Integration of power plant and amine scrubbing to reduce CO2 capture costs

Available online at www.sciencedirect.com
Applied Thermal Engineering 28 (2008) 1039–1046
www.elsevier.com/locate/apthermeng
Integration of power plant and amine scrubbing
to reduce CO2 capture costs
Luis M. Romeo *, Irene Bolea, Jesús M. Escosa
Centro de Investigación de Recursos y Consumos Energéticos (CIRCE), Universidad de Zaragoza, Centro Politécnico Superior,
Marı́a de Luna, 3, 50018 Zaragoza, Spain
Received 6 November 2006; accepted 21 June 2007
Available online 13 July 2007
Abstract
Due to security, sustainability of supply, strategic and energetic dependence reasons, it is well accepted the necessity to continue using
coal as main fuel for producing electricity from power plants. In order to reduce CO2 concentrations in the atmosphere, it is essential to
develop carbon capture and storage technologies that lead to zero emissions fossil fuels power plants. Absorption by chemical solvents
combined with CO2 long-term storage appears to offer interesting and commercial applicable CO2 capture technology. However, the high
regeneration energy requirements make necessary a process optimization in large-scale power plants. Although actual CO2 capture cost
remains around 55 €/ton CO2, the target is to maintain this cost below 25 €/ton CO2.
This paper proposes different possibilities to overcome the energy requirements by means of amine scrubbing integration into a commercial power plant, and presents a technical and economical analysis of the performance of these approaches. Although some schemes
show small efficiency penalties, it becomes essential to calculate specific cost per ton CO2, the main aim is to chose the proper configuration to implement large-scale cost-effective schemes that leads to CO2 capture demonstration projects.
Ó 2007 Elsevier Ltd. All rights reserved.
Keywords: MEA scrubbing; CO2 capture; Power plant; Energy integration; Capture costs
1. Introduction
Today, fossil fuels produce over 60% of the world’s electricity. Coal is the most abundant fossil fuel, playing an
essential role as fuel for power plant operation and contributing to about 38% of the total electricity generation [1].
For the coming decades it is expected to continue as a
prominent fuel for electricity production [2]. However,
CO2 has the greatest negative impact on the observed
greenhouse effect, causing approximately 55% of the global
warming [3]. As a consequence, European National Allocation Plans have considered an important reduction in the
utilization of coal, especially in power plants.
In order to maintain the increasing rate of electricity
production based on coal is necessary the development of
*
Corresponding author. Tel.: +34 976 762570; fax: +34 976 732078.
E-mail address: luismi@unizar.es (L.M. Romeo).
1359-4311/$ - see front matter Ó 2007 Elsevier Ltd. All rights reserved.
doi:10.1016/j.applthermaleng.2007.06.036
clean fossil fuels power plants. The development of zero
and near zero emissions power plant technologies is gaining importance worldwide and large demonstration projects are expected in the coming decade for new plants
[3]. But if drastic reductions are requested in the medium
term, it is also necessary to support and study technologies
that could be able to capture any percentage of CO2 from
existing power plants.
In a post-combustion capture, CO2 is directly isolated
from a stream of flue gases once combustion is completed;
then, a recovery process is applied to the CO2 captured.
Among those methods, CO2 absorption by amine derived
chemical solvents appears to offer an interesting and practical alternative from combustion flue gases at power stations. Besides absorption technology is commercially
applicable, there are a lot of experiences with a conventional chemical solvent, like monoethanolamine, and
research projects are planned to be executed for new plants
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L.M. Romeo et al. / Applied Thermal Engineering 28 (2008) 1039–1046
during the next years [4,5]. The main disadvantage of
amine scrubbing is the cost, which is perceived too high
to be economically attractive. A practical research objective is the analysis of the CO2 capture process integration
with a view towards minimizing the cost of implementation, operation and the cost per ton of CO2 avoided. Obviously intensive research is necessary to reduce its current
cost from 40 to 70 €/ton CO2 [2] to values well under
25 €/ton CO2.
CO2 absorption by amine scrubbing has been extensively studied by many researchers but studies are mainly
focused on chemical reaction mechanism, mass transfer,
gas/liquid equilibrium, and other related aspects of CO2
absorption [6–9]. Nevertheless, one of the main problems
is related to the large quantities of heat required to regenerate the amine solvent within the CO2 capture process. A
typical range is between 0.72 and 1.74 MWt per MWe generated in a coal-fired power plant [10]. The economical cost
of this energy requirement, mainly in the stripper reboiler
and CO2 compression, is usually higher than capital cost.
Outstanding studies have analyzed different alternatives
to reduce the heat duty on the reboiler and the thermal
integration requirements on the power cycle [11–15]. These
studies have been focused in the location of steam extraction at steam turbine and the re-injection of condensate
from stripper to steam cycle. It seems evident that the optimal option is to extract saturated steam midway through
the low pressure section of the turbine [11–14] with a pressure between 1.8 and 2.8 bar using the lowest quality steam
available to fit with the reboiler requirements [14]. Most of
the steam turbines do not have an extraction at this pressure range, as a consequence, perfect integration is only
possible when steam cycle is designed taking into account
a future amine scrubbing installation. For existing power
plants, researchers have analyzed different options to integrate amine scrubbing with a small efficiency reduction in
the original power plant performance. Power reductions
around 17% has been reported, for a 900 MW coal-fired
power plant, [11], where 611 t/h of CO2 are captured and
compressed, using 737 t/h of steam, which is the 54% of
the steam leaving the boiler. Other studies increase the
power reduction up to 26%, with a reduction in power
plant efficiency of 11.6 points for a 320 MW coal-fired
power plant [12]. In this case 335.2 t/h of steam were
extracted at 5 bar, in low pressure turbine stage, 33% of
the steam leaving the boiler, to capture 213.1 t/h of CO2
and the condensate was re-injected into the deaerator. A
novel strategy to reduce the efficiency losses is based on
an extraction from an IP/LP crossover pipe and an expansion through a new auxiliary turbine [14], to get the adequate conditions for the steam to the reboiler. In this
case, 79% of the steam is drawn-off from a 450 MW power
plant. Finally, some researchers [15] have increased the
complexity of the installation adding an auxiliary gas turbine and natural gas boiler for the stripper energy requirements. In this case, CO2 avoided was reduced due to
emissions from these equipments, which were not captured.
In order to completely analyze the amine capture process the CO2 compression installation, the cooling equipment must be taken into account. Power reduction due to
compression could represent around 10% of the electrical
power and refrigeration necessities could increase up to
60%. In spite of these data and some studies [12,15] that
have considered the compression necessities, there is still
a lack of information and studies that include the integration of the heat from the compression stages into the steam
cycle in order to reduce the cooling requirements and the
efficiency penalty into the steam cycle. Generally, neither
the CO2 compression power nor the cooling equipment
and its effect on power plant performance are taken into
account, in the way of improving the power plant performance, once the capture system is included.
The objective of this paper is to compare the power
plant performance, with special attention on the power
output and efficiency penalty, and investment cost and specific price of CO2 when MEA scrubbing is integrated with
the steam cycle. Different alternatives to provide heat and
power have been evaluated in order to minimize the cost
of CO2 avoided and the cost of electricity, after adding
the capture process to the power plant: Reboiler heat duty
provided by an external auxiliary steam boiler, by a steam
turbine extraction or even by heat provided by a gas turbine that also satisfies the power requirements for CO2
compression. Finally, cost calculations have been developed taking into account the total annual costs of each
configuration and the total CO2 avoided, in order to
achieve a specific value, price per ton of CO2 avoided, to
be able to compare the different alternatives.
2. Case study
The simulated power plant arranges three similar pulverized coal-fired units with a 350 MWe reheat steam turbine featuring six stages of regenerative preheating, three
low pressure, two high pressure and deaerator. At base
load, the steam conditions at the turbine admission valves
supplied from each of the three fired boilers are 311.2 kg/s
of live and reheat steam at 168 bar/540 °C and 39 bar/
540 °C respectively. The net efficiency of such units
amounts to 36.93% (LHV). The combustion of coal supplied to each fired boiler produces 982.89 MWt at base
load and yields approximately 630.0 kg/s (1,990,000 Nm3/
h) of flue gas being 96.3 kg/s of CO2 (194,224 Nm3/h,
9.76 %v). This emission CO2 values is low compared to regular flue gases from coal firing but the coal used for calculations was a low-rank Spanish lignite with low carbon
content (40%C, 20%H2O, 25%ash). A power plant simulation has been developed to provide a base case and essential information on coal consumption, thermal efficiency,
net plant efficiency and electricity output. Simulations
can also provide the quality and quantity of steam
throughout power cycle as well as the emission rate, temperature, and composition of the flue gas.
L.M. Romeo et al. / Applied Thermal Engineering 28 (2008) 1039–1046
3. Capture plant simulation
Initial condition of the simulation has been to capture
between 60% and 65% of CO2 produced, owed to economical reasons. In a medium-age power plant (typical for the
majority of installation in Europe) a high investment in
CO2 capture cost could not be cost-effective. In these situation seems reasonable to reduce the capture rate just to
fulfill National Allocations Plans for each installation.
The hypothesis considered has been that medium-age
power plants are forced to reduce a maximum of 60% of
CO2 emissions.
It is used a pure 30%w MEA aqueous solution. An
absorber packed column could treat a maximum volume
flow rate around 300,000 m3/h [12], so that the equipment
sizing becomes technical and economically feasible. Four
trains of 10 m diameter each absorber were used [15] to
treat 1,284,371 m3/h. With these values four separate
absorption/regeneration column trains were necessary,
treating one sixth of the gases flow each one (331,600 m3/
h). Flue gas, with a mass flow of 105 kg/s (331,666 Nm3/
h) is drawn-off after desulphurization unit at 55 °C and
1 atm. It is assumed no pollutants in flue gas such NOx
and SOx. A purge of 5% of degraded MEA will be also
included within the model. Absorption process flowsheet
is shown in Fig. 1.
CO2 capture is modeled using chemical-absorption with
MEA. The ASPEN PLUS block [16] used for the simulations, Aspen RadFrac, is a rigorous model for simulating
multistage vapor–liquid fractionation operations, in particular: absorption, reboiled absorption, stripping and
reboiled stripping. It has been assumed no pollutant in
1041
the flue gases and an adiabatic absorption process. Main
simulation variables and results are shown in Table 1. Electricity and heat consumption per ton of CO2 captured are
calculated with ASPEN and values are comparable but
slightly lower than those reported by other authors [11–
13]. Total energy requirements, electricity and heat consumption, amounts approximately 4.0 GJ/t CO2 with an
electricity consumption of 112 kW h/tCO2 and heat
required similar to [13]. The discrepancy with the value
of 2.76 is due to the use of KS-1 solvent in [11]. Although
the heat for stripper reboiler can be reduced using different
amines and blends, the objective of present work is to minimize its effects in the power plant performance.
Total compression energy required to CO2 conditioning
for transport, 140 bar and ambient temperature, is
70.5 MWe, which represents about 7% of the power plant
energy output. The compression process requires intercooling stages, to reduce compression requirements and to
avoid excessive CO2 temperature.
4. Integration of power plant and MEA scrubbing
CO2 capture process requires a great amount of supplementary energy to avoid excessive power output penalty.
For amine scrubbing, thermal energy is needed for amine
regeneration, electricity consumption for CO2 compression
and cooling necessities for refrigeration. An important consideration to select steam quality for the stripper is the
steam pressure. The consensus is that the reboiler temperature must not overcome 122 °C, value above which degradation of MEA and corrosion becomes intolerable.
Assuming 10 °C as hot side temperature approach in the
Q
COOL
REGABS
REGCOLD
GASOUT
MIXSOL
B4
CO2
B3
SOL
SOLIN
ABSORBER
DESORBER
LIQHOT
W
LIQ2
REG5
GASIN1
REG
QREB
WPUMP
Q
LIQ1
REG2
PUMP
SPLIT
MIX2
REG3
PURGA
Fig. 1. MEA absorption process flowsheet.
REGENERA
PURGA1
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L.M. Romeo et al. / Applied Thermal Engineering 28 (2008) 1039–1046
Table 1
Main simulation parameters comparison
Base plant net generation
Base plant efficiency (LHV)
Flue gases CO2 concentration
Technology
CO2 flow rate captured
CO2 captured
Electricity consumption per CO2 captured
Heat consumption per CO2 captured
Units
This paper
Mimura [11]
Desideri [12]
Bozzuto [13]
MWe
%
%v
1069
36.9
9.7
MEA
689.6
65
111.93
3.57
900
321
31.1
13.2
Fluor Daniel
203.6
86.5
91.50
3.95
434
36.7
15.0
Kerr-McGee
378.8
98
118.84
–
t/h
%
kWh/tCO2
GJ/tCO2
reboiler, the steam conditions of the saturation temperature amounts to 132 °C [14]. Saturation pressure at this
temperature is 2.8 bar. This thermal energy can be supplied
from either an auxiliary boiler, or from a power plant
steam extraction. Finding the optimum way to extract this
steam becomes essential in order to get the less power plant
energy penalty.
Before the compression process, it is required to dry the
captured CO2 stream, cooling it down until around 30 °C.
A valuable heat stream is produced cooling down the
stream in a first stage to 50 °C and in a second stage to
25 °C. Such stream could be integrated into the low pressure steam cycle lowering the heating requirements. Two
low-pressure heaters could be eliminated from steam cycle
and the extraction steam mass flow feeds the LP steam turbine to increase electricity production. This fact will be taking into account along the different configurations
simulated.
Some researchers have considered in their analysis to
maintain the power plant original output to the grid [15],
resulting that a considerable amount of supplementary
energy must be supplied for the CO2 separation processes
using gas turbine or natural gas boilers. The drawback is
that CO2 generated by the combustion of natural gas used
in these systems is not captured, consequently the CO2
avoided is reduced and the capture cost per ton of CO2 is
increased. In this study it is assumed a power plant output
reduction owes to steam de-rate and compression electricity requirements. In order to supply this energy and minimize the impact on power output, efficiency and capture
cost, three possible options are simulated and integrated
into the original power station for comparison, Fig. 2:
– The first one uses a natural gas auxiliary boiler to produce steam for the absorption process avoiding the negative effect in original plant steam cycle efficiency and
power output.
– The second one is integrating the absorption process
into the original power plant optimizing the overall efficiency, but also reducing power output.
– Finally, supplementary energy is generated using a gas
turbine in partial repowering of the power plant.
Results show the power plant performance for one
power plant unit.
13.3
KS-1
611.0
90
119.00
2.76
CO2 emitted
Flue gas
CO2 absorption
and compresion
Reference
Plant
MWe
MWe
CO2 captured
Auxiliary boiler
MWt
Natural Gas
Flue gas
Reference
Plant
CO2 emitted
CO2 absorption
and compresion
MWe
MWe y MWt
CO2 captured
Optimization
Flue gas
CO2 emitted
CO2 absorption
and compresion
Reference
Plant
MWt
MWe
MWe
CO2 captured
Auxiliary gas turbine
Natural Gas
Flue gas
Fig. 2. Integration using a natural gas auxiliary boiler, internal energy
flows, natural gas auxiliary gas turbine.
4.1. Auxiliary boiler
A natural gas boiler has been modeled to supply heat
requirements to the stripper boilers. Compression energy
and other auxiliary equipment are driven by the original
steam turbine. Table 2 shows a comparison between the
base case without capture and the use of a natural gas boiler for thermal energy requirements in stripper boiler. As
expected, there is a drop of 10 points in the power plant
global efficiency, due to the rise of fuel thermal energy.
Net power output decreased 23.6 MWe, because the compression energy requirements are provided by the steam
turbine generator. Although 60% of CO2 is captured, the
boiler flue gases increase the specific value of emissions
per kWh up to 0.469 kg/kWh.
4.2. Power plant internal flows integration
Integration based on power plant internal streams,
depends upon the plant configuration. Ideally, best results
L.M. Romeo et al. / Applied Thermal Engineering 28 (2008) 1039–1046
1043
Table 2
Integration results summary
Base plant
Auxiliary N.G. boiler
From LP1 extraction
From IP2 extraction
Gas turbine HP and IP
heaters bleed reduction
Gas turbine and extra
steam generation
Steam turbines
output (MWe)
Aux. electric.
consump. (MWe)
N.G. energy
requirements
(MWt)
Net output
(MWe)
Global
efficiency
(LHV)
Specific CO2
emmited (kg CO2/
kWh)
362.98
362.98
320.50
314.71
394.18
19.92/3
90.69/3
89.82/3
90.18/3
19.92/3
–
306.6/3
–
–
137/3
356.34
332.75
290.57
284.65
320.04
36.93%
26.18%
30.11%
29.50%
33.27%
0.969
0.469
0.451
0.460
0.467
398.76
20.40/3
137/3
324.46
33.70%
0.464
would be obtained from an extraction at the pressure of
2.8 bar, at which saturation temperature is 130 °C. Most
of existing power plants will not have this condition in
any extraction and should adapt them to the required conditions. Stripper boiler conditions can be achieved after
first low-pressure turbine extraction, 2.8 bar and
208.5 °C. This flow needs to be cooled down until saturation temperature (130 °C), before getting into the desorber,
because of degradation problems. It is proposed to mix this
steam flow with condensate re-injection from reboiler in
order to increase the mass flow to stripper and reduce the
extraction mass flow necessary for regeneration.
Thermal energy from the first compression intercooling
in the compression stage is used also to improve the cycle
efficiency. Two low-pressure heaters are eliminated from
steam cycle as is shown in Fig. 3, reducing output penalty
in low pressure turbines.
The possibility of extracting steam from an intermediate
pressure point has been also studied, Fig. 3, after medium
pressure turbine, steam pressure is 7.3 bar. This flow is
expanded down to 3 bar in an auxiliary steam turbine, generating 20 MWe and reducing compression power necessities. Saturated water is returned to the cycle through the
deaerator.
Results are also presented in Table 2. It is observed a
reduction in steam turbine production (around 18.5%)
caused by the steam de-rate in last turbine stages as well
as the use of steam turbine generator output to provide
electricity to the compression process. The first option
results on a increased efficiency of 0.61 points more than
the second one, but it is 6.8 points lower than the reference
case. Specific CO2 emissions are reduced to 0.450–0.460 kg/
kWh
4.3. Gas turbine
Adding gas turbines to existing steam power plants have
been used to enhance their performance since gas turbines
LP1
LP
2
ηLHV= 36.93%
311 ºC
206,8 ºC
7,3 bar
2,8 bar
IP1
IP2
LP1
LP2
LP3
LP4
6
1
113.2 kg/s
8,3 kg/s
121.5 kg/s
LP
extraction
REBOIL
267 MW
Flue gases
Boiler
LP4
2
3
363 MWe
HP
LP3
Condenser
5
4
3
2
1
23 MW
Deareator
(from intercooler)
COAL HEAT
845 MWt
IP2
LP1
LP2
LP3
LP4
121,5 kg/s
20 MWe
1
2
PRESAT
HP Exchangers
LP Exchangers
IP
extraction
Deareator
REBOIL
264 MW
15,5 MW
(from PRESAT)
23 MW
(from intercooler)
Fig. 3. Integration with internal flows.
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L.M. Romeo et al. / Applied Thermal Engineering 28 (2008) 1039–1046
Deareator
Condenser
Natural gas
6
Combustion
Chamber
246ºC
5
4
210ºC
169ºC
3
118ºC
1
2
81ºC
56ºC
38ºC
Wout= 67.5 MW
Compressor
Q1
Turbine
Q2
Q3
Air in
Flue gas
537ºC
240ºC
200ºC
111ºC
Fig. 4. Using the heat from de gas turbine flue gas to minimize feed water heaters requirements.
were introduced to electric utilities in 1949 [17]. Repowering projects have been both to increase capacity stations
at higher efficiency and to reduce of mainly NOx and
SO2 emissions in a cost-effective way. Presently, when carbon dioxide emissions seem to have an important role in
our society, repowering concept adds another credit to be
more attractive.
In repowering arrangement, gas turbine exhaust gas
could be used as combustion air for the coal fired power
plant. This option would require excessively arrangements
in the air–coal system and in the steam boiler. Moreover
hot windbox repowering arrangement was not survey
because of the lower oxygen concentration than ambient
air and the increase of flue gas volume that could lead to
erosion problems and different temperature profiles inside
the boiler. Also gas turbine exhaust gas could be used to
improve steam cycle efficiency. On this paper some possibilities have been simulated adding one Siemens V64.3
gas turbine to the three steam cycles. On feed water repowering, gas turbine flue gases are cooled down in three stages
reducing steam turbine bleedings, Fig. 4. Also, a gas turbine heat steam recovery generator is used to supply reheat
steam to the turbine. Power delivered by the gas turbine is
used as auxiliary power for CO2 compression.
Results, Table 2, show a small net output reduction of
9% (around 32 MWe) but specific emissions remains in values similar to those presented above due to natural gas
combustion in gas turbines. Efficiency penalty is lower than
previous configurations, almost 3.0 points over the steam
cycle integration.
Even if gas turbine results are showed a minimum efficiency and output penalty, it becomes necessary to value
them into economical terms, in order to focus that configuration that minimize the capture cost and the increase of
electricity cost.
5. Economic evaluation
The target for the CO2 capture studies is to recover 60–
65% of the original emissions with the minimum cost per
CO2 avoided.
The target for this analysis is to capture around 60–65%
of the original emissions with the minimum cost per CO2
avoided. It is evident that the majority of the studies raise
this quantity up to 90%, [3], in a medium, long-term analysis this could be the objective.
Nevertheless, a short-term option for power companies
is to reduce CO2 emissions in order to carry out the
National Allocations Plans without an important impact
in their economic results. In this scenario, a less intensive
capture process could be economically attractive.
Capital costs were evaluated using different sources [16–
21]. It has been used the ‘‘six-tenth rule’’, broadly used and
explained [20]. Assumptions used in the economic evaluation were:
– Existing power plant is paid off.
– 5% interest rate.
– 20 year project life with zero salvage value at the end of
the project.
– No taxation or depreciation calculations were included
in this study.
– Electricity price, 5.29 €/MWh.
– Cost of coal for power plant boiler and the auxiliary
power unit, 2 €/GJ.
– Cost of natural gas for auxiliary power units, 4 €/GJ.
– Cost of natural gas (NG) auxiliary boiler, 75 €/kWh t.
– Cost of gas turbine (GT) and heat recovery steam generator (HRSG), 265 €/kW.
– Cost of the make-up water, 0.191 €/m3.
– Cost of the make-up MEA, 981 €/ton.
– The plant operates for 7500 h/year, which gives time for
maintenance.
– The maintenance costs are 2.2% of the fixed capital
investment.
– The final CO2 product will be provided at 25 °C and
139 bar.
Equipment costs, Table 3, are the main contribution to
the total cost as it was previously shown by [12,15]. O&M
cost are also itemized in Table 3 for the absorption process.
Total annual cost amounts to 49 million euros per year.
This is not the unique contribution to the capture process,
it is necessary to take into account the influences of the
reduction of power output, extra fuel for auxiliary equipment and the gas turbine and heat recovery steam genera-
L.M. Romeo et al. / Applied Thermal Engineering 28 (2008) 1039–1046
Table 3
Total annual costs (€)
Capital costs (€)
Blower
Absorber
Desorber
Reboiler
MEA plant and auxiliaries
Regenerator
Total capture equipment costs (€)
Total compression equipment costs (€)
Total equipment costs (€)
Instalation cost (14%)
Initial MEA
Instrumentation and control (10%); piping (17%)
Electrical equipment (8%); buildings and services (16%)
Capture plant and compression total cost (€)
Engineering and supervision cost (7%); process and project
contingency (15%)
Direct and indirect total cost (€)
O&M fix cost
Total maintenance cost
Maintenance cost assigned to
workers
Administration cost
2.2% plant total cost
12% maintenance total
cost
30% worker assigned
cost
Total O&M fix costs (€)
4,174,945
33,399,560
3,931,981
3,444,496
16,052,668
2,355,650
63,359,301
167,770,755
231,130,056
32,358,208
12,346,790
62,405,115
55,471,213
393,711,382
50,848,612
444,559,995
10,220,571
1,226,469
367,941
11,814,980
O&M variables cost
MEA make-up
Water make-up
Total O&M variable cost (€)
837,810
1,188,628
2,026,438
Total O&M cost (€)
13,841,418
Total annual cost (€)
49,048,209
tor, auxiliary boiler or plant modifications. These quantities are shown in Table 4.
Modifications of steam cycle for the stripper energy
requirement is the cheaper option but, as it was shown in
Table 2, have the maximum power output reduction and
a loss of efficiency of 6.8 points. As no extra CO2 emissions
are needed the CO2 avoided amounts 4.8 million tons per
year with a cost of 25.3 €/ton CO2 avoided. This option
seems to be the preferred choice.
Gas turbine scheme shows a intermediate annual cost
due to the size of GT + HRSG is substantially lower than
NG boiler. Although is the option with the higher efficiency
and power output, CO2 avoided is slightly lower than previous configuration. As a consequence, the cost increases
up to 31.0 €/ton CO2 avoided.
Finally, the equipment and operational cost of the auxiliary boiler option increase the total annual cost for this
1045
configuration. Moreover, the CO2 emissions decrease the
CO2 avoided and increase the cost per ton CO2 avoided
up to 60 €. If coal is used instead NG cost is reduced to
56 €.
Despite expected steam turbine operational problems,
the option of steam cycle modifications with integration
of intercooling compression into the low-pressure steam
cycle seems to be worthy compared with configurations
including GT and/or steam generators.
6. Conclusions
Amine scrubbing is a well-known method for CO2 capture. Chemical reaction mechanisms and solvent development have been studied in the last decade in order to
reduce energy regeneration requirements. However, the
optimum integration of capture process into the power
plant has not been solved yet. The power output and efficiency penalties make that the efficiency optimization and
the economical optimization do not agree. This paper has
proposed different possibilities to overcome the energy
requirements by means of amine scrubbing integration into
a commercial power plant, and has presented a technical
and economical analysis of the performance of these
approaches. It should be noticed that regeneration requirements and its effect on power plant performance can also
be reduced using different amines and blends. But in these
cases, further research is needed in order to propose several
integration schemes.
Using a gas turbine to supply compression electrical
energy requirements and extracting steam from the steam
cycle is the optimum option with regard to the efficiency
penalty on the power plant performance. Nevertheless, economic evaluation shows that GT operation reduces the
CO2 avoided and increases the capture cost up to 6 €/ton
CO2 with reference to a configuration with steam cycle
modifications. These configurations have shown the best
results according the capture cost, even if larger penalties
in efficiency and power output are produced. Obviously,
the less efficient and cost-effective option is the installation
of new steam generator for the stripper energy requirements. Efficiency reduction amounts 10 points with reference to the base case, and a capture cost of 60 €/ton CO2
avoided for NG and 56 for coal operation.
Although research is focused in the integration of capture process into the existing power plants, more research
is needed in order to design new power plant with integrated CO2 capture process. Efficiency penalty would be
reduced and a cost-effective process could be developed.
Table 4
Specific CO2 prices, calculated for each configuration
Gas natural boiler
Internal flows
Gas turbine
Total annual costs (€)
CO2 avoided (t/year)
Price per CO2 ton (€/t)
Global efficiency (LHV)
216,639,379
121,573,539
137,465,238
3,575,826
4,815,288
4,401,810
60.58
25.25
31.23
26.18%
30.11%
33.70%
1046
L.M. Romeo et al. / Applied Thermal Engineering 28 (2008) 1039–1046
Acknowledgements
The authors are grateful for the financial support from
the Spanish Government, without which, this work could
not have been undertaken. The work described in this paper was supported by the R + D Spanish National Program from the Spanish Ministry of Science and
Education under project ENE2004-06053, Cuasi-zero
CO2 emissions power plant technologies research. The
Spanish case.
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