System for techno-economic analysis (Hunter 3 process)

“The first step of the TEA was to establish the design criteria to be used as the basis for the CO2 capture facility. As part of the conceptual design, the major balance of plant (BOP) impacts associated with the slipstream CO2 capture facility are identified based on the utility requirements for the process. Using previous information gathered from MHI and engineering judgment, the CO2 system design and costs were scaled based on the MHI KM-CR Process ® with KS-1™ solvent and adapted for the Hunter application. As part of this overall effort, the feasibility and overall cost of retrofitting an existing power plant with a CCS system are evaluated by a commercial engineering design firm namely Sargent & Lundy, L.L.C (Flagg and Kunkel 2017). The annual operating and maintenance (O&M) cost based on the conceptual design is estimated.

A typical amine-based CO2 capture system consists of a quencher, an absorber column, and a stripping column; in addition, the flue gas will require a booster-induced draft (ID) fan to overcome the pressure loss through the CO2 capture system. A compressor train is also included after the stripper column for transportation through pipelines to the sequestration locations. A high-level block diagram of the system is shown in Fig. 1.

Fig 1

Fig. 1. Simplified process block diagrams showing the essential units for pretreating flue gas and capturing, separating, and compressing CO2(McPherson et al., 2018)

Amine solvents are sensitive to impurities and will react with SO2 and SO3 molecules present in the flue gas. These reactions contaminate the solvent by forming intermediate salts, which in turn leads to higher solvent regeneration requirements and increased operational costs. While Hunter 3 is equipped with a lime-based WFGD system, it does not currently provide the adequate SO2 and SO3 removal efficiency required for an amine-based system.

Additional SO2 and SO3 removal is required for the more efficient operation of the CO2 capture system and is completed by passing the flue gas through a caustic scrubber. The caustic scrubber uses a 10% (by weight) solution of caustic soda (NaOH) to remove residual acid gases.

Fig. 2 shows the detailed process flow diagram (PFD) of the CO2 capture system for Hunter 3. It is expected that the CO2 capture system would consist of a 1 × 100% train, regardless of if the system is treating 100% of the flue gas or less than 50%.

Fig 2

Fig. 2. Process flow diagram (PFD) of the CO2 capture system for Hunter 3 (McPherson et al., 2018)

In the scrubber (C1), the flue gas passes through a counter-current packed tower, where a caustic solution is recirculated to scrub the flue gas to approximately 1 ppmv SO2. Residual particulates, water, sulfates, and other soluble components will build-up in the caustic solution as it is recycled; therefore, a blowdown stream (3) is required to reduce the concentration of contaminants and overall liquid volume. The blowdown stream is sent to a new wastewater treatment system.

In addition to the removal of residual acid gases, flue gas needs to be cooled prior to being introduced to the solvent. This is due to the improved absorption efficiency of the solvent at lower temperatures. To provide this cooling, the polishing scrubber also functions as a quencher (C2). The flue gas leaving the scrubber/quencher is cooled to approximately 100°F. The contact cooling water is cooled with a heat exchanger and returned to the quencher. The cooling process results in additional condensed water; therefore, a blowdown stream is required to reduce the volume of recirculating water. The blowdown stream is sent to the cooling tower as makeup.

The cool flue gas then passes through a counter-current packed absorber column (C3), where the amine-solvent absorbs CO2 present in the flue gas. Several levels of packing, spray zones, and trays facilitate the appropriate liquid-to-gas contact to ensure a high level of CO2 absorption by the solvent (≥ 90%). The temperature of the absorber is controlled using an intercooler or heat exchange (E3) which cools the semi-rich solvent and returns it to the absorber. A water wash is located at the top of the absorber to remove any entrained solvent in the flue gas. The clean gas exits the absorber and is exhausted through a new stack located on top of the absorber.

The CO2 – rich solvent from the absorber enters the top of a counter-current packed stripper column (C4), where CO2 is desorbed from the amine-solvent through the addition of heat energy to break the weak intermediate bond between the amine-solvent and the dissolved CO2. The boiler (E8) at the base of the stripper utilizes low-quality steam as the source of energy to vaporize water in the dilute solvent. This water vapor rises through the stripper providing energy to facilitate stripping the CO2 and regenerating the amine solvent.

The hot-lean (or regenerated) solvent which is free of CO2 is returned to the absorber. The hot-lean solvent is directed to the lean/rich exchanger (E5) to recover sensible heat and preheat the cool/rich solvent from the absorber. This preheating helps to recover some of the energy used for regeneration, reducing the overall energy requirements of the process, especially in the regeneration stage.

A mixture of CO2 and steam exits the top of the stripper and is sent to the compressor system, which both dehydrates and compresses the CO2 steam. The compressor is designed to pressurize the CO2 product stream to pipeline quality. This system involves eight stages of compression including an intercooler (E7) after each stage. As part of this process, additional moisture is removed to provide a CO2 stream with ≥ 99% purity at 2,215 psia. Moisture removed from the dehydration system and during the compression process is collected and sent back to the stripper.

Leave a Comment