DOCSLIB.ORG

WRI/WBCSD GHG Protocol Stationary Combustion Guidance

Total Page：16

File Type：pdf, Size：1020Kb

Download full-text PDF Read full-text
WRI/WBCSD GHG Protocol Stationary Combustion Guidance CALCULATION TOOL FOR DIRECT EMISSIONS FROM STATIONARY COMBUSTION Version 3.0 July 2005 A WRI/ WBCSD Tool Prepared by Michael Gillenwater Environmental Resources Trust With special contributions from Mike Woodfield (AEA Technology), Tim Simmons (Avonlog Ltd), Mike McCormick (California Climate Registry), Vince Camobreco (EPA Climate Leaders), Leif Hockstad (EPA Climate Division), Kyle Davis (MidAmerican Energy), Brian Jones (MJ Bradley), Kelly Levin (NESCAUM), Chris Nelson (State of Connecticut), Jochen Harnisch (Ecofys), Simon Schmitz (WBCSD), Brad Upton (NCASI). Questions or comments on this material can be directed to: Florence Daviet 10 G Street NE Suite 800 Washington DC, 20777 Phone: 202-729-7822 Fax: 202- 729-7610 e-mail: [email protected] WRI/WBCSD GHG Protocol Michael Gillenwater Stationary Combustion Guidance Page 1 of 94 GHG PROTOCOL GUIDANCE DIRECT EMISSIONS FROM STATIONARY COMBUSTION1 1 INTRODUCTION..............................................................................................................................................4 1.1 ORGANIZATIONAL AND OPERATIONAL BOUNDARIES ...................................................................................7 1.2 COMBUSTION PROCESSES ............................................................................................................................8 1.3 SPECIAL EMISSIONS ACCOUNTING ISSUES..................................................................................................10 1.3.1 Biomass................................................................................................................................................10 1.3.2 Waste fuels...........................................................................................................................................12 1.3.3 Transferred CO2 ..................................................................................................................................12 1.3.4 CO2 capture and storage .....................................................................................................................13 1.3.5 Non-combustion processes ..................................................................................................................13 2 DIRECT CO2 EMISSIONS FROM FUEL COMBUSTION .......................................................................13 2.1 COMPARING METHODOLOGIES ..................................................................................................................13 2.2 CALCULATION METHOD AND DATA COLLECTION ......................................................................................15 2.2.1 Fuel consumption (Activity data).........................................................................................................18 2.2.2 Fuel sampling and analysis (Factors) .................................................................................................20 2.2.3 Oxidation factors .................................................................................................................................27 2.3 DIRECT MEASUREMENT ISSUES..................................................................................................................29 2.3.1 Flow rate..............................................................................................................................................33 2.3.2 Gas concentration................................................................................................................................34 3 DIRECT CH4 AND N2O EMISSIONS FROM FUEL COMBUSTION......................................................35 4 DIRECT CO2 EMISSIONS FROM OTHER PROCESSES ASSOCIATED WITH STATIONARY COMBUSTION FACILITIES .................................................................................................................................37 4.1 SORBENT EMISSIONS .................................................................................................................................38 4.2 EMISSIONS FROM REDUCING AGENTS AND FUEL CELLS .............................................................................39 5 PROJECT LEVEL REDUCTIONS...............................................................................................................39 6 QUALITY MANAGEMENT AND UNCERTAINTY..................................................................................40 7 DOCUMENTATION AND ARCHIVING.....................................................................................................41 8 REFERENCES.................................................................................................................................................42 9 ACKNOWLEDGMENTS ...............................................................................................................................44 10 REVISION HISTORY ....................................................................................................................................44 11 ANNEX A: BACKGROUND ON CARBON CONTENT FACTORS .......................................................45 11.1 INTERGOVERNMENTAL PANEL ON CLIMATE CHANGE (IPCC)...................................................................45 11.2 U.S. ENVIRONMENTAL PROTECTION AGENCY ..........................................................................................45 11.2.1 Variability and uncertainty in U.S. coal carbon content factors.....................................................46 11.2.2 Variability and uncertainty in U.S natural gas carbon content factors ..........................................47 11.2.3 Variability and uncertainty in U.S. petroleum product carbon content factors..............................48 11.3 EUROPEAN UNION EMISSION TRADING SCHEME .......................................................................................50 11.4 ESTIMATING CARBON CONTENT FROM API GRAVITY AND SULFUR CONTENT DATA...................................51 12 ANNEX B: BACKGROUND ON CALORIFIC/HEATING VALUES......................................................53 11 This document also addresses emissions from select non-combustion process related to the production of energy (i.e., use of sorbents in emissions control, geothermal energy production, use of fossil fuels as reducing agents, and fossil fuel reforming for fuel cells). WRI/WBCSD GHG Protocol Michael Gillenwater Stationary Combustion Guidance Page 2 of 94 13 ANNEX C: U.S. ACID RAIN PROGRAM (40 CRF PART 75) DEFAULT FACTORS .........................55 14 ANNEX D: RELEVANT TECHNICAL STANDARDS..............................................................................57 14.1 AMERICAN SOCIETY OF TESTING AND MATERIALS (ASTM).....................................................................57 14.2 U.S. ENVIRONMENTAL PROTECTION AGENCY (EPA)................................................................................58 14.3 AMERICAN SOCIETY OF MECHANICAL ENGINEERS (ASME).....................................................................59 14.4 AMERICAN NATIONAL STANDARDS INSTITUTE (ANSI) ............................................................................59 14.5 GAS PROCESSORS ASSOCIATION (GPA)....................................................................................................59 14.6 AMERICAN GAS ASSOCIATION (AGA) ......................................................................................................60 14.7 AMERICAN PETROLEUM INSTITUTE (API).................................................................................................60 14.8 INTERNATIONAL STANDARDS ORGANIZATION (ISO) ................................................................................60 14.9 GERMAN INSTITUTE FOR STANDARDIZATION (DIN) .................................................................................64 14.10 COMMITTEE ON EUROPEAN NORMALIZATION (CEN)................................................................................65 15 ANNEX E: UNIT CONVERSIONS ..............................................................................................................66 16 GLOSSARY......................................................................................................................................................67 WRI/WBCSD GHG Protocol Michael Gillenwater Stationary Combustion Guidance Page 3 of 94 1 Introduction The objective of this document is to provide guidance on the estimation of direct (i.e., see box below on Scope 1) greenhouse gas emissions from stationary combustion processes that is in keeping with the principles of the GHG Protocol. Specific guidance is provided on the selection and implementation of emission estimation methodologies, data collection, documentation, and quality management. Methodological and data collection options are described so that different users of this tool may match the rigor and detail of their emission inventory to their needs or goals. This guidance, along with its companion Excel worksheet tool, may be used by companies for internal or public reporting needs, or to participate in a GHG program. Likewise GHG programs, including voluntary or mandatory programs and emission trading schemes, may also customize this tool for their program’s needs.2 GHG Protocol Scope 1: Direct greenhouse gas emissions Direct greenhouse gas emissions occur from sources that are owned or controlled by the company, for example, emissions from combustion in owned or controlled boilers, furnaces, vehicles, etc.; emissions from chemical production in owned or
Load more

Recommended publications
  • Exco55 P1 a Global Operational Status of Co-Firing Biomass And
    Global operational status on cofiring biomass and waste with coal Experience with different cofiring concepts and fuels Jaap Koppejan1, Larry Baxter2, 1 Project manager Bioenergy systems, TNO-MEP, PO Box 342, 7300 AH Apeldoorn, Netherlands, phone +31 55 5493167, fax +31 55 5493287, email [email protected] 2 Professor Chemical Engineering, Brigham Young University, Provo, UT 84601, USA, phone: +1 (801) 422-8616, fax: +1 (801) 422-0151, email [email protected] 1. Primary motivations for biomass-coal cofiring One means of reducing the environmental impacts of fossil fuel combustion is to increase the fraction of renewable and sustainable energy in the national energy supply. Renewable energy technologies have, however, struggled to compete in open electricity supply markets with fossil energy, due to their low efficiencies, high costs, and the high technical and financial risks. The result is that they usually require the introduction of subsidies or other financial instruments to support their implementation. The co-firing of biomass with the coal in traditional coal-fired boilers makes use of the large investment and extensive infrastructure associated with the existing fossil-fuel-based power systems, while requiring only a relatively modest capital investment, typically up to $50-$300 per kW of biomass capacity. [i]. These costs compare very favorably with any other available renewable energy option1. Worldwide, each percent of coal that is substituted with biomass in all coal fired power plants results in a biomass capacity of 8 GWe, and a reduction of approx. 60 Mton of CO2. At a typical cofiring ratio of 5% on energy basis, this would correspond with a global potential of approx.
    [Show full text]
  • Biomass Cofiring in Coal-Fired Boilers
    DOE/EE-0288 Leading by example, saving energy and Biomass Cofiring in Coal-Fired Boilers taxpayer dollars Using this time-tested fuel-switching technique in existing federal boilers in federal facilities helps to reduce operating costs, increase the use of renewable energy, and enhance our energy security Executive Summary To help the nation use more domestic fuels and renewable energy technologies—and increase our energy security—the Federal Energy Management Program (FEMP) in the U.S. Department of Energy, Office of Energy Efficiency and Renewable Energy, assists government agencies in developing biomass energy projects. As part of that assistance, FEMP has prepared this Federal Technology Alert on biomass cofiring technologies. This publication was prepared to help federal energy and facility managers make informed decisions about using biomass cofiring in existing coal-fired boilers at their facilities. The term “biomass” refers to materials derived from plant matter such as trees, grasses, and agricultural crops. These materials, grown using energy from sunlight, can be renewable energy sources for fueling many of today’s energy needs. The most common types of biomass that are available at potentially attractive prices for energy use at federal facilities are waste wood and wastepaper. The boiler plant at the Department of Energy’s One of the most attractive and easily implemented biomass energy technologies is cofiring Savannah River Site co- fires coal and biomass. with coal in existing coal-fired boilers. In biomass cofiring, biomass can substitute for up to 20% of the coal used in the boiler. The biomass and coal are combusted simultaneously. When it is used as a supplemental fuel in an existing coal boiler, biomass can provide the following benefits: lower fuel costs, avoidance of landfills and their associated costs, and reductions in sulfur oxide, nitrogen oxide, and greenhouse-gas emissions.
    [Show full text]
  • Experience of Indirect Cofiring of Biomass and Coal
    Experience of indirect cofiring of biomass and coal Rohan Fernando CCC/64 October 2002 Copyright © IEA Clean Coal Centre ISBN 92-9029-370-9 Abstract There has been increasing interest in the use of biomass for power generation in recent years. The principal reason for this is that the use of biomass can significantly reduce net CO2 emissions. Other advantages of utilising biomass are that it diversifies the power plant’s fuel portfolio, it can lead to reductions in SO2 and NOx emissions and that such use can help to dispose of a solid waste. There are some disadvantages of firing biomass which relate to its supply, transportation and composition and these can be reduced if the biomass is cofired with coal. Cofiring can be direct, where the biomass and coal are fired in the same boiler, or indirect, where the combustion or gasification of biomass occurs in a separate unit. This report concentrates on indirect cofiring which is taken to mean technologies in which the ash from the coal and biomass are kept separate. Direct cofiring is relatively straightforward but can lead to several technical concerns. Indirect cofiring incurs greater costs and is particularly suitable for biomass containing troublesome components or when the quality of the ash is of importance. Indirect cofiring is less common than direct cofiring. The report discusses the relative advantages and disadvantages of direct and indirect cofiring. It then describes the following plants which indirectly cofire biomass: Aabenraa in Denmark, Amergas in the Netherlands, Avedøre 2 in Denmark, Kymijärvi in Finland, Zeltweg in Austria and Västerås in Sweden.
    [Show full text]
  • MPC for Upstream Oil & Gas Fields a Practical View
    MPC for Upstream Oil & Gas Fields a practical view Yahya Al-Naumani A thesis submitted in partial fulfillment of the requirements for the degree of Doctor of Philosophy University of Sheffield July 2017 Dedicated to my Parents and Family i ABSTRACT This work aims to improve corporate functional departments’ confidence in adopt- ing modern control approaches in new scenarios and thus presents control structure solutions based on model predictive control (MPC) for two control problems facing ex- isting upstream oil and gas production plants. These are the disturbance growth in the series connected process and the control system dependency on operators. The suggested control solution integrates MPC as a master controller for the existing clas- sical control of each subsystem, with a focus on those with high interaction phenom- ena. The proposed approach simply and inexpensively encompass MPC features such as predictions, optimizations, coordination and constraint handling as well as PID features like simplicity and ease of troubleshoot. In addition, the proposed control concept utilises the process safeguarding information and enhances the plant-wide op- timal performance. The suggested control solution supports the role of control room operators, which is shown to reduce the growth in the impact of process disturbances. Compared with some alternative control structures (centralised MPC, decentralised MPC, distributed MPC (DMPC), and hierarchical DMPC) this proposal is simple, in- expensive to implement, and critically, builds on the local team operational experience and maintenance skills. Three process models were developed that representing the common gas treatment processes in upstream oil and gas plants, gas sweetening, gas dehydration and hydro- carbon dewopointing.
    [Show full text]
  • Investigation of Waste Biogas Flame Stability Under Oxygen Or Hydrogen-Enriched Conditions
    energies Article Investigation of Waste Biogas Flame Stability Under Oxygen or Hydrogen-Enriched Conditions Nerijus Striugas,¯ Rolandas Paulauskas *, Raminta Skvorˇcinskiene˙ and Aurimas Lisauskas Laboratory of Combustion Processes, Lithuanian Energy Institute, Breslaujos str. 3, LT-44403 Kaunas, Lithuania; [email protected] (N.S.); [email protected] (R.S.); [email protected] (A.L.) * Correspondence: [email protected]; Tel.: +370-37-401830 Received: 18 August 2020; Accepted: 9 September 2020; Published: 11 September 2020 Abstract: Increasing production rates of the biomethane lead to increased generation of waste biogases. These gases should be utilized on-site to avoid pollutant emissions to the atmosphere. This study presents a flexible swirl burner (~100 kW) with an adiabatic chamber capable of burning unstable composition waste biogases. The main combustion parameters and chemiluminescence emission spectrums were examined by burning waste biogases containing from 5 to 30 vol% of CH4 in CO2 under air, O2-enriched atmosphere, or with the addition of hydrogen. The tested burner ensured stable combustion of waste biogases with CH4 content not less than 20 vol%. The addition of up to 5 vol% of H2 expanded flammability limits, and stable combustion of the mixtures with CH4 content of 15 vol% was achieved. The burner flexibility to work under O2-enriched air conditions showed more promising results, and the flammability limit was expanded up to 5 vol% of CH4 in CO2. However, the combustion under O2-enriched conditions led to increased NOx emissions (up to 1100 ppm). Besides, based on chemiluminescence emission spectrums, a linear correlation between the spectral intensity ratio of OH* and CH* (IOH*/ICH*) and CH4 content in CO2 was presented, which predicts blow-off limits burning waste biogases under different H2 or O2 enrichments.
    [Show full text]
  • JODI Oil Manual Is Another Important Milestone on the Road to More Transparent Energy Markets Through Improved Data
    1 ASIA PACIFIC ECONOMIC COOPERATION (APEC) APEC is an intergovernmental grouping operating on the basis of non-binding commitments, open dialogue and equal respect for the views of all participants. It was established in 1989 to further enhance economic growth and prosperity for the region and to strengthen the Asia-Paci�ic community. APEC’s 21 Member Economies are Australia; Brunei Darussalam; Canada; Chile; People’s Republic of China; Hong Kong, China; Indonesia; Japan; Republic of Korea; Malaysia; Mexico; New Zealand; Papua New Guinea; Peru; The Republic of the Philippines; The Russian Federation; Singapore; Chinese Taipei; Thailand; The United States of America; and Viet Nam. Since its inception, APEC has worked to reduce tariff s and other trade barriers across the Asia-Paci�ic region, creating ef�icient domestic economies and dramatically increasing exports. Key to achieving APEC’s vision are what are referred to as the ’Bogor Goals’ of free and open trade and investment in the Asia-Paci�ic by 2010 for industrialised economies and 2020 for developing economies. These goals were adopted by Leaders at their 1994 meeting in Bogor, Indonesia. APEC’s energy issues are the responsibilities of the Energy Working Group (EWG), one of its 11 working groups. The development and maintenance of the APEC Energy Database is assigned to EWG’s Expert Group on Energy Data and Analysis (EGEDA) who has appointed the Energy Data and Modelling Centre (EDMC) of the Institute of Energy Economics, Japan (IEEJ) as the Coordinating Agency. One of the objectives of EGEDA is to collect monthly oil data of the APEC economies in support of the Joint Asia Paci�ic Economic Cooperation (APEC) Organisations Data Initiative.
    [Show full text]
  • Table of Contents Biomass Gasification, Pyrolysis And
    Biomass Gasification, Pyrolysis and Torrefaction Practical Design and Theory, 2nd Edition Table of Contents Dedication Preface Acknowledgments About the Author Chapter 1. Introduction 1.1 Biomass and its Products 1.2 Biomass Conversion 1.3 Motivation for Biomass Conversion 1.4 Historical Background 1.5 Commercial Attraction of Gasification 1.6 Brief Description of Some Biomass Conversion Processes Symbols and Nomenclature Chapter 2. Economic Issues of Biomass Energy Conversion 2.1 Introduction 2.2 Biomass Availability and Products 2.3 Biomass Conversion Process Plant Equipment and Cost 2.4 Financial Analysis Symbols and Nomenclature Chapter 3. Biomass Characteristics 3.1 Introduction 3.2 What is Biomass? 3.3 Structure of Biomass 3.4 General Classification of Fuels 3.5 Properties of Biomass 3.6 Composition of Biomass Symbols and Nomenclature Chapter 4. Torrefaction 4.1 Introduction 4.2 What is Torrefaction? 4.3 Carbonization 4.4 Torrefaction Process 4.5 Degree of Torrefaction 4.6 Physical Properties of Torrefied Biomass 4.7 Torrefaction Technologies 4.8 Design Methods Appendix Mass and Energy Balance of Torrefier Mass Balance Energy Balance Chapter 5. Pyrolysis 5.1 Introduction 5.2 Pyrolysis 5.3 Pyrolysis Product Yield 5.4 Pyrolysis Kinetics 5.5 Heat Transfer in a Pyrolyzer 5.6 Pyrolyzer Types 5.7 Pyrolyzer Design Considerations 5.8 Biochar Symbols and Nomenclature Chapter 6. Tar Production and Destruction 6.1 Introduction 6.2 Tar 6.3 Tar Reduction Chapter 7. Gasification Theory 7.1 Introduction 7.2 Gasification Reactions and Steps 7.3 The Gasification Process 7.4 Kinetics of Gasification 7.5 Gasification Models 7.6 Kinetic Model Applications Symbols and Nomenclature Chapter 8.
    [Show full text]
  • Cofiring Biomass and Coal for Fossil Fuel Reduction and Other Benefits–Status of North American Facilities in 2010
    United States Department of Agriculture Cofiring Biomass and Coal Forest Service for Fossil Fuel Reduction and Pacific Northwest Other Benefits—Status of North Research Station American Facilities in 2010 General Technical Report PNW-GTR-867 David Nicholls and John Zerbe August 2012 D E E P R A U R T LT MENT OF AGRICU The Forest Service of the U.S. Department of Agriculture is dedicated to the principle of multiple use management of the Nation’s forest resources for sustained yields of wood, water, forage, wildlife, and recreation. Through forestry research, cooperation with the States and private forest owners, and management of the National Forests and National Grasslands, it strives—as directed by Congress—to provide increasingly greater service to a growing Nation. The U.S. Department of Agriculture (USDA) prohibits discrimination in all its programs and activities on the basis of race, color, national origin, age, disability, and where applicable, sex, marital status, familial status, parental status, religion, sexual orientation, genetic information, political beliefs, reprisal, or because all or part of an individual’s income is derived from any public assistance program. (Not all prohibited bases apply to all programs.) Persons with disabilities who require alternative means for communication of program information (Braille, large print, audiotape, etc.) should contact USDA’s TARGET Center at (202) 720–2600 (voice and TDD). To file a complaint of discrimination, write USDA, Director, Office of Civil Rights, 1400 Independence Avenue, SW, Washington, DC 20250–9410 or call (800) 795–3272 (voice) or (202) 720–6382 (TDD). USDA is an equal opportunity provider and employer.
    [Show full text]
  • Analysis of Combustion Products from the Cofiring of Coal with Biomass Fuels
    ANALYSIS OF COMBUSTION PRODUCTS FROM THE COFIRING OF COAL WITH BIOMASS FUELS Deirdre A. Belle-Oudry and David C. Dayton National Renewable Energy Laboratory 16 I7 Cole Boulevard Golden, CO 80401-3393 INTRODUCTION The threat of increased global warming has subjected fossil fuels to increasing scrutiny in terms of greenhouse gas and pollutant emissions. As a result, using renewable and sustainable energy resources, such as biomass, for electricity production has become increasingly attractive. The use of dedicated biomass feedstocks for electricity generation could help reduce the accumulation of greenhouse gases because carbon dioxide is consumed during plant growth. The agricultural and wood products industries generate large quantities of biomass residues that could also provide fuel for electricity production. Increasing the use of these waste biomass fuels could alleviate the burdens of waste disposal in the agricultural and wood products industries. Coal-fired power plants produce the most electricity in the United States. If biomass were cofired at low percentages in a small number of coal-fired power plants, the use of biomass for power production could dramatically increase. Cofiring biomass and coal increases the use of sustainable fuels without large capital investments, and takes advantage of the high efficiencies obtainable in coal-fired power plants. Fuel diversity is another advantage of biomass/coal cofiring. Cofuing reduces the need for a constant supply of biomass required as in a biomass power plant, and is a viable way to decrease the emissions of greenhouse gases and other pollutants from power-generating facilities. Biomass and coal have fundamentally different fuel properties. Biomass is more volatile than coal and has a higher oxygen content.
    [Show full text]
  • Prima PRO Process Mass Spectrometer No
    APPLICATION NOTE Prima PRO process mass spectrometer No. ?????? Accurate multi-component blast furnace gas analysis maximizes iron production and minimizes coke consumption Author: Graham Lewis, Thermo Fisher Scientific, Winsford, Cheshire, United Kingdom Key words • Top gas analysis • Below burden probe • Gas efficiency • Coke rate • Mass balance • Calorific value • Heat balance • Magnetic sector • Above burden probe Introduction Over a billion tonnes of iron a year are produced in These reduction zones are shown in Figure 1. blast furnaces, representing around 94% of global iron production1. The blast furnace consists of a large steel stack, lined with refractory brick. Iron ore, coke and limestone are dropped into the top of the furnace and preheated air blown into the bottom through nozzles called ‘Tuyeres’. Iron oxides are reduced in the melting zone, or ‘Bosh’, forming liquid iron (called ‘hot metal’) and liquid slag. These liquid products are drained from the furnace at regular intervals, and the blast furnace will run continuously for several years, until the refractory lining needs replacing. A wide variety of chemical reactions take place in the blast furnace. At the elevated temperatures towards the bottom Figure 1 of the furnace, a series of direct reduction reactions take Reduction place; these can be simplified to: profile in the blast furnace FeO + C = Fe + CO At lower temperatures higher up in the furnace, a series of indirect reduction reactions take place, simplified to: FeO + CO = Fe + CO2 Analysis of carbon monoxide (CO) and carbon dioxide Process control requirements (CO2) give vital information on the efficiency of the reduction The advantages of process MS over conventional analysis processes.
    [Show full text]
  • Gasification Based Biomass Cofiring Project Integration of Poultry Litter Gasification with Conventional PC Fired Power Plant
    National Energy Technology Laboratory Co-op Agreement No. DE-PS26-00NT 40898 Gasification Based Biomass Cofiring Project Integration of poultry litter gasification with conventional PC fired power plant B. Patel – Nexant, Inc.; Kevin McQuigg – Primenergy LLC; R. Tourney – WKE Inc. NETL Project Manager Dr. Phil Goldberg Participants US DOE NETL – program coordinator Nexant – overall engineering and cost estimate Primenergy – biomass gasification technology Western Kentucky Energy Corp – feasibility study site - Reid plant Project Concept Cofire an existing pulverized coal fired boiler with low-Btu gas produced from poultry litter gasification Within 100 km of plant ~120,000 t/y of poultry liter available Energy production alternative to land application Project Concept (contd.) Biomass Fuel Boiler Fuel Management (coal/oil/ Receive, Screen N.Gas) Storage, Reclaim Steam to turbine Fuel Conveyor Biomass Flue gas Gasifier Existing Utility Boiler Stack Producer Gas Gasifier Ash - Potential P/K Fertilizer Boiler Ash - Disposal Project Issues Optimize gasifier size that can be integrated with existing boiler Verify performance and operating parameters of gasifier on poultry litter Minimize impact on existing boiler operation No additional emissions from gasification Cost benefits for the host utility Project Phases Feasibility study Confirm fuel availability and characterization Evaluate integration of gasifier and boiler Determine optimum gasifier size Prepare preliminary design and plant layout Cost estimate and plant economics Design
    [Show full text]
  • Potential Impacts on the Energy System at the Integrated Steelwork by Changing Injection Coal Types to the Blast
    A publication of CHEMICAL ENGINEERING TRANSACTIONS The Italian Association VOL. 35, 2013 of Chemical Engineering www.aidic.it/cet Guest Editors: Petar Varbanov, Jiří Klemeš, Panos Seferlis, Athanasios I. Papadopoulos, Spyros Voutetakis Copyright © 2013, AIDIC Servizi S.r.l., ISBN 978-88-95608-26-6; ISSN 1974-9791 DOI: 10.3303/CET1335162 Potential Impacts on the Energy System at the Integrated Steelwork by Changing Injection Coal Types to the Blast Furnace Joel Orre*,a, Chuan Wanga, Johannes Larssonb, Erik Olssonb a 97512, Luleå, Sweden Swerea Mefos, Box 812, SE- b SSAB EMEA Oxelösund, SSAB SE-613 80, Oxelösund, Sweden [email protected] Pulverized coal is often injected into the blast furnaces (BFs) at the integrated steelworks as reducing agent for the hot metal production. The BF process will behave different depending on the injection coal used. The objective of this study is to investigate how different types of coal will influence the BF, and the total energy system at an integrated steel plant. The major process units covered in the model are coking plant, BF, reheating furnace at the rolling mill and a power plant. They are all linked to each other via the main products as well as process gases (i.e. blast furnace gas (BFG) and coke oven gas (COG)) and oxygen network. At the studied plant, the mixed gas of BFG and COG is used within the coking batteries at the coking plant and hot stoves at the BF. The fuel used at the reheating furnace is COG and oil with high heating values. In total, 13 different types of coal and one biomass charcoal are included in the study.
    [Show full text]