A kinetic model for the dissolution of borosilicate glass, incorporated into the EQ3/6 geochemical modeling code, is used to predict the dissolution rate of a nuclear waste glass. The glass dissolution rate is controlled by the rate of dissolution of an alkali-depleted amorphous surface gel layer. The good agreement between predicted and observed dissolution behavior suggests that the experimentally obtained non-linear glass release rates are not diffusion controlled, as previously believed, but are instead controlled by dissolution affinity. The model predicts that the long-term rate of glass dissolution will depend mainly on ion concentrations in solution, and therefore the secondary phased which precipitate and control ion concentrations. 4 refs., 5 figs., 1 tab.

We have developed a new class of sodium carbonate/silicone composite sorbents that selectively capture carbon dioxide (CO2) and can purify biogas to natural gas pipeline-quality biomethane. These nontoxic composites can be three-dimensionally printed or extruded at low costs, can have high specific CO2 sorption rates (in excess of 5 μmol s-1 g-1 bar-1) and high selectivity due to their chemical mechanism, and can be regenerated with low-energy air stripping. Therefore, these composite sorbents combine the high selectivity of liquid sorbents with the high specific sorption rates and low regeneration energies found in many solid sorbents. We characterized these composite sorbents with X-ray computed tomography, scanning electron microscopy (SEM), and X-ray diffraction (XRD). Furthermore, we measured composite sorption capacities of up to 0.62 mol CO2 kg-1 and recorded breakthrough curves in a flow-through, fixed-bed reactor using both simulated biogas and locally sourced industrial biogas. Additional tests of the composite sorbent were carried out with pure CO2 in a sealed pressure drop apparatus. This experimental data was used to validate a numerical model of the setup and to simulate an industrial-scale biogas upgrading process. Finally, we performed a preliminary technoeconomic analysis for this upgrading process and found that this composite sorbent can upgrade biogas at a lower cost (∼$0.97 per GJ) than other currently implemented techniques.

Glass dissolution takes place through metal leaching and hydration of the glass surface accompanied by development of alteration layers of varying crystallinity. The reaction which controls the long-term glass dissolution rate appears to be surface layer dissolution. This reaction is reversible because the buildup of dissolved species in solution slows the dissolution rate due to a decreased dissolution affinity. Glass dissolution rates are therefore highly dependent on silica concentrations in solution because silica is the major component of the alteration layer. Chemical modeling of glass dissolution using reaction path computer codes has successfully been applied to short term experimental tests and used to predict long-term repository performance. Current problems and limitations of the models include a poorly defined long-term glass dissolution mechanism, the use of model parameters determined from the same experiments that the model is used to predict, and the lack of sufficient validation of key assumptions in the modeling approach. Work is in progress that addresses these issues.

We have developed polymer composite inks that may be three-dimensionally (3D) printed to produce new reactor designs for CO2 capture. These inks are composed of solid sodium carbonate particles dispersed within an uncured silicone and are printed using direct ink writing (DIW). After printing, the silicone is cured, and the structures are hydrated to form aqueous sodium carbonate domains dispersed throughout the silicone. These domains enable high CO2 absorption rates by creating domains with a high surface area of the solvent per unit volume in the printed structures. These results demonstrate an order-of-magnitude improvement in CO2 absorption rates relative to a liquid pool of sodium carbonate. The results from this class of composite inks demonstrate the potential for the use of 3D printing to shape new and advanced CO2 capture reactors.

We encapsulated six solvents with novel physical and chemical properties for CO2 sorption within gas-permeable polymer shells, creating Micro-Encapsulated CO2 Sorbents (MECS), to improve the CO2 absorption kinetics and handling of the solvents for postcombustion CO2 capture from flue gas. The solvents were sodium carbonate (Na2CO3) solution, uncatalyzed and with two different promoters, two ionic liquid (IL) solvents, and one CO2-binding organic liquid (CO2BOL). We subjected each of the six MECS to multiple CO2 absorption and regeneration cycles and measured the working CO2 absorption capacity as a function of time to identify promising candidate MECS for large-scale carbon capture. We discovered that the uncatalyzed Na2CO3 and Na2CO3-sarcosine MECS had lower CO2 absorption rates relative to Na2CO3-cyclen MECS over 30 min of absorption, while the CO2BOL Koechanol appeared to permeate through the capsule shell and is thus unsuitable. We rigorously tested the most promising three MECS (Na2CO3-cyclen, IL NDIL0309, and IL NDIL0230) by subjecting each of them to a series of 10 absorption/stripping cycles. The CO2 absorption curves were highly reproducible for these three MECS across 10 cycles, demonstrating successful absorption/regeneration without degradation. As the CO2 absorption rate is dynamic in time and the CO2 loading per mass varies among the three most promising MECS, the process design parameters will ultimately dictate the selection of MECS solvent.

Compressing carbon dioxide (CO2) to supercritical pipeline pressures is one of the major costs of carbon capture and storage. Many innovative approaches to decreasing this cost have been suggested, in many cases relying on high temperature regeneration schemes utilizing high enthalpy solvents. Solid sorbent systems have not generally been examined for high pressure regeneration. We have now quantified through experimental and modelling studies that it is possible to obtain CO2 pressures of 150 bars or more by thermal decomposition of solid sodium bicarbonate (nahcolite, NaHCO3). In a cyclic operations with CO2 withdrawal, our model of the process predicts a swing capacity of 5% (wt.) when withdrawing CO2 at 20 bars, and 2% when withdrawing CO2 at 80 bars (supercritical fluid). Precipitation of solid sodium bicarbonate ("scaling") has been observed previously when using sodium carbonate solutions in CO2 capture, and was considered an obstacle to the use of sodium carbonate as a capture solution due to potential mineral precipitation on the packing material. The ability to encapsulate the capture solvent overcomes the scaling problem and allows multiple benefits of the sodium carbonate capture solvent to realized [1]. In addition to high pressures of regeneration, these benefits include the low cost and benign nature of sodium carbonate, thermal stability with no thermal degradation, competitive carbon transfer mass when compared with amines, relatively low heat of solution of CO2 in the carbonate solvent, and potentially a reduced mass of water heated during regeneration. Using previous experimental data as well as our own measurements of CO2 pressures in equilibrium with carbonate solutions, we have developed a model of the phase behavior over a range of processing conditions of up to 210 degrees C and saturation with respect to nahcolite. Using these data to parametrize a Pitzer electrolyte model, we predicted that in the absence of water, nahcolite reaches supercritical CO2 pressures over the solid at about 125 degrees C. This encouraged us to pursue experimental determination with realistic amounts of water to allow for conversion of carbonate (CO32-) to bicarbonate (HCO3-) as loading with CO2 takes place. High CO2 pressures shift to higher temperature as the carbonate/water ratio decreases. However, encapsulated carbonates allow the system to operate at very high carbonate/water ratios such that a solid phase is present throughout the capture process. Each capsule contains mainly a solid carbonate phase with a small mass of saturated solution. Engineering of the capsule material may allow us to control both CO2 loading and water content independently to maximize CO2 carrying capacity and minimize water content, saving process energy by heating only minimal water during regeneration. (c) 2017 The Authors. Published by Elsevier Ltd.

The current uncertainty in the global supply of rare earth elements (REEs) necessitates the development of novel extraction technologies that utilize a variety of REE source materials. Herein, we examined the techno-economic performance of integrating a biosorption approach into a large-scale process for producing salable total rare earth oxides (TREOs) from various feedstocks. An airlift bioreactor is proposed to carry out a biosorption process mediated by bioengineered rare earth-adsorbing bacteria. Techno-economic assessments were compared for three distinctive categories of REE feedstocks requiring different pre-processing steps. Key parameters identified that affect profitability include REE concentration, composition of the feedstock, and costs of feedstock pretreatment and waste management. Among the 11 specific feedstocks investigated, coal ash from the Appalachian Basin was projected to be the most profitable, largely due to its high-value REE content. Its cost breakdown includes pre-processing (leaching primarily, 77.1%), biosorption (19.4%), and oxalic acid precipitation and TREO roasting (3.5%). Surprisingly, biosorption from the high-grade Bull Hill REE ore is less profitable due to high material cost and low production revenue. Overall, our results confirmed that the application of biosorption to low-grade feedstocks for REE recovery is economically viable.

We present an approach for managing geologic CO2 storage using wells that serve three sequential purposes (1) characterization and monitoring, (2) brine production, and (3) CO2 injection. Two reservoirs are deployed in tandem: (1) a CO2-storage reservoir and (2) a brine-storage reservoir. This approach provides data that can be analyzed prior to CO2 injection, enabling proactive reservoir management, which reduces cost and risk. We analyze a range of brine-disposition options, including 100% reinjection in a nearby brine-storage reservoir and cases where a portion of the produced brine is used to generate water, with the residual brine reinjected in the nearby reservoir. We also consider the option of time-shifting the parasitic load of brine production and injection, so that those operations can utilize excess energy from electric grids during periods of over-generation.

Two of the most important challenges facing the global energy sector are to reduce the CO2 intensity and the water intensity of energy production. Because many economies will continue to depend on fossil fuels as primary energy sources, CO2 capture and storage (CCS) must play a major role in curbing CO2 emissions. A large portion of CO2 storage will need to occur in saline reservoirs because these resources are more widely distributed than hydrocarbon resources-where CO2 capture utilization and storage (CCUS) can be deployed for enhanced oil recovery (EOR). CCS deployment can be accelerated with a pressure-management strategy, called pre-injection brine production that proactively manages project risks linked to reservoir pressure. In this approach, a CCS wellfield is deployed sequentially, one well at a time, with each well being used for three stages: (1) monitoring, (2) brine production, and (3) CO2 injection. Using the same well to produce brine before injecting CO2 provides pre-injection reservoir diagnostics needed for proactive planning of wellfield operations. Because pressure drawdown is greatest where CO2 injection will subsequently occur, reservoir pressure is efficiently managed per well, and per unit of removed brine. This approach to managing geologic CO2 storage can (1) identify resources with sufficient CO2 storage capacity and permanence, and provide information needed to effectively manage those resources prior to injecting CO2; (2) increase CO2 storage capacity and efficiency; (3) limit pore-space competition with neighboring subsurface operations; and (4) reduce the duration of post-injection site care and monitoring, while (5) creating the opportunity to generate water, using an emerging CCUS technology called enhanced water recovery (EWR). Although beneficial consumptive use of produced brine may be preferred in water constrained regions, there may be situations where the brine composition is not economically treatable, which could necessitate reinjecting some or all of the produced brine into a separate reservoir. In this study we consider a range of brine-disposition options, from 100% reinjection in the subsurface to near zero net injection of fluid, which maximizes the water generation benefit per tonne of stored CO2. These options are analyzed for a case where a nearby saline reservoir overlying a CO2 storage reservoir is used to store some or all of the brine removed from the CO2 storage reservoir. (C) 2016 The Authors. Published by Elsevier Ltd.

Carbon capture, utilization and storage (CCUS) seeks beneficial applications for CO2 recovered from fossil fuel combustion. This study evaluated the potential for removing formation water to create additional storage capacity for CO2, while simultaneously treating the produced water for beneficial use. The process would control pressures within the target formation, lessen the risk of caprock failure, and better control the movement of CO2 within that formation. The project plans to highlight the method of using individual wells to produce formation water prior to injecting CO2 as an efficient means of managing reservoir pressure. Because the pressure drawdown resulting from pre-injection formation water production will inversely correlate with pressure buildup resulting from CO2 injection, it can be proactively used to estimate CO2 storage capacity and to plan well-field operations. The project studied the GreenGen site in Tianjin, China where Huaneng Corporation is capturing CO2 at a coal fired IGCC power plant. Known as the Tianjin Enhanced Water Recovery (EWR) project, local rock units were evaluated for CO2 storage potential and produced water treatment options were then developed. Average treatment cost for produced water with a cooling water treatment goal ranged from 2.27 to 2.96 US$/m(3) (recovery 95.25%), and for a boiler water treatment goal ranged from 2.37 to 3.18 US$/m(3) (recovery 92.78%). Importance analysis indicated that water quality parameters and transportation are significant cost factors as the injection-extraction system is managed over time. The study found that in a broad sense, active reservoir management in the context of CCUS/EWR is technically feasible. In addition, criteria for evaluating suitable vs. unsuitable reservoir properties, reservoir storage (caprock) integrity, a recommended injection/withdrawal strategy and cost estimates for water treatment and reservoir management are proposed. (C) 2016 Elsevier Ltd. All rights reserved.