Proper maintenance of and care for the critical components of an Electro-Hydraulic Control (EHC) system and the EHC fluid itself are essential to avoiding forced outages and costly damage to EHC system equipment. Regular EHC fluid sampling and analysis should be conducted to verify that your fluid is clean and free of other defects. If your fluid is regularly testing outside of acceptable limits, it is a good indicator that your system’s filtration components may need to be replaced. Having proper EHC fluid handling and hydraulic system maintenance procedures in place is also very important. For example, requiring a full system flush after cutting into the hydraulic system at any point. It is also very important to have regularly scheduled maintenance of the hydraulic system components such as rebuilding of hydraulic cylinders, accumulators, and trip manifolds. Servo valve rebuilds, spares, and exchange programs are also critical as servos are the most sensitive part of the system. Lastly, proper care for your Hydraulic Power Unit (HPU) and the EHC fluid pumps is essential to a reliable EHC system. Additional steps can be taken to improve system reliability with the addition of such things as offline filtration and diagnostics. With offline filtration the customer can engineer the proper filtration levels along with the proper heat removal by adding the heat exchanger circuit to this loop. Including the heat exchangers in the offline filtration circuit allows for a known flow rate to enter the heat exchanger resulting in a engineered heat transfer calculation. Diagnostics can be added to hydraulic system by simply adding commercially available diagnostic connectors to existing ports in the system. These points should be located at the actuator manifolds and HPU manifolds. These points will allow for local fluid sampling, temperature and pressure readings. These connections are of the quick disconnect design allowing for hand held gauges to be attached during turbine operation or permanent connections to transmitters feeding back through the turbine control system.
2. Why do I need to be concerned with frequency response?
With the increase in variable generation, frequency response has been spotlighted to insure grid stability during sudden load events. The North American Electric Reliability Corporation (NERC) requires that a particular generator, or a sharing group of generators, achieve an annual Frequency Response Measure that is equal to or better than its Frequency Response Obligation. NERC further requires that each generator implement a frequency bias setting in their Automatic Generation Controls (AGC). This frequency bias is intended to stabilize a frequency excursion event following inertial controls, turbine droop control, or spinning reserve that initially work to stabilize the energy balance of frequency and load during an event. With the turbine and boiler control systems being a critical item in the overall response to frequency upsets, successful implementation of the droop response in integrated turbine and boiler controls is critical to recovering and sustaining response from an event in a timely manner. Without coordinated control between the turbine and boiler, each independent control loop can fight one another resulting in increased lag time to recovery and unwanted stress on both pieces of equipment. In common “boiler follow” control schemes, the time it takes for the boiler to respond and provide more steam to the turbine, whose frequency is decreasing, is often times outside of the Frequency Response Obligation criteria. In addition to added stress on both the turbine and boiler, excess fuel consumption is common during these events. With the influx of renewable energy sources on the grid, the call on large utility turbines to operate at reduced loads with shorter start-up times, and aging generation resources with higher likelihood of trips, optimized frequency response control is more important than ever.
3. Why should I consider an open control system for combustion turbines?
Many gas turbines commissioned after the 1990s came equipped with OEM supplied proprietary “black-box” control systems. The idea here was to protect the OEM’s intellectual property so that competing manufacturers could not replicate their combustion and sequencing technology. Additionally, it prevents end users from changing how their product was designed to operate, minimizes “you break it, you buy it” scenarios, and ensures a consistent end user experience across their installed base. A consequence of this approach is that the OEM’s have put their customers at a major disadvantage: they’ve made it nearly impossible for end users to troubleshoot, maintain, or improve their system without OEM intervention. Third-party open control systems, namely of the DCS variety, allow users to see live data within the logic and use it to quickly make educated decisions regarding turbine operations. This allows them to instantly identify issues that may be preventing a start and identify workarounds to make sure the unit is available when called upon. Decreasing or eliminating the number of failed starts could allow an IPP to enter into riskier, and more lucrative, PPAs based on unit startup confidence. Lastly, the lifecycles of open control systems are typically much more favorable to the end user than OEM control systems. For example, ABB offers a backward compatible evolutionary path for control system upgrades. This allows the end user to maintain a state-of-the-art control system over the entire turbine lifecycle, while minimizing the cost and risk to the unit that is associated with rip and replace upgrades.
Thomas Nevinger, Thom has an MS in Environmental Engineering from Villanova University and did his undergraduate studies at Ithaca College. He as 7 years of operations and project management experience; two of which were with ABB’s turbine automation group in Pittsburgh, PA. Since May of 2013, Thom has been serving as the turbine group’s business development manager.