Preface

**Section 3 Soil Carbon Sequestration 149**

Deem

**VI** Contents

**Perennial Grass Systems 151**

**Section 4 Carbon Storage and Utilization 191**

**Utilization 193**

**Section 5 Economics of CCS 239**

Chapter 9 **CO2 Conversion to Chemicals and Fuel for Carbon**

Wonjun Cho, Hyejin Yu and Yonggi Mo

Chapter 10 **Challenges Associated with CO2 Sequestration and**

Roshani, Garrett Babb and Wesley Herron

Chapter 11 **Economics of Carbon Capture and Storage 241** John C. Bergstrom and Dyna Ty

**Hydrocarbon Recovery 209**

Chapter 7 **Maximizing Soil Carbon Sequestration: Assessing Procedural Barriers to Carbon Management in Cultivated Tropical**

Chapter 8 **Relationship Between Mineral Soil Surface Area and Carbon Sequestration Rate for Biosolids Added to Soil 171** Dongqi Wen, Wenjuan Zhai and Kenneth E. Noll

Jon M. Wells, Susan E. Crow, Manyowa N. Meki, Carlos A. Sierra, Kimberly M. Carlson, Adel Youkhana, Daniel Richardson and Lauren

Rouzbeh Ghanbarnezhad Moghanloo, Xu Yan, Gregory Law, Soheil

Carbon capture and storage (CCS) has been highlighted during the last decade as a practical way of dealing with anthropogenic CO2 that should be removed from the atmosphere at least to the level of 450 ppm. Also CCS is considered as the only practical way in sequester‐ ing the huge CO2 amount with a reasonable cost at this moment. But, CCS has not reached the full commercial level yet due to the high cost involved as well as due to many uncertain environmental and legal limitations. Hopefully some revolutionary CO2 utilization methods that can replace the storing of the CO2 underground can solve all the cost and huge volume issues. Unfortunately, the CCS technology itself had not attained the acceptable cost goal that most technical milestones in many developed countries have targeted as less than US \$20–30 per ton in capturing CO2. Most importantly, cost incentives for CCS by carbon tax or other similar systems have not been implemented globally yet. The CCS process typically requires a heavy instrumentation with a high energy penalty in capturing and storing facili‐ ties. After the Paris Agreement on reducing global warming in December 2015, reducing CO2 in every industrial sector becomes a key task that can guarantee the continuation of business in the long run. Industry waits the reliable and reasonable cost methods in elimi‐ nating CO2 that can continue their business, and this is the right time to provide the techni‐ cal solution in CO2 problems.

Scientific evidence from IPCC, etc., clearly indicates that carbon dioxide is a major contribu‐ ting source to climate change. Among the CO2-generating sources, fossil fuel power genera‐ tion produces almost a third of the global CO2 emission. Since the social infrastructure has already evolved to use fossil fuels that can provide a relatively cheap energy, it is not an easy task to eliminate suddenly the use of them. Especially in developing countries, coal will re‐ main as a cheap and reliable energy source, probably till the 2050s at least. In the long run, renewable energy should replace the fossil fuel and open the era of no-CO2 emission. The goal is very clear. We should replace the energy source that can minimize the generation of CO2 or store CO2 underground until a more pragmatic solution appears. Unfortunately, it requires a heavy burden in cost for individuals and investment for the newer infrastructure. Without technical breakthroughs in CO2 reducing, sequestering, storing, and converting methods, any enforced endeavor will yield a futile resonance in each person and companies even with mo‐ rally justified causes. The CCS can work as a bridge before the no-CO2 era of the future by applying to large-scale CO2-emitting facilities. Already there are many success stories that exhibited profitable CCS operation by connecting to enhanced oil recovery (EOR).

There is still the question whether CO2 really needs to be captured and sequestered. Even today many people insist that the recent climate change is just one of the climate cycles that happened throughout the earth's life span. In Cambrian period of about 500 million years

ago, CO2 concentration had reached 7,000 ppm compared to the current CO2 target of 450 ppm that IPCC intends to control. But, most land life forms had started about 400 million years ago which was even before the highest CO2 level at ca. 500 million years ago. Thus the high CO2 concentration of 7,000 ppm appears not to be applicable in the argument. The im‐ portant thing is that the CO2 concentration has never reached above 300 ppm during the last 400 million years in that life forms flourish. In the year 2012–2013, the earth's CO2 level has passed 400 ppm level and continues to rise. Many reports say that the 400 ppm level is the highest during the last 3–20 million years. With or without consenting the impact of CO2 level on climate change, if a very faint probability of the fatal climate consequences exists as many data forecast, we have to do something to prevent the worst scenario; otherwise, the world ecosystem might fall apart to the level we cannot do anything anymore.

The 1 ppm CO2 in global atmosphere means 2.13 gigatons of carbon. The current largest CCS plant can sequester 3 million CO2 tons per year, which is the amount of CO2 emitted from just one 500 MW coal-fired power plant. This suggests that there is a long way for CCS to yield a meaningful impact on the global CO2 issues, unless the technology achieves some kind of standardized form in reducing cost and applies at least hundreds of it a year. Con‐ sidering the immense volume of CO2 amount that CCS has to deal with, most of the CCS technologies still contribute too small portion of the CO2 problem.

The CCS was a big issue in major economies of the world during the years 2005–2008, pre‐ cipitating by the recommendation (G8 Hokkaido Toyako Summit Leaders Declaration) at the G8 summit meeting held on July 8, 2008, at Hokkaido in Japan. At the Declaration, CCS was mentioned as "launching of 20 large-scale CCS demonstration projects globally by 2010, taking into account various national circumstances, with a view to beginning broad deploy‐ ment of CCS by 2020." I had participated personally in the preparation of workshops to reach this Declaration from the IEA/CSLF Assessment Workshop in Oslo 2007 to the 2008 Major Economies Meeting in Hawaii. The CCS had been highlighted as a key solution for tackling CO2 issues in the early 2000s, but it appears to lose some passion by the lack of progress in technical developments and in commercial success stories other than EOR.

Renewable energies without any pollutants or CO2 emission should be the way of the fu‐ ture, but it might take several decades with current steps of technical and political stagna‐ tion in dealing with climate change. Then, we have to go back to basics, starting from finding a solution in small steps. Soil carbon sequestration that is included as a section of the book is a good example even though it will never give a big impact solution in CCS, but it can give a grass root impact that every individual can contribute a small token in tackling the CO2 issue. Since the CCS processes involve many energy consuming steps like CO2 sepa‐ ration to higher concentrations, CO2 compression, etc., there are many potentials in reducing the energy penalty by advanced technologies. The CCS technology desperately needs far newer ideas and breakthroughs that can separate earlier attempts to capture and sequester CO2 through improving, modifying, and switching the known principles. This book tries to give some insight into developing an urgently needed technical breakthrough through the recent advances in CCS research, in addition to the available small steps like soil carbon se‐ questration. Another recent direction dealing with climate change focuses on carbon utiliza‐ tion rather than the direct carbon capture and storage. Conceptually, converting CO2 to chemicals or fuels should be more beneficial to environment because it can substitute the

fossil fuels like oil, natural gas, or coal. Carbon utilization is considered as a continuation of CCS, and one chapter is included in the book.

ago, CO2 concentration had reached 7,000 ppm compared to the current CO2 target of 450 ppm that IPCC intends to control. But, most land life forms had started about 400 million years ago which was even before the highest CO2 level at ca. 500 million years ago. Thus the high CO2 concentration of 7,000 ppm appears not to be applicable in the argument. The im‐ portant thing is that the CO2 concentration has never reached above 300 ppm during the last 400 million years in that life forms flourish. In the year 2012–2013, the earth's CO2 level has passed 400 ppm level and continues to rise. Many reports say that the 400 ppm level is the highest during the last 3–20 million years. With or without consenting the impact of CO2 level on climate change, if a very faint probability of the fatal climate consequences exists as many data forecast, we have to do something to prevent the worst scenario; otherwise, the

The 1 ppm CO2 in global atmosphere means 2.13 gigatons of carbon. The current largest CCS plant can sequester 3 million CO2 tons per year, which is the amount of CO2 emitted from just one 500 MW coal-fired power plant. This suggests that there is a long way for CCS to yield a meaningful impact on the global CO2 issues, unless the technology achieves some kind of standardized form in reducing cost and applies at least hundreds of it a year. Con‐ sidering the immense volume of CO2 amount that CCS has to deal with, most of the CCS

The CCS was a big issue in major economies of the world during the years 2005–2008, pre‐ cipitating by the recommendation (G8 Hokkaido Toyako Summit Leaders Declaration) at the G8 summit meeting held on July 8, 2008, at Hokkaido in Japan. At the Declaration, CCS was mentioned as "launching of 20 large-scale CCS demonstration projects globally by 2010, taking into account various national circumstances, with a view to beginning broad deploy‐ ment of CCS by 2020." I had participated personally in the preparation of workshops to reach this Declaration from the IEA/CSLF Assessment Workshop in Oslo 2007 to the 2008 Major Economies Meeting in Hawaii. The CCS had been highlighted as a key solution for tackling CO2 issues in the early 2000s, but it appears to lose some passion by the lack of progress in technical developments and in commercial success stories other than EOR.

Renewable energies without any pollutants or CO2 emission should be the way of the fu‐ ture, but it might take several decades with current steps of technical and political stagna‐ tion in dealing with climate change. Then, we have to go back to basics, starting from finding a solution in small steps. Soil carbon sequestration that is included as a section of the book is a good example even though it will never give a big impact solution in CCS, but it can give a grass root impact that every individual can contribute a small token in tackling the CO2 issue. Since the CCS processes involve many energy consuming steps like CO2 sepa‐ ration to higher concentrations, CO2 compression, etc., there are many potentials in reducing the energy penalty by advanced technologies. The CCS technology desperately needs far newer ideas and breakthroughs that can separate earlier attempts to capture and sequester CO2 through improving, modifying, and switching the known principles. This book tries to give some insight into developing an urgently needed technical breakthrough through the recent advances in CCS research, in addition to the available small steps like soil carbon se‐ questration. Another recent direction dealing with climate change focuses on carbon utiliza‐ tion rather than the direct carbon capture and storage. Conceptually, converting CO2 to chemicals or fuels should be more beneficial to environment because it can substitute the

world ecosystem might fall apart to the level we cannot do anything anymore.

technologies still contribute too small portion of the CO2 problem.

VIII Preface

The book consists of five sections: CCS in coal power plants, carbon capture methods, soil carbon sequestration, carbon storage and utilization, and economics of CCS. The first section tells about some of the recent advances in dealing with CO2 issues by the coal power industry. The second section illustrates the most critical components in CCS, which are CO2-capturing methods involving absorbents, membranes, and biomaterials. The third section deals about the soil carbon sequestration that can be viewed as a meaningful CO2 study that starts with very minute step but can end with huge impact on agricultural cultivation techniques. The fourth section contains two chapters, one on the carbon utilization by conversion to chemicals and fuels and the other on the CO2 underground storage with actual site data. Finally, the fifth section talks about the basic economic principles that should be discussed in CCS.

Personally, I had read all the details of each chapter and acted as a critical reviewer to make a better quality book during the last nine months. I hope this book can serve as a small cor‐ nerstone in finding new concepts and more reliable technologies in CCS and CO2 utilization.

I thank all participating authors for contributing their chapters and for helping in revising where needed. Also, I really thank Ms. Martina Usljebrka who had helped me in every edit‐ ing step throughout the whole nine months in 2016.

> **Yongseung Yun** Institute for Advanced Engineering, Yongin, Republic of Korea

**CCS in Coal Power Plants**

**Provisional chapter**

#### **Development of a State-of-the-Art Dry Low NOx Gas Turbine Combustor for IGCC with CCS Development of a State-of-the-Art Dry Low NOx Gas Turbine Combustor for IGCC with CCS**

Tomohiro Asai, Yasuhiro Akiyama and Satoschi Dodo Satoschi Dodo Additional information is available at the end of the chapter

Tomohiro Asai, Yasuhiro Akiyama and

Additional information is available at the end of the chapter

http://dx.doi.org/10.5772/66742

#### **Abstract**

The successful development of the coal-based integrated gasification combined cycle (IGCC) with carbon capture and storage (CCS) requires gas turbines capable of achieving dry low nitrogen oxide (NOx) combustion of hydrogen-rich syngas fuels for low emissions and high plant efficiency. This chapter describes the development of a "multi-cluster combustor" as a state-of-the-art dry low NOx combustor for hydrogen-rich syngas fuels. The combustor consists of multiple clusters of pairs of one fuel nozzle and one air hole that are installed coaxially. The essence of the design concept is the integration of two key technologies: rapid mixing of fuel and air for low NOx and flame lifting for flashbackresistant combustion. The combustor has been developed in three steps: burner development, combustor development, and feasibility demonstration for practical plants. The combustor was tested with a practical syngas fuel in a multi-can combustor configuration in an IGCC pilot plant in the final step. The combustor achieved the dry low NOx combustion of the syngas fuel in the pilot plant and the test results demonstrated the feasibility for achieving dry low NOx combustion of the syngas fuel in practical plants.

**Keywords:** integrated gasification combined cycle (IGCC), carbon capture and storage (CCS), gas turbine, dry low NOx combustor (DLNC), multi-cluster combustor, hydrogen-rich syngas fuels

#### **1. Introduction**

Coal is a vital energy source for power generation with over 40% of the electricity produced worldwide stemming from coal [1]. Coal is able to ensure energy supply stability and security due to its low cost, abundant reserves, and worldwide availability. However, conventional pulverized coal–fired power plants are the most carbon dioxide (CO<sup>2</sup> )-intensive source of

© 2016 The Author(s). Licensee InTech. This chapter is distributed under the terms of the Creative Commons Attribution License (http://creativecommons.org/licenses/by/3.0), which permits unrestricted use, distribution, and reproduction in any medium, provided the original work is properly cited. © 2017 The Author(s). Licensee InTech. This chapter is distributed under the terms of the Creative Commons Attribution License (http://creativecommons.org/licenses/by/3.0), which permits unrestricted use, distribution, and reproduction in any medium, provided the original work is properly cited.

power generation. An effective method for cutting CO<sup>2</sup> emissions from coal-fired power plants is to employ a coal-based integrated gasification combined cycle (IGCC). IGCC plants release less CO<sup>2</sup> than conventional pulverized coal–fired power plants because of their higher plant efficiency. IGCC also possesses the capability to capture and store CO<sup>2</sup> before combustion [precombustion carbon capture and storage (CCS)]. CCS technology suppresses the release of CO<sup>2</sup> into the atmosphere by capturing and storing CO<sup>2</sup> emissions from thermal power plants. A report by the Intergovernmental Panel on Climate Change (IPCC) estimates that an IGCC plant with CCS might cut CO<sup>2</sup> emissions by about 80–90% compared with an IGCC plant without CCS [2]. However, the major technical hurdle with CCS is that CCS decreases plant efficiency because of the additional energy for capture and storage. The report by the IPCC estimates that a CCS-equipped IGCC plant might need 14–25% more energy than an IGCC plant of equivalent output without CCS [2]. Improving the efficiency of CCS-equipped IGCC plants is a key to the successful combination of the two technologies. In order to achieve high plant efficiency and low emissions, a gas turbine in IGCC plants requires a diluent-free ("dry"), low NOx combustor. This chapter describes the development of a state-of-the-art dry low NOx combustor intended for CCS-equipped IGCC plants.

#### **2. CCS-equipped oxygen-blown IGCC technology and technical hurdles with gas turbines**

#### **2.1. Overview**

Coal-based IGCC technology with CCS converts coal to syngas, removes CO<sup>2</sup> from the syngas, and generates electric power in the combined cycle by utilizing the produced hydrogen-rich syngas as gas turbine fuel. An oxygen-blown IGCC plant with a precombustion CCS system is composed of five key components: an air separation unit (ASU), a gasifier, a syngas cleanup unit, a CCS system, and a combined cycle unit. A schematic diagram of the plant is shown in **Figure 1**.

The plant generates electric power through the process as follows. The ASU separates air into oxygen (O<sup>2</sup> ) and nitrogen (N<sup>2</sup> ). The gasifier converts coal to raw syngas by reacting it with oxidant (oxygen). The gasifier employs oxygen as the oxidant, and this type of gasification is referred to as "oxygen-blown." This chapter addresses oxygen-blown IGCC technology. The syngas cleanup unit removes impurities, such as particulate matter, sulfur, and ammonia from the raw syngas, producing a clean syngas consisting mainly of carbon monoxide (CO) and hydrogen (H<sup>2</sup> ). A shift reactor of the CCS system converts CO in the clean syngas to H<sup>2</sup> and CO<sup>2</sup> by a water-gas shift reaction, producing a shifted syngas. A CO<sup>2</sup> capture unit removes CO<sup>2</sup> from the shifted syngas, thus producing a hydrogen-rich syngas. The hydrogenrich syngas is supplied to a gas turbine as fuel. A gas turbine combustor burns the syngas, and the combustion gas operates a turbine, which, in turn, generates electric power. A heat recovery steam generator (HRSG) produces steam using the waste heat of exhaust gas from the gas turbine, and sends the steam to the gasifier in order to produce the raw syngas and to a steam turbine in order to generate additional power. The gas turbine combustors are required to operate on oil fuel as the startup fuel at ignition and during part load in order to provide the HRSG with the waste heat until the syngas fuel is supplied to the gas turbine [3].

Development of a State-of-the-Art Dry Low NOx Gas Turbine Combustor for IGCC with CCS http://dx.doi.org/10.5772/66742 5

**Figure 1.** Schematic diagram of oxygen-blown IGCC plant with precombustion CCS system.

#### **2.2. Technical hurdles with gas turbines**

power generation. An effective method for cutting CO<sup>2</sup>

an IGCC plant with CCS might cut CO<sup>2</sup>

4 Recent Advances in Carbon Capture and Storage

less CO<sup>2</sup>

of CO<sup>2</sup>

**with gas turbines**

**2.1. Overview**

oxygen (O<sup>2</sup>

to H<sup>2</sup>

(CO) and hydrogen (H<sup>2</sup>

and CO<sup>2</sup>

removes CO<sup>2</sup>

) and nitrogen (N<sup>2</sup>

is to employ a coal-based integrated gasification combined cycle (IGCC). IGCC plants release

[precombustion carbon capture and storage (CCS)]. CCS technology suppresses the release

plants. A report by the Intergovernmental Panel on Climate Change (IPCC) estimates that

plant without CCS [2]. However, the major technical hurdle with CCS is that CCS decreases plant efficiency because of the additional energy for capture and storage. The report by the IPCC estimates that a CCS-equipped IGCC plant might need 14–25% more energy than an IGCC plant of equivalent output without CCS [2]. Improving the efficiency of CCS-equipped IGCC plants is a key to the successful combination of the two technologies. In order to achieve high plant efficiency and low emissions, a gas turbine in IGCC plants requires a diluent-free ("dry"), low NOx combustor. This chapter describes the development of a state-of-the-art dry

**2. CCS-equipped oxygen-blown IGCC technology and technical hurdles** 

and generates electric power in the combined cycle by utilizing the produced hydrogen-rich syngas as gas turbine fuel. An oxygen-blown IGCC plant with a precombustion CCS system is composed of five key components: an air separation unit (ASU), a gasifier, a syngas cleanup unit, a CCS system, and a combined cycle unit. A schematic diagram of the plant is shown in **Figure 1**. The plant generates electric power through the process as follows. The ASU separates air into

oxidant (oxygen). The gasifier employs oxygen as the oxidant, and this type of gasification is referred to as "oxygen-blown." This chapter addresses oxygen-blown IGCC technology. The syngas cleanup unit removes impurities, such as particulate matter, sulfur, and ammonia from the raw syngas, producing a clean syngas consisting mainly of carbon monoxide

by a water-gas shift reaction, producing a shifted syngas. A CO<sup>2</sup>

rich syngas is supplied to a gas turbine as fuel. A gas turbine combustor burns the syngas, and the combustion gas operates a turbine, which, in turn, generates electric power. A heat recovery steam generator (HRSG) produces steam using the waste heat of exhaust gas from the gas turbine, and sends the steam to the gasifier in order to produce the raw syngas and to a steam turbine in order to generate additional power. The gas turbine combustors are required to operate on oil fuel as the startup fuel at ignition and during part load in order to provide

the HRSG with the waste heat until the syngas fuel is supplied to the gas turbine [3].

from the shifted syngas, thus producing a hydrogen-rich syngas. The hydrogen-

). The gasifier converts coal to raw syngas by reacting it with

). A shift reactor of the CCS system converts CO in the clean syngas

Coal-based IGCC technology with CCS converts coal to syngas, removes CO<sup>2</sup>

efficiency. IGCC also possesses the capability to capture and store CO<sup>2</sup>

into the atmosphere by capturing and storing CO<sup>2</sup>

low NOx combustor intended for CCS-equipped IGCC plants.

than conventional pulverized coal–fired power plants because of their higher plant

emissions from coal-fired power plants

emissions by about 80–90% compared with an IGCC

emissions from thermal power

before combustion

from the syngas,

capture unit

The implementation of IGCC technology with CCS poses significant challenges to gas turbine combustors owing to properties of hydrogen-rich syngas fuels. **Figure 2** shows the variation in fuel compositions against the carbon capture rate for typical syngas fuels [4]. The fuel compositions vary widely depending on the carbon capture rate. As the carbon capture rate increases from 0 to 90%, as a result of the conversion of CO to H<sup>2</sup> and CO<sup>2</sup> in the shift reactor, H2 concentration increases widely from approximately 25 to over 80 vol%. Some properties of hydrogen, specifically its higher flame speed, lower ignition energy, and broader flammability limits compared with conventional gas turbine fuels (e.g., natural gas), increase the risk of flashback and autoignition [5].

The challenges posed by these properties of hydrogen require advanced combustion technologies for hydrogen-rich syngas fuels. Conventional gas turbine combustors are incapable of achieving low NOx emissions and high plant efficiency for hydrogen-rich syngas fuels. **Figure 3** summarizes technical hurdles with their use. The combustors are broadly classified into two types: premixed combustors and diffusion-flame combustors. Conventional premixed combustors are capable of achieving low NOx by supplying premixed fuel-air mixtures because they maintain low local flame temperatures. However, premixed combustors burning hydrogen-rich fuels are prone to flashback into their large premixing section because they are highly tuned to operate on low-flame-speed fuels like natural gas. This flashback tendency characteristic hinders the application of premixed combustion technology to

**Figure 2.** Fuel compositions of typical syngas fuels in oxygen-blown IGCC with CCS.


**Figure 3.** Technical hurdles with conventional combustors.

hydrogen-rich syngas fuels in IGCC. In contrast, conventional diffusion-flame combustors are capable of achieving flashback-resistant combustion of hydrogen-rich fuels by supplying fuel and air separately into their combustion chamber. However, diffusion-flame combustors are incapable of achieving high plant efficiency because they require additional energy to inject a diluent, such as water, steam, or nitrogen, into the combustion zone in order to suppress the increased NOx emissions due to high local flame temperatures. IGCC plants have thus far employed diffusion-flame combustors at the expense of decreased plant efficiency in order to achieve flashback-resistant combustion of hydrogen-rich fuels.

Development of a State-of-the-Art Dry Low NOx Gas Turbine Combustor for IGCC with CCS http://dx.doi.org/10.5772/66742 7

**Figure 4.** Advantages of dry low NOx combustor.

A solution to these hurdles is to develop state-of-the-art technologies for diluent-free (dry), low NOx combustion of hydrogen-rich fuels. **Figure 4** compares the advantages of dry low NOx combustors (DLNC) with those of diffusion-flame combustors. Diffusion-flame combustors decrease NOx by injecting diluents. This method is referred to as "wet control." However, injection of diluents decreases plant efficiency. In contrast, dry low NOx combustors achieve low NOx diluent-free (dry) combustion, thereby increasing plant efficiency. The successful implementation of IGCC technology with CCS requires state-of-the-art technologies for the dry low NOx combustion of hydrogen-rich syngas fuels that can achieve both lower NOx emissions and higher plant efficiency.

Many research groups and gas turbine manufacturers have been developing dry low NOx combustion technologies for hydrogen-rich fuels [6–18]. Technologies described in the literature include a multi-tube mixer fuel nozzle [7], a triple-fuel syngas burner [8], a MBtu EV burner [9], a low-swirl injector [10], a flameless-oxidation burner [11], a micro-mixing leanpremix injector [12], a DLN micromix burner [13, 14], a DLE combustor with supplemental burners [15], a lean premixed swirl-stabilized hydrogen burner with axial air injection [16], a rich catalytic hydrogen injector [17], and a rich/lean staged burner [18]. This chapter describes the development of a state-of-the-art dry low NOx combustor for hydrogen-rich syngas fuels in CCS-equipped oxygen-blown IGCC plants.

#### **3. A state-of-the-art dry low NOx combustor**

#### **3.1. Combustor configuration**

hydrogen-rich syngas fuels in IGCC. In contrast, conventional diffusion-flame combustors are capable of achieving flashback-resistant combustion of hydrogen-rich fuels by supplying fuel and air separately into their combustion chamber. However, diffusion-flame combustors are incapable of achieving high plant efficiency because they require additional energy to inject a diluent, such as water, steam, or nitrogen, into the combustion zone in order to suppress the increased NOx emissions due to high local flame temperatures. IGCC plants have thus far employed diffusion-flame combustors at the expense of decreased plant efficiency in order to

achieve flashback-resistant combustion of hydrogen-rich fuels.

**Figure 3.** Technical hurdles with conventional combustors.

6 Recent Advances in Carbon Capture and Storage

**Figure 2.** Fuel compositions of typical syngas fuels in oxygen-blown IGCC with CCS.

**Figure 5** shows the configuration of the state-of-the-art dry low NOx combustor [19]. The combustor consists of multiple fuel nozzles and multiple air holes. The key elements of the combustor each consist of one fuel nozzle and one air hole that are installed coaxially. A cluster of key elements constitutes one burner, which forms one flame. The air holes are embedded in one plate. Multiple burners constitute a can combustor, and several can combustors are installed on a gas turbine. The combustor is classified as a multi-can type [20]. Hereafter, this burner is referred to as a "cluster burner," and this combustor is referred to as a "multi-cluster combustor."

An individual multi-cluster combustor consists of multiple cluster burners, a cylindrical liner, a cylindrical casing, and an end cover. **Figure 6** illustrates a cross-sectional diagram of an individual multi-cluster combustor. The cluster burners are installed on the end cover equipped with fuel supplying systems. The liner is mounted concentrically inside the casing. **Figure 7** illustrates a detailed diagram of the cluster burners. The burners consist of one pilot burner at the center and several identical main burners surrounding the pilot burner. The combustor forms seven individual flames, each of which is anchored to the corresponding burner. The combustor assigns the function of maintaining operational stability to the pilot burner and the function of maintaining low NOx operation to the main burners.

**Figure 5.** Configuration of the state-of-the-art dry low NOx combustor for hydrogen-rich syngas fuels.

**Figure 6.** Cross-sectional schematic diagram of individual multi-cluster combustor.

Development of a State-of-the-Art Dry Low NOx Gas Turbine Combustor for IGCC with CCS http://dx.doi.org/10.5772/66742 9

**Figure 7.** Detailed diagram of cluster burners.

in one plate. Multiple burners constitute a can combustor, and several can combustors are installed on a gas turbine. The combustor is classified as a multi-can type [20]. Hereafter, this burner is referred to as a "cluster burner," and this combustor is referred to as a "multi-cluster

An individual multi-cluster combustor consists of multiple cluster burners, a cylindrical liner, a cylindrical casing, and an end cover. **Figure 6** illustrates a cross-sectional diagram of an individual multi-cluster combustor. The cluster burners are installed on the end cover equipped with fuel supplying systems. The liner is mounted concentrically inside the casing. **Figure 7** illustrates a detailed diagram of the cluster burners. The burners consist of one pilot burner at the center and several identical main burners surrounding the pilot burner. The combustor forms seven individual flames, each of which is anchored to the corresponding burner. The combustor assigns the function of maintaining operational stability to the pilot burner and the

function of maintaining low NOx operation to the main burners.

**Figure 6.** Cross-sectional schematic diagram of individual multi-cluster combustor.

**Figure 5.** Configuration of the state-of-the-art dry low NOx combustor for hydrogen-rich syngas fuels.

combustor."

8 Recent Advances in Carbon Capture and Storage

The pilot burner can ensure combustion stability over the operating range by forming a wellstabilized flame in the center. The pilot burner is equipped with an air-assisted oil spray nozzle at the center. The oil spray nozzle operates on oil fuel at ignition and during part load before syngas fuel is supplied to the gas turbine in IGCC plants [19].

The main burners can achieve homogeneous fuel-air mixing for low NOx combustion by dispersing fuel to multiple injection points. The injection points are arranged in three circles on each main burner: six points on the first circle with the smallest diameter, 12 points on the second circle with the intermediate diameter, and 12 points on the third circle with the largest diameter. Here, the region within each first circle on the perforated plate is referred to as the "inner region," and the region outside each first circle is referred to as the "outer region." The gaseous fuel injected from six fuel nozzles on each first circle is referred to as "inner fuel," and the gaseous fuel injected from 24 fuel nozzles on each of the second and third circles is referred to as "outer fuel." The main burners characterize the low NOx performance of the combustor [19].

#### **3.2. Burner concept**

The next subsections describe the concept of the cluster burner for hydrogen-rich fuels. The essence of this burner concept is the integration of two key technologies: rapid mixing of fuel and air for low NOx combustion and flame lifting for flashback-resistant combustion. The cluster burner provides both the advantage of the premixed combustor of low NOx combustion and the advantage of the diffusion-flame combustor of flashback-resistant combustion.

#### *3.2.1. Rapid mixing for low* NOx *combustion*

Rapid mixing achieves low NOx combustion. Thermal NOx from atmospheric air is formed extensively at high temperatures [6, 21]. As a result, NOx emissions are decreased to low levels by eliminating high-temperature regions. Such high-temperature and NOx-generating regions are removed by the formation of homogeneous fuel-air mixtures before combustion, because of the rapid mixing of fuel and air within a short distance. Here, rapid mixing achieves low NOx combustion.

The cluster burner mixes fuel and air rapidly by producing multiple coaxial fuel-air jets, each of which consists of a central fuel jet surrounded by an annular air jet. The burner is equipped with multiple injection points. The burner installs the fuel nozzles in separate air holes coaxially at each injection point, thereby producing multiple coaxial fuel-air jets [19].

The coaxial jets mix fuel and air rapidly within a short distance by enhancing turbulence through contracting and expanding air passages. **Figure 8** shows the fuel concentration distribution in the mixing process of a coaxial jet analyzed by large eddy simulation (LES). The simulation results show that turbulence increases the amplitude of a wavelike disturbance at the boundary between fuel and air jets downstream of the air hole exit, thus mixing fuel and air rapidly. The burner disperses fuel by multiplying the coaxial jet, thereby enhancing mixing of fuel and air [19].

Conventional premixed combustors can mix fuel and air almost completely. However, premixed combustors burning hydrogen-rich fuels are prone to flashback into their large premixing section because of their higher flame speeds. Thus, this flashback characteristic hinders the application of premixed combustion technology to hydrogen-rich fuel combustion.

#### *3.2.2. Flame lifting for flashback-resistant combustion*

Flame lifting achieves flashback-resistant combustion. Flame lifting means that a flame is stably held at a point away from the burner. As a result, flame lifting suppresses the occurrence of flashback into the burner.

The burner can lift a flame by generating converging and diverging swirl flows downstream from itself. **Figure 9** illustrates a cross-sectional diagram of the main burner to describe the operating principle of this flame-lifting technology. The air holes cause the combustion air passing through them to swirl because the central axis of each air hole is inclined in the direction of a tangent to each circle. The swirling flow issuing from the air holes first converges toward and then diverges from an axial position (flame-anchoring point) located away from the burner. As shown in the figure, the converging-diverging swirl flows induce a pressure profile in the

**Figure 9.** Operating principle of flame-lifting technology for the main burner.

flow direction. The converging flow induces a favorable pressure gradient due to the decrease in pressure downstream with increasing swirl velocity, whereas the diverging flow induces an adverse pressure gradient due to the increase in pressure downstream with decreasing swirl velocity. The adverse pressure gradient causes a vortex breakdown at the boundary between the converging and diverging swirl flows, thereby generating a recirculation flow. The recirculation flow stabilizes the flame by providing a stable heat source of combustion gas for the continuous ignition of fresh reactants. The reverse flow of the combustion gas from the boundary can be suppressed by the favorable pressure gradient in the converging flow. As a result, the flame is stabilized at the flame-anchoring point on the boundary. According to this operating principle, the flame is lifted from the burner and thus can suppress the flashback into the burner [19].

#### **3.3. Combustor operability**

levels by eliminating high-temperature regions. Such high-temperature and NOx-generating regions are removed by the formation of homogeneous fuel-air mixtures before combustion, because of the rapid mixing of fuel and air within a short distance. Here, rapid mixing

The cluster burner mixes fuel and air rapidly by producing multiple coaxial fuel-air jets, each of which consists of a central fuel jet surrounded by an annular air jet. The burner is equipped with multiple injection points. The burner installs the fuel nozzles in separate air holes coaxi-

The coaxial jets mix fuel and air rapidly within a short distance by enhancing turbulence through contracting and expanding air passages. **Figure 8** shows the fuel concentration distribution in the mixing process of a coaxial jet analyzed by large eddy simulation (LES). The simulation results show that turbulence increases the amplitude of a wavelike disturbance at the boundary between fuel and air jets downstream of the air hole exit, thus mixing fuel and air rapidly. The burner disperses fuel by multiplying the coaxial jet, thereby enhancing mix-

Conventional premixed combustors can mix fuel and air almost completely. However, premixed combustors burning hydrogen-rich fuels are prone to flashback into their large premixing section because of their higher flame speeds. Thus, this flashback characteristic hinders the

Flame lifting achieves flashback-resistant combustion. Flame lifting means that a flame is stably held at a point away from the burner. As a result, flame lifting suppresses the occurrence

The burner can lift a flame by generating converging and diverging swirl flows downstream from itself. **Figure 9** illustrates a cross-sectional diagram of the main burner to describe the operating principle of this flame-lifting technology. The air holes cause the combustion air passing through them to swirl because the central axis of each air hole is inclined in the direction of a tangent to each circle. The swirling flow issuing from the air holes first converges toward and then diverges from an axial position (flame-anchoring point) located away from the burner. As shown in the figure, the converging-diverging swirl flows induce a pressure profile in the

application of premixed combustion technology to hydrogen-rich fuel combustion.

ally at each injection point, thereby producing multiple coaxial fuel-air jets [19].

achieves low NOx combustion.

10 Recent Advances in Carbon Capture and Storage

ing of fuel and air [19].

of flashback into the burner.

**Figure 8.** Mixing process of a coaxial jet.

*3.2.2. Flame lifting for flashback-resistant combustion*

The combustors are required to operate stably from ignition through part load to base load in practical IGCC plants. The next subsections describe the fuel supply system and fuel staging.

#### *3.3.1. Fuel supplying system*

The fuel supply system supplies syngas and oil fuels to the multi-cluster combustor. **Figure 10** shows the fuel supplying system for the combustor [19]. The six main burners are divided into two groups (F2 and F3) consisting of three burners each, and arranged alternately around the pilot burner (F1). The syngas fuel is distributed into five fuel circuits: F1 fuel to the F1 pilot

**Figure 10.** Fuel supplying system.

burner, F2-1 fuel to the inner region of the F2 main burners, F2-2 fuel to the outer region of the F2 main burners, F3-1 fuel to the inner region of the F3 main burners, and F3-2 fuel to the outer region of the F3 main burners. The oil fuel is supplied to the oil spray nozzle.

The fuel distribution ratios (F1 ratio and outer-fuel ratio) are important test parameters influencing combustion performance. The F1 ratio is defined as the ratio of the mass flow rates of F1 fuel to all fuel. The F1 ratio is expressed as follows:

$$\begin{aligned} \text{Beinging combustion performance. The F1 ratio is defined as the ratio of the mass flow rates of F1 fuel to all fuel. The F1 ratio is expressed as follows:}\\ \text{F1 ratio (\%)} &= \frac{Gf\_{\text{I}}}{Gf\_{\text{ul}}} = \frac{Gf\_{\text{I}}}{Gf\_{\text{I}1} + Gf\_{\text{I}2+1} + Gf\_{\text{I}3+1} + Gf\_{\text{I}3+2}} \\ &\quad \text{(1)} \end{aligned}$$

where *Gf* denotes the mass flow rate, and subscripts "all," "F1," "F2-1," "F2-2," "F3-1," and "F3-2" denote all the fuel, F1 fuel, F2-1 fuel, F2-2 fuel, F3-1 fuel, and F3-2 fuel, respectively. The outer-fuel ratio is defined as the ratio of the mass flow rates of the outer fuel to all fuel supplied to the main burners. The outer-fuel ratio is expressed by Eq. (2). *<sup>G</sup> <sup>f</sup> <sup>F</sup>*2−<sup>1</sup> <sup>+</sup> *<sup>G</sup> <sup>f</sup>*

$$\text{supplied to the main burns. The outer-fuel ratio is expressed by Eq. (2).}$$

$$\text{Outer-fuel ratio (\%)} = \frac{Gf\_{\text{Dz2}} + Gf\_{\text{Dz2}}}{Gf\_{\text{Dz2}} + Gf\_{\text{Dz2}} + Gf\_{\text{Dz2}} + Gf\_{\text{Dz2}}} \tag{2}$$

#### *3.3.2. Fuel staging*

The multi-cluster combustor can achieve low emissions and high operability over the entire operating range by switching combustion modes according to operating conditions. The combustor switches the modes by manipulating the combination of operating burners for which the fuel circuit is fueled. The fuel staging with combustion modes and switching loads hinges on such factors as operating conditions, operational requirement, and environmental regulation for each practical plant. This chapter shows an instance of the fuel staging sequences and combustion modes. **Figure 11** shows the fuel staging [22]. In this figure, colored regions shown on the burner pictures indicate operating burners. This fuel staging consists of three distinct combustion modes: oil mode, partial mode, and final mode. The combustor operates on oil fuel in the oil mode and on syngas fuel in the partial and the final Development of a State-of-the-Art Dry Low NOx Gas Turbine Combustor for IGCC with CCS http://dx.doi.org/10.5772/66742 13


**Figure 11.** Fuel staging.

burner, F2-1 fuel to the inner region of the F2 main burners, F2-2 fuel to the outer region of the F2 main burners, F3-1 fuel to the inner region of the F3 main burners, and F3-2 fuel to the

The fuel distribution ratios (F1 ratio and outer-fuel ratio) are important test parameters influencing combustion performance. The F1 ratio is defined as the ratio of the mass flow rates of

<sup>=</sup> *<sup>G</sup> <sup>f</sup>*

*<sup>F</sup>*2−<sup>1</sup> + *G f*

*<sup>F</sup>*<sup>1</sup> + *G f*

where *Gf* denotes the mass flow rate, and subscripts "all," "F1," "F2-1," "F2-2," "F3-1," and "F3-2" denote all the fuel, F1 fuel, F2-1 fuel, F2-2 fuel, F3-1 fuel, and F3-2 fuel, respectively. The outer-fuel ratio is defined as the ratio of the mass flow rates of the outer fuel to all fuel

The multi-cluster combustor can achieve low emissions and high operability over the entire operating range by switching combustion modes according to operating conditions. The combustor switches the modes by manipulating the combination of operating burners for which the fuel circuit is fueled. The fuel staging with combustion modes and switching loads hinges on such factors as operating conditions, operational requirement, and environmental regulation for each practical plant. This chapter shows an instance of the fuel staging sequences and combustion modes. **Figure 11** shows the fuel staging [22]. In this figure, colored regions shown on the burner pictures indicate operating burners. This fuel staging consists of three distinct combustion modes: oil mode, partial mode, and final mode. The combustor operates on oil fuel in the oil mode and on syngas fuel in the partial and the final

*F*1 \_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_ *<sup>G</sup> <sup>f</sup>*

> *<sup>F</sup>*2−<sup>2</sup> + *G f F*3−2 \_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_ *<sup>G</sup> <sup>f</sup> <sup>F</sup>*2−<sup>1</sup> <sup>+</sup> *<sup>G</sup> <sup>f</sup>*

*<sup>F</sup>*2−<sup>2</sup> + *G f*

*<sup>F</sup>*2−<sup>2</sup> + *G f*

*<sup>F</sup>*3−<sup>1</sup> + *G f F*3−2

*<sup>F</sup>*3−<sup>1</sup> + *G f F*3−2 (1)

(2)

outer region of the F3 main burners. The oil fuel is supplied to the oil spray nozzle.

*G f all*

supplied to the main burners. The outer-fuel ratio is expressed by Eq. (2).

F1 fuel to all fuel. The F1 ratio is expressed as follows:

Outer <sup>−</sup> fuel ratio (%) <sup>=</sup> *<sup>G</sup> <sup>f</sup>*

F1 ratio (%) <sup>=</sup> *<sup>G</sup> <sup>f</sup>* \_\_\_\_*<sup>F</sup>*<sup>1</sup>

**Figure 10.** Fuel supplying system.

12 Recent Advances in Carbon Capture and Storage

*3.3.2. Fuel staging*

modes. The combustor switches from the oil mode, through the partial mode, to the final mode between ignition and base load.

In the oil mode, the combustor operates on oil fuel with the oil spray nozzle. The oil mode is used to ignite, accelerate, and operate the combustor over low loads. The oil fuel operation requires injection of diluent into the combustion zone to lower NOx emissions to the level required by environmental regulations, because NOx from oil fueled combustion increase owing to the local high-temperature regions compared with syngas fueled combustion. The combustor injects diluent nitrogen from the fuel nozzles in the outer regions of the main burners. The diluent nitrogen is separated from air by the ASU in IGCC plants. In the partial mode, the combustor operates on syngas fuel with the pilot burner (F1), inner regions of the F2 and F3 main burners (F2-1 and F3-1), and outer regions of the F2 main burners (F2-2). The partial mode is employed during part load from a low load to a middle load. At a low part load, the combustor switches from oil to syngas fuels. The combustor achieves stable combustion over low to middle loads by combusting the pilot fuel and inner fuel of the main burners associated with flame stabilization. In the final mode, the combustor operates on syngas fuel with the pilot burner and all the main burners. The final mode is used from a middle part load to base load. The combustor achieves low NOx combustion by distributing syngas fuel to all the burners [22].

#### **4. Combustor development**

#### **4.1. Development approach**

This section describes the development work for the multi-cluster combustors intended for hydrogen-rich syngas fuels in CCS-equipped oxygen-blown IGCC plants. **Figure 12** shows the development approach for the multi-cluster combustors. The development approach consists of three steps: burner development; combustor development; and feasibility demonstration for practical plants.


**Figure 12.** Development approach for multi-cluster combustors.

In Step 1, the purpose is to optimize configurations of single burners with pairs of a fuel nozzle and an air hole by performing single-nozzle mixing test and single-burner combustion test at atmospheric pressure with test fuels comprised of H<sup>2</sup> , methane (CH4 ), and N<sup>2</sup> . Step 1 evaluates performance of single burners in terms of emissions of NOx, CO, and unburned hydrocarbons (UHC), and stability, which is related to pressure fluctuations due to combustion oscillation. The single-burner combustion test showed that the operating range of stable low NOx combustion was restricted by the occurrence of combustion oscillation, and it was probably triggered by the attachment of the flame to the perforated plate due to the ignition of flammable mixtures in the wake behind the plate [3]. In order to suppress the combustion oscillation, a convex burner was suggested. The convex burner was equipped with a convex perforated plate, of which the center projected into the combustion chamber and the surface was inclined. The combustion test showed that the convex burner was effective in suppressing the combustion oscillation and it expanded the operating range of stable low NOx combustion [23].

In Step 2, the purpose is to optimize configurations of single-can combustors by performing the single-can combustor test at medium and high pressures with test fuels that were mixtures of H<sup>2</sup> , CH4 , and N<sup>2</sup> on the basis of the burner configurations optimized in Step 1. Step 2 evaluates performance of single-can combustors in terms of emissions, stability, and reliability. The performance for the reliability is related to metal temperatures of burners and liners. On the basis of the findings from the single-burner combustion tests, multi-cluster combustors equipped with the flat burner and the convex burner were developed.

In Step 3, the purpose is to demonstrate combustor performance in practical plants by real gas turbine test in a multi-can combustor configuration at practical pressure with practical syngas fuel. Step 3 evaluates performance of multi-can combustors in terms of emissions, stability, reliability, and operability. The performance for the operability is related to dynamic characteristics of the combustors during their operation.

The next subsections describe the development work in Step 2 and Step 3.

#### **4.2. Single-can combustor test**

In Step 1, the purpose is to optimize configurations of single burners with pairs of a fuel nozzle and an air hole by performing single-nozzle mixing test and single-burner combustion test at

performance of single burners in terms of emissions of NOx, CO, and unburned hydrocarbons (UHC), and stability, which is related to pressure fluctuations due to combustion oscillation. The single-burner combustion test showed that the operating range of stable low NOx combustion was restricted by the occurrence of combustion oscillation, and it was probably triggered by the attachment of the flame to the perforated plate due to the ignition of flammable mixtures in the wake behind the plate [3]. In order to suppress the combustion oscillation, a convex burner was suggested. The convex burner was equipped with a convex perforated plate, of which the center projected into the combustion chamber and the surface was inclined. The combustion test showed that the convex burner was effective in suppressing the combustion oscillation and it

In Step 2, the purpose is to optimize configurations of single-can combustors by performing the single-can combustor test at medium and high pressures with test fuels that were mix-

evaluates performance of single-can combustors in terms of emissions, stability, and reliability. The performance for the reliability is related to metal temperatures of burners and liners. On the basis of the findings from the single-burner combustion tests, multi-cluster combus-

In Step 3, the purpose is to demonstrate combustor performance in practical plants by real gas turbine test in a multi-can combustor configuration at practical pressure with practical syngas fuel. Step 3 evaluates performance of multi-can combustors in terms of emissions, stability, reliability, and operability. The performance for the operability is related to dynamic charac-

, methane (CH4

on the basis of the burner configurations optimized in Step 1. Step 2

), and N<sup>2</sup>

. Step 1 evaluates

atmospheric pressure with test fuels comprised of H<sup>2</sup>

**Figure 12.** Development approach for multi-cluster combustors.

14 Recent Advances in Carbon Capture and Storage

tures of H<sup>2</sup>

, CH4

, and N<sup>2</sup>

teristics of the combustors during their operation.

expanded the operating range of stable low NOx combustion [23].

tors equipped with the flat burner and the convex burner were developed.

The next subsections describe the development work in Step 2 and Step 3.

Step 1 evaluated performance of the flat burner and the convex burner by performing the single-burner combustion test in order to optimize the burner configuration. This subsection describes the development of multi-cluster combustors equipped with the flat burner and the convex burner [24, 25].

**Figure 13** shows the configurations of two types of prototype multi-cluster combustors: a flat multi-cluster combustor and a convex multi-cluster combustor. The two combustors differed in terms of the main burner configurations. The flat combustor was equipped with one concave pilot burner at the center and six flat main burners surrounding the pilot burner. The convex combustor was equipped with one concave pilot burner at the center and six convex main burners surrounding the pilot burner. The combustors were tested at a medium pressure under the base load condition.

**Figure 14** shows a schematic diagram of the single-can combustor test facility. A singlecan combustor was assembled into the test stand. An air compressor supplied combustion air to the combustor through a preheater, and the pressure in the combustion chamber was adjusted with a back pressure valve downstream. The test fuels were mixtures of H<sup>2</sup> , CH4 , and N<sup>2</sup> . The fuel supplying system independently supplied the following gases to a gas mixer: H<sup>2</sup> from H<sup>2</sup> -cylinder-loaded trailers; CH4 from CH4 -cylinder-loaded trailers; and N<sup>2</sup> from a liquefied nitrogen tank. The gas mixer produced a gas mixture with certain volume percentages (vol%) of the three gases as a test fuel. The compositions of the gas mixture were varied by changing the flow rates of the constituents independently. The gas mixture was separated into five fuel circuits. The measuring equipment consisted of a gas analyzer and a fluctuating-pressure-measuring system. The gas analyzer measured gas concentrations in the exhaust gas at a measuring duct downstream in the test stand. The fluctuating-pressure-measuring system measured pressure fluctuations inside the combustion chamber.


**Figure 13.** Configurations of prototype multi-cluster combustors.

**Figure 14.** Single-can combustor test facility.

The practical syngas fuels used in IGCC plants include a large amount of CO. However, the road traffic law in Japan prohibits the transport of a large amount of CO required for combustor tests mainly for safety reasons. This practical restriction requires use of CO-free test fuels for the combustor tests. **Table 1** lists properties of three mixtures of test fuels used. The test fuels contained 40, 55, and 65 vol% H<sup>2</sup> , simulating the practical hydrogen-rich syngas fuels at carbon capture rates of 0, 30, and 50% for CCS-equipped oxygen-blown IGCC, respectively. Hereafter, the test fuels are referred to as "CCS-0% fuel," "CCS-30% fuel," and "CCS-50% fuel."

Minimization of NOx requires homogeneous lean combustion. Homogeneous lean combustion was achieved by supplying syngas fuel to each fuel nozzle of the main burners at the


**Table 1.** Properties of test fuels.

same flow rate. This uniform fuel supply yielded an outer-fuel ratio of 80%. This ratio equaled the proportion of the number of fuel nozzles in the outer region (24 nozzles) to the total number of fuel nozzles (30 nozzles) of each main burner. This study set the target outer-fuel ratio at 80% for minimum NOx. This study defines a certain value of the maximum design amplitude of pressure fluctuations for safely operating the combustors. The combustors are required to be developed so that they can maintain the pressure fluctuation amplitudes below the maximum design value. The maximum design value is referred to as the criterion of combustion oscillation here. The combustion oscillation with an amplitude above the criterion may increase the risk of damage to the combustors.

**Figures 15** and **16** show variations in pressure fluctuation amplitude and NOx emissions, respectively, for the flat combustor as a function of the outer-fuel ratio. In **Figure 15**, the amplitude of pressure fluctuation was normalized by the maximum design value. For CCS-0% fuel, the flat multi-cluster combustor could increase the outer-fuel ratio to the target ratio with the pressure fluctuation amplitude below the criterion, and thus achieved the minimum NOx at the target ratio. For CCS-30% and CCS-50% fuels, however, the flat combustor could not increase the outer-fuel ratio to the target ratio because the pressure fluctuation amplitudes increased abruptly above the criterion before the outer-fuel ratio reached the target ratio. Consequently, the NOx minimization was restricted by the abrupt increase in pressure fluctuation amplitude above the criterion.

In contrast, **Figure 17** shows that the convex multi-cluster combustor could increase the outerfuel ratio to the target ratio with the pressure fluctuation amplitude below the criterion for CCS-0%, CCS-30%, and CCS-50% fuels. **Figure 18** shows that the convex combustor achieved the minimum NOx at the target ratio for all the test fuels. The test results demonstrated that the convex combustor was effective in suppressing the occurrence of combustion oscillation for hydrogen-rich fuels.

The practical syngas fuels used in IGCC plants include a large amount of CO. However, the road traffic law in Japan prohibits the transport of a large amount of CO required for combustor tests mainly for safety reasons. This practical restriction requires use of CO-free test fuels for the combustor tests. **Table 1** lists properties of three mixtures of test fuels used. The test fuels

capture rates of 0, 30, and 50% for CCS-equipped oxygen-blown IGCC, respectively. Hereafter,

Minimization of NOx requires homogeneous lean combustion. Homogeneous lean combustion was achieved by supplying syngas fuel to each fuel nozzle of the main burners at the

**Test fuels CCS-0% fuel CCS-30% fuel CCS-50% fuel**

MJ/kg 15.7 22.0 20.1

the test fuels are referred to as "CCS-0% fuel," "CCS-30% fuel," and "CCS-50% fuel."

 H<sup>2</sup> vol% 40.0 55.0 65.0 CH4 vol% 18.0 15.7 6.3 N<sup>2</sup> vol% 42.0 29.3 28.7 Density kg/m3\* 0.640 0.490 0.429 Lower heating value MJ/m3\* 10.0 10.8 8.6

, simulating the practical hydrogen-rich syngas fuels at carbon

contained 40, 55, and 65 vol% H<sup>2</sup>

Constituents:

\*At 273.15 K, and 0.1013 MPa.

**Table 1.** Properties of test fuels.

**Figure 14.** Single-can combustor test facility.

16 Recent Advances in Carbon Capture and Storage

**Figure 15.** Pressure fluctuation amplitude in single-can combustor test for flat multi-cluster combustor. Symbols: circles, CCS-0% (H<sup>2</sup> = 40 vol%); squares, CCS-30% (H<sup>2</sup> = 55 vol%); triangles, CCS-50% (H<sup>2</sup> = 65 vol%).

**Figure 16.** NOx emissions in single-can combustor test for flat multi-cluster combustor. Symbols: circles, CCS-0% (H<sup>2</sup> = 40 vol%); squares, CCS-30% (H<sup>2</sup> = 55 vol%); triangles, CCS-50% (H<sup>2</sup> = 65 vol%).

**Figure 17.** Pressure fluctuation amplitude in single-can combustor test for convex multi-cluster combustor. Symbols: circles, CCS-0% (H<sup>2</sup> = 40 vol%); squares, CCS-30% (H<sup>2</sup> = 55 vol%); triangles, CCS-50% (H<sup>2</sup> = 65 vol%).

Both multi-cluster combustors achieved flashback-free combustion throughout the tests. The test results demonstrated that the multi-cluster combustors could feasibly achieve the dry low NOx combustion of hydrogen-rich surrogate fuels with hydrogen content to 65 vol%.

#### **4.3. Pilot plant test**

In order to demonstrate the feasibility for practical IGCC plants, the multi-cluster combustor was tested on a real gas turbine in a multi-can combustor configuration in an IGCC pilot plant at practical pressure with practical syngas fuel [19, 22, 26, 27].

#### *4.3.1. Pilot plant EAGLE and test conditions*

The pilot plant was an oxygen-blown integrated coal gasification power generation pilot plant "EAGLE" ("coal Energy Application for Gas, Liquid and Electricity") at the Wakamatsu Research Institute of the Electric Power Development Co., Ltd. (J-POWER) (Japan). This pilot plant (**Figure 19**) was a test facility for developing coal gasification technologies with innovative

**Figure 18.** NOx emissions in single-can combustor test for convex multi-cluster combustor. Symbols: circles, CCS-0% (H<sup>2</sup> = 40 vol%); squares, CCS-30% (H<sup>2</sup> = 55 vol%); triangles, CCS-50% (H<sup>2</sup> = 65 vol%).

**Figure 19.** EAGLE pilot plant (photo courtesy of J-POWER).

Both multi-cluster combustors achieved flashback-free combustion throughout the tests. The test results demonstrated that the multi-cluster combustors could feasibly achieve the dry low NOx combustion of hydrogen-rich surrogate fuels with hydrogen content to

**Figure 17.** Pressure fluctuation amplitude in single-can combustor test for convex multi-cluster combustor. Symbols:

**Figure 16.** NOx emissions in single-can combustor test for flat multi-cluster combustor. Symbols: circles, CCS-0% (H<sup>2</sup>

= 65 vol%).

= 55 vol%); triangles, CCS-50% (H<sup>2</sup>

= 55 vol%); triangles, CCS-50% (H<sup>2</sup>

= 65 vol%).

= 40

In order to demonstrate the feasibility for practical IGCC plants, the multi-cluster combustor was tested on a real gas turbine in a multi-can combustor configuration in an IGCC pilot plant

at practical pressure with practical syngas fuel [19, 22, 26, 27].

= 40 vol%); squares, CCS-30% (H<sup>2</sup>

65 vol%.

**4.3. Pilot plant test**

circles, CCS-0% (H<sup>2</sup>

vol%); squares, CCS-30% (H<sup>2</sup>

18 Recent Advances in Carbon Capture and Storage

CO<sup>2</sup> capture [28–32]. The five main components of the EAGLE plant were an ASU, a gasifier, a gas cleanup unit, a gas turbine, and a CO<sup>2</sup> capture unit. The ASU separated air into oxygen and nitrogen. Oxygen was supplied to the gasifier as an oxidant for the gasification process. Nitrogen was supplied to the gas turbine as a diluent for oil fuel operation. The gasifier converted coal to raw syngas by reacting it with oxygen. The gasifier employed an oxygen-blown, single-chamber, two-stage, swirling flow entrained bed gasification method. The gas cleanup unit removed impurities from the raw syngas, thus producing a clean syngas consisting mainly of CO, H<sup>2</sup> , and N<sup>2</sup> . The clean syngas was supplied separately to the gas turbine and the CO<sup>2</sup> capture unit. This separate syngas supply was employed because of the plant's operational circumstance that the test of the gas turbine combustor proceeded with the test of the CO<sup>2</sup> capture individually in the test series [32].

The gas turbine was an open simple-cycle/single-shaft type. It was originally equipped with a conventional diffusion-flame combustor with one oil fuel supplying system and one syngas fuel supplying system. The diffusion-flame combustor needed to inject diluent nitrogen into the combustion chamber to decrease NOx emissions. The diffusion-flame combustor on the gas turbine was replaced by the multi-cluster combustor with four additional syngas fuel supplying systems for the present tests. The multi-cluster combustor for the IGCC was developed for middle and small capacity gas turbines. The flat multi-cluster combustor was employed for the test because it was applicable to hydrogen-rich syngas fuels with intermediate hydrogen contents and its structural reliability was ensured by the simple structure of the flat perforated plate.

The syngas fuel burned in the tests was comprised mainly of CO, H<sup>2</sup> , and N<sup>2</sup> . The syngas fuel contained approximately 50 vol% CO, 20 vol% H<sup>2</sup> , and 20 vol% N<sup>2</sup> . Distillate oil was also burned for oil fuel operation. The EAGLE pilot plant test was conducted from startup on distillate oil to the maximum load (corresponding to 80% of the gas turbine load) on syngas produced in the test series.

The measuring systems consisted mainly of a gas analyzer, fluctuating-pressure-measuring system, and metal-temperature-measuring system. The gas analyzer measured the concentrations of NOx, CO, O<sup>2</sup> , and CO<sup>2</sup> contained in the exhaust gas. The exhaust gas was sampled at multiple points in a cross section located in the exhaust duct downstream from the turbine. The fluctuating-pressure-measuring system measured pressure fluctuations at a point inside the combustion chamber on each can combustor. The metal-temperature-measuring system was equipped with thermocouples to measure metal temperatures of the liner and burner perforated plate [27].

#### *4.3.2. Combustor performance at maximum load*

This subsection evaluates combustor performance at a maximum gas turbine load of 80% [19]. The combustor operated with all the syngas-fueled burners in the final mode at the maximum load.

**Figure 20** shows the maximum amplitudes of pressure fluctuations in all the cans at the maximum load versus the outer-fuel ratio. The amplitudes were maintained at low values well below the criterion over the whole test range. This result demonstrated that the multi-cluster combustor achieved stable operation with low levels of pressure fluctuation amplitudes. The stable combustion performance was probably due to the stable lifted flames formed by the cluster burners.

CO<sup>2</sup>

of CO, H<sup>2</sup>

, and N<sup>2</sup>

the flat perforated plate.

produced in the test series.

tions of NOx, CO, O<sup>2</sup>

perforated plate [27].

maximum load.

individually in the test series [32].

a gas cleanup unit, a gas turbine, and a CO<sup>2</sup>

20 Recent Advances in Carbon Capture and Storage

capture [28–32]. The five main components of the EAGLE plant were an ASU, a gasifier,

. The clean syngas was supplied separately to the gas turbine and the CO<sup>2</sup>

and nitrogen. Oxygen was supplied to the gasifier as an oxidant for the gasification process. Nitrogen was supplied to the gas turbine as a diluent for oil fuel operation. The gasifier converted coal to raw syngas by reacting it with oxygen. The gasifier employed an oxygen-blown, single-chamber, two-stage, swirling flow entrained bed gasification method. The gas cleanup unit removed impurities from the raw syngas, thus producing a clean syngas consisting mainly

capture unit. This separate syngas supply was employed because of the plant's operational cir-

The gas turbine was an open simple-cycle/single-shaft type. It was originally equipped with a conventional diffusion-flame combustor with one oil fuel supplying system and one syngas fuel supplying system. The diffusion-flame combustor needed to inject diluent nitrogen into the combustion chamber to decrease NOx emissions. The diffusion-flame combustor on the gas turbine was replaced by the multi-cluster combustor with four additional syngas fuel supplying systems for the present tests. The multi-cluster combustor for the IGCC was developed for middle and small capacity gas turbines. The flat multi-cluster combustor was employed for the test because it was applicable to hydrogen-rich syngas fuels with intermediate hydrogen contents and its structural reliability was ensured by the simple structure of

burned for oil fuel operation. The EAGLE pilot plant test was conducted from startup on distillate oil to the maximum load (corresponding to 80% of the gas turbine load) on syngas

The measuring systems consisted mainly of a gas analyzer, fluctuating-pressure-measuring system, and metal-temperature-measuring system. The gas analyzer measured the concentra-

multiple points in a cross section located in the exhaust duct downstream from the turbine. The fluctuating-pressure-measuring system measured pressure fluctuations at a point inside the combustion chamber on each can combustor. The metal-temperature-measuring system was equipped with thermocouples to measure metal temperatures of the liner and burner

This subsection evaluates combustor performance at a maximum gas turbine load of 80% [19]. The combustor operated with all the syngas-fueled burners in the final mode at the

**Figure 20** shows the maximum amplitudes of pressure fluctuations in all the cans at the maximum load versus the outer-fuel ratio. The amplitudes were maintained at low values well

cumstance that the test of the gas turbine combustor proceeded with the test of the CO<sup>2</sup>

The syngas fuel burned in the tests was comprised mainly of CO, H<sup>2</sup>

fuel contained approximately 50 vol% CO, 20 vol% H<sup>2</sup>

, and CO<sup>2</sup>

*4.3.2. Combustor performance at maximum load*

capture unit. The ASU separated air into oxygen

, and N<sup>2</sup>

, and 20 vol% N<sup>2</sup>

contained in the exhaust gas. The exhaust gas was sampled at

capture

. The syngas

. Distillate oil was also

**Figure 21** shows the NOx emissions at the maximum load as a function of the outer-fuel ratio. The NOx decreased with increasing outer-fuel ratio until reaching the target ratio (80%); it yielded the minimum value at the target ratio, and then increased again with increasing outer-fuel ratio above the target ratio. The minimum NOx value was 10.9 ppm at the target ratio. The minimum NOx value at the target ratio was achieved by homogeneous lean combustion with a uniform equivalence ratio over the region in the main burners. The higher NOx values at outer-fuel ratios below and above the target ratio were due to the formation of high-temperature flames with a higher equivalence ratio in the inner region and the outer region, respectively.

**Figure 20.** Pressure fluctuation amplitude at maximum gas turbine load of 80%.

**Figure 21.** NOx emissions at maximum gas turbine load of 80%.

The multi-cluster combustor features diluent-free (dry), low NOx combustion. In order to demonstrate this feature, the dry low NOx performance of the multi-cluster combustor was compared with the diluent-controlled low NOx performance of the diffusion-flame combustor. **Figure 22** compares the NOx emissions for the multi-cluster combustor and the diffusionflame combustor at the maximum load plotted against the normalized mass-flow-rate ratio of diluent nitrogen to syngas fuel [19]. The data for the multi-cluster combustor yielded the minimum NOx value of 10.9 ppm as attained at the target ratio. The data for the diffusion-flame combustor were obtained in tests of the combustor in the same plant. This figure plots the data in the operating range. The prediction curve represents predicted NOx values for the diffusion-flame combustor. This curve was predicted on a correlation between NOx and the stoichiometric flame temperature of a fuel/air/diluent mixture, which is representative of the actual flame temperature closely associated with the NOx formation rate in diffusion flames [33, 34]. This figure shows that the multi-cluster combustor achieved low NOx below around 10 ppm at a N<sup>2</sup> /fuel ratio of zero (diluent-free (dry)). In contrast, the diffusion-flame combustor yielded much higher NOx around 200 ppm at a N<sup>2</sup> /fuel ratio of zero, and needed diluent nitrogen to decrease NOx to the same level as that achieved by the multi-cluster combustor as a diluent-free condition. This comparison demonstrated that the multi-cluster combustor could feasibly achieve dry low NOx combustion of the syngas fuel in the IGCC pilot plant.

#### *4.3.3. Combustor performance at part load*

The combustor is required to operate stably from ignition through part load to the maximum load in practical IGCC plants. This subsection evaluates the performance of the combustor at part load in the plant [22].

**Figure 23** shows the variations in NOx emissions as a function of the gas turbine load. From 0% load (full speed no load) to 30% load, the combustor operated on distillate oil with diluent

**Figure 22.** NOx comparison between multi-cluster combustor and diffusion-flame combustor at maximum gas turbine load. Symbols: circles, multi-cluster combustor; squares, diffusion-flame combustor; dotted line, prediction curve for diffusion-flame combustor.

Development of a State-of-the-Art Dry Low NOx Gas Turbine Combustor for IGCC with CCS http://dx.doi.org/10.5772/66742 23

**Figure 23.** Variations in NOx emissions with gas turbine load.

The multi-cluster combustor features diluent-free (dry), low NOx combustion. In order to demonstrate this feature, the dry low NOx performance of the multi-cluster combustor was compared with the diluent-controlled low NOx performance of the diffusion-flame combustor. **Figure 22** compares the NOx emissions for the multi-cluster combustor and the diffusionflame combustor at the maximum load plotted against the normalized mass-flow-rate ratio of diluent nitrogen to syngas fuel [19]. The data for the multi-cluster combustor yielded the minimum NOx value of 10.9 ppm as attained at the target ratio. The data for the diffusion-flame combustor were obtained in tests of the combustor in the same plant. This figure plots the data in the operating range. The prediction curve represents predicted NOx values for the diffusion-flame combustor. This curve was predicted on a correlation between NOx and the stoichiometric flame temperature of a fuel/air/diluent mixture, which is representative of the actual flame temperature closely associated with the NOx formation rate in diffusion flames [33, 34]. This figure shows that the multi-cluster combustor achieved low NOx below around

/fuel ratio of zero (diluent-free (dry)). In contrast, the diffusion-flame combus-

nitrogen to decrease NOx to the same level as that achieved by the multi-cluster combustor as a diluent-free condition. This comparison demonstrated that the multi-cluster combustor could

The combustor is required to operate stably from ignition through part load to the maximum load in practical IGCC plants. This subsection evaluates the performance of the combustor at

**Figure 23** shows the variations in NOx emissions as a function of the gas turbine load. From 0% load (full speed no load) to 30% load, the combustor operated on distillate oil with diluent

**Figure 22.** NOx comparison between multi-cluster combustor and diffusion-flame combustor at maximum gas turbine load. Symbols: circles, multi-cluster combustor; squares, diffusion-flame combustor; dotted line, prediction curve for

feasibly achieve dry low NOx combustion of the syngas fuel in the IGCC pilot plant.

/fuel ratio of zero, and needed diluent

10 ppm at a N<sup>2</sup>

tor yielded much higher NOx around 200 ppm at a N<sup>2</sup>

*4.3.3. Combustor performance at part load*

22 Recent Advances in Carbon Capture and Storage

part load in the plant [22].

diffusion-flame combustor.

nitrogen injection to control NOx in the oil mode. NOx increased with the load during oil operation between 0 and 30% load. At 30% load, the combustor switched from distillate oil to syngas. During this switching, the combustor disconnected the supply of diluent nitrogen for NOx control. NOx decreased from 58 to 23 ppm when the combustor switched the diluent-controlled oil operation to diluent-free syngas operation. From 30 to 60% load, the combustor operated on syngas in the partial mode. NOx increased with the load between 30 and 60% load. At 60% load, the combustor switched from the partial mode to the final mode, where the pilot burner and all the main burners were operating. NOx decreased from 44 to 12 ppm at this mode-switching load. This NOx decrease was due to the dispersion of fuel to all the burners. Finally from 60 to 80% load, the combustor operated on syngas in the final mode. NOx abruptly decreased at 60% load, and then gradually decreased with the load between 60 and 80% load. These results demonstrated that the multi-cluster combustor achieved dry low NOx of less than 12 ppm in the final mode above 60% load.

High values of combustion efficiency close to 100% indicate complete combustion, whereas low values of combustion efficiency indicate incomplete combustion, as manifested mainly in the form of CO emissions in the exhaust gas. Combustion efficiency is defined as the ratio of actual heat energy released in combustion to the theoretical heat energy available in fuel. In this study, the actual heat energy was calculated by subtracting the waste heat due to CO emissions in the exhaust gas from the theoretical heat energy. The theoretical heat energy was calculated as the heat liberated when fuel was completely burned [26].

**Figure 24** shows combustion efficiency as plotted against the gas turbine load. The combustion efficiency periodically increased and decreased with the load. The combustion efficiency increased with the load in each mode, and decreased at each mode-switching load. The combustion efficiency decreased from 99.8 to 98.7% when switching from the oil mode to the partial mode at 30% load, and decreased from 99.9 to 99.5% when switching from the partial mode to the final mode at 60% load. In summary, the multi-cluster combustor attained combustion efficiencies over 99.1% on oil operation between 0 and 30% load, and attained combustion efficiencies over 98.7% on syngas operation between 30 and 80% load. This result demonstrated that the combustor attained high values of combustion efficiency during oil and syngas operation at part load.

**Figure 25** shows the maximum pressure fluctuation amplitudes in all the cans as a function of the gas turbine load. The combustor maintained the amplitudes at values below the criterion

**Figure 24.** Variations in combustion efficiency with gas turbine load.

**Figure 25.** Variations in maximum amplitude of pressure fluctuations with gas turbine load.

over the entire load range. The result demonstrated that the combustor achieved stable operation with low pressure fluctuation amplitudes at part load.

**Figure 26** shows the maximum values of all liner metal temperatures in all the cans as a function of the gas turbine load. The combustor maintained the liner metal temperatures at values below the criterion over the load range. The liner metal temperatures yielded the maximum values around the liner end tip.

The multi-cluster combustor achieved flashback-free combustion throughout part load. The test results demonstrated the feasibility of dry low NOx combustion of the practical syngas fuel in the IGCC pilot plant.

**Figure 26.** Variations in maximum liner metal temperature with gas turbine load.

#### **5. Conclusions**

final mode at 60% load. In summary, the multi-cluster combustor attained combustion efficiencies over 99.1% on oil operation between 0 and 30% load, and attained combustion efficiencies over 98.7% on syngas operation between 30 and 80% load. This result demonstrated that the combustor attained high values of combustion efficiency during oil and syngas operation at part load. **Figure 25** shows the maximum pressure fluctuation amplitudes in all the cans as a function of the gas turbine load. The combustor maintained the amplitudes at values below the criterion

**Figure 25.** Variations in maximum amplitude of pressure fluctuations with gas turbine load.

**Figure 24.** Variations in combustion efficiency with gas turbine load.

24 Recent Advances in Carbon Capture and Storage

This chapter described the development of the multi-cluster combustor as a state-of-the-art dry low NOx combustor for hydrogen-rich syngas fuels that can achieve both low NOx and high plant efficiency. The development approach consisted of three steps: burner development; combustor development; and feasibility demonstration for practical plants. This chapter focused mainly on the second and third steps. The main findings from these steps are summarized as follows.


#### **6. Next steps**

#### **6.1. IGCC demonstration test**

On the basis of the experiences in the IGCC pilot plant test, a multi-cluster combustor was developed and installed on a middle capacity gas turbine in an oxygen-blown IGCC demonstration plant of the Osaki CoolGen Corporation, Japan [35–37]. The Osaki CoolGen project has been implemented as an "integrated coal gasification fuel cell combined cycle (IGFC) demonstration project" [37, 38]. This demonstration project is aiming at innovative low-carbon coal-fired thermal power generation by combining IGFC technology with innovative CO<sup>2</sup> capture technologies, thereby dramatically cutting CO<sup>2</sup> emissions from coal-fired thermal power plants. IGFC technology is expected to be an extremely efficient coal-fired thermal power generation technology. This demonstration project consists of three stages. The first stage is an oxygen-blown IGCC demonstration test. The project for the first stage is subsidized by the Ministry of Economy, Trade and Industry (METI) of Japan. The second stage is an oxygen-blown IGCC with CO<sup>2</sup> capture demonstration test. The final stage is a CO<sup>2</sup> capturing IGFC demonstration test. The project for the second and final stages is subsidized by the New Energy and Industrial Technology Development Organization (NEDO) of Japan.

#### **6.2. Applications of multi-cluster combustors**

The single-can combustor test results described in Section 4.2 showed that the multi-cluster combustors are capable of achieving dry low NOx combustion of hydrogen-rich fuels with hydrogen content to 65 vol%. Thus, the multi-cluster combustor is also applicable for byproduct gases with the same range of hydrogen contents. **Figure 27** shows suitable hydrogen-rich fuels including O<sup>2</sup> -blown IGCC/CCS syngas and by-product gases based on the hydrogen content and the volumetric lower heating value. By-product gases include coke oven gas (COG) from ironworks and off-gas from oil refineries. Use of by-product gases as a gas turbine fuel can offer low-cost power generation because it provides fuel cost economy.

**Figure 27.** Suitable hydrogen-rich fuels.

The development of the multi-cluster combustors is expected to progress to application to byproduct gases and further higher hydrogen content fuels (ultimately pure hydrogen) in order to expand the applicable hydrogen content range.

## **Acknowledgements**

**6. Next steps**

**6.1. IGCC demonstration test**

26 Recent Advances in Carbon Capture and Storage

is an oxygen-blown IGCC with CO<sup>2</sup>

gen-rich fuels including O<sup>2</sup>

**Figure 27.** Suitable hydrogen-rich fuels.

**6.2. Applications of multi-cluster combustors**

capture technologies, thereby dramatically cutting CO<sup>2</sup>

On the basis of the experiences in the IGCC pilot plant test, a multi-cluster combustor was developed and installed on a middle capacity gas turbine in an oxygen-blown IGCC demonstration plant of the Osaki CoolGen Corporation, Japan [35–37]. The Osaki CoolGen project has been implemented as an "integrated coal gasification fuel cell combined cycle (IGFC) demonstration project" [37, 38]. This demonstration project is aiming at innovative low-carbon coal-fired thermal power generation by combining IGFC technology with innovative CO<sup>2</sup>

power plants. IGFC technology is expected to be an extremely efficient coal-fired thermal power generation technology. This demonstration project consists of three stages. The first stage is an oxygen-blown IGCC demonstration test. The project for the first stage is subsidized by the Ministry of Economy, Trade and Industry (METI) of Japan. The second stage

capturing IGFC demonstration test. The project for the second and final stages is subsidized by the New Energy and Industrial Technology Development Organization (NEDO) of Japan.

The single-can combustor test results described in Section 4.2 showed that the multi-cluster combustors are capable of achieving dry low NOx combustion of hydrogen-rich fuels with hydrogen content to 65 vol%. Thus, the multi-cluster combustor is also applicable for byproduct gases with the same range of hydrogen contents. **Figure 27** shows suitable hydro-

hydrogen content and the volumetric lower heating value. By-product gases include coke oven gas (COG) from ironworks and off-gas from oil refineries. Use of by-product gases as a gas turbine fuel can offer low-cost power generation because it provides fuel cost economy.

emissions from coal-fired thermal


capture demonstration test. The final stage is a CO<sup>2</sup>


The multi-cluster combustors for the IGCC plant have been developed under the "Innovative Zero-Emission Coal Gasification Power Generation Project: Development of Low NOx Combustion Technology for High-Hydrogen Syngas in IGCC" by the New Energy and Industrial Technology Development Organization (NEDO) of Japan. The tests in the EAGLE plant were performed with the support of the Wakamatsu Research Institute of the Electric Power Development Co., Ltd. (J-POWER). The combustor development has been performed with the support of the Osaki CoolGen Corporation. The authors sincerely appreciate the valuable guidance and support offered by staff of NEDO, J-POWER and Osaki CoolGen Corporation. This chapter includes copyrighted materials of the American Society of Mechanical Engineers (ASME). The authors sincerely appreciate the ASME for granting permission to use them.

## **Author details**

Tomohiro Asai<sup>1</sup> \*, Yasuhiro Akiyama<sup>1</sup> and Satoschi Dodo<sup>2</sup>

\*Address all correspondence to: tomohiro3\_asai@mhps.com

1 Thermal Power Systems Research Department, Research & Development Center, Mitsubishi Hitachi Power Systems, Ltd., Hitachinaka, Japan

2 Hitachi Gas Turbine Engineering Department, Gas Turbine Technology & Products Integration Division, Mitsubishi Hitachi Power Systems, Ltd., Hitachi, Japan

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Additional information is available at the end of the chapter Additional information is available at the end of the chapter

http://dx.doi.org/10.5772/67188

#### **Abstract**

Coal-fired power plants are the largest source of anthropogenic carbon dioxide (CO<sup>2</sup> ) emissions into the atmosphere, with more than 9.5 billion tonnes of CO<sup>2</sup> emitted annually. In order to mitigate the emissions of CO<sup>2</sup> from coal-fired plants, several measures were proposed, such as increasing the efficiency of the plants, cofiring biomass with coal, and capturing and storing CO<sup>2</sup> deep underground. Among these measures, the use of biomass, which is considered one of the most cost-effective renewables and, in addition, carbon neutral, combined with CO<sup>2</sup> capture and storage will play an important role toward reducing the fossil-based CO<sup>2</sup> emissions. In this study, we investigated in detail the performances of pulverized coal combustion plants with direct cofiring of biomass and integrated with an amine-based postcombustion capture technology. All the systems were modeled and simulated using the process simulation software Aspen Plus. The results indicate that cofiring 10% of biomass in a coal-based power plant only slightly affects the energy performance of the plant, reducing the net efficiency by 0.3% points. The addition of an amine capture system to both the coal-fired and biomass cofiring plants further reduces the efficiency of the plants by more than 10% points. Analyzing the effect of various CO<sup>2</sup> capture process parameters on the heat, solvent and cooling water requirements, and on the overall plant performance, it was found that the concentration of amine in the solution is the most important parameter. The results showed that the net electrical efficiency increases for systems using higher amine concentrations. Further, we investigated the effect of systems with lower heat requirement for solvent regeneration on the plant gross/net power output and also analyzed the plant performances under a flexible CO<sup>2</sup> capture efficiency.

**Keywords:** pulverized coal combustion, biomass cofiring, postcombustion CO<sup>2</sup> capture, chemical absorption, monoethanolamine, Aspen Plus simulation

and reproduction in any medium, provided the original work is properly cited.

© 2016 The Author(s). Licensee InTech. This chapter is distributed under the terms of the Creative Commons © 2017 The Author(s). Licensee InTech. This chapter is distributed under the terms of the Creative Commons Attribution License (http://creativecommons.org/licenses/by/3.0), which permits unrestricted use, distribution, and reproduction in any medium, provided the original work is properly cited.

Attribution License (http://creativecommons.org/licenses/by/3.0), which permits unrestricted use, distribution,

#### **1. Introduction**

Among fossil fuel power plants, coal-fired ones are the largest source of anthropogenic carbon dioxide (CO<sup>2</sup> ) emissions, emitting to the atmosphere more than 9.5 billion tonnes of CO<sup>2</sup> each year [1]. The emissions of CO<sup>2</sup> from coal-fired power plants can be reduced by increasing the efficiency of the plants (1% increase in efficiency reduces CO<sup>2</sup> by 2–3%), cofiring carbon neutral fuels (e.g., woody biomass), and/or capturing CO<sup>2</sup> and storing it in geological formations. The capture of CO<sup>2</sup> can be realized by means of three main approaches [2], namely: postcombustion capture, in which the CO<sup>2</sup> is separated from the flue gas after combustion; oxy-fuel combustion, the combustion takes place in nearly pure oxygen resulting in a flue gas stream consisting mainly of CO<sup>2</sup> and water from which the CO<sup>2</sup> can be easily separated; and precombustion, in which the CO<sup>2</sup> is removed from the fuel before combustion. Among these technologies, postcombustion CO<sup>2</sup> capture is the most advanced one that can be relatively easily integrated into existing or new power plants without altering the combustion process. Currently, postcombustion capture with chemical absorption using an aqueous amine (e.g., monoethanolamine, MEA) solution is the most selected process, offering high capture efficiency and selectivity.

Biomass, as one of the most cost-effective renewables and, in addition, carbon neutral, can also contribute toward reducing fossil-based CO<sup>2</sup> emissions. Furthermore, biomass cofiring in existing or new coal-based power plants is an effective means of producing electricity from biomass at higher conversion efficiencies and lower costs [3]. In addition, cofiring biomass with coal can reduce the emissions of sulfur dioxide (SO<sup>2</sup> ) and, in some cases, nitrogen oxides (NOx ) [4]. Currently, biomass cofiring is used in over 240 power plants (most of which are located in Europe) [5]. The majority of these plants employ direct cofiring in pulverized coal (PC) boilers. Fluidized bed (bubbling and circulating) boilers and grate-firing boilers have also been used. The share of biomass used in the fuel mix is, in most cases, less than 10% on energy basis.

The impact of cofiring different types of biomass on the technical and economic performances of the PC plants, with and without postcombustion capture, was investigated by a number of studies [6–10]. All studies suggest that the use of cofiring in PC combustion systems will have a negative impact on the overall technical and economic performances of the plants. For example, in the work conducted by the US DOE's National Energy Technology Laboratory [6], biomass (hybrid poplar) was directly cofired with bituminous coal (Illinois no. 6) at different ratios, ranging between 15% and 100% on a mass basis. The results showed that the net electrical efficiency decreases with the increase of cofiring ratio. For plants with 15, 30, and 60% biomass share in the fuel mix, the net efficiency decreases by approximately 0.2, 0.4, and 1.1% points, respectively, in comparison with the reference plant without cofiring, while for the case with 100% biomass firing the efficiency penalty is significant, i.e., 2.7% points. Further, it is worth mentioning that, because of the lower overall efficiency of cofiring plants, the total CO<sup>2</sup> emissions, expressed in kg/MWh of power generated, are higher. However, if biomass is considered as a carbon neutral fuel, then the net CO<sup>2</sup> emissions to the atmosphere decrease with the increase of biomass cofiring ratio. For example, a 550 MWe (net) supercritical coal-fired power plant with a net efficiency of 40.7% (on a lower heating value (LHV) basis) has a carbon intensity of about 800 kg CO<sup>2</sup> /MWh. For cases with cofiring, the total CO<sup>2</sup> emissions increase to 813 kg/MWh with 15% biomass cofiring, 826 kg/MWh with 30%, 866 kg/MWh with 60%, and to around 985 kg/MWh with 100% biomass firing. However, if the net CO<sup>2</sup> emissions are calculated, then they decrease to 746 kg/MWh with 15% biomass cofiring, 692 kg/MWh with 30%, 530 kg/MWh with 60%, and 0 kg/MWh for the case with 100% biomass firing.

Integration of amine capture systems to coal-based plants leads to significant energy penalties [11]. The efficiency of coal-fired as well as biomass cofiring plants can be reduced by more than 10% points as a result of CO<sup>2</sup> capture by means of, for example, a MEA-based chemical absorption process [6, 12–14]. The reduction of power output is mainly caused by the extraction of large quantities of steam from the steam cycle of the power plant for amine solvent regeneration (~65% of total energy penalty) and the auxiliary power consumption for the compression of the CO<sup>2</sup> product (~25%) [15]. As mentioned earlier, compared to coal-fired plants, the plants with cofiring depending on the cofiring ratio, have efficiencies up to 1% points lower. In addition to this, the overall energy penalty in cofiring plants with CO<sup>2</sup> capture is higher, and the resulting cost of electricity is also higher than that of coal-fired plants [6, 10].

Although several studies investigated the impact of amine-based postcombustion CO<sup>2</sup> capture on the energy performance of cofiring plants, none of them investigated the effect of the CO<sup>2</sup> capture process parameters on the performances of the cofiring plants. In this study, we investigated in detail the technical performances of PC power plants with direct cofiring of biomass and integrated with an amine-based postcombustion capture technology. Aspen Plus process simulation tool was used for the modeling and simulation. First, we estimated the performances of coal-fired plants with/without cofiring and with/without CO<sup>2</sup> capture. Then we analyzed the effect of various CO<sup>2</sup> capture process parameters on the heat duty of the reboiler, solvent flow rate necessary to capture 90% of the CO<sup>2</sup> from the flue gas, and cooling water requirements. Further, we investigated the effect of absorption processes with lower heat requirement for solvent regeneration on the gross and net power output of the plants, and also analyzed the plant performances under a flexible CO<sup>2</sup> capture efficiency operation.

#### **2. Process description**

#### **2.1. Feedstock**

**1. Introduction**

bon dioxide (CO<sup>2</sup>

each year [1]. The emissions of CO<sup>2</sup>

32 Recent Advances in Carbon Capture and Storage

stream consisting mainly of CO<sup>2</sup>

precombustion, in which the CO<sup>2</sup>

technologies, postcombustion CO<sup>2</sup>

postcombustion capture, in which the CO<sup>2</sup>

also contribute toward reducing fossil-based CO<sup>2</sup>

sidered as a carbon neutral fuel, then the net CO<sup>2</sup>

the increase of biomass cofiring ratio. For example, a 550 MWe

with coal can reduce the emissions of sulfur dioxide (SO<sup>2</sup>

tions. The capture of CO<sup>2</sup>

ciency and selectivity.

(NOx

energy basis.

Among fossil fuel power plants, coal-fired ones are the largest source of anthropogenic car-

oxy-fuel combustion, the combustion takes place in nearly pure oxygen resulting in a flue gas

easily integrated into existing or new power plants without altering the combustion process. Currently, postcombustion capture with chemical absorption using an aqueous amine (e.g., monoethanolamine, MEA) solution is the most selected process, offering high capture effi-

Biomass, as one of the most cost-effective renewables and, in addition, carbon neutral, can

in existing or new coal-based power plants is an effective means of producing electricity from biomass at higher conversion efficiencies and lower costs [3]. In addition, cofiring biomass

The impact of cofiring different types of biomass on the technical and economic performances of the PC plants, with and without postcombustion capture, was investigated by a number of studies [6–10]. All studies suggest that the use of cofiring in PC combustion systems will have a negative impact on the overall technical and economic performances of the plants. For example, in the work conducted by the US DOE's National Energy Technology Laboratory [6], biomass (hybrid poplar) was directly cofired with bituminous coal (Illinois no. 6) at different ratios, ranging between 15% and 100% on a mass basis. The results showed that the net electrical efficiency decreases with the increase of cofiring ratio. For plants with 15, 30, and 60% biomass share in the fuel mix, the net efficiency decreases by approximately 0.2, 0.4, and 1.1% points, respectively, in comparison with the reference plant without cofiring, while for the case with 100% biomass firing the efficiency penalty is significant, i.e., 2.7% points. Further, it is worth mentioning that, because of the lower overall efficiency of cofiring plants, the total CO<sup>2</sup> emissions, expressed in kg/MWh of power generated, are higher. However, if biomass is con-

) [4]. Currently, biomass cofiring is used in over 240 power plants (most of which are located in Europe) [5]. The majority of these plants employ direct cofiring in pulverized coal (PC) boilers. Fluidized bed (bubbling and circulating) boilers and grate-firing boilers have also been used. The share of biomass used in the fuel mix is, in most cases, less than 10% on

and water from which the CO<sup>2</sup>

the efficiency of the plants (1% increase in efficiency reduces CO<sup>2</sup>

neutral fuels (e.g., woody biomass), and/or capturing CO<sup>2</sup>

) emissions, emitting to the atmosphere more than 9.5 billion tonnes of CO<sup>2</sup>

from coal-fired power plants can be reduced by increasing

is removed from the fuel before combustion. Among these

capture is the most advanced one that can be relatively

is separated from the flue gas after combustion;

emissions. Furthermore, biomass cofiring

emissions to the atmosphere decrease with

(net) supercritical coal-fired

) and, in some cases, nitrogen oxides

can be realized by means of three main approaches [2], namely:

by 2–3%), cofiring carbon

can be easily separated; and

and storing it in geological forma-

The composition and heating values of the fuels used in this study are shown in **Table 1**. Bituminous coal (Illinois no. 6) was selected as the base fuel. It has a lower heating value of ~29.5 MJ/kg (dry basis, db), a low moisture content of 11.1% (as received, ar), and a relatively high ash content of 10.9% (db). It is further characterized by having high sulfur content of 2.8% (db). The biomass selected for cofiring cases is hybrid poplar with a moisture content of 50% (ar) and a lower heating value of about 18.5 MJ/kg (db). Its ash (1.5% db) and sulfur (0.03% db) contents are very low. In this study, we assumed that hybrid poplar prior to be fed into the boiler was dried to 10% using a fluidized-bed drying system [6].


**Table 1.** Composition and heating values of coal (Illinois no. 6) and biomass (hybrid poplar) used in this study (by weight, db).

#### **2.2. Power plant**

The power plant is a supercritical PC-fired power plant designed to operate with main steam conditions at 242 bar/593°C and steam reheating at 42.4 bar/593°C. In this study, the reference plant (coal-fired, without carbon capture) generates 550 MWe net power at an efficiency of about 40.7% (LHV).

**Figure 1** shows a simplified layout of the power plant without CO<sup>2</sup> capture. From the boiler, the flue gas is sent to a gas cleaning system consisting of a selective catalytic reduction (SCR) for NOx control, a baghouse (BH) for fly ash removal, and a limestone-based flue gas desulfurization (FGD) unit for SOx removal. An air preheater (APH) is placed between the SCR and BH units. The primary air after exiting the APH is mixed with the fuel prior to entering the boiler while the secondary air was directly sent to the boiler.

**Figure 1.** Layout of a pulverized coal-fired power plant (adapted from [16]).

Aspen Plus software was used for the modeling of the whole plant, which included the boiler and the flue gas cleaning section (control of NOx , ash, and SOx ), the steam cycle, and the capture and compression process.

For the modeling of the boiler and flue gas cleaning section, the PR-BM (Peng-Robinson equation of state with Boston-Mathias alpha function) property method was selected. The following unit operation blocks were used in developing the model: the boiler consisted of an RYIELD block for the fuel decomposition, RGIBBS for the fuel combustion, and several HEATER blocks were used for the steam generation; the flue gas cleaning system was mainly modeled by means of SSPLIT and SEP blocks. The mass flow rate of fuel fed into the boiler, the amount of air required for the combustion, infiltration air, the heat transfer, and several other process parameters were controlled by means of Design Specs.

**Figure 2** shows the flow diagram of the power plant steam cycle considered in this study. As shown, the turbine consists of a high pressure (HP), an intermediate pressure (IP), and a low pressure (LP) turbine, all connected to the generator by a common shaft. The main steam from the boiler enters the high pressure steam turbine (HPST) at a pressure of 242 bar and a temperature of 593°C. From the HPST, the steam is reheated in the boiler to 593°C and introduced to the intermediate pressure steam turbine (IPST) at a pressure of 45.2 bar. In the IPST, the steam is expanded to a pressure of 9.3 bar and then sent to a low pressure steam turbine (LPST), where it is further expanded to the condenser pressure of 0.069 bar. For feedwater preheating, five low pressure feedwater heaters (LPFWHs) are used, including the deaerator, and three high pressure feedwater heaters (HPFWHs). The conditions of the feedwater before entering the boiler are 288 bar and 291°C.

**2.2. Power plant**

of about 40.7% (LHV).

furization (FGD) unit for SOx

34 Recent Advances in Carbon Capture and Storage

for NOx

The power plant is a supercritical PC-fired power plant designed to operate with main steam conditions at 242 bar/593°C and steam reheating at 42.4 bar/593°C. In this study, the refer-

**Table 1.** Composition and heating values of coal (Illinois no. 6) and biomass (hybrid poplar) used in this study (by weight, db).

the flue gas is sent to a gas cleaning system consisting of a selective catalytic reduction (SCR)

BH units. The primary air after exiting the APH is mixed with the fuel prior to entering the

control, a baghouse (BH) for fly ash removal, and a limestone-based flue gas desul-

removal. An air preheater (APH) is placed between the SCR and

**Bituminous coal Illinois no. 6 [13] Hybrid poplar [6]**

net power at an efficiency

capture. From the boiler,

ence plant (coal-fired, without carbon capture) generates 550 MWe

Moisture (% ar) 11.12 50.00 Ash (%) 10.91 1.48 Carbon (%) 71.73 52.36 Hydrogen (%) 5.06 5.60 Oxygen (%) 7.74 40.16 Nitrogen (%) 1.41 0.37 Chlorine (%) 0.33 – Sulfur (%) 2.82 0.03 Higher heating value (MJ/kg) 30.53 19.63 Lower heating value (MJ/kg) 29.45 18.46

**Figure 1** shows a simplified layout of the power plant without CO<sup>2</sup>

boiler while the secondary air was directly sent to the boiler.

**Figure 1.** Layout of a pulverized coal-fired power plant (adapted from [16]).

**Figure 2.** Diagram of the supercritical steam cycle (A: steam extraction point for solvent regeneration; B: reboiler condensate reinjection point in carbon capture cases) (adapted from [16]).

The STEAMNBS (NBS/NRC steam table) property method was selected to model the watersteam cycle in Aspen Plus. The flowsheet was built mainly with the COMPR and HEATER blocks. For example, to model a HPST, two COMPR units were connected in series. The stream exiting the first unit was split into two, one directed to the second unit, and the other one was sent for feedwater preheating. The amount of steam extracted for feedwater preheating, the steam required to drive the boiler feed pump turbine, the steam required for the solvent regeneration and condensate used for desuperheating in carbon capture cases, and the cooling water requirement in the condenser were controlled within the program by means of several Design Spec functions.

The assumptions used for the modeling and simulation of the power plant are presented in **Table 2**.



The STEAMNBS (NBS/NRC steam table) property method was selected to model the watersteam cycle in Aspen Plus. The flowsheet was built mainly with the COMPR and HEATER blocks. For example, to model a HPST, two COMPR units were connected in series. The stream exiting the first unit was split into two, one directed to the second unit, and the other one was sent for feedwater preheating. The amount of steam extracted for feedwater preheating, the steam required to drive the boiler feed pump turbine, the steam required for the solvent regeneration and condensate used for desuperheating in carbon capture cases, and the cooling water requirement in the condenser were controlled within the program by means of

The assumptions used for the modeling and simulation of the power plant are presented in

**Parameter Value**

 Operating pressure (bar) 1.01 Boiler efficiency (% LHV) 91.2 Primary/secondary air (%) 23.5/76.5 Infiltration air (% of FG exiting the APH) 1.6 Air leakage in APH (%) 5.5 Ash distribution, BA/FA (%) 20/80 FG outlet temperature, boiler/APH (°C) 350/170

 content in FG at the APH outlet (mol%) 2.5 PA/FD/ID fans pressure ratio (−) 1.10/1.04/1.08 Fans isentropic/mechanical efficiency (%) 80/95

 FA removal efficiency (%) 100 Pressure drop (bar) 0.014

 removal efficiency (%) 98 Limestone purity (wt%) 80.4 Limestone slurry, solid/liquid (%) 30/70

removal (%) 4

for oxidation (%) 135

 Pressure drop (bar) 0.034 FG outlet temperature (°C) 57.2

 Live steam pressure/temperature (bar/°C) 242.3/593.3 Reheated steam pressure/temperature (bar/°C) 45.2/593.3 IP/LP crossover pressure (bar) 9.3 Condenser pressure (bar) 0.069

several Design Spec functions.

36 Recent Advances in Carbon Capture and Storage

**Table 2**.

Boiler section:

O<sup>2</sup>

BH:

FGD: SO<sup>2</sup>

Excess sorbent for SO<sup>2</sup>

Excess O<sup>2</sup>

Steam cycle:

**Table 2.** Main assumptions for the simulation of the reference plant (without CO<sup>2</sup> capture) [6, 12, 13, 16, 17].

The power requirements of various subsystems in the power plant, such as solids handling and processing, emission control and other plant auxiliaries, are given in **Table 3**.


(a)Includes power consumption by circulating water pumps, ground water pumps, and cooling tower fans. (b)Includes power consumption by plant control systems, lighting, heating, ventilating, and air conditioning.

**Table 3.** Power consumption of various subsystems in the power plant [6, 13].

The power plant model developed in Aspen Plus was validated against the data from the NETL studies [6, 13]. The validation of the steam cycle parameters (i.e., mass flow rates, temperatures, and pressures of steam) is shown in **Figure 3**. As can be observed, the results are in good agreement with the reference [13]. The calculated steam turbine power output was 589.21 MWe , and the gross power output was 580.37 MWe , which is very close to the reference value of 580.40 MWe . **Table 4** compares the simulation results on the performance of coal-fired and biomass cofiring plants with the reference data [6, 13]. The deviation between the reference and the present results for the coal-fired case is insignificant. For the biomass cofiring case, with 10% heat input, the results are within the values reported in the reference [6].

**Figure 3.** Validation of the water/steam parameters of the supercritical steam cycle.

#### **2.3. CO2 capture and compression**

A simplified process flow diagram of the MEA-based chemical absorption process for CO<sup>2</sup> capture used in this study is shown in **Figure 4**. The flue gas after pretreating in a direct contact cooler (DCC), with reduced temperature and low impurities level, enters the absorber column where it contacts, countercurrently, with the aqueous amine solution (30 wt% MEA and 0.25 mol CO<sup>2</sup> /mol MEA loading) introduced from the top of the column. The CO<sup>2</sup> from the flue gas reacts with the absorbent forming a CO<sup>2</sup> -rich solution (~0.49 mol CO<sup>2</sup> /mol MEA), which is then pumped to the desorber column via a lean/rich heat exchanger (HX). The clean


**Table 4.** Comparison of plant performance without CO<sup>2</sup> capture. flue gas exits the absorber and is further washed in a water washing section in order to remove any amine residues. In the desorber, the CO<sup>2</sup> is released from the liquid absorbent as a result of the heat provided by the LP steam in the reboiler. The CO<sup>2</sup> -lean solution is then sent to the absorber column for the next cycle. The CO<sup>2</sup> product stream from the desorber column is further compressed, dehydrated, and transported to a storage site. The main assumptions used to model and simulate the capture and compression process are presented in **Table 5**.

589.21 MWe

**2.3. CO2**

CO<sup>2</sup>

(a)Case 11 [13]. (b)Case PN4 [6]. (c)Case PN3 [6].

and 0.25 mol CO<sup>2</sup>

 **capture and compression**

the flue gas reacts with the absorbent forming a CO<sup>2</sup>

**Table 4.** Comparison of plant performance without CO<sup>2</sup>

**Figure 3.** Validation of the water/steam parameters of the supercritical steam cycle.

**Case study Coal-fired Biomass cofiring**

Biomass share (% heat input) 0 0 6 10 13 Net plant efficiency (% LHV) 40.73 40.67 40.54 40.35 40.32 Fuel consumption (kg/MWh) 337.7 338.2 375.8 403.5 423.4

emissions (kg/MWh) 802.0 803.0 812.6 821.4 825.8

capture.

value of 580.40 MWe

38 Recent Advances in Carbon Capture and Storage

, and the gross power output was 580.37 MWe

, which is very close to the reference

from

/mol MEA),

. **Table 4** compares the simulation results on the performance of coal-fired

and biomass cofiring plants with the reference data [6, 13]. The deviation between the reference and the present results for the coal-fired case is insignificant. For the biomass cofiring case, with 10% heat input, the results are within the values reported in the reference [6].

A simplified process flow diagram of the MEA-based chemical absorption process for CO<sup>2</sup> capture used in this study is shown in **Figure 4**. The flue gas after pretreating in a direct contact cooler (DCC), with reduced temperature and low impurities level, enters the absorber column where it contacts, countercurrently, with the aqueous amine solution (30 wt% MEA

which is then pumped to the desorber column via a lean/rich heat exchanger (HX). The clean

/mol MEA loading) introduced from the top of the column. The CO<sup>2</sup>

**NETL(a) This study NETL(b) This study NETL(c)**


In Aspen, the ELECNRTL (electrolyte nonrandom two-liquid model with Redlich-Kwong equation of state) property method was selected for the simulation of the absorption process. The chemical reactions taking place during the absorption process are as follows:

$$\mathrm{MEA^{\ast}} + \mathrm{H\_{2}O} \leftrightarrow \mathrm{MEA} + \mathrm{H\_{3}O^{\ast}} \tag{\mathrm{R1}}$$

$$\rm{CO}\_2 + 2\, H\_2O \leftrightarrow H\_3O^+ + HCO\_3^- \tag{R2}$$

**Figure 4.** Process flow diagram of the chemical absorption process for CO<sup>2</sup> capture from flue gas.



**Table 5.** Main assumptions for the simulation of the CO<sup>2</sup> capture and compression process [13, 14, 16, 18].

$$\rm{HCO\_3^- + H\_2O \leftrightarrow H\_3O^+ + CO\_3^{2-}} \tag{R3}$$

$$\text{MEACCO}^{\cdot} + \text{H}\_{2}\text{O} \leftrightarrow \text{MEA} + \text{HCO}\_{3}^{\cdot}\tag{\text{R4}}$$

$$2\,\mathrm{H}\_{2}\mathrm{O} \leftrightarrow \mathrm{H}\_{3}\mathrm{O}^{\cdot} + \mathrm{OH}^{\cdot} \tag{\mathrm{R5}}$$

For these reactions, the equilibrium constants were calculated with the following equation:

$$\ln\text{(}K\_{\text{ach}}\text{)}=A+B\big[T+C\ln(T)+DT\tag{1}$$

in which, *T* is the temperature (K) and the coefficients *A*, *B*, *C*, and *D* are given in **Table 6** for each reaction.

To determine the loading of the solution (mol CO<sup>2</sup> /mol MEA), Eq. (2) was applied:

To determine the loading of the solution (mol CO ${}\_{2}$ /mol NHA), Eq. (2) was applied:

$$\text{Loading} = \frac{[\text{CO}\_{2}] + [\text{HCO}\_{3}^{\cdot}] + [\text{CO}\_{3}^{\cdot \cdot}] + [\text{MEACOO'}]}{[\text{MEA}] + [\text{MEA}^{\cdot}] + [\text{MEACOO'}]} \tag{2}$$

where the components in the numerator represent moles of all CO<sup>2</sup> species in the solution, whereas the components in the denominator represent moles of all MEA species.

The following unit operation blocks were used to develop the process flowsheet: RADFRAC columns were used to model the absorber and desorber columns using 18 and 12 equilibrium


**Table 6.** Coefficients from Eq. (1) for the calculation of the equilibrium constants in the CO<sup>2</sup> -MEA system.

stages, respectively [16]. For the modeling of the flue gas blower a COMPR block was used. For cooling and heating purposes, several HEATER blocks were employed. The desorber condenser was modeled with a FLASH2 block.

For the development of the compression model, three unit operation blocks were used, namely, COMPR for compression, HEATER for cooling of the product stream, and FLASH2 for excess liquid removal. As specified in **Table 5**, the CO<sup>2</sup> product stream from the capture unit was compressed to 110 bar in a multistage compressor using seven compression stages with intercooling to 30°C.

The modeling results of the capture and compression model are presented in **Table 7**. These are compared with other sources. As can be seen, the results are in good agreement with the values reported in the open literature for conventional absorption/desorption processes with 30 wt% MEA. In this study, the minimum reboiler heat duty of 3.5 MJ/kg CO<sup>2</sup> captured was obtained for the lean loading of 0.25 mol CO<sup>2</sup> /mol MEA. The solution leaving the absorber column had a loading of 0.49 mol CO<sup>2</sup> /mol MEA. In the simulation, the liquid to gas mass flow rate ratio used was about 3.9, and the lean solvent requirement was about 20 kg/kg CO<sup>2</sup> captured. The total CW needed to cool (i) the FG before entering the capture unit, (ii) the lean solution after exiting the lean/rich HX, and (iii) the CO<sup>2</sup> product stream in the compression train was estimated at about 71 kg/kg CO<sup>2</sup> captured. The specific energy requirement was estimated at about 110 kWh/kg CO<sup>2</sup> captured of which more than 75% were consumed by the compression unit. Furthermore, it was found that the specific steam used for solvent regeneration was 1.45 kg steam/kg CO<sup>2</sup> captured, which is in agreement with the values reported in [13, 21]. For example, in reference [21] about 1.42 kg steam/ kg CO<sup>2</sup> captured were used for the case with the steam extracted at 9 bar from the IP/LP crossover pipe and 1.47 kg steam/kg CO<sup>2</sup> for the case with steam extracted at 3 bar from the LPST.

#### **2.4. Integration of CO2 capture with power plant**

HCO3

**Table 5.** Main assumptions for the simulation of the CO<sup>2</sup>

each reaction.

CO<sup>2</sup>

(a)Calculated.

compression:

40 Recent Advances in Carbon Capture and Storage

MEACOO− + H<sup>2</sup> O ↔ MEA + HCO3

where the components in the numerator represent moles of all CO<sup>2</sup>

whereas the components in the denominator represent moles of all MEA species.

To determine the loading of the solution (mol CO<sup>2</sup>

Loading <sup>=</sup> [CO2] <sup>+</sup> [HCO3

<sup>−</sup> + H<sup>2</sup> O ↔ H3 O<sup>+</sup> + CO3

**Parameter Value** FG/lean solvent temperature at the absorber inlet (°C) ~45(a)/40 Lean/rich HX temperature difference (hot outlet—cold inlet) (°C) 5 Reboiler temperature difference (°C) 10 Operating pressure, absorber/desorber (bar) 1.0/1.7 Pressure drop, absorber/desorber (bar) 0.14/0.20 Number of equilibrium stages, absorber/desorber (−) 18/12 Booster fan pressure ratio (−) 1.1 Booster fan isentropic/mechanical efficiency (%) 85/95

 Final delivery pressure/temperature (bar/°C) 110/30 Number of compression stages (−) 7 Compressor pressure ratio (−) 1.8 Compressor isentropic/mechanical efficiency (%) 80/95 Intercoolers outlet temperature (°C) 30 Intercoolers pressure drop (% of inlet stream) 2

 2 H<sup>2</sup> O ↔ H3 O<sup>+</sup> + OH− (R5) For these reactions, the equilibrium constants were calculated with the following equation:

ln(*Kech*) <sup>=</sup> *<sup>A</sup>* <sup>+</sup> *<sup>B</sup>*/*<sup>T</sup>* <sup>+</sup> *<sup>C</sup>* ln(*T*) <sup>+</sup> *DT* (1)

in which, *T* is the temperature (K) and the coefficients *A*, *B*, *C*, and *D* are given in **Table 6** for

− ] + [CO3 2−

The following unit operation blocks were used to develop the process flowsheet: RADFRAC columns were used to model the absorber and desorber columns using 18 and 12 equilibrium

<sup>2</sup><sup>−</sup> (R3)

/mol MEA), Eq. (2) was applied:

] <sup>+</sup> [MEACOO−] \_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_ [ MEA] <sup>+</sup> [MEA+] <sup>+</sup> [MEACOO−] (2)

capture and compression process [13, 14, 16, 18].

<sup>−</sup> (R4)

species in the solution,

The amine capture unit requires significant amounts of energy for solvent regeneration. This energy is usually provided by the steam extracted from the main power plant. It can also be delivered by, for example, an additional boiler in which steam is generated at sufficient quality and quantity necessary for regeneration [9, 22]. However, this measure would be more costly than that of direct extraction from the plant. In this study, the required steam for solvent regeneration is extracted at 9.3 bar from the crossover pipe between the


**Table 7.** Main parameters of the capture and compression process for 90% CO<sup>2</sup> capture with 30 wt% MEA.

intermediate pressure and low pressure turbine. It is first expanded in an auxiliary turbine, desuperheated, and then enters the reboiler (**Figure 5**). Since the MEA solvent is regenerated at ~121°C, and the reboiler temperature approach is assumed to be 10°C, the conditions of the saturated steam before entering the reboiler are 132°C/2.86 bar. As will be further shown in this study, depending on the MEA concentration and other process conditions, approximately half of the steam from the IP/LP crossover will be extracted, and thus significantly reducing the gross power output. From the reboiler, the resulting condensate is pumped to 9.2 bar to the deaerator. The reboiler condensate can also be returned to one of the LPFWHs, provided that the temperature level is close to that of the condensate. In reference [16], with the same steam cycle, it was shown that the most appropriate location for the condensate reinjection is the deaerator.

#### **2.5. Plant performance indicators**

The performances of plants with/without cofiring and with/without MEA-based postcombustion CO<sup>2</sup> capture were evaluated using the following plant performance indicators:

Net plant efficiency, *η*net (%):

$$\begin{aligned} \text{New } & \bullet\_{\text{c}} \text{ capture were evaluated using the following panu premiumance nuncacous.}\\ \text{Net plant efficiency, } \eta\_{\text{net}} \text{ (\%):}\\ & \eta\_{\text{net}} = \frac{W\_{\text{net}}}{\dot{m}\_{\text{c}} \cdot LHV\_{\text{c}} + \dot{m}\_{\text{g}} \cdot LHV\_{\text{g}}} \end{aligned} \tag{3}$$

Efficiency penalty due to cofiring and/or carbon capture, *Δη*net (% points):

$$
\Delta \eta\_{\text{net}} = \eta\_{\text{net,out}} - \eta\_{\text{net,outtag and/or CCC}} \tag{4}
$$

Specific fuel consumption, *SC*fuel (kg/MWh):

\*\*Specunci uner consumpmuon, \*\*se.\_{\text{focal}} \log \text{mWm}\*\*]: 
$$\text{SC}\_{\text{fash}} = \frac{\left(\dot{m}\_c + \dot{m}\_b\right) \cdot 3600}{W\_{\text{net}}} \tag{5}$$

Specific CO<sup>2</sup> emissions, *SECO*<sup>2</sup> (kg/MWh):

$$SE\_{\text{CO}\_2} = \frac{\dot{m}\_{\text{CO}\_2} \cdot 3600}{W\_{\text{net}}} \tag{6}$$

Modeling and Evaluation of a Coal Power Plant with Biomass Cofiring and CO2 Capture http://dx.doi.org/10.5772/67188 43

**Figure 5.** Integration of the steam with the stripper reboiler.

Net CO<sup>2</sup> emissions, *NE*CO<sup>2</sup> (kg/MWh):

intermediate pressure and low pressure turbine. It is first expanded in an auxiliary turbine, desuperheated, and then enters the reboiler (**Figure 5**). Since the MEA solvent is regenerated at ~121°C, and the reboiler temperature approach is assumed to be 10°C, the conditions of the saturated steam before entering the reboiler are 132°C/2.86 bar. As will be further shown in this study, depending on the MEA concentration and other process conditions, approximately half of the steam from the IP/LP crossover will be extracted, and thus significantly reducing the gross power output. From the reboiler, the resulting condensate is pumped to 9.2 bar to the deaerator. The reboiler condensate can also be returned to one of the LPFWHs, provided that the temperature level is close to that of the condensate. In reference [16], with the same steam cycle, it was shown that the most appropriate location

captured) 70.1–71.4 106/103 61.7

**Study This study Abu-Zahra et al. [19] (a) CAESAR [14] Liu et al. [20]**

/mol MEA) 0.25 0.24/0.32 0.26 0.23

/mol MEA) 0.49 0.48/0.49 0.48 0.54

captured) 3.5 3.89/3.29 3.73 4.6

captured) 20 19.3/26.9 21.8 15.7

captured) 109 129.0 84.4(b)

capture with 30 wt% MEA.

L/G mass flow rate ratio (−) 3.87–3.92 3.48/4.83 4.05 2.75

product compression.

**Table 7.** Main parameters of the capture and compression process for 90% CO<sup>2</sup>

The performances of plants with/without cofiring and with/without MEA-based postcombus-

*<sup>Δ</sup> <sup>η</sup>*net <sup>=</sup> *<sup>η</sup>*net,ref <sup>−</sup> *<sup>η</sup>*net,cofiring and/or CC<sup>S</sup> (4)

= *m* . CO<sup>2</sup> <sup>⋅</sup> <sup>3600</sup> \_\_\_\_\_\_\_\_\_ *W*net

*W*net

capture were evaluated using the following plant performance indicators:

for the condensate reinjection is the deaerator.

Specific fuel consumption, *SC*fuel (kg/MWh):

emissions, *SECO*<sup>2</sup>

*SE*CO<sup>2</sup>

*<sup>η</sup>*net <sup>=</sup> \_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_\_ *<sup>W</sup>*net *<sup>m</sup>*˙ <sup>C</sup> <sup>⋅</sup> *LH <sup>V</sup>*<sup>C</sup> <sup>+</sup> *<sup>m</sup>*˙ <sup>B</sup> <sup>⋅</sup> *LH <sup>V</sup>*<sup>B</sup>

*SC*fue<sup>l</sup> <sup>=</sup> (*m*˙ <sup>C</sup> <sup>+</sup> *<sup>m</sup>*˙ <sup>B</sup>) <sup>⋅</sup> 3600 \_\_\_\_\_\_\_\_\_\_\_\_

(kg/MWh):

Efficiency penalty due to cofiring and/or carbon capture, *Δη*net (% points):

**2.5. Plant performance indicators**

Net plant efficiency, *η*net (%):

tion CO<sup>2</sup>

Lean loading (mol CO<sup>2</sup>

Rich loading (mol CO<sup>2</sup>

Reboiler heat duty (MJ/kg CO<sup>2</sup>

CW requirement (kg/kg CO<sup>2</sup>

Lean solvent requirement (kg/kg CO<sup>2</sup>

Power consumption (kWh/kg CO<sup>2</sup>

(b)Only the energy used for CO<sup>2</sup>

(a) Values refer to the baseline/optimum case.

42 Recent Advances in Carbon Capture and Storage

Specific CO<sup>2</sup>

$$\text{NE}\_{\text{CO}\_i} = \frac{\dot{m}\_{\text{CO}\_i} \cdot 3600}{W\_{\text{net}}} \tag{7}$$

Here, *m* . *C* is the flow rate of coal entering the plant (kg/s), *m* . B is the flow rate of raw biomass entering the plant in the case with cofiring (kg/s), *LHV*C and *LHV*B are the lower heating values of coal and, respectively, biomass (MJ/kg), *η*net,ref is the net efficiency of the reference plant, without cofiring and without CO<sup>2</sup> capture (%), *η*net,cofiring and/or CCS is the net efficiency of the plant with biomass cofiring and/or with CO<sup>2</sup> capture (%), *m* . CO<sup>2</sup> is the total flow rate of CO<sup>2</sup> generated (kg/s), *m* . CO<sup>2</sup> ,C is the flow rate of CO<sup>2</sup> generated only from coal combustion (kg/s), and *W*net is the plant net power output (MWe ), which is obtained after subtracting the plant auxiliary power consumption.

#### **3. Results and discussion**

(3)

(5)

(6)

#### **3.1. Performance of coal-fired and biomass cofiring plants with CO<sup>2</sup> capture**

Simulation results of the investigated plants with/without biomass cofiring and with/without MEA-based postcombustion carbon capture are summarized in **Table 8**. As can be seen, the reference coal-fired power plant has a net electrical efficiency of 40.67% and releases 803 kg CO<sup>2</sup> /MWh. The results further show that the performances of the plant with cofiring are slightly derated in comparison with the coal-fired plant. Cofiring 10% of biomass in a supercritical coal-based plant leads to a reduction in efficiency to 40.35% (i.e., 0.33% points efficiency penalty compared with coal-fired case). This reduction is mainly attributed to the fact that the biomass fuel considered in this study has a lower calorific value and significantly higher moisture content, and the energy needed for its processing and drying is substantial. However, one can also note that cofiring biomass has a positive effect on the ash and SO<sup>2</sup> flow rates reducing the power demand of subsystems associated with their removal. The specific CO<sup>2</sup> emissions from the cofiring plant are estimated at 821.4 kg CO<sup>2</sup> /MWh. But if considering only the emissions resulted from coal combustion, then they decrease to around 740 kg CO<sup>2</sup> /kWh.

The addition of a MEA-based postcombustion CO<sup>2</sup> capture system significantly reduces the energy performance of both plants. For the coal-fired power plant with 90% CO<sup>2</sup> capture rate, the net efficiency drops to 30.47% (i.e., an efficiency penalty of 10.21% points with respect to


**Table 8.** Performance of PC plants with/without cofiring, with/without CO<sup>2</sup> capture. the reference plant) while for the cofiring plant the net efficiency decreases to 29.97% (i.e., an efficiency penalty of 10.7% points) after integrating the CO<sup>2</sup> capture and compression process. As can be noted from the table, the capture and compression process consumes more than 55% of the total auxiliary load. The results further show that in order to generate the same amount of energy, the systems with carbon capture should use 35% more fuel than the reference plant without capture. The CO<sup>2</sup> emissions reduce to 107.2 kg CO<sup>2</sup> /kWh in case of coal-fired and to 110.6 kg CO<sup>2</sup> /kWh in case of cofiring. For the cofiring case, if we assume that all the CO<sup>2</sup> resulted from the combustion of coal is captured from the plant, then the net CO<sup>2</sup> emissions would be zero.

#### **3.2. Effect of operating parameters on CO<sup>2</sup> capture process**

penalty compared with coal-fired case). This reduction is mainly attributed to the fact that the biomass fuel considered in this study has a lower calorific value and significantly higher moisture content, and the energy needed for its processing and drying is substantial. However, one

the net efficiency drops to 30.47% (i.e., an efficiency penalty of 10.21% points with respect to

flow rates reducing

/kWh.

/MWh. But if considering only the emis-

capture system significantly reduces the

emissions

capture rate,

can also note that cofiring biomass has a positive effect on the ash and SO<sup>2</sup>

from the cofiring plant are estimated at 821.4 kg CO<sup>2</sup>

44 Recent Advances in Carbon Capture and Storage

The addition of a MEA-based postcombustion CO<sup>2</sup>

**CO2**

Fuel input:

Power generated/consumed:

Coal handling and milling (MWe

BH and ash handling system (MWe

capture and compression (MWe

Biomass handling, processing and drying (MWe

FGD and limestone handling/reagent preparation (MWe

Miscellaneous BOP, ST auxiliaries and transformer losses (MWe

**Table 8.** Performance of PC plants with/without cofiring, with/without CO<sup>2</sup>

ST output (MWe

PA/FD/ID fans (MWe

Condensate pumps (MWe

Overall plant performance: Net power output (MWe

Specific CO<sup>2</sup>

Net CO<sup>2</sup>

Condenser auxiliaries (MWe

Total auxiliary consumption (MWe

CO<sup>2</sup>

the power demand of subsystems associated with their removal. The specific CO<sup>2</sup>

sions resulted from coal combustion, then they decrease to around 740 kg CO<sup>2</sup>

energy performance of both plants. For the coal-fired power plant with 90% CO<sup>2</sup>

 **capture No Yes**

**Cofiring No Yes No Yes**

 Coal (kg/s ar) 51.69 46.60 51.69 46.60 Biomass (kg/s ar) 14.67 14.67 Heat input (MWth LHV) 1352.80 1354.98 1352.80 1354.98

) 580.37 580.37 485.07 483.26

) −9.83 −9.91 −9.83 −9.91

) −0.80 −0.80 −0.42 −0.41

) 550.22 546.68 412.14 406.07

 Net plant efficiency (% LHV) 40.67 40.35 30.47 29.97 Efficiency penalty (% points) 0.33 10.21 10.70 Specific fuel consumption (kg/MWh) 338.2 403.5 451.5 543.2

emissions (kg/MWh) 803.0 821.4 107.2 110.6

emissions (kg/MWh) 803.0 739.3 107.2 0

) −7.65 −7.65 −8.07 −8.14

) −3.16 −2.85 −3.16 −2.85

) −0.61 −0.57 −0.61 −0.57

) −43.03 −43.69

) −30.14 −33.69 −72.93 −77.19

capture.

) −4.20 −4.20

) −3.89 −3.51 −3.89 −3.51

) −4.20 −4.20 −3.90 −3.90

One of the main objectives of this study is to investigate the effect of different process parameters on the energy, solvent, and CW requirements in the CO<sup>2</sup> capture process. The effect of the MEA concentration in the solution (20–40 wt%), the FG temperature at the absorber inlet (40–50°C), the lean solvent temperature at the absorber inlet (30–50°C), the temperature difference in the lean/rich HX between hot outlet and cold inlet (5–10°C), and the stripper operating pressure (1.5–1.9 bar) were investigated. **Figure 6** shows the simulation results on the effect of different process variables on the heat, solvent, and CW requirements in the CO<sup>2</sup> capture process with respect to the base case (30 wt% MEA, 45°C FG inlet temperature, 40°C lean solvent temperature, 5°C lean/rich HX temperature difference, and 1.7 bar stripper operating pressure). For all simulation cases, the CO<sup>2</sup> capture rate was fixed at 90%. As shown, the concentration of MEA is the most important parameter with great effect on the heat, solvent, and CW requirements. Operating the capture unit with a lower MEA concentration (20 wt%) leads to a significant increase of the reboiler heat duty (>12% more compared with the base case), solvent requirement (>35%), and CW requirement (>30%). This is because as the MEA concentration decreases more solvent needs to be fed into the absorber column to remove 90% of CO<sup>2</sup> from the FG stream. The increased solvent flow rate then leads to higher cooling requirements. Further, the temperature of the rich solution entering the desorber column is lower, which needs more heat for solvent regeneration. Contrary to this, increasing the MEA concentration from 30 wt% (base case) to 40 wt% results in a decrease of the reboiler heat duty (>9%), solvent flow rate (>17%) and CW requirement (>17%). It should be mentioned, however, that the use of more concentrated solutions can lead to higher corrosion rates and increased amine emission from the system. In addition, the reboiler temperature increases for cases operating with higher MEA concentrations, which can also lead to thermal degradation of the solvent.

From **Figure 6**, it can be further noted that the FG inlet temperature has almost no effect on the heat requirement, solvent flow rate, and CW requirements. The same was also observed when varying the lean solvent temperature and only influencing the CW requirements. The use of solvent at lower temperatures than that of the base case (40°C) increases the CW requirements by more than 20%. This increase is mainly used in the lean solvent cooler. The temperature difference in the lean/rich HX and the operating pressure of the stripper were found to influence only the heat and CW requirements. If the lean/rich HX is operated with a larger temperature difference, then the rich solvent before entering the desorber column is cooler and, in consequence, more heat is required for solvent regeneration, and since the lean solvent

**Figure 6.** Effect of different parameters on the heat, solvent, and CW requirement in the CO<sup>2</sup> capture process with respect to the base case.

leaving the HX is warmer, then more CW is required to cool the stream to 40°C. Furthermore, operating the stripper at lower pressure leads to higher heat requirement and CW consumption. However, increasing the pressure from 1.7 bar (base case) to 1.9 bar reduces both the reboiler duty and the CW requirement, and in addition, the energy consumption for the compression of CO<sup>2</sup> is also reduced.

#### **3.3. Effect of MEA concentration**

**Figure 6.** Effect of different parameters on the heat, solvent, and CW requirement in the CO<sup>2</sup>

to the base case.

46 Recent Advances in Carbon Capture and Storage

capture process with respect

As was shown earlier, the concentration of MEA in the solution can significantly influence the CO<sup>2</sup> capture process requirements. Therefore, it is necessary to investigate its effect on the plant performance. **Table 9** presents the simulation results for the coal-fired and cofiring cases using different MEA concentrations in the capture process. As can be seen, increasing the concentration of MEA has a positive effect on the plant energy performance. For coal-fired cases, the net electrical efficiency increases from 29.56% with 20 wt% MEA to 31.13% with 40 wt% MEA, i.e., an improvement of 1.57% points. It can be noted that the power demand of the CO<sup>2</sup> capture and compression process in all three cases is almost the same and only slightly decreases with the increase of amine concentration. This is because the solvent flow rate decreases and leads to lower pumps work. The amount of steam required for solvent regeneration decreases from about 180.5 kg/s, representing 57.1% of the total IP/LP crossover with 20 wt% MEA, to 145.4 kg/s, i.e., 46% of the IP/LP steam with 40 wt% MEA. For the cofiring cases, the electrical efficiency is 0.5% points lower than that of coal-fired cases. As noted, the gross power output is lower because the amount of steam extracted for solvent regeneration is higher in the cofiring cases. For example, the amount of extracted steam in the cofiring case with 20 wt% MEA is about 4 kg/s higher than that of the coal case. Moreover, the auxiliary power consumption in the cofiring cases with capture is higher, by approximately 4.2 MWe , which is mainly consumed by the biomass processing system. The results further show that the solvent flow rate, the CW requirement, and the heat requirement for solvent regeneration for the cofiring plants with CO<sup>2</sup> capture are slightly higher than the values for coal cases.



**Table 9.** Effect of MEA concentration on the energy performance of coal-fired/biomass cofiring plants with CO<sup>2</sup> capture.

#### **3.4. Effect of heat requirement**

In this section, the effect of the heat requirement for solvent regeneration on the power plant gross output was investigated. The simulation results are presented in **Figure 7**. The heat duty of the stripper reboiler was varied between 3.5 MJ/kg CO<sup>2</sup> captured (base case) and 2 MJ/kg CO<sup>2</sup> captured. The results showed that for the chemical absorption systems with heat requirement of 3.5 MJ/kg CO<sup>2</sup> captured, the gross power output of the plant decreases by more than 16% compared with the reference plants without CO<sup>2</sup> capture and the steam extracted from the IP/LP crossover amounts to ~50% of the total flow rate. In comparison, for systems with reduced heat requirement, for example, of 2 MJ/kg CO<sup>2</sup> captured, the power output decreases by only 9%, and the proportion of steam extracted is reduced to less than 30%. The amount of steam extracted for solvent regeneration is reduced from 1.45 kg steam/kg CO<sup>2</sup> captured (base case) to about 0.85 kg steam/kg CO<sup>2</sup> captured for the case with 2 MJ/kg CO<sup>2</sup> captured.

**Figure 8** shows the effect of a capture system with lower heat requirement for solvent regeneration on the net power output and efficiency of the biomass cofiring plant. The simulations were carried out using the Cansolv technology for CO<sup>2</sup> capture with the following specific requirements: 2.48 MJ/kg CO<sup>2</sup> reboiler heat duty and 33.3 kWh/t CO<sup>2</sup> power duty [23]. It should be noted here that this technology is currently used at the SaskPower Boundary Dam power plant in Canada being the first commercial scale postcombustion carbon capture project [11]. The simulation results show that the net power output of the biomass cofiring plant integrated with the Cansolv capture technology would increase to about 428 MWe , which is 5.3% higher than that of the plant using conventional MEA system. Compared with the reference biomass cofiring plant without carbon capture, the efficiency penalty due to CO<sup>2</sup> capture reduces to 8.79% points in case with Cansolv.

**Figure 7.** Effect of the reboiler heat duty on the gross power output (bars with a lighter color show the percentage of steam extracted from the IP/LP crossover).

#### **3.5. Effect of CO<sup>2</sup> capture efficiency**

**3.4. Effect of heat requirement**

heat requirement of 3.5 MJ/kg CO<sup>2</sup>

captured.

reduces to 8.79% points in case with Cansolv.

were carried out using the Cansolv technology for CO<sup>2</sup>

2 MJ/kg CO<sup>2</sup>

**CO2**

CO<sup>2</sup>

Biomass cofiring cases: Gross power output (MWe

Other auxiliary loads (MWe

Net power output (MWe

capture and compression (MWe

48 Recent Advances in Carbon Capture and Storage

kg steam/kg CO<sup>2</sup>

with 2 MJ/kg CO<sup>2</sup>

requirements: 2.48 MJ/kg CO<sup>2</sup>

In this section, the effect of the heat requirement for solvent regeneration on the power plant gross output was investigated. The simulation results are presented in **Figure 7**. The heat

extracted from the IP/LP crossover amounts to ~50% of the total flow rate. In compari-

power output decreases by only 9%, and the proportion of steam extracted is reduced to less than 30%. The amount of steam extracted for solvent regeneration is reduced from 1.45

**Figure 8** shows the effect of a capture system with lower heat requirement for solvent regeneration on the net power output and efficiency of the biomass cofiring plant. The simulations

should be noted here that this technology is currently used at the SaskPower Boundary Dam power plant in Canada being the first commercial scale postcombustion carbon capture project [11]. The simulation results show that the net power output of the biomass cofiring plant

5.3% higher than that of the plant using conventional MEA system. Compared with the refer-

integrated with the Cansolv capture technology would increase to about 428 MWe

ence biomass cofiring plant without carbon capture, the efficiency penalty due to CO<sup>2</sup>

reboiler heat duty and 33.3 kWh/t CO<sup>2</sup>

captured (base case) to about 0.85 kg steam/kg CO<sup>2</sup>

captured. The results showed that for the chemical absorption systems with

) 580.37 471.95 483.26 492.01

) −33.69 −34.23 −33.50 −33.20

) 546.68 393.80 406.07 415.22

) −43.93 −43.69 −43.59

captured, the gross power output of the plant decreases

captured (base case) and

capture and the steam

captured for the case

power duty [23]. It

, which is

capture

capture with the following specific

captured, the

capture.

duty of the stripper reboiler was varied between 3.5 MJ/kg CO<sup>2</sup>

 **capture (90%) No Yes**

**MEA concentration (wt%) 20 30 40**

 Net plant efficiency (% LHV) 40.35 29.06 29.97 30.64 Solvent requirement (kg/s) 3051.8 2248.9 1859.3 CW requirement (kg/s) 10526.2 8013.7 6636.3 Heat requirement (MWth) 442.3 393.4 356.8 Steam requirement (% of total IP/LP) 58.2 51.7 46.9

**Table 9.** Effect of MEA concentration on the energy performance of coal-fired/biomass cofiring plants with CO<sup>2</sup>

by more than 16% compared with the reference plants without CO<sup>2</sup>

son, for systems with reduced heat requirement, for example, of 2 MJ/kg CO<sup>2</sup>

To investigate the effect of the capture efficiency on the performances of coal-fired and biomass cofiring plants, the FG exiting the FGD unit was split into two streams, one directed to the capture unit and the other one sent directly to the stack. The amount of FG sent to the absorber column of the capture system varied between 100% and 56% of the total mass flow in order to achieve capture rates of 90–50%. In another configuration (not considered here), all the FG can be sent to the capture unit; however, in this case, the power requirements and cooling duties of the plant would increase.

The simulation results presented in **Table 10** show that the gross power output of both the coal-fired and biomass cofiring plants increases by ~9% as the capture efficiency decreases from 90 to 50%. This is primarily due to the fact that the quantity of steam extracted for solvent regeneration from the steam cycle is significantly lower (by ~45%) and, therefore, more steam is available for power generation. The net power output of the plants increases by more than 15% and the net electrical efficiency is 4.6% points higher than that of the case with 90% CO<sup>2</sup> capture. While the energy performances improve with a decrease in the capture rate, the plants specific CO<sup>2</sup> emissions increase from around 110 kg/kWh to more than 450 kg/MWh.

**Figure 8.** Effect of the capture system with lower reboiler heat duty on the net power output and efficiency of the biomass cofiring plant.



**Table 10.** Effect of CO<sup>2</sup> capture efficiency on the performances of coal-fired and biomass cofiring plants with CO<sup>2</sup> capture.

#### **4. Conclusions**

**Overall capture efficiency (%) 90 80 70 60 50 FG to capture unit (% of total FG) 100 89 78 67 56**

**Figure 8.** Effect of the capture system with lower reboiler heat duty on the net power output and efficiency of the

 Net plant efficiency (% LHV) 30.47 31.58 32.72 33.88 35.05 Solvent requirement (kg/s) 2203 1958 1713 1469 1224 CW requirement (kg/s) 7739 6878 6020 5160 4299 Heat requirement (MWth) 386 343 300 257 214 Steam requirement (% of total IP/LP) 51 45 39 34 28

emissions (kg/MWh) 107 207 299 386 466

) 485.07 495.43 506.11 517.00 528.11

) −29.89 −29.92 −29.95 −29.97 −30.00

) 412.14 427.26 442.69 458.33 474.21

) 483.26 493.75 504.63 515.71 527.00

) −33.50 −33.52 −33.54 −33.56 −33.58

) −43.69 −38.83 −33.98 −29.13 −24.27

) −43.03 −38.25 −33.47 −28.70 −23.91

Coal-fired cases:

biomass cofiring plant.

Specific CO<sup>2</sup>

CO<sup>2</sup>

Biomass cofiring cases: Gross power output (MWe

Other auxiliary loads (MWe

CO<sup>2</sup>

Gross power output (MWe

Other auxiliary loads (MWe

Net power output (MWe

capture and compression (MWe

50 Recent Advances in Carbon Capture and Storage

capture and compression (MWe

In this study, we investigated in detail the effect of biomass cofiring and carbon capture on the plant performances. For cofiring cases, 10% of heat input was substituted with hybrid poplar used as the biomass fuel. When carbon capture was considered, the plants were integrated with a MEA-based postcombustion capture technology. The plant's submodels, i.e., the boiler and flue gas cleaning section (deNOx, deDust, deSOx), the steam cycle, and the CO<sup>2</sup> capture and compression process were all modeled and simulated in Aspen Plus software. The simulation showed the following:


with 40 wt% MEA, the net efficiency of both the coal-fired and biomass cofiring plants improves by ~0.7 and ~1.6% points compared with the cases of 30 and 20 wt% MEA in the solution, respectively. The steam requirement reduces by ~9 and ~20% compared with 30 and 20 wt% MEA cases, respectively.


#### **Acknowledgements**

Financial support provided by the Ministry of Labor, Family and Social Protection (Romania) and cofinanced by the European Social Fund for the second author through the strategic grant POSDRU107/1.5/S/77265 is gratefully acknowledged.

#### **Nomenclature**



#### **Author details**

with 40 wt% MEA, the net efficiency of both the coal-fired and biomass cofiring plants improves by ~0.7 and ~1.6% points compared with the cases of 30 and 20 wt% MEA in the solution, respectively. The steam requirement reduces by ~9 and ~20% compared

(iii) The heat requirement for solvent regeneration in conventional MEA-based capture systems significantly affects the gross power output of the plant and, in consequence, the overall plant energy performance. It was found that the gross power output increases with decreasing the heat duty of the reboiler. For both the coal-fired and biomass cofiring

capture and an assumed heat requirement of 2 MJ/kg CO<sup>2</sup>

the gross power output increases by ~8.5% compared with the base case, while the steam requirement decreases by more than 40%. Lower reboiler heat duty of chemical absorption systems can be achieved by, for example, using an improved process configuration (e.g., absorber intercooling, lean vapor compression, split-stream, etc. [24–26]) and/or

mances of both the coal-fired and biomass cofiring plants. In this case, only a part of the flue gas stream was treated in the capture unit (with a fixed 90% capture rate), and the rest was sent directly to the stack. The results showed that the gross power output of

plant requires less steam to be extracted for the solvent regeneration and, consequently, more steam is available for power generation. Furthermore, for lower capture rates, the net power output improves since the auxiliary power demand of the capture and compression process decreases. However, reducing the capture rates would negatively affect

in case of biomass cofiring will be lower compared with coal-fired if only the net CO<sup>2</sup>

Financial support provided by the Ministry of Labor, Family and Social Protection (Romania) and cofinanced by the European Social Fund for the second author through the strategic grant

the plants increases with decreasing the capture efficiency. Capturing less CO<sup>2</sup>

emissions, generating significantly more CO<sup>2</sup>

captured,

from the

into the atmosphere, which

capture efficiency on the overall perfor-

with 30 and 20 wt% MEA cases, respectively.

solvents with better characteristics [18, 23, 26–28].

(iv) In addition, we analyzed the effect of the CO<sup>2</sup>

plants with 90% CO<sup>2</sup>

52 Recent Advances in Carbon Capture and Storage

the plants CO<sup>2</sup>

**Acknowledgements**

**Nomenclature**

APH Air preheater BA/FA/TA Bottom/fly/total ash

BH Baghouse BOP Balance of plant DCC Direct contact cooler

emissions would be considered.

POSDRU107/1.5/S/77265 is gratefully acknowledged.

Dumitru Cebrucean\*† , Viorica Cebrucean† and Ioana Ionel

\*Address all correspondence to: dumitru\_cebrucean@yahoo.com

Department of Mechanical Machines, Equipments and Transportation, Politehnica University of Timisoara, Timisoara, Romania

† These authors contributed equally.

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