Brown Coal-fired Power Station Research Articles

Outcomes from pilot plant trials of precipitating potassium carbonate solvent absorption for CO2 capture from a brown coal fired power station in Australia

A precipitating potassium carbonate (K2CO3) based solvent absorption process has been developed for capturing carbon dioxide (CO2) from industrial sources. Demonstration of this process has been completed using real flue gas in a pilot plant located at Hazelwood power station in Victoria, Australia. The pilot plant was designed to capture up to 1tonne per day of CO2 and was operated over a number of campaigns to test the absorption performance of a liquid solvent (30wt% K2CO3), a precipitating solvent (45wt% K2CO3) and a promoted precipitating solvent (promoter with 45wt% K2CO3). The main aim of this study was to collect operational data from the industry based pilot plant absorber in order to validate thermodynamic experiments and further improve simulation models developed from lab-scale precipitating column trials using synthetic feed gas. The performance of the industry based absorber including CO2 capture rate, pressure drop, solvent loadings and temperature profile, has been measured over a range of operating conditions. The CO2 capture rate improved when operating with a lower gas flow rate, higher solvent temperature and when a rate promoter was added to the solvent. The highly concentrated solvent trials created some difficulties with absorber flooding and intermittent operation due to blockages at start-up but minimal issues were encountered once the system was stabilized. Process simulations have been developed to successfully predict the pilot plant performance over a range of operating conditions. Completion of these pilot plant trials has provided confidence in plant operation and will enable an improved full-scale design and costing of this slurry based solvent process to be completed for commercial scale.

Brown coal exit: A market mechanism for regulated closure of highly emissions intensive power stations

In this paper we propose a market mechanism for regulated exit of highly emissions intensive power stations from the electricity grid. The starting point is that there is surplus capacity in coal fired power generation in Australia. In the absence of a carbon price signal, black coal generation capacity may leave the market instead of high emitting brown coal power stations. We lay out options for a mechanism of regulated power station closure using a market mechanism. Plants bid competitively over the payment they require for closure, the regulator chooses the most cost effective bid, and payment for closure is made by the remaining power stations in proportion to their carbon dioxide emissions. This could overcome adverse incentive effects for plants to stay in operation in anticipation of payment for closure and solve the political difficulties and problems of information asymmetry that plague government payments for closure and direct regulation for exit. We explore the issues theoretically and provide empirical illustrations. These suggest that closure of a brown coal fired power station in Australia could yield emissions savings at costs that are lower than the social benefits. The analysis in this paper is applicable to other countries.

Monoethanolamine Degradation during Pilot-Scale Post-combustion Capture of CO2 from a Brown Coal-Fired Power Station

The use of aqueous amines, such as monoethanolamine (MEA, 2-aminoethanol), for post-combustion capture (PCC) of CO2 from fossil-fuel-fired power station flue gases leads to undesirable reactions with oxygen, SOx, and NOx. This study has used a gas chromatography with mass spectrometry detection (GC–MS) method to measure the changes in concentrations of organic compounds in samples of a 30% (w/w) aqueous MEA absorbent obtained from CSIRO’s PCC pilot plant operating at AGL’s Loy Yang brown coal-fired power station in Latrobe Valley, Victoria, Australia. This aqueous MEA absorbent was previously used for more than 700 h of PCC, and the collected samples represent a further 834 h of PCC operation. These data provide a new perspective on the close, interdependent relationships between corrosion and amine degradation reactions. Other important outcomes include confirmation that (a) organic degradation products identified during laboratory-scale trials were also produced during pilot-scale PCC and (b) N-(2-hydro...

Remediation of monoethanolamine after exposure to brown coal flue gases

Monoethanolamine (MEA) is the solvent most commonly considered for post-combustion capture. However, the solvent will accumulate a range of contaminants during use, notably heat stable salts, that reduce its performance. This work considers the removal of these contaminants from MEA solutions that had been exposed to over 50 and 1800h of post combustion capture of flue gases from a brown coal-fired power station. Analysis indicated that these MEA solutions contained significant quantities of heat stable salts including iron, potassium, sulphate, nitrate and organic anions, particularly in the older sample. Both solutions were initially neutralised to free the protonated amine, which led to precipitation of some impurities within the older solvent. Nanofiltration was considered as an approach to further concentrate impurities, but was ineffective due to low permeation rates and low rejection of monovalent salts, at less than 20%. It was effective in concentrating metal contaminants and may be useful into the future for this reason. Conversely, electrodialysis was effective in removing up to 91% of the ionic content of the solutions, although the current efficiency fell at low feed conductivities. Monovalent salts such as sodium, potassium and nitrate were removed more readily than multivalent salts such as iron and sulphate. MEA loss was consistent with our prior work at around 0.15g/m2s and was predominantly as the free amine rather than the carbamate salt.

Primary sources and accumulation rates of inorganic anions and dissolved metals in a MEA absorbent during PCC at a brown coal-fired power station

Post-combustion capture (PCC) of CO2 from fossil fuel-fired power station flue gas is one of many technologies that are being developed to reduce anthropogenic greenhouse gas emissions in the medium term. Wet-gas scrubbing using aqueous amines is currently the most mature PCC technology suitable for separating CO2 from coal-fired power station flue gases. In this study, a series of twelve samples of a degraded 30% (w/w) MEA absorbent were obtained over a six month pilot scale PCC campaign at a brown coal-fired power station in Australia. These samples were used to investigate the accumulation of heat-stable salts, inorganics and minerals. The heat-stable salts concentration increased from 0.80 to 2.29% (w/w, as MEA) and organic acids from the oxidative degradation of MEA were the largest component of heat-stable salts. Acid gases such as SOx and NOx, make-up water, ultra-fine fly-ash and corrosion were all sources of the minerals and inorganics that accumulated in the aqueous MEA absorbent. Corrosion was the single biggest contributor of transition metals and the abrupt change in ratios of Fe, Cr and Mo suggests that the dominant corrosion mechanism may have changed towards the end of the campaign. The rapid accumulation of minerals and inorganics during this PCC campaign highlights the importance of continuing research into the interactions between amine absorbents and inorganic or mineral contaminants. The data presented in this study are an important resource for design of laboratory scale experiments to investigate these physical and chemical interactions between aqueous amines, minerals and inorganics.

Evaluation of methods for monitoring MEA degradation during pilot scale post-combustion capture of CO2

Amine degradation is an important and current focus in the development of chemical absorption technology based on the use of aqueous amines for post-combustion capture (PCC) of CO2. The oxidative degradation and carbamate polymerisation of monoethanolamine (the current industry standard amine for PCC) has been studied extensively at the laboratory scale. However, methods for monitoring long-term amine degradation during pilot, demonstration and commercial scale PCC are needed to enable researchers and operators to optimise amine management (e.g. minimising degradation and optimising reclamation strategies), improve PCC plant operation and avoid operational instabilities. The current industry standard method, based on the measurement of heat-stable salts (HSS) is not suitable for continuous monitoring of amine degradation. This study discusses the organic structural changes of severely degraded 30% (w/w) aqueous monoethanolamine samples obtained from a PCC pilot plant operating at a brown coal-fired power station in Australia. It demonstrates that absorbance measurement at 313nm by UV–vis, change in infra-red absorbance and the organic carbon content of degradation products correlate strongly with HSS concentrations. These parameters are easily measured using well established technology and are suitable for monitoring the degradation of aqueous monoethanolamine during PCC.

Comparative life cycle assessment of potassium carbonate and monoethanolamine solvents for CO2 capture from post combustion flue gases

Carbon capture and storage (CCS) has the potential to enable significant reductions in carbon dioxide (CO2) emissions from stationary sources such as coal-fired power stations. The most advanced carbon capture technology is CO2 absorption using amine-based solvents, such as monoethanolamine (MEA). However, there is concern that the increased use of amine-based solvents will lead to other potential negative environmental impacts, such as increased human toxicity. The use of benign inorganic solvents, such as potassium carbonate, which do not degrade in the presence of oxygen or other impurities such as sulphurous or nitrous oxides offer significant advantages over amine-based solvents in terms of environmental impact.A comparative life cycle assessment (LCA) between the use of MEA and the CO2CRC's potassium carbonate based UNO MK 3 technology for the capture of 1tonne of CO2 from a brown-coal fired power station has been completed. The results reveal that the UNO MK 3 process is significantly better than MEA on ecotoxicity and carcinogen emissions and substantially better on all other indicators. The benefits of the UNO MK 3 process compared with MEA are due to avoidance of emissions from MEA degradation along with the savings in energy use for CO2 removal.The significant environmental benefits of the UNO MK 3 process compared with MEA were not altered by an uncertainty analysis or sensitivity analysis of key inputs and assumptions.

Pilot-scale evaluation of AMP/PZ to capture CO2 from flue gas of an Australian brown coal–fired power station

Monoethanolamine (MEA) is a well-established absorption liquid used in post-combustion capture (PCC) technology that has a high rate of reaction with CO2. However, an absorption liquid with improved properties, such as less degradation, less corrosion and a lower energy requirement for solvent regeneration, would greatly benefit the PCC process. An alternative to MEA is an aqueous solution of 2-amino-2-methyl-1-propanol (AMP), promoted with piperazine (PZ). This absorption liquid is expected to improve CO2 recovery and reduce reboiler heat duty for solvent regeneration in PCC plants.This paper evaluates the pilot-scale performance of an aqueous mixture of 25wt% AMP and 5wt% PZ (AMP/PZ) with a total amine concentration of 30wt% compared with the baseline performance of aqueous MEA (30wt%). We evaluated the reboiler heat required for solvent regeneration and CO2 recovery for AMP/PZ and MEA as both a function of CO2-lean loading at a similar liquid to gas (L/G) ratio, and as a function of L/G ratio at a similar CO2-lean loading.Our results show that AMP/PZ is a promising alternative to MEA. At a similar L/G ratio, both MEA and AMP/PZ required lower reboiler heat duty when CO2-lean loading was reduced. At higher CO2-lean loadings, neither absorption liquid showed any changes in reboiler heat duty as a function of L/G ratio. One exception occurred for AMP/PZ at lower CO2-lean loadings (0.03 and 0.08mol CO2/mol amine), when reboiler heat duty dropped as the L/G ratio rose. In most experiments with AMP/PZ, the condenser heat and sensible heat were the major contributors to the reboiler heat duty at lower CO2-lean loadings (<0.1mol CO2/mol amine). For MEA, the condenser heat had the highest portion in the reboiler heat duty at a CO2-lean loading of <0.18mol CO2/mol amine. Increasing condenser heat was associated with an increase of heat for water evaporation to generate steam for CO2 stripping. The reboiler heat duty to capture ∼80% and ∼85% CO2 was similar for both absorption liquids; yet, to capture this proportion of CO2, AMP/PZ required a higher L/G ratio than MEA.

Chemical Characterization of MEA Degradation in PCC pilot plants operating in Australia

An important step towards commercial scale post-combustion CO2 capture from coal-fired power stations is understanding solvent degradation. Laboratory scale trials have identified three main solvent degradation pathways for 30% MEA: oxidative degradation, carbamate polymerization and formation of heat stable salts. This paper probes the semi-volatile organic compounds produced from a single batch of 30% MEA which was used to capture CO2 from a black coal-fired power station (Tarong, Queensland, Australia) for approximately 700hours, followed by 500hours at the brown coal-fired power station (Loy Yang, Victoria, Australia). Comparisons are made between the compounds identified in this aged solvent system with MEA degradation reactions described in literature.Most of semi-volatile compounds tentatively identified by GC/MS have previously been reported in laboratory scale degradation trials. Our preliminary results show low levels of degradation products were present in samples after its use in the pilot plant at Tarong (black coal) and consequent 13 months storage, but much higher concentrations were later found in the same solvent during its at use in the pilot plant at Loy Yang Power (brown coal). Further work includes identifying the cause of poor GC/MS repeatability and investigating the relative rates of reactions described in literature. The impact of inorganic anions and dissolved metals on MEA degradation will also be explored.

Soil acidification and nutrient sustainability of forest ecosystems in the northeastern German lowlands - Results of the national forest soil inventory

Between the first and second national forest soil inventory in the northeastern German lowlands a significant soil acidification took place with regionally varying intensity. It manifests itself in a reduced base saturation in the whole rooting zone. This applies to the base cations magnesium and calcium. For potassium, however, no significant changes were detected. The acidification dynamic is the strongest in the southern part of Brandenburg. The specific immission situation in this region during the past four decades explains this. Particularly in southern Brandenburg high dust depositions (fly ashes from brown coal-fired power stations) buffered the acid components and enriched the soil with base cati ons in the 1970s and 1980s. Since the reduction of these atmospheric depositions, the bases were obviously totally incorporated in the biomass or leached out with seepage water. Currently, the majority of the forest sites in Mecklenburg-Vorpommern and Brandenburg are poor in basic nutrient elements (Ca, Mg, K). Especially the element magnesium is assumed to be lacking. This paper presents an assessment of the long-term availability of the nutrients Ca, Mg und K on the basis of calculated nutrient balances for various forest management scenarios (e.g. full-tree harvest). The results show that the sustainable supply is critical especially for intensive forest use on numerous sites.

Performance of MEA and amine-blends in the CSIRO PCC pilot plant at Loy Yang Power in Australia

Chemical reactive liquid absorption in post-combustion carbon capture (PCC) has sparked an interest of many researchers for improvement in creating high CO2 absorption capacity and minimising the reboiler heat duty for regeneration.This paper discusses results from performance trials on different solvents: mono-ethanolamine (MEA-baseline), a mixture of MEA with 2-amino-2-methyl-1-propanol/AMP (Blended Amine 1) and Blended Amine 2 (a propietary solvent developed by Research Institute of Innovative Technology for the Earth (RITE), Japan). The trials were carried out in CSIRO’s PCC pilot plant at Loy Yang Power. The pilot plant receives flue gas from this 2.2GW brown coal-fired power station in the Latrobe Valley, Victoria. The study has shown the benefits of using blended solvents for CO2 capture in terms of CO2 recovery and reboiler duty for solvent regeneration.The correlation of CO2 recovery and process parameters, i.e., liquid and gas (L/G) ratio and lean loading, has been established for the range of solvents tested. The results show that, in general, an increase of L/G ratio increases the CO2 recovery. It is also noted that a solvent at higher lean loading requires a greater solvent (recycle) flow rate, or vice versa, in order to capture a given amount of CO2. The effect of reducing the stripper’s bottom temperature from 115 to 112°C reduced the CO2 recovery of both MEA and Blended Amine 1 as their solvent lean loadings are raised. The same temperature change, however, did not significantly decrease CO2 recovery of Blended Amine 2, as it also shown by insignificant changes in solvent lean loadings.The results also indicate that the reboiler heat duty is dependent upon L/G ratio, solvent lean loading and blending solvent type. For the MEA-115°C, a minimum reboiler heat-duty as a function of L/G ratio is clearly observed and the Blended Amine 1–112°C has also shown a similar pattern. In contrast, Blended Amine 1–115°C showed excessive energy duty, which indicates unfavourable condition for this solvent. This is not the case for Blended Amine 2. It is observed that the reboiler heat duty decreases as stripper bottom temperature decreases, which in turn raises the lean loading for both MEA and Blended Amine 1. On the other hand, the lean loading of Blended Amine 2 in the temperature range examined did not affect the reboiler heat duty changes. The investigation also found that the magnitude of reboiler duty is decreasing following the order MEA>Blended Amine 1>Blended Amine 2.In order to obtain CO2 recovery of 85%, the Blended Amine 2–115°C (L/G=3.60) has similar reboiler duty relative to that of MEA-115°C with L/G ratio of 4.12. For the Blended Amine 1 (L/G=3.04), however, the reboiler heat duty increased by 51% at a similar temperature. The temperature reduction to 112°C decreased the reboiler heat duty of both Blended Amines 1 and 2 by 11% (L/G=4.01) and 14% (L/G=3.60) respectively. Further raising the CO2 recovery to 90–95%, in comparison to that of MEA at 115°C with L/G ratio of 4.20, the reboiler heat duty of Blended Amine 1 has risen by 49% (L/G=3.95) and of Blended Amine 2 dropped by 5% (L/G=3.52) under a similar temperature. At 112°C, the reboiler heat duty of Blended Amine 1 decreased by 18% (L/G=5.02). Blended Amine 2 may give a similar reboiler heat duty if run at a larger L/G ratio.Overall, the result of the MEA baseline and blending solvents has shown different behaviours of CO2 stripping. The distribution of the components of reboiler heat duty may explain this difference. For MEA, the condenser heat, which equals the heat needed for water evaporation, is a major contributor to the reboiler duty. For both Blended Amine solvents, the magnitude of sensible heat and the heat of CO2 desorption are more pronounced than the condenser heat. At the minimum reboiler duty reached by MEA and Blended Amine 1, the condenser heat share is lower than the other reboiler duty components. Therefore, further works involve optimisation of the PCC process with blended Amines and other blends.

Novel post-combustion capture technologies on a lignite fired power plant - results of the CO2CRC/H3 capture project

Commissioned in 2009, the CO2CRC/H3 Capture Project is demonstrating post-combustion carbon capture (PCC) on a lignite fired power plant in the Latrobe Valley, Victoria, Australia. The facility is located within International Power’s Hazelwood Power Plant and uses three different CO2 capture technologies — solvent, adsorption and membrane processes. This project, addressing the PCC issues specific for Victorian brown coal fired power stations, was initiated in July 2007 as a three year research project by the Cooperative Research Centre for Greenhouse Gas Technologies (CO2CRC) under the Victorian State Government’s Energy Technology Innovation Strategy (ETIS) program. The project is part of the Latrobe Valley Post Combustion Capture (LVPCC) Project — a multi site, multi scale, multi technology PCC trial. The integrated research and development program includes an evaluation of these technologies for commercial scale application. This paper describes the technologies used, how they have progressed from laboratory to pilot demonstration, the main outcomes, and plans for future developments.

Process integration analysis of a brown coal-fired power station with CO2 capture and storage and lignite drying

Abstract Integration of CO2 capture and storage (CCS) into existing and new coal fired power stations is seen as a way of significantly reducing the carbon emissions from stationary sources. A significant proportion of the estimated cost of CCS for post-combustion capture from coal-fired power stations is due to the additional energy expended to capture the CO2 and compress it for transport and storage. The additional energy either reduces the power plant output or creates additional CO2 which will increase the CCS requirements. Therefore, reductions in the overall energy penalty of CCS by improving the efficiency of both the carbon capture processes and the integration of the capture technology with the power plant can lead to significant reductions in the cost of CCS. Pre-drying lignite using low temperature heat sources enables power stations to increase their energy efficiency by the use of low grade heat, providing energy that is less carbon intensive and potentially reducing the cost of electricity production. This work reviews the current thinking for integration of CO2 capture plants using solvent absorption for postcombustion coal fired power stations. It also reviews the integration potential of brown coal dewatering processes to a power plant with CCS. The review uses as a basis a 200MWe(nominal) train of an existing pulverised brown coal fired power plant using heat and process integration techniques such as heat pinch analysis to determine the potential for reductions in capture cost by minimising the energy penalty associated with the addition of the CCS. The study shows that the energy penalty reduces from 39% for a CCS plant with no heat integration to 24% for a plant with effective heat integration. The energy penalty can be further reduced by the addition of pre-drying of the coal. This study shows there is potential to reduce the energy penalty associated with the addition of CCS, however the heat exchanger network and the required modifications to the existing equipment have not been determined and further work identifying these issues is required and these will have a large impact into whether the reductions suggested by this study can be economically implemented.

98/02429 Flue gas desulfurization scrubbers ‘2000’. A new generation of SO 2 absorbers for brown coal-fired power stations : Heiting, B. et al. VGB Kraftwerkstech., 1997, 77, (12), 1057–1067. (In German)

98/02429 Flue gas desulfurization scrubbers ‘2000’. A new generation of SO 2 absorbers for brown coal-fired power stations : Heiting, B. et al. VGB Kraftwerkstech., 1997, 77, (12), 1057–1067. (In German)

97/01422 Processing of fly ash from a captive power plant for use in PPC manufacture

Post-combustion capture (PCC) of CO2 from fossil fuel-fired power station flue gas is one of many technologies that are being developed to reduce anthropogenic greenhouse gas emissions in the medium term. Wet-gas scrubbing using aqueous amines is currently the most mature PCC technology suitable for separating CO2 from coal-fired power station flue gases. In this study, a series of twelve samples of a degraded 30% (w/w) MEA absorbent were obtained over a six month pilot scale PCC campaign at a brown coal-fired power station in Australia. These samples were used to investigate the accumulation of heat-stable salts, inorganics and minerals. The heat-stable salts concentration increased from 0.80 to 2.29% (w/w, as MEA) and organic acids from the oxidative degradation of MEA were the largest component of heat-stable salts. Acid gases such as SOx and NOx, make-up water, ultra-fine fly-ash and corrosion were all sources of the minerals and inorganics that accumulated in the aqueous MEA absorbent. Corrosion was the single biggest contributor of transition metals and the abrupt change in ratios of Fe, Cr and Mo suggests that the dominant corrosion mechanism may have changed towards the end of the campaign. The rapid accumulation of minerals and inorganics during this PCC campaign highlights the importance of continuing research into the interactions between amine absorbents and inorganic or mineral contaminants. The data presented in this study are an important resource for design of laboratory scale experiments to investigate these physical and chemical interactions between aqueous amines, minerals and inorganics.

96/06651 Modernization and flue gas cleaning at existing brown coal-fired power stations of VEAG (East Germany)

96/06651 Modernization and flue gas cleaning at existing brown coal-fired power stations of VEAG (East Germany)