23488 ESMAP TECHNICAL PAPER vol. 1 011 Technology Assessment of Clean Coal Technology for China: Electric Power Production Volume I .~~~~~~~~1v December 2001 Energy Sector Management Assistance Programme Q$AAA D 60J1 vIIt VI Papers in the ESMAP Technical Series are discussion documents, not final project reports. They are subject to the same copyrights as other ESMAP publications. JOINT UNDP / WORLD BANK ENERGY SECTOR MANAGEMENT ASSISTANCE PROGRAMME (ESMAP) PURPOSE The Joint UNDP/World Bank Energy Sector Management Assistance Program (ESMAP) is a special global technical assistance partnership sponsored by the UNDP, the World Bank and bi-lateral official donors. Established with the support of UNDP and bilateral official donors in 1983, ESMAP is managed by the World Bank. ESMAP's mission is to promote the role of energy in poverty reduction and economic growth in an environmentally responsible manner. Its work applies to low-income, emerging, and transition economies and contributes to the achievement of internationally agreed development goals. ESMAP interventions are knowledge products including free technical assistance, specific studies, advisory services, pilot projects, knowledge generation and dissemination, trainings, workshops and seminars, conferences and roundtables, and publications. ESMAP work is focused on three priority areas: access to modern energy for the poorest, the development of sustainable energy markets, and the promotion of environmentally sustainable energy practices. GOVERNANCE AND OPERATIONS ESMAP is governed by a Consultative Group (the ESMAP CG) composed of representatives of the UNDP and World Bank, other donors, and development experts from regions which benefit from ESMAP's assistance. The ESMAP CG is chaired by a World Bank Vice President, and advised by a Technical Advisory Group (TAG) of independent energy experts that reviews the Programme's strategic agenda, its work plan, and its achievements. ESMAP relies on a cadre of engineers, energy planners, and economists from the World Bank, and from the energy and development community at large, to conduct its activities under the guidance of the Manager of ESMAP. FUNDING ESMAP is a knowledge partnership supported by the World Bank, the UNDP and official donors from Belgium, Canada, Denmark, Finland, France, Germany, the Netherlands, Norway, Sweden, Switzerland, and the United Kingdom. ESMAP has also enjoyed the support of private donors as well as in-kind support from a number of partners in the energy and development community. FURTHER INFORMATION For further information on a copy of the ESMAP Annual Report or copies of project reports, please visit the ESMAP website: www.esmav.ori. ESMAP can also be reached by email at esmaP(iq)worldbank.or2 or by mail at: ESMAP c/o Energy and Water Department The World Bank Group 1818 H Street, NW Washington, D.C. 20433, U.S.A. Tel.: 202.458.2321 Fax: 202.522.3018 Technology Assessment of Clean Coal Technologies for China: Volume 1-Electric Power Production May 2001 Joint UNDPWVorld Bank Energy Sector Management Assistance Programme (ESMAP) Copyright © 2001 The International Bank for Reconstruction and Development/THE WORLD BANK 1818 H Street, N.W. Washington, D.C. 20433, U.S.A. All rights reserved Manufactured in the United States of America First printing May 2001 ESMAP Reports are published to communicate the results of the ESMAP's work to the development community with the least possible delay. The typescript of the paper therefore has not been prepared in accordance with the procedures appropriate to formal documents. Some sources cited in this paper may be informal documents that are not readily available. The findings, interpretations, and conclusions expressed in this paper are entirely those of the author(s) and should not be attributed in any manner to the World Bank, or its affiliated organizations, or to members of its Board of Executive Directors or the countries they represent. The World Bank does not guarantee the accuracy of the data included in this publication and accepts no responsibility whatsoever for any consequence of their use. The Boundaries, colors, denominations, other information shown on any map in this volume do not imply on the part of the World Bank Group any judgement on the legal status of any territory or the endorsement or acceptance of such boundaries. The material in this publication is copyrighted. Requests for permission to reproduce portions of it should be sent to the ESMAP Manager at the address shown in the copyright notice above. ESNIAP encourages dissemination of its work and will normally give permiission promptly and, when the reproduction is for noncommercial purposes, without asking a fee. Contents FOREWORD ................................................... V ABSTRACT ................................................... VI ACKNOWLEDGMENTS ................................................... VII ABBREVIATIONS AND ACRONYMS ....................................................Vm EXECUTIVE SUMMARY ................................................... 1 INTRODUCTION ......................................................................... .... 1 OVERVIEW OF CCT SOLUTIONS ....................................................1 METHODOLOGY ................................................... 2 GENERATION TECHNOLOGY COST AND PERFORMANCE SUMMARY ................................................... 3 PARTICULATE CONTROLS ................................................... 3 SO2 CONTROLS ................................................... 5 NOx CONTROLS ................................................... 7 SUPERCRITICAL PULVERIZED COAL (PC) PLANTS ................................................... 9 ATMOSPHERIC FLUIDIZED-BED COMBUSTION (AFBC) ................................................... 11 INTEGRATED GASIFICATION COMBINED CYCLES (IGCC) ................................................... 13 UTILIZATION OF FLY ASH AND BY-PRODUCTS FROM SO2 CONTROLS ................................................... 15 INTRODUCTION ................................................... 17 1.1 COAL AND THE ENVIRONMENT IN CHINA ....................................................17 1.2 ENVIRONMENTAL IMPROVEMENT OPPORTUNITIES .............................................................18 1.3 STUDY OBJECTIVES ..................................................19............... .................... 19 1.4 TECHNOLOGY ASSESS MENT METHODOLOGY ...................................... 20 1.5 ORGANIZATION OF THIS REPORT ...................................... . 20 REFERENCE PLANTS ...................................... 21 2.1 DESIGN BASIS .................................... 21 2.2 DESIGN BASIS FOR REFERENCE PLANTSS .................................... 23 2.3 REFERENCE PULVERIZED-COAL POWER PLANTS .................................... 24 2.4 COST-ESTIMATING BASIS .................................... 24 2.5 METHODOLOGY FOR CONVERTING COSTS FROM U.S. TO CHINA ........................................................ 26 2.6 COST OF REFERENCE PLANTS IN CHINA ................................................................... 27 POWER GENERATION AND ENVIRONMENTAL CONTROL TECHNOLOGIES ...................... 29 3.1 PARTICULATE CONTROLS ................................................................... 30 3.2 SO2 CONTROLS ................................................................... 43 3.3 NO, CONTROLS ................................................................... 61 3.4 SUPERCRITICAL PULVERIZED COAL (PC) PLANTS ................................................................... 85 3.5 ATMOSPHERIC FLUIDIZED-BED COMBUSTION (AFBC) ................................................................... 104 3.6 PRESSURIZED FLUIDIZED BED-COMBUSTION (PFBC) ................................................................... 118 3.7 INTEGRATED GASIFICATION COMBINED CYCLES (IGCC) ................................................................ 131 3.8 UTILIZATION OF FLY ASH AND BY-PRODUCTS FROM SO2 CONTROL PROCESSES ............................. 144 3.9 GENERATION TECHNOLOGY COST AND PERFORMANCE SUMMARY ................................................. 164 APPENDIX A COAL PRODUCTION AND USE IN CHINA ............................................................. 167 A. 1 SUSTAINABILITY ISSUES ................................................................... 167 A.2 COAL PRODUCTION ................................................................... 168 A.3 COAL CONSUMPTION ................................................................... 168 iii A.4 FORECASTS OF FUTURE CONSUMPTION ....................................................... 169 A.5 LIMITED ABILITY TO SUBSTITUTE NATURAL GAS ................... .................................... 169 APPENDIX B EARLY IGCC OPERATING EXPERIENCE ....................................................... 171 APPENDIX C SUPERCRITICAL BOILERS AND SUPPLIERS IN CHINA-REPORT ON SITE VISITS ........................................................ 173 C. 1 TRIP REPORT SUMMARY ........................................................ 173 C.2 SUPPLEMENT-DETAILS ON SUPERCRITICAL TECHNOLOGY IN CHINA ............................................ 177 C.3 STEAM TURBINE SUPPLIER CAPABILITIES IN CHINA ........................................................ 186 iv Foreword Funding for the studies was provided by a number of sources including the Japan Staff and Consultant Trust Fund (JSCTF) large scale study fund, the Energy Sector Management Assistance Program (ESMAP), the East Asia and Pacific Region's Energy Sector Unit (EASEG), and the Infrastructure Department's Energy Unit (INFEG). The project was jointly managed by EASEG and INFEG. This report is based upon a report prepared for the World Bank by Electric Power Research Institute (EPRI) of the US, under a contract to The Electric Power Development Corp (EPDC) and Tokyo Electric Power Co (TEPCo) of Japan. World Bank staff1 led the overall project team supervising this study. This is the first volume of the Clean Coal Technology Assessment report which focus on the cleaner and more efficiently use of coal in power sector. In publishing this report, we hope to provide an insightful analysis of the long-term opportunities CCT presents for sustainable development of China. Yukon Huang Director China Country Unit East Asia and Pacific Region Noureddine Berrah of EASEG, Zhao Jianping of EECCF, MasakiTakahashi and Stratos Tavoulareas of INFEG v Abstract China's transition to a market economy, which has been proceeding for two decades, places it among the world's five fastest-growing economies. Economic growth has been fueled by increased coal combustion, which has serious environmental impacts. Pollution from coal combustion is damaging human health, air and water quality, agriculture, and, ultimately, the economy itself. Coal is China's chief energy source, accounting for 74% of primary energy consumption. Given the nation's abundant coal reserves and emphasis on development using indigenous resources, coal will remain the dominant fuel well into the 21lt century. Analysts expect China to continue improving the efficiency of energy production and use, thereby decoupling the traditional relationship between GDP and energy consumption. Environmentally acceptable economic growth is closely linked with further improvements in the overall efficiency of energy use. Both of these goals will require a continued increase in the use of coal to produce electricity, along with a more deliberate and rapid transition from direct coal combustion to the use of electricity and other cleaner coal-based fuel sources, especially for cooking, space heating, and industrial fumaces. The opportunity for environmental improvement in conjunction with economic growth lies in the wise adoption of clean coal technologies (CCT) for both the electric power and non-power sectors. This report presents CCT options for the power sector that can help China achieve these twin goals. The CCT options are: Air pollution controls for particulate, SO2, and NO, x Advanced electricity generation technologies-supercritical pulverized-coal boilers, atmospheric and pressurized fluidized-bed combustors, and integrated gasification combined cycle plants Completion of the ongoing program to replace the many small power boilers with new, larger, more efficient plants equipped with modem pollution controls will help China achieve these objectives. At the same time it will be essential to replace the many inefficient, polluting coke-making ovens and industrial gasifiers with newer, cleaner technology. These changes are vital because about 60% of coal production is currently consumed by these inefficient technologies, which emit their pollutants at low heights where they have greater direct impact on people's health. vi Acknowledgments This report is based upon a report prepared by EPRI with important input from other members of the project team. EPRI acknowledges the insights and experiences in supercritical boilers and pressurized fluidized-bed combustion boilers shared by the Electric Power Development Corporation (EPDC) and Tokyo Electric Power Company (TEPCO) in Japan. The Nanjing Environmental Protection Research Institute (NEPRI) and the Thermal Power Research Institute (TPRI) in Xi'an, China, assisted the study in two important ways-they arranged the site visits and accompanied the team on those visits, and they provided reports documenting experiences in China with the clean coal technologies (CCT) discussed in this report. Their input has been seamlessly interwoven in the report, so the EPRI authors wish to acknowledge their contributions explicitly here. EPRI especially acknowledges the contributions of Drs. Zhu Fahua (NEPRI) and He Hongguang (TPRI).2 Takahashi Masaki, the World Bank Project Manager, provided invaluable guidance and assistance, developing the framework for this project, establishing key directions and priorities, and leading the site visits. He was ably assisted in these efforts by Stratos Tavoulareas of Energy Technologies Enterprises Corp., a consultant to the World Bank. Nishino Toshiro brought the team together and facilitated the communications among the members that enabled EPRI to prepare a comprehensive report. This report would not present an accurate and full account of the status of CCTs in China without the hospitality and openness of the management and staff at the many sites the team visited-power plants with demonstration or commercial CCTs, provincial power authorities, and Chinese equipment suppliers. Too numerous to mention here, their cooperation is greatly appreciated. We trust they will recognize their inputs to this report as they read it. This report was reviewed and prepared for publication by Dean Girdis with assistance by Masaki Takahashi and was edited by Bevilacqua Knight, Inc., specifically Deborah Dunster and Rich Myhre. 2 The names of the Chinese and Japanese contributors are presented in conventional Chinese and Japanese fashion (famnily name, then given name). vii Abbreviations and Acronyms ABB Asea Brown Boveri ADB Asian Development Bank AFBC Atmospheric Fluidized-Bed Combustors AFUDC Allowance for Funds used During Replaceable items ASTM American Society of Testing Materials ASU Air Separation Unit AVT Deoxigenated All-Volatile BAW Bilateral Agency of Switzerland BBW Beijing Boiler Works BMZ Bilateral Agency of Germany BWBC Babock and Wilcox Beijing Co., Ltd CCPUA China Coal Processing and Utilization Association CCT Clean Coal Technology CCPUA China Coal Processing and Utilization Association CFBC Circulating Fluidized Bed Combustion COS Carbonyl Sulfide DFID Bilateral Agency of the United Kingdom DGIS Bilateral Agency of the Netherlands EAF Equivalent Availability Factors EASG East Asia and Pacific Region's Energy Sector Unit EHE External Heat Exchanger EMTEG Energy, Mining and Telecommunications Department's Energy Unit EPDC The Electric Power Development Corporation EPRI Electric Power Research Institute ESP Electrostatic Precipitators FGD Flue Gas Desulfurization FSI Furnace Sorbent GTZ Bilateral Agency of Germany HGCU Hot Gas Clean-up HRSG Heat Recovery Steam Generator HVFA High Volume Fly Ash IGCC Integrated Gasification Combined Cycle IHI Ishikawajima Harima Heavy Industries KyEPCO Kyushu-Electric Power Company LHV Lower Heating Value viii LIFAC Limestone Injection into a Furnace and Activation of Unreacted Calcium LLB Lurgi Lentjes Babock LNB Low Nox Burner LNCFS Low Nox Cocentric Fining System LSFO Limestone with Forced Oxidation MCR Maximum Continuous Rating MHI Mitsubishi Heavy Industries NEPRI The Nanjing Environmental Protection Research Institute NERC-CCC National Engineering Research Center of Clean Coal Combustion OECD Organization for Economic Cooperation and Development O&M Operating and Maintenance PC Pulverized Coal PFBC Pressurized Fluidized Bed Combustion PCFB Pressurized Fluidized Bed SBWL Shangai Boiler Works, Ltd SC Supercritical Boilers SD Spray Dryers SNCR Selective non-Catalytic Reduction TEPCO Tokyo Electric Power Company TPRI Thermal Power Research Institute TPC Total Plant Cost TAG Technical Assessment Guide UBCs Unburned Hydrocarbons USC Ultra Supercritical VAT Value Added Taxes VOCs Volatile Organic Compounds WHO World Health Organization ix i i Executive Summary Introduction China's transition to a market economy during the past two decades places it among the world's five fastest-growing economies. Economic expansion has increased incomes, improved health indicators and reduced overall poverty levels. This economic growth has not, however, been totally benign. It has been fueled by increased coal combustion and the resulting, often severe, environmental impact. It is abundantly clear that coal resources are not being used as efficiently as possible. More than 80% of the coal consumed in China is combusted directly in equipment that is not designed for high efficiency, such as small kilns and residential stoves. At present, the general energy utilization efficiency of coal in China is about half that of highly industrialized countries. In recent years, China has made progress in improving air quality in many cities through residential fuel-switching programs and industrial emissions control. However, ambient air concentrations of particulates, sulfur dioxide (SO2), and other air pollutants are still two to five times higher than World Health Organization (WHO)-recommended maximum levels. The opportunity for environmental improvement in conjunctions with economic growth lies in the wise adoption of clean coal technologies (CCT) in both the electric power and non-power sectors. This report will propose and examine various solutions for electrical power production CCT's. Overview of CCT solutions There are several principal CCT options in the power sector that could be employed and they include the following: * Air pollution control equipment for particulates (also called fly ash or dust), SO2, and nitrogen oxides (NO,) * Advanced power generation processes that convert fuel to electricity and heat more efficiently and with less environmental impact than current boilers. Applicable technologies include: - Supercritical pulverized-coal boilers - Atmospheric fluidized-bed combustors (AFBC) - Pressurized fluidized-bed combustors (PFBC) - Integrated gasification combined cycle (IGCC) systems 1 2 Technology Assessment of Clean Coal Technologies for China Methodology This technology assessment report synthesizes the experience and extensive in-house information collected over the years by the study team. The team was led by EPRI3, which provided the majority of the technical input and prepared the report. The report incorporates input received from all of the technology partners in the project: EPDC and Tokyo Electric Power Company (TEPCO) on CCTs in use or under development in Japan and on two simplified SO2 control processes just recently demonstrated by EPDC-vendor consortia and turned over to their Chinese plant operators; and the Thermal Power Research Institute (TPRI) in Xi'an and the Nanjing Environmental Protection Research Institute (NEPRI) on recent experience with CCTs in China. The study team supplemented its information base by visits to China to (1) inspect several technology demonstrations and (2) discuss the readiness of Chinese boiler and turbine manufacturers to supply advanced generation processes. This report describes each CCT with particular reference to conditions in China (boiler types, fuels used, etc.), discusses its commercial readiness and applicability to China, presents its environmental performance and any impacts on the power plant, and then provides estimated costs for applications in China. In any project that compares costs of competing technologies, it is essential to provide consistency in the cost estimates. A methodology developed by EPRI, the Technical Assessment Guide (TAG), serves this function and is therefore widely used by technology analysts within government and the private sector in the United States, as well as internationally. While the costing methodology used here is specific to this study, the TAG methodology was used as a guideline. That is, the cost estimates were first developed using TAG models that approximate costs for plants at a Midwestern U.S. location. These costs were then converted to conditions applicable to China by factoring in differences in labor costs, relative prices of manufactured items, import duties, value-added taxes (VAT), etc. Specifically, the total plant cost for each plant or pollution control system was broken down into engineered equipment (or factory materials), field materials, and installation labor. The equipment and material costs were then further classified as imported or locally available, and costs for the local systems computed as a percentage of their cost on the international market. Labor costs were computed by multiplying the labor hour estimates for an installation in the United States by the product of (a) an average labor rate in China and (b) an index that reflects the relative productivity of labor in the two countries. The allocation of equipment and materials is based on knowledge of China's procurement practices and domestic manufacturing capabilities as determined during the site visits and follow-up discussions with firms doing business in the China energy sector. 3 Formerly known as the Electric Power Research Institute, EPRI is a United States-based organization that conducts research and development programs for the energy industry worldwide. Executive Summary 3 Generation Technology Cost and Performance Summary Table 1 on the next page presents a summary of the costs, heat rates, and emissions for two conventional plants and the clean coal generation technologies described in the report. These estimates are all for new plants. It is important to understand that the conventional plants, themselves, should not be compared directly with the "clean coal technologies"-AFBC, PFBC, and IGCC-because the conventional plants have neither sulfur controls nor high- performance NO, controls such as selective catalytic reduction (SCR). The emission rates shown in this table clearly indicate these differences. The estimates for the pulverized coal (PC) plants with flue gas desulfurization (FGD) for S02 control and selective catalytic reduction (SCR) for advanced NO, reduction are provided to show the relative costs of power generation technologies with similar environmental performance as the CCTs. However, because the reference coal, Shenmu, has a sulfur content of about 0.63%, a plant firing this coal under today's regulations in China would not require an SO2 control system. Particulate Controls Particulate control options for both retrofit and new power generation technologies fall into three general categories: (1) mechanical collectors, (2) electrostatic precipitators, and (3) fabric filters. Mechanical collectors (e.g., cyclones), which can have either wet or dry designs, are simple and reliable but require a high operating pressure drop to achieve a high level of performance. Further, these collectors do not provide the high collection efficiency required to meet increasingly stringent emission standards. Both electrostatic precipitators (ESPs) and fabric filters can produce extremely high collection efficiencies, and both devices are reliable. The choice of a particulate control device is influenced primarily by the required emission limit, although coal composition and combustion processes (pulverized-coal firing, circulating fluidized-bed combustion, etc.) can be factors because they also determine the cost. Today's limits are low enough that mechanical collectors are no longer a viable option and thus are not discussed. Electrostatic precipitators can be designed to meet very low emissions limits by building them large enough. Because they are relatively inexpensive and the technology is highly developed in China, they are the first choice in most cases. While fabric filters can meet the most stringent emission limits worldwide - less than 50 mg/Nm3 - they are less well established in China and typically not needed to meet current or projected emission limits. 4 Technology Assessment of Clean Coal Technologies for China Table 1: Cost and Performance Summary-Conventional and Clean Coal Technologies Generation Readi- Emissions Heat Rate Construc Costs2 system ness' Rate (kJ,kWh, t time (Shenmu coal, (mg/Nm3) LHV) (years) Capital Fixed Variable 0.63% S) ($/kJ9V O&M O&M ($/kW-yr) (mills/kWh) PC-subcritical, no C SO2 = 1540 9,400 3 665 17.4 0.3 FGD, 300 MW NO, = 500 Part = 200 PC-subcritical, no C Ditto 9,210 3 548 14.4 0.3 FGD, 600 MW PC-supercritical, C Ditto 8,805 3 588 13.8 0.3 no FGD, 600 MW PC-supercritical, C Ditto 8,725 3 543 12.8 0.3 no FGD, 800 MW PC-subcritical, C SO2 = 154 9,530 3 725 26.8 5.8 FGD, 300 MW NO, = 500 Part= 100 PC-supercritical, C Ditto 8,930 3 629 21.2 5.8 FGD, 600 MW PC-supercritical, C SO2 = 154 8,950 3 677 21.3 8.6 FGD/ SCR, 600 NO,, = 100 MW Part = 100 AFBC, 300 MW3 D SO2 = 154 9,400 3 721 17.9 0.5 3-5 yrs NO,, = 163 Part = 200 PFBC, 350 MW3 D SO2 = 154 8,920 3 803 20.1 0.5 -10 yr NO,, = 213 Part = 200 IGCC, 400 MW D S02 = 10 7,980 3 1,038 22.5 0.1 -10 yr NO,, = 50 Part = < 10 I C = commercial; D = demo. Numbers in parentheses = projected years to commercial availability. 2 Costs are for applications in China; capital costs exclude AFUDC and "owners costs" (royalties, land, and initial inventory of all consumables or replaceable items); O&M costs are for first year. 3 SNCR at $9/kW (plus ammonia at - 300 kg/hr for a 300-MW unit) would yield NO, emissions similar to a subcritical or supercritical boiler with SCR. ESP size and cost estimates for three representative coals are shown in Table 2 for the current China emission limit of 200 mg/Nm3 and the more stringent level of 50 mg/Nm3 adopted in most OECD countries and used by the World Bank as a guideline. Table 2: Representative ESP size and costs Mine Ash Sulfur SCA (m2/m3/s) Capital Costs ($/k4T) (0/) (C/) 200 mg/Nm3 50 mg/Nm3 200 mg/Nm3 50 mg/Nm3 Sonzao 30 4.00 49.0 73 21.4 29.4 Shenmu 7 0.63 49.0 76 21.4 30.1 Yanzhou 33 1.22 62.2 84 25.5 32.6 Executive Summary 5 These performance estimates and costs apply equally to subcritical and supercritical boilers. Pressurized fluidized-bed combustors and integrated gasification combined cycle systems remove the particulate within the process. Atmospheric fluidized-bed combustors also use add-on particulate collectors, and an ESP with an SCA of 70 to 80 m2/(m33s) would reduce particulate emissions to 200 mg/Nm3 for such a unit. All these size estimates are based on the assumption that the ESPs would be energized using conventional ESP controls and rectifier sets. The advanced power supply and control sets being developed by the Nanjing Environmental Protection Research Institute (NEPRI) can enhance precipitator performance; where effective, they would enable smaller design SCAs. SO2 Controls Sulfur dioxide removal from power plant flue gas can be accomplished using a variety of processes. They range from high efficiency, high capital cost, conventional wet scrubbing using limestone and producing a gypsum by-product to low capital cost, moderate removal, dry injection processes that produce a mixture of fly ash, unused reagent, and reaction products. In addition, combination removal processes, such as the E-beam SOx/NOx concept, have been developed. The factors that can influence which process is chosen in a given situation include the emission control requirements, the fuel, by-product markets, alkali costs, the availability of investment capital, and the age of the power plant. The processes described in this report are summarized below. Most of these technologies have been installed at pilot or on a commercial scale in China. They represent the range of processes at or near commercial scale, and span the full range of SO2 removal capabilities and costs. * Wet Scrubbing - By far the most common SO2 control method is conventional wet scrubbing using calcium-based absorbents. Most flue gas desulfurization (FGD) systems being installed worldwide today are of this type. * Spray Drying (Dry FGD) - Spray drying is also common in the U.S. and Europe. It is mainly used for lower-sulfur coals and to achieve removals between 70% and 90%, although higher removals have been achieved in the latest installations. * Simplified Wet and Dry FGD Systems - The Japanese are developing simplified wet and dry FGD systems with streamlined designs to reduce capital costs. The compromise is that their SO2 removal rates are somewhat lower than for conventional designs. The only known applications of these technologies are one demonstration of each design in China. * Dry Injection Technologies - These range from low-cost furnace sorbent injection (FSI), a process with low capital costs, relatively high alkali costs, and removals in the 35-50% range, to the LIFAC process, which is similar to spray drying in terms of cost and control capabilities. 6 Technology Assessment of Clean Coal Technologies for China * Seawater Scrubbing - This is a niche process with application only in coastal areas. Its current application has been in Europe. * E-beam Process - This process uses high-energy electron beams to control both SO2 and NO,. The technology has been under development for many years, and a demonstration was recently conducted in China. The SO2 emission reduction capabilities of these technologies are presented in Table 3. Table 3: SO2 Emission reduction capabilities Process S02 Removal, % Fuel Sulfur Content Conventional Wet Scrubbing > 95 All levels Conventional Spray Drying > 90 < 2% Simplified Wet Scrubbing 80 All levels Simplified Dry Scrubbing 80 < 2% Furnace Sorbent Injection 30-50 < 2% LIFAC 70-80 < 2% Seawater Scrubbing > 90 All levels E-Beam > 90 All levels Power consumption rates for these systems (excluding E-beam) range from 0.6% of the plant's output for furnace sorbent injection to 1.6% for a wet FGD treating the flue gas from a boiler burning a 4% sulfur coal. The power requirement for E-beam reported for the China application (where NOx removal is incidental) is 2% of the plant output. Representative costs for application in new plants or retrofit to existing plants are shown in Table 4 for several of these S02 control processes and three coals. Executive Summary 7 Table 4: Summary of SO2 Control Costs NEWINSTALLATIONS 300 MW 600 MW LSFO SWS SSD FSI LSFO SWS SSD FSI Fuel 1 Capital cost, $/kW 59.2 51.9 37.4 41.5 35.5 24.8 O&M, $/kW-yr 9.7 7.1 11.1 8.6 6.3 9.8 Fuel 2 Capital cost, $/kW 61.0 53.8 38.2 43.1 36.8 25.6 O&M, $/kW-yr 11.2 8.3 13.0 10.1 7.5 11.7 Fuel 3 Capital cost, $/kW 66.1 57.7 40.9 47.5 40.7 28.4 O&M, $/kW-yr 16.0 12.6 21.0 15.1 11.8 19.8 RETROFIT 300 MW 600 MW INSTALL TIONS LSFO SWS SSD FSI LSFO SWS SSD FSI Fuel 1 Capital cost, $/kW 76.8 67.2 48.5 27.5 53.8 46.0 32.2 19.5 O&M, $/kW-yr 10.4 7.5 11.3 20.9 11.5 7.9 10.9 21.7 Fuel 2 Capital cost, $/kW 79.0 69.8 49.5 29.7 55.9 47.7 33.2 21.2 O&M, $/kW-yr 11.9 8.8 13.3 23.3 13.2 9.2 12.8 24.1 Fuel 3 Capital cost, $/kW 85.7 74.9 53.1 61.6 52.8 36.8 O&M, $/kW-yr 16.8 13.1 21.4 15.7 12.1 20.0 Note 2: O&M costs (fixed plus variable) are first-year costs. Capital costs are total plant costs. Year basis is 1999. Note 1: Fuel I (Daton mixed) is 1.20% sulfur; Fuel 2 (Changzi unwashed) is 1.93% sulfur; and Fuel 3 (Sonzao meager) is 4.02% sulfur. NOx Controls The formation of NOx emissions during combustion of coal is controlled by a number of fuel, burner design, and boiler operating factors. Because of this dependence, NO, emissions vary widely among coal types, boiler and burner designs, operating conditions, and even equipment maintenance practices. Therefore, it is often difficult to project the potential reductions in NO, emissions that are possible with available controls without a detailed evaluation of many site-specific conditions. The NO, control section of this technology assessment describes demonstrated and commercially available NOx controls and provides broad estimates of their NO, reduction capabilities and the costs for retrofitting them on operating boilers in China. These estimates are based principally on demonstrated performance on U.S. boilers and on cost algorithms developed from documented experience. Application of specific controls in China may require direct purchase of needed equipment and materials or license agreements with original equipment manufacturers (OEMs) that hold patents on proprietary technologies. 8 Technology Assessment of Clean Coal Technologies for China Commercial approaches for reducing NO, emissions prevent the generation of NO, in the lower furnace, during the combustion process, or reduce NO, after it has left the furnace, in the postcombustion region. Some applications combine approaches to minimize NO,. Controls that focus on reducing NO, before it is formed are generally termed combustion modification controls. These include tuning4 and optimization, modifications to the existing burners, replacement of the burners with new low-NOx designs, or the application of staged combustion air via the use of overfire air ports. The details of these modifications depend on the boiler's firing type. While most boilers in China, and the coals burned in them, are similar to technologies used elsewhere, some power plants use difficult-to-burn coals, such as low- volatile anthracites. These are often fired in specialized downshot or W-type furnaces that maximize the time in a high-temperature zone to overcome the fuel's slower burning characteristics; combustion NO, controls for these types of boilers and fuels are not yet well demonstrated. Controls that focus on reducing NO, after the combustion process is completed are typically termed postcombustion or flue gas treatment controls. These include non-catalytic and catalytic reduction controls, either implemented alone or in combination. A process called "reburning" is a transition scheme in between combustion and gas treatment NOx controls; typically it uses natural gas introduced in a "reburn" zone above the main burner zone to provide hydrocarbon radicals that reduce a significant portion of the NOx flowing through this zone. The reburn fuel extends the combustion process higher into the furnace, thereby reducing both the formation of NOx during combustion and the NOx already formed in the lower furnace. Representative costs (for applications in China) and percent NOx reductions are shown in Table 5 for retrofits to a typical 300 MW boiler firing a bituminous coal (see Section 3.3 for an explanation of how the costs change when the control is part of the design for a new plant). Costs and NO, performance are very dependent on the circumstances at a given site, so these figures should be viewed only as indicative of general ranges. 4 The authors strongly recornmend that power plant operators tune their boilers to the lowest possible NO, emnission levels consistent with safe, reliable, efficient operation before selecting and designing further NO, controls. Executive Summary 9 Table 5: Estimates of Retrofit Costs in China for a 300-MW Boiler-Shenmu Coal Control Average Cost Estimates, 1,000 US$ NO, Equipment and Instrumentation Total $/kW Reduction, Installation and Control Bumer component 30 724 88 816 2.7 modifications* Overfire air (OFA)* 20 459 343 802 2.7 Low-NOx burners 50 2,874 1,176 4,049 13.5 (LNB)* LNCFS It 35 1,028 1,215 2,243 7.5 LNCFS Ut 40 3,595 1,215 4,810 16.0 LNCFS IIIt 50 5,048 1,215 6,263 20.9 Gas rebum 55 1,383 526 1,909 6.4 Fuel lean gas reburn 40 500 289 789 2.6 Selective 35 2,470 235 2,704 9.0 noncatalytic reduction (SNCR) Selective catalytic 75 14,994 320 15,314 51.0 reduction (SCR)l * Wall-Fired: Single wall, 20 burners, 5 burner columns. t Tangentially Fired: Single furnace, five levels of burners. t SCR costs are based on 75% NO, reduction on a unit with furmace exit NO, levels = 650 mg/Nm3 and using aqueous ammonia reagent. Supercritical Pulverized Coal (PC) Plants Steam boiler designs are characterized as "subcritical" or "supercritical," depending on whether steam entering the high-pressure stage of the turbine (main steam) is below or above the critical point of water-about 22.1 MPa-abs (absolute pressure) and 374°C. Because supercritical boilers operate at higher pressures-and generally higher temperatures-than subcritical boilers, they offer higher unit efficiency. Most of the basic systems and equipment are the same for both subcritical and supercritical generating units, except that supercritical steam generators do not use a boiler drum that separates steam from water. Thus, these boilers are often called once-through units. High- energy piping and turbine steam chests are also thicker or of a higher-strength material in supercritical units. The relative difference in plant heat rate between a basic subcritical unit with steam conditions of 16.7 MPa/538°C/538°C and a supercritical unit operating at 24.2 MPa/5380C/565°C is about 4%. If steam conditions in the supercritical plant can be increased to 31 MPa/6000C/600°C/600°C (note: a second reheat step has been added), the heat rate advantage over a conventional subcritical unit reaches about 8%. 10 Technology Assessment of Clean Coal Technologies for China The term ultra-supercritical (USC) refers to supercritical power plants that operate with steam temperatures > 570°C (the majority of today's supercritical plants employ steam temperatures below this level). Ongoing research is aimed at developing double-reheat units that operate at 35 MPal650°C/650°C/650°C, which would produce an efficiency gain of about 11% relative to a conventional subcritical unit. Such a unit would also be 3-4% more efficient than the current state of the art in supercritical units installed in OECD countries. Figure 1 shows very clearly how efficiency improves with higher temperatures and pressures. In countries where the technologies for supercritical power plants are mature, the unit costs ($/kW) are virtually the same as subcritical plants. Thus, selection of a subcritical or supercritical unit often depends on a power producer's experience, the pressure to reduce fuel consumption relative to other considerations, and commercial terms of vendors' bids. For China, in the near term, several key components of supercritical plants would probably need to be imported, such as the high-temperature pressure parts and tubes and materials for piping and the steam turbines. Therefore, the capital cost comparison in China is influenced very much by the relative taxes and tariffs imposed on domestic and imported materials and finished equipment (assuming no additional taxes on erected plants). Figure 1: Heat Rate Improvement from Steam Cycle with Ultra-Supercritical Steam Conditions (single reheat) 9 8 Single Reheat 7 - 593/621 C 7 6 593/593 C ? ~~~~~~~~~~565/593 C 565/565 C E 4- 538/565 C 3 - 538/538 C 2- 1 0* 150 200 250 300 350 Rated Main Steam Pressure (bar) Figures on curve are main and reheat steam temperatures (C) Economies of scale can reduce the unit cost ($/kW) of power plants in the 800-1000 MW range. In addition, there is a modest improvement in steam turbine efficiency and lower percentage heat losses as size increases. Cycle and cost estimates indicate that an 800-MW unit has 1% better heat rate and a 7.5% lower unit capital cost ($/kW) than a 600-MW plant. Several larger units are currently operating in the United States, Europe, and Japan. The reliability and non-fuel operating and maintenance (O&M) costs of supercritical units have improved since the commercial introduction in the early 1980s of new steel alloys with higher allowable stresses and longer life at elevated temperatures. This is borne out in new Executive Summary 11 USC plants, which have proven themselves to be reliable in routine operation. Based on these successes, researchers continue to improve designs and materials, and it appears that USC plants with main steam conditions of 35 MPa and 625°C (or higher) will become fully commercial in the next 5-1 0 years. The same fuels and emission control systems can be used for either supercritical or subcritical plants. All else being equal, the emissions of SOx, NOx, C02, and particulate matter (in terms of mg/kWh of electricity generated) will be lower. for a supercritical plant in proportion to its lower coal usage per kWh (i.e., improved heat rate). Atmospheric Fluidized-Bed Combustion (AFBC) Like conventional pulverized-coal (PC) boilers, atmospheric fluidized-bed combustion (AFBC) units employ a Rankine steam cycle, and, from the exterior, a waterwall-enclosed AFBC unit resembles a PC boiler. The most common AFBC designs now add a large cyclone between the furnace and the convective heat transfer sections to recirculate unburned fuel back to the bed, where the remaining carbon can be burned; these systems are called circulating fluidized-bed combustors (CFB) to distinguish them from the earlier bubbling bed configurations. Inside the furnace, the differences from PC boilers become apparent. AFBC boilers burn a non-pulverized fuel in a fluidized bed and operate at lower temperature than PC units. This low combustion temperature limits the formation of NO, and optimizes in-situ capture of SO2 by free lime (see below). The low temperature also prevents or limits the slagging of coal ash, thus greatly reducing slagging and fouling of heat transfer surfaces. Further, AFBC systems are capable of buming high-ash coals and other low-rank fuels that cannot be accommodated by PC units. In SO2-capture applications, coal and limestone are fed into a bed of hot solid particles that are suspended in turbulent motion (fluidized) by combustion air blown in from below through a series of nozzles. The limestone is converted to free lime, a portion of which reacts with SO2 to form calcium sulfate (CaSO4). Therefore, the limestone sorbent requirement and spent sorbent tonnage for solids disposal are 50-100% higher than for PC plants with flue gas desulfurization (FGD). For low-sulfur coals in which SO2 capture is not required, sand is used as the bed material in place of limestone. For some high ash-coals, the ash itself may provide sufficient bed mass without the addition of sand. Also, coals with a high calcium content in the ash and needing only moderate SO2 removal often do not need to have limestone added to the bed. Because of the high recycle rate (high residence time) of unutilized sorbent and unburned carbon, CFB provides better SO2 capture and better carbon burnout than bubbling bed designs. CFB also allows more effective air staging for improved NO, control and is less prone to upsets due to fuel quality variation. Consequently, atmospheric pressure CFB is the predominant type of FBC boiler installed worldwide in unit sizes above 90,000 kg per hour of steam. Burning all kinds of fuels, AFBC plants have demonstrated high availabilities, heat rates comparable to PC boilers with FGD, 90-95% in-situ SO2 capture, low NO, emissions (60-240 12 Technology Assessment of Clean Coal Technologies for China mg/Nm3 without postcombustion controls), fuel flexibility, and the ability to burn high-ash slagging/fouling fuels that would be problematic in pulverized-coal boilers. Thus, with regard to air emissions, AFBC is environmentally competitive with PC boilers equipped with low- NOx burners, SCR, and FGD. Depending on coal quality and combustor design, the AFBC system may need SNCR to reach the lowest NO, control levels achievable by a PC plant with SCR. However, an AFBC system's spent sorbent tonnage typically exceeds that of a PC plant with FGD, and disposal costs are sometimes greater due to the large volume and its higher reactivity. Depending on a number of project-specific factors, AFBC may also be economically competitive with PC boilers. The competitiveness of AFBC increases with decreasing fuel quality and sulfur content. Since the late 1980s, numerous independent power producers, or IPPs (with contractual availability incentives), industrial cogenerators/self-generators (with strong incentives for high availability to keep their production facilities operating), and utility owned and operated plants have consistently achieved FBC availabilities and annual capacity factors in the 80- 95% range. Pressurized Fluidized Bed-Combustion (PFBC) Pressurized FBC combines the combustion benefits of FBC with the efficiency gains of combined cycles. In a PFBC, the pressurized hot flue gas, after particulate removal, is expanded through a gas turbine to drive the combustion air compressor and generate additional electric power. Typically, pressures in the range of 1.2-1.6 MPa are employed, which correspond to the pressure ratios of conventional heavy-duty combustion turbines. Both bubbling and circulating PFBC are being developed, but currently all commercial units are of the bubbling-bed design. The main advantages of pressurized FBC are that: * An additional 20% or more net electric power output can be generated with a 6% or better improvement in plant heat rate * A more compact boiler may result * Carbon burnout and sorbent utilization are improved In principle, any atmospheric pressure FBC technology can be designed for pressurized operation; consequently, there are bubbling PFBC and circulating PFBC classifications. ABB Carbon, Mitsubishi Heavy Industries (MI), and Hitachi Ltd. have developed PBFB technologies, while Lurgi Lentjes Babcock (LLB, the Lurgi-Deutsche Babcock partnership) and Foster Wheeler (now incorporating Ahlstrom Pyropower) are developing PCFB technologies. To date, development of these PCFBs has not progressed beyond the pilot plant stage. Six commercial-scale bubbling PFBC units have been put into service around the world. However, most of these boilers are demonstration units, with financial support from government or international agencies, and all but one are less than 100 MW,. At this smaller size, with the accompanying dis-economies of scale, PFBC is likely to be limited to smaller niche markets, such as heat and power (e.g., district heating) applications. Scale-up of the technology to 350-400 MW must be demonstrated before PFBC can be more widely Executive Summary 13 deployed. At this larger size, supercritical steam turbines can be used, and PFBC would then be in a much better position to compete with super-critical PC plants in the larger power plant market. A 360-MW supercritical PFBC based on the ABB technology and a 250-MW subcritical unit based on the Hitachi technology have been constructed in Japan and are scheduled to complete commissioning in mid-2000. The operating experience obtained from these units will have a strong influence on the future of commercial PFBC technology. PFBC systems are well suited for China because of their ability to cleanly burn high-ash, low- volatile, and/or high-sulfur coals. They offer a competitive alternative to supercritical plants with FGD and SCR, and would provide China with a coal-to-electricity source that is clean enough to permit economic expansion while also improving environmental conditions. Once developed and adequately demonstrated as a reliable technology, there should be no technical constraints to their application in China. In fact, with China's experience of 18 years investigating this technology, one can expect its engineers to continue gaining experience together with the international community and contributing to the development of the technology. At comparable steam cycle conditions, PFBC offers a heat rate improvement over AFBC or PC units of about 5%. Large units operating with a supercritical steam cycle would have even better heat rates. All emissions would, therefore, be reduced by comparable amounts over those from AFBC. In addition, the CO2 emissions from PFBC are less than those of a comparable-sized AFBC since no CO2 is produced from calcination of the excess limestone. The capital cost shown in Table ES-1 is for a mature 350-MW single-boiler PFBC plant based on the ABB bubbling-bed technology with standard subcritical steam conditions of 16.7 MPa/538°C/538°C. That cost figure is higher than the estimate for comparable AFBC and PC plants, due largely to a higher percentage of imported equipment components and materials. Integrated Gasification Combined Cycles (IGCC) The integrated gasification combined cycle (IGCC) allows the use of coal in a power plant that has the environmental benefits of a gas-fueled plant and the thermal performance of a combined cycle. In its simplest form, coal is gasified with either oxygen or air, and the resulting raw gas (called syngas, an abbreviation for synthetic gas) is cooled, cleaned, and fired in a gas turbine. The hot exhaust from the gas turbine passes to a heat recovery steam generator (HRSG) where it produces steam that drives a steam turbine. Power is produced from both the gas and steam turbine. By removing the emission-forming constituents from the gas under pressure prior to combustion in the power block, an IGCC can meet extremely stringent air emission standards. IGCC plants have been developed to commercial size over the past two decades, but have only been built and operated as demonstration plants. These units have now accumulated several years of operating experience and have shown that they can meet extremely stringent air emission standards while also achieving high plant efficiencies. The main barriers to the widespread adoption of IGCC technologies are: (1) demonstration of high availability, at least 14 Technology Assessment of Clean Coal Technologies for China equal to existing PC plants; and (2) high capital cost relative to state-of-the-art PC plants and natural gas-based combined cycles. There are many variations on the basic IGCC scheme, especially in the degree of integration. The five commercial-sized, coal-based IGCC demonstration plants in operation each use a different gasification technology, gas cooling and gas cleanup arrangement, and integration scheme between the plant units (mostly in the source of compressed air for the air separation unit [ASU]). While a more highly integrated design gives higher plant efficiency, it currently suffers from a loss of plant availability and operating flexibility. The general consensus among IGCC plant designers today is that the preferred design supplies part of the air supply to the ASU from the gas turbine compressor and part from a separate dedicated compressor. The electric output of an IGCC plant is largely determined by the firing temperature (- 1 100°C or - 1260°C) of the gas turbine and frequency of the electricity produced. The net total output for single-train IGCC plants would be - 275 MW in the U.S.(60 Hz) and - 400 MW for Europe and China (50 Hz). Plant net efficiency is typically 43-46% on an LHV basis. By removing the emission-forming constituents (sulfur and nitrogen species and particulates) prior to combustion in the gas turbine, IGCC plants meet extremely stringent air emission standards. Sulfur emissions can be almost completely eliminated; SO2 emissions are expected to be 40-115 mg/Nm3 at 6% 02 (expressed on an equivalent basis to PC plants rather than on a 15% 02 basis as is common for combustion turbines). NO, emissions have been controlled to levels below 125 mg/Nm3 (at 6% 02) at two of the demonstrations using steam or nitrogen dilution in the combustor and half that level at two other sites operating at lower combustion turbine temperatures. Recently, GE has claimed that they can meet a level of 60 mg/Nm3 even with their 1260°C series FA gas turbine. CO2 emissions will be proportionate to coal usage -- i.e., about 15% lower than from a comparable size PC plant without FGD and even better when compared to a PC plant with FGD (due to the CO2 liberated when the limestone is converted to lime in the FGD, as well as to the CO2 generated by the power plant to replace the auxiliary power consumption of the FGD). In principle IGCC plants can be designed to handle the range of coals in China. However, the high ash content of many Chinese coals require the use of fluidized-bed gasifiers, and these gasifiers are at a much earlier stage of development than entrained flow systems (such as Texaco, Destec, Shell, and Krupp-Uhde Prenflo). Although much of the gasification, heat exchange, and gas cleanup equipment can be manufactured in China, the major components of the air separation unit and gas turbine would currently have to be imported. As the technology matures and Chinese manufacturing adopts practices used in the OECD countries, the IGCC capital costs in China should be reduced. The IGCC plant cost in Table 1 is for a single-train plant of - 400 MW plant using the Shell gasification process integrated with a GE 9FA gas turbine combined cycle. In other IGCC, EPRI has been found that the total plant cost for a two-train IGCC plant (800 MW) would be about $150/kW lower. Cost estimates by others for IGCC plants based on the newer G and H Executive Summary 15 gas turbines suggest that these units could cost $100-$200/kW less; however, these estimates must be treated with caution until the performance of the new turbines is confirmed. Utilization of Fly Ash and By-products from SO2 Controls China now reuses 50% of its coal ash in productive uses. The utilization potential is generally not limited by technological barriers or lack of understanding of the use options. Rather, barriers to greater use of coal ash are low disposal costs, wide availability of natural materials, and long distances (high transportation costs) from the point of production to the point of use. An opportunity for greater utilization of fly ash despite these barriers comes from research in the United States and Canada that is demonstrating the technical feasibility and benefits of using up to 60% low-calcium fly ash as replacement for portland cement in the manufacture of concrete, a much greater percentage than the current practice of < 20% replacement.. In contrast, FGD by-products are not widely reused, as the very limited number of SO2 control systems in China has prevented the establishment of use patterns for their by-products. Disposal costs are likely to increase in China, as they have in the OECD countries, which should make the economics of utilization more favorable. The utilization potential of wet FGD sludge is related to its quality and characteristics. Producing a useful by-product from FGD sludge often requires additional processing, such as forced oxidation (usually within the SO2 absorber reactor in the limestone forced oxidation systems) or fixation/stabilization. Oxidizing FGD sludge allows it to compete for the current uses of naturally occurring gypsum: (1) wallboard production, (2) cement production, and (3) agricultural use. While synthetic gypsum (gypsum produced from FGD sludge) can be purer and more consistent in quality than natural gypsum, power plants must have higher efficiency particulate collectors than most do now in China to achieve this result. Fixing or stabilizing FGD sludge (by adding dry fly ash, soil, etc., to reduce its moisture and improve its handling characteristics) can enhance its physical properties for structural uses such as: (1) structural fill, (2) road construction, (3) soil stabilization, (4) liner cap material, (5) artificial reefs, and (6) mine reclamation. The by-products generated from dry CCT processes (dry SO2 controls and fluidized-bed combustion systems) have physical properties similar to those of conventional fly ash but chemical properties that are somewhat different due to the alkaline reagents. These properties suggest that the materials could be used in highway construction, mining, soil amendment, etc. However, the property differences also mean that by-product managers will need to change some utilization practices relative to fly ash alone. The exact composition of a by-product is determined by the type of sorbent or reagent, where the sorbent/reagent is added (boiler or post-furnace), and the coal constituents. The primary components include fly ash, unspent sorbent (lime, limestone, or dolomite), and reaction products (calcium sulfate/sulfite). The high percentage of fly ash in the by-products gives it its pozzolanic nature, while the unreacted lime or limestone contributes to its self-hardening characteristics. II I~~~~~~ Introduction 1.1 Coal and the Environment in China China's transition to a market economy, which has been proceeding for two decades, places it among the world's five fastest-growing economies. While economic expansion has increased incomes and improved health indicators, as well as reduced overall poverty levels, this growth has not been totally benign. Economic growth has been fueled by increased coal combustion, which has serious environmental impacts. Pollution from coal combustion is damaging human health, air and water quality, agriculture, and, ultimately, the economy itself. A report released in 1998 by the World Health Organization (WHO) noted that seven of the ten most polluted cities in the world are in China. Sulfur dioxide (SO2) and soot or other fine particles caused by coal combustion are the two most important airborne pollutants in terms of quantities present in the air and their impacts on health and the economy. According to studies carried out by the Chinese government, the World Bank, the Asian Development Bank (ADB), and others, environmental degradation in China is contributing to: * A reduction in agricultural productivity of up to 25% due to acid rain, especially in South and East China. Acid rain now falls on over 40% of China's total land area and is caused primarily by SO2 emissions from coal combustion. Acid rain is also caused by nitrogen oxide, or NOx, emissions from coal combustion, which contribute to smog as well. * Loss of more than seven million person-work-years annually due to air pollution- related diseases * Mortality rates five times higher than in the United States due to cardiopulmonary diseases caused by pollution, especially indoor air pollution from burning coal In recent years, China has made progress in improving air quality in many cities through residential fuel-switching programs and industrial emissions control. However, ambient air concentrations of particulates, SO2, and other air pollutants are still two to five times higher than WHO-recommended maximum levels. 17 18 Technology Assessment of Clean Coal Technologies for China 1.2 Environmental Improvement Opportunities Coal is China's chief energy source, accounting for 74% of primary energy consumption. Given the nation's abundant coal reserves and emphasis on development using indigenous resources, coal will remain the dominant fuel well into the 21lt century. China expects its economy to grow at an average rate of 7% or more per year over the next decade. If a constant ratio of primary energy to gross domestic product (GDP) is assumed for this period, primary energy consumption would nearly double, meaning that the electric generating capacity in particular would need to increase by 17-20 GW each year. However, analysts expect China to be able to make continued improvements in the efficiency of energy production and use, thereby further decoupling the traditional relationship between GDP and energy consumption. The country has already cut its energy-to-GDP ratio by 50% over the last 20 years; the Ministry of Electric Power projects a value of about 0.65 kg of coal- equivalent per yuan of GDP for 2000. Environmentally acceptable economic growth is closely linked with further improvements in the overall efficiency of energy use. Both of these goals will require a continued increase in the use of coal to produce electricity, along with a more deliberate and rapid transition from direct coal combustion to the use of electricity and other cleaner coal-based fuel sources, especially for cooking, space heating, and industrial furnaces. Completion of the ongoing program to replace the many small power boilers with new, larger, more efficient plants equipped with modem pollution controls will also help China achieve these objectives. At the same time it will be essential to replace the many inefficient, polluting coke-making ovens and industrial gasifiers with newer, cleaner technology. These changes are vital because about 60% of coal production is currently consumed by these inefficient technologies, which emit their pollutants at low heights where they have greater direct impact on people's health. The opportunity for environmental improvement in conjunction with economic growth lies in the wise adoption of clean coal technologies (CCT) for both the electric power and non-power sectors. CCT options for the power sector include: * Air pollution control equipment - For particulates (also called "dust")-conventional electrostatic precipitators (ESPs), and in some cases wet ESPs and bag-filter technologies - For S02-conventional and simplified wet scrubbers and spray dryers, various sorbent injection processes, and E-beam technology - For nitrogen oxides (NO)-burner tuning and optimization and various combustion modifications (e.g., low-NO, burners and overfire air) that minimize NO, formation, and postcombustion controls that chemically reduce NO, to molecular nitrogen (e.g., selective catalytic and non-catalytic reduction) * Advanced power generation processes that convert fuel to electricity and heat more efficiently and with less environmental impact than current boilers. Introduction 1 9 Applicable technologies include: - Supercritical pulverized-coal boilers - Atmospheric fluidized-bed combustors (AFBC) - Pressurized fluidized-bed combustors (PFBC) - Integrated gasification combined cycle (IGCC) systems CCT options for the non-power sector include: * Town gas or less-polluting coal briquettes to replace direct burning of "lump" or raw coal in homes for heating and cooking * Advanced gasification processes, whether for the production of town gas for use in residential and commercial buildings or for the production of feedstocks in chemical plants (especially ammonia-based fertilizer manufacturing) * Replacement of beehive and other older coke-making processes with newer, more- efficient, less-polluting technologies * Improved (less-polluting) processes for manufacturing more durable, cleaner-burning, and lower-cost briquettes 1.3 Study Objectives The primary objective of the overall project is to assist policy makers and enviromnental planners in choosing the most appropriate clean coal technologies and environmental control options. This assistance is provided in three ways: * A two-volume technology assessment report on clean coal technologies: - Technology Assessment of Clean Coal Technologies for China: Volume 1- Electricity Power Production - Technology Assessment of Clean Coal Technologies for China: Volume 2- Environmental and Energy Efficiency Improvements for Non-power Uses of Coal * Development of an approach for conducting a systemwide analysis of a province or region that yields a least-cost plan for meeting alternative environmental objectives under several energy development scenarios. This computer model-based approach has been applied to Hunan province as a case study, and the results are presented in a companion report prepared by the SP Power Economic Center. * A technology dissemination program for Chinese decision makers. This program aims to improve their understanding of the various options through (1) a workshop held in China at the conclusion of this study and (2) a tour to sites in Japan that are operating CCTs. 20 Technology Assessment of Clean Coal Technologies for China 1.4 Technology Assessment Methodology The two-volume technology assessment report synthesizes the experience and extensive in- house information collected over the years by the study team. The team was led by EPRI which provided the majority of the technical input and prepared the report. The report incorporates input received from all the technology partners in the project: EPDC International and Tokyo Electric Power Company (TEPCO) on CCTs in use or under development in Japan, as well as on two simplified SO2 control processes just recently demonstrated by EPDC-vendor consortia and turned over to their Chinese plant operators; and the Thermal Power Research Institute (TPRI) in Xi'an and the Nanjing Environmental Protection Research Institute (NEPRI) on recent experience with CCTs in China. The study team supplemented its information base by visits to China to (1) inspect several technology demonstrations and (2) discuss the readiness of Chinese boiler and turbine manufacturers to supply advanced generation processes. This report describes each CCT with particular reference to conditions in China (boiler types, fuels used, etc.), discusses its commercial readiness and applicability to China, presents its environmental performance and any impacts on the power plant, and then provides estimated costs for applications in China. In any project that compares costs of competing technologies, it is essential to provide consistency in the cost estimates. A methodology developed by EPRI, the Technical Assessment Guide (TAG), serves this function and is therefore widely used by technology analysts within government and the private sector in the United States, as well as internationally. While the costing methodology used here is specific to this study, the TAG methodology was used as a guideline. That is, the cost estimates were first developed using TAG models that approximate costs for plants at a Midwestern U.S. location. These costs were then converted to conditions applicable to China by factoring in differences in labor costs, relative prices of manufactured items, import duties, value-added taxes (VAT), etc. 1.5 Organization of This Report The project costing methodology is explained in Section 2. Each electric power CCT option is presented in Section 3. Because of the importance of making changes to the non-power sector in order to achieve significant environmental improvements without sacrificing China's reliance on coal, a discussion of these opportunities is presented in Volume 2. That volume was prepared entirely by the China Coal Processing and Utilization Association (CCPUA), with EPRI providing only an editorial function. A summary of coal production and use in China prepared by CCPUA as part of their report is presented here as Appendix A to provide a bridge between the two volumes. Formerly known as the Electric Power Research Institute, EPRI is a United States-based organization that conducts research and development programs for the energy industry worldwide. 2 Reference Plants This section reviews the methodology for developing consistent reference plant designs, capital cost estimates, and performance estimates for the clean coal-based power generation technologies evaluated in this study. Two reference plant designs-one 300 MW, the other 600 MW-are provided to help calibrate the estimates for new technologies. The reference designs are conventional pulverized-coal-fired generating units without SO2 controls. Evaluation of the new clean coal power-generating technologies is based on the use of the same site conditions, coal type, fuel storage, and duty cycle as the reference pulverized-coal plant designs. Sections 2.1 and 2.2 discuss the reference designs. The costing methodology is specific to this study for China, although EPRI's Technical Assessment Guide (TAG) methodology was used as a guideline. That is, the cost estimates were first developed using EPRI models that approximate costs for plants at a Midwestern U.S. location. These costs were then converted to conditions applicable to China by factoring in differences in labor costs, relative prices of manufactured items, import duties, value-added taxes (VAT), etc. Section 2.4 describes the methodology used to estimate costs for the U.S. plant, while Section 2.5 explains how these costs were converted to conditions prevailing in China. 2.1 Design Basis This section defines the design guidelines used in this study. Unit Duty Cycle/Availability The power plants that are described in this report are assumed to be baseloaded. For economic evaluations, baseload plants have a nominal capacity factor of 65%. However, the clean coal technologies described in this report are capable of achieving equivalent plant availability of up to 85%, including planned maintenance. Unit Size Arbitrary differences in unit sizes among competing technologies should be minimized to ensure consistency in generation-system planning studies. For certain technologies, such as 21 22 Technology Assessment of Clean Coal Technologies for China integrated gasification combined cycle or pressurized fluidized-bed combustion, the net plant output is dictated by the size of commercially available gas turbines. Unit Cost Boundary The generating unit boundary includes the area in which all of the unit components are located. The cost within this boundary includes all major parts of the unit (the boiler, turbine generator, etc.) and all support facilities needed to operate the plant (shops, offices, cafeteria, fuel-handling and storage equipment, water intake structures, and waste treatment facilities). It also includes the high-voltage bushing of the generation step-up transformer but not the switchyard and associated transmission lines. The switchyard and transmission lines are generally influenced by transmission system-specific conditions and hence are not included in the cost estimate. Ambient Conditions Although ambient conditions vary greatly from site to site, the following average Midwestern U.S. site conditions are used in this study for consistency: Average dry bulb temperature = 1 5°C Average wet bulb temperature = 1 1°C Ambient pressure = 0.99 bar Cooling Water System Mechanical-draft cooling towers are used in all cases. The design cooling water temperature range for this study is 24° to 35°C. This assumes a minimum 6°C cooling water temperature approach to the wet bulb temperature. Fuel Systems Coal is assumed to be delivered by unit train with rotary-dump hopper cars. The fuel storage capacity for these baseload plants is designed for a 60-day supply at 100% capacity factor. Water Analysis A river for raw water supply is assumed to be located within 10 km of the site. Startup Facilities It is assumed that electric power is available at the site for startup purposes. Other facilities needed for startup are included in the design and cost estimate. Unit Emissions Emission limits in China are currently 200 mg/Nm3 for particulates in urban areas and 650 mg/Nm3 for NO,, from dry-bottom boilers. Units firing anthracite have less-restrictive NO,, requirements but more-restrictive particulate limits. For SO2, current Chinese regulations Reference Plants 23 place no emission limits on boilers firing a coal with less than 1 % sulfur content. For higher- sulfur coals, the regulations use a formula based on construction date (pre August 1992, post 1996, and in between), location (urban, rural plain, rural other), typical meteorology, and stack height to calculate an allowable emission limit. For the reference plants and reference coal (S = 0.63%), no SO2 controls were considered for the pulverized coal (PC) subcritical and supercritical plants, 90% SO2 removal was assumed for the atmospheric and pressurized fluidized-bed combustors, and nominal outlet emissions of 10 mg/Nm3 were assumed for the integrated gasification combined cycle (IGCC) plant. Cost estimates for the electrostatic precipitators were developed on the basis of the size needed to meet the 200 mg/Nm3 urban limit; again, the nature of the IGCC process, with its internal contaminant removal systems, led to a much lower particulate level of <10 mg/Nm3. NO, emissions were set at 500 mg/Nm3 for the PC plants based on experience in OECD countries with the use of just low-NO, burners (LNB) in new boilers-i.e., no additional controls such as overfire air. For the advanced generation processes, the NO, emissions are those projected for these technologies. Therefore, these various plants are not directly comparable from an environmental perspective. Costs for any additional pollution controls, such as SO2 removal systems, larger electrostatic precipitators to reduce particulate emissions, retrofit LNB or controls beyond LNB, etc., are discussed in Section 3 under each technology. 2.2 Design Basis for Reference Plantss The reference plant designs for this study are based on a greenfield facility at a Midwestern U.S. location. The site is assumed to be clear and level with no special problems. Plant performance is based on the use of Shaanxi coal (Shenmu mine) from China with the following as-received properties: Heating value = 22.87 MJ/kg (LHV) Moisture = 16.45% Ash = 7.19% Sulfur= 0.63% Other general study criteria are as follows: * Performance is evaluated at an ambient temperature of 15°C and a condensor pressure of 6.75 kPa. * The site is in Seismic Zone 2A, per the U.S. Uniform Building Code (i.e., a modest seismic risk) at an elevation of 180 meters above sea level. * Soil conditions are assumed to require the use of pile foundations. * Equipment sizing and sparing is based on an equivalent availability of 85%. * Equipment is designed for a 30-year plant life. * Coal is delivered to the site by rail. 24 Technology Assessment of Clean Coal Technologies for China * Limestone (94.1% CaCO3) is delivered to the site by rail. * On-site emergency ash storage is sized for 90 days. Final disposal is off-site. 2.3 Reference Pulverized-Coal Power Plants The major components of the reference power plants described in this report (300 MW and 600 MW subcritical pulverized-coal plants) include the coal-handling equipment, steam generator island, turbine generator island, electrostatic precipitator, bottom and fly ash handling system, and stack. The cost and performance data include low-NO, burners. As noted earlier, the reference plants do not include SO2 controls; performance and cost information for SO2 controls are presented in section 3.2 The steam generator island includes the coal pulverizers, burners, waterwall-lined furnace, superheater, reheater, economizer, soot blowers, Ljungstrom air heater, and axial-flow-forced and induced-draft fans. The steam conditions are 17 MPa/540°C superheated steam, with a single reheat to 5400C. The turbine generator island includes the main, reheat, and extraction steam piping, feedwater heaters, condenser, mechanical draft cooling towers, boiler feedpumps, and auxiliary steam generator. The steam turbine is a tandem-compound unit, designed for constant-pressure operation with partial arc admission. The feedwater heating system uses two parallel trains of seven heaters, including the deaerator; the boiler feedpumps are turbine-driven. The condenser is designed to operate at 6.75 kPa backpressure. 2.4 Cost-Estimating Basis For cost-estimating purposes, technologies are generally assumed to be in a mature state of development, meaning that no extra equipment or costs are included to account for unit malfunction or extra equipment outages, except for spare equipment typically provided as part of the normal plant design. Also, costs associated with extra facilities needed for demonstration of first commercial plants are not normally reflected in the cost estimates. 2.4.1 Capital Investment Capital cost components are defined in the following paragraphs. Because of the limited scope of the study, the following components are described for illustration only. The specific details of the estimate breakdowns used as a basis for this study are not provided. Total Plant Cost The total plant cost (TPC) is the sum of the following: Process facilities capital General facilities capital Reference Plants 25 Engineering and home office overhead including fee Project and process contingencies TPC is developed on the basis of instantaneous, overnight construction (occurring at a single point in time) and is expressed in mid-1999 dollars for this study. Process Facilities Capital Process facilities capital is the total constructed cost of all on-site processing and generating units, including all direct and indirect construction costs. All sales taxes (value-added tax, or VAT, for the case of China) and freight costs are included where applicable. The process capital cost is divided into major generating components (e.g., fuel storage, combustion systems, emission control systems, and generators). In addition, the total process capital for each generating unit component is broken down into factory materials (or engineered equipment), field materials, and installation labor. General Facilities Capital General facilities capital is the total construction cost of the general facilities, including roads, office buildings, shops, laboratories, etc. Fuel, chemicals, and by-product storage systems are included in the process facilities capital costs, not as part of the general facilities. VAT and freight costs are included where applicable. Engineering and Home Office Overhead Including Fee The estimate includes the engineering and home office overhead and fee that is considered representative of the type of generating or storage unit in the study. Contingencies Two types of contingencies are generally included: the project contingency and the process contingency. The project contingency is intended to cover the uncertainty in the cost estimate itself, whereas the process contingency covers the uncertainty in the technical performance of the equipment. In both cases, the contingencies represent costs that are expected to occur. For this study, the project contingency used reflects the complexity of the various technologies. Because the costs were developed for mature configurations of each technology-i.e., it was assumed that the plant would achieve the rated performance in the configuration that was costed-no process contingencies were included in the total costs. 2.4.2 Operating and Maintenance Costs Operating and maintenance (O&M) costs are estimated for a typical year of normal operation and presented in mid-1999 dollars. O&M costs include operating labor and total maintenance costs. 26 Technology Assessment of Clean Coal Technologies for China Fixed O&M Costs Fixed operating costs are composed of the following components: Operating labor, based on experience or estimates for each generating technology Total maintenance costs (including labor and materials), calculated as a fixed annual percentage of capital costs Variable O&M Costs Consumables are the principal components of variable O&M costs. These include water, chemicals, and other materials that are consumed in proportion to energy output. By-product credits (if any) are subtracted from the consumables cost. 2.5 Methodology for Converting Costs from U.S. to China The total plant cost for the reference plants is broken down into engineered equipment (or factory materials), field materials, and installation labor as described in Section 2.4. Further classification of equipment and material costs as imported or locally available is required before the costs can be converted to a China basis. The allocation of equipment and materials is based on knowledge of China's procurement practices and domestic manufacturing capabilities. The exchange rate assumed throughout this study is 8.3 yuan per U.S. dollar. The cost for imported equipment and materials includes the following items that are added to the world price of imported equipment to obtain the total cost delivered to the job site in China: Duty and customs fees at the host location. Assumed to be 6%. Freight cost from shipping plant to dock, ocean freight, unloading, storage, and delivery to plant location. Assumed to be 10%. Value-added taxes imposed by the host country. Assumed to be 17%. Other taxes imposed by national or local government. Assumed to be zero. Locally supplied equipment and material is discounted by a factor of 0.7 from the cost at the reference plant location in the U.S. Midwest. China also includes 17% value-added taxes on domestically supplied items. The following inputs are required in order to adjust the cost of installation labor: * The weighted average craft rate for a construction worker, assumed to be 25 yuan/hour ($3.00/hour), including benefits. * The relative productivity of labor in the country relative to labor at the base location (Midwest U.S.) for open-shop operation. This reflects typical labor practices and skills as well as the availability and use of labor-saving construction tools and equipment in the host country. The factor for this study is assumed to be 3.0. These labor rate and productivity assumptions are highly uncertain. During the course of this study, information on typical all-in construction labor costs for power projects in China were Reference Plants 27 obtained from many sources, including the World Bank, equipment vendors, process developers, and architect/engineering firms. Wage rates varied from a low of $1.00/hour (excluding benefits) to a high of $8.00/hour (including benefits and other indirect labor costs). Benefits such as housing and medical can add approximately 50% to the direct hourly labor cost. Productivity factors varied from a low of 2.5 to as high as 7 or 8. Productivity multipliers relative to the base location are typically higher for civil/structural crafts and lower for more skilled crafts such as welding. The current wage rate and productivity assumptions lead to an overall labor cost for a power project in China that is only about 20% of the labor cost for a similar plant constructed in the United States. Using the low range of wage rates and productivity factors would result in China's labor cost being less than 10% of the U.S. cost, while use of the high range would result in China's labor cost being as much as half of the U.S. labor cost. The higher overall labor costs are more representative of a project financed by a foreign company, which would include a much greater percentage of imported supervision. A project financed and constructed by local Chinese companies would typically employ lower-cost domestic supervision. Average wage rates for power plant operators in China are typically about 20-30% higher than average wage rates for construction labor. However, productivity multipliers are generally lower than for construction labor due to use of more skilled labor. These factors tend to be offsetting, resulting in about the same overall net hourly wage rates for plant operators and construction labor. The overall net hourly wage rate is the product of the base wage rate (including benefits and other indirect costs) and the productivity multiplier. Approximately half of the fixed O&M cost is derived from the overall net hourly operating wage rate. The cost for maintenance labor and materials comprises the other half of fixed O&M and is based on a fixed annual percentage of capital cost. Since the adjusted capital cost already includes the effect of lower Chinese labor rates, we have assumed that the maintenance percentage remains the same as for a U.S. plant and have not included any other adjustments. Costs for consumable items such as coal and limestone are calculated based on the quantity of material needed and the local cost of the item in China. Some of the China-specific cost assumptions are as follows: Water cost is assumed to be zero. Limestone cost is 175 yuan/tonne. Solid waste disposal cost is 20 yuan/tonne. Delivered coal cost is 242 yuan/tonne. Rural land cost is 50,000 yuan/667 square meters. Sulfur by-product credit is 274 yuan/tonne (applies to gasification power plants only). 2.6 Cost of Reference Plants in China Table 2.1 gives the cost and performance of the reference plants. 28 Technology Assessment of Clean Coal Technologies for China Table 2.1: Reference Plant Emissions, Heat Rate, and Costs Generation System Emissions Heat Rate Costs-" (Shenmu Coal, 0.63% S) Rate (kJ/kWh, Capital Fixed O&M Variable (mg/Nm3)/ LHV) ($/kW) ($/kW-yr) O&M (mills/kWh) 300-MW subcritical PC S02 = 1540 9400 665 17.4 0.3 plant, no FGDt NO, = 500 TSP = 200 600-MW subcritical PC Same 9210 548 14.4 0.3 plant, no FGD t PC = pulverized coal; FGD = flue gas desulfurization (SO2 scrubber) t TSP = total suspended particulates (i.e., fly ash) : Costs are for applications in China. Capital costs exclude AFUDC (Allowance for Funds Used During Construction) and "owners costs" (royalties, land, and initial inventory of all consumables or replaceable items). O&M costs are for first year. O&M costs are first year costs. 3 Power Generation and Environmental Control Technologies This section describes technologies that could be used in China to reduce emissions from existing coal-fired boilers or to produce heat and electricity from new coal-fueled energy conversion systems with less environmental impact than current plants. These "clean coal technologies" would serve two functions: (1) improve the current quality of the air in affected regions, and (2) allow China to expand its industrial economy while simultaneously improving the health and environmental conditions of its people and its natural resources (especially timber and agriculture). As much as 60% of the coal used in China is consumed by the non-power sector, such as residences, commercial facilities, and industry. Therefore, this report devotes a separate volume to that sector, discussing technologies that could replace or improve current coal- burning systems at greatly reduced environmental impact (see Volume 2, Environmental and Energy Efficiency Improvements for Non-power Uses of Coal). The technologies discussed here in Volume 1 are either environmental control systems that can be added to existing and new pulverized-coal (PC) fired boilers, or advanced combustion systems that generate electricity and heat more efficiently and/or with less air emissions than current boilers. The environmental focus of is on air emissions, although the impact of these technologies on water discharges and solid by-products is also discussed. Thus, the first three subsections describe controls for particulate, SO2 and NO, emissions, respectively, while the next four subsections present information on supercritical boilers, atmospheric fluidized-bed combustors, pressurized fluidized-bed combustion systems, and integrated gasification combined cycle plants. The following subsection provides an overview of potential uses for the solid by-products generated by the SO2 control technologies and advanced generation systems, because these by-products are new to China. In contrast, China already uses about 50% of the fly ash collected from power plants. When assessing one of the technologies that produce these new by-products, the analyst and decision maker should consider the use or disposal of the solid by-products. The word "by-product" (rather than waste) is used very deliberately here to refer to these solid discharges; they have commercial uses, and the environment benefits when they are used that way. 29 30 Technology Assessment of Clean Coal Technologies for China The final subsection summarizes cost and performance information for supercritical boilers, AFBC, PFBC, and IGCC, and compares these to current designs of pulverized-coal boilers with and without SO2 controls. The discussions of each technology are intended to serve two purposes: (1) to provide input into the Task B energy-economic-environmental assessment of energy development scenarios for Hunan province conducted by the SP Power Economic Center in Beijing; and (2) to inforrn decision makers and policy planners who are considering the adoption of new technologies as part of an energy development plan. As such, the discussions are designed to present an overview of the technology and the key issues associated with its use-energy and environmental performance; worldwide experience and readiness for application; ease of adoption in China; impacts on heat rate, other emissions, or plant availability; and, of course, costs. The discussions are not intended to be in-depth handbooks or detailed technology references for engineers charged with procuring, designing, or operating these systems. 3.1 Particulate Controls Particulate control options for both retrofit and new power generation technologies fall into three general categories: (1) mechanical collectors, (2) electrostatic precipitators, and (3) fabric filters. Mechanical collectors (e.g., cyclones), which can have either wet or dry designs, are simple and reliable but require a high operating pressure drop to achieve a high level of performnance. Further, these collectors do not provide the high collection efficiency required to meet increasingly stringent emission standards. Both electrostatic precipitators (ESPs) and fabric filters can produce extremely high collection efficiencies, and both devices are reliable. The choice of a particulate control device is influenced by the composition of the coal, the nature of the combustion process (pulverized-coal firing, circulating fluidized-bed combustion, etc.), and the required emission limit. Today's limits are low enough that mechanical collectors are no longer a viable option and thus will not be discussed. On the other hand, fabric filters, including conventional and pulse-jet cleaning designs, can meet the most stringent emission limits worldwide, less than 50 mg/Nm3. Assuming they are in good mechanical condition, fabric filters have inherently high collection efficiencies. Electrostatic precipitators can be designed to meet very low emissions limits as well, since collection efficiency depends on their size. All of these factors, including the effect of the emission limit on electrostatic precipitator size, are discussed below. 3.1.1 Technology Descriptions Electrostatic Precipitators Electrostatic precipitators (ESPs) can be either a dry or wet design. Dry designs are universally used in the utility industry for fly ash control. There is a long history and very large data base for this application, and, as noted later, the dry precipitator is the most attractive particulate control option for most situations considered in this report. However, for the plants in China that are currently using a wet particulate scrubber for fly ash removal, conversion to operation as a wet electrostatic precipitator might also be a viable option. Power Generation and Environmental Control Technologies 31 Figure 3.1: A Conventional Electrostatic Precipitator (ESP) Weighted-Wire Gas Flow Collection Plate Discharge Electrode Conventional (Dry) ESPs A typical utility ESP is connected by ductwork to the hot gas outlet of the air heater, employs horizontal gas flow, and is operated dry. As illustrated in Figure 3. 1, the internals of such an ESP include both discharge electrodes, which create a stream of electrons that add a charge to fly ash particles they impact, and collection plates that attract and collect the charged particles. The plates are arranged in parallel sets with gas flow through the passages formed by two adjacent plates. The discharge electrodes are placed in the middle of each gas passage. Periodically, the plates are struck with a hammer-like "rapper" to dislodge the collected dust cake, which falls into the hoppers at the bottom of the ESP. From here, the ash is eventually evacuated into a transport line that carries it to a storage silo or landfill. The factors that affect the size of an ESP include the required collection efficiency, the concentration and size distribution of the particulate (fly ash), the electrical resistivity of the fly ash, and the flow rate of the treated gas. These factors are, in turn, determined by the size of the boiler, boiler operating parameters, coal and ash chemistries, and temperature and composition of the flue gas entering the precipitator. The electrical resistivity of the fly ash is particularly important. While a function of the ash chemistry, electrical resistivity is also greatly affected by the SO3 concentration and temperature of the flue gas. Low-sulfur fuels (i.e., S < 1%) produce little S03, and, consequently, the fly ash tends to have a high resistivity-typically > 1010 ohm-cm-which makes the fly ash harder to collect. ESP size is stated in terms of plate area per unit volume of treated gas; units are m2/(m3/s). This ratio is called the specific collection area or SCA. In these terms, the SCA of a small utility ESP will be on the order of 20 to 30 m2/(m3/s). Such a precipitator would produce a 32 Technology Assessment of Clean Coal Technologies for China modest collection efficiency in the 95-98% range when collecting fly ash with a low resistivity. At the other extreme, ESPs with SCAs in the 200 m2/(m3/s) range are used to deal with high ash loadings or difficult, high-resistivity fly ashes in applications that require a collection efficiency over 99%. Dry ESPs are inexpensive and relatively reliable. They tolerate off-design or "upset" operation reasonably well. Further, ESPs operate with both a low pressure drop and relatively low power consumption. Their principal disadvantage is their sensitivity to coal ash and flue gas properties. There is, however, enough operating experience to make reasonable estimates of ESP performance for a wide variety of coals and for a number of coal-burning technologies (pulverized-coal-fired boilers, circulating fluidized beds, etc.). Wet ESPs In contrast to dry ESPs, wet ESPs have been used in only a few utility applications. Normally, wet ESPs are used in industrial applications where they collect very difficult aerosols such as condensed sulfuric acid. There is, however, growing interest in the OECD countries in using wet ESPs in utility applications because their performance is largely insensitive to fly ash properties and they are capable of extremely high collection efficiencies. It has been demonstrated that a single wet field that is slightly under three meters long in the direction of gas flow can achieve a collection efficiency of 95%. Possibly the most attractive way to use this technology in a utility application would be to build a hybrid dry/wet ESP. In this design, the first two or three fields would be operated as conventional dry ESP fields, but the last field would be converted to wet operation. In recent large pilot-scale (2.5 MW) tests in the United States, it has been demonstrated that a precipitator with a hybrid design can be operated with outlet temperatures well above the moisture dew point of the flue gas. This minimizes the amount of water required and eliminates the need to reheat the flue gas to protect downstream equipment from moisture and acid damage. In addition to ensuring low particulate emissions, a hybrid ESP will remove around 50% of the S03 and approximately 20% of the SO2, HCI, and HF from the flue gas, thus reducing the emission of acid gases. This acid removal, however, makes it necessary to treat the water used in the wet field. The same pilot tests that established the feasibility of high-temperature operation also studied treatment systems for the two common water management practices: (1) once-through water operation and (2) recirculated water operation. These tests identified relatively inexpensive water treatment systems for both water management practices that produced reliable operation and a final waste stream that had acceptable disposal properties. As a consequence of the recent studies, the hybrid dry/wet concept is believed to be ready for full-scale demonstration. In an entirely different approach, a wet ESP has been added to the outlet of an existing full- scale SO2 scrubber (i.e., flue gas desulfurization system) at a power plant in the United States. This vertical-flow ESP, which treats flue gas saturated with moisture, is used to collect both the particulate and moisture droplets that are carried out of the scrubber by the flue gas. In this boiler, ten 75-MW scrubber modules serve the 750-MW unit, and all ten modules will be Power Generation and Environmental Control Technologies 33 retrofit with wet ESPs. The oldest of the retrofit 75-MW modules has been in operation more than two years; its operation has been reliable and its performance has exceeded expectations. Conceptually, this vertical-flow design might be applicable to the wet particulate scrubbers employed at some utility plants in China. It could greatly reduce outlet particulate emissions and would add very little pressure drop to the flue gas flow circuit. Fabric Filters In recent years, utilities have started using fabric filters (also called baghouses) for fly ash control because these devices have very high collection efficiencies, moderate capital and operating costs, and are relatively insensitive to fly ash properties. Two different cleaning systems are now in use-conventional (usually reverse gas, but sometimes shake deflate) and pulse jet. Conventional baghouses typically operate at a gas-to-cloth ratio of about 1.0 cm/s and employ woven nylon bags with a Teflon coating. The reverse-gas cleaning system produces a relatively gentle cleaning process and hence a long bag life. Pulse-jet baghouses use a much more vigorous cleaning approach and operate at a higher gas- to-cloth ratio, typically in the 2.0 cm/s range. The higher gas-to-cloth ratio means a pulse-jet fabric filter will be smaller than a reverse-gas unit treating the same gas flow, but bag life may be shorter. Pulse-jet bags are typically made of a needled felt cloth. In the United States, pulse-jet bags are usually made from Ryton (both felt and scrim), and these baghouses clean flue gas that comes directly from the air heater outlet where temperatures are around 150°C. In Australia and South Africa, pulse-jet bags are frequently made of acrylic. Ambient air is mixed with flue gas before the baghouse, lowering the temperature to around 125°C to stay within the operating range for acrylic bags. Both conventional and pulse-jet fabric filters are designed to operate at the same pressure drop across the bag tube sheet, 1.0 to 1.5 kPa. The total flange-to-flange pressure drop is typically 1.5 to 2.25 kPa for both filter types. COHPAC COHPAC is an acronym for COmpact Hybrid PArticulate Collector. In this case, a fabric filter is added after a dry ESP to form the total particulate collection system. The fabric filter has a relatively compact pulse-jet design that is operated at twice the gas-to-cloth ratio (4 cm/s) of a pulse-jet baghouse that would be needed if there were no ESP upstream of the baghouse. This combination produces very low outlet emissions at the cost of a relatively small increase in pressure drop through the fabric filter (typical pressure drop is in the 1.0 to 1.5 kPa range). The bags in all of the existing COHPAC baghouses are made of a Ryton needled felt. There are two ways to implement the COHPAC concept. The first is to add a pulse-jet baghouse in a separate casing after the ESP. In the second approach, the last field of the precipitator is removed and replaced with the filter bags, or other filtering media such as pleated filter cartridges or ceramic filters. There are two full-scale utility COHPAC installations in the United States. Both employ the first approach, a fabric filter in a separate 34 Technology Assessment of Clean Coal Technologies for China casing. The second concept has only been tested at pilot scale, but these tests have produced promising results. Flue Gas (Fly Ash) Conditioning As mentioned earlier, a conventional dry ESP is sensitive to fly ash properties, and the electrical resistivity of the ash is one of the most important of these properties. The resistivity of the ash collected on the plates of an ESP can limit the flow of electrical current through a precipitator if it is much above 1.0 x 1010 ohm-cm. However, it is possible to control the resistivity of the fly ash produced by most coals through the use of flue gas conditioning. The most commonly used conditioning agent, S03, is effective for most ashes if the operating temperature of the ESP is 1600C or below. Commercial SO3 conditioning systems generate SO3 by burning sulfur and converting the resulting SO2 to SO3 by passing it through a catalyst bed. The SO3 is then injected into the duct just ahead of the ESP where it combines with moisture in the flue gas to form sulfuric acid vapor. Some of acid adsorbs on the surface of fly ash particles and reduces the ash resistivity. Typical injection rates are in the 5 to 15 ppm (by volume) range. In some cases, SO3 is combined with ammonia to enhance the conditioning effect. Ammonia is used for two principal reasons: (1) to reduce the amount of SO3 needed to condition certain difficult ashes and (2) to increase the cohesiveness of fly ash in order to reduce reentrainment losses, i.e., losses due to once-collected particulate falling off the collecting plate and becoming reentrained in the flue gas stream. The most difficult ashes to condition are those with very high silica and alumina content. These ashes are particularly difficult to condition at temperatures above 160°C, but combining ammnonia with SO3 usually overcomes this difficulty. Reentrainment losses are always a significant part of the emissions from an ESP (the range can be great, but typically 50% of the total emissions leaving the ESP are due to reentrainment), so reducing these losses can have a significant effect on outlet emissions. Ammonia is effective because it combines with sulfuric acid vapor to form ammonium bisulfate, which has a melting temperature that is low enough to make the ash sticky when it co-precipitates with the ash on the collection plates. The ammonia and SO3 also form ammonia sulfate, and the split between the sulfate and bisulfate, the preferred chemical species, is controlled by adjusting the S03-to-ammonia injection ratio. Typical injection rates for a combined ammonia/ SO3 system would be 12 ppm SO3 and 6 ppm ammonia. Sodium compounds, principally sodium sulfate and sodium carbonate, have also been used for conditioning. These compounds are usually used to enhance the performance of "hot- side" ESPs located ahead of the air heater where the temperature is in the 400°C range. At this temperature, sodium ions have been demonstrated to be the principal charge carrier in fly ash. Increasing the concentration of sodium in the ash will therefore lower the electrical resistivity of the ash. To be most effective, the sodium compound should be added to the coal supply in a very uniform manner before the coal is burned. This task can be accomplished by pouring the compound at a controlled rate onto the coal on the belt that transports the coal into the plant. Typically, the compound is added at a rate that will increase the sodium content of the ash (measured as Na2O) by 0.5% to 1.0%. Power Generation and Environmental Control Technologies 35 While this approach to conditioning is normally used to improve the performance of hot-side precipitators, it has been demonstrated to be effective in at least one cold-side test in India. The increased tendency of the ash to foul the backpass of the boiler is the principal disadvantage of sodium conditioning. Spraying water into the flue gas ahead of a "cold-side" ESP can also improve its particulate collection performance via several mechanisms. Ash resistivity is a function of temperature and flue gas moisture (as well as ash chemistry and flue gas SO3 content), often peaking at temperatures near those of the flue gas entering the ESP. If the ash resistivity is too high for efficient ESP operation and is at, or near, its peak value, its resistivity can often be reduced enough to noticeably improve ESP performance by spraying water to cool the gas/ash and increase its moisture content. Cooling the gas also decreases its volume (albeit this effect is partially offset by the volume of the added water vapor), and this has the effect of increasing the precipitator's SCA, thereby also increasing its collection efficiency. The challenge in using humidification is to be able to add enough water to reduce the temperature at least 25-30°C without causing droplet impingement on internal structural members or duct walls. Typically this requires atomizers that can produce droplets with a diameter less than 50 ptm and a residence of time between the water lances and the closest obstructions in the duct (turns, flow straighteners, structural members, ESP fields) of at least 0.5 seconds. Such atomizers usually use air atomization, which requires compressed air. Therefore, the performance and cost-effectiveness of this approach are very site-specific. In a few cases, humidification has been the least-cost approach for bringing units into compliance with emission or opacity limits, but the experience base is not large. Care must be taken in operating a humidification system to prevent solids buildup from non-ideal operation of the injection sprays, especially with coals that contain high amounts of calcium and other alkali. 3.1.2 Commercial Status Electrostatic Precipitators Dry ESPs are manufactured for utility application by companies located all over the world. In fact, this technology is the dominant particulate control technology at power plants in most countries. ESPs are readily available in China and can be built in the sizes needed to meet current and future emission limits at a relatively low cost. More on the recommended size and estimated costs for such ESPs is presented later in this section. Wet Electrostatic Precipitators Wet ESPs have long been used in industrial processes and are made by a number of the major ESP manufacturers and by a number of smaller specialty companies. As a result of the recent successful utility applications in Japan and the United States, conventional wet ESPs operating at the moisture saturation temperature of the flue gas are now offered for utility application by some of the major ESP manufacturers. In addition, the results of the successful large pilot-scale tests mentioned earlier make it likely that wet ESP designs that operate above the moisture dew point will probably be commercially available in the near future. 36 Technology Assessment of Clean Coal Technologies for China Fabric Filters Most major ESP manufacturers that serve the worldwide market also manufacture both reverse-gas and pulse-jet baghouses. A number of full-scale reverse-gas baghouses in the United States have been operating at utility boilers for 10 years or longer. The reliability and performance of the units has been quite good. There are a few full-scale pulse-jet baghouses in the United States as well, but many more in Australia and South Africa. On the whole, these fabric filters have also provided satisfactory service. As noted earlier, the bag material selected depends on the flue gas temperature; if the correct choice is made for the given situation, and the temperature limit of the bag material is not exceeded, the choice of material has not seemed to affect reliability. Generally, fabric filters have been used at sites where the coal produces ash that is difficult to collect in a conventional electrostatic precipitator. COHPAC Two full-scale COHPAC systems are currently operating in the United States. The EPRI- developed technology is licensed to several pollution control equipment suppliers and could be applied outside the United States. Flue Gas (Fly Ash) Conditioning A number of companies manufacture flue gas conditioning systems in the United States, and these companies have subsidiaries all over the world. In addition, some of the major ESP manufacturers also supply flue gas conditioning systems. Consequently, both SO3 and ammonia conditioning systems are widely available. In fact, there are more than 100 SO3 conditioning systems in operation on utility units in the United States, and some of these systems have been in operation for 20 years or longer. Sodium conditioning has been successfully employed at approximately a dozen units equipped with hot-side ESPs in the United States, and a few of these systems have been in operation for more than 10 years. All of the operating systems were designed and installed by the operating utility; and consequently, these simple systems are not normally sold by equipment suppliers. As noted earlier, experience with humidification is still limited. While these systems are relatively simple to engineer and install, the nozzles must be specially designed to produce the required fine spray. Further, to achieve uniform cooling despite flow and temperature stratification in the duct, potential users should conduct flow modeling studies (either physical or computational) to design the spray system. The resulting design could include zones with different numbers of lances and nozzles, separate control of water and air flow to each zone, and careful monitoring of the temperature downstream of the spray zone to avoid droplet impingement on solid surfaces and minimize the quantity of water (and associated compressed air) needed. Maintenance should include periodic cleaning of the lances and inspection of the ductwork for deposit buildup. Power Generation and Environmental Control Technologies 37 3.1.3 Applicability to China As mentioned earlier, the choice of a particulate collection device is influenced by the nature of the combustion process, the coal and ash characteristics, and the required collection efficiency. Generally, mechanical collectors are a suitable option if the outlet emission limit is significantly greater than 200 mg/Nm3. For example, if the principal purpose of the collector is to protect an induced fan, a mechanical collector will be adequate. For outlet emission limits in the 200 mg/Nm3 range, a relatively small dry electrostatic precipitator may be the best choice. These precipitators have been used for many years for this purpose and have produced satisfactory performance in most applications. If the emission limit is close to the lower end of the range imposed by many OECD countries, 50 mg/Nm3, then both electrostatic precipitators and fabric filters should be considered. Both technologies are capable of limiting outlet emissions to these levels, but a very large ESP may be needed to capture enough ash from a difficult coal to meet such a limit. Electrostatic Precipitators Electrostatic precipitators are currently used at many utility plants in China for particulate control, and the facilities needed to manufacture and install ESPs in the size range and in the numbers needed to support the growth of the utility industry already exist. It is estimated that ESPs with SCAs in the range of 40 to 70 m2/(m3/s) would limit outlet emissions to below 200 mg/Nm3 for a broad range of Chinese coals burned in pulverized-coal-fired boilers. These ESPs would have four to five electrical fields in the direction of gas flow and a 300-mm plate spacing. At this size, they would provide a reasonable margin of performance safety (satisfactory performance with one field out of service). More specifically, size estimates for three representative coals are as follows: Mine Ash (%) Sulfur (Io SCA (m2/ m3/s) No. of Electrical Fields Sonzao 30 4.00 49.0 4 Shenmu 7 0.63 49.0 4 Yanzhou 33 1.22 62.2 5 These performance estimates apply equally to subcritical and supercritical boilers. Pressurized fluidized-bed combustors and integrated gasification combined cycle systems remove the particulate within the process. Atmospheric fluidized-bed combustors also use add-on particulate collectors, and an ESP with an SCA of 70 to 80 m2/(m3/s) would reduce particulate emissions to 200 mg/Nm3 for such a unit. Limiting outlet emissions for these coals to below 50 mg/Nm3 would require a larger precipitator. The estimated sizes for this limit are as follows: Mine SCA (m2/ m3/s) No. of Electrical Fields Sonzao 73 6 Shenmu 76 6 Yanzhou 84 7 38 Technology Assessment of Clean Coal Technologies for China These estimates have the same margin of safety built into them as the estimates for the 200 mg/Nm3 limit. That is, outlet emissions should remain below 50 mg/Nm3 even if one electrical field is out of service. All these size estimates are based on the assumption that the ESPs would be energized using conventional ESP controls and rectifier sets. The advanced power supply and control sets being developed by the Nanjing Environmental Protection Research Institute (NEPRI) can enhance precipitator performance; where effective, they would enable smaller design SCAs. Because ESPs are inexpensive and this technology is so highly developed in China, ESPs are recommended as the first choice for particulate control at new plants in China. The other particulate control technologies are described because they could be of interest in the future if more stringent regulations are imposed by the Chinese central or provincial governments, or if lower emission levels are required to obtain funding or loans from international agencies. Wet Electrostatic Precipitators The same technology used to build dry ESPs can be modified to build wet ESPs. In utility applications, the internals of a wet ESP should be constructed of stainless steel to minimize corrosion and increase the lifetime of the equipment. While the materials of construction are different, other design aspects, such as electrical clearances, power supplies and controls, etc., are very similar. The water cycles for a wet ESP are also similar to the water cycles for the wet particulate scrubbers used for particulate control on a number of small boilers in China. Thus, the technology to build wet ESPs for utility application is available. Possibly the most attractive place to use wet ESP technology would be at plants that are currently using wet particulate scrubbers. The addition of one or two electrical fields at the outlet of the scrubber could significantly reduce particulate emissions. There are enough data to predict that two electrical fields operating in wet mode, with a total length of 2.5 meters in the direction of gas flow, can achieve an overall collection efficiency of 90-95%. Flow through the wet sections could either be vertical or horizontal, depending on the design of the scrubber to which they are applied. Fabric Filters Fabric filters could be used for particulate control at some plants in China. As stated earlier, outlet emissions from both reverse-gas and pulse-jet fabric filters are quite low and should be well below 50 mg/Nm3-often as low as 10 mg/Nm3. However, many coals burned in China produce an ash that would be difficult to collect in a conventional fabric filter. Generally, fabric filters work best at sites burning low-sulfur coals with a moderate ash content (around 10%). The sulfuric acid in the flue gas at plants that burn high-sulfur coals will shorten bag life if the plant is operated in such a way that the flue gas temperature falls below the acid dew point at any time during normal operation. Consequently, there are almost no fabric filters in use at plants that burn high-sulfur coals. Further, very high ash loadings entering a conventional fabric filter will increase the cleaning frequency, which, in effect, will reduce bag life. Fabric filters are not commonly used at plants that burn coals with 2 30% ash content. For these reasons, conventional fabric filters would probably not be a practical choice for some plants in China. Power Generation and Environmental Control Technologies 39 COHPAC COHPAC units could be used for particulate control at new plants and could also be retrofit to existing plants in China. The two full-scale COHPAC installations in the United States are retrofits. However, current and near-term particulate emission standards in China do not require the very low outlet emission levels produced by COHPAC (or other fabric filters). Because COHPAC can be readily retrofit to an existing dry ESP, it could become an attractive option in the future if particulate emissions warrant the use of fabric filters. Flue Gas (Fly Ash) Conditioning Many of the fly ashes produced by the coals found in China can be conditioned with S03, SO3 plus ammonia, or sodium compounds. The ESP sizes in Section 3.1.3.1 assume that no conditioning is used. Resistivity estimates for the three coals indicated that ashes from the two low-sulfur coals, from the Shenmu and Yanzhou mines, will have electrical resistivities that are moderately high, in the low to mid 1011 ohm-cm range; therefore, the performance of ESPs on units that burn these coals could benefit from the use of flue gas conditioning. Generally, the use of flue gas conditioning would reduce the size of an ESP by one electrical field. If this technology is chosen, a conditioning system could be purchased from any one of a number of international suppliers. 3.1.4 Emissions Electrostatic Precipitators It is possible to size an ESP to meet almost any outlet emission level. For example, at some utility plants subject to very strict environmental regulations, ESPs are used to limit emissions to below 30 mg/Nm3 (even below 10 mg/Nm3 in some cases). Section 3.1.3.1 identifies precipitator sizes that will achieve 200 mg/Nm3 and below 50 mg/Nm3. In each case, the performance estimate indicates that the actual outlet emission level will be only about half the specified limit when all the electrical fields are operating at the estimated power levels. However, if one electrical field malfunctions due to an electrical short or a hopper that becomes too full, the emissions will increase to a level that is close to the indicated limit. Wet Electrostatic Precipitators Wet ESPs are capable of limiting outlet particulate emissions to very low levels. The high collection efficiency results from very high operating power levels and the elimination of reentrainment. In the large-scale pilot tests described earlier, where two dry fields were followed by two short wet fields fit into the space previously occupied by the third dry field, outlet emissions were typically below 50 mg/Nm3, and the collection efficiency of the two relatively short wet fields was approximately 95%. The wet ESPs installed in the 75-MW scrubber modules mentioned in Section 3.1.1.1 successfully limit outlet emissions to below 20 mg/Nm3. Addition of a one- or two-field, vertical-flow wet ESP to the wet particulate scrubbers already in service on some units in China would likely reduce emissions to well below the 200 mg/Nm3 level. 40 Technology Assessment of Clean Coal Technologies for China Fabric Filters and COHPAC As stated earlier in this report, both conventional and pulse-jet fabric filters will limit outlet emissions to well below 50 mg/Nm3 when in good mechanical condition (i.e., no broken or leaking bags). Higher emission levels are an indication of a problem. The same holds true for COHPAC systems. Flue Gas (Fly Ash) Conditioning Flue gas conditioning of high-resistivity ash can reduce outlet emissions by a factor of two to a factor of five. This technology could be applied to any of the plants in China that bum low- sulfur coals. It is reported that advanced power supplies and controls developed in China by NEPRI can also improve the performance of ESPs collecting high-resistivity ash. The study team was not able to evaluate the effectiveness of these controls, but did learn that they have been installed at several plants in China with apparent success. For ESP designs and fly ash where these controls are applicable, they could be used together with a properly sized ESP instead of relying on flue gas conditioning to increase the performance of an undersized unit. If there is still a need for further improvement in the performance of the ESP collecting high- resistivity ash, flue gas conditioning could then be considered. 3.1.5 Heat Rate The ESPs recommended for use in this report have only a small impact on heat rate. Power is consumed by the pressure drop across the ESP, the power supplies and controls, hopper heaters, insulation compartment heaters, and the ash removal system. However, the pressure drop across a typical ESP is less than 0.25 kPa. The ESP power supply consumes approximately 0.15% of the gross power output of the plant. The other electrical loads are comparable in size so that the total power consumption of the ESP is less than 0.5% of the gross power output of the plant. The principal impact of a fabric filter is the increased fan power needed to overcome pressure drop produced by the filter. Typically, the power required is 0.5% or less of the gross output of the plant. Since a COHPAC installation produces about the same pressure drop as a conventional fabric filter, it will have about the same impact on heat rate. Neither conversion of one field of an ESP from dry to wet operation nor flue gas conditioning has a significant impact on the energy consumption of the ESP and, hence, neither technology has a great impact on heat rate. 3.1.6 Impacts Electrostatic Precipitators A well designed cold-side ESP requires little maintenance. If the ESP has an adequate safety margin in the design (one extra field), limitations caused by ESP performance problems should be very rare. Regular inspections, both on-line and during unit outages, followed by correction of any identified problems should greatly limit the impact of ESP problems on plant operation. Power Generation and Environmental Control Technologies 41 Wet Electrostatic Precipitators There is very limited experience to inform predictions of the impact of wet ESPs on plant operation. However, this limited experience indicates that if adequate attention is paid to the water supply, little impact on plant operation will occur. The factors that should be monitored include total suspended solids, total dissolved solids, and water pH. Periodically, the spray nozzles inside the ESP should be inspected to assure unrestricted flow. These additions to the normal dry ESP monitoring routines should produce reliable operation. Fabric Filters-Conventional, Pulse Jet, and COHPAC In a proper application (low-sulfur coal and less than 15% ash), the fabric filter will not have a significant impact on plant operation. Fabric filters-whether conventional, pulse jet, or COHPAC-are built using a modular design that allows individual compartments to be taken off line and inspected while the boiler served by the filter is still operating. This design, along with modem bag failure detection devices and programs, makes it possible to minimize the impact of fabric filter failures on unit operation. However, careful attention to the operating conditions in the compartments, especially during startup and shutdown, is needed to ensure long bag life. Further, pilot tests should be conducted at any site contemplating a COHPAC installation, since the impacts of flue gas and fly ash constituents on bag life in this more severe operating environment (higher filtering velocity and, therefore, more frequent cleaning) are still not fully understood. Flue Gas (Fly Ash) Conditioning The injection rate of both SO3 and ammonia, if used, should be carefully monitored to ensure that optimum ESP performance is maintained without over-injecting either or both conditioning agents. Gross over-injection can actually increase outlet emissions of both particulate and the conditioning agents. The temperature change across the catalyst chamber in a conventional S03 conditioning system should be monitored to ensure that the catalyst has not become fouled. Beyond the addition of these monitoring tasks, a conventional SO3 conditioning system should have little impact on plant operation. The most significant impact of ammonia is on ash disposal or utilization. Ash from a plant that uses ammonia conditioning will release ammonia vapor when it is wetted. This phenomenon occurs when the ash is sluiced to an ash pond, landfilled and exposed to rain, or used in the manufacture of concrete. It is a particularly acute problem if the concrete is to be poured indoors, as the odor can be obnoxious. If sodium conditioning is used, fly ash samples should be taken routinely. The sodium concentration in the samples should be determined to confirm that sodium is being added at the desired rate. The pressure drop across the backpass of the boiler should be monitored to ensure that the increased sodium content of the ash is not causing excessive fouling in part of the boiler. Again, beyond the addition of these monitoring tasks, sodium conditioning should have little impact on plant operation. 42 Technology Assessment of Clean Coal Technologies for China As discussed earlier, humidification conditioning requires great care to avoid droplet impingement on internal structural members or duct walls, and to prevent solids buildup from non-ideal operation of the injection sprays. 3.1.7 Constructionllnstallation Time Electrostatic Precipitators The typical construction and installation time for a dry ESP in the United States is on the order of 12 weeks. The length of time can be held to a minimum by increasing the size of the construction force. Wet Electrostatic Precipitators The conversion of a dry field to wet operation should take approximately 10 weeks. In the example cited in 3.1.1.1, the addition of the wet ESPs to the scrubber modules took approximately 3 months with a one-shift work schedule. Fabric Filters and COHPAC A conventional fabric filter, pulse-jet filter, or COHPAC can be built in as little as 10 to 12 weeks with a two- or three-shift work schedule. Since it is often possible to locate and construct the pulse jet away from existing ductwork-especially with a compact COHPAC system-the boiler would only have to be shut down for the tie-in into the existing ductwork. This could take place during a short outage of 2 to 4 weeks. Flue Gas (Fly Ash) Conditioning A conventional conditioning system typically takes 4 to 8 weeks to put in place after it arrives on site, but the unit can be on-line during most of this period. The injection probes can be put into the ducts ahead of the ESP during a very short outage of 1 week or less. The storage silo for a sodium conditioning system and associated equipment can be constructed in 4 to 6 weeks. The addition of a sodium conditioning system does not require an outage. 3.1.8 Costs Estimated costs for the conventional ESP and approximate costs for the other technologies are presented in this section. These costs have been determined for pulverized-coal-fired boilers burning the three referenced coals (the same coals used for the FGD cost calculations presented in Section 3.2.8 of this report) and for an atmospheric fluidized-bed boiler. For PC boilers, costs were estimated for a 300-MW unit and for two outlet emission limits, as follows: Power Generation and Environmental Control Technologies 43 ESP Costs ($/kVV) Coal Mine 200 mg/Nm3 50 mg/Nm3 Sonzao 21.4 29.4 Shenmu 21.4 30.1 Yanzhou 25.5 32.6 The estimated cost for an ESP on an AFBC unit is $32/kW (for outlet emissions of 200 mg/Nm3). The costs are expressed in U.S. dollars, but they are estimated using costs that are appropriate for construction in China. Like the other costs presented in this report, they include value- added taxes for all materials and equipment. These costs can be translated to approximate costs for larger or smaller units using the 0.8 power rule. Previous experience indicates that this rule is reasonably valid, at least up to 500 MW; the economies of scale may diminish beyond that size. Cost estimates for the fabric filter options are given below. These estimates are based on the assumption that bags (and cages for the pulse-jet fabric filters) will have to be imported. Fabric Filter Costs ($/kW) Reverse Gas 56.5 Pulse Jet 36.2 COHPAC 26.2 The first-year operating costs for these technologies are estimated as follows. These costs are based on the same economic assumptions for labor costs, power rates, etc. in China used for all the other cost estimates. fTdacipjplgy Operating Cost (mills/kWh) ESP (SCA = 80 m / m3/s) 0.27 Reverse Gas 0.40 Pulse Jet 0.48 COHPAC 0.48 3.2 SO2 Controls Sulfur dioxide removal from power plant flue gas can be accomplished using a variety of processes. They range from high efficiency, high capital cost, conventional wet scrubbing using limestone and producing a gypsum by-product to low capital cost, moderate removal, dry injection processes that produce a mixture of fly ash, unused reagent, and reaction products. In addition, combination removal processes, such as the E-beam SOX/NOX concept, have been developed. The factors that can influence which process is chosen in a given situation include the emission control requirements, the fuel, by-product markets, alkali costs, the availability of investment capital, and the age of the power plant. The processes described in this report are conventional and simplified wet scrubbing, conventional and simplified spray drying, sorbent injection, seawater scrubbing, and E-beam systems. Most of these technologies have been installed at pilot or commercial scale in 44 Technology Assessment of Clean Coal Technologies for China China. They represent the range of processes at or near commercial scale, and span the full range of SO2 removal capabilities and costs. There are a number of processes under development or commercially available that claim incremental improvements to the processes described here. They have not been discussed in this report because (1) they do not differ enough from the processes that are covered to warrant individual summaries, and (2) the purpose of this report is to provide general information on pollutant removal processes. The economics discussed in this report should adequately represent the full scope of processes that could be considered for application in China. Naturally, for any given site, all processes that meet the environmental and technical requirements should be allowed to bid and be given serious consideration in the evaluation process. The one family of processes that has purposely not been included are the regenerable processes. These processes produce salable by-products (such as sulfuric acid or ammonia sulfate fertilizer) and recover the alkali used in the SO2 removal process. They have been omitted from this report because these processes have always cost significantly more than the competing options and/or the markets for their by-products are limited. Because this report presents ample cost-competitive options, exclusion of the regenerable processes will not affect an economic analysis of energy development strategies for a province. However, their absence from this report should not be taken to suggest that they do not merit consideration on a site-specific basis. 3.2.1 Technology Descriptions A wide variety of processes has been developed and applied in the United States, Europe, and Japan for many years: * Wet Scrubbing. By far the most common SO2 control method is conventional wet scrubbing using calcium-based absorbents. Most flue gas desulfurization (FGD) systems being installed worldwide today are of this type. * Spray Drying (Dry FGD). Spray drying is also common in the U.S. and Europe. It is mainly used for lower-sulfur coals and to achieve removals between 70% and 90%, although higher removals have been achieved in the latest installations. * Simplified Wet and Dry FGD Systems. The Japanese are developing simplified wet and dry FGD systems with streamlined designs to reduce capital costs. The compromise is that their SO2 removal rates are somewhat lower than for conventional designs. The only known applications of these technologies are one demonstration of each in China. a Dry Injection Technologies. These range from low-cost furnace sorbent injection (FSI), a process with low capital costs, relatively high alkali costs, and removals in the 35-50% range, to the LIFAC process, which is similar to spray drying in terms of cost and control capabilities. * Seawater Scrubbing. This is a niche process with application only in coastal areas. Its current application has been in Europe. Power Generation and Environmental Control Technologies 45 * E-beam Process. This process uses high-energy electron beams to control both SO2 and NO,. The technology has been under development for many years, and a demonstration was recently conducted in China. The rest of this section contains a more detailed description of these technologies. Conventional Limestone Wet Scrubbing with Forced Oxidation Limestone with forced oxidation (LSFO) FGD is a modification of a traditional wet limestone FGD process. In the traditional wet limestone system, oxidation is not promoted and the scrubber product formed is composed mostly of calcium sulfite. The LSFO FGD process precipitates solids high in calcium sulfate content (99%+). This high gypsum (CaSO4.2H20) content makes the scrubber sludge easier to dewater and avoids the need for fixation before disposal in a landfill. In the LSFO process, the hot flue gas exiting the particulate control device enters a spray tower where it is contacted with dilute limestone and calcium sulfate slurry. The SO2 reacts with the calcium carbonate in the limestone particles and the slurry drains into a separate recirculation tank or into the tower sump. This process is capable of removing more than 95% of the S02 present in the inlet flue gas. The SO2 reaction with calcium carbonate initially forms calcium sulfite, which is subsequently oxidized to calcium sulfate (gypsum) in the recirculation tank or absorber tower sump using an air sparger. The gypsum can be first dewatered using a thickener or hydroclones, with final dewatering using rotary drum or horizontal belt filters, and then transported to a landfill for disposal (or sold as a by-product if there is a market). This technology has been in operation on two units at the Luohuang Power Plant in Shanxi province since 1992-93. The plant uses an LSFO system supplied by Mitsubishi Heavy Industries (MHI), which removes > 95% of the S02 from an anthracite coal containing 3.5-5 wt% sulfur. Currently, the gypsum is landfilled. Additional LSFO installations are under construction in China at sites burning high-sulfur coals. The major advantage of a forced-oxidation limestone process is the abundant and low-cost (compared with lime or sodium compounds) source of raw material for the absorbent. The process can meet SO2 reduction requirements for all types of coals. Also, by increasing the solids content of the final dewatered product, the vacuum filter reduces the amount of interstitial water (and the corresponding dissolved solids that are present), reducing the capital and operating costs of the leachate collection system that is (or may be) necessary to minimize groundwater contamination. Conventional Spray Drying Historically, spray drying has only removed 70-80% of the sulfur, but recent installations have achieved > 90% removal rates, making spray drying a more widely applicable option. The conventional lime spray dryer process produces a dry mixture of fly ash and reaction products. In this process the hot flue gas exiting the boiler air heater enters a spray dryer 46 Technology Assessment of Clean Coal Technologies for China vessel (either cylindrical, conical bottom, or horizontal box). Within the vessel, an atomized slurry of lime and recycled solids contacts the flue gas stream. The sulfur oxides in the flue gas react with the lime and fly ash alkali to form calcium salts. The water entering with the slurry vaporizes, lowering the temperature and raising the moisture content of the scrubbed gas. In some spray dryer designs, the scrubbed gas leaves from the side of the vessel (as opposed to the bottom) and a portion of the dried reaction products and fly ash drop out in the conical bottom. A particulate control device downstream of the spray dryer removes the remainder of the dry solid reaction products and fly ash before the scrubbed gas is released to the atmosphere. A portion of the collected reaction products and fly ash solids is recycled to the slurry feed system to maximize alkali utilization. The remaining solids are transported to a landfill for disposal. In most new installations, a baghouse (fabric filter) would be used as the particulate device downstream of the spray dryer; however, spray dryers have been commercially installed upstream of electrostatic precipitators (ESPs) in units firing a low-sulfur coal. Recent research (pilot and full-scale experience) is demonstrating the viability of also using spray dryers in combination with ESPs in medium- and high-sulfur coal applications. This is an important point for retrofit applications, as the costs of retrofitting the spray dryer FGD process are greatly influenced by whether an existing ESP can be used as the downstream particulate control device instead of a new baghouse. In the typical spray dryer process, the atomized slurry is a mixture of slaked lime (Ca(OH)2) slurry, with approximately 25-30 wt% solids content, and a recycle solids slurry with approximately 35-45 wt% solids content. Both slurries are limited in solids content by viscosity. At higher solids content the slurries become too difficult to pump and to keep agitated in tanks. The lime slurry feed rate to the atomizer (rotary or dual fluid) is generally controlled to achieve the desired level of SO2 removal, while the recycle slurry flow rate is varied to control the spray dryer outlet temperature. Depending on vendor preference, the two slurries are combined either in the atomizer feed piping or in a small agitated tank. The major reaction product of slaked lime with the flue gas S02 is calcium sulfite, although a portion (25% or less) oxidizes to calcium sulfate. The dried solids, which are removed in a fabric filter or ESP, significantly raise the concentration of entrained solids in the flue gas entering the particulate control device. In new installations, the solids handling equipment for the particulate control device must be designed for a substantially greater capacity than in units without spray dryers. In retrofit situations, the existing ash removal system will likely have to be upgraded to accommodate the larger volume of solids and the higher moisture of this material. Also, because the temperature of the scrubbed gas is lowered and the moisture content is increased, the particulate control device must be better insulated than in conventional applications, to avoid moisture condensation and corrosion. This represents an additional cost component for spray dryer technology, for both new and retrofit applications. In this study, the costs of upgraded solids handling equipment and insulation are included in the new and retrofit costs for spray dryers. In spite of the increased solids loading resulting from the spray dryer FGD process, a baghouse particulate collector would not have to be increased in size relative to what is required for a conventional design for removal of fly ash only. In retrofit applications with Power Generation and Environmental Control Technologies 47 ESPs, additional collection plate area may be needed to handle the increased particulate loading. A pilot-scale spray dryer has been designed and built by a team from Sichuan Electric Power Administration (SEPA), and has seen about eight years of operation at SEPA's Baima Power Plant. The design is very similar to spray dryers offered commercially in OECD countries and seems to be as effective as these international products. SO2 removals up to 80% have been achieved without recycle. While most conventional spray dryers use recycle to improve alkali utilization, it is a tradeoff between alkali costs and the cost of the equipment required for recycle. Some problems were experienced with vibration of the atomizer, wear of the atomizing wheel, and deposits in the ESP. The lime was not high quality and needed to be ground significantly to reduce the potential for plugging of the atomizing wheel. Presumably these are engineering problems that will be resolved, making this system a competitive option in the marketplace. Spray dryer system advantages are as follows: * The spray dryer system requires only a small stream of scrubbing slurry to be pumped into the spray dryer as compared to the large volume of scrubbing slurry recycled in wet systems. This small, alkaline stream contacts the gas entering the dryer rather than the walls of the system. In wet systems, the walls of the absorbers, tanks, and pipes are subject to corrosion because of the continuous contact with low-pH slurries. The high-pH slurry and dry solids product inherent in the spray dryer allow mild steel materials of construction for the spray dryer vessel and slurry tanks. In contrast, wet FGD systems frequently require rubber liners or alloy liners at various locations in the system. * Wet systems require thickeners, centrifuges, filters, and mixers to handle the wet sludge product. Since the spray dryer produces a dry solid product that can be handled by conventional dry fly ash handling systems, the result is elimination of the dewatering solids handling equipment and a reduction in the associated maintenance and operating requirements. * High chloride concentrations in the slurry will typically reduce the SO2 removal efficiency in wet systems. In the spray dryer process, chloride has been found to enhance SO2 removal. * Cooling tower blowdown can be used for all slurry dilutions after completing the slaking of the lime reagent, with virtually no adverse effects on system performance. In some wet scrubber applications, cooling tower blowdown makeup water can have adverse effects on system SO2 removal performance, particularly with high-chloride- content waters. Spray dryer system disadvantages compared to wet limestone systems are as follows: * The lime spray dryer process cannot use cooling tower blowdown water in the lime slaking system, but instead requires fresh water for this step. 48 Technology Assessment of Clean Coal Technologies for China * The lime spray dryer process requires a higher reagent feed ratio (to achieve the desired removal efficiency) compared to a conventional wet alkali system. In addition, lime is more expensive than limestone. However, higher coal chloride levels, and/or calcium chloride spiking, can significantly reduce reagent consumption by the spray dryer FGD process. In the latter case, the savings in reagent consumption is partially offset by the costs of installing a calcium chloride addition system as well as the cost of the calcium chloride added. * Potential utilization of the by-product is limited due to the presence of fly ash, unreacted alkali, and calcium sulfite (see Section 3.8 for a discussion of possible uses). Simplified Wet Scrubbing The simplified wet scrubbing (SWS) system differs from LSFO mainly in equipment design. A number of modifications have been made to reduce capital costs with a tradeoff of lower SO2 removal. SWS is designed to achieve 80% removal vs. 95% in current-generation wet FGD systems. The chemistry of the process remains the same. The process was designed by Babcock-Hitachi in collaboration with the Electric Power Development Corporation (EPDC), both of Japan. The design consists of a horizontal absorber operating at high gas velocity (8 m/s vs. 3-5 m/s for conventional vertical absorbers) and low liquid-to-gas ratios (15 I/Nm3 vs. 18-23 l/Nm3 for conventional vertical absorbers). Another design feature is a combination mixer/air sparger in the main recycle tank that keeps the slurry mixed and provides oxidation air to produce the gypsum by-product. This is intended to minimize energy requirements. The ability to keep the slurry from settling may be compromised if the air feed is lost. The limestone is dry-ground to a coarser mesh size (95% < 100 mesh vs. 95% < 325 mesh for conventional vertical absorbers), again to save costs. The rest of the system is similar to the conventional design. The unit has been tested in a three-year program at the Taiyuan Power Plant in Shanxi province. A number of operational issues were reported. Dry limestone grinding equipment problems were experienced but all were minor and solved. Some scaling was experienced in the absorber, and some of the material fell into the recycle tank, plugging the hydroclones used as initial separators for the gypsum; this was believed to be caused by the frequent starts and shutdowns experienced during the demonstration program. Freezing of pipes due to lack of freeze protection was reported. One additional problem was AlF limestone blinding when high flue gas particulate loading was experienced, resulting in higher-than-desired alkali feed rates. The Al/F blinding problem may be chronic for wet scrubbers in China where older, less efficient ESPs are common and operational upsets are more likely. The advantages of the SWS are lower capital and energy costs. The disadvantage is lower SO2 removal. Simplified Spray Drying Simplified spray drying (SSD) is a modification of the conventional spray drying system. Mitsubishi Heavy Industries (MHI) of Japan developed the process in collaboration with Power Generation and Environmental Control Technologies 49 EPDC. The designed residence time in the absorber was reduced to save costs, but the major change is in the alkali processing where the Lively Intensified Lime-Ash Compound (LILAC) process is used. In this process, fly ash, lime, and by-product are mixed in a hot water curing process. This leads to formation of a reactive amorphous compound of SiO2, A1203, Ca(OH)2, and CaSO4. The fine silicates formed have a high surface area and this is believed to result in a more reactive alkali compared to the slaked lime normally used in the process. The amounts of material recycled are also lower in this process. The only known application of SSD is at the Huangdao Power Plant in Shandong province, which was visited as part of this project. The installation handles 100 MW of flue gas from the power plant boilers. Startup of the plant was in 1994 and the demonstration was completed in 1998. The plant reported that the spray dryer consistently met its goal of 80% SO2 removal. The spray dryer vessel experienced some buildup on its walls, and the electrostatic precipitator experienced some corrosion. In the demonstration, the material collected by the ESP was wet-sluiced to a pond rather than dry-landfilled. The advantages and disadvantages of this process are similar to those of the conventional spray dryer process. The smaller vessel size is a concern, but buildup on the walls was not reported to be a significant problem. Fumace Sorbent Injection The furnace sorbent injection (FSI) process is a dry system easily installed as a retrofit or incorporated in the design of a new boiler. Quicklime (CaO) is hydrated and injected into the furnace cavity of the boiler to react with SO2. Limestone can be used, but is generally considered ineffective alone (see the discussion of LIFAC in 3.2.1.6). It is often necessary to inject water into the ductwork between the air heater and the existing ESP for flue gas conditioning to maintain particulate emission compliance. In the FSI process, the sorbent is injected near the top of the furnace. Upon exposure to high gas temperatures (greater than 1150-1250'C), the sorbent rapidly decomposes to form highly reactive lime particles (CaO) in suspension, which capture SO2 to form solid calcium sulfate (CaSO4). The flue gas is humidified downstream of the air heater to improve reagent utilization and condition the flue gas for enhanced particulate removal. All solids entrained in the flue gas (reaction products, unreacted lime, and fly ash) are collected in the particulate control device. Experimental efforts in both the United States and in Europe demonstrated the possibility of achieving SO2 removal efficiencies of 35-50%. This collection efficiency was shown to be possible at sorbent injection rates (Ca/S ratio) between 2 and 4 if sorbent characteristics and injection conditions are properly controlled. The advantages of FSI are primarily the simplicity of the process and its low capital cost. The FSI process can be applied to boilers burning either low-sulfur or high-sulfur coals. FSI is better suited to relatively larger furnaces (for a given MW size) because it is easier to locate the proper injection point and provide sufficient residence time within the required temperature window-the system works best on furnaces whose combustion gases remain in 50 Technology Assessment of Clean Coal Technologies for China the active temperature window (900-12000C) for at least 300 ms. Smaller-capacity boilers are also better because the injected sorbent can mix rapidly with the flue gas. ESP efficiency will typically decrease with the addition of sorbent to the boiler. The higher particulate loading and the increased solids resistivity (due to the calcium) both reduce the ability of an existing ESP to maintain its original outlet particulate loading. Many of the older ESPs are of marginal design, with higher gas velocities and smaller specific collection areas than new units. As a result, they have little extra capacity, if any, and will generally have difficulty maintaining pre-retrofit particulate emission rates. One solution to poor ESP performance is to humidify the flue gas to temperatures approaching the gas adiabatic saturation temperature. However, at low approach to saturation (less than 10°C), duct corrosion can occur due to acid condensation downstream of the humidification point. The excess alkali carried over from the boiler helps in neutralizing acidic condensate. The sorbent injection point and, more specifically, the flue gas temperature, directly impacts the boiler SO2 removal efficiency. The optimum injection temperature is 1150-1250°C. At higher temperatures, the sorbent sinters and any CaSO4 formed is subject to decomposition, while at lower temperatures, the reaction proceeds too slowly. The optimum injection point would be below or near the nose of the boiler, but some boilers operate at higher furnace temperatures, which can extend the optimum window into the superheater zone. For a decreased boiler load capacity, this temperature window occurs closer to the burners and the sorbent should be injected in this region. Therefore, multiple injection points are required to allow the system to compensate for boiler load swings. The process advantages are as follows: * Low capital cost. The SO2 removal occurs primarily in the upper furnace cavity; therefore, a separate SO2 absorption vessel is not required. * Process simplicity. Because the hydrated lime is injected in dry form, reagent handling is less complex than in wet alkali systems and slurry pumping requirements are eliminated. * The FSI process produces a dry solid product that can be handled by an existing dry fly ash handling system. As a result, no dewatering/ sludge handling equipment is required, and associated capital and maintenance costs are avoided. * LSFO systems can have scaling problems in the scrubber vessels due to the deposition of hydrated calcium salts. With dry sorbent injection, the water injected in the flue gas should not cause problems as long as the approach to adiabatic saturation temperature is controlled above a minimum threshold value. * Power requirements for dry sorbent injection are lower because there is no equipment required to handle slurried reagent or wet sludge products. Major disadvantages of the FSI process relative to the wet FGD process can be summarized as follows: Power Generation and Environmental Control Technologies 51 * The FSI process is not capable of high SO2 removal efficiencies; removal rates are generally less than 50%. * The FSI process has lower reagent utilization than does a conventional wet alkali system. In addition, the quicklime used in this evaluation is more expensive than limestone. * Uses have not been demonstrated for the by-product produced (see Section 3.8 for a discussion of possible uses). * The humidification step carries the potential for solids deposition, either through solid- droplet impact or operation below the acid dew point. * This process can only be used effectively on boilers that provide > 200-300 ms of residence time (preferably 500 ms) in the temperature window. Load changes have major impacts on the boiler temperature profile; this may require the installation of multiple injection ports in the furnace wall to allow lime injection into the appropriate flue gas environment. The boiler injection point must then change with load swings. * Due to increased particulate loading in the flue gas and changes in ash resistivity, ESP performance decreases. Humidification should help the ESP collection efficiency, but additional collection capacity may be required. LIFAC The Tampella LIFAC (Limestone Injection into the Furnace and Activation of unreacted Calcium) process is a semi-dry system. This process was developed to improve the SO2 removal efficiency and reagent utilization of the basic FSI process. Finely pulverized limestone is injected into the upper part of the boiler furnace where a portion of the SO2 is removed. The reaction products entrained in the flue gas (along with the fly ash) pass into the activation reactor. In the reactor, water is sprayed into the flue gas to humidify the gas for additional SO2 removal and particulate conditioning prior to entering the ESP. The absorption reaction yields a dry solid product that is captured downstream in the ESP. A portion of the clean flue gas is extracted, heated, and recycled back to the outlet of the activation reactor to reheat the humidified flue gas stream before it enters the ESP. As an alternative design, in-line steam coils could be used to provide the necessary gas reheat. The solids captured by the ESP are transported to landfill for disposal. A demonstration of the LIFAC process is installed at Nanjing Xiaguan Power Plant on two 125-MW units. The first is in trial operation. At a design coal sulfur content of 0.9 wt%, and a Ca/S ratio of 2.5, the system is expected to achieve a total SO2 removal of 75%. The LIFAC system advantages are as follows: * The product is dry solid that can be handled by an existing dry fly ash handling system. As a result, no dewatering/sludge-handling equipment is required, and associated maintenance costs are avoided. * Unlike FSI, LIFAC can use less-expensive limestone. 52 Technology Assessment of Clean Coal Technologies for China * The limestone is injected in dry form; therefore, reagent handling is less complex compared to wet alkali systems. * The elimination of slurry recycle and handling results in reduced pumping requirements, significantly lowering power consumption. * Flue gas pressure drop is approximately one-half that of LSFO. * The LIFAC system is potentially well suited for retrofit installations due to its reduced space requirements. However, at some facilities, insertion of the activation reactor between the air heater and the ESP may be difficult or impossible. Disadvantages of the LIFAC system compared to LSFO are as follows: * It does not remove as much sulfur; removal rates are only 70-80% instead of 90+%. * There is the potential for an adverse impact on ESP performance due to increased particulate loading and changes in ash resistivity. * The by-product produced is unsuitable for utilization. * The LIFAC process requires more than twice the reagent feed required for conventional wet alkali systems, and is also higher than other dry FGD processes. * A larger quantity of dry solids is produced due to higher reagent feed rate. * Corrosion is a concern at two locations: (1) the humidification area due to operation below the acid dew point and (2) the downstream ductwork due to the high moisture content downstream of the reactor. * Gas reheat in the Tampella process requires more steam consumption than other dry processes. Since 1985, the Harbin Boiler Company has been developing a process similar to the LIFAC process called the desulfurization with injecting limestone system (DILS). Initial efforts concentrated on FSI with humidification. They have a pilot installed on a 20 t/h boiler with a water membrane particulate removal system. They tested at 75% load with an SO2 concentration of 3500-5000 ppm and report SO2 removal > 80% at a Ca/S ratio of 1.5. The limestone injection system is a dilute phase transfer and does not use a day bin. They claim the process will work with either an ESP or a wetted film particulate removal system. The material of construction for a wetted film collector is mullite and for an ESP, coated carbon steel. Harbin Boiler Company is continuing to develop this process. Seawater Scrubbing Seawater scrubbing is a process simple in concept-seawater is pumped through a packed tower, SO2 is absorbed into the water where it reacts with the alkalinity in the seawater, and the water is returned to the sea. The process is only realistic at coastal locations where seawater is available, so it is very limited in application. In these sites, however, it is well worth considering, as it can achieve high levels of SO2 removal at lower costs than conventional or simplified wet FGD. Typically, factors that would influence a decision are the coal sulfur level and ocean's capacity to accept the discharge at that location on the one Power Generation and Environmental Control Technologies 53 hand, and reagent costs and by-product salability or disposal costs on the other hand (in the absence of special business considerations). The design liquid-to-gas ratio (L/G) is similar to conventional wet scrubbing. The process requires additional alkali if it is used for other than low-sulfur fuels because the L/G would become too high to be cost-effective without the added alkali. The pH of the discharged seawater must be adjusted to drive off the carbonates also removed in the process and restore the pH to the level of the original seawater. In addition, the water is aerated to convert the sulfites formed to sulfates before discharge to the ocean. The flue gas is cooled below the moisture dew point because of the low temperature of the seawater; this can cause a problem with the stack plume rise. There are installations in Europe and units under construction in Asia. A 300-MW system is in early operation in China at the West Shenzhen Power Plant. The SO2 removal is > 90% on a 0.75 wt% sulfur coal. No alkali addition is required. The treated discharge is returned to the sea when the pH is more than 6.5 and the heavy metal contents are less than the Class III seawater standard. The absorber is a packed tower with an L/G of 6.4 l/Nm3. Advantages compared to conventional wet scrubbing include the following: * No waste product is produced because the seawater is returned to the ocean with the reaction products in low concentration and in a soluble form. * Generally, no alkali is needed for SO2 removal. * The system is very simple. Disadvantages include the following: * The process is applicable only at coastal installations with direct access to ocean waters (for receiving and diluting the discharge). * It requires a high L/G if high-sulfur coals are treated. This can be overcome with alkali addition, but then equipment to handle the alkali is necessary. * There may be opposition to the project due to concern over environmental impacts from contaminants, especially mercury and other trace metals, transferred from any ash captured by the spray in the absorber to the seawater This is one of the biggest issues organizations face when trying to specify this process. * There may be problems with plume rise because of the low gas temperatures at the stack exit. This can require reheat that adds considerable cost. Electron Beam The electron beam (E-beam) process simultaneously removes both SO2 and NOx. It is supplied by the Ebara Environmental Corporation, although other firms offer similar processes. The gas from the air heater passes through an ESP for particulate removal and then through an evaporative spray cooler, where the temperature is cooled to 60-65°C. The spray 54 Technology Assessment of Clean Coal Technologies for China cooler is operated with a dry bottom (i.e., all water injected into the flue gas is evaporated). Gaseous ammonia is also added to the flue gas either before or after the spray cooler. The flue gas then proceeds to the E-beam process chamber where it is irradiated by a beam of high-energy electrons. Additional water is added in the process chamber to counteract the temperature rise associated with the irradiation. Hydroxyl radicals and oxygen atoms result from the irradiation and subsequently oxidize the SO2 and NOx. These oxidized species mix with water in the flue gas to form sulfuric acid and nitric acid, which are neutralized by the ammonia. The by-products from this process, solid ammonium sulfate and ammonium sulfate-nitrate, are produced as a result and are collected downstream of the process vessel. By-product collection can be achieved in either an ESP or a baghouse or a combination of the two, such as COHPAC. After by-product collection, the flue gas goes to the stack. The collected by-product consisting of ammonia salts has the potential to be used as fertilizer, most likely after processing into a granular product. The E-beam process is capable of achieving SO2 removals of 95% or greater and NO,, removals of about 90%. High SO2 removals require a minimal E-beam dose, generally much lower than the E-beam dose necessary for NO,, removal. Once the minimum E-beam dose is achieved, the primary factors affecting SO2 removal are flue gas temperature and ammonia stoichiometry. The E-beam dosage required for 90% SO2 removal is a minimum of 1.0 Mrad. The removal of NO,, depends primarily on the E-beam dosage; temperature and SO2 concentration are of secondary importance. Higher NO,, removals require higher radiation dosages. A dose of about 0.3-0.6 Mrad is required to achieve 50% NO,, removal, and 90% NO,, removal requires at least 2.7 Mrad according to the data obtained to date. Better NO,, removals are obtained at higher temperatures, contrary to SO2 removal. Higher S02 concentrations also improve NO,, removal, making the process better suited for high-sulfur applications. The equipment selected for by-product collection after the process vessel will depend on the amount of particulate to be collected from the flue gas and the allowable amount of ammonia slip. The by-product particles are small, tend to be sticky, and are very hygroscopic. An ESP would be capable of removing most of the particulate; however, ammonia slip is high with only an ESP when a high SO2 removal rate is desired. Applications that require high SO2 removal, and therefore high ammonia injection rates, would probably require a baghouse to reduce the amount of ammonia leaving the process. There could be some problems with removing all the by-product using just a baghouse because the by-product is so sticky. Used alone, conventional baghouses have not been able to effectively release the by-product from the bags. This by-product caused too rapid a rise in the pressure drop across the baghouse. The addition of an inert material, such as diatomaceous earth, is one method that has been used to improve by-product release. Another method is to use an ESP ahead of the baghouse to remove a large fraction of the by-product before the flue gas is treated by the baghouse. In China, a 90-MW E-beam demonstration has been in operation since July 1997 at the Chengdou Power Plant in Sichuan province. SO2 removals have been in the mid-80% range Power Generation and Environmental Control Technologies 55 and NO, removal between 15% and 20% on a high-sulfuir bituminous coal (600-2500 ppm inlet SO2). They use an ESP to remove the by-products and have had problems with buildups on the wires and plates. They are still working on optimizing the temperature in the reaction zone, irradiation strength, and NH3 injection rate to maintain the desired SO2 removal rate. The biggest factors affecting system availability are the ESP buildups and the need to use a film on the beam window for protection from the flue gas. The advantages of the E-beam process include the following: * The process can simultaneously remove SO2 and NO,. * The by-product can be sold as fertilizer. * There are no disposal requirements. * The process does not produce any wastewater. The major disadvantages include the following: * The large E-beam equipment required for this process is still in the prototype stage, and the cost and long-term reliability of the equipment is not known. * Significant problems are associated with the by-product collection system. * The process uses a significant amount of electricity. Figures of 2-5% of the plant output are often cited, depending on the required NO, removal; the Chengdou demonstration plant consumed about 2% of the plant energy for an SO2 removal of 80% and NO, removal of 10%. 3.2.2 Commercial Status The commercial status of each process is summarized below. Conventional Limestone Wet Scrubbing with Forced Oxidation LSFO is the most prevalent FGD process in the world, with most new installations using this technology when high levels of SO2 removal are required. It is suitable for all levels of fuel sulfur content. The latest designs are much simpler than in the past, and many of the operational problems experienced in the past have been overcome. Costs have become more attractive as the technology has matured. There are many suppliers. Conventional Spray Drying This process has mainly found its niche in treating flue gas from lower-sulfur coals (< 2%). The most recent installations achieve SO2 removal > 90%, but most of the earlier applications are in the 70-80% range. While not as prevalent as conventional wet scrubbing, it is a mature technology with a significant number of installations. There are a number of suppliers. 56 Technology Assessment of Clean Coal Technologies for China Simplified Wet Scrubbing SWS should be applicable to all ranges of fuel sulfur content. The only known application of this technology is at the Taiyuan Power Plant. The size of the unit seems sufficient for a demonstration and there appear to be no hurdles to commercial application. However, it is not a mature technology with a large number of installations. Babcock-Hitachi of Japan is currently the only known supplier, at least of a demonstrated design. Simplified Spray Drying Like SWS, SDS has been installed only in China. Again, it is being demonstrated at a size sufficient to allow confidence in designing a commercial application. It would most likely be suitable for coals of the same sulfur content as conventional spray drying (< 2% S). MHI is currently the only known supplier of this type of simplified spray dryer. Fumace Sorbent Injection This technology has been installed at commercial scale but is not widely used. Currently the few operating systems are in eastern Europe, mostly on smaller boilers (e.g., industrial units). It is mainly suitable as a retrofit for old units that need only a small amount of SO2 removal and burn a lower-sulfur coal. LIFAC There are only a few commercial applications of this technology, which are generally used with lower-sulfur coals (< 2%) and provide 70-80% SO2 removal. Tampella, the developer, is the only supplier. The DILS system, under development by the Harbin Boiler Company, may become a domestic competitor when development is completed. Seawater Scrubbing This is a commercial process, but one with very limited applications. Where applicable, it should be able to achieve (with appropriate designs) very high SO2 removal for all levels of coal sulfur content. The suppliers are also limited. Electron Beam E-beam technology should be suitable for all levels of coal sulfur content and very high SO2 removals. However, there are no operating commercial applications, and few, if any, operating systems outside of the unit installed in China. Only one supplier is actively promoting this technology, but others are preparing to offer related systems (primarily different methods for producing the ionization energy). As an SO2 removal process only, it would cost more than other control options. Therefore, the market acceptance of this technology will depend on whether it is cheaper than the combination of other SO2 processes and NO, controls for the level of SO2 and NO, emissions required. Another major factor will be the price that can be obtained for the fertilizer by-product. Power Generation and Environmental Control Technologies 57 3.2.3 Applicability to China There does not seem to be an insurmountable obstacle to application of any of these processes in China. In fact, except for furnace sorbent injection, they have all been tested in China at pilot level (conventional spray drying), commercial-scale demonstration (SWS, SSD, E- beam), commercial level (LSFO), or are being installed (LIFAC, seawater scrubbing). Further, the project team has been told that Chinese companies are actively discussing licensing and technology transfer arrangements with international suppliers to develop a local capability. In addition, some companies and laboratories in China are developing their own SO2 removal technologies, including designs said to be simpler than current offerings. The relatively high fly ash levels in the flue gas entering the absorber can pose a potential issue for wet limestone FGD applications in China. Fly ash contains aluminum (Al), and the higher allowable particulate emissions means that more Al-bearing ash reaches the absorber than experienced by current FGD systems in OECD countries. This can be important because aluminum fluoride "blinding" of the limestone can occur when a source of Al, usually fly ash, is removed in the scrubber, and the Al is leached into the scrubbing liquid. The Al can combine with the fluoride removed from the gas stream by the scrubber. If conditions are right, some of this aluminum fluoride precipitates onto the limestone, reducing the dissolution rate of the limestone. More limestone has to be added to maintain SO2 removal as long as the Al source is available. In the United States, this blinding problem has occurred during ESP upsets and disappears when the ESP problem is fixed. For processes that use lime, obtaining good-quality lime is important. Poor quality, as experienced in some of China's installations, can result in higher alkali costs, limited SO2 removal, and/or additional processing costs to minimize wear of parts due to abrasive inerts. The availability of high-quality lime should be considered when selecting an FGD process. 3.2.4 Emissions For each candidate FGD process, Table 3.1 shows its control capability and most likely fuel sulfur applications. 58 Technology Assessment of Clean Coal Technologies for China Table 3.1: Process Applicability Process S02 Removal, % Fuel Sulfur Content Conventional Wet Scrubbing > 95 All levels Conventional Spray Drying > 90 < 2% Simplified Wet Scrubbing 80 All levels Simplified Dry Scrubbing 80 < 2% Furnace Sorbent Injection 30-50 < 2% LIFAC 70-80 < 2% Seawater Scrubbing > 90 All levels E-Beam > 90 All levels 3.2.5 Heat Rate The percent of plant power required for the four FGD systems for which the economics were developed is shown in Table 3.2. Table 3.2: Percent of Plant Power Required Fuel Sulfur, wt% LSFO SWS SSD FSI 1.20% 1.36 1.29 0.70 0.58 (Fuel 1, Daton mixed) 1.93% 1.43 1.36 0.71 0.60 (Fuel 2, Changzi unwashed) 4.02% 1.58 1.46 0.76 NA* (Fuel 3, Sonzao meager) * FSI was not evaluated for high-sulfur fuel due to the excessive levels of sorbent that would be required. The values for LSFO are typical of current designs. The value for SWS is somewhat lower than for LSFO due to the lower L/G, but SWS has a higher pressure drop due to the high gas velocity. The FSI value is high due to the energy required for solids conveying and the atomizing air used in the humidification system ahead of the ESP. The energy requirement for E-beam reported for the China application (where NO, removal is incidental) is 2% of the plant output. 3.2.6 Impacts Current-generation FGD systems seldom impact plant availability. Most major maintenance is done during planned outages. For wet scrubbing systems, the quality of the limestone used can affect the amount needed but usually does not impact the ability to maintain SO2 removal at moderate values (< 80%). Power Generation and Environmental Control Technologies 59 High SO2 removal usually requires a high-quality limestone. This is especially true if the scrubber treats flue gas from a high-sulfur coal and has a small residence time in the recycle tank; in this case, limestone dissolution rates could be affected. In dry scrubbing systems that use lime, the main issue is the water quality used in slaking the lime, i.e., converting it from CaO to Ca(OH)2. Water high in sulfates can result in blinding of the slaked lime, which will reduce the dissolution rates during scrubbing. This can limit SO2 removal. The hydrated lime used for the FSI process-received at the plant as a dry Ca(OH)2 powder- usually has most of the impurities removed during the hydration process, so blinding is not a problem with FSI. For wet scrubbing systems, the hydroclones, pumps, high alloys, and belt filters might be difficult to obtain within China. For spray dryers, the atomizer system is the only maintenance item that might be difficult to obtain within China. 3.2.7 Constructionllnstallation Time The construction time for FGD systems is generally a function of the size and number of units under construction at a given site. For the small units, two years is typical; for the largest units, four years might be required.. The FSI system could probably be installed in a significantly shorter period-perhaps one year. For retrofits, most tie-ins can be made during normal outages. 3.2.8 Costs The project team did not develop costs for all candidate control technologies, but rather for selected processes that represent the range of practical SO2 reduction levels: limestone forced oxidation (LSFO) for ASO2 > 95%; simplified wet scrubbing (SWS) for ASO2 ~ 80%; and furnace sorbent injection (FSI) for ASO2 - 35-50%. Costs were also estimated for the simplified spray dryer (SSD), an 80% SO2 removal option that costs less than the SWS but can be used only where its by-product can be managed readily. These costs are shown in Table 3.2-3. Although these four technologies were selected to provide generic input into the Task B energy/economic/environment analysis, all the technologies discussed in this report could be a viable option at a given site and should be considered where the technology is technically applicable-i.e., seawater scrubbing along the coast at places where the ocean can assimilate the discharge without environmental damage; E-beam where power costs are low, the incidental NO, reduction is valued, and a good market exists for the fertilizer by-product; and LIFAC or DILS where 70-80% SO2 reduction is acceptable, the plant layout allows a low- cost installation, the ESP is adequately sized, and the by-products can be managed. If the simplified spray dryer proves itself in continuing operation at the Huangdao Power Station and at the next two or three potential installations, it will probably replace conventional designs as the technology of choice where spray dryer performance is desired, because its cost is 10-20% lower. 60 Technology Assessment of Clean Coal Technologies for China Costs for the processes evaluated are shown in Table 3.3. The three coals were selected to represent the range of sulfur content above 1% that would require SO2 removal. Coal analyses of the three coals are shown in Table 3.4. FSI was assumed to be used only for retrofit to existing plants burning lower-sulfur coals. Table 3.3: Summary of S02 Control Costs NEWINSTALLATIONS 300MW 600 MW 800MW LSFO SWS SSD FSI LSFO SWS SSD FSI LSFO SWS SSD Fuel 1 Capital cost, $/kW 59.2 51.9 37.4 41.5 35.5 24.8 36.6 30.3 21.6 Fixed O&M, $/kW-yr 4.2 3.1 2.4 3.1 2.3 1.6 2.8 2.0 1.3 Variable O&M, $/kW-yr 5.5 4.0 8.7 5.5 4.0 8.2 5.5 4.0 8.1 Fuel 2 Capital cost, $/kW 61.0 53.8 38.2 43.1 36.8 25.6 38.3 31.8 22.0 Fixed O&M, $/kW-yr 4.3 3.1 2.4 3.2 2.3 1.6 2.9 2.1 1.3 Variable O&M, $/kW-yr 6.9 5.2 10.6 6.9 5.2 10.1 6.8 5.2 10.0 Fuel 3 Capital cost, $/kW 66.1 57.7 40.9 47.5 40.7 28.4 42.0 35.3 24.8 Fixed O&M, $/kW-yr 4.5 3.3 2.5 3.4 2.5 1.7 3.0 2.2 1.4 Variable O&M, $/kW-yr 11.52 9.28 18.56 11.74 9.31 18.14 11.56 9.36 18.03 RETROFITINSTALLATIONS 300 MW 600 MW LSFO SWS SSD FSI LSFO SWS SSD FSI Fuel 1 Capital cost, $/kW 76.8 67.2 48.5 27.5 53.8 46.0 32.2 19.5 Fixed O&M, $/kW-yr 4.9 3.5 2.7 1.5 3.6 2.6 1.8 1.1 Variable O&M, $/kW-yr 5.5 4.0 8.6 19.4 7.9 5.3 9.1 20.6 Fuel 2 Capital cost, $/kW 79.0 69.8 49.5 29.7 55.9 47.7 33.2 21.2 Fixed O&M, $/kW-yr 5.0 3.6 2.7 1.5 3.7 2.6 1.8 1.2 Variable O&M, $/kW-yr 6.9 5.2 10.6 21.8 9.5 6.6 11.0 22.9 Fuel 3 Capital cost, $/kW 85.7 74.9 53.1 61.6 52.8 36.8 Fixed O&M, $/kW-yr 5.3 3.8 2.8 4.0 2.8 1.9 Variable O&M, $/kW-yr 11.5 9.3 18.6 11.7 9.3 18.1 Note 1: Fuel I (Daton mixed) is 1.20% sulfur; Fuel 2 (Changzi unwashed) is 1.93% sulfur; and Fuel 3 (Sonzao meager) is 4.02% sulfur. Note 2: Fixed and variable costs are first-year costs. Capital costs are total plant costs. Year basis is 1999. Note 3: Plant power costs were taken as $0.03/kWh. This is the average of a figure of yuan 0.20-0.30/kWh for power costs at the plant boundary (converted at yuan 8.30 = $1.00) provided to the study team by one power plant. For new installations, the lowest-cost process, based on capital and fixed operating and maintenance (O&M) costs, is the simplified spray dryer. However, the processes all operate at different levels of S02 removal, and this must be considered in the comparison. In addition, SSD has the highest variable O&M costs of the group. Power Generation and Environmental Control Technologies 61 For retrofit processes, the same is true when comparing the higher-removal processes. FSI shows much lower capital and fixed O&M costs but a very high variable O&M cost. Once again, the low SO2 removal must be taken into consideration. FSI was not evaluated for the high-sulfur fuel because of its high variable O&M costs. Moreover, FSI was not evaluated for an 800-MW boiler as it is better suited to smaller boiler sizes, which allow the injected sorbent to mix rapidly with the flue gas. Table 3.4: Analysis of Fuels Used to Estimate SO2 Control Costs (ASTM Ultimate Analysis, as Received, by Weight) Fuel 1 Fuel 2 Fuel 3 Coal Type Daton, mixed Changzi, unwashed Sonzao, meager Moisture 3.50 1.78 4.22 Ash 33.10 28.69 30.45 Carbon 51.10 61.22 55.93 Hydrogen 2.00 1.00 2.20 Nitrogen 1.00 1.00 0.94 Chlorine 0.10 0.10 0.10 Sulfur 1.20 1.93 4.02 Oxygen 8.00 4.28 2.14 TOTAL 100.00 100.00 100.00 Heating Value, 5500 5100 5150 kcal/kg, LHV 3.2.9 Environmental Impacts The main environmental impact from FGD is the by-product produced. The wet scrubbing systems produce gypsum, and the dry processes usually produce a mixture of ash, unused alkali, and reaction products. A discussion of the impacts and utilization possibilities is presented in Section 3.8. 3.3 NO, Controls The formation of NO, emissions during combustion of coal is controlled by a number of fuel, burner design, and boiler operating factors. It is this dependence that makes NO, emissions so variant among coal types, boiler and burner designs, operating conditions, and even equipment maintenance practices. Therefore, it is often difficult to project the potential reductions in NO, emissions that are possible with available controls without a detailed evaluation of many site-specific conditions. The intent of this section is to describe demonstrated and commercially available NO, controls and provide broad estimates of their NO, reduction capabilities and the costs for retrofitting them on operating boilers in China. These estimates will be principally based on demonstrated performance on U.S. boilers and on cost algorithms developed from documented experience. Application of specific controls in China may require direct purchase of needed equipment and materials or license 62 Technology Assessment of Clean Coal Technologies for China agreements with original equipment manufacturers (OEMs) that hold patents on proprietary technologies. 3.3.1 Technology Descriptions It is well known that NO, emissions from coal combustion have two principal sources: a thermal NO, formation and a fuel NO, formation. Thermal NO, formation is the result of high-temperature reactions of dissociated nitrogen and oxygen in the combustion air. Fuel NOx is partially the result of oxidation of fuel nitrogen in the volatile fraction of the coal. Fuel nitrogen in the volatile fraction of the coal produces a variety of nitrogen-based radicals that rapidly react with available oxygen in the near-burner region to form volatile NOx. Further, fuel NO, is produced when the char is oxidized. In pulverized-coal-fired boilers, all the thermal and volatile-fuel NOx is "frozen" shortly after leaving the burner zone, and no further gas-phase NO, formation or reduction reactions take place in the upper furnace region or downstream of it (unless other NOx control processes are used in this region of the boiler, as described later). However, NOx can still be formed in the upper furnace by reactions between oxygen and the residual nitrogen in the char as the char undergoes final burnout. The NOx measured at the stack is a combination of both thermal and fuel NOx. Commercial approaches for reducing NOx emissions from coal-fired boilers focus on reducing both thermal and fuel NOx either in the lower furnace, during the combustion process, or after the NOx has already left the furnace, in the postcombustion region. Some applications have a combination of approaches to minimize NOx. Controls that focus on reducing NOx before it is formed are generally termed combustion modification controls. These include modifications to the existing burners, replacement of the burners with new low-NOx designs, or the application of staged combustion air via the use of overfire air ports. The details of these modifications depend on the boiler's firing type. Approximately 90% of the boiler capacity in China is fired using fuel and air injectors located at the corners of the furnace. Because these injectors introduce the fuel and air along a tangent to an imaginary circle in the center of the furnace, where they create a rotating fireball around a vertical axis, they are called tangential-fired (T-fired). Most of the remaining boilers in China are wall-fired, with burners located on the walls; these burners can be on either the front wall alone or on both the front and rear walls in an opposed arrangement. Difficult-to- burn coals, such as low-volatile anthracites, are often fired in downshot or W-type furnaces that maximize the time in a high-temperature zone to overcome the fuel's slower burning characteristics. Controls that focus on reducing NO, after the combustion process is completed are typically termed postcombustion or flue gas treatment controls. These include non-catalytic and catalytic reduction controls, either implemented alone or in combination. Working somewhere in between combustion and gas treatment NOx controls are "reburning" controls. These typically call for the use of natural gas-or, less commonly, other fuels such as oil or pulverized coal-introduced in a "reburn" zone above the main burner zone to Power Generation and Environmental Control Technologies 63 provide NO,-reducing radicals. The reburn fuel extends the combustion process higher into the furnace, thereby reducing both the formation of NOx during combustion and the NOx already formed in the lower furnace. Because these rebum control2s generally rely on the use of natural gas, which is not widely or economically available in much of China, this technology may not be of significant interest to Chinese boiler operators; therefore, it will not be discussed in as much detail. The following subsections provide a brief description of the technologies and their reported NO, reduction potential. Several of these technologies can be used either singly or in combination to maximize NOx reductions and, in some cases, reduce cost. Where possible, the impact of coal type on NOx reduction performance will be highlighted. However, the bulk of publicly documented U.S. and European experience has been on bituminous-coal-fired boilers. Only recently, because of the greater use of subbituminous coals such as Montana's Powder River Basin (PRB) coal, have NOx controls been operated with these more reactive, lower heating value coal types. Tuning and Optimization When developing a NOx-reduction strategy for a given unit, a power producer should first consider boiler/burner tuning and optimization. Tuning refers to manual adjustments based on a quick assessment of the plant's condition and performance. Such adjustments are typically inexpensive and provide a cost-effective means of reducing NO, while also improving boiler performance and operation. The associated NO, reduction depends heavily on the unit's condition prior to tuning, but improvements as high as 20% can be achieved for boilers that have not been tuned for years. Engineers in China report that they have been able to reduce NOx emissions 80-150 mg/Nm3 by tuning the boiler, without increasing unburned carbon levels. Optimization relies on the use of a computer program to determine the optimum set points for a potentially large number of components in the fuel and air feed systems (e.g., mills, dampers, fans) to minimize NOx emissions and/or heat rate. Industry experience at over 110 power plants in the United States and Europe has shown that the use of optimization software can reduce NOx emissions 5-30% and improve heat rate 0.5-1.5% beyond the levels achievable with quick tuning. A quick tune is the level of tuning that can be carried out by a plant performance engineer (or outside consultant) in three to five working days. Typical areas addressed in quick tuning include air registers, damper set points, excess air levels, or combustion staging (fuel staging, or biasing; air staging, including simulated overfire air; and burners or mills out-of-service). Adjustment of pulverizer spring tension or outlet temperature could also be included in a quick tune. Optimization software is classified as stand-alone, online/advisory, or closed-loop. Selection of the most appropriate approach for a given boiler depends on the following factors: * Availability of digital control systems (DCS) and/or data acquisition systems (DAS) * The need for continuous or one-time optimization 64 Technology Assessment of Clean Coal Technologies for China * Performance improvement objectives * Cost-effectiveness of the various alternatives Table 3.5 shows how performance can improve, depending on the initial state of the unit and its flexibility/adaptability to operating and low-cost equipment modifications. Table 3.5: Potential Performance Improvements Flexibility/Tunability NO. Reduction, % Heat Rate Improvement, % Limited 5-15 0-0.75 Moderate 15-30 0.5-1.25 Significant 25-40 1.0-1.5 These values are based on experience at a significant number of sites in the United States and Europe. Although most of the applications through 1998 have been with stand-alone systems, approximately 10 units had used online/advisory systems and 13 had used closed-loop approaches, and the number is growing rapidly. Some general rules for selecting the class of optimization software needed for a particular site are as follows: * Stand-alone systems are not suitable for continuous performance optimization. * Online advisory or closed-loop systems are required for continuous optimization at the upper end of the performance improvement range. Even if continuous optimization is not the goal, online advisory or closed-loop systems are more likely to achieve high levels of improvement more cost-effectively than stand-alone approaches. Any optimization process can be used beneficially in conjunction with another NO, control, whether combustion, postcombustion, or both. In fact, the more complex the combustion controls (e.g., low-NO, burners with overfire air versus just low-NO, burners alone), the more likely it is that systems will benefit from using optimization software, relative to manual or other methods. The same is true in situations where the combustion control system already comes close to achieving the unit's NO, emission and unburned carbon objectives. Finally, optimizers (especially continuous online advisory or closed-loop types) relieve operators from the burden of having to continuously monitor and adjust emissions and fireside heat rate performance. Bumer Component Modification Burner component modification (BCM) entails the replacement of certain components in the existing burners to reduce NOx emissions. NOx reduction is achieved by greater separation of air and coal in the near-burner region. The replacement of these burner components is often done in conjunction with balancing the air and fuel flow to achieve the maximum benefit while minimizing operational impacts for this low-cost control approach. Although BCM is site-specific, most applications involve the following activities: Power Generation and Environmental Control Technologies 65 * Redesign of the coal nozzle and swirlers to segregate the coal flow in a way that creates axial and/or radial staging * Addition of devices to split the air flow into secondary and tertiary streams, which are then controlled separately * Addition of flame stabilization components to ensure flame stability and staging at the burner outlet BCM is generally a good retrofit option when only modest NOx reductions of 30-50% are needed. Therefore, the following boilers may be good candidates for burner modifications: * Older boilers in good operating condition (typically an inspection is necessary to ensure that that is the case) * Boilers with first-generation low-NOx burners * Boilers firing volatile or highly reactive coals because these coals show the greatest NO, reduction performance Table 3.6 summarizes the available performance and experience of BCM controls on wall and roof-fired boilers in the United States. Two specific factors affect NOx reduction performance. The first is the specific modifications implemented. Each project may include different modifications ranging from air flow control to flame stabilizers and coal nozzles. The second factor is the operating condition of the boilers. Well-tuned boilers are expected to experience lower NO, reduction than boilers that have not been tuned in the last year or so. Typically, BCM in wall-fired boilers can achieve the following NOx reductions: * Addition of flame stabilizer and air flow control: 10-20% * Addition of coal nozzle and air flow control: 20-30% * Addition of coal nozzle, flame stabilizer, and air flow control: 30-50% For tangentially fired (T-fired) boilers, the retrofit of ABB Combustion Engineering's P2 tips with vaned close-coupled overfire air can be expected to produce NOx reductions in the range of 15-35%. The costs and performance of this, retrofit are just slightly less than those of ABB's LNCFS I system (see Section 3.3.1.4). Operation with BCM is likely to result in some operational impacts, as documented in U.S. applications. For example, unburned carbon in the ash typically increases. The actual amount will depend on the type of coal and grind. Windbox pressure drop increases by 2.0 to 3.0 inches of water (3.7 to 5.4 mm Hg). BCM components also have a limited life, ranging from 3 to 10 years depending on the abrasiveness of the coal. In the U.S., BCM is offered commercially by a number of suppliers, who generally rely on physical or computational fluid dynamics (CFD) modeling to determine BCM designs. Balancing of air and coal flows to each of the existing burners is essential to the success of BCM projects and should be completed before final BCM design. 66 Technology Assessment of Clean Coal Technologies for China Table 3.6: NO. Reduction Performance of BCM Retrofits on Coal-Fired Boilers* Coal Type Typical NOx Controlled NOx Limits Experience Base Fuel Reduction Kg/GJ mg/NmP Ratiof Bituminous 1.0-2.0 10-50% 0.21-0.33 600-930 Very site-specific results; figures shown reflect wall- fired units Subbituminou 1.0-1.3 25-35% 0.19-0.22 550-620 Limited experience s Lignite 1.0-1.2 NAt NA NA No experience available for this fuel Anthracite 3.5-4.0 NA NA NA One retrofit on down-fired boiler * Source: Achieving NO, Compliance at Least Cost: A Guidance for Selecting the Optimum Combination of NOX Controls for Coal-Fired Boilers, EPRI TR-1 11262, December 1998. t Fuel Ratio: Fixed carbon divided by the volatile matter. The smaller the fuel ratio, the more reactive the coal. t NA: No available experience with anthracite or lignite. The study team understands that some power plants in China have collaborated with boiler suppliers, design institutes, and/or technical universities to develop BCM for a few boilers. However, the team was not given any detailed test reports on these installations conducted by independent third-party engineering firms who characterized the furnace, coal, and both pre- and post-retrofit emissions behavior of the burners over the boiler's load range. Hence, this report cannot assess those retrofits. Overfire Air Overfire air (OFA) involves diverting a portion of the burners' secondary air to injection ports (wall-fired boilers) or compartments (T-fired boilers) located above the top burner row. OFA is also called combustion air staging. Typically 10-30% of the air is diverted this way while keeping the overall excess air constant, resulting in substoichiometric combustion conditions in the primary combustion zone. Because of the lack of oxygen in the burner zone, the formation of fuel NO,, primarily volatile nitrogen conversion to NOx, is suppressed. NOx reductions achieved this way can be substantial, at least for medium to high volatile coals. However, this approach can impact boiler operation. The staging of air may lead to increased carbon in the ash, waterwall corrosion, or changes in slagging and fouling patterns and a loss in steam temperature. To avoid or minimize these potential problems, both the location and design of the OFA ports must often be done with the aid of furnace computational modeling and a careful evaluation of the pulverized-coal physical and chemical properties. Power Generation and Environmental Control Technologies 67 In general, OFA effectiveness is primarily dependent on: * Placement of the OFA ports/compartments, which is determined by the available furnace bulk residence times below and above the OFA location and access to this location. Preferably, the location of the ports will provide sufficient residence time both above and below the port location to ensure maximum NO,, suppression and complete burnout of the fuel. * Coal properties, primarily reactivity of the coal, sulfur content, and grind. The higher the reactivity (volatile content), the greater the NOx reduction that can be expected. Higher-sulfur coals can cause increased waterwall wastage rates. Coarse grind will also tend to limit the effectiveness of OFA because of potential increases in unburned carbon. * OFA flow penetration, determined by the degree of mixing and coverage achieved to ensure complete combustion of first-stage unburned fuel. Careful design and placement of the ports is necessary to balance these objectives with the available furnace access options With OFA alone, NOx reductions are generally in the range of 10-30% for wall- and T-fired boilers burning bituminous coals. For subbituminous coals, NOx reductions can be substantially higher. To minimize the effects of increased unburned carbon and reduced steam temperature, excess 02 must often be increased by 0.5-1.5%. Implemented by itself, OFA has seen very few applications because the relatively low NOx reductions do not justify the cost of the pressure part modifications and potential operational impacts such as increased unburned carbon and waterwall wastage. The latter has been a concern primarily for high-sulfur bituminous and other low-volatile coals. For example, in the U.S. only two OFA retrofits are in operation. However, it is used extensively in conjunction with low-NOx burners when needed to meet the emission limits (or reduce the demand on a postcombustion control). Combustion air staging is also a recommended approach for NOx control when burning low- volatile coals in downshot or the German-designed W-type furnaces. The degree of air staging possible depends on the volatile content of the coal.5 For anthracite coals, substoichiometric conditions may not be possible because of requirements to maintain stable ignition and prevent excessive increases in unburned carbon. The NOx reduction performance of combustion air staging for these fuels can approach 50%. In two downshot furnaces in China, engineers were able to reduce emissions to 1200-1500 mg/Nm3 in the unit firing meager coal and 1400-1600 mg/Nm3 in the one firing anthracite using air staging together with low-NO,, burners designed specially for these fuels. However, the unburned carbon levels exceeded 10%. 5 In China, fuels are categorized by volatile matter (VM). On a dry, ash-free basis, coals with VM = 10-20% are called "meager" while those with VM < 10% are called anthracite. 68 Technology Assessment of Clean Coal Technologies for China Low-NO, Burners Low-NO, burner (LNB) technology-i.e., low-NO, burners for wall-fired boilers and low- NO, firing systems (LNCFS) for tangentially fired boilers-is by far the most commonly used NO, control technology worldwide, especially in the OECD countries. LNB is usually adopted prior to trying more expensive postcombustion control approaches. LNB alone may be sufficient to meet emissions targets; if not, it can reduce the size-and therefore capital and operating costs-of subsequent postcombustion controls. Burner control modifications are also generally adopted along with LNB as part of the retrofit. Whether wall-fired or T-fired designs, these new low-NOx burners operate on the principle of creating a reducing zone in the near-burner area to suppress the conversion of volatile nitrogen to NOx. This reducing zone is surrounded and followed by a regime with greater oxygen content, where the combustion process continues towards completion as the gases and char diffuse outward and forward into the furnace. Improved air register designs allow for better control of secondary and tertiary air flows, providing independent control of burner stoichiometry and mixing, by which NOx emissions are reduced. Figure 3.1 illustrates a typical LNB concept for wall-fired boilers. Sometimes for wall-fired boilers and often for T- fired boilers, these new burner systems come equipped with overfire air injection for added NO, reduction. Figure 3.1: Schematic of the Low-NO. Combustion Process Flame stabilized ignition zone Staged air Fuel rich Air \ zone Fuel lean staged zone i --A / staged zone .lgnitiorn zone Staged flame - i\ / stabilzer ; Coal & . . Fuel primary air A A zone Air -*A zone Staged air zone Staged fuel ricth,uel lean comrbustion zone (Section "A-A') Low NOX Flame Cross Section The following sections highlight those technologies applicable to the major categories of wall- and T-fired boilers that are predominant in China. LNB technology for boilers burning anthracite coal is not discussed in the literature, but the study team understands that international boiler suppliers are willing to provide such technology, with guarantees. Of course, these low-NO, combustion systems would not produce the low levels of NO, emissions that can be achieved with the more volatile coals and common firing types, and the systems are all likely to include both burners and air staging ports-i.e., to be more complex, and hence costly, than normal LNB. Power Generation and Environmental Control Technologies 69 Low-NO, Burners for Wall-Fired Boilers All international suppliers of wall-fired boilers, as well as several U.S. independent firms, offer LNB for wall-fired boilers regardless of the original boiler manufacturer. Each of these offerings represents a variation on the basic approach, which aims to improve coal and air separation and control stoichiometry and mixing at all boiler loads. Figure 3.2 illustrates one such commercial offering. With most LNB, the air is split into two annular streams, each swirled by means of separate fixed-vane assemblies. Sliding-sleeve-type dampers independently control the total and inner air zone airflows. Coal flow distributors located within the coal discharge pipe or at the nozzle create fuel-rich and fuel-lean concentrations of coal and primary air at the nozzle exit. Most burners are designed to minimize pressure part modifications when used as replacement for existing burners. Therefore, they fit into existing burner openings. They can be used with separate OFA for added NOx reduction, depending on the NO, regulations, uncontrolled emission levels, acceptable impacts (e.g., whether or not unburned carbon increases must be minimized to maintain ash sales), and the specific economics of each retrofit. Figure 3.2: Schematic of Foster Wheeler's Controlled Flow Split Flame Low-NO, Burner Ignitor . Perforated p late air hood t>F>,->flOuter re gisteta 1: ......HDt -side Post-FG;D Bumout air, Combined Reburn fuel inj nontrol SCR reac vr Air heater (Hot-side) Particulate or Stack FGD device Fuel-Lean Gas Reburn Although commercially offered, fuel-lean gas reburn (FLGR) is a relatively new technology that has seen limited experience in utility boilers. The technology injects a smaller percentage of natural gas into the upper furnace than conventional reburn, nominally 5-8% of the total Power Generation and Environmental Control Technologies 75 heat input. The amount of gas used is not sufficient to create an overall substoichiometric zone, as is the case for the conventional gas reburn; instead, the injection system is designed to create localized substoichiometric zones where the flue gas flow is concentrated. This has the advantage of avoiding the need for, and cost of, overfire air ports. Several demonstrations to date have achieved NO, reductions of 25% to 45%. When compared with conventional gas reburn, the technology represents a tradeoff between costs and performance; i.e., by decreasing cost, the NO, reduction performance is also decreased. Selective Non-catalytic Reduction Selective non-catalytic reduction (SNCR) relies on the injection of nitrogen-based compounds, such as ammonia (NH3) or urea (NH2CONH2), to selectively reduce NO in the presence of 02. At elevated flue gas temperatures between about 760-1090°C, the reaction converts NO to nitrogen and water without the assistance of a catalyst, according to the following global reaction: 4NH3 + 4NO + 02 3 4N2 + 6H20 Below this temperature range, the reagent remains unreacted and NH3 escapes with the flue gas, contaminating the fly ash and causing pluggage in the air heater by ammonia sulfate salts. Above this temperature range, the reagent is oxidized to form NO. Peak NOx reduction occurs at a flue gas temperature of approximately 940°C. The SNCR temperature range typically occurs in the upper furnace region or just as the flue gas leaves the furnace, as illustrated in the schematic of Figure 3.3-5. The actual location in the furnace varies according to boiler load, boiler geometry, and burners in operation, and is normally not constant across each cross-sectional plane. For maximum performance, the reagent must be well mixed with the flue gas and be given enough time within the temperature window to react with the NO. In the laboratory where both temperature and mixedness are well controlled, SNCR can achieve nearly 100% conversion of NO to nitrogen and water, at peak reaction temperature. However, in utility boiler applications, flue gas temperatures are rapidly changing and the mixing of the reagents with the flue gas can be particularly difficult, especially for larger furnaces. These conditions tend to severely limit the performance of SNCR in most utility applications. One notable exception, perhaps, is circulating fluidized-bed boilers because at the injection location (typically in the recirculating cyclone), flue gas temperatures tend to be more uniform and remain constant over a longer gas residence time. The key controlling parameters for achieving peak NO, reduction performance are: * Available residence time in the temperature range of reagent activity * Mixing efficiency achieved by the injection system * Flue gas temperature and CO concentration at the point of injection * Allowable ammonia levels in the ash or stack gas 76 Technology Assessment of Clean Coal Technologies for China Because of the many chemistry and boiler furnace parameters involved, the application of SNCR frequently entails a trade-off between achievable NO, reduction performance and allowable ammonia in the flue gas resulting from unreacted reagent (so-called ammonia slip). In order to maximize the performance of this technology while minimizing unreacted NH3 slip, several modeling and field test measurements are often necessary to fully map the temperature and gas profiles in the upper furnace. These data serve to optimize the location of the injectors and specify the method of injection and injection rate. The NOx reduction potential of SNCR systems for pulverized-coal-fired boilers using either urea or anhydrous or aqueous ammonia ranges from 30% to 55%. Because of the difficulty in achieving good mixing with wall injectors, the greater expense of lance injectors, and regulatory requirements in Europe and the United States, which either can be satisfied by combustion controls or require selective catalytic reduction (see next section), all the commercial applications to date have been limited to smaller boilers, typically less than 200 MW. Thus, the documented performance is limited to smaller units, but at least two demonstrations are underway in 1999 on large units (one 600 MW). NOx reduction will vary significantly with boiler load unless injectors are installed at multiple locations to match the optimum temperature for each load. This increases the cost of the process significantly. As a postcombustion technology, SNCR need not be applied alone, but can be used in concert with combustion controls. For example, in combination with LNB, NOx reductions can reach nearly 70% provided furnace conditions are favorable to the application of SNCR. Potential operational impacts of SNCR on coal-fired utility boilers include: * Air heater fouling due to animonium bisulfate formation in the air heater * Ammonia contamination of the fly ash, affecting ash salability or disposal * Minor increases in unit heat rate due to latent heat losses from vaporization of injected liquids and/or increased power requirements for high-energy injection systems Air heater fouling and fly ash contamination can be minimized by ensuring that NH3 slip is maintained below 5 ppm at all times. Often, the design point is as low as 2 ppm. Selective Catalytic Reduction Selective catalytic reduction (SCR) removes NOx from the flue gas in a reaction combining approximately equimolar quantities of NH3 and NO, in the presence of a catalyst. As in the case of SNCR, the principal reaction products are nitrogen and water vapor. However, traces of NH3 and SO3 are also produced from unreacted reagent and from oxidation of SO2. The presence of a catalyst permits the reaction to take place at much lower temperature than SNCR, typically between 320-400'C. This temperature occurs between the economizer and air heater, where it is possible to insert the reactor vessel and necessary ductwork. SCR for coal-fired power plants is a commercial technology with a growing experience base, mostly limited to low-sulfur (< 2%) coals. In general, SCR can be applied in one of three installation approaches: (1) conventional SCR using a separate reactor, (2) in-duct SCR using a reduced amount of catalyst to fit in existing Power Generation and Environmental Control Technologies 77 or enlarged ductwork, or (3) air heater SCR where one layer of baskets is replaced with catalyst. By far the most widespread use of SCR is the conventional type because it provides the greatest NO, reduction potential. The reactor housing is sized to provide the optimum flue gas velocity and catalyst volume, and is oriented for vertical gas flow to minimize ash deposition on the catalyst surface. The amount of catalyst can also be adjusted to provide the desired NO, reduction efficiency. The upper range of NO, reduction is nominally 90%. However, most facilities worldwide operate between 65% and 80%. Virtually all the vendors' catalysts consist of a V205 active material on a TiO2 substrate, or a mixture of these two compounds in a homogeneous form. Different suppliers add W203 or MoO3 to improve NO, reduction and minimize S02 to S03 conversion. However, there is no reason to select a supplier based just on the compounds they use; all suppliers can deliver the required performance. The differences are more likely to be commercial than technical. SCR installations entail many design and operating considerations. In general, both new and retrofit installations on coal-fired boilers must address the following issues: 1. Coal Characteristics * Coals high in sulfur and with significant quantities of alkaline or alkaline-earth compounds, arsenic, calcium oxide, or phosphorus in the ash can severely reduce the useful life of the catalyst due to poisoning, blinding, and reduced chemical activity. * Most, if not all, catalysts oxidize SO2 to SO3, thereby exacerbating ammonium bisulfate/sulfate deposition on cold-end sections of the air heater, which causes corrosion and increased pressure drop. 2. Reactor Temperature * The active temperature window must be maintained for continued SCR performance. This often entails the use of economizer bypass during low boiler loads or a reactor bypass during startups. * At reduced temperature, catalyst activity decreases, while precipitates can deposit on the active catalyst leading to reduced activity. * S02 to S03 conversion increases with temperature, growing exponentially above 3700C. With increasing temperatures, catalyst sintering occurs, resulting in permanent deactivation. 3. Ammonia Injection * Reagent must be well mixed with the flue gas and in direct proportion to the amount of NO, reaching the catalyst. Careful control is necessary to achieve maximum NO, reduction and minimum NH3 slip. * In general, catalysts guarantees are predicated upon meeting a ±10% variation in flow across the face of the catalyst and a +20% variation in temperature across the face of the catalyst. Flow-straightening devices or static mixers are required to create this uniform flue gas distribution. 78 Technology Assessment of Clean Coal Technologies for China Worldwide, nearly all applications have been on coals with less than 2% sulfur. For SCR applications on coals whose properties differ significantly from those burned in Europe, Japan, or the U.S., boiler owners should conduct pilot-scale tests on sample catalysts to identify any potential poisoning tendencies. Often the catalyst suppliers can design the catalysts to minimize the deactivation rate with the particular flue gas. For China, coals of special concern could be the Sichuan coal because of its high sulfur and ash content, and the Shanxi and Yunnan coals due to their high CaO and P205 concentrations. 3.3.2 Impact of Coal Quality on Combustion Modification NO, Control Coal quality influences boiler NOx emissions and unburned carbon in the fly ash via many complex mechanisms interrelated to burner and furnace design and operation. Qualitatively, these interrelationships are well understood, but simple correlations are not available for the less-used, difficult-to-bum fuels such as anthracite and meager coals. Attempts to develop correlations between NOx and coal quality have been frustrated for the principal reason that coal quality effects are often masked by more dominant effects of furnace/burner design and operation. This is especially the case for low-NOx combustion conditions where combustion stoichiometry, residence time, and furnace temperatures play important roles in the overall conversion of fuel-bound nitrogen to NO and on the thermal NO contribution to the overall measured NOx. While advances in coal sciences have allowed engineers to develop efficient (fast) computer models that can predict changes in NOx for a given boiler due to a change in fuel, these models are based on experience in boilers designed for the more common coals (lignite to bituminous). Presumably, the boiler suppliers have detailed, complex CFD models that can compute performance with low-volatile coals, but these are not available for public analysis. The conversion of the volatile nitrogen fraction in the coal to NO plays an important role in the NOx reduction efficiencies of combustion controls, such as LNB, LNCFS, and OFA in dry-bottom furnaces. Based on correlations of the effects of coal quality on NOx during combustion staging, the principal coal-related property that determines NOx levels is the char nitrogen that is not devolatized in the flame zone near the coal injector. The amount of nitrogen in the char leaving the burner zone is highly dependent on the boiler operating conditions, such as heat release rate and available oxygen (i.e., excess air and level of staging), as well as fuel properties. For the latter, recent research conducted at CONSOL, Inc., points to the strong dependence of NO, on the coal fuel ratio (FR, defined as fixed carbon divided by volatile matter). Figure 3.5 presents full-scale NO, emissions from three tangentially fired units and the CONSOL pilot combustor firing coals with FR ranging from 1.0 to 4.0. The best-fit lines drawn through the data indicate a dependence of NOx on FR based on a simple relationship of the type NO, = a - b/FR (again, for a given boiler, burner, excess 02 level, and OFA settings). For example, for the lowest OFA case (6-10% OFA), the low-volatile coal (FR = 4) emitted about 800 mg/Nm3 in these combustors, whereas a typical bituminous coal (e.g., FR = 1.3-1.8) generated around 500 mg/Nm3. However, other research points to more complex relationships, especially if one includes the full range of world coals. More robust correlations predict char nitrogen using a first-principles model of coal devolatilization, and Power Generation and Environmental Control Technologies 79 then calculate an estimated NO, emissions based on models and empirical correlations for both volatile and char nitrogen conversion to N2 or NO,. Figure 3.5: NO, Emissions from T-Fired Combustors as a Function of Fuel Ratio and OFA Quantity 0.30 .OFA=6-10 0.25 % OFA = 22-25 0, a20 - E Q.1S _ / tr 83o cONSOL 0.5 MW 0 CONSOL 0.S IJW er o/ Q CONSOL 0.5 MW 0.10 5 a Borse* 400 MW o is Maaavlakte 520 MW G 05 _ *~~~~~ DPC Genoa 375 MWV .... .. I I I I I I 1 2 3 4 FR, Fixed CarboruVolatile Mater Figure 3.5 also shows that variations in NO, emissions with FR are lower with increased overfire air levels, corresponding to deeper staging. As with NO, emissions, unbumed carbon levels also increase with decreasing coal reactivity (higher FR). These trends are more readily observed in pilot-scale data than in field applications because the other boiler/burner design and operating parameters have an even greater impact on UBC than they do on NO,. These include coal grind and ash composition in addition to the ones mentioned above. Figure 3.6 illustrates how increasing anthracite concentration in a coal blend increases unburned carbon loss, with and without air staging. Although carbon losses increase in both cases, the rate of change is significantly greater under staging. 80 Technology Assessment of Clean Coal Technologies for China Figure. 3.6: Effect of Anthracite/Bituminous Coal Blend Ratio on Unburned Carbon Loss 0 No air staging A 30% air staging 5 g4 l 0 20 40 60 80 100 Blend Ratio of Anthracite (%) The OECD countries' experience in LNB controls using conventional air staging techniques has been limited to coals with an FR in the range of 1.4 to 3.0. China's low-volatile meager and anthracite coals range in FR from about 3.5 to 10. The increase in combustion-controlled NO, emissions for anthracite due to its low volatility is somewhat compensated by its lower nitrogen content (fuel nitrogen, or FN, = 0.4 for anthracite versus 0.9 for meager coal). Several researchers have developed estimates of the overall impact of burning low-volatile coals on combustion-controlled NOx. However, these estimates have generally not extended to the very hard coals such as anthracite because they are typically burned in different furnace designs, such as downshot units. For example, one correlation indicates that, under staged combustion conditions, Hunan anthracite coal (with an FR*FN product of 4.0) would emit 135 ppm more than would a Shanxi bituminous coal (with an FR*FN factor of 0.92). However, the algorithm development did not include anthracite coals, which generally cannot be burned with the same degree of combustion staging as bituminous coals, and probably under-predicts the difference in emissions. 3.3.3 Commercial Readiness and Applicability to China Most technologies described earlier are commercially available, with a few exceptions: * Fuel-lean gas rebum and other advanced gas reburn processes, which have been tried on only a very few full-scale units to date * Gas reburn and SNCR on large boilers, where reagent mixing with the combustion gas may be a problem. However, a few recent demonstrations suggest that these technologies can work on boilers as large as 600 MW, although the NO, reduction performance may be 5-15% less than on smaller units. Power Generation and Environmental Control Technologies 81 In general, all the technologies should be applicable to boilers in China to the extent that they are compatible with the boiler type and coal. The most notable concern is the limited set of combustion control options for boilers firing very low volatility coals; international boiler suppliers are offering low-NOx burners and air staging technologies, but the performance, cost, and potential impacts of these new offerings have not been demonstrated. The applicability of SNCR also depends on the availability of sufficient flue gas residence time in the critical temperature window (900-970°C). Of course, gas reburning is only applicable where gas is available in adequate supplies and at an economical price. Similarly, continuous, closed-loop optimization approaches would probably not be cost-effective on many existing units, since they usually do not have DCS systems. However, if a plant is going to convert its current control system to a DCS to improve overall boiler performance and/or reduce operating costs, then the additional cost of the optimization software and testing is relatively small and can be a very cost-effective NOx reduction option. 3.3.4 Cost Estimates for NO, Controls Costs of NOx controls, especially retrofit controls, are a function of many site-specific factors. Typically, the more demanding the retrofit, the more uncertain is the actual cost. For example, SCR costs have a greater range because of the significant difference in the modifications that may be necessary at one site versus another. The approach used to arrive at estimates for costs of NOx controls on Chinese boilers was first to develop costs for three U.S. boiler sizes (300, 600, and 800 MW) using both T- and wall-fired designs burning bituminous coal. Following this, costs were then developed for applications in China using ratios of Chinese versus U.S. costs for the major cost categories and estimates of imported versus locally supplied equipment, materials, and labor (see Sections 2.4 and 2.5). Installation labor estimates were generally based on 100% locally supplied labor. Engineered equipment and materials, where applicable, were assumed to contain 95-100% domestic content except for the postcombustion technologies, where imported equipment content ranged from 40% to 70%, depending on the complexity of the equipment and the patent position. About 70% of the instrumentation and controls, including burner management systems, were assumed to come from domestic sources. Estimates were developed for all major NO,, control technologies, regardless of application potential. The costs of combinations of controls are generally additive (although the cost of a combined LNB + OFA retrofit on a wall-fired boiler is $1-3/kW less than if done separately), but the NOx reductions are not always directly multiplicative. All costs are reported as 1999 U.S. dollars. Because the costs for optimization are usually not expressed in terms of $/kW and mills/kWh, they are presented separately in Table 3.9. The table shows typical costs for both stand-alone, one time optimization and closed loop, continuous control for conditions in the United States and Europe. Because optimization is largely a labor activity, assuming the boiler already has a DCS/DAS system, these costs could be significantly less if the technology is transferred to local experts in China. 82 Technology Assessment of Clean Coal Technologies for China Table 3.9 Typical Optimization Costs Optimization Type Initial Cost, 1,000 US$ Annual Cost, 1,000 US$ Stand-alone 40-60 30-50** Closed-loop 150-250* 20-40 * These costs assume the unit has a DCS/DAS. ** This estimate assumes that optimization must be repeated annually. Table 3.10 lists capital cost estimates for retrofit of a 300-MW single-furnace boiler designed for bituminous coal firing with 20 corner or wall burners. Combustion modification controls for T-firing include the LNCFS series of burner arrangements. (Burner control modification for T-fired units costs about 80-90% of LNCFS I and provides 80-90% the NO, reduction, so it is not considered a practical option.) For wall-fired boilers, combustion controls include BCM, OFA, and LNB. Because rebuming (GR and FLGR) is applied above the main combustion zone, it is equally applicable to both boiler types, as are the posteombustion technologies SNCR and SCR. The costs are presented with the average NO, reduction potential anticipated for each of the controls. In general, the controls with the lowest capital cost are those with the least equipment requirements and, especially, the least need for imported equipment. Because ABB's new TFS2000 low-NO, combustion system has been applied to only a few units to date, cost data are not available for the range of possible applications. The major differences in equipment complexity between the TFS2000 and LNCFS III systems are the addition of the second SOFA compartment and the dynamic classifiers in the pulverizers in the TFS2000. Therefore, where this system is applicable (based on furnace height and coal), the incremental cost over LNCFS III could be around $5/kW. In general, BCM, OFA, and FLGR offer the lowest-capital-cost approaches. However, NOx reductions are likely to remain below 40% for these controls. NOx reductions around 50% will generally require an initial investment of about $13/kW to $21/kW (excluding gas reburning). Without gas use on site, the additional control options are SNCR and SCR, and their capital cost ranges from about $6/kW to $5 11kW. For new boiler installations, the costs for FLGR, GR, SNCR, and SCR will likely vary between 60% and 80% of the cost of a retrofit, inversely dependent on the complexity of the system-e.g., 80% for reburning and as low as 60% for SCR. BCM controls are strictly for retrofits and are not applicable to new boiler installations. Costs for LNB or LNCFS I for new installations are essentially zero; all new boilers would be offered with these burners. Incremental costs for OFA in addition to LNB, or for LNCFS III instead of LNCFS I, would likely be 50-60% of the corresponding differential costs for retrofits; a new installation would not have the expense of retrofit installation labor and new burner management/control systems. (LNCFS II is primarily an option for retrofits and offers no advantages relative to LNCFS III for new boiler installations.) Power Generation and Environmental Control Technologies 83 Table 3.1Q: Estimates of Chinese Retrofit Costs for 300-MW Boilers-Shenmu Coal Control Average NO, Cost Estimates, 1, 000 US$ Reduction, % Equipment and Instrumentation Total $/kW Installation and Control BCM 30 724 88 816 2.7 (wall)* OFA 20 459 343 802 2.7 LNB 50 2,874 1,176 4,049 13.5 LNCFS I' 35 1,028 1,215 2,243 7.5 LNCFS II' 40 3,595 1,215 4,810 16.0 LNCFS IIIt 50 5,048 1,215 6,263 20.9 GR 55 1,383 526 1,909 6.4 FLGR 40 500 289 789 2.6 SNCR 35 2,470 235 2,704 9.0 SCRt 75 14,994 320 15,314 51.0 * Wall-Fired: Single wall, 20 burners, 5 burner columns. t Tangentially Fired: Single furnace, five levels of burners. t SCR costs are based on 75% NO, reduction on a unit with furnace exit NO, levels 650 mg/Nm3 and using aqueous ammonia reagent. Table 3.11 provides capital costs of the controls presented in Table 3.3-6 for larger-size boilers. Normally, capital costs show an economy of scale, but this does not occur for some controls because the larger units are more complex-more burners and/or a change from single-wall to opposed-wall firing or from single furnace to twin tangential. Also, because GR, FLGR, and SNCR have seen very limited or no application on large boilers, no costs are given for some of the larger sizes. 84 Technology Assessment of Clean Coal Technologies for China Table 3.11: Estimates of NO. Control Costs for Different Size Boiler Retrofits in China-Shenmu Coal Control 300 MW 600 MW 800 MW 1,000 US$ $/kW 1,000 US$ $/kW 1,000 US$ $/kW BCM 876 2.9 1,720 2.9 2,349 2.9 (wall*) OFA* 802 2.7 1,113 1.9 1,115 1.4 LNB* 4,049 13.5 7,662 12.8 10,325 12.9 LNCFS It 2,243 7.5 4,246 7.1 4,891 6.1 LNCFS III 4,810 16.0 6,624 11.0 7,787 9.7 LNCFS IIIt 6,263 20.9 9,109 15.2 10,230 12.8 GR 1,909 6.4 2,930 4.9 NAlt NA FLGR 789 2.6 NA NA NA NA SNCR 2,704 9.0 3,833 6.4 NA NA SCRI 15,314 51.0 28,723 47.9 37,520 46.9 * Wall-fired units: -300-MW boiler has 20 bumers; 600-MW boiler has 40 burners (20 each on opposed walls in five columns); 800-MW boiler has 48 bumers (24 each on opposed walls in six columns). t T-fired units: 300-MW boiler has a single furnace with 5 levels (20 fuel injectors); 600-MW boiler has twin furnace with 5 levels (40 fuel injectors); 800-MW boiler has twin furnace with 6 levels (48 fuel injectors). t SCR costs are based on 75% NO, reduction on a unit with furnace exit NO, levels = 650 mg/Nm3 and using aqueous ammonia reagent. t NA: Not demonstrated at this size. Table 3.12 provides estimates of O&M costs for these controls on T- and wall-fired boilers. For energy and consumables, these O&M estimates are presented on the basis of changes in plant heat rate and major uses of materials. Combustion modification controls are likely to have an O&M cost due to some losses in efficiencies. These losses come principally from a slight increase in unburned carbon, and in applications with deeper NO, reductions, also from small changes in steam temperatures and excess air levels. Combustion controls can also increase the unburned carbon levels in the fly ash above a level of 4%, which would prevent the power producer from selling the ash to the cement industry (at least in the U.S. and Europe). The potential charges for changing a revenue stream into a waste disposal cost are not included in the table. All these effects are greatly influenced by the type of coal, the operating condition of the existing equipment, and the degree of NOx reduction attempted. Power Generation and Environmental Control Technologies 85 Table 3.12: Estimates of Operating Costs for NO, Controls on a 300-MW Boiler in China Control Plant Heat Rate Major Expendables* Other, $US/yrt Change, % BCM-wall-firedf -0.16 OFA -0.92 LNB -0.41 LNCFS I -0.00 LNCFS I -0.92 - LNCFS III -0.92 GR +0.17 557,000 MJ/hr of natural gas - FLGR +0.10 247,000 MJ/hr of natural gas - SNCR -0.19 697 kg/hr of 29%NH3 solution 29,000 SCR -0.53 $1,229,000/yr for replacement 42,000 catalyst; 684 kg/hr of 29%NH3 solution * Expendables are based on 300-MW boiler with an uncontrolled NO. level of 650 mg/Nm3 operating with a 70% capacity factor. SNCR NO, control efficiency is 33% (lower for larger units); for SCR it is 75%. t BCM equipment has an estimated lifetime of less than 7 years. Includes maintenance labor and materials and, for SCR, annual testing and tuning of the injection grid. Costs are based on China labor rates and U.S.-based labor hour estimates. No expendable costs are indicated for BCM or low-NO, burner systems. However, U.S. experience has shown that some BCMs have required more frequent replacement due to erosion and thermal damage. This is caused by greater variations in the distribution of coal among the burners, resulting in higher coal velocities in some burners. It may also be caused by an increase in the burner component surface exposed to coal flow and in thermal stresses. For reburning and ammonia-based controls, major expendables include the differential cost of fuels, ammonia reagents, and, in the case of SCR, replacement catalyst. Operating labor impacts are likely to be minor for most combustion controls, but maintenance labor costs will increase for postcombustion controls due to the complexity of the system and the potential impacts on downstream equipment, especially air heaters. 3.4 Supercritical Pulverized Coal (PC) Plants 3.4.1 Technology Description Steam boiler designs are characterized as "subcritical" or "supercritical," depending on whether the thermodynamic state of steam exiting to the high-pressure stage of the turbine (main steam) is below or above the critical point of water-about 22.1 MPa-abs (absolute pressure) and 374°C. Because supercritical boilers operate at higher pressures-and generally higher temperatures-than subcritical boilers, they offer higher unit efficiency. 86 Technology Assessment of Clean Coal Technologies for China Most of the basic systems and equipment are the same for both subcritical and supercritical generating units, except that supercritical steam generators do not use a boiler drum that separates steam from water. Thus, these boilers are often called once-through units. High- energy piping and turbine steam chests are also thicker or of a higher-strength material in supercritical units. Subcritical PC Units Conventional subcritical plants are the most commonly used boiler design. High-pressure (main) steam is limited to a maximum practical pressure of about 18 MPa. The range of main steam pressures extends from a low of about 3.5 MPa up to this limit. During operation over the normal load range, feedwater enters the boiler at the relatively cool temperature of 177- 230°C and is heated to saturated vapor in the furnace. The resulting two-phase mixture (vapor and liquid) is separated in a drum, with the liquid returned to the furnace waterwall while the vapor is sent to the superheater. The steam exits the boiler superheated at temperatures usually ranging from 455°C to 565°C, with a current maximum of about 600°C. After passing through the high-pressure turbine, the steam is usually returned to the boiler convective pass for reheating before entering the intermediate- and low-pressure turbines. (Note: Some relatively high-pressure subcritical boilers have been designed for once-through flow, without internal recirculation to the furnace waterwall.) Supercritical PC Units This design requires a minimum high-pressure steam limit of about 23 MPa. The range of pressures used in operating supercritical power plants extends from this minimum up to 35 MPa. During operation over the normal load range, the feedwater entry and steam exit temperatures are similar to those for subcritical boilers. Within a supercritical boiler, the phase change from water to saturated steam and then to superheated steam does not occur because the operating conditions are above the water/steam critical point. Rather, above the critical point a "supercritical" fluid state exists where there is no difference between liquid and saturated vapor. When water is heated at a pressure above 23 MPa, the fluid undergoes a transition in the enthalpy range 1977 to 2442 kJ/kg where its physical properties (density, compressibility, and viscosity) change continuously from liquid to vapor. In supercritical units employing "double reheat," the steam is returned to the boiler convective pass for reheating not only between the high-pressure and intermediate-pressure turbines, but also between the intermediate-pressure and low-pressure turbines. This second reheat step increases unit efficiency relative to single reheat designs. The relative difference in plant heat rate between a basic subcritical unit with steam conditions of 16.7 MPa/538°C/538°C and a supercritical unit operating at 24.2 MPa/538°C/565°C is about 4%. If steam conditions in the supercritical can be increased to 31 MPa/6000C/6000C/600°C (and a second reheat step added), the heat rate advantage over a conventional subcritical unit reaches about 8%. The term ultra-supercritical (USC) has been applied to supercritical power plants that operate with steam temperatures > 570°C (the majority of today's supercritical plants employ steam temperatures below this level). Ongoing research is aimed at developing double-reheat units Power Generation and Environmental Control Technologies 87 that operate at 35 MPa/650°C/650°C/650°C, which would produce an efficiency gain of about 11% relative to a conventional subcritical unit. Such a unit would also be 3-4% more efficient than the current state of the art in supercritical units installed in OECD countries. In countries where the technologies for supercritical power plants are mature, the unit costs ($/kW) are virtually the same as subcritical plants. Thus, selection of a subcritical or supercritical unit often depends on a power producer's experience, the pressure to reduce fuel consumption relative to other considerations, and commercial terms of vendors' bids. The reliability and non-fuel operating and maintenance (O&M) cost of supercritical units have improved since the commercial introduction in the early 1980s of new steel alloys with higher allowable stresses and longer life at elevated temperatures. This is borne out in new USC plants, which have proven themselves to be reliable in routine operation. Based on these successes, researchers continue to improve designs and materials, and it appears that USC plants with main steam conditions of 35 MPa and 6250C (or higher) will be become fully commercial in the next 5-10 years. The following subsections summarize key design are,as and pertinent issues for supercritical units, including turbine and boiler materials selection, effects of water chemistry, boiler design considerations and possible erosion issues, and plant startup. Boiler Materials For superheater and reheater tubes, headers, and steam piping, creep strength and rupture strength are the foremost considerations in the selection of materials. For tubes, fireside corrosion resistance and steam-side oxidation resistance are also crucial. Material for thick-section components, such as headers and steam piping, must also possess fabricability, weldability, fracture toughness, and resistance to thermal fatigue. For operating metal temperatures of 540-565°C, the 1 /4Cr-1,2Mo and 2¼/4Cr-lMo class of steels have been widely used successfully. For higher metal temperatures, stronger alloys are needed. Remarkable progress has been made in the 1990s on 9% to 12% Cr steels that are superior to low-alloy ferritic steels for service at 540-600°C, particularly with respect to creep strength. Improvements have come mainly through optimal use of solid-solution strengtheners, such as molybdenum, tungsten, and carbon, and precipitation strengtheners, such as vanadium, niobium, and titanium. In terms of creep strength and steam-side scale exfoliation resistance, 9-12% Cr steels, such as T91, appear most cost-effective for tubing with metal temperatures of 565-600°C (when fireside corrosion is not a concern). When T91 is used for waterwall tubes, postweld heat treatment is required, which can be difficult to perform in the field. In response, Sumitomo has developed a promising 2.5 Cr steel (T23) that has been approved by ASME without preheat or postweld heat treatment. Test panels are now in service in several boilers. If fireside corrosion proves to be a problem, alloy HR3C may be needed. 88 Technology Assessment of Clean Coal Technologies for China EPRI has published numerous reports on problems related to dissimilar metals weld joints between austenitic and ferritic steel tubing. The reasons for the problems are well understood, and solutions have been developed. Note that special attention should be given to the procedures used for welding such joints. For thick-walled components, such as headers and steam piping, the alloy P91 possesses clearly superior thermal fatigue resistance compared with other lower-alloy ferritic steels (such as P1 and P22, which are widely used in the United States) and higher-alloyed austenitic steels for metal temperatures of 565-580°C. Most designers feel that P91 will probably be limited to maximum steam conditions of 25 MPa and 580°C, a little short of the near-term goal of 31 MPa and 600°C for USC units. However, Professor Fujita in Japan showed that the partial substitution of Mo with W raised the creep strength of 9-12Cr, Mo, V, Nb steels by 30%. This led to further developments including a 9Cr steel developed by Nippon Steel (P92) and a 12Cr steel developed by Sumitomo Metals (P122), both of which have been approved by ASME for use in boiler heavy-section components. Table 3.13 lists candidate materials for various potential steam conditions. Materials for headers and for steam pipes are likely to be similar and, therefore, have been grouped together. In the piping systems, the average metal temperature is expected to be identical to the steam temperature; in superheater and reheater tubes, however, metal temperatures can be up to 30°C higher than the steam temperature. Hence, 9-12% Cr steels, which have a creep- strength capability extending up to 580°C, can be used for piping at 31 MPa/600°C conditions, but are relegated to maximum conditions of 31 MPa/565°C when used for tubing.' (See the list of references at the end of this section; the first citation provides an excellent review of the state of the art in boiler materials development.) Obviously, the recommendations of Table 3.13 should be used tentatively, as actual metal temperatures vary at different stages of the steam-raising circuit and are design-specific. The European COST (CO-operation in the field of Science and Technology) program has now also adopted P91 /T91 as the preferred materials for supercritical boiler design. Power Generation and Environmental Control Technologies 89 Table 3.13: Candidate Materials for Supercritical Plants with Advanced Steam Conditions Phase 0 Phase 1 Phase IB Phase 2 31 MPa 31 MPa 31 MPa 34.5 MPa Component 565/565/565 °C 593/593/593 °C 620/620/620 °C 650/650/650 °C Headers/steam P22,HCM2S(P23), P91,HCM12, NF616 (P92), SAVE12, pipes P91, NF616(P92), HCM9M,HT9, HCM12A (P122), NF12 HCM12A(P122) NF616(P92), E911, HCM12A(P122) TB 12 Finishing SH T91,HCM12M, Tempaloy Al Super 304 H, 17-4 CWMO, non-corrosive HCM9M,HT9, TP347 HFG Tempaloy AA1, Esshete 1250 HT91 ~~~~~~~Esshete 1250, 17-4 Cu Mo corrosive 304SS Tempaloy A3, HR3C, NF707, NF709, HR3C NF709 Inconel 617, Cr 30A, HR6W Finishing RH Same as SH Same as SH Same as SH Same as SH Waterwall lower wall C steel Tl l, T12, T22 Same as Phase 1 Upper wall Tl l, T12, T22 T91, HC12, Same as Phase 1 HCM2S (T23), HCM9M Same as Phase 0 For low NO,, Chromized or clad Same as Phase 0 with alloy Same as Phase containing >20% 0 Cr Separator/safety A302 C steel, 2-1/4Cr-lMo Same as Phase 1 Same as Phase valve 2-1/4Cr-lMo casting, 1 casting, HCM9M WC9 casting Boiler WC6 casting, WC6 WC6 WC6 recirculating 1 -1/4Cr-1/2Mo pump P91 and tungsten alloy materials for boiler superheat and reheat convection surfaces and headers also provide significant improvement in allowable pressures and temperatures relative to previously available boiler materials. These new ferritic materials also provide better corrosion resistance and allow more rapid startup rates. 90 Technology Assessment of Clean Coal Technologies for China Austenitic steel tubing has been used in the past and will continue to be used in future high pressure and temperature cycles despite having higher thermal expansion and lower thermal conductivity. The high allowable stress and corrosion resistance of these materials offset other disadvantages for certain boiler surfaces. Boiler Design Issues Some early supercritical units suffered from undersized furnaces and poor thermal design, resulting in fly ash erosion and thermal creep problems. Because a 10°C change in temperature can cut creep life in half, high temperature gradients can cause local thermal creep problems. Improvements in design to avoid thermal stresses and high velocities in the furnace and convective passes, as well as better materials selection, have solved these early problems. As an example, the use of inclined waterwall tubes was found to provide better heat transfer characteristics and more uniform wallwater temperatures than vertical tubes. Fly ash erosion (FAE) is a concern in all boiler designs, including supercritical units. Erosion of furnace tubes is usually associated with improper operation of wall-type sootblowers. It can be readily eliminated by (1) proper positioning of the sootblower nozzle with respect to the furnace wall in order to maintain appropriate clearance, (2) avoiding instances in which blowers are allowed to operate unnoticed on a continuous basis, and (3) monitoring inlet pressure to avoid excessively high energy levels of the blowing medium (air or steam). Erosion of horizontal convection-pass tube surfaces is driven by local turbulent velocity of the ash-laden gas flowing over the tubes. With proper design velocity and selection of materials, this should be no more of a problem in a supercritical unit than a subcritical one. There will always be a trade-off between chosen gas velocity and ultimate cost of the heat exchange surface. However, it is not always possible to fully predict localized regions of high velocity, and thus localized erosion can occur. Methods are now available to determine localized high- velocity regions once the plant is built and to alleviate those areas by installing strategically located diffusing and distribution screens to limit peak velocities to acceptable limits. High-pressure boiler feedwater pumps have also been developed, with reliabilities comparable to subcritical plant feedpumps, to accommodate the higher pressures used in supercritical boilers. Steam Turbine Design Using today's technology and materials, advanced supercritical steam turbines (with double reheat) can be built to operate at steam pressures of 31 MPa and temperatures of 600°C. Manufacturers have addressed the key design concerns. Thus, supercritical steam turbines can now achieve reliability levels comparable to or better than subcritical turbines. This wasn't always the case. The first supercritical units were built in the late 1950s. By the late 1970s, problems with these first-generation units began to surface. Most were related to specific designs, changes in operating conditions, or plant malfunctions unrelated to higher pressures and temperatures. Nonetheless, a few general areas warranted improvement, both to increase steam operating Power Generation and Environmental Control Technologies 91 conditions and improve plant reliability and availability. The areas of concern included rotor materials and means to combat solid particle erosion of steam turbine blades. Subsequent design and material improvements have offset any deleterious effect of higher steam conditions on the cyclic fatigue life of turbine components. The net result is that current designs do not push design margins on materials beyond the traditional margin of safety used for subcritical units (which, in part, explains why new supercritical units based on these designs have equal or better availability than subcritical units). Parallel advances in rotor forging technology have proceeded in the United States and Europe. Since 1981, the European COST program has been the primary force behind the development of forged IP and HP rotors using 9-12% Cr steels in Europe. Similar developments have occurred in the United States under EPRI sponsorship. Successes achieved by the two programs include the following: (a) Modified 9-12% Cr Alloy Steam Turbine Forgings The development of modified 12Cr steel for forged turbine rotors enables designers to develop machines that can operate at temperatures up to 600°C without the need for internal steam cooling or measures to accommodate highly stressed parts. The formulation of the alloy drew upon on substantial experience in the development, design, manufacture, and operation of conventional 12Cr rotor forgings over an extended period of time. This modified 12Cr rotor steel has a good combination of high-temperature and room-temperature strength, ductility, and toughness. The reduction or elimination of steam bleeds for use in cooling a rotor made from modified 12Cr steel also boosts unit efficiency. The properties of the modified 12Cr alloy were verified by producing and testing a 20-tonne model rotor forging and two 2-tonne Electroslag Remelt forgings."' A modified 12Cr rotor forging was then installed in 1991 in a 500-MW unit at Hokuriku Electric Power Company's Tsuruga Power Plant in Japan. The new 9-l0%CrMo(W)VNbN(B) steels developed under the COST program permit an increase in steam temperatures of about 50-60'C over traditional 1%CrMoV and 12%CrMoV steels. (b) Superclean Steam Turbine Rotor Forgings Optimum steam turbine efficiency can be achieved in supercritical plants by increasing the crossover temperature between the intermediate-pressure (IP) turbine section and the low- pressure (LP) turbine section above the normal limit of 345°C. What had prevented designers from raising crossover temperature was the LP rotor material, which, in the conventional formulation, loses toughness due to embrittlement at higher temperatures (the inlet region of the LP rotor would be at risk). However, a new "superclean" LP rotor material eliminates embrittlement problems, and is therefore suitable for use at temperatures higher than 3450C.111 The material has extremely low impurity levels (i.e., high cleanliness) and excellent toughness, as well as a high resistance to embrittlement. The ability to produce large rotor forgings from this material was verified through the production of a 105-tonne trial rotor forging. Subsequently, seven superclean rotors were produced for 700-MW units at Chubu 92 Technology Assessment of Clean Coal Technologies for China Electric Company's Kawagoe, Chita, and Hekinan stations. The application of superclean steel in the LP turbines also eliminated the need for internal steam cooling, thereby improving heat rate. In all, about 30 superclean rotors have been installed in supercritical units worldwide. (c) Solid Particle Erosion (SPE) of Steam Turbine Blading Exfoliation of magnetite scale from the inside surfaces of superheater and reheater tubes can cause substantial erosion problems in HP and IP turbines. This scale can impact turbine blading at high velocity, resulting in progressive degradation of the turbine (and its efficiency). Damage to the inlet section of the HP turbine can be particularly severe. SPE is exacerbated by high-temperature and high-pressure operation, and if not addressed by designers, can affect supercritical turbines. Cycling duty can also accelerate SPE. During the last 10 years, various technologies have been developed to prevent SPE or minimize its damage. In Europe, the most widely used approach is to employ steam turbine bypass during startup to avoid passing material through the turbine during the critical transient. In the United States, where bypass systems are less common, the most widely used technology is turbine coatings, followed by improved nozzle designs and materials and modifications in flow path geometry. Plasma diffusion coating processes offer long-lasting (five years or more) protection against SPE. The latest turbine designs with modified steam path geometry will reduce the severity of future SPE. Weld repair, though widely used, is basically a repair technology. Based on current utility experience, either a bypass system or erosion-resistant turbine coatings are cost-effective in solving the problem of SPE. (d) Other Steam Turbine Improvements The improvements discussed in the preceding sections are achieved by increasing the temperature and pressure at which heat is added to the power cycle. Other important improvements to the heat rates of both subcritical and supercritical plants have been attained by reducing aerodynamic and leakage losses as the steam expands through the turbine. These latter advances raised overall turbine efficiency from 87% in the 1970s to 90% in the 1990s. The highest losses in the turbine are the blade and sealing losses. In LP turbines, the additional losses attributable to moisture and exhaust indicated that the LP turbine section offered a major opportunity for efficiency improvement. In the 1980s, improved integrally shrouded blades raised the efficiency of the first stages of LP turbines and enabled efficiency gains in HP and IP turbines as well. Use of labyrinth and double strip seals further reduced losses. The introduction of advanced LP turbine blade designs developed through computational fluid dynamics (CFD) modeling and finite element analysis have markedly reduced the relatively high losses from older LP turbines. Gains from improvements in new LP turbine designs, improved condenser and vacuum systems, and condensate and feedwater heaters include: Power Generation and Environmental Control Technologies 93 Reduced pressure drop in extraction and exhaust steam Increased annulus area in the turbine unit Reduced turbine flow losses Enhanced thermal performance in condensers and heaters Water Chemistry Issues Water quality is of particular importance for supercritical units. Because there is no steam drum, from which a blowdown stream could be drawn, all impurities in the feedwater will either be deposited on the furnace and superheater surfaces or carried over into the turbine. Therefore, makeup water and a portion of the condensate must be purified to very high standards. Otherwise corrosion products will build up on the inside of the waterwall tubes, resulting in tube failures -and forced outages for cleaning and repairs. The corrosion products flow from the feedwater heaters in units that operate with deoxygenated all-volatile (AVT) cycle chemistry, and are the primary cause of many of the availability problems observed in first- and second-generation supercritical boilers. Particular problem areas include: * Boiler tube failures, especially circumferential cracking due to thermal fatigue * Boiler waterwall fireside wastage * Boiler pressure drop loss These problems have been worse in oil- and gas-fired units because of their higher heat fluxes. The Europeans have been working on these issues since the late 1960s; EPRI began to tackle them for U.S. utilities in 1984.1V Supercritical units are less prone to corrosion fatigue problems than subcritical units with drum boilers. Therefore, this concern has not been specifically identified as a supercritical boiler issue. One solution to these problems is the use of oxygenated treatment (OT) to maintain purity of the boiler water.v In China and other countries, OT is known as Combined Water Treatment because the process uses both oxygen and ammonia. Treating the water with OT changes the nature of the oxide that forms on the feedwater surfaces from magnetite (with AVT) to ferric oxide hydrate (with OT). The latter has a much lower solubility in feedwater, and hence the amount removed from the feedwater tube walls and transported to the boiler waterwalls is much reduced, as are the waterwall deposits. This means that these units do not need to be chemically cleaned-a significant maintenance saving. Use of OT also makes the water/steam circuit more forgiving to air in-leakage. The use of OT has eliminated many boiler tube problems, made generating units more reliable and easier to operate, and has saved utilities many millions of dollars. Worldwide, approximately 350 supercritical (and over 20 subcritical) boilers manage cycle chemistry with OT. 3.4.2 Commercial Status General Assessment Dramatic improvements in materials for boilers and steam turbines since the early 1980s and a better understanding of cycle water chemistry have yielded an increased number of new 94 Technology Assessment of Clean Coal Technologies for China plants employing supercritical steam cycles around the world. The ultimate selection of a supercritical or a subcritical cycle is, of course, dependent on many site-specific factors, including fuel cost, emissions regulations, capital cost, load factor, duty, local labor rates, and perceived reliability and availability. However, EPRI and others have shown that the reliability and availability of the supercritical cycle, after more than 30 years of research and development, is equal or superior to the subcritical cycle for baseloaded operation. Operation of the first supercritical units in China has confirmed this assessment. The selection of subcritical cycles for the limited number of PC plants that have been built in the United States in the last 20 years has been mainly due to relatively low fuel costs, which eliminated the economic justification for the perceived capital cost penalty of the higher- efficiency supercritical cycles. However, in countries where fuel cost is a higher fraction of the total cost, higher-efficiency supercritical plants can provide a lower cost of electricity and fewer emissions than a subcritical plant. The preference for supercritical units is growing worldwide, especially in Europe and Japan. Figure 3.7 shows a plot of the recent (1992 to 2003) supercritical plants both installed and planned in Europe and Japan. As shown, recent supercritical units range in size from 350 MW to 1050 MW, with most plants constructed after 1998 larger than 600 MW. There is a growing tendency to build 1000-MW supercritical plants, especially in Japan. Figure 3.7: Installed and Planned Supercritical Units Since 1992 1200 - 1000 * * 800 * * * * N 600 - 400- Cx 400 * - * 200 0 1992 1 994 1996 1998 2000 2002 2004 Year Recent Experience Worldwide In the late 1950s, units operating at supercritical pressures were introduced in the United States and Germany. American Electric Power conmmissioned the Philo supercritical unit in 1957 and Philadelphia Electric followed shortly thereafter with Eddystone 1. Today, more than 500 supercritical units are operating worldwide, with ratings from 200 MW to 1300 MW. Steam pressures for these units are typically 24 MPa, with most employing single reheat. Steam temperatures are usually limited to just under 600°C, to enable use of all-ferritic materials for thick-walled components. The increased pressures and temperatures Power Generation and Environmental Control Technologies 95 provide significantly higher efficiency than subcritical units, with attendant reductions in stack emissions of SOX, NOX, CC2, and particulates. The region with the greatest number of supercritical units is the countries of the former U.S.S.R., where 232 units are in operation. They generate about 40% of total fossil-fired power in the region. These units are designed at standard sizes of 300 MW, 500 MW, 800 MW, and 1200 MW. Steam conditions are typically 24 MPa/565°C/565°C. An EPRI study characterized design and operation of these plants.'l The former U.S.S.R. also manufactured 18 supercritical units, at 300 MW and 500 MW, with shaft speeds of 3600 rpm, for China and Cuba. In Japan, 25 supercritical PC plants are in operation, and another 9 are due to startup in the next two years. Until the early 1990s these plants had steam conditions of 24.6 MPa/538°C/566°C, but starting in 1993 the steam temperatures of new plants have climbed up to the ultra-supercritical range, approaching 600°C. The more recent of the large-scale supercritical PC units to come on line, and those planned for commissioning in the next few years, are shown in Tables 3.14 and 3.15, respectively. Table 3.14: Recent Coal-Fired Ultra-Supercritical Plants in Japan Unit Company Output Steam Conditions Startup Date MW MPa/°C/°C Hekinann #3 Chubu 700 24.6/538/593 April 1993 Noshiro #2 Tohoku 600 24.6/566/593 Dec. 1994 Nanao-Ohta #1 Hokuriku 500 24.6/566/593 Mar. 1995 Reihoku #1 Kyushu 700 24.1/566/566 July 1995 Haramachi #1 Tohoku 1000 25/566/593 July 1997 Maatsuura #2 EPDC 1000 24.6/593/593 July 1997 Misumi#1 Chugoku 1000 25/600/600 June 1998 Haramachi #2 Tohoku 1000 25/600/600 July 1998 Nanoa-Ohta #2 Hokuriku 700 24.6/593/593 July 1998 Table 3.15: Coal-Fired Ultra-Supercritical Plants Under Construction in Japan Unit Company Output Steam Conditions Scheduled MW MPa/°C/°C Startup Hekinann #4 Chubu 1000 24.6/566/593 Nov. 2001 Hekinann #5 Chubu 1000 24.6/566/593 Nov. 2002 Tsuruga #2 Hokuriku 700 24.6/593/593 Oct. 2000 Tachibana-wan Shikoku 700 24.6/566/566 July 2000 Karita #1 (PFBC) Kyushu 350 24.6/566/593 July 2000 Reihoku #2 Kyushu 700 24.6/593/593 July 2003 Tachibana-wan #1 EPDC 1050 25/600/610 July 2000 Tachibana-wan #2 EPDC 1050 25/600/610 July 2001 Isogo (New #1) EPDC 600 25.5/600/610 April 2002 Hitachinaka #1 Tokyo 1000 24.5/600/600 2002 Maizuni #1 Kansai 900 24.1/593/593 2003 Maizuni #2 Kansai 900 24.1/593/593 2003 96 Technology Assessment of Clean Coal Technologies for China There are about 60 supercritical units in Europe, chiefly in Germany, Italy (mostly oil fired), and Denmark. Table 3.16 lists the most recent European coal-fired units (and one oil-biomass unit) with advanced supercritical steam conditions. Table 3.16: Recent European Supercritical Plants with Advanced Steam Conditions Power Plant Fuel Output Steam Conditions Startup MW MPa/°C/°C/°C Date Skaerbaek Coal 400 29/582/580/580 1997 Nordiyland Coal 400 29/582/580/580 1998 Avedore Oil, Biomass 530 30/580/600 2000 Schopau A,B Lignite 450 28.5/545/560 1995-96 Schwarze Pumpe A,B Lignite 800 26.8/545/560 1997-98 Boxberg Q,R Lignite 818 26.8/545/583 1999-2000 Lippendorf R,S Lignite 900 26.8/554/583 1999-2000 Bexbach II Coal 750 25/575/595 1999 Niederausem K Lignite 1000 26.5/576/599 2002 An EPRI survey of 159 supercritical units operating in the United States in the mid-1980s found significant efficiency advantages (up to 3%), relative to typical subcritical units, and outage rates comparable to drum units after an initial learning period.vii Most of these units are single reheat units, with typical steam conditions of 24 MPa/538°C/538°C. Table 3.17 lists U.S. plants with advanced cycle conditions and two stages of reheat. Table 3.17: Advanced Supercritical Units in the United States Unit Name(s) & Company Steam Conditions Design MPa/°C/°C/°C Capacity, MW Eddystone 1, PECO 34.3/649/565/565 325 Breed 1, AEP 24/565/565/565 450 Spom 5, AEP 24/565/565/565 450 Eddystone 2, PECO 24/565/565/565 325 Tanners Creek 4, AEP 24/538/552/565 580 Muskingum River 5, AEP 24/538/552/565 590 Cardinal 1&2, AEP 24/538/552/565 600 Hudson 1, PSEG 24/538/552-/565 400 Brayton Point 3, NEP 24/538/552/565 600 Hudson 2, PSEG 24/538/552/565 600 Big Sandy 2, AEP 24/538/552/565 760 Chalk Point 1&2, PEPCO 24/538/552/565 355 Haynes 5&6, LADWP 24/538/552/565 330 Mitchell 1&2, AEP 24/538/552/565 760 Amos 1&2 24/538/552/565 760 EPRI also conducted studies of the optimum steam pressures and temperatures for supercritical cycles in the early 1980s, and also on the preferred materials for boiler and turbine components. Partly on the basis of this work, standards have been adopted worldwide Power Generation and Environmental Control Technologies 97 for new supercritical units; these include the use of P91 (super 9 chrome) for such thick- walled components as headers, steam lines, valves, and turbine casings. EPRI also confirmed that supercritical units in the United States had essentially the same availability as subcritical units . A follow-on study recommended the optimum design for a new supercritical cycle as a 700-MW double-reheat unit with steam conditions of 30.9 MPa/594°C/594°C/594°C. Such units have since been constructed or are in the design phase in Japan and Denmark. 3.4.3 Applicability of Supercritical PC Plants to China Current Status in China Ten supercritical units are currently operating in China, and ten more units are planned or have been approved. Table 3.18 lists the units in operation or under construction. Table 3.18: Supercritical Plants in Operation or Under Construction in China Plant Name Province Coal Type Size, MW Startup Date Shidongkou Shanghai Shanxi 2 x 600 #1 June 1992 Second 1&2 Bituminous #2 Dec. 1992 Nanjing 1&2 Nanjing Shanxi Meager 2 x 320 #1 March 1994 #2 Oct. 1994 Yinkou 1&2 Liaoning Lignite 2 x 300 #1 Jan. 1996 #2 Dec. 1996 Panshan 1&2 Tianjing Shanxi 2 x 500 #1 Jan. 1996 Bituminous #2 May 1996 Yinmin Inner Mongolia Lignite 2 x 500 #1 Nov. 1998 #2 Under Construction Suizhong Liaoning Shanxi 2 x 800 Both Under Bituminous Construction The only supercritical units not supplied by Russia are the two 600-MW units at the Shidongkou Second Plant, near Shanghai, which were put into operation in 1992. For those units, CE/Sulzer supplied the boiler island, and ABB provided the turbine. The steam conditions are the commonly used 24 MPa/541°C/566°C. The other eight supercritical units currently operating in China are of Russian design with similar steam conditions, 25 MPa/545°C/5450C. The experience to date with these supercritical units is somewhat limited, but is nevertheless encouraging. (Note: Appendix C summarizes the project team's visit to two Chinese power plants with supercritical units and also to the three largest boiler suppliers in China.) The plant with the most experience is Shidongkou; in 1997 and 1998 its units had Equivalent Availability Factors (EAF) of 88% and 96%, respectively. The Russian-supplied units have had fewer years of operating experience, and are thus far generally showing lower EAFs, although the two 320-MW units at Nanjing posted EAFs of 85% and 95% in 1997. The staff at the two supercritical power plants visited by the World Bank team displayed a sound 98 Technology Assessment of Clean Coal Technologies for China understanding of the operational characteristics of supercritical plants and of the importance of proper training (e.g., they exercised careful control of water quality and metal temperatures). The three Chinese large boiler manufacturers appear to have the manufacturing capability to provide components made of high-chromium P91 and T91 for supercritical boilers with steam conditions of 25 MPa/540°C/565°C (see also Appendix C). Some additional technology transfer from foreign suppliers may be needed on detailed design issues. If the end-user clients will accept the products of Chinese manufacturers, then the domestic capability exists. All three manufacturers also have experience with the domestically produced 12CrlMoV material. They would import more-advanced materials and Inconels, as well as 12 CrlMoV (when the import price is lower than the domestic price, as is often the case) until the domestic manufacturers gain the necessary technology and quality control capabilities and experience. The three Chinese turbine manufacturers have yet to supply a complete supercritical steam turbine, although they do have the capability to supply some components. The Shanghai Turbine Company (STC) has a joint venture agreement with Siemens-Westinghouse for the supply of design documentation and manufacturing drawings for supercritical (and other) plants. Westinghouse will supply key components and will be responsible for quality control throughout the manufacture. The Harbin Turbine Company (HTC) plans to offer its own supercritical turbine design, but is also in discussion with foreign companies for potential cooperation. The Dongfang Steam Turbine Works (DFSTW) also plans to develop supercritical turbine designs through an arrangement with a foreign company, and to establish the domestic manufacturing capability in a phased manner, starting by importing technology. There is a broad consensus within China that a 600-MW 25 M[Pa/540°C/565°C cycle is the most appropriate supercritical design for China in the near term. Larger units of 800-1000 MW may be also be appropriate for the rapidly growing coastal areas, where the cost of coal is higher and the additional economies of scale and efficiency may be justified. A single- reheat, single-shaft design is recommended. However, there are many double reheat units operating satisfactorily in the United States and Europe, and also a few in Japan. Double reheat typically reduces heat rate by a 1.5-2% relative to single-reheat designs. These should be considered candidates also, despite some concern over the added complexity and cost. In 1995, the average coal consumption in Chinese thermal power plants was 412 g/kWh (standardized coal heat content is 7000 kcal/kg). State Power has set a target to reduce that to 380 g/kWh by 2000, a reduction of 7.8%. The adoption of supercritical technology will assist in achieving this efficiency goal (although the contribution from new units would come after 2000). The difference in coal usage between a conventional subcritical plant with steam conditions of 17 MPa/538°C/538°C and a supercritical plant rated at 25 MPa/540°C/565°C is about 4%. The corresponding coal consumption rates for the 600-MW subcritical and supercritical plant designs used for comparison are estimated to be 314 g/kWh and 301 g/kWh, respectively. A greater gain in heat rate can be expected in the future, when China adopts ultra-supercritical power plant technology. As noted previously, the heat rate of state-of-the-art (USC) units is 4% better than supercritical units operating at 25 MPa/540°C/565°C; an additional 3-4% improvement is projected for future state-of-the-art Power Generation and Environmental Control Technologies 99 units if the ongoing research succeeds in developing plants that can operate at 650°C, and if a double reheat cycle is used. Coal Quality Issues Supercritical plants are being operated worldwide on a wide range of coal types, from bituminous to lignites. In general, the preferred coal characteristics are similar to those preferred for subcritical units. Coal with lower moisture, sulfur, and ash contents will produce higher efficiencies. However, because most supercritical units will operate at baseload, consistent coal quality is particularly desirable to minimize fatigue induced by changes in conditions in the high-temperature regions. High variations in moisture and ash contents should be avoided. With regard to ash content and ash chemistry, the high ash fusion temperatures of many Chinese coals suggests there should be few problems with slagging and fouling. High silica contents can be a cause of concern, as free quartz is usually a good indicator of erosion potential. Additional infornation on coal mineralogy using computer-controlled electron microscopy would be useful for further evaluating boiler deposition, precipitator performance, and erosion potential. Experience has shown that nearly all fireside corrosion problems in supercritical boilers occur in units firing a coal with more than 2% sulfur. Fortunately, 90% of the coal mined in China has a sulfur content of less than 2% on a moisture ash free basis. In those instances where higher-sulfur coal is used, materials with greater corrosion resistance will likely be required for high-temperature regions. Also, if combustion staging (i.e., overfire air) is used for NO, control, corrosion can be a problem at fuel sulfur contents below 2%. Recent EPRI research has led to air and fuel feed guidelines to minimize or even avoid waterwall corrosion while reducing NO,. Chlorine contents > 0.15% can also contribute to fireside corrosion. If fireside corrosion is a concern, stainless steels such as 304, 310, and 347 can be used for waterwall tubing. 3.4.4 Emissions The same fuels and emission control systems can be used for either supercritical or subcritical plants in China or elsewhere. All else being equal, the emissions of SO,,, NO,, C02, and particulate matter (in terms of mg/kWh of electricity generated) will be lower for a supercritical plant in proportion to its lower coal usage per kWh (i.e., improvement in heat rate). For the recommended supercritical plant with steam conditions of 25 MPa/5400C/5650C, the emissions would be about 4% less than those from a conventional subcritical plant operating at 17 MPa/538°C/538°C. Accordingly, for an ultra-supercritical plant with double reheat and steam conditions of 30 MPal600°C/600°C/600°C, the emissions would be about 8% less than those for a subcritical plant. Thus, supercritical and USC technology can aid China in its effort to reduce emissions per unit of final energy. 100 Technology Assessment of Clean Coal Technologies for China 3.4.5 Heat Rate The heat rate benefits of higher temperatures and pressures, as well as double reheat, have been presented previously. The range of these benefits is shown graphically in Figure 3.8 for single reheat cycles and Figure 3.9 for double reheat cycles. Cooling water temperature and the achievable condenser vacuum has an important effect on heat rate. Evaluations based on European plants, particularly Danish units, often use a condenser pressure as low as 2.5 kPa-abs, whereas condenser pressure is more typically 5 kPa-abs in Japan and 8.5 kPa-abs in the United States. In this assessment of supercritical plant performance in China, a value of 6.75 kPa-abs is used. However, if condenser pressure could be reduced from 6.75 kPa-abs to 5 kPa-abs, unit heat rate would improve by about 1.3%. If it could be reduced to the Danish level of 2.5 kPa-abs, heat rate would improve by 3.3% relative to a unit operating with a condenser pressure of 6.75 kPa-abs. Figure 3.8: Heat Rate Improvement from Steam Cycle with Ultra-Supercritical Steam Conditions (single reheat) 9 Single Reheat 593/621 C 593/593 C E 565/593 C 1 5 // 565/565 C | 4 / / / / 5381565 C 3 538/538 C 16 I 0 150 200 250 300 350 Rated Main Steam Pressure (bar) Figures on curve are main and reheat steam temperatures (C) Power Generation and Environmental Control Technologies 101 Figure 3.9: Heat Rate Improvement from Steam Cycle with Ultra-Supercritical Steam Conditions (double reheat) 9 8 Double Reheat 5931621/621 C ' 7 - :F 7593/593/593 C .-' ro 6 5651593/593 C E 5 565/565/565 C _ CL 4 538/565/565 C: 2 5381538/538 C I3 Single Reheat 538/538 C 0 - 150 200 250 300 350 Rated Main Steam Pressure (bar) Figures on curve are main and reheat steam temperatures (C) Shanghai Turbine Company has quoted a turbine heat rate of 7556 kJ/kWh for a 600-MW turbine based on steam conditions of 24.2 MPa/538°C/566°C. Harbin Turbine Company estimates a value of 7601 kJ/kWh for the same size and conditions. These heat rates are based on a condenser pressure of 4.05 kPa-abs (temperature of 15°C), and are consistent with the EPRI estimate of 7726 kJ/kWh for a condenser pressure of 6.75 kPa-abs, which is based on a cooling tower design. The availability of once-through cooling water also has a beneficial effect on heat rate by eliminating the auxiliary power requirements for pumping cooling water to the towers. This can typically reduce overall heat rate by about 0.6%. Coal properties also affect heat rate. High moisture and high ash contents reduce boiler efficiency. Concern over corrosion in the cold end of the air heater and downstream ductwork sets a minimum on the permissible boiler outlet temperature when higher-sulfur coals are used, and thereby reduces the achievable boiler efficiency. A 1 0°C increase in air heater exit temperature reduces heat rate by about 15 kJ/kWh, or approximately 0.2%. Danish supercritical plants, for example, are usually designed for high-quality international merchant coals with low sulfur content. The European standards for calculation of boiler efficiency and turbine efficiency differ from U.S. standards. The combined effects of once-through cooling water at low temperature, higher boiler efficiency due to use of only high-quality coals, and the different efficiency calculation methods account for the differences in attainable heat rates reported by U.S. and European researchers for PC plants with the same steam conditions and reheat stages. Thus, 102 Technology Assessment of Clean Coal Technologies for China European analysts may report net plant efficiencies about 4% higher than the values cited above for essentially comparable supercritical plants. 3.4.6 Operational Impacts Availability/Reliability EPRI studies on the relative reliability of U.S. subcritical and supercritical PC plants in the mid-1980s found that the effects of advanced steam conditions are related more to temperature than pressure.viii By the time first-generation supercritical units had accumulated 10 years of operation, average unavailability of the pressure parts had leveled off at less than 500 hours/year. Temperature effects for coal-fired supercritical plants were chiefly boiler tube thermal fatigue and creep in headers, steam pipes, and turbine forgings and castings due to long-term overheating. EPRI research showed that such effects can be overcome by using high-chrome materials for superheater and reheater tubing, and by using super 9-chrome steel (P91) for high-temperature headers, steam lines, valves, and turbine components. This 9- chrome steel, a very strong ferric material, was initially developed in the United States for nuclear breeder reactors, but it has since been approved by ASME for fossil power plants. It is now routinely used worldwide for fossil units operating at higher steam temperatures and pressures. Other aspects of supercritical plant operation that require attention, based on EPRI's evaluation of early supercritical units, include the design of startup systems and potential adverse effects on valving, solid particle erosion of turbine blades, and waterwall tube cracking. All these issues have been resolved and are not barriers to the use of supercritical steam conditions.l x xlXi As discussed in Section 3.4.3, the Chinese experience to date with supercritical units is very encouraging; the high availability of these units parallels the general worldwide experience with such units. Plant Operability Issues Two perceptions about supercritical plant operating restrictions warrant review: * The added complexity of supercritical plant startup may be less tolerant to operator error. * Supercritical plants are less responsive for load following, cycling, and low-load operation. Earlier designs using excessively thick-walled steam lines and valve bodies have experienced accelerated damage due to severe metal temperature gradients. This then required slower startup procedures and higher minimum loads to ease these stresses. However, with stronger and more creep-resistant materials such as P91, allowable wall thicknesses are reduced, resulting in lower peak stress levels. Throttling and pressure breakdown valves have also evolved through improved designs and more erosion-resistant materials. Power Generation and Environmental Control Technologies 103 From the operator's standpoint, the added complexity of transitioning from the bypass recirculation circuit during startup to the once-through mode can be minimized by current commercial digital control systems (DCS). The improved response, automation, and diagnostics available in today's DCS, and their incorporation in simulator-based training programs, greatly enhance operator effectiveness. Valve coordination during the subcritical/supercritical transition and attemperation system operation to match steam turbine warming have been successfully automated, requiring only operator oversight or minimal interaction. Thus, new materials, improvements in design, and the use of DCS systems have allowed startup procedures and times to be on par with subcritical systems. Historically, coal-fired supercritical plants have been designed for baseload duty. However, where nuclear plants have fulfilled baseload power needs, supercritical plants have sometimes been forced into cycling operation. A conventional subcritical design is a proven cyclic performer constrained for the most part only by minimum load for combustion stability. However, if cyclic operation is anticipated for a significant portion of the life of a supercritical plant, different design features should also be considered.x"' (Japanese supercritical units, for example, are designed for daily startup.) Waterwall designs using rifled tubing and spiral-wound walls can be deployed for cycling and sliding-pressure operation. However, if the supercritical pressure is maintained across the load range, then smooth bore tubing can be used. Supercritical units are capable of operating at full steam pressures over a normal control range of 100% down to 35-40% of their Maximum Continuous Rating (MCR). Lower continuous loads, say down to 25%, may be obtainable, but can be limited by combustion stability or adequate steam/fluid distribution. Within the control range, a once-through unit is likely to be more responsive to load changes than a comparable drum unit, due to its waterwall design. Cycle water purity also needs to be closely maintained during startup and transients with supercritical units, an issue of lesser importance in subcritical units, and thus sometimes underestimated by operators. Direct chemistry monitoring, as opposed to grab sample batch analysis, should be tied into the operator DCS console. 3.4.7 Constructionllnstallation Time The construction/installation time for subcritical and supercritical units should be about the same-roughly 3 years from groundbreaking to completion of installation. 3.4.8 Costs In the United States, Europe, and Japan, the capital costs of subcritical and supercritical plants are very similar on a $/kW basis. For China, in the near term, several key components of supercritical plants would probably need to be imported, such as the high-temperature pressure parts and tubes and materials for piping and the steam turbines. Therefore, the capital cost comparison in China is influenced very much by the relative taxes and tariffs imposed on domestic and imported materials and finished equipment (assuming no additional taxes on erected plants). The costs presented in this report assume that the following materials and equipment of a supercritical plant built in the next 3-8 years would be imported: all high-temperature, high-pressure tubes; alloys for steam pipes and headers; the steam 104 Technology Assessment of Clean Coal Technologies for China turbine rotor; and the boiler/turbine control systems. In a mature Chinese market (i.e., when most of the plant equipment can be purchased within China as it is now for subcritical units), it is expected that the capital costs of subcritical and supercritical plants would also be similar on a $/kW basis. The standard 600-MW subcritical and supercritical units evaluated for deployment in China were estimated to have capital costs of $548/kW and $607/kW, respectively. Economies of scale could reduce the $/kW cost for units in the 800-1000 MW range. In particular, there is a modest improvement in steam turbine efficiency and lower percentage heat losses as size increases. Cycle and cost estimates indicate that an 800-MW unit has 1% better heat rate and a 7.5% lower unit capital cost ($/kW) than a 600-MW plant. Several larger units are currently operating in the United States, Europe, and Japan. The distribution of costs during the installation period follows the usual S-shaped curve, with the largest portion in the second year following the delivery of major equipment items to site. 3.5 Atmospheric Fluidized-Bed Combustion (AFBC) 3.5.1 Technology Description General Characteristics Like conventional pulverized-coal (PC) boilers, atmospheric fluidized-bed combustion (AFBC) units employ a Rankine steam- cycle, and from the exterior, a waterwall-enclosed AFBC unit resembles a PC boiler. The most common AFBC designs now add a large cyclone between the furnace and the convective heat transfer sections to recirculate unburned fuel back to the bed, where the remaining carbon can be burned; these systems are called circulating fluidized-bed combustors (CFB). Inside the furnace, the differences from PC boilers become apparent. AFBC boilers operate at lower temperature and pressure, and burn a non-pulverized fuel in a fluidized bed. They are capable of burning high-ash coals and other low-rank fuels that cannot be accommodated by PC units. FBC boilers capitalize on the unique characteristics of fluidization to control the combustion process, minimize NO,, formation, and capture SO2 in situ. In S02-capture applications of FBC, coal and limestone are fed into a bed of hot solid particles that are suspended in turbulent motion (fluidized) by combustion air that is blown in from below through a series of nozzles. The limestone is converted to free lime, a portion of which reacts with SO2 to form calcium sulfate (CaSO4). At steady-state operation the bed consists of unburned fuel, limestone, free lime, calcium sulfate, and ash. Because of the well- mixed nature of the bed and the relatively long residence time of the fuel particles (via high recycle rates in the CFB), efficient combustion can be maintained at temperatures as low as 850-900'C. This low combustion temperature limits the formation of NO,, and is the optimum temperature range for in-situ capture of SO2 by the free lime. The low temperature also prevents or limits the slagging of coal ash, thus greatly reducing slagging and fouling of heat transfer surfaces. Power Generation and Environmental Control Technologies 105 For low-sulfur coals in which SO2 capture is not required, sand is used as the bed material in place of limestone. For some high ash-coals, the ash itself may provide sufficient bed mass without the addition of sand. Also, coals with a high calcium content in the ash and needing only moderate SO2 removal often do not need to have limestone added to the bed. The bed of solids provides thermal "inertia" which moderates upsets due to sudden changes in fuel composition. However, the limestone sorbent requirement and the spent sorbent tonnage for solids disposal are 50-100% higher than for PC plants with flue gas desulfurization (FGD). The enviromnental competitiveness of FBC with PC boilers is enhanced by the lower NO, production-typically in the range of 0.022-0.086 kg/GJ without postcombustion NO, controls, compared to 0.086-0.172 kg/GJ for new PC boilers with the latest low-NO, burners and overfire air. The use of relatively inexpensive selective non-catalytic reduction (SNCR) with FBC can reduce the flue gas NO, level an additional 50-90%, depending on ammonia slip and detached plume considerations. With a PC boiler, the more expensive selective catalytic reduction (SCR) would probably be required to achieve the same flue gas NO, levels as FBC with SNCR. FBC units can handle a wide variety of fuels including those difficult to burn in PC or stoker boilers, such as high-ash coals, slagging/fouling coals, coal wastes, and industrial and municipal sludge. However, this fuel flexibility is assured only if the FBC boiler is designed for the full range of fuels that are intended for use. Combustion temperatures can be maintained for fuels with heating values as low as 4650 kJ/kg, assuming no combustion heat removal. Types of Boilers There are two basic types of FBC-bubbling and circulating. Hybrid designs build off the advantages of each of these basic types. Bubbling FBC Bubbling FBC (BFB) operates at low superficial gas velocities (1-3.7 m/s), such that the bed is expanded and lifted, but not carried away (i.e., entrained), and it looks like a bubbling boiling liquid. In-bed boiler tubes can be effectively employed for combustion control in BFB if adequate tube erosion safeguards are also employed. Circulating FBC Circulating FBC (CFB) operates at gas velocities high enough to entrain a large portion of the solids (3.7-9.1 m/s), which then have to be efficiently separated from the flue gas and recycled (recirculated) to the lower furnace to achieve good carbon burnout and sorbent utilization. Typically an external high-efficiency cyclone is used at the furnace exit as a separation device. CFB recycle ratios typically exceed 40 kg of recycled solids per kg of feed solid, and may be much higher depending on the cyclone efficiency. In contrast, fly ash recycle from the baghouse or low-efficiency multiclones in BFB generally does not exceed 5 kg/kg and is typically - 3kg/kg. 106 Technology Assessment of Clean Coal Technologies for China In-bed boiler tubes cannot be used in the CFB furnace because of severe tube erosion. However, an optional external bubbling fluidized bed can be employed as an external heat exchanger (EHE). In this unit, boiler tubes are immersed in a bed of the hot recirculating solids from the cyclone that are lightly fluidized by low-velocity secondary air. The cooler solids leaving the EHE are then recycled to the lower furnace. An EHE can take up a large fraction of the total heat duty in large CFB unit, and therefore provides a flexible alternative to the need for additional in-furnace heat transfer surface (wing walls, panels, etc.) in units larger than 40 MWe (net). An EHE is also advantageous in conserving the fumace height in large CFB units and in optimizing reduced-load operation. Because of the high recycle rate (high residence time) of unutilized sorbent and unburned carbon, CFB provides better SO2 capture and better carbon burnout than BFB. CFB also facilitates more effective air staging for improved NO, control and is less prone to upsets due to fuel quality variation. Consequently, atmospheric pressure CFB is the predominant type of FBC boiler installed worldwide in unit sizes above 90,000 kg per hour of steam. Hybrids A few variations on these two basic types of AFBC involve hybrids of BFB and CFB features, and designs to circulate the solids internally rather than externally. Hence these designs are referred to as hybrid FBC (HFB) and internally circulating FBC (ICFB). Selected bubbling and circulating FBC features are combined in hybrid FBC boiler designs in efforts to realize the advantages of both and minimize the disadvantages of both. Commercial designs in the hybrid FBC classification are offered by Combustion Power (which has been acquired by ABB-Combustion Engineering), Deutsche Babcock, Ebara, and Austrian Energy & Environment (AE&E). The Combustion Power design operates in the low-velocity range (1- 1.5 m/s) of the bubbling bed regime, but employs a high recirculation rate of fines. The Deutsche Babcock design operates in the transition between the bubbling and circulating fluidization regimes (4-4.5 m/s). Ebara and AE&E designs employ internal recirculation of solids, achieved partly by using internal partitions to separate a high-velocity circulating fluidized bed from a low-velocity bubbling bed-both inside the combustor. They are also called internally circulating FBCs (ICFBs). The ICFBs were originally developed for burning refuse and waste fuels, but are applicable to coal also. So far their applications have been relatively small-scale projects. 3.5.2 Commercial Readiness FBC is a relative newcomer to the field of commercial large-scale boiler technology. It is only since the early 1990s that FBC boiler technology has really become established worldwide as a mature, reliable technology for the generation of steam and electric power- with its added advantage of in-furnace SO2 capture with limestone. In fact, the major impetus in the widespread deployment of this relatively new boiler technology, particularly CFB, since the mid-1980s has been its resemblance to a conventional boiler with the added capability for in-situ SO2 capture, which eliminates the need for FGD. The primary proving grounds for FBC boilers have been the United States, Western Europe, and Japan. Hundreds of FBC boilers, predominantly atmospheric pressure CFB boilers, have Power Generation and Environmental Control Technologies 107 been deployed in these three regions to meet strict SO2 and NO, emissions limits with sulfur- bearing fuels. Since the late 1980s, numerous FBC independent power producers (IPPs) with contractual availability incentives, industrial cogenerators/self-generators, and utility owned and operated FBC plants have consistently achieved availabilities and annual capacity factors in the 80-95% range. Units in the 50-165 MW size range are now proven and widely used by industrial cogeneration, independent power producers, and utility power plants. There are several CFB plants > 200 MW in France, Korea, Poland, and the U.S. The only large bubbling FBC boiler is EPDC's 350-MW unit at Takehara, which was supplied by Hitachi and started up in 1995. Operating AFBC units > 200 MW are listed in Table 3.19. Figure 3.10 shows the worldwide growth in numbers of all types of FBC boiler installations with steam capacities > 22,000 kg/hr, from 1960 through units commissioned in 1996. Figure 3.11 shows the corresponding growth in total installed capacities. These data indicate about 260 bubbling FBC units worldwide through 1996 with an average unit steam capacity of 77 t/h and about 300 CFB units with an average unit steam capacity of 156 t/h. The continued growth in bubbling FBC installations reflects their recognized suitability for low-sulfur fuel applications, e.g., for biomass plants and certain retrofits. CFB boilers employed in cogeneration applications have typically had steam capacities of 136-272 t/h. Table 3.20 presents the number and steam capacity of FBC installations in China and worldwide by application. Table 3.19: AFBC Units Larger Than 200 MW Company, Location Type, Net MW Startup Fuel Type Plant Name Supplier EPDC, Hiroshima, Bubbling FBC, 315 1995 Imported Coal Takehara Japan Hitachi EDF, Provence, CFB, 232 1996 Subbituminous Gardanne France Stein (Lurgi) Coal, 30% ash, 4% S Turow Power Silesia, CFB, 2 x 230 1999 Brown Coal, Station Poland Foster Wheeler 23% ash, 44% H20, 0.6% S KEPCO Kangwon-do, CFB 200 1998 Korean Anthracite South Korea KHI/ABB- CE AES Warrior Run, CFB, 2 x 200 1999 Bituminous Coal Maryland, USA ABB-CE/Lurgi JEA Jacksonville, CFB, 250 2002 Bituminous Coal, Florida, USA Foster Wheeler Petroleum Coke Sithe/Tractabel Red Hills, CFB, 2 x 220 2002 Lignite Mississippi, USA ABB-CE/Stein 108 Technology Assessment of Clean Coal Technologies for China Figure 3.10: Historical Growth of FBC Boiler Installations Worldwide (Number of Units) 700_____= Al 50,000 /" A lat 600 ad No c of.o seu hti U. 500 _____ CFBC 400 APBC 7 HFBC 300 FBo MI' 0- ~ a i - - -9-- 300 = Tot_ ofuill U.S f C Botines X0= U 200 Z O0 *0 U _ _ _ _ 01955 1960 196S 1970 1975 1980 0985 1990 1995 2000 Year of Start Figure 3.11: Historical Growth of FBC Boiler Capacity Worldwide (Accumulated Equivalent Steam Capacity, Mlb/hr) Ac ateo uice . Boosts *B ni taopotuiu Ž 50,000 OblhJ t I noo,f oO w st of bgoennod tignwi/ SIe C zia not nCluded C. Pa 040,000 ityc, 1b 020,000 / 000,000 Tol . . s~--0- CFBC/ 60,000 _Tot. of11 U.S. FBC Ble 20,000 0 h - --__-_r-----. - 1955 1960 1965 1970 1975 19S0 1985 1990 1995 2000 Year of Start Power Generation and Environmental Control Technologies 109 Table 3.20: FBC Installations by Application-Real Projects Only, China and Worldwide* Utility Cogeneration Small Power District Heating Process Steam Location No. Steam, No. Steam, No. Steam, No. Steam, No. Steam, 106 kg/hr 106 106 106 106 kg/hr kg/hr kg/hr kg/hr China 19 2,170 16 1,670 2 40 0 0 0 0 Total 114 23,940 337 41,037 61 5,840 46 3,506 74 2,825 Worldwide Source: EPRI FBC Database, updated by SFA Pacific, Inc., 3rd Quarter 1995 * No. is number of units; steam is total equivalent primary steam capacity 3.5.3 Applicability of AFBC Technology in China China initiated work on bubbling-bed AFBC boilers in the early 1960s and currently ranks first in the world in terms of the number of small-scale AFBC boilers. There are, at present, about 3000 small-scale AFBC boilers in operation throughout China, all of which were designed and manufactured in China. Research work on CFB boilers was started later. In the 1990s, a series of CFB test facilities was constructed by the National Engineering Research Center of Clean Coal Combustion, or NERC-CCC, which was established in 1992 and hosted at Thermal Power Research Institute (TPRI) of the State Power Corporation of China. Key technologies and SO2 removal performance for CFB systems have been examined, and the test results have been used to guide the design and operation of large CFB boilers. A small-scale CFB test rig was constructed in 1991. Test work carried out on this rig included measurements of combustion efficiency, SO2 removal efficiency, and temperature/pressure distribution along the furnace height. Five coals and three limestones were tested and provided the design basis for four engineering projects. In 1993, a I-MWth pilot-scale CFB test facility was constructed. Since the furnace height (23 m) is near that of a full-scale CFB boiler, the test results represent the actual operating process. To date, tests of five coals and six limestones have provided the technical basis and guidance for the design and operation of relevant engineering projects. The first small-scale CFB boiler, with a live steam output of 35 t/h for power generation, was put into operation in 1989. China now has more than 300 operating small boilers with live steam output of 35-75 t/h for power generation. At present, China is capable of manufacturing AFBC boiler units up to 50 MW capacity. As shown in Table 3.21 nearly 20 units rated > 50 MW are currently in operation or under construction. Over the past several years, the Chinese market for Western FBC technology has grown significantly, and all of the major vendors are active in China. Some of them have developed relationships with major Chinese boiler manufacturers. 110 Technology Assessment of Clean Coal Technologies for China Babcock & Wilcox Beijing Co., Ltd. (BWBC) is the joint venture company formed by B&W and Beijing Boiler Works in 1994. Beijing Boiler Works (BBW) continues to exist and holds a license for the Deutsche Babcock Circofluid boiler through Deutsche Babcock's U.S. subsidiary, Riley DB. Several Circofluid units are under construction or have already been commissioned in China. Shanghai Boiler Works has supplied several CFB boilers through an arrangement with Foster Wheeler Energy Corporation, both within China and also elsewhere in Asia. In China, they supplied two 50-MW units to Aixi in Sichuan in 1996. Dongfang Boiler Works has been collaborating with Foster Wheeler (and previously with the former Ahlstrom Pyropower, now part of Foster Wheeler) since 1994 in the introduction of Foster Wheeler's CFB technology in China. Several-units have been supplied at the 50 MW size, and six units of 100 MW are currently being built in Hebei province (see Table 3.5-3). Power Generation and Environmental Control Technologies 111 Table 3.21: CFB Boiler Units in China Larger Than 50 MW Live Stveam Bie N.of Steam Prme Fuele Plant Name Province Units Output, Parame Supplier* th MPal/0C I Dalian Xianghai Thermal Liaoning 2 220 9.8/540 HBC Bituminous Coal Power Plant 2 Changshu Yatai Paper Jiangsu 2 241 12.5/54 HBC Bituminous Coal Corporation 0 3 Yanzhou Power Plant Shandon 2 220 9.8/540 HBC Bituminous Coal (minemouth) g 4 Wangjiangmen Thermal Zhejiang 2 220 9.8/540 Bituminous Coal Power Plant 5 NanJing Jinling Power Jiangsu 2 220 9.8/540 Alstrom Petroleum Coke Plant 6 Shanxi Zhenxing Power Shanxi 1 240 3.82/45 JBW Middlings Plant 0 Pingdingshan Coal 7 (Group) Co., Ltd. Henan 1 220 9.8/540 DBW Bituminous Coal (minemouth) 8 Zhenhai Power Plant Zhejiang 2 220 9.8/540 FWEI Petroleum Coke 9 Dalian Chemical Liaoning 2 220 9.8/540 FWPI, Bituminous Coal Industrial Corporation HBC Hangzhou Xielian FWPI 10 Thermal Power Zhejiang 1 220 9.8/540 HBC' Bituminous Coal Corporation 11 Aixi Thermal Power Plant Sichuan 1 220 9.8/540 FWPI Meager Coal SBC 12 Liaohe Thermal Power Liaoning 1 220 9.8/540 FWPI, Bituminous Coal Plant HBC BiunosCa 13 Ningbo Zhonghua Paper Zhejiang 2 220 9.8/540 DWB Bituminous Coal Corporation 14 Zhejiang Paper Zhejiang 3 2 x 400 9.8/540 FWEC Bituminous Coal Corporation 1 x250 15Jiaozuo Power Plant Hnn 2 40 9850Meager Coal, (planned) Henan 2 410 9.8/540 Coal Rejects 16 Shijiazhuang Power Plant Hebei 4 410 9.8/540 DBW Meager Coal (planned) 17 Baoding Power Plant Hebei 2 450 9.8/540 DBW Meager Coal (planned) 18 Yibin Power Plant Sichuan 1 410 9.8/540 DBW Meager Coal (planned) 19 Neijiang Power Plant Sichuan 1 410 9.8/540 FVWEOY' Meager Coal 20 Baima Power Plant Sichuan 1 1025 13.7 Anthracite (planned) 540/540 * HBC: Harbin Boiler Company Ltd., China DBW: Dongfang Boiler Works, China SBW: Shanghai Boiler Works, China FWEC: Foster Wheeler Energy Corporation, USA FWPI: Foster Wheeler Pyropower, Inc., USA FWEOY: Foster Wheeler Energia OY, Finland 112 Technology Assessment of Clean Coal Technologies for China Harbin Boiler Works (HBW) had an arrangement with Ahlstrom Pyropower for the development and supply of CFB boilers up to 50 MW. They now have an arrangement with EVT of Germany for the technology transfer and design of CFB units of 50-100 MW. EVT was a former licensee of Ahlstrom Pyropower in the period 1983-1992. In 1992 the license expired, but because it covered an early design, apparently EVT is able to market it independently. However, EVT is part of the Alstom group which also includes Stein Industry, a Lurgi licensee. The ownership of CFB technology is further complicated by ABB's recent announcement of a merger with Alstom. In addition, Combustion Power Company, which itself has recently been taken over by ABB, has a licensing arrangement with HBW for the design and supply of FI-CIRC FBC units in the range of 35-75 t/h of steam capacity. This latter agreement was made possible through the Global Environmental Fund (GEF) Industrial Boiler Program. A 100-MW CFB boiler was imported from Foster Wheeler Energia Oy of Finland under an agreement signed in June 1992. The State Power Company selected the 100-MW Gaobo Power Plant at Neijang, Sichuan-owned by the Sichuan Electric Power Administration (SEPA)-as a CFB demonstration project. The steam turbine is of Chinese design and was supplied by Beijing Heavy Machine Works. The plant started commercial operation in June 1996 using a local anthracite of high ash (average 32%) and high sulfur (- 4%). The World Bank team visited the Gaobo plant on April 30, 1999, and up to that time 14,700 hours of operation had been accumulated. All emission guarantees have been met or exceeded (< 700 mg/Nm3 SO2 at Ca/S = 2.2 and < 200 mg/Nm3 of NO,). The unit can operate stably as low as 30% of maximum capacity rating (MCR) and in 1998, the first full year of operation, the availability was 79%. The anthracite is of low reactivity and the unburned carbon in the ash was as high as 18% originally but has recently been reduced to 13% through an increase of air flow to the combustor and partial recycle of the ESP fly ash. The State Power Company is also planning a 300-MW CFB demonstration plant at Baima, also in Sichuan province. This CFB boiler is designed to burn anthracite with high sulfur and ash contents. It will effectively solve the problems of lower combustion efficiency, higher pollutant emissions, and slagging encountered in conventional firing systems. The World Bank team was told by the Chinese boiler manufacturers that the intent was to solicit bids for the design and technology transfer. The technology is intended to be shared with the three main Chinese boiler manufacturers-Shanghai, Dongfang, and Harbin-although the boiler would probably be built by Dongfang because of its closer proximity to the Baima site. It was stated that the solicitation was to be sent to Foster Wheeler, ABB-CE, and Alstom-Stein. However the recent merger arrangement between ABB and Alstom could reduce the competition to just two firms. In summary, CFB technology is suitable for use with the wide range of Chinese coals, from lignites to anthracites. It is particularly suited to high-ash coals, typical of many Chinese coals, when correctly designed for them. There is ample domestic Chinese operating experience with CFB units up to 100 MW. Domestic boiler manufacturers have supplied units up to 50 MW. Technology arrangements are in place for the supply of 100-MW units and several are currently in construction. The State Power Corporation plans to solicit bids Power Generation and Environmental Control Technologies 113 for the design and technology transfer of a 300-MW CFB unit to be located at Baima, Sichuan province. 3.5.4 AFBC Emissions Air emissions and solid wastes are the effluents of primary concern from FBC boilers. Liquid effluents from FBC boilers are primarily a function of the steam cycle design and operation, and are comparable to those from PC boilers. Because a major advantage of an FBC plant is its cost-effective reduction of air emissions (as well as its ability to use fuel sources that are difficult to burn), this section focuses on air emissions. Solid waste issues are discussed in Sections 3.5.8 and 3.5.9. Air emissions in the form of fugitive dust from fuel, limestone, sand, bottom ash, and fly ash handling and storage are not covered in this report, since these emissions are controlled by well-established designs for such systems. S02 Emissions In an FBC unit, SO2 capture is a function of the limestone reactivity, bed quality, and Ca/S ratio, increasing in proportion to these parameters. As the sulfur content of the fuel increases, the Ca/S ratio (i.e., the available CaO surface area) required for a given percentage SO2 reduction decreases because of the increased driving force (partial pressure) for the sorption process. For high-sulfur coals (> 2% S), the typical SO2 emission level when using Ca/S ratios of 2-2.5 is 5-9% of the theoretical maximum based on fuel sulfur content (i.e., > 90% sulfur removal). For low-sulfur coals (< 1%), a Ca/S ratio of 3-6 is required to achieve the same 5-9% of the theoretical maximum. Sorbent utilization is optimal at 800-900°C; however, somewhat higher temperatures may be required with low-reactivity fuels to achieve good carbon burnout and prevent combustion in the cyclone(s). Burning in these devices can cause sintering and plugging of the cyclone. The inherent CaO content of some coal ashes also contributes to SO2 capture. However, the Chinese coal analyses provided to the World Bank team have mostly low CaO content; the two exceptions, Shenmu and Zhaotong, are both of low sulfur content, so that the contribution to SO2 capture would be minor. Several of the coals listed have sulfur contents on a moisture ash free (MAF) basis of < 1%, and for these coals, limestone addition may not be necessary. Some of these low-sulfur coals also have fairly high ash content, so that it may not be necessary to add supplemental bed material. Engineers at the 100-MW CFB Neijiang Gaoba Power Plant in Sichuan province measured SO2 emissions of 684 mg/Nm3 at a Ca/S ratio of 2.2 for the local anthracite with a 3.5% sulfur content. This is equivalent to about 93% sulfur removal. S03 Emissions SO3 is generally not a concern with FBC units, because only a relatively small portion of the SO2 produced is oxidized to SO3 at the low firing temperature in an FBC. Further, the sorbent also removes (reacts with) any SO3 that might be formed. 114 Technology Assessment of Clean Coal Technologies for China NO, Emissions Because of the relatively low temperature of the FBC process, the NO, output is inherently low. Theoretically, the only NO, produced is fuel NO, (from the oxidation of fuel-bound nitrogen), because no appreciable thermal NOx is produced at temperatures below about 1500°C. However, some thermal NOx could be produced if poor fuel distribution creates localized hot spots in the combustor, and the production rate would depend exponentially on the temperature of these hot spots. NOx production is reduced by staging the combustion air and decreasing the overall excess air level. Unfortunately, higher Ca/S ratios to increase sulfur capture rates can also increase NOx. NOx emissions from FBC boilers are typically 5-15% of the theoretical equivalent of conversion of all the fuel-bound nitrogen to NOx. This is typically equivalent to emissions in the range of 60-240 mg/Nm3. A test run at the Gaoba plant measured NOx emissions of 78 mg/Nm3 compared to a contract guarantee of 200 mg/Nm3. With the installation of selective non-catalytic reduction (SNCR), the NOx at the furnace outlet can be reduced a further 50- 90% depending on the amount of ammonia or urea injected (see following paragraphs for further discussion). Other Gaseous Air Emissions The other air emissions of concern are CO, unburned hydrocarbons (UBCs), and volatile organic compounds (VOCs). They result from incomplete combustion caused by process conditions maintained to control SO2 and NOx, and decrease as combustion temperature increases. Although their minimization is limited by the temperature requirements of the FBC process, they generally fall within acceptable limits. Good control of feed, recycled solids, and air distribution and mixing is essential to prevent air-deficient/fuel-rich zones or air-rich zones in the combustor, both of which will have a negative impact on one or more emissions. The required number and location of fuel feed points to avoid these problems depends partly on the reactivity or volatile content of the fuel. The downstream flue gas cooling process can have a secondary effect on the chemical and physical form of some of the flue gas constituents, but this effect generally is negligible, except in the detached plume scenario noted below. The range of CO emissions can be 12-300 mg/Nm3 and UBC emissions can be similar, depending on fuel, temperature, air staging, and excess air. While an FBC boiler can be designed to minimize CO for a given percent SO2 reduction, NO, would probably increase---but could be reduced by the postcombustion application of selective non-catalytic reduction (SNCR). SNCR, if required for postcombustion NOx reduction, is a source of NH3 emissions (ammonia slip), typically 5-20 mg/Nm3. Both ammonia and urea can be used as the NO, reducing agents in SNCR. Because both NOx reduction and ammonia slip increase with increasing injection ratios of the ammonia or urea, the allowable slip determines the amount of NOx that can be reduced by the SNCR process in a given application. Power Generation and Environmental Control Technologies 115 Another pollutant of potential concern is N20, a greenhouse gas that is not currently regulated. The N20 from the FBC process itself is estimated to be - 200-400 mg/Nm3 at combustor temperatures of 850°C, decreasing with increasing temperature to - 20-140 mg/Nm3 at 900°C. A further source of N20 would be the SNCR system, if that NO, control technology is used. A portion of the urea or ammonia reagent is converted to N20, with urea producing significantly more N20 than ammonia. If both NH3 slip and HCI are present in the flue gas exiting the stack, ammonium chloride can be formed and would condense as fine NH4Cl crystals to produce a visible detached plume. Particulate Emissions AFBC particulate emissions consist primarily of spent sorbent (i.e., CaO, CaSO4, and limestone inert solids), fuel ash, and unburned carbon. The level of emissions depends on the type and design of the particulate collection device. With sulfur-bearing fuels, where sorbent is added for SO2 control, electrostatic precipitators (ESPs) are usually not suitable for achieving the low limits of particulate emissions (under 37 mg/Nm3) required in North America, Europe, and Japan. The performance difficulty arises from the higher electrical resistivity of the spent sorbent component of the fly ash and the large amounts of fly ash. However, on FBC units burning low-sulfur coals, wood waste, biomass, and refuse-derived fuel that do not require the addition of sorbent for SO2 reduction or bed inventory control, ESPs have been employed in both the U.S. and Europe. Two of the newest large utility AFBC plants are equipped with ESPs: EPDC's 350-MW bubbling FBC at Takehara, Japan, and EdF's 250-MW CFB at Gardanne, France. There was some concern that fabric filters could not cope with the mixed combustion of coal and residual oil planned for the Gardanne plant. The conditions that favor ESPs may exist at many potential AFBC sites in China. Particulate emissions from baghouses typically fall in the 5-25 mg/Nm3 range-well below the most stringent current standards in the U.S. and Europe and within the range of the strictest requirements in Japan. A great deal of experience and learning in fabric filter and baghouse design and performance has been accumulated in FBC applications for the full range of possible fuels, sorbents, and fly ash characteristics. This experience base enables confidence in fabric filter selection and baghouse design for good performance and maintainability. 3.5.5 Heat Rate The heat rates of AFBC and pulverized-coal (PC) plants are very similar at the same plant size under the same steam conditions. The heat rates for a subcritical (16.8 MPa/538°C/538°C) 300-MW PC plant without FGD and for a subcritical 300-MW AFBC plant with limestone addition are both estimated at 9400 kJ/kWh. There are slight effects on AFBC boiler efficiency depending on the specific coals and sorbent usage. The calcination reaction, CaCO3 4 CaO + CO2, is endothermic, whereas the sulfation reaction, CaO + S02 + 1/2 02 4 CaSO4, is exothermic. At a Ca/S molar ratio of 2.3, the heats of the two reactions balance each other. Carbon conversion may also be slightly 116 Technology Assessment of Clean Coal Technologies for China lower with AFBC; however, if compared with a low-NO. PC design, the difference may not be very significant. Generally only subcritical steam conditions are considered appropriate for plant sizes up to 300 MW. Manufacturers do not typically supply supercritical steam turbines in these smaller size ranges. However, if in the future the plans by Foster Wheeler and EDF materialize for CFB units in the 400-600 MW size range, then supercritical steam cycles can be utilized with the attendant advantages of reduced heat rates. AFBC plants of 100 MW or less have often been designed for more modest steam conditions. For example the 100-MW CFB plant at Gaoba is a non-reheat unit with steam conditions of 9.8 MPa/540°C. Harbin Boiler Works now offers a 100-MW CFB design with reheat at 13.7 MPa/540°C/5400C. Smaller plants with lower steam conditions would, of course, have higher heat rates than a 300-MW PC plant with steam conditions of 16.8 MPa/540°C/5400C. 3.5.6 Impacts Relative to Reference PC Plant Burning all kinds of fuels, AFBC plants have demonstrated high availabilities, heat rates comparable to PC boilers with FGD, 90-95% in-situ SO2 capture, low NO, emissions, fuel flexibility, and the ability to burn high-ash slagging/fouling fuels that would be problematic in pulverized-coal boilers. With regard to air emissions, AFBC is environmentally competitive with PC boilers equipped with low-NO, burners, SCR, and FGD; depending on coal quality and combustor design, the AFBC system may need SNCR to reach the lowest NO, control levels achievable by a PC plant with SCR. However, an AFBC system's spent sorbent tonnage typically exceeds that of a PC plant with FGD, and disposal costs are sometimes greater due to the large volume and its higher reactivity. Depending on a number of project- specific factors, AFBC may also be economically competitive with PC boilers. The competitiveness of AFBC increases with decreasing fuel quality and sulfur content. Since the late 1980s, numerous independent power producers, or IPPs (with contractual availability incentives), industrial cogenerators/self-generators (with strong incentives for high availability to keep their production facilities operating), and utility owned and operated plants have consistently achieved FBC availabilities and annual capacity factors in the 80- 95% range. The 100-MW CFB plant at Gaoba has experienced a three-year average availability of 70% since its startup in May 1996, steadily improving to 76% in 1997 and 79% in 1998. The reports on production costs for the 96-MW ACE plant in Trona, California (supplied by Ahlstrom Pyropower) may be the best available CFB operation and maintenance costs published. This plant used a low-sulfur Utah bituminous coal. The average plant availability for January 1991 through December 1993 was 86.6%, and the corresponding adjusted capacity factor was 83.4%. The forced outage rate showed steady improvement over this period as plant reliability increased and operating experience accumulated. In principle, from a steam and power generation standpoint, FBC boilers are interchangeable with conventional boilers and can be utilized for the full range of utility applications and solid fuel situations, including cycling operation. An EPRI comparative analysis of the cycling capabilities of AFBC boilers with PC boilers concluded that AFBC units with modem reheat subcritical steam conditions up to 300 MW will meet the same cycling standards that utilities Power Generation and Environmental Control Technologies 117 expect of their PC boilers. Turndown to about 35% of full load is generally achievable with CFB, (bubbling FBC has somewhat less flexibility), and many IPP-owned FBC plants operate under dispatchable power purchase contracts and varying degrees of cycling service. The operating and maintenance staffing levels are very similar for comparable-size AFBC and PC plants. 3.5.7 Constructionllnstallation Time Similar-sized AFBC and PC plants (e.g., 300 MW) require about the same construction/installation time, i.e., about three years. 3.5.8 Costs Using the costing methodology presented in Section 2 (with the plant built and installed in China), EPRI estimates that a 300-MW AFBC unit with limestone will cost $721/kW. Thus, it is higher than the $665/kW estimate for a 300-MW PC plant without FGD. However these estimates are for a low-sulfur coal. If a higher-sulfur coal were selected, the PC plant would need an FGD system in order to comply with emission standards, and its capital cost would be similar to AFBC. The operating and maintenance costs for an AFBC plant with limestone usage are 17.9 $/kW- year for fixed operating costs and 0.5 mills/kWh for variable costs. These are very similar to those for a PC plant without FGD. If a higher-sulfur coal were used and FGD were required for the PC plant, the fixed and variable operating costs would increase for both the AFBC and PC + FGD plants. As noted in Sections 3.5.4 and 3.5.9, the comparative economics of the two technologies will be markedly affected by the choice of coals, the sorbent cost, and solid waste disposal costs. The cost estimates presented here are based on a limestone cost of 175 yuan/tonne and a solid waste disposal cost of 20 yuan/tonne. 3.5.9 Other Environmental Impacts Fluidized-bed combustion systems produce more solid waste than other solid-fueled power generation processes and SO2 control technologies. On the same dry basis, a conventional FGD system requires half as much limestone and generates 30% less solid waste. For example, assuming a 3.3 wt% sulfur feed fuel with a Ca/S molar ratio of 1.8 (based on inlet sulfur levels) to achieve 90% sulfur capture, the FBC generates about 20 tonnes of dry sorbent solid waste for every 100 tonnes of ash-free fuel. Increasing the sulfur capture to 95% could increase the required Ca/S ratio to 3.6 and the dry solid waste to over 24 tons per 100 tons of feed fuel. Moreover, the main by-product from the calcination of the excess limestone required for sulfur capture is the lime (CaO), which is highly reactive. Therefore, the AFBC solid waste can be more difficult to market than that produced by PC plants with FGD or by integrated gasification combined-cycle (IGCC) systems. However, disposal of FBC solid waste in an economically efficient and environmentally sound manner has been achieved by many FBC users. 118 Technology Assessment of Clean Coal Technologies for China There are three main sources of solid waste from FBC: * Ash and residual carbon from the FBC fuel * Sulfur capture sorbent, the associated inert material, and the products of sorbent reactions in the FBC process * Other bed material if required, e.g., sand Carbon conversion in FBC is usually quite good, in the range of 98-99%. Nevertheless, FBC carbon conversion is usually slightly lower than that of a PC boiler for the same fuel due to the much lower operating temperature of FBC systems. There is a significant variation in the FBC solid waste composition between the coarse bottom ash and the fine fly ash. The carbon and lime content of the coarse bottom ash is usually lower than that of the fine fly ash, due to the longer residence time of coarse particles in the FBC system. The split in solid waste between bottom ash and fly ash is a function of many variables, with the major ones being the: * Total solid waste generation (if little solid waste is produced, it is mostly fly ash) * FBC furnace gas velocity (CFB produces more fly ash than BFB) * Fuel/sorbent friability linproved cyclone efficiency and/or recycle of the material collected by the ESP or baghouse can affect this bottom ash/fly ash split and reduce the carbon and sorbent losses in the fly ash. Nevertheless, the fine solid waste will still be higher in carbon and lime than will the bottom ash, although for the most part the fly ash meets acceptable standards for sale as a cement additive. But it may be beneficial to segregate the two solid waste streams, especially if effective solid utilization applications can be developed. 3.6 Pressurized Fluidized Bed-Combustion (PFBC) 3.6.1 Technology Description Pressurized FBC permits a combined cycle, in which the pressurized hot flue gas, after particulate removal, is expanded through a gas turbine to drive the combustion air compressor and generate additional electric power. Typically, pressures in the range of 1.2-1.6 MPa are employed, which correspond to the pressure ratios of conventional heavy-duty combustion turbines. Both bubbling and circulating PFBC are being developed, but currently all commercial units are of the bubbling-bed design. The main advantages of pressurized FBC are that: * An additional 20% or more net electric power output can be generated with a 6% or better improvement in plant heat rate * A more compact boiler may result * Carbon burnout and sorbent utilization are improved In contrast to AFBC, PFBC calcines only the MgCO3 component of the sorbent. At the elevated pressures of PFBC, the CaCO3-CaO-CO2 equilibrium, high partial pressure of C02, Power Generation and Environmental Control Technologies 119 and relatively high rate of recombination of CaO and CO2 into CaCO3 have the effect of stabilizing the unutilized CaCO3. The unutilized CaCO3 ends up in the solid waste essentially in its original chemical form. Generally, PFBC is able to accomplish sulfur removal at somewhat lower Ca/S ratios than AFBC. In the second-generation technology variant under development, called "advanced PFBC," a pyrolyzer is added ahead of the PFBC combustor. The fuel gas generated in the pyrolyzer is burned with the flue gas from the main combustor in a topping cycle to raise the turbine inlet gas temperature and increase the power output and efficiency of the turbine. The char from the pyrolyzer is burned in the main combustor. Sorbent is added to both the pyrolyzer and the main combustor. The successful development of hot gas cleanup (HGCU) technology using ceramic particle filters and alkali vapor removal is crucial to protecting the gas turbine against erosion and corrosion, especially as the turbine's firing temperature is raised. Hence, the successful development of HGCU is crucial to the successful demonstration of advanced PFBC. In principle, any atmospheric pressure FBC technology can be designed for pressurized operation; consequently, there are bubbling PFBC and circulating PFBC classifications. However, only a few vendors have actually developed pressurized versions of their basic AFBC technologies. The PFBC classifications are briefly described below: Bubbling PFBC (PBFB) As shown schematically in Figure 3.12, the PBFB boiler itself looks like an atmospheric pressure BFB. However, although in-bed boiler tubes are retained in the pressurized version, the convection pass is eliminated to conserve energy for the expansion of the hot flue gas through the gas turbine. An economizer or heat recovery steam generator (HRSG) is used after the gas turbine for final heat recovery. The gas turbine drives an electric generator as well as the combustion air compressor. Final particulate removal is accomplished in a baghouse or ESP. ABB Carbon, Mitsubishi Heavy Industries (MHI), and Hitachi Ltd. have developed PBFB technologies. ABB Carbon employs two stages of cyclones for particle removal before the hot gas is admitted to a gas turbine that has been "ruggedized" to withstand the erosive effects of the entrained small solid particles in the hot gas. While the term "ruggedized" has not yet been clearly defined, it implies that the turbine has been modified to handle particulate loadings up to 500 ppmw from the cyclone. ABB has been developing improved gas turbine blade materials and mechanical designs based on experience with its five commercial-scale PFBC demonstration units. Originally the MHI and Hitachi PBFB designs employed single- stage cyclones followed by ceramic hot gas filters, which remove fine particles much more effectively than the second-stage cyclone. Consequently, these MHI and Hitachi systems may be able to adapt conventional gas turbines for their systems without "ruggedization." However, the 250-MW PBFB plant supplied to Chugoku Electric by Hitachi uses cyclones (no hot gas filter) and a "ruggedized" GE-type gas turbine. In contrast with the ABB and MHI designs, Hitachi employs a twin-bed design to separate the reheat function and reheat duty, which eliminates the need for spray attemperation of the reheat temperature, and thereby gains some improvement in overall plant efficiency. 120 Technology Assessment of Clean Coal Technologies for China Figure 3.12: Schematic of First-Generation Pressurized Bubbling FBC Cydone PFBC Coal & Water , Srbent Steam .- - Partculate To Stack Air | RG ttColledor t t _V V Steam Water Circulating PFBC (PCFB) Like its bubbling-bed counterpart, the PCFB boiler itself is more compact than the atmospheric CFB, and is also enclosed in a pressurized containment vessel. The PCFB containment vessel is just slightly taller, but has a considerably smaller diameter than the PBFB containment vessel. The hot cyclone is inside the pressure vessel. The hot flue gas then flows through a ceramic HGCU system before expanding through the gas turbine. The HGCU system can be contained within the PCFB or placed in a separate containment vessel. The PCFB plant configuration is essentially the same as that of the PBFB except that there is no need for the final baghouse or ESP. Lurgi Lentjes Babcock (LLB, the Lurgi-Deutsche Babcock partnership) and Foster Wheeler (now incorporating Ahlstrom Pyropower) have been developing PCFB technologies which include external heat exchangers (EHEs) to cool the recirculating solids and ceramic HGCU systems. To date, development has not progressed beyond the pilot plant stage. Advanced Pressurized Systems (AdvPFBC) As noted previously, advanced PFBC (or advanced second-topping-cycle generation PFBC as it is sometimes called), combines PFBC with partial gasification (therefore also sometimes Power Generation and Environmental Control Technologies 121 called hybrid gasification/PFBC) to achieve a higher efficiency. Char from the partial gasifier ("carbonizer") is burned in a PCFB. The design includes ceramic hot-gas filter systems on both the gasifier fuel gas and the PCFB flue gas right after the cyclones to provide the particle-free and alkali-free gas required by combustion turbines. The cleaned gasifier fuel gas output is fired with the cleaned PCFB flue gas in a topping combustor to raise the gas turbine firing temperature above the nominal 815-870°C of the first-generation PFBC. There are several major development issues yet to be resolved in the demonstration of this technology. In principle, any PFBC and any gasification technology can be utilized in this hybrid concept. 3.6.2 Commercial Readiness Current Experience Six commercial-scale bubbling PFBC units (five plants, one with two units) have been put into service around the world; Table 3.22 summarizes their design and operating data. However, most of these boilers have been treated as demonstration units, with financial support from government or international agencies, and all but one are less than 100 MWe. At this smaller size, with the accompanying dis-economies of scale, PFBC is likely to be limited to smaller niche markets, such as heat and power (e.g., district heating) applications. Scaleup of the technology to 350-400 MW must be demonstrated before PFBC can be more widely deployed. At this larger size, supercritical steam turbines can be used, and PFBC would then be in a much better position to compete with pulverized-coal plants in the larger power plant market. A 360-MW supercritical unit based on the ABB technology and a 250- MW subcritical unit based on the Hitachi technology have been constructed in Japan at Karita for Kyushu Electric Power Company (KyEPCO) and at Osaka for Chugoku Electric, respectively. Both are due to complete commissioning in mid-2000. The operating experience obtained from these units will have a strong influence on the future of commercial PFBC technology. Five of the six operating PFBC units listed in Table 3.22 are based on ABB's bubbling-bed P 200 PFBC module, designed for about 80 MWe. The sixth unit, an 85-MW module designed by Mitsubishi Heavy Industries (MHI), started up in early 1996. Deutsche Babcock and Foster Wheeler (forrnerly Ahlstrom) have conducted test programs on circulating PFBC pilot plants in Germany and Finland, respectively, but no larger units have yet been built. The ABB plants were all designed to operate with the ABB GT35P "ruggedized" gas turbine and to use two stages of cyclones for particulate removal. However, the Wakamatsu plant was designed to operate either with cyclones or with full gas cleanup using ceramic candle filters. The Tidd plant also tested a candle filter on the gas from one of the seven primary cyclones, and a candle filter test unit has also been installed on the gas stream from one of the nine primary cyclones at the Escatron plant. The primary aim of the hot gas filter development is to better protect the gas turbine against erosion and to eliminate the need for a downstream baghouse or ESP. As of May 1999, about 110,000 hours of operation had been accumulated on the ABB plants, mostly on the non-reheat units in Spain and Sweden operating at modest steam conditions (9 MPa5l10°C and 13 MPa/530°C, respectively). The Escatron unit in northern Spain had 122 Technology Assessment of Clean Coal Technologies for China accumulated about 30,500 hours of operation through August 1998 and is being run in a semi- commercial mode. It started its life primarily as a demonstration plant but has been upgraded to operate in a dispatch mode. The Vartan station near Stockholm, Sweden, is a combined heat and power plant that operates only during the heating season. Its two units had accumulated approximately 22,000 and 24,000 hours of operation, respectively, by the end of August 1998. They burn a low-sulfur Polish coal and are run in a fully commercial mode. The U.S. plant at Tidd was a demonstration unit that was shut down at the completion of the government co-funded demonstration program and has subsequently been dismantled. The ABB plant in Japan is a reheat unit with steam conditions of 10.2 MPa/593°C/593°C. The first phase of its demonstration program extended from startup in October 1993 through December 1997. In this period it accumulated 11,628 hours of operation, about 6000 of which were with the ceramic candle filter. A sixth plant of the ABB P 200 design, under construction at Cottbus, Germany, will be a heat and power plant similar to the Vartan units. An 85-MWe bubbling-bed PFBC unit designed by Mitsubishi Heavy Industries (MHI) was built for Hokkaido Electric at Tomatoh-Atsuma and started up in early 1996. This plant also includes full gas stream filtration. At the beginning there were major problems with the gas turbine and the filter, and little information was made available. However, in 1998 some more information was disclosed, which has been included in summary form in Table 3.22. Table 3.22: Commercial PFBC Plants and Operating Experience Technology ABB ABB ABB ABB MHI Facility Escatron, Vartan, Tidd, USA Wakamatsu, Tomatoh- Name Spain Sweden Japan Atsuma, Japan Coal Type Lignite Polish Ohio Australian Various Coal Sulfur, 7 0.65 4 0.4 0.9 Coal Ash, % 36 15 10 10 Not Available CoalFeed Dry Paste Paste Paste Dry Sorbent Feed Dry Paste Dry/Paste Paste Dry Sorbent Limestone Dolomite/ Dolomite Limestone Limestone Limestone Feed Points 16 6 6 6 Not Available NO,, Control None SNCR + None SCR SCR SCR Gross Output, 79 135 + 73 71 85 MWe 224 MWth Units 1 2 1 1 1 Cyclones 9x2 7x2 7x2 7x 1 2x 1 Hot Filter 1/9 Slip None 1/7 Slip Full Gas Flow Full Gas Flow Power Generation and Environmental Control Technologies 123 Stream Stream (part time) Steam 90 130 90 102 166 Pressure, bar Steam 510 530 496 593/593 566/538 Temperature, OC Excess Air, 15 25 25 20 Not Available Fluidization 0.9 0.9 0.9 0.9 Not Available Velocity, m/s Bed Height, 3.5 3.5 3.5 4.0 4.5 m Pressure, bar 12 12 12 12 10 Operating 30,500 22,200/24,37 11,413 11,628 6,292 through Hours thru 0 March 9,1998 Aug,31/98 Large Plants in Startup The aforementioned Karita PFBC plant, the first 360-MW-size PFBC plant ever built, replaces an old, conventional coal-fired power plant. It consists of one novel ABB P 800 module with a GT140P 75-MW gas turbine and a 290-MW steam turbine. The boiler is designed for supercritical steam conditions of 24.1 MPa/565°C/593°C. A wide range of coal qualities, from lignite to anthracite, will be used at this plant, and the fuel and sulfur sorbent mixture will be fed as paste. The order for the plant was placed with ABB Carbon's licensee, Ishikawajima-Harima Heavy Industries (IHI), which has undertaken the engineering, manufacturing, erection, and commissioning of the plant. The GT140P turbine was supplied by ABB STAL and the steam turbine by Toshiba. Commissioning of the plant is currently being conducted, with startup anticipated in mid-2000. One of the two 250-MW bubbling-bed PFBC units designed by Hitachi for Chugoku Electric is under construction at Osaka. This plant will use cyclones only (no ceramic filter) with a "ruggedized" GE turbine. Startup is anticipated for 2000. Operating Experience Historically, there have been a number of problems common to all the ABB plants which, for the most part, have been satisfactorily addressed. However, some uncertainty still exists in the following areas: * Coal and sorbent distribution in the bed. Fuel and sorbent distribution need to be optimized to achieve maximum sorbent utilization and uniform bed temperatures. * Cyclone liner life. Proper application of select materials and/or unlined austenitic stainless steel cyclones being tested at Vartan may resolve this issue. 124 Technology Assessment of Clean Coal Technologies for China * Cyclone ash removal. This is being addressed by instrumentation that indicates blockage and by the development of cleaning devices that can be operated externally while on-line. * Coal feed. This is an ongoing concern. Wet feed systems need proper size distribution and a better indicator of proper consistency; dry feed systems need designs that address erosion in transport pipes at high pressure and redundant systems for high availability. * Gas turbine lifetime. High-cycle fatigue damage and erosion are ongoing problems being addressed by the suppliers. * Gas filter performance. Development continues on thermal shock-resistant ceramic candle filters. 3.6.3 Applicability of PFBC Plants to China PFBC systems are well suited for China because of their ability to cleanly burn high-ash, low- volatile, and/or high-sulfur coals. They offer a competitive alternative to supercritical plants with FGD and, maybe, SCR, and would provide China with a coal-to-electricity source that is clean enough to permit economic expansion while also improving environmental conditions. Once developed and adequately demonstrated as a reliable technology, there should be no technical constraints to their application in China. In fact, with China's experience of 18 years investigating this technology, one can expect its engineers to continue gaining experience with the international community and contributing to the development of the technology. China began experimental studies of PFBC in 1981, and a 1-MWtb pilot-scale PFBC test facility was completed in 1984. Over 900 hours of performance tests have been conducted on this facility. Technologies for fuel feeding and furnace ash removal under pressure were successfully developed to ensure the nornal operation of the PFBC boiler. A bituminous coal with ash content up to 57% and a coal with medium sulfur content were fired. Test results showed that combustion efficiency reached 97-99%, and SO2 removal efficiency was 80- 89% at a Ca/S molar ratio of 1.3-1.8. Basic information and experience have been obtained on heat transfer and combustion, as well as hot-gas cleanup systems. After 10 years of research on the pilot-scale PFBC test facility, it was felt that applying PFBC to large coal-fired combined cycle power plants would be one way to generate electricity cleanly. Therefore, China started to build a semi-industrial-scale PFBC plant over the period of the eighth Five-Year Plan from 1990 to 1995. The site selected was the Jiawang Power Plant in Jiangsu Province. The total electrical output of the PFBC-CC plant is 15 MWe, of which 12 MWe are from the existing turbo-generation unit and the remaining 3 MWe are generated from a newly installed gas turbine unit. A PFBC boiler with a live steam output of 60 t/h was newly installed. The PFBC system consists mainly of coal pre-handling, sorbent for SO2 removal, the PFBC boiler, water and steam, furnace ash removal, high-temperature particulate removal, and the steam turbine and gas turbine systems. The equipment has been installed, and startup commissioning will be performed soon. The plant will provide basic technical information and first-hand experience of PFBC design and Power Generation and Environmental Control Technologies 125 operation, as well as a better understanding of the PFBC process, which will serve to further develop large-scale PFBC development in China. China plans to build a 100-MW-class PFBC demonstration plant at Taishan Thermal Power Plant in Dalian City. It will include two sets of PFBC boilers, each equipped with a 17-MW gas turbine and a 50-MW steam turbine cogeneration unit, for a total electrical output of 2 x 67 MW. At present, engineering feasibility studies and technical negotiations are being carried out with ABB Carbon. A similar demonstration plant is also planned for Jiawang. In summary, only the bubbling-bed PFBC technology is currently offered commercially, and most of the operating plants are sized at - 80 MW. The market for this size of plant is probably not large since it would be in direct competition with the more commercially established AFBC technology. However, it may be effective for certain niche applications such as combined heat and power and district heating. Penetration of PFBC into the much larger coal-fired power plant market will depend on the results of the two larger demonstrations starting up in Japan at this time; note that both of these plants require ruggedized turbines because they do not have hot gas filters. Assuming successful operations at the Chinese 100-MW demonstrations and the larger units in Japan, it is reasonable to expect that PFBC plants could start to be commercially deployed in China from 2010 onwards. If properly designed, PFBCs should be able to accept a wide range of coals, including coals with high ash content, although better performance would be obtained with lower ash content, higher heating value coals. 3.6.4 Emissions The emissions from PFBC units are similar to those from AFBC units. See Section 3.5.4 for a discussion of the principles involved in emissions control of the various species from FBC plants. SO2 removals of up to 98% are possible with higher-sulfur coals. A significant difference between PFBC and AFBC is that the excess limestone in PFBC is not calcined, which leads to an increase in the mass of solid waste from this source. However, this increase is offset, particularly with higher-sulfur coals, since PFBC is able to achieve comparable SO2 control at lower Ca/S ratios than AFBC. Typically PFBC may achieve 90% SO2 removal at a Ca/S ratio of 1.5 compared to a ratio of 2 for AFBC. In addition, the absence of free lime reduces several solid waste handling, disposal, and utilization problems. PFBC systems usually produce equal or lower NOx emissions than AFBC systems and are very amenable to SNCR applications. Further, the PFBC's higher oxygen partial pressure im proves carbon conversion and produces less carbon monoxide (CO) and unburned carbon (UBC) than an AFBC. At comparable steam cycle conditions, PFBC offers a heat rate improvement over AFBC of about 5%. All emissions would, therefore, be reduced by comparable amounts over those from AFBC. In addition, the CO2 emissions from PFBC are less than those of a comparable- sized AFBC since no CO2 is produced from calcination of the excess limestone. 126 Technology Assessment of Clean Coal Technologies for China 3.6.5 Heat Rate At the standard steam conditions of 16.7 MPa/538°C/538°C, the heat rate of a PFBC unit is about 5% less (better) than for comparably sized AFBC or PC units. Large units operating with a supercritical steam cycle would have even better heat rates. 3.6.6 Impacts Reliability, Availability, and Maintainability PFBC is a relatively new technology with most of the first plants being demonstration units. Therefore, a complete picture of the availability and reliability is not yet in hand. However, based on the operational history to date (Table 3.22), it appears that with time the startup problems were overcome and the units gained an increasing record of availability and reliability. For example, the Escatron plant has averaged 55-60% availability over the past three years, with runs as long as 1,000 hours. Vartan experienced slightly over 80% availability during one full heating season, suffered gas turbine blade problems the next year, and returned to reliable operation with an availability of 85% in the 1998-99 heating season. After facing problems in the early years, Wakamatsu operated at an availability of 90% in 1997, including a 788-hour run with the gas filter on the full gas stream. As one might expect, the problems have often centered on getting the materials in and out of the combustor rather than any issue with the basic process. For the most part, the design principles are understood, the design steam levels have been met, and control issues are also well understood. Metal wastage rates in the tube bundle and waterwalls have been no more severe than on conventional AFBC plants. Due to a resonant frequency problem with the gas turbine, long-term history on corrosion, erosion, and deposition in the turbine is not yet available. However, it is reported that ABB will guarantee 5,000 hours before refurbishment is needed. In actuality, the erosion history may be a function of the nature of the ash. Thus, if high quartz levels are present, more erosion-resistant materials may need to be chosen. Other than the vibration problem with the gas turbine, no unexpected issues have been encountered. However, there is a general concern about alkali levels. Recent measurements at Wakamatsu show that sodium is the major alkali-vapor species present in the flue gas in ranges comparable to those reported in the literature. It appears that around 0.01-0.02% of the total alkali content in the coal exists in the vapor state at 800°C. The long-term effect of these alkali levels is not yet known, but so far no corrosion issues have been identified traceable to alkali levels. Based on the history to date, estimates have been made for an equivalent availability of 85% for a mature plant constructed within the next five years. However, even with the encouraging experience to date, PFBC cannot yet be characterized as "mature" in the same sense as AFBC and PC plants. Adequate redundancy in the fuel and sorbent preparation needs to be built into the plant to be able to reach this availability level. As this fuel and sorbent feed technology utilizes existing components proven in the utility and petrochemical industries, the reliability of these components should be quite high. Power Generation and Enviromnental Control Technologies 127 The component that is stretching the envelope of conventional usage is the ruggedized gas turbine for handling several hundred ppm of particulates, especially with erosive ash. ABB and others continue to work on coatings, design, and material selection to improve abrasion resistance. A careful analysis should be made of the ash in any prospective feed coal to determine its potential for erosion. In general, if PFBC is to be considered, tests on the coal should also be conducted at the supplier's pilot plant. Maintenance of a pressurized plant will be more difficult than for a conventional plant. As many of the major components reside inside the pressure vessel, access to these is limited to periods when the plant is down. Fortunately, there are few moving parts within the pressure vessel that might require periodic maintenance. Methods have also been devised to clean out blocked discharge lines from outside the pressure vessel without requiring a plant shutdown. In addition, some components needed for a conventional plant-such as the forced-draft and induced-draft fans, and an FGD system-are not needed for the PFBC system. Multiple fuel feed systems are also being used and spare systems provided to accommodate servicing. However, the fuel feed systems do operate under pressure, which makes for greater complexity when servicing. Part-Load Performance ABB's approach to achieving part-load operation is straightforward-decrease the coal feed to the boiler. This reduces the amount of flue gas and, in turn, the power available from the turbine. Since the LP turbine and LP compressor are balanced, reducing the turbine output reduces the amount of fresh air to the system. To balance the air and coal while maintaining the bed temperature, the bed level is lowered by moving solids to the ash reinjection vessels also located within the combustor vessel. Using the split-shaft gas turbines allows ABB to achieve minimum loads as low as 30-35%. As expected for a PFBC plant, the heat rate increases as the plant operating load level decreases because the gas turbine reaches the minimum operating load limit before either the steam turbine or combustor. A typical curve of heat rate vs. load for a single boiler is shown in Figure 3.13. 128 Technology Assessment of Clean Coal Technologies for China Figure 3.13 Typical Effect of Load on Plant Heat Rate (at 150C) for a Single 0-MW Module 12,500 12,000 S11,500 - - 11,000 - \ a: 10,500- z 10,000 z 9,500 - - 9,000. I I I I I I I 20 30 40 50 60 70 80 90 100 Percent of Load Effect of Ambient Temperature High ambient temperatures can adversely impact both gas and steam turbines. However, of the two, the gas turbine is impacted the most. Figure 3.14 shows typical PFBC performance sensitivity to ambient temperature in terms of output and net heat rate. Although this curve was generated for a specific fuel and location, the performance of most PFBC plants is expected to follow similar trends. ABB has also suggested another option for its turbines, which are split-shaft machines with high- and low-pressure expanders-to reheat the partially expanded flue gas leaving the HP turbine before it enters the LP turbine. The increase in temperature offsets the loss of power from the high ambient temperatures. Power Generation and Environmental Control Technologies 129 Figure 3.14 Typical Effect of Ambient Temperature on PFBC Heat Rate and Plant Output for a Single 80-MW Module 9700 85 9600 9500 80 9400 9300 75 O - ~~~~~~~~~~~~0 I 9200 9100 'b 70 9000 8900 1 1 1 1 1 -65 0 10 20 30 Ambient Temperature, °C Transients For the PFBC plant, startup, shutdown, and turndown have not proven to be any longer or more difficult than for a conventional plant once the plant operators learn the new procedures associated with operating at pressure. Ramp rates are limited to about 4% per minute and minimum load is predicted to be about 25%. 3.6.7 Constructionllnstallation Time The construction/installation time for a PFBC unit is estimated to be about three years, which is the same as for a PC unit of comparable size. Depending on the site access and the size of the PFBC modules (90 MW or 360 MW), the large boiler vessels may either be delivered whole or in pieces. In Japan, where the PFBC plants have been located on sites with ocean access, the whole boilers vessels have been delivered to the site. However, in China it is anticipated that field fabrication of the boiler vessel would often be necessary. In the latter case, the integrity of the large circumferential and head welds would require special attention and quality control. 130 Technology Assessment of Clean Coal Technologies for China 3.6.8 Costs The capital cost for a mature 350-MW single-boiler PFBC plant based on the ABB bubbling- bed technology with standard subcritical steam conditions of 16.7 MPa/538°C/538°C has been estimated at $803/kW for domestic Chinese manufacture with importation of some key equipment such as the gas turbine. This capital cost is higher than that estimated for comparable AFBC ($72 1/kW) and PC ($665/kW) plants, due largely to a higher percentage of imported equipment components and materials. Since ABB's PFBC technology has yet to be fully demonstrated at the 350-MW scale, this cost estimate is necessarily more uncertain than those for most of the other coal technologies. The costs of the 360-MW Karita plant are thought to be in the range of $1,500-1,600/kW, but the study team does not know what is contained in this estimate, especially whether it includes certain first-of-a-kind engineering, development, and other project costs. The capital costs for smaller ABB units based on the 80-MW (P 200) modules would suffer from the dis-economies of the smaller scale. A single 80-MW plant would have a unit capital cost ($/kW) approximately 1.6 times that of a single 360-MW plant. If two 80-MW units were built together, it is estimated that the capital cost would be about 1.4 times that of a 360- MW unit in $/kW. If four 80-MW modules were built together, the unit capital cost could be just 1.2 times that for a single 360-MW plant. PFBC pressures of 1.4-1.6 MPa allow a considerable reduction in the footprint required by the major equipment as compared to AFBC and PC plants. This makes PFBC systems good candidates for repowering of existing plants where space may be limited. There is also the potential for modular construction-this is true in two completely different ways. First, operating at higher pressure reduces the size of the equipment to the point that a higher percentage can be fabricated in the shop, saving field labor costs and reducing the construction schedule. Second, because PFBC units come in finite sizes based on the gas turbine, an owner can elect to add capacity incrementally rather than building the entire facility at once. The Karita fluidized-bed pressure vessel has a diameter of approximately 15 meters and a height of 44.6 meters for 360 MW. In this design the cyclones and the ash recirculation vessels are situated above the fluidized-bed boiler. The entire combustor with all its internals (weighing 3600 tonnes) was manufactured and pressure-tested at IHI's Aioi manufacturing facilities before shipment on a barge to the Karita site. The corresponding vessel for an 80- MW (P 200) module at Wakematsu was 11 meters in diameter and 29.5 meters in height. The operating costs for PFBC will depend very much on the sulfur content of the selected coal. Many of the Chinese coals are < 1% sulfur and may not require the addition of limestone to conform with the SO2 emission regulations. The operating costs of PFBC units using coals > 1% sulfur will be markedly affected by the costs for limestone and the subsequent disposal of the solid waste. Power Generation and Environmental Control Technologies 131 3.6.9 Environmental Impacts The non-air pollutant environmental impacts of PFBC will be similar to those of AFBC, although the volumes will be somewhat less due to the better efficiency. See Section 3.5.9 for more detailed discussion of these other environmental impacts from AFBC plants. PFBC will have lower CO and UBC emissions than AFBC due-to better combustion conditions (higher oxygen partial pressure). Limestone usage for higher-sulfur (> 2%) coals is only about 60- 70% of that for AFBC, but is still higher than for PC + FGD plants (which use about half that of AFBC). For higher-sulfur coals (> 2%) the solid waste generation at a given degree of SO2 removal will be about 75% that of AFBC and the same as for PC plants with FGD. The absence of free lime in PFBC solid waste makes it easier to handle and dispose of than the by-product from AFBC plants. 3.7 Integrated Gasification Combined Cycles (IGCC) 3.7.1 Technology Description The integrated gasification combined cycle (IGCC) allows the use of coal in a power plant that has the environmental benefits of a gas-fueled plant and the thermal performance of a combined cycle. In its simplest form, coal is gasified with either oxygen or air, and the resulting raw gas (called syngas, an abbreviation for synthetic gas) is cooled, cleaned, and fired in a gas turbine. The hot exhaust from the gas turbine passes to a heat recovery steam generator (HRSG) where it produces steam that drives a steam turbine. Power is produced from both the gas and steam turbine. A block flow diagram of a highly integrated IGCC system is shown in Figure 3.17. By removing the emission-forming constituents from the gas under pressure prior to combustion in the power block, an IGCC can meet extremely stringent air emission standards. 132 Technology Assessment of Clean Coal Technologies for China Figure 3.15: Block Flow Diagram of a Highly Integrated IGCC Power Plant Coal Gasifi- Gas Sulfur Coal-- Prep r catio -0 Cooin -0 ewa Steamro HRSGas Feedwater (BFW) Conventional Integrated GCC ------------------- Addition for Highly Integrated GCC Turbine There are many variations on this basic IGCC scheme, especially in the degree of integration. The five commercial-sized, coal-based IGCC demonstration plants in operation each use a different gasification technology, gas cooling and gas cleanup arrangement, and integration scheme between the plant units. Integration, specifically, is a major design difference between the two European IGCC plants and the U.S. plants. The European plants at Buggenum (Netherlands) and Puertollano (Spain) are both highly integrated designs with all the air for the air separation unit (ASU) being taken as a bleed from the gas turbine compressor. In contrast, the U.S. plants at Tampa and Wabash are less integrated, and the ASUs have their own separate air compressors. The more highly integrated design does give higher plant efficiency; however, there is a loss of plant availability and operating flexibility. It is the general consensus among IGCC plant designers today that the preferred design is one in which the ASU derives part of its air supply from the gas turbine compressor and part from a separate dedicated compressor. Gasification Processes Three major types of gasification are used today-moving bed, fluidized bed, and entrained flow. These processes are illustrated in Figure 3.16. Pressurized gasification is preferred to avoid large auxiliary power losses for compression of the syngas. Most gasification processes currently in use or planned for IGCC applications are oxygen blown; however, the Pifion Pine Plant in the United States uses an air-blown fluid bed process (KRW). The Lurgi moving-bed dry ash gasifier is a pressurized oxygen-blown countercurrent gasifier in widespread use around the world in South Africa, the United States, Germany, the Czech Republic, and China. Steam is injected with the oxygen as a moderator to keep the coal ash well below its ash fusion temperature. The plants in Germany and the Czech Republic use some of the gas to fuel gas turbine combined cycle power plants. A slagging version of the Power Generation and Environmental Control Technologies 133 Lurgi gasifier has been developed, and a large commercial-sized unit based on this technology is now being commissioned in Germany. Figure 3.16: Three Major Types of Gasification Process Coal Gas¢- 99% of the sulfur from the syngas. The Wabash plant with the Destec technology firing high-sulfur Indiana coal has reported SO2 emissions as low as 13 g/GJ and always less than 40 g/GJ of coal used. Expressed on an equivalent basis for PC plants- namely at 6% excess oxygen-these emission levels are 37-115 mg/Nm3 of SO2. (Since the gas turbine exhaust is about 15% 02, the actual concentration of SO2 in its flue gas is approximately one-third the above-quoted numbers.) For NO, control, the Tampa plant uses nitrogen dilution of the syngas and the Wabash plant uses syngas saturation and steam injection. Both plants consistently achieve flue gas NO, emissions < 20 ppmv at 15% oxygen. This translates to < 43 g/GJ of coal used or < 123 mg/Nm3 of NO, when put on a 6% excess oxygen basis. The gas turbines in the IGCC plant at Buggenum and the pioneer Coolwater Plant (100-MW) in California have a lower firing temperature of - 11 00C and report NO, emissions of about 10 ppmv, or about half of those cited for Wabash and Tampa. Recently GE has claimed that < 10 ppmv can also now be achieved with the higher firing temperature (- 1260°C) GE FA gas turbines. Power Generation and Environmental Control Technologies 141 Carbon monoxide (CO) emissions are extremely low with measured levels typically about 1- 3 g/GJ or - 3-10 mg/Nm3 when stated on the same basis as PC plants (6% 02). Particulate emissions are also extremely low, generally < 5 g/GJ or < 15 mg/Nm3 when stated at 6% 02. CO2 emissions will be proportionate to the coal usage. If a 400-MW IGCC plant has a heat rate of 7980 kJ/kWh and a 300-MW PC plant has a heat rate of 9400 kJ/kWh, the CO2 emissions for the IGCC plant will be about 15% lower than for the PC plant. Compared to a 800-MW supercritical plant with a heat rate of 8725 kJ/kWh, IGCC has - 8.5% lower CO2 emissions. If compared to a PC plant with FGD or an AFBC plant with limestone addition, the CO2 reduction would be even greater due to the CO2 released from the limestone and the auxiliary power generated to overcome the pressure drop in the FGD. 3.7.5 Heat Rate Using the current generation of gas turbines with firing temperatures of A1260°C, IGCC plants can achieve plant heat rates in the range of 7800-8400 kJ/kWh on an LHV basis. The actual heat rate will depend on the coal, the gasification process, the plant elevation, the ambient conditions, the gas turbine characteristics, and the plant configuration (degree of integration). For the Shenmu coal from Shaanxi province and using the Shell-type gasifier with a GE 9FA-type gas turbine, the heat rate is estimated to be 7981 kJ/kWh for a nominal 400-MW IGCC plant at the standard site conditions given in Section 2. The use of higher-moisture and higher ash-coals will increase (worsen) the achievable heat rate for all gasification processes, particularly with the coal/water-slurry-fed processes such as Texaco or Destec. Development of a commercial pressurized fluidized-bed gasification process would be preferred for such coals. The G- and H-class turbines with firing temperatures of -1500°C are now entering commercial service firing natural gas. With these gas turbines, the single-train IGCC plants will be larger and more efficient. IGCC plant heat rates in the range of 7100-7500 kJ/kWh should be achievable with these advanced gas turbines. 3.7.6 Impacts Operator Training The Coolwater plant in California and the other demonstration projects have shown that, with proper training, operators with a typical power plant background can run these plants very competently. A background in process operations, such as those used in petroleum refining and natural gas processing, would obviously be desirable. It is strongly recommended that a dynamic simulation model of the plant be developed and used during the design and construction period for control system optimization and for later use in a plant simulator for operator training. 142 Technology Assessment of Clean Coal Technologies for China A vailability/Reliability The three coal-based IGCC plants with the most operating experience had on-stream availability factors of about 60% in 1998. These availability numbers are not especially good, but these are still early days for IGCC and the numbers are already close to the average for many PC plants. Additional experience will be gained in the next few years on these coal- based plants and on the many IGCC plants coming into operation firing petroleum residuals. Although there will probably always be a lower availability for solid-fuel plants than for liquid-fuel plants, the experience gained in the integrated operation of these plants should be of considerable benefit to the improved design and future availability of all IGCC systems. Causes of forced outages in the gasification section of the current IGCC plants bear a striking similarity to the problems encountered in PC plants. The fouling and corrosion of heat exchange surfaces, the changed fuel characteristics of blended fuels, and slagging have been common problems. The Buggenum plant has experienced the best availability of any of the gasification sections. It has been quoted as 95% for the gasification island and 85% for the power block. The Wabash and Tampa plants have experienced a reverse pattern, with the power block having an availability around 95% while the gasification plant has been generally lower-about 75% at Wabash and 70% at Tampa. Safety The presence of toxic gases containing CO and H2S in the pipework of IGCC plants requires additional precautions over those for PC or AFBC. However, these safety procedures have been in effect in the natural gas and petroleum refining industries for over 50 years. The use of local and portable CO and H2S sensors is crucial to safe operations. Additional attention is also required during startup and in the transition from startup fuels to coal and coal-based syngas. The use of appropriate control and simulation training is very important in this regard. 3.7.7 Constructionllnstallation Time Most of the large components of an IGCC plant (such as the cryogenic cold box for the ASU, the gasification vessel, the gas coolers, the absorption towers, the gas turbine, and the HRSG sections) are usually shop-fabricated and transported to the site. The construction/installation time is estimated to be about the same three years as for a comparable-sized PC plant. Construction time for a natural gas combined cycle plant can be as short as 18 months. If natural gas is available and there is an urgent need for power, it may be worthwhile to construct the combined cycle first and add the ASU and gasification section later. In such a case, special consideration needs to be given to the design of the HRSG, since the gasifier section provides most of the heat to evaporate the water in an IGCC configuration, while this duty must be borne by the HRSG in a natural gas combined cycle plant. 3.7.8 Costs Although much of the gasification, heat exchange, and gas cleanup equipment can be manufactured in China, the major components of the ASU and gas turbine would currently Power Generation and Environmental Control Technologies 143 have to be imported. As the technology matures and Chinese manufacturing adopts practices used in the OECD countries, the IGCC capital costs in China should be reduced. The total plant cost for a single-train IGCC plant of 400 MW firing the Shenmu coal in the Shell gasification process integrated with a GE 9FA gas turbine combined cycle is currently estimated to be $1038/kW for an application in China. Based on the many past IGCC studies conducted by EPRI, it has been found that the total plant cost for a two-train IGCC plant with about double the electric output would be about 0.85 of the unit cost (i.e., stated as $/kW) of a single-train 400-MW system-i.e., about $882/kW for an 800-MW system. Additional cost estimates have been performed for IGCC plants based on the newer G and H gas turbines and suggest that the costs of plants with these turbines could be $100-$200/kW lower than the figures cited above. These estimates must necessarily be treated with some caution until the performance of these new turbines is determined. Fixed operating costs (mainly labor and materials) are currently estimated as being slightly higher than for PC or AFBC plants. The variable operating costs will depend on coal selection and by-product (mainly sulfur) pricing. It has sometimes been found that the by-product sales revenue can completely offset the variable operating cost of chemicals and catalysts. 3.7.9 Environmental Impacts Solid By-products The sulfur in the coal is generally converted to elemental sulfur via the Claus process. At Tampa, sulfuric acid is produced. Both sulfur and sulfuric acid are commodity chemical products and a source of revenue for IGCC plants, at least until the market becomes saturated. The coal ash from entrained-flow slagging gasifiers is produced as an inert slag (frit) and is also generally sold as a by-product. It resembles the slag obtained from "wet bottom" (slagging) PC boilers and can be used in the same applications, such as road fill and blasting frit. Even if the slag cannot be sold, the solid waste is just the ash from the coal and is markedly less than the discharge from AFBC units with limestone addition or PC plants equipped with FGD. Obviously, if the AFBC unit does not require the use of limestone and the PC plant does not have an FGD system, the relative amount of solid waste corresponds to the relative plant heat rates (assuming use of the same coal). Water Effluents IGCC plants have two principal sources of water effluents. The first is wastewater from the steam cycle, including blowdowns from the boiler feedwater purification system and the cooling tower. The amount depends on the quality of the raw water and the size of the steam cycle. 144 Technology Assessment of Clean Coal Technologies for China The second source is the process water blowdown from the scrubbing of the coal-derived gas to remove trace particulates and gases. The raw process water, which contains various components such as ammonia and H2S, is usually steam-stripped, and the stripped gases are sent to the Claus plant or incinerated. The cleaned water is usually recycled. The net amount of blowdown depends on the amount of water-soluble inorganics (particularly chlorides) in the coal. Dry-coal-fed gasification processes that use dry cleanup systems produce less process water effluent. Some plants use the process water effluent as cooling water makeup. The Tampa and Buggenum plants are both designed as zero-discharge facilities. In these plants the process water effluent is further treated for removal of trace components and evaporated to produce a salt cake for disposal. 3.8 Utilization of Fly Ash and By-products from SO2 Control Processes 3.8.1 Introduction China now reuses 50% of its coal ash in productive uses. The utilization potential is generally not limited by technological barriers or lack of understanding of the use options. Rather, coal ash is not used in greater volume due to the low cost of disposal, the wide availability of natural materials, and transportation costs from the point of production to the point of use. In contrast, flue gas desulfurization (FGD) by-products are not widely reused, as the very limited number of sulfur dioxide (SO2) control systems in China has prevented the establishment of use patterns for the by-products of these processes. Yet the general trend in S02 control continues to be the use of non-regenerable systems, which produce large volumes of by-products. The cost and environmental impact of disposing of these by-products provides inducement for utilization rather than disposal. Disposal costs are likely to increase in China, as they have in the OECD countries, largely due to stricter environmental regulations and, in some locations, limited space for suitable landfill. These changes are likely to make the economics of utilization more favorable. This section discusses the utilization potential and evaluation methods for clean coal technology (CCT) by-products. Given the maturity of fly ash utilization technology in China, the only fly ash topic discussed in this section is the relatively new approach of using high volumes of fly ash in structural concrete. The balance of the discussion presents potential uses of FGD by-products from wet flue gas desulfurization (wet FGD), spray dryers (SD), and furnace sorbent injection (FSI). Also discussed are the combined ash/FGD by-products from both atmospheric and pressurized fluidized-bed combustion (AFBC and PFBC). 3.8.2 High-Volume Fly Ash Concrete Since the use of fly ash as a partial replacement for portland cement in concrete was first introduced over 60 years ago, most practical uses have involved one of three approaches: * Use of relatively large volumes of ash as portland cement replacement in mass concrete where early strength is not required and ultimate strengths are in the range of 25 to 35 MPa Power Generation and Environmental Control Technologies 145 * Use of relatively small volumes of ash (10-25% replacement) in structural concrete * Compacted and flowable backfills or road bases containing large quantities of fly ash for applications where minimal strength development is demanded As the demands placed on structural concrete increase, especially in the area of durability, there has been a growing use of all types of supplementary cementing materials in what might be regarded as "tailored concretes." As part of these developments, structural concrete incorporating high volumes of low-calcium fly ash (designated Class F by the American Society for Testing and Materials, or ASTM) was developed by CANMET in Canada in 1987. In this type of concrete, less water and cement are used than in the traditional concrete mix, allowing the proportion of fly ash the total cementitious materials to reach 55-60%. More recently, various high-volume fly ash (HVFA) compositions based on both high-calcium ASTM Class C fly ashes and Class F materials were developed for use in pavement and structural applications. The utility industry has much to gain from the development of HVFA concretes to the point where they can be extensively used in structural applications at the commercial level. Clearly, technology that permits the use of three or more times the amount of fly ash in concrete than is currently employed can significantly extend the market for fly ash in construction. The most commercially attractive of these HVFA concrete materials are proportioned to contain more fly ash than portland cement. By careful selection of mix proportions and the use of superplasticizers, concretes with the following features have been produced: * Good Low portland cement content (-150 kg/m3), permitting them to be produced at lower cost and lower energy demand than conventional concretes * High workability * Reasonable strength and high elastic modulus. For example, concretes produced at CANMET under EPRI sponsorship have been shown to develop compressive strengths greater than 40 MPa by 28 days, with early-age strength in the range of 10- 15 MPa at 3 days. * Durability in chemically aggressive environments 3.8.3 Wet FGD By-products Wet FGD sludge is the liquid/solids bleed stream from the scrubber, which carries away the reaction products and contains water, dissolved solids, and suspended solids (predominantly calcium sulfite, calcium sulfate, and sometimes fly ash). These sludges are the waste products from lime, limestone, alkaline fly ash-enhanced, magnesium-enhanced lime, and dual-alkali wet scrubbers. The utilization potential of wet FGD sludge is related to its quality and characteristics. Because of this, the type and degree of processing largely determine the uses of sludge that merit consideration. Producing a useful by-product from FGD sludge often requires additional processing, such as forced oxidation (usually within the SO2 absorber reactor in the limestone forced oxidation systems) or fixation/stabilization. 146 Technology Assessment of Clean Coal Technologies for China Oxidizing FGD sludge allows it to compete for the current uses of naturally occurring gypsum. The following markets have been identified as potential primary applications for FGD by-product gypsum: (1) wallboard production, (2) cement production, and (3) agricultural use. Fixing or stabilizing FGD sludge can enhance its physical properties for potential structural uses. Demonstrated uses include (1) structural fill, (2) road construction, (3) soil stabilization, (4) liner cap material (5) artificial reefs, and (6) mine reclamation. Utilization of Oxidized FGD Sludge Calcium sulfate (gypsum) is a principal by-product generated in lime- or limestone-based FGD scrubbing systems. Often, both calcium sulfate and calcium sulfite are produced, although it is possible to employ forced oxidation either in the scrubber or as a separate step to convert the sulfite to sulfate. FGD sludges high in calcium sulfate can be used in lieu of natural gypsum for wallboard, plasters, cement additives, and other products. Wallboard Production. In the United States, the largest consumer of gypsum is the wallboard industry (-75%), followed by the portland cement industry (-15%), agricultural applications (-6%) and plaster manufacture (-4%). In Europe and Japan the different methods of construction, and consequent differences in the products manufactured, give a slightly different breakdown of gypsum uses. Plasters consume a much higher proportion of gypsum than does wallboard in Europe, while Japan has developed a reinforced wallboard design suitable for its thinner walls. On a worldwide basis, the proportion of uses are about 80% for walls (wallboard or plaster), 15% for cement, and 5% for agricultural uses. In substituting FGD gypsum for naturally occurring gypsum in wallboard production, the following product variables are of concern: free water, fly ash, soluble salt contents (particularly chlorides), and crystal size and shape. The free water content of natural gypsum is approximately 3%, while that of FGD gypsum is typically much greater, at times exceeding 10%, depending on the efficiency of the dewatering equipment used. This excessive moisture can be a problem in handling FGD gypsum in the calcining step of wallboard production, since free water must be driven off. In addition, a high moisture content may indicate poorly formed crystals. In wallboard manufacturing, the unit bperations can be sensitive to changes in the raw materials. Therefore, direct substitution of synthetic gypsum for natural gypsum is not always possible. The characteristics of the feed material and its subsequent impact on the materials handling and process chemistry must be fully understood to facilitate by-product substitution. On the other hand, one advantage of FGD gypsum is its typical high purity (CaSO4.H2O content) which, when added as a portion of the board line feed, may improve some board properties with only minor changes to the operating parameters. FGD gypsum has been used successfully in the manufacture of wallboard in the United States and Europe, and its use is continuing to grow. Fly ash is present in FGD gypsum in varying amounts, depending on the type of particulate removal system. A fly ash content of more than 2% will affect the color of wallboard. In Power Generation and Environmental Control Technologies 147 particular, iron, manganese, and unburned carbon in the fly ash are responsible for contributing color to the wallboard. Discoloration due to fly ash may render the wallboard unattractive to potential consumers. FGD gypsum may contain varying amounts of soluble salts depending on the coal type and process conditions. The presence of soluble salts in by-product gypsum reduces the required calcination temperature. If the concentration is excessive, the gypsum may begin to recalcine during the wallboard drying process, thus disrupting the paper-gypsum bond. Excessive salt concentrations can also corrode nails used to install the wallboard and can cause efflorescence, the deposition of a white powdery residue on the wallboard surface during humid weather. Making quality wallboard requires large gypsum crystals and a blocky crystal shape. Smaller crystals make it necessary to use more water when the calcined gypsum is rewetted in the production process. This may result in increased drying costs and decreased board strength. Other Board Processes. Attempts are continuously made to improve or modify gypsum board. In these new board products, the properties provided by the paper liner are replaced by other materials. These materials are either less costly or provide improvements in the board quality and possibly enhance the variety of applications for the gypsum board product. Successful modifications to the structure of the board from a commercial point of view consist of either distributing paper fiber throughout the gypsum matrix rather than applying paper to the surface, or replacing the paper surface liner with a fiberglass sheet or mat. These alternative gypsum board process include: (1) fiber-reinforced board, where fibers provide improved tensile, flexural, and impact strength to board products; (2) filler-reinforced board, where modifications of gypsum wallboard with inorganic fillers might be particularly compatible with the utilization of a combined gypsum and fly ash FGD scrubber waste; and(3) polymer-modified board, which was developed to improve moisture resistance, freeze- thaw durability, strength, and abrasion resistance. Plasters. FGD gypsum has good potential for plaster manufacture because of its high purity. However, the plaster market is relatively small, accounting for only about 1 million tonnes annually in the OECD countries. In the United States, there are two main types of plasters, designated as alpha- and beta-plaster. Alpha-plaster is a higher-value material (up to $350 per tonne, f.o.b. plant) and is produced under different and more costly conditions than beta- plaster. Alpha-plaster is used for specialty applications including industrial molding, dental and medical plasters, and possibly mining mortars. Due to their higher cost, alpha-plasters are not as common as aridized beta-plasters in North American floor applications. Beta-plaster is a lower-value material (ranging from $16 to $100 per tonne, f.o.b. plant in the U.S.) produced via more conventional "dry" calcination methods. In addition to wallboard manufacture, beta-plaster is used in wallplasters and as a fireproof coating. Filler Material. Natural gypsum has not seen significant application as a filler material in the world, although several grades of calcium sulfate fillers are commercially available in North America. However, certain qualities of FGD gypsum (i.e., high purity, fineness, whiteness) may make it suitable for specific filler applications. Therefore, Section 3.8.3.3 includes a 148 Technology Assessment of Clean Coal Technologies for China discussion of mineral fillers, describing the properties of fillers required for different applications. The use of gypsum as a filler in some applications is also reviewed. Cement Production. The use of by-product gypsum as a set retarder for portland cement appears to be quite viable. In the manufacture and use of portland cement, gypsum is an important and essential component that serves two main functions. First, during grinding of the clinker, the finely ground clinker particles have a tendency to adhere to the grinding media and walls of the mill. Gypsum is used as a grinding aid and its action has been theorized to be based on the release of water from the gypsum during grinding. Reportedly, this allows for the conduction of electricity and a reduction in the buildup of static electricity on the cement particles. Gypsum, being a softer mineral, also contributes to the measured fineness of the final product. Second and more important, gypsum serves as a set regulator for portland cement to prevent flash set during the early stages of mixing and placement. Flash set of cement is the irreversible, early stiffening of the cement paste which occurs as a result of the rapid reaction of tricalcium aluminate (3CaO.AI203) with water. The level of gypsum added to the cement clinker (i.e., SO3 content) will directly influence the early setting behavior of the cement paste. Gypsum can also control the rate of early strength development and shrinkage during drying. When natural gypsum is used in the manufacture of portland cement, the rock is crushed to pass 5-cm screening and then fed through chutes to a vibrating pan/conveyor. Handling of the finer-sized FGD gypsums may be an issue, as cement plants are designed for using gypsum as a coarsely crushed rock which is added directly to the clinker for grinding. Cement plants offer the greatest utilization potential for FGD gypsum. A typical cement plant can use 80,000-100,000 tonnes of gypsum per year. Several cases are known where FGD gypsum has been used successfully in the manufacture of cement in the United States. There are fewer problems in producing gypsum for cement than for wallboard use. Impurities are not as critical; gypsum with a higher fly ash content can be used and chloride content of up to 1% can be tolerated. The major differences between natural and FGD gypsum are particle size/shape and moisture content as related to materials handling. In some cases, it may be necessary to dry and/or agglomerate the gypsum in order to provide a material that is more compatible with existing equipment. Another difference is the absence of insoluble anhydrite (anhydrous calcium sulfate) which can occur in natural deposits of gypsum. If the cement plant is accustomed to using a gypsum/anhydrite blend to control the setting of cement, some developmental work may be required prior to substituting FGD gypsum for natural gypsum. Agricultural Use of Gypsum The use of natural gypsum in agriculture has a long history, and ground gypsum is commonly referred to as landplaster. By-product gypsum also has considerable potential for use in agriculture as a soil amendment, soil conditioner, fertilizer, or soil stabilizer. In agricultural applications, the gypsum is either in the form of the dihydrate or the anhydrite and is used for Power Generation and Environmental Control Technologies 149 both chemical and physical conditioning of soils. Gypsum also provides a supplemental source of sulfur and calcium for specific crops, particularly peanuts, legumes, potatoes, and cotton. Additionally, gypsum can serve as a composting aid for use with stored manures prior to their application in the soil. Finally, gypsum is also used to some degree as an extender for animal feeds and as a carrier for nutrients, insecticides, and herbicides. The use of FGD gypsum in agriculture is relatively straightforward. The specifications for this application relate mainly to toxic impurities, particularly limits on the heavy metals content. Market penetration depends mainly on transportation costs and the cost and availability of natural gypsum sources at the user locations. As a soil conditioner, gypsum improves soil structure by loosening heavy, compacted soils and clays to increase permeability and thus improve aeration, drainage, and the penetration and retention of water in the soil. This can result in better growth and higher yields through improved germination and increased root growth. Also, surface-applied fertilizers can penetrate into the roots more readily. Another widely used application is as a soil conditioner in the amendment of high-salt (sodium) and/or sodic (alkaline) soils. High salt content in soils can interfere with the water uptake of plants, and can also adversely affect soil permeability and thus penetration of water into the soil. The soils can become crusty, restricting seedling emergence and root extension. In this case, the calcium ions of the gypsum undergo anion exchange with the sodium ions, leaving the sodium ions free to be leached out. This lowers the pH and buffers soils against excessive alkalinity. In these applications, the gypsum is typically applied and intermixed as a finely ground powder (80-90% through 100 mesh) but in some cases, products are graded (i.e., multisized) such that solubilization occurs over an extended period to provide a "time- release" effect over the growing season. Many agricultural-grade products are commercially available. Recently a U.S. firm, Domtar, introduced a solution-grade agricultural gypsum for use with its gypsum solution system. The gypsum is specially milled to allow for dissolution in irrigation water and application through common irrigation equipment. The gypsum used for this product is of high purity so as to prevent plugging of application equipment. A further interesting application for gypsum in agriculture has been demonstrated by U.S. research showing that gypsum granules are a good substrate for carrying nutrients, insecticides, and herbicides. The use of granules has eliminated the difficulties associated with blending pesticides with the fine grades of gypsum. When the gypsum granules are impregnated with pesticides and nutrients, the result is a combined soil conditioner, fertilizer, and pesticide with more efficient bulk handling and distribution characteristics. Miscellaneous Uses of FGD Gypsum Mining Mortars. Cut and fill mining practice-in which depleted mines are backfilled with tailings and mortar-is an important method for mining silver, lead, zinc, copper, tungsten, gold, and to a lesser extent, mercury, asbestos, and talc. This method is increasing in popularity due to three factors. First, it is environmentally acceptable, as all the tailings and 150 Technology Assessment of Clean Coal Technologies for China other wastes stay in the mine. Second, productivity is increased, as the yield from the vein is effectively 100%. Third, the method is safe, since only a portion of the mine is open at one time, thereby decreasing the chance of subsidence (i.e., gradual settling). As this practice becomes more popular, the need for cheap mortar materials will increase. In Europe, alpha-plaster or portland cement mixed with pozzolanic materials such as fly ash is commonly used for mortar applications. However, in North America, the use of alpha-plaster, fly ash, or slags as binders for mining mortars has not been fully developed. While guidelines for these materials do not yet exist in the United States, leachability seems to be the most important criterion when considering their use in this application. Self-Leveling Flooring Material. To ensure proper application of final flooring materials (ceramic tiles, linoleum, and carpet), the smoothness and consistent level of the entire subfloor must be assured. Commonly, floor underlayment such as plywood sheets, with one side smooth-finished, is used to provide an adequate surface. However, plywood is expensive and provides little fire resistance. To reduce cost, particle resin board is sometimes used as a replacement for plywood. This product also has little fire resistance, and inhalation of the volatile organics used to fabricate the board may be harnful. Alternatively, slurries of calcium sulfate mortars using anhydrite or alpha-plaster can be applied over the subfloor to provide a level, smooth, hard, dimensionally stable, seam-free surface, in addition to providing substantial fire resistance. Fillers. Although calcium sulfate-based filler products are currently available in OECD countries, use of these fillers has not been fully exploited. As an example of the potential market, the mineral extender and filler consumption in North America alone is estimated to exceed 12 million tonnes, with a value of $4 billion. Extender and filler minerals fall into two classes, chemical or physical. Chemical fillers are used when their chemical nature and reactivity are important. Examples of these are lime, salt, soda ash, and phosphates. Physical extenders and fillers, such as talc and calcium carbonate (CaCO3), have found widespread application for two reasons. First, as extenders, they reduce the amount of the typically more costly host matrix material, thus improving the cost-effectiveness of the product. Second, as functional fillers, they can be used to enhance existing properties of the host matrix or to introduce new properties. Specific mineral properties can be used to improve casting characteristics and strength, reduce thermal expansion, and better control density, thermal conductivity, and electrical properties. Calcium sulfates are chiefly used as physical fillers and have found their largest markets in the structural fillers and extender/filler pigment categories. These two categories for gypsum filler applications can be further segregated into the principal industries that consume the largest quantities of these minerals: Paper Paints and coatings Putties, caulks, sealants, and gypsum-based joint compounds Adhesives Power Generation and Enviromnental Control Technologies 151 Rubbers and plastics Carpet backing Traditionally, these industries have primarily used six minerals, namely, calcium carbonate, kaolin, barite, mica, silica, and talc. Gypsum-based extenders and fillers will be in direct competition with these minerals in terms of properties and price. Although large-scale use of gypsum in any extender or filler application has not been realized to date, recent developments seem promising. Gypsum is a soft mineral with a relatively high whiteness. Its crystal shape and size are variable, and it is relatively resistant to acid and alkali materials, as compared to calcium carbonate. A high whiteness and refractive index are beneficial when color is an important criterion. Good resistance to acids and alkali is required for many applications. Matching the physical properties of gypsum with those of other minerals is not the only consideration for the substitution of gypsum in a particular application. For example, a guaranteed supply with consistent quality is also imperative to gain user acceptability of gypsum as a mineral extender or filler, and synthetic gypsum provides this consistent quality. Although the market in OECD countries is beginning to recognize this value of synthetic gypsum, the cost and performance differences between synthetic and natural gypsum are not large enough to induce the users to change their buying habits quickly. Plastics. After the 1973-74 fuel shortage in OECD countries sparked the need for more economic utilization of expensive oil-based resins, the use of minerals in plastics increased dramatically. At that time, minerals were only used in the non-functional sense. However, extensive research has since been conducted realizing that minerals can impart useful properties to the final product. For example, minerals can serve as low-cost inert fillers, extenders, and reinforcement in plastics. The minerals commonly used in plastics, rubbers, and molding compounds are calcium carbonate, talc, silica, kaolin, wollastonite, aluminum trihydrate, and more recently gypsum. Fibrous calcium sulfate (both hemihydrate and insoluble anhydrite) has demonstrated suitability for use in urethanes and polyurea reaction injection molding, offering both improved surface appearance and dimensional stability. Each form of calcium sulfate offers specific properties suitable to different end uses. The dihydrates serve as a flame-retarding filler in unsaturated room temperature cure polyesters, while insoluble anhydrite has demonstrated good compatibility in thermoplastic systems. It can improve impact resistance and stiffness, allowing redesign of parts to lower their costs. In rigid PVCs, higher loading levels of insoluble anhydrite improve impact resistance and tensile strength, and increase throughput rates-without necessarily sacrificing other physical properties. Insoluble anhydrite can also be used to replace barites in PVC plastisols, offering cost savings for many food contact applications. Insoluble anhydrite has been used in thermosets for microwaveware because of its flow characteristics and resistance to food acids. Both its electrical properties and resistance to breakage from impacts rival those of materials used as industry standards. 152 Technology Assessment of Clean Coal Technologies for China Utilization of Fixed/Stabilized FGD Sludge FGD sludge can be stabilized by adding dry fly ash, soil, or another dry additive to reduce the moisture content and improve handling characteristics without a chemical interaction between the sludge components and the additive. Fixation or chemical treatment is a type of stabilization that involves the addition of lime or other reactive material such as blast furnace slag, alkaline fly ash, or portland cement, which cause cementitious-type reactions with the sludge. These reactions bind the sludge particles together, thus increasing shear strength and reducing permeability. The structural stability and environmental characteristics of the waste product are thereby improved. Treated FGD sludge produced as a dry product has valuable structural properties. Similar to soil but somewhat cementitious, fixed/stabilized sludge makes excellent fill. In general, it could be used for road fill, dikes, berms, general fill, and similar local construction uses. In addition, fixed/stabilized sludge has been demonstrated to be of beneficial use as a base for paving material (roads and parking lots), wearing surfaces in some cases, embankments, wastewater pond or landfill liner, blocks for artificial ocean reefs, and fill for mine reclamation. Proper planning and design of the disposal area for fixed/stabilized sludge may allow for eventual residential, recreational, or light industrial development on top of the fill. The potential for utilizing such a fill for structural purposes is largely dependent upon structural integrity. Compressive strength should be at least 10 tonnes/m2, and permeability should be less than 5 x 10-5 cm/s. In addition to uses for light structural developments, fixed/stabilized sludge could be used in a variety of construction projects requiring stable fill material, such as roadways. In utilizing fixed/stabilized sludge as borrow material in construction, similar requirements for structural integrity would apply. As is the case for some of the dry CCT by-products, land recovery, especially mine or quarry backfill, may be a promising use for fixed/stabilized FGD sludge in selected areas. As an added benefit in this application, depending on the type of coal burned and scrubber efficiency, the sludge may contain free lime, which can mitigate acid formation in depleted mines. Other Potential Uses. Through research activities and small-scale applications, a number of other potential uses of sludge have been explored. These include: * Artificial reefs * Production of lightweight aggregate * Brick and concrete block * Mineralizer in metals extraction * Cement replacement at levels as high as 60% (compared to the current practice of 20%) Producing brick from a mixture of FGD sludge, silica sand, and lime may be viable. Experiments have indicated that autoclaving such a mixture can result in a product of satisfactory quality. FGD sludge also can be used as a cementing agent or a partial cement Power Generation and Environmental Control Technologies 153 replacement in producing concrete blocks that are lighter than conventional blocks. Such blocks would be used as low-cost, non-load-bearing construction materials (e.g., interior walls, decorative walls, patios, thermal insulating walls, and acoustic insulating walls). 3.8.4 Dry By-products from Clean Coal Technologies The by-products generated from dry CCT processes (dry SO2 controls and fluidized-bed combustion systems) have some chemical, physical, and engineering properties similar to conventional fly ash. The exact composition of a by-product is determined by the type of sorbent or reagent, the injection process, and the coal source. But in general, the primary components include fly ash, unspent sorbent (lime, limestone, or dolomite), and reaction products (calcium sulfate/sulfite).* The high percentage of fly ash in the by-products indicates the potential for pozzolanic activity. The unreacted lime or limestone contributes to the self-hardening characteristics of the by-products. In view of the physical and chemical characteristics of the dry CCT by-products, it is believed that there are potential uses for these materials in highway construction, mining, soil amendment, etc. The dry CCT by-products are dry powders and have physical properties similar to those of conventional fly ash. Their chemical properties are somewhat different from conventional fly ash, however, due to the alkaline reagents. These differences will require some changes in utilization practices relative to fly ash alone. The most promising utilization options are listed here and discussed briefly below: Road base stabilization Soil stabilization Sludge stabilization Structural fill Grout Asphalt mineral filler Aggregate Cement production and replacement Soil amendment Advantages of dry CCT by-products for utilization include: Dry particles Cementitious/pozzolanic reactivity Grain size distribution similar to conventional fly ash * Sodium-based compounds would, of course, be a significant constituent of the by-products from processes using these materials as a sorbent. However, the relatively high cost of sodium compunds and the potential environmental issues associated with the by-product (its high solubility leads to leaching of sodium salts, which need to be treated to avoid contamination of surface or ground waters) have restrained the market penetration of this technology. Therefore, this section does not discuss by-products from sodium injection processes. 154 Technology Assessment of Clean Coal Technologies for China Nonhazardous High pH, calcium, and sulfur (for soil amendment) Disadvantages of dry CCT by-products for utilization include: Exothermic hydration Potential for expansion High soluble sodium salt content of sodium sorbent injection by-products Potential for corrosion or sulfate attack on concrete Limited understanding of long-term performance characteristics High sulfur The dry CCT by-products contain significant portions of aluminous and siliceous compounds as well as alkali (calcium or sodium) ions. These chemical species (SiO2, A1203, Fe2O3, and CaO) give the dry CCT by-products self-hardening or cementing characteristics when they come in contact with water. The strength developed depends on the quantity of cementitious materials produced, with the calcium sulfate contributing to early strength gains through the formation of ettringite and thaumasite. In general, the pozzolanic reactions are similar to those of other lime-fly ash mixtures, with reactivity dependent on the fly ash percentage and alkali content. The high sulfate/sulfite composition may contribute to the strength, but may also cause expansion. Further, the high calcium sulfate concentrations cause these by- products to fail existing U.S. materials standards for conventional coal combustion fly ashes in certain reuse applications, and may cause the long-term strength loss observed with some by-products. Major, minor, and trace elements will partition so that elements from coal ash will be enriched in the entrained solids (the fly ash) and depleted in the spent bed material. Nevertheless, these solids would pass the U.S. leachate tests and not be classified as hazardous materials. Calcium from limestone will preferentially remain in the spent bed material. The properties of the AFBC by-products indicate that some changes will need to be made to conventional by-product management practices. Dry transport systems are preferable to liquid transport systems, and reactions with water will need to be considered when by-product management systems are designed. AFBC by-products tend to be more abrasive than conventional fly ashes, so special transport designs with few, smooth, abrasion-resistant elbows are needed. The AFBC by-products should develop adequate strength for placement in a landfill, but leachate generation controls may be required, depending on local conditions. Road Base Dry CCT by-products have potential as substitutes for lime or fly ash in road base construction. A possible advantage would be faster strength development and less sensitivity to cold weather during curing. However, the potential for expansion (dimensional instability) should be explored for each by-product source and mix. Also, a separate hydration step may be required prior to mixing and placement. A dry CCT by-product road base would be required to fulfill design and performance criteria similar to a cement-stabilized road base. While it would provide pavement support, it may not be appropriate where a free-draining Power Generation and Environmental Control Technologies 155 base course is required. When used as base course beneath a portland cement-based concrete pavement, the potential for sulfate attack on the concrete should be considered. Application of spray dryer by-product in the embankment layer offers the best opportunity for high-volume use in road construction. The by-product can provide a low-cost alternative to the use of common borrow when a borrow pit is not readily accessible. The strength gained from the spray dryer by-product will provide a more solid foundation for the upper road materials. In a 1991 demonstration, EPRI found that the average common borrow strength of the spray dryer by-product used on a section of roadway was 17.6 MPa, which is similar to the strength of natural borrow material. However, spray dryer by-product should not be mixed with the granular and select granular materials that are placed beneath the surface pavements, because it will reduce the permeability of that layer. Several EPRI demonstration projects have shown that mixtures of the by-product from a dry FGD process with either soil or the by-products from other CCTs produces an excellent material for road construction. A program completed in 1999 has shown that a mixture with the by-product from a PFBC plant can be used successfully in highway construction to stabilize the local soil. This by-product mixture demonstrated high strength and ease of installation, and no special equipment or training was necessary for its use. Performance during construction demonstrated that the level of care normally required on any construction project should be adequate when working with this material. In other projects, EPRI found that a mixture of the by-products from wet and dry FGD systems can yield a material this has excellent strength properties and workability. Lastly, in Ohio, dry FGD by-product and soil were mixed on site in approximately equal proportions and used to repair a state highway; the resulting strengths were close to those obtained with the FGD by-product alone. This specific FGD material appears to be well suited as a soil stabilizer, and the mixes can be blended in the field and modifications easily made. Soil Stabilization Similar to stabilization of FGD sludge, soil stabilization increases soil strength and bearing capacity while decreasing its water sensitivity and volume change potential. Stabilized soil can be used in the construction of roadways, parking areas, foundations for pavement, embankments, and other structural applications. Soil stabilization can eliminate the need to obtain and transport expensive, better-quality borrow materials, expedite construction by improving wet or unstable soil, and reduce pavement thicknesses by improving subgrade conditions. Cement and lime are the most effective stabilizers for a wide range of soils. Fly ash has also been used to stabilize soils in recent years. Since many fly ashes are low in CaO content, lime or cement is commonly added. The use of dry CCT by-products in soil stabilization is similar in many respects to the use of Class C fly ash or lime/cement-fly ash, since the main compositions of dry CCT by-products are fly ash, calcium sulfate/sulfite, and unreacted lime. The resulting mixtures have been found to be serviceable as subgrade in highway construction. 156 Technology Assessment of Clean Coal Technologies for China The primary method of physical stabilization is compaction. However, because compaction alone is sometimes not enough to provide soil stability, especially for fine-grained cohesive soil, chemical stabilization using a calcium-based material is often needed. Lime-fly ash and cement-fly ash mixtures were developed as stabilizers in the past decade. Class F fly ash requires the addition of cement or lime because it is not self-hardening. Class C fly ash is usually used alone as stabilizer. However, if its free lime content is low, the Class C fly ash may need to be combined with small quantities of lime or cement. With the exception of sodium sorbent injection by-product, dry CCT by-products have a high calcium content which may lead to self-cementing characteristics similar to most Class C fly ash. The presence of unreacted lime in the by-products helps the moisture reduction, plasticity modification, and pH adjustment of soils. In addition, the calcium components will react with siliceous and aluminous components in the fly ash to induce a cementing action and develop long-term strength gains due to the pozzolanic reaction. And the presence of sulfate/sulfite may contribute to moderate early strength gains of the stabilized soil due to the beneficial formation of ettringite. However, these same sulfur compounds may also cause unexpected expansion. The expansion problem has been previously observed when using lime to stabilize soil high in sulfate content. This reaction usually occurs slowly and may not become apparent until six months to two years or more after construction. Since the dry CCT by-products contain high sulfate/sulfite and abundant aluminum contents, dimensional stability should be one of the durability criteria. The basic design criteria for stabilized soils are unconfined compressive strength and durability, or ability to resist damage caused by freeze-thaw and wet-dry cycles. In the United States, for example, the American Society for Testing and Materials (ASTM) has developed a specification for the use of lime-fly ash-soil mixtures that establishes minimum unconfined compressive strength and durability requirements. The above strength and durability criteria are directed toward soil stabilization with emphasis on its use in highway construction. Dry CCT by-products can also be used for soil modification to improve the characteristics of wet, muddy sites to expedite construction. Strength and durability criteria are not normally applied to this use as they are in highway use. An evaluation of the effectiveness of stabilizers can be done simply by monitoring the improvement in the soil characteristics or properties of concern as the amount of stabilizer is varied. Stabilization of Waste Sludge Fly ash has already been used as a stabilizer for various sludges, and the solid by-products from dry CCT processes also show promise for stabilizing wet FGD, industrial waste, and hazardous waste sludges. The selection of a stabilizing agent depends on the characteristics of the sludge and cost. For FGD sludge and nonhazardous waste sludge, fly ash alone or together with lime is frequently used as a stabilizing agent. In this case, the silica and aluminum in fly ash react with the calcium in lime to form a low-strength solid. Lime may also raise the pH value of the sludge. For hazardous waste sludge, fly ash together with lime or cement can be used as a stabilizing Power Generation and Environmental Control Technologies 157 agent. Hydration of the by-product reduces the sludge moisture content and results in a strength gain. However, in many cases, blending dry CCT by-products with sludge may make a more stable and readily used material than sludges stabilized with conventional fly ash. Of particular benefit is the ability of CCT by-product to immobilize trace elements in sludge by causing them to be trapped in the ettringite/thaumasite crystal structure formed from the calcium, aluminum, silica, and sulfur in the CCT by-products. In addition, the high alkalinity of the by-products will chemically stabilize hazardous waste sludge. Sludge stabilization is similar to soil and road base stabilization in many respects. However, since most sludges generally have a high moisture and low solids content, the percentage of dry CCT by-products used in sludge stabilization is considerably higher than that used in soil or road base stabilization. Structural Fills The major advantage to using a dry CCT by-product as fill material is its high unconfined compressive strength relative to soil. The major disadvantage is that it is a new material, and its long-term behavior is relatively unknown. Laboratory tests indicate leachate concentrations are well below toxicity levels for hazardous waste, but the pH is high, generally about 12. A potential concern with these by-products is dimensional stability (expansion). Although no reports of expansion of these by-products in fills have been identified, fluidized-bed materials have in some cases been expansive in road base, and erratic unconfined compressive strengths have been observed over time in some laboratory samples. Finally, these by-products need to be used when they are available; otherwise they may be impractical to recover from the storage facility because they are self-hardening (unless stored dry in silos-typical silo volumes are 300 to 500 cubic meters). Further, exposed stockpiles may experience in changes in by-product reactivity. Grout Grouts are fluids used to fill voids or fissures accessible only by injection. Their purpose is either to increase the structural strength or reduce the permeability of a subsurface location. Suspension grouts are typically cement and water based, and may contain combinations of fly ash, lime, and/or sand. Admixtures may also be used to control set or improve workability. In grout, dry CCT by-products may be used to replace fly ash, lime, and/or cement. Granular spent bed material from AFBC and PFBC may also serve as a replacement for sand in a grout mix. Potential advantages of dry CCT by-products include: Fine particle size Reduced segregation Low cost Excellent strength development Possible limitations to be considered include: 158 Technology Assessment of Clean Coal Technologies for China Expansion Sulfate attack on concrete Time of set Heat of hydration Brick, Block, and Aggregates Bricks use mixtures of by-products and clay or sand. In block production, the basic components of the mixture are cement, by-products, sand, aggregate, and water. Sometimes preconditioning of the by-product is needed before mixing the by-product with other materials. Synthetic aggregate can be formed by mechanical agglomeration, briquetting, or forming large blocks/beams. In general, synthetic aggregates should meet ASTM specifications for the expected application. The bricks/blocks should be evaluated for absorption, compressive and flexural strength, efflorescence, freeze-thaw resistance, and dimensional stability. The calcium sulfate compounds in dry CCT by-product ash pose some potential concerns, including dimensional stability (expansion), long-term strength loss, and sulfate attack on mortar within or between concrete blocks. Use of prehydrated by-product may mitigate long-term changes in dimensional stability and strength; however, a field demonstration wall would be necessary to completely resolve concerns associated with calcium sulfate and related compounds. Cement Production and Replacement As with fly ash, there are three potential uses of dry CCT by-products in the cement manufacturing industry: Raw feed for cement production (by-product added prior to clinkering) Production of a blended cement (by-product added after clinkering) Partial substitution for cement in concrete The self-hardening characteristics of dry CCT by-products and their high percentage of fly ash (up to 70%) are desirable characteristics for utilization in cement and concrete production. However, wherever ASTM specifications are applicable, the use of these by-products in cement production and concrete is severely limited. ASTM C 150 provides standard specifications for Portland cement, including the chemical criteria for the final cement produced. There are no chemical composition requirements for the raw materials used to produce the cement, but the final product is limited to 4% sulfate (reported as sulfur trioxide). Because dry CCT by-products typically contain more than 4.0% sulfate, only small proportions can be used. In general, the maximum amount of by-product that may be introduced in cement production or as a cement replacement in concrete is often determined by the SO3 content. A high SO3 content may contribute to formation of sulfates in the concrete and lead to deterioration of the concrete due to sulfate expansion. Dry CCT by-product behave as pozzolans, similar to fly ash, when used to replace cement in concrete. To satisfy ASTM C 618 requirements the by-product must contain a minimum of 50% combined content of sio2 + A1203 + Fe2O3. However, this same specification disallows Power Generation and Environmental Control Technologies 159 the use of residue resulting from "the injection of lime directly into the boiler for sulfur removal." This is because of the expansive reactions that would be created by the SO2 sorbent by-products mixed with the conventional fly ash. ASTM C 618 also states that the material to be used as a mineral admixture should have no more than 5% oxidized sulfur reported as sulfur trioxide. This corresponds to 6% as sulfate/sulfite. Most of the dry CCT by-products have high sulfate/sulfite content, ranging from 6% to 20%. The high concentrations of sulfate/sulfite prohibit by-products from use as a mineral admixture for Portland cement concrete. The loss-on-ignition (LOI) levels of dry CCT by-products are similar to conventional fly ash and depend on the NOx controls used in conjunction with these SO2 controls. ASTM limits LOI to 6%, but concrete plants typically refuse ash with greater than 4% LOI. Substitutes forAgricultural Lime Dry CCT by-products can be used as soil amendments to raise the soil pH of both acidic mine soils and agricultural soils. Natural gypsum has long been used in agriculture for both chemical and physical conditioning of soils. Gypsum provides a supplemental source of sulfur and calcium for legumes, particularly peanuts, and to a lesser degree potatoes and cotton. Similar to natural agricultural gypsum, dry CCT by-products contain calcium and sulfur. However, these elements may or may not exist in the same form as in natural gypsum. Unlike gypsum, dry CCT by-products typically raise soil pH, and may harden rather than loosen soil at high application rates. Some soils may benefit by properly applied dry CCT by-products. Some peanut cropland, for instance, could benefit by an increase in pH, as this would reduce the solubility of zinc and potassium in the soil, two elements which inhibit the growth of peanuts. Fly ash and dry CCT by-products have been used in many revegetation studies and projects. Combinations of biosolids and alkaline by-products may provide complementary plant nutrients. Concerns with using dry CCT by-products include: * Variability of calcium carbonate equivalency (CCE), which could result in incorrect application rates * Contamination of agricultural land by trace elements * Interference with seed germination on sandy soil by high levels of soluble salts * Different materials handling methods than used for standard agricultural lime * Crusting or hardening of the amended soil The first three "challenges" can be overcome by frequent sampling, testing, and diligent quality assurance practices. The properties that should be tested are CCE, trace elements, soluble salts, and ash variability. The loading rate of a dry CCT by-product is determined by the rate required for proper pH adjustment. At that loading rate, it must then be determined that the following are not exceeded: 160 Technology Assessment of Clean Coal Technologies for China Soluble salts Boron, molybdenum, and selenium Heavy metals-both annual and lifetime cumulative loading rates Crusting or hardening Because of their alkalinity, one possible beneficial use for dry FGD by-products is as a limestone substitute for amendment of acidic agricultural soils. Land application of fluidized- bed combustion by-products as a lime substitute and a source of Ca and S has been investigated in a number of studies (Holmes et al., 1979; Korcak, 1980; Stout et al., 1979; Terman et al., 1978), and most recently by EPRI (TR-1 12916, July 1999). These studies have generally reported positive effects on plant growth and crop yield, with negative effects occurring only at application rates of 25 wt% or higher. Most studies with fluidized-bed materials have investigated soil pH and plant responses, with little emphasis on potential environmental impacts. EPRI investigated the responses of alfalfa (Medicago sativa L.) and corn (Zea mays L.) grown on three acidic agricultural soils amended with a dry FGD by- product applied at rates based on the liming requirement of the soils. In addition to crop responses, soil chemical effects and transport of the FGD material were monitored. Soil application of dry FGD by-product materials at the recommended liming rate can effectively and rapidly neutralize acidity in the zone of incorporation. An EPRI project even found evidence of increasing pH in underlying soil to a depth of 30 cm within one year of application. This makes the soil more favorable for plant growth because the increased pH in the zone of incorporation produces an immediate decrease in water-soluble concentrations of Al, Fe, and Mn and an increase in Ca, Mg, and S concentrations. In fact, the ability of FGD by-products to accelerate the movement of Ca and Mg, thereby increasing the base-status of sub-soils well below the zone of incorporation, is a benefit not realized with conventional liming materials. In studies to date, EPRI has found no evidence that land application of FGD by-products at the recommended liming rate would lead to elevated levels of potentially toxic trace elements in soil or water. One potential exception is water-soluble boron, which was found to increase in the application of some SO2 control by-products (from PFBC in this case) to three different soils. However, the concentrations always remained well below phytotoxic levels and decreased with time as the boron was leached from the soil. With pH-sensitive crops such as alfalfa, application of FGD by-products can increase growth and yield on acidic soils. Even when applied at twice the lime requirement rate of the soils, past studies have found no adverse effect on yield. With a crop such as corn that is less pH sensitive, the potential yield benefit from FGD by-product application may be less than for a more sensitive crop such as alfalfa. In the study using by-products from a PFBC unit, plant-available phosphorous (P) decreased, and this was attributed to the large amount of added Ca and consequent precipitation of relatively insoluble calcium phosphate. This may require farmers to adjust P fertility programs in soils where available P is low at the time the FGD by-product is applied. Power Generation and Environmental Control Technologies 161 Fertilizer from Mixture of Dry CCT By-products and Biosolids Although fly ash and CCT by-products have been used in many revegetation studies and projects, these materials, do not provide essential nitrogen to plants. Some recent research has focused on the use of biosolids (sewage sludge) to provide organic matter and nitrogen. While biosolids can increase a site's biomass, they may not affect the pH, iron, or lead contents of the soils; these could be improved by the addition of an alkali such as a CCT by- product. Miscellaneous Uses of Clean Coal By-products Another use of the by-products from clean coal technologies is to create farm feedlot surfaces that could improve animal production. In areas with humid climates, muddy farm conditions can cause poor animal productivity. There are few economically viable remedies currently available to overcome this problem. In one project, EPRI constructed a feedlot pad by blending dry PFBC material into the top 20 cm of in-place soil and compacting. This procedure created a suitable platform for the placement of an additional 20 cm to 30 cm layer of blended cyclone and bed ash of the PFBC material. Based on laboratory results and the field observations from the PFBC feedlot, two additional 1200 m2 pads were constructed for hay bale storage using wet FGD by-product material. To achieve the required densities and strengths, an additional 5% to 10% of lime was added at the job site prior to compaction. The chemistry of FGD by-products is ideal for use in reclamation of abandoned mine sites. The high alkalinity content improves soil pH, creating an environment that is acceptable for plant growth. The high gypsum content helps move calcium down into the soil profile so that areas not directly in contact with the applied FGD by-product can also be improved. One of the problems with traditional resoil reclamation technologies is that the surface soil layer is very thin. If any erosion occurs, the rooting depth becomes too shallow to maintain plant growth. FGD by-products help overcome this problem by providing more soluble basic cations that can move into the underlying spoil material, thus increasing plant rooting depth. In addition, use of FGD by-products avoids the problem of having to disturb one area of land to reclaim another. Moreover, EPRI studies have shown that surface water quality can be substantially improved from what existed prior to reclamation, with no change in ground water quality. 3.8.5: Environmental Impacts of Combustion By-product Use This section provides information on the environmental characteristics of clean coal technology by-products that affect reuse options. The chemical, physical, and engineering characteristics of the CCT by-products determine how each by-product will react with its environment and with the other mixture components involved in specific utilization options. It is also useful to know how the differences in the CCT processes such as process operating conditions, source and type of coal, type of sorbent, etc., change the by-product characteristics. 162 Technology Assessment of Clean Coal Technologies for China General CCT Characteristics By-products are characterized by chemical reactivity, physical characteristics, and leachate chemistry. All these criteria influence utilization potential and are interrelated. Changes in one property can produce changes in the other properties and affect the utilization potential. Generally, the differences between the properties of CCT by-products and those of conventional fly ash and bottom ash are due to the addition of alkali to capture S02 and the resulting presence of an alkali-sulfur solid product. Chemical compounds related to CCT by- products are listed on Table 3.26. Unlike Class F coal ash, SO2 control by-products contain significant quantities of calcium or sodium oxide (CaO or Na2O) and calcium or sodium sulfate/sulfite (CaSO4 and CaSO3 or Na2SO4 and Na2SO3). Like many sources of Class C fly ash, these compounds exhibit self-hardening, or cementing, properties and react exothermically (release heat) with the addition of water. If this heat of reaction is excessive, the material may experience cracking, weakening, or even blowouts. Also, the high alkalinity of these by-products produces a higher-pH leachate than most conventional fly ashes. It is necessary to understand the leaching characteristics of CCT by-products to properly determine the potential environmental consequences of disposing of the residues. Many countries have laws governing the classification of wastes for handling and disposal based on standardized leaching tests. Laboratory leaching tests include the shake or batch test and the colunn or lysimeter test. The shake test will usually give a "worst case" result, while the column test, which is designed to determine long-term leaching behavior, provides a more representative idea of leaching behavior under natural conditions. However, column or lysimeter tests are somewhat problematical for most CCT residues, since they tend to consolidate into monoliths leading to very low permeability rates. Therefore, leachates from residues newly created that have not been wetted or conditioned will differ from those older residues. 2- 2 Leachates from AFBC residues tend to be higher in soluble ions, such as S04 , Ca2+, and Cl, than conventional pulverized-coal fly ash. The concentrations of trace elements in the residues are directly related to the initial fuel composition. Although the trace element concentrations of AFBC residues are reported in the literature as similar to pulverized-coal fly ash, their leaching characteristics are different. The solubility of trace elements is decreased due to their adsorption onto the fly ash particles and they may co-precipitate with concentrated salts during the leaching procedure. The solubility is also dependent on the pH of the leaching solution and its buffering capacity. The calcium-sulfur reaction occurs in the boiler in both AFBC and FSI technologies. Because of the lower combustion temperature, AFBC fly ash typically has irregularly shaped particles with low pozzolanic reactivity. However, in the FSI process the sorbent is injected into a higher-temperature region of a conventional boiler, producing spherical, glassy FSI particles. The calcium-sulfur reaction products produced from both technologies are calcium sulfate; little or no calcium sulfite is formed due to the oxidizing atmosphere inside the boiler. Power Generation and Environmental Control Technologies 163 Table 3.26: Some Chemical Compounds Relevant to CCT By-product Formation and Utilization Name Formula Alkali Ca or Na Anhydrite CaO*SO3 or CaSO4 Calcite or Calcium Carbonate CaCO3 Calcium Oxide (lime) CaO Calcium Sulfate CaSO4 Calcium Sulfite CaSO3 Hannebachite CaSO3 Y /2H20 Ettringite 3CaO - A1203 3CaSO4 32H20 or Ca6 A12 (SO4)3 (OH)12 * 26H20 Thaumasite 2CaO * 2SiO2 *2CaCO3 * 2CaSO4 *30H20 or Ca6Si2 (SO4)2.(CO3)2 (OH)12 * 24H20 Gypsum CaO * SO3 .2H20 or CaSO4 '2H20 Hematite or Iron Oxide Fe2O3 Hydrated (slaked) Lime or Ca(OH) Portlandite Sodium Hydroxide NaOH Periclase or Mg Oxide MgO Quartz or Silicon Dioxide SiO2 Sodium Sulfate Na2SO4 Sodium Sulfite Na2SO3 The fly ash content of the by-product from postcombustion dry SO2 technologies is generally higher than that from the AFBC and FSI technologies. The physical properties of these by- products are similar to those of conventional fly ash, but they are extremely fine. Fly ash is coated by and intermixed with calcium (or sodium)-sulfur reaction product and is collected together with reaction product and unreacted sorbent. Spray dryers produce mainly sulfite components, sodium duct injection mainly sulfate components, and calcium duct injection both sulfite and sulfate components. The sodium compounds are much more soluble in water than the calcium compounds, which may result in elevated sodium concentrations in leachate. These by-products do not exhibit toxic or hazardous characteristics under current U.S. Environmental Protection Agency regulatory definitions. However, the high calcium sulfate concentrations in AFBC by-products can lead to high sulfate concentrations in leachates (which could cause violations of drinking water standards if these sulfates are allowed to reach surface or ground waters untreated). Environmental Effects of Using FGD By-product for Crop Production The use of FGD by-products as a soil amendment for crops was discussed previously. Environmental studies of these applications have shown that elemental composition of both alfalfa foliage and corn grain can be affected by FGD by-product application. The largest increases occurred with Mg and S, two major and highly soluble elements in the FGD by- product. There was no evidence of any toxicity problems due to these elements, and the increase was much less in the second growing season than it was in the first application. There were significant increases in Mo concentrations for both alfalfa and corn. Increased 164 Technology Assessment of Clean Coal Technologies for China Mo uptake is frequently noted when soils are limed and pH is increased; thus the source of the Mo is likely not from the by-product. Although there was some evidence of a small increase in alfalfa boron concentrations resulting from FGD by-product application, concentrations remained well below phytotoxic levels. There was no evidence that the use of the FGD by- product increased any other trace elements. On the other hand, there was some evidence of decreased plant tissue concentrations of Cd, Ni, and Zn in the first year of application. Calcium, the other major element in the by-product, was either unaffected or decreased; its uptake was likely inhibited by the large amount of soluble Mg in the soil following application of the FGD by-product. Data from an EPRI demonstration showed that application of FGD by-product at the design rate (22.5 Mg/ha) had no significant effect on soil physical properties including soil bulk density, moisture retention characteristics, and saturated conductivity. Similar results were observed for measurements made at different stages of crop growth and for other growing seasons. However, there were differences in total runoff due to the FGD by-product treatment; treatment decreased runoff loss by a factor of 2.5. This is attributed primarily to the improved plant growth that was stimulated by amending the soil with this by-product material. Consistent results from EPRI field studies suggest that application of FGD by- product as a soil amendment may have the beneficial side effect of reducing soil erosion. 3.9 Generation Technology Cost and Performance Summary Table 3.27 on the next page presents a summary of the costs, heat rates, and emissions for the reference plants discussed in Section 2 and the clean coal generation technologies described in Sections 3.4 through 3.7. These estimates repeat those in the earlier sections, showing them all on one table for ease of comparison. They are all for new plants. It is important to understand that the reference plants, themselves, should not be compared directly with the "clean coal technologies"-AFBC, PFBC, and IGCC-because the reference plants have neither sulfur controls nor high-performance NOx controls such as selective catalytic reduction (SCR). The figures in the emissions rate column clearly indicate these differences. The table also contains cost and performance information for three examples of reference boilers equipped with postcombustion emission controls: * The 300-MW subcritical unit with a limestone forced oxidation SO2 scrubber (FGD). Further, because a typical FGD removes approximately 50% of the particulates reaching the scrubber vessel, the particulate emission rate shown in the table for these units (100 mg/Nm3) is lower than the current requirement in China (200 mg/Nm3 in urban areas) * The 600-MW supercritical unit with an FGD * The same 600-MW supercritical unit with both an FGD and an SCR at 80% NOx reduction These estimates are provided to show the relative costs of power generation technologies with similar environmental performance. However, because the reference coal, Shenmu, has a Power Generation and Environmental Control Technologies 165 sulfur content of about 0.63%, a plant firing this coal under today's regulations in China would not require an SO2 control system. Table 3.27: Cost and Performance Summary-Conventional and Clean Coal Technologies Generation Readine Emissions Heat Rate Construct Costs2 system ss] Rate (kJ/lkWh, time (Shenmu coal, (mg/Nm3) LHV) (years) Capital Fixed Variable 0.63%S) ($/k W) O&M O&M ($/kW-yr) (mills/kWh) PC- C S02 = 1540 9,400 3 665 17.4 0.3 subcritical, no NO, = 500 FGD, 300 MW Part = 200 PC- C Ditto 9,210 3 548 14.4 0.3 subcritical, no FGD, 600 MW PC- C Ditto 8,805 3 607 14.2 0.3 supercritical, no FGD, 600 MW PC- C Ditto 8,725 3 561 13.1 0.3 supercritical, no FGD, 800 MW PC- C SO2 = 154 9,530 3 725 26.8 5.8 subcritical, NO, = 500 FGD, 300 MW Part= 100 PC- C Ditto 8,930 3 608 21.6 5.8 supercritical, FGD, 600 MW PC- C S02= 154 8,950 3 656 21.7 8.6 supercritical, NO, = 100 FGD/ SCR, 600 Part = 100 MW AFBC, 300 D (3-5 SO2 = 154 9,400 3 721 17.9 0.5 MW3 yrs) NOX = 163 Part = 200 PFBC, 350 D (-10 S02= 154 8,920 3 803 20.1 0.5 MW3 yr) NO, = 213 Part = 200 IGCC, 400 MW D (-10+ S02 = 10 7,980 3 1,038 22.5 0.1 yr) NO, = 50 Part=< 10 o C = cormnercial; D = demo; P = pilot. Numbers in parentheses = projected years to conmmercial availability. o Costs are for applications in China; capital costs exclude AFUDC and "owners costs" (royalties, land, and initial inventory of all consumables or replaceable itemns); O&M costs are for first year. o SNCR at $9/kW (plus ammonia at - 300 kg/hr for a 300-MW unit) would yield NO, emissions similar to a subcritical or supercritical boiler with SCR. I I i Appendix A Coal Production and Use in China China is the world's leading producer and consumer of coal. Given the nation's energy resources, existing infrastructure and technological development, and economic growth rates, coal will remain China's dominant energy source for many decades to come. However, this heavy reliance on coal raises serious sustainability concerns, in terms of both natural resource conservation and environmental impacts. A.1 Sustainability Issues Natural resource depletion is a concern with high coal use in the face of rapid economic expansion. On a per capita basis, China has half the proven coal reserves of the rest of the world-and these are being mined at a very fast pace, with current mining accounting for a quarter of total world output. Because most of these coal resources are combusted directly in equipment that is not designed for high efficiency, such as residential stoves, the general energy utilization efficiency of coal in China is only about 9%. This ratio is roughly half that of highly industrialized countries. From an environmental perspective, coal use has had serious impacts on all media-land, water, and air. The large amount of coal mining, with associated processing and waste storage, has damaged the ecology of vast tracts of land that could otherwise be used for agriculture. The quantity of coal refuse being stored now amounts to 3 Gt, at 1,200 disposal sites. More than 120 of these waste piles have caught fire spontaneously, emitting substantial amounts of SO2, NOR, CO, H2S, and particulates. Carbon dioxide is, of course, also produced from these fires and upon coal combustion. Greenhouse gas emissions also come from the estimated 5 billion cubic meters of coal bed methane vented from underground mines each year. Wastewater is also a problem; every year, 2.2 Gt of mine drainage water, 10 Mt of slurried fines, 28 Mt of effluent from coal cleaning, and 30 Mt of other mining-related wastewater are discharged. In addition to production impacts, coal consumption-especially direct combustion-has caused serious air quality problems in most of China's cities. About 74% of sulfur dioxide (SO2), 85% of carbon dioxide (CO2), 60% of nitrogen oxides (NOj) and 70% of total suspended particulate (TSP) emissions are caused by coal combustion. These coal-derived SO2 emissions are also the chief cause of the country's acid rain problems. Air pollution could be alleviated through greater use of coal cleaning. Although China's coal is generally of poor quality with high ash and sulfur content, and could thus benefit from cleaning, less than 25% of commercial raw coal is washed prior to combustion. 167 168 Technology Assessment of Clean Coal Technologies for China Figure A.1: Primary Energy Production in China, 1997 Raw C oal /~ 75% / -1 _SS <~~~~~~~\Crude Oil 17% // < _Natural Gas Hydro & / 2% Nuclear- 6% A.2 Coal Production Over the last two decades, coal has constituted 70-75% of China's primary energy production. In 1997, China produced 1325 Mt of coal (1027 Mt bituminous, 241 Mt anthracite, and 57 Mt lignite), which accounted for 74.3% of its primary energy. In contrast, China's 1997 crude oil production was 17.4% of the total energy mix, natural gas production was 2.3%, and the non-fossil sources-hydropower and nuclear generation-contributed 6.0% of the energy production (see Figure A.1). A.3 Coal Consumption Coal also accounts for about three quarters of China's primary energy consumption. Coal use in China is dominated by five main sectors: power generation and district heating, metallurgy, building materials, chemical manufacturing, and residential use. As shown in Table A-1, utilization of coal by these five sectors relative to the total consumption in China increased 10 percentage points from 1990 to 1997, and is projected to grow an additional 6 percentage points by the year 2005. Significantly, within these sectors, the power generation and heating sector grew, while the residential sector decreased its reliance on direct combustion of coal; this important trend is projected to continue for the foreseeable future. As discussed earlier, increasing the proportion of coal used for electricity production and district heating-rather than for domestic heating and cooking, which have lower energy conversion efficiencies-is good news, indicating progressive improvement in overall energy use efficiency, environmental quality, and public awareness of the importance of energy conservation. Coal Production and Use in China 169 Table A.1: Coal Consumption by Main Sectors in China (in megatonnes) 1990 1995 1997 2000 (est.) 2005 (est.) Total coal consumption 1055 1307 1311 1200 1300 1. Power generation and heating 291 477 538 553 615 Power generation portion (265) (430) (481) (495) (550) Heating portion (26) (47) (52) (58) (65) 2. Metallurgy 81 102 104 100 100 3. Chemicals 60 82 76 76 79 4. Building materials 107 155 152 135 140 5. Residential use 167 135 135 120 130 Subtotal of these 5 sectors 706 951 1005 984 1064 Five-sector share of total coal use 67% 73% 77% 82% 82% A.4 Forecasts of Future Consumption Analysts suggest that China will be able to sustain an average annual economic growth rate of 7.2% during the ninth and tenth Five-Year periods, with little or no increase in energy consumption (1,300 Mt/y). Projections for 2010, however, show an increase in annual coal use to 1,500 Mt, which will require expansion of existing mines or opening of new mines. At the same time, the corresponding need for new coal-to-electricity energy conversion systems provides China the opportunity to expand economically with more environmentally friendly clean coal technologies. A.5 Limited Ability to Substitute Natural Gas As the cleanest of fossil fuels, natural gas creates less pollution than coal. Moreover, natural gas can be burned in higher-efficiency appliances and gas turbine combined cycles for power production. But while natural gas offers environmental advantages, it does require economic access to this resource, including the willingness to import the desired amounts. In addition, its widespread use requires a more complex transmission and distribution infrastructure than coal, with pipelines and underground storage reservoirs. As of 1997, natural gas comprised only 2.2% of China's energy consumption mix, compared with a world average of 23.5%. China's natural gas output in 1996 was 20.1 Gm3, with about 42% of this amount coming directly from gas fields while the remainder was "associated gas" produced concurrently with crude oil production (mostly onshore). The country's reserves are not extensive; as of 1996, proven natural gas reserves were 1.17 Tm3, with a reserve-to- mining ratio of 58.8, ranking 20th in the world. However, experts believe that the actual recoverable reserves could be as high as 30 Tm3 from gas fields and associated gas production. In addition, an equal amount of gas could potentially be extractable as coalbed methane. Analysts project that natural gas production and use will grow to 7-8% of China's primary energy resources by 2010, and to 9-10% by 2020. Yet even with this approximate 170 Technology Assessment of Clean Coal Technologies for China quadrupling in use over the next two decades, its role in China's overall energy consumption will remain relatively small. Natural gas will chiefly be used in areas where transmission and distribution piping systems can be installed economically, such as newly developed areas of major cities, industrial centers, and regions close to gas fields. Since natural gas can make an important contribution to environmental improvement, particularly in cities afflicted with poor air quality, the government may need to adopt policies to encourage its use where natural market forces or environmental laws, themselves, will not produce this result. Such policy could include measures to promote expanded natural gas exploration and industry development. Expanding town gas beyond its current use by about 10% of the population (mostly in middle- sized and large cities) should be considered an alternative where natural gas is very costly or a strategic option is desired that provides the environmental benefits of gas and the security of using domestic coal. Appendix B Early IGCC Operating Experience This Appendix provides some additional details beyond the overview presented in Section 3.7.2. Pifnon Pine, Nevada, USA. As of September 1999, this facility has only experienced some short runs on coal and had not yet delivered syngas to the combustion turbine. The main problem has been with the discharge and handling of fine material collected in the hot gas filter, which resulted in significant candle breakage. Puertollano, Spain. The ELCOGAS project in Spain also experienced startup problems and, therefore, has only a few hundred hours of operations on coal. The main problem has been vibration ("humming") in the Siemens combustors similar to that which had occurred earlier at Buggenum (see below). Siemens has supplied redesigned burners, and improvements have been made; however, the vibration problem has persisted during the changeover from natural gas to syngas. As noted in Section 3.7.2, only extended multi-year operations can really test the durability of gas turbines in an IGCC application. With this caveat in mind, it can be said the results to date from the U.S. projects with the GE F-class gas turbines are very encouraging. In fact, in recent papers GE has stated that the 7FA should be capable of producing over 200 MW in certain IGCC configurations. However, in March of 1999, the GE 7FA at Wabash experienced a compressor failure unrelated to the IGCC application. This unit has been repaired, and the plant has just completed a run of- 1000 hours. Tampa, Florida, USA. At this Texaco gasifier, the gas/gas heat exchangers have been taken out of service to overcome the fouling downstream of the gasifier and corrosion in the lower gas temperature range of 250-300°C that had been experienced. Further, the horizontal firetube convective coolers require cleaning every 8-10 weeks. The gasifier has experienced greater generation of fines than expected in the design and, therefore, lower carbon conversion. Work continues on addressing these problems, but, in the meantime, the plant continues to performn well at lower than design efficiency. Wabash River, Indiana, USA. The main remaining problem area for the Destec gasifier at this site seems to be the dry gas filter, where corrosion and blinding of the metallic candles continues to occur. This project included the repowering of an old steam turbine, and a problem with the feedwater heaters for the HRSG has resulted in the steam turbine producing only 98 MW versus the design value of 105 MW. If a newly designed steam turbine had been used, the output would have been > 120 MW. The problems mentioned above are being addressed at both Tampa and Wabash River, and most recent operations at these two sites are encouraging. The plants show considerable progress, with both projects experiencing long runs and higher availability. 171 172 Technology Assessment of Clean Coal Technologies for China Buggenum, The Netherlands. Because of the characteristics of the Siemens gas turbine and the owner's desire for maximum efficiency, the SEP/Demkolec plant was designed with full integration of the ASU and gas turbine. In other words, the entire feed for the ASU is supplied (extracted) from the gas turbine compressor. This tight integration has resulted in some operational sensitivities and complexities, leading SEP to recommend only partial integration for future installations. The ASUs at Wabash and Tampa are supplied by their own compressors, so this problem does not arise. The main problem encountered in the early years of operation at Buggenum has been combustion-induced vibrations and overheating in the gas turbine combustors. In contrast to the multiple-can annular-type combustors on the GE F-class gas turbines, the Siemens V 94.2 has two external vertical silo-type combustors situated on each side of the shaft. GE/EPRI/Shell/DOE conducted full-pressure, full-load syngas combustion tests on the GE 'F' combustors in 1990-92 prior to their installation in the U.S. IGCC projects. Unfortunately it would have been prohibitively expensive for Siemens to conduct full-scale silo combustion tests before installation, and it has, therefore, been necessary to utilize multiple empirical "cut and try" design changes in the field to alleviate the vibration and overheating problems. As noted above, the same problem occurred later at the Puertollano site in Spain. To maximize efficiency, the pressure drop across the fuel gas control valve at the European sites was only about half that normally used for natural gas. This probably contributed to some of the problems of maldistribution, lack of combustion control, and vibrations. The design changes made in early 1997 have markedly improved the vibration problem, and since that time several long runs have been conducted, with an availability of over 80% in each quarter since the third quarter of 1997. In the third and fourth quarters of 1998, the gasification island was in continuous operation for over 2000 hours. In 1998, the overall on- stream IGCC factor was - 56%. The Shell gasifier has generally performed well, and the successful scaleup from the 225 tonnes/day gasifier at Houston (SCGP-1 operated 1987-91) to the 2000 tonnes/day unit at Buggenum has been amply demonstrated. The raw gas from a dry-coal-fed gasifier such as Shell has lower water content than the slurry-fed gasifiers of Texaco and Destec. Because of this, dew point corrosion in the lower temperature ranges is less likely to occur and, consequently, has not been a problem at Buggenum. The Shell gasifier at Buggenum has achieved its design cold gas efficiency. The gasifiers on the Wabash River and Tampa plants are generally operating a little below their design cold gas efficiencies. Both the Wabash River and Buggenum plants have met their overall IGCC design efficiencies. However, at Tampa, the removal of the gas/gas exchangers from service and the extra fines production from the lower carbon conversion (and hence lower cold gas efficiency) are currently the major contributors to the lower-than-design overall efficiency. Appendix C Supercritical Boilers and Suppliers in China-Report on Site Visits This appendix presents the detailed information obtained during visits to two power plants with supercritical boilers and the three major boiler manufacturers in China. The first section reproduces that portion of the trip report prepared for the World Bank that summarizes the information and insights obtained during these visits (power plants with other technologies were also visited and documented in the trip report, as were organizational meetings held during the same time period, but these are not presented here). The next section supplements the summary in the trip report with a detailed report that contains all the information provided to the study team by the power plants and boiler manufacturers. All three major boiler suppliers belong to parent companies who also have steam turbine divisions. The study team did not visit these turbine suppliers, but sent them questions about their capabilities and experience with supercritical plants. These questions and the turbine suppliers' responses are contained in the last section of this appendix. C.1 Trip Report Summary Dates: April 26 through May 7, 1999 Locations: Shanghai, Dongfang, and Harbin Boiler Works; Shidongkou and Panshan power stations Topics: Domestic capabilities to supply and operate supercritical power plants The purpose of the visits to the boiler works and power plants was to obtain in-depth technical information on the capabilities of these organizations to supply and operate supercritical (SC) boilers. During the meetings with the boiler works, the team also explored their plans for developing or obtaining expertise in clean coal technologies. C. 1.1 Key Findings 1. The three domestic boiler suppliers seem to have the manufacturing capability to provide first-generation supercritical (SC) boilers (approximately 25 MPa/540°C/540°C), possibly with some additional technology transfer from foreign suppliers on detailed design issues. Further technology transfer will be required for units with higher pressure and temperature. 2. The two power plants with SC boilers visited by the study team understood the unique operational characteristics of these types of boilers; exercised careful control of water quality and metal temperatures; and were achieving good availabilities and forced outage rates. 173 174 Technology Assessment of Clean Coal Technologies for China 3. The boiler suppliers would import 70-100% of the steel for the high- temperature/pressure components. This is based on a combination of availability and price considerations (some advanced steels made in China cost more than imported steels). 4. The expected price difference between SC and subcritical boilers seems to range from 5-20%. 5. Extensive and thorough training is essential to minimize problems during the first few years of operating a new technology. The SC plants that emphasize training of their engineers, operators, and maintenance staff did not experience many problems due to operator or maintenance errors. C.1.2 SummaryReport The discussion of the three boiler suppliers is presented first, followed by that for the two power plants. The order of the discussion in each case is simply the order in which they were visited. Cl.2.1 Shanghai Boiler Works On April 26, the study team met with Dr. T. K. Niu (Vice President and Chief Engineer), Mr. Z. Liu (Deputy Director), H. Pan, X. Jin, and W. Zhuang (Vice Chief Engineers), and C. Guo (Senior Engineer). Dr. Niu introduced the team to Shanghai Boiler Works, Ltd. (SBWL) and stressed SBWL's ability to develop its own technology, such as once-through boilers. He also identified the many companies with whom they cooperate, including many of the major international boiler suppliers. They have been providing once-through boilers with vertical waterwalls since the early 1960s using Soviet technology and have recently switched to Steinmueller technology. SBWL generally imports high-quality steel because the domestic steel manufacturers do not have the technology to manufacture it nor the code approvals (expensive to obtain and not yet justified by demand). As a result, they import 30-60% of the pressure-part materials for subcritical units and 100% for SC boilers. The cost differential between domestic and imported steels is about 30%. Their shops are very large, well maintained, and have the necessary equipment to bend and weld tubes, including spiral-wound waterwalls; to weld large pipes and headers (all seamless); and to roll and weld thick plates for drums (the only place they use seam welding). In addition, they have the largest annealing furnace in China (30 m long). C.1.2.2 Dongfang Boiler Works (DBC) Also on April 30, the study team visited the Dongfang Boiler Works, hosted by Mr. Benrong Yao, Vice President and Chief Engineer, with assistance from Mr. Guang Li, Director of the Comprehensive Technology Department, Mr. Jiaqin Xu, Director of the Technology Department, and others. They are developing the know-how to design and manufacture CFB Supercritical Boilers and Suppliers In China-Report on Site Visits 175 and SC boilers, and are watching technology developments for the longer-term technologies (PFBC, IGCC). They are allied with Babcock-Hitachi (BHK) for SC boilers, which would be manufactured at Dongfang using BHK technology, and with Foster Wheeler for CFB technology (they have built several 50-MW units under this license and had just heard that they had received orders for 6 units of 410-450 ton/hr capacity). They see a large demand for CFB units in China over the next ten years. For larger units (e.g., 300 MW), they plan to use a combination of in- house technology development and cooperation with foreign suppliers. For SC boilers, their answers to the questions sent in advance by the team showed that: (1) they understood all the materials issues associated with SC boilers; (2) had a careful QA/QC program for both in-house work (i.e., welding) and materials (steel) inspection on receipt from their suppliers; (3) used mostly imported steel for high-pressure, high-temperature parts; (4) are ISO 9001 certified and use only ISO 9001 certified steel suppliers; and (5) have ASME S, U, and U2 stamps; (6) procure their materials according to the applicable international codes (ASME for U.S. suppliers or customers that specify this code, JIS for Japan, DIN or BS for Europe, or equivalent national codes for material supplied and used domestically). The shop visit showed that their welding equipment is highly automated. Therefore, they should be able to build SC boilers with a high-percentage of domestic content, except for the steels/alloys used for the high-temperature, high-pressure headers and pipes. For subcritical boilers they import about 50% of the steel for pressure parts, and for SC boilers they expect to import 70-80% of these raw materials. C.1.2.3 Harbin Boiler Co., Ltd. (HBC) This visit took place on May 3, and the study team was hosted by Mr. Jinlong, Vice Executive General Manager, with the assistance of Mr. Wenjian Li, Vice General Manager, and Mr. Shuquan Zhang, Director of Sales and Marketing. HBC has had a license with ABB-CE since 1981 to manufacture subcritical boilers (300-600 MW); a cooperative agreement with Ahlstrom/ PyroPower since 1993 for CFBs (mostly < 220 t/h, or 50 MW,); a recent technology transfer agreement with Combustion Power Corporation for 35-75 t/h CFB (under the GEF industrial boiler project); and a new agreement with EVT in Germany for 220-410 t/h CFBs. HBC has also built components and complete boilers for several foreign suppliers. They are very interested in obtaining expertise in foreign technology and accelerating its penetration into China, but the absence of a predictable demand for these advanced technologies leads them to rely on Chinese government or international financing assistance for such technology transfer; they obtained the license for the Combustion Power technology in this manner (a GEF project). Informally, they estimate that the capital cost of a 100-MW CFB would be about 20% higher than for a subcritical coal plant without FGD. HBC also provided answers to the questions sent in advance, which showed that they had similar understanding of the issues, QA/QC procedures, and steel procurement philosophies as Dongfang (see above). In addition, they had made substantial investments in automated welding and inspection equipment, have developed their own dual-register low-NOx burner (capable of meeting World Bank limits) and semi-dry SO2 removal system (a variant of LIFAC), and have participated in several collaborative projects on PFBC and IGCC. They 176 Technology Assessment of Clean Coal Technologies for China did mention that they were conducting research on some domestic steels that could have better properties than T22 for tubes. C.1.2.4 Shidongkou Power Station On April 27, the team visited this site of the first two supercritical (SC) boilers in China, hosted by Mr. Shihai Hu, Deputy Plant Manager, and Mr. Xuzhu Tao, Deputy Manager and Chief Engineer. The station provided detailed availability data; for 1998 it was 85% for one unit that had a scheduled 45-day outage and 96% for the other unit. The plant has an aggressive maintenance program, which has resulted in fewer maintenance problems than typical subcritical boilers (the once-through design also helps by avoiding problems with drums), and more stable operation. Since startup in 1994, 80% of the problems have been due to design and startup issues. All the design issues have been on the fireside and most have been corrected through operating changes and some modifications (only one boiler tube failure in 1998). The remaining 20% of the problems have been due to operator unfamiliarity with this equipment, and were corrected by 1995 by increased training. The steam turbine has never caused an unplanned outage. These units do benefit from a stable coal supply (two coals blended to achieve target slagging temperatures). The hightemperature/pressure steels were all imported (from Europe, meeting DIN standards), and they would require international code-compliant steels in future procurements (e.g., phase 2). They pay strict attention to water quality (using combined water treatment), with substantial on-line and manual sampling, maintaining key paramneters within internationally recognized levels. For the future, they considered 2 x 900 MW advanced clean coal technologies, but are now looking at natural gas-or LNG-fueled power stations because the Shanghai government has banned the construction of new coal facilities. C.1.2.5 Panshan Power Plant, North China Power On May 5, the study team visited this plant to learn about their experience operating two 500- MW SC boilers. Mr. Dake Gu, Director, and Mr. Zhigwang Jia, Deputy Chief Engineer of Operations, represented the plant. Virtually the entire power plant was supplied by Russia, including the boilers, turbine-generators, instrument and control systems, and all balance-of- plant equipment and services. The units are constant-pressure boilers, designed to operate as baseload units between 70% and 100% MCR, with steam conditions of 25 MPa/545°C/545°C. Startup was 2/96 and 5/96 for units 1 and 2, respectively, and operation was not as stable as desired at the beginning due to design problems, installation issues, and operator unfamiliarity with the technology. Most of the problems have been resolved, and the reliability/availability has improved as follows: average operational hours increased from 2900 in 1996 to 5600 in 1998, while total forced outages for both units combined decreased from 38 in 1996 to 10 in 1998, with only 6 expected in 1999. Two-thirds of these outages have been due to leaking valves or trips caused by the control system for no reason (they are replacing the control system on one unit now, during its major overhaul); none have been due to tube failures-i.e., inadequate temperature or water chemistry control. They monitor tube metal temperatures at Supercritical Boilers and Suppliers In China-Report on Site Visits 177 numerous locations and water chemistry at seven on-line locations plus manual sampling at three-hour intervals. They check for tube leaks by acoustic monitoring and measuring deposition inside waterwall tubes (selective extraction of tube samples during the annual maintenance outage). As far as they understand, the reliability/availability experience of all the operating Russian SC boilers in China (two other 500-MW units and four 300-MW units; an additional four are under construction) is about the same as for typical new Chinese subcritical plants. Most of their experience has been with one coal (0.9% sulfur, 12% ash), but they began using a second coal (0.3-0.4% sulfur, 7% ash) in February 1999. Neither coal gives them slagging problems. C.2 Supplement-Details on Supercritical Technology in China The following discussions are arranged in the same order as in the previous section. Most of the QA/QC procedures are the same for all three boiler suppliers. The only apparent manufacturing differences are less automation at SBWL and lack of spiral-wound capabilities atDBC. There is a general consensus in China (suppliers, design institutes, and government, with the power companies following suit because they rely on the design institutes as their A/E's and technical experts) that a 25 MPa/541°C/569°C unit is the right design for China now. All three boiler suppliers have been acquiring experience in this technology through a combination of arrangements with major Japanese, U.S., or European firms and in-house R&D. Higher-pressure/temperature systems may be considered in the future if the first few SC units built according to the above specifications with significant domestic content perform satisfactorily. To find out more about the materials for SC boilers, the study team sent the questions listed in Table B-1 to the three boiler suppliers. A summary of their answers is presented in Table B-2 (both are at the end of this appendix). C.2.1 Shanghai Boiler Works SBWL manufactures about 4,000 MW of boilers per year-all subcritical except for being a subcontractor to ABB on the Shidongkou #2 600-MW project (25 MPa/541°C/569°C) and 25 years experience producing 5 t/h industrial SC units-and has 40% of the Chinese market share of 300-MW units. They say they can design and fabricate SC boilers themselves, based on training from abroad; they have "done" 17.2 MPa/540°C units and have the capability to do 23.7 MPa/540°C. They are authorized to use ASME Stamps S, U, and U2, as well as the Japanese JIS and MITI codes, the Indian IBR code, and the European BS and DIN codes. SBWL was certified as compliant with ISO 9001 in 1993. They have a technology transfer agreement with ABB Sulzer for SC boilers, including spiral-wound tubes and startup bypass, as well as with ABB CE for the combustion system. Other vendors with whom they have cooperated include Foster Wheeler, IHI, Mitsui Babcock, Deutsche Babcock, MHI, and Uhde. 178 Technology Assessment of Clean Coal Technologies for China According to SBWL, the Chinese steel manufacturers cannot supply high-alloy steels, thick plates for drums, or large-diameter pipes and do not have ASME code approval (although they do have Chinese code approval, which is based on ASME codes and is even stricter in some aspects). For domestic plants, they use Chinese steels for about 70% of the pressure parts and imported steels for 30%, mainly the high-temperature components. They use domestic 20G, 15Mo3, 15CrMo, and 12CrlMoV in the low- and medium-temperature zones. For subcritical plants supplied abroad, they generally use 100% imported steels because the customers require conformance to some international code (ASME, DIN, etc.). The cost differential between domestic and imported steels is about 30% after including freight, import tariffs of 6-7%, and value-added taxes (VAT) of 17%; the price of domestic steel including the 17% VAT is about the same or slightly higher than the cost of imported steel before application of these three additional charges. (This differs from Dongfang, which said the price is often the same or more expensive domestically where the product is available both locally and as an import, although this may be a short-term effect due to dis-economies of scale for the Chinese facilities today.) SBWL has worked out a procedure for welding ferritic to austenitic steels that has worked successfully for many years. They can bend metal up to 250 mm for vessels. They have been using T91 for 10 years and now are ready to use P91. SA 291, SA 213, T 91, and TP347 must all be imported. They have not experienced any boiler tube failure (BTF) problems with these materials, even in high-sulfur applications. Steel suppliers are: Small Diameter, Domestic BaoShan (Shanghai), Shanghai Iron & Steel Works, Tiensing Steel Tube (near Beijing) Small Diameter, Foreign Sumitomo, NKK, Nippon, Kawasaki; Mannesman (now V&M); Valouric Large Diameter Wuhan Casting and Forging Works Heavy Plate, Domestic Wuyan Iron and Steel Heavy Plate, Foreign Dillinger, Thyssen, Creusot-Loire Welding Consumables Shanghai Electrode Works, Kobe (especially for T91), Nippon Welding Consumables, Hyundai Welding Consumables, Isaac (UK), another Japanese firm for 9Cr alloy If the tube diameter is > 30 mm, it is supplied after tempering and quenching; if < 30 mm, it is supplied after normalizing and tempering. For QA/QC on receipt of steel, they do a combination of "conventional" and "additional" tests. First, they check the QA certificate and do size variation and appearance (surface quality) verification. Then they collect samples of the material and re-test it for conformance with the specifications (e.g., chemical analysis, tensile strength, impact resistance, thermal expansion). They claim that Chinese law prohibits the buyer from participating in the Supercritical Boilers and Suppliers In China-Report on Site Visits 179 supplier's QA/QC program, so they can just observe (the other suppliers said they audit their suppliers for compliance with their stated QA/QC procedures). If the steel mill has ASME code approval, it will have the necessary physical and chemical test equipment. Third-party inspectors are not used unless specified by the customer (typical of all three boiler suppliers). This is generally not done for boilers built according to ASME or Chinese codes; it may be done for units bid in accordance with DIN or BS standards, if specified in the bid document. They use seam welding for drums with induction heating to improve the weld; otherwise use seamless tubing and piping. They do dissimilar welding only in the shop. After much R&D and lab tests, they have settled on nickel-based weld material (> 67% Ni) to deal with different thermal expansion and migration of carbon. They did this in 1986 on SH and RH tubing for a 600-MW boiler. They use two techniques: CIT (constant infusion technology) for the first two layers and MIT (metal infusion technology) for the surface layer. They also follow special procedures (heat treatment schedules) to reduce internal stresses. Using these techniques, they have never had a problem with dissimilar welds and have units with > 10 years operation. Recommended inspection intervals are largely specified by the customer and the Department of Labor's safety regulations. These requirements are largely driven by ASME and Chinese codes and are very comprehensive. Their operation manual does recommend, for example, temperatures that should be measured; these recommendations are based on their experience and lab tests. C.2.2 Dongfang Boiler Works (DBC) DBC inspects 100% of its welds. Automated welding equipment was installed between 1991 and 1996. They do not have spiral-wound capability (the only one of the three manufacturers that doesn't). They use the materials specified by Babcock-Hitachi (BHK), similar to those used for subcritical boilers purchased in China. They expect that over 90% of boiler components for SC boilers will be produced at DBC, including all the welding. For subcritical units, they use P22 (some available domestically) for the header; for SC boilers it would be P91 (imported). SS304, and 347 for small-diameter tubes and materials for headers are all imported. However, they said they purchase on the basis of price and availability; generally, imported alloy steels cost less than the Chinese products. There is now some limited domestic capability to produce SS304 and 349 (joint venture with a U.S. firm). DBC is cooperating with a Chinese supplier to produce P91. One Chinese supplier has recently begun to supply large headers; it has already produced > 10,000 tons (including C-steel and P22). Regarding QA/QC used by steel suppliers, they too demurred on this one. They do have specifications and certify their suppliers according to them. They also audit their suppliers per ISO 9001. They specify the heat treatment/quench process to be used by the suppliers based on ASME and Chinese national codes (e.g., GB 5310-this code was also mentioned by Harbin). On testing, they specify that suppliers must UT 100% of steel plate and 100% UT plus 100% eddy current on steel tubes. They also specify destructive tests for physical properties. Composition is based on codes (JIS, ASME, DIN if purchased internationally; Chinese codes if purchased domestically). Upon receipt of the steel, they check the 180 Technology Assessment of Clean Coal Technologies for China documents for record of complete QA/QC by the supplier, verify that the documents apply to the materials, conduct their own chemical and property tests (e.g., bending) on random samples, also do micrographic tests on samples of tubes, and UT and eddy current tests of all tubing. If a shipment passes all the tests, it is assigned a test number which it carries during the entire manufacturing process through to shipment of the final product. They use seam welding for large-diameter headers (can bend plates up to 250-mm thick in lengths up to 4.2 m). Over 30 years of doing this, they have experienced no failures with these welds (their own special design) due to the quality of their operators, their heat treatment procedures, and their QC. Dissimilar welds are used extensively in 300-MW units, and they have never experienced failures with these. They use the following methods to prevent failures: 1. Proper weld wire-Inconel 82, which has a thermal expansion between that of ferritic and austenitic steels and which reduces decarburization 2. Proper shape of the chamfer groove 3. Automatic welder (including automatic wire feeding) to ensure high quality and good penetration; this prevents undercutting from root (i.e., mitigates against stress concentration) 4. Design guides that avoid tight bends too close to such welds to prevent the introduction of additional stresses, and that keep these welds away from areas of high- temperature gradients They have conducted extensive R&D in this area for many years (their recently retired expert gave us this comprehensive briefing), especially on ways to reduce stress. Their main focus has been on weld parameters, weld angles, root angles, and their effects on residual stress. They have also worked on creep mechanisms and the effect of weld parameters and design on creep (in conjunction with a university). Use of outside inspectors is similar to SBWL, i.e., determined by government regulations and customer requirements. Inspection intervals are identified in the operations manual supplied with the boiler based on their experience and codes. In general, they recommend ordinary inspections during each annual maintenance outage and special inspections during a major outage every four years. They can provide remaining-life calculations for drums if requested. Usually the customer decides if/when they want UT and other NDE tests. DBC, too, said that most inspection intervals and condition assessments are defined by government regulations. C.2.3 Harbin Boiler Works (HBC) A subsidiary of the Harbin Power Equipment Company Limited (HPEC), HBC is the largest utility boiler manufacturer in China. Its annual manufacturing capacity is 3500 MW. Through the end of 1997, HBC had produced 580 utility boilers, or one-third of all the utility boilers made in China. These include 7 x 600 MW, 8 x 350 MW and 45 x 300-MW units. They have also supplied components and boilers to many countries abroad. In 1981, they entered into an agreement with ABB-CE for the introduction of subcritical controlled- circulation boiler design and manufacture, and in 1986 the first 600-MW unit of this type was Supercritical Boilers and Suppliers In China-Report on Site Visits 181 produced. They subsequently developed 300-MW controlled-circulation and natural circulation boilers in 1987. The 15-year agreement with ABB-CE ended in 1996, but they are currently negotiating again with ABB-CE regarding a license for supercritical units in Asia. They stated that they would like to continue the relationship that they previously established with ABB-CE and Mitsubishi. Through cooperation with foreign manufacturers and domestic design institutes, HBC has developed CFB technology for China and has supplied 22 CFB boilers with capacities of 35, 75, and 220 t/h of steam. Since 1993, they have had a cooperative agreement with Ahlstrom Pyropower (now Foster Wheeler) for 220 t/h (- 50 MWe) Pyroflow CFB technology. More recently they have established a technology transfer agreement with Combustion Power Company for the Fl CIRCT technology at the 35-75 t/h size. This latter agreement is part of the UNDP/GEF industrial boiler project. They also have a new agreement with EVT (now part of Alstom ABB) for the design and manufacture of 220-420 t/h CFB boilers with higher pressure parameters (13.73 MPa/ 540°C / 5400C) including reheat. HBC does the detailed design and tries to procure materials within China. Up to the 50-MW size, domestic Chinese materials are acceptable, but some components such as the L valve, expansion joint, and loop seal must be imported. They also produce a large variety of valves, and, in 1989, they negotiated a technology transfer agreement with regard to safety valves with the Okono Valve Corporation of Japan. HBC has also manufactured some HRSGs for combined cycle units in association with CMI of Belgium, and in 1993 they supplied eight 42.75 t/h HRSGs to Pakistan. HBC has conducted a fairly substantial R&D program on supercritical technology for several years, and they have completed a preliminary design for a 600-MW unit with steam conditions of 25.3 MPa/543°C or 571°C main steam / 569°C reheat. The R&D program included water circulation and hydrodynamic calculation for vertical waterwalls, heat transfer and pressure drop for rifled tubes, the design and research of the startup bypass system, separator stress analysis, and a 12 t/h test boiler. HBC's material research institute has conducted studies on the following materials for supercritical units: Heat treatment, structure, and properties of HCM2S (better weldability than T-22) ASME SA335 P22 large-diameter pipe WB 36 plate used for steam-water separator Heat treatment, structure, properties, and weldability of T 91 Study and test of 7CrMoVTiB10 1 0(T 24) E91 1 tube for supercritical boiler HCM12A (ASME CASE 2180 HCM12A) and super 304H tubes Both P 22 and P 91 have to be imported. They would use P 22 for subcritical and P 91 for supercritical boilers. The 600-MW supercritical units can be either spiral wound or vertical waterwall. HBC prefers the vertical wall with its lower pressure drop, lower auxiliary power consumption, and lower temperature imbalance. However, for the 300-MW size, it may be preferable to select spiral winding because the tube diameter may be too small for vertical wall construction. 182 Technology Assessment of Clean Coal Technologies for China In 1994, HBC obtained the ISO 9001 Quality System Authorization Certification and passed the audit for renewal in 1997. In 1987, HBC obtained S, U, and U2 authorization certifications from ASME and NB (National Board of the Peoples Republic of China), and in 1990, 1993, and 1996 passed the audit for renewal. In 1996, they obtained the R code stamp and authorization certificate from NB. They have also obtained the design and manufacture certificates for Class A boiler, Class ARI pressure vessel, and nuclear equipment awarded by the PRC government. As was the case with Dongfang, they purchase according to their specifications or those of their customers, and the suppliers must conform per ISO 9001. Imported material is checked for ASME conformance if applicable. Steam drum plate and small-diameter tubes are often purchased to conform to the German DIN standards. They require 100% UT testing of plate and tubes. Chinese codes are used if materials are purchased and used domestically. Their suppliers for plate include Wuyang and Chongqing Iron & Steel Works (China), NKK (Japan), CLI (France), and AG der Dillinger HCltten Werke Preussag Stahl (Germany). Their suppliers for tube are Shanghai and Baoshan Iron & Steel Works (China), Kawasaki and Nippon Steel (Japan), Mannesmann (Germany), and Vallouec (France). HBC is well equipped with automatic manufacturing, welding, and diagnostic tools including an 8000-tonne oil press (up to 300 mm thick and 8 m wide), a 4-MeV linear accelerator, a 4 x 4 m Narrow Gap Submerged Arc welding machine, a 32-m NC gas furnace, a computer- controlled boiler serpentine production line, a four roller plate bender (up to 70 mm thick and 8 m wide), automatic argon-shielded arc welding for tube-to-tube sheet joints, and an X-ray Industrial TV Defect detector for continuous inspection of butt welds. HBC does not use seam-welded tubes. The large-diameter pipes are also seamless. HBC provided an account of their research and welding methods for dissimilar ferritic/austenitic materials. The problems of different thermal expansion coefficients and the need to avoid decarburization and possible martensite formation were delineated. They use Ni-based welding materials and argon arc process welding to avoid these problems. HBC maintains a Materials Research Institute that is responsible for the acceptance of materials. There is a national standard for China GB 3375. The procedures include the checking of the certificate, visual inspection, coupon tests for each lot number (chemical composition, microscopic metallurgical, mechanical, and ultrasonic tests). Boiler inspection intervals and condition assessments are established by the Ministry of Labor in a steam boiler inspection code. C.2.4 Shidongkou Power Station This plant began operation in 1992, and the plant staff are very strong advocates of SC units for improved efficiency, operation, and maintenance. Availabilities and operating hours have been as follows during the past three years: Supercritical Boilers and Suppliers In China-Report on Site Visits 183 Average Unit 1 Unit 2 Availability '98 89.7 94.6 84.9* '97 92.2 88.0 96.3 '96 86.9 90.4 83.5 Operating hours '98 8244 7437* '97 7710 8402 '96 7843 7279 * Unit 2 had a 45-day scheduled outage during 1998. They believe these experiences are better than the typical international experience, and they see little difference between subcritical and supercritical units in the level of maintenance needed and the resulting reliability/availability. They think their plant has a better operating record than most because of aggressive management attention to maintenance; this even though they are operating closer to western standards of staff/MW (about 0.35 people/MW vs. Chinese and Eastern Europe norms of 1:1). They also feel their SC unit is more stable than typical 300-MW units in China (partly because subcritical boilers have steam drums, which are major maintenance and operating problems). They attributed 80% of the problems they experienced in the beginning to design flaws: (1) controls (setting protection levels incorrectly) and (2) BTF from the waterwall (WW) to the final superheater (SH) due to sootblower erosion, deformation of parts of the WW during commissioning, deformation of the spacing plates for the SH tubes during commissioning leading to contact between tubes and consequent wear from rubbing, and faulty welds. They feel that all these problems could happen on any plant. Some of the rehater (RH) tubes had loose material left in them from manufacturing problems, which also led to overheating and tube failures. They have solved all the problems they could solve, but were limited by lack of cooperation from ABB and have some remaining problems that they attribute to design flaws. Only 20% of the problems were due to operator unfamiliarity with SC operations in the early years; they attribute this to insufficient training and stepped-up their training very early. They do have a simulator, which is the same size as the boiler and responds in real time. They use two coals, which have consistent properties, and they reject a shipment if it fails any one criterion. Coal A has 5-10% ash (8.1% average), 0.4% S, 19% Ca, 1165°C fusion temperature. Coal B has 8-15% ash (12.2% average), 0.7% S, 5.8% Ca, 1270°C fusion temperature. They mix these two coals to mitigate slagging. All the pressure-part steels were imported from Europe and meet DIN standards. - Economizer 15CrMo3 - Water separator WB 36 - Waterwall 15CrMo3 or l3Cr44Mo or lOCr9Mo (or 1OCrIOMo) depending on the temperature 184 Technology Assessment of Clean Coal Technologies for China - SH/RH 13Cr44Mo, WB36, lOCr9 (or IOCrlO), X20, again depending on the temperature. Also X8 in RH. They use combined water treatment (CWT), adding NH3 at the outlet of the polisher and 02 at this location and the outlet of the demineralizer. Their polisher is a medium-pressure regeneration system and treats 100% of the water leaving the condensate pump. They installed "many" sampling points in the water/steam line, including on-line monitoring for conductivity, pH, dissolved 02, and NaOH as well as manual sampling (eight hour intervals) for pH, conductivity, NaOH, and Cl. Their conductivity limit is 0.2 his, but they usually control it to 0.06-0.07. They keep AP < 10 g/m2. Their waterwall (WW) problems are usually less severe. They monitor WW temperatures, as well as the SH/RH tubes. If any of these exceed their limits, it is usually due to deposition and they activate the appropriate sootblowers. If it's due to one of the remaining design problems, they reduce the primary and/or secondary air flow. They have never exceeded their limit by 50°C. The only difference they see between subcritical and supercritical steam turbines is the HP section. Theirs is imported by ABB from Switzerland. It has operated stably with no impact on availability since 1994. Earlier they had had one failure on the control wheel, which was attributed to a design and manufacturing flaw (heat treatment) and was replaced by ABB, along with a revised design. C.2.5 Panshan Power Plant (Heibei Province) This plant comprises two 500-MW supercritical boilers supplied by Russia under a barter deal with China. Panshan is part of the North China Power Company Group. The steam conditions are the conventional 25 MPa!545°C/545°C. The first unit was started up in February 1996 followed by the second unit in May 1996. The availability and forced outage statistics to date are reported in the summary trip report, above. Average operating hours in 1998 were 5600 per unit. Although this is markedly lower than the availability reported for the Shidongkou units, these Panshan units are dispatched. The design operating range is 70- 100% of full load, but they sometimes have to operate at < 70%. The design coal consumption of 322 g/kWh has not yet been met largely because of low-load operation. The actual coal consumption has been 335-340 g/kWh. The characteristics of the two bituminous coals used at Panshan are as follows: Coal Mine/Location Datong/Shanxi Shemu/Inner Mongolia Proximate Analysis Moisture, % 7 15 Ash, % 12 7 Volatile Matter, % 36.6 55.5 Fixed Carbon, % 37 48 Sulfur Content, % 0.9 0.3-0.4 Supercritical Boilers and Suppliers In China-Report on Site Visits 185 Lower Heating Value, Kcal/lkg 6000 6000 Ash Deformation >1150 1100 Temperature, °C None of the forced outages were attributable to coal properties. The materials used in each section of the boilers are given below. They were all supplied from Russia. They have had no problems or forced outages due to materials. Waterwalls - 1 ICrlMo Superheater and Reheater (Finishing) - l2Crl8Nil2Ti " " 6 4 (Preliminary) - 11 CrlMo Main Steam Pipes and Headers - 15CrlMolV About 33% of the forced outages have been due to valve leakage (seals and welds), 30% due to problems with the control protection system, and the rest miscellaneous. They believe that the valve problems have been largely solved. However, they are replacing the Russian- supplied control system with a European design. The water quality is monitored on-line at the condenser outlet, polisher outlet, economizer inlet, boiler water separator inlet, and main superheater and reheater outlets for conductivity, Na, 02, and pH. The sample probes and the HP and LP heaters are all stainless steel. They also conduct manual sampling every three hours. They have had only one incident of forced outage (-2 years ago) due to water quality, and that was attributable to an equipment problem. The design basis was to decrease oxygen in the water; however, after rehabilitation of unit #2 they have used oxygen addition, and they now wish to rehabilitate unit #1 to also use oxygen treatment. Water quality criteria were provided that showed a conductivity of <0.3 gus/cm; however, they told us that it was usually kept lower. Tube leaks are checked by acoustic monitoring and measurement of deposition in selected tube samples taken during the annual outage. They have not yet had to do an acid wash. The superheater and reheater temperatures are monitored. They can control by water spray or superheater bypass; however, they have not had overly high-temperatures. The design is typical of the standard Russian 500-MW designs with vertical waterwalls and two parallel superheater/reheater passes on either side of the main boiler. The HP and IP turbine casings were cast from a custom steel 15CrlMolV. There have been no forced outages due to steam turbine failure. There had been a problem with cracking of the casting, so a round groove was cut along the crack to eliminate any high-stress points. The retaining rings in the generator are 1 8Crl lMoNiV. There have been no failures. Additional forced outages have been caused by lack of operator familiarity with supercritical unit operations. Operators were sent to Russia for training, and they do have a simulator on site and have obtained additional training from other domestic subcritical power plants. 186 Technology Assessment of Clean Coal Technologies for China The Russian supercritical units are supplied in three standard sizes-300 MW, 500 MW, and 800 MW. Apparently Russia has supplied additional units to China including 2 x 500 MW units in Yimin (started up 1998), 2 x 800 MW units at Suizhong (planned startup 1999), and 2 x 300 MW units at three additional sites (all six of which are believed to be in operation). C.3 Steam Turbine Supplier Capabilities in China In lieu of visiting the steam turbine divisions of the three major power plant suppliers-i.e., the sister divisions to the boilers works discussed above-the study team sent the following questions to these three turbine suppliers. Their responses are summarized (in alphabetical order) below each question. The suppliers are Dongfang Steam Turbine Works (DFSTW), Harbin Turbine Co. (HTC), and Shanghai Turbine Co. (STC). 1. Have you supplied components of supercritical (SC) steam turbines or entire SC turbines? If so, how many, what size (MWe), and for what operating pressures and temperatures? What pressure and temperature capabilities and what steam turbine sizes are you now prepared to offer on a commercial basis? DFSTW is currently developing SC steam turbines, and will manufacture a 600-MW turbine on a trial basis for 24.22 MPa/538°C/566°C. Although they have no experience supplying turbines for these conditions, they do have the capability to supply components for them. HTC has subcontracted to produce parts for SC turbines, but has not yet supplied a complete SC turbine. They have completed designs for such turbines, possess the facilities to manufacture them, and are prepared to offer them commercially (600 MW, up to 24.2 MPa/566°C/566°C). STC manufactured 21 components of the steam turbines for the 600-MW Shidongkou SC plant, under subcontract to ABB, in 1989-1990. This included the LP cylinder, pedestal, lube oil system, gland system, drain system, oil tank, IP/LP cross-over pipe, wedge and foundation bolts, etc. 2. Are the SC steam turbines that you have supplied or are offering for sale based on your own designs or produced under a license from another company? If a license, from which company or companies? Do you plan to continue this arrangement, or are you developing your own designs for SC turbines? DFSTW plans to co-design and co-manufacture SC steam turbines with a major international firm. However, they plan to increase the amount manufactured locally with time through a combination of importing technology and developing products locally after they have mastered the imported technology. HTC plans to sell turbines designed in-house but is also discussing cooperation and other arrangements with international firms. STC is a joint venture of Shanghai Turbine Works and Siemens-Westinghouse, in which Siemens-Westinghouse will provide STC a complete set of design documentation and Supercritical Boilers and Suppliers In China-Report on Site Visits 187 drawings for manufacturing turbines covering the range of 120 MW to 1300 MW. This includes units for fossil and nuclear plants, as well as subcritical and supercritical designs. The main technical parameters of the 600-MW 24.2 MPa/538°C/566°C supercritical steam turbines are as follows: * Type: tandem, reheat, condensing steam turbine * Steam flow at maximum output: 1824 tAh * Feedwater temperature: 286.1 °C * Length of last-stage blade: 980 mm * Regenerative system: 3HP heaters + 1 deaerator + 4 LP heaters * Speed: 3000 r/min * Heat rate: 7556 kJ/kWh (1805 kcal/kWh) Under this joint venture, Westinghouse will guarantee unit heat performance and reliability, provide key components, and be responsible for QA/QC in the entire manufacturing process. STC will sign the contract with the client and be responsible for the joint venture's products. STC also has a complete set of design documentation, drawings for manufacture, and process information of Mitsubishi's NANKO-type supercritical 600-MW unit. 3 WVhat materials do you (or would you) use for the blades, rotors, steam casings (inner and outer), and valve chests for the high pressure (HP), intermediate pressure (IP), and low pressure (LP) sections? Where will you purchase these materials? DFSTW was not prepared to provide this information given the current stage of development of their design. HTC's HP/lIP rotors are made of 12% Cr stainless steel or Cr-Mo-V steel forging. They adjust the alloy content, in collaboration with China No. 1 Heavy Machinery Group based on the latest information from international firns. For the LP rotor, they use 3OCr2Ni4MoV steel. The casing and main stop valve chest are made of Cr-Mo-V or 12% Cr stainless steel forging, again with the alloy content adjusted based on international experience. They use lCrl2Mo, 2Crl2NiMolVWV, and OCrl7Ni4Cu4Nb for both sub- and supercritical blades. STC provided the following table in response to this question. Component Material Supplier Blade HP, IP, LP Cr-Ni-Mo-W-V steel Ben Xi Steel Works in China Cr-Mo steel 174PH Rotor HP, IP Cr-Mo-V steel Japan LP Cr-Mo-Ni steel China: No. 1 Heavy Works, FuLaErJi Cylinder outer cylinder Cr-Mo steel STC inner cylinder Cr-Mo-V steel Valve Cr-Mo steel STC Cr-Mo-V steel 188 Technology Assessment of Clean Coal Technologies for China 4. How do you design your turbine blades? i e., what design guides and computer models do you use? HTC designs their blades on the basis of: Aerodynamic design - 3D design technology including high-efficiency blade profile - Meridian converging, bending, and torsional full-3D adjustable cascade - Full-3D flow pattern design Structural strength and vibration characteristics - Full-annulus integral shroud blading - Smooth meridian plane flow path Computer models include: full-3D stream field (viscous and non-viscous), blade strength, single blade and full-annulus blade vibration frequency calculations STC uses Westinghouse's design criteria and "standard calculation programs." Machining of their blades is also under Westinghouse QA/QC. 5. What is the blade length and efficiency of your last stage? What is the heat rate of your SC turbine design? For HTC, the last stage is 1000 mm long, the blade is of full-3D design, the vane is bent and twisted, and the blade profile is designed for ultrasonic flow. This gives it a high efficiency and better performance over a range of loads. The integral blades are connected with loose lacing to achieve better strength and vibration behavior, small dynamic stress, and greater margins of safety. They consider this design to be state- of-the-art and have demonstrated its performance on 600-MW subcritical units. The heat rate of their turbines is 7600 kJ/kWh (1816 kcal/kWh). STC uses a Westinghouse-designed 980-mm-long blade for the last stage. With this blade, the heat rate is 7556 kJ/kWh (1805 kcal/kWh). 6. Do you use welded or mono-block rotors in turbines for SC power plants? Where do you obtain the rotors? If you procure them outside China, do they come machined or do you machine them in your facility? (Note: if you have not yet supplied SC turbines, please answer by saying where you would procure and machine these rotors.) DFSTW would consider both domestic and imported materials; at least, they expect to have high-temperature materials available within a few years. However, price would dictate where the components are obtained. They would use solid forgings for rotors. HTC uses an integral rotor for SC units. The stock is procured locally and machined by HTC. Supercritical Boilers and Suppliers In China-Report on Site Visits 189 STC uses mono-block rotors for all three sections (HP, IP, LP), and obtains them either domestically or from abroad in a rough machined condition. STC does the finish machining in-house. 7. What QA/QC procedures (including non-destructive evaluation [NDE] techniques) do you: (a) require of your suppliers? (b) use when you accept purchased materials; and (c) use on components you machine and/or weld in-house? How do you inspect rotors, blades, and casings? DFSTW plans to use the same QA/QC procedures as the international steam turbine suppliers. HTC's QA/QC system complies with the requirements of GB/T19001-1994 and ISO 9001, having attained their certificate of registration in 1994. They place the same QA/QC requirements on their subcontractors. Specifically, they: - Verify their subcontractors by ISO 9002 (generally) and ISO 9001 (partially) - Test all materials according to accepted standards (usually stipulated in the contract) - Follow B/GL06-08.1 In-process Quality Control Procedures for most machining and welding operations - Check rotor, blading, and casing according to the applicable guides, such as 73A or 75A Product Test Guides for 300-MW and 600-MW units, respectively. STC uses the non-destructive tests identified below: Component (a) Test Content Rotor HP, IP, LP Chemical Composition and Physical Properties Test UT, Hydraulic Test (post machine) Magnetic Inspection Sulfur Test Fracture Appearance Transition Temperature Test Remnant Stress Detection Residual Magnetic Test Blade Material Test Magnetic Inspection Shroud Welding, Position Inspection Cylinder Material Test Magnetic Inspection X-ray Inspection Crack Inspection 8. How large a flow can your steam bypass system handle (please answer as a percent of full-load steam flow)? 190 Technology Assessment of Clean Coal Technologies for China DFSTW's bypass capacities in subcritical units supplied to date range from 30% to 50%, depending on the turbine design. HTC provides systems with the bypass quantities requested by the customer. Their condensors can hold 30-100% of the bypass flow. STC follows the guidelines of the Power Plant Design Institute in determining steam turbine bypass flow. 9. Do you supply digital control systems for your turbines or require your customers to use digital controls to meet performance guarantees? All three suppliers provide digital controls with their steam turbines. 10. Do you know if "superclean" LP rotors have been used in China? If so, how many, were they manufactured in China, and how many operating hours have they accumulated? DFSTW is in the early stages of using superclean LP rotors. To date, they have supplied 10 of these rotors, all imported. HTC has been using superclean LP rotors for 5 years. STC would import this type of rotor if the client requested it. Table C.1: Questions to Boiler Suppliers on Materials for Supercritical Boilers 1. What percent (cost basis) of the raw material (steel) for pressure-bearing parts is imported now for subcritical boilers (165 bar/541°C/541°C) and would be imported for supercritical boilers (250 bar/541°C/569°C)? 2. What are the highest temperature and pressure alloys that are available from domestic suppliers today? E.g., P22/T22; P91/T91; alloys with higher chrome and/or molybdenum contents (possibly with other metals added)? You may provide separate answers for boilers designed to meet national standards versus international standards. 3. For alloys that are available from domestic suppliers, what is the cost difference between imported and domestic sources, as delivered to the boiler works (materials plus all the added charges)? 4. What percent of the total plant cost (as shipped from the boiler works) for a supercritical boiler would be imported equipment? Please identify the major manufactured components that would be imported. 5. What would be the percent difference in installed cost in China between a supercritical and subcritical boiler today? Please indicate if your answer is based on actual experience, a detailed economic study, or an estimate. Supercritical Boilers and Suppliers In China-Report on Site Visits 191 Table C.2: Responses by Chinese Boiler Manufacturers to Questions on Materials for Supercritical Boilers Question Shanghai (SBWL) Dongfang (DBC) Harbin (HBC) 1. % (cost-basis) Provided detailed list of Sub-critical - about 20% Sub-critical: TP347H, pressure part steel materials for sub-critical . - d TP304H, P12, P22, imported for unit designed/fabricated Super-critical - assumed SA 106B. Cost of imported sub/super-critical in China. Would import raw material about 30% of boilers for: steam drum, pipe > all material need be per total material cost. Estimate 219 mm; also for m , Wi e 0 higher for SC units waterwall rifle tube, MT imported and HT (580 or 600°C) SH/RH, if customer requires 2. Highest T alloys GB: 15CrMo (540°C), l2CrlMoV tube/pipe for GB: 20G, 15CrMo, l2CrlMoV available from l2CrlMoV (580°C), T <580'C (S565°C for Int'l std: SA210A1, Tl I, T12 domestic suppliers? R102 (600°C), T91, headers and main steam TP347H pipe). Small pipe either domestic or imported; ASME: T12, T22, T91, large pipes mainly TP347 imported but could be 12Crl MoV and Rl 02 produced in China. better hi T strength than 12Cr2MoWVTiB for T22 T < 6000C T91/P91, TP304H, TP347H mostly imported; trial production in China now 3. Differential cost Hard to compare because No significant difference Cost difference between (delivered to boiler codes different => use in price SA210AI and 20G works) between materials of different 7000 yuan/t imported and strength, hence different domestic supply for thinness. high alloy steels available in China 4. % total plant cost No cost given. Imported Imported equipment Cost of imported equipment (as shipped) for SC equipment: 20% total plant cost for for SC unit approx. 34% unit and major items Sub-critical - safety SC boiler. Circulating total plant cost. Imported that would be valve, control valve, pump, LNB, safety equipment is control system, imported DCS, circulating pump, valves, control valves, some valves, start-up equipment? valves in fuel oil system other high pressure valves circulating pump, etc. Super-critical - above w.o. circulating pump 5. % A installed Erection costs could be 5- % difference in installed cost in China 10% higher for SC due to costs between SC and sub- between SC and increase in field welding critical z 3%. sub-critical joints and other difficulties 192 Technology Assessment of Clean Coal Technologies for China Bakker, W.T., Materials for Advanced Boilers," Proc. Advanced Heat Resistant Steels for Power Generation, April 27-29, 1998, San Sebastian, Spain, pp. 435-444 (also EPRI Report #TR-1 11571). EPRI, Production and Properties of a Superclean 2.5%oNi-CrMo V HP/LP Rotor Shaft, TR- 103689, February 1994. EPRI, New Materials for Advanced Steam Turbines, Volume 3: Evaluation of Superclean Rotor Forgings for Advanced Design Power Plants, TR- 1 00979-V3 September 1994. EPRI, Circumferential Cracking on the Waterwalls of Supercritical Boilers: Volumes 1 and 2, TR-104442, September 1995. EPRI, Cycle Chemistry Guidelines for Fossil Plants: Oxygenated Treatment, TR-102285, December 1994. n Oliker, I., Armor, A. F., Supercritical Power Plants in the USSR, EPRI Report TR-100364, February 1992. EPRI, Assessment of Supercritical Power Plant Performance, Report CS-4968, December 1986. EPRI, Assessment of Supercritical Power Plant Performance, Report CS-4968, December 1986. EPRI, Development of Improved Boiler Startup Valves, Report GS-6280, April 1989. EPRI, Solid Particle Erosion Technology Assessment, Report TR-103552, December 1993. xi EPRI, Circumferential Cracking on the Waterwalls of Supercritical Boilers, Report TR- 104442, Septemnber 1995. xii Armor, A. F. and Holterstine, R. D., "Cycling Capability of Supercritical Turbines: A Worldwide Assessment," Joint Power Generation Conference, Milwaukee, WI, October 20-24, 1985, ASME Paper 85- JPGC-PWR-6. 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