108 research outputs found

    Addressing Technology Uncertainties in Power Plants with Post-Combustion Capture

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    AbstractRisks associated with technology, market and regulatory uncertainties for First-Of-A-Kind fossil power generation with CCS can be mitigated through innovative engineering approaches that will allow solvent developments occurring during the early stage of the deployment of post-combustion CO2 capture to be subsequently incorporated into the next generation of CCS plants. Power plants capable of improving their economic performance will benefit financially from being able to upgrade their solvent technology. One of the most important requirements for upgradeability is for the base power plant to be able to operate with any level of steam extraction and also with any level of electricity output up to the maximum rating without capture. This requirement will also confer operational flexibility and so is likely to be implemented in practice on new plants or on any integrated CCS retrofit project

    Built-in flexibility at retrofitted power plants: What is it worth and can we afford to ignore it?

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    AbstractMaking best use of existing assets is a high priority for industry, particularly when significant capital expenditure would be required to construct replacement capacity to meet continued demand if they were taken out of service. In this context, the potential to retrofit carbon dioxide (CO2) capture to existing power plants so that they can continue to operate in plausible future scenarios where significant cuts in CO2 emissions are required from the electricity sector has become an increasingly ‘hot topic’. One potentially important characteristic of retrofitted plants that is typically over-looked in assessments of CO2 capture retrofit is that they are likely to have ‘built-in flexibility’. For example, for plants that retrofit post-combustion capture without any significant changes to the power cycle (i.e. that do not undertake a boiler/turbine retrofit at the time as adding capture), it should be technically feasible for the plant to avoid the majority of the efficiency penalty associated with operating CO2 capture by temporarily bypassing the capture unit. The low pressure steam turbine, condenser and generator will be sized so that they are able to use the steam that is diverted away from the CO2 capture unit for power generation without any additional expenditure, since this steam was included in the design flow before capture was fitted. This paper and a related PhD thesis contributes to developing understanding of the potential value of built-in flexibility of coal-fired power plants retrofitted with post-combustion capture and potential enhancements associated with temporary storage of rich solvent. This analysis is important to inform investment and policy decisions and brings together engineering and economic assessment. Thus, it is able to draw robust conclusions that are relevant in determining both priorities for future technical design work and decisions about which modes of operating flexibility may be sufficiently valuable to warrant further analysis within investment appraisal or policy-making related to retrofitting post-combustion capture to pulverised coal plants

    Financing new power plants ‘CCS Ready’ in China–A case study of Shenzhen city

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    AbstractWe evaluate the benefits of a ‘CCS Ready Hub’ approach, a regional ‘CCS Ready’ strategy, which not only includes a number of new coal-fired power plants but also integrates other existing stationary CO2 emissions sources, potential storage sites and potential transportation opportunities into an overarching simulation model. A dynamic top-down simulation model was built based on economic decision criteria and option pricing theory. The model inputs and assumptions build on spatial sampling and analysis using a geographic information system (GIS) approach, engineering assessment of local projects and outputs of a CCS retrofitting investment evaluation through cost cash flow modelling. A case study of Shenzhen city in the Pearl River Delta area in Guangdong in southern China is presented, based on engineering and cost assessment studies and stakeholder consultations and building on existing geological surveys and infrastructure plans. The simulation results show that financing ‘CCS Ready’ at regional planning level rather than only at the design stage of the individual plant (or project) is preferred since it reduces the overall cost of building integrated CCS systems. On the other hand, we found the value of considering existing stationary CO2 emissions sources in CCS ready design. Therefore, we recommended that making new plants CCS ready or planning a CCS ready hub should consider existing large emissions sources when possible

    Sequential supplementary firing in natural gas combined cycle with carbon capture: A technology option for Mexico for low-carbon electricity generation and CO<inf>2</inf> enhanced oil recovery

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    Combined cycle gas turbine power plants with sequential supplementary firing in the heat recovery steam generator could be an attractive alternative for markets with access to competitive natural gas prices, with an emphasis on capital cost reduction, and where supply of carbon dioxide for Enhanced Oil Recovery (EOR) is important. 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 the same capture technology. 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, 15.3% and 9.1% for the subcritical and the supercritical combined cycle configurations with capture compared to a conventional configuration. For a gas price of 2/MMBTU,theTotalRevenueRequirement(TRR)ametriccombininglevelisedcostofelectricityandrevenuefromEORofsubcriticalandsupercriticalsequentialsupplementaryfiringisconsistentlylowerthanthatofaconventionalNGCCby,respectively,2.2and5.72/MMBTU, the Total Revenue Requirement (TRR) - a metric combining levelised cost of electricity and revenue from EOR - of subcritical and supercritical sequential supplementary firing is consistently lower than that of a conventional NGCC by, respectively, 2.2 and 5.7 /MWh at 0 /tCO2andby4.9and6.7/t CO2 and by 4.9 and 6.7 /MWh at 50/tCO2.Atagaspriceof50/t CO2. At a gas price of 4/MMBTU and 6/MMBTU,theTRRofasubcriticalconfigurationisconsistentlylowerforanycarbonsellingpricehigherthan2.56/MMBTU, the TRR of a subcritical configuration is consistently lower for any carbon selling price higher than 2.5 /t CO2 and 37 $/t CO2 respectively

    Valuing Responsive Operation of Post-combustion CCS Power Plants in Low Carbon Electricity Markets

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    AbstractThis work considers the potential value in the additional flexibility of CCS post-combustion power plants gained by varying the operating CO2 capture level. The continuous relationship between CO2 capture level and the specific electricity output penalty is illustrated, and a new methodology is proposed for maximising net plant income through optimising the operating capture level. This methodology allows the plant to respond to electricity prices, fuel prices, and carbon reduction incentives including CO2 prices and premium payments for low carbon electricity. The implications for flexible operation under different market scenarios are qualified, and the indicative value to plant operators is determined
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