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Measurements of 222 Rn, 220 Rn, and CO 2 Emissions in Natural CO 2 Fields in Wyoming: MVA Techniques for Determining Gas Transport and Caprock Integrity

An integrated field-laboratory program evaluated the use of radon and CO 2 flux measurements to constrain source and timescale of CO 2 fluxes in environments proximate to CO 2 storage reservoirs. By understanding the type and depth of the gas source, the integrity of a CO 2 storage reservoir can be assessed and monitored. The concept is based on correlations of radon and CO 2 fluxes observed in volcanic systems. This fundamental research is designed to advance the science of Monitoring, Verification, and Accounting (MVA) and to address the Carbon Storage Program goal of developing and validating technologies to ensure 99 percent storage performance. Graduate and undergraduate students conducted the research under the guidance of the Principal Investigators; in doing so they were provided with training opportunities in skills required for implementing and deploying CCS technologies. Although a final method or “tool” was not developed, significant progress was made. The field program identified issues with measuring radon in environments rich in CO 2 . Laboratory experiments determined a correction factor to apply to radon measurements made in CO 2 -bearing environments. The field program also identified issues with radon and CO 2 -flux measurements in soil gases at a natural CO 2 analog. A systematic survey of radon and CO 2 flux in soil gases at the LaBarge CO 2 Field in Southwest Wyoming indicates that measurements of 222 Rn (radon), 220 Rn (thoron), and CO 2 flux may not be a robust method for monitoring the integrity of a CO 2 storage reservoir. The field program was also not able to correlate radon and CO 2 flux in the CO 2 -charged springs of the Thermopolis hydrothermal system. However, this part of the program helped to motivate the aforementioned laboratory experiments that determined correction factors for measuring radon in CO 2 -rich environments. A graduate student earned a Master of Science degree for this part of the field program; she is currently employed with a geologic consulting company. Measurement of radon in springs has improved significantly since the field program first began; however, in situ measurement of 222 Rn and particularly 220 Rn in springs is problematic. Future refinements include simultaneous salinity measurements and systematic corrections, or adjustments to the partition coefficient as needed for more accurate radon concentration determination. A graduate student earned a Master of Science degree for this part of the field program; he is currently employed with a geologic consulting company. Both graduate students are poised to begin work in a CCS technology area. Laboratory experiments evaluated important process-level fundamentals that effect measurements of radon and CO 2 . Laboratory tests established that fine-grained source minerals yield higher radon emissivity compared to coarser-sized source minerals; subtleties in the dataset suggest that grain size alone is not fully representative of all the processes controlling the ability of radon to escape its mineral host. Emissivity for both 222 Rn and 220Rn increases linearly with temperature due to reaction of rocks with water, consistent with faster diffusion and enhanced mineral dissolution at higher temperatures. The presence of CO 2 changes the relative importance of the factors that control release of radon. Emissivity for both 222 Rn and 220 Rn in CO 2 -bearing experiments is greater at all temperatures compared to the experiments without CO 2 , but emissivity does not increase as a simple function of temperature. Governing processes may include a balance between enhanced dissolution versus carbonate mineral formation in CO 2 -rich waters.

12 MANAGEMENT OF RADIOACTIVE AND NON-RADIOACTIVE W↗

Development and Implementation of the Midwest Geological Sequestration Consortium CO 2 -Technology Transfer Center

In 2009, the Illinois State Geological Survey (ISGS), in collaboration with the Midwest Geological Sequestration Consortium (MGSC), created a regional technology training center to disseminate carbon capture and sequestration (CCS) technology gained through leadership and participation in regional carbon sequestration projects. This technology training center was titled and branded as the Sequestration Training and Education Program (STEP). Over the last six years STEP has provided local, regional, national, and international education and training opportunities for engineers, geologists, service providers, regulators, executives, K-12 students, K-12 educators, undergraduate students, graduate students, university and community college faculty members, and participants of community programs and functions, community organizations, and others. The goal for STEP educational programs has been on knowledge sharing and capacity building to stimulate economic recovery and development by training personnel for commercial CCS projects. STEP has worked with local, national and international professional organizations and regional experts to leverage existing training opportunities and provide stand-alone training. This report gives detailed information on STEP activities during the grant period (2009-2015).

96 KNOWLEDGE MANAGEMENT AND PRESERVATION↗

Intrinsic Fiber Optic Chemical Sensors for Subsurface Detection of CO 2

Intelligent Optical Systems, Inc. has developed distributed intrinsic fiber optic sensors to directly quantify the concentration of dissolved or gas-phase CO 2 for leak detection or plume migration in carbon capture and sequestration (CCS). The capability of the sensor for highly sensitive detection of CO 2 in the pressure and temperature range of 15 to 2,000 psi and 25°C to 175°C was demonstrated, as was the capability of operating in highly corrosive and contaminated environments such as those often found in CO 2 injection sites. The novel sensor system was for the first time demonstrated deployed in a deep well, detecting multiple CO 2 releases, in real time, at varying depths. Early CO 2 release detection, by means of a sensor cable integrating multiple sensor segments, was demonstrated, as was the capability of quantifying the leak. The novel fiber optic sensor system exhibits capabilities not achieved by any other monitoring technology. This project represents a breakthrough in monitoring capabilities for CCS applications.

54 ENVIRONMENTAL SCIENCES↗

Final report of “A Detailed Study of the Physical Mechanisms Controlling CO2-Brine Capillary Trapping in the Subsurface” (University of Arizona, DE-SC0006696)

Carbon capture and storage (CCS) of carbon dioxide emissions generated by production or combustion of fossil fuels is a technologically viable means to reduce the build-up of CO2 in the atmosphere and oceans. Using advantages of scale and location, CCS is particularly suitable for large point sources near ubiquitous deep saline aquifers, depleted gas reservoirs, or at production reservoirs for enhanced oil recovery (EOR). In the BES-funded research project, Oregon State University (OSU) carried out capillary trapping experiments with proxy fluids that mimic the properties of the scCO2/brine system under ambient temperatures and pressures, and successfully developed a unique and novel x-ray compatible, high-pressure, elevated temperature setup to study the scCO2/brine system under challenging reservoir conditions. Both methodologies were applied to a variety of porous media, including synthetic (glass bead) and geologic (Bentheimer sandstone) materials. The University of Arizona (UA) developed pore-scale lattice Boltzmann (LB) models which are able to handle the experimental conditions for proxy fluids, as well as the scCO2/brine system, that are capable of simulating permeability in volumes of tens of millions of fluid elements. We reached the following summary findings (main institute indicated): 1. (OSU/UA) To understand capillary trapping in a multiphase fluid-porous medium system, the system must be analyzed from a pore-scale force balance perspective; trapping can be enhanced by manipulating wetting and nonwetting phase fluid properties. 2. (OSU) Pore-scale fluid connectivity and topology has a clear and direct effect on nonwetting phase capillary trapping efficiency. 3. (OSU) Rock type and flow regime also have a pronounced effects on capillary trapping. 4. (OSU/UA) There is a predictable relationship between NWP connectivity and NWP saturation, which allows for development of injection strategies that optimize trapping. The commonly used Land model (Land, 1968) does not predict amount of trapped NWP accurately. 5. (UA) There are ambiguities regarding the segmentation of large-volume gray-scale CT data into pore-volumes suitable for pore-scale modeling. Simulated permeabilities vary by three orders of magnitude and do not resemble observed values very well. Small-volume synchrotron-based CT data (such as produced by OSU) does not suffer significantly from segmentation ambiguities. 6. (UA) A standard properly parameterized Shan-Chen model LB model is useful for simulating porous media with proxy fluids as well as the scCO2/brine system and produces results that are consistent with tomographic observations. 7. (UA) A LB model with fluid-interactions defined by a (modified) Peng-Robinson Equation of State is able to handle the scCO2/brine system with variable solid phase wettability. This model is numerically stable at temperatures between 0 and 250 °C and pressures between 3 and 50 MPa, and produces appropriate densities above the critical point of CO2 and exhibits three-phase separation below. Based on above findings OSU and UA have proposed continued experimentation and pore-scale modeling of the scCO2/brine system. The reported research has extensively covered capillary trapping using proxy fluids, but due to limited beam-time availability we were unable to apply our high-pressure CO2 setup to sufficient variation in fluid properties, and initial scCO2 connectivity. New data will also allow us to test, calibrate and apply our LB models to reservoir conditions beyond those that are currently feasible experimentally. Such experiments and simulations will also allow us to provide information how suitable proxy fluids are for the scCO2/brine system. We believe it would be worthwhile to pursue the following new research questions: 1. What are the fundamental differences in the physics underlying capillary trapping at ambient vs. supercritical conditions? 2. Do newly developed pore-scale trapping interactions and relationships translate to continuum scales? A motivation for these questions was elaborated in “Capillary Trapping of Super-Critical CO2: Linking Pore and Continuum Scales to Verify new Relationships” that was submitted to DOE-BES in 2015.

20 FOSSIL-FUELED POWER PLANTS↗

Low-Probability High-Consequence (LPHC) Failure Events in Geologic Carbon Sequestration Pipelines and Wells: Framework for LPHC Risk Assessment Incorporating Spatial Variability of Risk

If Carbon dioxide Capture and Storage (CCS) is to be effective in mitigating climate change, it will need to be carried out on a very large scale. This will involve many thousands of miles of dedicated high-pressure pipelines in order to transport many millions of tonnes of CO 2 annually, with the CO 2 delivered to many thousands of wells that will inject the CO 2 underground. The new CCS infrastructure could rival in size the current U.S. upstream natural gas pipeline and well infrastructure. This new infrastructure entails hazards for life, health, animals, the environment, and natural resources. Pipelines are known to rupture due to corrosion, from external forces such as impacts by vehicles or digging equipment, by defects in construction, or from the failure of valves and seals. Similarly, wells are vulnerable to catastrophic failure due to corrosion, cement degradation, or operational mistakes. While most accidents involving pipelines and wells will be minor, there is the inevitable possibility of accidents with very high consequences, especially to public health. The most important consequence of concern is CO 2 release to the environment in concentrations sufficient to cause death by asphyxiation to nearby populations. Such accidents are thought to be very unlikely, but of course they cannot be excluded, even if major engineering effort is devoted (as it will be) to keeping their probability low and their consequences minimized. This project has developed a methodology for analyzing the risks of these rare but high-consequence accidents, using a step-by-step probabilistic methodology. A key difference between risks for pipelines and wells is that the former are spatially distributed along the pipe whereas the latter are confined to the vicinity of the well. Otherwise, the methodology we develop for risk assessment of pipeline and well failures is similar and provides an analysis both of the annual probabilities of accident sequences of concern and of their consequences, and crucially the methodology provides insights into what measures might be taken to mitigate those accident sequences identified as of concern. Mitigating strategies could address reducing the likelihood of an accident sequence of concern, or reducing the consequences, or some combination. The methodology elucidates both local and integrated risks along the pipeline or at the well providing information useful to decision makers at various levels including local (e.g., property owners and town councils), regional (e.g., county and state representatives), and national levels (federal regulators and corporate proponents).

54 ENVIRONMENTAL SCIENCES↗

Feasibilities of a Coal-Biomass to Liquids Plant in Southern West Virginia

This project has generated comprehensive and realistic results of feasibilities for a coal-biomass to liquids (CBTL) plant in southern West Virginia; and evaluated the sensitivity of the analyses to various anticipated scenarios and parametric uncertainties. Specifically the project has addressed economic feasibility, technical feasibility, market feasibility, and financial feasibility. In the economic feasibility study, a multi-objective siting model was developed and was then used to identify and rank the suitable facility sites. Spatial models were also developed to assess the biomass and coal feedstock availabilities and economics. Environmental impact analysis was conducted mainly to assess life cycle analysis and greenhouse gas emission. Uncertainty and sensitivity analysis were also investigated in this study. Sensitivity analyses on required selling price (RSP) and greenhouse gas (GHG) emissions of CBTL fuels were conducted according to feedstock availability and price, biomass to coal mix ratio, conversion rate, internal rate of return (IRR), capital cost, operational and maintenance cost. The study of siting and capacity showed that feedstock mixed ratio limited the CBTL production. The price of coal had a more dominant effect on RSP than that of biomass. Different mix ratios in the feedstock and conversion rates led to RSP ranging from $104.3 - $157.9/bbl. LCA results indicated that GHG emissions ranged from 80.62 kg CO 2 eq to 101.46 kg CO2 eq/1,000 MJ of liquid fuel at various biomass to coal mix ratios and conversion rates if carbon capture and storage (CCS) was applied. Most of water and fossil energy were consumed in conversion process. Compared to petroleum-derived-liquid fuels, the reduction in GHG emissions could be between -2.7% and 16.2% with CBTL substitution. As for the technical study, three approaches of coal and biomass to liquids, direct, indirect and hybrid, were considered in the analysis. The process models including conceptual design, process modeling and process validation were developed and validated for different cases. Equipment design and capital costs were investigated on capital coast estimation and economical model validation. Material and energy balances and techno-economic analysis on base case were conducted for evaluation of projects. Also, sensitives studies of direct and indirect approaches were both used to evaluate the CBTL plant economic performance. In this study, techno-economic analysis were conducted in Aspen Process Economic Analyzer (APEA) environment for indirect, direct, and hybrid CBTL plants with CCS based on high fidelity process models developed in Aspen Plus and Excel. The process thermal efficiency ranges from 45% to 67%. The break-even oil price ranges from $86.1 to $100.6 per barrel for small scale (10000 bbl/day) CBTL plants and from $65.3 to $80.5 per barrel for large scale (50000 bbl/day) CBTL plants. Increasing biomass/coal ratio from 8/92 to 20/80 would increase the break-even oil price of indirect CBTL plant by $3/bbl and decrease the break-even oil price of direct CBTL plant by about $1/bbl. The order of carbon capture penalty is direct > indirect > hybrid. The order of capital investment is hybrid (with or without shale gas utilization) > direct (without shale gas utilization) > indirect > direct (with shale gas utilization). The order of thermal efficiency is direct > hybrid > indirect. The order of break-even oil price is hybrid (without shale gas utilization) > direct (without shale gas utilization) > hybrid (with shale gas utilization) > indirect > direct (with shale gas utilization).

01 COAL, LIGNITE, AND PEAT↗

Large Pilot CAER Heat Integrated Post-combustion CO 2 Capture Technology for Reducing the Cost of Electricity

The goal of this final project report is to comprehensively summarize the work conducted on project DE-FE0026497. In accordance with the Statement of Project Objectives (SOPO), the University of Kentucky Center for Applied Energy Research (UKy-CAER) (Recipient) has developed an advanced, versatile, 10 MWe post-combustion CO 2 capture system (CCS) for a coal-fired power plant, Louisville Gas and Electric Company’s Trimble County Generating Station, using a heat integrated process combined with two-stage stripping and any advanced solvent to enhance the CO 2 absorber performance. The proposed project (Phase 1 and 2) will involve the design, fabrication, installation and testing of a large pilot scale facility that will demonstrate the UKy-CAER innovative carbon capture system integrated with an operating supercritical power plant. Specifically during Phase 1, the Recipient has provided all necessary documentation to support its Phase 2 down-selection including: the Project Narrative, the updated Project Management Plan (PMP), the preliminary engineering design, the Technical and Economic Analysis report (TEA) (including the Case 12 – Major Equipment List and submitted as a Topical Report), a Phase 1 Technology Gap Analysis (TGA), an Environmental Health and Safety (EH&S) Assessment on the 10 MWe unit, and updated Phase 2 cost estimates (including the detailed design, procurement, construction, operation, and decommissioning costs) with a budget justification. Furthermore, the Recipient has proposed a combined modular and freestanding column configuration with an advanced absorber gas/liquid distribution system, an advanced solvent, with the integration of discrete packing, a smart cross-over heat exchanger, and a load and ambient condition following control strategy, all to address ten of 12 technology gaps identified during the Phase I work. If successful, the proposed heat integrated post-combustion CCS will pave the way to achieve the United States Department of Energy National Energy Technology Laboratory (U.S. DOE NETL) CO 2 capture performance and cost target, as indicated in the submitted TEA and summarized in this report.

01 COAL, LIGNITE, AND PEAT↗

Technical Advisor to the American Indian Research and Education Initiatives (AIREI).

The American Indian Research & Education Initiative (AIREI) is a pilot program that started in 2011 and is funded by the US Department of Energy (DOE) Economic Impact & Diversity and National Nuclear Security Administration in partnership with the American Indian Higher Education Consortium (AIHEC) and the American Indian Science and Engineering Society. AIREI brings science, technology, engineering, and mathematics (STEM) research and education funding to Tribal Colleges and Universities (TCU) and other US universities. AIREI has funded eight schools, including four pairs of tribal colleges and mainstream universities, in order for student and faculty research teams to bring energy projects to tribal lands. The research team from Southwest Indian Polytechnic Institute (SIPI) and Northern Arizona University (NAU) has performed a student-centric research and analysis feasibility study of a potential utility-scale solar power plant on the Jemez Pueblo reservation trust land. The research team from Navajo Technical University (NTU) and Arizona State University (ASU) has assessed the effectiveness of solar photovoltaic (PV) system designs in meeting the electricity demands of Navajo Tribal homes and public buildings in addition to the development of a solar technology curriculum that incorporates the outcomes of this study, helping to advance PV system design and installations on local Tribal lands. The Little Big Horn College (LBHC) and Montana State University-Bozeman (MSUB) team has developed fast growing strains of nitrogen-fixing cyanobacteria to help advance carbon capture and sequestration (CCS) technologies. The research supported the Crow Nation reservation as it evaluates opportunities for coal-to-liquid fuel and CCS projects. The Sinte Gleska University (SGU) and South Dakota School of Mines (SDSM) team developed computer modeling and simulation technologies to evaluate the feasibility of oil and gas development from the Niobrara Formation on the Rosebud Sioux reservation. Through this project, the students developed skills in applied energy-related research involving computer simulation, chemistry, geology, and petroleum engineering. AIREI supports collaboration between these universities and connects the teams with the technological expertise and mentorship opportunities provided through Sandia National Laboratories (Sandia). AIHEC consists of 37 American Indian tribally controlled colleges around the nation and provides technical assistance through professional development workshops, strategic planning meetings, and information sharing strategies.

99 GENERAL AND MISCELLANEOUS↗

Lignite-plus-Biomass to Synthetic Jet Fuel with CO2 Capture and Storage: Design, Cost, and Greenhouse Gas Emissions Analysis for a Near-Term First-of-a-Kind Demonstration Project and Prospective Future Commercial Plants

We report on a 30-month design study for a first-of-a-kind (FOAK) demonstration plant that would be built at a site near Meridian, Mississippi, to coprocess lignite coal and woody biomass into jet fuel. The design uses an oxygen-blown TRIG™ gasifier developed by KBR and Southern Company. Fischer-Tropsch conversion of the syngas produces synthetic paraffinic kerosene (SPK) as the primary product, plus naphtha. Other co-products include electricity sold to the grid and CO 2 sold for use in enhanced oil recovery (EOR). Previous studies have identified coprocessing of various coals and biomass with CO 2 capture as promising options for cost-competitive production of low net lifecycle greenhouse gas (GHG) emissions synthetic fuels. The effort reported here goes beyond earlier studies in the level of detail in process design and cost estimation with the aim of improving the understanding of the economic prospects for lignite and woody biomass coprocessing systems. Key objectives in the design of the FOAK lignite/biomass-to-jet (LBJ) plant were to achieve net lifecycle GHG emissions for the SPK that are less than for conventional petroleum-derived jet fuel and to make process design and equipment selections such that the plant could be built and operated in the near term, e.g., before 2025. The process design was developed by researchers at Princeton University and the University of Queensland and validated by engineers at the WorleyParsons Group (WP). Commercial vendors provided design and cost estimates for several major plant components. Bare-erected capital costs and operating and maintenance costs were estimated by WP. The primary objective in building and operating the FOAK plant would be to demonstrate the technical viability of the LBJ concept as an essential first step toward launching commercial-scale plants in the longer term. With this in mind, the project team developed a set of principles to help guide the process design: the total plant cost should be less than 2 billion USD (to limit investment risk); the level of input biomass should be both proportionally significant to reflect biomass/lignite co-gasification and sufficient to achieve GHG emissions goals; process design decisions and vendor/equipment selections should prioritize the likelihood of technical success over minimizing the cost of jet fuel production. The resulting FOAK plant design capacity is 1,551 metric t/d (45.5% moisture) lignite and 556 t/d (43.3% moisture) biomass, for a total input of 295 MW HHV , of which 25% is biomass. The design output is 1,252 actual barrels per day of liquids, of which 80% is SPK (62.3 MW LHV ) and 20% is naphtha (13.9 MW LHV ). It exports 15 MW e of electricity after satisfying a 38 MW e onsite auxiliary load. Additional products are 1,326 t/d of pressurized pipeline-quality CO 2 and 49 t/day of sulfuric acid (93 wt% H 2 SO 4 ). With thinnings from sustainably-managed southern pine plantations as the biomass, and with captured CO 2 stored underground via EOR, the net lifecycle emissions for the SPK product are estimated to be about one-quarter of those for petroleum-derived jet fuel. The bare-erected cost (BEC) estimated by WP for this plant is 588 million USD (2015). The authors’ best estimate of total plant cost (TPC) is 1,230 million USD, arrived at by assuming engineering, procurement and construction management services (20% of BEC), process 5 contingencies (35% of BEC), and project contingencies (35% of the sum of all other costs, i.e., 35% of 1.55xBEC). Not surprisingly, an annual discounted cash flow (DCF) analysis determined that it would be impossible to generate a positive net present value (NPV) over a wide range in key input assumptions. An SPK production cost subsidy of nearly 400/bbl USD over a 20-year plant life would be required to achieve zero NPV under a baseline set of assumptions (including 3% real weighted average cost of capital and a levelized crude oil price of 80/bbl USD). Alternatively, a capital grant in excess of the TPC value would also achieve zero NPV. The poor financial results reflect the small scale of the plant, the design principle to prioritize technical success, the levels of contingencies appropriate for the relatively early stage of project development, and the first-of-a-kind nature of the plant. Technology innovations, learning via construction and operating experience, alternative plant configurations, and larger scale should improve economics of future plants. To help understand these prospects, a preliminary analysis of N th -of-a-kind (NOAK) plants was developed, but with the limitation that plants would use only equipment components that for the most part are already commercial today: consideration of advanced, not-yet-commercial technologies and of R&D-driven improvements in existing technologies were beyond the scope of this analysis. The analysis found that a variety of NOAK plant designs that coprocess lignite and woody biomass to make jet fuel are unlikely to be economically competitive without subsidy even in the presence of a high future carbon tax or equivalent greenhouse gas mitigation policy. This conclusion applies to process configurations and input biomass/lignite ratios that result in net GHG emissions as high as those for petroleum-derived jet fuel and as low as zero. In contrast, encouraging results were found for plants processing only biomass. The economics of these “BECCS” plants (biomass energy with CCS) improve dramatically with the strength of carbon mitigation policies because of their strongly negative net GHG emissions. These findings do not imply that coal/biomass coprocessing strategies for making synfuels with CCS are not economically promising – only that, in the case of lignite, much more than a 25% biomass coprocessing rate would be needed. However, our analysis shows that all such systems are unlikely to be economic in the absence of a strong carbon mitigation policy. Future R&D driven technological innovations could modify this conclusion. Among other R&D priorities, an emphasis on better understanding and reducing plant auxiliary loads is warranted.

09 BIOMASS FUELS↗

Carbon Capture via Crystallization with a Guanidine Ligand

Carbon capture and storage (CCS) is an important strategy aimed at stabilizing the atmospheric CO2 concentration and thereby the global temperature. In conventional fossil fuel-fired power plants, the resulting flue gas is released into the air without any carbon dioxide scrubbing, which gradually increases the atmospheric CO 2 concentration (currently at approximately 409 ppm). Implementation of post-combustion capture (PCC) of carbon dioxide, whereby the CO 2 emitted by power plants is captured and stored into geological repositories, would enable us to continue to use relatively cheap fossil fuels such as coal, natural gas, and oil, but with significantly reduced CO 2 emissions. A recent report by the International Energy Agency indicated that by 2050 CCS could reduce the annual CO 2 emissions by almost 6 gigatones, which represents about 14% of the total carbon emission reduction necessary to limit the global temperature increase by 2 ºC by the end of the 21st century (International Energy Agency, 2016). This goal will be accomplished by developing inexpensive materials that can be used to effectively capture CO 2 and be regenerated with minimal energy penalty. This project helped address this need by introducing new materials and mechanisms for CO 2 capture. The goal of this project was to demonstrate a bench-scale CO 2 capture process based on a novel guanidinium (bi)carbonate crystallization approach, and ultimately develop an energy-efficient and cost-effective technology for CO 2 capture from flue gas. The project built on our recent discovery of a new class of aqueous guanidine sorbents that react with carbon dioxide and crystallize as carbonate or bicarbonate salts of very low aqueous solubility (Brethomé, 2018; Williams, 2019). The resulting guanidinium (bi)carbonate crystals release the CO 2 upon mild heating at 80-120 ºC, which regenerates the guanidine ligands quantitatively (Figure 1). The potential advantage of this crystallization-based approach over traditional amine scrubbing methods (i.e., using aqueous MEA) is that it allows sorbent regeneration by heating the solid crystals alone, without the bulk solution, making this process more energy-efficient.

20 FOSSIL-FUELED POWER PLANTS↗

Performance and Cost Assessment of a Natural Gas-Fueled Direct sCO 2 Power Plant

This final report details the cost and performance baseline developed at NETL for a natural gas-fueled direct sCO 2 plant, which holds promise as an efficient, cost-effective method of power production with carbon capture and storage (CCS). The steady state plant model includes turbine cooling flows based on a semi-empirical cooling model, and thermal integration with the air separation unit and oxygen compression train. Discussion of the performance of the baseline plant design is followed by details on the costing methodology, overall plant capital cost, and resulting cost of electricity (COE). Performance results yield a baseline sCO 2 plant thermal efficiency of 48.2% (HHV) with 98.2% carbon capture, an improvement over the reference NGCC plant with CCS (45.7% and 90.7% carbon capture). Cost analyses yield a 5% reduction in COE versus the NGCC plant, albeit with significant uncertainty. Finally, the effects of incomplete combustion on the overall plant performance are assessed.

03 NATURAL GAS↗

Integrated Carbon Capture and Storage in the Louisiana Chemical Corridor

There are a variety of methods by which carbon emissions can be avoided. The two most common include end-use energy efficiency and the adoption of renewables. Carbon capture and storage (CCS) technologies represent a third and often less-recognized method for mitigating carbon emissions. However, over the past twenty years, most CCS interest has been focused on the power generation sector and not on a broader set of applications that include other industrial and manufacturing sources.

54 ENVIRONMENTAL SCIENCES↗

Comparative Analysis of Transport and Storage Options from a CO 2 Source Perspective

This analysis evaluated integrated CCS costs (i.e., capture, transport, and storage) from the perspective of a CO 2 source. Capture costs for sources with annual CO 2 capture rates from 0.65 to 3.90 Mt were based on two NETL reports. Transportation costs from source to storage reservoir were modeled for two pipelines systems (dedicated and trunkline) using the FE/NETL CO 2 Transport Cost Model. Storage costs were modeled in dome and regional dip structural settings for two reservoirs in the Rose Run Formation, three within the Mt. Simon, one in the Lower Tuscaloosa, and one in the Frio using the FE/NETL CO 2 Saline Storage Cost Model. A paper with the same name and information as well as additional details on this analysis was published in The International Journal of Greenhouse Gas Control along with a supplementary document that provides additional material (i.e., key parameters used in the models for obtaining transport and storage costs and CCS cost and pipeline results).

03 NATURAL GAS↗

Mid-Atlantic U.S. Offshore Carbon Storage Resource Assessment Project (Final Technical Report)

The greatest potential for carbon storage in the northeastern United States lies in the offshore geologic formations comprising the outer continental shelf (Monteverde et al., 2011). Offshore storage can be linked to large point-sources of carbon dioxide (CO 2 ) while avoiding many of the logistical difficulties and potential risks encountered when siting onshore projects, especially in densely populated areas of the East Coast. Offshore CO 2 storage assessment and research in the United States is underway to address uncertainty in potential storage resources, particularly in the mid- and north-Atlantic offshore area. Given the current knowledge base and access to publicly available data, the objectives of the Mid-Atlantic U.S. Offshore Carbon Storage Resource Assessment Project (MAOCSRAP) were fourfold: (1) complete a systematic carbon storage resource assessment of the mid-Atlantic offshore coastal region from the Georges Bank Basin (GBB) through the Long Island Platform (LIP) to the southern Baltimore Canyon Trough (BCT); (2) define key input parameters to reduce uncertainty for offshore storage resource and efficiency estimates; (3) perform a preliminary assessment of risk factors, uncertainties, and data gaps; and (4) engage industry and regulatory stakeholders through development of a Road Map to assist future project planning and implementation. The MAOCSRAP project has compiled, inventoried, and assimilated various publicly available data sets to provide a strong technical basis on which future carbon storage studies and applications can be built. The knowledge infrastructure necessary to support the development of full-scale offshore carbon storage include: Defining the geologic characteristics of candidate storage sites (Chapter 2). Using existing seismic data to better define the continuity of the storage zones and seals (Chapter 3). Cataloguing the hydrogeologic properties of mid-Atlantic offshore storage sites (Chapter 4). Calculating prospective CO 2 storage resources using net effective pore volumes and fluid displacement properties specific to offshore lithologies (Chapter 5). Examining risk factors related to offshore storage (Chapter 6). Communicating with industry and other stakeholders about the future prospects for offshore storage (Chapter 7). Ensuring technology transfer to industry and other stakeholders (Chapter 8). Led by Battelle, this project was conducted by public and private entities with expertise in offshore geology and resources for the study region, including state geological surveys of Delaware, Maryland, and Pennsylvania; United States Geological Survey-Woods Hole Coastal and Marine Science Center and Haifa University; Rutgers University; Harvard University; and Lamont-Doherty Earth Observatory (LDEO) at Columbia University. The storage resource assessment was completed for a broad region offshore of the U.S. East Coast, from Massachusetts to Virginia. The results include high-level storage resource estimates for areas not previously characterized and improved storage resource estimates for geographically expansive portions of offshore geologic units. Results of the project provide a foundation for developing CO 2 storage along offshore areas of the mid-Atlantic United States. A combination of information was used to provide confidence in project results. Key findings of the major project tasks are summarized as follows. Subsurface Data Analysis: Legacy seismic, well-log, core, and biostratigraphic data were digitized, reprocessed, and analyzed using modern techniques, augmenting previous characterization efforts. The sequence stratigraphic framework for the Cretaceous and Jurassic strata was developed by correlating well-log depositional sequences to seismic reflectors identified in the BCT, LIP, and GBB. The integration of well-log stratigraphy with seismic stratigraphy and petrophysical analysis helped to identify and map potential storage zones within sequences of the Logan Canyon (LC), Missisauga, and Mohawk formations, as well as the regionally extensive caprock comprised of the Dawson Canyon shale. Approximately 4,000 kilometers (km) of seismic data was reprocessed to create a structural framework that was used to tie together all available well data, constrain sequence stratigraphic interpretations, and make regional assessments of offshore carbon storage resources. Prospective storage resource estimates were 150 to 1136 megatons (Mt) for the combined storage zones. This suggests mid-Atlantic U.S. offshore formations can store decades of CO 2 from industrial sources in the region. Preliminary local reservoir simulations suggest that injection rates of 1 Mt CO 2 /year may be sustained for 30 years in single injection wells in the BCT. Advanced geologic modeling and new data acquisition are needed to address data gaps and advance carbon capture and storage (CCS) in key offshore areas selected for further investigation. Offshore Risk Factors: Offshore geologic risk factors include soft sediment deformation, unit continuity, sedimentological and structural features, seismicity and hydrates. CO 2 storage risks include inadequate seals, migration/leakage, and chemical interactions leading to decreased storage. Sensitive habitats, environmental impacts, disturbance to seafloor, and other risks need to be identified in advance of project activities and integrated into detailed mitigation plans for all project phases. Stakeholder Engagement: Input and participation from government, industry, and environmental groups provided input into the Road Map and address next steps needed for project deployment. Early engagement and ongoing communication, as well as policy framework development, is key to large-scale deployment of CCS. Next Steps: This project represents an important first step by completing a high-level CO 2 storage resource assessment and building the knowledge infrastructure necessary to improve quantitative storage resource estimates. The data sets that have been curated under this project provide an opportunity to conduct research and development (R&D) needed to address data gaps and reduce risk and uncertainty. Offshore characterization and validation strategies that are systematically designed to provide data and infrastructure that can be upscaled to meet commercial requirements could be developed off of this foundation.

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CO 2 Mineralization Using Porous Carbon and Industrial Wastes to Make Multifunctional Concrete

Along with substantial benefits and promises of carbon capture and storage (CCS) technologies, significant challenges exist in developing scalable materials and methods for capture and of CO 2 . The overarching objective of this project is to provide a system approach for developing a new CO 2 capture and utilization technology using porous carbon and industrial wastes to make a low-cost, scalable and multifunctional concrete product. The objective of Phase I of this project is to develop and fine-tune activated carbons from different wastes such as plastic wastes to offer a cheap, abundant and scalable feedstock for CO 2 uptake. The objective of Phase 2 is creating a facile protocol to develop a concrete prototype comprising CO 2 adsorbed activated carbon (e.g. from plastic wastes), followed by product validation, life-cycle analysis, and bench-scale testing. The project objectives are designed to specifically obtain a final product and technology that directly addresses the main goals of the DOE’s CCS programs.

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Site Design and Layout In Preparation for the Anthropogenic Test (SECARB Work Product 6.2.1.b)

Commercial-scale carbon capture and storage (CCS) technology deployment for the electrical utility industry will require a robust international R&D program with governmental support both in cost-share and in risk management. In an effort to comply with environmental legislation or regulation related to CO 2 , the electrical utility industry hopes to be in a position to make financial decisions on utility boiler sourced CCS technology and associated risk management by 2020.

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Information products and communication materials for NGOs

The Southeast Regional Carbon Sequestration Partnership (SECARB) Phase III Anthropogenic Test is a full integrated carbon dioxide (CO 2 ) capture, transportation, and geologic storage project located in southern Alabama. The CO 2 for the Anthropogenic Test is obtained from a demonstration-scale, post-combustion CO 2 capture facility at Southern Company's subsidiary Alabama Power's existing 2,657 Megawatt (MW) Barry Electric Generating Plant in Mobile County, Alabama. A small amount of flue gas from Plant Barry (equivalent to the amount produced when generating 25 MW of electricity) is being diverted from the plant's #5 coal burning unit and captured using a process developed by Mitsubishi Heavy Industries (MHI) to produce high purity CO 2 . The captured CO 2 is compressed at Plant Barry and transported approximately 19 kilometers (12 miles) by dedicated pipeline to the injection location at Citronelle Field. Public outreach and education associated with the Anthropogenic Test is critical to promoting public acceptance and eventual deployment of CCS technologies near large CO 2 sources in the Southeast. Southern Company, with support from the project team, has kept NGO communities informed of project status through press releases, public meetings, and presentations since site selection was announced on May 200, 2009. Maintaining good community relationships with neighbors and customers near its facilities is a priority. Goals are to educate NGO's about the demonstration, request that they inform their constituencies, and learn about their concerns related to CCS. The following report documents outreach activities by Southern Company and the project team through websites, press releases, local outreach, and presentations and outreach events.

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Information Products & Communications Materials for COR and Contractors' Meetings [Slides]

Contents include the following: 1) Large Scale CO 2 Storage in the Lower Tuscaloosa Massive Sand Formation, December 12, 2007; 2) CoalFleet Program Update and Workshops, July 26-28, 2005; 3) Regional Carbon Sequestration Partnership Annual Review Meeting, November 18, 2009; 4) SECARB U. S. Regional Partnerships from Pilot to Demonstration, November 5, 2009; 5) The SECARB Anthropogenic Test–CO 2 Capture/Transportation/Storage, August 21-23, 2012; 6) Citronelle Project–Experiences With Permitting and Regulations on CCS, August 21, 2013; 7) Partnering With Industry for Large Scale CCS Projects, August 22, 2013; 8) Plant Barry-Citronelle Field Project, August 13, 2104; 9) SECARB's Early Test at Cranfield, Mississippi; 10) SECARB Partnership Early Test at Cranfield Status, August 18-20, 2015; 11) Citronelle Project, August 18, 2015; 12) Plant Barry 25 MW Demo; 13) SECARB Phase III Citronelle Project (Anthropogenic Test) in Alabama, August 18, 2015; 14) SECARB Early Test Retrospective; 15) SECARB Anthropogenic Test Lessons Learned, August 16-18, 2016; 16) SECARB Early Test at Cranfield, August 1-3, 2017; 17) Carbon Storage and Oil and Natural Gas Technologies Review Meeting, August 1-3, 2017; 18) SECARB Partnership Early Test at Cranfield, August 13-16, 2018; 19) SECARB Anthropogenic Test Update, August 13-16, 2018; 20) SECARB Partnership Early Test at Cranfield, August 26-30, 2019; 21) SECARB (Citronelle) Phase III, August 27, 2019.

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