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All sourcesNASA NTRSDOE OSTI
DOE OSTI2022

Method to account for natural fracture induced elastic anisotropy in geomechanical characterization of shale gas reservoirs

Shale has been usually recognized as a transverse isotropic (TI) medium in conventional geomechanical log interpretation due to its laminated nature. However, when natural fractures exist in the shale rock, additional elastic anisotropy is introduced, converting laminated Shale to an orthorhombic (OB) medium. Previous studies illustrate that neglecting the natural fracture induced anisotropy in shale geomechanical log interpretation could lead to inaccurate evaluations of elastic moduli and in-situ stresses. In this paper, a new method is developed to account for the natural fracture induced anisotropy in geomechanical log interpretation based upon the TI acoustic model developed by the author and a characterization technique of elastic wave anisotropy (Sayers, 1991). The new OB model incorporates the four acoustic log data inputs and five modeling constraints in a nonlinear optimization algorithm to solve for the nine independent stiffness coefficients of an OB rock, and further to solve for the geomechanical properties and in-situ stress profiles in an OB formation. The new method was validated with a Marcellus Gas Shale field case. Both the new OB model and the conventional TI model were applied to interpret the minimum horizontal stress profile for the same formation. By comparing the results, the OB model is more robust than the TI from two aspects. First, the average stress magnitude predicted by the OB model is closer to the one measured by the Diagnostic Fracture Injection Test (DFIT). Second, the OB model predicts a more obvious stress barrier between the lower Marcellus and upper Onondaga Limestone than the TI model does. Finally, the predicted stress barrier is consistent with the observation of the microseismic events of a horizontal well drilled and completed nearby, which reveals that no hydraulic fracture propagates downward through the bottom boundary of Marcellus Shale into the underlying Onondaga Limestone.

03 NATURAL GAS↗
DOE OSTI2023

Optimization of operational strategies for rich gas enhanced oil recovery based on a pilot test in the Bakken tight oil reservoir

Horizontal well drilling and multistage hydraulic fracturing have been demonstrated as effective approaches for stimulating oil production in the Bakken tight oil reservoir. However, after multiple years of production, primary oil recovery in the Bakken is generally less than 10% of the estimated original oil in place. Gas huff ‘n’ puff (HnP) has been tested in the Bakken Formation as an enhanced oil recovery (EOR) method; however, most field pilot test results showed no significant incremental oil production. One of the factors affecting HnP EOR performance is premature gas breakthrough, which is one of the most critical issues observed in the field because of the presence of interwell fractures. Consequently, injected gas rapidly reaches adjacent production wells without contacting reservoir rock and increasing oil recovery. Proper conformance control is therefore needed to avoid early gas breakthrough and improve EOR performance. In this study, a rich gas EOR pilot in the Bakken was carefully analyzed to collect the essential reservoir and operational data. A simulation model with 16 wells was then developed to reproduce the production history and predict the EOR performance with and without conformance control. EOR operational strategies, including single- and multiple-well HnP, with different gas injection constraints were investigated. The simulation results of single-well HnP without conformance control showed that a rich gas injection rate of at least 10 MMscfd was needed to yield meaningful incremental oil production. The strategy of conformance control via water injection could significantly improve oil production in the HnP well, but injecting an excessive amount of water also leads to water breakthrough and loss of oil production in the offset wells. By analyzing the production performance of the wells individually, the arrangement of wells was optimized for multiple-well HnP EOR. The multiwell results showed that rich gas EOR could improve oil production up to 7.4% by employing conformance control strategies. Furthermore, replacing rich gas with propane as the injection gas could result in 14% of incremental oil production.

02 PETROLEUM↗
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 OSTI2021

Newly acquired core enhances geologic understanding of the northern Paradox Basin Cane Creek play, southeastern Utah

The Cane Creek interval is an emerging unconventional heterolithic play within the Pennsylvanian Paradox Formation of the northern Paradox Basin, southeastern Utah. Structural controls (basement uplifts, salt movement, faults, fractures) likely control production from the Cane Creek, where total oil production of ~10 MMBO is just a fraction of current estimates of the undiscovered resource (up to 1.2 BBOE). Oil production has been most successful from unstimulated horizontal wells in the Cane Creek Unit in the central play area, whereas areas to the north (Greentown and Gunnison Valley) have to date proven to be largely unproductive from vertical and horizontal wells drilled without the benefit of 3D seismic or the deployment of modern hydraulic fracturing techniques. However, the limited historical drilling has shown significant promise (e.g., significant shows). The lack of core data in the northern part of the play has impeded thorough assessment of reservoir quality, character, and lithological facies heterogeneity. The Cane Creek is informally divided into three distinct zones. The upper A and basal C zones are composed of fabric destructive and wavy bedded anhydrite, dolomitic mudstone, and organic-rich algal laminated mudstones (source rock). The middle B zone is generally wave rippled and burrowed, low-permeability sandstone-siltstone (reservoir) with subordinate displacive anhydrite. Recent potash cores collected from the Salt Valley anticline near Crescent Junction, Utah (but east of the main play area), show thicker reservoir sandstone/siltstone packages (~40 ft) in the B zone, and parts of the C zone, in the northern part of the Paradox Basin in comparison to the central (~35 ft) and southern (~30 ft) areas. Source rock analyses from northern core/cuttings also indicate that it is well positioned within the oil window (VRo ~0.8), with thin organic-rich mudstone beds containing up to 20 wt% TOC. Because the siliciclastic reservoir rocks have low permeabilities (0.009–0.202 mD) and variable porosities (6–17%) due to dolomite-anhydrite cement, naturally occurring and possibly stimulated fractures may be essential for hydrocarbon recovery. To better understand the northern part of the Cane Creek play, a new core was obtained from the research stratigraphic well State 16-2 (January 2021). Details from this new core will help characterize reservoir quality via core analyses, petrography, fracture orientations, geomechanics, and correlation of facies and depositional trends. Additionally, an evaluation of matrix porosity/permeability will be conducted to determine its contribution to productivity.

02 PETROLEUM↗
DOE OSTI2026

OES CO 2 Pipeline FEED Project Design Basis Memorandum

The OES CO₂ Pipeline project will move captured carbon dioxide from two ethanol facilities near Gibson City, Illinois, roughly 7.8 miles southeast to three injection wells outside Anchor, where it will be permanently stored underground. The system is designed to handle up to 4.5 million metric tonnes per year of dense-phase CO₂ at pressures up to 2,500 psig, using 16-inch mainline pipe and 10.750-inch laterals made from API 5L X-60 and X-65 steel. Wall thicknesses vary depending on location, with thinner pipe in open country, heavier wall at road crossings, and the heaviest where the pipe passes under highways or railroads via horizontal directional drill. The pipe gets a fusion-bonded epoxy coating, with an added abrasion-resistant layer wherever it's bored or drilled. Major water crossings will use HDD rather than open trenching. The pipeline will be cathodically protected, equipped with SCADA-compatible pressure and temperature instrumentation, and monitored for leaks using a computational pipeline monitoring system per API RP 1130. Hydrostatic testing will be performed at 1.25 times design pressure, and an ILI caliper run will follow to catch any construction defects. Several items, including fracture toughness requirements, specific NDE methods, and ILI tool selection, are left for the detailed design phase. The whole system falls under 49 CFR Part 195 and ASME B31.4, and Gulf Interstate Engineering prepared this document as the FEED-level design basis under the CarbonSAFE Phase III program.

09 BIOMASS FUELS↗
DOE OSTI2021

Conasauga Shale Research Consortium (CSRC) (Final Report)

The objective of the Conasauga Shale Research Consortium (CSRC) project was to establish a field laboratory and utilize a horizontal well of opportunity to conduct a scientific study designed to advance the understanding of the petrophysical and geomechanical properties of the emerging Rogersville Shale unconventional oil and gas play. Unfortunately, just as the research program was beginning, our industry partner lost a primary investor in the horizontal well which was intended to be the ‘well of opportunity’ for the project. In a negotiated restructuring of the project by DOE-NETL and the Awardee consortium, additional time for Budget Period 1 was granted in the hopes that the industry partner could acquire additional investments to allow for the drilling of the horizontal well. This search was ultimately unsuccessful, and the consortium was unable to pass the negotiated Go/No-go Decision Point #1, which resulted in the termination of the project on July 31, 2021.

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↗
DOE OSTI2021

The EGS Collab Project: Status and Accomplishments

The EGS Collab project, supported by the US Department of Energy, is addressing challenges in implementing enhanced geothermal systems (EGS). This includes improving understanding of the stimulation of crystalline rock to create appropriate flow pathways, and the ability to effectively simulate both the stimulation and the flow and transport processes in the resulting fracture network. The project is performing intensively monitored rock stimulation and flow tests at the 10-m scale in an underground research laboratory. Data and observations from the field test are compared to simulations to understand processes and to build confidence in numerical modeling of the processes. In Experiment 1, we examined hydraulic fracturing an underground test bed at the Sanford Underground Research Facility (SURF) in Lead, South Dakota, at a depth of approximately 1.5 km. We drilled eight sub-horizontal boreholes in a well-characterized phyllite. Six of the boreholes were instrumented with many sensor types to allow careful monitoring of stimulation events and flow tests, and the other two boreholes were used for water injection and production. We performed a number of stimulations and flow tests in the testbed. Our monitoring systems allowed detailed observations and collection of numerous data sets of processes occurring during stimulation and during dynamic flow tests. Long-term ambient temperature and chilled water flow tests were performed in addition to many tracer tests to examine system behavior. Data were rapidly analyzed, allowing adaptive control of the tests. Numerical simulation was used to answer key experimental design questions, to forecast fracture propagation trajectories and extents, and to analyze and evaluate results. Many simulations were performed in near-real-time in conjunction with the field experiments, with more detailed process study simulations performed on a longer timeframe. Experiment 2 will examine hydraulic shearing in a test bed being built at the SURF at a depth of about 1.25 km in amphibolite under a different set of stress and fracture conditions than Experiment 1. Five sets of fracture orientations were considered in design, and three orientations seem to be consistently observed.

EGS Collab↗
DOE OSTI2022

Utah FORGE GeoThermOPTIMAL Video

This is a project description video by Dr. William W. Fleckenstein related to their "Development of Multi-Stage Fracturing System and Wellbore Tractor to Enable Zonal Isolation During Stimulation and EGS Operations in Horizontal Wellbores" R&D project at Utah FORGE which is linked bellow.

15 GEOTHERMAL ENERGY↗
DOE OSTI2022

Modeling Validation of Mechanical and Thermal Borehole Breakouts From Polyaxial Laboratory Tests to Determine Maximum Horizontal in Situ Stress

To accurately assess rock behavior in the deep subsurface, it is necessary to measure the in situ stress directions and magnitudes. The current methods for measuring the in situ stress state in the deep subsurface primarily include hydraulic fracturing tests (i.e., the minimum horizontal stress) or occasionally observing existing compressive borehole breakouts (i.e., the maximum horizontal stress) that have occurred naturally from drilling. If there are no existing compressive breakouts in a borehole, the maximum horizontal in situ stress cannot be estimated with much confidence. In response to this data gap, a new thermal breakout technology is being developed that will provide a method for thermally inducing borehole breakouts and obtaining consistent measurements of the maximum horizontal stress magnitude. This thermal breakout technology involves heating the borehole and increasing the thermoelastic compressive stress in the rock until a breakout develops, which is directly correlated to the maximum horizontal stress magnitude. In support of developing the thermal breakout technology, polyaxial laboratory tests have been performed on small-scale boreholes within rock blocks where mechanically- and thermally-induced borehole breakouts have been created. Numerical models along with the principal of superposition were created and used to analyze the polyaxial laboratory tests to predict the maximum horizontal stress, given the same data that would be obtained in an actual subsurface borehole thermal breakout test. Multiple failure criteria were used to evaluate the best prediction of the breakout onset and maximum horizontal stress. The maximum horizontal stress predictions were compared to the actual maximum horizontal stress applied at breakout using acoustic events recorded from emission sensors in the polyaxial tests. The results showed consistent results that could be used to refine the modeling approach and failure criterion that are used to make the maximum horizontal stress predictions. This study provided insight and validation for the thermal breakout stress measurement concept.

Jones, Matt↗
DOE OSTI2021

Stratigraphically Controlled Stress Variations at the Hydraulic Fracture Test Site-1 in the Midland Basin, TX

We investigated the relationship between stratigraphy, stress, and microseismicity at the Hydraulic Fracture Test Site-1. The site comprises two sets of horizontal wells in the Wolfcamp shale and a deviated well drilled after hydraulic fracturing. Regional stresses indicate normal/strike-slip faulting with E-W compression. Stress measurements in vertical and horizontal wells show that the minimum principal stress varies with depth. Strata with high clay and organic content show high values of the least compressive stress, consistent with the theory of viscous stress relaxation. By integrating data from core, logs, and the hydraulic fracturing stages, we constructed a stress profile for the Wolfcamp sequence, which predicts how much pressure is required for hydraulic fracture growth. We applied the results to fracture orientation data from image logs to determine the population of pre-existing faults that are expected to slip during stimulation. We also determined microseismic focal plane mechanisms and found slip on steeply dipping planes striking NW, consistent with the orientations of potentially active faults predicted by the stress model. This case study represents a general approach for integrating stress measurements and rock properties to predict hydraulic fracture growth and the characteristics of injection-induced microseismicity.

microseismicity↗
DOE OSTI2023

$S$ Hmax orientation in the Alpine region from observations of stress-induced anisotropy of nonlinear elasticity

The orientation of $S$ Hmax is commonly estimated from in situ borehole breakouts and earthquake focal mechanisms. Borehole measurements are expensive, and therefore sparse, and earthquake measurements can only be made in regions with many well-characterized earthquakes. Here, we derive the stress-field orientation using stress-induced anisotropy in nonlinear elasticity. In this method, we measure the strain derivative of velocity as a function of azimuth. We use a natural pump-probe (NPP) approach which consists of measuring elastic wave speed using empirical Green’s functions (probe) at different points of the earth tidal strain cycle (pump). The approach is validated using a larger data set in the Northern Alpine Foreland region where the orientation of maximum horizontal compressive stress is known from borehole breakouts and drilling-induced fractures. The technique resolves NNW-SSW to N-S directed $S$ Hmax which is in good agreement with conventional methods and the recent crustal stress model. We confirm that the NPP method can be applied to dense large-scale seismic arrays. The technique is then applied to the Southern Alps to understand the contemporary stress pattern associated with the ongoing deformation due to counterclockwise rotation of the Adriatic plate with respect to the European plate. Our results explain why the two major faults in Northeastern Italy, the Giudicarie Fault and the Periadriatic Line (Pustertal–Gailtal Fault) are currently inactive, while the currently acting stress field allows faults in Slovenia to deform actively. We have demonstrated that the pump-probe method has the potential to fill in the measurement gap left by conventional approaches, both in terms of regional coverage and in depth.

58 GEOSCIENCES↗
DOE OSTI2023

Analysis of Rotary Steerable Systems versus Conventional Mud Motors for Vertical and Horizontal Wells in the Caney Formation, Southwest Oklahoma

Rotary steerable systems (RSS) have transformed directional drilling over the years and are becoming widely accepted throughout the world. RSS technology has been proven to provide the required strength and agility in challenging and abrasive environments as well as provide a higher rate of penetration (ROP) by allowing more weight transfer to the bit. Due to the higher price of RSS, some companies have stayed loyal to the conventional bent housing (CBH) with a performance drilling motor, regardless of the RSS benefits. This paper examines the performance and cost benefits of standalone RSS (SA-RSS), motor driven RSS (MD-RSS), and CBH systems. Three wells drilled in the Caney formation in Southwestern Oklahoma were selected for the analysis. Results showed that using RSS in the 12.25” intermediate vertical section and the 8.75”/8.5” lateral section was more cost effective than a CBH system. The cost per foot for the CBH was 1.6 to 2.3 times higher than RSS in the vertical section and 1.7 times higher in the lateral section. The RSS ROP was 2.3 to 4.8 times faster than CBH in the vertical section and 1.6 times faster in the lateral section.

Hayes, John↗
DOE OSTI2022

Detecting the Presence of Intrusive Drilling in Secure Transport Containers Using Non-Contact Millimeter-Wave Radar

We employ a 77–81 GHz frequency-modulated continuous-wave (FMCW) millimeter-wave radar to sense anomalous vibrations during vehicle transport at highway speeds for the first time. Secure metallic containers can be breached during transport by means of drilling into their sidewalls but detecting a drilling signature is difficult because the large vibrations of transport drown out the small vibrations of drilling. For the first time, we demonstrate that it is possible to use a non-contact millimeter-wave radar sensor to detect this micron-scale intrusive drilling while highway-speed vehicle movement shakes the container. With the millimeter-wave radar monitoring the microdoppler signature of the container’s vibrating walls, we create a novel signal-processing pipeline consisting of range–angle tracking, time–frequency analysis, horizontal stripe image convolution, and principal component analysis to create a robust and powerful detection statistic to alarm if drilling is present. To support this pipeline, we develop a statistical model combining the vibrating container and the random vibrations induced by vehicle movement to explore the robustness of the sensor’s detection capabilities. The presented results strongly support the inclusion of a millimeter-wave radar vibration sensor into a transport security system.

Wagner, Samuel↗
DOE OSTI2022

Designing a Particle Flow Control Apparatus

Flow control within a particle-based Concentrated Solar Power (CSP) system is essential in determining the heat transfer coefficient, and therefore, the power generation capability of these systems. There are three areas where particle flow control is significant: the receivers, storage tanks, and particle-sCO2 heat exchangers. The focus of this work is on designing a new mechanism to control the flow in the particle-sCO2 heat exchangers due to the simplicity and potential cost savings when compared to the other areas of interest. The goal is for this new design to have quicker response times in terms of particle flowrate than a slide gate or flow control valve, which are designs currently used. The design resembles that of a chuck mechanism within a drill where a rotation of the sleeve elicits movement of the jaws both vertically and horizontally to close the outlet area of the nozzle. Additionally, this design will utilize the current actuator that is already used within these heat exchangers to reduce the complexity of implementation. The jaws are designed to be closed at an angle of 76˚ which is just slightly steeper than the hopper leading to the mechanism. Furthermore, this design can be tuned to limit particle bridging and other particle flow phenomena that result in blockages. The prototypes were 3D printed out of polylactic acid (PLA) and scaled up to 100%, 200%, and 400% to be able to observe the velocity profiles of the mechanism more clearly. Experiments are performed with this prototype to compare the inlet and outlet mass flow rates at different configurations of the jaws. The particles used in these experiments are 0.3mm HSP 40/70 that are commonly used in particle-based CSP systems.

14 SOLAR ENERGY↗
DOE OSTI2023

DESIGNING A PARTICLE FLOW CONTROL APPARATUS

Flow control within a particle-based Concentrated Solar Power (CSP) system is essential in determining the heat transfer coefficient, and therefore, the power generation capability of these systems. There are three areas where particle flow control is significant: the receivers, storage tanks, and particle-sCO2 heat exchangers. The focus of this paper is on designing a new mechanism to control the flow in the particle-sCO2 heat exchangers due to the simplicity and potential cost savings when compared to the other areas of interest. The goal is for this new design to have quicker response times in terms of particle flowrate than a slide gate or flow control valve, which are designs currently used. The design resembles that of a chuck mechanism within a drill where a rotation of the sleeve elicits movement of the jaws both vertically and horizontally to close the outlet area of the nozzle. Additionally, this design will utilize the current actuator that is already used within these heat exchangers to reduce the complexity of implementation. The jaws are designed to be closed at an angle of 76 ̊ which is just slightly steeper than the hopper leading to the mechanism. Furthermore, this design can be tuned to limit particle bridging and other particle flow phenomena that result in blockages. The prototypes were 3D printed out of polylactic acid (PLA) and scaled up to 100%, 200%, and 400% to be able to observe the velocity profiles of the mechanism more clearly. Experiments are performed with this prototype to compare the inlet and outlet mass flow rates at different configurations of the jaws. The particles used in these experiments are 0.3mm HSP 40/70 that are commonly used in particle-based CSP systems.

14 SOLAR ENERGY↗
DOE OSTI2021

State of Stress Uncertainty Quantification and Geomechanical Risk Analysis for Subsurface Engineering

All subsurface stress measurement methods available for deep subsurface applications are indirect and involve a significant amount of uncertainty. Quantifying these uncertainties is critical for applications where the state of stress is a component of a risk analysis with significant safety, environmental, and economic considerations. A publicly available and open source tool called the State of Stress Analysis Tool (SOSAT) has been developed to aid in performing a Bayesian uncertainty quantification and geomechanical risk analysis using many types of commonly available data. A new feature of this tool is using data from the FutureGen 2.0 site. The new feature of the tool was uses information about the absence or presence of borehole breakouts to constrain the state of stress. This new feature allows the user to specify probability distributions for the relevant parameters such as the drilling mud pressure, temperature, and the formation strength properties. The tool computes the posterior joint probability distribution of the horizontal principal stresses. Using random samples from this posterior distribution the tool then computes the probability of activating a critically oriented fault at a range of pore pressures. This latter feature can be used to aid in the assessment of the risk of induced seismicity and leakage in geologic carbon sequestration and enhanced geothermal systems.

Burghardt, Jeffrey A.↗
DOE OSTI2021

Experimental study on rheological and settling properties of shape memory polymer for fracture sealing in geothermal formations

This article studies the rheology and annular flow of a smart lost circulation material (LCM) at 160 °C, using a high-temperature flow loop. The smart LCM is a shape memory polymer (SMP) that activates at high temperatures, and its particle size increases to seal fractures in geothermal formations. SMP was mixed with the base fluid in two different concentrations, 1.0 and 3.0 wt%, to study rheology, wellbore hydraulics, activation process, and settling behavior under different testing conditions. The results of this study showed that the SMP could be activated at high temperatures. An increase of 80–100% in the particle size was observed at 160 °C. The mud samples showed a high shear-thinning behavior at the two concentrations with a Power-law flow index (n) ranging between 0.025 and 0.101. No additional frictional pressure losses were observed when SMP was added to the base fluid. SMP particles showed an excellent suspension at 1.0 wt% while, at 3.0 wt%, a bed was formed at a low flow rate and without pipe rotation. Increasing the drill pipe rotational speed or flow rate effectively removed the bed and homogeneously dispersed the SMP particles, ensuring a better sealing efficiency. SMP particle dispersion in inclined wells was better than in horizontal wells. Moreover, the findings of this study help optimize the lost circulation treatment by considering a wide range of operating parameters that can further be extended to different systems and geometries.

02 PETROLEUM↗