Search NASA⌕ Search

SEARCH · Search NASA

Results for “FLUID INJECTION”

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.

Quote a phrase for an exact phrase match. Source license links do not imply unrestricted reuse.

At least 271 records · Page 15
All sourcesNASA NTRSDOE OSTI
NASA NTRS1995

Metamorphosis of a Hairpin Vortex into a Young Turbulent Spot

Direct numerical simulation was used to study the formation and growth of a hairpin vortex in a flat-plate boundary layer and its later development into a young turbulent spot. Fluid injection through a slit in the wall triggered the initial vortex. The legs of the vortex were stretched into a hairpin shape as it traveled downstream. Multiple hairpin vortex heads developed between the stretched legs. New vortices formed beneath the streamwise-elongated vortex legs. The continued development of additional vortices resulted in the formation of a traveling region of highly disturbed ow with an arrowhead shape similar to that of a turbulent spot.

Singer, Bart A.↗
NASA NTRS2010

Transverse Injection into Subsonic Crossflow with Various Injector Orifice Geometries

Computational and experimental results are presented for a case study of single injectors employed in 90 deg transverse injection into a non-reacting subsonic flow. Different injector orifice shapes are used (including circular, square, diamond-shaped, and wide rectangular slot), all with constant cross-sectional area, to observe the effects of this variation on injector penetration and mixing. Whereas the circle, square, and diamond injector produce similar jet plumes, the wide rectangular slot produces a plume with less vertical penetration than the others. There is also some evidence that the diamond injector produces slightly faster penetration with less mixing of the injected fluid. In addition, a variety of rectangular injectors were analyzed, with varying length/width ratios. Both experimental and computational data show improved plume penetration with increased streamwise orifice length. 3-D Reynolds-Averaged Navier-Stokes (RANS) results are obtained for the various injector geometries using NCC (National Combustion Code) with the kappa-epsilon turbulence model in multi-species modes on an unstructured grid. Grid sensitivity results are also presented which indicate consistent qualitative trends in the injector performance comparisons with increasing grid refinement.

Foster, Lancert E.↗
DOE OSTI2015

Code Comparison Study Fosters Confidence in the Numerical Simulation of Enhanced Geothermal Systems

Numerical simulation has become a standard analytical tool for scientists and engineers to evaluate the potential and performance of enhanced geothermal systems. A variety of numerical simulators developed by industry, universities, and national laboratories are currently available and being applied to better understand enhanced geothermal systems at the field scale. To yield credible predictions and be of value to site operators, numerical simulators must be able to accurately represent the complex coupled processes induced by producing geothermal systems, such as fracture aperture changes due to thermal stimulation, fracture shear displacement with fluid injection, rate of thermal depletion of reservoir rocks, and permeability alteration with mineral precipitation or dissolution. A suite of numerical simulators was exercised on a series of test problems that considered coupled thermal, hydraulic, geomechanical, and geochemical (THMC) processes. Problems were selected and designed to isolate selected coupled processes, to be executed on workstation class computers, and have simple but illustrative metrics for result comparisons. This paper summarizes the initial suite of seven benchmark problems, describes the code comparison activities, provides example results for problems and documents the capabilities of currently available numerical simulation codes to represent coupled processes that occur during the production of geothermal resources. Code comparisons described in this paper use the ISO (International Organization for Standardization) standard ISO-13538 for proficiency testing of numerical simulators. This approach was adopted for a recent code comparison study within the radiation transfer-modeling field of atmospheric sciences, which was focused on canopy reflectance models. This standard specifies statistical methods for analyzing laboratory data from proficiency testing schemes to demonstrate that the measurement results do not exhibit evidence of an unacceptable level of bias.

benchmark problems↗
DOE OSTI2021

Recent Thermal and Hydraulic Stimulation Results at Raft River, ID EGS Site

The Raft River geothermal system, located 160 km northwest of Salt Lake City, Utah is the site of a Department of Energy Enhanced Geothermal System (EGS) stimulation demonstration project. The target well RRG-9 ST-1, is roughly 1.6 km (1 mile) south of the power plant. This well has undergone a series of thermal and hydraulic stimulation treatments. Furthermore, the well passes through approximately 1,524 m MD (5,000 ft. MD) of laterally discontinuous Quaternary and Tertiary volcanoclastic and volcanic rocks that unconformably overlie the Precambrian basement. The Elba Quartzite formation located in the Precambrian basement is the target zone for the stimulation program. Fluid injected into the well exits through a fracture zone in the Elba Quartzite at 1,567 m TVD (5,140 ft. TVD). In June 2013 low-rate stimulation began at RRG-9 ST-1 using injection water from the geothermal plant. The average injection rate, temperature, and well head pressure of the low-rate stimulation was 163 Lpm (43 gpm), 34°C, and 1,931kPa (280 psig), respectively. This injection continued through late August of 2013 when wellhead pressures were intentionally increased to approximately 5,516 kPa (800 psig) at approximately 984 Lpm (260 gpm). From September 12 to September 24, 2013 cold well water was injected. The average surface injection temperature was approximately 12°C. On September 25, 2013 injection of the warmer plant water was resumed. This was continued through the rest of 2013 and into 2014. Between April 1, 2014 and April 4, 2014, a higher rate hydraulic stimulation was conducted. Colder water (~10°C) was injected at rates of 20 bpm to 30 bpm (3,178 Lpm to 4,770 Lpm) at wellhead pressures of 5,861 kPa (850 psig) over approximately 24 hours. Microseismic activity was recorded near the Tertiary-Precambrian contact. Subsequently, injection of water from the plant was resumed. As of mid-January, 2015, over 666 million liters (176 million gallons) have been injected into the well. The fate of this water is the subject of ongoing numerical analyses and continuous site monitoring. Various analyses have been implemented to monitor and assess the ongoing stimulation program. Modified Hall plot analysis shows increasing conductivity and/or a decreasing skin factor around the wellbore. Since April, 2014, the injectivity index has increased significantly from 0.28 Lpm/kPa (0.5 gpm/psig) to 0.93 Lpm/kPa (1.7 gpm/psig).

enhanced geothermal system↗
DOE OSTI2018

Experimental Investigation of Time-Dependent Deformation of Fluid Disposal Reservoir Caprocks

For approximately the last two decades low-permeability formations have become a prominent research area because these are the target of unconventional oil shale exploration, and also the primary trapping mechanism for CO2 sequestration and other such subsurface storage. The objective of this research is focused on the sealing ability and induced seismic risk of such tight formations. Disposal of fluid into the subsurface alters the stress state in both the target reservoir and the surrounding formations from their initial in situ state. Therefore, caprocks must be able to deform and accommodate the altered stress and strain state while maintaining the integrity of the seal. The deformation induced in caprock formations often results in a decrease in the normal stress on faults and fractures, which may induce shear slip and therefore create the potential for induced seismicity and leakage. Deformations induced by fluid injection are generally not instantaneous, but typically occur gradually as a pressure front advances through the reservoir and caprock formations. As such, an injection program design can influence both the rate and magnitude of deformation and associated changes in stress. Many common caprock formation types, such as shales and evaporates, are prone to undergo time-dependent deformation such as viscoelastic and/or viscoplastic response. Both the magnitude of the time-dependent deformation and the associated characteristic time scale are important considerations for selecting or operating an injection site. This paper describes tests intended to characterize these effects using caprock samples from a variety of current or potential storage sites. Triaxial and load relaxation test data are presented and used to quantify the time-dependent deformation behavior of rocks with different textures and compositions.

Edelman, Eric↗
DOE OSTI2019

Numerical Simulation of Critical Factors Controlling Heat Extraction from Geothermal Systems Using a Closed-Loop Heat Exchange Method

Closed-loop heat exchange for geothermal energy production involves injecting working fluid down a well that extends through the geothermal resource over a significant length to absorb heat by conduction through the well pipe. The well then needs to return to the surface for energy recovery and fluid re-injection to complete the cycle. We have carried out mixed convective-conductive fluid-flow modeling using a wellbore flow model for TOUGH2 called T2Well to investigate the critical factors that control closed-loop geothermal energy recovery. T2Well solves a mixed explicit-implicit set of momentum equations for flow in the pipe with full coupling to the implicit three-dimensional integral finite difference equations for Darcy flow in the porous medium. T2Well has the option of modeling conductive heat flow from the porous medium to the pipe by means of a semi-analytical solution which makes the computation very efficient because the porous medium does not have to be discretized. When the fully three-dimensional option is chosen, the porous medium is discretized and heat flow to the pipe is by conduction and convection, depending on reservoir permeability and other factors. Simulations of the closed-loop system for a variety of parameter values have been carried out to elucidate the heat recovery process. To the extent that convection may occur to aid in heat delivery to the pipe, the permeability of the geothermal reservoir, whether natural or stimulated, is an important property in heat extraction. The injection temperature and flow rate of the working fluid strongly control the ultimate energy recovery. Pipe diameter also plays a strong role in heat extraction, but is correlated with flow rate. Similarly, the choice of working fluid plays an important role, with water showing better heat extraction than CO2 for certain flow rates, while the CO2 has higher pressure at the production wellhead which can aid in surface energy recovery. In general, we find complex interactions between the critical factors that will require advanced computational approaches to fully optimize.

Oldenburg, Curtis↗
DOE OSTI2024

A novel digital lifecycle for Material‐Process‐Microstructure‐Performance relationships of thermoplastic olefins foams manufactured via supercritical fluid assisted foam injection molding

Abstract This research significantly enhances the applicability of thermoplastic olefins (TPOs) in the automotive industry using supercritical N 2 as a physical foaming agent, effectively addressing the limitations of traditional chemical agents. It merges experimental results with simulations to establish detailed material‐process‐microstructure‐performance (MP2) relationships, targeting 5–20% weight reductions. This innovative approach labeled digital lifecycle (DLC) helps accurately predict tensile, flexural, and impact properties based on the foam microstructure, along with experimentally demonstrating improved paintability. The study combines process simulations with finite element models to develop a comprehensive digital model for accurately predicting mechanical properties. Our findings demonstrate a strong correlation between simulated and experimental data, with about a 5% error across various weight reduction targets, marking significant improvements over existing analytical models. This research highlights the efficacy of physical foaming agents in TPO enhancement and emphasizes the importance of integrating experimental and simulation methods to capture the underlying foaming mechanism to establish material‐process‐microstructure‐performance (MP2) relationships. Highlights Establishes a material‐process‐microstructure‐performance (MP2) for TPO foams Sustainably produces TPO foams using supercritical (ScF) N 2 with 20% lightweighting Shows enhanced paintability for TPO foam improved surface aesthetics Digital lifecycle (DLC) that predicts both foam microstructure and properties DLC maps process effects & microstructure onto FEA mesh for precise prediction

Engineering↗
DOE OSTI2016

Apparatus and method for nanoflow liquid jet and serial femtosecond x-ray protein crystallography

Techniques for nanoflow serial femtosecond x-ray protein crystallography include providing a sample fluid by mixing a plurality of a first target of interest with a carrier fluid and injecting the sample fluid into a vacuum chamber at a rate less than about 4 microliters per minute. In some embodiments, the carrier fluid has a viscosity greater than about 3 centipoise.

36 MATERIALS SCIENCE↗
DOE OSTI2013

Radiological issues associated with the recent boom in oil and gas hydraulic fracturing

As the worldwide hydraulic fracturing 'fracking' market continued to grow to an estimated $37 Billion in 2012, the need to understand and manage radiological issues associated with fracking is becoming imperative. Fracking is a technique that injects pressurized fluid into rock layer to propagate fractures that allows natural gas and other petroleum products to be more easily extracted. Radioactivity is associated with fracking in two ways. Radioactive tracers are frequently a component of the injection fluid used to determine the injection profile and locations of fractures. Second, because there are naturally-occurring radioactive materials (NORM) in the media surrounding and containing oil and gas deposits, the process of fracking can dislodge radioactive materials and transport them to the surface in the wastewater and gases. Treatment of the wastewater to remove heavy metals and other contaminates can concentrate the NORM into technologically-enhanced NORM (TENORM). Regulations to classify, transport, and dispose of the TENORM and other radioactive waste can be complicated and cumbersome and vary widely in the international community and even between states/provinces. In many cases, regulations on NORM and TENORM do not even exist. Public scrutiny and regulator pressure will only continue to increase as the world demands on oil and gas continue to rise and greater quantities of TENORM materials are produced. Industry experts, health physicists, regulators, and public communities must work together to understand and manage radiological issues to ensure reasonable and effective regulations protective of the public, environment, and worker safety and health are implemented. (authors)

12 MANAGEMENT OF RADIOACTIVE AND NON-RADIOACTIVE W↗
DOE OSTI2016

Numerical Analysis of the Source of Excessive Na + and Cl – Species in Flowback Water From Hydraulically Fractured Shale Formations

Fracture fluid comprises fresh water, proppant, and a small percentage of other additives, which support the hydraulic fracturing process. Excluding situations in which flowback water is recycled and reused, total dissolve solids in fracture fluid is limited to the fluid additives, such as potassium chloride (1-7 weight percent KCL), which is used as a clay stabilizer to minimize clay swelling, and clay particle migration. However, the composition of recovered fluid, especially as it relates to the total dissolve solids (TDS), is always substantially different than the injected fracture fluid. The ability to predict flowback water volume and composition is useful when planning for the management or reuse of this aqueous byproduct stream. In this work, an ion transport and halite dissolution model was coupled with a fully implicit, dual porosity, numerical simulator, to study the source of the excess solutes in flowback water, and to predict the concentration of both Na+ and Cl- species seen in recovered water. The results showed that mixing alone, between the injected fracture fluid and concentrated in situ formation brine, could not account for the substantial rise in TDS seen in flowback water. Instead, the results proved that halite dissolution is a major contributor to the change in TDS seen in fracture fluid during injection and recovery. Halite dissolution can account for as much as 81% of Cl- and 86.5% of Na+ species seen in 90-day flowback water; mixing, between the injected fracture fluid and in situ concentrated brine, accounts for approximately 19% Cl- and 13% Na+.

03 NATURAL GAS↗
DOE OSTI2023

Characterization of Aquifer Poroelastic Response to Impulse and Oscillatory Well Pressure Using Distributed Acoustic Sensing

Abstract The storage of fluids in the subsurface is critical for a broad spectrum of applications including managed aquifer recharge, storage of liquefied carbon dioxide and hydrogen, geothermal heat extraction and exploitation of hydrocarbon. It is surprising then, that there has been relatively little measurement of the vertical distribution of poroelastic storage in geologic formations as compared with permeability. We present experiments in which fluid was injected into an important regional aquifer and the depth‐dependent strain response measured using fiber optic distributed acoustic sensing. The formation expansion and contraction in response to fluid injection were several 100 nanostrain. Strain, and the implied storage distribution, was highly localized in specific strata and demonstrated complex, hydromechanical behavior. This new window into fluid‐geomechanical coupling undermines some typically use models and observations currently in practice, but provides potential for complete representation and prediction of fluid storage in the subsurface.

58 GEOSCIENCES↗
DOE OSTI2024

SOSAT: Geohazard Risk Assessment in Carbon Sequestration Operations

Like all operations in which fluids are injected into the subsurface, geologic carbon storage (GCS) presents inherit risks that must be assessed and mitigated to successfully deploy such technology in the field. For example, alterations to pore pressure and the stress state due to fluid injection may trigger certain geohazards, such as potential fault activation and induced seismicity or unintentional hydraulic fracturing. Here we present capabilities for assessing these potential risks using the State of Stress Analysis Tool (SOSAT): a Python library and web-based application capable of probabilistically estimating the subsurface state of stress informed by various field observations. Using posterior distributions of principal stress components, SOSAT can assess the risk of fault activation within the injection formation for either a critically oriented fault or a fault with a user-prescribed orientation. Additionally, SOSAT can estimate the probability of unintentional hydraulic fracturing of the intact reservoir rock. Here, we demonstrate these SOSAT capabilities using a hypothetical GCS site. This type of risk assessment can assist with the effective deployment of GCS technology in the field by informing safe design and management practices.

Haagenson, Ryan J.↗
DOE OSTI2012

Gas-assisted gravity drainage (GAGD) process for improved oil recovery

A rapid and inexpensive process for increasing the amount of hydrocarbons (e.g., oil) produced and the rate of production from subterranean hydrocarbon-bearing reservoirs by displacing oil downwards within the oil reservoir and into an oil recovery apparatus is disclosed. The process is referred to as "gas-assisted gravity drainage" and comprises the steps of placing one or more horizontal producer wells near the bottom of a payzone (i.e., rock in which oil and gas are found in exploitable quantities) of a subterranean hydrocarbon-bearing reservoir and injecting a fluid displacer (e.g., CO.sub.2) through one or more vertical wells or horizontal wells. Pre-existing vertical wells may be used to inject the fluid displacer into the reservoir. As the fluid displacer is injected into the top portion of the reservoir, it forms a gas zone, which displaces oil and water downward towards the horizontal producer well(s).

02 PETROLEUM↗
DOE OSTI2015

Impacts of Organic Ligands on Forsterite Reactivity in Supercritical CO 2 Fluids

Subsurface injection of CO 2 for enhanced hydrocarbon recovery, hydraulic fracturing of unconventional reservoirs, and geologic carbon sequestration produces a complex geochemical setting in which CO 2 -dominated fluids containing dissolved water and organic compounds interact with rocks and minerals. The details of these reactions are relatively unknown and benefit from additional experimentally derived data. In this study, we utilized an in situ X-ray diffraction technique to examine the carbonation reactions of forsterite (Mg 2 SiO 4 ) during exposure to supercritical CO 2 (scCO 2 ) that had been equilibrated with aqueous solutions of acetate, oxalate, malonate, or citrate at 50 °C and 90 bar. The organics affected the relative abundances of the crystalline reaction products, nesquehonite (MgCO 3 ·3H 2 O) and magnesite (MgCO 3 ), likely due to enhanced dehydration of the Mg 2+ cations by the organic ligands. These results also indicate that the scCO 2 solvated and transported the organic ligands to the forsterite surface. Lastly, this phenomenon has profound implications for mineral transformations and mass transfer in the upper crust.

37 INORGANIC, ORGANIC, PHYSICAL, AND ANALYTICAL CH↗
DOE OSTI2017

Systems and methods for multi-fluid geothermal energy systems

A method for extracting geothermal energy from a geothermal reservoir formation. A production well is used to extract brine from the reservoir formation. At least one of nitrogen (N.sub.2) and carbon dioxide (CO.sub.2) may be used to form a supplemental working fluid which may be injected into a supplemental working fluid injection well. The supplemental working fluid may be used to augment a pressure of the reservoir formation, to thus drive a flow of the brine out from the reservoir formation.

15 GEOTHERMAL ENERGY↗