Energy Penalty Reduction Research Articles

Proposal and thermodynamic investigation of pressurized calcium looping integrated with chemical looping combustion for tail-end CO2 capture in a retrofitted natural gas combined cycle power plant

The integration of tail-end calcium looping into an existing natural gas combined cycle (NGCC) power plant has minimal impact on CO2 capture retrofits. However, a high volume of flue gas needs to be preheated before entering the carbonator, and the relatively high energy consumption of oxygen production exacerbates the energy penalty of the NGCC system with tail-end CO2 capture. This paper proposes the method of pressurized calcium looping integrated with chemical looping combustion (PCaL-CLC). It employs the PCaL-CLC method to reduce the energy penalty and energy consumption of the NGCC system with tail-end CO2 capture. Results show that the proposed system using the PCaL-CLC method achieves a 3.0% reduction in energy penalty, decreasing from 9.1% in the reference system employing the calcium looping method to 6.1% in the proposed system. Besides, the specific energy consumption for CO2 avoided (SPECCA) declines from 4.43 MJLHV/kg CO2 to 2.76 MJLHV/kg CO2. Exergy analysis and energy utilization diagrams reveal the underlying reason for improving system performance. Furthermore, by optimizing the operating parameters of the gas turbine and equipping it with advanced heat recovery steam generation, an energy penalty of 2.9% and a SPECCA of 1.21 MJLHV/kg CO2 are achieved without CO2 compression, which is superior to those of amine scrubbing and hot-end calcium looping CO2 capture technologies. The proposed PCaL-CLC method offers an alternative approach to reducing the energy consumption of tail-end CO2 capture in existing natural gas combined cycle power plants.

Technical and economic performance assessment of blue hydrogen production using new configuration through modelling and simulation

Steam methane reforming (SMR) is the dominant process for hydrogen production, which produce large amount of carbon dioxide (CO2) as a by-product. To address concerns about carbon emissions, there is an increasing focus on blue hydrogen to mitigate carbon emissions during hydrogen production. However, the commercialization of blue hydrogen production (BHP) is hindered by the challenges of high cost and energy consumption. This study proposes a new configuration to address these challenges, which is characterized by: (a) the use of piperazine (PZ) as a solvent, which has a high CO2 absorption efficiency; (b) a more efficient heat exchange configuration which recovers the waste exergy from flue gas; (c) the advanced flash stripper (AFS) was adopted to reduce the capital cost due to its simpler stripper configuration. In addition, the technical and economic performance of the proposed energy and cost-saving blue hydrogen production (ECSB) process is investigated and compared with the standard SMR process. The detailed models of the SMR process and the post-combustion carbon capture (PCC) process were developed and integrated in Aspen plus® V11. The results of the technical analysis showed that the ECSB process with 30 wt.% PZ achieves a 36.3 % reduction in energy penalty when compared to the standard process with 30 wt.% Monoethanolamine (MEA). The results of the economic analysis showed that the lowest levelized cost of blue hydrogen (LCBH) was achieved by the ECSB process with 30 wt.% PZ. Compared to the BHP process with 30 wt.% MEA, the LCBH was reduced by 19.7 %.

Carbon capture in power sector of China towards carbon neutrality and its comparison to renewable power

CO2 capture from coal power plants is an important and necessary solution to realizing carbon neutrality in China, but CCS demonstration deployment in power sector is far behind expectations. Hence, the reduction potential of energy consumption and cost for CCS and its competitiveness to renewable powers are very important to make roadmaps and policies toward carbon neutrality. Unlike the popular recognition that capturing CO2 from flue gases is technically and commercially mature, this paper notes that it has been proved to be technically feasible but far beyond technology maturity and high energy penalty leads to its immaturity and therefore causes high cost. Additionally, the potential energy penalty reduction of capture is investigated thermodynamically, and future CO2 avoidance cost is predicted and compared to renewable power (solar PV and onshore wind power). Results show that energy penalty for CO2 capture can be reduced by 48%-57%. When installation capacity reaches a similar scale to that of solar PV in China (250 GW), CO2 capture cost in coal power plants can be reduced from the current 28-40 US$/ton to 10-20 US$/ton, and efficiency upgrade contributes to 67%-75% in cost reduction for high coal price conditions. In China, CO2 capture in coal power plants can be cost competitive with solar PV and onshore wind power. But it is worth noting that the importance and share of CCS role in CO2 emission reduction is decreasing since renewable power is already well deployed and there is still a lack of large-scale CO2 capture demonstrations in China. Innovative capture technologies with low energy penalties need to be developed to promote CCS. Results in this work can provide informative references for making roadmaps and policies regarding CO2 emission reductions that contribute towards carbon neutrality.

Combined carbon capture cycles: An opportunity for size and energy penalty reduction

One of the main technical difficulties in the design and dimensioning process of carbon capture and storage (CCS) systems is the proper utilization of the low temperature energy streams within the process. Rejecting these energy streams has a negative effect on both the process energy efficiency and the penalty of the CCS in industry or power plants. This is particularly important in oxyfuel and some post-combustion technologies such as amine scrubbing or Calcium-Looping.With the objective of reducing dimensions, energy penalty and capital costs of the CO2 capture systems, this study analyses and demonstrates the beneficial effects of splitting the CO2 capture in two cycles which operate at high (Ca-looping, Ca-L) and low temperature (amine impregnated solid sorbent, AISS). The latter (bottoming-carbon cycle) makes use of the waste energy from the high temperature capture cycle (topping-carbon cycle). Flue gas flow is split and each capture system treats a percentage of flue gas stream.This study quantifies the energy improvements derived from the combination of a topping and a bottoming CO2 capture system and analyses the required dimensions and the optimum flue gases split between both systems. Results show a reduction of energy penalty when 20–30% of the flue gas is diverted from the Ca-L to the AISS system if the AISS specific energy consumption for CO2 captured is between 2000 and 3000 kJ/kgCO2.

Pilot Plant in Dunkirk for Demonstrating the DMX TM Process

The DMXTM process developed by IFP Energies nouvelles (IFPEN) and licensed by Axens is a second-generation CO2 capture process using a phase change solvent. Experimentation on mini-pilots and techno-economic evaluation carried out within the OCTAVIUS & VALORCO projects have confirmed its potential in terms of reduction of energy penalty and operational costs for capturing CO2 respectively on coal power-station flue gases and blast furnace gas. So, DMXTM process is very promising but it needs now to be demonstrated in an industrial scale pilot plant. ArcelorMittal, IFPEN and Axens are now considering this demonstration at the steel mill operated by ArcelorMittal in Dunkirk (France). Capacity considered is 0.5 tCO2 capture/h which is sufficient to upscale CO2 capture on all the gas emitted by a blast furnace. This paper will present the process study carried out to optimise the design of the pilot plant but also the evaluation study based on this design. First experimentation plan will be also presented and explained. It will include a parametric study on absorption and regeneration pressure but also long test runs on real steel mill gas. Planning of the demonstration and expected commercialisation will be also discussed.

Amine-impregnated silicic acid composite as an efficient adsorbent for CO2 capture

A new high efficiency inorganic–organic composite solid sorbent was developed by the simple impregnation of aminoethylethanolamine (AEEA) on the nanoporous silicic acid (SiO(OH)2) for CO2 capture from flue gas. Experimental results revealed that amine loading amount, adsorption temperature, and moisture addition could greatly affect the CO2 adsorption capacity. At the optimal AEEA loading of 55 wt%, the CO2 sorption capacity reached a maximum value of 4.54 mmol/g at 25 °C under 10 vol% CO2and 10 vol% H2O. To the best of our knowledge, this is the first time that an AEEA based adsorbent has been reported as an efficient adsorbent for CO2 capture. The AEEA impregnated SiO(OH)2 also had good stability and reusability during cyclic adsorption/desorption tests, and the sorption capacity loss may be recovered by mixing condensed AEEA with cyclic sorbents. The Avrami’s fractional order kinetic model was applied for the kinetic analysis of CO2 adsorption and desorption on the optimized sorbent. The obtained activation energy for CO2 desorption was 33.5 kJ/mol. The estimated regeneration heat duty on the optimized AEEA sorbent was 53.29 kJ/mol CO2, a great energy penalty reduction compared to that of a typical aqueous monoethanolamine system.

Optimization and economic analysis of amine-based acid gas capture unit using monoethanolamine/methyl diethanolamine

In this work, process optimization and economic analysis of amine-based acid gas capture unit using monoethanolamine (MEA) and methyl diethanolamine (MDEA) blends have been carried out using Aspen Plus (version 8.8). Amine-based CO2 absorption technology is proposed in this study to be retrofitted into the power plant due to its high selectivity and high absorption capacity. However, the associated energy penalty to such technology is relatively high and energy intensive and exhibits process dynamic which necessitates more research to ensure a significant reduction in carbon capture costs achievable. The present work tackles these limitations by analysing the steady-state simulation via Aspen Plus (version 8.8) in determining the technical and economic parameters that make CO2 capture system more efficient, economic and less energy intensive. Optimization of the process was aimed towards minimal reboiler heat duty and maximum CO2 removal efficiency in having the least economic impact of the process. The optimal operating conditions resulted from this study were found to be at 30 °C (1 atm.) for the absorber and at 120 °C (2 atm.) for stripper. The methyl diethanolamine (MDEA) to monoethanolamine (MEA) ratio is fixed at 3:7 with 40 wt% of amine in the solvent. The results showed an increase of 5.5% in acid gas removal rate which resulted in 91.27% of CO2 removal rate as compared to the optimized parameters obtained by Tenaga Nasional Berhad Research’s (TNBR) pilot plant case study situated in Kajang, Selangor. A 300% reduction in energy penalty and heat duty cost is achieved when MEA/MDEA mixture is used instead of MEA alone, resulting in a more economic acid gas removal process with optimum operation. The results showed that this optimization successfully achieved significant energy saving whilst minimizing greenhouse gas emission bringing a significant beneficial environmental and economic impact.

Benchmarking of the DMXTM CO2 Capture Process

This paper presents the main results of Task 13.4 of the OCTAVIUS project dedicated to the benchmarking of DMXTM versus MEA 30 wt. % CO2 capture processes.In the introduction are given the main objectives of the FP7 Project OCTAVIUS, which ended in June 2016. In this first part are also presented the main characteristics of the DMXTM process developed by IFP Energies nouvelles (IFPEN) and licensed by PROSERNAT, which uses a phase change solvent.The benchmarking study takes into account the design and the optimal integration of the CO2 capture process within the power plant and the CO2 compression at 110 bara. The thermal integration has been realised by TUHH. The design and evaluation of the capture processes were carried out by IFPEN based on the results of mini–pilots experimentation within OCTAVIUS and of previous works. The comparison has been performed for a reference power plant (805 MWe coal power station) using criteria defined jointly with the industrial partners of the OCTAVIUS project.This techno-economic study confirms that the DMXTM process is very promising as it allows a reduction in energy penalty compared to the MEA reference process without Lean Vapour Compression by approximately 2% points. As a consequence, it gives lower Cost of Electricity and lower avoided CO2 cost: 42.6 €/tCO2 (56.5 €/tCO2 for the MEA reference process).The DMXTM process needs now to be demonstrated in an industrial scale pilot plant.

Enhancements in mass transfer for carbon capture solvents part II: Micron-sized solid particles

The mass transfer of CO2 into amine-based carbon capture solvents was improved with the addition of heterogeneous micron- and nano-sized particle additives. Enhancement in CO2 removal rate was determined in a stirred reactor with a flat steady gas-liquid interface and in a small packed-bed absorption column. The screening of several particle types in the stirred reactor indicated that carbon particles are best suited to enhance the rate of CO2 diffusion in 30wt.% monoethanolamine (MEA), and tests in the small packed-bed absorption column showed improved CO2 mass transfer in three solvents, MEA, piperazine (PZ), and hexanediamine (HDA), upon addition of nano-sized activated carbon particles. The enhancement of CO2 capture efficiency and KG increases with increasing solvent kinetics, in order of methyldiethanolamine (MDEA)<MEA<PZ<HDA, confirming the particle additives have a larger impact on kinetically faster, liquid-side diffusion limited, solvents. The combined benefits of the particle additives were then demonstrated on an absorption-desorption integrated bench-scale CO2 capture unit, in both MEA and the thermally stable advanced amine blend: 1-amino-2-propanol (A2P)/2-amino-2-methyl-1-propanol (AMP). The combined system translated to an overall 26% reduction in energy penalty for CO2 capture on the CAER Bench-scale unit.

Process Simulations of CO2 Desorption in the Interaction between the Novel Direct Steam Stripping Process and Solvents

Intensive energy consumption is one of the major challenges for large-scale implementation of amine-based CO2 chemical absorption processes. The study of diverse typical solvents in a novel process can effectively exploit the potential of energy saving to the utmost. This work focuses on the optimization of a novel direct steam stripping process using three typical solvents, monoethanolamine (MEA), 2-amino-2-methyl-1-propanol (AMP), and piperazine (PZ). A rate-based model was established to investigate the regeneration process. The direct steam stripping process exhibits 20–30% reduction in energy penalty for different solvents. Detailed information on the concentration and pressure profiles along the stripping column was presented in the direct steam stripping process. There is a strong flash process at the top of the column, which results in an enormous reduction of the latent heat. Therefore, using MEA as the absorbent shows the best performance on reducing energy penalty as a result of its best proper...

Optimisation of Operational Parameter and Economic Analysis of Amine Based Acid Gas Capture Unit

Electricity demand in Malaysia has been projected to escalate and this has led to additional coal-fired power plants being built. Combustion of coal has released greenhouse gases such as CO2 into the atmosphere. It is predicted that CO2 emission from coal fired power plants will grow 4.1 % annually to reach 98 Mt by 2020. Greenhouse gases like CO2 is claimed to be the root of global warming, closely related to the verdict of 2 °C increase in global temperature. To resolve this issue, amine unit has been integrated into the power plant for acid gas removal. Amine is highly preferred due to its characteristic of high selectivity. The drawbacks of this technology are costly operation, energy intensive and exhibits process dynamic. Detailed process simulation utilising Aspen Plus is able to optimise the process and overcome these limitations. In steady state simulation, the optimal operating conditions of absorber and stripper are found. Absorber should be operated at 30 °C (1 atm), while stripper at 120 °C (2 atm). The MDEA to MEA ratio is fixed at 3 : 7 with 40 wt% of amine in the solvent. By comparing the optimised parameters to TNBR’s result, acid gas removal rate showed an increment of 5.5 % which resulted in 91.27 % of CO2 removal rate. 300 % reduction in energy penalty and heat duty cost are achieved when MEA/MDEA is used instead of MEA. A more economical and feasible acid gas removal process with optimum operation is achieved. This has provided better insight for large scale implementation of amine unit in industries with low energy penalty.

Membrane evaporation of amine solution for energy saving in post-combustion carbon capture: Wetting and condensation

A membrane evaporation system for energy penalty reduction in liquid absorbent based carbon capture and the effects of operating parameters (i.e. evaporation temperature, and gas/liquid flow rates) on mass and heat transfer are systematically investigated. It is found that monoethanolamine (MEA) vapor flux is approximately one order of magnitude lower than water vapor flux for membrane evaporation of 30wt% MEA solution. Heat flux across the membrane is closely associated with mass transfer and is also influenced by the evaporation efficiency. Experimental results show that membrane wetting and vapor condensation occurs during the evaporation of MEA solution. Both evaporation temperatures and liquid flow rates play important roles in membrane wetting via changing the pressure on the liquid side. Slight wetting may decrease both mass transfer and the associated convective heat transfer across the membrane, but it can also provide benefit by preventing CO2 absorption into the lean solvent. The occurrence of vapor condensation on the gas side is determined by the gas flow rate. Vapor condensation occurs at low gas flow rates but it will not be a significant operational issue in the membrane evaporator application as long as condensation occurs within the desorber where the latent heat is released and recovered.

Membrane evaporation of amine solution for energy saving in post-combustion carbon capture: Performance evaluation

In this study, we propose a membrane evaporation system for energy penalty reduction in post-combustion carbon capture (PCC) and carry out membrane evaporation of amine solutions. The effects of some key factors (i.e. evaporation temperature, gas and liquid flow rates and solvent concentration) on mass and heat transfer are systematically investigated. It is found that both evaporation temperature and gas flow rates have significant influences on vapor and heat transfer, while liquid flow rates have limited effect on mass and heat transfer in membrane evaporation. The vapor and recovered heat fluxes increase exponentially with the rise in evaporation temperature, and increase linearly with the rise in gas flow rates. The increase in evaporation temperature and gas flow rates also significantly improves the evaporation efficiency and heat recovery. Mass and heat transfer rates decrease as the concentration of the solvent increases because of the reduced vapor pressure of the liquid at higher concentration. It is estimated that the recovered heat flux can be up to 32MJm−2h−1 and heat recovery can be over 40% when the gas/liquid flow rate ratio is 150. Therefore, the proposed membrane evaporation system has great potential to save considerable energy in large-scale PCC pilot plant operation.

Process integration of solar thermal energy with natural gas combined cycle carbon capture

This project investigates the energy cost of CO2 capture for NGCC (natural gas combined cycle) power plants and studies the effect of solar thermal energy on the energy penalty for such a system.The gas turbine used in this study is the ALSTOM GT26. Alongside the standard case, other cases include an EGR (exhaust gas recirculation) and a pre-combustion case that utilises EGR with the capture taking place after the compression stage of the gas turbine. The solar thermal technology used in these simulations is a solar tower system capable of reaching 1000 °C. The integration of the solar energy is used to provide heat to the first of the two combustion chambers in the gas turbine. Cases are optimized for 75% capture.For a NGCC it was found that using EGR decreased the specific energy penalty as well as capture energy penalty. The pre-combustion case showed a reduction in the energy penalty over the standard and EGR cases but at a reduced capture rate. The addition of solar thermal shows a reduction in the total energy penalty. This is due to a reduction in the total CO2 produced in the system, hence a reduction in the total CO2 captured.

Heat integration and exergy analysis for a supercritical high-ash coal-fired power plant integrated with a post-combustion carbon capture process

The International Energy Agency (IEA) has recommended eliminating at least 80% of the CO2 emission from the power sector by 2050 as a response to climate change. Meeting this target is expected to be challenging since a lion’s share of the power generation is based upon coal combustion. A cost effective strategy to decarbonise the power sector would require carbon capture and storage, largely through a post-combustion capture (PCC). In this study, a model of the supercritical coal-fired power plant (CFPP) fed with a high-ash coal was developed and validated, a validated model of a PCC pilot plant using monoethanolamine (MEA) solvent is scaled-up to meet the CFPP capacity, a CO2 compression unit model was developed to fully assess the energy penalty, and the three models were integrated for a 90% capture level. This required determination of the PCC steam requirement and identification of the optimal condensate return location. The performance of the integrated models was compared with the reference CFPP model (with a net efficiency of 39.1%), and the energy penalty was estimated to cause a 25% fall in the CFPP power output. Then, energy saving opportunities were investigated through the heat exchanger network (HEN) analysis. Several HEN designs were analysed, revealing that heat can be recovered from the flue gas leaving the CFPP, and used to heat up boiler feedwater to enhance the plant efficiency. Such a configuration resulted in reduction of energy penalty by 4.15%, improving the performance of the integrated plant. Finally, it is inferred from the exergy analysis that further energy savings can be achieved by reducing the exergy destruction in the PCC.

Performance assessment of first generation oxy-coal power plants through an exergy-based process integration methodology

In this study, an exergy-based system level methodology is conducted to assess the energy penalty reduction potential of different configurations of first generation oxy-fired pulverized coal power plants. Once the process improvement potential is identified by exergy analysis on an oxy-fired plant with minimal integration, a heat integration methodology minimizing the exergy losses is carried out. Exergy analysis is employed as a guideline weighted by technological and operational constraints.This methodology has been applied to study the conventional cold flue gas recycle scheme and three alternative flue gas recirculation options including the widely studied warm recycle scheme. The integration potential of advanced cryogenic ASUs (air separation units) has also been assessed. Finally, the energy penalty associated to the capture when a high-purity CO2 flow is required has been determined.Among the different cases considered in this study, recirculation of the flue gas before the regenerative heater with an advanced ASU and a double-column CPU (compression and purification unit) leads to the highest NPE (net plant efficiency). For this case, the NPE is 39.1 % based on the lower heating value (7 %-pts energy penalty), which corresponds to a 6.5% improvement compared to the base-case plant. When high-purity CO2 is desired, the energy penalty is increased by 0.2 %-pts for the same configuration.

Utilisation Of Microwave Energy for CO2 Desorption in Post-combustion Carbon Capture Using Solid Sorbents

Abstract One of the most promising technologies for CO 2 capture is adsorption using solid sorbents, with the most important advantage being the energy penalty reduction during capture and regeneration of the material compared to liquid absorption. Nevertheless, the challenge in this application remains the same, namely to intensify the production of a high purity CO 2 stream in terms of adsorption/desorption rates and energy use while preserving the textural characteristics of the sorbents. Towards this target, a new adsorption system is proposed in this research, namely Microwave Swing Adsorption (MSA), which takes advantage of the different heating procedure that electromagnetic energy can provide. Results showed that microwaves are able to enhance the rate of CO 2 desorption from the sorbent, contributing to a four times faster overall desorption process, compared to conventional heating desorption. It was also proved that the solid sorbent's CO 2 adsorption capacity is also well preserved, without any significant reduction even after 20 adsorption/desorption cycles.

Towards Second Generation Oxy-pulverized Coal Power Plants: Energy Penalty Reduction Potential of Pressurized Oxy-combustion Systems

During the last decade, CO2 capture on coal power plants has been the subject of sustained attention as one of the most credible way to drastically reduce anthropogenic greenhouse gas emissions. Significant reduction in the energy penalty related to the oxy- combustion routes has been achieved but uncertainties remain in the operation of such a process inducing major modifications of the power island. In this context, for oxy-combustion, and more generally carbon capture to become a reality, its energy penalty shall be drastically reduced. In that perspective, cutting edge strategies allowing taking full advantage of oxy-fired operation have to be investigated. Among them, boiler pressurization has been identified as one of the most promising solution. Two major pressurized oxy-combustion concepts have emerged in literature: the flameless combustion technology (ISOTHERM®) and the staged-pressurized oxy-combustion (SPOC) concept. According to the authors describing those two processes, whilst very different in the combustion temperature control strategy, they both succeed in allowing pressurized operation. In this work, those two concepts have been compared to an air-fired, a conservative and optimized atmospheric oxy-fired power plants in terms of energy performances. The reason underlying below the observed differences, have been determined using exergy analysis. The SPOC process leads to significantly lower energy penalty, as low as 3.8%-pts compared to the ISOTHERM® concepts which lead to performance in the same order of magnitude than the optimized atmospheric design. It has been highlighted that this difference is essentially due to the large flue gas recycling requirement for the latter concept to control combustion temperature.

Lime enhanced biomass gasification. Energy penalty reduction by solids preheating in the calciner

Abstract Hydrogen is expected to be one of the most important energy carriers in the future. Gasification process may be used to produce hydrogen when joined with carbon capture technologies. Furthermore, the combination of biomass gasification and carbon capture presents a significant technical potential in net negative greenhouse gas emissions. Lime enhanced biomass gasification process makes use of CaO as a high temperature CO2 carrier between the steam biomass gasifier and an oxy-fired regenerator. Important energy penalties derive from the temperature difference between the reactors (around 250–300 °C). A cyclonic preheater similar to those used in the cement industry may improve the energetic efficiency of the process if the particles entering the regenerator reactor are heated up by the gas leaving this reactor. A lime enhanced biomass gasification system was modelled and simulated. A cyclonic preheater was included to evaluate the improvement. Results show an increase of the gasification chemical efficiency and a reduction of the energy consumption in the regenerator.

Energy penalty reduction in the calcium looping cycle

Despite the interest of carbon capture and storage research on the calcium looping cycle due to the potentially low CO2 avoided cost this technology offers, there is a need to keep on reducing both cost and system size to ensure the economic advantage of this technology. This work presents three novel calcium looping configurations designed with the objective of decreasing the fuel consumption in the regeneration reactor and the energy requirements in the air separation unit. Available heat from the solid and gaseous streams leaving the calciner is used to heat up the particles before entering this reactor. These systems are thermodynamically modelled and their thermal efficiencies and available energy flows analyzed to establish which configuration has the higher coal and oxygen consumption saving potential. The configuration that includes an extra heat recovery bed to exchange heat between the CO2 stream and the solid particles entering the calciner presents the lowest coal and fresh sorbent consumption in the regeneration step. As a consequence, smaller system size and operational cost may be achieved with this configuration. Since fuel requirements are reduced, so does the oxygen demand from the air separation unit which will introduce less energy penalties associated to its high specific electrical consumption.