White - LNG Processing Presentation

1. L N G P R O C E S S I N G P R E S E N T A T I O N

2. AGENDA
• LNG Process Overview
• Major Process Units
• Calculation of LNG Production Capacity
– LNG4/5 used as an example
– Comparison with other liquefaction processes
• Impact of High Nitrogen Feed Gas
• Rules of Thumb

3. LNG PROCESS OVERVIEW

4. LNG TRAIN
GAS LNG
Energy consumption
Energy rejection
LNG Train

5. Energy rejection
(Condenser)
Cooling
(Evaporator)
Simple Refrigeration Cycle
Pressure
Let-down
ENERGY
PRESSURE

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LNG Processing
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28 June 2005
DRIMS#2039387
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WHAT IS LNG
Methane Gas Liquefied Natural Gas
Temperature 110 deg C (in reservoir) -162 deg C
Pressure 200 bar (in reservoir) 1 bar
Specific Volume 600 1
Density (kg/m3) 0.75 460
(at 15C and 1 bar)
Natural Gas to LNG

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LNG Processing
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28 June 2005
DRIMS#2039387
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Specification Typical Value
Methane min. 84 mol% ~ 87 mol%
Ethane balance ~ 8 mol%
Propane balance ~ 3 mol%
Butanes max. 2 mol% ~ 0.8 mol%
Pentanes + max. 0.1 mol% ~ 0 mol%
Mercury max. 10 ng/Sm³ ~ 0 ng/Sm³
Hydrogen Sulphide max. 5 mg/Sm³ ~ 0 mg/Sm³
HHV 1050 - 1170 Btu/ft³ 1110 - 1150 Btu/ft³
LNG Specification

8. Title :
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LNG Processing
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28 June 2005
DRIMS#2039387
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LNG Specification
Specification US Gas Japan LNG
West. Aust
Pipeline Gas
Main Reason(s)
Higher Heating Value (min) 970 Btu/Scf 1070 Btu/Scf 37.3 MJ/Sm3 Combustion limits
Higher Heating Value (max) 1150 Btu/Scf 1170 Btu/Scf 42.3 MJ/Sm3 Combustion limits
Wobbe (max) - - 47.3 MJ/Sm3 Combustion limits
Wobbe (min) - - 51.0 MJ/Sm3 Combustion limits
Butanes - < 2.0 mol% - Liquid dropout
Pentanes plus < 0.2 mol% < 0.1 mol% - Liquid dropout
Hydrocarbon Dewpoint - - < 0 deg C Liquid dropout
Nitrogen - < 1.0 mol% - Stratification & rollover (LNG)
Carbon Dioxide < 0.1 mol% None 3.6 mol%
Corrosion if water wet / Freeze-out
(LNG)
Oxygen < 0.2 mol% - 0.2 mol% Unwanted combustion
Total Inerts - - 5.5 mol% Minimise “dead” gas
Water - None 48 mg/Sm3 Corrosion / Freeze-out
Hydrogen Sulphide < 5 mg/Sm3 < 5 mg/Sm3 < 2 mg/Sm3 Smell / toxicity
Total Sulphur (unodourised) 16ppm (vol) < 30 mg/Sm3 < 10 mg/Sm3 Smell / toxicity
Solids or impurities
Mercury
- None
<10 ng/Sm3
None Blockages / fouling
Corrosion (LNG)

9. LNG
Fuel
LPG
C5+
Acid Gas
Where does the feed go?
(Approximate!)

10. Title :
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LNG Processing
NWSV
28 June 2005
DRIMS#2039387
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Karratha Gas Plant Production
Production Mtpa Price A$/te Annual Sales
Value A$ millions
LNG 12.5
(LNG 1-4)
250 3125
Domgas 4.1
(600 TJ/d)
100 408
Condensate 3.78
(100,000 bpd)
560
(US$ 50/bbl)
2180
LPG 0.68
(2000 tpd)
300 204
Notes
1. Cost of petrol at the bowser is A$1/litre or A$1600/te.

11. • Proven Technology with excellent safety record
– In operation since 1969
– Odourless, colourless, non-corrosive and non toxic
– Non-explosive in liquid or vapour state in unconfined spaces
– No major spillage at sea (108 tankers operating)
– Only one major accident at the 37 operating facilities world-
wide
– Less wear and tear on equipment compared to coal, oil and
nuclear based power plants
– Easy to handle compared to coal and nuclear fuel
• Environmentally friendly
– No ash content
– No sulfur or heavy metals
– No radioactive wastes and power plant decommissioning
complexities
Advantages of LNG
HSE Issues Relating to LNG

12. MAJOR PROCESS UNITS

13. Existing
Fractionation
Existing
LNG Storage
& Loading
U4400
Fuel Gas
System
Existing
Flare
Systems
C3
C4
C5+
FEED
LNG
LNG
LNG Train 4
U1100
Acid Gas
Removal
U1300
Dehydration
U1500
Mercury
Removal
U1400
Liquefaction
Karratha Gas Plant
U1250
Thermal
Combustion
Unit
Condensate
Storage
& Loading
U4000
Power
Generation
U1600
Existing
Refrig.
Storage
U4700
Air
U6000
Fire
Fighting
U6400
Drainage
& Effluent
Treating
U4600
Closed
Loop
Cooling
Existing LNG Train
Gas to Perth
Existing Domgas Plant
Existing LNG Train
Existing LNG Train
AGR
Area
U4100
Heated
Water
U4800
Nitrogen
U1200
Sulfinol
Reclaimer
Unit

14. Karratha Gas plant

15. From V1303
V1101
P1103 A/B/C
AFA
E1103 A/B/C/D/E
S1101/2/3
Feed
Gas
NNF
To LP Fuel
Acid Gas
to unit 1250
V1104
Water
make-up
P1102 A/B
E1104 A/B Heated
Water
Unit 1100 – Acid Gas removal
E1102
Treated Gas to U1300
C1101A
C1101B
V1103
P1101 A/B/C
C1102
E1101
Solvent Regeneration

16. Vent Gas
From
U1100
V1251
Condesibles
V1252
Fuel Gas Flash Gas
Oxazolidone
A1251
P1251A/B
K1251
Unit 1250 - Thermal Combustion
1F-1251

17. C1301A
C1301C
C1301B
V1303
Dried Gas
to Mercury Unit
Unit 1300 - Dehydration
Gas From
Unit 1100
E1301
E1303
K1310
V1301
E1401E1432
V1302
Water / HC to Acid Gas Removal Unit
Flash gas to Fuel Gas System

18. C1501
Absorber
S1501
Dust Filter
Dried Gas
From U1300
Treated Gas
to Liquefaction
U1400
Unit 1500 - Mercury Removal

19. U1300 U1500
E1450
E1451
E1452
E1401E1432 E1402 E1403
E1410 E1425 E1420
K1410
K1420
V1410
E1421 E1422 E1423
P1402
E1404
P1401
V1401
C1401
E1406
E1460
E1413
E1405A
GT1420A
GT1410
K1450
C1410
Unit 1400 - Liquefaction
E1424
V1421
E1441 E1440
GAS
LNG
K-1430
V1430
V1431
V1432
V1440
U1800
(existing)
E1405B
GT1420B
HHP
HP
MP
LP
HMR
LMR
Scrub Column MCHE Nitrogen Rejection
Mixed Refrigerant
V1442
E1442
Propane Pre-Cooling

20. MCHE Heating and Cooling Curves
Temperature
Energy Transferred
0 An awful lot
GAS
LNG
PR
MR
Subcooling by
liquid expander
Ambient
Very cold

21. U1300 U1500
E1450
E1451
E1452
E1401E1432 E1402 E1403
E1410 E1425 E1420
K1410
K1420
V1410
E1421 E1422 E1423
P1402
E1404
P1401
V1401
C1401
E1406
E1460
E1413
E1405A
GT1420A
GT1410
K1450
C1410
Unit 1400 - Liquefaction
E1424
V1421
E1441 E1440
E1442
GAS
LNG
K-1430
V1442
V1430
V1431
V1432
V1440
U1800
(existing)
E1405B
GT1420B
HHP
HP
MP
LP
HMR
LMR

22. V4101
Unit 4100- Heated Water System
HP Nitrogen Blanket
P-4101A/B/C
To ATM
E-1301
Fr.7 GT Exhaust Gas
E4103
A-4101
Demin
Water
Consumers

23. Unit 4400 - Fuel Gas
HW
4E4404
V-4417
V-4422
V-4409
HW
4E4407
V-4410
V-4407
K4402
E4408
To TCU
To Domgas
To Fr.7 GTs
E4406
Flash Gas
from U1100
End Flash Gas
From TOT
To GTGs
LP System
HP System
HHP System
4V-4415
Water
to U1100
Flash Gas
from U1300
Cross-connection
to/from existing LP
fuel gas

24. Unit 4600 -Fresh Water Cooling System
V4620
GT1410
GT1420A/B
K1410/
1420
P4101A/B/
C/D
4K4402
K1450 K1430 K1310
E4620
From Demin
Water
Distribution

25. CALCULATION OF LNG
PRODUCTION CAPACITY
(USING LNG4/5 AS AN EXAMPLE)

26. Calculation of LNG Production Capacity
• LNG TECHMAX production rate RT at a given ambient temperature T is:
– RT = (PGT + PH)T / wT
• wT = specific power at T (typical values shown in Table P1, adjust for actual T
and temp ex MCHE)
• PGT = Gas turbine power at T as shown in Table P2
• PH = Helper motor power
• Annual LNG TECHMAX production capacity (PTECHMAX) is calculated by
summing for all ambient temperatures (T) the product of the TECHMAX rate
at T (RT) and the frequency with which T occurs (FT) i.e.:
– PTECHMAX = T (RT x FT)
• FT is obtained from the ambient temperature profile at the site (i.e. the hours
per year at each temperature) and is plotted in Figure P3 for KGP
• Annual LNG design production capacity (PLNG) is calculated from the product
of annual TECHMAX capacity (PTECHMAX) and overall plant availability (A):
– PLNG = PTECHMAX x A
• Spreadsheet developed to facilitate these calculations

27. Example - LNG4 Production Capacity
• Select nominal annual LNG design production capacity (PLNG = 4 MTPA)
• Determine average ambient temperature Tav for the site
– For Karratha Tav = 27 + 2 = 29oC (from Figure P3))
• Select refrigeration cycle (C3/MR) and determine specific power at Tav
– wav = 12.0 kW/tpd (from Figure P1)
• Select GT type and number (2 x Frame 7) and determine power output at Tav:
– PGT = 73,000 kW per machine (from Figure P2 or Tables P2 and P3)
• Estimate overall plant availability (A = 0.93)
• Check annual LNG production PLNG rate can be achieved based on Tav:
– PLNG = (PGT + PH)T / wT = 365 x 0.93 x 2 x 73,000 / 12.0 = 4.1 MTPA
• Select helper motor size PH (>= starting load)
– PR = 11,000 kW, MR = 20,000 kW
• Confirm annual LNG production (PLNG) by summing for all ambient temps (T)
the product of the production rate at T (RT), based on the installed power, the
frequency (FT) with which T occurs (from Figure P3) and the overall plant
availability (A):
– PLNG = T (RT x FT) x A = T (((PGT + PH)T / wT) x FT) x A = 4.6 MTPA (rated)

28. LNG Capacity Definitions
 Design Process Flow Rate*
– Also referred to as Heat and Material Balance Capacity
 Technical Maximum Capacity (TECHMAX)*
– Equivalent to the Design Process Flow Rate for an operating plant
 Guaranteed Capacity*
– Design process flow rate less Process Licensor margin (2.5% for LNG4)
 Nameplate Capacity#
– Design process flow rate less onshore and offshore planned and un-
planned outages (9.8% for LNG4?)
 Annualised Technical Rundown#
– Less system effects/planning margins (3.5% for LNG4?)
 Annualised Technical Loadable Volume (or ACQ for FOB ships)#
– Less boil-off gas losses (typically 3% for new plant)
* Annualised rate given on a stream day basis
# Annualised rate given on a calendar day basis

29. Figure P1
Impact of Ambient Temperature on LNG Specific Power

30. Figure P2
Impact of Ambient Temp on Gas Turbine Performance
Frame 7 Available Power
y = -0.5219x + 88.335
R2
= 1
y = -0.5271x + 87.582
R2
= 1
65
70
75
80
15 20 25 30 35 40
Temperature, o
C
Power,
MW
KT-1430
KT-1410

31. Figure P3
Impact of Ambient Temperature on LNG Production
Ambient Temperature Distribution
0
1
00
200
300
400
500
600
700
800
900
1
0 1
5 20 25 30 35 40 45
Temperature
o
C
Hours
per
Year

32. Figure P4
Impact of Ambient Temperature on LNG Production
LNG4 Tmax - Comparisons
10000
10500
11000
11500
12000
12500
13000
13500
14000
14500
15000
20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40
AmbientTemp (C)
LNG4
Rundown
(TPD)
Design rundown
Daily Averages
Commit LNG4 Tmax
OTS Runs
Uncommitable Upside Tmax

33. Figure P5
Impact of Ambient Temperature on LNG Production
LNG TECHMAX PRODUCTION
3.50
4.00
4.50
5.00
5.50
0 10 20 30 40 50 60 70 80 90 100
Cumulative Hours %
MTPA

34. Figure P6
Impact of Ambient Temperature on LNG Production
LNG Production per Train
0
20
40
60
80
100
14 16 18 20 22 24 26 28 30 32 34 36 38 40 42
Temperature, o
C
LNG
Production,
%

35. Figure P7
Impact of Ambient Temperature on LNG Production
LNG HELPER MOTOR POWER
0.000
5.000
10.000
15.000
20.000
25.000
30.000
10 15 20 25 30 35 40 45
Ambient Temperature, o
C
Helper
Power,
MW
MR Helper PR Helper Total Helper

36. Figure P8
Impact of Refrigeration Temp on Theoretical
Refrigeration Power

37. Figure P9
Impact of Temp ex MCHE on LNG Specific Power
LNG4 AGAA Case

38. Figure P10
Impact of Temp ex MCHE on LNG Production
THEORETICAL INCREASED PRODUCTION (AMBIENT TEMP 27OC)

39. Table P1a
Base Load Liquefaction Processes
Liquefaction Cycle Specific Power (1) Capacity
Range per
Train, Mtpa
kW/tpd kJ/kg Relative
to C3/MR
Propane Pre-cooled Mixed
Refrigerant (C3/MR)
12.2 1054 1.0 =< 5
Air Products APX 12.0 1035 0.98 =< 9
Double Mixed Refrigerant (DMR) 12.5 1080 1.02 =< 5 (2)
Cascade 14.1 1218 1.16 =< 3.5 (2)
Single Mixed Refrigerant (SMR) 14.5 1253 1.19 =< 3.8 (2)
BHP/Linde cLNG (Propane Pre-
cooled Double N2 Expander)
15.6 1520 1.44 =< 2.2
Notes
1. Specific powers are indicative and will depend on feed and ambient conditions and temp ex MCHE..
2. Larger train capacities possible by installing parallel items of equipment, such as compressors.
3. Data (except for APX) taken from LNG12 Conference Paper 3.3 “Comparison of Base Load
Liquefaction Processes” by K.J. Vink and R. Klein Nagelvoort, Shell International Oil products, B.V.

40. Table P1b
Small to Medium Scale Liquefaction Processes
Liquefaction Cycle Specific Power (Note 1) Capacity
Range
Mtpa
kW/tpd kJ/kg Relative
to C3/MR
Single Mixed Refrigerant (SMR) 15.3 1318 1.25 0.1 – 1
ABB NicheLNG (Double (Methane and
N2) Expander)
16.9 1460 1.39 0.3 – 1.5
BHP/Linde cLNG (Double N2 Expander) 17.6 1520 1.44 0.3 – 1.5
Pre-cooled Double Expander 15.6 1348 1.28 0.1 – 1.5
Double Expander 19.7 1702 1.61 <0.2
Pre-cooled Single Expander 19.7 1702 1.61 <0.2
Single Expander 23.2 2004 1.90 <0.1
Notes
1. Specific powers are indicative and will depend on feed and ambient conditions and temp ex MCHE.
2. Data taken from published vendor data (ABB and BHP/Linde) and article “Offshore and Smaller Scale
Liquefiers” by G.L. Johnson et al, Costain, published in LNG Journal.

41. Table P2
Gas Turbine Performance
Iso Power,
MWe
Iso Heat Rate
kJ/kWh
Iso Thermal
Efficiency %
te CO2 / MW
(Note 1)
Waste Heat
MWth/MWe
Frame 5
(PG5371(PA))
26.3 13,080 27.5 0.182 1.73
Frame 6
(M6581(B))
43.5 10825 33.3 0.150 1.25
Frame 7
(M7111(EA)
86.7 11022 32.7 0.153 1.29
LM2500-PE 23.3 9588 37.5 0.133 1.0
LM2500+ 25.9 8948 40.2 0.124 0.87
LM6000 43.1 8701 41.4 0.121 0.81
Trent 51.5 8753 41.1 0.122 0.82
Combined Cycle
(theoretical)
- - >50 <0.1 <0.5
Notes
1. CO2 emissions assume fuel gas LHV 50 MJ/kg and 2.5 kg CO2 produced per kg fuel gas burnt.
2. Waste heat recovery without supplemental firing and assumes 25% of waste heat not recoverable.
3. Data obtained from 1999/2000 Gas Turbine World Handbook and LNG4 vendor data.

42. Table P3
Gas Turbine De-rating Factors
De-Rating Factor Frame 5 Frame 7 LM6000
Iso Power, kW (PISO) 26,300 86,680 43,100
Inlet Losses (A) 0.99 0.982 0.99
Outlet Losses (B) 0.985 0.995 0.996
Aging (C) 0.97 0.97 0.97
Fouling (D) 0.98 0.98 0.98
TOTAL (A x B x C x D) 0.927 0.929 0.937
Temperature, kW/oC (E) 195 525 600
GT power PGT = PISO x A x B x C x D - E x (T - 15)

43. Table P4
Overall Cycle / Gas Turbine Efficiency
Frame 5 Frame 6 Frame 7 LM2500+ LM6000 Combined
Cycle
C3/MR 1.19 0.98 1.00 0.81 0.79 <0.65
DMR 1.21 1.00 1.02 0.83 0.81 <0.66
SMR 1.42 1.17 1.19 0.96 0.94 <0.77
Cascade 1.38 1.14 1.16 0.94 0.92 <0.75
NicheLNG 1.65 1.36 1.39 1.13 1.10 <0.90
Pre-cooled
double
expander
1.52 1.26 1.28 1.04 1.01 <0.83
Note: Efficiency indicated is relative to Frame 7 driven C3/MR.

44. Table P5
Overall Cycle / Gas Turbine CO2 Emissions
Frame 5 Frame 6 Frame 7 LM2500 LM6000 Combined
Cycle
C3/MR 0.30 0.25 0.25 0.20 0.20 <0.16
DMR 0.30 0.25 0.26 0.21 0.20 <0.17
SMR 0.36 0.29 0.30 0.24 0.24 <0.19
Cascade 0.35 0.29 0.29 0.24 0.23 <0.19
Double
Expander
0.41 0.34 0.35 0.28 0.28 <0.23
Pre-cooled
double
expander
0.38 0.32 0.32 0.26 0.25 <0.21
Note: Emissions indicated are te CO2 per te LNG produced by combustion in gas turbines
and do not include CO2 removed from the feed gas.

45. Title :
By :
Date :
Location :
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LNG Processing
NWSV
28 June 2005
DRIMS#2039387
‹#›
Figure P11
Combined Heat and Power
THERMAL EFFICIENCY OF CHP SCHEMES
(FIRED HEATER EFFICIENCY 90%, 25% OF HEAT IN GT EXHAUST NOT RECOVERABLE)
0.0
10.0
20.0
30.0
40.0
50.0
60.0
70.0
80.0
90.0
100.0
0 10 20 30 40 50 60 70 80 90 100
Power as a % of Total Energy Consumption
Overall
Thermal
Efficiency,
%
GT Efficiency 25% GT Efficiency 30% GT Efficiency 35% GT Efficiency 40%
GT Efficiency 50% Brow se OGP

46. IMPACT OF HIGH NITROGEN FEED GAS

47. Impact of High N2 Feed Gas on LNG Production
• A 1% increase in feed gas N2 would increase end flash gas (EFG)
rate by approx 10% (i.e. % of flow ex MCHE that flashes off) for a
given MCHE outlet temp, throughput and MR/PR compression
power – Figure N1
• Conversely, to maintain a fixed amount of EFG, a 1% increase in
feed gas N2 would require the MCHE outlet temperature to be
reduced by 1.5oC – Figure N2
• Each 1oC reduction in MCHE outlet temperature would reduce the
LNG run-down rate by approx 1% for a given MR/PR compression
power – Figure N3
• Therefore a 1% increase in feed gas N2 would reduce LNG
production by approx 1.5% – Figure N4
• Conversely to maintain LNG production would require an approx
10% increase in EFG compression capacity – Figure N5

48. Figure N1
Impact of N2 on LNG Production
IMPACT OF N2 IN FEED ON EFG PRODUCTION
(FIXED FEED RATEAND TEMP EX MCHE)
8
10
12
14
16
18
0.0 0.2 0.4 0.6 0.8 1.0 1.2 1.4 1.6 1.8 2.0 2.2 2.4 2.6 2.8 3.0
N2 in Feed, %
EFG
Production,
%
LNG4 LNG1/2/3

49. Figure N2
Impact of N2 on LNG Production
TEMPERATURE EX MCHE
(FIXED FEED RATEAND CONSTANT EFG CAPACITY)
-150
-145
-140
-135
-130
0.00 0.25 0.50 0.75 1.00 1.25 1.50 1.75 2.00 2.25 2.50 2.75 3.00
N2 in Feed, %
Temperature,
degC
LNG4 LNG1/2/3

50. Figure N3
Impact of N2 on LNG Production
Impact of Temp ex MCHE on LNG Rundown Rate
(Rundown Rate Relative to Average Gas (AG) Case)
85.0
90.0
95.0
100.0
105.0
110.0
-160.00 -155.00 -150.00 -145.00 -140.00 -135.00 -130.00 -125.00
Temp. ex MCHE, degC
LNG
Rundown
Rate,
%
LNG4, AG LNG1/2/3, AG LNG4, HN LNG1/2/3, HN

51. Figure N4
Impact of N2 on LNG Production
IMPACT OF N2 IN FEED ON LNG CAPACITY
(FIXED EFG COMPRESSION CAPACITY)
97
98
99
100
101
102
0.25 0.50 0.75 1.00 1.25 1.50 1.75 2.00 2.25 2.50 2.75
N2 in Feed, %
LNG
Capacity,
%
LNG4 Production LNG1/2/3 Production

52. Figure N5
Impact of N2 on LNG Production
Impact of EFG Flowrate on LNG Rundown Rate
(Rates are relative to Average Gas (AG) Case)
88
90
92
94
96
98
100
102
104
106
108
30 40 50 60 70 80 90 100 110 120 130 140 150 160 170 180 190
EFG Flowrate, %
LNG
Rundown
Rate,
%
LNG4, AG LNG1/2/3, AG LNG4, HN LNG1/2/3, HN

53. Figure N6
Impact of N2 on LNG Production
N2 CONTENT IN EFG AND LNG
(FIXED FEED RATEAND EFG CAPACITY)
0
5
10
15
20
25
30
35
40
0.0 0.5 1.0 1.5 2.0 2.5 3.0
N2 in Feed, %
%
N2
in
EFG
0.0
0.5
1.0
1.5
2.0
%
N2
in
LNG
LNG4 EFG LNG1/2/3 EFG LNG4 LNG LNG1/2/3 LNG

54. Impact of High N2 Feed Gas on Domgas
• Most nitrogen in LNG feed gas is flashed off as end flash
gas (EFG)
– If relative amount of EFG increased additional EFG mainly CH4
• EFG is compressed and used as fuel gas, excess routed
to Domgas (if available)
• With the high nitrogen levels in the EFG a Nitrogen
Rejection Unit (NRU) may be required to meet the
Domgas inerts spec
– Acceptability of venting NRU waste nitrogen stream (containing
~0.1% hydrocarbon) would need to be confirmed
– CO2 offsets may be required

55. Possible NRU Process Configuration
• Cryogenic process
– previous work by SGSI
indicated a Cryogenic unit
would be lower cost and more
proven than alternatives such
as PSA
• Single column with heat pump
– Relatively easy to model
– Meets required product
specifications
– However may not be optimum
cryogenic process design for
this application – further work
would be required to evaluate
this

56. NRU Costs
NRU CAPEX
0
20
40
60
80
100
120
0 200 400 600 800 1000 1200 1400 1600 1800 2000 2200 2400
Feed Flowrate, tpd
CAPEX,
A$
million

57. RULES OF THUMB

58. Gas Field
(Exploration & Development)
Pipeline Liquefaction
Plant
Ocean
Transportation
Receiving
Terminal
Gas Utilities/
Power Station
Gas
Processin
g Facilities
LNG
Liquefacti
on Plant
LNG Tank LNG
Loading
Terminal
Ocean
Transportation
LNG Carrier
(Discharging)
LNG
Tank
Gas
Utilities
Pipeline
Pipeline
Receiving
Terminal
LNG Carrier
(Loading)
Power
Station
Gas Fields
Regasificatio
n
Typical Supply Chain of a LNG Import Scheme
Gas
Processin
g Facilities
LNG
Liquefactio
n Plant
LNG Tank LNG
Loading
Terminal
Ocean
Transportation
LNG Carrier
(Discharging)
LNG
Tank
Gas
Utilities
Pipeline
Pipeline
Receiving
Terminal
LNG Carrier
(Loading)
Power
Station
Gas Fields
Regasificatio
n

59. LNG Supply Chain Rules of Thumb
• Gas reserves required to support an LNG development:
– 1 tcf of gas per Mtpa of LNG over 20 years
– Therefore a 4 Mtpa train would require 4 tcf
– Associated C5+ liquids (MMbbl) = CGR (bbl/mmscf) x tcf of gas
– One cargo pa equivalent to 10 MMSCFD offshore capacity
• Pipeline vs LNG development - determined by distance
from supplier to customer:
– <2500 km: pipeline
– >2500 km: LNG
• Number of ships:
– A 130,000 m3 ship can transport 1 MTPA from NWS to Japan
• Storage tank volumes:
– 1 cargo plus 3 days production (approx.)

60. Typical LNG CAPEX Breakdown
• LNG Supply Chain
– Upstream Development: 10%
– LNG Plant: 40%
– LNG Transportation: 30%
– Receiving and Re-gasification Terminal: 20%
• LNG Plant
– Pre-treatment: 6%
– Liquefaction: 50%
– Utilities: 16%
– LNG Storage: 18%
– Loading Facilities: 10%

61. LNG Costs (Australia)
• LNG plant :
– CAPEX = A$ 2900 (Plant Capacity (Mtpa) / 4.2)0.7 x 106
– CAPEX = US$ 520 / tpa LNG
– Note: Approx 1/3 of the CAPEX is materials (equipment and
bulks) and 2/3 is construction labour
• LNG train (liquefaction and pre-treatment):
– CAPEX = A$ 1600 (Train Capacity (Mtpa) / 4.2)0.7 x 106
– CAPEX = US$ 286 / tpa LNG
• OPEX: 3% of CAPEX PA
• Abandonment: 5% of CAPEX
• LNG Price: ~A$250/te

62. Typical LNG Train Costs (Australia)
0
200
400
600
800
1000
1200
1400
1600
1800
0 2000 4000 6000 8000 10000 12000 14000
Train Capacity, tpd
CAPEX,
A$
millions

63. Typical LNG Train Costs (Australia)
0
200
400
600
800
1000
1200
1400
1600
1800
2000
0.0 0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0 4.5
Train Capacity, Mtpa
CAPEX,
A$
/
tpa

64. Typical LNG Tank Costs (Australia)
0
20
40
60
80
100
120
60 80 100 120 140
LNG Tank Capacity x 1000 m³
LNG
Tank
Capital
Cost,
A$
millions
Single Containment Double Containment Full Containment

65. Typical LNG Tank Costs (Australia)
0
200
400
600
800
1000
1200
60 80 100 120 140
LNG Tank Capacity x 1000 m³
LNG
Tank
Capital
Cost
/
m
3
,
A$/m
3
Single Containment Double Containment Full Containment

66. Typical LNG Ship Costs
0
500
1000
1500
2000
2500
3000
3500
20 40 60 80 100 120 140
LNG Ship Capacity x 1000 m³
LNG
Vessel
Capital
Cost
per
m³,
A$/m3

67. Process Rules of Thumb (1)
• A 1oC increase in MCHE outlet temperature (for a given refrigeration
compression power):
– Increases MCHE throughput by approx 1.5%
– Increases the LNG run-down rate by approx 0.9%
– Increases proportion of MCHE throughput flashing off by approx 0.6%
(i.e. an increase in end flash gas rate of typically 6%)
• A 1oC increase in ambient temperature:
– Increases LNG specific power by approx 1.1%
– Reduces gas turbine output by approx 0.6%
– Reduces LNG production by approx 1.7%
• A 1 bar increase in feed pressure increases LNG production by
approx 0.7%
• A 1% increase in MW increases LNG production by approx 1.4%
Note: all capacity variations are on a mass basis.

68. Process Rules of Thumb (2)
• A 1% increase in feed gas N2 would increase end flash gas (EFG)
rate by approx 10% (for a given MCHE outlet temp, throughput and
MR/PR compression power)
• A 1% increase in feed gas N2 would require the MCHE outlet temp to
be reduced by 1.5oC to maintain a fixed amount of EFG
– This would reduce LNG production by approx 1.5%
– Conversely to maintain LNG production would require an approx 10%
increase in EFG compression capacity
• A 1% increase in propane condenser UA increases LNG production
by approx 0.3%
• A 15% increase in propane sub-cooler UA increases LNG production
by approx 0.8%
• Hydraulic turbines increase LNG production by ~4%:
– LNG hydraulic turbine ~2%
– MR hydraulic turbine ~2%

69. Process Rules of Thumb (3)
• Specific power for train 4 (C3/MR process):
– 12 kW/tpd (27oC average ambient, -145oC ex MCHE)
• Fuel gas consumption ~8% of feed flow (C3/MR)
• Mol sieve regeneration flow ~7% of feed gas flow
• CO2 produced by process:
– Combustion: 0.25 t CO2 / t LNG (Frame 7 driven C3/MR)
– From AGRU: 1 mol% CO2 in feed equates to approx 0.03 t CO2 / t LNG
• AGRU regeneration duty:
– Accelerated MDEA: 2400 kW / kg/s CO2 (27.8 kW/tpd CO2)
– Sulfinol: 3400 kW / kg/s CO2 (39.4 kW/tpd CO2)
• BOG losses from storage and loading facilities: ~3% of design rate
• Largest LNG tank capacity 200,000 m3
• Typical LNG train availability 93%

70. Background Reading / References
1. LNG12 conference paper “Comparison of Base Load Liquefaction Processes”
by K.J. Vink and R. Klein Nagelvoort, Shell International Oil products, B.V. (3.6).
2. LNG12 conference paper “Targeting and Achieving Lower Cost Liquefaction
Plants”, David Jamieson et al, Atlantic LNG (7.1).
3. LNG13 conference paper “Increasing LNG Train Capacity Through Higher
MCHE Outlet Temperatures”, Henri Paradowski and Philip Hagyard, Technip
(PS2-1).
4. LNG13 conference paper “A New Tool – Efficient and Accurate for LNG Plant
Design and Debottlenecking”, Hidefumi Omori et al (PS2-4).
5. “Production of LNG Using Dual Independent Expander Refrigeration Cycles”,
Jorge H. Foglietta, Randall Gas Technologies.
6. “Wheatstone Opportunity – Impact of High Nitrogen Feed Gas on LNG and
Domgas Production”, DRIMS# 1884488.
7. LNG4 Process Induction Presentation (Boris Ertl).
8. Maurutania Presentation, DRIMS# 1748812 (Murthy Eranki).

71. BACK-UP SLIDES

72. Table P3
Gas Turbine De-rating Factors
De-Rating Factor Frame 5
G5371(PA)
Frame 6
M6581(B)
Frame 7 LM2500–
PE
LM6000 Trent
Iso Power, kW (PISO) 26,300 43,530 86,680 23,300 43,100 51,460
Inlet Losses (A) 0.99 0.982 0.99
Outlet Losses (B) 0.985 0.995 0.996
Aging (C) 0.97 0.97 0.97
Fouling (D) 0.98 0.98 0.98
TOTAL (A x B x C x D) 0.927 0.929 0.937
Temperature, kW/oC (E) 195 525 90 600 (455?) 470
GT power PGT = PISO x A x B x C x D - E x (T - 15)

73. Tank designed and constructed so that:
•The primary container contains the refrigerated liquid and the secondary container
contains the vapour under normal operating conditions.
•The secondary container capable both of independently containing the refrigerated
liquid and of controlled venting of the vapour resulting from product leakage after a
credible event.
•The secondary container can be 1 m to 2 m distance from the primary container.
•The outer roof is supported by the secondary container.
FULL CONTAINMENT LNG STORAGE TANK
FULL CONTAINMENT LNG STORAGE TANK

74. Title :
By :
Date :
Location :
Slide No:
LNG Processing
NWSV
28 June 2005
DRIMS#2039387
‹#›
LNG Receiving and Re-gasification Terminal

75. Typical LNG Shipping Costs
0
500
1000
1500
2000
2500
3000
0 50 100 150
LNG Ship Capacity x 1000 m³
LNG
Vessel
Capital
cost/m³
of
capacity
0
20
40
60
80
100
120
140
LNG
Tariff
US
C/MMBtu
LNG Vessel Capital Cost US $/m³ capacity Ship Freight in US C/MMBtu

76. LNG Shipping
• LNG ship capacity 130,000 – 220,000 m3 ?
• Number of ships (N) required:
– N = LNG production pa / (No. round trips pa x ship capacity tonnes)
= MTPA / [365/((2D/24u)+2) x V x 0.46]
Where:
D = distance from LNG plant to customer terminal
u = ship speed (typically 25 km/h)
V = ship capacity in m3 (LNG density approx. 0.46 t/m3)
e.g. A 130,000 m3 ship can transport 1 MTPA from NWS to Japan
(approx. 11,500 km)
• BOG produced in transit: ~3.1% of inventory
– Natural BOG ~2.3%
– Forced BOG ~0.8%