PV Impacts on Dynamic Voltage Stability Ahmad Tbaileh Chetan Mishra, Kyle Thomas Dept. of ECE, Virginia Tech Blacksburg, USA firstname.lastname@example.org Dominion Virginia Power Richmond, USA email@example.com, firstname.lastname@example.org Abstract-In this paper we discuss the impact of PV on dynamic voltage stability. The power system becomes more vulnerable as we add PV and displace conventional generation, and consequently inertia and VAR support. While PV inverters have the capability to provide reactive power, the fact that most PVs are connected at lower voltage levels limits its usefulness. We use the Dominion Virginia Power's system with different PV scenarios to show how dynamic voltage stability of the system was significantly affected. The purpose of this paper is to increase the awareness to the dynamic voltage stability issues the in case of significant PVs connected to the system. Index Terms- Dynamic Stability, Renewable Integration, Solar PV, Voltage Stability. I. INTRODUCTION With the continuous increase in electric load, power generation must increase with a similar rate to keep up with the demand. In the last few decades, the sources of power generation were mainly coal, nuclear, and natural gas. In recent years, however, it has become mandatory to include a percentage of clean electric power generation. The Department of Energy has set requirements by 2030 to use renewable resources that do not produce harmful by-products, like C02, coal ash and nuclear waste [I]. There are many ways to convert renewable energy to electricity. These are mainly seen as hydropower, wind, biomass and solar generation. While other sources of renewable energy resources can be more efficient, solar energy can be optimum to use in certain locations when the amount of sun radiation is high and the price of land is relatively inexpensive. One of the ways to convert solar radiation into electricity can be done using Photovoltaic (PV) cells. PV cells can convert solar radiation into DC electricity, which then can be converted to AC through inverters before integrating it to the grid . Owing to the EPA regulations , utilities are driven to heavily reduce their carbon footprints. In the case of Dominion VA Power, this drive is further fueled by a 30% tax credit for solar developers. Thus, a lot of distribution and transmission interconnected PV is expected. To get the maximum economic benefits from PV, it seems attractive to displace the more expensive peaking units with it. While being an economically as well as environmentally justifiable option, this could lead to serious reliability concerns, one being the dynamic VAR supports from the displaced units. In a practical system, most of the big generators are connected at higher kV levels making the sharing of real and reactive resources possible over longer distances. PV inverters can provide reactive support. Yet, the 978-1-5386-1539-3/17/$31.00 ©20171EEE PVs are being connected at a lower voltage level due to cheaper interconnection costs and smaller commissioning times. Thus, displacing conventional units at high kV levels with PVs at lower kV levels will result in the reactive power from these resources to be shared locally and not with the rest of the system. Thus, it becomes necessary to study the voltage stability impact ofPV. The authors in  investigated the impact ofPV generation on small signal stability as the dynamic characteristics of PV are dominated by the inverter. The authors in [5, 6] showed how the system transient stability becomes more vulnerable to problems with higher levels of PV penetration. The authors in  discuss the impact of large scale PV on static voltage stability. Steady-state power flow analysis in not enough to capture the complete phenomenon of voltage stability, especially with the growth of dynamic loads (more will be discussed in section III). The impact of PV integration on static and dynamic voltage stability with effects of meteorological factors has been addressed in . This paper comes to study and emphasize the impact ofPV integration at transmission level on power system dynamic voltage stability, which has not been addressed. The outline of the paper will be as follows. In section II we discuss the index we used for voltage stability, which namely is Transient Voltage Stability Index. Section III describes the dynamic models we used for solar PV and load in our studies. In section IV we describe the process of how PVs have been integrated to the system and show the results we obtained for our case studies. Then the paper will be wrapped up with conclusions and future work in section V. II. SHORT TERM VOLTAGE STABILITY INDEX Since we are studying the impact ofPVs on voltage stability, it is important to set indices to measure the effects that PV s leave on voltage stability of the power system. Thus, we use the Transient Voltage Stability Index. Transient Voltage Stability Index (TVSI), which has been proposed by authors in , to quantifies the transient voltage performance of the system buses following a clearance of a disturbance. TVSI can be calculated using the formula in (1). TVSI = "N " T -'"'=l-'"t=Tc TVDI',.t NX (T - Tc ) (1) where N is the total number of buses in the system, T is the simulation time frame, Tc is the fault clearing time and TDVI is the transient voltage deviation index, defined in (2). TDVli,t = (IVi,Vit-Vi.o .ol, if IVi,Vit-Vi.o .ol 0, 2:: 15 otherwise where V;.[, t is the voltage magnitude of bus i at time t and 0 is (fault for example), induction motors slow down and in extreme cases stall, which is marked by a rapid increase in reactive power consumption. This will depress the voltage further and interfere with voltage recovery. In extreme cases this could lead to a collapse . The need for including a dynamic component in loads to truly simulate the system trajectory during collapse was first presented in . The problem ofFIDVR is not pronounced in our test system so a PSS\E standard complex load model CLODZN was used with 50 % constant current and 50% large induction motor as used in planning studies. the threshold for unacceptable voltage deviation level. Hence, TVSI accounts for the buses with unacceptable violation during the transient period in addition to the magnitude and the duration of the violation. Therefore, it can provide a quantitative comparison of the system transient voltage performance following a disturbance. A smaller TVSI value means the transient voltage performance is better. Large Motors III. DYNAMIC MODELS A. Solar PV Model Discharge Lighting Transfonner Saru£atiOll Figure 2 CLODZN Load Model For simulating the dynamic behavior of PV in our studies, we use the PSS\E's  generic PV model with the default parameters. The model comprises of four modules as shown in Fig. I. Figure 1. PSS\E PV Model The irradiance module contains the data for irradiance levels at different times, and is useful for studying the effect of cloud cover. In the present work, we keep the irradiance fixed. This is followed by the PV panel model that maps the irradiance level to the maximum DC output power that can be extracted. Here it should be noted that this assumes the maximum power point tracking dynamics to be non-existent. The DC output power serves as the input to the inverter and its controls, which are the same as type 4 wind generator model. Low voltage ride through  is an inherent feature of this model. However, it remains connected regardless of the fault duration which is somewhat unrealistic. However, since we are more focused on the issue with displacement of dynamic VAR support, this will still give insight, though a bit optimistic. B. Sma11 Motors Load Model Voltage stability used to be studied through power flow simulations only, which consisted of predicting the closeness to the nose of the PV curve or the bifurcation point. With the increase in air conditioning loads which are majorly induction motors, the industry was compelled to study voltage dynamics. The reason being that in the case of a depressed voltage event IV. RESULTS A. Creation a/Case Studies The 2019 Summer Peak Eastern Interconnection planning model was used for our studies to begin with. Only the Dominion VA Power territory was focused on with 3015 MW PV added with multiple parameters varied to derive multiple cases. PV was added to the two transmission zones with lowest land prices and land availability. The amount ofPVs connected is 800 MW to zone 4 and 2215 MW to zone 7. In order to study the impact of having voltage support from the PVs, two sets of cases were created with same amount of PV added to the 230 kV and 115 kV buses, respectively. The interconnection buses in both cases were chosen such that a 230 kV PV bus would have a counterpart 115 kV bus at the same substation or at most one substation away. This was done to highlight the region of influence of grid support from PV when connected at two different voltage levels. As discussed before, the PV with grid support was modeled as operating in a voltage control mode with ± 0.95 power factor while lack of grid support was unity power factor. Now, to study the impact of displacing VAR resources, the amount of MW displacement per MW PV added was varied. This idea was introduced in  and was referred to as displacement ratio. A displacement ratio of 20% meant 0.2 MW of conventional generation is displaced for every 1 MW of PV added to the system. The remaining 0.8 MW is accommodated by re­ dispatching the rest of the units. The amount of Mvar displaced per zone in our studies is shown in Table I. In the case of Dominion VA Power, the base load units (mainly coal and nuclear) were left untouched while the rest of the units were displaced based on a priority order that was totally driven by cost. This was done to somehow approximate the market operation. Once the units were displaced according to the priority order, rest of the non-base load units have their outputs scaled down uniformly. The cases of 0 and 1 displacement ratios are studied in this work. Table I Mvar displaced per zone Zone Mvar Displaced 1 2 138 165 198 3 4 6 23 87 102 7 8 135 103 5 The cases created for our study are summarized in Table [I. Three variables were studied namely: PV kV level, presence of grid support and displacement ratio. Table II Case Studies Case 1 2 3 4 1 2 3 4 PV Level 230 230 230 230 ll5 liS ll5 ll5 kV Grid Support N Y N Y N Y N Y Displacement Ratio 0 0 I 1 0 0 1 1 First, we want to see the impact of different displacement ratios on the system voltage response, without the presence of grid support. As discussed earlier in this section, we have four cases for each voltage level. TVS[ for all cases forPV at 115 kV level and 230 kV level are shown in Fig. 3 and 4, respectively. It can be noticed that displacing generators can have a negative impact on the voltage stability. By comparing the displacement ratios, with and without grid support (blue vs. grey and orange vs. yellow, respectively), it can be seen that the system has mostly higher TVSI, which translates into worse voltage recovery of the system. This can be related to the fact that while displacing conventional generation for PV MWs, the system loses their reactive support as well. This has been noticed when connecting PVs on either 115 or 230kV substations. For those faults where the system TVSI had small to no impact (faults 1, 2 and 10), this can be explained as these faults occur in zones where small to no displacement happened (zones 5 and 9). When no generators are displaced from a certain zone, it will maintain its reactive support. This will be seen in the voltage response of the system after a disturbance, as it remains unaltered or slightly affected. 160 Vi C. Simulation Results Using TVS[ discussed in section III, we were able to see that impact of different setting ofPV on the dynamic voltage stability of the system. The value for 8 is 5% pu, thus treating any value above 1.05pu or below 0.95pu as a voltage violation. • 1disp 0 grid .1 disp 1 grid 100 80 Fault Locations To study the dynamic voltage stability, we simulated faults of 150ms and recorded the voltage response across the system for 5 seconds. The process of selecting fault locations was as follows. First, we acquired an idea of each bus's reactive power basin in the original system. This was done by using a Q-V curve stress test which has been proposed in . This test identifies all ioss-of-voitage-control and clogging-voltage instabilities due to shortage of reactive power supply. The output of the stress test is a set of generators associated with each bus. These generators had their reactive limit exhausted trying to save the bus from the voltage collapse. These generators make up the reactive reserve basin (RRB) for that bus. Secondly, this set of generators was cross listed with the generators displaced byPV. Thirdly, buses across the Dominion system are ranked based on the percent of their RRB overlaps with the displaced generators. A bus with its whole RRB displaced is at the greatest threat of voltage collapse. We selected the top 10 buses based on the ranking to study the faults at. For each bus fault, the line connected to it with the least impedance is chosen to be tripped when clearing the fault. This has been done to study the faults most likely to lead to a collapse. .0disp 1 grid 120 i:: B. .0dispOgrid 140 60 I I ,� I I HI 40 20 0 1111 1111 4 1111 Fault •••• 7 10 Figure 3: TVSI for Different Faults for 230kV PV Connection 160 .0 disp Ogrid 140 .Odisp 19rid 120 a1disp 1arid .1 disp 0 grid Vi i:: 100 80 60 40 20 0 III 11I1 III I � I� I � I I •••• Fault 10 Figure 4: TVSI for Different Faults at 115 kV PV Connection [t can also be noticed that even the presence of grid support is not sufficient to counter the effect displacing conventional generators and losing their reactive support. When PV inverters provide reactive support, regardless of the voltage level, the voltage response of the system improves slightly but not enough (comparing blue vs. orange and grey vs. yellow). This could be attributed to the fact that a solar developer doesn't necessarily choose a site based on system reliability. PV locations are mainly chosen based on land availability and prices while the generator displacement is driven by operation costs and environmental concerns which do not necessarily result in the same location. Thus, the PVs interconnected in our case are not electrically close to the displaced generators. To have a closer look at the voltage response of the system, a comparison between two displacement ratios for the faulted bus of fault 3 in zone 2 is depicted inFig. 5. We can see how the voltage response has a larger overshoot and larger oscillations for 100% compared to 0% displacement. It can be observed that the voltage response for a higher displacement ratio shows a higher voltage deviation after disturbance. l.15 ' 1= '---'=======::;-J � -- ---�--- . DR=O.O. GS=O DR=1.0. GS=O l.10 I • 140 _230 kV _115 kV 120 100 8 0 Vi 60 i:: Il.dlll 1111 40 20 0 II I. 4 Fault 8 6 •• 9 10 Figure 6: TVSI for PV Connected to 230kV vs. ll5kV for Case 2. 160 140 120 100 �80 0 6 40 ..9> � 2 1.05 0 0 II II 5 l.00 •• 8 Fault 10 Figure 7: TVSI for PV Connected to 230kV VS. 115 kV for Case 4 0 .9 �.'oo0 --'--c0� . O-- -- 2 � 0.7 -- 4 ----;o�; .6 -- Time (5) �.0B c;-- --- �l.0 -- Figure 5: Voltage Response for different Cases of PV Connection at 230kV for Fault 3 In this another analysis, the results between the integration of PV at 115kV against 230kV at the same substations are compared. We noticed that the system has a better voltage response given PV inverters are providing grid support, regardless of the dispatch ratio. The results are shown in Fig. 6 and 7 for cases 2 and 4 comparing TVSI for PVs at 115kV vs. 230kV substations, respectively. It can be seen that the TVSI had larger values for almost all faults for PVs connected to 115kV compared to 230kV. This can be related to the transfer of reactive power through the system. Here it should be noted that the transformer impedance plays a key role in limiting the flow of reactive power fromPVs to the rest of the system. When PVs are connected at a higher voltage level, the reactive power they provide can be shared across the system in a better way. Lines around the system tend to have smaller impedances at higher voltage levels, compared to lower voltage levels. We also compare the voltage response of the faulted bus of fault 8 in zone 3 for different voltage levels. The results are shown in Fig. 8. We can notice that the voltage showed a better response when PVs are connected 230kV compared to 115kV. This result also emphasized the impact of different voltage level ofPV connection on the dynamic voltage stability of the system. l.10 ' 1- l �====J --�---�---�-- - 230kV 115kV l.05 � 1.00 > 0.95 0.9 'C.';;-0 --'---c 0�.2;-- -- �0.';-4 ------Oo';; -; .6=--�0.;;-B ------1.-,J 0 -- Time (5) Figure 8: Voltage Response for Case 3 Fault 8 at Different kV Level V. CONCLUSION This paper discusses the impact of integrating large amount of solar PV on the dynamic voltage stability of power system. The paper demonstrates how displacing conventional generators, compared to only re-dispatching, can have a significant negative impact on the voltage stability of the system. This is because when generators are displaced (shutdown), we lose the reactive power support they used to provide. While PV inverters can provide reactive power, the support they can provide is limited because PVs are being connected at low voltage levels. 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