Apart from demonstrating the vulnerability of the electric grid, the American
and European blackouts of 2003 put enormous pressure on energy companies to
prove they’re serious about raising reliability by investing in infrastructure.
But how?

Physical infrastructure requires a huge capital investment – $10 billion
a year for the next decade, at the very least. However, the first, quick steps
toward greatly enhanced reliability need not be so costly. They involve processes
and technology, not vast changes in physical infrastructure.

Consider this: More than four hours before the August blackout in the northeastern
United States, there were clear indicators of grid instability. Both the New
England independent system operators (ISO) and the Pennsylvania-New Jersey-Maryland
(PJM) ISO managed to avoid substantial involvement because they have the technology
to provide early visibility to grid conditions and clear lines of authority
in place that allowed operators to either isolate from the grid or bring on
generation necessary to meet demands on reactive power.

In contrast, the control area at the Midwest ISO is highly fragmented, with
no overall visibility to conditions. So, despite the fact that practically
every technology vendor in the space boasts of having contracts in the ISO,
the blackout spread quickly.
Simply said, the technology exists to prevent massive blackout conditions,
but visibility and authority must be in place at larger regional transmission
organizations (RTOs).

The Key Objective

Reliability has always been critical for the transmission control operators,
but never more so than today. Although North American Electric Reliability
Council (NERC) standards are voluntary – there are no penalties – that
is expected to change quickly. Energy companies also look at reliability from
the perspective of generation plant up-time and availability, as well as outage
frequency and duration on the distribution grid.

Most energy companies list enhanced reliability as a key corporate objective
for the year ahead. Customers expect greater levels of reliability, and the
regulators demand it. At the same time, the industry is suffering from extreme
pressure on the balance sheet, forcing companies to limit capital expenditures.

Faced with this conundrum, the industry needs to look at reliability
from three perspectives: the grid at the control level; reliability of equipment;
and planning to expand capacity. We’ll examine each of these.

The Control Level
Although the August blackout pointed out deficiencies in grid control,
the move toward more interconnection in recent years didn’t cause this
problem. In fact, greater availability of power from a greater number of sources
has prevented more frequent localized outages.

The future of regional markets may be in doubt; witness the furious debate
over this issue with regards to the Energy Bill. However, there were interconnections
between control areas before wholesale markets and there will be interconnections
in the future. The energy industry must accommodate that reality.

The real need is to model and simulate the grid on an ongoing basis in order
to understand how it responds. Knowledge gained from simulations through tools
such as state estimation and contingency analysis allows protections to be
built into the system at all levels – the local transmission grid, the
control areas (such as ISOs, power pools, or RTOs), and even between control
regions and countries.

Operators can also use this knowledge to recognize patterns leading up to potential
failure and take corrective action long before the situation becomes a crisis.
This same type of approach proved necessary in very complex manufacturing environments,
such as semiconductor plants.

State estimation combined with contingency analysis to support automated decision
rules or human intervention is the most practical approach to addressing future
grid vulnerability. There are three steps to follow: characterize the risks;
install or identify monitoring equipment for incipient conditions; and establish
operating rules to make the grid more resilient. The requirements to support
this approach are:

  • Access to historical control data for analysis. Time series control data is
    already being collected through supervisory control and data acquisition (SCADA)
    for the grid and energy management systems (EMS) for generation. Companies
    with data delivery platforms, such as OSIsoft and their experience with the
    California ISO, have a long history of working in the power industry to provide
    access to control system data. IT provides access, but the data must be shared
    across interconnected control areas.
  • Analytical engines to predict potential hot spots and simulate
    possible mitigation strategies    . The idea is to recreate the demand conditions, understand
    what
    can happen, and then change the rules at local nodes to determine how
    the system reacts. Simulating the grid is no easy task. Each interconnection
    node and
    generator tie-in must be included in the analysis. There are tens of
    thousands of nodes to be considered. While calculation capacity needs to
    be robust and
    must accommodate large amounts of data, it does not need to occur at
    super speeds. In addition to the traditional providers of state estimators
    and contingency
    analysis, Emerson, AspenTech, and Pavilion Technologies have developed
    optimization capabilities in the power industry that go beyond reliability
    to profitability
    and environmental compliance – AspenTech with generation unit
    dispatch within the context of location on transmission grid,
    and Pavilion with power plant emissions with emission credits.
  • Protections built into control systems to prevent potential disasters.
    Control systems are good at reacting to local conditions. Based on what is
    learned
    from scenario testing,
    logic is added to controls systems at points of vulnerability. Companies
    such as ABB, Alstom ESCA, GE Harris, and Siemens provide control
    systems. However,
    there is often little communication between SCADA and EMS. SCADA
    needs to be better integrated with EMS systems at local, control
    area, and
    regional areas
    so that these systems can respond more rapidly to potentially disastrous
    conditions.
  • Sharing of real-time information between interconnected regions
    to act as a final failsafe    . The US-Canada Task Force cited both FirstEnergy and
    the Midwest
    Independent Systems Operator (MISO) for communication failures.
    Regardless of how the debate on regional electricity markets resolves, there
    will still
    be a need for visibility of voltage status, not ubiquity of control,
    across interconnected control regions in real time. A few years ago, security
    was
    important to prevent access to information that would lead to gaming
    the system. Now, the concern is protection against terrorist attack. Secure
    portals allow
    for implementation of security measures at each level.

Reliability of Equipment
As we stated earlier, commercially available and proven technology
already exists to support equipment reliability. An early warning system
can
alert energy companies to potential failures so that there is time
to react,
as long as those systems are turned on and functioning. If the time
window is
wide
enough and other conditions are right, the turbine, transformer, or
section of network can be taken offline and repaired or replaced, averting
failure.
If there is not enough time, energy can be diverted around the problem.

Essentially, this involves a focus on the assets in the energy supply
and delivery network (see Figure 1). Of course, it is important that
reliability
is maintained,
but within cost constraints. At the same time, an energy company cannot
lose sight of top-line opportunities related to the asset. However,
while the
technology for optimizing performance of assets exists, reliability-centered
maintenance
(RCM), RCM2, and asset lifecycle management have yet to be accepted
as a corporate mandate.

There are some basic steps that do not require a large new investment
in information technology, but may require installation of additional
monitoring
equipment:

  • Enhance existing enterprise asset management (EAM) and
    work management (WM) applications with plug-ins for scheduling
    and reliability-centered maintenance    .
    Scheduling modules speed work turnaround, while RCM provides the analytical
    tools to determine the optimal maintenance schedule. EAM vendors with experience
    in energy, such as Datastream, IFS, Indus, Intentia, JD Edwards, MRO Software,
    and Mincom, have experience working with each. The advanced application architecture
    of the latest EAM applications makes integration with new modules by the same
    or other vendors easier.
  • Enable access to control data for fault identification. There is already
    an active control system in place – SCADA and EMS.
    Data historians make control data easily accessible for analysis.
    OSISoft has the largest presence in transmission and distribution.
    Its experiences
    with
    Idaho Power and the California ISO are particularly notable.
    InStep’s
    eDNA is used by Southern California Edison to facilitate interfaces
    with five separate GE Harris SCADA systems widely distributed
    throughout the territory.
    Most utilities already use data historians in their engineering
    departments; IT should seek out these tools and support engineering
    in applying them.
  • Enable access to monitoring equipment in the field to identify
    conditions that indicate potential failure    . SmartSignal has applied its experience
    in the airline industry to the statistical analysis of condition data
    for generators to identify
    potential generator failures at companies such as Entergy
    and Dynegy. Look also at new approaches to monitoring transmission line sag.
    Work with engineering
    to determine whether there are enough of the right monitors
    in
    place to perform a robust analysis. Develop a business case to determine
    whether it is worth
    the investment
    by operations to add more.
  • Put in place the connections to initiate a work process
    to address a problem asset    . EAM offered by SAP is linked and in production
    with data historians
    like PI to automate the creation of work orders to investigate,
    repair, or replace an asset. Similar links are developed between EAM applications
    by Indus,
    MRO Software and JD Edwards. Keep tabs on how these links
    are working as they come into production; there are still lessons to be learned.
  • Portals provide the right information to engineering supervisors. Condition-based
    monitoring is best paired with repair histories for determining
    the best approach to repairing or replacing a failing piece of equipment.
    TransAlta has a notable
    portal for engineering supervisors that serves up PI
    data, asset content from NRX, repair history on the asset from SAP, and other
    outside data services
    through SAP’s xApps architecture. But just having
    access to condition data is not enough. Energy companies
    need the
    right analytics to quickly determine
    whether there is a problem and to initiate the proper
    maintenance approach.
  • There will be times when engineering services are required. Complex problems
    may not easily lend themselves to automated solutions.
    Vendors of EAM applications also offer add-on engineering services to be
    used in conjunction
    with software
    to determine the right maintenance or repair approach
    for a piece of highly engineered equipment or process. Companies such as
    Data Systems
    and Solutions
    and Invensys are currently offering these services.
    Take stock of your resident expertise and their capabilities; in-house resources
    may be
    able to use the
    analytical tools to construct specialized approaches
    at a lower cost.


Planning to Expand Capacity
Investment now in information technology will reduce the need
for massive new physical infrastructure. Energy companies
have more
data available
for planning
than any other industry. The operation of the grid depends
on information technology.

Ultimately, there is a need for new infrastructure investment
to replace aging pipes and wires, or to add new substations,
transformers,
and
other infrastructure,
especially in areas of high load growth. But there are
alternatives to massive investment in infrastructure, through
demand management
and better
forecasting.

There are some promising new concepts and existing applications
that can help energy companies use that data:

  • Meter data at the substation level and below can be used to assess
    the need for new distribution infrastructure    . ONEOK and Xcel Energy are
    at the beginning stages using Silicon Energy technology recently acquired
    by
    Itron. CES International
    has also done exploratory work in this area. Systems
    integrator SAIC has done extensive work in this area. This approach is
    still at the experimental
    level;
    companies with a business model built on
    T&D will want to invest in pilots.
  • Start to investigate planning and design tools for new transmission.
    CGI, through its acquisition of Cognicase, Itron, through its acquisition
    of Linesoft, and
    niche vendors PLSCADD, Cook/Hurlbert, and Enghouse
    have transmission and distribution design functionality. ABB has tools that
    will aid in transmission
    citing. There
    are likely to be barriers against location of new
    infrastructure, so look for design tools that can aid in taking advantage
    of existing rights
    of way.

Ultimately, using load response and market pricing signals – an approach
that EPRI also recommends – is a better way to prevent
grid failure than any failsafe device (see the AMR Research report “Economic
Demand Response: Increasing Margins on Commercial
and Industrial Customers”). A market mechanism that provides a
price signal (power becomes more expensive when supply is low relative to demand,
or transmission is constrained) provides a way
to relieve pressures on the grid to perform.

Energy companies, grid operators, and control vendors should spend 2004
shoring up their existing information technology infrastructure supporting
reliability.