SEARCH · Search NASA
Search indexed NASA NTRS and DOE OSTI research on propulsion, heat transfer, battery materials and energy systems. Follow report and document links to the original sources.
Quote a phrase for an exact phrase match. Source license links do not imply unrestricted reuse.
The operations of the NETL baseline Supercritical Pulverized Coal (SCPC) power plants with or without carbon capture and sequestration (CCS) on the basis of 1 MWh electricity output. To access the model referenced in the report, please visit https://www.netl.doe.gov/energy-analysis/details?id=B5A2EB6F-4FBC-4883-922C-BE720FAC5A80
Material input for the construction of the NETL baseline supercritical pulverized coal (SCPC) plant with or without carbon capture and sequestration (CCS). To access the model referenced in the report, please visit https://www.netl.doe.gov/energy-analysis/details?id=404A3685-9CEF-4095-91EB-44CCF08D24F4
Explore the source record for details and available documents.
Abstract not provided
Life Cycle Analysis of a Supercritical PC plant with CCS Retrofit. Develops an Inventory of emissions results, and calculates Life Cycle costs for the plant with and without CCS.
Presented by NETL at Clearwater Clean Energy Conference, 06/19
The increasing use of renewable energy sources is leading to increased cycling of fossil-fueled power plants (FFPP) that are designed to operate at base-loaded conditions. Integrating energy storage facilities with the FFPPs can be helpful in reducing load-following operation of FFPPs. Decentralized deployment of energy storage facilities at the FFPP level has considerable advantages due to possibilities of smaller storage capacities, immediate benefits realized by the host power plant due to the increase in the efficiency, cleaner emission and higher plant life to name a few. Most importantly, deployment at the FFPP level can exploit the existing equipment items and facilities at the host power plant, thus reducing the CAPEX and reducing the storage capacity. However, realization of these benefits will critically depend on novel configuration/integration strategies with the least impact on the power plant operation and its configuration. Furthermore, dynamics of the entire integrated system including both the FFPP and the storage technologies must be taken into account to obtain the cost-optimal solution. With these motivations, the objective of this project was to complete a focused evaluation of decentralized deployments of energy storage facilities at the FFPP level. Promising thermal, chemical, mechanical, and electro-chemical storage technologies were evaluated with due consideration of their transient response to obtain various optimal system concepts that can minimize the levelized cost of storage. For thermal storage, cryogenic energy storage along with high temperature heat storage in molten salt as well as phase change material were evaluated. For mechanical storage, cryogenic air storage and pumped hydro storages were evaluated. For chemical storage, hydrogen storage was evaluated. For electrochemical storage, the team evaluated sodium sulfur, vanadium redox flow battery as well as Li-ion batteries. Integration of these storage technologies with the natural gas combined cycle (NGCC) and supercritical pulverized coal (SCPC) plants was considered. Six technologies, namely molten salt, cryogenics, compressed air, pumped hydro, H2 storage and Li-ion battery storage, were downselected based on their levelized cost of storage. It was observed that the ranking of the optimal storage technology can differ based on the host power plant technology even when same demand/supply/price profile for electricity are considered. It was also observed that as the variability in power demand varies, the ranking of the optimal storage technologies vary. However, for the same demand and LMP profile, top six optimal storage technologies for NGCC vs SCPC plants did not differ much even though LCOS for the same technology and optimal size of a given storage technology did differ. Detailed techno-economic assessment of these six technologies was undertaken.
The Power Systems L-CAT is a high-level dynamic model that calculates levelized production costs and tracks environmental performance for a range of electricity generation technologies: natural gas combined cycle (using either imported (LNGCC) or domestic natural gas (NGCC)), integrated gasification combined cycle (IGCC), supercritical pulverized coal (SCPC), existing pulverized coal (EXPC), nuclear, and wind. All of the fossil fuel technologies also include an option for including carbon capture and sequestration technologies (CCS). The model allows for quick sensitivity analysis on key technical and financial assumptions, such as: capital, O&M, and fuel costs; interest rates; construction time; heat rates; taxes; depreciation; and capacity factors. The fossil fuel options are based on detailed life cycle analysis reports conducted by the National Energy Technology Laboratory (NETL). For each of these technologies, NETL's detailed LCAs include consideration of five stages associated with energy production: raw material acquisition (RMA), raw material transport (RMT), energy conversion facility (ECF), product transportation and distribution (PT&D), and end user electricity consumption. The goal of the NETL studies is to compare existing and future fossil fuel technology options using a cradle-to-grave analysis. The NETL reports consider constant dollar levelized cost of delivered electricity, total plant costs, greenhouse gas emissions, criteria air pollutants, mercury (Hg) and ammonia (NH3) emissions, water withdrawal and consumption, and land use (acreage).
This technical final report submitted to DOE/NETL presents all the research activities performed during the entirety of DE-FE0031660 project-Emissions Mitigation Technology for Advanced Water-Lean Solvent-Based CO 2 Capture Processes which spans from October 2018 through March 2022. RTI International has been conducting studies from fundamental and operational aspects to reduce the overall amine emissions from the advanced Water-Lean Solvent (WLS) systems, specifically RTI’s Non-Aqueous Solvent (NAS). This technical final report will highlight the key findings from project which align closely to the project objectives which are: Identify the contribution of vapor loss, entrainment, and aerosols to the overall emissions of water-lean systems; Determine the significance of CO 2 capture system operating parameters to the amine emissions; Develop an emissions model based on critical operating parameters; Evaluate the effectiveness of emissions mitigation devices to reduce the amine emissions to <1 ppm under flue coal-fired flue gas; and, Determine the contribution of the ECTs to the overall CO 2 capture cost. The following are the key findings based on numerous tests using both lab-scale setups and parametric testing performed at RTI’s Bench-scale Gas Absorption System (BsGAS). During the BP1, the aerosol generation system and monitoring equipment were installed at BsGAS to produce and determine the aerosol characteristics during the NAS CO 2 capture process. The aerosol produced by this setup produced aerosols with the peak diameter and concentration of 50 micron and 1.2E10 7 cm -3 , respectively. These particle sizes and concentrations are matched to those observed in the actual coal-fired power plant flue gases and expected to be found at the absorber inlet of the CO 2 capture system. Over 1,300 hours of parametric testing have been conducted to evaluate the impact of the aerosols and operating conditions during the CO 2 capture with NAS on the overall amine emissions in the treated flue gas. At the worse condition tested, the presence of the aerosols in the flue gas could increase the overall emissions by 10X compared to the baseline emissions from NAS’s vapor pressure. CO 2 capture rate was found to be a main factor impacting the overall emissions as well as aerosol size and concentrations in the absorber off-gas. The higher CO 2 capture rate, the higher amine emissions in the treated gas. The temperature difference between the temperature bulge seen in the absorber and the water wash temperature also impacts the particle growth where the larger the temperature difference, the more amine emissions from aerosols in the treated gas. The majority of the aerosols did not grow substantially in the system, and the particle concentrations remained nearly constant between the absorber inlet and wash outlet. Only a small portion of the particles were found to grow significantly. The high efficiency demister with mesh size of 5-10 micron can be installed to remove a portion of the aerosols from the gas stream leaving the water wash. Overall, these results from parametric testing have established the emission baseline and validate our assumption on the need of emission control technologies (ECT) in order to minimize the emissions from the baseline NAS CO 2 capture process. Over 2,000 of BsGAS operating hours was used to investigate a handful of process improvements which led to a selection of the vital few changes that effectively control the amine emissions. These process improvements are lime-coated-filters for absorber gas inlet, advanced demister at the top of the absorber, a second water wash with amine recovery unit were designed, installed, and tested at BsGAS at the end of BP1. The result showed that the NAS CO 2 capture process with these additional emission control devices could lower the amine emission in the treated gas to about 1 ppm using a simulated coal-fire flue gas stream. The main contributor in lowering the amine emission came from the second water wash with amine recovery unit where the amine concentration in the scrubbing water was kept below 2 wt% through a continuous amine removal via an adsorbent bed, resulting in a low amine vapor pressure. The adsorbent bed was regenerated via a direct steam regeneration and the recover amine was returned to the absorber to minimize wastewater and makeup amine. A flue gas generation system was designed and installed during the first half of BP2 to support the emission testing using a real coal-derived flue gas. The system is capable of generating both coal- and natural gas- derived flue gases with the composition of the gaseous species highly resemble to that of the power plant flue gases. The particulates detected in the coal-derived flue gas showed the mean diameter of 1 micron. The CO 2 capture operating was then proceed using the real coal-derived flue gas where the amine emission was controlled to be about 0-3 ppm for the total run time of about 200 hours. Similar testing was conducted with natural gas-derived flue gas and the result showed a highly amine emission of 30 ppm under the total run time of 200 hours. The Principal Component Analysis (PCA) and the Partial Least Squares Projection to Latent Structures (PLS) techniques were applied to the parametric testing data to derive a multivariate statistical model. The model was validated and trained with half of the data collected, and the predictive ability of the model was evaluated using the remaining half of the data. The resulting empirical model was capable of predicting the overall emissions from the NAS process without the ECTs with ±15% accuracy (average absolute deviation, AAD) in BP1. As more emission data were obtained under the real coal-flue gas in the BP2, the model incorporated these new set of data to reflect the final process configuration, operating parameters, and amine emission. This results in the updated empirical model predicting the amine emission from the NAS CO 2 capture process with 84% goodness-of-fit (R 2 ), 85% predictability (Q 2 ), and 15% AAD. The study evaluates the use of RTI’s Non-Aqueous Solvent technology for 90% CO 2 capture from a net 650 MWe pulverized coal power plant, downstream of the flue-gas desulfurization unit. The captured CO 2 has a purity of > 95% CO 2 , and is dried, compressed to 15.3 MPa (2,215 psia), ready for sequestration. The analysis uses Case B12B from the DOE Baseline study on Bituminous Coal, Revision 4 where the Cansolv CO 2 capture plant is replaced by the RTI CO 2 Capture plant. The CO 2 capture plant has been sized to capture >90% CO 2 from flue gas derived from a net 650 MWe supercritical pulverized coal power plant. The CO 2 capture plant is equipped with emission control technologies that limits the amine emissions to < 1 ppm. Two different cases were evaluated for the technoeconomic study. The key difference between the two cases is the regenerator pressure. In Case 1, the regenerator operates at 0.195 MPa (28.3 psia), whereas in Case 2, the regenerator pressure is 0.44 MPa (64 psia) thus removing the need for the first stage of compression of the eight-stage compression train. Results from the TEA are compared against the DOE reference cases for SCPC plant with and without CO 2 Capture (Case B12A and Case B12B of the DOE Baseline study, respectively). Case 2 with CO 2 regeneration at higher pressure results in the lower cost of CO 2 capture. The total capital cost of the capture process has been estimated using 2018 dollars in Aspen Process Economic Analyzer and was estimated to be $579 MM. The capture plant operation leads to a total parasitic power loss rate of 96 MWe, resulting in a decrease in pulverized coal power plant efficiency of 7.8% points. The resulting cost of electric power increases from 64.4 mills/kWh, for no capture, to 97.5 mills/kWh, with 90% capture, an increase of 51% in the COE. The cost of capturing 90% CO 2 was estimated to be $38.2/tonne-CO 2 , and meets the DOE target of $40/t-CO 2 . Emission control technologies (ECT) investigated in this project includes a second water wash with use of activated carbon beds for removal of amine from the wash water prior to recirculation in the water wash. These ECT allow operation of the CO 2 capture plant with < 1 ppm amine emissions with the treated flue gas and contributes to $2.4/t-CO 2 captured. Amine emissions derived from thermal and oxidative degradations were investigated under this project along with the emissions derived from aerosols for the NAS system. The thermally degraded of the lean NAS showed less than 4% decreased of the original total amine content in the NAS at 150 °C while the result obtained at 120 °C showed no drop in total amine content, suggesting that thermal degradation of the NAS is minimal. These results also suggested that the thermally degraded species are not likely formed and contributed to the emissions due to the low regeneration temperature of the NAS at 90-105 °C. The oxidative degradation, on the other hand, could become problematic as some of these oxidative degraded species were observed during the NAS-5 testing at National Carbon Capture Center (NCCC) and SINTEF in our previous project. The rapid screening of selected inhibitors suggested that oxidative degradation of NAS can be suppressed using thiol containing compounds in amounts of at least 1 mol%. The detailed mechanistic degradation pathway was conceived for a specific amine used in NAS formulation during BP2. he reduction of the nitrosamines caused by the NO x present in the flue gas was also examined. The study suggested that the thermo-chemical treatment of the NAS solvent would be a more effective and economically viable compared to removing NO x at the DCC.
Traditional energy production plants are increasingly forced to cycle their load and operate under low-load conditions in response to growth in intermittent renewable generation. A plant-wide dynamic model of a supercritical pulverized coal (SCPC) power plant has been developed in the Aspen Plus Dynamics® (APD) software environment and the impact of advanced control strategies on the transient responses of the key variables to load-following operation and disturbances can be studied. Models of various key unit operations, such as the steam turbine, are developed in Aspen Custom Modeler® (ACM) and integrated in the APD environment. A coordinated control system (CCS) is developed above the regulatory control layer. Three control configurations are evaluated for the control of the main steam; the reheat steam temperature is also controlled. For studying servo control performance of the CCS, the load is decreased from 100% to 40% at a ramp rate of 3% load per min. The impact of a disturbance due to a change in the coal feed composition is also studied. The CCS is found to yield satisfactory performance for both servo control and disturbance rejection.
To address industry challenges in attaining operational excellence for electricity generation plants, the U.S. Department of Energy’s (DOE) National Energy Technology Laboratory (NETL) has launched a world-class facility for Advanced Virtual Energy Simulation Training and Research (AVESTARTM). This presentation will highlight the AVESTARTM Center simulators, facilities, and comprehensive training, education, and research programs focused on the operation and control of high-efficiency, near-zero-emission electricity generation plants. The AVESTAR Center brings together state-of-the-art, real-time, high-fidelity dynamic simulators with full-scope operator training systems (OTSs) and 3D virtual immersive training systems (ITSs) into an integrated energy plant and control room environment. AVESTAR’s initial offering combines--for the first time--a “gasification with CO2 capture” process simulator with a “combined-cycle” power simulator together in a single OTS/ITS solution for an integrated gasification combined cycle (IGCC) power plant with carbon dioxide (CO2) capture. IGCC systems are an attractive technology option for power generation, especially when capturing and storing CO2 is necessary to satisfy emission targets. The AVESTAR training program offers a variety of courses that merge classroom learning, simulator-based OTS learning in a control-room operations environment, and immersive learning in the interactive 3D virtual plant environment or ITS. All of the courses introduce trainees to base-load plant operation, control, startups, and shutdowns. Advanced courses require participants to become familiar with coordinated control, fuel switching, power-demand load shedding, and load following, as well as to problem solve equipment and process malfunctions. Designed to ensure work force development, training is offered for control room and plant field operators, as well as engineers and managers. Such comprehensive simulator-based instruction allows for realistic training without compromising worker, equipment, and environmental safety. It also better prepares operators and engineers to manage the plant closer to economic constraints while minimizing or avoiding the impact of any potentially harmful, wasteful, or inefficient events. The AVESTAR Center is also used to augment graduate and undergraduate engineering education in the areas of process simulation, dynamics, control, and safety. Students and researchers gain hands-on simulator-based training experience and learn how the commercial-scale power plants respond dynamically to changes in manipulated inputs, such as coal feed flow rate and power demand. Students also analyze how the regulatory control system impacts power plant performance and stability. In addition, students practice start-up, shutdown, and malfunction scenarios. The 3D virtual ITSs are used for plant familiarization, walk-through, equipment animations, and safety scenarios. To further leverage the AVESTAR facilities and simulators, NETL and its university partners are pursuing an innovative and collaborative R&D program. In the area of process control, AVESTAR researchers are developing enhanced strategies for regulatory control and coordinated plant-wide control, including gasifier and gas turbine lead, as well as advanced process control using model predictive control (MPC) techniques. Other AVESTAR R&D focus areas include high-fidelity equipment modeling using partial differential equations, dynamic reduced order modeling, optimal sensor placement, 3D virtual plant simulation, and modern grid. NETL and its partners plan to continue building the AVESTAR portfolio of dynamic simulators, immersive training systems, and advanced research capabilities to satisfy industry’s growing need for training and experience with the operation and control of clean energy plants. Future dynamic simulators under development include natural gas combined cycle (NGCC) and supercritical pulverized coal (SCPC) plants with post-combustion CO2 capture. These dynamic simulators are targeted for use in establishing a Virtual Carbon Capture Center (VCCC), similar in concept to the DOE’s National Carbon Capture Center for slipstream testing. The VCCC will enable developers of CO2 capture technologies to integrate, test, and optimize the operation of their dynamic capture models within the context of baseline power plant dynamic models. The objective is to provide hands-on, simulator-based “learn-by-operating” test platforms to accelerate the scale-up and deployment of CO2 capture technologies. Future AVESTAR plans also include pursuing R&D on the dynamics, operation, and control of integrated electricity generation and storage systems for the modern grid era. Special emphasis will be given to combining load-following energy plants with renewable and distributed generating supplies and fast-ramping energy storage systems to provide near constant baseload power.
The U.S. Department of Energy’s Carbon Capture Simulation Initiative (CCSI) is dedicated to accelerating the commercialization of carbon capture technologies from discovery to development, demonstration, and ultimately the widespread deployment to hundreds of power plants. In this multi-lab initiative in partnership with academic and industrial institutions, the National Energy Technology Laboratory (NETL) leads the development of a multi-scale modeling and simulation toolset for rapid evaluation and deployment of carbon capture systems. One element of the CCSI is focused on optimizing the operation and control of carbon capture systems since this can have a significant impact on the extent and the rate at which commercial-scale capture processes will be scaled-up, deployed, and used in the years to come. Capture processes must be capable of operating over a wide range of transient events, malfunctions, and disturbances, as well as under uncertainties. As part of this work, dynamic simulation and control models, methods, and tools are being developed for CO{sub 2} capture and compression processes and their integration with a baseline commercial-scale supercritical pulverized coal (SCPC) power plant. Solid-sorbent-based post-combustion capture technology was chosen as the first industry challenge problem for CCSI because significant work remains to define and optimize the reactors and processes needed for successful sorbent capture systems. Sorbents offer an advantage because they can reduce the regeneration energy associated with CO{sub 2} capture, thus reducing the parasitic load. In view of this, the current paper focuses on development of a dynamic model of a solid-sorbent CO{sub 2} adsorber-reactor and an analysis of its transient performance with respect to several typical process disturbances. A one-dimensional, non-isothermal, pressure-driven dynamic model of a two-stage bubbling fluidized bed (BFB) adsorber-reactor is developed in Aspen Custom Modeler (ACM). The BFB stages are of overflow-type configuration where the solids leave the stage by flowing over the overflow-weir. Each bed is divided into three regions, namely emulsion, bubble, and cloud-wake regions. In all three regions, the model considers mass and energy balances. Along with the models of the BFB stages, models of other associated hardware are developed and integrated in a single flowsheet. A valid pressure-flow network is developed and a lower-level control system is designed so that the overall CO{sub 2} capture can be maintained at a desired level in face of the typical disturbances. The dynamic model is used for studying the transient responses of a number of important process variables as a result of the disturbances that are typical of post-combustion CO{sub 2} capture processes.
Under contract DE-FE0007603, the University of North Dakota conducted the project Evaluation of Carbon Dioxide Capture from Existing Coal Fired Plants by Hybrid Sorption Using Solid Sorbents. As an important element of this effort, a Technical and Economic Feasibility Study was conducted by Barr Engineering Co. (Barr) in association with the University of North Dakota. The assessment developed a process flow diagram, major equipment list, heat balances for the SCPC power plant, capital cost estimate, operating cost estimate, levelized cost of electricity, cost of CO2 capture ($/ton) and three sensitivity cases for the CACHYS™ process.
Future markets for power are expected to require more load following power plants, which reduces output during the night and early morning. This is when the demand for electricity is the lowest, so plants must respond rapidly at any time to peak loads resulting from the variable output of wind and solar power. A coal power plant based on Flameless Pressurized Oxy-combustion (FPO) can go from 5% to 100% of capacity rate in less than 30 minutes in response to fluctuating demand, operating at capacity when power prices are highest. FPO is a proven oxy-combustion technology that was developed to recover energy from low ranking coal, other brown fuels and wastes. ITEA began developing FPO in 2003 on a 5-MWth pilot in Gioia del Colle, Italy, to destroy hazardous industrial waste and as such, design objectives were very high combustion efficiencies and capture of metals in the fuel in the vitreous slag. The technology was subsequently deployed in 2009 at the 15-MWth scale at the Jurong Island petrochemical cluster in Singapore for waste incineration. FPO is an oxy-combustion process whereby oxygen is separated from the air, and it is used in combustion with recirculated flue gas to maintain combustion temperatures at acceptable levels. The resultant flue gas is primarily CO 2 and water, which allows for a relatively simple and cheap CO 2 capture process. This is in contrast to air-combustion systems which require a complex and costly post-combustion capture (PCC) process. Coal is fed to the combustor slurried in water, and the combustor operates at elevated pressure (approximately 12 bar) which improves the overall efficiency and reduces the size and cost of the combustor. Notably, the FPO cycle maintains high efficiency by recovering most of the heat of vaporisation of the contained water. The combustor is designed to coalesce the molten ash particles so that they settle to the chamber walls and drain to the outlet, significantly reducing the particulate content in the exhaust gas and allowing the use of coals with up to 40% alkaline ash content. FPO is a low-emission technology: zero thermal NOx minimises overall NOx; any organic nitrogen is converted to elemental nitrogen (N2). Total organic content (TOC) at combustor exit is hundreds of times lower than for traditional combustion processes, with dioxin and furans close to zero. Work commenced on a DOE funded pilot demonstration project in October 2016 to provide the design for a 50-MWth FPO pilot plant that can fire a wide range of high-to-low rank coals. The project will investigate updating and improving the cycle for power generation with CO 2 capture by incorporating a turbo-expander with a principal steam power island that utilizes a heat recovery steam generator, increasing the overall efficiency of the cycle. A cost study is also performed on the updated FPO design as part of the project. The FPO pilot plant built based on the design will then be demonstrated over a 3-year test program to generate data for the design of a commercial-scale 500 MWth firing module commercial power plant with integral carbon capture and sequestration (CCS), which could start construction in 2025. A discussion of the levelized cost of electricity (LCOE) of various cases are presented, including a comparison of established supercritical with PCC (SCPC) technologies with FPO fitted with CO 2 compression and liquefaction, and FPO ready for carbon capture and sequestration (CCS-ready). This would enable CO 2 capture for use in enhanced oil recovery (EOR) or sequestration when market conditions make it attractive to do so. In addition, a comparison of LCOE of FPO and conventional processes for firing low-ranking coals with high water and ash content will be provided.
This work was presented at the TechConnect Conference in Boston, MA on June 17, 2019. NETL is evaluating the environmental life cycle impacts of algae biofuels synthesized using CO2 from five types of thermoelectric power plants. The power plants considered in the analysis are (1) Subcritical Pulverized Coal-fired Power Plant (SubPC), (2) Supercritical Pulverized Coal-fired Power (SCPC), (3) Solid Oxide Fuel Cell Power Plant (SOFC), (4) Oxycombustion Pulverized Coal Plant (OxyPC), and (5) NGCC to model algae biofuel pathways. Both flue gas and captured (amine-based solvent) CO2 scenarios are considered. Algae-to-biofuel conversion is modeled via Combined Algae Processing (CAP) and Hydrothermal Liquefaction (HTL) pathways with the algae cultivation in open raceway ponds (ORPs) and photobioreactors (PBRs).
Presentation for life cycle analysis compilation of the power LCA reports. Develops an inventory of emissions results, and calculates life cycle costs for each plant with and without CCS.
Presentation for life cycle analysis compilation of the Power LCA Reports. Develops an inventory of emissions results, and calculates life cycle costs for each plant with and without CCS.
Presentation for life cycle analysis compilation of the power LCA reports. Develops an inventory of emissions results, and calculates life cycle costs for each plant with and without CCS.