An Integrated Lightning Risk Assessment of Outdoor Air-Insulated HV Substations

Abstract

Although various lightning protection methods have been used in the industry, many outdoor high-voltage (HV) substations are still experiencing high failure rates due to lightning strikes. The applications of these rule-of-thumb-based methods generally lack coherence among the practitioners. IEC 62305-2 provides a systematic way for practitioners to assess the lightning risk for buildings or structures in a probabilistic way. However, this standard has not explicitly covered the application of HV substations. Moreover, IEC 62305-2 involves a tedious set of risk factors which may hinder many practitioners from applying the aforementioned standards while other preferred rule-of-thumb methods are available. As IEC 62305-2 does not specify the applicability to lightning risk assessment in HV substations, this paper proposes a novel approach to complement the standard-based risk assessment process. During this integrated risk assessment process, significant risks are identified, followed by ambiguous risks that will be adjusted in subsequent phases. The significant ambiguous risk factors such as fire load function (rf), environmental factor (CE), LPL class, and other governing factors have been analyzed and discussed. By adjusting these significant risk factors, the practitioners will understand the adjusted risk factors in relation to the practical implementation of lightning protection system (LPS). Therefore, integrating the substation characteristics, assumptions, and findings of ambiguous risk factors can result in a successful integrated lightning risk assessment process.

1. Introduction

Lightning is the electrostatic charges built up in the clouds, producing enormous discharge energy that potentially transfers in high current to the tall structures or ground surface [1]. The outdoor air-insulated HV substations are one of the structures that are exposed to lightning strikes. The substations serve the purpose of switching, converting, diverting, measuring, and protecting the power transmission networks to provide a stable power supply to the consumers [2]. Although the substations are equipped with a lightning protection system (LPS), it is found that lightning strikes are still causing substation failures even in modern times [3,4]. Consequently, this has caused the substation practitioners to seek an alternative approach to assess the risk of lightning strikes via the probabilistic method [5].

IEC 62305-2 has outlined the lightning risk assessment process for the general structures [6]. Recent progress in lightning risk assessment was discussed in [7,8]. Due to the rigorous nature of risk assessment, a tool has been developed to simplify the process [9]. In spite of the fact that IEC 62305-2 does not specifically refer to the risk assessment of outdoor HV substations, the lightning risk assessment process can be conducted by incorporating assumptions with similar representations to those used for building structures [10,11].

As mentioned, despite the fact that presumably all HV substations are equipped with LPS, many failure cases were still reported in the past.

Table 1. Failure Cases due to Lightning Incidents.

Substation/Location	Date of Incidents	Affected Public Residents
Greenbrier Substation, Alabama, USA [12]	3 January 2022	3500
NSP Lakeside Substation, Nova Scotia, Canada [13]	22 July 2019	45,000
FPL Substation, Fort Lauderdale, USA [14]	26 March 2019	33,000
Edison Electric Substation, Colton, USA [15]	31 August 2017	50,000
Avista Substation Troy Highway, USA [16]	6 May 2017	11,000
Mt. Auburn substation, Missouri, USA [17]	21 April 2017	2000
PNM Substation, New Mexico, USA [18]	8 August 2016	130,000

shows the failure cases that caused outages and damages due to lightning incidents [12,13,14,15,16,17,18].

2. Literature Review

2.1. Tolerable Risk Values

IEC 62305-2 [19] provides a process for estimating the risk of loss of human life or permanent injuries (R1) and loss of service to the public (R2). The tolerable risk values (RT) for R1 and R2 are shown in

Table 2. Tolerable Risk Values.

Type of Loss	RT (Per Year)
Loss of human life or permanent injuries (R1)	0.00001
Loss of service to the public (R2)	0.001

. The risk of loss of cultural heritage (R3) is excluded as HV substations are not cultural heritage buildings. Moreover, due to the complexity of equipment procurement and electricity tariffs, the risk of loss of economic value (R4) is excluded as well.

The general equation of the risk value (R) consists of the components of the number of dangerous events per annum (N), probability of damage to a structure (P), and consequent loss value (L):

R = N × P × L

(1)

2.2. Lightning Strike Distance (S)

IEC 62305-2 uses striking distance (S) to determine the lightning protection level (LPL) of an LPS. The striking distance is the final jump of the stepped leader in air space to a structure or ground plane. As a result of various lightning strike distance formulas proposed by researchers over the course of history, electro-geometrical methods (EGM) such as rolling sphere methods (RSM) lack coherence of application [20,21,22]. The most widely used formulas are based on Love’s and Mousa’s as shown in (2) and (3) respectively [23,24]:

S = 10 × I^0.65

(2)

S = 8 × I^0.65

(3)

where I is lightning stroke current in kA.

As shown in

Table 3. Comparison of Striking Distance (S) to LPL.

Criteria	LPL I	LPL II	LPL III	LPL IV
Minimum peak current	3 kA	5 kA	10 kA	16 kA
Striking distance, S (IEC 62305)	20 m	30 m	45 m	60 m
S = 8 × I0.65	16.3 m	22.8 m	35.7 m	48.5 m
S = 10 × I0.65	19.7 m	27.4 m	42.8 m	58.2 m

, Equation (2) shows a closer match to the striking distances based on the LPL table presented in IEC 62305-3 [25]. Thus, the results of (2) will be compared with the LPL table in IEC 62305-3 to determine the LPL to apply in the integrated risk assessment process.

2.2.1. Basic Impulse Level (BIL)

Basic impulse level (BIL) is one of the fundamental factors to determine the allowable lightning stroke current. It is the standardized withstand impulse voltage level of electrical insulation without causing the equipment to experience flashover and damage due to lightning strikes. It is the reference levels expressed in impulse crest voltage with a standard wave not longer than 1.2 by 50 µs wave and the tests applied on the equipment shall be equal to or greater than the BIL [26,27]. The common BIL ratings of the substation are based on the voltage systems of the substations.

2.2.2. Lightning Stroke Current (I)

The allowable lightning stroke current which will not cause the flashover or back-flashover for the equipment is based on (4) [3]. The equation is proportional to the BIL rating of the specified equipment which was connected to the system voltage lines.

I = BIL × 2.2/Z_s

(4)

where Z_s is the surge impedance, commonly assumed as 300 Ω unless specified [22].

2.3. Lightning Flash Density

The ground flash density (NG) is the key factor that determines the risk assessment result. The general formula stated in IEC 62305-2 which was originally suggested by Anderson [28], estimated that 10% of thunderstorm days per year (TD) is the number of lightning flashes per km² per year, with an allowance for reduced numbers of flashes to lines due to shielding by trees and undulating terrain. The formula for calculating the ground flash density is shown in (5).

NG = 0.1 × TD

(5)

When compared to the tropical and equatorial zone such as Brazil, Columbia and Mexico, NG is closer to (5) and considered as practical as the annual thunderstorm days are normally recorded higher [29].

In the real case, obtaining specific local meteorological data such as TD is not a straightforward task. There is an alternative method that uses optical transient density measurement, a space-based earth orbit sensor, which was suggested in IEC 62858 that the ground flash density as shown in (6) is proportional to the total cloud-to-ground and inter-cloud optical recorded flashes per km² per year (NT) [30,31].

NG = 0.25 × NT

(6)

NT in flashes per km² per year can be based on NASA’s space-based earth orbit sensor data as shown in [32]. By considering the case in Malaysia for example, the TD range is 50 to 350 thunderstorm days per km² per year as compared to the NT range of 10 to 70 optical flashes per km² per year. It is noticeable that the ground strike-point (NSG), as shown in (7), for new optical transient density measurement based on NASA’s data is very similar to the lightning density formula stipulated in (5) [33,34]. Thus, this method can be considered for risk assessment if the local meteorological data is unavailable.

NSG = 2 × 0.25 × NT

(7)

3. Methodology

Figure 1 outlines the lightning risk assessment for HV substations based on IEC 62305-2 [19]. By incorporating the assumptions to resemble the outdoor substations as the “structures” [18], the lightning risk assessment for HV substations based on IEC 62305-2 can be performed. Five HV substations with different characteristics will be selected for the case study. The actual HV substation layouts will be overlaid in CAD tools to calculate the collection areas. After that, the lightning risk assessment based on IEC 62305-2 will be performed and several significant risk factors will be identified. Among the significant risk factors, some ambiguous risk factors will be identified. Lastly, the simplified integrated risk assessment process will be proposed.

3.1. Risk Components

The risk components are similarly evaluated based on IEC 62305-2, in which R1 and R2 will be calculated based on the summation of the individual risk components as shown in

Table 4. Risk Values of R1 and R2 (IEC 62305-2).

Risk	Risk Components
Risk of loss of human life including permanent injury (R1)	R1 = RA1 + RB1 + RC1 + RM1 + RU1 + RV1 + RW1 + RZ1
Risk of loss of service to the public (R2)	R2 = RB2 + RC2 + RM2 + RV2 + RW2 + RZ2

. These risk components are calculated based on the tabulated risk factor values suggested in the same standard. The numbers after the alphabetical character of risk components represent the type of losses. For example, RB1 is risk component for loss of human life due to physical damage inside the structures due to lightning. On the other hand, RB2 is the risk component for loss of service to the public due to the same cause. The brief explanations of the risk components are explained in

Table 5. Definitions of Risk Components (IEC 62305-2).

Risk Components	Descriptions and Definitions
Risk components for a structure due to flashes to the structure	RA: Component related to injury to living beings caused by electric shock due to touch and step voltages inside the structure and outside in the zones up to 3 m around down-conductors. RB: Component related to physical damage caused by dangerous sparking inside the structure triggering fire or explosion which may also endanger the environment. RC: Component related to the failure of internal systems caused by lightning electromagnetic pulse (LEMP).
Risk components for a structure due to flashes near the structure	RM: Component related to the failure of internal systems caused by LEMP.
Risk components for a structure due to flashes to a line connected to the structure	RU: Component related to injury to living beings caused by electric shock due to touch and step voltages inside the structure and outside in the zones up to 3 m around down-conductors. RV: Component related to physical damage caused by dangerous sparking between external installation and metallic parts generally at the entrance point of the line into the structure due to lightning current transmitted through or along incoming lines. RW: Component related to the failure of internal systems caused by overvoltage induced on incoming lines and transmitted to the structure.
Risk components for a structure due to flashes near a line connected to the structure	RZ: Component related to the failure of internal systems caused by overvoltage induced on incoming lines and transmitted to the structure.

.

3.2. Collection Areas

The collection areas are determined by the horizontal span of the land surface area of the substations and the height of the structures. The outer radius of the collection area is either dependent on the height of structures or the fixed values suggested by IEC 62305-2. Based on IEC 62305-2, the collection area of the shielding structures (AD) such as gantry and lightning masts, the area covers the horizontal span of ground surface area radially which is three times the structure’s height. Besides that, the collection area near the structures (AM) covers a 500 m radius of the ground area. For the collection areas to the line (AL) and near to the line (AI) such as bare conductors and busbars within the substations, the radial span distances are 20 m and 1000 m respectively. This measurement can be performed by using CAD tools to measure the footprint of the relevant installed structures in the substations. The collection areas possess the risk and shall normally cover the interest area where the equipment and human activities are located. As a result, the maximum collection areas are only up to the substations’ fence boundary.

3.3. Case Studies

Five cases of substations from three different countries have been chosen for the lightning risk assessment. The characteristics of the HV substation cases have been recorded as shown in

Table 6. Characteristics of the HV Substation Cases.

Case	Unit	Case 1	Case 2	Case 3	Case 4	Case 5
Location	State, Country	Kuala Lumpur, Malaysia	New South Wales, Australia	Selangor, Malaysia	Leyte, Philippines	Terengganu, Malaysia
Ur	kV	132	132	500	230	132
Standard		IEC 61936-1 [35]	AS 2067 [36]	IEC 61936-1	IEEE C62.82.1	IEC 61936-1
BIL	kVp	650	650	1550	1050	650
Area (Fence)	m2	20,690	8400	208,030	1360	5230
NG/ NGS	/km2/year	28	3	16	28	20
S	m	28	28	49	38	28
LPL Class [19]	-	I	I	III	II	I

. The substation characteristics primarily cover the location, voltage system (Ur), layout design, types of shielding, and sources of lightning flash density. LPL classes are determined based on Table 3.

4. Results and Discussions

The results of R1 and R2 for five substation cases are shown in

Table 7. Result of Risk Value of Loss of Human Life (R1).

Risk Component	Case 1	Case 2	Case 3	Case 4	Case 5
R1	1.17 × 10−4	4.47 × 10−6	2.75 × 10−3	2.82 × 10−5	1.81 × 10−5
RA1	1.56 × 10−11	4.10 × 10−13	2.64 × 10−10	3.17 × 10−12	1.74 × 10−12
RB1	2.06 × 10−5	1.35 × 10−6	8.72 × 10−4	1.05 × 10−5	5.76 × 10−6
RC1	7.81 × 10−5	2.05 × 10−6	1.32 × 10−3	1.27 × 10−5	8.72 × 10−6
RM1	4.60 × 10−21	2.05 × 10−22	1.38 × 10−19	7.16 × 10−21	9.84 × 10−21
RU1	1.60 × 10−12	8.04 × 10−14	4.17 × 10−11	3.81 × 10−13	3.49 × 10−13
RV1	2.12 × 10−6	2.65 × 10−7	1.37 × 10−4	1.26 × 10−6	1.15 × 10−7
RW1	1.60 × 10−5	8.04 × 10−7	4.17 × 10−4	3.81 × 10−6	3.49 × 10−7
RZ1	0.00	0.00	0.00	0.00	0.00

and

Table 8. Result of Risk Value of Loss of Service to the Public (R2).

Risk Component	Case 1	Case 2	Case 3	Case 4	Case 5
R2	1.54 × 10−4	6.36 × 10−6	3.92 × 10−3	4.11 × 10−5	2.53 × 10−5
RB2	3.75 × 10−5	2.46 × 10−6	1.58 × 10−3	1.90 × 10−5	1.05 × 10−5
RC2	9.37 × 10−5	2.46 × 10−6	1.58 × 10−3	1.52 × 10−5	1.05 × 10−5
RM2	5.53 × 10−21	2.46 × 10−22	1.66 × 10−19	8.60 × 10−21	1.18 × 10−20
RV2	3.85 × 10−6	4.82 × 10−7	2.50 × 10−4	2.28 × 10−6	2.09 × 10−7
RW2	1.93 × 10−5	9.64 × 10−7	5.00 × 10−4	4.57 × 10−6	4.19 × 10−6
RZ2	0.00	0.00	0.00	0.00	0.00

. The bolded results indicate the cumulative risk values or the individual risk components which exceeds the tolerable risk RT as shown in Table 2. It is found that RB1, RC1, RV1, and RW1 are the significant risk components which exceeds RT for R1 in some cases. On the other hand, RB2, RC2, RV2, and RW2 are the significant risk factors that contribute to high values in results for the R2 case. RZ1 and RZ2 are zero values due to the risk factor selection that the earth bonding for the aerial power line shields to the internal equipment bonding bar (CLI) are commonly joint. Besides that, RM1 and RM2 have shown less significant risk values due to the selection of the continuously covered shields for internal equipment (KS2) and bonded metal cable trays to lay the internal cabling (KS3).

4.1. Risk Factor Characteristics

Based on IEC 62305-2, the characteristics of the risk factors can be summarized in

Table 9. Risk Factors Characteristics.

Risk Factors	Fixed Value Factors	Measurable Risk Factors	Ambiguous Risk Factors
Number of dangerous events (N)	CI, CT	AD/ADJ, AM, AL, AI	CD, CE
Probability of the Losses (P)	KS2	KS1	PTA, PTU, PB, PSPD, PEB, PLD, PLI, CLD, CLI, KS3, Uw (KS4)
Loss Values (L)	LT, LF, rt, hz	nz, nt	rf, rp

. The characteristics are basically divided into three main categories: fixed value factors, measurable risk factors, and ambiguous risk factors.

The fixed value factors are uniform in selection due to the clear descriptions of the risk factors shown in the standard. For measurable risk factors, practitioners are required to perform the calculation such as identifying the collection areas by using CAD tools. Lastly, there is a group of risk factors that may be found ambiguous for practitioners to select when performing the risk assessment.

4.1.1. Common Values of Risk Factors

The risk factors that are having common fixed values for outdoor HV substation cases are shown in

Table 10. Common Risk Factors.

Risk Factors	Selection	Value
CI	Aerial	1
CT	HV Power	0.2
LF	Substation	0.33
LT	Injury due to electrical shock	0.01
rt	Gravel, moquette, carpets	0.0001
hz	Low-level panic (less than 100 people)	2

.

4.1.2. Significant Range of Risk Factors

The range of risk factors can be estimated by registering the highest to lowest values of the risk factors, and by estimating the ratio of the factor values to obtain the approximate range of risk values for each component. Some of the significant range of risk factors based on IEC 62305-2 are shown in

Table 11. Major Significant Range of Risk Factors.

Risk Factors	Highest Factor Value	Lowest Factor Value	Factors Ratio & Affected Risk Components
CE	1 (Rural)	0.01 (Urban with high building)	100 RU, RV, RW, RZ
PTA	1 (No protection)	0.01 (Effective soil equipotentialization)	100 RA
PTU	1 (No protection)	0.01 (Electrical Insulation)	100 RU
KS3	1 (Unshielded cable)	0.0001 (Shielded cables in metal conduits)	10,000 RM
rf	1 (Solid explosive)	0.001 (Low fire)	1000 RB, RV

. The value of these risk factors varies depending on the substations’ characteristics. For example, the environmental factor (CE) and function of fire and explosion risk of structure (rf) have shown the potential of change of risk values in the maximum range of 100 and 1000.

After tabulating the major risk factors as shown in Table 11, the ratio of the factor values can be registered as shown in

Table 12. Accumulated Variation of Risk Values for Risk Components.

Risk Factors	RA	RB	RC	RM	RU	RV	RW	RZ
CD	8	8	8		8	8	8
CE					100	100	100	100
PTA	100
PTU					100
PB	10	10
PSPD			5	5			5	5
KS3				10,000
KS4				6
PEB					2	2
PLD					50	50	50
PLI								10
CLD			1		1	1	1
CLI								10
hz		2				2
rt	10				10
rf		1000				1000
rp		2.5				2.5
Total	8 × 104	4 × 105	4 × 101	3 × 105	8 × 107	4 × 108	2 × 105	5 × 104
x, for 10x	4	5	1	5	7	8	5	4

to estimate the approximate range of the risk values for each component in the power of ten. For example, it is shown that RV is having the highest variation of risk values mainly due to CE and rf. Besides that, KS3 is the risk factor with the highest range in variation of value which mainly affects RM.

4.1.3. Ambiguity of Risk Criteria

The ambiguity in the risk criteria arises due to the lack of risk factor criteria selection options to represent substation case. For example, the probability of persons being injured because of the failure of internal systems (Lo) has a limited set of selection options, which limits them to select the only “risks of explosion”. In addition, in fact, that the operators find it much easier and more frequent to access urban substations in the aspect of CE than rural substations, which carry a greater risk of injury. The ambiguous risk criteria which are commonly found in a typical HV substation are shown in

Table 13. Ambiguous Risk Criteria.

Risk Factors	Discussions and Remarks
CE	Rural substations are not necessarily more likely to cause injury to humans when compared to urban substation, and the relative topological location and pollution level of the substation have not been considered. Besides that, the future development around the substations will be re-evaluated over time. Moreover, most rural substations are in autonomous mode and without an on-site operator.
PTA	For effective soil equipotentialization in the substation especially for touch voltages, the steel gridded carpet is bonded to the earth grids for operators to stand on. The effectiveness of earthing grid is also depending on the actual soil condition. Earthing resistance test shall be conducted and verified after the installations. Practitioners shall reserve the possibility of high acidic soils and theft events causing the discontinuity of connection and affecting the effectiveness of the earthing over time.
PTU	The actual performance of the insulation is based on the test results of the equipment. The degraded insulation of the aging equipment shall be considered over the years.
PB	Some down-conductors or bonded structures are having the same size or even bigger than the LPL classes of substations. Besides that, the factor to have segregation of space between the dangerous sparks and the combustible fuel to cause the fire is absence.
PSPD/PEB	The level of LPL for SPDs is independently specified and not necessary to match the LPL of LPS.
Uw (KS4/PLD/PLI)	The selection of the rated impulse withstand voltage of the internal system is dependent on the product design and type test history. Most of the LV equipment is tested up to 1000 DC volts for insulation. The sensitive electronics are normally protected via external SPDs and are not susceptible to impulse voltage due to lightning.
KS3	The internal wiring includes the intrinsic circuitry of the internal systems which is unable to be quantified practically. Sometimes, several sections of the connected wires of internal systems are directly buried in the ground or exposed to air.
rt	The resistivity of the soil is depending on the infiltration such as events after rain and flood. Besides that, substations will have multiple layers of soil unlike the uniformed soil specified in the standard.
nz, nt	The hours of operators working in the structure and the zone per day are unpredictable depending on the daily activities on site. The continuous ongoing construction activities at the site may expose higher risk.
hz	The level of panic based on the special hazards is undefined for the outdoor substation cases due to non-uniformed designs. The effective egress path in the substation may affect the safety of operators.
Lo	Only having “Risk of explosion” can be selected for the substation case.

. Note that typical HV substation means a conventional HV substation that is outdoors.

4.1.4. Ambiguity of Risk Values

The risk values published by IEC 62305-2 are very comprehensive and critically useful to perform the risk assessment. In spite of the convenience of applying straightforward risk values to the risk assessment process, practitioners may find it difficult to comprehend the basis of the risk values provided by the standard. Moreover, the current standard also lacks specific guidance for practitioners to apply in the HV substation context. The ambiguous risk values based on IEC 62305-2 for a typical HV substation are shown in

Table 14. Ambiguous Risk Values.

Risk Factors	Discussions and Remarks
CD	The sensitivity of change of risk values in relation to the substation structures’ height compared to surrounding structures is not defined.
CE	The risk value is dependent on the relative height of the surrounding object. The standard does not present the sensitivity of risk values to the features of the surrounding structures.
PTA	The risk value has not reflected the level of the equipotentialisation as the earthing grid system with low resistance is normally applied to HV substations to prevent the built-up induced overvoltage. Besides that, the level of insulation of the protected equipment is absent as well in relation to the risk value.
PTU	The selection has shown the absence of the probability when the human is electrocuted when touching the bonded structures during lightning strikes in relation to the magnitude of stroke currents, earthing design, and insulation level.
PB	The down-conductor connections for other LPL classes are not mentioned and defined. Besides that, the minimum stroke current and striking radius are based on the assumed fixed value of surge impedance.
CLD/CLI	The risk values is depending on the effectiveness of shielding, grounding, and isolation conditions.
Uw (KS4/PLD/PLI)	The sensitivity of impulse voltage selection to cause the change of risk values is not defined.
rf	The explosion or fire incidents in outdoor substations are dependent on the volume of combustible oil and fuel containment at the site. Besides that, the degradation of equipment insulations may contribute high risk of unnoticed internal failures. Moreover, the fire load (qc) is dependent on the total calorific value of the insulating oil over the specific floor area where oil spillage on the uncertain surrounding surface may affect the spread. It is assumed that the substation is designed with an adequate fire radius from the fire source by not breaching the safe fire distance to the nearby oil-filled transformers. The risk value based on the selected fire risk factors may have a lack of consideration of the mentioned combined factors.
rp	In the event of an explosion or major fire incident, the location of the substation may determine the time for firemen to reach the site. The fire-fighting measures is depending on the initial planning and the efficiency during execution. These efficiency factors vary among utilities.
CT	The risk values are supposedly dependent on the effectiveness of the lightning shielding on the lines. The standard has not covered the level of effective shieldings.
LT	The only assumption is that 1% of people will experience an electric shock.
LF	The only assumption is that 1/3 of the people on site will experience the injury due to fire.
Lo	The risk values of power interruption due to damage to the internal system and the major equipment are similar. However, it also depends on the contingency level of switching to another network supply and the time duration for the repair and replacement of the faulty equipment.

.

4.1.5. Ambiguity Level of Risk Factors

In order to identify the ambiguous risk factors that potentially influence the significance level of risk values, Table 13 and Table 14 are analyzed. The risk factors which are mentioned in both Table 13 and Table 14 are summarized in

Table 15. Risk Factors Shown in Both Table 13 and Table 14.

Risk Factors	RA	RB	RC	RM	RU	RV	RW	RZ
CE					100	100	100	100
PTA	100
PTU					100
PB	5	5
PLD					50	50	50
PLI								10
hz		2				2
Total	5 × 102	1 × 101	0	0	5 × 105	1 × 104	5 × 102	1 × 103
x, for 10x	2	1	0	0	5	4	2	3

. As a result, RU, RV, and RZ have shown a high level of ambiguity. It is known that the results shown in Table 7 and Table 8 indicate that RB, RC, RV, and RW have higher risk values, which are towards exceeding the tolerable risk. Due to this, when comparing the actual results with Table 15, RB and RV with ambiguous risk factors in the range of 10 and 10,000, respectively, could potentially bring the results to exceed the tolerable risk values. Practitioners will be made aware of these ambiguous risk factors through subsequent risk assessments.

On the other hand,

Table 16. Risk Factors Only Shown in Either Table 13 or Table 14.

Risk Factors	RA	RB	RC	RM	RU	RV	RW	RZ
CD	8	8	8		8	8	8
PSPD			2	2			2	2
PEB					2	2
KS3				10,000
KS4				6
CLI								10
rp		2.5				2.5
rf		1000				1000
rt	10				10
Total	8 × 101	2 × 104	1.6 × 101	1.2 × 105	1.6 × 102	4 × 104	1.6 × 101	2 × 101
x, for 10x	1	4	1	5	2	4	1	1

has shown the risk factors which are only mentioned in either Table 13 or Table 14. RB, RM, and RV have shown a high level of ambiguity when the risk assessment is performed. Similarly, when comparing the actual results, the ambiguous risk factors found in RB and RV are considered significant and will be highlighted in subsequent risk assessments.

In conclusion, the ambiguous risk factors will impact the results of the risk values. Table 13 and Table 14 summarise the risk factors which practitioners would find ambiguous if they are to conduct the risk assessment as per IEC 62305-2. These ambiguities and the lengthiness of the process of IEC 62305-2 may potentially cause the inaccurate representation of lightning risk on substations. However, the onerous summarized findings of the significant ambiguous risk factors can be emphasized for future assessments and research.

4.1.6. Comparison of Ambiguous Factors to Actual Cases

Based on the actual results shown in Table 7 and Table 8, RB, RC, RV, and RW are the prominent risk components for all cases. RB, RV, and RW have a high level of ambiguity. Furthermore, the significant risk factors such as CE, PLD, PLI, KS3, rt, and rf have to be emphasized and selected carefully while performing the lightning risk assessment.

4.2. Integrated Process of Lightning Risk Assessment

The integrated process is based on the required inputs to perform the lightning risk assessment. This process can be summarized in the flowchart shown in Figure 2. Furthermore, the process can be simplified by creating the risk assessment sheets by identifying the groups of risk factors as discussed earlier. Besides that, integration such as adopting IEEE 998 to determine the rolling sphere radius is crucial to determining the LPL risk values. By having CAD tools, the collection areas can be determined as well. In addition, the ambiguous risk factors can be adjusted to run the iterations of risk assessments.

Iterations of Lightning Risk Assessment

After obtaining the required inputs, practitioners can proceed to perform the lightning risk assessment by using the process flow and risk tables based on IEC 62305-2. The selection of risk factors should be taken into consideration when considering ambiguous risk factors as described in earlier sections. It is imperative to test the sensitivity of the result values in successive iterations with the range of probable changes in risk factors.

It is known that the previously generated results have shown some risk components exceeding the tolerable risk values. Thus, it is important for designers and practitioners to identify the risk factors that can be adjusted to improve the design. In principle, it is unlikely to change the fixed geographical aspects to improve the risk values. However, some other risk factors such as substation design such as LPS class and installations can be improved. Although the improvement measures will reduce the lightning risk values, it is noted that the additional materials and installations will incur higher costs. Based on these adjustments, the utilities and designers can at least make a fair decision to consider the exposed risk values and the incurred cost. The adjusted factors to improve the risk results are shown in

Table 17. Proposed Adjustment of Risk Factors-Improved-case.

Risk Factors	Proposed Adjustment
PB, PSPD, PEB	To next better LPS class, more provisions allocated
PLD, Uw	Install higher rated impulse withstand voltage equipment on site and lower resistance earth conductors
rp	Install automatic operated extinguisher and alarm that fireman to arrive within 10 min

. The improved-case results are shown in

Table 18. Result of Risk Value of Loss of Human Life (R1) -Improved-case.

Risk Component	Case 1	Case 2	Case 3	Case 4	Case 5
R1	8.88 × 10−6	5.40 × 10−7	6.15 × 10−5	1.48 × 10−6	2.03 × 10−6
RA1	7.81 × 10−12	2.05 × 10−13	2.64 × 10−11	6.35 × 10−13	8.72 × 10−13
RB1	1.03 × 10−6	2.70 × 10−7	3.49 × 10−5	8.38 × 10−7	1.15 × 10−6
RC1	7.81 × 10−6	2.05 × 10−7	2.64 × 10−5	6.35 × 10−7	8.72 × 10−7
RM1	1.28 × 10−23	5.69 × 10−25	7.68 × 10−23	9.95 × 10−24	2.73 × 10−23
RU1	3.21 × 10−15	1.61 × 10−16	1.67 × 10−14	3.81 × 10−16	6.98 × 10−16
RV1	4.24 × 10−9	2.12 × 10−10	2.20 × 10−8	5.03 × 10−10	9.21 × 10−11
RW1	3.21 × 10−8	6.43 × 10−8	1.67 × 10−7	3.81 × 10−9	6.98 × 10−9
RZ1	0.00	0.00	0.00	0.00	0.00

and

Table 19. Result of Risk Value of Loss of Service to the Public (R2) -Improved-case.

Risk Component	Case 1	Case 2	Case 3	Case 4	Case 5
R2	2.96 × 10−5	8.15 × 10−7	9.53 × 10−5	2.29 × 10−6	3.15 × 10−6
RB2	1.87 × 10−5	4.92 × 10−7	6.34 × 10−5	1.52 × 10−6	2.09 × 10−6
RC2	9.37 × 10−6	2.46 × 10−7	3.17 × 10−5	7.61 × 10−7	1.05 × 10−6
RM2	1.53 × 10−23	6.83 × 10−25	9.21 × 10−23	1.19 × 10−23	3.28 × 10−23
RV2	3.08 × 10−7	3.86 × 10−10	4.00 × 10−8	9.14 × 10−10	1.67 × 10−10
RW2	1.16 × 10−6	7.71 × 10−8	2.00 × 10−7	4.57 × 10−9	8.37 × 10−9
RZ2	0.00	0.00	0.00	0.00	0.00

. The bolded results indicate the cumulative risk values or the individual risk components which exceeds the tolerable risk RT.

For example, R1 for Case 3 is still exceeding RT, mainly due to the large collection areas and the risk of fire or explosions. Although the on-site autotransformers are generally having higher oil volume due to their higher MVA ratings, the comparison of fire spread area around the hazardous oil-filled autotransformers is relatively small compared to the overall switchyard. This has also shown that selecting the fire risk factors due to lightning strikes as discussed earlier remains ambiguous. The improved results have narrowed the list of concerned risk components, and this will help the practitioners to pay close attention to those risk factors.

Conversely, practitioners can expect worse-case risk results by assuming some less stringent designs. By adjusting the ambiguous risk factors to higher values, the practitioners can notice the changes in results. As discussed, some of the ambiguous factors such as CE has been interpreted wrongly in the text. The practitioners shall revisit the actual risk values to suit the actual case. Moreover, by applying higher risk values of LPS due to the leniency of selecting the next higher striking distance, practitioners can predict the potential increase of risk values due to human mistakes and aging installations. Besides that, there is a potential that conditions of actual bonding and shielding are not fully established in the substations. It could be due to broken connections after many years. The adjustment of risk factors is shown in

Table 20. Proposed Adjustment Risk Factors-Worse-case.

Risk Factors	Proposed Adjustment
CE	If the surrounding structure or tree around the urban substation is not higher than the substation’s structures, the environmental factor shall be considered “rural”.
PB, PSPD	To next worse LPS class
PB, PSPD, PEB	To next better LPS class, more provisions allocated
CLD/CLI	Separate bonded earth points
KS3	The internal wiring is not shielded and has no routing precaution when directly buried in a large area below the ground.

. The worst-case results are shown in

Table 21. Result of Risk Value of Loss of Human Life (R1) -Worse-case.

Risk Component	Case 1	Case 2	Case 3	Case 4	Case 5
R1	2.55 × 10−4	9.70 × 10−6	3.65 × 10−3	6.56 × 10−5	3.94 × 10−5
RA1	3.90 × 10−11	1.02 × 10−12	5.28 × 10−10	6.35 × 10−12	4.36 × 10−12
RB1	5.15 × 10−5	3.38 × 10−6	1.74 × 10−3	2.09 × 10−5	1.44 × 10−5
RC1	1.56 × 10−4	4.10 × 10−6	1.32 × 10−3	3.17 × 10−5	1.74 × 10−5
RM1	9.21 × 10−13	4.10 × 10−14	1.38 × 10−11	1.79 × 10−12	1.97 × 10−12
RU1	3.98 × 10−12	1.61 × 10−13	4.17 × 10−11	9.52 × 10−13	6.98 × 10−13
RV1	5.26 × 10−6	5.30 × 10−7	1.37 × 10−4	3.14 × 10−6	2.30 × 10−7
RW1	3.98 × 10−5	1.61 × 10−6	4.17 × 10−4	9.52 × 10−6	6.98 × 10−6
RZ1	1.84 × 10−6	8.20 × 10−8	2.76 × 10−5	3.17 × 10−7	3.49 × 10−7

and

Table 22. Result of Risk Value of Loss of Service to the Public (R2) -Worse-case.

Risk Component	Case 1	Case 2	Case 3	Case 4	Case 5
R2	3.41 × 10−4	1.41 × 10−5	5.54 × 10−3	9.37 × 10−5	5.63 × 10−5
RB2	9.37 × 10−5	6.15 × 10−6	3.17 × 10−3	3.81 × 10−5	2.62 × 10−5
RC2	1.87 × 10−4	4.92 × 10−6	1.58 × 10−3	3.81 × 10−5	2.09 × 10−5
RM2	1.11 × 10−12	4.92 × 10−14	1.66 × 10−11	2.15 × 10−12	2.36 × 10−12
RV2	9.56 × 10−6	9.64 × 10−7	2.50 × 10−4	5.71 × 10−6	4.19 × 10−7
RW2	4.78 × 10−5	1.93 × 10−6	5.00 × 10−4	1.14 × 10−5	8.37 × 10−6
RZ2	2.21 × 10−6	9.84 × 10−8	3.32 × 10−5	3.81 × 10−7	4.19 × 10−7

. The bolded results indicate the cumulative risk values or the individual risk components which exceeds the tolerable risk RT.

After both improved and worse-case iterations have been performed, the practitioners will be able to identify the adjusted ambiguous risk factors which significantly affect the result. As the process reaches completion, it is considered satisfactory when no further adjustments of risk factors are required to improve the situation for the HV substations.

5. Conclusions

Historically, many HV substations have experienced lightning shielding failures in the past, despite various lightning protection methods that have been implemented in the design, such as RSM, direct angles, and empirical curves. This has made designers and practitioners face difficulties to analyze the adequacy of the designs which are fundamentally conducted incoherently. IEC 62305-2 has provided an alternative method for practitioners to estimate the risk values via the risk assessment process. As discussed in earlier sections, although IEC 62305-2 has not specifically stated the applicability of the lightning risk assessment on the HV substations, a similar representation of the substations to the structures [11] can be made. Besides that, the characteristics of the outdoor HV substations such as BIL will be used as the inputs to determine the LPL of the LPS. Apart from that, this integrated risk assessment process requires some inputs which are generated from the CAD tools and based on some external resources such as meteorological data and other international standards. Moreover, the integrated process will also involve identifying the significant risk factors which are governing the results. IEC 62305-2 specifies a limited selection of risk factors for HV substations. It is crucial that practitioners adjust any ambiguous risk factors in subsequent assessments to estimate the significance of the results. The adjustment of the significant risk factors is crucial for the practitioners to identify the risk factors that can be brought forward to improve the LPS designs.