Paper PS2-7
HOW TO REDUCE CO2 EMISSIONS IN THE LNG CHAIN
Pierre Rabeau
Henri Paradowski
Jocelyne Launois
with the participation of André Le Gall and Joelle Castel
Technip
Paris, France
ABSTRACT
LNG is a clean fuel and its use instead of other hydrocarbons reduces pollution and
CO2 emissions. However the liquefaction of natural gas to produce LNG, the
transportation in LNG carriers, the vaporization of LNG to produce natural gas, and the
use of that gas for the generation of electric power and heat produce large quantities of
CO2.
Whereas previous studies have examined costly and unproductive techniques for
capture and sequestration of CO2 at LNG production facilities, in this paper the reduction
of CO2 production and hence emissions at moderate cost are discussed at some levels of
the LNG plant, including the production of electric power and heat.
Based on the results of LNG projects, the contribution of each step to the total CO2
release in a typical LNG plant is analyzed.
The CO2 emissions are reduced when the energetic efficiency of the processes is
increased. Possibility to increase the efficiency is discussed on some process units:
Condensates Stabilization, NGL Recovery, Liquefaction and LNG End Flash.
The efficiency of the generation of heat and power is of prime importance and the
CO2 emissions of five different systems are compared.
The authors conclude that significant reductions of CO2 emissions can be obtained.
Some of them are easy to implement and do not generate complexity or reduced
availability. The fuel savings are sufficient to justify most of the proposed solutions from
an economic point of view. A CO2 tax could lead to the selection of more sophisticated
solutions less proven in the LNG industry.
PS2-7.1
Paper PS2-7
INTRODUCTION
Many authors have already discussed the subject of CO2 emissions in the LNG chain
and it is not the purpose of this paper to challenge the authors or present very innovative
solutions.
On the opposite what we wish to demonstrate is that very simple techniques, proven
on some projects, easy to use, can contribute to reduce significantly the CO2 emissions.
Natural gas is a clean fuel and its proper use produces limited amounts of CO2.
To reduce the CO2 emissions we will follow two routes, one on the process side, and
another one on the energy generation.
The possible process optimizations will be illustrated by few examples but many
other improvements are feasible.
The method used to determine CO2 emissions in each case study is rigorous. It takes
into account reduced efficiency of power generators when running at partial load. This
model is also considering the split between process units for all energy uses (steam,
electricity, fuel gas).
LNG CHAIN CO2 EMISSIONS
CO2 Emissions from Natural Gas
Natural gas can be used to produce power or heat. It is a much better fuel than liquid
hydrocarbons.
To produce power the emissions of CO2 depend on the technology that is used:
•
0.55 kg/kW.h for a simple cycle Industrial Gas Turbine,
•
0.39 kg/kW.h for a combined cycle.
To produce heat the emissions of CO2 depend on the temperature level and on the
technology that is used:
To produce heat at 150°C the emissions are the following:
•
0.23 kg/kW.h for direct fired heater,
•
0.13 kg/kW.h for recovery on Gas Turbine’s Exhaust Gases,
•
0.09 kg/kW.h for recovery on a Combined cycle.
To produce heat at 250°C the emissions are the following:
•
0.25 kg/kW.h for direct fired heater,
•
0.16 kg/kW.h for recovery on Gas Turbine’s Exhaust Gases.
If we use Propane instead of Natural Gas the emissions are 15% higher and the use of
Fuel Oil increases the emissions by more than 50%. This is due to the ratio of hydrogen
to carbon that is much lower in heavy hydrocarbons than in methane.
PS2-7.2
Paper PS2-7
Production of Natural Gas by Means of the LNG Chain
Large reserves of natural gas are located overseas and to be used in the countries that
need imports it is necessary to build an LNG chain:
•
Transportation of Natural gas to the LNG Plant,
•
Liquefaction and storage and loading of LNG on an LNG carrier,
•
Transportation of LNG,
•
Regasification of LNG.
Each of these steps produces CO2 emissions. Typical numbers for a Chain connecting
Nigeria to Europe [1] are as follows :
•
0.01 kg CO2/kg LNG for step 1
•
0.32 kg CO2/kg LNG for step 2
•
0.05 kg CO2/kg LNG for step 3
•
0.03 kg CO2/kg LNG for step 4
More than 75% of the CO2 emissions are due to the LNG plant.
Use of Natural gas
The production of electric power has been given a lot of consideration and very
efficient gas fired combined cycles are used. Research and development is on going and
should result in even better efficiencies.
The use of natural gas for domestic heating purposes is very inefficient from a
thermodynamic point of view. The development of the micro turbine technology is not
promoted as it should be.
LNG PRODUCTION PLANT
As the LNG plant is the main contributor to the CO2 emissions, we shall focus on this
subject.
There are two ways to increase the efficiency and decrease the emissions:
•
Improve the processes,
•
Improve the efficiency of the production of heat and power.
Of course there are many interactions between these two ways.
IMPROVE PROCESS TO REDUCE ENERGY REQUIREMENT
At first we have to analyze where the consumptions of energy and the emissions of
CO2 are located.
For a plant producing about 25 MTA of liquefied gases: Low Btu LNG, Propane and
Butane, the figures are summarized in Table 1 hereafter:
PS2-7.3
Paper PS2-7
Table 1 – CO2 balance for LNG plant
Process units
Warm units
Cold units
Storage and loading
Others
Total
%
14.0 %
82.0 %
2.2 %
1.8 %
100.0%
Tons/h of CO2
135
790
21
17
963
The cold units that are the NGL recovery and the LNG production are the main
contributors but the warm units that include the Condensates Stabilization, the Acid Gas
Removal unit and the Dehydration should not be neglected.
Use of Heat Integration in Warm Pre-Treatment Units
The condensate stabilization unit represents 20 to 45% of the CO2 emissions of the
“warm units” depending on the heat power generation systems that are used and that will
be discussed later on. To reduce the energy consumption we do have two main
possibilities:
•
Optimize the process scheme to obtain a better heat integration,
•
Optimize the operating parameters, mainly the pressure of the stabilizer.
We will show the improvements obtained on the stabilizer reboiler duty and on the off
gas compressor power.
Condensates Stabilisation Unit Heat Integration. The simplest process scheme
used for the condensates stabilization is shown of figure 1a.
HP Gas
K2
K1
M
A2
A1
HP Feed
V3
V4
55 bar
15°C
9 bar
V1
25 bar
E1
V2
Stabilized
C5+
A3
40°C
HP steam
E2
Figure 1a – Condensates Stabilization unit
PS2-7.4
Paper PS2-7
In this scheme n° 1, the feed from the MP separator is split in two parts:
•
One is cold and fed on the first tray of the stabilizer,
•
The second is heated against the hot condensates from the bottom of the column.
In a second scheme we add a reflux to the stabilizer to decrease the power of the off
gas compressor.
In a third scheme we add a side reboiler to scheme n°2,
In a fourth scheme that is shown on figure 1b we add a second side reboiler.
HP Gas
K2
K1
M
A2
HP Feed
A1
8 bar
V3
V4
55 bar
15°C
V1
A4
25 bar
V5
E1
V2
E4
Stabilized
C5+
A3
E3
40°C
HP steam
E2
Figure 1b – Condensates Stabilization Unit Heat Integration
For each scheme we optimize the pressure of the stabilizer to obtain the lowest CO2
emissions. The improvements obtained on the stabilizer reboiler duty and on the off gas
compressor are shown on Table 2.
Table 2 – Condensates stabilization heat integration results
Reboiler duty
Off gas compressor power
CO2 emissions
Stabilizer pressure
kW
kW
T/h
Bar
Scheme 1
53.6
11.2
24
9
PS2-7.5
Scheme 2
54.5
10.9
24
8.5
Scheme 3
42.2
11.4
20.6
8
Scheme 4
38.4
11.3
19.4
8
Paper PS2-7
The conclusion is that 20% savings can easily be obtained on that process by using
heat integration and by optimization of the stabilizer pressure. The use of side boilers
does not affect the operability of the unit.
Condensates Stabilization Column Pressure. On a second study, the stabilizer
pressure only has been varied. The results are shown on Table 3.
Table 3 – Condensates Stabilization Pressure Variation
Stabilizer pressure
Reboiler duty
Off gas compressor power
CO2 emissions
Bar
KW
KW
T/h
9.5
43.3
10.2
20.1
9
41.8
10.5
19.9
8.5
40
10.9
19.6
8
38.4
11.3
19.4
The conclusion is that 5% savings can easily be obtained on that process by
optimisation of the stabilizer pressure.
Use of CFD to optimize the LNG Process efficiency
The process that is selected in this example to quantify the benefits of designs done
with CFD is the C3-MR process from APCI. A schematic is shown on figure 2.
LNG
MR Compression
Helper
MCHE
GT
-37° C
MP
HP
LP
60 bar
40° C
C3R Compression
Starter
GT
MR Separator
LLP
LP
MP
-34° C
60° C
HP
d H2o
40° C
70 bar
40° C
NGL
HP Gas
Figure 2 – Liquefaction unit
The line up is very simple. The propane precooling uses 4 pressure stages: LLP, LP,
MP and HP. The propane compressor has 2 casings : one for LLP, LP, and MP stages and
another for HP. A single shaft gas turbine rotating at 3000 RPM drives the propane
compressor. The propane is condensed in air coolers at about 60°C and is sub cooled to
40°C prior to being sent to the kettle type evaporators. The MR is compressed in 3 stages:
PS2-7.6
Paper PS2-7
LP, MP and HP. The MR compressor has two casings: one for LP and another one for
MP and HP MR. A single shaft gas turbine rotating at 3000 RPM drives the MR
compressors. A variable speed helper motor provides additional power to the turbine.
C3 Precooling Kettles. The pre cooling process uses high efficiency Wieland tubes.
This makes it possible to use a cold end approach of 2°C instead of 3°C that is currently
used. The reduction of the approach makes it feasible to save 1500 kW per propane cycle
in each train. The total savings are then 6000 kW for the LNG plant, which correspond to
a reduction of CO2 emissions of about 4 T/h. The kettles are rather compact and it is
necessary to use CFD to determine the following details:
•
The dimensions of the kettle,
•
The size and the location of the inlet propane distributor,
•
The size and location of the mist eliminator,
•
The number, dimensions and location of the outlet nozzles.
Without the use of CFD, it would be almost impossible to obtain a robust design. On
figure 3, the geometry of the kettle and the velocity magnitude of the propane vapour are
shown.
Figure 3 – Velocities in C3 Pre-cooling Kettle
Decrease of Pressure Drop in Compressor Lines. In an LNG train the lines
connecting the exchangers to the suction of the refrigerant compressors are of very large
diameter (up to 80 inches); there are also valves, strainers, and suction drum internals.
Without the use of CFD, it is very difficult to optimize the line routing and obtain low
pressure drops and acceptable velocity profiles at the inlet of the suction drum and at the
inlet of the compressor.
PS2-7.7
Paper PS2-7
When CFD is used for design then it is possible to reduce the pressure drops at
compressor suction from the conventional 0.15 bars to 0.10 bars. By doing that we can
save 1600 kW per LNG train, that is 6400 kW for the LNG plant and 4 t/h of CO2
emissions.
On figures 4a and 4b the LP MR line connecting the MCHE to the LP MR suction
drum is shown.
Figure 4a – Model for LP MR Line from MCHE to Suction Drum
Figure 4b – Pressure profile in LP MR Line from MCHE to Suction Drum
PS2-7.8
Paper PS2-7
Optimization of Suction Drums. Another area where CFD has become a design tool
is the design of the suction drums.
With use of CFD it has become obvious that the feed distributors previously used,
such as half open pipes, were not able to ensure a proper distribution of gas in large KO
drums.
The vane type distributor has proved to be much more efficient.
Many separation drums have been retrofitted with this type of distributor in capacity
enhancement projects and the results have always been good.
For new projects the size of the suction drum will depend on the capacity of the mist
eliminator but also on nozzle diameters, distances between the distributor and the mist
eliminator and distance between the distributor and the liquid level.
On figure 5 we can see a KOD designed with the use of CFD.
Figure 5 – Velocities in Knock Out Drum
Integration of NGL recovery and LNG units
The cold units that are the NGL recovery and the LNG production are the main
contributors to the consumption of fuel gas and therefore for the emissions of CO2.
The successful integration of the NGL unit with the LNG unit is very important.
PS2-7.9
Paper PS2-7
Two main parameters are to be considered:
•
The pressure of the recovery tower in the NGL unit,
•
The pressure of the gas sent to the liquefaction.
Pressure of Recovery Tower. A schematic of the NGL recovery unit is presented on
figure 6. The process selected ensures a propane recovery of more than 98%.
Dry feed gas
Turbo-expander
De-ethanizer T2
Treated gas
to compression
Cold box
Recovery tower
T1
C3R
V1
C3R
C2
LP steam
P1
NGL
Figure 6 – NGL Recovery Unit
The dry feed gas is cooled to about –43 °C and partly condensed in the cold box.
Vapor and liquid are separated in the cold separator V1. The vapor is sent to the turboexpander where it is cooled and partly condensed by means of an isentropic expansion.
The resulting two-phase flow is sent to the Recovery Tower operating at 20.5 bars. The
liquid from the cold separator is directly sent to the bottom of the recovery tower. The
liquid from the bottom of the recovery tower is sent to the de-ethanizer after reheating in
the cold box.
The de-ethanizer is operated at a pressure slightly higher than the Recovery tower. It
produces a C3+ cut that is sent to the fractionation, a C2 cut used for refrigerant make-up
and a vapor distillate that is a methane-ethane mixture. The vapor distillate is condensed
in the cold-box and sent to the recovery tower as reflux. The Vapor from the Recovery
Tower is reheated in the cold box and compressed in the compressor driven by the
expander to about 24 bars. The treated gas is compressed in a booster compressor to the
liquefaction pressure. (Refer to figure 7).
Propane refrigerant from the liquefaction unit is used in the cold box to supply
refrigeration required at about –30°C.
PS2-7.10
Paper PS2-7
The recovery tower pressure has to be optimized. When the pressure is increased, the
power of the expander is reduced and more propane is required. The power of the booster
compressor is decreased but additional power is required from the propane cycle. Results
are shown in Table 4.
Table 4 – NGL Recovery Optimization results
Recovery
Cold
Propane
Booster
Propane Total
CO2
tower
separator refrigerant compressor compressor power emissions
pressure temperature
flow rate
power
power
Bars
°C
Kmoles/h
MW
MW
MW
T/h
20.5
-42.8
2030
40.3
3.4
43.7
26.2
21.5
-43.8
2350
38.7
3.9
42.6
25.6
22.5
-45
2620
37.4
5.2
42.6
25.6
23.5
-46.2
3000
36.0
6
42.1
25.3
24.5
-47.3
3370
34.8
6.8
41.6
25.
25.5
-48.4
3800
34.6
7.8
42.4
25.4
26.5
-49.3
4300
34.4
8.9
43.3
26
27.5
-50.1
5600
34.2
10
44.2
26.5
28.5
-50.9
6600
33.9
11.7
45.6
27.4
A careful optimization of the recovery tower pressure can save about 2 MW of energy
per LNG train (i.e. 8 MW for the LNG plant) and 5% on CO2 emissions.
Booster Compressor Discharge Pressure. The discharge pressure of the Booster
Compressor can be selected so as to minimize the power consumption and the CO2
emissions. When the gas to be liquefied is available at the MCHE inlet at high pressure it
is much easier to liquefy. The MR can then contain more propane and less methane.
The results of a detailed study are shown on Table 5 here below. High pressure gives
a significant benefit: 13 MW per train are saved when the gas is liquefied at 67.8 Bars
instead of 47.8. This reduces the CO2 emissions by 31 T/h for the LNG plant.
Table 5 – Booster Compressor Discharge Pressure Optimisation
NG
Pressure at
MCHE inlet
Bars
42.8
47.8
52.8
57.8
62.8
67.8
NG Booster
Power
MW
17.2
21.5
25.3
28.8
32.2
35.3
MR
compressor
Power
MW
153.9
145.2
139.6
133.4
128.9
124.5
Propane Total Power Total Power
compressor
Power
MW
MW
%
88.0
259.1
107.6
87.0
253.7
105.4
84.2
249.1
103.4
83.0
245.2
101.8
81.7
242.8
100.8
81.0
240.8
100.0
PS2-7.11
Paper PS2-7
Use of LNG Deep flash
At the outlet of the MCHE the LNG is often sent to an End Flash unit.
The use of End Flash has many advantages:
•
Reduced size of the MCHE,
•
Reduced power and volume flow rate of the MR compressor,
•
Produces high quality Fuel Gas,
•
Eliminates from LNG light components such as Nitrogen, Oxygen, and Helium.
•
Prevents high LNG flash at LNG tank inlet
With the line up that is considered in this paper and that is shown on figure 7, one
question arises: would it be beneficial to produce more end flash gas than necessary for
the fuel and recycle the excess Fuel Gas to the suction of the Booster Compressor ?
Dry gas
50 bar
NGL Recovery
Liquefaction
Gas
compression
70 bar
EFG
Compression
LNG
M
M
NGL
30 bar
EFG recycle
LNG
Fuel gas
Figure 7 – End Flash Gas Unit
A study was conducted with variation of the temperature of the LNG at the outlet of
the MCHE. The results are presented on Table 6 here after for a constant LNG
production.
PS2-7.12
Paper PS2-7
Table 6 – Deep End Flash Study Results
Temperature of LNG at
outlet of MCHE
End Flash gas
compressor power
MR compressor power
C3R compressor power
NG Booster compressor
power
Total power of
compressors
Total power of
compressors
°C
-136.25
-141.25
-146.25
-151.25
-156.25
MW
32.1
24.8
17.9
11.2
5.6
MW
MW
MW
103.9
82.7
39.2
110.2
82.5
37.7
118.4
82.3
36.3
126.8
80.7
34.9
141.6
83
33.7
MW
257.9
255.2
253.9
253.6
253.9
%
101.7
100.6
100.1
100
100.1
The total power is fairly constant in a large range of temperature. The split of the
power is different. Increasing the End Flash leads to a decrease of power of the MR
compressor and increases the power of End Flash Gas compressor and the power of the
NG Booster compressor. The choice can then be dictated by the energetic scheme and the
selection of the driver for the End Flash Gas compressor.
BETTER ENERGY INTEGRATION TO REDUCE CO2 EMISSION
A rigorous model linked to all the process units and reflecting the reduced efficiency
due to running N+1 power generators at a partial load has been considered. This model
allows to determine CO2 emissions in a multicase study. This model is identical to the
ones used on the large LNG projects.
Base Case
A common practice in existing LNG plant is to use steam as heating medium and to
produce it in package boilers, to use gas turbines as refrigerant compressor drivers and to
produce electricity with another set of gas turbines in a dedicated power generation unit
as shown on figure 8.
By allocating shares of steam and electricity to the consuming process units, a CO2
balance per process units has been established and is presented in Table 7 here below as
the base case. The CO2 contained in the feed gas and rejected to the atmosphere from the
acid gas removal unit is not included in this balance because capture and reinjection of
CO2 is not considered in this paper.
PS2-7.13
Paper PS2-7
FG
MOTOR
LP MR
MP/HP MR
GE9
PROCESS HEAT
EXCHANGERS
FG
PACKAGE
BOILER
BFW
MOTOR
LP C3
HP C3
GE9
BFW
LS
BFW
Figure 8 – Base Case Energy Scheme
The process units have been grouped in four different entities.
•
Warm units are the inlet facilities, acid gas removal, dehydration and mercury
removal units.
•
Cold units are the NGL recovery, Fractionation, Liquefaction and End flash units.
•
The storage and loading are for LNG, LPG and Condensates storage and loading.
•
Others are for Excess steam air coolers and Fuel gas heater, water and air utility
units.
The main contributors of the inlet facilities and of the acid gas removal units are the
steam consumptions. The main contributors of the NGL recovery, liquefaction and end
flash units are the refrigerant compressor drivers and the refrigeration air coolers. The
main contributors of the storage and loading units are the loading pumps and compressor
drivers.
Table 7 – CO2 Balance for base case
Process units
Warm units
Cold units
Storage and loading
Others
Total
% Tons/h of CO2
14.0 %
135
82.0 %
790
2.2 %
21
1.8 %
17
100.0 %
963
PS2-7.14
Paper PS2-7
Use of Heat Recovery Steam Generation
The idea of reducing CO2 emissions by applying better energy integration at the
sources led us to consider the well-known and mature technology of heat recovery steam
generation (HRSG).
In the first case, the steam generation though HRSG has been adjusted to the steam
demand (figure 9) In this configuration, only one gas turbine needs to be equipped with a
HRSG system. Conventional steam pressure level has been selected and at the same time
a back pressure steam turbine has been added to replace the electric motor driving the end
flash gas compressor.
FG
EFG
MOTOR
LP MR
MP/HP MR
GE9
PROCESS HEAT
EXCHANGERS
FG
HRSG
BFW
BFW
MOTOR
LP C3
HP C3
GE9
LS
BFW
Figure 9 – Heat Recovery on One Gas Turbine
In the second case, the two gas turbines have been equipped with HSRG and the
excess steam is used to produce electricity within the LNG trains through condensing
steam turbines generators (figure 10).
PS2-7.15
Paper PS2-7
FG
HRSG
EFG
BFW
MOTOR
LP
MR
MP/HP MR
GE9
PROCESS HEAT
EXCHANGERS
FG
HRSG
G
BFW
BFW
MOTOR
LP
C3
HP
C3
GE9
LS
BFW
Figure 10 – Heat Recovery on Two Gas Turbine and Electricity Generation
The CO2 balance showing the emissions reduction is shown in Table 8.
Table 8 – CO2 balance for one HRSG per train and two HRSG per train
Number of HRSG
Process units
Warm units
Cold units
Storage and loading
Others
Total
One per train
%
7.4%
88.2%
2.8%
1.6%
100.0%
Tons/h of
CO2
61
725
22
13
821
Two per train
Tons/h of
%
CO2
7.5%
51
90.0%
614
1.4%
10
1.1%
7
100.0%
682
It can be observed that for one HRSG per train, the main benefit on the reduction of
CO2 emissions is within the warm units (mainly inlet facilities and amine unit) because
of the steam generation package boilers deletion. With two HRSG per train, the reduction
is observed everywhere because of the reduction of CO2 emission in the power
generation unit. Compared to the base case, CO2 emissions have been reduced by about
15% by using one HRSG per train and by about 30% by using two HRSG per train.
Use of Combined Cycle in Power Generation Unit
The next technique that is available and can be applied in the power generation unit is
to use aero-derivative gas turbines known for their better efficiency than the widely used
heavy-duty gas turbines. The comparison has been done on the basis of the GE LM6000
PS2-7.16
Paper PS2-7
aero-derivative gas turbine but many other possibilities exist as described by Peterson [2],
Avidan [3] and Yates [4].
Finally, this idea can be extended by using combined cycle power generation instead
of open cycles. The new case with combined cycle has been done on the basis of the GE
PG9171 and same level of steam as base case but many other possibilities exist as
described by Kikkawa [5, 6].
The CO2 balance showing the emissions reduction is shown in Table 9. It can be
observed that the CO2 emissions are reduced in the cold units because they have the
highest power demand. Compared to the base case, CO2 emissions have been reduced by
more than 30% by simply applying available techniques.
Table 9 – CO2 balance for improved efficiency in power generation unit
Power generation type
Process units
Warm units
Cold units
Storage and loading
Others
Total
LM 6000 gas turbines
%
Tons/h of CO2
7.5%
50
90.2%
602
1.3%
9
1.0%
7
100.0%
668
Combined Cycle
%
Tons/h of CO2
7.5%
48
90.6%
581
1.0%
6
0.9%
6
100.0%
641
CONCLUSION
In this study we have quantified some improvements that can be implemented in an
LNG plant to reduce the CO2 emissions by increasing the efficiency of processes and
energy generation systems.
In the following Table 10 and Table 11 a summary of the savings is shown together
with the fuel savings. The admissible CAPEX increase is calculated on the basis of the
fuel savings only for a financed project and 20 years of operation. The figures are based
on fuel cost of 1.5 $/Mbtu and on a CO2 tax of 10 $/t. One day of production loss gives a
20.5 M$ penalty.
Table 10 – Summary of possible reductions of CO2 for process units
T/h
5
Fuel
consumption
reduction
T/h
2
Admissible
CAPEX
increase
M$
8
CO2 tax
reduction for
20 years
M$
7
5
31
2
11
9
56
8
50
8
3
15
13
48
18
88
78
CO2 emissions
Reduction
Condensates
stabilization
NGL recovery
Liquefaction
pressure
Liquefaction
unit
Total
PS2-7.17
Paper PS2-7
All the proposed options for the optimization of the process units are economically
justified.
Table 11 – Summary of possible reductions of CO2 for generation of energy
Option
1
2
3
4
One HRSG per LNG
train instead of
conventional boiler
Two HRSG per LNG
train instead of one
Aero derivative GTs
instead of heavy duty
GTs for electricity
generation
Combined cycle instead
of aero derivative GTs
for electricity
generation
Total
CO2
Fuel
Admissible
CO2 tax
emissions consumption
CAPEX
reduction for
Reduction
reduction
increase
20 years
T/h
T/h
M$
M$
142
52
258
229
139
51
259
224
14
6
56
26
27
10
15
44
322
119
588
523
The savings in this field are very important. The use of HRSG on the exhaust gases of
the process GTs brings a lot of advantages and option 1 does not lead to any loss of
availability and production.
For option 2, it is more difficult because the steam generated by the second HRSG is
used for electricity generation. If the system is not correctly engineered the loss of
availability for the LNG plant may exceed 1% and the loss of production may exceed
1500 M$ over a 20 years period.
In regard of possible loss of availability options 3 and 4 are very dependent on the
design basis and project strategy.
REFERENCES
1. “How to reduce CO2 emissions from the LNG chain”, H. Paradowski, J. Launois, GPA
technical meeting - Bergen – Norway, May 2002
2. “Higher efficiency, lower emissions”, N. Peterson, D. Messersmith, B. Woodard, K.
Anderson , Hydrocarbon Processing, December 2001
3. “LNG liquefaction technologies move toward greater efficiencies, lower emissions”,
A. Avidan, D. Messersmith, B. Martinez, Oil and Gas Journal, August 19, 2002
4. “The DARWIN LNG Project”, D.E. Yates, C. Schuppert, LNG14 - Doha - Qatar,
March 2004
PS2-7.18
Paper PS2-7
5. “Zero CO2 emission for LNG power chain ?” , Y. Kikkawa, Y.N .Liu, LNG 13 - Seoul
- Korea, May 2001
6. “How to optimize the power system of baseload LNG plant with minimizing CO2
emission”, Y. Kikkawa, M. Ohishi , AICHE Spring meeting - New Orleans - 30/03/2003
PS2-7.19