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ScienceDirect
Energy Procedía
Energy Procedia 1 (2009) 195-204
www.elsevier.com/locate/procedia
GHGT-9
Performance of Formulated Solvent in Handling of Enriched CO2
Flue Gas Stream
Ahmed Aboudheir*, Walid ElMoudir
HTC Purenergy Inc., 001 2305 Victoria Avenue, Regina, SK, S4P 0S7, Canada,
Carbon dioxide is considered to be one of the main contributors of the world climate change and flue gases from power plants emit the most CO2. To reduce the carbon footprint, CO2 capturing from flue gas becomes increasingly unavoidable to meet the CO2 emission requirements. CO2 removal with amine solvent has been gaining more and more attention as it may be the only feasible approach technically and economically. Formulated amine solvents are promising over traditional amine solvents to enhance the CO2 absorption considerably, Kohl and Nielsen (1997) [1]. It can be seen as a challenge for a CO2 removal unit to handle flue gas with a variety of CO2 concentrations, especially when the power plant is upgraded, in which its flue gas becomes enriched with CO2.
In this paper, a comparison study is carried out to demonstrate the economic potential of capturing CO2 from enriched and non-rich CO2 flue gas stream with Monoethanolamine (MEA) and HTC formulated amine solvent, which is based on mixed amines. Flue gas from combined heat and power plant with 3.5 mol. % CO2 is used as a base case and enriching it with CO2 up to 9.2 mol. % is done to simulate the gas turbine exhaust gas recycling. The study shows that it is advantageous to use HTC formulated solvent over the conventional MEA solvent mainly due to its lower steam consumption, circulation rate, power requirements, and cooling water requirements. The study also shows that the working capacity of the HTC formulated solvent is higher than the MEA solvent. These findings result in significant operating cost savings when processing enriched CO2 flue gas stream using HTC formulated solvent.
© 2009 Elsevier Ltd. All rights reserved.
Key Words; CO2 capture, flue gas, CO2 enrichment, amine, MEA, HTC Formulated Solvent.
Abstract
* Corresponding author. Tel.: +1-306- 352-6132; fax: +1-306-545-3262. E-mail address: aaboudheir@htcenergy.com.
doi:10.1016/j.egypro.2009.01.028
1. Introduction
The main greenhouse gases produced by industrial and human activity are carbon dioxide (CO2), methane (CH4), nitrous oxide (N2O), sulphur hexafluoride (SF6), perfluorocarbons (PFCs) and hydrofluorocarbons (HFCs). Greenhouse gases emissions have been classified as a main contributor to the global climate change according to the International Energy Agency, IEA, report for CO2 Capture published in May 2007 [2]. Although greenhouse gases vary in their impact on the environment as shown in Table 1 the CO2, which has less impact potential, it is considered to be the most greenhouse gas contributor by percentage of more than 65% comparing to other greenhouse gases.
Table 1. The most greenhouse gases has the most impact potential, IEA (2007) [2]
Global Warming Potential (for various time horizons)
20 years 100 years 500 years
CO, 1 1 1
CH4 56 21 6.5
N,0 280 310 170
IEA in its report for green house Burning/combustion of the fossil fuel and gas for power production and emitting flue gas, which contains CO2, are known for increasing the CO2 content in the atmosphere, IEA (2007) [2]. This will be true even in the near future based on the prediction of OPEC due to the gradual and steady increase of demand on different kind of fuel as shown in Figure 1. The booming demand of energy is caused by the fast growing economics in Asia (i.e. China and India) OPEC (2007) [3].
S 5000 s
« 4000
E 3000
5 2000
| 1000 0
2000 2005 2010 2015 2020 2025 2030 2035 —Oil -^Coal -^^Gas —e^Nrenewable Mtoe = Million Tonnes of oil equivalent Figure 1. World supply of primary energy by fuel type, OPEC (2007) [3]
To reduce the CO2 emission for power consumption, renewable types of energy might be used. However, Oil, Gas and Coal will be in the lead for consumption and this will be used for power production. It is clear that alternative ways to reduce CO2 emission should be used and the most feasible method is CO2 capture with liquid solvent IEA
(2007) [2]. This method has been widely applied in gas treatment processing for removal of acid gas (i.e. CO2 and H2S) for a long period of time, Kohl and Nielsen (1997) [1]. The captured CO2 can be used for many useful applications such as food manufacturing, chemical production (urea production), enhancing oil recovery, or simply can be stored underground in an oil or gas empty reservoir as mentioned by IEA (2007) [2] and Iijima et al (2004) [4].
Irons et al (2007) [5] show that CO2 emission can be reduced for power generation by three capture technologies: post-combustion, pre-combustion and oxy-combustion. In the first method, which is called post-combustion Capture, a liquid solvent such as amine to capture CO2 from the flue gas of power plants is used. In the second method (pre-combustion capture), the fuel is reacted with air or oxygen and then with steam (Steam Reforming) to produce a mixture of CO2 and H2. A separation between two gases is applied where CO2 is removed and the hydrogen is used as the fuel. In the last technology (Oxy-combustion) pure oxygen is used for combustion instead of air, which results in a flue gas rich with CO2 that has the potential to be used directly for EOR or store underground. The three technologies are illustrated in Figure 2.
Postcombustion
Air Separation Unit
•Enhanced Oil Recovery
•Enhanced Coal
Bed Methane
•Old Oil/Gas Fields
•Saline Formations
Fossil Fuel
Precombustion Denitrogenation
Figure 2. Three Methods for CO2 Capture, Steeneveldt et al (2006) [5]
According to Steeneveldt et al (2006) [5], IEA (2007) [2] and Irons et al (2007) [6], the first technology is the only most feasible technology to implement in near future especially for exiting power plants with amine solvents. Typical process flow sheet is shown in Figure 3. Iijima et al (2004) [4] report why CO2 capture from flue gas has not been performed much due to concerns reported in literature:
1- Its use was limited to a very small part (such as foods in those areas where CO2 is absent)
2- Its recovery has been technically difficult because flue gas is not pressurized and contains oxygen as well as SOx and NOx.
However, those difficulties can be overcome. With respect to the first point, many application of captured CO2 has been already mentioned previously IEA (2007) [2]. Regarding SOx and NOx, it has been proven experimentally that their impact can be reduced by pre-treatment of flue gas before send it to the absorber, Idem et al (2006) [7].
2. CO2 Capture: Single or Formulated Amine Solvent
Kohl and Nielsen (1997) [1] mentioned that the amine solvent has been used for a long time in natural gas processing and it has proven itself as a technical and economical feasible process. They also highlight that mixed and formulated solvent recently start gaining attention because of their high absorption and low energy demand to regenerate them. Furthermore, mixed amine solvent can lead to lower circulation flow rate which means smaller
equipment size and eventually less capital investments and operating costs required, . This has been found proven in laboratory and pilot plant Idem et al (2006) [8] as well as in industrial application Kohl and Neilsen (1997) [1]. The formulated solvent is usually a mixture of amines with the possibility of present of other ingredients to enhance the solvent stability, reduced foaming and corrosion tendencies and reduce solvent losses.
MEA solvent is usually used as a reference solvent with a concentration of 30 wt% as reported by Irons et al (2007) [6] and Idem et al (2006) [7]. The MEA with 30 wt% is already the solvent selected for Flour Process Econamine FG Plus), Steeneveldt et al (2006) [5]. In this work, this solvent has been used as the reference solvent to compare 30 wt% MEA performances with HTC formulated solvent, HTC FS.
3. Flue Gas Enrichment with CO2
The flue gas from natural gas power plant has low concentration of CO2 and typically around 4 mol.% [2]. As the CO2 capture by amines is a bulk removal process, it fevers to treat high CO2 content rather than low concentration. This will increase the driving force of absorption of CO2 in amines and make the process looks more attractive from technical and economical point of view.
Enriching flue gas with CO2 has been mentioned by many scientists Steeneveldt et al (2006) [5], Lijima et al (1999) [8], Lombardi (2003) [9], Manfrida (1999) [10], Bolland and Undruma (2003) [11], Wall et al (1995) [12], Carrea et al (2007) [13]. Although the most of those researchers have mentioned the enrichment approach in different context and it may not without utilization of amine process as removal method of CO2. In the enrichment approach, the turbine exhausted gas is partially recycled to the combustion chamber where recycled O2 is consumed and more CO2 is produced. It has been mentioned that CO2 can help control the combustion temperature to an optimum and in the same time it will help reduction the NOx formation. However, a small sacrifice of overall efficiency of the power plant might be realized as a penalty of this, Lombardi (2003) [11], Bolland and Undruma (2003) [12], and Tsukagoshi et al (2007) [14].
The comparison study between MEA 30wt% and HTC FS has been carried out by simulating of amine process using ProMax2 process simulator. The HTC amine process flow sheet is given in Figure 3 and the process description can be found elsewhere along with the assumption used for this model, Aboudheir and McIntyre (2008) [13]. The simulation model has been constructed on bases to recovery 85% of CO2. In our previous work, it has been found as an optimum CO2 recovery from natural gas flue gas with an amine process as depicted in Figure 4 and this recovery ratio is selected for all simulation cases of the comparison study.
56.0 T
54.0 --
52.0 --
85% 90%
C02 Recovery
Figure 4. Optimum CO2 Recovery from Natural Gas Flue Gas Aboudheir et al (2007) [16]
2 Process Simulator from Bryan Research & Engineering Inc, www.bre.com
Cooling Water Return
To CO! Compression
Flue Gas>_
| Cooling Water Supply
Flue Gas Cooler CIR. Pump
Figure 3. HTC Simplified Process Flow Diagram for the CO Capture Plant
4. Solvent Performance
A comparison study between HTC formulated solvent and MEA 30wt% is carried out, capturing CO2 from flue gas. The study shows superiority of HTC FS over the MEA 30 wt% in terms of process performance criteria such as utility loads and productivity. Figure 5 presents the performance of these two solvents with CO2 content of 3.5mol%. It can be seen that the circulation flow rate of HTC FS is less than that of MEA by around 35%. Steam demand of MEA solvent is about 30 % higher than that requires by HTC FS solvent. Cooling water and Power requirements are lower in the case of using HTC FS solvent than using the MEA solvent. Finally, the higher HTC FS working capacity can be noticed, which is defined as a difference between rich CO2 loading minus the lean CO2 loading. This term is used to help illustration how much CO2 can be captured and carried out by the solvent based on mol to mol basis.
Figure 5. Performance Comparison of HTC FS vs. MEA 30 wt%
5. Simulation of Combined Cycle with Exhaust Gas Recirculation
The flue gas and a recycled a part of CO2 product are used to simulate the flue gas with exhaust gas circulation in which different quantities of CO2 produced are recycled and mixed with flue gas feed stream. Many scenarios (0, to 80% recycling of the CO2 Product stream) have been prepared and the results are presented next.
The introduction of the CO2 in the feed stream would effect the amine plant process requirements and performance. As can be seen in Figure 6, the increase of CO2 concentration will lead to the demand of more solvent circulation rate for both solvents, but the quantity of solvent demands by HTC FS is less than that for MEA. For instance, at 6 % CO2 product recycle ratio and 85 % CO2 recovery rate the demands of MEA circulation Rate is 17.5 kg/kg CO2 produced, while it is only 13 kg/kg CO2 produced for HTC FS. Less circulation flow rate means smaller equipment size (i.e. heat exchangers and pumps) comparing to MEA plant leading to less capital costs.
CO2 mol% in Flue Gas Figure 6. Specific Solvent Circulation Rate vs. CO2 Content in Flue Gas
The second process parameter affected is the steam demands. The higher CO2 in the feed stream needs more steam to regenerate the solvent and release the CO2 absorbed. Figure 7 illustrates this and clearly shows that the steam requirement in case of MEA is higher than that for HTC FS. This can be translated that less operating costs would be realized. For instance and at 6 mol.% in flue gas, the steam consumption for MEA would be 1.7 kg steam / kg CO2 while for HTC FS would be 1.55 kg steam/kg CO2.
CO2 mol% in Flue Gas
Figure 7. Specific Steam Consumption (Reboiler and Reclaimer) vs. CO2 Content in Flue Gas
The other parameter that can be compared is the working capacity. More CO2 mixed with flue gas, which leads to more CO2 being removed and captured by the solvent (Figure 8). The working capacities of both solvents are narrowing as the CO2 content in the flue gas is increased; however, the working capacity of HTC FS still higher than
MEA. At CO2 content of 8 mol%, the working capacities for MEA and HTC FS are 0.28 and 0.30 mol CO2/mol solvent, respectably.
4 5 6 7 8 9
CO2 mol% in Flue Gas Figure 8 Working Capacities vs. CO2 Content in Flue Gas
Another process parameter is the cooling water. As can be seen in Figure 9, the cooling water (CW) demands would be higher for MEA than HTC FS. For example, as 8 mol.% content of CO2 in flue gas the cooling water requirement is 60 kg CW/kg CO2 captured while it is 55 kg CW/kg CO2.
O O O u
CO2 mol% in Flue Gas
Figure 9 Specific Cooling Water Requirements vs. CO2 Content in Flue Gas
The electricity power demands of the MEA case are higher than HTC FS, as presented in the Figure 10. This is mainly due to the higher circulation flow rate required for MEA in comparisons to HTC FS solvent.
CO2 mol% in Flue Gas Figure 10 Specific Power Requirement vs CO2 Content in Flue Gas
6. Conclusion
It has been seen that the higher the CO2 content (with enrichment by recycle of exhaust gas) and consequently more
CO2 production, the more benefit to the economic of amine process, as the relative cost for utilities will go down.
Furthermore, introducing HTC Formulated Solvent has shown dramatic reduction in utility loads and in the same
time increase the CO2 absorption capacity for the same conditions when comparing the MEA solvent. In brief, HTC
FS solvent relative to 30 wt% MEA demonstrated superior performance in the main performance areas expected for
the amine process of CO2 capture.
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