Southern California Electricity Markets in The United States Paper Find out status of Electricity market in USA using web resources and briefly describe re
Southern California Electricity Markets in The United States Paper Find out status of Electricity market in USA using web resources and briefly
describe reasons for two states, where (and why) market operation has been
suspended? (1.5 pages max limit for answer)
https://www.electricitylocal.com/resources/deregul…
https://www.electricchoice.com/map-deregulated-ene…
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Problem 2
Choose one of the cases in last 10 years and why FERC has charged penalties for
market manipulation? (Search online for additional material other than below
links) (1.5-page max limit for answer directly addressing the reasons)
https://www.ferc.gov/enforcement/market-manipulati…
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Problem 3
Summarize your understanding for prerequisites needed to implement electricity
market in any regional electric system. (1-page max limit for answer)
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Problem 4
Summarize your understanding of work scope for different possible operators desk
in a control center? (1.5-page max limit for answer)
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Problem 5
Define multiple level of control for frequency, voltage and power balancing. How
are these managed in Electricity Market? What are the NERC reliability Standards
related to these? (2 pages max limit for answer) Power System Control Centers: Past, Present,
and Future
FELIX F. WU, FELLOW, IEEE, KHOSROW MOSLEHI, MEMBER, IEEE, AND
ANJAN BOSE, FELLOW, IEEE
Invited Paper
In this paper, we review the functions and architectures of control
centers: their past, present, and likely future. The evolving changes in
power system operational needs require a distributed control center
that is decentralized, integrated, flexible, and open. Present-day control centers are moving in that direction with varying degrees of success. The technologies employed in todays control centers to enable
them to be distributed are briefly reviewed. With the rise of the Internet age, the trend in information and communication technologies
is moving toward Grid computing and Web services, or Grid services. A Grid service-based future control center is stipulated.
KeywordsComputer control of power systems, control center,
energy management system, SCADA.
I. INTRODUCTION
The control center is the central nerve system of the power
system. It senses the pulse of the power system, adjusts its
condition, coordinates its movement, and provides defense
against exogenous events. In this paper, we review the functions and architectures of control centers: their past, present,
and likely future.
We first give a brief historical account of the evolution
of control centers. A great impetus to the development
of control centers occurred after the northeast blackout
of 1965 when the commission investigating the incident
recommended that utilities should intensify the pursuit of
all opportunities to expand the effective use of computers
Manuscript received October 1, 2004; revised June 1, 2005. This work
was supported in part by the Research Grant Council of Hong Kong under
Grant 7176/03E), in part by National Key Basic-Research Funds of China
under Grant 2004CB217900), in part by EPRI Worldwide under Contract
P03-60005), and in part by the DOE CERTS Program under Contract
DE-A1-99EE35075.
F. F. Wu is with the Center for Electrical Energy Systems, University of
Hong Kong, Hong Kong (e-mail: ffwu@eee.hku.hk).
K. Moslehi is with ABB Network Managements, Santa Clara, CA 95050
USA (e-mail: Khosrow.Moslehi@us.abb.com).
A. Bose is with the College of Engineering and Architecture, Washington
State University, Pullman, WA 99164-2714 USA (e-mail: bose@wsu.edu).
Digital Object Identifier 10.1109/JPROC.2005.857499
in power system planning and operation . Control centers
should be provided with a means for rapid checks on stable
and safe capacity limits of system elements through the
use of digital computers. [1] The resulting computer-based
control center, called the Energy Management System
(EMS), achieved a quantum jump in terms of intelligence
and application software capabilities. The requirements for
data acquisition devices and systems, the associated communications, and the computational power within the control
center were then stretched to the limits of what computer
and communication technologies could offer at the time.
Special designed devices and proprietary systems had to be
developed to fulfill power system application needs. Over
the years, information technologies have progressed in leaps
and bounds, while control centers, with their nonstandard
legacy devices and systems that could not take full advantage
of the new technologies, have remained far behind. Recent
trends in industry deregulation have fundamentally changed
the requirements of the control center and have exposed its
weakness. Conventional control centers of the past were, by
todays standards, too centralized, independent, inflexible,
and closed.
The restructuring of the power industry has transformed its
operation from centralized to coordinated decentralized decision-making. The blackouts of 2003 may spur another jump
in the applications of modern information and communication technologies (ICT) in control centers to benefit reliable
and efficient operations of power systems. The ICT world
has moved toward distributed intelligent systems with Web
services and Grid computing. The idea of Grid computing
was motivated by the electric grids of which their resources
are shared and consumers are unaware of their origins. The
marriage of Grid computing and service-oriented architecture into Grid services offers the ultimate decentralization,
integration, flexibility, and openness. We envision a Grid services-based future control center that is characterized by:
an ultrafast data acquisition system;
greatly expanded applications;
0018-9219/$20.00 © 2005 IEEE
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PROCEEDINGS OF THE IEEE, VOL. 93, NO. 11, NOVEMBER 2005
distributed data acquisition and data processing
services;
distributed control center applications expressed in
terms of layers of services;
partner grids of enterprise grids;
dynamic sharing of computational resources of all intelligent devices;
standard Grid services architecture and tools to manage
ICT resources.
Control centers today are in the transitional stage from the
centralized architecture of yesterday to the distributed architecture of tomorrow. In the last decade or so, communication
and computer communities have developed technologies that
enable systems to be more decentralized, integrated, flexible, and open. Such technologies include communication
network layered protocols, object technologies, middleware,
etc. which are briefly reviewed in this paper. Control centers
in power systems are gradually moving in the directions of
applying these technologies. The trends of present-day control centers are mostly migrating toward distributed control
centers that are characterized by:
Separated supervisory control and data acquisition
(SCADA), energy management system (EMS), and
business management system (BMS);
IP-based distributed SCADA;
common information model (CIM)-compliant data
models;
Middleware-based distributed EMS and BMS
applications.
Control centers today, not surprisingly, span a wide range
of architectures from the conventional system to the more
distributed one described above.
The paper is organized as follows: Section II provides a
historical account of control center evolution. Section III
presents the functions and architecture of conventional control centers. Section IV describes the challenges imposed
by the changing operating environment to control centers.
Section V presents a brief tutorial on the enabling distributed
technologies that have been applied with varying degrees
of success in todays control centers. Section VI describes
desirable features of todays distributed control centers.
Section VII discusses the emerging technology of Grid
services as the future mode of computation. Section VIII
presents our vision of future control centers that are Grid
services-based, along with their data acquisition systems and
expanded functions. Section IX draws a brief conclusion.
II. CONTROL CENTER EVOLUTION
In the 1950s analog communications were employed to
collect real-time data of MW power outputs from power
plants and tie-line flows to power companies for operators
using analog computers to conduct load frequency control (LFC) and economic dispatch (ED) [2]. Using system
frequency as a surrogate measurement of power balance
between generation and load within a control area, LFC was
used to control generation in order to maintain frequency
and interchange schedules between control areas. An ED
adjusts power outputs of generators at equal incremental
WU et al.: POWER SYSTEM CONTROL CENTERS: PAST, PRESENT, AND FUTURE
cost to achieve overall optimality of minimum total cost
of the system to meet the load demand. Penalty factors
were introduced to compensate for transmission losses by
the loss formula. This was the precursor of the modern
control center. When digital computers were introduced in
the 1960s, remote terminal units (RTUs) were developed to
collect real-time measurements of voltage, real and reactive
powers, and status of circuit breakers at transmission substations through dedicated transmission channels to a central
computer equipped with the capability to perform necessary
calculation for automatic generation control (AGC), which
is a combination of LFC and ED. Command signals to
remotely raise or lower generation levels and open or close
circuit breakers could be issued from the control center. This
is called the SCADA system.
After the northeast blackout of 1965, a recommendation
was made to apply digital computers more extensively
and effectively to improve the real-time operations of the
interconnected power systems. The capability of control
centers was pushed to a new level in the 1970s with the
introduction of the concept of system security, covering
both generation and transmission systems [3]. The security
of a power system is defined as the ability of the system to
withstand disturbances or contingencies, such as generator
or transmission line outages. Because security is commonly
used in the sense of against intrusion, the term power system
reliability is often used today in place of the traditional
power system security in order to avoid causing confusion to
laymen. The security control system is responsible for monitoring, analysis, and real-time coordination of the generation
and the transmission systems. It starts from processing the
telemetered real-time measurements from SCADA through
a state estimator to clean out errors in measurements and
communications. Then the output of the state estimator
goes through the contingency analysis to answer what-if
questions. Contingencies are disturbances such as generator
failure or transmission line outages that might occur in the
system. This is carried out using a steady-state model of the
power system, i.e., power flow calculations. Efficient solution algorithms for large nonlinear programming problem
known as the optimal power flow (OPF) were developed
for transmission-constrained economic dispatch, preventive
control, and security-constrained ED (SCED). Due to daily
and weekly variations in load demands, it is necessary to
schedule the startup and shutdown of generators to ensure
that there is always adequate generating capacity on-line
at minimum total costs. The optimization routine doing
such scheduling is called unit commitment (UC). Control
centers equipped with state estimation and other network
analysis software, called Advanced Application Software,
in addition to the generation control software, are called
energy management systems (EMS) [4].
Early control centers used specialized computers offered
by vendors whose business was mainly in the utility industry.
Later, general purpose computers, from mainframe to mini,
were used to do SCADA, AGC, and security control. In the
late 1980s minicomputers were gradually replaced by a set
of UNIX workstations or PCs running on an LAN [5]. At
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the same time, SCADA systems were installed in substations
and distribution feeders. More functions were added step by
step to these distribution management systems (DMS) as the
computational power of PCs increased.
In the second half of the 1990s, a trend began to fundamentally change the electric power industry. This came to
be known as industry restructuring or deregulation [6]. Vertically integrated utilities were unbundled; generation and
transmission were separated. Regulated monopolies were
replaced by competitive generation markets. Transmission,
however, remained largely regulated. The principle for the
restructuring is the belief that a competitive market is more
efficient in overall resource allocation. While suppliers maximize their profits and consumers choose the best pattern of
consumption that they can afford, the price in a market will
adjust itself to an equilibrium that is optimal for the social
welfare.
Two types of markets exist in the restructured power industry. One is the bilateral contracts between suppliers and
consumers. The other one is an auction market in which generators submit bids to a centralized agent which determines
the winning bids and the price. The price could be determined
by a uniform pricing scheme (in the United States) based on
the highest bid price that is deployed to serve the load, or a
nonuniform pricing scheme (in the U.K.) based on the bid
price (pay-as-bid). A market operator is needed to run the
auction market. The market operator may be an independent
system operator (ISO), a regional transmission organization
(RTO), or other entities with similar functions. With the introduction of electricity markets, some control centers, e.g.,
that of an ISO or an RTO, have had the responsibility of running the market operation, as well as maintaining system reliability. The two aspects are usually separated but with close
coordination.
The electricity market is different from any other commodity market in that power has to be balanced at all times.
This requirement leads to a more complex market structure.
Most electricity markets have a day-ahead energy market, a
real-time balancing market, and an ancillary service market.
The day-ahead market is a forward market in which hourly
clearing prices are calculated for each hour of the next
day based on generation and demand bids, and bilateral
transaction schedules. If the reliability of the transmission
system imposes limits on most economical generation
causing transmission congestion to occur, congestion management is required. One of the approaches to congestion
management is based on the pricing differences, called
locational marginal prices (LMP), between the nodes of the
network. The LMPs are obtained from the nodal shadow
prices of an OPF or SCED. The day-ahead market enables
participants to purchase and sell energy at these binding
day-ahead LMPs. A security-constrained unit commitment
(SCUC) is conducted, based on the bids submitted by
the generators, to schedule the startup and shutdown of
generators in advance. The transmission customers may
schedule bilateral transactions at binding day-ahead congestion charges based on the difference in LMPs at the
generation and the demand sides. The balancing market is
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Fig. 1. Control centers (CC) in the market environment.
the real-time energy market in which the market clearing
prices (a new set of LMPs) are calculated using SCED every
5 min or so based on revised generation bids and the actual
operating condition from state estimation. Any amount of
generation, load, or bilateral transaction that deviates from
the day-ahead schedule will pay the balancing market LMP.
There is a host of supporting functions to ensure reliable delivery of electricity to consumers. To ensure against
possible generator failure and/or sudden load increase,
additional generation capacity has to be provided. This real
power reserve is always ready to take on the responsibility
instantaneously. Adequate reactive power resources are
needed to maintain voltage at an acceptable level for proper
operation of the system. These are all grouped under the
name of ancillary services. An ancillary service can either
be self-provision by users of the transmission system or
system-wide management by the ISO/RTO. Markets have
also been established to manage ancillary services.
Industry restructuring has so far brought two major
changes in control centers structures. The first one is the
expansion of the control center functions from traditional
energy management, primarily for reliability reasons, to
business management in the market. The second one is the
change from the monolithic control center of traditional
utilities that differed only in size to a variety of control centers of ISOs or RTOs, transmission companies (Transcos),
generation companies (Gencos), and load serving entities
(LSEs) that differ in market functions. The control centers
in the market environment are structured hierarchically in
two levels, as shown in Fig. 1.
In Fig. 1, the ISO/RTO control center that operates the
electricity market of the region coordinate the LSE and
other control centers for system reliability in accordance
with market requirements. All entities, ISO, RTO, LSE,
Genco, etc., are market participants. Their control centers
are equipped with business functions to deal with the market.
The part of control center functions that is responsible for
business applications is called the business management
system (BMS). The ISO or RTO is usually the market operator; therefore, its BMS is also called the market operations
system (MOS). There are close interactions between the
functions of EMS and BMS as shown in Fig. 2. For other
types of control centers that do not operate a market, a BMS
is added to the traditional EMS to interact with the market.
PROCEEDINGS OF THE IEEE, VOL. 93, NO. 11, NOVEMBER 2005
Fig. 2.
EMS and BMS interactions.
III. CONVENTIONAL CONTROL CENTERS
Control centers have evolved over the years into a complex communication, computation, and control system. The
control center will be viewed here from functional and architectural perspectives. As pointed out previously, there are
different types of control centers whose BMS are different.
From the functional point of view, the BMS of the control
center of ISO/RTO is more complex than the others. Our
description below is based on a generic control center of
ISO/RTO, whereas specific ones may be somewhat different
in functions and structure.
A. Functions
From the viewpoint of the systems user, a controlcenterfulfills certain functions in the operation of a power system. The
implementations of these functions in the control center computers are, from the software point of view, called applications.
The first group of functions is for power system operation and largely inherits from the traditional EMS. They
can be further grouped into data acquisition, generation control, and network (security) analysis and control. Typically,
data acquisition function collects real-time measurements of
voltage, current, real power, reactive power, breaker status,
transformer taps, etc. from substation RTUs every 2 s to get
a snapshot of the power system in steady-state. The collected
data is stored in a real-time database for use by other applications. The sequence of events (SOE) recorder in an RTU
is able to record more real-time data in finer granularity than
they send out via the SCADA system. These data are used for
possible post-disturbance analysis. Indeed, due to SCADA
system limitations, there are more data bottled up in substations that would be useful in control center operations.
Generation control essentially performs the role of balancing authority in NERCs functional model. Short-term
WU et al.: POWER SYSTEM CONTROL CENTERS: PAST, PRESENT, AND FUTURE
load forecasts in 15-min intervals are carried out. AGC is
used to balance power generation and load demand instantaneously in the system. Network security analysis and control,
on the other hand, performs the role of reliability authority in
NERCs functional model. State estimation is used to cleanse
real-time data from SCADA and provide an accurate state
of the systems current operation. A list of possible disturbances, or contingencies, such as generator and transmission
line outages, is postulated and against each of them, power
flow is calculated to check for possible overload or abnormal
voltage in the system. This is called contingency analysis or
security analysis.
The second group of functions is for business applications
and is the BMS. For an ISO/RTO control center, it includes
market clearing price determination, congestion management, financial management, and information management.
Different market rules dictate how the market functions are
designed. The determination of market clearing price starts
from bid management.
Bids are collected from market participants. A bid may
consist of start-up cost, no-load cost, and incremental energy cost. Restrictions may be imposed on bids for mark…
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