Techno-Economic Analysis for Decarbonization and Broader Climate Objectives

Natural gas power plants remain prevalent due to their high efficiency, often enhanced through the implementation of combined cycle configurations. In response to increasingly stringent environmental regulations, many operators are integrating carbon capture technologies to curb emissions. These systems, however, impose substantial energy demands, leading to increased fuel usage and reduced net electricity output, thereby elevating generation costs. Among available methods, post-combustion capture using Monoethanolamine (MEA) is the most widely adopted. This technique extracts carbon dioxide from flue gas and regenerates the solvent via heat input—typically sourced from low-pressure steam within the plant, resulting in diminished power export and higher cost per kilowatt-hour. To mitigate these drawbacks, the present study investigates multiple strategies to improve energy efficiency. These include deploying advanced solvents with reduced regeneration energy needs, incorporating vapor recompression to reclaim thermal energy, and supplementing with solar generation and Battery Energy Storage System (BESS) during peak demand periods. Together, these measures aim to offset the performance penalties of carbon capture. The objective is to determine optimal configurations that sustain consistent power delivery while minimizing the energy and cost burdens of carbon capture by integration with solar generation and grid-scale BESS. The LCOE estimates for BESS and PV Solar exclude current tax credits due to uncertainty in evolving policy frameworks. However, anticipated future incentives have the potential to significantly improve the economic outlook for these technologies, further supporting their integration with NGCC facilities utilizing CCS. This paper dives into the integration of a grid-scale BESS and Photovoltaic (PV) Solar with a Natural Gas Combined Cycle (NGCC) power plant equipped with a post-combustion Carbon Capture System (CCS) presenting a novel approach to enhancing operational efficiency and grid responsiveness. The thermodynamic base case was constructed in the Ebsilon Professional process simulator, which enables detailed component-level heat-balance modelling for combined-cycle plants. An H-class gas turbine was calibrated to vendor performance data; the accompanying heat-recovery steam generator and three-pressure steam turbine train were then iteratively tuned to close all mass- and energy-balance loops. Table-1 summarizes the resulting cycle parameters. Adiabatic efficiencies, inlet pressures, and outlet pressures are shown for the high-, intermediate-, and low-pressure steam turbines, along with the net power contributions of each turbine group and the overall plant. Net generating capacity varies modestly—from 492 MW in the baseline MEA case to 514 MW when lean-vapour recompression and a rich-amine heat exchanger are added—because steam extraction requirements differ among solvent configurations. The model’s calculated flue-gas flow rate and composition provide the boundary conditions for the post-combustion CO₂-capture simulations described later in the paper, refer to Table 1 (Oh, Lee, & Lee, 2021). The flue gas properties were determined based on the simulation results. The combustion turbine generator (CTG) discharge flue gas was directed to the heat recovery steam generator (HRSG), where it provided the necessary thermal energy to produce steam for power generation through the steam turbine. The final flue gas properties after heat recovery are presented in Table 2.