MEA Absorption Research Articles

Reducing carbon footprint in cities: Natural gas-based energy generation with zero CO2 emission

This work proposes a novel zero–CO2–emission energy system to meet thermal and electrical energy needs of the cities without emitting CO2 while using natural gas as a primary energy source. Since the system uses available technologies, it is envisioned as a part of transition towards net-zero sustainable economy. At the core of the system is production of hydrogen via pyrolysis of methane which has recently achieved technological maturity of industrial scale production. Natural gas combustion in a combined heat and power (CHP) unit produces electrical and thermal energy required by the city and by the energy system itself. CO2 produced by CHP is captured via MEA absorption and converted to methanol via synthesis with hydrogen while also producing carbon black. We consider different carbon reduction scenarios, urbanization levels, system operation conditions, operational costs, capital costs, and energy and material prices in evaluating the system. If such systems are deployed worldwide, subject to produced methanol being equal to the current demand (111 Million ton/yr), they would eliminate 44 Million t/yr CO2 emissions from existing methanol plants and 160 Millon t/yr CO2 emissions from standalone energy systems that provide heating and cooling for 40 Million people.

Three pathways towards elimination of CO2 emissions from industrial plants that use hydrocarbon fuels

Many industrial plants burn hydrocarbon fuels to generate electricity and high-temperature thermal energy required in their processes. This work proposes a novel system for generation of such thermal energy while eliminating CO2 emissions. The system produces electricity, thermal energy, methanol, and carbon black. Combined heat and power (CHP) unit generates high-temperature thermal energy and electricity required by the industrial plant; CO2 produced by CHP and by the plant itself is converted to methanol by using hydrogen produced via pyrolysis of methane, which has recently advanced to the first industrial scale plant. Thermal energy contained in the CHP flue gas replaces utility plant boilers or furnaces of the industrial plant (e.g. a refinery or a petrochemical plant). Two pathways are based on two different methane pyrolysis methods and CO2 removal via MEA absorption. The third pathway replaces MEA absorption with a novel in situ CO2 conversion reactor. Proposed pathways are examined as ways of eliminating CO2 emissions from a 5 million ton of crude oil per annum refinery. The study includes operational costs, capital costs, and material prices in USA, EU, and China. The results show that the proposed pathways are profitable for USA and EU, while for China they are not. The proposed pathways provide CO2 free energy generation from natural gas as an alternative to energy generation from either solar, wind or hydro energy sources. In addition, they enable capture and conversion of CO2 emissions from industrial process units.

Power-to-Green Methanol via CO2 Hydrogenation—A Concept Study including Oxyfuel Fluidized Bed Combustion of Biomass

A revolution of the global energy industry is without an alternative to solving the climate crisis. However, renewable energy sources typically show significant seasonal and daily fluctuations. This paper provides a system concept model of a decentralized power-to-green methanol plant consisting of a biomass heating plant with a thermal input of 20 MWth. (oxyfuel or air mode), a CO2 processing unit (DeOxo reactor or MEA absorption), an alkaline electrolyzer, a methanol synthesis unit, an air separation unit and a wind park. Applying oxyfuel combustion has the potential to directly utilize O2 generated by the electrolyzer, which was analyzed by varying critical model parameters. A major objective was to determine whether applying oxyfuel combustion has a positive impact on the plant’s power-to-liquid (PtL) efficiency rate. For cases utilizing more than 70% of CO2 generated by the combustion, the oxyfuel’s O2 demand is fully covered by the electrolyzer, making oxyfuel a viable option for large scale applications. Conventional air combustion is recommended for small wind parks and scenarios using surplus electricity. Maximum PtL efficiencies of ηPtL,Oxy = 51.91% and ηPtL,Air = 54.21% can be realized. Additionally, a case study for one year of operation has been conducted yielding an annual output of about 17,000 t/a methanol and 100 GWhth./a thermal energy for an input of 50,500 t/a woodchips and a wind park size of 36 MWp.

Effect of Temperature on Diffusivity of Monoethanolamine (MEA) on Absorption Process for CO2 Capture

iffusion coefficient study gains an interest to know the mass transfer properties of molecules especially in study of the absorption process. The main objective of this study is to investigate the effect of temperature on diffusivity of MEA absorption process for CO₂ capture. Three different values of process temperature were chosen for simulation was carried out at 25°C, 40°C. The MD simulation was carried out at NVE (200ps) and NPT (INS) ensemble in Material Studio 7.0 software.

Flexibility of Power‐to‐Gas Plants: A Case Study

AbstractDue to the increasing share of renewable energies in the power sector, the need for energy storage and flexible performance is rising. This study provides an in‐depth investigation of the flexibility of a Power‐to‐Gas plant for the production of synthetic natural gas. Model‐based analysis is conducted for the individual technologies PEM electrolysis, MEA absorption and fixed‐bed methanation as well as for the continuously operated process. This study reveals that the Power‐to‐Gas plant offers a capacity flexibility of 87–125 %, corresponding to 4.79–6.88 MW electrical input power.

CFD simulation of a packed bed industrial absorber with interbed liquid distributors

CO2 absorption processes at industrial scale are usually carried-out in multi-bed columns. However, the design, modelling and simulation of CO2 absorbers are usually executed with simplified single bed columns that do not represent the full design realities of industrial-scale absorbers; limiting the applicability of such results to industrial processes. In this study, a CFD simulation of an MEA absorption process for the removal of CO2 gas on an AMT-SP 350Y structured packing was executed for an industrial-scale pilot plant. The CFD simulation was carried out for three different absorber configurations (Type A, Type B, and Type C). The liquid hydrodynamics, pressure drop, and CO2 removal efficiencies were studied and compared among the three types. Results from the Type A (single bed) and Type B (double bed) absorbers were found to have deviated from the actual plant data while the Type C, with 5-beds and four, interbed liquid distributors was observed to give the best performance as a true representation of the industrial absorber. A two-parameter validation in terms of pressure drop and CO2 removal efficiency was carried out between the pilot plant and the CFD simulation with a maximum discrepancy of 5.2% between the results. On the parametric study of the impact of varying CO2 loadings on absorption efficiencies, it was found and subsequently recommended that keeping the CO2 loading up to 30 mol % will ensure an efficient carbon capture. Further parametric studies were also performed to ascertain the effect of varying gas flow rates on the absorption process.

Simulation and design of tar recovery and gas decarbonization process

A multi-production system including pulverized coal molding, pyrolysis and activation is designed to solve the key problems of powder coal pyrolysis in Northern Shanxi. As the pulverized coal molding is just a physical procedure, so more attention is arranged on the preliminary design of Shenfu coal pyrolysis process. As coal tar can be converted to gasoline by hydrocracking technology, the pyrolyzation gas is cooled and coal tar is reclaimed by a spray tower, then a decarbonization unit is introduce to separate CO2 by MEA absorption. In the design process, process simulation and performance parameters optimization were carried out by Aspen Plus. At the same time, corresponding safety measures and relevant wastes treatment suggestions for the whole process were put forward.

A comprehensive modeling of the hybrid temperature electric swing adsorption process for CO2 capture

Adsorption technologies provide high selectivity and low energy consumption making this technique very attractive to be employed in post-combustion carbon capture. In this publication, a material made of activated carbon and zeolite 13X is considered for a hybrid process termed Temperature Electric Swing Adsorption (T/ESA). This hybrid T/ESA can work as a traditional Temperature Swing Adsorption (TSA) heated by hot gas, but can also increase the temperature of the adsorbent very fast by Joule effect as long as the activated carbon provides a continuous conductive matrix for electricity. This paper discusses a detailed modeling of the T/ESA process when applied to three cases. The first case is the simulation of the T/ESA process with exhaust with 12% of CO2 concentration, which has been chosen to validate the model against literature results. The second and third case studies consider the T/ESA application in a natural gas combined cycle (NGCC) traditional power plant, and in a NGCC plant with exhaust gas recycle (EGR). These cases were selected to investigate the adsorption technology at low CO2 concentration and quantify the benefit of the EGR for carbon capture applications. Starting from an NGCC overall electric efficiency of 58.3% LHV based, the efficiency of the NGCC with T/ESA technology reduces to 35.3% while with EGR is 38.9% against the 49.9% with the MEA absorption plant. The same results are confirmed by the SPECCA index 13.05 MJLHV/kgCO2 to 9.64 MJLHV/kgCO2 against the reference of 3.36 MJLHV/kgCO2. The energy penalty of the T/ESA is significant because of electric consumptions required for the heating and fast cooling of the adsorbent.

A novel temperature swing adsorption process for natural gas purification, Part II: Performance assessment

A novel temperature swing adsorption-based natural gas purification cycle using a monolith consisting of adsorbent-coated microchannels is investigated in this two-part study. In the accompanying paper, Part I, the development of a full process simulation model, and selection of geometric parameters and adsorbent and heat transfer fluid were reported. This paper, Part II, develops a comprehensive performance map of the process that involves determination of ranges of product purity, CH4 recovery and process capacity, and energy requirements. The TSA-based process in the present work is found to produce up to two orders of magnitude more purified product than that from adsorbent bed-based PSA processes reported in the literature, while product purity and CH4 recovery values remain competitive. This concept is also found to reduce the system footprint by 82% when compared with a TSA process that uses separate microchannels for the flow of working and coupling fluids. Additionally, methods for reducing process energy requirements are considered, along with enhancement of product purity via a staged purification scheme. The energy requirement for the process is found to be lower than that for MEA absorption systems, indicating the potential for large-scale installations based on this process.

CO2 capture efficiency and heat duty of solid acid catalyst-aided CO2 desorption using blends of primary-tertiary amines

This study evaluated improvements in the CO2 capture process in terms of cyclic capacity, absorption efficiency and heat duty caused by using a primary amine (5 M MEA) blended with a tertiary amine (2 M MDEA or 1.25 M DEAB) and a catalyst-aided desorber loaded with two different solid acid catalysts (γ-Al2O3 or HZSM-5) in a bench scale full cycle CO2 capture plant. The absorber and desorber were stainless steel pipes with inside diameter of 0.05 m and height of 1.50 m. The desorber was loaded with varying amounts of solid acid catalyst at an average bed temperature of 85 °C. The two mixed amine solvents tested, were compared with 5 M MEA each with a circulation rate of 0.06 L/min. Simulated flue gas, 15% CO2 in N2, was used at a total flow rate of 15 SLPM. The results showed that in 5 M MEA system, cyclic capacity and absorption efficiency increased while heat duty decreased when the catalyst amount was increased. In the case of mixed primary and tertiary amines, catalysts contribute to slight improvements. The increase in absorption efficiency was found to be in the order of 5 M MEA: γ-Al2O3 < 5 M MEA: HZSM–5 < 5 M MEA: 2 M MDEA: γ-Al2O3 < 5 M MEA: 2 M MDEA: HZSM–5 < 5 M MEA: 1.25 M DEAB: γ-Al2O3 < 5 M MEA: 1.25 M DEAB: HZSM-5. The relative reduction in heat duty of the system was found to be in the order of 5 M MEA: 1.25 M DEAB: HZSM–5 < 5 M MEA: 2 M MDEA: HZSM–5 < 5 M MEA: 1.25 M DEAB: γ-Al2O3 < 5 M MEA: 2 M MDEA: γ-Al2O3 < 5 M MEA: HZSM-5 < 5 M MEA: γ-Al2O3.

Dynamic and Control of an Absorber - Desorber Plant at Heilbronn

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

CO2 capture from natural gas combined cycles by CO2 selective membranes

This paper performs a techno-economic analysis of natural gas-fired combined cycle (NGCC) power plants integrated with CO2 selective membranes for post-combustion CO2 capture. The configuration assessed is based on a two-membrane system: a CO2 capture membrane that separates the CO2 for final sequestration and a CO2 recycle membrane that selectively recycles CO2 to the gas turbine compressor inlet in order to increase the CO2 concentration in the gas turbine flue gas. Three different membrane technologies with different permeability and selectivity have been investigated. The mass and energy balances are calculated by integrating a power plant model, a membrane model and a CO2 purification unit model. An economic model is then used to estimate the cost of electricity and of CO2 avoided. A sensitivity analysis on the main process parameters and economic assumptions is also performed. It was found that a combination of a high permeability membrane with moderate selectivity as a recycle membrane and a very high selectivity membrane with high permeability used for the capture membrane resulted in the lowest CO2 avoided cost of 75US$/tCO2. This plant features a feed pressure of 1.5bar and a permeate pressure of 0.2bar for the capture membrane. This result suggests that membrane systems can be competitive for CO2 capture from NGCC power plants when compared with MEA absorption. However, to achieve significant advantages with respect to benchmark MEA capture, better membrane permeability and lower costs are needed with respect to the state of the art technology. In addition, due to the selective recycle, the gas turbine operates with a working fluid highly enriched with CO2. This requires redesigning gas turbine components, which may represent a major challenge for commercial deployment.

Process simulations of post-combustion CO2 capture for coal and natural gas-fired power plants using a polyethyleneimine/silica adsorbent

The regeneration heat for a polyethyleneimine (PEI)/silica adsorbent based carbon capture system is first assessed in order to evaluate its effect on the efficiency penalty of a coal or natural gas power plant. Process simulations are then carried out on the net plant efficiencies for a specific supercritical 550MWe pulverized coal (PC) and a 555MWe natural gas combined cycle (NGCC) power plant integrated with a conceptually designed capture system using fluidized beds and PEI/silica adsorbent. A benchmark system applying an advanced MEA absorption technology in a NETL report (2010) is used as a reference system. Using the conservatively estimated parameters, the net plant efficiency of the PC and NGCC power plant with the proposed capture system is found to be 1.5% and 0.6% point higher than the reference PC and NGCC systems, respectively. Sensitivity analysis has revealed that the moisture adsorption, working capacity and heat recovery strategies are the most influential parameters to the power plant efficiency. Under an optimal scenario with improvements in increasing the working capacity by 2% points and decreasing moisture adsorption by 1% point, the plant efficiencies with the proposed capture system are 2.7% (PC) and 1.9% (NGCC) points higher than the reference systems.

Effect of Temperature on Diffusivity of Monoethanolamine (MEA) on Absorption Process for CO2 Capture

Diffusion coefficient study gains an interest to know the mass transfer properties of molecules especially in study of the absorption process. The main objective of this study is to investigate the effect of temperature on diffusivity of MEA absorption process for CO2 capture. Three different values of process temperature were chosen for simulation in this study, 298 K, 313 K and 318 K. The MD simulation was carried out at NVE (200ps) and NPT (1ns) ensemble in Material Studio 7.0 software. Mean Square Displacement (MSD) analysis was done to compute the self-diffusion coefficient of molecules in tertiary system (MEA+H2O+CO2). The results show that the rate of the diffusion coefficient is increased as temperature increased. Diffusion coefficient at 318 K is the highest compared to others temperature. MD simulation is used to study details about absorption process and capture CO2 acid gases. The simulation diffusivity result obtained from this work shows higher compared with theoretical results.

CO2 Absorption from Natural Gas: Dynamic Study & Simulation

Rate -based non-equilibrium dynamic simulation model for CO2 removal at high pressure is presented in this research. To ensure the smoothness in the operation plant for natural gas process, therefore the process control need to be designed based on the dynamics model studied. In order to successfully design a dynamic model, steady state model simulation model need to be established and in this research, Aspen Plus simulator had been utilized. The input data and information for the simulation had been acquired from the real pilot plants that operate at 15bar using structured column of FLEXIPAC 1Y. Dynamic analysis is conducted to observe the effect of changing the lean solvent flow rate and thermodynamic state on the MEA absorption column behavior. It is observed that the model satisfactorily predicts the pilot plant behavior under multiple inputs and disturbances.

An Improved CO2 Separation and Purification System Based on Cryogenic Separation and Distillation Theory

In this study, an improved CO2 separation and purification system is proposed based on in-depth analyses of cryogenic separation and distillation theory as well as the phase transition characteristics of gas mixtures containing CO2. Multi-stage compression, refrigeration, and separation are adopted to separate the majority of the CO2 from the gas mixture with relatively low energy penalty and high purity. Subsequently, the separated crude liquid CO2 is distilled under high pressure and near ambient temperature conditions so that low energy penalty purification is achieved. Simulation results indicate that the specific energy consumption for CO2 capture is only 0.425 MJ/kgCO2 with 99.9% CO2 purity for the product. Techno-economic analysis shows that the total plant investment is relatively low. Given its technical maturity and great potential in large-scale production, compared to conventional MEA and SelexolTM absorption methods, the cost of CO2 capture of the proposed system is reduced by 57.2% and 45.9%, respectively. The result of this study can serve as a novel approach to recovering CO2 from high CO2 concentration gas mixtures.

Simultaneous Design and Control of the MEA Absorption Process of a CO2 Capture Plant

Abstract This paper presents the simultaneous design and control of the MEA absorption section of a post-combustion CO2 capture plant. An optimization framework is proposed to minimize the process economics while complying with the process constraints in the transient domain using a decentralized control scheme. The optimal design obtained by the proposed methodology has been validated and compared against the traditional optimal steady-state design approach. The results indicate that the proposed design is dynamically feasible in the presence of oscillatory disturbances in the flue gas flowrate.

Techno-economic Performance of a Hybrid Membrane – Liquefaction Process for Post-combustion CO2 Capture

Gas separation membranes, considered among one of the promising emerging capture technologies for post-combustion capture, requires a two-stage process with significant compression work for CO2 capture from a coal fired power plant flue gas. A hybrid membrane–liquefaction process for post-combustion CO2 capture from the power plant flue gas is developed to mitigate the deficiencies of the two-stage membrane process. The energy efficiency of the process depends on the permeate CO2 composition from the membrane unit. The performance envelope of the hybrid process is evaluated and shows that the optimum CO2 concentration in the permeate is 65%– 67% depending on the targeted CCR. A techno-economic analysis for 85% CCR was performed and the cost of CO2 avoided is calculated to 48 €2008/tCO2,avoided, that is, 9% more cost-efficient than the baseline MEA absorption process.

Energy Saving for Biogas Production and Upgrading – Thermal Integration

Thermal integration of anaerobic digestion (AD) biogas production with amine based biogas upgrading has been studied for improving the overall thermal efficiencies of the two systems. The thermal characteristics have been investigated for typical AD raw biogas generation and MEA absorption biogas upgrading. The investigation provides a basic understanding of energy saving for both industrial scale biogas production and upgrading processes. The thermal integration is carried out based on the thermal characteristics of the two systems by well-defined case studies, which take the following factors into account such as important thermal conditions of sub-systems, material and energy balances, the efficiencies of heat exchange and heat transfer, necessary integration optimization and ambient conditions. The results show that the thermal integration is achievable with very positive effects for overall energy efficiency and water usage.

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.In the present work, a rigorous optimization model is developed to address the design and operation of power plants coupled to capture systems. The equations-oriented modeling strategy here utilized can address greenfield designs in which design and operating variables are simultaneously optimized, in order to ensure that the system will be able to meet process requirements at minimum cost. Then, an analysis of the electricity cost, CO2 avoidance cost, energy penalties, as well as the optimal values of decision variables is thoroughly pursued.Different economic tradeoffs are comprised at the optimal solutions for the joint project, as given by the different discrete and continuous decisions that the designer needs to weight in order to achieve the desired generation and capture goals, including the number of parallel capture trains, the inherent efficiency of each recovery unit, and the overall emissions reduction rate.In this context, the joint optimization of the NGCC power plant with the amine-based capture option results in a novel configuration where 731MW are optimally generated for supplying both the external demand and the capture plant energy requirements, and achieving an overall CO2 emissions reduction rate of 82.1% by means of a three capture trains arrangement, where 13.4% of the flue gas stream is bypassed and 94.8% of the CO2 gets recovered at each unit.This new generation/capture project features optimal values of its economic performance indicators, with an avoidance cost of 81.7US$ per tonne of CO2 captured, which can only be secured by simultaneously optimizing the design and operating variables of both systems on a start-of-the-art optimization algorithm.