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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 649 records · Page 36
All sourcesNASA NTRSDOE OSTI
DOE OSTI2013

Experimental Evidence for Self-Limiting Reactive Flow through a Fractured Cement Core: Implications for Time-Dependent Wellbore Leakage

We present a set of reactive transport experiments in cement fractures. The experiments simulate coupling between flow and reaction when acidic, CO{sub 2}-rich fluids flow along a leaky wellbore. An analog dilute acid with a pH between 2.0 and 3.15 was injected at constant rate between 0.3 and 9.4 cm/s into a fractured cement core. Pressure differential across the core and effluent pH were measured to track flow path evolution, which was analyzed with electron microscopy after injection. In many experiments reaction was restricted within relatively narrow, tortuous channels along the fracture surface. The observations are consistent with coupling between flow and dissolution/precipitation. Injected acid reacts along the fracture surface to leach calcium from cement phases. Ahead of the reaction front, high pH pore fluid mixes with calcium-rich water and induces mineral precipitation. Increases in the pressure differential for most experiments indicate that precipitation can be sufficient to restrict flow. Experimental data from this study combined with published field evidence for mineral precipitation along cemented annuli suggests that leakage of CO{sub 2}-rich fluids along a wellbore may seal the leakage pathway if the initial aperture is small and residence time allows mobilization and precipitation of minerals along the fracture.

42 ENGINEERING↗
DOE OSTI2016

Effects of Asperity Distribution on Fluid Flow and Induced Seismicity During Deep Geothermal Exploitation

This work investigates the injection-induced seismic response of a heterogeneous fault plane, featuring low-permeability asperities embedded into a high-permeability damage zone. We simulate the pressure evolution with a hydrogeological simulator, accounting for the heterogeneous fault plane. Seismicity occurs then on the asperities, represented as unstable patches reactivating by means of the Mohr-Coulomb criterion. The hydrological and seismic modules are implicitly coupled to account for effects of asperity reactivation on the permeability. Results show that permeability changes may cause at a later time a change in seismicity propagation. Finally, we also investigated such effects by varying the density of asperities.

58 GEOSCIENCES↗
DOE OSTI2015

Liquid chromatography detection unit, system, and method

An embodiment of a liquid chromatography detection unit includes a fluid channel and a radiation detector. The radiation detector is operable to image a distribution of a radiolabeled compound as the distribution travels along the fluid channel. An embodiment of a liquid chromatography system includes an injector, a separation column, and a radiation detector. The injector is operable to inject a sample that includes a radiolabeled compound into a solvent stream. The position sensitive radiation detector is operable to image a distribution of the radiolabeled compound as the distribution travels along a fluid channel. An embodiment of a method of liquid chromatography includes injecting a sample that comprises radiolabeled compounds into a solvent. The radiolabeled compounds are then separated. A position sensitive radiation detector is employed to image distributions of the radiolabeled compounds as the radiolabeled compounds travel along a fluid channel.

46 INSTRUMENTATION RELATED TO NUCLEAR SCIENCE AND ↗
DOE OSTI2018

The Role of Capillary Hysteresis and Pore-Scale Heterogeneity in Limiting the Migration of Buoyant Immiscible Fluids in Porous Media

Understanding the main mechanisms affecting long-term migration and redistribution of injected CO 2 in geological carbon storage is needed for developing predictive models to assess environmental risks and designing monitoring schemes. Preparation of a postinjection site care plan is required for CO 2 injection wells, including monitoring of pressure changes and injected CO 2 plume. Knowledge gaps exist regarding assessment of postinjection monitoring timeframes for the CO 2 plume because the processes driving long-term CO 2 plume migration and trapping are not fully understood. In the postinjection stage of geological carbon storage, redistribution of CO 2 occurs mainly due to buoyancy and capillary forces. This work presents experimental and modeling studies to investigate processes contributing to postinjection plume distribution and stabilization. We conducted a flow cell experiments (0.5 m × 0.05 m × 0.01 m) with two immiscible fluid phases in a glass bead porous medium to study postinjection plume behavior. We employed a hysteretic macroscopic two-phase flow model to interpret the experimental results and to understand main processes leading to plume stabilization. Our findings show that capillary pressure hysteresis explains the experimentally observed plume shape and redistribution at early postinjection stages; however, the long-term plume migration and eventual plume stabilization can only be represented when in addition microscale heterogeneity is accounted for. Results also show that plume stabilization can be extremely slow and that the migration of the plume front can occur through multiple intermittent bursts over long times. Here, further studies are needed to understand implications of the results for more realistic porous media and large-scale storage reservoirs.

58 GEOSCIENCES↗
DOE OSTI2015

Liquid jet breakup regimes at supercritical pressures

Previously, a theory has been presented that explains how discrete vapor–liquid interfaces become diminished at certain high-pressure conditions in a manner that leads to well known qualitative trends observed from imaging in a variety of experiments. Rather than surface tension forces, transport processes can dominate over relevant ranges of conditions. In this paper, this framework is now generalized to treat a wide range of fuel-oxidizer combinations in a manner consistent with theories of capillary flows and extended corresponding states theory. Different flow conditions and species-specific molecular properties are shown to produce distinct variations of interfacial structures and local free molecular paths. These variations are shown to occur over the operating ranges in a variety of propulsion and power systems. Despite these variations, the generalized analysis reveals that the envelope of flow conditions at which the transition from classical sprays to diffusion-dominated mixing occurs exhibits a characteristic shape for all liquid–gas combinations. As a result, for alkane-oxidizer mixtures, it explains that these conditions shift to higher pressure flow conditions with increasing carbon number and demonstrates that, instead of widely assumed classical spray atomization, diffusion-dominated mixing may occur under relevant high-pressure conditions in many modern devices.

71 CLASSICAL AND QUANTUM MECHANICS, GENERAL PHYSIC↗
DOE OSTI2020

High pressure/high temperature multiphase simulations of dodecane injection to nitrogen: Application on ECN Spray-A

The present work investigates the complex phenomena associated with pressure/high temperature dodecane injection for the Engine Combustion Network (ECN) Spray-A case, employing more elaborate thermodynamic closures, to avoid well known deficiencies concerning density and speed of sound prediction using traditional cubic models. A tabulated thermodynamic approach is proposed here, based on log 10 (p)-T tables, providing very high accuracy across a large range of pressures, spanning from 0 to 2500 bar, with only a small number of interpolation points. The tabulation approach is directly extensible to any thermodynamic model, existing or to be developed in the future. Here NIST REFPROP properties are used, combined with PC-SAFT Vapor-Liquid-Equilibrium to identify the liquid in mixtures penetration, hence avoiding the use of an arbitrary threshold for mass fraction. Identified liquid and vapour penetration are compared against experimental data from the ECN database showing a good agreement, within approximately 3–8% for axial penetration of liquid, 2% for vapor axial penetration and within experimental uncertainty for radial distribution of mass fraction. Analysis of the vortex evolution indicates that driving mechanisms behind the jet break-up are vortex tilting/stretching, then baroclinic torque, leading to Rayleigh-Taylor instabilities, closely followed by vortex dilation and finally viscous effects.

42 ENGINEERING↗
DOE OSTI2016

Experimental Study of Porosity Changes in Shale Caprocks Exposed to Carbon Dioxide-Saturated Brine II: Insights from Aqueous Geochemistry

Laboratory experiments evaluated two shale caprock formations, the Gothic Shale and Marine Tuscaloosa Formation, at conditions relevant to carbon dioxide (CO 2 ) sequestration. Both rocks were exposed to CO 2 -saturated brines at 160°C and 15 MPa for ~45 days. Baseline experiments for both rocks were pressurized with argon to 15 MPa for ~35 days. Varying concentrations of iron, aqueous silica, sulfate, and initial pH decreases coincide with enhanced carbonate and silicate dissolution due to reaction between CO 2 -saturated brine and shale. Saturation indices were calculated and activity diagrams were constructed to gain insights into sulfate, silicate, and carbonate mineral stabilities. We found that upon exposure to CO 2 -saturated brines, the Marine Tuscaloosa Formation appeared to be more reactive than the Gothic Shale. Evolution of aqueous geochemistry in the experiments is consistent with mineral precipitation and dissolution reactions that affect porosity. Finally, this study highlights the importance of tracking fluid chemistry to clarify downhole physicochemical responses to CO 2 injection and subsequent changes in sealing capacity in CO 2 storage and utilization projects.

58 GEOSCIENCES↗
DOE OSTI2012

Active Management of Integrated Geothermal-CO2 Storage Reservoirs in Sedimentary Formations

Active Management of Integrated Geothermal–CO2 Storage Reservoirs in Sedimentary Formations: An Approach to Improve Energy Recovery and Mitigate Risk: FY1 Final Report The purpose of phase 1 is to determine the feasibility of integrating geologic CO2 storage (GCS) with geothermal energy production. Phase 1 includes reservoir analyses to determine injector/producer well schemes that balance the generation of economically useful flow rates at the producers with the need to manage reservoir overpressure to reduce the risks associated with overpressure, such as induced seismicity and CO2 leakage to overlying aquifers. Based on a range of well schemes, techno-economic analyses of the levelized cost of electricity (LCOE) are conducted to determine the economic benefits of integrating GCS with geothermal energy production. In addition to considering CO2 injection, reservoir analyses are conducted for nitrogen (N2) injection to investigate the potential benefits of incorporating N2 injection with integrated geothermal-GCS, as well as the use of N2 injection as a potential pressure-support and working-fluid option. Phase 1 includes preliminary environmental risk assessments of integrated geothermal-GCS, with the focus on managing reservoir overpressure. Phase 1 also includes an economic survey of pipeline costs, which will be applied in Phase 2 to the analysis of CO2 conveyance costs for techno-economics analyses of integrated geothermal-GCS reservoir sites. Phase 1 also includes a geospatial GIS survey of potential integrated geothermal-GCS reservoir sites, which will be used in Phase 2 to conduct sweet-spot analyses that determine where promising geothermal resources are co-located in sedimentary settings conducive to safe CO2 storage, as well as being in adequate proximity to large stationary CO2 sources.

15 GEOTHERMAL ENERGY↗
DOE OSTI2013

Joint Analysis of Surface Deformation Data for Reservoir Management (CRADA Final Report)

This was a collaborative effort between Lawrence Livermore National Security, LLC as manager and operator of Lawrence Livermore National Laboratory (LLNL) and Chevron North America Exploration and Production Company, a division of Chevron U.S.A. Inc. (Chevron), to develop an operational tool to carry out joint inversion of global positioning system (GPS), Interferometric Synthetic Aperture Radar (InSAR) and tilt, temperature, and electrical resistivity data to monitor the temporal and spatial evolution of fluid volume and temperature in a thermal diatomite oilfield. The original goal of the research and development carried out under the CRADA was to conduct joint inversion of GPS, InSAR and tilt data sets from Chevron’s McKittrick field. Temperature and electrical resistivity data were added to the joint inversion scheme at later stages of the project. The overall objective of the joint inversion was to provide improved mapping over time of changes in the spatial distributions of reservoir fluid volume and temperature within the reservoir in response to injection and production. This CRADA was originally designated as a three (3) year project, and was to be carried out in four phases. Each task was numbered according to the project phase it fell under. The four phases are identified below. Phases 3 and 4 were developed based on the results obtained in Phase 2, and the detailed work plan and refined budget were added by amendment.

Foxall, William↗
DOE OSTI2017

Geomechanical Framework for Secure CO 2 Storage in Fractured Reservoirs and Caprocks for Sedimentary Basins in theMidwest United States

This report presents final technical results for the project Geomechanical Framework for Secure CO 2 Storage in Fractured Reservoirs and Caprocks for Sedimentary Basins in the Midwest United States (DE-FE0023330). The project was a three-year effort consisting of seven technical tasks focused on defining geomechanical factors for CO 2 storage applications in deep saline rock formations in Ohio and the Midwest United States, because geomechancial issues have been identified as a significant risk factor for large-scale CO 2 storage applications. A basin-scale stress-strain analysis was completed to describe the geomechanical setting for rock formations of Ordovician-Cambrian age in Ohio and adjacent areas of the Midwest United States in relation to geologic CO 2 storage applications. The tectonic setting, stress orientation-magnitude, and geomechanical and petrophysical parameters for CO 2 storage zones and caprocks in the region were cataloged. Ten geophysical image logs were analyzed for natural fractures, borehole breakouts, and drilling-induced fractures. The logs indicated mostly less than 10 fractures per 100 vertical feet in the borehole, with mostly N65E principal stress orientation through the section. Geophysical image logs and other logs were obtained for three wells located near the sites where specific models were developed for geomechanical simulations: Arches site in Boone County, Kentucky; Northern Appalachian Basin site in Chautauqua County, New York; and E-Central Appalachian Basin site in Tuscarawas County, Ohio. For these three wells, 9,700 feet of image logs were processed and interpreted to provide a systematic review of the distribution within each well of natural fractures, wellbore breakouts, faults, and drilling induced fractures. There were many borehole breakouts and drilling-induced tensile fractures but few natural fractures. Concentrated fractures were present at the Rome-basal sandstone and basal sandstone-Precambrian contacts at the Arches and East-Central Appalachian Basin sites. Geophysical logs were utilized to develop local-scale geologic models by determining geomechanical and petrophysical parameters within the geologic formations. These data were ported to coupled fluid-flow and reservoir geomechanics multi-phase CO 2 injection simulations. The models were developed to emphasize the geomechanical layers within the CO 2 storage zones and caprocks. A series of simulations were completed for each site to evaluate whether commercial-scale CO 2 could be safely injected into each site, given site-specific geologic and geomechanical controls. This involved analyzing the simulation results for the integrity of the caprock, intermediate, and reservoir zones, as well quantifying the areal uplift at the surface. Simulation results were also examined to ensure that the stress-stress perturbations were isolated within the subsurface, and that there was only limited upward migration of the CO 2 . Simulations showed capacity to inject more than 10 million metric tons of CO 2 in a single well at the Arches and East Central Appalachian Basin sites without excessive geomechanical risks. Low-permeability rock layers at the Northern Appalachian Basin study area well resulted in very low CO 2 injection capacity. Fracture models developed for the sites suggests that the sites have sparse fracture network in the deeper Cambrian rocks. However, there were indicators in image logs of a moderate fracture matrix in the Rose Run Sandstone at the Northern Appalachian Basin site. Dual permeability fracture matrix simulations suggest the much higher injection rates may be feasible in the fractured interval. Guidance was developed for geomechanical site characterization in the areas of geophysical logging, rock core testing, well testing, and site monitoring. The guidance demonstrates that there is a suitable array of options for addressing geomechanical issues at CO 2 storage sites. Finally, a review of Marcellus and Utica-Point Pleasant shale gas wells and CO 2 storage intervals indicates that these items are vertically separated, except for the Oriskany sandstone and Marcellus wells in southwest Pennsylvania and northern West Virginia. Together, project results present a more realistic portrayal of geomechanical risk factors related to CO 2 storage for existing and future coal-fired power plants in Ohio.

58 GEOSCIENCES↗
DOE OSTI2022

Coupling a Lagrangian–Eulerian Spark-Ignition (LESI) model with LES combustion models for engine simulations

In the United States transportation sector, Light-Duty Vehicles (LDVs) are the largest energy consumers and CO 2 emitters. Electrification of LDVs is posed as a potential solution, but SI engines can still contribute to decarbonization. Car manufacturers have turned to unconventional engine operation to increase the efficiency of Spark-Ignition (SI) engines and reduce the carbon emissions of their fleets. Dilute, lean, and stratified-charge engine operation has the potential for engine efficiency improvements at the expense of increased cyclic variability and combustion instability. At such demanding engine conditions, the spark ignition event is key for flame initiation and propagation and for enhanced combustion stability. Reliable and accurate spark ignition models can help design ignition systems that reduce cyclic variability. Multiple computational spark-ignition models exist that perform well under conventional conditions, but the underlying physics needs to be expanded, for unconventional engine operation. In this paper, a hybrid Lagrangian–Eulerian Spark-Ignition (LESI) model is coupled with different turbulent flame propagation models for engine simulations. LESI relies on Lagrangian arc tracking and Eulerian energy deposition. The LESI model is coupled with the Well-Stirred Reactor (WSR), Thickened Flame Model (TFM), and g-equation model and used to simulate several cycles of a Direct-Injection Spark-Ignition (DISI) engine using a commercial Computational Fluid Dynamics (CFD) engine solver. The results showcase the successful coupling of LESI with the combustion models. Global engine metrics, such as pressure and Apparent Heat Release Rate (AHRR), for each simulation setup are compared to experimental engine results, for validation. In addition, results highlight the successful prediction of spark channel movement by comparing simulation images to experimental optical engine images. Finally, the successful coupling of LESI to combustion models, making it a usable model in the engine modeling community, is emphasized and future development details are discussed.

33 ADVANCED PROPULSION SYSTEMS↗
DOE OSTI2015

Fuel injection assembly for use in turbine engines and method of assembling same

A fuel injection assembly for use in a turbine engine is provided. The fuel injection assembly includes an end cover, an endcap assembly, a fluid supply chamber, and a plurality of tube assemblies positioned at the endcap assembly. Each of the tube assemblies includes housing having a fuel plenum and a cooling fluid plenum. The cooling fluid plenum is positioned downstream from the fuel plenum and separated from the fuel plenum by an intermediate wall. The plurality of tube assemblies also include a plurality of tubes that extends through the housing. Each of the plurality of tubes is coupled in flow communication with the fluid supply chamber and a combustion chamber positioned downstream from the tube assembly. The plurality of tube assemblies further includes an aft plate at a downstream end of the cooling fluid plenum. The plate includes at least one aperture.

33 ADVANCED PROPULSION SYSTEMS↗
DOE OSTI2016

Reservoir response to thermal and high-pressure well stimulation efforts at Raft River, Idaho

An injection stimulation test begun at the Raft River geothermal reservoir in June, 2013 has produced a wealth of data describing well and reservoir response via high-resolution temperature logging and distributed temperature sensing, seismic monitoring, periodic borehole televiewer logging, periodic stepped flow rate tests and tracer injections before and after stimulation efforts. One of the primary measures of response to the stimulation is the relationship between fluid pressure and flow rate, short-term during forced flow rate changes and the long-term change in injectivity. In this paper we examine that hydraulic response using standard pumping test analysis methods, largely because pressure response to the stimulation was not detected, or measurable, in other wells. Analysis of stepped rate flow tests supports the inference from other data that a large fracture, with a radial extent of one to several meters, intersects the well in the target reservoir, suggests that the flow regime is radial to a distance of only several meters and demonstrates that the pressure build-up cone reaches an effective constant head at that distance. The well’s longer term hydraulic response demonstrated continually increasing injectivity but at a dramatically faster rate later from ~2 years out and continuing to the present. The net change in injectivity is significantly greater than observed in other longterm injectivity monitoring studies, with an approximately 150–fold increase occurring over ~2.5 years. While gradually increasing injectivity is a likely consequence of slow migration of a cooling front, and consequent dilation of fractures, the steady, ongoing, rate of increase is contrary to what would be expected in a radial or linear flow regime, where the cooling front would slow with time. As a result, occasional step-like changes in injectivity, immediately following high-flow rate tests suggest that hydro shearing during high-pressure testing altered the near-well permeability structure.

15 GEOTHERMAL ENERGY↗
DOE OSTI2020

The TRANSCEND University Consortium: Theme 2 - Site Decommissioning, Deconstruction and Remediation - 20329

This paper will discuss the aims, objectives and progress to-date under Theme 2 of the TRANSCEND consortium project: Site decommissioning, deconstruction and remediation. Decommissioning nuclear sites involves waste retrieval, decontamination, deconstruction and, where necessary, containment and/or remediation of the remaining structure and surrounding land. Critical to management of these processes is limiting radiation exposure for the workforce, restricting the spread of radionuclides in groundwater, surface water and airborne particulates, and minimising the volume of contaminated waste for disposal. The aim of Theme 2 research is to develop new technologies for monitoring, remediation and containment that serve to minimise the volume of radioactively contaminated waste for disposal, for application prior to, during and after retrieval, deconstruction and decontamination operations. Prior research, conducted under the previous DISTINCTIVE project, demonstrated that colloidal silica grout can penetrate low permeability materials (including cement) for hydraulic barrier formation, and improved sorption capacity. The silica grout can be injected at surface using extremely small (potentially gravity-driven) fluid pressures, without the need for borehole drilling. Current work is investigating the erodibility of silica-grouted soils for inhibition of airborne and water-borne particulates as well as enhancing the grout's sorption capacity by addition of other materials to provide a chemical, as well as hydraulic, barrier to subsurface migration. EK remediation uses low voltage DC current to control migration of contaminants in porous media as well as to remove or degrade them. Researchers in the consortium have already demonstrated that low-energy ex-situ EK techniques can be used to provide remediation and volume minimisation for AWE legacy wastes in the UK. Under the current project researchers are building EK test cells containing simulated site materials at laboratory and intermediate(m)-scales to: remove, focus or degrade contaminants (remediation or waste minimisation); and direct subsurface water, chemical and colloid flow (fencing/containment or forced migration). This lab-based research is being informed by numerical models of EK processes that can subsequently be used to design full-scale on-site applications by nuclear site holders. Research under theme 2 of TRANSCEND will ultimately combine novel non-invasive detection technologies with EK techniques and colloidal silica grout barriers, to optimise the containment of radionuclide contamination in soils. Thus, allowing us to detect in-situ contamination, mobilise it to a selected location and grout it in-situ, prior to the initiation of decommissioning and deconstruction operations. (authors)

12 MANAGEMENT OF RADIOACTIVE AND NON-RADIOACTIVE W↗
DOE OSTI2015

Modeling of fault activation and seismicity by injection directly into a fault zone associated with hydraulic fracturing of shale-gas reservoirs

We conducted three-dimensional coupled fluid-flow and geomechanical modeling of fault activation and seismicity associated with hydraulic fracturing stimulation of a shale-gas reservoir. We simulated a case in which a horizontal injection well intersects a steeply dip- ping fault, with hydraulic fracturing channeled within the fault, during a 3-hour hydraulic fracturing stage. Consistent with field observations, the simulation results show that shale-gas hydraulic fracturing along faults does not likely induce seismic events that could be felt on the ground surface, but rather results in numerous small microseismic events, as well as aseismic deformations along with the fracture propagation. The calculated seismic moment magnitudes ranged from about -2.0 to 0.5, except for one case assuming a very brittle fault with low residual shear strength, for which the magnitude was 2.3, an event that would likely go unnoticed or might be barely felt by humans at its epicenter. The calculated moment magnitudes showed a dependency on injection depth and fault dip. We attribute such dependency to variation in shear stress on the fault plane and associated variation in stress drop upon reactivation. Our simulations showed that at the end of the 3-hour injection, the rupture zone associated with tensile and shear failure extended to a maximum radius of about 200 m from the injection well. The results of this modeling study for steeply dipping faults at 1000 to 2500 m depth is in agreement with earlier studies and field observations showing that it is very unlikely that activation of a fault by shale-gas hydraulic fracturing at great depth (thousands of meters) could cause felt seismicity or create a new flow path (through fault rupture) that could reach shallow groundwater resources.

54 ENVIRONMENTAL SCIENCES↗
DOE OSTI2024

Instabilities and Mixing in Inertial Confinement Fusion

By imploding fuel of hydrogen isotopes, inertial confinement fusion (ICF) aims to create conditions that mimic those in the Sun's core. This is fluid dynamics in an extreme regime, with the ultimate goal of making nuclear fusion a viable clean energy source. The fuel must be reliably and symmetrically compressed to temperatures exceeding 100 million degrees Celsius. After the best part of a century of research, the foremost fusion milestone was reached in 2021, when ICF became the first technology to achieve an igniting fusion fuel (thermonuclear instability), and then in 2022 scientific energy breakeven was attained. A key trade-off of the ICF platform is that greater fuel compression leads to higher burn efficiency, but at the expense of amplified Rayleigh–Taylor and Richtmyer–Meshkov instabilities and kinetic-energy-wasting asymmetries. In extreme cases, these three-dimensional instabilities can completely break up the implosion. Even in the highest-yielding 2022 scientific breakeven experiment, high-atomic-number (high-Z) contaminants were unintentionally injected into the fuel. Here we review the pivotal role that fluid dynamics plays in the construction of a stable implosion and the decades of improved understanding and isolated experiments that have contributed to fusion ignition.

70 PLASMA PHYSICS AND FUSION TECHNOLOGY↗
DOE OSTI2022

Findings on Subtask 3.1 - Bakken Rich Gas Enhanced Oil Recovery Project

Total in-place oil for the Bakken petroleum system (BPS) (which includes the Bakken and Three Forks Formations) has been estimated to be 600 billion barrels (bbl). However, BPS wells have decline rates as high as 85% over the first 3 years of their lives, and primary recovery factors typically range from 3% to 10% of original oil in place. Given the low initial recovery rates, even small incremental productivity improvements could dramatically increase technically recoverable oil in the BPS. One potential solution is enhanced oil recovery (EOR) using gas injection, such as carbon dioxide (CO2) or hydrocarbon (HC) gases. While commonly used in conventional reservoirs, CO2 EOR in unconventional tight oil reservoirs has been limited to pilot tests. EOR using rich gas (mixture of methane, ethane, and propane) has also been employed in numerous pilots in several unconventional plays and has recently been successfully applied in the Eagle Ford play. If successful, large-scale gas-based EOR in the BPS could dramatically increase oil productivity and recovery factors and extend the life of the play for decades. While CO2 may be a technically suitable working fluid for EOR in the BPS, supplies are limited and costs for using CO2 in EOR pilots are prohibitively high. Meanwhile, produced gas flaring has presented challenges for BPS operators in North Dakota. Analysis conducted by the North Dakota Pipeline Authority indicates that the current gas-gathering infrastructure in North Dakota is insufficient to accommodate all of the associated gas that is produced from the BPS. The geographically isolated location of North Dakota relative to large natural gas markets, combined with suppressed natural gas prices, has made it economically challenging for industry to invest capital in expanding gas-gathering infrastructure in the state. These circumstances led to a research program conducted by the Energy & Environmental Research Center (EERC) in partnership with Liberty Resources Management Company LLC (LR) to examine the potential to use rich gas injection for EOR and mitigate flaring. A rich gas EOR pilot test was designed and executed by LR at its Stomping Horse development area in Williams County, North Dakota. From July 2018 through May 2019, a total of 160 million standard cubic feet (MMscf) of rich produced gas was injected into the BPS using five different wells in a sequential injection strategy. LR’s Leon–Gohrick drill spacing unit (DSU) was used as the test site. Regulatory oversight was provided by the North Dakota Industrial Commission (NDIC). Technical support was provided by the EERC through a series of laboratory, modeling, and field-based activities, and additional post-pilot research activities incorporated learnings from the test, developed new laboratory data, improved fracture modeling methods, and developed machine learning and big data analytics. The results from the Stomping Horse rich gas EOR pilot activities indicate that developing an effective, economical EOR approach for the BPS will require more field tests. Another key lesson learned from the Stomping Horse tests is that detailed pre- and posttest data on reservoir conditions and fluids production are essential. Robust reservoir characterization provides information that is crucial to creating realistic geomodels and conducting valid dynamic simulations of potential EOR scenarios. A detailed understanding of the completions and production history of offset wells is also necessary for valid test result interpretations. This knowledge is essential to designing the operational parameters of injectivity tests and interpreting the results. A conformance control strategy is also essential to success. Laboratory-based examinations of rich gas interactions with reservoir fluids and rocks were conducted, with an emphasis on determining the ability to mobilize oil in the tight reservoir rocks and shales of the BPS. Injection fluid composition was shown to have a positive impact on reducing reservoir oil minimum miscibility pressure (MMP), reducing interfacial tension (IFT), and altering wettability. IFT and contact angle measurements demonstrated that wettability can be altered in the presence of rich gas, suggesting the potential to improve oil recovery. Iterative modeling of surface infrastructure and reservoir performance using data generated by the various project activities was conducted. A geologic model of the Stomping Horse area was built; history-matched oil, gas, and water production was used in simulations of various EOR scenarios. Early programmatic modeling results were used to support LR’s design and operation of the EOR pilot and to provide insight regarding optimization of future commercial-scale BPS EOR design and operations. Post-pilot modeling focused on alternative methods of understanding complex fracture networks and accelerating simulation time. These led to improved simulation run times and provide excellent history-matching results. Several of these iterative models were used as the bases for developing algorithms into machine learning and big data analytics. History matching in reservoir simulation is time-consuming and computer processing-intensive. Machine learning algorithms were created, and an automated history-matching tool was developed. A large set of synthetic reservoir simulations were created to generate well responses (oil, gas, and water production, well bottomhole pressure [BHP], and tracer or propane breakthrough) for a set of EOR operating parameters that included offset well status (open or closed), injectate (rich gas or propane), injection rate, and injection well BHP. A user interface was developed to provide real-time visualization. Machine learning-based models were developed to provide rapid forecasting of well performance given a set of user-defined EOR operating parameters. These predictive models allow the user to modify the offset well status, injection rate, and injection well BHP and rapidly forecast future production performance. The combination of real-time visualization tools with real-time forecasting tools provides a framework for real-time control—operational changes that the EOR site operator can enact (e.g., changing gas injection rates) to affect the observed performance and potentially improve the EOR outcome. There is great reason to be optimistic about the future of EOR in the Bakken. The results of the laboratory studies suggest significant potential for high rates of oil mobilization using produced field gas injection under the right conditions. The results of the lab studies, combined with rigorous statistical analysis of well production data and associated modeling efforts, confirm the notion that fluid mobility within the reservoir is controlled by fractures. As more knowledge is gained about the nature and distribution of fracture networks in the Bakken, the industry will be in a better position to predict and, ultimately, influence fluid mobility. New field tests are necessary to develop a more complete understanding of those conditions. Thoughtful and creatively engineered field tests within a well-characterized geologic setting will yield the fundamental knowledge needed to take Bakken oil production to the next level. This subtask was cofunded through the EERC–U.S. Department of Energy Joint Program on Research and Development for Fossil Energy-Related Resources Cooperative Agreement No. DE-FE0024233. Nonfederal funding was provided by the North Dakota Industrial Commission’s Oil and Gas Research Program and Computer Modelling Group.

04 OIL SHALES AND TAR SANDS↗
DOE OSTI2015

Proppant backflow: Mechanical and flow considerations

One of the concerns of using proppant in geothermal wells, and particularly in enhanced geothermal systems, is proppant flowback. Particulate proppant maintain post-closure conductivity in hydraulically opened fractures. If that proppant is displaced from the near-wellbore region, either due to overflushing during stimulation or flowback to the wellbore at any time, the reduced fracture width chokes the injection or production. Two intermediate-scale laboratory analogs of a propped hydraulic fracture were prepared, and fluid was flowed through a normally stressed, propped fracture into a central wellbore. The tests were conducted in a polyaxial load frame. Acoustic/microseismic activity was measured during the injection programs. In one scenario—radial flow through a transverse fracture to a wellbore—the results suggest the creation of flow channels and nominally intact propped zones around the channels, maintaining fracture aperture. In the other—linear flow through a longitudinal fracture into a wellbore—there was substantially more proppant removal. The measurements have shown a greater tendency for proppant flowback in a linear flow situation (proppant movement is kinematically more restricted for radial convergent flow). The pressure gradients causing flow are exceedingly small and restraining flowback will be difficult. Convergent flow relationships could be an issue for injector wells, which will experience fluid flowback during hard shutdowns.

15 GEOTHERMAL ENERGY↗