POST COMBUSTION CARBON CAPTURE Thermodynamic Modelling
101010-00686 – PM-REP-0001
19 February 2013
GLOBAL CCS INSTITUTE POST COMBUSTION CARBON CAPTURE THERMODYNAMIC MODEL - LOY YANG POWER PLANT
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Disclaimer
This report has been prepared on behalf of and for the exclusive use of Global CCS Institute. WorleyParsons accepts no liability or responsibility whatsoever for it in respect of any use of or reliance upon this report by any third party.
Copying this report without the permission of Global CCS Institute or WorleyParsons is not permitted.
PROJECT 101010-00686 - POST COMBUSTION CARBON CAPTURE
REV DESCRIPTION ORIG REVIEW WORLEY- DATE CLIENT DATE PARSONS APPROVAL APPROVAL
0 Issue for Use 19 Feb 2013 19 Feb 2013 YB Chan L Gebert M Robinson D Van Puyvelde
Document No : PM-REP-0001 Page ii GLOBAL CCS INSTITUTE POST COMBUSTION CARBON CAPTURE THERMODYNAMIC MODEL - LOY YANG POWER PLANT
EXECUTIVE SUMMARY
First-of-a-kind carbon capture projects are facing a unique challenge affecting not only project developers and carbon capture technology providers, but also project financiers and regulators.
Project developers and financiers require an accurate prediction of capital and operating costs. Regulators are seeking an in-depth understanding of the process and resources required as well as emissions reduction before agreeing to permit the project.
With “off the shelf” technologies, like flue gas desulphurization (FGD), which have been newly-built or retrofitted on many occasions to power plants, performance data is readily available to use as benchmarks for financial models or performance guarantees. However with first-of-a-kind technologies like CCS and the need to protect the IP of technology providers has seen project developers, financiers and regulators having to deal with a lack of publically available information to assess the technology.
This report provides a methodology for the independent validation of impacts on plant performance and inputs for retrofitting Post Combustion Capture (PCC) technology. The methodology can also be readily applied to green-field sites. It will also provide the foundation for the valuation of performance risks and potential revenue impacts on facility operation. The report uses a case study based on a 5000 tpd PCC retrofit at the Loy Yang A power station to develop and explain the methodology and presents results from the case study.
Importantly, both the methodology and results described in this report has been peer reviewed by a leading CCS capture technology expert who found the methodology to be a sound approach in providing performance data and in protecting technology vendor IP whilst at the same time providing sufficient confidence to the wider CCS community in being able to evaluate a project.
In order to achieve this, the company executing the validation (independent engineering contractor) has to be fully supported by the technology provider as well as the CCS project proponents1.
WorleyParsons as the independent engineering contractor managed the overall execution of the project, carried out the power plant modelling work, integration of the PCC plant and assessment of the remaining cases evaluating power plant process improvements due to the addition of coal drying, wet and dry flue gas cooling. WorleyParsons was also responsible for the operational performance data of the overall system including the host unit, PCC and the coal drying plant.
The technology provider Mitsubishi Heavy Industry (MHI) provided all the necessary inputs/outputs for the PCC plant retrofit and the changes arising in the operating conditions of the capture plant due to the addition of coal drying to improve the overall efficiency of the power plant.
The power station host Loy Yang Power provided all the necessary operational data for the modelling of the host power plant.
1 This study has been performed by WorleyParsons together with the project proponents and carbon capture technology provider Mitsubishi Heavy Industries (MHI). Whilst MHI supplied PCC-process data to WorleyParsons, no confidential process data has been published in the public report. Any confidential data used in this public report has been normalized to show the relative impact of plant optimization.
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This scope split ensured a protection of the technology vendor’s IP whilst allowing an independent evaluation of the overall performance impact. The methodology adopted minimizes the technology vendor’s “black box” and therefore isolates to the best extent possible specific capture technology- related issues from overall plant performance and plant integration issues. From a power plant perspective, individual components and the entire process can thus be benchmarked against theoretically achievable results with a reduced performance risk profile of a project.
Project scope
This study was focused around retrofitting an existing sub-critical PC (brown coal) fired power station with a coal drying plant and a commercial sized (5000tpd) PCC plant for the partial capture of CO2.
The block diagram below illustrates the existing power plant retrofitted with the coal drying plant and the PCC plant. It also shows the essential processes (inputs and outputs) that requires integration between the power station and the retrofitted coal drying and PCC plants.
Block Flow Diagram of Existing Power Station retrofitted with Coal Drying and PCC Plant
Source: WorleyParsons
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Methodology A simple schematic of the methodology adopted in the study is shown in the figure below. Summary of Study Methodology
Source: WorleyParsons
Five cases have been defined in order to demonstrate and validate the methodology over a range of technical solutions. These cases shown in the Table below have been chosen specifically for this case study with the objective of identifying and comparing sensitivities of performance impacts of the different technical options. In practice, these cases will vary depending on the question to be answered. For example, these cases would look vastly different if the project goal was to identify the best available PCC-technology for a specific power station. The chosen cases in this study are primarily focused on identifying the best possible performance of a retrofitted power plant using a pre- selected PCC-technology, coal drying process and wet and dry flue gas cooling.
Case Studies Matrix
Base Plant PCC Plant Coal Drying Plant Air Cooled Optimisation Operation
Base Case X
Case 1 X X
Case 2 X X X
Case 3 X X X X
Case 4 X X X
Case 5 X X X X X Source: WorleyParsons
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One major shortcoming in today’s commercially available software for process plant modelling is that no single tool is available in the market allows the integration multiple technologies such as a Rankine power cycle, PCC-plant and a coal drying plant in one coherent model. As a consequence, it is therefore critical that an independent engineering contractor is in a position to identify available software packages and a suitable suite of software tools to achieve the project goal. This also includes the capability to integrate these packages to ensure integrity of the modelling outcomes.
The base case validation methodology is shown in the Figure below. A part load case was validated alongside a full load case in order to ensure the accuracy of the base power plant model. Both these cases have been compared with and validated against actual operating data of the unit by the power station host to ensure a high level of accuracy of the model developed.
Base Case Methodology Flow Chart
Source: WorleyParsons
In order to allow the technology provider to define process inputs and outputs to his “black box” the flue gas conditions and properties data from the Base Plant (Base Case) were provided to the PCC process technology IP proprietor for modelling of the 5000tpd PCC plant.
The output data from 5000tpd PCC plant model were obtained from the technology IP proprietor and fed back into the Base Plant model to complete the Case 1 model.
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The Case 1 validation methodology is shown in the Figure below.
Case 1 Methodology Flow Chart
Source: WorleyParsons
The remaining cases 2 to 5 were modelled in a similar manner with an increased level of complexity, due to the higher level of plant integration, to optimize overall performance of the retrofitted power plant.
In order to compare the results of the various cases, a set of key performance parameters were then identified. These parameters might vary depending on the cases studied and questions to be answered. It is important to determine a clear set of KPIs at the outset of the project in order to define the output required from the modelling. This approach also ensures that the modelling undertaken does not have to be re-visited whilst the results can be compared and benchmarked against each other.
For this case study, the following key performance parameters have been determined and evaluated for each case: • Steam Extraction Supply to PCC plant, MW • Auxiliary Power Supply to PCC plant, MW
• CO2 Compression Power, MW • Auxiliary Power Supply to Coal Drying plant, MW • Power Station Net Sent Out Generation, MW • Net plant efficiency, %
• Electricity Output Penalty, kWhe/tonne CO2
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The above parameters can also be utilised to assess different types of post carbon capture technologies independently of the fuel composition.
It has to be noted that this case study was performed at the pre-feasibility stage for the implementation of a PCC-retrofit at an existing lignite fired power station. It is recommended that this independent validation is repeated at each decision gate of a project, and particularly so as part of the final investment decision. This process ensures that any changes in technology, as well as the increased level of engineering definition in subsequent stages of project evaluation to FID, are fully reflected in the result and that the project proponents have clarity about costs and performance impacts at every decision gate of project development. Independent Review of Methodology
The applied methodology was validated by an Independent Peer Reviewer, Dr. Kelly Thambimuthu (also Chairman of the IEA Greenhouse Gas Research and Development Program) in order to set an industry benchmark. This independent validation focused on the review of the methodology only and did not review, nor validate, any specific performance data from either the power station or the PCC process.
The Independent Peer Reviewer did not have access to any proprietary information from either the power station or the technology IP proprietors as it was a peer review of the methodology and not of the actual results. The validation was carried out through close involvement of the Independent Peer Reviewer in the following phases:
• Kick-off meeting and definition of methodology at the start of the project;
• Intermediate methodology review after the base cases had been established; and
• Final methodology review at project finalization. Results
The following table shows a summary of the thermodynamic modelling results and key performance parameters. The results from the independent validation are in line with the expectations of plant owner and technology provider and have therefore confirmed the expectations of all parties of the anticipated performance of the retrofitted power plant.
Whilst these technical process performance parameters allow the comparison of the individual cases against each other, they are not sufficient to make a final decision for the best configuration taking into account economic and environmental factors. However, they are important inputs and are the foundation for subsequent techno-economic and environmental impact assessments which will ultimately define the preferred technical solution and investment decisions.
In these case studies, the implementation of an optimized PCC-solution (Case 4) achieves a higher net plant output and therefore higher revenue for the plant operator. However, it is offset by a lower efficiency compared to the optimized case including coal drying (Case 3) and therefore incurs higher net charges for residual CO2-emissions and fuel costs. These considerations underline the importance of extending the methodology developed on the basis of thermodynamic modelling to incorporate additional techno-economic assessments.
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Summary of Thermodynamic Modelling Results SYSTEM CONFIGURATION Base Case 1 Case 2 Case 3 Case 4 Case 5
Base Plant X X X X X X
PCC Plant X X X X X
Coal Drying X X X
Plant Optimization X X X
Air Cooled (PCC Plant Only) X POWER GENERATION kW kW kW kW kW kW SUMMARY Main Steam Turbine 568,960 530,810 527,700 528,840 549,390 528,840 Generation Expander Generation 5,320 3,130 5,320
Total Gross Power Generation 568,960 530,810 527,700 534,160 552,520 534,160
Net Power Generation 521,380 446,460 445,840 452,380 468,270 452,480
Net Power Output Reduction - 74,920 75,540 69,000 53,110 68,900
Gross Plant Efficiency, % 31.46% 29.35% 30.74% 31.12% 30.53% 31.12%
Net Plant Efficiency, % 28.82% 24.68% 25.97% 26.36% 25.88% 26.36% AUXILIARY LOAD POWER kW kW kW kW kW kW SUMMARY Base Plant Auxiliary Load 47,580 47,450 44,350 44,270 47,350 44,170
PCC Plant Auxiliary Load - 36,900 34,500 34,500 * 36,900 * 34,500 Coal Drying Plant Auxiliary - - 3,010 3,010 - 3,010 Load Total Plant Auxiliary Load 47,580 84,350 81,860 81,780 * 84,250 * 81,680 Power
CO2 CAPTURE SUMMARY Base Case 1 Case 2 Case 3 Case 4 Case 5
CO2 Captured, (tpd) - 5,000 5,000 5,000 5,000 5,000
CO2 Produced, (tpd) 14,831 14,831 14,081 14,081 14,854 14,081
CO2 Emitted, (tpd) 14,831 9,831 9,081 9,081 9,854 9,081 Gross Specific Emission, 1.086 0.772 0.717 0.708 0.743 0.708 (kg/kWh) Net Specific Emission, 1.185 0.917 0.849 0.836 0.877 0.836 (kg/kWh) Electricity Output Penalty, - 419.89 274.70 233.60 284.36 233.60 (kWh/t CO2 )
Note: (*) The actual PCC Plant Auxiliary Load and hence the Total Plant Auxiliary Load for Case 4 and Case 5 will be either equal or less than the figures shown in table above. For the purpose of this study a detailed assessment of the PCC auxiliary load has not been carried out. Source: WorleyParsons
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Conclusion
The proposed methodology achieves the project goal to independently validate the performance impact caused by retrofitting a PCC-plant into an existing power station. The results for the PCC plant and coal drying plant were found to be in-line with the expectations of the plant owner and confirmed the data provided by the technology IP Proprietor to the point where the expected performance obtained through the validation process agreed with the data provided.
The concept of independently validating the technology provided by the IP Proprietor’s “black box” allows a high level of transparency and confidence between technology driven performance and overall plant performance, whilst ensuring the confidentiality of the technology vendor’s intellectual property. The process ensured that individual process components could be validated using an independent process that would assess that the data provided by the IP Proprietors fits within the window of expectation and confirms that it is within the realm of credibility. This is essential to provide the confidence to all stakeholders that the performance of the chemical and thermodynamic processes is credible.
The selection of a suitable software suite and compatible software tools has been critical in achieving the project goals as no fully integrated software package was commercially available to execute the entire project scope. The selected software tools are flexible enough to be used with not only the defined case study, but also for green-field sites and other boiler technologies employing super- critical or ultra-supercritical steam cycles.
It is important to note that although this study is based on a specific IP technology, the validation methodology developed is readily applicable to studies using other types of post combustion capture, coal drying and/or combined technologies retrofitted to existing or green field coal power plants.
In the absence of an all-encompassing thermodynamic/process software package that specifically addresses coal drying and/or PCC retrofits, the methodologies formulated in this study can be presented as the current best practice for modelling such retrofits.
This independent validation of the plant performance would contribute to a reduction of the currently required risk premiums to finance the execution of a large scale PCC project as it identifies a methodology to independently validate the performance of the first-of-a-kind plants. It is important that this methodology is applied at critical project stages to ensure a high level of transparency of performance impacts and operating costs to the plant owner and other project proponents and stakeholders.
The key recommendation arising from this study is that proponents of PCC retro-fit projects should study the methodology described in this report, identify differences between the PCC scheme described in this report and their proposed PCC scheme, and modify this methodology as required to in order to develop a customised methodology for application on their plant.
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CONTENTS EXECUTIVE SUMMARY...... III
1 INTRODUCTION ...... 1
1.1 History and Project Outline ...... 1
2 SCOPE OF STUDY ...... 3
2.1 Study Framework ...... 3
3 PLANT CONFIGURATION & TECHNOLOGY ...... 5
3.1 Description Loy Yang A Power Station Plant ...... 5
3.1.1 Site Conditions ...... 7
3.1.2 Coal Specification ...... 7
3.1.3 Notes on Coal Constituents ...... 7
3.1.4 Boiler Plant Inputs and Outputs ...... 8
3.1.5 Notes on Boiler Plant Inputs and Outputs ...... 9
3.1.6 Steam Turbine Inputs and Outputs ...... 9
3.1.7 Flue Gas Conditions and Composition ...... 11
3.2 Post Combustion Capture Plant ...... 12
3.2.1 Description of 5000tpd Post Combustion Capture Plant ...... 12
3.2.2 Technical Process Description for the 5000tpd PCC Plant ...... 12
3.2.3 PCC Plant Dry Air Cooling System ...... 14
3.3 Description Coal Drying Plant ...... 15
3.3.1 Sources of Waste Heat ...... 15
3.3.2 Fluidized Bed Coal Dryer ...... 17
3.3.3 Segregation ...... 17
4 METHODOLOGY...... 18
4.1 Project Execution Roles ...... 18
4.2 Overall Study Methodology and Project Timeline ...... 18
4.3 Definition of project scope, cases and evaluation methodology ...... 19
4.3.1 Project Scope ...... 19
4.3.2 Case Definition ...... 20
4.3.3 Definition of Evaluation Methodology ...... 20
4.4 Selection of Software Tools ...... 22
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4.4.1 LYA Power Plant (Base Case Plant) Software ...... 22
4.4.2 Post Combustion Capture Plant Software ...... 23
4.4.3 Coal Drying Plant Software ...... 25
4.5 Methodology used to construct and validate the Thermodynamic Models ...... 25
4.5.1 Base Case: Host Unit - LYA Power Plant ...... 27
4.5.2 Case 1: Host Unit and Post Combustion Capture Plant Model ...... 29
4.5.3 Case 2: Host Unit with Coal Drying Plant Model ...... 33
4.5.4 Case 3: Host Unit with Coal Drying, PCC Plant and Optimization ...... 43
4.5.5 Case 4: Host Unit with PCC Plant and Optimization ...... 45
4.5.6 Case 5: Host Unit with Coal Drying, PCC Plant (with Air Cooling) and Optimization 47
4.6 Validation of Methodology by Independent Peer Review ...... 48
5 POST COMBUSTION CAPTURE INTEGRATION ...... 49
5.1 Steam Extraction for Solvent Regeneration ...... 49
5.2 Substitute Options for Steam ...... 49
5.3 CO2 Compressor Drive Options ...... 49
5.4 CO2 Compressor Utilisation of Waste Heat ...... 49
5.5 Operating Flexibility of Power Station Boiler Plant ...... 50
5.6 Operating Flexibility of PCC Plant ...... 50
5.7 Implications of an actual PCC Retrofit and Coal Drying on the Existing Plant Systems .. 51
6 RESULTS ...... 52
6.1 Power Generation Outputs ...... 52
6.2 Electricity Output Penalty ...... 54
6.3 Retrofit PCC Plant Cooling Water Requirement ...... 55
6.4 Consideration of Peer Reviewer’s Notes on PCC Capture Integration ...... 57
7 APPLICATION OF THE MODELLING METHODOLOGY ...... 59
7.1 Adaptability to a Generic Coal Fired Power Plant ...... 59
7.2 Other Plausible Model Cases ...... 59
8 CONCLUSIONS ...... 60
9 RECOMMENDATIONS ...... 63
10 REFERENCES ...... 64
11 ABBREVIATIONS ...... 65
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FIGURES
Figure 2.1 - Overview Block Flow Diagram ...... 4
Figure 3.1 - Loy Yang A Power Station ...... 5
Figure 3.2 - Boiler Plant Inputs and Outputs ...... 8
Figure 3.3 - Block Flow Diagram of PCC Plant ...... 12
Figure 4.1 - Summary of Study process ...... 19
Figure 4.2 - Base Case GateCycleTM ...... 23
Figure 4.3 - Base Case Methodology Flow Chart ...... 27
Figure 4.4 - Case 1 Methodology Flow Chart ...... 29
Figure 4.5 - Overview Block Flow Diagram ...... 32
Figure 4.6 - Case 2 Methodology Flow Chart ...... 33
Figure 4.7 –Wet and Dried Coal Flow Rates as a Function Coal Moisture Content ...... 35
Figure 4.8 – Reduction in CO2 emissions as a function of coal moisture content ...... 36
Figure 4.9 – Product moisture content and the number of Mark II fluidized bed coal dryers as functions of the required and available heat ...... 36
Figure 4.10 – Acid dewpoint T °C as a function of SO3 and H2O concentrations in the flue gas ...... 37
Figure 4.11 - Case 3 Methodology Flow Chart ...... 43
Figure 4.12 - Case 4 Methodology Flow Chart ...... 45
Figure 4.13 - Case 5 Methodology Flow Chart ...... 47
Figure 5.1 – Condensate Heating and CO2 Compressor Cooling Integration T-Q Diagram ...... 50
Figure 6.1 - Power Generation Outputs & Aux Loads ...... 53
Figure 6.2 - Generation Specific Emissions ...... 54
Figure 6.3 - Electricity Output Penalty...... 54
Figure 6.4 - Retrofit PCC Cooling Water Requirement ...... 56
Figure 6.5 – NETL Water Demand Graph ...... 57
TABLES
Table 3.1 – Site Conditions Input Data ...... 7
Table 3.2 – Loy Yang Coal Specification Input Data ...... 7
Table 3.3 – Boiler Plant Model (Combustion) Input Data ...... 9
Table 3.4 - LYA Steam Cycle Conditions ...... 10
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Table 3.5 - LYA Unit Upgrades Dates ...... 10
Table 3.6 - LYA Units' Post Upgrade Conditions ...... 11
Table 3.7 - Summary of Fuel Moisture Reduction Results from Previous Study ...... 16
Table 4.1 - Case Studies Matrix ...... 20
Table 4.2 - Coal Drying Flue Gas Conditions ...... 39
Table 4.3 - Wet and Dried Coal Data Comparison ...... 40
Table 6.1 - Modelling Cases Power Generation Outputs and Auxiliary Loads ...... 52
Table 6.2 - Modelling Cases Cooling Water Requirement ...... 55
Appendix - Table A - Flue Gas Definition (100%) Design Case ...... 75
Appendix - Table B - Flue Gas Definition - Equipment Sizing ...... 76
Appendix - Table C - PCC Plant Cooling Water Condition ...... 77
Appendix - Table D - PCC Plant Power Requirements ...... 77
Appendix - Table E - PCC Plant Product CO2 ...... 78
APPENDIX 1 PROJECT PROPONENTS
APPENDIX 2 HEAT AND MASS BALANCE DIAGRAMS
APPENDIX 3 BLOCK FLOW DIAGRAMS
APPENDIX 4 BASIS OF DESIGN
APPENDIX 5 INDEPENDENT PEER REVIEWER’S REPORT
APPENDIX 6 THERMODYNAMIC MODELLING STUDY TIMELINE
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1 INTRODUCTION
1.1 History and Project Outline
There is a frustrating challenge at the heart of most first-of-a-kind carbon capture projects. It is a challenge that impacts not only project developers and carbon capture technology providers, but also project financiers, regulators, and to some extent communities considering whether or not to host a carbon capture demonstration project in their vicinity. 1 Project developers and financiers
In order to secure funding for a carbon capture demonstration project, developers and financiers need to be able to accurately predict the costs involved in operating a carbon capture plant over the life of a demonstration project. This means being able to understand, for example, its impact in key areas of operating costs (OPEX) due to a reduction in thermal efficiency and steam, water and power consumption of the capture plant. One of the key risks related to the OPEX, as identified by one of Europe’s most advanced large scale integrated CCS project2, is that the actual outcome will not be the same as the forecasted cost, which could lead to:
• Unacceptable OPEX if overestimated – leading to the risk of a project not proceeding,
• Unforeseen additional costs if underestimated – financial risk during the operational phase. 2 Regulators and communities
Regulators and some communities considering hosting a capture plant project are also interested in this operational data, as they need to understand how much a project will cost, what resources it will require and any emissions that it may produce, before agreeing to permit a project. For many regulators’, charged with permitting the various aspects of these novel first of a kind capture projects, the challenge will likely prove complex. Despite the emergence of CCS-specific regulatory regimes, many of the elements and associated processes will require permitting and approval under existing models of environmental, planning and energy law. The regulator will be required to maintain the integrity and requirements of the regulatory permitting process, whilst simultaneously ensuring that the project proponent’s, or technology provider’s, intellectual property (IP) is protected. Furthermore, it will be important to establish good practices which enable high levels of transparency and inspire public confidence in the regulatory processes involved. 3 Carbon capture technology providers
The group that usually holds the information that everyone is so keen to access, analyse and evaluate (the carbon capture technology providers) has invested substantial resources to develop their technologies and, accordingly, are keen to protect valuable intellectual property.
With “off the shelf” technologies, like flue gas desulphurization (FGD), which have been newly-built or retrofitted on many occasions to power plants, this kind of operational performance data is readily available to use as benchmarks for financial models or to verify performance guarantees. However,
2 ROAD | Maasvlakte CCS Project C.V. “Mitigating project risks”, 13 December 2011
Page 1 GLOBAL CCS INSTITUTE POST COMBUSTION CARBON CAPTURE THERMODYNAMIC MODEL - LOY YANG POWER PLANT with first-of-a-kind technologies like CCS, the need to protect the IP of technology providers has seen project developers, financiers and regulators having to deal with a lack of publically available data to properly assess both performance and cost.
Recognizing that “trust me I’m a carbon capture technology provider” does not substitute for an independent validation of the performance data, the Global CCS Institute has supported WorleyParsons to work with carbon capture project proponents Loy Yang Power and Energy Australia (formerly TruEnergy), and carbon capture technology provider Mitsubishi Heavy Industries (MHI), to go through a process to validate vendor data and create a methodology to assist power station owners with the validation of performance and potential revenue impacts for their facility operation, while protecting the potentially highly sensitive IP of the technology provider.
This report provides a methodology for the independent validation of impacts on plant performance and inputs for retrofit Post Combustion Capture (PCC) projects that can also be easily applied to green-field sites. This will assist with the valuation of performance risks and potential revenue impacts for facility operation. The report uses a case study based on a partial PCC retrofit at the Loy Yang A power station to explain the methodology, and details the results of that case study with the full support of the technology provider as well as the CCS project proponents3.
Importantly, both the methodology and results described in this report have been peer reviewed by a leading CCS capture technology expert who found the methodology to be a sound approach to providing operational performance data assurance while protecting technology vendor IP and providing the CCS community with confidence in the transparency of the assessment process. It is expected that this methodology can be adapted to provide the kind of assurance, cost and quality checks required to additionally satisfy project financing decisions, environmental and advanced permitting approvals.
The independent validation of the plant performance could contribute to a reduction of the currently- required risk premiums to finance the project execution of a large scale PCC plant as it identifies a methodology to independently validate and to reduce any perceived uncertainties in the performance of the first-of-its-kind plants.
3 This study has been performed by WorleyParsons together with the project proponents and carbon capture technology provider Mitsubishi Heavy Industries (MHI). Whilst MHI supplied PCC-process data to WorleyParsons, no confidential process data has been published in the public report. Any confidential data used in this public report has been normalized to show the relative impact of plant optimization
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2 SCOPE OF STUDY
The scope of the study is to assist the implementation and roll out of carbon capture and storage facilities. There is an important need to understand the performance impacts of CCS projects when proposed for deployment on existing or new power stations, as these performance impacts are a main contributor to the operational costs of the CCS infrastructure and therefore impact profitability of the power station operator and the cost of mitigation of climate change impacts to society as a whole.
This study will address the two following main critical aspects for the development of PCC projects:
• The proposed methodology will provide an independent validation of impacts on plant performance and inputs for PCC projects. It documents a methodology for power station owners for the valuation of risks and revenue impacts on their plant operations.
• The independent validation of the plant performance can contribute to a reduction of the currently- required risk premiums to finance the execution of a large scale PCC project as it identifies a methodology to validate the performance of the first-of-a-kind retrofits to power plants. 2.1 Study Framework
This study uses a case study to demonstrate the methodology for independent evaluation of plant performance impacts with the implementation of capture related CCS infrastructure at a power generation plant.
The case study was framed around retrofitting an existing sub-critical PC (brown coal) fired power station with a coal drying plant and a commercial sized (5000tpd) PCC plant for the partial capture of
CO2.
For this study the 5000tpd PCC plant is nominated for integration with one unit at the Loy Yang A Power Station.
The block diagram in Figure 2 .1 below illustrates an existing unit retrofitted with the coal drying plant and the PCC plant. It also shows the essential processes (inputs and outputs) that require integration between the existing power station and the retrofitted coal drying and PCC plants.
This framework based on a real case of an existing power plant has been chosen to define a methodology that can be extended to similar retrofit or green-field applications of PCC-technology
The modelling of storage of CO2 is not part of this study scope and framework. The compressed CO2 is assumed to be delivered at the power plant gate at conditions suitable for transportation via pipeline to an off-site storage/sequestration facility.
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Figure 2 .1 - Overview Block Flow Diagram
Source: WorleyParsons
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3 PLANT CONFIGURATION & TECHNOLOGY
3.1 Description Loy Yang A Power Station Plant
The Loy Yang A Power Station is a brown coal-fired power station located 7 km south-east of Traralgon in south-eastern Victoria, a state of Australia. Figure 3 .1 below shows the general location of the site.
The station produces about 40% of Victoria’s electricity requirements. Electricity generation at Loy Yang A Power Station requires over 60,000 tonne of brown coal a day, supplied exclusively by a dedicated open-cut mine. Mining operations commenced at Loy Yang in 1982.
The power station was constructed through the 1980s, and consists of four boiler/turbine units: Loy Yang A (Units 1, 2, 3 & 4).
Figure 3 .1 - Loy Yang A Power Station
Source: WorleyParsons
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The four boilers are installed in the station, and each is a part of a generating unit. In addition to the boiler, a unit comprises a turbine-generator, auxiliary plant and pipe work. Each unit was originally rated for 500MW and, since being commissioned, they have had upgrades carried out to increase their output, on average, to above 550MW. The units are operated and monitored from the unit control room.
The boilers are installed in the boiler house, which is attached to the coal bunker and electrical annex structure. The building is not fully enclosed, the wall being only partially sheeted. The four boilers are arranged in a west-to-east line commencing with Unit 1 boiler.
Each boiler comprises the following equipment: • Draft plant - two induced draft (I.D.) fans; two forced draft (F.D.) fans; two rotary air heaters; auxiliary systems, ducting, dampers and draft plant controls; the chimney.
• Auxiliary firing equipment - three briquette bunkers; bunker gates; table feeders; bowl mills and P.F. exhausters; P.F. pipes connecting to twelve P.F. burners (3 levels on each of the 4 furnace walls); natural gas ignitors and pilot burners, gas piping with control trip and isolating valves; flame scanning systems and controls.
• Main firing equipment - bunker gates; coal feeder conveyors; coal feeder discharge dampers; eight pulverised fuel mills; burners; main firing equipment controls.
• Precipitators - electrostatic dust precipitators and their controls.
• Boiler structure and pressure parts - furnace enclosure which incorporates the evaporative heating membrane tube water-walls, superheaters, reheaters and their associated circuit (hanger) tubes; attemperators; economisers; separating and mixing vessels; circulating pumps and strainers; superheater and reheater safety valves and other special valves.
• Online boiler cleaning - including remote, manual and automatic equipment and controls for both convection bank lance soot-blowers and furnace water cannons.
Each boiler is a balanced draft, tower unit type, with superimposed recirculation. The superheaters, reheaters and economisers are stacked in the furnace enclosure, above the combustion chamber.
The boilers are fired with pulverised brown coal, taken from the Loy Yang open cut mine, which has a high moisture content (approximately 60%) but a low ash content (average of 0.9% wet basis).
Adjustments, as noted in the following sub-sections below, have been made where it was necessary to reconcile the model input data sets.
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3.1.1 Site Conditions
The LYA site conditions for the Base Case model is presented in the table below.
Table 3 .1 – Site Conditions Input Data
Parameter Units Value Source
Barometric Pressure bar 1.009 Loy Yang Power
Ambient Air Temperature (Dry Bulb) °C 13.4 Loy Yang Power
Relative Humidity % 62 Loy Yang Power Source: WorleyParsons
3.1.2 Coal Specification
The LYA coal specification for the Base Case model is presented in the table below.
Table 3 .2 – Loy Yang Coal Specification Input Data
Parameter Units Value Source
Ultimate Analysis
Moisture Wt % 60.0 Loy Yang Power
Carbon (C) Wt % 27.2 Loy Yang Power
Hydrogen (H) Wt % 2.0 Loy Yang Power
Sulphur (S) Wt % 0.2 * * See Section 3.1.3 below
Oxygen (O) Wt % 9.5 Loy Yang Power
Nitrogen (N) Wt % 0.2 Loy Yang Power
Ash Wt % 0.9 * * See Section 3.1.3 below
Total Wt % 100.0
Higher Heating Value Btu/lb 4,522 Loy Yang Power
Higher Heating Value MJ/kg 10.52 Loy Yang Power Source: WorleyParsons
3.1.3 Notes on Coal Constituents
The sulphur (S) content value in the table above is not used directly in the Base Case model but instead is adjusted within the model to match the flue gas SO2 composition listed in the Feed Gas
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Definition 100% (design case) of the 5000tpd PCC plant shown in Appendix 4. The adjusted sulphur (S) content input value used in the model is 0.10%.
The average ash recorded for 2011 was 2.9 wt% (dry basis), while the 0.9 wt% used in the models was based on 2010 records and is deemed by LYP to be on the low side. This will require further consideration in a detailed design phase of the potential PCC retrofit, as the LYA plant is a mine mouth operation which can encounter coal with different constituents depending on which direction the mine is being developed.
3.1.4 Boiler Plant Inputs and Outputs The boiler plant inputs and outputs are shown in the simplified block diagram below.
Figure 3 .2 - Boiler Plant Inputs and Outputs
Source: WorleyParsons The main boiler inputs are combustion air, water and fuel (pulverised brown coal) while the boiler outputs are steam, flue gas and ash.
For modelling the boiler plant the input data presented in the table below is entered into the GateCycleTM software.
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Table 3 .3 – Boiler Plant Model (Combustion) Input Data
Parameter Units Value Source
Excess Air % 20.87 Loy Yang Power
UBC in Ash % 0.04 * * See Section 3.1.5 below
Radiation Loss % 0.34 Loy Yang Power
Other Boiler Loss % 0.037 Loy Yang Power
CO in flue gas ppmv 7 Loy Yang Power
Economizer Exit Gas °C 358.64 * * See Section 3.1.5 below
Air Heater Exit Gas °C 181 Loy Yang Power
Air Heater Inlet Air °C 18 Loy Yang Power
Boiler Efficiency % 72.0 * * See Section 3.1.5 below Source: WorleyParsons
3.1.5 Notes on Boiler Plant Inputs and Outputs
”UBC in Ash” above is the Weight Fraction of Unburned Carbon in Ash as defined by combustion calculations performed in previous the DryFiningTM Study Report.
The “Economizer Exit Gas” value above can approach 410˚C towards the end of a boiler run at LYA.
The “Boiler Efficiency” value in the table above is not used as an input to the model. The “Boiler Efficiency” is calculated from model outputs and compared with the value reported above.
The Air Heater Leakage value in the model is adjusted to match the air heater flue gas composition as presented in the Feed Gas Definition 100% (Design case) of the 5000tpd PCC Plant, shown in Appendix 4.
3.1.6 Steam Turbine Inputs and Outputs
The Unit 1 the steam turbine was supplied by OEM Siemens. It was ordered with a guaranteed rating of 500MW, and an expected maximum capability of 529 MW with 8.29 kg/s re-heater spray flow.
Achievable generation was typically less than 529 MW, dependent on steam conditions, boiler spray flows, plant configuration and the extent of equipment deterioration over time.
These limits are based on rated turbine inlet steam conditions as shown in the table below.
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Table 3 .4 - LYA Steam Cycle Conditions
Parameter Units Value
Main Steam Pressure MPa (abs) 16.4 (at MSV)
Main Steam temperature ºC 538 (at MSVs);
Hot Reheat Temperature ºC 538 (at RSVs);
Reheat System Pressure Loss % 10
Condenser Pressure kPa.(abs) 9.5
Source: Loy Yang Power
The OEM indicated that the boiler furnace capability is significantly in excess of that required to supply turbine rated steam flows on all units.
During the early half of last decade, the OEM was approached to upgrade the turbine-generator units to the maximum economic extent, consistent with:
• a boiler thermal capability of 1,295 MW (heat added to steam) and,
• a limit on main steam flow of 473 kg/s
Unit 1 upgrades were performed in the period as outlined in the table below.
Table 3 .5 - LYA Unit Upgrades Dates
Unit Turbine Upgrade Condenser Upgrade 1 Nov / Dec 2003 Nov / Dec 2003 Source: Loy Yang Power
The solution adopted by the OEM was the replacement and modification of the HP and Intermediate Pressure inner modules (inner cylinders and rotors) with turbines of greater swallowing capability, fitted with modern high efficient blading. Coupling bolts were upgraded to hydraulic bolts to allow the transmission of additional torque and to reduce maintenance effort.
The Unit 1 HP and Intermediate Pressure inner modules were replaced with new components. The efficiency of Unit 1 is higher than the Unit 3 and Unit 4 turbines.
The turbine inlet areas on the upgraded HP and Intermediate Pressure cylinders were increased to ensure that steam pressures remain below boiler safety valve settings.
To ensure the correct sequence of boiler safety valve operation, with nominal 464 kg/s main steam flow and to allow for the associated greater heat load:
• Main steam pressure was reduced from 16.4 to 16.0 MPa.abs,
• Safety valve settings were adjusted in line with the higher steam flows, and
• Design condenser pressure was increased to 10 kPa.abs.
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Achievable load at the design boiler load will be dependent on plant condition and condenser pressure. The new turbine design conditions based on a boiler thermal load of 1,295 MW (heat to steam) are shown in the table below.
Table 3 .6 - LYA Units' Post Upgrade Conditions
Parameter Unit 1
Generator Load (MW) 568.961
Main Steam Flow (kg/s) 463.737 [ t/h ] [1669.453]
Main Steam Pressure (MPa.abs) 16
Main Steam Temperature (ºC) 538
Hot Reheat Temperature (ºC) 538
Condenser Pressure (kPa.abs) 10.0
Superheater Spray Flow (kg/s) 37
Reheater Spray Flow (kg/s) 12
Heat Rate (kJ/kW.hr) 8,194
HP Turbine Efficiency 93%
Intermediate Pressure Turbine Efficiency 94%
Source: Loy Yang Power
The tolerance on steam swallowing capacity was specified as -0% / +4% and therefore the maximum expected load was greater than the above rated conditions.
The corresponding tolerance on turbine load is approximately -0 MW / +22.5 MW. The higher load can only be achieved with a correspondingly greater-than-design steam flows and boiler thermal load.
3.1.7 Flue Gas Conditions and Composition
The Air Heater Leakage value of the Model is adjusted to match the Air Heater Exit flue gas composition as presented in the Basis of Design, in the Feed Gas Definition 100% (Design case) of the 5000tpd PCC Plant, shown in Appendix 4.
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3.2 Post Combustion Capture Plant
3.2.1 Description of 5000tpd Post Combustion Capture Plant
The PCC technology IP proprietor’s (MHI) flue gas CO2 capture plant utilizes an advanced hindered amine solvent, as the CO2 absorbent. During the development of this project it was agreed with Global CCS Institute and the PCC technology proprietor to use a standard 5000tpd PCC plant which would be provided with flue gas from one Loy Yang A boiler plant. This 5000tpd PCC plant is rated to capture 90% of the feed flue gas (i.e. 90% efficient).
3.2.2 Technical Process Description for the 5000tpd PCC Plant The process for the 5000tpd plant consists of three main sections described below: (1) Flue gas pre- treatment section, (2) CO2 capture section, (3) CO2 Compression and Dehydration section. A block flow diagram illustrating these sections and brief descriptions of each section are as follows in Figure 3 .3.
Figure 3 .3 - Block Flow Diagram of PCC Plant
Source: MHI
(1) Flue Gas Pre-treatment Section
SO2 absorber
The SO2 absorber consists of a single tower complete with oxidation equipment and single spray pipes. Flue gas is introduced into the SO2 absorber where it makes contact with limestone slurry. SO2 contained within flue gas is absorbed and oxidized to form gypsum during this process.
Deep FGD section The flue gas enters the integrated deep FGD section in the bottom part of the Flue gas quencher, where the flue gas contacts directly with an alkaline, pH controlled solution to remove SO2,
Flue gas washing section After passing the deep FGD section, the flue gas moves upward into the flue gas washing section through packing. At this stage the temperature of the flue gas from the deep FGD is too high to feed directly into the CO2 absorber since a lower temperature for exothermic reaction of CO2 molecules
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and solvent is preferred. Therefore, prior to entering the CO2 absorber, flue gas is cooled in the flue gas quencher by direct contact with circulating water supplied from the top the quencher.
(2) CO2 Capture Section
CO2 absorption
The CO2 absorber also uses packing. It consists of two main sections, (1) the CO2 absorption section in the lower part and (2) a water wash section in the upper part.
1) CO2 absorption section The pre-treated flue gas from the flue gas quencher is introduced into the bottom section of the
CO2 absorber. The flue gas moves upward through packing material, while lean solvent is introduced from the top of the absorption section directly onto the packing. The flue gas spreads evenly within the packing, before coming in contact with the solvent on the surface of
the packing, where the CO2 in the flue gas is selectively absorbed by the solvent.
The rich solvent from the bottom of the CO2 absorber is pumped by the rich solution pump and then is directed to the regenerator via the solution heat exchanger.
2) Water wash section
The flue gas from the CO2 absorption section moves upward into the water wash section into
the upper part of CO2 absorber. The treated gas is washed by water, thus removing any vaporized solvent and is cooled down to maintain the water balance within the system. The water wash section features a combination of packing and several demisters. One special proprietary demister which is specifically developed by MHI is included in this system. The system configuration of MHI’s proprietary design has been commercially demonstrated in several plants throughout the world.
Solvent regeneration Regeneration takes place in a cylindrical column using packing where the rich solvent is steam- stripped, using low pressure steam, to remove CO2.
The rich solvent from the bottom of the CO2 absorber is heated by the lean solvent from the bottom of the regenerator by means of a solution heat exchanger. The heated rich solvent is then introduced into the upper section of the regenerator, where it contacts with the stripping steam over the packing.
The steam in the regenerator is produced by the regenerator re-boiler which uses LP steam to boil the lean solvent. The condensate from the regenerator re-boiler is collected in the steam condensate drum and then pumped to the battery limit by the steam condensate return pump. The overhead vapour leaving the regenerator column is cooled by the regenerator condenser and condensate water is collected in the regenerator reflux drum.
The lean solvent is cooled to an optimum reaction temperature by the solution heat exchanger and lean solution cooler prior to being sent to the CO2 absorber. Some of the solvent flow is filtered to remove oil and soluble impurities which is likely to be contaminants arising from the flue gas stream.
(3) CO2 compression & Dehydration section
Product CO2 gas is sent to the CO2 compression and dehydrated section, where after passing through the low pressure stage of the CO2 compressor, it is sent to the dehydration plant in order to
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dehydrate product CO2. The CO2 compressor will compress product CO2 to a pressure of 100 bar before being transferred to pipeline where it will be sent to the sequestration site.
3.2.2.1 SOLVENT RECLAIMING (INTERMITTENT OPERATION) The primary purpose of the reclaiming is to remove soluble solvent degradation products such as heat stable salts (HSS) from the solvent. The Reclaimer operates as a simple batch distiller, and since the solvent degradation products and the salt have higher boiling temperatures than water or solvent, they remain in the reclaimer kettle where they can easily be collected for disposal.
3.2.2.2 UTILITY Steam system LP steam is required for the operation of the PCC plant. The LP steam is used to boil lean solvent through regenerator re-boiler.
The PCC plant base case for driving the CO2 compressor is by an electric motor. On an intermittent basis, MP steam is used to boil solvent during reclaiming operations.
Condensate is collected in a condensate drum which will be sent back to the station’s condensate system.
3.2.3 PCC Plant Dry Air Cooling System
The dry air cooling system of the PCC plant (used for Case 5) is proposed to be configured based on a closed cooling water circulation system equipped with air cooled heat exchangers.
This differs from the conventionally configured wet type open loop cooling water systems (e.g. once through or wet cooling tower systems).
For Case 5, the air cooling system will replace the wet cooling system of the PCC plant that is used for the following heat loads:
• Flue Gas Cooling Water Cooler
• Wash Water Cooler
• Lean Solution Cooler
• Absorption Intermediate Cooler
• Regenerator Condenser
• 1st Stage to 6th Stage Discharge Coolers
• Low/High Pressure Stage CO2 Compressor Stage Cooler
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3.3 Description Coal Drying Plant Great River Energy (GRE) has developed and patented a unique coal drying and coal upgrading technology, termed DryFiningTM, which enables improvement in the performance efficiency of a coal fired power station and thereby reduce the emissions and the station’s carbon footprint. The DryFiningTM concept involves utilizing waste heat which may be available in a power station to partially dry the feed (raw) coal in a fluidized bed dryer (FBD). Using gravitational segregation feature of a fluidized bed and a special design of the coal dryer, denser materials present in the coal such as pyrites, small rocks, and sands are segregated and separated from coal, thereby improving the quality of the coal fed to the power station. DryFiningTM was developed in conjunction with the first round of the U.S. Department of Energy (DOE) Clean Coal Power Initiative (CCPI) and with the additional support of the National Energy Technology Laboratory (NETL) based in Morgantown, West Virginia. Over the last decade GRE has proved technical feasibility of the concept firstly in a proof-of- concept 2 t/hr pilot-scale coal dryer, then a 75 t/hr prototype-scale dryer integrated in the GRE Coal Creek Station, located near Bismark, North Dakota, USA, and finally in the complete conversion of this 2 x 600 MW mine-mouth station to DryFiningTM the whole coal feed for the power station. The commercial coal drying system at Coal Creek includes four commercial size (125 t/hr) moving bed fluidized bed dryers per unit, crushers, a conveying system to handle raw lignite, segregated, and product streams, particulate control system, and control system. The system is fully instrumented for process monitoring and control. System commissioning was completed in December 2009.
The resultant reduction in emissions, including NOx, SOx, mercury and carbon dioxide as well as the increase in power production per ton of coal have confirmed the technical and economic viability of this concept. Under the conditions of the DOE Initiative, GRE is able to promote the use of the DryFiningTM technology elsewhere in the world. Power stations which fire high-moisture coals will find particular advantage with the implementation of DryFiningTM technology.
3.3.1 Sources of Waste Heat
In as much as Loy Yang A Power Station units fire very high moisture fuel, Loy Yang Power commissioned WorleyParsons in 2010, to perform an initial pre-feasibility study (Phase 1A) into the application of Coal Drying (DryFiningTM) at Loy Yang A Power Station. The objective of that evaluation was to perform a high level process analysis to allow Loy Yang Power to make an informed decision for a possible Phase 1 study.
The analysis of the Loy Yang “soft” lignite (brown coal) provided for that study showed that Loy Yang coal is geologically much younger than the Great River Energy’s “hard” lignite from North Dakota, USA. At 60 wt% (or 1.5 kg of water per dry kg of coal) Loy Yang’s brown coal is also significantly higher in moisture content compared with Great River Energy’s 38 wt% coal (0.61 kg water per kg).
Reducing the moisture in Loy Yang’s coal feed has therefore the potential to provide significant improvement in power station performance. In that study the size of the coal drying plant was based on drying coal for one complete 500 MW plant (Unit 3) at LYA. The major source of waste heat for DryFiningTM on most units is from the flue gas system. This heat is extracted by locating flue gas coolers (FGCs) in the flue gas stream at a convenient location downstream of the air heaters and particulate removal equipment.
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LYA operates flue gas temperatures at typically between 170°C and 190°C at the ID fan inlets. However, the operating philosophy limit is not less than 160°C, which is just 20°C to 25°C above the sulphur dew point of that of the stack gas. Despite the fact that corrosion due to sulphuric acid condensation in the flue gas system has been a serious problem in the LYA operating history, that study assessed the potential available at a stack temperature on the estimated dew point with a margin of 5 ºC above that point. Allowing for a design margin of 5°C, a lower stack gas temperature of 140°C may be used. This equates to the exit temperature of the flue gas cooler. The resulting heat available for coal drying then suggested a fuel moisture reduction from 60% to 54% is possible. Reduction of the moisture content to 54% results in a reduction of fuel flow to the boiler and through the majority of the coal handling system. The reduced moisture load on the boiler results in an increased boiler efficiency from 72% to 75.4%. Additional operational benefits expected are reduced flue gas flows through the back-end equipment, reduced loads on coal handling and processing equipment (especially the pulverisers), reduced loads on the ID fans and air handling equipment (air preheaters, ESP, ducts, etc.). Most importantly the carbon foot print of the LYA is reduced due to the resultant reduction in emissions.
A summary of the coal drying results from that study is presented in the Table 3 .7.
Table 3 .7 - Summary of Fuel Moisture Reduction Results from Previous Study
CO2 Fuel Emission Moisture Moisture Firing Boiler Gas Flow HHV (kg/kWh) Content Removal Rate (kg/s) Efficiency Reduction (MJ/kg) Gross
60% 0% 168 72.0% N/A 10.52 1.057
57%* 3% 152 73.8% 4.0% 11.31 1.038
54%* 6% 139 75.4% 7.8% 12.10 1.016
*After drying Source: WorleyParsons
The data provided by Loy Yang Power and collected from the previous 2010 coal drying study forms the design basis for the coal drying base model for this study.
The size of the coal drying plant for this study’s model is determined by
• the quantity of flue gas required by the 5000tpd PCC plant, and
• limiting the existing stack gas temperature to 140°C. The boiler plant of LYA is assumed to be able to operate at the modelled design conditions without any adverse effect, as in the case of the 2010 study.
From the design basis described above, a two-stage FGC was considered in this study.
The first stage, cooling the flue gas stream from 181°C to 140oC, would operate above the acid dewpoint temperature.
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The second stage will cool approximately 37% of the flue gas flow down to 70oC (conditions as required by the 5000tpd PCC plant) and, thus will operate below the acid dewpoint temperature, requiring corrosion-resistant alloys to be employed for its construction. A higher-grade heat may also be obtained from the flue gas upstream of the air heater.
The circulating water system is also a potential source of waste heat for DryFiningTM, although it has to be used indirectly because of its relatively low temperature. This can be done by transferring the heat into the boiler system via fan inlet or outlet coils. The nature of this benefit requires more detailed heat integration modelling. As the units at LYA are equipped with cooling towers, using the hot water fed to these towers may not only benefit the DryFiningTM process but also lessen the heat rejection load on the cooling towers.
As coal moisture is reduced, the efficiency of the plant increases resulting in a decrease in coal feed rate and emissions. A trade-off study is recommended to compare the cost of equipment required to reduce plant CO2 emissions versus the capital and operating cost of the Post-Combustion Carbon capture system and price of the CO2 emission allowances.
3.3.2 Fluidized Bed Coal Dryer A coal dryer developed by a team led by GRE employs a moving bed fluidized bed dryer fluidized by air. The fluidization velocity is optimized to minimize the flow rate of fluidizing air and fan power. The dryer operates at low drying temperatures (110°C to 120°C) at near-atmospheric pressure. The heat to the dryer is supplied by the in-bed heat exchangers (typically 65 to 70% of the total heat input) and by the fluidizing air (30 to 35%). A fluidized bed coal dryer is designed to maintain the temperature of the coal bed in the 45°C to 50°C range, while the maximum bed temperature is restricted to 55°C. The high heat and mass transfer characteristics and high throughput of a moving fluidized bed result in a compact design of the drying system. Due to a low operating temperature of the dryer, no exotic materials are needed, and the dryer is manufactured of carbon steel.
The fluidized bed coal dryer is designed for a coal crushed to a mean size of 6.4mm. Therefore, new coal crushing equipment would need to be installed at LYA since the existing coal crusher only prepares coal to 75mm.
3.3.3 Segregation Using gravitational segregation features of a fluidized bed and special features of the Mark II coal dryer design, denser materials present in the coal such as pyrites, small rocks, and sands are segregated and separated from coal, thereby improving the quality of the coal fed to the power station. For LYA, the brown coal has lower sulphur; ash and mercury content than the GRE lignite, but reportedly has excursions in sodium, iron, and total ash. Therefore, segregation feature of DryFiningTM may be desirable to Loy Yang for mitigation of furnace slagging and heat recovery area (HRA) fouling.
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4 METHODOLOGY
This study was undertaken as a case study of a real life plant with all relevant stakeholders participating in the evaluation.
4.1 Project Execution Roles
The following roles are critical to achieving a satisfactory outcome of an independent evaluation:
Independent engineering contractor: WorleyParsons took up the role as independent engineering contractor for this study carrying out the software selection, definition of project scope and cases, power plant modelling including the integration of the PCC plant and assessment of all cases. The major output included an independent view of plant performance impacts caused by the implementation of the PCC-retrofit, coal drying unit and method of flue gas cooling.
Host unit: Loy Yang Power provided all the necessary inputs for the power station’s boiler and steam turbine unit to WorleyParsons for the modelling of the plant using the appropriate software. It also provided resources to validate the thermodynamic models by comparing the outputs with real plant performance data.
Technology provider: It is important to include the technology provider as project participant since the PCC-process itself is proprietary. It will not be possible for the independent engineering contractor to model the complete process. The OEM will therefore provide the required process data for operation of the core PCC-process. However, isolation of this core process from the overall plant performance will also permit an assessment to ensure that chemical, heat and mass balances are maintained. In this case, MHI provided all the necessary inputs and outputs that was to be independently validated for a 5000tpd PCC plant retrofitted to the base power plant with and without the coal drying unit.
A more detailed description of the participating organizations can be found in Appendix 1.
In order to ensure that the proposed methodology was meeting the project goals, an independent peer reviewer was engaged to validate the methodology used in the study. This role was performed by Dr. Kelly Thambimuthu, who is an independent expert in the CCS area and also the chairman of the IEA Greenhouse Gas Research and Development Program. This role is not an ongoing one and would not be required in any subsequent rollout of the methodology developed in this study.
4.2 Overall Study Methodology and Project Timeline A high level study process schematic is shown in Figure 4 .1. The individual steps in constructing the models will be described in more detail in Section 4.5 .
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Figure 4 .1 - Summary of Study process
Source: WorleyParsons
The project timeframe from kick-off to the completion of the draft report took approximately six months. It is considered likely that the project timeframe could be shortened to around four months if there were a smaller number of parties involved.
4.3 Definition of project scope, cases and evaluation methodology
It is recommended that this first step is executed in a workshop environment that includes all project participants and any additional stakeholders. This will ensure that all project participants are aligned with respect to scope, deliverables and expectations of the study outcomes.
4.3.1 Project Scope
The overall technical scope of a project will be well defined in a real life case and the independent validation of process performance would be an added undertaking in the overall project feasibility study. However, it is important to note, that this independent validation will have to be repeated at each project stage up to FID or as the project achieves a higher level of engineering definition or incorporates other technical modifications.
It is important at this stage to define the battery limits and interface requirements between the power station host, the technology provider and the independent engineering contractor. This ensures a high level of integrity of the results. It is important to also minimize the “black box” of the separate PCC technology as much as possible relative to the overall system evaluated. However, it should be noted that it is impossible to verify the accuracy of a technology developer’s claim about the energy required for solvent regeneration, unless the chemical properties of the solvent are known. The physical properties of the solvent are also required to accurately simulate the overall performance of a chemical absorption system. This type of information is only available for public disclosure for MEA (mono ethanol amine) without additives. Despite these limitations in the access to data on the solvent
Page 19 GLOBAL CCS INSTITUTE POST COMBUSTION CARBON CAPTURE THERMODYNAMIC MODEL - LOY YANG POWER PLANT properties, it is nevertheless possible to benchmark the overall system performance using thermodynamic laws and expected process efficiencies.
In this case study, the actual CO2 capture process or other proprietary process technology (e.g. coal drying) were modelled by the respective process technology IP proprietors who participated in this study led by WorleyParsons. The PCC and coal drying process data were used to demonstrate which process data is required to validate overall plant performance after a PCC-and/or coal drying unit integration. These interfaces need to be defined in a case and technology specific manner. In cases where the relevant information is available under confidentiality agreements or is publicly available the independent engineering contractor might be in a position to validate the complete process without any requirement for inputs from the technology provider.
4.3.2 Case Definition
Several study cases should be defined in order to validate the models and to provide an optimised outcome for the retrofitted plant.
This study focuses on five specific Case Studies. The five Case Studies are presented in Table 4 .1. These cases have been tailored to evaluate the different performance impacts of different technical solutions applied to a specific host unit, with the overall aim of identifying the best combination from a plant output and efficiency perspective.
Table 4 .1 - Case Studies Matrix
Base Plant PCC Plant Coal Drying Plant Air Cooled Optimisation Operation
Base Case X
Case 1 X X
Case 2 X X X
Case 3 X X X X
Case 4 X X X
Case 5 X X X X X Source: WorleyParsons
4.3.3 Definition of Evaluation Methodology
It is important to define the evaluation methodology in the initial project phase. This ensures that the model outputs are in-line with the evaluation criteria and no rework is required. The individual parameters chosen will depend on the technology evaluated.
The following performance parameters have been evaluated as key variables for the deployment and/or roll out of carbon capture and storage facilities: • Steam Extraction Supply to PCC plant, MW • Auxiliary Power Supply to PCC plant, MW
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• CO2 Compression Power, MW • Power Station Net Sent Out Generation, MW • Water Requirements for the retrofit PCC plant, ML
The parameters above can also be utilised to assess a number of different carbon capture technologies.
In this retrofit application the amount of CO2 captured (5000tpd) and thus parasitic power for PCC and
CO2 compression are constant between the cases.
Thus, loss in gross generation is the only variable that is a function of the amount of heat recovered from CO2 compression.
However, the carbon capture technology in this study is based on the technology of an IP technology proprietor who is also one of the project’s proponents, which is then combined with an option to include a proprietary coal drying technology.
Hence, the above parameters would not be sufficient to capture all variations in plant performance between the study cases. For example it is not able to account for improvement in cycle efficiency resulting from the coal drying process.
The following parameters were therefore added to the list of variables: • Power Station Net Efficiency, % • Auxiliary Power Supply to Coal Drying Plant, MW
• CO2 emissions intensity per net power generated, kg CO2/ MWh net
In addition based on a recommendation from the independent peer reviewer, a calculated Electricity Output Penalty (EOP) was also used to compare results for the different cases.
The Electricity Output Penalty (EOP) in this study is defined as the Net Power Output Reduction divided by the absolute mass flow of CO2 captured, as follows: EOP = Net Power Output Reduction
CO2 captured mass flow Where:-
• Electricity Output Penalty (EOP) (kWhe/tCO2) • Net Power Output Reduction (kW) = Base Case Net generation (kW) – Study Case Net Generation (kW)
• CO2 captured mass flow (tonnes/h) • Study Case Net Generation = Study Case Gross Generation – [Study Case base plant auxiliary power + PCC auxiliary power (including CO2 Compression ) + Coal Drying auxiliary power] • Auxiliary power is the parasitic (power) loads of the plant /equipment of the respective base plant, PCC plant and coal drying plant as described above.
Overall, the performance results have to be combined with capital and operating cost estimates which will then allow the selection of the best technical and most economically viable solution.
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4.4 Selection of Software Tools
Commercially available software do not provide a single tool that allows the integration of multiple technologies such as a Rankine power cycle, PCC-plant, CO2-compression and coal drying operations in a coherent model. It is therefore important for the independent engineering contractor to select and validate a suite of software tools to achieve the project goal. This software suite must be tailored to the overall plant system and the technologies to be integrated. The individual packages have to be integrated off-line due to the interactions that have to occur to accommodate the IP of a technology provider and which increases the complexity needed to achieve a high level of data integrity.
The paragraphs below describe the approach adopted and software selected for these case studies.
4.4.1 LYA Power Plant (Base Case Plant) Software
The software for modelling the power plant (boiler/steam turbine) was selected following an assessment of commercially available software packages such as GE’s GateCycleTM, ThermoflowTM’s SteamPro and ThermoflowTM’s Themoflex.
SteamPro software automates the process of designing a conventional (Rankine steam cycle) power plant. It is particularly effective for creating new plant designs and finding their optimal configuration and design parameters. The user inputs design criteria and assumptions and the program computes heat and mass balance, system performance, and component sizing. Most key inputs are automatically created by intelligent design procedures that help the user identify the best design with minimal time and effort, while preserving the flexibility to make any changes or adjustments. It normally computes a heat balance and simultaneously designs the required equipment. When run in conjunction with an optional PEACE module, the program provides engineering and cost estimation details. Plant off-design conditions can be modelled with the SteamMaster module.
GateCycleTM is a plant performance monitoring software that predicts design and off-design performance of combined cycle plants, fossil fuelled boiler plants, nuclear power plants, cogeneration systems, combined heat-and-power plants, advanced gas turbine cycles and many other energy systems. The GateCycleTM software can be used for quick assessments, detailed engineering, design, retrofitting, re-powering and acceptance testing. Its component-by-component approach and advanced macro capabilities allow users to model virtually any type of energy system. However, GateCycleTM does not provide equipment sizing and cost estimation details.
ThermoflowTM’s Thermoflex is similar to GateCycleTM in terms of its component-by-component approach.
From the three software packages described above the GateCycleTM software was chosen to model the LYA power (boiler/steam turbine) plant due to;
• WorleyParsons’ experience that GateCycleTM is easier to use for analysing off-design runs and “what if” scenarios. All off-design cases are in a single model file. Changing a component design will automatically change all off-design cases for the component while the other inputs for the “off- design” cases remain unchanged. The component can be also linked to the component in any other model. By contrast, each “off-design” case has an individual model file in ThermoflowTM’s ThermoFlex/SteamPro with the components also placed at “off-design” modes. Changing the design of any component in the design file would require the creation of a new off-design file since there is no link/connection between the design and off-design model files.
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• GateCycleTM allows the as-built Loy Yang A plant to be modelled more accurately using the component-by-component approach especially in matching the various coal constituents (e.g. moisture, carbon content etc), boiler combustion and flue gas composition that feeds into a PCC plant model.
A screen shot of the Base Case Model using the GateCycleTM software package is shown in the Figure 4 .2 below.
Figure 4 .2 - Base Case GateCycleTM
Source: WorleyParsons
4.4.2 Post Combustion Capture Plant Software
The PCC plant model was built by the PCC technology IP proprietor using their own software and provided WorleyParsons the relevant Vendor performance information/data. This information was validated using a third party model to test the expected performance and establish if the performance data provided by the PCC technology IP proprietor is within the realm of credibility.
4.4.2.1 VALIDATION PROCESS
Validation of IP Proprietor’s PCC technology was carried out using a third party model for the integration of PCC plants with coal fired power plants. It is important for the validation process to be effective that before starting the process an accuracy tolerance (approximately ±5 %) is set and adhered to during the modelling and result evaluation processes. Equally important is the choice of software/model used to validate the IP proprietor’s data. It is necessary that the data provided by the
Page 23 GLOBAL CCS INSTITUTE POST COMBUSTION CARBON CAPTURE THERMODYNAMIC MODEL - LOY YANG POWER PLANT
IP Proprietor is sufficient to be able to compare with the output of the software/model chosen for validation.
The process undertaken involved simulating the output of the Loy Yang A boiler (flue gas flow, temperature, characteristics, etc) and using an embedded PCC model in SteamPro software. The boiler output flue gas flow was set to provide a 100% feed flow for a 5000tpd PCC plant. The software used to validate the data provided of the PCC technology was adequately flexible in being able to model a range of key variables such as:
• Amine, advanced or user defined process selection
• Solvent consumption/unit CO2
• Misc aux load
• SOx removal efficiency
• Cooling water inlet and delta temperatures
• Solvent circulation efficiency
• Flue gas flow, temperature and flue gas characteristic to the PCC plant
• CO2 capture efficiency
• Flue gas cooler exit temperature
• Treated flue gas exit temperature & Pressure
• Heat input rate (per unit CO2)
• CO2 compression pressure, temperature and RH
• CO2 compression efficiency
• Solvent flow rate
A number of iterations are normally required before settling on the model configuration for the PCC plant. Once the model is developed it is possible to assess the data provided by the PCC technology IP proprietor to establish if it fits within the window of expected performance and is within the realm of credibility.
The key pieces of data that were examined and compared with the model output were:
• Flue gas flow quantities relative to CO2 production
• Solvent usage rate
• Heat input rate (steam flow)
• PCC Auxiliary power consumption
• CO2 Compressor power consumption
• Cooling water flow rate
If the model results are found to vary beyond the accuracy tolerance that was set at the start of the validation process, the relevant data provided by the IP proprietor should be questioned and if necessary should be validated and confirmed by the PCC technology IP proprietor. It is important
Page 24 GLOBAL CCS INSTITUTE POST COMBUSTION CARBON CAPTURE THERMODYNAMIC MODEL - LOY YANG POWER PLANT that the consultant carrying out the validation process fully understands any underlying characteristics of the IP proprietor’s data, especially when the data does not easily conform to currently available models/software. Adjustments to the model can be made after clarification is provided by the IP proprietor.
4.4.3 Coal Drying Plant Software
The coal drying process is simulated using a proprietary MS Excel based model which is developed by the Lehigh University for Great River Energy (GRE), the coal drying technology proprietor. This model formed a part of the independent validation process. The remainder of the independent validation process involved a high level simulation of the coal drying process again to establish if the performance data provided by the coal drying technology proprietor is within the realm of credibility.
4.4.3.1 VALIDATION PROCESS
Validation of coal drying IP proprietor was carried out by a high level design check for the integration of coal drying plant with the coal fired power plant. Similarly as stated for the PCC plant validation, that for the validation process to be effective it is necessary that before starting the process an accuracy tolerance is set and adhered during the calculation and result evaluation processes. It is also necessary that the data provided by the coal drying IP Proprietor is sufficiently defined and understood by the validating consultant.
Similarly as for the case of the PCC, the process undertaken for the coal drying involved simulating the output of the Loy Yang A boiler (flue gas flow, temperature, characteristics, etc) and carrying out a number of design checks against the data generated on an Excel based model developed by Lehigh University.
The starting point for the validation was to use the output data that was validated by the boiler software model (GateCycleTM) and preliminary input data for the PCC plant. Several iterations may be necessary before the output data from the boiler and the input data to the PCC plant produces a stable output for the PCC plant (5000tpd output).
A key issue that required a number of iterations before arriving at a validated set of data for the coal drying plant was the limit of coal drying that could be achieved in the current boiler design before other technical issues
4.5 Methodology used to construct and validate the Thermodynamic Models
The methodology to construct and validate the Thermodynamic Models involved:
• Data collection and review, as input for the thermodynamic modelling,
• Set up the thermodynamic model and validate it so that it reproduces the existing unit’s performance. This provides assurance that the model will be able to predict cycle performance
under the various design modes, i.e. with CO2 capture and part load operation,
• Perform simulations and produce overall block flow diagrams (Appendix 3) and the host unit power plant heat and mass balance diagrams (Appendix 2); corresponding to each design case, showing steam extraction for solvent recovery and heat recovery from compression,
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• Validate results against real performance data (where possible) or against general thermodynamic and process requirements.
In this study, the CO2 compression modelling was performed by MHI (the PCC technology IP proprietor) using a commercially available software package. MHI’s model results produced the power and cooling requirements of the PCC plant based on CO2 captured flow rate, pressure and temperature. The CO2 compression model also calculates heat energy that could be recovered for the steam cycle. The CO2 compression modelling can be modelled by any project developer using commercially available software (e.g. Aspen HYSYS).
The following sections provide an overview of the methodologies developed, and the data and assumptions required, for a thermodynamic model of each case examined.
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4.5.1 Base Case: Host Unit - LYA Power Plant
The Base Case methodology is shown in the Figure 4 .3 below.
Figure 4 .3 - Base Case Methodology Flow Chart
Source: WorleyParsons
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4.5.1.1 STEP 1: DATA COLLECTION
The GateCycleTM model input data for the Base Case Model uses several sets of existing Loy Yang A Power Station’s Unit 1 - Steam Turbine Generator operating data that have been verified for use by Loy Yang Power.
The nominated sources of the input data are as follows:-
• Loy Yang Power’s LYA Heat and Mass Balance Diagrams of Unit 1 from the Loy Yang Power Post power enhancement project as appended in the LYP “Post Upgrade Report”4
• Loy Yang Power’s DryFiningTM Coal Drying Pre-Feasibility Study Phase 1A 5
• Loy Yang Power’s Large Scale Demo Project Post Combustion Capture Prefeasibility Study6
• Loy Yang Power’s LYA Unit 1 Guarantee Case HMB diagram FR23/0927/1002 and LYP Unit 1 part load HMB diagram FR23/0927/1006
The Base Case plant data is extracted from the LYP Unit 1 Heat Mass Balance Diagram “FR23/0927/1002 – LYP Station HP Intermediate Pressure Turbine No 10575 – Valves Wide Open with an output of 569MW, and steam conditions of 37kg/s Superheat and 12kg/s Reheat Spray” - Guarantee condition as outlined in Appendix 2.
This Steam Turbine “Guarantee” condition HMB is nominated for the reason that it will provide the optimum case scenario for analysis of the effect of steam extraction (as required by the PCC plant) on the steam turbine’s output.
Generic and typical lignite fired sub-critical steam cycle power plant assumptions were used wherever specific project data were not available and/or not provided by LYP or the PCC process technology IP proprietor.
4.5.1.2 STEP 2: MODEL THE BASE CASE PLANT
The Base Case model built is validated by testing the GateCycleTM Steam Turbine cycle against the original HMB for full and part load as supplied by Loy Yang Power. These conditions are presented in Appendix 2.
A GateCycleTM model based on the LYP Unit 1 Guarantee Case HMB diagram FR23/0927/1002 was created. The results of the guarantee case simulation are presented in the WorleyParsons Base case HMB drawing CCLY-1-HT-021-0001. The gross generation in the LYA Unit 1 guaranteed case HMB is 568,961 kW.
WorleyParsons model predicted gross generation of 568, 960 kW (a 0.00018% difference).
4 Sinclair Knight Merz “Loy Yang Power- Power Enhancement Project, Post Upgrade Report Units1,3 and 4, Final”, 29 September 2009
5 WorleyParsons, “Loy Yang Power - DryFining – Coal Drying Prefeasibility Study Phase 1a Report, Rev 0”, 29 July 2010
6 WorleyParsons, “Loy Yang Large Scale Demonstration PCC Plant Basis of Design, Rev 2”, 20 January 2012
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4.5.1.3 STEP 3: VALIDATE LOW LOAD BASE CASE MODEL
The partial load case was simulated based on the operating condition in the LYA Unit 1 HMB diagram FR23/0927/1006. In this partial load HMB, the LP steam turbine inlet flow rate is approximately 290 kg/s, which is comparable to the LP turbine flow range of 310 – 350 kg/s in the PCC retrofit cases. The LYA Unit 1 HMB diagram shows gross power output of 426,024 kW.
The model predicted the gross power output of 426,122 kW for the same conditions (less than a 0.25% difference).
4.5.1.4 STEP 4: REVIEW AND CONFIRM MODEL OUTPUT WITH PLANT OWNER
The modelled Base Case’s Heat Mass Balance (HMB) diagram (WorleyParsons drawing CCLY-1-HT- 021-0001) is shown in Appendix 2 and a simplified block diagram of the model is shown in Appendix 3.
The model output results were presented to the plant owner and the differences between the model predictions and actual HMB data are deemed acceptable.
This model is then used as the Base Plant Model to model the study cases.
4.5.2 Case 1: Host Unit and Post Combustion Capture Plant Model
The Case 1 methodology and validation steps are shown in the figure below.
Figure 4 .4 - Case 1 Methodology Flow Chart
Source: WorleyParsons
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4.5.2.1 STEP 1: PROVIDE DATA TO PCC TECHNOLOGY IP PROPRIETOR
The Base Plant (GateCycleTM) flue gas conditions and properties data was provided to the PCC process technology IP proprietor to allow him to model the 5000tpd PCC plant.
4.5.2.2 STEP 2: PCC TECHNOLOGY IP PROPRIETOR MODELS PCC PLANT
The PCC technology IP proprietor completed the model of the PCC plant in accordance with his standard procedure for demonstration and commercial PCC plants.
In this case study the PCC-technology provider also modelled the CO2-compression cycle. However, this can also be performed by the independent engineering contractor using a commercially available model such as Aspen HYSIS. The model produces power and cooling requirements based on the captured CO2 flow rate, pressure and temperature. The CO2 compression model also calculates heat energy that could be recovered for the steam cycle.
4.5.2.3 STEP 3: COLLECT PCC MODEL OUTPUT DATA
The output data from the 5000tpd PCC plant model is obtained from the technology IP proprietor. This data, which is independently validated by WorleyParsons, comprises:
• Cooling water, steam supply, condensate return and waste discharge auxiliary power requirements,
• Heat available from the CO2 compression process,
• Treated flue gas and product CO2 conditions / properties.
Output data provided by the PCC process technology IP proprietor for the 5000tpd unit includes: • List of utility services and condition requirements, • Utilities Flow Diagrams, • Process Flow Diagrams,
• CO2 compression heat available for power plant integration.
Figure 4 .5 – Overview Block Flow Diagram depicts the inputs and outputs of the PCC plant.
4.5.2.4 STEP 4: COMPLETE THE MODEL OF CASE 1
Data collected in Step 3 is fed into the Base Plant model to run it as the Case 1 model.
4.5.2.5 STEP 5: REVIEW AND CONFIRM CASE 1 MODEL OUTPUT WITH PLANT OWNER
The modelled Case 1 Heat Mass Balance (HMB) diagram (WorleyParsons drawing CCLY-1-HT-021- 0002) is shown in Appendix 2 and a simplified block diagram of the model is shown in Appendix 3.
The final Case 1 model output results were presented to the plant owner and review and confirmation was undertaken with them.
In the Case 1 steam cycle simulation, as in all of the CO2 capture cases, the validation procedure included the step whereby the main steam turbine throttle steam flow and the Intermediate Pressure
Page 30 GLOBAL CCS INSTITUTE POST COMBUSTION CARBON CAPTURE THERMODYNAMIC MODEL - LOY YANG POWER PLANT steam inlet flow were maintained similar to the corresponding flows in the Base Case, while the LP steam flow rate to the LP turbine ranges from 310 – 350 kg/s due to the extraction for the PCC plant, which is close to the LP steam turbine inlet flow rate of approximately 290 kg/s for the partial load validation case.
Page 31 GLOBAL CCS INSTITUTE POST COMBUSTION CARBON CAPTURE THERMODYNAMIC MODEL - LOY YANG POWER PLANT
Figure 4 .5 - Overview Block Flow Diagram
Source: WorleyParsons
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4.5.3 Case 2: Host Unit with Coal Drying Plant Model
The Case 2 methodology and validation steps are shown in the figure below.
Figure 4 .6 - Case 2 Methodology Flow Chart
Source: WorleyParsons
4.5.3.1 STEP 1: PROVIDE DATA TO COAL DRYING IP PROPRIETOR
The Base Case model flue gas data were provided to the Coal Drying team to model the Coal Drying process as the flue gas data of the Base Case plant was used as the initial conditions. During the modelling iteration, the new flue gas conditions firing dried coal were used until the model achieved convergence. The drivers for plant sizing are outlined in more detail in Section 3.3 .
4.5.3.2 STEP 2: COAL DRYING IP PROPRIETOR MODELS COAL DRYING PLANT
The Coal Drying model is built to:
• Determine the total amount of heat and fluidizing air required for coal drying in fluidized bed coal dryers (FBDs) as a function of the product (dried coal) moisture content for Loy Lang A power plant. (The total heat input to a FBD includes heat for the in-bed heat exchangers and heat required by the fluidizing air.)
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• Determine the number of FBDs as a function of the product moisture content.
• Given the amount of heat that may be recovered from the flue gas, determine the achievable product moisture content.
The design basis for the base case coal drying plant is described in Section 3.3 Description Coal Drying Plant. 1) Calculation Inputs
A standard calculation procedure, used to design the commercial coal drying system at Coal Creek Units 1 and 2 was used in the Loy Yang study.
Drying of raw coal is accomplished in fluidized bed dryers (FBDs) of standard Mark II design.
Based on the operating experience with North American Lignites, the surface temperature of the in- bed heat exchangers of 121°C was selected. Devolatization tests will be needed to confirm this assumption for the final design. For highly reactive coals, a lower temperature for the in-bed heat exchanger surface might be needed.
The temperature of the fluidizing air entering the plenum of a FBD of 121°C was selected for the analysis. It has to be noted that temperature of the fluidizing air may be different (higher or lower) compared to surface temperature of the in-bed heat exchanger.
For the selected drying temperatures and Mark II design of a FBD, approximately 35% of the total heat input to the FBD is supplied by the fluidizing air.
The computer code, developed by Lehigh University, for predicting performance of a FBD (product moisture content, bed temperature, and heat input to the in-bed heat exchangers) as functions of the FBD operating and design parameters (feed rate and moisture content of the raw coal, in-bed heat exchanger surface temperature and heat exchange area, fluidizing air temperature, FBD size, expanded bed depth, and moisture content of the fluidizing air) was employed in the analysis.
The code has been extensively verified against the laboratory-scale, pilot-scale, and prototype-scale test data and is a standard tool used for the FBD design.
In the absence of information on drying kinetics of the Loy Yang coal, its drying properties were approximated by those of German lignite. This is a good approximation since German lignite contains moisture within the range of 54% to 57%, compared to the Loy Yang lignite’s moisture content of 60%.
An iterative calculation procedure was used to determine product moisture content for the required flow rate of dried coal. Since efficiency of the plant improves as coal moisture content is reduced, the required flow rate of dried coal and raw feed coal (Figure 4 .7) decrease with a decrease in product moisture content, thus requiring the iteration. Iteration is performed by varying the feed rate of raw coal and the number of FBDs. Convergence on flow rate and moisture content of the dried coal is typically achieved in three iteration steps.
The raw coal moisture content of the Loy Yang coal of 60% was used in the calculations.
The specific moisture content of fluidizing air of 0.007895 kg H2O/kg dry air, used in the calculations, was determined from the information provided on dry and wet bulb temperatures.
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2) Calculation Outputs
Flow rates of wet (raw) coal feed and product (dried) coal as functions of coal moisture content predicted by the model of Loy Yang A power plant, and determined iteratively by the FBD performance analysis are presented in the Figure 4 .7 below. The curves show the relationship of wet and dry coal flow rates at a constant boiler throttle steam flow rate, pressure, temperature and enthalpy. This is to ensure the steam conditions are consistent with all Cases modelled.
Figure 4 .7 –Wet and Dried Coal Flow Rates as a Function Coal Moisture Content
Loy Yang Performance Prediction 180
170
160
150
140 Coal Flow Rate [kg/s]
Wet Coal Feed 130 Dried Coal - Product Wet Coal Feed - FBD Analysis
120 48 50 52 54 56 58 60 62 Product Coal Moisture Content [%] Source: Lehigh University
The results of the coal drying process simulation are presented in the following figures.
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Figure 4 .8 – Reduction in CO2 emissions as a function of coal moisture content
Loy Yang Performance Prediction 10
9
8
7
6 Emissions [%] 2 5
4
3 Reduction inCO 2
1
0 48 49 50 51 52 53 54 55 56 57 58 59 60 61 62 Product Coal Moisture Content [%]
Source: Lehigh University
Figure 4 .9 – Product moisture content and the number of Mark II fluidized bed coal dryers as functions of the required and available heat
Loy Yang FBD Performance Prediction
60 10
9
55 8
7
50 6
5
45 4 Numberof FBDs
3
40 Qfgc, Tfg,FGC,out = 140/70 Deg. C 2 ProductCoal Moisture Content [%] Qfbd, 40-inch bed Number of FBDs 1
35 0 40 50 60 70 80 90 100 110 120 130 140
QFBD,TOT or QFGC [MWth]
Source: Lehigh University
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Figure 4 .10 – Acid dewpoint T °C as a function of SO3 and H2O concentrations in the flue gas
Acid Dewpoint Temperature vs. SO3 and H2O Concentration 140
130 C] o
120 17 % H20 18% H20 19% H20 20% H20 21 % H20 110 22% H20 Acid Acid Dewpoint [ Temperature
100 0 0.5 1 1.5 2 2.5 3 3.5 4 4.5 5
SO3 Concentration [ppmv]
Source: Lehigh University
• In Figure 4 .9 the quantity Qfgc, indicated by a blue line, represents the amount of heat that may be recovered from the flue gas by cooling approximately 37% of the flue gas flow from 181°C to 70oC and the rest (approximately 63%) from 181°C to 140°C. Variation of the flue gas flow rate
with moisture content of dried coal was taken into the account when calculating Qfgc.
• As shown in Figure 4 .10, the Flue Gas Cooler (FGC) cooling 63% of the flue gas flow will, at full plant load, operate above the acid dewpoint temperature (127°C to 130°C).
• The quantity Qfbd, indicated by a red line on Figure 4 .9, represents the total amount of heat required for coal drying.
• The intersection on Figure 4 .9 of the available and required heats represents operating point of the coal drying system and determines the achievable product moisture content (55%), a 5%- point reduction, for the analysed coal drying configuration.
• The product coal moisture content may be reduced further by supplying additional heat from other
sources, which will shift the Qfgc on the Figure 4 .9 curve to the right. This analysis was outside of this scope of work, but is recommended.
• As shown in Figure 4 .8, a 5%-point reduction in coal moisture content corresponds to
approximately 5% reduction in CO2 emissions.
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• The number of fluidized bed dryers (FBDs) of the standard Mark II design with a 40” expanded bed height is also presented. A shown on Figure 4 .9, five FBDs are needed to reduce coal moisture content from 60 to 55%.
• A cost-benefit analysis is needed to determine if further reduction of coal moisture content by employing additional heat exchange equipment is economically viable, after verification that the existing boiler plant design can handle reduced moisture content coals.
The results of the Coal Drying modelling are shown in the Table 4 .2 and Table 4 .3.
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Table 4 .2 - Coal Drying Flue Gas Conditions
Parameters Units Value Notes of MHI
Coal Moisture % 55
Coal Feed (dried) kg/s 145.11
Coal Feed (wet 60%) kg/s 163.25
Total Flue Gas Flow kg/s 892
Flue Gas Temp (after ID °C 175 Fan)
Flue Gas Composition, by % From Coal (Assumed 90% capture eff based volume % Drying model on PCC process technology IP proprietor data)
N2 % 63.33
CO2 % 11.70
SO2 % 0.02
O2 % 4.26
H2O 19.93
Ar % - 0.74
Others % 0.76 0.02
Total % 100
Average Molecular Weight 27.84 28.1
CO2 by weight % 18.49 18.30
Flue Gas Flow1 to Carbon kg/s 347 352 Capture (PCC)
Flue Gas Flow1, Temp °C 70 To PCC plant (After FG cooler)
Flue Gas Flow2 to kg/s 545 540 Chimney
Flue Gas Flow2 Temp °C 140 (After Cooler) Source: WorleyParsons
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Table 4 .3 - Wet and Dried Coal Data Comparison
Parameters Units Existing LYP Wet Coal Possible LYP Dried (Value) Coal (Value)
Coal Ultimate Analysis
Coal Moisture % 60 55
Carbon (C) % 27 31
Hydrogen (H) % 2 2
Sulphur (S) % 0 0
Oxygen (O) % 10 11
Nitrogen (N) % 0 0
Moisture % 60 55
Ash % 0.90 1.01
Total % 100 100
HHV kJ/kg 10,511 11,825
HHV BTU/lb 4,519 5,084 Source: WorleyParsons
While typically three iterations were foreseen to achieve convergence of moisture content in the feed coal and the flue gas properties, the modelling of the coal drying process was performed in two iterations from the initial 60% moisture brown coal feed. This was accomplished by performing parametric analysis to establish the relationships between the moisture content in the dried coal, and the boiler flue gas composition and other characteristics. The outcome of the parametric analysis is the correlation between available heat from the flue gas, heat requirement by the drying system, and moisture removal rate of the coal drying system.
4.5.3.3 STEP 3: REVIEW AND VERIFY BOILER ACCEPTANCE OF LOWEST COAL MOISTURE CONTENT
The outputs of the coal drying plant are the flue gas conditions / properties and dried coal conditions / properties leaving the coal drying process. Refer to Figure 4 .5 above for the inputs and outputs of the coal drying plant.
The results from the last iteration was reviewed and validated based on the lowest dried coal moisture content achievable whilst ensuring downstream flue gas temperatures;
• do not impact the existing power station flue stack’s acid dew point temperature (approximately 130°C) and,
• provide a reasonably cooled flue gas to the PCC plant.
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The Coal Drying model output results were presented to the plant owner and deemed acceptable based on previous results from the DryFiningTM study.
4.5.3.4 STEP 4: MODEL BASE PLANT WITH DRIED COAL DATA
The results/outputs from the Coal drying process in Steps 2 and 3 above are fed back into a Base Case model to simulate a Case 2 Base Plant operating with Dried Coal. The use of a coal drying process changes the flue gas characteristics of the power station.
It is therefore important to run the PCC-process calculation specifically for this case as the flue gas entry condition to the PCC-plant would not have the same flue gas characteristics as that of the Base Case or Case 1 (wet coal).
4.5.3.5 STEP 5: PROVISION OF FLUE GAS DATA TO PCC TECHNOLOGY IP PROPRIETOR
The flue gas conditions and properties data from the modelling as Case 2 Base Plant (GateCycleTM) was provided to the PCC process technology IP proprietor for modelling of the 5000tpd PCC plant.
4.5.3.6 STEP 6: PCC TECHNOLOGY IP PROPRIETOR MODELS PCC PLANT
The PCC process technology IP proprietor process team re-models the PCC plant as a Case 2 PCC plant.
The outputs for this model will define utility requirements of this PCC-plant.
4.5.3.7 STEP 7: COLLECT PCC MODEL OUTPUT DATA FROM PCC TECHNOLOGY IP PROPRIETOR
The output data from 5000tpd PCC plant model are then obtained from the technology IP proprietor.
The outputs of the PCC model that are provided by the PCC technology Proprietor and independently validated by WorleyParsons are: • Cooling water, steam supply, condensate return, waste discharge, auxiliary power requirements • Heat available from the CO2 compression process • Treated flue gas and product CO2 conditions / properties
Output data provided by the PCC process technology IP proprietor for the 5000tpd unit includes: • List of utility services and condition requirements. • Utilities Flow Diagrams. • Process Flow Diagrams.
• CO2 compression heat available for power plant integration.
Refer to Figure 4 .5 - Overview Block Flow Diagram on the inputs and outputs of the PCC plant.
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4.5.3.8 STEP 8: COMPLETE MODEL OF CASE 2
Data collected in Step 7 above is fed back into the Case 2 Base Plant model to complete the loop as the final Case 2 model.
4.5.3.9 STEP 9: REVIEW AND CONFIRM CASE 2 MODEL OUTPUT WITH PLANT OWNER
The modeled Case 2 Heat Mass Balance (HMB) diagram (WorleyParsons drawing CCLY-1-HT-021- 0003) is shown in Appendix 2 and a simplified block diagram of the model is shown in Appendix 3.
The final Case 2 Model output results were presented to the plant owner and review and confirmation was undertaken with them.
In the Case 2 steam cycle simulation, as in all of the CO2 capture cases, the validation procedure included the step whereby the main steam turbine throttle steam flow and the Intermediate Pressure steam inlet flow were maintained similar to the corresponding flows in the Base Case, while the LP steam flow rate to the LP turbine ranges from 310 – 350 kg/s due to the extraction for the PCC plant, which is close to the LP steam turbine inlet flow rate of approximately 290 kg/s for the partial load validation case.
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4.5.4 Case 3: Host Unit with Coal Drying, PCC Plant and Optimization
The Case 3 methodology and validation steps are shown in the figure below.
Figure 4 .11 - Case 3 Methodology Flow Chart
Source: WorleyParsons
4.5.4.1 STEP 1: REVIEW CASE 2 MODEL OUTPUTS
The Case 2 model forms the basis of the Case 3 model where the optimization options are evaluated and inputted/introduced into the Case 3 Base Plant model.
The following plant optimization provisions were identified:
• Parallel condensate heaters after each CO2 compression stage to recover high quality heat from
the CO2 gas compression (Refer Section 5.4 for further detailed discussions).
• A steam expander is utilized (instead of steam pressure reducing station in Cases 1 and 2.) to reduce pressure of the steam being extracted for the PCC plant, while generating additional power.
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4.5.4.2 STEP 2: MODEL BASE PLANT WITH DRIED COAL DATA AND OPTIMISATION INPUTS
The Case 3 Base Plant is modelled with dried coal and with the optimization inputs describe in Step 1, above, added on and finalized as the Case 3 model.
In the Case 3 Configuration, heat recovered from flue gas cooling upstream of the PCC plant is utilized for coal drying as in the Case 2.
4.5.4.3 STEP 3: REVIEW AND CONFIRM CASE 3 MODEL OUTPUT
The modelled Case 3 Heat Mass Balance (HMB) diagram (WorleyParsons drawing CCLY-1-HT-021- 0004) is presented in Appendix 2 and a simplified block diagram of the Case 3 Model is shown in Appendix 3.
The final Case 3 Model output results were presented to the plant owner and review and confirmation was undertaken with them.
In the Case 3 steam cycle simulation, as in all of the CO2 capture cases, the validation procedure included the step whereby the main steam turbine throttle steam flow and the Intermediate Pressure steam inlet flow were maintained similar to the corresponding flows in the Base Case, while the LP steam flow rate to the LP turbine ranges from 310 – 350 kg/s due to the extraction for the PCC plant, which is close to the LP steam turbine inlet flow rate of approximately 290 kg/s for the partial load validation case.
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4.5.5 Case 4: Host Unit with PCC Plant and Optimization
The Case 4 methodology and validation Steps is shown in the figure below.
Figure 4 .12 - Case 4 Methodology Flow Chart
Source: WorleyParsons
4.5.5.1 STEP 1: REVIEW CASES 1 AND 3 MODEL OUTPUTS
The Case 1 and Case 3 models form the basis of the Case 4 model where the optimization options are evaluated and inputted / introduced into the Case 4 model.
The following plant optimization provisions were identified:
• Parallel condensate heaters after each CO2 compression stage to recover high quality heat from
the CO2 gas compression,
• A steam expander is utilized (instead of steam pressure reducing station in Cases 1 and 2.) to reduce pressure of the steam being extracted for the PCC plant, while generating additional power,
• Case 4 do not have the coal drying process therefore flue gas coolers are utilized to generate low pressure steam to supplement steam extraction for the PCC plant.
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4.5.5.2 STEP 2: MODEL BASE PLANT WITH OPTIMISATION INPUTS
The Case 4 Base Plant is modelled with the optimization inputs describe in Step 1, above, added on and finalized as the Case 4 model.
4.5.5.3 STEP 3: REVIEW AND CONFIRM CASE 4 MODEL OUTPUT WITH PLANT OWNER
The modelled Case 4 Heat Mass Balance (HMB) diagram (WorleyParsons drawing CCLY-1-HT-021- 0005) is shown in Appendix 2 and a simplified block diagram of the model is shown in Appendix 3.
The final Case 4 Model output results were presented to the plant owner and review and confirmation was undertaken with them.
In the Case 4 steam cycle simulation, as in all of the CO2 capture cases, the validation procedure included the step whereby the main steam turbine throttle steam flow and the Intermediate Pressure steam inlet flow were maintained similar to the corresponding flows in the Base Case, while the LP steam flow rate to the LP turbine ranges from 310 – 350 kg/s due to the extraction for the PCC plant, which is close to the LP steam turbine inlet flow rate of approximately 290 kg/s for the partial load validation case.
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4.5.6 Case 5: Host Unit with Coal Drying, PCC Plant (with Air Cooling) and Optimization
The Case 5 methodology and validation Steps is shown in the figure below.
Figure 4 .13 - Case 5 Methodology Flow Chart
Source: WorleyParsons
4.5.6.1 STEP 1: REVIEW CASE 3 MODEL OUTPUTS
This Case 5 model is similar to Case 3 except that the PCC process utilises dry air cooling system instead of wet water cooling system.
The Case 3 model forms the basis of the Case 5 model where the optimization options are evaluated and inputted / introduced into the Case 5 model.
The following plant optimization provisions were identified:
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• Parallel condensate heaters after each CO2 compression stage to recover high quality heat from
the CO2 gas compression.
• A steam expander is utilized (instead of steam pressure reducing station in Cases 1 and 2.) to reduce pressure of the steam being extracted for the PCC plant, while generating additional power.
For this dry air cooling case, the PCC plant cooling heat load is assumed to be the same as in Case 3, where both cases’ main processes are the same except where a dry air cooling system is utilized for the PCC plant instead of the normal wet cooling system. This will result in the power station efficiency and output being marginally lower for the dry air cooling option because of its higher auxiliary power consumption.
4.5.6.2 STEP 2: MODEL BASE PLANT WITH OPTIMISATION INPUTS
The Case 5 Base Plant is modelled with the optimization inputs describe above in Step 1, added on and finalized as the Case 5 model.
4.5.6.3 STEP 3: REVIEW AND CONFIRM CASE 5 MODEL OUTPUT
The modelled Case 5 Heat Mass Balance (HMB) diagram (WorleyParsons drawing CCLY-1-HT-021- 0006) is shown in Appendix 2 and a simplified block diagram of the model is shown in Appendix 3 .
The final Case 5 Model output results were presented to the plant owner and review and confirmation was undertaken with them.
In the Case 5 steam cycle simulation, as in all of the CO2 capture cases, the validation procedure included the step whereby the main steam turbine throttle steam flow and the Intermediate Pressure steam inlet flow were maintained similar to the corresponding flows in the Base Case, while the LP steam flow rate to the LP turbine ranges from 310 – 350 kg/s due to the extraction for the PCC plant, which is close to the LP steam turbine inlet flow rate of approximately 290 kg/s for the partial load validation case.
4.6 Validation of Methodology by Independent Peer Review
The applied methodology was validated by the Independent Peer Reviewer in order to set an industry benchmark. This validation process focused on the review of the methodology only and did not review any specific performance data from either the power station or the PCC process.
The Independent Peer Reviewer therefore did not have access to any proprietary information from either the power station or the technology IP proprietors.
The validation was carried out through close involvement of the Independent Peer Reviewer in the following phases:
• Kick-off meeting and definition of methodology at the start of the project,
• Intermediate methodology review after the base cases have been established, and
• Final review at project end.
A report written by the Independent Peer Reviewer summarising his findings is shown in Appendix 5.
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5 POST COMBUSTION CAPTURE INTEGRATION
5.1 Steam Extraction for Solvent Regeneration
Steam for the PCC plant solvent regeneration is extracted from the steam crossover pipe between the intermediate pressure and low pressure (LP) turbine cylinders, with the extraction pressure set as close as possible (allowing for pressure and temperature drops) to the pressure and temperature required by the PCC plant at the tie in battery limit.
Within the PCC plant battery limit, the steam is trimmed further and condensed (typically in a re-boiler feeding a stripper column) to provide the heat required to regenerate the solvent.
5.2 Substitute Options for Steam
In Case 4, the flue gas coolers are utilized to generate low pressure steam to supplement steam extraction for the PCC plant and an alternative source of steam supply for solvent regeneration was not explored. Alternative steam supply sources can be accommodated into the model by the addition of other steam boilers/generators to the GateCycleTM model on the power plant side. The latter approach is sometimes pursued to investigate options for a plant conversion that avoids a drop in the net heat rate of the host power plant retrofitted with a PCC unit. The latter option was not within the scope of work of the current study and was not pursued.
5.3 CO2 Compressor Drive Options
The CO2 compression drive in this study is an electrically driven unit. The power required for the CO2 compression is an input required for the overall integrated modelling of the PCC process. For the integration this compression power is to be taken off from the power station’s gross generated power output.
Other options for the CO2 compression drive were not evaluated in this study. However, if desired, this option can be modelled either by WorleyParsons or the PCC plant IP proprietor and integrated into the system.
5.4 CO2 Compressor Utilisation of Waste Heat
Waste heat from the CO2 compression process in the PCC plant is recovered / integrated into the power station’s steam cycle for condensate feed-water heating via the CO2 compressor’s inter-stage coolers.
The CO2 gas stream exiting the MHI PCC system is compressed in several staged compressors.
After each compression stage, the CO2 gas is cooled in a cooler to recover high quality heat, and then is cooled further in a trim cooler. This configuration reduces the efficiency penalty by recovering some energy from the CO2 compression cycle, minimizing net energy use for CO2 compression, and reducing the cooling load requirement.
The T-Q diagram presented in Figure 5 .1 below provides details of CO2 compressor inter-stage cooling and CO2 gas heat recovery integration that occurs with feedwater heating.
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Figure 5 .1 – Condensate Heating and CO2 Compressor Cooling Integration T-Q Diagram
Source: WorleyParsons
5.5 Operating Flexibility of Power Station Boiler Plant
The power station’s boiler plant is assumed to be able to operate at the modelled design conditions without any adverse effect.
In the model cases where coal drying is integrated, the minimum dried coal moisture content was selected so as not to have any adverse impact on the flue gas acid dew point in the existing power station stack.
Further in depth and site specific investigation would have to be performed during actual feasibility studies / detailed design stages of any PCC plant in order to determine the operating flexibility of the retrofitted power plant.
5.6 Operating Flexibility of PCC Plant
MHI PCC plants have the ability to adjust to Power Station load changes, or to load follow. Load following ensures stable operation during low load, maximum export load, transitioning periods and during in between conditions.
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5.7 Implications of an actual PCC Retrofit and Coal Drying on the Existing Plant Systems
Retrofitting a PCC system at the existing LYA Unit 1 requires actual engineering, physical equipment and plant addition of the PCC plant and CO2 compression system. It also requires actual engineering and physical modifications to the existing boiler flue gas system, steam cycle/condensate systems, and additions/modifications to the balance of plant systems. Modification of the existing unit, unlike a “green-field” design, is significantly influenced by its pre-existing configuration. The scope of modifications and techniques that could be applied to reduce the energy penalty associated with enabling carbon capture is constrained by the existing plant system design, layout and operating pattern. In this report, the methodology adopted has been demonstrated as valid, but the actual engineering and physical PCC technology retrofit impacts on the existing LYA Unit 1 system have not been fully explored or analysed. These aspects are recommended for further investigations if a business case can be justified. Those potential impacts may include:
1. For the design Cases 2, 3, and 5 that include coal drying, addition of the flue gas cooler will increase the pressure drop in the flue gas system. The flue gas flow rate to the stack and the flue gas temperature will be reduced, as compared to the Base Case. The net impact of these changes on the existing ID fan and stack operation were not taken into account in this assessment and would need to be explored.
2. In the Case 4 configuration, flue gas coolers are utilized to generate low pressure steam to supplement steam extraction for the PCC plant. Addition of the flue gas cooler will increase pressure drop in the flue gas system. The flue gas temperature and volumetric flow rate to the stack (but not the mass flow rate as in cases with coal drying) will be reduced as compared to the Base Case and its impact needs to be assessed.
3. In all of the design cases, flue gas temperature entering the stack will be lower as compared to the Base Case. More so in the cases that employ flue gas cooling for coal drying or LP steam generation. This should affect stack system draft and dispersion. The existing stack liner material adequacy to the new operating conditions should also be investigated.
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6 RESULTS
6.1 Power Generation Outputs
The Power Generation Output and Auxiliary Load results from the modelled cases are shown in the table below:-
Table 6 .1 - Modelling Cases Power Generation Outputs and Auxiliary Loads
SYSTEM CONFIGURATION Base Case 1 Case 2 Case 3 Case 4 Case 5
Base Plant X X X X X X
PCC Plant X X X X X
Coal Drying X X X
Plant Optimization X X X
Air Cooled (PCC Plant Only) X POWER GENERATION kW kW kW kW kW kW SUMMARY
Main Steam Turbine Generation 568,960 530,810 527,700 528,840 549,390 528,840
Expander Generation 5,320 3,130 5,320
Total Gross Power Generation 568,960 530,810 527,700 534,160 552,520 534,160
Net Power Generation 521,380 446,460 445,840 452,380 468,270 452,480
Net Power Output Reduction - 74,920 75,540 69,000 53,110 68,900
Gross Plant Efficiency, % 31.46% 29.35% 30.74% 31.12% 30.53% 31.12%
Net Plant Efficiency, % 28.82% 24.68% 25.97% 26.36% 25.88% 26.36% AUXILIARY LOAD POWER kW kW kW kW kW kW SUMMARY
Base Plant Auxiliary Load 47,580 47,450 44,350 44,270 47,350 44,170
PCC Plant Auxiliary Load - 36,900 34,500 34,500 * 36,900 * 34,500
Coal Drying Plant Auxiliary Load - - 3,010 3,010 - 3,010
Total Plant Auxiliary Load Power 47,580 84,350 81,860 81,780 * 84,250 * 81,680
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CO2 CAPTURE SUMMARY Base Case 1 Case 2 Case 3 Case 4 Case 5
CO2 Captured, (tpd) - 5,000 5,000 5,000 5,000 5,000
CO2 Produced, (tpd) 14,831 14,831 14,081 14,081 14,854 14,081
CO2 Emitted, (tpd) 14,831 9,831 9,081 9,081 9,854 9,081
Gross Specific Emission, 1.086 0.772 0.717 0.708 0.743 0.708 (kg/kWh)
Net Specific Emission, (kg/kWh) 1.185 0.917 0.849 0.836 0.877 0.836
Electricity Output Penalty, - 419.89 274.70 233.60 284.36 233.60 (kWh/t CO2 )
Note: (*) The actual PCC Plant Auxiliary Load and hence the Total Plant Auxiliary Load for Case 4 and Case 5 will be either equal or less than the figures shown in table above. For the purpose of this study, a detailed assessment of the PCC auxiliary load has not been carried out.
Source: WorleyParsons
Figure 6 .1 - Power Generation Outputs & Aux Loads
Source: WorleyParsons
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Figure 6 .2 - Generation Specific Emissions
Source: WorleyParsons
6.2 Electricity Output Penalty
Results of the calculated Electricity Output Penalty are shown in Table 6 .1 and plotted in Figure 6 .3.
Figure 6 .3 - Electricity Output Penalty
Source: WorleyParsons
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6.3 Retrofit PCC Plant Cooling Water Requirement
The existing LYA power station has a wet recirculating water system utilising natural draught cooling towers.
For the proposed 5000 tpd retrofit PCC plant the additional cooling water requirement is shown in the table below.
It should be noted that this is only a high level model estimate. More detailed modelling would have to be performed to determine actual overall water requirements in any proposed site and case specific retrofit PCC plant feasibility study.
Table 6 .2 - Modelling Cases Cooling Water Requirement
Parameter Units Case 1 Case 2 Case 3 Case 4 Case 5
Cooling Water Air ML/yr 279,383 189,216 ≤189,216 <279,383 Requirement (*) Cooling
Cooling Water Air litres/MWh 74,412 50,467 ≤ 49,737 < 70,946 Requirement (*) Cooling
(*) Cooling Water Inlet Temperature is 40°C and Outlet Temperature is 50- 51°C Source: MHI / WorleyParsons For the dry air cooling (Case 5), cooling water is assumed to be only required at initial filling of the closed cooling loop and therefore not considered for comparisons with the other cases.
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Figure 6 .4 - Retrofit PCC Cooling Water Requirement
Source: WorleyParsons
According to a CCS Water Demand7 study undertaken by the U.S. Department of Energy’s National Energy Technology Laboratory (NETL), shown in Figure 6.5, the water requirements for subcritical PC plants with carbon capture will most likely to increase by nearly twice the amount compared to plants without carbon capture. However it is important to acknowledge that the NETL study data is based on a NETL Baseline study where 90% CO2 is captured and the net power generation is constant, i.e., representing cases with PCC which had a much larger gross output. The NETL Baseline study did not consider heat integration between CO2 compression and condensate heating. Or for that matter, the flue gas cooling for coal drying or steam generation were also not considered in the NETL Baseline study but which is undertaken in this study. Therefore, in this study, only a high level review of the PCC plant’s cooling water requirements was undertaken without any comparisons made to the NETL Baseline study.
7 J.P. Ciferno, U.S. Department of Energy, National Energy Technology Laboratory; R.K. Munson and J.T. Murphy, Leonardo Technologies Inc.; and B.S. LaSh; “Determining Carbon Capture and Sequestration’s Water Demands” March 2010
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Figure 6 .5 – NETL Water Demand Graph
Source: US DOE/NETL
6.4 Consideration of Peer Reviewer’s Notes on PCC Capture Integration a) The Independent Peer Reviewer’s Notes8, (Part A; Clause a.), states that for retrofits, it would
appear that the penalty per tonne of CO2 emissions avoided is independent of the turbine (inlet) steam conditions.
However, it should be noted that in this study the penalty per tonne of CO2 avoided is not
evaluated, since this parameter focuses on CO2 emissions calculated relative to the replacement
power of a plant without capture. Instead this study is focused on the penalty per tonne of CO2 captured.
For this study, the steam used for solvent regeneration is extracted from the crossover pipe between the intermediate pressure turbine and low pressure turbine. The modelled Base Case and Cases (1 to 5) main steam conditions have been kept constant and thus the HP turbine inlet conditions is the same for all cases. However a very slight difference in reheat steam flow condition is encountered at the intermediate turbine inlet. A slight difference in LP turbine inlet conditions (flow and pressure) is also encountered for Cases 1, 2, 3 and 5. Case 4 has a notable LP steam flow and pressure difference compared to the other Cases. The modelled cases’ heat and mass balance diagrams are in Appendix 2.
8 Independent Peer Reviewer’s “Notes on effective thermodynamic post-combustion capture integration and sensitivity analyses of the thermodynamic model developed for the PCC retrofit”
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From the above paragraphs and results reviewed in Sections 6.1 , the penalty (EOP) per tonne of
CO2 captured therefore seems to be independent of the turbine (HP) inlet conditions. b) The Independent Peer Reviewer’s Notes8, (Part A; Clauses b and c.), states that temperature of steam extracted for solvent regeneration should be as close as possible to the solvent regeneration temperature; solvent regeneration temperature optimized to minimise total overall electricity loss; and produce as much electricity as possible.
It should be noted that this study evaluates a single operating mode at 100% steam throttle flow rate. The pressure in LP crossover may not be sufficient for solvent regeneration during the part load operation. Optimization of steam extracted for solvent regeneration for a specific plant requires consideration of all typical operating modes of the plant.
In this study the steam extracted for solvent regeneration is assumed to be optimized by the PCC technology IP proprietor at a temperature (and corresponding pressure) as close as possible to the required solvent regeneration temperature. The temperature and pressure in the study, where only one type of solvent is involved, is held constant throughout all Cases. c) The Independent Peer Reviewer’s Notes 8, (Part A; Clause d.), states that any waste heat from
CO2 capture/compression is to be used in the steam cycle.
The study only evaluated what waste heat was perceived to be reasonably technically feasible for use in the steam cycle, without any economic evaluation. As an example, additional waste heat may be available for coal drying, but will require economic evaluation to properly assess the net benefit. d) The design for the whole life of the PCC plant anticipating use of the latest solvent developments can be accommodated into the models in accordance with the Independent Peer Reviewer’s Notes (Part A; Clause e.), but has not been pursued in the course of this study. e) In the Independent Peer Reviewer’s Notes (Part A; Clause f.), where the flexibility of post- combustion capture (enabling capture operation at low profit periods and/or as necessary to accelerate ramp rate during transient operation) could be exploited would be suitable as separate further study.
The PCC retrofit configuration considered in this report is based on processing a slip stream of the boiler flue gas. The balance of the flue gas is routed directly to the stack, bypassing the PCC system. Such PCC retrofit configuration should not have an impact on power unit operating flexibility.
The Electricity Output Penalty (EOP) results from this study (pulverised brown coal plant) are between
234 to 420 kWhe/tCO2 compared to the Independent Peer Reviewer’s Notes where for state-of-the-art solvent and state-of-the-art energy integration, the electricity output penalty (EOP) for PCC would be of the order of 250- 300 kWhe/tCO2 for pulverised coal power plants according to published literature.
For cases with PCC alone (Cases 1 and 4), the EOP of PCC alone without optimisation (Case 1) is outside the range of published literature, while with optimisation (Case 4) the EOP is positioned well within the range.
For cases with coal drying and PCC (Cases 2, 3 and 5) the EOP are all within the range of published literature and lower compared to Case 4 due to the further improvements achieved in the efficiency of the base power plant.
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7 APPLICATION OF THE MODELLING METHODOLOGY 7.1 Adaptability to a Generic Coal Fired Power Plant
From the discussions of the results in Section 6.4 , above we are able to the confirm that the models (GateCycleTM’s power station steam cycle, Coal drying process and PCC process) built will be able to be adapted for use on a generic subcritical coal fired power plant that is to be retrofitted with a post combustion carbon capture plant. The proposed methodology can be universally adopted for the independent valuation of CCS-project performance impacts. Whilst the specific outcomes of each step will differ, the general steps to be taken are broadly similar. 7.2 Other Plausible Model Cases
This study has only included 5 model cases based on one specific PCC process technology, where a specific solvent is utilised for carbon capture.
The same methodology would apply in evaluating other cases with different solvent types employed in post combustion capture. This is on the basis of experience gained from recent confidential WorleyParsons study projects delivered to various customers.
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8 CONCLUSIONS
The purpose of this study was to address the following main critical aspects for the development of PCC-projects as retrofits to existing plants:
• The model will provide an independent validation of impacts on plant performance and inputs for retrofit PCC projects. It documents a methodology for power station owners to evaluate the risks and revenue impacts for their plant operation.
• The independent validation of the plant performance can contribute to a reduction of the currently required risk premiums to finance the execution of a large scale PCC-projects as it identifies a methodology to independently validate the performance of first-of-a-kind retrofits to a coal power plant.
The methodology adopted in this study achieves the project goal of independently validating the impact on an existing power plant’s performance of the retrofit of a PCC-plant into that power plant. The results from this study are in line with expectations of both the technology vendor and the power station owner.
Regarding the accuracy of a carbon capture technology developer’s (IP) claim about their solvent regeneration energy, it is not possible to verify this unless both the physical and chemical properties of the solvent are known. Solvent physical properties are required to accurately simulate performance of a chemical absorption system whilst the chemical properties determine the energy required for regeneration. This information for public disclosure is only available for MEA (mono ethanol amine) without additives. It is therefore important to minimize the technology vendor’s “black box” as much as possible from the remaining plant to allow a high level of transparency between specific technology (solvent) driven performance relative to intelligent process integration of heat and mass flows on overall plant performance whilst ensuring the confidentiality of the technology vendor’s intellectual property. This allows the successful benchmarking of individual process components against theoretical achievable limits from a chemical and thermodynamic point of view.
The selection of suitable software tools is critical to achieving the project goals, since there is no software package currently available that is able to integrate all required technology components. As a consequence off-line integration forms a large and important part of the process to integrate the individual technology elements that is required to evaluate an overall plant performance impact. The tools chosen are flexible enough to not only be used for the defined cases for a PCC retrofit plant evaluated in this study but can also be applied to green field sites and other fossil fuelled technologies.
The selected cases evaluated in this study are targeted to identify and compare sensitivities of energy penalties of different technical solutions with a specific and pre-selected PCC-technology, and several approaches to reduce the energy penalty associated with the PCC retrofit have been assessed in the course of this work. The thermodynamic modelling methodology employed in the study enabled exploration of technical merits of each approach, which are as follows:
1) Case 1 design that does not include either heat integration with CO2 compression, or low temperature heat utilization for coal drying. As a result, Case 1 performance, as compared to other
retrofit cases, is estimated to have the lowest net efficiency of 24.68% and the highest CO2
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emissions intensity of 0.917 kg CO2 per kWh net. The energy penalty EOP for Case 1 is the highest amongst the cases considered.
2) In Case 2, low temperature flue gas heat is utilized for coal drying, which results in an approximately 1.3% improvement in the net unit efficiency (as compared to Case 1) to 25.97%.
CO2 emissions intensity in Case 2 is about 8% lower as compared to Case 1. However, reduction in unit net output in Case 2 is 0.6 MWe higher as compared to Case 1 (Case 1 EOP of 419.89
kWh/t CO2 vs. 274.7 kWh/t CO2 in Case 2). In Case 2, as a result of firing coal with lower moisture content, heat flux in the boiler furnace is estimated to increase with corresponding reduction of the heat transfer in the boiler back pass. This reduces water flow rate to the superheat and reheat de- superheaters, increases the feed water flow into the boiler and results in a corresponding increase in the steam extraction from the HP and Intermediate Pressure sections of the steam turbine. As a consequence of the above, the steam gross generation by the steam turbine decreases, but the steam cycle efficiency increases due to reduction of the steam condenser duty.
3) In the Case 3 design, coal drying is supplemented by steam cycle heat recovery from the CO2 compression system. In addition, a steam expander is employed to reduce steam pressure for the PCC plant. These measures resulted in the highest unit net efficiency of 26.36% (1.68% higher than in Case 1), and the lowest efficiency penalty of 2.46% as compared to the Base Case plant.
Accordingly, the CO2 emissions intensity of 0.836 kg CO2 / kWh net is the lowest amongst all the study cases. The reduction in unit net output of about 69 MW is almost 6 MW lower as compared
to Case 1 (Case 1 EOP of 419.89 kWh/t CO2 vs. 233.6 kWh/t CO2 in Case 3).
4) In the Case 4 design, low temperature flue gas heat is utilized to generate low pressure steam for the PCC plant to supplement steam extraction from the steam turbine. The flue gas LP steam generator in Case 4 is configured to extract almost the same amount of heat energy from the boiler flue gas as the flue gas coolers in Cases 2 and 3. The flue gas LP steam generator produces 28 kg/s of low pressure steam, which represents about 42% of total PCC plant steam demand in Case 4. The notable benefit of this approach is the lowest among all the cases reduction in net unit net power output of 53.1 MW, 21.8 MW lower as compared to Case 1 (Case 1 EOP of 419.89 kWh/ t
CO2 vs. 284.36 kWh/t CO2 in Case 4). Unit net efficiency of 25.88% in Case 4, while 1.2% higher than in Case 1, is somewhat lower as compared to Case 3 that employs coal drying with plant optimisation.
5) Case 5 performance is similar to Case 3. No PCC plant performance deterioration is expected at the specified ambient temperature, when air cooled heat exchangers are utilized instead of cooling towers. However, there is a likelihood of poorer PCC plant performance at higher ambient temperatures, and additional analysis for the site's maximum ambient temperature is recommended. It is noted that the performance is very similar between Case 3 & 5 due to the low dry bulb temperature of 13.4°C at which all design cases are evaluated. An obvious advantage for case 5 is that there will be a much reduced cooling water requirement.
Cases 3 and 5 (with coal drying, PCC and optimisation) show the electricity output penalty for carbon capture is the lowest of all the cases. However, these have the second highest net power plant output of all the cases.
Case 4 (with PCC and optimisation without coal drying) has the highest net power plant output. It has a higher electricity output penalty than Case 3 and 5.
Cases 3 and 5 have a net plant efficiency of almost 0.5 percentage points higher than Case 4.
Page 61 GLOBAL CCS INSTITUTE POST COMBUSTION CARBON CAPTURE THERMODYNAMIC MODEL - LOY YANG POWER PLANT
Cases 3 and 5 also have the lowest CO2 emissions intensity.
These findings suggest that an additional cost benefit analysis needs to be undertaken to establish, which design approach is most beneficial and/or of net advantage in reducing the overall cost of CO2 capture in subcritical coal-fired power plants firing high moisture coals.
Page 62 GLOBAL CCS INSTITUTE POST COMBUSTION CARBON CAPTURE THERMODYNAMIC MODEL - LOY YANG POWER PLANT
9 RECOMMENDATIONS
1. The specifics of the methodology described in this report were developed in relation to retro-fit of PCC to a particular power plant. This methodology can, in general, be applied for such projects on other plants. However, differences in existing plant design, proposed retro-fit technology and stakeholder composition, for example, will result in the need to adjust this methodology for use at other plants. Therefore the key recommendation arising from this study is that proponents of PCC retro-fit projects should study in detail the methodology described in this report, identify differences between the PCC scheme described in this report and their proposed PCC scheme, and modify this methodology as necessary in order to develop a customised methodology for application on their plant. By adoption of this approach the methodology developed in this study can be regarded as a template that can be used by other PCC proponents for customisation so their specific requirements are best addressed.
2. It is recommended that an independent evaluation be included at every critical stage of a PCC project, in order to adequately capture and reflect the engineering definition or changes of technology, as the project moves through successive assessments to FID. This will reduce the risk profile of the project proponents before major funding is committed.
3. This evaluation concludes that the thermodynamic modelling and integration of a PCC plant into an existing or new fossil fuel fired power station can be performed with commercially available software. However, it should be noted that this independent (thermodynamic modelling) evaluation is only one part of a range of site specific studies or investigations that need to be performed in an actual PCC plant deployment project. It is recommended that site specific studies or investigations be undertaken in conjunction with the methodology outlined in this report. These may include, but not be limited to, the following:
• Range of Ambient Conditions
• Power station operating regime
• Availability of water source for PCC plant
• Availability of land for PCC plant
• Water Requirements for PCC plant
• Total as opposed to partial cooling of the flue gas stream for additional heat recovery
• Economic analysis of the design cases in this study
• Impacts of the PCC retrofit on the existing plant systems and operability
Page 63 GLOBAL CCS INSTITUTE POST COMBUSTION CARBON CAPTURE THERMODYNAMIC MODEL - LOY YANG POWER PLANT
10 REFERENCES
• WorleyParsons, 29th July-2010, ‘DryFiningTM, Coal Drying Prefeasibility Study Phase 1a Report, Rev 0’, WorleyParsons, Melbourne.
• Sinclair Knight Merz, 29th September 2009, ‘Power Enhancement Project, Post Upgrade Report Units1, 3 and 4, Final’, Sinclair Knight Merz, Melboune.
• HRL Technology Pty Ltd, August 2007, ‘Loy Yang A Power Station - Unit 3 Net Unit Heat Rate Tests Pre And Post-Upgrades Conducted 22nd March and 6th June 2007 Report No: Hlc/2007/111’, HRL Technology Pty Ltd, Melbourne.
• WorleyParsons, 20th January 2012, ‘Loy Yang Large Scale Demonstration PCC Plant Basis of Design, Rev 2’, WorleyParsons, Melbourne.
• HRL Technology Pty Ltd, August 2011,’Emissions Sampling On Loy Yang A Unit 4, Flue 1 and 2, 27 - 30 June 2011 (High Load) 19 – 22 July 2011 (Low Load); Report No: HLC/2011/244’, HRL Technology Pty Ltd, Melbourne.
• WorleyParsons, 19th December 2011, ’Loy Yang Large Scale Demonstration PCC Plant - Efficiency Offset Study’, WorleyParsons, Melbourne.
• Lucquiaud,M, Gibbins, J, March 2011, ‘On the integration of CO2 capture with coal-fired power plants: A methodology to assess and optimize solvent-based post-combustion capture systems’, Chemical Engineering Research and Design, The Institution of Chemical Engineers, (doi:10.1016/j.cherd.2011.03.003), Elsevier B.V.
• Lucquiaud, M, Gibbins, J, November 2010, ‘Effective retrofitting of post-combustion CO2 capture
to coal-fired power plants and insensitivity of CO2 abatement costs to base plant efficiency’, International Journal of Greenhouse Gas Control, (doi:10.1016/j.ijggc.2010.09.003), Elsevier B.V.
• Ciferno, JP, March 2010, ‘Determining Carbon Capture and Sequestration’s Water Demands’, U.S. Department of Energy, National Energy Technology Laboratory; R.K. Munson and J.T. Murphy, Leonardo Technologies Inc.; and B.S. LaSh, USA.
• Independent Peer Reviewer, ‘Notes on effective thermodynamic post-combustion capture integration and sensitivity analyses of the thermodynamic model developed for the PCC retrofit’, Peer Reviewer, Melbourne.
Page 64 GLOBAL CCS INSTITUTE POST COMBUSTION CARBON CAPTURE THERMODYNAMIC MODEL - LOY YANG POWER PLANT
11 ABBREVIATIONS abs Absolute AQCS Air Quality Control Systems BIP Background Intellectual Property BOD Basis of Design CCS Carbon Capture and Storage CCPI Clean Coal Power Initiative
CO2 Carbon Dioxide CPRS Carbon Pollution Reduction Scheme CSIRO Commonwealth Scientific and Industrial Research Organisation DCFS Double Contact Flow Scrubber DOE U.S. Department of Energy EIA Energy Information Agency EOP Electricity Output Penalty EPA Environmental Protection Authority Victoria EPCM Engineering, Procurement and Construction Management EPRI Electric Power Research Institute ESP Electrostatic Precipitator ETIS Energy Technology Innovation Strategy FBD Fluidized Bed Dryer FEED Front End Engineering Design FGC Flue Gas Coolers FID Financial Investment Decision GCCSI Global Carbon Capture and Storage Institute GRE Great River Energy HHV Higher Heating Value HMB Heat and Mass Balance HP High Pressure ID Induced draft IP Intellectual Property kPa kilo Pascal LP Low Pressure LYA Loy Yang A Power Station
Page 65 GLOBAL CCS INSTITUTE POST COMBUSTION CARBON CAPTURE THERMODYNAMIC MODEL - LOY YANG POWER PLANT
LYP Loy Yang Power MAL Mitsubishi Australia Limited (100% subsidiary of Mitsubishi Corporation) MC Mitsubishi Corporation MHI Mitsubishi Heavy Industries MP Medium / Intermediate Pressure MPa Mega Pascal MSV Main Steam Valve MW Mega Watts NETL US DOE’s National Energy Technology Laboratory OEM Original Equipment Manufacturer OPEX Operational Expenditure PCC Post Combustion Capture R&D Research and Development RITE Research Institute of Innovative Technology for the Earth RSV Reheat Steam Valve ST Steam turbine tpd Metric tonnes per day UBC Unburned carbon
Page 66 GLOBAL CCS INSTITUTE POST COMBUSTION CARBON CAPTURE THERMODYNAMIC MODEL - LOY YANG POWER PLANT
Appendix 1 Project Proponents
Page 67 GLOBAL CCS INSTITUTE POST COMBUSTION CARBON CAPTURE THERMODYNAMIC MODEL - LOY YANG POWER PLANT
Loy Yang Power www.loyyangpower.com.au
Loy Yang Power owns and operates the Loy Yang A Power Station and the adjacent Loy Yang coal mine. Loy Yang Power is Victoria’s largest electricity generation facility supplying approximately one third of the state’s electricity requirements. From a National Electricity Market perspective it supplies the equivalent of 8% of total generation for Victoria, New South Wales, Queensland, South Australia, Tasmania and the Australian Capital Territory.
Loy Yang Power is owned by the Great Energy Alliance Corporation (GEAC). GEAC consists of the following shareholders – AGL (32.5%), Tokyo Electric Power Company (32.5%), RATCH-Australia Corporation Ltd (14%), Motor Trades Association of Australia (MTAA) Superannuation Fund (12.8%), Westscheme (5.7%) and Statewide Super (2.5%).
Loy Yang A Power Station has a generating capacity of 2,200MW and is fuelled from the Loy Yang Power mine, which is the largest open cut brown coal mine in Australia, with an annual output of approximately 30 million tonnes of coal. The Loy Yang Power mine also supplies brown coal resources to the adjacent Loy Yang B Power Station.
Loy Yang A Power Station is located within the heart of the Latrobe Valley, 165 kilometres east of Melbourne. It commenced operations as a corporatised entity in February 1995 following the disaggregation of the State Electricity Commission of Victoria and its generating arm, Generation Victoria. Loy Yang Power was privatised in May 1997 as part of the Victorian Government's privatisation strategy.
Loy Yang Power has been a lead participant and active collaborator in the brown coal research and development space for many years, including participation in:
• Victorian Government’s R&D Advisory Committee;
• Cooperative Research Centre for Clean Power from Lignite;
• Mechanical Thermal Expression Coal Dewatering demonstration facility;
• Victorian Government / LV Generator strategic efficiency improvements & CO2 abatement options studies undertaken by SKM;
• ETIS research and development projects viz, Advanced Materials, Phased Array, Small gasification, Oxyfuel, etc;
• Bankable feasibility studies for a new Power Station and re-powering of existing station with improved emissions performance;
• Latrobe Valley Post Combustion Capture project with CSIRO, International Power-Hazelwood and CO2CRC.
Page 68 GLOBAL CCS INSTITUTE POST COMBUSTION CARBON CAPTURE THERMODYNAMIC MODEL - LOY YANG POWER PLANT
Energy Australia (formerly TRUenergy) www.energyaustralia.com.au
Energy Australia (formerly TRUenergy) is one of Australia’s largest integrated energy companies with a goal to be Australia’s best customer-focused energy management group.
With the acquisition of Energy Australia, the Delta West gentrader rights and NSW generation development sites from the NSW Government in early 2011, Energy Australia has a portfolio of approximately $7 billion of generation and retail assets and employs around 1,600 employees and contractors through major operational partnerships across South East Australia. Energy Australia provides gas and electricity to approximately 2.75 million household and business accounts in New South Wales, Victoria, South Australia, Queensland and the ACT.
As an investor, generator and retailer in Australian energy, Energy Australia recognises the importance of building a sustainable business. Energy Australia has committed to reducing emissions from the portfolio through Energy Australia’s climate change strategy announced in July 2007. Energy Australia is committed to immediately capping its carbon intensity with reductions commencing by 2010 with an ultimate target to reduce emissions by 60% by 2050 (on a 1990 baseline). Energy Australia’s greatest challenge lies in reducing the carbon emissions footprint of Yallourn and is actively assessing options to achieve this, including working with Loy Yang Power on this project.
Energy Australia is a wholly-owned subsidiary of the CLP Group, which is publicly listed in Hong Kong. CLP is one of the largest investor-owned power businesses in the Asia Pacific region and operates in Hong Kong, Australia, India, China, Taiwan and Thailand and has a market capitalization of approximately A$21 billion.
Mitsubishi Heavy Industries www.mhi.co.jp/en/
MHI is a leading global heavy machinery manufacturing and engineering company with a wide range of products including fossil & nuclear power systems, chemical plants, renewable energy technology, environmental control systems, aerospace systems, economical aircraft ocean going ships and other heavy industrial equipment.
MHI is a ‘Global Fortune 500’ company with an annual sales revenue of $35 billion USD (2010 Financial Year) and a global, consolidated, workforce of around 68,000 employees with six (6) major R&D Centres and manufacturing workshops distributed throughout Japan and the world.
Within MHI, the Plant and Transportation Systems Engineering & Construction Centre Environmental & Chemical Plant Division, located in Yokohama (MCEC) is the organization responsible to supply engineering, procurement and construction of process plants such as petrochemical, fertilizer, methanol and process technologies for environmental control systems.
Among the extensive range of environmental control systems, high efficiency Flue Gas
Desulphurization (FGD) and post combustion CO2 capture
(PCC) technology is considered one of the most important product categories applicable to power generation in the future due to GHG and carbon dioxide abatement legislation which is expected to be
Page 69 GLOBAL CCS INSTITUTE POST COMBUSTION CARBON CAPTURE THERMODYNAMIC MODEL - LOY YANG POWER PLANT introduced in many countries over the coming years. In particular MHI views the Loy Yang Power PCC demonstration plant as a strategically important project to demonstrate MHI’s proprietary post combustion CO2 capture process on brown coal flue gas and to confirm the respective impacts of brown coal flue gas impurities, at large scale, on the CO2 capture process leading to future commercial CO2 capture solutions for the power generation industry.
WorleyParsons www.worleyparsons.com
WorleyParsons is one of the world's largest engineering and project delivery companies and has serviced the global resource, energy and infrastructure markets for over 30 years. With 40,800 personnel in 163 offices in 41 countries, WorleyParsons have the technical expertise, project delivery capability, global reach and depth of resources to provide a comprehensive range of solutions to their customers.
WorleyParsons has extensive experience in the design and construction of CO2 capture, compression and pipeline transport, and the range of issues for deep geological storage. WorleyParsons has provided carbon capture plant design, and support contractor services for over 27 years to our energy customers and national research organizations including the U.S. Department of Energy and the Electric Power Research Institute. WorleyParsons also has substantial qualifications and experience in materials handling, infrastructure, environmental compliance, permitting, and operations which provides our clients a full scope capability to assure project success from concept through commissioning.
Mitsubishi Corporation (Mitsubishi Australia Limited) www.mitsubishicorp.com/jp/en/network/ao/australia.html
Mitsubishi Corporation (MC - of which MAL is a wholly owned subsidiary) is Japan's largest general trading company (sogo shosha) with over 200 bases of operations in approximately 80 countries worldwide. Together with its over 500 group companies, MC employs a multinational workforce of approximately 60,000 people. MC has long been engaged in business with customers around the world in virtually every industry, including energy, metals, machinery, chemicals, food and general merchandise.
MC remains committed to investment, promotion and facilitation of environmental projects that embrace sunrise technologies such as Integrated Gasified-coal Combined Cycle (IGCC) and Post
Combustion CO2 Capture (PCC). Through these activities MC seeks to contribute through the role of a key financial, facilitation and proponent link between cross the value chain.
Although MC's activities encompass everything from trading to business investment, the essence of MC can best be described as focusing on the needs and seeds of customers and society, conceiving business models, and reliably providing functions and services to propel these businesses forward. When MC invests in a business, we share risk with our partners and add value to the business by leveraging MC's organizational strength and global networks to procure necessary business resources.
Page 70 GLOBAL CCS INSTITUTE POST COMBUSTION CARBON CAPTURE THERMODYNAMIC MODEL - LOY YANG POWER PLANT
In addition, we provide optimal solutions for all stages of business - from development, procurement and production, to logistics and sales. Supporting the realization of these solutions, linking businesses and coordinating customer affiliations are all important MC functions.
Furthermore, MC endeavours to anticipates trends in the market and society and takes initiative to develop new business such as Carbon Capture and Storage and low emissions power projects MC is one of the world's largest owners of Emissions Credits and a founding member of the Global CCS Institute, underlining MC's commitment to realising a low emissions world.
Qualifications and Experience
The project proponents have allocated experienced and well qualified personal to this project and are confident of achieving all program objectives. The Parties have been in discussion regarding the development of this project since 2008 and during this time have developed an efficient and professional working relationship.
Page 71 GLOBAL CCS INSTITUTE POST COMBUSTION CARBON CAPTURE THERMODYNAMIC MODEL - LOY YANG POWER PLANT
Appendix 2 Heat and Mass Balance Diagrams
Page 72
GLOBAL CCS INSTITUTE POST COMBUSTION CARBON CAPTURE THERMODYNAMIC MODEL - LOY YANG POWER PLANT
Appendix 3 Block Flow Diagrams
Page 73 Flue Gas Composition Value Gas Composition, mol% CO 2 11.3% H2O 22.4% N2 & Ar 62.1% SO 2 & SO 3 0.02% O2 4.1% Total 100% NOx, ppmv wet 144 Total flue gas from boiler, kg/s 960 Dust, g/m 3 (STP) 0.04 CO 2 Captured, t/d 0 CO 2 Captured, kg/d 0 CO 2 Captured, kg/s 0 CO 2 Capture eff (assumed) 0% Flue gas through PCC plant, kg/s 0 Percentage of the flue gas to the PCC plant 0% Percentage of the flue gas to the chimney 100%
To Consumers Power Station Sent Out Generation; 521 MW (Net)
To Atmosphere
LYP UNIT 1 Brown Coal Fired Power Existing Flue Gas Stack Air Plant 569 MW (Gross) ESP ID FAN Wet Coal; Moisture Content 60 wt %, 10.52 MJ/kg
Existing Power Station Plant
Pressure (abs) 99.6 kPa Temperature 183 °C Mass Flow Rate 960 kg/s Enthalpy - kJ/kg
Air Flue Gas Solids / Coal Power
DRAWN:Y. CHAN DATE: 26/06/2012
CHECKED:Y. LU DATE: 04/07/2012 GLOBAL CCS INSTITUTE 101010-00686 GCCSI - THERMODYNAMIC MODELLING ENG / PM:N. NIGRO DATE: 10/07/2012 BASE CASE - BASE PLANT LOY YANG POWER STATION BLOCK FLOW DIAGRAM DRAWING No. TITLE No. DATE DRAWN CHECKED APPROVED DESCRIPTION ENG CLIENT PROC ENG:- DATE: - SCALE DRAWING NUMBER REV REFERENCE DRAWINGS REVISIONS NTS 00686-PR-DBD-0001 A
H:\Jobs Oracle\101010-00686 - GGCSI Thermodynamic Modelling\10_Engineer\Block Flow Diagrams\00686-PR-DBD-0001 Rev A.xlsm WP SelectDraw v2.07 Flue Gas Composition Value Gas Composition, mol % CO 2 11.3% Pressure (abs) 99.6 kPa H2O 22.4% Temperature 183 °C N2 & Ar 62.1% Mass Flow rate 606 kg/s SO 2 & SO 3 0.02% Enthalpy - kJ/kg O2 4.1% Total 100% Nox, ppmv wet 144 Pressure (abs) * 100 kPa Total flue gas from boiler, kg/s 960 Temperature 48 °C 3 To Atmosphere Dust, g/m (STP) 0.04 Mass Flow rate 311 kg/s CO 2 Captured, t/d 5,000 Enthalpy - kJ/kg CO 2 Captured, kg/d 5,000,000 CO 2 Captured, kg/s 58 CO 2 Capture eff (assumed) 90% Existing Flue Gas Stack Flue gas through PCC plant, kg/s 354 Percentage of the flue gas to the PCC plant 36.9% Percentage of the flue gas to the chimney 63.1%
To Consumers Power Station Sent Out LYP UNIT 1 Brown Generation; 446 MW (Net) Coal Fired Power Air Auxilliary Power Supply to PCC Plant; 36.9 MW (Including CO 2 compressor ) Plant To Atmosphere 531 MW (Gross) Steam Supply; * °C, * bar(a)
Wet Coal; Condensate Return; * °C, * bar(a) Moist Treated Flue Gas Content 60 wt %, 10.52 MJ/kg
Post Combustion Carbon Capture Product CO 2 To CO Pipeline ESP ID FAN Plant (5000tpd) 2
Chemicals Waste Products Cooling Water 8859kg/s (Limestone, (Solids & Liquids) alkaline) Supply & Return To Waste Disposal Existing Power Station Plant Power Station Retrofits plus Services Water
Pressure (abs) 99.6 kPa Pressure (abs) * 98 kPa Pressure (abs) * 9,998 kPa Temperature 183 °C Temperature * 200 °C Temperature 45 °C Mass Flow Rate 960 kg/s Mass Flow rate * 433 kg/s Mass Flow rate 58 kg/s Enthalpy - kJ/kg Enthalpy - kJ/kg Enthalpy - kJ/kg
Air Steam Power Flue Gas Notes: 1) Thin lines represent existing equipment or systems. Solids / Coal / Water / Condensate Product CO 2 Wastes 2) Bold lines represent new equipment or systems. Chemicals 3) Figures with * are tecnology IP proprietor's model input values
DRAWN:Y. CHAN DATE: 07/08/2012
CHECKED:Y. LU DATE: 07/08/2012 GLOBAL CCS INSTITUTE 101010-00686 GCCSI - THERMODYNAMIC MODELLING ENG / PM:N. NIGRO DATE: 07/08/2012 CASE 1 - BASE with PCC PLANT LOY YANG POWER STATION BLOCK FLOW DIAGRAM DRAWING No. TITLE No. DATE DRAWN CHECKED APPROVED DESCRIPTION ENG CLIENT PROC ENG:- DATE: - SCALE DRAWING NUMBER REV REFERENCE DRAWINGS REVISIONS NTS 00686-PR-DBD-0002 A
H:\Jobs Oracle\101010-00686 - GGCSI Thermodynamic Modelling\10_Engineer\Block Flow Diagrams\00686-PR-DBD-0002 Rev A.xlsm WP SelectDraw v2.07 Flue Gas Calculation Value Gas Composition, mol % CO 2 11.7% Pressure (abs) 99.0 kPa H2O 19.9% Temperature 140 °C N2 & Ar 63.3% Mass Flow rate 545 kg/s SO 2 & SO 3 0.02% Enthalpy - kJ/kg O2 4.3% Others 0.8% Total 100% Pressure (abs) * 100 kPa Nox, ppm 144 Temperature 48 °C Total flue gas from boiler, kg/s 892.0 To Atmosphere Mass Flow rate * 268 kg/s 3 Dust, g/m (STP) 0.04 Enthalpy - kJ/kg CO 2 Captured, t/d 5,000 CO 2 Captured, kg/d 5,000,000 Existing Flue Gas Stack CO 2 Captured, kg/s 58 CO 2 Capture eff (assumed) 90% Flue gas through PCC plant, kg/s 347 Percentage of the flue gas to the PCC plant 38.9% Percentage of the flue gas to the chimney 61.1%
Power Station Sent Out To Consumers Generation; 446 MW(Net) Auxilliary Power Supply to PCC Plant; 34.5 MW (Including CO compressor ) LYA UNIT 1 Brown 2 Steam Supply; * °C, * bar(a) Coal Fired Power To Atmosphere Plant Condensate Return; * °C, * bar(a) Air 528 MW (Gross) Auxilliary Power Supply to Coal Drying Plant; 3 MW Treated Flue Gas
Post Combustion Carbon Capture Product CO 2 To CO Pipeline ESP ID FAN Coal Drying Plant Plant (5000tpd) 2
Dried Coal; Moisture Content 55 wt % , 11.83 MJ/kg Chemicals Waste Products Wet Coal; Moisture Content 60 wt %, 10.52 MJ/kg (Limestone, Cooling Water 6000kg/s (Solids & Liquids) alkaline) Supply & Return To Waste Disposal plus Services Water Existing Power Station Plant Power Station Retrofits
Pressure (abs) 99.6 kPa Pressure (abs) 99.0 kPa Pressure (abs) * 9,998 kPa Temperature 175 °C Temperature 70 °C Temperature 45 °C Mass Flow Rate 892.0 kg/s Mass Flow rate * 352 kg/s Mass Flow rate 58 kg/s Enthalpy - kJ/kg Enthalpy - kJ/kg Enthalpy - kJ/kg
Notes: Air Steam Power Flue Gas 1) Thin lines represent existing equipment or systems. 2) Bold lines represent new equipment or systems. Solids / Coal / Water / Condensate Product CO 2 Wastes 3) Figures with * are tecnology IP proprietor's model input values Chemicals
DRAWN:Y. CHAN DATE: 07/08/2012
CHECKED:Y. LU DATE: 07/08/2012 GLOBAL CCS INSTITUTE 101010-00686 GCCSI - THERMODYNAMIC MODELLING ENG / PM:N. NIGRO DATE: 07/08/2012 CASE 2 - BASE w COAL DRYING & PCC LOY YANG POWER STATION BLOCK FLOW DIAGRAM DRAWING No. TITLE No. DATE DRAWN CHECKED APPROVED DESCRIPTION ENG CLIENT PROC ENG:- DATE: - SCALE DRAWING NUMBER REV REFERENCE DRAWINGS REVISIONS NTS 00686-PR-DBD-0003 A
H:\Jobs Oracle\101010-00686 - GGCSI Thermodynamic Modelling\10_Engineer\Block Flow Diagrams\00686-PR-DBD-0003 Rev A.xlsm WP SelectDraw v2.07 Flue Gas Calculation Value Gas Composition, mol % CO 2 11.7% Pressure (abs) 99.0 kPa H2O 19.9% Temperature 140 °C N2 & Ar 63.3% Mass Flow rate 545 kg/s SO 2 & SO 3 0.02% Enthalpy - kJ/kg O2 4.3% Others 0.8% Total 100% Pressure (abs) * 100 kPa Nox, ppm 144 Temperature 48 °C Total flue gas from boiler, kg/s 892.00 To Atmosphere Mass Flow rate * 268 kg/s 3 Dust, g/m (STP) 0.04 Enthalpy - kJ/kg CO 2 Captured, t/d 5,000 CO 2 Captured, kg/d 5,000,000 Existing Flue Gas Stack CO 2 Captured, kg/s 58 CO 2 Capture eff (assumed) 90% Flue gas through PCC plant, kg/s 347 Percentage of the flue gas to the PCC plant 38.9% Percentage of the flue gas to the chimney 61.1%
To Consumers Power Station Sent Out LYA UNIT 1 Brown Generation; 452 MW (Net) Auxilliary Power Supply to PCC Plant; 34.5 MW (Including CO 2 compressor ) Coal Fired Power Steam Supply; * °C, * bar(a) Plant To Atmosphere Condensate Return; * °C, * bar(a) Air 534 MW (Gross)
Heat Recovery from CO 2 Auxilliary Power Supply to Coal Drying Plant; 3 MW Compression process Treated Flue Gas
Post Combustion Carbon Capture Product CO Plant (5000tpd) 2 ESP ID FAN Coal Drying Plant To CO 2 Pipeline with plant Optimisation
Dried Coal; Moisture Content 55 wt %, 11.83 MJ/kg Chemicals Waste Products Wet Coal; Moisture Content 60 wt %, 10.52 MJ/kg (Limestone, Cooling Water ≤ 6000kg/s (Solids & Liquids) alkaline) Supply & Return To Waste Disposal plus Services Water Existing Power Station Plant Power Station Retrofits
Pressure (abs) 99.6 kPa Pressure (abs) 99 kPa Pressure (abs) * 9,998 kPa Temperature 175 °C Temperature 70 °C Temperature 45 °C Mass Flow Rate 892 kg/s Mass Flow rate * 352 kg/s Mass Flow rate 58 kg/s Enthalpy - kJ/kg Enthalpy - kJ/kg Enthalpy - kJ/kg
Heat Notes: Air Steam Power Flue Gas 1) Thin lines represent existing equipment or systems. 2) Bold lines represent new equipment or systems. Solids / Coal / Water / Condensate Product CO 2 Wastes 3) Figures with * are tecnology IP proprietor's model input values Chemicals
DRAWN:Y. CHAN DATE: 07/08/2012
CHECKED:Y. LU DATE: 07/08/2012 GLOBAL CCS INSTITUTE 101010-00686 GCCSI - THERMODYNAMIC MODELLING ENG / PM:N. NIGRO DATE: 07/08/2012 CASE 3 - BASE w COAL DRYING & PCC (OPTM) LOY YANG POWER STATION BLOCK FLOW DIAGRAM DRAWING No. TITLE No. DATE DRAWN CHECKED APPROVED DESCRIPTION ENG CLIENT PROC ENG:- DATE: - SCALE DRAWING NUMBER REV REFERENCE DRAWINGS REVISIONS NTS 00686-PR-DBD-0004 A
H:\Jobs Oracle\101010-00686 - GGCSI Thermodynamic Modelling\10_Engineer\Block Flow Diagrams\00686-PR-DBD-0004 Rev A.xlsm WP SelectDraw v2.07 Flue Gas Composition Value Gas Composition, mol % CO 2 11.3% Pressure (abs) 99.6 kPa H2O 22.4% Temperature 140 °C N2 & Ar 62.1% Mass Flow rate 606 kg/s SO 2 0.02% Enthalpy - kJ/kg O2 4.1% Total 100% Nox, ppmv wet 144 Pressure (abs) * 100 kPa Total flue gas from boiler, kg/s 960 Temperature 48 °C To Atmosphere Dust, g/m 3 (STP) 0.04 Mass Flow rate 311 kg/s CO 2 Captured, t/d 5,000 Enthalpy - kJ/kg CO 2 Captured, kg/d 5,000,000 CO 2 Captured, kg/s 58 CO 2 Capture eff (assumed) 90% Existing Flue Gas Stack Flue gas through PCC plant, kg/s 354 Percentage of the flue gas to the PCC plant 36.9% Percentage of the flue gas to the chimney 63.1%
To Consumers Power Station Sent Out LYP UNIT 1 Brown Generation; 468 MW (Net) Coal Fired Power Air Auxilliary Power Supply to PCC Plant; < 36.9 MW (Including CO 2 compressor ) Plant To Atmosphere 553 MW (Gross) Steam Supply; * °C, * bar(a) Condensate Return; * °C, * bar(a) Wet Coal; Moist Treated Flue Gas Content 60 wt %, Heat Recovery from CO 2 Compression process 10.52 MJ/kg
Post Combustion Carbon Capture Product CO Flue gas Plant (5000tpd) 2 ESP ID FAN LP Steam To CO 2 Pipeline Generator with plant Optimisation
Chemicals Waste Products Cooling Water < 8859kg/s (Limestone, (Solids & Liquids) alkaline) Supply & Return To Waste Disposal Existing Power Station Plant Power Station Retrofits plus Services Water
Pressure (abs) 99.6 kPa Pressure (abs) * 98 kPa Pressure (abs) * 9,998 kPa Temperature 183 °C Temperature 70 °C Temperature 45 °C Mass Flow Rate 960 kg/s Mass Flow rate * 433 kg/s Mass Flow rate 58 kg/s Enthalpy - kJ/kg Enthalpy - kJ/kg Enthalpy - kJ/kg
Heat Notes: 1) Thin lines represent existing equipment or systems. Air Steam Power Flue Gas 2) Bold lines represent new equipment or systems. 3) Figures with * are tecnology IP proprietor's model input values Solids / Coal / Water / Condensate Product CO 2 Wastes Chemicals
DRAWN:Y. CHAN DATE: 07/08/2012
CHECKED:Y. LU DATE: 07/08/2012 GLOBAL CCS INSTITUTE 101010-00686 GCCSI - THERMODYNAMIC MODELLING ENG / PM:N. NIGRO DATE: 07/08/2012 CASE 4 - BASE with PCC PLANT (OPTM) LOY YANG POWER STATION BLOCK FLOW DIAGRAM DRAWING No. TITLE No. DATE DRAWN CHECKED APPROVED DESCRIPTION ENG CLIENT PROC ENG:- DATE: - SCALE DRAWING NUMBER REV REFERENCE DRAWINGS REVISIONS NTS 00686-PR-DBD-0005 A
H:\Jobs Oracle\101010-00686 - GGCSI Thermodynamic Modelling\10_Engineer\Block Flow Diagrams\00686-PR-DBD-0005 Rev A.xlsm WP SelectDraw v2.07 Flue Gas Calculation Value Gas Composition, mol % CO 2 11.7% Pressure (abs) 99 kPa H2O 19.9% Temperature 140 °C N2 & Ar 63.3% Mass Flow rate 545 kg/s SO 2 & SO 3 0.02% Enthalpy - kJ/kg O2 4.3% Others 0.8% Total 100% Pressure (abs) * 100 kPa Nox, ppm 144 Temperature 48 °C Total flue gas from boiler, kg/s 892.00 To Atmosphere Mass Flow rate * 268 kg/s 3 Dust, g/m (STP) 0.04 Enthalpy - kJ/kg CO 2 Captured, t/d 5,000 CO 2 Captured, kg/d 5,000,000 Existing Flue Gas Stack CO 2 Captured, kg/s 58 CO 2 Capture eff (assumed) 90% Flue gas through PCC plant, kg/s 347 Percentage of the flue gas to the PCC plant 38.9% Percentage of the flue gas to the chimney 61.1%
Power Station Sent Out To Consumers Generation; 452 MW (Net) Auxilliary Power Supply to PCC Plant; 34.5MW (Including CO 2 compressor ) LYA UNIT 1 Brown Steam Supply; * °C, * bar(a) To Atmosphere Coal Fired Power Condensate Return; * °C, * bar(a) Air Plant 534 MW (Gross) Auxilliary Power Supply to Heat Recovery from CO 2 Coal Drying Plant; 3 MW Compression process Treated Flue Gas
Post Combustion Carbon Capture
Plant (5000tpd) Product CO 2 To CO Pipeline ESP ID FAN Coal Drying Plant with Air Cooling 2 and plant Optimisation
Dried Coal; Moisture Content 55 wt %, 11.83 MJ/kg Chemicals Waste Products Wet Coal; Moisture Content 60 wt %, 10.52 MJ/kg (Limestone, Cooling Water 0 kg/s (Solids & Liquids) alkaline) plus Services Water To Waste Disposal Existing Power Station Plant Power Station Retrofits
Pressure (abs) 99.6 kPa Pressure (abs) 99 kPa Pressure (abs) * 9,998 kPa Temperature 175 °C Temperature 70 °C Temperature 45 °C Mass Flow Rate 892 kg/s Mass Flow rate * 352 kg/s Mass Flow rate 58 kg/s Enthalpy - kJ/kg Enthalpy - kJ/kg Enthalpy - kJ/kg
Notes: Heat 1) Thin lines represent existing equipment or systems. 2) Bold lines represent new equipment or systems. Air Steam Power Flue Gas 3) Figures with * are tecnology IP proprietor's model input values 4) There is a likelihood of poorer PCC plant performance at higher Solids / Coal / Water / Condensate Product CO 2 Wastes ambient temperatures. (Additional analysis for the site's Chemicals maximum ambient temperature is recommended)
DRAWN:Y. CHAN DATE: 07/08/2012
CHECKED:Y. LU DATE: 07/08/2012 GLOBAL CCS INSTITUTE 101010-00686 GCCSI - THERMODYNAMIC MODELLING ENG / PM:N. NIGRO DATE: 07/08/2012 CASE 5 - BASE w C DRY & PCC (AIR COOL - OPTM) LOY YANG POWER STATION BLOCK FLOW DIAGRAM DRAWING No. TITLE No. DATE DRAWN CHECKED APPROVED DESCRIPTION ENG CLIENT PROC ENG:- DATE: - SCALE DRAWING NUMBER REV REFERENCE DRAWINGS REVISIONS NTS 00686-PR-DBD-0006 A
H:\Jobs Oracle\101010-00686 - GGCSI Thermodynamic Modelling\10_Engineer\Block Flow Diagrams\00686-PR-DBD-0006 Rev A.xlsm WP SelectDraw v2.07 GLOBAL CCS INSTITUTE POST COMBUSTION CARBON CAPTURE THERMODYNAMIC MODEL - LOY YANG POWER PLANT
Appendix 4 Basis of Design
Page 74 GLOBAL CCS INSTITUTE POST COMBUSTION CARBON CAPTURE THERMODYNAMIC MODEL - LOY YANG POWER PLANT
BASIS OF DESIGN Flue Gas
The specification for flue gas assumed to be available for the 5000tpd PCC plant is provided in the following Appendix - Table A.
Appendix - Table A - Flue Gas Definition (100%) Design Case
Item Item Description Units Description / For Reference Value ＜Range＞
(a) Location Australia
(b) Flue Gas Sources Lignite fired
(c) Flow Rate Nm3/h Wet 1072000
(d) Pressure mBar (abs) 996 978 - 1009
(e) Temperature °C 182 170 - 200
(f) Composition
N2 + Ar vol% Wet 62 (balance) 50 - 69
CO2 vol% Wet 11 9.5 - 13
O2 vol% Wet 5 3.5 - 7
H2O vol% Wet 22 18 - 30
SOx ppmv Dry 197.4 151 - 213
SO2 ppmv Dry 196 150 - 210
SO3 ppmv Dry 1.4 1 - 3
NOx ppmv Dry 185 100 - 300
NO2 ppmv Dry N/A N/A
NH3 ppmv Dry TBA TBA
Dust g/m3 Dry 0.04 0 - 0.08
HCl ppmv Dry TBA TBA
HF ppmv Dry TBA TBA Source: MHI
Page 75 GLOBAL CCS INSTITUTE POST COMBUSTION CARBON CAPTURE THERMODYNAMIC MODEL - LOY YANG POWER PLANT
The flue gas specification used by MHI to design the 5000tpd plant equipment sizing is shown in the following Appendix - Table B.
Appendix - Table B - Flue Gas Definition - Equipment Sizing
Item Item Description Units Description/Value
(a) Location Australia
(b) Flue Gas Sources Lignite fired boiler
(c) Flow Rate Nm3/h Wet 1,309,900
(d) Pressure mBar (abs) 978
(e) Temperature °C 200
(f) Composition
N2 + Ar vol% Wet 54 (balance)
CO2 vol% Wet 9
O2 vol% Wet 7
H2O vol% Wet 30
SOx ppmv Dry 503
SO2 ppmv Dry 500
SO3 ppmv Dry 3
NOx ppmv Dry 300
NO2 ppmv Dry N/A
NH3 ppmv Dry TBA
Dust (*) g/m3 Dry (STP) 0.08
HCl ppmv Dry 124 (*)
HF ppmv Dry 1.26 (*)
(*) Measurement result max in HRL report (No. HLC/2011/244) “Emissions Sampling On Loy Yang A Unit 4, Flue 1 and 2; 27 - 30 June 2011 (High Load) 19 – 22 July 2011 (Low Load) “ Source: MHI Steam
The specification for steam supplied to the PCC plant is provided by MHI for the modelling process. Cooling Water
The specification for cooling water supplied to the PCC plant is provided in the following table Appendix - Table C.
Page 76 GLOBAL CCS INSTITUTE POST COMBUSTION CARBON CAPTURE THERMODYNAMIC MODEL - LOY YANG POWER PLANT
Appendix - Table C - PCC Plant Cooling Water Condition
Item Description Units Value
(a) Supply Pressure kPaG 900
(b) Supply Temperature (max) °C 40
(c) Return Pressure kPa To CW drain system
(d) Return Temperature (max) °C 50 - 51 Source: MHI Power
The specification for power required for the PCC plant is provided in the following table Appendix - Table D.
Appendix - Table D - PCC Plant Power Requirements
Item Description Units Value
(a) Motor more than 375 kW volts 6,600 (*)
phase 3
Hz 50
(b) Motor from 250 kW to 375 kW volts 6,600 or 415 (*)
phase 3
Hz 50
(c) Motor below 250 kW volts 415 (*)
phase 3
Hz 50
(*) To be confirmed by MHI Source: MHI Air (Instrument & Service)
Based on previous work at Loy Yang A there is insufficient existing air capacity at site and therefore it is assumed that the PCC plant will be designed with the necessary instrument and service air capacity. Key PCC Outputs for PCC Base Case Plant Condensate Return
The specification for condensate return from the PCC plant is provided by MHI for the modeling process.
Page 77 GLOBAL CCS INSTITUTE POST COMBUSTION CARBON CAPTURE THERMODYNAMIC MODEL - LOY YANG POWER PLANT
Product CO2
The specification for product CO2 from the PCC plant is provided in the following table Appendix - Table E.
Appendix - Table E - PCC Plant Product CO2
Item Description Units Value (Post Compressor)
(a) Capacity (CO2 100% Dry) tpd 5000
(b) Quality Required :
N2/Ar vol% Dry 1.2 (max)
CO2 vol% Dry 98.0 (min)
O2 vol% Dry 0.2
H2O ppmv < 500
(c) Pressure kPa(g) 9,899
(d) Temperature °C 45 Source: MHI
Page 78 GLOBAL CCS INSTITUTE POST COMBUSTION CARBON CAPTURE THERMODYNAMIC MODEL - LOY YANG POWER PLANT
Appendix 5 Independent Peer Reviewer’s Report
Page 79
Peer Review Report on Post Combustion Capture – Thermodynamic Model Loy Yang Power Plant
Dr. Kelly Thambimuthu, FTSE 31 August 2012
1. Background and Scope
The aim of the study commissioned by the Global CCS Institute with Worley Parsons as the principal contractor was to understand the performance impacts of post combustion capture (PCC) when proposed for deployment on existing subcritical pulverised coal (PC) fired thermal power plants firing lower rank coals with the overall purpose of implementing the roll out of carbon capture and storage facilities. Performance impacts in the study were to be assessed through:
• Impact on net sent out generation • Impact on supporting infrastructure • Impact on utilities such as water requirements for the process and cooling
It is intended that the outcomes would address the following main critical aspects for the development of PCC-projects as retrofits to existing pulverised coal power plants:
• Develop a thermodynamic model that will provide an independent validation of plant performance and inputs for retrofit PCC projects and document a methodology for power station owners to value the risks and revenue impacts for their plant operation. • Provide a means for the independent validation of the plant performance that can contribute to a reduction of the currently required risk premiums to finance the execution of first-of-its-kind large scale PCC plants.
Work carried out in the study was undertaken in the specific context of thermodynamic modelling of a partial retrofit of a commercially sized PCC plant of 5000 tpd capacity to the Loy Yang A Power Station’s Unit 1 generating unit with a nominal rating of 569 MWe, firing high moisture Victorian brown coal. Specific case studies assessed as a means for validating the methodology developed for the thermodynamic modelling of the plant included the following;
Table 1. Matrix of Case Studies
The terms of reference for the study issued by the Global CCS Institute called for the validation of methodology developed for thermodynamic modelling of the plant by independent peer review. The present report by the independent peer reviewer, Dr Kelly Thambimuthu serves this purpose.
The study was undertaken over a period of approximately 6.5 months from a kick off meeting initiated on the 25 th of January 2012 to the delivery of a draft version of the final report for peer review on the 10 th of August 2012. Access of the peer reviewer covered the following interactions with the study team and/or the principal contractor, Worley Parsons;
• Participation in a pre-kick off conference call on 19 January 2012 to review the terms of reference of the study with the Worley Parsons project leads • Participation in a project kick off conference call on 25 January 2012 with the main study team participants from MHI (Melbourne and Japan), Worley Parsons (Reading, USA and Melbourne) and the Global CCS Institute representative. • Feedback provided by the peer reviewer to Worley Parsons on 6 th Feb 2012 by way of a note on key criteria to be addressed for thermodynamic plant modelling • Peer review of the draft Table of Contents provided by Worley Parsons, 8-9 February 2012 • Communication of base case full load modelling results from Worley Parsons (28 June 2012) and response by the peer reviewer (2 July 2012) • Delivery of the draft version of the final report for peer review by Worley Parsons on 10 August 2012 and a subsequent response by the peer reviewer on 16 August 2012
The chronology of events above shows limited access of the peer reviewer to any detailed aspect of the study or in participating in project review meetings with the study team. It must therefore be emphasised that the validation of the study provided by the peer reviewer has focused on the broad review of the methodology and outcomes of the thermodynamic modelling only , and does not cover the review of any specific performance data from the power station, PCC plant or coal drying process. This is consistent with the peer reviewer not being provided with any access, under the terms of the study contract, to proprietary information from either the power station or the technology IP proprietors.
2. Key Issues for Capture Plant Integration
In order that integration of the PCC plant retrofit with the power plant cycle be undertaken in the most energy efficient manner possible, the peer reviewer recommended that the following best practise guidelines in the published literature (Lucquiaud et al, 2010 and IEAGHG 2011) be adopted where relevant in developing the thermodynamic model. This information was communicated by the peer reviewer in a note to Worley Parsons on 6 February 2012, following the kick off meeting for the project noted in Section 1. These guidelines covered the following;
a. For new build, add heat to the steam cycle at as high a temperature as possible (use best available steam conditions when justified). For retrofits to existing plants, however,
it appears that the penalty per tonne of CO 2 emissions is independent of the turbine (inlet) steam conditions. b. Reject heat from the steam cycle for the steam extracted for solvent regeneration at a temperature (and corresponding pressure) as close as possible to the required solvent regeneration temperature. Optimize solvent regeneration temperature to minimize the
total overall electricity output to the capture and CO 2 compression system. c. Produce as much electricity as possible (for retrofit projects use additional turbines if commercially beneficial) consistent with rejecting heat at the regeneration temperature of the solvent. The same rule applies if any additional fuel is used for capture
d. Use any waste heat from CO 2 capture/compression in the steam cycle. e. Design for the whole life of the plant anticipating use of the latest solvent developments f. Exploit the flexibility of post-combustion capture (enabling capture operation at low profit periods and/or as necessary to accelerate ramp rate during transient operation).
With the successful application of these rules, it is expected that for state-of-the-art solvent and state-of-the-art energy integration, the electricity output penalty (EOP) for PCC would be of
the order of 250-300 kWh e/tCO 2 for pulverised coal power plants (IEA GHG 2011). The electricity output penalty (EOP) being defined as follows;
EOP = Efficiency penalty for capture and compression (MWhe/MWh th ) /Fuel specific emissions captured (kg CO 2/MWh th ). The peer reviewer in his communication also noted that the utility of the model developed would be enhanced if it were to be able to address performance sensitivity to:
• Amount of CO2 captured from partial to full load • Impact of plant ambient conditions • Impact of wet and dry cooling options • Impact of fuel moisture and coal quality • Impact of future solvent improvements
These features would enhance the general applicability of the model to generic subcritical coal-fired power plants burning a range of coal and compatible solvent types that use a similar configuration for the PCC plant. However, the peer reviewer also noted that many of desirables requested above were outside the contracted scope of the study with the exception of two key elements pertaining to the effect coal drying/fuel moisture and the use of wet/dry cooling which were already covered in the 6 cases specified in the study scope (see Table 1 in Section 1). For the other features not covered in the scope of the study, it was suggested that a qualitative discussion be incorporated to address the impact of the relevant features in the final report.
3. Study Methodology and Modelling
The methodology adopted in the study involved the simulation of the steady-state performance of the various technological islands of the base and retrofitted plant fitted with the PCC, coal drying unit and wet or dry cooling. The overall approach adopted was to first set up and verify the steady state simulations of individual technology islands representing the base power plant, PCC unit, the CO2 compression unit, coal drying process, wet and dry cooling and finally with various combinations of these units with and without process optimisation of the integrated plant performance in 6 case specific configurations. The 6 case specific simulations identified in Section 1 looked at the following operating modes;
• Base Case – simulation of the full scale power plant based on plant inputs and verification of performance by comparison with actual plant performance data. Simulated the part load performance of power plant at conditions closest to derating that may occur with addition of a PCC unit and verification of the steady state simulation with actual plant data at part load operation. • Cases 1 and 4 provided simulation of plant performance with the addition of the PCC unit only with and without process optimisation respectively. Wet cooling was adopted for the operation of the PCC unit • Cases 2 and 3 provided simulation of plant performance with the combined addition of the PCC and coal drying unit with and without plant optimisation respectively. Wet cooling was adopted for the operation of the PCC unit • Case 5 presented a simulation of the optimised plant with the PCC and coal drying unit but with dry as opposed to wet cooling employed for the operation of the PCC unit
The overall strategy employed in the methodology chosen successfully identified the direct impact of the PCC unit addition on power plant performance through comparison with the base plant case and cases 1 and 4 while cases 2 and 3 examined the additional impact of the coal drying unit. Likewise, the comparison of Cases 3 and 5 were able to identify the direct impact of wet opposed to dry cooling on the retrofitted plant performance. However, the plant case simulations reported do not provide a direct assessment of the benefits of adding the coal drying unit in isolation.
In the discussion presented in Section 4.3 of the main report, the merits of using different types of software commercially available to undertake the process simulations is presented. Whilst the peer reviewer has no direct experience in the use of these different software packages to comment authoritatively on the preferred use (for well justified reasons in the report) of the GateCycle TM software by the contractor, it should be noted that subsequent development and use of the current thermodynamic model to cost retrofitting CO2 capture to existing power plants would incur an added complication from the absence of a seamless bolt on costing module that is not available for the GateCycle TM software package. However, other approaches may be deployed to derive the cost outcomes (and which is not a deliverable required in the present work) from the overall approach and process simulations undertaken in this study.
The GateCycle TM software utilized for modelling was able simulate plant performance with delivery of the following key outputs to the PCC and coal drying unit as relevant;
• Steam Extraction Supply to PCC plant; MW • Auxiliary Power Supply to PCC plant; MW
• CO 2 Compression Power MW • Auxiliary Power Supply to Coal Drying plant; MW • Power Station Net Sent Out Generation; MW • Water Requirements for the retrofit PCC plant; ML
These parameter outputs together with other derived values of the EOP, plant efficiency, amount of CO2 capture etc adequately meet the deliverables desired to access the impact of retrofitting PCC to a power plant.
Finally, a potential drawback noted in the methodology employed in the subsequent utilisation of the thermodynamic model, is the off-line treatment of inputs, outputs and iterations from the PCC and coal drying units undertaken due to the proprietary ownership of the relevant software modules and data confidentiality issues. To retain universal applicability of the thermodynamic model in being able to present an independent and comprehensive tool for the assessment and roll out of carbon capture and storage facilities consistent with the ultimate goal of the Global CCS Institute, there would be a need to develop and incorporate generic and non-proprietary modules for the PCC and coal drying plants in future iterations of the methodology and model developed from this study. It should be noted, however, that this off-line iteration procedure adopted was not of any impediment whatsoever in meeting the deliverables required from the current work.
4. Review of Results in the Context of the Study Methodology and Modelling
A key result of the study is achieving optimal integration of the PCC unit and other plant refinements to minimise the energy penalties, impact on infrastructure and other utilities/resources in a plant retrofitted with CO2 capture. The most significant part in achieving this outcome stems from attaining the most energy efficient integration of the PCC unit retrofitted to the power plant. The list of criteria to enable this goal through energy integration/plant optimisation, as summarised by the peer reviewer (see section 2), was addressed as relevant to this partial PCC retrofit case in the work carried out in the study. Detailed commentary on the relevant issues addressed, is provided by the contractor in Section 7.4 of the main report. The main table of results summarising energy use in the 6 cases examined in the study is reproduced in the Table 2 below.
Table 2. Summary of Thermodynamic Modelling Results
Base Case 1 Case 2 Case 3 Case 4 Case 5
SYSTEM CONFIGURATION Base Plant X X X X X X
PCC Plant X X X X X
Coal Drying X X X
Plant Optimization X X X
Air Cooled (PCC Plant Only) X
POWER GENERATION kW kW kW kW kW kW SUMMARY Main Steam Turbine 568,960 530,810 527,700 528,840 549,390 528,840 Generation
Expander Generation 5,320 3,130 5,320
Total Gross Power 568,960 530,810 527,700 534,160 552,520 534,160 Generation
Net Power Generation 521,380 446,460 445,840 452,380 468,270 452,480
Net Power Output Reduction - 74,920 75,540 69,000 53,110 68,900
Gross Plant Efficiency, % 31.46% 29.35% 30.74% 31.12% 30.53% 31.12% Base Case 1 Case 2 Case 3 Case 4 Case 5 Net Plant Efficiency, % 28.82% 24.68% 25.97% 26.36% 25.88% 26.36%
AUXILIARY LOAD POWER kW kW kW kW kW kW SUMMARY
Base Plant Auxiliary Load 47,580 47,450 44,350 44,270 47,350 44,170
PCC Plant Auxiliary Load - 36,900 34,500 34,500 36,900 34,500
Coal Drying Plant Auxiliary - - 3,010 3,010 - 3,010 Load
Total Plant Auxiliary Load 47,580 84,350 81,860 81,780 84,250 81,680 Power
CO 2 CAPTURE SUMMARY
CO 2 Captured, (tpd) - 5,000 5,000 5,000 5,000 5,000
CO 2 Produced, (tpd) 14,831 14,831 14,081 14,081 14,854 14,081
CO 2 Emitt ed, (tpd) 14,831 9,831 9,081 9,081 9,854 9,081
Gross Specific Emission, 1.086 0.772 0.717 0.708 0.743 0.708 (kg/kWh)
Net Specific Emission, 1.185 0.917 0.849 0.836 0.877 0.836 (kg/kWh)
Electricity Output Penalty, - (kWh/t CO 2 ) 419.89 274.70 233.60 284.36 233.6
The calculated value of the EOP from thermodynamic modelling for Case 4 with optimised integration of the PCC unit only, falls well within the range of 250- 300 kWhe/tCO 2 stated in the published literature for the most energy efficient integration of PCC units in pulverised coal fired power plants. Data for case 2, for the unoptimised plant that includes both the PCC and coal drying units also falls within this range. The process optimised plant case (Case 3) shows EOP values that are an improvement compared to the range cited in the literature, underscoring the positive benefit of adding coal drying in improving the efficiency of the base power plant and additionally reducing the overall CO2 emissions from less fuel use. Indeed, the comparison of cases 2 and 3 show that for the simulations including the PCC and coal drying units, optimised plant integration by the thermodynamic model reduces the EOP from 274.70 for the non-optimised case 2 to 233.60
kWhe/tCO 2 for the optimised case 3. These results provide a good test of the thermodynamic model and methodology developed in addition to the successful benchmarking of the base case model predictions that was verified by comparison with real plant data. Similarly, the outcome of the improved performance prediction of the optimised case 3 with coal drying compared to optimised case 4 with the PCC unit only again demonstrates the sensitivity of the modelling in predicting the positive effect of coal drying on the energy efficiency of CO2 capture for the specific conditions evaluated in these cases.
5. Conclusion and Recommendations
The methodology and model developed in this study is able to optimise plant integration and predict the impact of partially retrofitting a PCC unit for CO2 capture, coal drying for moisture reduction and the use of wet or dry cooling in a subcritical, brown coal fired power plant. The peer reviewer has been able to verify this finding based on the case studies presented in the contractor’s final report prepared for the Global CCS Institute.
The methodology and thermodynamic model developed in this work has been tailored to analyse specific, proprietary technology options in case specific situations and thus requires further work to extend its use to a more universal application to evaluate the integration of a range of vendor supplied PCC units to generic pulverised coal power plants using either low or high rank coals. The referee’s recommendations for further work to extend the universal application of the methodology and model developed in this study include:
• The capability to handle the impact of coal rank and moisture content, • Use of a generic solvent capture PCC module for CO2 capture as a substitute for proprietary vendor developed modules. The generic modules should be able to model future improvements arising from the latest solvent developments such as the reduction in regeneration temperature and energy use, • Extend the ability of the model to analyse the impact of the separate addition of secondary heat or power sources in heat or power matched retrofit conversions of CO2 capture to coal- fired power plants. This option may provide potential cost advantages compared to new build power plants with capture and avoid significant deration of capture retrofitted plants in a power grid • Enhance model flexibility and methodology to cost capture retrofitted plants • Enhance modelling capability to retrofit conversions of supercritical and ultra-supercritical coal fired power plants
The above recommendations are desirable improvements that are above and beyond the contracted scope of current work that has been very ably addressed by the study team led by Worley Parsons.
References
IEA GHG (2011), ‘Retrofitting CO2 capture to existing power plants’, Report 2011/02, IEA Greenhouse Gas Program, Cheltenham, UK, May 2011.
Lucquiaud, M. (2010), ‘Steam cycle options for capture-ready power plants, retrofits and flexible operation with post-combustion CO 2 capture’, PhD Thesis, Imperial College London, London, UK
There are no further attachments to this peer review report GLOBAL CCS INSTITUTE POST COMBUSTION CARBON CAPTURE THERMODYNAMIC MODEL - LOY YANG POWER PLANT
Appendix 6 Thermodynamic Modelling Study Timeline
Page 80 ID Task Name Duration 1st Quarter 2nd Quarter 3rd Quarter Jan Feb Mar Apr May Jun Jul Aug Sep 1 Kick-Off Meeting 1 day? 2 Issue Monthly Reports to GCCSI 67 days 7 Define Detailed Methodology 10 days 8 Data Collection LYP & Discuss Utilities 12 days 9 Define Final PCC Plant Capacity & Request Data from IP Owner 5 days 10 Model Required PCC Capacity Plant (by IP Owner) 32 days 11 Workshop with US Team (WP Reading) to Define Process Modelling 1 day? 12 1) Establish Thermodynamic Model Software 10 days 13 2) Establish Basis of Design (BOD) for Base Case 10 days 14 3) Establish BOD for Coal Drying 10 days 15 4) Establish Methodology for Model Validation 10 days 16 Develop Table of Contents for Report 2 days 17 Peer Review Table of Contants & Obtain Notes From Peer Reviewer 3 days 18 Modelling for LYP Base Case 15 days 19 Carry out Sensitivity for Base Case 5 days 20 Issue Base Case Results to LYP for Validation 5 days 21 Issue BOD & Request for Coal Drying Case to Vendor 25 days 22 Receive PCC Data from IP Owner 0 days 30/03 23 Model LYP with Commercial Scale PCC Plant - Case 1 10 days 24 Carry out Sensitivity for Case 1 5 days 25 Receive Coal Drying Data from Vendor 0 days 3/05 26 Model LYP with Coal Drying & PCC Plant - Case 2 10 days 27 Carry out Sensitivity for Case 2 5 days 28 Workshop with Commercial Scale PCC IP Owner 1 day? 29 1) Establish Opportunities for Heat Recovery in the PCC Plant 5 days 30 2) Quantify Heat Recovery Opportunities 5 days 31 3) Discuss Air Cooled Option and the impact on the PCC Process 5 days 32 Model LYP with Coal Drying, PCC Plant, & Plant Optimisation - Case 3 5 days 33 Carry out Sensitivity for Case 3 2 days 34 Model LYP, PCC Plant & Plant Optimisation - Case 4 5 days 35 Carry out Sensitivity for Case 4 2 days 36 Model LYP, Coal Drying, PCC Plant, Plant Opt & Air Cooling - Case 5 5 days 37 Carry out Sensitivity for Case 5 2 days 38 Prepare a Draft report 50 days 39 Review Draft Report with GCCSI 0 days 3/08
Task External Milestone Manual Summary Rollup Split Inactive Task Manual Summary
Project: GCCSI Timeline 101012 Milestone Inactive Milestone Start-only Date: Thu 11/10/12 Summary Inactive Summary Finish-only Project Summary Manual Task Progress External Tasks Duration-only Deadline
Page 1 ID Task Name Duration 1st Quarter 2nd Quarter 3rd Quarter Jan Feb Mar Apr May Jun Jul Aug Sep 40 Issue Draft Report to WP (Reading) & PCC IP Owner 8 days 41 Revise Repiort issue to WP (Reading) & LYP 8 days 42 Issue Revise Report to PCC IP Owner to Remove Sensitive IP Data 8 days 43 Revise Draft Report for Issue to GCCSI 5 days 44 Obtain Comments From GCCSI 5 days 45 Produce Final Draft of the Report & Issue to GCCSI 5 days
Task External Milestone Manual Summary Rollup Split Inactive Task Manual Summary
Project: GCCSI Timeline 101012 Milestone Inactive Milestone Start-only Date: Thu 11/10/12 Summary Inactive Summary Finish-only Project Summary Manual Task Progress External Tasks Duration-only Deadline
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