Optimization of the various modes of flexible operation for post-combustion CO2 capture plant

One option to mitigate the adverse effect of power plant output loss from adding a CO₂ capture plant is to operate it in flexible modes in which the capture level and/or regeneration rate are dynamically varied in response to varying electricity market demand and price. This can help the plant meet peak electricity demand and improve its overall profit. However, the benefit is offset by higher capital costs and/or CO₂ emission penalty. Various modes of flexible operation including capture level reduction and solvent storage have been optimized for a given post-combustion capture system with typical daily electrical energy price patterns and the results are compared with those from a fixed point operation. Effects of varying storage capacities and energy price patterns have also been evaluated. Simultaneous use of the two flexible modes is also optimized and the result showed significantly higher cost savings compared to the individual uses.     

Partial O2-fired coal power plant with post-combustion CO2 capture: A retrofitting option for CO2 capture ready plants

In the work presented in this paper, an alternative process concept that can be applied as retrofitting option in coal-fired power plants for CO₂ capture is examined. The proposed concept is based on the combination of two fundamental CO₂ capture technologies, the partial oxyfuel mode in the furnace and the post-combustion solvent scrubbing. A 330 MW_el Greek lignite-fired power plant and a typical 600 MW_el hard coal plant have been examined for the process simulations. In a retrofit application of the ECO-Scrub technology, the existing power plant modifications are dominated by techno-economic restrictions regarding the boiler and the steam turbine islands. Heat integration from processes (air separation, CO₂ compression and purification and the flue gas treatment) can result in reduced energy and efficiency penalties. In the context of this work, heat integration options are illustrated and main results from thermodynamic simulations dealing with the most important features of the power plant with CO₂ capture are presented for both reference and retrofit case, providing a comparative view on the power plant net efficiency and energy consumptions for CO₂ capture. The operational characteristics as well as the main figures and diagrams of the plant’s heat balances are included.     

Impact of liquid absorption process development on the costs of post-combustion capture in Australian coal-fired power stations

Australian power generators produce approximately 170 TWh per annum of electricity using black and brown coals that accounts for 170 Mtonne of CO₂ emissions per annum or over 40% of anthropogenic CO₂ emissions in Australia. This paper describes the results of a techno-economic evaluation of liquid absorption based post-combustion capture (PCC) processes for both existing and new pulverised coal-fired power stations in Australia. The overall process designs incorporate both the case with continuous capture and the case with the flexibility to switch a CO₂ capture plant on or off depending upon the demand and market price for electricity, and addresses the impact of the presently limited emission controls on the process cost. The techno-economic evaluation includes both air and water cooled power and CO₂ capture plants, resulting in cost of power generation for the situations without and with PCC. Whilst existing power plants in Australia are all water cooled sub-critical designs, the new power plants are deemed to range from supercritical single reheat to ultra-supercritical double reheat designs, with a preference for air-cooling. The process evaluation also includes a detailed sensitivity analysis of the thermodynamic properties of liquid absorbent for CO₂ on the overall costs. The results show that for a meaningful decrease in the efficiency and cost penalties associated with the post combustion CO₂ capture, a novel liquid sorbent will need to have heat of absorption/desorption, sensible heat and heat of vaporisation around 50% less in comparison with 30% (w/w) aqueous MEA solvent. It also shows that the impact of the capital costs of PCC processes is quite large on the added cost of generation. The results can be used to prioritise PCC research in an Australian context.     

Initial evaluation of the impact of post-combustion capture of carbon dioxide on supercritical pulverised coal power plant part load performance

Pulverised coal-fired plants often play an important role in electricity grids as mid-merit plants that can operate flexibly in response to changes in supply and demand. As a consequence, these plants are required to operate over a wide output range. This paper presents an initial evaluation of some potential impacts of adding post-combustion CO₂ capture on the part load performance of pulverised coal-fired plants. Preliminary results for ideal cases analysed using a simple high-level model indicate that post-combustion CO₂ capture could increase the options available to power plant operators. In particular, solvent storage could allow higher effective plant load factors to be achieved to assist with capital recovery while still permitting flexible operation for grid support. A number of areas for more detailed analysis are identified.     

Integration of a chemical process model in a power plant modelling tool for the simulation of an amine based CO2 scrubber

Post-combustion is considered among the different options for CO₂ capture as the most mature available technology. All major components of the CO₂ absorption/desorption process are commercially available but at a smaller scale, and they are not integrated and optimized for the application in power plants. Therefore, it is still to be demonstrated that this process is a viable option for the capture of CO₂ at power plants. The amine scrubbing process with standard solvents is highly energy demanding due to solvent regeneration and CO₂ compression. This is a significant energy sink for the power plant and efficiency can be reduced up to 16%-points. In order to minimise the energy penalty, complete integration and optimization of the capture and the power plant processes are necessary.Simulations of the power plant cycle and the amine scrubbing system have been performed with specialized software. The results of the integration are discussed.     

The multi-period optimisation of an amine-based CO2 capture process integrated with a super-critical coal-fired power station for flexible operation

In this work, we present a model of a super-critical coal-fired power plant integrated with an amine-based CO₂ capture process. We use this model to solve a multi-period dynamic optimisation problem aimed at decoupling the operation of the power plant from the efficiency penalty imposed by the CO₂ capture plant, thus providing the power plant sufficient flexibility to exploit price variation within an electricity market. We evaluate four distinct scenarios: load following, solvent storage, exhaust gas by-pass and time-varying solvent regeneration. The objective is to maximise the decarbonised power plant's short run marginal cost profitability. It is found that while the solvent storage option provides a marginal improvement of 4% in comparison to the load following scenario, the exhaust gas bypass scenario results in a profit reduction of 17% whereas the time-varying solvent regeneration option increases the profitability of the power plant by 16% in comparison to the reference scenario.     

Influence of process operating conditions on solvent thermal and oxidative degradation in post-combustion CO2 capture

The CO₂ post-combustion capture with amine solvents is modeled as a complex system interconnecting process energy consumption and solvent degradation and emission. Based on own experimental data, monoethanolamine degradation is included into a CO₂ capture process model. The influence of operating conditions on solvent loss is validated with pilot plant data from literature. Predicted solvent consumption rates are in better agreement with plant data than any previous work, and pathways are discussed to further refine the model. Oxidative degradation in the absorber is the largest cause of solvent loss while thermal degradation does not appear as a major concern. Using a single model, the process exergy requirement decreases by 10.8% and the solvent loss by 11.1% compared to our base case. As a result, this model provides a practical tool to simultaneously minimize the process energy requirement and the solvent consumption in post-combustion CO₂ capture plants with amine solvents.     

Post-combustion CO2 capture with chemical absorption: A state-of-the-art review

Global concentration of CO₂ in the atmosphere is increasing rapidly. CO₂ emissions have an impact on global climate change. Effective CO₂ emission abatement strategies such as Carbon Capture and Storage (CCS) are required to combat this trend. There are three major approaches for CCS: post-combustion capture, pre-combustion capture and oxyfuel process. Post-combustion capture offers some advantages as existing combustion technologies can still be used without radical changes on them. This makes post-combustion capture easier to implement as a retrofit option (to existing power plants) compared to the other two approaches. Therefore, post-combustion capture is probably the first technology that will be deployed. This paper aims to provide a state-of-the-art assessment of the research work carried out so far in post-combustion capture with chemical absorption. The technology will be introduced first, followed by required preparation of flue gas from power plants to use this technology. The important research programmes worldwide and the experimental studies based on pilot plants will be reviewed. This is followed by an overview of various studies based on modelling and simulation. Then the focus is turned to review development of different solvents and process intensification. Based on these, we try to predict challenges and potential new developments from different aspects such as new solvents, pilot plants, process heat integration (to improve efficiency), modelling and simulation, process intensification and government policy impact.     

FAU zeolite membranes for dewatering of amine-based post-combustion CO2 capture solutions

In amine-based CO₂ capture processes, aqueous amine solvent is circulated between absorber (CO₂ absorption) and stripping (solvent regeneration) columns. To reduce solvent regeneration energy demand, a selective membrane can dewater and enrich the CO₂ concentration in solution prior to the stripper, lowering steam requirements for solution heating. In this work, a facile synthesis strategy was developed to prepare faujasite (FAU) zeolite membranes built upon polydopamine (PDA) modified α-Al₂O₃ substrates. PDA facilitated the attachment of zeolite phases onto the substrate surface to form a 3 μm membrane layer. Membrane permeation flux of 4.45 kg m⁻² h⁻¹ and 95% rejection rate calculated by either CO₂ loading or total alkalinity was achieved in dewatering of CO₂ loaded 30 wt% monoethanolamine (MEA) solution. The effects of temperature on membrane dewatering performance and stability were investigated. This study highlights the potential for process integration of membrane technology in amine-based post-combustion CO₂ capture operations.     

CO2 capture in a multistage CFB: Part I: Number of stages

The most common technology for postcombustion of CO₂ capture is the amine solvent scrubber. The energy consumption for capturing CO₂ from flue gases using amine solvent technology is 15–30% of the power plant electricity production. Hence, there is a need to develop more efficient methods of removing CO₂. A circulating fluidized bed using sodium or potassium carbonates is potentially such a process, as their high decomposition pressures allow regeneration at low temperatures using waste heat rather than steam from the power plant. But equilibrium data for the sorbents require the use of several cooled stages to achieve high CO₂ conversions. Here, a method of computing such a number of stages for a given CO₂ conversion was developed using multiphase computational fluid dynamics. It was found that it required six equilibrium stages to remove 96% of CO₂ with the initial mole fraction of 0.15 in a sorption riser. © 2017 American Institute of Chemical Engineers AIChE J, 63: 5267–5279, 2017     

Intensification of low temperature thermomorphic biphasic amine solvent regeneration for CO2 capture

High-energy requirements for solvent regeneration represent one of the main challenges in the conventional post-combustion capture (PCC) process. Thermomorphic biphasic solvent (TBS), comprising lipophilic amines as the active components, exhibit a liquid–liquid phase separation (LLPS) upon heating, giving rise to extractive behaviour, and thus enhancing desorption at temperatures well below the solvent boiling point. The low regeneration temperature of less than 90 °C together with the high cyclic CO₂ loading capacity, 3–4 mol/kg, of such TBS system permits the use of low temperature and even waste heat for desorption purposes. In order to improve the solvent regeneration process and reduce the commensurate energy demand still further, desorption experiments with various techniques for enhancing CO₂ release in place of gas stripping, such as nucleation, agitation, ultrasonic method, etc., were studied at temperatures in the range of 75–85 °C. Nucleation and agitation both accelerate CO₂ desorption, but regenerability by nucleation only achieves 70–85%, while by agitation attains 80–95%. Ultrasonic desorption also intensifies the solvent regeneration and superior to conventional stripping process. The energy consumption for TBS system with those intensification techniques is only half of that for alkanolamine-based process with steam stripping. Extractive regeneration is another potential method to substitute for stripping and reduce the exergy demands. An extraction process using inert solvent was developed for improving the regeneration efficiency and elevated pressures were applied for reducing the significant volatile solvent loss.     

Comparison of solvent performance for CO2 capture from coal-derived flue gas: A pilot scale study

The performance of a proprietary solvent (CAER-B2), an amine-carbonate blend, for the absorption of CO₂ from coal-derived flue gas is evaluated and compared with state-of-the-art 30 wt% monoethanolamine (MEA) under similar experimental conditions in a 0.1 MWth pilot plant. The evaluation was done by comparing the carbon capture efficiency, the overall mass transfer rates, and the energy of regeneration of the solvents. For similar carbon loadings of the solvents in the scrubber, comparable mass transfer rates were obtained. The rich loading obtained for the blend was 0.50 mol CO₂/mol amine compared to 0.44 mol CO₂/mol amine for MEA. The energy of regeneration for the blend was about 10% lower than that of 30 wt% MEA. At optimum conditions, the blend shows promise in reducing the energy penalty associated with using industry standard, MEA, as a solvent for CO₂ capture.     

Optimal design for flexible operation of the post-combustion CO2 capture plant with uncertain economic factors

The ultimate benefit of flexible operation of the post-combustion CO₂ capture (PCC) plant depends on the ability to optimally balance between many competing factors, including the additional capital investment and operating cost savings. In this work, a large number of scenarios are constructed by considering combinations of possible realizations of the uncertain economic factors such as energy cost profile, emission penalty and value of captured CO₂. Then, the design choices like the size of the storage tanks and the regeneration capacity are optimized by minimizing an overall cost averaged over all the scenarios. The optimal design problem is naturally formulated as a two-stage stochastic program. This multi-scenario optimal design is compared with the design that minimizes the overall cost for just a single nominal scenario as well as the design that minimizes the cost averaged over the worst-case scenarios.     

The calcium looping cycle for CO2 capture from power generation, cement manufacture and hydrogen production

Calcium looping is a CO₂ capture scheme using solid CaO-based sorbents to remove CO₂ from flue gases, e.g., from a power plant, producing a concentrated stream of CO₂ (∼95%) suitable for storage. The scheme exploits the reversible gas-solid reaction between CO₂ and CaO(s) to form CaCO₃(s). Calcium looping has a number of advantages compared to closer-to-market capture schemes, including: the use of circulating fluidised bed reactors—a mature technology at large scale; sorbent derived from cheap, abundant and environmentally benign limestone and dolomite precursors; and the relatively small efficiency penalty that it imposes on the power/industrial process (i.e., estimated at 6-8 percentage points, compared to 9.5-12.5 from amine-based post-combustion capture). A further advantage is the synergy with cement manufacture, which potentially allows for decarbonisation of both cement manufacture and power production. In addition, a number of advanced applications offer the potential for significant cost reductions in the production of hydrogen from fossil fuels coupled with CO₂ capture. The range of applications of calcium looping are discussed here, including the progress made towards demonstrating this technology as a viable post-combustion capture technology using small-pilot scale rigs, and the early progress towards a 2 MW scale demonstrator.     

Techno-economic evaluation of a PVAm CO2-selective membrane in an IGCC power plant with CO2 capture

Published data for an operating power plant, the ELCOGAS 315 MWe Puertollano plant, has been used as a basis for the simulation of an integrated gasification combined cycle process with CO₂ capture. This incorporated a fixed site carrier polyvinylamine membrane to separate the CO₂ from a CO-shifted syngas stream. It appears that the modified process, using a sour shift catalyst prior to sulphur removal, could achieve greater than 85% CO₂ recovery at 95 vol% purity. The efficiency penalty for such a process would be approximately 10% points, including CO₂ compression. A modified plant with CO₂ capture and compression was calculated to cost €2320/kW, producing electricity at a cost of 7.6 € cents/kWh and a CO₂ avoidance cost of about €40/tonne CO₂.     

Economic implications of oxyfuel application in a lignite-fired power plant

Scope of the work presented in this paper is to examine and evaluate the application of the oxyfuel combustion CO₂ capture technology in a lignite-fired power plant from an economic point of view. Results from simulations dealing with the most important features for CO₂ reduction are performed. The operational characteristics, the efficiency penalties as well as the net efficiency reduction emerging from the Greenfield application of the oxyfuel technology are presented.CO₂ capture costs and the energy requirements associated with the oxyfuel method affect significantly the cost of electricity. This paper focuses on the analysis of the techno-economic factors that result in the increase of the cost of electricity in comparison with the conventional air-fired power plant. For this reason a typical Greek lignite power plant is used as a reference case. Any technical, economic and financial assumptions applied provide a common basis for both power plants (i.e., conventional and oxyfuel) for the assessment of the change of the cost of electricity and the CO₂ capture cost. The oxyfuel simulations are performed by taking into account the adoption of measures for the exploitation of heat that would otherwise be wasted. Such measures concern both the water/steam cycle and the gas flows (e.g., the oxygen flow). Heat integration from processes - such as the air separation, the CO₂ compression and purification and the flue gas treatment - is adopted in order to lower as much as possible the efficiency penalty.The cycle calculations have been performed using the thermodynamic cycle calculation software ENBIPRO (ENergie-BIllanz-PROgram). ENBIPRO is a powerful tool for heat and mass balance solving of complex thermodynamic circuits, calculation of efficiency, exergetic and exergoeconomic analysis of power plants. The software code models all pieces of equipment that usually appear in power plant installations and can accurately calculate all thermodynamic properties (temperature, pressure, enthalpy) at each node of the thermodynamic circuit, power consumption of each component, flue gas composition, etc. The code has proven its validity by accurately simulating a large number of power plants and through comparison of the results with other commercial software (Stamatelopoulos GN. Calculation and optimisation of power plant thermodynamic cycles. VDI-Regulations. Series 6, No. 340. Braunchweig, Mechanical Engineering Department; 1996 [in German]).     

Carbon capture from natural gas combined cycle power plants: Solvent performance comparison at an industrial scale

Natural gas is an important source of energy. This article addresses the problem of integrating an existing natural gas combined cycle (NGCC) power plant with a carbon capture process using various solvents. The power plant and capture process have mutual interactions in terms of the flue gas flow rate and composition vs. the extracted steam required for solvent regeneration. Therefore, evaluating solvent performance at a single (nominal) operating point is not indicative and solvent performance should be considered subject to the overall process operability and over a wide range of operating conditions. In the present research, a novel optimization framework was developed in which design and operation of the capture process are optimized simultaneously and their interactions with the upstream power plant are fully captured. The developed framework was applied for solvent comparison which demonstrated that GCCmax, a newly developed solvent, features superior performances compared to the monoethanolamine baseline solvent. © 2015 American Institute of Chemical Engineers AIChE J, 62: 166–179, 2016     

Simulations of Membrane Gas Separation: Chemical Solvent Absorption Hybrid Plants for Pre- and Post-Combustion Carbon Capture

Solvent absorption and membrane gas separation are two carbon capture technologies that show great potential for reducing emissions from stationary sources such as power plants. Here, plants combining chemical solvent absorption and membrane gas separation are considered for post-combustion capture as well as pre-combustion capture. In all ASPEN HYSYS simulations the membrane stage initially concentrates CO₂ into either the permeate or the retentate stream, which is then passed to a monoethanolamine (MEA) based solvent absorption process. In particular, post-combustion capture scenarios examined a membrane that is selective for CO₂ against N₂, while for the pre-combustion scenario a H₂-selective membrane was studied. It was found the energy demand of the combined hybrid plant was always more than that of a stand alone MEA solvent process. This was mainly due to the need to generate a pressure driving force upstream of the membrane in the post-combustion scenario or to recompress downstream gas streams in the pre-combustion scenarios. For both scenarios concentrating the CO₂ in the feed to the solvent system reduced the absorber column height and diameter, which could represent a CAPEX saving for the hybrid plant, dependent upon the membrane price. The use of a hydrogen selective membrane downstream of an oxygen fired gasifier was identified as the most prospective scenario, as it led to significant reductions in absorber size, for a relatively small membrane area and energy penalty.     

A NGCC power plant with a CO2 post-combustion capture option. Optimal economics for different generation/capture goals

Fossil fuel power plants are one of the major sources of electricity generation, although invariably release greenhouse gases. Due to international treaties and countries regulations, CO₂ emissions reduction is increasingly becoming key in the generators’ economics. NGCC power plants constitute a widely used generation technology, from which CO₂ capture through a post-combustion and MEA absorption option constitutes a technological challenge due to the low concentration of pollutants in the flue gas and the high energy requirements of the sequestration process.     

Techno-economic modelling and cost functions of CO2 capture processes

The paper presents the techno-economic modelling of CO₂ capture process in coal-fired power plants. An overall model is being developed to compare carbon capture and sequestration options at locations within the UK, and for studies of the sensitivity of the cost of disposal to changes in the major parameters of the most promising solutions identified. Technological options of CO₂ capture have been studied and cost estimation relationships (CERs) for the chosen options calculated. Created models are related to the capital, operation and maintenance cost. A total annualised cost of plant electricity output and amount of CO₂ avoided have been developed. The influence of interest rates and plant life has been analysed as well. The CERs are included as an integral part of the overall model.