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Feedstock Purfication in Hydrogen Plants
The document discusses the importance of feedstock purification in hydrogen plants, focusing on catalyst requirements and various poisoning agents such as sulfur, chlorides, and heavy metals. It outlines methods for hydrogenation, dechlorination, and sulfur removal, along with typical purification flowsheets and operational conditions. The text emphasizes the need for careful monitoring of feed compositions and purification system performance to maintain plant efficiency and prolong catalyst life.
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Feedstock Purfication in Hydrogen Plants
- 1. Feedstock Purification in HydrogenPlants G B Hawkins Managing Director, CEO GBH Enterprises Ltd.
- 2. Feedstock Purification inHydrogen 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.
- 3. 1. Reasons forFeedstock 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
- 4. 1. Reasons forFeedstock 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 GBH Enterprises Ltd.
- 5. 1. Reasons forFeedstock 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 GBH Enterprises Ltd.
- 6. Natural Gas Feeds Mercurymay 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 GBH Enterprises Ltd.
- 7. Component "Typical" Composition (mol %) Ranges C3H80.5 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 1. Sources of Poisons GBH Enterprises Ltd.
- 8. 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 1. Sources of Poisons *H2S & reactive organic S compounds GBH Enterprises Ltd.
- 9. 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 GBH Enterprises Ltd.
- 10. Type of SulfurTypical 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 1. Sources of Poisons GBH Enterprises Ltd.
- 11. 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 GBH Enterprises Ltd.
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- 13. Feedstock Purification inHydrogen 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 GBH Enterprises Ltd.
- 14. Hydrogenation Reactions CoMo orNiMo 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 GBH Enterprises Ltd.
- 15. Feed Type MinH2 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 GBH Enterprises Ltd.
- 16. 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 GBH Enterprises Ltd.
- 17. 2. Typical HydrogenationCatalyst Characteristics - CoMo Typical composition (wt %):- CoO 4.0 % MoO3 12.0 % Cement Balance Form:- Usually extruded thin cylinders with high porosity A true catalyst! GBH Enterprises Ltd.
- 18. 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 GBH Enterprises Ltd.
- 19. 2. Typical HydrogenationCatalyst 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! GBH Enterprises Ltd.
- 20. 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% GBH Enterprises Ltd.
- 21. 2. Hydrogenation Typicaloperating 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 GBH Enterprises Ltd.
- 22. 2. Hydrogenation Organometalliccompounds 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 GBH Enterprises Ltd.
- 23. 2. Hydrogenation Lowsulfur 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 GBH Enterprises Ltd.
- 24. 826 F 665F1040 F 540 F 1/Temperature Co Mo Ni Sulfided Phase Reduced Phase 2. Co, Mo & Ni Sulfur Equilibrium Phase Diagram GBH Enterprises Ltd.
- 25. 2. Hydrogenation AromaticsHydrogenation • 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 GBH Enterprises Ltd.
- 26. 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 GBH Enterprises Ltd.
- 27. 2. Hydrogenation Reactionof 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 GBH Enterprises Ltd.
- 28. 2.Hydrogenation - TypicalProblems 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 GBH Enterprises Ltd.
- 29. Feedstock Purification inHydrogen 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 GBH Enterprises Ltd.
- 30. 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 GBH Enterprises Ltd.
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- 32. 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? GBH Enterprises Ltd.
- 33. HClZnO Crystallites Catalyst Pore s Effect of Chlorideon ZnO Sulfur Removal Catalyst 1. Fresh ZnO 2. Poisoned ZnCl2 blocks catalyst surface and pores to prevent sulfur absorption 3. Chloride Removal GBH Enterprises Ltd.
- 34. HCl + NaAlO2AlOOH + 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 GBH Enterprises Ltd.
- 35. 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 GBH Enterprises Ltd.
- 36. • Design Clslip = <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 GBH Enterprises Ltd.
- 37. Comparative Performance ofPromoted 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 GBH Enterprises Ltd.
- 38. Feedstock Purification inHydrogen Plants 1 Introduction 2 Hydrogenation 3 Dechlorination 4 Sulfur Removal • catalysts/absorbents • sulfur pick-up • operational aspects Purification system start-up & shut- down GBH Enterprises Ltd.
- 39. • Fe3O4 (reducedFe2O3) 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 GBH Enterprises Ltd.
- 40. Typical compositions:- 1. ZnO90-94.0 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 GBH Enterprises Ltd.
- 41. 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 GBH Enterprises Ltd.
- 42. 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 GBH Enterprises Ltd.
- 43. 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 GBH Enterprises Ltd.
- 44. Temperature Affect onTotal 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 GBH Enterprises Ltd.
- 45. 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! GBH Enterprises Ltd.
- 46. 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 GBH Enterprises Ltd.
- 47. 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 GBH Enterprises Ltd.
- 48. Feedstock Purification inHydrogen Plants 1. Introduction 2. Hydrogenation 3. Dechloration 4. Sulfur Removal 5. Purification system start-up and shut down GBH Enterprises Ltd.
- 49. 5. Purification SystemStart-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 GBH Enterprises Ltd.
- 50. 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 GBH Enterprises Ltd.
- 51. 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 GBH Enterprises Ltd.
- 52. Purification Catalyst forHydrogen 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 GBH Enterprises Ltd.