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DOE OSTI2014

Developing a Comprehensive Risk Assessment Framework for Geological Storage CO 2

The operational risks for CCS projects include: risks of capturing, compressing, transporting and injecting CO₂; risks of well blowouts; risk that CO 2 will leak into shallow aquifers and contaminate potable water; and risk that sequestered CO 2 will leak into the atmosphere. This report examines these risks by using information on the risks associated with analogue activities such as CO 2 based enhanced oil recovery (CO 2 -EOR), natural gas storage and acid gas disposal. We have developed a new analysis of pipeline risk based on Bayesian statistical analysis. Bayesian theory probabilities may describe states of partial knowledge, even perhaps those related to non-repeatable events. The Bayesian approach enables both utilizing existing data and at the same time having the capability to adsorb new information thus to lower uncertainty in our understanding of complex systems. Incident rates for both natural gas and CO 2 pipelines have been widely used in papers and reports on risk of CO 2 pipelines as proxies for the individual risk created by such pipelines. Published risk studies of CO 2 pipelines suggest that the individual risk associated with CO2 pipelines is between 10 -3 and 10 -4 , which reflects risk levels approaching those of mountain climbing, which many would find unacceptably high. This report concludes, based on a careful analysis of natural gas pipeline failures, suggests that the individual risk of CO 2 pipelines is likely in the range of 10-6 to 10-7, a risk range considered in the acceptable to negligible range in most countries. If, as is commonly thought, pipelines represent the highest risk component of CCS outside of the capture plant, then this conclusion suggests that most (if not all) previous quantitative- risk assessments of components of CCS may be orders of magnitude to high. The potential lethality of unexpected CO 2 releases from pipelines or wells are arguably the highest risk aspects of CO 2 enhanced oil recovery (CO2-EOR), carbon capture, and storage (CCS). Assertions in the CCS literature, that CO 2 levels of 10% for ten minutes, or 20 to 30% for a few minutes are lethal to humans, are not supported by the available evidence. The results of published experiments with animals exposed to CO 2 , from mice to monkeys, at both normal and depleted oxygen levels, suggest that lethal levels of CO 2 toxicity are in the range 50 to 60%. These experiments demonstrate that CO 2 does not kill by asphyxia, but rather is toxic at high concentrations. It is concluded that quantitative risk assessments of CCS have overestimated the risk of fatalities by using values of lethality a factor two to six lower than the values estimated in this paper. In many dispersion models of CO 2 releases from pipelines, no fatalities would be predicted if appropriate levels of lethality for CO 2 had been used in the analysis.

54 ENVIRONMENTAL SCIENCES↗

DOE OSTI2014

Review of Quantitative Monitoring Methodologies for Emissions Verification and Accounting for Carbon Dioxide Capture and Storage for California’s Greenhouse Gas Cap-and-Trade and Low-Carbon Fuel Standard Programs

The Cap-and-Trade and Low Carbon Fuel Standard (LCFS) programs being administered by the California Air Resources Board (CARB) include Carbon Dioxide Capture and Storage (CCS) as a potential means to reduce greenhouse gas (GHG) emissions. However, there is currently no universal standard approach that quantifies GHG emissions reductions for CCS and that is suitable for the quantitative needs of the Cap-and-Trade and LCFS programs. CCS involves emissions related to the capture (e.g., arising from increased energy needed to separate carbon dioxide (CO 2 ) from a flue gas and compress it for transport), transport (e.g., by pipeline), and storage of CO 2 (e.g., due to leakage to the atmosphere from geologic CO 2 storage sites). In this project, we reviewed and compared monitoring, verification, and accounting (MVA) protocols for CCS from around the world by focusing on protocols specific to the geologic storage part of CCS. In addition to presenting the review of these protocols, we highlight in this report those storage-related MVA protocols that we believe are particularly appropriate for CCS in California. We find that none of the existing protocols is completely appropriate for California, but various elements of all of them could be adopted and/or augmented to develop a rigorous, defensible, and practical surface leakage MVA protocol for California. The key features of a suitable surface leakage MVA plan for California are that it: (1) informs and validates the leakage risk assessment, (2) specifies use of the most effective monitoring strategies while still being flexible enough to accommodate special or site-specific conditions, (3) quantifies stored CO 2 , and (4) offers defensible estimates of uncertainty in monitored properties. California’s surface leakage MVA protocol needs to be applicable to the main CO 2 storage opportunities (in California and in other states with entities participating in California’s Cap-and-Trade or LCFS programs), specifically CO 2 -enhanced oil recovery (CO 2 -EOR), CO 2 injection into depleted gas reservoirs (with or without CO 2 -enhanced gas recovery (CO 2 -EGR)), as well as deep saline storage. Regarding the elements of an effective surface leakage MVA protocol, our recommendations for California are that: (1) both CO 2 and methane (CH 4 ) surface leakage should be monitored, especially for enhanced recovery scenarios, (2) emissions from all sources not directly related to injection and geologic storage (e.g., from capture, or pipeline transport) should be monitored and reported under a plan separate from the surface leakage MVA plan that is included as another component of the quantification methodology (QM), (3) the primary objective of the surface leakage MVA plan should be to quantify surface leakage of CO 2 and CH 4 and its uncertainty, with consideration of best-practices and state-of-the-art approaches to monitoring including attribution assessment, (4) effort should be made to monitor CO 2 storage and migration in the subsurface to anticipate future surface leakage monitoring needs, (5) detailed descriptions of specific monitoring technologies and approaches should be provided in the MVA plan, (6) the main purpose of the CO 2 injection project (CO 2 -EOR, CO 2 -EGR, or pure geologic carbon sequestration (GCS)) needs to be stated up front, (7) approaches to dealing with missing data and quantifying uncertainty need to be described, and (8) post-injection monitoring should go on for a period consistent with or longer than that prescribed by the U.S. EPA.

54 ENVIRONMENTAL SCIENCES↗

DOE OSTI2018

Integrated Pre-Feasibility Assessment for a Northern Michigan Basin CarbonSAFE CO 2 Storage Complex

One of the key gaps in the critical path toward carbon capture and storage (CCS) deployment is the development of commercial-scale (50+ million metric tons carbon dioxide [CO2]) geologic storage sites for CO 2 from industrial sources. There has been relatively little effort by the private sector to identify and certify (i.e., regulatory permit) geologic storage sites that are capable of storing commercial-scale volumes of CO 2 , primarily because of the lack of immediate economic incentives. As a result, commercial-scale CO 2 sources that want to develop CCS projects face the risk of not finding a suitable saline storage site for their captured CO 2 . Carbon Storage Assurance Facility Enterprise (CarbonSAFE) is a U.S. Department of Energy (DOE)-sponsored effort to develop an integrated CCS storage complex constructed and permitted for operation in the 2025 timeframe over a series of sequential phases of development: Integrated CCS Pre-Feasibility, Storage Complex Feasibility, Site Characterization, and Permitting and Construction. Subject to availability of funds, a series of funding opportunity announcements (FOAs) are planned to accomplish this mission. This document describes a project that addresses DOE FOA-1584 Phase I: Integrated Carbon Capture and Storage (CCS) Pre-Feasibility. The objective of this project was to take the first step in developing an integrated commercial geologic CO 2 storage complex in the Northern Michigan Basin, herein referred to as the CarbonSAFE – Northern Michigan Basin (CS-NMB) storage complex. This includes demonstrating that the storage sites within the complex have the potential to store more than 50 million metric tons (MMT) of industrially-sourced CO 2 emissions safely, permanently and economically. To achieve the overall objective of the Phase I pre-feasibility study, FOA-1584 required three activities: • Perform a high-level technical sub-basinal evaluation to identify a potential storage complex with storage site(s), including a description of the geology and risks associated with the potential storage site; identify and evaluate potential CO 2 sources. • Develop a plan for the storage complex and storage site(s) including a strategy that would enable an integrated capture and storage project to be economically feasible and publicly acceptable. • Form a CCS coordination team capable of addressing regulatory, legislative, technical, public policy, commercial, financial, etc. challenges specific to commercial-scale deployment of the CO 2 storage project.

20 FOSSIL-FUELED POWER PLANTS↗

DOE OSTI2020

Connected Communities: A Multi-Building Energy Management Approach

Connected Communities (CCs) are collections of buildings and distributed energy resources (DERs) that incorporate integrated energy management strategies at the multi-building scale. Based on the research conducted for this report, RMI and NREL have identified examples of CCs that are enabling increasingly integrated solutions, sharing resources among buildings, and providing services back to the grid. As demonstrated by these examples, CCs can provide real and scalable solutions to mitigate energy costs, enable more flexibility in grid operations, and offer choices in meeting greenhouse gas (GHG) emissions goals. Nationwide examples of these solutions are included in the appendix of this report. In order to understand the most promising practices for the design, operation, and business models associated with CCs, a search was performed to create a nationwide inventory of CCs and multiple stakeholder interviews were conducted. Based on that research, this paper explores the many factors that influence the development and operation of CCs and evaluates their potential value.

32 ENERGY CONSERVATION, CONSUMPTION, AND UTILIZATI↗

DOE OSTI2022

Flexible FlueCO2

Carbon dioxide (CO2) emission reductions remain a significant challenge on the path to clean energy. There are increasing legislative, social, and environmental factors motivating CO2 emissions reduction from power plants with carbon capture and storage (CCS). CCS in natural gas combined cycle (NGCC) power plants is critical to achieve a net-zero carbon electricity grid. Enhanced 45Q tax credits provide new incentives, but currently available technologies are unable to profitably operate in grids with deep variable renewable penetration which require flexible NGCC operation. Luna Labs has developed the FlueCO2 membrane to enable a profitable NGCC-CCS process. The FlueCO2 membrane couples steam transport across the membrane to CO2 transport in the opposite direction, enabling high capture efficiencies and low energy costs even at low CO2 concentrations. The dual-phase membrane can operate in the range of typical flue gas temperatures and pressures and does not require temperature or pressure cycling. Luna Labs’ FlueCO2 technology enables flexible and profitable operation of NGCC plants with lower capital investment and impact on electricity prices. In this Phase 1 project, Luna Labs utilized experimental testing, modeling, process simulation, and standardized costing methodologies to evaluate the techno-economic value of a 650 MW greenfield NGCC plant with FlueCO2 (NGCC-FlueCO2). Key design requirements for operation were established and plant performance under load-leveling conditions was validated through computational fluid dynamics and process modeling. Luna Labs developed a dynamic modeling tool which modeled plant operational modes across a variety of tax structures and electricity pricing scenarios to project the overall Net Present Value (NPV) of the NGCC-FlueCO2. FlueCO2 minimizes the impact of CCS integration on plant operation by integrating directly into the NGCC heat recovery steam generator (HRSG). By tapping into the plant’s low-pressure (LP) steam, operators can divert LP steam to the greenfield NGCC and/or CCS process in response to dynamic markets. Since FlueCO2 will not significantly affect HRSG (or NGCC) operation, CCS only turns off during peak power demand (>$250/MWh). Under baseload conditions, FlueCO2 lowers the capital (37%), energy (36%) and carbon capture (<$40/tonne) costs and can increase the overall plant lifetime NPV by approximately ~$1B in comparison with NGCC solvent-based capture reference cases (NETL Case 31B). Luna Labs has shared its costing tools with several interested partners and customers, which follows a generalizable approach to costing analysis.

Kelly, Jesse↗

DOE OSTI2024

Test and Validate Distributed Coaxial Cable Sensors for in situ Condition Monitoring of Coal-Fired Boiler Tubes

This project aims to test, validate, and advance the technology readiness level (from TRL5 to TRL7) of a novel low-cost distributed stainless-steel/ceramic coaxial cable sensing (SSC-CCS) technology for in situ monitoring of the boiler tube temperature in existing coal-fired power plants. The novel SSC-CCS sensing technology and associated condition-based monitoring (CBM) software to be demonstrated in this project will lead to an improved understanding of the boiler tube failure mechanisms and a prognostic system to improve the overall performance, reliability, and flexibility of the nation’s coal-fired power plant fleet. A boiler tube monitoring system with distributed coaxial cable temperature sensors and a sensor acquisition system was constructed. The high-temperature coaxial cable sensor with a length of 1.3m was made by using a quartz tube (1mm inner diameter (ID) and 6mm outer diameter (OD)) to concentrically separate a 304 stainless-steel (SS) rod (1mm OD) and SS tube (7.94mm OD and 6.16mm ID). The sensor acquisition system includes a vector network analyzer (VNA), a radio frequency (RF) power amplifier, multiple switches and a USB hub. The distributed stainless-steel quartz coaxial cable sensor (SSQ-CCS) had a linear response to temperature with a resolution uncertainty of σ = 0.77℃. To withstand the harsh conditions of 3,300 steam pressures and 800℃ high temperatures, the sensor was shielded by a protective tube made of the same material as the boiler tube. The protection tube had an OD of 1.5 inches and a thickness of 0.25 inches. In the laboratory tests, the sensor showed good sensitivity and fast response. The drift was bounded between +0.33% and -0.67% during a test at 600℃ for 350 hours, indicating good stability of the sensor. A field test was conducted where four sensors were welded on four superheat tubes (SH-Ts) at a coal-fired power station over 400 days. Conventional thermocouples were welded to the superheater tubes alongside the coaxial cable sensors for the purpose of comparison. Two sensors were capable of distributed sensing, with three multiplexed sensing sections. The other two sensors were single section. During the 400-day test period, the power plant experienced startups and shutdowns. At the steady state operations, the temperature of the boiler tube is about 600℃ (1112°F). The sensors recorded the entire coal-firing processes (start-up, steady state, and shut-down) and the glitch event. A GSM modem and a Watchdog were added to the system to ensure reliable data recording. The GSM modem sent daily messages to plant managers and Clemson team to inform the status of the sensor system. If the system was not normally working, the Watchdog would reboot the system automatically. The new coaxial cable based distributed sensing technology has been proven to be successful in both laboratory and field tests. A comprehensive four-stage multi-physics computational framework has been developed to assist the design, optimization, installation, and operation of SSQ-CCS. With the consideration of various operation conditions, we predict the distributions of flue gas temperatures within coal-fired boilers, the temperature correlation between the boiler tube and SSQ-CCS, and the safety of SSQ-CCS. A conditional-based monitoring system is implemented as well. The computational framework developed in this work can guide the future operation of coal-fired plants and other power plants for the safety prediction of boiler operations.

01 COAL, LIGNITE, AND PEAT↗

DOE OSTI2024

Novel Carbon Storage Monitoring Methods

Conference presentation at American Institute of Chemical Engineers (AIChE) Annual Meeting, San Diego, California, October 27–31, 2024. We presented a high-level overview of many novel and sustainable carbon storage monitoring methods that are at various stages of planning or demonstration to accelerate the deployment of CCS technologies at future CCS sites across the United States. Our work impacts the general CCS industry by providing novel and more sustainable methods for tracking CO 2 plume migration and performing assurance monitoring. Our work primarily benefits three parties: 1) CCS community members through knowledge sharing of lessons learned; 2) CCS operators through commercialization of additional methods, including improvements on workflows and simplification of fieldwork; and 3) stakeholders of CCS projects through implementation of low-impact and more autonomous monitoring solutions.

02 PETROLEUM↗

DOE OSTI2024

GRIDCERF - Geospatial Raster Input Data for Capacity Expansion Regional Feasibility

The Geospatial Raster Input Data for Capacity Expansion Regional Feasibility (GRIDCERF) data package is a high-resolution product to evaluate siting suitability for renewable and non-renewable power plants in the conterminous United States. GRIDCERF offers hundreds of individual suitability layers for use with both renewable and non-renewable power plant technology configurations in a harmonized format that can be easily ingested by geospatially-enabled modeling software. It also provides pre-compiled technology-specific suitability layers and allows for user customization to robustly address science objectives when evaluating varying future conditions. GRIDCERF data can be directly used with the CERF (Capacity Expansion Regional Feasibility) model to site power plants at a 1km resolution. GRIDCERF includes composite technology siting suitability raster layers for the following utility scale technology configurations. Note that, in addition to technology sub-types shown below, various cooling types are also included (recirculating, pond, once-through, recirculating-seawater, dry-hybrid, or dry) for various technologies. Biomass Conventional (with or without CCS) IGCC (with or without CCS) Coal Conventional (with or without CCS) IGCC (with or without CCS) Natural Gas Combined-cycle (CC) (with or without CCS) Turbine Geothermal Enhanced Geothermal Systems (EGS) - Class 1 through Class 5 resource potential Nuclear Gen 2 Light Water Reactor (LWR) Gen 3 Small Modular Reactor (SMR) Gen 3 AP1000 Refined Liquids Combined-cycle (CC) (with or without CCS) Turbine Solar Photovoltaic (PV) - for capacity factors in the range of 6-18% Utility-scale Concentrating Solar Power (CSP) - for capacity factors in the range of 24-46% Tower Wind (Onshore) - for capacity factors in the range of 5-50% 80m hub height 100m hub height 120m hub height 140m hub height Wind (Offshore) - for capacity factors in the range of 25-60% 100m hub height 140m hub height 160m hub height

capacity expansion↗

DOE OSTI2026

GRIDCERF - Geospatial Raster Input Data for Capacity Expansion Regional Feasibility

capacity expansion↗

NASA NTRS1994

Extended cooperative control synthesis

This paper reports on research for extending the Cooperative Control Synthesis methodology to include a more accurate modeling of the pilot's controller dynamics. Cooperative Control Synthesis (CCS) is a methodology that addresses the problem of how to design control laws for piloted, high-order, multivariate systems and/or non-conventional dynamic configurations in the absence of flying qualities specifications. This is accomplished by emphasizing the parallel structure inherent in any pilot-controlled, augmented vehicle. The original CCS methodology is extended to include the Modified Optimal Control Model (MOCM), which is based upon the optimal control model of the human operator developed by Kleinman, Baron, and Levison in 1970. This model provides a modeling of the pilot's compensation dynamics that is more accurate than the simplified pilot dynamic representation currently in the CCS methodology. Inclusion of the MOCM into the CCS also enables the modeling of pilot-observation perception thresholds and pilot-observation attention allocation affects. This Extended Cooperative Control Synthesis (ECCS) allows for the direct calculation of pilot and system open- and closed-loop transfer functions in pole/zero form and is readily implemented in current software capable of analysis and design for dynamic systems. Example results based upon synthesizing an augmentation control law for an acceleration command system in a compensatory tracking task using the ECCS are compared with a similar synthesis performed by using the original CCS methodology. The ECCS is shown to provide augmentation control laws that yield more favorable, predicted closed-loop flying qualities and tracking performance than those synthesized using the original CCS methodology.

Davidson, John B.↗

NASA NTRS2012

Binaries in Transneptunian Resonances: Evidence for Slow Migration of Neptune?

A distinguishing feature of trans neptunian objects (TNO) is the high fraction that arc binary. This is particularly true for the Cold Classicals (CC), objects in lowe and low i orbits concentrated between the 3:2 and 2: 1 mean-motion resonances. CCs have other physical markers: red colors, high albedos, and equal-mass binaries. The CCs appear to be a coherent and physically distinct population of planetesimals that has survived to the present with their physical properties relatively unaltered. Their spatial concentration between 39.4 and 47.7 AU has made identification of the CCs as a physical group possible. However, objects that started out as CCs arc almost certainly 1101 limited to this one dynamical niche. We can, therefore, use the measurable physical properties of CCs as tracers of Neptune-driven dynamical mixing in the Kuiper Belt. As Neptune migrated, its mean-motion resonances preceded it into the planetesimal disk. The efficiency of capture into mean motion resonances depends on the smoothness of Neptune's migration and the local population available to be captured. The two strongest resonances, the 3:2 at 39.4 AU and 2: 1 at 47.7 AU, straddle the core repository of the physically distinct CCs, providing a unique opportunity to test the details of Neptune's migration. Smooth migration should result in a measurable difference between the 3:2 and 2:1 with low inclination 2:1s having a red, binary population mirroring that of the CC itself while the 3:2 will be less contaminated. Alternative models with rapid migration would generate a more homogeneous result.

Noll, Keith↗

NASA NTRS2019

Command and Control System Automated Testing

The Kennedy Space Center (KSC) has developed its own Command and Control System for the launch of the Space Launch System (SLS) and Orion capsule. The Command and Control System (CCS) is used by console engineers for the launch and system checkout of aerospace vehicles. The CCS allows console engineers to read data from the flight hardware on the launch pad and from the ground control systems and allows console engineers to issue commands, like opening a valve, to the flight hardware and ground control systems. The CCS needs to interact with thousands of devices and hardware controllers for the spacecraft and ground systems, receive data from these devices, distribute the data to console engineers in real-time, and allow console engineers to issue commands to manipulate hardware on the launch pad. The system needs to be robust, fault tolerant, responsive, and fast. In order to keep up with the pace of development of the CCS, a Test Automation System (TAS) is needed to validate the integrity of the system as a whole along with its individual components. Automated tests allow for faster development time, since tests can be ran through a Continuous Integration system and allow developers to check their code faster. Currently, the different modules, classes, and functions that make up the CCS are tested at the unit level, and the system level, with all the modules working together. My project was to implement a system for the data protocol layer of the Command Control System to be tested as a complete functional unit, with all of its classes and functions working together, but independent of the other modules of the CCS.

Automated TestingTest Automation↗

DOE OSTI2014

Risk Evaluation for CO2 Geosequestration in the Knox Supergroup, Illinois Basin Final Report

This report describes a process and provides seed information for identifying and evaluating risks pertinent to a hypothetical carbon dioxide (CO2) capture and sequestration (CCS) project. In the envisioned project, the target sequestration reservoir rock is the Potosi Formation of the Knox Supergroup. The Potosi is identified as a potential target formation because (1) at least locally, it contains vuggy to cavernous layers that have very high porosity, and (2) it is present in areas where the deeper Mt. Simon Sandstone (a known potential reservoir unit) is absent or nonporous. The key report content is discussed in Section 3.3, which describes two lists of Features, Events, and Processes (FEPs) that should be considered during the design stage of such a project. These lists primarily highlight risk elements particular to the establishment of the Potosi as the target formation in general. The lists are consciously incomplete with respect to risk elements that would be relevant for essentially all CCS projects regardless of location or geology. In addition, other risk elements specific to a particular future project site would have to be identified. Sources for the FEPs and scenarios listed here include the iconic Quintessa FEPs list developed for the International Energy Agency Greenhouse Gas (IEAGHG) Programme; previous risk evaluation projects executed by Schlumberger Carbon Services; and new input solicited from experts currently working on aspects of CCS in the Knox geology. The projects used as sources of risk information are primarily those that have targeted carbonate reservoir rocks similar in age, stratigraphy, and mineralogy to the Knox-Potosi. Risks of using the Potosi Formation as the target sequestration reservoir for a CCS project include uncertainties about the levels of porosity and permeability of that rock unit; the lateral consistency and continuity of those properties; and the ability of the project team to identify suitable (i.e., persistently porous and permeable) injection depths within the overall formation. Less direct implications include the vertical position of the Potosi within the rock column and the absence of a laterally extensive shale caprock immediately overlying the Potosi. Based on modeling work done partly in association with this risk report, risks that should also be evaluated include the ability of available methods to predict and track the development of a CO2 plume as it migrates away from the injection point(s). The geologic and hydrodynamic uncertainties present risks that are compounded at the stage of acquiring necessary drilling and injection permits. It is anticipated that, in the future, a regional geologic study or CO2-emitter request may identify a small specific area as a prospective CCS project site. At that point, the FEPs lists provided in this report should be evaluated by experts for their relative levels of risk. A procedure for this evaluation is provided. The higher-risk FEPs should then be used to write project-specific scenarios that may themselves be evaluated for risk. Then, actions to reduce and to manage risk can be described and undertaken. The FEPs lists provided as Appendix 2 should not be considered complete, as potentially the most important risks are ones that have not yet been thought of. But these lists are intended to include the most important risk elements pertinent to a Potosi-target CCS project, and they provide a good starting point for diligent risk identification, evaluation, and management.

Hnottavange-Telleen, Ken↗

DOE OSTI2016

Analysis of state and federal regulatory regimes potentially governing the extraction of water from carbon storage reservoirs in the United States

Not Available

Schroeder, Jenna N.↗

DOE OSTI2023

Energy-Community-Geo-Database

Fundamental to understanding evolving infrastructure and technology is understanding the drivers for energy communities that affect where and how infrastructure is placed and used. An Energy Community Geo Database aligned to carbon storage systems will aid stakeholders in decision making around key future infrastructure (e.g., CCS injection locations) placement while helping contextualize these analyses against past and present-day social and environmental attributes. Much of the data required to support analyses are available from authoritative, largely governmental sources, but at present are disparate and require time-consuming acquisition, integration, and upkeep for currency. The CCS-EC-GB v2.0 integrates datasets from various federal agencies and authoritative sources to aid stakeholders and decision makers of the social and environmental factors that might impact the viability of CCS and energy related project implementation. There are 5 categories in the CCS-EC-GB v2 database. Most of the layers within each category have been updated in this version. As compared to the old database, there is 1 new category in the CCS-EC-GB v2 database: infrastructure. This is an evolving project and application will be updated periodically with new datasets and information. Notes for consideration: This database/web map will be updated with additional as new data and information becomes available and has been processed, reviewed, and approved for release. Additional state and federal entity data are planned to be integrated and included in future revisions. Summary layers provided in this application are derived from proprietary layers and do not always contain key features (age, status, or TVD) and therefore might not be shown when data are queried for those features.

CCS,Carbon capture and storage,Carbon storage,U.S.↗

DOE OSTI2025

MRCI Task 4: Evaluating Regional Infrastructure Technical Summary Report

The infrastructure required to enable carbon capture and sequestration (CCS) goes beyond the equipment and materials needed to capture, transport, and store carbon dioxide (CO2) but includes people and policy that make CCS feasible. The Infrastructure Assessment task of the Midwest Regional Carbon Initiative (MRCI) seeks to determine the infrastructure requirements for the MRCI study area through four activities: • Infrastructure Readiness: Strategizing the buildout of capture, transport, and storage infrastructure in the Midwest, Northeast, and Mid-Atlantic Offshore. • Site Readiness: Determining the CCS readiness of each state in the MRCI region in the categories of subsurface readiness; infrastructure readiness; regulations, permitting, and incentives; and social dynamics. • Jobs, Economics, and Social Characteristics: Quantifying the economic potential, job opportunities, and training opportunities for CCS as well as the social characteristics of the region with a focus on energy and environmental justice (EJ) issues. • Policy and Regulations: Providing an updated accounting of the CCS-relevant policy and regulations in the MRCI region.

CCUS,Carbon storage,Midwest,Midwest Regional Carbo↗

DOE OSTI2018

Policy, Regulatory, Legal, and Permitting Case Study Subtask 3.2 – Topical Report

This report summarizes the policy, regulatory, legal, and permitting requirements to-date for the siting of a CO 2 injection and storage project in the CarbonSAFE Illinois East Sub-Basin pre-feasibility study area. Where applicable, the East Sub-Basin case study focuses on a proposed carbon capture and storage (CCS) site location in West Terre Haute, Indiana. Indiana has established the legal mechanisms to obtain rights to the subsurface mineral estate with the expectation to apply to reservoir pore space for CO 2 storage in an analogous manner to storage of natural gas, which is a common practice in Indiana. There is, however, no precedent in Indiana to take liability for stored CO 2 . There are currently no Indiana State incentives for CCS, but at the Federal level, tax credits for carbon capture and storage under 26. U.S. Code § 45Q constitute the greatest incentive targeted at CCS projects. The amendment to these credits put forth in the Bipartisan Budget Act (the FUTURE Act) of 2018 substantially increases the per-ton incentive for CCS—from $22.66 per ton in tax year 2017 up to $50 per ton in tax year 2027, for CO 2 not used as an injectant (i.e. saline storage). Additional economic opportunities may exist for the provision of CO 2 for potential EOR in the Illinois Basin. Policies that may support the development of CO 2 pipelines and/or CCS projects in Indiana include: 1) Title 41 of the FAST Act (2015), which created a new governance structure, procedures, and funding authorities in order to improve and expedite Federal review and authorization of covered infrastructure projects, including pipelines, and 2) the Eminent Domain for Transportation of Carbon Dioxide by Pipeline (IC 14-39, Indiana State, 2011), which declares pipeline transportation of CO 2 exclusively to a carbon management application, including sequestration, enhanced oil recovery, and deep saline injection as a benefit to the welfare of Indiana and the people. The US Environmental Protection Agency’s (EPA) Underground Injection Control (UIC) Program Class VI rule and permit requirements address all components pertaining to CO 2 injection and monitoring for long-term storage, and outline the minimum technical criteria to protect underground sources of drinking water at, and surrounding, injection well sites. The Class VI requirements also address financial responsibility for corrective action, post-injection site care, and site closure. In addition, UIC Program public notice requirements include that the EPA issue notice of the draft permit preparation to key stakeholders, and open a public comment period of not less than 30 days. A public hearing about the permit would also be held, if specifically requested by the public. A potential Class VI CO 2 injection well permit for the East Sub-Basin case study site would be obtained through the US EPA Region 5, because the State of Indiana does not have UIC Class VI primacy. Although no CO 2 injection wells have been permitted in Indiana, the US EPA Region 5 (which covers Illinois and Indiana) and the East Sub-Basin CarbonSAFE team (via the Midwest Geological Sequestration Consortium [MGSC]) have Class VI permitting experience from several projects located in Illinois. Based on our experience, applying for a Class VI permit can be an intensive and iterative process requiring clear communication and numerous interactions with EPA staff. In addition to gathering and preparing the data/models and documentation necessary for a permit application’s initial submittal, the subsequent public comments, EPA response and review, and answering of any follow-up questions/requests by the EPA could significantly increase the timeframe of draft permit issuance. The US EPA offers guidance documents regarding the specific Class VI permit requirements, and shows a general permitting timeline example from the FutureGen Alliance 2.0 covering one-and-a-half years from permit submittal to issuance. However, the overall permitting process to-date has a high degree of variability, and in MGSC’s project experience we observed a more extended timeline to receive Class VI permits for each of two CO 2 injection wells.

01 COAL, LIGNITE, AND PEAT↗

DOE OSTI2025

Carbon‐negative hydrogen from ethanol via catalytic oxidative reforming

Abstract This study evaluated a commercial technology for producing low‐ or negative‐carbon hydrogen through ethanol catalytic oxidative reforming, focusing on the life cycle greenhouse gas emissions, or carbon intensity (CI). Various scenarios were analyzed: (a) comparing corn ethanol (first‐generation or Gen1 ethanol) and cellulosic ethanol (second‐generation or Gen2 ethanol) as feedstocks; (b) assessing carbon capture and sequestration (CCS) for CO 2 from upstream fermentation; and (c) evaluating oxygen sourcing via air separation units vs. on‐site or off‐site water electrolysis using a proton exchange membrane. Findings indicate that the CI for hydrogen production using Gen2 ethanol from corn stover is lower than that of Gen1 corn ethanol. Additionally, using proton exchange membrane‐generated oxygen results in a lower CI than air separation unit‐generated oxygen, regardless of the sourcing method. Implementing CCS for the hydrogen production plant's evolved CO 2 is essential for achieving a net‐negative CI for hydrogen from Gen1 ethanol. All examined scenarios, including both ethanol generations, oxygen sources, and CCS applications, demonstrated a net‐negative carbon intensity, surpassing the life cycle greenhouse gas emissions threshold of 0.45 kg CO 2 e/kg to enable policy credits as outlined in the Inflation Reduction Act §45V. In comparison, the CI for hydrogen from steam methane reforming stands at 3.4 kg CO 2 e/kg with CCS and 9.4 kg CO 2 e/kg without CCS.

08 HYDROGEN↗