environmental impacts of amine-based co2 post combustion capture (pcc)...

CSIRO ENERGY TECHNOLOGY/ENERGY TRANSFORMED FLAGSHIP

Environmental Impacts of amine-based CO2 Post Combustion Capture (PCC) Process

Task 3: Process Modelling for Amine-based Post-Combustion Capture Plant

Narendra Dave, Thong Do, Merched Azzi, Paul Feron 15 July 2012

Prepared for Australian National Low Emissions Coal Research and Development

Project: 4-090-0067 Final Submission

Australian National Low Emissions Coal Research & Development

Process Modelling for Amine-based Post-Combustion Capture Plant

CSIRO Energy Technology/Energy Transformed Flagship

Citation

Dave N, Do T, Azzi M and Feron P (2013). Process Modelling for Amine-based Post-Combustion Capture Plant. CSIRO, Australia.

Copyright and disclaimer

© 2013 CSIRO To the extent permitted by law, all rights are reserved and no part of this publication covered by copyright may be reproduced or copied in any form or by any means except with the written permission of CSIRO.

Important disclaimer

CSIRO advises that the information contained in this publication comprises general statements based on scientific research. The reader is advised and needs to be aware that such information may be incomplete or unable to be used in any specific situation. No reliance or actions must therefore be made on that information without seeking prior expert professional, scientific and technical advice. To the extent permitted by law, CSIRO (including its employees and consultants) excludes all liability to any person for any consequences, including but not limited to all losses, damages, costs, expenses and any other compensation, arising directly or indirectly from using this publication (in part or in whole) and any information or material contained in it.

Process Modelling for Amine-based Post-Combustion Capture Plant 3

Contents

Acknowledgments .............................................................................................................................................. 4

Summary ............................................................................................................................................................ 5

Part I Current State of Post-Combustion Capture Knowledge 2

1 Introduction .......................................................................................................................................... 3

2 Current State of PCC knowledge .......................................................................................................... 4

Part II Atmospheric Emissions of Monoethanolamine (MEA) and Its degradation products 16

3 Summary of the Latest Existing Information Related to Emissions from PCC .................................... 17

3.1 Esbjergvaerket Pilot Plant Results ............................................................................................ 17

3.2 National Carbon Capture Centre Pilot Solvent Tests Unit Results ........................................... 23

3.3 SINTEF CO2 Capture Mongstad Technology Qualification Program Amine 6 Research Results – Pilot Plant ............................................................................................................ 26

3.4 SINTEF CO2 Capture Mongstad Technology Qualification Program Amine 6 Research Results – Laboratory Results ............................................................................................... 29

4 Atmospheric Emissions of 2-amino-2-methyl-1-propanol (AMP)/ piperazine Blend and its Degradation Products ...................................................................................................................................... 38

4.1 Oxidative Degradation of 2-amino-2-methyl-1-propanol (AMP)/Piperazine Blend ................ 39

4.2 Thermal Degradation of 2-amino-2-methyl-1-propanol (AMP)/Piperazine Blend .................. 40

Part III ASPEN-Plus Simulation Results 42

5 Improved ASPEN-Plus Estimations of Atmospheric Emissions ........................................................... 43

5.1 Improving Emissions Estimates of Monoethanolamine and its Degradation Products .............................................................................................................................................. 44

5.2 Methodology & Results ............................................................................................................ 44

5.3 Analysis of Aspen-Plus Generated Atmospheric Emission Estimates ...................................... 57

6 Significance of Pilot Plant Performance Data and ASPEN-Plus Emissions Estimates For Australia ........................................................................................................................................................... 58

7 Conclusions ......................................................................................................................................... 60

8 Recommendations for future work .................................................................................................... 63

References ....................................................................................................................................................... 65


Acknowledgments

The authors wish to acknowledge financial assistance provided through Australian National Low Emissions Coal Research and Development (ANLEC R&D). ANLEC R&D is supported by Australian Coal Association Low Emissions Technology Limited and the Australian Government through the Clean Energy Initiative.

The authors would like to thank the appointed ANLEC Reviewers Geoff Bongers and Peter Nelson for their detailed comments.


Summary

This report is the final project deliverable of the Activity 3 entitled “Process modelling for amine-based CO2 Post Combustion Capture plant”. This activity was carried out as one of the five activities of the project funded by ANLEC R&D “Environmental Impacts of Amine-based CO2 Post Combustion Capture (PCC) Process”. The model-based process simulation software ASPEN-Plus, was used to simulate the anticipated atmospheric emissions from an amine-based CO2 PCC plant.

This report is an extension of the previous work reported to the ANLEC R&D as Tasks 3.1 and 3.2 Milestone Reports for the project. It includes additional public domain information on the oxidative and thermal degradation of monoethanolamine (MEA), 2-amino-2-methyl-1-propanol (AMP), piperazine (PZ) and their blends, as observed during laboratory experiments and pilot plant trials. It also reports the likely emissions of these solvents and their degradation products to the atmosphere, if they were to be used to reduce CO2 emissions from an Australian black coal-fired power generation plant.

Amines are mainly lost in an amine-based absorption/stripping system due solvent vaporisation, amine entrainment in the flue gas and amine degradation in the process. The two firsts occur at the top of the absorber column causing amine emissions to the air. ASPEN simulation results showed that a well designed water wash column can be used to recover most of the amine losses by volatility.

Solvent degradation can also occur through irreversible side reactions with different constituents in the flue gas such as O2, NOx and SOx to produce volatile and non-volatile degradation products. These products affect the CO2 absorption capacity of the solvent, corrosion, increase viscosity and provoke release of volatile degradation pollutants to the atmosphere. The process simulations undertook in the current study considered the degradation behaviour and possible degradation pathways for selected amines to predict the potential releases to the atmosphere of major degradation products from the PCC plant for optimised operating conditions.

Due to limitations of the analytical and emission measurement techniques, the solvent degradation products have not yet been fully identified and quantified. However, various pilot plant-performance data point to mist and aerosols formation during CO2 capture, and their contribution to the total emissions of parent amines and their degradation products from absorbers.

Particulate matter and fly ash present in coal-fired power plant flue gas are now known to act as seeds for heterogeneous condensation or nucleation for aerosol formation. Similarly, SO3 present in this gas stream at concentrations as low as 1 ppmv can potentially contribute to sulphuric acid mist formation, which gives opacity to the CO2 lean gas stream. Sudden quenching of the water-saturated gas within the absorber also causes homogeneous nuclei formation via condensation. These nuclei grow by condensation and dissolution of amine vapours and its degradation products, forming sub-micron size aerosols. Brink mist eliminator-type candle filters are only 65–90% effective against aerosols of


atmospheric emissions to the process operating parameters for the wash tower observed at the pilot plant scale is in the same range as that predicted by the Aspen-Plus process simulation software, and reported to ANLEC R&D in our Task 3.2 project report in 2012.

The atmospheric emissions of MEA and its degradation products have been studied with a greater degree of clarity than the AMP/PZ blend. Studies undertaken at SINTEF (Scandinavia’s largest independent research organisation), funded by Norway’s full-scale CO2 Capture Mongstad (CCM) project, have provided more detailed and useful information on the topic. SINTEF has emulated industry practice at the laboratory scale with their solvent degradation rig. They measured the rate of formation and accumulation of various degradation products of MEA, including alkylamines, nitrosamines and nitramines.

The results of the SINTEF study, though strictly valid for processing natural-gas-fired flue gas, were used for estimating the atmospheric emissions of MEA degradation products at the industrial scale when processing black coal-fired power plant flue gas using the Aspen-Plus process simulation software. The results from these simulations are given in Table 1 and compared with Task 3.1’s results.


Table 1 Comparison of latest predicted atmospheric emissions with those reported in Task 3.1 report at 40 °C

Compound New estimate of atmospheric emissions Atmospheric emissions (Task 3.1 report)

mg/Nm3 dry CO2 lean gas mg/tonne CO2 mg/Nm

3 dry CO2 lean gas mg/tonne CO2

Minimum Maximum Minimum Maximum Minimum Maximum Minimum Maximum

Monoethanolamine (MEA) 1.08E-01 1.08E-01 3.60E+02 3.60E+02 1.4E-01 1.4E-01 4.36E+02 4.43E+02

Diethanolamine (DEA) 2.02E-09 2.31E-06 6.77E-06 7.76E-03 0.00E+00 3.0E-05 0.00E+00 8.4E-02

2-oxazolidone (OZD) 9.51E-09 1.09E-08 3.19E-05 3.66E-05 0.00E+00 0.00E+00 0.00E+00 0.00E+00

N,N’-bis(2-hydroxyethyl)oxalamide (BHEOX) 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00

N-(2-hydroxyethyl)acetamide (HEA) 3.73E-12 4.27E-12 1.25E-08 1.43E-08 0.00E+00 0.00E+00 0.00E+00 0.00E+00

N-(2-hydroxyethyl)-glycine (HEGly) 6.67E-12 7.63E-12 2.24E-08 2.56E-08 0.00E+00 0.00E+00 0.00E+00 0.00E+00

4-(2-hydroxyethyl)piperazin-2-one (HEPO) 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00

N-(2-hydroxyethyl)formamide (HEF) 5.33E-13 6.10E-13 1.79E-09 2.05E-09 0.00E+00 0.00E+00 0.00E+00 0.00E+00

N-(2-hydroxyethyl)imidazole (HEI) 1.47E+01 1.52E+01 4.92E+04 5.11E+04 0.00E+00 0.00E+00 0.00E+00 0.00E+00

MEA-NO2 (Nitramine) 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00

Ammonia 1.08E-01 6.59E+00 3.63E+02 2.21E+04 1.0E-03 1.2E-01 2.8E+00 3.74E+02

Dimethylamine 1.04E+00 1.04E+00 3.47E+03 3.49E+03 0.00E+00 0.00E+00 0.00E+00 0.00E+00

Methylamine 1.00E+01 1.00E+01 3.36E+04 3.37E+04 2.1E-01 2.2E-01 6.68E+02 7.03E+02

Ethylamine 3.78E-01 3.80E-01 1.27E+03 1.28E+03 0.00E+00 0.00E+00 0.00E+00 0.00E+00

Diethylamine 1.32E-02 1.35E-02 4.42E+01 4.53E+01 0.00E+00 0.00E+00 0.00E+00 0.00E+00

Nitrosodiethylamine (NDEA) 5.02E-09 5.72E-09 1.68E-05 1.92E-05 0.00E+00 0.00E+00 0.00E+00 0.00E+00

Nitrosodimethylamine (NDMA) 7.29E-08 8.27E-08 2.44E-04 2.78E-04 0.00E+00 0.00E+00 0.00E+00 0.00E+00

Nitrosodiethanolamine (NDELA) 6.65E-02 6.72E-02 2.23E+02 2.26E+02 0.00E+00 0.00E+00 0.00E+00 0.00E+00


Nitrosomorpholine 1.95E-06 2.17E-06 6.54E-03 7.28E-03 0.00E+00 3.0E-06 8.9E-03 8.9E-03

Formaldehyde 2.69E-01 2.74E-01 9.02E+02 9.19E+02 2.6E-01 2.7E-01 8.48E+02 8.85E+02

Acetone 8.13E-02 1.00E-01 2.73E+02 3.37E+02 3.1E-01 3.3E-01 1.01E+03 1.08E+03

Acetaldehyde 1.56E-01 1.66E-01 5.22E+02 5.58E+02 3.0E-01 3.0E-01 9.34E+02 9.66E+02

Acetamide 2.08E-07 9.60E-05 6.98E-04 3.22E-01 0.00E+00 1.1E-03 0.00E+00 4.0E-01

i Process Modelling for Amine-based Post-Combustion Capture Plant

The revised Aspen-Plus results confirm that:

(1) The extent of degradation of MEA, and the distribution of its degradation products occurring when processing black coal-fired power plant flue gas, could be similar to that occurring when processing a natural-gas-fired flue gas stream.

(2) Though a greater number of different thermal degradation products have been identified by the

solvent degradation rig study than in the work done by Davis55

(which was the basis for the

Task 3.1 work), these products are unlikely to be emitted to the atmosphere.

(3) Nitramines are unlikely to be an atmospheric emission issue, because their carryover with

CO2-lean gas leaving the absorber section is below ppbv levels.

(4) The formation of nitrosamines is driven by the presence of the secondary amine DEA produced as a by-product of the MEA degradation when the later is used as a solvent to

capture CO2. The extent of emissions will depend upon what measures have been put in place with regard to efficient working of the water wash tower.

(5) The wash water stream (WW1) leaving the wash tower has a noticeable level of alkylamines and nitrosamines. Thus, the effective disposal of wash water should be assessed for a full-scale capture plant. This also applies to the in-line activated carbon filters that are used after the trim cooler to control the build-up of organic acids and phenolic compounds in the lean

solvent in an amine-solvent-based CO2 capture plant.

The pilot scale trials so far confirm that accuracy of emission quantification depends on the:

sampling techniques employed

frequency of calibration of on and off-line instruments

type of filters, sorbents, water traps, etc. used in the sampling lines

handling and storage condition of samples for any off-line analysis.

More research and standardisation work needs to be done to build confidence in the numerical accuracy and reproducibility of these measurements.

In light of the above limitations, the following work program is proposed:

(1) Identify, evaluate and standardise various on and off-line techniques and instruments suited for

the CO2 capture environment of a demonstration plant to quantify the emissions of various

inorganic and organic species.

(2) Identify, evaluate and rank various solvent degradation and corrosion inhibitors, at bench and pilot scales, which could minimise solvent degradation and atmospheric emissions in full-scale amine-solvent-based post-combustion capture (PCC) technologies.

(3) Fully characterise and quantify degradation products of amine solvents, both in the gas and liquid streams, in an Australian pilot scale PCC plant. The plant chosen should operate at steady state in gas–liquid flow regimes representative of current industrial-scale PCC plants.

(4) Develop process improvements around the direct contact cooling (DCC) tower and the water wash towers downstream of both absorber and stripper in an Australian pilot plant, to minimise first, the adverse impact of flue gas impurities on amine solvents, and second, the atmospheric emissions of amine solvents and their degradation products.


Part I Current State of Post-Combustion

Capture

Knowledge

3 Process Modelling for Amine-based Post-Combustion Capture Plant

1 Introduction

Commercially available technologies using aqueous amino solvents to remove acid gases from natural and synthetic gas streams have been universally viewed as an appropriate technological solution to curb carbon dioxide (CO2) emissions from fossil-fuel-fired power plant flue gas streams. Laboratory and pilot plant data from CSIRO and other research institutions show that these solvents undergo oxidative and thermal degradation during post-combustion capture (PCC) of CO2. The degradation process will produce different volatile and non-volatile degradation products. Nitrosamines and nitramines may also be produced during the degradation process depending on the existing operating conditions and chemical reactions occurring in the process. Some of these compounds can potentially be released to the atmosphere in both the vapour phase and the droplet phase, along with the parent solvents, and may adversely affect the environment.

The objective of this project is therefore to:

1. estimate, from the laboratory and pilot plant data, the likely emissions of amino

solvents and their degradation products into the atmosphere, if they are used in a

large-scale PCC plant connected to a black coal-fired power plant.

2. explain, in an Australian context, the significance of the pilot plant operating data for

minimising the atmospheric emissions of solvents and their degradation products.

This report is an extension of the previous work reported to ANLEC R&D as Tasks 3.1 and 3.2 Milestone Reports. The current report includes additional public domain information on the oxidative and thermal degradation of aqueous amine solvents observed during laboratory experiments and pilot plant trials. It also reports the likely emissions of these solvents and their degradation products to the atmosphere for an Australian black coal-fired power plant using available data in the public domain. When possible, emissions have been estimated by process modelling using Aspen-Plus process simulation software.

The overall project objective is to understand the environmental impact of amino solvents when implemented for PCC at a large scale from a black coal-fired power plant flue gas stream. Therefore, emphasis has been given to those amino solvents currently in use for this application, either commercially or at the technology demonstration scale. These solvents are monoethanolamine (MEA), 2-amino-2-methyl-1-propanol (AMP), piperazine (PZ) and their blends.


2 Current State of PCC knowledge

Since early 2000, technology developers and research institutions have concentrated on developing aqueous amine-based PCC technologies. The principal aim is to reduce the energy efficiency and cost penalties associated with large-scale PCC from coal-fired power plant flue gas streams. These efforts have led to some pilot scale trials on slip streams no larger than 5–25 MWe from power plants. The distinction between these technologies depends on the process configurations, the type of amine solvents used and the mode of integration into the power plant. Amines can interact with selected constituents of the flue gas such as NOx, SOx, O2, particles, to produce different degradation products that will affect the performance of the solvent to capture CO2. All current CO2 capture technologies recommend a flue gas stream with SOx and NOx below 10 ppmv and preferably below 2 ppmv to minimise solvent usage and cost

Several available PCC technologies are currently being investigated at the pilot plant trial stage. These include Fluor’s Econamine FG+, Mitsubishi Heavy Industries KS-1, Cansolv Technology, Alstom/Dow Chemical Advanced Amine Process (AAP), Aker Clean Carbon,

Hitachi, and Toshiba Corporation. Stephen Mills1 gives a full list of these technologies, along

with their history of development and general description of the relevant amine solvent. He also includes details of the capacity and locations of pilot plants, the TRLs, and the next planned phases of activity for commercial implementation of carbon capture and sequestration. The pilot scale trials have essentially involved testing for improved performance of the amine solvent, capture equipment and/or process configuration. The trials are aiming to reduce:

the physical and chemical loss of solvent (vapour and droplet-phase emissions of solvent and solvent degradation)

equipment corrosion

energy demand for solvent regeneration

fixed and operating costs of PCC.

Almost all of these technologies claim to reduce the energy demand for solvent regeneration: from around 4 GJ/tonne of CO2 captured (with conventional MEA solvent), to as low as 2.8 GJ/tonne of CO2 (with MHI KS-1, Toshiba TS-1 and Alstom/Dow UCARSOL FGC 3000 series amine solvents). However, comparison of actual solvent performance is very difficult. This is because the exact formulation of amine solvent – including the additives, such as reaction rate promoters and amine degradation inhibitors – is usually proprietary information.

Nevertheless, Mangalapally et al2-4

show that all such solvents have a preferred operating

range, which depends on the capture plant design, flue gas characteristics (e.g. composition,

temperature, flow rate) and level of CO2 capture targeted. Similarly, Dumée et al5 indicate

that in a capture plant, chemical and thermal degradation processes often occur simultaneously to produce a range of degradation products. More than 100 temporary or permanent products can occur, depending on the flue gas composition, the extent of corrosion of equipment, the working temperatures and the type of pre-treatment operations employed.


The extent of solvent degradation is therefore affected not only by the specific additives used in the solvent formulation, but also by the time for which the solvent has remained in service without reclamation or pre-treatment. One example is that of the Alstom/Dow Chemical

Advanced Amine Process6 being trialled at their plant, which has a capacity of 5 tonnes of

CO2 per day and is based at South Charleston, West Virginia. The process uses UCARSOL FGC 3000 solvent and restricts the SOX content of flue gas at the inlet to the absorber below 20 ppmv. The trials showed that the overall heat-stable salt formation due to solvent degradation remained below 0.5% w/w, but accelerated to 4.5% w/w when the upstream SOX/NOX scrubber and the electrodialysis reclamation unit were switched off. This confirms that removing flue gas impurities and their degradation products maintains solvent quality.

Similarly, pilot plant trials at the Dong Energy’s Esbjergvaerket pilot plant in Denmark, which used uninhibited 30% w/w MEA, gave solvent degradation rates of 1.4 to 2.4 kg/tonne CO2. In contrast, later trials with the same solvent at the lignite-fired Nideraussem pilot plant in

Germany gave only 0.3 kg/tonne CO27. This plant is owned by German companies RWE and

The Linde Group and was commissioned by chemical company BASF. In both trials, the composition profile of the degradation products was weighted towards species formed via an

oxidative degradation pathway, as proposed by Goff and Rochelle8, Rooney et al

9 and

Vevelstad10

. Very limited formation of thermal degradation products such as oxazolidone,

1-(2-hydroxyethyl)imidazoline-2-one (HEIA) and N-(2-hydroxyetrhyl-ethyelnediamine (HEEDA) occurred in the trials. The limited reporting of SOX/NOX-induced degradation products for these trials undoubtedly reflects the relatively low levels of SOX/NOX present in the flue gas, due to the use of flue gas desulphurisation (FGD) and NOX reduction systems upstream.

Primary amines such as MEA are not expected to directly interact with nitrosating agents existing in the PCC process to form nitrosamines. In a commercially operated, 600 tonnes per day CO2 capture plant owned by global power company, AES Corporation, and based at

Shady Point, Oklahoma, which uses 10 to 18% MEA11, nitrates and nitrites were identified

and reported. In other reported trial results, Strazisar et al12

report detection of nitrosamines

at 2.91 µmol/mL in the lean amine stream of the 800 tonnes per day IMC Chemicals plant based at Trona, California, which uses MEA. Assuming that all of the nitrosamine

compounds are present as nitrosodiethanolamine (NDELA), as proposed by Schallert13,14

,

then the concentration of nitrosamines measured by Strazisar et al is equivalent to 390 mg of NDELA per litre of lean amine solvent. This seems rather high. However Strazisar et al’s quantification was based on a generalised functional group test for NO, and did not detect any specific nitrosamines. The authors further state that nitrosamines were not detected in the reclaimer bottoms, perhaps due to their low boiling point. On the issue of nitrosation of

MEA, Fostås et al15

have recently shown that during CO2 capture operations, MEA can

degrade into the secondary amine diethanolamine (DEA). DEA is then nitrosated by reaction with nitrites formed in the aqueous phase from NOX, and thus forms nitrosamines.

For CO2 capture plants that use inhibited aqueous MEA solvent and operate commercially at a capacity of at least 600 tonnes per day, the AES Shady Point and Trona-based plants provide some guidance towards aerosol formation in the absorber and identification of the solvent degradation products in the reclaimer.

Arnold et al11

studied aerosols and provided various liquid stream composition analyses

undertaken for the AES Shady Point plant in 1982. The CO2-lean gas leaving the water-wash tower downstream of the absorber section at this plant was found to carry out aerosols of monoethanolamine sulphate and ammonium sulphate. These compounds are products of the reaction of SOX with MEA and ammonia, respectively. The wash water entrained in the CO2-lean gas had a droplet size of less than 5 microns, with the majority


being less than 3 microns. A subsequent retrofit of a Brink mist eliminator downstream of the wire-mesh demister in the wash tower had almost eliminated atmospheric emissions of the aerosols and fine droplets from the plant. Tables 2 and 3 give the analysis of various liquid samples obtained from the plant. The composition of the MEA absorber exhaust line condensate corresponds to the composition of the droplet phase wash water, which is

carried along as entrainment in the CO2-lean gas stream. Arnold et al11

further state that the

solvent reclamation operation at the plant usually indicated insignificant solvent degradation.

Table 2 Liquid sample analysis at AES Shady Point Plant11

Analysis Absorber

wash water Stripper

reflux water

MEA absorber exhaust-line condensate

pH 8.7 6.4 9.0

Cl- (%)


The performance of the Trona plant, as well as the solvent degradation issue, was studied

by Strazisar et al12

in 2003. They analysed virgin concentrated MEA solution from the

storage tank for presence of impurities, and lean MEA solution at the inlet to the absorber and the reclaimer bottoms for solvent degradation impurities. Table 4 lists the solvent degradation products identified by these authors in the reclaimer bottoms sample.

Table 4 Solvent degradation products identified at Trona plant in the reclaimer

bottoms12

Compound Chemical formula

N-Formylethanolamine C3H7NO2

N-Acetylethanolamine C4H9NO2

2-Oxazolidone C3H5NO2

N-(hydroxyethyl)succinimide C6H9NO3

N-(2-hydroxyethyl)-lanthamide C5H11NO3

1-Hydroxyethyl-3-homopiperazine C7H14N2O2

1-(2-hydroxyethyl)-2-imidazazolidnone C5H10N2O2

1-Hydroxyethyl-2-piperazinone C6H12N2O2

4-Hydroxyethyl-2-piperazinone C6H12N2O2

3-Hydroxyethylamino-N-hydroxyethyl propanamide C7H16N2O3

2-Hydroxyethylamino-N-hydroxyethyl acetamide C6H14N2O3

Ammonia NH3

Acetic acid C2H4O2

Propionic acid C3H6O2

n-Butyric acid C4H8O2

Monoethanolamine C2H7NO

2,6-Dimethyl-4-pyridinamine C7H10N2

2-Imidazolecarboxaldehyde C4H4N2O

1-Methyl-2-imidazolecarboxaldehyde C5H6N2O

Very limited information is available in public domain about pilot scale performance of amine

solvents other than 30% w/w MEA. Knudsen et al16

describe the performance of CESAR 1

and CESAR 2 solvents at the Esbjergvaerket pilot plant, under the European Union- sponsored CESAR program for development of novel amino solvents, which started in early

2008. Table 5 gives some details of this plant. The authors now disclose17

that CESAR 1 is

a mixture of AMP and PZ in water (3M AMP + 2M PZ), whereas CESAR 2 is an aqueous solution of 5M ethylenediamine (EDA).

During 2000 hours of plant trials for each solvent at a 90% CO2 capture rate, Knudsen et al determined that with intercooling of the absorber, CESAR 1 requires 2.8 GJ of thermal energy per tonne of CO2 to regenerate. A similar campaign with an intercooled absorber for 30% w/w uninhibited MEA revealed a regeneration energy requirement of 3.7 GJ per tonne of CO2. Thus, CESAR 1 uses 25% less energy to regenerate than 30% MEA. The absorber also operated adequately at a 33% lower liquid:gas ratio when using CESAR 1 than that


required for MEA for the same capture duty. Measurements taken over 500 hours of continuous plant trials showed that consumption of AMP and PZ were 0.73 and

0.15 kg/tonne CO2, respectively, compared with 2.3 kg/tonne CO2 for MEA. Knudsen et al17

claim that MEA loss was mainly due to degradation, whereas AMP loss was mainly due to emission and reaction with SOX.

The Task 3.2 Milestone Report for this project shows that in the presence of NOX in flue gas, PZ is known to form mono and di-nitrosopiperazine, which are considered to be toxic and carcinogenic. These compounds were not reported during the plant trials of CESAR 1 solvent. These plant trials further indicate that the iron content of uninhibited MEA solvent accelerated to about 800 mg per litre of solution in less than 200 hours of operation. In contrast, even after 1000 hours of operating at full load, the iron content of CESAR 1 remained less than 10 mg per litre of solution. This shows that AMP/PZ blend is less corrosive than MEA. In comparison with CESAR 1, CESAR 2 was found to be very corrosive and less advantageous on all counts.

Table 5 Dong Energy (Esbjergvaerket) pilot plant specifications16

Parameter Design value

Fuel Bituminous coal

Flue gas capacity (after flue gas desulphurisation) 5000 Nm3/h (0.5% slip stream)

CO2 removal (at 12% by volume CO2) 1000 kg/h

CO2 capture efficiency 90%

Maximum solvent flow 40 m3/h

Maximum stripper pressure 300 kPa (absolute)

Flue gas condition 47 °C @ inlet to absorber,


Cansolv blend (0.42 M DIHEP + 0.58 M HEP) has a lower CO2 absorption potential, but

higher desorption potential, than 1 M MEA solvent. Aronu et al18

quote US Patent 6500397,

filed by Yoshida et al19

, for their assertion that MHI solvent KS-1 is a blend of AMP and PZ.

If this is true, then the information published by MHI comparing atmospheric emissions of KS-1 solvent with that of conventional MEA solvent during capture of CO2 from coal combustion flue gas is very useful for understanding the influence of SOX and NOX in flue gas.

Recent publications by Kishimoto et al20

, Endo et al21

and Kamijo22

state that to minimise

degradation and atmospheric emissions of solvent when processing flue gas from a coal-fired power plant, the build up of particulate matter in lean solvent needs to be less than 10 ppmw, and the SO3 content of flue gas at the absorber inlet must not exceed 0.1 ppmv. Submicron particulate matter carried with the gas stream in a gas–liquid contactor is known to act as heterogeneous nuclei, around which condensation of vapours causes aerosol formation. Similarly, SO3, when carried in a gas stream containing water vapour, serves as homogeneous nuclei for producing acid mist. Condensation of vapour-phase amines around

such mist particles facilitates formation of amine aerosols in CO2 absorbers23

. The amine

aerosols are responsible for the visible plumes of CO2-lean flue gas leaving the absorber top. Figure 1 compares the plume visibility of MHI plants A, B and C while processing flue gas with and without SO3.

Figure 1 Impact of SO3 presence in flue gas on amine solvent emissions22

Table 6 quantifies the influence of SO3 content of flue gas on the atmospheric emissions (total of vapour plus droplet phase) of KS-1 and conventional MEA solvents.


Table 6 Influence of SO3 content on atmospheric emissions of KS-1 and

monoethanolamine (MEA)22

SO3 concentration at absorber inlet

(ppmv)

KS-1 emissions (ppmv)

MEA emissions (ppmv)

3 23.2 67.5

1 9.1 29.8

0 0.4 0.8

The above publications20-22

further state that in MHI’s 10 tonne-per-day pilot plant, based at

J-Power’s Matsushima power plant, KS-1 solvent consumed 1– 3% of flue gas NOX. This resulted in the formation of heat-stable salts at low levels after 5000 hours of operation. MHI claims that the overall solvent loss (including loss due to degradation) is less than 1 kg per tonne of CO2. No further information is available from MHI on either the characterisation or quantification of degradation products from KS-1, their atmospheric emissions, or how the

process operation parameters affect the emissions. However, Mertens et al24

state that the

Esbjergvaerket CO2 capture plant, which used the CESAR 1 solvent (3M AMP and 2M PZ), was equipped with on-line continuous measurement techniques, such as flame ionisation detection (FID) and Fourier transform infrared spectroscopy (FTIR), to monitor the effect of various process parameters on the atmospheric emissions of AMP and PZ. The parameters included the wash tower operating conditions, the lean amine solvent temperature at the absorber inlet, and the CO2 content of flue gas. Mertens et al report that increasing the CO2 content of flue gas left less ‘free’ amine in the solvent, and therefore, emissions of AMP and PZ at the outlet of the wash section decreased. Similarly, lowering the CO2 loading of lean solvent increased the wash tower load for the same operating conditions, resulting in higher emissions. Lowering the wash water temperature or increasing the frequency of changing water (more makeup water) lowered emissions of both AMP and PZ. Figures 2 to 5 show the plant performance data in terms of atmospheric emissions of AMP and PZ. The Task 3.2 Milestone Report submitted to ANLEC R&D, which used Aspen-Plus modelling software, estimated the impact of wash tower operating conditions on atmospheric emissions of AMP and PZ along similar lines.


Figure 2 Effect of increased cooling water flow rate on atmospheric emissions24

Figure 3 Effect of increasing temperature difference over the wash section (i.e.

decreasing wash tower temperature) on atmospheric emissions24


Figure 4 Effect of carbon dioxide (CO2) concentration in flue gas on atmospheric

emissions24

Figure 5 2-amino-2-methyl-1-propanol (AMP) and piperazine (PZ) emissions over one

month of continuous operation24


Seventy per cent of total AMP loss was determined by Mertens et al24

as vapour phase

emissions, whereas for PZ, the figure was 3%. AMP therefore has a higher volatility than PZ,

in accordance with the observations of Nguyen et al25-27

. The remaining losses (30% for

AMP, 97% for PZ) were determined to occur through several other mechanisms: e.g. formation of heat-stable salts, gaseous emissions of degradation products, and AMP and PZ losses with waste water from the plant. This suggests that the volatility of amines, rather than droplet entrainment, is the dominant pathway for atmospheric amine emissions from AMP/PZ blends. Volatile organics, such as formaldehyde, acetaldehyde and ammonia, were not detected at the outlet of the wash section, due to the functional limits of on-line

measurement equipment. Mertens et al24

gave no gas or liquid sample analysis results for

the AMP/PZ blend campaign, and do not present any evidence for detection or otherwise of either oxidative or thermal degradation products of AMP and PZ. These include mono-nitrosopiperazine (MNPZ) and di-nitrosopiperazine (DNPZ), which are expected to be formed due to nitrosation of PZ in the presence of NOX in the flue gas. The Task 3.2 Milestone Report has already pointed out that various carboxylates, ammonia, acetone, 2,4-lutidine (dimethyl pyridine) and 4,4-dimethyl-2-oxazolidine are the main oxidative degradation products of AMP, whereas ethylenediamine, N-formyl piperazine, various carboxylates and oxalyl amides are the main degradation products of PZ.

While analysing amine solvent degradation in a PCC environment and its impact on the resulting atmospheric emissions, a very important point to discern is that the full list of pilot

scale technology trials compiled by Stephen Mills1 includes trials in which commercial

technology vendors, such as Fluor Daniel, Dow Chemicals, Cansolv and MHI, are participants. Such pilot plant trials may have involved amine solvent formulations with proprietary solvent degradation and corrosion inhibitors. Hence, the atmospheric emissions noted from such trials could differ, both qualitatively and quantitatively, from trials in which the amine solvent used is generically the same, but its formulation is plain or uninhibited. For example, trials at a 5-tonne-per-day CO2 capacity plant by Alstom/Dow Chemical at South

Charleston, West Virginia, used UCARSOL FGC 3000 series amine solvent6. Similarly, the

Cansolv and EON consortium used CANSOLV DC-103 series solvents for 7.5-MW-scale

trials at Heyden, Germany28

, and the Fluor Daniel and EON consortium used Fluor

Econamine FGPlus

amine solvent at 5-MW-scale trials29

at Wilhelmshaven, Germany. All

these examples involved the use of inhibited solvents. Trials making use of plain or

uninhibited solvents include Dong Energy’s Esbjergvaerket pilot plant trials30

in Denmark

and RWE/Linde/BASF commissioned Nideraussem pilot plant trials7 in Germany. Figures 6

and 7 clearly show that by using appropriate inhibitors, solvent degradation can be seriously

altered31

. These results were obtained in a laboratory in conjunction with 40% w/w MEA

solvent development trials (HiCapTM

process, developed by the French Institute of

Petroleum (IFP) at a 2.25 tonnes-per-hour capacity pilot plant operated by power company Enel at Brindisi, Italy.


0

250

500

750

1000

1250

1500

1750

2000

2250

2500

0 1 2 3 4 5 6 7

time (days)

[NH

3] p

pm

without inhibitor

V1

V2

V3

V4

V5

V6

V7

V8

Figure 6 Ammonia formation from 40% w/w monoethanolamine solvent degradation at

80 oC with and without inhibitors V1 to V831

0

2000

4000

6000

8000

10000

12000

14000

16000

18000

none V1 V2 V3 V4 V5 V6 V7 V8

Inhibitor (0,25%-wt)

An

ion

Co

nce

ntr

atio

n (

pp

m)

0

50

100

150

200

250

300

350

400

V1 V2 V3 V4 V5 V6 V7 V8

formiate

acetate

oxalate

nitrate

nitrite

Figure 7 40% w/w monoethanolamine oxidation at 80 oC with and without inhibitors V1

to V831

The issue of amine solvent loss due to degradation and degradation of solvent causing corrosion particularly in the equipment parts made out of carbon steel, stainless steel and copper alloys is being studied by technology vendors to develop the appropriate inhibitors to reduce the operation costs of their capture plants. This is why increasingly higher amine concentrations (more than 30% w/w MEA, versus previous levels of 10–18% w/w MEA) and treating flue gas with oxygen content up to 15% v/v has now become possible in the

commercial arena32

.


Voice and Rochelle33

claim that diethylene triamine penta acetic acid (DTPA) is one of the

best corrosion inhibitors to use with MEA. Among the sulphur-containing inhibitors, dimercaptothiadiazole (DMTD) has also been considered a very effective corrosion inhibitor,

though it is relatively costly. In addition to DTPA and DMTD, Voice and Rochelle33

recommend diethylene triamine penta methylene phosphonic acid (DTPMP) and hydroxy ethylidene diphosphonic acid (HEDP). These additives suppress ammonia and formic acid formation as a result of oxidative degradation by as much as 80%, and only need to be added to the lean MEA solution at less than 1% w/w. Recent results from Rochelle;s

research group33

suggest that a mixture of HEDP and DTPA, when added to lean MEA

solution at 1.5% w/w, suppresses ammonia formation by up to 97%.

The oxygen scavengers, such as sodium sulphite (Na2SO3), hydrazine (N2H4), carbohydrazide (H6N4CO), erythorbate, methylethylketoxime (MEKO), hydroquinone,

diethylhydroxylamine and their mixtures are listed in the public domain literature34

for either

passivating metal surfaces (by creating an oxide layer), or binding chemically the dissolved oxygen in amine solutions. Similarly, proprietary corrosion inhibitors, for example Max-Amine

GT-741C made by General Electric (GE)35

, are used to prevent corrosion of process

equipment caused by dissolved CO2 and organic acids.

Unfortunately, quantitative information about atmospheric emissions of degradation products of inhibited solvent (e.g. nitrosamines, nitramines) from commercial technology suppliers is very restricted. This is despite CO2 PCC plants commercially operating on coal combustion

flue gas streams since the 1970s. To date, only one publication12

is available in the public domain that has dealt with amine solvent degradation products in a commercially operating plant environment. Useful information, at least for uninhibited MEA and AMP/PZ solvents, has only lately become available in public domain. Some of this information has been previously used for completing project Tasks 3.1 and 3.2. Since submission of those milestone reports, additional information has become available, which is summarised in Sections 3 and 4 and is used to complete Tasks 3.3 and 3.4 of this project.

In summary, a number of pilot plant-scale trials of amine-solvent-based PCC processes are

ongoing globally. Stephen Mills1 describes these technologies in detail. The trials have

essentially involved testing for improved performance of the amine solvent, capture equipment and/or process configuration. The aim is to reduce physical and chemical solvent losses (vapour and droplet phase emissions of solvent and solvent degradation), equipment corrosion, energy demand for solvent regeneration, and costs (both fixed and operating) of PCC. Very little data has been published from these trials to could explain the effect of solvent degradation and corrosion inhibitors on atmospheric emissions of amine solvents and their degradation products. The data published so far covers mainly uninhibited MEA and blends of AMP/PZ, and shows that SOX present in flue gas contributes towards amine solvent loss via aerosol formation. The extent of atmospheric emissions depends upon the capture plant design and the way it is operated, particularly the water wash tower.


Part II Atmospheric Emissions of

Monoethanolamine

(MEA) and Its

degradation products


3 Summary of the Latest Existing Information Related to Emissions from PCC

The Since 2008, Dong Energy’s Esbjergvaerket pilot plant in Denmark and the RWE/Linde/BASF Niederaussem pilot plant in Germany have been testing the effect of inorganic impurities in power plant flue gas on uninhibited 30% w/w MEA solvent. The trials analysed the formation of heat-stable salts in amine solvent, overall MEA loss over more than 2000 hours of continuous operation, and emissions of MEA and its degradation products at the outlet of the absorber section and the water-wash section. While the Esbjergvaerket pilot plant treated bituminous coal combustion flue gas, the Nideraussem pilot plant used flue gas from lignite combustion. For Tasks 3.3 and 3.4 of this project, the data on the performance of MEA solvent at Esbjergvaerket pilot plant is relevant. Dahlin et

al36, 37

also provide some data on the performance of uninhibited MEA solvent, which was

measured in the Pilot Solvent Tests Unit (PSTU) operating at National Carbon Capture Test Center (NCCC), Alabama, United States. The PSTU uses 0.5-MW equivalent flue gas slip stream from the coal-fired Alabama Power’s Plant Gaston power station. At the laboratory and process development unit scale, SINTEF has dealt with uninhibited MEA degradation and emissions from CO2 absorber within the CO2 Capture Mongstad (CCM) Technology Qualification Program (TQP) Amine 6. The relevance of these studies for Tasks 3.3 and 3.4 of the ANLEC R&D project, and their implications for Australian PCC research efforts, will be discussed in the next sections.

3.1 Esbjergvaerket Pilot Plant Results

The technical details for the Esbjergvaerket CO2 absorber are given in Table 5. The trials studied the plant’s energy efficiency and optimised plant performance for various process configurations (e.g. absorber inter-cooling, lean vapour compression, rich solvent split). In addition, the quantification of emissions of various inorganic and organic species was targeted, using procedures such as iso-kinetic sampling of flue gas at inlet and outlet of the absorber, and online techniques such as FTIR and FID. The FTIR analyser (Gasmet CX 4000) was specifically calibrated for formaldehyde, acetaldehyde, MEA, AMP and PZ, as well as many other standard inorganic components such as NH3, SO2, NOX, CO, CO2, HCL and HF. The details of FID equipment, iso-kinetic sampling probes and other on and offline analytical tools used to identify and quantify solvent degradation products is given by

Mertens et al23, 38. Rohr and Shaw39 discuss the merits and limitations of the on and offline

tools and techniques used by Mertens et al23

. Authors indicated the urgent need for an

international approach to develop and validate methods for collecting and analysing samples from PCC plants.

Since ammonia (NH3) formation is a key degradation product of MEA oxidation (see Reactions 1 to 13 below), the concentration of ammonia at the absorber outlet is considered to directly represent the extent of oxidative degradation.

C2H7NO + 0.5O2 HOCH2CHO + NH3--------------------------- (1)

C2H7NO + 0.5O2 2HCHO + NH3---------------------------------- (2)

HCHO + 0.5O2 HCOOH----------------------------------------- (3)


C2H7NO + 1.5O2 2HCOOH + NH3-------------------------------- (4)

C2H7NO CH3CHO+ NH3---------------------------------- (5)

CH3CHO + 0.5O2 CH3COOH-------------------------------------- (6)

2C2H7NO + O2 2CH3COOH + 2NH3-------------------------- (7)

C2H7NO + 0.5O2 + NH3 HCONH2 + CH3NH2 + H2O-------- (8)

C2H7NO + 2O2 HOCOCOOH + NH3 + H2O-------------------- (9)

C2H7NO + 2O2 + NH3 H2NCOCONH2 + 3H2O------------------ (10)

C2H7NO + 0.5O2 H2NCH2COH + H2O-------------------------- (11)

2C2H7NO + 0.5O2 HOCH2CH2NHCHO + CH3NH2 + H2O--- (12)

2C2H7NO + 0.5O2 HOCH2CH2NHCOCH3 + NH3 + H2O----- (13)

Figure 8 shows ammonia emissions (as per cent of full scale) from the top of the absorber as

measured by the FTIR from a long-term test at the Esbjergvaerket pilot plant23

. The water-

wash section, which contained structured packing downstream of the absorber section, was further improved at this plant by addition of a single bubble cap tray. The flue gas temperature at the outlet was maintained at 50 °C during emission measurements.

Figure 8 Ammonia emissions representing oxidative degradation of

monoethanolamine23


Although the FTIR instrument was not working between 3100 and 3400 operating hours, it is clear that NH3 emissions rise over time, and double over 1000 operating hours. The NH3 emissions are positively correlated to the Fe content measured in the uninhibited MEA solvent. In this test, the solvent chemistry was not kept under control, and solvent reclaiming was not continuously applied. The high metal ion content is believed to have originated from corrosion issues at particular locations in the pilot plant. The Task 3.2 report submitted to ANLEC R&D showed that metal ions in the solvent catalyse the oxidative degradation of MEA under laboratory conditions; Figure 8 is consistent with this laboratory finding. Mertens

et al23

explain that MEA emission levels at the outlet of the absorber seem to suddenly

intensify (see Figure 9), and that frequency of such fluctuations increase over time. This is possibly due to changes in the flue gas composition at the power plant end, and changes in temperature within the absorber, resulting in spurts of fine mist formation. The power plant load changes also caused peaky behaviour of ammonia emissions (see Figure 10).

Figure 9 Peaky behaviour of monoethanolamine emissions at absorber outlet23


Figure 10 Impact of power plant load changes on ammonia (NH3) and

monoethanolamine (MEA) emissions23

Mertens et al23

observed that reducing water temperature from 50 to 35 °C in the

water-wash tower downstream of the absorber temporarily reduced emissions of both NH3 and MEA by a factor of three. However, emissions then started rising to a new equilibrium due to the continuous degradation of MEA to NH3 in the absorber. This implies that for atmospheric emissions to remain at a set level in a practical situation, the wash water circulation rate, temperature and concentration of MEA and NH3 need continuous monitoring and management. This control stategy will also need to take into account fluctuations in the power plant load level. Table 7 shows the concentrations of various inorganic species

measured17

during two hours of steady-state operating conditions at the inlet and outlet of

the wash tower when the flue gas outlet temperature was set at 50 °C. These results clearly imply that fly ash in flue gas must be breaking through the CO2 absorber, despite the use of high-surface-area structured packing. The absorber must therefore have captured some coal fly ash, and the accumulated fly ash in the solvent may be contributing towards accelerating solvent degradation. The wash tower, with its add-on bubble cap tray, finally acts as an additional polisher of atmospheric emissions. As postulated by Kolderup et al40, the carryover of fly ash through the absorber must act as a source of heterogeneous nuclei for condensation of water and MEA vapours. This leads to the formation of amine aerosols, which eventually break through the water-wash tower as well. Thus, the design of the wash tower, its internals and its operating regime are critically important in managing gaseous and droplet-phase atmospheric emissions from PCC plants.


Table 7 Atmospheric emissions of inorganic species using monoethanolamine17

Wash tower inlet

(mg/Nm3)

Wash tower outlet

(mg/Nm3) Compound

CO2 13.2 1.7

CO 9.8 12.4

HCL 0.06


Table 8 Atmospheric emissions of organic species using monoethanolamine17

Compound

Absorber inlet

(mg/Nm3)

Wash tower outlet

(mg/Nm3)

No polisher Polisher

Formaldehyde


3.2 National Carbon Capture Centre Pilot Solvent Tests Unit Results

This test unit is owned by the United States National Carbon Capture Centre (NCCC) and located at Wilsonville, Alabama. It operates on a 0.5-MW-equivalent flue gas slipstream from Alabama Power’s Plant Gaston power station. It has been used since March 2011 to test

uninhibited MEA and advanced proprietary solvents33,37

. Iso-kinetic sampling probes fitted

with impingers and sorbent tubes are used to identify and quantify emissions of solvent degradation products. Table 9 describes analytical procedures and techniques employed at this unit for the droplet/condensate phase analysis. Table 10 describes the details of sorbent tubes and analytical procedures used for analysing certain chemical species. These procedures are accredited by the Environmental Protection Agency, National Institute of Occupational Safety and Health, and Occupational Safety and Health Administration.

Table 9 Analysis of droplet/condensate phase at National Carbon Capture Centre test

unit36

Chemical species Analytical

procedures Technique

Volatile organic compounds (includes ketones)

EPA 8260C GC/mass spectroscopy

Nonhalogenated organic compounds

EPA 8015B Direct injection GC

Volatile fatty acids EPA VFA Direct aqueous injection GC

Carbonyl compounds (includes aldehydes)

EPA 8315A High-performance liquid chromatography

Nitrosamines RJ Lee internal method

Thermal energy analyser

EPA = Environmental Protection Agency; GC = gas chromatography

Table 10 Analysis of sorbent tubes at National Carbon Capture Centre test unit36

Chemical species

Analytical procedures

Sorbent tube description

Nitrosamine NIOSH 2522 Thermosorb N

NIOSH 2522 Thermosorb N; glass fibre for nitrosodiethanolamine

Ketones NIOSH 1300 CS charcoal

NIOSH 1550 CS charcoal for total hydrocarbons

Amine scan OSHA 60 Naphthylisothiocyanate on XAD-2 resin

Formaldehyde NIOSH 2539 Hydroxymethyl piperadine on XAD-2 resin

OSHA 52 Hydroxymethyl piperadine on XAD-2 resin

Aldehyde scan NIOSH 2532M 2,4-dinitrophenylhydrazine on silica gel

CS = coconut shell; NIOSH = National Institute of Occupational Safety and Health; OSHA = Occupational Safety and Health Administration


To understand the levels of degradation products emitted with CO2 lean flue gas and virtually pure CO2 product streams, emissions were measured at the wash tower outlet and the CO2 regenerator condenser drum outlet. Except for stating that the PSTU is made of

316L stainless steel, Dahlin et al36

have not adequately described the plant operating

conditions for the quantification of degradation products. However, Table 11 summarises the emission measurements obtained using the techniques and equipment listed in Tables 9 and 10.

Table 11 Degradation products quantified to date at National Carbon Capture Centre

test unit36, 37

Compound

Wash tower outlet (ppmv) CO2 regenerator (ppmv)

Vapour Liquid Vapour Liquid

Monoethanolamine 4.40 131 0.061 Not detected

Formaldehyde 0.035 0.28 0.505 1.58

Acetaldehyde 0.63 0.063 1.78 0.36

Ammonia 53.7 86.4 0.152 3.3

Ethylamine 0.036 ND ND ND

Dimethylamine 0.043 ND ND ND

Acetone NM 0.18 NM 0.033

Acetonitrile NM 0.039 NM 0.023

Acetic acid NM 0.021 NM 0.020

Propionic acid NM 0.23 NM 0.26

N-nitrosomorpholine (NMOR) 0.000025 0.0287 NM ND

N-nitrosodiethanolamine (NDELA) 0.0011 ND ND ND

N-nitrosodimethylamine (NDMA) 0.00022 ND 0.0000058 ND

ND = not detected; NM = not measured

In Table 11, the measured droplet phase (liquid) concentration is expressed as ppmv in vapour stream. In comparison with Dong Energy’s Esbjergvaerket pilot plant results, the NCCC emissions show higher MEA and ammonia losses, but nitrosamines are definitely detected and quantified. The vapour-phase emissions of NDELA are higher than that of N-nitrosodimethylamine (NDMA), though NDMA is considered more volatile. Surprisingly, the product CO2 stream carries higher concentration of aldehydes than CO2-lean flue gas. This implies that in an actual plant environment, recycling condensate from the CO2 regenerator to the absorber wash tower for washing CO2-lean free gas may increase aldehyde emissions. To reduce atmospheric emissions of MEA and its degradation products, NCCC trialled the concepts of an additional water wash and a separate acid wash of flue gas. Data presented in Table 12 shows that water wash removes vapour phase emissions more efficiently than acid wash.

Dahlin et al36

confirm that SO3 formed in the power plant boiler reacts with water vapour and

condenses in the form of an ultrafine sulphuric acid aerosol, which escapes collection in the wet FGD tower and enters the amine scrubber. The acid aerosol droplets then collect amine vapour and carry it through the absorber. The droplets escape collection in the wash tower due to their very small size. These authors further indicate that despite using 316L as


construction material, corrosion still occurs, and that corrosion-inhibiting additives are required in the MEA solvent formulation. Figure 11 shows that the concentration of iron, nickel, chromium and manganese – all constituents of 316L steel – in the CO2-rich solvent increases with time. The concentration of arsenic, barium, cobalt, selenium and zinc in CO2-rich MEA solution also rose: from several hundred parts per billion (ppb) to several thousand parts per billion over 400 hours of operation (see Table 13).

. Table 12 Effect of additional washing on vapour emissions at National Carbon

Capture Centre test unit37

Compound Wash tower outlet (ppmv)

Removal efficiency (%)

No wash Acid wash Water wash Acid Water

Monoethanolamine 4.40 3.02 2.13 31 52

Formaldehyde 0.035 0.002 0.0031 94 91

Acetaldehyde 0.63 0.49 0.73 22 –16(as

reported)

Ammonia 53.7 4.75 1.74 91 97

Ethylamine 0.036 0.033 0.026 8 28

N-nitrosodimethylamine (NDMA) 0.00022 0.000037 0.000017 83 92

Figure 11 Corrosion of stainless steel 316L at National Carbon Capture Centre test

unit37


Table 13 Concentration of heavy metals detected in monoethanolamine (MEA) at

National Carbon Capture Centre test unit37

Metals Inlet gas

(ppb)

Liquid concentrations (ppb) Suspected source of

build-up Fresh MEA Makeup water Final CO2-rich

MEA

Arsenic 3.62


Table 14 Maasvlakte pilot plant specifications43

Parameter Design value

Fuel Medium sulphur bituminous coal

Flue gas capacity (after flue gas desulphurisation) 1500 m3/h (0.4 MWe equivalent)

CO2 removal (at 12.36% by volume CO2) 250 kg/h

CO2 capture efficiency 90%

Maximum solvent circulation rate 5 tonnes/h

Maximum stripper pressure 300 kPa (absolute)

Flue gas condition 47 °C @ inlet to absorber,


For the detection and quantification (as mg per m3 of gas sample) of aerosols, three instruments were used. The focus of these measurements was assessing the usefulness of a BDU as a means to reduce fine mist emissions. The instruments were:

Two fog sensors, one each before and after the BDU

An aerodynamic particle sizer (TSI 3321 model) for measuring the particle-size-dependent aerosol concentration in gas samples

An electrical low-pressure impactor (Dekati model).

The concentrations of MEA and its degradation products (e.g. nitrosamines, nitramines) in the CO2-lean and rich solvent streams, in water wash liquid and in liquid collected by the BDU were determined by tandem liquid chromatography, triple quadruple mass spectrometry (LC-MS-MS-QQQ) using an Agilent 1290/6460 instrument. In addition, lithium (Li) and rubidium (Rb) carbonates were used as tracers to quantify physical entrainment of liquid (as droplets) from the absorber and water-wash sections. Further details of the emissions measurement techniques and instruments employed during the uninhibited MEA

test campaign are given in the SINTEF report43

.

The pilot plant trials showed the presence of NDELA, nitrosodimethylamine (NDMA) and nitrosomorpholine (NMOR) in the concentration range of 2.0–2.1 mg/L in the CO2-rich MEA solvent. Presence of H2SO4 fine mist at a concentration of 18 mg/Nm

3 at the inlet to the CO2 absorber caused significant amine aerosol formation in the absorber. Rapid cooling in the absorber or water-wash system led to growth of aerosols, which once formed, could not be captured in the water-wash tower or by the YORKMESH demister. Solvent degradation products such as heat-stable salts were not detected in the gas phase, and less hydrophilic compounds, such as ammonia, were not carried over in aerosols. However, MEA from the gas phase condensed on aerosols, with temperature changes occurring in the absorber and water-wash tower, which resulted in amine carryover by aerosols.

Aerosols were found to be a major contributor to overall emissions, whereas physical entrainment of liquid was a small contributor. The average aerosol concentration in the gas stream before the water-wash section was determined to be 120 ppmv, of which only 50% was reduced by the water wash. The fog sensor confirmed that the size of aerosol particles after the water wash of the gas stream was in the range of 0.75–0.78 µm.

The trials further revealed that at inlet of the BDU, the average concentration of NDELA was 25 ng/Nm3 of dry gas, but in the liquid sample collected from BDU, the NDELA concentration was equivalent to 53 ng/Nm3 of dry gas. This implies that tiny fibres within the BDU created a very large surface area for nitrosation of amine droplets (


emissions, which remained around 20–70 mg/Nm3. Such high ammonia emissions are due to the higher oxygen content of absorber feed gas (17.2% v/v, vs 7% v/v in power plant flue gas). It is very surprising that, contrary to the results from Dong Energy’s Esbjergvaerket pilot plant and NCCC’s PSTU trials, the Maasvlakte pilot plant trials did not detect any aldehydes and ketones in gas or condensate samples (see Reactions 2, 5 etc. in Section 3.1). This was despite the flue gas having a high oxygen concentration (17.2% v/v), and the FTIR instrument being calibrated for detecting these compounds.

The above results clearly imply that in a PCC plant processing coal-fired power plant flue gas, aerosols will be formed at much higher level, due to a higher concentration of CO2 (12 to 13% v/v vs 3.4% v/v). A higher concentration of CO2 will definitely lead to sharp temperature differences across the absorber and the water wash tower. In such an environment, presence of fly ash in the gas stream will create a bigger source of condensation nuclei. Using a BDU as the ultimate device for reducing the aerosol emissions in that environment will produce a greater pressure drop, and hence an increase in overall electrical energy requirement of more than 7%.

3.4 SINTEF CO2 Capture Mongstad Technology Qualification Program Amine 6 Research Results – Laboratory Results

In addition to their involvement with the TNO-operated pilot plant, SINTEF has separately

studied uninhibited amine degradation at bench scale46

, using a complete absorber and

stripper set-up that looks to emulate realistic process operating conditions. Figure 12 shows the system, which SINTEF calls the solvent degradation rig (SDR). Compared with a purely oxidative or thermal experimental setup, the SDR permits the study of the possible influences of different degradation mechanisms. It is also equipped to provide an overview of potential emissions to air from the absorber without the presence of emission-reducing technologies, thus representing a worst-case emission profile.

A structured packing with a high specific surface area is used as the gas–liquid contactor in both columns, which have a 50-mm internal diameter and are made from 316L stainless steel. The two-column system can be operated as an open, closed or combination system (once-through, total or partial recycling) with regards to the gas side. The liquid solvent is

circulated between the absorber and stripper. Typically, 3 m3/h of gas circulation and 10 L/h

of 30% w/w uninhibited MEA solvent circulation are possible in the SDR. During the solvent degradation campaign, the liquid-to-gas (L/G) ratio for the absorber was 0.002 m3 per m3. For the industrial-scale, 30% w/w MEA-based PCC plant, this ratio is normally 0.001 m3 per m3. The Aspen-Plus simulations for MEA degradation used the latter ratio in Task 3.1 of this

project. Further details of the SDR are given elsewhere46

.


Figure 12 SINTEF solvent degradation rig46

Within the CCM TQP Amine 6 research program, the SDR was operated continuously for 14 weeks, using uninhibited MEA and the gas composition representative of flue gas for the natural-gas-fired Mongstad CHP plant. The experiments involved four different cases; variations in the process parameters are summarised in Table 15. In all cases, the absorber liquid inlet temperature was 40 °C. The lean and rich loadings for the solvent were around

0.2 and 0.45 moles of CO2 per mole of amine, respectively. The CO2-lean gas was cooled to

20 °C before being released in air.


Table 15 Summary of process parameters for SINTEF’s solvent degradation rig46

Condition Stripper temperature (oC)

O2 (mol%) NOX (ppmv) Duration (weeks)

Standard 120 12 5 5

High oxygen 120 18 5 3

High stripper 140 12 5 3

High NOX 120 12 50 3

During the experiments, samples of lean and rich amine solvent, condensate (vapours condensed in the area downstream of absorber packing) and CO2-lean gas emissions were analysed according to the CCM TQP Amine 4 process protocol. MEA and its degradation products were analysed by LC-MS-QQQ, except for total nitrosamines, which were analysed by gas chromatography-nitrogen chemiluminescence detector (GC-NCD). MEA

concentration was also determined by titration with H2SO4. CO2 was determined by a total

organic carbon analyser operated in inorganic modus, and the metals were analysed by high-resolution-inductively coupled plasma mass spectrometry (HR-ICP-MS). Lean MEA samples were also analysed for a range of known degradation products, including: DEA, HEPO, (HEI), N-(2-hydroxyethyl)-glycine (HEGly), HEF, BHEOX, HEA and 2-oxazolidone (OZD). All of these results are shown in Figures 13 and 14.

Figure 13 Degradation products of lean monoethanolamine as a function of time46


Figure 14 Diethanolamine (DEA) concentration in lean monoethanolamine as a

function of time46

In addition to the standard thermal degradation products of MEA stated above, a number of nitrosamines and alkylamines were detected in the lean MEA solvent, along with 2-nitroamino ethanol (MEA-NO2) and ammonia. The nitrosamines identified are NDELA, nitrosopiperidine (NPIP), nitrosodiethylamine (NDEA), NDMA, nitrosomethylethylamine (NMEA), NMOR, nitrosodibutylamine (NDBA), nitrosodipropylamine (NDPA) and nitrosopyrrolidine (NPYR). The concentration of total nitrosamines was determined as the equivalent concentration of NDMA in the lean MEA solvent. Tables 16 to 18 provide the quantification of these degradation products determined in lean MEA solution.

Table 16 Quantification of nitrosamines in lean monoethanolamine solvent46


Note: All specific nitrosamines were analysed by tandem liquid chromatography, triple quadruple mass spectrometry. Total nitrosamine (NA) group detection was analysed by gas chromatography.

NDEA = nitrosodiethylamine; NDELA = nitrosodiethanolamine; NDBA = nitrosodibutylamine; NDMA = nitrosodimethylamine; NDPA = nitrosodipropylamine; NMEA = nitrosomethylethylamine; NMOR = nitrosomorpholine; NPIP = nitrosopiperidine; NPYR = nitrosopyrrolidine

Table 17 Concentration of various alkylamines and ammonia (NH3) in lean solvent46

Table 18 Liquid chromatography-mass spectrometry measurements of nitramine

(MEA-NO2) in lean solvent46

To monitor possible corrosion during the campaign, lean samples were regularly analysed for metals (V, Cr, Fe, Ni and Mo) by HR-ICP-MS. Table 19 shows the metal concentrations as a function of time.


Table 19 Metal corrosion indicators for 30% w/w uninhibited lean monoethanolamine46

The SINTEF Report F2260846

indicates that the CO2-lean gas was cooled to 20 °C before

leaving the SDR. As a result, a large amount of MEA and its degradation products condensed downstream of the absorber packing. The condensate was drained periodically and recycled with regenerated amine solvent. The condensate samples were collected through two sample points, V01 and V28, which were strategically located on the SDR. The exact details of these locations and their strategic significance are explained on the P&ID for the SDR, which is given in the SINTEF report. Tables 20 to 23 reproduce SINTEF’s identification and quantification of MEA and its degradation products. The total condensate data (V01 + V28) represents the combination of physically entrained liquid, any aerosol captured and water, plus organic vapours condensed downstream of the absorber packing. SINTEF has not sized or quantified the aerosol and physically entrained liquid present in the

CO2-lean gas leaving the SDR.

Table 20 Monoethanolamine (MEA) concentration in the condensate collected in the

solvent degradation rig46


Table 21 Concentration of nitrosamines in the condensate collected in the solvent

degradation rig46

NDEA = nitrosodiethylamine; NDELA = nitrosodiethanolamine; NDBA = nitrosodibutylamine; NDMA = nitrosodimethylamine; NDPA = nitrosodipropylamine; NMEA = nitrosomethylethylamine; NMOR = nitrosomorpholine; NPIP = nitrosopiperidine; NPYR = nitrosopyrrolidine

Table 22 Results for nitramine (MEA-NO2) in condensate46


Table 23 Concentration of alkylamines in the solvent degradation rig condensate46

The results presented in Figures 13 and 14 and in Tables 16 to 23 confirm the following points:

1. A high oxygen and NOX content of flue gas and high stripper temperature increase MEA degradation.

2. Except for the aldehydes, the degradation compounds identified in the SDR are in line with observations made at Dong Energy’s Esbjergvaerket pilot plant and NCCC’s PSTU: though the SDR feed gas represents natural gas combustion, whereas the flue gas for other units represents coal combustion. In other words, the flue gas composition does not affect the type of MEA degradation products formed, but might affect their relative concentrations. Of course, this does not apply to SOX-related MEA degradation, since combusted natural gas will not contain SOX.

3. The presence of formamides, acetamides and oxamides in the CO2-lean MEA

solvent implies that aldehydes must have been produced during solvent degradation in the SDR, but that the degradation reactions proceeded beyond formation of aldehydes.

4. If the laboratory-scale units are truly emulating the industrial environment, then the same amine solvent degradation pathways occur in both laboratory and industrial-scale units.

5. Increasing the NOX content of gas accelerates the conversion of DEA to

nitrosamines, which decreases the concentration of DEA in the CO2-lean MEA

solvent. In other words, the rate of formation of nitrosamines exceeds the rate of MEA degradation to DEA.

6. NDMA, NDELA and NMOR are the predominant nitrosamines formed during degradation of MEA solvent. This observation is in line with the pilot plant-scale trials with uninhibited MEA solvent in the NCCC test unit at Alabama (see Table 11). NDMA is a more volatile nitrosamine than NDELA, and its concentration in the condensate is therefore higher than that of NDELA. Conversely, more NDELA is detected in the lean amine solvent than NDMA.


7. The higher concentration of NDMA in the condensate stream is in line with the observations made at the NCCC test unit (see Table 12).

8. Increasing the stripper temperature increases the rate of formation of alkylamines, but reduces the amount of nitrosamines present in the lean solvent and in the condensate streams. This implies that to some extent, nitrosamines may have been thermally destroyed or stripped out in the solvent regenerator (reboiler).

9. A high oxygen and NOX content of flue gas and high stripper temperature increases the level of metal leaching (corrosion) in the uninhibited solvent, and this further catalyses the degradation of solvent.

10. The lack of thermal degradation products (e.g. OZD, HEPO, HEI, HEGly) detected in the condensate implies that thermal degradation products are unlikely to be an atmospheric emission issue for large-scale PCC plants.

Despite SINTEF’s detailed experimental work, which focused on emulating the industrial operating conditions in a laboratory environment, it is difficult to understand why heat-stable salts were not detected in the lean solvent circulating for 14 weeks in the SDR. The

published SINTEF report does not explain whether this was deliberate, or due to no SO2

being added to the feed gas.


4 Atmospheric Emissions of 2-amino-2-methyl-1-propanol (AMP)/ piperazine Blend and its Degradation Products

As mentioned in the Task 3.2 report for this project, the oxidative and thermal degradation of

AMP has been studied at bench scale by Wang and Jens47

, Lepaumier et al48, and Eide-Haugmo et al

49, and the oxidative and thermal degradation of PZ has been studied

extensively by Freeman50

. Lately, Wang51

has released information in the public domain

about the oxidative and thermal degradation of 3.5 M AMP and 1.5 M PZ blend at bench scale. At the pilot plant scale, a 3M AMP and 2M PZ blend has been tested as CESAR1

solvent17

at Dong Energy’s Esbjergvaerket pilot plant and EON’s Maasvlakte pilot plant52

.

The performance of the first plant with AMP/PZ blend and related atmospheric emissions of AMP and PZ were described in Section 2 of this report. In the case of the latter pilot plant, the absorber and stripper details were given in Table 14: except that during the AMP/PZ blend trials, both the absorber and water-wash tower were packed with IMTP 50 random

packing, and the emissions of AMP and PZ with CO2-lean gas leaving the water-wash tower

were monitored by FTIR. Huizinga et al52

describe these plant trials and process operating

conditions, which primarily focused on assessment of water-wash tower performance. Table 24 and Figure 15 show the process trends, with atmospheric emissions of AMP and

PZ measured as mg/Nm3 of dry gas. These results clearly show that increasing the

wash-water flow rate, reducing the lean solvent temperature at the inlet to the absorber section and lowering the wash-water temperature (i.e. increasing the temperature difference between the absorber and water-wash sections) reduce the emissions. The AMP emissions are roughly one order of magnitude greater than PZ emissions, due to AMP’s greater volatility. These conclusions are consistent with those presented for an AMP/PZ blend by CSIRO in the Task 3.2 report for this project.

Table 24 Process trends and atmospheric emissions of 2-amino-2-methyl-1-propanol

(AMP)/piperazine (PZ)52


Figure 15 Effect of increasing temperature difference (□T) between the absorber and

water-wash sections on 2-amino-2-methyl-1-propanol (AMP) emissions52

A drawback of Dong Energy’s Esbjergvaerket and EON’s Maasvlakte pilot plant trials17, 52

is

that the emissions data do not cover the oxidative and thermal degradation products of AMP/PZ blend described in Sections 4.1 and 4.2. It is likely that the identification and quantification of AMP/PZ degradation products was not in the scope of investigations when

these trials were undertaken. The first public domain study51

on this subject matter only

became available in October 2012. Unfortunately, this information is not sufficient for estimating atmospheric emissions of the degradation products of AMP/PZ blend using the Aspen-Plus type process simulations software. Hence, it is not possible to further improve the emissions estimates submitted as the Task 3.2 report for this project.

4.1 Oxidative Degradation of 2-amino-2-methyl-1-propanol (AMP)/Piperazine Blend

When a blend of 3.5 M AMP and 1.5 M PZ is degraded with 250 kPa O2 in an autoclave

reactor, the major degradation products formed include ammonia, acetone, EDA, DMOZD, 2,4 lutidine, N-formylpiperazine (FPZ), OPZ, N-methylpiperazine, and three heat-stable salts: formate, acetate and oxalate. Nitrite and nitrate are also detected as degradation products.

Wang51

postulates that an hydroxyl radical (·OH) attacks NH3, which forms ·NH2, and then

·NH2 is oxidised to ·NHOH. Since ·NHOH is unstable, it rapidly converts to NH2O2– and

consequently to NO2–. Gradually, NO2

- is oxidised to NO3

–. Figure 16 represents the

measurements of Wang, which show that nitrite and nitrate ions are indeed formed during oxidative degradation of AMP.

Lean Temperature


Figure 16 Formation of nitrite and nitrate ions during oxidative degradation of

2-amino-2-methyl-1-propanol (AMP)51

Wang’s postulation could be correct, since MNPZ is also detected in the degradation product mix. These products are consistent with observations of individually degraded AMP and PZ solutions. Wang’s observation has significant implications for the industrial-scale implementation of MHI-type AMP/PZ blend-based PCC technologies, since it means that even with no NOX present in flue gas, nitroso compounds will be formed if there is excess oxygen present in flue gas. These compounds will be emitted to the atmosphere if appropriate measures are not in place. The degradation results further show that the rate of AMP degradation in the blend is the same as in the single AMP system, whereas the rate of PZ degradation in the blend is much higher than when it degrades individually under the same degradation conditions.

4.2 Thermal Degradation of 2-amino-2-methyl-1-propanol (AMP)/Piperazine Blend

Significant thermal degradation of 3.5 M AMP and 1.5 M PZ occurs in the presence of CO2.

At an initial loading of 0.3 mol of CO2 per mol of total amine, the blend exhibits 8.5% PZ and

6.4% AMP loss after being kept at 135 °C for five weeks. The overall degradation rates of AMP and PZ are 0.27 and 0.15 millimoles per kg of solution per hour, respectively. The most abundant degradation products are N-methylpiperazine (MPZ) and 4,4-dimethyl-2-oxazolidinone (DMOZD). MPZ accounts for 34% of the PZ loss, and DMOZD accounts for 42% of the AMP loss.

In summary, Wang51

concludes that increasing the CO2 loading of AMP/PZ blend increases

the oxidative and thermal degradation of the blend. Raising the blend’s temperature also increases its rate of degradation. Transition metal ions (Fe2+, Fe3+ and Cu2+) have no obvious effect on the oxidative degradation rates of AMP, which explains its low corrosion potential. Similarly, Fe2+, Cr3+ and Ni2+ ions in solution do not catalyse degradation of PZ; however, copper (Cu2+) is a strong catalyst for PZ oxidation. This implies that carbon steel


and stainless steel as materials of construction for PCC absorbers are suited for AMP/PZ applications. Copper-based corrosion inhibitors such as copper borates or carbonates, which are used in the sour gas treatment industry, cannot be used for AMP/PZ-based PCC plants.


Part III ASPEN-Plus Simulation Results


5 Improved ASPEN-Plus Estimations of Atmospheric Emissions

The information presented here and in the Task 3.2 report for this project shows that the oxidative and thermal degradation of 30% w/w uninhibited MEA solvent has been extensively studied both at the bench and pilot plant scales. Most of the pilot plant studies discussed here differ from the industrial practice, because solvent formulations for the industrial environment contain both oxidative degradation and corrosion-inhibiting additives.

The publications of Strazisar et al12

, Mertens et al23

and Dahlin et al36

have, however, shown

that the MEA degradation products identified with uninhibited solvent are more or less the same as those identified with inhibited solvent. This is after allowance has been made for the fact that not all degradation products have been identified and quantified in industrial PCC plants. Although the degradation products are roughly the same in both situations, it is highly likely that the extent of degradation and the degradation product distribution could be quite different: more towards the extreme end for uninhibited solvent.

As a result, the atmospheric emissions of MEA and its degradation products measured at the pilot plant-scale trials could represent a worst-case scenario. This could be even more so as far as hazardous products such as nitrosamines and nitramines are concerned. From the point of view of conservative environmental regulatory policy formulation, this may not be worrisome; but, such overestimations may be inherently flawed for correctly assessing the

competitive advantage of one technology over the other (e.g. Fluor Econamine FGPlus

technology vs Kerr-McGee or ABB Lummus technology). However, the assessment of competitive advantage of different technologies is not an objective of this project. Instead, we are aiming to quantify the likely atmospheric emissions when amine-solvent-based PCC technologies are deployed at full scale in black coal-fired power plant. Therefore, the SDR data from SINTEF is useful, because it provides some refinement of the atmospheric emission estimates for MEA and its degradation products, which were made in Tasks 3.1 and 3.2 of this project.

While the knowledge base for MEA solvent is somewhat robust, there is a large gap for AMP/PZ blends. No confirmed information is available in the public domain on industrial use

of AMP/PZ in a PCC plant. However, Aronu et al18

and Yoshida et al19

suggest that this

blend is a preferred component of the KS-1 solvent used in industrial PCC plants using MHI technology. In addition, the pilot scale trials of a 3 M AMP/2 M PZ blend at Dong Energy’s Esbjergvaerket and EON’s Maasvlakte power stations have not attempted to identify or quantify the degradation products present in the CO2-lean gas emitted to the environment.

The bench-scale study by Wang51

covers only a 3.5 M AMP/1.5 M PZ blend, which is

different from the blend used in the above-mentioned pilot plant trials. The solvent degradation environment employed for Wang’s study does not represent industry practice, and the study is incomplete concerning the material balance for total nitrogen and carbon. This implies that the list of oxidative and thermal degradation products identified by Wang is incomplete.


Due to the above limitations, it is not possible to improve the Aspen-Plus simulations of atmospheric emissions of AMP/PZ and its degradation products already presented in Task 3.2 of this project. The present work on improving the Aspen-Plus sim

environmental impacts of amine-based co2 post combustion capture (pcc)...

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