Advanced Coal Power Systems with CO2 Capture: EPRI's CoalFleet for Tomorrow Vision · ·...

Advanced Coal Power Systems with CO2 Capture: EPRI’s CoalFleet for Tomorrow Vision

A Summary of Technology Status and Research, Development, and Demonstrations


A Summary of Technology Status and Research, Development, and Demonstrations

1016877

Interim Report, September 2008

EPRI Project ManagersJ. ParkesA. MaxsonJ. Wheeldon

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:

(A) MAKES ANY WARRANTY OR REPRESENTATION WHATSOEVER, EXPRESS OR IMPLIED, (I) WITH RESPECT TO THE USE OF ANY INFORMATION, APPARATUS, METHOD, PROCESS, OR SIMILAR ITEM DISCLOSED IN THIS DOCUMENT, INCLUDING MERCHANTABILITY AND FITNESS FOR A PARTICULAR PURPOSE, OR (II) THAT SUCH USE DOES NOT INFRINGE ON OR INTERFERE WITH PRIVATELY OWNED RIGHTS, INCLUDING ANY PARTY’S INTELLECTUAL PROPERTY, OR (III) THAT THIS DOCUMENT IS SUITABLE TO ANY PARTICULAR USER’S CIRCUMSTANCE; OR

(B) ASSUMES RESPONSIBILITY FOR ANY DAMAGES OR OTHER LIABILITY WHATSOEVER (INCLUDING ANY CONSEQUENTIAL DAMAGES, EVEN IF EPRI OR ANY EPRI REPRESENTATIVE HAS BEEN ADVISED OF THE POSSIBILITY OF SUCH DAMAGES) RESULTING FROM YOUR SELECTION OR USE OF THIS DOCUMENT OR ANY INFORMATION, APPARATUS, METHOD, PROCESS, OR SIMILAR ITEM DISCLOSED IN THIS DOCUMENT.

ORGANIZATION(S) THAT PREPARED THIS DOCUMENT

Electric Power Research Institute Bevilacqua-Knight, Inc.

NOTE

For more information, contact the EPRI Customer Assistance Center at 800.313.3774 or e-mail [email protected].

Electric Power Research Institute and EPRI are registered service marks of the Electric Power Research Institute, Inc.

Copyright © 2008 Electric Power Research Institute, Inc. All rights reserved.

iiiAdvanced Coal Power Systems with CO2 Capture: EPRI’s CoalFleet for Tomorrow Vision

Citations

This document was prepared by

Electric Power Research Institute (EPRI) 3420 Hillview Avenue Palo Alto, CA 94304

Principal Investigators Neville Holt Andrew Maxson Jack Parkes Jeff Phillips Rob Trautz John Wheeldon Jeff Brehm (Editor)

Bevilacqua-Knight, Inc. 1000 Broadway, Suite 410 Oakland, CA 94607

Editors Richard Myhre Marian Stone Eric Worrell

This document describes research sponsored by the Electric Power Research Institute. Its goal is to provide a primer on the status of the portfolio of gasification- and combustion-based advanced coal power technologies, and opportunities for increased efficiency, state-of-the-art emissions controls, and CO2 capture and storage.

This publication is a corporate document that should be cited in literature in the following manner:Advanced Coal Power Systems with CO2 Capture: EPRI’s CoalFleet for Tomorrow Vision, EPRI, Palo Alto, CA: 2008. 1016877.

�Advanced Coal Power Systems with CO2 Capture: EPRI’s CoalFleet for Tomorrow Vision

T he Electric Power Research Institute (EPRI) has examined current and potential options for reducing greenhouse gas (GHG) emissions from the electric sector. EPRI’s analysis shows a significant

contribution from advanced coal power systems with carbon capture and storage (CCS) likely will be required to achieve economical GHG reductions. However, CCS technology is not yet commercially available.

Results and Findings

Proposed roadmaps for providing cost-effective and low-carbon advanced coal power for multiple technologies have been developed.

Challenges and Objectives

Increasing demand for cost-effective power in the face of ever more stringent environmental pressures is a significant challenge. Now, CO2 concentrations in the atmosphere that could result in global climate change pose a new challenge. As climate change effects have become better understood, the need to limit anthropogenic emissions of CO2 and other GHGs has become a familiar topic among policymakers and the public and ultimately may require substantial changes in the way power is produced. For coal, which is the largest producer of power in the world and emits CO2 at high levels, the requirement to develop new technology and processes to combat CO2 is a pressing need.

The objective of this project is to outline the issues related to coal generation and carbon capture and storage, detail the current state of its technology, including pulverized coal, fluidized beds, oxy-combustion, and IGCC, and discuss a plan by EPRI to develop and demonstrate advanced coal technologies.

Applications, Values, and Use

This document describes research sponsored by EPRI. Its goal is to provide a primer on the status of the portfolio of gasification- and combustion-based advanced coal power technologies, and opportunities for increased power generation efficiency, state-of-the-art emissions controls, and CO2 capture and storage.

EPRI Perspective

A “full portfolio” of innovative technology approaches is needed to make substantial CO2 emissions reductions, while minimizing economic impacts of reductions policies. A significant part of that portfolio is commercially viable CO2 capture and storage for coal generation by 2020. EPRI has developed aggressive plans to achieve this goal, encompassing a series of large-scale demonstrations to validate new technology and processes.

Approach

In collaboration with other researchers, EPRI is pursuing critical-path activities to help ensure that multiple, competitive, advanced coal generation and CCS technologies become a commercial reality by 2020. The power industry is working with EPRI to launch major demonstrations of advanced coal and CCS technologies, the kinds of “big steps” urgently required for commercial readiness of CCS by 2020. The challenge lies in how to fast-track the development and deployment of technologies that could meet those goals.

Product Description

�i Advanced Coal Power Systems with CO2 Capture: EPRI’s CoalFleet for Tomorrow Vision

EPRI’s approach is to help develop and implement roadmaps for development and deployment of multiple advanced coal generation types and provide independent assessments of new technologies and processes to help accelerate their development and application.

Keywords

Carbon capture and storage (CCS)CoalCoalFleet for TomorrowGreenhouse gas (GHG)Integrated gasification combined cycle (IGCC)Pulverized coal (PC)

�iiAdvanced Coal Power Systems with CO2 Capture: EPRI’s CoalFleet for Tomorrow Vision

Contents

1 ELECTRICITy GENERATION FOR A LOW-CARBON FUTURE . . . . . . . . . . . . . . . . 1-1Satisfying the Demand for Affordable Electricity while Reducing CO2 Emissions .............. 1-2Modeling the Future: EPRI’s PRISM and MERGE Studies ................................................. 1-3Independent Studies Corroborate EPRI Findings ........................................................... 1-4Coal’s Role in Global Power Generation ..................................................................... 1-5RD&D to Prepare Coal Generation for a Low-Carbon Future .......................................... 1-5

2 ThE PROMISE OF ADVANCED COAL POWER SySTEMS . . . . . . . . . . . . . . . . . . 2-1Building a Portfolio of Competitive Advanced Coal Technology Options ......................... 2-2Coal Properties Drive Generation Technology Selection and Plant Design ...................... 2-5The Importance of Early Deployment of Advanced Coal Technologies ............................ 2-6

3 COMBUSTION-BASED SySTEMS – EXTENDING ThE LIMITS OF A MATURE TEChNOLOGy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3-1

Pulverized Coal ........................................................................................................ 3-1Commercial Status ............................................................................................. 3-1Environmental Controls – The Promise of Near-Zero Emissions ................................. 3-2

SO2 Removal with Flue Gas Desulfurization .................................................... 3-2Dual Strategies for NOX Control .................................................................... 3-3Technologies for Particulate Control ............................................................... 3-4Reducing Mercury Emissions ......................................................................... 3-4

Reducing CO2 Emissions Through Increased Efficiency and Improved CO2

Capture Processes .............................................................................................. 3-4Steps and Timeframe for USC PC Cost Reduction and Efficiency Gains .................... 3-5Advanced Materials – The Key to PC Efficiency Gains ............................................ 3-6

Ferritic/Martensitic Steels ............................................................................. 3-6Austenitic Stainless Steels .............................................................................. 3-6Nickel-Based Alloys ..................................................................................... 3-6

Advanced Materials Research8 ........................................................................... 3-6Post-Combustion Removal of CO2 from Flue Gases ................................................. 3-7

Amine-Based Solvent Technologies ................................................................ 3-8Potential Alternatives to Amine-Based Solvent Technologies ............................... 3-9Oxy-Combustion for CO2 Capture ................................................................. 3-10

Circulating Fluidized-Bed Combustion ......................................................................... 3-11Commercial Status ............................................................................................. 3-11Environmental Controls ....................................................................................... 3-11Efficiency Improvements and CO2 Capture ........................................................... 3-12

4 IGCC TEChNOLOGIES – TRANSITIONING TO ThE COMMERCIAL ERA . . . . . . . . 4-1Overview ................................................................................................................ 4-1Commercial Status .................................................................................................... 4-3Emission Controls ..................................................................................................... 4-3

Sulfur Species Removal ...................................................................................... 4-3NOX Control ...................................................................................................... 4-3Mercury and Trace Toxics Removal ...................................................................... 4-4Particulate Removal ............................................................................................ 4-4

�iii Advanced Coal Power Systems with CO2 Capture: EPRI’s CoalFleet for Tomorrow Vision

Steps and Timeframe for IGCC Capital Cost Reduction and Efficiency Gains ................... 4-4Longer-Life Components for Improved Gasifier Availability6 ..................................... 4-5Higher-Pressure Gasifiers .................................................................................... 4-5Gas Turbines for Synthesis Gas Firing ................................................................... 4-6Supercritical Heat Recovery Steam Generators ...................................................... 4-6Liquid CO2-Coal Slurrying for Low-Rank Coals ....................................................... 4-6Ion Transport Membrane for Lower Cost, Energy-Efficient Oxygen Production ........... 4-7

CO2 Capture for IGCC Units ...................................................................................... 4-7Hydrogen-Firing Gas Turbines ............................................................................. 4-9New Gasifier Designs Better Suited for CO2 Capture ............................................. 4-9

5 CO2 COMPRESSION, TRANSPORTATION, AND STORAGE . . . . . . . . . . . . . . . . 5-1CO2 Purification, Drying, and Compression ................................................................. 5-1CO2 Transportation ................................................................................................... 5-3CO2-Based Enhanced Oil and Gas Recovery ............................................................... 5-3Long-Term Geologic Storage ...................................................................................... 5-4

Depleted Oil and Gas Reservoirs ......................................................................... 5-5Deep Saline Formations ...................................................................................... 5-5Unminable Coal Beds ......................................................................................... 5-6

Regulatory Oversight for CCS .................................................................................... 5-6Select RD&D Programs for Geologic Carbon Sequestration ........................................... 5-7

IEA GHG .......................................................................................................... 5-7Regional Carbon Sequestration Partnerships22 ...................................................... 5-7

6 IMPLEMENTING ThE ADVANCED COAL RD&D ROADMAP . . . . . . . . . . . . . . . . 6-1EPRI Steers a Course to Advanced Coal-Based Generation with CCS ............................. 6-1Advanced Combustion with Post-Combustion Capture ................................................... 6-2UltraGen ................................................................................................................. 6-3Post-Combustion CO2 Capture Scale-Up Demonstrations ............................................... 6-4Oxy-Combustion for PC and CFBC ............................................................................. 6-5IGCC with CO2 Capture and Storage ......................................................................... 6-5Scale-Up and Integration of ITM Oxygen Production ................................................... 6-6The Resources Necessary for Success ......................................................................... 6-6EPRI Helps Shape the Future ...................................................................................... 6-6

ixAdvanced Coal Power Systems with CO2 Capture: EPRI’s CoalFleet for Tomorrow Vision

List of Figures

Figure 1-1 Electricity Generation by Fuel for Select Countries and Continents (2004, with Projections of Growth Through 2020)1 ......................................... 1-1

Figure 1-2 EPRI’s PRISM Analysis Illustrates a Path to Lowering U.S. Electricity-Related CO2 Emissions by 30% by 2030 ................................................................... 1-3

Figure 1-3 EPRI’s MERGE Analysis Shows the Value of Employing a Full Portfolio of CO2-Reduction Technologies for the U.S. Electric Sector ................................... 1-4

Figure 1-4 High-Efficiency Advanced Pulverized Coal Power Plants Substantially Reduce Fuel Costs and CO2 and Other Emissions8 ........................................... 1-6

Figure 2-1 Development Status of Major Advanced Coal and CO2 Capture and Storage Technologies ............................................................................................... 2-7

Figure 3-1 Photo of MidAmerican’s Walter Scott, Jr. Energy Center Unit 4 SCPC Plant 1 ...... 3-1

Figure 3-2 RD&D Path for USC PC Power Plants with 90% CO2 Capture (Upturning Arrows Refer to Right Axis and Downturning Arrows to the Left Axis) .................. 3-5

Figure 3-3 PC Net Power Output, Capital Cost, and COE with and without Capture (Powder River Basin Coal)11 .......................................................................... 3-8

Figure 3-4 Schematic of Oxy-Combustion Process16 ......................................................... 3-10

Figure 4-1 Aerial View of Tampa Electric Company’s 250 MW Polk Unit 1 IGCC Plant1...... 4-1

Figure 4-2 Block Flow Diagram of an IGCC Power Plant .................................................. 4-2

Figure 4-3 RD&D Path for IGCC Power with 90% CO2 Capture (Upturning Arrows Refer to Right Axis and Downturning Arrows to the Left Axis) ............................. 4-4

Figure 4-4 Net Power Output for IGCC with and without Capture (Illinois #6 Coal)12 .......... 4-8

Figure 5-1 Injection of CO2 for Enhanced Oil Recovery (EOR) with Some Storage of Retained CO2

7 ......................................................................................... 5-4

Figure 6-1 Steps in Technology Validation and Scale-Up Projects to Meet CURC-EPRI Roadmap Goals for Advanced Coal Technologies with CCS ............ 6-2

Figure 6-2 Design Parameters for EPRI’s UltraGen III ........................................................ 6-3

xiAdvanced Coal Power Systems with CO2 Capture: EPRI’s CoalFleet for Tomorrow Vision

List of Tables

Table 2-1 Progression of Coal Power Technology Development in the United States* ......... 2-1

Table 2-2 Advanced Coal Power Block Technologies ..................................................... 2-3

Table 2-3 Typical Control Technologies for Air Emissions from Coal Power Plants ............. 2-4

Table 2-4 CO2 Capture Technologies for Advanced Coal Power Plants ............................ 2-5

Table 6-1 Performance Parameters for UltraGen I, II, and III ............................................ 6-3

xiiiAdvanced Coal Power Systems with CO2 Capture: EPRI’s CoalFleet for Tomorrow Vision

List of Acronyms

Acronym Meaning Acronym Meaning

ACI activated carbon injection Hg mercury

AEP American Electric Power H2S hydrogen sulfide

AGR acid gas recovery HHV higher heating value

ALWR advanced light water (nuclear) reactor HRSG heat recovery steam generator

ASTMAmerican Society for Testing and Materials

IEA International Energy Agency

ASU air separation unit IGCCintegrated gasification combined cycle

B&W Babcock & Wilcox ITM ion transport membrane

CCS carbon or CO2 capture and storage MDEA methyldiethanolamine

CFBC circulating fluidized bed combustion NOX nitrogen oxides

CO carbon monoxide NZE near-zero emissions

CO2 carbon dioxide PAC powdered activated carbon

COE cost of electricity PC pulverized coal

COS carbonyl sulfide PHEV plug-in hybrid vehicle

CURC Coal Utilization Research Council PM particulate matter

ECBM enhanced coal bed methane RD&Dresearch, development, and demonstration

EIA U.S. Energy Information Administration SCPC supercritical pulverized coal

EOR enhanced oil recovery SCR selective catalytic reaction

EPA U.S. Environmental Protection Agency SO2 sulfur dioxide

EPRI Electric Power Research Institute tpd tons per day

ESP electrostatic precipitator UIC underground injection control

FGD flue gas desulfurization USC ultra-supercritical

GHG greenhouse gas

x�Advanced Coal Power Systems with CO2 Capture: EPRI’s CoalFleet for Tomorrow Vision

List of Units

Acronym Meaning (Unit Type, System) Acronym Meaning (Unit Type, System)

bara bar absolute (pressure, English) mega (M) 106

Btu British thermal unit (energy, English) micro (µ) 10–6

°C degrees Celsius (temperature, SI) milli (m) 10–3

°Fdegrees Fahrenheit (temperature, English)

N Newton (force, SI)

g gram (mass, SI) ppb parts per billion (concentration)

giga (G) 109 ppm parts per million (concentration)

J Joules (energy, SI) psipounds per square inch (pressure, English)

kilo (k) 103 psiapounds per square inch absolute (pressure, English)

lb pound (mass, English) tons 2000 pounds (weight, English)

m meter (length, SI) W Watt (power, SI)

m3 cubic meter (volume, SI) Wh Watt hours (energy, SI)

x�iiAdvanced Coal Power Systems with CO2 Capture: EPRI’s CoalFleet for Tomorrow Vision

Foreword

S ociety demands viable solutions to global climate change that also minimize increases in energy prices and their economic impacts.

The Electric Power Research Institute (EPRI) has examined current and potential options for reducing greenhouse gas (GHG) emissions from the electric sector and has concluded a “full portfolio” of innovative technology approaches, ranging from energy efficiency to clean generating technologies to plug-in hybrid vehicles (PHEV), will enable substantial emissions reductions while minimizing economic impacts of reductions policies. Moreover, implementation of the portfolio must start now1.

EPRI’s analysis further shows a significant contribution from advanced coal power systems with carbon capture and storage (CCS) likely will be required to achieve economical GHG reductions. Also extremely important are efficiency-improving technologies that reduce emissions of all kinds, including CO2. Such measures also can allow CO2 reductions at existing plants that may not be able to retrofit CCS systems. However, CCS technology is not yet commercially available and requires public and private resources for its research, development, and demonstration (RD&D). “Only CCS can reconcile the continued use of our enormous coal resources with the need to reduce CO2 emissions,” wrote Steven Specker, CEO of EPRI, in the Spring 2007 EPRI Journal.

Other researchers have drawn similar conclusions. Their belief is exemplified by a quote from International Energy Agency (IEA) Executive Director Nobuo Tanaka: “We would need to build at least 20 CCS demos by 2020, at a cost of ~$1.5 billion each. Such a construction program should be viewed as a litmus test of our seriousness towards combating climate change.”2

In collaboration with many other researchers, EPRI is pursuing critical-path activities to help ensure that multiple, competitive, advanced coal generation and CCS technologies become a commercial reality by 2020. The challenge lies in how to fast-track the development and deployment of technologies that could enable advanced coal power plants to meet society’s affordable energy and environmental goals.

For the last three years, the more than 60 member organizations within several EPRI programs—in particular, the CoalFleet for Tomorrow group—have examined in detail the technical and institutional barriers to advanced coal and CCS technologies, and have identified the critical RD&D pathways to overcome these barriers and achieve a set of competitive, commercially ready technology options. Many important development activities for advanced coal and CCS technologies already are under way, both collaboratively through EPRI and independently by multiple utilities and technology developers across the globe.

Further, the power industry is working with EPRI to launch major demonstrations of advanced coal and CCS technologies. These are the kinds of “big steps” urgently required to meet society’s need for commercial readiness of CCS by 2020. Despite these activities, there still is a need to accelerate the pace of RD&D and increase investment in advanced coal and CCS technologies to make them ready for commercial deployment.

The steps to realizing CCS for coal power plants are understood and technically sound. The challenge lies in developing and deploying these new technologies before it is too late to reduce GHG emissions sufficiently to avert the projected consequences of global climate change.

1 The Power to Reduce CO2 Emissions: the Full Portfolio, Discussion Paper by EPRI Energy Technology Assessment Center, EPRI, Palo Alto, CA: August 2007 (http://epri-reports.org/DiscussionPaper2007.pdf)

2 Enhancing Energy Resource Availability, Presented at the 11th International Energy Forum, Rome, 21 April 2008, http://www.iea.org/textbase/speech/2008/tanaka/iefrome.pdf

Electricity Generation for a Low-Carbon Future


1-1

1 ElECtRICIty GEnERAtIOn FOR A lOW-CARBOn FutuRE

E lectricity is the lifeblood of our modern world. Indeed, it is hard to find a single aspect of life that has not been transformed by electric power. Many advances in medicine, transportation,

manufacturing, communications, and information technology were attainable because of electricity. In societies around the globe, electrification is a fundamental catalyst for economic growth and the means to improve living conditions.

Around the world, electricity largely is produced from fossil fuels, and coal often is the predominant fuel choice (see Figure 1-1). In North America, Australia, and parts of Europe, Asia, and Africa, coal-fired power plants supply more than half of the electricity consumed. Coal has become the primary fuel for affordable and reliable electric power production because it is relatively easy to transport and use and because many countries have indigenous coal resources.

In exploiting the benefits of electricity generated from coal and other fossil fuels, societies face many environmental quality challenges. During the last few decades, producers of coal-based electricity in North America, Europe, and parts of Asia have successfully responded to ever-more-stringent regulations to control emissions from coal plants (particulates, sulfur oxides, nitrogen oxides, and, more recently, mercury). Now, CO2 concentrations in the atmosphere that could result in global climate change pose a new challenge. As climate change effects have become more apparent, the need to limit anthropogenic emissions of CO2 and other GHGs has become a familiar topic among policymakers and the public.

1 Data Source: U.S. Department of Energy, Energy Information Administration, International Energy Outlook 2007.

Figure 1-1Electricity Generation by Fuel for Select Countries and Continents (2004, with Projectionsof Growth through 2020)1

50%

20%

18%

9%3%

USATotal generation: 3,975 TWh

17% electric demandgrowth by 2020

33%

29%

16%

19%3%

OECD EuropeTotal generation: 3,250 TWh


79%

2%1%

2%

ChinaTotal Generation: 2,080 TWh


RussiaTotal Generation: 881 TWh


IndiaTotal Generation: 631 TWh


Non-OECD Europe and EurasiaTotal Generation: 615 TWh


AfricaTotal Generation: 505 TWh

55% electric demandgrowth by 2020 Australia

Total Generation: 266 TWh23% electric demand

growth by 2020

44%

3%25%

18%10%

3%2%16%

69%

10%

20%

16%

43%

19%2%

2%7%

14% 2%

23%

20%32%

20%5%

74%0%8%

18% 0%CoalNuclearGasRenewables/HydroOther Central/South America

Total Generation: 882 TWh54% electric demand

growth by 2020

16%

75%


1-� Advanced Coal Power Systems with CO2 Capture: EPRI’s CoalFleet for Tomorrow Vision

Satisfying the Demand for Affordable Electricity while Reducing CO2 Emissions

The challenge of reducing GHG emissions—which likely will mandate substantial changes in the way we produce and consume power—comes at a time when significantly more electricity is needed to meet demand growth throughout the world cost-effectively.

By 2020, for example, the projected demand for electricity in the United States is approximately 17% higher than current levels (Figure 1-1); by 2030, it is projected to be as much as 30% higher.2 Meeting this increased demand using existing generation would cause a significant rise in CO2 emissions, increasing the risks associated with climate change. To reduce these risks, ways must be found to reduce the carbon intensity of the world’s economies while still promoting productivity and maintaining the benefits of affordable electricity.

Developing and deploying multiple GHG-reducing technologies is the best strategy for reducing risk. Termed the “full portfolio” by EPRI, it likely will include renewable energy resources, advanced light water reactor (ALWR) nuclear plants, distributed energy resources, PHEVs, and advanced coal power generation with CCS.

CCS refers to processes that separate CO2 from fuel or exhaust gases at industrial plants, which for the electric power sector is most notably coal-based plants, but also may include other fossil-fired plants. After separation, the captured CO2 can be compressed and stored in deep underground formations capable of holding it in place for hundreds to potentially millions of years. Known as geologic seques-tration, this approach for securely storing CO2 prevents its release into the atmosphere.

Lowering CO2 emissions through a portfolio of technologies is essential because no single technology has clear-cut advantages in all circumstances. This can be seen today in the regional variations around the world, where power producers employ differing generation strategies to match local resources, needs, and markets.

Projected Growth in Global Population and Electricity Consumption*

The world’s population is predicted to grow by 36%—from 6.1 to 8.3 billion people—from 2000 to 2030. The U.S. population also is forecast to grow over this period by an estimated 80 million people, or almost 30%.*

World net electric power generation is projected to increase from 14,426 billion kWh in 2000 to 30,364 billion kWh in 2030—an increase of more than 110%.** The aggregate demand growth in emerging economy (i.e., non-OECD***) countries is forecast to be nearly as great as current world electricity use.

* http://esa.un.org/unpp/** http://www.eia.doe.gov/oiaf/ieo/excel/figure_61data.xls*** Organization for Economic Cooperation and Development.

2 Based on projections by U.S. Department of Energy, Energy Information Administration, Annual Energy Outlook 2008.

3 Ibid.


1-�Advanced Coal Power Systems with CO2 Capture: EPRI’s CoalFleet for Tomorrow Vision

Modeling the Future: EPRI’s PRISM and MERGE Studies

To examine the technical feasibility and potential economic impact of achieving large-scale CO2 emissions reductions while meeting growth in U.S. electricity demand, EPRI developed two related analyses3:

PRISM analysis, which determined the technical potential for reducing CO2 emissions based on assumption of successful development and deployment of a full portfolio of advanced technologies.MERGE analysis, which modeled the economic value of deploying a full technology portfolio, and projected the least-cost combination of technologies needed to meet an economy-wide CO2 emissions reduction requirement.

The results of the PRISM study suggest that deployment of a full portfolio of advanced technologies can reduce U.S. electric sector CO2 emissions by 2030 to a level below 1990 emissions. This would be about 45% below the U.S. Energy Information Administration’s (EIA) revised 2008 “base case” projection for 2030, while meeting the projected increased demand for electricity. Figure 1-2 illustrates this result. The inset table lists the differences in technology performance and/or deployment levels between the EPRI and EIA base-case scenarios.

As shown in Figure 1-2, substantial CO2 emissions reductions require a balanced portfolio of technologies. CCS technologies applied to advanced coal-based power plants coming on-line after 2020 play a critical role in this portfolio.

■

■

Using the MERGE economic model, EPRI analyzed a CO2 emissions constraint representative of antici-pated reduction requirements described in major policy proposals. As shown in Figure 1-3, a limited portfolio scenario without advanced coal technologies and CCS (and without any expansion of nuclear power) results in wholesale electricity prices in 2050 of more than double the cost of a mix with the full portfolio of PRISM technologies. An additional result of the limited portfolio is a projected sharp rise

Figure 1-2EPRI’s PRISM Analysis Illustrates a Path to lowering u.S. Electricity-Related CO2 Emissions by 30% by 2030

0

500

1000

1500

2000

2500

3000

3500

1990 1995 2000 2005 2010 2015 2020 2025 2030

U.S

.Ele

ctric

Sect

orC

O2

Emis

sion

s (m

illio

nm

etric

tons

)

EIA Base Case 2008

130 GWe Plant Upgrades46% New Plant Efficiency

by 2020; 49% in 2030

No Existing Plant Upgrades40% New Plant Efficiency

by 2020–2030Advanced Coal Generation

5% of Baseload in 2030< 0.1% of Baseload in 2030DER

10% of New Vehicle Sales by 2017;+2%/yr ThereafterNonePHEV

Widely Deployed After 2020NoneCCS

64 GWe by 203020 GWe by 2030Nuclear Generation

100 GWe by 203060 GWe by 2030Renewables

Load Growth ~ +0.75%/yrLoad Growth ~ +1.2%/yrEfficiency

TargetEIA 2008 ReferenceTechnology

130 GWe Plant Upgrades46% New Plant Efficiency

by 2020; 49% in 2030

No Existing Plant Upgrades40% New Plant Efficiency

by 2020–2030Advanced Coal Generation

5% of Baseload in 2030< 0.1% of Baseload in 2030DER

10% of New Vehicle Sales by 2017;+2%/yr ThereafterNonePHEV

Widely Deployed After 2020NoneCCS

64 GWe by 203020 GWe by 2030Nuclear Generation

100 GWe by 203060 GWe by 2030Renewables

Load Growth ~ +0.75%/yrLoad Growth ~ +1.2%/yrEfficiency

TargetEIA 2008 ReferenceTechnology



EPRI’s findings indicate that even with aggressive development and deployment of alternative energy sources, coal-based electricity generation will remain an important part of the power portfolio, especially in rapidly expanding economies like those of China and India. EPRI’s PRISM and MERGE analyses highlight the urgent need to develop and deploy new energy technologies. Advanced coal technologies and CCS must be fully commercial by 2020 to meet the CO2 reductions for 2030 shown in Figure 1-2 and must begin to be widely deployed by 2020 to achieve the 2050 market penetration shown in Figure 1-3. If these technologies are not developed to commercial readiness in the next 10–12 years, their potential to help meet energy needs in a low-carbon future will be far less certain.

Independent Studies Corroborate EPRI Findings

An interdisciplinary study published in 2007 by the Massachusetts Institute of Technology examined the viability of coal power under scenarios in which mandated GHG reductions imposed an added cost on its use for power generation.5 The report concluded that despite cost premiums for GHG controls, coal

in natural gas prices (due to higher demand from the electric sector)—a double hit on households and businesses paying utility bills for both gas and electric service.

In the case with the full portfolio, the U.S. gross domestic product cumulatively is roughly $1 trillion larger over the period 2000–2050 (in present value terms measured in 2007 dollars) than in the limited portfolio case. A previous EPRI study based on “real options” principles (the technology equivalent of financial-market options contracts) produced a similar result.4

Although EPRI’s initial analyses focused solely on the United States, work currently under way on a global analysis is expected to show similar energy mix changes and significant economic impacts.

4 Market-Based Valuation of Coal Generation and Coal R&D in the U.S. Electric Sector, EPRI, Palo Alto, CA: 2002. 1006954.

5 The Future of Coal: Options for a Carbon-Constrained World, Massachusetts Institute of Technology, 2007.

Figure 1-3EPRI’s MERGE Analysis Shows the Value of Employing a Full Portfolio of CO2-Reductiontechnologies for the u.S. Electric Sector



would continue to play a “large and indispensable role” in supplying electric power for a growing world population. The report further identified CCS as “the critical enabling technology that would reduce CO2 emissions significantly while also allowing coal to meet the world’s pressing energy needs.”

The IEA also examined scenarios for the technical and economic potential of advanced coal technolo-gies and CCS to contribute to GHG reductions. It concluded, “a large abatement potential exists in the coming decades, notably by application of CCS.”6

Coal’s Role in Global Power Generation

Coal has played and continues to play a significant role in meeting global demand for energy services. Coal remains in wide use because it usually is a reliable and low-cost energy source, and because coal resources are abundant and broadly distributed geographically.

Many countries view their indigenous coal resources as an essential element of their plans for national economic development and security. Coal also is relatively easy to mine, ship, and store. These quali-ties make coal-fired power plants important electricity price stabilizers and reliable producers, espe-cially in electric systems using more price-volatile or intermittently available resources. If advanced coal technologies with CCS are not available, analysts suggest that pressure on natural gas supplies and prices may increase further.

Worldwide, the most significant rise in coal consumption is in the rapidly developing economies of China, India, and other Asian nations. Although forecasts vary, IEA has estimated that China alone will commission about 600 GW of new coal-fired generating units between 2006 and 2030, more than doubling its coal-fired capacity.7

Given the large investment in coal-based power plants around the world, analysts believe that many nations want to continue using coal for electricity generation for decades to come. Development and deployment of advanced coal technologies are crucial to fulfill the need for affordable energy while addressing environmental concerns.

RD&D to Prepare Coal Generation for a low-Carbon Future

Technically, it is possible to incorporate equipment to capture CO2 in all types of new coal-based power plants. Depending on available space and other considerations, such equipment also can be retrofitted to existing coal-fired plants.

The drawback to adding CO2 capture, beyond its added cost, is a reduction in plant output and efficiency. For this reason, research into less expensive, less energy-intensive, and more flexible capture technologies is the focus of major demonstration programs at EPRI and elsewhere.

CO2 capture and/or reduction is only part of the CCS picture. Important work is proceeding around the world to identify potential storage sites and capacities, verify predicted CO2 behavior in target geologic formations, minimize or eliminate environmental impacts, and assess the cost and performance of monitoring instruments. Yet there still are only a few large-volume CO2 storage demonstrations, and none to date involves integrated operation with a capture system at a power plant. Research organizations around the world point to such demonstrations as the crucial link to commercialization. In addition, geologic CO2 storage requires resolution of many legal and regulatory issues. Some analysts believe these issues may prove to be the biggest obstacle to overall CCS commercialization.

6 “Clean Coal Technologies for a Carbon-Constrained World,” Profiles, IEA Clean Coal Centre: July 2007. PF 07-05; http://www.iea-coal.org.uk/publishor/system/component_view.asp?LogDocId=81774&PhyDocID=6424

7 Drivers of New Generation Development—A Global Review, EPRI, Palo Alto, CA: 2008, Report 1014920.


1-6 Advanced Coal Power Systems with CO2 Capture: EPRI’s CoalFleet for Tomorrow Vision

RD&D also is needed to improve the thermodynamic efficiency of coal power plants as a way to reduce CO2 emissions. Increased thermodynamic efficiency reduces the amount of CO2 generated per unit of plant output (see Figure 1-4), meaning that plants that are more efficient can use smaller, less-expensive CO2 capture systems. Other emissions and equipment sizes are reduced as well. Materials development and testing to support higher efficiency designs is under way, to be followed by full-scale demonstrations.

Figure 1-4High-Efficiency Advanced Pulverized Coal Power Plants Substantially Reduce Fuel Costs and CO2 and Other Emissions8

8 Efficiencies shown are for pulverized coal plants, using the fuel’s higher heating value

(Bituminous coal, without CO2 capture)

20% reduction inCO2 correspondsto similarreductions (perMWh) in fuelconsumption,emissions, andwater use

9% Efficiency Gain = 20% CO2 Reduction

(Bituminous coal, without CO2 capture)

20% reduction inCO2 correspondsto similarreductions (perMWh) in fuelconsumption,emissions, andwater use

9% Efficiency Gain = 20% CO2 Reduction9% Efficiency Gain = 20% CO2 Reduction9% Efficiency Gain = 20% CO2 Reduction

Economic analyses show that the dual strategy of improving efficiency and improving CO2 capture system performance is the optimal path to competitive advanced coal power systems with CCS. In situ-ations where new, highly efficient coal plants are replacing older coal units, the emissions reduction benefit—even without the use of CO2 capture equipment—could be sufficient to meet near-term GHG emission reduction goals.

Ongoing RD&D for air quality control systems has improved the environmental performance of coal-based plants to the point that near-zero emission (NZE) levels for traditional coal pollutants now are seen as achievable (yet still to be demonstrated) targets. In addition, because several CO2 capture technologies require inlet flue gas with extremely low levels of SO2 and NOX, the need for technologies that reach NZE levels has become linked to commercializing post-combustion CO2 capture processes.

The Promise of Advanced Coal Power Systems


2-�

2 ThE PROmISE Of AdVAnCEd COAl POwER SySTEmS

T he power industry has progressively improved power plant designs to meet increasingly stringent limits for air pollution. New coal plants today are cleaner and more efficient than plants built in the

past (see Table 2-1).

Table 2-1Progression of Coal Power Technology development in the United States*

year 1921 2008Net Output, MW 40 750

Efficiency, % HHV 24 38

Main Steam Temperature, °F (°C) 611 (322) 1050 (565)

Main Steam Pressure, psia (bara) 315 (21.6) 3515 (242)

SO2, lb/MWh (kg/MWh) 83.6 (37.9) 1.1 (0.5)

NOX, lb/MWh (kg/MWh) 9.1 (4.1) 0.6 (0.27)

CO2, lb/MWh (kg/MWh) 2850 (1290) 1840 (834)*Values for Illinois #6 Coal with heating Value 11,000 Btu/lb (25,500 kJ/kg) and 3.2% Sulfur

However, the CO2 challenge is bigger than that of other air emissions because it is a primary product of combustion, not the product of side reactions involving coal’s minor constituents. Thus, the quantities of CO2 to be removed dwarf those of SO2 and NOX. Similarly, the cost of CO2 removal using today’s technologies far exceeds that of other air emissions.

Technologies that can potentially bring down the cost of CO2 capture already are being investigated at pilot scale. Many more are being tested in research laboratories around the world. Specifically:

Three primary approaches to CO2 capture are being considered, with competing technology developers leading the commercialization effort

Pre-combustion capture technologies are applied to pressurized synthesis gas, prior to combustion in the gas turbine of an IGCC unitPost-combustion capture technologies are used to absorb CO2 from flue gas, at atmo-spheric pressure, from coal-fired boilers using PC, CFBC, and other types of combus-tion systemsOxy-combustion technologies, applied to new or modified combustion power boilers, eliminate most of the nitrogen in air prior to combustion, thereby allowing direct compression of flue gas following any final purification steps.

Some of these processes already are used in other industries, albeit at smaller scale than is needed for power plants. This experience reduces the lead time and risk for scale-up. In addition, many researchers and entrepreneurs are working on novel CO2 capture technologies, raising the potential for new breakthroughs.

Geologic injection of CO2 for enhanced oil recovery (EOR) has been a commercial practice for 35 years. Traditional approaches now are being modified to maximize the amount of CO2 left securely in the ground at the conclusion of injection operations. Researchers also now are investigating the viability of injection of CO2 into porous saline formations, which are much more prevalent than depleted hydrocarbon reservoirs.

■

–

–

–

■



New alloys with high nickel and chromium content, similar to those used in jet engines and oil refineries, are being tested in gas turbines, steam turbines, and coal-fired boilers to enable a new generation of more efficient power plants. Just like energy-efficient cars and buildings, highly efficient power plants consume less fuel per unit of output, take up less space, and reduce environmental impacts, including GHG emissions.

EPRI and the Coal Utilization Research Council (CURC) have formulated a “roadmap” for developing the technologies needed to affordably accomplish the environmental and electricity goals in EPRI’s PRISM and MERGE analyses. This plan identifies and sequences the necessary RD&D activities at the component, integrated system, and power plant levels for coal power technologies. Critical links between development efforts also have been identified.

Building a Portfolio of Competitive Advanced Coal Technology Options

To realize the benefits of competition, and to accommodate the cost and performance risks of any one technology, the power industry will require multiple, competing technologies. In addition, because fuel properties are a major driver in designing coal-based power plants, different technologies often are needed when different coals are used (in contrast to natural gas and nuclear plants, where fuel homogeneity allows for greater standardization).

EPRI’s work has shown that no single advanced coal technology holds clear-cut advantages across the full range of coal types and operating environments. Because technologies do not remain static over time, each undergoing modification and improvement through operating experience and supporting research programs, their relative strengths and weaknesses do not remain constant. Thus, attempting to pick “winners” and focusing all investments on these select technologies is not the best strategy for meeting future electricity needs. To address environmental concerns with minimal economic impact, the best strategy lies in developing a robust portfolio of technologies from which power producers (and regulators) can select the options most suited to preferred coal types, local conditions, and compliance needs. Table 2-2 describes the fundamental types of advanced coal “power block” technologies in commercial application or development. For pulverized coal and circulating fluidized bed boilers, oxygen-firing (“oxy-combustion”) versions producing high purity CO2 exhaust streams are also are in development (see Table 2-4).

■



COmBUSTIOn TEChnOlOGIES

Pulverized Coal (PC): Traditional coal plants in which coal is ground to the consistency of flour in a pulverizer and blown into a boiler for rapid combustion to create superheated steam, which a steam turbine uses to generate power. PC plants can be categorized into two types (subcritical and supercritical), based on the thermodynamic state of steam entering the first turbine. In the higher-efficiency supercritical type, two subdesignations are used:

Supercritical Pulverized Coal (SCPC): SCPC is a fully commerical technology. Plants typically employ a “main steam” (i.e., high-pressure turbine inlet) with a temperature of 1050–1100°F (565–595°C). The “reheat steam” (i.e., intermediate-pressure turbine inlet) temperature usually is the same as, or slightly higher than, the main steam temperature. For coals with high sulfur and/or chlorine content, these steam temperatures may require use of newer steels with high corrosion resistance.Ultra-Supercritical Pulverized Coal (USC PC): Defined to mean plants with a main steam temperature greater than 1100°F (595°C), these highly efficient plants have been built commer-cially in Europe and Asia, but not in North America (except for Philadelphia Electric’s novel Eddystone Unit 1 from 1960). A major gain in efficiency will come from “advanced” USC conditions (main steam up to 1400°F or 760°C), which will require development and qualification of new nickel-based alloys with improved high-temperature strength and creep and corrosion resistance.

Circulating fluidized Bed Combustion (CfBC): This type of plant combusts coal and other solid fuels in a bed of hot sorbent particles suspended in motion (fluidized) by combustion air. The chief benefit of CFBC technology is its fuel flexibility; almost any combustible material, including biomass and municipal waste, can be readily burned. At present, only the subcritical design is commercially available, although a supercritical unit is under construction.1

GASIfICATIOn TEChnOlOGIES

Integrated Gasification Combined Cycle (IGCC): Although not widely deployed, the experience base for IGCC technology is sufficient to qualify these plants for nascent commercial status. An IGCC plant consists of a gasifier to convert coal to a fuel gas (“syngas”), which is cleaned up in a series of chemical processing stages. A gas turbine burns the cleaned syngas followed by a steam turbine heat recovery unit that transfers heat from the hot flue gas to raise steam. There are a variety of gasifier designs and manufacturers, each offering certain advantages, most of which use oxygen to convert the coal to syngas. The gas turbines are slightly modified versions of those used to burn natural gas.

Table 2Advanced Coal Power Block Technologies

1 The first supercritical CFBC plant is now under construction in Poland: http://www.power-technology.com/proj-ects/lagisza/

2 Although there is no precise definition of NZE, EPRI target values for coal-based plants are SO2 and NOX levels of ~0.01 lb/MBtu (10 mg/Nm³), SO3 levels less than 1 ppm, filterable particulate levels of ~0.002 lb/MBtu (2 mg/Nm³), and mercury levels less than ~ 0.01 ppb (0.1 µg/Nm³). Actual values achieved may vary depending upon the coal being used.

Emission control technologies for both gasification- and combustion-based power plants have been highly effective in reducing air emissions. Typical devices used for controlling emissions of standard pollutants and mercury are listed in Table 2-3, along with representative values for reductions that may be specified in permits or have been observed across a range of real-world operating conditions. Further refinement of today’s emission control technologies, and in some cases introduction of secondary “polishing” emission control devices, should enable the industry to introduce coal-based plants with NZE.2



nOX (nitrogen oxides): Low-NOX burners with overfire air (for boilers) or combustors with water or nitrogen injection (for gas turbines) limit maximum flame temperatures and oxygen availability in the flame core to reduce NOX formation by up to 35–55% for boilers and 70–90% for gas turbines (relative to conventional equipment). Downstream selective catalytic reduction (SCR) systems flow flue gas through a catalyst bed, along with a reagent (typically ammonia) to reduce NOX chemically to molecular nitrogen and water, reducing inlet NOX emissions by up to an additional 85–90% or more. These technology combinations yield a net overall reduction in NOX of 90–95% for boilers and 95–99% for gas turbines, respectively.

SO2 and h2S (sulfur dioxide and hydrogen sulfide): For boilers, flue gas desulfurization (FGD) systems or “scrubbers” use injected agents either as a slurry/solution or in solid form (typically finely ground limestone, lime, or sodium compounds) to react with flue gas SO2, reducing emissions by 95–98% or more. In IGCC plants, where SO2 is not an issue, the sulfur species of concern predominantly is H2S. Regenerable solvents with engineered chemical and physical properties are used to remove H2S and other “acid gas” species from the synthesis gas prior to combustion. Such processes are very effective, often removing 99.5% or more of the H2S.

Pm (particulate matter): For boiler flue gases, electrostatic precipitators (ESP), which use a series of electrically charged collector plates, or baghouses, can reduce solid particulate emissions to less than 0.015 lb/MBtu of heat input to the boiler (~15 mg/Nm3), a reduction of more than 99%. In IGCC plants, particles are removed from syngas prior to combustion either by using water scrubbing or dry filters.

hg (mercury): Newer than other emission controls, and thus less certain in terms of long-term performance, injection of activated carbon or other additives in boiler flue gases appears capable of reducing mercury emissions by up to 90%. For boilers using some coal types, modifications to the SCR and scrubber can remove large fractions of mercury without additive injection. In IGCC units, activated carbon “beds” can remove 95% or more of the mercury from syngas prior to combustion.

Table 2-3Typical Control Technologies for Air Emissions from Coal Power Plants

The use of dedicated systems to capture CO2 from electric power plants is a relatively new concept that has evolved only over the last decade, along with the understanding of the effect of atmospheric buildup of CO2 from industrialization. Historically, CO2 separation only has been practiced in indus-trial coal gasification plants. This is why, today, “pre-combustion” CO2 capture from IGCC plants is a more mature technology than “post-combustion” or “oxy-combustion” capture options for PC or CFBC plants. Table 2-4 describes these basic types of CO2 capture systems for coal-based power plants and their development status.



Coal Properties drive Generation Technology Selection and Plant design

Fuel properties factor significantly in the selection of coal-based generating technologies. In the United States, coal is ranked using a system established by the American Society for Testing and Materials (ASTM D 388). Coal rank generally correlates with the age of the coal, ranging from oldest to youngest (or from “high” to “low” rank) in the following order:

Class I: Anthracitic: >15,000 Btu/lb (>35 MJ/kg)Class II: Bituminous: 10,500-15,000 Btu/lb (24–35 MJ/kg)Class III: Subbituminous (including Powder River Basin coals): 8000–13,000 Btu/lb (19–30 MJ/kg)Class IV: Lignitic (“brown coal”): 4000–8000 Btu/lb (9–19 MJ/kg).

As indicated, the heating value of coal generally decreases with decreasing rank, while moisture and ash (non-combustible mineral content) increase. (Note: Anthracitic coals are relatively uncommon, are harder to grind, and may have too little volatile matter for pulverized coal combustion. They seldom are used in power generation).

The heating value of the coal determines the quantity of fuel needed for a given electrical energy output. As a result, lower-rank coals require higher volumes and larger boilers for a given MW rating than do bituminous coals. This also can result in increased capital and maintenance costs for plant processes such as coal and ash handling and emissions control. High-sulfur coals require additional consideration because of the corrosive nature of sulfur and the need to integrate sulfur emissions controls into plant design.

■

■

■

■

Pre-Combustion CO2 Capture: Applicable to IGCC plants, pre-combustion capture involves an additional chemical process unit to cause carbon monoxide (CO) present in the synthesis gas to react with steam to form CO2 and hydrogen, allowing for CO2 separation via a separate physical-solvent-based “extraction and stripping” process. The gas turbine then has to be designed to burn hydrogen, not a combination of CO and hydrogen. The individual processes involved in pre-combustion capture are commercially available, but their integration with an IGCC power plant has yet to be demonstrated.

Post-Combustion CO2 Capture: Best suited for combustion-based plants, post-combustion capture passes the flue gas through an absorber where a chemical solvent selectively removes the CO2. The CO2-laden solvent passes to a stripper where it is heated to release a nearly pure CO2 stream while the “lean” solvent is recycled back to the absorber to capture more CO2. Amines and ammonia are among the candidate solvents now being developed for use with coal-fired boilers. There is some small-scale commercial experience, but post-combustion technology still has to be scaled up and integrated with a utility-size boiler.

Oxy-Combustion CO2 Capture: Oxy-combustion boilers burn coal in oxygen rather than air, greatly reducing the nitrogen content of the flue gas and thereby increasing its CO2 content. This eases the task of CO2 separation, although some purification of the flue gas still is required. To keep flame temperatures manageable and use near-conventional boiler designs and materials, a fraction of the CO2-rich exhaust gas is recycled back to the boiler. Oxy-combustion is an emerging tech-nology, with the largest pilot unit currently at about 12-MW equivalent. Developers have announced plans to demonstrate units at 50 MW scale, but these will not be built for several years.

Table 2-4CO2 Capture Technologies for Advanced Coal Power Plants



Where fuel flexibility is important or where lower-grade fuels (e.g., recovered coal fines) will be burned, CFBC may be selected because of this technology’s ability to accommodate a wide range of fuels. Other factors that may influence technology choice include the availability of water and, where IGCC is concerned, site elevation, because less dense air at high altitudes reduces the gas turbine’s maximum power output.

Although it has been reported that IGCC with CO2 capture holds an economic advantage for low-moisture bituminous coals, studies by EPRI3 and the Canadian Clean Power Coalition4 show that PC plants with post-combustion CO2 capture are competitive for subbituminous and lignite coals (which have high moisture content and relatively lower heating value). These studies underscore the need for multiple technologies, as no single advanced coal generating technology will be preferable for all coal types.

Cost analyses can determine which technology will deliver the lowest levelized cost of electricity (COE) for a given fuel under the operating conditions of a specific location. Once the generation technology is selected, the unit can be specifically designed for a range of fuels (referred to as the design feed or design coal). For example, ash removal and handling systems must be sized for the highest ash content that will be encountered, while other components may be designed and critically sized for the highest sulfur content that will be encountered.5 The furnace size for PC plants needs to be increased for lower-rank coals or coal with higher slagging potential. Thus, design decisions depend on knowledge of the extremes to which the equipment will be subjected by the design feed.

Using fuels outside the range of specifications for the design feed can adversely affect the operation of the unit, which may exceed emissions limits, lose generating capacity, and experience more forced outages.

The Importance of Early deployment of Advanced Coal Technologies

The typical path for commercializing a technology moves from the conceptual stage to laboratory testing, then to pilot-scale tests, larger-scale tests, full-scale demonstration, and finally to deployment of multiple systems in full-scale commercial operation. For capital-intensive technologies such as advanced coal power systems, each stage can take several years or more to complete and entails increasing levels of investment.

As depicted in figure 2-1, some advanced coal power technologies are relatively mature, but many only are in the development phase. Technologies are particularly vulnerable during this period because the projected costs often are higher than earlier estimates, assembled when less was known about the scale-up and application challenges. To maintain momentum during this critical phase, it is essential that there is clear a path to cost reduction.

The historical record of technology development shows that costs, which are highest at the start of the demonstration phase, begin to fall due to:

Experience gained from “learning by doing”Increasing economies of scale in design and production as order volumes riseRemoval of contingencies covering uncertainties and first-of-a-kind costs Competition from second- and third-to-market suppliers.

■

■

■

■

3 Feasibility Study for an Integrated Gasification Combined Cycle Facility at a Texas Site, EPRI Palo Alto, CA: October 2006. 1014510.

4 Summary Report on the Phase I Feasibility Studies Conducted by the Canadian Clean Power Coalition, Canadian Clean Power Coalition, May 2004.

5 CoalFleet User Design Basis Specification for Coal-Based Integrated Gasification Combined Cycle (IGCC) Power Plants, Version 7, EPRI, Palo Alto, CA: June 2008. 1015684.



An IEA study conducted by Carnegie Mellon University and others observed this pattern for power plant emission controls. The research team predicted a similar reduction in the cost of CO2 capture technologies as their cumulative installed capacity grows.6 RD&D of specifically targeted technology refinements can lead to greater cost reductions in the deployment phase. Once a technology reaches maturity, its costs often are relatively close to those originally projected.

6 “Estimating Future Trends in the Cost of CO2 Capture Technologies,” IEA Greenhouse Gas R&D Programme (IEA GHG): February 2006/5, January. Report 2006/6.

figure 2-1development Status of major Advanced Coal and CO2 Capture and Storage Technologies

Of the coal-based power and carbon storage technologies shown in Figure 2-1, only SCPC technology has reached commercial maturity. If all of these technologies in the portfolio can reach the stage of declining costs before being widely deployed, the cost of implementing CO2 controls on the economy will be much lower.

All advanced coal technologies with CCS will require techniques for secure, long-term CO2 storage at large scale and associated measurement, monitoring, and verification technologies. Oil-field EOR operations offer considerable commercial experience with CO2 injection that can aid our understanding of long-term CO2 storage issues. However, these projects historically have been designed to maximize oil recovery while consuming as little CO2 as possible, so modifications to traditional operating practices will be required.

Research Development Demonstration Deployment Mature Technology

Oxy-com-bustion

CO2 Storage

CO2 Capture

IGCC Plants

USC PC Plants

SCPC Plants

1150°F(620°C)

1100°F(595°C)

~1100°F (~595°C)1050°F(565°C)

Advanced USC PC Plants1150°F+ (620°C+)1400°F (760°C)

Post-combustion

Pre-combustion

CO2-EOR

Research Development Demonstration Deployment Mature Technology

Oxy-com-bustion

CO2 Storage

CO2 Capture

IGCC Plants

USC PC Plants

SCPC Plants

1150°F(620°C)

1100°F(595°C)

~1100°F (~595°C)1050°F(565°C)

Advanced USC PC Plants1150°F+ (620°C+)1400°F (760°C)

Post-combustion

Pre-combustion

CO2-EOR

Note: Temperatures shown for pulverized coal technologies are turbine inlet steam temperatures.

An

tici

pat

edC

ost

of

Fu

ll-S

cale

Ap

plic

atio

n

2008

Combustion-Based Systems – Extending the limits of a Mature Technology


3-�

3 COMBUSTION-BASED SYSTEMS – EXTENDING THE LIMITS OF A MATURE TECHNOLOGY

T here are two major coal-fired technologies used for power generation—pulverized coal, the major provider, and circulating fluidized-bed combustion.

Figure 3-1Photo of MidAmerican’s Walter Scott, Jr. Energy Center Unit 4 SCPC Plant 1

1 Brian Mundt, “Walter Scott Energy Center Unit 4,” presentation at EPRI CoalFleet for Tomorrow General (Technical) Meeting, Tulsa, Oklahoma, April 15, 2008.

Key Points

PC plants are the predominant form of combustion-based coal-fired power generation throughout the world and have improved significantly since their inceptionCFBC plants are less common, but are another form of combustion-based coal powerAdvances in materials allow higher steam temperatures, which improve efficiency and reduce CO2 productionHigh levels of CO2 capture from a PC or CFBC unit require post-combustion CCS using a chemical solvent, typically aminesPost-combustion CCS requires near-zero inlet levels of emissions, which may be achievable with current emission controlsOxy-combustion is an alternative process that uses oxygen to combust coal and produces flue gas rich in CO2.

Pulverized Coal

Commercial StatusPulverized coal combustion has been the prevailing mode of firing coal in power plants worldwide for more than 75 years and provides the backbone of electricity generating systems in many countries. In the U.S., there is about 300,000 MW of installed PC generating capacity.

■

■

■

■

■

■



There are approximately 300 supercritical and ultra-supercritical units in the world. During the 10-year period from the mid-1990s to the mid-2000s, Japan and South Korea dominated the new plant market, while China began to show signs of rapid growth. In the U.S., MidAmerican’s 790-MW Walter Scott, Jr. Energy Center (formerly Council Bluffs) Unit 4 became the first supercritical unit to be built in the U.S. in 20 years. About 9 GW of coal-fired SCPC generation is under construction in the United States in 2008.

Environmental Controls – The Promise of Near-Zero EmissionsEmissions from PC power plants have progressively fallen over the past few decades and permits now are at levels previously thought unachievable. To meet current emission control targets, PC power plants today can use different processes for the main criteria pollutants. The most commonly used processes are:

SO2 removal with wet or dry flue FGDNOX control using low-NOX burners with or without the addition of SCRParticulate control with an ESP or fabric filters (“baghouse”).

Factors that influence the selection of emission control technologies include coal type, site location and conditions, plant size, emissions limits, consideration of mercury and sulfuric acid controls, and sale or disposal of solid combustion products.

Progress in lowering emissions levels is expected to continue in response to the demand for near-zero emissions. At present, the ultra-low levels proposed for NZE are targets for ongoing research programs. Some of these are focused on extending the limits of current emission control technologies, while others seek to develop new sorbents and even new technologies that show promise in meeting NZE targets. These include multi-pollutant control technologies that remove all pollutants of interest in a single train at potentially lower cost.

Additional equipment, maintenance and operating costs, and consumption of energy required by emis-sions control technologies all affect the plant’s net efficiency and levelized COE.2 Finding ways to lower capital and operating costs and limit parasitic energy losses is critical to realizing lower emissions while keeping electricity from coal-fired plants affordable.

SO2 Removal with Flue Gas DesulfurizationSO2 removal efficiencies of 95–97% were the norm in the early 2000s. Current wet FGD systems are being ordered with guarantee requirements of 98% SO2 removal efficiency. Because of its higher removal efficiency, wet FGD typically is used for high- to medium-sulfur coals. Dry FGD typically is used only for low- and medium-sulfur coals (usually below ~2%).

The wet FGD process uses alkaline slurry to contact the flue gas in an absorber vessel and remove the SO2 through absorption and chemical reaction. The reagents used include limestone, lime, enhanced lime, ammonia, magnesium oxide, and sodium carbonate.

■

■

■

2 Levelized COE is the net present value of all costs associated with a plant over its economic life divided by the total generation in megawatt hours (MWh) over that period. This term, frequently expressed as $/MWh, has the virtue of being a single numeric representation of the complex cash flows associated with construction capital, financing, taxes, fixed and variable O&M, and purchase of commodities such as coal and emission allowances required to operate the plant.


3-3Advanced Coal Power Systems with CO2 Capture: EPRI’s CoalFleet for Tomorrow Vision

High capital costs, plot plan requirements, and balance-of-plant impacts for wet FGD typically are balanced by increased SO2 control efficiency, reduced reagent costs, increased reagent utilization efficiency, and increased salability of fly ash and FGD by-products, which reduces disposal costs. Wet FGD systems become increasingly cost-effective as system size and flue gas sulfur content increase.

Dry FGD technology injects an alkaline reagent into the flue gas, where it absorbs and reacts with the SO2. The reagent may be injected as a dry powder or mixed in a slurry, from which the water is then evaporated. Solids from the process are collected in a particulate control device (ESP or fabric filter).

Lower capital costs, a smaller footprint, and lower water use are the benefits of dry FGD. However, because dry FGD systems require reagents that are more expensive and use them less efficiently, they become less cost-effective, compared with wet FGD technology, as flue gas flow rate, SO2 concentra-tion, and/or required removal efficiency increases.

The 2006 EPRI/CURC Technology Roadmap projects technological potential to reduce SO2 emissions from 2005 levels of 0.08 lb/MBtu of fuel input (~80 mg/Nm3) to NZE levels of 0.01 lb/MBtu (~10 mg/Nm3) by 2025. Achieving this low of an SO2 emission level on a consistent basis for power plant applications remains to be demonstrated. Improvements to current SO2 removal processes that will help realize NZE levels include:

More sophisticated monitoring and control of moisture, temperature, and reagent levelsAdvanced flow analysis techniques to ensure that gas/liquid contact is uniform and sufficient throughout the absorber vessel, and to minimize pressure drops and the resulting auxiliary power demandsFine-tuning of reagents through more precise purchase specifications, carefully designed additive packages, and adaptation for optimized co-capture performanceRedundancy in sprays and pumps to achieve required availability.

Dual Strategies for NOX ControlMost NOX is formed during combustion from fuel nitrogen (fuel NOX), and some results from oxidation of a small amount of the nitrogen contained in the combustion air (thermal NOX). The production of fuel NOX depends on the amount of oxygen available, while thermal NOX, as the name implies, is highly dependent on temperature.

In-furnace NOX control technologies can achieve significant reductions by properly staging combustion to control temperature and oxygen levels. The goal is to have the fuel nitrogen released in a zone of low oxygen to reduce fuel NOX, and then complete combustion in a zone of higher oxygen to reduce temperatures and minimize thermal NOX. Low-NOX burners are designed to control airflow to achieve proper zones of fuel-air ratios and facilitate mixing. Staging typically is completed in the boiler itself, in which the lower section is fuel-rich and the upper section is made air-rich by the addition of overfire air.

Post-combustion NOX control technologies remove a significant amount of the remaining NOX through chemical reduction. SCR uses an ammonia or urea reagent, injected upstream of a catalyst (materials used include vanadium, molybdenum, and tungsten) to chemically reduce NOX to molecular nitrogen and water.

The NOX emissions limits for coal-fired PC plants currently are as low as 0.05–0.07 lb/MBtu (~50–70 mg/Nm3), using a combination of low-NOX burners and SCR.3

■

■

■

■

3 Status and Performance of Recently Permitted BACT/LAER Plants, EPRI, Palo Alto, CA: 2006. 1013346.



Achieving NZE NOX levels of 0.01 lb/MBtu (~10 mg/Nm3) will require the resolution of operational issues, along with technological advancements in both in-furnace and post-combustion NOX controls. For units firing high-sulfur bituminous fuels, NZE for NOX may only be achievable in new boilers designed specifically for low-NOX emissions. Again, achieving this consistent low-NOX emission level for power plant applications remains to be demonstrated.

Technologies for Particulate ControlElectrostatic precipitators or baghouses installed on coal-fired boilers for particulate control typically can meet the particulate emissions limits commonly required of coal-fired power plants, which are as low as 0.012 lb/MBtu (~12 mg/Nm3).

ESP control devices exploit the electrical properties of small particles to collect them on metal surfaces. An electrical charge (generally negative) is imparted to the particles by establishing a corona current in the ESP. An established electric field then forces the charged particles to a grounded collection surface. The metal surfaces periodically are rapped to loosen the particles, which fall into collection hoppers.

When a fabric filter is used, the particle-laden flue gas passes through the filter and the particles are caught on the fabric and do not pass through with the flue gas. In practice, a dust layer of accumulated particulate supported by the fabric and not the fabric itself collects the bulk of the particulate. The dust layer is removed periodically to keep the pressure drop across the filter within acceptable limits.

The NZE particulate target suggested by several organizations is 0.002 to 0.010 lb/MBtu (~2 to 10 mg/Nm3).4 It is likely that with improvements an ESP or a baghouse, or a combination of the two, can achieve these levels.

Reducing Mercury EmissionsU.S. mercury regulations for coal-fired power plants still are evolving. If allowable, the primary control strategy for existing plants likely will be to employ co-capture of mercury in FGD and particulate capture systems. New plants may be required to install additional mercury capture such as activated carbon injection (ACI). In ACI technology, powdered activated carbon (PAC) sorbent is injected into the flue gas at a location in the duct preceding the ESP or a baghouse. The PAC sorbent binds with the mercury in the flue gas and is captured in the ESP or baghouse.

Since the mid-1990s, DOE NETL has spearheaded RD&D into the formation and capture of mercury from coal-fired power plants, including ways to enhance ACI and FGD-related processes.5 The program seeks to develop a suite of control options to allow for cost-effective compliance with mercury regulations. Twelve projects were selected in 2006 that will focus on field testing of technologies capable of at least 90% mercury capture.

Reducing CO2 Emissions Through Increased Efficiency and Improved CO2 Capture ProcessesA major thrust in advancing PC technology consists of increasing the operating temperatures and pressures of the steam cycle, which results in greater efficiencies, decreased fuel consumption, and lower emissions levels. A 2% gain in efficiency, for example, provides a reduction in fuel consumption of roughly 5% and can provide similar reductions in pollutants and CO2.

4 Technologies to Achieve Near-Zero Emissions Goals: Concepts and Technical Challenges, EPRI, Palo Alto, CA: 2006. 1010335.

5 http://www.netl.doe.gov/technologies/coalpower/ewr/mercury/index.html



Worldwide, operating ratings for supercritical units range from 200–1300 MW. The increased pressures and temperatures provide significant efficiency improvements over subcritical units with comparable availability.

Ultra-supercritical steam parameters of 4350 psi and 1112°F (300 bar and 600°C) are in operation today with generating efficiencies of 42% (HHV).6 There are several years of experience with these plants in Europe and Japan, with excellent availability, and plans have been announced for several USC PC plants in the United States.

Significant CO2 reductions can be achieved through efficiency gains, but further reductions in CO2 emissions will require CCS. However, adding capture processes to new plants and retrofits currently imposes large net power reductions and efficiency (operating cost) penalties, because part of the plant’s power must be used for CO2 capture. Extensive RD&D is under way to improve both post-combustion capture and oxy-combustion processes. It should be noted that as a consequence of incorporating CCS, plants also would achieve NZE.

Steps and Timeframe for USC PC Cost Reduction and Efficiency GainsEPRI’s CoalFleet for Tomorrow research program addresses the gaps in RD&D identified for USC PC plants with CO2 capture by supporting the development of promising emerging technologies. Figure 3-2 depicts the anticipated timeframe for achieving efficiency gains through higher operating parameters and through improvements in CO2 capture technologies that will result in lower energy penalties.

6 Efficiencies as high as 44% have been achieved when additional reheat and cold condenser temperatures are used. However, these efficiencies may not be available in most parts of the United States, where expected efficiency for such steam conditions would be about 40% HHV.

Figure 3-2RD&D Path for USC PC Power Plants with 90% CO2 Capture (Upturning Arrows Refer to Right Axis and Downturning Arrows to the Left Axis)

2005 2010 2015 2020 2025

Near Mid-Term• Upgradesteam

conditions to1110 F (600 C) MS1150 F (620 C) RH

Mid-Term• Upgradesteam conditions

to 1300 F (700 C) MS &RH, then 1400 F(760 C) MS &Double RH

30

32

34

36

38

40

Plan

tNet

Effic

ienc

y(H

HV

Bas

is)

Near-Term• Upgradesolvent from MEAto

MHI KS-1 (or equivalent)• Upgradesteam conditions

from 1050 F (565°C) MS& RH to 1100°F (595°C)MS & RH

Long-Term• Upgradesolvent

to <10% energypenalty and <20%COE penalty

1.1

0.6

0.7

0.8

0.9

1.0

1.2

1.3

42

44

Tota

lPla

ntC

ost(

$/kW

,con

stan

tdol

lars

norm

aliz

edto

2005

plan

tcos

t)



In addition, EPRI’s CoalFleet for Tomorrow research program has produced a Guideline for Advanced Pulverized Coal Power Plants,7 a comprehensive overview of state-of-the art and emerging technologies. The guideline helps expedite technology selection, permitting, and design processes for advanced pulverized coal plants, offering insights into key areas of plant operations, technology updates, and lessons learned that should be addressed by engineers developing PC plant specifications.

Advanced Materials – The Key to PC Efficiency GainsMore corrosion-resistant materials to allow for higher steam conditions is the main enabling technology needed for construction of coal-fired boilers and turbines with higher efficiencies.

Ferritic/Martensitic SteelsDuring the last two decades, research on advanced materials to withstand higher steam conditions has focused on cost-effective, high-strength ferritic-martensitic steels with crystal lattice structure in the base metal and a very hard surface structure. These improved steels are capable of operating at metal temperatures up to 1150°F (620°C), have good weldability, and fracture toughness. Researchers are working to push this limit towards 1200°F (650°C).

Austenitic Stainless SteelsThe next class of steels that has the necessary creep strength and corrosion resistance is known as the austenitic stainless steels. These steels contain a higher percentage of nickel, and chromium well in excess of 18%. Those with more than 22% chromium are the best candidates for use with highly corrosive coals. The limiting temperature for austenitic steels is about 1250–1275°F (675–690°C). Austenitic stainless steels have a higher coefficient of expansion than ferritic steels, making weld joints with ferritic steels particularly challenging.

Nickel-Based AlloysHigh-nickel-content alloys have better strength and corrosion resistance than stainless steels at very high temperatures, but are considerably more expensive and more difficult to weld. Nonetheless, researchers are working to qualify nickel-based alloys for use in high-temperature boiler and steam turbine components. Ultimately, these materials are expected to enable steam temperatures of up to 1400°F (760°C), which would allow generating efficiencies to climb to 47% (HHV basis with bituminous coal; slightly less for higher-moisture coals). This approximately 10% improvement over the efficiency of a new conventional subcritical PC plant would equate to a decrease in CO2 and other emissions of about 25% per MWh.

Advanced Materials Research8 In the United States, the challenge of developing and testing new materials has been taken up by DOE’s (Fossil Energy) Advanced Materials Research program, which consists of multiple subprograms involving laboratories, universities, and non-profit organizations. One subprogram, “Evaluating Materials Technology for Ultra-supercritical Coal-Fired Plants,” is dedicated to identifying, evaluating, and qualify-ing materials for construction of coal-fired boilers and turbines with advanced steam cycles. This activity is co-funded by the Ohio Coal Development Office and is managed and coordinated by EPRI, with the participation of several boiler and turbine manufacturers.

7 CoalFleet Guideline for Advanced Pulverized Coal Power Plants, Version 3, EPRI, Palo Alto, CA: March 2008. 1014226.

8 http://www.fossil.energy.gov/programs/powersystems/advresearch/advresearch-materials.html



Phase I of the program includes work to identify, fabricate, and test advanced materials and coatings with mechanical properties, oxidation resistance, and fireside corrosion resistance suitable for cost-competitive boiler operation at steam temperatures up to 1400°F/5500 psi (760°C/380 bar). These USC PC plants are anticipated to become commercially available by about 2015. In addition, materials issues that affect boiler design and operation at temperatures as high as 1600°F (870°C)9 are being explored. Phase II of the program involves optimizing the designs of Phase I and conducting further field evaluations, as well as extending the studies to define the conditions for oxy-fuel-fired boilers and how these affect materials degradation.

A similar European program is establishing materials and designs for a plant with steam temperatures of 1290°F (700°C). Work has progressed to the point where large panels of advanced material compo-nents are being tested in an in-service boiler (E.ON Energie’s Scholven plant) equipped with a separate steam circuit to simulate the advanced USC PC temperature environment (this facility is known as “ComTes-700”). The program envisions constructing a showcase USC PC unit (~400 MW) to demonstrate these steam conditions. E.ON Energie also has announced its intention to build an ~450-MW USC PC unit at about 1290°F (700°C).

Post-Combustion Removal of CO2 from Flue GasesMost post-combustion CO2 capture processes envisioned for power plant boilers draw upon commer-cial experience with absorption and separation using amine solvents. This currently is done at a much smaller scale (up to 20-MW equivalent) in the food and beverage and chemical industries, and in three applications of CO2 capture from slipstreams of exhaust gas at CFBC units.

These processes contact flue gas with an amine solvent in an absorber column where the CO2 chemi-cally reacts with the solvent. The CO2-rich liquid mixture passes to a stripper column where it is heated, releasing the CO2, and the “regenerated” solvent is re-circulated back to the absorber column. The released CO2 may be processed further before compression to a supercritical state for efficient trans-portation to a storage location.10

After drying, the CO2 released from the regenerator is relatively pure. However, successful CO2 removal requires very low levels of SO2 and NOX in the flue gas entering the CO2 absorber, as these species also react with the solvent. Thus, high-efficiency SO2 and NOX control systems are essential to minimizing solvent consumption costs for post-combustion CO2 capture.

The addition of current commercial amine solvent separation technologies to coal-fired PC units would impose high capital and operating costs and require steam and power inputs that would substantially reduce net plant output (see Figure 3-3). Extensive RD&D is in progress to improve the solvent and system designs for power boiler applications and to develop better solvents with greater absorption capacity, less energy demand for regeneration, and greater ability to accommodate flue gas contaminants.

9 Technologies to Reduce or Capture and Store Carbon Dioxide Emissions, The National Coal Council, June 2007.10 CO2 storage is discussed in Chapter 5.



Amine-Based Solvent TechnologiesThe two leading manufacturers of post-combustion CO2 capture technology, Fluor and MHI, are working to meet the requirements of large-scale power plant applications by increasing the performance of their solvents and decreasing the amount of thermal energy required to regenerate them.

Fluor’s Econamine FG process uses a 30% aqueous solution of monoethanolamine solvent with proprietary additives. Econamine is deployed at some 20 plants supplying CO2 to the chemical and food industries and for EOR. However, none of these units process coal-derived flue gas.

As part of a Canadian Clean Power Coalition study, a more recent commercial offering, Econamine FG Plus, was retrofitted to a PC boiler fired with lignite. This reduced energy consumption by about a third—from 1750 Btu/lb to 1180 Btu/lb of CO2 captured (4070 kJ/kg to 2760 kJ/kg)12—compared to the conventional Econamine FG process.

MHI has successfully used an amine solvent, designated KS-1, at several large-scale commercial plants for fertilizer and heavy oil production. The first testing of KS-1 on coal-generated flue gas is under way at a 10-ton-day CO2 pilot at J-POWER’s Matsushima plant in Nagasaki, Japan.13 An EPRI study is evaluating the use of KS-1 for power plant applications. Results are expected in late 2008.

Figure 3-3PC Net Power Output, Capital Cost, and COE with and without Capture (Powder River Basin Coal)11

11 George Booras and Neville Holt, “Review of New CoalFleet Engineering-Economic Evaluations,” presentation at CoalFleet for Tomorrow General (Technical) Meeting, Tulsa, Oklahoma, April 16, 2008.

12 Evaluation of Advanced Coal Technologies with CO2 Capture: Canadian CPC Phase 1 Studies of Coal Technolo-gies with CO2 Capture, EPRI, Palo Alto, CA: 2004. 1004880.

13 Assessment of Post-Combustion Carbon Capture Technology Developments, EPRI, Palo Alto, CA: February 2007. 1012796.

40

60

80

100

120

140

160

Supercritical PC

30-Y

rlev

eliz

edC

OE,

$/M

Wh

(Con

stan

t200

7$)

. No Capture

Retrofit CaptureNew Capture

1,500

2,000

2,500

3,000

3,500

4,000

4,500

5,000

5,500

6,000

6,500

Supercritical PC

Tota

l Cap

ital R

equi

rem

ent,

$/kW

(200

7$)

. No Capture

Retrofit CaptureNew Capture

0

100

200

300

400

500

600

700

800

Supercritical PC

Net

Pow

erO

utpu

t,M

We

.

No CaptureRetrofit CaptureNew Capture



Three other suppliers have completed extensive pilot plant programs and are submitting proposals in response to solicitations for commercial projects. They are:

Aker Clean Carbon – an earlier version of the process is used to capture CO2 on the Sleipner projectCansolv – the process uses two solvents to simultaneously remove SO2 and CO2

HTC Purenergy – the process includes a control system to optimize heat utilization.

Along with modifications to the chemical properties of sorbents, research also is addressing the physical structure of the absorber and regenerator equipment, examining membrane contactors to improve gas-liquid contact and/or heat transfer, and optimizing thermal integration with steam turbine and balance-of-plant systems.

Potential Alternatives to Amine-Based Solvent TechnologiesExtensive research is being carried out to identify new processes and liquid solvents for CO2 capture that offer economic advantages and are suitable for scale-up and demonstration. Some notable examples of this development work include post-combustion CO2 capture using a chilled aqueous ammonium carbonate as the solvent, currently under development and testing by Alstom and a collaborative of EPRI members. CO2 is captured in an absorber at low temperature and atmospheric pressure, forming ammonium bicarbonate, which then is regenerated at increased temperature and high pressure to drive off a concentrated stream of CO2. Although still to be confirmed, it is projected that the heat of regeneration will be approximately half that of amine systems. Further, because the CO2 is released at pressure, less energy is required for the compression stage.

Alstom and the EPRI consortium have constructed a 1.7-MW pilot unit connected to a flue gas slipstream at We Energies’ Pleasant Prairie Power Plant and testing has commenced. A 20-MW scale-up is planned at American Electric Power’s (AEP) Mountaineer power plant in West Virginia, with AEP potentially hosting a 200-MW scale-up demonstration at its Northeastern station in Oklahoma.

Also in development is an ammonia-based process (ECO2) that is being tested by Powerspan at 1-MW scale at FirstEnergy’s R.E. Burger plant in Ohio. If successful, Basin Electric plans to test a 120-MW scale-up at its Antelope Valley station in North Dakota.

Ionic liquids, a class of organic compounds, show promise for post-combustion CO2 capture as they can be formulated to have high selectively for CO2 relative to nitrogen and oxygen. Unlike amines, they do not react with CO2 but form weak ionic bonds that result in a relatively low heat of regeneration. DOE-NETL currently is funding development at the University of Notre Dame.

In Europe, the CASTOR (for Capture and Storage) project, a cooperative effort involving some 30 European RD&D organizations, is exploring newly developed solvents for CO2 capture in pilot-scale tests at a coal-fired plant in Esbjerg, Denmark.14

■

■

■

14 “Start-up of the Largest Installation in the World to Capture CO2 in the Flue Gases of a Coal-fired Power Station - Denmark - European Castor Project.” Press Release, IFP. Lyon, France: March 16, 2006;

http://www.ifp.com/actualites/communiques-de-presse/premier-pilote-mondial-de-captage-de-co2-projet-castor


3-�0 Advanced Coal Power Systems with CO2 Capture: EPRI’s CoalFleet for Tomorrow Vision

In addition to liquid solvents, alternative approaches also are being investigated to separate CO2 from flue gas. These include:15

Multiple physical and chemical adsorption processesCryogenic separation processes that “freeze” out the CO2

Molecular sieve and solution-diffusion membranesBiological processes that use photosynthesis to fix the CO2 as algae.

Oxy-Combustion for CO2 CaptureFuel combustion in a blend of oxygen and recycled flue gas rather than in air is known as oxy-fuel combustion or oxy-combustion, and it is gaining worldwide interest as a viable CO2 capture alternative for PC (and CFBC) plants. The process is applicable to virtually all fossil-fueled boiler types and is a candidate for retrofits and new power plants.

Firing coal with only high-purity oxygen would result in a flame temperature too high for existing fur-nace materials, so the oxygen is diluted by mixing it with a slipstream of recycled flue gas. The flue gas recycle loop may include dewatering and desulfurization processes. As a result, the flue gas down-stream of the recycle slipstream take-off consists primarily of CO2 and water vapor (with small amounts of nitrogen, oxygen, and criteria pollutants). After the water is condensed, the CO2-rich gas is com-pressed and purified to remove contaminants and prepare the CO2 for transportation and storage.

■

■

■

■

Figure 3-4Schematic of Oxy-Combustion Process16

15 Assessment of CO2 Capture Options Currently Under Development, EPRI, Palo Alto, CA: February 2007. 1012796.

16 John Wheeldon and Des Dillon, “Oxy-Combustion of Coal,” EPRI CoalFleet for Tomorrow General (Technical) Meeting, Greenville, South Carolina, July 26, 2007.

ESP orbaghouse

FGD

Boiler

Flue gasheater

Coalprep

Coal

Oxygenplant

Air

Dryer

WaterTo CO2 purification and compression

Oxygen

Primary flow

Secondary flow

Nitrogen

Wet recycled flue gas (RFG)Dried RFG


3-��Advanced Coal Power Systems with CO2 Capture: EPRI’s CoalFleet for Tomorrow Vision

Oxy-combustion boilers have been studied in laboratory-scale and small pilot units of up to 3 MWt. Two larger pilot units at 30 MWt are operating, one by Babcock & Wilcox (B&W), and one by the Swedish power company Vattenfall. An Australian-Japanese project team is pursuing a 30-MWe repowering project at the CS Energy’s Callide A station in Queensland, Australia.17 These larger tests will allow verification of the technology and provide engineering data useful for designing pre-commercial systems of about 300 MW.

Because the oxy-fuel combustion process requires a supply of high-purity oxygen, it stands to benefit from developments in oxygen separation such as membrane-based air separation technology, which could replace energy-intensive cryogenic process air separation technology.

Circulating Fluidized-Bed CombustionCommercial StatusCFBC technology has been employed for power generation for only 20 years and still is evolving. In the United States, there is about 5000 MW of coal-fired generating capacity, with another 1000 MW in construction, and worldwide there is estimated to be more than 14,000 MW of capacity. The typical maximum size of the units is 300 MW, although two units can be combined to raise steam for a single 600-MW turbine. By contrast, PC units can generate more than 1,000 MW. The poorer economy of scale of the CFB results in a higher capital cost and has limited its deployment.

Almost all CFB units raise sub-critical steam and are less efficient than the USC PC plants in operation. A 460-MW SC CFB under construction in Lagisza, Poland will be the largest CFB built. These two features, steam conditions and generating capacity, will improve the efficiency and economy of CFB technology and make it more competitive with PC plants.

The CFB furnace operates at approximately 1550°F (843°C), much lower than the 2400°F (1320°C) achieved in a PC unit. The lower combustion temperature limits ash fouling and corrosion of the heat transfer surfaces and allows the CFB to handle fuels that are difficult to burn in a PC unit. Many CFB units are fired with waste coal and serve to clean up waste piles left over from mining activities. Its greater fuel flexibility allows CFB to use lower-grade, lower-cost fuels than a PC unit and this helps compensate for the higher capital costs.

Environmental ControlsIn the CFB design, relatively coarse coal and limestone (for sulfur capture) are fed into the furnace and the majority of the solids present are carried over by the combustion air. Most of these solids are capture by cyclones and returned to the base of the furnace, which extends the residence time of the solids and helps increase combustion and sulfur capture efficiency.

The majority of the sulfur in the coal is captured in the furnace by the calcined limestone, with an additional amount captured by a dry FGD located after the cyclones. Emissions of SO2 as low as 0.08 lb/MBtu (~80 mg/Nm3) have been achieved, similar to that of a PC, but the limestone feed rate required is almost twice that of a wet FGD.

The low furnace temperature results in reduced NOX formation. This can be further reduced by non-selective catalytic reduction through injection of ammonia into the upper furnace. Emission levels of 0.07 lb/MBtu (~70 mg/Nm3) have been achieved, again similar to those of a PC unit. SCRs are not considered practical for CFB operation as the flue gas dust loading is higher than for a PC unit and this will impair its operation.

17 “Callide Oxyfuel Project,” April 2008. Fact Sheet OXY01; http://www.csenergy.com.au/research_and_devel-opment/070911_Oxyfuel_fact_sheet.pdfoxy_fuel_news.aspx


3-�� Advanced Coal Power Systems with CO2 Capture: EPRI’s CoalFleet for Tomorrow Vision

The low temperature results in a slightly lower combustion efficiency than for a PC unit, but the additional carbon present in the fly ash offers intrinsic mercury capture, and collection efficiencies of more than 90% have been measured. Particulate control is achieved using baghouses, which operate with similar collection efficiency to those used for PC units.

Efficiency Improvements and CO2 Capture The improved materials being developed primarily for USC PC applications are expected to be equally suitable for CFB designs. Presently no USC CFB units are planned but designs reportedly have been prepared. The CFB efficiency gains arising from the improved steam conditions are expected to be similar to those achieved by the PC designs.

Post-combustion technologies for PC applications are expected to be equally suitable for CFB applica-tions. A sub-critical CFB design will produce more CO2 than the more- efficient USC PC design, however, so the capture plant will be larger, more expensive, and require increased power losses. USC CFB designs need to be demonstrated and proven if they are to play an effective role in the future.

Oxy-combustion also is applicable to CFB technology and may have some advantages over PC designs. The process is similar to that shown in Figure 3-4 for PC oxy-combustion with these exceptions:

Because the sulfur is captured mainly in the CFB furnace, no FGD is required. Any remaining SO2 is removed in the cryogenic CO2 purification stage.Ammonia injection for NOX reduction is eliminated and the NOX is removed in the cryogenic CO2 purification stage along with the SO2.The furnace temperature can be controlled by cooling the circulating solids and lower-ing the amount of flue gas that has to be recycled. Flowing less gas through the furnace allows its size to be reduced, with associated reductions in capital and operating costs.

Both Alstom and Foster Wheeler are evaluating CFB for oxy-combustion. Recently, the Oxy-Coal Alliance (composed of Praxair, Foster Wheeler, and others) announced plans to build a 50-MW oxy-combustion CFB for Jamestown Board of Public Utilities in New York. This commercial project will demonstrate the viability of the technology and provide design data for scaling up to units of 300 MW and larger.

■

■

■

IGCC Technologies – Transitioning to the Commercial Era


4-�

4 IGCC TEChnOlOGIES – TRAnSITIOnInG TO ThE COmmERCIAl ERA

1 The Tampa Electric Integrated Gasification Combined-Cycle Project, An Update,TopicalReportNumber19.U.S.DOECleanCoalTechnologyProgramandTampaElectricCompany:July2000;www.lanl.doe.gov/projects/cctc

Figure 4-1Aerial View of Tampa Electric Company’s 250 mW Polk Unit 1 IGCC Plant1

Key Points

IGCCprocessesareamenabletoenvironmentalcontrolsthatresultinverylowairemissionsLessonsleanedfromthefirstgenerationofIGCCplantsareexpectedtoleadtoincreasedavailabilityinnewIGCCplantsHighlevelsofCO2capturefromanIGCCunitrequiretheadditionofoneortwowater-gasshiftreactorsandphysicalorchemicalsolventprocessesCO2canbecapturedfromIGCCunitsatelevatedpressure,whichreducesthecostandenergyrequirementsforcompressiontopipelinepressureGasturbinescapableoffiringthehigh-hydrogensyngasthatresultsafterCO2removalarethesubjectofextensiveRD&Defforts.

Overview

IGCCtechnologyallowstheuseofsolidandliquidfuels(typicallycoal,petroleumcoke,ablendofcoalandpetroleumcoke,residuum,orbiomass)inapowerplantthathastheenvironmentalbenefitsofanaturalgas-fueledplantandthethermalperformanceofacombinedcycle.Initssimplestform,thesolidorliquidfuelisgasifiedwitheitheroxygenorair,andtheresultingrawgas(calledsyngas,anabbreviationforsyntheticgas)iscooled,cleanedofparticulatematterandsulfurspecies,andfiredinagasturbine.Byremovingtheemission-formingconstituentsfromthegasunderpressurepriortocombustioninthepowerblock,IGCCplantscanmeetextremelystringentairemissionstandards.Thehotexhaustfromthegasturbinepassestoaheatrecoverysteamgenerator(HRSG)whereitproducessteamthatdrivesasteamturbine.

■

■

■

■

■



Powerisproducedbothfromthegasandsteamturbines.Theuseofgasturbinesandasteamturbineconstitutes the“combinedcycle”aspectof IGCCand isone reasonwhygasification-basedpowersystemscanachievehighpowergenerationefficiencies. Ina typical IGCCunit,about60%of thenetpoweroutputisgeneratedbythegasturbine(s)andabout40%bythesteamturbine.Duetotherelativelyhighefficienciesofmoderncombinedcycletechnology,theoverallthermalefficiencyofanIGCCisinthe38–41%HHVrangeforbituminouscoal.2AblockflowdiagramofanIGCCsystemisshowninFigure 4-3.

TherearemanyvariationsonthisbasicIGCCscheme,especiallyinthedegreeofintegration.Fourmajorcommercial-sized,coal-basedIGCCdemonstrationplantsareinoperation,eachusingadiffer-entgasificationtechnology,gascoolingandgascleanuparrangement,andintegrationscheme.Allofthecurrentcoalbasedplantsintegratethesteamsystemsofthegasificationandpowerblocksections.Typically,boilerfeedwaterispreheatedintheHRSGandpassedtothegasificationsection,wheresaturatedsteamisraisedfromcoolingof therawsyngas.ThesaturatedsteampassestotheHRSGforsuperheatingandreheatingpriortointroduction,withadditionalHRSGsuperheatedsteam,tothesteamturbineforpowerproduction.

Thedegreeofintegrationofthegasturbinewiththeairseparationunit(ASU)isthepartofthedesignthatvariesmostamongthefourcoal-basedIGCCplants.ThemajordesignvariationsbetweenthetwoEuropeanIGCCplantsandtheU.S.plantsliesingasturbineselectionanddifferencesinphilosophiesabouttheimportanceofefficiencycomparedtoavailability.TheEuropeanplantsatBuggenum(Neth-erlands)andPuertollano(Spain)arebothhighlyintegrateddesignswithalltheairfortheASUtakenasableedofextractionairfromthecombustionturbinecompressor.TheU.S.plantsatTampaandWabasharelessintegrated,andtheASUshavetheirownseparateaircompressors.Themorehighlyintegrateddesignresultsinhigherplantefficiency,sincetheauxiliarypowerloadisloweredbytheeliminationoftheseparateaircompressor.However,thereisalossofplantavailabilityandoperat-ingcontrollabilityforthehighlyintegratedsystem.Startuptimeislonger,too,withthisdesign,asthecombustionturbinemustberunonmoreexpensivesecondaryfuel(naturalgasoroil)beforeextractionaircanbetakentotheASUforitscool-downandstart-up.

2 http://www.fossil.energy.gov/programs/powersystems/gasification/howgasificationworks.html

Figure 4-2Block Flow Diagram of an IGCC Power Plant

CoalPrep Gasification

Conventionally Integrated

Added for Highly Integrated

SteamTurbine

HRSG

GasTurbine

AIR

Air

Air Freshwater(BFW)

Steam

O2N2

BFWFresh boiler

AirSeparation

Unit

SulfurRemoval

GasCooling



Commercial Status

Twocoal-based, commercial-sized IGCCplants currentlyareoperating in theUnitedStates. ThreemoreareinEuropeandoneisinJapan,foratotalinstalledcapacityofabout1700MW.TheU.S.projectswerepartiallysupportedbyDOE’sCleanCoalTechnologydemonstrationprogram.

Althoughexperienceislimitedwithgasificationincoal-firedpowerplants,itissupplementedbymultiplechemicalplantsaround theworld,whichhave100yearsofexperience inoperatingcoal-basedgasificationunitsandrelatedgascleanupprocesses.ThemostadvancedoftheseunitsaresimilartothefrontendofamodernIGCCfacility.Similarly,severaldecadesofexperiencefiringnaturalgasandpetroleumdistillatehavemadethebasiccombinedcycleamaturegeneratingtechnology.

Recently,powercompaniesonfivecontinentsannouncedplanstobuild(orareconsidering)newcoal-basedIGCCpowerplants,andprovisionstoencouragetheirconstructionintheUnitedStateswereincludedintheEnergyPolicyActof2005.MuchofthisinterestismotivatedbythepotentialforIGCCpowerplantstocapturethemajorityoftheirCO2emissions.

IntheUnitedStates,DukeEnergyhasbegunconstructionofanew630-MWIGCCplantinEdwardsport,Indiana.Theplantisscheduledtocomeon-linein2012andwillreplacefouroldergeneratingunitsofatotalcombined160-MWcapacityatthesamesite.

Emission Controls

Thesyngasfedintothegasturbinefirstpassesthroughaseriesofclean-upstepstoremovespeciesthatwouldharmtheenvironmentortheturbine.

Sulfur Species Removal Under the reducingconditionsofgasification, sulfur in thecoal isconvertedprimarily tohydrogensulfide(H2S),with~3–10%converting tocarbonylsulfide(COS).This typicallynecessitates theuseofaCOShydrolysisreactortoconverttheCOStoH2SpriortoH2Sremovalbyanacidgasrecovery(AGR)system.

ThemostcommonAGRprocessesusethechemicalsolventmethyldiethanolamine(MDEA)oraphysicalsolventsuchasSelexol,whichisamixtureofdimethylethersofpolyethyleneglycol.Thechemicalsolventreactswith theacidgasesand requires heat to reverse the reactionsand release theacidgases.Physicalabsorbentsdissolveacidgasesandrequirepressureasthedrivingforceforabsorptionandpressurereleaseforregeneration.

IGCCplantshavedemonstratedsulfurremovalratesof~99%.3Thesulfurorsulfuricacidcanbesoldforuseinfertilizermanufacturingtohelpoffsetplantoperatingcosts.

NOX ControlThemaincontributor toNOXemissions is thermalNOXfromtheuncontrolledcombustionofsyngas(whichhasahighflametemperature).ThethermalNOXiscontrolledtoverylowlevelsbydilutionofthesyngaswithnitrogentolowertheflametemperature.ThediluentnitrogenalsoprovidesadditionalmassandmotiveforcetothegasturbinethatincreasestheMWoutput.Theuseoflow-NOXburnersinthegasturbinewillfurtherlimittheproductionofNOX.Inthegasificationprocess,thesmallamountsoffuel-boundnitrogenarereadilyremovedfromthesyngasbywaterwashing.Together,theseprocessessignificantlylimitNOXemissionsforIGCCplants.

3 Gasification Technology Status - December 2006,EPRI,PaloAlto,CA:December2006.1012224.



IffurtherNOXemissionsreductionsarerequired,aSCRsystemcouldbeaddedtotheplant.AlthoughtheapplicationofSCRisnotyetcommerciallyprovenoncoal-derivedsyngas,someproposedprojectsplantouseSCR.

Mercury and Trace Toxics RemovalAllIGCCunitsproposedsince2004incorporatemercuryremovalsystemsintheirdesign.Typically,thesystemconsistsofasinglebedofsulfur-impregnatedactivatedcarbon,whichisexpectedtoremoveupto94%ofthesyngasmercurycontent.Arsenicandothertracemetalsalsoareabsorbedbythecarbon,withvaryingdegreesofefficiency.

Particulate RemovalParticulates in syngascanbe removedby“dry”processes suchasa rigidbarrier,pulse-cleanedfilterorby“wet”processesusingventuriscrubbers(referredtoas“gasscrubbing”).Theprocessusedtypicallydependsontheselectedgasificationtechnology.Bothmethodsachieveextremelyhighlevelsofparticulateremoval.

Inthewetprocess,thesolidsalsocanberecoveredandrecycledtothegasifierifwarrantedbythecarboncontent.Inthedryprocess,solidscanbesoldforuseincementiflowincarbon,orrecycledtothegasifierifhighincarbon.

Steps and Timeframe for IGCC Capital Cost Reduction and Efficiency Gains

MembersofEPRI’sCoalFleet for Tomorrowresearchprogramteamedtoevaluatemorethan120coal-gasification-relatedresearchprojectsworldwideandtoidentifygapsorcritical-pathactivitieswhereadditionalresourcesandexpertisecouldhastenthemarketintroductionofIGCCadvances.Theresult-ingIGCCRD&DAugmentationPlan4describessuchopportunitiesandhowtheycouldbeaddressedforIGCCplantstobebuiltinthenearterm(by2012–15)andoverthelongerterm(2015–25).

4 CoalFleet RD&D Augmentation Plan for Integrated Gasification Combined Cycle (IGCC) Power Plants,EPRI,PaloAlto,CA:January2007.1013219.

Figure 4-3RD&D Path for IGCC Power with 90% CO2 Capture (Upturning Arrows Refer to Right Axis and Downturning Arrows to the left Axis)

Tota

lPla

ntC

ost(

$/kW

,con

stan

tdol

lars

norm

aliz

edto

2005

plan

tcos

t)

Plan

tNet

Effic

ienc

y(H

HV

Bas

is)Long-Term• Membrane separation• Warm syngas cleanup• CO2-coal slurryMid-Term

• ITM oxygen• G-class to H-class CTs• Supercritical HRSG• Dry ultra-low-NOX combustors

Near-Term• Add SCR• Eliminate spare gasifier• F-class to G-class CTs• Improved Hg detection

30

32

34

36

38

40

42

0.6

0.7

0.8

0.9

1.0

1.1

1.2

2005 2010 2015 2020 2025



Figure 4-3depicts theanticipated timeframe for select technologydevelopments,as identified inEPRI’sIGCCRD&DAugmentationPlan,thatpromiseasuccessionofsignificantimprovementsinIGCCunitefficiencyandcosts.Theseincludeadvancesingasifier,turbine,andairseparationtechnologies,aswellasopportunitiestoreducethecostofCO2capturethroughbettersolventsandintegrationwithotherplantprocesses.Notethattheseopportunitiesremaintobedemonstrated.

TheCoalFleet for TomorrowprogramaddressesthegapsinresearchanddevelopmentidentifiedintheIGCCAugmentationPlanbysupportingdevelopmentofpromisingemergingtechnologiesandthroughdisseminationofdataon IGCCtechnologies.The IGCC User Design Basis Specification,5providesEPRImembersacomprehensiveguidetothemajorspecificationsneededtocontractforanIGCCplant,includingmultipleconfigurationsof600-MWand800-MWcommercial IGCCpowerplants,usinggasificationprocessesandcombustionturbineequipmentfromseveralmanufacturers.

Longer-Life Components for Improved Gasifier Availability6

Theavailability(percentoftimeavailabletogenerateelectricity)ofIGCCplantsisaconcernbecauseoftherelativenewnessofthetechnology.“Lessonslearned”fromtheexistingplants,whicharethefirstgeneration,willbeincorporatedinnewIGCCplantsthroughdesignmodificationsthatareexpectedtoresultinimprovedavailability.AnumberofneworimprovedIGCCplantcomponentsandprocessesarebeingdeveloped.

Therearetwogenerictypesofgasifiervesseldesign.Oneusesmultiplelayersofrefractorybricktoinsulatethemetalwallofthepressure-containingvesselfromthehotgasificationreactionzone.Theotherusesawater-cooled“membrane”wallinwhichboilertubesareweldedtogethertoformacon-tinuouswallaroundthereactionzone.Athick,metalpressureshellbehindthemembranecontainstheprocesspressure.

Therefractory-linedvesseldesign isconsiderablycheaper tobuild than themembrane-wallvessel.However,therefractoryisworndownbychemicalattackfromgasificationproductsandmoltenslag,and suffers from thermal fatigue fractures due to the large temperature cycles experienced duringstartupsandshutdowns.Refractoryreplacementtypicallymustoccurevery6to18months,atacostofabout$1millionincludingmaterialsandlabor.

ResearchatDOE’sAlbanyResearchCenterisfocusedonthedevelopmentofimprovedchrome-basedrefractorymaterials.Thegoalistoextendtheintervalforrefractoryreplacementto36monthsormore,allowingtherefractoryworktobecarriedoutatthesametimeasthegasturbinehotsectionoverhaul.No additional outage time would be required for the refractory change-out, which takes about 3weeks,becausethegasturbinehotsectionoverhaultakes6weeks.

Increasingthelongevityoffeedinjectorsforslurry-fedgasifiersalsoisthesubjectofresearchbyseveralmanufacturersandshouldresultinlessdowntime.

Higher-Pressure GasifiersIncreasing theoperatingpressureofgasifiersallows forsmaller (albeit thicker-shelled)vessels foragivencapacityrating,whichinturnreducescostandspacerequirements.Higheroperatingpressurealsoiscompatiblewiththephysicalsolvent-basedsystemsgenerallypreferredforhighefficienciesofsulfurspeciesremovalandCO2separation.

5 CoalFleet User Design Basis Specification for Coal-Based Integrated Gasification Combined Cycle (IGCC) Power Plants, Version7,EPRI,PaloAlto,CA:June2008.1015684.

6 CoalFleet RD&D Augmentation Plan for Integrated Gasification Combined Cycle (IGCC) Power Plants,EPRI,PaloAlto,CA:January2007.1013219.



Gas Turbines for Synthesis Gas FiringSyngas isa low-energy-density fuelwithaheatingvalueofabout250Btuperstandardcubic foot(9.314MJ/m3),roughlyone-quarterthatofnaturalgas.Asaresult,operationonsyngasrequiresahighervolumetricflow through thegas turbinecombustors toachieve thesame turbine-sectionheatinputasoperationonnaturalgas.Currently,operatingadvancedgas turbineson syngas requiresturbineinlettemperaturestobelowerthanthoseusedwhenfiringnaturalgasbecauseofdifferencesinaerodynamics,heattransfer,anderosionissues.7

Nonetheless,gasturbineshavebeendesignedtoaccommodatehigherfuelmassflowandlowerflametemperaturesassociatedwithfiringsyngas.Inmanycases,despitethelowerfiringtemperature,thehighermassflowallowsanincreaseingasturbinepowerrating.Someturbinedesignsaremodifiedwithstrongerdriveshaftsandlargergeneratorstotakeadvantageofthiscapacity.Inaddition,tocontrolNOX,syngasisdilutedwithnitrogentolowertheflametemperature.Thediluentnitrogenprovidesadditionalmassandmotiveforcetothegasturbine,increasingtheMWoutput.

However,aerodynamicissueswithsyngasanddifficultiesintryingtocapturetheadditionalmass-flowenergy(e.g.,shafttorqueand/oraxialcompressorsurge)currentlylimitpowergainstovaluesbelowthosetheoreticallypossible.8

IGCCplantdevelopmentwillbenefitfromnewgasturbinesmodelswithhigherfiringtemperatures,greaterefficiencies,andlargerpoweroutputs,whichwillallowasignificantreductioninthecostofelectricity.Forplantscomingon-linecirca2015,thelargersizeG-classturbines—MitsubishiHeavyIndustries’M501G(60Hz)andM701G(50Hz),andtheSiemensSGT6-6000G,whichoperateathigherfiringtemperatures(relativetoF-classmachines)—canimproveefficiencyby1to2%whilealsodecreasingcapitalcostperkWcapacity.H-classgas turbines,comingon-line later,willprovideafurtherincreaseinefficiencyandcapacity.

Supercritical Heat Recovery Steam GeneratorsIn IGCCplants,hotexhaustgasexitingthegasturbineisductedintoaHRSGtoraisesub-criticalsteamtodriveasteamturbine.Thiscombinationofagasturbineandsteamturbinepowercyclesproduceselectricitymoreefficientlythaneitheragasturbineorsteamturbinealone.Thehigherexhausttemperatures ofG- andH-class gas turbines offer the potential to raise supercritical steam in theHRSG,resultinginincreasedcombinedcycleefficiency.MaterialsforuseinasupercriticalHRSGaregenerallyestablished.

Liquid CO2-Coal Slurrying for Low-Rank CoalsFutureIGCCplantsmayrecyclesomeoftherecoveredliquidCO2toreplacewaterastheslurryingmediumfor thecoal feed.LiquidCO2hasa lowerheatofvaporizationand isable tocarrymorecoalperunitmassoffluid.The liquidCO2-coalslurrywillflashalmost immediatelyuponenteringthegasifier,providinggooddispersionofthecoalparticlesandpotentiallyyieldingdry-fedgasifierperformancewithslurry-fedsimplicity.9

7 Enabling Near-Zero Emission Coal-Based Power Generation, U.S. DOE/NETL, Turbine Program, June Bro-chure, September 2005; http://www.netl.doe.gov/technologies/coalpower/turbines/refshelf/brochures/Bro-chure%209-19-05.pdf

8 Oluyede,E.O.andJ.N.Phillips,“FundamentalImpactofFiringSyngasinGasTurbines,”GT2007-27385,Pro-ceedingsofASMETurboExpo2007,May2007,Montreal.

9 Program on Technology Innovation: Advanced Concepts in Slurry-Fed Low-Rank Coal Gasification: Liquid CO2/Coal Slurries and Hot Water Drying, EPRI, PaloAlto,CA:2006.1014432.



Todate,CO2-coalslurryinghasbeendemonstratedatpilotscaleandhasyettobeassessedinfeedingcoaltoagasifier,sotheestimatedperformancebenefitsremaintobeconfirmed.10Itwillbenecessarytoupdatepreviousstudies toquantify thepotentialbenefitof liquidCO2slurrieswith IGCCplantsdesignedforCO2capture.Ifthereisapredictedbenefit,asignificantamountofscale-upanddemon-strationworkwouldberequiredtoqualifythistechnologyforcommercialuse.

Ion Transport Membrane for Lower Cost, Energy-Efficient Oxygen ProductionOxygenforthegasificationreactionscanbeprovidedeitherbyairorhigh-purityoxygen.Toobtainhigh-purityoxygen,IGCCunitsinstallanASUthatusesacryogenicdistillationprocesstoproduce95%pureoxygen.TheASUaddstotheplant’scapitalcostandresultsinparasiticpowerlosses,butresultsinasyngaswithaheatingvalueuptotwicethatfromanair-blowngasifier,inwhichthenitrogenintheairhastheeffectofdilutingthesyngas.Inanoxygen-blownsystem,thenitrogenseparatedbytheASUcanbeusedforpoweraugmentationinthegasturbine.Separatednitrogenalsocanbeusedtoconveycoal,orasastrippingagentintheAGRprocess,orforpurgingandblanketingduringoutages.

Iontransportmembrane(ITM)isoneofthetechnologiescurrentlybeingdevelopedasanalternativetoASUtechnology.ThegoalofITMisasignificantreductioninthepowerconsumptionandcapitalrequiredtoproducetheoxygenrequiredfortheIGCCapplication(andpotentiallyforoxy-fuelcombustion).

Foran ITMunit,air isextracted from thecombustion turbine,heated,andsent to themembranewhereoxygenisseparatedforthegasifier.Thenon-permeate,vitiatedairisreturnedtothecombustionturbine. For IGCC, the oxygenwould be compressed to the required pressure for the gasificationprocess.AchievingthefullbenefitsofITMtechnologyinIGCCapplicationsrequiresintegrationwithadvancedgasturbinesthatcan:

Extractmorethan50%ofthegasturbinecompressedairtosupplytheITMsystemAcceptthereturnofthenon-permeatevitiatedairstreamfromtheITMsystemOperateusingsyngas.

Althoughcurrentlyavailablegasturbinesmaybelimitedwithregardtooneormoreofthecapabilitiesnotedabove,thetechnologydeveloperprojectsthatITMstillcanresultina7%reductioninthecapitalcostand6%reductioninauxiliarypowerconsumptioncomparedwithanIGCCcycleusingacryo-genicASU.

CO2 Capture for IGCC Units

CO2canbeseparatedfromsyngasbyAGR,thesameprocessusedtoseparatesulfurspecies.11Forslurry-fedgasifiers,theCO2inthesyngascanrepresent15-18%ofthecarbonthatcouldberemovedbyaddingasingle-stageAGRprocess.ThisisthesimplestapproachtocapturingsomeCO2fromanIGCCunit,althoughitmaynotbethemostcost-effectiveona$/ton-CO2-removedbasis.

AchievinghigherlevelsofCO2capturewillrequireaddingawater-gasshiftreactorpriortoseparation.Thiscontainsacatalystthat,inthepresenceofwater,“shifts”carbonmonoxide(CO)inthesyngastoCO2andhydrogen:

CO+H2ODH2+CO2

■

■

■

11 Investigation of Low-Rank-Coal-Liquid Carbon Dioxide Slurries, EPRI, PaloAlto,CA:1986.AP-4849.12 AlthoughbothsulfurspeciesandCO2canberemovedsimultaneously,theresultingmixtureofCO2andhydrogen

sulfidewillnotbedesirableinmanyinstances.SeparateAGRapplicationsforsulfurspeciesandCO2arelikelytobemorecommonforIGCC.



Asingle-stageshiftreactorcanachievemostoftheCOconversion(80–85%).ToachieveadditionalCOconversionrequiresadditionalshiftreactorsatincreasedcapitalcost.TheCO2intheshiftedsyn-gasisremovedviacontactwiththesolventinanabsorbercolumn,leavingahydrogen-richgasforcombustioninthegasturbine.

Thewater-gasshiftreactionreleasesheat,whichdecreasesthechemicalenergycontainedinthesyn-gas.Consequently,inordertosupplythesamefuelenergytothegasturbineafterpassingthesyngasthroughawater-gasshiftreactor,5–10%moresyngaswouldhavetobeproduced.

Theheatreleasedduringtheshiftreactioncanbeusedtopreheatboilerfeedwaterforsyngassatura-tionortoproduceintermediatepressuresteam.

Thewater-gasshiftoptionallowsCO2capturetotakeplaceatthepre-combustionstageatelevatedpressure,ratherthanattheatmosphericpressureofpost-combustionfluegas,permittingcapitalsav-ingsthroughsmallerequipmentaswellasloweroperatingcosts.

TheimpactofcurrentCO2removalprocessesonIGCCplantthermalefficiency,netplantoutput,andcapitalcostissignificant(seeFigure 4-4).Inparticular,thewater-gasshiftreactionreducestheheat-ingvalueofsyngastotheturbine.BecausethegasifieroutletratiosofCOtoCH4toH2aredifferentforeachgasifiertechnology,therelativeimpactofthewater-gasshiftreactorprocessalsovaries.Ingeneral,however,itcanbeapproximatelya10%fuelenergyreduction.

12GeorgeBoorasandNevilleHolt,“ReviewofNewCoalFleetEngineering-EconomicEvaluations,”presentationatCoalFleetTechnicalMeeting,Tulsa,Oklahoma,April16,2008.

Figure 4-4net Power Output for IGCC with and without Capture (Illinois #6 Coal)12

0

100

200

300

400

500

600

700

800

GE RadiantQuench

GE TotalQuench

Shell GasQuench

E-Gas FSQ

Net

Pow

erO

utpu

t,M

We

No CaptureRetrofit CaptureNew Capture



Heatregenerationofsolventsfurtherreducesthesteamavailableforpowergeneration.Othersolvents,whicharedepressurizedtoreleasecapturedCO2,mustberepressurizedforreuse.Coolingwatercon-sumptionincreasesforsolventsneedingcoolingafterregenerationandforpre-coolingandinterstagecoolingduringcompressionofseparatedCO2toasupercriticalstatefortransportationandstorage.HeatintegrationwithotherIGCCcycleprocessestominimizetheseenergyimpactsiscomplexandcurrentlyisthesubjectofconsiderableRD&DbyEPRIandothers.

Hydrogen-Firing Gas TurbinesWhenCO2 is removed from syngas, the remaininggas consistsprimarilyof hydrogen,whichhascombustionpropertiessignificantlydifferentfromthoseofsyngasandnaturalgas.Althoughthereisextensivecommercialexperiencewithhydrogen-richfuelgasfiringingasturbines,mostofthisexperienceisforrefinerygasinwhichmethaneistheothermaincomponentofthefuelgas,andtheturbinesareolder,lower-firing-temperaturegasturbines.13

DOE’sTurbineTechnologyRD&DProgramissupportingtwoprojects(onebyGE14andonebySiemens15)todesignlarge-scale,high-temperatureturbinescapableoffiringhydrogen-richfuels.16PerformancegoalsincludetheabilitytointegratenewsystemsintoIGCC,fuelflexibilityforoperationusinghydrogenandsyngas,low-NOXemissions,andefficienciesof45-50%.GEcurrentlyoffersitsF-Classturbineforhigh-hydrogenfuelsfeaturingdiffusionflametechnologyandadiluenttolimitNOXproduction.

New Gasifier Designs Better Suited for CO2 CaptureTheIGCCreferenceplantdesignsinitiallyofferedbytheGE,ConocoPhillips,andShellteamswerepositioned tocompetewithPCplants in theU.S.powermarket.Thegasifieroperatingpressuresselectedweretheminimumrequiredtoaccomplishgasification,heatrecovery,andgasclean-up.

Sincethoseinitialofferings,however,theissueofCO2emissionshasbecomeamoredominantconcernintheselectionofnewgenerationtechnologies.Inresponse,thosethreeIGCCsuppliershaveannouncednewfeaturesthatwillreducecapitalcostsandimproveperformanceforCO2captureoperationonanexpandedrangeofcoals:

GEhasacquiredtheexclusiverightstotheStametsolidsfeedpump.Whenfullydevel-oped,itshouldbroadentherangeofcoalsthatcanbeusedeconomicallyinGEgasifi-ers,particularlywiththelower-cost,widelyavailablelow-rankcoals.GEalsoplanstosupplylargerquench-typegasifierswithcostsandoutputmatchingthefuelrequirementsof thegas turbinesplannedforuse in IGCCapplications.Quench-typegasifiersofferthemosteconomicalwayofintroducingmoistureintosyngas,whichisrequiredforthewater-gasshiftneededforCO2separation.Shell has announced the commercial offering of a partial water quench design thatwould eliminate the expensive syngas coolerwhilemoisturizing the syngas upstreamofthewater-gasshiftreactor,providingalower-costdesignoptionforplantscapturingCO2.Shellalsoisofferinglargergasifiersthatcansupplythefuelneedsofnew,large50-Hzgasturbines,whichwillprovidefurthereconomiesofscale.

■

■

13Carbon Dioxide Capture and Storage,IntergovernmentalPanelonClimateChange,CambridgeUniversityPress,2005.

14 Jones,Bob(GESyngasPowerIslandTechnologies).“GasTurbineFuelFlexibilityforaCarbonConstrainedWorld,”WorkshoponGasificationTechnologies,Bismarck,NorthDakota,June28,2006;http://204.154.137.14/technologies/coalpower/gasification/pubs/bizmark-2006/03RJones.pdf

15Brown,P.,Fadok,J.,andChan,P.,SiemensPowerGeneration,“SiemensGasTurbineH2CombustionTechnol-ogyforLowCarbonIGCC,”2007 Gasification Technologies Conference,SanFrancisco,CA,October14-17,2007.http://www.gasification.org/Docs/2005_Papers/39MOREConferences/2007/29BROW.pdf

16http://www.netl.doe.gov/publications/press/2005/tl_turbine_award.html


4-�0 Advanced Coal Power Systems with CO2 Capture: EPRI’s CoalFleet for Tomorrow Vision

ConocoPhillips’E-Gasgasifier’stwo-stagedesignallowsflexibilityintailoringthesyngascomposition.ForapplicationsrequiringCO2capture,ConocoPhillipshasindicatedthatmorewaterwouldbesenttothesecondstageofthegasifiertoproduceasyngaswithmoreCO2andahigherH2O/COratio.ConocoPhillipsalsohasindicateditiswillingtodesignforhigheroperatingpressures,whichwouldimprovetheeconomicsofphysicalsolvents.

■

CO2 Compression, Transportation, and Storage


5-�

5 CO2 COmPRESSIOn, TRAnSPORTATIOn, AnD STORAgE

T o successfully accomplish the goal of keeping power plant CO2 out of the atmosphere for centuries or longer, the captured CO2 can be compressed and injected into secure geologic formations. CCS

offers the prospect of major reductions in atmospheric emissions of CO2, particularly after 2020. By that time both capture and storage technologies may have matured, and associated legal and regulatory issues if given adequate investment, should have been resolved so that widespread deployment will become feasible.

This chapter provides an overview of the post-capture side of the CCS equation, including technolo-gies for purifying, drying, and compressing CO2; the experience base and considerations for pipeline design; suitable geologic storage formations; the potential for revenue from sale of CO2 to oil and gas producers; emerging regulatory regimes, and major ongoing research.

Key Points

For volumetric efficiency, CO2 is transported and stored under pressure in a fluid-like “supercritical” stateCO2 transportation via pipelines is commercially establishedEnergy requirements for CO2 compression—regardless of capture method—are substantialSeveral large-scale CCS demonstration projects are under wayGeologic storage capacity is large in many, but not all, areasGeologic storage has parallels in naturally occurring CO2 storage sites, natural gas storage operations, and enhanced oil recovery (EOR) operationsSite characterization and monitoring are critical to successful storage operations; oilfield technology gives researchers a good head startUnresolved barriers include regulatory, legal, and long-term liability issues. Addressing these issues will be critical on the path to commercialization.

CO2 Purification, Drying, and Compression

Most commercial applications for long-term geologic storage will use CO2 that has been compressed to become a “supercritical” fluid, a relatively dense phase that makes pipeline transportation and subsurface injection and storage more efficient.1 The compressors required to raise CO2 pressure to such a state are large, expensive, and consume significant amounts of power. With current technology, compression of the CO2 produced by a PC plant may require as much as 8% of the plant’s net power output. For a 1000-MW PC plant, the compression equipment may add about $150 million to the capital cost of the plant. For an IGCC plant, in which capture processes normally recover the CO2 at various elevated pressure, the overall work required to compress the CO2 to a supercritical state is lower (but still substantial at approximately 5% of the net plant rating).2

■

■

■

■

■

■

■

■

1 The critical point of CO2 is 1070 psia (74 bara) and 88°F (31°C), above which the gas and liquid phases be-come indistinguishable.

2 Technologies to Reduce or Capture and Store Carbon Dioxide Emissions, The National Coal Council, 2007.



The compressor will require heavy walls and strong mechanical components to contain the pressure, and stainless steel components to resist corrosion. To reach a typical overall compression ratio of 100:1, a centrifugal compressor would, for example, require about 8 handling steps (or “stages”), with each one compressing the inlet gas by a ratio of about 2:1 before passing it to the next stage. Compression inherently raises CO2 temperature (by as much as 200°F or 110°C per stage), and it is common practice to cool the CO2 between stages to reduce the overall cost and energy requirements for compression. Such interstage cooling typically increases the overall number of plant cooling tower cells and overall cooling water requirements. For plants in arid locations using dry cooling, CO2 compressor interstage cooling increases the number and cost of air-cooled heat exchangers. Given the expense of CO2 compression and its potential impact on plant water demand, DOE is sponsoring several projects to explore compressor technologies that promise higher efficiencies and better integra-tion with other plant subsystems to improve the economics of CO2 compression.3

The costs and choices for CO2 compression equipment are related to the choices of generating and capture technologies. The requirements for any post-capture purification equipment also are linked to the plant and capture system type and to the final CO2 quality specifications. In general, a capture technology that maximizes the pressure and purity of the CO2 product from the capture system will minimize the costs of downstream purification and compression equipment. Processes that produce CO2 at lower temperatures also can help modestly reduce compression costs. CO2 drying and purification processes may be integrated with the compression process (or other plant systems) to economize on the space and power requirements.

CO2 from some capture processes may contain impurities that, without an added purification step, would rapidly corrode pipeline, injection well, and possibly compressor component materials. Trace gases affect the minimum miscibility pressure of the CO2, leading to lower recovery of oil, or requiring application of EOR to deeper fields. To prevent such issues, water, oxygen, and other contaminants normally are removed in conjunction with CO2 compression. Impurities also may affect compression requirements by raising the effective critical point, by perhaps 50% to 1600 psi (110 bar),4 requiring a higher-powered compressor. In practice, however, this may not be problematic because commercial pipelines may require an inlet pressure of 2000 psi (140 bar) or more.

CO2 from pre-combustion physical solvent scrubbing processes may contain about 1–2% H2 and CO, as well as traces of hydrogen sulfide and other sulfur compounds. In some applications (e.g., a dedicated pipeline for enhanced oil recovery), IGCC plants can be designed to produce a combined stream of CO2 and sulfur compounds, which reduces capture costs and avoids the production of solid sulfur. Most IGCC plant designers, however, are planning for commercial CO2 sale or injection specifications that require very low levels of H2S and other sulfurous compounds.

For post-combustion “recoverable solvent”-type capture processes (e.g., amine-based), the CO2 produced by the capture system typically will be at a high level of purity. Plant designers normally will have ensured that most SO2, NOX, mercury, and other impurities are removed from the flue gas before it reaches the absorber vessel, in order to limit solvent make-up costs. The CO2 then may require only a dewatering/dehydration process to remove most of the remaining water vapor to meet quality specifications.

3 http://www.netl.doe.gov/publications/press/2005/tl_turbine_award.html4 Technologies to Reduce or Capture and Store Carbon Dioxide Emissions, The National Coal Council, 2007.



The equipment required for CO2 purification may be greatest for oxy-combustion boiler applications. The exhaust flue gas from an oxy-fuel process typically contains (in addition to CO2) moisture, nitrogen, oxygen, and trace amounts of other species such as SO2 and NOX. If the receiving pipeline or geologic formation cannot accommodate contaminants, they must be reduced in conjunction with the compres-sion process. The approach currently favored involves a cryogenic purification process.

CO2 Transportation

Mapping the distribution of potentially suitable CO2 storage formations across the United States and portions of Canada, as part of the research by DOE’s Regional Carbon Sequestration Partnerships program, shows that some areas have ample storage capacity while others appear to have little or none. Thus, storage of carbon from some power plants may require transportation for several hundred miles to suitable injection locations, possibly in other states or provinces. CO2 may be transported in trucks, trains, ships, and barges; however, for the large quantities of CO2 involved in CCS, pipelines likely are the most economic mode of transportation.

The technical, economic, and permitting aspects of CO2 pipeline transport are well understood in the United States, where CO2 pipelines currently extend over more than 3500 miles (5600 km), carrying 50 Mt/yr of CO2 from natural sources to enhanced oil recovery projects in west Texas, New Mexico, and Wyoming.

Pipeline transport for CCS may require a minimum specification for purity of the CO2 to prevent pipeline corrosion and reduce hazards in the event of an accidental release. The design of corrosion-resistant pipelines that could operate safely while conducting a less pure stream of CO2 also is an option. However, depending upon the length of the pipeline, the costs of corrosion-resistant materials are potentially higher than the costs of purifying the CO2.5

Although routing new pipelines through populated areas may prove difficult and time-consuming, there is no indication that the problems for CO2 pipelines will be any more challenging than those posed by hydrocarbon pipelines in similar areas. In some places, it may be possible to convert existing hydro-carbon pipelines to CO2 pipelines.6

EPRI expects that early commercial CCS projects will take place at coal-based power plants near sequestration sites or an existing CO2 pipeline. Three of the four final sites considered for the original FutureGen project offered sequestration opportunities. As the number of CCS projects increases, regional CO2 pipeline networks connecting multiple industrial sources to storage sites will be needed to service CO2 point sources that do not overlie sequestration sites or have other options for CO2 disposal.

CO2-Based Enhanced Oil and gas Recovery

Experience relevant to geologic carbon sequestration comes from the oil industry, where CO2 injection technology and modeling of CO2 subsurface behavior have a proven track record. EOR has been con-ducted successfully for 35 years in the Permian Basin fields of west Texas and New Mexico. Regulatory oversight and community acceptance of injection operations for EOR seem well established.

5 Carbon Dioxide Capture and Storage, Intergovernmental Panel on Climate Change, Cambridge University Press, New York, 2005.

6 Ibid.



In CO2-EOR, supercritical CO2 flows through permeable strata to contact residual oil that is dispersed in the pore spaces between sand grains and other materials. The CO2 effectively dilutes and swells the oil and sweeps it from the pore spaces through the strata to the production wells (Figure 5-1).

Although the purpose of EOR is to increase oil production, the practice can be adapted to include CO2 storage opportunities. This approach is being demonstrated in the Weyburn-Midale CO2 monitoring projects in Saskatchewan, Canada.8 The Weyburn project uses captured and dried CO2 from the Dakota Gasification Company’s Great Plains synfuels plant near Beulah, North Dakota. The CO2 is transported via a 200-mile pipeline constructed of standard carbon steel. Over the life of the project, the net CO2 storage is projected to be 20 million metric tons, while an additional 130 million barrels of oil will be produced.

The economic value of EOR with CCS represents an excellent opportunity for initial geologic seques-tration projects like Weyburn. “Next generation” CO2-EOR processes could boost U.S. technically recoverable oil resources by 160 billion barrels.9

Long-Term geologic Storage

Geologic sequestration of CO2 is being demonstrated in multiple projects worldwide. Together with the Weyburn project mentioned above, two other relatively large projects—Statoil’s Sleipner Saline Aquifer CO2 Storage project in the North Sea off of Norway10 and the In Salah Project in Algeria11—sequester a combined 3 to 4 million metric tonnes of CO2 per year, which approaches the output of a baseload 500-MW coal-fired power plant. Statoil estimates that Norwegian GHG emissions would have risen incrementally by 3% if the CO2 from the Sleipner project had been vented rather than sequestered.

Figure 5-1Injection of CO2 for Enhanced Oil Recovery (EOR) with Some Storage of Retained CO2

7

7 Carbon Dioxide Capture and Storage, Intergovernmental Panel on Climate Change, Cambridge University Press, New York, 2005; Figure 5.15, Page 216. http://www.ipcc.ch/ipccreports/special-reports.htm

8 http://www.co2captureandstorage.info/project_specific.php?project_id=709 http://www.adv-res.com/pdf/Game_Changer_Document.pdf10 http://www.statoil.com/statoilcom/SVG00990.NSF/web/sleipneren?opendocument11 “In Salah Project,” IEA RD&D Projects Database; http://www.co2captureandstorage.info/project_specific.

php?project_id=71


5-5Advanced Coal Power Systems with CO2 Capture: EPRI’s CoalFleet for Tomorrow Vision

Geologic storage of CO2 consists of injecting CO2 via injection wells into deep-lying formations that have the potential to securely store CO2 for long periods of time. The most promising formations include oil- and gas-bearing formations, saline formations, and deep, unminable coal seams.

At depths below 2500–3000 ft (800–1000 m), CO2 is supercritical and has a liquid-like density that makes for efficient utilization of underground storage space and improves storage security by reducing bouyant forces.12 Success of geologic sequestration depends largely upon the size and permeability of the storage formation and upon various physical and geochemical trapping mechanisms that prevent the CO2 from migrating to the surface. These include:

Structural trapping—an impermeable layer of rock overlies the storage formation and blocks upward migration Capillary or residual trapping—the CO2 is trapped within the pore spaces of the saline formationDissolution of CO2 into saline water Mineralization—over longer periods of time, the dissolved CO2 reacts with minerals to form solid carbonatesAdsorption of CO2 by coal and other organically rich formations.

To adequately qualify a site for geologic sequestration of CO2, a site assessment must be conducted to furnish an accurate evaluation of the site’s storage capacity and ability to safely store CO2. Other major considerations are naturally occurring geologic features such as faults; current and past land uses, includ-ing wells, mines, and basements; and site proximity to groundwater resources and populated areas.

Depleted Oil and Gas ReservoirsDepleted oil and gas reservoirs are excellent candidates for long-term CO2 storage because the bouyant hydrocarbons that originally accumulated in these reservoirs did not escape (in some cases for many millions of years), thus demonstrating their integrity and safety.13 Also, the geological structure and physical properties of most oil and gas fields have been extensively studied and characterized, and some of the infrastructure and wells already in place may be used for handling CO2 storage operations. Depleted fields will not be adversely affected by CO2 (having already contained hydrocarbons), and if hydrocarbon fields are still in production, CO2 can be used to enhance oil production.

Consideration of depleted oil and gas reservoirs as secure storage sites for CO2 will entail locating and examining existing wells, and possibly replugging any wells that may offer a path for the CO2 to escape.

Deep Saline FormationsSaline formations are sedimentary rocks saturated with formation waters or brines containing high concentrations of dissolved salts that make the water unsuitable for agriculture or human consump-tion. Deep saline formations are believed to have by far the largest capacity for CO2 storage and are more widespread than other options such as oil and gas reservoirs.14 Estimates for the United States and Canada indicate that saline formation storage capacity could be as much as 3500 billion tons of CO2.15 This is sufficient to store several centuries’ worth of CO2 emissions from the major stationary sources of these two countries at today’s emissions rates.

■

■

■

■

■



14 Ibid.15 NETL, Carbon Sequestration Newsletter, May 2007, http://www.netl.doe.gov/publications/carbon_seq/sub-

scribe.html



Criteria favorable to CO2 storage in saline formations include a deep, extensive, and thick layer of high-porosity, high-permeability formation such as sandstone, overlain by a thick, pervasive layer of low-permeability caprock such as shale or mudstone. The lower layer allows CO2 to be trapped in the formation, while the upper caprock serves as a seal to keep the CO2 from migrating upward. Studies have shown that over time, CO2 will dissolve in the brine and the saturated brine will become denser and sink. As this occurs, the potential for leakage from the storage formation will lessen.16

Unminable Coal BedsCoal beds that are too deep or thin to be mined may present opportunities for CO2 storage. Further-more, because coal contains methane, CO2 injection can be used for enhanced coal bed methane (ECBM) recovery. CO2-ECBM has been demonstrated successfully at pilot-scale (e.g., in New Mexico’s San Juan Basin). In suitable gas-bearing coal fields, geologists estimate this process can increase the amount of methane produced to nearly 90% of the gas originally in place, compared with conventional recovery of only 50% by reservoir-pressure depletion alone.17 Field tests by the Southwest Regional Carbon Sequestration Partnership are ongoing.

Regulatory Oversight for CCS

A regulatory framework to provide structure and oversight for CCS activities will be necessary to ensure that CCS fulfills its promise of lowering CO2 emission levels in a manner that is safe and long lasting. At present, some components of CCS, such as EOR injection operations, pipeline transportation, and natural gas storage, are covered under existing regulations. However, regulations directly pertaining to ongoing, long-term CO2 sequestration, including site permitting, monitoring requirements, and liability, have yet to be established.

The U.S. Environmental Protection Agency (EPA) published a first-of-its-kind guidance (UICPG # 83) in March 2007 for permitting underground injection of CO2.18 This guidance offers flexibility for CO2 injections wells in pilot-scale projects for evaluating the practice of CCS. In these instances, the wells may be designated Class V experimental wells.

In October 2007, the EPA announced that it would develop regulations for commercial-scale geologic sequestration injection operations within the existing Underground Injection Control (UIC) program. The UIC program was established by the Safe Water Drinking Act to ensure a consistent and effective permit system for the safe injection of fluids into the subsurface, in a manner that does not endanger current or future underground sources of drinking water. EPA published proposed regulatory changes to the UIC program to cover geologic sequestration of CO2 in July 2008,19 with public comments due by November 24, 2008.

Long-term liability of storage sites will need to be assigned before CCS can become fully commercial. Because CCS activities will be undertaken to serve the public good, as determined by government policy, a number of policy analysts have suggested that the entities performing these activities should be granted a large measure of long-term risk reduction.


17 Ibid.18 “Using the Class V Experimental Technology Well Classification Program for Pilot Geologic Sequestration

Projects—UIC Program Guidance,” March 1, 2007. UICPG #83; http://www.epa.gov/safewater/uic/pdfs/guide_uic_carbonsequestration_final-03-07.pdf

19 http://www.epa.gov/fedrgstr/EPA-WATER/2008/July/Day-25/w16626.htm



Select RD&D Programs for geologic Carbon Sequestration

IEA GHGThe IEA’s GHG RD&D Programme is an international collaborative research vehicle established in 1991 to study technologies to reduce GHG emissions. The program covers all of the main anthropogenic greenhouse gases, but its primary focus is on CO2 reduction. The IEA GHG research effort is supported by 16 member countries, the European Commission, and 10 multi-national sponsors. Principal activities are the evaluation of technologies to reduce GHG emissions, facilitating RD&D efforts, and the promotion and dissemination of results and data through technical reports, general publications, and conferences. The IEA maintains a global CO2 emissions database20 and an RD&D database for carbon capture and sequestration projects.21

Regional Carbon Sequestration Partnerships22 DOE’s Regional Carbon Sequestration Partnerships program consists of seven regional partnerships that involve more than 300 state agencies, universities, and private companies, and span 42 states, three Indian nations, and four Canadian provinces. The Partnerships have begun mapping U.S. and Canadian geologic formations suitable for CO2 storage, along with their proximity to major stationary sources of CO2 emissions. This information has been assembled in the “Carbon Sequestration Atlas of the United States and Canada,”23 and the “National Carbon Explorer,”24 a relational database and geographic information system.

The Partnerships are conducting pilot-scale CO2 injection validation tests across North America in differing geologic formations. These will be followed by larger-volume storage tests, involving storage of quantities of ~1 million metric tons of CO2 or more over a four-year period, along with post-injection monitoring to track the migration of the CO2 in the target formation(s).

20 http://www.co2captureandstorage.info/co2emissiondatabase/co2emissions.htm21 http://www.co2captureandstorage.info/co2db.php22 http://www.fossil.energy.gov/programs/sequestration/partnerships/index.html23 Carbon Sequestration Atlas of the United States and Canada, U.S. DOE-NETL: March 2007. http://www.netl.

doe.gov/publicationstechnologies/carbon_seq/refshelf/atlas/24 http://www.natcarb.org/

Implementing the Advanced Coal RD&D Roadmap


6-�

6 ImPlEmEntIng thE AdVAnCEd COAl Rd&d ROAdmAP

E PRI analyses have concluded that by 2020, it is technically feasible to begin reducing CO2 emissions from the U.S. electricity sector while accommodating continued growth in the demand for power.

By 2030, success in reducing U.S. electric sector emissions could potentially reduce emissions to below 1990 levels, a roughly 30% drop from their projected peak. Comparable emissions reductions, over different timespans, will be needed in other countries.

EPRI economic analyses for the United States show that the most affordable approach to reducing electric sector CO2 emissions is through a robust, diversified portfolio of generation, transmission and distribution, and end-use efficiency technologies.1 This conclusion is also expected to apply worldwide.

However, not all of the necessary technologies have achieved the level of development required for affordable, widespread deployment. Aggressive public- and private-sector RD&D is needed to accelerate commercial introduction and deployment of multiple technologies, including advanced coal-generation and CCS technologies. Industry, government, and other stakeholders will play crucial roles in working together on collaborative RD&D programs to meet this goal. Four broad areas of technological development are needed:

Increased thermodynamic efficiency of PC and CFBC power plants Increased thermodynamic efficiency and reliability of IGCC power plantsImproved emission control systems, including lower-energy-consuming methods for capture of CO2 from coal combustion and gasification power plantsReliable, acceptable methods for transportation and long-term storage of captured CO2.

Capital and operating cost reductions are inherent goals in each of the four areas, as it is critical to their self-sustaining commercial viability. Meeting future CO2 constraints will increase the cost of electricity. However, the magnitude of the increase can be limited through the availability and timely commercial deployment of advanced coal power and CCS technologies.

EPRI Steers a Course to Advanced Coal-Based generation with CCS

EPRI is formulating a major collaborative program of RD&D projects for critical-path CO2-reducing technologies. The aggressive, interrelated schedule for these projects, shown in Figure 6-1, reflects the consensus from experts that the industry objectives are attainable—provided the requisite investments are made. The figure shows pilot programs, which are early deployments of technology on a smaller scale, then demonstration projects, which are larger-scale validations of technology, followed by integration, where the vetted technology is integrated into a commercial plant at full scale. Each of the named projects shown in Figure 6-1 is discussed within this chapter.

By managing risk through staged development and shared costs among collaborative participants, EPRI’s demonstrations enable the type of large efforts needed to usher coal-based technologies into the next phase of commercial deployment.

■

■

■

■

1 Ibid.



Results from EPRI’s PRISM/MERGE analysis2 indicate that achieving significant CO2 emission reductions while keeping electricity affordable very likely will require commercial-scale coal-based generation units operating with 90% CCS between 2020 and 2030.

Advanced Combustion with Post-Combustion Capture

To reach goals for reduction of CO2 and other emissions from coal-combustion power plants, EPRI envisions a series of pilot-scale projects and commercial projects with demonstration elements lead-ing to commercial introduction of technologies incorporating higher steam conditions, improved CO2 capture, and near-zero air pollutant emissions.

The UltraGen Initiative would construct and evaluate three progressively advanced USC PC plants with NZE emission controls and integral CO2 captureThe ComTes-1400 component test facility would be installed as part of UltraGen in an operating boiler simulating 1400°F (760°C) steam conditionsCO2 capture pilots would evaluate use of advanced amines, chilled ammonia, and other sorbents that can reduce the steam and auxiliary power consumption requirements for capturing CO2 from flue gas at atmospheric pressureA continuing series of emissions control technology pilots evaluates stand-alone and integrated environmental control technologies to assist the development of new and refined systems with lower costs and with higher capture efficiencies that eventually approach NZE levelsContinuing and new oxy-combustion pilots will develop knowledge needed to implement oxy-combustion in new and retrofitted PC and CFBC boilersThe potential for use of ITM oxygen for oxy-combustion is being assessed along with the 150 ton-O2/day large-scale pilot, which is primarily focused at IGCC.

■

■

■

■

■

■

Figure 6-1Steps in technology Validation and Scale-Up Projects to meet CURC-EPRI Roadmap goals for Advanced Coal technologies with CCS

2 Ibid.

2005 2010 2015 20205202510201027002 2020

Chilled Ammonia PilotOther Pilots (Post-Combustion

and Oxy-Combustion)

Pilots

Demonstration

Integration

Other Demonstrations

AEP MountaineerSouthern/SSEB Ph. III

UltraGen ProjectsOther Projects(Oxy-Combustion)

IGCC + CCS Projects

Timing Dictates Pilots and Demonstrations be Performed in Parallel

Ion Transport Membrane O2 Scale-up

~2 MW CCS

~20 MW CCS

>200 MW CCS

2005 2010 2015 20205202510201027002 2020 5202510201027002 2020 5202510201027002 2020

Chilled Ammonia PilotOther Pilots (Post-Combustion

and Oxy-Combustion)

Pilots

Demonstration

Integration

Other Demonstrations

AEP MountaineerSouthern/SSEB Ph. III

UltraGen ProjectsOther Projects(Oxy-Combustion)

IGCC + CCS Projects

Timing Dictates Pilots and Demonstrations be Performed in Parallel

Ion Transport Membrane O2 Scale-up

~2 MW CCS

~20 MW CCS

>200 MW CCS



Ultragen

EPRI’s UltraGen program is a shared-risk effort to demonstrate competitive, highly efficient USC PC plants with NZE and CO2 capture through a series of three commercial projects that progressively achieve NZE, higher generating efficiencies and CO2 capture rates as technological advances become available. The progression of performance parameters for the three projects is shown in table 6-1. Results also will be applicable to CFBC power plants.

Parameter Ultragen I Ultragen II Ultragen IIINet output after capture, MW 800 600 600Net output before capture, MW 850 to 900 650 to 700 630 to 670Efficiency before capture, % (HHV) 39 42 to 44 45 to 48Main steam temperature, °F 1120 1290 1400High-temperature material Ferritic High nickel High nickelFlue gas slipstream flow, % (1) 25 (2) 50 or 100 (3) 100 (3)SO2, lb/MBtu (lb/MWh) 0.03 (0.25) 0.01 (0.080) 0.01 (0.080)NOX, lb/MBtu (lb/MWh) 0.03 (0.25) 0.01 (0.080) 0.01 (0.080)Total particulate, lb/MBtu (lb/MWh) 0.010 (0.088) 0.008 (0.064) <0.008 (0.064)Mercury, percent capture 90 Greater than 90 Greater than 90Projected earliest in-service date 2012 2015 2021

Notes: (1) To post-combustion CO2 capture plant (2) To achieve capture of 1 million ton-CO2/year (3) 50 to 60% results in CO2 emissions of around 900 lb/MWh similar to those from a natural gas combined cycle plant. 100% gas stream treatment results in up to 3.8 million ton-CO2/year capture.

table 6-1Performance Parameters for Ultragen I, II, and III

The ultimate technology goal, represented by UltraGen III as shown in Figure 6-2, is main steam conditions of 1400°F (760°C) and 4250–5000 psi (290–345 bar) using high-nickel alloys. The HHV efficiency for UltraGen III before capture will be from 45–48% (7120–7600 Btu/kWh), depending on coal type and system design parameters.

Figure 6-2design Parameters for EPRI’s Ultragen III

600 MWElectricity

100%Gas Flow

630–670 MWAdvanced USC

1400°F (760°C)Nickel-base alloys

45–48% HHV(before capture)

PRB Coal(or low-S, low-Cl

alternate)

(NZE)Stack

~3.5 million tonsof CO2 per year to

pipeline forstorage or EOR

Ultra-CleanEmissionControls

0.01 lb/MBtuSOX, NOX

CommercialCO2 Capture

Unit (90%capture)

90% capture results in CO2

emissions of about 180 lb/MWh (~80 kg/MWh)

>90% HgCapture

600 MWElectricity

100%Gas Flow

630–670 MWAdvanced USC

1400°F (760°C)Nickel-base alloys

45–48% HHV(before capture)

PRB Coal(or low-S, low-Cl

alternate)

(NZE)Stack

~3.5 million tonsof CO2 per year to

pipeline forstorage or EOR

Ultra-CleanEmissionControls

0.01 lb/MBtuSOX, NOX

CommercialCO2 Capture

Unit (90%capture)

90% capture results in CO2

emissions of about 180 lb/MWh (~80 kg/MWh)

>90% HgCapture



A series of EPRI engineering and economic studies will help better understand cost and performance tradeoffs and help refine the details of UltraGen and other demonstration programs. Key study areas include post-combustion capture with improved amines, better integration of the heat sources within a nominal 1100°F (600°C) USC PC plant and within the capture process,3 and evaluation of design and materials options and costs for a nominal 1300°F (700°C) plant design.

Phase 1 of the nominal 1300°F (700°C) USC PC plant study4 estimated efficiency at 42.7% (HHV basis) with subbituminous coal, compared with 36.2% (HHV basis) for a subcritical PC. This corresponds to a CO2 emissions reduction of 18%. The study also identified potential design improvements that could raise efficiency to over 44.5%, increasing CO2 reduction to over 23%.

The high-nickel alloys necessary f or a boiler and steam turbine operating at these higher temperatures are expected to be available to support construction of an UltraGen II demonstration plant within a few years. Emission limits of 0.03 lb/MBtu (~30 mg/Nm3) for SO2 and NOX, and mercury capture efficiency of 90%, are believed to be achievable using currently available technologies.

Post-Combustion CO2 Capture Scale-Up demonstrations

EPRI is participating with industry and government partners in several capture and storage RD&D projects:

EPRI is working with Alstom and We Energies on a 1.7 MWe equivalent CO2 capture pilot at Pleasant Prairie Power Plant in Wisconsin. Initial testing of the chilled-ammonia-based system began in mid-2008. Two large-scale demonstrations will combine CO2 capture from a PC power plant with storage of the collected CO2 in suitable geologic reservoirs—a critical step in the technical development of CCS

The first project will be conducted at AEP’s Mountaineer Plant in West Virginia, where Alstom and AEP will demonstrate Alstom’s chilled ammonia CO2 capture process along with CO2 storage in aquifers that are representative of the regional geology of the Midwest. If successful, AEP plans to host a future scale-up from the 20 MWe pilot to a 200 MWe demonstration unit.Southern Company Services will host the second project, which will demonstrate a different capture process along with storage in a regionally significant geologic reservoir in the southeastern U.S.

Both projects will capture more than 100,000 tons of CO2 annually for multiple years to test the stability and reliability of long-term storage over a significant period.Other processes being evaluated include MHI’s KS-1 solvent processes for CO2 capture and Research Triangle Institute’s dry sodium carbonate process.

■

■

–

–

■

3 An Engineering and Economic Assessment of Post-Combustion CO2 Capture for 1100ºF Ultra-Supercritical Pulver-ized Coal Power Plant Applications, Phase I Report, Tasks 1 and 2, EPRI, Palo Alto, CA: March 2008. 014924.

4 Engineering and Economic Evaluation of 1300 F Series Ultra-Supercritical Pulverized Coal Power Plants: Phase 1, EPRI, Palo Alto, CA: March 2008. 10149��.



Oxy-Combustion for PC and CFBC

EPRI is tracking5 oxy-combustion development work by Alstom, Babcock & Wilcox, Foster Wheeler, Praxair, and others, and has developed a preliminary roadmap for oxy-combustion RD&D needs.6 Key focus areas and developments needed in the near term (<10 years) include:

Minimization of excess air (possibly with oxygen lances at burner tip) and in-leakage to lower CO2 contaminants, the cost of final CO2 purification, and to reduce the boiler cross-section, recycle flue gas (RFG) duct cross section, and fan size NOX impact on the purification process; ability to remove remaining NOX without use of SCR Use of cyclone burners, which can reduce costs of coal preparation and reduce ash foulingConfirm that low N2 content in high-purity oxygen minimizes production of thermal NOX and that this is not offset by higher flame temperatureHeat integration of the boiler, ASU, and purification and compression stages to maximize energy utilization. This would include recovery of compression heat to preheat feedwater and use of ASU nitrogen for coal drying, especially with low-rank fuels.Use of tubular heat exchangers to eliminate inefficiency due to air heater bypass and recirculationDevelopment of alternatives to the cryogenic purification stageStudy of approaches for SO2 and SO3/H2SO4 control to prevent high levels in RFG, protect ducting and compression equipment, and meet CO2 product specificationsEvaluation of approaches for drying RFG to increase adiabatic flame temperature, improve in-furnace heat transfer, and reduce attemperation requirements, along with impact on waterwall materials requirements, unit operations, ash properties, and ESP performance Evaluation of operational characteristics, including startup, turndown, and load-following.

Over the longer term, improving energy efficiency and economic performance will require use of a lower-energy oxygen separation process such as ITM.

Alstom currently has a 3 MWt CFBC test unit operating with oxy-combustion in Windsor, Connecticut, and is working with Vattenfall on the 2008 startup of a 30 MWt pilot plant in Germany. In 2007, B&W began oxy-combustion testing at its 30 MWt test boiler in Alliance, Ohio, and prepared a preliminary design for a now-deferred 300 MW SCPC oxy-fuel boiler option for SaskPower. For CFBC, Alstom estimates that oxy-combustion could reduce unit size and cost substantially compared with an air-fired CFBC unit (–50% of plan area, –44% of volume, –35% of weight, and –32% of cost).7

IgCC with CO2 Capture and Storage

To accelerate IGCC technology with CCS through the critical development stages, EPRI is formulating a three-project program to demonstrate integrated operation of commercial IGCC power plants with CO2 capture, compression, injection, and monitoring.

■

■

■

■

■

■

■

■

■

■

5 Review of CO2-Capture Development Activities for Coal-Fired Power Generation Plants, EPRI, Palo Alto, CA: 2007: 1012239.

6 Wheeldon, J. and Dillon, D. (EPRI), “EPRI Perspective on Oxy-Combustion RD&D Needs,” EPRI CoalFleet General Meeting, Akron, Ohio, November 6, 2007

7 Bozzuto, C. (for Alstom) “Advanced Combustion - Input on Oxy-Firing (Vattenfall Demo Status), context to other CO2 Capture Technologies, and Advances in Environmental Control Technology,” EPRI CoalFleet General Meet-ing, Greenville, South Carolina, July 26, 2007



IgCC with CCS Project 1: The first project will take place at an existing plant and include CO2 capture from the unshifted syngas. This would achieve a 10-20% reduction in CO2 emissions and provide a sufficient quantity of CO2 (150,000-350,000 metric tons per year) for a large-scale geologic storage test. IGCC with CCS Project 1 represents the quickest path to demonstration of CCS from an operating facility, with the potential to be on-line by 2010-2011.IgCC with CCS Project 2: The second project adds equipment to facilitate a 40–60% reduction in CO2 emissions. This approach will meet current California and Washington state GHG standards of 1100 lb-CO2/MWh (500 kg-CO2/MWh) for new base-load power contracts and produce 1–2 million metric tons of CO2 per year for storage in a suitable geologic formation or use in EOR. IGCC with CCS Project 2 will demonstrate the ability of IGCC to match the CO2 emissions of a natural gas combined cycle plant without modifications to the existing gas turbine and could be on-line by 2014.IgCC with CCS Project 3: The third and final project will be a new plant designed to include 80-90% CCS. Because this level of capture will result in a fuel gas with high hydrogen content, demonstration will be most cost-effective on a new plant designed to handle the increased fuel demands of a hydrogen-fired gas turbine. Working with a new plant will allow use of advanced technologies that may enhance plant efficiency in addi-tion to improving CO2 capture and compression efficiency. IGCC with CCS Project 3 will result in 2–4 million metric tons of CO2 per year. By collaborating with projects already under development, this demonstration could be on-line by 2016.

Scale-Up and Integration of Itm Oxygen Production To support the development of lower-cost oxygen production for IGCC (and potentially oxy-combustion), EPRI has teamed with DOE and an Air Products to design, construct, and test a 150 ton-O2 per day (tpd) unit integrated with a Siemens ~20 MW industrial gas turbine. This effort builds upon the DOE-funded operation of a 5-tpd pilot unit. The scaled-up unit will provide essential information relating to the design, integration, and operation of a first-of-kind integrated ITM/gas turbine unit. The results will allow the indus-try to evaluate the role ITM technology can play more fully in producing oxygen more cost-effectively.

the Resources necessary for SuccessDeveloping and deploying the advanced coal power and CCS technologies needed for coal-fired power plants to achieve major, affordable CO2 emission reductions will require sustained investment in RD&D at near-unprecedented levels. EPRI and others have estimated that an additional expenditure of approximately $10 billion will be required from 2008–17.8 Over the next 20 years, it is expected that a total RD&D invest-ment of roughly $19 billion will be required for coal-based technologies. Although this may seem high, the PRISM and MERGE analyses show that the absence of advanced coal power and CCS technologies leads to higher costs for CO2 abatement and, ultimately, greater impact on the economies around the world.

EPRI helps Shape the Future

Through its PRISM/MERGE analyses, EPRI has identified a significant role that advanced coal power plants with carbon capture and storage can play in reducing GHG emissions while continuing to supply affordable electricity. The technological advances that would allow coal-based power plants to operate in a low-carbon future have been identified and the path to their commercial deployment is understood.

Collectively, EPRI’s technology demonstrations represent the type of “big steps” needed to deploy advanced coal-based generation with CCS widely after 2020, to help meet society’s increased demand for affordable, environmentally responsible electric power.

■

■

■

8 The MIT Future of Coal report estimates a 10-year RD&D funding need of $8-8.5 billion.

Electric Power Research Institute3420 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

The Electric Power Research Institute (EPRI), with major

locations in Palo Alto, California; Charlotte, North Carolina; and

Knoxville, Tennessee, was established in 1973 as an independent,

nonprofit center for public interest energy and environmental

research. EPRI brings together members, participants, the Institute’s

scientists and engineers, and other leading experts to work

collaboratively on solutions to the challenges of electric power. These

solutions span nearly every area of electricity generation, delivery,

and use, including health, safety, and environment. EPRI’s members

represent over 90% of the electricity generated in the United States.

International participation represents nearly 15% of EPRI’s total

research, development, and demonstration program.

Together...Shaping the Future of Electricity

Export Control Restrictions

Access to and use of EPRI Intellectual Property is granted with the

specifi c understanding and requirement that responsibility for ensur-

ing full compliance with all applicable U.S. and foreign export laws

and regulations is being undertaken by you and your company. This

includes an obligation to ensure that any individual receiving access

hereunder who is not a U.S. citizen or permanent U.S. resident is

permitted access under applicable U.S. and foreign export laws and

regulations. In the event you are uncertain whether you or your com-

pany may lawfully obtain access to this EPRI Intellectual Property, you

acknowledge that it is your obligation to consult with your company’s

legal counsel to determine whether this access is lawful. Although

EPRI may make available on a case-by-case basis an informal as-

sessment of the applicable U.S. export classifi cation for specifi c EPRI

Intellectual Property, you and your company acknowledge that this

assessment is solely for informational purposes and not for reliance

purposes. You and your company acknowledge that it is still the ob-

ligation of you and your company to make your own assessment

of the applicable U.S. export classifi cation and ensure compliance

accordingly. You and your company understand and acknowledge

your obligations to make a prompt report to EPRI and the appropriate

authorities regarding any access to or use of EPRI Intellectual Prop-

erty hereunder that may be in violation of applicable U.S. or foreign

export laws or regulations.

© 2008 Electric Power Research Institute (EPRI), Inc. All rights reserved. Electric Power Research Institute, EPRI, and TOGETHER...SHAPING THE FUTURE OF ELECTRICITY are registered service marks of the Electric Power Research Institute, Inc.

Printed on recycled paper in the United States of America

Program:

CoalFleet for Tomorrow – Future Coal Generation Options

1016877

Advanced Coal Power Systems with CO2 Capture: EPRI's CoalFleet for Tomorrow Vision · ·...

Documents

Transcript of Advanced Coal Power Systems with CO2 Capture: EPRI's CoalFleet for Tomorrow Vision · ·...