12. Results of amine plant operations from 30 wt% and 40 wt% aqueous MEA testing at the CO₂ Technology Centre Mongstad (2014)

Natasha Brigman^a,b, Muhammad I. Shah^c, Olav Falk-Pedersen^a,c, Toine Cents^a,b, Vian Smith^a,b, Thomas De Cazenove^a, Anne K. Morken^a,d, Odd A. Hvidsten^a,d, Milan Chhaganlal^a,d, Jane K. Feste^a,d, Gerard Lombardo^a,c, Otto M. Bade^e, Jacob Knudsen^e, Shalendra C. Subramoney^b, Berit F. Fostås^d, Gelein de Koeijer^d, Espen S. Hamborg^a,d,*

^aCO₂ Technology Centre Mongstad (TCM DA), 5954 Mongstad, Norway ^bSasol Technology, P.O. Box 5486, Johannesburg 2000, South Africa ^cGassnova SF, Dokkvegen 10, 3920 Porsgrunn, Norway ^dStatoil ASA, P.O. Box 8500, 4035 Stavanger, Norway ^eAker Solutions, P. O. Box 222, 1326 Lysaker, Norway

Abstract

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An amine plant campaign has been performed at the CO₂ Technology Centre Mongstad applying the aqueous 30 wt% and 40 wt% monoethanolamine (MEA) solvent systems for treatment of flue gas from a combined heat and power (CHP) plant. CHP flue gas flow rates were ranging from about 40.000 Sm³/h to 60.000 Sm³/h and the CO₂ content was about 3.5 vol%.

Minimum specific reboiler duties (SRD) of respectively 4.0 MJ/kg CO₂ and 3.7 MJ/kg CO₂ were obtained for the aqueous 30 wt% MEA solvent system without and with the addition of anti-foam solution. A minimum SRD of 3.4 MJ/kg CO₂ was obtained for the aqueous 40 wt% MEA solvent system. Lower SRD and absorber liquid to gas (L/G) ratios were obtained with higher concentration MEA solvents.

Increased absorber packing heights resulted in lower SRD. Variation in flue gas supply flow rates and corresponding variations in solvent flow rates, i.e. constant L/G ratios, did not yield any significant variations in SRD. Decreased flue gas supply temperatures resulted in lower SRD.

For any future large scale post-combustion capture (PCC) amine plant, engineering aspects such as the flue gas supply temperature and instrumentation monitoring CO₂ content in the flue gas must be evaluated to avoid the chemical equilibrium pinch behavior. Engineering and environmental aspects related to the use of anti-foam solutions for future large scale PCC amine plants must also be considered.

1. Introduction

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The CO₂ Technology Centre Mongstad (TCM DA) is the one of the world’s largest and  most advanced facilities  for testing and improving CO₂ capture technology. The facility enables vendors of suitable amine formulations and other post-combustion capture processes to test their process, collecting performance data to  support  full-scale  design. The vendors can then anticipate the associated performance and operating costs of their amine formulations  and capture processes. As a result, one of the main objectives of TCM DA is to investigate and demonstrate the flexibility of post-combustion amine based solvent systems with respect to load changes, variations in flue gas composition, variations in amine plant operations and solvent system compositions in order to achieve optimal and environmentally safe operating conditions. The flue gas utility system allows for flue gas supplies with varying temperatures, flow rates, and CO₂ content and also different types of flue gases with various trace components from either a combined heat and power (CHP) plant or a refinery catalytic cracker. In the CHP plant, the natural gas is combusted in a gas turbine and the flue gas content and characteristics are similar to those of a combined cycle gas turbine (CCGT) power plant. The amine plant at TCM DA is a highly flexible and well instrumented generic amine plant, designed and constructed by Aker Solutions, aimed to accommodate a variety of technologies with capabilities  of treating flue gas streams of up to 60.000 Sm³ per hour. The flexibility of the amine plant allows for handling of a wide range of flue gas flow rates, temperatures, and CO₂ content in the flue gas, and also a wide range of various operational parameters, i.e. solvent flow rates, absorber packing heights, stripper pressures, reboiler heat duties, lean amine and cross heat exchanger duties, absorber water wash temperatures and flow rates with or without acid injections, anti-foam solution injections, etc. [1, 2]

The campaign described in the current paper was conducted at TCM DA in the period December 2013 to

February 2014 as a part of Aker Solutions’ test period. In general, during the campaign the aqueous 30 wt% monoethanolamine (MEA) solvent system was applied treating the flue gas from the CHP plant.  The  primary purposes and goals of the campaign were:

• Generate results from CHP plant operations with CO₂ capture
• Generate an independently verified TCM DA amine plant base case while treating CHP plant flue gas with the aqueous 30 wt% MEA solvent system [3, 4]
• Investigate the performance potential of higher MEA concentration solvents
• Verify design capacities and flexibilities of the TCM DA amine plant and specific functionalities
• Gain better understanding of scale-up, performance, and emission aspects and transient operations of the TCM DA amine plant
• Verify and improve process simulation models
• Test and improve various online analyser for emission monitoring [5]
• Scientific dissemination of some results

These purposes and goals are aimed for gaining experience and knowledge for future large scale carbon capture and storage (CCS) projects.

This work is part of a continuous effort of gaining better understanding of the performance potential of the non- proprietary aqueous MEA solvent system, conducted by TCM DA and its affiliates and  owners, in order to test,  verify, and demonstrate CO₂ capture technologies. [3, 4, 5] The purpose of the current work is to provide results of various operational conditions of the TCM DA amine plant, and hence demonstrating some capacities, flexibilities,  and performances of the plant while treating CHP flue gases.

2. Testing Philosophy

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An overview of the TCM DA amine plant has been given elsewhere. [3, 4, 5]

The test philosophy during the current campaign was to adjust one operational parameter at  a  time,  e.g.  the solvent flow rate, the gas flow rate, etc., whilst subsequently allowing the amine plant  to  reach  steady-state  operations and simultaneously manually controlling the CO₂ capture rate to a specific value. The CO₂ capture rate    was controlled to about 85% for most of the campaign by manually adjusting the reboiler steam flow rate. The  response time of the amine plant was up to about 3 hours, depending on the varied operational parameter. The plant was operated for at least an additional 3 hours of  steady-state operations after  an operational parameter  change  before the plant was considered to provide representative process values. Any solvent sampling  for  laboratory  analysis was conducted once representative process values were obtained. Certain transient  operations  were  conducted during the campaign, and the aforementioned test philosophy was adapted in order to accommodate such operations. During Base-Case testing, as described elsewhere [3, 4], the amine plant was operated at steady-state operations for about 1 week.

Table 1 provides the main operational parameters and ranges adjusted during the campaign. Approximately 150 different operating conditions were conducted during the campaign, and the results of some of these are presented in the current work.

The calculations procedures for the various performance indices presented in the current work are as described by Thimsen et al. [3] and Hamborg et al. [4].

3. Chemicals

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MEA [CAS: 141-43-5] was supplied by AkzoNobel, and was diluted to a desired solvent concentration  by addition of demineralized water. Anti-foam solution was supplied from KCC Basildon.

4. Results and Discussion

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4.1 Mass recovery and MEA solvent concentrations

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The total mass and CO₂ mass recovery also referred to as the total mass and CO₂ mass balances, for the complete campaign, were determined as described by Thimsen et al. [3] and displayed in Figure 1. The total mass recovery is,  as expected, close to 100% during the complete campaign. The CO₂ mass recovery is however  scattered, and  this  may be attributed to inadequate instrumentation for monitoring of the CO₂ gas phase concentrations in the flue gas supply and depleted flue gas. The gas phase concentrations of CO₂ in the flue gas streams were monitored by the installed Fourier transform infrared spectroscopy (FTIR) analyzer, and accuracy and precision  challenges  with  respect to this FTIR analyzer setup has been described by elsewhere. [4] The scattering of the CO₂ mass recovery displayed in Figure 1 leads to uncertainties in the CO₂ capture rates, whereas the specific thermal use, as derived in   the current work, is independent of the FTIR analyzer system. [4]

The MEA solvent concentrations, based on sampling and laboratory analysis of the lean amine, are displayed in Figure 2. The MEA solvent concentration was maintained at about 30 wt% during most of the campaign, and was increased to above 40 wt% towards the end. The MEA solvent water balance was maintained by adjusting  the depleted flue gas temperature to the  flue gas  supply temperature, and, if necessary, addition of demineralized  water to the MEA solvent. Due to the rapid change of operational parameters and conditions and  additional  time  consuming sampling and laboratory analysis, the MEA solvent concentration could not be maintained at constant values throughout the campaign.

4.2 Overall energy performances

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Figure 3 displays the specific reboiler duties (SRD) for the aqueous 30  wt% MEA solvent system  with and  without the use of anti-foam solutions. The plant was operated with 24 meters of absorber packing heights, 1.9 bara stripper pressure, and a flue gas flow rate of about 47.000 Sm³/h at 25 °C. The CO₂ capture rate was kept at about 85%. The results in Figure 3 show a clear minimum in the SRD  of about 4.0 MJ/kg CO₂ at a lean amine loading of  about 0.25 for operations without anti-foam solutions added. Results refer to Base-Case testing as  presented  elsewhere [4] provided a SRD of 4.1 MJ/kg CO₂ and is displayed in Figure 3_. For operations with addition of anti- foam solutions, the minimum SRD is shifted towards lower lean CO₂ loadings, and the cause for this behavior is described later. The minimum SRD for these operations with anti-foam addition may have not been achieved. The  lean amine CO₂ loading can be assumed closely proportional to the MEA solvent circulation rate, assuming steady- state plant operations, and in these  specific cases solvent circulation rates approached the  minimum  achievable due  to solvent pump limitations. Lower solvent flow rates could have been achieved with the use of the solvent filtration system however this was not tested during operations with addition of anti-foam solutions. The minimum SRD obtained for operations with anti-foam solutions added was approximately 3.7 MJ/kg CO₂.

Figure 4 displays the SRD for the aqueous 40 wt% MEA solvent system. The plant was operated with 24 meters of absorber packing heights, 1.9 bara stripper pressure, and a flue gas flow rate of about 59.000 Sm³/h at 25 °C. The CO₂ capture rate was kept at about 85 %. The results in Figure 4 show a  minimum in the SRD of about 3.4 MJ/kg  CO₂ at lean amine loadings ranging between 0.2 and 0.25. A batch of anti-foam solutions were added several days prior to these tests, and the effect of the anti-foam solution was likely present during these operating conditions.

Figure 5 displays a comparison of the results presented in Figure 3 and Figure 4 as a function of the ratio of  solvent flow rate to the flue gas supply rate on mass basis (L/G ratio). Operations with the 40 wt% aqueous MEA solvent system clearly provide lower values of the SRD and L/G ratios. The use of 40 wt% or higher MEA concentrations must however be considered with respect to higher solvent degradation rates, as described by Morken  et al. [5], and possible material corrosion rates. The latter is however irrelevant for the TCM DA amine plant as it is constructed primarily of high grade stainless steel and polypropylene plastic material for absorber lining. The metal  ion concentrations were monitored during the MEA campaign, and no significant increase in ion concentration was observed for 40 wt% operations.

4.3 Effects of absorber packing heights

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Figure 6 displays the effects of absorber packing heights. The SRD obtained with 24 meters of absorber packing heights of about 4.0 MJ/kg CO₂ are lower than those of 18 meters  of about 4.5 MJ/kg  CO₂. The plant  was operated  at 1.9 bara stripper pressure and a flue gas flow rate of about 47.000 Sm³/h at 25 °C. The CO₂ capture rate was kept    at about 85 %.

It is well known that MEA is considered an amine with a relatively high kinetic reaction rate towards CO₂, and equilibrium conditions could be expected in the absorber bottom section. Solvent sampling and laboratory analysis resulted in rich solvent CO₂ loadings of about 0.44 and 0.48 for respective 18 meters and 24 meters of absorber packing heights, whereas the expected CO₂ equilibrium loading for the aqueous MEA system was approximately 0.50. Preliminary simulation work has indicated that it is most likely the kinetic rate which limits the approach to equilibrium in the test runs.

Similar trends, as displayed in Figure 6, were observed with the 40 wt% aqueous  MEA  solvent  system  at different absorber packing heights.

4.4 Effect of flue gas supply flow rates

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Figure 7 displays the effects of flue gas supply flow rates. The flue gas supply rate shows no significant effect on the SRD at specific lean amine loadings. The plant  was operated with 24  meters of absorber packing heights, 1.9   bara stripper pressure, and a flue gas supply temperature of 25 °C. The CO₂ capture rate was kept at about 85 %. At specific lean amine loadings it can be assumed that the amine plant was operated at close to identical conditions for  the various flue gas supply flow rates, except the correlated adjustment of the solvent flow rate. This would ideally create a constant L/G ratio for the various flue gas supply flow rates at a certain lean amine loading. The minor differences in the SRD between the various flue gas supply flow rates at a certain lean amine loading must therefore  be attributed to normal operational variations of the various amine plant unit operations.

4.5 Effect of flue gas supply temperatures

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Increased SRD were observed when increasing the flue gas supply temperatures from 25 °C to about 50 °C. The SRD  was determined to be about 4 MJ/kg CO₂ for the 30 wt% aqueous MEA solvent system at  25 °C flue gas  supply temperatures, whereas the SRD was determined to be about 5.0 MJ/kg CO₂ for 50 °C flue gas supply temperatures. Some increase is expected due to the  temperature dependent  CO₂ vapor liquid equilibria behavior in  the absorber bottom, leading to a lower rich amine loading at increased  absorber bottom  temperature, and the fact  that the partial pressure of CO₂ is slightly lower in the flue gas supply stream of 50 °C than 20 °C  leading to  decreased mass transfer driving forces. However, the more important aspect encountered during these test conditions  at elevated flue gas supply temperatures was chemical equilibrium pinching of the  upper  section  of the  absorber. This was encountered when the lean amine loading was not sufficiently low, i.e. the CO₂ equilibrium pressure in the lean amine solvent entering the absorber is close to or identical to the actual CO₂ partial pressure in the gas phase of the upper section of the absorber. At such conditions little mass transfer will occur in the upper section  of the absorber, as mass transfer driving forces are low. In order to avoid such chemical equilibrium pinching,  the  lean amine loading would need to be lowered by e.g. increasing the stripper bottom temperature. Aspects around this are described further below.

The chemical equilibrium pinch behavior, as aforementioned, was encountered primarily as a result of the very

low targeted depleted flue gas CO₂ partial pressure, as is a consequence of CO₂ capture  from  low partial  CO₂ pressure CHP flue gases. Assuming flue gas supply CO₂ content of about 3.5 vol% and a corresponding partial pressure of about 35 mbara by assumption of ideal gas law behavior, the depleted  flue gas  CO₂ partial pressure  would be about 5 mbara at 85 % CO₂ capture rate. In order to avoid and control such chemical equilibrium pinching behavior for any future large scale PCC amine plants in the upper section of  the  absorber,  engineering  considerations such as e.g. flue gas supply temperatures and sufficient instrumentation for monitoring of the CO₂ content in the depleted flue gas should be taken into account.

4.6 Effect of stripper behavior

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Figure 8 and Figure 9 displays the effect of addition of anti-foam solution to the solvent. The effect of anti-foam solution addition on the SRD is more pronounced at lower lean amine loadings. The plant was operated at 1.9 bara stripper pressure and a flue gas flow rate of about 47.000 Sm³/h at 25 °C. The CO₂ capture rate was kept at approximately 85 %.

Addition of anti-foam solutions showed no impact on the absorber temperature profile as displayed  by Figure  8, but showed a considerable impact on the stripper temperature profile as displayed  by Figure 9. The temperature  values displayed in the Figure 8 and Figure 9 are the average value of four temperature sensors in the radial plane at each axial column position. For operations without anti-foam solutions, the stripper temperature profile shows relatively high temperatures in the upper section of the stripper of about 115 °C. It is well known that such will lead   to excessive  amounts of  water vapor leaving the stripper and being further directed  to the overhead condenser,  which will lead to an unnecessarily high SRD. Upon analysis of the stripper temperature profiles in the radial plane and axial direction, it was concluded that transient channeling in the stripper bed occurred during operations without addition of anti-foam solution. This resulted in poor gas liquid distribution and contact, and condensation of the stripping gas and water vapor occurred in the overhead condenser rather than inside the stripper bed. Addition of anti-foam solution reduced the channeling behavior in the stripper, and well defined  as  expected  stripper  temperature profiles were obtained in the axial direction, as displayed by Figure 9,  and  minor  temperature  differences were observed in the radial plane. At these  stripper operating conditions,  only moderate  amounts  of water vapor, as defined by chemical phase equilibria, will leave the stripper and be further directed to the overhead condenser. This is defined as  optimal stripper behavior. The exact cause of the  observed transient steam channeling  is not yet clearly understood, however it may be caused by the solvent foaming. Engineering aspects related to this  and the use of anti-foam solutions for future large scale PCC amine plants must be considered.

Environmental aspects of the use of anti-foam in such amine plants where the depleted flue gas may be emitted to air must also be considered.

5. Conclusion

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A campaign has been performed in the amine plant at the CO₂ Technology  Centre  Mongstad  applying  the aqueous 30 wt% and 40 wt% MEA solvent systems for treatment of  flue gas from a  combined  heat and power  (CHP) plant. CHP flue gas flow rates were ranging from about 40.000 Sm³/h to 60.000 Sm³/h and the CO₂  content was about 3.5 vol%.

Minimum steam reboiler duties (SRD) of respectively 4.0 MJ/kg CO₂ and 3.7 MJ/kg CO₂ were obtained for the aqueous 30 wt% MEA solvent system without and with addition of anti-foam solution. Minimum SRD of 3.4 MJ/kg CO₂ was obtained for the aqueous 40 wt% MEA solvent system. Lower SRD and absorber liquid to gas (L/G) ratios could be obtained with the higher concentration MEA solvents.

Increased absorber packing heights resulted in lower SRD. Variation in flue gas supply flow rates and corresponding variations in solvent flow rates did not yield any significant variations in SRD. Decreased flue gas supply temperatures resulted in lower SRD, as rich amine loadings increased and chemical equilibrium  pinch  behavior in the upper section of the absorber was limited.

Engineering aspects such as flue gas supply temperatures and instrumentation for  gas  phase  monitoring of the CO₂ flue gas contents must be considered for any future large scale PCC amine plant in order to avoid chemical equilibrium pinch behavior during treatment of CHP flue gases. Engineering and  environmental  aspects  related to  the use of anti-foam solutions for future large scale PCC amine plants must also be considered.

Acknowledgements

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The authors gratefully acknowledge the staff of TCM DA, Gassnova, Statoil, Shell, Sasol, and Aker Solutions for their contribution and work at the TCM DA facility.

The authors also gratefully acknowledge Gassnova, Statoil, Shell, and Sasol as the owners of TCM DA and Aker Solutions for their financial support and contributions.

References

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