By Roy Hoffman and Michel Dubois, SNC-Lavalin Energy Control Systems
Weerachi Koykul and Suwat Chiochanchai, Provincial Electricity Authority
and Ron Wasley, KEMA Consulting
The Provincial Electricity Authority of Thailand (PEA) is implementing what is believed to be the largest distribution system automation and management project of its kind ever undertaken. The project will provide PEA with its first ever computer-based distribution dispatching centers.
The project includes a new system management center and five new area distribution dispatching centers (ADDCs). The system management center will manage ADDC power system operations from PEA headquarters in Bangkok, while the ADDCs perform their PEA power system operations from sites within their own service territories.
Stage 1 of the distribution dispatching center (DDC) project is procurement and implementation of a large scope distribution management system (DMS). The DMS implementation objectives are to apply distribution automation to improve service reliability, reduce operating costs, increase profitability and enhance customer service in five of PEA’s most industrialized and heavily loaded service areas. PEA plans to automate the other seven service areas in a separate second stage project during 2002-2006.
PEA’s Power System
The PEA power system serves more than 10.9 million customers and has a peak demand of more than 9,900 MW. Annual energy sales exceed 48,554 GWh, and demand continues to grow rapidly at more than 5.9 percent per year.
The system covers 510,000 square kilometers (approximately 99 percent of Thailand’s total area). It includes more than 243 substations with circuits operating at 115kV, 69kV, 33kV and 22kV. The 115kV and 69kV circuits constitute the high-voltage subtransmission system with a total length of 2,893 kilometers. The 33kV and 22kV circuits constitute the medium-voltage primary distribution system. Their total length is more than 238,990 kilometers (approximately 19 percent at 33kV and 81 percent at 22kV). PEA’s low-voltage secondary distribution system is operated at a feeder voltage of 400V.
With few exceptions, the power system is overhead and radial in nature. It is anticipated, however, that the high voltage circuits will become more meshed. The substations include switchable shunt capacitor banks and transformers with on-load tap changers. More and more substations are being automated through the application of computer-based substation control systems. The medium voltage circuits include circuit breakers at substations, reclosers on main lines and fuse cutouts on branch lines. Line regulators as well as fixed and time-switched capacitor banks are used. For efficiency and reliability, a system of open loops has been adopted. Feeders can be reconfigured by closing the normally open circuit breakers at substation load transfer buses and the normally open tie-switches at various pole-mounted locations outside the substations.
A small number of generators are connected to PEA’s power system. They are owned and operated by small power producers under contract with the Electricity Generating Authority of Thailand (EGAT).
PEA collaborates and shares responsibility for electricity supply in Thailand with EGAT and another state enterprise known as the Metropolitan Electricity Authority (MEA). EGAT is responsible for generation and bulk power transmission, while MEA distributes power to Bangkok and two adjoining provinces. PEA distributes power to all other parts of Thailand.
PEA is organized into four administrative regions-Northern, Northeastern, Central and Southern. Each region consists of three service areas with its own administrative office and ADDC.
At present, power system operations do not depend on computer-based facilities, but on manual dispatch procedures aided by hand-dressed mimic boards, paper maps and voice communication via telephone and UHF and VHF radio systems. Dispatchers plan and direct daily operations that are performed by personnel located at the substations and electric offices. The electric offices are responsible for providing local customer services including meter reading, bill collecting, connecting and disconnecting power, responding to customer telephone calls, and executing power system construction, maintenance and repair activities.
Developing the Business Case
DMS justification was based on a cost/benefit analysis that considered the economic feasibility of functions that address PEA’s specific business concerns. These concerns focused on system reliability, power quality, system losses, customer communications and customer billing. The candidate DMS functions included var dispatch, voltage dispatch, automatic meter reading (AMR), transformer load management and outage management.
Var dispatch was determined to be the most beneficial function based on its ability to switch capacitor banks and to maintain power factors more continuously near unity when compared to the use of existing fixed and time-switched banks. A significant reduction in power system capacity translates into capital savings through deferred construction costs. Further, with less frequent capacitor bank switching, maintenance costs can be reduced.
The main effect of voltage dispatch is the release of power system capacity. This is achieved during peak demand periods when reducing load voltages by 3 percent causes corresponding load reductions. PEA’s historical load duration curves suggested that load reduction can be an effective operating procedure for an accumulated period of at least 300 hours per year, resulting in significant net savings from deferred construction costs over and above the lost revenues due to load reduction.
The benefits of AMR for PEA were based on improved cash flow. This can be achieved through the remote and hence more timely reading of more than 400 revenue meters associated with PEA’s largest industrial and commercial customers. AMR will not be included in the initial DMS implementation, however, because the ability to achieve the stated benefits requires an interface and modifications to PEA’s customer billing system. In addition, AMR will most likely be an integral part of a separate enhanced customer service strategy.
In the case of transformer load management, the benefits lie in estimating loads to determine when more properly matched distribution transformers should serve those loads. Lightly loaded transformers should be replaced and used elsewhere to increase utilization, whereas heavily loaded or overloaded transformers should be replaced and used elsewhere to reduce energy losses and prevent failures.
The correlation between transformer and customer allows transformer loading statistics to be calculated from customer billing data instead of costly field measurements. In a similar manner to AMR, however, transformer load management will not be included in the initial DMS implementation because it may be applied in a separate and independent project.
In contrast to the other functions, outage management is the key to improving power system reliability and minimizing the impact of outages on customers. For PEA, there are two essential components, the fault isolation and system restoration (FISR) function and the trouble call function.
FISR handles outages caused by permanent faults on medium-voltage feeder circuits in several different ways. It opens switches immediately adjacent to the fault and re-energizes healthy upstream feeder sections by closing the faulted feeder’s circuit breaker. Then FISR either restores power to the healthy downstream feeder section by closing tie-switches automatically or it recommends, via supervisory control, that the tie-switch close to restore power to these sections. In this way, only the customers served by the faulted feeder section are affected for any significant period, and this can be rectified by rapidly dispatching field crews to perform the necessary repair works.
Trouble call, on the other hand, allows telephone calls from customers affected by outages to be answered and at the same time analyzed in a collective manner to locate what may be a fault beyond the medium-voltage fuse cutout. This can include distribution transformer or low-voltage circuit faults, resulting in the generation of a trouble ticket for crew dispatch. Trouble call can also provide customers with information on the status of the subsequent repair work.
Although outage management reduces outages and the amount of unserved energy, its more important benefits are largely subjective. Thus, outage management is clearly beneficial to PEA’s customers and to PEA’s relationships with its customers, but assigning a specific monetary value to these factors can prove elusive.
Scope of DCC Project
This first phase of the DCC Project requires many functions other than var dispatch, voltage dispatch and outage management. The additional functions provide additional direct and indirect benefits. They include SCADA, sequence-of-events data collection, disturbance data collection, switching order management, outage information system, calculation of power system reliability indices, switching device operations monitoring, load shedding, data exchange, state estimation, contingency analysis, power flow, short-circuit analysis, load forecast, dispatcher training simulator and historical information system.
The system’s user interface will support both Thai and English, and the large-scope nature of the project is further indicated by the following items to be supplied:
- Six interconnected DMS computer systems;
- All new buildings and facilities to house and support these systems;
- 118 remote DMS consoles at 59 existing electric offices;
- 53 substation RTUs;
- DMS interfaces to 111 existing or separately planned substation automation facilities in the form of computer-based substation control systems;
- More than 2,000 feeder RTUs interfaced to 1,600 line switches, 456 existing reclosers and 43 existing voltage regulators;
- DMS interfaces to 139 existing switchable capacitor banks via commercial paging services;
- DMS interfaces to PEA customer information system (CIS) and AM/FM/GIS facilities;
- DMS interfaces to non-PEA computer systems, such as those belonging to EGAT and MEA; and
- Multiple address radio system (MARS) for enabling DMS communications with all field devices, such as the remote controlled switches that are not directly accessible via PEA’s backbone communications system, which currently uses digital microwave radio link and time division multiple access facilities.
Project Status and Schedule
In July 2000, PEA signed a contract with SNC-Lavalin of Montreal, Canada, for the supply of the DMS. This includes computer systems, RTUs, FTUs, the MARS radio system, the six new distribution dispatching center buildings, and all necessary field installation and adaptation services. The 1,600 line switches to be integrated have been procured under two separate contracts for 800 switches, and virtually all of them have already been installed by PEA. The DMS will be fully operational and commissioned in 2003.
In addition to the DMS supplier contract, PEA signed a contract with KEMA Consulting (USA) at the end of October 2000 for project management services during system implementation. KEMA Consulting has assisted PEA with the DDC Project Stage 1 since its inception in 1996.