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CoalFleet RD&D Augmentation Plan for Integrated Gasification Combined Cycle (IGCC) Power Plants
1013219
Plan
t Net
Effi
cien
cy (H
HV)
30
32
34
36
38
40
2005 2010 2015 2020 2025 2030
Near -Term • Add SCR • Eliminate
spare gasifier • F-class to
G -class CTs• Improved Hg
detection
Mid-Term• ITM oxygen• G - class to H-class
CTs• Supercritical HRSG• Dry ultra-low-NOX
combustorsLong-Term • Membrane
separation • Warm gas
cleanup • CO2-coal slurry
Longest-Term• Fuel cell
hybrids
30
32
34
36
38
40
2005 2010 2015 2020 2025 20302005 2010 2015 2020 2025 2030
Near -Term • Add SCR • Eliminate
spare gasifier • F-class to
G -class CTs• Improved Hg
detection
Mid-Term• ITM oxygen• G - class to H-class
CTs• Supercritical HRSG• Dry ultra-low-NOX
combustorsLong-Term • Membrane
separation • Warm gas
cleanup • CO2-coal slurry
Longest-Term
ELECTRIC POWER RESEARCH INSTITUTE 3420 Hillview Avenue, Palo Alto, California 94304-1338 ▪ PO Box 10412, Palo Alto, California 94303-0813 ▪ USA
800.313.3774 ▪ 650.855.2121 ▪ [email protected] ▪ www.epri.com
CoalFleet RD&D Augmentation Plan for Integrated Gasification Combined Cycle (IGCC) Power Plants
1013219
Technical Update, January 2007
EPRI Project Manager
J. Phillips
DISCLAIMER OF WARRANTIES AND LIMITATION OF LIABILITIES
THIS DOCUMENT WAS PREPARED BY THE ORGANIZATION(S) NAMED BELOW AS AN ACCOUNT OF WORK SPONSORED OR COSPONSORED BY THE ELECTRIC POWER RESEARCH INSTITUTE, INC. (EPRI). NEITHER EPRI, ANY MEMBER OF EPRI, ANY COSPONSOR, THE ORGANIZATION(S) BELOW, NOR ANY PERSON ACTING ON BEHALF OF ANY OF THEM:
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ORGANIZATION(S) THAT PREPARED THIS DOCUMENT
Electric Power Research Institute
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Bevilacqua-Knight, Inc.
This is an EPRI Technical Update report. A Technical Update report is intended as an informal report of continuing research, a meeting, or a topical study. It is not a final EPRI technical report.
NOTE
For further information about EPRI, call the EPRI Customer Assistance Center at 800.313.3774 or e-mail [email protected].
Electric Power Research Institute, EPRI, and TOGETHER…SHAPING THE FUTURE OF ELECTRICITY are registered service marks of the Electric Power Research Institute, Inc.
Copyright © 2007 Electric Power Research Institute, Inc. All rights reserved.
iii
CITATIONS This document was prepared by
Electric Power Research Institute 1300 West W.T. Harris Blvd. Charlotte, NC 28262
Principal Investigator J. Phillips
This document describes research sponsored by the Electric Power Research Institute (EPRI).
This publication is a corporate document that should be cited in the literature in the following manner:
CoalFleet RD&D Augmentation Plan for Integrated Gasification Combined Cycle (IGCC) Power Plants. EPRI, Palo Alto, CA: 2006. 1013219.
v
ABSTRACT Advanced, clean coal technologies such as integrated gasification combined cycle (IGCC) offer societies around the world the promise of efficient, affordable power generation at markedly reduced levels of emissions—including “greenhouse gases” linked to global climate change—relative to today’s current fleet of coal-fired power plants. To help accelerate the development, demonstration, and market introduction of IGCC and other clean coal technologies, EPRI formed the CoalFleet for Tomorrow initiative, which facilitates collaborative research by more than 50 organizations from around the world representing power generators, equipment suppliers and engineering design and construction firms, the U.S. Department of Energy, and others. This group advised EPRI as it evaluated more than 120 coal-gasification-related research projects worldwide to identify gaps or critical-path activities where additional resources and expertise could hasten the market introduction of IGCC advances. The resulting “IGCC RD&D Augmentation Plan” describes such opportunities—and how they could be addressed—for both IGCC plants to be built in the near term (by 2012–15) and over the longer term (2015–25), when demand for new electric generating capacity is expected to soar. For the near term, EPRI recommends 19 projects that could reduce the levelized cost-of-electricity for IGCC to the level of today’s conventional pulverized-coal power plants with supercritical steam conditions and state-of-the-art environmental controls. For the long term, EPRI’s recommended projects could reduce the levelized cost of an IGCC plant capturing 90% of the CO2 produced from the carbon in coal (for safe storage away from the atmosphere) to the level of today’s IGCC plants without CO2 capture. EPRI’s CoalFleet for Tomorrow program is also preparing a companion RD&D augmentation plan for advanced-combustion-based (i.e., non-gasification) clean coal technologies (Report 1013221).
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ACKNOWLEDGEMENTS The authors gratefully acknowledge the many technical contributions and insightful advice provided by participants in EPRI’s CoalFleet for Tomorrow collaborative initiative, by the operators of current IGCC units around the world, and by the community of power generators, equipment and service providers, and other stakeholders interested in IGCC technology.
Particularly valuable were technical papers and other source material made available to the authors, responses to EPRI technology issue and outlook surveys, and participation in EPRI webcasts and workshops to review draft versions of the materials in this report.
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CONTENTS
1 INTRODUCTION ....................................................................................................................1-1 Reversing the Trend in Declining Energy System RD&D ....................................................1-2 IGCC RD&D Augmentation Plan Goals: Near-Term and Longer-Term ...............................1-4 Industry and Government Roles in Implementing the IGCC RD&D Augmentation Plan .....1-6 Report Organization.............................................................................................................1-6
2 TECHNOLOGY BASELINES .................................................................................................2-1 Generic IGCC Plant Configuration .......................................................................................2-1 IGCC Baseline Designs .......................................................................................................2-3 Supercritical PC Baseline Designs.......................................................................................2-4 Comparison of Baseline Technologies and Performance Targets.......................................2-5
Capital Cost....................................................................................................................2-7 Availability ......................................................................................................................2-8 Emissions.....................................................................................................................2-10 Impact of CO2 Capture .................................................................................................2-13
Surveys to Identify Barriers to Deployment of IGCC Technology ......................................2-18 Existing “As Planned” IGCC RD&D Targeted for 2012 ......................................................2-19
3 IGCC RD&D AUGMENTATION PLAN OVERVIEW—NEAR-TERM.....................................3-1 Overview of Near-Term Implementation Plan ......................................................................3-1 Benefits versus Cost Estimates for Near-Term Elements of the IGCC RD&D Augmentation Plan......................................................................................................................................3-3 Implementation Path for Near-Term Elements of the IGCC RD&D Augmentation Plan ......3-4 Near-Term RD&D Projects with Broad Applicability.............................................................3-5
G-Class CTs...................................................................................................................3-6 Supplemental Firing and Steam Cycle Optimization......................................................3-6 Improved IGCC Dynamic Models...................................................................................3-8 IGCC RAM Database.....................................................................................................3-8 Minimizing Startup and Shutdown Length......................................................................3-9 Improved Gasifier Instrumentation & Control .................................................................3-9 Reliable pH Meters for Black & Grey Water Systems ..................................................3-10 Combustion Turbine Health Monitoring........................................................................3-11 Improved Computer Modeling of Gasifiers...................................................................3-13 Recover Air Separation Unit (ASU) & Air Compressor Heat ........................................3-13 IGCC Construction Optimization ..................................................................................3-14
Near-Term Technology-Specific RD&D Projects ...............................................................3-15 24,000 hr Gasifier Refractory .......................................................................................3-15 8000 hr Feed Injectors .................................................................................................3-16 16,000 hr Dry Solids Filter Elements............................................................................3-16
x
Decreased Syngas Cooler Fouling/Plugging ...............................................................3-17 Chloride-Resistant COS Hydrolysis Catalyst ...............................................................3-18 GRE Coal Drying Process............................................................................................3-18 Dry Solids Pump ..........................................................................................................3-19 Continuous Slag Pressure Let-Down ...........................................................................3-21
4 IGCC RD&D AUGMENTATION PLAN OVERVIEW—LONGER-TERM................................4-1 Implementation of the Longer-Term Elements in the IGCC RD&D Augmentation Plan ......4-1 Recommended RD&D Elements for Slurry-Fed Gasifiers ...................................................4-7
Baseline Technology......................................................................................................4-7 SCR Addition..................................................................................................................4-7 Elimination of Spare Gasifier..........................................................................................4-8 Transition from F-Class to G-Class CTs ........................................................................4-8 Improved Hg Detection ..................................................................................................4-8 ITM Oxygen....................................................................................................................4-8 CO2-Coal Slurry..............................................................................................................4-9 Transition to H-Class CTs ............................................................................................4-10 Dry Ultralow-NOX Combustors .....................................................................................4-10 Supercritical HRSG ......................................................................................................4-11 Membrane CO2 Separation ..........................................................................................4-11 Warm Gas Clean-Up....................................................................................................4-12 Transition from H-Class CT to Fuel Cell-CT Hybrid .....................................................4-13
Recommended RD&D Elements for Dry-Fed Gasifiers .....................................................4-14 Baseline Technology....................................................................................................4-14 Lower Syngas Cooler Steam Pressure ........................................................................4-15 Dry Solids Feed Pump for High Moisture Coal.............................................................4-15 Water Quench ..............................................................................................................4-16 Advanced Gasification System ....................................................................................4-16
5 COMBUSTION TURBINE TECHNOLOGY DEVELOPMENT................................................5-1 Technology Evolution...........................................................................................................5-1 Reliability Issues ..................................................................................................................5-3 Scale-Up Issues...................................................................................................................5-5 Current Status and Market Introduction of New Syngas-Firing CTs ....................................5-6 Commercialization Issues ....................................................................................................5-7 Near-Term RD&D Needs for Combustion Turbines.............................................................5-8
6 SUPPLEMENTAL FIRING, SUPERCRITICAL STEAM CYCLES, AND OTHER HRSG OPTIMIZATION CONCEPTS ....................................................................................................6-1
Supplemental Firing Options for IGCC.................................................................................6-2 NovelEdgeTM Concept: Reducing Capital Cost with Maximized Supplemental Firing and HRSG Simplification.............................................................................................................6-4 Supercritical Steam Cycles for IGCC...................................................................................6-6
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Current Status of Supplemental Firing and HRSG Optimization for IGCC ..........................6-7 Commercialization Issues ....................................................................................................6-7 Near-Term RD&D Needs for Supplemental Firing and HRSG Optimization........................6-8 Longer-Term R&D Needs for Supplemental Firing and HRSG Optimization.......................6-9
7 IMPROVED GASIFIER REFRACTORY FOR INCREASED IGCC AVAILABILITY ..............7-1 Gasifier Refractory Fundamentals .......................................................................................7-1 Potential Advantages ...........................................................................................................7-3 Current Status ......................................................................................................................7-4 Commercialization Issues ....................................................................................................7-4 Near-Term RD&D Needs .....................................................................................................7-5
8 SIMPLIFYING GASIFIER DESIGN, FEED, AND DISCHARGE ............................................8-1 Stamet Dry Solids Feed Pump.............................................................................................8-2
Technology Description..................................................................................................8-2 Potential Advantages .....................................................................................................8-3 Current Status ................................................................................................................8-3 Commercialization Issues ..............................................................................................8-4 Near-Term RD&D Needs ...............................................................................................8-4 Longer-Term RD&D Needs............................................................................................8-5 Potential Additional Long-Term Advantages..................................................................8-5 Status of Current Work on Longer-Term Opportunities..................................................8-6
Pratt & Whitney Rocketdyne Compact Gasification System ................................................8-6 Potential Advantages .....................................................................................................8-8 Development and Commercialization Status and Issues...............................................8-9
9 IGCC PROCESS MODELING, MONITORING, AND CONTROL ..........................................9-1 Improved IGCC Dynamic Models.........................................................................................9-1 Improved Computer Modeling of Gasifiers...........................................................................9-2 Minimizing Startup and Shutdown Length............................................................................9-2 Improved Gasifier Instrumentation and Control (I&C) ..........................................................9-2
A ABBREVIATIONS AND ACRONYMS.................................................................................. A-1
B COALFLEET IGCC SUPPLIER & BUYER SURVEYS ........................................................ B-1 IGCC “Barriers to Deployment” Survey for Technology and Equipment Suppliers............. B-1 IGCC “Barriers to Deployment” Survey for Power Generators ......................................... B-11 Advanced Coal RD&D Needs Survey for Technology and Equipment Suppliers ............. B-18
C STATUS OF EXISTING WORLDWIDE ADVANCED COAL RD&D FOR IGCC.................. C-1
D I&C NEEDS OF INTEGRATED GASIFICATION COMBINED CYCLES.............................. D-1 Abstract ............................................................................................................................... D-1 Introduction ......................................................................................................................... D-1 Coal Feeding I&C Needs .................................................................................................... D-4
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Gasifier I&C Needs ............................................................................................................. D-5 Solids Handling I&C Needs................................................................................................. D-7 “Black Water” Handling I&C Needs..................................................................................... D-8 Combustion Turbine I&C Needs ......................................................................................... D-8 Air Separation Unit I&C Needs............................................................................................ D-9 General IGCC I&C Needs ................................................................................................... D-9 References........................................................................................................................ D-10
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1 INTRODUCTION
The industry-led CoalFleet for Tomorrow collaborative research initiative was launched by EPRI in November 2004 to overcome the technical, economic, and institutional barriers to deployment of advanced “clean coal” power plants, thereby enabling power producers around the world to continue to provide reliable, affordable electricity while addressing environmental challenges, including global climate change.
CoalFleet is addressing a portfolio of advanced coal technologies, including integrated gasification combined cycle (IGCC). An IGCC plant is essentially a combined cycle (gas turbine and steam turbine) power plant fed by gaseous fuel (known as synthesis gas or “syngas”) made from chemically reacting coal, oxygen, and sometimes steam, under heat and pressure in a gasifier. After exiting the gasifier, syngas is cleaned and fired in combustion turbines similar to those used in natural gas combined cycle power plants but with special modifications to accommodate the different composition and relatively lower heating value of syngas. Hot combustion turbine exhaust gases are then routed through a heat recovery steam generator (HRSG) to produce steam of one or more pressures that can power a conventional steam turbine. Both the combustion turbine(s) and steam turbine drive electrical generators.
Currently, four coal-based IGCC units are in operation around the world, with 30+ unit-years of experience. Several more IGCC units are in service at oil refineries, using petroleum residuals as feedstocks. And there are numerous coal-based gasification units (the front end of an IGCC) operating at chemical plants around the world. In recent years, power companies on five continents have announced plans to build (or are considering) new coal-based IGCC plants, and provisions to encourage their construction in the United States were included in the Energy Policy Act of 2005. Much of this renewed interest is motivated by high oil and natural gas prices, energy security concerns, and the potential for converting IGCC power plants at some point in their lifetime to an operating mode where the majority of CO2 that would otherwise have been emitted could be captured for long-term storage away from the atmosphere (thereby helping curb the atmospheric CO2 buildup that has been linked to global climate change).
In addition to supporting deployment of IGCC units now in the initial phases of design, the CoalFleet for Tomorrow initiative is seeking to hasten the development, demonstration, and market introduction of the “next steps”—IGCC component and design advances that reduce costs, boost unit availability, enhance operating flexibility, and improve environmental performance.
EPRI and the CoalFleet participating organizations have examined ongoing IGCC and gasification-related RD&D programs worldwide, and have identified opportunities where acceleration of existing programs by means of additional resources and expertise, and
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augmentation of existing programs with new and complementary activities, will deliver a high rate of return on investment and a large public benefit.
Accordingly, the chief purpose of the CoalFleet IGCC RD&D Augmentation Plan is to marshal the stakeholders in IGCC technology to commence definition, assignment of roles, funding, and implementation of specific RD&D projects to capitalize on these opportunities to remove the barriers to advanced IGCC plant deployment. The projects are specifically designed to supplement, not duplicate, activities that are already planned or under way. The IGCC RD&D Augmentation Plan will also serve to identify consortia, host facilities, and synergies that can help accelerate the implementation of the recommended projects.
[Note: CoalFleet for Tomorrow is also preparing a companion document, CoalFleet RD&D Augmentation Plan for Advanced Combustion Power Plants, EPRI report 1013221.]
Reversing the Trend in Declining Energy System RD&D
The CoalFleet initiative aims to meet needs that are shared by different facets of the industry, and which can best be met through sharing of lessons-learned, development of an easily accessible and comprehensive information resource, and sponsorship of research programs not adequately met through other means.
In the judgment of many in the industry, RD&D for coal-fired power generation has been under-funded for over 20 years in both private and public sectors. The CoalFleet RD&D augmentation plan for IGCC and other advanced coal power technologies is motivated by a need to quickly fill gaps in knowledge. Filling these gaps is essential to successful commercialization of these technologies. This implementation is itself seen as key to maintaining coal-based generation as an economically viable option and to achieving potential environmental gains.
The current R&D funding picture is illuminated by plotting energy-related R&D expenditures in the United States. An analysis by Daniel Kammen, a professor at the University of California–Berkeley, concluded that between 1980 and 2005, energy R&D fell from 10% of total U.S. R&D to 2% (see Figure 1-1). Additional analysis shows that this trend has not resulted solely from a cutback in government spending on R&D. Private sector R&D, in real dollars, has fallen by almost 75% since 1980. It is even more striking to realize that this shrinkage occurred during a time that the U.S. economy was growing dramatically.
Although Dr. Kammen’s analysis focused on energy R&D as a whole and not just coal-related R&D, a look at recent budgets for the U.S. Department of Energy (DOE) shows that expenditures for coal-related R&D approximately equaled 1% of the value of coal purchases by U.S. power generators.
For example, in the 12 months ending in October 2005, U.S. coal power plants paid $23.5 billion for 772,191,000 tons of coal at an average delivered price of $30.41/ton. DOE’s coal R&D budget for fiscal year 2005 (which ended in October 2005) was $272.7 million, or 1.1% of the amount spent on coal for power generation during the same period.
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Figure 1-1 U.S. Energy Related RD&D Expenditures since 1975 (Constant Dollars)
A similar situation occurs in the private sector. EPRI’s Electricity Technology Roadmap noted that private sector energy R&D investment dollars equaled less than 0.5% of energy sector revenues.1 In contrast, the medical private sector invests more than 10% of its revenues in R&D and the transportation equipment private sector (planes, trains, and autos) invests 6% of its revenues into R&D.
Under-funding of fossil energy R&D is not just a U.S. phenomenon. Figure 1-2 shows the history of German federal government spending on fossil fuel and renewable energy R&D from 1974 through 2003. Annual fossil fuel R&D funding has fallen from a peak of 200 million euros in 1982 to virtually zero in 2003.
The dramatically low level of advanced coal power system R&D funding might be somewhat understandable if coal-based generation were a small and declining fraction of global power production. However, the exact opposite is true. Statistics and forecasts assembled by the U.S. Energy Information Administration (EIA) indicate that coal-based power plants will remain the world’s dominant means of generating electricity for decades (at about a 40% market share through 2030, and at about a 50% share in the United States). New coal-based generating capacity totaling nearly 900 gigawatts is expected to be built worldwide between 2003 and 2030.2 This continued reliance on coal underscores the value proposition for increased investment in advanced coal power system RD&D, especially in light of the likely requirement that much of this new capacity capture CO2 for sequestration during some or all of its lifetime.
1 Electricity Technology Roadmap, EPRI report 1010929, 2003.
2 “International Energy Outlook 2006,” p.67, http://www.eia.doe.gov/oiaf/ieo/index.html
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There is a need for additional private sector funding to supplement DOE’s current R&D effort. “If not us, who? If not now, when?” is as relevant now as it ever was.3
The CoalFleet RD&D augmentation plans (IGCC and Advanced Combustion) focus on preserving coal as an option for power generation, so that societies around the world can choose a future based on abundant supplies of electricity produced in an environmentally sustainable manner.
Figure 1-2 German Federal Government R&D Spending on Fossil and Renewable Energy4
IGCC RD&D Augmentation Plan Goals: Near-Term and Longer-Term
EPRI has defined two sets of elements for meeting research and development goals: near-term and longer-term.
Near-term activities address technologies meant to be market-ready by 2012—developed and tested so that anyone ordering IGCC power plant technologies or specifying an entire IGCC power plant, for delivery in 2012 or later, could expect a manufacturer’s guarantee on the plant
3 Attributed to Robert F. Kennedy’s use of a translation of Rabbi Hillel from Pirkay Avot (Hebrew for “Chapters of the Fathers” or “Ethics of the Fathers”), a book of the Mishnah, the first part of the Talmud; this quotation was also popularized by Ronald Reagan.
4 Research and Development Concept for Zero-Emission Fossil-Fuelled Power Plants: Summary of COORETEC, Federal Ministry of Economics and Labor, Report Number 527, Berlin, December 2003.
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components including improvements in the list. Near-term projects could reduce the levelized cost of electricity (COE) of new IGCC units beginning operation in 2012.
Longer-term activities are not meant to be completed in the near-term timeframe, but as soon as reasonably possible. Decreasing the cost of coal plants with CO2 capture technology is going to take longer than 5 years, and is therefore a longer-term goal. Longer-term projects could reduce the cost of electricity for new IGCC units coming on-line after 2012–15. Stakeholders need to invest in long-term plans now to meet overall technology objectives while still meeting goals for the near-term.
Figures 1-3 and 1-4 illustrate the CoalFleet RD&D Augmentation Plan’s timeline for attaining capital cost reduction goals and efficiency goals, respectively, for IGCC plants with CO2 capture.
Figure 1-3 Forecast Reduction in IGCC (with Capture) Capital Cost through Implementation of the CoalFleet RD&D Plan (Slurry-fed gasifier, Pittsburgh #8 coal, 90% availability, 90% CO2 capture, 2Q 2005 U.S. dollars)
2200
coal slurry
Longest - Term• Fuel cell
hybrids
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2005 2010 2015 2020 2025 2030
Near -Term • Add SCR • Eliminate
spare gasifier • F- class to
G -class CTs• Improved Hg
detection
Mid-Term• ITM oxygen• G-class to H -class
CTs• Supercritical HRSG• Dry ultra -low-NOX
combustors
Long-Term• Membrane
separation• Warm gas
cleanup• CO2-coal slurry
Longest - Term• Fuel cell
hybrids Tota
l Pla
nt C
ost (
$/kW
)
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2005 2010 2015 2020 2025 20302005 2010 2015 2020 2025 2030
Near -Term • Add SCR • Eliminate
spare gasifier • F- class to
G -class CTs• Improved Hg
detection
Mid-Term• ITM oxygen• G-class to H -class
CTs• Supercritical HRSG• Dry ultra -low-NOX
combustors
Long-Term• Membrane
separation• Warm gas
cleanup• CO2-
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Figure 1-4 Forecast Improvement in IGCC (with Capture) Efficiency through Implementation of the CoalFleet RD&D Plan (Slurry-fed gasifier, Pittsburgh #8 coal, 90% availability, 90% CO2 capture, 2Q 2005 U.S. dollars)
Industry and Government Roles in Implementing the IGCC RD&D Augmentation Plan
EPRI uses the following general criteria in determining which entity would be best suited to take on individual and collective challenges for technology improvements:
• Individual OEMs should be the lead developers for technologies which are highly proprietary or which would give an individual supplier a competitive advantage.
• Large financial and commercial risk items, especially those with a major “public good” component, warrant support from government entities.
• Technology that can be applied to equal benefit for most IGCC suppliers and users should be developed by an industry-led collaborative. Shared projected value means that there must be a shared risk and investment.
• Fuel cell hybrids
Plan
t Net
Effi
cien
cy (H
HV)
30
32
34
36
38
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2005 2010 2015 2020 2025 2030
Near - Term • Add SCR • Eliminate
spare gasifier • F-class to
G - class CTs• Improved Hg
detection
Mid-Term• ITM oxygen• G -class to H-class
CTs• Supercritical HRSG• Dry ultra-low-NOX
combustorsLong-Term • Membrane
separation • Warm gas
cleanup• CO2-coal slurry
Longest-Term• Fuel cell
hybrids
30
32
34
36
38
40
2005 2010 2015 2020 2025 20302005 2010 2015 2020 2025 2030
Near - Term • Add SCR • Eliminate
spare gasifier • F-class to
G - class CTs• Improved Hg
detection
Mid-Term• ITM oxygen• G -class to H-class
CTs• Supercritical HRSG• Dry ultra-low-NOX
combustorsLong-Term • Membrane
separation • Warm gas
cleanup• CO2-coal slurry
Longest-Term
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Chapter 3 (“IGCC RD&D Augmentation Plan Overview—Near-Term”) tabulates and describes important technology improvements that, with accelerated RD&D schedules and additional funding, could be available for commercial deployment in the next five year period (i.e., for incorporation in plants commencing construction by 2012, or alternatively, for the FutureGen “main train” if desired).
Chapter 4 (“IGCC RD&D Augmentation Plan Overview—Longer-Term”) tabulates and describes important technology improvements with development cycles (or a market need)—even with augmented effort—that are longer than five years, and thus would at best be ready for plants being built in the later 2010s or 2020s.
Chapter 5 (“Combustion Turbine Technology Development”) explores in greater detail the RD&D Augmentation Plan recommendations associated with reducing capital costs through introduction of “G class” and “H class” machines for syngas and hydrogen-rich syngas, reliability improvements, and reductions in NOX emissions. It also examines the very-long-term integration of fuel cells and combustion turbines for markedly increased unit efficiency.
Chapter 6 (“Supplemental Firing, Supercritical Steam Cycles, and Other HRSG Optimization Concepts”) explores in greater detail the RD&D Augmentation Plan recommendations associated with the “back end” of the power cycle to improve output and/or efficiency, operating flexibility, and modifications to accommodate the thermal demands of CO2 capture processes.
Chapter 7 (“Improved Gasifier Refractory for Increased IGCC Availability”) explores in greater detail the RD&D Augmentation Plan recommendations associated with improving gasifier wall refractory lining life, a key issue in boosting overall IGCC plant availability.
Chapter 8 (“Simplifying Gasifier Design, Feed, and Discharge”) explores in greater detail the RD&D Augmentation Plan recommendations associated with fuel conveyance, slag removal, and advanced gasifier concepts.
Chapter 9 (“IGCC Process Modeling, Monitoring, and Control”) explores these types of RD&D Augmentation Plan projects in greater detail.
Appendices provide supporting analyses, survey results, and other relevant reference material.
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2 TECHNOLOGY BASELINES
EPRI has established representative plant configurations for IGCC and conventional supercritical PC (SCPC) plants to serve as “baseline designs” for comparison of the relative competitiveness of IGCC units and for evaluating the benefits of accelerating and augmenting IGCC RD&D efforts. These technology baselines provide key points of reference for comparative assessments of the IGCC improvements recommended in the IGCC RD&D Augmentation Plan.
These baseline designs reflect technologies judged to have been proven at commercial scale as of year-end 2004. Due to continuous development by power industry suppliers, the “proven” technologies embodied in EPRI’s baseline designs may now represent technology that is a “half-generation” older than the designs and equipment being offered today by IGCC and SCPC suppliers (e.g., FB-class combustion turbines are now available for syngas firing in place of the FA-class machines used in the baseline designs).
Generic IGCC Plant Configuration
The typical block flow diagram in Figure 2-1 illustrates the basic systems common to most IGCC power plant designs. Table 2-1 describes the basic systems and major components. Major components are contained in two groupings, commonly referred to as the “power island” and the “gasification island.” Typically, the capacity of the gasification system is selected to match the fuel needs of the combustion turbine, along with design decisions regarding spare gasification capacity, which may be used to increase plant availability or to allow supplemental firing to increase steam production for the steam turbine or process use.
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O2 N2
Air
BFWFresh boiler
Feedwater(BFW)
Steam
Steam Turbine
HRSG
CoalPrep
Gas CoolingGasificationSulfur
Removal
Air Separation
Unit
GasTurbine
Air
Figure 2-1 Typical Block Flow Diagram for IGCC5
Table 2-1 IGCC Plant Components and Process
Power Island
The power island of an IGCC plant uses the same basic components as a combined cycle power plant fired with natural gas or distillate oil. Modifications to these components may be made to suit a specific gasification technology. Three major components form the basis of the combined cycle.
The combustion turbine (CT, also called a gas turbine or GT), at the heart of the combined cycle power plant:
A multi-stage, axial-flow compressor draws in ambient air and raises its pressure for delivery to the combustor(s). In IGCC, a portion of this air may be redirected to the gasifier (air-blown gasifier) or to an air separation unit (oxygen-blown gasifier).
One or more combustors mix fuel with air and combust it to create a high-pressure, high-temperature gas working fluid. For IGCC, the high hydrogen content of the syngas requires use of older-style diffusion-flame combustors instead of the dry low-NOX (DLN) combustors commonly used for natural gas. The diffusion flame combustors use a steam or nitrogen diluent to reduce flame temperature and thereby reduce thermal NOX formation.
The working fluid exits the combustor(s) and flows through the multi-stage, axial-flow power turbine, which
5 N. Holt, “Gasification 101,” PowerPoint presentation, EPRI CoalFleet workshop, Tampa, FL, January 2005.
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converts its heat energy and kinetic energy into rotational energy. Temperature and stress limits of blade materials in the power turbine are typically the limiting factor in the advancement of CT design for efficiency and power capacity. CTs firing low-Btu syngas often have higher fuel mass flow and lower flame temperatures than the comparable turbine firing natural gas or distillate. In many cases, despite the lower firing temperature, the higher mass flow allows an increase in CT power rating. Some turbine designs are modified with stronger drive shafts and larger generators to take advantage of this capacity.
Exhaust gas, from the power turbine, is directed to a heat recovery steam generator (HRSG). The HRSG typically will produce steam at two or three pressures and may incorporate a reheat loop. For IGCC, the gas cooler(s) in the gasification cycle may augment some of the heat exchange surface in the HRSG and/or take the place of feedwater heaters.
Steam from the HRSG will be directed to a multi-stage steam turbine (ST). In a single-shaft combined cycle, the ST and CT are installed on a common shaft, driving a single generator. In a dual-shaft combined cycle, the ST is installed separately. In larger plants, it is common to have two or three CT/HRSG trains providing steam for a single large ST. Typically, the power output from the ST is about one-third to half of the output from the CT(s). This may be increased, if the plant incorporates significant supplemental firing, or decreased, if the plant serves a process steam load. The ST exhaust condenser and condenser cooling system would be modified accordingly. As with conventional combined cycles, the ST will be designed to match characteristics of the CT, HRSG, and condenser. The different heat, steam, and water requirements of the gasification system will further influence ST and HRSG design.
Gasification Island
The gasification island of an IGCC plant may resemble any of a number of different stand-alone gasification plants; gasification islands from different suppliers share many common elements but are also technically distinct in several ways. Elements common to IGCC gasification islands generally include:
A coal preparation area, where coal is pulverized and dried or slurried as necessary for feed to the specific type of gasification reactor. Additives may be added to adjust flow characteristics. Lime or another source of CaO may be added to optimize ash melting point and flow characteristics.
A gasification reactor, which receives dry or slurried coal, oxygen or air, and in some cases steam, and converts it to raw fuel gas composed chiefly of carbon monoxide, hydrogen, and methane. The reactor may incorporate one or more vessels and have one or two stages of reaction. Dry-feed reactors generally require lock hoppers for feed and for slag discharge. Slurry feed reactors may have a slag discharge hopper.
An air separation unit (ASU), which provides high purity oxygen when the gasifier is oxygen-blown. High-pressure air for the ASU may be provided from the CT compressor or from a separate compressor. Typically, the nitrogen by-product of the ASU is fed back to the CT combustor for dilution to reduce NOX formation and increase working gas volume.
Gas cooling, which generally serves double-duty by preheating boiler feedwater and/or generating part of the steam for the steam turbine, in addition to adjusting temperature as required for acid gas clean-up equipment.
Gas clean-up to remove solids, sulfur, mercury, and other undesired compounds before the fuel gas goes to the CT combustor(s).
A water-shift reactor and CO2 absorber may be added to enable CO2 separation for sequestration and/or to provide hydrogen-rich syngas for other purposes.
IGCC Baseline Designs
IGCC plant configurations used as “baseline designs” for economic comparisons employ two GE 7FA combustion turbines (CTs), each capable of producing 197 MW of power when fired on syngas. These turbines are incorporated in a combined cycle configuration with a single steam turbine-generator. The net plant output is approximately 520 MW.
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The baseline plant may have either a dry-fed gasifier or slurry-fed gasifier and may be oxygen-blown or air-blown. IGCC plants with oxygen-blown gasifiers have an air separation unit (ASU) with two 50% trains. A portion of the air for the ASU (usually 25–50%) is supplied by extraction from the CT compressors, reducing compression costs. The baseline IGCC designs do not include a spare gasifier.
Gas clean-up equipment includes a COS hydrolysis catalyst, an activated carbon bed for mercury capture, and a low-temperature acid gas removal (AGR) process using an MDEA or Selexol™ solvent. The captured H2S is converted to “yellow cake” sulfur in a Claus process unit (common in petrochemical processing), and the Claus tail gas is recycled to upstream of the AGR system. The sulfur level in the syngas after the AGR unit is 30 ppmv, regardless of the sulfur content of the feed coal. Combustion NOX control is accomplished by dilution of syngas with the excess N2 produced by the ASU and, if necessary, saturation of the syngas by contact with hot water or steam. Selective catalytic reduction (SCR) for post-combustion NOX control is not included.
The HRSG provides steam to the high-pressure turbine at 1800 psia (~120 bar) and 1000ºF (540ºC). High-pressure steam turbine exhaust is reheated to 1000ºF (540ºC) before entering the intermediate-pressure steam turbine (i.e., steam conditions of 1800 psia/1000ºF/1000ºF or 120 bar/540ºC/540ºC).
As of 2004, the GE 7FA was the largest combustion turbine operating in 60-Hz IGCC service, with one unit each at the Polk and Wabash River plants. [Note: Although these plants used GE machines, the firing temperatures, mass flow, and power output are roughly comparable in the Siemens SGT6-5000F (formerly Siemens-Westinghouse W501F) and MHI M501F machines, which are also candidates in 2004 for 60-Hz IGCC service.]
[Note: Facilities in Europe, much of Asia, Australia, and elsewhere use 3000 rpm/50-Hz CTs, which have roughly 33% to 50% greater mass flow and 33% greater power output than comparable 60-Hz machines. This size increase derives from the longer blading allowed by the lower centrifugal forces produced at the lower rotational speed. The Elcogas plant in Spain uses one Siemens SGT5-4000F (formerly KWU V94.3). The 50-Hz Mitsubishi M701F at Negishi, Japan, is currently the world’s largest CT in IGCC service. However, for competitiveness benchmarking, only 60-Hz baseline designs were established.]
Supercritical PC Baseline Designs
EPRI also defined baseline technology for SCPC plants in order to judge the relative competitiveness of IGCC technology. The baseline was set chiefly by what had been commercially proven in 2004.
For bituminous coal such as Pittsburgh #8, the steam cycle conditions for the baseline PC plant design are 3500 psia/1050ºF/1050ºF (240 bar/565ºC/565ºC). Emissions control is based on low-NOX burners and SCR for NOX, wet limestone scrubber for SO2 (98% SO2 removal), and a wet electrostatic precipitator (ESP) for fine particulate and acid mist removal. Mercury is partially removed by the FGD unit.
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Higher steam conditions (3500 psia/1100ºF/1100ºF, or 240 bar/595ºC/595ºC) can be used in plants fired with low-sulfur subbituminous coal, such as Powder River Basin (PRB), because of the less corrosive combustion environment. For this coal, emissions control is based on low-NOX burners, SCR, a dry limestone scrubber (95% SO2 removal), and fabric filters. Mercury is partially captured on the filter bags by the unburned carbon.
Net plant power output is set at 520 MW, for both coal types, to allow meaningful comparisons to the IGCC baseline designs.
Comparison of Baseline Technologies and Performance Targets
The IGCC RD&D Augmentation Plan focuses on technology areas deemed to be most important to establishing IGCC’s commercial viability. Useful targets for measuring progress toward that goal are provided in the joint Coal Utilization Research Council (CURC) and EPRI Roadmap published in 2002 and updated in 2006.6 The CURC-EPRI targets bring insights from many experts into a consensus forecast of what will be required by regulatory bodies and what can be achieved by industry if adequate resources are provided.
Much of the RD&D work for IGCC is focused on improving the long-term economic performance of IGCC power plants by improving availability and thermal efficiency and by reducing capital cost. The expected values for the IGCC and SCPC baseline designs are presented in Table 2-2, along with the 2020 goals for coal power plants contained in the updated CURC-EPRI Roadmap.
Table 2-2 Comparison of 2004 Baseline Designs to CURC-EPRI Targets for Coal Power Plants in 2020
Technology Coal Type Availability Thermal Efficiency, HHV basis
Capital Cost, $/kW 2Q 2005 USD
SCPC 2004 Pitts #8 86% 38.8% 1437
IGCC 2004 Pitts #8 80–85% 38.9–40.4% 1509–1761
CURC-EPRI Roadmap for 2020
Pitts #8 90% 42–46% 1220–1350
SCPC 2004 PRB 86% 37.6% 1552
IGCC 2004 PRB 80–85% 35.7–40.2% 1536–1832
CURC-EPRI Roadmap for 2020
PRB 90% 42–46% 1220–1350
6 “Clean Coal Technology Roadmap.” Downloadable at http://www.coal.org/PDFs/jointroadmap.pdf. A PowerPoint overview of the 2006 update of the Roadmap was made available in September 2006.
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For the SCPC baseline designs, costs and efficiencies were calculated using in-house EPRI models. For the IGCC baselines, EPRI used cost and performance results from various studies conducted in the 2002–04 timeframe. The cost and efficiency ranges for IGCC reflect the impact of using different gasification technologies (e.g., dry feed versus slurry feed). All capital cost data has been corrected to second quarter (2Q) 2005 dollars.
[Note: For IGCC units, the U.S. convention for calculating heat rate is on the basis of the higher heating value (HHV) of the fuel, as is the U.S. practice for other coal power technologies. This is different from the usual convention for European plants, or for U.S. plants with gas turbines or combined cycles that are fueled on oil or natural gas, where the low heating value (LHV) is presumed when “HHV basis” or “LHV basis” designations for heat rate are not provided.]
The baseline availability factor for SCPC is based on the 75th percentile value for all SCPC >375 MW for the five year period ending in 1999.7 For IGCC, the baseline availability factors are based on actual performance of commercial coal-based IGCC units through 2004.8,9 This is illustrated in Figure 2-3, which shows the availability history of six coal-based IGCC units and four oil-based IGCC units.
EPRI conducted competitiveness analyses for supplier- and fuel-specific IGCC baseline designs and compared them with levelized cost-of-electricity results for comparably fueled conventional SCPC plants to determine the COE “gaps” that must be overcome to achieve cost parity (see Table 2-3). These gaps serve as targets for the near-term projects in the IGCC RD&D Augmentation Plan (see Chapter 3).
Table 2-3 Baseline Competitiveness Analysis for 2004 Baseline IGCC and SCPC Designs (GE 7FA CTs, 2Q 2005 USD)
Gasifier GE CoP Shell KBR
Coal Pitts #8 PRB Pitts #8 PRB Pitts #8 PRB Pitts #8 PRB
$/kW 1600-2100
1400 – 1800
1700 - 2200
1625 – 2100
1635 – 2125
1425 - 1850
CF 81 78 78 83 83 80–85
Heat Rate, HHV (Annual Average)
8782 8612 9553 8446 8712 8486
COE Gap to SCPC, $/MWh
7.61 – 18.88
3.97 – 13.34
10.38 – 22.09
6.62 – 17.07
5.71 – 16.49
0.12 – 11.58
7 Slettehaugh et al. (Black & Veatch), “IGCC vs. Supercritical PC for Power Generation from Coal,” Coal-Gen 2005. 8 Ibid. 9 Evaluation of Alternative IGCC Plant Designs for High Availability and Near Zero Emissions, EPRI report 1010461, December 2005.
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Capital Cost
Current capital cost data are difficult to obtain, given the state of flux in the commercial IGCC arena and the rapid escalation in recent years of the prices for key commodities such as concrete and steel. Nonetheless, some data are available from public announcements and public utility commission (PUC) filings for new power projects. A sampling of these data is shown in Table 2-4. The final column in the table reflects, as a point of reference, EPRI’s estimated cost on a “Total Project Cost” (i.e., overnight dollars) and “Total Capital Requirements” basis for the plants described. Given current market conditions, EPRI recommends that all capital cost values be treated with a substantial uncertainty band, whether explicitly stated or not.
Table 2-4 Recently Reported PC and IGCC Capital Costs from PUC Submissions and Press Announcements
Owner Plant Name/ Location
Net MW Technology/Coal
Reported Capital Cost
$Million
Reported $/kW
EPRI Estimate May 2006 TPC/TCR10
Otter Tail Big Stone, SD 600 USC PRB 1500 2500 1400/1610
AEP- Swepco
Hempstead, AR 600 USC PRB 1300 2167 1486/1709
AEP- PSO/OGE
Sooner, OK 950 USC PRB 1800 1895 1268/1458
AEP Meigs County, OH
630 GE RQ IGCC Bit
1300 2063 1918/2282
Duke Edwardsport, IN 630 GE RQ IGCC Bit
1300-1600 2063-2540 1918/2282
NRG NY, CN, DE 750 Gross ~620 Net
Shell GRQ IGCC Bit
1466 1955 Gross ~2365 Net
1965/2335
One major influence on the capital cost and heat rate of IGCC plants and SCPC plants is coal quality, particularly coal moisture and ash content, which affect heating value. Figure 2-2 shows the relative increase in heat rate and capital cost for IGCC and SCPC technologies without CO2 capture upon moving from a high-heating-value bituminous coal such as Pittsburgh #8 to bituminous coals with lower heating value (e.g., Illinois #6) and low-rank coals, such as Powder River Basin and lignite. The higher moisture content of low-rank coals has a relatively greater deleterious effect on slurry-fed gasifiers. Although not shown in the figure, the “fall-off” for dry-fed gasifiers is more similar to SCPC units.
10 EPRI estimates have large uncertainty bands due to changing equipment and material costs, labor rates, productivity, etc.
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1.00
1.05
1.10
1.15
1.20
1.25
1.30
1.35
1.40
5,000 6,000 7,000 8,000 9,000 10,000 11,000 12,000 13,000 14,000 15,000Coal Heating Value, Btu/lb HHV
Rel
ativ
e H
eat R
ate
or C
apita
l Cos
t IGCC Capital Cost (E-Gas)
IGCC Heat Rate (E-Gas)
PC Capital Cost
PC Heat Rate
WY PRBTX Lignite
Illinois #6
Pittsburgh #8
Figure 2-2 Effect of Coal Quality on PC and IGCC Plant Heat Rates and Capital Cost
Availability
Along with high capital cost, overcoming RAM challenges is a significant factor in accelerating market acceptance of IGCC. Although combined cycle and gasification technologies are both well proven, there is less operating history—approximately thirty unit-years total—for plants that integrate these technologies on a commercially successful basis. One challenge for IGCC plants, as opposed to gasification-based chemical plants—which typically operate at steady-state without interruption between scheduled maintenance outages, is the need to accommodate more frequent and more rapid startup/shutdown cycles and throughput changes due to power dispatch cycling.
To date, just one of the coal-based IGCC units referenced in Figure 2-3 has reached the expected availability level shown in Table 2-2, and that was for a period of only one year. The factors in Table 2-2 reflect an adjustment to account for proven modifications that have been implemented in pilot plants or through upgrades to full-scale plants that EPRI expects will be included in current IGCC design offerings (e.g., improved refractory). Further, the IGCC availability factors in Figure 2-3 reflect coal/coke-based operation only. Cases where the combined cycle could continue operation with the gasifier out-of-service by using back-up liquid or gas fuel were not considered relevant for this comparison and are thus not included in the availability calculations.
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IGCC RAM Data - Excludes Impact of Back-up Fuel
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
1styear
2ndyear
3rdyear
4thyear
5thyear
6thyear
7thyear
8thyear
9thyear
10thyear
11thyear
Ava
ilabi
lity
NuonWabashTECOElcogasCool WaterLGTI SyngasSarlux (Oil)ISAB (Oil)Negishi (Oil)Api (Oil)
Figure 2-3 Availability Histories of IGCC Plants Worldwide (Coal/Petroleum Coke and Heavy-Oil-Based)
EPRI believes the stated baseline availabilities will be obtained and may be improved upon by IGCC projects which are currently in early development stages. For example, for a GE IGCC plant, a 3 percentage point improvement for future units has been credited based on removing the convective syngas cooler used at TECO Energy Polk Unit 1 from GE’s standard design. In the case of a Shell IGCC, credit is given for not having an ASU fully integrated with the gas turbine (as is the case at the Nuon IGCC in the Netherlands). The 90% availability factor cited in the 2006 CURC-EPRI Roadmap for 2020 assumes that further improvements will result from near-term RD&D efforts.
The data in Figure 2-3 illustrate two important points that provide useful insight into expectations for future performance:
1. Newly commissioned IGCC plants have typically experienced a “shake-out period” of 3 to 5 years before their “normal” availability is achieved. This shake-out period has been reduced for more recent plants (though these have been based on heavy oil rather than coal) and is expected to improve further as each subsequent plant benefits from the growing experience base and incorporates less technology at a developmental or early-commercial stage.
2. No coal-based IGCC plant to date has sustained an availability rate of over 80% for an extended period (not counting situations where you could run the combined cycle portion of the plant on natural gas or distillate), although Eastman’s chemical plant in Kingsport,
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TN—with the benefit of a spare gasifier and without the burden of a combustion turbine—has maintained availabilities exceeding 90% for many years. The combination of current market pressure to limit capital cost and the cumulative experience from the Eastman Kingsport, TN, chemical plant and TECO Energy Polk gasifiers has led GE/Bechtel and ConocoPhillips/Flour to omit a spare gasifier from their reference plant designs. [Note: Shell hadn’t previously included a spare gasifier in its plant design.]
An unexpected finding in operating IGCC units has been the substantial unavailability due to CT failures that appear to be unrelated to syngas firing. It has been observed that most CT issues have arisen at IGCC plants with low-serial-number CT models. Because these plants became favored by dispatchers as natural gas prices rose, they accumulated industry-leading operating hours for their models. Interestingly, lessons learned from the IGCC plant failures led to suppliers to make proactive changes that prevented many NGCC plants from experiencing the same problems.
Emissions
Table 2-5 Expected Emission Levels for Advanced Coal Power Generation Technologies
Technology Coal Type
NOX SOX Hg
SCPC 2004 (Baseline)
Pitts #8
0.494 lb/MWh 0.709 lb/MWh 90% removal
SCPC 2004 (Baseline)
PRB 0.500
lb/MWh 0.541 lb/MWh 80–90% removal
IGCC 2004 (Baseline)
Pitts #8 & PRB
0.064 lb/MMBtu,
0.544 lb/MWh
0.013 lb/MMBtu, 0.11 lb/MWh
>90% removal, <1 x10-6 lb/MMBtu, <8.4 x10-6 lb/MWh
NSPS 2006 Pitts #8 & PRB
0.114 lb/MMBtu,
1.0 lb/MWh
0.16 lb/MMBtu, 1.4 lb/MWh
~70% removal, 2.3 x10-6 lb/MMBtu,
20 x10-6 lb/MWh
2006 CURC-EPRI Roadmap for 2020
(IGCC and PC listed together)
Pitts #8
0.1–0.2 lb/MWh 0.02–0.1 lb/MWh 97% to 99% removal
Table 2-5 lists expected emissions rates for the baseline IGCC and SCPC designs and compares them to the 2006 CURC-EPRI Roadmap goals for 2020. The IGCC baseline levels are derived
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from the best levels achieved at existing coal-based IGCC units. The SCPC NOX and SOX levels are based on EPA’s 2006 “environmental footprints” study.11
Figure 2-4 provides a comparative illustration of permit limits and actual average annual emissions from existing IGCC plants and recently proposed IGCC units in the United States. The figure also shows the emission targets for design purposes in EPRI’s IGCC User Design Basis Specification (UDBS).12 Figure 2-5 shows the permit limits and actual average annual emissions from existing PC plants along with the permit limits for several SCPC plants under construction in the United States.
0.0
0.2
0.4
0.6
0.8
1.0
1.2
1.4
1.6
1.8
2.0
Elcogas(SP)
Nuon(NL)
TECO Wabash Negishi(JP)
Elm Rd Steelhead UDBS 1 UDBS 2
lb/M
W-h
r
NOx - permitNOx - actualSOx - permitSOx - actual
CURC 2020 NO
CURC 2020
Heavy oil-based IGCC with SCR
Lower GT firing temperature yields lower NOx
US NOx NSPS limit
US SOx NSPS limit
Wabash has run a 30-day test with deep sulfur recovery in which SO2 emisssions averaged 0.27 lb/MW-hr
Figure 2-4 Permit Limit and Actual (Annual Average) Emissions for Existing and Proposed IGCC Plants [Note: Negishi uses an asphalt residue feed; the others use coal and/or petroleum coke.]
11 Environmental Footprints and Costs of Coal-Based Integrated Gasification Combined Cycle and Pulverized Coal Technologies, U.S. Environmental Protection Agency, Report EPA-430/R06/006, July 2006. 12 See http://www.epri.com/portfolio/product.aspx?id=2137 for more information on the specification.
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Navah
o 2
Intermountai
n 2
W A Pari
sh 6
W A Pari
sh 8
Elm R
oad
Trimble
Cty 2
Spruce
2
Comanch
e 3
Council B
luffs 4
Isogo 1
(JP)
Isogo 2
(JP)
lb/M
W-h
r
NOx - permitNOx - actualSOx - permitSOx - actual
US SOx NSPS limit
US NOx NSPS limit
Figure 2-5 Permit Limit and Actual Emissions for Existing and Proposed PC Plants
In general, both IGCC and SCPC baseline designs can achieve current U.S. New Source Performance Standards (NSPS) for SO2 and NOX. IGCC units should be able to achieve the 2006 CURC-EPRI Roadmap NOX target for 2020 by incorporating an SCR into their designs. In contrast, SCPC units may need additional technology improvements to meet the NOX target.13 For mercury, both IGCC and SCPC plants appear likely to need further control technology advances to achieve the 2006 CURC-EPRI Roadmap target for 2020.
UDBS “Environmental Design 1” levels are based on an IGCC plant using bituminous coal with a nitrogen diluent for combustion NOX control. The more stringent target levels in UDBS “Environmental Design 2” assume that SCR is added for post-combustion NOX control, and that deeper sulfur removal is accomplished within the acid gas clean-up system.
13 2006 CURC-EPRI Roadmap 2020 targets are available at http://www.coal.org/PDFs/performancetargets.pdf. The Roadmap is explained at http://www.coal.org/content/roadmap.htm
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The comparatively low levels of NOX emissions for the Negishi and Nuon IGCC plants are due, in part, to fuel and operational choices. In particular:
• The Negishi plant uses petroleum-based asphalt residue for feed and achieves low NOX emissions through use of SCR. SCR is not included in the 2004 IGCC baseline design because no coal-based IGCC has experience with SCR.
• The Nuon IGCC is coal-based, but it features a lower firing temperature combustion turbine than the one included in the baseline IGCC design. Because NOX formation is a strong function of firing temperature, the Nuon NOX levels are not indicative of the expected NOX emissions from the baseline IGCC design.
Thus these levels do not represent a valid baseline for coal-based IGCC.
The existing PC plants shown in Figure 2-5 were selected from the EPA’s emissions database for 2004 and represent the plants with the lowest reported emissions of SO2 (Navaho and Intermountain) and NOX (W.A. Parish).14 The SCPC emission levels in Table 2-5 are based on EPRI’s estimates of the capability of the emissions control technology selected for the baseline designs. Note that all of the plants shown in Figure 2-5 use low-sulfur coal (<0.6% by weight), with the exception of We Power’s Elm Road plant.
The Isogo units shown in Figure 2-5 feature J-Power’s ReACT multi-pollutant capture system, which is based on a regenerated moving bed of activated carbon.15 The Isogo units’ emissions, therefore, are not indicative of what would be expected from the baseline SCPC design, but they suggest that SCPC emissions could possibly decrease further than the levels in the baseline designs.
Impact of CO2 Capture
With CO2 emission regulations now in effect in many countries, much interest has developed in the capability to capture most of the CO2 produced by power plants. Implementing CO2 capture has a significant impact on the capital cost, operating cost, and efficiency of both IGCC and SCPC plants. However, SCPC suffers a greater loss in net efficiency and greater increase in COE because of the size of equipment required to treat flue gas at atmospheric pressure. For plants using bituminous coal, it appears that including CO2 capture may shift the cost-of-electricity advantage to IGCC units. For low-rank coals, the greater negative impact of adding CO2 capture to SCPC is not enough to shift the advantage to IGCC. The high inherent moisture in these coals heavily impacts IGCC thermodynamics and equipment sizing. DOE16 and International Energy Agency (IEA)17 studies recently estimated a cost of $30/ton of CO2 avoided 14 EPA now uses an online “emissions wizard” to help calculate these figures from their database; see http://cfpub.epa.gov/gdm/index.cfm?fuseaction=emissions.wizard. 15 ReACT = Regenerated Activated Coal Technology. See http://www.jpower.co.jp/entech_e/what.html for more information. 16 R.L. Schoff, J.D. Ciferno, V. Vaysman, and P.J. Barrett, “Updated Market-Based Advanced Coal Power Systems Comparison Study,” 22nd Annual International Pittsburgh Coal Conference, September 2005. 17 “Improvement in Power Generation with Post-Combustion Capture of CO2,” IEA Greenhouse Gas R&D Programme, Report PH4/33, November 2004.
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for future SCPC power plants using an advanced (yet-to-be-demonstrated) version of Fluor’s Econamine process. This represents significant improvement from prior estimates that placed SCPC capture costs at greater than $40/ton of CO2 avoided. Another IEA study18 estimated CO2 capture cost at $16/ton-CO2 for IGCC using a GE high-pressure, quench-style gasifier, whereas the cost of capture from a Shell IGCC with full heat recovery was $24/ton-CO2.
In addition to comparing the cost of CO2 avoidance on a $/ton basis, EPRI has examined the cost impact on a levelized COE basis. Figure 2-6 shows the 30-year levelized COE, with and without CO2 capture, based on data contained in DOE and IEA studies.16,17,18 COE values were calculated using the capital cost, O&M cost, and heat rates from the referenced studies, but EPRI modified all monetary values to reflect 2005 U.S. dollars (USD) and EPRI’s standard economic inputs for cost of coal, interest rate, capacity factor, etc. [Note: As a result, the values shown in Figure 2-6 differ from their sources.] Figure 2-6 also shows the estimated ranges of uncertainty in the COE values based on an assumed capital cost accuracy of +15/-5% (i.e., the actual capital cost may be 15% higher or 5% lower than the “bar height” value).
Figure 2-6 indicates that without CO2 capture, the COE for an IGCC plant is about 10% higher than the COE from an SCPC plant. The data also show that with CO2 capture an IGCC plant based on the GE quench gasifier will have a 5–10% lower COE than an SCPC plant with CO2 capture. In the case of an IGCC plant with a Shell gasifier, the COE is essentially at parity with an SCPC plant with capture, given the range of uncertainty in the COE estimates. [Note: Only capital cost uncertainty was included, not fuel cost uncertainty, which would broaden the COE uncertainty bands for all cases.] It should be noted that the IEA studies were based on a 1.1% sulfur (by weight) bituminous coal from Australia, whereas the DOE study used Pittsburgh #8 bituminous coal. Although not shown, analyses by the Canadian Clean Power Coalition, EPRI, and others for low-rank coal indicate that even with CO2 capture, SCPC plants may hold a COE advantage over IGCC plants.
18 R. Domenichini, “Potential for Improvement in Gasification Combined Cycle Power Generation with CO2 Capture,” IEA Greenhouse Gas R&D Programme, Report PH4/19, May 2003.
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49.6 52.045.7 46.1
11.616.3
21.3 19.0
0
10
20
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40
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GE IGCC Shell IGCC SCPC-IEA SCPC-DOE
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ear L
evel
ized
Cos
t of E
lect
ricity
, $/M
Whr
Without Capture Delta for Capture
Range of Uncertainty
Range of Uncertainty
Figure 2-6 Levelized COE from Bituminous Coal Power Plants with/without CO2 Capture $2/MMBtu coal; 85% Capacity Factor, 2005 USD, excluding emissions allowances and sequestration; based on data from recent IEA and DOE studies16,17
The COE values in Figure 2-6 reflect commercial designs similar to the “technology baselines” described above (~2004 technology) and projections for the with-CO2-capture plants based on the technology status of post-combustion capture processes. Improvements in technology should improve the absolute COE values over time and could change relative competitiveness as well. Table 2-6 summarizes some plausible expectations. As indicated, because PC technology is very mature, EPRI does not expect large decreases in its capital cost (although construction optimization holds promise). Conversely, CO2 capture technology for PC units (post-combustion or oxy-fuel) has never been implemented at the scale needed for a 500 MW plant. EPRI believes it has a significant potential for cost improvement over time.
The situation with IGCC is nearly the opposite. Although many improvements are expected in gasifier performance, combustion turbine performance, and plant integration, which will reduce cost, the CO2 capture options for IGCC units is relatively well proven. Eastman Chemical, Ube Ammonia, and Dakota Gasification, for example, have been using water-gas shift (WGS) followed by CO2 removal processes since the early 1980s. After upgrades completed in 2000, Dakota Gasification is now delivering CO2 for enhanced oil recovery. Many chemical plants (although not coal-based) use WGS. Selexol is used for CO2 capture and acid gas clean-up in over 30 commercial installations around the world.
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Table 2-6 Trends in Maturity and Cost of Plant Technology and CO2 Capture Technology
Base Plant Technology
Overall Technology Maturity
Capital Cost Trend for Plant
Technology
CO2 Capture Technology
Maturity
Capital Cost Trend for CO2 Capture
PC Very mature Not decreasing Very immature
Can expect reasonably steady,
perhaps large decreases in cost
IGCC Youthful, bordering on immature
Can expect decreases as more plants come online
Capture technology is mature, but
requires H2 fired CTs which are not yet
proven
Revolutionary process changes (e.g., membrane separation or fuel cells) are required for significant cost
reduction
Table 2-7 provides recent EPRI estimates of the impact of CO2 capture on capital cost for bituminous-coal-fueled IGCC plants. At 600 MW (net), these designs are based on two-train configurations using the currently offered 7FB-class CTs (and sharing a common steam turbine). By any measure, the incremental cost for CO2 capture is large, and programs to reduce capital costs for IGCC units with CO2 capture are a primary focus of the longer-term elements in the IGCC RD&D Augmentation Plan (see Chapter 4).
Figure 2-7 provides a graphical representation of the capital cost data in Table 2-7.
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Table 2-7 EPRI 600 MW (net) IGCC Capital Cost Estimates (January 2006 USD) All estimates are for bituminous coals (Illinois #6 & Pittsburgh #8) without spare gasifiers; probably -5%/+20% given the state of development and current cost environment
Gasification Technology
GE Radiant Quench
GE Total Quench
Shell Recycle Gas Quench
E-Gas Full Slurry Quench
TPC $/kW, no capture 1760–2220 1545–1950 1800–2275 1565–1975
TCR $/kW, no capture 2094–2642 1839–2320 2142–2707 1862–2350
TCR $ Millions, no capture
1323–1670 1090–1375 1328–1678 1140–1438
TPC $/kW, with capture 2200–2780 1942–2453 2630–3324 2152–2718
TCR $/kW, with capture 2618–3308 2311–2919 3130–3955 2561–3234
TCR $ Millions, with capture
1440–1826 1209–1527 1565–1978 1319–1665
1,200
1,400
1,600
1,800
2,000
2,200
2,400
2,600
2,800
3,000
3,200
3,400
No Capture WithCapture
No Capture WithCapture
No Capture WithCapture
No Capture WithCapture
Tota
l Pla
nt C
ost,
$/kW
(200
6$)
.
GE Radiant Quench GE Total Quench Shell Gas Quench E-Gas FSQ
Figure 2-7 EPRI 600 MW (net) IGCC Capital Cost Estimates (Bituminous Coal With and Without CO2 Capture)
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Table 2-8 summarizes the strengths and weaknesses attributed to current IGCC and SCPC technologies.
Table 2-8 Relative Strengths and Weaknesses of IGCC and SCPC Power Plants
IGCC Strengths IGCC Weaknesses
Reduced SO2 emissions, especially with higher sulfur coal; reduced Hg emissions with low-sulfur coal
Lower incremental COE impact for conversion to CO2 capture
Increased COE when CO2 capture is not required, especially with low-rank coals (with high inherent moisture)
Lower than desired availability
SCPC Strengths SCPC Weaknesses
Lower COE when implemented without CO2 capture, especially with low-rank coals
Operating experience with SCR which yields lower NOX emissions than current F-class coal-based IGCC plants that do not include SCR
Higher COE when CO2 capture is required with bituminous coal
Higher SO2 emissions, particularly on high sulfur coals. SCPC can meet all current U.S. emissions regulations for coal-based power plants.
Given these relative strengths and weaknesses, the CoalFleet IGCC RD&D Augmentation Plan focuses on improving the capabilities and economics of all facets of IGCC units with the possible exception of the CO2 capture process per se. In contrast, a significant portion of the CoalFleet Advanced Combustion RD&D Augmentation Plan focuses specifically on improving CO2 capture processes for USC PC and SC CFB units. For both technologies, optimizing designs to integrate CO2 capture processes is essential to capital cost and COE reduction.
Surveys to Identify Barriers to Deployment of IGCC Technology
In developing the IGCC RD&D Augmentation Plan, EPRI sought to “take the pulse” of the industry through a series of surveys targeted to both IGCC technology suppliers and prospective buyers (i.e., generating companies). The objective of the surveys was to uncover RD&D gaps—beyond those obtained by analyzing the worldwide programs summarized in Appendix C—as well as to get a sense of stakeholders’ priorities for the various RD&D needs. Tabulations of survey responses and analyses of results are provided in Appendix B.
IGCC suppliers nominated the following preferences for future RD&D:
• A 200 to 400 tpd gasification demonstration plant where multiple improvements could be tested in an integrated manner
• An integrated drying and gasification system for low-rank coals
• A hotter desulfurization process
• Demonstrations of technology improvements in early deployment IGCC units; otherwise improvements are unlikely to be included
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• Demonstration of single-train gasifier for a 600 MW IGCC
In a survey of real and perceived barriers to IGCC technology, prospective buyers agreed with IGCC equipment suppliers on the top three technical deterrents to IGCC deployment. The greatest two deterrents (capital cost, reliability/availability) were expected; the third one, operation and maintenance costs, was somewhat of a surprise. Contractual and financing issues were also cited as important to buyers and suppliers.
Representatives from generating companies noted that perceived risks versus benefits made it difficult to obtain internal approvals and, potentially, external financing for IGCC projects (given their capital cost premium), even with significant government incentives.
Respondents also noted the need for a mechanism to share risks for early adopters of new or scaled-up technologies. Larger combustion turbines, for example, are deemed to be an important factor in lowering capital costs and COE for IGCC units. However, G-class and H-class CTs are still in the early commercialization stage on natural gas and in the development stage on syngas. Generating company representatives noted the risk of the significant “birthing pains” that were experienced during the introduction of prior new CT models in IGCC units.
Existing “As Planned” IGCC RD&D Targeted for 2012
Before specific IGCC RD&D projects could be recommended for acceleration or augmentation in the CoalFleet plan, a list of IGCC and related RD&D efforts around the world was assembled and reviewed (see Appendix C). More than 120 projects were evaluated.
During this process, EPRI identified eight ongoing IGCC RD&D efforts that should have a meaningful impact on IGCC units built in the near term (commissioned by 2012). The potential impacts of these projects in terms of reduction in 30-year levelized cost-of-electricity were estimated for IGCC units employing four different coal gasification technologies (ConocoPhillips, GE Energy, KBR/Southern, and Shell) and two types of coal (Pittsburgh #8 bituminous, and Powder River Basin subbituminous). As shown in Table 2-9, the cumulative COE impact of the eight projects typically ranged from $3–6/MWh. The ongoing projects with the largest potential impact on IGCC economics are:
• Use of advanced F-class combustion turbines (e.g., the GE 7FB or Siemens SGT-5000F)
• Improved gasifier refractory
• Lower cost syngas coolers
Even with a $6/MWh improvement in COE from the 2004 baseline designs, EPRI’s comparisons of IGCC plants to conventional supercritical PC plants showed that IGCC units would still be more expensive in 2012 than SCPC units—hence the need for the IGCC RD&D Augmentation Plan. [Note: The tax and financing incentives included in the Energy Policy Act of 2005 could be sufficient in some cases to make IGCC units competitive with SCPC by 2012 or sooner. But if IGCC technology is to become competitive without government subsidies after 2012, more innovations and improvements must happen in the near-term (and over the long term) than are currently anticipated.]
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Table 2-9 Expected Levelized COE Impact ($/MWh) of Eight Current Near-Term IGCC RD&D Projects
Gasifier GE CoP Shell KBR Coal Pitts #8 PRB Pitts #8 PRB Pitts #8 PRB Pitts #8 PRB Advanced F-Class CT -3.20 Note 1 -2.96 -3.35 -3.19 -3.07 Note 1 -2.60Improved Gasifier Instrumentation -0.45 -0.39 -0.43 -0.43 -0.43 -0.18Improved Refractory -1.19 -1.06 -1.16 0.00 0.00 0.00IGCC Dynamic Models -0.45 -0.39 -0.43 -0.43 -0.43 -0.35Improved Feed Injectors -0.13 -0.13 -0.13 0.00 0.00 0.00Higher Gasifier Pressure 0.00 -1.48 -5.992 0.00 0.00 0.00Lower Cost Syngas Coolers -0.50 0.00 0.00 -1.54 -1.83 0.00CT Health Monitoring -0.23 -0.20 -0.22 -0.22 -0.22 -0.18Subtotal -6.15 -6.61 -11.71 -5.81 -5.98 -3.30 Note 1: Not evaluated because of lack of experience of gasifier technology with this coal type. Note 2: Large impact of higher gasifier pressure on CoP with PRB due to CoP’s 2004 assessment of need for 3 gasifiers at lower pressure to process PRB versus 2 gasifiers at higher pressure. For Pittsburgh #8, 2 gasifiers are assumed for both lower and higher pressure cases.
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3 IGCC RD&D AUGMENTATION PLAN OVERVIEW—NEAR-TERM
This chapter summarizes the near-term elements of the CoalFleet IGCC RD&D Augmentation Plan and tabulates associated potential benefits. RD&D projects or programmatic sets of projects are outlined for the near-term elements that—with full funding—should produce results ready for commercial application by 2012. Realization of these improvements in IGCC designs will deliver value not only to earlier deployers, but it will establish the technical foundation necessary for achieving the IGCC RD&D Augmentation Plan’s longer-term goals (see Chapter 4), including elimination of the barriers to competitive deployment of IGCC technology for the major new capacity additions forecast for the 2015–20 timeframe and for addressing potential CO2 capture requirements. The IGCC RD&D Augmentation Plan is also crucial to the industry’s ability to achieve the advanced coal power system goals for 2020 in the 2006 CURC-EPRI Roadmap.
Chapters 5 through 9 provide expanded descriptions of many of the technologies summarized in this chapter.
Overview of Near-Term Implementation Plan
The near-term projects in the IGCC RD&D Augmentation Plan focus on improving IGCC plant economics to the point of approximate cost parity with conventional SCPC plants by 2012. The projects and their projected impact on the 30-year levelized cost of electricity for IGCC plants are listed in Table 3-1 and Table 3-2.
The projects listed in Table 3-1 are considered “broadly applicable,” because they can be used in virtually any commercial gasification technology. The projects in Table 3-2 are classified as “technology specific” because they are only applicable to certain types of gasification technologies, although they are important in achieving overall IGCC cost reduction goals. As an example, refractory with a service life extended to 24,000 fired hours will only benefit gasifiers that are refractory-lined.
The COE reduction values in both Tables 3-1 and 3-2 indicate potential savings if the projects are successfully implemented and achieve their expected improvements in capital cost, heat rate, availability, and/or O&M cost. The accumulated total of all the expected impacts ranges from $8/MWh to $10/MWh. However, EPRI does not expect that every project will achieve 100% of its potential benefits.
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Table 3-1 Potential Levelized COE Impact of “Broadly Applicable” Near-Term Projects in the IGCC RD&D Augmentation Plan
Gasifier GE CoP Shell KBR
Coal Pitts #8 Pitts #8 PRB Pitts #8 PRB PRB
COE Impact of RD&D Project if Successful
$/MWh $/MWh $/MWh $/MWh $/MWh $/MWh
G-Class CT -2.92 -2.50 -2.66 -2.89 -2.83 -2.38
Supplemental Firing / HRSG Optimization -1.61 -1.37 -1.61 -1.60 -1.71 -1.43
IGCC Dynamic Models -0.90 -0.78 -0.86 -0.86 -0.86 -0.70
IGCC RAM Database -0.90 -0.78 -0.86 -0.86 -0.86 -0.70
Minimize S/U and S/D Length -0.50 -0.50 -0.50 -0.50 -0.50 -0.10
Improved Gasifier Instrumentation -0.45 -0.39 -0.43 -0.43 -0.43 -0.18
Reliable pH Meters for Black & Grey Water Streams
-0.08 -0.08 -0.08 -0.08 -0.08 -0.08
CT Health Monitoring -0.23 -0.20 -0.22 -0.22 -0.22 -0.18
Improved Gasifier Models -0.13 -0.13 -0.13 -0.13 -0.13 -0.13
Recover ASU & Air compressor heat -0.24 -0.24 -0.24 -0.24 -0.24 -0.24
Construction Optimization -0.20 -0.20 -0.20 -0.20 -0.20 -0.20
Subtotal -8.16 -7.17 -7.79 -8.01 -8.06 -6.31
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Table 3-2 Potential Levelized COE Impact of “Technology Specific” Near-Term Projects in the IGCC RD&D Augmentation Plan
Gasifier GE CoP Shell KBR
Coal Pitts #8 Pitts #8 PRB Pitts #8 PRB PRB
COE Impact of RD&D Project if Successful
$/MWh $/MWh $/MWh $/MWh $/MWh $/MWh
24,000 hr Refractory -1.12 -0.99 -1.09 N/A N/A N/A
8000 hr Feed Injectors -0.13 -0.13 -0.13 N/A N/A N/A
16,000 hr Dry Solids Filter Elements N/A -0.13 -0.13 N/A N/A -0.13
Decreased Syngas Cooler Fouling -0.21 -0.59 -0.65 N/A N/A N/A
Cl-Resistant COS Hydrolysis Catalyst N/A -0.04 -0.04 -0.04 -0.04 -0.04
Great River Energy Coal Drying Process N/A N/A N/A N/A -0.70 -0.70
Dry Solids Feed Pump (based on Stamet) N/A N/A N/A -1.16 -1.17 -1.09
Continuous Slag Let-Down Unknown N/A N/A Unknown Unknown N/A
Subtotal -1.46 -1.88 -2.04 -1.20 -1.91 -1.96
Benefits versus Cost Estimates for Near-Term Elements of the IGCC RD&D Augmentation Plan
Figure 3-1 plots anticipated benefit against anticipated RD&D costs to achieve each near-term technology goals. [Note: The RD&D cost estimates are coarse, with an accuracy not better than a factor of 2 (i.e., +100/-50%); nonetheless, the estimates help to gauge the relative magnitudes of funding that would be required for each project.] The RAM Improvement Initiative and Use of HRSG Supplemental Firing Technology goals fall in the upper left quadrant, with the best estimated benefit-to-cost ratios (i.e., low development costs and large COE impacts). Benefit-to-cost ratios decrease rapidly as one moves right on the logarithmic “Cost” scale. On the right half of the chart, only projects with significant COE impact and/or critical impact on other operating parameters are likely to be justified. The significant item in this category is the RD&D budget for G-class CTs, which is based on the assumed cost of an IGCC demonstration plant with a single G-class CT that will be used for development and testing to optimize syngas combustion hardware.
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0.00
0.50
1.00
1.50
2.00
2.50
3.00
3.50
1.0E+05 1.0E+06 1.0E+07 1.0E+08 1.0E+09
Research, Development & Demonstration Cost ($)
Pote
ntia
l Sav
ings
in L
evel
ized
Cos
t of E
lect
ricity
, $/M
W-h
r
Upper EstimateLower Estimate
G class CT
HRSG Duct Firing
IGCC Simulator
RAM Improvement
Gasifier Instrumentation
CT MonitoringGasifier Models
Optimized Construction
Gasifier Refractory
ASU Heat Integration
Improved Filters
Reduce fouling
GRE coal dryer
Dry solids pump
Figure 3-1 Cost-of-Electricity Impact versus Estimated RD&D Cost for Near-Term Projects in the IGCC RD&D Augmentation Plan
Implementation Path for Near-Term Elements of the IGCC RD&D Augmentation Plan
For each element designated near-term in the IGCC RD&D Augmentation Plan, EPRI has identified the most appropriate entity or entities for leading the proposed project (see Table 3-3). As shown, technology suppliers are clearly the most appropriate entities for projects that involve highly proprietary technology, such as improvement of gasifier feed injectors. For projects of a more fundamental nature, especially large projects with a significant public good component, government entities such as DOE may appropriately take the lead role. For projects that will yield technology that could be widely applied by all IGCC suppliers and buyers, an industry-led RD&D collaborative is a logical approach.
Collaborative RD&D efforts, such as those managed by EPRI, provide a way to share the cost of technology development among all the stakeholders who will benefit from a technology. In addition to serving as a vehicle for aggregating funding for these collaborative efforts, EPRI’s implementation of this augmentation plan facilitates communication to help technology developers, technology users, and government RD&D sponsors gain a common understanding of research priorities.
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Table 3-3 Recommended Lead Organizations for each Element in CoalFleet Near-Term IGCC RD&D Augmentation Plan
RD&D Project Recommended Lead Organization(s)
G-Class CT CT OEMs and Government (e.g., CCPI project)
Supplemental Firing Collaborative
IGCC RAM Database Collaborative
IGCC Dynamic Models Government and Collaborative
Minimize S/U and S/D Length Collaborative
Improved Gasifier Instrumentation Government and Collaborative
CT Health Monitoring CT OEMs & Government
Improved Gasifier Models Gasifier Suppliers and Collaborative
Construction Optimization IGCC Supplier Alliances and Collaborative
24,000 hr Refractory Refractory Suppliers, Gasifier Suppliers, and Government
8000 hr Feed Injectors Gasifier Suppliers
Recover ASU & Air Compressor Heat Collaborative
16,000 hr Dry Solids Filter Elements Filter Suppliers, Gasifier Suppliers, and Government
Decreased Syngas Cooler Fouling Gasifier Suppliers, SGC OEMs, and Government
Cl-Resistant COS Hydrolysis Catalyst Catalyst Suppliers
Low-Rank Coal Drying Process GRE, Dryer and Gasifier Suppliers, and Government/Collaborative
Stamet Dry Solids Pump Stamet, Gasifier Suppliers, and Government
PWR Dry Solids Pump PWR and Government
Continuous Slag Let-Down Gasifier Suppliers
Near-Term RD&D Projects with Broad Applicability
As shown in Table 3-1, many of the recommended RD&D augmentation projects will yield results applicable to virtually all of the major gasifier technologies, and are therefore categorized as having a broad impact. Other projects (see Table 3-2) have important but narrower impacts.
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G-Class CTs
Technology enhancements for combustion turbine-generators generally focus on improving heat rate and improving generator output. “G-class” CTs, which were introduced to commercial operation on natural gas a few years ago, are distinguished by their larger size and use of steam-cooled stationary components (e.g., transition pieces) in the power turbine. Along with improvements in blade materials and other design refinements, this cooling allows G-class combustion turbines to operate at higher firing temperatures than the prior “F-class” machines. Further, the cooling steam returns heat to the steam cycle, reducing some of the thermal as well as parasitic losses accompanying air cooling in the F-class CTs. For the generator, no significant improvement is expected, as the largest generators for CTs are still much smaller than those used in steam turbine-generator applications.
A heat rate improvement of 1 to 2 percentage points is expected for the three G-class CTs that are currently on the market: Mitsubishi Heavy Industries’ (MHI) M501G (60 Hz) and M701G (50 Hz) and the Siemens SGT6-6000G. A further $/kW improvement, in comparison to systems based on F-class CTs, results from the economies of scale inherent in the increased power output for the G-class CTs. For example, a single-train IGCC based on a Siemens SGT6-5000F is expected to produce about 315 MW at ISO conditions, whereas a single-train IGCC based on the SGT6-6000G should produce about 400 MW.
The expected savings of $2.50–3.00/MWh shown in Table 3-1 (which are relative to currently offered units with 7FB CTs) are based on an assumption that a single gasifier can be scaled up to provide the syngas to fully fire one G-class combustion turbine. This will require an increase in gasifier size of approximately 33% over currently proven sizes. EPRI believes that this should not pose a significant technology risk.
Further discussion of advancements in CT technology, and their impacts, is presented in Chapters 4 and 5.
Supplemental Firing and Steam Cycle Optimization
Many natural gas combined cycle power plants increase the power output of the steam cycle with supplemental firing (or duct firing) via burners in the inlet duct of the heat recovery steam generator. The increased heat content and temperature of the CT exhaust gas allow for increased steam production which can be used to serve a cogeneration load or to increase the power output from the steam turbine-generator.
Plant modifications can range from simple installation of duct burners to reconfiguration of the HRSG and significant increases in the size of the steam turbine-generator, condenser, and cooling water system. In the most elaborate application, supplemental firing can fully exploit the excess oxygen in the CT exhaust and nearly double the net output of a combined cycle power plant. In some systems, an increase in steam temperature and/or pressure also increases the thermal efficiency of the steam cycle.
Research efforts addressing supplemental firing and steam cycle optimization will focus on determining the best design paths for optimizing the overall economics of the plant. Numerous
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variations of the basic concepts may be used to reduce the $/kW cost and increase the operating range of IGCC plants. These variations may:
• Provide peaking capacity. Because duct firing consumes fuel at a higher heat rate than when it is used to fire the CT, it most typically is used only to meet peak demand. However, capacity can often be increased with supplemental firing at a lower capital cost than alternative sources of peaking capacity (such as simple-cycle CT peaking units). In service, supplemental firing can often be placed on-line faster and with a lower heat rate than other sources of peak power.
Additional savings accrue through reduced maintenance costs and charges against emissions caps when startup of additional CT/HRSG trains or CT peaking plants can be avoided or performed more gradually.
• Exploit excess gasifier capacity. Implementation of duct firing may utilize excess gasifier capacity to increase peak power output when there is an intentional or coincidental mismatch between the capacity of the gasifier and CT fuel requirements.
Duct firing may use excess gasifier and steam turbine capacity when a CT/HRSG train is out-of-service. Duct firing can also be used to optimize timing of turbine starts and stops in a multiple train system.
Duct firing may also be used to exploit a secondary gas stream at lower quality than is required for the CT or at a lower pressure, which would require compression for use in the CT.
• Provide a substantial increase in plant capacity without the cost of adding a CT/HRSG train. Net plant output and operating flexibility can be increased by increasing gasifier, duct burner, HRSG, and ST capacity.
Steam cycle efficiency can be increased, along with capacity, by using duct firing with a modified HRSG design that allows increased steam temperature and/or pressure.
When gasifier capacity is increased with the addition of a full-sized gasifier train, the CT can operate at full power when one gasifier train is undergoing maintenance. This is equivalent to using a spare gasifier for extra production rather than letting it remain idle.
The concept patented by NovelEdge Technologies LLC aims to further reduce capital cost by simplifying the steam system from three pressures to a single drum while providing enough supplemental firing to double or triple the steam cycle output. NovelEdge claims that its patented innovations also minimize the increase in heat rate during maximum supplemental firing.19
Chapter 6 provides further discussion of these concepts, along with diagrams and explanation of the NovelEdge approach. Also, the various supplemental firing concepts have the potential to offer future benefits, such as improving net efficiency by enabling supercritical steam cycles and reducing net CO2 production should CO2 capture be required.
19 D. Heaven and W. Rollins, “NovelEdge IGCC Reference Plant: Cost & Emissions Reduction Potential,” Gasification Technologies Conference, Washington, DC, October 2004.
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Improved IGCC Dynamic Models
Dynamic models can be used several ways to help improve the availability of IGCC units, particularly during the first years of operation.20 During the plant design phase, a dynamic model can be used to test the design of the plant’s control system by providing realistic, real-time process data to which the control system can respond. Dynamic models can also be used to drive simulators for operator training before the IGCC is operational. Once the plant is running, a dynamic model can be used to predict the proper control settings when new feedstocks are introduced or new operating modes are proposed.
The COE impact estimates in Table 3-1 derive from an estimated average availability improvement of 2 percentage points over the life of an IGCC that would be achieved with use of a state-of-the-art dynamic simulator (i.e., improved over the dynamic models resulting from the ongoing RD&D reflected in Table 2-9). To be broadly applicable, a model must be flexible enough to be adapted to various IGCC configurations (i.e., different types of gasifiers and different types of gas turbines). The recommended project would augment ongoing work in the development and demonstration of IGCC dynamic models, particularly the DOE work initiated in 2005.
IGCC RAM Database
Improvement of IGCC reliability, availability, and maintainability (RAM) is the most fundamental achievement needed for IGCC technology to become more competitive and more readily accepted in the marketplace.
As former New York City mayor Ed Koch observed, “What gets measured, gets improved.” One cannot fully understand or substantially improve IGCC RAM without access to accurate, consistent, and broad-based data that document the factors that decrease reliability and availability by increasing the frequency and duration of maintenance activities in IGCC plants. Unfortunately, there are currently no formal mechanisms for acquiring and tracking IGCC RAM data.
EPRI is recommending initiation of a project aimed at creating the framework to capture and compile such data and to begin populating a database with historical RAM data from existing IGCC units. The recommended project would augment ongoing work by Syngas Consultants Ltd. and Strategic Power Systems Inc.21 EPRI estimates that this project would result in an improvement in availability of 2 percentage points for IGCC plants commencing operation after 2010. This would decrease the levelized COE by $0.70–0.90/MWh.
20 J. McDaniel, “Polk Integration Issues,” PowerPoint presentation, EPRI CoalFleet workshop, Indianapolis, April 2005. 21 C. Higman and S. DellaVilla, “The Reliability of Integrated Gasification Combined Cycle Power Generation Units,” Gasification Technologies Conference, San Francisco, October 2005.
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Minimizing Startup and Shutdown Length
A fundamental limitation of IGCC is the extended startup sequencing required to ensure stable operation of the gasification system prior to delivery of syngas to the CT fuel system. Similarly, IGCC requires a lengthy shutdown sequence to ensure proper purging and prevent fouling. The extended use of auxiliary power and inefficient use of fuel during startup and shutdown can increase the annual average heat rate of an IGCC plant by as much as 1000 Btu/kWh over the full load design value.22 The economic impact of this inefficiency is an increase in levelized COE of up to $1.50/MWh.
EPRI proposes a project aimed at reducing the cost of startups and shutdowns by minimizing their length and associated auxiliary power consumption. This project would target a 333 Btu/kWh decrease in the difference between annual average and design full load heat rate, which would reduce the levelized COE by $0.50/MWh.
The first phase of this proposed RD&D program would be an international workshop bringing together gasification plant operating staff to discuss best practices related to minimizing the length of startups and shutdowns and ASU auxiliary power consumption during those events. A secondary purpose of the workshop would be to identify RD&D for items needed to improve startup and shutdown operations.
The second phase of the program would address the RD&D items identified at the workshop. It is anticipated that some items would involve improved control strategies that could be developed with assistance from EPRI’s Instrumentation & Control Center and could be demonstrated at existing IGCC plants. Items related to ASU equipment would likely require the participation of one or more major ASU suppliers.
Improved Gasifier Instrumentation & Control
Many unplanned gasifier outages can be traced to changes in the quality and quantity of coal being fed to the gasifier. Most commonly, changes in the quantity and composition of ash change the flow of slag within and exiting the gasifier. Improved instrumentation and control for monitoring key process variables could prevent many, if not all, of these unplanned outages. In addition, for refractory-lined gasifiers, improved on-line monitoring of the integrity of the refractory could prevent unnecessary shutdowns for off-line inspection of the refractory.23
Based on the operating history of the four commercial-scale coal IGCC plants, availability could be improved by up to 1 percentage point through better monitoring and control of gasifier and slag operating conditions. [Note: This is in addition to the predicted benefit from ongoing RD&D reflected in Table 2-9.] Table 3-1 shows a smaller improvement for KBR’s Transport Reactor, as this type of non-slagging gasifier should have inherently fewer slag-related outages.
22 J. McDaniel, “Polk Integration Issues,” PowerPoint presentation, EPRI CoalFleet workshop, Indianapolis, April 2005. 23 J.N. Phillips, “I&C Needs of Integrated Gasification Combined Cycles,” 15th Joint ISA POWID/EPRI Instrumentation and Controls Conference, Nashville, June 2005.
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The most beneficial I&C improvements are expected to include the following:
• On-line monitoring of refractory wear
• Reliable optical access to the gasifier
• On-line coal quality analysis
• Rapid, on-line measurement of syngas composition using laser absorption spectroscopy
• Reliable gasifier temperature measurement
• On-line slag composition analysis, slag viscosity measurement, and/or slag thickness measurement
Appendix D contains an EPRI-ISA conference paper describing these improvement needs and the associated potential benefits.
Each of the improvements would first be tested in a simulated gasifier environment or pilot plant to verify the performance and reliability of the equipment. If successful, the technology would be packaged and installed for demonstration at a commercial gasification facility. The work recommended in the IGCC RD&D Augmentation Plan would locate appropriate expertise for developing or refining the desired I&C devices and algorithms, coordinate communication between IGCC plant personnel and I&C development firms to define requisite performance criteria and facilitate testing of design prototypes, and develop guidelines for appropriate implementation of the new systems.
Reliable pH Meters for Black & Grey Water Systems
Several IGCC plants have experienced unplanned outages due to corrosion and erosion failures and plugging of the black and grey water piping that carries mixtures of slag, ash, and water with high dissolved solids content. It is expected that better pH control would substantially reduce failures related to plugging, formation of hard mineral scales, under-deposit corrosion, and/or erosion-corrosion interaction. In existing plants, pH monitoring is compromised by a lack of adequate instrumentation for monitoring pH at the temperature and pressure of the circulating flows and with the added challenges of high loading of dissolved solids, erosive solids, and organic constituents.
Based on the operating history of the four commercial-scale coal IGCC plants, implementation of reliable pH monitoring would lead to an availability improvement of up to 0.2 percentage point. This availability improvement would lower the levelized COE by $0.08/MWh. A further decrease in COE would accrue through a reduction in maintenance costs.
The IGCC RD&D Augmentation Plan’s recommendation for this project calls for at least two companies with expertise in pH monitoring probes to develop probes specifically designed for operation in slag/ash circulating water loops of an IGCC. The probes would be tested side-by-side at a commercial IGCC unit. Additional analytical lab work would be required to verify the accuracy of the pH meters over a period of one year of operation.
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Combustion Turbine Health Monitoring
Recent experience at the four commercial coal-based IGCC units has shown the combustion turbine to be the most significant cause of operating time lost to unscheduled outages (see CCU, combined cycle unit, in Figure 3-2). Catastrophic failures of blades have caused outages of up to 100 days. Overall, the forced outage factor for IGCC units has been much higher than that for natural gas fired combined cycles (see Figure 3-3). The scheduled outage factor has been much lower because planned maintenance has been performed during forced outages and gasifier outages.
Figure 3-2 Unplanned Outage Time by Major Plant Subsection for the Four Coal-Based IGCC Units During 2001–0324
24 C. Higman, “Gasification Plant Reliability,” EPRI CoalFleet workshop, Birmingham, AL, November 2005.
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2.3%
3.7%
1.2%
4.3%
2.2%
6.8%
0%
2%
4%
6%
8%
10%
Aeroderivatives Mature Class F Class
Simple Cycle Plant Forced Outage Factor and Scheduled Outage Factor
2000 - 2005ORAP Data
Forced Outage Factor (%) Scheduled Outage Factor (%)
Figure 3-3 Forced and Scheduled Outage Factors for Natural Gas and Liquid Fired Combustion Turbines in the ORAP Database25
The fact that natural gas fired combined cycles have not, on average, experienced CT component failures to the same extent as IGCC combined cycles has been attributed to the small number of IGCC units tending to have early commercial units of given CT models. Accordingly, some of their CTs tend to be fleet leaders in terms of fired hours. This has led to “first-of-a-kind” failures in the IGCC CTs which served as the impetus for design modifications that could be implemented, during later scheduled outages, to prevent similar failures in natural gas-fired combined cycle units.
Still, the disappointing track record of IGCC CTs underscores the need for better diagnostic monitoring systems, especially for early vintage CTs, which could alert operators to impending failures before they become catastrophic and cause long unscheduled outages.
The estimated benefits for this project, as shown in Table 3-1, are based on a very modest 0.5 percentage point improvement in IGCC availability (beyond that resulting from the ongoing RD&D reflected in Table 2-9). This can be achieved by supporting the CT health monitoring development efforts of CT OEMs, who know their machines better than anyone else.
25 S.A. DellaVilla and T.M. Christiansen, “Gas Turbines Meet Owner Objectives,” Turbomachinery International, November/December 2004.
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Improved Computer Modeling of Gasifiers
A significant challenge for IGCC development has been predicting the actual conversion performance for new gasification projects. Even when a prior, proven technology has been used, gasifiers have experienced unexpected differences in performance compared to earlier gasifiers of the same technology. For example, the GE gasifier at TECO Energy’s Polk station produced a COS/H2S ratio that was twice as high as the smaller but similar Cool Water gasifier. This caused higher sulfur levels in the clean syngas than had been anticipated during design, which required a retrofit installation of a COS hydrolysis system. The Nuon Buggenum IGCC unit, which uses a Shell gasifier, suffered the opposite impact, with installed flyslag recycle equipment turning out to be unnecessary. In this case, the gasifier produced flyslag with much lower carbon content than the flyslag from the Shell pilot SCGP-1 gasifier. Elcogas, which also employs a Shell gasifier, had a similar result, with flyslag at 5% carbon by weight instead of the expected 10–40% carbon by weight.
A better understanding of the fundamentals of high-pressure coal gasification reactions would help improve performance prediction for new coal gasifiers. Although gasification technology suppliers are using advanced computational fluid dynamics (CFD) software and other tools to improve gasifier modeling capabilities, there is still much to be gained through both independent and joint efforts to improve understanding of reaction fundamentals and modeling.
Research in this area is being performed by Stanford University, Reaction Engineering Inc. (REI), Brigham Young University, Niska Energy Associates, and other organizations. Unfortunately, DOE has not funded research on gasification fundamentals and the scope and pace of the current work is less than that needed to produce timely “actionable information” for designing gasifiers.
In particular, there is a need to translate basic reaction rate data into a reactor model that can predict carbon conversion and sulfur speciation under typical conditions in a commercial gasifier. One possible path to success is to incorporate reaction rate data into a CFD model of the gasifier. The IGCC RD&D Augmentation Plan proposes a program to develop usable models and to test those models against actual performance data from commercial gasifiers. The four organizations mentioned above, and others, would be invited to submit project proposals and funding requests to EPRI.
The potential benefits of such efforts are difficult to quantify with specificity. However, the cost of adding the COS hydrolysis to TECO Energy’s Polk IGCC plant is probably indicative. The DOE final report on the Polk IGCC plant identifies this cost as $3 to $4 million, which corresponds to approximately $0.13/MWh.
Recover Air Separation Unit (ASU) & Air Compressor Heat
About 8% of the energy in the coal fed to an oxygen-blown IGCC plant is rejected to cooling water in the intercoolers in the main air compressor (MAC) and in the oxygen compressors.
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Previous EPRI studies have shown that about 50% of this energy can be returned to the steam cycle by using it to heat condensate.26
A recent joint study by Jacobs Consultancy and Nuon indicated that use of a non-intercooled main air compressor would provide better heat recovery options than an intercooled MAC as the temperature of the air entering an aftercooler would be 700ºF (370ºC) or hotter, which would allow for medium-pressure steam production. The study’s authors indicated this would yield an additional 5 MW for a nominal 250-MW IGCC.27
The overall plant efficiency would increase by about 0.8% if the net power increases by 2%. The value of a 0.8% improvement in thermal efficiency is $0.24/MWh, which is shown in Table 3-2.
This analysis assumed that the KBR gasifier will be air-blown and therefore would not include an ASU. However, a KBR system does require a large air compressor, using extensive intercooling, and should also benefit from the same concepts developed for the MAC of an ASU.
The IGCC RD&D Augmentation Plan recommends a straightforward engineering analysis of the heat to be captured, identification of the optimal place for utilizing this heat in the cycle, estimation of the cost of the required equipment, and estimation of the impact on the compressor design, cost, and power consumption that would result from eliminating intercooling. IGCC developers could then judge whether the heat recovery from intercoolers or from non-intercooled compressors would be economically favorable.
IGCC Construction Optimization
The IGCC RD&D Augmentation Plan recommends using engineering practices already employed by the nuclear power industry to compress the construction schedule and improve design and construction methods for IGCC plants.
A shorter construction schedule would reduce the “total capital requirement” for the plant by decreasing interest payments for funds used during construction. If the compressed schedule is accomplished by more efficient construction methods (as opposed to just having more people on the construction site at the same time), there would also be a reduction in labor costs. EPRI-sponsored studies on new nuclear plant construction schedules have shown that the construction time can be compressed by at least 10% using such techniques as “4-D virtual reality” model of the plant under construction.28
26 Advanced Air Separation for Coal Gasification Combined Cycle Power Plants, EPRI report AP-5340, August 1987.
27 E. Goudappel and M. Berkhout, “IGCC Based on Proven Technology Developing Towards 50% Efficiency Mark,” 7th IChemE European Gasification Conference, Barcelona, April 2006.
28 4-D Virtual Construction of the AP600 and AP1000 Plants, EPRI report 1002995, 2002.
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It seems reasonable to assume that a first-of-a-kind or second-of-a-kind IGCC plant would also benefit from similar construction efficiency techniques. Table 3-1 data are based on the premise that an IGCC plant would normally take 36 months to construct and that by using construction optimization methods this could be reduced by 10%. Shortening the construction time from 36 to 32.5 months would lower the levelized cost of electricity by $0.18/MWh due to less interest paid during construction. This does not include any benefits from a reduction in labor costs.
The proposed RD&D program would include a construction efficiency analysis similar that to conducted for advanced nuclear plant designs. Such an analysis should be completed before an early IGCC deployer begins construction.
Near-Term Technology-Specific RD&D Projects
The applicability of each project in Table 3-2 is likely to be limited to plants based on specific gasifier types. Nonetheless, these projects are essential to improving the cost and performance of IGCC generation technology overall.
24,000 hr Gasifier Refractory
This project aims to develop better refractory for use in the hot face of a refractory-lined gasifier so that the interval for refractory replacement can be extended from the current 12–18 months to 36 months or more. This would allow refractory replacement to be on the same schedule as the combustion turbine hot section overhaul. CT hot-section overhauls usually require 6 weeks of outage time, so no additional outage time would be required for the refractory change out.
If this goal could be achieved, gasifier availability would increase by 2.5 to 5.0 percentage points and the motivation for a spare gasifier would be eliminated. [Note: About half this improvement is attributed to the ongoing RD&D reflected in Table 2-9, and half the the recommendations for augmented RD&D in Table 3-2.] The reduced frequency of refractory replacement would save about $1 million per change-out (including materials and labor).29
DOE’s Albany Research Center has developed an improved refractory based on chromium oxide (Cr2O3). A test program for this refractory in commercial gasifiers is well under way. It is too early to tell whether the Albany Research Center refractory will be able to achieve the goal 24,000 fired hours, but at present this is the only refractory RD&D effort of this magnitude. EPRI believes it is important to have more than one alternative in development for long-life refractory.
Chapter 7 describes EPRI’s recommended RD&D augmentation program, which focuses on developing a non-Cr2O3 alternative that can achieve the 24,000 fired hour goal.
29 S.J. Clayton, et al., Gasification Technologies, U.S. Dept. of Energy Report DOE/FE-0447, Germantown, MD 2002.
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8000 hr Feed Injectors
The feed injectors for slurry-fed gasifiers (sometimes called “burners” because they mix coal and oxidant together) are subject to very severe duty. Both GE and CoP gasifiers experience significant maintenance expense for feed injectors, which require replacement as often as once every two months.
Conversely, feed injector life is not a major concern for dry-feed Shell gasifiers, which have proven feed injector life greater than 16,000 hours. And the KBR transport gasifier does not have injectors in which coal and oxidant are injected and mixed together.
TECO Energy staff at Polk Power Station report that feed injector replacement does not negatively impact gasifier availability because the injectors can be replaced in a “hot swap out” manner. Eastman has reported that in addition to the cost of the injectors, it is necessary to always have three extra maintenance personnel on-shift to conduct a swap out, if needed.30 The COE impact in Table 3-1 is based on an assumed total savings of $900,000 per year for a nominal 600 MW IGCC, with the improved feed injectors requiring only one change-out per gasifier per year. This is in addition to the benefit predicted in Table 2-9 from ongoing RD&D. As EPRI does not have access to feed injector cost data, actual savings may be greater or less than this estimate.
EPRI believes that gasifier OEMs are the most appropriate entities for developing improved designs to achieve an 8000 hour burner life. As the design of feed injectors is a fundamental element of these gasification technologies, it is therefore quite proprietary. EPRI has included this project in the IGCC RD&D Augmentation Plan in order to highlight the need for this improvement.
16,000 hr Dry Solids Filter Elements
The porous metal filter elements used in current gasifiers provide consistently reliable performance, but must be replaced after 8000 to 10,000 operating hours due to corrosion-based deterioration. Although porous ceramic filter elements have performed less reliably, one IGCC application (Nuon’s Buggenum plant) has experienced filter life exceeding 16,000 hours before replacement was required. If either the corrosion properties of porous metal filters or the reliability of porous ceramic filters could be improved, the length of time between filter element replacements could be extended to 16,000 operating hours without an adverse impact on unit availability.
Extending the life of a set of filter elements from 8000 operating hours to 16,000 operating hours would save an average of $500,000/yr in O&M costs for a 250 MW IGCC (which is equivalent to $0.13/MWh).
30 N. Moock, Eastman Gasification Services, personal communication, July 2005.
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DOE has sponsored the installation of a slipstream unit for testing filter elements at the Wabash River IGCC. It is recommended that an industrial consortium sponsor tests of candidate filter elements and their sealing mechanism (a key part for ceramic filter elements) to verify their ability to operate for more than 20,000 hours. A parallel program could be conducted at the Elcogas IGCC power plant, where ceramic filter elements are currently used but have not been able to achieve 16,000 hours of life.
The IGCC RD&D Augmentation Plan also recommends assisting a major filter element supplier who has developed a novel filter element cleaning process requiring much lower pressure pulse gas. This approach could reduce the stress on ceramic elements and sealing mechanisms, with the hope of extending their life. The supplier would like to test this new process in a commercial IGCC plant. The Wabash River slipstream unit appears to be a logical candidate for such a test, but additional money may be required to modify it for the novel cleaning process. And it may not be desirable to conduct the test of the novel cleaning process in parallel with the tests of candidate filter elements. Consequently, a second location for such a test should also be investigated.
This project is not applicable to GE Energy IGCC plants because GE’s reference plant design does not include a dry solids removal step. It is also not relevant for the Shell IGCC design, as that process has already achieved 16,000 hour filter element life at the Nuon IGCC unit.
Decreased Syngas Cooler Fouling/Plugging
Fouling and plugging problems in the syngas cooling systems have been a major cause of unplanned downtime and a significant contributor to unreliability in water-slurry fed IGCC plants. This has been a problem for GE IGCC plants at Cool Water and Polk and in E-Gas IGCC units at Plaquemine and Wabash River. The dry-fed Shell IGCC plants have avoided the problem by using recycled gas to quench the syngas to below 1400ºF (760ºC) and by using mechanical rappers to keep the heat transfer surfaces clean. It is not yet well understood as to why these two approaches (water slurry-fed and high-temperature heat recovery versus dry-fed and rapid quenching of high-temperature syngas followed by moderate temperature heat recovery) have had fundamentally different experiences.
The Polk IGCC plant currently averages 5% annual loss in availability due to fouling and plugging of the convective section of the syngas cooler. As a result, GE has omitted the convective syngas cooler from its new reference plant design, increasing the heat rate of the reference plant by 225 Btu/kWh while saving $11/kW in capital cost. For the GE technology, development of a non-fouling convective syngas cooler (which did not negatively impact IGCC availability) would allow a reduction of $0.21/MWh in the levelized COE, assuming a heat rate improvement of 225 Btu/kWh and capital cost of $11/kW.
At Wabash River, availability has been reduced by an annual average of 1.5 percentage points due to outages resulting from fouling issues with the firetube syngas cooler. An availability increase of 1.5% would reduce the COE by the amounts shown in the CoP columns of Table 3-2.
EPRI believes that the primary cause of this fouling is deposition of condensable solids and particulate matter on the heat transfer surfaces. Development of high-reliability syngas cooling
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systems will require an improvement in the fundamental understanding of the condensation phenomena and the role that particulate matter plays in the process.
In addition to research into the basic phenomena, the recommended multi-task program would:
• Develop computer models that simulate the flows, temperatures, and condensation phenomena experienced in syngas cooling systems.
• Use the computer models as the basis for the design of test rigs that could be installed in slipstream units at existing IGCC plants.
• Use the test installations to validate the models or provide data that could lead to better models.
When the models become capable of accurately predicting the conditions under which deposition would occur, and the locations of those deposits, they could be provided to syngas cooler designers for use in developing coolers that would not adversely affect unit reliability.
Chloride-Resistant COS Hydrolysis Catalyst
All of the IGCC designs shown in Table 3-1 use a COS hydrolysis catalyst to convert COS to H2S in order to improve sulfur capture efficiency in the AGR system. However, the current COS hydrolysis catalysts are poisoned by chlorides. To avoid chloride poisoning, the syngas is washed with water before entering the catalyst. Because this washing process lowers the syngas temperature below the optimum for the hydrolysis reaction, the washed syngas must then pass through a “feed-product” heat exchanger and/or a steam-heated pre-heater to raise the temperature.
The hydrolysis step can also produce some NH3 via the reaction of HCN with H2O. An additional washing step is therefore required downstream of hydrolysis to remove the ammonia.
For the three gasification designs using a dry solids removal step (i.e., all except GE), the availability of a chloride-resistant catalyst would eliminate the need for the first water-wash and for the subsequent pre-heater. Instead, a single water-wash step could be placed after the COS hydrolysis step. Although the capital saving for such a modification is estimated to be modest, one could also expect an availability improvement from having a simpler process line-up. The COE impact in Table 3-1 is based solely on the estimated $2/kW in initial capital savings. Further benefit would accrue from the availability improvement and from reducing the periodic cost of replacing COS hydrolysis catalyst by eliminating fouling by grey water carried over from the chloride washing step (the primary cause of COS catalyst replacement in existing IGCC units.)
GRE Coal Drying Process
Great River Energy (GRE) is currently demonstrating a new process for drying lignite at its Coal Creek Station (pulverized coal) near Underwood, North Dakota. The process uses low-level heat from the condenser to pre-heat air that is then used in a fluidized-bed dryer. The process is
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designed to reduce the lignite’s moisture content from 40% by weight to 30% by weight. At Coal Creek, this is expected to improve the heat rate by about 3–5%.
Although 30% moisture is higher than the normal drying target for either the Shell or KBR processes, the GRE drying process should have a beneficial impact on both Shell and KBR IGCC units designed for low-rank, high-moisture coal. By serving as a pre-dryer, the process would decrease the heat duty of the mill dryer, which would decrease the amount of clean syngas needed to fire the mill furnace. That, in turn, would decrease the amount of coal feed required and would decrease the size and cost of the gasification and gas clean-up systems.
A direct analysis of the impact of the GRE process on IGCC cost-of-electricity has not been conducted. The estimated benefits listed in Table 3-1 are based on the COE savings that GRE has estimated for pulverized coal power plants.
Assuming that the Coal Creek demonstration is successful, this technology should be ready for inclusion in dry-feed IGCC units. However, an engineering economic study is needed to gain a better understanding of the impacts of the process on an IGCC.
Dry Solids Pump
Current dry-solid-fed coal gasification systems (i.e., Shell, KBR) use lock hoppers to bring pulverized coal up to gasifier pressure. These systems are constructed of expensive high-pressure components and mechanical parts, require a tall super-structure, consume significant amounts of high-pressure nitrogen, and require significant maintenance due to the frequent cycling of the large valves exposed to solids. A mechanical device with the capability of injecting the feed coal into a pressurized storage vessel (or directly into the gasifier) would have the potential to reduce capital requirements and improve efficiency. With DOE support, Stamet Incorporated is developing such a mechanical device—a rotary feed pump or “coal pump” that will pressurize and feed coal at pressures up to 1000 psi (70 bar). In a separate DOE-supported program, Pratt & Whitney Rocketdyne Inc. is targeting mid-2008 for long duration testing of its dry solids pump with atmospheric pressure feed and 1200 psia (83 bara) discharge pressure.
Stamet Dry Solids Pump
Stamet and DOE envision the coal pump ultimately feeding coal directly into a gasifier and also eliminating the need for drying the coal. In the near-term, however, EPRI believes it is prudent to only expect the Stamet pump to replace the lock hopper system. This will minimize the amount of testing required to create a commercially viable pump. For the initial gasifiers using the Stamet pump, it will still be necessary to transport the pressurized coal from the pressurized storage vessel into the reactor zone pneumatically, which requires the coal to be dried because surface moisture can make the coal difficult to transport due to formation of lumps and buildup in transport ducting. Though the Stamet pump may also have the ability to replace slurry pumps in slurry-fed gasification systems, a representative of E-Gas stated they feel that their present slurry-feed system is more reliable than a dry-feed mechanical device. Therefore, ConocoPhillips would be reluctant to incorporate it in its designs. Consequently, EPRI has not included a benefit for the use of the Stamet pump for the slurry-fed cases in Table 3-2. Longer-
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term R&D efforts may prove the technology to be useful for slurry-fed gasifiers, especially for feeding biomass, which is difficult to pump in slurry form and for which E-Gas representatives acknowledge potential for using the Stamet pump.31
For dry-coal fed systems, the Stamet pump is expected to provide a reduction in capital investment by eliminating the coal feed lock hopper system, a reduction in operating costs for lock hopper pressurization gas, and a 1 percentage point improvement in availability. The availability improvement and the estimated capital savings of about $45/kW would reduce the levelized cost of electricity by about $1.10/MWh for dry-feed IGCC units.
A more detailed description of the Stamet feed pump and the proposed RD&D plan are provided in Chapter 8.
PWR Dry Solids Pump
Pratt & Whitney Rocketdyne Inc. has developed a dry solids pump to meet the demands of the ultra-dense phase dry-feed system for the PWR Compact Gasification System. At the 2006 Pittsburgh Coal Conference, PWR reported that testing would begin on the dry-feed system in early 2007.32 A 400 tpd prototype of the PWR dry solids pump will be installed in the feed system for long-term performance and acceptance testing of the feed system, beginning in mid-2008, after completion of design and fabrication of the pump prototype.
Published papers suggest that dense packing of coal particles during pump operation is expected to provide an adequate seal to transport coal from a gravity feed, atmospheric pressure storage silo to a 1200–1300 psia (83–90 bara) high-pressure discharge tank. A supplementary nitrogen feed to the high-pressure tank will maintain interstitial volume and drive the feed from the discharge tank to the gasifier feed nozzles. As with the near-term version of the Stamet dry coal pump, it is expected that coal will require significant drying and particle size control prior to feeding to the PWR pump.
With patents pending, design details of the PWR dry solids pump are being held as proprietary information. The compact gasifier and gasifier feed system are described in more detail in Chapters 4 and 8. The development schedule for the PWR pump may or may not allow it to be considered as a near-term alternative to the Stamet pump for other dry feed gasifiers. For these systems, the COE impact of the PWR pump is expected to be comparable to that forecast for the Stamet pump.
31 Personal conversation with Phil Amick, ConocoPhillips, July 2005. 32 K.M. Sprouse, D.R. Matthews, and G.F. Weber, “The PWR/DoE High Pressure Ultra-Dense Phase Feed System and Rapid-Mix Multi-Element Injector for Gasification,” Pittsburgh International Coal Conference, September 2006.
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Continuous Slag Pressure Let-Down
GE and Shell gasifier designs currently require the use of lock hoppers to depressurize the slag collected from the process after it is quenched and shattered in a water bath. The lock hoppers add considerable height to the gasification structure and require large and relatively expensive valves. ConocoPhillips has demonstrated and commercialized a “continuous slag pressure let-down” system which avoids the use of lock hoppers. As the name implies, the slag continuously flows out of the slag bath and through the depressurization equipment. Although ConocoPhillips has understandably kept the details of its slag let-down system confidential, it is known that the system allows the bottom of the gasifier to be very near grade level. This shortens the height (and cost) of the gasifier steel support structure considerably. The capital cost of the let-down system is also assumed to be less than that of a large lock hopper vessel sized to handle all of the slag produced during a sluicing cycle.
At the Power Systems Development Facility operated by Southern Company, KBR is testing a continuous ash let-down system (recall that the KBR gasification process is non-slagging). This system is expected to cost less than a lock hopper system and should also allow KBR to shorten the height of the gasifier steel support structure.
Because of the proprietary nature of ConocoPhillips’ and KBR’s continuous pressure let-down designs, it is not possible to estimate the capital cost impact of those designs. Hence, Table3-2 provides no COE impact estimates for this technology. For similar reasons, EPRI believes development of continuous slag pressure let-down systems is best left to the individual gasification technology suppliers. This project is included as a near-term element in the IGCC RD&D Augmentation Plan because EPRI believes that the GE and Shell gasifiers would also benefit from the addition of continuous slag let-down.
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4 IGCC RD&D AUGMENTATION PLAN OVERVIEW—LONGER-TERM
This chapter summarizes the longer-term elements of the CoalFleet IGCC RD&D Augmentation Plan and tabulates their associated benefits in terms of “milestones” toward the CURC-EPRI Roadmap goals for capital cost and efficiency of IGCC plants with CO2 capture. Where appropriate, distinctions are made between technologies suitable for slurry-fed gasifiers and dry (or semi-dry) feed gasifiers. As with the near-term elements summarized in Chapter 3, RD&D projects or programmatic sets of projects are recommended to realize the potential gains in cost competitiveness and performance. Some of the longer-term elements are continuations or logical next steps for the near-term activities covered in Chapter 3. Others have long development cycles and work must be started in conjunction with near-term RD&D augmentation projects, although the longer-term elements won’t reach fruition until after 2012.
Two elements directly address the incorporation of CO2 capture in IGCC designs, but most of the longer-term RD&D elements can be introduced independently of CO2 capture. In many cases, however, their economic justification becomes stronger when capture is included.
The IGCC RD&D Augmentation Plan’s goal is to bring to commercial readiness competitive IGCC designs with CO2 capture by the 2015–20 timeframe, and to introduce by 2025 advances that reduce the constant-dollar cost of IGCC plants with 90% capture to a cost lower than 2012’s IGCC plants without CO2 capture. And if fuel cell technology improves and scales up as planned, integration with IGCC units in the 2025–30 timeframe will create coal-based power systems with CO2 capture and unprecedented efficiency.
Chapters 5 through 9 provide expanded descriptions of many of the technologies summarized in this chapter.
Implementation of the Longer-Term Elements in the IGCC RD&D Augmentation Plan
The projects making up the longer-term strategy for implementing the IGCC RD&D Augmentation Plan have been evaluated in reference to an IGCC plant required to have 90% availability and 90% CO2 capture (coal feed to gasifier basis). Two “technology pathways” have been defined, one for slurry-fed gasifiers and one for dry-fed gasifiers. Overviews of the cost and performance attributes of the steps in these pathways are listed in Table 4-1 and Table 4-2. Table 4-3 and Table 4-4 provide additional cost details and unit size and emissions estimates.
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Assumptions embodied in the tabulated values include a two-stage water-gas shift reactor, an acid gas removal system designed for shifted syngas and CO2 separation, and CO2 drying and compression equipment. The water-shift reactor converts 95% of the CO in the raw syngas to CO2 for removal by a Selexol absorbent process, which can capture more than 90% of the CO2 in the shifted syngas. The captured CO2 is compressed to 2200 psig (150 bar) for export from the plant boundary by pipeline. The cost of the pipeline is excluded from the capital cost totals in the tables. The final line in each table shows the 2006 CURC-EPRI Roadmap targets for an IGCC power plant coming on-line in 2025.
Table 4-1 Longer-Term RD&D Pathway to CURC-EPRI Roadmap Goals for Slurry-Fed Gasifier with CO2 Capture (cost basis 2Q 2005 USD)
Technology $/kW
HHV %Eff
Total $/kW
HHV Eff’cy
Comments
Baseline Technology - - 2001 30.2% Based on F-class combined cycle, coal-water slurry
fed gasifier, spare gasifier train for 90% availability
Add SCR +15 -0.10 2016 30.1%
Assumes SCR will be proven in near-term without RD&D augmentation. As Selexol is included for CO2 capture, there is only small impact on AGR for deeper sulfur removal; $5/kW for SCR.
Eliminate Spare Gasifier
-116 0.00 1900 30.1%Maintain 90% availability via better refractory (covered in near-term plan) and improved I&C to support operations
F-Class to G-Class CT -166 +1.00 1734 31.1%
Assumes $10/kW savings from G-class CC, efficiency gain based on today’s delta between F- and G-class CC (covered in near-term plan)
Improved Hg Detection 0 0.00 1734 31.1% Assumes >95% Hg removal feasible with activated C
bed, but not currently measurable
ITM Oxygen -111 +1.20 1623 32.3%
Assumes ASU cost and power usage drops 35%, lower $/KW of other sections results from larger net output with no size change. May need funding to modify CT for integration with ITM.
CO2-Coal Slurry -31 +2.1 1592 34.4%
Assumes 10% improvement in cold gas efficiency, 10% reduction in O2 demand, $10/KW increase in coal feed costs
G-Class to H-Class CT -32 +0.9 1560 35.3%
Assumes $10/kW savings for H-class CC versus G-class, efficiency gain based on today’s H- and G-class CC efficiencies
Ultralow DLN Combustors -8 +0.10 1552 35.4% Eliminates SCR, but deep sulfur removal remains
(ongoing DOE program)
Supercritical HRSG -20 +0.80 1532 36.2%
Assumes 1100ºF (600ºC) steam, once-through design, efficiency gain based on IEA report PH 4-19, $/kW savings from greater net output
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Technology $/kW
HHV %Eff
Total $/kW
HHV Eff’cy
Comments
Membrane CO2 Separation
-135 +1.80 1397 38.0%Assumes 50% reduction in CO2 capture and compression costs and auxiliary power (multiple ongoing DOE programs)
Warm Gas Cleanup -63 +0.80 1334 38.8%
Assumes $100/kW for cold gas cleanup, half that for warm gas cleanup; efficiency improvement(ongoing DOE program)
H-Class to FC-CT Hybrid -88 +6.60 1246 45.2%
Assumes 65% syngas to kWe efficiency; same $/kW for power block facilities as H-class CC, eliminates water-gas shift reactor (ongoing DOE program)
CURC-EPRI Roadmap - - 1410-
1660 44–49% 2006 revised goals for units coming on-line in 2025
Table 4-2 Longer-Term RD&D Pathway to CURC-EPRI Roadmap Goals for Dry-Fed Gasifier with CO2 Capture
Technology $/kW
HHV %Eff
Total $/kW
HHV Eff’cy
Comments
Baseline Technology 2443 32.8% Based on F-class combined cycle, dry-fed gasifier;
no spare gasifier train
Add SCR +6 -0.10 2449 32.7%
Assumes SCR proven in near-term w/o RD&D augmentation. As Selexol is included for CO2 capture, there is only small impact on AGR for deeper Sulfur removal; $5/kW for SCR.
Lower Syngas Cooler Steam Pressure
-100 -1.00 2349 31.7%Assumes $100/kW reduction from eliminating HP steam and making only MP steam in syngas coolers; efficiency loss of one percentage point.
F-Class to G-Class CT -225 +1.00 2124 32.7%
Assumes $10/kW savings from G-class CC, efficiency gain based on today’s delta between F- and G-class CC (covered in near-term plan)
Improved Hg Detection 0 0.00 2124 32.7% Assumes >95% Hg removal feasible with activated C
bed, but not currently measurable
ITM Oxygen -116 +1.20 2008 33.9%
Assumes 35% decrease in ASU cost and power usage; decrease $/KW of other sections with larger net output but no size change. May need funding to modify CT for integration with ITM.
Dry Feed Pump for Moist Coal
-72 +0.10 1936 34.0%
Eliminates pneumatic feeding and drying of bituminous coals prior to feed (lock hoppers eliminated with earlier generation pump in near-term plan)
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Technology $/kW
HHV %Eff
Total $/kW
HHV Eff’cy
Comments
Water Quench
-92 +0.30 1844 34.3%Eliminates syngas recycle compressor and piping; provides moisture addition for shift with water spray, not MP steam
G-Class to H-Class CT -37 +0.90 1807 35.2%
Assumes $10/kW savings for H-class CC versus G-class; based on today’s H- and G-class CC efficiencies
Supercritical HRSG -23 +0.80 1784 36.0%
Assumes once-through design with 1100ºF (600ºC) steam; efficiency gain based on IEA report PH 4-19; $/kW savings from greater net output
Ultralow DLN Combustors -9 +0.10 1775 36.1% Eliminates SCR, but retains deep sulfur removal
(ongoing DOE program)
Membrane CO2 Separation
-199 +1.80 1576 37.9%Assumes 50% reduction in CO2 capture and compression costs and auxiliary power (multiple ongoing DOE programs)
Warm Gas Cleanup -66 +0.80 1510 38.7%
Assumes $100/KW for cold gas cleanup, half that for warm gas cleanup, efficiency improvement (ongoing DOE program)
Advanced Gasifier -52 +0.20 1458 38.9% Assumes cost and efficiency targets set for PWR
gasifier in DOE evaluation are met
H-Class to FC-CT Hybrid -151 +6.40 1307 45.3%
Assumes same $/kW for power block and generation facilities as H-class CC and 65% syngas to power efficiency, eliminates water-gas shift reactor (ongoing DOE program)
CURC-EPRI Roadmap - - 1410-
1660 44–49% 2006 revised goals for units coming on-line in 2025
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Table 4-3 Impacts of Key Steps in Longer-Term IGCC RD&D Augmentation Plan for Slurry-Fed Gasifiers33
Total $/kW
CC $/kW
Gfr $/kW
ASU $/kW
Gen $/kW
CO2 $/kW
HHV Heat Rate
HHV Effcy
Avail-ability
SOX lb/106Btu
NOX ppmvd
Hg removal
Net MW
1 Baseline Technology 2001 663 654 241 270 173 11300 30.2% 90.0% 0.013 15 90.0% 455
2 Add SCR 2016 670 661 241 271 173 11323 30.1% 90.0% 0.006 3 90.0% 454
3 Eliminate Spare Gasifier 1900 670 546 241 270 173 11323 30.1% 90.0% 0.006 3 90.0% 454
4 F-Class to G-Class CT 1734 659 475 210 240 150 10957 31.1% 90.0% 0.006 3 90.0% 670
5 Improved Hg Detection 1734 659 475 210 240 150 10957 31.1% 90.0% 0.006 3 >95% 670
6 ITM Oxygen 1623 642 463 136 234 147 10563 32.3% 90.0% 0.006 3 >95% 696
7 CO2-Coal Slurry 1592 640 453 125 234 140 9929 34.4% 90.0% 0.006 3 >95% 699
8 G-Class to H-Class CT 1560 629 440 122 232 137 9666 35.3% 90.0% 0.006 3 >95% 715
9 Dry Ultralow-NOX Combustors 1552 623 440 121 232 136 9646 35.4% 90.0% 0.006 3 >95% 716
10 Supercritical HRSG 1532 623 431 119 227 133 9434 36.2% 90.0% 0.006 3 >95% 732
11 Membrane CO2 Separation 1397 592 410 113 216 67 8980 38.0% 90.0% 0.006 3 >95% 770
12 Warm Gas Cleanup 1334 592 349 111 216 66 8801 38.8% 90.0% 0.006 3 >95% 770
13 H-Class to FC Hybrid 1246 592 314 100 216 24 7554 45.2% 90.0% 0.006 3 >95% 770
33 All values assume incremental change with each step. All dollars are on 2Q 2005 basis. Total represents total plant cost excluding owner’s costs, transmission lines, CO2 pipeline, and other “off site” infrastructure.
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Table 4-4 Impacts of Key Steps in Longer-Term IGCC RD&D Augmentation Plan for Dry-Fed Gasifiers34
Total $/kW
CC $/kW
Gfr $/kW
ASU $/kW
Gen $/kW
CO2 $/kW
HHV Heat Rate
HHV Effcy
Avail-ability
SOX lb/106 Btu
NOX ppmvd
Hg removal
Net MW
1 Baseline Technology 2433 663 999 222 245 304 10400 32.8% 90.0% 0.013 15 90.0% 455
2 Add SCR 2449 670 1007 222 245 305 10421 32.7% 90.0% 0.006 3 90.0% 454
3 Lower SGC Steam P 2349 670 907 222 245 305 10775 31.7% 90.0% 0.006 3 90.0% 439
4 F-Class to G-Class CT 2124 659 788 193 218 265 10427 32.7% 90.0% 0.006 3 90.0% 648
5 Improved Hg Detection 2124 659 788 193 218 265 10427 32.7% 90.0% 0.006 3 >95% 648
6 ITM Oxygen 2008 642 769 126 213 258 10052 33.9% 90.0% 0.006 3 >95% 674
7 Dry Feed Pump for Moist Coal 1936 642 699 125 213 258 10022 34.0% 90.0% 0.006 3 >95% 676
8 Water Quench 1844 638 613 125 212 256 9956 34.3% 90.0% 0.006 3 >95% 680
9 G-Class to H-Class CT 1807 627 599 121 211 250 9692 35.2% 90.0% 0.006 3 >95% 692
10 Supercritical HRSG 1784 627 586 119 210 244 9479 36.0% 90.0% 0.006 3 >95% 707
11 Dry Ultralow-NOX Combustors 1775 620 584 118 209 243 9460 36.1% 90.0% 0.006 3 >95% 708
12 Membrane CO2 Separation 1576 588 555 112 199 122 9005 37.9% 90.0% 0.006 3 >95% 746
13 Warm Gas Cleanup 1510 588 492 111 199 120 8816 38.7% 90.0% 0.006 3 >95% 746
14 Advanced Gasifier 1458 588 441 111 199 120 8780 38.9% 90.0% 0.006 3 >95% 751
15 H-Class to FC Hybrid 1307 588 396 99 199 24 7536 45.3% 90.0% 0.006 3 >95% 751
34 Assumes Shell gasifier, Pittsburgh #8 coal, 90% CO2 capture, 2Q 2005 U.S. Dollars.
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Recommended RD&D Elements for Slurry-Fed Gasifiers
This subsection describes the “technology path” shown in Tables 4-1 and 4-3 for meeting the 2006 CURC-EPRI Roadmap goals for IGCC plants with CO2 capture based on slurry-fed gasification technology.
Baseline Technology
The “baseline technology” for the longer-term RD&D pathway was derived from the IEA Greenhouse Gas Programme’s Report PH4-19, issued in May 2003.35 The configuration for the slurry-feed baseline uses GE Energy’s quench gasifier, sized to provide fuel for two combined cycle trains using GE 7FA combustion turbines. A spare gasifier train is incorporated in a 4 x 33% arrangement. [Note: The IEA report was based on GE 50-Hz 9FA combustion turbines. The net MW values listed in Table 4-3 are based on GE 60-Hz 7FA combustion turbines.]
The estimated capital cost for CO2 capture, in Table 4-3, includes the costs of adding CO2 compressors and water-gas shift reactors, along with increased costs of the acid gas removal system and sulfur recovery unit (SRU) compared to a base case without CO2 capture. The combined cycle block (“CC” column) includes the combustion turbine-generator, heat recovery steam generator, steam turbine-generator (or steam turbine on a common shaft with the CT), condenser, and associated auxiliary equipment. Along with the gasification reactor, the gasification block (“Gfr” column) includes coal milling, slag removal, quench, solids scrubber, low-temperature gas cooling, etc. The baseline gasifier estimate includes the AGR and SRU costs for an equivalent plant without CO2 capture. The “ASU” column presents estimated costs for the air separation unit and associated compressors for O2 and N2. The “Gen” column represents general facilities such as cooling towers, control rooms, and wastewater treatment.
SCR Addition
Adding an SCR system to the baseline technology should allow an IGCC unit to immediately meet the 2025 CURC-EPRI target for NOX emissions. However, it increases the cost of both the combined cycle unit and the gasification block (for deeper sulfur removal) while also slightly increasing the plant heat rate (due to increased backpressure on the combustion turbine exhaust flow).
It is expected that no RD&D augmentation effort will be needed to make IGCC with SCR a long-term reality. An SCR system has already been installed on the Negishi Refinery IGCC in Yokohama, Japan, and the api Energia IGCC in Falconara, Italy where oil-based residues are gasified, and several U.S. coal-based IGCC projects have submitted for air permits in 2006 that specify the use of SCR. Ongoing RD&D by various OEMs is expected to produce some additional refinement of SCR technology to reduce catalyst cost and/or extend life. 35 “Potential for Improvement in Gasification Combined Cycle Power Generation with CO2 Capture,” IEA Greenhouse Gas R&D Programme, Report PH4-19, May 2003.
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Elimination of Spare Gasifier
If near-term RD&D to improve refractory life to 24,000 hours is successful, a spare gasifier will not be needed for an IGCC plant to achieve 90% availability. Eliminating the spare gasifier decreases the cost of the gasification block, but does not affect heat rate.
Transition from F-Class to G-Class CTs
This step replaces the GE 7FA combustion turbine-generators in the IEA study (or an FB-class turbine offered commercially today) with “G-class” CTs. This step is also part of the near-term augmentation plan and is described in Chapters 3 and 5. Capital savings come from the economies of scale of the larger turbine and from increased thermal efficiency of the combined cycle (G-class machines have higher firing temperatures), which allows the size of the gasification system to be smaller relative to the net power output of the combined cycle portion of the IGCC plant.
Improved Hg Detection
The baseline technology includes an activated carbon bed to absorb mercury from the syngas. This technology is now in commercial use at Eastman’s Kingsport, TN, gasification facility. Current mercury measurement methods do not detect the presence of any mercury downstream of the carbon bed; however, the accuracy of the current detection methods can only provide certainty that 90% of the mercury has been removed. It is believed that current carbon bed technology reliably removes 95% of mercury. Thus, the minimum detectable level for mercury must be decreased by a factor of two for it to be possible to claim 95% mercury capture, which is the stated goal in the 2006 CURC-EPRI Roadmap.
A second part of the improved mercury detection project aims to achieve a better understanding of the fate of all the mercury in an IGCC process. Although an activated carbon bed will remove at least 90% of the mercury remaining in the syngas after the solids removal and low-temperature cooling steps, the amount of mercury in the syngas entering the carbon bed may be no more than 50% of the total mercury in the coal feed. Prior attempts to obtain a complete mass balance on mercury around a gasification plant have failed to close the mass balance to within +/-50%.36 Improved analytical techniques are needed to resolve this uncertainty.
ITM Oxygen
Ion transfer membrane (ITM) technology for the production of high purity oxygen is being developed by Air Products and Chemicals Inc., with significant financial support from DOE.37 36 T.A. Erickson et al., Trace Element Emissions Project, Final Technical Progress Report for U.S. Dept. of Energy, Energy & Environmental Research Center, Univ. of North Dakota, June 1999.
37 D.L. Bennett, E.P. Foster, and V E. Stein, “ITM Oxygen: The New Oxygen Supply for the New IGCC Market,” Gasification Technologies Conference, San Francisco, 2005.
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The ITM process allows oxygen in high-temperature air (about 1500ºF or 800ºC) to pass through a membrane while preventing passage of non-oxygen atoms. Compared with conventional cryogenic air separation units, Air Products expects an ITM process unit to cost 35% less and to produce oxygen using 35–60% less power.
Air Products is currently testing a 5 tpd ITM module as a side-stream unit at a cryogenic air separation plant in Maryland. If that prototype is successful, Air Products envisions building a demonstration unit with a capacity of up to 150 tpd as the next step to commercial 2000 tpd units for IGCC plants.
A key requirement for using ITM air separation effectively in an IGCC is successful integration with the compressor of a combustion turbine. The FutureGen “research platform” offers an excellent opportunity to test ITM in conjunction with an operating IGCC unit.
Successful development of ITM technology will also have a significant positive impact on the economics of oxy-fuel pulverized coal boilers.
CO2-Coal Slurry
Experimental work sponsored by EPRI in the 1980s indicated that liquid CO2-coal slurries with very high solids loading were technically feasible.38 Study results suggested that an increase of 14 points in cold gas efficiency could be achieved by replacing a dilute (~50% solids by weight) water-lignite slurry with a concentrated CO2-lignite slurry (~88% solids by weight) in an IGCC plant.39 In cases where steam must be consumed for CO shift, as is required for CO2 capture, the overall improvement in efficiency will be lower.
Besides allowing higher solids density in slurries, the heat of vaporization of CO2 is one-fifth that of water. This would reduce oxygen consumption significantly, as much less sensible heat would be needed to vaporize the liquid in a CO2-coal slurry. Based on a study in EPRI report AP-4509, it is estimated that using a liquid CO2-lignite slurry would improve heat rate by 4%. In concert with a capital cost reduction attained by reducing the size of some equipment, this would decrease capital cost by about 7.5%.
However, there is considerable technical risk in the development of liquid CO2-lignite slurry. It has only been tested in a 2-inch (50 mm) diameter piping loop at a pilot test facility. It has never been used in feeding coal to a gasifier at any scale, so the estimated performance benefits are highly uncertain.
Despite the large “carrot,” there has been no recent work on using liquid CO2 as a transport medium. It would be necessary to update previous engineering studies to quantify the potential value of liquid CO2 slurries, with the new studies based on an IGCC plant designed for CO2
38 Investigation of Low-Rank-Coal-Liquid Carbon Dioxide Slurries, EPRI report AP-4849, October 1986.
39 Use of Lignite in Texaco Gasification-Based Combined-Cycle Power Plants, EPRI report AP-4509, April 1986.
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capture. If new studies show a sizeable potential benefit remains, a significant amount of scale-up and demonstration work would be required to qualify this technology for commercial use.
Transition to H-Class CTs
Building IGCC units based on “H-class” CTs would provide improvements in heat rate and economies of scale. H-class combustion turbines use steam cooling for both stationary and rotating components in the hot section. H-class technology increases the efficiency and net power output of the CT by decreasing the amount of CT compressor discharge air used for cooling of the hot section, by recovering heat to the steam cycle, and by increasing the maximum CT firing temperature.
The first H-class CT, a 50-Hz GE 9H, entered commercial operation in September 2003 at the Baglan Bay power station in Wales. That turbine is fired on natural gas and has achieved combined cycle efficiency of 60% (LHV basis). This is two percentage points higher than GE’s 9FB combined cycles. The first 60-Hz GE 7H is scheduled to begin commercial operation in 2008 at Calpine’s Inland Empire Energy Center in southern California. Tokyo Electric Power Company (TEPCO) has ordered three 9H combined cycles, which are also scheduled to come on-line in 2008.
As is the case with the jump from F-class to G-class CTs, the jump from F-class to H-class CTs will also require an increase in gasifier size to optimize the overall system costs. A single-train GE 9H combined cycle is rated at 520 MW on natural gas; the 7H combined cycle is rated at 400 MW. The size increase from G-class to H-class CTs is much more modest, but will also require gasifier and balance-of-plant design optimization.
Siemens recently announced a project to develop an H-class combustion turbine for the 50-Hz market, with first 8000H CT to be delivered in 2007 for the E.ON Energie Irsching site in Bavaria. According to Siemens, the SGT5-8000H machine will have combined cycle output of at least 530 MW and an LHV efficiency exceeding 60%.
MHI has tested an H-class CT at its demonstration facility in Takasago, Japan, but has not announced plans to offer it commercially.
The RD&D effort required to implement H-class CTs in an IGCC will be similar to the effort leading to deployment of G-class CTs in IGCC units. It is EPRI’s belief that the timeline for deploying H-class CTs will not meet the 2012 commercial operation target date in the near-term IGCC RD&D Augmentation Plan, which would require a CT supplier to be ready to offer commercial guarantees in 2008 for an H-class CT operating on syngas.
IGCC CT evolution is discussed in greater detail in Chapter 5.
Dry Ultralow-NOX Combustors
A significant effort is under way in the industry to develop combustion technologies that will limit NOX levels in the exhaust of natural gas-fired combustion turbines to 3 ppmvd (corrected to
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15% O2). In addition, DOE is funding projects by GE and Siemens to achieve comparable goals for syngas- and H2-fired CTs. GE is focusing on developing pre-mix combustors that can operate on high-flame-velocity fuels such as H2-rich syngas. Siemens is focusing on developing catalytic combustors that can operate on syngas and H2.
The advantage of ultralow-NOX combustors comes from the capital and operating savings of eliminating the selective catalytic reduction system from the HRSG and from the slight heat rate improvement caused by elimination of the pressure drop across the SCR catalyst. Deep sulfur removal would still be required for this technology, as it is for IGCC with SCR.
Supercritical HRSG
As combustion turbine technology evolves to allow increased firing temperature, the CT exhaust temperature also increases. With most natural gas-fired F-, G-, and H-class CTs, exhaust temperatures are high enough to produce supercritical steam conditions without use of supplementary firing. The higher thermal efficiency of a supercritical steam generation cycle allows an improvement in the net power output from an IGCC unit. This increase results in an estimated capital savings of $20/kW and an 0.8 percentage point improvement in the net HHV efficiency.
Membrane CO2 Separation
Even with incremental improvements, the technologies currently available for CO2 removal, which use chemical and/or physical solvents and regeneration processes, impose significant impacts on the thermal efficiency and capital cost of IGCC plants. It is believed that this impact can be greatly reduced through use of membrane technology for separating CO2 from shifted syngas. It is assumed that the CO2 will exit the membranes at a higher pressure than it would leave a physical solvent-based capture process such as Selexol. The higher pressure decreases the auxiliary power needed to compress the CO2 to 2200 psia (150 bar). In addition, the auxiliary power and process steam consumption of the AGR system will decrease significantly. CO2 membrane separation technology is currently in the laboratory stage of development with several organizations working on different approaches, as shown in Figure 4-1. The benefits attributed to this step assume at least one of these projects leads to a 50% reduction in both the capital cost and auxiliary power requirements of current CO2 capture and compression technology.
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Figure 4-1 Summary of Current CO2 and H2 Separation R&D Projects Sponsored by the U.S. Dept. of Energy
Warm Gas Clean-Up
This step envisions the use of novel gas clean-up technology to remove sulfur compounds from the syngas at a temperature of approximately 300ºF (150ºC) instead of the 100ºF (40ºC) required by Selexol and amine-based AGR processes. As shown in Figure 4-2, DOE is sponsoring several technologies aimed at this goal. The benefits shown in Table 4-3 are based on a DOE-sponsored study conducted by Mitretek.40 That study used the Selective Catalytic Oxidation of Hydrogen Sulfide (SCOHS) process as the basis for the performance and cost impact estimate. The SCOHS process eliminates the Claus and Tail Gas Treating units as well as a traditional solvent-based AGR unit by directly converting H2S to elemental sulfur. The higher operating temperature also eliminates part of the low-temperature gas cooling train. Compressed air can be used as the oxidant, with the nitrogen in the air serving later as a diluent in the combustion turbine.
40 D. Gray, et al., Current and Future IGCC Technologies: Bituminous Coal to Power, Mitretek Technical Report MTR-2004-05, August 2004.
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Figure 4-2 Summary of Current Warm Gas Clean-Up R&D Projects Sponsored by the U.S. Dept. of Energy
Transition from H-Class CT to Fuel Cell-CT Hybrid
No matter how far gasification and turbine technology advance, IGCC power plant efficiency will never progress beyond the inherent thermodynamic limits of the modified Brayton (gas turbine) and Rankine (steam turbine) power cycles. The IGCC-fuel cell hybrid power plant concept provides a path to coal-based power generation with net efficiency that exceeds the inherent limits of combined cycle generation.
Solid oxide fuel cells (SOFC) convert H2 and CO directly to electrical energy at higher gross efficiencies than could be achieved by using the same syngas (H2 and CO) and air in a combined cycle. Fuel cell systems are limited, themselves, by the net efficiencies of the processes available to produce the hydrogen.
Various OEMs and research groups are looking at several schemes for combining SOFC with gas turbines, either in combination with or in place of combustors. DOE has a major program under way to develop hybrid FC-CT combined cycles with fuel-gas-to-electricity conversion efficiencies of 60–70% at a cost of $400/kW. The estimates in the IGCC RD&D Augmentation Plan assume integration of a high-efficiency fuel cell with an H-class IGCC power plant.
In addition to the high thermal efficiency of the hybrid cycle, the anode section of the fuel cell produces a stream that is highly concentrated in CO2. After removal of H2O, this stream can be compressed to 2200 psig (150 barg) for sequestration. The concentrated CO2 stream is produced
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without having to include a water-gas shift reactor in the process. This further improves the thermal efficiency and decreases capital cost.
The estimated benefits listed in Table 4-3 and Table 4-4 for this step are based on achieving a FC-CT power block thermal efficiency of 65% versus 60% for an H-class combined cycle, and on the FC-CT power block having the same $/kW cost as an H-class combined cycle. The overall coal-to-electricity efficiency of 47.2% is slightly less than that cited by a recent DOE report produced by the University of California–Irvine.41 That study used an Integrated Gasification FC-CT based on the KBR Transport Gasifier and concluded that the overall efficiency would be 49.6%. That report also set the baseline IGCC technology efficiency at 32.8%, so the delta from the baseline to an IG-FC-CT is quite similar to the differential values in Tables 4-1 and 4-3.
Recommended RD&D Elements for Dry-Fed Gasifiers
This subsection describes the “technology path” shown in Tables 4-2 and 4-4 for meeting the 2006 CURC-EPRI Roadmap goals for IGCC plants with CO2 capture based on dry-fed gasification technology. Many of the steps for plants using dry-fed gasifiers are similar or identical to those for slurry-fed gasification technology; thus, only the unique descriptions follow while the others are in the previous subsection.
Baseline Technology
The baseline technology for the dry-fed gasifier with CO2 capture was also taken from the IEA Greenhouse Gas Programme’s Report PH4-19, issued in May 2003.42 It is based on Shell’s coal gasification process and includes two GE FA combustion turbines. Unlike the baseline slurry-fed gasifier case, the dry feed baseline does not include a spare gasification train.
Note that the IEA report was based on GE’s 50-Hz 9FA combustion turbine. The net power values listed in Table 4-4 are based on GE’s 60-Hz 7FA combustion turbine. Unlike the GE Energy quench gasifier, the Shell gasifier produces a syngas that has a very low H2O/CO ratio (about 0.05). Because a water-gas shift reactor requires a feed with a ratio of 2 or more, it is necessary to add MP steam to the syngas upstream of the shift reactors. Because generating steam in a syngas cooler and then adding it to the syngas requires much more capital than a direct water quenching of the syngas and because Shell’s dry feed coal milling, drying, and pressurizing systems are more expensive than a coal slurry system, the $/kW cost of the gasification block of the dry-fed gasifier base case is much higher than that for the slurry-fed base case. Although it is more expensive, the base case dry-fed IGCC unit has a higher thermal efficiency than the slurry-fed base case unit.
41 G.S. Samuelson, et al., Vision 21 Systems Analysis Methodologies, First Semi-Annual Report to U.S. Dept. of Energy, Advanced Power and Energy Program, UC-Irvine, November 2004.
42 “Potential for Improvement in Gasification Combined Cycle Power Generation with CO2 Capture,” IEA Greenhouse Gas R&D Programme, PH4-19, May 2003.
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The $/kW cost of the other IGCC sections are similar to, or less than, the slurry-fed base case, except for the CO2 capture section. The latter is more expensive due to the need to switch from an amine-based AGR system to a more expensive Selexol process when CO2 capture is incorporated in a Shell IGCC. The estimated capital cost for CO2 capture in Table 4-4 includes the costs of adding the CO2 compressors and water-gas shift reactors, along with increased costs of the acid gas removal system and sulfur recovery unit compared to a case without CO2 capture.
The combined cycle block (“CC” column) in Table 4-4 includes the combustion turbine-generator, heat recovery steam generator, steam turbine-generator (or steam turbine on a common shaft with the CT), condenser, and associated auxiliary equipment. Along with the gasification reactor, the gasification block (“Gfr” column) includes coal milling, slag removal, solids scrubber, low-temperature gas cooling, etc. The baseline gasifier estimate includes the AGR and SRU costs for an equivalent plant without CO2 capture. The “ASU” column presents estimated costs for the air separation unit and associated compressors for O2 and N2. The “Gen” column represents general facilities such as cooling towers, control rooms, and wastewater treatment.
Lower Syngas Cooler Steam Pressure
The baseline technology assumes heat exchangers to raise both MP (43 barg) and HP (127 barg) steam in the syngas cooler (SGC). For projects with relatively low coal prices, Shell has recommended replacing the HP surfaces in the SGC with MP surfaces and only producing MP steam in the gasification block.43 Although this will decrease the thermal efficiency of the process, it will also provide a substantial reduction in capital cost. Based on prevailing U.S. market conditions and coal prices, lowering the SGC steam pressure will provide a significant reduction in the levelized COE of a Shell IGCC. Therefore, EPRI believes it will be incorporated in near-term Shell designs. Accordingly, it is also included in the long-term implementation pathway.
Dry Solids Feed Pump for High Moisture Coal
The Stamet solids pump is included as a near-term RD&D augmentation project (see Chapter 3) because of its potential to offer significant capital savings compared to a lock hopper coal pressurization system. The benefits attributed to the Stamet pump in the near-term analysis were based on only replacing the lock hoppers, while maintaining the coal milling and drying and nitrogen-entrained pneumatic feed system to the gasifier.
DOE and Stamet envision even larger modifications to dry-feed gasification systems via use of Stamet technology. They propose eliminating the coal drying step, replacing the roller mills with less expensive hammer mills, and feeding coal to the gasifier directly from the discharge of the Stamet pump with no pressurized coal storage silo in-between, allowing abandonment of the pneumatic transport feed lines.
43 H.J. Van der Ploeg, “The Shell Coal Gasification Process for the U.S. Industry,” Gasification Technologies Conference, Washington, DC, October 2004.
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EPRI believes such major modifications will not be commercialized in the near-term due to extensive testing that would have to take place before such a process could be offered with commercial guarantees. EPRI is also skeptical that hammer mills could be used in place of roller mills because hammer mills produce a coarse grind, which would reduce carbon conversion in entrained flow gasifiers such as the Shell design.
Nevertheless, the benefits of using the Stamet pump in the longer-term are potentially greater than what was assumed for the near-term analysis. The benefits attributed to the Stamet pump in the longer-term pathway are based on feeding coal to the gasifier directly from the Stamet pump discharge and on eliminating the coal drying process for bituminous coals.
There is no indication that the PWR dry solids pump design will allow a comparable adaptation for moist solids.
Water Quench
The baseline Shell technology quenches hot syngas exiting the gasifier by recycling cooled syngas. The temperature after mixing in the recycled gas is approximately 1650ºF (900ºC). The quenched syngas is then further cooled in the syngas cooler, which raises useful steam.
However, Shell could replace the recycled syngas quench with a water spray quench. The amount of water added to the syngas would be selected to match that needed to achieve the targeted H2O/CO molar ratio required by the water-gas shift reactor. This would still be well above the dew point of the syngas, and some MP steam could be raised by further cooling the moisturized syngas.
The benefits attributed to this step in Table 4-4 are based on an estimated capital savings from eliminating the recycle syngas compressor and much of the syngas cooler surface. The dry solids filter is also smaller due to the reduced volume of quenched syngas. Because the baseline case used MP steam to moisturize the syngas upstream of the water-gas shift reactor, the net MP steam production remains approximately the same when using a water quench. There is a slight improvement in heat rate due to the absence of the recycled syngas compressor auxiliary power.
Advanced Gasification System
Over the next 20 years, advanced are expected to take place in gasifier design. These advances should lead to improved IGCC economics. One potential advancement indicative of the magnitude of improvement that could be implemented over the next 20 years, is the compact gasification system being developed by Pratt & Whitney Rocketdyne (PWR) under a cooperative agreement with DOE. As currently envisioned the PWR system could improve the availability and significantly reduce the cost of gasification plants. The estimated capital cost and efficiency impacts provided in Table 4-2 are based on estimates provided by PWR with adjustments made by EPRI after a cursory review of the PWR information. The PWR gasification system includes a dry solids pump, a compact gasifier, and a partial water quench. The impacts shown for the “advanced compact gasifier” in Table 4-2 reflect EPRI estimates of only the improvements
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provided by the compact gasifier design, as the other two elements in the PWR system are already accounted for in other elements of the long-term roadmap.
The PWR compact gasifier is an oxygen-blown, dry feed, plug-flow entrained reactor designed to achieve carbon conversions approaching 100%. The gasifier uses PWR rocket engine technology to enable a compact design which PWR believes will yield improved IGCC performance and availability while decreasing capital costs. The injector design uses multi-element injection to rapidly mix the coal with hot steam and oxygen while rapidly dispersing the coal across the reactor’s cross-section. Efficient cooling of the injector face plate enables long injector life. The ceramic matrix composite gasifier liner is also actively cooled, resulting in a solid layer of slag on the gasifier side of the liner. This layer is expected to protect the refractory underneath, enabling a long operational life.
Because of the combination of dry feed and a partial water quench, the PWR design appears to be well-suited for production of hydrogen. Analyses sponsored by DOE (see DOE/NETL-401/061506) indicate that if the PWR system could achieve its cost and performance targets, it could reduce the cost of hydrogen production by approximately 25% relative to existing slurry-fed gasification technologies. This reinforces the importance of adding partial water quench designs to dry feed gasifiers as recommended in the long-term pathway for dry-feed IGCC units.
The PWR compact gasifier also uses a proprietary dry solids pump that was developed as part of the PWR/DOE program. Although these components were conceived to meet the specific requirements of the PWR gasifier, they may provide significant near-term to medium-term benefit for other dry-feed gasifiers, and are therefore covered along with the Stamet dry solids pump in the recommended list of near-term RD&D projects (see Chapter 3).
The PWR compact gasifier is described in more detail in Chapter 8, along with summaries of the key features of the dry feed system and dry solids pump.
It should also be noted that several other companies are developing advanced gasification technologies. Among the developments are:
• ConocoPhillips has announced its intention to develop an “Entrained flow, Slurry-fed, Transport” (or ESTR) gasifier that would combine the efficiency advantages of dry feed with the feed system simplicity of a slurry-fed process.44
• GE Energy has announced an R&D effort to improve its gasification technology’s capability to process low-rank coals.45
• KBR and Southern Company are continuing to improve their Transport Integrated Gasification (TRIG) technology through the use of improved cyclones.46
44 B. Stobbs, “Canadian Clean Power Coalition: Current Status of Clean Coal Technologies,” Wisconsin Clean Coal Study Group, February 2006; see http://psc.wi.gov/cleancoal/documents/2-10-06Meeting/CanCleanPower2-10-06.pdf 45 M. Atwell, “The Economic Utilization of Low-Rank Coal in IGCC,” Coal-Gen 2006, Cincinnati, August 2006.
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• MHI and a consortium of Japanese utilities are scaling up a two-stage, dry feed gasifier for a 250-MW IGCC unit in Nakoso, Japan, and are designing for very high thermal efficiency.47
EPRI recognizes and supports in earnest the ambitious next-generation-design RD&D programs now under way by these and other suppliers of gasification systems worldwide. Although it is not possible at this point to estimate the magnitude of the potential impacts of these developments, it is clear that gasification technology, particularly for low-rank coals (which currently favors dry-feed systems), has considerable potential for improvement over the next 20 years.
46 J.M. Nelson, et al., “Low-Rank Coal Gasification Studies Using the PSDF Transport Gasifier,” 20th Western Fuels Symposium, Denver, CO, October 2006. 47 S. Kaneko, “Status of 250 MW Air-blown IGCC,” 2005 Gasification Technologies Conference, San Francisco, October 2005.
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5 COMBUSTION TURBINE TECHNOLOGY DEVELOPMENT
Two key factors motivate RD&D efforts to overcome issues related to the relative complexity and higher capital cost of integrated gasification combined cycle technology: (1) the promise of high thermal efficiency and low criteria pollutant and mercury emissions, and (2) the promise of lower incremental costs for implementation of CO2 capture for sequestration. These factors, in turn, depend in part on rapid advancement in combustion turbine technology.
The prospective IGCC capital savings listed in Tables 3-1 and 4-1 through 4-4 for adoption of G- and H-class combustion turbines are based on the assumption that the incremental cost of the larger turbine is small on a $/kW basis and that the necessary scale-up of the gasifier, auxiliaries, and balance-of-plant equipment is technically feasible and much less expensive on a $/incremental-kW basis than adding a second equipment train. As previously noted, a single-train IGCC based on a Siemens SGT6-5000F, for example, is expected to produce about 315 MW at ISO conditions, whereas a single-train IGCC based on the SGT6-6000G should produce about 400 MW.
G-class CTs also yield an efficiency improvement of one to two percentage points. These improvements have been estimated to result in a reduction in COE of $2.50–3.00/MWh (from a base cost of about $45/MWh). This reduction represents about one-third of the current COE gap between IGCC and conventional SCPC plants (see Chapter 2).
The calculated improvements in COE assume that there will be no loss of reliability in the early operation of plants that utilize advanced gas turbines. An aggressive reliability engineering assessment is proposed to enable this to be achieved. Still, previous experience with startups of IGCC plants implementing new technologies indicates that it is necessary to anticipate unforeseen problems. Although most problems have been resolved quickly, others have taken a few months (blading replacement) to a few years (combustion-related vibration) to resolve.
Technology Evolution
The history of combined cycle power development shows a generally continuous improvement in the power output and efficiency of combustion turbine-generators installed in the largest plants. Similarly, it is expected that IGCC plant development will also benefit from timely implementation of CTs using leading-edge technologies with higher firing temperatures, higher efficiencies, and larger power outputs. The use of these new CT models allows a significant reduction in the cost-of-electricity for proposed IGCC power plants as compared with previous IGCC demonstration projects.
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Combustion turbine products follow a typical development path with new models designed on an approximately ten-year cycle. New units are first designed primarily for natural gas firing, with some accommodations made for liquid fuel firing. Prior to 1985, syngas firing was considered as having limited market potential. During the last twenty years, however, turbines designed for natural gas firing, such as the GE 7E and 7FA and the Siemens 94.2 and 94.3, were modified by changing their combustion hardware to accommodate the larger volumetric flow rates and lower heating values of the syngas produced in the IGCC demonstration plants.
Figure 5-1 and Table 5-1 illustrate the differences between combustion turbines that were developed for firing natural gas and the modified versions of those turbines for firing syngas in IGCC plants. Figure 5-1 shows the parallel and cross-evolution of the GE 7FA line of turbines for natural gas and syngas firing, while Table 5-1 provides additional information comparing the ratings for several generations of GE CTs and comparable Siemens CTs in natural gas and syngas applications.
Figure 5-1 Evolution of Syngas Fired CTs from GE’s 7F Line of Natural Gas Machines48
Significant modifications are required to adapt the leading-edge, advanced technology CTs to allow use with syngas. Ironically, these changes increase the net power output of the CT because greater mass flow is possible due to the reduced Btu content and lower firing temperature with syngas. This is apparent in Figure 5-1. The power increase gained by using syngas is greater than the power gained by increasing the turbine firing temperature and making other refinements that maximize the efficiency and power delivery of successive generations of natural-gas-fired CTs. However, diversion of CT compressor air to the gasifier or air separation unit may change this relationship.
48 The typical evolutionary development pathway illustrated in Figure 5-1 was presented by GE at the 2005 Gasification Technologies Meeting.
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Table 5-1 Growth in Combined Cycle Equipment Capacity for IGCC Plants
Gas Turbine Model
Natural Gas Simple Cycle
Rating,
MW
Natural Gas Combined
Cycle Rating,
MW
IGCC Application
Syngas Simple Cycle
Rating,
MW
Syngas Combined Cycle Net
IGCC Plant Rating,
MW
GE 7FA 150 Polk, Wabash
192 250
GE 7FA+e 172 263 197
GE 7FB 184 280
600 MW GE Standard IGCC Design
(2006)
232 ~315
GE 7H n.a. 400 n.a.
Siemens SGT5-2000E (previously V94.2) (50 Hz)
163 249 Buggenum ~250
Siemens SGT5-4000F (previously V94.3K) (50 Hz)
268 407 Puertollano ~330
Siemens SGT5-8000H (50 Hz)
340+ 530+
Siemens SGT6-5000F (previously 501F) 210 293 232 ~315
Siemens SGT6-6000G (previously 501G) 279 391 296 ~400+
To accommodate different fuel combustion properties and product gas compositions, conversion of a natural gas-fired turbine design for syngas operation requires modifications of the hot-section parts (combustors, nozzles/vanes, and buckets/blades) and other subsystems. Compared to their predecessors, the newer F-, G-, and H-class CTs, operate at significantly increased firing temperatures (2300–2600ºF, or 1260–1430ºC, on methane). They must be fired 200–300ºF (110–170ºC) lower when operating with hydrogen-rich fuels. Otherwise, blade overheating may occur as the high water vapor content of the combustion products results in high volumetric flow and heat transfer for a given mass flow through the power turbine.
Reliability Issues
Table 5-2 provides a partial list of problems that have been encountered when new combustion turbine models entered syngas-firing service. The right-hand column of the table outlines modifications made to remedy the problems. Even with extensive R&D, optimum materials selection, and careful engineering to anticipate and minimize potential problems, some IGCC projects have required major post-commissioning revamps of hot-section parts and major components. This is not, however, completely due to the IGCC turbine modifications and
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operating characteristics. Problems common to both syngas-fueled and natural-gas-fueled CTs were observed first in IGCC units that had low serial number CTs and relatively high operating hours.
Table 5-3 provides a list of modifications made to GE and Siemens turbines. Note that GE and Siemens have indicated the need for modifications to similar types of subsystems. In comparison to hot sections, modifications to these subsystems, which typically are not given the same level of design review and testing as the hot-section parts, often involve rather mundane engineering tasks.
Table 5-2 and Table 5-3 suggest that problems encountered during the initial operation of a specific CT model on syngas involve a mix of factors, some which might have been prevented by more thorough engineering and others that could not have reasonably been anticipated because of knowledge gaps in the existing technology base. Careful reliability engineering analyses can help avoid many of the predictable problems. A more comprehensive understanding of failures attributed to knowledge gaps should help to minimize the loss of availability due to unanticipated events.
Table 5-2 Typical Problems Encountered with Initial Application of CT Models in IGCC Plants
IGCC Plant Turbine Year Problem Modification
Cool Water GE 7E 1984 Leaking check valves on oil lines
Change valves
Plaquemine W501D5 1987 Combustor overheating Increase diameter of fuel inlet passages
Plaquemine W501D5 1987 Excessive acoustic noise when firing with natural gas
Redirect flow through fuel orifices
Polk GE 7FA 1996-97 Leaking check valves on oil lines
Change valves
Polk GE 7FA 1996-97 Undersized valves for diluents N2 injection
Larger valves
Polk GE 7FA 1998-99 Rotor spacing and bolting Rotor repairs
Polk GE 7FA 1998-99 Pipe, scale damage to turbine Install filter
Wabash River GE 7FA 1996 Cracked combustion liners Thermal barrier coatings
Wabash River GE 7FA 1996 Leaking N2 solenoid purge valves
Replace valves
Wabash River GE 7FA 1996 Expansion bellows cracking Redesign and replacement
Wabash River GE 7FA 1998 Rotor and spacing and bolting Rotor repairs
Wabash River GE 7FA 1999 Gas turbine compressor Redesign and replacement
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IGCC Plant Turbine Year Problem Modification
Buggenum Siemens 94.2
1994-96 Combustion induced vibration Redesign and replacement of combustion hardware
Puertollano Siemens 94.3
1999-2000
Combustion induced vibration Redesign and replacement of combustion hardware
Puertollano Siemens 94.3
1999-2000
Combustor overheating Redesign and replacement of combustion hardware
Table 5-3 Typical Gas Turbine Subsystem Modifications for IGCC Applications
GE
(Todd, 2000)
Siemens
(Morehead, 2005)
IGCC combustion system
Larger Stage 1 nozzles
Syngas combustion system
Off-base syngas fuel control / N2 purge module including syngas stop and control valves and gas detectors
Purge skid and manifolds
Syngas fuel piping: On-base and connection to syngas module
Syngas fuel supply
Nitrogen injection skid;
Steam injection for NOX control on back-up fuel
Diluent (nitrogen or steam) skid and manifolds
Air extraction and control skid Extraction air skid and manifolds
Control and protection system additions Mark VI unit controls
Fire and hazardous gas protection
Control system modifications
Protection system modifications
Accessory system / Enclosure design for syngas Enclosure modifications
Combustion system laboratory verification testing Full-scale testing
Scale-Up Issues
Scale-up of combustion turbines (i.e., GE 7FA+e to GE 7FB, GE 7FA to GE 7H, Siemens W501D5 to Siemens SGT6-5000F—previously W501F and to Siemens SGT6-6000G—previously W501G) brings important economies of scale to IGCC power generation. For IGCC plants, achieving these economies of scale requires development of larger, single-train gasifiers optimally matched to the fuel demands of the larger capacity CTs.
Table 5-4 reviews difficulties encountered during previous scale-up of commercial gasifier technology. Scale-up of any technology is difficult and poses some risk. In some cases, subtle
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differences in gas temperatures, flow patterns, and mixing combine to cause significant changes in gasifier reaction rates and products.
Table 5-4 Problems Encountered Scaling Up Gasification Systems
Technology Scale-up base Scaled up plant Problem Solution
GE 100 MW Cool Water 250 MW Polk Low carbon conversion
Add slag fines separation and recycle
GE 100 MW Cool Water 250 MW Polk High COS/H2S ratio
Add COS hydrolysis
Shell 250 T/D Deer Park 250 MW, 2000 T/D Buggenum
Overly large gasifier, high carbon conversion
None
E-Gas 160 MW Plaquemine 250 MW Wabash River
Solids fouling at inlet to fire-tube cooler
Modify solids flow path
The scale-up ratio to move from the current gasifiers matched to FB-class CTs to the gasifier size needed for G-class or H-class CTs is less than that for the systems shown in Table 5-4. Nonetheless, this scale-up still requires a firm understanding of gasifier fundamentals and carries some potential for unexpected results.
Current Status and Market Introduction of New Syngas-Firing CTs
North American IGCC projects that are currently in early development are primarily based on the GE 7FB and Siemens SGT6-5000F (F-class) CTs. Three “G-class” CT models are currently in natural gas service: MHI M501G (60 Hz) and M701G (50 Hz) and the Siemens SGT6-6000G (60 Hz, formerly W501G). The first natural-gas-fired H-class machine, the 50-Hz GE 9H, has also begun commercial operation (see Figure 5-2). The first natural-gas-fired 60-Hz GE 7H is scheduled for startup in 2008. Of these CT models, only the GE 7FB is substantially the same as a model that has already been proven in IGCC service, the GE 7FA, which is used at the Polk and Wabash River plants. In comparison to the GE 7FA and Siemens W501F, the 7FB and SGT6-5000F incorporate small evolutionary improvements in materials, flow path design, and other details that provide small improvements in net power output and efficiency.
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Figure 5-2 GE’s Steam-Cooled 9H Combustion Turbine—Natural Gas Service (copyrighted photos published with the permission of GE Energy)
GE has developed a standard design for a 600-MW IGCC plant that utilizes two GE 7FB CTs and can be adapted for several different gasifier product specifications. The first natural gas-fired 7FB units entered service in 2002. The first IGCC plants using the syngas-firing version of this turbine are expected to come on-line in 2012. Several technical features were incorporated in the original design of this engine to accommodate its future adaptation for syngas service. These include an increased shaft torque rating and a turbine nozzle design with more open flow area to allow higher volumetric gas flow without surge. GE 7FB units delivered for syngas service will include further modifications that are specifically engineered for this service.
G-class turbines divert less compressor air to cooling while also returning heat to the steam cycle. Combined cycle integration is impacted, because HRSG design and operation must accommodate the cooling steam requirements of the turbine. Although many plants install F-class CTs in a 2-on-1 or two-shaft 1-on-1 configuration, with a separate steam turbine-generator, this integration makes it likely that many or most G-class CTs will be installed with a steam turbine on a common shaft in a 1-on-1 configuration.
The greater use of cooling steam in H-class machines further increases the need for careful combined cycle integration. As with the G-class machines, this degree of integration makes it likely that most H-class CTs will be installed with a steam turbine on a common shaft in a 1-on-1 configuration.
Commercialization Issues
A number of commercial issues must be addressed to provide adequate incentives to initial buyers to accept the risks associated with first-of-a-kind combustion turbines in IGCC plants. These include the following questions:
• Are CT OEMs willing to certify their advanced F- and G-class machines on syngas without external R&D support?
• What can be done to ensure that CT system reliability is not reduced when a more advanced CT is used?
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• Will gasifier OEMs be willing to offer single-train systems with outputs that match G-class and H-class CT fuel requirements?
• What mechanisms are needed to encourage the first buyers to develop IGCC demonstration projects based on G-class and H-class CTs?
• Could a consortium be formed to provide financial assistance to purchase key spare parts so that outage times caused by unexpected events are limited?
• Could a consortium be formed to pay for “state-of-the-art” on-line monitoring systems to provide early warning of problems with CT design or integration?
• Could a consortium be formed to provide replacement power to a plant owner who has a power sales agreement to help early buyers offset the risk when a new (first-of-a-kind) plant is not operable as result of issues related to new technology?
Near-Term RD&D Needs for Combustion Turbines
EPRI has concluded that a formal reliability analysis should be conducted by the plant owner (or a consortium of early plant owners) for each new combustion turbine that is proposed for use in an IGCC plant. This work should specifically address how problems encountered during the introduction of previous new models will be avoided during the new introduction. An intensive reliability analysis of the turbine would include:
• Intensive reliability analyses of subsections that have been modified in size, function, or materials compared to previous experience, using insight gained via the proposed IGCC RAM database (described in Chapter 3).
• Full flow and full pressure testing of combustor “cans” with range of expected syngas compositions
In the 1990s, DOE funded the development of the “Advanced Turbine System” (ATS) natural-gas-firing combustion turbines to provide manufacturers with R&D support to provide a design basis for advanced technology engines that included advanced airfoil and materials technology, advanced compressors, and many other items. Siemens developed the SGT6-6000G (501G) based on its ATS platform. GE developed the 7H based on its ATS platform, which included advanced aircraft technology for airfoils and compressors. Qualifying these advanced machines for syngas will produce information that will be fed into the new DOE programs with both GE and Siemens to develop turbines that can be fueled with >90% hydrogen. These turbines are being developed to enable commercial CO2 capture at future IGCC plants.
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6 SUPPLEMENTAL FIRING, SUPERCRITICAL STEAM CYCLES, AND OTHER HRSG OPTIMIZATION CONCEPTS
Although the gasification system and combustion turbine tend to receive the most attention by designers, it is the heat recovery steam generator and steam turbine that complete the combined cycle and provide the vital increment of generating efficiency that makes IGCC attractive. The many options for configuring an IGCC unit’s HRSG provide opportunity for optimizing the IGCC system to meet various economic and operational goals.
Supplemental firing is generally the easiest HRSG variation to implement, but other options also merit consideration. Some of these options are integrated with supplemental firing whereas others can be used independently. Although most F-class natural gas combined cycle units employ a two- or three-pressure drum-type HRSG, a growing number of NGCC plants in the United States, Europe, and Japan are adopting once-through HRSG designs that share many of the characteristics of supercritical steam generators used in pulverized-coal plants.
When fired on natural gas, many F-, G-, and H-class combustion turbines have sufficiently high exhaust temperatures (1110–1185°F, or 600–640°C) to make a supercritical HRSG possible without supplemental firing, although a relatively large heat exchange area would be required. With the lower firing temperatures on syngas in an IGCC unit, supplemental firing would likely be necessary to achieve a practical SC-HRSG (with the possible exception of an H-class CT).
Other strategies, such as that developed by NovelEdge Technologies LLC, concentrate less on efficiency and more on maximizing output per capital dollar invested (i.e., minimizing $/kW) by simplifying the HRSG and/or maximizing supplemental firing and steam cycle output.
Supplemental firing is practical because combustion turbines use high ratios of excess air to optimize the temperature, pressure, and mass flow of the working fluid. Supplemental firing adds heat to the combustion turbine exhaust gas and increases its temperature. A corresponding increase in steam production and/or temperature can be used to serve a cogeneration load or to increase the power output from the steam turbine.
In an NGCC unit, the steam cycle typically provides about 35% of the full load output. In most applications, duct firing will increase steam turbine output by 20–40%, with a resulting 10–20%, increase in net plant output.
When supplemental firing is used, plant design modifications can range from simple installation of burners in the HRSG inlet duct (hence, supplemental firing is also known as duct firing) to major reconfiguration of the HRSG and significant increases in the size of the steam turbine,
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generator, condenser, and cooling water system. In its maximum application, supplemental firing can fully exploit the excess oxygen in CT exhaust and virtually double the net output of a combined cycle power plant.
Supplemental firing generally reduces the net efficiency of a combined cycle unit, but it offers a very cost-effective approach for providing additional peaking power capacity, making it economically attractive in many power markets. Another benefit of supplemental firing is its ability to be placed on-line faster and with a lower heat rate than other sources of peaking capacity. Additional savings may accrue through reduced maintenance costs and charges against emissions caps when startup of other CT peaking plants can be avoided.
Although many NGCC units use supplemental firing to increase maximum power output, this approach has not yet been applied to a coal-based IGCC unit and has only be implemented on one oil-based IGCC.
Supplemental Firing Options for IGCC
Adding supplemental firing to an IGCC unit could improve plant economics in a manner similar to NGCC applications, especially when the gasifier has capacity margin to allow an incremental increase in syngas production. Figure 6-1 illustrates a supplemental firing application for an IGCC unit.
Syngas forDuct Firing
SCR forNOX Control
Syngas forDuct FiringSyngas forDuct Firing
SCR forNOX Control
SCR forNOX Control
Figure 6-1 Schematic Diagram of Supplemental Firing for IGCC
Several supplemental firing approaches or strategies have been suggested to address the benefit opportunities and challenges of IGCC application. Examples include:
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• Providing peaking capacity and/or more flexible part-load operation.
Because duct firing consumes fuel at a higher heat rate than when it is used to fire the CT, it most typically is used only to meet peak demand. However, as shown in Figure 6-2, supplemental firing can improve IGCC heat rate at the part-load points where a combustion turbine is near its minimum load point (i.e., supplemental firing provides the operating flexibility to shift the shutdown or startup of an additional train to avoid the least-efficient CT operating points).
80%
90%
100%
110%
120%
130%
140%
0% 20% 40% 60% 80% 100% 120%
Plant load (% of rated load)
Hea
t Rat
e (%
of f
ull l
oad
valu
e)
3 trains2 trains1 trainSup.Firing
Figure 6-2 Comparison of IGCC Heat Rates Versus Load With and Without Supplemental Firing49
• Exploit excess gasifier capacity.
Implementation of duct firing can utilize excess gasifier capacity to increase peak power output when there is an intentional or coincidental mismatch between the maximum syngas production capacity of the gasifier and CT fuel requirements.
49 R. H. Eustis, Erbes, M.R., and Phillips, J.N., Analysis of the Off-Design Performance and Phased Construction of Integrated Coal Gasification Combined-Cycle Power Plants, EPRI report AP-5027, 2 vols., February 1987.
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Duct firing may use excess gasifier and ST capacity when a CT/HRSG train is out-of-service. And as noted in Figure 6-2, duct firing can be used to optimize the timing of starting up or shutting down a train in a multiple-train system.
• Exploit lower pressure and lower quality fuel gas.
Because duct burners operate at roughly atmospheric pressure and do not impact the dynamics of the combustion turbine, they can make beneficial use of secondary gas streams that would require compression for CT use and/or that have characteristics that would adversely affect CT performance, reliability, or emissions.
• Provide a substantial increase in plant capacity without the cost of adding a CT/HRSG train.
Net plant output can be increased, and operating flexibility gained, by increasing gasifier, duct burner, HRSG, and ST capacity.
Steam cycle efficiency can be increased, along with capacity, by using duct firing with a modified HRSG design that allows increased steam temperature and/or pressure. As material technology for SCPC and NGCC steam generators evolve, this evolutionary development could lead to a supercritical HRSG and, eventually, to an ultra-supercritical HRSG.
When gasifier capacity is increased with the addition of a full-sized gasifier train, the CT can operate at full power when one gasifier train is undergoing maintenance. This is equivalent to using a spare gasifier for extra production rather than letting it remain idle.
A concept patented by NovelEdge Technologies LLC aims to further reduce capital cost ($/kW) by simplifying the steam system from three pressures to a single drum while providing enough supplemental firing to double or even triple the steam cycle output. NovelEdge claims that their patented innovations also minimize the increase in heat rate during maximum supplemental firing.50
NovelEdgeTM Concept: Reducing Capital Cost with Maximized Supplemental Firing and HRSG Simplification
Technology Description
As noted, the NovelEdge concept maximizes the use of supplemental firing of the HRSG while simplifying the steam system from three pressure levels to a single high-pressure level. For an IGCC plant, this cycle can be used to address several potential supplemental firing applications. Common to all variations is the use of part of the syngas produced in the gasification plant by fuel duct burners in the HRSG rather than in a combustion turbine. In a large, multi-turbine plant, one of the combustion turbines and its HRSG could be eliminated. The standard 1100ºF (600ºC) turbine exhaust is then heated to a higher temperature by duct-firing the syngas. This allows the use of a higher pressure, more-efficient steam cycle that operates at 1815 psig/ 1050F/1050F (125 barg/565ºC/565ºC), as opposed to a conventional combined cycle plant which has a steam cycle that operates 1400 psig/1000F/996F (96 barg/538ºC/536ºC).
50 D. Heaven and W. Rollins, “NovelEdge IGCC Reference Plant: Cost & Emissions Reduction Potential,” Gasification Technologies Conference, Washington, DC, October 2004.
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With the NovelEdge concept, the IP and LP steam circuits are eliminated. Those circuits are generally used to maximize energy recovery from the flue gas so that the exhaust gas leaving the stack is at a temperature of approximately 200ºF (90ºC), which corresponds to the minimum exhaust gas buoyancy required for adequate dispersion. The NovelEdge cycle attains this desired balance by recovering the low-quality energy in the exhaust gas in the back end of the HRSG, while preheating the incoming cold boiler feedwater. Other savings result from the replacement of the LP deaerators with vacuum deaerating condensers, eliminating the LP line to the steam turbine, and reducing the amount of compression required to provide nitrogen diluent for the CT combustors (because one combustion turbine has been eliminated). These savings are offset to some extent by the costs of the duct burners, low-pressure piping to deliver fuel gas to the duct burners, and heat exchange module to preheat boiler feedwater. Figure 6-3 shows the equipment arrangement for this cycle.
With this implementation of the NovelEdge cycle, approximately 60% of gross power comes from the ST and 40% from the CT(s)—roughly the reverse of the split with a conventional combined cycle. The technology developers claim that the net plant heat rate increases by about one percentage point while the capital requirement is reduced by 5%. Additional savings accrue from reduced O&M requirements for the simplified equipment.
Figure 6-3 NovelEdge Power Generation Cycle Process Equipment Arrangement
Near-Term Potential for NovelEdge Concept
EPRI projects that IGCC units will ultimately be able to produce electricity at a COE that is competitive with conventional SCPC plants. In some applications, IGCC may become the lower COE option if carbon capture and sequestration are required. At this time, however, the estimated capital cost premium for an IGCC unit is in the range of 10–20%. Based on its internal studies, NovelEdge claims that its patented innovations can yield about 5% improvement in capital cost, on a $/kW basis, while limiting the increase in heat rate resulting from duct firing
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to about 1%. Based on information obtained from NovelEdge publications and discussions, EPRI has calculated that the NovelEdge cycle has the potential for net savings in COE of about $1.50/MWh or about 3% relative to a conventional IGCC. This COE advantage increases as the cost of coal decreases and, in turn, decreases the cost impact of the heat rate penalty for the NovelEdge concept. For plants with significant cycling, NovelEdge and other supplemental firing concepts may even be able to achieve an annual average heat rate that is lower than for an IGCC plant without supplemental firing.
Longer-Term Potential for NovelEdge Concept
For the longer term, EPRI envisions that a NovelEdge-based system could be used with “ultra-supercritical” steam conditions. In this case, the steam cycle arrangement and efficiency would be comparable to a “conventional” state-of-the art once-through USC steam generator.
The NovelEdge concept could provide some additional advantages that would accrue if an IGCC plant was retrofitted for CO2 capture:
• The original gasifier capacity would supply enough syngas to fully fire the CTs after conversion for CO2 capture
• Although the conversion would decrease net unit output, the ultimate heat rate could be impacted much less for a NovelEdge cycle than for a conventional IGCC design
• If membrane separation of CO2 from syngas is successfully developed, CO2 could be removed at process pressure while the secondary stream of low-pressure, hydrogen-rich syngas would be immediately suitable for supplemental firing. Conventional IGCC would require recompression to use this stream.
Supercritical Steam Cycles for IGCC
As incentives to reduce CO2 emissions become stronger, it is likely that advanced materials and other improvements developed for supercritical and ultra-supercritical steam plants will be adapted for IGCC. The basic principles that favor SC and USC steam cycles for pulverized-coal power generation also suggest that performance and economic gains should be available with use of higher steam conditions for IGCC.
As steam temperature rises, the gas-to-steam temperature differences (pinch) in the HRSG get smaller. This results in a relatively large required heat exchanger surface area. The analysis required to optimize this area is more difficult for an SC-HRSG because pinch points are not fixed by drum pressure as with a typical steam cycle.
Design of supercritical steam cycles for IGCC is further complicated by the lower firing temperatures for syngas-fueled CTs. A corresponding depression in exhaust gas temperature suggests that supplemental firing may be necessary if the SC-HRSG is to be effectively implemented for IGCC. It may be possible to achieve the desired exhaust temperatures by varying CT operating parameters with inlet guide vanes or other controls. It is expected that the SC-HRSG will become favored as technology evolves and greater cycle efficiency becomes increasingly important for meeting mandates for CO2 minimization and capture.
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Current Status of Supplemental Firing and HRSG Optimization for IGCC
Although there is extensive field experience with duct firing using natural gas, the experience with duct firing on syngas is limited to one operation at a small plant in Pennsylvania. EPRI is not currently aware of any study that would provide the background information needed (e.g., for duct firing using refinery fuel gas, blast furnace gas, or other low-Btu fuels) to engineer, insure, and permit an IGCC plant using an “aggressive” duct firing approach.
As of year-end 2006, NovelEdge technology had not yet been licensed to a conventional combined cycle plant developer. NovelEdge is continuing studies to optimize the cycle while working on arrangements to transition the technology from conceptual to commercial.
The situation, to date, is similar for supercritical HRSG applications. Although a number of studies have been published, and OEMs have conducted development work, there appears to be little design and operating experience to enable near-term deployment of SC-HRSG for IGCC units.
Commercialization Issues
IGCC plants now in the planning stage could be equipped with duct firing systems. OEMs have significant recent experience with providing these systems for NGCC plants and with providing burner systems suitable for a variety of chemical and process industry waste gas streams.
Implementation of more aggressive supplemental firing and HRSG optimization strategies, including the supercritical HRSG, will require further RD&D effort. At a minimum, to justify their selections to investors and regulators, early adopters need a more complete analysis of risk, performance, emissions, and cost data than is currently available. EPRI aims to fill this gap with a supplemental research project on “Supplemental Firing Options for Integrated-Gasification Combined-Cycle Plants.”
The projection of lower COE for IGCC plants using NovelEdge technology makes this an attractive option to evaluate. Although many of the individual components of the NovelEdge technology package are commercially available at this time, there are a number of issues that require further exploration. A demonstration in a natural gas application would offer insight into use of the cycle concept in an IGCC plant. On the basis of current information, it thus appears that the timeframe for potential use in IGCC applications would likely be in the mid-2010s. However, this timeline may be advanced if NovelEdge locates an appropriate demonstration partner, or if participants in EPRI’s supplemental project conclude that the technology risk is sufficiently low so as to be offset by the reduced capital risk. Also, the apparent optimal implementation of a single-train NovelEdge IGCC would require a gasifier larger than those currently available (although H-class CTs are also motivating gasifier suppliers to increase capacity).
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Near-Term RD&D Needs for Supplemental Firing and HRSG Optimization
To allow accelerated implementation of supplemental firing and steam cycle optimization options, near-term RD&D efforts should focus on determining the best design paths for optimizing overall economics of an IGCC plant while minimizing technology risk.
A thorough review of the potential issues with syngas duct firing should evaluate and document:
• Past power industry experience with duct firing of syngas and similar fuels.
– IGCC experience at the api Falconara plant in Italy (vacuum residual)
– Other North American, European, and Asian experience
• Transferability of design and safety practices from the petrochemical industry to the power industry, including:
– Experience with furnaces and cogeneration units operating on refinery gas, hydrogen, and other fuels
– Potential safety issues associated with the possibility of H2 or CO leakage
– Materials issues due to potential corrosive attack by hydrogen, CO, or low concentration contaminants
• Burner design and the impact of syngas duct firing on stack emissions
– Design of burners to handle syngas with natural gas backup
Single or dual burner setup for optimization
NOX formation and low emissions designs
CO formation or bypass
Unburned hydrocarbons
– Flexibility for hydrogen-rich syngas firing in case of CO2 retrofit
– Duct firing impact on SCR design
• Firing temperature limitations on HRSG materials (liner)
– Identify the point at which refractory is required
• Duct firing impact on syngas processing requirements
– Impact on sulfur removal requirements
– SO3 formation in duct burner
– Impact on ammonium bisulfate fouling if SCR included
– Expansion of process options or accrual of cost savings through ability to exploit lower-pressure and lower quality gas streams via duct firing rather than recompression
• Verification of supplier options for gasifier sizing suitable for cost-effective supplemental firing cases
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An independent review of the NovelEdge technology should include:
• Verification of the claimed benefits of the NovelEdge concept
• Comparison of the benefits of the NovelEdge technology with generic supplemental firing and related innovations
• Comparison of the economics and operating characteristics of conventionally designed IGCC units to IGCC with NovelEdge design, including the impact of later retrofit of CO2 capture for each case
Longer-Term R&D Needs for Supplemental Firing and HRSG Optimization
Over the longer-term, R&D efforts for supplemental firing and steam cycle optimization will focus on CO2 minimization and adaptation for CO2 capture. This will require greater focus on overall cycle efficiency and on the combustion dynamics and heat transfer implications of using hydrogen-rich fuel.
For implementing SC-HRSG and USC-HRSG technology, RD&D should address:
• Metallurgy for syngas-fired CT exhaust at SC and USC conditions
• HRSG heat transfer design for minimum pinch conditions
• Modification of CT design and operating practices to favor higher exhaust gas temperatures
• HRSG design for extreme duct firing temperature
• HRSG design with high-temperature refractory linings
• HRSG design with waterwalls
• For post-capture conversion, duct firing with hydrogen-rich syngas
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7 IMPROVED GASIFIER REFRACTORY FOR INCREASED IGCC AVAILABILITY
To be economically successful, IGCC plants must be available to produce power when it is needed. Ideally, key plant components can be made be sufficiently reliable to remain in service over an extended period of time. If this is impossible, or cost prohibitive, the plant must have an adequate spare that can be placed on-line as needed, or it must be possible to maintain the component (or its spare), and return it to service in a reasonable timeframe.
Much of the IGCC RD&D Augmentation Plan focuses on addressing the shortcomings in “reliability,” “availability,” and “maintainability” (RAM) that have compromised the success of current IGCC plants. One particular area of ongoing challenge—and a potential high payback in RAM improvement—is refractory-based gasifier wall linings. The IGCC RD&D Augmentation Plan sets a life goal for such refractory materials of 24,000 fired hours.
Gasifier Refractory Fundamentals
High-temperature slagging coal gasifiers typically use one of two techniques to protect the steel walls of their containment vessels from high-temperature loss of strength and high-temperature-related material degradation mechanisms. One approach, used in the Shell and Siemens (originally GSP) gasifiers, employs water-cooled membrane walls to produce a frozen slag layer on the wall surfaces. Molten slag then flows down over the frozen “protective” slag layer. This scheme requires a complex and costly cooling and control system, but the water-cooled membrane walls have an estimated lifetime of 25 years. The other approach involves a multiple-layer refractory lining. This approach, which is used in the ConocoPhillips E-Gas and GE Energy gasifiers, allows for a significantly lower cost gasification vessel, but the repair and/or replacement of the refractory lining is frequent and expensive. An illustrative sketch of the refractory system is shown in Figure 7-1.
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Figure 7-1 Slagging Coal Gasifier Containment Vessel Cross-Section with Multiple-Layer Refractory Lining
The inner layer of the structure consists of a chromium-oxide-based refractory. It must withstand severe gasifier operating environments, which typically entail temperatures of 2450–2900°F (1350–1600°C), pressures >400 psi (28 bar), thermal cycling, alternately reducing and oxidizing environments (the latter occurs during gasifier pre-heating), corrosive gases, and corrosive slag of variable viscosity derived from the mineral matter in the coal. This coal slag attacks the refractory as it flows down the refractory surface during gasification operations. Variations in operating temperature and slag composition result in different rates of attack. The highest rate of attack occurs in the slag tap zone of the gasifier. These attacks result in both spalling and a combination of dissolution and wear of the outer refractory surface, as indicated in Figure 7-2.
Typical intervals for planned refractory replacement, which require 3–4 weeks of unit downtime, range from 3 months to 18 months depending on the slag properties and severity of the operating conditions. Unplanned outages are also required periodically for minor refractory repairs.
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Figure 7-2 Typical Refractory Attack Mechanisms
Research at DOE’s Albany Research Center (ARC) has focused on the development of improved chrome-based refractory materials via the addition of aluminum and chrome phosphates (AlPO4, CrPO4). Phosphate addition offers the following potential benefits:
• A denser refractory body by reducing the volume of interconnected porosity and pore sizes
• Enhanced bond strength of aggregates
• Higher viscosity of the penetrated slag
• Higher melting point of the penetrated slag
• Lower “wetability” of the slag and/or refractory
• Increased corrosion resistance
• Increased thermal shock resistance
• Sealing of the refractory surface
• Quicker solidification of the slag within the refractory
Potential Advantages
The availability of improved refractories will result in reduced gasifier downtimes, reduced operating costs, and increased reliability and availability, all of which are required to reduce the COE from IGCC plants. If a 36-month (~24,000 fired hour) replacement cycle goal could be achieved, in addition to saving the cost of the refractory replacement—about $1 million per
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change-out including materials and labor51—the availability of the gasifier would increase by 2.5 to 5.0 percentage points and the motivation for having a spare gasifier to improve availability (or having to accept a lower availability rate) would be eliminated.
The 36-month cycle would also allow refractory replacement to be on the same schedule as the combustion turbine hot-section overhaul. CT hot-section overhauls usually require 6 weeks of outage time, so no additional outage time would be required for the refractory change out (i.e., the refractory change outs would occur during the CT overhauls).
Current Status
The new ARC refractory formulations based on phosphate additions are being tested in two commercial gasification plants. The actual refractory bricks used for these tests were produced by Harbison-Walker. Initial results of these two tests are promising. At one site, the sidewall containing test bricks looked good during an inspection after 110 days. The test was then extended and continued past 150 days at last report. In that same unit, where test bricks were installed in the lower cone area, the run ended for other reasons and the brick was replaced after 17 days of operation. Two more tests are planned for the lower cone. At the second site, the initial operation with test bricks installed in the sidewall exceeded 50 days and was still running at last report.
ARC is also looking at non-Cr-based refractories and at refractory coatings as alternative approaches, and EPRI endorses this “portfolio” or “hedge” strategy.
The typical path for development of a satisfactory, improved refractory material is long and arduous. For example, the ARC program began in earnest in 2002. It involved lab-scale exposures to gasifier slag at high temperatures in small crucibles, fabrication of commercial size bricks for use in larger lab tests, testing in a rotating “fired barrel” that simulates slag flowing long the refractory wall, testing of a small number of bricks in a commercial gasifier (in 2005), and finally testing of a complete replacement with the new refractory in a commercial gasifier. This last step, obviously, involves significant commercial risk.
However, there is time for further development of additional improved refractories that could be used in the next round of commercial IGCC plants. For example, refractory for an IGCC that begins construction in 2008 for a 2012 startup does not have to be proven ready for commercial use until perhaps 2011, when the gasifier will be bricked for the first time.
Commercialization Issues
It is too early to determine whether the ARC refractory will achieve the 24,000-fired-hour goal, but nevertheless, EPRI believes it is important to have more than one alternative for long-life refractory. Cr2O3-based refractory is not an ideal solution for gasifiers because: 51 S.J. Clayton, et al., Gasification Technologies, U.S. Dept. of Energy Report DOE/FE-0447, Germantown, MD 2002.
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• The cost of the material is high
• Fabrication limitations (bricks cannot be sintered to make desired shapes)
– There is only one U.S. supplier (Harbison-Walker) that has supplied improved refractory to date. However, Ceramatec has reportedly expressed interest in qualifying as a supplier.
– Potential environmental regulation of both brick production and disposal because of Cr content
– High alkali feeds (e.g., biomass) could cause problems with Cr in the slag
– If there is no alternate supplier, then the price for phosphate-enhanced Cr2O3 refractory may not be competitively priced
What is the most appropriate entity to conduct RD&D of new gasifier refractory?
• Gasifier OEMs?
• Refractory companies?
• U.S. Dept. of Energy?
• Utility-led consortium?
Near-Term RD&D Needs
• Development of alternate U.S. suppliers of phosphate-enhanced chrome-based refractories
• Development of repair techniques that could extend refractory life
• Development of non-chrome-based refractories
• Development of lower-cost refractories
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8 SIMPLIFYING GASIFIER DESIGN, FEED, AND DISCHARGE
The designers of gasification systems for IGCC plants face the challenge of converting solid coal into a continuous flow of high-quality syngas fuel for a combustion turbine. Accordingly, they must devise a process that transfers solid coal from atmospheric pressure to a large vessel operating at very high pressure and temperature. They must also maintain uninterrupted gas flow from this vessel and remove solid slag or ash byproducts from the vessel.
To date, all solutions devised for gasifier feed and slag or ash discharge reflect significant compromises. For example:
• Slurry-fed gasifiers entrain solid coal in liquid (water is most commonly used), which can be pumped at high pressure. Unfortunately, much of the heat contained in the coal is used to vaporize the liquid.
• Dry-fed gasifiers use lock hoppers with combinations of valves to fill, seal, pressurize, and discharge the lock hopper chamber, in a batch process, while discharging a continuous, metered flow of coal from the feed chamber to the reactor. Problems encountered include:
– The high pressure lock hopper and valves are heavy and require a tall steel superstructure which adds to the capital cost of the gasification block
– Significant quantities of nitrogen and auxiliary power are required to alternately pressurize and purge the lock hopper and feed chamber
– Lock hopper valves wear and require significant maintenance costs
• Many gasifiers also require a lock hopper arrangement for removing slag
• Most gasifiers utilize a large, high-pressure, high-temperature vessel to provide adequate retention time, pressure, and temperature to achieve the desired gasification reaction. Thick walls and a high-performance refractory or waterwall system are required to allow the pressure vessel to be constructed with cost-effective materials and withstand the necessary conditions.
The initiatives addressed in this chapter seek innovative solutions that provide simpler and less expensive means of achieving gasification and the associated gasifier feed and discharge. The targeted solutions include:
• A dry coal pumping system that provides continuous feed and eliminates the expensive lock hopper and valves and reduces nitrogen consumption
• A continuous slag pressure let-down system that eliminates the expensive lock-hopper and valves currently used for removing slag (see Chapter 4)
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• A CO2-coal slurry feed system that requires much less heat for vaporization than water-coal slurry (see Chapter 4)
• A paste feed system in place of the current slurry feed system. In recent years, mining technology vendors have developed methods for pumping solids in a paste form, with lower water content than is required for slurry pumping. The power industry is experimenting with similar methods for coal feed to high-pressure fluidized-bed combustors. Significant gains in thermal efficiency may be possible if an effective paste-feed technology could be developed for gasifiers that are currently slurry-fed.
• A compact gasification system that uses a dry coal pumping system and rocket-engine-derivative design concepts to substantially reduce the size and cost of the gasifier vessel
Stamet Dry Solids Feed Pump
As noted in Chapter 3, lock hopper gasifier feed systems are expensive, consume significant amounts of high-pressure nitrogen, and require frequent maintenance due to cycling of the large valves exposed to solids. A mechanical device, such as a direct-injection rotary feed pump, could reduce capital requirements and improve unit efficiency. With DOE support, Stamet Incorporated is developing and testing a mechanical device or “coal pump” at the Power Systems Development Facility (PSDF) pilot “transport gasifier,” operated by Southern Company in Wilsonville, AL. The long-term goal for the pump is to pressurize and feed coal at 1000 psi (70 bar). [Note: Current PSDF testing is at lower pressure due to a limitation in the pressure rating of the receiving vessel for the test.]
Technology Description
Gasification processes that feed coal to the gasifier as either a dry, fine powder (i.e., Shell) or as a dry, crushed solid (i.e., KBR Transport Reactor) utilize a series of lock hoppers to bring pulverized coal to reactor pressure and a transport gas, usually nitrogen, to inject the coal into the gasification reaction zone through feed injectors. These systems require a tall superstructure, are expensive, consume significant amounts of high pressure nitrogen, require energy to compress the pressurization gas, and require significant maintenance due to the frequent cycling of the large valves exposed to solids.
A mechanical device such as a rotary feed pump that has the capability of injecting the feed coal into a pressurized storage vessel (or directly into the gasifier) has the potential to reduce specific ($/kW) investment requirements and improve thermal efficiency by reducing pressurized N2 consumption. DOE has been sponsoring work by Stamet to develop a single stage mechanical device or pump that is capable of feeding coal to systems operating at pressures of up to 1000 psi (70 bar). Stamet has previously developed and commercialized solids feeders that are successfully used in other industries to inject atmospheric-pressure solids into low-pressure operating systems.
A sketch of the Stamet dry solids feed pump is shown in Figure 8-1. It was initially developed to feed crushed shale rock into high-temperature retorts that were used to liberate shale oil from the rock. The solids fall from the feed hopper into the space between two rotating plates that force
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the solids to move toward the discharge side of the device against the pressure of the fluids in the discharge zone. The particles form a seal as they rotate and gas leakage back through the solids is minimized. Because the device is a volumetric feeder, the amount of solids transferred is a function of the rotational speed.
Potential Advantages
As noted in Chapter 3, the expected benefits for dry-coal fed systems are a reduction in capital investment by eliminating the coal feed lock hopper system, a reduction in operating costs for lock hopper pressurization gas, and a one-percentage-point improvement in availability. The capital saving is estimated to total about $45/kW, which would reduce the levelized COE by about $1.10/MWh for a dry-feed gasifier.
Figure 8-1 Stamet Dry Solids Feed Pump
As noted in Chapter 3, EPRI only expects the Stamet pump to be able to replace the lock hopper system in the near term, but recognizes its long-term potential to feed undried coal (or biomass blends) directly into a gasifier without plugging.
Current Status
Laboratory work at Stamet facilities to date has successfully demonstrated that PRB coal, Eastern U.S. bituminous coal, and lignite can be injected into a vessel operating at 560 psi (39 bar) at flow rates of up to 4.8 ton/day. The solids used for these tests were not finely pulverized,
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but had ~50% passing 200 mesh (74 microns). Results of tests that investigated the linear relationship between rotational speed and the quantity of solids delivered confirmed that the Stamet feeder delivery is accurate and reproducible. Stamet is now developing a prototype to deliver coal into a 1000 psi (69 bar) system.
A test of a Stamet feeder at the PSDF was conducted in late 2005 and 2006. This test program focused on a 1000+ hr durability test of the Stamet pump in a stand-alone test loop. The test facility was constrained to 250 psig (17 barg) operation. PSDF staff would like to test the pump at up to 500 psig (34 barg) and up to 10 ton/day flow rate, but construction of a 500 psig receiving vessel is needed first.
In 2007, Stamet, DOE, and EPRI intend to collaborate on a test of a scaled-up version of the Stamet at the PSDF. Unlike the previous tests, the pump will deliver coal into the transport gasifier. The throughput of the pump will be 240 tpd, which is considerably larger than the capacity of the PSDF gasifier, so the pump will operate at part-load when feeding the gasifier. In off-line recirculation tests, the pump will be tested at full capacity. An EPRI supplemental project has been proposed for 2007; DOE will provide 80% of the funding for this effort.
Commercialization Issues
Some consideration has been given to the utilization of the Stamet technology in the 285 MW IGCC project at Orlando Utilities in Florida, which is based on the scale-up of the KBR transport gasifier at the PSDF. The current project design schedule will require system design decisions be made before the Stamet technology can be successfully demonstrated at sufficient scale and duration. Therefore, that project is likely to use a conventional lock hopper system for coal feeding.
One possible alternative is to design the Orlando Utilities plant so that a Stamet feed system could be added later to replace one lock hopper system.
The demonstration of the technology at another IGCC or gasification project host is also a possibility as an alternate path to commercialization.
Near-Term RD&D Needs
• How sensitive are Stamet components to wear related to particle characteristics of various feedstocks (e.g., coal, gasifier char, petroleum coke, high-carbon fly ash, slag, biomass, etc.)?
• Feeding tests are required at larger scale and long duration
• Are there alternative tests sites beyond the PSDF?
• Are other programs required beyond the PSDF effort?
• A test program is needed on finely pulverized coal before it can be used in Shell process
• A reasonably extensive demonstration of pressurized feeding into an entrained flow gasifier is needed
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Longer-Term RD&D Needs
As noted in Chapter 3, there are several potentially attractive applications in which a device such as the Stamet pump could be used to improve the efficiency of existing gasification processes and conceptual variations of those processes. These applications include the use of the device to:
• Inject crushed, surface-dried coal into the primary or secondary reaction zone injectors of pressurized gasifiers without the need for large quantities of carrier gas
• Reinject carbon-rich solids collected in cyclones or filters into pressurized gasifiers to appropriate zones of gasification reactors
• Control the continuous pressure let-down of either carbon-lean dry solids or wet ash slurries from pressurized vessels
• Feed biomass into pressurized fluid bed gasifiers
Realization of these longer-term opportunities suggest the need for R&D to commence on the following:
• Lab-scale (5 ton/day) tests pressurizing undried coal
• Lab-scale tests pressurizing and depressurizing gasifier ash and slag
• Dispersion modeling of coal injection
• Pilot-plant tests injecting coal directly from Stamet pump into gasifier
• Demonstration of these applications in commercial scale gasification plant
Potential Additional Long-Term Advantages
Current gasifiers fed with dried coal have differing requirements for the level of drying required to prevent coal from agglomerating as it moves through the specific transport system. Shell requires that coal be dried to less than 5% moisture content before it enters the lock hopper system to prevent the formation of agglomerates that would block the feed lines and injector ports. Coal mixed with nitrogen carrier gas is injected at high velocity into the very high temperature fireball in the reaction zone where its average residence time is fractions of a second. The KBR Transport Reactor process requirements are to dry low-rank coal to a moisture content of about 15–18% before it enters the lock hopper system. The challenge in the process is to inject the coal pneumatically into the gasifier with sufficient momentum to get it into the middle of the reaction zone. The average residence in the extensive reaction zone is several minutes.
If feeding undried coal directly into the gasification zone at required velocities without an accompanying transport gas were feasible, and the coal drying, lock hopper, and coal transport and control systems could be eliminated, the total capital savings are estimated at about $100/kW. The resulting system would then be analogous to a liquid fueled pump feeding a spray nozzle. The benefits would be large, but creating such a system is difficult.
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Reinjecting dry solids collected from cyclones and filters at various places in the gasification plant without the use of transport gas or slurry media should not be as difficult as injecting coal, because the dispersion requirements should not be as stringent.
The bulk of the ash removed from gasifiers fed with either dry coal or coal-water slurries is removed from the pressurized system as an ash/slag-water slurry. Some processes utilize a lock hopper system and others utilize a continuous pressure throttling system. The advantage of the latter is that it significantly reduces the total gasifier structure height. A Stamet pump could be envisioned as replacing lock hoppers in this service.
Pressurized fluidized-bed biomass gasifiers are currently fed through lock hopper systems. The use of a Stamet pump appears feasible for this application. A Stamet pump also appears to have the potential for injecting minor and separate streams of biomass into coal-fueled gasifiers. This co-feeding concept could also be applied to entrained flow gasifiers if a separate feed injector port was added for the biomass.
Another parameter not included in this analysis is the relative impact of the simpler, continuously operating Stamet pump on the overall gasifier reliability measures, especially when compared to batch-wise pressurizing lock hoppers with the many valve systems needed to manage the pressurizing and depressurizing of these vessels.
Status of Current Work on Longer-Term Opportunities
Beyond the testing of the Stamet pump described above under “Current Status,” none of the longer-term potential applications have been explored experimentally.
All of the longer-term concepts described are conceptual. A necessary first-step is the successful scale-up and use of the Stamet pump for pressurizing dried, pulverized coal, which is included as a near-term project in the IGCC RD&D Augmentation Plan. Once that is accomplished, small-scale experimental work is needed to explore the ability of the technology to pressurize undried coals of different types and particle size distributions. Pressurization and depressurization tests of gasifier ash and slag are also needed. Finally, tests injecting coal directly into a gasifier from the discharge of a Stamet pump are needed to verify that this can be done without a negative impact on carbon conversion or reliability.
One or more of the gasification technology vendors must become involved in the further development of these concepts to ensure that they would be implemented if successfully developed.
Pratt & Whitney Rocketdyne Compact Gasification System
As noted in Chapter 4, Pratt & Whitney Rocketdyne (PWR) is one of many organizations working to develop advanced gasifiers that reduce costs and increase carbon conversion rates and/or expand the range of acceptable fuels. A compact gasification system in particular holds the promise of significantly reducing the size and capital cost of gasification units.
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As described in Chapter 4, and illustrated in Figure 4-2, the PWR compact gasifier, based on PWR rocket engine technology, is an oxygen-blown, dry-feed, plug-flow entrained reactor with an actively cooled ceramic matrix composite liner that protects an underlying refractory wall. The gasifier employs multi-element injection to rapidly mix coal with hot steam and oxygen as it distributes it across the reactor’s cross-section.
Figure 8-2 PWR Compact Gasifier
The PWR dry solids pump continuously conveys pulverized coal from ambient pressure to feed system pressures of approximately 1200 psia (80 bara). Relying on similar principles as used by Stamet, the pump exploits the propensity for pulverized carbonaceous solids to bridge, forming an impermeable gas barrier that creates the pressure seal as the coal is fed through the pump and discharged into a high-pressure feed tank (see Figure 8-3).
Figure 8-3 PWR Compact Gasifier and Dry Solids Pump
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Potential Advantages
The key design features of PWR gasification technologies, and the potential advantages relative to existing dry-feed gasifier technology, are as follows:
• Dry solids pump. Continuous feed of dry solids at high-pressure (1200 psia, or 80 bara) via a mechanically simple low-cost pump, with a target pump efficiency of about 50% versus lock hopper efficiencies of about 25%.
• Compact plug flow gasifier. Reduces gasifier volume by up to 90%, if PWR projections prove out during testing. This will enable factory fabrication (versus field fabrication) for units matched to larger-scale combustion turbines such as the 60- and 50-Hz G-class machines. The compact design also promises low capital cost and short Mean Time to Repair (MTTR).
• Rapid-mix injector with dense-phase dry feed system. Facilitates “plug flow” regime within gasifier which allows for compact design without sacrificing carbon conversion efficiency.
• Unique cooled refractory liner design. Potentially simpler than “membrane wall” design and the compact size of the PWR design would allow rapid replacement of the liner.
• CO2 capture capability. High-pressure operation and a partial water quench facilitate cost-effective implementation of water-gas shift and CO2 capture.
PWR believes its feed pump and gasifier design will significantly improve gasifier availability. Given the early stage of development and lack of long duration testing, it is difficult to verify or refute this belief. Nevertheless, EPRI believes continuous dry feed pump systems such as those proposed by PWR and Stamet could improve availability by one percentage point compared to current lock-hopper-based dry coal pressurization systems. Current commercial coal-based IGCC units have reported little unscheduled outage time caused by their gasifiers.52 Therefore, the chief opportunity for improvement in gasifier availability is in the reduction of scheduled maintenance time. Nuon has indicated that its dry-feed gasifier supplied by Shell now requires three weeks of scheduled outage time each year, which means the gasifier is responsible for decreasing plant availability by approximately 6 percentage points. If an advanced gasifier by PWR or another supplier were able to cut scheduled outage time in half compared to the Nuon/Shell experience, IGCC availability would be 4 percentage points higher (3 points for the gasifier and 1 for the feed pump).
Table 8-1 compares the cost and performance potential of an IGCC design based on PWR or another supplier’s comparable technology to a current state-of-the-art IGCC. The capital cost and plant efficiency data come from a 2006 DOE analysis of the PWR design.53 The plant availability was based on EPRI’s judgment, as noted above, and the 30-year levelized COE was calculated using EPRI’s standard IGCC economic evaluation criteria. A compact gasification concept, as embodied by PWR’s design, meeting PWR’s high availability goals, would yield a
52 Evaluation of Alternative IGCC Plant Designs for High Availability and Near Zero Emissions: RAM Analysis and Impact of SCR. EPRI report 1010461, 2005. 53 M. Matuszewski, M.D. Rutkowski, and R.L. Schoff, Comparison of Pratt & Whitney Rocketdyne IGCC and Commercial IGCC Performance. U.S. Dept. of Energy Report DOE/NETL-401/062006, June 2006.
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potential COE improvement of about $3.50 per MWh over today’s dry-feed gasification technology for bituminous coal.
Table 8-1 Comparison of PWR Gasifier with an Existing Dry Feed, Entrained Flow Gasifier in an IGCC Application with Bituminous Coal (2004 $, EPRI-Edited Values)
Existing
Gasifier
PWR
Gasifier%
Total Plant Cost, $/kW 1519 1385 -8.8%
Net Plant Efficiency (HHV %) 42.0 42.2 +0.2 pt
Premised Availability (%) 85 89 +4 pt
Levelized Cost of Electricity, $/MWh 50.47 46.81 -7.3%
Because of its combination of dry feed and a partial water quench, the PWR design appears to be well-suited for production of hydrogen (as would other advanced designs by other suppliers with these features). Analyses sponsored by DOE, reported in DOE/NETL-401/061506, indicate that if the PWR system could achieve its cost and performance targets, it could reduce the cost of hydrogen production by approximately 25% relative to existing slurry-fed gasification technologies. This reinforces the importance of adding partial water quench designs to dry-feed gasifiers, as EPRI recommends in Chapter 4.
Development and Commercialization Status and Issues
PWR believes that proof-of-concept testing was completed for all key elements of its gasification system during the 1970s and 1980s, as shown in Figure 8-4. Blowdown testing of a dense phase (void fraction ~ 0.55) feed system was completed, and relationships between mass flux, pressure drop, line diameter, and line length were developed. Dense-phase feed allows uniform flow splitting, which was demonstrated on 3:1 and 6:1 flow splitters, yielding <1% deviation in mass flow rate along each of the splitter legs. Feed splitting enables multi-element injectors for efficient mixing of coal with oxygen and steam by reducing the hydraulic diameter of the reactant streams. The feed splitter and multi-element injector were integrated into a compact gasifier, where rapid conversion was verified for subbituminous and bituminous coal feedstocks.
Test results from the compact gasifier were used to validate a proprietary PWR kinetic model that serves as the basis for predicting gasifier performance as a function of feed stream conditions and residence time. A compact, rapid spray quench system was also demonstrated in testing by PWR, enabling a dry syngas product to be obtained at temperatures amenable to particulate removal using cyclones and metal candle filters. These proof-of-concept tests were typically no longer than 1 hour duration, which was sufficient to obtain test data validating technical feasibility, but not to assess component life or to thoroughly investigate the impact of operating parameters on key gasifier performance characteristics. Long duration testing was planned as a follow-on program.
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InjectorLiner Coolant
Chamber
Rapid-spray Quench
04CP-1118-027
InjectorLiner Coolant
Chamber
Rapid-spray Quench
04CP-1118-027
• Gasified coal, petcoke, and biomass (20-40 TPD)• Performed only short duration tests (< 1 hr)
• Gasified coal, petcoke, and biomass (20-40 TPD)• Performed only short duration tests (< 1 hr)
Flow Splitter
Rapid Mix Injector
Rapid Spray Quench
Dense Phase Dry Feed System
Compact Gasifier in Horizontal Position
04CP-1118-01404CP-1118-014
Figure 8-4 Proof of Concept Tests of Compact Gasification System Completed from 1975 through 1985
In the mid-1980s, as interest in coal gasification technology decreased in tandem with oil prices, further technology development was deferred. As the current era of constrained energy resources was emerging, PWR revisited the previously demonstrated technologies, and augmented the technology portfolio to incorporate recent rocket engine technology advances. Key among these was the use of ceramic matrix composites as a gasifier liner material in place of monolithic ceramic bricks or ramming mix. CMCs are high strength, relatively high conductivity materials with excellent thermal shock resistance. In conjunction with rocket-engine-style cooling approaches, CMC liners can provide the long life achieved with membrane wall reactors while tolerating the more demanding internal gasifier environment presented by the compact gasifier. A technology development program, now supported by DOE, was defined to demonstrate CMC feasibility in a gasifier environment, to demonstrate uniform splitting of dense phase feed at a commercial scale, and to define a gasifier pilot plant test program to provide the long duration test data required prior to advancing the technology to a commercial-scale demonstration.
Several tasks have been accomplished under the current DOE cooperative agreement: (1) three CMC liner test articles have been tested at the CANMET test facility in Ottawa, Canada, (2) a 400 tpd cold flow test facility is being constructed at the University of North Dakota’s Energy and Environmental Research Center to test the dense-phase feed system, flow splitter, and dry solids pump, and (3) an 18 tpd pilot plant has been defined to test the compact gasifier and quench system at the Gas Technologies Institute (GTI) “Flex Fuel Test Facility,” located in Des Plaines, Illinois. In parallel, PWR is developing the design of a commercial-size gasifier. Figure
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8-5 shows the two key facilities that will be used to test the compact gasifier and dry solids pump.
Current plans call for both components to be tested for at least 1000 hours to establish performance, operational, design, and component life data in advance of commercial-scale demonstration. The dry solids pump and feed system test are scheduled to begin in 2007.54 The test of the 18 tpd gasifier at the GTI facility has not yet been scheduled.
The intent is to follow these development tests with a 400 to 1000 tpd demonstration plant, which will validate the commercial readiness of the technology. Ultimately, PWR plans to license the technology to companies that construct, own, and operate plants, and provide licensees with critical components (the compact gasifier and dry solids pump) and after-market services.
Dry Solids Pump & Feed System
Test to be performed in 400 TPD cold flow test facility at EERC (Energy and Environmental Research Center)
Compact Gasifier & Quench System
Test to be performed in 18 TPD pilot plant at GTI (Gas Technologies Institute) Flex Fuel Test Facility
Figure 8-5 Locations of Facilities for Planned Tests of PWR Feed Pump and Gasifier
[Note: EPRI recognizes and supports in earnest the ambitious next-generation-design RD&D programs now under way by many suppliers of gasification systems worldwide. PWR efforts are described here as illustrative of the potential recognized throughout the industry for vast improvement in IGCC components and designs over the longer-term.]
54 K.M. Sprouse, D.R.Matthews, and G.F. Weber, “The PWR/DoE High Pressure Ultra-Dense Phase Feed System and Rapid-Mix Multi-Element Injector for Gasification,” Pittsburgh International Coal Conference, September 2006.
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9 IGCC PROCESS MODELING, MONITORING, AND CONTROL
The currently operating fleet of IGCC plants has experienced problems that can be attributed to insufficient knowledge at the time of their design in the early 1990s regarding how the plant process unit would operate in actual service. And although today’s IGCC plant designers still face this same issue, recent improvements in the performance and the cost of instrumentation, control systems, and process plant modeling software offer the prospect of reducing this knowledge gap. Advances in this “cross-cutting” area will contribute to realization of the potential benefits for virtually every near-term and longer-term element in the IGCC RD&D Augmentation Plan.
This chapter elaborates on the initiatives described in Chapter 3. They are aimed at near-term improvements in equipment and methodology for the prediction, design, commissioning, monitoring, and control of IGCC plant processes and equipment.
Improved IGCC Dynamic Models
Past experience with startup of IGCC plants points to the value that would come from a versatile dynamic model that accurately represents the integration processes and equipment. Applications could include:
• During the plant design phase, a dynamic model can be used to test the design of the plant’s control system by providing realistic, real-time process data to which the control system can respond
• During plant startup, a dynamic model can be used to drive a simulator for operator training before the IGCC is operational
• Once the plant is commissioned, a dynamic model can be used to predict the proper control settings when new feedstocks are introduced or new operating modes are proposed
As noted, such a model could also play a significant role in enabling other elements of the IGCC RD&D augmentation plan. Supporting opportunities include:
• Evaluating the impact of different levels of supplemental firing on net heat rate, power output, gas cooler operation, full versus part-load gasifier operation, etc.
• Testing the principles developed during the information-gathering phase of developing procedures for minimizing startup and shutdown length, prior to application of the procedures on an actual plant
• Verifying the added benefit of improved gasifier instrumentation
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• Verifying response times for improving gasifier control logic
Improved Computer Modeling of Gasifiers
Predicting the chemical reactions and products of the IGCC gasifier will require a thermochemical model similar to the tools used for process design in the petrochemical industry. This initiative aims to adapt existing, state-of-the-art process modeling software for the specific phenomena that are critical to gasification of different types of coal feed. Although such a model would probably not be easily combined with a dynamic integration model, it could provide a data table of “black box” inputs and outputs to be used in such a model. Chapter 3 provides an explanation of needs and expectations for such a model.
Minimizing Startup and Shutdown Length
The near-term initiative aimed at minimizing startup and shutdown length will draw on hands-on operator experience as well as on computational tools for process optimization. It is expected that the development of these procedures will also draw on input from the RAM database while the RAM database will benefit from the data gathering workshops that will develop the “human input” for this study. As noted in Chapter 3, improvement of best-practices for startup and shutdown operating modes will be important for meeting cost, production, and emissions goals for the next generation of IGCC plants.
Improved Gasifier Instrumentation and Control (I&C)
A 2005 EPRI paper, “I&C Needs of Integrated Gasification Combined Cycles”55 (see Appendix D) provides a comprehensive overview of the extensive instrumentation improvements and control systems integration that must be utilized to achieve desired goals for IGCC plant performance, reliability, and availability. Among the I&C improvements envisioned are:
• On-line monitoring of refractory wear
• Reliable optical access to the gasifier
• On-line coal quality analysis
• Rapid, on-line measurement of syngas composition using laser absorption spectroscopy
• Reliable gasifier temperature measurement
• On-line slag composition analysis or slag viscosity measurement or slag thickness measurement
Chapter 3 describes the near-term benefits expected from this set of improvements. It is expected that further I&C needs will be identified as lessons-learned are returned from other RD&D initiatives and from the startup and operation of the next generation of IGCC plants. 55 J.N. Phillips, “I&C Needs of Integrated Gasification Combined Cycles,” 15th Joint ISA POWID/EPRI Instrumentation and Controls Conference, Nashville, June 2005.
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A-1
A ABBREVIATIONS AND ACRONYMS
This list was excerpted from the CoalFleet User Design Basis Specification (UDBS) for Integrated Gasification Combined Cycle Power Plants, Version 2A, February 2006.
ABS ammonium bisulfate AGR acid gas removal ASU air separation unit, an oxygen/nitrogen plant BACT best available control technology barg bars, gauge Btu British thermal unit CC combined cycle CF capacity factor CFB circulating fluidized bed COE levelized busbar cost of electricity, often expressed in $/MWh CoP ConocoPhillips CT, GT combustion turbine, synonym for gas turbine CWS coal/water slurry DCS digital control system DOE United States Department of Energy dscf dry standard cubic feet dscm dry standard cubic meter EAF equivalent availability factor EPA United States Environmental Protection Agency EPC engineering procurement and construction contract or contractor EPRI Electric Power Research Institute FAC flow accelerated corrosion FD forced draft (fan) FOF forced outage factor FOR forced outage rate fps feet per second GADS Generating Availability Data System GAN gaseous nitrogen GE General Electric Company GEE GE Energy GOX gaseous oxygen GT, CT gas turbine, synonym for combustion turbine
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Hg mercury HHV Higher Heating Value (heating value of fuel if heat of condensation of water vapor from its
combustion products in a bomb calorimeter at 77ºF is included) HMI human/machine interface HP high pressure HPSS high pressure solids settler HRSG heat recovery steam generator HSS heat stable salts HTHP high temperature-high pressure particulate filter ID Induced Draft (fan) IGCC Integrated Gasification Combined Cycle; a type of electric power plant that uses syngas from a
gasifier as fuel for a combustion turbine topping cycle, and heat recovered from the combustion turbine exhaust and gasification process to produce steam for a steam-turbine bottoming cycle.
IGV inlet guide vane IP intermediate pressure ISO International Standards Organization K.O. knockout drum kW, kWe kilowatt electric kWt kilowatt thermal LAER lowest achievable emissions rate LHV lower heaving value (fictitious heating value of fuel if the heat of condensation of water vapor is
ignored; i.e., if the water in the combustion products were assumed to remain in the vapor state in the bomb calorimeter)
LIN liquefied nitrogen LOI loss on ignition LOX liquefied oxygen LP low pressure MAC main air compressor MCR maximum continuous rating MDEA methyldiethanolamine MMBtu 106 Btu, (million Btu) MP medium pressure MTPD metric tons/day MW, MWe megawatt electrical MWt megawatt thermal NA, N/A not applicable NAAQS national ambient air quality standards ND not detected NERC North American Electric Reliability Council NETL DOE National Energy Technology Laboratory NGCC natural gas-fired combined cycle NOX nitrogen oxides NPDES National Pollutant Discharge Elimination System
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NSPS New Source Performance Standards NSR New Source Review O&M operating and maintenance O2 oxygen ºC degrees Celsius OEM original equipment manufacturer ºF degrees Fahrenheit OHSA Occupational Health and Safety Administration P&ID piping and instrumentation diagram PC, pc pulverized coal PGM partial gasifier module PHA Process Hazard Analysis PM particulate matter ppmv parts per million by volume ppmvd ppmv, dry basis ppmvw ppmv, wet basis PRB Powder River Basin PSA pressure-swing absorber PSD Prevention of Significant Deterioration psia lb/square inch (14.696 psia = 1 atm) psig lb/square inch gauge [ (psia) – (local atmospheric pressure in psia) ] RCRA Resource Conservation and Recovery Act RD&D Research, Development & Demonstration RMS root-mean-square RO reverse osmosis S sulfur content of fuel SC Supercritical steam conditions (above 3200 psia or 220 bar, with temperatures typically >1000°F
or 540°C) scf standard cubic feet SCGP Shell Coal Gasification Process SCOT Shell-Claus off-gas treating unit SCPC Supercritical pulverized coal SCR selective catalytic reduction (for NOX control) SGC syngas cooler SO2 sulfur dioxide SOX sulfur oxides SRU sulfur recovery unit ST steam turbine SWS sour water stripper Syngas Synthesis gas t short ton (2000 lb) t/h, tph short tons per hour (2000 lb/h)
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t/y,tpy short tons per year (2000 lb/y) T250 the temperature at which the slag viscosity is 250 poise TBD, tbd to be determined TCLP toxicity characteristic leaching procedure TECO Tampa Electric TG turbine-generator, (turbine-generator) TGT tail-gas treatment TOC total organic carbon ton short ton, (2000 lb) tonne metric ton, (1000 kg or 2205 lb) TPC total plant cost UDBS User Design Basis Specification UHC unburned hydrocarbons U.S. United States USC Ultra-supercritical steam conditions (above 3500 psi or 240 bar and 1100°F or 595°C) USD, US$ United States dollar y, yr year ZLD zero liquid discharge
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B COALFLEET IGCC SUPPLIER & BUYER SURVEYS
This appendix contains the results from three surveys EPRI conducted in 2005 to ascertain stakeholder perceptions about the status and needs for IGCC components and designs. These surveys included:
• IGCC “Barriers to Deployment” Survey for Technology and Equipment Suppliers
• IGCC “Barriers to Deployment” Survey for Power Generators
• IGCC “RD&D Needs” Survey for Technology and Equipment Suppliers
IGCC “Barriers to Deployment” Survey for Technology and Equipment Suppliers
This section compiles the responses of 12 IGCC component or system supplier to an EPRI questionnaire. Individually identifiable remarks have been removed or edited to preserve anonymity. Form text and questions posed are in bold text. Responses are shown with bullets.
CoalFleet IGCC “Barriers to Deployment” Survey for Technology and Equipment Suppliers
EPRI’s CoalFleet for Tomorrow initiative is aimed at encouraging the deployment of more advanced (i.e., more efficient and cleaner) coal power plants – both combustion-based and gasification-based. To that end, EPRI is defining an advanced coal generation research, development and demonstration (RD&D) augmentation plan which is aimed at reducing the barriers to deploying advanced coal plants in the near term (in operation by 2012). The augmentation plan would not duplicate existing and planned RD&D projects. Instead it would identify additional work that needs to be done to reduce the barriers to deployment.
Because your organization is heavily involved in supplying technology for IGCC power plants, you have important insight about the market, the technology and the barriers to deploying IGCC technology. That is why we have asked you to participate in this survey. The results of this survey will be used by EPRI in defining the goals for, and the projects in, the CoalFleet RD&D Augmentation Plan. Your participation ensures that the plan will include the input of an important stakeholder in the future of IGCC technology.
Your typical scope of work in an IGCC plant:
• (Respondent answers omitted from tabulation)
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Based on feedback from potential customers, what are the most common reasons you are given for why IGCC is not selected for a new coal power plant project?
• Prior to the U.S. Energy Bill of July 2005, the main reasons mentioned are the competition of pulverized coal (PC) power plants that are available at lower captial costs. Availability has been mentioned sometimes, but has in all cases that we were involved in been changed to full acceptance, reviewing the satisfactory performance of the European IGCC power plants in Buggenum and Puertollano in the meantime.
• Capital cost too high and IGCC not proven yet. (Doesn’t feel either are valid)
• Investment cost, reliability of existing IGCC´s, non-comfort of utilities with operating a chemical plant
• Most reasons are based on total economy, especially the backflow of capital
• Large-scale coal IGCC plants have not been constructed and the risks of being first are too great
• IGCC cost-of-electricity appears to be higher than PC plants; customers will not accept the higher costs
• There are few if any EPC contractors and suppliers who will provide adequate guarantees of cost, schedule, and initial and long-term performance
• Higher price relative to competing power generation technologies Lower availability relative to competing power generation technologies Complexity of operation Unprovenness
• The capital costs is too high; not yet sufficiently proven technically and commercially; too many unpredictable problems during initial operations
• Higher cost; “new technology” risk; availability concerns; overall plant guarantees that are available
• Capital cost too high (primary reason) Reliability not high enough (primary reason) Concerns about getting a coal-based plant permitted, even one based on clean coal technology (particularly in areas without existing coal-based power generation)
• Capital cost and reliability concerns
• Syngas purification in the hot phase missing
• kWh produced in IGCC is said to be more expensive than in pulverized-coal-fired plants
• IGCC is too complex
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• RAM issues said to be better with PC fired plants (little commercial experience available)
The following is a list of technical aspects of IGCCs that could be barriers to deployment. Which of these, if any, do you believe need the most improvement, so that IGCC can gain wider adoption by electric power generators? [Editor’s Note: More than one could be chosen; left column indicates number of respondents selecting the item.]
10 Capital Cost
4 Operating & Maintenance Cost
10 Reliability & Availability
0 Heat Rate
2
Turn-down Capability
Useful Comment: Ideally, the first few fully commercial IGCC plants will be specified and designed for base load operation. Extras, such as demanding turndown requirements, can exacerbate IGCC’s economic challenges, particularly at this early stage of full commercialization.
0 Feedstock Flexibility
3 Cost and Performance of IGCC on Lower Rank Coals
0 CO2 Capture Readiness
1 By-Product Utilization
4 Other (please specify):
• Improved higher elevation performance relative to PC plants
• CO2 capture lower costs and efficiency
• Mentality change of plant operators and decision makers necessary
• It is strongly recommended to form teams consisting of process owners and key component suppliers (task forces) in order to design and optimize the plant layout. Competition during the development phase between different parties is counterproductive.
• The resurrection of supercritical technology in the U.S. has raised the bar for IGCC.
The following is a list of non-technical aspects of IGCCs that could be barriers to deployment. Which of these, if any, do you believe need the most improvement, so that IGCC can gain wider adoption by electric power generators? [Editor’s Note: More than one could be chosen; left column indicates number of respondents selecting the item.]
6 Too difficult or costly to get a Lump Sum Turnkey (LSTK) bid with performance
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guarantees vs. other coal technologies
Useful Comment: There is a very limited number of engineering contractors willing or able to offer gasification/IGCC projects on a LSTK basis. While this is a market advantage for those who take an active role in this market, we believe that a shortage of engineering contractors willing to accept such LSTK contracts for IGCC will limit the realization numbers of IGCC plants.
Useful Comment: A very significant issue
1 IGCC not considered commercially ready by regulatory authorities
3 IGCC won’t get rate base approval from regulatory authorities
4 Environmental regulations not expected to give sufficient credit to IGCC’s environmental performance
4 Customer difficulty in finding financing for an IGCC at reasonable terms
1 Customer difficulty in recruiting and training qualified operating staff
4 Generally insufficient IGCC knowledge within customers’ organizations
6 Other (please specify):
• Gasification is proven since over 60 years, and a number of over 400 gasifiers are currently in operation worldwide. However, most of the gasification applications are for chemicals, such as ammonia, hydrogen, methanol, oxo syngas, reducing gas, etc. and only a very small fraction, 1-2 %, is for power generation. Thus, gasification is neither new, nor unproven, nor unreliable, but plays in a different league: the chemical world, not the power/utility world. Consequentially, acceptance of gasification for IGCC applications remains a publicity and communication issue. Utilities need to see, touch, visit operating coal gasification plants around the world – even if they do not produce electricity but syngas: the gasification island is principally identical.
• Energy industry investment criteria now based on conservative forecasts of natural gas and oil prices. Until the industry accepts that oil and gas prices have reached a higher permanent plateau, no private capital will flow into new clean coal or clean refinery assets.
• Supplier constraints in supplying qualified engineers to design IGCC plants
• Supplier constraints in supplying basic materials and equipment and specialty hardware with firm prices and delivery in a constrained global economy
• Lack of adequate incentives from the Federal and State governments to fill deployment gaps
• Local community opposition to coal plants, including those using clean coal technology
• There are too few IGCC plants now in operation to have confidence that the plants will
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startup and operate as advertised. Thus the economics during first several years could be at best unpredictable and at worst highly negative.
• Dealing with the negative perception of coal re: getting an IGCC plant permitted in an area without coal-based power generation
• Don’t see non-technical barriers as areas where EPRI should be focused – spreading knowledge of IGCCs is one exception since it is really a technical issue
• Learn from the development of nuclear power generation: What is the strategy and tactics to convince politicians, public and utilities to accept this technology? A similar path is recommended to be found to gain acceptance for IGCC. (In other words, communication on all levels is necessary to show the advantages and disadvantages of the technology).
In your opinion what specific sections of an IGCC plant are in need of the most improvement? Is sufficient RD&D effort underway to bring about the needed improvement?
• Improvement required to lower capital cost of major equipment. This will happen over time, when these plants will be built in series, such as the ~15 new coal gasification projects currently happening in China.
• R&D effort should now focus on optimization and improvement of commercially proven gasification processes, and not focus any longer on spending more money and time for yet another gasification pilot plant somewhere in the world. Gasification is developed, fully commercialized in the chemical plants world, and should now only be optimized. Clear recommendation from one of the organizations that has designed their own gasification technologies to full commercial success: It takes 30 years from development of a new gasification process in a pilot plant, through a demonstration plant, then through a commercial-scale plant to have a market-ready product.
• No further R&D money for new gasifier inventions – only optimization to proven/commercial processes!
• Optimized integration design work is needed. There is little public effort going on this topic (suppliers are working on it internally).
• Reliability/availability of air separation unit and gasifiers
• Optimization of integration between gas and power island with respect to operability/reliability
• The most improvement is needed for cooperation of all parts of IGCC, e.g., the improvement of the availability of every single part to improve the total availability of the IGCC complex
• Refractory life for slurry fed gasifiers Advanced multiple stage gasifiers Control systems for multiple train integrated, highly efficient IGCC plants Hydrogen rich fuel turbines Next class of turbines; G and H models.
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High efficiency air separation technologies High efficiency carbon capture technology
• Feed pressurization, gasifier injectors, refractory, syngas coolers, solids removal (wet and dry), gas turbine, HRSG, process water treating
• Except for a few systems (gasification, particulate scrubbing, syngas coolers, and process water cleanup), IGCC technologies are fairly well-proven and predictable in operation. In these areas, the current problem is not so much as insufficient RD&D, but rather every plant to date has been a one-off design with new design features and technology step-outs. If the next round of plants incorporate lessons-learned and apply only prudent technology enhancements, they should work well and meet customer expectations.
• RD&D primarily is needed to bring cost-reduction technologies to the longer-term market (2012 and beyond) and to make gasification of high-moisture Western coals more economically attractive
• Process injectors (burners), gasifier startup, slag handling, fly ash fouling of syngas cooler, fly ash filters
• Gasifier reliability is in need of the most improvement (need improved burners, refractory, etc.)
• Gasification island needs most improvement, unsure of industry efforts. Gasifer burner and refractory life continue to be issues. Also heat recovery section.
• CT reliability is the #1 priority and very little work is visible on this topic
• Stamet pump is #2 priority – feel current level of effort is sufficient for short term, but additional $s will be needed later to go to larger scale
• Gas clean-up is an area that needs improvement
If EPRI could arrange or facilitate funding and/or a demonstration for only one near term IGCC RD&D topic aimed at breaking down the barriers to deployment, what topic should that be? [A “near term” RD&D demonstration is defined as one which would enable the subject technology to be offered commercially in 2012, with traditional guarantees for nominal 600 MW IGCC plants. Assume that 3-5 new IGCC plants of nominal 600 MW capacities will be on-stream in the U.S. by 2012 as a result of appropriating the incentives now authorized in the current Energy Bill.]
• In order to make maximum use of economies of scale, a single train gasifier for such capacity should be designed. One of the major barriers in gasification plants is the multiple train philosophy, where significant capital cost is invested for complete hot or cold stand by trains. Gasification needs to be a commercial product that can handle 600 MW IGCC nominal capacity in one single gasifier with equal availability and robustness. This would be the best investment of RD&D money and efforts, and is an achievable and very realistic task.
• EPRI should arrange for demonstration of selected improvements (did not nominate any) in
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the new IGCCs that get built by 2012. None of the project developers are going to be willing to accept the risk of new technologies. How then, do they get to be proven? EPRI can help.
• IGCC with higher feedstock flexibility (Lignite, biomass, wastes, high ash coal) as this would result in advantages of a EUROPEAN solution vs. U.S. demo technology
• The main topic is the further raising of the efficiency of the IGCC process. One aim could be the implementation of a hot slag discharge and a hot desulphurization of raw gas to use of the latent heat as much as possible.
• A multiple stage high efficiency gasifier with very long life refractory
• An integrated drying and gasification system for more efficient use of low-rank coals
• Our real need is not to demonstrate simply one R&D project at a time, but to have a site where key IGCC improvements can be demonstrated in an integrated manner at the 200 to 400 ton per day size. If EPRI could assist us in finding a suitable site that meets our requirements, that would be a great help.
• RD&D aimed at improving gasifier reliability is the highest priority need
• Perhaps not an R&D topic, but support to significantly improve reliability seems very worthwhile
• We are not aware of EPC RD&D that EPRI should fund or facilitate
• CO2 removal for sequestration
• Would like to see a detailed review of IGCC technology broken down into plant sub-sections: what designs have different plants used, what have been the lessons learned?
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Please comment on any other RD&D items you believe are needed to make IGCC plants more widely adopted in the near term (consider items outside your organization’s core expertise that you’d like to see someone else develop).
• Improved syngas ready gas turbines: New, larger scale gas turbines are needed to reduce capital cost and increase IGCC efficiency. This task must be handled by the major gas turbine manufacturers who all have syngas experience. Again: the “chemical plant,” gasification island, is proven since decades several hundred times, but the combination with suitable and reliable gas turbines remains a real challenge in economic and technical regards.
• In the European IGCC projects, the published availability analysis clearly showed that the gas turbines have caused more outages of the IGCC than the gasifiers by themselves. And although this is widely known in the “gasification world,” utilities remain to worry about the gasifier first. Thus, gas turbines are a key area of improvement potential!
• Need to make better use of existing commercial gasification plants to conduct R&D. Again, none of these plants would be willing to demonstrate new technology on their own, but might if subsidized.
• Dynamic analysis of load change behavior, Hydrogen gas turbine, Cheaper and more reliable Low temperature shift catalysts
• I believe that it would be necessary to come to higher input temperatures into the gas turbine and also higher to pressure steps in the whole IGCC process
• Long life refractories
• One area outside of our organization’s skill set is oxygen production, for which reductions in capital and operating costs as well as improvements in efficiency and reliability continue to be very important. We are aware that there are a number of ongoing RD&D efforts involving major industrial gas suppliers. We support these efforts and would encourage organizations such as EPRI to assist in any way possible to bring to commercialization these new technologies that represent significant improvements over the conventional cryogenic technology.
• In addition, EPRI could contribute significantly to the emerging gasification industry by helping to identify beneficial uses for the byproducts of gasification – slag and elemental sulfur. As more gasification plants are built and byproduct volumes increase, it will become more challenging to find a home for these materials.
• Carbonyl formation, separation, and fouling of SCR
• Efforts to establish an IGCC design philosophy and an IGCC design basis, and infusing the discipline to make the often difficult choices and compromises in establishing such a design basis is very important(e.g., reducing capital cost vs. increasing plant flexibility)
• Establishing how to best integrate the ASU with the rest of the IGCC facility
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• Syngas purification in the hot phase
• Implementation of raw gas / clean gas exchangers
Do you perceive any significant differences in the barriers and the programs to address those barriers amongst the different classes of potential customers; e.g., public utilities vs. municipals vs. IPPs?
• IPPs need project financing, requiring LSTK “wrap-around” contracts, and have a higher focus in overcoming the financing side of the projects. However, IPPs have little to no technical barriers, and accept IGCC as a commercial product, relying upon the EPC contractor to deliver an operating plant. Public utilities could afford a cost reimbursable EPC contract with lower risk shifting to the EPC contractors, but their barriers are more focussed on permitting and public acceptance of new power plants. Municipals are driven by cost comparisons and have little to no knowledge about gasification or IGCC, and need to make decisions based on a capex/opex cost analysis.
• While the perspectives to IGCC are different by those 3 groups, the barriers remain in principle the same: cost and acceptance in public are major issues to be addressed
• Not in terms of the RD&D that’s needed. Same projects will help all 3 types of customers.
• Yes, smaller customers are more willing to adapt a technology bearing aspects of a chemical plant than big ones
• Yes, the differences are dramatic. IPPs face great challenging obtaining private bank financing for very large capital projects with “first mover” technology. Municipals are 100% financing with public debt which is risk adverse. Municipals also do not have the technical staffs and skills to execute very complex projects Investor Owned Utilities have the greatest technical and financial resources, but have strict obligations to serve their monopoly service territories with the most prudent and low-cost services.
• IPPs are more likely to accept newer technology, but will always pick the lowest cost approach
• Customers who intend to project-finance IGCC projects initially put more emphasis on the commercial (not technical) barriers of project development (commercial wrap, etc). Operating companies, whether they intend to project finance or not, tend to place more initial emphasis than do financial developers on the technical aspects of the project. They all focus on the high capital cost and high project development costs of current IGCC designs. We believe that these near-term hurdles can be overcome through the reference plant approach in which parallel and second generation plants are design and constructed to very similar design criteria. Plants will cost less to develop, be more easily financed, cost less, have shorter startup periods, and operate as advertised. The reference plant approach allows for RD&D enhancements.
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• For municipalities, the barriers to entry are the same as for utilities. However, municipals follow utilities - letting the utilities with more load base (and money) try out new technologies. Once utilities have built and are operating a few IGCC plants, the larger municipals will follow (they'll have to - as emissions will dictate). As for IPPs, they won't lead the pack as the perception (today) is IGCC is more expensive (IPPs are very bottom line driven as they don't have an obligation to serve). Once emissions are lowered to IGCC capabilities and PC either can't attain the same levels or it's cost prohibitive, then bigger IPPs will follow.
• Yes. Although there will be common themes(e.g., reducing capital and increasing reliability), it is expected that the different pressures on different classes of potential IGCC owners will result in some differences in perceived barriers and in the programs best able to address those barriers.
• Non-technical barriers may be different, but the technical barriers are really the same
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IGCC “Barriers to Deployment” Survey for Power Generators
EPRI compiled responses of 7 power generator to a questionnaire distributed in 2005. Individually identifiable remarks have been removed or edited to preserve anonymity. Form text and questions posed are in bold text. Responses are shown with bullets.
CoalFleet IGCC “Barriers to Deployment” Survey for Power Generators
EPRI’s CoalFleet for Tomorrow initiative is aimed at encouraging the deployment of more advanced (i.e., more efficient and cleaner) coal power plants – both combustion-based and gasification-based. To that end, EPRI is defining an advanced coal generation research, development and demonstration (RD&D) augmentation plan which is aimed at reducing the barriers to deploying advanced coal plants in the near term (in operation by 2012). The augmentation plan would not duplicate existing and planned RD&D projects. Instead it would identify additional work that needs to be done to reduce the barriers to deployment.
Because your organization is considering, or has considered, building an IGCC power plant, you have important insight about the market, the technology and the barriers to deploying IGCC technology. That is why we have asked you to participate in this survey. The results of this survey will be used by EPRI in defining the goals for, and the projects in, the CoalFleet RD&D Augmentation Plan. Your participation ensures that the plan will include the input of an important stakeholder in the future of IGCC technology.
Your company’s classification (Left column indicates number of respondents selecting item)
2 Public Utility
1 Municipal
2 Independent Power Producer
1 Other (please specify)
Independent power developer specializing in deploying gasification technology for base load applications
Does your Company intend to build “Advanced Coal Power Plant(s)” during the period 2010–20 (on-line dates)?
If Yes, … (Individual inputs of 7 respondents)
Number Size Type of Fuel supply
3 2 1 1 1
600 MW 600 MW 600 MW 600 MW 650 MW
Bit & Subbit, Ill. #6, Pet coke & PRB,
Illinois basin, PRB,
PRB+ pet coke or Bit,
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2 6+
500 – 600 MW 500 – 600 MW
Coal – pet coke - renewables
For a decision within the next two years, which technologies will be considered for your application? [Editor’s Note: More than one could be chosen; left column indicates number of respondents selecting the item.]
PC – Subcritical
2 PC - Supercritical
PC – Ultra-Supercritical (>1100ºF)
7 IGCC – Power only
3 IGCC – Power plus hydrogen or other “polygen”
CFB
Please identify the reason or reasons for excluding technologies from near-term (within 2 years) consideration (note reasons for each technology excluded)
PC – Subcritical
• Tight emissions control technology needed to speed permitting is not proven at scale of 600 MW, not sequestration ready, at 500-600 MW cap cost is similar to IGCC (it is better at 1000 MW but then it is difficult to sell that large a chunk of power), >2-5 years to get a permit which makes putting together a power purchase agreement very difficult, more water usage
• Efficiency, not likely to be permitted in our state and too much future environmental uncertainty
• Efficiency is too low & power boilers have high air and solid waste emissions & mercury capture is expensive & carbon capture will be too expensive
• Current and future environmental risk
• This technology is subject to significant heat rate erosion and capital investments to comply with any anticipated carbon management scenario
• Efficiency is lower, which increases CO2 emissions
• Efficiency too low, so emissions and production unit costs not competitive
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PC - Supercritical
• Environmental, political
• High capital cost and solid waste and air emissions may be competitive but NOT suited to carbon capture (let alone cost effective carbon capture) and mercury capture is seen to be expensive
• Current and future environmental risk
• This technology is subject to significant heat rate erosion and capital investments to comply with any anticipated carbon management scenario
PC – Ultra-Supercritical (>1100ºF)
• Environmental, political
• High capital cost and limited operating experience in the U.S. (i.e., not proven) and inferior to IGCC for carbon and mercury capture and still has high solid waste disposal issues
• Current and future environmental risk
• This technology is subject to significant heat rate erosion and capital investments to comply with any anticipated carbon management scenario
• Reliability is expected to be lower which overcomes gains from better efficiency
• Not demonstrated yet in long-term successful operation
IGCC – Power only
• Has advantage of more jobs – would not be best choice for western coals, but they want to use local coal to increase local support
• Are seriously considering this because it is in the market and is environmentally responsible for today and gives potential options for future environmental regulations
• Regulated utility dispatch decision process conflicts with IGCC need to operate, but there are relationships that support IGCC
• Not yet cost-effective and support from Utility Commission doubtful
IGCC – Power plus hydrogen or other “polygen”
• has advantage of more jobs but market for methanol is limited, nevertheless it helps business plan by utilizing off-peak capacity to make a saleable product
• needs additional development and product market development. Believe it will happen.
• Clearly there is a need to demonstrate to the ability to meet the availability and capacity expectations of power generation before adding the any additional complexity of polygeneration
• This would increase complexity and risk beyond what we could tolerate
• Not yet cost effective and support from Utility Commission doubtful
B-14
CFB
• Can be cleaner than PC, but IGCC better choice for more expensive coals like I-basin – has higher cap cost for I6 & K9 than IGCC or PC
• Environmental, political
• Comparable reasons to “supercritical case” and large scale projects (greater than 250 MW are not proven) and poor performance record versus IGCC
• Future environmental risk
• This technology is subject to significant heat rate erosion and capital investments to comply with any anticipated carbon management scenario
• Waste disposal issues
• Not efficient enough, production costs too high, fuels not available in region to make best use
The following is a list of technical aspects of IGCCs that could be barriers to deployment. Which of these, if any, do you believe need the most improvement, so that IGCC can gain wider adoption by electric power generators? [Editor’s Note: More than one could be chosen; left column indicates number of respondents selecting the item.]
4 Capital Cost
3 Operating & Maintenance Cost
4 Reliability & Availability
Heat Rate
1 Turn-down Capability
1 Feedstock Flexibility
Cost and Performance of IGCC on Lower Rank Coals
1 CO2 Capture Readiness
By-Product Utilization
3 Other (please specify):
• Comfortable with all issues above, will rely on 3rd party for O&M, but concerned about lack of off-the-shelf designs
• Some successful projects that are enabled by government incentives and risk insurance-need to improve this prospect for public projects
B-15
• Utility executives fearful of owning/operating a “chemical” plant
The following is a list of non-technical aspects of IGCCs that could be barriers to deployment. Which of these, if any, do you believe need the most improvement, so that IGCC can gain wider adoption by electric power generators? [Editor’s Note: More than one could be chosen; left column indicates number of respondents selecting the item.]
1 Too difficult or costly to get a Lump Sum Turnkey (LSTK) bid with performance guarantees vs. other coal technologies
3 IGCC not considered commercially ready by regulatory authorities
1 IGCC won’t get rate base approval from regulatory authorities
Useful Comment: Not applicable to IPPs, thinks one IOU’s 20% request is excessive, wishes IPPs could get subsidy like that
3 Environmental regulations not expected to give sufficient credit to IGCC’s environmental performance
Useful Comment: Faster permitting is a big advantage for IGCCs
4 Difficulty in finding financing for an IGCC at reasonable terms
Useful Comment: Banks starting to worry about PC regulatory risks too, Energy bill should help also
Difficulty in recruiting and training qualified operating staff
2 Generally insufficient IGCC knowledge within generators’ organizations
3 Other (please specify):
• General state of the economy – impacts demand growth, community concerns that come with any large industrial project, transmission market concerns, no retail access in location of project
• Incentives/risk programs focus on private deals and not public deals
• Unnecessary insistence of licensors and EPCs to do major FEED work prematurely
If EPRI could arrange or facilitate funding and/or a demonstration for only one near term IGCC RD&D topic aimed at breaking down the barriers to deployment, what topic should that be? [A “near term” RD&D demonstration is defined as one which would enable the subject technology to be offered commercially in 2012, with traditional guarantees for nominal 600 MW IGCC plants. Assume that 3-5 new IGCC plants of nominal 600 MW capacity will be on-stream in the U.S. by 2012 as a result of appropriating the incentives now authorized in the current Energy Bill.]
• Buy $10 million equity position in one of their projects, offer open to all CoalFleet members. Would allow generators to say they have tried IGCC and either it works and now they are convinced to build more or it didn’t work and here’s why we won’t build
B-16
future ones.
• Reduction in capital/O&M costs
• EPRI needs to support the deployment of the first one or two projects to remove some of the mystery from the technology-I believe this is doable and EPRI speeches are too cautious-they are scaring away regulators and financing institutions. It is time for a leadership position and not a go slow and lets gets some more industry and government money to study it.
• Critique of license-feed-engineer sequence with eye to structuring confident lump sum price and change order management to enable cost/schedule/performance adjustments OR utilization of biomass and RDF feedstock in Oxygen-blown, slagging gasification systems
• One such project could be related to developing a life cycle cost model for evaluating the different technologies and its associated operating and emissions profiles. There is no standard tool available to utilities or independents for analyzing technology choices.
• Reducing the capital cost of IGCC to make it competitive with PC
• Assuming that these 3 to 5 projects are on-line by 2012, then EPRI could aid the next generation of plants and designs by gathering all the lessons learned and sharing them with potential future builders and designers. I don’t see where EPRI can advance the IGCC technology better than the current suppliers, but maybe some related or sub-system type enhancements could be funded by EPRI. Ideally, EPRI should also focus on the next step past IGCC, such as nuclear, hydrogen economy, CO2 management, etc.
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Please comment on any other RD&D items you believe are needed to make IGCC plants more widely adopted in the near term.
• None
• Taking the uncertainty (technically and economically) out of carbon capture and sequestration is needed
• Develop low cost synthetic gas cooling system to replace existing heat recovery boiler configurations
• It may not be classified as RD&D, but some sort of white report on the commercial readiness of the major systems that make up the IGCC. The gasifiers have a long history of reliable service outside of the power generation sector and the combined cycle power plant is an established technology. From a commercial viability perspective the integration of these two proven technologies seems to the area of most unknown performance. It might serve the technologies deployment well to deepen the understanding of potential integration issues and develop risk mitigation strategies to minimize performance problems.
• Advances in air separations technologies would enhance the overall heat rate of the IGCC technologies
• Tools to assess how to best improve the availability and reliability
• The best path to get wider acceptance of IGCC is through successful demonstrations. Once the current run of plants is operating for a number of years with known, verifiable costs (Capital and O&M) and performance, then the rest of the industry will probably be lining up to purchase these plants.
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Advanced Coal RD&D Needs Survey for Technology and Equipment Suppliers
EPRI received 98+ responses to a web-based survey sent to 265 recipients in March 2005. Respondents represent a broad range of experience and roles in OEMs, technology developers/licensers, academic and industry research organizations and consulting firms in Asia, Europe and North America. Individually identifiable remarks have been removed or edited to preserve anonymity. Form text and questions posed are in bold text. Responses for IGCC related responses are illustrated with charts or listed as bulleted text.
Question 1: The following is a list of advanced coal power RD&D topics being funded by various governments and organizations around the world. What is your opinion of the current level of worldwide RD&D funding of each topic?
Ultr
a-Su
perc
ritic
al M
ater
ials
Ultr
a-Su
perc
ritic
al P
lant
Des
igns
Oxy
-fuel
Com
bust
ion
CO
2 C
aptu
re T
echn
olog
ies
CO
2 S
eque
stra
tion
Gas
ifier
Mat
eria
ls
Gas
ifica
tion
Proc
ess
Impr
ovem
ents
Hyd
roge
n fro
m C
oal
Fuel
Cel
ls
Syng
as-fi
red
Gas
Tur
bine
s
Adva
nced
Coa
l Pow
erD
emon
stra
tion
Plan
ts
0.0
10.0
20.0
30.0
40.0
50.0
60.0
70.0
80.0
% o
f res
pons
es
Current Level of R&D Funding
Too muchAbout rightNeed moreDon't know
Figure B-1 Responses to Question 1.
B-19
Question 2: Is your organization currently involved in or planning research, development or demonstration (RD&D) activities related to Integrated Gasification Combined Cycles (IGCCs)?
Conducting IGCC-related RD&D
0.0
10.0
20.0
30.0
40.0
50.0
60.0
70.0
Current RD&D Planned RD&D Uncertain No Plans
% o
f res
pons
es
Figure B-2 Responses to Question 2.
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Question 3: Which of the following aspects of IGCCs do you believe need the most improvement for that technology to gain wider adoption by electric power generators? (Rank the one needing most improvement as 1, second-most as 2, etc.)
Most Important Aspect of IGCCs That Must Be Improved
0.0
10.0
20.0
30.0
40.0
50.0
60.0
Capital Cost O&M Cost Reliability &Availability
Heat Rate ProcessSimplication
StandardDesigns
% o
f Res
pons
es Most Important2nd Most3rd Most4th Most5th Most6th Most
Figure B-3 Responses to Question 3.
B-21
Question 4: What is your opinion of the state of technology for the following sections of an IGCC plant?
Feed
Pre
p, C
rush
ing,
Grin
ding
Feed
Pre
ssur
izat
ion
Gas
ifier
Bur
ners
(Fee
d In
ject
ors)
Oth
er G
asifi
er C
ompo
nent
s Sy
ngas
Coo
ler
Slag
Han
dlin
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ry S
olid
s R
emov
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et S
crub
bing
Acid
Gas
Rem
oval
Oth
er G
as T
reat
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r Rec
over
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s W
ater
Tre
atin
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TH
RSG
ST &
Con
d
I&C
BO
P
Excellent
AcceptableBad
0.0
5.0
10.0
15.0
20.0
25.0
30.0
35.0
40.0%
of r
espo
nses
IGCC Component Ratings
Figure B-4 Responses to Question 4.
B-22
IGCC Component Rating
1.0
1.5
2.0
2.5
3.0
3.5
4.0
Feed P
rep, C
rushin
g, Grin
ding
Feed P
ressu
rizati
on
Gasifie
r Burn
ers (F
eed I
njecto
rs)
Other G
asifie
r Com
pone
nts
Synga
s Coo
ler
Slag H
andli
ng
Dry Soli
ds R
emov
al
Wet Scru
bbing
Acid G
as R
emov
al
Other G
as Trea
ting
Sulfur
Recov
ery
Proces
s Wate
r Trea
ting CT
HRSG
ST & C
ond
I&CBOP
Rat
ing
(1 =
Exc
elle
nt, 5
= B
ad)
Suppliers Users
Figure B-5 Average Responses to Question 4 by Suppliers and Users.
B-23
Question 5: Is your organization currently involved in or planning research, development or demonstration (RD&D) activities in the following areas of advanced coal combustion?
Conducting Advanced Coal Generation RD&D
0.0
10.0
20.0
30.0
40.0
50.0
60.0
70.0
80.0
Ultra-SupercriticalSteam Turbines
Ultra-SupercriticalBoilers
SupercriticalCirculating
Fluidized BedBoilers
Oxy-Fuel Boilers Flue Gas CO2Capture
IGCC
% o
f res
pons
es
Current RD&DPlanned RD&DUncertainNo Plans
Figure B-6 Responses to Question 5.
Question 6: If you are currently working on advanced coal RD&D (combustion or gasification), please list your areas of activity. (Type “none” in Area 1 box if no current activity) [Editor’s Note: 67 respondents listed approximately 167 items. Repeated and overlapping items have been combined for brevity, with number of respondents listed.]
Ash utilization – FGD products Ash utilization – combustion and gasification Biomass combustion Chemical looping gasification and combustion Clean Coal II –DOE CO2 capture (separation) (3) CO2 capture – pre combustion CO2 capture and storage CO2 capture – flue gas CO2 capture – flue gas – CaO / CaCO3 cycle – FBC CO2-free power plants CO2 measurement in situ CO2 sequestration
B-24
Coal prep Coal processing – plasma-assisted Coal pyrolysis and combustion at high pressure Cofiring coal and biomass Cofiring coal with animal waste/biomass Combustion modeling Combustion optimization (2) Conceptual design Conceptual system design/simulation/cost analysis Cost Estimating Desulfurization Dry char removal systems – more reliable Dry feed system Effect of synfuel product gas on turbine blades Emissions Emissions – NOX modeling Emissions – NOX trim/reduction FBC– atmo/bubbling/recirculating FBC BOP design Feasibility and Evaluation Designs Fluidized Bed Gasification Fuels and chemicals from syngas Gas Measurement and Analysis Gas processing – Acid gas removal Gas processing – advanced acid gas processing Gas processing – Amine scrubbing Gas processing – Amine scrubbing for CO2 capture Gas processing – CO2/H2 separations Gas processing – (dry) particulate removal (2) Gas processing – gas separation Gas processing – hot gas cleanup with sorbents Gas processing – more efficient filter blowback for IGCC Gas processing – sulfur/SOX/H2S removal Gas processing – syngas cleaning / conditioning (2) Gas processing – Syngas desulfurization Gas processing – warm gas clean up (2) Gas processing – ultraclean syngas cleaning for halides and sulfur Gas to liquids Gas turbine combustion/syngas combustion (2) Gas turbine combustion – premix combustion of IGCC fuels in gas turbines Gas turbine improvement for burning syngas (2) Gas turbine materials Gas turbine materials – Effect of syngas on blade materials Gasifier laser absorption spec. – composition anal. Gasifier tech demo – 0.35 MW high-P slagging ent. Gasification/gasifier (5) Gasification – advanced gasification concepts Gasification – coal Gasification – coal and Biomass Gasification – coal for other than IGCC Gasification – coal gasification chemistry
B-25
Gasification – coal, petcoke, heavy crudes Gasification – data analysis Gasification – low-rank coals Gasification – pressurized Gasification technology evaluation Gasifier – advanced Gasifier design improvements / simplification Gasifier simulations Gasifier simulations – simulation of gasification in various gasifiers Group Combustion of Coal Hydrogen production and storage Hydrogen production from coal (2) Hydrogen production – gasification looping cycles w/ CO2 capture Hydrogen separation and purification IGCC/IGCC concepts/IGCC plant integration (4) IGCC – advanced cycle designs IGCC - BOP design IGCC - gas turbine IGCC – low cost IGCC – standardized designs (2) IGCC plant operational optimization IGCC process simulation (2) Implementation Innovative cooling for gas turbines using syngas Instrumentation and controls Instrumentation for entrained flow gasifiers Ion transport (ceramic) membranes for oxygen ITM oxygen Lignite drying Mercury/trace metal sampling/capture/removal (4) Oxy–fuel/oxy-combustion (5) Oxy-Fuel boilers Oxy-fuel combustion – CFBC (2) Oxy-fuel combustion tests Oxy-fuel engineering study Oxygen plant – air separation plant integration Oxygen plant – boiler integration Oxygen plant – cryo air separation Oxygen-enriched Combustion Oxygen-enriched low-NOX technologies PC firing – all fuels Planning and permitting applications Polymeric membrane gas separation predicting Hg emissions pressurized coal combustion Pressurized coal feeding Pressurized fluid bed gasification Process and detailed design Process design and modeling Reburn with animal waste for NOX reduction Refractories (2)
B-26
SC-CFB Sensors (2) Sensors – high temperature Slag crusher Slurries – COWs, etc. Supercritical boiler Supercritical CFBs Supercritical metals Syngas combustion Syngas combustion, NOX control, combustor stability Syngas applications Syngas cooling system / cooler development (2) Syngas turbine areo/heat transfer Syngas turbine flow path deposition, corrosion Syngas turbine materials System integration and cycle analysis Thermalflow combustion study around feed injectors Turbine augmentation (supercharging) Ultra-low emissions IGCC Ultrasupercritical PC boilers and materials Vision 21 oxygen combustion gas generator
Question 7: If you are planning (or would like to) conduct advanced coal RD&D in the future, please list those RD&D topics. (Type “none” in Topic 1 if not applicable). [Editor’s Note: 67 respondents listed approximately 167 items. Repeated and overlapping items have been combined for brevity, with number of respondents listed.]
Advanced coal feed pressurization systems Advanced gasification concepts Advanced operations and maintenance practices Alternative sulfur recovery/trace metals Amine scrubbing Anthracite cofiring with biomass ASU/GT integration – further integration Biomass combustion Carbon capture Carbon Scavenging Centralized gasification center CFD modeling of combustion turbines CFD modeling of gasifiers CFD modeling of sulfur recovery plant Chemical looping CO2 advanced recovery CO2 capture (3) CO2 capture and storage CO2 capture by chemicals, minerals CO2 capture from syngas CO2 Measurement for Sequestration CO2 separation CO2 slurries for low-rank coals CO2 storage options
B-27
Coal slurry Coal to liquids (2) Coke-related developments Combustion Combustion optimization COE – life-cycle modeling Cycle analysis – zero-emissions oxy-combustion Design optimization Design, fab, testing, of a syngas gas generator Detailed engineering modeling of gas cleanup Detailed engineering modeling of gasifiers DLN syngas combustion Dry particulate removal Emissions Emissions control – solids Emissions control– gases Emissions control – ideas for use of O2 for reduced NOX in PC boilers Emissions control – low-NOX combustion Emissions control– NOX trim/reductions through optimization FBC– atmospheric/bubbling/recirculating Feeder simplification Flue gas CO2 capture – CaO / CaCO3 cycle – FBC Gas processing – gas cleanup simplification Gas processing – high temperature H2/CO2 separation Gas Processing – hot gas cleanup Gas Processing – innovative sulfur recovery Gas processing – syngas cleaning Gas processing – syngas desulfurization Gas processing – trace metal removal to ppb levels Gas processing – warm gas clean-up Gas processing – water gas shift for improved H2 yield Gas constituent measurement Gas turbine Gas Turbine Combustion of H2 Gas turbine combustors Gasifier laser absorption spec. – composition anal. Gasifier tech demo – 0.35 MW high-P slagging ent. Gasification (5) Gasification – air blown Gasification – pressurized Gasification – pressurized entrained bed Gasification kinetics for coal Gasification process efficiency Gasification simulations for coal Gasifier simulations Gasifier using solid fuel rocket technology Gasifiers comparison/analyses Government action impact on IGCC H-class GT with syngas Heat Recovery High temperature coating life models
B-28
High temperature sensors Hydrogen combustion Hydrogen production Hydrogen production – gasification looping cycles w/ CO2 capture IGCC IGCC/IGFC IGCC – lower cost IGCC – lower emissions IGCC – small plants (less than 5 MW) IGCC – standard plant designs (3) Instrumentation for entrained flow gasifiers Instrumentation for other processes Materials development Materials for Better Plant Efficiency Mercury evolution during IGCC More high pressure coal gasification none (4) Oxy-boiler compact design Oxyburner/ O2 injection Oxycombustion (2) Oxy-fuel combustion (2) Oxy-fuel combustion – CFBC Oxy-fuel demonstration (25-50 MWe) Oxygen plant – air separation Oxygen plant – boiler/CO2 train integration Oxygen plants PC firing – all fuels Polygeneration Pressure let-down for ash removal Process integration and simplification O&M cost reduction Refractories (2) Reliability Reliability survey of existing gasification plants Repowering existing gas turbines Sensors and diagnostics systems for better RAM Slag-refractory chemical interaction Supercritical boilers Syngas combustion Synthetic natural gas production Syngas applications Syngas cooling system improvement Syngas to liquids Syngas turbine combustion, aero/heat transfer Syngas turbine deposition, corrosion, erosion Temperature control of gasifier Ultra-supercritical Rankine cycles USC – higher temperature
B-29
Question 8: If EPRI could arrange funding and/or a demonstration site for only one of your RD&D topics, which topic would you choose and how could EPRI help? [Edited responses from 74 respondents]
• Advanced CO2 removal technologies
• Advanced gasification – EPRI could create a consortium of coal user utilities to provide financial and political support for developing and demonstrating advanced technologies to dramatically reduce the cost of power from IGCC plants.
• Air-blown coal gasification for 250-500 MW using PRB coals
• CFD modeling of a gasifier EPRI would be instrumental in providing access and expertise in defining inputs
• CO2 capture and storage for coal gasification
• CO2 capture from syngas from air-blown gasification. EPRI could help by supporting pilot scale demonstration of shift reactor/CO2 scrubber at a site where suitable syngas is produced
• CO2 measurement for sequestration purposes funding/cost sharing with utility
• Coal/waste IGCC. Establish “optimum” gasification and gas cleaning islands for (specific power islands)
• Coal-based syngas to liquids. Cofunding for project to demonstrate FT technology using syngas from existing 0.5–1 tph pilot gasification facility.
• Co-generation for oxygen plants (and) integration of air separation plants with co-generation plants for the purpose of lowering the production costs. Advanced coal generation offers a unique setting and opportunity. EPRI could arrange funding to help such study and to facilitate a demonstration site.
• Combustion in oxygen for CFBs
• Combustion, advanced research on oxyfuel technology
• Combustion, balance of plant optimization, and materials. Plant instrumentation and monitoring.
• Centralized gasification center
• Deep fixed-bed biomass combustion power plant demo
• Demonstration of high-pressure-coal-feed Future Energy gasifier - EPRI could help with funding.
• Demonstrate alternative sulfur recovery/trace metal technologies
• Demonstration of multi-fuel power plant gasifier as key technology for 3rd generation IGCC with optional CO2 capture
• Demonstration site and funding for improved dry particulate removal
• Design, fab and testing of a coal syngas gas generator
• Dual-fuel for CTs on syngas & distillate
B-30
• Fuel blending of IGCC fuels with natural gas streams at pressure for introduction into dry, lean premixed combustion system designs for gas turbines
• Fund full-scale IGCC
• Fundamentals of high T and P coal gasification
• Gas turbine combustor for ultra-low-NOX and high temperature under IGCC application
• Gasification (with CO2 capture) of coals that represent the bulk of world-wide resources (as opposed to the historical concentration on high sulfur bituminous coal).
• Gasification for low-rank coals – EPRI could bring some additional partners to the demonstration project.
• Gasification process improvement; efficiency
• Gasification – EPRI can help by providing in-house data and environmental impact assessment
• Gasifier design / simplification – EPRI can help by (1) obtaining funding; (2) participating in technical review under NDAs; (3) providing a conduit and capital for technology demonstration
• Gasifier simulations for utilities evaluating prospects for implementing IGCC technology
• Help obtain access and provide funding for demonstration of acoustic gas temperature measurement in coal gasifiers and a study to document the value proposition for such a measurement.
• The University Turbine Systems Research (UTSR) Program, 107 U.S. universities funded by DOE’s National Energy Technology Lab. The work is focused on R&D in gas turbines in IGCC applications.
• A project to take a slipstream from an existing IGCC plant and run a burner rig test to test erosion/corrosion/deposition on cooled material samples with different coatings, at hot gas temperatures higher than current IGCCs have operated to determine the temperature beyond which corrosion/erosion/deposition becomes a big problem
• IGCC combustion turbine
• IGCC demonstration plant in United States
• IGCC plant monitoring of syngas composition and control of trace species such as metal carbonyls
• Install a supercharging system that would reduce the costs of turbine, increase capacity and create a lower capital cost/higher value plant
• ITM Oxygen – EPRI could organize a consortium of interested parties who could fund research in exchange for limited rights to the technology.
• Long-term commitment to large scale IGCC test bed with sufficient funds to revamp/improve units, especially downstream gas cleanup.
• Low cost, compact, and efficient gasifier design
B-31
• Lower cost blowback of filter elements in IGCC applications. We need a demonstration site for testing with both ceramic and metal filter elements.
• Need a way to verify life of new materials for better efficiency or lower O&M costs under IGCC simulated conditions for long periods of time.
• Verification of (innovative systems) data by EPRI and notice to power community of its advantages; added incentives such as funding
• Oxycombustion (a.k.a. oxy-fuel combustion)
• Oxycombustion - to make a survey of current activities and promote reference project and either implement or sustain the promotion
• Oxycombustion and O2 injection – providing site and support for operation
• Oxy-fuel demonstration – a 30 MWe retrofit demonstration requires about $30M (ASU, boiler modifications, flue gas recycle line, controls). Partners have to include a boiler company, a gas manufacturer and a utility company. EPRI could definitely help by cost-sharing the project that industrial partners can not afford at this point, by providing guidance for the communication and by helping identify the right candidate unit for such a demonstration.
• Plasma-assisted coal processing. EPRI could create a cooperation of sponsors and partners
• Polygeneration or CO2 capture where IGCC has clear advantages over PC
• Pressurized coal feed demonstration and evaluation
• Process design and optimization
• PSDF (Wilsonville, AL, research facility for IGCC processes)
• Reburn with animal waste for maximum NOX and Hg reduction
• Refractories for gasification – EPRI could organize and run controlled tests to determine important variables in refractory life
• Reliability survey of existing gasification plants
• Repower existing gas turbine site – EPRI could network any interested parties critical to 1) providing suitable existing site(s), 2) funding the project and 3) providing an appropriate gasification technology.
• Slipstream turbine materials tests at coal syngas plants at higher gas temperatures and appropriate surface temperatures representative of next generation syngas turbines
• Small IGCC demonstration plant using microturbine (with DLN syngas combustor), recuperator, and small gasifier (no steam cycle)
• Standardized IGCC designs
• Syngas cooler development to higher RAM issues. There is more R& D money in the development phase required than process owners can spend to a single components supplier. Also in-house budgets are limited. Small test units for advanced syngas cooler designs and
B-32
new materials would be helpful, too, as experience has shown that material costs drive the overall equipment costs.
• Syngas desulfurization
• Temperature control of gasifier
• There is a need to demonstrate ultrasupercritical boilers in the United States. The technology is already available in Japan/Europe for high-temperature steam cycles and U.S. vendors are prepared to offer them also. But U.S. utilities are reluctant to build anything that hasn't been demonstrated and are thus looking at subcritical or supercritical units with lower steam conditions. Demonstrating a ultra-supercritical unit in the U.S. will make it less risky for utilities to consider this option in the future. This technology will provide many benefits, including reduction in CO2 emissions, reduction in all criteria pollutants on a lb/kWh basis, and also help to extend our coal resources through lower plant heat rate.
• Waste heat recovery advanced heat exchanger
• A new sorbent-based technology to remove trace contaminants from coal-derived syngas. To fully assess its potential, sorbent performance needs to be tested in real coal gas. EPRI may provide the facility and the slipstream to test a prototype system
• Would prefer funding for looping cycle development
Question 9: Please comment on any other coal-related RD&D items you believe are needed to make advanced coal power plants more widely adopted (don't limit this to your organization's skill set, also consider things outside of your organization's competency that you'd like to see others develop).
• Low cost and simple pressure solid feeding device
• Selexol-SCR demonstration; byproduct utilization; DLN combustors for syngas
• We need to be able to speak of gasification with other cycles than just IGCC - oxygen combustion integrated gasification
• I know EPRI is quite active in the Gasification Technologies Council. Maybe EPRI and the GTC could facilitate several utilities getting together to make a large quantity purchase of IGCC plants, to make enough economy of scale that the manufacturers would be willing to make advancements in the state of the art of the plants. The overall intent is to bring IGCCs to the status of an accepted, proven technology – so project developers can get financing and insurance as readily as they can for natural gas combined cycles.
• Co-production of power and chemicals. Repowering of natural gas turbines with syngas.
• More test sites are required with a focus on burning multi and varying composition gases. Gas turbine combustors specifically designed to achieve the lowest possible emissions when burning coal gas.
• Advanced coal generation R&D offers a unique opportunity for the development of selective CO2 sequestration. The development of catalytic deoxidation and the protection of the catalyst against poisons.
• High firing temperature gas turbine
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• Further R&D related to combustion optimization and constituent measurement and the relationship/study between effects of one upon the other
• Future advanced coal plants are all going to have to deal with CO2 emissions and the need to approach “near-zero” emissions. Not only do we need to continue developing technologies and components to capture CO2, but we also need to understand just what a CO2-ready plant is today. Both IGCC and combustion steam plants today have the potential to capture CO2 in the future when required (and when sequestration is also ready and proven). However, it is prudent to design new plants today with the necessary provisions to add on CO2 capture equipment in the future. This includes leaving space for future equipment and designing the gasifier/boiler/turbines with ability to cope with future CO2 capture (which would result in significant impacts on plant heat rate). Some R&D work clearly needs to be done for both IGCC/combustion plants to clearly work through the issues associated with making a plant truly “CO2 capture-ready.”
• Energy efficient CO2 separation and compression
• Demonstration of various gasifier process concepts at min. 100 MW scale
• Demonstration of the quench version of the Shell gasifier
• I believe that the greatest driver towards implementation of IGCC would be a consistent long-term energy policy and emissions standards by the federal government.
• Need a wider selection of multi-pollutant control technologies to reduce the number of “mufflers” on the back of a power plant
• Price must be driving factor, along with reliability guarantees
• Gas turbine combustors for very low Btu syngas. We are interested in moist syngas from air-blown gasification, about 100 Btu/cf and sulfur capture from hot, wet syngas, at 300–400°C
• Gas cleaning is the most important topic. EPRI should deal with it.
• IGCC for H2 with CO2 capture and storage
• Plant-wide integration. Basic gasification reactor research.
• Advanced steam turbine
• ITM oxygen – improved heat rate for IGCC; improved reliability for IGCC
• Funding membrane technology to reduce air separation costs and electricity consumption for IGCC plants. Enhancing gasifier reliability (water-cooled membrane walls, advanced refractory material) to boost reliability and longevity between shutdowns.
• CO2 sequestration in an environmentally safe way (compare to nuclear waste storage)
• Coal to liquids
• Overall plant availability must be addressed to move IGCC forward
• Develop coal/solid fuel/biomass technology to replace gasoline, kerosene, natural gas
• Higher temperature tube materials
B-34
• More data on turbine operational experience at syngas plants, particularly the composition and particle size distributions of impurities in syngas and more information on the turbine flow path degradation that has been experienced.
• Focus on components improvements instead of entire IGCC plants demonstrations done by DOE. Sponsor more fundamental research.
• Water conservation and/or recovery. Integration with renewables (biomass and solar).
• High-temperature materials for boiler/steam turbine in ultra-supercritical plant
• The most difficult step in turning new ideas into practical application is the need to test it under representative conditions. There are certain difficulties in simulating a coal-driven synthesis gas in a lab environment. There is a need to develop for a facility to evaluate the performance of prototype systems that are under development in small-scale but under real conditions to stimulate commercial interest in the emerging technologies.
• Refractories; particulate removal
• CO2 storage in addition to geological sequestration
• Coal to liquid-fired GT
• R&D has to be put in the utility industry, (such) that the people understand the gasification process and its components, which are developed from similar equipment used in chemical/ petrochemical applications.
• Develop energy storage plants to support base-load gasified coal plants, such as Compressed Air Energy Storage (EPRI supported this earlier). This would provide peaking and system stabilization advantages to the whole system.
• Bulk solids handling into and out of pressure environment
• Work on institutional barriers that prevent the combination of the best (often proprietary) IGCC techniques/methods/strategies/technologies in order to achieve the “best” gasifier system
• Hot/warm gas clean-up low cost/power oxygen separation
• CO2 sequestration is essential, especially in developing countries like China and India
• Improving emissions control (removal of sulfur, slag, and corrosive components). Filtering of carbonyls.
• Cheap capture of impure CO2 for underground storage-acceptability
• Full commercial scale demonstrations of the technology are needed that quickly prove the economic viability of IGCC
• IGCC coproduction of chemicals/H2
• Standardized IGCC designs – it is a key supporting element of reducing capital cost and improving availability/reliability and reducing project development costs
• Advanced emissions control and cleanup technologies, including especially various metals (besides current focus on mercury)
B-35
• Economical CO2 capture
• Waste management; financial models; O&M improvements
• Develop a network for supply of after-market parts
• Increased understanding of coal ash
• Materials of construction; novel (more efficient) means (of) CO2 removal
C-1
C STATUS OF EXISTING WORLDWIDE ADVANCED COAL RD&D FOR IGCC
An initial step in formulation of the IGCC RD&D Augmentation Plan was the compilation of a list of known ongoing or planned IGCC-related RD&D activities worldwide. The results, tabulated in this appendix, were then used to identify RD&D gaps and opportunities to accelerate ongoing vital RD&D.
C-2
Technology Component Goal of RD&D Work Key Area of
Improvement Research Organization
Funding Organization
Current Annual Funding
Timeframe for Completion of Goal
IGCC Demonstration Plants
250 MW IGCC plant in Nakoso, Japan
Demonstrate dry-fed, air-blown IGCC technology, cold gas clean-up, 1200C TIT
Investment, Efficiency
Clean Coal Power R&D Company, Ltd.
CRIEPI with nine Japanese power companies
Operation begins in 2007
285 MW PRB Transport Gasifier IGCC plant
Scale up transport reactor technology from Wilsonville PSDF
Investment Southern Company, KBR
DOE $235 million, $322 million Orlando Utilities Commission and Southern Power Company
FY2006 not specified yet ($557 million total)
Demo operations completed 2015
531 MW Bituminous coal E-Gas IGCC plant
Scale up E-Gas technology, Implement learnings from 265 MW Wabash River project
Investment ConocoPhillips DOE $36 million, $1154 million ConocoPhillips and Excelsior Energy
FY2006 not specified yet ($1180 million total)
Demo operations completed 2013
275 MW FutureGen IGCC plant with CO2 capture
Demonstrate H2/power production with CO2 capture
Emissions, CO2 constraints
TBD DOE baseline estimate $457 million
$18 million 2012
1150 T/D Gasifier at Gotai Company, Ltd. in Lunan, China
Successful demonstration of slurry-fed, downflow gasifier with multiple opposed burners mounted through sidewalls of vertical, cylindrical gasification reactor
Improved carbon conversion from 95% to 98%
Research Institute of Clean Coal Technology, East China University of Science and Technology
Also demonstrated at 750 T/D scale at Shandong Chemical Company in Dezhou, China
1150 T/D gasifier at Gotai Company, Ltd. in Lunan, China
Based on successful test in 2005 of CO2 instead of nitrogen as transport gas for dry-fed gasifier
Reduced oxygen consumption, simplified gas cleaning
Research Institute of Clean Coal Technology, East China University of Science and Technology
41 MW Power plus 5000 B/D FT Liquids -- Gilberton Project
Demonstrate gasification of anthracite culm to produce power and FT Liquids
Investment WMBI PTY LC (subcontractors/ technology suppliers- Nexant, Bechtel, Shell, Uhde, SASOL)
$612 million total ($100 million DOE)
Status unknown 2003-2009 original schedule (current schedule unknown)
100 MW Brown Coal IDGCC demo
Demonstrate integration of HRL low-rank coal drying technology with IGCC plant
Investment HRL, CSIRO Coal 21 Australia 2008 operation; 800 MW commercial plant 2012
200 MW Black Coal IGCC Demo with CO2 capture
IGCC demonstration with CO2 capture and sequestration, Shell gasification technology has been selected for the project
CO2 capture Stanwell, Shell Stanwell Feasibility study to be completed in Oct 2005
C-3
500 MW Brown coal IGCC project
Feasibility of IGCC plant fueled with Victorian (Australia) brown coal
Investment Yallbourn Power subsidiary of CLP Power
$1 million (Australian dollars)
2006
300-400 MW Yantai-Shandong
IGCC Demonstration on high sulfur coal in China
Investment
World Energy Council Cross Border Project
200 MW IGCC China's Agenda 21 National Project to demonstrate IGCC technology in China
Investment
IGCC Leading Group in China
Demo plant lessons learned
COORIVA project: Evaluation of existing IGCC experience, lessons learned, "lean IGCC concept," optimization for hard and brown coal
Investment, reliability
TU Freiberg and Industry
Total = 4.6 m€ 4/05 to 12/07
HYPOGEN Large scale test facility for production of hydrogen and electricity; from decarbonated fossil fuels
CO2 capture EU
Canadian Clean Power Coalition
Demonstrate IGCC at retrofit or greenfield site, low-rank coal as feedstock
Investment, CO2 recovery
Fluor (Phase 1), Jacobs (Phase 2)
Canadian Clean Power Coalition
2010+
Gasification System Technology Development at Pilot Plant Scale
PSDF Operation 1000 hour PRB test, testing of char recycle, continuous coarse ash depressurization, Stamet solid feeder
Investment Southern Company, KBR
DOE 1990-2005 $414 million total, $360 million DOE; current annual funding probably now in the range of $10-15 million
168 T/D PFBG Pilot Plant Operation
Development of pressurized fluid bed gasifier (PFBG) for high ash (~42%) Indian coals
Investment BHEL (India) BHEL (India)
150 T/D Eagle IGFC pilot plant operation
Integrate MCFC with HYCOL gasification plant
Efficiency Hitachi Electric Power Development Company
24 T/D Moving Bed Gasifier Tests of high ash Indian coals Low-Rank Coals Indian Institute of Chemical Technology
Frontia 3 T/D Air Blown gasifier
Development of air-blown gasifier technology in Japan
Investment CRIEPI Japanese power companies
Transport Reactor development
250 pound/hr tests to develop supporting information for PSDF
Investment EERC North Dakota DOE $4.7 million through 2005
Partial gasification module Development data for partial gasification as the first stage of a process with a PFBC reactor for char combustion
Investment Foster Wheeler DOE $3.1 million, 42 months 2000-2005 (80% DOE)
C-4
Multiple bed advanced gasifier combustion process (chemical looping)
Demonstrate new approach to maximize coal conversion, production of H2, and separation of CO2 and pollutants from vent gas
Investment GE-EER DOE $3.7 million total, $2.7 million DOE, 30 months 2002-2005
Flexible-Fuel Gasifier, 10 - 20 tpd pilot plant
Fluidized bed gasifier provides platform for testing coal, biomass and other solid fuels, advanced gasifier designs, and new syngas clean-up systems
Emissions, low- rank coal
GTI Much self-funded but support also provided by State of Illinois Dept of Commerce and Economic Opportunity
$12 million to construction, additional $s for on-going testing
0.35 MW high pressure slagging gasifier pilot plant
Entrained flow gasifier (12.7 cm ID, operating at up to 1500 kPa and 1800ºC) is capable of running with a dry entrained feed or with a slurry feed. The reactor design allows the addition or removal of sections to investigate alternate gasification geometries. The gas treating can test third-party technologies such as advanced shift reactors, hot gas clean-up facilities, and fuel cells
Emissions, CO2 constraints
CANMET Canadian federal government
Chemical Looping process Pilot scale demonstration CO2 capture Alstom, Parsons, Lummus, PEMM
DOE $4 million total 2006-2007
Subsystem Development
Air Separation technology ITM Oxygen with planar ceramic membranes test at 1-5 T/D scale (2205), scale up to 25-150 T/D (2008)
Investment ($75-100/kW, Efficiency (1 point)
Air Products, (parallel Praxair project terminated)
DOE Acceleration of program being considered so that the technology could be installed in a FutureGen plant at a capacity of 2000 T/D
ASU process Development of low cost oxygen separating membranes
Investment ECN, Netherlands Dutch Government
Long term
Partial Air Integration Added air extraction piping from CT compressor discharge to supplement ASU main air compressor.
Efficiency, Investment
Tampa Electric Co. Tampa Electric Co.
2005 Near term
Instrumentation Optical pyrometer testing at Polk, optical fiber testing at Wabash River, and bench scale development of an acoustic pyrometer
O&M, Reliability TECO, Wabash River, ConocoPhillips
DOE
Instrumentation On-line laser-based coal analyzer O&M, Reliability Energy Research Co., Enertechnix
DOE SBIR program
$100k Phase 2 grant in 2003
Mid term
Instrumentation On-line coal analyzer to provide basis for controlling slag viscosity
O&M, Reliability Eastman Eastman 2005
C-5
Instrumentation Development of fiber optic based sensors that operate at >500C for in-situ monitoring of fossil fuel gases
O&M, Reliability GE, Penn State DOE DOE share, $361k, 30 months mid- 2005 start
Instrumentation Development of fiber optic based sensors that operate at >500C and ~200 psi for in situ monitoring of fossil fuel gases
O&M, Reliability New Mexico Institute of Minnig and Technology, Dr. Jerry Y. S. Lin
DOE DOE share $528,000, 26 months, mid- 2005 start
Instrumentation Testing of a spectroscopic technique to monitor the condition of gasifier fuel injectors, technique originally developed for natural gas burner monitoring
O&M, Reliability GTI, CANMET DOE Testing at CANMET pilot gasifier summer 2005, unknown $s
Near term
Instrumentation Gasifier in situ composition analysis via laser absorption spectroscopy
O&M, Reliability CANMET Canadian federal government
Instrumentation Development of fiber optic based sensors based on evanescent wave absorption in standing hole optical fibers for in situ monitoring of fossil fuel gases
O&M, Reliability Virginia Tech DOE DOE share $6000,000, 36 months, mid- 2005 start
Feed Injectors Feed injector improvements O&M, Reliability Tampa Electric Co. Tampa Electric Co.
Near term
Refractory Development
Reliability Saint Gobain Ceramics
Refractory Development
High-chromia refractory field test Reliability ConocoPhillips, Eastman, Harbison-Walker, Albany Research Center
DOE Field tests on-going in 2005
Near term
Refractory Development
Develop sodium zirconium phosphate structured ceramics with low coefficient of thermal expansion and low thermal conductivities
Reliability Penn State University DOE $200,000; 40 months 2001-2005
Syngas Cooler Add sootblowing to prevent plugging of firetube syngas cooler
Reliability Tampa Electric Co. Tampa Electric Co.
Near term
Corrosion Resistance Develop coatings for metals that are resistant to attack by H2S and other components in raw syngas
O&M, Reliability SRI International DOE $839,000 total, 80% DOE, 36 months 2003-2006
Component Development Support for 250 MW Nakoso project— pulverized coal feed system, gasifier, porous filters, gas clean-up, gas turbine combustor
Investment, Efficiency
Mitsubishi
Enhanced Acid Gas Removal
Add chilling to MDEA system Emissions Tampa Electric Co. Tampa Electric Co.
Near term
C-6
Gas Cleaning (solids removal)
Combined cyclone and filter system to reduce the cost of solids recycle system
Investment (1%) ConocoPhillips Wabash River
Gas Cleaning and Conditioning (near zero emissions)
Clean gas to levels acceptable for use in fuel cells, gas turbines, and chemical production (reduce sulfur and chlorine to ppb level and nitrogen species to <10 ppm)
Emissions RTI with slipstream testing at Eastman of 1) KBR transport reactor desulfurizer; 2) desulfurization sorbent from Sudchemie and RTI; 3) sorbent regeneration by RTI; 4) ammonia control by SRI; 5) mercury control by RTI; 6) membrane based syngas desulfurization by RTI and MEDAL LP
DOE $20.3 million total, $15.3 million DOE; 60 months 2001-2006
Gas Cleaning and Conditioning (near zero emissions)
Testing of beneficiated gasifier by-products (char) for use in Hg absorption.
Emissions, O&M Univ. of Kentucky Center for Applied Energy Research
DOE, Univ. of Kentucky Center for Applied Energy Research, Charah Environmental
$140K Near term
Gas Cleaning and Conditioning (near zero emissions)
Improved COS conversion catalyst Emissions, Investment
Univ. of Kentucky Center for Applied Energy Research
Univ. of Kentucky Center for Applied Energy Research
Gas Cleaning and Conditioning (near zero emissions)
Clean gas to levels acceptable for use in SOFC fuel cells and chemical production. Zinc titanate used as the sulfur sorbent and trona (hydrated sodium bicarbonate carbonate) for HCl capture
Emissions Siemens Westinghouse/GTI
DOE $4.3 million total, $3.4 million DOE; 66 months 1999-2005
Gas Cleaning and Conditioning (near zero emissions)
Multi-contaminant removal process to capture H2S, NH3, HCl, Hg, AS, Se, and Cd in a single process step (POM membrane) and high pressure conversion of H2S to elemental sulfur
Emissions, Investment
GTI, University of California at Berkeley, ConocoPhillips
DOE DOE Share $360,000, 18 months, mid- 2005 start
Gas Cleaning and Conditioning (near zero emissions)
Division of gas cleanup into bulk and polishing steps. The bulk cleanup stage will use a transport reactor to reduce H2S, COS, NH3, and HCl to low ppm values and a fixed bed polishing step that uses a multifunctional sorbent with active sites for the capture of H2S, COS, NH3, HCl, and heavy metals
Emissions, Investment
RTI, Eastman, Nexant, SRI International, SudChemie, and URS Corp.
DOE DOE share $1.03 million, 72 months, mid- 2005 start
C-7
Gas Cleaning and Conditioning (near zero emissions)
Process to capture mercury, arsenic, selenium, and cadmium from syngas at high temperature with a single adsorbent
Emissions, Investment
TDA Research, Inc DOE DOE share $300,000, 12 months mid- 2005 start
Mid-term, slip-stream test on real syngas needed next
Gas Cleaning and Conditioning (near zero emissions)
Monolithic, honeycomb structure coated with sorbent to capture contaminants in syngas made from lignites
Emissions, Investment
University of North Dakota, UNDERC, Corning, Inc.
DOE DOE share $5.0 million, 60 months, mid- 2005 start-up
Advanced Sulfur Removal Proprietary Emissions, Investment
ConocoPhillips ConocoPhillips Near term
Direct conversion of H2S to elemental sulfur
Achieve very low levels of sulfur compounds in syngas so that it can be used in fuel cells
Emissions, Investment
Oak Ridge NL DOE $300,000 total, 24 months 2004-2006
Direct conversion of H2S to elemental sulfur
Direct Oxidation Process for Sulfur and Mercury Removal from Coal-Derived Syngas
Emissions, Investment
GTI Illinois Clean Coal Institute
Direct conversion of H2S to elemental sulfur
Development of single step process to convert H2S to elemental sulfur
Emissions RTI DOE (20% cost sharing from RTI)
$578,000 total, 27 months 2003-2005
Project cancelled-technical failure
Direct conversion of H2S to elemental sulfur
CrystaSulf, a proprietary, non-aqueous process for direct conversion of H2S to elemental sulfur with large turndown capability. Expected to be economic for applications with S production <25 tpd, also an alternative Claus tail gas treatment process for larger sulfur producers
Emissions (H2S and COS to <5 ppm), Investment, Efficiency (1-2 points)
Crystatech GTI & Crystatech
Near term
Direct conversion of H2S to elemental sulfur
Selective Catalytic Oxidation of H2S to elemental sulfur in a single step at 100-300F with activated carbon and mixed metal oxide catalysts
Investment NETL DOE
Separate hydrogen from syngas
Identification of thin, dense membranes of either dual phase ceramic metal composites or monolithic mixed protonic and electronic conductors with hydrogen flux levels and stability of commercial interest
CO2 capture Argonne NL DOE $4 million total 1998-2005
Separate hydrogen from syngas
Identification of thin, dense ceramic membranes of protonic and electronic conductors with hydrogen flux levels and stability of commercial interest
CO2 capture Eltron, Argonne NL DOE, Eltron DOE $2,240,000, Eltron $560,000 (Total 2000-2005) Supporting R&D Argonne NL $750,000 (Total 2000-2004)
C-8
Separate hydrogen from syngas
Proton conducting hydrogen separation membranes with hydrogen flux levels and stability of commercial interest
CO2 capture ITN Energy Systems, Argonne NL, INEEL, Nexant, Praxair
DOE $3.1 million total, $2.6 million DOE; 48 months 2000-2004
Separate hydrogen from syngas
SiC membrane development CO2 capture Media and Process Technology
DOE
Separate hydrogen from syngas
Pd membrane development CO2 capture SwRI DOE
Membrane technologies Development of high efficient hydrogen production systems with integrated CO2 removal on basis of Pd-alloy hydrogen transport membrane
CO2 recovery ECN, Netherlands Dutch Government
?? Mid-to-long term
Separate hydrogen from syngas
Proton conducting hydrogen separation membranes with hydrogen flux levels and stability of commercial interest. Focus on identifying inorganic membranes with narrow pore size distribution
CO2 capture Oak Ridge NL DOE $850,000, 48 months 2000-2004
Enhanced Hydrogen Production
Development of a novel membrane reactor process that combines H2S removal, Water Gas Shift reaction, hydrogen separation and CO2 separation in a single membrane configuration with multiple membranes
CO2 capture GTI, Arizona State University
DOE, Illinois Clean Coal Institute, AEP
DOE Share $386,000, 24 months, mid- 2005 start
Enhanced Hydrogen Production
Development of a novel high-temperature membrane reactor process that combines H2S removal, Water Gas Shift reaction, and CO2 separation in a single structure configuration with multiple membranes to produce a pure hydrogen stream
CO2 capture GE DOE DOE Share $500,000, 24 months, mid- 2005 start
Enhanced Hydrogen Production
Development of a low-cost Water Gas Shift membrane reactor that uses a shift catalyst and hydrogen separation membrane that are each contaminant tolerant
CO2 capture Aspen Products Group
DOE DOE Share $498,000, 24 months, mid- 2005 start
Enhanced Hydrogen Production
Development of a process to produce 99.96% pure hydrogen by combining the Water Gas Shift reaction with the simultaneous separation of hydrogen by diffusion through a palladium membrane
CO2 capture United Technologies, Questek Innovations
DOE DOE Share $849,000, 24 months, mid- 2005 start
Enhanced Hydrogen Production
Development of a monolithic Water Gas Shift catalyst that supports a vanadium alloy hydrogen transport membrane
CO2 capture University of Wyoming, WRI
DOE DOE Share $500,000, 24 months, mid- 2005 start
C-9
Enhanced Hydrogen Production
Development of improved low temperature water-gas shift catalyst
CO2 capture Univ. of Kentucky Center for Applied Energy Research
Univ. of Kentucky Center for Applied Energy Research
Enhanced Hydrogen Production
Novel concept for hydrogen and CO2 separation from coal gasification products
CO2 capture Southern Illinois Univ. Carbondale
Illinois Clean Coal Institute
Enhanced Hydrogen Production
Development of a Thermal Swing Sorption Enhanced reaction process which simultaneously carries out the Water Gas Shift reaction and CO2 separation
CO2 capture Lehigh University DOE DOE Share $404,000, 24 months, mid- 2005 start
Solids separation Slip stream test of hybrid cyclone/filter dry particulate removal system for hot gas cleanup at Eastman
Emissions Gasification Engineering Corporation
DOE $900,000, 80% DOE, 30 months, 2002-2005
Solids separation Slipstream cyclone demo with the slipstream candle filter at Wabash
Investment, Reliability
ConocoPhillips Near term
Solids Pressurization Develop and demonstrate a dry feed solids pump capable of delivering solids at 300 psi (Phase 1) and 500 psi (Phase 2), flow rate will be up to 4.8 tpd
Investment, Reliability
Stamet DOE
Phase 1 successfully completed, Phase 2 to finish in mid-2005
System Assessments Screening of chemical looping, Adv. Gasif., multi-contaminant control
Efficiency NETL, RDS, TAMS, Mitretek, Parsons, GTC
DOE $3.941 million FY 2006
System Assessments TRIG process with CO2 capture CO2 constraints SCS DOE
System Modeling Software Framework for Advanced Power Plant Simulation. This integrated capability will link a hierarchy of plant-level and equipment-level models that will have varying levels of fidelity and computational speed suitable for either preliminary conceptual design or detailed final design
Investment Fluent, Alstom, Aspen Technology, Carnegie Mellon Univ.
DOE with co-share from research organizations
$2.5 million, $1.9 million from DOE
Near term
IGCC System Modeling Develop an engineering design tool to allow user to predict performance of an IGCC and to estimate capital and operating costs. Software tool will eliminate the need to use multiple simulation tools for different sections of an IGCC
Investment Enginomix EPRI Near term
System Modeling Computer simulation model of an entire IGCC which will incorporate component and sub-component models developed by third parties
Investment Reaction Engineering Intl, AEP, Ameren, Praxair, EPRI, Enertechnix, several U.S. universities and CRC-CSD Australia
DOE with co-share from research organizations
$440K from DOE Near term
C-10
Gasifier slag beneficiation
An ash beneficiation processing technology developed at the CAER to recover fly ash carbon from ash ponds and landfills will be applied to recover and separate marketable carbon and ash products from the gasifier chars
O&M Univ. of Kentucky Center for Applied Energy Research
DOE, Univ. of Kentucky
$250K Near term
Basic R&D Gasification reaction modeling and performance predictions of gasifiers as a function of coal type and operating conditions
Investment, O&M
Niksa Energy Associates
Niksa Energy Associates
Near term
Basic R&D Ash-flux test study Reliability, O&M ConocoPhillips ConocoPhillips Near term Basic R&D NETL Fluid Bed-basic R&D Investment Fluid bed (NETL) DOE Basic R&D Development of actively cooled refractory
and improved injectors, conceptual design of novel low cost entrained gasifier
Investment Rocketdyne DOE $6.2 million, 80% DOE; 30 months 2004-2007
Technology Gasification Cycle Improvements 50 bar high pressure steam in SGC
Lower cost, low alloy steels in steam superheater in syngas cooler
Investment Shell
Increased slurry quench to second E-Gas Stage
Higher pressure gasification, cyclone to separate solids for recycle to first stage
Investment E-Gas
IGCHAT Reduce investment cost by eliminating steam cycle and increasing mass flow through gas turbine
Investment ESPC
ISCC Simultaneous gasification and carbon capture of brown coal. Detailed definition of an environmentally friendly, highly efficient coal technology producing a highly enriched H2 product gas and in situ CO2 capture.
CO2 constraints Univ. of. Stuttgart plus 13 others
EU Total = 1.9 m€ 1/04 to 12/06
NovelEdge Reduce specific investment cost by firing HRSG with syngas to increase plant output
Investment NovelEdge
Technology Next Generation Gas Turbines for IGCC Plants
Advanced Combustors
a) Development of systems capable of using 100% H2 as fuel b) NOX reduction through catalytic combustion and fuel premixing
Investment, Efficiency
a) GE, SWPC b) GE, SWPC, PCI; R&D support from Clemson University
DOE $17.82 million FY2006
Syngas flow path deposition and corrosion control
Analyzing hot section parts from IGCC turbines to determine whether syngas environment contributed to TBC spalling and deposits
Reliability South Carolina Institute for Energy Studies, SwRI, EPRI
DOE, EPRI Near term
C-11
Thermal barrier coatings Investigation of the resistance of thermal barrier coating to oxidation, hot corrosion and erosion /impact from foreign objects, in syngas turbines.
Reliability Univ. of Pittsburgh DOE Near term
Thermal barrier coatings Evaluation and testing of thick TBCs produced by the SPS process for syngas turbine applications.
Reliability Univ. of Connecticut DOE Near term
Materials for syngas-fired gas turbines
Long-term materials tests under simulated syngas firing at conditions representative of next generation GTs
Reliability South Carolina Institute for Energy Studies
DOE, SWPC, some UK funding also
Additional funding needed for full testing program
Performance monitoring Development of sensing strategies to monitor the health and performance of gas turbine combustors with syngas
O&M, Reliability, Efficiency
Georgia Tech DOE Mid term
Combustion stability Investigation of the blowout and combustion instability characteristics of fuel-flexible (syngas) combustors
Reliability Georgia Tech DOE Near term
Combustion stability Examination of flame dynamics and stabilization for coal-derived syngas.
Reliability Virginia Tech DOE Near term
Combustion stability Evaluation of auto-ignition and flashback characteristics of syngas
Reliability UC Irvine DOE Near term
Combustion stability & Premixed combustors
Determination of the effect of combustor operating conditions on the static and dynamic stability of lean premixed low emission combustors with syngas
Emissions Penn State University DOE Near term
Pre-mixed combustion of syngas in GTs
Fuel Blending of IGCC fuels with natural gas streams at pressure for introduction into dry, lean premixed combustion system designs for gas turbines
Emissions Power Systems Manufacturing
PSM Near term
Enhanced Cooling of Hot Section Components
Investigation of the effects on turbine cooling effectiveness of airfoil roughness and film-cooling hole blockage on a turbine airfoil and associated end wall with syngas
Efficiency Virginia Tech DOE Mid term
Enhanced Cooling of Hot Section Components
Project investigates how the use of synthetic gas fuel affects the cooling and aerodynamics of turbine components
Efficiency Univ. of North Dakota, Univ. of Utah
DOE via UTSR $342k Mid term
Enhanced Cooling of Hot Section Components
Mist and Steam Cooling of High-Temperature Gas Turbines, which could significantly enhance heat transfer and allow higher firing temperatures
Efficiency Univ. of New Orleans Energy Center
UNO Long term
Improved combustors for gas turbines
Combustors for gas turbines, KW21-GV project
EU?
C-12
Application of Clean Energy Systems Combustor to Syngas
Firing of clean syngas (rather than natural gas) with oxygen and expanding the product gas through a still-to-be-developed high-temperature turbine
CO2 constraints Clean Energy Systems
DOE Testing 5 MW prototype at a former biomass power plant in Bakersfield
Commercial offering post 2015
Enabling Turbine Technologies for High Hydrogen Fuels (DE-PS26-05NT42380) - sub-elements listed below
1) Hydrogen Turbines for FutureGen
2-3% points increased HHV efficiency relative to current designs for syngas by 2010, 3-5% efficiency improvement by 2015 on H2, 3 ppm NOX without SCR
Investment, Efficiency
a) GE b) SWPC DOE a) $45.6 million, b) $45.5 million
a) 75 months, b) 56 months starting Sept 2005
2A) Coal-based Oxy-Fuel System Evaluation and Combustor Development
Develop and demonstrate a new combustor technology powered by coal syngas and oxygen. Evaluate and redesign the combustion sequence to achieve the ideal ratio of oxygen to fuel, a critical parameter in achieving optimum combustion and reducing costs
CO2 capture Clean Energy Systems
DOE $4.5 million 39 months starting Sept 2005
2B) Turbines for Oxy-Fuel Rankine Cycle Coal Based Systems
Combine current steam and gas turbine technologies to design an optimized turbine that uses oxygen with coal-derived hydrogen fuels in the combustion process
CO2 capture SWPC DOE $14.5 million 56 months starting Sept 2005
3A) Highly Efficient Zero Emission Hydrogen Combustion Technology for <100 MW Turbines
Build and demonstrate a full-scale, ultra-low NOX catalytic combustion system for fuel-flexible hydrogen combustors in megawatt-scale turbines
Emissions, Efficiency
Precision Combustion
DOE $4.9 million 60 months starting in Sept 2005
3A) Highly Efficient Zero Emission Hydrogen Combustion Technology for <100 MW Turbines
Adapt the designs and concepts of proven natural gas fuel-injector systems to hydrogen and coal syngas systems. Build and test next-generation fuel burners in a range of sizes. The modularity of this approach will reduce system production costs by allowing the building of injectors to multiple scales from a basic building block
Emissions Parker Hannifin DOE $1.2 million 32 months starting in Sept 2005
3C) <100 MW Turbines for Power and Hydrogen Co-Production in Industrial Applications
Conduct a detailed assessment of the feasibility of using partial-oxidation gas turbines for the coal-based co-production of electricity, hydrogen, and synthesis gas. In partial-oxidation turbines, part of the system’s fuel is unspent during combustion, making it available for post-system use, such as hydrogen extraction
Investment, Efficiency, Emissions
GTI DOE $1 million 22 months
4) Novel Concepts for the Compression of Large Volumes of CO2
Use supersonic shock wave technology to compress CO2. Design and fabricate a system that equals or surpasses current efficiency levels, and lowers costs through the simplification of system mechanics
CO2 capture Ramgen DOE $11 million 60 months starting in Sept 2005
C-13
4) Novel Concepts for the Compression of Large Volumes of CO2
Improve the mechanics associated with compressing and liquefying carbon dioxide. A total-system solution will be examined, including the integration of CO2 compression technologies with other IGCC subsystems
CO2 capture SwRI DOE $175k 12 months starting in Sept 2005
5) Advanced Brayton Cycles for Highly Efficient Zero Emission Systems
Identify R&D opportunities for TIT of up to 3100F, pressure ratio of up to 35, other cycle modifications, better integration with gasification and CO2 compression
CO2 capture UC Irvine DOE $600k 24 months starting in Sept 2005
Technology Integration of Fuel Cells and Gasification
IG-MCFC Operation of 2 MW MCFC on Coal Gas at Wabash River IGCC plant
Investment, Efficiency
Waiting for restart of operations
IG-SOFC Operation of small scale (~1 KW) Delphi SOFC stack on coal gas at Wilsonville PSDF
Efficiency First experiments completed in 2004
Solid Oxide Fuel Cell Coal-Based Systems
Project will eventually lead to >100 MW IGFC plants with CoP gasifiers, Siemens fuel cell/gas turbine hybrid and Air Products ITM O2. Phase 1 focus on the design, cost analysis, fabrication, and testing of large-scale fuel cell stacks fueled by coal synthesis gas.
Investment, Efficiency, CO2 capture
Siemens, ConocoPhillips, Air Products
DOE (DE-PS26-05NT42346)
Phase 1 is $7.5 million for 36 months
Mid-to-long term
Coal Gas Fed Solid Oxide Fuel Cell/Gas Turbine Hybrid with CO2 capture
Project will eventually lead to >100 MW IGFC plants with an overall efficiency of >50% HHV including 90% CO2 capture. Power block has capital cost goal of <$400/kW. Phase 1 focus on the design, cost analysis, fabrication, and testing of large-scale fuel cell stacks fueled by coal synthesis gas.
Investment, Efficiency, CO2 capture
GE, Pacific Northwest National Lab, Univ. of South Carolina
DOE (DE-PS26-05NT42346)
Phase 1 is $7.5 million for 36 months
Mid-to-long term
Technology CO2 Capture from Syngas Separate CO2 from syngas Scale up data on CO2 hydrate formation from
operation of 2.5 T/D slip stream unit for Polk IGCC plant
CO2 constraints Nexant, Simteche, Los Alamos NL
DOE $16 million total 1999-2006
CO2 separation Water-Gas Shift membrane reactor with carbon molecular sieve material deposited on stainless steel substrate, allows produced CO2 to pass through membrane, increases conversion of CO to CO2
CO2 Recovery
Media and Process Technology, USC
DOE $900K
CO2 separation Advanced separation membrane development and membrane evaluation
CO2 Recovery
INEEL, LANL, Colorado U
DOE $1.4 million
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CO2 separation Develop new sorbents for PSA and TSA separation of CO2 from syngas.
CO2 Recovery
Sud Chemie, CMU, NETL
DOE $400K
CO2 separation Removing CO2 by absorption in a water-gas shift reactor increases the efficiency, the so-called Sorption Enhanced Reaction Process (SERP).
CO2 Recovery
ECN, Netherlands Dutch Government
?? Mid-to-long term
CO2 separation Parallel programs to investigate CO2 removal by: 1) Hydrated, hollow fiber membranes (cellulose treated with N-MethylMorpholine-N-Oxide) 2) Polyimide membranes, 3) Flow through a porous liquid into a flowing absorption solvent
Dalian Institute of Chemical Physics, Chinese Academy of Science
ENCAP Provide pre-combustion decarbonization technologies in power cycles operated by natural gas, residual oil, hard coal and lignite with the objective: at least 90% capture rate for CO2, 50% capture cost reduction of the current cost per tonne of CO2 captured
CO2 constraints Vattenfall plus 32 others
EU Total = 10.7 m€ ?? 22 m€
3/04 to 3/09
Improved CO2 removal processes
COORAMENT: CO2 reduction, modeling and development (German acronym), creating new modeling tools, cost reduction increase efficiency of CO2 removal, scaleable gasification with integrated CO shift
CO2constraints TU Freiberg, Lurgi 2006 to 2009
CO2 capture and H2 production
HYCOAL project will take 2% of the syngas from the Elcogas IGCC and shift it to H2 and CO2 and then separate the CO2 and purify the hydrogen. 25000 t/yr of CO2 will be sequestered
CO2 constraints Elcogas EU 6th Framework Program
Co-gasification of biomass and coal
Co-feeding of up to 30wt% biomass and wastes to displace 15% of CO2 emissions from coal
CO2 constraints Nuon Buggenum Nuon Buggenum Near term
Improved Acid Gas Removal process, Morphysorb
Low cost, high acid gas loading capacity alternative to Selexol, being tested at NG treating facility in British Columbia
CO2 constraints GTI GTI Unknown Commercial scale test began in 2003, no plans to test on syngas
Technology Production of Liquid Fuels from Coal Liquids production from coal gas
Utilization of medium-alpha iron catalysts to produce barrel quantities of high-hydrogen Fischer-Tropsch liquids for testing
Investment Headwaters Technology, GTI, Nexant, Rentech, UOP, Pall Corporation, Air Force Research Laboratory, Argonne NL, FT Solutions
DOE DOE share $3.0 million, 24 months, mid- 2005 start
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Liquids production from coal gas
Utilization of cobalt-based catalysts to produce 6000 gallons of Fischer-Tropsch liquids for field testing
Investment Integrated Concepts and Research Solutions, Syntroleum Corporation
DOE DOE share $4.5 million, 24 months, mid- 2005 start
Liquids production from coal gas
Monash Energy Project: Production of 60,000 B/D of Diesel fuel from lignite with potential CO2 recovery for enhanced oil production or sequestration. 1500 tons of Australian lignite was gasified in a test at Future Energy's in Freiberg in 2005 to provide design data for the project.
Investment, CO2 recovery
Anglo Coal Anglo Coal 3.8 billion USD, 60 million Aust. Dollars spent so far on project development
Original schedule called for COD in 2008, current schedule unknown
Direct liquefaction of coal (hydrogenation)
Commercial production of 20,000 B/D of high quality gasoline and diesel fuel
Investment Axens (IFP); Local construction labor and fabrication of vessels
Shenhua Coal Company China
$850 million (first train)
First train under construction, operational in 2007 (four additional 20,000 B/D trains on stream by 2010-total production 1000,000 B/D)
Technology Coal Upgrading
Low-rank coal upgrading ~1000 T/D Great River Energy Demonstration project
25% reduction in feed coal moisture content to improve plant efficiency, lower SO2 and mercury emissions
Efficiency, Emissions, Investment
Great River Energy, EPRI
Great River Energy, DOE
$28 million total ($11 million DOE)
2006
Drying of 60-70% moisture Australian coals
Reduction in feed coal moisture content to improve plant efficiency
Efficiency, Investment
Coal 21 Australia
2008 commercial
Demonstrate Mechanical Thermal Expression (MTE) technology at 15 T/H scale
Reduce energy required to dry high moisture coal by using heat followed by mechanical compression to remove water
Efficiency CRC for Clean Power from Lignite
Latrobe Valley generators, Victoria government, Australian federal government
Funding uncertain due to closure of CRC for Clean Power in 2006
Pilot plant test in 2006
Coal de-ashing Ultra Clean Coal (Chemical de-ashing of coal with modified Bayer process)
Production of a very low ash solid fuel that can be used as gas turbine fuel
O&M, Investment
White Mining, Australia
Coal 21 Australia
2011 Commercial
Hyper coal (De-ashing of coal with solvent extraction and ion exchange)
Production of a solid fuel with <200 ppm ash and <0.5 ppm (Na+K)
O&M, Investment
NEDO Japan NEDO Japan
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D I&C NEEDS OF INTEGRATED GASIFICATION COMBINED CYCLES
The following EPRI paper was authored by Jeffrey N. Phillips and presented at the 15th Joint ISA POWID/EPRI Instrumentation and Controls Conference and 48th POWID 2005 Symposium in Nashville, Tennessee, in June 2005.
Abstract
Integrated gasification combined cycle (IGCC) power plants are a promising technology for clean coal-based power generation. However, the experience of the first few commercial units has shown that system reliability has been significantly lower than that of conventional coal power plants. Innovations in instrument and control technology could help reverse this trend. This paper reviews the primary opportunities for improvement in instrument and controls of an IGCC on a section by section basis.
Introduction
Integrated gasification combined cycle plants produce power using solid fuels such as coal and petroleum coke and approach both the environmental benefits of a natural gas-fueled plant and the thermal performance of a combined cycle. In its simplest form, the solid fuel is gasified with either oxygen or air, and the resulting raw gas (called syngas, an abbreviation for synthetic gas) is cooled, cleaned of particulate matter and sulfur species, and fired in a combustion turbine. By removing the emission-forming constituents from the gas under pressure prior to combustion in the power block, IGCC plants can economically meet extremely stringent air emission standards. The hot exhaust from the combustion turbine passes to a heat recovery steam generator (HRSG) where steam is produced that drives a steam turbine. Power is produced from both the combustion and steam turbines; hence, the name combined cycle.(1) A block flow diagram of an IGCC system is shown in Figure D-1.
Commercial and near commercial sized plants using IGCC technologies have now accumulated several years of operating experience. There are currently two commercial-sized, coal-based IGCC plant projects operating in the U.S. and two in Europe. The essential characteristics of these plants are shown in Table D-1.(2)
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Figure D-1 IGCC Process Block Diagram
Table D-1 Major Coal-Based IGCC Plants
Project Name / Location
Combustion Turbine
Gasification Technology
Net Output MW
Startup Date
NUON (formerly Demkolec) / Buggenum, The Netherlands
Siemens V 94.2 Shell 253 January 1994
Wabash River / Indiana
GE 7 FA E Gas (ConocoPhillips)
262 October 1995
Tampa Electric Co. Polk Power Station / Florida
GE 7 FA Texaco (GE Energy)
250 September 1996
ELCOGAS / Puertollano, Spain
Siemens V 94.3 Prenflo (now marketed as Shell)
300 December 1997
The main challenges with regard to the widespread adoption of this technology are: (i) demonstration of high availability equal to or better than existing direct Pulverized Coal (PC)
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plants and (ii) capital cost reduction to compete with state-of-the-art PC plants and natural gas based combined cycles. The first challenge is illustrated by the availability data of the four IGCC plants shown in Figure D-2. Availability factors for conventional pulverized coal combustion power plants are typically in the range of 85 to 90%, with the best approaching 95%. This means that 85 to 90% of the time a typical PC plant is available to operate. When a plant is not available to operate it is typically because of either planned or unplanned maintenance activity.
The trends shown in Figure D-2 indicate that the four IGCC plants have taken four to five years to reach availability factors between 60% and 80% and that none have reached the levels typical for conventional coal plants.
0.0%
10.0%
20.0%
30.0%
40.0%
50.0%
60.0%
70.0%
80.0%
90.0%
1styear
2ndyear
3rdyear
4thyear
5thyear
6thyear
7thyear
8thyear
9thyear
10thyear
11thyear
Nuon AvailabilityWabash AvailabilityTECO AvailabilityElcogas CF
Figure D-2 Availability and Capacity Factor (CF) Data for the Four Coal-Based IGCC Units Described in Table D-1. [Note that capacity factors are typically 5 to 10 points lower than availability.]
It should be noted that the data in Figure D-2 exclude the impact of combined cycle operation on back-up fuels. All four plants are capable of operating on natural gas or distillate fuel when syngas is not available. The Tampa Electric plant, for example, has exceeded 85% availability for 6 of the last 7 years when operation on back-up fuel is also considered. However, because of the high price of natural gas and distillate compared to coal, the economics of an IGCC is strongly influenced by its coal-fueled availability.
Based on analysis of the causes of unscheduled outages at the four IGCCs listed in Table D-1, and discussions with major IGCC technology suppliers as well as key staff at the U.S.
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Department of Energy, the Electric Power Research Institute (EPRI) believes that improvements in instrumentation and control technology could have a significant positive impact on the coal-fueled availability of IGCCs. The key areas where those I&C improvements are needed are described in this paper.
Coal Feeding I&C Needs
Accurately monitoring the quality and quantity of coal being fed to a gasifier is critical to maintaining smooth operation. In an ideal gasifier, only enough oxygen would be injected as is needed to react with the carbon in the coal based on the simplified chemical reaction:
C + ½O2 => CO (1)
In a real gasifier however, additional oxygen is added in order to convert some of the carbon monoxide (CO) to carbon dioxide (CO2):
CO + ½O2 => CO2 (2)
This second reaction is highly exothermic and generates the heat needed to drive the other gasification reactions. High temperatures are also needed to ensure operation above the slagging temperature, or melting point, of the coal’s ash. Since direct measurement of the gasifier operating temperature is difficult (see the discussion under the next heading) the gasifier operating conditions are usually controlled by monitoring the amount of CO2 in the syngas. This can be thought of as the gasification equivalent of the O2 concentration in a boiler’s stack gas. A schematic diagram for this gasifier control strategy is shown in Figure D-3.
If coal quality rapidly changes, such as an increase in the amount of ash or a change in the oxygen or moisture content of the coal, it may take several minutes or longer for the full impact of this change to be detected by the gas composition analyzer. During that time the temperature within the gasifier may fall and the slag may solidify or the amount of unconverted carbon in the solids exiting the gasifier may rise to levels that cause difficulties in the downstream processing.
An on-line coal quality analyzer would help greatly by providing plant operators and the gasifier control system with “advanced warning” of changes in coal quality that might adversely impact the gasification operations. Percent ash content and the percentages of the major ash species (alumina, silica, and oxides of calcium and iron) are the most important attributes that need to be monitored for all types of slagging gasifiers. Also, for gasifiers which use coal-water slurry to feed the gasifier, the percent water content of the slurry is an important parameter to monitor.
An accurate coal feed rate meter is a second need for this section of an IGCC. Coal is injected into a gasifier in one of two modes: dense-phase, pneumatic transport or as coal-water slurry. In either mode the coal flow is at high pressure (>2 MPa) as the gasifier is also operated at high pressure in order to produce a syngas suitable for feeding the combustion turbine. Both transport modes are difficult to measure with accuracy of the full range of gasifier operating conditions including start-up and shutdowns.
D-5
Gasifier
SyngasCleanup
Syngascomposition
controller
SyngasCO2 Content
Oxygen/CoalRatio
Oxygen
Coal
CleanSyngas
Figure D-3 Schematic Diagram of the Syngas Composition Control Loop
Gasifier I&C Needs
There are two generic types of gasifier vessel designs. One uses multiple layers of refractory brick to insulate the metal pressure containing vessel wall from the hot gasification reaction zone (typically >1400ºC in a slagging gasifier). The other uses a water-cooled “membrane wall in which boiler tubes are welded together to form a continuous wall around the reaction zone. A thick, metal pressure shell behind the membrane contains the process pressure.
The refractory-lined vessel design is considerably cheaper to build than the membrane wall construction. However, the refractory is worn down by chemical attack from the gasification products and the molten slag and it also suffers from thermal fatigue fractures due to the large temperature cycles experienced during start-ups and shutdowns. This refractory typically must be replaced every 6 to 18 months at a cost of about $1 million including materials and labor.(3)
Because of the high cost of replacement, a gasifier owner wants to extend the use of a given set of refractory for as long as is prudent. However, given the substantial damage that could be caused to the pressure shell if the refractory is allowed to deteriorate too much, gasifier owners also periodically inspect the condition of the refractory. Unfortunately, such an inspection requires the process to be shutdown and cooled off before staff can enter the gasifier. The distance from the gasifier centerline to the refractory surface is then measured at various places within the gasifier to get an overview of the state of the refractory. A new measurement system is needed which would allow the contour of the refractory surface to be mapped without a person having to enter the gasifier. Ideally this mapping should take place while the gasifier is operating to minimize downtime. Less ideally, but still an improvement over the current state-
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of-the-art, would be a system that mapped the refractory while the gasifier was shutdown but still hot. This would allow the gasifier to be quickly restarted after the mapping and minimize thermal fatigue on the refractory.
A second approach to refractory monitoring could be a system that inferred the refractory condition by monitoring the temperatures on the cold side of the refractory. The key would be having complete coverage of the refractory while minimizing the number of sensors to keep both initial cost and on-going O&M costs low.
A second part of the gasifier system which requires frequent maintenance is the feed injector. This is particularly true for gasifiers fed by coal-water slurries. Drops from the slurry can impinge on the injector’s metal surface causing failure due to thermal fatigue cracking. According to the U.S. Department of Energy, typical injector life in a slurry-fed gasifier is between two and six months.(3)
In order to avoid unnecessary shutdowns, it would be useful to have a feed injector integrity monitoring system which could advise operators on when an injector needed to be replaced.
Slag viscosity measurement is another important I&C need in the gasifier. The operating conditions within a gasifier are typically dictated by two considerations: adequate carbon conversion and staying above the ash melting point of the coal. One way to achieve both is to “overfire” the gasifier by sending more oxygen to the gasifier. However, this harms the overall efficiency of an IGCC by increasing the parasitic power load of the air separation unit, and, in the case of a refractory-lined gasifier, it also shortens the life of the refractory.
For most coals the ash melting point is more constraining than carbon conversion considerations and therefore sets the operating temperature of the gasifier. If the composition of the ash changes, the viscosity versus temperature characteristic of the slag will also change. This means the appropriate operating temperature of the gasifier should also change to avoid either overfiring or solidifying of the slag within the gasifier.
An indication of the slag viscosity at the point where the slag exits the gasifier would be a valuable tool for gasifier operators. This tool could take the form of an actual viscosity measurement, or a measurement of the thickness of the molten slag layer (an increasing thickness would be an indication of the need for a hotter gasifier), or an estimated viscosity derived from the composition of the ash in the gasifier feed stream. The latter approach would have to recognize that some partitioning of the ash species occurs within the gasifier with more volatile species exiting with the gas phase.
A companion to the slag viscosity measurement is the need for an accurate measurement of the gas phase temperature within the gasifier. The two most important locations for monitoring temperature are where the slag exits the gasifier and where the syngas exits the gasifier. In some gasifiers, this is the same location (i.e., down-fired gasifiers have both slag and syngas exiting at the bottom).
Because of the challenging physical conditions within the gas phase of a gasifier, direct measurement of the syngas temperature has not been successful. Instead the temperature is measured at some point downstream of the gasifier, and the gasifier exit temperature is estimated
D-7
from an energy balance around the equipment between the gasifier exit and the measurement point. The accuracy of such an approach suffers due to the large number of parameters that impact the calculation including gas composition and flow rate. The calculation is particularly inaccurate during non steady-state operation such as start-up and load changes.
Rapid, on-line syngas composition measurement is the final important I&C need in the gasifier section of an IGCC. As indicated in Figure D-3, the main control loop for the gasifier oxygen-to-coal ratio depends on measuring the syngas CO2 composition. Currently, syngas composition is measured by taking a gas sample downstream of the gasifier after the gas has been cooled and particulates have been removed. Typical raw syngas analyses are shown in Table D-2. The sample is then sent to a gas chromatograph (GC). Because of the cycle time of the GC and the residence time it takes for the syngas to travel from the gasifier to the sample point, it can take as long as 5 minutes for a change in gasifier operating conditions to be reflected in the syngas analysis.
Table D-2 Typical Raw Syngas Composition of Three Commercial Coal Gasification Processes (Trace Species not Included)
Syngas A Syngas B Syngas C
%vol %vol %vol
Ar 1.02 0.93 1.13
CH4 1.10 0.03 0.06
CO 52.33 63.14 43.04
CO2 10.90 1.05 17.93
H2 32.13 28.51 36.27
H2O 0.95 1.23 0.18
H2S 0.64 0.69 0.58
N2 0.93 4.42 0.81
Sum 100.00 100.00 100.00
In order to have rapid feedback between changes in the gasifier feed control valves and the syngas composition, it would be helpful to have a composition measurement that analyzed the composition at the gasifier exit. A tunable laser absorption-based system could be a potential solution, if it could be made reliable enough for control system use. Keeping an optical port open in a slagging environment will be one the challenges.
Solids Handling I&C Needs
Downstream of the gasifier the syngas is cooled in a waste heat boiler, and then the entrained solids are removed in either a rigid barrier, pulse-cleaned filter or a venturi scrubber. The advantage of the former is the solids are captured dry and can be sold for use in cement if low in
D-8
carbon or recycled to the gasifier if high in carbon. It also simplifies the treatment process for any water which condenses out of the syngas downstream of the filter as that water is solids-free.
However, if one of the filter elements should fail, it is important to quickly detect this failure and shutdown the gasifier before the downstream equipment is fouled by flyash and char. A system for detecting filter element failure is therefore another IGCC I&C need.
Several dry solids removal systems have caused outages when collected solids built up at the bottom of the filter vessels due to plugging of the solids depressurization path. The level of the solids eventually reached the filter elements and ultimately caused the elements to break. A reliable level detection system that will trip the process before the solids reach the level of the filter elements is the second I&C need of the solids removal section.
Ideally the level detection should not be based on a radiation source as this brings additional regulatory and training requirements to the maintenance of the plant.
“Black Water” Handling I&C Needs
For IGCCs which do not have a dry solids filter, the water which circulates through the venturi scrubbers is a dilute slurry of flyash, char and water. For obvious reasons this slurry is often referred to as “black water.” The black water contains dissolved gases such as H2S and CO2 as well as chlorides and ammonia. The resulting mixture can have a widely varying pH depending on the syngas composition, the chloride content of the coal, and the amount of blowdown from the circulating flow. Reliable, on-line pH measurement is required in order to adequately control the pH of the black water. If pH is allowed to swing, dissolved solids can precipitate out and plug the piping with calcium carbonate and other solids.
Unfortunately, the combination of high pressure and moderately high temperature (circa 200ºC) is not suitable for most pH meters. Depressurizing and cooling a slipstream sample of the black water typically causes the pH to change and therefore does not provide a true indication of the process. Reliable pH meters that can operate at the process temperature and pressure and also not be fouled by the solids in the black water are needed.
Also needed for controlling the black water system are flow meters which can stand up to the combination of high pressure, 200ºC temperatures, and solids loading. Magmeters would be a logical solution if their electronics could be designed to withstand the process temperature.
Combustion Turbine I&C Needs
Combustion turbine OEMs are concerned about the quality of the syngas being sent to their turbines. In order to adequately control the combustion process, the heating value of the syngas must be known. Rapid, on-line analysis of the fuel composition, from which heating value can be calculated, or rapid, direct analysis of the heating value is needed. GCs do not provide the response time needed for this application. As with the gasifier syngas measurement, tunable laser absorption is a potential application here.
D-9
In addition to knowing the composition of the major species of the syngas which contribute to the heat value, combustion turbine manufacturers also want to know if any species which could be harmful to the turbine are in the syngas. Such a measurement could be used to trigger a switch to a back-up fuel such as natural gas or distillate fuel oil until the syngas is back within the manufacturer’s specified limits. Among the items of interest are particulate matter, metal carbonyls, arsenic, and vanadium.
Air Separation Unit I&C Needs
Despite the fact that an air separation unit (ASU) is considered commercially mature technology, at least three commercial IGCC power plants have suffered lengthy outages due to failures associated with the control of the main air compressor in their ASUs.(4,5,6) In two cases the actuator systems for the main air compressor inlet guide vanes proved to be inadequate. In the third case an error in the surge control logic led to damage to the compressor’s third stage. Based on these experiences, more care in the design of the ASU control system is clearly needed.
General IGCC I&C Needs
A cost-effective process protection system is an important need for IGCCs. Nuisance trips caused by instrument failures are particularly costly to IGCCs due to their relatively long shutdown and start-up cycles. These types of trips can be limited by using multiple voting logic (e.g., 2 out of 3). However, additional instrumentation adds additional costs. Recommendations on cost-effective, yet safe protection system designs are needed.
Advanced, integrated control strategies are a final I&C need for IGCC power plants. An IGCC contains at least four separate processes which can have strong interactions on one or more of the other processes: ASU, gasification, syngas clean-up including sulfur recovery and the combined cycle. Three of these processes (ASU, sulfur recovery, and the combined cycle) are typically supplied by a vendor that is independent of the gasification process supplier and often are provided with independent control systems. Improved control strategies are needed to ensure that the IGCC process as a whole operates as close to its optimum as possible over the full range of operating conditions (i.e., varying ambient conditions and varying load levels).
The interaction between the combustion turbine and the ASU is one example. The air fed to the ASU can come from one of two sources: a bleed stream from the combustion turbine compressor discharge or a stand-alone air compressor driven by an electric motor. Optimizing the amount of air that comes from the two sources is not an intuitively obvious task. Increasing the bleed flow from the combustion turbine lowers the pressure ratio of the turbine which can impact the power cycle’s efficiency. However, under some ambient and load conditions, some air must be bled from the combustion turbine compressor in order to avoid surge. Reducing the load of the stand-alone air compressor, on the other hand, may cause it to operate at a lower efficiency. Sophisticated controls are needed to find the “sweet spot” for both machines.
A second example is the start-up procedure of the IGCC. If all of the equipment is at ambient temperature due to a long maintenance outage, a start-up can take more than 4 days. Most of that time is spent cooling down the ASU to cryogenic conditions. Also, once the gasifier begins producing syngas, that syngas must be flared until it meets all the specifications for the
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combustion turbine, principally supply pressure and sulfur content. This “lining out” of the process can take up to two hours from the time coal first enters the gasifier until flaring has stopped.(7) In addition to the cost of the coal which goes to waste, the emissions from the flare are also an unwanted situation. A control strategy to minimize the ASU cool down period and the flaring time would be welcomed developments.
References
1) Holt, Neville A.H., “Integrated Gasification Combined Cycle Power Plants,” Encyclopedia of Physical Science and Technology, 3rd Edition, Academic Press, September 2001.
2) Holt, Neville A.H., “Gasification Technology Status – September 2004,” Report #1009769, EPRI, Palo Alto, CA: 2004.
3) Clayton, S.J., et al., “Gasification Technologies,” Report DOE/FE-0447, U.S. Dept. of Energy, Germantown, MD: 2002.
4) McDaniel, John, “Tampa Electric Company Polk Power Station Integrated Gasification Combined Cycle Project,” Final Technical Report, U.S. Dept. of Energy, Morgantown, WV: 2002.
5) “Wabash River Coal Gasification Repowering Project,” Final Technical Report, U.S. Dept. of Energy, Morgantown, WV: 2000.
6) Yamaguchi, Makoto, “First year of Operational Experience with the Negishi IGCC,” presented at the 2004 Gasification Technologies Conference, Washington, DC: October 2004.
7) McDaniel, John, “Polk Integration Issues,” presented at EPRI CoalFleet for Tomorrow workshop, Indianapolis, IN: April 2005.
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