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Gas treating
Hammerfest LNG process
2008
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Inlet facilitiesMetering
Bulk water
Condensate treatment
Mercuryremoval
Acid gastreating
Dehydration Pre-coolingLiquefaction
LNG storage LNG loadingand jetty
LPG storage
Condensate storage
FractionationRefrigerantmakeup
Fuel gasNitrogenremovalFuel gas
MercuryWater
Nitrogen
H2S, CO2
LNGto ship
LPGto ship
Condensateto ship
Slug catcherand pigtrap
Hydrate inhibition recovery
UtilitySystem
FlareFacilities
Controlroom
Feed
Leanhydrate inhibition
General Block Diagram
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Naturgass kjøletårn
Nitrogenfjerning kjøletårn Prosess
understasjon
Elektrisk kraftproduksjon
Kompresjonsområde, lekter
Prosessområde, lekter
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1
HAMMERFEST LNG PLANT
OMRÅDE 2
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Why treat the gas?• To obtain gas specifications
• To protect equipment
• Environmental reasons
• Type of process or equipment depend on specifications
– Pipeline gas
– NGL pre-treatment (Kårstø plant)
– LNG pre-treatment (Hammerfest LNG plant)
• Cost will vary!
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Typical Gas Quality Parameters in Europe(Pipeline gas)
GQHWG Gas Quality parametersParameter Unit Min MaxWobbe Index kWh/Nm3 13,6 - 13,76 15,7-15,81Relative density 0,555 0,7GCV kWh/Nm3 10,1-10,2 13,1-13,2Total S mg/Nm3 30,0H2S + COS (as S) mg/Nm3 5,0Mercaptans (as S) mg/Nm3 6,0O2 ppm 10 - 100CO2 mol % 2,5H2O DP oC @ 70 bar(a) - 8HC DP oC @ 1- 70 bar(a) - 2
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Treatment in Hammerfest LNG plant• Acid gas removal (Unit 22)
• Water removal or dehydration (Unit 23)
• Mercury removal (Unit 21)
• Heavy hydrocarbon removal (Part of unit 25)
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Gas treatment in LNG processes• CO2
– Limited solubility in LNG
– 50 – 100 ppmv
– Freeze out on cold surfaces
– Corrosion in combination with free water
• H2S
– 4 ppmv
– Product specification
• Water
– <0.1 – 0.5 ppmv
– Freeze out on cold surfaces
• Mercury
– < 0.01 mikro-g/Nm3
– Solidification and reaction with aluminium /corrosion
• Aromatic (benzene/toluene) and heavy hydrocarbons
– 1 – 10 ppmv
– Freeze out on cold surfaces
CO2 solubility in LNG
(-73°C)
(-101°C)
(-129°C)
(-157°C)
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Acid Gas TreatingMain methods for acid gas removal
• Absorption process
– Washing process using a solvent for separation of sour components (CO2, H2S etc) from the gas
– Chemical absorption
– Physical absorption
– Hybrid process
• Adsorption
– Using a solid surface
• Other
– Membranes
– Cryogenic separation
– Freeze out
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Absorption processes• Physical absorption process.
– Based on solubility of CO2 in a chemical (Rectisol ,Selexol, Purisol)
– Advantageous at high partial pressures of CO2 ( PCO2 = YCO2 * P)
– Disadvantage - Co solution of hydrocarbons
• Chemical absorption process.
– Based on exothermic reversible chemical reaction (solvent heats up)
• Alkanolamines most common
– MEA, DEA, MDEA DIPA
– Mixed amines (MDEA + piperazine). Activated or accelerated MDEA
– Regenerated by endothermic stripping process (heat supplied)
• Disadvantage – Regeneration energy (varies with chemical)
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Adsorption processes (Cont.)
• Hybrid solutions
– Mixed physical and chemical (Sulfinol )
• Alkanolamines short names:
MEA –monoethanolamine
DEA –diethanolamine
MDEA –Methyl Di-Ethanol Amine
aMDEA – activated MDEA
DGA –diglycolamine
DIPA –di-isopropanolamine
• Most cost effective for larger plant, but also applied for smaller plant like Kollsnes LNG plant.
• Most amines are water based solutions which need drying afterwards
• For Hammerfest a BASF process is selected with about 50 wt% MDEA in the water. An activator/accelerator is
also used.
Hammerfest LNG
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Other processes
• Adsorption
– Smaller concentration and flow rate
– Other sulphur components like mercaptans
• Membrane process
– Bulk removal
• Cryogenic removal
– Cooling and distillation
– High concentration
• Freeze out
– Taking advantage of low solubility
– Integrate in liquefaction part
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CO2 Removal
Gas Permeation
Amine
Potassium CarbonateInhibited Concentrated AmineGas Permeation
Phys
ical
Sol
vent
s+
Am
ine
Gas
Per
mea
tion
Partial Pressure Acid Gas – Product (psia)
Part
ial P
ress
ure
Aci
d G
as –
Feed
(psi
a)
0.1 1.0 10 100
10
1
100
1,000
Gas Permeation, Potassium Carbonate or Amine
Physical solvents or Potassium Carbonate
Physical Solvents
Physical Solvents
Physical Solvents
+ Amine/Potassium Carbonate
Gas Permeatio
n HammerfestPco2-feed: ~50 psiPco2-prod: ~0.05 psi
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CO2 and H2S Removal
Amine or Sulfinol
Amine, Sulfinolor Carbonates
EconomineSelexolDEA
Physical Solvents
Partial Pressure Acid Gas – Product (psia)
Part
ial P
ress
ure
Aci
d G
as –
Feed
(psi
a)
0.1 1.0 10 100
10
1
100
1,000
Physical solvents or Economine
HammerfestPco2-feed: ~50 psiPco2-prod: ~0.05 psi
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Criteria for solvent selection• Feed gas characteristic (CO2 content, H2S content etc).
• Ability to meet the specifications
• Rate capability
– Reaction rate
– Diffusion rate
• Heat of reaction
• Loading capabilities.
– Desired to have high capability in absorber and low in stripper.
– Variation due to impact of other components and pressure
– Selectivity (CO2, H2S)
• Reliability in operation
– Foaming
– Fouling
– Corrosion (material selection)
• Chemical stability, volatility, toxicity, price
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Acid Gas TreatingPrincipal Amine system
MEA + H2S MEA hydrosulphide + heatMEA + H2O + CO2 MEA carbonate + heat
Purified Gas
Rich Amine
Lean Amine
Water
Gas
CO2CW
Hot Oil
Absorbing
High pressure and “Low” temperature
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Acid Gas Treating
MEA + H2SMEA hydrosulfide + heatMEA + H2O + CO2MEA carbonate + heat
Purified Gas
Rich Amine
Lean Amine
Water
Gas
CO2CW
Hot Oil
Regenerating
Low pressure and “High” temperature
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17CO2 Removal
Feed Gas
Feed Gas
Wash Water
Wash WaterWaste Water
Demin. Water
Demin. Water
Rich MDEA
Reg. gas
Treated gas to Dehydration
Lean MEG
Water Saturated
5.3 vol% CO2 p = 66 baraT = 32 ºC
MEG wash
p = 66 baraT = 45 ºC Treated Gas
Wash Column, MDEA Wash
p = 65 baraT = 27 ºC
N2
Anti Foam
22-QT-101 Package Unit
Lean MDEA
Lean MDEA
Lean MDEA
MEG/CO2Absorber Column
p = 2 baraT = 44 ºC
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18CO2 Removal
Tempered Heating Water
MDEA Drain
Skimming Header
Anti Foam
Rich MDEA
Wash Water
CO2Stripper
HC-Waste
Demin. Water
N2
Lean MDEA to part I
MDEA
Stabilizer Overhead
Flash Gas
Water Purge
p = 1.5 bara T = 113 ºC
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Lean MDEA
SW
SW
H2O/Acid Gas mixture
p = 1.2 bara T = 20 ºC
CO2Separator
CO2
SW
SW
Lean MDEA
MDEA Storage Tank
H.O.H.O.
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CO2 loading. Example• Absorber
– Low or medium temperature
• Stripper
– High temperature
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Packed column design
Increase contact area
Increased efficiency
Reduced flooding and pressure drop
Reduce height, diameter and weight
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Dehydration• Specifications is important for process selection
• The water removal process start at the wellhead
• Typical processes
– Cooling and expansion combined with separation process
– Absorption process
– Adsorption process
• The natural gas will be saturated with water from the amine process.
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Hydrates! –> MEG injectionHYDRATE EQUILIBRIUM CURVES
WEIGTH % MEG (OF TOTAL MEG AND WATER)
0
50
100
150
200
250
-20 -10 0 10 20 30
TEMPERATURE [C]
PRES
SUR
E [B
AR
A] Water
10 w%MEG20 w% MEG30 w% MEG40 w% MEG50 w% MEG
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Water content in natural gas
P-T diagram
0
20
40
60
80
100
120
140
160
180
200
-150 -100 -50 0 50 100 150
Temperatur [C]
Tryk
k [B
ar]
Hydrokarbon
VannHydrat
DIAGRAM
PVT MODEL
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Gas Drying by adsorption • Adsorption in to a solid material
– Used in “deep” gas processing like Kårstø, Snøhvit with cold process systems
– Removal of smaller amounts of water
– Extreme dryness, down to 0.1 ppm
• Dehydration to this specification is the exclusive field of molecular sieves.
• Porous structure that contains very large internal surface area
– 200 – 800 m2/g
• Strong affinity for water
– 5 – 15 % by weight
• Solids like
– Molecular sieve (3A or 4A type)
– Silica gel
• Regenerative process
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Water removal by adsorption
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LNG from Fuel GasH.O.
H.O.
Effluent
Condensate
Water content of 700 mol ppm p = 64.5 bara T = 27 ºC
LNGDrying Line
Treated gas
3 parallel Molecular Sieve Beds
T = 233 ºC
Dehydration/Mercury removalReg. gas for MDEA Wash Tempered
WaterT = 23 ºC
0.1 mol ppm 150 ng/Sm3 Hg
C1 Make-up Reg. gas
10 ng/Sm3
Hg
T = 233 ºC
Dry
Fee
d G
as to
Li
quef
actio
n
LNG to Distribution
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Mass transfer in adsorption bed
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Mercury removal• Chemical reaction with aluminium. Corrosion
• Health, safety and environmental
• Requirement: < 0.01 μg/Nm3 (Detection limit in earlier days)
• Detection limit
– 0.002 – 0.003 microgram/Nm3
• Speciation (Type of mercury components)
– Elementary in gas
– Ionic (in water)
– Organic / metallic species
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Mercury removal in bed
Reaction between Hg and metal sulphide (typical alumina) formingHgS.Removal and regeneration in special plantsTypical intervals 6 years
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Bed loading Hg removal
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Fixed bed removal of Hg
www.synetix.com
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Heavy Hydrocarbon removal• Obtaining sales specification related to GCV and wobbe index
• Removal of heavy hydrocarbons with low solubility in LNG
– Special aromatics like benzene and toluene
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Nat
ural
Gas
Liq
uefa
ctio
nC
ircui
ting
Feedgas frompre-processing
LNG
LPG FractionationRefrigerant make-up
Precooling SubcoolingLique-faction
N2/CH4 tonitrogenremoval
CH4 fromnitrogenremoval
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Hydrocarbon (+N2,CO2) phase envelope
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Some general points on process selection• Depending on the feed concentration
• Capital costs
• Energy consumption and operational costs
• Environmental aspects
– Hydrocarbon losses
– Chemical losses
– Type of chemicals
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Inlet facilitiesMetering
Bulk water
Condensate treatment
Mercuryremoval
Acid gastreating
Dehydration Pre-coolingLiquefaction
LNG storage LNG loadingand jetty
LPG storage
Condensate storage
FractionationRefrigerantmakeup
Fuel gasNitrogenremovalFuel gas
MercuryWater
Nitrogen
H2S, CO2
LNGto ship
LPGto ship
Condensateto ship
Slug catcherand pigtrap
Hydrate inhibition recovery
UtilitySystem
FlareFacilities
Controlroom
Feed
Leanhydrate inhibition
General Block Diagram
Remove H2S and CO2 to
avoid solids in LNG HXs
Avoid ice in liquefaction
Mercury cause corrosion of Aluminium
HXObtaining
GCV. Removal of heavies