Technical Assistance Consultant s Report

Transcription

1 Technical Assistance Consultant s Report Project Number: September 2014 People s Republic of China: Study on Carbon Capture and Storage in Natural Gas-Based Power Plants (Financed by the Carbon Capture and Storage Fund under the Clean Energy Financing Partnership Facility) Prepared by Beijing Jiaotong University and North China Electric Power University Beijing, China For Datang International Power Generation Co., Ltd. This consultant s report does not necessarily reflect the views of ADB or the Government concerned, and ADB and the Government cannot be held liable for its contents. (For project preparatory technical assistance: All the views expressed herein may not be incorporated into the proposed project s design.

2 ADB Technical Assistance Project: Aspen Simulation and Evaluation of Economic Feasibility of CO 2 Capture for Gaojing Gas Fired Power Plant Final (English Version) September 2014 Beijing Jiaotong University North China Electric Power University Edited by Steve Goldthorpe for ADB

3 Table of Contents 1 Introduction Background and Significance Research Objectives Research Scope Amount of flue gas treatment Operational mode MEA-based Carbon Capture and Chemical Process Simulation MEA-based Carbon Capture Technique Chemical Process Simulation Basic Data for Process Simulation Overview of extraction steam and flue gas conditions Parameters of LP Steam Quality of natural gas supply Flue gas conditions Aspen Plus Modeling Process Simulation for MEA-Based Carbon Capture Process Description Definition and simulation of benchmark conditions Models selection Reaction model Selection of equipment models Parameter research Results and Analysis Benchmark conditions CO 2 removal rate Flow rate of CO 2 -lean solution Operating pressure of stripper The temperature of rich solution at inlet of stripper The temperature of flue gas at inlet of absorber CO 2 -lean MEA temperature at inlet of absorber Summary I

4 4.5 Cooling water considerations Cooling water temperature Cooling water make up requirement Cooling water flow Economic Evaluation of MEA-Based Capture Process Basic Data Fixed Asset Investment Operating costs MEA and demineralised water costs Utilities costs Overall operating Costs Revised overall operating costs Influence of CO 2 Price on Operating Cost Summary Evaluation and Analysis of Retrofitting of Capture-ready Gas Fired Power Plant Land for Construction Power Plant efficiency Retrofitting Investment Summary Summary and Suggestions Tables References Appendix A TABLE 3-1 PARAMETERS OF PILOT PLANT LP STEAM RESOURCE... 3 TABLE 3-2 NATURAL GAS COMPOSITION (% BY VOLUME)... 3 TABLE 3-3 FLUE GAS PARAMETERS... 4 TABLE 3-4 FLUE GAS COMPOSITION... 4 TABLE 4-1 MAIN STREAMS OF THE ASPEN PLUS MODELING OF A SINGLE TRAIN... 8 TABLE 4-2 FLUE GAS FLOW RATE AND COMPOSITION TABLE 4-3 PARAMETERS FOR LP STEAM AND COOLING WATER II

5 TABLE 4-4 PARAMETERS OF THE MODELING MODULES TABLE 4-5 SIMULATION RESULTS AT BENCHMARK CONDITIONS TABLE 4-6 EFFECT OF CO 2 CAPTURE RATE ON THE UTILITIES DEMAND TABLE 4-7 EFFECT OF CO 2 -LEAN MEA FLOW ON THE UTILITIES DEMAND TABLE 4-8 EFFECT OF OPERATING PRESSURE OF STRIPPER ON THE UTILITIES DEMAND TABLE 4-9 EFFECT OF CO 2 -RICH MEA TEMPERATURE ON UTILITIES DEMAND TABLE 4-10 INFLUENCE OF TEMPERATURE OF FLUE GAS AT ABSORBER INLET TABLE 4-11 EFFECT OF TEMPERATURE OF LEAN MEA ON THE UTILITIES DEMAND TABLE 4-12 AIR AND COOLING WATER TEMPERATURE IN THE BEIJING REGION TABLE 5-1 CAPITAL COST EVALUATION BASIS TABLE 5-2 CAPITAL COSTS PARAMETERS TABLE 5-3 OPERATING COSTS ASSUMPTIONS TABLE 5-4 GENERAL INVESTMENT PARAMETERS TABLE 5-5 ESCALATION TABLE 5-6 COST OF EQUIPMENT UNITS INDICATED BY ASPEN PLUS TABLE 5-7 PROJECT CAPITAL COST TABLE 5-8 PRICES OF UTILITIES AND RAW MATERIAL TABLE 5-9 ESTIMATED RAW MATERIAL OPERATING COSTS [ORIGINAL] TABLE 5-10 ESTIMATED UTILITIES OPERATING COSTS [ORIGINAL] TABLE 5-11 OPERATING COST PER TRAIN [ORIGINAL] TABLE 5-12 REVISED OPERATING COST PER TRAIN FOR BENCHMARK CASE TABLE 6-2 PERFORMANCE OF RETROFIT OPTIONS FOR NGCC PLANT (IEAGHG, 2011) TABLE 6-3 COMPARISON OF CAPITAL COST APPENDIX A TABLE A-1 DESIGN DATA OF ADSORBER-TOWER TABLE A-2 DESIGN DATA OF COMPER TABLE A-3 DESIGN DATA OF COOLER TABLE A-4 DESIGN DATA OF COOLER TABLE A-5 DESIGN DATA OF COOLER III

6 TABLE A-6 DESIGN DATA OF EXCH TABLE A-7 DESIGN DATA OF FLASH TABLE A-8 DESIGN DATA OF GGH TABLE A-9 DESIGN DATA OF PUMP TABLE A-10 DESIGN DATA OF SEP TABLE A-11 DESIGN DATA OF STRIPPER-REBOILER TABLE A-12 DESIGN DATA OF STRIPPER-TOWER TABLE A-13 DESIGN DATA OF WASHER FIGURES FIGURE 2-1 ABSORPTION BASED POST COMBUSTION CAPTURE (GCCSI, 2012)... 1 FIGURE 4-1 FLUE GAS PRETREATMENT STAGE OF ASPEN PLUS PROCESS MODELING... 7 FIGURE 4-2 CO 2 CAPTURE STAGE OF ASPEN PLUS PROCESS MODELING... 7 FIGURE 6-1 SITE LAYOUT PLAN OF GAS FIRED POWER PLANT WITHOUT CARBON CAPTURE (IEAGHG, 2012) FIGURE 6-2 SITE LAYOUT PLAN OF GAS FIRED POWER PLANT WITH CARBON CAPTURE (IEAGHG, 2012) FIGURE 6-3 STEAM TURBINE RETROFIT WITH A FIXED INTERMEDIATE TURBINE OUTLET AND TWO LET-DOWN BACK PRESSURE TURBINES (IEAGHG, 2011), FIGURE A FIGURE 6-4 RETROFIT OF A NGCC PLANT WITH THE ADDITIONAL OF TWO BACK-PRESSURE TURBINES (IEAGHG, 2011), FIGURE A FIGURE 6-5 RETROFIT OF A NGCC PLANT WITH TWO THROTTLING VALVES (IEAGHG, 2011), FIGURE A4.7) IV

7 List of Abbreviations ADB ASME CAPEX CCS CER CHP CNY DIPGCL GDP GHG IEA IP LHV LP NGCC PCC PRC ROR USD Asian Development Bank American Society of Mechanical Engineers Capital expenditure Carbon capture and storage Certified emission reduction Combined heat and power Renminbi Yuan Datang International Power Generation Co., Ltd. Gross Domestic Product Greenhouse gas International Energy Agency Intermediate Pressure Lower heating value Low Pressure Natural Gas Combined Cycle Post-Combustion Capture The People s Republic of China Rate of return United States dollar V

8 1 Introduction 1.1 Background and Significance CO 2 is the main greenhouse gas (GHG) responsible for Climate Change. Its atmospheric concentration has increased to 401ppm in June 2014 (CO2now, 2014). With its rapid economic development in recent years, the Peoples Republic of China (PRC) became the largest energy consuming country in the world in 2009, with the consumption of 20% of global primary energy and 47% of global coal. In 2010, the PRC surpassed the U.S. and became the country with the largest total carbon emissions. Consequently, the PRC government made tremendous efforts to control its carbon emissions. On November 26, 2009, it released its ambitious GHG emissions cut target at the Copenhagen Climate Change Conference. China plans to cut its GHG emissions per unit of gross domestic product (GDP) by 40 to 45 percent below 2005 levels by Replacing coal-fired power plants with gas power plants is one of the major measures for CO 2 emissions reduction. Additionally, the gas power plant is especially suited to be used by developing countries, and regions like the PRC, to supply variable loads, provided a low cost natural gas supply can be accessed. In order to reduce CO 2 emissions, and achieve other environmental benefits, Beijing plans to convert all of its coal-fired power plants into gas power plants and heat supply centers. As one part of this plan, Datang International Power Generation Co Ltd. (DIPGCL) is now implementing a gas power plant conversion project at one of its suburban thermal power plants, Gaojing Combined Heat and Power (CHP). This project plans to shut down a 660MW coal-fired unit, which is being replaced by 3 sets of F-Grade gas turbines, each in a 350MW Natural Gas Combined Cycle (NGCC) configuration. After project completion, Gaojing CHP will have the power supply capacity of 6240GWh and winter heat supply capacity of 18 million cubic meters of hot water per annum. Nevertheless, large amounts of CO 2 will still be discharged from gas power plants. In the long run, gas power plants will be incorporated into the industry scope of CO 2 emission restrictions, which could mean that they are required to further reduce their CO 2 emissions, by implementing Carbon Capture and Storage (CCS). In light of this, ADB and the PRC government co-financed a project called, Study on Carbon Capture and Storage in Natural Gas-Based Power Plants (TA 8001-PRC), which was carried out by a research team administered by Beijing Jiaotong University (BJTU). The main purpose of this project is to develop the CCS roadmap for NGCC plants and to establish the CCS ready power plant criteria for Gaojing CHP. The research team conducted a detailed evaluation of technical and economic feasibility of retrofitting CCS to Gaojing CHP s gas-fired power plant, including a top-down economic assessment based on published data. This research project is an extension of the TA 8001-PRC study and attempts to make a bottom-up economic assessment of the proposed Gaojing CHP CCS plant. 1

9 1.2 Research Objectives The main objectives of this project are as below: Through process simulation, to evaluate CO 2 capture energy consumption in different scenarios and optimize that consumption; To make an economic feasibility evaluation of Gaojing CHP s CO 2 capture retrofitting; To evaluate the advantages of meeting capture-ready criteria in subsequent CCS implementation; and To recommend the capture-ready conditions for Gaojing CHP at different carbon capture rates. 1.3 Research Scope The research project will consider six scenarios comprising a matrix of three scales of operation and two load factors Amount of flue gas treatment There are a total of three 350MW NGCC and heat supply units in Gaojing Gas Fired Power Plant. Its three gas turbines are configured based on a one gas turbine with one steam cycle unit and a two gas turbines with one steam cycle unit. The three alternative scales of operation are: One-for-one unit scenario: In this scenario, carbon capture treatment is applied to flue gas in Gaojing CHP s one-for-one unit only. Given there is only one gas turbine in one-for-one unit, this scenario is equivalent to treating one third of flue gas of the plant. Two-on-one unit scenario: in this scenario, carbon capture treatment is applied to the flue gas in Gaojing CHP s two-on-one unit only. There are two gas turbines in the two-on-one unit, and therefore, it is equivalent in this scenario to treating two thirds of flue gas of the plant. All-plant flue gas scenario, i.e. one-for-one unit + two-on-one unit scenario: In this scenario, carbon capture treatment is applied to all flue gas in Gaojing CHP s One-for-one unit and two-on-one unit. Hence, it is equivalent in this scenario to treating the flue gas of the whole plant Operational mode During the heating season, Gaojing Gas Fired Power Plant needs to supply heat externally and generate electricity. During the non-heating season, it only needs to generate electricity. This research analyses CO 2 capture in two operational modes: 2

10 Scenario 1: running 2880 hours during the winter heating seasons + running 2620 hours during the non-heating seasons (spring and autumn), totaling 5500 hours in the year; and Scenario 2: running 2880 hours during the winter heating seasons +running 4620 hours during the non-heating seasons (spring, summer and autumn), totaling 7500 hours in the year. For these six scenarios, this research uses the chemical process simulation software, Aspen Plus, to undertake the process simulation and to analyze fixed asset investment and operating expenses. The influence of some process parameters, such as carbon capture rate, is assessed on LP steam requirement, electricity demand and cooling water requirement. This research carries out the simulation and analysis of carbon capture process only, excluding CO 2 dehydration, compression, transport and sequestration. 3

11 2 MEA-based Carbon Capture and Chemical Process Simulation 2.1 MEA-based Carbon Capture Technique MEA-based carbon capture technology is a mature post-combustion carbon capture technology with fast absorption rate and efficiency. It has been widely used for CO 2 recovery in some industrial processes. Figure 2-1 shows a typical process flow diagram of an MEA-based carbon capture process used to capture of CO 2 from a flue gas. In this process, CO 2 in the flue gas is absorbed by MEA in the absorber at a low temperature (about o C), and the CO 2 -rich MEA is then heated (to about o C) and CO 2 is regenerated in the stripper. Figure 2-1 Absorption based Post Combustion Capture (GCCSI, 2012) The Aspen Plus modeling that has been carried out on this process flow sheet is described in more detail in Chapter Chemical Process Simulation Computer simulation is useful for the preliminary design, operation optimization, sensitivity analysis, and technical and economic assessments of a chemical process. 1

12 Currently, software for chemical process simulation widely used by industry mainly includes ASPEN PLUS, PRO/II, HYSYS, ChemCAD and gproms. This research uses Aspen Tech s Aspen Plus software. The outstanding features of Aspen Plus are its complete physical properties databases. Physical properties models and data are the foundation for accurate simulation, and Aspen Plus software possesses a complete physical properties system most suited to the chemical industry. Its databases include pure component data, electrolyte solution data, solids data, Henry s constants, binary interaction parameter libraries, inorganic material data, combustion data, water solution data and other data for various chemical and physical parameters. Additionally, Aspen Plus provides pre-prepared carbon capture modules that use various amine absorbents for carbon capture in industrial process simulations. It provides physical properties data and binary interaction data that are suited to the simulation of MEA-based carbon capture process in the natural gas power plant. Aspen Plus is widely used and the results of other simulations have been well validated. 2

13 3 Basic Data for Process Simulation 3.1 Overview of extraction steam and flue gas conditions Parameters of LP Steam The stripper reboiler in the process of MEA-based carbon capture uses LP steam heating and stripping of the CO 2 -rich MEA solution to desorb CO 2 and regenerate MEA. The LP steam stream used in the Gaojing pilot plant comes from the gland sealing steam stream at conditions shown in Table 3-1. Table 3-1 Parameters of pilot plant LP steam resource Unit Value Temperature o C 150 Pressure bar 4.75 [Editorial Note - In a commercial scale optimized CO 2 capture plant the large volume of steam required for the stripper reboiler would be extracted from the crossover between the medium pressure and low pressure turbines in the power station steam cycle and would be depressurized is a power recovery turbine and desuperheated to increase its volume.] Quality of natural gas supply Gaojing Gas Fired Power Plant s gas turbine unit uses natural gas supplied via Shanxi-Beijing No. 3 Line. Table 3-2 provides the composition (volume percent) and LHV of natural gas. Table 3-2 Natural Gas composition (% by volume) CH 4 C 2 H 6 C 3 H 8 C 4 H 10 C 5 H 12 CO 2 N 2 H 2 S He 96.12% 0.501% 0.118% 0.033% 0.012% 2.6% 0.147% 4 ppmv 0.469% Lower Heating Value (LHV) MJ/Nm 3 (at normalized conditions of kpa and 20 o C) Flue gas conditions Feed gas processed by the CO 2 capture system comes from the exhaust of the host power station s heat recovery boilers. The flue gas may be subject to denitrification treatment. Table 3-3 and Table 3-4 show flue gas parameters and gas composition. 3

14 Table 3-3 Flue gas Parameters Unit Value Flue gas density kg/nm Flue gas temp. o C 79 Flue gas pressure KPa Flue gas velocity m/s 23.1 Flue gas mass flow kg/s Table 3-4 Flue gas composition Unit Value Ar 0.89 CO H 2 O % by volume 8.23 N O NOx mg/nm SO 2 mg/nm Dust mg/nm Aspen Plus Modeling Simulation of MEA-based carbon capture process Property methods and process simulation options need to be selected for simulating the MEA-based carbon capture process. Property method is the method used for the presentation of thermodynamic and kinetic parameters for physico-chemical properties and inter-species interactions (reactions) of all the species involving in the chemical process, and for the parameters that are unavailable in computer databases. In terms of the amine solution system of the MEA-based carbon capture process, for the property method in the liquid phase, the ELECNRTL method calculated via non-ideal models is used for liquid phase material (such as, water, amine and hydramine) to absorb acid gas. For gaseous phase parameters, Redlich-Kwong equation is selected. For the amine solution system, Aspen Plus possesses a dedicated data package suited to MEA-based carbon capture, which describes the dynamics on the reaction between MEA and CO 2 in the liquid phase. Therefore, KEMEA data package of MELECNRTL is used for this research. This data package is suited to the circumstances where the MEA concentration is <50% and solution temperature is <130 o C. 4

15 3.2.2 Unit models In the simulation of chemical processes, various chemical unit process and equipment are represented by modules. The main unit modules of MEA-based carbon capture process include absorbers, strippers, fans, pumps, splitters, mixers and heat exchangers. The calculation methods for simulation of modules are either equilibrium or non-equilibrium methods. Both the absorber and stripper involve multistage gas-liquid distillation operation, for which RADFRAC or RATEFRAC model can be used. RATEFRAC is a rate-based model for non-equilibrium separation. It simulates actual tray or packed columns, rather than idealized representations. RADFRAC is assumed to be an equilibrium stage model, suited to the optimization for theoretical analysis. RATEFRAC model needs to be used for the optimization of process parameters and in economic efficiency analysis. In these simulations, Aspen s RATEFRAC module is used. 5

16 4.1 Process Description 4 Process Simulation for MEA-Based Carbon Capture An illustrative process flow diagram for the MEA CO 2 capture process is shown in Figure 2-1. The corresponding diagrams for the configuration that has been modeled are shown in Figure 4-1 and Figure 4-2. Data for the main streams of the Aspen Plus modeling of a single train of the MEA process are presented in Table 4-1 Main Streams of the Aspen Plus Modeling of a single train. The flue gas (FLUEGAS) from the denitrification system of the host power station enters a separator (SEP) to condense part of the water vapor from the flue gas to decrease the load on the compressors. The compressors (COMPR1-COMPR4) compress the flue gas to the absorber inlet pressure. The compressed flue gas then enters a gas-gas-heater (GGH) and a cooler (COOLER1) to be cooled to the absorber inlet temperature. In the absorber (ADSORBER), cooled flue gas comes into contact with the recycled CO 2 -lean MEA-water solution (LEAN-ABS), and most of the CO 2 is absorbed by MEA and thus separated from the flue gas. The processed flue gas (TREATGAS) and a CO 2 -rich amine (RICH-MEA) are the output streams from the absorber module. The processed flue gas (TREATGAS) is cooled and enters a separator (WASHER) to condense water vapour and to remove MEA from the vented gas stream. The condensate (CONDWAT) discharged from WASHER flows back to a mixer (MIXER) to mix with the make-up water part of the MEA solution (MEAWAT) and recycled CO 2 -lean solution. The make-up of MEA is not modeled. The temperature of the scrubbed flue gas from WASHER is 32 o C. The flue gas at this low temperature is not buoyant. Ideally, the discharged flue gas should be warmer than 75 o C. Some Chinese plants discharge flue gas at o C after desulphurization. The clean flue gas (VENTGAS) discharged from WASHER enters the gas-gas-heater (GGH) to be heated to a temperature of 60 o C prior to discharge to atmosphere. The CO 2 -rich solution (RICH-MEA) discharged from the absorber is pumped to the lean/rich solution heat exchanger (EXCH), where the CO 2 -rich solution is preheated by the CO 2 -lean solution discharged from the stripper (STRIPPER). The preheated CO 2 -rich solution enters the stripper and is heated by LP steam in the reboiler to strip CO 2 out of the CO 2 -rich solution. CO 2 recovered from the amine solvent leaves from the top of the stripper accompanied by water vapor. That stream is cooled to condense water, which is separated and flows back into the stripper. The CO 2 -lean solution from the base of the stripper column is partially cooled in the heat exchanger EXCH by the CO 2 -rich solution stream. Because absorbent (MEA solution, MEA and H 2 O) degrades in the process and escapes with the processed flue gas, a mixer (MIXER) is added to the system to make up the lost MEA solution. The mixed stream is further cooled in COOLER4 to the absorber inlet temperature before entering the absorber. 6

17 Figure 4-1 Flue gas pretreatment stage of Aspen Plus process modeling [Editorial note The use of a bank of gas compressors, to substantially increase the pressure for the feed gas to the absorber, results from the assumption of a large pressure drop in the vapour phase passing through the absorber. In commercial MEA plant designs the vapour phase pressure drop across the absorber is minimized by equipment design, in particular by ensuring that flooding of the column with liquid does not occur and that the gas flows upwards freely over a packing that is wetted with down-flowing MEA solution. It appears that in this Aspen Plus modeling study the absorber has been modeled as a flooded column in which the gas phase is bubbled through the MEA solution against a large hydraulic head. Furthermore, since the flue gas is the exhaust gas from a gas turbine, the driving force could be provided by a back pressure on the gas turbine. Accordingly, the high capital cost and high energy consumption reported for feed gas compression in this modeling study is not representative of a likely commercial plant design. A low-power booster fan might be used to aid control of the process.] Figure 4-2 CO 2 Capture Stage of Aspen Plus process modeling 7

18 Table 4-1 Main Streams of the Aspen Plus Modeling of a single train Name FLUEGAS SEP-OUT FLUE-ABS TREATGAS CONDWAT VENTGAS Mass Flow kg/hr 637,470 36, , ,240 18, ,546 Mole Flow kmol/hr 23,048 2,021 21,027 21,517 1,036 20,480 Temperature C Pressure bar Vapor Frac Volume Flow m 3 /hr 665, , , ,507 Enthalpy Gcal/hr Component mass flows kg/hr H 2 O 52,468 36,406 16,062 35,071 18,651 16,416 CO 2 26, ,775 2, ,199 N 2 476, , , ,238 O 2 76, ,247 76, ,231 MEA Trace MEA + trace 19.8 MEACOO - trace HCO 3 trace trace CO 3 trace trace 0.5 ARGON 5, ,672 5, ,4510 SO 2 trace trace trace trace - HSO SO 3 trace NO 12 trace trace 12 Main streams of Aspen Plus modeling of a single train - continued Name RICH-MEA RICH-STP FLASHED LEAN-STP MEAWAT LEAN-ABS Mass Flow kg/hr 980, ,663 25, , ,843 Mole Flow kmol/hr 39,941 40, , ,986 Temperature C Pressure bar Vapor Frac Volume Flow m 3 /hr 1,026 1,091 5,743 1, ,008 Enthalpy Gcal/hr , ,905 Component mass flows kg/hr H 2 O 638, , , ,685 CO ,279 24, N trace 0.3 O trace 0.1 MEA 64,958 77,330 trace 130, ,662 MEA + 106, ,760 69, ,102 MEACOO - 160, , , ,227 - HCO 3 6,300 9,854 2,863 1, CO 3 2, ,068 ARGON SO 2 trace trace trace trace trace - HSO 3 trace trace trace trace 2- SO NO trace trace 8

19 In a commercial MEA plant there would be a discharge and reclaim system of waste solvent from the LEAN-STP stream between the reboiler and EXCH. However, due to the difficulty of the simulation of MEA degradation, this system is omitted in this modeling flow sheet. This simplification of the flow sheet does not alter the results of the parameter researches in this chapter. In Chapter 5, the loss of MEA due to degradation is estimated based on the data of process vendors. 4.2 Definition and simulation of benchmark conditions Basic hypothesis for simulation The power plant s exhaust gas consists of many constituents, and various other factors have impacts on the absorption process. In order to simplify the simulation process, the basic hypothesis of simulation is as follows: (1) NOx consists of NO, NO 2 and N 2 O. The content of NOx in post-denitrification flue gas is low, and even lower than the maximum NO 2 concentration that can be tolerated by MEA absorbent. In the simulation, consideration will not be given to the interactions between NOx and MEA in the simulation. The MEA loss resulted from degradation will be estimated based on the data of suppliers. [Editorial note The Chinese NOx emission standard for gas fired power stations is 50 mg (NO2) /Nm 3 (24.6 ppm by volume). The recommended maximum NO x content of MEA scrubber feed gas is 20 ppm by volume. So improved denitrification might be required prior to CO 2 capture.] (2) The influence of oxidation and corrosive effects in the simulation process are not considered; (3) The reaction process is assumed to be adiabatic; (4) In the state of gas-liquid equilibrium, CO 2, oxygen and nitrogen will conform to Henry s Law. Due to huge amounts of flue gas for processing, it is impossible for a single absorber to process such a huge amount of flue gas, even if just handling the flue gas from one gas turbine. For this reason, every gas turbine is equipped with 4 trains of carbon capture system, each train including 4 compressors, 1 absorber and 1 stripper. Each train will process one twelfth of flue gas from all the three gas turbines, i.e. each train will process one quarter of the flue gas from a single gas turbine. Flue gas flow, velocity and composition in the post-denitrification flue gas for the one-for-one unit of Gaojing Gas Fired Power Plant, are shown in Table 4-2. Parameters for low pressure stream extraction and cooling water from the capture process are shown in Table

20 Table 4-2 Flue gas flow rate and composition Units Parameter Temp. o C 79 Pressure kpa GT Flue gas Flow tonnes/h 2,550 Amount of flue gas flow processed by a single train of carbon capture tonnes/h Flue gas composition (volume%) Ar 0.89% CO 2 4.2% H 2 O 8.23% N % O % NOx 20 ppmv SO ppmv Table 4-3 Parameters for LP steam and Cooling Water Unit Value Temperature of LP steam o C 150 Pressure of LP steam bar 4.75 Cold End Temp. difference of the Reboiler o C 5 Temperature of cooling water o C 15 Pressure of cooling water bar Definition of benchmark conditions In the simulation, MEA characteristics embedded in modules of Aspen Plus are used to build thermodynamic and mass transfer models. They use ELECNRTL models to describe the thermodynamic properties of the MEA-H 2 O-CO 2 system. The simulated benchmark conditions are defined as below: CO 2 removal efficiency is nominally 90%; (Table 4-1 shows the simulation results of main streams for one train of CO 2 capture system. Stream FLUEGAS is the flue gas stream flowing into the capture system and stream FLASHED is the CO 2 product stream flowing off the capture system. CO 2 capture rate is calculated according to this equation: Capture rate of CO = mass low of CO in the stream of FLASHED mass low of CO in the steam of FLUEGAS According to the CO 2 flow rate of stream FLUEGAS and stream FLASHED in Table 4-1, the CO 2 capture rate is 91.79% in the benchmark case.) Absorbent concentration is 30% by weight MEA; 10

21 Stripper pressure is 1.9 bar; Temperature of CO 2 -rich solution at the stripper s inlet is 95 o C; Temperature of CO 2 -lean solution at the absorber s inlet is 40 o C; and, Temperature of the flue gas at the absorber s inlet is 40 o C. 4.3 Models selection Reaction model Due to existence of multi-stage equilibrium and dynamic reversible reaction, the reaction and absorption of MEA-H 2 O-CO 2 system are complicated. The equilibrium reactions in this model include the following, in which MEA is represented as R-NH 2 : 2H O=H O! +OH # (4-1) CO +2H O=HCO # +H O! (4-2) HCO # +H O=CO # +H O! (4-3) R NH! +H O=R NH +H O! (4-4) R NH COO # +H O=R NH +HCO # (4-5) SO +2H O=HSO # +H O! (4-6) HSO # +H O=SO # +H O! (4-7) The reaction equilibrium constants and kinetic constants included in the Aspen Plus modeling software are used in this simulation Selection of equipment models RATEFRAC model is used for absorber and stripper; HEATER unit model is used for the COOLER1, COOLER4 and COOLER5; HEATX model, which is a model for a two-stream heat exchanger for the gas-gas heat exchanger GGH and the lean/rich solution heat exchanger EXCH; MIXER model is used for the MIXER and MIXER3; FLASH2 Model is used for the gas-liquid separators (SEP, WASHER and FLASH); PUMP model is used for rich liquid pump. COMPR model is used for feed gas compressors Parameter research In this chapter, the effects of the parameters below on the utility requirements of the CO 2 capture process will be investigated: CO 2 removal efficiency; CO 2 -Lean solution flow rate. Operating pressure of stripper; Temperature of rich solution at the inlet of the stripper; Temperature of flue gas at the inlet of the absorber; 11

22 Temperature of lean solution at the inlet of the absorber; The following performance indicators used to evaluate parameter influence on the absorption/stripping process: Reboiler thermal duty for CO 2 stripper (GJ/t CO 2 ); Amount of low pressure steam needed by the stripper (t/t CO 2 ); [Editorial note the low pressure steam demand is equivalent to the reboiler thermal duty at an enthalpy change of GJ/tonne, which corresponds to the enthalpy difference between saturated steam at 150 o C and 4.75 bar and water condensate at 125 o C. Almost all that heat would be delivered at 150 o C, which may give rise to excessive thermal degradation of the MEA] Electrical power (kw/t CO 2 ); and, Consumption of cooling water (t/t CO 2 ). Table 4-4 Parameters of the modeling modules Model Temperature, o C Pressure, bar COOLER1 DHE TEMA EXCH COOLER4 DHE TEMA EXCH COOLER5 DHE TEMA EXCH EXCH DHE TEMA EXCH 95 GGH DHE TEMA EXCH 60 COMPR1,2,3,4 DGC CENTRIF 1.7 PUMP DCP CENTRIF 2.7 FLASH-flash vessel DVT CYLINDER SEP-flash vessel DVT CYLINDER 30 1 WASHER-flash vessel DVT CYLINDER 32.3 MIXER C 2.1 MIXER3 C 1.7 Temp. - o C Press.- bar No. stages Diam.- m STRIPPER-reboiler DRB THERMOSIPH 125 STRIPPER-tower DTW TRAYED ADSORBER-tower DTW TRAYED Results and Analysis Benchmark conditions The simulation results at benchmark condition are shown in Table 4-5. In the sensitivity studies the effect of one of the parameters on process performance is investigated and the other parameters remain unchanged. In this situation, the CO 2 capture rate may change. If so, the results presented are calculated to correspond to the consistent basis of the amounts of utilities required for capturing one tonne of CO 2. In the reporting of sensitivity studies the benchmark results are presented in bold. 12

23 Table 4-5 Simulation Results at Benchmark Conditions Unit Value Duty of reboiler GCal/h 35.7 GJ/t CO Consumption of LP steam tonnes/h t/t CO Flow of lean solution tonnes/h t/t CO Electricity requirement Electricity for compressors MW kw/t CO Electricity for CO 2 -rich solution pump kw 53.3 kw/t CO Total Electricity requirement MW kw/t CO Cooling water requirement Cooling water for flue gas(cooler1) tonnes/h t/t CO Cooling water for lean solution(cooler4) Tonnes/h t/t CO Cooling water for CO 2 product(cooler5) Tonnes/h t/t CO Total cooling water requirement tonnes/h t/t CO CO 2 removal rate Table 4-6 shows the influence of CO 2 capture rate on the utility requirement. The electricity requirement increases with an increase in CO 2 capture rate. However, the duty of reboiler, steam consumption of reboiler and the cooling water requirement reach their minimum between CO 2 capture rates of 76% and 91%. Table 4-6 Effect of CO 2 capture rate on the utilities demand CO 2 capture rate % Duty of Reboiler GJ/tCO 2 Steam t/tco 2 Electricity kw/tco % % % % % Cooling Water t/tco 2 13

24 4.4.3 Flow rate of CO 2 -lean solution Table 4-7 shows the influence of CO 2 -lean solvent flow rate on the utilities requirement. The duty of reboiler, steam consumption of reboiler and the cooling water requirement decrease with an increase in flow rate of CO 2 -lean solution. On the other hand, with an increase in flow rate of lean solution, the electricity requirement increases and CO 2 capture rate increases also. Table 4-7 Effect of CO 2 -Lean MEA flow on the utilities demand Lean flow tonnes/h Duty of Reboiler GJ/tCO 2 Steam t/tco 2 Electricity kw/tco 2 Cooling Water t/tco Operating pressure of stripper Table 4-8 shows the influence of the operating pressure of the stripper on the utilities requirement. With an increase in operating pressure of stripper, the duty of reboiler, the steam consumption, the cooling water requirement and the electricity requirement reach their minimum at 1.9 bar. Table 4-8 Effect of operating pressure of stripper on the utilities demand Operating pressure bar Duty of Steam Electricity Reboiler t/tco 2 kw/tco 2 GJ/tCO Cooling Water t/tco The temperature of rich solution at inlet of stripper Table 4-9 shows the influence of the temperature of rich solution at inlet of stripper on the utilities requirement. With an increase in the temperature of rich solution at inlet of stripper, the duty of reboiler, the steam consumption and the cooling water requirement decrease. However, the electricity requirement increases with an increase in the temperature of rich solution at inlet of stripper. In the temperature range of o C, an increase in the temperature of rich solution at inlet of stripper exerts few effect on the amount of electrical energy consumption, but results in an large decrease in CO 2 capture rate. As the result, the electricity requirement for capturing one tone of CO 2 increases with an increase in the temperature of rich solution at inlet of stripper. 14

25 Table 4-9 Effect of CO 2 -rich MEA temperature on utilities demand Temperature of CO 2 -rich MEA o C Duty of Reboiler Steam Electricity GJ/tCO 2 t/tco 2 kw/tco 2 95 o C Cooling Water t/tco 2 96 o C o C o C The temperature of flue gas at inlet of absorber Table 4-10 shows the influence of the temperature of flue gas at the inlet of the absorber on the utilities requirement. An increase in the temperature of the flue gas at the inlet of the absorber results in a decrease in the CO 2 adsorption efficiency of solvent, and hence a decrease in CO 2 capture rate. As a result, the duty of reboiler, the steam consumption and electrical energy consumption for capturing one tonne of CO 2 increases. On the other hand, with an increase in the temperature of flue gas at inlet of absorber, the cooling water flow required to cool the flue gas decreases, while the CO 2 capture rate decreases. An outcome is that cooling water requirement for capturing one tonne of CO 2 reaches its minimum at the flue gas temperature of 45 o C. Temperature of flue gas Table 4-10 Influence of temperature of flue gas at absorber inlet Duty of Reboiler GJ/tCO 2 Steam t/tco 2 Electricity kw/tco 2 Cooling Water t/tco 2 40 o C o C o C CO 2 -lean MEA temperature at inlet of absorber Table 4-11 shows the influence of CO 2 -lean MEA temperature at the inlet of the absorber on utilities requirement. With an increase in CO 2 -lean temperature at the inlet of the absorber, the duty of the reboiler, the steam requirement, and also the cooling water requirement decrease. However, electricity requirement for capturing one tonne of CO 2 increases with an increase in the CO 2 -lean temperature at the inlet of the absorber. Table 4-11 Effect of temperature of lean MEA on the utilities demand Temperature of lean MEA Duty of Reboiler GJ/tCO 2 Steam t/tco 2 Electricity kw/tco 2 38 o C o C o C o C Cooling Water t/tco 2 15

26 4.4.8 Summary The energy consumption is lowest at a CO 2 capture rate between 76% and 91%. The effect of certain parameters on one of the energy consumption indicators may be different from its effect on other energy consumption indicators, so the selection of the optimal operating condition should be decided by the evaluation of the effects of these parameters on the total cost of capture process. If the lowest consumption of LP steam is used as an object for optimization of the operating conditions, the optimal operation conditions are as follows: Operating pressure of stripper is 1.9 bar, The temperature of rich solution at the inlet of stripper is 99 o C; The temperature of flue gas at inlet of absorber is 40 o C;and The temperature of lean solution at inlet of absorber is 44 o C. If the lowest consumption of electrical energy is used as an object for optimization of the operating conditions, the different optimal operation conditions are as follows: The temperature of rich solution at the inlet of stripper is 95 o C; and The temperature of lean solution at the inlet of absorber is 38 o C. 4.5 Cooling water considerations Three coolers have been modeled in the carbon capture system, which require cooling water. In the modeled Gaojing CHP s carbon capture system, the coolers are Cooler1, Cooler4 and Cooler5. The required amount of cooling water is related to the temperature of cooling water Cooling water temperature Cooling water in the condenser s recirculation cooling water system in the steam cycle is used as the cooling water for Gaojing CHP s carbon capture system. Table 4-12 shows the average temperature of various seasons and average operating temperature of recirculation cooling water at a power plant in the Beijing region. Table 4-12 Air and Cooling Water Temperature in the Beijing Region o C Average Air Temp. Winter Spring Autumn Summer -5~+5 1~12 15~25 18~29 Temp. of Cooling Water The design temperature of the power station recirculating cooling water system is 33 o C at the maximum required to operate the power station condenser with the LP turbine exhaust at 42 o C. However, the actual operating temperature of recirculation cooling water in spring and autumn may be well under this maximum. The operating temperature for spring and autumn is usually 25 o C, while it is typically 15 o C in winter. 16

27 Cooling water temperature will influence the heat exchange area necessary for the heat exchanger, thus influencing its building cost. However, when designing the coolers, it is necessary to do so in the light of its annual maximum water temperature. Therefore a scenario is considered with an operating time of 5500 hours with the summertime operation avoided. On this basis the cooling water temperature would be 25 o C Cooling water make up requirement Consumption of recirculation cooling water includes the loss from evaporation, windage and blow down in the cooling tower. According to the specifications and data in (L/T5339, 2006), 1.5% is taken for evaporation loss coefficient, 0.4% for windage loss coefficient and 1% for blow down loss coefficient, which combine to make 2.9% for total cooling water make-up requirement Cooling water flow The carbon capture system needs large amounts of recirculation cooling water. Hence, consideration should be given to whether the capacity of Gaojing CHP s existing recirculation cooling water systems can provide sufficient cooling water for its carbon capture system. If it cannot provide sufficient cooling water, it is necessary for the carbon capture system to include new recirculation cooling water systems or to expand its existing recirculation cooling water systems. The carbon capture system extracts steam from the steam cycle, which reduces the steam discharging into the power plant condenser. Therefore the steam cycle condenser cooling water flow will be reduced accordingly. [Editorial note - From an energy balance perspective, the overall energy input to the power station is either exported as electricity or dissipated to cooling water, with only a small part of that energy dissipated by other means. If CO 2 capture is integrated into the power station energy balance, then the net electricity output is reduced, so the net heat dissipated to cooling water must increase by a similar amount, which is manifest as the addition of cooling in the CO 2 capture plant being greater than the reduction of cooling in the power plant condenser. The amount of energy delivered to CO 2 capture, and subsequently rejected to cooling, is about five times greater than the amount of electrical energy production that is lost due to steam extraction from the steam cycle. Therefore the net increase in combined cooling duty is about one fifth of the total CO 2 capture plant cooling duty. Table 4-5 reports a total cooling water demand of 57.7 tonnes per tonne of CO 2 for the Benchmark condition; i.e. 1,418 tonnes per hour. In light of the foregoing discussion, the corresponding net increase in cooling water demand for the power station with CO 2 capture would be about one fifth of that; i.e. 284 tonnes per hour per train. 17

28 The amount of make-up water is 2.9% of the cooling water flow. Therefore the additional cooling water make up requirement attributable to the addition of CO 2 capture would be 8.22 tonnes per hour per CO 2 capture train. Table 4-1 shows that the amount of water condensed from the flue gas feed stream under benchmark condition is 36.4 tonnes per hour, which is about four times greater than the additional amount of make-up water required for the cooling system. Therefore the overall water balance for the power station with CO 2 capture would be comfortably in surplus and no additional make-up water for the cooling systems would be required for replenishment in excess of that which is required for the host power station.] 18

29 5.1 Basic Data 5 Economic Evaluation of MEA-Based Capture Process Table 5-1 through Table 5-5 provide the basic data for economic evaluation. The design life of the capture plant is 30 years; Land for plant construction is a building-free cleared industrial site; Various pressurized equipment items and pipelines will be designed and manufactured based on the ASME standards; and All the control systems are the digital control systems with standard configurations. Table 5-1 Capital Cost Evaluation Basis Currency Conversion Rate Project Type Design code User Currency Name User Currency Symbol Description 6.2 CNY/US$ Cleared industrial site ASME Chinese Yuan CNY Table 5-2 Capital Costs Parameters UNITS Value Number of Weeks per Year Weeks/year 52 Number of Years for Analysis Year 20 Working Capital Percentage Percent/year 3 Desired Rate of Return/Interest Rate (ROR) Percent/year 20 ROR Annuity Factor 5 Project Capital Escalation Percent/year 3 Table 5-3 Operating Costs Assumptions UNITS Value Operating Labour (lump-sum) Cost/year 10 Maintenance Charges (lump-sum) Cost/year 10 User Entered Operating Charges (as percentage) Percent/year 15 Operating Charges (Percent of Operating Labor Costs) Percent/year 20 Plant Overhead (Percent of Operating Labor and Maintenance Costs) General and Administrative Expenses (Percent of Subtotal Operating Costs) Percent/year 25 Percent/year 4 19

30 Table 5-4 General Investment Parameters UNITS Value Tax Rate Percent/year 20% Interest Rate Percent/year 20% Economic Life of Project Years 30 Salvage Value (Fraction of Initial Capital Cost) Percent 10% Depreciation Method Straight Line Table 5-5 Escalation UNITS Value Project Capital Escalation Percent/year 3% Products Escalation Percent/year 3% Raw Material Escalation Percent/year 2% Operating and Maintenance Labor Escalation Percent/year 2% Utilities Escalation Percent/year 2% 5.2 Fixed Asset Investment Table 5-6 shows the cost of equipment for a CO 2 capture rate of 90%. The details of equipment specifications are shown in Appendix A. Table 5-6 Cost of equipment units indicated by Aspen Plus million CNY Total Direct Cost Equipment Cost ADSORBER-tower COMPER COMPER COMPER COMPER COOLER COOLER COOLER EXCH FLASH-flash vessel GGH PUMP SEP-flash vessel STRIPPER-reboiler STRIPPER-tower WASHER-flash vessel Total

31 Table 5-7 shows the project capital cost in various scenarios, including an allowance for CO 2 dehydration and compression. Table 5-7 Project capital cost Capital cost of whole plant Capital cost of one train One-for-one scenario Two-on-one scenario One-for-one + two-one-one scenario 329 million 1,316 million 2,631 million 3,946 million [Editorial note The equipment specifications in Appendix A show that almost all of the plant items are specified to operate at significant elevated pressure. Also, Table 5-6 shows that two thirds of the estimated capital cost is attributable to feed gas compressors that could be designed out of the process. Therefore it is likely to be feasible to design a CO 2 capture plant with a substantially lower capital cost than the plant that has been modeled in this study.] 5.3 Operating costs shows the price of utilities and raw materials. Table 5-8 Prices of utilities and raw material Unit Price Steam(selling price) CNY/t 192 Steam(cost price) CNY/t [see note] Electricity CNY/kWh Cooling water make up CNY/t 1.8 Demineralised water CNY/t 6 MEA CNY/kg 30 A local selling price for LP steam is noted in Table 5.8, but it is more reasonable to calculate the steam cost for CO 2 capture on the basis of the lost opportunity cost of converting that steam into electricity in the power station. Generally, 20 tonne of steam can generate 1MWh electricity, that is, one tonne of steam generate 50kWh electricity. Therefore, the cost price of steam is about 26.55CNY/t (Table 5-8). In this chapter, we use this steam price to calculate the steam cost. [Editorial note When steam extraction is integrated with a power station steam cycle, as described in the editorial note in 3.1.1, the amount of energy delivered as heat to the reboiler is about 5 times greater than the amount of energy in the form of electricity product that is lost from the LP turbine in the power station. That corresponds to about 8 tonnes of steam having the value of 1 MWh of electricity, i.e. 1 tonne of steam has the same value as 125 kwh of electricity. On this basis, the lost opportunity cost in the power station of steam extracted for the MEA reboiler is about 66 CNY per tonne of extracted steam.] 21

32 In this simulation, the expense for cooling water is calculated by the model based on cooling water flow, but the actual consumption of circulating cooling water is 2.9% of circulating flow (for details, see section 4.5). Therefore, the price of cooling water actually being input into the model is 2.9% of the raw price listed in the table, i.e. the price of input cooling water is CNY per ton of water circulated. [Editorial note See discussion in Section identifying that no cooling system make-up water is required.] MEA and demineralised ed water costs The main raw materials used in CO 2 capture process are demineralised water and MEA. Their losses have to be made up. The cost of demineralised water is calculated on the basis of its flow rate and price. According to the flow rate of H 2 O component in stream MEAWAT in Table 4-1 and the price of demineralised water shown in, the cost of demineralised water is 3.23CNY/h for one train of the CO 2 capture system. The loss of MEA includes the loss resulting from degradation and a minor loss resulting from entrainment in the discharge steams. In the simulation, the degradation of MEA is not simulated, but the flow rate of MEA components (including MEA and MEA + ) in stream MEAWAT represents the entrainment loss rate of MEA, by mass balance in the Aspen Plus model. The entrainment loss of MEA indicated in the Aspen Plus modeling is therefore kg/tco 2. The main loss of MEA in the CO 2 capture process is its degradation losses caused by oxidative degradation and thermal degradation. Some estimates of these losses are: China Wuhuan Engineering Corporation states that the specific loss of its MEA solvent (MEA loss per tonne of CO 2 captured) is 2.3 kg/tco 2 for the Gaojing pilot plant at a CO 2 capture rate of 90%. The price of its MEA solvent is 20CNY/kg. China Huneng Clean Energy Research Institute states the specific loss of its MEA solvent is 0.7 kg/tco 2 for PCC of NGCC power plant at a CO 2 capture rate of 85%, where the specific degradation loss of its solvent is 0.3 kg/tco 2. Mitsubishi Heavy Industries, Ltd states that the specific degradation loss of its solvent, KS-1, is only 10% of conventional MEA solvent. The price of KS-1 is 40 CNY/kg. [Editorial note - Table 4-1 shows that the NOx content of the feed gas is 12 kg (NO) /h. If each molecule of NOx degrades one molecule of MEA in the presence of oxygen, then the oxidative degradation of MEA would be 24.4 kg/h, i.e. 1 kg/tco 2. Thermal degradation in the reboiler would be additional.] 22