A Method to Increase Oxyfuel Power Plant Efficiency and Power Output

Transcription

1 A Method to Increase Oxyfuel Power Plant Efficiency and Power Output Andrew Seltzer Zhen Fan Horst Hack Foster Wheeler North America Corp., R&D 53 Frontage Road Hampton, NJ Presented at the 37th International Technical Conference on Clean Coal & Fuel Systems Clearwater, Florida June 3, 2012

2 ABSTRACT Power plants designed to incorporate oxyfuel combustion are expected to play a major role in the capture and sequestration of CO2 emissions from fossil fuel based power generation, as part of an overall strategy to achieve a reduction in greenhouse gas emissions. However, due to the additional parasitic power consumption of the air separation unit and the CO2 processing unit, a significant reduction in plant efficiency and net power is expected, compared to conventional air fired power plants. To minimize the plant s derating and CO2 removal penalty, novel boiler modifications are proposed and evaluated. Aiming to improve cycle efficiency and power generation of an oxyfuel power plant, Foster Wheeler has developed a method, in which the highest pressure feedwater heater(s) are shut off, and the boiler economizer and reheater sizes are enlarged. This method provides an increase in plant efficiency, resulting from reducing fluegas temperature to the downstream air/gas heater, shifting part of the heat recovery upstream for heating feedwater and increasing reheat steam flow. The additional reheat steam flow also provides an increase in plant power output, associated with the higher efficiency and increased firing rate. Such a methodology is also applicable to supercritical, and advanced ultrasupercritical steam cycles, due to high outlet feedwater temperatures and the firing of high moisture and/or high ash fuel as a consequence of high flue gas thermal capacity. INTRODUCTION Currently about 40% of the world s electrical power comes from coal, which is considered a major source of CO2 emissions. There are various ways to reduce the net CO2 emission, such as co firing with biomass, improving plant efficiency, applying CO2 capture and sequestration, and combining these methods, such as by supercritical (SC) or ultra supercritical (USC) oxycombustion [1 5]. The most cost effective way of reducing CO2 and other emissions is to improve plant efficiency. Plant efficiency can be improved by increasing main and reheat steam outlet conditions, such as in a SC or USC power plant. The efficiency can be further improved by utilizing the heat recovery methodology described herein. In a boiler, the fluegas exiting from a furnace is cooled down in a heat recovery area (HRA), consisting of superheat (SH), reheat (RH) and economizer sections. After the HRA, the flue gas supplies heat to a combustion air heater (AH). Figure 1 presents a typical Temperature Heat Duty (T Q) diagram for the AH, where the AH exit fluegas (stack gas) temperature is determined by the inlet AH temperature, the relative heat capacities of the fluegas and air, and the cold side air inlet temperature. Consequently stack gas temperature rises (reducing boiler efficiency) with advanced steam conditions, high fuel moisture and ash content and oxycombustion operation. Increased feedwater temperature resulting from high main steam pressure can increase stack gas temperature. Typically, the feedwater temperature is 440 F from a sub critical steam turbine, 570 F from a super critical steam turbine, and 630 F from an ultra supercritical steam turbine with a high main steam temperature of 1300 F. It is noted that the increase in feedwater temperature corresponds to an increase in the fluegas temperature exiting from 2

3 boiler economizer to the downstream AH. An elevated fluegas temperature to the AH potentially causes a temperature pinch on the AH and results in increased fluegas temperature exiting from AH (Figure 1) to the stack. High coal moisture/ash potentially increases stack gas temperature. The T Q diagram and the corresponding heat recovery is affected by the ratio of heat content of fluegas to air, (W Cp)gas/(W Cp)air. This ratio can be for a low moisture coal, and for a high moisture/ash coal. This ratio is even higher for the oxy combustion case since the duty of the AH is low. The greater this ratio the worse the temperature pinch and the higher is the stack gas temperature become. Figure 1 T Q Diagram for Air Heater Oxycombustion operation potentially increases stack gas temperature. For oxy combustion, fluegas is recirculated, mixed with oxygen and fed to the boiler [3]. Due to the higher inlet temperature of recirculated gas (compared to fresh air) and due to the reduced AH duty (caused by both the elevated temperature and the reduced flow of recirculation gas to the AH), a temperature pinch occurs, and results in the need for an additional economizer to recover low grade heat from fluegas for boiler efficiency improvement. A combination of high temperature (SC/USC) steam turbine and oxy combustion increase the challenge for efficiency improvement through low grade heat recovery. In order to lower the stack gas temperature for the oxy combustion case, an economizer is typically incorporated to recover low grade heat from the fluegas to replace part of feedwater heater(s). This economizer is designed in parallel with AH through split fluegas stream or directly after the AH, to recover heat for condensate heating with some of feedwater heaters 3

4 (FWH) shutoff. However, the addition of an economizer reduces the steam cycle efficiency. The steam cycle efficiency is determined by heat absorption from the boiler and heat rejection to the condenser. Using steam extraction to heat up condensate and feedwater through FWHs improves steam cycle efficiency, because the latent heat of steam is applied to and carried back by feedwater to the steam cycle, which directly reduces the heat requirement from boiler and thus the fuel firing rate. From the cycle efficiency point of view, the more steam is extracted for feedwater heating, the better the cycle efficiency, which is determined by the maximum obtainable feedwater temperature and thus the maximum steam extraction pressure. For this purpose, a high feedwater temperature is always desired. For the USC steam turbine case, the cycle efficiency increases significantly from 44% to 50% when steam extraction is applied for feedwater heating (Figure 2). Figure 2 Feedwater Temperature Effect on Cycle Efficiency When an economizer is added to lower the stack gas temperature, a high feedwater temperature heated by steam extraction may not be the optimum since it raises fluegas temperature to the AH and potentially causes a temperature pinch in the AH. To avoid such a temperature pinch, feedwater heaters are shutoff. As it can be seen from Figure 2, for the same increment of feedwater temperature, the improvement in cycle efficiency flattens out with the increase of steam extraction pressure. Therefore, it is more efficient to shutoff the high pressure than the low pressure steam extractions, when the temperature pinch occurs, such as for oxy combustion, and especially for SC/USC steam conditions. Note that the steam extraction from the high pressure steam turbine section decreases not only the power, but also the flowrate of working fluid for reheating. In principle, the more the heat absorbed after the 4

5 latent heat requirement for a working fluid, the more power and the better the cycle efficiency will be obtained. NEW METHOD A method (Figure 3) is proposed to reduce feedwater temperature by shutting off the top feedwater heater(s) when an economizer is required to recover low grade heat from fluegas as a temperature pinch on AH occurs. The following effects can be expected from a lowered feedwater temperature: a) Enlarged economizer to maintain the same water temperature to the evaporator; b) Reduced high pressure steam extraction resulting in more power (Figure 2); c) Increased cold RH steam flow improving system efficiency. The key element of the new approach is the reduction of feedwater temperature to lower the heat carried by fluegas. The reduced steam extraction from the high pressure steam turbine section, increased cold RH steam flow, and corresponding reheater and economizer size changes are direct results of reduced feedwater temperature. Consequently, the temperatures of the fluegas to and from the AH are reduced. Figure 1 Arrangement of Heat Recovery Area 5

6 EVALUATION AND RESULTS To evaluate power and efficiency gains from the new method process simulations were performed using of Aspen Plus. Detailed design issues, such as effects of the new approach on metal temperature and furnace heat flux, were performed via FW FIRE, a proprietary 3 D CFD code [5]. Case 1: Air fired USC PC boiler The reference case was selected as a USC boiler with a feedwater temperature of 629 F, which requires two economizers, one after and one in parallel to the AH, to lower the fluegas temperature to 277 F. In a parametric study, the feedwater temperature was varied from 629 F to 580 F to evaluate its effect on the cycle efficiency and net power. Figure 4 and Table 1 show the result, where it can be seen that the optimum feedwater temperature is about 601 F which corresponds to the elimination of the two added economizers. At this optimum point, the plant gains both 0.6% point in net efficiency and 15 MWe (or 2%) in net power, with cold RH steam flow raised by 4.4% and fuel flow by 0.7%, due to increased RH steam flow and duty, and due to reduced air temperature from AH to furnace. At a feedwater temperature of 550 F, the same efficiency of 53.1% is achieved as with both added economizers, but 50 MWe (or 7%) more in net power is generated, provided that the size of boiler economizer is enlarged to maintain the same feedwater temperature to furnace. Of course, in practice, the increase in cold RH steam flow may be constrained for a given steam turbine. The same applies to the firing rate for the given boiler. For a new plant, there may be no such issues. Figure 2 Effect of Feedwater Temperature on Performance 6

7 Case 2: Oxy fired USC PC boiler Table 1 Summary of Feedwater Temperature Effect The air firing USC boiler used in the Case 1 was converted to oxy firing in the simulation study. The Foster Wheeler Flexi Burn approach [1 5] was applied allowing the same boiler to be used for both the air firing and oxy firing. The modifications included adding ducts for oxygen supply and for fluegas recirculation, and an economizer for low grade heat recovery. For further performance improvement, co benefit of emission control, and reduction of cost, the Foster Wheeler Zero Emission Process [4] was applied for a 100% removal of emission gases, including CO2. To maintain SH and RH outlet steam temperatures, waterwall metal temperatures, and a reasonable water attemperation range, about 75% of flue gas was recirculated. Figure 5 presents the results of the CFD simulation which shows that the furnace wall heat flux (and thus the corresponding wall temperatures) for the air fired and oxy fired cases is similar. The base case for comparison is the optimum air firing case, with a feedwater temperature of 601 F, but with two added LP economizers to maintain the same gas temperature to the ID fan. An alternate case was then generated by shutting off the top FWH. This reduced the feedwater temperature to 566 F, raised the plant net efficiency by 0.3% points and net power by 21 MWe (or 3.4%). The cold RH steam flow was raised by 5.0%, main steam flow by 2.7%, and firing rate by 3.0%. These gains are extra improvements beyond those of the optimum air fired case. 7

8 Figure 3 Furnace Wall Heat Flux CONCLUSION For an oxycombustion boiler, especially with advanced steam conditions, the heat transfer of the air heater is limited by the hot side temperature pinch, resulting in a high flue gas outlet temperature. To lower the fluegas temperature entering the air heater, a downstream economizer is added to recover the low grade heat. An approach has been proposed, where the heat carried by fluegas to the downstream air heater is reduced by increasing the heat duty of the boiler economizer with a lowered feedwater temperature. The lower temperature is obtained by shutting off the top feedwater heater(s), which results in lowering fluegas exit temperature and producing more power. Parametric evaluation indicates that for the oxycombustion USC PC boiler, the application of new approach boosts the plant net efficiency by 0.3% points and the net power by 21 MWe (or 3.4%) when the optimum air fired case (0.6% points in net efficiency and 15 MWe or 2.0% in net power) is obtained and used as a start point for oxycombustion. The gains in efficiency and 8

9 power have the potential to reduce the cost of electricity and reduce the derating of an oxycombustion plant. Such gains are case dependent, affected by the extent of temperature pinch. The new approach is fully applicable for a retrofitted plant, but the extent needs to be checked against the margin of the RH design and steam turbine capacities. For the oxycombustion boiler, one option for retrofit is to extract hot RH steam to drive CO2 compressors to avoid flow rate limitations from low pressure steam turbine section. REFERENCES 1. H. Hack, A. Seltzer, Z. Fan, A. Robertson, T. Eriksson, and O. Sippu, Oxygen Combusting Boiler System and a Method of Generating Power by Using the Boiler System, Patent EU , granted 11/16/ Z. Fan, A. Seltzer and H. Hack, A Method to Improve Plant Efficiency and Output, 15th Annual Energy, Utility & Environment Conference (EUEC) 2012, Jan 30 Feb 1, Phoenix, AZ, USA 3. A. Seltzer, Z. Fan and H. Hack, Design of a Flexi Burn Pulverized Coal Power Plant for CO2 Sequestration, The 34th International Technical Conference on Coal Utilization & Fuel System, June 1 4, 2009, Clearwater, FL, USA 4. Z. Fan, A. Seltzer and H. Hack, Oxyfuel Power Generation with Closed Loop to Reach Zero Emission, 10th Annual Carbon Capture & Sequestration Conference, May 2 5, 2011, Pittsburgh, PA, USA 5. A. Seltzer, Z. Fan and H. Hack, Ultra Supercritical Oxyfuel Power Generation for CO2 Removal, The 36th International Technical Conference on Coal Utilization & Fuel System, June 3 7, 2011, Clearwater, FL, USA 9