Chapter- 5
FACTORS CONTRIBUTING TO GRID DISTURBANCES ON 30TH AND 31ST JULY 2012
5.1 As is the case with most system failures, no single factor was responsible for grid disturbances on 30th and 31st July 2012. After careful analysis of these grid disturbances, the Committee has identified several factors, which initiated collapse of power systems on these days. The Committee has also identified factors which could have saved the grids from total collapse. These factors are given below:
5.2 Factors that contributed to initiation of grid collapse
5.2.1 Depleted transmission network
It is observed that one circuit of 400 kV Bina-Gwalior-Agra section was taken under planned outage by POWERGRID from 11.47 AM of 28.07.2012 for up gradation to 765 kV level. A number of 400 kV lines were out prior to the incidence on both these days. The outage of 400 kV Bina-Gwalior–Agra for up-gradation work, non availability of 400 kV Zerda-Kankroli and 400 kV Bhinmal-Kankroli due to insulator problems in particular weakened the NR-WR Interface.
The availability of 400 kV Zerda-Bhinmal-Kankroli corridor requires to be improved by replacing porcelain insulators by polymer insulators at the earliest.
5.2.2 Overdrawals attributable to frequency control through commercial signals
5.2.2.1 One of the objectives of load despatch is to maintain power system parameters within permissible limits. The frequency, being one of the parameter has to be maintained at 50 Hz or close to 50 Hz. For historical reasons, the Indian grid Systems experienced poor frequency profile. In the 1990s, more loads were met with available generation at the cost of frequency. System was subjected to operate in the range of 48-51.5 Hz. Power quality and Grid security was compromised during this period. To enforce Grid discipline and to improve frequency profile, a new tariff mechanism was conceived in the early 1990s.The earlier PLF based tariff was replaced by Availability Based Tariff (ABT). Apart from fixed and variable charges, ABT had a third component, namely Unscheduled Interchange (UI) charge. UI charge is payable if an utility is deviating from schedule (Generation/drawal) depending on the frequency. ABT was first implemented in the WR on 1st,July 2002. It was possible to implement it with the regulatory support. There was positive improvement in the frequency profile. Initially the frequency band stipulated was 49.0-50.5 Hz and subsequently the range was tightened by Central Commission. The present range is 49.5-50.2 Hz. Further tightening of the frequency band by Central Commission has been challenged in the court. In the interest of power quality and grid security, there is a definite need to operate the system at and very close to 50 Hz. It is further observed that Utilities resort to load shedding to earn revenue through UI to compensate their poor financial management. If the frequency profile is close to 50 HZ, UI rate is nominal and utilities tend to over draw/under draw thereby completely deviating from the schedule. If more number of utility players resort to such activity, it may even lead to load encroachment phenomena and grid disturbance, as has been observed in recent grid disturbances. One has to draw power only through long term , medium term or short term contracts. UI mechanism, which helped the system initially, need to be reviewed now.
5.2.2.2 Electricity Act 2003 mandates that the operating frequency range defined in Grid standard(section73(d)) and Grid Code(section 79(1)(h)) has to be adopted by LDCs. Utilities rushing to court to define frequency range may not be in the interest of secured grid operation and power quality.
5.2.2.3 Just to give an example, it may be pointed out that the "Union for the Co-ordination of Transmission of Electricity" (UCTE), an association of transmission system operators in the Europe, operates at 50 Hz± 0.02 Hz . Similarly, North American Electric Reliability Council (NERC) ensures each balancing area to plan operation at 60 Hz. Though unintentional deviation take place, they are addressed without compromising the stipulated frequency. Intentional deviation is not being done as schedules are treated as binding contracts.
5.2.2. In the developed Systems, it is possible to operate at the stipulated frequency as the participating systems takes care of their load–generation balance at the stipulated frequency. In Indian Grid, Utilities have to adopt such practice for healthy system operation.
5.2.3 Inability to control flow on 400 kV Bina-Gwalior-Agra line
5.2.3.1 It is clear from the messages issued by NRLDC to various SLDCs and recorded telephonic conversations that regional load dispatcher had made desperate efforts for reduction of overdrawals by various States, which in turn would have led to relieving of loading of 400 kV Bina-Gwalior-Agra line. In spite of records of load shedding in log book of SLDCs, it is evident that there was hardly any reduction in flow on this line. It is observed that NLDC is revising TTC in case of planned outage of transmission elements and not in case of forced outage. During discussions, officials of NLDC had cited few reasons for not revising TTC on the day of disturbance. Firstly, in the opinion of NLDC, declaration of TTC is for the purpose of facilitating organized electricity trading contracts, which are cleared on day ahead basis and, therefore, revision of TTC in real time would not serve any purpose. Secondly, NLDC pointed out that calculation of TTC requires elaborate studies, which is a specialized task and cannot be performed by operators in real time. Thirdly, NLDC stated that regulatory provisions restrains them from applying congestion charges in case congestion is attributable to forced outage of transmission line in the corridor.
5.2.3.2 The very fact that provision to apply congestion charge forms part of the regulations on the issue of "Measures to relieve congestion in real time" indicates that security of the grid is main objective of such provision. However, the Committee tend to agree that calculation of TTC is a specialized task. However, ways and means can be found out to overcome this problem. The Committee has gone through relevant regulations of Central Commission. However, there is no provision which restrains NLDC from applying congestion charges. Further, para 5.4 of the "Detailed procedure for relieving congestion in real time operation" prepared by NLDC and approved by Central Commission does restrain NLDC from applying congestion charges in such situation but requires curtailment of transactions followed by revision of TTC. Thus, the procedure prepared under the provisions of a Regulation is not consistent with the Regulation. This aspect needs to be reviewed.
5.2.3.4 At present, there is no Automatic Generation Control (AGC)//tie line bias control in the network, which can automatically restrict the tie-line flows to the scheduled limit and also frequency at the nominal value.
5.2.4 Non-compliance of directions of LDCs and Regulatory Commissions
Non-compliance of instructions of RLDCs has been a problem since long. However, of late a disturbing trend of non compliance of directions of the Central Commission has been observed. The Committee is of the view that maximum penalty that can be imposed by Regulatory Commissions in accordance with the Electricity Act, 2003 is meager in comparison to damage that such non-compliance can cause to the grid. It is reported that in some cases, the penalty imposed by Central Commission has not been paid. States overdrawing from the grid often do not pay UI charges which has contributed to infectiveness of ABT.
5.2.5 Protection System Issues
5.2.5.1 It is noted that on both days, the grid disturbance was initiated by tripping of 400 kV Bina-Gwalior line on zone-3 of Main-II protection, though there were several other concurrent conditions, which ultimately led to collapse of grid. There is no doubt that this tripping is attributable to load encroachment i.e. the current and voltage conditions were such that the protection system perceived it as fault (during fault, current becomes very high and voltage goes down to very low levels). Thereafter, there were several tripping on load encroachment and power swing. It is also noted that on both days, only Main-II protections operated and Main-I protection did not pick up.
5.2.5.2 It may also be noted that during the disturbances on 30th and 31st July, 2012, the 400 kV Bina-Gwalior line was not thermally overloaded i.e., the current rating (quad Bersimis conductor) of the line was not exceeded. However, the system was “insecure”, i.e., the system was not stable for the loss of this line. System security requires that the system should be able to withstand credible contingencies.
5.3 Factors that could have saved the grid from collapse
5.3.1 Primary response from generators
5.3.1.1 The provision for putting all generating units on governor action has been part of Indian Electricity Grid Code (IEGC) for several years. However, this was not getting implemented as generators pointed out few difficulties including wide frequency fluctuations. However, in recent years, Central Commission has made concerted efforts to reduce the operating frequency band by periodically amending provisions in the IEGC and these regulatory provisions have been successful to large extent. Another difficulty cited in implementation of governor action was that the free governor action tries to lower the generation when frequency rises from a frequency lower than 50 Hz. This difficulty has also been addressed in the new IEGC issued in April 2010 by providing for restricting the governor action in such zone. In spite of the fact that impediments in implementation of governor action have been removed, there is still no evidence of governor action in Grid Disturbances on 30th and 31st July 2012. As mentioned elsewhere, had governor action been put into action during these disturbances, chances of survival of regional grid could have been more after isolation from NEW grid.
5.3.1.2 Another important aspect in relation to primary response is that it would be absolutely essential for survival of islands. In the wake of recent grid disturbances, the issue of formation of electrical islands as last resort to maintain essential services and quick restoration has come to fore. However, in case of imminent grid disturbance, if such electrical islands are formed, their chances of survival would be abysmally low if generating units included in these islands are not on governor action.
5.3.2 Optimum utilization of available assets
5.3.2.1 A large number of high capacity 400 kV lines have been added to the intra-regional and inter-regional systems in the recent past. However, a significant number of lines are generally kept open to contain high voltages. This makes system weak and such system may not be able to cope contingency. The widespread prevalence of high voltages is pointer of insufficient reactive compensation.
5.3.2.2 Practically all generating units are equipped with Power System Stabilizers (PSS), which can save the grid from several potential destabilizing conditions. However, there is need to tune PSS periodically. Similarly, various devices/equipment available in power system such as HVDC, TCSC and SVC have stability features, which need to be enabled. There is no evidence that these devices had any stabilizing influence during grid disturbances on 30th and 31st July 2012. The system requires a large of dynamic compensators, which need to be established through detailed study.
5.3.2.3 Presently, nine number of Phasor Measurement Units (PMUs) have been put in place in Northern Region and 3 PMUs have been installed in Western Region. Even these limited number of PMUs have been helpful in the past in understanding behavior of the system. Also, these PMUs have been of immense help to this Committee in analysis of grid failures on 30th and 31st July 2012. POWERGRID has plans to install PMUs in a big way, as they are bedrock requirement for development of smart transmission grids. However, it is matter of concern that on the days of disturbances, data from PMUs at Agra in Northern Region and Vindhyachal in Western Region is not available. It appears that the PMUs in Western Region are not time synchronized.
5.3.3 Operation of defense mechanism
Defense mechanisms like load shedding based on under frequency relays (UFRs) and Rate of change of frequency (df/dt) relays have been adopted in all Regional Power Committees (RPCs) in accordance with provisions of IEGC. Similarly, increasing number of Special Protection Schemes are being employed to save system in case of contingencies. However, the experience of the recent grid disturbances reveal that practically there was no load relief from these schemes. The case in point is Northern Region, where UFR based load shedding of 4000 MW (in 3 stages) and df/dt based load shedding of about 6000 MW has been agreed. The Committee is of the opinion that after loss of about 5000-6000 MW to Northern Region, had these relays operated, the grid could have been saved. The Committee has observed that so far violation of the various system security related provisions of IEGC issued by Central Commission and Grid Connectivity & Grid Standards issued by Authority has not been taken seriously and the attention has solely been on overdrawals from the grid.
5.3.4 Autonomy to Load Despatch Centres
5.3.4.1 The issue of lack of autonomy to Load Despatch Centres is on the horizon of policy makers for quite some time. In November 2007, Ministry of Power had constituted a Committee under Shri G.B. Pradhan, the then Additional Secretary in Ministry of Power. The mandate of this Committee was to examine issues relating to manpower, certification and incentives for the personnel employed on System Operation at various levels and also for ring-fencing the Load Despatch Centres to ensure their functional autonomy. This Committee had submitted its report in August 2008.
5.3.4.2 However, significant amount of efforts are required for implementation of recommendations of Pradhan Committee. One of the recommendations of the Pradhan Committee was to have qualified system operators. Towards this end, a certification programme has been started. But there is a need to provide incentives to those operators, who clear the certification examination as also recommended by the Pradhan Committee.
5.3.5 Intra-State transmission Planning and its implementation
In recent grid disturbances, it has been observed that overloading and consequent tripping of 220 kV system had pushed the system to the edge. It also appears that though inter-State system is being strengthened continuously, matching strengthening in intra-State transmission system has not been carried out. This not only limits ability of the States to draw power but also causes low voltage problems and unreliable supply to end consumers.
5.3.6 Dynamic security assessment and proper state estimation
At present the control centers do not have any tool to periodically assess the security condition of the system. They utilize only static state estimation results, which are being performed at 400 kV network at quite slow interval. The state estimator results are not quite reliable, due to non availability of data from a large number of RTUs. There is a need to arm the control centers with more advanced application functions and possibly perform the fast state estimation through synchrophasor measurements by deploying significant number of PMUs
The operators, at present, cannot readily determine whether the line loading will actually trip a relay. However, although they can, by doing an online contingency analysis, determine whether the system is secure or not. If the system is insecure (in an alert condition), the following preventive actions can be taken:
a) Use any controllable elements, like HVDC and TCSC, to re-route power flows. If continuous capability limits have been reached short time overload capabilities may be used to buy some time for other actions. The amount and effect of the rescheduling will have to be checked using online load flow/stability analysis.
b) Generation rescheduling may be attempted. An available hydro-generator may be called on to generate power.
c) Load tripping may be attempted to reduce line loading.
