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Modeling Water-Rock Reactions Beneath the Greenheugh Pediment, Gale Crater, Mars

The Mars Science Laboratory Curiosity rover has been exploring the clay rich Glen Torridon unit in Gale crater since sol 2300 of the mission [1]. As identified in orbital data [2], this clay rich area [3] in the Murray formation is overlain with the Greenheugh Pediment unit to the south, which is part of the Stimson Formation [4]. Curiosity acquired the drill sample Hutton in the Upper Murray formation 2 – 3 meters below the Greenheugh Pediment [5,6]. This study uses thermochemical modelling to investigate the hypothesis for alteration in the Murray formation below the Greenheugh Pediment. Specifically, if the contact between the Greenheugh Pediment and Murray sediments was a conduit for diagenetic fluids (a low water/rock scenario) or if subaerial weathering altered the Murray sediments before cementation began (a high water/rock scenario) [6]. Here, we report on preliminary modeling where we have reacted the chemical composition for the Hutton drill sample with Gale Portage Water (GPW) at 25 °C, 50 °C and 200 °C, for 10% Fe3+/Fetot of the host rock.

SMR Turner↗
DOE OSTI2012

SIMULATED LSST SURVEY OF RR LYRAE STARS THROUGHOUT THE LOCAL GROUP

We report on a study to determine the efficiency of the Large Synoptic Survey Telescope (LSST) to recover the periods, brightnesses, and shapes of RR Lyrae stars' light curves in the volume extending to heliocentric distances of 1.5 Mpc. We place the smoothed light curves of 30 type ab and 10 type c RR Lyrae stars in 1007 fields across the sky, each of which represents a different realization of the LSST sampling cadences, and that sample five particular observing modes. A light curve simulation tool was used to sample the idealized RR Lyrae stars' light curves, returning each as it would have been observed by LSST, including realistic photometric scatter, limiting magnitudes, and telescope downtime. We report here the period, brightness, and light curve shape recovery as a function of apparent magnitude and for survey lengths varying from 1 to 10 years. We find that 10 years of LSST data are sufficient to recover the pulsation periods with a fractional precision of {approx}10{sup -5} for {>=}90% of ab stars within Almost-Equal-To 360 kpc of the Sun in Universal Cadence fields and out to Almost-Equal-To 760 kpc for Deep Drilling fields. The 50% completeness level extends to Almost-Equal-To 600 kpc and Almost-Equal-To 1.0 Mpc for the same fields, respectively. For virtually all stars that had their periods recovered, their light curve shape parameter {phi}{sub 31} was recovered with sufficient precision to also recover photometric metallicities to within 0.14 dex (the systematic error in the photometric relations). With RR Lyrae stars' periods and metallicities well measured to these distances, LSST will be able to search for halo streams and dwarf satellite galaxies over half of the Local Group, informing galaxy formation models and providing essential data for mapping the Galactic potential. This study also informs the LSST science operations plan for optimizing observing strategies to achieve particular science goals. We additionally present a new [Fe/H]-{phi}{sub 31} photometric relation in the r band and a new and generally useful metric for defining period recovery for time domain surveys.

79 ASTRONOMY AND ASTROPHYSICS↗
DOE OSTI2016

Hydrogeologic Lessons Learned from Deep Drilling Projects Applied to Deep Borehole Disposal of Radioactive Wastes - 16133

Hydrogeological results from the Kola SG-3, Gravberg-1, Cajon Pass, and KTB-VB and KTB-HB boreholes are applied to the US deep borehole disposal concept to assess whether old, saline, and reducing deep groundwater, in low bulk permeability crystalline basement rocks, could be found in a DOE proposed deep borehole field test. Each of the drilling projects faced characterization challenges, including obtaining sufficient information to characterize key parameters and their uncertainty, equipment limitations and failures, and obtaining samples that are representative of in situ conditions while maintaining sample integrity. Despite these characterization challenges, each project obtained sufficient data to directly measure or infer, for redox state, conditions at the 3 to 5 km (1.9 - 3.1 miles) target disposal depth of the US deep borehole disposal concept. The hydrogeologic data suggest that old, saline, and reducing deep groundwater could be found at a test site located in geologically stable crystalline basement. Although the DOE deep borehole testing program has not defined the magnitude of an acceptably low bulk permeability, bulk permeability results indicate that values used in current US deep borehole modeling efforts may be too low by an order of magnitude or more, as compared with in situ conditions. (authors)

12 MANAGEMENT OF RADIOACTIVE AND NON-RADIOACTIVE W↗
DOE OSTI2017

Hardening of DOE UQ Codes for Ultra-Deep Proactive Geosteering in Oilfield Service

The primary objective of this project was to harden the DOE uncertainty quantification (UQ) code to solve the inverse problem for the geosteering service in the oilfield drilling and exploration. The primary focus is to verify the feasibility of using QUESO to solve geosteering inverse problems through statistical inversion. QUESO is a software library developed by QUEST, a DOE's Scientific Discovery through Advanced Computing (SciDAC) institute. In the process of drilling a borehole, geosteering is the act of adjusting the well trajectory on the fly to reach the geological targets or to keep the wellbore within desired formation. Geosteering inversion is to infer underground formation structure using measurements such as azimuthal resistivity logging data. The geosteering process relies on the real-time reconstruction of the subsurface earth model, and a robust and efficient inversion algorithm is always necessary to satisfy the job requirement. The new generation of azimuthal resistivity geosteering tool is capable of detecting multiple formation boundaries 20-100 ft away, and the corresponding geosteering inversion problem can be very challenging as many parameters need to be inverted within such a large depth of investigation. The success of the project will support US energy security by helping to advance subsurface modeling and characterization technologies in oilfield applications. An effective subsurface inversion algorithm and the implementation as a software package will promote the usage of ultra-deep azimuthal resistivity measurements, which can help well placement in complicated underground environments, reduce costs and risks of drilling, and increase oil and gas production. It will help medium and small size independent service companies and tool manufactures to enter the more advanced and lucrative directional drilling area. In addition, by hardening the QUESO code and building a transparent interface for easy manipulation of the QUESO functions, we provide a user-friendly tool for a larger scientific and industry communities that rely heavily on modeling and simulation tools for forecasting, parameter studies, design, and decision making. These are all activities that can strongly benefit from meaningful representations of modeling uncertainty supported by our product.

58 GEOSCIENCES↗
DOE OSTI2019

First Ever Polymer Flood Field Pilot to Enhance the Recovery of Heavy Oils on Alaska’s North Slope – Polymer Injection Performance

Alaska North Slope (ANS) holds an estimated 20-30+ billion barrel heavy oil resources, yet the development pace has been very slow due to high development costs and low oil recovery using conventional waterflood and EOR methods. The objective of this pilot is to perform a field experiment to validate the use of an advanced polymer flooding technology to unlock the vast heavy oil resources on ANS. The advanced polymer flooding technology combines polymer flooding, low salinity water flooding, horizontal wells, and if necessary, injection conformance control treatments into one integrated process to significantly improve oil recovery from heavy oil reservoirs. Two pairs of horizontal injection and production wells have been deployed in an isolated fault block of the Schrader Bluff heavy oil reservoir at the Milne Point Field to conduct a polymer flood pilot. The pilot will acquire scientific knowledge and field performance data to optimize polymer flood design in the Schrader Bluff heavy oil reservoirs on ANS. Polymer injection started on August 28, 2018 using a custom made polymer blending and pumping unit. This paper focuses on the facility setup and polymer injection performance into the horizontal injectors drilled and completed in the Schrader Bluff heavy oil reservoir. Partially hydrolyzed polyacrylamide (HPAM) polymer was selected and the initial target viscosity was set at 45 centipoise. Polymer injection rate was set at 2200 bbl/day for one injector (J-23A) and 1200 bbl/day for the other (J-24A) based on production voidage. Injection pressure was controlled at below fracture pressure to prevent fracturing the reservoir and causing fast breakthroughs. Step rate and pressure falloff tests indicate that short term polymer injectivity is similar to water injectivity, which means that injectivity is mostly controlled by fluid mobility deep in the reservoir rather than that in the vicinity of the injection wellbore. Long term injection data indicate that polymer injectivity has been decreasing in both injectors as the reservoir is filled by polymer. No polymer has been observed in the production stream 7 months after the start of polymer injection compared with a 3-month breakthrough time with waterflood. This indicates that polymer significantly delays breakthrough time which will lead to increased sweep efficiency.

Ning, Samson↗
DOE OSTI2017

Spontaneous imbibition of water and determination of effective contact angles in the Eagle Ford Shale Formation using neutron imaging

Understanding of fundamental processes and prediction of optimal parameters during the horizontal drilling and hydraulic fracturing process results in economically effective improvement of oil and natural gas extraction. Although, the modern analytical and computational models can capture fracture growth, there is a lack of experimental data on spontaneous imbibition and wettability in oil and gas reservoirs for the validation of further model development. In this work, we used neutron imaging to measure the spontaneous imbibition of water into fractures of Eagle Ford Shale with known geometries and fracture orientations. An analytical solution for a set of nonlinear second-order differential equations was applied to the measured imbibition data to determine effective contact angles. The analytical solution fit the measured imbibition data reasonably well and determined effective contact angles were slightly higher than static contact angles due to effects of in-situ changes in velocity, surface roughness, and heterogeneity of mineral surfaces on the fracture surface. Additionally, small fracture widths may have retarded imbibition and affected model fits, which suggests that average fracture widths are not satisfactory for modeling imbibition in natural systems.

DiStefano, Victoria H. (ORCID:0000000160239716)↗
DOE OSTI2024

De-risking fault leakage risk and containment integrity for subsurface storage applications

The subsurface is pivotal in the energy transition, for the sequestration of CO 2 and energy storage. It is crucial to understand to what extent geological faults may form leakage pathways that threaten the containment integrity of these projects. Fault flow behavior has been studied in the context of hydrocarbon development, supported by observations from wells drilled through faults, but such observations are rare in geoenergy projects. Focusing on mechanical behavior as early indicator of potential leakage risks, a probabilistic Coulomb Failure Stress workflow is developed and demonstrated using data from the Decatur CO 2 sequestration project to rank faults based on their containment risk. The analysis emphasizes the importance of fault throw relative to reservoir thickness and pore pressure change in assessing reactivation risks. Integrating this mechanical assessment with geological and dynamic fault analyses contributes to derisking fault containment for geoenergy applications, providing valuable insights for the successful development of subsurface storage projects.

58 GEOSCIENCES↗
DOE OSTI2021

Development and Field Testing Novel Natural Gas Surface Process Equipment for Replacement of Water as Primary Hydraulic Fracturing Fluid (Final Report)

Southwest Research Institute® (SwRI ® ), Schlumberger Technology Corporation (SLB), and Chevron Corporation ® (Chevron) developed a novel, optimized, and lightweight process for natural gas (NG) to replace water as a low-cost fracturing medium with a low environmental impact. Hydraulic fracturing is used to increase oil and NG production by injecting high-pressure fluid, primarily water, into a rock formation, which fractures the rock and releases trapped oil and NG. This method was developed to increase yield and make feasible production areas that would not otherwise be viable for large-scale oil and NG extraction using traditional drilling technologies. Since the fracturing fluid is composed of approximately 90% water, one of the principal drawbacks to hydraulic fracturing is its excessive water use and associated large environmental footprint. According to recent data collected at fracture sites within the United States, fracturing applications in North America can consume as much as 9 million gallons of water per well. During the fracturing process, some of the fracturing fluid is permanently lost and the portion that is recovered is contaminated by both fracturing chemicals and dissolved solids from the formation. The recovered water or flow-back represents a significant environmental challenge, as it must be treated before it can be reintroduced into the natural water system. Although there is some recycling for future fracturing, the majority of the flow-back water is hauled from the well site to a treatment facility or to an injection well for permanent underground disposal. To mitigate these issues, an optimized, lightweight and modular surface process using NG to replace a majority of the water was developed as a cost-effective and environmentally clean fracturing fluid. Using NG will result in significantly less consumption since the gas that is injected as a fracturing fluid will be mixed with the formation gas and extracted as if it were from the formation itself. This process will minimize the collection, waste, and treatment of large amounts of water and will reduce the environmental impact of transporting and storing the fracturing fluid. There are two major steps involved in utilizing NG as the primary fracturing medium: (1) increasing the supply pressure of NG to wellhead pressures suitable for fracturing and (2) mixing the required chemicals and proppant needed for the fracturing process at these elevated pressures. The second step (NG-proppant mixing at elevated pressures) still requires demonstration; but very similar processes have been demonstrated in the field with other gases such as nitrogen (N 2 ) and carbon dioxide (CO 2 ). However, the first step (a compact, on-site unit for generating high-pressure NG at costs feasible for fracturing) has not been developed and is currently not commercially available. Due to the inherent compressibility of NG, more energy is required to compress the gas than what is required to pump water (or other incompressible liquids) to the very high pressure required for downhole injection. This project aimed to develop a novel, hybrid method to overcome this challenge. The project accomplishments and findings are discussed in this report. Ultimately, the research and development efforts described herein demonstrate that fracturing with NG foam is a feasible alternative to using water.

02 PETROLEUM↗
DOE OSTI2022

Using Natural Gas Liquids to Recover Unconventional Oil and Gas Resources (Final Report)

This document presents final technical findings for the project Using Natural Gas Liquids to Recover Unconventional Oil and Gas Resources (FE0031782). The project is part of the U.S. Department of Energy Oil and Gas Program to develop and advance technologies that can significantly improve the recovery efficiencies of unconventional oil and gas resources. The overall objective of this project is to improve the ultimate recovery from unconventional oil and gas (UOG) resources in the United States by developing a method for using unrefined natural gas liquids (NGLs) as treatment fluids to improve hydrocarbon production. Horizontal extended-lateral drilling coupled with high volume hydraulic fracturing has significantly increased production from UOG resources in the U.S. However, the recovery efficiency is low compared to the estimated oil and gas in place. Recent data indicate that less than 10% of the oil in the liquid-rich UOG reservoirs is produced. Alternative completion methods using NGLs could increase production (Battelle, 2016; Wan et al., 2013; Wan, 2013; Downey et al, 2021); however, field validation tests are needed to develop an approach that is economical, efficient, and compatible in the UOG setting to advance towards commercial deployment. This project aims to develop and field test a method to improve recovery of oil resources in UOG shale plays by using Y-Grade NGLs, or a similar combination of NGLs, as treatment fluids. Refined NGLs have been used as a hydraulic treatment fluid in UOG plays for decades and are shown to be particularly effective because their miscibility with oil allows oil to flow more freely; however, the use of Y-Grade (unrefined) NGLs has not been studied. The use of Y-Grade NGLs would be advantageous over refined NGLs because Y-Grade NGLs do not require infrastructure or investment in refining and are already being produced from many UOG reservoirs. The concept was tested and monitored in the field at a commercial well site owned by project partner Hopco, Ltd. The project team, which consists of multiple oil and gas operators, Linde Gas North America LLC (Linde) and the Ohio Division of Geological Survey (ODGS), has extensive experience with oil and gas production in the Appalachian basin and the ability to work together quickly to solve technical issues and research needs. A key part of the proposed work was the use of existing wells for field testing and monitoring. A total of four wells (three vertical and one horizontal) were available for this project. One of the vertical wells was utilized as the test well for the NGL treatment test. A nearby vertical well was used for microseismic monitoring. The remaining vertical well and the horizontal well provided a baseline for typical UOG production in the oil window of the Utica/Point Pleasant (UPP). Major technical tasks of the project include characterization of the geotechnical properties of the UPP with an emphasis on the field site; design and planning for the NGLs testing; field testing and monitoring; analysis and integration of field data; and economic and resource/reserve assessment. The Shoman monitoring well and Doughty NGL treatment well were successfully plugged back during September-October 2020 in preparation for treatment and monitoring. A nitrogen diagnostic fracture injection test (DFIT) was completed on the Doughty well on July 22, 2021, consisting of 133,000 scf (91 Bbl.) of nitrogen. A nitrogen foam frac was completed in the Utica-Point Pleasant interval on August 17, 2021 with funding from outside sources. A microseismic monitoring array was installed in the Shoman well and monitored microseismic activity during the Doughty well frac job. Y-Grade NGL injection commenced on August 26, 2021. A total of 215 Bbl. was injected but the job was shut down due to a small leak on the suction hose on the pump truck. The Y-Grade treatment resumed on August 27, 2021 and an additional 726 Bbl. of Y-Grade NGL was injected at a well head pressure of 3850 psi. Total volume of injected Y-Grade over the two days of injection was 941 Bbl. The well was shut-in for 17 days following injection to allow the Y-Grade NGLs to soak on the formation. Y-Grade treatment flow back commenced on 9/13/2021 on a weekly basis. Production data, including surface pressures, oil, nitrogen, natural gas, and flow times was measured and recorded. Periodic gas samples were collected and analyzed to determine composition of flowback gas. As of July 2022, the treatment well had produced 726 Bbl of oil and 2,888 mcf gas. In August 2022, tubing and packer in the well were removed and a pump was installed to enhance oil recovery. Currently, the operator is producing the well about 2 days a week for a few hours. The performance of the NGL treatment test was evaluated based on reservoir simulations of the treatment process, processing of well testing data, analysis of micro seismic monitoring data, and production data analysis. This analysis suggested that oil production in the small test would continue through 2025. Upscaling the treatment to a horizontal Utica Point-Pleasant well would allow more oil recovery, but the process would involve more investment, services, and operational support. An economic analysis was conducted for scenarios aimed at upscaling the NGL treatment process for more typical horizontal UPP wells in the Appalachian Basin.

02 PETROLEUM↗
NASA NTRS1973

Trapped solar and cosmogenic noble gas abundances in Apollo 15 and 16 deep drill samples

Abundances and isotopic compositions of all the stable noble gases (He, Ne, Ar, Kr, Xe) were measured at different depths of the Apollo 15 and Apollo 16 deep drill cores, and in several surface fines and breccias. All samples analyzed from both drill cores were found to contain large concentrations of solar wind implanted gases. This means that even the deepest layers of both cores have experienced a lunar surface history. The Apollo 15 core data are consistent with a combined accretion plus static time of a few hundred million years, and also indicate variable pre-accretion irradiation of core material. Depth profiles of cosmogenic gases in the Apollo 16 core show considerably larger concentrations of cosmic gases below 65 cm depth than above. This pattern may be interpreted either as an accretionary process, or by a more recent deposition of regolith to the upper 70 cm of the core.

Bogard, D. D.↗
NASA NTRS1992

The Panther Mountain circular structure, a possible buried meteorite crater

Panther Mountain, located near Phoenicia, New York, is part of the Catskill Mountains, which form the eastern end of the Allegheny Plateau in New York. It is a circular mass defined physiographically by an anomalous circular drainage pattern produced by Esopus Creek and its tributary Woodland Creek. The circular valley that rings the mountain is fracture-controlled; where bedrock is exposed, it shows a joint density 5 to 10 times greater than that on either side of the valley. Where obscured by alluvial valley fill, the bedrock's low seismic velocity suggests that this anomalous fracturing is continuous in the bedrock underlying the rim valley. North-south and east-west gravity and magnetic profiles were made across the structure. Terrane-corrected, residual gravity profiles show an 18-mgal negative anomaly, and very steep gradients indicate a near-surface source. Several possible explanations of the gravity data were modeled. We conclude that the Panther Mountain circular structure is probably a buried meteorite crater that formed contemporaneously with marine or fluvial sedimentation during Silurian or Devonian time. An examination of drill core and cuttings in the region is underway to search for ejecta deposits and possible seismic and tsunami effects in the sedimentary section. Success would result in both dating the impact and furnishing a chronostratigraphic marker horizon.

Isachsen, Y. W.↗
DOE OSTI2024

Characterization Inform Sustainable Recovery of Critical Minerals from Fossil Energy Waste Feedstocks

Rare earth elements (REE) and other critical minerals (CM, e.g., Co, Ni, Li) have important uses in green energy and modern technologies, yet are vulnerable to potential supply chain disruptions. One potential domestic CM source is fossil energy wastes, such as acid mine drainage (AMD) and treatment solids (AMD solids), coal combustion ash, and Oil and Gas (O&G) drilling wastes (drill cuttings and produced waters). While they can contain lower CM concentrations then traditional ore, the quantity and fast availability as waste feedstock makes them a promising CM resource. To explore their promise, researchers at DOE’s National Energy Technology Laboratory (NETL) have collected and analyzed CM data for aforementioned fossil energy wastes, and utilized advanced geochemical characterization (e.g., synchrotron microprobe and sequential extraction) to identify the CM speciation and binding environments, and developed sustainable and targeted CM recovery. Successful examples include: (1) the discovery of easily mobile REE phases in Ca-rich coal combustion ash and developing a patented REE recovery process from Ca-rich Powder River Basin coal ash; (2) the successful identification of REE/Co/Ni/Zn hosting phases in acid mine drainage treatment solids (AMD solids) with diverse chemical composition (Al, Mn, or Fe-rich) informing the sequential recovery of different REE/CMs from AMD solids; (3) the recovery potential of Li and other CMs in O&G produced waters and drill cuttings. The innovations driven by characterization have the potential to offset the cost of waste management and wastewater treatments while reducing the cost and environmental footprint of CM extraction.

Stuckman, Mengling↗
DOE OSTI2023

Utah FORGE: Optimization of a Plug-and-Perf Stimulation (Fervo Energy)

Information around the plug-and-perf treatment design at Utah FORGE by Fervo Energy. Objective and Purpose: - Develop a multistage hydraulic stimulation approach designed specifically to target the top three factors that control the technical and commercial viability of an EGS system: i) Achieving sufficient injectivity to support high cross-well flow rates ii) Distributing flow evenly across the wellbore and reservoir to maximize heat mining efficiency, ensure sustained heat transfer, and mitigate thermal breakthrough iii) Overcoming the effects of stress heterogeneity, stress shadowing, and variations in natural fracture properties during the stimulation treatment, leading to a more predictable stimulated reservoir volume and offset well placement - The following activities will be performed: i) Design, plan, and execute a multistage plug-and-perf stimulation treatment at a Fervo site with data acquisition and well testing activities aimed at addressing key technical aspects of the issues above ii) Perform data processing and interpretation of field results to translate the results form the Fervo site to a site-specific design at the Utah FORGE site iii) Design, plan, and execute a multistage plug-and-perf stimulation treatment design at the Utah FORGE site Methods and Approach: - Design a detailed data acquisition plan to maximize learning around: i) DFIT testing ii) Petrophysical logging, image logging iii) Permanent DAS/DTS fiber optic monitoring iv) Deep borehole microseismic monitoring v) Shallow borehole induced seismicity monitoring vi) Injection/production testing (RTA analysis, tracer testing) vii) Integrated numerical modeling and production forecasting

15 GEOTHERMAL ENERGY↗
DOE OSTI2018

High Temperature 300°C Measurement While Drilling System

Many countries around the world, including the USA, have untapped geothermal energy potential. Enhanced Geothermal Systems (EGS) technology is needed to economically utilize this resource. Temperatures in some EGS reservoirs can exceed 300°C. To effectively utilize EGS resources, an array of injection and production wells must be accurately placed in the formation fracture network. Therefore, EGS can greatly benefit from a high temperature directional drilling system. Most commercial services for directional drilling systems are rated for 175°C while geothermal wells require operation at much higher temperatures. Two U.S. Department of Energy (DOE) Geothermal Technologies Office (GTO) projects have been initiated to develop a 300°C capable directional drilling system, the first developing a drill bit, directional motor, and drilling fluid (award number DE-EE0002782), and the second adding navigation and telemetry systems. This report is for the second project, “High Temperature 300°C Measurement While Drilling System”, award number DE-EE0005505. The “High Temperature 300°C Measurement While Drilling (MWD)” system complements the already developed drilling system with real time navigation capability. It is comprised of 175°C directional measurement electronics including the required sensors for measuring inclination and azimuth in 3 axes. It is embedded in a cooling and temperature isolation system to protect the electronics and sensors from the higher temperature outside the system, which can reach 300°C. Building the cooling and isolation system from non-magnetic materials and keeping a required distance to any magnetic component, such as alternator parts, ensures a high quality measurement of the earth’s magnetic field. This is required to achieve the specified navigation accuracy. The MWD system has a turbine driven alternator that is capable of delivering the required electrical energy to the electronic system at a 300°C borehole temperature. Measured data will be communicated to the surface by mud-pulse-telemetry. For this purpose the tool has a mud-pulse-valve that is controlled by the measurement electronics to establish a serial data communication via the mud stream. The mud-pulse-valve is also built to operate under 300°C borehole conditions. Three prototypes of the 300°C MWD were built and tested. These systems are available for a joint application with the previously developed 300°C drilling system, in a geothermal well.

15 GEOTHERMAL ENERGY↗
DOE OSTI2021

Subsurface Characterization and Machine Learning Predictions at Brady Hot Springs Results

Geothermal power plants typically show decreasing heat and power production rates over time. Mitigation strategies include optimizing the management of existing wells - increasing or decreasing the fluid flow rates across the wells - and drilling new wells at appropriate locations. The latter is expensive, time-consuming, and subject to many engineering constraints, but the former is a viable mechanism for periodic adjustment of the available fluid allocations. Data and supporting literature from a study describing a new approach combining reservoir modeling and machine learning to produce models that enable strategies for the mitigation of decreased heat and power production rates over time for geothermal power plants. The computational approach used enables translation of sets of potential flow rates for the active wells into reservoir-wide estimates of produced energy and discovery of optimal flow allocations among the studied sets. In our computational experiments, we utilize collections of simulations for a specific reservoir (which capture subsurface characterization and realize history matching) along with machine learning models that predict temperature and pressure timeseries for production wells. We evaluate this approach using an "open-source" reservoir we have constructed that captures many of the characteristics of Brady Hot Springs, a commercially operational geothermal field in Nevada, USA. Selected results from a reservoir model of Brady Hot Springs itself are presented to show successful application to an existing system. In both cases, energy predictions prove to be highly accurate: all observed prediction errors do not exceed 3.68% for temperatures and 4.75% for pressures. In a cumulative energy estimation, we observe prediction errors that are less than 4.04%. A typical reservoir simulation for Brady Hot Springs completes in approximately 4 hours, whereas our machine learning models yield accurate 20-year predictions for temperatures, pressures, and produced energy in 0.9 seconds. This paper aims to demonstrate how the models and techniques from our study can be applied to achieve rapid exploration of controlled parameters and optimization of other geothermal reservoirs. Includes a synthetic, yet realistic, model of a geothermal reservoir, referred to as open-source reservoir (OSR). OSR is a 10-well (4 injection wells and 6 production wells) system that resembles Brady Hot Springs (a commercially operational geothermal field in Nevada, USA) at a high level but has a number of sufficiently modified characteristics (which renders any possible similarity between specific characteristics like temperatures and pressures as purely random). We study OSR through CMG simulations with a wide range of flow allocation scenarios. Includes a dataset with 101 simulated scenarios that cover the period of time between 2020 and 2040 and a link to the published paper about this project, where we focus on the Machine Learning work for predicting OSR's energy production based on the simulation data, as well as a link to the GitHub repository where we have published the code we have developed (please refer to the repository's readme file to see instructions on how to run the code). Additional links are included to associated work led by the USGS to identify geologic factors associated with well productivity in geothermal fields. Below are the high-level steps for applying the same modeling + ML process to other geothermal reservoirs: 1. Develop a geologic model of the geothermal field. The location of faults, upflow zones, aquifers, etc. need to be accounted for as accurately as possible 2. The geologic model needs to be converted to a reservoir model that can be used in a reservoir simulator, such as, for instance, CMG STARS, TETRAD, or FALCON 3. Using native state modeling, the initial temperature and pressure distributions are evaluated, and they become the initial conditions for dynamic reservoir simulations 4....

15 GEOTHERMAL ENERGY↗
NASA NTRS1977

In-vivo bone strain telemetry in monkeys /M. nemestrina/

A new method for collecting in-vivo bone strain data in monkeys has been developed and tested. The method includes a system which consists of a new design of implantable strain transducer and its companion telemetry package. The transducer fits into a hole drilled in a monkey tibia and is threaded for subsequent bone ingrowth. The transducers and telemetry package are biocompatible for over 503 days. The telemetry package uses Pulse Interval Ratio Modulation (PIRM) to transmit strain information to receiving equipment located outside the animal housing cage.

Young, D. R.↗
NASA NTRS2000

Subsurface Science from a Penetrator

Much of what we know about the geologic history and present state of Mars is based upon interpretations of data collected from the immediate surface. Unweathered soil samples covered by dust and sand sized particles may provide clues about the role of water and the biological history of the planet. The use of drills and scoops to obtain such samples for lander-based instruments implies the development of relatively large, sophisticated platforms. Small (several kilograms), scientifically focussed penetrators can carry instruments to the subsurface and should be included in the Mars exploration strategy.

Yen, Albert S.↗
DOE OSTI2012

Demonstration and Performance Monitoring of Foundation Heat Exchangers (FHX) in Ultra-High Energy Efficient Research Homes

The more widespread use of Ground Source Heat Pump (GSHP) systems has been hindered by their high first cost, which is mainly driven by the cost of the drilling and excavation for installation of ground heat exchangers (GHXs). A new foundation heat exchanger (FHX) technology was proposed to reduce first cost by placing the heat exchanger into the excavations made during the course of construction (e.g., the overcut for the basement and/or foundation and run-outs for water supply and the septic field). Since they reduce or eliminate the need for additional drilling or excavation, foundation heat exchangers have the potential to significantly reduce or eliminate the first cost premium associated with GSHPs. Since December 2009, this FHX technology has been demonstrated in two ultra-high energy efficient new research houses in the Tennessee Valley, and the performance data has been closely monitored as well. This paper introduces the FHX technology with the design, construction and demonstration of the FHX and presents performance monitoring results of the FHX after one year of monitoring. The performance monitoring includes hourly maximum and minimum entering water temperature (EWT) in the FHX compared with the typical design range, temperature difference (i.e., T) across the FHX, and hourly heat transfer rate to/from the surrounding soil.

15 GEOTHERMAL ENERGY↗