Sequential supplementary firing in natural gas combined cycle plants with carbon capture for enhanced oil recovery

Abstract

The rapid electrification through natural gas in Mexico; the interest of the country to mitigate the effects of climate change; and the opportunity for rolling out Enhanced Oil Recovery at national level requires an important R&D effort to develop nationally relevant CCS technology in natural gas combined cycle power plants. Post-combustion carbon dioxide capture at gas-fired power plants is identified and proposed as an effective way to reduce CO2 emissions generated by the electricity sector in Mexico. In particular, gas-fired power plants with carbon dioxide capture and the sequential combustion of supplementary natural gas in the heat recovery steam generator can favourably increase the production of carbon dioxide, compared to a conventional configuration. This could be attractive in places with favourable conditions for enhanced oil recovery and where affordable natural gas prices will continue to exist, such as Mexico and North America. Sequential combustion makes use of the excess oxygen in gas turbine exhaust gas to generate additional CO2, but, unlike in conventional supplementary firing, allows keeping gas temperatures in the heat recovery steam generator below 820°C, avoiding a step change in capital costs. It marginally decreases relative energy requirements for solvent regeneration and amine degradation. Power plant models integrated with capture and compression process models of Sequential Supplementary Firing Combined Cycle (SSFCC) gas-fired units show that the efficiency penalty is 8.2% points LHV compared to a conventional natural gas combined cycle power plant with capture. The marginal thermal efficiency of natural gas firing in the heat recovery steam generator can increase with supercritical steam generation to reduce the efficiency penalty to 5.7% points LHV. Although the efficiency is lower than the conventional configuration, the increment in the power output of the combined steam cycle leads a reduction of the number of gas turbines, at a similar power output to that of a conventional natural gas combined cycle. This has a positive impact on the number of absorbers and the capital costs of the post-combustion capture plant by reducing the total volume of flue gas by half on a normalised basis. The relative reduction of overall capital costs is, respectively, 9.1% and 15.3% for the supercritical and the subcritical combined cycle configurations with capture compared to a conventional configuration. The total revenue requirement, a metric combining levelised cost of electricity and revenue from EOR, shows that, at gas prices of 2$/MMBTU and for CO2 selling price from 0 to 50 $/tonneCO2, subcritical and supercritical sequential supplementary firing presents favourably at 47.3-26 $/MWh and 44.6-25 $/MWh, respectively, compared with a conventional NGCC at 49.5-31.7 $/MWh. When operated at part-load, these configurations show greater operational flexibility by utilising the additional degree of freedom associated with the combustion of natural gas in the HRSG to change power output according to electricity demand and to ensure continuity of CO2 supply when exposed to variation in electricity prices. The optimisation of steady state part-load performance shows that reducing output by adjusting supplementary fuel keeps the gas turbine operating at full load and maximum efficiency when the net power plant output is reduced from 100% to 50%. For both subcritical and supercritical combined cycles, the thermal efficiency at part-load is optimised, in terms of efficiency, with sliding pressure operation of the heat recovery steam generator. Fixed pressure operation is proposed as an alternative for supercritical combined cycles to minimise capital costs and provide fast response rates with acceptable performance levels.