ARC FLASH ASSESSMENT GUIDE
Author
CLASSIFIED
SR 11.13122
25/09/2011
P Freeman PTE/EELE
Confidential
SR.11.13122
Arc Flash Assessment Guide
by
Peter Freeman (PTE/EELE)
This document is Confidential. Distribution is restricted to the named individuals and organisations contained in the
distribution list maintained by the copyright owners. Further distribution may only be made with the consent of the
copyright owners and must be logged and recorded in the distribution list for this document. Neither the whole nor
any part of this document may be disclosed to any third party without the prior written consent of the copyright
owners.
Copyright SIEP B.V. 2011.
Shell International Exploration and Production B.V., Rijswijk
Further electronic copies can be obtained from the Global Information Centre.
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Executive summary
Exposure of workers to the energy associated with arcing faults can and has caused serious
injuries and even deaths within the Shell group of companies.
Since the mid 1990s, there has been increasing attention within the electrical community in North
America to quantify and reduce the hazards associated with electrical arc flashes. Review of older
non-internal arc protected IEC switchgear has identified the potential of similar arc flash-overs in
such equipment.
Purpose of this guide is to provide not only a description of the recommended arc flash
assessment processes to be followed, but also practical advice as to difficulties that may be
encountered and possible methods of resolving them.
The arc flash assessment process described in this document is intended to fully satisfy the Shell
HSEE guidelines in the use of PPE.
Apply the following Hierarchy Of Control to manage Personal Protective Equipment use.
First:
Eliminate the Hazard or exposure.
Second:
Substitute materials or equipment to reduce the Hazard or exposure.
Third:
Use engineering Control of the Hazard or exposure.
Fourth:
Use procedural Control of the Hazard or exposure.
Fifth:
Use Personal Protective Equipment
The output of an arc flash risk assessment produced following this guide includes







Identification of where arc flash risk can be eliminated by only working on isolated
equipment
Identification of where arc flash risk can be reduced by using alternative techniques or
measurement points
Identification of mitigating actions that can be taken to reduce the probability of an arc
flash event occurring, looking at both the current practices and what additional
mitigations are feasible to introduce
Assessment of the residual levels of risk with no mitigation in place, with current
mitigations in place and after additional measures are implemented. This gives an
appreciation of the effectiveness of mitigation actions and basis for an objective
assessment of the level of actions needed to achieve ALARP.
Identification of any additional procedures and controls needed to reduce the probability
of an arc flash event occurring and to ensure that the correct levels of site management at
the location are involved depending on the level of the risk being managed.
Identification of when and where wearing of additional PPE is required to achieve ALARP
Identification of improvements needed to reduce the maximum arc flash level a person
may be exposed to at a location to below the target maximum level of 13 cal/cm 2. These
improvements can be prioritised in terms of the level of risk reduction achieved so as to
provide a basis for a location improvement plan.
This review process is recommended to be followed at all locations. Actions additional to those
given in this document may be required in some jurisdictions, where legislation or local regulatory
authorities have proscribed the actions to be undertaken. In such cases these mandated actions
must be completed in addition to those recommended in this document.
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Table of contents
0.
Executive summary
II
1.
Introduction
5
1.1. Why is arc flash now seen as an issue?
5
1.2. Business implications of an arc flash incident
6
1.3. Differences in regulatory requirements
6
1.4. Arc Flash energy units
7
General approach to management of Arc Flash Risks
8
2.1. Bowtie representation
8
2.2. General approach
9
2.
3.
4.
Arc Flash Risk Assessment procedure
13
3.1. Information required
14
3.2. Process steps to be followed
14
3.2.1.
Generic switchgear actions
15
3.2.2.
Step 1 – Eliminate the risk
16
3.2.3.
Step 2 – Evaluate the switchgear
16
3.2.4.
Step 3 – Calculate arc flash energy levels (where required)
17
3.2.5.
Step 4 – Review of the outcome of energy level calculations
18
Example Switchboard Assessment Summary Tables
19
4.1. Example LV Switchboards assessment form
19
4.2. Example HV switchboard assessment form
25
4.3. Example comparison table of overall clearance times vs tested IAC clearance times 31
4.4. Example record of assessment for Switchboards operated remotely or
de-energised
31
5.
Conclusions
32
6.
Bibliographic information
33
7.
Report distribution
34
Appendix A.
Commentry & advice on Arc flash assessment Procedures
35
A.1 Comments on Step 1 Elimination of the risk
35
A.2 Comments on Step 2 Evaluate the switchgear
36
A.3 Comments on Step 3 Calculate arc flash energy levels
36
A.4 Comments on Step 4 – Review of the outcome of energy level calculations
37
A.4.1
HV Circuits
38
A.4.2
LV Circuits
38
A.5 Use of temporary changes to protection settings
Appendix B.
Withstand times of Internal Arc Tested switchgear
39
40
B.1
IEC and US standards
40
B.2
Effect of reduced fault currents
40
Appendix C.
Comparison of clearance times and energy levels
41
C.1
HV switchgear (>1kV)
41
C.2
LV switchgear (400/415v & 690v)
42
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Confidential
Calculation of arc flash energy levels using IEEE 1584 spreadsheet
43
D.1
Calculation from “fixed” fault level sources
43
D.2
Calculation from “variable” sources of fault current.
45
D.3
Determining operating conditions for arc flash calculations
47
D.4
Entering values in the IEEE spreadsheet data input sheet
49
Appendix E.
E.1
E.2
2
Additional busbar insulation
2
E.1.1
LV switchboards
3
E.1.2
HV switchboards
3
Cable terminations
Appendix F.
F.1
Additional insulation and Cable Terminations
Scope for protection to minimise arc flash energy levels
4
5
HV switchboards
6
F.1.1
Non IAC tested switchboards Voltage range up to 15kV
6
F.1.2
Non IAC tested switchboards - Voltage range above 15kV
7
F.1.3
IAC tested HV switchboards
8
F.2
LV Switchboards
10
F.3
Summary of practical solutions
13
F.3.1
Non IAC-tested HV switchboards up to 15kV
13
F.3.2
Non IAC-tested switchboards above 15kV
13
F.4
Summary of solutions for LV switchboards
14
F.4.1
IAC tested switchboards
14
F.4.2
Non IAC-tested switchboards
14
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1.1.
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Introduction
Why is arc flash now seen as an issue?
Since the mid 1990s, there has been increasing attention within the electrical community in North
America to quantify and manage the hazards associated with electrical arc flashes.
This issue came to the fore in the United States when there was recognition in late 1990’s that
there are a large number of incidents where persons were being seriously hurt or killed, not by the
widely acknowledged risk of electrocution, but by the effects of blast and heat following a flash
over.
A report compiled in 1990’s estimated that five to 10 arc flash explosions happened in the USA
every day, resulting in 1 to 2 deaths per day.
In considering these figures it should be seen in context of relating to a continent with more than
240 million people and the highest energy use per person in the world, hence there are a very
large number of electrical installations and relatively large numbers of persons operating or
working on them.
Sufficient evidence was collected that the US Occupational Safety & Health Administration
(OSHA) was persuaded to act. OSHA dictated that all sites should
perform energy calculations,
label switchgear with the potential energy level,
provide additional PPE to match the potential energy release,
identify closest approach without wearing additional PPE that would not result in 2nd
degree burns
provide training to staff regarding arc flash hazards in their workplace.
Review of older non-internal arc protected IEC switchgear has identified the potential exists of
similar arc flash-overs with consequent severe effects. However within European countries
concerns about reducing the effect of internal short circuits were being considered from 1970’s
onwards and there have been attempts within individual countries to develop national or industry
standards to address this issue e.g. PELHA in Germany. However it was not until a common
approach was adopted by the IEC that testing regimes applicable to all countries were developed.
Reflecting this international common approach, the requirement for internal arc protected
switchgear has been included in the DEP 33.67.51.31-Gen for HV switchgear since 1985 and the
DEP 33.67.01.31-Gen. for LV switchgear since 1998 (Testing requirements for “arc resistant”
switchgear built to North American standards are given in IEEE C37.20.7-2001). IEC switchgear
manufactured before those dates and North American switchgear not tested in accordance with
IEEE C37.20.7 are to be regarded as non-Internal Arc Controlled (IAC) switchgear.
The above statement regarding existing equipment may be modified only if the manufacturer can
confirm that the design of switchgear prior to the adoption of the IEC standards met the
requirements for the subsequent IAC tests without modification. This reflects the fact that some
manufacturers had already put on the market IEC designs which were IAC compliant before the
tests were adopted by the IEC.
Note IEC test for LV switchgear (IEC/TR 61641) is not accepted within all jurisdictions therefore it
remains a technical report and is not a full standard.
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Within the Shell group we have not separately categorised electrical incidents as arc flash
incidents. Such incidents have occurred at many locations, not only in US but in other countries as
well.
Recent frequency rate of such incidents within the group has been one or two per year and in
every instance those involved in the incidents were hospitalised at best or died immediately or
soon thereafter.
Since our experiences mirror to a degree those experienced in the US, it follows that the issue of
arc flash is not restricted to US locations or locations using equipment built or operated to US
standards, it applies to all group locations.
Nevertheless the differences in standards used in specifying equipment and/or operating practices
between Europe and US do affect both the probability of such events occurring and their potential
consequences.
1.2.
Business implications of an arc flash incident
Not only can an arc flash incident affect people but there are also usually significant implications
in terms of cost and lost revenue or margin.
Even if the equipment is designed to control an arc (i.e. is to an IAC design), it can be seriously
damaged and need substantial repairs and extensive cleaning. Often the contamination of
conductive carbon or metal spreads to other equipment in the substation / switchroom and the
cleaning programme can be very extensive. In many cases complete replacement of part or all of
the equipment is required. There will be a loss of function for periods typically ranging from weeks
to many months. Not only the direct repair costs but also the consequential losses to the business
can be very high.
From a purely business perspective therefore, actions which prevent arc flash over’s from
occurring generate maximum benefit in terms of avoiding additional costs or loss of margin.
Where an arc flash does occur then rapid extinction of the arc not only limits the energy a person
may be exposed to, but also reduces the extent of damage to equipment and therefore potentially
cost of repairs and / or lost production. This extinction can come from design of the equipment or
operation of protective devices.
1.3.
Differences in regulatory requirements
As mentioned in section 1.1 in the US there are proscribed actions to be taken with regard to arc
flash hazards. These are the actions most regularly mentioned in literature about arc flash.
However these actions should not be taken in isolation. There is a general hierarchy of controls
which the US regulator requires to be in place that matches almost exactly those referred to in the
Shell HSSE & SP Control Framework, namely:
Apply the following Hierarchy Of Control to manage Personal Protective Equipment use.
First:
Eliminate the Hazard or exposure.
Second:
Substitute materials or equipment to reduce the Hazard or exposure.
Third:
Use engineering Control of the Hazard or exposure.
Fourth:
Use procedural Control of the Hazard or exposure.
Fifth:
Use Personal Protective Equipment
For Shell sites within US jurisdiction, actions taken must comply with their national requirements. In
jurisdictions other than the US/Canada, the direction provided by regulators is less explicit.
Typically a target or goal setting approach is taken rather than setting prescriptive actions.
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The direction given by other regulators is that if the site feels that the equipment is unsafe to
operate, or the actions to be taken are felt to be unsafe, then the work should not proceed until
these concerns are adequately addressed. Arc flash hazards are not separately addressed and
are treated in similar manner to electrocution or other electrical hazards.
The interpretation taken by regulators is that, if reliance is placed mainly on additional PPE to
ensure safety, then inherently the proposed actions or work scope does not meet the advice given
since PPE does not prevent an incident from occurring.
Strong preference is given to being able to demonstrate adequate measures to prevent an arc
flash incident occurring in the first instance. Regulators do not wish to see efforts aimed at
mitigating the effects of an incident reducing attention given to the primary focus of reducing the
probability of an incident occurring.
A further consideration is the requirement to be able to demonstrate we are compliant with As
Low As Reasonably Practical (ALARP). This means in some instances taking precautions which
may be in excess of that required purely from a conventional risk assessment.
Essentially the above means that
1. The equipment, through a combination of correct selection, installation, maintenance and
operation, should be safe to operate at all times provided that the previously mentioned
barriers are in place and are followed.
2. In some (but not all) cases, PPE can help mitigate the consequences to an individual should the
above barriers be inadvertently breached.
1.4.
Arc Flash energy units
There are two methods of expressing the energy released in arc flash calculations, Joules/cm2 or
cal/cm2. Values expressed in cal/cm2 are used in this report for convenience since these currently
are far in wider use than their SI equivalents (even though in principal J/cm2 is the “correct” S.I.
unit).
These values can be compared using the equation:
5.0 J/cm2 = 1.2 cal/cm2
Hence for values commonly used in this report the equivalent J/cm2 values are
1.2 cal/cm2
=
5
J/cm2
13
cal/cm2
=
55
J/cm2
40
cal/cm2
=
167 J/cm2
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General approach to management of Arc Flash Risks
2.1.
Bowtie representation
The bowtie relating to arc flash hazard can be represented as
Top Event
Loss of Control - Arc Flash
T
h
r
e
a
t
s
1.
Controls
Recovery Measures
- Design for incident energy
(limit fault current or duration)
- PPE
- Control of Personnel (distance
from Arc Flash)
- Physical Barrier
Critical Activities
- Inspection and Maintenance
Threats – Operating
and Maintaining
Switchgear
- Competency development
(training)
Consequence – Major
injury or Fatality
C
o
n
s
e
q
u
e
n
c
e
- Work practices
The Shell approach to risk management is to
1. Ensure the barriers to the incident on the left hand side of the bowtie are as robust and
effective as possible.
2. After these barriers are in place then consider how to reduce the effect on the incident. In
arc flash terms this means either reducing the amount of energy released and/or
relocating people away from the possible incident location.
3. The final action is to wear additional PPE, but this is seen as a method of last resort and
only applied after all other actions are taken. In this context, provided prevention and
mitigation are sufficient in extent and robustness, the wearing of PPE may be beyond what
is required by assessment of risk level by the business. Wearing of additional PPE could
therefore be seen as demonstrating ALARP rather than significantly reducing the level of
risk to the business or individual.
From a business and personnel safety perspective it is logical to focus on prevention since it
provides the maximum financial benefit as well as providing the maximum protection for the
individual.
The other aspect of Shell approach to risk management is that when barriers are identified, they
are “actively managed”.
“Actively Managed” means their profile is kept high so people remain aware of the requirements
and there are audits or checks to ensure the barriers remain sound and are in place i.e. what
happens in practice matches what should happen theoretically.
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General approach
Where there are no mandated requirements from national regulator or local legislation the
following is recommended as the hierarchy of actions to be taken.
1. Educate and train staff to understand and recognise where arc flash hazards may exist.
Ensure their role is fully understood in providing effective barriers to arc flash events by
following procedures, completing QA checks and similar activities. Highlight that, wherever
there doubt exists, advice should be sort rather than continuing with any action.
2. All work which involves switching or working on live equipment is challenged to determine if
there is no practical alternative to live working. Where working dead can be implemented,
then practices and procedures should be to be changed to suit.
Example
 Racking in/out of voltage transformers can nearly always be planned to be done when deenergised.
3. If working live is required e.g. to isolate a circuit to allow subsequent maintenance or
inspection then, where possible, choice of live working point should be such as to minimize
risk either to the business or to the individual.
Examples
 A single transformer feeder fed switchboard where isolation of board could be by
operating the LV incomer or by tripping HV feed to transformer. If energy levels are lower
at HV board or if the HV board is an IAC design and the LV board is not, then isolation
could be best performed at HV switchboard.
 Use remote switching of circuits where such features exist rather than operating from
directly in front of the switchgear
 Use points which are protected by fault limiting devices for phasing out or voltage checks
4. The existing barriers on site to an arc flash incident occurring are to be reviewed and where
necessary reinforced. Note should be taken that current rules will almost certainly have been
written with risks of electrocution as the foremost hazard and may not consider prevention of
arc flash events as a specific hazard. Reinforcement should take the form not only of
improving the barriers but also considering how they can be made robust through audits and
additional checks which assist in the correct execution of the task.
Example
 Before issuing clearance for electrical work, the clearance signatory requires the
technician to confirm he has the correct test equipment against a check list of the
equipment required against common electrical tasks. In this way the technician will not be
tempted to short cut procedures due to not having correct equipment when he arrives at
the substation (which is often remote from workshops).
5. The installation is reviewed to establish if the energy released in an arc flash incident could
be reduced and what are the resultant energy levels. Effectively this constitutes a review of a
significant part of the protection schemes for the site and experience elsewhere has shown
that some improvement can nearly always be made. The same experience shows that there is
a high probability that some addition or alteration to existing schemes may be required to
reduce potential energy release levels to acceptable levels.
6. Establish if, and if so where and when, additional PPE can be used or additional controls are
required, to reduce risk to individuals and demonstrate ALARP. Amend practices and
procedures to match these requirements.
Note Use of PPE as the only mitigating action against risk from arc flash is not ALARP
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The controls required can be summarized by this flow diagram and its associated notes.
1
1
2a
1
2b
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FLOW CHART COMMENTS (Refer to numbers in boxes in flow chart)
1. If switchgear/switchboard is replaced, it should be designed such that the incident energy that the
operator is exposed to during an arc flash is limited to less than 1.2 cal/cm2 **. If the equipment
is modified, the modification should lower the incident energy that the operator is exposed to less
than the rating of the standard PPE used by the facility (typically this is between 1.2 cal/cm2 and
13 cal/cm2, but no greater than 13 cal/cm2).
** NFPA 70E – Standard for Electrical Safety in the Workplace states that maintaining arc flash
incident energies below 1.2 cal/cm2 to the head and torso improves the chances of
survivability to persons exposed to electric arc flash events.
Common ways that the switchgear can be modified to achieve ALARP are shown below. The
location or project should evaluate both replacement and modification options to determine which
method is most appropriate and to verify modifications are consistent with accepted company and
industry practices and standards.
A. Reduce the Energy released during an arc flash by
- Limiting fault duration
i. Use instantaneous circuit breaker protection (i.e., bus differential protection, zone
selective interlocking, maintenance switches, etc.)
ii. Minimize time overcurrent settings (without sacrificing selective coordination)
iii. Use current limiting fuses
- Limiting fault current (keep in mind that limiting fault current may have an overall effective of
increasing incident energy because of the impact on fault clearing times)
i. Increase transformer impedance
ii. Utilize current limiting fuses
iii. Operate parallel secondary systems as normal open
iv. Utilize current-limiting reactors
B. Reduce Exposure
- Change distance person is from gear
i. Utilize remote operation/control panels
ii. Utilize remote racking mechanisms for circuit breakers
- Install an internal physical barrier (Internal Arc Controls)
2. (a & b) To operate and maintain energized switchgear/switchboards having Arc Flash energy
exposure levels between 13 cal/cm2 and 100 cal/cm2, Arc Rated PPE shall be worn and formal
work authorization should be obtained and documented (existing work process, such as Permit To
Work, may be used to do this or the location may decide to develop their own authorization form )
The Senior Electrical Authority is responsible for reviewing and verifying the requirements for
authorization have been completed.
2. (a) Operations and maintenance of the energized switchgear between 40-100 cal/cm2 will be
allowed on an interim basis until the switchgear/switchboard can be modified or replaced.
Additionally, the process unit manager is required to approve the work authorization.
The work authorization process for performing operation and maintenance on
switchgear/switchboard shall include the following:
1.
2.
3.
4.
5.
6.
Approval by Senior Electrical Authority for 13-40 cal/cm2.
Approval by Senior Electrical Authority and process unit manager for 40-100 cal/cm2
Verification of PMs on time and none overdue
Completed Job Hazards Analysis (JHA)
Emergency Response Plan – including CPR trained watch at job site
Verification of electrical and HSE Competencies of person performing work
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General Note 1: The Arc Flash Consequence during operation and maintenance of the
switchgear will only occur if the switchgear is energized. It is an option not to
undertake modifications or replacement and instead only operate and maintain
the switchgear when it is de-energized.
General Note 2: Emphasis should be placed on preventing arc flash events from occurring in the
first place by properly maintaining electrical equipment in accordance with
Shell and industry standards and by using special precautionary techniques
when operating or maintaining the equipment.
General Note 3: PPE is the last line of defence and should be selected based on the incident
energy exposure potential. The following table provides guidance for selecting
the appropriate PPE to demonstrate ALARP.
It is important to note that PPE only protects against the burn consequence and not the impact or
arc blast, burning shrapnel, pressure waves and percussion consequence associated with the arc
flash. For these reasons PPE is regarded as being ineffective at protecting an individual at energy
levels above 40 cal/cm2, even if the thermal effects can be managed by heavier or thicker suit
materials.
Required PPE for Switchgear / Switchboard Arc Flash Energy Exposure Level
Exposure Level
< 1.2 Calories / cm2
1.2 to 13 Calories / cm2
Required PP E
No special PPE required, however standard level of PPE
assumed
Standard PPE and face shield (Nomex or equivalent
clothing, gloves, hearing and eye protection, etc.).
Depending on Location specifications, standard PPE will
be typically rated for incident energy exposure between 5
to 13 cal/cm2.
Supplemental PPE per location requirements should be
used for exposure levels greater than the standard PPE
rating and up to 13 calories/cm2.
13- 40 Calories / cm2
Special PPE – Arc Rated Flash Suit with hood
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Arc Flash Risk Assessment procedure
Following the hierarchy of controls mandated by the Shell HSEE guidance of:
First:
Eliminate the Hazard or exposure.
Second:
Substitute materials or equipment to reduce the Hazard or exposure.
Third:
Use engineering Control of the Hazard or exposure.
Fourth:
Use procedural Control of the Hazard or exposure.
Fifth:
Use Personal Protective Equipment
The outcome of an arc flash assessment must be able to answer five questions





What measures have been implemented to eliminate the risk of an arc flash event?
What measures have been implemented to reduce the consequences of an arc flash event?
What changes have been made to control of activities to reduce the probability of an arc
flash event occurring?
What changes have been made to procedures to reduce the probability or consequences
of an arc flash event?
What measures have been implemented to reduce the effect of the consequences of an arc
flash event on individuals?
An assessment which fails to provide substantive answers to all these questions would be
inadequate. An example of such an inadequate assessment would be one which comprises only of
a listing of energy levels at each switchboard and identification of the corresponding level of
supplementary PPE to be worn.
Where the assessment is part of a sequence of assessments of different facilities it may be that
answers to some of the questions are “have the recommendations from initial assessments been
implemented?” rather than developing or identifying new measures in every case.
The procedure to be followed therefore should seek to ensure each of the hierarchy of controls is
satisfactorily covered.
It should also be recognised that protection schemes and their associated trip times at arc flash
current levels have a significant impact on resultant potential arc flash energy levels.
Existing protection schemes would have been originally developed without consideration of arc
flash energy levels. Therefore existing schemes are highly unlikely to have been optimised so as to
minimise arc flash energy levels. Typically this means settings may need changing and potentially
additional protection elements added.
The implication is that an arc flash assessment study will almost inevitably result in changes being
recommended to protection schemes. This, as a minimum, will mean the associated documentation
will require updating to reflect proposed changes and in many cases additional expenditure to
implement additional protection functions. Depending on how the documentation is created e.g.
manually or by computer, the costs and difficulty of updating documentation will vary
significantly.
Similarly, existing protection schemes not using multi-function relays will require either upgrading
or additional protection relays fitted, if additional protection elements are seen as being
necessary.
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The costs and resources to validate any changes proposed to changed protection schemes are
recommended to form part of the arc flash risk assessment budget. This work is needed to be able
to provide firm recommendations as to remedial actions required. If it is not included as part of
the risk assessment the quality and clarity of any recommendations that can be made will be
significantly lower.
3.1.
Information required
To allow the assessment to be completed it is necessary to assemble information about the facility
to be assessed.
As a minimum the following information will be required







3.2.
The electrical safety rules and common practices / procedures followed at the facility. This
should explicitly cover any instances of “live” working.
Make, model and age of the switchgear to be assessed including operating times of circuit
breakers and the arc withstand time of any IAC switchgear.
Understanding of the routine actions undertaken on the switchgear e.g. how switching,
earthing, racking in / out and testing is carried out
Knowledge of test equipment used with the equipment to prove dead or phasing out
Single line diagrams for the overall system and for individual segments of the system
(depending on size of the system being assessed) and clear definition of modes of
“normal” modes of operation to be assessed.
Maximum and minimum fault levels at the switchgear to be assessed for “normal” modes
of operation.
Information to allow protection operation times at predicted arcing currents to be
determined. This can be either through knowledge of the protection types, setting values, ct
ratios etc or more conveniently the output of the protection co-ordination study with
protection curves drawn for schemes in use. Checks should be made that drawings or
records accurately reflect actual settings on the switchgear.
Process steps to be followed
To provide a framework for the process a list shall be prepared of the switchboards in the location
to be assessed and visits should be made to review actual operations done on equipment. This has
been found to act as an excellent prompt, even when personnel are familiar with the equipment. It
has been suggested that videoing the operations being performed provides a very useful reference
when these actions are being reviewed in meetings away from the workplace
The generic actions given in the following table should be compared against the actual equipment
operation and the review outcomes recorded. Note that if additional actions for particular types of
switchgear are identified then these should also be recorded and if required, such additional
actions can be added to the generic list.
Links are provided in this section betaeen the body of main text and the Commentary and Advice
held in Appendix 1. This is done to make the main document text and the required actions easier
to understand.
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Generic switchgear actions
Task Description
Typically applicable to
1.
Inspection of substation, short visit typically < 4hr
LV & HV substations
2.
Work in substation but not on switchgear (re-lamping,
painting etc) typically taking from 4hrs to 1-2 weeks
LV & HV substations
3.
Testing or modification of protection relay settings
4.
Test IR (megger) of a motor cable or feeder
LV & HV
5.
Rack In/Out feeder circuit breaker, starter or vacuum
contactor
LV & HV
6.
Rack In/Out voltage transformer
7.
Open / Close fuse protected motor contactors or feeder
switches
8.
Open / Close outgoing circuit breaker fed feeders or motors
9.
Open / Close Incoming switches or circuit breakers
HV
HV
LV & HV
HV
LV & HV
10. Open / Close Bus Section switches or circuit breakers
LV & HV
11. Proving a circuit is dead
LV & HV
12. Application of earth to circuit for motor contactor
HV
13. Application of earth to circuit for outgoing feeder
HV
14. Application of earth to circuit for incomer
HV
15. Application of earth to bus bars
LV & HV
16. Fault finding work in the circuit breaker or contactor
compartment (withdrawable component jammed or circuit
breaker/contactor will not open to allow the truck or starter
tray to be withdrawn)
17. Fault finding in LV circuit compartment
LV & HV
18. Inspection of bus bars
LV & HV
19. Modification to wiring or components in non-withdrawable
starters
20. Phasing out
21. Removal of fuse or fuse carrier when circuit is still live and is
not protected by upstream fuse or current limiting circuit
breaker i.e. where there is a high fault level
LV & HV
LV
LV & HV
LV
SR.11.13122
3.2.2.
- XVI -
Confidential
Step 1 – Eliminate the risk
Action
Review operating practices and identify where arc flash risk can be eliminated by only working on
equipment when it is de-energised.
Review operating practices and ensure that they include requirement for all persons not required
to be inside switchroom or substation leave when an activity with potential to create an arc flash
event is being undertaken.
Link to Commentary
3.2.3.
Step 2 – Evaluate the switchgear
This step combines consideration of substitution or alternative methods of working and
engineering / procedural controls. It also includes identification of whether switchgear is designed
to contain or manage the consequences of an internal arc for a period of time.
Actions
The practical checks to be made are;
a) Evaluate what tasks are undertaken with switchgear energised
b) Evaluate if, and exactly how, an arc flash can occur during these tasks.
Then
For switchgear which has no internal arc control features
i.
Evaluate possible mitigating actions (excluding additional PPE) that can be taken which
reduce the probability and consequences of a flash over.
ii.
Evaluate the residual risk to personnel after mitigation is applied and if further
mitigation is necessary e.g. additional PPE.
iii.
Evaluate which protection element will operate in event of a phase to phase fault and
the time before the current is interrupted in event of a bus bar fault or fault in an
outgoing circuit which can develop into a bus bar fault.
iv.
Evaluate the distance of individual (face/torso) from the possible flash over point.
Or
For switchgear which has internal arc control features
i.
Identify the time for which the switchboard has been tested to withstand or manage the
effects on an internal arc.
ii.
Evaluate if the design features to control the consequences of an internal arc are
effective for the identified tasks. If they are not covered then complete assessment as
above for a switchboard without internal arc control features. An example of this could
be that the internal arc tests do not cover racking in / out with doors open.
The example tables are provided in Appendix B show how the information in this step can be
collected and collated. The use of tables also allows checks that there is consistency in assessment.
The risks levels are expressed in terms of the standard Shell Risk Assessment Matrix.
The assessment is based upon the types of switchgear rather than switchboard identification or
location so only one example need be assessed which can then be applied to all similar
installations.
Link to Commentary
SR.11.13122
3.2.4.
- XVII -
Confidential
Step 3 – Calculate arc flash energy levels (where required)
Before undertaking this step, refer to Appendix D for guidance on entering data into the IEEE
spreadsheet
Action
Following the previous two steps and using the information thereby gained,
a) For switchboards which are claimed to be of internal arc control (IAC) design,
Check operating times of protective elements using the reduced current levels suggested by
IEEE spreadsheet (i.e. enter fault levels and voltage values and note the arcing current
calculated by the spreadsheet)
Provided the manufacturers arc withstand test time is not exceeded at these reduced arcing
current levels then board may be regarded as interally arc controlled and there is no
requirement to calculate arc flash energy levels.
This is subject to any restrictions the manufacturer may place regarding when its IAC status is
impaired. For example IAC conditions may not be met if doors are opened to allow racking
in/out of circuits. An “IAC” board may therefore still have some actions where it creates an
arc flash hazard and hence require arc flash energy levels to be calculated.
A nominally “IAC” board, where clearance times are not within tested time, must be treated
as though it is a non-IAC board, at least for those sections of the switchboard where the arc
flash containment tests rely upon the upstream protection to operate.
Link to Commentary
b) For switchboards which have not been tested for internal arc containment (non-IAC)
Evaluate (using IEEE 1584 spreadsheet) the potential arc flash energy level an individual may
be exposed to. This applies where an arc flash risk has been identified during the switchgear
review for particular actions. It also applies to actions where there is insufficient other
mitigation available or if the wearing of PPE is seen as being required to be ALARP.
Link to Commentary
SR.11.13122
3.2.5.
- XVIII -
Confidential
Step 4 – Review of the outcome of energy level calculations
As indicated in section 2 on Arc Flash Risk management, two arc flash energy levels are identified
namely 13 cal/cm2 and 40 cal/cm2 as being boundaries where changes to PPE and the
management of activities should take place.
It is recommended to restrict arc flash PPE used to maximum of two types, one suitable for use up
to 13 cal/cm2 and another suitable for use up to 40 cal/cm2. It follows therefore that outcomes
from calculated energy levels can be grouped into three categories, namely
1. >40 cal/cm2.,
2. >13cal/cm2 < 40cal/cm2
3. < 13 cal/cm2,
In the absence of any other factors this provides a prioritisation for remedial actions i.e. tackle
higher arc flash energy levels first.
Actions
a) Establish if there is scope for reducing energy levels by protection (i.e. reducing protection
operating times) – either through changes to existing settings or design ,or by adding fast
acting protection elements such as blocking schemes, bus zone protection or differential
protection.
Link to Commentary and advice on HV & LV switchgear protection
An alternative solution is to reduce clearance times only when racking in/out or other higher
risk actions are taking place through a temporary decrease of setting values. If such a scheme
is implemented then there must have rigorous safeguards to ensure that it is impossible for
incorrect settings to be left in place after the work is completed.
Link to Commentary
Further advice
Refer to Appendix F for discussion on the options available to improve clearance times and
reduce arc energy levels
b) Depending on the residual energy levels after any improvements in protection clearance times
have been implemented, refer to flow chart in section 2.2 and implement the necessary
engineering and procedural controls to comply with flow chart requirements.
This can be expected to include the wearing of additional arc flash resistant PPE for certain
tasks.
The implementation of engineering and procedural controls should follow the guidance given
in the flow chart and associated notes. However, as far as is possible, they should use existing
documentation and procedures at a location. This means that they should be integrated into
the existing safety systems at a location rather than being a completely new set of controls,
documentation and procedures.
The new practices and controls shall be applied to all switchboards reflecting the current arc
flash energy levels i.e. relaxation is only permitted after any improvement is implemented and
not before.
SR.11.13122
4.
- XIX -
Confidential
Example Switchboard Assessment Summary Tables
Mitigation Actionss and risk levels are shown as example only. Grey text should be deleted when using forms for an actual assessment
1.
Wear PPE
appropriate to
incident energy
level
B4
A4
A2
Work in substation
but not on
switchgear (relamping, painting
etc) typically taking
from 4hrs to 1-2
weeks
Insulation failure
in bus bar or
incoming
compartment
Entry to substations and
switchrooms is restricted to
competent people who have
undergone periodical refresher
training. Regular maintenance
inspection of switchboards
includes busbars
2.
Wear PPE
appropriate to
incident energy
level
B4
A4
A2
Test IR (megger) of
a feeder or motor
cable
Contact with
droppers through
openings at rear
of cubicle
Test before applying meggar and
use instruments with insulated
probes and suitable internal fuse
or short circuit protection for fault
level.
Training and experience of staff
3.
B4
A0
Inspection of
substation, short visit
typically < 4hr
Reason
Standard Mitigation Actions
Switchboard 2
Make and model
No
Risk level with
additional
mitigation
Insulation failure
in bus bar or
incoming
compartment
Entry to substations and
switchrooms is restricted to
competent people who have
undergone periodical refresher
training. Regular maintenance
inspection of switchboards
includes busbars
Task Description
Switchboard 1
Make and model
No
Possible
additional
actions
Risk Level with
standard mitigation
Example LV Switchboards assessment form
Risk level with no
mitigation
4.1.
7.
A4
A2
B4
A0 – if
procedures
are followed
A2 (for
case
where
mistakes
are
made)
Wear PPE
appropriate to
incident energy
level
B4
A4
A2
Wear PPE
appropriate to
incident energy
level
B4
A4
A2
Possible
additional
actions
Rack In/Out feeder
circuit breaker,
starter
Short inside
starter tray + misalignment
Training and experience of staff.
Test with 500v Megger that starter
bus bar stabs are clear to earth
and between phases before
racking in.
Wear PPE
appropriate to
incident energy
level
Open / Close
withdrawable circuit
breaker/switches fed
feeders after
maintenance
Internal fault in
C/B or switch due
to incorrect
maintenance
Last checks before completion of
maintenance are functional check,
continuity check and insulation
checks
Wear PPE
appropriate to
incident energy
level
Open / Close
withdrawable circuit
breaker/switches fed
feeders (normal
operation)
Internal fault in
C/B or switch
Check operation during routine
maintenance.
Open / Close fixed
switches or circuit
breakers
Internal fault in
C/B or switch
Checks on operation during routine
maintenance.
Switchboard 2
Make and model
No
B4
Standard Mitigation Actions
Switchboard 1
Make and model
No
Risk level with
additional
mitigation
6.
Risk Level with
standard mitigation
5.
Confidential
Reason
Task Description
4.
- XX -
Risk level with no
mitigation
SR.11.13122
9.
Proving a circuit is
dead
Application of loose
earth leads to circuit
for incomer or bus
bars
Possible
additional
actions
Contact with
droppers for work
in outgoing
compartments or
wrong side of bus
section switch
connections.
Training of staff to always check
labelling and compare circuit
identification against work scope
before starting work. Use
instruments with insulated probes
and suitable internal fuse or short
circuit protection for fault level to
prove dead
Use low fault
level source to
test instrument
before use
B4
A4
A0
Training of staff to always check
labelling and compare circuit
identification against switching
programme and work scope before
starting work. Use instruments with
insulated probes and suitable
internal fuse or short circuit
protection for fault level to prove
dead before attaching earths
Wear PPE
appropriate to
incident energy
level
B4
A0
Wrong
compartment
Switchboard 2
Make and model
No
Standard Mitigation Actions
Switchboard 1
Make and model
No
Reason
Risk level with
additional
mitigation
8.
Confidential
Risk Level with
standard mitigation
Task Description
- XXI -
Risk level with no
mitigation
SR.11.13122
.
11
.
Fault finding in LV
circuit compartment
(fixed equipment)
Flash over due to
reduced
clearances
Contact with live
dropper
connections
Do not work on equipment in this
state with busbars or circuits
energised
Training and experience of staff.
Minimum level of IP20 as design
standard for circuit connections in
fixed compartments and IP41 for
connections which are live when
compartment is isolated
Include check of
shrouding and
possible gaps to
live connections
as part of work
site inspection.
Do not proceed
with the work if
excessive gaps
identified
C4
A0
A0
C4
B4
A0
Switchboard 2
Make and model
No
Possible
additional
actions
Switchboard 1
Make and model
No
Standard Mitigation Actions
Risk level with
additional
mitigation
10
Fault finding work in
the circuit breaker or
contactor
compartment
(withdrawable
component jammed
or circuit
breaker/contactor
will not open to allow
the truck or starter
tray to be withdrawn)
Reason
Confidential
Risk Level with
standard mitigation
Task Description
- XXII -
Risk level with no
mitigation
SR.11.13122
12
.
13
.
Wrong
compartment
Start inspection and removal of
covers from compartment where
loose earth leads are applied
Modification to wiring
or components in
fixed starters
Accidental contact
with dropper
connections,
typically through
inadequate
shrouding,
incorrect removal
of covers,
mechanical failure
of supports or
shrouding of live
connections due
to work being
undertaken
exerting forces on
these components
Training and experience of staff.
Minimum level of IP20 as design
standard for circuit connections in
fixed compartments and IP41 for
connections which are live when
compartment is isolated
None – working
on dead system
B4
A0
Only undertake
modifications
with boards
isolated.
C4
C4
A0
Switchboard 2
Make and model
No
Inspection of bus
bars
Possible
additional
actions
Switchboard 1
Make and model
No
Standard Mitigation Actions
Risk level with
additional
mitigation
Reason
Confidential
Risk Level with
standard mitigation
Task Description
- XXIII -
Risk level with no
mitigation
SR.11.13122
.
15
.
Phasing out/prove
dead
Removal of fuse or
fuse carrier when
circuit is still live and
is not protected by
upstream fuse or
current limiting
circuit breaker i.e.
where there is
possible high fault
level
Fault with leads or
test equipment
Use instruments with insulated
probes and suitable internal fuse
or short circuit protection for fault
level to prove dead before
attaching earths.
Failure of fuse
base while fuse is
removed / inserted
Do not insert or remove fuses
where there is no upstream fault
level limiting device (fuse or fault
limiting circuit breaker or if circuit is
not switched off I.e. off load. Or
wear PPE suitable for incident
energy level.
Use low fault
level source to
test instrument
before use
B4
A2
A0
C4
A2
A2
Switchboard 2
Make and model
No
Possible
additional
actions
Switchboard 1
Make and model
No
Standard Mitigation Actions
Risk level with
additional
mitigation
14
Reason
Confidential
Risk Level with
standard mitigation
Task Description
- XXIV -
Risk level with no
mitigation
SR.11.13122
SR.11.13122
3.
Work in substation
but not on
switchgear (relamping, painting
etc) typically
taking from 4hrs to
1-2 weeks
Testing or
modification of
protection relay
settings or Fault
finding in LV
circuit
compartment
Insulation failure in
bus bar or cable
compartment
Entry to substations and
switchrooms should be restricted
to competent person who have
undergone periodical refresher
training. Regular maintenance
inspection of switchboards
including busbars and cable
compartments
No evidence
from PD
monitoring of
imminent
insulation
failure.
Insulation failure in
bus bar or cable
compartment
Entry to substations and
switchrooms should be restricted
to competent person who have
undergone periodical refresher
training. Regular maintenance
inspection of switchboards
including busbars and cable
compartments
PD
measurements
to be taken
immediately
before work
starts and
repeated every
2 weeks
thereafter
Insulation failure
on bus bars
Entry to substations and
switchrooms should be restricted
to competent person who have
undergone periodical refresher
training. Regular maintenance
inspection of switchboards
including busbars and cable
compartments
PD
measurements
to be taken
immediately
before work
starts
B4
B4
B4
A4
A0
(business
case may
be
stronger
than
HSE)
A4
A0
(business
case may
be
stronger
than
HSE)
A4
A0
(business
case may
be
stronger
than
HSE)
Switchboard 2
Make and
model No
Possible
additional
actions
Switchboard 1
Make and
model No
Standard Mitigation Actions
Risk level with
additional
mitigation
2.
Inspection of
substation, short
visit typically < 4hr
Reason
Risk Level with
standard
mitigation
Example HV switchboard assessment form
Task Description
1.
Confidential
Risk level with
no mitigation
4.2.
- XXV -
4.
Test IR (megger)
of a motor cable
Being on wrong
panel and
contacts live
Correct and visible labelling at
front and rear on non-moveable
panels. Training of staff to always
check front and rear labelling and
compare circuit identification read
against switching programme or
work scope before removing
covers.
B4
A0
B4
A0
Check circuit is dead before
applying megger.
5.
Test IR (megger)
of a feeder cable
Being on wrong
panel and
contacts live
Correct and visible labelling at rear
on non-moveable panels. Training
of staff to always check front and
rear labelling and compare circuit
identification read against
switching programme or work
scope before removing covers.
Prove circuit dead before touching
terminals
Switchboard 2
Make and
model No
Possible
additional
actions
Switchboard 1
Make and
model No
Standard Mitigation Actions
Risk level with
additional
mitigation
Reason
Confidential
Risk Level with
standard
mitigation
Task Description
- XXVI -
Risk level with
no mitigation
SR.11.13122
B4
A4
A0
Rack In/Out
voltage
transformer
Flash over at
spouts due to misalignment or flash
over due to
internal insulation
failure inside
transformer
Only rack in/out with circuit or bus
bar de-energised
.
B4
A0
8.
Open / Close fuse
protected
contactors
Fault inside starter
downstream of
contactor
Fuse operates quickly enough to
prevent arc flash event
Open / Close
withdrawable
circuit
breaker/contactors
after maintenance
Internal fault in
C/B or switch due
to incorrect
maintenance.
Insulation failure
of ct's / circuit
conductors / cable
terminations
Operate from "remote" panel
where possible. Routine inspection
of ct's etc. include in maintenance
routines Last checks before
completion of maintenance are
functional check, continuity check
and insulation checks.
9.
Rack In/Out
feeder circuit
breaker, starter or
vacuum contactor
Flash over at
spouts due to misalignment or flash
over due to
internal insulation
failure inside
switching device.
Pole stays closed
when there is
individual phase
switching
None
Wear PPE
appropriate to
incident energy
level
A2
B4
A0 – remote
operation
A0 - if
procedures
are followed
A2 (for
case
where
mistakes
are
made)
Switchboard 2
Make and
model No
Risk level with
additional
mitigation
Training, experience and
authorisation of staff. Maintenance
checks specifically include checks
of mechanical interlocks
IR check on
breaker spouts
for earth/phase
faults with 5000v
megger and
then confirm
breaker or
contactor is
open
Reason
Switchboard 1
Make and
model No
Possible
additional
actions
Risk Level with
standard
mitigation
7.
Confidential
Standard Mitigation Actions
Task Description
6.
- XXVII -
Risk level with
no mitigation
SR.11.13122
12.
A2
Proving a circuit is
dead
Being on wrong
panel, contacts
live and flash over
when cover is
removed
Correct and visible labelling at
front and rear on non-moveable
panels. Training of staff to always
check front and rear labelling and
compare circuit identification read
against switching programme or
work scope before removing
covers.
B4
A0
Application of
earth to circuits or
busbars using
temporary leads
Circuit energised
from another
source
Test circuit is dead immediately
before applying earths. Backfeed isolation part of switching
programme
B4
A0
Reason
Standard Mitigation Actions
Open / Close
withdrawable
circuit
breaker/switches
(normal operation)
Internal fault in
C/B or switch.
Insulation failure
of ct's / circuit
conductors / cable
terminations
Operate from "remote" panel.
Investigate and determine reasons
for trips before re-closing. (O/H
lines one remote reclose
permitted) Routine inspection of
ct's etc during maintenance
Possible
additional
actions
Wear PPE
appropriate to
incident energy
level
Switchboard 2
Make and
model No
B4
A0 – remote
operation
A4
otherwise
Task Description
Switchboard 1
Make and
model No
Risk level with
additional
mitigation
11.
Confidential
Risk Level with
standard
mitigation
10
- XXVIII -
Risk level with
no mitigation
SR.11.13122
14.
Fault finding work
in the circuit
breaker or
contactor
compartment
(withdrawable
component
jammed or circuit
breaker/contactor
will not open to
allow the truck or
starter tray to be
withdrawn)
Flash over due to
reduced
clearances
Do not work on equipment in this
state with busbars or circuits
energised
Being on wrong
panel, contacts
live and flash over
when cover is
removed
Correct and visible labelling on bus
bar covers. Training of staff to
always check labelling and
compare circuit identification
against switching programme or
work scope before removing
covers. Prove circuit dead before
touching terminals
Inspection of bus
bars
Possible
additional
actions
None – working
on dead system
C4
A0
B4
A0
Switchboard 2
Make and
model No
Standard Mitigation Actions
Switchboard 1
Make and
model No
Reason
Risk level with
additional
mitigation
Task Description
Confidential
Risk Level with
standard
mitigation
13
- XXIX -
Risk level with
no mitigation
SR.11.13122
15.
Phasing
out/Proving dead
Use of incorrect
voltage
measurement
stick or failure of
the stick in service
Training, experience and
authorisation of staff. Check stick
using test device before and after
use. Test sticks visually checked
before use for damage and sent
for more extensive testing
according to maintenance
schedule
Use voltage
indication on
front (if fitted)
after proving
they are phase
correct. Earthing
sticks and
voltage test
sticks are
marked such
that differences
are immediately
apparent e.g.
colour coding
and are kept in
separate bags
or transport
boxes or wear
PPE appropriate
to incident
energy level
B4
A0
Switchboard 2
Make and
model No
Possible
additional
actions
Switchboard 1
Make and
model No
Standard Mitigation Actions
Risk level with
additional
mitigation
Reason
Confidential
Risk Level with
standard
mitigation
Task Description
- XXX -
Risk level with
no mitigation
SR.11.13122
SR.11.13122
4.3.
- XXXI -
Confidential
Example comparison table of overall clearance times vs tested IAC clearance
times
Make and model of
switchgear
Switchboard
number /
location
Comments
Allowed IAC
time
Actual
clearance
time
Low Voltage
Holec Capitole 40
IAC type relies on upstream
protection to clear faults in
incomers and bus section areas
300ms
650ms
ABB MNS
Version 1 of MNS - relies on
upstream protection to clear
faults in incomers and bus
section areas
300ms
300ms
0.5s
300ms
0.5s
900ms
1.0s
4s
0.5s
To be
confirmed
High Voltage
20kV Siemens model
8BC1 / 8BD1
Pressure switch added when
normal protection takes longer
than 0.5s. Tested IAC
conditions met
20 kV Holec Unitole
20 kV Schneider Megrini
Clearance times for generation
less than 1s but backfeeds from
66kV take much longer than 1s
to operate
6.6 kV Hazemyer Unitole
6.6 kV Schneider
Mergrini
Check operating time less than
1.0s so IAC conditions are met
(some checked)
1.0s
<1.0s
3.3kV ABB Type BA
(HB07)
IAC status to be checked with
site documentation otherwise
treat as non- IAC
0.5
350ms
3.3 kV Schneider Megrini
IAC board
1.0s
< 1.0s
4.4.
Example record of assessment for Switchboards operated remotely or
de-energised
Switchgear identification
Summary of conclusions
Switchboard A
Substation XYZ
Single end fed and can be isolated at supply end
using remotely operated switchgear. No arc flash risk
therefore and no calculation required
Switchboard B
Substation ABC
All external switchgear in switchyards operated
remotely from control room. Access not permitted in
switchyards when switching being undertaken. No
arc flash risk therefore and no calculation required
SR.11.13122
5.
- XXXII -
Confidential
Conclusions
The arc flash assessment process described in this document is intended to fully satisfy the Shell
HSEE guidelines in the use of PPE.
Apply the following Hierarchy Of Control to manage Personal Protective Equipment use.
First:
Eliminate the Hazard or exposure.
Second:
Substitute materials or equipment to reduce the Hazard or exposure.
Third:
Use engineering Control of the Hazard or exposure.
Fourth:
Use procedural Control of the Hazard or exposure.
Fifth:
Use Personal Protective Equipment
The output of an arc flash risk assessment produced following this guide includes







Identification of where arc flash risk can be eliminated by only working on isolated
equipment
Identification of where arc flash risk can be reduced by using alternative techniques or
measurement points
Identification of mitigating actions that can be taken to reduce the probability of an arc
flash event occurring, looking at both the current practices and what additional mitigations
are feasible to introduce
Measurement of the residual levels of risk with no mitigation in place, with current
mitigations in place and after additional measures is implemented. This gives an
appreciation of the effectiveness of mitigation actions and basis for an objective
assessment of the level of actions needed to achieve ALARP.
Identification of any additional procedures and controls needed to reduce the probability
of an arc flash event occurring and to ensure that the correct levels of management at the
location are involved depending on the level of the risk being managed
Identification of when and where wearing of additional PPE is required to achieve ALARP
Identification of possible improvements to reduce the maximum arc flash level a person
may be exposed to at a location to below the target maximum level of 13 cal/cm 2. These
improvements can be prioritised in terms of the level of risk reduction achieved so as to
provide a basis for a location improvement plan.
This review process is recommended to be followed at all Shell operated locations.
Note - Additional actions may be required to those given in this document in some jurisdictions.
National regulations or directives shall always take precedence over the recommendations
in this document unless they are less onerous than this document’s recommendations.
SR.11.13122
6.
- XXXIII -
Bibliographic information
Classification
Confidential
Report Number
SR.11.13122
Title
Arc Flash Assessment Guide
Author(s)
Peter Freeman (PTE/EELE)
Keywords
Arc flash
Date of Issue
August 2011
US Export Control
Not subject to EAR-No disclosure of technology
Approved by
Wim de Wilt (PTE/EELE)
Sponsoring
Company /
Customer
SHELL GLOBAL SOLUTIONS B. V.
Spons./Cust.
Address
Carel van Bylandtlaan 30,
2596 HR,
The Hague,
the Netherlands
Issuing Company
Shell International Exploration and Production
P.O. Box 60
2280 AB Rijswijk
The Netherlands
Confidential
SR.11.13122
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Report distribution
Paper copy distribution
OU
Recipient
Ref.ind.
No. of copies
Recipient
Ref.ind.
No. of copies
Electronic distribution (PDF)
OU
N/A – distribution via SIGN
forum
SR.11.13122
Appendix A.
A.1
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Commentry & advice on Arc flash assessment
Procedures
Comments on Step 1 Elimination of the risk
This action will involve challenging the need for all actions traditionally carried out with equipment
live. Often the outcome of such reviews on non-IAC switchgear is that the flexibility in operating
equipment will be restricted compared to that previously enjoyed.
Examples of eliminating the risk could be to state that:


Withdrawable voltage transformers in non-IAC switchboards will not be withdrawn or inserted
with the main circuit live
Fuses fed from high fault level sources shall not be withdrawn if the fuse is live.
It should be noted that almost inevitably isolating equipment before allowing work to proceed
requires switching - which itself exposes the operator to an arc flash risk if the switching device
fails. However the evidence from past failures is that switching devices are unlikely to give rise to
arc flash events provided that they are properly maintained and inspected. Preference should
normally be given to working on equipment when isolated and accept the risks of performing
switching to create that condition. This assumes that the appropriate maintenance and inspection
is correctly carried out on switches and circuit breakers used for isolation.
The second method of eliminating the risk is to use fault level limiting devices such as fuses, or
certain types of moulded case circuit breakers (mccb’s). These devices can interrupt high fault
currents in less than ¼ of a cycle and limit both the peak magnitude of the fault current. By this
means the amount of energy released is reduced such that an arc flash event can be prevented
from occurring. There can still be release of energy sufficient to cause burns or other injury but this
will not normally be life threatening. There will remain a risk of death from electrocution if there
are exposed accessible live connections.
Note
There must be sufficient current to cause the protective devices to operate quickly (say <10ms),
typically 10 – 20 times the nominal full load rating of the device. As an example a gG 10A fuse
requires minimum of 100A to operate within 10ms whereas a gG 400A fuse requires 7500
amps.
This means that for larger fuses or supplies with low fault levels the assumption cannot be made
that fuses or fault limiting mccb’s will automatically provide sufficiently fast protection that resultant
arc flash energy levels will be below the 1.2 cal/cm2 level.
Examples of this type of risk elimination are:


Phasing out MV circuits by using fixed capacitive voltage devices rather than test sticks
Phasing out LV circuits by using test points protected by fuses rather than measurement points
directly on main bus bars or incoming terminals.
(click here to return to main document)
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A.2
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Comments on Step 2 Evaluate the switchgear
The mitigation actions must specifically address the potential cause of a flash over identified in
step 2 otherwise they cannot be classed as a mitigating action. With reference to operating
distances to switchgear - these may vary depending on the action being performed.
In considering the effectiveness of mitigations which are dependent on actions by personnel,
assessor should be aware that the majority of arc flash incidents that have occurred in industry
have occurred during, or just after, human intervention in form of maintenance, modifications or
commissioning and often with experienced staff involved.
This leads to the conclusion that mitigation actions based upon actions of personnel must be
reinforced, for example by having independent checks made of each step. This almost inevitably
means that single person working will become much less common, at least until isolation is
established.
For Shell approved vendor DEP compliant IAC tested LV switchboards the evaluation should
include examination of the detail of the IAC tests. This will reveal that there are only a limited
number of locations where the tests required the upstream protection to operate i.e. where there is
a time limitation to the internal arc resistance. At other locations arcs may have been impossible to
creare, self extinguish or are cleared by the protective device of the outgoing circuit. Therefore the
actions which could give rise to an arc flash event will be limited. Typically these will be racking
in/out of air circuit breakers, flash over in incoming cable compartments or at copperwork
terminations onto air circuit breakers or large switches.
For such boards with non-withdrawable switches for incomers/bus section switches (or limitation
placed that air circuit breakers are not racked in/out with connections live) and where the
additional insulation has been extended to cover terminations at switches there may be no
locations where an internal arc can be sustained hence no arc flash risk.
(click here to return to main document)
A.3
Comments on Step 3 Calculate arc flash energy levels
a) For switchboards which are claimed to be of internal arc control (IAC) design,
The fault clearance time is the combination of the protection operating time and the breaker
opening time. Use fault current through protective device (i.e. without motor contribution to fault
level) to establish tripping time. If no specific information is available, assume motor contribution
is the same as the sum of the starting currents of the normally continuously running motors
connected to the board.
As an alternative to calculation via the spreadsheet, the following conservative reductions in
potential bolted symmetrical phase to phase fault current can be used to calculate protection
operating times for comparison with switchboard IAC test times.
HV circuits
For all fault levels
– assume 94% of potential fault current
LV Circuits
Fault levels up to 10kA
– assume 55% of potential fault current
Fault levels up to 30kA
– assume 43% of potential fault current
Fault levels up to 50kA
–assume 40% of potential fault current
Fault levels up to 80kA
–assume 35% of potential fault current
Fault levels up to 100kA
–assume 30% of potential fault current
For example for 10kA assume 5.5kA, for 45kA assume 10kA etc.
(click here to return to main document)
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b) For switchboards which have not been tested for internal arc containment (non-IAC)
An alternative approach is to compare the fault levels, voltages and clearance times with the
tables given in Appendix C.
The tables are based upon the following assumptions and shall not be used if these are not
valid for the particular equipment / action:




Distance between the torso of the operator and the switchgear when carrying out an
action is 900mm for HV and 610mm for LV.
Equipment is a switchboard or MCC
LV systems are solidly earthed and HV systems resistance earthed
For LV applications tripping times are substantially unchanged if the assumed arc
current is reduced by 15%
Voltages covered are 400V, 690V, 1kV to 15kV and 33kV.
Similar tables can be readily drawn up using alternative values if a location wishes to use
different voltages or distances.
Note that there are limitations in use of tables for voltages above 15kV.
Use of the table allows assignation of boards to categories corresponding to the arc flash
levels of
1. >40 cal/cm2.,
2. >13cal/cm2 < 40cal/cm2
3. < 13 cal/cm2,
This classification is needed in review of the outcomes which is the next step in the process
(click here to return to main document)
A.4
Comments on Step 4 – Review of the outcome of energy level
calculations
Reduction in clearance times by changes to protection schemes
Since original protection design schemes did not consider arc flash energy levels, the design
of such schemes will not necessarily have been set to minimise prospective arc flash energy
levels.
It can be anticipated therefore that many of the arc flash energy levels will exceed the target
value of 13 cal/cm2 and, especially for circuit voltages above 15kV, will exceed the upper
limit of PPE of 40 cal/cm2. This limit is also likely to be exceeded for boards at the upper
levels in a distribution system where the need for discrimination with downstream protective
devices will increase time delay settings, thereby increasing clearance times.
Of particular concern are



Main generation switchboards where the symmetrical fault currents do not decay as
rapidly as in other locations on the network i.e. fault levels are high and the clearance
times can be relatively long due to location in network
Boards which can be fed from a lower fault level sources as well as a relatively high level
source e.g. board fed via a transformer and also from an emergency generator.
Transformer fed LV switchboards with secondary side protected by IDMT elements on the
primary side or primary side fuses.
(click here to return to main document)
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A.4.1
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HV Circuits
For HV circuits the reduction in arcing current compared to the symmetrical fault level
suggested by the IEEE spreadsheet is relatively small and hence the operating time of the
protection functions will be very close to that expected in original protection design for a short
circuit condition.
For IAC design switchboards with a short circuit withstand capability of 1 sec and an internal
arc withstand time of 1 second this means faults on such boards should be cleared within the
internal arc withstand time.
Care needs to be taken where boards with an short circuit withstand time of 3 seconds have
been specified, that the protection still operates within the tested internal arc withstand time for
internal short circuits, otherwise the board will have to be classed as non-IAC.
For non-IAC HV boards it is probable that scope of changing settings and reducing operating
times to reduce arc flash energy levels is limited, unless the protection scheme is changed.
Effectively in most cases the options to reduce exposure to less than 13 cal/cm2 arc flash
energy levels are restricted to either remote operation of both open/close and racking in/out
(i.e. remove personnel from being near the switchgear) or by changing the protection schemes
to include bus zone protection or blocking schemes based upon directional over current
relays.
The latter solution will normally require replacement of existing relays and installation of new
numeric relays to provide the required functionality together with a limited amount of bus
wiring between cubicles. It should be noted that use of an improved protection scheme not
only reduces risk to the individual but also reduces the consequences to the business in event
of a fault, as the extent of damage will be significantly reduced. Therefore there is a business
justification to support expenditure as well as a safety justification.
(click here to return to main document)
A.4.2
LV Circuits
For LV circuits the reduction in arcing current suggested by the IEEE spreadsheet as compared
to the symmetrical fault level is much greater than for HV circuits and suggested arcing
currents will vary from 55% to 30% of the nominal symmetrical fault current value.
The standard Shell design for protection of LV switchboards downstream of transformers is to
use an extremely inverse IDMT over-current element and an instantaneous element fitted to the
HV circuit breaker feeding the transformer and a standby earth fault relay fed from a c.t. on
the neutral to earth link.
The secondary side phase to phase protection (via HV IDMT element) will normally have been
chosen to protect against overload and to trip rapidly (<1s) in event of a primary side short
circuit (based upon minimum short circuit current levels).
The only specific advice given is that the earth fault relay should trip within 1 sec for 50% of
maximum earth fault current and that the HV instantaneous element should be pick up at
130% of the maximum secondary side fault current reflected into HV windings i.e. the
instantaneous element should only respond to faults in HV cable and windings. For fuse
contactor fed transformers the fuse effectively adopts the role of the instantaneous element.
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The reduction in fault current to be considered for internal arc condition (55-30% of possible
short circuit value) will mean the protection operating time of the IDMT element will increase
significantly compared to clearance time at the full prospective fault current. It is highly
probable that the arc withstand time of any IAC LV switchboards (300ms) will be exceeded
with the standard Shell protection scheme set up as described above.
In fuse protected HV/LV transformers the combination of large fuses and low fault levels can
give rise to long clearance times (hence high arc flash levels) . Whereas fault levels on
switchboards mounted close to transformers will normally be high enough to ensure fast
operation of fuses for faults close to the switchboard, long feeder cables to remote
switchboards can result in significantly reduced fault levels at such sub-distribution boards due
to the effects of cable or overhead line impedances. As a consequence there can be increased
clearance times at the reduced fault levels (bearing in mind the additional 55-30% reduction
still has to be applied to determine clearance times). This can lead to the counter intuitive result
that arc energy levels at the termination of the supply cable at feeder switchboard are lower
than those at the termination of the cable at the sub-distribution board.
(click here to return to main document)
A.5
Use of temporary changes to protection settings
There are many past examples within the Company of unnecessary trips occurring when
protection settings have been altered, e.g. during commissioning or maintenance tests, and
not restored to correct values.
Effectively this means such changes should be automatically corrected if accidently left in more
sensitive position i.e. overrides can only exist for a limited period before timing out and
reverting to normal settings.
Although such temporary setting changes are strictly not maintenance overrides as used in
instrumentated protective systems (i.e. they do not override safety systems) it is possible that
the same type of management control system can be used to manage application and removal
of such temporary changes to protection settings. Alternatively the site management of change
process could be used, provided such a system can accommodate the numbers of times such
setting changes will be implemented.
(click here to return to main document)
SR.11.13122
Appendix B.
B.1
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Withstand times of Internal Arc Tested switchgear
IEC and US standards
Internal Arc testing of HV switchgear, whether to US or IEC standards, has very similar
approaches. Both require that the tests show an individual will not be harmed by deliberately
introducing an arc inside the equipment and showing that cotton indicators mounted around the
board are not significantly damaged or scorched, provided the arc is interrupted within a certain
period of time.
Regrettably however the tests are not inter-changeable and it is necessary for staff to understand
the specific standards relating to the equipment they are responsible for.
One difference between the standards is that the suggested arc withstand time in US HV standards
is 0.5s and there is a strong recommendation to detect the arc condition (e.g. by light, pressure
rise etc) and initiate a trip of the beaker(s) feeding the fault.
It should be appreciated that a 0.5s withstand time with an arc detection system / upstream trip
will effectively co-ordinate with downstream outgoing feeders, even if their short circuit clearance
times are greater than 0.5s. This is because the arc detection trip is dependent on combination of
high currents and triggering of the arc detection system i.e. the zone of protection is limited to
inside the switchboard; hence it should not react for external faults.
The IEC standard allows 0.1, 0.5 or 1s arc withstand times and makes no such recommendations
as to additional equipment to trip the supply breaker. Provided the protection on the board’s
supplying breaker is set to clear within IAC test time then the board will control the consequences
of an internal arc. If the clearance time of the upstream breaker is longer than the IAC test time
then the board will not control the consequences
Some manufacturers of IEC standard switchgear have adopted a similar approach to that
described for American equipment in the past, and examples of this type of protection maybe
found in some IEC based switchboards. Care is needed in such circumstances that the upstream
trip command has actually been connected to the breaker(s) supplying the board since its role
may not have been fully appreciated by the system designers.
Refer also to Appendix A.2 Commentry on Swithgear evaluation for additional information re
Shell approved vendor DEP compliant IAC tested LV switchboards.
B.2
Effect of reduced fault currents
If the boards being considered have been internal arc tested, then the longest clearance time must
be within the test time for the board to be classified as IAC. This is irrespective of whether there is
a reduction in arc current during the tripping sequence (for situations with multiple sources) or if
the arc current is less than that used in the IAC test (see extract below from IEC 62271 Annex A).
Extract from IEC 62271 Annex A
A.4.5 Duration of the test
NOTE: It is in general not possible to calculate the permissible arc duration for a current which
differs from that used in the test ....... there is no universal rule according to which the permissible
arc duration may be increased with a lower test current.
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Appendix C.
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Comparison of clearance times and energy levels
Tables are only valid for systems and equipment complying with assumptions stated as to
voltage, equipment type, earthing arrangements and distances of torso to equipment
C.1
HV switchgear (>1kV)
Working Distance
in mm
Equipment Class:
Grounding Type:
Protective Device
Type:
900
3 or 4
2
0
Switchboard or MCC
Resistance Earthed
Other Protective
device
Applicable
voltage range
33kV
15kV < V < 5kV
5kV < V < 1kV
Potential
fault
current
(kA)
Arc
current
(kA)
Maximum clearance times in seconds
(protection trip time + breaker operating
time)
40
40.00
0.05
<0.050
30
30.00
0.06
<0.050
20
20.00
0.1
<0.050
10
10.00
0.2
0.6
5
5.00
0.4
0.13
40
37.92
0.55
0.18
30
28.58
0.75
0.24
20
19.18
1.15
0.37
10
9.71
2.4
0.78
5
4.91
5
1.63
40
37.92
0.63
0.20
30
28.58
0.85
0.28
20
19.18
1.3
0.42
10
9.71
2.75
0.89
5
4.91
5.8
1.89
To meet 40 cal/cm2
limit
To meet 13 cal/cm2
limit
Notes
Values provided by IEEE spreadsheet for 33kV are for information only. These values should be
used with caution since they are considered to very conservative compared to values for voltages
up to 15kV. Nevertheless it illustrates that non-IAC tested 33kV indoor switchgear without fast
operating protection for internal faults is likely to have arc flash energy levels above 40 cal/cm 2.
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LV switchgear (400/415v & 690v)
Working
Distance in mm
Equipment Class:
Grounding Type:
Protective Device
Type:
610
3 or 4
1
0
Switchboard or MCC
Solidly Earthed
Other Protective
device
Applicable
voltage range
400/415V
690V
Potential
fault
current
(kA)
Arc
current
(kA)
Maximum clearance times in seconds
(protection trip time + breaker operating
time)
To meet 40 cal/cm2
limit
To meet 13 cal/cm2
limit
40
16.64
1.1
0.35
30
13.27
1.4
0.45
20
9.64
1.95
0.64
10
5.58
3.5
1.16
5
3.23
6.5
2.1
40
32.28
0.53
0.175
30
24.56
0.72
0.23
20
16.70
1.1
0.35
10
8.65
2.2
0.72
5
4.47
4.5
1.45
Notes
These values illustrate that the reduction in system voltage from 690 to 400/415 has a
dramatic effect on the arc current to be assumed. This actually means in most cases it is easier
to set protection to operate within the required time for 690v boards since the higher currents
will mean faster operating times of the IDMT curves
SR.11.13122
Appendix D.
D.1
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Calculation of arc flash energy levels using IEEE 1584
spreadsheet
Calculation from “fixed” fault level sources
In calculating arc flash energy levels it is necessary to determine what the fault level will be and
which protection devices will operate, to determine how long the arc will exist.
As a general rule arc flash energy levels will be reduced if the fault levels are reduced and fault
clearance times remain unchanged or are also reduced.
Based upon experience it is also recognized that probability of arc flash events occurring are
greatest when racking equipment in or out of housings and when re-energising circuits which
have been de-energised and have been previously worked on. The latter includes the initial
energisation of new installations. Faults in the actual switching devices which are energised on
both sides of the device are much less common – provided that the switching devices are properly
operated, maintained and inspected.
Therefore, wherever possible, those activities which carry the highest probability of an arc flash
should be done when fault levels are lowest provided clearance times remain, at worst,
unchanged. Actions should be limited to switching only when fault levels will be unavoidably
highest e.g. when paralleling or de-coupling parallel supplies. Racking in/out should therefore be
done when fed from minimum number of sources.
Implication is that two arc flash energy calculations may be required, one covering worst case
when switching is taking place and a second when switching has been completed and racking
in/out or similar activities are being carried out.
For existing installation ideally the protection should be such that the energy levels are less than
the target maximum (13 cal/cm2) for worst case switching and during subsequent racking in/out.
However that will not always be practical. A more pragmatic approach in such cases would be
that it is less than13 cal/cm2 during racking in/out and less than 40 cal/cm2 during switching.
Switching as a means to reduce fault levels before racking in/out is only effective if the fault levels
are affected by the switching operation.
A
Switchboard No 1
Feeder
Tx No 1
N/C
Feeder
Tx No 2
Tx No 2
Tx No 1
C
Incomer
No 1
Incomer
No 2
Switchboard No 3
N/O
B
N/O
Switchboard No 2
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In example given above the fault levels at B and C are at maximum when the downstream
switchboards are fed by parallel supplies and at a minimum when the boards are fed by a single
supply.
However the reduction is dependent on the impedances of the feeders between the supply board
A and the downstream boards.
Where there are transformers the fault level will always be higher in the parallel supply case.
Where there are plain feeders such as for switchboard B, if the interconnection has relatively short
cable connections, the fault level will be essentially unchanged.
However if they are long overhead lines the fault level in parallel case will be much higher than
single feed case.
In order to be able to able to take advantage of reduced fault levels by switching before racking
in/out it is necessary to follow a specific sequence of actions.
As an example, if it is wished to take transformer No 1 out of service, then the following switching
scheme should be followed. (In this it assumed any other bus section switches further up in the
system are closed and other steps, such as checking for voltage indication, applying padlocks etc.
are not mentioned for sake of clarity)
Close bus section A
Switchboard 1
Close bus section C
Switchboard 3
Open Incomer No 1 on board C
Switchboard 3
Open bus section A
Switchboard 1
Open Transformer No 1 Feeder on board A and rack out
Switchboard 1
Rack out Incomer No 1.
Switchboard 3
The difference is that normal practice would be to Open Incomer No 1 and rack out before
leaving Switchboard No 3 to minimize journeys between substations. This may not be an issue in
plant areas but can be significant if substations are some distance apart.
To restore supplies the sequence is essentially reversed
Rack in Incomer No 1.
Switchboard 3
Rack in Transformer No 1 Feeder on board A
Switchboard 1
Close bus section A
Switchboard 1
Close Transformer No 1 Feeder on board A
Switchboard 1
Close Incomer No 1 on board C
Switchboard 3
Open bus section C
Switchboard 3
Open bus section A
Switchboard 1
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Difference again is that racking in of Incomer No 1 is done early in sequence and again this
implies an additional journey between substations.
Given the wide variation found in circuit configurations it is not possible to provide examples
which cover all cases. However as a guiding rule it is recommended to always develop switching
schedules where racking in / out breakers only takes place after parallel supplies have been
restored to single feed status. Additionally always ensure that the schedule will not result in “back
feeding” i.e. the system is being energised from the reverse of its normal operation, unless the
protection schemes have been designed for this condition. For example closing Incomer No 1 on
board C before closing Feeder No1 Transformer on board A would result in energisation of the
primary winding of Transformer No 1 with no earth reference and it being inadequately
protected.
From an arc flash calculation standpoint then there are two values; one when board C is fed by
two transformers and one when it is fed by single transformer. Typically the feeders will operate in
the same time as each other in both cases and there is no doubt as to the time to be assumed until
the arc will be extinguished
D.2
Calculation from “variable” sources of fault current.
Equal clearance times will not be found where there are dissimilar sources e.g. when there is
distributed generation or interconnection to the local grid with local generation.
G
B
Fault condition power flow
G
Substation No 1
33kV (fed from grid)
Normal power flow
Normal power flow
Fault condition power flow
A
Substation No 2
11 kV
EG
Substation No 3
0.4 kV
C
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In example above the generation at Substation 2 is normally run in parallel with the grid
substation No 1 and power flows are normally from the grid towards substation No 2 with the
local generation running part loaded. In event of loss of grid then loads on substation No 2 can
be supported by running both generators at close to full load. There is an islanding scheme which
trips the 33/11kV transformer feeders if power flows are from Substation No 2 towards
Substation No 1 i.e. preventing back feeding of substation No 1 and hence the grid.
During monthly testing the emergency generator is run in parallel with main generation.
How can switchboards 2 and 3 be assessed for arc fault energy levels?
Substation 2
The natural presumption is that worst case will be when fault levels are at their highest i.e. with all
bus section switches closed, maximum potential fault level at Substation 1 from the grid and with
all generation in operation.
The fault current values for this condition will typically be calculated in any system study to allow
the required short circuit withstand current capability of the switchboards to be established.
In practice the generation and transformer protection will almost inevitably take different times to
trip so the fault current at switchboard No 2 will start at a high figure and then reduce in steps as
the supplying breakers open.
It is also necessary to look at case of minimum grid fault level if this reduction has the effect of
significantly increasing transformer trip times for faults at Substation No 2.
The IEEE spreadsheet assumes single fault levels and single trip times and is not designed to deal
with fault currents varying with time.
Recommendation is to take following approach


If trip times are close (<100ms difference) then assume highest value of fault current will
flow for the longest clearance time of a supplying breaker.
If trip times differ significantly (>100ms difference) use tool such as SKM Power Tools to
model the system and calculate energy levels. This will provide most accurate figures
currently available.
If it is wished to make a manual calculation and it is accepted that this will not be as
accurate as a computer programme solution then assume worst case fault current and a
trip time equating to when first significant drop in fault current occurs (in example above
this will be when either the generation or the transformers trip). Enter these values into
spreadsheet and note arc flash energy predicted. Then assume the lower fault current that
will flow after one set of sources have tripped and the clearance time for the remaining
supply points. Enter these lower current / longer time values in spreadsheet and note arc
flash energy predicted.
Take whichever is the higher value as being the arc flash energy level but
Substation No 3
At 400v level it is necessary to calculate energy levels when fed by transformers and generation
and also when fed by the generator alone.
Assuming the transformer and generator are of equal capacity then it may be assumed that the
same protection settings may be used at feeder breakers on Switchboard 2 and at generator. This
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however ignores the fact that typically the maximum generator fault current will be between one
third and one quarter that provided by a single transformer. When running on emergency
generator alone, the combination of longer clearance time and a lower fault current will result in
higher arc flash energies than when fed by transformers. This issue can be resolved by using a
faster acting element at the generation circuit breaker relay than for the transformers, but this will
almost certainly be at the expense of discrimination with the larger outgoing circuits fed from
Substation 3.
Recommendation is to ensure (if possible) that setting of generation protection should clear faults
on associated busbar such that arc flash energy level does not exceed 13 cal/cm2.
In determining tripping time account should be taken of the arc current suggested by the IEEE
spreadsheet, which will be around 55% of bolted short circuit value for generation up to 1250
kVA.
Note however this recommendation is dependent on still being able to start or energise the
necessary loads fed under emergency conditions. Alternatively expressed, the constraint on
tripping time at reduced fault current may limit the maximum permitted size of emergency loads
having a significant inrush or starting current. A mitigation will be to fit additional measures to
detect a start condition and prevent the generation protection from operating prematurely during
a large motor start. This will add significant complexity to the protection design and ideally should
be avoided unless there are no other options available.
D.3
Determining operating conditions for arc flash calculations
A further distinction needs to be made in determining which operating mode or conditions the arc
flash levels will be calculated for.
In example given previously there are many possible operating modes.
For example
1.
2.
3.
4.
5.
Grid supply available and both main generators.
Grid supply available and only one main generator running.
Grid supply available and no generation running
Only one grid transformer available and both main generation running
Only one grid transformer available and only one main generator running
To each of these can be added the options of minimum and maximum grid fault levels and
whether or not the emergency generator is running.
Calculation for all possible modes of operation would be a very extensive task and most of the
calculations will not provide useful additional information.
The simplest approach for the HV switchboard is to consider the scenario with maximum fault
levels and calculate the arc flash energy level. Then look at minimum fault level conditions to see if
the tripping times are significantly extended.
In this instance are tripping times of the transformers extended when there are minimum grid fault
levels? If so worst case could be when grid fault levels are at minimum not maximum value.
For the LV board, as mentioned previously, both the condition when fault levels are at a maximum
and when they are at a minimum (emergency generator only) should be considered.
SR.11.13122
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This may require a comparison of different conditions to arrive at an indicative figure for the arc
flash energy where there are differences in clearance times of the supplying circuits.
In more complex circuits there may be even greater numbers of potential operating modes and a
decision may be required to only consider “normal” modes which exist for extended periods of
time i.e. accept that under abnormal operating conditions arc flash calculations may not be
correct.
The implication of such a decision to manage size of arc flash study is that works during abnormal
system arrangements should be limited to those needed to put the system in a safe condition e.g.
isolate faulty circuits or to return the system to a normal (hence studied) condition.
If works (other than switching) which have a risk of creating an arc flash event have to be
completed during abnormal conditions then a specific assessment for the particular configuration
should be carried out to confirm the arc flash energy levels and/or if IAC test times are not
exceeded.
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D.4
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Entering values in the IEEE spreadsheet data input sheet
Motor Contribution Factor:
0.03
Enter typical portion of bolted fault from motor contribution.
Example: 0.03 Enter zero if no motor contribution
kV of
bus
Bolted
fault
current of
bus in kA
(from
study)
Portion of Bolted
fault current that
flows through
protective device
in kA (from
study)
Protective
device fault
current
without motor
contrib. in kA
(B21)
Switchboard XYZ – single feeder
3.3
6.75
6.75
6.75
Switchboard XYZ – single feeder
3.3
6.75
Switchboard XYZ – twin feeder
3.3
13.5
6.75
6.75
Switchboard ABC – single feeder
0.4
25
25
25
Name of bus
6.55
Free choice of text which is
repeated on summary page
This is always the Voltage of
the Busbar being considered
Fault level at the busbar being
considered at the voltage
level in previous column
Cells coloured yellow are
available for data or text entry.
White boxes have calculation
formula in them and should not
have any data entered in them
All currents should be entered
at the voltage of the busbar
being considered.
This is the current flowing through
protective device. If there are twin
sources of supply it will be half the
Bolted Fault current less any motor
contribution
This is the current flowing through protective
device.
If no entry in previous column it will insert the
value of the study Bolted Fault current reduced
by the fraction shown in Motor contribution
factor box above the table – see red text
6.75*97% = 6.55
If an entry is made in previous column, that
value will be used
SR.11.11111
-1-
Trip time of protective
device at arcing current.
For LV circuits only, the
calculation requires the
tripping time at 85% of the
arcing fault current to also
be entered.
Note
If the protective device is at
a different voltage level to
the busbar voltage being
considered, then the arcing
current will have to be
converted to match the
voltage level at which the
protective device is
operating to be able to
establish the trip time.
Arcing fault
current in
protective
device, in kA
(Calculated)
Confidential
As before this may have to
be converted to the fault
current at the voltage level
on which the protective
device is operating
If an entry is required the
cells remain blue
Trip
Time
Opening
Time
Reduced
arcing fault
current in
protective
device, in kA
6.52
0.1
0.25
6.40
0.12
6.52
12.2
Trip Time
at
Reduced
Current
Opening
Time at
reduced
current
Grounding Type:
Working
distance is the
distance to the
torso of the
person from
the front of the
switchboard
1 - Solid Grounded
2 - Ungrounded,
Resistance Grounding,
Other Impedance
Grounding
Working
Distance
in mm
Equipment
Class
Grounding
Type
Protective
Device
Type
Not required
1000
3
2
0
0.25
Not required
1000
3
2
0
0.1
0.25
Not required
1000
3
2
0
0.8
0.2
10.37
610
4
1
0
1.0
0.2
Operating time of the circuit breaker or
contactor
Equipment Class:
1 - Open Air
2 - Cable
Calculation of the current value to
be used in assessing the trip time
of the protection device.
3 - Switchgear
4 - MCCs, Panels
For HV circuits this reduction is
only a few % of the protective
device fault current in previous
column
The spreadsheet reports only
one energy level in the
summary sheet
For LV circuits the reduced value
will be between 55 and 30% of
the potential fault current. The %
reduction is greater as the LV
bolted fault current value
increases
This is the higher of the two
arc flash energy levels
calculated using the trip time /
arcing fault current and the
trip time / 85% of arcing fault
current (where entered)
Protective device type
refers to US standard
MCB’s and should be
left with zero entered
SR.11.11111
Appendix E.
E.1
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Additional insulation and Cable Terminations
Additional busbar insulation
Switchgear uses air, or an insulating gas such as SF6, together with supports made from
insulating materials to meet the normal and over voltage requirements of the relevant IEC
standards. In some cases this is supplemented by insulating phase barriers especially where the
same equipment is used for a range of voltages e.g. 400 & 690v or 11kV and 13.8kV.
Phase barriers are often added where air insulation values will not meet peak over-voltages
applied during testing. All such insulation and phase barriers can be described as being the
functional insulation of the switchboard.
There has been a requirement for additional insulation called for in the relevant DEP’s which predates any requirement for formal tests for arc flash containment. This insulation is additional to
that required to meet IEC standards and is to be applied to busbars and droppers of a
switchboard for both LV and HV Air Insulated switchgear.
The purpose of this insulation is not to be able to meet any of the IEC tests, but to reduce the
probability of a flash over occurring and to reduce the consequences should one occur.
This can be described as additional insulation since it is not required to meet the IEC functional
requirements.
The advice provided with the IEEE spreadsheet recommends using a tripping time based upon
phase protection only and takes no account of earth fault protective devices.
The assumption is that a three phase fault represents the worst case in terms of energy released
and the phase protection elements will be the slowest acting protection element.
This is approach is sensible if the majority of equipment being considered has little or no
additional insulation to minimise the opportunity for a flash over between phases and little or no
segregation of different segments of the switchgear. Typically this situation will be found in most
switchgear not built to IEC based DEP standards.
Uncontrolled arcs will naturally tend to expand their path length and the driving voltage / current
will pass through zero, potentially creating a condition which will naturally extinguish the arc. This
can occur because the products of the arc (ionised gasses and vapourised metal) tend to be
moved away from original source of the arc, effectively increasing the arc length hence its
impendence.
In equipment without additional insulation the roots of the arc can move so as to keep the arc
length short negating this natural arc impedance increase and allowing a restrike after
current/voltage zero i.e. the arc will be sustained once it is established.
It is the existence of a sustained arc which gives rise to highest energy levels. If the arc is
extinguished quickly this significantly limits the amount of energy released.
Note however


Pressure development in the vicinity of the arc is within the first 15 ms after ignition
The temperature increase within the first 20 ms will be up to 20 000 °C
Equipment therefore still has to be able to withstand initial pressurization event and there will be
significant damage to equipment unless the arc extinguishes very quickly (say < 15ms).
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LV switchboards
During testing to demonstrate internal arc control, a shorting wire is placed at various points in a
low voltage switchboard where there are exposed connections permitting such wires to be
attached. Results of such tests between boards with un-insulated bars and those with insulated
bars and segregation of compartments show a marked difference.
Those with insulated bars obviously limit the possibility of an arc occurring by virtue of the
insulation preventing an arc from being created in the first place. Even if the insulation is
damaged sufficiently to allow a shorting wire to be installed then, provided such damage is
limited in extent, the arc will self extinguish i.e. there is no reliance on upstream devices to
operate in order to extinguish the arc. Arc duration is short, typically between 7 and 15ms.
However most test reports do not show tests results from these “arc free zones” since it is not
called for in the IEC TR test standard.
By comparison, an un-insulated bus bar design with large areas of exposed copper work does
not prevent an arc from being established initially and it will continue to support the arc until the
test supply is interrupted i.e. self extinguishing will not occur because arc impendence is not
increased. In practice the arc impendence is likely to be reduced by allowing multiple arcs to be
established. Such a system is wholly dependent on the upstream protective device operating to
extinguish the arc.
Experience and test results allow that if a board has a fully insulated bus bar system (including
droppers) in accordance with DEP requirements, then the system can be treated as an arc free
zone and assumed not to be a possible source of arc flash. This applies irrespective of whether
the board has been subject to an IAC test.
Note
It may be necessary to examine the board to ensure the manufacturer has continued the insulation
up to and including connection points to major components such as bus bar or down dropper
couplers, incoming switches or circuit breakers. If significant exposed areas of copper are
identified then these shall be treated as potential arc locations (or insulation applied to eliminate
them from this consideration).
Refer also to Appendix A.2 Commentry on Evalauation of switchboards for observations on Shell
approved DEP compliant IAC tested LV switchboards.
E.1.2
HV switchboards
Testing for HV boards also use similar shorting wires where there are exposed connections. The
test results show no self extinguishing capability and arcs only extinguish when the test supply is
disconnected. All IAC tested HV switchboards therefore have an arc withstand time.
However tests have not been completed with insulated bus bar systems so no conclusions can be
drawn as to whether arc flash containment performance of such boards differs from un-insulated
bus bar systems. Practical experience indicates however that the extent of damage is much
reduced if insulated systems are used; but that any flash over will readily find any exposed copper
work or other weaknesses in the additional insulation.
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Implication for HV switchboards is that a benefit in terms of reduction in arc flash energy due to
the additional insulation called for in the DEP exists, but cannot be readily quantified. Fot this
reason no allowance can be made for any reduction in risk due to additional insulation.
E.2
Cable terminations
For HV three core cables there can be phase to phase faults especially within the crotch of the
cable where cores are split out for termination or where crosses are made to maintain correct
phase sequence. In such instances electric stress levels can be high, especially if termination has
not been completed exactly in accordance with termination kit manufacturers’ recommendations.
Often there are differential schemes across cables which are sensitive enough to react before such
faults can fully develop. For such installations the arc flash hazard is therefore also significantly
reduced since such systems have very fast tripping times.
There are instances e.g. motors and feeders to LV transformers which do not have such differential
protection and faults can develop into phase to phase faults before protection can react. This is
especially true of outdoor terminal boxes where water may gain ingress. There have been many
examples of such terminals boxes literally shattering under such fault conditions when fed by
circuit breakers. The introduction of fuse protection to most motor and HV/LV transformer circuits
has eliminated such consequences since the fuse limits the amount of energy released in the HV
circuits. Note however that fuses chosen to provide short circuit protection of the HV circuits (as
found in vacuum contactor circuits) provide no protection for the LV windings or LV secondary
cables / terminations.
Refer to Appendix F for discussion on HV/LV transformers protection.
Cable terminations to be considered as possible arc flash locations are therefore those which are
not within a differential tripping scheme (or similar instantaneous protection) or are not protected
by an upstream fuse at the same voltage level as the cable termination.
SR.11.11111
Appendix F.
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Scope for protection to minimise arc flash energy
levels
For a given type and make of switchgear there is little that can be done to alter the level of
protection afforded by equipment design i.e. convert to IAC design, nor is there great scope for
altering the position of the individual with respect to the location of a potential arc flash point. The
only realistic methods of changing the energy levels an individual is exposed to, is either by
remote operation or by reducing the arc duration.
The practicality of remote operation will depend on the action needed to be carried out and the
availability of suitable equipment. The availability or practicality of such equipment cannot be
guaranteed for all equipment types.
However reducing the arc duration is possible in every case by altering the protection settings to
reduce tripping times.
Downside of such a change is that it will reduce discrimination between upstream and
downstream devices.
If differentiation is reduced below the recommended limits (typically 0.4s for traditional HV relays
and air or oil circuit breakers reducing to 0.3s for modern relays and vacuum or SF6 breakers),
false trips may occur and larger parts of the network may be lost as a result of a downstream
fault.
Since unexpected trips of part of the network may of themselves create other potential hazards,
loss of discrimination in order to reduce arc flash energy levels is not a satisfactory long term
option.
Therefore there will be a limit as to the extent arc flash energy levels can be reduced by changes
to protection settings unless the protection scheme is changed to one with a restricted zone of
protection.
A further complication is that the recommended arc flash current (from IEEE spreadsheet) for
calculating clearance times is less than the maximum fault current. The original designers of
existing protection schemes will not have considered these reduced values since these limits were
not available to be considered at the time of the original design.
In considering what improvements can be made using protection the target values we are looking
for are:
For non-IAC tested switchboards
Maximum arc flash energy of 13 cal/cm2 (long term) and 40 cal/cm2 (in short to
medium term) at all voltage levels
For IAC tested switchboards
Total clearance time
300ms
(L V)*
Total clearance time
1s or 0.5s
(HV)
*300ms is normal IAC test time but must check actual test time for switchgear being considered as
some can be as low as 100ms
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F.1
F.1.1
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HV switchboards
Non IAC tested switchboards Voltage range up to 15kV
For HV equipment and voltages in range up to 15kV the reduction in fault current to be used in
calculation of arc flash energy is relatively small (6% max) and the clearance time will be little
changed from that calculated for maximum fault current. Properly designed protection schemes
with fast acting elements for short circuit conditions should already result in almost the lowest
practical arc flash energy levels for the fault level at that point in the system while providing
adequate discrimination.
Difficulties will be found in achieving fast operating times when there are multiple levels of
substations fed at same voltage level unless there is bus zone or blocking scheme protection
installed. Traditionally such systems have not been installed at lower voltage levels (3-15kV) within
the Shell Group, since their complexity and cost were seen as outweighing the benefits. This
balance has now changed with introduction of numeric relays and implementation of such
schemes is now much simpler and requires no additional ct’s and little additional wiring.
For new installations this type of protection is still not preferred since it is possible to purchase IAC
switchgear which has been tested to control internal arc faults.
Such protection solutions are acceptable however as a retrofit solution to allow continued use of
an otherwise acceptable older installation.
Clearance times to meet 13 Cal/cm2 limit
Time in seconds
Proportion of fault current to calculate
tripping times
(based upon resistance earthed 6 kV board and 900mm distance)
1.1
1
0.9
0.8
Total Clearance time
to meet 13 cal/cm2
limit
0.7
0.6
Protection operating
time assuming a 80ms
breaker operating
time
Proportion of
potential fault current
through protective
device
0.5
0.4
0.3
0.2
0.1
0
10
20
30
40
50
60
Prospective Fault level in kA
In above illustrative graph it can be seen that, for the example 6kV switchboard being
considered, the allowable clearance times to meet a 13 cal/cm2 arc flash energy restriction will
only permit discrimination with downstream devices (tripping time > 0.4s) once fault levels are
SR.11.11111
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below 10-15kA, which is relatively low level for most locations. Also shown (green line) is the
relatively small change in proportion of prospective fault current to be used to deterimine tripping
times
It can also be seen that for any fault level up to around 40kA, protection which operates within
100ms will keep energy levels below 13 cal/cm2. If this protection operating time is adopted as a
standard then inherently the objective of restricting arc flash energy levels will be achieved
provided that care is taken that protection pick up values are consistent with available fault levels.
Therefore control of energy levels to maximum of 13 cal/cm2 by fast protection operation for
voltage levels up to 15kV is possible, provided discrimination can be achieved by some means. In
practice this implies using a blocking scheme when making protection changes to existing boards
since this does not require additional c.t.’s. to be fitted
F.1.2
Non IAC tested switchboards - Voltage range above 15kV
Once the voltage rises above 15kV a different calculation method is used in the IEEE spreadsheet
and the energy levels thereby calculated undergoes a step change and uses the original Lee
equations. These give results which are very conservative and for this reason the IEEE
recommendation is to restrict use of the spreadsheet to voltage below 15kV. Unfortunately we do
not yet have an alternative more accurate method available to quantify arc flash energies at these
higher voltages.
If the IEEE spreadsheet is followed as the method for determining arc flash energy levels, then,
even with total clearance time of 100ms, the calculated energy levels for a metal clad switchboard
with impedance earthing and at a typical 900mm distance a from the switchgear are always in
excess of 13cal/cm2 unless fault levels are below 10kA for 24kV and 6kA at 33kV. These are
relatively low fault levels compared to those normally seen at petrochemical facilities for these
voltage levels.
Exception to the above will be applications where higher voltages have been selected to reduce
voltage drop rather than as a consequence of higher power ratings.
In these circumstances boards at remote locations fed by overhead lines may have relatively low
fault levels at the receiving end. This means that the corresponding arc flash energy level will also
be low and may be kept below 13 cal/cm2 if “normal” fast acting protection is fitted and set up to
reflect the lower fault currents.
Note however in such circumstances it is still likely that the board at the sending end will have a
much higher fault level and be subject to higher potential arc flash energy levels.
Therefore for majority of applications using the IEE spreadsheet to calculate realistic protection
settings to control arc flash energy levels to less than 40 cal/cm2 at voltages above 15kV is not
possible with spreadsheet version currently available.
In conducting risk assessment we are forced to rely on a more subjective and less analytical
approach. Specifically to use our experiences with consequences seen when such flashovers have
occurred and the design features stipulated in our DEP’s which limit the creation of phase to
phase faults.
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Design features which assist in control of arc flash energy levels at voltages above 15kV can be




Fixed switchgear with cast resin insulation and cable terminations insulated to functional
insulation standards
Fast acting zone protection or blocking schemes,
Insulated bus bars
System impedance earthing to limit size of earth fault currents coupled with sensitive fast
acting earth fault protection.
Such systems designed such that an earth fault will always develop initially (limited by the earth
neutral impedance) and be detected & acted upon quickly before or while a phase to phase fault
is being fully established. Although the possibility of a phase to phase fault developing cannot be
eliminated, such a system is already reacting and responding to the fault condition and hence the
time during which a phase to phase fault exists will be less than the clearance time of the phase to
phase protection and associated circuit breaker.
It is not possible to make a firm prediction as to the resultant time a full phase to phase fault exists.
However evidence from locations where such failures have occurred, is that the consequences are
not as severe as predicted by the IEEE spreadsheet in its current form. As a further restriction and
to make the assumption conservative, such reduced effects can only be assumed to be effective in
limiting arc flash energy if all covers and doors are closed and secured.
Due to the difficulty in being precise in the arc flash energy levels present, for non IAC tested
switchboards operating above 15kV preference shall be given to operating remotely wherever
possible. This should include both switching and isolation actions.
For boards which are in compliance with DEP requirements and incorporate fast (typically trip
initiation within 100ms) acting protection i.e. differential, bus zone or blocking schemes, then
wearing of 40 cal/cm2 PPE when undertaking racking in/out operations is deemed to be ALARP.
F.1.3
IAC tested HV switchboards
The manufacturers IAC test report will define the test time which will typically be 0.1, 0.5 or 1s
duration. There are no boards with a 3s IAC test time.
Boards with a 0.1s IAC test time should be effectively assumed to be non-IAC tested since it is
almost impossible to detect and interrupt the supply within such a short timescale. To maintain
their IAC status it would be necessary to fit arc detection and very fast acting (6-10ms) switches
which apply a solid earth to all phases to quench the arc. The use of such switches and deliberate
application of a solid earth to the system is not recommended, both because of the stress of the
high fault currents on other components in the system and the depression of system voltage that
will occur.
0.5s IAC tested boards can only be assumed to be IAC compliant if their upstream supply feeder
protection operates within 0.5s. This implies all outgoing feeders must have instantaneous
protection which will then permit adequate discrimination (0.4s) between the upstream feeder and
outgoing feeder protection. However existing protection schemes may not have been set up with
this constraint and changes may be necessary. If such a board has a feeder supplying a
SR.11.11111
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subsidiary board at the same voltage then it will be impossible to maintain discrimination between
the incomer of the main board, the outgoing feeder from the main board and the outgoing
feeders of the subsidiary board without some form of blocking or differential scheme being
employed.
Note that comments previously made about cable terminations in Appendix E will apply to the
incoming cable connections, the outgoing cables will be protected by the instantaneous protection
on feeder circuits.
1.0s IAC tested switchboards will allow conventional protection schemes to be used since they will
have normally been designed to match the short circuit withstand time of the board (typically 1s).
Such boards therefore do not require modification to protection schemes for board to remain IAC
with possible exception of incoming cable compartments.
Where a 3s short circuit withstand time for a 1s IAC board has been specified there should have
been measures applied to interrupt bus bar faults within 1s since a 3s fault would effectively
destroy the switchboard. 3s short circuit withstand time boards are normally specified where
greater than 1s is required to provide discrimination with outgoing feeders and sub distribution
boards at the same voltage level. If no measures have been implemented to ensure bus bar fault
clearance within 1s then these boards should be treated as non-IAC boards.
To achieve compliance with IAC test timeanad still retain discrimination between incoming and
outgoing supplies it will be necessary to use blocking or bus zone protection scheme.
SR.11.11111
F.2
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LV Switchboards
For LV switchboards the reduction in potential fault current to be used to calculate protection
operating times is much larger, typically value to be used lies between 55% and 30% of maximum
fault current.
This severe reduction is applied as a result of tests done in the US to verify the size of fault
currents seen in practical applications.
The reduction in fault level is due to the fact that LV faults seen in practice always have impedance
which limits the maximum current to significantly less than that of a solidly bolted fault. A solidly
bolted fault is typically calculated in system studies and used to determine the required short
circuit withstand current of the busbar system.
If original scheme designers followed the rules and advice given in DEP or other sources of good
protection practice, then the protection will have been designed as described in Appendix A
Section 4.2 Commentary on LV switchgear assessment.
Experience has shown these guidelines have not been universally observed and relatively long
clearance times can have been allowed, especially where there are several levels of distribution
with air circuit breakers as protection elements rather than fuses.
This may arise because original protection design may have assumed it was sufficient for faults to
be cleared within the short circuit withstand time of the LV busbars (typically 1 or 3 seconds) or
even longer if the fault currents are less than the busbar rating.
Such assumptions are not valid if fault clearance time exceeds the arc flash tested value
(nominally 300ms for LV boards). There is no extension permitted to the clearance time because
the fault current is less than that used in the IAC test.
Clearance times to meet 13 cal/cm2 limit
(based on 400v board, solidly earthed and at a 610mm
Time in seconds
Proportion of fault current to calculate tripping times
distance)
1.3
1.2
1.1
1
0.9
0.8
0.7
0.6
0.5
0.4
0.3
0.2
0.1
0
10
30
50
70
90
Prospective Fault level in kA
Total Clearance time to meet 13 cal/cm2 limit
Protection operating time assuming a 80ms
breaker operating time
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From the above illustrative graph it can be seen that, to stay with a 13 cal/cm2 limit, for a 80kA
fault level the protection operating time must be around 100ms and that it must respond to 35% of
available fault current so around 28kA. Similarly for 50kA and 30 kA fault levels the time and
trigger current levels are 200ms / 20kA and 360ms / 13kA.
It is only when fault levels are less than 15kA that sufficient time delay can be allowed to permit
discrimination with a second level of distribution and still stay with a 13cal/cm 2 limit if a minimum
discrimination time between devices of 300-400ms is assumed.
For typical transfomer fed LV board this means limiting the supply transformer to having a rating
of 500kVA or lower and not being operated in parallel with another supply. Such installations
are only normally found in electrified production fields with a limited number of ESP’s installated.
A typical potential 50kA short circuit level installation is where two 1 MVA transformers are
paralleled by closing a bus section, say to allow one transformer and its switchgear to be taken
out of service for maintenance. It should be noted that when operating alone the fault level is say
25kA and the corresponding fault current for assessment of operating time is 11.5kA but when
operating in parallel at 50kA the tripping time calculation fault current is 9.9kA. The difference is
explained by the reduction in proportion of available fault current from 45% at 25 kA down to
40% at 50kA. Hence parallel operation is likely to be the most onerous limit to be met.
For an installation with more than one level of low voltage distribution which is not fed by a fault
limiting device e.g. a fuse, then to restrain the energy levels below the 13 cal/cm2 target where
fault levels are greater than 15kA at the supplying board it will be necessary to have devices
which allow much shorter discrimination times than default 300-400ms.
Vendors of modern air circuit breakers suggest that discrimination will still be achieved even with
timing differences as low as 100ms.
1600A
Incomer air
circuit
breaker
2
1
1
Main switchboard
400A
Feeder air
circuit
breaker
3
Incoming
switch
2
Subsidiary switchboard
160A
Moulded
case circuit
breaker
160A
3
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In this example the vendor is suggesting 100ms is sufficient to allow discrimination between the
incoming air circuit breaker and the feeder to the subsidiary board while still co-ordinating with
loads on subsidiary board. This example gives an operating time of 200ms from 3000A upwards
for main board which would mean for 2*1MVA fed switchboard the criteria for keeping energy
levels below 13 cal/cm2 would be met.
Whilst this reduced time discrimination may be possible for modern numerical microprocessor
based protection it is not recommended to use such close settings for older devices with
conventional thermal or magnetic trips.
It is also recommended that, irrespective of circuit breaker age or protection type, whenever use
is made of lower discrimination times than default values, the application is discussed with
vendors of the circuit breakers to obtain confirmation system will operate as expected.
A protection operating time of 100ms will restrain energy levels below 13 cal/cm 2 for up to
90kA. So control of energy levels to below 13 cal/cm2 by fast protection operation is
theorectically possible, provided discrimination can be achieved by some means.
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F.3
F.3.1
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Summary of practical solutions
Non IAC-tested HV switchboards up to 15kV
Ideal solution is to fit protection which will operate within 100ms. This will limit energy levels to 13
cal/cm2 or less for all fault levels up to 40kA, allowing use of lower rated PPE when undertaking
tasks with a significant risk of an arc flash event.
For retro fit permanent solutions this can most economically be achieved by replacing existing
relays with numeric devices and implementing a blocking scheme between the outgoing feeders
and the incoming sources of supply. Note that standing load of new relays will mean the
associated substation DC power supply units and batteries will also need to be replaced.
An alternative solution is to fit new relays to incoming sources of supply and a have means of
temporarily applying definite time elements with 100ms trip time while activities with highest risk
of an arc flash event e.g. racking in / out are being undertaken. As an example a switch could be
provided to change the setting group to one which has a definite time element included. To
prevent sensitive setting being left on by accident then use a timer in the relay logic to force
reversion to original setting group after a set period has elapsed from activation e.g. 5 minutes.
As an additional safeguard local indication and/or alarm could be raised while the more
sensitive settings are enabled.
Even with an automatic cancellation of protection settings change, the latter solution carries a
residual risk i.e.a fault occurring downstream of the switchboard while the more sensitive setting is
applied could cause whole board to trip rather than just affected circuit.
For either solution fitting of fast acting elements to incomer circuit breakers will not limit arc flash
energy at the incoming cable compartments or the incomer circuit breakers themselves. Hence
additionally it is recommended to adopt procedure that racking in/out is only performed when
incoming supply is isolated such that the breaker being moved is then protected by fast acting
protection on the remaining incomer (refer to switching sequences mentioned in Appendix D
section1)
F.3.2
Non IAC-tested switchboards above 15kV
Preferred solution is to use remote racking in / out open / close equipment where personnel can
undertake these operations either in a control room or while standing outside the substation and
away from the entrance doors to the substation.
While it is normally relatively straightforward to implement a remote electrically operated
open/close function it is less easy to make racking in/out a remote operation. There are
motorised devices available to drive the racking lead screw, either from the switchgear vendor or
from specialist companies.
Alternatively (although this is not supported by a formal calculation) for boards compliant with
DEP (insulated busbars, higher IP ratings etc) where all potentially arc flash creating actions can
be undertaken with doors or covers closed then use fast acting protection (as described for
switchgear up to 15kV) set to operate at maximum of 100ms together with PPE rated to 40
cal/cm2.
As with lower voltage boards the fast protection setting can be permanent or temporary in nature
SR.11.11111
F.4
F.4.1
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Confidential
Summary of solutions for LV switchboards
IAC tested switchboards
Assuming the installation follows DEP std drawings and recommended protection scheme then
simplest modification is to introduce a fast acting definite time element to the upstream protection
set to pick up and start to time out at 85% of the calculated arcing fault current with a delay of
300ms (assumes IAC test time of board is 300ms).
In almost every case this will require a check made with the largest outgoing feeder protection to
ensure adequate discrimination at the proposed pick up current. If fault levels are such that the
fault level is determined principally by the transformer impedance (i.e. transformer impedance >>
supply system impedance) and if the largest outgoing fuse is no greater than ¼ of the
transformer FLC then adequate discrimination should be possible. Where larger fuses are fitted
than this ratio there is a greater possibility that discrimination time will be less than recommended
value given by 4*fuse operating time + 150ms.
A further limitation is that in most instances the pick up value of this element will be within the
value of the inrush current of the transformer (10-12 times FLC). To prevent tripping on
energisation it is recommended that the fast acting element is inhibited from operation before and
for first 10 seconds after transformer energisation.
As with HV protection there is an opton to make this additional element a temporary change such
that it is only activated when undertaking higher risk activities. Especially if the board is of DEP
compliant type with limited locations / actions which give rise to an arc flash risk, then use of a
temporary setting reduction may be preferable to a permanent application of an additional fast
acting element if discrimination margins with outgoing circuits are close to recommended
minimum margins.
Note For Delta-Star connected transformers to ensure discrimination under all possible fault
conditions the discrimination must be valid when primary side currents are calculated at a value
of approx 15% higher than use of simple transformer voltage ratio indicates.
F.4.2
Non IAC-tested switchboards
The same protection as referred to for IAC tested boards can be applied as suggested for
IACswitchboards but with time delay limited to 100ms to reduce arc flash level to below 13
cal/cm2 for all fault levels up to 80kA. This will mean discrimination with outgoing circuits cannot
be maintained in many instances therefore can only be used as a temporary change while higher
risk activities are carried out.
Depending on type of switchgear this can mean such a reduction is being routinely applied which
increases risk of an unwanted trip due to co-incident downstream fault elsewhere while lower
settings are being applied.
In such cases it may be decided that business risks of lost production justify the cost and difficulty
of making the switchgear fully remotely operable at least for high risk activities such as racking
in/out.
If the lack of discrimination affects only larger circuit breaker protected outgoing circuits it may be
possible to add an inhbit function to such circuits such that the incoming supply fast acting element
is inhibited in event of a downstream fault on one of the circuit breaker fed circuits.
SR.11.11111
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Confidential
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