The 13th Annual Carbon Capture, Utilization & Storage Conference ,
Pittsburgh, USA, April 28 - May 1, 2014
Optimization of a CO2 post-capture plant to fit
proposed EPA requirements for US based coal
fired power plants
Dennis Horazak, Michael Horn, Harry Morehead, Albert Reichl, Oliver
Reimuth
Copyright © Siemens AG, 2014. All rights reserved.
Optimization of a CO2 post-capture plant to fit proposed EPA requirements for US based
coal fired power plants
TableofContents
1
Executive Summary ........................................................................................................................ 2
2
Introduction ..................................................................................................................................... 2
2.1
Coal fired power plants in US ................................................................................................. 2
2.2
EPA requirements ................................................................................................................... 3
2.3
Typical configuration of a modern supercritical coal fired steam power plant....................... 3
3
Application of Siemens PostCapTM to a typical US coal-fired steam power plant under proposed
EPA requirements ................................................................................................................................... 5
3.1
Siemens PostCapTM technology .............................................................................................. 5
3.2
PostCapTM CO2 Capture Plant design ..................................................................................... 6
3.2.1
Plant design resulting from EPA requirements and NETL configuration ...................... 6
3.2.2
Plant design resulting from Siemens PostCap™ process requirements .......................... 7
3.3
Cost Impact and economic viability ........................................................................................ 9
4
Conclusion .................................................................................................................................... 11
5
References ..................................................................................................................................... 11 1/11
Optimization of a CO2 post-capture plant to fit proposed EPA requirements for US based
coal fired power plants
1 ExecutiveSummary
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 CoalfiredpowerplantsinUS
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.
Figure 2 –US Electric Generating Capacity Changes from 2013 through 2040 [1]
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Optimization of a CO2 post-capture plant to fit proposed EPA requirements for US based
coal fired power plants
2.2 EPArequirements
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/MWhgross) 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 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.
2.3 Typicalconfigurationofamodernsupercriticalcoalfiredsteampower
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 forced-draft
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 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 3.
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Optimization of a CO2 post-capture plant to fit proposed EPA requirements for US based
coal fired power plants
Figure 3 – 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.
Plant Thermal input
Steam Turbine Power (gross)
Plant Auxiliary Power
Plant Net Power
Plant Net Efficiency (HHV)
MWth
MWe
MWe
MWe
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
MPa (psia)
°C (°F)
MPa (psia)
°C (°F)
MPa (psia)
°C (°F)
MWth
MPa (psia)
°C (°F)
Coal type
1,400
580
30
550
39.30%
24 (3515)
593 (1100)
4.5 (656)
593 (1100)
1.2 (170)
392 (737)
638
0.01 (1)
38
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)
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Optimization of a CO2 post-capture plant to fit proposed EPA requirements for US based
coal fired power plants
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 ApplicationofSiemensPostCapTMtoatypicalUScoal‐firedsteam
powerplantunderproposedEPArequirements
3.1 SiemensPostCapTMtechnology
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 plants as well as from
industrial sources. Figure 4 shows the principal Siemens PostCap process configuration.
Cleaned Flue Gas
Solvent Reclaiming
CO2 Compression
CO2 Absorption
CO2 Desorption
Flue gas inlet
Figure 4 – 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.
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Optimization of a CO2 post-capture plant to fit proposed EPA requirements for US based
coal fired power plants
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 vapour pressure
 Good solvent stability against various degradation mechanisms, particularly against oxygen
and - as a result - low solvent refill need
 Ease of handling by power station operators and personnel.
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 with coal and gas based flue gas in
the PostCap™ pilot plant at E.ON’s Staudinger Power Plant in Germany since September 2009.
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 as a
basis of project development 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 largescale 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 desulphurization vs. cost of
reclaiming). Furthermore a highly selective separation of the amino acid salt solvent from other byproducts is applied in the second reclaiming step and thus a high recyclability assured. Each step of
the reclaimer can be operated independently (either continuously or batch-wise), which allows tailormade 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 PostCapTMCO2CapturePlantdesign
Based on the reference coal fired plant (NETL Case 11) as described under 3.1 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 clause 2.2 for
a reference power plant and
b) use a sophisticated design to reduce necessary investment and operating costs.
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 solution for supply mainly of steam and power (but also
for other necessary utilities) out of the existing systems. Furthermore, additional space restrictions in
the existing plant layout have to be considered.
3.2.1 PlantdesignresultingfromEPArequirementsandNETLconfiguration
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
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Optimization of a CO2 post-capture plant to fit proposed EPA requirements for US based
coal fired power plants
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 to the Siemens PostCap™ process.
Fluegas @ CCP inlet
Temperature
Pressure
composition
CO2
N2
O2
Ar
H2O
Total amount
by-products
57 °C
1,0077 bara
amount kg/h
216.179
692.391
27.881
0
99.218
1.047.562
amount kg/h
135°F
3,11 INWC
Mass fraction
20,6%
66,1%
2,7%
0,0%
9,5%
vol fraction
13,5%
68,1%
2,4%
0,0%
15,2%
ppmv
NOx
45
NO2
2
SO2
88
38
SO3
3
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.
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 PlantdesignresultingfromSiemensPostCap™processrequirements
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 site-erected 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).
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Optimization of a CO2 post-capture plant to fit proposed EPA requirements for US based
coal fired power plants
Absorber column design
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.
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 design:
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).
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). A possible arrangement is shown in
Figure 5. 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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Optimization of a CO2 post-capture plant to fit proposed EPA requirements for US based
coal fired power plants
Figure 5 - Possible Layout for a Carbon Capture Facility
3.3 CostImpactandeconomicviability
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]. They are distributed on several portions as shown in Figure 6.
Columns incl. internals
28,3%
16,2%
5,4%
Other equipment
14,7%
7,2%
CO2 Compression
Bulk material
13,2%
Construction
15,0%
Civil
Others/owners cost
Figure 6 – CAPEX distribution for CCS plant
The addition of PostCap to the power plant is estimated to increase the CAPEX per kWe by 60-70%
and increase the OPEX 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 $
80-85/t CO2 captured seems feasible. Not considered in this paper are cost for transport and storage of
the captured CO2. Those costs have to be evaluated and added project specific depending on local
infrastructure, distance to and characteristics of the storage location.
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Optimization of a CO2 post-capture plant to fit proposed EPA requirements for US based
coal fired power plants
Table 4 shows the resulting data for the reference configuration used in this study.
Power plant
only
Power plant incl.
carbon capture plant
Delta
Plant Thermal input
MWth
1,400
1,400
0
Steam Turbine Power (gross)
MWe
580
535
-45
Plant Auxiliary Power
MWe
30
65
+35
Plant Net Power
MWe
550
470
-80
Plant Net Efficiency (HHV)
%
39.3
33.6
5.7
CO2 emission to atmosphere
kg/MWe(g)
760
460
-300
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 h 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 t CO2 captured per year.
Taking into account the above mentioned costs of $ 80-85/t CO2 captured and compressed 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)
A growing market for CO2 as a product is expected in the USA based on EOR opportunities. In EOR
CO2 is used to extract additional oil from depleted oil fields. An oil field can yield under normal
circumstances only about 10-15 % of its oil content. With secondary measures such as water or gas
injection the percentage can be increased to 20 - 40 %. Using CO2 for injections has the additional
benefit that besides the increased pressure in the field the viscosity of the oil is decreased so that in
total 30 - 60 % of the original oil in place may be extracted [7]. In the USA there is already an
existing pipeline infrastructure for CO2 in some regions like Texas and the Louisiana. 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 the CO2 compressor. Depending on the
location of the coal-fired plant the generated CO2 may be fed into such pipelines and used for EOR
with a commercial benefit to be further investigated. Published reports indicate CO2 market prices of
$40 – 80/ton of CO2.[8]
Utilization of CO2 for methane or methanol production
Under the assumption that hydrogen is available (such as from electrolysis driven by temporarily
available excess power from renewables), CO2 can be either converted to methane (natural gas) or to
methanol (raw material for chemical industry). These processes are still in the research state; however
once they have reached technical maturity, CO2 utilization could be boosted considerably.
Future improvements and cost reduction:
It has to be stated that a CCS plant will pose a huge investment. At the current situation of CCS
development, the technology still has a high potential for optimization and further cost reductions as
the process matures.
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Optimization of a CO2 post-capture plant to fit proposed EPA requirements for US based
coal fired power plants
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.
Based on these effects a midterm cost reductions of approximate 20 % can be expected.
4 Conclusion
The paper shows that a carbon capture plant using Siemens PostCap™ technology is feasible to fulfil
EPA requirements for a medium-to-large size coal fired power plant in the US. Depending on the
development of the electricity production in the USA “clean coal” solutions may become an option in
future energy scenarios. Further development of the technologies is necessary to reach higher maturity
and confidence as well as to decrease cost 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-dioxide-undersection-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/enhanced-oilrecovery
[8]
Bloomberg New Energy Finance, company filings
11/11
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13th Annual Carbon Capture, Utilization & Storage Conference
April 25 - May 1, 2014
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and certain assumptions, and are, therefore, subject to certain risks and uncertainties. A variety of factors, many of which are beyond Siemens’ control, affect its operations, performance,
business strategy and results and could cause the actual results, performance or achievements
of Siemens worldwide to be materially different from any future results, performance or
achievements that may be expressed or implied by such forward-looking statements. For us,
particular uncertainties arise, among others, from changes in general economic and business
conditions, changes in currency exchange rates and interest rates, introduction of competing
products or technologies by other companies, lack of acceptance of new products or services
by customers targeted by Siemens worldwide, changes in business strategy and various other
factors. More detailed information about certain of these factors is contained in Siemens’ filings with the SEC, which are available on the Siemens website, www.siemens.com and on the
SEC’s website, www.sec.gov. Should one or more of these risks or uncertainties materialize,
or should underlying assumptions prove incorrect, actual results may vary materially from
those described in the relevant forward-looking statement as anticipated, believed, estimated,
expected, intended, planned or projected. Siemens does not intend or assume any obligation to
update or revise these forward-looking statements in light of developments which differ from
those anticipated.
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