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DOE OSTI2018

Analysis of Cost Reduction Potential of Vertical Bore Ground Heat Exchanger (Final)

The geothermal heat pump (GHP), also referred to as a ground source heat pump, is a proven technology that can provide space conditioning and water heating with efficiencies higher than conventional heating, ventilation, and air-conditioning (HVAC) systems. This technology possesses great potential to become a mainstream technology for satisfying the thermal demands in the built environment. Analysis from the ongoing Geothermal Vision Study indicates that 100% retrofitting of commercial and residential markets with GHPs has the potential to save on the order of 6 quadrillion Btu per year (Liu et al. 2017). However, the current high installation costs and long payback periods limit the attractiveness of GHP installation in the United States. The cost of installing ground heat exchangers (GHXs) used for GHPs accounts for more than 30% of the total cost of a GHP system (NYSERDA 2017), and it is the biggest contributor to the cost premium of GHPs compared with conventional HVAC systems.

32 ENERGY CONSERVATION, CONSUMPTION, AND UTILIZATI↗
DOE OSTI2018

In-Cylinder Diagnostics to Overcome Efficiency Barriers in Natural Gas Engines (LDRD 200166)

The high-level objective of this project is to solve national-security problems associated with petroleum use, cost, and environmental impacts by enabling more efficient use of natural-gas-fueled internal combustion engines. An improved science-base on end-gas autoignition, or “knock,” is required to support engineering of more efficient engine designs through predictive modeling. An existing optical diesel engine facility is retrofitted for natural gas fueling with laser-spark-ignition combustion to provide in-cylinder imaging and pressure data under knocking combustion. Zero-dimensional chemical-kinetic modeling of autoignition, adiabatically constrained by the measured cylinder pressure, isolates the role of autoignition chemistry. OH* chemiluminescence imaging reveals six different categories of knock onset that depend on proximity to engine surfaces and the in-cylinder deflagration. Modeling results show excellent prediction regardless of the knock category, thereby validating state-of-the-art kinetic mechanisms. The results also provide guidance for future work to build a science base on the factors that affect the deflagration rate.

33 ADVANCED PROPULSION SYSTEMS↗
DOE OSTI2018

Multifamily Tool for Energy Audits (MulTEA) Engineering Manual (Version 1)

The Multifamily Tool for Energy Audits (MulTEA) is an energy audit tool designed to provide auditors with an improved energy simulation tool for multifamily buildings and an improved tool for identifying cost-effective energy-efficiency retrofit measures for multifamily buildings. MulTEA is designed specifically to help states and local weatherization agencies implement the Department of Energy (DOE) Weatherization Assistance Program. MulTEA was developed jointly by the Oak Ridge National Laboratory (ORNL) and the Lawrence Berkeley National Laboratory (LBNL). MulTEA is part of ORNL’s web-based Weatherization Assistant suite of audit tools (https://weatherization.ornl.gov/softwaredescription/). The energy calculation engine including the DOE- 2 simulation model and supplementary calculation modules is shared by MulTEA and LBNL’s Home Energy Saver pro (HESpro) (http://hespro.lbl.gov/pro/). On the ORNL side, the energy calculation engine is coupled with a user interface and output reporting capabilities based on Weatherization Assistance Program regulations and guidelines pertinent to MulTEA. On the LBNL side, the same engine will be used in HESpro to expand it to handle multifamily buildings. MulTEA is designed to address small and large multifamily buildings with decentralized and centralized heating, ventilation, and air-conditioning (HVAC) and domestic hot water (DHW) systems. Version 1 of MulTEA addresses small multifamily buildings with decentralized HVAC systems, and decentralized or centralized DHW systems. The capability to model large buildings and centralized HVAC systems will be incorporated in Version 2.

32 ENERGY CONSERVATION, CONSUMPTION, AND UTILIZATI↗
DOE OSTI2018

Tracking the Sun: Installed Price Trends for Distributed Photovoltaic Systems in the United States - 2018 Edition

Berkeley Lab’s Tracking the Sun report series is dedicated to summarizing installed prices and other trends among grid-connected, distributed solar photovoltaic (PV) systems in the United States. The present report, the 11th edition in the series, focuses on systems installed through year-end 2017, with preliminary trends for the first half of 2018. As in years past, the primary emphasis is on describing changes in installed prices over time and variation in pricing across projects based on location, project ownership, system design, and other attributes. New to this year, however, is an expanded discussion of other project characteristics in the large underlying data sample. Future editions will include more of such material, beyond the report’s traditional focus on installed pricing. The trends described in this report derive primarily from project-level data reported to state agencies and utilities that administer PV incentive programs, solar renewable energy credit (SREC) registration systems, or interconnection processes. In total, data were collected and cleaned for more than 1.3 million individual PV systems, representing 81% of U.S. residential and non-residential PV systems installed through 2017. The analysis of installed pricing trends is based on a subset of roughly 770,000 systems with available installed price data. Key findings from this year’s report include the following: -Installed Prices Continued to Fall through 2017 and into 2018. National median installed prices in 2017 were $3.7 per watt (W) for residential systems (a $0.2/W or 6% decline from the prior year), $3.1/W for small non-residential systems (a $0.4/W or 11% decline), and $2.2/W (a $0.1/W or 5% decline) for large non-residential systems. Data for the first half of 2018 show an additional drop of $0.1/W for residential and small non-residential systems, and effectively no change for large non-residential systems. These recent trends are generally consistent with the pace of price declines since 2014, and mark a slowing from the years immediately preceding (2009-2013) when prices fell by roughly $1/W per year. -Installed Prices Vary Widely Across Individual Projects. Among residential systems installed in 2017, 20% were priced below $3.0/W (the 20th percentile value) while another 20% were above the 80th percentile at $4.5/W. Non-residential systems also exhibit wide spreads, albeit shifted downward, from $2.4/W to $4.1/W for small non-residential and from $1.8/W to $2.8/W for large non-residential projects. These pricing spreads have persisted over time and are both reflective of the heterogeneity in PV systems and markets, as well as suggestive of the potential for further price declines. -Pronounced Pricing Disparities Exist Across States. State-level median installed prices in 2017 ranged from $2.6/W to $4.5/W for residential systems, from $2.2/W to $4.0/W for small non-residential systems, and from $2.1/W to $2.4/W for large non-residential systems. Three of the largest state markets (California, Massachusetts, and New York) are relatively high-priced, pulling overall U.S. median prices upward. These cross-state pricing differences reflect both idiosyncratic features of particular states as well as more-fundamental differences related to market and policy conditions. -Installed Pricing Variation Also Reflects Differences in System Design, Installer, and Customer Characteristics (among other factors). Significant pricing differences were also observed across system sizes within each customer segment (with median prices ranging from $3.2/W to $4.5/W across residential systems of varying size, and from $2.1/W to $3.7/W across non-residential systems), between third-party owned (TPO) and host-owned residential systems ($3.3/W vs. $3.8/W), across residential installers ($2.1/W to $9.6/W for host-owned systems and $1.1/W to $5.1/W for TPO systems), between residential new construction and retrofit systems in California ($2.3/W vs. $3.9/W), between large non-residential systems at commercial sites and tax-exempt customer sites ($2.1/W vs. $2.6/W), and between systems with standard vs. premium efficiency modules ($3.6/W vs. $4.2/W among residential systems). A public version of the underlying dataset can be downloaded at https://emp.lbl.gov/tracking-the-sun.

14 SOLAR ENERGY↗
DOE OSTI2018

Stasis PCM Test Results

A phase change material product distributed by Stasis Group, designed to reduce the cooling energy requirements of multi-story commercial buildings, was tested in a side-by-side comparison at FLEXLAB® (LBNL, 2018), a calibrated test facility for low energy building technology solutions. The product was installed according to Stasis recommendations in the ceiling plenum of a 600 ft 2 cell representative of an office space, while an identical cell was operated in the same conditions, except for the night-time pre-cooling sequence and without the product, to gather baseline data. The cells were operated to replicate summer conditions of a candidate office building for retrofit. For the tests conducted at FLEXLAB, two Phase Change Material (PCM) compositions were tested, with the second product having an upgraded composition for thermal performance and upgraded packaging that was used to meet with fire safety requirements for a plenum application. Two rounds of tests were performed, which were designed to collect data for both core (designated as Round 1) and perimeter (Round 2) office space conditions. Following the analysis of the data collected during Round 1, the experimental design was modified to better represent the thermal conditions of a typical office space in relation to the PCM performance. A new product was also brought in for testing in Round 2, which had an improved operational temperature range and packaging properties. In Round 1, multiple tests were conducted to evaluate the performance of the product under different conditions of internal loads, temperature setpoints, pre-cooling strategies and temperature control strategies. In Round 2, the internal conditions were kept constant, while the test conditions only differ in the amount of PCM installed in the test cell plenum and the length of the nighttime pre-cooling sequence. The performance benefits of PCM are generally two-fold: the material may reduce peak cooling energy use during daytime hours (a peak demand energy use benefit) and may allow for energy savings with pre-cooling at night through night flush HVAC controls when night time outside air temperatures are lower, and fan energy use for cooling is more efficient than the use of daytime compressor-based cooling. The focus of this research project was mainly on quantifying the energy savings potential of the latter case although some effects on peak reduction were noted. Between the cell with PCM and nighttime precooling and the reference cell without PCM or precooling, a reduction in cooling load during occupied hours was noted between 7.6 kWh (or 22% of occupied hours cooling load) and 12.5 kWh (or 33% of occupied pg. 7 hours cooling load). Future work can further evaluate the peak cooling load reduction benefits of this product in more detail. This report highlights the results of Round 2, which reflect the performance of the modified PCM product when operated in suitable conditions. The results of Round 1, along with an analysis of the experimental data to identify the factors that prevented the product from performing as desired are presented in Appendix B.

32 ENERGY CONSERVATION, CONSUMPTION, AND UTILIZATI↗
DOE OSTI2017

Report on the Economic Optimization of a Demonstration Case for a Static N-R HES Configuration using RAVEN

The synthetic time history generation algorithm in RAVEN has been extensively tested and used to perform qualitative assessments of the statistical characteristics of the net demand vs. demand for different values of the penetration of wind generation. Reported results highlight the need to consider the impact of variable renewable on the electricity net demand profile, due to the increase in its volatility with increased wind penetration. This analysis provides a strong foundation for the modeling and simulation needs expressed under the "Nuclear-Renewable Hybrid Energy Systems" (NRHES) project. Following this confirmative analysis the entire stochastic optimization framework has been tested in a demo case. The case chosen is an optimization driven by profitability for a system composed by a nuclear plant and a hydrogen production industrial process. This type of economical analysis is aimed to assess the capability of a hybrid system to penetrate the current energy market. In this sense it differs from the approach suggested under NRHES, where a cost minimization approach is suggested. This analysis is instead aimed to show the flexibility of the developed framework, e.g. for the evaluation of retrofitting projects of already existing plants. The system considered is subject to variable prices of electricity, which are simulated using the algorithm for the production of synthetic time histories. The physical system is considered without inertia so that it can be replaced by dispatching rules based on the highest marginal profit. Two optimization problems have been considered, for the first the size of the nuclear power plant is fixed and the optimization variable is the capacity of the hydrogen production plant. For the second, both plant sizes are optimization parameters while the overall capital expenditure is caped. The economical figures of merits considered are the Internal Rate of Return (IRR) and/or Profitability Index (PI) for the first one (since no cap is placed on the investment size) and Net Present Value (NPV) and/or IRR for the second one where the capital expenditure is constrained. Economic input data concerning capital costs, size-scaling factors, and operational costs for both plants have been collected from literature in order to achieve a simulation as realistic as possible. More work will be needed to obtain even more realistic numbers, possibly from industrial partners, and considering market elasticity for the hydrogen market. In order to perform the optimization of the cases described above, the economical external RAVEN module (CashFlow) for financial analysis has been improved in flexibility and generality. Some improvements have also been made to the optimization algorithm for a more efficient treatment of the boundary constrains. In conclusion three major results have been obtained: a) collection of the economical parameters characterizing the nuclear power plants and hydrogen production plants, b) extension of the financial analysis module (CashFlow) to drive the calculation of all needed cash flow streams and c) the testing of the full framework in a nearly final configuration.

97 MATHEMATICS AND COMPUTING↗
DOE OSTI2018

Lab-scale Development of a Hybrid Capture System with Advanced Membrane, Solvent system, and Process Integration

The objective of the project is to achieve lab-scale demonstration of a transformational hybrid membrane/solvent system for the capture of CO 2 from flue gas. A novel process integration scheme was proposed to overcome the low partial pressure of CO 2 present in flue gas. This scheme takes advantage of the potential synergies inherent in the membrane and solvent capture systems. The proposed hybrid technology replaces the second-stage membrane with a solvent capture process. The combustion air is used as a sweeping gas in the solvent stripper. This overall configuration has the major advantages of requiring much less air and eliminating the problems associated with oxygen slip in the membrane-based systems. Even more importantly, because of the presence of the air sweep in the stripper, much lower temperatures are required for solvent regeneration, which enables heat integration to the point that no process steam is required. This project was to perform lab-scale demonstration of Liquid Ion Solutions (LIS) transformational hybrid membrane/solvent system for post-combustion CO 2 capture while demonstrating significant progress toward achievement of the overall fossil energy performance goals of 90% CO 2 capture rate with 95% CO 2 purity at a cost of electricity 30% less than baseline capture approaches. This report is written chronologically based on budget periods. Each budget period discusses the work performed and its results. At the end of each budget period the milestone charts are provided to show the progress. This project was not able to meet its stated goals. The performances of the power plant equipped with the hybrid process and Baseline Case B12B were compared. The simulation results showed that the power plant equipped with hybrid CO2 capture process has an improved thermal efficiency of 33.4% compared to the Baseline Case B12B, which is 32.5%. However, the COE for the hybrid process is $146.3/MWh which is higher than the $142.8/MWh for Case B12B. If this process were to be applied as a retrofit, it may make sense to use this configuration as it does not require any change in an existing plant configuration and steam cycle. However, for a new powerplant the capital cost is higher than the Case B12B. On the membrane development side, we successfully showed that interfacially-controlled envelope (ICE) membranes work. The inclusion of surface modified nano-particles results in much higher gas diffusivities. The Gen-1 ICE membrane developed under this project showed exceptional improved permeability for CO 2 . However, we ran into major problems which were associated with the scalability and reproducibility of the poly(phosphozene) polymers. The issues with scale-up are and batch to batch variability is also discussed. At the end of this report we have provided our recommendations on materials development for better membrane materials and alluded to the use of much simpler chemistry while keeping the concept of ICE membrane intact. It is also clear that vacuum and compression equipment is costly. If a process which can eliminate the use of vacuum and compression equipment would significantly decrease the overall cost of capture. Some thoughts regarding such system is also provided in the outlook portion of this report.

20 FOSSIL-FUELED POWER PLANTS↗
DOE OSTI2018

Applying the Transactive Systems Business Value Model to IRP

As part of the Transactive Systems Program at Pacific Northwest National Laboratory, a value modeling system was developed to support the evaluation of transactive systems. The technique is general enough to be applied outside transactive systems and to demonstrate this capability, a project was undertaken to use this value modeling technique as a means for modeling the valuation process undertaken by vertically integrated utilities when undergoing integrated resource planning (IRP). IRP is the process by which vertically integrated utilities (those that both serve customers directly as well as manage and run generation assets to do so) regularly go through to demonstrate to their regulators that they have a plan to meet the expected future load of their customers in a least cost and compliant manner. Traditionally this has been primarily an issue of how many and of which types of power plants to build but increasingly has included alternative measures such as demand response programs. Increasingly, environmental regulations play a significant role in both determine what types of power plants can be built under current regulations as well as what retrofits or upgrades need to be made to existing plants to allow them to continue to operate. Two use-case diagrams were constructed, one showing the showing the process by which IRP is carried out and another showing how a vertically integrated utility procures the resources it requires to meet load now and in the future. These diagrams help clarify the difference and provide a high-level outline of the two processes. A class diagram was constructed to clearly define the types of actors that would be considered in this model and the relationships between them. This diagram tacitly indicates which types of actors are and are not included in the model which provides significant guidance in defining the scope of the model. The relationship between the classes/actors provides further indication of what areas of the model have higher levels of detail and by implication bear more significance in modeling the system. Using the classes/actors defined in the class diagram, a business value diagram was constructed that defines the key value streams exchanged between the actors. This diagram provides a clear expression of the business case of the vertically integrated utility and who its counterparties are during the process of meeting load. These value streams have not only to do with meeting the load but doing so in a manner that meets environmental regulations. Increasingly, IRPs have three key metrics to evaluate a given plant to meet load: net present value of revenue required, emissions, and renewable energy credits. From this business value diagram, more detailed activity diagrams were formed that focus on a few of the key value stream exchanges, showing the process by which each party accrues value. These diagrams provide insight into the timing and sequence of the interactions in a way that the business value diagrams did not. The transactive value model was found to be highly compatible with IRP and provided a clear, simple model of the analysis done during IRP and key metrics driving IRP decisions. In particular it highlighted a few key items that may or may not have been as clear prior to the development of the model. Specifically, the role of the environmental regulations has become increasingly important and two of the three key metrics by which IRPs are typically evaluated are environmentally focused. Additionally, though generally not acknowledged, the role of the investor was included in this model as they are an essential source of capital in building new power plants and cannot be ignored when defining the business case of the vertically integrated utility.

24 POWER TRANSMISSION AND DISTRIBUTION↗
DOE OSTI2019

NRT Design Verification Test Plan

The National Rotor Testbed (NRT) design verification experiment is the first test of the new NRT blades retrofitted to the existing Vestas V27 hub and nacelle operated at the Sandia Scaled Wind Farm Technology (SWiFT) facility. This document lays out a plan for pre-assembly, ground assembly, installation, commissioning, and flight testing the NRT rotor. Its performance will be quantified. Adjustments to torque constant and collective blade pitch will be made to ensure that the tip-speed-ratio and span-wise loading are as close to the NRT design as possible. This will ensure that the NRT creates a scaled wake of the GE 1.5sle turbine. Upon completion of this test, the NRT will be in an operational state, ready for future experiments.

17 WIND ENERGY↗
DOE OSTI2019

Low-Cost Multi-Modal Wireless Sensor Platform for Smart Buildings

Buildings consume 73% of the energy produced in the United States [1, 2]. Advanced sensors, controls, and communications have the potential to reduce the energy consumption of buildings by 20–40% [3, 4]. Currently, installation and wiring costs for sensors are quite high, making it cost-prohibitive for building managers to deploy large quantities of advanced sensors [5]. Wireless sensors have recently been deployed in buildings to provide the information necessary for optimal control of heating, ventilation, and air-conditioning and lighting systems [6, 7]. Wireless sensors have the unique advantage of being suitable for easily retrofitting existing buildings at a minimal labor cost, and the flexibility to be placed at optimal, observable locations. However, current commercially available wireless sensors are still very expensive ($150–300/node). Thus, revolutionary technological improvements in wireless sensors are required to promote inherently low-cost manufacturing for building applications to successfully exploit the energy efficiency opportunities in buildings.In this report, we present the efforts carried out at Oak Ridge National Laboratory and Molex Inc. toward exploring the design, implementation, and performance evaluation of low-cost, self-powered wireless sensors—including temperature, relative humidity, occupancy, and indoor air quality sensors—to enable advanced control applications that reduce energy consumption in buildings. Our focus is to demonstrate a novel multifunctional sensor platform that will evolve with advances in materials technology, low-cost printing techniques, nano-antennas, and co-integration of monitoring, control, and communication circuitry. We also present a low-power and bandwidth-efficient wireless communication technology that can be driven by energy harvesting in self-powered wireless sensors. It is based on code-phase-shift keying (CPSK) spread-spectrum signaling that improves both transmitter range and power consumption. The objective is to minimize the number of components within the wireless transceiver and reduce power consumption to allow sensor networks powered by energy harvesting, thus eliminating the expense and effort of periodically replacing the sensor batteries. Current state-of-the-art radio technologies have demonstrated 25–30 mA current consumption for the transmitter. Our prototype demonstrations lowered the consumption to 4 mA using spread-spectrum-based CPSK so that solar cells can be used with indoor lighting to recharge a battery indefinitely. Therefore, the system can run with no attention or maintenance for the life of the components, which is expected to be 20 years. The developed technology has the potential to generate fully printable wireless sensors with costs on the order of $1–10/node.

32 ENERGY CONSERVATION, CONSUMPTION, AND UTILIZATI↗
DOE OSTI2019

Efficiency-Optimized Dual Fuel Engine with In-Cylinder Gasoline/CNG Blending

The objective of the proposed project is to demonstrate targeted blending of gasoline and natural gas as a means to reduce petroleum consumption of light-duty spark-ignition engine vehicles by at least 50%. This goal will be achieved through petroleum displacement with natural gas (NG) combined with a relative engine efficiency improvement in excess of 10% while meeting retrofitability requirements with an anticipated payback period of less than 36 months. Further through NG direct injection (DI) a 10% improvement in power density over the PFI baseline will be demonstrated. The proposed project employs a sound R&D approach and combines experimental work with state-of-the-art computational modeling to be able to demonstrate the ambitious project goals. The project spans a 30 month period and is divided in 3 phases with the initial phase focused on experimental characterization of the gaseous jet structure of the high-pressure NG DI injector which is used to validate the 3D-CFD simulation tool. The phase also includes an experimental demonstration of the fundamental feasibility of the proposed dual-fuel approach on an automotive single-cylinder research engine. The scope of the second phase includes optimization of the combustion system by means of virtual design combined with 3D-CFD analysis. The resulting optimized combustion system will be built and experimentally evaluated by the end of the 12 month period. The third and final phase expands the scope by integrating the engine results in a vehicle level simulation tool with the objective of developing an optimized engine control strategy that maximizes the efficiency benefits attainable with the limited on-board NG supplies. A detailed cost analysis to verify that the 36 month amortization period requirement is met will conclude the proposed effort.

42 ENGINEERING↗
DOE OSTI2019

Coatings and Process Development for Reduced Energy Automotive OEM Manufacturing Final Technical Report

The project team successfully developed a new low-temperature coating system that achieves performance, durability, and appearance requirements for an Automotive Original Equipment Manufacturer paint system. This coating system is compatible with current OEM manufacturing paint lines, allowing application to existing manufacturing locations. The new coating system can also save capital expenses for new lines or renovations of existing lines. The new paint system enable energy savings and operational expense savings. DURR has designed a reference system that can serve as the starting point for new or retrofit paint line upgrades to this low temperature coating system. NDSU has developed and demonstrated the value of high-throughput screening for polymers and cure performance.

37 INORGANIC, ORGANIC, PHYSICAL, AND ANALYTICAL CH↗
DOE OSTI2014

CO 2 Capture with Ionic Liquids Involving Phase Change (Final Report)

Coal-fired power plants provide nearly 50% of all electricity in the U.S. While coal is a cheap and abundant natural resource, its continued use contributes to rising carbon dioxide (CO 2 ) levels in the atmosphere. Capturing and storing this CO 2 would reduce atmospheric greenhouse gas levels while allowing power plants to continue using inexpensive coal. Carbon capture and storage represents a significant cost to power plants that must retrofit their existing facilities to accommodate new technologies. Reducing these costs is the primary objective of ARPA-E's carbon capture program. Researchers at the University of Notre Dame and their partners at Matric developed a new CO 2 capture process that uses materials that we call Phase Change Ionic Liquids (PCILs). PCILs are solid at the temperature of the CO 2 absorption but change to liquid when they bind with CO 2 . The PCILs have a high capacity for CO 2 at post-combustion flue gas pressures and temperatures because of a chemical reaction between the CO 2 and the PCIL. Upon heating, the CO 2 is released, and the PCILs re-solidify. The heat released in the solidification process reduces the amount of external heat that must be added. As with conventional CO 2 capture processes, the PCIL process has an absorber and a regenerator. Computer simulation of the process enabled calculation of viable process conditions and power needs. The main concepts of the process were demonstrated using lab-scale apparatus. Capture of CO 2 was carried out using a sieve tray column in continuous mode. Desorption of the CO 2 in the regenerator occurred while the liquid droplets solidified. The key to making this process viable was the use of a mixture of the complexed liquid with the unreacted solid particles in the absorber. This mixture formed a well-behaved slurry that flowed readily. Therefore, handling of solid particles is avoided in the process. Parasitic power was decreased by 55% from the amount required by the monoethanolamine (MEA) process. For the PCIL process, parasitic power is only 23% of the net power generated by the plant, which is remarkably close to the 19% DOE target. The capital cost for the CO 2 capture unit is higher for the PCIL process than the MEA process. Nonetheless, the overall increase in the cost of electricity (COE) is dramatically lower - only 4.1¢/kWh for the PCIL process compared with 5.7¢/kWh for the MEA process. The cost of CO 2 avoided is $48/ton of CO 2 . As a result, we conclude that CO 2 capture with phase change ionic liquids is an exceedingly promising technology.

01 COAL, LIGNITE, AND PEAT↗
DOE OSTI2019

Experimental and numerical evaluations of the energy savings potential of thermally anisotropic composites

Previous numerical studies conducted in FY 17 showed that the application of thermally anisotropic composites (TACs) coupled with a heat sink/source can re-direct and reduce unwanted heat flows through exterior building walls, with associated reductions in envelope-generated heating and cooling loads in buildings. The numerical analyses included two-dimensional finite element models (FEM) of wall assemblies and whole-building modeling to estimate the annual reductions in wall-generated heating and cooling loads, and associated energy consumption. The FY17 study used combined FEM and EnergyPlus (E+) simulations of a typical two-story, single-family DOE prototype residential building model.1 We studied performance of several configurations of walls containing exterior continuous insulation and thermally anisotropic composites on the wall exterior. The study showed that annual energy cost savings of up to $270 are possible under Phoenix and Baltimore weather conditions, by retrofitting a baseline wall with an anisotropic composite. In the cases considered, the TAC consisted of three layers of aluminum foil-faced foam boards. In general, it was found that the anisotropic composites were effective in reducing cooling loads; more investigation on heating loads is needed. During FY 18, ORNL performed a series of laboratory tests of anisotropic composites and appropriate heat sink/source, validated the FEMs used for the FY17 numerical study using experimental data, and revisited the whole-building modeling. Wall prototypes were created and tested in ORNL’s large scale climate simulator (LSCS) under variable conditions approximating summer and winter time periods.

32 ENERGY CONSERVATION, CONSUMPTION, AND UTILIZATI↗
DOE OSTI2019

Integrated Commercial Carbon Capture and Storage (CCS) Prefeasibility Study at Rock Springs Uplift, Wyoming (Final Report)

To establish the potential of safe, long-term commercial-scale carbon capture & storage (CCS) in southwestern Wyoming, the University of Wyoming formed a CCS coordination team (CCT) to complete a Phase I CarbonSAFE pre-feasibility study adjacent to the region’s largest coal-fired power plant, the Jim Bridger Plant (JBP). The study’s primary objective was to evaluate the potential of storing 50+ million metric tons of anthropogenic carbon dioxide (CO 2 ) in stacked reservoirs over a period of 25 years. In addition, this integrated study evaluated related aspects of carbon capture utilization & storage (CCUS) at the study site, including: (1) the CO 2 character of post-combustion flue gas from JBP and the technical capacity for retrofitting proven commercial-scale CO 2 capture technology relative to CO 2 source character and technological constraints; (2) utilization of the existing CO 2 pipeline network in the immediate vicinity of JBP for enhanced oil recovery (CO 2 -EOR) and utilizing that network as part of a regional hub for CO 2 storage from other anthropogenic sources; (3) assessment of the challenges and benefits of meeting all of CarbonSAFE programmatic Phase I goals relative to Wyoming’s carbon management regulatory framework; and (4) assessment of the community and environmental factors that may impact CCS at JBP. With respect to storage, we analyzed the potential of stacked Mesozoic reservoirs at the study site, focusing on the Entrada and Nugget sandstones. The reservoir response to injection simulations varied greatly between formations, though they both were capable of CO 2 storage. The Entrada Sandstone is relative thin (~40’) and heterogeneous; storage using one injection and production well was limited to 1.2 Mt over 25 years at the study site. The Nugget Sandstone is much thicker (> 400’) and generally homogeneous; storage using one injection and production well approached 15.0 Mt over 25 years; this scenario suggests that the storage potential in the Nugget Sandstone is close to the estimated P90 calculation of 9.6 Mt/mi 2 as models indicate a storage potential of 8.3 Mt/mi 2 at saturation. Both reservoirs’ storage capacity benefited greatly from coupling an injection well with an offset production well; total storage capacity increased and reservoir pressure stayed below critical thresholds. This indicates that implementing a pressure management strategy at the study site would optimize storage and decrease risk. Seals associated with the targeted reservoirs were shown to be capable of retaining the potential storage volumes, and the site benefits from multiple seal redundancies (i.e. > 7,000’ of seal formations). Furthermore, assessment of different reservoir variables (e.g., fluid composition, pressure, etc.) indicates all reservoirs at the study site are isolated. Storage assessments from Mesozoic reservoirs were coupled with simulations from the site’s Paleozoic reservoirs (the Weber Sandstone and Madison Limestone), which were the focus of previous study. The fully integrated stacked reservoir pre-feasibility studies suggest that the Nugget and Madison formations alone could safely store 50 million metric tons of CO 2 within the study site. Furthermore, both formations are true saline reservoirs near JBP, making them ideal target reservoirs for CO 2 sequestration. Analysis of Wyoming’s laws and regulations confirm that the State has a favorable policy environment for CCS/CCUS. The project’s economic models estimated that the following revenues collectively are sufficient to finance the project over its lifespan if CO 2 utilization is coupled with CCS via the following strategies: (1) sales of CO 2 for EOR (approximately $69 million/year); (2) use of CO 2 tax credits such as amended §45Q and §48A (approximately $484 million total); and (3) sales of low-carbon electricity and marketable carbon offset/credits into carbon-constrained markets (approximately $11-$17 million/year) to West Coast consumers. These revenue estimates are broadly consistent with other studies that concluded arbitrage in JBP retail electricity sales between California and Wyoming could help to support the cost of deploying CCS at JBP. The models also indicate that maintaining a successful business case for long-term CCS -- wherein associated capture, transportation and operational costs are fully addressed at JBP -- is reliant on numerous external factors that complicate predictions. This study suggests that this site meets the CarbonSAFE program’s requirements of being able to feasibly store 50+ million metric tons of CO 2 over 25 years within the site’s stacked reservoirs, especially if coupled with pressure management strategies. This study suggests that the Nugget Sandstone and the Madison Limestone are two of the best reservoirs in the State with respect to overall storage capacity. In addition, the site’s proximity to existing CO 2 transportation networks, CO 2 -EOR opportunities, ability to sell to markets that value low-carbon electricity, Wyoming’s existing carbon regulatory framework, and a public that is well-educated with respect to energy markets and issues collectively increase the potential for implementing commercial-scale CCS adjacent to the JBP. With respect to the available technical and non-technical site data, and the reservoir quality at the study site, we suggest that this site is capable of moving directly into Phase III of the CarbonSAFE program.

01 COAL, LIGNITE, AND PEAT↗
DOE OSTI2019

Weatherization Crew Leader Job Task Analysis

The US Department of Energy's Guidelines for Home Energy Professionals project maintains job task analyses for jobs in the Weatherization Assistance Program and home performance industry. One of those jobs is Crew Leader, defined as: 'A Crew Leader is responsible for supervising and assisting in the retrofitting activities specified in the scope of work. He or she is responsible for interacting with the client plus managing personnel and materials on the job site in a safe and effective manner. The Crew Leader is responsible for quality control, testing procedures, documentation, and conducting a walk through in preparation that all work is completed in a satisfactory manner.' This document is an updated version of the Crew Leader job task analysis.

29 ENERGY PLANNING, POLICY, AND ECONOMY↗
DOE OSTI2019

Making Coal Relevant for Small Scale Applications: Modular Gasification for Syngas/Engine CHP Applications in Challenging Environments

This Front-End Engineering Design (FEED) study is funded by the US Department of Energy (DOE), and managed by the National Energy Technology Laboratory (NETL) through a Cooperative Agreement awarded to the University of Alaska Fairbanks (UAF) to perform a technical and cost study for the design and installation of a Hamilton-Maurer International (HMI) gasifier for generating a clean syngas for firing in reciprocating engines. An existing diesel engine generator (DEG) and a commercially available spark ignition engine are used to generate electricity with the low-Btu syngas. Other than the HMI gasifier, only commercially available technologies were assumed for this study. An important objective of this design study was to estimate capital and operating costs of small modular coal and coal/biomass fired generating units to provide wind regulation services. Although this study is based on retrofitting an existing coal fired power plant with the HMI gasifier, sufficient data was developed to characterize greenfield units. The original concept was to provide clean syngas and tars/oils from the gasification process to the existing Colt-Pielstick PC2.6B diesel engine generator (9.6 MWe) installed at the UAF Atkinson Power Plant. The intent was to convert the diesel engine to operate in a dual fuel mode, firing both syngas and tars/oils. As the project progressed, Fairbanks Morse Engine (FME), current licensee for the Colt-Pielstick engine line, was not able to develop a modification package for the engine to allow for syngas firing. Although this type of modification is available for firing natural gas, the capability does not extend to syngas. Western Energy Systems, distributor for Innio Jenbacher, was able to offer the Jenbacher Model JMS620 engine. After review of available options, the project team selected a design configuration using two Jenbacher engines rated at 1965 kWe each to fire the syngas, with the oils/tars directed to the Colt Pielstick diesel to be blended with ultra-low sulfur diesel oil (ULSD). The Jenbacher engines are expected to operate at continuous base load, with some load-following ability, while the existing diesel engine will operate in grid support service, with loads varying from a nominal 25% to 100%. An annual capacity factor for the diesel engine is projected to be between 50% and 60%. The overall gasifier and gas clean-up system is sized to produce enough syngas to adequately fuel three Jenbacher Engines for a nominal power output of 5.9 MWe, but this study assumes that only two Jenbacher engines will be installed due to space constraints in the Atkinson Power Plant, and because of expected air emission permit limitations. There is still potential that the excess syngas capacity equivalent to about 2 MWe could be used as supplemental fuel for the DEG. The exhaust from the Jenbacher engines is passed through heat recovery units to generate low pressure steam, thereby providing a significant portion of the steam required for operating the gasifier. The overall performance of the HMI gasifier/engine configuration is summarized as follows: 1) Overall electric efficiency, Jenbacher and diesel engines, based on gasifier fuel production (syngas and pyrolysis liquids) is 35.2% LHV, 2) Overall cogenerating efficiency (electricity plus steam), based on gasifier fuel production (syngas and pyrolysis liquids) is 54.8% LHV, 3) Overall electric efficiency, Jenbacher and diesel engines, based on coal input, is 29.6% LHV, and 4) Overall cogenerating efficiency, electricity plus steam, based on coal input is 46.0%. This project is estimated to have a Bare Erected Cost (BEC) of $\$$ 33.4 million and a Total Plant Cost (TPC) of $\$$ 45.7 million. Based on the original scope, sending both the clean syngas and the oils and tars to the existing diesel engine, the BEC and TPC values would have been $\$$ 23.3 million and $\$$ 32.1 million, respectively. A variable Cost of Electricity (COE) is calculated to reflect only those costs that will be incurred by incremental operation of the system for the HMI gasifier/Jenbacher engine combination. Operation of the diesel engine is determined separately. The variable COE values are: Case 1: 100% Usibelli Coal: (a) HMI gasifier/Jenbacher Engines -- 8.3 cents/kWh; (b) Diesel Engine -- 20.2 cents/kWh, and Case 2: 80% Usibelli Coal + 20% wood chips (proportion based on Btu input, LHV basis): (a) HMI Gasifier/Jenbacher -- 13.7 cents/kWh; (b) Diesel Engine -- 20.2 cents/kWh. The incremental cost of operating the gasifier/Jenbacher system increases with co-firing of wood chips due to the high cost of this material, over five times as costly as Usibelli coal delivered to the Atkinson Power building. The diesel cost is constant as the oils and tars are priced at the same value as the ULSD for the purposes of fueling the diesel engine. Section 8 of this report provides details of the O&M costs. The overall power system is configured to be modular and scalable to provide a wide range of generating capacity using the same components. This allows for reduction in cost, risk, schedule time to engineer and construct, and provides some degree of repeatability for air permitting.

01 COAL, LIGNITE, AND PEAT↗
DOE OSTI2019

An Assessment of Hydropower Environmental Mitigation Costs

This report provides an assessment of environmental mitigation costs for hydropower projects across the United States (U.S.) based on data extracted from Environmental Assessments (EA) submitted to the Federal Energy Regulatory Commission (FERC). EAs are required by the Federal Power Act (FPA) for hydropower license and relicense applications to weigh the “power” and “non-power” (i.e. environmental) benefits of their development and operation. For this analysis, we collected data from 184 EA documents reviewed by FERC between 1996 and 2018, and created a database of environmental protection, mitigation, and enhancement (PM&E) measures with their associated economic information. The data cover two hydropower relicense categories—103 Relicensed Conventional Hydropower Dams (RCHD) and 6 Relicensed Pumped Storage Hydropower (RPSH) projects—and three new development categories—57 hydropower retrofits at Non-Powered Dams (NPD), 11 New Stream-Reach Development (NSD) projects and 6 Pumped Storage Hydropower (NPSH) projects. For the analysis, we classify the PM&E measures into 11 Tier 1 categories. We evaluated capital and operations & maintenance (O&M) costs of PM&E measures on a $\$$/kW basis by project type and mitigation category, as well as their share in the total project levelized cost of energy (LCOE).

13 HYDRO ENERGY↗