Post-combustion Capture Plant Research Articles

Enhanced Geothermal System with captured CO2

Post-combustion capture plants are widely studied because they represent a feasible solution to limit the CO2 emissions from existing plant. They can be applied to power plants and to industrial plants. The captured CO2 is transported to dedicated sites to be sequestrated. In this study, the captured CO2 from a coal-fired power plant is exploited to extract the geothermal energy for subsequent electric production. The system of wells consists of one of injection in a geothermal source of about 200-300 °C and one of production from which the CO2 exits at high pressure and high temperature. It is expanded in a turbine to extract part of the energy and it is cooled to be sent to the storage site. The cooling process exchanges heat with an Organic Rankine Cycle to convert the heat to electric power. The ORC plants are tested with five different substances: R245fa, HCFO, hexane, pentane, and Isobutane. The better performances are obtained with the latter two.

A Comparative Study of Aqueous Potassium Lysinate and Aqueous Monoethanolamine for Postcombustion CO2 Capture

Aqueous monoethanolamine (MEA) is widely used for CO2 capture and has been demonstrated as an effective absorbent in many postcombustion capture plants. However, several disadvantages such as toxicity, high volatility, solvent degradation, and high energy consumption were reported in the practical applications. Aqueous amino acid salts, particularly potassium lysinate (LysK), are considered as attractive alternatives to MEA. A comparative study of absorbent characteristics of aqueous LysK (2.0 M and 2.5 M) and aqueous MEA (5.0 M) was conducted in this study. The absorption and cyclic capacities, absorption and desorption rate, solubility of CO2, and heat of absorption were measured using a stirred batch-type reactor and a CPA201 reaction calorimeter under similar postcombustion capture conditions. Thermal and oxidative degradation was also evaluated for aqueous 2.0 M LysK at 383 and 423 K under static N2 and O2 exposure conditions for 15 days. Samples were analyzed by total alkalinity and 13C and 1H NMR s...

Repowering Options for Complying with Canadian CO2 Emission Intensity Limits on Existing Coal Plants

The Canadian federal government has introduced carbon dioxide emission intensity limits of no greater than 420 kg/MWh net for new coal plants and existing coal plants more than 50 years of age. Many operating coal plants in Canada will be impacted by this legislation in the near future, requiring operators to plan a compliance strategy. The Canadian Clean Power Coalition (CCPC) investigated the performance and economics of a number of options for existing plants that could deliver compliant solutions. These options included strategies in which natural gas is available and some in which only coal firing is feasible due to cost or logistical issues.Repowering and post-combustion capture (PCC) options were studied using an eastern Canadian power plant firing bituminous coal. The base-case (BC) option was a new combined-cycle gas turbine (CCGT) plant, against which all other options were compared. The following cases were investigated:1.PCC using:a.Monoethanolamine MEA solvent with crossover steam regenerationb.Commercial advanced solvent with crossover steam regenerationc.Commercial advanced solvent with a small gas turbine (GT) and a low-pressure steam generatord.Commercial advanced solvent with a GT, triple-pressure heat recovery steam generator (HRSG) and a back pressure steam turbinee.Commercial advanced solvent with a natural gas boiler and a back pressure steam turbine2.Repowering of existing steam turbines with new a GT and HRSG3.Repowering of existing steam turbines with fuel cellsa.New solid oxide fuel cell (SOFC) topping unitb.New molten carbonate fuel cell (MCFC) topping unit4.Expanded PCC approach with:a.Third unit with full LP steam turbine bypass supplying steam to PCCb.Circulating fluidized bed (CFB) boiler and back pressure steam turbineOne of the issues with incorporating PCC in an existing facility is delivering the thermal regeneration energy to the PCC reboilers in an efficient and cost-effective manner. This can involve significant integration with the low-pressure stages of the steam turbine, a duty for which the turbine was not designed. Because turbine modifications (to deliver partially expanded steam to the PCC plant) can be costly and would require significant down time, alternative strategies were investigated in which the PCC facility would effectively be a “standalone” facility, with the main plant interfaces being the flue gas to be treated and some shared services.The costing analysis was carried out on the following basis: 30-year plant design life (with life-extension costs included for existing plant), 90% capacity factor for the first year cost of electricity (COE), and a coal cost of $4.73/GJ and a natural gas cost of $10.00/GJ (based on 2013 forecasted costs). Case 2 (repowering existing steam turbines with new natural gas combined-cycle plant) without any additional CO2 abatement, delivered both the lowest capital costs and cost of electricity. If the existing coal boiler plant remains operational, the lowest costs were achieved by installing a molten carbonate fuel cell (Case 3b) followed closely with an advanced solvent PCC unit with solvent regeneration thermal energy being delivered by an efficient, small, dedicated gas turbine with a triple pressure HRSG (Case 1d). Where there is no existing infrastructure to deliver natural gas, the traditional methodology of extracting crossover steam from the unit for PCC solvent regeneration proved to be the lowest-cost option.

Integrating geothermal into coal-fired power plant with carbon capture: A comparative study with solar energy

A new system integrating geothermal energy into post-combustion carbon capture is proposed in this paper. Geothermal energy at medium temperatures is used to provide the required thermal heat for solvent regeneration. The performance of this system is compared with solar assisted carbon capture plant via technical and economic evaluation. A 300 MWe coal-fired power plant is selected as the reference case, and two different locations based on the local climatic conditions and geothermal resources are chosen for the comparison. The results show that the geothermal assisted post-combustion carbon capture plant has better performances than the solar assisted one in term of the net power output and annual electricity generation. The net plant average efficiency based on lower heating value can be increased by 2.75% with a thermal load fraction of about 41%. Results of economic assessment show that the proposed geothermal assisted post-combustion carbon capture system has lower levelized costs of electricity and cost of carbon dioxide avoidance compared to the solar assisted post-combustion carbon capture plant. In order to achieve comparative advantages over the reference post-combustion carbon capture plant in both locations, the price of solar collector has to be lower than 70 USD/m2, and the drilling depth of the geothermal well shall be less than 2.1km.

Siderite corrosion protection for carbon steel infrastructure in post-combustion capture plants

To mitigate CO2 release, large-scale post-combustion capture with amine solvents is essential. To achieve capital cost savings, carbon steel infrastructure can replace stainless steel if corrosion by CO2-loaded amine solvents is controlled. A coating, to protect the carbon steel, formed using an amine (or additive) is beneficial because it can be regenerated. Siderite has been shown to form a protective crystalline product layer, created when Fe oxidised at the surface reacts with carbonate ions. Tertiary or sterically-hindered CO2-loaded amine solutions can form this layer. Herein siderite was prepared on carbon steel substrates from 5M methyldiethanolamine (MDEA), 5M 2-amino-2-methyl-1-propanol (AMP), and 1MK2CO3 at 40 and 80°C. At 40°C, K2CO3 produced the most successful protective siderite layer; by contrast, the amine solutions developed layers with interlocking crystals at 80°C. After siderite formation, these substrates were tested in 2.5M MEA and AEPZ, both highly corrosive but with more desirable capture kinetics. At 80°C, substrates pre-treated with MDEA or AMP showed good resistance against the corrosive actions of MEA and AEPZ for four weeks. The siderite layer reduced Fe oxidation at the surface and ingress of solution species thereby ceasing contact and corrosion.

Cost and performance of some carbon capture technology options for producing different quality CO2 product streams

A techno-economic assessment of power plants with CO2 capture technologies with a focus on process scenarios that deliver different grades of CO2 product purity is presented. The three leading CO2 capture technologies are considered, namely; oxyfuel combustion, pre-combustion and post-combustion capture. The study uses a combination of process simulation of flue gas cleaning processes, modelling with a power plant cost and performance calculator and literature values of key performance criteria in order to evaluate the performance, cost and CO2 product purity of the considered CO2 capture options. For oxyfuel combustion capture plants, three raw CO2 flue gas processing strategies of compression and dehydration only, double flash system purification and distillation purification are considered. Analysis of pre-combustion capture options is based on integrated gasification combined cycle plants using physical solvent systems for capturing CO2 and sulfur species via three routes; co-capture of sulfur impurities with the CO2 stream using Selexol™ solvent, separate capture of CO2 and sulfur impurities using Selexol™, and Rectisol® solvent systems for separate capture of sulfur impurities and CO2. Analysis of post-combustion capture plants was made with and without some conventional pollution control devices. The results highlight the wide variation in CO2 product purity for different oxyfuel combustion capture scenarios and the wide cost variation for the pre-combustion capture scenarios. The post-combustion capture plant with conventional pollution control devices offers high CO2 purity (99.99mol%) for average cost of considered technologies. The calculations performed will be of use in further analyses of whole chain CCS for the safe and economic capture, transport and storage of CO2.

Dynamic Behavior of Coal-Fired Power Plants with Postcombustion CO2 Capture

The combined operation of postcombustion CO2 capture and a power plant is a complex process with significant mutual interactions. Although the application of CO2 capture imposes an efficiency penalty on the power plant, it also provides the opportunity to operate the power plant in a more flexible way. To analyze this process, a detailed model of a postcombustion capture plant is developed and validated with measurement data. Afterward, the model is coupled to the model of a hard coal-fired power plant to study the effects of a joint operation. In a case study scenario, the steam extraction of the carbon capture plant is reduced by 50% to increase the power generation of the power plant. The results indicate that it is possible to provide primary frequency control by using this mode of operation.

Sequential supplementary firing in natural gas combined cycle with carbon capture: A technology option for Mexico for low-carbon electricity generation and CO2 enhanced oil recovery

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, 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 $/t CO2 and by 4.9 and 6.7 $/MWh at $50/t CO2. At a gas price of $4/MMBTU and $6/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.

Analysis of di-methyl ether production routes: Process performance evaluations at various syngas compositions

This paper investigates direct di-methyl ether (DME) production based on dry methane reforming (DMR-to-DME) and on bireforming (BiR-to-DME). Technically, DMR-to-DME is preferred to BiR-to-DME because the former produces synthesis gas (syngas) with a hydrogen to carbon monoxide molar ratio (H2/CO) of 1 which is the ideal ratio for DME synthesis. Whereas the latter produces a H2/CO close to 2 and consequently suffers from two apparent drawbacks: (1) lack of the so-called ‘synergy effect’ – a feature that enhances DME yield when operating at H2/CO close to 1, and (2) generation of a high heat capacity by-product (H2O) which makes DME recovery energy intensive. In this paper, we find that those two disadvantages actually enhance the performance of BiR compared to DMR across a range of performance metrics. Although the presence of water increases the cooling/heating duty and the distillation columns’ reboiler duty in the BiR route, more heat released from DME synthesis reactor can be utilized in the reboilers to make BiR techno-economically compatible. To assess the sustainability of DMR and BiR, evaluations are carried out against an existing industrial scale DME production route (auto-thermal-reforming (ATR)). By utilizing the carbon in the CO2 from an attached post-combustion carbon capture plant, DMR and BiR can save 22.3% methane feed uptake on average compared to the ATR process, which results in the DMR and BiR reducing CO2 emissions by at least 6.5% on average.

The effect of CO2-loaded amine solvents on the corrosion of a carbon steel stripper

The corrosive behaviour of loaded amine solvents was evaluated under stripper operating conditions, for post-combustion carbon capture, to determine the feasibility of using carbon steel in plant construction. In addition to monoethanolamine, three alternative amine solvents: methyldiethanolamine (MDEA), 2-amino-2-methyl-1-propanol (AMP), 1-(2-aminoethyl)piperazine (AEPZ), and the common additive K2CO3 were studied when in contact with carbon steel (C1018) over a 28-day period. Corrosive behaviour was evaluated using carbon steel coupons: gravimetric method for weight change, surface imaging (SEM) and analytical techniques (EDX and XRD), and Fe ion concentration in solution (ICP–OES). The results demonstrated that MDEA and AMP as well as K2CO3 develop a significant siderite (FeCO3) layer on the carbon steel surface. The presence of this layer is attributed to the preferred reaction pathway with CO2 for tertiary and sterically hindered amines. The FeCO3 layer formed in the case of MDEA provides superior protection from continued corrosion of the carbon steel. By contrast, MEA and AEPZ show significant corrosion to the carbon steel surface. In conclusion, MDEA, AMP, and K2CO3 can preferentially produce sufficient surface FeCO3 layers to reduce corrosion levels in carbon steels for use under stripper conditions in post-combustion carbon capture plants.

Agile control of CO2 capture technology for maximum net operating revenue

This paper uses a multi-layered control scheme consisting of model predictive control (MPC) and mixed integer non-linear programming (MINLP) for the analysis of power plant net operating revenue when retrofitted with a post-combustion carbon capture (PCC) plant. The capability of the proposed control scheme is examined for 24-hour operations of an integrated plant (power plant with PCC) in the years 2011 and 2020. The control scheme is tested in response to variability in upstream power plant dynamic loads. The agility of the control scheme subject to forecast 2020 electricity and carbon prices is shown to result in yearly net operating revenue of approximately 12% of the gross revenue. Whereas, the same integrated plant generates a net operating revenue loss of roughly 13% of the gross revenue under 2011 electricity and carbon prices.

Dynamic Operation and Simulation of Post-Combustion CO2 Capture

Thermal power need to operate, on a daily basis, with frequent and fast load changes to balance the large variations of intermittent energy sources, such as wind and solar energy. To make the integration of carbon capture to power plants economically and technically feasible, the carbon capture process has to be able to follow these fast and large load changes without decreasing the overall performance of the carbon capture plant. Therefore, dynamic models for simulation, optimization and control system design are essential.In this work, we compare the transient behavior of the model against dynamic pilot data for CO2 absorption and desorption for step-changes in the flue gas flow rate. In addition we investigate the dynamic behavior of a full-scale post-combustion capture plant using monoethanolamine (MEA) and piperazine (PZ). This analysis demonstrates the good agreement between the developed model (dCAPCO2) and the pilot measurements at both, transient and steady-state conditions. It outlines how the time needed to reach a new steady-state varies with respect to amine type and concentration. The simulation study reveals that it is essential to control the lean solvent flow to avoid sudden changes in the CO2 removal rate and to avoid increased heat demand of solvent regeneration. In addition, it shows how storage tanks (liquid hold-up of the system) can be designed to accommodate significant upstream changes in the power plant management. This flexibility is especially needed for operation in future mixed green energy market.

A techno-economic analysis of post-combustion CO2 capture and compression applied to a combined cycle gas turbine: Part I. A parametric study of the key technical performance indicators

In order to mitigate significant capital expenditure and parasitic energy demands associated with post combustion capture plant, many studies focused on improving its performance and efficiency through improvement in the design, integration of utilities and selection of key operating parameters (KOPs) using various key performance indicators (KPIs). In this study, an equilibrium monoethanolamine-based CO2 capture plant and compression train model was developed, validated and then used to assess the effects of KOPs on the performance of the CO2 capture and compression process applied to a 400MWe combined cycle gas turbine (CCGT) power plant in hot countries using selected non-monetized key economic and environmental performance indicators. These were selected so as to allow performance comparisons without resorting to economic assumptions (e.g., discount rates, costs of energy), which make such comparisons difficult. The results illustrate higher compression power and dramatic increase of cooling water requirements in coolers and washing water systems in hot countries. This work elucidates the complex compromise between minimizing capital and operating expenditure indicators, and environmental impacts. It highlights the importance of considering the whole process, as opposed to simply focusing on the energy penalty associated with solvent regeneration.

Evaluation of methods for monitoring MEA degradation during pilot scale post-combustion capture of CO2

Amine degradation is an important and current focus in the development of chemical absorption technology based on the use of aqueous amines for post-combustion capture (PCC) of CO2. The oxidative degradation and carbamate polymerisation of monoethanolamine (the current industry standard amine for PCC) has been studied extensively at the laboratory scale. However, methods for monitoring long-term amine degradation during pilot, demonstration and commercial scale PCC are needed to enable researchers and operators to optimise amine management (e.g. minimising degradation and optimising reclamation strategies), improve PCC plant operation and avoid operational instabilities. The current industry standard method, based on the measurement of heat-stable salts (HSS) is not suitable for continuous monitoring of amine degradation. This study discusses the organic structural changes of severely degraded 30% (w/w) aqueous monoethanolamine samples obtained from a PCC pilot plant operating at a brown coal-fired power station in Australia. It demonstrates that absorbance measurement at 313nm by UV–vis, change in infra-red absorbance and the organic carbon content of degradation products correlate strongly with HSS concentrations. These parameters are easily measured using well established technology and are suitable for monitoring the degradation of aqueous monoethanolamine during PCC.

Branching ratios for the reactions of OH with ethanol amines used in carbon capture and the potential impact on carcinogen formation in the emission plume from a carbon capture plant.

The OH initiated gas-phase chemistry of several amines that are potential candidates for use in post-combustion carbon capture (PCCC) plants have been studied by laser flash photolysis with OH monitored by laser induced fluorescence. The rate coefficients for the reaction of OH with N-methylethanolamine (MMEA) and N,N-dimethylethanolamine (DMEA) have been measured as a function of temperature (∼300-500 K): k(OH+MMEA) = (8.51 ± 0.65) × 10(-11)(T/298)(-(0.79±0.22), k(OH+DMEA) = (6.85 ± 0.25) × 10(-11)(T/298)(-(0.44±0.12). The results for DMEA lie between previous values. This is the first kinetic study of the OH + MMEA reaction. At low pressures in the presence of oxygen, OH is recycled in the DMEA reaction as has been observed for other tertiary amines. Branching ratios for OH abstraction with MEA, DMEA and MMEA are dominated by abstraction from the αCH2 group. Abstraction from N-H is determined to be 0.38 ± 0.06 for MEA and 0.52 ± 0.06 for MMEA at 298 K. The impact of these studies has been assessed by using a modified chemical box model to calculate downwind concentrations of nitramines and nitrosamine formed in the photo-oxidation of MEA. Under clear sky conditions, the simulations suggest that current safe guidelines for nitramines may be significantly exceeded with predicted MEA emission rates.

Technology Could Cut CO2 Cost Sharply for Enhanced Oil Recovery

Technology Update As oil fields throughout the world are reaching maturity and requiring the use of secondary and tertiary recovery techniques, oil companies are looking for new processes and technologies to extract more oil from these aging fields. In the next 20 years, an estimated 50% of waterflooded fields will need to shift to enhanced oil recovery (EOR). Carbon dioxide (CO2) has proved to be an almost ideal EOR medium for a broad range of reservoir types and conditions, yielding increases in recovery of up to 15% of oil initially in place. Most of the experience with commercial CO2 EOR has been gained in onshore oil fields in the United States, particularly in the Permian Basin of Texas, where nearby sources of natural CO2 gas and an extensive CO2 transport infrastructure are available. “Onshore CO2 flooding is economical at CO2 costs of around USD 35 to 40 per tonne and an oil price of more than USD 75 per barrel,” said Richard Doidge, director of the TriGen CO2 removal technology program at Maersk Oil. “Where natural CO2 sources are not readily available, CO2 may today be sourced from petrochemical and pre- or post-combustion capture plants, for example. However, these capture methods typically yield CO2 prices of USD 80 to 120 per tonne, which would make CO2 flooding uneconomical.” A ready but limited source of lowcost CO2 can be obtained from facilities, such as ethanol, petrochemical, and gasto- liquids plants, but the bulk of globally emitted industrial CO2 comes from power production and heavy industries, such as steelmaking and cement production. There are three main approaches to removing or “scrubbing” CO2 from feed or flue gases: precombustion, post-combustion, and combustion. Because of the oxygen required in the combustion mixture, the combustion methods are usually called oxy-fuel processes. The efficiency of these processes depends on, among other factors, the concentration of CO2 in the feed or flue gas and the pressure at which the contaminated gas is treated.

MALDI-MS and HILIC ESI-MS/MS as Versatile Tools for Detection of Monoethanolamine Degradation Products in a Real Postcombustion Carbon Dioxide Capture Plant

A simple method based on hydrophilic liquid chromatography (HILIC) and electrospray mass spectrometry (ESI-MS) for the detection of monoethanolamine (MEA) degradation products in CO2 postcombustion capture plants has been developed. MEA byproducts determination has traditionally been difficult due to analytical separation problems. Even in recent sophisticated methods, this difficulty remains as the major issue often resulting in time-consuming sample preparations. In this work, we have collected samples directly from a real pilot plant and analyzed them, for the first time, by using matrix assisted laser desorption ionization (MALDI)-MS or ESI-MS without any separation, both in positive and negative ionization modes. Alternatively, a previous liquid chromatography (LC) run was performed before ESI-MS; traditional reverse phase separation and HILIC were compared. Our results indicated that HILIC separation using an amino modified column, coupled to ESI-MS or ESI-MS/MS measurements, is the suitable method for identifying as many degradation products. Moreover, some plausible degradation mechanisms are proposed to explain some peaks in the spectra. The present work is intended as a preliminary study aiming to show the usefulness of these alternative techniques for this kind of investigations.

Emissions to the Atmosphere from Amine-Based Post Combustion CO2Capture Plant – Regulatory Aspects

Amine-based Post Combustion Capture (PCC) of CO<sub>2<sub/> is a readily available technology that can be deployed to reduce CO<sub>2<sub/> emissions from coal fired power plants. However, PCC plants will likely release small quantities of amine and amine degradation products to the atmosphere along with the treated flue gas. The possible environmental effects of these emissions have been examined through different studies carried out around the world. Based on flue gas from a 400 MW ultra-supercritical coal fired power plant Aspen-Plus PCC process simulations were used to predict the potential atmospheric emissions from the plant. Different research initiatives carried out in this area have produced new knowledge that has significantly reduced the risk perception for the release of amine and amine degradation products to the atmosphere.In addition to the reduction of the CO<sub>2<sub/> emissions, the PCC technology will also help in reducing SO<sub>x<sub/> and NO<sub>2<sub/> emissions. However, some other pollutants such as NH<sub>3<sub/> and aerosols will increase if appropriate control technologies are not adopted. To study the atmospheric photo-oxidation of amines, attempts are being made to develop chemical reaction schemes that can be used for air quality assessment. However, more research is still required in this area to estimate the reactivity of amino solvents in the presence of other pollutants such as NO<sub>x<sub/> and other volatile organic compounds in the background air.Current air quality guidelines may need to be updated to include limits for the additional pollutants such as NH<sub>3<sub/>, nitrosamines and nitramines once more information related to their emissions is available. This paper focuses on describing the predicted concentrations of major pollutants that are expected to be released from a coal fired power plant obtained by ASPEN-Plus PCC process simulations in terms of current air quality regulations and other regulatory aspects.

On the Integration of Sequential Supplementary Firing in Natural Gas Combined Cycle for CO2-Enhanced Oil Recovery: A Techno-economic Analysis for Mexico

Abstract A techno-economic analysis of a natural gas combined cycle (NGCC) integrated with MEA-based CO 2 capture with an advanced configuration is carried out. Sequential supplementary firing in the Heat Recovery Steam Generator (HRSG) is combined with a supercritical combined cycle for the purpose of increasing CO 2 production for Enhanced Oil Recovery (EOR) at a competitive levelised cost of electricity. Supercritical steam conditions with a double reheat in the steam cycle are used to largely improve performance and take full advantage of sequential supplementary firing in the HRSG. Sequential supplementary firing increases the flue gas temperature throughout the Heat Recovery Steam Generator (HRSG) by burning additional fuel at different stages to maximise the use of oxygen available in the flue gas exiting the gas turbine. The positive impact on the post combustion capture plant size and energy requirements for solvent regeneration are attractive for markets with cheap natural gas, and where the emphasis on capital cost reduction is important. This study then investigates the effect of fuel prices and capital costs for this configuration and compares it with a typical combined cycle integrated with MEA-based CO 2 capture. A case study for Mexico is presented, at a range of gas prices where these modifications would be attractive, with a tentative target of $40/tCO 2 .

Solid Formation in Piperazine Rate-based Simulation

Piperazine is a promising solvent for reducing CO2 emissions. It can be applied for the post-combustion capture process and it has limited degradation and fast kinetics. However, precipitation and slurry formation still represent a challenge for the PZ-CO2-H2O system from an operational point of view but also from a modeling perspective. The present work develops a rate-based model for CO2 absorption and desorption modeling for gas-liquid-solid systems and it is demonstrated for the piperazine CO2 capture process. This model is an extension of the DTU CAPCO2 model to precipitating systems. It uses the extended UNIQUAC thermodynamic model for phase equilibria and thermal properties estimation. The mass and heat transfer phenomena is implemented in a film model approach, based on second order reactions kinetics. The transfer fluxes are calculated using the concentration of the dissolved species since the piperazine is deactivated when present as solid. It is assumed that solid-gas reactions are slow compared to normal liquid side reactions. In the current work, the formation of solids is described in an equilibrium approach, assuming instantaneous formation of hydrates such as PZo 6H2O, PZo ½H2O, and anhydrous PZ. The simulation of a 100t/hr post-combustion capture plant outlines that 5 % solid reduces the CO2 capture rate with 13%. Therefore, it demonstrates that an accurate description of the precipitation phenomenon is essential for realistic and accurate modeling.