Validation of a Dynamic Model of the Brindisi Pilot Plant

Abstract In this work, a dynamic model of the Brindisi CO2 capture pilot plant is implemented in K-spice general simulation tool. The model is used to simulate relevant step changes performed during a pilot plant campaign conducted in the EU project Octavius in May and June 2013. Model results are compared to dynamic pilot plant data and it shows good transient agreement to the experimental results. The model is therefore able to capture the main process dynamics. An offset is, however, observed in some cases, especially during the initial simulation time. This is most likely caused by the fact that the model was given a steady state starting point, while the pilot plant was not necessarily completely at steady state when the step change was introduced. It is challenging to ensure steady state conditions prior to dynamic tests in a pilot plant, especially for one that is connected to a real power production unit as this one. Power production variations will act as disturbances to the capture unit, and due to slow transients in the solvent inventory of the capture unit, it will take several hours to ensure steady state conditions with stable inlet flue gas conditions

Demonstration of non-linear model predictive control for optimal flexible operation of a CO2 capture plant

Due to the penetration of renewable intermittent energy, there is a need for coal and natural gas power plants to operate flexibly with variable load. This has resulted in an increasing interest in flexible and operational issues in the capture plant as well. In the present paper a nonlinear model predictive control (NMPC) system was tested at the Tiller pilot plant in Norway. The most important part of the NMPC software is the dynamic model representing the absorber/desorber plant. A previous first principle (mechanistic) dynamic model of the plant using MEA was modified for a solvent of AMP and piperazine, and then successfully verified by step response tests. The NMPC, which was set up to minimize the deviation from the capture rate setpoint and minimize the specific reboiler duty was then tested in a closed loop with large changes in flue gas flow and CO2 composition. Even for gas rate variations of more than 300% (110–340 m3/h) and CO2 concentration changes of 30%, the dynamic response was satisfactory. A test with frequently occurring constraints on the reboiler duty revealed a need for an extension to include direct control of the lean loading. Test of setpoint changes in total CO2 recovery showed that the control system managed to rapidly change from one capture rate to another with a time constant of typically 10 min. This might be used in a second layer of optimization, a dynamic real-time optimizer, that minimizes the capture costs during a longer horizon considering varying energy prices.publishedVersio

CCS on Offshore Oil and Gas Installation - Design of Post Combustion Capture System and Steam Cycle

Most of the released CO2 on offshore oil and gas installation originates from the gas turbines that power the installations. For certain offshore installations, CO2 capture and storage (CCS) could be an alternative to decrease the CO2 emissions. When opting for a chemical absorption CO2 capture system, a heat source for the stripper reboiler is needed. Since most offshore installations are powered by simple cycle GTs, there is typically no steam available that could be used for stripper reboiler heat. A compact steam bottoming cycle could, in addition to providing the reboiler steam, partly or fully provide power from a steam turbine generator to the equipment in the CCS system, including CO2 compressors, pumps, and flue gas booster fan. Three different steam cycle configurations were designed, modeled, and simulated. The design of the post-combustion CO2 capture system is also presented but the main focus in the paper is on the steam cycle design. In addition to the energy and mass balance results, a weight assessment of the major equipment was done with the objective to come up with a simplified weight relationship for changes in the oil and gas installation size in terms of changes in total mass flow from the gas turbines. A steam cycle with a back-pressure steam turbine was ultimately selected. The back-pressure option was able to provide all necessary steam and power (with some margin) to the CO2 capture and compression system.publishedVersio

CCS on Offshore Oil and Gas Installation - Design of Post Combustion Capture System and Steam Cycle

Most of the released CO2 on offshore oil and gas installation originates from the gas turbines that power the installations. For certain offshore installations, CO2 capture and storage (CCS) could be an alternative to decrease the CO2 emissions. When opting for a chemical absorption CO2 capture system, a heat source for the stripper reboiler is needed. Since most offshore installations are powered by simple cycle GTs, there is typically no steam available that could be used for stripper reboiler heat. A compact steam bottoming cycle could, in addition to providing the reboiler steam, partly or fully provide power from a steam turbine generator to the equipment in the CCS system, including CO2 compressors, pumps, and flue gas booster fan. Three different steam cycle configurations were designed, modeled, and simulated. The design of the post-combustion CO2 capture system is also presented but the main focus in the paper is on the steam cycle design. In addition to the energy and mass balance results, a weight assessment of the major equipment was done with the objective to come up with a simplified weight relationship for changes in the oil and gas installation size in terms of changes in total mass flow from the gas turbines. A steam cycle with a back-pressure steam turbine was ultimately selected. The back-pressure option was able to provide all necessary steam and power (with some margin) to the CO2 capture and compression system.publishedVersio

Dynamic and Control of an Absorber - Desorber Plant at Heilbronn

The present work is based on an MEA absorption test campaign performed November 2013–January 2014 at EnBW's amine test pilot located in Heilbronn, Germany. The test campaign included transient step responses in steam, exhaust gas, solvent flow rate and in exhaust gas CO2 concentration. In addition, a test with simultaneous steps in all flow rates (exhaust gas, solvent and steam) was included. A dynamic model of the Heilbronn plant was then implemented in the dynamic simulator K-Spice® and tested against the step responses at the plant. In spite of some stead state deviations, the model was able to capture the process dynamics very well. For dynamic studies one can therefore assume that the model is representative for the plant. In the work presented here, two different control configurations were tested: 1) Ratio control in combination with a slow feed back control on the CO2 out of the absorber and 2) Control of CO2 out of the absorber by lean liquid flow rate and a temperature sensor up in the desorber packing. Both structures involve only simple PID control loops and are thus easy to implement. The proposed control configurations were tested by simulations with 30% changes in flue gas flow and composition. Both configurations showed good performance during the simulation testing, but the second one was superior as well as excellent with respect to tight CO2 recovery control. This may be an important property in supervisory control schemes.publishedVersio

Dynamic and Control of an Absorber - Desorber Plant at Heilbronn

The present work is based on an MEA absorption test campaign performed November 2013–January 2014 at EnBW's amine test pilot located in Heilbronn, Germany. The test campaign included transient step responses in steam, exhaust gas, solvent flow rate and in exhaust gas CO2 concentration. In addition, a test with simultaneous steps in all flow rates (exhaust gas, solvent and steam) was included. A dynamic model of the Heilbronn plant was then implemented in the dynamic simulator K-Spice® and tested against the step responses at the plant. In spite of some stead state deviations, the model was able to capture the process dynamics very well. For dynamic studies one can therefore assume that the model is representative for the plant. In the work presented here, two different control configurations were tested: 1) Ratio control in combination with a slow feed back control on the CO2 out of the absorber and 2) Control of CO2 out of the absorber by lean liquid flow rate and a temperature sensor up in the desorber packing. Both structures involve only simple PID control loops and are thus easy to implement. The proposed control configurations were tested by simulations with 30% changes in flue gas flow and composition. Both configurations showed good performance during the simulation testing, but the second one was superior as well as excellent with respect to tight CO2 recovery control. This may be an important property in supervisory control schemes

Baseline test of capture from bio flue gas with MEA at Tiller plant

A campaign on carbon capture from biomass flue gas was carried out at Tiller pilot plant during 30th September - 8th November 2019. Biomass was supplied by Drax power station. SRD of 3.57MJ/kgCO2 was obtained for MEA, in agreement with typical values for MEA. The plant was down at various time during the campaign due to operational issues mostly linked to the accidental short circuit of one part of the flue gas filter elements. These incidents, although unwanted, revealed the importance of keeping control of the particulate concentration in the flue gas to prevent high amine emissions due to aerosols. Increased levels of typical degradation products for MEA were found at the end of campaign. This can be explained by the high levels of ash dust in flue gas earlier in the campaign when the filter was not working properly. Flue gas was characterised using various set ups: FTIR, CPC, gravimetric and ELPI, for gaseous and particulate measurements at four different locations between the burner and the flue gas exit to the atmosphere. Zero emission of amine from the plant was achieved when the filter was working properly. Particulate effect on emissions was studied by partial bypass of the filter. Relationship is established between emissions, particle mass and particle number. Particle size distribution measurements identified region of particles responsible for emissions.publishedVersio

Rapport de mission en Guadeloupe (8/12/89-15/12/89)

Aluminum production contributes to global CO2 emissions both due to the production process itself and due to the generation of electric power required for aluminum production. A concept is presented for increasing the CO2 concentration in the aluminum exhaust from ∼1% to ∼5% through the feeding of aluminum plant exhaust gas to a natural gas combined cycle (NGCC). The specific energy demand for CO2 capture is therewith reduced for both the aluminum plant and the NGCC. An evaluation was made of the impact the aluminum exhaust gas may have on the gas turbine and it is estimated that the most critical issues are corrosion due to SO2 in the aluminum plant exhaust gas and gas turbine inlet filter saturation, since the exhaust gas is saturated with seawater after the wet scrubber. A gas turbine inlet filter was tested for a period of five weeks, but a longer filter test period would be required for verifying filter integrity over time. In order to proceed, the viability of the concept should be evaluated by a gas turbine manufacturer. An alternative concept to evaluate for concentration of CO2 emissions could be to feed the aluminum plant exhaust gas to a boiler in a steam power plant

Phase Equilibrium Measurements of Ammonia Based CO2 Capture Solvents with FTIRr for Gas Phase Analysis

Vapor-liquid-solid equilibrium (VLSE) was measured for four solvents (blends A-D) at atmospheric pressure in a low-temperature setup at 20 oC and at 20, 35, and 55 oC for blend E. The blends are ammonia-based aqueous solutions selected to evaluate the potential for CO2 capture at post-combustion conditions with high pressure solvent regeneration. The set-up was modified to enable analysis of ammonia and CO2 in the vapor phase using FTIR®. Solid formation in the liquid phase was monitored using optical probes FBRM® and PVM® to determine maximum CO2 loadings for the precipitation-free range