EXPERIENCE CONCERNING AVAILABILITY AND RELIABILITY OF DIGITAL SUBSTATION AUTOMATION SYSTEMS

687
EXPERIENCE CONCERNING
AVAILABILITY AND RELIABILITY OF
DIGITAL SUBSTATION AUTOMATION SYSTEMS
(DSAS)
WORKING GROUP
B5.42
MAY 2017

Members
M. PETRINI, Convenor IT
R. LØKEN, Secretary NO
E. CASALE IT
A. DARBY GB
C. DE ARRIBA ES
T. FABIO IT
P. LINDBLAD FI
J.L. NOE FR
M. PEDICINO IT
Contributors
M. BASTOS BR
F. KAWANO JP
Y. WATABE JP
D. ESPINOSA MX
WG B5.42
Copyright © 2017
“All rights to this Technical Brochure are retained by CIGRE. It is strictly prohibited to reproduce or provide this publication in
any form or by any means to any third party. Only CIGRE Collective Members companies are allowed to store their copy on
their internal intranet or other company network provided access is restricted to their own employees. No part of this
publication may be reproduced or utilized without permission from CIGRE”.
Disclaimer notice
“CIGRE gives no warranty or assurance about the contents of this publication, nor does it accept any responsibility, as to the
accuracy or exhaustiveness of the information. All implied warranties and conditions are excluded to the maximum extent
permitted by law”.
WG XX.XXpany network provided access is restricted to their own employees. No part of this publication may be
reproduced or utilized without permission from CIGRE”.
Disclaimer notice
“CIGRE gives no warranty or assurance about the contents of this publication, nor does it accept any responsibility, as to the
EXPERIENCE CONCERNING
AVAILABILITY AND RELIABILITY OF
DIGITAL SUBSTATION
AUTOMATION SYSTEMS (DSAS)
ISBN : 978-2-85873-390-3

Experience concerning availability and reliability of DSAS
Page 3
Experience concerning
availability and reliability of
DSAS
Table of Contents
1 PREFACE..............................................................................................................................................6
2 SCOPE...................................................................................................................................................6
3 DEFINITIONS ........................................................................................................................................7
4 OVERVIEW OF THE RESPONDENTS.................................................................................................8
4.1 Main activities of respondent companies..........................................................................................8
4.2 Substations and voltage levels .......................................................................................................10
4.3 DSAS technology............................................................................................................................10
4.4 Type of DSAS manufacturers from which the utilities purchase their DSAS .................................12
4.5 Strategies adopted by utilities for producing DSAS technical specification ...................................14
4.6 Purchasing and implementation strategies.....................................................................................15
4.7 Standardization and cost reduction ................................................................................................16
4.8 Dependability management and company organization ................................................................17
4.9 Conclusions ....................................................................................................................................17
5 DSAS CONCEPT AND DEFINITION..................................................................................................19
5.1 DSAS RAMP requirements defined by utilities...............................................................................19
5.2 Means used by utilities to support the fulfilment of RAMP requirements .......................................20
5.3 Environmental conditions defined in the DSAS specification.........................................................20
5.4 Maintainability requirements defined by utilities .............................................................................21
5.5 Function dependability....................................................................................................................21
5.6 Where RAMP requirements come from..........................................................................................23
5.7 How utilities define cyber security requirements ............................................................................24
5.8 Conclusions and suggestions.........................................................................................................24
6 DESIGN AND DEVELOPMENT..........................................................................................................26
6.1 General design strategies to guarantee higher DSAS reliability ....................................................26
6.2 Reasons for different DSAS architectures......................................................................................26
6.3 DSAS architecture and distribution of functions .............................................................................28
6.4 Functional integration .....................................................................................................................29
6.5 Design strategy to deliver higher reliability of products ..................................................................30
6.6 Design solutions adopted to improve the RAMP of DSAS .............................................................31
6.7 How utilities verify the fulfilment of RAMP requirements................................................................33
6.8 Features of IEC 61850 not yet exploited enough ...........................................................................33
7 MANUFACTURING .............................................................................................................................36
7.1 Level of detail of RAMP requirements ............................................................................................36

Page 4
7.2 Use of pilots as a proof of concept .................................................................................................37
7.3 Vendor policies about RAMP..........................................................................................................37
8 INSTALLATION...................................................................................................................................43
8.1 Technical support from vendors during DSAS installation .............................................................43
8.2 Degradation or improvement of RAMP after the pilot.....................................................................43
9 OPERATION AND MAINTENANCE ...................................................................................................45
9.1 Data recorded by utilities ................................................................................................................45
9.2 Actions made by utilities based on recorded figures ......................................................................47
9.3 Tests performed by utilities to evaluate DSAS maintainability .......................................................48
9.4 Number of faults occurring in DSAS...............................................................................................49
9.5 Occurrence of faults during the different life cycle phases.............................................................50
9.6 Post warranty DSAS maintenance and support contracts .............................................................52
9.7 Use of remote access for maintenance ..........................................................................................52
9.8 Differences between vendors in topics affecting RAMP.................................................................53
9.9 Topics affecting MTTR....................................................................................................................54
9.10 Impact of DSAS firmware-upgrading activities ...............................................................................56
9.11 Experiences concerning malware/viruses in operating DSAS .......................................................57
9.12 Rate of software/firmware upgrade ................................................................................................57
9.13 Dependability improvements brought by digital technology ...........................................................59
9.14 Improvements brought by IEC 61850.............................................................................................61
9.15 Vendor’s skills seen from utility point of view .................................................................................62
9.16 Utilities’ skills seen from vendor point of view ................................................................................62
9.17 Conclusions and Suggestions ........................................................................................................64
10 DISPOSAL...........................................................................................................................................66
10.1 Useful life of DSAS based on proprietary protocols or platforms ...................................................66
10.2 Useful life of DSAS based on IEC 61850 .......................................................................................67
10.3 Main reasons for disposal or refurbishment / upgrading ................................................................68
11 CONCLUSIONS ..................................................................................................................................71
11.1 Use of IEC 61850 ...........................................................................................................................71
11.2 RAMP requirements .......................................................................................................................72
11.3 Cybersecurity..................................................................................................................................73
11.4 RAMP requirements effect and fulfilment .......................................................................................73
11.5 DSAS maintenance ........................................................................................................................74
11.6 Recorded RAMP figures and their use ...........................................................................................75
11.7 DSAS obsolescence and useful life................................................................................................76
11.8 Future trends...................................................................................................................................76
11.9 Suggestions ....................................................................................................................................77
12 ACRONYMS ........................................................................................................................................78
13 REFERENCES ....................................................................................................................................80
ANNEX A. SURVEY REPORT....................................................................................................................82
PURPOSE OF THE QUESTIONNAIRE......................................................................................................82
READING INSTRUCTIONS ........................................................................................................................83
A - OVERVIEW OF UTILITIES AND VENDORS ........................................................................................84
B - DSAS CONCEPT AND DEFINITION.....................................................................................................91
C - DESIGN AND DEVELOPMENT ............................................................................................................98
D - MANUFACTURING .............................................................................................................................107

Page 5
E - INSTALLATION....................................................................................................................................113
F - OPERATION AND MAINTENANCE ....................................................................................................115
G - DISPOSAL...........................................................................................................................................131
ANNEX B. DEFINITIONS AND TERMS ...................................................................................................134
ANNEX C. MATHEMATICAL EXPRESSIONS FROM THE STANDARD................................................144
ANNEX D. EVALUATION OF THE DEPENDABILITY OF A DSAS ........................................................148

Page 6
1 PREFACE
Nowadays Reliability, Availability, Maintainability (and, more in general, “Dependability”) are essential performance
measures for systems used in every domain. A dependable product is achieved through the implementation of
dependability disciplines during the whole life cycle, from the early concept to the disposal.
Digital Substation Automation Systems (DSAS) are a vital element for the efficiency of the power system operation.
Their functions include protection, command, control, supervision, grid and equipment monitoring, auto-diagnosis
and metering, to varying degrees of capability and complexity.
DSAS have already been in service for several decades. Most utilities and vendors have their own procedure to
gather information from the field about operation and failure analysis of DSAS, and initiate specific maintenance or
replacement actions based on this information.
It is thus timely to consider the experiences of the variety of solutions of DSAS deployed, and give meaningful
reference to Users, Manufacturers and Systems Integrators, in order to allow them to specify, design and develop
the new systems with an improved fulfilment of Reliability, Availability, Maintainability, and Performance (RAMP)
requirements.
A survey was sent to Utilities, Manufacturers and Systems Integrators to collect feedback and experiences
concerning RAMP requirements of different DSAS solutions. The first section of the survey was intended to give a
snapshot about respondent companies (overview of utilities and vendors (section A)). The following sections of the
survey were structured in the different lifecycle phases considered relevant for RAMP, and defined according to the
IEC 60300 standard (Dependability management):
• DSAS concepts and definitions (B);
• Design and development (C);
• Manufacturing (D);
• Installation (E);
• Operation and maintenance (F);
• Disposal (G).
2 SCOPE
Feedback of the experience gained to date has been identified as of major benefit to users, not only for life-time
management but also for new developments or improvements of protection and control systems.
Based on a survey of utilities and vendors, the purpose of this Technical Brochure is to collate the experience, in
order to give recommendations applicable to:
• DSAS specification, design, architecture and maintenance;
• Protection and control IEDs design and maintenance;
• Utility organization concerning DSAS specification, design, operation and maintenance.
The brochure describes the approach and practice used by different utilities and vendors for the DSAS’s RAMP
requirements and monitoring, not only considering the general definitions of these terms, but also the specific
interpretation of their meaning given by each entity, in order to establish a coherent overview of the existing practice.
Some numerical analysis of the survey is also given.
Moreover, concerning the penetration of new technologies, figures have been gained related to:
• DSAS versus legacy electromechanical and electronic SAS;
• DSAS based on IEC 61850 versus DSAS based on proprietary solutions.
Finally, utilities and vendors feelings about the impact of the IEC 61850 Standard on DSAS RAMP have been
investigated.

Page 7
3 DEFINITIONS
This chapter describes the meaning of the main terms or acronyms used in the rest of the document. Further
definitions related to RAMP are available in the Annex B.
DSAS (CIGRE SCB5 WG06: Maintenance Strategies for Digital Substation Automation Systems – June 2011)
“DSAS are Substation Automation Systems using digital communications on substation level where the main
functions are implemented in Intelligent Electronic Devices (IED) such as bay controllers or digital protections. Data
are exchanged between different devices of the DSAS through a local network based on fiber optic cables and/or
copper wires. It may be based on LAN and switches, which connect all the IEDs to the station computer, to gateways
and to the time synchronizing equipment.”
IED
Intelligent Electronic Device
RAMP
RAMP is the acronym of “Reliability, Availability, Maintainability and Performance”. For Definitions and Terms related
to RAMP extracted from International Standards, please refer to the Annex B.
User
Company involved in electric power transmission or distribution that uses DSAS. In this document, the term “User”
takes on the same meaning as the term “Utility”.
Utility
In this document, the term “Utility” is referred to a company mainly involved in electric power transmission or
distribution.
Vendor
The term is generally referred to:
• Manufacturers, that make the main components of a DSAS (for example IEDs);
• System Integrators, that make a whole DSAS using components produced by third party companies
or by themselves;
• Consultant companies supporting utilities in DSAS specification or engineering.
Transmission system operator
Transmission system operator means a natural or legal person responsible for operating, ensuring the maintenance
of and, if necessary, developing the transmission system intended as an high-voltage electric grid which includes
delivery to final customers or to distributors, but does not include supply;
Distribution system operator
Distribution system operator means a natural or legal person responsible for operating, ensuring the maintenance of
and, if necessary, developing the distribution system intended as a medium-voltage and low-voltage electrical
systems which includes delivery to customers, but does not include supply;

Page 8
4 OVERVIEW OF THE RESPONDENTS
The WG B5.42 survey, sent in 2013, has received 36 answers by 24 utilities and 12 vendors from all of the 5
continents. A detailed list of responding countries is in the Annex A (Question A–2).
4.1 Main activities of respondent companies
In question A - 1 companies were asked to indicate their main activity.
Considering that the respondents were allowed to flag more than one option, the sum of percentages shown in Table
1 (and often in the rest of the brochure too) can be greater than 100.
Most of the responding utilities (87.5%) manage transmission substations, 50% manage distribution substations and
25% are involved in power generation.
Items
Totals (36 responding, 0
not responding)
Vendors
(12 responding, 0 not
responding)
Utilities
responding)
Generation 6 16.7% 0 0.0% 6 25.0%
Transmission 21 58.3% 0 0.0% 21 87.5%
Distribution 12 33.3% 0 0.0% 12 50.0%
Manufacturer 9 25.0% 9 75.0% 0 0.0%
System Integrator 9 25.0% 8 66.7% 1 4.2%
Consultant 3 8.3% 3 25.0% 0 0.0%
Other: Railway 1 2.8% 1 8.3% 0 0.0%
Table 1
Vendors activities are almost equally distributed between two options: Manufacturer (75%) and System Integrator
(66.7%); a small part (25%) of vendors is also involved in consulting activities.
A different view of respondents is given in Figure 1 and Figure 2, where options proposed in the survey as main
activity, have been aggregated as indicated in the labels. For example, “Transmission Utilities” includes responding
utilities involved only in transmission activity (that is, they flagged only the “Transmission” option); “Transmission and
Distribution Utilities” indicates utilities that flagged at the same time transmission and distribution activities.

Page 9
Figure 1
Figure 2
It is interesting to notice that only one of the respondent utilities is also a System Integrator.
For vendors, many manufacturers (42% of respondent vendors) are also System Integrators: this is not surprising
because this applies, for example, to worldwide manufacturers that have both factories - typically serving multiple
countries - and engineering units involved in DSAS integration - typically one per country/region.
Generation and
Transmission and
System Integrator
4%
Generation and
Transmission and
Distribution
9%
Generation and
Distribution
4%
Generation and
Transmission
8%
Transmission and
Distribution
29%
Distribution
8%
Transmission
38%
Overview Of Utilities Respondents
Manufacturer
25%
System Integrator
9%
Consultant
8%
Manufacturer and
System Integrator
42%
Consultant and
System Integrator
8%
Manufacturer and
System Integrator
and Consultant and
Railway
8%
Overview Of Vendors Respondents

Page 10
4.2 Substations and voltage levels
In question A - 2, utilities were asked to indicate the number of substations and power stations1 owned, being the
former furtherly parted in transmission and distribution. In addition, it was requested to specify their grid voltage
levels.
In Table 2, besides the detailed quantity of utilities per class, the sum of substations declared by the utilities is
reported.
For example, referring to the first row (transmission utilities), the total number of “transmission utilities” (that is, the
utilities that flagged only the “Transmission” option) is 9. The sum of the Transmission Substations owned by the 9
transmission utilities is 3,751.
Referring to the third row: the total number of “Transmission and Distribution Utilities” (that is, the utilities that flagged
both the “Transmission” and “Distribution” options) is 7. In this case, 7 Transmission and Distribution Utilities own
both transmission substations (the total is 620), and distribution substations (the total is 45,587). The total number of
substations owned by the 7 utilities is 46,207.
Main activity of utilities
Utilities type
(24 responding, 0
not responding)
N° of power
substations
N° of transmission
substations
N° of
distribution
substations
Total
substations
Transmission Utilities 9 0 3,751 0 3,751
Distribution Utilities 2 0 0 2,097 2,097
Transmission and Distribution
Utilities
7 0 620 45,587 46,207
Generation and Transmission
Utilities
3 14 167 0 181
Generation and Distribution
Utilities
1 3 0 300 303
Generation, Transmission and
Distribution Utilities
2 190 425 870 1,485
Totals 24 207 4,963 48,854 54,024
Table 2
Note: compared to Figure 1, a simplification has been done in Table 2. In order to reduce the number of classes of
respondents, the “generation and transmission and system integrator” class has been included in the “generation
and transmission” class. This simplification is possible because only one Utility belongs to the “generation and
transmission and system integrator” group and that it only owns power substations and transmission substations
such as the utilities in the “Generation and Transmission Utilities” class. These simplifications are assumed in the
rest of the chapter.
4.3 DSAS technology
In question A – 3, utilities were asked to indicate the total number of their DSAS based on the definition given in 3
and, among these, the number of DSAS based on IEC 61850.
1
The term power station refers to substation where a power plant is connected to the electric grid.

Page 11
For simplicity reasons, the 6 responding utilities classes identified in Table 2, are now grouped in the following 2 main
types:
• “mainly transmission utilities” (for example utilities mostly involved in transmission activities),
includes the two groups “Generation and Transmission” and “Transmission utilities”;
• “mainly distribution utilities” (for example utilities mostly involved in distribution activities) includes
“Generation and Distribution”, “Generation, transmission and distribution” and “Transmission and
Distribution”.
“Mainly transmission utilities” manage 3,932 substations in total: 3,918 transmission substations and 14 power
substations.
“Mainly distribution utilities” manage 50,092 substations in total: 48,854 distribution substations, 1,045 transmission
substations, 227 power substations. As the total number of distribution substations is 48,854 ( (*) = percentage
based on the total substations number
(**) = percentage based on the number of DSAS substations
Table 3) this class owns the totality of distribution substations. Moreover, in this class there are also some
transmission and power substations, but, as they represent almost 2.5% of the total substations managed by “Mainly
distribution utilities”, we can consider this class made only by distribution utilities.
Type of Utility
N. of Utilities per
type (24
responding)
Total
substations
Total DSAS
substations
Total IEC
61850
Substations
% of DSAS
substations*
% of IEC
61850
substations*
% of IEC
61850
substations**
Mainly Transmission 12 3,932 1,027 364 26.1% 9.3% 35.4%
Mainly Distribution 12 50,092 4,298 87 8.6% 0.2% 2.0%
Total 24 54,024 5,325 451 9.9% 0.8% 8.5%
(*) = percentage based on the total substations number
Table 3
Looking at the last row, (*) = percentage based on the total substations number
Table 3 gives primarily information about the diffusion of the digital technology versus the electromechanical/static:
about 10% of the 54,024 total substations are digital. The number of electromechanical/static SAS in service is still
very high. In all probability, this could be related to the fact that the electromechanical/static SAS have not yet reached
the end of their useful life and it has been considered too early to have them replaced. Another reason may be the
possibility to renew only specific critical parts (for example the protection devices), preserving the same interfaces,
instead of renewing the whole SAS. This is another way to align some functions to the new technologies, preserving
the rest of the system.
With reference to the diffusion of IEC 61850, it is interesting to notice that 8.5% of the DSAS are based on IEC 61850.
10 years have passed since the first edition of the standard and only a small percentage of the DSAS in service have
adopted it. This is not surprising as every innovation is often accompanied by slow changes due to inertia of the past
habits and also to some people’s scepticism. In addition, the installation of an IEC 61850 DSAS is related to the
substations renewal, and this process seems to be very slow.
Considering the differences between transmission and distribution classes of utilities, (*) = percentage based on the
total substations number
Table 3 above shows that the “mainly transmission utilities” manage a smaller number of substations (3,932), but the
DSAS percentage (26.1%) over the total number of substations is significantly greater. For “mainly transmission”
utilities, also the IEC 61850 based DSAS percentage (35.4%) is relatively high.

Page 12
On the contrary, for the “mainly distribution” utilities, DSAS are used only in 8.6% of the total number of substations,
only 0.2% out of the total of SAS are IEC 61850 based. Hence, the distribution utilities are characterized by a minor
DSAS penetration and the percentage of IEC 61850 based DSAS is even lower.
The low diffusion of Digital Technology may be related to the fact that generally the quantity of distribution substations
managed by one utility is much greater than the quantity of transmission ones, hence they need much more economic
efforts to be managed and to be kept upgraded to the latest technological standards.
Moreover, the consequences deriving from a failure in the transmission grid generally raise more concern, not only
because the components of EHV grids have much higher costs but also because the grid is a part of an
interconnected transmission system, a failure in one region could affect other regions, or even the overall system
stability and safety, resulting in many loads shedding. Accordingly, the transmission substations must be protected
by a more sophisticated and well-maintained system. On the contrary, at the LV distribution level, normally the grid
components have relatively minor cost. Each failure would normally result in a power supply interruption for some
consumers, but because of radial topology, the consequences of the failures are normally local. This can explain the
reason for a lower focus on digitalization of distribution substations.
However, with more stringent power quality requirements and the rising number of distributed generation connections
to the grid, the distribution grid scenario is changing.
4.4 Type of DSAS manufacturers from which the utilities purchase
their DSAS
By answering question A-4, utilities give information about the type of vendor (for example vendor dimension/market
orientation) and on the quantity of vendors from which they purchase their DSAS. The types of vendors proposed by
the question were the followings:
• Countrywide local vendor: a middle/small vendor from the same country as the utility, that cannot be
defined as a worldwide vendor;
• Countrywide foreign vendor: a middle/small vendor not from the same country as the utility, that
cannot be defined as a worldwide vendor;
• Worldwide manufacturer: a multinational vendor competing in the worldwide market.
Concerning the number of DSAS vendors they use, there is some variety in the utility declarations: values given by
the respondents range from 1 to 7. Probably, this variety depends on the interpretation of the option offered by the
question. Maybe in some case the term “countrywide local vendor” could be interpreted as a “worldwide
manufacturer” that refers to local suppliers or local system integrators; the term “countrywide foreign vendor” could
be interpreted as a “worldwide manufacturer”.
Anyhow, the number of vendors for each type has been evaluated by a weighted average of the values recorded
from the answers. The used weight is the “frequency” of each value; for example, if “2 vendors” is the most frequent
value within the utilities for a certain type of vendor, then the value “2” will have a bigger weight.
As in the previous questions, the respondents can flag more than one option.
As it could be expected, most of the utilities (18 out of 24) purchase their DSAS from a worldwide manufacturer, with
an average of 3 different “worldwide vendors”. The “worldwide vendor” has several competitive advantages:
• many differentiated products deriving from historical experience, developed for different markets and
for different needs in the world;
• it can lower its prices due to economies of scale;
• it has a sufficiently large and stable organization to install, support and maintain the asset for a long
time and almost everywhere in the world.
“Countrywide local vendors” is the second most flagged option, with an average of 3 vendors per utility. The big
advantage of this kind of vendor is the possibility to provide a custom solution to meet as much as possible the utility’s
needs; this is sometimes impossible for a worldwide vendor.

Page 13
Finally, “countrywide foreign vendors” are the least flagged vendors, with 4 flags and 2 vendors in average declared
by utilities.
Probably this is due to the following reasons:
• they may not be as reliable as a worldwide manufacturer, but they could offer the same countrywide
local vendor advantages. However, they are not from the same country as the utility and this could
result in some market barriers;
• they are prepared to satisfy the local market of their country and probably they cannot fully satisfy
all the specific foreign utility requirements;
• they probably cannot satisfy the need for assistance during the DSAS lifecycle, not being present in
the utility country with local infrastructures;
• normally, between the local vendor and the utility, there is a very clear link related to the
customization of the products. Furthermore, a countrywide manufacturer relies on the utility for
business continuity, and the utility relies on the manufacturer for the support during the lifecycle of
the installed DSAS. This could be a risk for referring to foreign countrywide vendors.
Figure 3 shows the different combinations of types of vendor selected by the respondent utilities.
Figure 3
Half of the utilities refer only to “worldwide manufacturer” for their DSAS purchasing, then 25% adopt a double
strategy: “worldwide” and “country local manufacturer”. The remaining 25% is composed of utilities purchasing
solutions only from “countrywide manufacturers”: local countrywide, foreign countrywide or both local and foreign
countrywide.
Interesting findings:
The utility declaring only one “foreign countrywide vendor” owns over 31,000 distribution substations, including LV
substations (400V), while the utility declaring only “local countrywide manufacturer”, declares 7 vendors, and owns
almost 2,700 substations, not including LV substations.
Worldwide
Manufacturer
50%
Countrywide Local
Vendor and
Worldwide
Manufacturer
25%
Countrywide Local
Manufacturer and
Countrywide Foreign
Manufacturer
13%
Countrywide Local
Manufacturer
8%
Countrywide Foreign
Manufacturer
4%
Mix of DSAS manufacturers adopted by responding utilities

Page 14
4.5 Strategies adopted by utilities for producing DSAS technical
specification
Question A - 5 referred to the strategy adopted by the utilities for the production of their DSAS technical specifications.
Considering that more flags were allowed per respondent, respondents chose the options provided by the question
as follows:
• 88% flagged to “produce the specifications on their own”;
• 21% flagged to “purchase the specification”;
• 21% flagged to “involve the consultant for a contribution”.
Figure 4 shows the correlation between the strategies for producing the specifications and the main activities of the
responding utilities. As already explained for the A-3 question, two main activities can be considered for utilities:
transmission and distribution. Considering the strategies for specifications, some utilities adopt mixed solutions
(option 1 and option 2, or option 1 and option 3). The percentages in the graph are calculated by dividing the number
of flags by the number of responding utilities (24, in this case).
Looking at Figure 4, we have:
• for both transmission and distribution utilities, the most used specification strategy is option 1:
“specification on your own”; this means that the specifications are completely produced using internal
competences, without external support;
• for transmission utilities:
o the second most used strategy is to have both cases: some specifications are produced completely
internally by the company, for some specifications it is necessary to involve a consultant for an external
contribution;
o the least used strategies are the “purchasing of a specification” and the “involving a consultant” for a
complete support for all the specifications.
• for distribution utilities:
o the second mostly used strategy is to have both cases: some specifications are purchased, some others
are produced in the company;
o the least used strategy is to purchase all the specifications.
Even if this aspect has not been considered in the question, the different strategies adopted may depend on the
different types of project to be developed: for projects using “standard” applications, the company could have the
internal skills to develop the specification, otherwise for new or unusual projects, the intervention of a consultant on
the specific subject may be preferred.

Page 15
Figure 4
4.6 Purchasing and implementation strategies
Utilities were asked about their DSAS purchasing and implementation strategies by question A - 6.
DSAS purchasing & implementation policy
N° of flags (24
responding,0 not
responding)
% of the
responding
You purchase a turnkey substation/power station 10 42%
You purchase components and integrate them by yourself (In-house
development)
9 38%
You purchase a DSAS based on an off the shelf product 8 33%
You require a product customization for your DSAS 7 29%
Other 0 0%
Table 4
As we can see in Table 4, the answers to the question A-6 seem to be quite balanced as the flags are almost equally
distributed for all the options. Moreover, the most flagged options: “You purchase a turnkey substation/power station”
and “You purchase components and integrate them by yourself”, refer to two opposite strategies. These ambiguous
results do not help us to deduce a general strategy.
The detail of combinations selected by respondents may be useful. As already done previously, in the following table
the combinations of answers obtained are collated (see Table 5). For example: the row “customization” shows the
number of utilities that only ticked the option “You require a product customization for your DSAS”. The row
“integration” shows the number of flags from utilities that only ticked the box: “You purchase components and
integrate them by yourself (In-house development)”. “Turnkey DSAS and Off the Shelf” shows the flags on both of
the following items:
• “You purchase a turnkey substation/power station”;
• “You purchase a DSAS based on an off the shelf product”.
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
MAINLY TRANSMISSION MAINLY DISTRIBUTION
Correlation between specification strategies and main activity
Purchasing + Own Solution
Consultant + Own Solution
Purchasing
Consultant
Own Solution

Page 16
Answers Number of flags
Turnkey DSAS 5
Customization 5
Integration 4
Turnkey DSAS and Off the Shelf 3
Off the Shelf and Integration 2
Turnkey DSAS and Off the Shelf and Integration 1
Off the Shelf 1
Off the Shelf and Customization 1
Customization and Integration 1
Turnkey DSAS and Integration 1
Table 5
Starting from the results given in Table 5, we could try to aggregate the answers characterized by some common
element; this leads to resolve the 10 combinations in two different groups, corresponding to two strategies (according
to two different highlighting colours used for the rows):
• Strategy 1 (green, italic): utilities purchasing only Turnkey or Off The Shelf DSAS. These utilities
do not achieve any customization of the vendors product or any in-house integration in their DSAS;
• Strategy 2 (red, normal): utilities introducing some customization or in-house integration in their
products. The customization could concern a big or a little part of the vendor product. The utilities
may also have different strategies for different DSAS: off the shelf product for some DSAS,
customization for other DSAS, or alternatively they could purchase an off the shelf product and
require some customization from the vendor.
Aggregating the respondents according to the abovementioned strategies, it is possible to point out a predominant
tendency, within the responding utilities, to require modifications/customization from the vendors, or make in-house
integration, to better suit their specific needs (Strategy 1: 9 flags; Strategy 2: 15 flags).
A correlation between the previous figures and the main activity of the respondent utilities, gives the following results:
• 5 transmission utilities, owning 28.5% of DSAS, do not require any customization for their DSAS
from the vendors;
• 7 transmission utilities, owning the remaining 71.5% of DSAS, usually require some customization
or perform some integration on their DSAS from the vendors;
• 4 distribution utilities, owning 1.5% of DSAS, do not require any customization to their DSAS from
the vendors;
• 8 distribution utilities, owning the remaining 98.5% of DSAS, usually require some customization or
perform some integration on their DSAS from the vendors.
Therefore, for both transmission and distribution utilities managing a large number of substations, the tendency is
the same: requiring customizations for DSAS from the vendors in order to fit their specifications.
4.7 Standardization and cost reduction
Question A - 7 was intended to establish if the main driver for the development of DSAS solutions is standardization
or cost reduction.
The most flagged option (63.6%) is the development of a DSAS standard project, to be applied to as many cases as
possible. Therefore the utilities seem to prefer to reduce the design solutions, in order to reduce the proliferation of
design changes and so reduce the maintenance costs. The maintenance process takes advantages from this strategy

Page 17
because of the possibility to use the same spare parts, the same training courses, and the same operation
experiences. This results, from the RAMP point of view, in an increase in maintainability, reducing the mean time to
restoration (MTTR), and consequently in an increase of availability. On the other side, non-optimal performances in
terms of size reductions, costs, and complexity must be expected.
The least flagged option, with the 36.4% of flags, is the development of many different DSAS solutions in order to fit
the different type of substations. This solution surely provides the benefit of a greater efficiency in terms of size
reduction and costs, as the design is often tailored for the specific substation. The disadvantage is that multiple
varieties of DSAS project make the maintenance process more complex: many training courses, many skills to
develop, many spare parts to store. This could result in a decrease of availability, and an increase in operation and
maintenance costs. These extra-costs could be accepted if the purchasing cost of the tailored solutions is significantly
less than the purchasing cost of a standard DSAS for the entire owned substation.
Furthermore, correlating the answers A-7 and A-5, it is noted that the 14 respondents flagging the first option
(standard project solution) prefer mostly (13 out of 14) to define the technical specification on their own. Of these 13,
10 require some customization or integration from the vendors and do not purchase turnkey or off the shelf DSAS.
8 out of the 13 are mainly transmission utilities, 5 are mainly distribution, but 4 of these 5 own both distribution and
transmission substations.
Based on these figures, it is possible to point out that most of the transmission utilities adopt standard
project solutions, produce their own specifications, do not purchase turnkey or off the shelf products, but
require some kind of customization to DSAS by the vendors, paying attention to the reduction of ownership
costs.
4.8 Dependability management and company organization
Question A-8 was focused on the dependability management adopted by both utilities and manufacturers.
Almost all manufacturers have an organizational unit involved in dependability management (only 1 vendor declared
that they do not have it) whereas more than one third of utilities declared that they do not have a dedicated unit.
Based on utilities’ and vendors’ comments, it is possible to identify 5 types of departments or organizational units
involved in dependability management:
• Technical department: this department is usually the most involved in DSAS dependability.
Depending on the company, it can be named “Telematic”, “Control and Protection”, “Protection and
Control, SCADA and Teleprotection”. Sometimes these departments are also involved in the
maintenance of the assets they deal with;
• SAS department/System and Electronic Department: is involved primarily in DSAS dependability;
• Research and Development: is generally involved in dependability for all company assets;
• Asset management: is generally involved in dependability for all company assets;
• Quality department: is generally involved in dependability for all company assets.
4.9 Conclusions
There was an acceptable number of respondents among utilities and even better among vendors. The utilities that
responded were most often operating in transmission. The vendors that responded were quite often also working as
system integrators.
The utilities were of very diverging size, their number of substation assets differing significantly. Almost all utilities
write and/or use their own technical specifications for purchasing DSAS. Some utilities also use consultants to help
with the specifications.
It is possible to point out a predominant tendency, within the responding utilities, to require
modifications/customization from the vendors, or make in-house integration, to better suit their specific needs. This
is most common for both transmission and distribution utilities managing a large number of substations.

Page 18
Digital technology is today more adopted in transmission power systems than in distribution ones, and the same
trend can be found in the adoption of the IEC 61850 standard. However, with more stringent power quality
requirements and the rising number of distributed generation connections to the grid, the distribution grid scenario is
changing.
Half of the utilities purchase their DSAS only from a “worldwide manufacturer”. Another 25% adopt a double strategy:
“worldwide” and “country local manufacturer”. The remaining 25% is composed of utilities purchasing solutions only
from “countrywide manufacturers”: local countrywide, foreign countrywide or both local and foreign countrywide.
Vendors are more likely to have dedicated dependability management departments than utilities.

Page 19
5 DSAS CONCEPT AND DEFINITION
According to dependability management standard IEC 60300-2 (2004-04) "Part 2: Guidance for dependability
management", the Concept and Definition phase is the life cycle phase during which the need for the product is
established and its objectives are specified. During this phase, the foundation is laid for the product’s dependability
and its life cycle cost implications. Decisions made during this phase have the greatest impact on the product
performance, functions and ownership costs.
During this phase, the users state their DSAS philosophies, requirements and rules for functionality, performance,
capacity and RAMP, which they document in their procurement/design specifications. In this phase, the
manufacturers in turn make their product and design specifications accordingly, trying to meet the market needs as
comprehensively as possible and in a competitive way.
5.1 DSAS RAMP requirements defined by utilities
The utilities were asked in question B – 1 to state which RAMP requirements are defined in either implementation or
maintenance contracts.
The survey answers, reported in Annex A, clearly show that many utilities today do not consider it important to make
significant efforts in specifying detailed requirements for RAMP of DSAS. Nearly 40% of the respondents do not have
any requirements for RAMP, 40% of them mainly specify system wide RAMP requirements and a little over 20%
specifies RAMP only for some specific devices and/or functions.
Since utilities were allowed to flag more than one answer, the following table helps to define a pattern in the
respondents’ choice, showing multiple flag combinations.
Requirements for RAMP in
specifications
N° of flags
responding)
% of
Responding
RAMP are not defined 9 39.1%
System wide (Only) 6 26.1%
Specific devices (Only) 4 17.4%
System wide and Specific Function 2 8.7%
System wide and Specific Device 1 4.3%
Specific Device and Specific
Function
1 4.3%
Specific functions (Only) 0 0.0%
Table 6
The same trend is also shown from the limited number of responses to the table of availability, MTBF and MTTR
values (see the second table of question B-1 in survey report, Annex A). The following summary can be made from
the values given in the table:
• The requirement for availability of the DSAS as a whole ranges from 99 to 99.75%, and for the
different components it ranges from 99.7% up to 99.995%;
• MTBF requirements are more difficult to interpret, as the answers vary a lot:
o for the DSAS as a whole, the MTBF ranges from 8,760 to 50,000 hours;
o for the substation computer as a whole, the MTBF ranges from 4,000 to 8,760 hours;
o for other DSAS components, the MTBF ranges from 4,000 to 8,760 hours or even from 40 to 100 years;
• there were exceptionally few answers about maintainability requirements (MTTR for DSAS as a
whole ranging from 2 hours to 24 hours);
• no required RAMP values were provided for IED and Substation Computer (SC) components (for
example motherboard, power supply, fan, etc..).

Page 20
Based on the broad range of the values given in the answers and the low number of respondents to some of the
questions, it can be inferred that the knowledge of RAMP among many users is very low.
5.2 Means used by utilities to support the fulfilment of RAMP
requirements
Question B - 2 investigated the means adopted by utilities to verify the fulfilment of the requirements from the
manufacturers.
18 out of 24 utilities responded to this question.
Figure 5
Please note that it was possible to flag several options and that 40% of the utilities use two of the methods listed in
Figure 5. The most commonly used method (50%) is to ask the manufacturer for a description of the solution adopted
to fulfil RAMP requirements. A smaller number (22%) of utilities ask the manufacturers to provide DSAS RAMP
calculations, and more than one third (33%) specify stress tests. In particular, the majority of utilities that flagged that
they specify stress test, declared also that they perform stress test on a component/device sample or on a DSAS
prototype during the design and development phase (see par. 6.7). Only 11% (2 respondents) give a technical weight
to the fulfilment of the RAMP requirements in the tender evaluation. In these two cases, the weight factor is very
different: one is only 0.12% and the other 5%.
Finally, 22% do not specify a means to verify the fulfilment of their RAMP requirements at all.
From the survey results, there are no clear indications about standard means to verify the fulfilment of RAMP
requirements. The suggestion could be to specify stress tests in the design and development phase, and to assess
continuously, during the operation phase, if these results are respected.
5.3 Environmental conditions defined in the DSAS specification
Question B - 3 asked about the environmental conditions defined in the DSAS specification.
The definition of Reliability (see Annex B) is referred to “given conditions” that define the normal operating
environment for the system.
0,0%
10,0%
20,0%
30,0%
40,0%
50,0%
60,0%
a_You ask the
vendor for a
description of the
solution adopted to
fulfill RAMP
requirements
b_You ask the
vendor to provide
DSAS RAMP
calculation
c_You specify DSAS
stress test
d_In the tender
evaluation, you give
a technical weight to
the documentation
that demonstrates
the fulfillment of the
RAMP requirements.
RAMP not
specified/fulfilment
not required
How the utilities promote the fulfilment of RAMP
Requirements

Page 21
Environmental conditions that utilities often define in their DSAS specifications are listed, based on survey answers,
from higher to lower number of flags:
• station power supply (design and quality, 96%) ;
• temperature (87%);
• EMC (83%);
• humidity (61%).
Many respondents also define some requirements for mechanical stress tests (for example vibration, anti-seismic
conditions). On the other hand, only 30% of the respondents specify protection against rodent attack: maybe this is
due to the fact that specific requirements to avoid rodent access to DSAS are referred to infrastructures that host
them. Also “anti-seismic requirements” (26.1%) and “Mechanical (for example vibrations) during transport” (21.7%)
are specified in few cases.
5.4 Maintainability requirements defined by utilities
Question B - 4 concerned what is specified about maintainability of the DSAS in the technical specification (or in the
maintenance contract).
Utilities do usually define DSAS maintainability either in their DSAS technical specifications or in their maintenance
contract specifications. The majority of respondents define requirements for:
• DSAS documentation (79.2%);
• remote accessibility to the system devices and parts (75.0%);
• criteria of independence of parts, in order to allow taking them out of service without any impact on
the rest of the system (70.8%);
• spare parts strategy (70.8%).
Approximately half of the respondents require:
• the availability of a system configuration tool easy to use by the utility (54.2%);
• quality assurance for firmware and software development, testing and maintenance (54.2);
• physical accessibility features to the system (for example to the cubicles) (50.0%);
• DSAS configurability, and re-configurability along the whole life cycle, by the utility (50.0%);
• security rules for remote accessibility (45.8%);
A strategy for DSAS extension is defined by 42%, a repairing strategy by 37.5%, and DSAS upgrading only by 25%
of the respondents.
It can be concluded from the answers given that during the concept and definition phase, utilities consider some
means to improve DSAS maintainability, but improvements are possible to achieve the optimal maintainability
specifications. For example, issues like repair strategy, time to intervention in case of different kinds of DSAS faults,
and fault descriptions with priority have been mentioned by few utilities (ranging from 37.5% to 16.7%). 8.3% of the
respondents declare to not specify anything about DSAS maintainability.
5.5 Function dependability
In question B – 5 of the survey, Utilities were asked to assign a level of importance of different DSAS functions
dependability.
Considering RAMP, and according to the utilities experiences, some functions prove to be more important than
others. This can influence the selected DSAS architecture, in order to improve the dependability of the DSAS and
the specific functions.
The values show that the most relevant functions of a DSAS change, depending whether the weighting factor is used
or not. The difference may be explained by noticing that DSAS installed in medium and low voltage level grids are
more than 4 times the quantity of those installed in HV grids. Accordingly, it can be deduced that the relevance values

Page 22
in the third column of Table 7 mostly depict the point of view of distribution companies whereas the relevance values
in the second column are more in line with transmission utilities opinions.
Functions
Dependability relevance
(mean values on 23
responding, 1 not
responding)
Dependability
relevance (weighted
average values) (*)
Substation level protection 4.4 4.3
Bay level protection 4.3 4.3
Remote operation of substation 4.1 4.7
Substation alarms, signals, measurements, status 4.0 4.6
Substation level operation 4.0 4.3
Bay level operation 3.8 4.1
Power system monitoring (for example fault location,
SOE, disturbance recorder)
3.7 4.3
Process level operation 3.7 4.0
Substation control (for example interlocking) 3.7 3.8
Time synchronization 3.6 4.4
Access Control 3.3 3.6
DSAS monitoring and diagnostic 3.3 3.8
Remote access to DSAS for maintenance 3.0 2.0
Remote access to DSAS for configuration and setting 2.3 1.4
(*) Average value of dependability relevance weighted on the number of owned DSAS declared by the utilities in the A-3 question.
The procedure for calculating the average is the following:
• the value of dependability relevance given by each utility is multiplied by the number of DSAS owned by the respondent utility;
• all the 23 results of the multiplications are summed, and the sum is divided by the total number of DSAS (the sum of DSAS
owned by the 23 responding utilities).
Table 7
In order to deeper investigate differences between transmission and distribution utilities perception of relevancy of
DSAS functions on dependability, a further distinction has been made in the following table: the weighted values
reported in the previous table are now summarized by TSOs and DSOs.
Functions
Mainly transmission
(weighted values)
Mainly distribution
(weighted values)
Bay level protection 4.6 4.2
Substation level protection 4.4 4.2
Power system monitoring (for example fault location, SOE,
disturbance recorder)
4.1 4.4
Remote operation of substation 4.1 4.9
Time synchronization 4.0 4.5
Substation level operation 3.9 4.4
Substation alarms, signals, measurements, status 3.8 4.7
Bay level operation 3.7 4.2
Substation control (for example interlocking) 3.4 3.9
Remote access to DSAS for maintenance 3.3 1.6
Access Control 3.3 3.7
DSAS monitoring and diagnostic 2.8 4.0

Page 23
Process level operation 2.3 4.4
Remote access to DSAS for configuration and setting 2.3 1.2
Table 8
For transmission utilities, dependability of protection is, as expected, considered the most important function, followed
by monitoring as well as remote and local substation level operation. A feature becoming more and more essential
with digital technology, time synchronization, is already considered quite important. The dependability of maintenance
related modern techniques, like DSAS monitoring and remote access systems, were considered less important,
surprisingly together with process level operation.
For distribution utilities, the dependability of remote operation, alarms, signals, measurements and status indications
are considered the most important issues. These are followed closely by time synchronization, process and
substation level operation, as well as monitoring issues. The main similarities with transmission utilities are on the
issues considered less important, like maintenance and remote access means. From the survey results, it seems
that, for distribution utilities, protection functions are neither the most nor the least important.
A very low level of importance has been noticed for “Substation control” by both transmission and distribution utilities.
Some interesting comments from the respondents:
• The priority of substation control is affected by the fact that there can be several operation locations.
Usually, nowadays the remote operation from the Control Centre via SCADA system is the main
operation location. At substation level, there are options to operate switchgear via the operator's
workstation HMI or with pushbuttons at bay control units or at the operating mechanisms of the
switches or breakers at the process level (in the switchgear);
• Power system monitoring functions like fault location, SOE, disturbance recording are expected to
be more efficiently implemented;
• DSAS monitoring and diagnostics are not considered critical but helpful.
With reference to this last function, it can be assumed that, due to the increasing complexity and aging of the DSAS
solutions, these functions will tend to become more important.
5.6 Where RAMP requirements come from
Question B – 6 referred to where the RAMP requirements (both theoretical/quantitative and practical/experience
based/qualitative) come from.
Origin of RAMP requirements N° of flags
% of
responding
Feedback from the operation & maintenance process 19 86.4%
International standards (Please specify): 10 45.5%
Consultant suggestions 7 31.8%
Other (Please specify): 3 13.6%
Research & Development Department 2 9.1%
Table 9
The respondents RAMP requirements, both theoretical / quantitative (figures) and practical / experience based /
qualitative (for example redundancy, hot stand by), are mainly based on the feedback from the operation &
maintenance process (86%). Almost half of the utilities also refer to international standards like IEC 61850-3, IEC
60870-4, IEC 60255 and IEC 60300 (45.5%). One third gets RAMP requirement suggestions from consultants
(31.8%). A few utilities get them from departments for R&D or Quality of Service.
Because the feedback from the operation and maintenance process is an important source for technical specification,
it is suggested to periodically review this practice between operation and engineering departments in order to improve

Page 24
the consistency with the DSAS concept and definition process within the company. This is much more important
when new DSAS families are deployed.
5.7 How utilities define cyber security requirements
Digital technology implies cyber security issues that could affect, potentially significantly, DSAS performances.
Answers to question B – 7 explain which strategy is used for the specification of the DSAS cyber security
requirements.
The cyber security strategy is most often specified by the utility on its own (60.9%). Less than half of the utilities
require manufacturers to propose solutions (43.5%) and only a few of them commit the definition of solutions to third
parties (17.4%). The awareness of cyber security importance is today very high among utilities, as all respondents,
except one, specify some cyber security requirements.
Own solutions often comprise login/password policy (local and remote access) and local firewall for substations.
Some respondents also mention type tests to confirm firewall rules, and disabling unused communication ports.
Some mention IT department policies and architectures that require cyber security according to national or
international standards (ICE/ISO 177999, NZSIT 400, FIPS PUB 199, NERC CIP). One utility mentions legislative
requirements as basis for its cyber security requirements.
Cyber security is a new and growing issue for utilities that are deploying high bandwidth communication networks to
promote remote maintenance and monitoring in order to be more efficient. This issue may reduce the expected effect
of this deployment. It is crucial for utilities to gain new skills in order to define accurate cyber security requirements
from the beginning of the DSAS specification, to allow the safe use of remote maintenance.
5.8 Conclusions and suggestions
Based on the analysis of the survey answers given, the following guidelines for DSAS concept and definition phase
can be set up:
• the broad range of the values given in the answers and the low number of respondents to some of
the questions asking for RAMP figures, can be probably interpreted as a broad variance in the
knowledge of RAMP among users; therefore, it could be valuable for many users to improve their
knowledge level of RAMP;
• from the survey results there are no clear indications about standard means to prove the fulfilment
of RAMP requirements. The suggestion could be to specify stress tests in design and development
phase and to verify continuously, during the operation phase, if these results are respected, possibly
by improving the feedback process;
• environmental conditions are generally specified by the majority of utilities, except for protection
against rodent attacks or anti-seismic and mechanical vibrations requirements during transport or
normal operation. It can be noticed that temperature specifications may grow in importance with
limitations of the use of cooling systems due to the need to reduce environmental impact;
• during the concept and definition phase, utilities consider some means to improve DSAS
maintainability, but improvements are only possible to achieve with an overall view on the DSAS
lifecycle. For example issues like repair strategy, time to intervention in case of different kinds of
DSAS faults and fault classification according to a priority level, should be considered with a higher
level of importance;
• digital technology introduced new issues such as time synchronisation and remote access for
monitoring but they do not modify the dependability ranking of “core” functions such as protection
and remote operation. Probably in the near future the growing need for operation efficiency will give
more importance to remote access dependability that is now underrated;
• it is to be noted that availability and reliability calculations are done by different departments in
different utilities, and that the calculations are more generic for a concept than for the specific
products. Therefore, detailed fault statistics will play an important role in the analysis of the DSAS
assets;

Page 25
• utilities need to pay more attention to the whole DSAS life cycle, considering DSAS maintainability
not only during the operation phase, but also as early as in the technical specification by including
specific requirements for it (reference to B-4);
• because the feedback from the operation and maintenance process is an important source for
technical specification, it is suggested to periodically review this practice between operation and
engineering departments in order to improve the consistency with the DSAS concept and definition
process within the company. This is much more important when new DSAS families are deployed;
• it is suggested for utilities to provide means to promote the fulfilment of RAMP requirements, for
example by the inclusion in tender evaluations of specific parameters related to RAMP values to be
declared by the vendors for both DSAS components and for the whole system;
• cyber security should be included in the primary requirements in order to allow systems maintenance
from remote.

Page 26
6 DESIGN AND DEVELOPMENT
According to dependability management standard IEC 60300-2 (2004-04) "Part 2: Guidance for dependability
management", the design and development phase is the life cycle phase during which the system architecture,
hardware and/or software are created. The relevant product information is captured and documented to facilitate
subsequent hardware manufacturing and assembly, software coding and replication, and system integration.
For a utility/end user of a DSAS project, actions should be planned during the design and development phase to
ensure:
• the adequacy of the dependability design specifications;
• the completeness of design verification and validation prior to design release;
• the suitability of the maintenance support strategy throughout the whole product lifecycle.
For a DSAS system or equipment manufacturer, actions during the design and development phase include:
• RAMP requirement specification;
• hardware and software specification;
• definition of quality and certification procedures;
• definition of compliance testing.
6.1 General design strategies to guarantee higher DSAS reliability
Question C-1 asked both utilities and vendors whether their general design strategy to guarantee higher DSAS RAMP
during its whole lifecycle is based on:
• a sophisticated project (based on redundancy and detailed information);
• a simple project (based on a minimum amount of devices);
• other principles.
The option “sophisticated DSAS project” was selected by 61.8% of respondents. The option “basic (simple) solution”
was selected by 17.6% of respondents. This significant difference between the two options was found both among
utilities and among vendors.
Vendors gave a little bit more weight to the third option “other”, adding some specific indication, such as:
• design rules;
• component selection guidelines;
• validation routines.
However, these last three factors seem to be more related to the product design than to the system design.
Some additional comments provided by utilities mentioned a “Keep It Simple” approach and the necessity of including
some critical components/functions/equipment, that are resistant to common mode failure, in the specification.
Other comments, still from utilities, show a trend to prefer solutions already successfully proven, rather than simply
defining RAMP requirements in their procurement/design specifications.
6.2 Reasons for different DSAS architectures
In question C – 2, it was requested to indicate the reasons for adopting (by utilities) and proposing (by vendors)
different DSAS architectures, it was also requested to give each reason a level of importance considering 5 the
highest level and 1 the lowest.
Results of the survey are shown in Table 10 below.

Page 27
Reasons for adopting/proposing different DSAS
architectures
Total
(34 responding, 2
non responding)
Utilities
(22 responding, 2
non responding)
Vendors
(12
responding, 0
non
responding)
N° of
flags
%
N° of
flags
%
N° of
flags
%
Voltage level (EHV, HV, MV) 30 88.2% 19 86.4% 11 91.7%
Substation size (number of bays) 23 67.6% 13 59.1% 10 83.3%
Availability of room in the substation (for example room
constraints, no room limits)
9 26.5% 5 22.7% 4 33.3%
Substation topology (single busbar, double busbar, ring bus) 15 44.1% 10 45.5% 5 41.7%
Application of the substation within the power system (e.g
transmission, distribution, collector of dispersed generation,
HVDC converter, switching)
21 61.8% 12 54.5% 9 75.0%
Switchgear Insulation technique (AIS, GIS, Hybrid) 10 29.4% 4 18.2% 6 50.0%
Purchasing cost reduction 21 61.8% 12 54.5% 9 75.0%
RAMP optimization (for example vs. cost, vs. substation
importance)
19 55.9% 9 40.9% 10 83.3%
Other: Integration with legacy systems 1 2.9% 1 4.5% 0 0.0%
Table 10
Level of importance for adopting/proposing different DSAS architectures
Level of Importance (*)
Total Utilities Vendors
Voltage level (EHV, HV, MV) 4.4 4.2 4.5
Substation size (number of bays) 3.5 3.5 3.5
Availability of room in the substation (for example room constraints, no room limits) 2.6 2.1 3.0
Substation topology (single busbar, double busbar, ring bus) 3.2 3.0 3.4
Application of the substation within the power system (e.g transmission, distribution,
collector of dispersed generation, HVDC converter, switching)
3.9 4.1 3.6
Switchgear Insulation technique (AIS, GIS, Hybrid) 3.0 3.0 3.0
Purchasing cost reduction 3.3 2.8 3.8
RAMP optimization (for example vs. cost, vs. substation importance) 3.5 3.5 3.5
Other (**): Integration with legacy systems 5.0
(*) Mean values.
(**) This is not a mean value because it has been added by only one respondent.
Table 11
By combining the information about the reasons for adopting/proposing different DSAS architectures together with
the importance assigned to each reason, we can conclude that:
• the most common reason is the voltage level, that is mentioned by 88.2% of the respondents with a
level of importance of 4.4 out of 5;
• the second reason is the substation size (number of bays), that is mentioned by 67.6% of the
respondents; however, it appears to be less important (3.5) than the: “application of the substation
within the power system” (3.9).
Regarding the opportunity for purchasing cost reduction, vendors and utilities indicated a different approach:
• for vendors this is a relevant reason for adopting different architectures (75%; level of importance 3.8);
• for utilities this reason has a lower level of importance (54.5%; level of importance 2.8).
RAMP optimization is mentioned by 55.9% of total respondents, but interestingly vendors who mentioned it (83.3%)
are twice as many as utility respondents (40.9%). An equal level of importance (3.5 out of 5) is given to RAMP
optimization by both utility and vendor respondents, showing that it is a major consideration in the DSAS selection.

Page 28
Utilities answers show that RAMP optimization has still higher importance than the cost; this is probably related to
the criticality of the electrical power system.
6.3 DSAS architecture and distribution of functions
Question C – 3 of the survey aimed to establish trends in RAMP by investigating where the protection, control and
monitoring functions are located in the DSAS.
The options provided by the questionnaire for the allocation of each function were:
• Centralized at the substation level;
• Centralized per voltage level;
• Distributed at bay level;
• Distributed at process level (near to the switchgear).
In Figure 6 below, it is shown where the functions are located. The main findings are:
• Bay protection is mostly distributed at bay level. Although some distribution utilities allocate bay
protection function at voltage level. In some cases the bay protection is allocated at the process
level;
• Busbar protection is typically concentrated per voltage level. Further analysis of vendors’ answers
shows that busbar protection is mostly distributed at bay level. Some distribution and transmission
utilities distribute the function at the bay level, some other at the process level;
• Both utilities and vendors reported that control functions are split between substation level and bay
level. A further analysis shows that control functions are mostly distributed at bay level by
transmission utilities whereas distribution utilities prefer to allocate them at the substation level;
• HMI functions are reported as mostly at the substation level. Some vendors also report HMI functions
at the bay level – this probably refers to protection and control IEDs with integrated HMI display;
• Monitoring is predominantly reported at bay level, but also quite highly at substation level. Vendors
considered this more at bay level, compared with utilities reporting more at station level.
Figure 6 - DSAS Architecture
8,3%
13,9%
58,3%
91,7%
55,6%
8,3%
58,3%
13,9%
8,3%
5,6%
80,6%
38,9%
61,1%
41,7%
72,2%
16,7%
8,3%
16,7%
2,8%
16,7%
Bay protection Busbar protection Control (operation,
interlocking)
HMI Monitoring (primary
equipment, event and
fault data)
Overview of DSAS architecture
Centralized at Station Level Centralized per Each Voltage Level
Distributed at Bay Level Near to Switchgear

Page 29
6.4 Functional integration
Question C - 4 was intended to provide a snapshot of the common practices about functional integration at DSAS
device level adopted by respondents. Vendors and utilities were asked to state whether they include protection,
control and monitoring functions, or any combination of them, in a single device with or without redundancy, or if they
prefer to use separate devices for each function.
Table 12 shows that:
• The most flagged option by all respondents to have in the same device is Control and Monitoring.
• The most flagged option to have in separate devices is Protection and Control.
• The most flagged option to have in a device with redundancy is Protection and Monitoring.
Transmission utilities prefer to separate protection and control functions, whereas vendors are more in favour of
combining protection and control in the same device. There are more details on the responses to this question in the
Appendix, but since multiple choice was allowed, there are difficulties in interpretation of the answers. For example,
when referring to “protection and control functions” integration, respondents who ticked the option “in the same
device” may have also flagged “device with redundancy”, and those who ticked the option “in separate device”, may
have done the same.
Protection remains considered as the primary function, if compared to the other functions. Probably this depends on
the background of the majority of the people involved in this survey and, more generally, on the background of the
people managing DSAS in the utilities.
Function
integration
Respondents
(24 utilities, 12 vendors
responding. 0 not
responding)
In the same device
In separate
devices
Device with
redundancy
N° of
flags
% of
respondi
ng
N° of
flags
% Of
Respo
nding
N° of
flags
% Of
respondi
ng
Protection +
Control +
Monitoring
Totals 16 44.4% 20 55.6% 10 27.8%
Utilities 9 37.5% 12 50.0% 6 25.0%
Vendors 7 58.3% 8 66.7% 4 33.3%
Protection
+Control
Totals 12 33.3% 23 63.9% 10 27.8%
Utilities 3 12.5% 15 62.5% 5 20.8%
Vendors 9 75.0% 8 66.7% 5 41.7%
Protection +
Monitoring
Totals 17 47.2% 14 38.9% 15 41.7%
Utilities 11 45.8% 6 25.0% 10 41.7%
Vendors 6 50.0% 8 66.7% 5 41.7%
Control +
Monitoring
Totals 22 61.1% 8 22.2% 5 13.9%
Utilities 14 58.3% 2 8.3% 1 4.2%
Vendors 8 66.7% 6 50.0% 4 33.3%
Table 12

Page 30
(*) C,M and P refers to different functions: C=Control, M=Monitoring, P=Protection.
Figure 7
6.5 Design strategy to deliver higher reliability of products
Question C-5 was aimed at vendors, to find out their general design strategy to deliver higher reliability in their
products. However, many utilities (14) actually answered this question.
All responding vendor selected the following factors:
• selection of component suppliers;
• testing during the system development phases;
• adoption of quality control system (for example ISO 9000).
Additionally, most vendors also selected:
• investment in Research and Development;
• use of high grade electronic components;
• feedback from customer’s operation experience.
It is probably not surprising that vendors selected these factors, but it should be comforting to utilities that feedback
from customer’s experience is widely recognised as valuable for enhancement of design quality.
The most flagged selection by utilities is “Limitation of the number of vendors in order not to have too many solutions”.
This option is actually more related to a general utility strategy than to a design strategy, so it should have been
0% 10% 20% 30% 40% 50% 60% 70% 80%
P+C+M SAME DEVICE
P+C+M SAME DEVICE, WITH REDUNDANCY
P+C+M SAME DEVICE, WITHOUT REDUNDANCY
P, C, M SEPARATE DEVICE
P,C,M SEPARATE DEVICE WITH REDUNDANCY
P,C,M SEPARATE DEVICE WITHOUT REDUNDANCY
P+C SAME DEVICE
P+C SAME DEVICE, WITH REDUNDANCY
P+C SAME DEVICE, WITHOUT REDUNDANCY
P, C SEPARATE DEVICE
P,C SEPARATE DEVICE WITH REDUNDANCY
P,C SEPARATE DEVICE WITHOUT REDUNDANCY
P+M SAME DEVICE
P+M SAME DEVICE, WITH REDUNDANCY
P+M SAME DEVICE, WITHOUT REDUNDANCY
P, M SEPARATE DEVICE
P,M SEPARATE DEVICE WITH REDUNDANCY
P,M SEPARATE DEVICE WITHOUT REDUNDANCY
C+M SAME DEVICE
C+M SAME DEVICE, WITH REDUNDANCY
C+M SAME DEVICE, WITHOUT REDUNDANCY
C,M SEPARATE DEVICE
C,M SEPARATE DEVICE WITH REDUNDANCY
C,M SEPARATE DEVICE WITHOUT REDUNDANCY
VENDOR MAINLY TRANSMISSION MAINLY DISTRIBUTION

Page 31
asked in another part of the survey. Still its meaning is clear: it indicates the value given in the minimization of the
differences and in the standardization. We noticed that this option was not flagged by any vendors.
Utilities support the vendors’ opinion that “Testing during the system development phase” is important.
Vendors state that training is one of the key factors for the improvement of RAMP. Training is a key factor in every
phase, but in the specific case of the product design strategy, it is important to minimize errors in the early
development stage.
6.6 Design solutions adopted to improve the RAMP of DSAS
Question C-6 was principally oriented to vendors and its goal was to find out the specific design solutions adopted in
order to improve the RAMP of their DSAS. However, many utilities (20) answered this question.
Figures in Table 13 and Figure 8 below show the answers of vendors, utilities, and both together. Items are listed
from the most flagged to the least. Percentages are referred to the total numbers of respondent vendors or utilities.
Items
Total (31
responding, 5
not responding)
Utilities (19
responding, 5
not responding)
Vendors (12
responding, 0 not
responding)
Backup power supply (for example batteries, diesel generators) 90.3% 94.7% 83.3%
System self-supervision and monitoring 87.1% 94.7% 75.0%
Redundancy of protection devices 83.9% 94.7% 66.7%
Watchdog 83.9% 73.7% 100.0%
Redundancy of communication between IEDs (ring topology or double
star)
80.6% 73.7% 91.7%
Standardization of devices used and design solutions 80.6% 78.9% 83.3%
Redundancy of system power supply 74.2% 78.9% 66.7%
Redundancy of Ethernet switches 71.0% 57.9% 91.7%
Hot standby of components (for example station computers) 71.0% 57.9% 91.7%
Automatic restart (after a temporary loss of supply) 71.0% 57.9% 91.7%
Redundancy of station computer 67.7% 52.6% 91.7%
Clear documentation 67.7% 63.2% 75.0%
Clear indications (for example nameplates) for rapid identifications of
components
64.5% 57.9% 75.0%
Data retransmission 54.8% 47.4% 66.7%
Components’ automatic self-test 54.8% 52.6% 58.3%
Redundancy of communication links with different physical paths 48.4% 42.1% 58.3%
Generation of alarms and automatic calls to a maintenance centre 48.4% 36.8% 66.7%
Provision of easily accessible testing points (for example test
marshalling)
45.2% 36.8% 58.3%
Redundancy of internal power supply of switch 41.9% 36.8% 50.0%
Redundancy of HMI work station 38.7% 36.8% 41.7%
Redundancy of control devices 35.5% 36.8% 33.3%
Automatic failure detection and resolution (self-healing systems) 32.3% 26.3% 41.7%
Environmental coating of boards 29.0% 10.5% 58.3%
Other (Please specify): 6.5% 5.3% 8.3%
Table 13
The principle of components redundancy is relevant to improving the DSAS reliability and availability because,
obviously, the probability of having a failure in a parallel system (all parallel components in a state of fault at the same

Page 32
time) is lower than the probability of having a failure in a single component. Nevertheless redundancy is considered
by vendors and utilities more or less important depending on the specific function/device.
For vendors, redundancy of station computers, Ethernet switches and communication between IEDs is on the top,
while redundancy of control devices, HMI workstation and internal power supply of the switches is considered less
important.
Utilities consider protection devices to be the most critical component to be redundant, while redundancy of station
computers, Ethernet switches and communication links are located at a lower level of importance. Redundancy of
the protection functions is often a mandatory requirement due to regulation of the electrical sector.
The differences between vendors and utilities are probably due to the different focus of the respondents: vendors
concentrate on DSAS as a system, whilst the utilities are more focused on the impact of the DSAS on the whole
power system.
Vendors and utilities seem to agree on a lower need for redundancy of control devices, HMI workstation and internal
power supply of switches.
The high percentage by vendors for “Hot standby of components” reveals that this is one of the most used methods
to implement redundancy and confirms that redundancy is often proposed by vendors.
With reference to the power supply, the presence of a backup power supply (for example generator) is considered
by both vendors and utilities more important than the redundancy of the system power supply (for example, double
line feeder from distribution). Probably this is related to the cost of the full duplication of a power supply system and
to the risk, in case of blackout, of a loss of power even if the power system is redundant.
Referring to Ethernet switches, the figures also show that the redundancy of the whole device is preferred to the
redundancy of the internal power supply.
Maintainability, mostly depending on elements like “documentation” and “clear indication for rapid identification of
components” is not in the highest positions, but it is more important than the redundancy of some of the above
mentioned components.
“Watchdog” (100%) and “automatic restart” (91.70%) are technical solutions selected by almost all the vendors to
improve the availability of digital devices (because they help in reducing the time of restoration).
“Automatic failure detection and resolution” is a solution rarely adopted by either vendors or utilities. Probably this is
due to the high cost and to the limited presence of these kinds of functions in the market of DSAS.
Finally, vendors (83.3%) and utilities (78.9%) agree about the importance of standardization of devices and design
solutions, in order to improve interoperability and efficiency throughout the whole DSAS lifecycle and, as a
consequence, the DSAS RAMP.

Page 33
Figure 8
6.7 How utilities verify the fulfilment of RAMP requirements
Question C-7 asked the utilities to declare how they verify the fulfilment of RAMP requirements of vendors during the
design and development phase. Although the question was intended for utilities, 2 vendors responded, probably
giving their experience with customers.
Most of the utilities (58.3%) selected the option “stress test on a component/device sample or on a DSAS prototype”.
The second highest option was “check of the test made by the vendor” (50%).
It is interesting to notice that many utilities declared that they perform stress test during design and development
phase, by including this request in their specification (see section 5.2).
6.8 Features of IEC 61850 not yet exploited enough
Question C – 8 asked both utilities and vendors to state if there is any feature of the IEC 61850 model that needs to
be better developed and/or used in order to increase DSAS RAMP.
Vendors and utilities agree on the fact that interoperability between IEDs manufactured by different vendors has not
yet been exploited enough (top of the list for both vendors and utilities).
The use of process bus is at the top of the list for vendors and quite important for utilities too.
The availability of vendor independent system configuration tools is also considered very important by the utilities,
but less important for vendors.
The possibility to integrate new components in an operating DSAS, without scheduling an outage, is another
opportunity to be investigated.
0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100%
Other (Please specify):
Environmental coating of boards
Automatic failure detection and resolution (self healing systems)
Redundancy of control devices
Redundancy of HMI work station
Redundancy of internal power supply of switch
Provision of easily accessible testing points (e.g. test marshalling)
Redundancy of communication links with different physical paths
Generation of alarms and automatic calls to a maintenance centre
Data retransmission
Components’ automatic self test
Clear indications (e.g. nameplates) for rapid identifications of components
Redundancy of station computer
Clear documentation
Redundancy of Ethernet switches
Hot standby of components (e.g. station computers)
Automatic restart (after a temporary loss of supply)
Redundancy of system power supply
Redundancy of communication between IEDs (ring topology or double star)
Standardization of devices used and design solutions
Redundancy of protection devices
Watchdog
System self supervision and monitoring
Backup power supply (e.g. batteries, diesel generators)
Vendors Utilities Total

Page 34
On the other side, the use of GOOSE messages seems to be already consolidated and accepted by most of the
utilities and vendors.
6.9 Conclusions and suggestions
Utilities answers show that RAMP optimization has even higher importance than the cost: this is probably related to
the criticality of the electrical power system. Consequently, sophisticated projects are widely preferred over basic
system solutions; moreover, for utilities the request for the development of different system architectures is more
related to technical considerations rather than to a cost evaluation.
Quite a different trend emerges by comparing transmission and distribution utilities answers, especially when they
are questioned about the functional integration and the distribution of functions among the substation levels.
Integration of different functions into the same device is in general mainly accepted by distribution utilities and vendors
(over 40% of distribution utilities adopt devices that integrate all of protection, control and monitoring), whereas it is
still not common among transmission utilities (less than 10%). Important functions like control and interlocking are
mainly located at bay level in HV substations, while the majority of distribution utilities declared that they concentrate
these tasks at substation level.
Looking at the answers given by utilities, it is clear that protection is considered as the primary function, compared
to the other functions like control and monitoring. Probably this depends on the background of the majority of the
people involved in this survey and, more generally, on the background of the people managing DSAS inside the
utilities. Other reasons for the importance given to protection devices are that transmission utilities deal with the
impact of a fault on the electric power system and the related costs, for example damage to the primary equipment,
penalties due to power loss or power quality degradation.
Considering reasons for adopting different DSAS architectures, utilities and vendors agreed that voltage level is the
most significant factor, followed by the substation size. An equal level of importance is given to RAMP optimization
by both utility and vendor respondents, although it is mentioned by more vendors than utilities.
Redundancy of protection devices has been selected by utilities as the key factor to achieve a high level of DSAS
reliability, with the aim of avoiding misoperations in case of a single point of failure. Redundancy of the protection
functions can also be a mandatory requirement of the energy regulator. On the contrary, vendors’ opinions reveal a
“whole system oriented” approach in the design solutions adopted to increase RAMP.
All responding vendors agreed on the “selection of component suppliers”, “testing during the system development
phases” and “adoption of quality control system (for example ISO 9000)” as important factors for the improvement of
RAMP.
Testing is currently considered by both vendors and utilities to be the most effective way to verify the compliance of
a single product or of a system to the expected level of reliability. Almost 60% of utilities stated they perform stress
tests on prototypes, while half of them check on the tests made by vendors. On the other side, vendors selected
“testing during the system development phase” as one of the most common strategies to deliver high reliability
products.
One point that was not included in the questionnaire, related to improvement of DSAS RAMP, is design to minimise
misoperations due to operator human error, both for configuration and operation phases. This consideration is
already common practice in the design of DSAS.
Although the use of GOOSE messages seems to be already established and accepted, vendors and utilities agree
on the fact that interoperability between IEDs manufactured by different vendors is not yet exploited enough (top of
the list for both vendors and utilities).
Interoperability seems to play a significant role in the company strategy definition; this can also be deduced from
section 6.5, where most of the utilities mentioned “Limiting the number of vendors” as the top strategy for RAMP
optimization: the limitation of the number of vendors is an advantage, if referred to the reduction of cases and spare
parts and to the simplification of the documentation and training, but it is a drawback from the point of view of the
cost, being against the competitivity both for the purchasing of new systems and for the modification of the existing
ones: interoperability is the way to get all the mentioned advantages without any drawback.
The availability of vendor independent system configuration tools for IEC 61850 is also considered very important by
the utilities, The process bus opens a new approach in the DSAS architectures and the substation layout. The use
of process bus is at the top of the list of features not yet exploited enough for vendors, and utilities are interested too,
but at the moment process bus implementations are mostly limited to some pilot substations.
The possibility to integrate new components in an operating DSAS, without scheduling an outage, is another
opportunity to be investigated.

Page 35
When DSAS is applied to a substation, it is important to avoid system unavailability due to a single point of failure.
This is very important and should be carefully considered in order to ensure dependability of operation for the
substation. Some of the relevant factors are redundancy of power supplies, redundancy of station computers,
redundancy of Ethernet switches and communication links (communication topology). However, too much emphasis
on redundancy may cause complexity in system configuration and result in an increase in costs.
From the answers, we can notice that there is a tendency to refer to the past experience, related to
electromechanical/static SAS, as a reference RAMP level to be exceeded by means of new technologies.
System self-supervision and monitoring scored highly as a means to improve RAMP. Some vendors develop systems
and IEDs with built in test routines that facilitate the commissioning and testing, and with built in self-diagnostics that
allow quick failure detection, thus improving reliability and dependability.

Page 36
7 MANUFACTURING
According to dependability management standard IEC 60300-2 (2004-04) “Part 2: Guidance for dependability
management”, the manufacturing phase is “the life cycle phase during which the product is produced, the software
is replicated, and the system components are assembled”.
In this chapter, manufacturing refers to the whole DSAS and to all its specific components.
The quick evolution of digital technology and the changes in the customer requirements make the manufacturing
phase very critical.
There is a different perception of the meaning of this phase between vendors and utilities:
• Vendors look at the whole period during which a component is produced (for example 15 years);
• Utilities look at the period of duration of a contract that usually covers the realization of different
substations (for example 1 to 5 years).
The manufacturing phase can include issues related to:
• product modification due to fixing of a problem found, for example, in an earlier project;
• evolution of the product portfolio of the vendor;
• software evolution;
• update of circuit diagrams and other documents;
• evolution of the customer requirements (new functionalities, new functions, ....)
This part of the survey consisted of three questions:
• two were mainly oriented to vendors, asking how RAMP affects the manufacturing process taking
into account the feedback they receive from the utilities/end customers;
• one was mainly oriented to utilities/end users asking whether they use a prototype/pilot system to
validate the RAMP of the system.
7.1 Level of detail of RAMP requirements
The aim of question D -1 was to acquire information from vendors whether utilities/end users require RAMP
parameters either directly or in another way.
Vendors state that customers directly request RAMP parameters and figures for:
• IEDs or their components (100%);
• whole DSAS (70%);
• functions (protection, remote control) (40%).
Percentages showed above suggest that many respondents flagged more than one option. The seven different
combinations that respondents could choose and the number of flags recorded are listed in Table 14.
Item
N° of flag
(10 responding, 2
not responding)
DSAS as a whole 0
Related to specific IEDs or components 2
Related to functions 0
DSAS as a whole & Related to specific IEDs or components 4

EXPERIENCE CONCERNING AVAILABILITY AND RELIABILITY OF DIGITAL SUBSTATION AUTOMATION SYSTEMS

EXPERIENCE CONCERNING AVAILABILITY AND RELIABILITY OF DIGITAL SUBSTATION AUTOMATION SYSTEMS

Recommended

Recommended

More Related Content

What's hot

What's hot (20)

Similar to EXPERIENCE CONCERNING AVAILABILITY AND RELIABILITY OF DIGITAL SUBSTATION AUTOMATION SYSTEMS

Similar to EXPERIENCE CONCERNING AVAILABILITY AND RELIABILITY OF DIGITAL SUBSTATION AUTOMATION SYSTEMS (20)

More from Power System Operation

More from Power System Operation (20)

Recently uploaded

Recently uploaded (20)

EXPERIENCE CONCERNING AVAILABILITY AND RELIABILITY OF DIGITAL SUBSTATION AUTOMATION SYSTEMS