An open-access FEED study for a post-combustion CO2 capture plant retrofit to a CCGT

Abstract

Bechtel National (Reston, VA) have now completed a FEED study for retrofitting a 2x2x1 natural gas-fired combined cycle gas turbine (CCGT) power plant with post-combustion carbon capture (PCC) for CO2 storage/utilization. The comprehensive program of work covers the integration of the retrofitted carbon capture and compression plant as an add-on to Panda Energy Fund’s existing natural gas-fired gas turbine combined cycle power plant at Sherman in Texas, together with the detailed design of an amine-based conventional absorber-stripper scrubbing system with a non-proprietary MEA solvent. This study is one of a series of natural gas power FEED studies, announced by the US DOE in late 2019 [1].

The open-access and open-technology approach allows full, unredacted publication of the FEED study. While several large PCC projects, and a number of smaller ones, have been built using generally similar approaches, because the design, construction and operational details have largely been treated as proprietary, so far only very limited meaningful knowledge exchange has been able to take place, both from and to the projects and their developers and operators. In addition, design studies for other PCC plants that did not eventually get built have also either not been published or are heavily redacted in important areas.

The PCC unit uses 35% w/w MEA as the solvent to capture 85% of the CO2 in a slipstream, corresponding approximately to the flow at minimum stable generation in order to maximize usage of the new investment (possible design variations to achieve capture levels of up to 99% will also be discussed). MEA was selected because extensive information is available for it in the public domain and, as described above, a previous NGCC retrofit study [2] has shown that it would be comparable in performance and overall costs to a range of proprietary solvents. It is also widely available at low prices. At the design flue gas throughput of 704 kg/s the PCC unit captures 129 t/h of CO2. Energy consumption for solvent regeneration is estimated as 3.65 GJ/tCO2 (of which 0.14 GJ/tCO2 is provided by waste heat recovery from the CO2 compressors), with design lean and rich loadings of 0.254 and 0.475 mole CO2/mole MEA and an absorber liquid/gas ratio of 1.07. To maintain a low level of degradation products in the circulating solvent, a semi-continuous thermal reclaimer is used to process the equivalent of a complete plant solvent inventory every 28 days. Reclaiming takes place in two stages with 150oC operating temperature in both. The first stage vents to the stripper at 2.6 bara, allowing the heat in the evaporated water vapor and MEA to be recovered. The second stage vents to the top of the absorber, at near atmospheric pressure. Solvent recovery in the reclaimer is estimated at ≥90%, with net solvent consumption 2 kg MEA/tCO2 captured. As previously noted, MEA supply cost at the plant site was ascertained to be $1.15/kg delivered, 99% purity, iron and chlorine free. Reclaimer bottoms disposal costs are estimated Corresponding author. Bill Elliott. [e-mail]. GHGT-16 Bill Elliott 2 at $500/t.

In addition to heat recovery from the reclaimer, energy consumption for solvent regeneration is reduced by flashing some of the rich solvent using heat from the CO2 compressor intercoolers, as noted above, and returning the resulting semi-lean solvent part-way down the absorber. The overall capital cost for the PCC retrofit is estimated as $477M, including indirect costs, owner’s and contractor’s costs, and interest during construction; completion is 30 months from notice to proceed. CO2 absorption equipment (including semi-lean flash system), at 34%, is the largest part of this; two cylindrical stainless steel absorbers are used, internal diameter 11.8 m and 44.3 m straight section, with a nominal gas velocity of 2.76 m/s, and a total packing height of 15 m in two beds. Flue gas conveyance and conditioning, via a 6 x 6 m duct, with a water fogging system to reduce flue gas temperatures, accounts for 23% and the stack modifications feeding into a transition manifold, a further 7% of capital costs. The solvent stripper and reboilers costs are 17% of the total. CO2 compression and conditioning accounts for 19% of capital costs; a centrifugal compressor, send out pump and dehydration are used, delivering 151 bara CO2. Estimated baseline CO2 capture costs are $114.50/tCO2, dominated by capital recovery charges. For a 70/30 debt to equity ratio with 6% interest rate on debt over 15 years and 12% return on equity, plus PCC operation for an average of 5000 hours per year, these total $83.10 $/tCO2. Power plant net output is reduced by 67.3 MW when supplying PCC steam and electricity requirements. The PCC plant is not operated during those limited periods when the Texas ERCOT power grid has elevated prices (up to $9000/MWh), nor when the power plant is not operating, and average foregone electricity revenues are assessed at $25/MWh, contributing $13.00/tCO2 captured. Other costs are maintenance ($7.00/tCO2), staffing ($7.75/tCO2), solvent replacement ($2.30/tCO2) and waste disposal ($1.35/tCO2).

In addition to the detailed design parameters summarized above for the final FEED design the paper will also discuss the reasons behind the design philosophy for this CCGT application and possible variations for alternative market conditions. These variations will include potential modifications for higher capture levels, up to 99%, and for intermittent operation to complement renewables. Overall, this paper is expected to contribute to a detailed discussion of CCGT+PCC applications at GHGT16, driven by the significant number of FEED studies now completed or in progress for this relatively novel application.

Keywords: post-combustion capture, amine, engineering, reclaiming

JEL Classification: O, Z