Energy Efficient Control Strategy to Operate Post- Combustion CO2 Capture in Response to Power Plant Load Reduction

Energy Efficient Control Strategy to Operate Post- Combustion CO₂ Capture in Response to Power Plant Load Reduction

Increasing concern about global warming has motivated the development CO₂ capture and sequestration as a potential option for reducing emissions from PC and IGCC plants. One of the mature technologies that can capture CO₂ emissions from a coal-fired power plant is amine-based absorption/stripping, which has the advantage of being added to an existing power plant. However, this technology is a very energy intensive, which can reduce the efficiency of power plants by 30%.

In this technology the aqueous amine solution countercurrently contacts the flue gas in a packed absorber and absorbs CO₂ from the flue gas by exothermic chemical reactions and significantly reduces the CO₂ concentration in the gas stream exiting the absorber. The CO₂-rich amine solution from bottom of the absorber is sent through a cross exchanger and directed to the stripper. The stripper temperature is maintained sufficiently high to reverse the amine-CO₂ reaction and liberate CO₂. The lean solution leaving the bottom of the stripper is cooled  and recycled to the absorber to remove more CO₂. The concentrated CO₂ stream from the top of stripper is compressed by a multistage into a supercritical form where it can be pumped to its destination. A potential option for providing reboiler steam is to extract it from steam turbines.

Due to high-energy demand that is mostly attributed to solvent regeneration and CO₂ compression, many research efforts seek to find the most energy efficient steady sate design . However there are few studies have been performed on minimizing energy consumption during possible operational scenarios for an existing capture plant. This study has  simulated a transient operation imposed by a power plant load change to understand the capture behavior and explore control strategies that minimize capture lost work at the new operating condition.

This work incorporated models of MEA absorption/stripping process, CO2 compressor and power cycle steam turbines and created the integrated process flowsheet in the framework of Aspen Custom Modeler ®. Absorber and stripper are packed columns modeled as multi-segment components with time variant mass and energy balance equations. Each segment is modeled with a nonequlibrium rate-based approach that simultaneously solves the mass and energy balances for liquid and vapor phases together with mass and energy transfer rate equations and equilibrium equations for the phase interface. It also incorporates empirical equations for pressure drop across the columns. The reboiler was modeled as an equilibrium stage with time variant mass and energy balances for each well-mixed phase. Other process blocks in the flow sheet including heat exchangers, pumps, compressor and steam turbines are modeled with simplified steady state equations. The model employs general characteristic curves of centrifugal pump and compressor and ellipse law for steam turbine to predict the pressure-flow variation during dynamic operation.

During boiler load variation in power plants, so many process variables are subject to change. One of the important variables influencing downstream capture plant operation is the property of flue gas entering the absorber. Based on discussion in literature on reduced load operation of coal-fired power plants, it could be assumed that as load reduces, the rate of flue gas is reduced accordingly while the composition and temperature are constant. The other issue resulting from power plant load change is related to the steam  rate in power cycle and further impacts the operation of the stripping part of capture. Therefore, the other assumption made is that the total steam rate entering 1^st stage steam turbine is changing accordingly with boiler load, which influences extracted steam flow rate and pressure. This analysis takes into account both effects on the MEA plant at the same time.

Regarding energy efficient operation, the simulation results demonstrated that a variable speed compressor is much more beneficial than a constant speed one. Adjusting compressor speed reduces lost work by pushing the compressor away from surge condition and avoids additional energy use due to recycling gas in the compressor. In addition, as total steam rate is reduced in power cycle, the reboiler steam pressure and flow rate is reduced and consequently CO2 removal drops. In order to keep CO2 removal high the compressor speed should increase to decrease reboiler temperature and condense more steam at lower pressure. Increasing reboiler temperature reduces heat duty equivalent work; however, the temperature should not exceed 120 °C (design value) since MEA thermal degradation is starting. On the other hand, reducing reboiler temperate to enhance CO2 removal is limited by maximum compressor speed, which is typically 120% of rated speed.

Another potential process variable which can be manipulated to minimize reboiler lost work and save the compressor from surging is solvent circulation rate. At fixed reboiler temperature, there is an optimum solvent rate that minimizes lost work and maximizes CO2 removal. As reboiler temperature goes up, optimum solvent rate decreases. However, there is a feasible range of solvent rate to vary that is set by compressor and pump operability. The minimum flow is always set by compressor surge condition while the maximum flow  depends on the level of load reduction. For example, when the power plant is operated at 80% load, the maximum liquid rate is limited by run-off condition of one of the pumps. At a  lower load like 60%, compressor surge condition is the dominant limiting factor for increasing solvent rate.

Based on minimization of total lost work by compressor speed and solvent circulation rate performed in the presence of operational constraints associated with pumps, compressor and solvent thermal degradation, this study gives a practical optimum CO₂ removal over 40%-100% operating load range. For this range of load change in an MEA plant designed for 90% removal, the plant can remove up to 94% of inlet CO₂. The practical minimum removal over that load range is about 85%, where the reboiler temperature reaches its maximum allowable value and the lost work is at a minimum.

Reducing the load of power plant that reduces extracted steam rate in the capture results pushes the compressor operating curve to the surge limit such that at minimum load (40%) , adjusting solvent rate and compressor speed no longer moves the operating curve away from  the surge limit and therefore the anti-surge control must be activated.

Based on energy minimization in response to power plant load reduction, two control strategies were found to operate the capture close to minimum energy path at each desired removal .

1. Ratio control between reboiler steam rate and CO₂ rate in rich solution or

2. Controlling lean loading to vary proportional to the CO₂ removal change.

In the future we plan to observe and compare dynamic performance of these two control strategies.