Benchmarking Benchmarking

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Benchmarking
of island System
Line Worker Certification
Training & Qualification Standards for lineworkers
Energy
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P. O. Box CP5907, Desir Avenue, San Souci, Castries, St. Lucia, W.I
Tel: ++ ( 758 )-452-0140/1 Fax: ++ ( 758 )-458-0142/458-0702
Email: [email protected] www.carilec.com
Industry Journal 1
Editorial
T
he issues of climate
change, energy security,
energy poverty, and volatile
energy prices are propelling
a paradigm shift in the energy
sector that will dispel inept
energy thinking, and usher in
the new energy revolution.
This inevitable change will
impact significantly the current
business model of Electric
Utilities in the Caribbean.
Energy has the potential to
contribute significantly to the
integration and growth of the
regional economies. In fact,
the history of development identifies an efficient energy system
as a prerequisite for socio-economic development and growth.
The region’s dependence on electric energy for efficient business
operations is considerable, especially in the tourism industry which
is a major driver of economic growth in the Caribbean.
However, such development cannot be sustainable without changes
in the current energy framework, and in the extent or the nature
of the existing energy flows. The policy makers, regulators, Electric
Utilities, and consumers must confront this issue with the aim of
ensuring that the region realises a secure and sustainable energy
future. To achieve this, their mandate must be to promote energy
efficiency and conservation; to maximise economic use of low- and
zero-carbon emitting generation, and to make electricity available,
accessible, affordable and reliable so as to benefit the environment,
the economy and society.
There must be a concerted effort to move beyond the identification
and investigation of alternative or renewable energy sources, towards
the deployment of renewable energy technologies and systems
for electricity generation. However, the creation of an enabling
environment, which includes appropriate policies, adequate
investments and meaningful incentives, is critical to the success
of such initiatives. The recently concluded Caribbean Renewable
Energy Forum (CREF) is testimony to the international and local
communities’ efforts at countering the apparent lack of investments
in alternative clean energy technologies in the Caribbean.
CARILEC will continue to work with its member utilities who
recognize the fact that a bright future cannot be based on cheap
unlimited fossil fuel. The Secretariat will promote among its
member utilities, changes that are aimed at reducing the region’s
carbon footprint, enhancing efficiency in operations, improving
productivity, and the overall sustainability of the Caribbean Electric
Utilities
Andrew Thorington, Editor
Project Manager, CARILEC
Contents
4
Benchmarking of Island System
12 Communication Networks:
The Enablers of utility
Automation Success
18 Electric Power Systems
Integration: The Case of
Aqualectra Utility Grid System
and CUOC/ISLA Refinery Grid
System
26 Energy Conservation: Own Use
Reduction at Electric Utilities
33 Electricity Grid Modernisation:
Domlec Makes the Smart Choice
with AMI
36 Training & Qualification Standards
for Lineworkers
40 Optimising The Value of
Off-Grid Durable Power
Generation
CARILEC Industry Journal
is published in January & July annually by
Advertising & Marketing Services Ltd for
CARILEC the Caribbean Electricity Utility
Services Corporation
Editorial & Distribution : CARILEC
P. O. Box CP5907, Desir Avenue, San Souci,
Castries, St. Lucia, W.I
Tel: ++ ( 758 )-452-0140/1
Fax: ++ ( 758 )-458-0142/458-0702
Website: www.carilec.org
Editor : Andrew Thorington,
Project Manager, CARILEC
[email protected]
Advertising Sales, Design & Production:
Advertising & Marketing Services Ltd,
P. O. Box 2003, Gros Islet, St. Lucia, W. I.
Tel: 1 (758) 453 1149
Fax: 1 (758) 453 1290
Email: [email protected]
Industry Journal 3
BENCHMARKING OF
ISLAND SYSTEMS
USA
Caribbean
By: Roel Verlaan, KEMA Inc
Figure 1: Average Energy Costs 2007 in the Caribbean versus the USA
For having the right answers to these
questions, benchmarking information
showing performance indicators and
yearly trends, can be very valuable,
particularly if the information is appropriately analyzed. One can make
use of performance indicators of island
1.
systems and mainland systems in order
to identify where island systems are
really behind and to what extend better performing island systems can get
closer to mainland systems.
For example in the next figure already
more information appears and if your
utility has the lowest cost per kWh
in the peer group of island systems,
the distance with mainland systems,
particularly the mainland systems with
highest cost, is already much smaller.
It could be identified where the frontiers of excellence for island systems
Why benchmarking?
Benchmarking is commonly used in
the power sector worldwide as a tool
to identify where the electric utilities
stand compared with each other. Not
only the electric utilities themselves
feel the need for benchmarking in order
to find out where they stand, but also
Regulators are making use of benchmark studies, looking at technical,
financial/economical, organizational
and commercial performance indicators. This way Regulators are able to
determine the relative efficiency and
the performance of the electric utilities.
The benchmarking information is used
by these authorities for setting rates and
performance targets. The fact that Regulators are using results of Benchmark
Studies for these purposes is as such
already an important reason for electric
utilities to perform Benchmark Studies.
This way the electric utilities are able to
keep up with the Regulator by making
use of the benchmarking information
for analyzing the utilities’ technical
and financial performance in order to
be prepared for discussions with the
Regulator on issues like rate setting and
performance targets.
While Benchmark Studies have been
performed for some decades already
in the different continents and in many
mainland countries, benchmarking of
island systems only took off some 10
years ago. CARILEC was one of the first
organizations that started a Benchmark
Study for island systems in the year
2002. Some years later this initiative
was followed by NESIS in Europe, an
organization founded by the European
association of electric utilities Eurelec
tric, which focuses on the particular
issues of small and isolated island
systems.
Industry Journal 4
Because isolated island systems do
not have interconnections with other
systems, the island utilities have to keep
up higher reserves margins in order to
keep up a reasonable level of reliability
and at the same time they don’t have
the benefits of economy of scale like in
the mainland countries. Furthermore
costs of fuel are higher, also because of
higher transportation costs. For these
reasons the kWh rates in small islands
are much higher than in mainland
countries. Stakeholders, like hotel owners and commercial businesses, have
their concerns about the high rates
which are much higher than for example in Florida, or the UK. How can
an island utility explain that their cost
per kWh is more than four times higher
than the average cost per kWh in the
USA? And what about the SAIDI and
SAIFI figures on reliability, which are
quite better in the USA and in Europe?
Figure 2: Average and Highest/Lowest Energy Costs Caribbean versus USA
can be found. It can also be identified
where the electric utilities stand compared with each other and with mainland systems in different fields of their
activities, such as Generation, T&D,
and commercialization. It can be concluded, for example, that small island
systems are indeed behind mainland
systems and large island systems in
the field of Generation, but in T&D the
island utilities can compete with mainland systems as benchmarking results
have shown. T&D costs (US$/MWh)
are in some Caribbean islands lower
than in large energy-intensive cities like
Paris, Tokyo, Hong Kong.
Industry Journal 5
Finally it can be mentioned that
with all data and performance
indicators as gathered through the
years not only trend analyses can
be made but also analyses on the
interrelationships between performance indicators, which will be
illustrated in section 3.
Relative efficiencies
In order to get a more realistic comparison of the diverse utilities’ efficiencies
multi-dimensional benchmarking methodologies have been developed, using
multiple inputs and outputs, in order to
mitigate the “apples and oranges”-effect
and to come to comparisons of rela-
Major answers that are given by
electric utilities to the question
“Why Benchmarking” are listed
below:
• Without Benchmarking the electric utility is not able to keep up with the Regulator who is using benchmarking information for setting regulatory requirements.
• Benchmarking Information is needed • Where do we stand compared with for Regulation
other island utilities?
• Regulation is needed as a surrogate
• What is our level of performance and
for competition or to enable efficiency?
competition in generation, while
• What weak points do we have?
T&D remains a monopoly to be • Does the Regulator make use of the regulated
right Benchmarking Information • The best strategy for the electric when setting rates and performance utility is to Stay Ahead of the targets?
Regulator
• Without Benchmarking an electric utility is not aware of its levels of 2.
Methodologies
performance, its efficiency, its strong and its weak points.
Different Benchmarking Methodologies
• Worldwide we see that Electric Utili- can be used such as uni-dimensional
ties, Governments and Regulators benchmarking, just comparing unique
are using Benchmark Studies as technical, financial/economical,
a major tool for setting rates and organizational and commercial figures
performance targets
or more advanced technologies with
which the relative efficiency and
performance can be compared, making
use of multiple parameters in order to
take differences in account such as for
example different sizes and customer
demands of companies and differing
geographical and demographical
parameters.
Benchmarking has the danger of comparing apples and oranges. Obviously
one could think of this when comparing
for example small island systems with
only light fuel (diesel) fired generation
units and other islands with HFO fired
generation units or even coal and/or
LNG power plants in the larger islands.
When making comparisons one should
be aware of these distinctions, although
these islands can still be compared on a
more equal basis when it comes to nongeneration performance indicators.
Typical uni-dimensional performance
indicators which are commonly used
are, among others:
tive efficiencies of the island utilities.
In principle the relative efficiency of for
example a mountainous and relatively
poor island, may not really be lower
than the relative efficiency of a flat and
wealthy island with loads concentrated
in areas close to the power plant. Such
determinations of relative efficiency
could be reached by for example the
Figure 4: Score of relative inefficiencies
Figure 4 shows the efficiency score of
5 electric utilities with utility C having
the highest relative efficiency. The other
utilities can identify their relative inefficiencies and can start analyzing which
areas in their organization and systems
need improvement. For the analysis the
performance indicators of uni-dimensional benchmarking can be very valuable particularly when comparing with
islands with similar characteristics.
Figure 5 shows the outcome of a CAPEX
versus OPEX study and the dots in this
study are representing the positions of
the participating utilities. As a result
of this analysis the blue line turned
out to be the frontier of excellence for
this peer group. Further analysis on a
number of the participants however
showed that the true frontier should
be the black line. This illustrates that a
Benchmark Study is never perfect and
depends on data provided and (un)
availability of data.
With this analysis it can be seen that for
example a utility with high operational
expenditures has low capital expen-
Figure 3: Performance Indicators Carilec Benchmark Study
Industry Journal 6
Data Envelopment Analysis (DEA),
which is one of the multi-dimensional
benchmarking methodologies that has
become popular among electric utilities
and regulators worldwide. For both
parties it is of importance to determine
the utilities’ relative efficiencies with a
methodology like DEA when it comes
to a realistic setting of efficiency targets.
Industry Journal 7
ditures. Given the high operational
expenditures it would be worthwhile to
investigate how these expenditures can
be reduced by investing in new, more
efficient equipment. The effect will be
that the position of this utility in the
graph will move up (higher CAPEX) and
to the left (lower OPEX) but as a total
result this will not imply that the utility
will get closer to the frontier of efficiency. Here it is recommended to link the
analysis to asset management principles
with which costs are balanced against
performance and risks of the system’s
assets.
System Energy Losses:
Figure 6: Example of Benchmarking Results for System Losses
The red bars show the system energy
losses of Utility “X” through the years
2002 – 2007, the green bars show the
average of the system energy losses of
the other utilities in the peer group,
while the blue bars show the system
energy losses for the latest year (2007)
of each individual participant.
In one view it can be seen that Utility
“X” has a downward trend of system
energy losses through the years, the
same can be said for the Caribbean average and furthermore one can see that
utility “X” is performing quite good,
below the average, but there are still
some 5 utilities performing even better.
Also one can see that there are some
utilities with a high percentage of losses
(utilities M, N and O) with one utility
even peaking over 20%.
Average Energy Costs:
Figure 5: Efficiency analysis CAPEX versus OPEX
3. Benchmarking of Caribbean Island Systems
The uni-dimensional study shows big
differences between the islands like
maximum loads varying from 13 to
over 1000 MW, quite different load
densities and different figures for consumption per customer. These and other
differences require cautiousness when
making comparisons between island
utilities.
Still the study shows a rather uniform
performance explained by the similarities of technologies used and by the
physical environment where the utilities
carry out their business. The utilities
present basically the same characteristics between 2002 and 2007 in their
service areas, structure and ownership,
legal and regulatory framework and
market composition.
The cost structure of the utilities is
basically the same with fuel costs and
operation & maintenance as the dominant costs, and with fuel costs highly
increasing through these years until
the 3rd quarter of 2008, when the fuel
prices went down due to the economic
crisis.
information is better collected and recorded when a Regulator has imposed
performance targets and standards
Regulation has been developed up to a
quite mature level in only a few Caribbean States. Development of Regulatory
Frameworks (Rate Setting, Performance
Standards) is however coming up on
the horizon of many islands. Initiatives
have been started to set up a Regulatory
Agency for the OECS Member States in
order to share costs as well as experience in these small islands which have
rather similar characteristics.
In certain areas information is not readily available at some utilities, such as
information on:
- non-technical losses
Some examples of performance indi- non-served energy
- service interruptions and interruption cators as used in the uni-dimensional
benchmark study are given below. Figdurations
ures are not representing real figures of
any utilities but are made up (although
In general it shows that such typical
close to the real figures).
journal 8
Industry Journal
Figure 7: Example of Benchmarking Results for Average Energy Costs
A trend analysis shows that utility “X”
had lower costs per MWh than the
average costs in the years 2002 – 2006,
but in 2007 costs per MWh became
higher than the Caribbean average.
It could first be investigated whether
some of the participants in the peer
group show improvement during the
past years (less increase than others, maybe even no increase). Then it
Industry Journal 9
should be analyzed by what cost components the average energy costs
have really increased (higher
operational costs? Higher fuel
costs because more LFO
out of benchmarking results, once a
‘dashboard’ like this becomes available.
For sure Regulators, Utility Managers,
Shareholders and Consumers will all
look from different points of view at the
information as presented this way.
had to be used instead of HFO? Higher
capital costs? Higher overhead costs? A
combination of cost increases?). Subsequently measures should be developed
for getting these costs below the Caribbean average again.
In order to see all performance indicators in a bird-eye view a spider diagram
can be developed, showing all performance indicators compared with the
Caribbean average:
The spider diagram has been config-
4. Final Remarks
In the Caribbean a majority of the
electric utilities has already joined the
CARILEC Benchmark Study, which
is updated every year. For member
utilities a web site has in the meantime
been created where they have access to all data of Benchmark Studies
as performed since 2002. Charts and
graphs can be produced in many different ways, with the possibility of selecting all or certain years, all or certain
indicators and all or certain participants
only. Furthermore anonymous versions
can be produced or versions with all
participants anonymous and only the
own utility name shown. All reports as
published through the years are also
downloadable.
This way better and instant access to
all benchmarking information has now
been made available 24 hours per day.
It would be encouraged if CARILEC
would be able to extend the peer group
by also including European islands
via the organization NESIS as already
mentioned and by including islands in
the Pacific Ocean via the Pacific Power
Association.
A next step would be the introduction
of the Data Envelopment Analysis with
which the relative productivity and
efficiency of the participants can be
determined.
From the perspective of the electric utilities these efforts and the advanced analytical methodologies are primarily very
helpful for analyzing their performance,
Figure 8: Spider Diagram showing all Performance Indicators of Utility “X” compared with the average of all
other participating utilities.
ured in such a way that the red circle is
going along the averages of all individual indicators. Indicators that give
values of over 100% (outside the red
circle) are better than the average and
indicators under 100% (within the red
circle) show a lower performance than
the average.
This utility “X” has quite some indicators that show a better performance.
Productivity is high, generation and fuel
costs are better than the average, losses
are below the average. Looking at the
rates one can see that domestic rates
are better than the average, but commercial and industrial rates are higher
than the average (less rate performance,
under 100%), which indicates that
there is apparently a policy in place for
applying social rates for households.
Furthermore performance is below
the average on T&D costs, SAIFI and
Generation Reserves Margin. Finally
one can see that the Operational Profit
Margin and the Return on Assets are
better than the average.
From a consumer side one could think
of reducing rates by reducing the
Profit Margin and the ROA, the GenIndustry Journal 10
eral Manager should maybe focus on
the Generation Reserves Margin and
possible investments in the near future
that will change the different indicators. At the same time he would like to
find out why T&D costs are high with
at the same time a high T&D labor
productivity. Environmentalists may
think that given the positive overall
score they may be financial possibilities
for applying renewable energy solutions that may have higher costs but
could be funded by reducing the profit
margin. These are just some examples
of considerations that can be derived
Industry Journal 11
identification of weak points and preparation of improvement plans, but also
for having well documented analyses in
place when it comes to discussions and
negotiations with Stakeholders and with
the Regulator in particular.
References:
Ajodhia Virendra, Petrov Konstantin,
Scarsi, Gian Carlo (2003): Benchmarking and its Applications, Zeitschrift
für Energiewirtschaft 27 (2003) 4,
p. 261 – 274.
Verlaan, Roel (2008): Energy Efficiency
of Small Island Systems, PPA Magazine, Pacific Power Association, Fiji,
October 2008, Volume 16/3, p. 15-17.
Efficiency Score
Communications Networks:
The Enablers of Utility Automation Success
In most cases, the future state cannot be
achieved without adding new enterprise and/or operational applications.
Utilities tend to identify AMI, mobile
workforce management, SCADA,
distribution automation, IP communications to substations and district offices,
and upgrades to their mobile voice
system as the application improvements
needed to support their overall utility
strategic plan.
When operational applications that
have proven positive business cases are
identified, the next step is to develop a
technology roadmap that outlines the
implementation of the utility strategic
plan. The technology roadmap identi-
mobile communication planning while
looking at the “bigger picture” of all of
their application needs. This is “developing a Strategic Communications
Plan”. The key driver of this change in
philosophy is the realization by smart
grid planners that their success centers
on the future need for a backbone network to enable dozens of applications,
including all fixed and mobile data applications. The figure below illustrates
this concept.
needed. The price has steadily
declined and the features/
capabilities have improved.
Typical range is 15 to 25 miles.
This system requires path and
line of sight. There is very little
risk for spectrum interference.
Price point per path for all cost
involved is close to $100,000.
Fiber Optic Communications
Proprietary spread spectrum
products generally come with at
least 4 way-side circuit-switched
T-1s and 10 to 45 Mbps of Ether-
fies which technologies are going to be
implemented at the utility over a given
3-5 year period.
Once the technology roadmap is complete, a strategic communications plan
can follow. The communications plan
focuses on how the different technology
applications identified in the technology roadmap will interoperate. It should
identify if a private communications
backbone infrastructure can be justified
versus using a commercial carrier.
mission utilities. Most utilities would
put in fiber nearly everywhere if costs
were not an issue. Fiber is immune to
ground potential rise and EMI. Reliability for fiber depends on the architectural
design.
Fiber is most often viewed as the very
best communications media for trans-
Point to Point Microwave:
2.4 GHz and 5.8 GHz
By: Charles Plummer
The common denominator for
successful deployment of utility
automation applications such as
Distribution Automation (DA),
advanced metering infrastructure
(AMI), mobile computing (mobile
data), mobile voice, and other
utility applications is a well
developed communications plan and
infrastructure. Heavily involved in this
type of planning project is a concept
of deployment called the “Smart Grid”.
This article will provide information
on many of the building blocks that
need to be considered in developing a
strategic communications plan for the
future as well as examples of different
approaches taken by utilities for their
communication infrastructure for their
fixed data and mobile voice and data
applications.
Planning for the Smart Grid
The Smart Grid has been a popular
subject over the last few years. A
smart grid leverages existing assets
and applications. Technology ranges
from AMI, OMS, GIS, to SCADA, new
electric distribution, and “smarter
databases”. The Smart Grid is not a
purchased product, but a concept of
deployment for a range of technology
systems.
Discussion of the subject ranges from
AMI, DR, feeder automation, and
advanced grid optimization. The smart
grid advances the level of intelligence
in a utility’s operation to include
not only traditional “grid” aspects of
the field, but also enterprise systems
and processes such as CIS, work
management, rates, and other future
applications.
tion that was implemented. Typically,
utilities have different departments purchasing systems and applications. The
operations department would purchase
mobile voice (land mobile radios),
SCADA and, possibly, mobile data
products, the engineering department
would purchase the software applicaThe common themes of any smart
tion suites for downloading recloser
grid design include:
data from the field, and the billing
department would focus on receiving
• The need for automatic collection meter data from the customers. Unforof data from multiple applications tunately, a coordinated effort between
throughout the utility network. While utility departments would not often
the smartest grids will include end-
occur. This approach creates silos in
user premises, this is not a prerequi
the organization, meaning that each
site for a smarter grid.
functional group has its own isolated
information storage area.
• The need for adaptive integrated Shifting the utility culture from a funccommunication mediums that can tional or “silo” organization to a shared
handle data from multiple applica
data infrastructure is the first step in
tions located throughout the utility implementing a smart grid. This step is
infrastructure.
probably the most challenging. However, it is the key to leveraging both the
• The need for integration of appli
infrastructure and operational data.
cation software suites so they share collected data in common dynamic Developing a Strategic
databases.
Communications Plan
Need for Communications
Infrastructure
An integrated communications infrastructure starts with a strategic desire,
shared by all functional stakeholders.
In the past, utilities tended to develop a
unique infrastructure for each applicaIndustry Journal 12
The utility stakeholders should document the current state of the utility, the
future state goal and then create a gap
analysis that outlines the missing components between the current state and
the future state goal. The gap analysis
will help define areas that need change
to achieve the future state.
Communication Infrastructure
Many utilities now approach their
Point to Point Microwave: 6, 11,
and 18 GHz
Proprietary licensed radio technology
products generally come with at least
8 wayside circuit- switched T-1s and
50 to 155 Mbps of Ethernet bandwidth.
The wayside T-1s can be consolidated
into Ethernet to increase bandwidth if
Industry Journal 13
net bandwidth. The wayside T-1s
can be consolidated into Ethernet
to increase bandwidth if needed.
These products were not common five years ago. The price has
steadily declined and the features/capabilities have improved.
The actual radio cost is around
$8,000. Typical range is 15 to
20 miles. This system requires
path and line of sight. There is
some risk for spectrum “overuse”
interference issues at 2.4 GHz
in urban areas. This has become
a very common communications media for utility backbone
networks.
SCADA, AMI, DA, and Tower Nodes
Communication Requirements for
Utility Automation and Substations
Communication requirements at tower
sites are dependent on how many field
locations and applications will feed
into the tower site. Distribution substations have become regional nodes for
a variety of utility automation applications including:
• SCADA
• AMI via PLC or nodes for fixed wireless concentrators
• Direct connect via Ethernet into substation IEDs
• Video monitoring
• Concentration points for down-line DA
• Hot spots for mobile data
Smart Grid designs can offer dramatically enhanced monitoring, control,
and processes affecting reliability,
power quality, and the aging grid. It can
allow an integrated approach to prevention, rapid diagnosis, and restoration
of power outages via weaving together
multiple applications (e.g. AMI, OMS,
GIS, AVL, SCADA, DA, etc.) and programs (e.g. transformer management,
voltage monitoring/modeling, etc.).
Advanced Meter Infrastructure
(AMI)
AMI infrastructure has become one of
the main drivers for the Smart Grid ap-
proach to monitoring the utility system.
AMI is a system that gathers data on
client consumption and transmits that
information back to the utility on a
systematic basis. Classical AMI systems
utilize 15-minute interval metering data is sent back every 15 minutes once
per hour. Classical load management
includes water heaters and air conditioners as the top two applications.
What is changing, however, is that load
management is migrating to be run over
the AMI network versus a private load
management network. New Critical
Peak Pricing (CPP) systems include
connections into an In-Home Energy
Use Display (IHD) in order to monitor
usage. Most utilities that have deployed
two-way AMI technology in the last few
years have done so with the intention of
deploying many programs beyond basic
Reduce
Costs
Improve Customer
Service
Capturing individual load contribution
during system peak conditions
X
X
X
Evaluate transformer loading
X
X
X
Developing load shapes for customer classes
Voltage monitoring
X
X
Identifying system blinks & power quality
X
X
Monitor system conditions during load xfrs
X
X
Track phase changes and phase verification
X
Critical Peak Pricing (CPP)
Productivity
Improvement
make cellular a long term risky WAN
choice for AMI.
meter reading.
AMI Backhaul WAN Options
Mobile Data Communications
Large amounts of data pass between
gateways and the master station most
often located in a utility’s office. Media
used for WAN communications typically use longer-range, high-power radios
or Ethernet IP-based solutions. Some
private options are 900 MHz spread
spectrum point-to-multipoint, 2.4 GHz
spread spectrum (mesh and point-tomultipoint), 3.65 GHz WiMAX, BPL,
and fiber optics. Public options include
DSL or other Telco lines, and cellular.
Many utilities choose cellular to
provide a WAN for their AMI systems.
Cellular is a “quick and easy” WAN
solution. Disadvantages of cellular include monthly recurring charge – usually about $45 USD per month per take
out point. If the utility has 100 takeout
points, this equates to $54,000 per year.
This is about $800,000 dollars over
15 years, not taking into consideration
escalation factors. Cellular is typically
not preferred for mission critical applications. With the dawn of the “Smart
Grid” many AMI functions are now
considered mission critical. This may
Mobile data has become a very hot
trend in the utility industry over the
last recent years. The scope of data has
ranged from automatic vehicle location
(AVL or GPS) all the way to broadband
communications to the computer terminals located in the trucks. The amount
of bandwidth needed and the size of
the territory dictate the communications medium chosen by the utility.
The bandwidth requirements can be
separated into three groups:
1. Low bandwidth (less than 2400 bps) – The applications that can use this bandwidth are AVL, short data messaging (texts) and band
width conservative mobile work
force management (MWM) tools - service order. In this case the data can be combined with the mobile voice system if there is adequate
capacity.
2. Medium bandwidth (between 2400 bps and 33 kbps) – The
applications that can use this
bandwidth
tend to be larger MWM and some X
The needs of the utility dictate
the cost of implementation of the
mobile data communications.
Mobile Voice Communications
Mobile voice technologies include analog conventional, digital conventional
(P25), analog trunking, digital Trunking (P25), and cellular. PSE has not
seen a trend for commercial cellular to
replace the utility private mobile voice
radio. Trends have shown that current
systems provide private voice radio
coverage gap fill-ins between the vehicle and dispatch, private utility calls
and calls with end-user customers.
However, they cannot be depended
on for tasks with safety ramifications,
Below is a comparison of the main differences between analog trunking systems and digital trunking systems.
Analog Trunking
Digital Trunking
Separate Talk Groups
YES
YES
Status Messaging and AVL
YES
YES
Mobile-to-mobile across the service
territory
YES
YES
YES
YES
Functionality
X
enterprise data. There are several
manufacturers of radio systems
that can provide this service in the 150
– 900 MHz range.
High bandwidth (more than 33 kbps)
– The applications that would use
this bandwidth tend to be completely
connected computer systems with full
internet applications. The systems used
for this bandwidth tend to be 3.65
GHz WiMax or similar or commercial
cellular communications.
DG & Net Metering
X
X
X
Capability to roam to any tower site
and use system with no manual intervention
Reduce theft of service
X
X
X
Caller ID
YES
YES
Distribution Automation (DA)
X
X
Voice mail
YES
YES
Time of Use rates (TOU)
X
X
X
Private calling
YES
YES
Voice mail
YES
YES
Remote disconnect/reconnect
X
X
X
Simultaneous voice and data
NO
YES
Load Management (LM)
X
X
X
Mobile data rate
Industry Journal 14
2.4 kbps
Industry Journal 15
7.2 kbps
group calls or any dispatch related
tasks.
Conclusions
As utilities face the loss of manpower
and degradation of older systems, new
infrastructure can revolutionize how
they gather and use data and information. Although the new technology can
be daunting, putting a Strategic Communications Plan into place will allow
a utility to utilize the best applications
for their needs. Following the plan can
assist with reducing customer costs,
solving a utility’s business challenges,
and realizing value and potential in
their infrastructure. While the learning
curve can be steep, the benefits can be
invaluable as a utility plans their future.
About Power System Engineering
About the Author:
Power System Engineering, Inc. (PSE)
is a full-service, independent consulting firm for electric utilities. Our clients
include distribution cooperatives, generation and transmission cooperatives,
investor-owned utilities, municipal utilities, public utility districts, and industry
associations. The professionals at PSE
include engineers, IT and communication experts, economists, and financial
analysts. The PSE team has extensive
experience in all facets of the utility
industry. PSE is employee-owned and
100% vendor independent, with offices
in Minneapolis, MN; Madison, WI;
Indianapolis, IN; and Marietta, OH.
Charles W. Plummer (Lead Communications Consultant, Madison, WI, USA)
Charles is currently facilitating the
evaluation, procurement and implementation of strategic infrastructure
technologies for PSE utility clients
following smart grid technology roadmaps. Charles has been working in the
electrical utility industry for 15 years in
various communications and application technologies. He has a Bachelor of
Science degree in Electrical Engineering from the University of Wisconsin
– Madison.
Industry Journal 16
Industry Journal 17
Electric Power Systems Integration:
The Case of Aqualectra Utility Grid System
and CUOC/ISLA Refinery Grid System
By: Oswin Martina, Senior Electrical Engineer
Aqualectra, Curaçao
Background
The former Curaçao Utility KAE
(Kompania di Awa i Elektrisidat) had
incorporated in its development plan in
1994 the construction of a new 25 MW
unit (Boiler- Turbine- Generator) at its
Mundu Nobo premises. In order to do
this, the local Utility Company (KAE)
had to obtain the necessary permissions
and financial guarantees from the local
government.
Parallel to this, the power-plant of the
local refinery (the ISLA refinery), owned
by the Local Government and leased
to the Venezuelan PDVSA, was at the
point of being upgraded.
In the discussions regarding the
feasibility of the two projects, the
decision was taken by the Local
Government to build a 90 MW powerplant ( 4* 22.5 MW units) at the refinery
which would deliver 60 MW to the
refinery and the excess (30 MW) of
power to the Utility. The government
selected a Contractor to execute the
project based on a B.O.O. (Build, Own,
and Operate) contract. As part of this
contract, the Utility would obtain an
existing old Middle (Steam) Pressure
Power Plant (M.P.P.P.).
In the years 1999/2000 the former
Power and Water Production Company
(KAE), and KODELA, the former Power
and Water Distribution Company
merged to form the new Company,
Aqualectra.
This paper presents the various aspects
regarding the coupling of two grid
systems (the Utility grid system) and
the Refinery grid system (an Industrial
Plant):
a) The conditions for coupling of the two grid systems
b) The coupling/decoupling criteria
c) The operation experiences
d) Actions taken to improve the operation of the coupled system
e) Future actions to be taken to improve the operations of the
coupled system.
Project Implementation
Because the electrical coupling of an
Industrial plant (the ISLA refinery) with
a Utility (Aqualectra) is technically a
tour de force, a technical specification
that incorporated very clear and
rigorous conditions was written by
Aqualectra to achieve the goal.
The System Power Study
According to the technical
specification, a system power study that
included the following activities and
deliverables was required:
• Load flow analysis ( ISLA 15 kV circuit system within new and
existing generators)
• Stability analysis, Short circuit analysis ( ISLA 15 kV circuit system within new and existing generators)
• Short dynamic investigation, including load-shedding
requirements of ISLA 15 kV loadcenter 1, 2 & 3 (Electrical)
• Mid-term dynamic investigation, including spinning reserve
requirements (Mechanical)
• Protection and system grounding study
• Short circuit analysis ( including Industry Journal 18
stability analysis)
• Recommended interconnections
• Aqualectra system expansion plans to be taken into
consideration
• Basic equipment design
• General control functions
A Consultant was selected to perform
the analytical studies for the integration
of the Aqualectra and BOO/ISLA
systems. The study was divided into two
phases i.e. Phase A and Phase B which
were to be undertaken successively.
and system control and operation
procedures. However, for reasons
unclear to us, the Contractor did not
execute Phase B of the system study
and the interconnection was done
based only on the Phase A study.
Basic Configuration Criteria
The Curaçao BOO/ISLA- Aqualectra
interconnection and generation
expansion does not follow the typical
applied approach for connecting
public utility grids with highly sensitive
industrial complexes such as the ISLA
refinery, where supply interruption will
immediately cause production losses
that are associated with high costs.
The general approach in such cases
takes into account that the supply
reliability of a utility transmission and
distribution system is much lower than
that required for industrial production
(e.g. refinery) with high associated costs
for non-served energy. Consequently,
such industrial systems have their own
generation with a back-up connection
to the public grid being typically
utilized in situations such as generation
or spinning reserve shortages. In
such situations, interconnection to
the public grid is made with high
impedance transformers of limited
capacity- typically equivalent to the
largest generation unit- allowing for the
mitigation of major impacts from faults
that may occur at the transmission
level.
The approach to the implementation
of the integrated BOO/ISLA-Aqualectra
system was different. Here, the
upgraded power-plant is integrated
to the ISLA grid and serves basically
as a major generation and generation
reserve plant. Supply of power to the
Aqualectra grid is only of secondary
importance. This concept has major
implications for the possible connection
and future expansion options.
Interconnection Options
Based on the constraints discussed
above the options for electrically
interconnecting the Aqualectra grid
with the BOO/ISLA grid were mainly
defined by contractual agreements.
Phase A
The objectives of the Phase A study
were:
•To check the ability of the
integrated system to cope with
common practice design criteria in
terms of active and reactive powerflow, short-circuit capability and
voltage sags.
•To identify components which are
at their limits with respect to the
control range or load.
•To identify all ISLA and Aqualectra
(Production & Distribution)
components which are at their
limits or overloaded from a shortcircuit stress point of view.
•To identify and rank the possible
interconnection alternatives
according to their main
characteristics.
Phase B
The Phase B study focused on detailed
engineering studies required for the
final interconnection and operation
philosophy, such as protection,
grounding, load-shedding coordination
Industry Journal 19
Based on this, the following four
(4) interconnection options were
presented:
Option 1: 30 kV interconnection
Option 2: 66 kV connection; BOO
at 30 kV and Isla via 15/30 kV
transformer(s) connected to 66 kV
Option 3: 66 kV connection; BOO at
66 kV and Isla 15 kV connected to 66
kV
Option 4: 30 kV connection; BOO
Splitted Bus-bar Operation
Of the four (4) options presented,
Option 2 was chosen by Aqualectra
(see fig.1) i.e.: a 66 kV Substation (S/S)
and the Aqualectra transmission system
are used for the interconnection of
Aqualectra with the BOO/ISLA grid,
two 75 MVA 66/30 kV transformers in
parallel (BOO-I and BOO-II) are used.
ISLA however, is connected via 15/30
kV transformer(s) to the BOO 30 kV.The
Aqualectra grid is divided into three (3)
load centers (Weis, Parera and Nijlweg),
each of them connected to the 66 kV
system. It was also decided that the
ISLA MPPP has to be replaced by a new
Aqualectra diesel powerplant (NDPP)
installed by ISLA.
• Step 5 : 48.6 Hz Aqualectra step 4
• Step 6 : 48.5 Hz Isla Level 1
• Step 7: 48.4 Hz Aqualectra Step 5
• Step 8: 48.2 Hz Aqualectra step 6
• Step 9: 48.0 Hz Aqualectra step 7
• Step 10: 48.0 Hz Isla Level II
• Step 11: 47.5 Hz Isla Level III
• Step 12: 47.5 Hz More Severe than Level III ( Time Delayed)
• Isla’s Gas turbine # 8 and MPPP/
BH10 will remain out of service
• Tripping command to CUOC-
Aqualectra interconnection breaker due to the tripping of one of the CUOC boilers to be disabled
• CUOC will operate their units to maintain 10 MW spinning reserves within the new BOO project to
assure variations of generation
Operation experiences after
making the interconnection
After the effective coupling of the grids
there were some operation experiences
which led both parties to acknowledge
that a further investigation or study with
regard to the operation and decoupling
criteria must be executed.
Delivery of Power to CUOC
without any Decoupling
On January 28, 2004 there was a
trip at the new Aqualectra Isla diesel
power plant (NDPP) (33 MW) followed
by a trip of Dokweg diesels and the
Aqualectra Mundu Nobo thermal
plant unit 10. This resulted in the
activation of the Aqualectra frequency
load-shedding steps 1 and 2 (f = 49.4
and f = 49.1 Hz) and the automatic
export of some 60 MW from CUOC to
Aqualectra, but CUOC did not have
any option of reducing the amount of
power exported to Aqualectra. This was
of grave concern for CUOC and hence,
the search for ways to reduce the power
exported to Aqualectra in such cases
began. This has led later on to the
implementation of the CUOC “Export
Power Controller.”
Activating of three(3) Aqualectra
Load Shedding Steps without
Aqualectra’s interference
On August 18, 2006 there was a trip of
one of CUOC 22.5 MW unit, which has
caused three (3) Aqualectra frequency
load-shedding steps (f = 49.4, 49.1 and
48.8 Hz) to activate before there was a
decoupling of the systems on frequency
at f = 48.7 Hz. (figures 3 and 4 below).
Also the exchange of apparent power
S (MVA), active power P (MW) and
reactive power Q (MVAR) between the
systems can be seen.
Fig. 1 Aqualectra chosen interconnection Option 2
Conclusions of the Phase A study.
Based upon the results of the analytic
studies, which were carried out on the
basis of a detailed computer model, the
following main aspects of the BOO/
ISLA and Aqualectra interconnection
options were summarized:
• The interconnected BOO/ISLA and Aqualecta power generation and supply systems could
successfully be interconnected in
terms of basic load-flow
conditions. Reactive power supply
is sufficient to operate the
transmission system within its
normal operational limit. In terms
of load-flow characteristics, the
30 kV and 66 kV alternative are comparable;
• From the point of view of short- circuit capabilities and limitations,
the 30 kV and 66 kV alternatives
are only feasible if the ISLA/
Aqualectra exchange capacity is
limited to 50 MVA. The best
location for the interconnection
transformer(s) is at the
interconnection point of the two
systems;
• In order to prevent faults that originate at Aqualectra from
interrupting ISLA production,
voltage sags shall be limited to
70 % at ISLA main distribution
levels.
Memorandum of Understanding of
April 2003
The installation of the new BOO
power-plant was completed by the
beginning of 2003 and it was time for
effectuating the grid interconnection
between Aqualectra and Isla. The
original agreement was that both Phase
A and Phase B of the system power
study should be completed before the
effective interconnection of the systems
is executed. Since only the Phase A
Industry Journal 20
study was completed at this time, the
interconnection was done based on
the Memorandum of Understanding
(MOU) of April 11, 2003 with the
technical conditions given below.
The technical conditions of the MOU
were the following:
• The BOO-Aqualectra interconnection breaker will open
at an under-frequency relay setting
of 48.7 Hz
• ISLA’s electrical load-shedding scheme Level 1 shall be set to operate at an under-frequency
of 48.5 Hz
• The integrated electrical load-
shedding scheme will be on a temporary basis as follows:
• Step 1 : 49.4 Hz Aqualectra step 1
• Step 2 : 49.1 Hz Aqualectra step 2
• Step 3 : 48.8 Hz Aqualectra step 3
• Step 4 : 48.7 Open interconnection
breakers between AqualectraBOO/ISLA
Fig. 3: Frequency curve with the activating of three Aqualectra load shedding steps
(f = 49.4, 49.1 and 48.8 Hz) and decoupling of the systems on frequency (f = 48.7 Hz)
Industry Journal 21
Fig 5: CUOC Export Power Controller in order to maintain constant export to
Aqualectra when in parallel operation with island grid
Note
Fig. 4: Power exchange between (fig. 4 ) the coupled systems, apparent power S
(MVA), active power P (MW) and reactive power Q (MVAR) (BOO-I)
The activating of three Aqualectra
frequency load shedding steps without
Aqualectra’s interference, and the
delivery of power to CUOC without
any decoupling were unacceptable to
Aqualectra and as such they began to
look for ways to avoid a recurrence.
Dynamic system study
As there were no decoupling criteria
based on power exchange/voltage
criteria for the coupled systems, and
also based on operation experiences,
Aqualectra, together with a Consultant,
decided to do a dynamic system study
in order to get decoupling criteria
based on the abovementioned points.
The results of this dynamic study:
“Operation and Protection of the
Interconnected Aqualectra, CUOC
and Isla Power System” was presented
by March 2006 with the following
decoupling recommendations:
R1: There shall be no de-coupling in case of faults at Aqualectra side except for out-of- step
conditions. These might be
detected via impedance relays with out-of-step (pole slip) unit installed at Aqualectra/
ISLA interconnection facilities
R2: Aqualectra/ISLA connection shall be disconnected when
Aqualectra is exporting active
power to ISLA. Recommended relay settings were: 5 MW/3s and 15
MW/1s. The relay shall be disabled during network synchronization
R3: In case of sustained low voltage conditions at CUOC/ISLA side (caused by unsuccessful
fault clearing or voltage
instability) CUOC/ISLA link shall be opened via under-voltage conditions as follows: Aqualectra 66 kV voltage below 50% and CUOC voltage below
30% for more than 400 ms and Aqualectra 66 kV below 80%
and CUOC voltage below 75% for more than 1s.
However, the abovementioned
recommendations have not been
implemented because of the need for
special relays which are not ordered
yet. For this reason, Aqualectra has
temporarily activated an existing
Reverse Power Relay in the Aqualectra
66 kV substation, which gives a
Industry Journal 22
decoupling criterion for both feeders
(BOO-I & BOO-II ).
The decoupling settings are:
P = 1.6 MW, t = 0.5 s when active
power P flows from Aqualectra to
CUOC/ISLA (for both feeders BOO-I
and BOO-II). Subsequently, this was
changed to:
BOO-I: P = 0.8 MW, t = 0.5 s and
BOO-II: P = 5.0 MW, t = 0.5 s
Export Power Controller
On the other hand CUOC has effected
the inbuilt “Export Power Controller” at
the four 22.5 MW CUOC units based
on the experience of the incident of
January 28, 2004. (see fig. 5)
The “Export Power Controller” is a
power exchange controller which is a
pure power controller. As a result, such
a controller will try to limit the export
according to the set power exchange
value, regardless of the frequency. In
other words, the power controller will
always “drive” the system frequency
down to finally reach the set power
exchange value and by that in most
cases also the disconnecting point
( f = 48.7 Hz ).
Power exchange controllers are
typically implemented as frequency
directed power controller. The result
would be that in case of frequency
deviations, the power exchange setpoint will be shifted up or down. E.g.
when the system frequency goes down,
the exchange power set-point will be
increased according to a droop setting.
Consequently, as long as the absolute
limit of such exchange power is not
reached, the connected system (CUOC/
ISLA) will help to support the frequency
of the faulty system. This is the typical
method of all interconnected systems.
Consequently, the CUOC Export Power
Controller was activated and began to
gradually reduce the power export to
Aqualectra and simultaneously brought
down the system frequency. Due to the
decreasing of the system frequency,
three (3) Aqualectra frequency loadshedding stages were activated
Operation experiences with
activated Aqualectra Reverse
Power decoupling and the effected
CUOC Export Power Controller
After the implementation of the
Aqualectra Reverse Power decoupling
and CUOC Power Export Controller in
the interconnected systems, there were
several operation incidents, some of
these incidents are:
Activation of three(3) Aqualectra
load-shedding steps
On April 28, 2008 at 12.00.48 hrs.
Aqualectra’s unit-11 tripped with
14.679 MW. The export from CUOC
(BOO-II) to Aqualectra was at that time
P = 15.258 MW and (BOO-I) was out
of service. CUOC’s exported power
(BOO-II) increased from P = 15.258
MW to P = 32.201 MW. (see fig. 6).
Industry Journal 23
(f = 49.4, 49.1 and 48.8 Hz). At last,
the systems were decoupled by the
Aqualectra Reverse Power Decoupling
at P = -7.540 MW as CUOC began to
take active power from Aqualectra.
Aqualectra first frequency
load-shedding stage activated
On August 19, 2008 problems with
a boiler feed pump (BFP) at a CUOC
boiler caused an active power swing
of some 3 MW in the interconnected
systems (Aqualectra/CUOC/ISLA ). This
active power swing caused a decrease
of the system frequency and by that an
activating of the Aqualectra first loadshedding frequency stage (f = 49.4 Hz)
(see fig. 7).
Fig 8: Power and frequency curves at the incident of April 27, 2009
Fig.6: Frequency curve and active power exchange curve
Conclusions/Recommendations
to improve the operation of the
interconnected Aqualectra-CUOC/
ISLA system
Activating of four Aqualectra
frequency load-shedding stages
On Monday April 27, 2009 starting at
13.36.40 hrs there was the initiation
of a total blackout at CUOC/ISLA.
During this period four (4) Aqualectra
frequency load-shedding stages were
activated ( f = 49.4, 49.1, 48.8 and 48.6
Hz). There was decoupling of the two
systems (Aqualectra-CUOC/ISLA) on
frequency at the decoupling frequency
of f = 48.7 Hz ( fig. 8)
With the presented incidents the
conclusion can be drawn that neither
the Aqualectra Reverse Power
Decoupling nor the CUOC/ISLA
“Export Power Controller” is giving a
satisfactory solution for the operation
of the coupled Aqualectra-CUOC/ISLA
systems. In addition, neither Aqualectra
nor CUOC/ISLA is forming an electrical
back-up for the other. Due to this, a
solution must be devised to improve
the operation of the coupled systems.
Here the following recommendations
are given to improve the operation of
the coupled Aqualectra-CUOC/ISLA
systems:
1. Implement the recommendations R1, R2 and R3 of the system study as indicated above
2. Study the possibility of changing the implemented CUOC/ISLA “Export Power Controller” to a “Frequency Directed Power
Exchange Controller”
3. Study the possibility of bringing
down the first Aqualectra frequency load-shedding stage to a lower value e.g. to f = 49.0 Hz instead of the existing f = 49.4 Hz
so as to avoid the activating of the existing Aqualectra first stage load-
shedding stage at CUOC /ISLA
power swings.
4. Execute the phase B study as indicated above.
Fig 7: Activating of Aqualectra first stage loadshedding ( f = 49.4 Hz) due
CUOC active power Swing
Industry Journal 24
Industry Journal 25
REFERENCES
1) Technical Specification BOO Project, KAE N.V, 1998
2) Integrated Network Studies, Analysis of the BOO, Isla KAE and Kodela Interconnection, Phase A Final Report , DIgSILENT GmbH/KEMA N.V, Germany/The Nederlands , December 2000,
3) Operation and Protection of the Interconnected Aqualectra, CUOC and ISLA Power System , Final Report , DIgSILENT, March 2006
4) Graphs recorded by DIgSILENT Power Factory Monitoring (PFM) systems installed at Aqualectra (from 2003 on)
OWN USE REDUCTION
AT ELECTRIC UTILITIES
Prepared by
Fidel Neverson
Planning Engineer (Generation)
St. Vincent Electricity Services Limited (VINLEC)
Introduction
At St. Vincent Electricity Services
Limited (VINLEC), “Own Use” is
defined as all forms of the utility’s
electricity consumption. This would
include electricity use at the various
types of facilities that are utilized
by the Company such as power
plants, substations, office buildings,
warehouses, machine shops, mechanic
shops, remote sites, etc. At VINLEC
“Own Use” electricity is typically
drawn from the electricity grid that
the utility uses to provide power to its
customers.
Own use is a necessary part of
running an electric utility. Like any
other business, an electric utility uses
electricity for the day-to-day operation
of its various facilities and the cost of
this consumption can often represent
a large portion of a utility’s operating
budget. As such, own use management
can be an important aspect of corporate
cost management. Furthermore, own
use reduction can lead to a number of
benefits including reducing corporate
expenditure through energy savings,
reducing pollutant emissions, and
projecting an image of responsible
energy use and concern for the
environment to customers.
Some Approaches for Own Use
Reduction
There are a variety of ways in which
own use reduction can be achieved.
The following are three possible
approaches. Firstly, energy conservation
measures can be implemented that
result in reduced consumption from
lighting, air conditioning, water
heating, office equipment, and
machinery. Secondly, grid-connected
small scale renewable energy systems
such as photovoltaic, wind energy,
and bio energy systems can be used
to provide power for utility facilities
Industry Journal 26
thereby reducing or entirely replacing
the energy that would otherwise have
been drawn from the grid. Thirdly,
Combined Heat and Power (CHP) is an
approach where the waste heat from
generators can be used for building
heating, building air conditioning via
an absorption chiller, or to drive a
steam turbine generator that would
produce electricity for own use. Some
of these approaches are being explored
by VINLEC for its Own Use Reduction
Programme.
The Own Use Reduction
Programme at VINLEC
VINLEC is a state owned electric utility
that is the sole entity responsible for
the generation and distribution of
electricity throughout St. Vincent and
the Grenadines. VINLEC operates 11
power stations on the islands of St.
Vincent, Bequia, Canouan, Mayreau,
and Union Island. Six of the power
stations are diesel stations and 5 are
hydro stations. The company also has
12 office buildings and 5 material
stores buildings.
VINLEC initiated the Own Use
Reduction Programme in late 2007.
The drivers for this programme were:
1. High energy costs – The rapidly rising cost of oil on the international market and the VINLEC’s high dependence on fossil fuels for electricity generation (83% of electricity production was from
diesel generation in 2008,).
2. To prove the value of energy conservation as a low-cost means of reducing energy costs.
3. To project a positive corporate image.
The following are the objectives of
the Own Use Reduction Programme:
1. To investigate and accurately record the amount of electricity consumed at the various VINLEC buildings and facilities.
Industry Journal 27
2. To identify areas where energy consumption could be reduced.
3. To implement cost effective measures to conserve energy.
4. To monitor the results of the conservation measures taken so as to determine the extent of their
impact.
5. To come up with a model for energy conservation in commercial and industrial buildings that could be promoted to customers.
The initial undertaking of the Own Use
Reduction Programme was an energy
conservation pilot project at the Cane
Hall Engineering Complex.
Cane Hall Engineering Complex
Energy Conservation Pilot Project
The Cane Hall Engineering Complex
is a two storey building with a floor
space of 6,000 square feet. It houses
the company’s human resources and
environmental health & safety staff and
some engineering staff. The building has
central air conditioning and fluorescent
fixtures are used for all of the interior
lighting.
This building was chosen for the pilot
project because there were many
known areas of energy wastage where
improvements could be made in order
to conserve energy. These included
lights being left on unnecessarily in
offices and bathrooms, fluorescent light
fixtures using inefficient T12 lamps
and magnetic ballasts, air conditioning
units being left on when no one was
in the building, and computers often
being left on unnecessarily. In addition,
problems with the air conditioning
thermostat resulted in the temperature
on the first floor not being properly
regulated. This often led to overcooling
of the first floor.
The first step in the energy conservation
project was to perform an energy
CARILEC
ENERGY CONSERVATION:
Other lighting improvement initiatives
included replacing the T12 fluorescent
lamps and magnetic ballasts for most
of the interior lighting fixtures with T5
lamps and electronic ballasts. Over 180
T12 lamps and ballasts were replaced.
Also, light switches were installed in
offices that didn’t have any so that the
office users could switch the lights off
whenever they were not needed.
In terms of air conditioning, three
CARILEC
The results of the energy audit were
that the typical workday consumption
for the building was approximately
500 kWh and the typical nonworkday (weekends and public
holidays) was around 200 kWh. Air
conditioning, computer equipment,
and interior lighting were found to be
sources of high energy consumption.
Air conditioning accounted for
approximately 70% of the daily energy
consumption at the building, computer
equipment was responsible for about
16% of the daily consumption, and
interior lighting accounted for around
12%. In addition, the results of the
T5 lamp versus T12 lamp comparison
were that the 28W T5 lamp with an
electronic ballast consumed 40%
less energy than the 40W T12 with
a magnetic ballast. It was therefore
decided that energy conservation
measures that targeted the areas of air
conditioning, computer equipment, and
interior lighting would be focused on
during the pilot project.
The first energy conservation measure
that was implemented was the
installation of motion sensors in the
building’s four bathrooms that would
control the turning on and off of the
bathroom lights. As someone enters a
bathroom the motion sensor picks up
movement in the room and turns the
lights on. The lights remain on for a few
minutes and then the motion sensors
turn them off once movement is no
longer sensed in the room. This meant
that energy would no longer be wasted
as was the case if someone forgot to
turn the lights off when he or she exited
a bathroom.
Industry Journal 28
improvements were made. Firstly,
an electronic timer was installed to
automatically turn on and off the two
central air conditioning units for the
building at the beginning and end
of each work day. This alleviated
the possibility of the units being left
running unnecessarily beyond 5:00
p.m. when most people would have
already left for the day. Secondly, the
room housing the thermostat and
the air handler for the first floor air
conditioning system was found to
be improperly sealed, consequently,
warm air from the outside of the
building was being drawn into the
room. This was causing the thermostat
to see a false reading for the first floor
temperature and therefore not regulate
this temperature properly. The result
was that the first floor air conditioning
unit would run more than necessary
thereby wasting energy. This problem
was rectified by properly sealing the
air handler/thermostat room from
the outside air. Thirdly, sheds were
built over the two air conditioning
compressor units on the outside of the
building in order to shield them from
direct sunlight thereby allowing them
to operate in a more energy efficient
manner.
All of the above-mentioned energy
conservation measures were put in
place between May 2008 and January
2009.
Sheds installed to shield the air conditioning compressors from direct sunlight
One very important aspect of the
Cane Hall Engineering Complex
Energy Conservation Pilot Project was
staff participation in the exercise. In
order to gain the buy-in from the staff
members that work in the building,
two structured sessions were held to
apprise them of the objectives of the
energy efficiency pilot project and to
solicit their cooperation. Staff members
were encouraged to conserve energy by
switching off lights when not needed,
turning off computer screens when not
in use, and shutting down computers at
the end of each day.
The results of the energy conservation
initiatives are shown in Figure 1 below
(Note: No workday consumption
figures are available for January 2008
and February 2008 as reliable meter
readings were not available for those
months). As can be seen the average
workday energy consumption at the
building decreased steadily from July
Industry Journal 29
2008 through February 2009 as the
various energy conservation measures
were put in place. Also, as shown
in Figure 2, when the four month
period of March 2009 to June 2009 is
compared to the same period in 2008
it can be seen that the average workday
consumption for each of the four
months in 2009 is significantly lower
than that for each corresponding month
in 2008.
CARILEC
audit of the building. This included
installing a kWh meter for the building
as there was none prior to the start of
the project and therefore there was no
way of knowing how much energy
was being consumed at the building.
Also, individual electrical circuits in
the building were checked to identify
high load devices and to estimate
the energy consumption of these
devices. In addition, an experiment
was undertaken to compare the energy
consumption of energy saving T5
fluorescent tubes with T12 fluorescent
lamps since T5 lamps were being
considered for replacement of the T12
lamps in the building. This energy audit
was conducted between December
2007 and February 2008.
ber
cem
De
No
vem
ber
er
tob
Oc
ber
Sep
tem
st
Aug
u
July
Jun
e
Ma
y
il
Apr
rch
Ma
y
uar
Feb
r
ary
Jan
u
The average cost of electricity
(including fuel surcharge, demand
charge, and taxes) in USD for
commercial customers over the last 2
years has been approximately $0.40/
kWh. If the Cane Hall Engineering
Complex is categorized as a
commercial customer and assuming
that $0.40/kWh will also be the average
price of electricity in the near term then
the annual projected savings as a result
of the energy conservation measures
would be:
$0.40/kWh x 27,850 kWh =
$11,140.00
The project costs, which mainly
included materials and labour, were
as follows:
1. Lighting improvements – $6,300.00
2. Air conditioning improvements – $3,000.00
Total cost – $9,300.00
As such, the straight payback period
for the project is:
Straight payback period = $9,300/$11,140/year
= 0.83 years
= 10 months
Based on the significant reduction in
energy use and the projected payback
Figure 1 – Average workday energy consumption by month in 2008 and 2009
period of less than one year the Cane
Hall Engineering Complex Energy
Conservation Pilot Project has been
a resounding success. The following
conclusions can be drawn:
1. Measures that target specific low energy efficiency areas in
commercial buildings can yield significant energy savings at relatively low cost.
2. An energy audit during the preliminary stages of the project is
essential for identifying areas where conservation efforts should be
focused.
3. Staff buy-in can be critical to the success of an energy conservation project.
Average Workday Energy Consumption
(kWh)
Average Workday
Reduction (kWh)
%
Reduction
2008
2009
March
448.5
336.7
81.8
18.2
April
490.9
397.1
93.8
19.1
May
536
417.7
118.3
22.1
June
561.4
428.7
132.7
23.6
In terms of projected savings from the
pilot project, when one considers the
entire 4-month period of March 2008
to June 2008 the average workday
energy consumption was 514.3 kWh.
For the four (4) months of March 2009
to June 2009 the average workday
energy consumption was 402.0 kWh.
Therefore, the reduction in the average
workday energy consumption over this
period is 112.3 kWh or 21.8%. Of this
average workday energy reduction of
112.3 kWh the estimated impact of the
various conservation measures is as
follows:
• A/C improvements – savings of 77 kWh/day
• Lighting improvements – savings of 25 kWh/day
• Staff conservation efforts – savings of 10 kWh/day
Industry Journal 30
With an average of 248 work days per
year and assuming that the average
workday energy savings over an entire
year is the same as the 112.3 kWh
determined for the 4 month period
previously considered, then the annual
energy savings would be:
248 days x 112.3 kWh/day = 27,850
kWh
CARILEC
CARILEC
Figure 2 – Comparison of the average workday energy consumption for March to June in
2008 and the same period in 2009
Industry Journal 31
ELECTRICITY GRID
Cane Hall Engineering Complex
Photovoltaic (PV) System Project
Energy Conservation Projects at
Power Stations & Substations
The objective of this project is to install
10 kW PV system in order to reduce the
amount of energy that the Cane Hall
Engineering Complex consumes from
the grid. It is projected that on average
the PV system will produce around 40
kWh of electricity per day. Any energy
that the PV system produces would
result in reducing the amount of energy
imported from the grid by an equivalent
quantity. While the PV system would
not actually reduce own use since
overall building energy consumption
would remain the same, it does replace
energy that is produced by expensive
fossil fuels with less expensive clean
renewable energy.
VINLEC plans to undertake energy
conservation projects at its power
stations and substations during
2009 and 2010. For these projects
the following energy conservation
measures have been proposed:
• Increased use of natural lighting through changes to building roofing material
• Lighting retrofits and use of motion sensor controlled lighting where possible
• Use of waste heat from diesel generators for absorption chiller air conditioning (Lowmans Bay Power Station)
• Encouragement of energy CARILEC
conservation practices
byJournal
staffAd.ai
6/15/2009
members
The projected cost of the PV system
is US $46,000 and straight payback
period would be 7.9 years. This project
should be completed by December
2009.
CARILEC
Corporate Headquarters and Stores
Warehouse Energy Conservation
Project
Similar to the Cane Hall Engineering
Complex Energy Conservation Pilot
Project, the objective of the Corporate
Headquarters and Stores Warehouse
Energy Conservation Project is to
reduce building energy use through
lighting and A/C improvements and
better conservation practices by staff.
These measures are expected to result
in a combined energy consumption
reduction of approximately 10,000
kWh per year. The projected cost is
US $12,000 and the projected straight
payback period is 3 years. This project
should commence in 2010.
C
M
Y
CM
MY
CY
CMY
K
Industry Journal 32
The cost and savings projections
for these projects have not yet been
calculated.
Conclusion
VINLEC plans to use the knowledge
and experience gained from the
Own Use Reduction Programme
to encourage and guide customers
to undertake their own energy
conservation programmes. Such
programmes would help customers
reduce their energy use and energy
costs. This would in turn reduce overall
demand growth and also reduce the
pace at which VINLEC would have to
increase generating capacity in order to
meet demand growth.
MODERNISATION
DOMLEC MAKES THE SMART CHOICE WITH AMI
After a successful pilot
of the Energy Axis
System from April of
2008, DOMLEC decided
to implement a full
deployment of the
system.
11:07:30 AM
The benefits of the system are aimed
firstly at our customers. One of the
key areas is the reduction in outage
restoration time and in estimated bills
since the actual energy consumed will
be recorded by the meter and available
for reading whenever needed.
With the aim of encouraging and
assisting our customers to improve
the management of their energy
usage patterns, DOMLEC will utilise
a web presentment portal to provide
customers with the information that is
needed to make informed consumption
decisions which will lead to substantial
benefits they do not currently enjoy.
In addition, the reduction in overall
operating costs such as meter
readings, and service disconnects and
reconnects, in the long term should
benefit our customers through a
reduction in tariffs
Within the Commercial Department,
employees in the Billing section will
be happy to have such a powerful
meter reading system which will
almost eliminate meter reading errors,
avoid estimated readings, and enable
prompt accurate billing with greater
confidence. Consequently, fewer
customer complaints will be received.
In addition, the system will facilitate
remote connection and disconnection
Industry Journal 33
operations. The efficiency and reliability
of operations within the department
will be enhanced thereby greatly
improving customer service.
The Engineering and Transmission and
and to realise the installation of 27,000
meters. We are presently beginning to
explore the following applications of
our Energy Axis AMI system:
•Time of use (TOU) metering for our
domestic customers which would allow
us to offer them special rates at various
times of the day, DOMLEC is also
exploring different rate structures for
other categories of customers. Presently
Distribution staff have a lot to look
forward to and significant benefits to be
derived from AMI. Our T&D engineers
will be better able to manage and
control the voltage across the entire
network and assist us in keeping more
strictly with the legislated tolerance
level for voltage fluctuation. Instead of
relying on rough estimates, engineers
armed with AMI’s detailed knowledge
of distribution loads and electrical
quality can accurately size equipment
and protection devices, and better
understand the behaviour of the
distribution system.
during the restoration efforts.
Project Status and Future Plans
As of the beginning of the second week
of November, 2009 we have installed
approximately 1200 meters in the
only industrial customers are offered
TOU rates.
•Monthly maximum demand billing for
our commercial, industrial, and hotel
customers as a fair way to replace the
present installed capacity charge
•Prepaid ready system in order to allow
DOMLEC to move customers to and
from prepaid service with ease
•Web presentment of consumption
field and expect to have 3,500 meters
installed before the end of the year, all
in the capital city of Roseau.
The installation phase of the project
is expected to last to the end of 2011
System Planning will have a lot more
data available to them for improved
grid planning and decision making,
for example; demand, load profile and
voltage profiling. There may even be a
case to be made in later years for loss
reduction through energy conservation,
among other uses that may not now be
apparent.
Outage management is another critical
area which will be positively impacted
by AMI. The ability to tell if any of our
customers have lost power and when
they are back online will be a powerful
tool for DOMLEC. This area has been
one of concern particularly during
restoration after a disaster such as a
hurricane in which areas can be missed
Industry Journal 34
Industry Journal 35
patterns to all customers
Conclusion
The possibilities for AMI to
fundamentally change the way we
operate at DOMLEC is clear and we are
positive that it will be a win-win move
for both the company and the customer.
TRAINING & QUALIFICATION
STANDARDS FOR LINEWORKERS
By: Ronald J. Schenk, Executive Director - Institute for Safety in Powerline Construction (ISPC)
T
he lack of standards in the Electric
Utility Industry for Lineman
training and qualification plagues
us when hiring, managing safety or
deciding which work assignments to
give to which employee. Additionally,
after a storm, as outside help comes
in, can these new workers restore our
system, without getting hurt? How do
we know what they are qualified to do?
It is singularly odd, in such a potentially
hazardous occupation, that what
qualifies one to be a Lineman should
be so ambiguous.
How did it get this way?
The U.S. Department of Labour says
there were approximately 112,000
Electrical Powerline Installers and
Repairers (SOC Code 499051) working
in the trade, in 2006. Small numbers
when compared to the millions of
workers out there in the various trades.
The number of Linemen working for
Utilities and Contractors has always
been relatively small. When the pool
of qualified workers is low, wages are
higher. That’s good, if you’re looking
for a high-paying career. But, it’s also
true that when employment levels
are so relatively low, formalities get
overlooked. Linemen have always
tended to ‘fly under the radar’
concerning safety, training, competency
requirements and even OSHA
regulation enforcement. It’s a small
group – who cares if 38 occupational
fatalities occurred in 2006? That’s not
many compared to other trades. So, the
Industry Journal 36
old worn out process of ‘apprenticing’
to an experienced journeyman has
prevailed – nothing formal – just tag
along and pay attention. No standards
of competency or performance. Maybe
the new employee gets lucky and he
learns enough to stay alive and build
on his experience – just minus a couple
of fingers or some minor flash burns to
teach him a lesson. Maybe the next
employee isn’t that lucky and looses
an arm, a leg or his life. And so it has
gone for the past 125 years, since that
first line was energized in the public
domain.
That was then; this is now
What once was acceptable for highvoltage Lineworkers, isn’t any more.
Attitudes are changing and a new
generation of young people entering
the trade actually seeks formal training
and some form of recognition that they
are competent to do the job. Overall,
according to the Centre for Energy
Workforce Development, by 2013 the
Industry may need to replace between
40% and 50% of its aging workforce.
At the same time, growth is expected to
add 13,500 Lineworkers to the current
level, by 2016. Taken together, more
than 50,000 new Lineworkers will
apprentice over the next 6 years. Other
pressures from OSHA, Liability Insurers,
Surety Underwriters, Bankers and even
the public now expect management
to ensure worker safety, increasing
the need for formal and standardized
training.
Over the past ten or fifteen years many
have tried to implement training and
safety programs to comply with the
new expectations for Lineworkers.
Hit and miss can best describe most
of these efforts – though something
has been better than nothing. The
challenge has been to design
programs that adequately train to
the competencies required to be a
high-voltage Lineworker, today. And
everyone thinks they know what those
competencies are. Just ask them. But
in this case, when everyone thinks they
know, no one really knows. When we
have thousands of opinions about what
those true qualifications should be,
we end up with thousands of partially
qualified Linemen. No Standard has
yet been established against which we
can measure. To train someone to be
a Journeyman Lineman you need to
widely agree upon what a Journeyman
Lineman must be qualified to do.
Achieving Industry ‘Consensus
Standards’
The Electric Utility Industry, along
with Powerline Contractors, needs
Lineworker training and qualification
Consensus Standards. Consensus
means what it says: the majority of
us needs to agree upon, and put into
practice what a Lineworker must
know and be able to do, to be called
a Lineman. Here are some important
aspects of a Consensus Standard:
1.It must define ‘Levels of Performance’
2.It must serve the ‘Public Good’
3.It must be ‘Voluntary’
4.It must be created by ‘Consensus’
5.It must be ‘Impartial’
6.It must define ‘Baselines of
Performance’
7.It must be widely accepted and
widely used
The Electric Utility Industry is
fragmented. Many separate
organizations exist today that employ
Lineworkers, but these can actually be
grouped into four main categories:
• Investor Owned Utilities (IOU’s)
employ 80,000 Lineworkers
• Rural Electric Co-operatives
(Co-ops) employ 18,000
Lineworkers
• Municipal Electric Utilities (Muni’s) employ 15,000 Lineworkers
• Contractors employ 22,000 Lineworkers
This is just in the United States, alone.
Bringing these groups together to
define and agree upon training and
qualification standards for Lineworkers
will not be easy – just necessary.
Many organizations with interest in
the Industry recognize the need for
Standards and are beginning to voice
support for such an effort:
• U.S. Dept. of Labour, OSHA, Occupational Safety & Health Administration
• IBEW, International Brotherhood of Electrical Workers
• EEI, Edison Electric Institute
• CARILEC, the Caribbean Association of Electric Utilities
• APPA, American Public Power Association
• NRECA, National Rural Electric Cooperative Association
• IUOTA, Inter-Utility Overhead Training Association
• ISPC, Institute for Safety in
Powerline Construction
It has been suggested that an initial
endorsement to a Consensus Standard
should come from the U.S. Department
of Labour, Bureau of Apprenticeship
and Training (DOL BAT), since they
already have a Certification process in
place and represent the ‘Public Good’
as mentioned above.
Industry Journal 37
The difference between
‘Standards’ and
‘Certification’
Don’t confuse ‘Standards’ with
‘Certification’ or vice-versa.
The difference is important
and can be explained with the
following definitions:
• Standards: Determine ‘performance requirements’
• Certification: Indicates ‘Conformity to a standard’
The establishment of
“Consensus” Standards should
be the first undertaking,
followed by the use of the
Consensus Standards as
a minimum requirement
to award appropriate
Certifications.
Where to Start?
The best Lineworkers have
a solid foundation of three
components: knowledge,
skills and experience. They
must be knowledgeable of
both the theory behind the
electric systems on which
they work and the practical
understanding of what works
and why. They must be
proficient at the skills required
to build and maintain the
electric system using the ‘best
practices’ acknowledged by
their fellow tradesmen. They
must have an opportunity
to experience the work and
practice their trade. With
practice, the Lineworker
becomes professional – a
Journeyman and ultimately a
Master Mechanic.
So, what should a Lineman
know and be able to do – and
when, within this process of
becoming a professional? In
2006, the Institute for Safety
in Powerline Construction
(ISPC), a non-profit Industry
Association, canvassed Electric
Utility safety and training
professionals through an
Industry-wide, on-line and direct mail survey. From the results, ISPC compiled a list of 171 Basic Lineman Competencies
within 8 major categories that sets a minimum ‘Benchmark’ Standard for Lineworkers wishing to practice their trade at a
Journeyman level on energized distribution systems:
Categories
Lineman Career Track Model
Number of Competencies
Electrical Theory
12 Competencies
T&D Systems Overview
20 Competencies
Safety Practices
36 Competencies
Rigging Skills
19 Competencies
Tools and Equipment
29 Competencies
System Protection and Metering
15 Competencies
Overhead Distribution Systems
28 Competencies
Underground Distribution Systems
12 Competencies
MAINTENANCE BASICS UNITS
(18 months)
Certification Earned: Powerline Technician
DISTRIBUTION
Substation & Switchyards
(6 months)
Endorsement Earned:
Substation & Switchyards
Transmission
(6 months)
Endorsement Earned:
Transmission
Endorsement Earned:
URD
Additionally, to be considered a ‘Master Mechanic,’ 2 more categories need to be integrated into the Standard comprising 20
additional competencies:
Categories
Number of Competencies
Transmission Systems
9 Competencies
Substations and Switchyards
11 Competencies
This proposed initial Standard, then,
suggests a baseline Benchmark. There
are 10 major categories comprising
191 competencies to be qualified as a
professional Lineworker.
Are 10 categories and 191
competencies the magic number; the
right formula? Possibly not, but it is a
reasonable place to start. Individual
organizations may choose to build on
this Standard just as they may choose
now to exceed the minimum safety
standards required in the US DOL
OSHA 1910.269 regulations. Going
beyond the minimum Standard may
be important in a given situation or
within a given organization. But by
having a reasonable baseline, it is
easier to make that determination.
Also, with a minimum Standard,
the U.S. Department of Labour can
begin to measure applications for
Certifications against an accepted
baseline, to determine if the applying
organization’s training program meets
or exceeds the Standard. If so, the US
DOL BAT Certification endorsement
can be granted, adding credibility to the
process, both for the worker and for the
Utility or Contractor.
Apprenticeship Models
The question of ‘when’ a Lineworker
should know and be able to reasonably
perform each of these competencies
within the Standard highlights the
need for an Apprenticeship ‘Model.’
Generally speaking, the Industry has
accepted an 8,000 hour, four year
(48 months) duration for Lineman
Apprenticeships. Apprenticeships in the
U.S. currently range from 36 months
to 72 months, though a majority of
current programs subscribe to the 48
months model. Once again, US DOL
Industry Journal 38
BAT patterns their Certifications for
achieving Journeyman Lineman status
on this four year period of training, as
well.
ISPC has arranged these first 8
Categories and 171 Competencies into
a progressive model (see illustration)
that defines a Lineman Apprenticeship
over a 48 month time frame to
complete the curriculum and gain the
knowledge and skill sets to be called
Journeyman. An additional 12 months’
training on the remaining 2 Categories
and 20 Competencies are required to
achieve ‘Master Mechanic.’ Again, as
mentioned above, practicing the trade
and gaining the experience required
for true proficiency takes time. A
physician just coming out of school is
not as proficient as his/her counterpart
who has been practicing for 20 years.
The same will always be true of the
Lineworker, as well. Underground Distr.
(6 months)
Overhead Distr.
De-energized
(12 months)
Endorsement Earned:
O/H - De-energized
Conclusion
Being a Lineman is a highly skilled, honourable trade that will continue to be important to
the Electric Utility Industry for generations to come. Commonly accepted safety and training
practices are essential to the health of the Trade and every worker employed within it. It’s time
that training and qualification Consensus Standards be implemented for Lineworkers everywhere.
Biography
Energized
(12 months)
Certification Earned:
Journeyman Lineman
Ron Schenk’s career in the Construction Industry spans 30 years and
includes 14 years on staff with an ENR top 5 powerline contractor,
serving as Director of Training for 1,800 lineworkers. In addition
to a bachelor’s degree in business, Ron is a Certified Occupational
Safety Specialist. Ron is currently Executive Director of the Institute
for Safety in Powerline Construction (ISPC), an Electric Utility Industry
Association focusing on safety and training for lineworkers.
Ronald J. Schenk, COSS, Executive Director
Institute for Safety in Powerline Construction
Industry Journal 39
OPTIMISING THE VALUE OF
OFF-GRID DURABLE POWER
GENERATION
By: Mr. Arnoud Bartelink, Marketing, Sales and Business Development Manager
Dynamic Power Stabilizers for Hitec Power Protection BV
Introduction
Society is adopting more and more
durable (renewable) energy sources
as an alternative for traditional energy
sources. Most of the power that will be
generated from durable energy sources
is, and in the future will be, integrated
as part of the grid. But there is also a
considerable market for renewable
energy technologies in remote areas
since off-grid power is generated
mainly by means of diesel or gas engine
power plants.
The current trend is to replace part
of the traditional power generation
capacity with durable sources of
energy. In Australia for example, a big
renewable energy investment program
was lined up as part of the country’s
ambition to reduce its carbon emission
level. However, in countries like India,
China and Russia, off-grid power
generation produces a huge amount
of Greenhouse gasses on a daily basis.
It is therefore inevitable that in future
durable energy sources become part of
these micro-grids.
Challenges Associated With the
Utilisation of Durable Sources of
Energy
There are challenges associated with
the utilisation of durable sources of
energy: these sources of energy are not
always available and often they are
not stable enough to ensure constant
contribution to the grid like an off-grid
fossil fuel power generation plant;
stability is however necessary if a diesel
or gas generator set is to be replaced by
solar panels or wind turbines. Hence
additional equipment is needed to
synchronize the different power sources
and to ensure that the required load is
always supported.
Industry Journal 40
Optimizing the Value of the Capital
Investment
Hitec Power Protection recently
introduced its Dynamic Power
Stabilizer (DPS), developed to
contribute to the success of medium
and large scale off-grid power
generation plants. Three major benefits
of the system optimize the value of
the capital investment needed for such
projects.
CAPEX versus OPEX
Grid Stability
Adding equipment apparently means
additional capital investment (CAPEX)
is needed. The reduction in the
operating costs (OPEX) then determines
the payback time of the additional
CAPEX. Traditionally, achieving
effective synchronisation between
different power sources required an
extra diesel or gas generator set. Such
a requirement can be eliminated by
utilising a DPS system which facilitates
and ‘smoothens’ synchronization
between the different power sources.
With that, the CAPEX stays relatively
on the same level while maintaining a
reduction in OPEX.
The key issue for off-grid power
generation is having a stable frequency
and voltage. The DPS system supports
the load when there is a temporary
shortage of power generation from
durable sources like wind, solar or
hydro. If this short fall in generation
takes too long, there is enough time to
start an extra diesel or gas generator
set. To ensure a stable grid the DPS
system also supplies extra power during
network fault conditions and stabilizes
the output power under load steps. In
addition, the DPS system allows load
sharing between different generator
sets.
Reduced Fuel Consumption
Reduced Carbon Emissions
The DPS system also supports the
power generating plant when small dips
in supply or power quality problems
occur which would otherwise result
in the automatic start-up of the extra
generator set. With the DPS system,
you have a few seconds of ride through
power, that is, a considerable reduction
of the number of diesel or gas generator
starts. This, in combination with the
fact that a generator set is eliminated,
leads to a significant reduction in fuel
consumption.
By using the DPS system, durable
energy sources can be integrated with
off-grid fossil fuel power generation
plant in an efficient way. Minimisation
of the number and frequency of use of
fossil fuel generator sets results in the
reduction of carbon emission.
The DPS system therefore enables using
clean energy with a positive effect on
the CAPEX, OPEX and the environment.
Case Study
In a remote location, power is
generated by an off-grid solar/diesel
generation power plant. The plant
consists of 4 diesel generators (500 kW
rating) - running 24 hours a day, seven
days a week - and a 550 square meters
solar field (500 kW rating). Adding a
Dynamic Power Stabilizer to the total
system improved stability and the
efficiency of the system.
When a fault occurs on the
transmission lines, the Dynamic Power
Stabilizer avoids an under-frequency
situation by delivering fault current
immediately for a short time frame.
This will enable the customer to trip the
faulted feeder (diesel generator or solar
field) before getting an under-frequency
event. Without the Dynamic Power
Stabilizer the power plant can have a
network fault which causes the whole
plant to trip on under-frequency before
the operator can trip the faulted feeder.
Another advantage is that if the solar
power output in the system reduces
too quickly - e.g. because of a cloud
cover or a fault in solar generation - or
if a diesel generator trips, the Dynamic
Power Stabilizer will supply power
to the load until another generator is
started (less than 30 seconds).
The Dynamic Power Stabilizer gave
the customer the option of eliminating
one diesel generator set and saving
approximately 570.000 litres of diesel
fuel per year at full load and therefore
causes a considerable reduction of
carbon emissions.
Biography
Mr. Arnoud Bartelink is Marketing, Sales and Business
Development Manager of Dynamic Power Stabilizers for Hitec
Power Protection BV at headquarters in The Netherlands. With
a degree in International Business, Arnoud Bartelink realizes
several energy projects worldwide, initially only in the power
quality market by means of ride through systems, also called
dynamic rotating UPS systems. However, from last year many
business opportunities were realized in the field of renewable
energy projects.
For more information:
Hitec Power Protection BV
The Netherlands
E-mail: [email protected]
Telephone: +31 546 589 553
Cell phone: +31 6 55305515
www.hitec-ups.com
Mr. Arnoud Bartelink, Marketing,
Sales and Business Development Manager
Dynamic Power Stabilizers for Hitec Power
Protection BV
Industry Journal 42
Industry Journal 43
Notes
Industry Journal 44