Integrated optimization method of coal and biomass direct-fired power generation negative carbon emission system

Abstract

The invention discloses an integrated optimization method for a coal and biomass direct-fired power generation negative carbon emission system. The method comprises the steps that S1, a whole-process model of the coal and biomass direct-fired power generation negative carbon emission system is built; s2, simulation is carried out based on the operation data of the target power plant; s3, comparing the simulation value of the key operation parameter in the whole-process model in the step S2 with an actual operation value corresponding to the target power plant, so that the relative error of the key operation parameter meets a preset deviation range, and obtaining an adjusted whole-process model; s4, preparing the amine absorbent in the whole process model adjusted in the step S3 into a mixed aqueous solution of amine and monoethanolamine; and S5, performing energy gradient utilization optimization on the whole-flow coupling system. The integrated optimization method integrating heat gradient utilization has flexibility and sustainability of negative carbon emission, the system carbon capture efficiency is higher than 90%, the power generation efficiency loss is smaller than 3%, and the annual negative carbon amount from biomass reaches 10.18 million tons.

Description

TECHNICAL FIELD

[0001] The present application relates to an integrated optimization technology of a coal-biomass direct combustion power generation negative carbon emission system, and belongs to the technical field of negative carbon emission system integration. BACKGROUND

[0002] Global energy consumption demand continues to grow, and the low-carbon transformation of the power sector, as the main body of coal consumption, is crucial. Coal-fired and biomass coupled power generation technology, combined with carbon capture and storage, is considered as one of the potential paths to achieve negative carbon emission of coal-fired power plants and promote deep decarbonization of the energy system. However, this technology path still faces a series of severe challenges in practical application, especially in terms of system energy consumption, economy and overall integrated optimization.

[0003] First, the high energy consumption of the carbon capture subsystem restricts its large-scale application. Traditional carbon capture technologies, such as the absorption method based on monoethanolamine MEA, often come with huge energy consumption penalties when pursuing higher CO2 capture rates, resulting in a significant decrease in power plant efficiency. The power generation efficiency of a typical 600 MW supercritical unit with a traditional carbon capture system installed can be reduced by more than 10%. Although the use of space-hindered amines such as 2-amino-2-methylpropanol AMP is considered to be able to reduce the regeneration energy consumption, how to construct a mixed amine absorbent formula with high capture efficiency and low energy consumption, and quantify its performance in the whole system, is still a problem to be solved.

[0004] Second, the lack of system integration limits the improvement of overall energy efficiency. Existing researches mostly focus on the independent simulation and optimization of single fuel (pure coal) power generation systems or local process units such as carbon capture, lacking a method that considers coal-biomass coupled combustion, steam power cycle, flue gas purification and carbon capture as an organic whole for whole-process modeling and collaborative optimization. This leads to insufficient utilization and recovery of a large amount of low-grade energy such as steam turbine extraction and flue gas waste heat within the system, leaving a huge space for improvement in energy utilization efficiency. For example, how to select the heat source of the carbon capture reboiler from the steam turbine extraction, and how to select the backflow position of the heat transfer medium to minimize the work capacity loss, all lack systematic optimization strategies.

[0005] Finally, the limitations of existing simulation methods make it difficult to support rapid and accurate system design and operation optimization. Traditional experimental research and simplified theoretical calculation cannot fully and accurately reveal the transfer and transformation rules of multiple energy flows and multiple materials in complex coupled systems, and cannot provide low-cost and high-efficiency technical support for quickly finding the optimal operating conditions and system design parameters.

[0006] Therefore, there is an urgent need in the art for an integrated optimization method that can comprehensively solve the above problems, i.e., significantly reducing system energy consumption while ensuring high carbon capture rate, and establishing an accurate full-process model to provide reliable tools for engineering practice. SUMMARY

[0007] To solve the above technical problems, the present application provides an integrated optimization method for a coal and biomass direct-fired power generation negative carbon emission system, provides a mixed amine formula and adopts a steam heat exchange optimization method with tail flue gas heat recovery, integrates the flexibility of heat cascade utilization and the sustainability of negative carbon emission, the carbon capture efficiency of the new system is higher than 90%, the power generation efficiency loss is less than 3%, and the annual negative carbon amount from biomass reaches 101800 tons.

[0008] To achieve the above purpose, the present application adopts the following technical solutions:

[0009] An integrated optimization method for a coal and biomass direct-fired power generation negative carbon emission system, comprising the following steps:

[0010] S1, building a full-process model of the coal and biomass direct-fired power generation negative carbon emission system, the full-process model at least integrates modeling of the boiler, steam power generation, flue gas treatment, carbon capture and heat recovery subsystems;

[0011] S2, based on the operation data of the target power plant, simulating the full-process model built in step S1;

[0012] S3, comparing the simulation values of the key operating parameters in the full-process model obtained in step S2 with the actual operating values corresponding to the target power plant, and adjusting the operating unit parameters in the model according to the comparison results, so that the relative error between the simulation values and the actual values of the key operating parameters satisfies the preset deviation range, to obtain an adjusted full-process model; the key operating parameters at least include the boiler combustion efficiency, the unit power generation power and the NO, SO2 emission amount;

[0013] S4, configuring the amine absorbent of the carbon capture subsystem in the full-process model adjusted in step S3 as a mixed aqueous solution of amine with steric hindrance structure and monoethanolamine;

[0014] S5, energy cascade utilization optimization is adopted for the full-process coupled system, including regeneration extraction point optimization, regeneration extraction backflow position optimization and tail flue gas heat recovery optimization of the system;

[0015] The regeneration extraction point optimization: from the multi-stage regeneration extraction of the steam power generation subsystem, a regeneration extraction point with steam quality that can meet the heat source demand of the carbon capture subsystem reboiler and energy level higher than the reboiler demand is selected to provide heat source for the reboiler of the carbon capture subsystem;

[0016] Regeneration steam extraction return position optimization: the condensate formed after the regeneration extraction point extraction of the regeneration extraction steam exchanges heat with the regenerator, and returns to the deaerator in the steam power generation subsystem;

[0017] Tail flue gas heat recovery optimization: a heat recovery link is arranged between the dust remover outlet of the flue gas treatment subsystem and the desulfurization tower inlet, and the tail flue gas waste heat is recovered to heat the condensate in the steam power generation subsystem, so as to reduce the temperature of the tail flue gas to below 60℃.

[0018] Beneficial effects: The present application builds a model of a coal-biomass co-fired direct-fired power generation coupled carbon capture system, and breaks through the limitation of traditional coal-fired power plant process simulation research which only aims at single fuel heat production and power supply and subsystem process simulation. The model of the carbon capture subsystem with mixed amine absorbent formula and the proposed heat recovery subsystem model can simulate and optimize the coal-biomass co-fired direct-fired power generation coupled carbon capture system. Among them, the amine and monoethanolamine MEA mixed amine absorbent with steric hindrance structure makes the carbon capture rate of the carbon capture subsystem not less than 90%, and the power generation efficiency loss of the whole process model after combining the heat recovery subsystem is about 3%, and the flue gas pollutant emission concentration meets the ultra-low emission standard, so the model has high accuracy.

[0019] In addition, the heat recovery subsystem model fully embodies the principle of energy cascade utilization: a) the power consumption of the regeneration extraction steam is reduced due to the lower steam quality; b) the regeneration extraction steam returns to the deaerator, effectively recovering the steam heat energy of the four low-pressure heaters to supply the low-pressure cylinder of the steam turbine; c) the boiler tail flue gas heats the condensate, and the condensate cools the waste heat generated by the flue gas treatment system, reducing the extraction heat recovery of each stage of the steam turbine. Co-firing of biomass and coupling of the carbon capture system is conducive to the realization of sustainable negative carbon emissions. The present application integrates the flexibility of heat cascade utilization and the sustainability of negative carbon emissions, and can co-fire 10% of biomass under the condition of meeting constant total heat input, the power generation efficiency loss of the new system is less than 3%, and the annual negative carbon amount from the biomass reaches 101800 tons.

[0020] As a further preferred embodiment of the above-mentioned optimization method of the present application, in step S1, the model of the heat recovery subsystem is configured to include:

[0021] A first heat exchanger, the inlet of its stream stock is connected with the regeneration extraction point in the steam power generation subsystem, the outlet of its stream stock is connected with the inlet of the deaerator, and the heat flow stock thereof forms a heat exchange flow path with the regenerator in the carbon capture subsystem;

[0022] A second heat exchanger arranged in the condensate loop of the steam power generation subsystem;

[0023] a third heat exchanger arranged in a flue between an outlet of a dust remover of the flue gas treatment subsystem and an inlet of a desulfurization tower, and forming a heat exchange flow path with the second heat exchanger;

[0024] a flow divider arranged on a cold end outlet pipeline of the second low-pressure heater, and used for dividing the condensed water into the second heat exchanger and the third low-pressure heater;

[0025] a mixer, an inlet of which is connected with an outlet of the second heat exchanger and an outlet of the fourth low-pressure heater respectively, and an outlet of which is connected with an inlet of the deaerator;

[0026] modeling heat exchange between the reheat steam of the regeneration extraction steam point and a reboiler in the carbon capture subsystem model in the first heat exchanger;

[0027] returning the steam at the outlet of the first heat exchanger to the deaerator in the steam power generation subsystem model;

[0028] modeling heat exchange between the tail flue gas model from the outlet of the dust remover in the flue gas treatment subsystem model and the subsystem condensed water model from the second low-pressure heater in the steam power generation subsystem model flowing through the second heat exchanger in the third heat exchanger.

[0029] As a further preferred embodiment of the above-mentioned optimization method, in step S3, the key operating parameters at least include the boiler combustion efficiency, the unit power generation capacity and the NO and SO2 emission amounts.

[0030] Beneficial effects: ensure that the unit meets the power generation capacity, at the same time, grasp the fuel consumption required for unit power generation, and ensure that the gaseous pollutants meet the ultra-low emission standard during the operation of the unit.

[0031] As a further preferred embodiment of the above-mentioned optimization method, in step S4, the mixed aqueous solution is an amine and monoethanolamine mixed aqueous solution meeting the carbon capture efficiency and capture heat consumption requirements.

[0032] Beneficial effects: compared with a single MEA absorbent, the amine with a steric hindrance structure mixed with MEA makes the carbon capture efficiency not less than 90%, and the carbon capture heat consumption is 3.5-3.6 GJ / t CO2.

[0033] As a further preferred embodiment of the above-mentioned optimization method, in step S5, the selection of the regeneration extraction steam point meets the following three conditions at the same time:

[0034] A) The temperature of the regeneration extraction steam point is higher than the required temperature of the reboiler by 9-12℃ to meet the heat exchange requirements;

[0035] B) the pressure of the regeneration extraction point is higher than the saturated steam pressure corresponding to the temperature, to meet the pressure requirement for steam condensation;

[0036] C) the flow rate of the regeneration extraction point meets the heat load requirement of the reboiler, to meet the CO2 desorption energy requirement.

[0037] As a further preferred embodiment of the above-mentioned optimization method of the present application, in step S5, the temperature of the condensed water flowing back to the deaerator differs from the working temperature of the deaerator by 10-12°C, to avoid heat waste and increased condensation load caused by the direct flow of the high-temperature condensed water back to the condenser after heat exchange.

[0038] As a further preferred embodiment of the above-mentioned optimization method of the present application, in step S5, the system power generation efficiency loss of the optimized full-process coupled system is less than 3%.

[0039] As a further preferred embodiment of the above-mentioned optimization method of the present application, in step S2, the operation data includes fuel characteristic parameters of the biomass and the coal, the energy blending ratio of the biomass is 5-15%, and the annual negative carbon amount derived from the biomass is higher than 100,000 tons.

[0040] As a further preferred embodiment of the above-mentioned optimization method of the present application, in step S3, the preset deviation range is within 3%. BRIEF DESCRIPTION OF DRAWINGS

[0041] Figure 1 FIG. 1 is a schematic diagram of the connection structure of a coal / biomass direct combustion power generation coupled carbon capture system;

[0042] Wherein: I is a boiler subsystem, II is a steam power generation subsystem, III is a flue gas treatment subsystem, IV is a carbon capture subsystem, and V is a heat recovery subsystem; 1-1 and 1-2 are crushers for coal and biomass respectively, 1-3 is a blower, 1-4 is a preheater, 1-5 is a cracking and combustion reactor, 1-6 is a platen superheater, 1-7 is a final stage superheater, 1-8 is a high temperature reheater, 1-9 is a low temperature superheater, 1-10 is a low temperature reheater, and 1-11 is an economizer; 2-1 is a high pressure cylinder, 2-2 is a medium pressure cylinder, 2-3 is a low pressure cylinder, 2-5 is a generator, 2-6 is a condenser, 2-7 is a condensate pump, 2-8 is a deaerator, 2-9 is a feed water pump, 2-10 is a first low pressure heater, 2-11 is a second low pressure heater, 2-12 is a third low pressure heater, 2-13 is a fourth low pressure heater, 2-14 is a first high pressure heater, 2-15 is a second high pressure heater, and 2-16 is a third high pressure heater; 3-1 is a denitration reactor, 3-2 is a dust remover, 3-3 is a desulfurization tower, and 3-4 is an induced draft fan; 4-1 is an absorption tower, 4-2 is a rich liquid pump, 4-3 is a heat exchanger, 4-4 is a reboiler, 4-5 is a desorption tower, 4-6 is a condenser, and 4-7 is a mixed amine feeder; 5-1 is a first heat exchanger, 5-2 is a second heat exchanger, 5-3 is a third heat exchanger, 5-4 is a flow divider, and 5-5 is a mixer;

[0043] Figure 2 A comparison chart of net efficiency of an existing coupling system and an optimized coupling carbon capture system;

[0044] Figure 3 A chart showing annual biomass-derived negative carbon amount in an optimized coupling carbon capture system as a function of biomass energy blending ratio. DETAILED DESCRIPTION

[0045] The technical solutions of the present application will be further described in detail below with reference to specific embodiments and the accompanying drawings.

[0046] An integrated optimization method of a coal and biomass direct combustion power generation negative carbon emission system, comprising the following steps:

[0047] S1, building a full process model of a coal-fired biomass blending direct combustion power generation coupling carbon capture system;

[0048] Figure 1 A connection diagram of the present application and a specific coal / biomass direct combustion power generation coupling carbon capture system, which comprises a boiler subsystem I, a steam power generation subsystem II, a flue gas treatment subsystem III, a carbon capture subsystem IV, and a heat recovery subsystem V; the steam outlet and the feed water inlet of the boiler subsystem I are connected with the inlet end and the outlet end of the steam power generation subsystem II, and the inlet flue gas and the outlet desulfurized flue gas of the flue gas treatment subsystem III are connected with the outlet end of the boiler subsystem I and the inlet end of the carbon capture system IV respectively.

[0049] The general way of implementing the model, using the Aspen Plus V14 simulation software;

[0050] The process flow also includes a chemical reaction module, a calculator module, and a design specification module, wherein the chemical reaction module is used to simulate and analyze various chemical reactions in the chemical process; the calculator module is used to control the calculation process of each operation module; the design specification module is used to adjust a certain variable to obtain the target value range;

[0051] The boiler subsystem I is used to simulate the pulverized coal furnace equipment, wherein the cracking and combustion reactors 1-5 are controlled by the above-mentioned calculator module; the primary / secondary air ratio is preset to be 0.1-0.5; the mechanical efficiency and pressure increase of the air supply fan 1-4 are respectively preset to be 0.9-0.99 and 0.01 MPa;

[0052] The steam power generation subsystem II is used to simulate the steam expansion power generation equipment in the turbine; wherein the isentropic efficiency of the high-pressure cylinder 2-1, the medium-pressure cylinder 2-2, and the low-pressure cylinder 2-3 is preset to be 0.7-0.9, the split ratio of the steam extraction is preset to be 0.001-1, and is controlled by the above-mentioned design specification module; the heat exchange temperature difference of the multiple high-pressure heaters and the multiple low-pressure heaters is preset to be 4-7℃; the pressure of the condensate pump 2-7 is preset to be 1-5-2.0 MPa;

[0053] The flue gas treatment subsystem III is used to simulate the flue gas denitration, dust removal, and desulfurization processes; wherein the denitration reactor 3-1 is used to simulate the process of absorbing NO by NH3; the dust remover 3-2 is used to simulate the gas-solid separation process; the desulfurization tower 3-3 is used to simulate the absorption reaction and oxidation reaction of SO2 in the flue gas; the absorption reaction refers to the reaction of SO2 in the flue gas dissolving in water and reacting with continuously injected limestone slurry to generate calcium sulfite CaSO3, and the oxidation reaction refers to the oxidation of the slurry by air blowing and the conversion to calcium sulfate CaSO4; the calcium sulfate slurry is discharged from the bottom of the desulfurization tower, and the flue gas after desulfurization is sent to the next purification system;

[0054] Wherein the catalyst bed void fraction and particle density of the denitration reactor 3-1 are respectively preset to be 0.3-0.7 and 1000-3000 kg / m 3 , and the denitration process is analyzed by the above-mentioned chemical reaction module of NH3 absorbing NO; the split ratio of the non-conventional component stream of the dust remover 3-2 is preset to be 0.999; the reaction temperature of the desulfurization tower 3-3 is preset to be 50-60℃, and the desulfurization process is analyzed by the above-mentioned chemical reaction module of the absorption reaction and oxidation reaction of SO2;

[0055] The carbon capture subsystem IV is used for simulating the CO2 absorption process and the desorption process in the flue gas; wherein, the absorption tower 4-1 is used for simulating the CO2 absorption process of the mixed amine solution of AMP and MEA; the desorption tower 4-5 is used for simulating the CO2 desorption process of the mixed amine solution;

[0056] Wherein, the tray number of the absorption tower 4-1 is preset to be 10-15, and the CO2 capture rate is preset to be 0.9 by the above design specification module; the tray number of the desorption tower 4-5 is also preset to be 10-15, and the pressure is preset to be 160-220 kPa; the effluent flow rate range is preset to be 5-30 kg / s, and the reflux ratio is preset to be 0.1-1 by the above design specification, and the carbon capture process is analyzed by the chemical reaction of the mixed amine solution absorption and desorption CO2; the heat exchange temperature difference of the heat exchanger 4-3 is preset to be 3-10℃;

[0057] S2 simulates and verifies based on the operation data of the target power plant:

[0058] The operation data includes the feed stream type and the feed stream process parameters; wherein, the feed stream type includes coal, biomass, air, feed water, reheat steam, NH3, CaCO3 and mixed amine absorbent; the feed stream process parameters include temperature, pressure, mass flow, molar flow and component fraction;

[0059] S3 CO2 amine absorbent formula parameter determination:

[0060] The mixed amine absorbent of AMP and MEA which is beneficial to desorption and reduces the regeneration energy consumption is selected to replace the MEA reference amine absorbent, the carbon capture efficiency meets not less than 90%, and the carbon capture heat consumption is 3.5 to 3.6 GJ / t CO2;

[0061] S4 uses energy cascade utilization optimization for the whole process coupling system, including regeneration extraction steam point optimization, regeneration extraction steam reflux position optimization and tail flue gas heat recovery optimization;

[0062] The regeneration extraction steam point optimization includes selection from eight regeneration extraction steam points according to the reboiler conditions and extraction steam site conditions in the carbon capture subsystem; the extraction site needs to meet the following three conditions at the same time:

[0063] A) The temperature of the regeneration extraction steam point is higher than the heat exchange temperature difference of 9-12℃ of the reboiler temperature, so as to meet the heat exchange demand;

[0064] B) The flow rate of the regeneration extraction steam point meets the heat load demand of the reboiler, so as to meet the CO2 desorption energy demand;

[0065] C) The pressure of the extraction site is greater than the saturation vapor pressure corresponding to the set heat exchange temperature difference of the reboiler temperature, so as to meet the pressure demand required for steam condensation;

[0066] The eight-stage regenerative extraction steam meets the above extraction point, and the steam quality gradually decreases as the steam acts in the steam turbine, so the power consumption of the regenerative extraction steam site greater than 5# is greater, and the 5# regenerative extraction steam site is preferred;

[0067] The prior art of the same type of 600MW coal-fired unit coupled with a carbon capture system adopts a 4-stage extraction steam and a carbon capture reboiler heat exchange mode, and the 5-stage regenerative extraction steam adopted in the present application reduces power consumption due to lower steam quality, and the regenerative extraction steam returns to the deaerator, effectively recovering the steam heat energy of the four low-pressure heaters to provide power to the low-pressure cylinder of the steam turbine, cooperating with the boiler dust removal, heating the condensate water, promoting the waste heat generated by the condensate water cooling flue gas treatment system, and further reducing the extraction heat recovery of each stage of the steam turbine.

[0068] The regenerative extraction steam return position optimization includes the preferred return of the regenerative extraction steam and the carbon capture system to the condenser and the deaerator according to the condensate temperature conditions after heat exchange in the first heat exchanger 5-1, and the selection of the deaerator with similar temperature in the steam power generation system to effectively recover the steam heat energy of the four low-pressure heaters to provide power to the low-pressure cylinder, avoiding the waste of heat and the increase of condensing load caused by the direct return of the high-temperature condensate to the condenser after heat exchange;

[0069] The tail flue gas heat recovery optimization includes adding a heat exchanger for heat recovery according to the dust remover flue gas temperature condition and the desulfurization tower flue gas latent heat release condition, and the low-pressure heater cold end water temperature condition and the deaerator inlet water temperature condition, and based on the preferred 5# regenerative extraction steam site and the return of the regenerative extraction steam to the deaerator, a third heat exchanger 5-3 is added at the dust removal outlet and the desulfurization inlet to recover the waste heat of the flue gas after dust removal and the latent heat of the flue gas of the desulfurization tower, and the recovered heat is used to heat half of the condensate water in the low-pressure heater 2-11 with similar flue gas temperature in the newly added second heat exchanger 5-2, and the condensate water in the low-pressure heater 2-13 is mixed in the mixer 5-5 and then sent to the deaerator 5-8 with similar inlet water temperature.

[0070] Embodiment:

[0071] S1, build a full-flow model of a coal and biomass direct-fired power generation negative carbon emission system, including a boiler subsystem I, a steam power generation subsystem II, a flue gas treatment subsystem III, a carbon capture subsystem IV, and a heat recovery subsystem V.

[0072] S2, based on the operation data of a certain 600MW supercritical coal-fired power plant, simulate the full-flow model built in step S1, wherein the received base parameters of the fuel are as shown in Table 1.

[0073]

[0074] Table 2 Comparison of simulation results and design values of boiler subsystem and steam power generation subsystem

[0075] Name Setting value Simulation result Relative error / % Boiler combustion temperature (℃) 1409.00 1409.00 0.00 Main steam outlet temperature (℃) 571.00 570.00 0.18 Reheated steam outlet temperature (℃) 569.00 569.00 0.00 Reheated steam inlet temperature (℃) 311.00 318.00 2.25 Low-temperature superheater flue gas outlet temperature (℃) 488.00 488.00 0.00 Low-temperature reheater flue gas outlet temperature (℃) 372.00 379.00 1.88 Flue gas discharge temperature (℃) 127.00 128.00 0.79 Boiler efficiency (%) 94.40 94.90 0.53 2-16 Heater temperature (℃) 283.00 279.00 1.41 2-15 Heater temperature (℃) 249.20 249.00 0.08 2-14 Heater temperature (℃) 206.40 206.00 0.19 2-13 Heater temperature (℃) 138.20 138.00 0.14 2-12 Heater temperature (℃) 100.30 100.00 0.30 2-11 Heater temperature (℃) 81.30 81.00 0.37 2-10 Heater temperature (℃) 54.80 55.00 0.36 Unit gross power generation (MWe) 600.00 608.14 1.36

[0076] Table 3 Comparison of simulation results and design values of flue gas treatment subsystem and carbon capture subsystem

[0077] Name mg / m 3 ]] Removal rate% Design value% Relative error / % NO 48.33 97.12 97.12 2.70 SO2 34.37 96.93 96.93 1.99 CO2 / 91.00 90.00 1.11

[0078] S3, compare the data results calculated by the model in step S1 with the design results. The comparison results are shown in Tables 2 and 3. The design values and simulation values of the boiler subsystem and the steam power generation subsystem, wherein the relative error of the reheated steam inlet temperature is up to 2.25%, and the relative error of all other values is within 2%, to verify the rationality of the model. According to the ultra-low emission standard in coal-fired power plants, the emission limits of NOx and SO2 are 50 mg / m 3 and 35 mg / m 3 , respectively. In the given conditions, the removal rates of NO and SO2 in the present model can reach more than 96%, and the emission concentrations of NO and SO2 at the chimney outlet are 48.33 mg / m 3 and 34.37 mg / m 3 , respectively, both of which meet the ultra-low emission standard, and the relative errors of all other values are kept within 3%, which further verifies the accuracy of the designed model.

[0079] S4: Determination of CO2 amine absorbent formula parameters: As shown in Table 4, the mixed amine absorbent of AMP and MEA with steric hindrance is used in the present case, and a mixed aqueous solution of 12 wt% AMP and 18 wt% MEA is input into the carbon capture subsystem according to the preferred ratio, and the obtained carbon capture efficiency is 91% and the carbon capture heat consumption is 3.51 GJ / t CO2.

[0080] Table 4 Effect of different proportions of mixed amines on the carbon capture subsystem

[0081] AMP / MEA / wt% 0 / 30 4 / 28 8 / 22 12 / 18 16 / 14 Capture efficiency / % 80 90 90 91 91 Capture heat consumption / GJ / t CO2 4.83 3.62 3.56 3.51 3.54

[0082] S5: Optimization of Regeneration Extraction Points: In this case, the reboiler temperature and flow rate in the carbon capture subsystem are 121.94℃ and 37460.23 kmol / h, respectively. Based on a 10℃ heat exchange temperature difference, the extraction point should meet the requirements of a temperature higher than 131.94℃ and a flow rate higher than 37460.23 kmol / h, and the pressure at the extraction point should be greater than the 0.29 MPa saturated vapor pressure corresponding to steam at 131.94℃. In the simulation system, among the eight-stage regeneration, at least 5# regeneration extraction points meet the above requirements. Considering that steam quality gradually decreases as the steam acts in the turbine, taking the 4# and 5# regeneration extraction points, both of which are returned to the condenser, as an example, the net power generation efficiency losses of the 4# and 5# regeneration extraction points compared to the uncoupled carbon capture system are 4.09% and 3.33%, respectively. The 4# regeneration extraction point requires greater power consumption, therefore the 5# regeneration extraction point is preferred.

[0083] Table 5. Impact of different optimization methods on the net power generation efficiency of the system

[0084] Optimization mode Net power generation efficiency / % No coupled carbon capture 40.17 4# Regenerative extraction steam + backflow to condenser 36.08 5# Regenerative extraction steam + backflow to condenser 36.84 5# Regenerative extraction steam + backflow to deaerator 37.10 5# Regenerative extraction steam + backflow to deaerator + tail flue gas heat recovery 37.68

[0085] Optimization of the regenerated steam return location: In this case, the condenser and deaerator temperatures in the steam power generation system are 29℃ and 138℃, respectively. After the regenerated steam at 131.94℃ exchanges heat with the reboiler of the carbon capture system's stripping tower in heat exchanger 5-1, the regenerated steam is converted into condensate at 131.94℃. This condensate is then returned to the deaerator in the steam power generation system at a similar temperature, effectively recovering the steam heat energy from the four low-pressure heaters to power the low-pressure cylinder. This avoids heat waste and increased condensation load caused by the high-temperature condensate directly returning to the condenser after heat exchange. As a result, the net power generation efficiency increases to 37.10%.

[0086] Optimization of flue gas heat recovery: In this case, the flue gas temperature at the dust collector outlet is 127℃, and more than 70% of the heat energy of the flue gas in the desulfurization tower is released through the latent heat of water vapor. By adding a third heat exchanger 5-3 at the dust collector outlet and the desulfurization inlet, the flue gas temperature is reduced to 60℃, recovering the waste heat of the flue gas after dust removal and the latent heat of the flue gas in the desulfurization tower. The recovered heat is used in the newly added heat exchanger 5-2 to heat half of the condensate in the second low-pressure heater 2-11 with a cold end outlet water temperature of 55℃. The condensate in the third low-pressure heater 2-13 flows together to the mixer 5-5 and then into the deaerator 5-8 with an inlet water temperature of 138℃. At this time, the net power generation efficiency is further increased to 37.68%.

[0087] After following the above steps, if Figure 2 As shown, the net efficiency loss of the existing unoptimized unit system of the same type is 12.27%, while the net efficiency loss of the new coupled system is only 2.49% smaller than that of the uncoupled carbon capture system.

[0088] As Figure 3 shown, simulation experiments were carried out on the optimization system of the application according to corn energy blending ratios of 5%, 7.5%, 10%, 12.5% and 15%, and the annual negative carbon amount from biomass reached 101.8 million tons when the blending ratio was 10%.

[0089] In summary, the model of the coal-biomass direct-fired power generation coupled carbon capture system is built, and the whole process simulation of the coal-biomass direct-fired power generation coupled carbon capture system is carried out, which breaks through the limitation of the traditional coal-fired power plant process simulation research which only aims at single fuel heat production and power supply and subsystem process simulation. The carbon capture subsystem with mixed amine absorbent formula and the proposed heat recovery subsystem model can simulate and optimize the coal-biomass direct-fired power generation coupled carbon capture system. Among them, the amine and monoethanolamine MEA mixed amine absorbent with steric hindrance structure makes the carbon capture rate of the carbon capture subsystem not less than 90%, and the power generation efficiency loss of the whole process model after combining the heat recovery subsystem is about 3%, and the concentration of flue gas pollutants meets the ultra-low emission standard, so the model has high accuracy.

[0090] In addition, the heat recovery subsystem model proposed by the application fully embodies the principle of energy cascade utilization:

[0091] a) The power consumption of the regenerated extraction steam is reduced due to the lower steam quality;

[0092] b) The regenerated extraction steam flows back to the deaerator, effectively recovering the steam heat energy of the four low-pressure heaters to supply the low-pressure cylinder of the steam turbine;

[0093] c) The boiler tail flue gas heats the condensate water, and the waste heat generated by the condensate water cooling flue gas treatment system reduces the extraction backheat of each stage of the steam turbine.

[0094] Blending biomass and coupling carbon capture system is conducive to realizing the sustainability of negative carbon emission. The application integrates the flexibility of heat cascade utilization and the sustainability of negative carbon emission, and can blend 10% of biomass under the condition of meeting constant total heat input, the power generation efficiency loss of the new system is less than 3%, and the annual negative carbon amount from biomass reaches 101.8 million tons.

[0095] The above is only the preferred embodiment of the application, it should be noted that for ordinary skilled in the art, without departing from the principles of the application, can make several improvements and refinements, these improvements and refinements should be considered as the protection scope of the application.

Claims

1. An integrated optimization method for a coal and biomass direct combustion power generation negative carbon emission system, characterized in that, Includes the following steps: S1. Build a full-process model of a coal and biomass direct combustion power generation negative carbon emission system. The full-process model shall integrate and model at least the boiler subsystem, steam power generation system, flue gas treatment subsystem, carbon capture subsystem and heat recovery subsystem. S2. Based on the operating data of the target power plant, simulate the full-process model built in step S1; S3. Compare the simulated values ​​of key operating parameters in the full-process model described in step S2 with the actual operating values ​​corresponding to the target power plant. Adjust the operating unit parameters in the full-process model according to the comparison results so that the relative error between the simulated and actual values ​​of the key operating parameters meets the preset deviation range. S4. Based on the full-process model in step S3, the amine absorbent of the carbon capture subsystem is configured as a mixed aqueous solution of amine and monoethanolamine with a sterically hindered structure. S5. Energy cascade utilization optimization is adopted for the entire process coupled system, including optimization of the system's regeneration steam extraction point, optimization of the regeneration steam extraction return location, and optimization of tail gas heat recovery. Among them, the optimization of the regeneration extraction point is as follows: from the multi-stage regeneration extraction of the steam power generation system, a regeneration extraction point with steam quality that can meet the heat source requirements of the reboiler of the carbon capture subsystem and with an energy level higher than the requirements of the reboiler is selected to provide a heat source for the reboiler of the carbon capture system. Optimization of the regeneration extraction steam return location: The condensate formed after the regeneration extraction steam extracted from the regeneration extraction point exchanges heat with the reboiler is returned to the deaerator in the steam power generator system. Optimization of flue gas heat recovery: A heat recovery link is set between the dust collector outlet and the desulfurization tower inlet of the flue gas treatment subsystem to recover the waste heat of the flue gas for heating the condensate in the steam power generator system, so as to reduce the temperature of the flue gas to below 60°C.

2. The integrated optimization method for a negative carbon emission system for direct combustion power generation of coal and biomass as described in claim 1, characterized in that, In step S1, the model of the heat recovery subsystem is configured to include: The first heat exchanger has its inlet connected to the regeneration extraction point in the steam power generation system, its outlet connected to the inlet of the deaerator, and its heat flow stream forming a heat exchange path with the reboiler in the carbon capture subsystem. The second heat exchanger is installed in the condensate circuit of the steam power generator system; The third heat exchanger is located in the flue between the dust collector outlet and the desulfurization tower inlet of the flue gas treatment subsystem, and forms a heat exchange flow path with the second heat exchanger. A distributor is installed on the cold end outlet pipe of the second low-pressure heater to divert condensate to the second heat exchanger and the third low-pressure heater in the steam power generation system. The mixer's inlet is connected to the outlet of the second heat exchanger and the outlet of the fourth low-pressure heater in the steam power generator system, and its outlet is connected to the inlet of the deaerator. The heat exchange model is performed between the reheated steam at the regeneration extraction point and the reboiler in the carbon capture subsystem model in the first heat exchanger of the heat recovery subsystem. The steam at the outlet of the first heat exchanger is returned to the deaerator in the steam power generator system model; The tail gas model from the dust collector outlet in the flue gas treatment subsystem model is used to model heat exchange with the condensate model from the second low-pressure heater in the steam power generation subsystem model, which flows through the second heat exchanger, in the third heat exchanger.

3. The integrated optimization method for a negative carbon emission system for direct combustion power generation of coal and biomass as described in claim 1, characterized in that, In step S3, the key operating parameters include at least boiler combustion efficiency, unit power generation, and NO and SO2 emissions.

4. The integrated optimization method for a negative carbon emission system for direct combustion power generation of coal and biomass as described in claim 1, characterized in that, In step S4, the mixed aqueous solution is a mixed aqueous solution of amine and monoethanolamine that meets the requirements of carbon capture efficiency and capture heat consumption.

5. The integrated optimization method for a negative carbon emission system for direct combustion power generation of coal and biomass as described in claim 2, characterized in that, In step S5, the selection of the regeneration extraction point simultaneously satisfies the following three conditions: A) The temperature at the regeneration extraction point is 9°C to 12°C higher than the required temperature of the reboiler; B) The pressure at the regeneration extraction point is higher than the saturated vapor pressure corresponding to the temperature of the regeneration extraction point; C) The flow rate at the regeneration extraction point meets the heat load requirements of the reboiler.

6. The integrated optimization method for a negative carbon emission system for direct combustion power generation of coal and biomass as described in claim 1 or 2, characterized in that, In step S5, the temperature of the condensate returned to the deaerator is 10°C to 12°C different from the operating temperature of the deaerator, so as to avoid heat waste and increased condensation load caused by the condensate with a higher temperature after heat exchange being directly returned to the condenser.

7. The integrated optimization method for a negative carbon emission system for direct combustion power generation of coal and biomass as described in claim 1, characterized in that, In step S2, the operating data includes fuel characteristic parameters of biomass and coal, the energy blending ratio of biomass is 5% to 15%, and the annual negative carbon content from biomass is higher than 100,000 tons.

8. The integrated optimization method for a negative carbon emission system for direct combustion power generation of coal and biomass as described in claim 1, characterized in that, In step S3, the preset deviation range is within 3%.

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