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equipment

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.

PROJECT: DCS Upgrade Project


An independent power producer (IPP) owned a significant portion of the west coast generation assests including a 210 MW unit consisting of a natural gas fired Riley Stoker boiler and a Westinghouse tandem compound turbine/generator. This client needed to install a Selective Catalytic Reduction (SCR) system to meet recent air emission standards but their existing Bailey pneumatic boiler combustion control system with a partial Westinghouse WDPF DCS temperature control system was obsolete and inadequate for this type of a control system upgrade.

The IPP's choice was to perform a full unit control system upgrade. The IPP's in-house control system expertise was talented and enabled them to bid a full control system upgrade specification with the successful supplier being ABB Inc. with their Symphony control system.

A project of this magnitude would have overloaded the IPP's single control system expert to manage so the IPP contracted for management services as a formal Project Manager. A specific criterion requested by the IPP was that the Project Manager have an extensive background in process and control systems.

RESULTS


• Constructed using MSVisio simplified functional logic diagrams of all the major control logic loops for unit, boiler, and turbine controls. Responsible for the initial unit characterization constants and stability tuning. Built a tuning plan.

PROJECT: Large Boiler Combustion Troubleshooting/Tuning Project


This project was a return visit after being away from the site for over two years (i.e., see project: Twin 335 MW Units Complete Controls Tuning Program). Engineering services had completed a full tuning program on both units in May of 2002. At which time, both units were very responsive, stable, and achieved their full load capabilities. During that two year period, the IPP had installed a "blackbox" boiler optimization software program on one of the units.

The engineering service was able to compare the copy of previous software logic taken two years prior with the existing logic, document any differences, and conclude where the problem area was located. The cause of the combustion instabilities was identified to be how the optimization software program had interfaced with the existing control logic. The combustion optimization would occur while the unit was parked at a fixed load but when the unit moved to a new load, the optimization would not be correct at the new load or for the load change itself.

A formal final report was provided documenting the process used for troubleshooting, any tuning changes made, and discussion regarding the improper implimentation of the combustion optimization software.

There had been a historical curtailment of 10 MW for this unit due to the unstable optimization software so a full load test was conducted which proved that full load capability had not changed since the tuning effort two years ago.

RESULTS


• Correctly identified the cause of combustion instabilities resulting from the improper application of a "combustion optimization" software "blackbox" program. Documented findings and presented the report to the client.

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.

• Performed a complete hardware evaluative assessment of the local area networked Allen-Bradley PLC system consisting of PC server/client based HMI's, ControlLogix redundant PLC's, redundant industrial switches, and ControlNet communication to remote I/O.

• Created functional logic drawings in MSVisio for the original EPI logic, the original BaileyCAD drawings, and the existing PLC logic in the ControlLogix processors. Used these three versions to determine the optimal logic for critical control loops.

• Found and corrected the preheat burner purge logic. It was clear that past logic changes had been implemented to bypass safety features of the standard purge as defined by NFPA. Implemented the correct changes and successfully commissioned the new logic.

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.

PROJECT: Twin 335 MW Units Complete Controls Tuning Program


These twin large fossil fueled generating units are each rated at 335 MW with cross compound GE turbine/generators and steam supplied by Combustion Engineering controlled circulation boilers rated at 2,490,000 lbs/hr at 2450 pisg, 1050F superheat, and 1000F reheat. The boiler design is somewhat non-traditional and looks upside down in architecture. The boiler utilizes tangentially fired burners located near the upper structures of the furnace area and a major portion of steam temperature control is performed by "tilting" the burner mechanisms to direct the flame path. In addition, this is a pressurized furnace design with only forced draft fans providing combustion air and gas recirculation fans.

An independent power producer (IPP) purchased this facility from Southern Cal Edison in the 1998 era of power plant sales. Shortly after the purchase, a major NOx reduction upgrade was installed to lower emission levels with the use of a Selective Catalytic Reaction (SCR) draft modifications. Additionally, the Bailey Net90 (aka: ABB DCS) system had been managed by Southern Cal Edison engineers but that expertise was lost with the plant sales. Subsequently, no formal control system tuning program had thus been implemented since the sale of the plant resulting in significant process changes without compensation within the control system.

For a number of years, plant operators manually dealt with many unstable combustion issues during load changes and numerous other unit stability problems with load, boiler pressure, steam flow, and steam temperatures. It was very common for the stack to "smoke" even with the use of natural gas as their fuel supply during a load change.

Engineering services were brought in to conduct a full control system assessment, instrumentation maintenance including all final control elements, and complete unit tuning program. The goals of the project were to stabilize the process, increase the load ramp rate, improve efficiency, reduce NOx excess incidents, and eliminate the combustion smoking safety issue.

Due to an immediate improvement in all of the goals achieved on the first unit, engineering services were continued to conduct a duplicate program on the sister unit and achieved similar results.

RESULTS


• Completely reversed engineered all of the major control loops (e.g., fuel, air, feedwater, load, temperature, etc.) into simplified SAMA diagrams using MSVisio. Created an interactive program with references to the BaileyCAD nomenclature.