(62e) Energy Efficient Control Strategy to Operate Post- Combustion CO2 Capture in Response to Power Plant Load Reduction

Ziaii, S., The University of Texas at Austin
Rochelle, G. T., The University of Texas at Austin
Edgar, T. F., Dept. of Chem. Eng.,The University of Texas at Austin

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 1st
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.