Solvent Circulation Rate Research Articles

Comparative studies of heat duty and total equivalent work of a new heat pump distillation with split flow process, conventional split flow process, and conventional baseline process for CO2 capture using monoethanolamine

Two absorption/stripping process configurations, namely a new heat pump distillation with split flow process (HPDSFP) and split flow process with an overhead heat exchanger, were evaluated to minimize the energy consumption of CO2 capture from a 300MW power plant flue gas using 30wt% aqueous monoethanolamine (MEA). Their performances were compared with that of the baseline MEA process. All the processes were simulated using ProMax3.2 program. A rigorous model built on SWEET kinetics of ProMax was used to simulate the exothermic, reversible chemical reactions in MEA-CO2 system in the absorption/regeneration process. Sensitivity analyses were performed to evaluate the effects of key parameters (e.g. solvent circulation rate and lean CO2 loading) on energy requirement. Comparison of the HPDSFP, the split feed process with an overhead heat exchanger and the baseline process was conducted in terms of total equivalent work. In this work, the minimal total equivalent works of HPDSFP, the split flow process and baseline process were 0.37, 0.50 and 0.56GJ/tCO2, respectively. The simulation results showed that the new process configuration HPDSFP and split flow process with an overhead heat exchanger resulted in large improvements with reductions of total equivalent work by 10.7% and 33.9%, respectively.

Advanced Amine Process Technology Operations and Results from Demonstration Facility at EDF Le Havre

Abstract Alstom Power and The Dow Chemical Company have jointly developed an Advanced Amine Process (AAP) utilizing Dow's advanced amine solvent formulation UCARSOL™ FGC-3000 for the capture of CO2 from fossil fuel power plant-generated flue gas. This development effort includes the use of facilities to address operational issues such as energy efficiency and solvent management, along with environmental factors such as emissions and wastes. A new demonstration facility has been constructed in Le Havre, France, through a partnership between Alstom and Electricite de France (EDF) with support from ADEME, the French Environment and Energy Management Agency. This facility is designed to capture 25 tonnes of CO2/day at a 90% capture rate on a slip- stream flue gas from a hard coal-fired power plant. The EDF-Le Havre demonstration plant is equipped with flue gas conditioning for controlling the water content, temperature and SOx level of the incoming flue gas stream. The CO2 absorber column contains structured packing selected for optimal CO2 capture efficiency and fluid flow characteristics. The exiting flue gas passes through a water wash section designed to capture residual amine emissions. Amine solvent management comprises an amine reclamation system and assisted by an on-site amine solvent analytical laboratory. The quality of the incoming flue gas, the exiting flue gas and CO2 product gas streams are assessed through various gas sample locations in the pilot plant. Amine solvent sampling is available at various locations throughout the amine circulation loop as well as the liquid discharge locations for waste assessment. Additionally, the EDF facility is also equipped with an oxygen stripper to study the impact on solvent degradation. The current status of the Alstom Advanced Amine Process at EDF will be discussed in this paper. The presented results include the performance of the UCARSOL™ FGC-3000 amine solvent evaluated under varied process conditions in an advanced flow scheme set-up. The test campaign comprised several series of tests, including energy consumption at varied liquid-to-gas flow ratios (L/G) in the absorber while maintaining 90% CO2 removal, the effect of varying process conditions at a set solvent circulation rate, and the effect of different absorber intercooling and recirculation configurations on energy consumption. Results show that the advanced flow scheme effectively reduced power and energy demand by over 30% at a 90% CO2 capture rate versus a conventional process scheme with MEA solvent.

Multiobjective Optimization of a Benfield HiPure Gas Sweetening Unit

We show how a multiobjective bare-bones particle swarm optimization can be used for a process parameter tuning and performance enhancement of a natural gas sweetening unit. This has been made through maximization of hydrocarbon recovery and minimization of the total energy of the process as the two objectives of the optimization. A trade-off exists between these two objectives as illustrated by the Pareto front. This algorithm has been applied to a sweetening unit that uses the Benfield HiPure process. Detailed models of the natural gas unit are developed in ProMax process simulator and integrated to the multi-objective optimization developed in visual basic environment (VBA). In this study, the solvent circulation rates, stripper pressure and reboiler duties are considered as the decision variables while hydrogen sulfide and carbon dioxide concentrations in the sweetened gas are considered as process constraints. The upper and lower bounds of the decision variables are obtained through a parametric sensitivity analysis of the models. The Pareto sets show a significant improvement in hydrocarbon recovery and a decent reduction in the heat consumption of the process.

DME 생산공정에서 메탄올을 이용한 이산화탄소 제거 공정 연구

본 연구에서는 Dimethyl ether (DME) 생산 공정 중에 포함되어 있는 이산화탄소 제거를 위한 용매로써 메탄올 수용액을 사용하는 공정에 대한 전산모사를 수행하였다. 공정모사를 위하여 Aspen tech 사의 Aspen Plus release 7.3을 사용하였으며, 열역학 모델식으로는 PC-SAFT 모델식을 사용하였다. PC-SAFT 모델식에서 필요한 이성분계 상호작용 매개변수를 결정하기 위하여 실험 데이터를 수집하고 회귀분석을 통해 새롭게 결정하였으며, 결정한 매개변수의 정확성은 실험 데이타와의 비교를 통해 검증하였다. 한편, 이러한 모델식과 검증한 매개변수를 사용하여 공정을 모델링 하였으며 최적 순환유량과 운전압력 그리고 원료 주입단 등을 결정하여 공정 최적화를 수행하였다. In this study, simulation works have been performed for the modeling of <TEX>$CO_2$</TEX> removal process contained in the DME production process through an absorber-stripper system using methanol aqueous solution. Aspen Plus release 7.3 in AspenTech company was utilized as a simulation tool and PC-SAFT modeling equation of state was used as a thermodynamic model. Fitting parameters built-in PC-SAFT model was determined by regressing experimental data, predicted results using PC-SAFT model were compared with experimental data in order to verify the exactness of the thermodynamic model. Optimization works have been performed to reduce the utility consumptions using solvent circulation rate, column operating pressure and feed stage location as manipulated variables.

Design Parameters Affecting the Commercial Post Combustion CO2 Capture Plants

A comprehensive design exercise for a 4,500 TPD CO2 capture plant is conducted based on coal flue gas streams at three recovery rates ranging between 80% and 90%. Three solvents (30wt% MEA, HTC formulated solvents RS-2™ and RS-1210) and enhanced configurations are utilized to achieve the production capacity at minimum emission to atmosphere and minimum energy consumptions. Design parameters and performance comparison of different scenarios are presented in terms of flue gas rates, solvent circulation rates, cooling duties, steam consumption, electricity consumption, main equipment sizes, and emissions to atmosphere.

Demonstration test result of High Pressure Acid gas Capture Technology (HiPACT)

The HiPACT technology (High Pressure Acid-gas Capture Technology), jointly developed by JGC and BASF, is an advanced CO2 capture technology that contributes to economical CCS (Carbon dioxide Capture and Storage) implementation. The demonstration test was conducted in INPEX's Koshijihara natural gas plant in Japan. HiPACT showed excellent performance in CO2 absorption; 20-27% reduction of solvent circulation rate and 10-20% savings in reboiler duty compared with OASE purple were achieved, keeping the CO2 specification at the absorber overhead unaffected. A case study suggests that HiPACT reduces CO2 recovery cost (AGRU + CO2 Compressor) by 25 to 35% over OASE purple.

Evaluating the impact of an ammonia-based post-combustion CO2 capture process on a steam power plant with different cooling water temperatures

The use of aqueous ammonia is a promising option to capture carbon dioxide from the flue gas of coal-fired power plants. Compared to a capture process using monoethanolamine (MEA), the use of ammonia can reduce the heat requirement of the CO2 desorption significantly, although an additional effort is necessary to provide the cooling of the process. To allow for a fair evaluation of the integration of this CO2 capture process into a power plant process, an overall process evaluation is carried out. The use of detailed models of the power plant, of the compressor and of the CO2 capture process enables the calculation of the power loss due to the steam extraction as well as due to the required auxiliary power for CO2 compression, solvent and cooling pumps and mechanical chillers. To study the influence of the cold end of the process, two power plants with different cooling water temperatures are analysed. Additionally, two different process configurations of the capture plant, with either one single absorber or two absorbers connected in series where the first absorber captures the majority of the CO2 and the second limits the NH3 slip, are evaluated.The influence of the main process parameters (desorber pressure, solvent circulation rate, solvent recycling rate and chilling temperature) are evaluated and the optimal configuration with respect to the overall net efficiency penalty is determined.The study shows that the configuration of the process with absorption at low temperature (approximately 10°C) with or without precipitation of ammonium carbonate compounds leads to a lower net efficiency penalty than an MEA-based process, assuming that low temperature cooling water is available. An estimate of the size of the absorber shows that the absorber columns of an ammonia-based process are significantly higher than the ones required for an MEA-based process.

Optimization of CO 2 capture process with aqueous amines using response surface methodology

Amine is one of candidate solvents that can be used for CO 2 recovery from the flue gas by conventional chemical absorption/desorption process. In this work, we analyzed the impact of different amine absorbents and their concentrations, the absorber and stripper column heights and the operating conditions on the cost of CO 2 recovery plant for post-combustion CO 2 removal. For each amine solvent, the optimum number of stages for the absorber and stripper columns, and the optimum absorbent concentration, i.e., the ones that give the minimum cost for CO 2 removed, is determined by response surface optimization. Our results suggest that CO 2 recovery with 48 wt% DGA requires the lowest CO 2 removal cost of $43.06/ton of CO 2 with the following design and operating conditions: a 20-stage absorber column and a 7-stage stripper column, 26 m 3/h of solvent circulation rate, 1903 kW of reboiler duty, and 99°C as the regenerator-inlet temperature.

Optimum design and control of amine scrubbing in response to electricity and CO2 prices

Abstract This paper presents steady state and dynamic modelling of post combustion CO 2 capture using 30 wt% MEA integrated with models of CO 2 compression and the steam power cycle. It uses multivariable optimization tools to maximize hourly profit of a 100 MWe coal-fired power plant. Steady state optimization for design provided optimum lean loading and CO 2 removal as a function of price ratio (CO 2 price/electricity price). The results indicated that for price ratio between 2.1 and 7, the plant should be designed at removal between 70% and 98% and lean loading in the range of 0.22–0.25. Dynamic optimization determined the operation of the capture system in response to two partial load scenarios (reboiler steam load reduction and power plant boiler load reduction) and provided optimum set points for steam rate, solvent circulation rate and stripper pressure control loops. Maximum profit is maintained by allowing the stripper pressure to drop and implementing a ratio control between solvent and steam rate (and flue gas rate for partial boiler load operation).

CO&lt;sub&gt;2&lt;/sub&gt;の高圧分離回収プロセスを用いたCCSの経済性向上

Tens of million tons per year of CO2 are being captured from raw feed gas by natural gas plants and are then being released to the atmosphere. As interest in reducing CO2 emissions from the natural gas plants has increased in recent years, CO2 capture and storage (CCS) has gained in importance. Among the several types of CO2 capture technologies, chemical solvent based technology is widely used to meet product natural gas specification in CO2 contentThis paper discusses a new chemical solvent based CO2 capture technology (HiPACT ; High Pressure Acid-gas Capture Technology), a new concept to improve economic efficiency in CCS implementation, jointly developed by JGC and BASF. The solvent has high stability against thermal degradation, which enables high pressure and elevated temperature operation during solvent regeneration to reduce CO2 compression cost downstream. The solvent also has a higher CO2 absorption capacity than commercially available solvent technologies, which results in decreased solvent circulation rates and lower AGRU (Acid Gas Removal Unit) capital and operating costs. After the concept has been confirmed with pilot plant runs with stimulant gas, a demonstration test using INPEX's commercial natural gas plant has successfully completed.

Regression Analysis Study on the Carbon Dioxide Capture Process

Research on amine-based carbon dioxide (CO2) capture has mainly focused on improving the effectiveness and efficiency of the CO2 capture process. The objective of our work is to explore relationships among key parameters that affect the CO2 production rate. From a survey of relevant literature, we observed that the significant parameters influencing the CO2 production rate include the reboiler heat duty, solvent concentration, solvent circulation rate, and CO2 lean loading. While it is widely recognized that these parameters are related, the exact nature of the relationships are unknown. This paper presents a regression study conducted with data collected at the International Test Center for CO2 capture (ITC) located at University of Regina, Saskatchewan, Canada. The regression technique was applied to a data set consisting of data on 113 days of operation of the CO2 capture plant, and four mathematical models of the key parameters have been developed. The models can be used for predicting the performance of the plant when changes occur in the process. By manipulation of the parameter values, the efficiency of the CO2 capture process can be improved.

Design of CO2 absorption plant for recovery of CO2 from flue gases of gas turbine

Abstract The ongoing human-induced emission of carbon dioxide (CO 2 ) threatens to change the earth's climate. A major factor in global warming is CO 2 emission from thermal power plants, which burn fossil fuels. One possible way of decreasing CO 2 emissions is to apply CO 2 removal, which involves recovering of CO 2 from energy conversion processes. This study is focused on recovery of CO 2 from gas turbine exhaust of Sarkhun gas refinery power station. The purpose of this study is to recover the CO 2 with minimum energy requirement. Many of CO 2 recovery processes from flue gases have been studied. Among all CO 2 recovery processes which were studied, absorption process was selected as the optimum one, due to low CO 2 concentration in flue gas. The design parameters considered in this regard, are: selection of suitable solvent, solvent concentration, solvent circulation rate, reboiler and condenser duty and number of stages in absorber and stripper columns. In the design of this unit, amine solvent such as, diethanolamine (DEA), diglycolamine (DGA), methyldiethanolamine (MDEA), and monoethanolamine (MEA) were considered and the effect of main parameters on the absorption and stripping columns is presented. Some results with simultaneous changing of the design variables have been obtained. The results show that DGA is the best solvent with minimum energy requirement for recovery of CO 2 from flue gases at atmospheric pressure.

Computer simulation of BTEX emission in natural gas dehydration using PR and RKS equations of state with different predictive mixing rules

A typical natural gas dehydration plant, which employs triethylene glycol (TEG) as the dehydrating agent, is simulated using a steady state flowsheeting simulator (Aspen Plus). All major units were included in the flowsheet, that is: absorption column, flash unit, heat exchangers, regenerator, stripper, and reboiler. The base case operating conditions are taken to resemble field data from one of the existing dehydration units operating in the United Arab Emirates (UAE). To explore effects of the thermodynamic model employed in the simulator on the reliability of the whole simulation process, different predictive mixing rules applied to two cubic equations of state (EOS), as programmed by the simulator, have been investigated. The EOS used in the simulation is the Redlich–Kwong–Soave (RKS) and the Peng–Robinson (PR), both with Boston–Mathias (BM) alpha function. In addition to the classical empirical mixing rules, the following ones are investigated: Predictive Soave–Redlich–Kwong–Gmehling (PRKS), Wong–Sandler (WS), and Modified-Huron–Vidal (MHV2) mixing rules. These mixing rules are all predictive in nature. The plant performance criteria that have been studied for their response to changes in the solvent circulation rate include: BTEX (benzene, toluene, ethyl benzene, and xylenes) emissions rate, desiccant losses (makeup), water content in the dehumidified natural gas, purity of the regenerated TEG, and reboiler heat duty. Comparison with the field data is done. Very diverse results have been obtained from the different models and mixing rules. No one single model gives the best results for all criteria.

Extraction–Stripping Process Synthesis with Multiple Solvent Circulation Loops

A flow scheme is suggested for synthesizing solvent extraction–solvent regeneration processes consisting of sets of mixer-settlers. The proposed scheme is based on equal partitioning of the separation capacity between the extraction and stripping cascades with each pair of stages interconnected via an independent solvent circulation loop. A dimensionless linear steady-state model is developed for analysing the behaviour of the proposed multi-loop scheme. It enabled the identification of limiting design conditions and the generation of results relating the combination of strippant consumption and solvent circulation rates required to achieve a given purification duty in a given number of stages. A simple numerical (graphical) method is also suggested for the analysis when equilibrium relations in the extractor and stripper are non-linear. The superiority of the proposed multi-loop scheme over the conventional method of coupling the extraction and stripping cascades via a single solvent circulation loop is illustrated quantitatively. Compared with the conventional scheme the proposed flow structure enables the same purification to be achieved with the same total separation capacity, but at lower solvent circulation rates and strippant consumption. This is obviously reflected as savings in both equipment and operating costs.

Integrated design of coupled separation processes with independent solvent circulation loops

An integrated process system model has been developed for coupled separation operations involving two independent solvent circulation loops. This flow scheme is characterized by lower strippant (energy) consumption compared to the single loop configuration. The character of the relation between the strippant and solvent throughputs satisfying a given purification ratio has been analysed. Interesting characteristics of this flow structure concerning the effect of design and operating parameters such as the total number of stages, the ratio of the separation capacities, and the solvent circulation rates in the two loops on the system behaviour are uncovered. A systematic approach to the design optimization of single and twin loop flow structures is presented.

Integrated analysis of coupled separation operations

An integrated system analysis model is developed for processes involving two interacting countercurrent separation cascades coupled through a single-solvent circulation loop. The overall process model reveals interesting trends characterizing the dependence of the strippant (energy) required for achieving a given solute fractional recovery on the system design and operating variables. There is a minimum solvent circulation rate corresponding to infinite stripping agent requirements. The stripping agent requirements are minimized at an optimum solvent circulation rate and an optimum partition of the total system separation capacity between the two cascades. The developed rational design optimization method is compared with existing rule of thumb approach to the process design of coupled separation operations.