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DOE OSTI2013

Advanced CO 2 Capture Technology for Low Rank Coal IGCC System

The overall objective of the project is to demonstrate the technical and economic viability of a new Integrated Gasification Combined Cycle (IGCC) power plant designed to efficiently process low rank coals. The plant uses an integrated CO 2 scrubber/Water Gas Shift (WGS) catalyst to capture over90 percent capture of the CO 2 emissions, while providing a significantly lower cost of electricity (COE) than a similar plant with conventional cold gas cleanup system based on Selexol TM technology and 90 percent carbon capture. TDA’s system uses a high temperature physical adsorbent capable of removing CO 2 above the dew point of the synthesis gas and a commercial WGS catalyst that can effectively convert CO in The overall objective of the project is to demonstrate the technical and economic viability of a new Integrated Gasification Combined Cycle (IGCC) power plant designed to efficiently process low rank coals. The plant uses an integrated CO 2 scrubber/Water Gas Shift (WGS) catalyst to capture over90 percent capture of the CO 2 emissions, while providing a significantly lower cost of electricity (COE) than a similar plant with conventional cold gas cleanup system based on Selexol TM technology and 90 percent carbon capture. TDA’s system uses a high temperature physical adsorbent capable of removing CO 2 above the dew point of the synthesis gas and a commercial WGS catalyst that can effectively convert CO in bituminous coal the net plant efficiency is about 2.4 percentage points higher than an Integrated Gasification Combined Cycle (IGCC) plant equipped with Selexol TM to capture CO 2 . We also previously completed two successful field demonstrations: one at the National Carbon Capture Center (Southern- Wilsonville, AL) in 2011, and a second demonstration in fall of 2012 at the Wabash River IGCC plant (Terra Haute, IN). In this project, we first optimized the sorbent to catalyst ratio used in the combined WGS and CO 2 capture process and confirmed the technical feasibility in bench-scale experiments. In these tests, we did not observe any CO breakthrough both during adsorption and desorption steps indicating that there is complete conversion of CO to CO 2 and H 2 . The overall CO conversions above 90 percent were observed. The sorbent achieved a total CO 2 loading of 7.82 percent wt. of which 5.68 percent is from conversion of CO into CO 2 . The results of the system analysis suggest that the TDA combined shift and high temperature PSA-based Warm Gas Clean-up technology can make a substantial improvement in the IGCC plant thermal performance for a plant designed to achieve near zero emissions (including greater than 90 percent carbon capture). The capital expenses are also expected to be lower than those of Selexol. The higher net plant efficiency and lower capital and operating costs result in substantial reduction in the COE for the IGCC plant equipped with the TDA combined shift and high temperature PSA-based carbon capture system.

01 COAL, LIGNITE, AND PEAT↗

DOE OSTI2014

Bio-Oil Separation and Stabilization by Supercritical Fluid Fractionation. 2014 Final Report

The objective of this project is to use supercritical fluids to separate and fractionate algal-based bio-oils into stable products that can be subsequently upgraded to produce drop-in renewable fuels. To accomplish this objective, algae was grown and thermochemically converted to bio-oils using hydrothermal liquefaction (HTL), pyrolysis, and catalytic pyrolysis. The bio-oils were separated into an extract and a raffinate using near-critical propane or carbon dioxide. The fractions were then subjected to thermal aging studies to determine if the extraction process had stabilized the products. It was found that the propane extract fraction was twice as stable as the parent catalytic pyrolysis bio-oils as measured by the change in viscosity after two weeks of accelerated aging at 80°C. Further, in-situ NMR aging studies found that the propane extract was chemically more stable than the parent bio-oil. Thus the milestone of stabilizing the product was met. A preliminary design of the extraction plant was prepared. The design was based on a depot scale plant processing 20,000,000 gallons per year of bio-oil. It was estimated that the capital costs for such a plant would be $8,700,000 with an operating cost of $3,500,000 per year. On a per gallon of product cost and a 10% annual rate of return, capital costs would represent $0.06 per gallon and operating costs would amount to $0.20 per gallon. Further, it was found that the energy required to run the process represented 6.2% of the energy available in the bio-oil, meeting the milestone of less than 20%. Life cycle analysis and greenhouse gas (GHG) emission analysis found that the energy for running the critical fluid separation process and the GHG emissions were minor compared to all the inputs to the overall well to pump system. For the well to pump system boundary, energetics in biofuel conversion are typically dominated by energy demands in the growth, dewater, and thermochemical process. Bio-oil stabilization by near critical propane extraction had minimal impact in the overall energetics of the process with NER contributions of 0.03. Based on the LCA, the overall conversion pathways were found to be energy intensive with a NER of about 2.3 and 1.2 for catalytic pyrolysis and HTL, respectively. GHG emissions for the catalytic pyrolysis process were greater than that of petroleum diesel at 210 g CO2 eq compared to 18.9 g CO2 eq. Microalgae bio-oil based diesel with thermochemical conversion through HTL meets renewable fuel standards with favorable emission reductions of -10.8 g CO2 eq. The importance of the outcomes is that the critical fluid extraction and stabilization process improved product stability and did so with minimal energy inputs and processing costs. The LCA and GHG emission calculations point toward the HTL pathway as the more favorable thermochemical route towards upgrading algae to bio-fuels. Since the quality of the HTL oil was significantly lower than that of the catalytic pyrolysis bio-oil, the next steps point toward improving the quality of the HTL oils from algae biomass and focusing the critical fluid stabilization on that bio-oil product.

09 BIOMASS FUELS↗

DOE OSTI2014

SISGR-Fundamental Experimental and Theoretical Studies on a Novel Family of Oxide Catalyst Supports for Water Electrolysis

Identification and development of non-noble metal based electro-catalysts or electro-catalysts with significant reduction of expensive noble metal contents (E.g. IrO2, Pt) with comparable electrochemical performance as the standard noble metal/metal oxide for proton exchange membrane (PEM) based water electrolysis would constitute a major breakthrough in the generation of hydrogen by water electrolysis. Accomplishing such a system would not only result reduction of the overall capital costs of PEM based water electrolyzers, but also help attain the targeted hydrogen production cost [< $ 3.0 / gallon gasoline equivalent (gge)] comparable to conventional liquid fuels. In line with these goals, it was demonstrated that fluorine doped IrO2 thin films and nanostructured high surface area powders display remarkably higher electrochemical activity, and comparable durability as pure IrO2 electro-catalyst for the oxygen evolution reaction (OER) in PEM based water electrolysis. Furthermore, corrosion resistant SnO2 and NbO2 support has been doped with F and coupled with IrO2 or RuO2 for use as an OER electro-catalyst. A solid solution of SnO2:F or NbO2:F with only 20 - 30 mol.% IrO2 or RuO2 yielding a rutile structure in the form of thin films and bulk nanoparticles displays similar electrochemical activity and stability as pure IrO2/RuO2. This would lead to more than 70 mol.% reduction in the noble metal oxide content. Novel nanostructured ternary (Ir,Sn,Nb)O2 thin films of different compositions FUNDAMENTAL STUDY OF NANOSTRUCTURED ELECTRO-CATALYSTS WITH REDUCED NOBLE METAL CONTENT FOR PEM BASED WATER ELECTROLYSIS 4 have also been studied. It has been shown that (Ir0.40Sn0.30Nb0.30)O2 shows similar electrochemical activity and enhanced chemical robustness as compared to pure IrO2. F doping of the ternary (Ir,Sn,Nb)O2 catalyst helps in further decreasing the noble metal oxide content of the catalyst. As a result, these reduced noble metal oxide catalyst systems would potentially be preferred as OER electro-catalysts for PEM electrolysis. The excellent performance of the catalysts coupled with its robustness would make them great candidates for contributing to significant reduction in the overall capital costs of PEM based water electrolyzers. This s.thesis provides a detailed fundamental study of the synthesis, materials, characterization, theoretical studies and detailed electrochemical response and potential mechanisms of these novel electro-catalysts for OER processes.

25 ENERGY STORAGE↗

DOE OSTI2013

Assessment of Brine Management for Geologic Carbon Sequestration

Geologic carbon sequestration (GCS) is the injection of carbon dioxide (CO 2 ), typically captured from stationary emission sources, into deep geologic formations to prevent its entry into the atmosphere. Active pilot facilities run by regional United States (US) carbon sequestration partnerships inject on the order of one million metric tonnes (mt) CO 2 annually while the US electric power sector emits over 2000 million mt-CO 2 annually. GCS is likely to play an increasing role in US carbon mitigation initiatives, but scaling up GCS poses several challenges. Injecting CO 2 into sedimentary basins raises fluid pressure in the pore space, which is typically already occupied by naturally occurring, or native, brine. The resulting elevated pore pressures increase the likelihood of induced seismicity, of brine or CO 2 escaping into potable groundwater resources, and of CO 2 escaping into the atmosphere. Brine extraction is one method for pressure management, in which brine in the injection formation is brought to the surface through extraction wells. Removal of the brine makes room for the CO 2 and decreases pressurization. Although the technology required for brine extraction is mature, this form of pressure management will only be applicable if there are cost-effective and sustainable methods of disposing of the extracted brine. Brine extraction, treatment, and disposal may increase the already substantial capital, energy, and water demands of Carbon dioxide Capture and Sequestration (CCS). But, regionally specific brine management strategies may be able to treat the extracted water as a source of revenue, energy, and water to subsidize CCS costs, while minimizing environmental impacts. By this approach, value from the extracted water would be recovered before disposing of any resulting byproducts. Until a price is placed on carbon, we expect that utilities and other CO 2 sources will be reluctant to invest in capital intensive, high risk GCS projects; early technical, economic, and environmental assessments of brine management are extremely valuable for determining the potential role of GCS in the US. We performed a first order feasibility and economic assessment, at three different locations in the US, of twelve GCS extracted-water management options, including: geothermal energy extraction, desalination, salt and mineral harvesting, rare-earth element harvesting, aquaculture, algae biodiesel production, road de-icing, enhanced geothermal system (EGS) recharge, underground reinjection, landfill disposal, ocean disposal, and evaporation pond disposal. Three saline aquifers from different regions of the US were selected as hypothetical GCS project sites to encompass variation in parameters that are relevant to the feasibility and economics of brine disposal. The three aquifers are the southern Mt. Simon Sandstone Formation in the Illinois Basin, IL; the Vedder Formation in the southern San Joaquin Basin, CA; and the Jasper Interval in the eastern Texas Gulf Basin, TX. These aquifers are candidates for GCS due to their physical characteristics and their close proximity to large CO 2 emission sources. Feasibility and impacts were calculated using one mt-CO 2 injected as the functional unit of brine management. Scenarios were performed for typical 1000MW coal-fired power plants (CFPP) that incurred an assumed 24 percent carbon capture energy penalty (EP), injected 90 percent of CO 2 emissions (~9 million mt- CO 2 injected annually), and treated extracted water onsite. Net present value (NPV), land requirements, laws and regulations, and technological limits were determined for each stage of disposal, and used to estimate feasibility. The boundary of the assessment began once extracted water was brought to the surface, and ended once the water evaporated, was injected underground, or was discharged into surface water bodies. Results of the assessment were generated, stored, and analyzed using Microsoft Excel spreadsheets and ESRI Geographical Information System (GIS) maps. Conclusions about the relative benefits and impacts of alternative brine-management strategies were highly sensitive to local climate and weather, and aquifer water chemistry. The NPV of certain scenarios ranged from -$50/mt-CO 2 (a cost) to +$10/mt-CO 2 (revenue). The land footprint of the scenarios in this study ranged from <1 km 2 to 100 km 2 . Brine extraction as a pressure management tool for GCS has potential for improving the economics and for minimizing the environmental impacts of CCS. In order to maximize this potential, careful analysis of each saline aquifer and region must be conducted to determine a regionally appropriate brine use sequence (BUS) at the time of site selection. Models that use GIS will be essential tools in determining such sequences for individual CFPP. Future studies that perform risk and life cycle assessments (LCA) of BUS scenarios, incorporate additional impact metrics into the BUS model, and enhance the temporal sensitivity of the model would improve the robustness of this regional assessment method.

54 ENVIRONMENTAL SCIENCES↗

DOE OSTI2013

56 th & Walnut—A Philly Gut Rehab Development

Load-bearing brick-masonry multifamily buildings are prevalent in urban areas across much of the U.S. Northeast and mid-Atlantic. In most instances, these buildings are uninsulated unless they have been renovated within the past two decades. Affordable housing capital budgets typically limit what can be spent and energy improvements often take a back seat to basic capital improvements such as interior finish upgrades and basic repairs. The Consortium for Advanced Residential Buildings is researching cost-effective solution packages for significant energy efficiency and indoor air-quality improvements in these urban buildings, as presented in this report.

32 ENERGY CONSERVATION, CONSUMPTION, AND UTILIZATI↗

DOE OSTI2014

Oil-free centrifugal hydrogen compression technology demonstration

One of the key elements in realizing a mature market for hydrogen vehicles is the deployment of a safe and efficient hydrogen production and delivery infrastructure on a scale that can compete economically with current fuels. The challenge, however, is that hydrogen, being the lightest and smallest of gases with a lower viscosity and density than natural gas, readily migrates through small spaces and is difficult to compresses efficiently. While efficient and cost effective compression technology is crucial to effective pipeline delivery of hydrogen, the compression methods used currently rely on oil lubricated positive displacement (PD) machines. PD compression technology is very costly, has poor reliability and durability, especially for components subjected to wear (e.g., valves, rider bands and piston rings) and contaminates hydrogen with lubricating fluid. Even so called “oil-free” machines use oil lubricants that migrate into and contaminate the gas path. Due to the poor reliability of PD compressors, current hydrogen producers often install duplicate units in order to maintain on-line times of 98-99%. Such machine redundancy adds substantially to system capital costs. As such, DOE deemed that low capital cost, reliable, efficient and oil-free advanced compressor technologies are needed. MiTi’s solution is a completely oil-free, multi-stage, high-speed, centrifugal compressor designed for flow capacity of 500,000 kg/day with a discharge pressure of 1200 psig. The design employs oil-free compliant foil bearings and seals to allow for very high operating speeds, totally contamination free operation, long life and reliability. This design meets the DOE’s performance targets and achieves an extremely aggressive, specific power metric of 0.48 kW-hr/kg and provides significant improvements in reliability/durability, energy efficiency, sealing and freedom from contamination. The multi-stage compressor system concept has been validated through full scale performance testing of a single stage with helium similitude gas at full speed in accordance with ASME PTC-10. The experimental results indicated that aerodynamic performance, with respect to compressor discharge pressure, flow, power and efficiency exceeded theoretical prediction. Dynamic testing of a simulated multistage centrifugal compressor was also completed under a parallel program to validate the integrity and viability of the system concept. The results give strong confidence in the feasibility of the multi-stage design for use in hydrogen gas transportation and delivery from production locations to point of use.

08 HYDROGEN↗

DOE OSTI2015

Use of Low-Temperature Geothermal Energy for Desalination in the Western United States

This joint project between the National Renewable Energy Laboratory and the Colorado School of Mines has examined the potential of using low-temperature geothermal resources for desalination. The temperature range in question is not well suited for electricity generation, but can be used for direct heating. Accordingly, the best integration approaches use thermal desalination technologies such as multi-effect distillation (MED) or membrane distillation (MD), rather than electric-driven technologies such as reverse osmosis (RO). The examination of different desalination technologies led to the selection of MD for pairing with geothermal energy. MD operates at near-ambient pressure and temperatures less than 100°C with hydrophobic membranes. The technology is modular like RO, but the equipment costs are lower. The thermal energy demands of MD are higher than MED, but this is offset by an ability to run at lower temperatures and a low capital cost. Consequently, a geothermal-MD system could offer a low capital cost and, if paired with low-cost geothermal energy, a low operating cost. The target product water cost is $1.0 to $1.5 per cubic meter depending on system capacity and the cost of thermal energy.

15 GEOTHERMAL ENERGY↗

DOE OSTI2016

Collaboration in Research and Engineering for Advanced Technology.

SNL/CA proposes the Collaboration in Research and Engineering for Advanced Technology and Education (CREATE) facility to support customer-driven national security mission requirements while demonstrating a fiscally responsible approach to cost-control. SNL/CA realizes that due to the current backlog of capital projects in NNSA that following the normal Line Item process to procure capital funding is unlikely and therefore SNL/CA will be looking at all options including Alternative Financing.

99 GENERAL AND MISCELLANEOUS↗

DOE OSTI2016

Electrochemical Hydrogen Compressor

Conventional compressors have not been able to meet DOE targets for hydrogen refueling stations. They suffer from high capital cost, poor reliability and pose a risk of fuel contamination from lubricant oils. This project has significantly advanced the development of solid state hydrogen compressor technology for multiple applications. The project has achieved all of its major objectives. It has demonstrated capability of Electrochemical Hydrogen Compression (EHC) technology to potentially meet the DOE targets for small compressors for refueling sites. It has quantified EHC cell performance and durability, including single stage hydrogen compression from near-atmospheric pressure to 12,800 psi and operation of EHC for more than 22,000 hours. Capital cost of EHC was reduced by 60%, enabling a path to meeting the DOE cost targets for hydrogen compression, storage and delivery ($2.00-2.15/gge by 2020).

08 HYDROGEN↗

DOE OSTI2015

Process Improvements to Biomass Pretreatment of Fuels and Chemicals

MBI, a 501c(3) company focusing on de-risking and scaling up bio-based technologies, has teamed with Michigan State University and the Idaho National Laboratory to develop and demonstrate process improvements to the ammonia fiber expansion (AFEX) pretreatment process. The logistical hurdles of biomass handling are well known, and the regional depot concept - in which small, distributed bioprocessing operations collect, preprocess, and densify biomass before shipping to a centralized refinery - is a promising alternative to centralized collection. AFEXTM (AFEX is a trademark of MBI) has unique features among pretreatments that would make it desirable as a pretreatment prior to densification at the depot scale. MBI has developed a novel design, using a packed bed reactor for the AFEX process that can be scaled down economically to the depot scale at a lower capital cost as compared to the traditional design (Pandia type reactor). Thus, the purpose of this project was to develop, scale-up, demonstrate, and improve this novel design The key challenges are the recovery of ammonia, consistent and complete pretreatment performance, and the overall throughput of the reactor. In this project an engineering scale packed bed AFEX system with 1-ton per day capacity was installed at MBI’s building. The system has been operational since mid-2013. During that time, MBI has demonstrated the robustness, reliability, and consistency of the process. To date, nearly 500 runs have been performed in the reactors. There have been no incidences of plugging (i.e., inability to remove ammonia from biomass after the treatment), nor has there been any instance of a major ammonia release into the atmosphere. Likewise, the sugar released via enzyme hydrolysis has remained consistent throughout these runs. Our economic model shows a 46% reduction in AFEX capital cost at the 100 ton/day scale compared to the traditional design of AFEX (Pandia type reactor). The key performance factors were demonstrated; >94% ammonia recovery, >75% sugar yields at high solid loading, and complete utilization of the sugars for ethanol production at the 2500 liter scale. Fermentation tests were performed using Zymomonas mobilis 8b and densified AFEX-treated corn stover at >20% solid loading. The obtained titer (~60g/l), productivity (2.5 g/L-h), and yield (330 L/tonne of biomass) exceeded the performance targets set out by NREL. The key findings from these efforts are: no contamination was observed, no cleanup of the sugar stream was required, and no major nutrient addition was required. Our economic model shows that using a packed bed design for the AFEX process and pelleted AFEX-treated biomass reduces the ethanol production cost by 24% when compared to using the traditional AFEX design.

09 BIOMASS FUELS↗

DOE OSTI2015

Utilization of UV Curing Technology to Significantly Reduce the Manufacturing Cost of LIB Electrodes

Previously identified novel binders and associated UV curing technology have been shown to reduce the time required to apply and finish electrode coatings from tens of minutes to less than one second. This revolutionary approach can result in dramatic increases in process speeds, significantly reduced capital (a factor of 10 to 20) and operating costs, reduced energy requirements, and reduced environmental concerns and costs due to the virtual elimination of harmful volatile organic solvents and associated solvent dryers and recovery systems. The accumulated advantages of higher speed, lower capital and operating costs, reduced footprint, lack of VOC recovery, and reduced energy cost is a reduction of 90% in the manufacturing cost of cathodes. When commercialized, the resulting cost reduction in Lithium batteries will allow storage device manufacturers to expand their sales in the market and thereby accrue the energy savings of broader utilization of HEVs, PHEVs and EVs in the U.S., and a broad technology export market is also envisioned.

14 SOLAR ENERGY↗

DOE OSTI2013

Concept Design for a High Temperature Helium Brayton Cycle with Interstage Heating and Cooling

The primary metric for the viability of these next generation nuclear power plants will be the cost of generated electricity. One important component in achieving these objectives is the development of power conversion technologies that maximize the electrical power output of these advanced reactors for a given thermal power. More efficient power conversion systems can directly reduce the cost of nuclear generated electricity and therefore advanced power conversion cycle research is an important area of investigation for the Generation IV Program. Brayton cycles using inert or other gas working fluids, have the potential to take advantage of the higher outlet temperature range of Generation IV systems and allow substantial increases in nuclear power conversion efficiency, and potentially reductions in power conversion system capital costs compared to the steam Rankine cycle used in current light water reactors. For the Very High Temperature Reactor (VHTR), Helium Brayton cycles which can operate in the 900 to 950 C range have been the focus of power conversion research. Previous Generation IV studies examined several options for He Brayton cycles that could increase efficiency with acceptable capital cost implications. At these high outlet temperatures, Interstage Heating and Cooling (IHC) was shown to provide significant efficiency improvement (a few to 12%) but required increased system complexity and therefore had potential for increased costs. These scoping studies identified the potential for increased efficiency, but a more detailed analysis of the turbomachinery and heat exchanger sizes and costs was needed to determine whether this approach could be cost effective. The purpose of this study is to examine the turbomachinery and heat exchanger implications of interstage heating and cooling configurations. In general, this analysis illustrates that these engineering considerations introduce new constraints to the design of IHC systems that may require different power conversion configurations to take advantage of the possible efficiency improvement. Very high efficiency gains can be achieved with the IHC approach, but this can require large low pressure turbomachinery or heat exchanger components, whose cost may mitigate the efficiency gain. One stage of interstage cooling is almost always cost effective, but careful optimization of system characteristics is needed for more complex configurations. This report summarizes the primary factors that must be considered in evaluating this approach to more efficient cycles, and the results of the engineering analysis performed to explore these options for Generation IV high temperature reactors.

30 DIRECT ENERGY CONVERSION↗

DOE OSTI2014

Development of a Microchannel High Temperature Recuperator for Fuel Cell Systems

This report summarizes the progress made in development of microchannel recuperators for high temperature fuel cell/turbine hybrid systems for generation of clean power at very high efficiencies. Both Solid Oxide Fuel Cell/Turbine (SOFC/T) and Direct FuelCell/Turbine (DFC/T) systems employ an indirectly heated Turbine Generator to supplement fuel cell generated power. The concept extends the high efficiency of the fuel cell by utilizing the fuel cell’s byproduct heat in a Brayton cycle. Features of the SOFC/T and DFC/T systems include: electrical efficiencies of up to 65% on natural gas, minimal emissions, reduced carbon dioxide release to the environment, simplicity in design, and potential cost competitiveness with existing combined cycle power plants. Project work consisted of candidate material selection from FuelCell Energy (FCE) and Pacific Northwest National Laboratory (PNNL) institutional databases as well as from industrial and academic literature. Candidate materials were then downselected and actual samples were tested under representative environmental conditions resulting in further downselection. A microchannel thermal-mechanical model was developed to calculate overall device cost to be later used in developing a final Tier 1 material candidate list. Specifications and operating conditions were developed for both SOFC/T and DFC/T systems. This development included system conceptualization and progression to process flow diagrams (PFD’s) including all major equipment. Material and energy balances were then developed for the two types of systems which were then used for extensive sensitivity studies that used high temperature recuperator (HTR) design parameters (e.g., operating temperature) as inputs and calculated overall system parameters (e.g., system efficiency). The results of the sensitivity studies determined the final HTR design temperatures, pressure drops, and gas compositions. The results also established operating conditions and specifications for all equipment in the SOFC/T and DFC/T systems. Capital cost and Cost of Electricity (COE) sensitivity analyses have been completed for MW-scale SOFC/T and DFC/T systems. Environmental testing consisted of 1000-hour and 2000-hour dry air oxidation testing on leading candidate materials, used to rank order and, in part, develop a final Tier 1 material candidate list. A thermal-mechanical model was subsequently used to provide material and manufacturing cost estimations for microchannel HTR’s to further refine the Tier 1 candidates. A capital cost and 20-year levelized cost of electricity (COE) was developed for a MW-scale version of the SOFC/T system concept as well as for a MW-scale version of the DFC/T system concept. Test frameworks were established for subsequent long-term materials stability testing, including oxidation resistance and mechanical strength. Mechanical strength testing was then carried out by a third-party test laboratory. Technology demonstration vehicles (TDV’s) were designed and fabricated. Several iterations of TDV’s were fabricated, each improved over the previous build as far as fabrication techniques. Two of three fabricated TDV’s were integrated with the TDV Test Facility for hot-testing at simulated operating conditions. The second of these two was successfully hot-tested for over 1000 hours at simulated temperature and pressure. Post-test leakdown assessment showed negligible leakage at benchtop conditions of 30 psig, a considerable improvement over the previous TDV’s.

30 DIRECT ENERGY CONVERSION↗

DOE OSTI2016

California Power-to-Gas and Power-to-Hydrogen Near-Term Business Case Evaluation

Flexible operation of electrolysis systems represents an opportunity to reduce the cost of hydrogen for a variety of end-uses while also supporting grid operations and thereby enabling greater renewable penetration. California is an ideal location to realize that value on account of growing renewable capacity and markets for hydrogen as a fuel cell electric vehicle (FCEV) fuel, refineries, and other end-uses. Shifting the production of hydrogen to avoid high cost electricity and participation in utility and system operator markets along with installing renewable generation to avoid utility charges and increase revenue from the Low Carbon Fuel Standard (LCFS) program can result in around $2.5/kg (21%) reduction in the production and delivery cost of hydrogen from electrolysis. This reduction can be achieved without impacting the consumers of hydrogen. Additionally, future strategies for reducing hydrogen cost were explored and include lower cost of capital, participation in the Renewable Fuel Standard program, capital cost reduction, and increased LCFS value. Each must be achieved independently and could each contribute to further reductions. Using the assumptions in this study found a 29% reduction in cost if all future strategies are realized. Flexible hydrogen production can simultaneously improve the performance and decarbonize multiple energy sectors. The lessons learned from this study should be used to understand near-term cost drivers and to support longer-term research activities to further improve cost effectiveness of grid integrated electrolysis systems.

33 ADVANCED PROPULSION SYSTEMS↗

DOE OSTI2013

Market and Policy Barriers to Energy Storage Deployment

Electric energy storage technologies can provide numerous grid services; there are a number of factors that restrict their current deployment. The most significant barrier to deployment is high capital costs, though several recent deployments indicate that capital costs are decreasing and energy storage may be the preferred economic alternative in certain situations. However, a number of other market and regulatory barriers persist, limiting further deployment. These barriers can be categorized into regulatory barriers, market (economic) barriers, utility and developer business model barriers, cross-cutting barriers and technology barriers.

25 ENERGY STORAGE↗

DOE OSTI2017

Final Techno-Economic Analysis of 550 MWe Supercritical PC Power Plant CO 2 Capture with Linde-BASF Advanced PCC Technology

This topical report presents the techno-economic evaluation of a 550 MWe supercritical pulverized coal (PC) power plant utilizing Illinois No. 6 coal as fuel, integrated with 1) a previously presented (for a subcritical PC plant) Linde-BASF post-combustion CO 2 capture (PCC) plant incorporating BASF’s OASE® blue aqueous amine-based solvent (LB1) [Ref. 6] and 2) a new Linde-BASF PCC plant incorporating the same BASF OASE® blue solvent that features an advanced stripper interstage heater design (SIH) to optimize heat recovery in the PCC process. The process simulation and modeling for this report is performed using Aspen Plus V8.8. Technical information from the PCC plant is determined using BASF’s proprietary thermodynamic and process simulation models. The simulations developed and resulting cost estimates are first validated by reproducing the results of DOE/NETL Case 12 representing a 550 MWe supercritical PC-fired power plant with PCC incorporating a monoethanolamine (MEA) solvent as used in the DOE/NETL Case 12 reference [Ref. 2]. The results of the techno-economic assessment are shown comparing two specific options utilizing the BASF OASE® blue solvent technology (LB1 and SIH) to the DOE/NETL Case 12 reference. The results are shown comparing the energy demand for PCC, the incremental fuel requirement, and the net higher heating value (HHV) efficiency of the PC power plant integrated with the PCC plant. A comparison of the capital costs for each PCC plant configuration corresponding to a net 550 MWe power generation is also presented. Lastly, a cost of electricity (COE) and cost of CO 2 captured assessment is shown illustrating the substantial cost reductions achieved with the Linde-BASF PCC plant utilizing the advanced SIH configuration in combination with BASF’s OASE® blue solvent technology as compared to the DOE/NETL Case 12 reference. The key factors contributing to the reduction of COE and the cost of CO 2 captured, along with quantification of the magnitude of the reductions achieved by each of these factors, are also discussed. Additionally, a high-level techno-economic analysis of one more highly advanced Linde-BASF PCC configuration case (LB1-CREB) is also presented to demonstrate the significant impact of innovative PCC plant process design improvements on further reducing COE and cost of CO 2 captured for overall plant cost and performance comparison purposes. Overall, the net efficiency of the integrated 550 MWe supercritical PC power plant with CO 2 capture is increased from 28.4% with the DOE/NETL Case 12 reference to 30.9% with the Linde-BASF PCC plant previously presented utilizing the BASF OASE® blue solvent [Ref. 6], and is further increased to 31.4% using Linde-BASF PCC plant with BASF OASE® blue solvent and an advanced SIH configuration. The Linde-BASF PCC plant incorporating the BASF OASE® blue solvent also results in significantly lower overall capital costs, thereby reducing the COE and cost of CO 2 captured from $147.25/MWh and $56.49/MT CO 2 , respectively, for the reference DOE/NETL Case 12 plant, to $128.49/MWh and $41.85/MT CO 2 for process case LB1, respectively, and $126.65/MWh and $40.66/MT CO 2 for process case SIH, respectively. With additional innovative Linde-BASF PCC process configuration improvements, the COE and cost of CO2 captured can be further reduced to $125.51/MWh and $39.90/MT CO 2 for LB1-CREB. Most notably, the Linde-BASF process options presented here have already demonstrated the potential to lower the cost of CO2 captured below the DOE target of $40/MT CO 2 at the 550 MWe scale for second generation PCC technologies.

20 FOSSIL-FUELED POWER PLANTS↗

DOE OSTI2016

Characterizing the Benefits of Seismic Isolation for Nuclear Structures: A Framework for Risk-Based Decision Making

This report provides a framework for assessing the benefits of seismic isolation and exercises the framework on a Generic Department of Energy Nuclear Facility (GDNF). These benefits are (1) reduction in the risk of unacceptable seismic performance and a dramatic reduction in the probability of unacceptable performance at beyond-design basis shaking, and (2) a reduction in capital cost at sites with moderate to high seismic hazard. The framework includes probabilistic risk assessment and estimates of overnight capital cost for the GDNF.

42 ENGINEERING↗

DOE OSTI2016

Final Report: Hydrogen Production Pathways Cost Analysis (2013 – 2016)

This report summarizes work conducted under a three year Department of Energy (DOE) funded project to Strategic Analysis, Inc. (SA) to analyze multiple hydrogen (H 2 ) production technologies and project their corresponding levelized production cost of H 2 . The analysis was conducted using the H2A Hydrogen Analysis Tool developed by the DOE and National Renewable Energy Laboratory (NREL). The project was led by SA but conducted in close collaboration with the NREL and Argonne National Laboratory (ANL). In-depth techno-economic analysis (TEA) of five different H 2 production methods was conducted. These TEAs developed projections for capital costs, fuel/feedstock usage, energy usage, indirect capital costs, land usage, labor requirements, and other parameters, for each H 2 production pathway, and use the resulting cost and system parameters as inputs into the H2A discounted cash flow model to project the production cost of H 2 ($/kgH 2 ). Five technologies were analyzed as part of the project and are summarized in this report: Proton Exchange Membrane technology (PEM), High temperature solid oxide electrolysis cell technology (SOEC), Dark fermentation of biomass for H 2 production, H 2 production via Monolithic Piston-Type Reactors with rapid swing reforming and regeneration reactions, and Reformer-Electrolyzer-Purifier (REP) technology developed by Fuel Cell Energy, Inc. (FCE).

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