Feasibility Study - Pressurized Oxy-fuel Approach To Carbon Capture

Technical and Economic Feasibility Study of a Pressurized Oxy-fuel Approach to Carbon Capture Part 1 – Technical Feasibility Study and Comparison of the ThermoEnergy Integrated Power System (TIPS) With a Conventional Power Plant and Other Carbon Capture Processes

Ligang Zheng, Richard Pomalis and Bruce Clements

March 2, 2007 Combustion Optimization Group CANMET Energy Research Centre Natural Resources Canada

Technical and Economic Feasibility Study of a Pressurized Oxy-fuel Approach to Carbon Capture – Part 1

Table of Contents Table of Contents............................................................................................................. i 1. Introduction................................................................................................................ 1 2. Objectives ................................................................................................................... 2 3.1. The Amine Scrubbing Method for CO2 Capture ................................................ 4 3.2. The Product Recovery Train............................................................................... 5 3.3. PRT Operating Ranges ....................................................................................... 6 4. Impact of Operating Pressure on Plant Efficiency..................................................... 9 5. Baseline Conditions and Assumptions .................................................................... 11 6. Air and Oxy-fuel Ambient Case Study.................................................................... 17 6.1. Design Considerations ...................................................................................... 17 6.2. Oxy-fuel Ambient Case Recycle Schemes ....................................................... 18 6.3. Boiler Performance Results .............................................................................. 20 7. TIPS Case Study I – Existing Turbine..................................................................... 30 7.1. Design Considerations and Fuel Delivery System............................................ 30 7.2. Condensing Heat and Boiler FWH System ...................................................... 30 7.3. Boiler Performance Results ............................................................................... 31 8. TIPS Case Study II – New Turbine ......................................................................... 41 8.1. Design Considerations for FWH System.......................................................... 41 8.2. Boiler Performance Results .............................................................................. 41 8.3. PRT Performance Results ................................................................................. 47 9. Key Findings and Analysis of Technical Aspects ................................................... 48 10. Conclusions............................................................................................................ 49 11. Suggestion for Further Work ............................................................................. 49 12. Acknowledgements................................................................................................ 50 13. References.............................................................................................................. 50

List of Figures 2.1 Pressure-temperature phase diagram for pure CO2. ………………………….. CO2 stream vapour fraction as a function of oxygen and nitrogen impurity 2.2 concentration. ………………………………………………………………..... 2.3 CO2 recovery rate as a function of temperature and pressure. ……………….. 2.4 CO2 purity as a function of temperature and pressure. ……………………….. CO2 purity as a function of temperature and pressure for a recovery rate 2.5 greater than or equal to 90%. ………………………………………................. 5.1 Schematic of the boiler steam/water cycle. …………………………………... 6.1 The oxy-fuel process with dry recycle. ………………………………………..

6 7 8 8 9 16 19

List of Tables 5.1 5.2 5.3 5.4 Part 2

Proximate analysis of coals (% by weight). ………………………………... Ultimate analysis of coals (% by weight). ………………………………….. Coal properties. …………………………………………………………….. Air and oxygen analyses. …………………………………………………...

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Technical and Economic Feasibility Study of a Pressurized Oxy-fuel Approach to Carbon Capture – Part 1

Key furnace information for air case and ambient oxy-fuel case. …………. Key plant performance data firing at ambient pressure. …………………… Plant auxiliaries power consumption at ambient pressure (kW). …………... Key boiler performance data firing at ambient pressure. …………………... Furnace outlet flue gas properties firing at ambient pressure. ……………... Flue gas and steam temperatures (°C) for Wyoming PRB firing at ambient 6.6a pressure. …………………………………………………………………….. Flue gas and steam temperatures (°C) for Illinois No. 6 firing at ambient 6.6b pressure. …………………………………………………………………….. Steam/water pressure (bar) firing at ambient pressure. …………………….. 6.7 Main steam/water mass flow (kg/s) firing at ambient pressure. …………… 6.8 FWH bleed steam inlet conditions firing at ambient pressure. …………….. 6.9 6.10 FWH main water outlet inlet conditions firing at ambient pressure. ………. 6.11 Section heat duties firing at ambient pressure (kJ/h). ……………………… 6.12 Flue gas velocities (m/s) firing at ambient pressure. ………………………. 6.13a Wyoming PRB air heaters performance firing at ambient pressure. ……….. 6.13b Illinois No. 6 air heaters performance firing at ambient pressure. …………. 6.14 Final flue gas (entering the PRT) properties firing at ambient pressure. …... Key plant performance data for TIPS configuration No. 1. ………………... 7.1 Key plant performance data for TIPS configuration No. 1. ………………... 7.2 Key boiler performance data for TIPS configuration No. 1. ……………….. 7.3 Furnace outlet flue gas properties for TIPS configuration No. 1. ………….. 7.4 7.5 Temperatures (°C) for TIPS configuration No. 1. ………………………….. Steam/water pressures (bar) for TIPS configuration No. 1. ………………... 7.6 Steam/water mass flow (kg/s) for TIPS configuration No.1. ………………. 7.7 FWH bleed steam inlet conditions for TIPS configuration No. 1. …………. 7.8 FWH main water outlet inlet conditions for TIPS configuration No. 1. …… 7.9 7.10 Section heat duties (kJ/h) for TIPS configuration No. 1. …………………... 7.11 Flue gas FWH performance for TIPS configuration No. 1. ………………... 7.12 Final flue gas (entering the PRT) properties for TIPS configuration No. 1. .. 7.13 PRT condensing heater No. 1 performance for TIPS configuration No. 1. ... 7.14 PRT condensing heater No. 2 performance for TIPS configuration No. 1. ... Final flue gas (after PRT condensing heater No. 1) properties for TIPS 7.15 configuration No.1 with oxygen purity at 95%. ……………………………. Key plant performance data for TIPS configuration No. 2. ………………... 8.1 Key plant performance data for TIPS configuration No. 2. ………………... 8.2 Key boiler performance data for TIPS configuration No. 2. ……………….. 8.3 Furnace outlet flue gas properties for TIPS configuration No. 2. ………….. 8.4 8.5 Temperatures (°C) for TIPS configuration No. 2. ………………………….. Steam/water pressure (bar) firing at TIPS configuration No. 2. …………… 8.6 Steam/water mass flow (kg/s) for TIPS configuration No. 2. ……………… 8.7 Section heat duty (kJ/h) for TIPS configuration No. 2. ……………………. 8.8 Flue gas FWH performance for TIPS configuration No. 2. ………………... 8.9 8.10 Flue gas FWH performance for TIPS configuration No. 2. ………………... 8.11 PRT condensing heater performance for TIPS configuration No. 2. ………. 6.1 6.2 6.3 6.4 6.5

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17 20 21 22 22 23 23 24 25 25 26 27 27 28 28 29 31 32 33 33 34 34 35 35 36 37 37 38 39 40 40 42 42 43 43 44 44 45 45 46 46 47

Technical and Economic Feasibility Study of a Pressurized Oxy-fuel Approach to Carbon Capture – Part 1

Glossary of Acronyms

AH ASME ASU CBM CCPC COE CW CETC – Ottawa ECON EOR ESP FGD FOT FWH HHV HP HTSH IGCC IP ITM LHV LP LTSH NBS OFA O&M PFBC PRB PRIMRH PRT RH RSH SECDRH TEPS TIPS

Air heater American Society of Mechanical Engineers Air separation unit Coal bed methane Canadian Clean Power Coalition Cost of electricity Cooling Water CANMET Energy Technology Centre – Ottawa Economizer Enhanced oil recovery Electrostatic precipitator Flue gas desulphurization Furnace outlet temperature Feed water heater Higher heating value High pressure High temperature superheater Integrated gasification combined cycle Intermediate pressure Ion transport membrane Lower heating value Low pressure Low temperature superheater National Bureau of Standards Over fire air Operating and maintenance Pressurized fluidized bed combustion Powder River Basin Primary reheater Product recovery train Reheater Radiant superheater platen Secondary reheater ThermoEnergy Power Systems ThermoEnergy Integrated Power System

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Technical and Economic Feasibility Study of a Pressurized Oxy-fuel Approach to Carbon Capture – Part 1

Abstract

This study was conducted to investigate the technical feasibility of the ThermoEnergy Integrated Power System (TIPS) [1] which is a pressurized oxy-fuel fired process using Wyoming PRB (PRB) and Illinois No. 6 coals in a 100 MWe (net) boiler. In order to fully investigate the technical and economic advantages of the TIPS process, comparable air-fired pulverized coal plants and various oxy-fuel configurations operating at ambient pressure as well as at elevated pressures are reported. Results from TIPS plants optimized for CO2 recovery using different oxygen purities are also investigated. It was found that the TIPS process has significantly higher plant thermal efficiency with full CO2 capture than the air-fired and ambient oxy-fuel cases. With CO2 capture, the plant thermal efficiency of TIPS process is at about 30% while the corresponding airfired case is at about 25% and the ambient oxy-fuel case at 24%. The TIPS process can handle a very wide range of fuels. The process can utilize the full energy potential of the fuel by almost completely condensing out the water vapor in the flue gas and by making the water vapor in the flue gas a useful heat source. It was further found that the amount and quality of the heat of condensation can be used to significantly reduce the requirements for extraction steam from the turbine used for the boiler feed water heating (FWH) system requirements. Hence, the TIPS process allows for a considerable thermal efficiency gain when compared with most conventional combustion processes that only use the low heating value of the fuel. By operating at elevated pressure, TIPS also has the advantage of high CO2 recovery at ambient temperatures if oxygen of high purity is employed for combustion. For example, for PRB coal, it was discovered that the TIPS can have essentially 100% CO2 recovery with more than 95% purity. Furthermore, the recovery can be carried out at plant operating pressure and ambient temperature. Thus, in such a case, the need for a CO2 recovery system involving multi-stage compression and refrigeration is eliminated, resulting in significant energy, capital, and operating and maintenance savings compared with other CO2 recovery systems. Like other oxy-fuel systems, the TIPS process is advantageous over air-fired systems because it allows for the integration of an emission control approach [1]. In addition, the condensation steps of the TIPS process scrubs out particles eliminating the need for an electrostatic precipitator (ESP) and/or baghouse, normally required in other oxy-fuel systems. The benefits of the TIPS process are particularly advantageous when high moisture fuels are utilized. In these cases, the gain in plant thermal efficiency is high as is the CO2 content in the final flue gas. It is important to point out that these advantages are not shared by other oxy-fuel combustion systems due to the presence of infiltration air, and their inability to utilize (or fully utilize) the heat of condensation.

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Technical and Economic Feasibility Study of a Pressurized Oxy-fuel Approach to Carbon Capture – Part 1

1. Introduction At the request of ThermoEnergy Power Systems (TEPS) LLC of Hudson, Massachusetts, the CANMET Energy Technology Centre-Ottawa (CETC-Ottawa) undertook a technical and economic feasibility study of the ThermoEnergy Integrated Power System (TIPS) process. TIPS is a patented [1] process developed by TEPS LLC that uses oxygen instead of air for combustion (known as oxy-fuel combustion) at elevated pressure, thus eliminating nitrogen from the feed gas to the combustor and producing a highly enriched CO2 stream ready for sequestration and industrial applications such as enhanced oil recovery (EOR) and coal bed methane (CBM). Many advanced and conceptually new power generating processes firing coal have been proposed as answers to the climate change problem facing electrical utilities. Oxy-fuel combustion has been viewed as a simple and elegant method to solve the CO2 emission problem for utilities and other combustion related industries. It can be applied to both new and existing units. Furthermore, the key technology components in oxy-fuel combustion are mostly “off the shelf” technologies that have been widely used for a long period of time. In addition, the existing work force has rich experience with these technologies. Therefore, this ensures that operating staff would be able to perform their duties with a minimum of additional training. As a consequence, oxy-fuel technology has attracted worldwide attention as one of the key technologies for the capture and sequestration of CO2 from fossil fuel combustion. In Europe and the USA, major developments have been underway for the demonstration of this technology at the industrial level. In fact, Vattenfall Europe AG has been working on a 30 MWe oxy-fuel power plant demonstration project in Germany ready for operation by 2008 and Jupiter Oxygen of Chicago has started to retrofit a 25 MWe at Orrville, Ohio for oxy-fuel operation for 2008 as well. The TIPS process is an advanced concept of oxy-fuel combustion, and as such, is quite different from atmospheric oxy-fuel combustion. By operating at pressure, the TIPS plant also has the potential to be more compact than conventional atmospheric combustion systems of similar capacity. By pressurizing the entire process, it enables the plant operating points to be shifted from those of the conventional areas to a pressure and temperature range where gas to liquid phase change can occur. As a consequence, water vapor in the flue gas can be condensed out at much higher temperatures making it useful for heating the boiler feed water (BFW) or condensate return. Thus, compared with a conventional boiler operating at ambient pressure, the TIPS process almost fully utilizes the energy content of the fuel. TIPS uses the higher heating value (HHV) of the fuel rather than the lower heating value (LHV). Given the fact that the TIPS process has this advantage, it is not surprising that it can use a very wide range of fuels including low rank coal, lignite, Orimulsion®, biomass and municipal solid waste. The TIPS process can not only utilize the latent heat of the fuel by operating at elevated pressure, but, more importantly it can also condense the CO2 in the flue gas at ambient heat sink temperatures. In the authors’ view, this is far more beneficial than the efficiency gain due to latent heat recovery. It is well established that the oxy-fuel process

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Technical and Economic Feasibility Study of a Pressurized Oxy-fuel Approach to Carbon Capture – Part 1

operating at ambient pressure requires the use of multi-staged compression together with inter-stage cooling, typically termed the product recovery train (PRT), for CO2 capture and recovery [2], [3]. The final PRT operating conditions are usually in the neighborhood of 28 bar and -60°C in order to ensure high CO2 capture rates with high product purity. Clearly, the PRT is an energy intensive process particularly because of the considerable refrigeration requirements. Yet, in the TIPS process, CO2 capture may occur at ambient temperatures resulting in significant capital, and operating and maintenance (O&M) cost savings. Another key advantage of the TIPS process is that of integrated emissions control. It is known that for a typical coal-fired power plant, the emissions control percentages of capital and annual costs are at about 25% and 38% of the total plant costs [4]. Yet, the TIPS process, operating at elevated pressure, can scrub particles out from the flue gas, and condense acid gases (SO2 and SO3) and mercury into the product stream. It is also worth mentioning that a small amount of sulphur compounds helps in improving oil miscibility, and there is little concern regarding corrosion due to the dry CO2 stream. Hence, significant capital and annual savings can be achieved in this respect by using the TIPS process.

2. Objectives The objectives of this study were to: 1. Establish Design Basis and Configuration Set up major operating parameters and establish a plant configuration the TIPS process operation with Rankine cycle. 2. Flow Sheet Development Based on the design parameters and configuration, a flow sheet, including all major unit operations and material and energy flows, was developed. A steadystate computer model was built to simulate the performance of the basic TIPS process based on the detailed flow sheet layout. The computer model consisted of all major components of the boiler. These included the furnace, superheaters, reheaters, economizer, air heaters (as applicable), condensing heat exchanger, mill, and auxiliary parts. 3. Technical Feasibility Study For each of the unit operations, heat duty, mass flows, temperatures, estimated heating surface areas, and other engineering considerations/specifications were established. 4. Major Equipment Sizing Analysis The combustor, SH/RH/Econ, and the condensing heater exchange was sized based on the process data from the technical feasibility study. The sizing analysis will mainly relied on information gathered from a literature survey together with some manufacturers’ specifications.

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Technical and Economic Feasibility Study of a Pressurized Oxy-fuel Approach to Carbon Capture – Part 1

Two coals, Illinois No. 6 and Wyoming PRB, were selected as fuels for TIPS technical and economic feasibility study. An air-based coal-fired power plant at 100 MWe (net) was designed, sized, and cost for each fuel. The design was optimized for the plant thermal efficiency rather than the capital cost. Based on the air case for each fuel, an oxy-fuel power plant operating at ambient pressure was studied. This analysis provided many insights about how to size and operate the oxy-fuel plant. For example, the recycle rate, heat transfer rates, tube bank velocities, and so on, were studied. For each fuel, the ambient pressure oxy-fuel case was further developed and the model converted to a TIPS plant. Several configuration scenarios were investigated for the TIPS concept and the impact on plant performance using 99.5% and 95.0% oxygen as well as the PRT was explored. All technical studies include detailed mass and energy balances of all major components such as furnace, air heater, pulverizer, etc. Also included are detailed steam/water arrangements and a feed water heating (FWH) system analysis. Thermal efficiencies of the boiler as well as total plant efficiency were calculated. A detailed conceptual design for the CO2 recovery in the air case was not performed; however, amine scrubbing technology was chosen to estimate typical energy consumption and costs, based on data from literature [5]. The well known Peng-Robinson Equation of State was used in this study to calculate all necessary thermodynamic properties for all fluids other than steam and water. Properties of steam and water were computed using the American Society of Mechanical Engineers (ASME) and National Bureau of Standard (NBS) steam tables. Aspen HYSYS1 simulation software was used throughout this study.

1

Aspen HYSYS is a registered trademarks of Aspen Technology, Inc., Cambridge, MA, U.S.A.

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Technical and Economic Feasibility Study of a Pressurized Oxy-fuel Approach to Carbon Capture – Part 1

3. CO2 Recovery Options for Combustion Processes There are two major methods for capturing CO2 from combustion processes, namely amine scrubbing and the use of a PRT as described above. The recovery rate of CO2 is defined as the percentage of the mass flow of CO2 in the final product stream, ready for industrial application or geological sequestration, compared to the mass flow of CO2 out of the combustion process. The CO2 purity is defined as the volume percentage of the CO2 in the final product stream. It is not clear what the optimum product CO2 purity is from economic and geologic points of view. Few studies have addressed this important issue. Certainly, the required purity depends on the product application and geological properties of the specific site. For example, in some EOR applications, the purity of CO2 for pipeline delivery is specified at 95% [6]. However, it is known that streams with lower than 95% CO2 purity are routinely injected at other sites [7]. It is clear, though, that sequestration of low CO2 concentration streams is not particularly economical and may not, in fact, be geologically feasible. Additionally, the CO2 purity issue has a substantial impact on the CO2 capture processes. The impact is not only on energy consumption but also on the process operating ranges since it is known that there is a reciprocal relationship between the product recovery rate and product purity [2]. Since the rationale for oxy-fuel combustion is almost exclusively for the capture and sequestration of the CO2 from the flue gas, it may be that any process with a lower than 90% recovery rate may not be acceptable. It is also felt that any value added CO2 application will dominate the CO2 market at earlier stage. Hence, a technology that can produce higher purity CO2 has much better market potential than those that cannot. 3.1. The Amine Scrubbing Method for CO2 Capture The CO2 concentration in the flue gas of an air-fired combustion process is very low, usually below 15% by volume. The dominant component in the flue gas is nitrogen, mainly from the combustion air, at levels close to 70%. It is difficult to separate the CO2 from the rest of flue gas. Currently, the most well established method of carbon capture from air-fired combustion systems is the so called amine scrubbing method. Amine scrubbing is a chemical absorption process using amine solvents to capture the CO2. The amine scrubbing process has a very stringent limit with respect to flue gas impurities. Species such as NOx, SOx and hydrocarbons must be removed before the gas can be sent into the amine scrubbing process. Clean flue gas is passed through an absorption column in which the amine reacts with the CO2 and selectively absorbs it from the gas stream. The CO2-rich amine is then heated, upon which the CO2 is released as nearly pure CO2 gas. In fact, the purity of the CO2 gas is so high that the gas can be used in food industry applications. The energy consumption of the amine scrubbing process is very high. The energy input needed to regenerate the amine is about 2756 kJ/kg of CO2 [5]. In addition, the amine scrubbing process has a large footprint requiring a very large plant area. It is estimated

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Technical and Economic Feasibility Study of a Pressurized Oxy-fuel Approach to Carbon Capture – Part 1

that for a 400 MWe coal-fired power plant, the square footage needed for the amine scrubbing process is nearly two or three times as big as the power plant itself [8]. 3.2. The Product Recovery Train The motivation of oxy-fuel is to obtain a highly enriched CO2 flue gas stream by using oxygen instead of air for combustion. By eliminating nitrogen from the combustion medium, the major components in the flue gas out of the oxy-fuel system are CO2 and H2O. In most oxy-fuel configurations, part of the flue gas is recycled back into the combustion chamber to quench the high flame temperature. The remainder of the flue gas is sent to the CO2 capture system. Due to the high flue gas concentration of CO2 in oxy-firing cases, there is no need to use a chemical process to separate the CO2 from the flue gas. All that is required is that the flue gas be compressed and cooled. The multistage compression and cooling of CO2 for capture is generally referred as the product recovery train (PRT). The PRT was thoroughly studied and investigated in a paper presented at the 2005 Clearwater Coal Conference [2]. The energy requirement for the PRT is significant, but not as great as that for the ASU. In general, it is believed that about 7 to 10% of the total output of the power plant is consumed by the PRT [4]. This is mainly due to the compression shaft power and refrigeration duty necessary to achieve sufficiently high recovery rates and product purities [2]. In general, the refrigeration duty is always greater than the compression duty. As a result, CANMET’s studies have been constrained so that excessive cooling is not employed. In fact, attempts to avoid refrigeration entirely have been considered in previous work on the PRT. In subsequent work the lowest cooling temperature for the PRT was artificially set at –20°C. However, it was found that under such a constraint, the recovery rate of CO2 for some gases from the oxy-fuel process were unacceptably low [2]. The CO2 concentration in the product flue gas in a typical oxy-fuel pulverized coal boiler ranges from 75% to 90% on a dry volumetric basis [9]. CO2 gas stream impurity is largely due to infiltration air leaking into the furnace and boiler sections and impurities consisting of nitrogen and argon associated with the reactant oxygen stream, uncondensed water vapor, excess oxygen, and oxidation products (SOx, NOx, etc.) in the flue gas. The flue gas must be further processed to increase its CO2 concentration in order to produce a liquid product stream with a CO2 purity of 95% or higher for enhanced oil recovery (EOR) or coal bed methane (CBM) applications. The performance of the PRT and its energy requirements are closely associated with the ASU and the combustion unit. Since the presence of nitrogen and oxygen makes the thermodynamic behavior of the flue gas very complicated, a high purity of oxygen from ASU and little infiltration air are desired. In general, boilers are operated under slightly negative pressure; however, this practice must be revisited in oxy-fuel operation since it tends to introduce too much air leakage into the flue gas, making it very difficult for the PRT to produce high purity CO2 with high recovery rates. Due to this consideration, most oxy-fuel pilot facilities are operated under slightly positive pressure [10, 11].

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Technical and Economic Feasibility Study of a Pressurized Oxy-fuel Approach to Carbon Capture – Part 1

Operating at high pressure with CO2 gas as the circulating fluid, infiltration air is not a concern in the TIPS process. However, as it was shown in the detailed case studies in subsequent sections of this report, oxygen purity can have a dramatic impact on the operating ranges and configurations of the PRT. As a consequence, oxygen purity also leads to significant capital and operational costs differences. 3.3. PRT Operating Ranges The thermodynamic properties of CO2 are well studied. Fig. 2.1 is a pressuretemperature plot for CO2. The liquid phase exists in the region above the curve. This figure provides information for choosing the PRT operating conditions. For example, if the temperature of final liquid product stream leaving PRT is desired to be at -20°C, then the pressure must be greater than approximately 20 bar. Similarly, if the PRT is operated at more than 60 bar, the vapor to liquid phase change can occur at ambient heat sink temperatures.

80

Pressure (bar)

60

40

20

0 -100

-80

-60

-40

-20

0

20

40

Temperature (°C)

Figure 2.1 – Pressure-temperature phase diagram for pure CO2. It is important to emphasize that the information provided by Fig. 2.1 can only be used as a reference point. Flue gas compositions are different from that of pure CO2 gas. Therefore, a flue gas may have considerably different thermodynamic properties. Consequently, flue gas composition has a significant impact on the performance of the PRT in terms of the recovery rate and the product stream purity. Failing to realize this key point has led to many wrong assumptions and conclusions in various studies. Part 1

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Technical and Economic Feasibility Study of a Pressurized Oxy-fuel Approach to Carbon Capture – Part 1

For example, from Fig. 2.1, it is easy to see that CO2 is in the liquid phase at 20°C and 70 bar. This temperature-pressure point lies far away from the critical line dividing the liquid and vapor regions. As consequence, it should be a stable point with regards to small amounts of gas impurities. Figure 2.2 shows how gas impurities can profoundly change the phase equilibrium of a CO2-rich stream. In the CO2-rich stream under consideration, the only impurities are oxygen and nitrogen. For example, when 3.0% oxygen and 3.5% nitrogen are present in the CO2 stream, the vapor fraction of the stream is more than 50% on a molar basis. This means that with these impurities the recovery rate of CO2 will decrease from 100% to less than 50%. This reduction of the recovery rate caused by such small amounts of impurities is truly remarkable.

Figure 2.2 – CO2 stream vapour fraction as a function of oxygen and nitrogen impurity concentration.

On the other hand, choosing an even higher pressure and lower temperature does not necessarily guarantee that the liquid product will meet the desired standards. For example, at 80 bar and 5°C, all the CO2 in a flue gas composed of 90% CO2, 4% O2, and 6% N2 will be condensed. However, at such conditions, the whole stream is in the liquid phase: that is, the CO2 component will not separate from the other species.

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Technical and Economic Feasibility Study of a Pressurized Oxy-fuel Approach to Carbon Capture – Part 1

Figure 2.3 – CO2 recovery rate as a function of temperature and pressure.

Figure 2.4 – CO2 purity as a function of temperature and pressure.

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Technical and Economic Feasibility Study of a Pressurized Oxy-fuel Approach to Carbon Capture – Part 1

80

70

Pressure (bar)

60

50

88% 40

89% 90% 91% 92%

30

93% 94% 95%

20

10 -50

-40

-30

-20

-10

0

10

20

Te mpe rature (°C)

Figure 2.5 – CO2 purity as a function of temperature and pressure for a recovery rate greater than or equal to 90%. Figures 2.3 and 3.4 illustrate how the recovery rate and product purity are affected by temperature and pressure for a typical oxy-fuel flue gas. As the temperature decreases and the pressure increases, more CO2 condenses resulting in higher recovery rates. In general, CO2 purity follows a similar trend. However, after a certain point, as the pressure continues to rise and/or the temperature drops further, other gas species begin to condense with the CO2. The result is a reduction in the purity of the product CO2. Figure 3.5 is an intersection of Figs. 2.3 and 2.4 at 90% or higher recovery rates. This figure demonstrates the effect of pressure and temperature on the purity, as noted above. Furthermore, the operating region for a given recovery rate becomes smaller as the purity requirement increases. 4. Impact of Operating Pressure on Plant Efficiency The impact of plant operating pressure on plant thermal efficiency is straight forward. With high pressure operation, the water vapor in the flue gas can be condensed out at higher temperatures than those required at low pressures. In cases where the quantity and quality of the condensing heat are high, the condensing heat can be used resulting in a plant efficiency gain. In general, in the air case operating at ambient pressure, flue gas exits the boiler island at about 150°C. It is obvious that at such temperature, water vapor cannot be easily condensed out. Consequently, the latent heat of the moisture from the fuel and air plus the water from hydrogen combustion cannot be readily recovered. Thus, by definition, the lower heating value of the fuel is utilized in the process, rather than the higher heating value. Trying to decrease this temperature and condensing the water in an attempt to

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Technical and Economic Feasibility Study of a Pressurized Oxy-fuel Approach to Carbon Capture – Part 1

capture the heat will yield large amounts of heat at lower temperatures which are not readily useable within the power generation cycle. In typical pressurized combustion systems using air, such as pressurized fluidized bed combustion (PFBC) boilers, an expansion turbine is used to generate additional power. When CO2 recovery is required, it makes no sense to expand the pressurized flue gas since the final CO2 product must be in a pressurized liquid state. More importantly, it is difficult to obtain significant efficiency gains with the pressurized air case by utilizing a condensing heat exchanger. This is due to the large volume of nitrogen in the flue gas (about 70%), making the water vapor fraction small. Thus, because of the low condensing temperatures needed, the heat of condensation is of a low grade. However, the situation is very different in the oxy-fuel case, in which the flue gas water vapor content is much higher. In fact, the water vapor content is dependent on the fuel of choice. In the case of PRB and lignite coals, the water vapor fraction in the flue gas may easily be more than 25% by volume. Such high water vapor fractions make it much easier to condense the water out at higher temperatures in a condensing heat exchanger when high pressure is employed. This is one of the key advantages of the TIPS process. At a given condensing temperature, it is easy to see that the higher the pressure, the more water will condense out of the flue gas. However, after a certain point, increasing the pressure results in diminishing amounts of water condensation. For example, for flue gas with 65% CO2 and 27% H2O at 25°C and 3.5 bar, more than 97% of the water condenses out; resulting in a flue gas water vapor volume of less than 1%. Hence, while the potential to recover more water at this pressure still exists, it is rather small. In other words, the water recovery efficiency difference as one moves from ambient to high pressure is significant but flattens out at higher pressures. As the operating pressure increases the condensing temperature rises. Use of the appropriate pressure will ensure that the condensing heat can be used in the process. The question is how much benefit exists in employing high operating pressures. Without considering the cost and energy penalties, a quick back-of-the-envelope calculation may be carried out with the higher to lower heating value ratio. Interestingly, high pressure operation also has a negative impact on the boiler efficiency. This is due to the fact that high pressure causes the flue gas high heat capacity to increase. As a result, assuming that all other factors are the same, the dry flue gas losses become greater at higher pressures given the same temperature.

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Technical and Economic Feasibility Study of a Pressurized Oxy-fuel Approach to Carbon Capture – Part 1

5. Baseline Conditions and Assumptions 5.1. Fuels Two coals, Wyoming PRB sub-bituminous and Illinois No. 6 bituminous, were selected for this study due to their wide use and because they are representative over a range of different fuels. Illinois No. 6 coal is a high volatile C bituminous coal which has been used in many technical feasibility studies as a reference coal. Wyoming PRB is a particularly unique fuel. It has very high moisture content, making its heating value small compared to most other coals. However, it has very low sulfur content. Both coals have similar ash softening temperatures. Illinois No. 6 coal has high fouling characteristics; therefore, it is important to make sure that the furnace outlet temperature of the flue gas is below the ash softening temperature of the coal if a dry ash combustor is employed. Proximate and ultimate analyses and other properties of the two coals are given in Tables 5.1 through 5.3. Table 5.1 – Proximate analysis of coals (% by weight).

Moisture Volatile Matter Fixed Carbon Ash

Wyoming PRB

Illinois No. 6

31.63 29.73 34.08 4.57

12.00 33.00 39.00 16.00

Table 5.2 – Ultimate analysis of coals (% by weight). Wyoming PRB

Illinois No. 6

Moisture Carbon Hydrogen Sulfur

31.63 46.59 3.38 0.37

12.00 55.35 4.00 4.00

Nitrogen

0.63

1.08

Oxygen

12.84

7.47

Ash

4.57

16.00

Table 5.3 – Coal properties. Wyoming PRB

Illinois No. 6

High Heating Value (kJ/kg) Low Heating Value (kJ/kg)

18955 17443

23492 22326

Ash softening temperature (°C)

1135

1182

Ash initial deformation temperature (°C)

1087

1126

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5.2. Air, Oxygen, and Ambient Conditions The ambient conditions for this study were: Ambient temperature at 25°C, Ambient pressure at 1.0135 bar, Cooling water (CW), from either lake or river sources, available at 15°C.

Table 5.4 – Air and oxygen analyses. Air analysis

% by volume

Nitrogen (N2) Oxygen (O2) Carbon dioxide (CO2) Water (H2O)

77.2646 20.7273 0.0310 1.0500

Argon (Ar)

0.9272

Oxygen from ASU @ 99.5% purity

% by volume

Oxygen (O2)

99.5000

Nitrogen (N2)

0.0000

Argon (Ar)

0.5000

Oxygen from ASU @ 95% purity

% by volume

Oxygen (O2)

95.0000

Nitrogen (N2)

2.5000

Argon (Ar)

2.5000

The cost of oxygen production is one of the single biggest factors in plant thermal efficiency decreases and the resultant increase in the cost of electricity (COE) for oxyfuel due to significant parasitic energy needs for a cryogenic air separation unit (ASU). Many novel oxygen production technologies are rapidly developing to meet the need of supplying large quantities of oxygen at high purity. Most notable are the ion transport membrane (ITM) technology developed by Air Products, Inc. and Praxair, Inc. and the ceramic autothermal recovery oxygen generation technology developed by the BOC Group. Whether the cost of oxygen production will be reduced remains to be seen. It has been suggested that the ITM technology cost is 35% lower than that of cryogenic air separation [12]. Oxygen purity also has a significant impact on process energy requirements and the cost of CO2 recovery. The CO2 recovery process is typically known as a product recovery train (PRT) [2], [3]. In this study, 99.5% and 95% oxygen purities were chosen. Several well-known oxy-fuel technology studies employed 99.5% oxygen from cryogenic ASUs. Most notably, the study done by Clean Coal Power Coalition (CCPC) of Canada in 2003 Part 1

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employed 99.5% oxygen, even though the use of 95% oxygen is more economical for a cryogenic ASU. Infiltration air can have serious impact [2], [4], [9] on the performance of the product recovery train and adds significant cost to the ambient oxy-fuel system. Ideally, the oxyfuel unit should be well sealed to minimize air infiltration. It is believed that a new unit could have air infiltration levels as low as 1%. However, infiltration air in a retrofitted unit could be as high as 5 to 6%. Part of the infiltration air leaks into the furnace while the remainder enters the backend system. In this study, it was assumed that the infiltration air was 3% and was well distributed in both the furnace and the backend system. Because the TIPS process is operated at elevated pressure inside a pressurized vessel, no air can infiltrate. CO2 gas is employed as the fluid between the pressure vessel shell and the boiler to keep the shell temperature low. Approximately 2% of the shell CO2 gas may be assumed to leak into the boiler system; however, it was decided that no CO2 gas leakage credit be given in order to fully investigate the TIPS technical and economic aspects. The oxygen purity’s impact on oxy-fuel operation and economics is well understood [10]. In this study, an oxygen purity of 99.5% was chosen. It should be noted that the oxygen purity has little impact on the performance of the boiler. However, the oxygen purity has a big influence on PRT performance both in terms of plant configuration and economics. This point will be further discussed in later sections. 5.3. Steam Turbine and Boiler A particularly common steam turbine was selected for this study: it is a single reheat condensing steam turbine rated at 3600 + 3600/3600 rpm. The main steam conditions are specified to be 540.2°C and 103.5 bar while those of the reheat steam are 540°C and 25.31 bar. The turbine consists of high pressure (HP), intermediate pressure (IP), and low pressure (LP) sections. The design exhaust steam pressure of the LP section is 0.04826 bar with vapor fraction at about 90%. The net turbine output in the air case is rated at 100 MWe (net). The steam conditions were optimized for the two selected coals. The boiler designed for this study is a pulverized coal-fired tower boiler with twin cell furnaces. The convective components consist of one radiant superheater platen section (RSH), a primary reheater section (PRIMRH), a secondary reheater section (SECDRH), a high temperature superheater (HTSH) section, a low temperature superheater section (LTSH), and an economizer (ECON). The economizer is equipped with a by-pass control. The main steam temperature is controlled with attemperating spray and the reheat steam temperature is controlled with tilting burners. A trisector regenerative air heater (AH) in the baseline air and ambient oxy-fuel cases was used to preheat the primary and secondary air/recycle gas upstream of the milling system and wind box.

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For the TIPS process, as noted later, instead of heating the recycle gas in air heaters, the flue gas is used to heat the water in the steam/water side through a condensing heat exchanger. Therefore, air heaters were not required in the TIPS case. The TIPS system results in a much smaller furnace configuration and in order to take advantage of this there are a few variations that have been examined. Furnaces are generally sized for ash content and handling as well as heat transfer to the walls for steam generation. Using the TIPS approach can minimize the furnace size if the ash characteristics are managed. The two methods of doing this are using a wet furnace that runs the slag (also called a slagging furnace) similar to some gasification systems or using a fluid bed that is run at a temperature less than the ash deformation temperatures and therefore handles only dry ash. For the purposes of this study the first approach (slagging reactor) was used. This type of furnace is more similar to the baseline configurations and therefore was used to get better comparison with the baseline systems. Examination of the second approach of using a fluid bed has many advantages and should be considered for further study. Using the slagging furnace approach may necessitate the use of spaced generating sections for steam generation which can be accommodated within the furnace shell or convective pass. Because using this approach reduces the ash load to the convective pass to approximately 30% there is the possibility of using a tighter spacing within the convective passes for the same coal at the same flue gas temperature. To keep a conservative design flue temperatures entering the convective passes using the slagging furnace were maintained at similar temperatures to those employed in the baseline dry furnace situations. 5.4. Pollution Control System and Auxiliaries The pollution control equipment for this boiler in the baseline air case includes a dry electrostatic precipitator (ESP), a flue gas desulphurization (FGD) unit, and low NOx burners together with over fire air (OFA). Due to the potential advantage of integrated emission control [13] in the oxy-fuel process and the TIPS process ability to scrub out particles, no emissions control equipments were included in the TIPS scenarios. Plant auxiliaries include boiler primary and secondary air fans, and the boiler induced draft fan. Pumps for boiler forced circulation, condenser cold water flow, condensate return, boiler feed, boiler feed booster and feed water drainage are included in the auxiliaries. 5.5. Feed Water Heater System and Steam Cycle The feed water heater (FWH) system consists of five steam-water heaters. They are of type D-D-C-D-P where the first heater is of type P. For each heater, steam drawn (termed bleed steam) from the turbine is used to heat the condensate return. The third heater, of type C, is really a mixer. First, the condensate return water, the steam, and any condensing water from any other heaters are heated by the steam by

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mixing them together. Then the resulting water is pumped to high pressure and sent to other heater for further heating. The type D heaters (second, fourth, and fifth heaters) are essentially condensing heater exchangers. The condensing steam, with any condensed water from other heaters, is used to heat the main water. The first heater of type P is rather interesting. It is usually used as the first heater to heat the main water from the condensate return pump. The steam is drawn before the final stage of the LP section. The main water is heated by the steam and condensing water from other heaters. The condensed water from the heater is then pumped to high pressure and mixed with the main water. Water out of the FWH system enters the inlet of the economizer inlet after a small amount is used to desuperheat the main steam. Water out of the economizer is evaporated in the furnace water wall tubes. The main steam is further heated in the radiant superheater (RSH), low temperature superheater (LTSH), and high temperature superheater finish (HTSH Finish). The main steam is then expanded in the HP section of the steam turbine. A small part of the steam leaving the HP section of steam turbine is used to heat the main water in the last FWH heater and the rest is reheated in the primary reheat (Primary RH) and reheat finish sections (RH finish) of the boiler. The reheated steam is then expanded in the IP section of the steam turbine while a small amount of steam is taken out in the middle of the IP section for use in the second last FWH. The outlet of the IP section is further expanded in the LP section while three streams of steam are taken out for various FWH heaters. The partially condensed (about 10%) LP steam is then condensed and pumped back into the first FWH heater. Figure 5.1 is a detailed schematic of the steam cycle.

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Main Steam Reheat Steam

Boiler

HP Turbine

LP Turbine

LP Turbine Condenser

Desuperheating Spray

Condensate Pump

Heater 5

Heater 4

Heater 3

Feed Water Pump 2

Figure 5.1 – Schematic of the boiler steam/water cycle.

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Heater 2

Heater 1

Feed Water Pump 1

Technical and Economic Feasibility Study of a Pressurized Oxy-fuel Approach to Carbon Capture – Part 1

6. Air and Oxy-fuel Ambient Case Study 6.1. Design Considerations Two initial cases were studied in which the boilers were fired with either air or oxygen under ambient pressure. These scenarios are referred to as the air and oxy-fuel ambient cases. Key furnace data are listed in Table 6.1a and Table 6.1b.

Table 6.1a – Key furnace information for air case. Wyoming PRB

Illinois No. 6

Furnace Plan Area (m2)

101.42

92.89

Furnace Height (m)

44.32

38.56

Furnace Volume (m3)

4495

3581

Table 6.1b – Key furnace information for ambient oxy-fuel case. Wyoming PRB

Illinois No. 6

Furnace Plan Area (m )

105.89

98.13

Furnace Height (m)

45.26

39.62

4793

3888

2

3

Furnace Volume (m )

The furnace is designed to ensure that the furnace outlet temperature (FOT) is lower than the fuel ash softening temperature. In the case where a slagging furnace is employed, the FOT may be higher than the ash softening temperature as long as the flue gas temperature entering the first convective section is lower than the ash softening temperature. In an oxy-fuel system, part of the flue gas is recycled back to the furnace for temperature control. Generally, enough gas is recycled such that the furnace outlet temperature (FOT) is below the ash softening temperature to avoid fouling on the convective sections. In one paper [14] presented at the 2005 Clearwater Conference, the authors examined some aspects of boiler sizing under oxy-fuel operation. They pointed out that the key is how to avoid slagging and ash deposition in the lower and upper furnace. The oxy-fuel flue gas exiting the AH is further cooled in a condensing heat exchanger before a portion is recycled back to the furnace. Since the heat of condensation is lowgrade heat, it was not credited as a useful heat source. In fact, CANMET has been put considerable effort to examine methods to use this heat in new and retrofit cases, but to date no feasible solution has been found. In simulations, care was taken to ensure that the primary gas entering the pulverizer had sufficiently high enough temperature and heat capacity to guarantee adequate drying of the coal for proper ignition. The air/recycle gas leakages into the flue gas side in the air

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and oxy-fuel ambient cases were assumed to be at the same ratio for both the primary and the secondary air heaters.

6.2. Oxy-fuel Ambient Case Recycle Schemes Several ways exist to recycle flue gas back to the boiler for the purpose of controlling the FOT. In the past, CANMET has studied the various ways of recycling flue gas for this purpose [9], [15]. The dry recycle scenario, in which the flue gas coming out of the air heaters is cooled to a selected temperature (typically close to the ambient temperature), was selected for the ambient oxy-fuel case study. In this scenario the flue gas water vapor is condensed and the dry flue gas is split into recycle gas and raw product gas for the product recovery train process. Figure 6.1 illustrates the oxy-fuel process with dry recycle. One of the obvious advantages of the dry recycle scheme is improved performance of pulverizers because hot dry gas certainly helps to drive off the moisture from the coal. Wet recycle gases could be used to do the same task; however, using wet gases requires much higher temperatures into the pulverizers.

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Economizer Bypass Raw Product Gas Flue Gas Recycle Economizer Water

Boiler

Furnace SAH

Flue Gas Condenser

PAH

ESP O2

ASU Water

Coal

Tempering Bypass Pulverizers

Figure 6.1 – The oxy-fuel process with dry recycle.

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CETC-Ottawa

Prote

6.3. Boiler Performance Results The boiler’s performance for the air cases and the oxy-fuel ambient case for the two selected coals are presented in this section. Key plant performance data are given in Table 6.2. As expected, Illinois No. 6 coal has better plant gross efficiency than the PRB coal due to the latter’s high moisture content and lower high heating value. The oxy-fuel cases have slightly higher gross efficiencies than the air cases. This is consistent with previous oxy-fuel research [9]. The energy cost for ASU is not included in the oxy-fuel cases when plant gross efficiencies and net efficiencies without capture were calculated. However, all energy consumptions, such as ASU, PRT, Amine & Scrubbing, CO2 compression, were all included in the net efficiencies calculation in the captured cases. Table 6.2 – Key plant performance data firing at ambient pressure. Wyoming PRB

Parameter

Illinois No. 6

Air-fired

Oxy-fuel

Air-fired

Oxy-fuel

24.06

22.38

25.63

24.07

33.20

33.30

35.37

35.82

36.39

36.51

38.77

39.27

Plant net power output (kW)

100000

100000

100000

100000

Plant gross power output (kW)

151804

163669

151286

163110

HP turbine power output (kW)

40160

43298

40490

43650

IP turbine power output (kW)

37381

40298

36110

38930

LP turbine power output (kW)

74263

80063

74710

80560

Fuel heat input (kJ/h, LHV)

1.377 × 109

1.480 × 109

1.335 × 109

1.421 × 109

Fuel heat input (kJ/h, HHV)

1.497 × 109

1.608 × 109

1.405 × 109

1.495 × 109

Net plant heat rate (kJ/kWh, LHV) 13772

14801

13350

14211

Net plant heat rate (kJ/kWh, HHV) 14966

16084

14047

14954

Coal mass flow (kg/s)

21.932

23.570

16.610

17.682

Air mass flow (kg/s)

171.36

Plant net efficiency (%, HHV), with capture Plant net efficiency (%, HHV), without capture Plant gross efficiency (%, HHV), without capture

Oxygen mass flow (kg/s)

164.83 34.156

31.925

The plant net efficiencies with capture for the air cases were slightly higher than those of the oxy-fuel cases. This is due to the significant energy consumptions of the oxy-fuel cases for the ASU and PRT. CO2 capture would result a relative 34% reduction of the plant net efficiency for the air case using amine & scrubbing while for the oxy-fuel it is about 39%.

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Technical and Economic Feasibility Study of a Pressurized Oxy-fuel Approach to Carbon Capture – Part 2

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Table 6.3 – Plant auxiliaries power consumption at ambient pressure (kW). Wyoming PRB

Parameter

Air-fired

Oxy-fuel

Amine Scrubbing and Compression 37713.1

Illinois No. 6 Air-fired

Oxy-fuel

37413.3

ASU

28603.5

28773.0

FGR-cooling

3302.0

3387.8

FGR-fan

161.9

166.1

PRT

17843.7

18307.1

Total CO2 Capture Use Total CO2 Capture Use (% of plant gross output)

37713.1

49911.1

37413.3

50634.0

24.84

30.50

24.73

31.04

SCR

881.7

0.00

886.9

0.00

ESP

517.2

564.9

520.2

579.6

FGD

3043.8

3374.7

3061.6

3461.0

PAC

23.7

25.9

23.9

26.6

In furnace NOx control

50.0

0.00

50.0

0.0

Total Emission Control Use Total Emission Control Use (% of plant gross output)

4516.4

3965.5

4542.6

4067.2

2.98

2.42

3.00

2.49

Boiler primary air fan

380.7

410.6

279.4

300.9

Boiler secondary air fan

398.8

431.1

447.6

484.2

Boiler induced draft fan

2142.4

1755.3

2016.4

1608.3

Boiler fuel delivery

1741.0

1875.6

1318.3

1417.3

Ash handling

159.0

171.3

421.9

453.5

Condenser cold water pump

850.7

935.7

824.6

904.5

Condensate pump

142.9

157.7

146.1

158.9

Boiler feed pump

2980.6

3215.1

3097.7

2242.2

FW heater drain pump

22.4

24.6

22.3

24.3

Miscellaneous plant auxiliaries

756.6

815.6

756.6

813.9

Total Boiler Use Total Boiler Use (% of plant gross output)

9575.1

9792.6

9330.9

8408.0

6.31

5.98

6.16

5.15

Energy requirements of the plant auxiliaries are presented in Table 6.3. CO2 capture for the air cases are about 25% of the plant gross output. For the oxy-fuel case, it counts more than 30%. No NOx control equipment was used for the oxy-fuel case given the well established fact that the oxy-fuel has significant low NOx emissions [4]. The emission control part would consume about 2.5 to 3% of the plant gross output. For the boiler part,

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the major ones are the fuel delivery blower, boiler induced draft fan, and the boiler feed pump. Key boiler performance data are given in Table 6.4. The adiabatic flame temperature has little application significance but it does give some indication of the flame characteristics under various modes of operation. The FOTs in the four cases studied were all below or very close to the value of fuel ash softening temperature with the exception of the air case firing Illinois No. 6 coal. Consequently, increased furnace slagging and ash deposition in convective sections is not expected in the ambient pressure oxy-fuel cases. The furnace residence times of the oxy-fuel cases were longer than those of the air-fired cases; therefore, the carbon burn out rates should be at least as great as those of the air-fired cases. Table 6.4 – Key boiler performance data firing at ambient pressure. Wyoming PRB

Parameter

Illinois No. 6

Air-fired

Oxy-fuel

Air-fired

Oxy-fuel

Boiler efficiency (%, HHV)

83.39

83.59

87.05

87.84

Adiabatic flame temperature (°C)

1906

1914

2020

1875

Furnace outlet temperature (°C)

1112

1141

1178

1119

Recycle rate (%)

72.00

76.00

Recycle flue gas mass flow (kg/s)

123.18

139.42

Table 6.5 – Furnace outlet flue gas properties firing at ambient pressure. Wyoming PRB

Parameter Temperature (°C) Mass flow rate (kg/s)

Air-fired

Oxy-fuel

Air-fired

Oxy-fuel

1112

1141

1178

1119

175.60

169.79

166.99

174.67

1.342

Specific heat (kJ/kg-°C) 3

Actual volumetric gas flow (m /h) Density (kg/m3)

Illinois No. 6

2.465 × 10 0.2565

1.433 6

1.936 × 10 0.3158

1.306 6

2.411 × 10 0.2493

1.374 6

1.862 × 106 0.3378

Composition (% by volume) CO2 H 2O O2 N2 SO2 Ar

14.1509 13.4312 2.6945 68.8588 0.0420 0.8227

65.3716 21.4739 4.8632 7.6304 0.1927 0.4682

13.6498 8.8229 3.3146 72.9726 0.3687 0.8715

69.8086 14.9713 3.9120 8.9029 1.8788 0.5263

From Table 6.5, it can be seen that the mass and volumetric flows of the oxy-fuel cases were similar to those of the air cases. This indicates that boiler retrofit for oxy-fuel Part 1

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operation is feasible. The current approach to ambient oxy-fuel combustion is to design a system capable of operating in both air-fired mode as well as oxy-fuel mode and therefore retrofit and new boiler design approaches are in fact essentially the same. This current attitude enables power generation utilities the use of an oxy-fuel system without major concern for system availability. It also minimizes the risk of purchasing newly designed equipment specific to oxy-firing. Along with these current advantages comes the penalties associated with the higher costs associated with these systems. As systems transition to oxy-firing there will be a comfort level reached within the industry. At that time the technical and economic advantages of second generation approaches such as TIPS will be realized. The perceived risks to utilities of adopting this newer technology will be minimized after gaining operating experience comfort levels with first generation oxy-firing technology.

Table 6.6a – Flue gas and steam temperatures (°C) for Wyoming PRB firing at ambient pressure. Wyoming PRB Air-fired

Section Superheater platen High temperature finish Reheater finish Low temperature superheater Primary reheater Economizer

Flue Gas

Steam

In

Out

In

1112 1003 870.5 765.2 628.1 524.7

1003 870.5 765.2 628.1 524.7 341.7

331.9 445.4 445.9 367.1 359.7 229.8

Oxy-fuel Flue Gas

Steam

Out

In

Out

In

Out

384.5 540.2 540.0 445.4 445.9 294.4

1141 1026 886.8 775.4 629.4 518.5

1026 886.8 775.4 629.4 518.5 318.5

331.9 445.4 445.9 367.1 359.7 229.8

384.5 540.2 540.0 445.4 445.9 294.4

Table 6.6b – Flue gas and steam temperatures (°C) for Illinois No. 6 firing at ambient pressure. Illinois No. 6 Air-fired

Section Superheater platen High temperature finish Reheater finish Low temperature superheater Primary reheater Economizer

Flue Gas

Steam

In

Out

In

1178 1062 922.3 812.6 663.1 547.7

1062 922.3 812.6 663.1 547.7 353.1

331.9 444.8 446.0 364.7 353.6 229.8

Oxy-fuel Flue Gas

Steam

Out

In

Out

In

Out

383.9 540.0 540.0 444.8 446.0 295.8

1119 1005 866.3 756.8 606.5 489.3

1005 866.3 756.8 606.5 489.3 287.7

331.9 444.8 446.0 364.7 353.6 229.8

383.9 540.0 540.0 444.8 446.0 295.8

Tables 6.6a and 6.6b give detailed performance data for the convective pass sections. By using the appropriate amount of attemperating spray, it was possible to obtain the desired Part 1

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main steam (high temperature finish) temperature. The reheat steam temperature was controlled by the burner tilt. It is also interesting to point out that the temperatures of the flue gas leaving the economizer in all four cases were similar. The economizer was equipped with a flue gas bypass for air heater temperature control. Tables 6.6a, 6.6b, 7, 8, 9, 10, and 11 give complete performance data of the steam/water cycle. It is no surprise that the largest heat duty occurs at the furnace water walls where the evaporation takes place. The next biggest heat duty exists in the FWH system. The fact that the low temperature superheater section and the high temperature finish section heat duties are similar implies that the convective pass is well designed and balanced. This point is again confirmed when the heat duties of the primary reheat section and the secondary reheat section are compared. The heat duty of the FWH was split amongst five heaters by using bleed steams with similar flow rate. The pressure drops across the convective sections were well controlled. The condensate pump and boiler feed pumps maintain the required cycle pressure. Table 6.7 – Steam/water pressure (bar) firing at ambient pressure. Wyoming PRB Economizer inlet Furnace wall inlet Superheater platen inlet Low temperature superheater inlet High temperature finish inlet Primary reheater inlet Reheater finish inlet LP steam out of turbine Main water out condense Main water out pump to FWH Main water out FWH Condensing water inlet Condensing water outlet

Illinois No. 6

Air-fired

Oxy-fuel

Air-fired

Oxy-fuel

112.5 112.0 105.1 104.1 103.6 26.72 25.82 0.04826 0.04826 9.894 112.5 2.401 1.611

112.5 112.0 105.1 104.1 103.6 26.72 25.82 0.04826 0.04826 9.894 112.5 2.401 1.611

115.7 114.0 107.1 106.2 104.6 26.72 26.09 0.04826 0.04826 9.894 115.7 2.401 1.611

115.7 114.0 107.1 106.2 104.6 26.72 26.09 0.04826 0.04826 9.894 115.7 2.401 1.611

One of the key functions of the recycled flue gas was to avoid radically altering the tube bank velocities of the oxy-fuel cases as compared with the air-fired cases for maintaining convective heat transfer rates and minimizing erosion. It is clear from Table 6.12 that in all oxy-fuel cases, the tube bank velocities were lower, but still within an acceptable range, than in the air-fired case.

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Table 6.8 – Main steam/water mass flow (kg/s) firing at ambient pressure. Wyoming PRB Economizer Furnace wall Superheater platen Desuperheater water Low temperature superheater High temperature finish Primary reheater Reheater finish LP steam out of turbine Main water out condense Main water out pump to FWH Main water out FWH Condensing water

Illinois No. 6

Air-fired

Oxy-fuel

Air-fired

Oxy-fuel

118.36 118.36 118.36 3.66 122.02 122.02 112.95 112.95 87.33 87.33 87.33 122.02 4781.63

127.61 127.61 127.61 3.95 131.56 131.56 121.78 121.78 94.16 94.16 94.16 131.56 5155.37

114.27 114.27 114.27 4.04 118.30 118.30 109.46 109.46 84.21 84.21 84.21 118.30 4541.51

123.20 123.20 123.20 4.35 127.55 127.55 118.01 118.01 90.80 90.80 90.80 127.55 4896.48

Table 6.9 – FWH bleed steam inlet conditions firing at ambient pressure. Wyoming PRB Bleed steam to heater (kg/s) - heater No. 1 - heater No. 2 - heater No. 3 - heater No. 4 - heater No. 5 Temperature of bleed steam to heater (°C) - heater No. 1 - heater No. 2 - heater No. 3 - heater No. 4 - heater No. 5 Pressure of bleed steam to heater (bar) - heater No. 1 - heater No. 2 - heater No. 3 - heater No. 4 - heater No. 5

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Illinois No. 6

Air-fired

Oxy-fuel

Air-fired

Oxy-fuel

6.6239 5.8670 7.3566 5.7789 9.0662

7.1416 6.3256 7.9316 6.2306 9.7749

5.8171 6.7141 7.1347 5.5788 8.8401

6.2717 7.2389 7.6923 6.0148 9.5311

108.8 246.9 373.4 457.4 359.7

108.8 246.9 373.4 457.4 359.7

87.97 231.4 373.4 457.4 353.6

87.97 231.4 373.4 457.4 353.6

0.449 2.135 6.895 13.67 26.72

0.449 2.135 6.895 13.67 26.72

0.449 2.135 6.895 13.67 26.72

0.449 2.135 6.895 13.67 26.72

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Tables 6.13a and 6.13b present the primary and secondary air heater performance data. Pulverizer performance is one of the key factors for the smooth operation of the boiler. The amount of the moisture to be driven off in a pulverizer is a stringent performance requirement for proper ignition in the furnace. The final raw flue gases were sent to the amine scrubbing unit and the PRT for CO2 recovery processing. The detailed performance of these CO2 recovery technologies were not studied here since extensive data are available in the literature [2], [3], [5]. Infiltration air contributed to the high nitrogen and oxygen contents in the flue gas of the oxy-fuel cases. The two oxy-fuel gases have very similar compositions with respect to the major species (carbon dioxide, nitrogen, oxygen, and water). However, the sulfur dioxide fractions were very different because of the different fuel sulphur contents. For the air case, the high water vapor present in the PRB flue gas is attributed to the water content of the fuel.

Table 6.10 – FWH main water outlet conditions firing at ambient pressure. Wyoming PRB Air-fired Main water from heater (kg/s) - heater No. 1 87.329 - heater No. 2 99.820 - heater No. 3 122.02 122.02 - heater No. 4 122.02 - heater No. 5 Temperature of main water from heater (°C) - heater No. 1 76.27 - heater No. 2 112.9 - heater No. 3 163.7 - heater No. 4 192.0 - heater No. 5 229.8 Pressure of main water from heater (bar) - heater No. 1 9.344 - heater No. 2 6.895 - heater No. 3 6.895 - heater No. 4 113.1 - heater No. 5 112.5

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Illinois No. 6

Oxy-fuel

Air-fired

Oxy-fuel

94.155 107.62 131.56 131.56 131.56

84.219 96.750 118.30 118.30 118.30

90.801 104.31 127.55 127.55 127.55

76.27 112.9 163.7 192.0 229.8

78.18 112.9 163.7 192.0 229.8

78.18 112.9 163.7 192.0 229.8

9.344 6.895 6.895 113.1 112.5

9.351 6.895 6.895 116.3 115.6

9.351 6.895 6.895 116.3 115.6

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Table 6.11 – Section heat duties firing at ambient pressure (kJ/h). Wyoming PRB Air-fired Economizer Furnace wall Superheater platen Low temperature superheater High temperature finish Primary reheater Reheater finish FWH (total) - heater No. 1 - heater No. 2 - heater No. 3 - heater No. 4 - heater No. 5 Total Duty (including FWH) Total Duty (without FWH)

Illinois No. 6

Oxy-fuel

1.360 × 10 6.432 × 108 9.240 × 107 1.087 × 108 1.098 × 108 7.971 × 107 9.240 × 107 3.170 × 108 5.690 × 107 5.527 × 107 8.044 × 107 4.986 × 107 7.454 × 107 1.579 × 109 1.262 × 109 8

Air-fired

1.466 × 10 6.935 × 108 9.962 × 107 1.172 × 108 1.184 × 108 8.594 × 107 9.235 × 107 3.418 × 108 6.135 × 107 5.959 × 107 8.672 × 107 5.375 × 107 8.036 × 107 1.695 × 109 1.354 × 109 8

Oxy-fuel

1.343 × 10 6.139 × 108 9.037 × 107 1.105 × 108 1.080 × 108 8.278 × 107 8.306 × 107 3.103 × 108 5.812 × 107 5.360 × 107 7.796 × 107 4.833 × 107 7.224 × 107 1.533 × 109 1.223 × 109 8

1.448 × 108 6.618 × 108 9.744 × 107 1.191 × 108 1.164 × 108 8.925 × 107 8.955 × 107 3.334 × 108 6.267 × 107 5.779 × 107 8.405 × 107 5.210 × 107 7.788 × 107 1.653 × 109 1.318 × 109

Table 6.12 – Flue gas velocities (m/s) firing at ambient pressure. Wyoming PRB Economizer Furnace wall Superheater platen Low temperature superheater High temperature finish Primary reheater Reheater finish

Part 1

Illinois No. 6

Air-fired

Oxy-fuel

Air-fired

Oxy-fuel

7.79 13.41 8.52 10.44 10.24 10.99 9.81

5.94 10.35 6.69 8.11 8.03 8.47 7.65

7.35 14.30 9.05 9.70 10.17 9.72 9.83

5.50 10.79 6.99 7.41 7.84 7.35 7.54

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Table 6.13a – Wyoming PRB air heaters performance firing at ambient pressure. Wyoming PRB Air-fired

Temperature of primary air heater (°C) Temperature of secondary air heater (°C) Mass flow of primary air heater (kg/s) Mass flow of secondary air heater (kg/s)

Oxy-fuel

Flue Gas

Air

Flue Gas

Recycle Gas

In

Out

In

Out

In

Out

In

Out

341.7

160.8

25

300.0

318.5

230.7

37.78

300.0

341.7

162.9

65.56

273.9

318.5

149.0

37.78

273.9

43.901 47.945 35.471 31.427 59.426 62.814 25.865 22.477 131.70 144.34 35.89

123.25 110.36 119.22 97.303 88.448

Table 6.13b – Illinois No. 6 air heaters performance firing at ambient pressure. Illinois No. 6 Air-fired

Temperature of primary air heater (°C) Temperature of secondary air heater (°C) Mass flow of primary air heater (kg/s) Mass flow of secondary air heater (kg/s)

Part 1

Oxy-fuel

Flue Gas

Air

Flue Gas

Recycle Gas

In

Out

In

Out

In

Out

In

Out

353.1

164.7

25

330.0

287.7

220.7

37.8

250.0

353.1

159.7

65.6

273.9

287.7

90.34

37.8

250.0

35.067 37.815 25.681 22.933 73.363 77.217 28.341 25.497 131.92 140.97 139.17 130.11 101.31 111.35 110.37 100.33

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Table 6.14 – Final flue gas (entering the PRT) properties firing at ambient pressure. Wyoming PRB

Parameter

Illinois No. 6

Air-fired

Oxy-fuel

Air-fired

Oxy-fuel

Temperature (°C) Mass flow rate (kg/s)

153.7

37.78

154.1

37.78

192.28

47.903

178.78

44.026

Specific heat (kJ/kg-°C) Actual volumetric gas flow (m3/h) Density (kg/m3)

1.087

0.9234

1.062

0.9160

8.317 × 105

1.097 × 105

7.612 × 105

9.971 × 104

0.8323

1.571

0.8455

1.589

12.9141 12.3467 4.2740 69.5952 0.0383 0.8315

76.1095 6.6660 6.0623 10.3758 0.2235 0.5630

12.7272 8.2964 4.4942 73.2634 0.3437 0.8750

75.2368 6.6718 4.5711 10.9164 2.0209 0.5831

Composition (% by volume) CO2 H 2O O2 N2 SO2 Ar

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7. TIPS Case Study I – Existing Turbine 7.1. Design Considerations and Fuel Delivery System As in any other current conceptual and pilot scale oxy-fuel combustion system, TIPS recycles part of the flue gas back to the furnace to moderate the combustion temperature. As discussed previously, the amount of flue gas to be recycled was determined by the coal ash softening temperature. In this study, TIPS is particularly advantageous in that the process is also an integrated emissions control system. While ambient oxy-fuel systems require particulate control systems (ESP and/or baghouse), TIPS can scrub out the particulate matter without such technologies. Compared with the air case, this leads to significant capital and operating and maintenance cost savings. The energy savings attributed to the air case ESP and FGD are about 1.2 MWe when a similar amount of coal is fired. Since the TIPS process operates at elevated pressure, a slurry coal-water mixing and pumping system are required to transfer the fuel to the burners. The slurry solid concentration was set at 55% by mass. 7.2. Condensing Heat and Boiler FWH System As noted above, TIPS high pressure operation allows for flue gas water vapor condensation at higher temperatures. As a consequence, it may be possible to make good use of the heat of condensation and, thus, to increase the boiler efficiency. For example, for the PRB coal, the water vapor content in the flue gas exiting the furnace is at about 30% by volume. This flue gas will begin to condense at about 69°C at ambient pressure. As a result, it is difficult to effectively use this heat in the boiler/steam/water system. However, at 80 bar, the condensation point is raised to 208°C. At such a high condensing temperature, the heat available from the condensate can be more readily used within the power cycle resulting in a subsequent increase in the plant efficiency. Indeed, the use of the flue gas condensing heat is a main advantage of TIPS. A major thrust of this work is to quantify the amount and the temperature of the heat and develop strategies to use it effectively within the power cycle. Since the water vapor only begins to condense at about 208°C at 80 bar, it was decided that instead of using the gas exiting the economizer to heat the air/recycle gas in an AH it would be better to use it to heat water as part of FWH system. The challenge is to adjust the bleed steams in the FWH system and replace part of the steam’s heat duty with the flue gas condensing heat. It turns out that for both PRB and Illinois No. 6 coals there is enough condensing heat for use in the FWH system.

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Two designs were carried out to investigate the potential use of the condensing heat in the FWH system. The designs were based on turbine mass flow specifications. The first design consisted of maintaining the steam mass flow through HP, IP, and LP sections as close as possible to original values in order to use the same turbine. This approach also ensures that the turbine load and output of each of the sections is similar. The second design was based on a new turbine with no restrictions on mass flow and load. The first design as discussed in this section while the second design is presented in the subsequent section. 7.3. Boiler Performance Results Table 7.1 lists the key plant performance data using the TIPS configuration. As shown, the plant thermal efficiency increased for both coals when compared to the air and ambient oxy-fuel cases. This result is mainly due to the use of condensing heat in the FWH, resulting in steam savings for turbine output.

Table 7.1 – Key plant performance data for TIPS configuration No. 1.

Parameter Plant net efficiency (%, HHV), with capture Plant net efficiency (%, HHV)

Wyoming PRB

Illinois No. 6

80 bar, 99.5% O2

80 bar, 99.5% O2

30.37

29.96

37.07

37.14

Plant gross efficiency (%, HHV)

39.17

39.37

Plant net power output (kW)

100000

100000

Plant gross power output (kW)

128982

131441

HP turbine power output (kW)

32320

33920

IP turbine power output (kW)

30032

30740

LP turbine power output (kW)

66630

66781

Fuel heat input (kJ/hr, LHV)

1.091 × 10

9

1.142 × 109

Fuel heat input (kJ/hr, HHV)

1.186 × 109

1.202 × 109

Net plant heat rate (kJ/kWh, LHV) 10909

11422

Net plant heat rate (kJ/kWh, HHV) 11855

12018

Coal mass flow (kg/s)

17.374

14.210

Oxygen mass flow (kg/s)

24.934

25.341

Slurry water mass flow (kg/s)

4.2244

8.504

Slurry mass flow (kg/s)

21.598

22.714

Slurry concentration (%)

55

55

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The energy cost for ASU is not included when plant gross efficiencies and net efficiencies without capture were calculated. However, it is included in the net efficiencies calculation in the captured cases. It is interesting to notice that the net efficiencies without capture of the TIPS cases are significantly higher than those of air and oxy-fuel cases (Table 6.2). Due to the facts that the TIPS process can utilize almost all latent heat of fuel and CO2 can be condensed at ambient temperature (Tables 7.13 and 7.14), the TIPS process has very high net efficiency with CO2 capture. Most of the increase in efficiency for the TIPS case results from the elimination of PRT processes required by the ambient oxyfuel case.

Table 7.2 – Plant auxiliaries power consumption for TIPS configuration No. 1(kW). Parameter

Wyoming PRB

Illinois No. 6

80 bar, 99.5% O2

80 bar, 99.5% O2

ASU

20830.72

22712.53

FGR-fan

120.23

131.09

Oxygen & FWH pumps

945.39

950.11

Slurry pump

177.80

186.97

Total CO2 Capture Use Total CO2 Capture Use, (% of plant gross output)

22074.14

23980.69

17.11

18.24

Boiler primary air fan

242.39

261.78

Boiler secondary air fan

254.57

274.93

Boiler induced draft fan

1037.99

1121.00

Boiler fuel delivery

1107.35

1195.91

Electrostatic precipitator

502.23

542.40

Flue gas desulphurization

511.30

552.20

Ash handling

101.16

109.25

Condenser cold water pump

510.79

551.64

Condensate pump

71.26

76.96

Boiler feed pump

1184.32

1279.04

Boiler feed booster pump

9.42

10.17

FW heater drain pump

10.80

11.66

Miscellaneous plant auxiliaries

1364.00

1473.08

Total Boiler Use Total Boiler Use, (% of plant gross output)

6907.84

7460.30

5.36

5.68

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Plant auxiliary power consumptions are presented in Table 7.2. CO2 capture, mainly on ASU, takes about 18% of the plant gross output. For the boiler part, it is very similar to the ambient oxy-fuel case.

Table 7.3 – Key boiler performance data for TIPS configuration No. 1. Parameter

Wyoming PRB

Illinois No. 6

80 bar, 99.5% O2

80 bar, 99.5% O2

Boiler efficiency (%, HHV) 98.70 Adiabatic flame temperature 1974 (°C) Furnace outlet temperature (°C) 1138

98.74 1942

Recycle rate (%)

69.00

1131

67.00

Recycle flue gas mass flow (kg/s) 63.868

69.520

The boiler efficiency is very high as result of the utilization of a condensing FWH heater. The flue gas recycle rate for TIPS is lower than the ambient oxy-fuel cases because the water added in the pressurized slurry fuel feeding system.

Table 7.4 – Furnace outlet flue gas properties for TIPS configuration No. 1. Parameter

Wyoming PRB

Illinois No. 6

80 bar, 99.5% O2

80 bar, 99.5% O2

Temperature (°C)

1138

1131

Mass flow rate (kg/s)

109.61

115.15

1.514

Specific heat (kJ/kg-°C)

Actual volumetric gas flow (m /h) 1.641 × 10 3

Density (kg/m3)

1.482 1.674 × 104

4

24.05

24.76

CO2

66.2254

67.0233

H 2O

30.6119

28.1394

O2

2.2239

2.3405

N2

0.3855

0.5637

SO2

0.1690

1.5289

Ar

0.3842

0.4042

Composition (% by volume)

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Table 7.5 – Temperatures (°C) for TIPS configuration No. 1. Illinois No. 6

Wyoming PRB Section Superheater platen High temperature finish Reheater finish Low temperature superheater Primary reheater Economizer

80 bar, 99.5% O2 Flue Gas Steam

80 bar, 99.5% O2 Flue Gas Steam

In

Out

In

Out

In

Out

In

Out

1138 1012 859.0 736.3 576.9 456.4

1012 859.0 736.3 576.9 456.4 248.3

331.9 445.4 445.9 367.1 359.7 229.8

384.5 540.2 540.0 445.4 445.9 294.4

1131 1012 854.8 735.9 572.8 447.6

1006 854.8 735.9 572.8 447.6 240.4

331.9 444.8 446.0 364.7 353.6 229.8

383.9 540.2 540.0 444.8 446.0 295.8

Table 7.6 – Steam/water pressures (bar) for TIPS configuration No. 1. Parameter Economizer inlet Furnace wall inlet Superheater platen inlet Low temperature superheater inlet High temperature finish inlet High temperature finish outlet Primary reheater inlet Reheater finish inlet Reheater finish outlet LP inlet LP steam out of turbine Main water out condense Main water out pump to FWH Main water out FWH Condensing water inlet Condensing water outlet

Part 1

Wyoming PRB

Illinois No. 6

80 bar, 99.5% O2

80 bar, 99.5% O2

112.5 112.0 105.1 104.1 103.6 103.5 26.72 25.82 25.21 6.895 0.04826 0.04826 6.895 112.5 2.401 1.611

115.7 114.0 107.1 106.2 104.6 103.5 26.72 26.09 25.21 6.694 0.04826 0.04826 6.694 115.7 2.401 1.611

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Table 7.7 – Steam/water mass flow (kg/s) for TIPS configuration No.1. Parameter Economizer inlet Furnace wall inlet Superheater platen inlet Superheater platen inlet Desuperheating water Low temperature superheater inlet High temperature finish inlet High temperature finish outlet Primary reheater inlet Reheater finish inlet Reheater finish outlet LP inlet LP steam out of turbine Main water out condense Main water out pump to FWH Main water out FWH Condensing water inlet Condensing water outlet

Wyoming PRB

Illinois No. 6

80 bar, 99.5% O2

80 bar, 99.5% O2

95.59 95.59 95.59 95.59 2.96 98.54 98.54 98.54 91.55 91.55 91.55 85.91 85.91 85.91 85.91 98.54 4737.12 4737.12

95.74 95.74 95.74 95.74 3.38 99.12 99.12 99.12 91.33 91.33 91.33 86.83 86.83 86.83 86.83 99.12 4786.93 4786.93

Table 7.8 – FWH bleed steam inlet conditions for TIPS configuration No. 1. Parameter

Wyoming PRB

Illinois No. 6

80 bar, 99.5% O2

80 bar, 99.5% O2

Bleed steam to heater (kg/s) - heater No. 1 - heater No. 2 - heater No. 3 - heater No. 4 - heater No. 5

N/A N/A 0.0000

N/A N/A 0.0000

5.6408 6.9946

4.4980 7.7909

Temperature of bleed steam to heater (°C) - heater No. 1 - heater No. 2 - heater No. 3 - heater No. 4 - heater No. 5

373.4 457.4 359.7

370.1 457.4 353.6

Pressure of bleed steam to heater (bar) - heater No. 1 - heater No. 2 - heater No. 3 - heater No. 4 - heater No. 5

N/A N/A 6.895 13.67 26.72

N/A N/A 6.694 13.67 26.72

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Table 7.9 – FWH main water outlet inlet conditions for TIPS configuration No. 1. Wyoming PRB

Illinois No. 6

80 bar, 99.5% O2

80 bar, 99.5% O2

N/A N/A 98.54 98.54 98.54

N/A N/A 99.12 99.12 99.12

Temperature of main water from heater (°C) - heater No. 1 - heater No. 2 - heater No. 3 162.8 - heater No. 4 193.5 - heater No. 5 229.6

162.8 190.0 229.8

Pressure of main water from heater (bar) - heater No. 1 - heater No. 2 - heater No. 3 - heater No. 4 - heater No. 5

N/A N/A 6.694 116.3 115.7

Parameter Main water from heater (kg/s) - heater No. 1 - heater No. 2 - heater No. 3 - heater No. 4 - heater No. 5

Part 1

N/A N/A 6.895 113.1 112.5

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Table 7.10 – Section heat duties (kJ/h) for TIPS configuration No. 1. Wyoming PRB

Illinois No. 6

80 bar, 99.5% O2

80 bar, 99.5% O2

Economizer

1.098 × 108

1.125 × 108

Furnace wall

5.195 × 108

5.143 × 108

Superheater platen

7.462 × 107

7.571 × 107

Low temperature superheater

8.782 × 107

9.254 × 107

High temperature finish

8.869 × 107

9.046 × 107

Primary reheater

6.460 × 107

6.907 × 107

Reheater finish

6.942 × 107

6.930 × 107

Flue gas FWH

1.557 × 108

1.628 × 108

FWH (total, steam side)

1.016 × 108

1.023 × 108

- heater No. 4

4.404 × 107

3.868 × 107

- heater No. 5 Total Duty (including Flue gas FWH)

5.751 × 107

6.366 × 107

1.170 × 109

1.187 × 109

Parameter

- heater No. 1 - heater No. 2 - heater No. 3

Table 7.11 – Flue gas FWH performance for TIPS configuration No. 1. Wyoming PRB 80 bar, 99.5% O2 Flue Gas Main Water

Illinois No. 6 80 bar, 99.5% O2 Flue Gas Steam

In

Out

In

Out

In

Out

In

Out

Temperature (°C) Pressure (bar) Vapor fraction Mass flow (kg/s) Compositions (mole %) CO2 H 2O O2 N2 SO2 Ar

248.3 80 1.0000 109.61

139.0 80 0.7445 95.325

32.29 6.895 0.0000 85.909

151.6 6.895 0.0000 85.909

240.4 80 1.0000 115.15

123.4 80 0.7516 100.75

32.29 6.694 0.0000 86.832

155.6 6.694 0.0000 86.832

66.2254 30.6119 2.2239 0.3855 0.1690 0.3842

88.7122 7.0612 100.0 2.9851 0.5177 0.2077 0.5161

67.0233 28.1394 2.3405 0.5637 1.5289 0.4042

88.9643 4.7784 100.0 3.1123 0.7498 1.8574 0.5377

Heat duty (kJ/h) Condensing water flow (kg/s)

1.557 × 108 14.284

Parameter

Part 1

100.0

1.628 × 108 14.397

37

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Technical and Economic Feasibility Study of a Pressurized Oxy-fuel Approach to Carbon Capture – Part 2

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Table 7.12 – Final flue gas (entering the PRT) properties for TIPS configuration No. 1. Wyoming PRB

Illinois No. 6

80 bar, 99.5% O2

80 bar, 99.5% O2

Temperature (°C)

139.0

123.4

Mass flow rate (kg/s)

31.457

31.233

1.254

1.266

Actual volumetric gas flow (m /h) 979.5

893.4

Parameter

Specific heat (kJ/kg-°C) 3

3

Density (kg/m )

115.6

125.9

CO2

88.7122

88.9643

H 2O

7.0612

4.7784

O2

2.9851

3.1123

N2

0.5177

0.7498

SO2

0.2077

1.8574

Ar

0.5161

0.5377

Composition (% by mole)

7.4. PRT Performance Results Flue gas water vapor is condensed in the FWH resulting in an almost dry gas stream exiting the boiler island. This gas stream is further cooled in the PRT. The amount of water condensed in the PRT is very small compared to that condensing in the FWH. For the two cases considered here, about 4 to 6% of the total condensed water comes from the PRT. This condensation process is necessary for the purpose of CO2 recovery and transportation: first, it leads to a significant increase of CO2 purity; second, it eliminates any concerns of ice formation in the downstream process in the event that a refrigeration system is required; and third, the presence of water vapor is a serious corrosion concern in a gas containing sulfur oxides. As indicated in Table 7.13, a small condensing heater exchange utilizing cold water substantially alters the flue gas composition. With the Wyoming PRB flue gas, the CO2 concentration becomes more than 95%, already meeting the highest CO2 purity standard for EOR applications. Thus, all that is required for recovery in this case is to condense the resulting gas with no additional change in composition.

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Table 7.13 – PRT condensing heater No. 1 performance for TIPS configuration No. 1. 80 bar, 99.5% O2

Parameter

Wyoming PRB

Illinois No. 6

Inlet flue gas

Outlet flue gas Inlet flue gas

Outlet flue gas

Temperature (°C) Vapor fraction Mass flow (kg/s)

139.0 1.0000 31.457

50.0 0.9335 30.549

123.4 1.0000 31.233

50.0 0.9564 30.643

Compositions (mole %) CO2 H2O O2 N2 SO2 Ar

88.7122 7.0612 2.9851 0.5177 0.2077 0.5161

95.0085 0.4711 3.1975 0.5545 0.2155 0.5528

88.9643 4.7784 3.1123 0.7498 1.8574 0.5377

93.0086 0.4866 3.2542 0.7840 1.9043 0.5623

Condensing water flow (kg/s)

2.094 × 107 0.9083

Cooling water

Inlet

Outlet

Inlet

Outlet

Temperature (°C) Pressure (bar) Mass flow (kg/s)

15.00 2.401 279.16

20.00 1.611 279.16

15.00 2.401 216.85

20.00 1.611 216.85

Heat duty (kJ/h)

1.627 × 107 0.5907

One of the main motivations of operating at high pressure is to enable the CO2-enriched flue gas to condense at ambient heat sink temperatures. This eliminates the need for an energy intensive refrigeration system that is required for CO2 recovery in ambient pressure oxy-fuel operations. Table 7.14 demonstrates that this is indeed practical as the flue gas for both fuels completely condense resulting in 100% CO2 recovery rates. It is interesting to note that, if required, there is a relatively easy way to increase the CO2 purity in the Illinois No. 6 case. Examination of the compositions of the two product streams in Table 7.14 shows that the major species difference is the SO2 concentration. This is not surprising since Illinois No. 6 coal has almost ten times the sulphur content of Wyoming PRB coal (Table 5.2), and this same ratio was reflected in the product compositions (Table 7.14). However, with an FGD unit the SO2 in the final product stream could easily be lowered to improve the CO2 purity to more than 95%. Using an FGD unit would be far more economical than employing a costly and energy intensive refrigeration system. The energy consumption of an FGD is several orders of magnitude lower than a PRT refrigeration system [13], [4].

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Table 7.14 – PRT condensing heater No. 2 performance for TIPS configuration No. 1. 80 bar, 99.5% O2

Parameter

Wyoming PRB

Illinois No. 6

Flue gas

CO2 Product

Flue gas

CO2 Product

Temperature (°C) Vapor fraction Mass flow (kg/s)

50.00 1.0000 30.549

-5.292 0.0000 30.549

50.00 1.0000 30.643

-6.609 0.0000 30.643

Compositions (mole %) CO2 H2O O2 N2 SO2 Ar

95.0085 0.4711 3.1975 0.5545 0.2155 0.5528

95.0085 0.4711 3.1975 0.5545 0.2155 0.5528

93.0086 0.4866 3.2542 0.7840 1.9043 0.5623

93.0086 0.4866 3.2542 0.7840 1.9043 0.5623

Cooling Oxygen

2.727 × 107 Inlet

Outlet

2.771 × 107 Inlet

Outlet

Temperature (°C) Pressure (bar) Mass flow (kg/s)

-141.5 80 24.934

25.00 80 24.934

-141.5 80 25.341

25.00 80 25.341

Heat duty (kJ/h)

Table 7.15 – Final flue gas (after PRT condensing heater No. 1) properties for TIPS configuration No.1 with oxygen purity at 95%. Wyoming PRB

Illinois No. 6

TIPS at 80 bar using 95% O2

TIPS at 80 bar using 95% O2

Temperature (°C)

50

50

Mass flow rate (kg/s)

31.792

32.048

1.769

1.816

Actual volumetric gas flow (m /h) 583.7

575.7

Parameter

Specific heat (kJ/kg-°C) 3

3

Density (kg/m )

196.1

200.4

CO2

90.2805

88.3451

H 2O

0.4450

0.4576

O2

3.0406

3.0877

N2

3.2765

3.5121

SO2

0.2062

1.8230

Ar

2.7531

2.7746

Composition (% by mole)

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Boiler performance does not vary much when 95.0% oxygen is used instead of 99.5% oxygen. However, oxygen purity has a great impact on flue gas composition and, hence, on the performance of the PRT. Table 7.15 gives the properties of the final flue gas using 95.0% oxygen after the water vapor is almost completely condensed out. It is clear that these flue gases must be further treated in order to obtain a higher purity CO2 product stream. The options to do this are rather limited, with refrigeration being the only solution. The resultant energy penalty would be very high to make sense for TIPS. Therefore, the use of higher purity oxygen in the TIPS process is preferred if high purity product is required.

8. TIPS Case Study II – New Turbine 8.1. Design Considerations for FWH System In this section the design aspects and detailed performance of the TIPS process are investigated when a new turbine is used. The goal here is to eliminate all bleed steams and use the flue gas latent heat of condensation exclusively to heat the main water out of the steam/water condenser to the required economizer inlet conditions. A newly designed (or retrofitted) turbine is necessary for this purpose. This is because the steam mass flows crossing all HP, IP, and LP sections must be the same when there is no bleed steam is used for FWH. Elimination of the steam FWH system and replacement with a flue gas condensing FWH system could afford considerable capital and operating and maintenance savings while simplifying the plant layout. Details of these benefits must be further identified and investigated. The objective of this section is to investigate the technical feasibility of this option. The design principals and philosophy of this case is almost identical to those of the previous section. 8.2. Boiler Performance Results Table 8.1 presents plant performance data using the TIPS configuration. The data indicate that the plant thermal efficiencies are similar to the cases using the existing turbine as detailed in the previous section. The fuel flow rates were slightly different, due to different recovery rates of the condensing heat in the FWH. Since almost all of the water vapor condenses out in the FWH (Table 8.10) and the temperature of flue gas exiting the FWH is approximately 50°C, it is expected that the boiler efficiencies for fuel cases are close to 100% (Table 8.4). The recycle rates are either the same or slightly higher than those given in Table 7.4 (existing turbine case) because with a new turbine design, the flue gas water content was drier. Thus, in this case, greater flue gas recycle mass flows are needed to cool the flame.

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Table 8.1 – Key plant performance data for TIPS configuration No. 2. Wyoming PRB

Illinois No. 6

80 bar, 99.5% O2, no bleed steam

80 bar, 99.5% O2, no bleed steam

30.54

29.93

37.25

37.12

39.36

39.36

Plant net power output (kW)

100000

100000

Plant gross power output (kW)

128852

131509

HP turbine power output (kW)

29370

30960

IP turbine power output (kW)

29860

30770

LP turbine power output (kW)

69622

Parameter Plant net efficiency (%, HHV), with capture Plant net efficiency (%, HHV) Plant gross efficiency (%, HHV)

69780

Fuel heat input (kJ/hr, LHV)

1.085 × 10

9

1.143 × 109

Fuel heat input (kJ/hr, HHV)

1.179 × 109

1.203 × 109

Net plant heat rate (kJ/kWh, LHV)

10847

11432

Net plant heat rate (kJ/kWh, HHV)

11787

12029

Coal mass flow (kg/s)

17.273

14.223

Oxygen mass flow (kg/s)

24.790

25.364

Slurry water mass flow (kg/s)

4.200

8.512

Slurry mass flow (kg/s)

21.473

22.735

Slurry concentration (%)

55

55

Table 8.2 – Plant auxiliaries power consumption for TIPS configuration No. 2 (kW). Wyoming PRB

Illinois No. 6

80 bar, 99.5% O2

80 bar, 99.5% O2

20710.00

22733.05

FGR-fan

119.53

131.21

Oxygen & FWH pumps

978.20

990.82

Slurry pump

176.77

187.21

21984.50

24042.29

17.06

18.28

Boiler primary air fan

180.41

196.15

Boiler secondary air fan

290.34

315.67

Boiler induced draft fan

963.19

1047.23

Boiler fuel delivery

849.85

924.00

Electrostatic precipitator

190.29

206.90

Parameter ASU

Total CO2 Capture Use Total CO2 Capture Use, (% of plant gross output)

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Technical and Economic Feasibility Study of a Pressurized Oxy-fuel Approach to Carbon Capture – Part 2

n Flue gas desulphurization

883.61

960.70

Ash handling

271.97

295.70

Condenser cold water pump

503.46

547.38

Condensate pump

72.32

78.63

Boiler feed pump

1244.43

1353.01

Boiler feed booster pump

9.94

10.81

FW heater drain pump

10.76

11.70

Miscellaneous plant auxiliaries

1397.47

1519.40

Total Boiler Use Total Boiler Use, (% of plant gross output)

6867.81

7467.04

5.33

5.68

Table 8.3 – Key boiler performance data for TIPS configuration No. 2. Wyoming PRB

Illinois No. 6

80 bar, 99.5% O2

80 bar, 99.5% O2

99.850

99.760

Adiabatic flame temperature (°C)

1886

1913

Furnace outlet temperature (°C)

1136

1166

Recycle rate (%)

69.50

69.00

Recycle flue gas mass flow (kg/s)

69.511

69.664

Parameter Boiler efficiency (%, HHV)

Table 8.4 – Furnace outlet flue gas properties for TIPS configuration No. 2.

Parameter Temperature (°C) Mass flow rate (kg/s)

Illinois No. 6

80 bar, 99.5% O2

80 bar, 99.5% O2

1136

1166

114.98

115.95

1.484

Specific heat (kJ/kg-°C) 3

Actual volumetric gas flow (m /h) Density (kg/m3)

Wyoming PRB

1.672 × 10

1.476 4

1.706 × 104

24.76

24.47

CO2

70.0235

69.0409

H2O

26.6562

26.1210

O2

2.3494

2.4073

N2

0.4069

0.5797

SO2

0.1587

1.4356

Ar

0.4054

0.4156

Composition (% by volume)

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Technical and Economic Feasibility Study of a Pressurized Oxy-fuel Approach to Carbon Capture – Part 2

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With the correct amount of recycle mass flow, the flue gas mass flows (Table 8.4) were very close to those in the previous section (Table 7.4). However, the gas compositions were somewhat different due to the fact that the recycle gas is much drier, increasing the CO2 concentration. Table 8.5 – Temperatures (°C) for TIPS configuration No. 2.

Section Superheater platen High temperature finish Reheater finish Low temperature superheater Primary reheater Economizer

Wyoming PRB 80 bar, 99.5% O2 Flue Gas Steam

Illinois No. 6 80 bar, 99.5% O2 Flue Gas Steam

In

Out

In

Out

In

Out

In

Out

1136 1025 890.2 774.4 630.4 516.9

1025 890.2 774.4 630.4 516.9 333.9

331.9 445.4 445.9 367.1 359.7 229.8

384.5 540.2 540.0 445.4 445.9 294.4

1166 1053 915.6 798.8 651.7 529.2

1053 915.6 798.8 651.7 529.2 340.2

331.9 444.8 446.0 364.7 353.6 229.8

383.9 540.2 540.0 444.8 446.0 295.8

Table 8.6 – Steam/water pressure (bar) firing at TIPS configuration No. 2. Parameter Economizer inlet Furnace wall inlet Superheater platen inlet Low temperature superheater inlet High temperature finish inlet High temperature finish outlet Primary reheater inlet Reheater finish inlet Reheater finish outlet LP inlet LP steam out of turbine Main water out condense Main water out pump to FWH Main water out FWH Condensing water inlet Condensing water outlet

Part 1

Wyoming PRB

Illinois No. 6

TIPS at 80 bar using 99.5% O2 112.5 112.0 105.1 104.1 103.6 103.5 26.72 25.82 25.21 6.895 0.04826 0.04826 6.895 112.5 2.401 1.611

TIPS at 80 bar using 99.5% O2 115.7 114.0 107.1 106.2 104.6 103.5 26.72 26.09 25.21 6.694 0.04826 0.04826 6.694 115.7 2.401 1.611

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Table 8.7 – Steam/water mass flow (kg/s) for TIPS configuration No. 2. Parameter Economizer inlet Furnace wall inlet Superheater platen inlet Superheater platen outlet Desup water Low temperature superheater inlet High temperature finish inlet High temperature finish outlet Primary reheater inlet Reheater finish inlet Reheater finish outlet LP inlet LP steam out of turbine Main water out condense Main water out pump to FWH Main water out FWH Condensing water inlet Condensing water outlet

Wyoming PRB

Illinois No. 6

80 bar, 99.5% O2 86.48 86.48 86.48 86.48 3.03 89.51 89.51 89.51 89.51 89.51 89.51 89.51 89.51 89.51 89.51 89.51 4940.88 4940.88

80 bar, 99.5% O2 87.38 87.38 87.38 87.38 3.08 90.46 90.46 90.46 90.46 90.46 90.46 90.46 90.46 90.46 90.46 90.46 4993.07 4993.07

Table 8.8 – Section heat duty (kJ/h) for TIPS configuration No. 2. Wyoming PRB

Illinois No. 6

80 bar, 99.5% O2

80 bar, 99.5% O2

Economizer

9.937 × 107

1.027 × 108

Furnace wall

4.700 × 108

4.694 × 108

Superheater platen

6.751 × 107

6.910 × 107

Low temperature superheater

8.229 × 107

8.440 × 107

High temperature finish

8.056 × 107

8.256 × 107

Primary reheater

6.320 × 107

6.842 × 107

Reheater finish

6.788 × 107

6.864 × 107

Flue gas FWH

2.710 × 108

2.737 × 108

Total Duty (including Flue gas FWH)

1.202 × 109

1.219 × 109

Parameter

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Technical and Economic Feasibility Study of a Pressurized Oxy-fuel Approach to Carbon Capture – Part 2

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Table 8.9 – Flue gas FWH performance for TIPS configuration No. 2. Wyoming PRB TIPS at 80 bar using 99.5% O2 Flue Gas Main Water

Parameter

In Temperature (°C) Pressure (bar) Vapor fraction Mass flow (kg/s) Composition (% by mole) CO2 H2O O2 N2 SO2 Ar

Out

In

Out

Illinois No. 6 TIPS at 80 bar using 99.5% O2 Flue Gas Main Water In

Out

In

Out

333.9 52.20 33.41 229.8 340.2 51.18 33.44 229.8 80 80 112.5 112.5 80 80 115.7 115.7 1.0000 0.7362 0.0000 0.0000 1.0000 0.7398 0.0000 0.0000 114.98 100.02 89.510 89.510 115.95 100.96 90.464 90.464 70.0235 26.6562 2.3494 0.4069 0.1587 0.4054

Heat duty (kJ/h) Condensing water flow (kg/s)

95.0128 0.5074 100.0 3.1908 0.5527 0.1857 0.5506 2.710 × 108 14.968

69.0409 100.0 26.1210 2.4073 0.5797 1.4356 0.4156

93.2153 0.5036 100.0 3.2533 0.7835 1.6825 0.5618

100.0

2.737 × 108 14.987

Table 8.10 – Final flue gas (entering the PRT) properties for TIPS configuration No. 2. Wyoming PRB

Illinois No. 6

80 bar, 99.5% O2

80 bar, 99.5% O2

Temperature (°C)

52.20

51.18

Mass flow rate (kg/s)

30.505

31.298

1.934

2.044

535.0

529.6

205.3

212.8

CO2

95.0128

93.2153

H2O

0.5074

0.5036

O2

3.1908

3.2533

N2

0.5527

0.7835

SO2

0.1857

1.6825

Ar

0.5506

0.5618

Parameter

Specific heat (kJ/kg-°C) 3

Actual volumetric gas flow (m /h) 3

Density (kg/m ) Composition (% by mole)

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When bleed steam is eliminated certain restrictions on the corresponding gas side are removed allowing for additional water vapor condensation. Table 8.9 shows that the condensation temperature can be reduced to about 50°C compared with 120°C in those cases in which bleed steam was required (Table 7.11). It is clear that the FWH is a very efficient device in terms of driving water vapor from the flue gas as well as utilizing available latent heat. 8.3. PRT Performance Results Compared with the case in which bleed steam was needed (Table 7.12), it was easy to see that there was virtually no water vapor in the flue gases entering the PRT (Table 8.10). Actually, the gas is very similar in composition to that exiting PRT heater No. 1 of Table 7.13. Therefore, all that is required is to cool the flue gas to ambient temperature to obtain the final CO2 product. CO2 product flow rates are lower than those of Table 7.14 due to the lower fuel firing rates in this configuration (Table 8.1).

Table 8.11 – PRT condensing heater performance for TIPS configuration No. 2. 80 bar, 99.5% O2

Parameter

Wyoming PRB

Illinois No. 6

Flue gas

CO2 Product

Flue gas

CO2 Product

Temperature (°C) Pressure (bar) Vapor fraction Mass flow (kg/s)

52.20 80 1.0000 30.505

-3.187 80 0.0000 30.505

51.18 80 1.0000 31.298

-3.700 80 0.0000 31.298

Composition (% by mole) CO2 H2O O2 N2 SO2 Ar

95.0128 0.5074 3.1908 0.5527 0.1857 0.5506

95.0128 0.5074 3.1908 0.5527 0.1857 0.5506

93.2153 0.5036 3.2533 0.7835 1.6825 0.5618

93.2153 0.5036 3.2533 0.7835 1.6825 0.5618

Heat duty (kJ/h) Cooling water Temperature (°C) Pressure (bar) Mass flow (kg/s)

Part 1

2.711 × 107 Inlet Outlet -141.5 80 24.790

25.00 80 24.790

47

2.773 × 107 Inlet

Outlet

-141.5 80 25.364

25.00 80 25.364

Technical and Economic Feasibility Study of a Pressurized Oxy-fuel Approach to Carbon Capture – Part 2

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9. Key Findings and Analysis of Technical Aspects Based on the TIPS technical performance data and comparison with the air and ambient oxy-fuel cases, it can be seen that: • • • • • • • •

• • • •

Part 1

By operating at elevated pressure, the TIPS process is able to more fully utilize the latent heat of flue gas water vapor condensation heat in a FWH. The FWH system represents the most logical place to use the latent heat from the flue gas to be used within the power generation cycle. Due to the significant reduction of steam consumption for the FWH, more power can be generated from the steam turbine, resulting in higher gross and net power outputs when compared to the air and ambient oxy-fuel cases. With the ability to utilize most of the condensing heat of the flue gas, the TIPS process has higher boiler thermal efficiencies and higher overall plant efficiencies than those of the air and ambient oxy-fuel cases. The TIPS process can handle a very wide range of fuels. The advantages of the TIPS process over other conventional processes using low rank coals, such as PRB and lignite are particularly notable. Integrated emissions control together with particle scrubbing is feasible for the TIPS process. The final flue gas can be condensed at ambient heat sink temperatures resulting in complete CO2 recovery in a liquid stream. In addition, cases exist in which the purity of the CO2 in the recovered liquid stream is higher than 95%. There is a significant advantage operating the combustion system at pressure compared with ambient oxy-fired systems which release the ASU pressure for firing, requiring considerable power consumption for compression and refrigeration for CO2 recovery. Char combustion reactions in higher operating pressure environments proceed at higher rates increasing carbon burnout and allowing for simpler processing of difficult to burn fuels. Increased heat transfer rates can be achieved at these higher pressures allowing for decreased size of convective pass sections. The TIPS furnace can be much smaller due to the increased pressure. The furnace sizing strategy will be similar to that of gasifiers and can be either wet (slagging) or of a fluid bed style. The major factor limiting size reduction will be the ability of the system to manage ash removal, deposition and cleaning.

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10. Conclusions An extensive and detailed technical assessment of the TIPS process has been completed. The work includes analyses of 100 MWe (net) power plants firing with air and oxygen at ambient pressure for comparison with the TIPS process. For high pressure operation, a coal-water slurry system is used for fuel delivery. A thorough examination of the feed water heating system reveals that the flue gas condensing heat can be used effectively in the TIPS case. This leads to significant savings of steam for FWH usage and increases in plant thermal efficiency. Compared with processes operating at ambient pressure, the TIPS final product stream can be condensed at ambient heat sink temperatures eliminating multi-stage compression and refrigeration, necessary for ambient oxy-fuel case. At this level of study, there appear to be no major technical obstacles in the TIPS process. Depending on the fuel properties and purity of oxygen, the TIPS process can recover CO2 completely at high purity levels. For example, firing Wyoming PRB coal with 99.5% oxygen allows for 100% CO2 recovery with a purity of more than 95%. The optimal operating pressure for TIPS is dependent on the CO2 recovery rate and purity specifications, fuel properties, and the oxygen purity. It is interesting to compare the TIPS with IGCC with CO2 capture. IGCC is known to have high plant thermal efficiency and excellent emissions control, especially for SOx species. The CO2 emission rate for IGCC is about 0.75 kg/kWh [16]. IGCC utilizes the well-known water gas shift reaction for CO2 capture at maximum 85% recovery rate [17]. However, IGCC faces many operational challenges such as plant availability and fuel quality. And, IGCC technology can only handle high rank coals. On the other hand, TIPS does not appear to be limited in terms of the fuel type being fired. In fact, TIPS is particularly advantageous over other processes when high moisture fuels are fired because of the TIPS process capability to fully utilize the latent heat of the fuel.

11. Suggestion for Further Work a) Lower Furnace Arrangement The details of the lower furnace arrangement must be established. It is currently thought that the TIPS process lends itself to IGCC type furnaces and can either be slagging or of a fluid bed type. There are associated problems and benefits associated with each of these arrangements. Simulations of these systems are required followed by computational fluid dynamics modeling of several different arrangements. Eventually pilot testing should be carried out to validate the results. b) Fluid Bed Type If the TIPS system were to use a fluid bed, the advantages of a bubbling system must be compared with a circulating arrangement. Circulating arrangements are typically

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used to increase residence time in ambient systems; this may not be relevant in the TIPS process because of the higher resident times associated with pressure and the expected higher combustion rates. Moderation of the furnace temperature could probably be most easily accomplished with a circulating arrangement thus eliminating the need for flue gas recycle; however, bubbling arrangements are simpler with fewer maintenance and operational issues. Moderation of bed temperatures may be able to be achieved using bubbling bed technology thus eliminating the erosion prevalent with circulating systems. c) Pilot Scale Work Experimental work is required to validate the combustion properties of various fuels at pressure, lower furnace heat transfer rates, ability to manage molten ash within the slagging arrangement, radiative and convective heat transfer rates at pressure, hotside corrosion rates, hot-side erosion rates, condensing heat exchanger design, operating cycles for startup and shutdown, fluid bed performance, and combustion in general at pressure and pollutant scrubbing. Additionally, material testing must be carried out, particularly for the hottest furnaces zones and the condenser. d) Modeling Studies A TIPS system should be designed in more detail in conjunction with an equipment manufacturer and should include basic flowsheets, design specifications and equipment sizing. Detailed computational fluid dynamics modeling work should be done in conjunction with process simulations to better understand the specific system performance details. Lower furnace and convective pass arrangements, burner design, flue gas condenser and scrubber configuration, and so on, should be investigated in the study. The models should use exact char kinetic parameters, derived from pilot-scale work data, for specific fuels at specified operating pressures. In addition, the optimal TIPS operating pressures, which depend upon the fuel type, delivered oxygen quality, required CO2 recovery rate and CO2 purity, must be established for each application.

12. Acknowledgements The authors wish to thank Mr. Dave Winship and Mr. Mark Douglas for input on furnace arrangements. Thanks are extended to Dr. Yewen Tan for providing two references on amine scrubbing. We would also like to thank Dr. Dennis Lu and Mr. Robin Hughes for input into pilot scale testing. The authors would also like to acknowledge the long term support for novel power generation processes supplied by the Canadian Panel on Energy R&D (PERD). 13. References [1]

Part 1

Fassbender, A., United States Patent No: US 6,196,000 B1, March 6, 2001.

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Technical and Economic Feasibility Study of a Pressurized Oxy-fuel Approach to Carbon Capture – Part 2

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[2]

Zheng, L. “Product Recovery Train Development for CO2 Capture in Oxy-fuel Environment,” The 30th International Technical Conference on Coal Utilization and Fuel Systems, Clearwater, FL, April 18-22, 2005.

[3]

Allam, R.J., Panesar, R.S., White, V., and Dillon, D. “Optimising the Design of an Oxyfuel-fired Supercritical PF Boiler,” The 30th International Technical Conference on Coal Utilization and Fuel Systems, Clearwater, FL, April 18-22, 2005.

[4]

Zheng, L., Tan, Y. and Wall, T. “Some Thoughts and Observations on Oxy-fuel Technology Developments,” The 22nd International Pittsburgh Coal Conference, Pittsburgh, PA, September 12-15, 2005

[5]

http://www.epri.com, “Evaluation of Advanced Coal Technologies with CO2 Capture,” Electric Power Research Institute (EPRI) Report 000000000001004880, April, 2004

[6]

Fluor Corporation, “Evaluation of CO2/O2 Combustion (Oxy-fuel) Options,” Canadian Clean Power Coalition Study Report, July, 2003.

[7]

Craigen, D. Personal communication, Weyburn, Saskatchewan, July, 2003.

[8]

Douglas, M. Personal communication, Ottawa, Ontario, July, 2002.

[9]

Zheng, L., Clements, B. and Douglas, M. “Simulation of an Oxy-Fuel Retrofit to a Typical 400 MWe Utility Boiler for CO2 Capture,” The 26th International Technical Conference on Coal Utilization and Fuel Systems, Clearwater, FL, March 5-8, 2001.

[10] Tan, Y. and Croiset, E. “Emissions from Oxy-fuel Combustion of Coal with Flue Gas Recycle”, Proceeding of The 30th International Technical Conference on Coal Utilization and Fuel Systems, April 18-22, 2005, Clearwater, Florida. [11] Chatel-Pelage, F., Marin, O. et al.; “A pilot-scale demonstration of oxy-combustion with flue gas recirculation in a pulverized coal-fired boiler”, Proceeding of The 28th International Technical Conference on Coal Utilization and Fuel Systems, March 10-13, 2003, Clearwater, Florida. [12] Allam, R., Foster, E., and Stein, V. ; “Improving Gasification Economics through ITM Oxygen Integration”, Proceeding of The 5th (IchemE) European gasification Conference, april 8-10, 2002, Noordwijk, The Netherlands. [13] Zheng, L., Tan, Y., Pomalis, R., and Clements, B. “Integrated Emission Control and Its Economics for Advanced Power Generation Systems,” The 31st International

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Technical Conference on Coal Utilization and Fuel Systems, Clearwater, FL, May 21-25, 2006. [14] Zheng, C., Clements, B. and Zheng, L. “The Feasibility of Decreased Furnace Size with Reduced Flue Gas Re-circulation in Coal-Fired Boiler Designs,” The 30th International Technical Conference on Coal Utilization and Fuel Systems, Clearwater, FL, April 18-22, 2005. [15] Zheng, L., Clements, B. and Runstedtler, A. “A Generic Simulation Method for the Lower and Upper Furnace of Coal-fired Utility Boilers Using Both Air Firing and Oxy-Fuel Combustion with CO2 Recirculation,” The 27th International Technical Conference on Coal Utilization and Fuel Systems, Clearwater, FL, March 4-7, 2002. [16] Ordorica-Garcia, G., Douglas, P., Croiset, E., and Zheng, L. “Technoeconomic evaluation of IGCC Power Plants for CO2 Avoidance,” Journal of Energy Conversion & Management, 47 (2006) 2250-2259. [17] Dijkstra, J., van der Marel, J., et al. “Near zero Emission Technology for CO2 Capture from Power Plant,” IEA Greenhouse Gas R&D Program, Report Number: 2006/13, October, 2006.

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