Switching Operations in 110 kV Networks in the Context of Synchro-Check and Mitigation of Switching Stress by Utilizing Proper Control of Renewables and Energy Storages

Abstract

Synchro-check (SC) relays are devices that control synchronization between different fragments of power system networks. Synchronism is monitored by controlling the voltage amplitude, angle, and frequency differences. The goal of monitoring is to avoid dangerous transients after the circuit breaker (CB) closing, which occur when the differences between the voltage, angle, and frequency at both sides of the CB are above the threshold. Although the idea of SC is straightforward, one needs to realize that blocking of the CB closing may cause even more severe issues, i.e., the deterioration of power system stability and safety. The conflicting goals of the switching operation result in many different interpretations, regarding the recommended settings and utilization of the SC relays in different locations of power system networks. The paper presents considerations connected with switching operations in power systems, in particular, in 110 kV networks. Different problems connected with switching operations are highlighted and described. Moreover, the switching-relevant parameters and switching constraints are provided. Further, the simulation results connected with switching operations are presented, the realistic possible voltage and angle differences before switching operations are provided, and the impacts of mitigation measures—renewables and energy storage—are estimated. Finally, the proposed procedures and algorithms of switching stress mitigation are provided.

1. Introduction

Irrespective of whether the power line (or transformer) was switched off due to a planned (operational) outage or an emergency shutdown, it is necessary to switch on these elements again in order to restore the transmission capacity of the network. With a heavy load on the transmission network when the considered network element is switched off, the voltage differences between the open poles of the circuit breaker may be large in terms of module and phase. This phenomenon will be observed especially in the cases of difficult operational situations, when more than one transmission line in a given area is turned off and the remaining lines are heavily overloaded. This situation can lead to a system failure due to cascading shutdowns of overloaded lines. In such a situation, the transmission network dispatcher should reconnect the switched off lines as soon as possible in order to reduce the loading of the overloaded lines remaining in operation.

If in a given operating state of the power system the switching angle exceeds the permissible values (resulting from the setting of the synchro-check device), a serious problem arises for the transmission network dispatcher. Each of the decisions that a dispatcher must make under time pressure can be associated with two opposing threats:

• Switching on a network element at a large switching angle (in this case, the synchro-check device should be ignored or blocked) may lead to damage to the power system elements and, consequently, to a serious system failure.
• Blocking the switching operation by the synchro-check device and failure to switch on a network element in a sufficiently short time may, in turn, lead to a strong overload of other network elements and, as a result, to a serious system failure through cascading line outages.

Moreover, blocking of the switching operation may result in higher voltage amplitudes since impedances of lines are higher, which is a significant problem in modern networks.

Conversations with dispatchers lead to the conclusion that they most often choose the first option, i.e., they block the synchro-check device, and despite exceeding the permissible value of the switching angle, they perform the switching operation. Is there another compromise solution? Some actions may be considered if the current conditions of the transmission network do not allow the circuit breaker to be closed. Dispatchers should then change the load distribution of the system in such a way that switching on a given network element is possible and safe. In particular, it is about reducing the switching angle (SPA (standing phase angle)). These activities are called the reduction in the switching angle and are included in the scope of activities related to the restoration of the power system [1,2].

This paper consists of the theoretical background connected with SC relays, problems connected with SC relays, and the modification of SC relays by adding further functionalities. The focus is on the 110 kV system, and the main goal is to mitigate problems with switching operation in modern networks with a large share of renewable energy sources and high power loads, e.g., electric vehicle (EV) chargers and energy storage systems.

2. Materials and Methods

2.1. State of the Art

The switching angle can be reduced by

• Generation rescheduling at a given load of consumers;
• Relieving the network by switching off some loads (load shedding).

The switching angle reduction is, however, limited to conventional generation, and attention is paid to extra-high-voltage (EHV) lines. The goal of the paper is to address gaps by utilizing batteries and renewable energy sources and focusing on 110 kV networks. Moreover, attention is paid to the simplicity and self-adaptability of the algorithms since the structure of 110 kV network is changed more often than the EHV lines. In this way, the problems, which arose from the integration of renewables with the 110 kV network, can be mitigated. Despite the mentioned switching issues, one can mention.

• The exceeding of the voltage level;
• The negative impact on conventional voltage regulation methods and the increased number of tap changer operations;
• The worsening of power quality;
• The increased complexity of protection schemes;
• The increased level of short circuit power and resulting thermo-mechanical stresses.

From the dispatcher’s point of view, the first method is easier, which assumes the possibility of using the so-called centrally dispatched generating units. Switching off consumers is associated with a significant cost of non-delivery of electricity, so the second method will be considered only when reducing the switching angle by changing the distribution of loads between generating nodes does not provide satisfactory results. Of course, the change in the load distribution conducted for the purposes of switching angle reducing may be executed only temporarily and immediately after switching on the given line, while the dispatcher or control automation can restore the previous load distribution.

The main difficulty is the selection of generating units that will affect the value of the switching angle. It turns out that this is not an easy task. Making the right decision on how to reduce the switching angle without the support of the results of optimization calculations is a difficult task for the dispatcher, especially since time is of the essence when the network is heavily overloaded and experimenting based on intuition is not advisable. Therefore, for this purpose, computer software is used to optimize the changes in load distribution in order to reduce the switching angle. The reduction in the switching angle by changing the generator loads can be classified as optimization problems with constraints. The algorithm works by changing the load in such a way as to reduce the switching angle at the connection point, while maintaining technical limitations. Taking into account the temporary nature of the connection state, network losses and electricity generation costs can be excluded from technical limitations (of course, within reason). What is important, however, is the efficiency and safety of the obtained solution. Efficiency means that the load changes made to achieve the required reduction in the switching angle will be as small as possible. For this purpose, those generating nodes should be selected for changes, whose load changes have the strongest influence on the value of the activation angle, i.e., the difference in the voltage arguments on the open poles of the circuit breaker. Safety means that the proposed load changes will not jeopardize the operational reliability of the power system. Usually, only static certainty is taken into account, i.e., it is required that the proposed load changes do not overload network elements and do not exceed the permissible voltage values.

In the literature, there can be found various implementation methods of obtaining the connection angle. Most of them use typical source optimization methods based on heuristics and flow algorithms [3,4,5,6,7,8], but there are also methods based on artificial intelligence [9,10]. Ref. [3] focuses on the minimum re-dispatch strategy during the reduction in differences between both sides of the CB to reduce the restoration process. Further, the load shedding in the context of the switching action is considered [4,5], and testing of the proposed procedures using the IEEE 118 bus model is performed [5]. Different approaches to minimization are proposed; e.g., [6] proposes that the higher the sensitivity, the higher the participation logic during regulation activities. We can also find an implementation of methods that look for the external (safe) angle of the switching value [11].

In [7,8], the problem of changing the generator load in order to reduce the switching angle is treated as a problem of non-linear optimization with constraints. For the purposes of this optimization, three areas of power system operating conditions were defined:

• S_TH(k), a set of operating points that meet the permissible load conditions for the configuration (i.e., for the state before the circuit breaker is closed);
• S_SPA(k), a set of operating points for which the SPA (standing phase angle) switching angle is acceptable from the point of setting the SC devices;
• S_TH(k + 1), a set of operating points that meet the permissible load conditions for the configuration (i.e., for the state after the circuit breaker is closed).

The effective and safe closing of the circuit breaker is possible when, before closing the circuit breaker, the operating state of the system is in the area constituting the logical product of the three mentioned areas, i.e., in the area that meets the condition

$$\mathrm{S}\left(\mathrm{k}\right)={\mathrm{S}}_{\mathrm{TH}}\left(\mathrm{k}\right)\cap {\mathrm{S}}_{\mathrm{TH}}(\mathrm{k}+1)\cap {\mathrm{S}}_{\mathrm{SPA}}\left(\mathrm{k}\right) \ne 0$$

(1)

This set cannot be empty, so $\mathrm{S}\left(\mathrm{k}\right)\ne 0$, which means that a given network element can be safely connected.

The optimization calculations proposed in [7,8] incorporate two steps:

• The first step is finding an area S(k) for all generating units available for regulation and checking whether $\mathrm{S}\left(\mathrm{k}\right)\ne 0$.
• The second step is finding the generation unit (or units) for which the required changes are minimal.

The authors of [7,8] used a linearized model of the system in step 1, and linear programming was used to search for individual areas. The required power changes of the generating units (step 2) can be found by solving the following optimization problem:

$$\mathrm{find} ∆\mathrm{P} \in \mathrm{S}\left(\mathrm{k}\right), \mathrm{for} \mathrm{which} \mathrm{C}\left(∆\mathrm{P}\right)={\sum }_{\mathrm{i}}{\mathrm{c}}_{\mathrm{i}}{\left(∆{\mathrm{P}}_{\mathrm{i}}\right)}^2=\min$$

(2)

where it can be assumed that c_i = 1 for all i, i.e., by minimizing the sum of the squares of the load changes of the generating units.

It should be emphasized that when changing the load distribution between generating units, the sum of the load changes must be close to zero (with the accuracy to the change in grid losses). This means that an increase in the power of some generators is accompanied by a decrease in the power of other generating units.

In the previously discussed method [7,8], the permissible operating areas are first determined, and then, based on them, a solution is found in the form of the minimum value of the sum of squared changes in the active power of generation nodes. The method proposed in [5,6] is completely opposite. First, a solution is found for which the sum of the squared changes in the loads of the generating units with active power is minimal, by using the appropriate solution of linear equations. In the next step, this solution is corrected if there are exceedances of generation capacity limits.

The method of switching angle reducing proposed in [4] is an extension of the methods described in [5,6]. This extension consists in allowing the possibility of load nodes offloading.

The connection angle reduction method discussed in [12] uses the DC method of solving network equations, which can be considered as its main disadvantage. This method does not take into account the constraints of generating nodes.

In [3], the aim was to search for such changes in the generation loads and consumption nodes that, when switching on a given network element, the active power surges in all generators meet the condition: $\le 0.5 {\mathrm{P}}_{\mathrm{n}\mathrm{i}}$(where ${\mathrm{P}}_{\mathrm{n}\mathrm{i}}$ is the active power of the i-th generator). To achieve this goal, a two-step optimization method and an additional computer program were used to calculate the active power surge in generators during the circuit breaker closing in a given power system load state. The optimization process consists of two steps.

In the first step, the function is minimized, taking into account all typical network constraints using the optimal power flow program (OPF):

$$\mathrm{OF}=\sum _{\mathrm{i}\in {\mathrm{Q}}_{\mathrm{G}}}\frac{1}{2}{\mathsf{\rho }}_1{\left({\mathrm{P}}_{\mathrm{Gi}}^{(-)}- {\mathrm{P}}_{\mathrm{Gi}}^0\right)}^2+\sum _{\mathrm{i}\in {\mathrm{Q}}_{\mathrm{L}}}{\mathsf{\rho }}_2·{\mathsf{\alpha }}_{\mathrm{i}}$$

(3)

where

-

Ω_G, Ω_L—sets of generating nodes G and receiving nodes L;

-

ρ₁, ρ₂—weight coefficients;

-

${\mathrm{P}}_{\mathrm{Gi}}^{(-)}$—the active power in the determined state before closing the given CB;

-

${\mathrm{P}}_{\mathrm{Gi}}^0$—the active power in the output state;

-

α_i—the part of the receiving power to be unloaded.

The calculations are performed assuming that the circuit breaker is open. The calculation result is the starting point for the second step.

In the second step, the instantaneous state is analyzed for the first moment after the circuit breaker is closed, i.e., the state in which an active power surge occurs in the generators. In this step, the OPF optimization program is used to minimize the following function:

$${\mathrm{W}}_2=\sum _{{\mathsf{\Omega }}_{\mathrm{inj}}}\frac{1}{2}{\mathsf{\rho }}_3{\left({\mathrm{P}}_{\mathrm{i}}^{\mathrm{inj}}\right)}^2$$

(4)

where

-

Ω_inj—a set of generating nodes for which load change is allowed in order to achieve the calculation goal (reduction in power surges);

-

ρ₃—weighting coefficient;

-

${\mathrm{P}}_{\mathrm{i}}^{\mathrm{inj}}$—a fictitious power injection, which is an auxiliary variable that is set to zero as it iterates over successive steps 2 and 1.

The power injection in a given step is chosen to satisfy the node balance, which is the following equation:

$${\mathrm{P}}_{\mathrm{Gi}}^{(+)}+{\mathrm{P}}_{\mathrm{i}}^{\mathrm{inj}}-{\mathrm{P}}_{\mathrm{Li}}^{(+)}-\sum _{\mathrm{i}\in {\mathsf{\Omega }}_i}{\mathrm{P}}_{\mathrm{ij}}^{(+)}=0$$

(5)

where the superscript (+) refers to the state at the first moment after the circuit breaker is closed, and the set of nodes j are the neighbors of a given node i. The results of the calculations are ${\mathrm{P}}_{\mathrm{Gi}}^{(-)}$ and α_i, which refer to the required values of the generated power and the required relief of load nodes.

The OPF algorithms in the process of reducing the switching angle were also used in [13]. The objective function is the required difference of angles at two selected points of the network. For two nodes i and j, the objective function will take the form

$${\mathrm{F}}_{\mathrm{c}}\left(\mathrm{s}\right)=\left|{\mathsf{\delta }}_{\mathrm{ij}}-{\mathsf{\delta }}_{\mathrm{ijreq}}\right|$$

(6)

where

-

δ_ij—the angle difference between nodes i and j;

-

δ_ijreq—required angle difference between nodes i and j.

The task to be solved is the minimization of the objective function described by Formula (6). In [13], one of the heuristic optimization methods, namely, the simulated annealing method, was used to obtain a solution.

Other methods of reducing the switching angle can be found in [10,14,15,16,17,18]. All the methods discussed above assume that large, centrally dispatched generating units will be used primarily in the process of reducing the switching angle. Some of these methods also allow load shutdowns in case the change in generator loads does not lead to the expected solutions. The literature review can be summarized by citing examples of the calculations presented in [13]. The calculations were performed on the Polish power system model for a switched off 400 kV power line, for which the permissible switching angle was assumed equal to 20°. From the power flow calculations performed for the model with the considered switched off line, the difference of the angles at the open poles of the circuit breaker was 28.5°. The optimization calculations showed that it was possible to reduce the switching angle of the selected line to the required value (20°). However, this result was paid for by changes in the value of power generated in practically all sources in the grid, with the largest changes in the value of generated power of several hundred megawatts. The possibility of practical execution and implementation of optimization algorithms based on large power units seems doubtful. This is evidenced by the fact that the latest articles on this subject come from 2013.

Therefore, the authors suggest that the possibility of reducing the phase angle and voltage level should be sought using distributed energy sources and energy storages for this purpose.

2.2. Switching Operations and Limitations

Switching operations are essential to disconnect damaged elements and fragments of the network, as well as to perform maintenance and modernization of the power system network. The switching operations need to be executed in the proper order, e.g., opening the circuit breaker before the disconnector, with properly functioning devices, within technical limits, and under the proper conditions—differences of frequency, voltage amplitude, and angle at both sides of the circuit breaker have to be within an acceptable range to avoid both premature aging and the risk of damage to the elements of the power system network [19,20].

The settings of SC relays need to ensure that the switching operation will not cause harm to the power system, in particular, the circuit breakers, transformers, and generators. Standards rarely provide requirements regarding the withstand capabilities under out-of-synchronism switching operations. One of the examples is connected with the circuit breakers: switching operations under 180 degrees (max) phase shift. In other cases, the requirements are provided regarding the short circuit capabilities [21]. One needs to underline that out-of-synchronism switching operations are similar to short circuits since in both cases the points of network, characterized by different voltages, are connected, and the voltage differences cause high-amplitude current flow.

The SC relays can constitute a separate device or additional function in protection relays, e.g., distance relays [22]. Moreover, some producers offer devices that not only monitor but also control the voltage magnitude, angle, and frequency difference by sending signals to conventional generators in all types of power plants, i.e., nuclear, gas, diesel, or coal [23].

The recommended settings provided in the literature, as well as the settings in real SC relays, may differ significantly. The authors of [21] specify KPI for synchro-check:

• Acceptable if ∆φ ≤ 3°;
• Manageable if 3° < ∆φ ≤ 10°;
• Too demanding if 10° < ∆φ ≤ 20°;
• Impermissible if ∆φ > 20°.

The CIGRE Working Group (WG) recommendation is to limit the switching angle to 60° [24].

The generic recommendations do not consider numerous power network conditions and differences between networks all over the world; therefore, every time, the protection engineer should perform a detailed analysis of the synchro-check settings. A detailed SC setting selection methodology and software for the selection of settings is presented in [25]. The settings of real SC relays are often significantly reduced, which can be explained by technical and human factors: the precautionary approach. The precautionary approach results in a higher probability that the switching operations will be blocked, which leaves the dispatcher of the power system network under difficult situations. In general, the SC should be considered in the following types of locations:

• High power loads and energy sources on both sides of the open CB;
• Different impedances between both sides of the CB caused by the length of the line or different unit impedances, e.g., cable and overhead lines.

In practice, such conditions often exist close to cities, which are characterized by high load, and suburban areas, which are usually characterized by a high share of renewable energy sources. Moreover, the voltage and angle difference in the 110 kV network results from differences between supplying the EHV network, which may be significant, in the range of tens of degrees per 200 km [26].

The goal of the paper is to extend the synchro-check algorithms by adding the synchronizer/automatic voltage regulations capabilities to the synchro-check relays. The synchronizers are typically used in power plants to adjust the rotational speed of generators to the frequency of the network, whereas the automatic voltage regulator (AVR) regulates the voltage and its phase to minimize transients during the connection of new sources to the grid. The paper focuses on voltage and phase regulation since the voltage and angle differences may occur under normal operating conditions, and the differences of rotational speed may occur under emergency conditions caused by an imbalance of active power and are directly connected with emergency operating conditions [27,28]. The conventional AVRs and synchronizers utilize local measurements, whereas the proposed extension is based on a combination of measurements at SC locations with the existing power sources or storages installed in the vicinity of the SC relay.

The idea is to monitor the synchronism like in a conventional SC; however, when differences are above the thresholds, the SC sends a signal to the SCADA system to regulate the active (P) and reactive (Q) power of nearby power sources or energy storages to reduce the differences of the voltage amplitude and angle.

2.3. Regulating Capabilities

There are different types of power sources in the network, which are characterized by different regulation capabilities. The characteristics of typical wind turbines are presented in Figure 1, which refers to the regulation capabilities of the most popular type 3 wind turbines with an AC/DC/AC converter in the rotor circuit. Older type 1 and type 2 wind turbines (WTs) are practically not used in the 110 kV network, whereas type 4 is seldom used due to the higher investment cost. The literature mentions type 5 wind turbines; however, type 5 is still in the research phase [29,30].

The type 3 wind turbine PQ characteristic is the result of the induction generator with a converter in the rotor circuit. The exemplary type 3 wind turbine regulation capabilities are presented in Figure 1. As can be seen, the type 3 wind turbine is able to provide reactive power only when active power is produced, so the wind has to be between the minimum and maximum wind speed. The maximum speed may be further modified by using the so-called wind ride through [31]; however, the risk of too-strong wind or wind below the minimum still occurs.

Figure 1. Characteristic of the reactive power capability of a typical wind power plant generator [32].

Figure 1. Characteristic of the reactive power capability of a typical wind power plant generator [32].

Much more flexible reactive power regulation capabilities are offered by PV power plants (Figure 2). In older types of PV plants, the maximum available reactive power is lower, e.g., 0.3 Pmax, and it rises in newer inverters to 0.6 Pmax or more, e.g., 0.9.

Moreover, the new types of PV sources support a new function—Q at night, where reactive power is available even when there is no output power, which provides them almost perfect controllable volt/var regulating capabilities for the whole day [34]. Despite the power sources, one should consider the energy storages as reactive power sources and active power sources. Energy storages may be divided into two categories: AC energy storages (direct AC I hydro pumps or indirect due to a converter), with high reactive power regulation capabilities, and DC power storages, e.g., connected with a DC traction network [35]. The DC energy storages are able to control only active power, which also has an impact on the voltage level; however, the impact is significantly lower. Further, the DC storages can be divided into two subcategories: one-way power control in the case of a passive diode rectifier or two-way active power control in the case of an active rectifier/inverter [36]. The utilization of energy sources for switching support requires minimal battery capacity since the support lasts tens of seconds, so the energy is in the range of kW. Figure 3 shows the U-Q/Pmax characteristics of the synchronous generating module, while Figure 4 shows the required reactive power control capabilities of the type B power bank module.

Different regulation capabilities of power sources would be very problematic for the operation of the power system; therefore, the regulation capabilities are standardized using the NC RfG [38] grid code and the requirements of the local transmission system operator. The grid code specifies four types of sources, irrespective of the technology: types A (lower than 0.2 MW), B, C, and D, according to

Table 1. Classification of max power generating modules in Poland [38].

Maximum Power Threshold Limit for Qualifying Power-Generating Modules
Type B	Type C	Type D
0.2 MW	10 MW	75 MW

.

Type A is connected with low-voltage networks, whereas type D is connected with EHV networks. Type A is excluded from the analysis because of its small impact on the 110 kV network and the difficulties in adjusting the reactive powers because of the constraints in low-voltage networks. Type D is excluded because of its high impact on the whole power system. Finally, two types of power sources can be considered for reactive power support in the 110 kV network: types B and C are analyzed; however, the utilization of type B needs to be carefully analyzed since improper regulation could deteriorate the power quality in MV networks.

The transmission system operator can specify different characteristics within the area specified in the grid code. One needs to underline that the grid code specifies requirements not for a single source itself but for a whole installation; therefore, internal reactive power sources are considered, e.g., capacitive current of lines, etc. In many cases it is impossible to meet the requirements of grid codes using only the generator; therefore, additional devices, e.g., capacitors or reactors, are used. One needs to remember that additional requirements occur; e.g., under regulation of the power factor, the step change of the reactive power has to be below 5% of the max reactive power or 5 MVA, depending on which occurs first. Moreover, the grid code allows one to utilize the tap changer to fill the requirements. As a result, in some cases, the reactive power is not available immediately but after a significant time. To sum up, the reactive power can be categorized as immediate smooth regulation and discrete regulation in time steps, e.g., a tap changer or a capacitor bank.

The presented regulation capabilities allow one to change the power flows in such a way to reduce the voltage differences on both sides of the open CB, which minimizes the switching transients, which cause premature aging or risk of failure, e.g., the shafts of turbines [39]. In a conventional power system network, in order to avoid high switching transients and the resulting premature aging, the planned switching operations are often performed under low loading conditions of the line. Unfortunately, the rapid growth of renewables in the distribution and subtransmission system causes low-load conditions to occur rarely, and in the case of WTs they are difficult to predict. The proposed algorithm addresses the presented issues of modern power system networks.

The active power reserves are available because all types of conventional power storages operate below the maximum in order to ensure frequency regulation reserves [40]. Further, as a result of the required reactive power capabilities, the active power of the sources is limited; however, under emergency situations, the limit of the active power can be deactivated, and additional real power can be produced. In some cases the energy units operate with a further reduction in power in order to ensure so-called virtual inertia [41], so additional active power regulation in an increasing direction occurs. Reductions in the generated power are commonly used.

2.4. Power Flows in Current 110 Networks

The high-voltage and extra-high-voltage networks are operated as a closed loop at the same voltage level. Moreover, the EHV networks are closed through 110 kV networks, which in general also operate as closed loops; nevertheless, sometimes, the radial structure of a feeder exists in the cases of non-essential stations (Figure 5).

Nationwide networks (Figure 6) usually consist of tens of thousands of interconnected elements; therefore, the calculation has to be performed using the proper simulation software. Among the different calculation procedures, one can mention load flow analysis, contingency analysis, or short circuit analysis. In order to test the effectiveness of the proposed actions in the power system, one can modify the reactive power in order to impact the voltage amplitude and angle.

The authors performed a study and proposed settings of SC relays in a 110 kV network [43,44]. The analysis performed using the Synchrosoft software allowed the authors to choose locations in which the expected voltage amplitude and angle differences were high. Further, the locations were analyzed using the RMS simulation software Power Factory 2022 SP4, in which modifications of the reactive power and active power were performed to assess the expected impact of renewables and energy storages on the change of the voltage amplitude and phase difference.

Figure 6. Fragment of the Polish power system network (blue, 110 kV; green, 220 kV; and red, 400 kV) [45].

Figure 6. Fragment of the Polish power system network (blue, 110 kV; green, 220 kV; and red, 400 kV) [45].

The RMS analyses were based on creating an n − 1 situation in unfavorable locations and observing the voltage and angle differences and impacts of renewables and energy storages on the reduction in electrical differences between the CB poles. For the real case analysis, the Synchrosoft software was used to find locations characterized by the high expected voltage and angle differences. Figure 7 shows a model of an exemplary line used in the simulations. Because of data sensitivity the results were not published, and only the example which was characterized by realistic parameters was used.

Before the energization of the CB, high differences of angle of almost 20° and voltages in the range of 0.09 pu (9%) were observed due to the load and generation structure. First, the minimization of the voltage difference using the reactive power using sources at the sides of station A and station B is presented (Figure 8 and Figure 9). As can be seen, the modification of the reactive power at the side of station A had a small impact on the analyzed parameters (Figure 8), whereas the modification of the reactive power at the side of station B had a significant impact on the reduction in the voltage difference; however, at the same time, there was a noticeable deterioration of the angle difference. One can conclude that in some cases, when only the voltage difference is high, there is a small deterioration of the angle difference. In cases where the voltage difference is outside the limits and the angle differences are close to the limits, it is necessary to adjust the parameters smoothly to thresholds, i.e., to reduce the voltage difference to its limits (e.g., 0.1 pu) but no more since it could cause the angle difference to fall outside the limits. Further, in the case in which both parameters are above the threshold, one needs to consider angle regulation, which is presented in Figure 10 and Figure 11.

Figure 10 presents the modification of active power at the supply side, and Figure 11 presents the modification of active power at the feeder side. As can be observed, the impact of the modification of active power had a very small impact on the voltage difference and a small impact on the angle difference. One can notice that even after the modification of active power was stopped, the angle changed for some time because the regulation of active power required some time to find a new point of stable operation. The flow of parameters required the setting of additional parameters in synchro-check relays, e.g., prediction algorithms, which analyzed the differences of the parameters at the exact moment of the CB closure [46]. There was a similar action with the opposite sign: generation at the feeder side resulted in a reduction in the angle difference of around 3.5° per 10 MW. In the presented case, the regulation of active power at the supply side was meaningless; however, in the case of the CB opening in the middle of the feeder, the strength of regulation at both sides was divided between both sides, and therefore, one should not focus only on one side of the feeder.

The presented results show that the modification of parameters at the supply side has an often minimal impact on the parameters in 110 kV networks, and therefore, conventional regulation schemes, which are based on big power plants, are not sufficient to ensure smooth switching operations in a 110 kV network.

3. Results

3.1. Proposed Algorithm

The flowchart of the developed algorithm is presented in Figure 12. The first step is performed in conventional synchro-check relays: when the monitored CB is opened and the detected voltage amplitude, voltage angle, or frequency difference before closing is too high, the closing of the CB is blocked. The emergency voltage regulation signals are sent to the SCADA system with the measured voltage amplitudes, angles, and frequencies. The SCADA system performs an analysis of the feeder structure at both ends of the CB. The feeder is continued until one of the following conditions occurs:

• Open CB of the de-energized element (out of service);
• Natural end of the feeder;
• A change of the voltage level, i.e., a higher voltage (e.g., 220 or 400 kV) at the substation is met.

Further, the list of active power sources and reactive power sources connected to feeder is created. The length and impedance of the feeder are stored. Further, the feeder is analyzed in the context of energized, connected, nonexcluded (e.g., the activation of the reactive power regulation reserves causes a high fluctuation of the voltage) energy sources or storages. Both sources connected directly to the 110 kV lines (simplifications of modeling) and sources connected through the block transformer are considered. The available sources at both sides of the CB are sorted according to the expected strength of the regulation, which is calculated as the impedance between the supply autotransformer and the source or alternatively as the distance between the supply autotransformer and the source. The sources are utilized for regulation with an ascending order: the sources with the strongest impact are used at first and so on. The sole operation of one source is justified by the unexpected results of regulation due to hidden errors. After the list is created, the pre-regulation is performed. The goal of the pre-regulation phase is to calculate the strength of the modification: the °/MV and the voltage difference (pu)/MW, as well as both the °/MV and the voltage difference (pu)/MW. The pre-regulation signals are created based on

Table 2. List of actions performed based on the calculated voltage and angle difference.

Parameter	Value	Action
Angle difference	Above threshold	Modify active power only
Voltage difference	Safe limits from thresholds
Angle difference	Safe limits from thresholds	Modify reactive power only
Voltage difference	Above threshold
Angle difference	Above threshold	Modify active power and reactive power if needed
Voltage difference	Above threshold

.

The pre-regulation signals have constant values, with a unit change of power 1 MW/s or 1 MVar/s in order to observe the impact of the power change and regulation strength for the current network conditions and to eliminate the risk of an incorrect operation, e.g., a rise of power instead of a reduction due to an incorrect polarization of the meters. Further, the required power change is calculated as

$$\mathrm{R}\mathrm{C}=\mathrm{R}\mathrm{S}·\mathrm{R}\mathrm{R}$$

(7)

where

• RC—required change;
• RS—regulation strength °/MW, pu/MW, °/MVar, and p.u./MVar;
• RR—required regulation, e.g., 5° above the limits or 0.05 p.u. above the limit.

The required change of power is activated according to the table above. Further, the character of reactive power is determined to be reactive when the voltage should be reduced and capacitive when the voltage needs to be increased. Finally, the reactive power sources from the list are activated sequentially and increase the reactive power using a ramp function in order to minimize the impact on the voltage flicker in the range of a few MVAR/second until the maximum capabilities or a satisfying reduction in the electrical differences occurs. When the differences are still above the threshold, the next reactive power source is activated. The procedure is continued until all of the reactive power control reserves are used or until reaching the acceptable voltage and angle differences. In case of acceptable differences, the CB is closed automatically, whereas in the case of values above the threshold, the operator makes the decision about the CB closing and takes other actions, e.g., uses the tap changer or waits, if possible.

Further, the voltages on both sides are analyzed in the context of the voltage level to avoid worsening of the power quality, e.g., the voltage level; that is, when voltage on one side is 1.12 and other is 1.14 Un, it is not recommended to increase the voltage level at the 1.12 side and to limit action to the minimization of the voltage at the 1.14 side. If a single side action does not allow for the minimization of the differences to acceptable values, the second side action can be activated by the power system dispatcher.

The effects of regulation are constantly observed, and regulation is stopped when the signals are within limits. If not, the procedure is repeated using the next source from the list.

The inverters are chosen because they provide smooth regulation. Conventional voltage regulation is used only when the inverter regulation capabilities are exceeded. After the CB is closed, the reactive power settings are restored to the levels before the switching operations using a ramp function. The whole operation is performed in reverse order; however, this time, the voltage level is controlled. If the restoration leads to unwanted voltage levels, the operation is stopped, and the dispatcher performs the voltage regulations manually.

3.2. Verification of the Proposed Procedure

The test grid is developed in PowerFactory 2022, SP4 software as a simplified fragment of a 110 kV grid (Figure 13). It is assumed that the grid consists of four feeders supplied by 220/110 or 400/110 stations, over a dozen 110/MV substations and one 110 kV substation, which allow for the reconfiguration of the 110 networks. The normal configuration for the presented grid is the connection of any three feeders since the connection of a fourth feeder causes a rise of the short circuit power above the permissible values and, moreover, may cause unwanted reactive power flow. The presented grid could be configured in numerous ways; however, for the sake of simplicity, only one example is provided. It is assumed that the line between stations C1 and C2 is deenergized because of the maintenance activities; further, the line between stations B1 and B2 is disconnected by protection relays and after the inspection is planned to be reconnected to the network. The CB closure is blocked because the angle difference is almost 13°, which is above the threshold (the angle difference is the result of the declared values for external grids and further changes due to the loads and sources in the test grid). The voltage is within the acceptable level; therefore, according to Table 2, the modification of active power only is activated. The list of active power sources is created.

The first source from the B2 side is the synchronous generator 15 MVA operating at an 11 MW level. The generator is assumed to be installed in a local heat and power plant, which is susceptible to transients of active power during the switching actions. The heat and power plant is excluded from the regulation process due to the negative impact of changes of the power and steam on technical processes. Additionally, the regulation capabilities are limited due to the small nominal power of the heat and power plant. The next sources are a 48 MW PV power plant, operated at 40 MW, and the companion battery storage, which at the analyzed moment is being charged since energy prices are low. Further, the 60 MW wind power plant is connected to B4, which is inactive. At the second side of CB, the 40 MW wind power plant, operated at the 30 MW level, is connected.

The order of the activation of active power regulation capabilities is determined, and at 50 s the 1 MW change of power is activated (a reduction in the generated power), and the proper direction of the action is confirmed by the reduction in the angle difference; therefore, the full regulation capabilities are activated, and the energy storage changes the power to −11 MW (load). As a result, the angle difference is reduced to 9° (Figure 14), which is still above the threshold, which is 6°. The second active power regulation capabilities source, the PV power plant, is activated, and the generated power is reduced according to the blue line. When the angle difference reaches the threshold, the CB is closed at 140s. One may observe that the transient power reaches 15.7 MW (a 4.7 MW rise), which has a negative impact on the shaft of the turbine and accelerates the aging of the turbogenerator. Figure 15 presents the case in which the operator decides to block the synchro-check and close the CB. One can notice that the transient power reaches 21.84 MW, so the output power is doubled. Naturally, the higher the transient, the worse the impact on aging and potential failure. The acceptable values should be discussed with the manufacturer of the turbogenerators.

4. Discussion

Reactive power capabilities are rarely used in practice in a 110 kV network. Moreover, even when Q = f(U) is used, the defined settings may allow for higher voltage differences than acceptable. As can be observed in the example control characteristic in Figure 16, given the values of 0.94 p.u. at one side and 1.06 p.u. at the second side, the voltage amplitude difference would be 0.12 p.u., and regulation would remain inactive.

One has to underline that Figure 16 is only exemplary and specify typical characteristic for the LV network since operators do not specify typical characteristic for 110 kV. Moreover, to the best of the authors’ knowledge, there are no requirements regarding angle control and monitoring, even though it is becoming a more and more problematic parameter in modern networks.

The proposed solution is based on existing infrastructure. The implementation is connected only with the work load needed to connect and add new routines in the SCADA system. The proposed routine requires minimal preparatory work and can be utilized for different locations, as well as multi-end feeders.

5. Conclusions

The literature research allowed the authors to conclude that synchro-check issues have not been currently investigated, since new literature presenting the topic stopped emerging approximately 10 years ago. The research performed by the authors shows that changes in the power system network can result in high differences between the voltage and angle on both sides of the opened circuit breakers in 110 kV networks, which could cause operational issues, such as blocking of CB operation, which in turn could cause further issues, e.g., the overload of other lines. In order to address the CB issues, a simulation analysis was performed. The simulation results allowed the authors to conclude that renewables and energy storages can have significant impacts on the differences of electrical parameters between the CB poles. Based on the simulation results and knowledge of existing procedures in power systems, the 110 kV SC support algorithm was created. The algorithm connects a conventional approach with the features of new devices, e.g., Q at night and the activation of renewable power reserves or stored energy. The proposed algorithm can be introduced in a typical SCADA system and allow one to minimize the problems caused by the integration of new devices with the power system.