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At least 919 records · Page 51
All sourcesNASA NTRSDOE OSTI
DOE OSTI2016

A New Empirical Correlation for Condensation Heat Transfer Coefficient of Air-Steam Mixture on a Vertical Tube

The Passive Containment Cooling System (PCCS) provides passive means to remove the decay heat and protect the integrity of the containment during severe accidents. For thermal design and performance evaluation of the PCCS condensers, one needs experimental data and a heat transfer model for condensation heat transfer in the presence of a noncondensable gas on a vertical tube. The main objective of this study is to propose a new empirical correlation, based on the experimental data obtained in Jeju National University, expressed in terms of dimensionless numbers. Dimensionless numbers to account for vapor-gas condensation phenomena are found by non-dimensionalizing the governing boundary layer equations, and the predictions of the proposed correlation is validated with selected sets of experimental data. (authors)

22 GENERAL STUDIES OF NUCLEAR REACTORS↗
DOE OSTI2024

Water separator for hydrogen steam injected turbine engine

A propulsion system for an aircraft includes a core engine that includes a core flow path where air is compressed in a compressor section, communicated to a combustor section, mixed with a hydrogen based fuel and ignited to generate a core gas flow that is expanded through a turbine section. The propulsion system includes a hydrogen fuel system that is configured to supply hydrogen fuel to the combustor through a fuel flow path, a condenser that is arranged along the core flow path and configured to condense water within the core gas flow, and a separator that includes an inlet, a primary water outlet and an exit that includes a plurality of exit guide vanes for straightening the core gas flow that proceeds through the exit. The exit guide vanes include a secondary water outlet for removing condensed water in the core gas flow that proceeds through the exit.

Terwilliger, Neil J.↗
DOE OSTI2018

An Integrated Supercritical System for Efficient Produced Water Treatment and Power Generation

The main goal of this project was to evaluate the feasibility of an integrated supercritical (SC) water desalination and power generation system for treatment of produced waters from CO 2 sequestration, oil production, and coal-bed methane recovery. This system may offer a transformative approach to generating power from coal or natural gas (NG) and purifying saline water or produced water with high total dissolved solids (TDS) in a zero-liquid discharge plant. The closed-loop steam cycle of conventional power plants was replaced with an open-loop steam cycle that heated the pretreated produced water above the SC point of water (374 °C and 221 bar) to precipitate and separate the salts dissolved in the water. After separation of the precipitated salt, the SC steam required further treatment to reduce the salt content from ~100 mg/L (ppm) to <1 ppm to make it suitable for use in turbines for power generation. A SC membrane distillation unit was used to polish the SC steam, which could be sent through a series of turbines for power generation, and the steam exiting the low-pressure turbine could be condensed by cooling water to produce pure water. Project tasks included a process simulation and a techno-economic evaluation of the integrated system; design and assembly of SC salt precipitation and membrane distillation systems; development and characterization of advanced carbon membranes for SC membrane distillation; and pretreatment, desalination, and purification of different produced water samples with salt concentrations of 30,000–200,000 ppm to a high-purity (<1 ppm) level. Process simulations were performed for 550 MW SC coal-fired or NG baseline cases and various scenarios for the proposed integrated SC system using produced water as the water source and coal or NG as the fuel source. Simulation results indicated that the net plant efficiency loss of the proposed SC cogeneration process would be in the range of <1% to ~4%, in which NG and lower TDS produced water cases would have higher efficiencies. The proposed process for coal-fired cases could provide all water needs for the power generation process and generate additional pure water for beneficial use. A techno-economic analysis was performed to estimate the cost of produced water treatment (dollars /kgal of treated water) by conventional treatment processes compared with the proposed cogeneration process. The cost estimation for the proposed cogeneration system included the cost of pretreatment, the cost of power loss to integrate the water desalination process into the power generation system, and the cost of plant modification or retrofitting. The cost of produced water treatment was calculated by assuming three different scenarios in which converting a baseline power plant to the proposed cogeneration plant would increase the cost of the boiler and feed water system by 10%, 50%, and 100%. Results indicated that the cost of produced water treatment, even with a 100% cost increase, was in the range of $8.6–11.6 dollars per kgal, which is about half of the treatment cost by conventional methods. The cost of produced water treatment by the proposed cogeneration system could be further reduced or a considerable income could be generated if the values of saltwater and freshwater products are considered. Overall, the techno-economic analysis results indicated that the proposed integrated SC system could potentially treat produced water at a cost significantly lower than the cost of produced water treatment by conventional technologies. To evaluate the feasibility of the proposed treatment system at a laboratory scale, a SC salt precipitation and membrane distillation system was designed and fabricated to treat a simulated brine or pretreated produced water by precipitating salts and further polishing the SC steam containing ~100 ppm salts to a high-purity steam. Through baseline tests with NaCl solutions, with concentrations ranging from 30,000 to 200,000 ppm, it was demonstrated that concentrated feed solutions could be treated by precipitating salt at SC conditions to a TDS level of 130 ppm. Produced water samples were collected from a potential CO 2 sequestration site, a coal-bed methane site, and an oilfield in Illinois. Representative samples were characterized for various water quality parameters, including pH; turbidity; conductivity; and concentrations of selected anions, cations, alkalinity, dissolved organic carbon, total suspended solids, TDS, and total petroleum hydrocarbons. The produced water samples were first treated by conventional pretreatment methods to remove residual oil, dissolved organic matter, and scale-forming species. Pretreatment methods included coagulation, sedimentation, filtration, activated carbon adsorption, and ion-exchange adsorption. Pretreated produced waters were treated at SC conditions in which salts were precipitated. Analysis of treated samples revealed that the concentration of Na (the main cation) in produced waters was reduced dramatically from 14,000–47,400 ppm in the feed to 21–80 ppm in treated waters. Concentrations of other main cations (Ca, Mg, Sr, K) also decreased significantly from initial values of ~1,000–22,000 ppm to ~1 ppm or less. However, a significant increase in the concentrations of Fe, Ni, Cu, and Co was observed, mainly caused by leaching of these elements from the system (vessels, filters, tubing), which is manufactured from alloys containing Fe, Ni, Cu, and Co. To polish the SC steam containing a salt content of ~100 ppm to a high-purity level of <1 ppm, a SC membrane distillation treatment using carbon membranes was employed. Different types of self-standing or supported carbon membranes were developed from graphite, graphene, carbon nanotubes, carbon nanofibers, and pyrolytic carbon. Screening tests revealed that only a limited number of developed carbon membranes were suitable for the purification of steam at SC conditions. Membranes that were either fragile and lacked mechanical strength or had large pores and showed limited salt rejection (<20%) were found to be unsuitable for the purification of SC steam. Promising carbon membranes that were successfully tested for purifying SC steam included two graphite membranes (i.e., AF-5, a porous graphite material, and FGS, a flexible graphite sheet) and a carbon nanotube membrane grown on a Hastelloy substrate and then further modified using a proprietary method (i.e., membrane C). The AF-5 membrane exhibited a stable water flux of ~50 kg/m 2 ∙h and ~40% salt rejection. The FGS membrane had a high salt rejection of 95%–98% but a lower water flux of ~15 kg/m 2 ∙h. Membrane C showed an extremely high flux of 200-800 kg/m 2 ∙h, which is one order of magnitude higher than the water flux of conventional membranes. Membrane C also exhibited 87%–93% salt rejection. Overall, a two-stage or multistage polishing treatment by these membranes could lower the salt content of the SC steam from initial values of ~100–200 ppm to the steam quality of <1 ppm or to parts per billion levels required for the power cycle.

20 FOSSIL-FUELED POWER PLANTS↗
DOE OSTI2016

Packed Bed thermal storage for compact Light water-cooled Small Modular Reactors

Nuclear power plants (NPPs) have less flexibility to follow grid load demand than their natural-gas fueled counterparts. Most of the natural-gas power plants can supply peak-loads by adding more fuel, and thus, can generate far more revenue during those peak hours. On the other hand, use of NPPs for peak load following is quite complex due to technical constraints associated with reactor behavior. These technical challenges include the adequate handling of reactivity swings caused by time-varying fuel and moderator temperatures, a higher fuel-failure probability due to thermal-structural cycling, and spatial variations in xenon concentration. Although there are presently some reactors around the world that are operating with flexible load-following capabilities, such operation is restricted to slowly-varying powers, 2-3 times a day, and only up to 80% of the fuel cycle. Thus, a more convenient and effective method to facilitate load following by NPPs would be to integrate energy storage Authors have previously developed models and performed exergy analysis for integrating liquid type TES with LWRs and SMRs. These exergy based models show that technical feasibility index of integrating thermal energy storage is very high. But most of these previous studies include integration based on existing layout of NPPs with heat exchange between storage Heat Transfer Fluid (HTF) and Reactor Coolant (RC). However, most of the Light Water-cooled Small modular reactor (LW-SMR) based NPP designs can not accommodate additional heat exchange equipment. Although power production is only reduced to 1/20 scale, the containment volume in thus NuScale LW-SMR is reduced to {approx} 1/170 scale. As steam is the secondary or working fluid which exits out of the reactor containment in LW-SMRs, the simplest and most practical way to integrate thermal storage with LW-SMRs is to directly store the energy from steam. Indirect heat exchange between steam and another heat transfer fluid during the storage process, and then heat recovery again via indirect heat exchange is inefficient process due to heat transfer resistance. This inefficiency is due to what is called as 'Pinch point' which occurs whenever there is indirect heat transfer between two media where one undergoes phase change and other undergoes change in sensible heat. Another existing popular option is to use a steam accumulator which stores dry or wet steam directly inside the pressure vessels, however, due to large volumetric requirements it is not a viable option. This work proposes a new method of integrating packed bed TES systems with LW-SMRs, where steam produced in the secondary side of LW-SMRs can be injected into the packed bed of inert particles with sufficient thermal conductivity and capacity to efficiently store energy with high energy density. The changes in the load demand will not effect the LWSMR operation and the excess steam will be diverted to TES. When the demand increases this stored energy in hot packed beds can be recovered by injecting cold pressurized water. Although there are some existing packed bed TES designs and models which consider steam as HTFs, these models have not been extended for wide range of process parameters important for this integration. Authors have previously developed a packed bed thermal model for steam injection and validated it using experimental data. This thermal model is extended to assess behavior of packed bed thermal energy storage (TES) system under storage and recovery cycles. Steam is the only heat transfer fluid (HTF) which exits the reactor vessel, so any application such as process heat or TES integration should be evaluated with steam as process fluid. This project will develop a process system integration model of LW-SMR with packed bed type TES using steam as HTF. (authors)

21 SPECIFIC NUCLEAR REACTORS AND ASSOCIATED PLANTS↗
DOE OSTI2016

All Nuclear Hybrid Superheater Design Method

The 'All Nuclear Hybrid' (ANH) concept combines Light Water (LWR) and Generation IV (Gen IV) reactor technologies to produce superheated steam. LWR technology characteristically produces steam temperatures of ∼300 C. Process steam demands such as refineries and hydrogen production can require steam temperatures that exceed 600 C. Therefore, an additional heat source must be added to provide the heat to increase or 'boost' the temperature of the steam generated from by the LWR. A recent study demonstrated that application of the ANH concept to a refinery optimized the use of nuclear technologies and maximized carbon dioxide emission reductions. The objective of the present work is to size the heat exchangers (Superheaters) required to apply the ANH concept to a Westinghouse AP1000 LWR to produce 675 C superheated steam. Two GenIV reactor concepts are considered to provide the additional heat source and high primary coolant temperatures required to produce the superheated steam: a High temperature Gas Reactor (HTGR) using helium as primary coolant, and a Molten Salt reactor. The details of the GenIV reactor designs are not the focus of this study; however, the primary coolant thermal conditions from these concepts are utilized directly in the superheater sizing calculations. Also, a tube and shell superheater design is assumed for the superheater due to its extensive use in the nuclear and other industries. The ANH concept generates superheated steam by first utilizing LWR technology to accomplish the phase change from liquid water to steam within the steam generator. This is a well-established technology with several decades of successful safe operation. Next, the concept utilizes GenIV reactor technology to superheat the steam. Since both the working fluids in the superheater are single phase, the heat transfer and pressure drop calculations required to size the superheater can be performed without complex two-phase computer analyses (i.e., RELAP5). This study presents an approach for the sizing the ANH superheater using an iterative LMTD heat exchanger design method. (authors)

21 SPECIFIC NUCLEAR REACTORS AND ASSOCIATED PLANTS↗
DOE OSTI2023

Preconceptual Designs of Coupled Power Delivery between a 4-Loop PWR and 100-500 MWe HTSE Plants

This study develops a preconceptual design for the integration between a large-scale high-temperature electrolysis facility and a NPP. Two hydrogen facility sizes are considered: 100 MWnom and 500 MWnom. Both steam supply designs use cold reheat steam extraction as a heat source. A reboiler inside the protected area of the power plant transfers steam heat to the demineralized water supply for the hydrogen plant. After the heat transfer, the extracted steam condenses and returns to the condenser while the process steam routes out of the protected area to the electrolyzers. Electrical power is tapped off from the high voltage side of the GSU transformer, where it is then transported via a 345-kV transmission line to the hydrogen facility. Circuit breakers and disconnects are located at both ends of the transmission line. Step down transformers and miscellaneous switchgear/buses are located at the end of the transmission line inside the HTEF boundary. Control capabilities for the steam interfacing equipment and electrical dispatch are accessible from the Main Control Room, and protective relays for the transmission line are located inside the Relay Room. Computer modeling was performed for the thermal and electrical designs. PEPSE analysis provided the steady-state parameters for thermal extraction from the turbine cycle. These parameters were used to inform transients and size equipment in combination with Applied Flow Technology (AFT) Arrow and AFT Fathom modeling for steam and water piping, respectively. Electrical transients were analyzed using PSCAD. An ETAP model was used to evaluate power flow and short circuit, which enabled the sizing of transformers and protective equipment. A cost estimate was developed for both integration designs when considering plant separation distances of 250 m and 500 m. From these estimates, the modifications for thermal and electrical interfacing of a first-of-a-kind nuclear-integrated hydrogen facility are anticipated to cost between $60–250/kWnom., where the subscript “nom” refers to the nominal size of the hydrogen plant. On a thermal power basis, the thermal power has a cost of approximately $8/MWth for a 500 MWnom high temperature electrolysis plant located 500 m distant from the NPP. That value decreases to approximately $7.5/MWth for a 250 m separation distance between the hydrogen plant and the NPP. This value is lower than previous estimates of the cost of heat extracted from NPPs primarily because in this work the steam is extracted from cold reheat instead of the main steam line, which reduces the cost of the dispatched steam by approximately $3.5/MWth. Nuclear steam extraction can provide a profit avenue for many plants and is not restricted to hydrogen production. Ammonia production, oil refining, and paper production, among other industrial processes all require thermal energy, which can be provided by NPPs. Future work should look further at the details of thermal extraction for a variety of use cases. This can include increased levels of extraction and multiple simultaneous users. Additionally, site-specific studies should be performed to develop industry experience and improve cost accuracy.

08 HYDROGEN↗
DOE OSTI2017

TRACE Analysis of Loss of Flow for the APR1400

The APR1400 is a pressurized water reactor (PWR). The APR1400 nuclear steam supply system consists of a reactor pressure vessel (RPV), which contains the reactor core, and two primary reactor coolant system loops connected in parallel to the RPV. Each coolant loop consists of a hot leg (HL), a u-tube steam generator (SG), two reactor coolant pumps (RCPs) and two cold legs (CLs). A pressurizer is connected to the hot leg on one of the coolant loops. During normal operation, the RCPs circulate high pressure water through the reactor core to remove the heat. The heated water exits the RPV and passes through the hot legs into the steam generator tubes. Heat is transferred through the walls of the steam generator tubes into a lower pressure secondary coolant system. Cooled primary system water from the steam generators is returned through the RCPs and cold legs to the RPV. The RCPs operate at constant speed; the primary coolant system is designed to provide a prescribed rate of coolant flow through the reactor core. The APR1400 SG secondary coolant system pressure is controlled through modulation of valves in the steam lines to maintain a prescribed turbine inlet pressure. The SG secondary coolant inventory is controlled by using a feedwater control system to maintain a prescribed liquid level in the steam generator downcomer. This water inventory level is sufficient to cover the outer surfaces of the steam generator tubes while preventing overfill that would cause liquid to pass from the steam generators through the steam lines into the turbine system. In the current work, the Nuclear Regulatory Commission's reactor systems analysis code, TRACE?2 was used to perform an analysis of a loss of flow anticipated operational occurrence (AOO). The loss of flow is initiated by a loss of off-site power (LOOP), resulting in a trip of the RCPs. The regulatory purpose of the current work is to confirm safety analyses documented in the APR1400 Design Control Document (DCD)

21 SPECIFIC NUCLEAR REACTORS AND ASSOCIATED PLANTS↗
NASA NTRS1976

Comparison of geothermal power conversion cycles

Geothermal power conversion cycles are compared with respect to recovery of the available wellhead power. The cycles compared are flash steam, in which steam turbines are driven by steam separated from one or more flash stages; binary, in which heat is transferred from the brine to an organic turbine cycle; flash binary, in which heat is transferred from flashed steam to an organic turbine cycle; and dual steam, in which two-phase expanders are driven by the flashing steam-brine mixture and steam turbines by the separated steam. Expander efficiencies assumed are 0.7 for steam turbines, 0.8 for organic turbines, and 0.6 for two-phase expanders. The fraction of available wellhead power delivered by each cycle is found to be about the same at all brine temperatures: 0.65 with one stage and 0.7 with four stages for dual stream; 0.4 with one stage and 0.6 with four stages for flash steam; 0.5 for binary; and 0.3 with one stage and 0.5 with four stages for flash binary.

Elliott, D. G.↗
DOE OSTI2016

Thermostatic Radiator Valve Evaluation and Demonstration

A large stock of multifamily buildings in the Northeast and Midwest uses hot water or steam for space heating. Typically, residents do not pay for heat directly (i.e., heating fuel serves a central plant and use is not submetered). Losses from these systems are typically high, and a significant number of apartments are overheated much of the time. This is often evidenced by open windows on winter days. Controls and distribution are often faulty, and improving them can be more cost effective than replacing boilers. Thermostatic radiator valves (TRVs), which have been in use for many decades, are one potential strategy to combat this problem. They are commonly used in Europe and in other markets such as commercial buildings, but have not been widely accepted by the residential retrofit market in the northeastern United States. Anecdotal evidence suggests that heating systems engineers and contractors have a variety of opinions about their effectiveness, illustrating a lack of consensus on this potentially important energy efficiency measure. A review of the limited available literature revealed that, in one study, heating fuel savings as high as 15% was achieved through TRV retrofits. In this project, the U.S. Department of Energy Building America team, Advanced Residential Integrated Energy Solutions, sought to better understand the current usage of TRVs by key market players in steam and hot water heating and to conduct limited experiments on the effectiveness of new and old TRVs as a means of controlling space temperatures and reducing heating fuel consumption. The project included a survey of industry professionals, a field experiment comparing old and new TRVs, and cost-benefit modeling analysis using BEopt (Building Energy Optimization software). Radiator and apartment space temperature data were collected and analyzed for two similar apartment units in a building that underwent a one-pipe steam TRV retrofit. Space temperature comparisons were made across the pre- and post-TRV installation heating periods and between rooms equipped with old or new TRVs in an attempt to show the comparative effectiveness of each vintage of TRV. Analyses of the heating fuel utility bills before and after the building-wide TRV installation were conducted to quantify potential savings. The results of the field experiment and utility bill analysis did not show energy savings at either the unit or the building-wide level. The results provided inconclusive answers to the original study questions but provided valuable insight into common steam system imbalance and resident behavior issues that are critical to address in conjunction with TRV retrofits. Specific issues identified included steam distribution imbalance, possible TRV sensor location issues, a persistent window-opening habit, and a failure to optimize the boiler control set points as part of the TRV retrofit. The lack of heating fuel savings underscored the need to include whole steam system commissioning alongside or as a prerequisite to TRVs. Failed air vents and uneven steam main venting are critical to address either in conjunction with or before a TRV installation. Monitoring existing space temperatures before a retrofit strategy is chosen would allow the consultant and building owner to better assess the potential benefits of a whole-building TRV retrofit, selective installation of TRVs in some units, or simply balancing the steam distribution venting. Further gaps in the understanding of underlying processes that allow TRVs to function effectively were also identified and are presented as opportunities for future research.

Array↗
DOE OSTI2012

Application of European Large Component Technology in the United States - 12561

The European nuclear community currently has safer, more environmentally-friendly disposal options for large component disposal than the United States. The technology and innovation that makes these options viable will soon be available stateside. The removal and replacement of steam generators is a large and complicated task making volume reduction a vital service for the nuclear power industry. As plants age, the replacement of certain components is required in order to maintain plant efficiency and public safety. Currently in the United States, there are 3 options for the disposal of these items including: on-site storage, direct-disposal at a licensed (low-level radioactive waste) LLWR site, and volume reduction prior to disposal. If today's nuclear plants are to be used by future generations, waste stored on-site will eventually have to be disposed of to make room for newer, more advanced technology. Also, the space at LLWR disposal sites is finite, so all waste sent for disposal should be minimized whenever possible. Reducing the volume of decommissioned steam generators prior to final disposal shows the public that the nuclear industry is doing everything that it can to minimize its waste and conserve the environment. Additionally, many steam generators are massive and are not easily transported to a disposal site. When there is no practical transportation route, the size and weight of the component must be reduced. For various reasons including public safety, cost, and technical expertise, size reduction cannot be practically performed at the site of generation. However, since most facilities have some kind of access to a waterway, the components can be safely transported to another facility with barge access for size reduction. The size reduction process for steam generators has evolved over the past 5 years. Because of reductions to the amount of final waste, the dose to personnel, and the processing time, it is now an environmentally and economically friendly alternative to on-site storage and direct disposal. The major operations of this process include: - removal of the carbon steel steam generator dome; - removal of the channel head and majority of tube sheet to free the tubes from the tube sheet and gain access to all of the tubes for grit blasting; - grit blast decontamination of the steam generator tubes to allow disassembly; - removal of the U-Bend Section of the tubes to allow for tube pulling - tube pulling operations; - disassembly of the remainder of the steam generator shell and tube support assemblies; - size reduction of the steam generator resultant materials. All of the equipment for the American market is based on previous designs but has been adapted to meet the size requirements for processing of larger steam generators. This includes a large horizontal band saw, a tube pulling machine, tube blasting equipment, and a diamond wire saw frame. (authors)

12 MANAGEMENT OF RADIOACTIVE AND NON-RADIOACTIVE W↗
DOE OSTI2023

Optimization of metal-supported solid oxide electrolysis cells with infiltrated catalysts

We report metal-supported solid oxide electrolysis cells (MS-SOECs) are being developed for steam-to-hydrogen electrolysis, especially for utilization of dynamic or intermittent electrical power from renewable sources. Various aspects of the electrocatalyst processing and composition, and metal support structure were explored. Catalyst materials, infiltration temperature and infiltration cycles were optimized for high performance and durability. Numerous catalyst materials were screened for both oxygen and steam electrodes. The oxygen catalyst had moderate impact on both initial cell performance and durability. Reducing Ni content in the steam electrode had little effect on durability, but reduced initial performance. Ex-situ XRD analysis and cell assessment of catalyst infiltration temperature revealed that the optimal range is 750–850 °C. The best cell performance and durability was achieved with LSCF-SDC oxygen electrocatalyst and SDC-Ni (60:40 vol%) steam electrocatalyst infiltrated 11 times at 800 °C and operated at 700 °C. At low steam content, a significant mass transport limitation on the steam side results in limiting current behavior. Thinner and more porous metal supports were implemented, and found to improve steam mass transport at low steam content, relevant for SOECs operating under high H 2 recycle rate or high steam utilization.

08 HYDROGEN↗
DOE OSTI2016

Synchrotron Characterization of the Oxidation of Advanced Steel Cladding Alloys

Advanced steel alloys are proposed as nuclear fuel claddings due to their high corrosion resistance under extreme conditions of pressure and temperature. APMT is an iron based alloy (Fe-22wt.%Cr-5.8wt.%Al) and Alloy 33 is a mixture of iron, chromium, and nickel (32wt.%Fe-33wt.%Cr-31wt.%Ni). This paper focuses on studying the corrosion mechanisms for these alloys under exposure to superheated steam at 800 deg. C and 1000 deg. C using the synchrotron based X-ray diffraction (XRD) and Hard X-ray photoelectron spectroscopy (HAXPES) techniques. HAXPES data was collected using 4 keV X-rays with a 1x1 mm spot size at X24A beamline. Specimens were mounted on the sample holder. The specimens were tilted 5 degrees relative to the beam and the estimated probe depth (for this fixed energy) is 63 A. The X-ray wavelength for XRD studies at X14A beamline is 0.7792 A with a beam size of of 2 x 0.2 mm{sup 2}. Specimens were exposed to steam environment at 800 and 1000 deg. C for 8, 24, and 48 hours. For Alloy 33; a layer of mixed Cr{sub 2}O{sub 3} and FeCr{sub 2}O{sub 4} oxides is formed after exposure to steam. Specimen tilting indicated that Cr{sub 2}O{sub 3} is formed near the metal/oxide interface and FeCr{sub 2}O{sub 4} was formed on the oxide surface. The oxide peak intensities increased with an increase in steam temperature. The specimen oxidized at 1000 deg. C had well-developed oxide peaks compared to the specimen oxidized at 800 deg. C. For APMT; a layer of mixed α-Al{sub 2}O{sub 3} and monoclinic θ-Al{sub 2}O{sub 3} oxides is formed on the outer surface. The peak intensities of the monoclinic θ-Al{sub 2}O{sub 3} phase, decreases relative to the peaks from the Al{sub 2}O{sub 3} phase with increasing tilt angle. This indicates that the surface is dominated by the θ-Al{sub 2}O{sub 3}. After exposure to steam at 800 deg. C, oxidation of Alloy 33 results in the formation of Cr{sub 2}O{sub 3} oxide with time and absence of both metallic and substoichiometric phases is observed. No nickel peaks are seen on the surface after oxidation at 800 deg. C, however Fe(II) peak is noticed after 8 and 24 hours of steam exposure, which then disappears after 48 hours. This presence of FeCr{sub 2}O{sub 4} oxide phase is observed after 8 and 24 hours. After exposure to steam at 1000 deg. C, the Cr{sub 2}p{sub 3/2} doublet persists at all exposure times, indicating the presence of the FeCr{sub 2}O{sub 4} oxide. Nickel peak is found on the surface at all exposure times and is attributed to the presence of Ni(OH){sub 2} phase. This may be due to increased diffusion of Ni through chromic oxide scale at higher temperature as compared to 800 deg. C. This nickel reacts with steam at 1000 deg. C to form Ni hydroxide at the surface. For APMT, after exposure to steam at 800 and 1000 deg. C, no Al and Cr metal peaks are seen. Growth of oxide layer is seen with increase in exposure time. The oxide structure contains mainly Al{sub 2}O{sub 3} oxide with the addition of mixed oxide (Al{sub x}Cr{sub 1-x}){sub 2}O{sub 3}. These results demonstrate that Cr diffuses into the alumina layer. (authors)

36 MATERIALS SCIENCE↗
DOE OSTI2017

Dual Rate Adaptive Control for an Industrial Heat Supply Process Using Signal Compensation Approach

The industrial heat supply process (HSP) is a highly nonlinear cascaded process which uses a steam valve opening as its control input, the steam flow-rate as its inner loop output and the supply water temperature as its outer loop output. The relationship between the heat exchange rate and the model parameters, such as steam density, entropy, and fouling correction factor and heat exchange efficiency are unknown and nonlinear. Moreover, these model parameters vary in line with steam pressure, ambient temperature and the residuals caused by the quality variations of the circulation water. When the steam pressure and the ambient temperature are of high values and are subjected to frequent external random disturbances, the supply water temperature and the steam flow-rate would interact with each other and fluctuate a lot. This is also true when the process exhibits unknown characteristic variations of the process dynamics caused by the unexpected changes of the heat exchange residuals. As a result, it is difficult to control the supply water temperature and the rates of changes of steam flow-rate well inside their targeted ranges. In this paper, a novel compensation signal based dual rate adaptive controller is developed by representing the unknown variations of dynamics as unmodeled dynamics. In the proposed controller design, such a compensation signal is constructed and added onto the control signal obtained from the linear deterministic model based feedback control design. Such a compensation signal aims at eliminating the unmodeled dynamics and the rate of changes of the currently sample unmodeled dynamics. A successful industrial application is carried out, where it has been shown that both the supply water temperature and the rate of the changes of the steam flow-rate can be controlled well inside their targeted ranges when the process is subjected to unknown variations of its dynamics.

Adaptive signal approacg↗
DOE OSTI2025

Advanced nuclear reactor integration opportunities for the pulp and paper industry in the U.S. context: Technical perspectives, gap analysis, and preliminary technoeconomic assessment

Pulp and paper (P&P) manufacturing requires a large amount of low-pressure (LP) steam to digest, wash wood fibers and dry pulp into paper. Most of the LP steam is extracted from backpressure turbines that produce power from high-pressure (HP) steam. This HP steam is generated from burning wood waste material; bark is burned in hog boilers, and lignin is boiled in a black liquor recovery boiler. In a typical integrated P&P mill, 50–100% of the steam is produced from these sources, while additional steam is produced in natural gas (NG), fuel oil, or coal boilers. The other energy-intensive process in the plant is the chemical-recovery section (e.g., lime kiln), which requires high-temperature processing from NG combustion to retrieve and recirculate spent chemicals. This paper assesses the energy and heat demand and material balances of a typical generic kraft pulp mill, along with the nuclear heat, steam, and power integration opportunities to replace conventional combustion systems. The paper also addresses steam and electricity generation through a comprehensive technical and engineering gap analysis of five different nuclear-integration opportunities and their process economics, thus enabling the lignin and bark to be further processed into biobased chemicals or fuels, as well as the potential to reduce overall emissions from kraft pulping. Preliminary findings have shown that the P&P industry could achieve technological benefits by integrating their current manufacturing process with small modular nuclear reactors (SMNRs) on a national level. This research aims to set the path forward for a cleaner and more resilient P&P industry.

Advanced nuclear reactor↗
DOE OSTI2019

Ettringite-Related Dimensional Stability of CO 2 -Cured Portland Cement Mortars

Carbonation curing, where cement is cured in a CO 2 -rich environment, is an emerging technology in the precast industry that promotes CO 2 sequestration in construction materials. It demonstrates good promise for enhancing material strength development, chemical resistance and manufacturing sustainability. A critically important but little studied aspect of carbonation curing is the dimensional stability of the cured materials, which poses a significant impact on longevity of cement-based materials and structures. In this study, we propose to use carbonation curing to substitute the conventional energy-intensive steam curing and time-consuming moisture curing, and examine the dimensional stability of Portland cement mortars manufactured by different curing approaches. The common pathology in precast concrete that potentially creates undesirable expansions, known as Delayed Ettringite Formation (DEF), is particularly investigated. Four curing approaches were examined including moist, steam (maximum temperature at 85°C to purposefully induce DEF), combined steam-carbonation, and carbonation curing in which steam curing was used to verify favorable cement chemistry for DEF and to indicate DEF onset timing. It was found that, among the four curing approaches designed in this study, the carbonation-cured mortars demonstrated the lowest expansion (~0%) whereas the steam-cured mortars showed the highest (>0.6%) after 500 days of storage in saturated limewater. Mortar expansion after the combined steam-carbonation curing (~0.1%) was lower than that of steam curing, but remained higher with respect to the moisture-cured reference. Here, the mineral ettringite was detected at 500 days after all curing approaches. However, larger ettringite crystal size (5-10 μm) with greater dispersion was observed via scanning electron microscopy after steam curing in reference to carbonation curing (< 5 μm). Additionally, the calcium carbonate precipitated by CO 2 carbonation was found to participate in the post-carbonation hydration to promote formation of monocarboaluminate and hemicarboaluminate, which stabilize ettringite and potentially lead to a secondary densification of the mortar microstructure.

37 INORGANIC, ORGANIC, PHYSICAL, AND ANALYTICAL CH↗
DOE OSTI2017

Pilot-Scale Silicone Process for Low-Cost Carbon Dioxide Capture. Final Scientific/Technical Report

GE Global Research has developed, over the last 8 years, a platform of cost effective CO 2 capture technologies based on a non-aqueous aminosilicone solvent (GAP-1m). As demonstrated in a previous funded DOE project (DE-FE0007502), the GAP-1m solvent has increased CO 2 working capacity, lower volatility and corrosivity than the benchmark aqueous amine technology. The current report describes the cooperative program between GE Global Research (GE GRC), and the National Carbon Capture Center (NCCC) to design, construct, and operate a pilot-scale process using GAP-1m solvent to demonstrate its performance at 0.5 MWe. (i) Performance of the GAP-1m solvent was demonstrated in a 0.5 MWe pilot with real flue gas for over 900 hrs. of operation using two alternative desorption designs: a Continuous Stirred Tank Reactor (CSTR), and a Steam Stripper Column (SSC). The CSTR is a one-stage separation unit with reduced space requirements, and capital cost. The alternative is a multi-stage separation column, with improved desorption efficiency. Testing the two desorber options allowed us to identify the most cost effective, and space efficient desorber solution. (ii) CSTR Campaign: The CSTR desorber unit was designed, fabricated and integrated with the pilot solvent test unit (PSTU), replacing the PSTU Steam Stripper Column at NCCC. Solvent management and waste water special procedures were implemented to accommodate operation of the non-aqueous solvent in the PSTU. Performance of the GAP-1m solvent with the CSTR was demonstrated for over 500 hrs. while varying temperature of the desorption (230 – 265 oF), solvent circulation rate (GAP-1m : CO 2 (molar) = 1.5 – 4), and flue gas flow rates (0.2 – 0.5 MWe). Solvent carry-over in the CO 2 product was minimized by maintaining water content below 5 wt.%, and desorption pressure at 7 psig. CO 2 capture efficiency achieved was 95% at 0.25 MWe (GAP-1m : CO 2 = 4 (molar), 230 oF desorption), and 65% at 0.5 MWe (GAP-1m : CO 2 (molar) = 1.5, 248 oF). Solvent loss was dominated by thermal degradation of the rich solvent. (iii) Steam Stripper Column Campaign: Higher expected cost of the solvent vs. aqueous amines makes solvent management a top priority to maintain the low cost for the process. During the testing of the GAP-1m solvent with the CSTR, thermal degradation of the rich solvent was found to be the main mechanism in solvent loss. Small amounts of water in the working solution were found to be an effective way to enable steam stripping, thereby lowering desorption temperature, and hence reducing thermal degradation. Steam stripping also increased working capacity by 30% due to a more efficient desorption. The concept was first tested in a glass stripping column (lab scale, GE GRC), optimized in a continuous bench scale system (2 kWe, GE GRC), and demonstrated in a 0.5 MWe PSTU at NCCC. No special system modifications were required to the PSTU to accommodate the testing of the non-aqueous GAP-1 solvent with the regenerator column. SSC was found to be more robust towards solvent entrainment (H 2 O < 35 wt.%). 90 – 95% CO 2 capture efficiency was achieved under stoichiometric conditions at 0.5 MWe (235 oF desorption, 2 psig and 19 wt. % H 2 O). Both CO 2 capture efficiency and specific duty reached optimum conditions at 18 wt.% H 2 O. Low amine degradation (< 0.05 wt.%/day) was recorded over 350 hrs. of operation. Controlled water addition to GAP-1m solvent decreased the desorption temperature, thermal degradation, and improved the CO 2 working capacity due to more efficient absorption and desorption processes. Under these conditions, the GAP-1m solvent exhibited a 25% increased working capacity, and 10% reduction in specific steam duty vs. MEA, at 10 oF lower desorption temperature. (iv) Techno-economic Analysis: The pilot-scale PSTU engineering data were used to update the capture system process models, and the techno-economic analysis was performed for a 550 MW coal fired power plant. The 1st year CO 2 removal cost for the aminosilicone-based carbon-capture process was evaluated at $48/ton CO 2 using the steam stripper column. This is a 20% reduction compared to MEA, primarily due to lower overall capital cost. CO 2 cost using the CSTR desorber is dominated by the economics of the solvent make-up. The steam stripper desorber is the preferred unit operation due to a more efficient desorption, and reduced solvent make-up rate. Further reduction in CO 2 capture cost is expected by lowering the manufacturing cost of the solvent, implementing flowsheet optimization and/or implementing the next generation aminosilicone solvent with improved stability and increased CO 2 working capacity.

0.5 MW Pilot↗
DOE OSTI2022

Liquid Salt Combined-Cycle Pilot Plant Design

The work described in this report is responsive to the Office of Fossil Energy program ‘Energy Storage for Fossil Power Generation.’ This Phase I report has been prepared by Pintail Power LLC, with support from Nexant ECA, Electric Power Research Institute (EPRI) and Southern Company Services as a deliverable for the U.S. Department of Energy for NETL Award DE-FE-00320016. The Liquid Salt Combined Cycle™ (LSCC™) technology provides large-scale energy storage integrated with Fossil Electric Generating Units (FEGUs) to meet critical needs in the energy transition by providing: • the lowest cost large-scale storage for time-shifting of renewable energy, • superior fuel efficiency to reduce GHGs from dispatchable resources, • flexible capacity and ramping to balance variability of wind and solar resources, • essential grid stability services to assure reliability of a low-carbon grid. The LSCC approach: • employs equipment that has already been proven in utility service, • uses safe, non-toxic, non-degrading, perpetual-life storage medium, • leverages and repurposes existing FEGU assets, • expands the value stack of energy storage to reduce market, financing, and commodity risks. Pintail Power has developed the LSCC technology to meet the need for reliable, efficient, and cost-effective integration of Variable Renewable Energy (VRE) into a low-carbon electric grid by coupling proven thermal energy storage with proven gas turbines, steam turbines, and heat transfer equipment. This novel approach is intended to address the key issues facing the grid and operators of renewable and fossil generating units including: • Overgeneration and curtailment of renewables, • Need for fast ramping dispatchable resources, • Improved efficiency and flexibility of fossil units, • Additional peaking capacity to support electrification of transportation and heating, • Provision of reliability services to support high penetration of VRE, especially synchronous inertia and fast frequency response. A Technology Readiness assessment by EPRI confirmed that LSCC technology consists of commercially proven hardware used in industrial and utility applications. Although the novel LSCC approach has not yet been demonstrated as a complete system, interfaces between major components have been conservatively specified. A Phase III pilot is planned to demonstrate equipment integration and operation. The patented innovation is removal of the evaporator section from the exhaust heat recovery system, with the evaporation performed by stored energy in a separate steam generator. This arrangement couples renewable and fossil power generation via long-duration energy storage to deliver cost, performance, and operational synergies, including superior charging and discharging flexibility, reduced fuel consumption and lower CO 2 emissions compared to conventional Combined Cycle Power Plants, and low-cost, large-scale energy storage. The LSCC technology is composed of proven equipment integrated with gas turbine exhaust heat in a novel system. During charging, electric heaters raise the salt temperature as it flows from the Cold Salt Tank to the Hot Salt Tank. During discharging, hot salt produces steam from feedwater that is heated with gas turbine exhaust, which also superheats steam to drive a steam turbine. LSCC technology can be added to any combustion-turbine to integrate renewable energy, provide needed grid services, and increase the value of fossil electric generating units based on the technology’s following attributes: • Long-duration storage enables time-shifting of VRE to avoid curtailment and impairment of renewable assets. • Long storage duration combined with fast-charging capability increases arbitrage opportunities by storing more energy when the price is low and discharging more hours when the price is high. • Long storage duration allows resource adequacy to be supplied across multiple days to increase reliability and reduce risk. • The stored energy reduces fuel heat rate and GHG emissions, and increases merit, so the LSCC dispatches earlier and longer to increase the plant’s capacity factor and asset value. • The stored energy enables pre-heating and startup of the steam cycle, without operating the gas turbine, to enable fast startup and ramping when dispatched for discharge. • The steam turbine can operate without the gas turbine so it can provide valuable synchronous inertia during charging without consuming fuel. • Fast frequency response and regulation services can be provided during charging using solid-state heater and pump controls to vary the charge power input in response to grid signals. • The LSCC system can be configured for resilience including black start, islanded/micro-grid operation, and even self-recharging of storage using either gas turbine power or gas turbine exhaust heat. The commercialization plan is to add LSCC technology to existing simple cycle gas turbine power plants with the 50MW GE LM6000 aero-derivative gas turbine as the reference design basis. A Techno-economic assessment of the reference design evaluated the benefits (Levelized Avoided Cost of Energy) and costs (Levelized Cost of Energy). The plant definition included all major systems and budgetary vendor quotes. Pintail Power and NexantECA developed the overall cost estimate for the LSCC plant up to the total plant cost level, following the DOE-NETL cost estimate guidelines at AACE Class 3 (-20%/+30%). This includes the equipment cost, bulk material, direct and indirect labor costs to arrive at the bare erected cost. Engineering costs are factored from the BEC and added to it to arrive at the EPC cost. Process and project contingencies were then factored from the EPC cost and rolled-up to yield the total plant cost of $\$$184 million for 1746 MWh of discharge electricity. • At $\$$105/kWh, the reference plant costs less than any of the Energy Storage Systems evaluated by PNNL in 2020 for the Energy Storage Grand Challenge. Operations and Maintenance cost estimates were scaled from combined cycle practice, assuming that the LSCC unit was co-located with and sharing some labor expense with other units, to arrive at $\$$2.2 million per year. Plant economics were evaluated using prices from the ERCOT Day-Ahead Market for calendar year 2019 (excluding the market disruptions from the COVID pandemic and the February 2020 deep freeze event). Assuming economic dispatch in the ERCOT Day-Ahead market, the reference plant capacity factor would have discharged for 2777 hours at 91.9 MW, a 31.66% capacity factor, with a marginal cost of $\$$25.59/MWh, and a LACE of $\$$82.41/MWh. Fixed charges were calculated according to EIA guidelines to arrive at an LCOE of $\$$83.48. The benefit-to-cost ratio of 0.99 suggests that the reference plant would have been cost-effective and competitive in the market. EPRI interviewed selected utilities to gauge the need for, applicability of and interest in the LSCC system. Several utilities are currently managing increased load growth along with the inclusion of increasing levels of renewable generation, putting pressure on conventional generation by requiring increased turndown requirements and ultimately lower capacity factors. All of the utilities interviewed have CO 2 reduction targets in the 2030-2050 timeframe that will severely limit the participation of fossil generation and require better utilization of carbon free generation. While there is limited opportunity for storage in the current markets, the utilities interviewed stated that there will be a substantial need for long duration energy storage in the future given the expected trends. Utilizing an energy storage system will generally be preferred over new gas capacity in some cases, with the capabilities of the LSCC system being a potential option for retrofit to existing simple cycle gas turbine units, allowing them to deliver greater participation in the market with lower carbon intensity. A technology gap assessment and technology maturation plan identified a pilot-scale demonstration as the final step before commercialization. Key gaps to be addressed during the Phase II FEED (Front-End Engineering Design) are component selection and design, commissioning procedures, and operational procedures and the control system for LSCC charging and discharging. The project team has been expanded to include Wood Group PLC as EPC. The proposed Phase II work leads to a pilot-scale engineering demonstration (TRL 6) to be conducted at Southern Company’s Plant Rowan, where the prototype system will perform “all the functions that will be required of the operational system.” The proposed pilot will facilitate commercialization (TRL-9) by scale-up to utility-scale systems integrated with peaking GTs or directly to facility scale systems using industrial GTs. The conceptual design for the pilot plant focuses on the novel integration aspects of LSCC technology. A slipstream of gas turbine exhaust will feed a waste heat recovery unit coupled to a molten salt steam generator heated by stored energy. The pilot is intended to demonstrate all key operating modes of the LSCC technology during charging, discharging and standby. The pilot equipment will be approximately one-seventh scale of the LM6000 commercial target and is expected to have commercial off-ramp potential for facility-scale applications.

01 COAL, LIGNITE, AND PEAT↗