Factors to be considered in design of H2S Abatement Unit ......plaju/sei gerong s. pakning dumai p....
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SulfurUnit.com Seminar, 13-16 September 2010 Calgary - Alberta, Canada Factors to be considered in design of H 2 S Abatement Unit in LNG Project SURYA ARMANSYAH Sr. Downstream Business Analyst [email protected] ___________________________________ ___________________________________ ___________________________________ ___________________________________ ___________________________________ ___________________________________ ___________________________________ Page 2 OUTLINE 1. INTRODUCTION (PERTAMINA Profile) 2. BACKGROUND (Indonesia LNG Plants) 3. H 2 S DESIGN FACTORS 4. EVALUATION 5. CONCLUSION ___________________________________ ___________________________________ ___________________________________ ___________________________________ ___________________________________ ___________________________________ ___________________________________ Page 3 I. INTRODUCTION PERTAMINA PROFILE ___________________________________ ___________________________________ ___________________________________ ___________________________________ ___________________________________ ___________________________________ ___________________________________
Transcript of Factors to be considered in design of H2S Abatement Unit ......plaju/sei gerong s. pakning dumai p....
SulfurUnit.com Seminar, 13-16 September 2010Calgary - Alberta, Canada
Factors to be considered in design of H2S Abatement Unit in LNG Project
SURYA ARMANSYAHSr. Downstream Business Analyst
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OUTLINE
1. INTRODUCTION (PERTAMINA Profile)2. BACKGROUND (Indonesia LNG Plants)3. H2S DESIGN FACTORS 4. EVALUATION5. CONCLUSION
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I. INTRODUCTION
PERTAMINA PROFILE
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Downstream(Fuel, Non Fuel, Petrochemicals)
Upstream(Oil, Gas, Geothermal)
• Exploration• Development• Production Fuel
• Gasoline• Kerosene• Gasoil• Avtur• LPG
Non Fuel• LSWR• Naphtha• Asphalt• Lube Base• Wax
Petrochemicals• Paraxylene• Benzene• PTA• Propylene• Polypropylene
Activities : Refining, Petrochemicals Plant, Distribution, Shipping,Transportation, Terminal.
• Lube Oil• Solvent
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PERTAMINA REFINERIES & PETROCHEMICAL PLANTS PROFILE (2007)
BALONGAN
CILACAP
PLAJU/SEI GERONG
S. PAKNINGDUMAI
P. BRANDAN
B.ALIKPAPAN
UP II - DUMAI / S PAKNING170 MBSD
UP III - PLAJU / SEI GERONG133.7 MBSD
UP I - P. BRANDAN
5 MBSD
SORONG
UP VI - BALONGAN125 MBSD
UP IV - CILACAP
348 MBSD
UP V - BALIKPAPAN
260 MBSD
UP VII - KASIM - SORONG 10 MBSD
POLYPROPYLENE& PTA
PROPYLENE PARAXYLENE
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II. BACKGROUND
INDONESIA LNG PLANTS
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INDONESIA LNG PLANTS
BALONGAN
CILACAP
PLAJU/SEI GERONG
S. PAKNINGDUMAI
P. BRANDAN
B.ALIKPAPAN
ARUN
LNG PLANT
10 MTPA
SORONG
Donggi
LNG PlantBONTANG
LNG PLANT
22.5 MTPA
TANGGUH LNAG PLANT
7 MTPA
2 MTPA (in progress)
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564321
Dock-1
Dock-2Dock-3
HGFE
A
DB
C
LPG Tanks
J Lay-down Area
BONTANG PLANT WITH TRAIN I LOCATION
TRAIN-I PROJECT
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III. DESIGN FACTORS
H2S ABATEMENT UNIT
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FACTORS TO BE CONSIDERED IN DESIGNING H2S ABATEMENT UNIT
Feed Gas Composition to CO2 Absorber
Process Flow Alternatives
Acid Off- Gas Composition to H2S Abatement Unit
Process Screening
Base Case C02 : 6,5%
Alt Case C02 : 4%
H2S To be
(Capex, Opex,Life Cycle Cost)
Optimum Design
Catalyst change out frequency
Catalyst TypeAdsorbed
Note :- H2S adsorbed = H2S inlet Abatement Unit – H2S Environment spec- H2S Environmental specification is max. 35 ppm
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IV. EVALUATION OF DESIGN FACTORS
LNG PROCESSING
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LNG Process Flow Diagram
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CO2 & H2S ABSORPTION PROCESS
REG
ENER
ATO
R
ABSO
RBERFEED
GAS
SWEET GAS
TO LNG UNIT
LEAN SOLVENT
RICH SOLVENT
Case -1: CO2 Content in feed gas = 6.5% mol and 4.5 % mole as Case -2
H2S in feed gas about 4.44 kg/hr .
H2S in Acid Off-gas about 3.47 kg/hr
H2S
CO2
H2S Abatement Unit
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1. Feed Gas Composition to Absorber Unit (dry-mol %)
< Base Feed Gas Case: CO2 6.5 mol% >
REG
ENER
ATO
R
ABSO
RBERFEED
GAS
SWEET GAS
TO LNG UNIT
LEAN SOLVENT
RICH SOLVENT
ACID OFFGAS
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Feed Gas Composition to Absorber Unit (kg/hr)
< Base Feed Gas Case: CO2 6.5 mol% >
REG
ENER
ATO
R
ABSO
RBERFEED
GAS
SWEET GAS
TO LNG UNIT
LEAN SOLVENT
RICH SOLVENT
ACID OFFGAS
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Feed Gas Composition to Absorber Unit (dry-mol %)
< Base Feed Gas Case: CO2 4.0 mol% >
REG
ENER
ATO
R
ABSO
RBERFEED
GAS
SWEET GAS
TO LNG UNIT
LEAN SOLVENT
RICH SOLVENT
ACID OFFGAS
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2. Acid Off-Gas Composition (H2S Removal Unit Design Condition)
H2S
Rem
ova
l Un
it
TREATED ACID
OFF GAS
ACID
OFF GAS
TreatedAcid
Off-gas(35 PPMY)
TreatedAcid
Off-gas(4 PPMY)
AcidOff-gas
OverallAcid
Off-gas(35 PPMY)
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3. H2S to be Removed (2 kg/hr or 48 kg/day)
H2S
Rem
ova
l Un
it
TREATED ACID
OFF GAS
ACID
OFF GAS
TreatedAcid
Off-gas(35 PPMY)
TreatedAcid
Off-gas(4 PPMY)
AcidOff-gas
OverallAcid
Off-gas(35 PPMY)
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4. PROCESS SCREENING
NO H2S TO BE REMOVED PROCESS TYPE
01. 10-30 TON SULFUR /DAY REGENERABLES SOLVENT SOLVENT/CLAUS PROCESS
02. LOWER SULFUR RATES REDOX PROCESS
03. VERY LOW SULFUR SIMPLER NON REGENERATIVESPROCESS
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Summary on Non Regenerable H2S Scavenging Technologies
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Sulfur Recovery Process Selection
10
100
1000
10000
100000
1000000
0.01 0.1 1 10
H2S
Co
nce
ntr
atio
n (
pp
mV
)
Gas Flow (106 Nm3/day)
50 kg Sulfur / Day
Non-RegenerableSolids & Liquids
Amine + SulFerox/Shell-Paques
Amine + Claus(+ SCOT)
Shell-Paques
SulFerox
50 ton Sulfur / Day5 ton Sulfur / Day
Source : Shell, 2009
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5. Conceptual Flow Scheme for H2S Abatement Unit (Case – 1: Full Flow; Case – 2: Bypass Flow to H2S Removal Vessel)
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Case Case-1 Case-2
Feed Gas Full Flow Bypass Flow
Catalyst A B A B
Time to Change out(Year)
0.5 1 0.5 1 0.5 1 0.5 1
6. CHANGE OUT FREQUENCY
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TYPICAL OF H2S VESSEL CONFIGURATION
Adsorbent
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7. Total H2S adsorbed, Catalyst Required and Equipment Sizing, Case-1: Full Flow and 0.5 years Catalyst Change out (or 0.5 year continuous operation)
A B
Catalyst - A Catalyst-B
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7a. Cost Required (estimated) for Point 7
Catalyst-A Catalyst-B
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8.Total H2S adsorbed, Catalyst Required and Equipment Sizing, Case-1: Full Flow and 1 years Change out (or 1 year continuous operation)Equipment Summary
A B
Catalyst -A Catalyst -B
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8.a. Cost Required (estimated) for Point 8
Catalyst-A Catalyst-B
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9. Total H2S Adsorbed, Catalyst Required and Equipment Sizing, Case-2: Bypass Flow and 0.5 years Catalyst Change out (or 0.5 year continuous operation)
Catalyst-A Catalyst-B
A B
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9.a. Cost Required for Point 9
Catalyst-A Catalyst-B
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10. Total H2S adsorbed, Catalyst required and Equipment Sizing, Case-2: Bypass Flow and 1 years Catalyst Change out (or 1 year continuous operation)
Catalyst-A Catalyst-B
A B
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11. Cost Required for point 10
Catalyst-A Catalyst-B
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12. CHANGE OUT / DISPOSAL PROCEDURES
Catalyst-A Catalyst-BDescription
Catalyst A requires the use of more land area than Catalyst B.
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13. PLANT LAY OUT
NOT A BIG DIFFERENCE FOR PLANT LAY OUT OF CATALYST A AND B.
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13. Study Summary for H2S Abatement Unit
A B A B
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14. Life Cycle Cost Estimation H2S Abatement Unit (Case 1)A B A B
A B A B
Life Cycle Cost for Catalyst A lower than Catalyst B
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15. Life Cycle Cost Estimation H2S Abatement Unit (Case 2)
A B A B
A B A B
Life Cycle Cost for Catalyst A lower than Catalyst B
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16. Life Cycle Cost for H2S Abatement Unit (Case 1)
A (Year)
B (1 Year)
A (5 Year)
B (0.5 Year
Catalyst A has a lower life cycle cost than Catalyst B
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17. Life Cycle Cost for H2S Abatement Unit (Case 2)
A (Year)
B (1 Year)
A (5 Year)
B (0.5 Year
Life Cycle Cost for Catalyst A is lower than Catalyst B
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CONCLUSION
Catalyst type A is recommendable from the aspect of overall life cycle cost along with consideration of factors
such as Capex, Opex.
From this study, it could be concluded that the following factors need to be considered in designing the H2S Abatement Unit:
1) feed gas composition to Absorber Unit 2) acid off-gas composition to H2S Abatement Unit 3) catalyst type 4) change out of catalyst frequency 5) process flow alternatives 6) cost analysis of Capex and Opex7) life cycle cost of the system 8) the plant lay out factors and change out/disposal procedure
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