Scholarly article on topic 'Towards large scale CCS'

Towards large scale CCS Academic research paper on "Chemical engineering"

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Abstract of research paper on Chemical engineering, author of scientific article — Trina Dreher, Craig Dugan, Trent Harkin, Barry Hooper

Abstract In order to reduce CO2 emissions on a global scale large pilot and demonstration projects that trial new technologies, designs, or construction techniques applicable to full scale plants need to be undertaken. Process Group has designed and built several pilot scale capture plants including one located at the Hazelwood Power Station, which is the largest capture plant on a coal fired power station in Australia. This paper discusses some of the lessons from these pilot plants and presents a new retrofit post-combustion study that investigates carbon capture from a 500 MW power station (nominally 3.7 million tpa CO2) using three solvents with and without heat integration into the steam cycle. Data pertaining to processing 25% of the flue gas from a 500 MW power station (nominally 0.9 million tpa CO2) is also presented. The study found <5% difference between existing solvent processes in terms of overall plant CAPEX and <15% difference in OPEX and that for the end user the most advantageous way to design a capture plant is to ensure that it functions with a wide range of solvents and can be easily adapted for future technology advances. The cost of capture for a 500 MW brown coal power station with non-optimised heat integration was determined to be in the range AUD$53-63/t CO2 avoided, which incorporated an improvement of approximately $8-13/t due to the non-optimised heat integration. The heat integration resulted in modest (5%) energy and cooling duty savings however, with further optimisation performed specific to the given power station and capture plant it is expected that the cost of capture could be further reduced to at or below AUD$50/t CO2 avoided. In situations where cooling water is used exclusively for a full scale capture facility the cooling water usage increased by 85–95%. However, when enhanced heat integration is incorporated this increase is expected to be limited to 75–80% for all technologies analysed.

Academic research paper on topic "Towards large scale CCS"

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Procedía

Energy Procedía 4 (2011) 5549-5556 :

www.elsevier.com/locate/procedia

GHGT-10

Towards large scale CCS

Trina Drehera, Craig Dugana *, Trent Harkinb, Barry Hooperb

a Process Group, 5 Hobbs Court, Rowville, Vic., 3178, Australia b Cooperative Research Centre for Greenhouse Gas Technologies (CO2CRC), The University of Melbourne, Vic., 3010, Australia

Abstract

In order to reduce CO2 emissions on a global scale large pilot and demonstration projects that trial new technologies, designs, or construction techniques applicable to full scale plants need to be undertaken. Process Group has designed and built several pilot scale capture plants including one located at the Hazelwood Power Station, which is the largest capture plant on a coal fired power station in Australia. This paper discusses some of the lessons from these pilot plants and presents a new retrofit postcombustion study that investigates carbon capture from a 500MW power station (nominally 3.7 million tpa CO2) using three solvents with and without heat integration into the steam cycle. Data pertaining to processing 25% of the flue gas from a 500MW power station (nominally 0.9 million tpa CO2) is also presented.

The study found <5% difference between existing solvent processes in terms of overall plant CAPEX and <15% difference in OPEX and that for the end user the most advantageous way to design a capture plant is to ensure that it functions with a wide range of solvents and can be easily adapted for future technology advances. The cost of capture for a 500 MW brown coal power station with non-optimised heat integration was determined to be in the range AUD$53-63/t CO2 avoided, which incorporated an improvement of approximately $8-13/t due to the non-optimised heat integration. The heat integration resulted in modest (5%) energy and cooling duty savings however, with further optimisation performed specific to the given power station and capture plant it is expected that the cost of capture could be further reduced to at or below AUD$50/t CO2 avoided. In situations where cooling water is used exclusively for a full scale capture facility the cooling water usage increased by 85-95%. However, when enhanced heat integration is incorporated this increase is expected to be limited to 75-80% for all technologies analysed.

© 2011 Published by Elsevier Ltd.

Keywords: Carbon Capture and Storage; Post-combustion Capture; Hazelwood; Integration; Energy Penalty; Cost of Capture

1. Introduction

Coal is the primary fuel for over 80% of Australia's current power supply and is one of the largest contributors to Australia's total domestic greenhouse gas emissions. Post-combustion Carbon Capture and Storage (CCS) is seen as a way of significantly reducing power station emissions however, the challenges in implementing CCS on a large scale are many. Process Group has designed and built several pilot scale capture plants, including the largest plant

* Corresponding author. Tel.: +61-3-9212-7100 fax: +61-3-39212-7199. E-mail address: craig.dugan@processgroup.com.au

ELSEVIER

doi:10.1016/j.egypro.2011.02.542

on a coal fired power station in Australia. The lessons from these pilot plants combined with a retrofit postcombustion study are presented in this paper. The detailed study looks at carbon capture from a 500MW power station (nominally 3.7 million tpa CO2) using three different solvents with and without heat integration into the steam cycle. Given that a large scale pilot carbon capture plant will be built before such a full scale plant, we also present data pertaining to processing 25% of the flue gas from a 500MW power station (nominally 0.9 million tpa CO2).

2. Carbon Capture and Sequestration at the Hazelwood Power Station

In early 2009 Process Group completed commissioning of a 15,500 tpa pilot carbon capture and mineral sequestration plant it designed and fabricated for International Power's Hazelwood Power Station. Hazelwood is a 1600MW nominal capacity brown coal fired power station that supplies up to 25% of Victoria's electricity needs, which is equivalent to approximately 5% of Australia's National Electricity Market.

The Hazelwood pilot capture plant follows the standard solvent absorption process however, some modifications to this process were made so that the plant can operate with multiple solvents including BASF's PuraTreat™ F, generic amines, and carbonate solvents. A portion of the CO2 captured is sequestered via an innovative process that results in the production of calcium carbonate and eliminates the need for expensive waste water treatment chemicals. Waste ash water from the power station contains a high concentration of dissolved calcium hydroxide and as such has a pH in the order of 12 that needs to be reduced before it can be discharged. The treatment system designed by Process Group injects the captured CO2 into the ash water where it reacts with the dissolved calcium to form calcium carbonate. The reaction lowers the solution pH and sequesters the injected CO2 as a solid calcium carbonate product.

2.1. Issues Facing Small Scale Pilot Plants

Small scale capture plants, such as the unit at Hazelwood face a range of economic challenges that make it very difficult to demonstrate new technologies, designs, or construction techniques because such advances are frequently considered too risky to implement. In addition, small scale and demonstration capture pilot plants (<0.3 million tpa CO2) are of a size that they can be designed and built using standard engineering practices and as such new designs and technologies aimed at reducing the size and cost of large scale capture plants are often deemed too risky for incorporation into these demonstration plants. Therefore, most small scale pilot plants do not include technologies, such as heat integration, alternate vessel construction, or new absorber internals that may have higher technical risk but offer significant potential for future reduction of the cost of carbon capture.

Funding mechanisms for demonstration CCS projects also often hamper technology development in that they are funded by research or governmental organisations under a lump sum grant to cover the plant capital (CAPEX) and operating (OPEX) expenditures over the life of the project. This type of funding has two significant disadvantages; (i) short project life times discourage the end user to make any significant modifications to existing infrastructure and (ii) as the funding level is fixed rather than being linked to parameters such as the amount of CO2 avoided or technology advances, the end user has little incentive to try to decrease OPEX or increase plant efficiency. The result is that there is little incentive to trial new technology so many small scale pilot plants do little except demonstrate already proven technology.

3. Large Scale CCS

The International Power pilot capture plant only captures in the order of 0.1% of the Hazelwood Power Station's total CO2 emissions. For CCS to significantly reduce emissions from stationary sources much larger capture plants need to be built. This retrofit study for full scale post-combustion capture from a 500MW power station investigates the effect of heat integration for three different solvents. This study assumes that certain emerging technologies, such as the Ramgen Supersonic Compressor, and mechanical limitations, such as fluid distribution in large columns, will be resolved in the years before such a plant is actually built. While this study should be considered indicative, all key issues have been addressed and the general conclusions reached are considered applicable to future studies.

3.1. Study Methodology

The study examines retrofit post-combustion capture (PCC) on a 500 MW brown coal fired power station in the Latrobe Valley using three solvents at two separate flow rate cases. It should be noted that due to the low cost and low sulphur content (<1%) of the coal, such power stations are relatively inefficient and do not have flue gas desulphurisation (FGD) or nitrogen removal (DeNOx) units. Furthermore coal drying is not installed.

Process simulation of the Power Station steam cycle and its integration into the capture plant closely follows that described previously for similar studies [1,2]. The economic analysis follows the previously described CO2CRC/UNSW methodology for CCS projects [3]. In this instance, the actual installed capital costs have been estimated by Process Group together with standard setup costs and a project contingency. The CAPEX and OPEX figures quoted are for an installed and fully operational capture and compression plant and include auxiliary costs such as chemical storage facilities, steam cycle modifications, and costs associated with providing for the increased cooling water demand. The basis of design is given in Table 1 and although it is for Australian brown coal conditions the study is sufficiently generic for the conclusions to be relevant for capture plants around the world.

Three solvents were considered for this study; amine, glycinate, and carbonate. It should be noted that amine and glycinate based solvents are extensively used in current commercial solvent processes however, the carbonate process presented here is an emerging precipitating solvent technology under development by the CO2CRC. Precipitating solvent systems have lower circulation rates compared to conventional systems and as such could reduce plant CAPEX and OPEX. Energy to run the capture plant is obtained parasitically from the power station. Specifically, all electrical power for the capture plant is supplied directly from the power station's generator thereby decreasing the sent out power. Steam supplied directly from the LP turbine is used as the reboiler heat source. In order to reduce the parasitic energy load, heat integration between the capture plant and the steam cycle was incorporated into each capture plant design broadly as shown in Figure 1. In this study heat integration refers to integration of energy from the power station, such as flue gas and condensate from the steam cycle, with the heat exchangers of both the capture plant and power station. There are many different heat integration options that could have been investigated and optimised for each specific solvent however, for simplicity and ease of comparison we have chosen a single heat integrated design. The integrated exchangers were selected so that the condensate is returned to the deaerator to maintain a deaerator temperature of approximately 170 °C. The design is not optimised for either the steam cycle nor each solvent and is designed to illustrate the potential efficiency gains that heat integration offers. It is of note that previous work [2] showed target parasitic loads resulting from heat integration improvements for a similar power station to be as low as 11-19% depending on the extent to which coal drying was incorporated into the design. Such low parasitic loads may be possible due to the considerable available heat in the exhaust flows from relatively inefficient power stations.

3.2. Process Design

The capture design proposed for each solvent largely follows the standard solvent absorption system as given in Figure 1. The main differences are summarised in Table 2: Due to the low sulphur content of the coal used in this study FGD or DeNOx treatment was not employed for any solvent however, due to amine's intolerance to SOx 20wt% caustic scrubbing was used only for the amine solvent. Mechanical vapour recompression was considered however, for the cases investigated its incorporation was found to be unfavourable as the compressor and associated equipment significantly increased the plant CAPEX and energy penalty. Nevertheless, such a configuration may prove to be beneficial in other situations.

In order to investigate the benefits of direct heat integration between the carbon capture plant and the power station's steam cycle the following streams were targeted as illustrated in Figure 1: Firstly, the steam required for the reboiler is desuperheated as it exits the LP turbine and is fully condensed in the reboiler. The condensate is then pumped through the compressor inter and after coolers, heating it before it returns to the deaerator. Secondly, condensate from the LP turbine passes through the capture plant condenser and then the flue gas economiser before it also returns to the deaerator. The flue gas economiser is designed by ERK and pre cools the flue gas before final cooling in the Scrubber section of the Absorber tower. In the non-heat integrated cases these exchangers are all cooled via cooling water.

Table 1: Design Basis

25% Flue gas processed (125MW equiv.) 100% Flue gas processed (500ME equiv.

Gross/Net power output before CCS 520 / 500 MWe

Thermal efficiency 35% LHV

Flue gas flow rate 809,500 kg/h 3,238,000 kg/h

Flue gas inlet conditions 2 kPag, 192 °C

Flue gas compositions (mol %) CO2 11.0%, N2 + Ar 62.6%, O2 3.9%, H2O 22.5%

Flue gas impurities (ppmv, dry basis) NOx 151, CO 13.9, SO2 211, SO30.5

CO2 emission before capture 4,949,000 tpa

Overall CO2 recovery rate (mass basis) 85 %

CO2 product (at compressor discharge) > 99 mol%, 150 bara , 50 °C

Fuel (coal) cost (AUD$/GJ HHV) 0.7

Project life (years) 25

Construction period (years) 2

Plant capacity factor (%) 85 %

Discount rate (% real) 7 %

Electricity selling price (AUD$/MWh) 40

Table 2: Process Design Comparison

25% Flue Gas Processed (125 MW equiv.) 100% Flue Gas Processed (500MW equiv.)

Solvent Amine Glycinate Carbonate Amine Glycinate Carbonate

CAPEX (Millions AUD$ 2010 ±20%) 253 253 253 621 615 602

OPEX (Millions AUD$ 2010 ±15%) 23 21 22 64 58 61

LCOE (Millions AUD$ 2010/MWh) 58 58 58 111 108 107

Relative lean solvent flow rate 1.9 2.5 1 1.9 2.5 1

Absorber solvent intercooler Yes No Yes Yes No Yes

Absorber wash section Yes No No Yes No No

Note: All values are indicative and should not be taken as definitive project design. Separate CAPEX, OPEX, and LCOE figures for the (i) with and (ii) without heat integration cases are not shown however, within study accuracy they are effectively the same in this instance.

3.3. Plant Comparison

The Cost of Capture

As shown in Table 2, within the accuracy of this study, the plant CAPEX for each of the three solvents is the same at AUD$253 and $613 million respectively for the 25% and 100% plants. Even though there are some differences between the solvent designs, this has little effect on the overall plant cost as the capture and compression plant equipment only accounts for ~50% of the total plant CAPEX. In accurately costed smaller capture plants (<100,000 tpa CO2) without FGD or DeNOx units Process Group also found very similar CAPEX figures across a range of commercial solvents further confirming that designing plants to operate with a range of solvents has little impact on overall CAPEX. As such, this conclusion enables the end user to operate with the best available solvent at any given time and gives them the ability to take advantage of advances in solvent technology over the life of the capture plant. The OPEX showed greater variance with a range of AUD$58-64 million, although the difference is within data accuracy of ±15%. This difference is largely dictated by the cost of replacement and disposal of solvent

and other chemicals that can vary greatly between solvents. As such, OPEX figures can vary significantly according to the solvent chosen and should be determined on a case by case basis.

Figure 2 illustrates that the cost of capture for heat integrated plants, expressed as AUD$ per tonne CO2 avoided, for the three solvents is in the range AUD$53-63/t CO2 avoided (100% plant). This figure incorporates an improvement of $8-13/t due to the heat integration. The reduction is largely due to the increase in sent out power, as discussed below. It is expected that with optimisation of heat integration the cost of capture could be further reduced to at or below AUD$50/t CO2 avoided for the best option. The results also indicate that the cost of capture is significantly greater for the smaller scale (25%) plant due to the lower amounts of CO2 captured.

Figure 1: Schematic of heat integrated capture plant and steam cycle

Energy Penalty

Figure 3 (a) and (b) illustrate that with heat integration the full scale CCS plant results in a 23-28% reduction in sent out power, which is equivalent to 8-10% reduction in thermal efficiency. Figure 4 shows the impact on cooling water demand with the inclusion of the capture plant resulting in an 85-95% increase in cooling water duty. Further optimisation of the heat integration system for this application is expected to decrease parasitic losses to between 15-20%. This would also reduce the cooling water impact, limiting the increase on the base load cooling duty to an additional 75-80%. Heat integration optimisations could include improved and additional process integration between the capture plant and the power station such as more complete matching of the available hot and cold streams, heating boiler feedwater streams downstream of the deaerator, incorporating coal drying options, and using steam turbine drives for applications such as the CO2 compressor. As discussed above, the improved efficiency resulting from heat integration significantly decreases the cost of capture.

Capture plant cooling water duties vary between the solvents mainly due to differences in the solvent circulation rate, the condenser operating conditions, and the requirement of a solvent wash section or intercooler however, the total amount of cooling water required for the capture plant and steam cycle varies less than 15% across all solvents. Heat integration does reduce the quantity of cooling required in the capture plant however, this reduction is offset by an increase in demand in the steam cycle due to the increase in sent out power. It should be noted that the basis of this study was restricted to the use of cooling water and no effort was made to investigate air cooling, which would allow further reductions in cooling water requirements.

Cost of Capture

$120 $100

GLYCINATE

CARBONATE

EJ100% Without heat integration

□ 100% With heat integration

□ 25% Without heat integration H 25% With heat integration

Figure 2: Cost of Capture (Bars from left to right 100% with/without heat integration, 25% with/without heat integration)

(a) Energy Penalty - Reduction in sent out power

40% T 35% -30% -25% -20% -15% -10% -5% -0% -

GLYCINATE CARBONATE

(b) Energy Penalty - Reduction in thermal efficiency

14% - %

12% - %

ÍÍ10% -c 1 0

R 8% -

^ 6% -5 4% - 1

GLYCINATE CARBONATE

Figure 3: Energy Penalty of Capture. Reduction in (a) Sent out power, (b) Thermal efficiency. (Bars from left to right 100% with/without heat integration, 25% with/without heat integration)

Levelized Cost of Electricity (LCOE)

The LCOE for a capture facility incorporates the added cost and energy impacts of the plant into the most significant variable for a power generator. The various costs for each of the cases in this study were imposed on a base plant LCOE of AUD$40/MWh. The calculation of LCOE also includes an allowance of AUD$15/t CO2 for the storage component, which is considered appropriate for storage locations near to the Latrobe Valley. As given in

Table 2 the resulting LCOE ranges from AUD$107-111/MWh for the full scale case and AUD$58/MWh for the 25% case.

Cooling Water Demand Increase

120% -

i 100% -e

i 80% -gn

1 60% -o c

2 20% -r c

- 0% -

AMINE GLYCINATE CARBONATE

□ 100% Without heat integration

□ 100% With heat integration

□ 25% Without heat integration

□ 25% With heat integration

Figure 4: Cooling water demand increase of PCC plant (Bars from left to right 100% with/without heat integration, 25% with/without heat integration)

Scrubber/Absorber Vessel Design

Due to the very large diameter (~22m) and height (~49m) of the Scrubber/Absorber vessel it may be impractical to construct this vessel from steel. A more practical and possibly cost effective alternative is to construct the vessel from concrete and line it with thin stainless steel in order to protect the concrete from chemical attack. The Scrubber/Absorber vessels included in this study were designed to be built in concrete taking into account the loads from the various internal structures and packing and the relevant environmental conditions. A circular vessel cross-section was deemed most suitable in terms of constructability and cost.

WES Froth Absorber Technology

The Scrubber/Absorber vessel is one of the most expensive equipment items in the capture plant costing in the order of $20 million (100% plant) and accounts for approximately 3.5% of the total operational capture plant CAPEX. Given the significant cost of the Scrubber/ Absorber vessel, any means of simplifying the internals or reducing the absorber height could significantly reduce vessel cost. Revolutionary advances in internals design, such as the WES Froth Technology proposed by Westec Environmental Solutions [4], could lead to reductions in Absorber section height by 50% thereby decreasing the Scrubber/Absorber cost in the order of $5-8 million. The WES technology incorporates novel patented Micro Froth Absorber technology where conventional packing is replaced by the WES patented froth generators. In this manner mass transfer is facilitated across a froth matrix generating mass transfer surface areas many times higher than through conventional random or structured packing thereby resulting in lower absorber heights.

Solvent and Chemical Usage

Solvent and chemical make-up and disposal costs contribute 30-40% to total OPEX however, for generic solvents this figure would be closer to 20-30% as commercial solvents are at least 50% more expensive than their generic counterparts. Solvent costs can vary significantly between solvents due to differences in solvent make up rates, primarily due to differences in solvent degradation rates which are higher for generic solvents, and this factor needs to be analysed on a case by case basis. For this study we have calculated make up rates based on typical degradation rates for the given solvent.

The very large solvent and chemical inventories required for full scale capture will present several handling issues associated with chemical manufacture, transport, storage, and disposal. It is Process Group's experience that end users prefer solvents with low toxicity to reduce their risk in case of spills or accidents and to facilitate ease of disposal. In particular, the formation of carcinogenic nitrosamines and their potential release to the environment may

be a major impediment for amine based solvents. Process Group has seen a strong preference by end users for glycinate rather than amine based solvents due to the elimination of such toxic by-products. Compression

To render the recovered CO2 vapour in a state suitable for geosequestration, the vapour is compressed and between compression stages water is removed via conventional CO2 glycol dehydration. The compressor used could be a conventional (e.g. gear type) multi-stage compressor however, in this study we use a 2-stage Ramgen Compression Systems supersonic compressor [5] as it offers the opportunity for significant waste heat recovery with stage discharge temperatures in the order of 250 °C. Compared to conventional technologies Ramgen's shock compression technology represents a significant advancement in the state of the art for many compressor applications and specifically for CO2 compression. The principle advantage of Ramgen's shock compression is that it can achieve high compression efficiency at very high single stage compression ratios resulting in a product simplicity and size that will lower both manufacturing and operating costs. Costing ~$28 million (100% case) the Ramgen compressor accounts for ~4.8% of the total plant CAPEX. The compressor also accounts for ~75% of the CCS plant's total power usage to drive the compressor motors. For the three solvents the 100% case requires 1013% of the power station's total generation capacity to run the compressor. Since a greater amount of power is required as the suction pressure decreases, high regeneration pressures favour lower compressor power usage.

4. Conclusion

The following conclusions are drawn from this study and previous work performed by Process Group on small scale capture plants without FGD or DeNOx facilities:

• There is <5% difference between existing solvent processes in terms of overall plant CAPEX and <15% difference in OPEX.

• The most advantageous way to design a capture plant for the end user is to make it flexible so that it functions with a number of commercial solvents and that it is able to be adapted to enable the end user to change the solvent or operating conditions to take advantage of advances in solvent design.

• The cost of post-combustion capture for a retrofit to a 500 MW brown coal power station with non-optimised heat integration is in the range AUD$53-63/t CO2 avoided. This figure incorporates an improvement of approximately $8-13/t due to the heat integration. With further design and process optimisation performed specific to the given power station and capture plant it is expected that the cost of capture could be reduced to at or below AUD$50/t CO2 avoided.

• A primary concern of the end user is chemical safety and as such there is a strong preference for solvents that exhibit low toxicity and low volatility.

5. Acknowledgements

The authors gratefully acknowledge the cooperation of the following organisations in this study; CBI Constructors, Cooperative Research Centre for Greenhouse Gas Technologies (CO2CRC), ERK Eckrohrkessel, International Power, Leighton Contractors, and Ramgen Compression Systems. Thanks are also extended to Dr. M. Ho (CO2CRC/UNSW) for assistance with the economic analysis.

6. References

[1] Harkin, T., Hoadley, A, and Hooper, B., Process integration analysis of a brown coal-fired power station with CO2 capture and storage of lignite drying, Energy Procedia 1, 2009, 3817-3825.

[2] Harkin, T., A. Hoadley, and B. Hooper, Reducing the energy penalty of CO2 capture and compression using pinch analysis, Journal of Cleaner Production, 2010, 18(9), 857-866.

[3] Allinson, W.G., Neal, P.R., Ho, M., Wiley, D.E. and McKee, G.A., 2006. CCS economics methodology and assumptions, School of Petroleum Engineering, The University of New South Wales, Sydney, Australia. CO2CRC Report Number RPT06-0080.

[4] Westec Environmental Solutions (WES), www.wes-worldwide.com

[5] Ramgen Compression Systems, www.ramgen.com