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Search indexed NASA NTRS and DOE OSTI research on propulsion, heat transfer, battery materials and energy systems. Follow report and document links to the original sources.

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At least 37 records · Page 2
All sourcesNASA NTRSDOE OSTI
DOE OSTI2022

Single–Well Injection–Drift Test to Estimate Groundwater Velocity

A simple algebraic equation is presented here to estimate the magnitude of groundwater velocity based on data from a single-well injection-drift test thereby eliminating the time-consuming and costly extraction phase. A volume of tracer-amended water was injected by forced-gradient into a single well followed by monitoring of the conservative solute tracers under natural-gradient conditions as their upgradient portions drifted back through the well. The breakthrough curve data from the single well during the drift phase was analyzed to determine the mean travel times of the tracers. The estimated mean upgradient travel distance back through the single well and the mean travel times of the tracers were used in a simple algebraic equation to estimate groundwater velocity. The groundwater velocity based on the single-well injection-drift test was estimated to be approximately 0.64 ft per day. Two transects of observation wells were used to monitor the natural-gradient tracer transport downgradient of the injection well. The one-dimensional, or dual-well, transport of the tracer from the injection well to the nearest downgradient observation well indicated that the groundwater velocity was 0.55 ft per day. The two-dimensional, or multi-well, transport of the center of mass of the tracers indicated that the groundwater velocity was 0.60 ft per day; the dual- and multi-well results were in excellent agreement with those from the single-well and validated the simple algebraic equation. In conclusion, the new single-well method presented here is relatively simple, rapid, and does not require an extraction phase.

54 ENVIRONMENTAL SCIENCES↗
DOE OSTI2023

9A Injection: July 26 thru November 21, 2022

Processed Gladwin Tensor Strainmeter, Optical Fiber Tensor Strainmeter, and well pressure data from the well 9A injections from July 26 thru November 21, 2022, at the North Avant Field, OK

Land-surface deformation↗
DOE OSTI2019

9A Injection: October 11 thru October 17, 2017

Processed Gladwin Tensor Strainmeter, Eddy current vertical strain and tilt, and well pressure data from the well 9A injection on October 11 thru October 17, 2017, at the North Avant Field, OK

Geologic Carbon Storage↗
DOE OSTI2016

Surface uplift and time-dependent seismic hazard due to fluid injection in eastern Texas

Observations that unequivocally link seismicity and wastewater injection are scarce. We show that wastewater injection in eastern Texas causes uplift, detectable in radar interferometric data up to >8 kilometers from the wells. Using measurements of uplift, reported injection data, and a poroelastic model, we computed the crustal strain and pore pressure. We infer that an increase of >1 megapascal in pore pressure in rocks with low compressibility triggers earthquakes, including the 4.8–moment magnitude event that occurred on 17 May 2012, the largest earthquake recorded in eastern Texas. Seismic activity increased even while injection rates declined, owing to diffusion of pore pressure from earlier periods with higher injection rates. Finally, induced seismicity potential is suppressed where tight confining formations prevent pore pressure from propagating into crystalline basement rocks.

58 GEOSCIENCES↗
DOE OSTI2014

Restoration of the Potosi Dynamic Model 2010

In topical Report DOE/FE0002068-1 [2] technical performance evaluations on the Cambrian Potosi Formation were performed through reservoir modeling. The data included formation tops from mud logs, well logs from the VW1 and the CCS1 wells, structural and stratigraphic formation from three dimensional (3D) seismic data, and field data from several waste water injection wells for Potosi Formation. Intention was for two million tons per annum (MTPA) of CO2 to be injected for 20 years. In this Task the 2010 Potosi heterogeneous model (referred to as the "Potosi Dynamic Model 2010" in this report) was re-run using a new injection scenario; 3.2 MTPA for 30 years. The extent of the Potosi Dynamic Model 2010, however, appeared too small for the new injection target. It was not sufficiently large enough to accommodate the evolution of the plume. Also, it might have overestimated the injection capacity by enhancing too much the pressure relief due to the relatively close proximity between the injector and the infinite acting boundaries. The new model, Potosi Dynamic Model 2013a, was built by extending the Potosi Dynamic Model 2010 grid to 30 miles x 30 miles (48 km by 48 km), while preserving all property modeling workflows and layering. This model was retained as the base case. Potosi Dynamic Model 2013.a gives an average CO2 injection rate of 1.4 MTPA and cumulative injection of 43 Mt in 30 years, which corresponds to 45% of the injection target. This implies that according to this preliminary model, a minimum of three (3) wells could be required to achieve the injection target. The injectivity evaluation of the Potosi formation will be revisited in topical Report 15 during which more data will be integrated in the modeling exercise. A vertical flow performance evaluation could be considered for the succeeding task to determine the appropriate tubing size, the required injection tubing head pressure (THP) and to investigate whether the corresponding well injection rate falls within the tubing erosional velocity limit. After 30 years, the plume extends 15 miles (24 km) in E-W and 14 miles (22 km) in N-S directions. After injection is completed, the plume continues to migrate laterally, mainly driven by the remaining pressure gradient. After 100 years post-injection, the plume extends 17 miles (27 km) in E-W and 15 miles (24 km) in N-S directions. The increase of reservoir pressure at the end of injection is approximately 370 psia around the injector and gradually decreases away from the well. The reservoir pressure increase is less than 30 psia beyond 14 miles (22 km) away from injector. The initial reservoir pressure is restored after approximately 20 years post-injection. This result, however, is associated with uncertainties on the boundary conditions, and a sensitivity analysis could be considered for the succeeding tasks. It is important to remember that the respective plume extent and areal pressure increase corresponds to an injection of 43 Mt CO2. Should the targeted cumulative injection of 96 Mt be achieved; a much larger plume extent and areal pressure increase could be expected. Re-evaluating the permeability modeling, vugs and heterogeneity distributions, and relative permeability input could be considered for the succeeding Potosi formation evaluations. A simulation using several injectors could also be considered to determine the required number of wells to achieve the injection target while taking into account the pressure interference.

Adushita, Yasmin↗
DOE OSTI2023

Utah FORGE: Well 16A(78)-32/Well16B(78)-32 Circulation Test Data

This dataset encompasses the collected data and associated reports from the low-rate injection circulation test conducted on wells 16A(78)-32 and 16B(78)-32 in July 2023 at Utah FORGE. It includes comprehensive raw circulation data, captured by Pason and Schlumberger (SLB). The dataset details various parameters recorded during circulation testing such as produced fluid, injection pressure, injection rate, produced rate, temperature, downhole pressure difference, bottom hole pressure in the well, and surface treating pressure. Note that the Pason data is presented in Mountain Time, whereas the SLB data is in Pacific Time.

15 GEOTHERMAL ENERGY↗
DOE OSTI2018

Using distributed temperature sensing to detect CO 2 leakage along the injection well casing

The objective of this study is to evaluate the sensitivity of Distributed Temperature Sensing (DTS) data to detect CO 2 leakage along an injection well casing. This paper describes the relationship between the CO 2 leakage rate and temperature response at DTS locations, and the method and numerical model used for understanding such a relationship. The uncertainties in the parameters are propagated to the interpretation of DTS measurements, which may lead to false positive and false negative identifications of CO 2 leakage. We propose to identify CO 2 leakage by analyzing both temperature history plots at selected vertical locations as well as the vertical temperature profiles at different times. The analysis should be combined with numerical simulations for the estimation of leakage rates. In addition, leakage needs to be confirmed by data from a warm-up test (temperature recovery after injection of cold CO 2 is stopped) to minimize the probability of false identifications.

42 ENGINEERING↗
DOE OSTI2023

WELLS Database

The Wellbore Exploration and Location Logistic System (WELLS) is a living national wellbore database - created and maintained by the National Energy Technology Laboratory (NETL). This resource contains more than seven million public wellbore records from state, federal, and tribal resources. Sourced from over 65 authoritative, yet disparate resources, the WELLS Database combines and synthesizes well data from oil, gas, underground injection, research, geothermal, geotechnical, groundwater and other types of wells in a single, unified system. This resource can be explored and visualized through the WELLS Interactive Application, also on EDX: https://edx.netl.doe.gov/dataset/wells-interactive-application The WELLS Database (formerly titled CO2-Locate) is an integrated national well dataset, representing open-source wellbore data from disparate state, tribal, and federal entities. The database provides publicly available well header data with key attributes such as well age, depth, and status. The database contains a fully integrated CSV file with all values in numerical columns, such as depth, converted into numbers. This version has a NETL derived API (American Petroleum Institute) number column and has been handled for redundancies, resulting in one record for every unique API number. The database also contains a fully integrated CSV file, where all original data are kept as text values. Additionally, the database includes a shapefile containing key attributes and coordinates from the integrated dataset, reformatted public wells CSV files, and a proprietary well density grid shapefile. Notes for consideration: The WELLS Database will be updated periodically with new datasets and information. A field dictionary with field (i.e., attribute) coverage across acquired public well resources, and the resulting integrated public well datasets are available in the spreadsheet, WELLS_Field_Dictionary.xlsx. Summary layers provided in this database are derived from proprietary layers and do not always contain key features (status, type, true vertical depth, or spud year) and therefore might not be shown when data are queried for those features.

AS↗
DOE OSTI2025

Developing a Prototype Methodology to Rank CO2-EOR Wells and Assess Their Reuse Potential for Geologic Carbon Storage

This paper presents a prototype methodology to assess the possible transition of Class II carbon dioxide-enhanced oil recovery (CO2-EOR) wells to Class VI wells. The focus is on wellbore construction materials—casing, cement, tubing, and the packer—and includes comprehensive workflows to evaluate these materials, with primary emphasis on compliance with Environmental Protection Agency (EPA) Class VI well construction and conversion guidelines. These workflows systematically assess material properties and performance criteria to ensure regulatory compliance and optimize long-term wellbore integrity and functionality. Utilizing Python scripts and JavaScript Object Notation (JSON) representations, the study automates checks on digitized Texas Railroad Commission (TRRC) data to rank wells based on workflow criteria. By emphasizing critical factors such as casing integrity, cementing techniques, tubing compatibility, and packer selection, the methodology helps well owners and operators prioritize wells for potential reuse as CO2 injection wells. Given limitations in digitized data, manual user verification is required in some sections. Future improvements include integrating non-digitized data through web scraping and machine learning techniques. This research serves as a practical guide for stakeholders, supporting environmental compliance and sustainable well operations.

geologic carbon sequestration↗
DOE OSTI2026

Illinois Storage Corridor, CarbonSAFE Phase III: UIC Class VI Permitting Plan

The Illinois Storage Corridor (ISC) project evaluated two distinct sites to determine the feasibility of commercial-scale CO₂ storage at each. The project leveraged the region's exceptional geological characteristics, particularly the well-characterized Cambro-Ordovician Storage Complex, to enable permanent geological storage of more than 50 million tonnes of CO₂ over 30 years. The two storage sites are located at One Earth Energy (OEE) facility in northcentral Illinois and Prairie State Generating Company (PSGC) in southcentral Illinois. Once operational, these facilities will combine to capture and store more than 6.5 million tonnes of CO₂ per year, positioning the ISC among the largest carbon storage regions globally. Preliminary homogeneous dynamic modeling based on regional and site-specific reservoir characteristics indicates promising injection capabilities at both locations. For the OEE site, modeling predicts a maximum allowable injection rate of 3.7 MTPA, with a baseline scenario of 1.7 MTPA over 30 years producing a CO₂ plume radius of 1.4 miles at end of injection. For the PSGC site, incorporating recent well data, modeling indicates a single-well maximum injection rate of 2.1 MTPA, with a plume radius of 4.2 miles at end of injection for the 60 MT over 30 years scenario. The primary objective of this CarbonSAFE Phase III project is to develop and submit Class VI Underground Injection Control (UIC) permit applications to the U.S. Environmental Protection Agency Region 5. The permitting plan outlines comprehensive site characterization, Area of Review delineation, monitoring programs, well construction designs, financial responsibility provisions, and post-injection site care procedures necessary to demonstrate safe, permanent CO₂ storage protective of underground sources of drinking water. Three UIC Class VI permit applications for the OEE site were submitted to EPA in October 2022 and are progressing through technical review, with final permit decision projected by June 2026. Through five rounds of Requests for Additional Information and responses, the applications have been refined to address computational modeling, area of review delineation, well integrity, monitoring protocols, and financial assurance requirements. For the PSGC site, finalized characterization and permitting documentation was delivered directly to the facility in July 2023 due to business constraints precluding formal federal regulatory submission. This comprehensive permitting effort builds upon extensive prior subsurface evaluations and demonstration projects that have confirmed the feasibility of widespread commercial-scale carbon storage in the region.

01 COAL, LIGNITE, AND PEAT↗
DOE OSTI2023

NEWTS Well Summary by Hydrologic Regions and Subbasins in the U.S.

Oil and gas well production data (2000-2022), including water production and injection, as well as summary information (e.g., well count by status, total vertical depth statistics, etc.) spatially summarized by Watershed Boundary Dataset's (WBD) region (Hydrologic Unit Code (HUC) 2) and subbasin (HUC8). Energy-related produced waters data were acquired and summarized in support of the development of the National Energy Technology Laboratory's NEWTS (National Energy Water Treatment and Speciation Database). Due to the proprietary nature of the wellbore data, this derived product has been spatially compiled by key areas to support research and stakeholder needs.

Energy Infrastructure↗
DOE OSTI2024

Subsurface Energy Systems Mapping Inquiry Tool (MapIT)

The Subsurface Energy Systems Mapping Inquiry Tool (MapIT) is an online web mapping tool designed to help users discover available public-sourced data to facilitate data exploration for subsurface energy exploration and characterization efforts for resource identification (e.g. critical minerals, hydrocarbons, geothermal) as well as injection of geologic sequestration of carbon dioxide (e.g. enhanced oil recovery, saline storage, etc.). Modules within the tool curate data related to geology, faults, fractures, injection and confining zones, hydrologic information, groundwater, groundwater wells, geomechanical and petrophysical data, and geochemical data. User documentation on how to use the tool is also provided. Data have been collected from authoritative national, state, and local sources and made available in this tool. The data is also available as a data catalog and Esri Geodatabase at: https://edx.netl.doe.gov/dataset/mapit-database Disclaimer: There is no guarantee of completeness or appropriateness for individual user’s requirements. Use of this tool is solely at the discretion of the user. See full Federal Disclaimer for further information (https://netl.doe.gov/home/disclaimer). This project was funded by the United States Department of Energy, National Energy Technology Laboratory, in part, through a site support contract. Neither the United States Government nor any agency thereof, nor any of their employees, nor the support contractor, nor any of their employees, makes any warranty, express or implied, or assumes any legal liability or responsibility for the accuracy, completeness, or usefulness of any information, apparatus, product, or process disclosed, or represents that its use would not infringe privately owned rights. Reference herein to any specific commercial product, process, or service by trade name, trademark, manufacturer, or otherwise does not necessarily constitute or imply its endorsement, recommendation, or favoring by the United States Government or any agency thereof. The views and opinions of authors expressed herein do not necessarily state or reflect those of the United States Government or any agency thereof. https://www.netl.doe.gov/home/disclaimer

Carbon Sequestration↗
DOE OSTI2014

Southeast Carbon Sequestration Partnership (SECARB) Phase III Anthropogenic Test at Citronelle Field, Mobile Co., AL: Project Assessment Report

The Southeast Carbon Sequestration Partnership Phase III Anthropogenic Test at Citronelle Field is the United States’ largest CO 2 capture and transportation, injection, storage and monitoring project using CO 2 derived from a coal-fired power station. The project represents a U.S. Department of Energy research and development initiative designed to demonstrate deep underground injection and containment of 100,000 tonnes or more of anthropogenic-source CO 2 . This report provides an assessment of the CO 2 injection at the Citronelle Anthropogenic Test site for the period August 23, 2012 to August 31, 2013. The purpose of the project assessment is to re-evaluate the AoR for the injection well. The AoR is defined as the region surrounding the geological sequestration project that may be impacted by the injection activity. The AoR is further defined as the farthest reach of the tangible CO 2 plume and/or the region of ‘significant’ reservoir pressure increase. An updated geologic model of the injection zones and storage reservoir sandstones incorporates geologic data obtained from the injection well and characterization wells drilled at the Phase III Anthropogenic Test site. The numerical modeling of the injection was conducted using the updated geologic model, plus the monitoring results obtained to August 31, 2013. The simulation demonstrates effective containment of CO 2 by the reservoir architecture of the upper Paluxy Formation, consisting of multiple, stacked, highly porous and permeable sandstones, separated by low permeability flow barriers. The CO 2 containment demonstrated in this report requires an AoR with a radius of 440 ft from the injection well. This revision reduces the radius of the AoR from the preinjection determination of 1,700 ft. With the revised AoR, the only well within the AoR is the injection well itself, the D 9-7 #2. The nearest well to the injector is the D 9-8 #2. The surface location is 870 ft away from the D 9-7 #2, placing the D 9-8 #2 outside the revised AoR.

01 COAL, LIGNITE, AND PEAT↗
DOE OSTI2023

Real-Time Monitoring of Fracture Dynamics with a Contrast Agent-Assisted Electromagnetic Method

In collaboration with the Advanced Energy Consortium, our team has previously demonstrated that the placement of electrically active proppants (EAPs) in a hydraulic fracture surveyed by electromagnetic (EM) methods can enhance the imaging of the stimulated reservoir volumes during hydraulic fracturing. That work culminated in constructing a well-characterized EAP-filled fracture anomaly at the Devine field pilot site (DFPS). In subsequent laboratory studies, we observed that the electrical conductivity of our EAP correlates with changes in pressure, salinity, and flow. Thus, we postulated that the EAP could be used as an in-situ sensor for the remote monitoring of these changes in previously EAP-filled fractures. This paper presents our latest field data from the DFPS to demonstrate such correlations at an intermediate pilot scale. We conducted surface-based EM surveys during freshwater (200 ppm) and saltwater (2,500 ppm) slug injections while running surfaced-based EM surveys. Simultaneously, we measured the following: 1) bottomhole pressure and salinity in five monitoring wells; 2) injection rate using high-precision data loggers; 3) distributed acoustic sensors in four monitoring wells; and 4) tiltmeter data on the survey area. We demonstrated that injections into an EAP-filled fracture could be successfully coupled with real-time electric field measurements on the surface, leading to remote monitoring of dynamic changes within the EAP-filled fracture. Furthermore, by comparing the electrical field traces with the bottomhole pressure, flow rate, and salinity, we concluded that the observed electric field in our study is influenced by fracture dilation and flow rate. Salinity effect was observed when saltwater was injected. EM simulations solely based on assumptions of fracture conductivity changes during injection did not reproduce all of the measured electric field magnitudes. Preliminary estimates showed that including streaming potential in our geophysical model may be needed to reduce the simulation mismatch. The methods developed and demonstrated during this study will lead to a better understanding of the extent of fracture networks, formation stress states, fluid leakoff and invasion, characterizations of engineered fracture systems, and other applications where monitoring subsurface flow tracking is deemed important.

02 PETROLEUM↗
DOE OSTI2023

Moving-horizon false data injection attack design against cyber–physical systems

Systematic attack design is essential to understanding the vulnerabilities of cyber–physical systems (CPSs), to better design for resiliency. In particular, false data injection attacks (FDIAs) are well-known and have been shown to be capable of bypassing bad data detection (BDD) while causing targeted biases in resulting state estimates. However, their effectiveness against moving horizon estimators (MHE) is not well understood. In fact, this paper shows that conventional FDIAs are generally ineffective against MHE. One of the main reasons is that the moving window renders the static FDIA recursively infeasible. Here, this paper proposes a new attack methodology, moving-horizon FDIA (MH-FDIA), by considering both the performance of historical attacks and the current system’s status. Theoretical guarantees for successful attack generation and recursive feasibility are given. Numerical simulations on the IEEE-14 bus system further validate the theoretical claims and show that the proposed MH-FDIA outperforms state-of-the-art counterparts in both stealthiness and effectiveness. In addition, an experiment on a path-tracking control system of an autonomous vehicle shows the feasibility of the MH-FDIA in real-world nonlinear systems.

42 ENGINEERING↗
DOE OSTI2017

Aquistore CO 2 Storage Project: Numerical Modeling and Simulation Update

This updated simulation model at the EERC is now capable of reproducing (with a global history-matching error of around 7%) not only the continuous pressure response but also the well logging monitoring data such as CO 2 flow distributions at the injection well and the CO 2 breakthrough profile at the observation well. The first arrival of CO 2 at the observation well is not known. The PNL data collected in February 2016 showed clear evidence of CO 2 presence with saturation values as high as 60% at the observation well while a monitoring logging event (a pulsed-neutron decay [PND]) prior to that one, performed on December 4, 2015, showed no sign of CO 2 . The history-matching results indicate that CO 2 appears to have first arrived at the iv observation well around mid-December 2015, after approximately 8 months of injection. At the end of the history-matching process, the simulated CO 2 plume extent appears the largest in Perforation 2 with a diameter of 540 m around the injection well.

54 ENVIRONMENTAL SCIENCES↗
NASA NTRS2002

Lost Hills Field Trial - incorporating new technology for resevoir management

This paper will discuss how Chevron U.S.A. Production Company is implementing a field trial that will use Supervisory Control and Data Acquisition (SCADA)on injection wells, in conjunction with satellite images to measure ground elevation changes, to perform real-time resevoir management in the Lost Hills Field.

SAR interferometry ground subsidence oil fields re↗
DOE OSTI2018

EGS Collab Project Experiment 1 Overview and Progress

Enhanced Geothermal Systems (EGS) offer the potential to extract and use large quantities of clean energy, but questions remain on reservoir creation and sustainability. The EGS Collab project, supported by the US Department of Energy’s Geothermal Technologies Office, is establishing a suite of highly monitored and well-characterized intermediate-scale (~10-20 m) field test beds along with fracture stimulation and interwell flow tests to better understand processes that control formation of effective subsurface heat exchangers. EGS Collab tests will provide a means of testing tools and concepts that could later be employed under geothermal reservoir conditions at DOE’s Frontier Observatory for Research in Geothermal Energy (FORGE) or enhanced geothermal systems. Key to the project is using numerical simulations in the experiment design and interpretation of results. Our first set of experiments is underway at the Sanford Underground Research Facility (SURF) in South Dakota. To date, stepwise stimulations have been performed at two locations, with the final stimulation connecting our injection and production wells. Numerous data have been collected and are currently being analyzed.

Enhanced Geothermal Systems, EGS Collab, Stimulati↗