Gas treating

Hammerfest LNG process

2008

2

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

Naturgass kjøletårn

Nitrogenfjerning kjøletårn Prosess

understasjon

Elektrisk kraftproduksjon

Kompresjonsområde, lekter

Prosessområde, lekter

23

1

HAMMERFEST LNG PLANT

OMRÅDE 2

4

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!

5

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

6

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)

7

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)

8

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

9

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)

10

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

11

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

12

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

13

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

14

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

15

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

16

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

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

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

14

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.

19

CO2 loading. Example• Absorber

– Low or medium temperature

• Stripper

– High temperature

20

Packed column design

Increase contact area

Increased efficiency

Reduced flooding and pressure drop

Reduce height, diameter and weight

21

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.

22

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

23

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

24

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

25

Water removal by adsorption

26

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

27

Mass transfer in adsorption bed

28

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

29

Mercury removal in bed

Reaction between Hg and metal sulphide (typical alumina) formingHgS.Removal and regeneration in special plantsTypical intervals 6 years

30

Bed loading Hg removal

31

Fixed bed removal of Hg

www.synetix.com

32

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

33

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

34

Hydrocarbon (+N2,CO2) phase envelope

35

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

36

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