Power generation main body benefit evaluation method for multi-market combined clearing

Abstract

The invention discloses a power generation main body benefit evaluation method for multi-market joint clearing. The method comprises the following steps: calculating a system inertia demand and a primary frequency modulation demand through frequency change rate constraint, transient frequency extreme value constraint and quasi-steady-state frequency constraint; a settlement price is represented by a partial derivative of a required service through a Lagrange function, a benefit evaluation model with economic benefit maximization as a target is constructed, bid amount constraints of a power generation main body in a primary frequency modulation market, an inertia market and an electric energy market are set, optimal configuration of inertia and primary frequency modulation resources is realized through dynamic frequency security constraints, and the optimal configuration of the inertia and primary frequency modulation resources is realized. The power purchase cost is minimized based on market joint clearing, and three resources of electric energy, inertia and primary frequency modulation are reasonably configured. The new energy unit is stimulated to participate in the inertia and primary frequency modulation market, the system frequency response capability is improved, reliable economic benefit analysis is provided for power generation enterprises, resource configuration optimization and market strategies of the power generation enterprises are supported, and the market competitiveness of power generation subjects is improved.

Description

Technical Field

[0001] The present invention relates to the field of electric power technology, and in particular to a method for evaluating the benefits of power generation entities in multi-market joint clearing. Background Art

[0002] As the global climate change problem becomes increasingly serious, countries have proposed the goals of "carbon peak" and "carbon neutrality". Under the guidance of the "dual carbon" goal, the proportion of new energy has increased year by year. However, under the conventional control strategy, the output power and frequency of new energy units are decoupled. Therefore, when a large power shortage occurs in the system, the new energy units cannot respond to the frequency, and the frequency stability of the power system faces an important test.

[0003] Inertia and primary frequency regulation play an important role in maintaining the stability of the power system, and it is imperative to introduce the inertia and primary frequency regulation market. At present, the research on new auxiliary service markets such as inertia and primary frequency regulation is in its infancy. In the primary frequency regulation market, some studies have proposed primary frequency regulation auxiliary services suitable for energy storage, and constructed a joint clearing mechanism of electric energy-primary frequency regulation auxiliary services taking into account energy storage. The results show that the introduction of primary frequency regulation services can provide system frequency stability. In addition, based on the review of foreign frequency regulation auxiliary service market mechanisms, some studies have proposed a safety-constrained unit combination model for joint optimization and clearing of primary and secondary frequency regulation considering dynamic frequency constraints, which verifies that the joint clearing of primary and secondary frequency regulation not only achieves effective utilization of resources, but also improves the system frequency response capability.

[0004] In terms of the inertia market, some studies have studied the inertia market from the perspective of the capacity market, and achieved the construction goal of giving full play to the allocation of market resources by optimizing the market design. Other studies have designed a special virtual inertia market mechanism for renewable energy units, but this market mechanism is independent of the power system operation constraints, and its actual applicability has certain limitations. The above studies have made certain contributions to the research on inertia and primary frequency regulation markets, but they have only conducted independent research on the primary frequency regulation market and the inertia market.

[0005] Traditional frequency regulation markets all use SCED to clear the price of frequency regulation resources, which has certain limitations, namely, it cannot reflect the scarcity of frequency regulation resources when the output of new energy is large. The dynamic frequency evolution of the system after a large power shortage is reasonably simplified and further deduced, pointing out that inertia and primary frequency regulation both play a role in suppressing frequency changes after a large disturbance occurs in the system, and to a certain extent, primary frequency regulation and inertia have a mutual substitution relationship. Therefore, there are deficiencies in conducting independent research on the primary frequency regulation market and the inertia market.

[0006] At present, there is a lack of research on the benefit evaluation method of power generation entities based on the joint clearing of multiple markets for electric energy, frequency regulation and inertia. The literature has studied the benefit evaluation method of power generation entities in the electric energy and peak-shaving markets, but a complete benefit evaluation method for power generation entities based on the joint clearing of multiple markets for electric energy, frequency regulation and inertia has not yet been formed. Summary of the invention

[0007] The purpose of the present invention is to provide a method for evaluating the benefits of power generation entities in a multi-market joint clearing process.

[0008] To achieve the above object, the present invention is implemented according to the following technical solutions:

[0009] The present invention comprises the following steps:

[0010] S1: Market demand analysis: Calculate the system inertia demand and primary frequency modulation demand to obtain the minimum inertia value and the minimum primary frequency modulation value respectively; determine the specific demand through frequency change rate constraint, transient frequency extreme value constraint and quasi-steady-state frequency constraint;

[0011] S2: Market clearing price calculation: The partial derivative of the Lagrangian function of the Lagrangian multiplier method with respect to the required service is used to express the settlement price, and the expressions for the electric energy price, inertia price and primary frequency regulation price are obtained;

[0012] S3: Establishment of benefit evaluation model for power generation entities: Construct a benefit evaluation model with the goal of maximizing economic benefits; the objective function includes the bidding amount of the power generation entity in the electric energy, inertia and primary frequency regulation market, as well as the power generation marginal cost coefficient of the power generation entity;

[0013] S4: Constraint setting: Set the bidding constraints of power generation entities in the primary frequency regulation market, inertia market and electric energy market; power generation entities need to reserve some power generation space to provide inertia and primary frequency regulation to ensure that the sum of the bidding amounts is within the maximum power generation range;

[0014] S5: Optimize resource allocation: Consider the substitution relationship between inertia and primary frequency regulation, and achieve the optimal allocation of inertia and primary frequency regulation resources through dynamic frequency safety constraints; minimize the electricity purchase cost based on market joint clearing, and reasonably allocate the three resources of electric energy, inertia and primary frequency regulation.

[0015] The beneficial effects of the present invention are:

[0016] The present invention is a method for evaluating the benefits of power generation entities by joint clearing of multiple markets. Compared with the prior art, the present invention has the following beneficial effects: inertia and primary frequency regulation have a substitution relationship to a certain extent, and the inertia and primary frequency regulation markets are cleared independently. Although the system frequency response capability can be enhanced, it causes a waste of inertia and primary frequency regulation resources. Taking into account the mutual coupling of electric energy, inertia, and primary frequency regulation, a dynamic frequency safety constraint is constructed on the basis of considering the substitution relationship between inertia and primary frequency regulation resources, and a reasonable characterization of the demand for inertia and primary frequency regulation resources is achieved. Through the joint clearing of the electric energy-inertia-primary frequency regulation market, while minimizing the cost of purchasing electricity, the three resources of electric energy, inertia, and primary frequency regulation are reasonably and economically allocated, the system frequency response capability is enhanced, and the risk of cutting generators and loads when a large power shortage occurs in the system is reduced. In addition, the traditional primary frequency regulation service market uses the SCED model to price resources, which cannot reflect the scarcity of frequency regulation resources when the output of new energy is large. The present invention uses the Lagrangian function to reasonably price the inertia and primary frequency regulation market resources, and performs price clearing in the continuous SCUC. The pricing method used to obtain the marginal clearing price can truly reflect the scarcity of resources at each moment, and realizes the role of price signals in guiding the optimal allocation of resources. The present invention combines the resource clearing price obtained by the continuous type (SCUC), while taking into account the conditional constraints of the power generation entity to evaluate the benefits of the power generation entity. This evaluation method aims to provide a comprehensive benefit analysis framework by integrating economics and constraints, thereby optimizing the operating decisions of the power generation entity and maximizing its own economic benefits. BRIEF DESCRIPTION OF THE DRAWINGS

[0017] Figure 1 A market clearing flow chart of the present invention;

[0018] Figure 2 Predict curves for load and renewable energy;

[0019] Figure 3 The inertia market clearing diagram obtained by using the market clearing flow chart of the present invention;

[0020] Figure 4 The inertia clearing price obtained by using the market clearing flow chart of the present invention;

[0021] Figure 5 A primary frequency modulation clearing price obtained by using the market clearing flow chart of the present invention;

[0022] Figure 6 An electric energy market clearing diagram obtained by using the market clearing flow chart of the present invention;

[0023] Figure 7 The electric energy clearing price obtained by using the market clearing flow chart of the present invention;

[0024] Figure 8 A primary frequency modulation market clearing diagram obtained by using the market clearing flow chart of the present invention;

[0025] Fig. 9 Market bidding diagrams of power generation entities in the electric energy market and the primary frequency regulation market obtained by using the benefit evaluation method of the present invention;

[0026] Fig.10 The market bidding diagram of the power generation entity in the inertia market obtained by the benefit evaluation method of the present invention. DETAILED DESCRIPTION

[0027] The present invention will be further described below in conjunction with the accompanying drawings and specific embodiments. The illustrative embodiments and descriptions of the present invention are used to explain the present invention but are not intended to limit the present invention.

[0028] The present invention mainly includes two stages. In stage one, the present invention adds the system dynamic frequency constraint constructed based on the substitution relationship between inertia and primary frequency regulation into the model, thereby forming a multi-market joint clearing model of electric energy, frequency regulation and inertia. This model includes three parts: discrete unit load clearing (SCUC), continuous unit load clearing (SCUC) and economic dispatch (SCED). In the discrete SCUC, the start and stop status of the system synchronous unit and the inertia clearing amount of the synchronous machine are determined by the clearing results. Subsequently, the continuous SCUC determines the price of inertia and primary frequency regulation resources. In the SCED stage, the clearing results will clarify the actual clearing amount of electric energy and primary frequency regulation resources. In stage two, the benefit evaluation of the power generation subject is carried out according to the clearing prices of each market. This process is based on the operating characteristics constraints of the power generation subject, and its market bidding behavior is determined with the goal of achieving maximum benefits, thereby realizing its systematic benefit evaluation.

[0029] (1) Market clearing model: Since the three types of models, discrete SCUC, continuous SCUC, and SCED, are highly similar in mathematical expression, for the sake of simplicity, only the continuous SCUC model is presented in detail, which is used to clear resource prices.

[0030] Objective function: The inertia cost of synchronous machines is implicit in the minimum electricity cost loss of the generators that are additionally started due to inertia demand, so the inertia bidding cost of synchronous machines is not included in the objective function.

[0031]

[0032] in All are unit quotations. is the start-up and shutdown cost coefficient. The unit start-up and shutdown cost only appears in the discrete SCUC model and the continuous SCUC model, but not in the SCED model.

[0033] Constraints:

[0034] (1) Power balance:

[0035]

[0036] Where N g is the number of synchronous machines, N w is the number of wind farms; N s is the number of energy storage units; P w,t is the wind farm output during period t; P D,t is the total load demand during period t. t is the dual variable of the constraint

[0037] (2) Synchronous unit operation constraints:

[0038]

[0039] In the formula, u g,t is the unit state variable in period t. In the discrete SCUC model, u g,t is a [0,1] discrete variable, in the continuous SCUC model it is a [0,1] continuous variable, in the SCED model u g,t is a known discrete value of [0,1]; are the minimum and maximum output of the unit respectively; They are the up and down climbing limits of the unit respectively; is the primary frequency regulation value provided by the synchronous unit; k i It is the speed limiter of the unit; They are the minimum continuous operation and shutdown time of the synchronous unit respectively. The minimum start-stop constraint of the synchronous unit only appears in the discrete SCUC model and the continuous SCUC model, but not in the SCED model.

[0040] (3) Energy storage constraints:

[0041]

[0042] α ci,t +α di,t ≤1 (14)

[0043] α ci,t ,α di,t ∈{0,1} (15)

[0044]

[0045] In the formula, is the maximum charging power of energy storage; is the maximum discharge power of energy storage; α ci,t , α di,tThey are 0-1 state variables for energy storage charging and discharging respectively. is the soc state of the energy storage at time t; It is the minimum state of energy storage SOC; It is the maximum state of energy storage SOC; is the initial state of energy storage SOC; It is the end state of energy storage SOC; is the charging efficiency of the energy storage; is the discharge efficiency of the energy storage; is the rated capacity of the energy storage; Δt is the duration of energy storage charge and discharge;

[0046] (4) Wind turbine constraints:

[0047]

[0048] In the formula, is the maximum power generation of the wind turbine at time t.

[0049] (5) Frequency change rate constraint: In general, the system maximum frequency change rate (RoCoF) usually occurs at the moment of system disturbance. The primary frequency regulation of the synchronous unit usually has a control dead zone and delay, and only the inertia of the synchronous machine can respond instantaneously. Therefore, the RoCoF constraint is only related to the system disturbance loss power and the inertia level of the synchronous machine.

[0050]

[0051] Where f0 is the rated frequency of the system; |RoCoF|, |RoCoF max | are the actual RoCoF value after the system is disturbed and the maximum RoCoF limit allowed by the system, H g The inertia provided for the synchronous unit.

[0052] (6) Transient frequency extreme value

[0053] Assume that the fault occurs at the initial time and the system frequency is t nadir When the system frequency reaches the extreme value, the system frequency begins to deviate from the normal level under the extreme expected fault, and quickly crosses the dead zone of the primary frequency regulation control of the generator set, and then the primary frequency regulation control starts to act (0~T); when the active power output by the primary frequency regulation control is equal to the initial unbalanced power, the system frequency reaches the extreme value, and the synchronous unit continues to respond by inertia during this process. Therefore, at the moment of transient frequency extreme value, the primary frequency regulation and inertia both play a role in suppressing frequency changes, and there is a substitution relationship between the two.

[0054] |Δf(t nadir )|≤|Δf max| and the above parameters are substituted into the frequency evolution constraint formula after a large disturbance occurs in the system, and an equivalent change is made, and the maximum frequency deviation constraint can be expressed as follows:

[0055]

[0056] Transform the above formula appropriately into

[0057]

[0058] Can be converted to a second-order cone constraint

[0059]

[0060] Where, T g,del is the synchronous unit speed governor response delay time, is the synchronous unit speed governor response duration, Δf max is the maximum frequency variation allowed by the system, P loss,t It is the maximum power shortage value of the system at time t.

[0061] The SOC dual variable is defined as the λ in the first and second rows of the left matrix of the above formula. 1,t and λ 2,t , μ of the right-hand vector t The following conditions are met:

[0062]

[0063] (7) Quasi-steady-state frequency constraint: The total amount of primary frequency modulation provided by the system must be greater than the system power deficit.

[0064]

[0065] In the formula, is the dual variable of this constraint.

[0066] (8) Inertia and primary frequency modulation market demand: As shown in equations (20)-(24), the frequency change rate constraint and the transient frequency extreme value constraint jointly determine the system inertia demand, and the transient frequency extreme value constraint and the quasi-steady-state frequency constraint jointly determine the system primary frequency modulation demand. Inertia and primary frequency modulation jointly act on the transient frequency extreme value constraint. Therefore, when calculating the system inertia and primary frequency modulation demand, the influence of the frequency change rate constraint and the transient frequency extreme value constraint on the system inertia demand should be taken into account at the same time, and the influence of the transient frequency extreme value constraint and the quasi-steady-state constraint on the system primary frequency modulation demand should be taken into account at the same time.

[0067]

[0068]

[0069] In the formula, They are system inertia requirement and primary frequency regulation requirement; The minimum inertia value obtained for the frequency change rate constraint; They are the minimum inertia value and the minimum primary frequency modulation value obtained by the transient frequency extreme value constraint respectively; The minimum primary frequency modulation value obtained for the quasi-steady-state frequency constraint;

[0070] Market clearing price: In the clearing process, the prices of various services can be obtained using Lagrange multipliers, and the settlement price is expressed by the partial derivative of the Lagrangian function with respect to the required service. The final Lagrangian function is

[0071]

[0072] The resource prices in each market can be obtained from the Lagrangian function. The expression of electricity price is:

[0073]

[0074] The inertia price is:

[0075]

[0076] The price of a frequency modulation is:

[0077]

[0078] Power generation entity benefit evaluation model:

[0079] In order to maximize economic benefits, power generation entities bid according to the clearing prices of each market.

[0080] Objective function:

[0081]

[0082] F=c1(P t PR +P t IN +P t da )+c2 (36)

[0083] Where P t da , H t , P t PR are the bidding amounts of power generation entities in the electric energy, inertia, and primary frequency regulation markets, respectively. t IN It is the power generation space reserved by the power generation entity to provide inertia, and c1 and c2 are the marginal cost coefficients of power generation of the power generation entity.

[0084] Constraints:

[0085] The bidding quantity constraints of power generation entities in the primary frequency regulation market are as follows:

[0086] 0≤P t PR ≤k i P max (37)

[0087] In the formula, k i The amplitude limit of the primary frequency regulation provided to the power generation entity, P max It is the maximum power generation of the power generation entity.

[0088] The bidding quantity constraints of power generation entities in the inertia market:

[0089] 0≤H t ≤H smax P max (38)

[0090] In the formula, H smax It is the maximum inertia time constant value that the power generation entity can provide.

[0091] The bidding quantity constraints of power generation entities in the electricity market:

[0092] 0≤H t ≤H smax P max (39)

[0093] In the formula, H smax It is the maximum inertia time constant value that the power generation entity can provide.

[0094] Constraints on the total bidding volume of power generation entities:

[0095] The power generation entity needs to reserve some power generation space to provide inertia and primary frequency regulation. Therefore, the sum of the bids of the power generation entity in the three markets must be within the range of its maximum power generation:

[0096]

[0097] 0≤P t da +P t PR +P t IN ≤P max (41)

[0098] The calculation example uses 10 thermal power units, 4 energy storage units, and 1 wind turbine unit for testing. The wind power output and load forecast curves are shown in Figure 2 .

[0099] Firstly, the discrete SCUC clearing is performed on the electric energy-inertia-primary frequency regulation market considering the system dynamic frequency security constraint, and the start-stop state of the system synchronous unit and the inertia clearing amount of the synchronous machine are obtained. The inertia clearing results are as follows: Figure 3 Then, the synchronous machine state variables are relaxed, and the electric energy-inertia-primary frequency regulation market is cleared by continuous SCUC. The inertia and primary frequency regulation prices are as follows: Figure 4 Figure 5 Next, based on the start-stop status of the synchronous machine obtained by the discrete SCUC, the electric energy-inertia-primary frequency regulation market SCED is cleared to obtain the clearing price and clearing amount of the system electric energy and the clearing amount of the system primary frequency regulation, as shown in Figure 6 Figure 7 Figure 8 As shown. When deriving the system dynamic frequency security constraint, the substitution relationship between inertia and primary frequency regulation is fully considered, and the electric energy-inertia-primary frequency regulation market is cleared on the basis of considering the coupling relationship between electric energy, inertia and primary frequency regulation. Therefore, the market clearing result obtained achieves the optimal configuration of multiple resources and avoids waste of resources. The continuous SCUC is used to clear the inertia and primary frequency regulation prices. When the output of new energy is large, the resource price is high, which fully reflects the scarcity of system inertia and primary frequency regulation resources at this moment. Based on the market clearing price, the benefit evaluation of the power generation entity is carried out, and the bidding strategy decision is made with the goal of maximizing the profit of the power generation entity. The bidding results of the power generation entity in each market are shown as follows. Fig. 9 Fig.10 The specific benefit results are shown in Table 3, the synchronous unit parameters are shown in Table 1, and the energy storage unit parameters are shown in Table 2.

[0100] Table 1

[0101]

[0102]

[0103] Table 2

[0104]

[0105] Table 3

[0106]

[0107] The present invention combines the clearing of electric energy, inertia and primary frequency regulation markets by reasonably considering the substitution relationship between primary frequency regulation and inertia resources, and analyzes and evaluates the economic benefits of power generation entities based on the market clearing price and the conditional constraints of power generation entities, so as to optimize the allocation of market resources and promote the active participation of power generation entities in the inertia and primary frequency regulation markets.

[0108] The present invention constructs a frequency security constraint relationship formula based on the reasonable consideration of the substitution relationship between primary frequency regulation and inertia resources, and takes it into account in the multi-market joint clearing model of electric energy, frequency regulation and inertia, thus avoiding the waste of primary frequency regulation and inertia resources. The continuous SCUC is used to clear the price of frequency regulation and inertia resources, reflecting the real price of resources at each moment.

[0109] The present invention is based on the resource clearing price of continuous SCUC, and optimizes its market behavior by fully considering the operating characteristics of the power generation subject to evaluate the benefits of the power generation subject. This method maximizes the economic benefits of the power generation subject, helps the power generation subject improve its overall competitiveness and market adaptability, and enhances the enthusiasm of the power generation subject to participate in the inertia and primary frequency regulation market.

[0110] The technical solution of the present invention is not limited to the above-mentioned specific embodiments. All technical variations made according to the technical solution of the present invention fall within the protection scope of the present invention.

Claims

1. A method for evaluating the benefits of power generation entities in multi-market joint clearing, characterized in that: The following steps are involved: S1: Market demand analysis: Calculate the system inertia demand and primary frequency modulation demand to obtain the minimum inertia value and the minimum primary frequency modulation value respectively; determine the specific demand through frequency change rate constraint, transient frequency extreme value constraint and quasi-steady-state frequency constraint; S2: Market clearing price calculation: The partial derivative of the Lagrangian function of the Lagrangian multiplier method with respect to the required service is used to express the settlement price, and the expressions for the electric energy price, inertia price and primary frequency regulation price are obtained; S3: Establishment of benefit evaluation model for power generation entities: Construct a benefit evaluation model with the goal of maximizing economic benefits; the objective function includes the bidding amount of the power generation entity in the electric energy, inertia and primary frequency regulation market, as well as the power generation marginal cost coefficient of the power generation entity; S4: Constraint setting: Set the bidding constraints of power generation entities in the primary frequency regulation market, inertia market and electric energy market; power generation entities need to reserve some power generation space to provide inertia and primary frequency regulation to ensure that the sum of the bidding amounts is within the maximum power generation range; S5: Optimize resource allocation: Consider the substitution relationship between inertia and primary frequency regulation, and achieve the optimal allocation of inertia and primary frequency regulation resources through dynamic frequency safety constraints; minimize the electricity purchase cost based on market joint clearing, and reasonably allocate the three resources of electric energy, inertia and primary frequency regulation.

2. The method for evaluating the benefits of power generation entities in multi-market joint clearing according to claim 1 is characterized by: The step S1 specifically includes establishing an objective function: in All quotations are for units. is the start-stop cost coefficient; Create constraints: Power Balance: Where N g is the number of synchronous machines, N w is the number of wind farms; N s is the number of energy storage units; P w,t is the wind farm output during period t; P D,t is the total load demand during period t; t is the dual variable of the constraint; Synchronous unit operation constraints: In the formula, u g,t is the unit state variable during period t; are the minimum and maximum output of the unit respectively; They are the up and down climbing limits of the unit respectively; is the primary frequency regulation value provided by the synchronous unit; k i It is the speed limiter of the unit; They are the minimum continuous operation and shutdown time of synchronous units respectively; Energy storage constraints: α ci,t +α di,t ≤1 (14) α ci,t ,α di,t ∈{0,1} (15) In the formula, is the maximum charging power of energy storage; is the maximum discharge power of energy storage; α ci,t , α di,t They are 0-1 state variables for energy storage charging and discharging; is the soc state of the energy storage at time t; It is the minimum state of energy storage SOC; It is the maximum state of energy storage SOC; is the initial state of energy storage SOC; It is the end state of energy storage SOC; is the charging efficiency of the energy storage; is the discharge efficiency of the energy storage; is the rated capacity of the energy storage; Δt is the duration of energy storage charge and discharge; Wind turbine constraints: In the formula, is the maximum power generation of the wind turbine at time t; Frequency change rate constraint: Where f0 is the rated frequency of the system; |RoCoF|, |RoCoF max | are the actual RoCoF value after the system is disturbed and the maximum RoCoF limit allowed by the system, H g Inertia provided for synchronous units; Transient frequency extremes: |Δf(t nadir )|≤|Δf max | and the above parameters are substituted into the frequency evolution constraint formula after a large disturbance occurs in the system, and an equivalent change is made, and the maximum frequency deviation constraint is expressed as follows: Transform the above formula appropriately into: Can be converted to a second-order cone constraint: Where, T g,del is the synchronous unit speed governor response delay time, is the synchronous unit speed governor response duration, Δf max is the maximum frequency variation allowed by the system, P loss,t is the maximum power shortage value of the system at time t; The SOC dual variable is defined as the λ in the first and second rows of the left matrix of the above formula. 1,t and λ 2,t , μ of the right-hand vector t The following conditions are met: Quasi-steady-state frequency constraint: In the formula, is the dual variable of the constraint; Inertia and primary frequency modulation market demand: In the formula, They are system inertia requirement and primary frequency regulation requirement; The minimum inertia value obtained for the frequency change rate constraint; They are the minimum inertia value and the minimum primary frequency modulation value obtained by the transient frequency extreme value constraint respectively; The minimum primary frequency modulation value obtained for the quasi-steady-state frequency constraint.

3. The method for evaluating the benefits of power generation entities in multi-market joint clearing according to claim 2 is characterized by: The Lagrangian function in step S2 is: The resource prices in each market can be obtained from the Lagrangian function, and the expression of electricity price is: The inertia price is: The price of a frequency modulation is:

4. The method for evaluating the benefits of power generation entities in multi-market joint clearing according to claim 3 is characterized by: The objective function of the benefit evaluation model in step S3 is: In the formula, H t , They are the bid amounts of power generation entities in the electric energy, inertia and primary frequency regulation markets, respectively. It is the power generation space reserved by the power generation entity to provide inertia, and c1 and c2 are the marginal cost coefficients of power generation of the power generation entity.

5. The method for evaluating the benefits of power generation entities in multi-market joint clearing according to claim 4 is characterized by: The constraint conditions in step S4 are: The bidding quantity constraints of power generation entities in the primary frequency regulation market are as follows: In the formula, k i The amplitude limit of the primary frequency regulation provided to the power generation entity, P max It is the maximum power generation of the power generation entity. The bidding quantity constraints of power generation entities in the inertia market: 0≤H t ≤H smax P max (38) In the formula, H smax It is the maximum inertia time constant value that the power generation entity can provide; The bidding quantity constraints of power generation entities in the electricity market: 0≤H t ≤H smax P max (39) In the formula, H smax It is the maximum inertia time constant value that the power generation entity can provide; Constraints on the total bidding volume of power generation entities:

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