Feedstock Purification in Hydrogen Plants
G B Hawkins
Managing Director
GBH Enterprises Ltd.
Feedstock Purification in Hydrogen Plants
1. Introduction reasons for purification, types of
poisons, and typical systems 2. Hydrogenation 3. Dechlorination 4. Sulfur Removal 5. Purification system start-up and
shut-down
GBH Enterprises Ltd.
1. Reasons for Feedstock Purification
Steam reforming catalyst requirements • process gas feed to reformer (dry basis)
sulfur <0.1 ppmv: poison chlorides <0.1 ppmv: poison As/V/Pb/Hg <5ppbv: poison olefins <1-2 vol %: carbon formation
LTS catalyst requirement • process gas feed to LTS (dry basis)
chlorides <5 ppb: severe poison sulfur <0.1 ppmv: poison
1. Reasons for Feedstock Purification
Steam reformer catalyst poisoning • Increased methane slip
low plant efficiency • Hot tubes
tube life reduction or failure • Carbons formation
increased pressure drop increased methane slip and hot tubes
• Sulfur poisoning can be recovered by steaming the steam reforming catalyst
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1. Reasons for Feedstock Purification
LTS catalyst poisoning • Reduced life
premature plant S/D due to high Co slip and high pressure drop
• Chloride deactivates catalyst at concentrations of only 0.05 wt%
• Cu poisoning is not reversible
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Natural Gas Feeds
Mercury may be present in some NG supplies *H2S & reactive organic S compounds (odoring agents often added)
Component NG (mol %)
CH4 93.2C2H6 4.8C3H8 1.2C4H10 0.4C5+ 0.4
Total Sulfur* 2-20 ppmv
1. Sources of Poisons
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Component "Typical" Composition
(mol %)
Ranges
C3H8 0.5 0.1 - 90iC4H10 30 10 - 99nC4H10 69 10 - 99C5H12 0.5 0.1 - 10
Total Sulfur (Organic) *
20 ppm (wt) 0 - 100 ppm (wt)
* Reactive types
Olefins may be present!
LPG Feeds
1. Sources of Poisons
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Component Offgas #1(mol %)
Offgas #2 (mol%)
H2 27.6 35.2CH4 35.6 26.5C2H6 19.2 15.2C3H8 9.9 12C4H10 6.7 8.8C5H12 0.8 2C6H14 0.2 0.3
Total Sulfur* 2 ppmv 10 ppmvTotal Chloride 1-2 ppmv -
Refinery Offgas Feeds
1. Sources of Poisons
*H2S & reactive organic S compounds
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Refinery Offgas Feeds (Contd.)
1. Sources of Poisons
COS may be present • particularly if CO2 is present
Cl may be present as NH4Cl Significant variation in poison content may
occur • hydrogenation duty designed for peaks • poisons absorption capacity designed for
average concentrations
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Type of Sulfur Typical Split of S (%)
H2S TraceRSH 36R2S2 3R2S 51
*Unreactive S 10
Naphtha Feeds - Sulfur Species
* Stable > 400 Deg C (752 Deg F) - e.g. Thiophene
1. Sources of Poisons
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Naphtha Feeds (Contd.)
1. Sources of Poisons
Large variation in S level • 0.1 - 500 ppm wt
Chloride level typically 0.1 - 2 ppm wt Pb/As/Va may be present
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Hydrocarbon Feed
Hydrogenation Chloride Removal
Sulfur Removal
Hydrocarbon Feed
Hydrogenation
Sulfur Removal
Chloride Removal
Hydrocarbon Feed
Sulfur Removal
Hydrogenation
1. Typical Purification Flowsheets
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Feedstock Purification in Hydrogen Plants
1. Introduction Reasons for purification, types of
poisons, and typical systems 2. Hydrogenation 3. Dechlorination 4. Sulfur Removal 5. Purification system start-up and
shutdown
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Hydrogenation ReactionsCoMo or NiMo type catalystsExothermic reactions, but little temperature rise due to low concentrations
C2H5Cl + H2 C2H6 + HCl
C2H5SH + H2 C2H6 + H2S
C4H4S + 4H2 n-C4H10 + H2S
NH4Cl NH3 + HCl
Hydrogen requirement fixed by feed type
2. Hydrogenation
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Feed Type Min H2 Requirement
(mol %)
Typical H2 Levels(mol %)
NG 0 2-5LPG 10 12
Light Naphtha 20 25H. Naphtha
<20% Aromatics25 25
H. Naphtha>20% Aromatics
30 30
ROG feeds usually have sufficient hydrogen content
Hydrogenation Hydrogen Requirements 2. Hydrogenation
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Feedstock TemperatureSOR
TemperatureEOR
ROG 370°C (698°F) 390°C (734°F)*LPG 360°C (680°F) 380°C (716°F)
Naphtha 375°C (707°F) 400°C (752°F)
Hydrogenation Inlet Temperatures
- Lower inlet temperatures needed
C4s can crack more readily
2. Hydrogenation
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2. Typical Hydrogenation Catalyst Characteristics - CoMo
Typical composition (wt %):- CoO 4.0 % MoO3 12.0 % Cement Balance
Form:- Usually extruded thin cylinders with high porosity
A true catalyst!
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2. Hydrogenation - CoMo Most common hydrogenation catalyst Active in the sulfided state Side reactions
• methanation
CO + 3H2 → CH4 + H2O
CO2 + H2 → CH4 + H2O use NiMo if CO>3 vol% or CO2 >13 vol%
• hydrocracking very low activity - carbon slowly formed
• can achieve very long lives 6-20 years
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2. Typical Hydrogenation Catalyst Characteristics - NiMo
Typical composition (wt, loss free):- NiO 4.0% MoO3 14.0% Cement Balance
Form:- Usually extruded thin cylinders with high porosity
A true catalyst!
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2. Hydrogenation - NiMO
Active in the sulfided state Side reactions
• methanation suppressed when catalyst is sulfided
• hydrocracking low activity - carbon slowly formed (activity
marginally higher than CoMo) Can achieve long lives (6-20 years) Olefin hydrogenation activity slightly higher than
CoMo so NiMo usually chosen when olefin concentration >1 vol%
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2. Hydrogenation
Typical operating conditions (CoMo & NiMo): • Operating temperature range
290-430OC (550-750OF) • Operating pressure range
1 - 50 atm (15 psig - 750 psig) • Space velocity
300 - 8000 hour-1 more typically 1000 - 4000 hour-1
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2. Hydrogenation
Organometallic compounds absorbed by CoMo/NiMo • approx. 1wt% of catalyst can be absorbed • special catalyst grades exist that can
increase metals pick-up to approx. 2 wt% useful for high Pb content naphthas
• extra catalyst design volume required catalyst volume for metals absorption plus
catalyst volume for hydrogenation
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2. Hydrogenation
Low sulfur feeds • CoMo/NiMo can over-reduce if S level
<1-2ppmv permanent partial deactivation
• Hydrocracking carbon formation
• Need to sulfur-inject if alternate S-containing feeds are expected
• Equilibrium charts
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826 F 665 F 1040 F 540 F
1/Temperature
Co
Mo
Ni
Sulfided Phase
Reduced Phase
2. Co, Mo & Ni Sulfur Equilibrium Phase Diagram
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2. Hydrogenation
Aromatics Hydrogenation • Naphtha feeds contains aromatics • Hydrogenation rate very slow over CoMo/NiMo
in reality - negligible Olefin hydrogenation
• Maximum olefins to steam reformer = 1-2 vol% • Hydrogen “consumption” needs to be taken
into account (increase hydrogen R/C” • Temperature rise implications
re-circulation system can be used to limit impact of temperature rise
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Hydrogenation
320°C (608°F)
388°C (730°F)
2. Hydrogenation - Olefin Conversion Using a Recirculation System
H2 29.1% C3’ 0.1% C4’ 48.9% C4” 21.3% C5’ 0.6% H2 10.0%
C3’ 0.2% C4’ 89.1% C4” 0.001% C5’ 0.7%
Recirculator Cooler
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2. Hydrogenation
Reaction of COS over CoMo/NiMo
• COS is not absorbed by amine systems
• Low temperature operation • At temperatures <290 OC (550 OF), then
hydrogenation activity is very low • Catalysts containing higher active metal
contents May be used for temperatures down to 240 OC (464 OF)
COS + H2O
H2S + CO2
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2.Hydrogenation - Typical Problems Pressure drop increase
carbon formation • formed from hydrocarbon cracking
carry-over of solids
Sulfur slippage low temperature of operation
• e.g. small plants with high heat loss rate Increase sulfur level increase
• very significant if sulfur is unreactive type
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Feedstock Purification in Hydrogen Plants
1. Introduction 2. Hydrogenation 3. Dechlorination
sources of chloride effects of chloride removal of chloride
4. Sulfur Removal 5. Purification system start-up & shut-
down
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3. Chloride Removal
Possible sources of chlorides • offgas from certain catalytic reformer
plants HCI & NH4Cl
• LPG and naphtha feeds organic chlorides
Some chlorides might originate from the process steam due to incorrect boiler feed water quality
control
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Hydrocarbon Feed
Hydrocarbon Feed
Hydrogenation Chloride Removal
Sulfur Removal
Hydrogenation
Sulfur Removal
Chloride Removal
Hydrocarbon Feed
Sulfur Removal
Hydrogenation
Typical Purification Flowsheets
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3. Chloride Removal
ZnO catalyst • Some of the chlorides will react with the
ZnO to form ZnCl2 this significantly reduces the ZnO capacity
to absorb sulfur weakens the catalyst ZnCl2 sublimes at purification section
normal operating temperatures and can deposit Zn and Cl on downstream reforming catalyst
Why remove the chlorides before ZnO?
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HCl ZnO Crystallites
Catalyst Pores
Effect of Chloride on ZnO Sulfur Removal Catalyst
1. Fresh ZnO 2. Poisoned
ZnCl2 blocks catalyst surface and pores to prevent sulfur absorption
3. Chloride Removal
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HCl + NaAlO 2 AlOOH + NaCl
2HCl + 2NaAlO 2 Al 2 O 3 + 2NaCl + H 2 O
Removing chlorides at elevated temperatures requires a chemical absorbent Physical absorbents like activated aluminas can not operate at normal purification system temperatures as absorbent must operate downstream of the hydrogenation catalyst
Need to use a promoted alumina - e.g. Na2O/Al2O3
3. Chloride Removal
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3. Chloride Removal - Operational Aspects
Operation very straightforward Temperature range
• 0 - 400OC (32 - 752OF) Pressure range
• 0 - 50 atm (14 - 750 psig) Space velocity
• experience of up to 10000/hr • typically 1000-4000/hr
Absorbent sensitive to condensation • pressure drop increase could be due to
condensation
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• Design Cl slip = <0.1ppmv • (Typically 0.05 ppmv or less)
• Monitor HCl slip on a regular basis
• If inlet chloride known, then life of catalyst can be calculated approximately
• 12-14 weight % of chloride in catalyst
• High space velocities are possible • Catalyst can be installed as a "ZnO" top-up
• Other Halogens
• Fluoride and bromide can also be removed
3. Chloride Removal
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Comparative Performance of Promoted Alumina and Alumina
3. Chloride Removal
02468
101214
%w
t Chl
orid
e in
A
bsor
bent
0 20 40 60 80 100Bed Depth
SodiumPromotedAluminaAlumina
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Feedstock Purification in Hydrogen Plants
1 Introduction 2 Hydrogenation 3 Dechlorination 4 Sulfur Removal
• catalysts/absorbents • sulfur pick-up • operational aspects
Purification system start-up & shut-down
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• Fe3O4 (reduced Fe2O3) not ideally suitable due to high S slip
• ZnO used almost universally
“black” ZnO - Lower S capacity
H2S + ZnO H2O + ZnS
Mercaptans can also crack
C2H5SH + ZnO H2O + ZnS + C + CH4
4. Sulfur Removal
Chemical Reaction of H2S with absorbent
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Typical compositions:- 1. ZnO 90-94.0 wt% Cement Balance 2. ZnO 99 wt%
Forms:- - Large variation
•Pelleted cylinders •Extrudates •Granulated spheres
Typical Sulfur Removal Catalyst Characteristics
Target is to achieve maximum accessible ZnO
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4. Sulfur Removal - Total Pick-up
Catalyst requirements (high S pick-up) • High porosity
allows access of H2S to centre of catalyst pellet
porosity maintained as ZnO is converted to ZnS
upstream chloride slip has lower effect on catalyst S capacity
• Highly accessible surface area sharp S absorption profile at high space
velocities
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4. Sulfur Removal - Operational Aspects
Temperature range • 300 - 400OC (572 - 752OF)
Pressure range • 1 - 50 atm (14 - 750 psig)
Space velocity • experience of up to 8000hr-1 • typically 500 - 4000hr-1
Sulfur slip • usually designed for 0.1 ppmv sulfur • achieved S slip <0.05 ppmv for fresh beds
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4. Sulfur removal - Monitoring and Life Assessment
Monitor for H2S regularly • daily for “stressed” beds (6 month lives) • or daily/weekly
Also monitor other organic S compounds • weekly
Note:- If average inlet S is known, life of ZnO can be predicted using expected S pick-up value (eg 20-35 wt%) - NOT theoretical pick-up based on
ZnO quantity!
Monitoring still important
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Temperature Affect on Total Sulfur Absorption
100 200 300 400 0 20 40 60 80
100
Temperature (°C)
Total amount of S absorbed prior to breakthrough. % theoretical
4. Sulfur removal - ZnO Absorbent Capacity
Low pressures (<12 bar, 17 psig) also decreases total amount of S absorbed
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4. Sulfur Removal - Typical Problems Premature sulfur slip
• check for organic S CoMo/NiMo problems
• check for chlorides an operating plant achieved only 2-5 wt% S
pickup with 1-2 ppmv Cl • check for changes in feed sulfur specification
and operating conditions higher space velocities will decrease original
predicted sulfur pick-up Hot reformer tubes (hot bands etc)
• cross-check S analysis results!
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Lead-Lag
• Series arrangement • Configuration can be
reversed
• Upstream reactor can be operated with H2S slip to maximise S pick-up
• Catalyst bed changed on-line
4. Sulfur removal - Series Beds
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4. Sulfur removal - Carbon Beds Beds of activated carbon promoted with
copper Carbon removes organic sulfur and
copper removes H2S Regenerable
• Steam generation removes organic sulfur • H2S can not be easily removed from Cu unless
steam/air regeneration used • Effluent problems
H2S removal capabilities decrease with time
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Feedstock Purification in Hydrogen Plants
1. Introduction 2. Hydrogenation 3. Dechloration 4. Sulfur Removal 5. Purification system start-up and shut down
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5. Purification System Start-up
Usually heated-up with an inert gas or NG • Heat up rate typically 50OC/hr (90OF/hr) • If sour NG is used, avoid passing to the steam
reformer until conditions are reached for H2S conversion and adsorption
For re -start of naphtha/LPG based plants, ensure that the catalyst beds have been fully purged of hydrocarbons before reformer is brought on line
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5. Purification System - Start-up CoMo/NiMo usually sulfided as hydrocarbon
feed is introduced • In some cases, in situ pre-sulfiding may be
required Feeds with high CO2/CO content Sulfur-free C4 stream Involves injection of carbon disulfide or
dimethyl disulfide etc in a flow of N2 or NG at 200OC (390OF)
Purification system usually effective at reduced rates once 300OC (572OF) is achieved • monitoring of S slip still important however
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5. Purification System - Shut-down Beds should be purged with inert gas
cooling to < 38OC (100OF) before depressurization • For naphtha/LPG type feeds, if steam is
already isolated, purging should be done to flare and not through the reformer
Discharged catalyst should be considered pyrophoric • Fine carbon, residual hydrocarbons & iron
carry-over • During discharge, have water hoses ready
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Purification Catalyst for Hydrogen Plants - Summary
Types of poisons, required poison limits, and typical purification systems
Hydrogenation • CoMo/NiMo • Aromatics and Olefin hydrogenation • Sulfur equilibrium • Dechlorination • Sulfur removal • Start-up and shut-down
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