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At least 1,477 records · Page 82
All sourcesNASA NTRSDOE OSTI
DOE OSTI2021

Distribution of rare earth elements and other critical elements in beneficiated Pennsylvania anthracites

The Pennsylvania Anthracite Fields are in a complex tectonic and metamorphic terrain, historically hosting one of the largest concentrations of coal mining in the USA. Anthracite mining now largely consists of the surface mining of the pillars remaining from the prime years of underground mining. The geochemical study of the sized coal products and the refuse (largely rock) from three preparation plants (breakers) demonstrates that Principal components analysis (PCA) of select major oxide, minor element, and rare earth elements illustrates some differentiation among the products from the individual plants. The rock samples, with abundant quartz and metamorphic Al-Si minerals and with a lower ash-basis REE concentration than the coals, were distinctly separated from the coal samples on the PCA plots. Plots of Gd N /Gd N * vs. Eu N /Eu N * and Ce N /Ce N * vs. Eu N / Eu N * showed differentiation between the individual suites of coals showed that the refuse samples had distinct REE distributions compared to the associated coals. Further, several minor and trace elements show enrichments in the coal samples. Lithium, with concentrations of up to 314 ppm on an ash basis, is among the most promising of the critical elements, exceeding the enrichment of the REY and Sc.

58 GEOSCIENCES↗
DOE OSTI2019

Optimal design of 3D borehole seismic arrays for microearthquake monitoring in anisotropic media during stimulations in the EGS collab project

Multiple U.S. national laboratories, universities and industrial collaborators are conducting collaborative research under the EGS Collab project supported by the U.S. Department of Energy, to understand the fracture creation and imaging during fracturing in enhanced geothermal systems. Microearthquake hypocenter locations and focal mechanisms are used to monitor hydraulic fracturing growth and characterization at the EGS Collab experimental site at the Sanford Underground Research Facility using seismic receivers in multiple monitoring wells. In this study, we develop a methodology for optimal design a 3D borehole seismic array for cost-effective seismic monitoring in anisotropic media using not only the relationship between receiver distributions and standard deviation errors of microearthquake hypocenter locations, but also that between receiver distributions and focal-mechanism inversion errors. Our results indicate that microearthquake hypocenter locations and focal mechanisms can be reasonably well reconstructed for the EGS Collab Experiment I using six monitoring wells, including four fracture-parallel monitoring wells and two orthogonal wells. Lastly, eight seismic receivers evenly distributed in four parallel monitoring wells or twelve receivers in all six monitoring wells are required for hypocenter location, and twelve receivers evenly distributed in six wells or sixteen receivers in four wells are needed for focal-mechanism inversion.

58 GEOSCIENCES↗
DOE OSTI2022

The 2017 Pohang, South Korea, Mw 5.4 main shock was either natural or triggered, but not induced

Understanding the cause of the November 2017 Pohang main shock is of considerable importance to the future of the geothermal industry because of its large magnitude compared to prior expectations based on case histories of other projects involving underground fluid injection. Of the three possibilities – induced, triggered or natural, “induced” can be ruled out based on the disproportionately large seismic moment of the main shock. Furthermore, whether natural or triggered, the source of seismic hazard at Pohang was tectonic strain accumulation, not fluid injection. Arguably, the most timely indicator of seismic hazard and risk in the environs of Pohang was the September 2016 Mw 5.4 Gyeongju earthquake, which was natural and located about 40 km south of Pohang along the same active fault system.

58 GEOSCIENCES↗
DOE OSTI2016

Dynamic simulation of CO 2 -injection-induced fault rupture with slip-rate dependent friction coefficient

It is known that poro-elastic stress and effective stress reduction associated with deep underground fluid injection can potentially trigger shear rupture along pre-existing faults. We modeled an idealized CO 2 injection scenario, to assess the effects on faults in the first phase of a generic CO 2 aquifer storage operation. We used coupled multiphase fluid flow and geomechanical numerical modeling to evaluate the stress and pressure perturbations induced by fluid injection and the response of a nearby normal fault. Slip-rate dependent friction and inertial effects have been taken into account during rupture. Contact elements have been used to take into account the frictional behavior of the rupture plane. We investigated different scenarios of injection rate to induce rupture on the fault, employing various fault rheologies. Published laboratory data on CO 2 -saturated intact and crushed rock samples, representative of a potential target aquifer, sealing formation and fault gouge, have been used to define a scenario where different fault rheologies apply at different depths. Nucleation of fault rupture takes place at the bottom of the reservoir, in agreement with analytical poro-elastic stress calculations, depending on injection-induced reservoir inflation and the tectonic stress scenario. For the stress state considered here, the first triggered rupture always produces the largest rupture length and slip magnitude, both of which correlate with the fault rheology. Velocity weakening produces larger ruptures and generates larger magnitude seismic events. Heterogeneous faults have been considered including velocity-weakening or velocity strengthening sections inside and below the aquifer, with the upper sections being velocity-neutral. Nucleation of rupture in a velocity-strengthening section results in a limited rupture extension, both in terms of maximum slip and rupture length. For a heterogeneous fault with nucleation in a velocity-weakening section, the rupture may propagate into the overlying velocity-neutral section, if the extent of velocity-weakening and associated friction drop are large enough.

58 GEOSCIENCES↗
DOE OSTI2022

Experimental study of fracture slip due to stress perturbation in fractured geo-resources

Anthropogenic activities such as underground fluid injection/extraction, well stimulation, and dam impoundment will perturb the state-of-stress in the subsurface, which could activate critically stressed pre-existing fractures and faults. Fault and fracture activation can induce seismicity, change flow behavior, and damage asperities on the fracture surface to alter reservoir permeability. Here, in this study, triaxial shear tests were conducted on saw cut and rough fracture Barre granite specimens to better characterize how a decrease in normal stress and increase in shear stress will influence crystalline rock fracture hydromechanical properties. In a triaxial set up, confining pressure (CP) and differential stress (DS) were used to induce normal and shear stress on a 45° oriented fracture. Fracture slip and the corresponding stress relaxation was observed when the confining stress decreased. Fracture permeability increased when the fracture slipped. Moreover, new micro-cracks observed by x-ray images indicated the creation of new flow paths for fluid movement. The experimental outcomes of this study indicate that decrease in normal stress due to stress perturbations along the faults/fractures in the extensional stress regime can induce the slip along the fracture. This could have a significant influence on slope stability in quarries, stimulation and injection strategy in deep geo-resources, and potentially minimize the risk of induced seismicity. The observed stress dependency of hydraulic aperture in rough fracture during pre- and post-slip stages could provide key inputs for field-scale simulation of geo-resources.

58 GEOSCIENCES↗
DOE OSTI2015

A digital seismogram archive of nuclear explosion signals, recorded at the Borovoye Geophysical Observatory, Kazakhstan, from 1966 to 1996

Seismologists from Kazakhstan, Russia, and the United States have rescued the Soviet-era archive of nuclear explosion seismograms recorded at Borovoye in northern Kazakhstan during the period 1966–1996. The signals had been stored on about 8000 magnetic tapes, which were held at the recording observatory. After hundreds of man-years of work, these digital waveforms together with significant metadata are now available via the project URL, namely http://www.ldeo.columbia.edu/res/pi/Monitoring/Data/ as a modern open database, of use to diverse communities. Three different sets of recording systems were operated at Borovoye, each using several different seismometers and different gain levels. For some explosions, more than twenty different channels of data are available. A first data release, in 2001, contained numerous glitches and lacked many instrument responses, but could still be used for measuring accurate arrival times and for comparison of the strengths of different types of seismic waves. The project URL also links to our second major data release, for nuclear explosions in Eurasia recorded in Borovoye, in which the data have been deglitched, all instrument responses have been included, and recording systems are described in detail. This second dataset consists of more than 3700 waveforms (digital seismograms) from almost 500 nuclear explosions in Eurasia, many of them recorded at regional distances. It is important as a training set for the development and evaluation of seismological methods of discriminating between earthquakes and underground explosions, and can be used for assessment of three-dimensional models of the Earth’s interior structure.

45 MILITARY TECHNOLOGY, WEAPONRY, AND NATIONAL DEF↗
DOE OSTI2015

Economic evaluation on CO₂-EOR of onshore oil fields in China

Carbon dioxide enhanced oil recovery (CO₂-EOR) and sequestration in depleted oil reservoirs is a plausible option for utilizing anthropogenic CO₂ to increase oil production while storing CO₂ underground. Evaluation of the storage resources and cost of potential CO₂-EOR projects is an essential step before the commencement of large-scale deployment of such activities. In this paper, a hybrid techno-economic evaluation method, including a performance model and cost model for onshore CO₂-EOR projects, has been developed based on previous studies. Total 296 onshore oil fields, accounting for about 70% of total mature onshore oil fields in China, were evaluated by the techno-economic method. The key findings of this study are summarized as follows: (1) deterministic analysis shows there are approximately 1.1 billion tons (7.7 billion barrels) of incremental crude oil and 2.2 billion tons CO₂ storage resource for onshore CO₂-EOR at net positive revenue within the Chinese oil fields reviewed under the given operating strategy and economic assumptions. (2) Sensitivity study highlights that the cumulative oil production and cumulative CO₂ storage resource are very sensitive to crude oil price, CO₂ cost, project lifetime, discount rate and tax policy. High oil price, short project lifetime, low discount rate, low CO₂ cost, and low tax policy can greatly increase the net income of the oil enterprise, incremental oil recovery and CO₂ storage resource. (3) From this techno-economic evaluation, the major barriers to large-scale deployment of CO₂-EOR include complex geological conditions, low API of crude oil, high tax policy, and lack of incentives for the CO₂-EOR project.

02 PETROLEUM↗
DOE OSTI2016

Simulation of carbon dioxide injection at the FutureGen2.0 site: Class VI permit model and local sensitivity analysis

Numerical simulation was conducted to evaluate supercritical CO 2 (scCO 2 ) storage in the Mt. Simon sandstone at the FutureGen 2.0 site in Morgan County, Illinois. The simulations illustrate the recent modeling effort conducted to successfully obtain a Class VI permit under the Underground Injection Control Program of the U.S. Environmental Protection Agency. The scCO2 was injected into a highly stratified reservoir, distributed among four lateral wells. Results show that each of the multiple reservoir layers with low permeability traps a fraction of the scCO 2 beneath it so that the injected scCO 2 does not reach the top of the reservoir by the end of the simulation period. Hence, all of the injected scCO 2 is considered to be safely trapped by the stratified structure within the reservoir. A local sensitivity analysis (LSA) was conducted for injectivity and plume size at the end of the 20 year injection period. The LSA indicates that the imposed initial conditions and the hydraulic properties of the injection layer contribute the most to the sensitivity. Overall, the simulation outputs are very sensitive to only a small fraction of the inputs. However, the parameters that are important for controlling CO 2 injectivity are not the same as those controlling the plume area. The three most sensitive inputs for injectivity are the horizontal permeability and the residual aqueous saturation of the injection layer, and the initial fracture-pressure gradient. For the plume area, the most sensitive inputs are the horizontal permeability of the injection layer and the residual aqueous saturation of the two adjacent layers above the injection layer. Furthermore, the advantages of requiring just a single set of simulation results, scalability to the proper parameter errors, and straightforward calculation of the composite sensitivities make the proposed analysis attractive for guiding site characterization, injection well design, estimating AoR uncertainty and, and monitoring network design.

54 ENVIRONMENTAL SCIENCES↗
DOE OSTI2018

Numerical estimations of storage efficiency for the prospective CO 2 storage resource of shales

Here, hydrocarbon-bearing shale formations might be an attractive geologic reservoir for permanent carbon dioxide (CO 2 ) storage. Shale formations applicable for storage require previous hydrocarbon production to deplete a reservoir, hydraulic fracturing to provide a highly-permeable stimulated zone, sufficient depths (generally > 800 m or 2600 feet) to maintain CO 2 in a supercritical state, and an overlying seal to prevent CO 2 migration to underground sources of drinking water and into the atmosphere. CO 2 is stored in shale as a free phase within fractures and matrix pores, and as a sorbed phase on organic matter and clay minerals. Recently in our previous work, we presented a screening-level assessment methodology for CO 2 storage in shales using a volumetric approach. The approach deals with reduction of CO 2 storage through estimations of efficiency factors based on petrophysical properties (i.e., bulk volume, porosity, sorption, etc.) and their limitations on fluid transport. Here, we conducted numerical simulations using the FRACGEN/NFFLOW simulator to study the CO 2 injection into a depleted hydro-fractured shale reservoir to estimate storage efficiencies using a range of reservoir parameters and injection scenarios. Specifically, the ranges for two efficiency factors, E Φ and E S , measure the effectiveness of free and sorbed CO 2 storage. These efficiency factors were estimated to have P 10 to P 90 probability ranges of 0.15 to 0.36 for and 0.11 to 0.24 for E S , reported after 60 years of CO 2 injection.

58 GEOSCIENCES↗
DOE OSTI2019

Cost curve of large-scale deployment of CO2-enhanced water recovery technology in modern coal chemical industries in China

China has emerged as a world leader in the coal chemical industry, which requires large amount of water and results in considerable CO2 emissions. This situation has led to the challenge of the CO2-Water nexus for China and particularly for the sustainable development of its coal chemical industry. CO2-enhanced water recovery (CO2-EWR) technology can provide large-scale CO2 mitigation and additional water supply in an integrated manner, especially in arid areas. Meanwhile, CO2 streams from industrial separation processes in the coal chemical industries are amenable to separation and can dramatically simplify or even dispense with the capture process. This study presents the first systematic assessment of a cost curve for onshore CO2-EWR potential using CO2 streams from industrial separation processes by an evaluation framework encompassing CO2 emission inventory, site suitability evaluation, and source–sink matching with techno-economic models. Preliminary results focused on the full capacity of several coal chemical processes as of 2015 suggest that CO2-EWR technology can mitigate 269 million tons of CO2 from industrial separation processes at relatively low cost ranging from 12 to 30 USD/t CO2 in China. Furthermore, 404 million tons of underground water could be produced for further desalination and utilization. When additional capacity under development could become fully operational, the emissions of 878 million tons of CO2 could be mitigated and provide 1318 million tons of vital water resources. Therefore, CO2-EWR technology can be essential to clean and sustainable development of the coal chemical industry and may provide low-cost opportunities to accelerate the deployment of large-scale CCUS projects in China.

CO2-enhanced water recovery, Modern coal chemical ↗
DOE OSTI2020

Multi-physics modeling of injected nanoparticles effect on remediation of CO 2 leakage through cracks

One potential risk in CO 2 sequestration is the leakage of carbon dioxide, which can result in contamination of underground water, creating potential threats to existing ecosystems. The common leakage pathway is through the pre-existing fractures or discontinuities within cement in the wellbore, incurred by the environmental conditions imposed on the cement. Injecting nanoparticles into pre-existing cracks is one of the most recently proposed ideas for mitigating fracture propagation in cement CO 2 sequestration. To demonstrate the feasibility of this new technology, a numerical approach was taken in this work, as it is challenging to investigate it in a laboratory setting. We proposed a coupled ALE (Arbitrary Lagrangian–Eulerian)–DEM (Discrete Element Method)–peridynamic modeling strategy within the LS-Dyna package to investigate the intertwined interaction among the CO 2 fluid flow, native fluid (e.g., brine), particle clusters, and cracks within the cement. The numerical results demonstrate that injected nanoparticles can effectively reduce the pressure exerted on the crack surface. Accordingly, the potential fracture propagation at the crack tip would be reduced compared to corresponding cases without nanoparticels as pressurized by fluid flow. This result verifies the effectiveness of proposed nanoparticle injection technology. Finally, using this established modeling strategy, the effect of filling particles on the fracture mitigation for different crack geometries (e.g. particle cluster patterns, aspect ratio of crack aperture and length) and CO 2 reservoir pressure are examined. The result shows that injected particles successfully reduce the fracture propagation in these scenarios.

42 ENGINEERING↗
DOE OSTI2020

Probabilistic risk-based Area of Review (AoR) determination for a deep-saline carbon storage site

Regulatory oversight of a geologic carbon sequestration (GCS) project relies on iterative estimations, throughout the project lifetime, of the area where increased risks to underground sources of drinking water (USDWs) may occur due to injection of CO2. This area, referred to as Area of Review (AoR), is typically delineated by predicting the migration of fluid between the reservoir and the lowermost USDW via an open wellbore using predictions from physics-based reservoir simulators. The inherent uncertainty in input parameters used in reservoir modeling therefore affects the accuracy of determining the AoR for a project. Furthermore, the standard analytical approaches for calculating a critical pressure to delineate the risk area yield an infinite AoR for cases where the injection reservoir is overpressured relative to the USDW. A methodology is presented in this paper to better characterize the risk to USDWs while accounting for the uncertainty in reservoir modeling, with an application to a permitted GCS project with an overpressured injection formation, FutureGen 2.0. The methodology is demonstrated using the National Risk Assessment Partnership’s open-source integrated assessment model (NRAP-Open-IAM) to develop a probabilistic estimate of impact risk to USDW quality. CO2 and pressure predictions from the reservoir modeling conducted using the STOMP-CO2 simulator for the FutureGen 2.0 site are used in a NRAP-Open-IAM model with reservoir, wellbore, and aquifer components to: (1) assess the extent of potential leakage into the USDW for the predicted reservoir pressure conditions; (2) evaluate the extent of potential impact using “no-net-degradation” thresholds; and (3) account for uncertainty in reservoir permeabilities.

03 NATURAL GAS↗
DOE OSTI2020

Influence of geochemical reactions on the creep behavior of Mt. Simon sandstone

The capture and subsurface storage of carbon dioxide is a sustainable option that is currently pursued worldwide to mitigate greenhouse gas effect. However, predicting the long-term mechanical integrity of CO 2 underground storage systems remains a challenge. To address that question, it is essential to understand the influence of fluid-rock chemo-mechanical interactions on the long-term and on the time-dependent mechanical properties. In turn, the long-term mechanical response and the time-dependent mechanical behavior can be represented by the creep response. We investigate the impact of CO 2 -induced geochemical reaction on the creep response of Mt. Simon sandstone with a 50–400 micron grain size. We perform static and dynamic flow experiments on Mt. Simon sandstone specimens under geological conditions, at a temperature of T = 50 - 53 °C and for CO 2 pressures of P = 8:62; 17:2 MPa under both static flow and dynamic flow-through conditions. After aging, we employ creep indentation testing, high-resolution SEM-EDS, computer vision, machine learning, and micromechanics modeling to probe changes on the microstructure and mechanical properties. Following both static and dynamic flow-through experiments, we observe a 10–22% decrease in quartz volume fraction and an increase in both the microporosity (7–28%) and nanoporosity (60–65%). Additional CO 2 -induced microstructural changes include an enlargement of pore throats and the formation of channels. These observations point to the presence of CO 2 -induced K-feldspar dissolution and clay dissolution reactions. Here, the macroscopic creep behavior is logarithmic and the macroscopic creep modulus varies depending on the microporosity and the relative quartz and feldspar content. As a result of these geochemical reactions and of the related microstructural changes, a 55-60% decrease in the macroscopic logarithmic creep modulus is predicted.

58 GEOSCIENCES↗
DOE OSTI2022

Assessment of oil and gas fields in California as potential CO 2 storage sites

California's total annual greenhouse gas (GHG) emissions (425.3 MtCO 2 e) in 2018 were about 6.4% of the US total (6,677 MtCO 2 e) and around 1% of global emissions. About 39% of 2018 GHG emissions in California were from the industrial and electrical sectors. Many of these emissions were from large stationary point sources and were suitable for carbon capture retrofit with subsequent storage of the captured carbon dioxide (CO 2 ) in geological formations. Previous studies of California found suitable geology and CO 2 storage resource. This study refines and furthers prior work using a three-stage screening process of oil fields, gas fields, and underground natural gas storage (UGS) sites by combining criteria from previous studies while excluding sites that pose technical risk or are located in regions with surface restrictions including sensitive habitats and dense populations. In the first stage, 129 CO 2 storage sites in California were identified using qualification criteria based upon formation properties including geological conditions and pore pressure. The second stage identified sensitive sites by applying conservative screens including seismic activity, faulting, population density, restricted lands, and sensitive habitats. During the third stage, 61 CO 2 potential storage sites were identified by subtraction of stage 2 areas from stage 1. The potential storage volume in the third stage ranged from 1.0 to 2.0 GtCO 2 . Finally, we applied a scoring system with seven parameters to rank the 61 potential sites based on subsurface technical criteria. The scored sites are classified as high priority, medium priority, and sites for future study. Prospective CO 2 storage sites with high and moderate priority were selected and linked to CO 2 sources. There are 14 prospective sites (above 20 MtCO 2 storage resource per site) with a total storage resource of 1024 MtCO 2 distributed in Northern and Southern California. Of these sites, there are 9 potential CO 2 -EOR sites and 1 depleted oil field with a total estimated CO 2 storage volume of ~800 MtCO 2 in the Southern San Joaquin and Ventura Basin. These 10 prospective sites with a storage resource greater than 20 MtCO 2 could potentially deliver more than 20 years of storage with an average injection rate of 40 MtCO 2 /year. The remaining 4 highly prospective sites are in Northern California. Additionally, study results suggest that saline formations should be re-evaluated in concert with storage in oil, gas, and natural gas storage reservoirs.

58 GEOSCIENCES↗
DOE OSTI2022

Risk matrix for legacy wells within the Area of Review (AoR) of Carbon Capture & Storage (CCS) projects

The success of CCS depends on the capacity, injectivity, and confinement by the storage medium. Thousands of wells drilled over the past century with the intention to find the trapped oil and gas may penetrate the containment seals. These wells may provide leakage pathways for the CO 2 to escape and contaminate the underground sources of drinking water (USDW) or reach the surface in the worst-case scenario. Identifying the risky wells penetrating the containment seals and predicting their current as well as future well integrity is the most challenging task when limited data is available. Here, this paper proposes a unique methodology for risk assessment of the wells penetrating the containment seals based on the proximity of these wells from the proposed injection location, mechanical integrity, and accessibility of these wells over the lifecycle of the CCS project. This helps in identifying the wells which need immediate attention from the wells that need little to no attention. It also highlights the corrective actions necessary for the success of the CCS project as well as help estimate the approximate cost required to perform the corrective actions. This methodology focuses on all wells (producers, injectors, orphan, abandoned, water, stratigraphic, etc) while the majority of the studies found in literature focused on wells with sustained casing pressure (SCP) reports and cement bond logs (CBL). The proposed risk matrix, if applied to future CCS projects across the globe, will uniformly categorize the wells within the Area of Review (AoR).

58 GEOSCIENCES↗
DOE OSTI2025

Quantifying CO 2 Plume Stabilization at Carbon Storage Projects, North Dakota, USA

This study presents an approach for quantifying when injected carbon dioxide (CO 2 ) stabilizes pursuant to carbon capture and storage (CCS) project permitting and site closure requirements. The distribution of mobile-phase CO 2 (CO 2 plume) will evolve within the storage reservoir during and after injection through both physical and chemical trapping mechanisms. CCS policies generally agree that the CO 2 plume’s migratory behavior in post-injection should demonstrate nonendangerment to the environment but do not provide specific guidance on how to meet the definition of plume stabilization, generating some uncertainty for operators. Plume stability herein means the CO 2 plume 1) changes size minimally and predictably in the storage reservoir such that it will not cross key boundaries identified in the permit and 2) does not pose a threat to human health, underground sources of drinking water (USDWs), and the environment because of lateral migration to areas where leakage pathways may exist. Published literature on plume metrics was reviewed to determine which metric(s) may be most appropriate for determining CO 2 plume stability. A technical approach that defines plume stabilization by estimating the rate of change in the geographic footprint of the CO 2 plume with respect to time was developed and illustrated using a case study from North Dakota, USA, as a proposed solution for CCS operators to apply at the project permitting stage. Any prospective CCS operator may benefit from using the same approach to inform the selection of pore space lease and monitoring areas and develop post-injection site care plans.

03 NATURAL GAS↗