Feedstock Purfication in Hydrogen Plants

Feedstock Purification
in Hydrogen Plants
G B Hawkins
Managing Director, CEO
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

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

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

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

Natural Gas Feeds
Mercury may be present in some NG supplies
*H2S & reactive organic S compounds (odoring agents often added)
Component NG (mol %)
CH4 93.2
C2H6 4.8
C3H8 1.2
C4H10 0.4
C5+ 0.4
Total Sulfur* 2-20 ppmv
1. Sources of Poisons

Component "Typical"
Composition
(mol %)
Ranges
C3H8 0.5 0.1 - 90
iC4H10 30 10 - 99
nC4H10 69 10 - 99
C5H12 0.5 0.1 - 10
Total Sulfur
(Organic) *
20 ppm (wt) 0 - 100 ppm
(wt)
* Reactive types
Olefins may be present!
LPG Feeds

Component Offgas #1
(mol %)
Offgas #2
(mol%)
H2 27.6 35.2
CH4 35.6 26.5
C2H6 19.2 15.2
C3H8 9.9 12
C4H10 6.7 8.8
C5H12 0.8 2
C6H14 0.2 0.3
Total Sulfur* 2 ppmv 10 ppmv
Total Chloride 1-2 ppmv -
Refinery Offgas Feeds
*H2S & reactive organic S compounds

Refinery Offgas Feeds (Contd.)
 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

Type of Sulfur Typical Split of S
(%)
H2S Trace
RSH 36
R2S2 3
R2S 51
*Unreactive S 10
Naphtha Feeds - Sulfur Species
* Stable > 400 Deg C (752 Deg F) - e.g. Thiophene

Naphtha Feeds (Contd.)
 Large variation in S level
• 0.1 - 500 ppm wt
 Chloride level typically 0.1 - 2 ppm wt
 Pb/As/Va may be present

Hydrocarbon
Feed
Hydrogenation Chloride
Removal
Sulfur
Removal
Hydrocarbon
Feed
Hydrogenation
Sulfur
Removal
Chloride
Removal
Hydrocarbon
Feed
Sulfur
Removal
Hydrogenation
1. Typical Purification Flowsheets

Plants
 1. Introduction
 Reasons for purification, types of
poisons, and typical systems
 5. Purification system start-up and
shutdown

Hydrogenation Reactions
CoMo or NiMo type catalysts
Exothermic 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

Feed Type Min H2
Requirement
(mol %)
Typical H2
Levels
(mol %)
NG 0 2-5
LPG 10 12
Light Naphtha 20 25
H. Naphtha
<20% Aromatics
25 25
H. Naphtha
>20% Aromatics
30 30
ROG feeds usually have sufficient hydrogen content
Hydrogenation Hydrogen Requirements
2. Hydrogenation

Feedstock Temperature
SOR
Temperature
EOR
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

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!

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

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!

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%

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

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

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

826 F 665 F1040 F 540 F
1/Temperature
Co
Mo
Ni
Sulfided Phase
Reduced
Phase
2. Co, Mo & Ni Sulfur Equilibrium
Phase Diagram

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

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

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

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

Plants
 1. Introduction
 sources of chloride
 effects of chloride
 removal of chloride
 5. Purification system start-up & shut-
down

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

Hydrocarbon
Feed
Hydrocarbon
Feed
Hydrogenation Chloride
Removal
Sulfur
Removal
Hydrogenation
Sulfur
Removal
Chloride
Removal
Hydrocarbon
Feed
Sulfur
Removal
Hydrogenation
Typical Purification Flowsheets

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?

HClZnO
Crystallites
Catalyst
Pore
s
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

HCl + NaAlO2 AlOOH + NaCl
2HCl + 2NaAlO2 Al2O3 + 2NaCl + H2O
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

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

• 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

Comparative Performance of Promoted
Alumina and Alumina
3. Chloride Removal
0
2
4
6
8
10
12
14
%wtChloridein
Absorbent
0 20 40 60 80 100
Bed Depth
Sodium
Promoted
Alumina
Alumina

Plants
 1 Introduction
 2 Hydrogenation
 3 Dechlorination
 4 Sulfur Removal
• catalysts/absorbents
• sulfur pick-up
• operational aspects
 Purification system start-up & shut-
down

• 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

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

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

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

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

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

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!

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

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

Plants
1. Introduction
2. Hydrogenation
3. Dechloration
4. Sulfur Removal
5. Purification system start-up and
shut down

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

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

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

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

Feedstock Purfication in Hydrogen Plants

Feedstock Purfication in Hydrogen Plants

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