On the retrofitting and repowering of coal power plants with post-combustion carbon capture: An advanced integration option with a gas turbine windbox

Retrofitting a significant fraction of existing coal-fired power plants is likely to be an important part of a global rollout of carbon capture and storage. For plants suited for a retrofit, the energy penalty for post-combustion carbon capture can be minimised by effective integration of the capture system with the power cycle. Previous work on effective integration options has typically been focused on either steam extraction from the power cycle with a reduction of the site power output, or the supply of heat and electricity to the capture system via the combustion of natural gas, with little consideration for the associated carbon emissions. This article proposes an advanced integration concept between the gas turbine, the existing coal plant and post-combustion capture processes with capture of carbon emissions from both fuels. The exhaust gas of the gas turbine enters the existing coal boiler via the windbox for sequential combustion to allow capture in a single dedicated capture plant, with a lower flow rate and a higher CO2 concentration of the resulting flue gas. With effective integration of the heat recovery steam generator with the boiler, the existing steam cycle and the carbon capture process, the reference subcritical unit used in this study can be repowered with an electricity output penalty of 295 kWh/tCO2 – 5% lower than a conventional steam extraction retrofit of the same unit – and marginal thermal efficiency of natural gas combustion of 50% LHV – 5% point higher than in a configuration where the gas turbine has a dedicated capture unit

Process simulation of a dual-stage Selexol unit for pre-combustion carbon capture at an IGCC power plant

AbstractIt is aimed to simulate a dual-stage Selexol process for removing CO2 as well as H2S from the syngas typically found in the IGCC power plant with a dry-coal fed gasifier. Temperature-dependent Henry's law is employed in the process simulation to estimate the solubilities of gas components in Selexol. The operating conditions of dual-stage Selexol unit were found so as to meet simultaneously various specifications such as 99+% H2 recovery, 90% or 95% CO2 recovery and 99+% H2S recovery. The power consumptions for auxiliary units and CO2 compression estimated by the simulation are in good agreement with those reported in the literature [1]. It is shown that the conventional, integrated dual-stage Selexol unit can achieve 95% carbon capture rate as well as 90% by simply changing the operating conditions

Techno-economic assessment of two novel feeding systems for a dry-feed gasifier in an IGCC plant with Pd-membranes for CO2 capture

This study focuses on the application of Pd-based membranes for CO[subscript 2] capture in coal fueled power plants. In particular, membranes are applied to Integrated Gasification Combined Cycle with two innovative feeding systems. In the first feeding system investigated, CO[subscript 2] is used both as fuel carrier and back-flushing gas for the candle filters, while in the second case N[subscript 2] is the fuel carrier, and CO[subscript 2] the back-flushing gas. The latter is investigated because current dry feed technology vents about half of the fuel carrier, which is detrimental for the CO[subscript 2] avoidance in the CO[subscript 2] case. The hydrogen separation is performed in membrane modules arranged in series; consistently with the IGCC plant layout, most of the hydrogen is separated at the pressure required to fuel the gas turbine. Furthermore, about 10% of the overall hydrogen permeated is separated at ambient pressure and used to post-fire the heat recovery steam generator. This layout significantly reduces membrane surface area while keeping low efficiency penalties. The resulting net electric efficiency is higher for both feeding systems, about 39%, compared to 36% of the reference Selexol-based capture plant. The CO[subscript 2] avoidance depends on the type of feeding system adopted, and its amount of vented gas; it ranges from 60% to 98%. From the economic point of view, membrane costs are significant and shares about 20% of the overall plant cost. This leads in the more optimistic case to a CO[subscript 2] avoidance cost of 35 €/t[subscript CO2], which is slightly lower than the reference case.Seventh Framework Programme (European Commission) (Grant agreement no. 241342

Process integration of a Calcium-looping process with a natural gas combined cycle power plant for CO2 capture and its improvement by exhaust gas recirculation

AbstractIn this study, it was sought to find an efficient way to integrate a Ca-looping process with a Natural Gas Combined Cycle (NGCC) power plant for its post-combustion CO2 capture. Compared to its application to coal combustion flue gas, Ca-looping would incur augmented energy penalty when integrated with a NGCC of which the flue gas contains only 4.0mol% CO2. The reduced CO2 concentration in the feed requires the carbonator to operate at a lower temperature and more solids to circulate between carbonator and calciner for keeping up the carbon capture efficiency at 90%. However, this study demonstrated that such negative effects could be alleviated greatly by implementing 40% exhaust gas recirculation to the NGCC with the CO2 concentration in the flue gas increasing up to 6.8%. Accordingly, the resulting net power efficiency increased notably 1.6% points in comparison to its equivalent non-EGR NGCC case and it was only 0.9% points less than amine capture case. This study exhibited that exhaust gas recirculation would be crucial in decarbonising a NGCC power plant by Ca-looping

CO2 capture from syngas by an adsorption process at a biomass gasification CHP plant: Its comparison with amine-based CO2 capture

AbstractAn exemplary 10MWth biomass-fuelled CHP plant equipped with a FICFB (Fast Internally Circulating Fluidised Bed) gasifier and a Jenbacher type 6 gas engine was simulated using Honeywell UniSim R400 to estimate the power and thermal outputs. The biomass gasification CHP plant was integrated with either a pre-combustion adsorptive capture process or a conventional post-combustion amine process to achieve carbon-negative power and heat generation. The practical maximum of carbon capture rate achievable with an adsorptive CO2 capture process applied to a syngas stream was 49% in overall while the amine process could boost the carbon capture rate up to 59%. However, it was found that the two-stage, two-bed PVSA (Pressure Vacuum Swing Adsorption) unit would have a clear advantage over the conventional amine processes in that the CHP plant integrated with the PVSA unit could achieve 1.7% points higher net electrical efficiency and 12.8% points higher net thermal efficiency than the CHP plant integrated with the amine process

Geochemical tracers for monitoring offshore CO2 stores

Chemical tracers are proposed as an effective means of detecting, attributing and quantifying any CO2 leaks to surface from geological CO2 storage sites, a key component of Carbon Capture and Storage (CCS) technology. A significant proportion of global CO2 storage capacity is located offshore, with some regions of the world having no onshore stores. To assure regulatory bodies and the public of CO2 storage integrity it is important to demonstrate that robust offshore monitoring systems are in place. A range of chemical tracers for leakage have been tested at onshore pilot CCS projects worldwide, but to date they have not been trialled at injection projects or CO2 release experiments located offshore. Here, for the first time, we critically review the current issues surrounding commercial scale use of tracers for offshore CCS projects, and examine the constraints and cost implications posed by the marine environment. These constraints include the logistics of sampling for tracers offshore, the fate of tracers in marine environments, tracer background levels, marine toxicity and legislative barriers – with particular focus on the Europe and the UK. It is clear that chemicals that form a natural component of the CO2 stream are preferable tracers for ease of permitting and avoiding cost and risks of procuring and artificially adding a tracer. However, added tracers offer more reliability in terms of their unique composition and the ability to control and regulate concentrations. We identify helium and xenon isotopes (particularly 124,129Xe), and artificial tracers such as PFCs and deuterated methane as the most suitable added tracers. This is due to their conservative behaviour, low environmental impact and relative inexpense. Importantly, we also find that SF6 and C14 are not viable tracers for CCS due to environmental concerns, and many other potential tracers can be ruled out on the basis of cost. Further, we identify key challenges that are unique to using tracers for offshore monitoring, and highlight critical uncertainties that future work should address. These include possible adsorption or dispersion of tracer compounds during ascent through the overburden, longevity of tracers over the timeframes relevant for CCS monitoring, the permissible environmental effects of tracer leakage, and tracer behaviour in seabed CO2 bubble streams and in dissolved CO2. These uncertainties directly affect the selection of appropriate tracers, the injection programme and concentrations necessary for their reliable detection, and appropriate sampling approaches. Hence offshore tracer selection and associated expense are currently poorly constrained. Further, there is limited experience of sampling for tracers in the marine environment; current approaches are expensive and must be streamlined to enable affordable monitoring strategies. Further work is necessary to address these unknowns so as to evaluate the performance of potential tracers for CO2 leak quantitation and provide more accurate costings for effective offshore tracer monitoring programmes

Emerging CO2 capture systems

In 2005, the IPCC SRCCS recognized the large potential for developing and scaling up a wide range of emerging CO2 capture technologies that promised to deliver lower energy penalties and cost. These included new energy conversion technologies such as chemical looping and novel capture systems based on the use of solid sorbents or membrane-based separation systems. In the last 10 years, a substantial body of scientific and technical literature on these topics has been produced from a large number of R&D projects worldwide, trying to demonstrate these concepts at increasing pilot scales, test and model the performance of key components at bench scale, investigate and develop improved functional materials, optimize the full process schemes with a view to a wide range of industrial applications, and to carry out more rigorous cost studies etc. This paper presents a general and critical review of the state of the art of these emerging CO2 capture technologies paying special attention to specific process routes that have undergone a substantial increase in technical readiness level toward the large scales required by any CO2 capture system