Siemens AG
COAL-GEN
August 20-22, 2014
COAL-GEN, Nashville, Tennessee, USA, August 20 - 22, 2014
Adding CO2 Post-Capture Helps US CoalSteam Plants Meet Proposed EPA Limits
Dennis Horazak, Michael Horn, Oliver Reimuth and Gernot Schneider
Siemens AG (Germany) and Siemens Energy, Inc. (USA)
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1 Executive Summary
Coal will continue to generate significant amounts of power in the US, but coal plant operators
will eventually need to control CO2 emissions. The current EPA proposal would require that
about half of the flue gas produced by a coal fired power plant need to be treated in a carbon
capture facility.
Siemens has developed a post carbon capture technology (PostCap™) based on an Amino Acid
Salt (AAS) solution as solvent. The AAS process offers a viable method for both new and
existing plants to meet EPA requirements. This paper describes the addition of a Siemens
PostCap™ system to a typical pulverized coal supercritical steam power plant, including the
estimated impact on thermal performance, cost and space
2
Introduction
2.1 Coal fired power plants in US
Based on actual publications for the year 2013 [1] the United States has 1,031 GWe of installed
electric capacity, of which 302 GWe, or 29% is fueled by coal.
The US Department of Energy expects 45 GWe of coal plant retirements between now and 2040
but only 1.2 GWe of new coal plants, resulting in an overall 14% decline in active coal power to
258 GWe in 2040 [1]. However, the US has large domestic reserves of coal, and coal is expected
to continue as a significant source of power generation fuel, as shown in Figure 1.
Figure 1 – Coal-fueled US Electric Generating Capacity from 2013 through 2040 [1]
Figure 2 shows that over that same period oil and natural gas fueled capacity is expected to
increase dramatically so that the 2040 energy mix would be led by 644 GWe or 52% by oil or
gas-fueled plants and 258 GWe or 21% by coal-fueled plants. Even with only small predicted
numbers for new build coal fired plants this gives a large potential for retrofit of the existing
fleet. To receive or extend operation licenses the fulfillment of environmental restrictions is
crucial.
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Figure 2 –US Electric Generating Capacity Changes from 2013 through 2040 [1]
2.2 EPA requirements
Between 1971 and 2002 the US Environmental Protection Agency (EPA) established power
plant emission limits for particulate matter, sulfur oxides, and nitrogen oxides. In September
2013 the EPA proposed to also limit carbon dioxide emissions. Under the proposed rule, new
power plants would be limited to 454 g CO2/kWh-gross (1,000 lb CO2/MWh-gross) for natural
gas-fired turbines burning more than 249 MWth (850 MBtu/h) of natural gas, and to
499 g CO2/kWh-gross (1,100 lb CO2/MWh-gross) for smaller natural gas turbines and coal-fired
units. Table 1 shows the current EPA limits for particulates, SO2, and NOx for power plants built
after May 3, 2011 [2] and proposed CO2 limits for new power plants. There is no current limit
on SO3 emissions, which are typically much lower than SO2 emissions.
Contaminant
Emission Limit
Particulate Matter – smaller of
11 ng/J (0.040 g/kWh = 0.090 lb/MWh) gross power
output or
12 ng/J (0.043 g/kWh = 0.097 lb/MWh) net power output
Sulfur Dioxide (SO2) –
smaller of
130 ng/J (0.486 g/kWh = 1.0 lb/MWh) gross power output
or
140 ng/J (0.504 g/kWh = 1.2 lb/MWh) net power output,
or
3% of potential SO2 emissions (97% reduction)
Nitrogen Oxides (NOx) –
smaller of
88 ng/ J (0.317 g/kWh = 0.70 lb/MWh) gross power output
or
95 ng/J (0.342 g/kWh = 0.76 lb/MWh) net power output
Carbon Dioxide (CO2),
proposed
499 kg/MWh (1,100 lb/MWh) gross power output
Table 1 – US EPA Emission Limits for New Coal-fired Plants
The proposed CO2 limits for new plants are expected to be finalized by June 2014 [3], after
which the EPA can address CO2 limits in existing power plants. Section 111(d) of the Clean Air
Act requires each of the 50 states to develop plans to implement new emission standards in their
existing plants, subject to EPA review and approval [4]. To fulfill the upcoming limits for CO2
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emissions it is important to have carbon capture technologies developed and mature for full scale
applications. While for new build plants three major technology lines are currently apparent (Pre
combustion/coal gasification, post combustion/absorption from flue gas and oxy-fuel), for
retrofit of existing plants the choice is limited to post combustion technologies. This is based on
the fact that the use of the two other technologies would require major changes within the
existing power plant. Thus those technologies are not feasible for retrofit.
2.3 CO2 Removal from Typical Coal-Steam Plants
Most US coal-steam plants would have to capture between 30% and 60% of flue gas CO2 in
order to meet the EPA limit of 500 kg (1,100 lb) per MWh(e) of plant gross power, as shown in
Figure 3. Most US bituminous coals produce between 295 and 325 kg CO2 per MWh(thermal)
(650-720 lb/MWht), and most US low-rank coals produce between 310 and 350 kg/MWht (690770 lb/MWht). For reference, pure carbon produces 390 kg (860 lb) of CO2 per thermal
megawatt hour. Typical subcritical and supercritical PC plants without CO2 capture have gross
efficiencies around 39% and 41%, respectively. Adding CO2 removal to comply with EPA
regulations reduces gross efficiency by 3 to 10 points, depending on the removal technology 1,
resulting in gross efficiencies around 29-36% for subcritical plants and 31-38% for supercritical
plants. As a result the curved lines represent 30%, 35% and 40% gross efficiencies of power
plants that include CO2 removal to meet EPA emission limits.
Figure 3 is a simplified graph for the estimation of how much CO2 must be removed to meet
EPA regulations at a given power plant. The horizontal axis represents CO2 produced for each
thermal MWh of heat released by burning the coal 2. The gross efficiency of the standard power
plant should be reduced by 3 to 10 points to get the curved lines. The vertical axis shows the
percent of CO2 that must be removed from the flue gas in order to meet EPA limits.
An example: Illinois No. 6 coal with an HHV of 27.13 MJ/kg (11,666 Btu/lb) and 63.75%
carbon produces 310 kg(683 lb)/MWht, plus another 2% of CO2 produced by the FGD, resulting
in 316 kg (697 lb)/MWht of total CO2 on the horizontal axis. If it were used in a supercritical
plant with 38% gross efficiency (41% minus 3% for CO2 removal), the required CO2 reduction to
get to 500 kg (1,100 lb) per MWh(e) would be 40%. 3 (Please refer to the black arrows in
figure 3.)
1
Included here: CO2 compression to 152 bara
Includes CO2 from flue gas desulfurization (FGD), assumed to be 2% of coal CO2.
3
For comparison: The flue gas without CO2 removal would contain 1,834 lb (832 kg) of CO2, per
MWh(gross electric)
2
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Figure 3 - Required CO2 Removal to meet 1,100 lb(CO2)/MWhe(g)
2.4 Typical configuration of a modern supercritical coal fired steam power plant
Driven by the increased environmental awareness over the last decades and resulting legislations
equipment for emission reduction with regards to NOx, SOx and particulate matters for power
plants has been developed, introduced to the market and is now state of the art.
The main elements of a typical state of the art pulverized coal supercritical steam power plant are
shown in Figure 3. Coal is burned with primary air in a wall-fired boiler furnace while forceddraft fans provide additional air, including over-fire air to reduce NOx. The pressure in the boiler
is slightly less than ambient, so that any air leakage is into the boiler, identified as infiltration air.
A selective catalytic reduction (SCR) unit in the boiler controls NOx emissions, fabric filters in a
baghouse remove particulate material, and activated carbon injection (not shown) controls
mercury.
An induced draft fan provides additional pressure to move the flue gas through the remaining
emission control equipment and out the stack. A wet flue gas desulfurizer (FGD) converts flue
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gas sulfur compounds into byproduct gypsum using makeup water, oxidation air and limestone
slurry.
The requirement to reduce the CO2 emission poses a new challenge to the industry, mainly based
on the large quantities to be treated. By using a post capture technology this leads to a
predominantly “chemical” plant, which has to be considered with regards to capital and operative
expenses as well as space and utility consumption.
The principal location of the CO2 Capture Plant and CO2 compression in the process is shown
with dashed lines in Figure 4.
Figure 4 – Main Elements of Typical Pulverized Coal Supercritical Steam Power Plant
Thermal Performance
Operating conditions and performance data for a typical supercritical steam cycle is taken from a
comparison study of various types of reference coal-fired plants with and without carbon capture,
performed for the Department of Energy and reported in 2010 [5]. From this report, Case 11 was
chosen as a base for this paper. The main performance data of this case (without CO2 capture)
are summarized in Table 2. Plants with CO2 capture would have reduced gross power due to LP
steam being used for solvent regeneration. Besides that, the net power output is shortened due to
the auxiliary loads for the CO2 removal equipment and CO2 compressor.
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Plant Thermal input
Steam Turbine Power (gross)
Plant Auxiliary Power
Plant Net Power
Plant Net Efficiency (HHV)
Steam main cycle pressure
Steam main cycle temperature
Reheat steam pressure
Reheat steam temperature
IP/LP steam crossover pressure
IP/LP steam crossover temperature
Condenser cooling duty
Condensation pressure
Condensation temperature
MWth
MWe
MWe
MWe
1,400
580
30
550
39.30%
MPa (psia)
°C (°F)
MPa (psia)
°C (°F)
MPa (psia)
°C (°F)
MWth
MPa (psia)
°C (°F)
24 (3515)
593 (1100)
4.5 (656)
593 (1100)
1.2 (170)
392 (737)
638
0.01 (1)
38
Coal type
Illinois No.6
Total Auxiliary Power Requirement
MWe
30
Table 2 – Main performance data for Case 11 (typical supercritical steam power plant
without carbon capture)
Capital and Operating Cost Estimates
Using the NETL report [6] as a reference, the equipment capital cost (Total Plant Cost) of this
power plant, excluding owner’s costs, is estimated to be $ 1,981/kWe, in June 2011 dollars.
When owner’s costs are added to this figure, including preproduction costs, inventory capital,
initial catalysts and chemicals, land, and financing costs, the resulting Total Overnight Capital is
$2,452/kWe. Operating and maintenance costs for this typical plant, including fuel costs are
estimated to be $42.61/MWh.
Emission Performance
For a new supercritical plant, the emissions are assumed to meet EPA New Source Performance
Standards for NOx, SO2 and particulates
3
Application of Siemens PostCapTM to a typical US coal-fired steam power plant under
proposed EPA requirements
3.1 Siemens PostCapTM technology
The Siemens Energy Sector has developed the PostCap (post combustion carbon capture)
absorption process based on an amino acid salt solvent (aqueous solution), which is capable of
separating at least 90% of the CO2 contained in the flue gas from coal, oil or gas fired power
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plants as well as from industrial sources. Figure 5 shows the principal Siemens PostCap process
configuration.
Cleaned Flue Gas
Solvent Reclaiming
CO2 Compression
CO2 Absorption
CO2 Desorption
Flue gas inlet
Figure 5 – Siemens PostCapTM Process configuration
The raw flue gas is cooled in a flue gas cooler and then conveyed by a blower through the
absorber. The gas leaves the top of the absorber as cleaned flue gas. The solvent meets the flue
gas in the countercurrent absorber, where CO2 is selectively absorbed by a chemical reaction.
The “rich” solvent (loaded with CO2) is pumped from the absorber bottom and heated up in a
“rich/lean solvent heat exchanger”, before it enters the top of the desorber column. At the
desorber bottom, the chemical bonding of CO2 is reversed at a higher temperature (which is
provided by steam in a reboiler). Thus a mixture of CO2 and water is stripped out. The water is
condensed at the desorber top, whereas the remaining CO2 is compressed (and if applicable
purified) for transport, such as by pipeline, and further use. The “lean” solvent (which has been
relieved of most of its CO2) is pumped from the desorber bottom, cooled in two steps (“rich/lean
solvent heat exchanger” and “lean solvent cooler”) and then fed to the absorber top. A small
solvent slipstream is taken downstream of the lean solvent cooler for reclaiming. The purified
solvent is fed back upstream of the lean solvent cooler.
The particular advantages of using an Amino Acid Salt as solvent are:
•
Application of an environmentally friendly, non-toxic solvent
•
Minimal detectable solvent emissions due to a very low vapor pressure
•
Good solvent stability against various degradation mechanisms, particularly from oxygen
and - as a result - low solvent refill need
Ease of handling by power station operators and personnel.
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In addition to these features Siemens has proven the operability and effectiveness of the process
and its low energy consumption in more than 9,000 hours of operation in the PostCap™ pilot
plant at E.ON’s hard coal fired Power Plant Staudinger in Germany since September 2009. The
onsite pilot facility is able to process flue gas from the coal fired plant as well as from a separate
gas fired plant.
One selection criterion for the solvent was a low thermal energy demand for stripping CO2 from
the rich solvent. The PostCap™ demand of 2.7 GJ per tonne (1161 Btu/lb) of CO2 captured has
been validated in the pilot plant. It was achieved with improved process configurations and is
considerably lower than the energy demand for MEA baseline solution. In addition there is still
potential to further decrease this figure. Absorber operating temperature would be in the range of
40°C to 50°C (104°F to 122°F), and the stripper operating temperature between 100°C and
110°C (212°F to 230°F). The PostCap™ reclaimer needs much less thermal energy than does the
MEA baseline process because it uses crystallization instead of thermal distillation to separate
waste material from the solvent.
Based on the results of these pilot plant tests, a scale-up of this technology to large-scale
demonstration and full-scale projects is possible. Siemens PostCap technology had been chosen
by several large-scale projects globally for the design of CO2 capture plants to be optimally
integrated into either new-build power plants or to be retrofitted to existing ones. Recently,
Siemens successfully finalized the Technology Qualification Program for the large-scale Carbon
Capture Mongstad (CCM) project in Norway. The 18-month program included a pilot plant
operation and comprehensive engineering for the large-scale CO2 capture plant.
During process operation amino acid salt solvents (as well as amines) form degradation products
by thermal stress or reactions with SOx, NOx, and oxygen contained in the flue gas. To offset this
degradation, the Siemens PostCap process applies a proprietary two-step reclaiming process to
minimize solvent losses, hence operation costs. SOx contaminated solvent is fully recovered, the
blocking of the solvent is fully reversed, and a sellable sulfur product is generated. In principle
any SOx content in the flue gas is feasible for PostCap, however in practice a reasonable level
has to be determined based on economic considerations (cost of flue gas desulfurization vs. cost
of reclaiming). Furthermore a highly selective separation of the amino acid salt solvent from
other by-products is applied and thus a high recyclability assured. Each step of the reclaimer can
be operated independently (either continuously or batch-wise), which allows tailor-made
solutions for client’s needs. For full scale applications the dimensions of the reclaimer are
relatively small compared to the rest of the capture plant. Siemens has developed a reclaimer
design with a high degree of prefabrication where complete units are pre-mounted in
transportable skids with steel frames. This allows system testing (such as water tightness) in the
factory and thus shortens erection and commissioning periods on site.
3.2 PostCapTM CO2 Capture Plant Design
Based on the reference coal fired plant (NETL Case 11) as described under 2.4 a post
combustion capture plant design was developed to
a) fulfil the EPA requirements given for new build coal fired power plants as outlined in
section 2.2 for a reference power plant and
b) use a state-of-the-art design to reduce necessary investment and operating costs.
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The same technology would apply for the retrofit of an existing coal fired plant. In this case it
would be necessary to investigate the best possible ways to supply mainly of steam and power
(but also for other necessary utilities) from the existing systems. Furthermore, additional space
restrictions in the existing plant layout have to be considered.
3.2.1 Plant Design Resulting from EPA Requirements and NETL Configuration
To reach the EPA requirement for CO2 emissions of 499 g/kWh (gross) only a slip stream of the
flue gas needs to be treated by CO2 capture. To calculate this slip stream, the normal CO2
emissions of a supercritical coal fired power plant of 760 g/kWh (gross) needs to be taken into
account, as well as the loss of gross power caused by the heat consumption of the capture plant.
For this paper it was decided to keep the power plant at its given design, to simulate an existing
plant. This means that the net power output will be reduced by the power demand for CO2
capture and compression. This decision was made to keep the comparability for new build plants
as well as for retrofits. With approximately 13 vol% of CO2 in the flue gas and a state-of-the-art
capture rate of 90 % this results in a slipstream of approx. 49 % of flue gas mass flow, or
291 kg/s (642 lb/s) to the Siemens PostCap™ process.
Temperature
Pressure
57 °C
135°F
1.0077 bara
3.11 in w.c.
Composition
Amount kg/h
CO2
216.179
476,596
20.6%
13.5%
N2
692.391
1,526,469
66.1%
68.1%
O2
27.881
61,467
2.7%
2.4%
Ar
0
0
0.0%
0.0%
H2O
99.218
218,739
9.5%
15.2%
Other
11.893
26,220
1.1%
0.8%
1.047.562
2,309,491
100.0%
100.0%
Total amount
By-products
Amount kg/h
Amount lb/h Mass fraction
Vol fraction
Amount lb/h ppmv
NOx
45
NO2
2
SO2
88
194
SO3
3
7
38
Table 3: Mass Flow and Composition of Flue Gas at Carbon Capture Plant Inlet
From the IP/LP crossover, steam of 364 °C (688 °F) at 0.93 MPa (135 psia) is available for the
PCC process in the NETL configuration [5]. This steam is throttled, and condensate is injected in
order to reach the conditions desired at battery limits of the capture plant, which are 153 °C (307
°F) and 0.52 MPa (75 psia). Optimizing the effect of steam extraction on the power plant along
with the requirements of the PostCap plant gives room for further improvement but is not
covered in this paper because an integral approach to both plant designs would be necessary.
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Detailed simulation of PostCap performance by Siemens showed that the chosen parameters lead
to a decrease of gross output by approx. 45 MWe. Based on the resulting value of 535 MWe the
specific CO2 emission is 460 g/kWh (gross) (1,014 lb/MWh) and thus well below the required
limit set in the EPA requirements.
3.2.2 Plant Design Resulting from Siemens PostCap™ Process Requirements
When investigating the design parameters for this paper we kept in mind that for future
investment decisions the capital expenditure (CAPEX) is of major importance while in parallel
operating expenditures (OPEX) need to be kept at a reasonable level.
Taking into account that CO2 compression is not directly influenced by PostCap design, and
would lead to similar values for different capture processes, and that that the balance of plant is
highly dependent on local conditions (such as available space, air, and water conditions), the
major lever for a general CAPEX reduction is the design of the columns and internals and the
choice of materials. Based on this the decision was to use a single train design (1 flue gas cooler,
1 flue gas blower, 1 absorber, 1 desorber). This leads to column diameters smaller than 12 m
(39 ft), which is well within the limits for production, transport and handling during erection.
Whether the large columns will be delivered as single prefabricated units or in pieces to be siteerected has to be decided for each specific project based on local labor cost and available
infrastructure.
Flue Gas Cooler
The flue gas cooler is designed to cool the flue gas from 57 °C (135 °F) to approx. 30 °C (86 °F).
In addition the flue gas cooler washes out some particulate matter and other contaminants in the
flue gas. To further reduce the SOx content of the flue gas a dosing of an alkaline solution shall
be integrated. A high amount of SOx in the flue gas would lead to higher (temporary) blocking of
the solvent and thus a larger Siemens SOx reclaimer. The diameter of the flue gas cooler is 12 m
(39 ft).
Absorber Column
A high efficiency packing design optimized for the configuration with amino acid salt (AAS) is
used in the absorber. This leads to higher gas volume flow and thus a reduced column diameter,
resulting in a lower CAPEX. As an alternative the pressure drop and thus the power requirement
of the flue gas blower could be reduced, if the column diameter is kept constant. This would lead
to lower OPEX and may be considered at regions with high prices for electrical energy. Based on
the given cooling water conditions (NETL report)[5] the solvent temperature at the inlet of the
absorber was set to 30 °C (86 °F). At this temperature an effective and flow optimized absorption
can be achieved. For the cost evaluations in this paper the lower column diameter was taken into
account. Under the given design conditions the column diameter was calculated to be 11.5 m
(38 ft).
In amine-based PCC processes there is normally an additional washing step installed on top of
the absorber column to clean the emitted flue gas from solvent aerosols and vapor. This step is
not considered necessary for the AAS solution used by Siemens based on the fact that salts have
very low vapor pressures. For possible droplet emissions a demister is foreseen. This
configuration was tested successfully in the pilot plant at E.ON’s Staudinger coal fired power
plant in Germany.
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The decision to use either high alloy steel or concrete with liner for the absorber column
structure depends on local labor cost, local availability and local cost of material (for concrete)
and requirements such as earthquake or explosion pressure. Explosion pressure may apply in
cases where oil and gas producing facilities are close by (e.g. refineries). In general the use of
concrete becomes more cost effective if stability requirements would lead to thicker steel
columns.
Desorber Column
For the desorber, a packing capable of handling higher liquid loads is used. The desorber is
operated at a pressure of 3 bara (43.5 psia), which leads to a lower pumping power and cost
reduction for some auxiliary equipment. At the same time, the column diameter can be reduced,
which outweighs the higher cost for the design of the desorber as pressure vessel. Under the
given design conditions this results in a column diameter of 10 m (33 ft) for the desorber.
Reclaimer
As described in chapter 2.3, Siemens has developed a proprietary design for reclaiming the
solvent. The reclaimer consists of two units each modularized on pre-fabricated transportable
skids with steel frames approximately 3.5 m long, 4 m wide, and 13 m high (11 ft x 13 ft x
43 ft). For the described reference plant configuration and based on the given concentrations of
SOx and NOx in the flue gas the SOx reclaimer consists of 3 modules (3 vertical) and the NOx
reclaimer of 4 modules (1 vertical, 3 horizontal).
Plant Layout
Taking into account the dimensions of the main components and auxiliary buildings as well as
necessary areas for construction, operation and maintenance lead to a space requirement of
approximately 170 m x 125 m (558 ft x 410 ft or 5.25 acres). One possible arrangement is shown
in Figure 6. Structures for cooling water supply are heavily dependent on local conditions and
are project specific, so direct cooling, cooling tower or air/water cooling units and are not shown
here. Therefore at a cooling water circulation rate of approximately 35,600 m3/h (156,760 gpm),
a significant space requirement for cooling water supply or cooling tower also has to be taken
into account.
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Figure 6 - Possible Layout for a Carbon Capture Facility
3.3 Cost Impact and economic viability
Impact on Electricity Price
The capital expenses for a 49 % slip stream post carbon capture facility based on Siemens
PostCap™ technology were estimated for a supercritical pulverized coal power plant with a
defined gross output of approximately 535 MWe and at the environmental conditions described
in NETL Report, Case 11 [5]. The cost is distributed among several portions as shown in
Figure 7.
Columns incl. internals
28.3%
16.2%
5.4%
14.7%
7.2%
13.2%
CO2 Compression
Other equipment
Bulk material
Construction
15.0%
Civil
Others/owners cost
Figure 7 – CAPEX Distribution for CCS Plant
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The addition of PostCap to the power plant is estimated to increase the CAPEX per kWe by 6070% and increase the OPEX per MWh by 30-35%. OPEX strongly relates to local utility prices
(e.g. steam, electricity, water). In this paper it is assumed that steam and electricity are supplied
internally by the power station without any additional cost, except for the power penalty related
to a decreased net output of the plant.
Using a simplified calculation taking into account CAPEX depreciation over 20 years and OPEX
including power penalty, solvent refill, and operation and maintenance, a CO2 cost of
approximately $80-58/tonne CO2 captured seems feasible. Not considered in this paper are cost
for transport and storage of the captured CO2. Those costs project-specific have to be evaluated
and added depending on local infrastructure, distance to and characteristics of the storage
location.
Table 4 shows the resulting data for the reference configuration used in this study. EPA limits
were met by capturing 90% of the CO2 from approximately 49% of the flue gas stream.
Power plant
only
Plant Thermal input
MWth
Steam Turbine Power
(gross)
Power plant incl. Delta
carbon capture
1,400
1,400
0
MWe
580
535
-45
Plant Auxiliary Power
MWe
-30
-65
-35
Plant Net Power
MWe
550
470
-80
Plant Net Efficiency (HHV)
%
CO2 emission to atmosphere
kg(lb)
/MWhe(g)
39.3
760
(1675)
33.6
460
(1014)
5.7
-300
(-661)
Table 4: plant performance data without and with carbon capture
The net output of the power plant decreases 15% from 550 MW to 470 MW, leading to a 5.7 %point reduction in efficiency. At 7,500 hours of operation per year this results in an electrical
production of 3,525,000 MWh/a (net). The specific CO2 emission is reduced by 300 kg/MWh
(gross) (662 lb/MWh(gross)) leading to an amount of 1,459,000 tonnes of CO2 captured per year.
These performance estimates are for the CO2 capture system retrofitted into an existing coalsteam plant without modifying the steam turbine. In the retrofit case, relatively high-quality
steam is extracted from the steam cycle to regenerate the sorbent, then throttled and cooled
without any further utilization.
The performance penalty would be smaller if the steam turbine could be modified for optimal
steam extraction, or if a back-pressure turbine could be added to utilize more energy from the
higher-pressure steam. It might also be possible to replace the intermediate pressure section with
a new design that allows steam extraction at the desired conditions. Newly built power stations
offer still more options, although the available turbine designs might still not be optimal, and
consideration of turbine part-load behavior can increase the complexity of the analysis. In any
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case, attention to detail when integrating the CO2 capture system with the power block can help
reduce the overall plant performance loss associated with the retrofit.
Taking into account the above mentioned costs of $80-85/tonne CO2 captured the application of
a CCS Plant at a coal fired power plant to reach the new EPA requirements would lead to a
penalty of $30-35/MWh for the electricity price. It has to be stated that this value is based on a
lot of assumptions where local environmental and industrial conditions and market situation are
involved.
Enhanced Oil Recovery (EOR)
Primary oil recovery methods can produce only about 10-15 % of the oil in an oil field, and
secondary methods such as water injection can re-pressurize the well and increase oil recovery to
20 - 40 %. A tertiary (enhanced) recovery method such as CO2 injection can increase recovery
up to 30 – 60% by mixing CO2 with the oil to decrease its viscosity while increasing its
pressure.[7]
The quality of the CO2 generated in the PostCap™ process can meet the requirements for EOR
applications, when CO2 purification steps are applied in combination with CO2 compression.
Published reports indicate market prices of $40 – 80 per tonne of CO2.[8]
There is already an existing CO2 pipeline infrastructure in the US serving regions around Texas
and Louisiana, as shown in Figure 8. US oil wells produced about 103 million barrels of oil
using 62 million tons of CO2 for EOR in 2012 [9], and the US market for CO2 is expected to
grow. There are an estimated 80,000 million barrels of oil under the US that could be
economically recovered using EOR, and approximately 25,000 million metric tons of CO2
would be required for this recovery.[10] For comparison, the Summit Texas Clean Energy IPCC
Project produces 2.5 million metric tons of CO2 per year, so it would take 500 Summit-sized
plants operating for 20 years to meet the potential CO2 market for EOR in the US.
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August 20-22, 2014
Figure 8 - Active US CO2 Pipeline and Injection Site Infrastructure [11]
Future Improvements and Cost Reductions
It has to be stated that a CCS plant will require a huge investment. At the current state of CCS
development, the technology still has a high potential for optimization and further cost
reductions as the process matures.
With increasing confidence in the technology based on operational experience, processes can be
optimized in regard to temperature, pressure and volume flow. Use of cheaper materials will be
investigated and could lead to further cost reduction.
For a real project, and especially with increasing market for plants with CO2 capture, equipment
cost will decrease based on common purchasing levers.
4 Conclusion
The paper shows that a carbon capture plant using Siemens PostCap™ technology can meet EPA
requirements for a medium-to-large size coal fired power plant in the US. Depending on the
growth of electricity production in the USA, “clean coal” solutions may become viable options
in future energy scenarios. The use of CO2 for EOR will assist in quicker market introduction of
CO2 capture technology.
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Large scale employment of CO2 capture technology is possible today. However, further
development of CO2 capture technologies is necessary to reach higher maturity and confidence
while decreasing costs for full scale applications.
5 References
[1]
EIA, Annual Energy Outlook 2014 Early Release, December 2013. Table 9, Electric
Generating Capacity
[2]
EPA, 40 CFR Part 60, Subpart Da – Standards if Performance for Electric Utility
Steam Generating Units, sections 60.42Da, 60.43Da, and 60.44Da.
[3]
McCarthy, James E., EPA Standards for Greenhouse Gas Emissions from Power
Plants: Many Questions, Some Answers, November 15, 2013.
[4]
Tarr, Jeremy M., Jonas Monast & Tim Profeta, Nicholas Inst. for Envtl. Policy
Solutions, Duke Univ., Regulating Carbon Dioxide under Section 111(d) of the Clean
Air Act: Options, Limits, and Impacts (2013),
http://nicholasinstitute.duke.edu/climate/policydesign/regulating-carbon-dioxideunder-section-111d
[5]
NETLa, Cost and Performance Baseline for Fossil Energy Plants, Volume 1,
Bituminous Coal and Natural Gas to Electricity, Revision 2, DOE/NETL-2010/1397,
November 2010.
[6]
NETLb, Updated Costs (June 2011 Basis) for Selected Bituminous Baseline Cases,
DOE/NETL-341/082312, August 2012.
[7]
US Department of Energy, http://energy.gov/fe/science-innovation/oil-gas/enhancedoil-recovery
[8]
Bloomberg New Energy Finance, company filings
[9]
Godec, M. L., “Opportunities for Utilizing Anthropogenic CO2 for Enhanced Oil
Recovery and CO2 Storage,” presentation to Workshop: Introduction to Carbon
Dioxide Enhanced Oil Recovery (CO2-EOR), Houston Texas, June 11, 2013.
[10]
Van Leeuwen, T., “An Updated Review of US and Worldwide CO2-EOR
Resources,” prepared by Advanced Resources International for the 17th Annual
Midland CO2 Flooding Conference, Midland Texas, December 8, 2011.]
[11]
Melzer, L. Stephen, Carbon Dioxide Enhanced Oil Recovery (CO2 EOR): Factors
Involved in Adding Carbon Capture, Utilization and Storage (CCUS) to Enhanced Oil
Recovery, prepared for the National Enhanced Oil Recovery Initiative, Center for
Climate and Energy Solutions, February 2012.
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Permission for use
The content of this paper is copyrighted by Siemens and is licensed to COAL-GEN for
publication and distribution only. Any inquiries regarding permission to use the content of this
paper, in whole or in part, for any purpose must be addressed to Siemens directly.
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