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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 19 records
All sourcesNASA NTRSDOE OSTI
DOE OSTI2024

Repurposing Inactive Oil and Gas Wells for Energy Storage: Maximizing the Potential Via Optimal Drivetrain Control: Preprint

In recent years, there has been a growing emphasis on utilizing energy storage to enhance grid resilience against disruptive events. While renewable energy supply continues to expand, gravity-based solutions like pumped hydro remain dominant in the commercial space. However, their geographical limitations constrain availability, scalability, and increase costs for co-locating solar and wind energy. An alternative approach proposes repurposing idle oil and gas wells located closer to existing grid infrastructure, offering a promising and cost-effective solution. This paper addresses the optimization and control of a regenerative drive system coupled to an interior permanent magnet synchronous machine in a 300-meter well with a 100-Newton weight. The study employs a dynamic MATLAB/Simulink model to simulate the operation of the electric drivetrain system during storage and discharge operations. The results demonstrate an initial round-trip efficiency of 85.9% for the electrical system alone and identify crucial factors for maximizing efficiency. The optimized operation and control of the electromechanical drivetrain system hold great potential for minimizing the levelized cost of storage while maximizing efficiency and revenue generation.

ENERGY STORAGE,ENGINEERING↗
DOE OSTI2018

Well Design, Operation and Maintenance and Proactive Rehabilitation to Optimize Remediation Well Performance - 18605

Optimizing performance of extraction, injection and monitoring wells, which are integral components of groundwater remediation systems, result in lower life cycle costs and a higher probability of meeting project objectives. These wells provide the means to extract contaminated groundwater, inject reagents, treated water and clean water to create groundwater reaction/flushing zones, and to provide groundwater level, contaminant concentration and geochemical data. Initial costs associated with well installation and associated pipelines and treatment systems are significant project expenditures related to site remediation. However, the life cycle costs for wells are dominated by the long-term operation and maintenance (O and M) expenditures. Remediation wells are particularly susceptible to various types of fouling that impact well performance and, therefore, drive up operating costs. Simply defined, fouling is the result of any biological, geochemical or physical process that negatively impacts the intended performance of a remediation well. Fouling decreases well performance by effectively reducing hydraulic communication between the well and the surrounding formation. Oftentimes this occurs via clogging screens and/or gravel pack/formation pore space by bacterial or chemical byproducts and gases, which can lead to corrosion of metal components and spreading fouling deposits to pipelines and surface treatment systems. Ultimately, this results in reduced hydraulic performance in extraction and injection wells and result in erroneous water level and chemical parameter concentration measurements in monitoring wells. Remediation well fouling cannot be eliminated, and natural fouling processes are exacerbated by the installation and operation of remedial systems. Steps required to extend the life of remediation wells and to lower life cycle costs are discussed in this paper in order to establish the required approach to effective system management. These optimization approaches have been developed through years of operation and maintenance of complex large-scale plume remediation systems utilizing a variety of subsurface in-situ and ex-situ technologies. Remediation well performance can be improved by: - careful site characterization, - appropriate well design, - proper well installation and development, - thoughtful and adaptable operation and maintenance, - well performance maintenance tracking and, - proactive well rehabilitation. Clear understanding of the site hydro-stratigraphy and geochemical settings places constraints on the compatibility of well materials and the configurations of well screens. Proper well design, including collection and analysis (sieve/grain-size) of screen zone formation samples, assures that wells can be optimally installed, developed and redeveloped during well rehabilitation. Design considerations should include proper sizing of filter packs and well screens, casing/screen diameter, well material selection/compatibility, expected life/use, and well head configuration to allow for future access. Applying appropriate and effective well installation and development methods are of paramount importance and rely on a good understanding of site characteristics (e.g., geologic setting) as well as local drilling company expertise and experience. Different approaches to operation and maintenance can greatly affect the degree of fouling, these include limiting reagent concentrations, maintaining submerged well screens and filtering injection water to prevent the introduction of fouling enhancing constituents. Tracking well performance by monitoring changes in system operation and metrics such as specific capacity or injectivity for extraction and injection wells, respectively, or turbidity and chemical analyses for monitoring wells is key to identifying well maintenance issues early when well rehabilitation can be most effective. Proactive well rehabilitation can include mechanical brushing, surging and jetting, chemical treatment or other specialized approaches; however, the approach needs to be based on a site-specific understanding of the predominant fouling mechanisms. Collection and analyses of fouling deposits can provide guidance for selection of rehabilitation methods and chemicals that will be most effective. Application of these approaches have led to extended operational life for reagent injection wells, which can foul quickly, from months to years. Additionally, proper maintenance will often lead to increased and extended productivity of the well. For extraction wells, this translates to a higher sustainable yield, which means shorter cleanup times. Similarly, for injection wells, proper maintenance allows for the introduction of a greater volume of reagents over a shorter period, thus, shorter cleanup times that reduce overall project costs. (authors)

12 MANAGEMENT OF RADIOACTIVE AND NON-RADIOACTIVE W↗
DOE OSTI2024

Results from an Aeromagnetic Survey to Detect Steel-Cased Wells at a Marcellus Shale Well Site in Washington County, Pennsylvania

Pennsylvania has a 150-year history of oil and gas production—the longest of any state—and this enduring activity has resulted in the drilling of more than 300,000 recorded wells. However, unknown wells likely exist because innumerable wells were drilled during Pennsylvania’s intense early oil and gas history when incomplete records were kept of well locations. There is concern that early wells are likely to be ineffectively sealed because there were no laws that required plugging when the wells were abandoned. Today, many undocumented and unplugged wells are thought to be in areas of emerging shale gas and shale oil development where open wellbores can provide a pathway for undesired upward migration of fluids and gas from hydraulically fractured reservoirs. Due to this concern, Pennsylvania regulators have asked operators to locate orphaned and abandoned wells within a 1,000-ft buffer of proposed new wells. The objective of this report is to demonstrate that high-resolution aeromagnetic surveys, historic air photos, and Light Detection and Ranging (LiDAR) imagery can be rapid and effective methods to reconnoiter large, forested areas of moderate terrain for the presence of abandoned wells. These well-finding methods were evaluated at a proposed Marcellus Shale gas drilling site in Washington County, Pennsylvania, where the methods collectively located 18 confirmed wells: 15 wells were identified from aeromagnetic surveys, two wells were identified from inspection of historical air photos, and one well was identified by evaluation of state-wide LiDAR imagery. Only six wells were previously known, and their locations, as recorded in Pennsylvania’s statewide oil and gas wells database (PA/IRIS/WIS), were often too inaccurate for the wells to be found in the dense underbrush. Twelve wells identified in this study were abandoned, unmarked, and undocumented. Aeromagnetic surveys locate wells by detecting the unique magnetic signature of vertical, steel well casing, which is depicted on magnetic maps as a “bull’s eye” type anomaly that is centered directly over the well. However, when wells were drilled and found to be sub-economic, their casing was sometimes pulled and salvaged for reuse. Such wellbores provide no magnetic response and go undetected if all casing was removed. Oftentimes attempts to retrieve well casing were not 100% successful. For example, historical records for one well in the study area indicate that the well was completed in 1902 as a dry hole and that, to the extent possible, the casing was pulled for reuse. However, a section of 10-in. diameter steel casing was not recovered and remains at an unknown depth in the wellbore. This well was easily detected by the aeromagnetic survey although only deep casing remained in the well. To mitigate for the likelihood that wellbores exist where most or all casing has been removed, this study augmented aeromagnetic data with historic air photos and digital terrain models generated from LiDAR datasets—both databases are publicly available at no cost for areas within Pennsylvania. These complementary methods located three wells where the aeromagnetic anomaly, although present, was subtle and overlooked. Together, these methods determined accurate locations for six known wells within the study area and located 12 previously unknown wells. Although it is not certain that these methods successfully located all wells in the study area, the application of these methods does represent a significant improvement over relying on existing databases for well locations. For the Appendix to the report, see: https://www.netl.doe.gov/energy-analysis/details?id=b46c417a-7c9e-4d25-b810-e6248b0217f4</p>

04 OIL SHALES AND TAR SANDS↗
DOE OSTI2021

Wells of Opportunity: An Assessment of Idle Geothermal Wells in Nevada

Geothermal energy is poised to play an increasing role in the energy transition over the coming decades. At the same time, idled and inactive geothermal wells represent both an opportunity for increased geothermal energy production but also an environmental risk. However, it is unclear how many geothermal wells are idled or inactive, making it difficult to identify pathways to redeploy these wells or prioritize them for additional monitoring, maintenance, or abandonment. Through a comparison of state well databases, this study develops an inventory of all existing large-bore wells at geothermal fields in Nevada to identify idled wells and their characteristics. The results show that at least 91 production or injection wells may be idled (inactive for 7 or more years), representing 21% of inventoried wells across all fields. This idled rate is significantly below the national rate for oil and gas wells (69%), though there are an additional 92 geothermal wells with an unknown status. The average age and length of inactivity for potentially idled geothermal wells is 26 and 23 years respectively, and active generation fields comprise most of the inventory (83%). Idled well incidence varies significantly across active fields, with 6 of the 17 fields having idled rates of 20%-50% and/or more than 5 idled wells, while 3 fields have no idled wells and the remaining fields have rates below 20%. Younger or more recently idled wells at these active fields likely present the best opportunities for future use or enhanced geothermal systems technology testing. However, a significant proportion of the older and long-term idled wells will likely require additional monitoring or eventual abandonment.

geothermal↗
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 OSTI2024

TCF - Sustainable Well Cement for Geothermal, Thermal Recovery, and Carbon Storage wells

Primary cementing is the most important operation performed on a subterranean well. Cement, placed in the annulus between the casing and the formations, serves as a hydraulic seal preventing fluids and gas migrations, protecting steel casing from corrosion, and supporting the well structure. Poor cementing jobs can be directly responsible for wells not reaching their full capacity, casing corrosion, compromised well integrity and, in the worst-case scenarios, well collapse. Geothermal, thermal recovery, and carbon storage wells offer environments that are especially difficult for cements to survive while the required lifespan of these wells can be years. In these wells currently used cements cannot provide durable well integrity, and new solutions are necessary. The necessity of stabilizing the electric grid, increasing its flexibility, and providing energy on demand will further expand the market of durable cement solutions for applications in high-temperature underground reservoir thermal energy storage wells (HT RTES). The design challenges of special cement systems for such wells originate from chemistry limitations of currently used well cements, aggressive environments, temperature and repeated shock conditions associated with them, and very weak formations that are not uncommon in these wells. During the last 70 years the most common systems for thermal-well construction have been Ordinary Portland Cement (OPC) (absolute majority of the wells), silica-lime system, and high aluminum cement-containing formulations. The major issues of calcium-silicate hydrates, that form during the hydration of OPC resulting in hardened material, are their poor chemical resistance to acids due to the calcium interactions with acid anions followed by its eventual dissolution, even in mild acids, such as carbonic acid from CO 2 dissolution, and inadequate bonding to the steel causing serious casing corrosion problems (Sugama & Pyatina, 2019). Performance of OPC-based cement may be significantly improved with organic additives; however, those are limited by their temperature stability. An alternative to calcium-silicate cement was developed by BNL and commercialized by Halliburton as ThermaLock TM cement. Calcium-aluminate-phosphate-based chemistry of the material allowed overcoming acid-resistance problems of OPC, especially in CO 2 -rich geothermal environments. In 2012-2015, building upon this experience, BNL developed Thermal Shock Resistant Cement (TSRC) with the support of Geothermal Technology Office (GTO) of DOE. TSRC has high-temperature stable chemistry, superior properties of cement-metal casing bond and corrosion protection (4-times better than currently used OPC-based formulation), significantly outperforms common well-cements in thermal-shock tests, has self-healing properties, and like ThermaLock TM is CO 2 resistant incorporating carbonate ions into stable hydrates (Gill et al., 2012).

15 GEOTHERMAL ENERGY↗
DOE OSTI2019

Utah FORGE: Phase 2C Seismic Observation and Ground Water Well Data and Well Locations

This submission contains the following data associated with Utah FORGE Phase 2C within the Roosevelt Hot Springs geothermal area: - An ArcGIS shapefile with well locations for wells 58-32, 78-32, 68-32, OH-3, OH-4, WOW-2, and WOW-3. Well 58-32 is the deep test well, wells 68-32 and 78-32 are seismic test wells, and the OH and WOW wells were used for ground water monitoring and temperature gradient logging. - Drilling reports, lithologic logs, daily drilling reports, cuttings logs, and drilling photos for seismic monitoring wells 78-32 and 68-32. - Raw and post-processing temperature logs for wells OH-3, OH-4, WOW-2, and WOW-4. The archive also includes a README.txt file, which contains an explanation of the data and how it was acquired, and a text file with coordinates for the logged wells.

15 GEOTHERMAL ENERGY↗
DOE OSTI2022

Impact of WELL certification on occupant satisfaction and perceived health, well-being, and productivity: A multi-office pre- versus post-occupancy evaluation

The WELL Building Standard (WELL) is currently one of the most comprehensive building certification programs that aim to enhance the health and well-being of building occupants. However, there is a lack of systematic evaluation of the effectiveness of WELL in achieving its goal. This study investigates the impact of WELL certification on occupant satisfaction with the workplace and occupant perceived health, well-being, and productivity. More than 1300 pre- and post-occupancy survey responses provided by the nearly same cohort of occupants from six companies in North America were quantitatively analyzed. The results showed that transitioning to WELL certified offices from non-WELL certified offices had a positive impact on occupant satisfaction with the workplace and occupant perceived health, well-being, and productivity, with increases in means from pre-to post-occupancy being highly statistically significant. The majority of the studied occupant satisfaction parameters as well as occupant perceived mental health had large effect sizes. While they improved from pre-to post-occupancy, the analysis revealed small effect sizes for occupant perceived physical health and self-assessed productivity. The majority of the effect sizes for the perceived well-being parameters were large and medium. In addition to analyzing the survey responses in aggregate, the responses were examined at the individual company level to confirm the by-company and aggregate findings aligned.

32 ENERGY CONSERVATION, CONSUMPTION, AND UTILIZATI↗
DOE OSTI2023

Interpretation of Fracture Initiation Points by In-Well Low-Frequency Distributed Acoustic Sensing in Horizontal Wells

Summary Low-frequency distributed acoustic sensing (LF-DAS) exploits the optical phase shift of Rayleigh backscatter in fiber-optic cables to obtain distributed measurements of changes in strain and temperature. Fiber-optic cables are often installed for multistage hydraulic fracture diagnostics in horizontal wells. LF-DAS in an untreated well provides far-field strain measurements, while offset wells are hydraulically fractured. Such a configuration is called crosswell LF-DAS sensing. Crosswell LF-DAS measurements have proved useful in diagnosing fracture hits, fracture azimuth, planarity, cluster efficiency, fracture propagation rates, and the dynamic distance to the fracture front. In contrast, in-well LF-DAS is conducted on the actively fractured well. Due to cool fracture fluid being injected at high injection rates, the strain component of the LF-DAS response is largely obscured by temperature changes. In permanent fiber-optic cable installations, distributed temperature sensing (DTS) is often conducted simultaneously with LF-DAS. An opportunity exists to decouple the temperature and strain components of LF-DAS sensors to observe strain changes on in-well LF-DAS. The LF-DAS response is modeled as linearly dependent on strain and temperature changes. Theoretical LF-DAS temperature and strain sensitivity coefficients are derived based on the changes to the index of refraction and length of the fiber. Using the DTS measurements, temperature changes are computed, smoothed, filtered, and compared to the LF-DAS response. Crossplots of the in-well LF-DAS measurements and temperature changes from DTS measurements far from the actively fractured region are used to validate the theoretical sensitivity coefficients. Uncertainty in the temperature component of the LF-DAS response is quantified. The difficulty in corresponding the different spatial and temporal resolutions of the DTS and LF-DAS measurements is overcome by comparing the responses over a moving temporal and spatial window. If the LF-DAS response at the center of the window agrees with the DTS response within uncertainty, the measurement is filtered out. After filtering, the remaining nonzero in-well LF-DAS measurements are due to changes in strain. The data are then visualized in waterfall plots. The results indicate that the theoretical and observed strain and temperature coefficients agree within 10%. After the temperature component of the in-well LF-DAS response is extracted, the remaining nonzero measurements are located primarily within the actively treated region. Locations with peaks in the strain response are interpreted to indicate fracture initiation points. These fracture initiation points are compared with in-well DTS and high-frequency DAS noise measurements across multiple stages to better understand fracture initiation along the horizontal well.

Engineering↗
DOE OSTI2019

Managing well leakage risks at a geologic carbon storage site with many wells

Potential geologic carbon storage (GCS) sites with a history of oil and gas production have well-characterized injectivity and storage capacity, but the presence of legacy wells increases leakage risk. Thus, the success of GCS operations at sites with many wells will require a thorough leakage risk assessment and a robust strategy for managing well leakage risk over the lifetime of the project. In this study, we demonstrate a workflow that uses the National Risk Assessment Partnership’s open-source Integrated Assessment Model to quantify well leakage risks and test the performance of various leakage risk management strategies at a heavily drilled GCS site. Here, our model simulates a 50-year basin-scale injection of CO 2 at a hypothetical site based on the Kimberlina Project Site in the Southern San Joaquin Valley of California. Brine and CO 2 leakage through 1,000 legacy wells into a USDW are stochastically simulated as a proxy for risk. We consider multiple scenarios that explore the efficacy of various well leakage risk management strategies with changes in well leakage behavior, reservoir behavior, and post-injection site care (PISC) length. Predicted leakage at the site after 100 years was small with a maximum CO 2 leakage of 102.1 tonnes (4.08×10 -5 % of the 250 Mt injected) and a maximum brine leakage of 2.4 tonnes. Leakage risk management strategies based on accurate prior information about well leak probability reduced leakage risks more effectively at the modeled site and were more robust with respect to reservoir uncertainty than strategies based on the distance of the legacy well from the injector. The importance of the PISC period length was not clear as it had a negligible impact on CO 2 leakage risk but a sizable impact on brine leakage risk in our model.

58 GEOSCIENCES↗
DOE OSTI2026

Optimization of well design and CO 2 injection strategy for risk reduction in Class VI geological carbon sequestration wells

The safety and durability of Class VI wells are critical for geological carbon sequestration (GCS). However, current GCS operations face unique challenges: unlike traditional Class II wells, Class VI CO 2 injection wells operate at rates up to 100 times higher, dramatically increasing the risk of wellbore leakage and structural compromise due to severe temperature drops and associated mechanical stresses. Despite existing guidelines on material selection, there remains a substantial gap in understanding how rapid CO 2 injection rates, low surface temperatures, and variable reservoir conditions interact to threaten long-term well integrity. This study presents a comprehensive, original workflow integrating advanced analytical and numerical models for both well flow and well integrity analysis. By systematically simulating a wide range of field-relevant scenarios—including variations in injection rate, CO 2 temperature, and reservoir pressure—this work provides the first cross-validated assessment of cooling effects on wellbore. The results reveal that extreme temperature drops, up to 60 °C, can occur under high injection rates, particularly in depleted reservoirs, significantly increasing the risk of cement failure. Building on these insights, the study proposes innovative, practical well design and operational strategies, including ductile cement formulations, pre-stressing techniques, advanced insulation coatings, and proactive management of injection rates. The safety of Class VI well extends beyond simply using CO 2 resistant materials. Cement materials should possess optimal thermo-hydraulic-mechanical-chemical properties for effective performance. This work provides a scientific basis for optimizing Class VI well designs, with direct benefits for minimizing environmental risk, lowering operational costs, and enhancing the long-term reliability of GCS.

25 ENERGY STORAGE↗
DOE OSTI2018

Transport and Fate of Natural Gas and Brine Escaping from a Hydrocarbon Reservoir Through a Failed Deepwater Well in the Oceanic Subsurface of the Gulf of Mexico

The possibility of broaching, or the release of fluids at the seafloor due to a damaged or faulty well, is a hazard that must be assessed in the well permitting process. Here, this paper describes a numerical simulation study of a real-life scenario where a complex, permeable sandy formation, connected to the seafloor via known chimneys/seeps, is intersected by a damaged production well that drains another deeper, gas-bearing formation. The objective of the study is to determine the transport and fate of hydrocarbon reservoir fluids (gas and brines) escaping into the sandy formation through the casing shoe of the failed well, and to determine the time it takes for these contaminants to reach the ocean floor. We conducted a detailed simulation study to represent the conditions, properties, and behavior of the system under such failure conditions, and we investigated the migration of gas and brine for a range of reservoir and chimney properties. A key conclusion is that, for such complex systems, modeling the three-dimensional geometry of the system in detail is the key to describing transport and assessing the time and magnitude of potential releases. For the system studied here, transport times range from under 2 years (highest permeabilities) to many decades, ensuring significant time to respond to potential broaching hazards. Lastly, under the conditions investigated in this study, we also determine that gas-dominated releases associated with low rates of water flow into the sandy formation are likely to cause hydrate formation that can reduce permeabilities in the colder, upper regions of the chimneys and possibly mitigate releases.

58 GEOSCIENCES↗
DOE OSTI2024

Aerial imagery dataset of lost oil wells

Orphaned wells are wells for which the operator is unknown or insolvent. The location of hundreds of thousands of these wells remain unknown in the United States alone. Cost-effective techniques are essential to locate orphaned wells to address environmental problems. In this paper, we present a dataset consisting of 120,948 aerial images of recently documented orphan wells. Each of these 512 × 512 images is paired with segmentation masks that indicate the presence or absence of such well. These images, sourced from the National Agriculture Imagery Program, cover the continental United States with spatial resolutions ranging from 30 centimeters to 1 meter. Additionally, we included negative examples by selecting locations uniformly across the United States. Accompanying metadata includes the IDs and spatial resolution of the original images, which are available for free through the United States Geological Survey, and the pixel coordinates of documented orphaned wells identified in these images. This dataset is intended to support the development of deep-learning models that can help locating undocumented orphan wells from such imagery, thereby blunting the environmental damage they do.

Climate-change mitigation↗
DOE OSTI2023

Visualization of fast ion phase-space flow in plasmas well-below, near and well-above Alfvén eigenmode stability threshold in tokamak

Abstract Transport of fast ions along certain local phase space paths, referred to as fast ion phase-space flow, has been systematically measured by an imaging neutral particle analyzer (INPA) in three plasma regimes, which are well-below, near, and well-above the Alfvén eigenmode stability threshold (Du et al 2021 Phys. Rev. Lett. 127 235002). (1) In plasmas well-below the Alfvén eignenmodes (AE) stability threshold, fast ions are well-confined on passing particle orbits without noticeable transport over the phase space. The observed INPA images agree well with the synthetic INPA images, using the fast ion distribution predicted by neoclassical theory. (2) In plasmas near the AE stability threshold, INPA images in the presence of AE activity moderately deviate from those without AE activity. The image difference can be well interpreted by AE-driven, phase-space fast ion flow. Paths of this flow over the velocity space (or streamlines) are reconstructed by the intersection lines of curved E ʹ and µ surfaces, referred to as E ʹ and µ line (where E ′ ≡ E − ( ω / n ) P ζ ; E , P ζ and µ are the energy, canonical toroidal momentum and magnetic moment of ions; ω and n are the angular frequency and toroidal mode number of AEs, respectively). Resonant fast ions move radially inward by gaining energy and move radially outward by losing energy and the trajectory well aligns with the E ʹ and µ lines that pass through the mode resonances near the injection energy of neutral beams. (3) In plasmas well-above the AE stability threshold, fast ion phase-space dynamics shows additional features. Fast ions are transported out of the birth positions so promptly along the streamlines that the slowing-down process from the injection energy is not observable, exhibiting strong critical gradient behavior at local phase space. As a result, the increase of electron temperature is very small, in spite of an increase of beam power by ∼ 45 % . It should be emphasized that the directions of phase-space transport, induced by AEs with different frequencies, structures and mode numbers, do not largely differ.

70 PLASMA PHYSICS AND FUSION TECHNOLOGY↗
DOE OSTI2021

Impact of Rheology Models on Horizontal Well Polymer Flooding in a Heavy Oil Reservoir on Alaska North Slope: A Simulation Study

Polymer rheology can have either a positive or a negative effect on polymer flooding performance under varied circumstances. Many researchers have studied the effect of polymer rheology in a vertical well, but no field scale studies have been conducted to investigate whether polymer rheology is beneficial to polymer flooding in heavy oil reservoirs developed by horizontal wells. In this paper, we conducted a numerical simulation study to examine the effect of HPAM polymer rheology on a polymer flooding pilot, which is the first-ever project conducted on a heavy oil reservoir from Alaska North Slope (ANS) developed by horizontal wells. Three rheology types were considered in the study including the apparent viscosity measured during coreflooding of using a HPAM polymer, the bulk viscosity measured with a viscometer, and a Newtonian flow model. The results suggest that using the bulk viscosity in simulation underestimates the conformance control and the water-oil-ratio reduction capability of the HPAM polymer solution. When the apparent viscosity is used, the incremental oil and sweep were largely increased, and the optimal recovery period of polymer flooding was extended greatly, especially for the heterogeneous formations. Therefore, the rheology type of polymer plays a significant role in the incremental oil recovery and injection profile of the horizontal well system given the pilot test conditions. This study has provided practical guidance to field operators for the ongoing polymer flooding pilot on ANS and will also provide valuable information for other polymer projects conducted in similar conditions.

Leng, Jianqiao↗
DOE OSTI2021

NETL Well Integrity Workshop: Identifying Well Integrity Research Needs for Subsurface Energy Infrastructure

Wells are a critical component of subsurface energy infrastructure. Ensuring the integrity of wells as engineered pathways for the safe extraction, injection, and storage of fluids in the subsurface is key to maximizing the effectiveness and resilience of that infrastructure. Addressing well integrity issues in a technically robust manner that promotes environmental sustainability and social equity is also an important focus of the United States (U.S.) Department of Energy’s (DOE) Office of Fossil Energy and Carbon Management. Industry best practices, regulatory standards, modern monitoring data acquisition and control systems, and decades of research and development have dramatically improved the performance and reliability of wells for hydrocarbon extraction and underground injection in the oil and gas industry. Yet, important innovation is required to improve and ensure well integrity performance in engineered geologic systems where operational environments (fluid composition, temperature, pressure, and/or stress conditions) and long functional life cycles of well systems present unique challenges. Additionally, work is needed to understand and manage the long-term integrity and risks associated with legacy wells—especially those located adjacent to and presenting hazards for new subsurface activity.

02 PETROLEUM↗