Optimization of a CO2 post-capture plant to fit proposed EPA ...

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Copyright © Siemens AG, 2014. All rights reserved. The 13 th 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

Transcript of Optimization of a CO2 post-capture plant to fit proposed EPA ...

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Copyright © Siemens AG, 2014. All rights reserved.

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

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TableofContents1 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 

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1 ExecutiveSummaryCoal 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 CoalfiredpowerplantsinUSBased 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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2.2 EPArequirementsBetween 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 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 Typicalconfigurationofamodernsupercriticalcoalfiredsteampowerplant

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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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 MWth 1,400 Steam Turbine Power (gross) MWe 580 Plant Auxiliary Power MWe 30 Plant Net Power MWe 550 Plant Net Efficiency (HHV) 39.30%

Steam main cycle pressure MPa (psia) 24 (3515) Steam main cycle temperature °C (°F) 593 (1100) Reheat steam pressure MPa (psia) 4.5 (656)

Reheat steam temperature °C (°F) 593 (1100) IP/LP steam crossover pressure MPa (psia) 1.2 (170) IP/LP steam crossover temperature °C (°F) 392 (737) Condenser cooling duty MWth 638 Condensation pressure MPa (psia) 0.01 (1)

Condensation temperature °C (°F) 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)

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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‐firedsteampowerplantunderproposedEPArequirements

3.1 SiemensPostCapTMtechnologyThe 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.

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.

CO2 Absorption CO2 Desorption

CO2 Compression

Solvent Reclaiming

Flue gas inlet

Cleaned Flue Gas

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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 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 desulphurization vs. cost of reclaiming). Furthermore a highly selective separation of the amino acid salt solvent from other by-products 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 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 PostCapTMCO2CapturePlantdesignBased 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 PlantdesignresultingfromEPArequirementsandNETLconfigurationTo 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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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 57 °C 135°F Pressure 1,0077 bara 3,11 INWC composition amount kg/h Mass fraction vol fraction CO2 216.179 20,6% 13,5% N2 692.391 66,1% 68,1% O2 27.881 2,7% 2,4% Ar 0 0,0% 0,0% H2O 99.218 9,5% 15,2% Total amount 1.047.562by-products amount kg/h 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™processrequirementsWhen 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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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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Figure 5 - Possible Layout for a Carbon Capture Facility

3.3 CostImpactandeconomicviabilityImpact 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.

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.

16,2% 5,4%

14,7%

15,0%13,2%

7,2%

28,3%

Columns incl. internals

CO2 Compression

Other equipment

Bulk material

Construction

Civil

Others/owners cost

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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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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 ConclusionThe 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-under-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/enhanced-oil-recovery

[8] Bloomberg New Energy Finance, company filings

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