Updating, transforming and evaluating method for water-turbine generator set

Abstract

The invention discloses a water-turbine generator set updating transformation and evaluation method, and relates to the technical field of water-turbine generator sets. According to the method, starting from power station and unit parameter collection, the transformation range is preliminarily judged in combination with maintenance, operation and vibration throw data, then core analysis is carried out on whether a runner is transformed or not, the power generation potential improvement requirement, the capacity increasing target and scheme determination, and technical feasibility is verified through CFD simulation and model tests; and rechecking the adaptability of the auxiliary system, the electrical equipment and the basic structure, and finally combining investment estimation and economic evaluation to output a decision basis. According to the method, the whole transformation process is covered, the technical rationality and economic benefits are considered, the transformation range can be accurately defined, the problems of efficiency attenuation of old units, insufficient adaptive power grid capacity and the like are solved, scientific support is provided for power station transformation decision making, and reference is provided for similar projects.

Description

Technical Field

[0001] This invention relates to the field of hydro-generator technology, specifically to a feasibility study and evaluation method for the efficient, comprehensive, and systematic upgrading and renovation of hydro-generators that have been in operation for a long time, have degraded performance, or are unable to adapt to the current grid dispatching requirements. Background Technology

[0002] my country's modern hydro-turbine generator units are rapidly developing towards larger, more complex, higher-speed, and higher-power models. The shaft systems of these units are becoming increasingly complex, with a continuously improving degree of integration. Their safe and stable operation involves the coordinated efforts of multiple disciplines, including hydraulics, mechanics, electrical engineering, and structural mechanics. In actual operation, the complex kinetic energy parameters under different constraints, as well as the mutual influence and interaction of the hydraulic and dynamic behaviors among the various flow components of the unit, pose severe challenges to the daily management, maintenance, condition monitoring, fault diagnosis, and safety operation evaluation of the units.

[0003] According to the international standard "Hydrogen Turbines, Storage Pumps and Pump-Turbine Retrofitting and Performance Improvement" (IEC 62256 2008) and the national standard "Guidelines for the Retrofitting and Performance Improvement of Hydrogen Turbines, Storage Pumps and Pump-Turbines" (GB / T28545-2023), the expected lifespan of mixed-flow turbines is 30-50 years, that of axial-flow turbines is 25-50 years, that of other types of pump-turbines and storage pumps is 25-35 years, and that of generators is 25-40 years. Currently, hydropower stations put into operation before 2000 have generally been in operation for over 25 years. During long-term operation, some power stations' turbine-generator units have gradually experienced significant efficiency decline, aging and damage to core components, decreased operational stability, and inability to adapt to current grid frequency regulation and peak-shaving demands, seriously affecting the economic benefits and safe operation of the power stations.

[0004] However, existing methods for retrofitting hydro-generator units are mostly limited to replacing single components, such as the runner or guide vanes, or directly replacing the entire unit. They lack a systematic feasibility study methodology covering the entire process from parameter analysis to scheme design, technical verification, and economic evaluation. This piecemeal approach not only fails to fundamentally solve the unit's systemic problems but may also lead to poor compatibility of components after retrofitting, wasted investment, and poor economic returns. Therefore, the industry urgently needs a scientific, efficient, and systematic feasibility study methodology for retrofitting hydro-generator units. Summary of the Invention

[0005] The purpose of this invention is to overcome the lack of systematic feasibility study methods for the upgrading and renovation of hydro-turbine generator sets in the existing technology, and to provide a feasibility study and evaluation method for the upgrading and renovation of hydro-turbine generator sets that covers the entire renovation process and takes into account both technology and economy. Through standardized steps, the scope of renovation can be accurately determined, the economic benefits of the power station can be maximized, and old power stations that have been in operation for many years can regain efficient and stable operation capabilities.

[0006] To achieve the above objectives, this invention provides a feasibility study method for the upgrading and retrofitting of hydro-generator units, the method comprising the following steps: 1) Collect power plant and unit parameters This step is the foundation for all subsequent analyses and requires the comprehensive collection of data related to hydropower and scheduling, operation and maintenance, and equipment and structure.

[0007] 2) Based on the unit maintenance status, power station operation status, unit vibration and swing status, the scope of the hydro-generator unit renovation is preliminarily determined.

[0008] Based on the unit maintenance information collected in Step 1, such as frequently failing components, power plant operation conditions such as prolonged low-load operation and severe water wastage, and unit vibration and sway conditions such as vibration values ​​exceeding standards under certain operating conditions, a preliminary screening of the scope for modification of the hydro-generator units is conducted. For example, if the unit's vibration consistently exceeds standards under low-load conditions, and wear is found on the runner blades during maintenance, it can be preliminarily determined that the runner may need modification; if the generator's insulation performance deteriorates, leading to frequent tripping, the generator can be preliminarily included in the potential modification scope. The purpose of this step is to narrow down the focus of subsequent analysis and clarify the core modification direction.

[0009] 3) Determine if the modification includes a rotating wheel; if yes, proceed to step 4); otherwise, proceed to step 12. The turbine runner is the core component of a hydroelectric generator unit, converting water energy into mechanical energy. Its performance directly determines the unit's efficiency, stability, and power output. Therefore, after initial assessment, it is necessary to further clarify whether the modification includes the turbine runner. If the preliminary assessment of the scope of modification includes the impeller, such as an aging impeller, severe wear, or an existing impeller that cannot adapt to the new operating conditions, then proceed to step 4), focusing on impeller modification and subsequent related analysis. If the scope of the modification does not include the runner, such as only repairing the auxiliary system or replacing small electrical components, then skip the steps related to the runner, such as capacity expansion and hydraulic performance analysis, and proceed directly to step 12), focusing on defining the scope of modification for non-runner components.

[0010] 4) Determine if it is necessary to increase the power generation potential. If yes, proceed to step 5; otherwise, proceed to step 9. Based on the power plant operation data collected in step 1, we assess whether there is room for improvement in power generation potential from three dimensions: Analysis of water wastage: If there is seasonal or continuous water wastage, such as during the flood season, it indicates that there are underutilized hydropower resources, which have the potential to increase power generation.

[0011] Peak shaving demand matching: Considering the grid's dispatch requirements for power plants, such as whether they undertake frequency regulation and peak shaving tasks, if the power plant needs to frequently switch between high and low loads, but the existing units have a narrow output range and slow response speed, improving the power generation potential, such as widening the output range and increasing the rated power, can better adapt to the grid demand.

[0012] Efficiency degradation assessment: Compare the unit's factory efficiency curve with the current actual operating efficiency. If the efficiency degradation exceeds 5% or exceeds the allowable range of the standard, the original efficiency level can be restored or even surpassed by upgrading the power generation potential.

[0013] If the above analysis shows that there is a necessity and feasibility to enhance the power generation potential, then proceed to step 5); if the existing power generation capacity fully meets the demand, there is no water wastage and the efficiency is stable, then proceed to step 9), focusing only on the repair and optimization of existing components.

[0014] 5) Determine if capacity expansion or modification is needed. If yes, proceed to step 6; otherwise, proceed to step 8. Pathways to enhance power generation potential include capacity expansion and upgrading to increase rated power, and efficiency optimization that improves generation efficiency without changing rated power. This step requires consideration of the power plant's actual needs, such as whether there are plans to increase installed capacity, grid connection conditions, such as whether the grid allows for capacity expansion, and economic expectations, such as whether the benefits of capacity expansion cover the costs, to determine whether capacity expansion should be adopted. If the power plant clearly intends to increase its capacity, and the power grid allows it and it is economically feasible, then proceed to step 6) to design the capacity increase target and plan; If capacity expansion is not adopted, such as due to grid capacity limitations or excessively high expansion costs, proceed to step 8) and only improve power generation potential through efficiency optimization and operating condition adjustments, skipping the design of capacity expansion-related goals and schemes.

[0015] 6) Determine the capacity expansion target The capacity expansion target must be scientifically determined based on the actual hydropower resources and operational needs of the power station to avoid blind expansion leading to wasted investment or underutilization. Power generation forecast: Based on the actual power plant data collected in step 1, such as the power output characteristics under different water heads and the distribution of inflow, the annual power generation under different installed capacity schemes, such as the existing capacity, capacity increase of 5%, capacity increase of 10%, and capacity increase of 15%, is predicted using hydrological and hydropower calculation methods.

[0016] Inflection Point Analysis: Plotting the installed capacity-predicted power generation curve, the curve typically shows a trend of rapid initial growth, followed by slower growth until it stabilizes. The point where the growth rate slows significantly is the inflection point. The installed capacity at the inflection point indicates that further capacity expansion will result in limited power generation increases, representing the economically optimal expansion boundary.

[0017] Target setting: The installed capacity near the inflection point is used as the recommended installed capacity after the expansion, forming a clear expansion target. For example, if the existing installed capacity is 1200MW, it is recommended to expand to 1320MW, which is an increase of 10%.

[0018] 7) Determine the capacity expansion plan For the capacity expansion target determined in step 6, four technically feasible capacity expansion schemes are provided, and the optimal scheme is selected through comparative analysis: Option A: Keep the runner diameter and rated head unchanged, and improve unit parameters such as increasing runner speed and optimizing blade profile to enhance flow capacity. This option is suitable for scenarios where the existing runner diameter and head conditions are already matched, and capacity expansion can be achieved simply by optimizing parameters.

[0019] Option B: Keep the rated head and unit parameters unchanged, and increase the runner diameter, such as increasing the runner diameter from 3.8m to 4.0m. This is suitable for scenarios where the output needs to be increased by increasing the flow area, but the head conditions cannot be changed. It is necessary to ensure that the flow channel is compatible with the enlarged runner.

[0020] Option C: Keep the runner diameter and unit parameters unchanged, and increase the rated head, such as from 120m to 130m. This option is suitable for reservoirs that have the conditions to raise the water level. The capacity can be increased by increasing the energy density per unit volume of water, without changing the runner size, and with minimal impact on the existing flow channel and civil engineering structure.

[0021] Option d: Two or more of the following parameters change: runner diameter, rated head, and unit parameter levels, such as simultaneously increasing the runner diameter and raising the rated head. This is suitable for scenarios where adjusting a single parameter cannot meet the capacity expansion target and multi-dimensional collaborative optimization is required.

[0022] When comparing the four options, key considerations include: whether the capacity expansion target is met; the compatibility of the existing flow channels with the civil engineering structure (e.g., whether large-scale modifications are needed); the parameter matching of core equipment such as generators and speed governors (e.g., whether synchronous replacement is needed); and the modification cost and construction period. If an option meets all constraints and is the most economical, it is determined as the final capacity expansion option. If none of the options meet the capacity expansion target, return to step 6 to readjust the capacity expansion target, and repeat this step until a matching option is found.

[0023] 8) Impact of reviewing capacity expansion plans on downstream power plants If there are other hydropower stations, irrigation projects, or water-using areas downstream of the current power station, the capacity expansion and renovation may change the timing and volume of downstream water inflow, requiring targeted verification: Spatiotemporal distribution analysis of water flow: The hydrological model is used to simulate the downstream flow process of the power station after the capacity expansion, such as whether the downstream flow increases during the flood season and whether the downstream flow decreases during the dry season, and to compare the inflow conditions of the downstream power station before and after the renovation.

[0024] Downstream impact assessment: Determine whether the capacity expansion will lead to an increase in the amount of water abandoned by downstream power plants. For example, if the upstream discharge flow increases sharply and exceeds the flow capacity of downstream units, the power generation will decrease. If the upstream discharge flow is insufficient during the dry season, it may affect the downstream irrigation and ecological water demand.

[0025] Plan adjustment: If there are adverse effects, the capacity expansion plan needs to be adjusted (such as optimizing the scheduling method and limiting the maximum discharge flow during the flood season); if there are no effects or the effects are within an acceptable range, proceed to step 9).

[0026] 9) Propose the weighted factors for the operation of the modified power plant, pressure pulsation index, cavitation index, blade passage vortex, Karman vortex, output and efficiency guarantee values.

[0027] Based on relevant national standards such as GB / T28545-2023, power plant operation requirements, and capacity expansion targets, the core technical indicators that the upgraded units must meet are clearly defined to provide a basis for subsequent design and verification. Power plant operation weighting factor: The weighting coefficient is determined based on the proportion of operating time under different operating conditions of the power plant, and is used to evaluate the comprehensive performance of the unit across the entire operating range.

[0028] Pressure pulsation indicators include: tailrace pressure pulsation (peak-to-peak value not exceeding 0.05 times the rated head under rated operating conditions), pressure pulsation in the bladeless area before the runner and after the guide vanes (peak-to-peak value not exceeding 0.1 times the rated head), and pressure pulsation at the volute measuring point, to ensure stable water flow pressure during unit operation and avoid excessive vibration.

[0029] Cavitation index: Cavitation will cause wear on the runner and reduce efficiency. It is necessary to ensure that the ratio of the power plant cavitation coefficient to the primary cavitation coefficient is not less than 1.05 to ensure sufficient safety margin to avoid primary cavitation. The ratio of the power plant cavitation coefficient to the critical cavitation coefficient is not less than 1.55 to avoid severe cavitation.

[0030] Blade passage vortex and Karman vortex control requirements: Blade passage vortex and Karman vortex can cause unit vibration and noise. It is required that nascent blade passage vortex should not appear in the area of ​​30% of the expected output and above, and visible Karman vortex is not allowed in the operating range.

[0031] Guaranteed output value: Clearly define the output capacity of the unit after modification under different water heads, such as the rated power under the rated water head (e.g., 35MW) and the guaranteed output corresponding to the minimum water head (e.g., 80MW).

[0032] Efficiency guarantee values ​​include the rated efficiency of the prototype turbine under rated operating conditions of not less than 92.5%, the highest efficiency of the prototype turbine across the entire operating range of not less than 95.5%, and the corresponding efficiency of the model turbine under rated operating conditions of not less than 90.8%.

[0033] 10) Establish a full-flow-channel calculation model for the turbine, and conduct CFD simulation analysis on the optimal operating conditions before and after the modification, the maximum head rated output operating conditions, the rated head rated output operating conditions, the minimum head guaranteed output operating conditions, and the operating conditions at 30% of the rated output at each head. Predict the stable operation capability of the unit and determine whether it is necessary to replace the movable guide vanes.

[0034] Computational Fluid Dynamics (CFD) simulation is a key technology for predicting the hydraulic performance and stability of water turbines. The specific process is as follows: Model establishment: Based on the flow channel size data collected in step 1, a full flow channel calculation model of the turbine, including the volute, guide vanes, runner, and draft tube, was established using software such as ANSYS and Fluent, ensuring that the error between the model and the actual structure does not exceed 2%.

[0035] Operating conditions selection: Multiple typical operating conditions before and after the modification were selected for simulation, including the optimal operating condition (the operating condition with the highest efficiency), the operating condition with the maximum head and rated output, the operating condition with the rated head and rated output, the operating condition with the minimum head and guaranteed output, and the small load operating condition with 30% of the rated output at each head to focus on verifying the vibration problem, totaling no less than 10 operating conditions.

[0036] Simulation analysis: Calculate the flow velocity distribution, pressure distribution, and vortex distribution under various operating conditions to evaluate the unit's flow capacity, efficiency, pressure pulsation intensity, and cavitation risk. For example, if the simulation shows that the peak-to-peak pressure pulsation in the tailrace pipe is reduced to 0.03 times the rated head after the modification, it indicates a significant improvement in hydraulic stability; if the cavitation area exceeds 5% of the runner blade area, the design needs to be optimized.

[0037] Determination of movable guide vanes: Based on the simulation results, if the profile and angle of the existing movable guide vanes cannot be adapted to the modified water flow conditions, such as causing water flow deviation, increased pressure pulsation, or failure to meet the flow regulation requirements after capacity expansion, then it is determined that the movable guide vanes need to be replaced; if the existing guide vanes can meet the requirements by adjusting the angle, then there is no need to replace them.

[0038] 11) Hydropower turbine model test Conduct a turbine model test and compare the test results with the requirements proposed in step 9). If the requirements are not met, return to step 10) to adjust the CFD simulation parameters or optimize the design scheme and repeat the test; if the requirements are met, proceed to step 12).

[0039] Turbine model testing is a physical testing method to verify the feasibility of the modification plan. It can be carried out by the winning bidder or a third-party testing agency after the unit modification bidding process. Model making: The model runner, guide vanes and flow channels are made according to the geometric similarity ratio of the prototype water turbine, which is usually 1:10 to 1:20, to ensure that the geometric similarity between the model and the prototype is not less than 98%.

[0040] Test content includes: energy test to measure model efficiency under different operating conditions and convert prototype efficiency; cavitation test to determine primary cavitation coefficient and critical cavitation coefficient; stability test to measure pressure pulsation and vibration acceleration under different operating conditions; and runaway test to verify whether the runaway speed of the unit is within the safe range.

[0041] Result verification: Compare the test results with the index requirements proposed in step 9). If the model efficiency, cavitation coefficient, pressure pulsation, etc. all meet the requirements, it proves that the modification scheme is technically feasible; if not, it is necessary to return to step 10) to adjust the CFD simulation parameters or optimize the design scheme and conduct the test again.

[0042] 12) In summary, the scope of components that must be modified and the scope of components that do not need to be modified are determined.

[0043] Based on the combined analysis results from steps 2) to 11), the components and systems of the hydro-generator unit are classified as follows: The scope of mandatory modifications includes components with severely substandard performance (e.g., efficiency degradation exceeding 8%), components posing safety hazards (e.g., runner cracks, excessive spindle wear), components that are incompatible with the modified operating conditions (e.g., insufficient rated current after capacity expansion), and components that must be replaced based on CFD simulations and model tests (e.g., movable guide vanes). For example, if the generator stator windings are irreparably aged and the current exceeds the carrying capacity after capacity expansion, the entire generator must be included in the mandatory modification scope.

[0044] Non-essential modifications include components with good performance (e.g., efficiency degradation less than 3%), components whose rigidity meets post-modification requirements (e.g., volute housing seat ring stress within permissible limits), and components requiring only routine maintenance such as cleaning and lubrication for normal operation, such as the base ring and tailrace cone without cracks or wear. The purpose of this step is to accurately define the modification boundaries to avoid excessive modifications that increase costs.

[0045] 13) Perform rigidity analysis on non-essential components to ensure that these components can meet the requirements after the unit's power generation potential is increased. If any component does not meet the rigidity requirements, it must be included in the scope of mandatory modification. If the unit's power generation potential is not increased, this step is not required.

[0046] If the generating unit needs to increase its power generation potential, such as by increasing its capacity, non-essential components may lack sufficient rigidity due to increased loads such as water flow pressure and torque, requiring a special analysis: Component selection: For key load-bearing components that are not required to be modified, such as the volute seat ring, tailrace elbow, foundation ring, and cone inlet gate, rigidity and strength calculations are carried out.

[0047] Calculation conditions: Considering extreme conditions such as maximum head, maximum output, and runaway after capacity expansion, finite element analysis software such as ANSYS and ABAQUS are used to calculate the stress distribution and deformation of the components.

[0048] Result judgment: If the maximum stress value of the component does not exceed the allowable stress of the material, such as the allowable stress of Q345 steel is 235MPa, and the deformation does not exceed the allowable value of the specification, such as the maximum deflection of the main shaft does not exceed L / 10000, where L is the span of the main shaft, then no modification is required; if the stress or deformation exceeds the standard, then the component should be adjusted to the scope of mandatory modification, such as replacing it with a higher strength material, increasing the wall thickness, or reinforcing the structure.

[0049] 14) After the unit’s power generation potential is increased, check whether the stator foundation can meet the requirements. If it does not meet the requirements, some measures need to be taken to reinforce the foundation. This step is not required if the unit’s power generation potential is not increased.

[0050] The generator stator foundation is a critical structure that bears the weight of the generator and transmits the vibration of the unit. After capacity expansion, the weight of the unit may increase, such as by replacing with a larger capacity generator, or the vibration load may increase, requiring a review. Load calculation: Calculate the static load of the generator after capacity expansion, such as the weight of the stator and rotor; the dynamic load, such as the centrifugal force and hydraulic excitation force during unit operation; and the short-term design conditions, such as unit start-up and shutdown, and the additional loads under accidental design conditions, such as unit load shedding and earthquakes.

[0051] Load-bearing capacity verification: Using structural mechanics methods or finite element software, verify the compressive, shear, and tensile bearing capacities of the stator foundation components, such as the concrete pile cap and embedded bolts, under the aforementioned loads. For example, if the shear bearing capacity of the concrete pile cap exceeds the code limit under short-term design conditions, reinforcement measures are required.

[0052] Reinforcement measures: If the bearing capacity does not meet the requirements, reinforcement can be carried out by increasing the foundation cross section, increasing reinforcement, pasting carbon fiber cloth, and inserting anchor rods; if the requirements are met, no treatment is required.

[0053] 15) Verify whether the generator ventilation and cooling scheme can meet the relevant requirements after the unit's power generation potential is increased. If it does not meet the requirements, the generator ventilation and cooling need to be strengthened. If the unit does not increase its power generation potential, this step is not necessary.

[0054] After the capacity is increased, the generator's losses, such as copper losses and iron losses, will increase, leading to an increase in heat generation. It is necessary to review whether the existing ventilation and cooling scheme meets the heat dissipation requirements. Heat generation calculation: Based on the rated power and efficiency of the generator after capacity expansion, calculate the power loss of the stator winding, rotor winding, and core, and then determine the total heat generation, such as when the total loss increases from 5MW to 6.5MW after capacity expansion.

[0055] Cooling capacity verification: For existing ventilation and cooling methods such as closed self-circulating air cooling, forced air cooling, and water cooling, calculate the total air volume or water volume of the cooling system and the heat exchange area of ​​the cooler, and evaluate whether the heat dissipation capacity can control the temperature of each component of the generator within the allowable range, such as the stator winding temperature not exceeding 120℃.

[0056] Optimization measures: If the cooling capacity is insufficient, measures such as increasing the number of coolers, expanding the heat exchange area, increasing the fan speed, and optimizing the air duct design can be taken to enhance ventilation and cooling; if the requirements are met, no adjustment is needed.

[0057] 16) Review the turbine speed control system, plant lifting equipment, oil, gas and water systems, and determine the components in these systems that must be modified.

[0058] Auxiliary systems of hydro-generator units, such as speed control systems, oil-gas-water systems, and lifting equipment, are crucial for ensuring the normal operation of the unit and must be reviewed one by one. Speed ​​control system: Verify whether the governor's adjustment range, response speed, and oil pressure level are suitable for the output adjustment requirements of the upgraded unit, such as whether a larger guide vane operating force is needed after capacity expansion. For example, if the governor's oil pressure level of 6.3MPa can meet the new operating force requirements, then no modification is needed; if it is insufficient, the governor needs to be replaced or the oil pressure level needs to be increased.

[0059] Factory cranes: Verify whether the crane's rated lifting capacity, lifting height, and working radius can meet the hoisting requirements of the modified components (e.g., whether the crane's lifting capacity is sufficient when replacing a generator rotor with a larger capacity one). If the lifting capacity is insufficient, the crane needs to be modified or replaced; if it is sufficient, no action is required.

[0060] Oil, gas, and water systems: Verify the oil volume and pressure of the hydraulic system, the air volume and pressure of the compressed air system, and the water volume and pressure of the technical water supply system to ensure they meet the needs of the upgraded equipment. For example, if the oil storage capacity of the hydraulic system is insufficient, the oil tank volume needs to be increased; if only some pipe fittings are corroded, the corroded pipe fittings can be replaced without requiring a complete system overhaul.

[0061] 17) Review and verify the transition process after the renovation. During the start-up, shutdown, and load shedding processes of the generating unit, phenomena such as sudden increases in speed and sudden changes in pressure may occur. Simulation calculations are needed to verify the safety of the modified transition processes. Simulation model establishment: Based on the turbine characteristic curve, pipeline characteristics, and speed control system parameters, a transient process simulation model is established, such as using SIMULINK or HYDROSIM software.

[0062] Operating condition simulation: Simulates typical transient processes such as shedding 100% and 50% of the rated load under rated head, as well as starting and stopping the unit under minimum head.

[0063] Evaluation criteria: If the maximum speed increase rate of the unit during the transition process does not exceed 50% of the rated speed, the maximum pressure of the volute does not exceed 1.5 times the rated head, and the maximum vacuum degree at the tailrace pipe inlet is not lower than -0.08MPa, then the transition process is safe. If all indicators meet the requirements of GB / T15468-2006 and other relevant standards, the transition process is safe. If the indicators exceed the standards, the governor shutdown pattern needs to be adjusted, such as by adopting a two-stage shutdown or optimizing the flow channel design.

[0064] 18) Review the primary electrical equipment. Primary electrical equipment such as transformers, circuit breakers, disconnectors, IPBs, and cables are the core of power transmission and distribution; their parameters need to be verified to ensure they are suitable for the post-modification operating conditions. Parameter verification includes checking whether the rated voltage matches the grid voltage level, whether the rated current exceeds the equipment's rated current after capacity expansion, whether the rated breaking current can interrupt fault current, and whether the insulation level meets overvoltage requirements. For example, if the unit's rated current increases from 10kA to 11kA after capacity expansion, but the existing IPB's rated current is 10kA, then the IPB needs to be replaced; if the transformer's rated capacity meets the capacity expansion requirements, then no modification is needed.

[0065] Condition assessment: Based on the equipment's years of operation and test reports such as insulating oil tests and DC resistance tests, assess whether the equipment has problems such as aging or performance degradation. If the equipment is nearing the end of its service life and insulation aging is present, it needs to be included in the renovation scope; if the condition is good, only enhanced monitoring is required.

[0066] 19) Review the secondary electrical equipment. Secondary electrical equipment, such as excitation systems, protection devices, measurement and control devices, and automation systems, are responsible for the control, protection, and monitoring of the unit. Their functions and parameters need to be verified. Excitation system: Review the excitation peak voltage multiple, such as whether it needs to be increased to 2.0 times after capacity expansion; the excitation current adjustment range; and whether the response speed can meet the excitation requirements after generator capacity expansion. If the existing excitation transformer capacity is insufficient or the demagnetizing resistor parameters are mismatched, it needs to be replaced; if only a software upgrade is needed to meet the requirements, then no hardware replacement is required.

[0067] Protection devices: Review the protection settings, such as overcurrent protection and overvoltage protection settings, to see if they need adjustment to match the rated parameters of the unit after capacity expansion. Verify that the sampling accuracy and operating speed of the protection devices meet the requirements. If the protection devices are outdated and cannot be upgraded, they need to be replaced; if the settings can be adjusted through setting calculations, no modification is necessary.

[0068] Measurement and Control Automation System: Verify the measurement range of the measurement and control device, such as the current and voltage measurement ranges, and whether the logic control of the automation system can adapt to the modified operating conditions. If the automation system lacks compatibility and cannot connect to the new equipment, the system needs to be upgraded; if only the measurement points need to be added, no overall modification is required.

[0069] 20) Determine the scope of the hydro-generator unit renovation and formulate the project renovation schedule and construction period.

[0070] Integrate all the review results from steps 12 to 19 to form the final list of renovation scopes, and formulate a project schedule: Final scope of modification: Identify components that must be modified, such as the impeller, main shaft, generator, IPB, and excitation transformer; components that do not require modification but need maintenance, such as cleaning the tailrace pipe and lubricating bearings; and structures that need reinforcement, such as the stator foundation. The list should include the component name, specifications, and modification method, including replacement / repair / reinforcement.

[0071] Schedule and Duration: Based on the power plant's power generation plan, such as avoiding flood season, peak load periods, and major unit overhaul windows (e.g., a 3-month overhaul every 5 years), a project schedule should be developed. For example, the project might be divided into three phases: preliminary preparation (preparation of tender documents and procurement), approximately 6 months; equipment manufacturing (manufacturing of core equipment such as turbine runners and generators), approximately 18 months; and on-site installation and commissioning (installation and commissioning of the first unit), approximately 7 months, for a total duration of approximately 31 months. The schedule should clearly define key milestones such as equipment factory acceptance and the time requirements for the first unit's grid connection.

[0072] 21) Based on the scope of the renovation and current prices, derive an estimated investment for the renovation.

[0073] Based on the final scope of the renovation, and taking into account current price levels, market quotations, and engineering quotas, an investment estimate for the renovation project should be prepared, requiring separate calculations for two scenarios: The estimated investment for capacity expansion and renovation includes: procurement costs for core equipment such as turbines, generators, and IPBs; civil construction costs such as foundation reinforcement and flow channel repair; installation and commissioning costs; design and supervision costs; spare parts costs; and contingency funds, which are typically 5% to 10% of the total investment. For example, the estimated total investment for capacity expansion and renovation of a 300MW unit is approximately 120 million yuan.

[0074] Investment estimate for renovation without capacity increase: After deducting the equipment and construction costs related to capacity increase (such as the cost of replacing the IPB and excitation transformer required for capacity increase, and the cost of foundation reinforcement solely due to capacity increase), the investment estimate for repairing existing problems without increasing the rated power is obtained. For example, the investment estimate for renovation without capacity increase is approximately 0.8 billion yuan.

[0075] 22) Based on the investment estimate, conduct an economic evaluation of the project based on the revenue generated by the increased power generation potential of the power station. If the unit does not increase its power generation potential, this step is not required.

[0076] Based on the investment estimate and post-capacity expansion revenue forecast from step 21, a dynamic economic evaluation method is used to determine the economic feasibility of the project. Revenue Calculation: Based on the annual power generation after capacity expansion and the annual power generation without capacity expansion predicted in step 6, the new power generation is calculated as follows: annual power generation after capacity expansion is 2.784 billion kWh, and without capacity expansion it is 2.761 billion kWh, resulting in a new generation of 0.23 billion kWh. In most provinces, the benchmark price for conventional hydropower is between 0.25 and 0.35 yuan / kWh. However, in the Southwest hydropower base, due to abundant water resources, the price is relatively low, ranging from 0.22 to 0.28 yuan / kWh. In the eastern provinces, due to scarce hydropower resources, the price is relatively high, ranging from 0.30 to 0.38 yuan / kWh. Combining this with the on-grid price of the power station, such as 0.3 yuan / kWh, the annual new revenue is calculated as 0.23 billion kWh × 0.3 yuan / kWh = 6.9 million yuan.

[0077] Cost calculation: Includes the investment in capacity expansion, i.e., the total investment in capacity expansion and renovation - the investment in renovation without capacity expansion, such as 120 million yuan - 80 million yuan = 40 million yuan, and the additional operation and maintenance costs after capacity expansion, such as an increase of 200,000 yuan per year.

[0078] Economic indicators were calculated as follows: The return on equity (ROE) and payback period (static / dynamic) were calculated using two schemes: a 100% equity plan (all investment funded by the power plant's own capital) and a 30% equity plan (70% investment funded by bank loans), with an annual interest rate of 4.35%. For example, the ROE was 8.5% under the 100% equity plan and 12.3% under the 30% equity plan.

[0079] Feasibility assessment: If the return on equity is higher than the industry benchmark return, such as 8% for hydropower projects, and the investment payback period is less than the remaining service life of the equipment, such as less than 20 years, then the capacity expansion and renovation plan is economically feasible; if not, the capacity expansion target needs to be reassessed or the renovation plan needs to be optimized to reduce costs.

[0080] 23) The final scope of power plant renovation, expected stability indicators, expected energy indicators, expected cavitation indicators, investment estimates for power plant renovation, and economic evaluation of the project are obtained, so that the power plant can make the final decision.

[0081] Based on the analysis results of all the above steps, a final feasibility study report is generated, which includes the following core contents: Final list of modifications: Clearly define the components and systems that must be modified and those that are not, as well as the structures that need to be reinforced, and indicate the modification methods and technical requirements.

[0082] Expected technical indicators include: expected stability indicators such as pressure pulsation and vibration swing value; expected energy indicators such as annual power generation and efficiency; and expected cavitation indicators such as cavitation coefficient and cavitation risk level. These indicators are compared with those before the upgrade to quantify the upgrade effect.

[0083] Investment and economic evaluation results: The results present detailed investment estimates for capacity expansion and renovation versus renovation without capacity expansion, as well as economic indicators such as ROE and investment payback period under different capital plans, and clearly define the conclusions on economic feasibility.

[0084] Risk warnings and suggestions: Analyze the technical risks that may be faced during project implementation, such as failure of model tests, economic risks such as cost overruns due to rising prices, and schedule risks such as delays in equipment manufacturing, and propose countermeasures such as conducting model tests in advance, signing fixed-price contracts, and setting up backup equipment suppliers.

[0085] Preferably, the data to be collected in step 1) is as follows: a) Collect daily average measured hydropower data for the power station, including time, inflow, reservoir level, tailrace level, outflow, turbine head, power station output, output of each unit, number of units in operation, and unit flow rate; collect reservoir operation schedules, actual tailrace flow relationship of the power station, and flood conditions in the downstream river; collect typical daily scheduling data and typical annual monthly scheduling data. b) Collect data on the vibration and sway of each unit under different upper and lower reservoir water levels and different unit outputs; collect data on major, intermediate, and minor overhauls of the units (including maintenance frequency, maintenance time, and specific maintenance content). c) Collect drawings and performance parameters of the hydro-turbine generator set and electrical equipment of the power station; collect information on the modification and changes of the water diversion and power generation system flow channel and hydraulic measurement points of the power station.

[0086] Preferably, in step 6), the capacity expansion target is determined using the following method: a) Based on the actual power plant data collected in step 1), predict the power generation of the power plant under different installed capacity schemes; b) Identify the inflection points of the curves showing the relationship between power generation and installed capacity under different predicted installed capacities; c) The installed capacity near this inflection point is the recommended installed capacity after the capacity increase.

[0087] Preferably, in step 7), the capacity expansion scheme is determined using the following method: a) Keep the runner diameter and rated head unchanged, and improve the unit parameter levels; b) Keep the rated head and unit parameters unchanged, and increase the runner diameter; c) Keep the runner diameter and unit parameters unchanged, and increase the rated head; d) There are two or more variations in the runner diameter, rated head, and unit parameter levels.

[0088] By comparing a) to d), check whether the capacity expansion target recommended in step 6) can be met. If it cannot be met, repeat steps 6) to 7) until it can be met.

[0089] The generator set retrofitting method and evaluation method of this invention can provide power plant management with a comprehensive and scientific basis for deciding whether to implement retrofitting, which retrofitting scheme to choose for capacity expansion, or only repair. It also provides technical guidance for subsequent bidding, procurement, and construction organization. The specific beneficial effects are as follows: 1. Strong systematicity: The modification method and evaluation method of this invention cover the entire process from parameter collection to scheme design, technical verification, economic evaluation and decision output. It breaks through the limitations of existing single component modification, and conducts multi-dimensional collaborative analysis from hydraulic, mechanical, electrical and structural dimensions to ensure the integrity and adaptability of the modification scheme.

[0090] 2. Technically reliable: This invention integrates CFD numerical simulation and physical model testing to dually verify the hydraulic performance and stability of the modification scheme. At the same time, through stiffness analysis and transient process verification, it ensures the safe operation of the modified unit and reduces technical risks.

[0091] 3. Excellent economic efficiency: This invention determines the optimal capacity expansion target through inflection point analysis, avoiding blind capacity expansion; it compares the investment and returns of capacity expansion and non-capacity expansion scenarios, quantifies economic feasibility, and ensures that the transformation project maximizes economic benefits on the basis of technical feasibility.

[0092] 4. Wide applicability: This invention is applicable to different types of hydro-generator units, such as mixed-flow and axial-flow types. It can provide customized analysis for different problems such as efficiency decline of old units, insufficient grid adaptability, and safety hazards. At the same time, it provides methods and processes that can be used for the upgrading and renovation of similar power plants. Attached Figure Description

[0093] Figure 1 This is an overall flowchart of the method of the present invention.

[0094] Figure 2 Here is an example of the relationship curve between the installed capacity and the predicted power generation of a power plant.

[0095] Figure 3 This is an example of a full-flow path calculation model for a power station turbine. Detailed Implementation

[0096] To make the technical solution and beneficial effects of the present invention clearer, the present invention will be further described in detail below with reference to the accompanying drawings and embodiments. However, these descriptions do not constitute a limitation on the present invention and are merely examples.

[0097] This invention provides a systematic research method for the upgrading and renovation of hydropower station turbine generator units, accurately predicting the scope of upgrading and renovation, and ultimately evaluating the renovation from technical and economic perspectives to support power plant decision-making. It also serves as a reference for the upgrading and renovation of similar power plants and can be widely applied in the field of hydropower generator unit technology. This invention mainly achieves the following functions: 1) Confirm the scope of the hydro-generator unit upgrade and renovation; 2) Evaluate the renovation from both technical and economic perspectives; 3) Provide decision-making solutions for power plants.

[0098] like Figure 1 As shown, this invention proposes a systematic feasibility study method for the upgrading and renovation of hydro-turbine generators. Taking a peak-shaving and frequency-regulating power station that has been in operation for many years as an example, the power station is equipped with four 300MW mixed-flow hydro-turbine generator units, with a total installed capacity of 1200MW. The power station intends to upgrade its capacity, hoping to maintain the existing flow channel layout and civil structure, the governor oil pressure level of 6.3MPa, and the generator voltage level of 18kV unchanged. The feasibility study method for the upgrading and renovation of the hydro-turbine generator units of this power station includes the following steps: 1) Collect daily average measured hydropower data for the power station, including time, inflow, reservoir level, tailrace level, outflow, turbine head, power station output, output of each unit, number of units in operation, and unit flow rate; collect reservoir operation schedule, actual tailrace flow relationship, and flood conditions in the downstream river; collect typical daily scheduling data and typical annual monthly scheduling data.

[0099] Collect data on the vibration and sway of each unit under different upper and lower reservoir water levels and different unit outputs; collect data on major, intermediate, and minor overhauls of the units (including maintenance frequency, maintenance time, and specific maintenance content).

[0100] Collect drawings and performance parameters of the hydro-turbine generator set and electrical equipment of the power station; collect information on the modification and changes of the water diversion and power generation system flow channel and hydraulic measurement points of the power station.

[0101] 2) Based on the situation of this power station, the unit's vibration and sway exceed the standard under low load. According to the statistics of the actual operation of the power station, the power station operates at 60% or less of the rated load for more than 60% of the time. In addition, the power station needs to have a strong frequency regulation and peak regulation capability. Therefore, it is recommended to replace the runner for this power station, and we will determine whether the movable guide vanes need to be replaced in subsequent steps.

[0102] Regarding the concept of "low load" in this invention, in the operating scenario of a hydro-generator unit, low load refers to the operating state where the actual output of the unit is lower than its rated output by a certain percentage. This means the actual power generation has not reached the design rated value, and it falls under the low-load operating condition. Generally, actual output ≤ 60% of rated output is defined as low load. This invention uses the unit's designed rated output as the benchmark. For example, a 300MW unit with an actual output ≤ 180MW is considered to be in a low-load operating state. It should be noted that low load is not a fixed value and needs to be considered in conjunction with the power station's dispatching requirements. In this invention, the power station emphasizes frequency and peak regulation capabilities and frequently operates in a low-output state; therefore, 60% of the rated output becomes the key dividing point for low load. Low output adjustments will occur when the power station's inflow is insufficient, the grid load demand is low, or peak and frequency regulation is needed. Vibration and excessive sway are typical hidden dangers of low-load operation. Because the hydraulic design of hydro-generator units is mostly optimized for rated load conditions, under low load, the water flow is prone to unstable flows such as vortices and pressure pulsations in the flow channel, which can lead to unit vibration and affect operational safety.

[0103] 3) The turbine of this power station needs to be replaced.

[0104] The power plant needs to replace the runner for the following two reasons.

[0105] First point: Step 2 of this invention explicitly mentions that, based on the conditions of this power station, the unit's vibration and sway exceed the standard under low load; and based on statistics of the actual operation of the power station, the proportion of the power station operating at 60% or below the rated load exceeds 60%. This is the direct technical basis for determining that the turbine runner needs to be replaced. First, the root cause of excessive vibration is strongly related to the turbine runner: the vibration of a hydro-generator unit, especially hydraulic vibration, mainly stems from the flow stability of water within the flow channel. The turbine runner is the core hydraulic conversion component within the flow channel, and its blade shape, angle, and surface condition directly determine the flow trajectory and pressure distribution of the water. When the unit is under low load, such as less than or equal to 60% of rated output, the water flow rate is relatively small. If the turbine runner design is not adapted to low flow conditions, such as a mismatch between the blade inlet angle and the low flow rate, it will cause the water flow to generate flow separation and vortices, such as blade passage vortices, on the surface of the turbine runner blades. This will then cause turbine runner vibration, which will be transmitted to the entire unit through the main shaft, resulting in excessive vibration and sway.

[0106] Secondly, the existing runner cannot meet the requirements for long-term stable operation. In the specific embodiment, the power station operates under low load for more than 60% of the time, indicating that low output conditions are the unit's normal operating state, not an occasional occurrence. If the original runner continues to be used, the vibration problem will persist, not only affecting the unit's service life (such as component fatigue damage) but also potentially triggering safety protection shutdowns, thus failing to guarantee a stable power supply to the power station. Therefore, replacing the runner is the core technical solution to address excessive vibration under low load conditions. This requires hydraulic optimization design of the new runner to adapt to low flow conditions and reduce unstable flow.

[0107] Secondly, the power plant has the functional objectives of increasing power generation potential and meeting peak shaving and frequency regulation needs, and the original turbine cannot match the new objectives.

[0108] The subsequent steps of this invention explicitly state that the power plant needs capacity expansion and upgrading, namely, increasing the installed capacity by 10% and possessing strong frequency regulation and peak shaving capabilities. This functional objective further dictates that the turbine runner must be replaced. First, the capacity expansion requires the turbine runner to adapt to higher energy conversion demands: the core of capacity expansion is to increase the rated output of the unit from 300MW to 335MW. The turbine runner is the core component of the turbine that converts water energy into mechanical energy. Its flow capacity, strength, and hydraulic efficiency directly determine whether the unit can achieve the capacity expansion target. The original turbine runner's design flow area and blade strength were based on the 300MW rated output and could not withstand the greater water flow impact and torque after the capacity expansion. The new capacity expansion target, which increases the rated head, requires a redesign of the turbine runner's blade angle and flow channel dimensions to adapt to the higher head conditions and ensure energy conversion efficiency. The subsequent steps of this invention were also verified through CFD simulation. The new turbine runner needs to work in conjunction with the capacity expansion scheme to achieve stable operation.

[0109] Secondly, the peak-shaving and frequency regulation requirements necessitate a wider range of operating condition adaptability for the turbine runner: As a peak-shaving and frequency regulation power station, the power plant needs to frequently switch between low load, rated load, and overload operation. The original turbine runner could only maintain stability under specific operating conditions, such as rated load, and its vibration exceeded the standard under low load, failing to meet the requirements of stable operation under a wide range of operating conditions for peak-shaving and frequency regulation. One of the core objectives of this invention in replacing the turbine runner is to broaden the load range for stable operation through hydraulic optimization of the new turbine runner, such as optimizing the blade profile and increasing the number of blades, ensuring that vibration can still be avoided during low-output peak-shaving, thus matching the grid dispatching requirements.

[0110] The existing impeller caused excessive vibration under low load, and this is the normal operating condition of the power plant. Without replacement, the safety hazard cannot be resolved. Capacity expansion and peak / frequency regulation requirements necessitate that the impeller exceed the original design limitations in terms of current carrying capacity and operating condition adaptability; the existing impeller cannot meet the new functional objectives. Therefore, based on step 2) and points one and two above, the conclusion is that the impeller needs to be replaced.

[0111] 4) By statistically analyzing the power station's inflow, outflow, and reservoir capacity, according to the formula: Inflow + Original reservoir capacity = Power generation water volume + Flood discharge + Waste water volume + Current reservoir capacity The daily water discharge from the power station is calculated, summed over the years, and then the average value over many years is taken as the multi-year average water discharge of the power station.

[0112] The inflow of water into the reservoir is calculated by summing the data annually and then taking the average value over many years. This average value represents the long-term average inflow of the power station.

[0113] The multi-year average water utilization rate is calculated using the following formula: (Average annual inflow - Average annual wastewater) / Average annual inflow × 100% = Average annual water utilization rate According to the formula, the average annual water utilization rate of this power station exceeds 90%, which is a high level.

[0114] We will compile monthly statistics on the power station's water discharge and analyze which months the water discharge mainly occurs. The power station's water discharge mainly occurs during the flood season.

[0115] In step 4) of this invention, the existence of potential for increasing power generation capacity was demonstrated in detail using power plant operation data. Specifically, the determination of whether the power generation potential could be increased was completed through three dimensions: analysis of water wastage, calculation of water utilization rate, and matching of peak-shaving demand. First, the water utilization rate is calculated to determine if there is energy waste: the daily water wastage of the power station is calculated, and the average value over many years is obtained by summing the daily amounts over the years. This is the average annual water wastage of the power station. The inflow of water into the reservoir is also calculated, and the average annual inflow is obtained by summing the inflow over the years. The average annual water utilization rate is calculated using the formula: (Average annual inflow - Average annual wastage) / Average annual inflow × 100%. The results show that the average annual water utilization rate of this power station exceeds 90%, indicating a high water utilization rate. A high water utilization rate means that the usable water under normal operating conditions has been fully converted into electrical energy. However, further analysis of the distribution of water wastage periods reveals that the wastage mainly occurs during the flood season, indicating seasonal energy waste. During the flood season, the inflow is large, but the existing installed capacity cannot fully absorb it, resulting in the wastage of some water. This provides a core basis for increasing the power generation potential and capacity. By increasing capacity, the wasted water during the flood season can be absorbed, converting the wasted water energy into electrical energy.

[0116] Secondly, considering the functional positioning of the power station, it is determined whether enhancing the power generation potential matches the requirements: This invention mentions that the power station needs to have strong frequency regulation and peak shaving capabilities, and the proportion of low-load operation exceeds 60%. Frequency regulation and peak shaving require the unit to have the ability to flexibly adjust its output. Enhancing the power generation potential, such as increasing capacity and optimizing hydraulic performance, can broaden the output range of the unit from the original 300MW to 335MW. This can provide higher output during peak grid loads and reduce vibration and improve peak shaving flexibility during low loads by optimizing the turbine design. This shows that enhancing the power generation potential is highly matched with the core functional requirements of the power station, and therefore, it is necessary to enhance the power generation potential.

[0117] Furthermore, the subsequent steps of this invention explicitly propose the need to enhance power generation potential and translate this into specific capacity expansion and renovation targets. Step 5 of this invention clearly states that, based on the actual situation of the power plant, the plant intends to expand its capacity. Capacity expansion and renovation can increase the generating capacity during the flood season, thereby improving the plant's efficiency. Capacity expansion and renovation is essentially a concrete path to enhance power generation potential, namely, increasing the installed capacity from 1200MW to 1320MW, transforming the abstract need to enhance power generation potential into an executable technical solution. Subsequent steps 6 (determining the capacity expansion target) and 7 (determining the capacity expansion plan) are both based on the judgment that there is a need to enhance power generation potential.

[0118] 5) Based on the actual situation of the power plant, the power station intends to expand its capacity. Therefore, capacity expansion and renovation can be carried out to enable the units to generate more electricity during the flood season and improve the efficiency of the power station.

[0119] The power grid allows the power plant to be upgraded to 1320MW, and the revenue from the upgrade is expected to cover the costs. Therefore, the upgrade is carried out, and the process proceeds to step 6.

[0120] 6) Based on statistical data, with the current installed capacity of the power station at 1200MW, the actual power generation is 2.757 billion kWh. The predicted power generation without capacity increase after the renovation is 2.761 billion kWh. After a 5% capacity increase, the power generation is 2.778 billion kWh. After a 10% capacity increase, the power generation is 2.784 billion kWh. After a 12% capacity increase, the power generation is 2.786 billion kWh.

[0121] A curve showing the relationship between installed capacity and projected power generation is attached. Figure 2 , Figure 2 The figure shows an example of the relationship between the installed capacity and the predicted power generation of a power plant. The horizontal axis represents the installed capacity (MW), and the vertical axis represents the multi-year average power generation (10,000 kWh). The inflection points of the curve and the corresponding recommended capacity expansion are marked.

[0122] The inflection point will occur around 1320MW of installed capacity, at which point the target of a 10% increase in capacity will be set.

[0123] 7) Based on the renovation principles and the power plant's requirements, this power station can be divided into the following capacity expansion schemes: a) Keep the runner diameter and rated head unchanged, and improve the unit parameter levels; b) Keep the rated head and unit parameters unchanged, and increase the runner diameter; c) Keep the runner diameter and unit parameters unchanged, and increase the rated head; d) The turbine runner diameter, rated head, and unit parameter levels have two or more variations; By comparing options a) to d), all four options can achieve the 10% capacity increase requirement recommended in step 6).

[0124] We collected recommended parameters from manufacturers of main units for similar projects, compared four options (a) to (d), and determined that option (c) was recommended to be used, which maintains the turbine diameter and unit parameters unchanged while increasing the rated head, and option (10% increase in power generation potential).

[0125] The specific implementation of this invention clarifies the prerequisites for the power plant renovation: it is desired that the existing flow channel layout and civil structure remain basically unchanged, the governor oil pressure level remains unchanged at 6.3MPa, and the generator voltage level remains unchanged at 18kV. These are the primary constraints for selecting scheme c, and scheme c happens to meet these constraints. First, no changes are needed to the existing flow channels and civil structures: Since the runner diameter remains unchanged, key dimensions within the flow channels that mate with the runner, such as the volute outlet diameter and the tailrace inlet diameter, do not require adjustment. Existing flow channel layouts, such as those in the water diversion and power generation system mentioned in step 1, can be completely reused, avoiding large-scale projects like channel excavation and civil structure reconstruction. Such projects are not only costly and prolong the construction period but may also affect the safety of the original power station structure. Increasing the rated head essentially optimizes the energy utilization efficiency of the water flow, requiring no changes to the physical form of the flow channels. It can be achieved through hydraulic design optimization, such as adjusting the runner blade profile, rather than dimensional adjustments, perfectly aligning with the constraints of the existing civil structures remaining largely unchanged.

[0126] Secondly, there is no need to adjust the parameters of key auxiliary equipment: if the unit parameters remain unchanged, such as the speed and efficiency design benchmark, the design parameters of existing equipment such as the governor oil pressure level of 6.3MPa and the generator voltage level of 18kV can remain unchanged, without the need to replace the core components of the governor and generator. If option b is chosen to increase the diameter of the runner, it will lead to an increase in the torque of the unit, which may require upgrading the governor to match the greater operating force; option d, with its multiple parameter changes, is more likely to exceed the limitations of the equipment parameters.

[0127] Option C's technical approach better aligns with the goal of increasing power plant capacity by 10%, and avoids the technical risks associated with other options. Specifically, this is reflected in: The core capacity expansion requirement of the power plant in this invention is to generate more electricity during the flood season. During the flood season, the reservoir water level is higher and the head is greater. Increasing the rated head can perfectly meet this operating condition: increasing the rated head means that the turbine can operate stably under a higher head, and the energy conversion efficiency per unit volume of water is higher. Based on the CFD simulation results in step 10, this scheme can achieve a 10% capacity expansion and the hydraulic stability is better than the existing units, which verifies its technical feasibility. If scheme a is chosen, which only improves the unit parameter level, it may not be able to meet the 10% capacity expansion due to the limited space for parameter optimization. Scheme b, which increases the runner diameter, may lead to a mismatch in the flow area of ​​the water in the channel, causing new vibration problems. If option b is chosen to increase the runner diameter, all components related to the runner within the flow channel, such as the volute, seat ring, and tailrace pipe, need to be adjusted simultaneously. However, step 13 of this invention requires that non-essential components, such as the volute, seat ring, and tailrace elbow pipe, only have slightly excessive local stress. If the runner diameter is forcibly changed, it may lead to aggravated stress exceeding the standard in these components, which would need to be included in the scope of mandatory modification, increasing technical complexity. Option c does not require changing the runner diameter and can be directly optimized based on the hydraulic characteristics of the existing runner, reducing the risk of "adapting new components to the old flow channel." Furthermore, the model test in step 11 can further verify the stability after the head increase, making the technical risks more controllable.

[0128] Option C, while meeting the capacity expansion target, minimizes modification costs, shortens the construction period, and improves project economics. Since the runner diameter and unit parameters remain unchanged, Option C requires no replacement of the runner itself, only optimization of the blade profile, governor, and core generator components. It also eliminates the need for civil engineering modifications. Compared to Option B, which requires modifications to the runner and flow channel components, and Option D, which involves multiple parameter changes and component replacements, Option C significantly reduces the scope of necessary modifications and lowers investment costs. The low cost of Option C is a crucial prerequisite for achieving this economic advantage; excessively high modification costs could lead to unmet return on investment. Option C eliminates the need for large-scale civil engineering construction and flow channel modifications, allowing it to be completed within the existing overhaul window. Option C only requires replacing the optimized runner blades and adjusting hydraulic parameters, while Options B and D, involving more component replacements and civil engineering adjustments, may exceed the overhaul period, impacting the power plant's power generation revenue.

[0129] 8) Since there are downstream power stations, but the capacity expansion only changes the spatiotemporal distribution of water flow, based on data from downstream power stations, it is predicted that it will not increase the amount of water abandoned by downstream power stations. For example, if the downstream power station is a run-of-river power station, the discharge flow during the flood season will remain unchanged after the capacity expansion, and only the abandoned water will be utilized, which will have no impact on the amount of abandoned water or power generation downstream. Therefore, the capacity expansion of this power station will have no impact on downstream power stations.

[0130] 9) Based on the increased rated head after the capacity expansion and renovation of this power station, and the parameters of the unit after the renovation, the weighting factor of the turbine after the capacity expansion and renovation is analyzed.

[0131] Based on the obtained turbine weighting factor and the requirements of relevant specifications, requirements are put forward for the pressure pulsation of the draft tube, the pressure pulsation of the bladeless area behind the guide vane and in front of the runner, and the pressure pulsation of the volute measuring point.

[0132] Based on the current operating conditions of the power plant, it is proposed that the ratio of the power plant's cavitation coefficient to the primary cavitation coefficient should not be less than 1.05, and the ratio of the power plant's cavitation coefficient to the critical cavitation coefficient should not be less than 1.55. It is proposed that primary blade passage vortices should not appear in the power plant area at or above 30% of the expected output, and visible Karman vortices are not allowed.

[0133] The power output guarantee value of the power station is proposed, namely, the rated power of the power station under the new rated head is 335MW, and the minimum head at which the turbine generates 335MW of power. The power station's efficiency guarantee values ​​are proposed, namely, that the rated efficiency of the prototype turbine is not less than 92.5% at rated head and rated power, and the efficiency of the model turbine at the corresponding operating point is not less than 90.8%. In the entire operating range, the highest efficiency of the prototype turbine is not less than 95.5%, and the efficiency of the model turbine at the corresponding operating point is not less than 94.5%.

[0134] 10) Model the flow channel, see appendix. Figure 3 , Figure 3 This is an example of a full-flow path calculation model of a power station turbine built using ANSYS 2020R1 software. The figure shows the positions and dimensions of various components of the flow path, including the volute, guide vanes, runner, and draft tube, at a scale of 0-1.0m, for CFD simulation analysis. Full-flow path CFD analysis was performed under 14 operating conditions: optimal operating condition before and after modification, maximum head rated output operating condition before and after modification, rated head rated output operating condition before and after modification, minimum head guaranteed output operating condition before and after modification, maximum head 30% rated output operating condition before and after modification, rated head 30% rated output operating condition before and after modification, and minimum head 30% rated output operating condition before and after modification.

[0135] Analysis indicates that the upgraded power station is expected to achieve a 10% capacity increase and will outperform the existing turbines in terms of hydraulic stability. However, the cavitation safety margin is relatively small. Appropriate measures can be taken to enhance the unit's resistance to cavitation during wide-load operation. Replacing the movable guide vanes is recommended.

[0136] 11) Turbine model test. This step can also be completed after the unit modification bidding.

[0137] 12) Based on the above analysis, the scope of the turbine that must be modified includes the runner, main shaft, movable guide vanes, and guide vane servo. Due to the generator's own problems, the entire generator needs to be replaced. If only the turbine is modified without increasing its capacity, then the guide vane servo does not need to be replaced.

[0138] The turbine runner is a core component for solving vibration problems and adapting to capacity expansion targets. Step 2 clearly shows that the unit's vibration exceeds the standard under low load, and the proportion of low load operation exceeds 60%. The root cause of the vibration is that the original turbine runner hydraulic design is not adapted to the flow separation under low flow conditions, and the vibration is caused by impeller vortices. Step 10's CFD simulation verifies that replacing and optimizing the turbine runner can solve the vibration problem and meet the hydraulic stability requirements of a 10% capacity expansion. If the turbine runner is not replaced, the vibration problem will continue to exist, and the high load operation after capacity expansion may also aggravate the fatigue damage of the turbine runner, directly affecting the safety of the unit. Therefore, the turbine runner must be modified.

[0139] The main shaft is designed to meet the increased torque requirements after capacity expansion. A 10% capacity increase means that the rated output of the unit increases from 300MW to 335MW. As the core component that transmits the mechanical energy of the turbine to the generator, the main shaft needs to withstand greater torque, which is positively correlated with the output. The original main shaft was designed to match the 300MW output. After the capacity expansion, the torque exceeds the original design limit. If it is not replaced, it may lead to serious safety accidents such as deformation and breakage of the main shaft. Therefore, the main shaft needs to be modified synchronously with the turbine to match the increased load requirements after capacity expansion.

[0140] The movable guide vanes are used to optimize water flow regulation and adapt to the hydraulic characteristics of the new impeller. The CFD simulation in step 10 indicates that the cavitation safety margin is small after the modification, and it is recommended to replace the movable guide vanes. The function of the movable guide vanes is to regulate the flow rate and angle of the water entering the impeller. The profile and angle of the original guide vanes do not match the hydraulic design of the new impeller. The new impeller is adapted to a higher head, and the guide vanes need to provide a more stable water inflow angle. If the movable guide vanes are not replaced, the water flow will be deflected when entering the impeller, which will aggravate the cavitation problem and even affect the output stability after the capacity increase. Therefore, the movable guide vanes must be modified.

[0141] The guide vane relay is designed to adapt to the adjustment requirements of the movable guide vane and the increased operating force after capacity expansion. The guide vane relay is the actuator that drives the movable guide vane. Its thrust must match the resistance of the movable guide vane. The replacement movable guide vane may have changes in resistance due to hydraulic design optimization such as profile adjustment. In addition, the increased water pressure after capacity expansion requires greater thrust to stably adjust the guide vane. Under the target of capacity expansion, the original relay thrust is insufficient. Therefore, the guide vane relay needs to be modified synchronously with the movable guide vane.

[0142] If early inspections reveal inherent defects in the generator that cannot be resolved through partial repairs, such as aging stator windings, degraded insulation performance (making the insulation unable to withstand the increased voltage / current load), excessive rotor core losses that cannot be restored by partial repairs, or severe bearing wear (frequent low-load operation may lead to poor bearing lubrication, exceeding the repair threshold, and continued use will cause vibration and overheating problems), then partial repairs are not only costly, requiring disassembly of core generator components and resulting in a long repair cycle, but may also fail to meet the increased capacity requirements. Therefore, complete replacement is more feasible than partial repairs. Furthermore, a 10% increase in capacity means the generator needs to output a higher rated power, from 300MW to 335MW. This places new demands on the generator's core electrical performance, including an increase in stator rated current. The power increase requires a corresponding increase in current, and the original stator winding conductor cross-sectional area and number of turns design cannot withstand the higher current, which can lead to overheating and burnout of the windings. Excitation system adaptation: After the capacity increase, a stronger excitation magnetic field is required to maintain voltage stability. The original excitation winding and excitation transformer cannot meet the requirements. Moreover, the excitation system is highly integrated with the generator body, and partial replacement may lead to compatibility issues. If the entire generator is not replaced and only electrical auxiliary equipment such as the excitation system is modified, the generator body performance bottleneck will appear, making it impossible to achieve the rated output of 335MW, and the capacity increase target will not be achieved. Therefore, replacing the entire generator is the choice to adapt to the capacity increase requirements.

[0143] 13) Analyze the stress on non-essential components to determine whether the existing non-essential components meet the requirements after capacity expansion.

[0144] Non-essential modification components include the spiral casing seat ring, foundation ring, draft tube cone, draft tube elbow, draft tube inlet valve, and elbow valve inlet valve. The rigidity and strength of these components were analyzed. The analysis revealed that the draft tube inlet valve and elbow valve do not meet the requirements after the capacity expansion modification and need to be replaced. The seat ring and draft tube elbow valve experience slightly excessive local stress under certain operating conditions and do not require replacement; further verification will be conducted during the turbine generator unit procurement phase.

[0145] 14) The structural bearing capacity shall be reviewed in accordance with the specifications and taking into account the long-term design conditions, short-term design conditions and accidental design conditions.

[0146] After review, the local compressive bearing capacity of the component met the requirements; however, under a brief design condition, the shear bearing capacity of the component exceeded the structural bearing capacity. Therefore, the tangential force under this condition will be specified in subsequent procurement stages, and the foundation will be reinforced if necessary.

[0147] 15) Because the power station is hot in summer, the generator adopts a closed self-circulating air cooling method. After the capacity is increased, it is calculated that the total air volume generated by the motor structure can meet the motor cooling needs.

[0148] 16) Upon review, the speed control system, plant lifting equipment, oil equipment, technical water supply equipment, and gas system all require no modification. Only some corroded pipe fittings need to be replaced.

[0149] 17) After the power plant capacity was increased, the power plant transition process was reviewed. The review confirmed that the guide vanes used a single-stage pressure shut-off, and that the unit speed increase rate, volute pressure, and tailrace inlet vacuum all met the requirements.

[0150] 18) Upon review of the primary electrical equipment, it was found that the rated current of the IPB does not meet the requirements for capacity expansion and renovation, therefore the IPB needs to be replaced; if only renovation is performed without capacity expansion, then the IPB does not need to be replaced.

[0151] 19) Upon review of the secondary electrical equipment, it was found that the excitation peak voltage multiple needs to be increased to 2.0, and the excitation transformer and demagnetizing resistor do not meet the requirements for capacity expansion and need to be replaced; if only the expansion is carried out without capacity increase, then no replacement is required.

[0152] 20) Based on the scope of the renovation, it is planned to utilize the unit overhaul time for the renovation, which will take approximately 31 months from the preparation of the tender documents to the first unit generating electricity.

[0153] 21) Based on the scope of the renovation and current prices, derive the investment estimate required for capacity expansion and renovation, as well as the investment estimate required for renovation without capacity expansion.

[0154] 22) After the power station's capacity is increased by 10%, it is expected to generate approximately 2.784 billion kWh of electricity. Compared with the power station's capacity increase of 2.761 billion kWh, the power station can generate an additional 0.23 billion kWh of electricity. Multiplying this by the power station's grid connection price gives the economic benefits that the increased capacity can generate.

[0155] The investment for capacity expansion is the investment required for capacity expansion and modification minus the investment required for modification without capacity expansion, namely the cost of guide vane servo, IPB, excitation transformer, and demagnetizing resistor. The additional investment for capacity expansion only calculates the cost of the four types of components that need to be replaced / modified due to capacity expansion: guide vane servo, IPB, excitation transformer, and demagnetizing resistor. It does not include basic costs required for modification without capacity expansion. The investment is divided into two scenarios: the first is modification without capacity expansion, which only addresses existing problems such as unit aging and excessive vibration, without increasing the installed capacity. In this case, the above four types of components do not need to be replaced, corresponding to a basic investment. The second is capacity expansion and modification, which, in addition to addressing existing problems, achieves an additional 10% capacity increase. Capacity expansion requires the replacement of the above four types of components, such as guide vane servo adapting to greater regulating force and IPB rated current meeting the requirements after capacity expansion, corresponding to a total investment. In this invention, deducting the cost of guide vane servo, IPB, excitation transformer, and demagnetizing resistor essentially calculates the investment specifically for capacity expansion. Dedicated investment for capacity expansion = Total investment in capacity expansion and renovation - Basic investment for renovation only without capacity expansion The difference between the two figures represents the procurement and installation costs of the four types of components that only need to be replaced during capacity expansion and not required for non-capacity expansion. This is equivalent to separately calculating the additional cost required to generate an extra 0.23 billion kWh of electricity. This ensures that the economic evaluation focuses solely on the benefits and costs of the capacity expansion, resulting in a more accurate assessment. During the economic evaluation, the result of multiplying the additional 0.23 billion kWh of revenue from capacity expansion by the grid connection price is compared with the dedicated investment for capacity expansion. This allows for an accurate judgment on whether the capacity expansion decision is worthwhile, avoiding the inclusion of infrastructure upgrade costs in the capacity expansion calculation, which could lead to misjudgment. The annual additional power generation is 0.23 billion kWh, with an annual revenue of 6.9 million yuan; the ROE for 100% equity is 8.6%, and the ROE for 30% equity is 12.5%, both exceeding the benchmark rate of return by 8%, indicating economic feasibility.

[0156] An economic evaluation was conducted on the capacity expansion portion, using both 100% and 30% equity capital schemes. The return on equity (ROE) for both schemes was higher than the benchmark return on equity (ROE) of 8%. Based on the two financial evaluation schemes, the capacity expansion and renovation scheme is feasible.

[0157] In this invention, the 100% equity investment scheme and the 30% equity investment scheme are two financial evaluation scenarios based on the structure of project funding sources. The 100% equity investment scheme, also known as the fully self-funded model, means that all investment funds for the project come from the power plant's own capital, without relying on any external financing such as bank loans or bond issuance. The 30% equity investment scheme means that the project's investment funds consist of two parts: 30% of the total investment comes from the power plant's own capital, and the remaining 70% is financed through external financing, such as long-term bank loans, with interest payments required according to the agreement. The main difference between the two schemes lies in whether financing costs are included in the calculation logic of return on equity (ROE), which directly affects the practicality of the economic evaluation conclusions. In the economic evaluation of hydropower projects, such as unit renovation, using only one scenario can lead to a one-sided conclusion. Choosing two scenarios allows for a more comprehensive verification of project feasibility. The specific reasons are as follows: Using only the 100% equity investment scenario may overestimate the project's actual return on investment. While fully self-funded investment incurs no interest costs and a relatively high ROE, in reality, few companies invest entirely with their own funds, making the conclusion unrealistic. Using only the 30% equity investment scenario may underestimate the project's risk resistance. If future loan interest rates rise, interest expenses will increase, requiring verification of whether the ROE can still cover the benchmark even under high financing costs. According to the "Methods and Parameters for Economic Evaluation of Construction Projects," large fixed asset investment projects such as hydropower unit renovation require at least two scenarios: "fully equity investment" and "self-funded investment + financing." This invention employs two scenarios to comply with industry standards, ensure the compliance and rigor of the economic evaluation conclusions, and avoid conclusions that are not accepted due to missing evaluation dimensions.

[0158] In this invention, the project's return on equity (ROE) calculated by the two equity calculation schemes is higher than the benchmark return on equity (ROE) of 8%. Based on the two financial evaluation schemes, the capacity expansion and renovation scheme of this invention is feasible. The calculation method of ROE is existing technology and will not be described in detail here.

[0159] 23) Based on the above conclusions, the power plant makes a decision.

[0160] Output the basis for decision-making, form a report, recommend the adoption of the 10% capacity increase renovation plan, clarify the scope of renovation, technical indicators, investment and economic conclusions, and indicate the risk of equipment manufacturing delays.

[0161] Obviously, those skilled in the art can make various modifications and variations to this invention without departing from its spirit and scope. Therefore, if these modifications and variations fall within the scope of the claims of this invention and their equivalents, this invention also intends to include these modifications and variations.

[0162] The contents not described in detail in this specification are existing technologies known to those skilled in the art.

Claims

1. A method of updating and evaluating a hydroelectric generating unit, characterized in that, The method comprises the following steps: 1) Collecting power station and unit parameters, including water energy and scheduling data, operation and maintenance data, equipment and structure data; 2) Preliminarily judging water-turbine-generator unit reconstruction range according to unit maintenance condition, power station operation condition, unit vibration and swing condition; 3) Judging whether the reconstruction contains a runner, if yes, entering step 4), if not, entering step 12); 4) Judging whether the power generation potential needs to be improved based on power station operation data, through water abandonment quantity analysis, water quantity utilization rate calculation and peak regulation demand matching, if yes, entering step 5), if not, entering step 9); 5) Judging whether capacity expansion reconstruction is needed in combination with actual power plant demand and power generation potential improvement target, if yes, entering step 6), if not, entering step 8); 6) Determining capacity expansion target: predicting power generation capacity under different installed capacity schemes according to actual power station data collected in step 1); drawing a curve of predicted power generation capacity and installed capacity, finding out a curve inflection point, and taking installed capacity near the inflection point as recommended installed capacity after capacity expansion; 7) Preparing multiple alternative capacity expansion schemes, comparing multiple capacity expansion schemes, rechecking whether the capacity expansion target in step 6) is met, if not, repeating steps 6) to 7) until a capacity expansion scheme meeting the requirement is determined; 8) If there is a downstream power station, rechecking the influence of the capacity expansion scheme on downstream power station water abandonment quantity, power generation capacity and operation safety in combination with downstream power station operation data and water demand, if there is an adverse influence, adjusting the capacity expansion scheme; 9) Proposing power station operation weighted factor, pressure pulsation index, cavitation index, blade passage vortex control requirement, karman vortex control requirement, output guarantee value and efficiency guarantee value after reconstruction; 10) Carrying out simulation analysis on the water-turbine flow passage, predicting the capacity of stable operation of the unit, and judging whether the movable guide vane needs to be replaced; 11) Carrying out water-turbine model test, comparing test results with index requirements proposed in step 9), if not meeting the requirements, returning to step 10) to adjust simulation parameters or optimize the design scheme and then retesting; if meeting the requirements, executing step 12); 12) Obtaining the range of water-turbine-generator units that must be reconstructed and the range of non-must-reconstruct parts based on analysis results of steps 2) to 11); 13) If the unit needs to improve the power generation potential, carrying out rigidity analysis on non-must-reconstruct parts, if there is a part not meeting the rigidity requirement, including it in the must-reconstruct range; 14) If the unit needs to improve the power generation potential, rechecking the bearing capacity of the stator foundation structure considering permanent design condition, short-term design condition and accidental design condition, if not meeting the requirement, taking reinforcement measures; 15) If the unit needs to improve the power generation potential, calculating the heat generation of the generator after capacity expansion, rechecking the total air volume and cooling efficiency of the ventilation and cooling scheme, if not meeting the requirements, strengthening ventilation and cooling; 16) Rechecking water-turbine governing system, power plant hoisting equipment, oil system, gas system and water system, and determining the parts that must be reconstructed among them; 17) Rechecking the speed rise rate, spiral case pressure and tailrace inlet vacuum degree of the unit in the process of starting, stopping and load adjustment transition after reconstruction, and ensuring that the requirements of the specifications are met. 18) Review the rated current, rated voltage and breaking capacity of the electrical primary equipment, and determine the equipment that needs to be replaced or modified; 19) Review the functions and parameters of the electrical secondary equipment, and determine the equipment that needs to be replaced or modified; 20) Integrate the results of steps 12) to 19), determine the final modification scope, and combine the power plant generation plan and the unit overhaul window to develop the project modification schedule and duration; 21) According to the final modification scope and the current price, respectively calculate the investment estimate under the scenarios of capacity expansion modification and only modification without capacity expansion; 22) If the unit needs to improve the power generation potential, calculate the economic benefits according to the investment estimate and the additional power generation capacity and the on-grid electricity price after capacity expansion, calculate the project capital return rate using different capital ratio schemes, and judge the economic feasibility; 23) Output the final modification scope, expected stability index, expected energy index, expected cavitation index, modification investment estimate and project economic evaluation results to provide a basis for power plant decision-making.

2. The method for updating and evaluating a hydroelectric generating unit according to claim 1, characterized in that: The water energy and dispatching data collected in step 1) include but are not limited to daily average water energy measured data of the power station, reservoir dispatching operation diagram, actual tail water flow relationship of the power station, flood situation of the downstream river channel of the power station, typical day dispatching situation, typical year monthly dispatching situation; operation and maintenance data include but are not limited to vibration and runout data of each unit at different upper and lower reservoir water levels, different unit outputs of the power station, frequency, time and specific content of unit overhaul, intermediate repair and minor repair; equipment and structure data include but are not limited to drawings and performance parameters of the water turbine generator unit and electrical equipment of the power station, flow channel of the power station water diversion and power generation system, modification and change of water quantity measurement points.

3. The method for updating and evaluating a hydroelectric generating unit according to claim 1, characterized in that: The multiple capacity expansion schemes in step 7) include a) maintaining the runner diameter and rated water head unchanged and improving the unit parameter level; b) maintaining the rated water head and unit parameter level unchanged and improving the runner diameter; c) maintaining the runner diameter and unit parameter level unchanged and improving the rated water head; d) two or more of the runner diameter, rated water head and unit parameter level change; if all schemes do not meet the capacity expansion target, return to step 6) to adjust the capacity expansion target and then determine the capacity expansion scheme again.

4. The method for updating and evaluating a hydroelectric generating unit according to claim 1, characterized in that: The cavitation index requirement in step 9) is that the ratio of the power station cavitation coefficient to the initial cavitation coefficient is not less than 1.05, and the ratio of the power station cavitation coefficient to the critical cavitation coefficient is not less than 1.

55.

5. The method for updating and evaluating a hydroelectric generating unit according to claim 1, characterized in that: The control requirement of the blade passage vortex and Karman vortex in step 9) is that the initial blade passage vortex does not appear at 30% of the expected output and above, and visible Karman vortex is not allowed to appear in the operating range.

6. The method for updating and evaluating a hydroelectric generating unit according to claim 1, characterized in that: The simulation analysis of the water turbine flow channel in step 10) is a numerical simulation analysis of the water turbine flow channel using computational fluid dynamics (CFD). The CFD simulation analysis working conditions include the optimal working condition, the maximum water head rated output working condition, the rated water head rated output working condition, the minimum water head guaranteed output working condition, and the 30% rated output small load working condition at each water head, a total of not less than 10 groups of working conditions.

7. The hydroelectric generator unit retrofit and evaluation method of claim 1, wherein, The review working conditions of the transition process in step 17) include shedding 100% rated load and 50% rated load at the rated water head of the unit, and starting and stopping at the minimum water head.

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