Carbon Capture Final Presentation for CCUS

Final Project Carbon capture

1. Course: Carbon Capture (ENPC 870) Instructor: Dr. Paitoon Tontiwathchukwul Ph.D , P.Eng. University of Regina, SK, Canada Date : August 11, 2022. Presentation on Review of the Application of Technological Processes in CO2 Capture from Coal-Fired Power Plant. A case study of Boundary Dam Unit 03 By Mazeen Abdalla - 200421889 Oluwakemi Olufayo - 200468777 Lawrence Adetu- 200478849

2. Introduction Aims and Objective Literature Review Design, Model and Simulate CO2 Capture with BD3 Processes using MEA Solvent Design Plan Discussion on comparism of Literature Conclusion and Recommendation References 2 Outline

3. Design, Model, and Simulate CO2 Capture with BD3 Processes using MEA Solvent Review boundary dam technological processes in CO2 capture by using the post-combustion method. Consider boundary dam power plant as a commercial scale of CO2 capture technologies reflects several high-risk technologies and business issues that have been overcome. Reflect the environmental impact of CCUS technology by mitigating climate change by reducing CO2 emissions. 3 Project Objective

4. 4 Introduction BOUNDARY DAM COAL FIRE POWER PLANT Boundary dam coal fire power plant is the first, commercial–scale, coal-fired power plant using amine solvent technology in, Saskatchewan, Canada. This was a global landmark event. Although carbon capture technologies had been known and well tested but not for a commercial– scale Presence of boundary dam power plant is reflecting several high-risk technology and business issues have been overcome .

5. 5 GHG Regulations, 2015. environmental and/ or socioeconomic outcomes have given a preference to continuing using coal fire in order to ensure stable pricing and electricity supply to the customers. taking foreword steps from owners and operators to retrofit (BD3 ) to continue operating by using fire-coal as a power-generator by adding CCS technology not only wasn’t easy and consumed effort and time. BD3 provided power at a competitive price in addition to mitigating climate change . 2015 new governmental regulations came into effect to reduce SO2 and NOX emissions. Sulphur dioxide (SO2) at 0.47 – 4.91 kg per MWh Nitrogen oxides (NOX) at 0.47 – 0.66 kg per MWh Particulates (PM10 + PM2.5) at 7.5 – 12 g per MWh

6. 6 GHG Regulations, 2015 and intensity supply option

7. 7 Why Choose Post Combustion Capture The use of the ability for the power plant to continue to generate cheap power for the long-term supply of coal. To get benefit from a past capital investment in the power unit and generate clean energy. The criteria for selecting the PCC technology and associated power plant retrofits were the following technical needs, commercial cost, lifecycle cost of electricity, capability to remove 90% of effluent CO2, operational flexibility, acceptable technical and financial risk, and Reasonable cost of electricity compared to alternative forms of Generation. such as NGCC

8. 8 The Effect of CCUS

9. 9 Fundamentals of coal fired power plant A coal-fired power plant is a type of thermal power plant which basically consists of turbines, steam generator, a condenser, a generator and also feed water systems. It usually generates steam with the use of energy from coal combustion in the boilers furnace with the generation of hot flue gas. Carbon capture in coal fired power plant Coal is a very interesting energy source for the generation of electricity. According to energy security viewpoint, domestic coal reserves are substantially bigger than that of other fossil fuel sources, making coal a more preferred fuel source. One of the most significant long term environmental challenges is climate change due to anthropogenic emissions of greenhouse gases (GHGs) from coal fired power plant, fossil fuel, flue gas and many other human activities. Emission of CO2 must be regulated Literature Review

10. Boundary Dam Power Station (Boundary Dam) which is located near Estevan in Saskatchewan, Canada is one of three coal-fired power plants established in the province. It consists of six units which were commissioned between 1959 and 1978 with the total capacity of 882 MW [1]. SaskPower decided to retire units 1 and 2 in 2013 and 2014, respectively because of the bigger picture of its fleet and the environmental regulations Studies for retrofit of carbon capture were taken into account and Boundary Dam Unit 3 was implemented and full operation began in 2014. Post-combustion capture was the most attractive and promising approach of all the carbon capture technologies considered for Boundary Dam Unit 3. The capture facility uses Cansolv’s licensed sulfur dioxide (SO 2 ) and CO 2 capture technology Cansolv provides amines for gas scrubbing applications [2] 10 Coal Fired Power Plants (Boundary Dam Power Station)

11. 11 Boundary Dam Power station

12. To address safety issues and construction deficiencies some major processes were carried out on the plant such as, Mitigating the unanticipated reactions of the fly ash with the amine process Investigating and in some cases improving the systems designed to remove fly ash from the plant. Increasing the thermal reclamation capability and mitigating increased degradation of the amine solvents [1] The correction achieved some milestones including: Three days of operation at design capacity (>3200 tonnes per day) by the end of 2015 Total capture of 800,000 tonnes of CO 2 within 12months between November 2015 and October 2016 Total capture of 2,000,000 tonnes of CO 2 by March 2018 and capture facility operation of 98.3 between January and April 2018 [1]. 12 Plant operation and efficiency

13. Source: Carolyn et al, 2018 13 Summary of BD3 ICCS operational histories

14. Boundary Dam Carbon Capture Volumes 14

15. Manuilova et al., 2014 performed a study to evaluate the environmental performance of the commercial carbon capture and storage demonstration project on boundary dam power station using a life cycle assessment LCA) methodology . Operations of the lignite coal fired electricity generating station with and without post-combustion CO2 capture and CO2-Enhanced Oil Recovery (CO2-EOR) were both modeled. 30%wt MEA was used as the sorbent in this study. It was reported that there was a reduction in the release of pollutants into the atmosphere but waste stream became more concentration as releases to soil and water. However, according to the study, the reduction in atmospheric pollutant outweigh that. Idem et al., 2006 evaluated the benefit of using mixed amine solvent for CO2 capture. The studies were carried out using two different pilot plant: Technology development Pilot Plant at UR and Boundary dam. MEA/MDEA were blended together and the results were compared with MEA. It was reported that huge heat-duty reduction can be achieved by using a mixed MEA/MDEA solution instead of a single MEA solution in an industrial environment of a CO2 capture plant but this depend on whether the chemical stability of the solvent can be maintained Brief overview of CO2 Capture in Boundary Dam coal-fired power station 15

16. Zhigun et al., 2017 evaluated the boundary dam spillage using an autonomous sensor fish device and objectives of this study were to determine the relative potential of fish injury during spillway and also providing validation data for a model that was used to predict the total dissolved gas levels. Nine baffle blocks were added to the spillway chute to reduce total dissolved gas production at the boundary dam. It was reported that, addition of the baffle blocks reduce the depth and impact of total dissolve gases entrance and the study can also help for design and operations to reduce spillways for living organism inside water Brief overview of CO2 Capture in Boundary Dam coal fired power station 16

17. Post combustion is the removal of CO 2 from power station flue gas prior its compression, transportation and sequestration. The major CO 2 separation methods in the exhaust gas of a coal-fired boiler are absorption, adsorption, membrane separation, pure oxygen combustion and chemical looping technology Since post-combustion capture can be applied to both new conventional coal power stations and existing stations, it attracts more attention from the scientific world and considered to be the most promising for CCS technology. Chemical absorption is the most mature technology for post combustion CO 2 in the exhaust gas reacts with CO 2 absorbent. However, during this process, CO2 is absorbed by the absorbent, then released from the absorbent after heat treatment and separated from exhaust pipe as shown in the equation below. Post Combustion in Coal Fired Power Plant 17

18. H2O decomposition 2H 2 O power → H 3 O + + OH - (1) CO 2 dissolved in water to form carbonic acid 2H 2 O + CO 2 →H 3 O + + HCO 3 - (2) H 2 O + HCO 3 → H 3 O + + CO 3 2- (3) MEA hydrolysis (R −NH 2 represents MEA) H 3 O + + R −NH 2 →H 2 O + R – NH 3 + (4) CO 2 absorption process: R − NH 2 +HCO 3 - →H 2 O + R –NH –COO - (5) R – NH 2 +CO 2 →NH 3 + + R – NH – COO - (6) MEA regeneration process R – NH – COO - + R –NH 3 + energy → CO 2 +2R– NH 2 (7) Post Combustion in Coal Fired Power Plant Cont’d 18

19. Post-Combustion Amine-Based CO2 Capture Retrofit Source: Mashood et al., 2007 Post-Combustion Amine-Based CO2 Capture 19

20. PROCESS OVERVIEW OF THE BD3 SO2 AND CO2 CAPTURE TECHNOLOGY[1],[13] 20

21. 21 Power Generation Unit Components Mol Fraction N 0.57 H20 0.23 CO2 0.11 O2 0.045 SO2 0.02 NO 0.00025 NO2 0.02475 Method of Carbon Capture from Coal[14]

22. 22 This research work focuses on two design approaches that aims to dissect the behavior of Gas – Liquid separation process used in the Boundary Dam Coal Fired Power Plant with particular interest to CO2 Capture technology. The two design approaches are listed below. Empirical Design Method calculation to Determine the KGAv , Column Height, and Column Diameter.   Process Simulation and Modelling with ASPEN Hysys Simulation Software of the Conventional BD3 SO2 and CO2 Capture Process using MEA, DEA and MDEA Solvents. Table 1: Operating Condition and Basis of Empirical Design [20] ABSORBER DESIGN An absorption column has been designed to treat 45,000 kg/hr of flue gas based on the calculated K G a v value from the previous section. The inlet amine flowrate, column diameter and height were determined and are shown below. Design Plan

23. 23 Flue Gas Composition Component in Gas Inlet (Sour Gas) Component in Gas Outlet (Sweet Gas) Component in Liquid Inlet (MEA Lean CO2 ) Component in Liquid Outlet (MEA Rich CO2) Flowrates of Gas and Liquid Type and Details of Packings Physical Information Superficial Velocities KGaV Column Height Column Diameter Empirical Design Method

24. 24 Theory (   A simplified form of Eqn. 3 is obtained as: Where: is the overall volumetric mass transfer coefficient, kmol /m 3 .h.kPa flux of the inert gas, kmol /m 2 .h ; mole fraction of CO 2 in the gas bulk ; mole fraction of CO 2 in equilibrium with liquid at the interface Z ; height of section, m P; operating pressure, kPa mole ratios of gas phase CO 2 to N 2 entering the sections of the column The was assumed to be zero in computing the because the chemical reaction is fast, and it is difficult to determine the CO 2 concentration at the gas−liquid interface ( Natewong et al., 2019)  

25. 25 Theory (Absorber design   The design of the absorber involves determining or specifying the proper absorber size required for a given CO 2 capture operation. (Liang et al., 2011) To accomplish that, the properties of the gas stream involved in the absorption process must be specified completely (including composition, temperature, pressure etc.). (Perry, 1997) The main information that is required in this process is: The liquid flowrate This can be obtained from a material balance on the column based on the inlet and outlet compositions in the gas and liquid. The type of packing for the column The type of packing is selected based on resistance to corrosion, mechanical strength, capacity for handling the required flows, mass-transfer efficiency, and cost. Depending on the choice of packing, the packing factor Fp is empirically determined for each packing type and size.(Perry, 1997)

26. 26 Theory (Absorber design   The calculation of the flow parameter ( ) should be performed by using the following equation. where, L is the liquid mass flow rate, kg/h V is the gas flow rate, kg/h the average vapor density, kg/m 3 the average liquid density, kg/m 3 The ordinate values on the flooding curve ( Figure 1 ) in the next slide correspond to a capacity parameter , given by: Where = Capacity parameter = superficial gas velocity, ft/s average gas and liquid densities, kg/m 3 packing factor, ft -1 kinematic viscosity of liquid, cS (Perry, 1997)  

27. 27 Theory (Absorber design   Using the flow parameter from the abscissa in conjunction with the ∆ P flood = 0.115* Fp 0.7, ( Kister , 1992) the capacity parameter is determined, which is used to determine the mass flow rate of the gas per unit cross sectional area. The column diameter can be computed using: Where represents the area, the mass flowrate of the gas per unit time, the mass flowrate of the gas per unit time per unit area, flooding factor and the column diameter respectively   Figure 1 : Generalized pressure drop correlation of Eckert/Leva, as modified by Strigle . From Packed Tower Design and Applications by Ralph E. Strigle , Jr., copyright © 1994 by Gulf Publishing Co., Houston, Texas. Used with permission. All rights reserved (Perry, 1997)

28. 28 calculations (   Based on Equation 4, the overall mass transfer coefficient was calculated.   The mole fractions, heights and temperature values were read from the data given in the reference paper, recorded and used for the calculations and preparations of the graphs . The gas molar flowrate was calculated based on the relation below: G = 20.16 kmol /m 2 h   Packed Column operating conditions as reported by Natewong et al., 2019 Feed gas flow rate 15 SLPM CO 2 concentration in feed gas 15 % and balance of 85% N 2 Solvent feed temperature 40 o C BEA-AMP concentration 4 kmol /m 3 Pressure in column 101.325 kPa

29. 29 calculations (   Table 1 : shows how each parameter needed for K G av calculation was obtained using Microsoft Excel The values of overall mass transfer coefficient obtained above were plotted against the packed column height as indicated in Figure 3 Figure 3 . Overall mass transfer coefficient against packed column height

30. 30 calculations (   A suitable mean was calculated by taking the geometric mean of the K G av values obtained for each adjacent point along the column height and obtained as: K G av = 0.1428 kmol /m 3 .h.kPa The average overall mass transfer coefficient based on the top and bottom values was obtained by a geometric mean of the top and bottom K G av values and obtained as: K G av (bottom/top) = 0.5868 kmol /m 3 .h.kPa

31. 31 calculations (   An absorber was intended to be designed to process an inlet flue gas stream of 45,000 kg/ hr Step 1 (Gas inlet Composition) Knowing the composition of the gas feed (15% CO 2 , 85% N 2 ) and by assuming this mixture as an ideal gas, the vol %=mol %. The average molecular weight ( of the gas mixture was calculated using the relation: where is mole fraction of species i and is the molecular weight of species i . The total molar flow rate of the gas stream was then evaluated by dividing the mass flowrate (45,000 kg/hr) by   The individual molar flowrates were then calculated by multiplying the mole compositions by the total molar flowrate of the gas, . The individual mass flowrates, were obtained from the molar masses of the gases, and the mole flowrates using: The individual mass flowrates were summed up to obtain the total mass flowrate of the inlet gas stream, The mass compositions were then calculated by dividing the individual mass flowrates by the total mass flowrate.  

32. 32 calculations (   Step 2 (Gas outlet composition) Assuming 90 % efficiency of CO 2 gas removal, the molar flowrate of CO 2 gas in the gas outlet, G out was calculated. The amount of nitrogen gas remains the same as in the inlet gas. The mole fractions were calculated by dividing the individual molar flowrates by the total molar flowrate of the outlet gas. The respective mass flowrates and fractions were calculated using same procedure described in Step 1 above Step 3 (Liquid flowrate) The lean and rich loading for the amine used was given in the reference paper as: Lean loading 0.33 mol of CO 2 /mol of amine Rich loading 0.49 mol of CO 2 /mol of amine Given the concentration of the amine solution in the paper as 4 mol/L, the molar compositions of the components in the liquid inlet and outlets were calculated using their corresponding densities and molecular weights. Tables 2, 3, 4 and 5 in the next slide summarizes the values obtained for steps 1- 3

33. 33 calculations (   Table 3 : Gas outlet composition Table 4 : Liquid inlet composition Table 2 : Gas inlet composition Table 5 : Liquid outlet composition

34. 34 calculations (  

35. 35 calculations (   The inert liquid flowrate was calculated using the following equation: Where is the inert liquid flow rate, kmol /h : inert gas flow rate, kmol /h ( 1,257.46) mole fraction of CO 2 in gas phase at the bottom (0.15) mole fraction of CO 2 in gas phase at the top ( 0.0173) mole fraction of CO 2 in liquid phase at the bottom ( 0.0541) mole fraction of CO 2 in liquid phase at the top ( 0.0371)   By substituting the values of , , and , and solving for :   was obtained as 10,703 kmol /hr Using the relation , the inlet liquid flowrate was calculated as:  

36. 36 calculations (   Step 4 (Column diameter) Due to the specified gas flowrate of 45,000 kg/h, a commercial type of packing ( Gempac 4A) was selected for the design with a packing factor of 69/m from Perry’s Chemical Engineering Handbook The and liquid kinematic viscosity were calculated from the compositions and flowrates of the gas and liquid streams As a rule of thumb, the average vapour density was reduced by 12.5 % for design to account for the less dense gas stream at the top of the column. kg/m 3 The flow parameter was also calculated as; Using the flow parameter from the abscissa in conjunction with the ∆ P flood the capacity parameter was read from the ordinate axis of Figure 1 as:   Figure 1 : Generalized pressure drop correlation of Eckert/Leva, as modified by Strigle . From Packed Tower Design and Applications by Ralph E. Strigle , Jr., copyright © 1994 by Gulf Publishing Co., Houston, Texas. Used with permission. All rights reserved (Perry, 1997)

37. 37 calculations (   Step 4 Cont’d (Column diameter) Using equation for the capacity parameter, the superficial gas velocity was calculated as (1.923 m/s) The maximum gas flow rate per cross sectional area 13 = 2.207 kg/m 2 s At 60% flooding, kg/m 2 s Hence the cross sectional area, m 2 The column diameter is obtained using Eqn. 6:  

38. 38 calculations (   Step 5 (Column Height) The empirical method based on a material balance of the transferred CO 2 to obtain the relation given below: 156.77 kmol / m 2 h   The volumetric mass transfer coefficient is assumed to be constant along the column height and it is basically correlated as a function of the operating parameters such as flow rates, pressure and temperature (Liang et al., 2011) The overall mass transfer coefficient used in the absorber design was recalculated based on the inlet and outlet compositions Substituting the values into the equation, the height of the column is calculated as: This height was recalculated with computational methods using Wolfram that indicated a 4.76% error with the method used.  

39. 39 calculations (   Step 5 (Column Height) The empirical method based on a material balance of the transferred CO 2 to obtain the relation given below: 156.77 kmol / m 2 h   The volumetric mass transfer coefficient is assumed to be constant along the column height and it is basically correlated as a function of the operating parameters such as flow rates, pressure and temperature (Liang et al., 2011) The overall mass transfer coefficient used in the absorber design was recalculated based on the inlet and outlet compositions Substituting the values into the equation, the height of the column is calculated as: This height was recalculated with computational methods using Wolfram that indicated a 4.76% error with the method used.  

40. 40   The simulation is done by Aspen HYSYS Version 10.1. The SO2 99.9% purity and CO2 70 - 98 mole% purity at the product stream determined for all simulations. Typical equipment used in simulation are separators, heat exchangers, recyclers, absorber; regenerator; reboiler and condenser; pumps; pre-heater; cooler and mixer. Three Amines were considered and a simulation process was made for each of the amines. For the amines, weight% used Iranian Petroleum Standards (IPS). The amines solution strength in mass % of MEA 15 to 25%, DEA 25 to 35%, and MDEA 40 to 50%. Flue Gas composition % by weight CO2 % 11.4 H2O % 12.6 O2 % 6.1 N2+ Ar % 69.4 SO2 (ppmv dry) 600 SO3 (ppmv dry) <1 NO (ppmv dry) 198 NO2 (ppmv dry) 2 HCL (ppmv dry) 6.7 HF(ppmv dry) 0.14 Composition of Flue Gas from Coal Fire Power Plant [25]

41. 41 MEA CO2 Absorption Simulation Process

42. 42 DEA CO2 Absorption Simulation Process

43. 43 MDEA CO2 Absorption Simulation Process

44. 44 The Amine, P r i ma r y a mi n es i n c l ud e e th a n ol a m i n e (M E A); t h e sec o nd a ry ami n es i n c l u d e d i eth a n ol a mi n e (D E A) a n d t h e t e rt i ary ami n es m e th yl d i e th a n ol a m i n e (M D EA) were considered in this simulation process to have a comparism of the capture competencies. Process Selection Specifications for Base Case CO2 removal MEA DEA MDEA Inlet gas temperature ºC 74.23 30 35 Inlet gas pressure bar(a) 20 68 10.14 Inlet gas flow kmole/h 8000 1245 1245 CO2 in inlet gas mole-% 3.5 4.13 3.12 Water in inlet gas mole-% 6.71 6.75 6 Lean amine temperature ºC 74.3 130.7 115.6 Lean amine pressure bar(a) 20 21.72 22.6 Lean amine rate kmole/h*) 8000 1479 834.5 MEA content in lean amine mass-% *) 30 25 30 CO2 in lean amine mass-% *) Number of stages in absorber 12 10 10 Rich amine pump pressure bar 15 68.95 10.14 Heated rich amine temperature ºC *) 117 93 45.96 Number of stages in stripper 20 18 20 Reflux ratio in stripper 0.5 0.5 Reboiler temperature ºC 120 82 115.6 Lean amine pump pressure bar 12 21.72 10.72 Minimum deltaT in heat exch. ºC 10 10 10 Component List Fluid Package – Acid Gas Set of Reaction Pressure Tem perature Flesh Composition of Reactants Simulation and Model

45. 45 Comparism of Overall Mass Balance of Amines Fr o m gra p h i c a l r ep r e s e nt a t i o n , s e t solve n t f lowra t e, a b s or b er a n d s t r i p p er p l a t e s, r e ge n e r a t or i n l e t t e m p e ra t u r e, solve n t w t . % a n d r e c ov e ry of C O 2 in a b s o rb er a n d s t ri p p er [ 20 , 2 1 ]. T ab le 3 a n d 4 s h ow th e ov e rall mass b al a n c e o f ami n e, r e s p ec t ively T h is s t u d y p e rf o rm e d n u m b e r s of i t e r a t i o n s t o get o pt i m u m c o nd i t io n s f or e a c h solve n t .

46. 46 Below table and graph s h o w s a t r e n d b e t w e e n duties of the three solvents MEA, DEA and MDEA. It is noted that the MEA has the highest duties and 80% of the energy is from the amine regeneration section of the simulation process. Comparism of Overall Duties of MEA,DEA,MDEA

47. 47 Solvents Circulation Concentration Absorber Stripper Reboiler Regenerator CO 2 % Name rate (wt. %) stages stages duty inlet temperature o C absorbed   (m 3 /hr)       (kW)     MEA 34.99 15 12 20 35611.1 120 89.1 MDEA 111.4 40 10 18 199.027 115 68.97 DEA 50.16 25 10 20 4377.78 082 73.5 Table above, we can easily determine which amine solvent is given more CO2 recovery in absorber at optimum conditions. In MEA, the major disadvantage is a lower circulation rate and higher reboiler duty, but it absorbed more CO2. In MDEA the major disadvantage is that it has a much higher circulation rate and it’s also absorbed least CO2 compared to other solvents. In DEA the disadvantage is higher circulation rate than MEA and low CO2 absorption capability than MEA, but it gives low reboiler duty. Comparism of Operating Conditions of MEA,DEA,MDEA

48. According to a research conducted by Raphael et al., 2006 on the use of mixed amine on coal fired power plant, the design parameters as stated in the report shows that the plant which is the University of Regina technology development pilot plant processes up to 4.8 _ 103 m 3 /day of flue gas and captures up to 1 ton of CO2 per day. A steam boiler (250 kW) is the heart of the flue gas generation/pretreatment unit which produce both flue gas and high-quality steam for the CO 2 capture unit. In the same unit is a 30 kW micro-gas-turbine connected to the steam boiler. The configuration is designed such that the boiler can operate on its own or in conjunction with the micro-gas-turbine. The CO 2 capture unit design is composed of three absorption column and each absorption column is composed of three 0.3 m-diameter sections for a total height of 10 m. Comparison of the existing design and process simulation with the present study 48

49. The operating Conditions used for the study are stated as follows, MEA concentration used for both the BD and UR plants was 5 kmol /m 3 for MEA. In the case of the mixed MEA/MDEA, the total amine concentration was 5 kmol /m 3 and the MEA/MDEA ratio was 4:1. A proprietary corrosion inhibitor was added to solvent used at BD while no corrosion inhibitor was used at UR power plant. The solvent were used at circulation rate of 8 L/min and the CO 2 for concentration used for the flue gas at UR plant was between 11-15% while that of the BD plant was only 15%. The UR technology development pilot plant is considered to be one of the best testing facilities, equipped with a state-of the art process control and instrumentation with data acquisition system called DeltaV . Comparison of the existing design and process simulation with the present study (Cont’d) 49

50. In the report stated by Paitoon et al., 1992 on the evaluation of CO 2 absorption by NaOH and amine solvent in a packed column, the absorption column height was 7.2m high and the diameter was 0.1m i.d which was made of acrylic plastic and packed 12.7mm ceramic Berl Saddles. The column consisted of six sections with 1.2m high each with redistributors inserted between sections. The packing height of each section was about 1.1 m. However, to vary the effective packing height, the gas could be introduced at different locations between sections. The following operating conditions were used: superficial gas flow rate 11.1 to 14.8 mol /m 3 s, the superficial liquid flow rate was 9.5 to 13.5 m 3 /m 2 h, the feed CO 2 concentration was 11.5 to 19.5%, the total absorbent concentration 1.2 to 3.8 kmol /m 3 , CO2 loading in the liquid feed 0.00 to 0.371molCO 2 / mol absorbent, the liquid feed temperature was 14 to 20°C, total pressure was 103.15 kPa . The column was operated at 30 to 75% of flooding which is typical for gas absorbers.  In this present study using boundary dam as a case study, the experimental design was similar to key unit operational processes used in BD3 and the column consists of 12 stages. Comparison of the existing design and process simulation with the present study (Cont’d) 50

51. 51 Conclusion and Recommendations The future recommendation is that, study the effect of changing the composition of flue gasses on different solvents that which solvents behaves well at low and high acid gasses concentration in the feed and also by changing the effect of feed pressure that on high pressure which solvents give the best result The results demonstrate that the absorber height, solvent circulation rate and reboiler duty have the most remarkable effects on the CO2 retention ability however the stripper stature and the regenerator-inlet temperature does not indicate critical impacts. Promoting technology performance by : Supporting research and technologies that push the scientific field forward. Prepare comprehensive plan for carbon dioxide sales. Calculating the over all revenue and evaluated as a function of CO2 credit .

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55. Chance for questions 55