Process simulation using Aspen HYSYS

“In this study, PCC is used to remove CO2 from the flue gas of natural gas-fired once-through steam generators in a typical oil sands facility. Two amine-based solvents are considered for the PCC unit and various combinations of three process modifications are tested. The aim was to reduce the energy consumption of the carbon capture unit and to compare the selected solvents. MEA is the conventional solvent, while a-MDEA is a solvent of choice with low regeneration energy. Aspen HYSYS® v10 is used for simulating the process with the built-in Chemical Solvents Amine Fluid Package for aqueous amine solutions and Aspen Process Economic Analyzer (APEA) is used for the cost analysis. In this section, the PCC process and the proposed process modifications are described. In addition, the simulation approach and assumptions, simulation of different configurations with the proposed modifications, and cost analysis are presented.

The use of amine solvent in PCC can create important challenges that affects simulation and cost analysis as follows:


Low CO2 molar fractions translate to a small driving force in absorption resulting in large absorber size and, thereby, a higher capital investment,


Huge flowrates of the flue gas are not easy to compress. These conditions also dictate a large size of absorber due to atmospheric pressure,


Thermal and oxidative degradations of amines pronounce more due to the presence of oxygen in the flue gas stream, and;


For the same reason, corrosion rates are higher. This implies either selecting higher construction material (higher alloys with more capital cost) or adding inhibitors to the amine formulations, equivalent to higher operating costs.

In this study, the simulation model was initially validated at two levels (20 TPD and 2000 TPD CO2 Capture) with PFD data for a slipstream of flue gas from a natural gas power plant in a Mexican feasibility study by (Nexant Inc., 2016). Those reported data are meant to be for a case of generic MEA process and another case of MEA with an intercooled absorber. The following general assumptions were made when all the configurations examined:

Special adjustments were applied to the numeric solver to expedite the convergence of 79 reactions together with one (two or three) recycle loops with significant amine flow rates.

As products of amine degradation, heat stable salts (HSS) were not considered to moderate the long runtimes.

Makeup streams for water and amines were included to compensate for the carryover in the decarburized gas vented from the top of the absorber.

Spreadsheet variables and formulas were implemented to calculate special indices (user-defined) to take full advantage of features available in Aspen HYSYS®.

A cutter block was used to transfer the global fluid package to Plocker equation of state (EOS) for the compression section. This trick maintains the supercritical CO2 in the liquid phase after the final compression stage (before its transportation through the pipeline).

Table 2 lists down the model blocks used in Aspen HYSYS. The main process conditions/specifications of the respective equipment are also presented in this table. Fig. 1 & Fig. 2 (in sections 2.1 Process description2.2 Process modifications) display the process flowsheet, as adopted in the process simulator’s GUI. Further details about simulation by equipment (i.e. design specifications) are shown later in section 2.3Table 3.

Table 2. Details of Process Simulation Flowsheet (Major Process equipment in HYSYS GUI).

Process Equipment & function Unit Operation Model Block in Simulation a
Makeup Pump
Direct Contact Cooler (DCC) 2-phase flash drum with pump around cooler
The water recovery of 75% was set as a main spec.
Absorber Column Rigorous packed-bed column with pump around (intercooler); temperature and pressure are fixed at the top and bottom of the column.
Stripper Column (Regenerator) Rigorous packed-bed column with pump around (intercooler); temperature and pressure are fixed at the top and bottom of the column.
Lean/Rich (L/R) Amine
Recirculation Pumps
A simple equipment from the pressure changer class of pump. The discharge pressure was set.
Lean/Rich (L/R) Amine Heat
Exchanger (Economizer)
Plate and frame counter-current heat exchanger. The outlet of the cold side (Lean Amine) was fixed.
LVR compressor & suction drum (lean vapor flash drum)b 2-phase flash drum
The vapor fraction was set to 1 for the vapor stream from the top and is fed to the suction side of LVR compressor

The values of the specified process variables (temperature & pressure) are shown on Fig. 2Fig. 3.


This compressor is considered only in the configuration including LVR that are AIC-LVR and AIC-LVR PEA.

Fig. 1

Fig. 1. Schematic of a conventional configuration for amine-based PCC.

Fig. 2

Fig. 2. Schematic of the proposed process modifications: a) AIC, b) LVR, c) PEA.

Table 3. Flue gas conditions and product CO2 specifications.

Parameters Values
Flue gas from the steam generation system of an oil sands facility
Flue gas composition (%v/v wet)
CO2 8.8
H2O 17.3
N2 71.9
O2 2.0
Flue gas pressure (kPag) 0
Flue gas temperature (°C) 195
Flue gas flow rate (kg/h) 625,000
Total CO2 in flue gas (t-CO2/day) 2092
CO2 capture rate (%) 90
CO2 captured (t-CO2/day) 1883
CO2 pressure (kPa) 15,700
CO2 purity (%v/v dry) 99.5

2.1. Process description

The process flow diagram of the conventional PCC process is shown in Fig. 1. Before the flue gas enters the absorber, a blower and a direct contact cooler (DCC) or flue gas scrubber is used to set temperature and pressure, remove any sulfur oxides in general, and condense most of the water vapor in the flue gas. In the absorber column, the cooled flue gas transfers CO2 to the solvent while passing through the three packed beds in a counter-current flow direction (Nexant Inc., 2016) and the clean flue gas is vented from the top of the absorber. This stream contains nitrogen, oxygen, water, a small amount of CO2 and traces of solvent. A rich-lean heat exchanger, typically a plate and frame exchanger, is located between the absorber and the stripper columns for heat recovery. Inside the stripper column (also known as the desorber or solvent regenerator), the rich amine passes through the packed sections of the column to release the CO2. At the bottom of the stripper, steam is used in the reboiler to boil-up part of the solvent and return it back to the stripper. Finally, the majority of the lean solvent is recycled back to the absorber after cooling in the rich-lean exchanger and subsequently in the lean solvent cooler.

After the top of the stripper, the overhead (a mixture of CO2 and water) is cooled to condense most of the water that is returned to the stripper. Then, there is a compression section to compress the CO2 and make it ready for transportation via pipeline. The captured CO2 is compressed to 15,700 kPa (157 bars) in multi-stage compressors with inter-stage coolers to cool down the compressed CO2 and remove as much moisture as possible between each stage. At 45 °C and 15,700 kPa (157 bar), CO2 is a supercritical fluid and less energy is required for its transportation through pipeline (Nexant Inc., 2016). The process specifications of the major equipment in this process configuration are listed in section 2.3.

2.2. Process modifications

Different modifications have been investigated separately and in combinations to minimize the energy demand of the process. It is recommended to use the sensible heat or the latent heat of the solvent streams by flashing a hot liquid stream at the top or at the bottom of the stripper column (Le Moullec and Kanniche, 2011a). This produces a hot gaseous stream (boiled-up) that mainly contains steam, which is then recompressed to the corresponding operating pressure of the stripper and is injected below the condenser stage or above the reboiler stage. In the case of the reboiler, steam recompression increases the temperature of the boil-up stream and therefore decreases the boil-up flow rate, which results in less energy consumption in the reboiler.

In principle, in absorber intercooling (AIC) modification, a part of the solvent is taken out of the absorber, cooled and then pumped back into the absorber with a typical pump-around arrangement (see Fig. 2).

Lean vapor recompression (LVR) is a modification, presented in Fig. 2, through which the boil-up liquid from the reboiler at the bottom of the stripper is sent to a flash drum with lower pressure to create lean vapor. The vapor is then compressed and sent back to the stripper column. Compression increases both the temperature and pressure of the lean vapor and decreases the reboiler duty. The lean liquid stream from the flash drum is recycled back to the absorber column. In the parallel exchanger arrangement (PEA) modification, shown in Fig. 2, the rich solvent stream is split into two streams and the divided streams exchange heat with the lean solvent stream and the overhead vapor of the stripper before the condenser. Despite often being considered plug-in units, like any other carbon capture, amine-based PCC process units require some attention when integrated into an existing plant (Feron, 2016). In order to maximize the synergies between the two operations and reduce the cost associated with carbon capture, the following points should be considered:


Heat integration from the hot flue gas: this will provide some of the regeneration energy required in the PCC unit, and the hotter the flue gas, the larger the amount of regeneration energy that can be provided by heat recovery. Otherwise, all the required energy has to be provided by a separately installed steam generation system.


If low-carbon electricity is available from the grid, then use electricity-driven pumps and blowers rather than steam-driven equipment.


The PCC unit uses the control system of the parent plant that is intended for capturing CO2 from its flue gas.

Since the installation of commercial-scale PCC units with distinctive design improvements is costly, process simulation plays a pivotal role in system optimization and evaluation of the various process modifications. Among the explained process design modifications, AIC, LVR, and rich solvent split are known to be less complex and more applicable. AIC and LVR were among the most recommended modifications in the literature (Feron, 2016) and are available in some commercial applications. For the sake of comparison with the study performed by Nexant as reference (Nexant Inc., 2016), we chose similar modifications (i.e., AIC and LVR). PEA is preferred over other modifications due to the minimal amount of additional equipment required for its implementation. Nonetheless, a thorough analysis is necessary to conclude whether more advanced modifications are justified for a special amine-based solvent considering carbon capture efficiency, reboiler heat intensity, capital investment, and operating costs. In this study, the determining factors and key operational variables were varied over a feasible range in order to have a grasp of the overall performance of the process with respect to the key performance indicators (KPIs), including carbon capture efficiency, reboiler heat demand, and cooling requirement.

A base case simulation model was developed according to Nexant’s study for a small-scale PCC unit using MEA-based absorption capturing 20 tonnes per day (TPD) from a natural gas-fired power plant (Nexant Inc., 2016). The model was validated against plant data. Then it was expanded to a large-scale model to capture 2000 TPD, and the results were again validated against existing plant data. Finally, the simulation model was used to capture the CO2 from flue gas produced by the once-through steam generators (OTSGs) of a typical in-situ oil sands extraction facility. The flue gas characteristics are presented in Table 2. All configurations aimed for a 90% CO2 capture rate from the flue gas. The proposed process modifications considered different combinations of AIC, LVR, and PEA as follows: 1) AIC only, 2) AIC and PEA, 3) AIC and LVR, 4) AIC, PEA and LVR. All simulations were performed for two aqueous solvents: a benchmark MEA (MEA 30% by wt.) and an activated a-MDEA (30% MDEA by wt. with 12.5% PZ by wt.). In addition, we tried to fill in the gap on the advantages of using a-MDEA as an advanced amine solvent for carbon capture. AIC, LVR, and PEA (combined with split flow arrangements) were simulated and compared with respect to the mentioned KPIs and cost. Including the base case design with no process modifications, a total of five different scenarios were simulated for each solvent, with each scenario representing a separate configuration.

2.3. Simulation assumptions

All of the simulation cases were created in Aspen HYSYS® v10. The amine (Chemical Solvents) fluid package was used in the simulation environment.

Several aspects and assumptions were considered for the simulation of the different scenarios, as follows:

Aqueous solutions of MEA (30 wt%) and a-MDEA (30 wt% MDEA and 12.5 wt% PZ) were used.

Special adjustments were applied to the numeric solver to expedite the convergence of several reactions in the process and the recycle loops with significant amine flow rates.

No heat loss to ambient was taken into account.

A rate-based stage-wise model was created to simulate the multi-component reaction and mass transfer efficiencies in the absorption and desorption sections of the process.

For both absorber and regenerator (stripper or desorber) columns, a rigorous non-isothermal (advanced rate-based modeling with internals in the column settings) set of reactions with mass transfer in the gas-liquid phases was applied to achieve accurate simulation predictions.

Heat-stable salts, as products of amine degradation, were not considered to moderate the long run times.

Make-up streams for water and amines were included to compensate for the carryover in the clean flue gas vented from the top of the absorber.

Spreadsheet variables and formulas were implemented to calculate special (user-defined) indices.

The packed sections of the absorber were divided into 25 packing stages. The top 10 stages were allocated to the two water wash sections and the bottom 15 stages were allocated to the absorption section. We considered intercooling at the bottom of the absorber column since Gomez increased column efficiency by considering this modification. For the cases with AIC modification, the pump around was located on top of the absorption section (Gomez, 2015).

The stripper was divided into 20 packed stages with the top 5 stages operating as a reflux wash section.

A cutter block was used to transfer the global fluid package to the Plocker equation of state (EOS) for the CO2 compression section. This was to maintain the supercritical CO2 in the liquid phase after the final stage of compression before its pipeline transportation.

The steam consumption and the required cooling duty were calculated for each case at a 90% CO2 capture rate.

The process specifications for the major equipment in the simulation are tabulated in Table 3 below.

As can be observed in Table 3, the main difference is in the absorber diameter between the cases with MEA solvent and the ones with a-MDEA solvent. In order to have a fair comparison between those cases, the same values of design parameters (except for the absorber column diameter, which is different in MEA and a-MDEA case studies) were used in the simulations.

In general, MDEA has a lower heat of regeneration compared to MEA. However, MDEA reaction rates with CO2 are significantly lower than those of MEA. As a matter of fact, these behaviors stem from the different chemistry and chemical equilibriums of the solvents with carbon dioxide. To promote the slow reaction rates of MDEA and CO2, piperazine (PZ) is added as a promoter. Although a considerable amount of PZ was added to promote the reaction rates, the size of the absorber columns in the MDEA cases was approximately two times bigger in volume and 38% bigger in diameter. The absorber diameter was set to have the desired carbon capture rate of 90% and, at the same time, feasible hydraulics for the column. This means that the operating point is located in a reasonable pressure drop region with sufficient vapor and liquid flow rates along the height of the column, to maintain the hydrodynamics. The stripper dimensions were kept constant in all cases and the only differences are the reboiler duty, and correspondingly the condenser duty, that were adjusted to reach appropriate CO2 concentration in the overhead and CO2 loading in the regenerated/lean solvent. Conventional process configurations were first simulated for each solvent as the base cases. All of the simulated scenarios were then compared to those base cases and ranked with respect to their performance indicators.

Fig. 1 depicts a schematic of the entire PCC process simulation. The entire process is divided into three sub-flowsheets, namely flue gas cooling, CO2 capture, and CO2 compression in order to better manage the convergence of the simulation. Fig. 2 represents the simulation model of the carbon capture section with all proposed process modifications that were detailed in the methodology section. In all analyzed simulation cases, the rate-based absorber columns were used for both absorber and stripper columns. In the Column Environment section, Advanced Modeling was selected, hydraulic plots along the height for each column were monitored, and pumparounds were added to take into account the absorber’s internal cooling. The Internals Manager feature was also used to divide each bed into segments with different packing types. Recycle stream flow rates and the outlet temperature of the lean/rich heat exchanger (shown as L/R HE in Fig. 2) were carefully adjusted to avoid a cross temperature effect in the heat exchanger and to maintain a realistic run time as well as tolerance for the convergence of the recycle loops.

Unit operations that exist in an amine contactor unit are specified in the chemical solvents/amines property fluid package in Aspen HYSYS®. A rate-based stage-wise model was created to simulate the multi-component reaction and mass transfer efficiencies in the absorption and desorption sections of the process. Mass and energy balance equations along the height of the columns were solved by means of a rigorous non-isothermal set of reactions with mass transfer in the gas-liquid phases. The base case models were validated against detailed PFD (Process Flow Diagram) data at small and large scales published in our reference study (Nexant Inc., 2016).

In this simulation work, Mellapak+ type 250Y was selected for the bottom bed of the absorber while 3.5″ pall rings were used for the two beds at the top of the absorber and the stripper. This was in accordance with the data presented in Nexant’s study (as listed in Table 3). Regarding the columns’ hydrodynamics, diameters were estimated based on 75% of flooding for the gas phase velocity. Hydrodynamics curves were checked with the latest feature offered in Aspen HYSYS® columns named Advanced Modeling with internals. In the absorber, the diameter and lean-amine flow rate were adjusted to achieve CO2 recovery of 90%. In the stripper, the condenser temperature and the reboiler duty are specified considering lean/rich loading, lean amine boil-up temperature in the reboiler, and a carbon capture rate of 90%.

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