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ABB/Bailey Net90/Infi90 DCS


PROJECT: Combined Cycle Power Plant Steam Drain System Improvement Project


This facility was a 147 MW combined cycle generation unit using two gas turbines each with their own Heat Recovery Steam Generators (HRSG's) and one steam turbine/generator unit. At the time of this project, the plant had been recently commissioned within the last two years and was still ironing out some of the left over operational design issues.

The typical loading schedule for the plant was nightly shutdowns with a subsequent restart the following morning. The plant had incorporated many design features for this type of loading schedule. One of these designs was the method by which the high and low pressure main steam piping utilized a drain system to prevent the accumiliation of condensate during the warm up process. This was necessary to prevent the condensate from flashing resulting in potential piping hammering or water induction to the steam turbine.

The plant had a history of compliants registered from the nearby residential neighborhoods resulting from the noise created by the warm up steam releases even though the design of the warm up steam drain system used a flashtank with a very large silencer.

The engineering service was able to conduct a thorough evaluation of the system, used extensive compressible multi-phase steam flow modelling, and redesign the piping, valves, exhaust system sizes, and control logic to completely eliminate all steam drain system noise.

RESULTS


• Completed a thorough evaluation of the equipment, piping, control logic, and operational process, of the steam drain system. Detemined the causes of noise and provided formal recommendations for correcting.

• Completed a computer modeled simulation of the steam drain multi-phase steam flow conditions. Used this computer model to determine the new design modifications to eliminate flow conditions above sonic velocities.

PROJECT: Simultaneous Restoration of Two Biomass Power Plants


Two mid 1980's vintage biomass power plants each rated at approximately 12.5 MW's had been shutdown and abandoned in mid year 2010 due to the loss of permanent financing. With the financial challenges prior to these plants being abandoned, the equipment had suffered from over use, lack of maintenance, and make shift repairs with limited site resources. The Allen-Bradley PLC based control systems were one of the casualties of the lack of maintenance and technical expertise to the point where the contract O&M service were unaware of the full extent of the problems.

The initial responsibilities started late in the "refurbishment" process (i.e., four weeks before the scheduled startup date) and included simply fixing some perceived "bugs" in the PLC system, PLC process & control tuning, and startup engineering support. The responsibilities grew to include a full upgrade of the Allen-Bradley system from their mid 1990's version to current hardware and software, rebuilding of many major process control loops, process & control tuning, and full unit engineering startup support which included engineering changes to various process methods.

The combustors for these sites are Energy Products of Idaho (EPI) bubbling fluidized bed combustors providing heat energy to a Zurn 122 kpph at 684 psig & 765F superheated steam boiler. Both sites burned agricultural waste which primarily amounted to chopped up almond orchards during the course of this startup.

The plants were built and placed in operation in 1988 and 1990 but were sold to the second owner in 1992. The facilities were shutdown in 1995 after the power purchase agreements (PPA's)were bought out. The third owners purchased the sites, refurbished the equipment and negotiated new PPA's. This major refurbishment was needed to correct damage for the 12 years of being abandoned the first time. Unfortunately, the control system upgrade was not managed well which resulted in many control loops being operated in manual. During the refurbishment, the sites were sold to the fourth owner which ended up having to fire the general contractor conducting the refurbishment and utilizing the contract O&M service to complete the work. After the startup of this first refurbishment beginning in 2008, the plant only ran to mid year 2010, again, being abandoned. The fifth owner purchased the plants and conducted these current refurbishments.

RESULTS


• Performed a complete control system evaluative assessment for the existing control logic in the PLC's, compared this to the OEM original design functional logic, and BaileyCAD logic. Provided a formal control system improvement program proposal document.

• Created and formally documented a proposed process and control logic upgrade for the boiler master, fuel flow, air flue, gas recirculation, and induced draft fan control logic. This new design included improved process monitoring and control philosophy.

• Completed a performance assessment of the required steam flow for full load capacity versus the historical performance and instrumentation calibration. Provided documented proof of a severe degradation in turbine performance.

• Completed a tuning program of the primary control loops necessary for stable automatic operation of the biomass combustor process, boiler controls, and turbine controls.

• Conducted final start up activities for both biomass generation units supporting all control system and process troubleshooting activities. Successfully placed in operation both full power generation facilities ahead of the expected schedule.

PROJECT: Turbine Gland Steam Controls Upgrade Project


This facility was a 147 MW combined cycle generation unit using two gas turbines each with their own Heat Recovery Steam Generators (HRSG's) and one steam turbine/generator unit. At the time of this project, this plant had been recently commissioned within the last two years and was still ironing out some of the left over operational design issues.

The Mitsubishi 53.6 MW condensing steam turbine was supplied with a pneumatic stand-alone gland steam supply system. At lower loads, the gland steam supply required a stable source of 60 psig, 510F supply steam for providing sufficient sealing steam to the two ends of the steam turbine rotating shaft. This steam was supplied by the "1st Stage Pressure Reduction & Desuperheating Station". At higher loads, the turbine was "self-sealing" and excess pressure was dumped to the steam condenser via a sparger system.

The "2nd Stage Pressure Reduction & Desuperheating Station" design utilized a common pneumatic pressure controller stand-alone system with the attemperation supply valve for the low pressure end of the turbine shaft controlled by the ABB DCS system. This pressure controller controlled both the steam supply and steam dump valves.

The purpose of this project was to diagnose the current causes of instabilities, recommend cost affective upgrade solutions, and conduct the approved modifications. Engineering services found that the primary cause of instabilities was the use of stand-alone controllers. It was common for one steam system to continue supplying steam while another controller was dumping to the condenser. Engineering services designed fully dependant control logic in the ABB DCS and had all necessary process inputs and outputs also transferred to the DCS.

RESULTS


• Completed a thorough evaluation of the equipment, piping, control logic, and operational process, of the turbine steam gland system. Detemined the causes of instabilities and provided formal recommendations for correcting.

• Evaluated instabilities of two natural gas combustion turbines with HRSG's. During supplemental duct burner operation, the DCS control logic would drive the CT's into the whole. Found the problem and corrected the logic.