feedstock purfication in hydrogen plants

Feedstock Purification in Hydrogen Plants

G B Hawkins

Managing Director, CEO

GBH Enterprises Ltd.


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


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



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 93.2C2H6 4.8C3H8 1.2C4H10 0.4C5+ 0.4

Total Sulfur* 2-20 ppmv

1. Sources of Poisons


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



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


*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 TraceRSH 36R2S2 3R2S 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



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


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


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


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


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 F 1040 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



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


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?


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


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


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

02468

101214

%w

t Chl

orid

e in

A

bsor

bent

0 20 40 60 80 100Bed Depth

SodiumPromotedAluminaAlumina



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



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

Technology