Solvent For CO2 Absorption Research Articles

Modeling pilot plant results for CO2 stripping using piperazine in two stage flash

Piperazine (PZ) has shown good potential for use as a solvent for CO2 absorption in post-combustion carbon capture It has a high absorption rate good capacity and very good resistance to thermal and oxidative degradation . Thermodynamic and kinetic models for PZ-CO2-water have been developed in Aspen Plus® . Pilot scale experiments were conducted on a 0.1 MW scale at the Separations Research Program at UT Austin to demonstrate the performance of concentrated (8 m) PZ using an intercooled absorber and a two-stage flash. This paper describes modeling and simulation of CO2 stripping from PZ using data from two pilot campaigns conducted in Winter and Fall 2011.Vapor liquid equilibrium equations and thermodynamic models for this system were validated using pilot plant data and found to satisfactorily represent the actual operating conditions. Rigorous reconciliation was done on Fall 2011 data using Aspen Plus® Data Fit. The only major systematic adjustments were found in the CO2 measurements, which required 1.2 to 6.9% increase to match the predicted model values.The best equivalent work was 45.5kJ/mol CO2 in Winter 2011 and 36.6kJ/mol CO2 in Fall 2011. The validated model predicted that the pilot plant stripper configuration should be able to achieve 32.6kJ/mol at its optimum operating conditions. Major parameters that affected pilot plant performance were low values of rich loading and non-optimal operation of lean loading and cold rich bypass. Optimized values of operating conditions at 0.4 rich loading were identified as 0.31 lean ldg and 4% cold rich bypass flow.

The National Carbon Capture Center: Cost-effective test bed for carbon capture R&D

The US Department of Energy (DOE) established the National Carbon Capture Center (NCCC) as part of its strategy to address the need for cost-effective CO2 capture technologies. The focus of the NCCC is to conduct research and development to advance emerging CO2 control technologies to commercial scale for effective integration into coal- based Integraged Gasification Combined Cycle (IGCC) and combustion processes. To achieve this goal, the NCCC provides a test-bed for government, industrial, and university projects to conduct meaningful tests in an industrial setting.The NCCC test plan includes both post-combustion and pre-combustion CO2 capture development. A flexible post- combustion test facility, Post-combustion Carbo Plant E.C. Gaston, in Wilsonville, Alabama. The facility, which is managed by Southern Company Services, provides a platform for testing technologies at a wide-range of sizes and process conditions on coal-derived flue gas. Since completing commissioning and baseline testing in early 2011, several technologies have been tested.The PC4 facility includes multiple slipstreams with a range of flue gas throughputs to allow the evaluation of post- combustion CO2 capture technologies. It provides the capability to test modules from technology developers and to test solvents in an absorber/regenerator unit, the pilot solvent test unit (PSTU). In 2011, PSTU baseline tests were completed, using a reference solvent, monoethanol amine (MEA) to characterize its performance and verify the reliability of the data generated. The PSTU was later operated to test a potential commercial solvent developed by Babcock & Wilcox. Aker Carbon Solutions installed a mobile test unit at the site to test its commercial solvent, and Membrane Technology & Research installed and commissioned its 0.05-MW polymeric CO2-separation membrane, which will continue to be tested throughout 2012. Also in 2012, several other developers will test solvents in the PSTU and enzyme-based solvent systems in the bench scale area on coal-derived flue gas. Collaboration with additional developers for future test plans is on-going.The NCCC also generates coal derived syngas which is available for testing technologies related to pre-combustion CO2 capture. Several slipstreams are in place with a range of syngas throughputs. Technologies tested in 2011 include water gas shift catalysts, high-temperature mercury and CO2 sorbents, a hydrocarbon removal system, physical and chemical solvents for CO2 absorption, a polymeric CO2-separation membrane, and three hydrogen- separation membranes (carbon molecular sieve, polymeric, and palladium based). Several of these technologies will be tested further in 2012, and membranes and solvents from other developers will also be tested.Result from NCCC's testing have indicated the facility's usefulness in accelerating the commercialization of advanced CO2 capture technologies. This paper will detail the NCCC's capabilities, test results, and future plans.

Investigation of Mass-Transfer Performance for CO2 Absorption into Diethylenetriamine (DETA) in a Randomly Packed Column

The mass-transfer performance of CO2 absorption into aqueous diethylenetriamine (DETA) solutions was investigated in an absorption column randomly packed with Dixon rings at 303–303 K and atmospheric pressure, and compared with that of monoethanolamine (MEA), which is widely considered as a benchmark solvent for CO2 absorption. The mass-transfer performance was presented in terms of volumetric overall mass-transfer coefficient (KGav). In particular, the effects of operating parameters, such as inlet CO2 loading, solvent concentration, liquid flow rate, inert gas flow rate, and liquid temperature, were investigated and compared for both MEA and DETA. Over 40 runs of absorption experiments were carried out in this study. The results showed that KGav of DETA was found to be higher than that of MEA. Also, inlet CO2 loading, solvent concentration, liquid flow rate, and liquid inlet temperature had significant effect on KGav for both systems. However, the inert gas flow rate had an insignificant effect on KGav....

Kinetics of CO2 Absorption by a Blended Aqueous Amine Solution

AbstractThe reaction rates of CO2 in an aqueous blend of amine solutions of N‐(2‐hydroxethyl)piperazine (N‐HEPZ) and 2‐amino‐2‐hydroxymethyl‐1,3‐propanediol (AHPD) at 298 K were investigated in a concentration range of 0.0025–0.03 kmol m–3 N‐HEPZ with a blend of 1 kmol m–3 AHPD. The reaction was modeled using a termolecular reaction mechanism with a rate of 12 971 m3kmol–1s–1. The results indicate that the blended aqueous solution of N‐HEPZ and AHPD is a potential candidate as an alternative solvent for CO2 absorption, where the sterically hindered AHPD increases the CO2 capacity and the reaction rate is enhanced by the promoter, N‐HEPZ.

Studies on corrosion and corrosion inhibitors for amine based solvents for CO2 absorption from power plant flue gases containing CO2, O2 and SO2

Abstract This work investigated the effects of operating parameters on the corrosion of carbon steel in MEA- H2O-CO2-O2-SO2 systems. It also investigated the effectiveness of a number of chemical additives in inhibiting corrosion. Two methods, namely, the Tafel plot and potentiodynamic polarization techniques were used to quantify the corrosion rate. The results showed that an increase of both O2 and SO2 concentrations in simulated flue gas stream, CO2 loading, MEA concentration and the operating temperature induced higher corrosion rates. Also, the data obtained from different corrosion measurement techniques produced almost the same results. In addition, the corrosion products obtained experimentally based on CE and SEM/EDS measurements included Fe(OH)2, Fe(OH)3, 2Fe2O3⋅H2O, FeCO3, and FeSO4. A power-law model shows that CO2 loading had the highest impact on the corrosion rate, while SO2 and O2 show only slight effects on the corrosion rate. I was observed that all of the corrosion inhibitors tested can minimize corrosion of carbon steel in the MEA- H2O-CO2-O2-SO2 system. However, the inhibition efficiency of each inhibitor depended on its concentration.

UT/SRP CO2 capture pilot plant — Operating experience and procedures

Abstract The Separations Research Program (SRP) pilot plant is located at The University of Texas (UT) Pickle Research Campus and has been operated as a carbon capture facility since 2002. The semi-works scale pilot facility uses air and 3–14 mol% CO2 as flue gas as it applies the latest advancements in carbon dioxide recovery technology. The capacity of the pilot plant is approximately 15 m3/min of gas and 130 liters/min of solvent. Past experimental studies include solvent performance characterization using potassium carbonate with piperazine, monoethanolamine, concentrated piperazine and other proprietary solvents. In recent years, the pilot plant has been utilized to determine the mass transfer and hydraulic characteristics of various structured and random packings using amine-based solvents for CO2 absorption. In 2002, the UT/SRP began developing improved measurement techniques and operating procedures to ensure reliable process control and closure of material and energy balances. Past experience and learning with the UT/SRP pilot plant is currently being utilized for the design and operation of several future pilot plants that will process actual coal-fired flue gas. The purpose of the presentation is to provide a brief description of the UT/SRP CO2 capture pilot plant capabilities, innovative operational procedures and instrument accuracies. The objectives of this paper are to discuss SRP pilot plant experience including: process description, operations and control, key equipment, measurement methods including novel techniques, overall process performance, and future work.

CO2 Capture in Flue Gas: Semiempirical Approach to Select a Potential Physical Solvent

The reported work aims at proposing a method to select potential physical solvents for CO2 absorption in flue gas. A parametric approach based on solubility data available in the open literature is engaged. It appears that CO2 capture with physical solvents is dominated by two fundamental aspects. On one hand, solvent−solvent interactions, characterized by the Hildebrand solubility parameter, have to be minimized so as to facilitate CO2 incorporation into the solvent. On the other hand, CO2−solvent interactions, which can be estimated by ab initio calculations, have to be maximized in order to allow good cohesion between CO2 and the solvent molecules. Considering these two requirements, several types of solvents are highlighted, namely, ethers, esters, ketones, tertiary amines, and alkyl phosphates. This parametric approach differs notably from similar works about another acid gas, SO2, and the forthcoming differences are discussed. Some mechanistic considerations are also given about the critical problem...

Solubility of CO, NO, CH, And CH In Polar Solvents

Abstract The solubility of carbon dioxide, nitrous oxide, methane and ethane in a physical solvent, triethylene glycol monomethyl ether (TEGMME) was recently measured by Henni and Mather(1–4) at 40, 70, and 100 ° C at pressures up to 10.9 MPa. TEGMME was found to be the best solvent for CO2 removal among the physical solvents used in the gas processing industry. In order to compare these solubility data with those of other polar solvents, a literature search was done to gather solubility data in solvents with a wide range of dielectric constants. The solubility data compiled were for pressures higher than atmospheric pressure and the Peng-Robinson(5) equation of state was used to correlate the data for the solubility of CO2 in these polar solvents. The Henry's Law constants are then derived using the Kritchevsky-Kasarnovsk(6) or the Kritchevsky-Iliinskaya(7) equation. The results show that ethyl acetate and propyl acetate are the two solvents that have the highest capacity for CO2 absorption. Among the solvents that absorb CO2 the most, TEGMME has the highest boiling point; this translates into lower solvent losses in the regeneration section. Dimethyl ether is among the best solvents for CO2 absorption but it is also among solvents that absorbs methane the most. Diethyl ether comes at the top of the list in its ability to absorb. The study confirms the fact that the best physical solvents for absorbing acid gases have the disadvantage of absorbing the largest amounts of ethane. It also recommends the use of this new solvent TEGMME as a new solvent for acid gas removal. The solubility data in the CO2, N2O, CH4 and C2H6 systems were generally well-correlated by the Peng-Robinson equation of state even for those systems that are highly non-ideal. Introduction The Government of Canada has been an active participant in the development of international agreements and protocols for emissions reduction. It has committed the country to meeting national emission caps for anthropogenic air emissions. Just how these national targets will be met is a critical question to provincial governments but also to oil, coal and utility companies in Canada. Since carbon dioxide is a major contributor to the global warming phenomenon, the process of carbon dioxide removal from coal-fired power plants and its utilisation as a flooding agent for enhanced oil recovery (EOR) is the focus of considerable of attention. The CO2 captured will generate revenues and will help reduce emissions that contribute to the greenhouse effect. Zawacki et al.(8) have screened more than 100 solvents for their potential of removing acidic gases (CO2, H2S). The dimethyl ether of tetraethylene glycol (DMETEG) was chosen as one of two most promising solvents. In an attempt to provide the industry with better physical solvents, a study was initiated to test new physical solvents. Triethylene glycol monomethyl ether [TEGMME, C.A. Registry No. 112-35-6] was chosen in the initial study as it belongs to the same chemical family as DMETEG but it costs four times less.

Exhibit of Dallas County Dental Society

Piperazine (PZ) has shown good potential for use as a solvent for CO2 absorption in post-combustion carbon capture It has a high absorption rate good capacity and very good resistance to thermal and oxidative degradation . Thermodynamic and kinetic models for PZ-CO2-water have been developed in Aspen Plus® . Pilot scale experiments were conducted on a 0.1 MW scale at the Separations Research Program at UT Austin to demonstrate the performance of concentrated (8 m) PZ using an intercooled absorber and a two-stage flash. This paper describes modeling and simulation of CO2 stripping from PZ using data from two pilot campaigns conducted in Winter and Fall 2011.Vapor liquid equilibrium equations and thermodynamic models for this system were validated using pilot plant data and found to satisfactorily represent the actual operating conditions. Rigorous reconciliation was done on Fall 2011 data using Aspen Plus® Data Fit. The only major systematic adjustments were found in the CO2 measurements, which required 1.2 to 6.9% increase to match the predicted model values.The best equivalent work was 45.5 kJ/mol CO2 in Winter 2011 and 36.6 kJ/mol CO2 in Fall 2011. The validated model predicted that the pilot plant stripper configuration should be able to achieve 32.6 kJ/mol at its optimum operating conditions. Major parameters that affected pilot plant performance were low values of rich loading and non-optimal operation of lean loading and cold rich bypass. Optimized values of operating conditions at 0.4 rich loading were identified as 0.31 lean ldg and 4% cold rich bypass flow.