Apros success story – Development and implementation of fast trip control response to avoid pressure drop in process steam network

This story is an example of the sound benefits that Apros has provided to Uniper. One site suffered a steam generator trip, which affected the production process of downstream industrial consumers due to slow response of the steam pressure control. Uniper’s engineering team proposed a bespoke trip control function to address the issue, which was then developed and tested within Apros simulation software (so-called virtual commissioning) before implementation. A simulation model of the same process steam system was already available from a previous project, which provided a good starting point for swift execution.

The incident was analyzed in detail to understand exactly why the existing control logic behaved as it did during the trip. The conventional pressure control reacts to pressure deviation from the setpoint value. This means that by the time the controller starts to respond, the system pressure is already in a downward trajectory and difficult to recover. Ideally, the control should respond proactively before the process is affected. Uniper’s engineering team developed and tested a new feed-forward control logic in Apros. The dynamic simulator included the different steam generation units with relevant control loops as well as the process steam network.

Figure 1 shows the difference between the conventional control response (solid line) and the feed-forward control response simulated in Apros Thermal (dashed line), where the steam control valve is moved to new position immediately when the generator trip is identified. Furthermore, only the steam generator preselected for pressure control at the time of the trip ramped up while the other steam generators did not support. Thus, the task was to develop a feed-forward logic for immediate and coordinated control response of all steam generators in operation.

After the detailed analysis and design phase, a control logic was developed in Apros following the six steps described below:

1. When the trip of a steam generator is observed, the resulting steam deficit is automatically captured via analog memory and forwarded through a gradient limiter that captures the typical trip gradient of the affected unit.
2. On the other hand, a steam trip indication triggers additional memory blocks to quantify the spare ramp-up capacity of the remaining steam generators in operation
3. The steam deficit from step 1 is allocated to the available steam generators, where the steam offset of each generator is calculated based on the relative share in the total ramp-up gradient – higher offset is assigned to fast generators.
4. Steam offset value from step 3 is compared against the spare capacity from step 2 for each steam generator. If the steam offset exceeds spare capacity, the excess steam demand is handed over to the steam generator next in order. If the spare capacity of the last steam generator is exceeded, an alarm signal is triggered.
5. The fastest actuators in the network by far are steam conditioning stations with multiple stages. To make the speed available for feed-forward control, in the logic the steam offset allocated to these “generators” is converted to valve stroke offset by using Kv characteristic curve and distinguishing between subcritical flow, critical flow, and transition flow regime. In critical flow, it is assumed that the total pressure drop is distributed equally over the stages. The calculations were verified with design load cases of the manufacturer with relative error <5 %, which is sufficiently accurate for feed-forward control.
6. The steam offset value from step 4 is routed to the feed-forward input of the steam generator load controller, and the stroke offset value from step 5 is routed to the feed-forward input of the controller for the steam conditioning station. Positive gradient limits are applied to each offset to capture the respective ramp-up limit of the generator or the opening speed of the valve. Small negative gradient limits applied to the same offsets enable the feed-forward logic to reset after a trip without disturbing the pressure.

As part of the development process, correct function of the logic was verified with several dynamic test scenarios in the Apros simulator of the process steam system. The developed automation plans from the simulator were directly programmed in the power plant’s Distributed Control System (=DCS). Specific parameter values in the logic were adjusted based on operator experience where required, such as individual trip gradient of the steam generator.

A few months after programming, the largest steam generator in the system suffered a trip. Figure 2 shows the real trip response of the feed-forward control logic and the resulting pressure changes. Steam conditioning station 1, which reduces steam from the tripped boiler to the high pressure (=HP) steam system, opens immediately after the trip to discharge steam from the boiler. Steam conditioning station 2, which reduces steam from the tripped boiler to the intermediate pressure (=IP) steam system, opens at the same time. Steam flow over station 2 increases when HP steam flow in the tripped boiler is diverted from the HP turbine to the HP bypass station. Meanwhile, firing load of boilers 1 and 2 is gradually increased to replace the lost generation capacity in the system. As result of the timely and coordinated action of all available steam suppliers, HP process steam pressure and IP process steam pressure remain stable.