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Novel absorber intercooling configurations were evaluated for CO 2 capture with 8 m piperazine (PZ) for NGCC flue gas (3.5 mol % CO 2 ) over a range of operating conditions (90–99% CO 2 capture, LLDG = 0.15–0.27 mol CO 2 /mol alkalinity, L/G = 0.7–1.4 mol/mol). The improved intercooling configurations included solvent recycle and hybrid intercooling where the gas stream is split and contacted in multiple passes by the solvent. In both advanced designs, absorber performance is enhanced by introducing a new degree of freedom: an independent liquid-to-gas ratio (L/G) in high-intensity contacting sections. The higher L/G sections benefit from enhanced mass transfer due to turbulence generated in the packing (modeled via mass transfer coefficients and interfacial area of packing) and improved intercooling function (large solvent rate to moderate temperatures). In addition, the direct contact cooler upstream of the absorber was integrated into the column with the amine solvent performing the flue gas cooling function in a packed section with a higher L/G. Hybrid contacting outperformed all other configurations at all conditions evaluated, providing up to 70% reduction in packing area over the baseline absorber. A simplified 1x3+1 hybrid design (2 column sections) provided packing reduction over the baseline design and reduced complexity over other advanced configurations. At 99% CO 2 removal, only a 2x3+1 hybrid contacting scheme was able to integrate the direct contact cooler and achieve 99% removal at the conditions evaluated in this work. The hybrid design benefits from enhanced intercooling (multiple discrete intercooling points to approximate continuous solvent cooling and large L/G) and a better approximation of countercurrent contacting than the solvent recycle design.

Chemical absorption using aqueous amine is one of the most feasible options for post-combustion CO2 capture. One of the main challenges of this technology is its high energy requirements. Absorber intercooling was considered as a viable method to offer benefits in terms of solvent absorption capacity and mass transfer efficiency in CO2 absorption processes. However, the effectiveness of absorber intercooling on overall energy requirements depends on other factors such as lean loading and liquid to gas ratio. This study evaluates the benefits of using two different configurations of absorber intercooling, i.e. “in-and-out” and “recycled” intercooling when using 30 wt% aqueous monoethanolamine (MEA) to capture 90% CO2 from a natural gas fired turbine with 4 mol% CO2. The Lean CO2 loading was varied from 0.15 to 0.42 (mol CO2/mol MEA) to determine the lean loading at which the application of intercooling is most significant. Absorber intercooling provides the most benefit at lean loading from 0.30 to 0.34. The use of in-and-out and recycle intercooling at 0.34 lean loading, provided 15.6 and 15.8% reduction in the total equivalent work associated with 32.0% and 36.6% reduction in required packing area when using 1.2 times the minimum liquid flow rate. At lean loading greater than 0.34, the benefit of absorber intercooling is a trade-off between reduction of solvent flow rate and total energy requirement and the drawback of greater packing area in the absorber. The greatest saving in total equivalent work, 17%, was observed at the 0.36 lean loading associated with nearly 60% more packing area when using 1.2 times the minimum solvent flow rate. At very low lean loading and very high lean loading absorber intercooling does not offer significant benefit.

Offshore storage capacity has been identified as an essential part of long-term Carbon Capture, Utilization, and Storage (CCUS) strategies. Transporting the CO2 from the source onshore to the offshore storage site will be a critical aspect of the technical and economic viability of offshore storage projects. Transport of CO2 will include all processes and equipment from the preparation of CO2 for transport at the source to the wellhead at the offshore storage site. This paper will review the technology required at each step, identify risks/key knowledge gaps specific to the offshore transport process, suggest steps to be taken to advance the technology, and provide an overview of cost/economics for each step in the process. The authors use existing literature, an analysis of analog industries (e.g., offshore natural gas transport), knowledge from CO2 onshore transport, and a technical review of the processes and equipment required for offshore CO2 transportation. This analysis is based on a hypothetical CO2 source and transport process, but will highlight some project and site-specific challenges and decisions for each step. Specific results from the review of offshore transport process include the following: Impact of CO2 source on transport processes, including purification and preparation for transport (e.g., dehydration/compression processes); Comparison of offshore pipeline specifications and costs to comparable onshore applications; Review of scenarios where alternate transportation methods (e.g., ship transport) may be considered; Technical review of wellhead and injection facility in the offshore CO2 application in comparison to onshore analogs; Review of the impact of CO2 utilization (e.g., enhanced oil recovery) of CO2 on transport processes; Tabulation of gaps in data or knowledge to guide further research or industry input. The limited experience with offshore CO2 transport projects leaves significant gaps in available data and information on these projects. By aggregating the available information on offshore CO2 transport projects, supplementing with knowledge and data from related processes (offshore natural gas transport, onshore CO2 transport), and performing a technical review of the offshore transport processes and infrastructure, some specific data needs and risks for offshore CO2 transport projects are identified.

A low-order amine scrubbing model was developed for an intercooled absorber and advanced flash stripper configuration with piperazine solvent. The low-order lumped parameter model uses semi-empirical thermodynamics and rate-based mass transfer and embeds reaction kinetics in a constant overall transfer coefficient. The predicted off-design steady state of this model is compared to a high-order Aspen Plus simulation for 100–85% power plant load. The difference in CO2 removal rate between the two models is less than 1% when power plant load is greater than 94%. The removal rate is systematically overpredicted in the low-order model because a constant CO2 mass transfer coefficient in the absorber leads to an overprediction of absorber performance at part-load operation. Compared to pilot plant data, the low-order model captures the dynamic response of a step change in the stripper pressure control valve. The characteristic time of the total CO2 inventory is found to be 77 min, compared to a total liquid resi...

Abstract A novel method to remove nitrogen dioxide (NO2) from the flue gas of coal-fired power plants with CO2 capture has been advanced for commercial implementation. The technology leverages the equipment and chemistry in an existing (sulfur dioxide) SO2 polishing scrubber upstream of the main CO2 capture unit to remove the NO2, preventing degradation of the CO2 capture solvent and formation of nitrosamines. The report focuses on further evaluation of the chemical additives and operating conditions associated with the NO2 removal process to define conditions for commercial scale testing and deployment. Experimental work systematically evaluated a series of potential additives to minimize the oxidation of sulfite in a representative SO2 pre-scrubber solution. The additive combinations and concentrations were varied alongside important process conditions such as temperature, oxygen concentration, and metals present in solution to mimic the conditions expected in a commercial system. Important results of the parametric experimental work include identifying a new, potent sulfite oxidation inhibitor, revealing the importance of combining inhibitors with metal chelating agents, validation of a low-cost additive process, and development of a new semi-empirical model to represent mechanisms associated with sulfite oxidation. In addition, the experimental work revealed the impact of operating at higher temperatures (representative of a field test unit), which will guide the selection and concertation of additives as well. Techno-economic analysis identified potential net savings as large as $1.30/tonne CO2 captured and quantified the potential benefit of low cost additive options actively being pursued by the development team. Finally, the experimental results and engineering analysis supported the development of a detailed field testing plan and protocol to evaluate the technology at near-commercial scale. The field test preparation included development of procedures to introduce chemical additives to an existing SO2 polishing unit and identification of representative flue gas conditions based on a review of existing plants. These activities will have direct bearing on operation and design of commercial units.

This article provides an independent cost estimate for uranium production from seawater through the braid-type adsorbent recovery system proposed by the Japan Atomic Energy Agency (JAEA). Production costs were developed with standard engineering cost estimation techniques using vendor data and plant design and operational data. The analysis includes life cycle discounted cash flows, economies of scale, and propagation of uncertainties. A reference case based on the Japan Atomic Energy Agency assessment, with a fresh adsorbent capacity of 2 kgU/t ads and 6 recycles, yielded a production cost of $1230/kg uranium with a 95 percent confidence interval of [$1030/kg U, $1430/kg U] when component cost uncertainties alone were considered. Sensitivity studies confirmed that adsorbent capacity, number of recycles, and capacity degradation are major cost drivers. If capacity and number of recycles increases to 6 kg U/t ads and 20, respectively, with no degradation and unchanged adsorbent production costs, the uraniu...

Pilot plant data for CO2 capture with 8 m piperazine (PZ) were reconciled with an absorber model in Aspen Plus® using quantified error in pilot plant input data and a global correction to absorber performance parameters. Four global corrections were applied independently to adjust: interfacial area, liquid side mass transfer coefficient, solvent CO2 content, or solvent piperazine (PZ) content. Each of the four cases resulted in a reconciled model with pilot plant data and provides a potential route to quantifying and correcting measurement and experimental error as well as enhancing understanding of real absorber performance. The modified absorber model was then used to quantify the performance improvement due to implementation of a spray nozzle in the absorber intercooling loop. The spray nozzle added the equivalent of 7% to 20% more packing to the column as a function of the flow rate through the nozzle.

The recovery of uranium (U) from seawater has been investigated for over six decades in efforts to secure uranium sources for future energy production. The majority of the research activities have focused on inorganic materials, chelating polymers, and nanomaterials. Previous studies of uranium adsorption from aqueous solutions, mainly seawater, are reviewed here with a focus on various adsorbent materials, adsorption parameters, adsorption characterization, and marine studies. Continuous progress has been made over several decades, with adsorbent loadings approaching 3.2 mg U/g adsorbent in equilibrium with seawater. Further research is needed to improve first, the viability including improved capacity, selectivity, and kinetics, and second, the sorbent regeneration for multicycle use. An overview of the status of the uranium adsorption technology is provided and future research needs to make this technology commercially competitive are discussed.

A systematic evaluation of the solvent capacity and mass transfer benefits of absorber intercooling was conducted for CO 2 capture with 8 m piperazine (PZ) for three different flue gas sources: NGCC (4.1% CO 2 ), coal-fired boiler (14.7% CO 2 ), and steel blast furnace (27.4% CO 2 ). The study identified the best intercooling strategy as a function of operating conditions (lean loading, liquid to gas ratio (L/G)). For all applications, operation at low lean loadings did not require intercooling to avoid temperature-related capacity or mass transfer penalties. In a broad intermediate loading range, simple in-and-out intercooling provided large solvent capacity benefits (measured as minimum solvent rate, LMIN) compared to a column without intercooling. LMIN was reduced by 71%, 53%, and 42% for NGCC, coal, and steel, respectively. Finally, the coal and steel applications had a large L/G range at higher loadings where intercooling was once again unnecessary. An enhanced intercooling design for NGCC could yield up to 62% reduction in packing and 46% reduction in solvent capacity at specific conditions (benefits for coal and steel were much lower). A recycle intercooling design for NGCC was introduced to reduce overall column temperatures and enhance mass transfer. For the case evaluated with recycle intercooling, the new design achieved significant packing reductions (>50%) compared to a simple intercooling design and approximated the performance of an isothermal column.