Method)
Thermal Oxidation Stability (JFTOT Procedure)
Acidity in Aviation Turbine Fuel
Boiling Range Distribution of Gasoline by Gas Chromatography
Flash Point by Small Scale Closed Tester
Density and Relative Density by Digital Density Meter
Standard Test Method for Free Water and Particulate
Contamination in Distillate Fuels (Visual Inspection Procedures)
Sulfur by Energy-Dispersive X-Ray Fluorescence Spectroscopy
Determination of Carbon Residue (Micro Method)
Distillate Fuel Storage Stability at 43°C
Trace Nitrogen by Syringe/Inlet Oxidative Combustion and
Chemiluminescence Detection
ASTM
ASTM
ASTM
ASTM
ASTM
ASTM
D
D
D
D
D
D
4658
4737
4929
4952
5063
5184
ASTM D
5185
ASTM
ASTM
ASTM
ASTM
D
D
D
D
5191
5236
5453
5762
ASTM D
5863
ASTM D
ASTM D
ASTM D
5901
6304
6371
ASTM D
6591
ASTM E
ASTM E
1064
203
Sulfides in sour Water
Calculated Cetane Index by Four Variable Equation
Determination of Organic Chloride Content
Qualitative Analysis for Active Sulfur Species (Doctor Test)
Determination of Al and Si by Ashing, Fusion, Inductively Coupled
Plasma Atomic Emission spectrometry, and Atomic Absorption
Spectrometry
Determination of Selected Elements in Base Oils by Inductively
Coupled Plasma Atomic Emission Spectrometry (ICP-AES)
Vapor Pressure (Mini Method)
Distillation of Heavy Hydrocarbon Mixtures (Vaccum Potstill Method)
Determination of Total Sulfur by Ultraviolet Fluorescence
Nitrogen by Boat-Inlet Chemiluminescence
Determination of Ni, V, Fe, and Na by Flame Atomic Absorption
Spectrometry
Freezing Point of Aviation Fuels (Automated Optical Method)
CFPP : Cold Filter Plugging Point for Diesel
Standard Test Method for Determination of Aromatic Hydrocarbon
Types in Middle Distillates-High Performance Liquid Chromatography
Method with Refractive Index Detection
Karl Fisher (Naphtha)
Karl Fisher (Naphtha)
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Rev 5
HR SERIES
IFP
9312
Determination of Arsenic Graphite Furnace Electrothermal Atomic
Absorption Spectrometry
IFP
IFP
9313
9407
Asphaltenes content visible spectrometry
Determination of Conjugated Diolefins Maleic Anhydride Addition
Reaction and Potentiometry
IFP
IFP
IFP
9409
9507
Mono-, Di-, Polyaromatique content UV Absorption Spectrometry
Determination of Ni and V Inductively Coupled Plasma
Determination of Mercury Content Flameless Atomic Absorption
Spectrometry
Hydrotreating Gas. Analysis of H2, HC, Air, Water and H2S Gas
chromatography
Determination
of
Hydrogen
Sulfide
and
Mercaptans Rev 5
Potentiometry.
Amine solutions. H2S Concentration Iodine Titration.
Catalytic cracked Gas. Analysis of H2, Nitrogen, Oxygen, Carbon
Oxides, H2S, NH3 and HC Gas chromatography
9606
IFP
9622
IFP
9627
IFP
9762
IFP
9810
IFP
IP
IP
IF
EN
9903
129-16
143
309
CFPP : Cold Filter Plugging Point
116
CFPP : Cold Filter Plugging Point
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HR SERIES
8.1.2
Gas
Gasoil
Stream
Make-up gas
Make-up gas
Recycle gas
Sour gas
Analysis
Composition
Impurities (CO)
Composition, H2S
Composition, H2S
Stripper OVHD
Composition, H2S
Stabilizer OVHD Composition, H2S
-
VGO
Kero Naphtha
Method
IFP 9622
Draeger tube
IFP 9622
IFP 9622
IFP 9622
IFP 9622
-
-
-
-
8.1.3 Amine
8.1.3.1.Lean Amine
Analysis
Apparent H2S
Method
IFP 9762
MDEA / DEA
Appearance
Standard
Visual
Analysis
Apparent H2S
Method
IFP 9762
8.1.3.2.Rich Amine
Appearance
Visual
8.1.4 Sour Water
Analysis
Method
ASTM D-1293
ASTM D-4658
ASTM D-1426
ASTM D1068
ASTM D512
PH
Sulfides
Ammonia
Fe
Cl
8.1.5 Regeneration phase
Analysis
pH
pH
Salts
O2, CO, CO2
SO2
Location
Spent caustic
Spent caustic
Spent caustic
Separator drum
outlet
Separator drum
outlet
Method
Labo
pH paper
as required
IFP 9810
Draëger tube
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8.2. Catalyst analysis
Please find in the table the different catalyst characteristics which can be analysed if
required.
Characteristics
Aspect
Pore size distribution
Total Pore Volume
Surface area
Attrition Resistance
Particle Crushing
Strength
Bulk Crushing Strength
Image analysis
Mean diameter
Mean length
particle size / Granulo
H2-O2 Chemisorption
CO Chemisorption
Metallic Phases
Dispersion
Loss on ignition at 500
°C
Drying
Simple Lab.
Regeneration
Carbon content
Sulfur
content
Chlorides content
XRF Content (…)
XRF Scanning for
poisons and impurities
(Fluorescence X-Ray)
X Ray Diffraction
(α Alumina Ratio)
Alkalines Contents
Fluorides content
Analysis
unit
REP
VPT
BET
AIF
ml/100g
m2/g
%
EGG
daN
ESH
Mpa
mm
ml O2/g
ml CO/g
%
%
%
C
S
Cl
%
%
%
%
ppm
%
F
ppm
ppm
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9.
FOLLOW-UP OF THE HDS UNIT
9.1. Generalities
The target is to know all along the run the “catalyst activity” for the main reactions required
(HDS, HDN, HDA, Cracking), for all the products ‘specifications to achieve (Diene value,
Bromine number, Sulfur, Nitrogen, yields, Sp.Gr, Cetane Number, Viscosity Index,
Aromatic content, …).
In order to evaluate the catalyst activity evolution, check that it is normal or anticipate
eventual problems, a close follow of the WABT can be realised.
But the required WABT at a given time in the reactor does not only depend on the catalyst
activity, but also on the feed quality (sulfur), feed rate, reactor pressure, hydrogen purity,
and operation severity (exact product sulfur).
This is the purpose of the normalized WABT to "eliminate" the impacts of the varying
parameters, except catalyst activity of course; so that the variation of the normalized
WABT with time is only due to catalyst activity variation (or deactivation).
This normalised WABT is generally calculated from a reference base which can be the
results of a test run for example.
By definition the normalized WABT trend is an estimate of the catalyst deactivation rate,
usually expressed in °C/month.
The data needed for a close follow-up of the performances of the HDS unit can be
separated in two sets:
ƒ History of the unit that concerns only the reaction section, in order to follow the unit
feedstock, reactor operating conditions, compressors operation, and to have an
overall material balance.
ƒ Mini test runs for a detailed evaluation of the catalyst and unit performances. A
complete set of operating conditions and analysis of feedstocks and products,
make-up and recycle gas are needed for the purpose. The frequency of such mini
tests will be adjusted to your normal schedule, but we estimate that at least one
mini test per month will assure an accurate follow-up.
There are different ways of calculating the normalised WABT (or different ways of
evaluating the catalyst activity). Two major types can be distinguished:
ƒ A method based on a pseudo-kinetic model known as “Point Pivot”. This method is
generally implemented when a rough view of the unit is required or when only a few
data have been collected. (Example: follow-up for catalyst change, …)
ƒ A method based on a correlative model which is based on pilot plant experiences.
This method is really accurate and allows a close follow up of the catalyst activity.
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9.2. The Pseudo-Kinetic model
The basic equation is as follow:
dS
n
m
= − k [S ] [ ppH 2] with k=ko e-Ea/RT
dt
S = sulfur content
t = time
ppH2 = partial pressure of H2
Ea = activation energy
R = constant
T = Temperature
ko = catalyst activity
This model is limited because it does not take in account the WAT (Weight Average
Temperature) and the “Sulfur zero effect” (it is more difficult to remove the last ppm of
sulfur).
Using only a few operating parameters, the pseudo-kinetic model gives a good first
approximation and is very helpful when the correlations do not exist or for predictions.
The graph attached hereafter shows the WABT from operating conditions and the
normalised WABT with its tendency.
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y = 0.0438x + 341.32
400.0
390.0
380.0
Temperature, °C
370.0
360.0
350.0
340.0
330.0
320.0
310.0
300.0
0
20
40
60
80
100
120
140
Days on stream
WABT
Corrected WABT
Linear regression (corrected WABT)
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9.3. The Correlative model
Correlations have been developed on particular feed like straight run or on particular
catalyst from IFP pilot plant experiences.
These correlations are based on more parameters than the pseudo-kinetic model and
therefore allow an accurate evaluation of the catalyst activity, activity which is determinant
to know, when the catalyst will need to be changed or regenerated, or what is the
expected catalyst life with new operating conditions.
This catalyst evaluation is performed by Axens.
From the correlative model, curves dedicated to a particular unit can be drawn.
They are exposed in the following pages under different forms:
o HDS=f(LHSV, TMP, GO_Conv, PPH2) @ different WABT
o HDS=f(WABT) @ different LHSV, TMP, GO_Conv, PPH2) (in this part: GO_Conv
means Distillate_Conv)
This set of curves draw from the results of correlative model has been especially dedicated
to a particular case and can not be used in other cases. Furthermore comparison of
results from a particular unit with the curves attached hereafter could lead to
misinterpretation.
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THIS DOCUMENT IS THE PROPERTY OF AXENS AND SHALL NOT BE REPRODUCED OR DIVULGATED WITHOUT AXENS CONSENT
HR SERIES
THIS DOCUMENT IS THE PROPERTY OF AXENS AND SHALL NOT BE REPRODUCED OR DIVULGATED WITHOUT AXENS CONSENT
HR SERIES
THIS DOCUMENT IS THE PROPERTY OF AXENS AND SHALL NOT BE REPRODUCED OR DIVULGATED WITHOUT AXENS CONSENT
HR SERIES
THIS DOCUMENT IS THE PROPERTY OF AXENS AND SHALL NOT BE REPRODUCED OR DIVULGATED WITHOUT AXENS CONSENT