Method for optimizing coordinated control system of coal-fired power generating unit

Abstract

The invention relates to an optimization method for a coordinated control system of a coal-fired power generation unit. The optimization method comprises the following steps: step 01, coordinating an AGC control system; 02, optimizing a primary frequency modulation control system; and 03, flow curves of the DEH high-adjusting valve and the gulp valve are optimized. The control system has the beneficial effects that the control system is optimized, a supercritical unit control strategy improved in a large range is adopted, and the operation mode that an original coal mill hot air adjusting baffle is fully opened is reserved; the boiler load response sensitivity is greatly excavated in the aspects of water supply, powder preparation, combustion and boiler pressure energy storage, and a relatively balanced optimization effect is finally obtained in the aspect of comprehensive indexes of stability, economical efficiency and rapid sensitivity.

Description

Technical Field

[0001] This invention relates to the field of coal-fired power generation technology, and in particular to an optimization method for a coordinated control system of a coal-fired power generation unit. Background Technology

[0002] The original design philosophy of medium-speed direct-fired pulverizing supercritical coal-fired generator units with double high-pressure regulating valves and double supplementary steam valves was to reduce turbine throttling losses. The boiler operation also prioritized energy conservation; therefore, for many years, the coal mill hot air regulating damper has been operated in a fully open state. Although control strategies have undergone various optimizations, they have all focused on parameter stability while prioritizing energy conservation, without deeply exploring the multiple stages of pulverization, combustion, and power generation, and without considering the speed and sensitivity of AGC (Automatic Generation Control) power generation. Consequently, although these units have achieved excellent energy-saving indicators in actual operation over the years, they have consistently suffered significant economic losses in terms of AGC primary frequency regulation. Summary of the Invention

[0003] The purpose of this invention is to provide an optimization method for the coordinated control system of a coal-fired power generation unit, thereby solving the aforementioned problems in the prior art.

[0004] The technical solution of the present invention to solve the above-mentioned technical problems is as follows: An optimization method for a coordinated control system of a coal-fired power generating unit includes the following steps: Step 01: Coordinate the AGC (Automatic Generation Control) system: including 1.1 Optimize the main steam pressure setting system: Adjust the main steam pressure rise and fall rate and deviation; 1.2 Optimize the turbine main control system: Modify the load control loop of the turbine main control system; 1.3 Optimize the boiler main control system: Optimize the generation of coal feed rate setpoints and water flow rate setpoints for the boiler main control commands; 1.4 Optimize the intermediate point temperature and feedwater control system: Based on the boiler intermediate point setpoint, generate an overheat correction coefficient for the water flow setpoint; 1.5 Optimize the fuel control system: The final coal feeding instructions for each coal feeder are generated from the boiler control instructions; 1.6 Optimize the coal mill hot air system: Generate the primary air flow rate setpoint based on the final coal feeding instruction; 1.7 Optimize the coal mill cooling system; generate primary air flow rate setpoints based on the final coal feeding command; 1.8 Optimize the primary air pressure control system: Generate primary air pressure setpoints based on fuel master control setpoints; 1.9 Optimize supply air oxygen control; 1.10 Optimize the boiler main and reheat steam temperature control system: Optimize control parameters on-site; Step 02: Optimize the primary frequency regulation control system; Step 03: Optimize the flow curves of the high-pressure regulating valve and the air supply valve in the DEH (Digital Electro-hydraulic Control System for Steam Turbines).

[0005] The beneficial effects of this invention are: the optimized control system, through a widely improved supercritical unit control strategy, retains the original operation mode of fully opening the hot air regulating damper of the coal mill, and significantly improves the boiler load response sensitivity in terms of water supply, pulverization, combustion, and boiler pressure energy storage; ultimately achieving a relatively balanced optimization effect in terms of stability, economy, and rapid sensitivity.

[0006] Based on the above technical solution, the present invention can be further improved as follows.

[0007] Furthermore, 1.1 Optimizing the main steam pressure setting system specifically includes: during the load increase process, slowing down the rise and fall of the main steam pressure setting value, reducing the main steam pressure deviation based on the boiler feedforward control results, and reducing the attenuation rate regulation effect of the boiler PID (proportional-integral-derivative control algorithm) regulator; slowing down the change of the pressure setting value when the unit is running in the range of low load and high load; and accelerating the change of the pressure setting value in the intermediate load operating range.

[0008] The further beneficial effects of adopting the above are: to prevent or slow down the change of main steam pressure, which would lead to a slow rise in main steam pressure and full opening of the DEH high-pressure valve when the load increases, or a slow drop in main steam pressure and excessively small opening of the main steam valve when the load decreases.

[0009] Furthermore, 1.2 Optimizing the turbine main control system specifically includes modifying the load control loop of the turbine main control system, including the setpoint system and the feedforward system.

[0010] The further beneficial effect of adopting the above is to improve the load response time index value in the AGC load response quality of the unit. Attached Figure Description

[0011] Figure 1 This is a flowchart of an optimization method for a coordinated control system of a coal-fired power generation unit according to the present invention. Detailed Implementation

[0012] The principles and features of the present invention are described below with reference to the accompanying drawings. The examples given are only for explaining the present invention and are not intended to limit the scope of the present invention.

[0013] Example 1 like Figure 1 As shown, an optimization method for a coordinated control system of a coal-fired power generating unit includes the following steps: Step 01: Coordinate the AGC control system: including 1.1 Optimize the main steam pressure setting system: Adjust the main steam pressure rise and fall rate and deviation; 1.2 Optimize the turbine main control system: Modify the load control loop of the turbine main control system; 1.3 Optimize the boiler main control system: Optimize the generation of coal feed rate setpoints and water flow rate setpoints for the boiler main control commands; 1.4 Optimize the intermediate point temperature and feedwater control system: Based on the boiler intermediate point setpoint, generate an overheat correction coefficient for the water flow setpoint; 1.5 Optimize the fuel control system: The final coal feeding instructions for each coal feeder are generated from the boiler control instructions; 1.6 Optimize the coal mill hot air system: Generate the primary air flow rate setpoint based on the final coal feeding instruction; 1.7 Optimize the coal mill cooling system; generate primary air flow rate setpoints based on the final coal feeding command; 1.8 Optimize the primary air pressure control system: Generate primary air pressure setpoints based on fuel master control setpoints; 1.9 Optimize supply air oxygen control; 1.10 Optimize the boiler main and reheat steam temperature control system: Optimize control parameters on-site; Step 02: Optimize the primary frequency regulation control system; Step 03: Optimize the flow curves of the DEH high-adjustment valve and the air supply valve.

[0014] This control system optimization, through a widely improved supercritical unit control strategy, retains the original operation mode of fully opening the coal mill hot air regulating damper, and significantly enhances the boiler load response sensitivity in terms of feedwater, pulverization, combustion, and boiler pressure energy storage. Ultimately, a relatively balanced optimization effect is achieved in terms of stability, economy, and rapid sensitivity.

[0015] In practical implementation, the boiler control loop of the boiler-turbine coordinated control system employs an improved boiler-water-coal dynamic decoupling control strategy. Based on the characteristics of the frequency-regulating AGC operation mode of thermal power units, the strategy has been specifically refined and optimized. For the turbine load control loop of the boiler-turbine coordinated system, targeted refinements and optimizations have been made to address the speed and time requirements of AGC, thereby improving the indicator values ​​of the two detailed rules (the "Implementation Rules for Grid-Connected Operation Management of Power Plants in Central China" and the "Implementation Rules for Ancillary Service Management of Grid-Connected Power Plants in Central China") during the unit's AGC process. For other subsystems of the unit, the control strategy basically follows the original single-loop PID plus feedforward control strategy, or the cascaded PID plus feedforward control strategy.

[0016] Based on the improvement and refinement of the control strategy, the control parameters of each system are comprehensively optimized and adjusted during normal unit operation to adapt to the rapid disturbance requirements of the unit's AGC and improve the stability of the unit's main and auxiliary parameters during the rapid frequency regulation AGC process.

[0017] Example 2 This embodiment is a further improvement on embodiment 1, as detailed below: 1.1 Optimizing the main steam pressure setting system specifically includes: Due to various possible reasons such as pulverization, combustion, flame center position, and disturbances, the main steam pressure may deviate significantly from the set value during unit operation. During load increases, the rate of increase and decrease of the main steam pressure set value is slowed down. Based on the boiler feedforward control results, the main steam pressure deviation is reduced, and the attenuation rate regulation effect of the boiler PID controller is reduced, thereby improving the stability of the main steam pressure operation. When the unit operates in the lower and higher load ranges, the change in the pressure set value is slowed down to prevent large changes in the pressure set value from causing large disturbances and overpressure. In the intermediate load operating range, the change in the pressure set value is accelerated to prevent or slow down the change in main steam pressure, which could lead to a slow rise in main steam pressure during load increases with the DEH high-pressure valve fully open, or a slow drop in main steam pressure during load decrease with the main steam valve opening too small. In practical implementation, the processing of the main steam pressure set value can address these two issues. However, to a certain extent, the handling of these two issues is contradictory. When optimizing control parameters, a balance must be struck between them.

[0018] Example 3 This embodiment is a further improvement on embodiment 1, as detailed below: 1.2 Optimizing the turbine main control system specifically includes modifying the load control loop of the turbine main control system, including the setpoint system and the feedforward system, to improve the load response time index value in the unit's AGC load response quality.

[0019] 1.3 Optimizing the boiler main control system specifically includes: Under the coordinated mode, the boiler main control system mainly consists of two parts: one is the PID control part for pressure deviation, and the other is the proportional conversion part for load command. The sum of the PID control part for pressure deviation and the proportional conversion part for load command forms the nominal command of the boiler main control system. This nominal command is corrected by the superheat correction coefficient (divided by the coefficient) to obtain the final boiler main control command, which is sent to the fuel main control loop and the feedwater main control loop respectively. After compensation and conversion, the set values ​​of the boiler coal feed rate and feedwater flow rate are formed.

[0020] Example 4 This embodiment is a further improvement on embodiment 1, as detailed below: 1.4 Optimization of the intermediate point temperature and feedwater control system specifically includes: calculating the saturated steam temperature at the separator based on the separator pressure, superimposing the superheat setpoint curve calculated based on the unit load, and compensating for the main steam temperature deviation (this function can be enabled or disabled by operators), and adding the superheat bias value to form the boiler intermediate point temperature setpoint. The intermediate point temperature setpoint is compared with the separator outlet temperature, and the difference is processed by PID calculation to form the feedwater flow setpoint superheat correction coefficient. The superheat correction coefficient is a correction coefficient in the range of (0.5-1.5). When the superheat increases, this correction coefficient increases, and the boiler feedwater flow setpoint corrected by this coefficient increases, thus controlling the increase in superheat. At the same time, the boiler main control setpoint corrected by the reciprocal of this coefficient will decrease, and the converted fuel main control setpoint will decrease, which can also achieve the effect of controlling the increase in superheat.

[0021] 1.5 Optimizing the fuel master control system specifically includes: superimposing the fuel overshoot compensation part during the load change process into the boiler master control command, and then correcting it through the coal quality correction loop to form the boiler fuel quantity command. After calculation by the fuel master control PID, the final coal feeder common command is formed, and then the respective biases are superimposed to form the final coal feeding command of each coal feeder.

[0022] Both the optimization of the coal mill hot air system in section 1.6 and the optimization of the coal mill cold air system in section 1.7 specifically include: converting the set value of the primary air flow of the coal mill into the final coal feeder command, using a PID controller, and feedforward converting the set value into the final coal feeder command.

[0023] Example 5 This embodiment is a further improvement on embodiment 1, as detailed below: 1.8 Optimizing the primary air pressure control system specifically includes: dividing the total boiler fuel quantity command by the number of operating coal-fired power units to generate an approximate fitted value for the fuel master control output. This approximate fitted value is then used to generate the boiler primary air pressure setpoint. This avoids the impact of fluctuations in the fuel master control during coal shortages. According to project requirements, when setting the automatic air pressure setpoint, the characteristics of the wall-mounted airflow are considered to a certain extent, achieving a balance between boiler rapid response and combustion stability. 1.10 Optimizing the boiler main and reheat steam temperature control system specifically includes: maintaining the original cascade PID structure for the main control strategy, appropriately modifying some compensation and feedforward functions, and optimizing the control parameters on-site. This makes the desuperheating spray control more flexible and accurate.

[0024] Optimizing the primary frequency control system specifically includes: obtaining the primary frequency control load command component based on the frequency inequality rate and dead zone conversion function, forming three control or compensation actions respectively: the frequency control component of the load setpoint to the CCS (coordinated control system for boiler and turbine) control loop, the frequency control feedforward control component to the DEH high-voltage valve integrated command (designing a feedforward control correction system based on load conversion to solve the problem of inaccurate linearity of the turbine high-voltage valve to a certain extent), and the frequency control command feedforward component to the boiler main control feedforward (for unidirectional long-term large-amplitude frequency regulation in some areas, it can compensate for the disturbance of the primary frequency regulation to the boiler, so as to improve the stability of the boiler main parameters during the primary frequency regulation action); optimizing the sequential valve coordinated action control strategy of the turbine's supplementary steam valve and high-voltage valve: the high-voltage valve and the supplementary steam valve overlap in opening with a certain flow rate, forming that the high-voltage valve opens first, and when approaching the inflection point of the high-voltage valve flow rate, the supplementary steam valve will start from the pre-opening opening and gradually open to the full effective range.

[0025] Optimizing the flow curves of the DEH high-pressure regulating valve and the supplementary air valve specifically includes: first, conducting field tests to determine the flow characteristic curves of each valve; then, performing numerical calculations to determine the valve overlap function and flow distribution function. In practical implementation, for supercritical DC units, due to the large cruising range of the main steam pressure during unit operation, the influence of the main steam pressure on the actual valve flow rate must be incorporated into the calculation algorithm in the second step of numerical calculation.

[0026] test 1. Experimental Basis GB / T3146 Power Grid Operation Guidelines DL / T 1210 Performance Testing and Acceptance Procedures for Automatic Generation Control Systems in Thermal Power Plants DL / T 1870 Technical Specification for Power System Grid-Source Coordination DL / T 657 Acceptance Test Procedure for Analog Control Systems in Thermal Power Plants DL / T 5295 Code for Acceptance and Evaluation of Commissioning Quality of Thermal Power Plant Construction Units DL / T5437 Procedures for Commencement and Acceptance of Thermal Power Plant Construction Projects DL / T774-2004 Maintenance and Repair Procedures for Thermal Automation Systems in Thermal Power Plants DL / T-656-2006 Acceptance Test Procedure for Steam Turbine Control Systems in Thermal Power Plants GB / T 36045 Regulatory Standard for Capacity Expansion and Retrofitting of Coal-fired Power Units Implementation Rules for the Management of Ancillary Services of Grid-Connected Power Plants in Central China Implementation Rules for Grid Connection and Operation Management of Power Plants in Central China Jiangxi Power Grid Automatic Generation Control (AGC) Operation and Management System Design Drawings and Manuals, and other technical documents. The relevant regulations of Jiangxi Power Dispatch and Communication Center regarding the commissioning of primary frequency regulation function of grid-connected generating units, and the "Notice on Issuing Opinions on the Management of Grid-Connected Power Plant Operation" (Electric Power Market Supervision

[20031] No. 23), etc. The power plant's relevant drawings and instructions. State Grid Corporation of China Power Safety Production Work Regulations (State Grid Safety Supervision

[2008] No. 23).

[0027] 2. Test Content 2-1 Test of unit load control quality under AGC mode.

[0028] 2-2 Control quality test of other main parameters of the unit under AGC mode.

[0029] 3. Performance test load range Low load range: 50%Pe-75%Pe; High load range: 75%Pe-100%Pe.

[0030] 4. Variable load performance test For variable load AGC tests, two modes are selected: unidirectional ramp load command variation mode and triangular wave load command variation mode. When using the unidirectional ramp load command variation mode, the unidirectional ramp load command variation is performed separately in the direction of increasing and decreasing load, and the settling time between the two load variation tests should be no less than 20 minutes. When using the triangular wave load command variation mode, the amplitude of the triangular wave load command variation is 5%Pe, and the command curve is designed as at least 2.5 uninterrupted continuous triangular waves. Variable load AGC performance tests are conducted separately at low load and high load levels of the unit.

[0031] Test 1: 5% Pe amplitude unidirectional slope load reduction test in low load section. The test data are shown in the table below: The average rate of change of load is 1.34%Pe / min, which meets the relevant requirements. The load response time is 56 seconds, which meets the relevant requirements. The dynamic over-adjustment of the load is 0.35%Pe, which meets the relevant requirements; The steady-state load deviation is 0.45%Pe, which meets the relevant requirements. The main analog quantity indicators meet the relevant requirements.

[0032] Experiment 2: 5% Pe amplitude unidirectional ramp load increase test in low load section. The experimental data are shown in the table below: The average rate of change of load is 1.32%Pe / min, which meets the relevant requirements. The load response time is 40 seconds, which meets the relevant requirements. The dynamic over-adjustment of the load is 0.35%Pe, which meets the relevant requirements; The steady-state load deviation is 0.45%Pe, which meets the relevant requirements. The main analog quantity indicators meet the relevant requirements.

[0033] Experiment 3: 5% Pe amplitude unidirectional slope load reduction test in high-load section. The experimental data are shown in the table below: The average rate of change of load is 1.39%Pe / min, which meets the relevant requirements. The load response time is 35 seconds, which meets the relevant requirements. The dynamic over-adjustment of the load is 0.62%Pe, which meets the relevant requirements; The steady-state load deviation is 0.6%Pe, which meets the relevant requirements. The main analog quantity indicators meet the relevant requirements.

[0034] Test 4: 5% Pe amplitude unidirectional ramp load increase test in high-load section. The test data are shown in the table below: The average rate of change of load is 1.39%Pe / min, which meets the relevant requirements. The load response time is 32 seconds, which meets the relevant requirements. The dynamic over-adjustment of the load is 0.9%Pe, which meets the relevant requirements; The steady-state load deviation is 0.8%Pe, which meets the relevant requirements. The main analog quantity indicators meet the relevant requirements.

[0035] Test 5: Triangular wave variable load test at low load section. The test data are shown in the table below: The average rate of change of load is 1.27%Pe / min, which meets the relevant requirements. The load response time is 42 seconds, which meets the relevant requirements. The dynamic over-adjustment of the load is 0.6%Pe, which meets the relevant requirements; The steady-state load deviation is 0.55%Pe, which meets the relevant requirements. The main analog quantity indicators meet the relevant requirements.

[0036] Experiment 6: Triangular wave variable load test in high load section. The experimental data are shown in the table below: The average rate of change of load is 1.26%Pe / min, which meets the relevant requirements. The load response time is 34 seconds, which meets the relevant requirements. The dynamic over-adjustment of the load is 0.2%Pe, which meets the relevant requirements; The steady-state load deviation is 0.34%Pe, which meets the relevant requirements. The main analog quantity indicators meet the relevant requirements.

[0037] Based on the above test results: After optimization, the primary frequency regulation of AGC has significant benefits, the parameters operate smoothly, the control optimization effect is obvious, and it meets all the requirements of the power plant's technical agreement.

[0038] The above description is only a preferred embodiment of the present invention and is not intended to limit the present invention. Any modifications, equivalent substitutions, improvements, etc., made within the spirit and principles of the present invention should be included within the protection scope of the present invention.

Claims

1. An optimization method for a coordinated control system of a coal-fired power generating unit, characterized in that, Comprising the following steps: Step 01, coordinating AGC control system: comprising 1.1 optimizing main steam pressure value setting system: adjusting main steam pressure value rising and falling speed, deviation; 1.2 optimizing steam turbine main control system: modifying steam turbine main control load control loop; 1.3 optimizing boiler main control system: optimizing boiler main control instruction to form coal supply amount setting value and water flow setting value; 1.4 optimizing intermediate point temperature and water supply control system: according to boiler intermediate point setting value, forming water flow setting value superheat correction coefficient; 1.5 optimizing fuel main control system: forming final coal supply instruction of each coal supply machine from boiler main control instruction; 1.6 optimizing coal mill hot air system: generating primary air flow setting value according to final coal supply instruction; 1.7 optimizing coal mill cold air system: generating primary air flow setting value according to final coal supply instruction; 1.8 optimizing primary air pressure control system: generating primary air pressure setting value according to fuel main control setting value; 1.9 optimizing air supply oxygen amount control; 1.10 optimizing boiler main re-vapor temperature control system: optimizing control parameters on site; Step 02, optimizing primary frequency modulation control system; Step 03, optimizing DEH high regulating valve and air supplement valve flow curve.

2. The method of claim 1, wherein the optimization is performed by a computer system. 1.1 The specific optimization of the main steam pressure value setting system includes: slowing down the rising and falling speed of the main steam pressure setting value during the unit load rising process, reducing the main steam pressure deviation according to the boiler feedforward control result, and reducing the attenuation rate adjustment of the boiler PID regulator; when the unit is running at a lower load and a higher load range, the pressure setting value changes slowly; in the intermediate load working area, the pressure setting value changes quickly.

3. The optimization method for the coordinated control system of a coal-fired power generating unit according to claim 2, characterized in that, 1.2 The specific optimization of the steam turbine main control system includes: modifying the load control loop of the steam turbine main control, including the setting value system and the feedforward system.

4. The method of claim 1, wherein the method further comprises: 1.3 The specific optimization of the boiler main control system includes: the sum of the PID control part of the pressure deviation and the proportional conversion part of the load instruction forms the nominal instruction of the boiler main control, which is corrected by the superheat correction coefficient to obtain the final boiler main control instruction, which is sent to the fuel main control loop and the water supply main control loop respectively, and then forms the coal supply amount setting value and the water flow setting value of the boiler after compensation and conversion.

5. The optimization method for the coordinated control system of a coal-fired power generating unit according to claim 4, characterized in that, 1.4 The specific optimization of the intermediate point temperature and water supply control system includes: the saturation steam temperature at the separator is converted according to the separator pressure, the superheat setting curve converted according to the unit load is superimposed, the compensation correction according to the main steam temperature deviation is added, and the superheat bias value is added to form the boiler intermediate point temperature setting value. The difference between the intermediate point temperature setting value and the separator outlet temperature is subjected to PID operation to form the water flow setting value superheat correction coefficient.

6. The method of claim 1, wherein the method further comprises: 1.5 The specific optimization of the fuel main control system includes: superimposing the fuel overshoot compensation part in the boiler main control instruction during the variable load process, then correcting it through the coal quality correction loop to form the total boiler fuel amount instruction, and then forming the final coal supply machine public instruction through the fuel main control PID calculation, and then superimposing the respective bias to form the final coal supply instruction of each coal supply machine.

7. The method of claim 1, wherein the method further comprises: 1.6 Optimizing the hot air system of the coal mill and 1.7 optimizing the cold air system of the coal mill both specifically include: according to the final coal feeder instruction, the primary air flow of the coal mill is converted into a set value, a PID regulator is used, and feedforward is converted according to the final coal feeder instruction.

8. The method of claim 1, wherein the method further comprises: 1.8 Optimizing the primary air pressure control system specifically includes: according to the fuel master control set value, the number of coal mill operating stations is divided to convert the approximate fitting amount of the fuel master control output, and the approximate fitting amount is converted to generate the boiler primary air pressure set value; 1.10 Optimizing the boiler main re-steam temperature control system specifically includes: the main structure of the control strategy remains the original cascade PID structure, some compensation and feedforward functions are appropriately modified, and the control parameters are optimized on site.

9. The method of claim 1, wherein the method further comprises: determining a set of optimal parameters for the coordinated control system of the coal-fired power plant based on the optimization of the objective function. 1.9 Optimizing the primary frequency modulation control system specifically includes: according to the frequency modulation inequality rate and the dead zone conversion function, the primary frequency modulation load instruction component is obtained, and three control or compensation effects are formed respectively: the frequency modulation component of the load set value to the CCS control loop, the frequency modulation feedforward control component to the DEH high pitch valve comprehensive instruction, and the frequency modulation instruction feedforward component to the boiler master feedforward; Optimizing the valve action control strategy of the steam turbine's supplementary valve and high pitch valve: the high pitch valve and the supplementary valve have a certain flow overlap in opening degree, forming the high pitch valve opening first, and when approaching the high pitch valve flow inflection point, the supplementary valve will start from the pre-activation opening and gradually open the effective range.

10. The method of claim 1, wherein the coordinated control system optimization for coal-fired power generating units is performed by a computer system. Optimizing the DEH high pitch valve and supplementary valve flow curve specifically includes: first, field tests are conducted to determine the flow characteristics curve of each valve, and then numerical calculations are performed to determine the valve overlap function and flow distribution function.

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