Xcel Energy Northern Region Experience with Excitation System Upgrades and Retrofits

David S. Kral Xcel Energy

Minneapolis, MN

Abstract Since the mid-1980s, Xcel Energys Northern Region has replaced the OEM exciter and/or automatic voltage regulator on twenty-three units ranging in size from 2 to 239 MW. Most of these projects have been completed within the past five years using modern digital control equipment. A project is currently underway to replace the excitation system on a 598 MW generator, our largest project to date. This paper describes the scope of these projects, the reasoning behind them, the resources required to plan, design, install and commission the equipment, and some of the lessons learned along the way. Scope of Projects Within the Northern Region of Xcel Energy (formerly Northern States Power) we have been upgrading excitation systems since the mid-1980s. To date, a total of twenty-four projects have been completed or are in progress. We are currently in the evaluation stage for six more large projects, including three nuclear units. Six of the projects have involved installing Basler SSE static exciters on small hydro and steam turbine units ranging from 2.5 MW to 12.5 MW in size. Four of these were done to eliminate maintenance on the belt driven rotating exciters. The two steam units were upgraded following the mechanical failure of the shaft-driven rotating exciters. The SSE exciters are simple and robust, although their analog controls do not provide the level of response that can be obtained with more modern digital controls. Currently in progress is our largest rotating to static exciter retrofit project. This involves replacing dual Westinghouse Mark II brushless exciters on a 600 MW unit with an ABB Unitrol static exciter. The equipment is being delivered to the plant site with installation to occur in September of 2005. This project is being done in conjunction with an overall upgrade of the boiler and pollution control equipment. Five of the projects involved replacing Electric Machinery voltage regulators on combustion turbines with Basler DECS-15 or DECS-200 regulators. These

projects were performed in because of the lack of replacement parts and support and to improve the overall protection of the generator. In one case, the project was forced due to the failure of the existing regulator. Five of the projects involved replacing 1950s and 60s vintage voltage regulators (two GE Amplidyne type and three Allis-Chalmers Regulex type) with Basler DECS-300 regulators and PSS-100 power system stabilizers. These are on medium sized (100 239 MW) steam units in the Twin Cities area. The driving force behind these projects was obsolescence of the original equipment and, in the case of the GE units, the failure of the power system stabilizers that were added on in the 1970s. Six GE combustion turbines with SCT-PPT static excitation systems were retrofitted with Basler DECS-300 regulators due to an increase in the component failure rate of the original analog regulators and to improve the generator protection. The remaining project was performed under a turn-key upgrade project to convert a coal fired unit to a HRSG-driven combined cycle unit for a new combustion turbine. In that case, an older KWU Thyrosim regulator was replaced with redundant Siemens RG-3 regulators. Benefits and Justification In most of the cases, the excitation systems were so out-of-date that, at best, parts were only available from salvage sources and technical expertise was rapidly disappearing. In addition, a generator failure caused by overexcitation during a start-up due to the units potential transformers being out-of-service, made us very sensitive to off-line field current limiting. The fact that modern digital regulators include separate off-line and on-line overexcitation limiting forms a large part of our justification for voltage regulator upgrades. Since the modern controls can be tuned much more aggressively without creating unstable conditions, the voltage response of the generator can be dramatically improved (see Fig. 1). This is true even when retaining the original rotating exciter with the extra inductance and time delays that are involved. In a stability-limited region, like MAPP, this is of no small importance and can allow power import and export limits to be raised. However, the economic benefits are very hard to pin down and we have found that getting the people on the T&D side to give us a hard number to use for cost justification is very difficult.

Fig. 1 Five percent step response with original analog and upgraded digital AVR Other benefits that come with excitation system upgrades include an easier and better means of performing periodic response testing, which appears now to be an imminent NERC requirement. For our combustion turbines that have to meet ten minute reserve response requirements, we have found that by using the system voltage matching feature in the new regulators, the units come on-line thirty to sixty seconds faster than when the matching was done by the automatic synchronizing relay. This allows them to reach a higher load within the ten minute response window. Finally, in the case of replacing shaft-driven rotating exciters with static units, there is an increase in useful space on the turbine floor and a reduction in alignment time following major overhauls. Design Considerations There are a number of issues to be dealt with once the decision has been made to upgrade an excitation system. How secure does the source to the power bridge(s) need to be? Do you want redundant controls and/or power bridges? Will you be doing your control interface with hard-wired dry contacts or via a DCS data highway? Do you need a power system stabilizer? What level of user-friendliness does the programming interface need to have? For static exciter upgrade projects that we have performed we have always fed them from the generator terminals through a dedicated excitation transformer. We have done this even on small units, as much due to limited auxiliary bus source capacity as to provide as secure a power source as possible. For regulator upgrades, we generally have used the auxiliary bus source that previously powered the rotating amplifier. Although this is not as secure as a source directly from the generator terminals, it is no less secure than the original scheme that was removed.

Except for the new 600 MW static exciter upgrade, we have not installed redundant controllers or power bridges. With the exception of the four small hydro units, which challenge the power electronics severely on every start, we have found the bridges to be extremely reliable. We have found the same to be true of the control processors, and have yet to trip a unit due to a processor failure. In regard to control interface, we have used hard-wired dry contacts as the means of control and alarm connections. Since the wiring and control contacts are already in place, this minimizes the amount of wire to be pulled. In the MAPP region, power system stabilizers are required on units of 70 MW or greater. Certain units were grandfathered in because PSSs were not available, but with the excitation upgrades, we have added them where they were lacking before. Most often, the PSS function is included in the control processor software and the customer merely has to pay a fee to have that function activated. In some cases, the PSS may be a stand-alone box that sends an analog signal into an auxiliary input to the AVR processor. We allow the PSS to be implemented in either fashion. However, in order for a PSS to function effectively, the AVR must have negative, as well as positive, forcing capability. If you are planning on doing any of the system tuning in-house or plan to use the data recording functions now built into most regulators, the capabilities and user-friendliness of the interface software needs to be considered as part of the system evaluation. It can be quite daunting to be faced with a set of transfer block diagrams when looking for a particular gain setting. Project Resources In all but two of the projects we have undertaken we have done the design of the interface and installation in-house. This has been done by either our electrical tech support group or by a plant system engineer. It normally takes one to two weeks of dedicated time to design the interface scheme between the original system and its replacement. In the case of major plant upgrade projects contracted to an AE, the excitation system portion has been subcontracted to the new excitation system manufacturer. For those projects done in-house, installation has been performed by the plant electricians under supervision of the tech support or plant engineer. This normally involves one or two electricians with occasional support from other plant maintenance staff in demolition of the old equipment and rigging in the new cabinets. On a medium size steam unit this is normally done in a three to four week time frame working one shift, five days per week. The SCT-PPT retrofits took about one week with one electrician, while the Electric Machinery regulators were replaced in two days.

Fig. 2 Replacement of a GE Amplidyne with a Basler DECS-300 The commissioning of the new exciters and regulators has also been done in-house for the most part. This includes pre-operational testing to ensure the controls operate the correct parameters and the alarms function as designed. We have performed most of the off-line AVR tuning and on-line limit testing as well. While we have tuned analog power system stabilizers ourselves, with the new digital PSSs, we have been contracting with the OEM to perform the tuning. In the cases of the turnkey upgrade projects, the OEM has done the commissioning. Lessons Learned Your operators have to deal with fruits of your labor after the installation is complete and it is essential that they be comfortable with the changes. We try to make the transition as transparent as possible in the way that they operate the unit, but there are bound to be some changes. The dynamics of the unit may be different as well. The generator terminal voltage may be much more active than it was with an old analog AVR. This will not be as readily apparent if they see the voltage as a number on a CRT, but if they still have analog voltmeters they may need to be reassured that its doing a better job of supporting the transmission system.

Our biggest headache so far has been the failure of coils in the contactors that isolate the power bridges during shutdown. We have had two unit trips due to coil failure in service. After talking to the manufacturer, we have been removing these contactors and relying on the control to turn off the thyristors during shut down. We have also left the original Generator Field Breaker in service where we have upgraded AVRs, so this provides a positive means of interrupting excitation for both generator faults and normal shutdowns. There have been a few other hardware-related issues that we have encountered. One AVR had a bad voltage transducer when it came from the factory, which was found during pre-op testing. Another AVR developed a bad current transducer during operation, but this did not affect operation since we operate our units with the Droop setting at zero. As mentioned previously, the static exciters at the hydro plant have experienced power electronic and surge suppressor failures. However, the start-up sequence on these units calls for bringing the generator to approximately synchronous speed, closing the generator output breaker, and then applying field to lock it into synchronism. This induces a large voltage spike in the field that challenges the equipment on each start, so I do not consider this as normal service. The final lesson we learned occurred due to an incident on one of our new combustion turbines, though it applies to the refurbished units as well. With separate off-line and on-line excitation limiters, the reliability of the Generator On-line indication becomes critical. If the unit is on-line at high load, the failure of the on-line indication could cause the off-line excitation limiter to activate, tripping the unit on Loss of Field if the Underexcitation Limiter is overridden or disabled because the AVR thinks the generator is off-line. Summary Upgrading obsolete excitation systems can provide benefits to both the generating unit and the transmission grid. The cost for upgrading the voltage regulator alone is relatively small, while a full static exciter retrofit can be fairly expensive. As with any other plant upgrade, normal precautions should be taken.