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At least 19 records
All sourcesNASA NTRSDOE OSTI
DOE OSTI2025

An experimental study on gas-liquid phase fluid migration in hydrate-bearing sediments during hydrate dissociation

Natural gas hydrate production tests face problems such as severe sand blockage, poor gas-liquid phase separation, and significant land subsidence. This is because of the insufficient understanding of the complex phase transition and gas-liquid multi-phase fluid migration during hydrate dissociation. In hydrate-bearing sediment systems, hydrate phase transition couples with gas-liquid fluid migration. The phase transition causes changes in pore structure, which in turn modifies porous infiltration parameters and fluid flow capacity. Meanwhile, alterations in phase interfaces affect key parameters like surface tension and wettability. Gas-liquid fluid migration influences heat and mass transfer, thus affecting phase equilibrium and dissociation rates. To bridge the gap in describing gas-liquid fluid migration during hydrate dissociation in experiments, this research innovatively integrated an unsteady-state gas displacement by water and a quantitative hydrate dissociation process, independently developed a multi-phase seepage experimental system suitable for hydrate dissociation and determined the relationship between seepage parameters and hydrate saturation under different porosity. The results are as follows: a) Core samples with higher initial porosity show a greater recovery rate of fluid flow capacity. b) The retarding effect of multi-phase fluid has a more significant impact on the migration of the wetting phase fluid (water) than that of the non-wetting phase fluid (methane). c) During hydrate dissociation, the evolution of absolute permeability shows an “S-shaped” pattern, and the evolution of relative permeability shows a “wiring-harness” pattern. In conclusion, the findings can provide a theoretical basis for preventing geological disasters and for geotechnical engineering design during hydrate production.

58 GEOSCIENCES↗
DOE OSTI2026

Determining the extent of potential fugitive fluid migration from geologic carbon storage in hydrocarbon-bearing reservoirs: Insights from one-dimensional numerical modeling

Numerical modeling of Geologic Carbon Sequestration in permeable reservoirs initially containing hydrocarbons is conducted using the multi-phase, multi-component thermohydrologic simulator TOGA (TOUGH Oil, Gas, Aqueous; TOUGH stands for Transport Of Unsaturated Groundwater and Heat), to determine how phase and composition of the original fluids influence the extent of the zone where upward fugitive fluid migration could potentially occur, denoted R f . The area within R f comprises regions of substantially elevated pressure and free-phase CO 2 saturation, where a breach in reservoir sealing capacity would lead to upward fugitive fluid migration. The model examines the conditions within the storage reservoir that could lead to fugitive flow, but does not model the fugitive flow itself. A one-dimensional radial model of the storage reservoir is used, and three initial phase conditions are considered: single-phase aqueous, two-phase gas-aqueous, and three-phase oil-gas-aqueous. Components that may be present are H 2 O, CO 2 , CH 4 , C 4 H 10 , and C 10 H 22 . The most important factors controlling Rf are (1) the initial gas-phase saturation within the reservoir, and (2) the lateral extent of multi-phase initial conditions, particularly CO 2 . The composition of liquid and gas phases has a secondary effect. The impact of reservoir depth, thickness, injection rate, and hydrologic properties are also briefly examined, with thickness (or equivalently injection rate) having the biggest effect. These results can help to understand important trends in potential response of CO 2 -EOR fields being considered for dedicated CO 2 storage.

CO₂ plume migration↗
DOE OSTI2022

Fluid migration in low-permeability faults driven by decoupling of fault slip and opening

Understanding the response of faults to the injection of high-pressure fluids is important for several subsurface applications, for example, geologic carbon sequestration or energy storage. Lab-based experiments suggest that fluid injection can activate fault slip and that this slip can lead to increased fluid transmission along low-permeability faults. Here we present in situ observations from a cross-borehole fluid-injection experiment in a low-permeability shale-bearing fault, which show fault displacement occurring before fluid-pressure build-up. Comparing these observations with numerical models with differing permeability evolution histories, we find that the observed variation in fluid pressure is best explained by a change in permeability only after the fault fails and slips beyond the pressurized area. Once fluid migration occurs along the fault as a result of slip-induced permeability increase, the fault experiences further opening due to a decrease in the effective normal stress. We then suggest that decoupling of fault slip and opening, leading to a rapid increase in fluid pressurization following the initial fault slip, could be an efficient driver for fluid migration in low-permeability faults.

58 GEOSCIENCES↗
DOE OSTI2025

Deep learning model for fast, science-based forecasting of fluid migration along faults in geologic carbon storage scenarios

Effective long-term geologic storage depends on robust site selection and credible, science-based forecasting of subsurface behavior to ensure storage integrity. For this work, we develop a deep learning–based reduced-order model (ROM) to quantify potential carbon dioxide (CO₂) and brine migration through geological faults. The ROM combines a Transformer model for binary classification and a Stacked Ensemble for regression, trained on a comprehensive dataset generated from 1400 physics-based reservoir simulations. Key geologic and operational parameters—including fault geometry, reservoir structure, and injection conditions—were systematically varied to capture a wide range of fluid migration scenarios. The ROM accurately predicts the onset of migration, cumulative migration volumes of both CO₂ and brine, and associated migration rates, as compared to an independent set of validation simulations, while significantly reducing computational cost compared to traditional simulation methods. Model performance was evaluated across diverse fault configurations, revealing that shallow reservoir geometry and fault angle are among the most influential factors governing migration behavior. Sensitivity analysis using SHapley Additive exPlanations (SHAP) provided interpretability, revealing distinct patterns in how geological and operational features drive transient versus cumulative migration outcomes. The ROM’s ability to rapidly simulate fault migration scenarios enables efficient sensitivity analyses, scenario evaluations, and decision support for site selection and monitoring design. This approach enhances the safety, scalability, and long-term operational performance of geologic carbon storage (GCS) systems by providing a robust, interpretable tool for predicting subsurface fluid migration and assessing fault-related migration potential.

42 ENGINEERING↗
DOE OSTI2023

In-situ experiment reveals CO2 enriched fluid migration in faulted caprock

Abstract The sealing characteristics of the geological formation located above a CO 2 storage reservoir, the so-called caprock, are essential to ensure efficient geological carbon storage. If CO 2 were to leak through the caprock, temporal changes in fluid geochemistry can reveal fundamental information on migration mechanisms and induced fluid–rock interactions. Here, we present the results from a unique in-situ injection experiment, where CO 2 -enriched fluid was continuously injected in a faulted caprock analogue. Our results show that the CO 2 migration follows complex pathways within the fault structure. The joint analysis of noble gases, ion concentrations and carbon isotopes allow us to quantify mixing between injected CO 2 -enriched fluid and resident formation water and to describe the temporal evolution of water–rock interaction processes. The results presented here are a crucial complement to the geophysical monitoring at the fracture scale highlighting a unique migration of CO 2 in fault zones.

Science & Technology - Other Topics↗
DOE OSTI2019

Basin-wide gradients in dolomite d26Mg and 87Sr/86Sr identify the structural centre of the Williston Basin as a source of magnesium for dolomitization of the Middle Devonian Winnipegosis Formation

Dolomitized carbonates in the Williston Basin are common below the Middle Devonian Prairie Evaporite Formation, indicating a plausible role for brine-reflux as the source of Mg for dolomitization. However, the Lower Member Winnipegosis Formation, which directly underlies the evaporite sequence, exhibits dolomite 87Sr/86Sr ratios that are higher than expected for Middle Devonian seawater, instead suggesting that the dolomitizing fluids ascended from the deep basin where present-day formation waters are known to be more radiogenic. This interpretation is supported in this study by Mg isotope data showing a basin-scale gradient of increasing d26Mg values from the deep center (–2.03‰) to the edge (–1.34‰) of the Williston Basin along the lower Member Winnipegosis bed. Dolomite favors light isotopes of Mg when it forms, thus driving dolomitizing solutions, and the produced dolomite, towards heavier isotopic compositions in the direction of fluid flow. However, dolomite is also Mg-deficient when it forms, and its initial Mg isotope composition is susceptible to alteration by fluid-rock interactions occurring later in the depositional history of the deposit. We argue that the Mg isotope gradient in the Lower Member Winnipegosis was created by an ascending flow of isotopically light Mg-bearing fluid that differentially altered an earlier formed brine-reflux dolomite, with more alteration occurring deeper in the basin and less towards to edges. Alteration of pre-existing dolomite by an Mg isotope exchange mechanism requires large supplies of Mg. This fact, and the direction of fluid flow point to the underlying crystalline basement as an important Mg source for dolomitization in the Williston Basin. We speculate that ultramafic rocks supplied the Mg when they were hydrothermally altered during an anomalous heating event that affected the Williston Basin in the Late Devonian / Early Carboniferous. Seismic pumping drove these fluids upwards through fracture networks in the crust, and eventually into the deep center of the Williston Basin along vertically-oriented down-to-the-basement faults, pressuring deep aquifers like the Winnipegosis, which resulted in fluids migrating up the stratigraphic dip of the beds towards the edges of the basin. Plotting and contouring the dolomite d26Mg data on a map of the Williston Basin reveals the pathways taken by the migrating fluids. One prominent pathway extending outwards from the center of the basin towards the northeast bears a strong resemblance to petroleum migration fairways deduced for the underlying Late Ordovician Red River Formation. This study demonstrates that Mg isotopic mapping of large dolomite bodies is a useful tool for deciphering fluid flow histories in sedimentary basins and may assist in locating migrated petroleum and Mississippi Valley Type ore deposits.

Magnesium Isotopes, Strontium Isotopes, Dolomitiza↗
DOE OSTI2019

Approaches to multi-scale analyses of mechanically and thermally-driven migration of fluid inclusions in salt rocks

Fluid inclusions are found within mineral crystals or along grain boundaries in many sedimentary rocks, notably in evaporite formations, and can migrate along a thermal or hydro-mechanical gradient. Shale and salt rocks have been considered potential host rocks for radioactive waste disposal, due to their low permeability. Previously stagnant inclusions may become mobilised by a perturbation of the in situ state by a geotechnical installation or the emplacement of heat-generating waste. Here, the migration of fluid inclusions can thus have important impacts on the long-term performance of a geologic repository for high-level radioactive waste disposal. As a part of the international research project DECOVALEX-2019, two aspects of fluid inclusion migration in rock salt are currently investigated under different boundary conditions: a) altered hydro-mechanical conditions as a consequence of tunnel excavation or borehole drilling and b) coupled thermo-hydro-mechanical-chemical conditions during the heating period of the post-closure phase of a repository.

58 GEOSCIENCES↗
DOE OSTI2025

Deep-learning-enhanced assessment of wellbore barrier effectiveness in geologic storage systems with intermediate aquifers

For geologic systems where carbon dioxide (CO 2 ) is injected underground, existing wells represent potential pathways for fluid migration. Here, this study introduces a novel deep learning model to quantify the likelihood and potential magnitude of fluid migration through wellbores at sites with intermediate aquifers or thief zones between the injection units and underground drinking water sources. Synthetic datasets, generated using reservoir simulations, captured a wide range of subsurface conditions, well attributes, operational parameters, and fluid migration scenarios. Among the regression models developed to predict brine and CO 2 leakage rates and CO 2 saturations along leaky wellbores, convolutional neural network (CNN) outperformed both Light Gradient Boosting Machine and deep neural network. Additionally, a CNN-based classification model was created to predict whether brine and CO 2 would leak along a wellbore, further improving performance over regression alone. The best models were integrated into the National Risk Assessment Partnership Open-source Integrated Assessment Model for rapid, stochastic assessment of storage system containment and leakage risks. A case study demonstrated the model’s ability to simulate fluid migration through existing wells with multiple intermediate aquifers. This computationally efficient wellbore model offers value in support of site performance evaluation and risk-informed decision making by stakeholders.

CO2 leakage↗
DOE OSTI2020

Determination of permeability for hydrocarbon release due to excavation-induced stress redistribution in rock salt

Due to a stress redistribution after the excavation of an underground tunnel for radioactive waste disposal, an Ed/DZ (excavation disturbed/damaged zone) will be generated in the near field of the opening, resulting in significant changes in the hydraulic and mechanical properties of the rock mass in the zone. Initially more or less randomly distributed hydrocarbons at grain boundaries in rock salt, which sometimes can only be observed with ultraviolet light, can then be mobilised and migrate at a potentially significant rate towards the excavation. Within the international cooperative project DECOVALEX 2019, the migration mechanism of such fluid inclusions in rock salt is being studied intensively. Specifically, a multi-scale modelling strategy has been developed. A macroscale coupled hydro-mechanical modelling of an underground excavation was performed to determine hydraulic and time-dependent deviatoric stress conditions, by taking into account the rock salt creep behaviour. Under the obtained macro-scale constraints, micro-scale modelling of a pathway dilation along halite grain boundaries was performed using different model strategies: a) coupled hydromechanical modelling with a consideration of hydraulic pressure-induced dilatant deformation, b) nonlinear dynamic model taking account of fluid migration, stress-dependent grain boundary wetting and shear-induced dilatancy of salt, and c) phase-field modelling of flow pathway propagation. The permeability increase resulting from the pathway dilation is estimated to be as high as two orders of magnitude. Based on the permeability determined, a series of pressure buildups measured from a borehole with a high hydrocarbon release rate, a total of 430 build-ups within a monitoring time of 938 days, can be simulated with a macro-scale compressible flow model accounting for different zones around the opening.

58 GEOSCIENCES↗
DOE OSTI2018

Permeability Evolution and Frictional Stability of Fabricated Fractures With Specified Roughness

Roughness is widely observed on natural fractures, and its impact on the potential for induced seismicity and associated fluid migration in the subsurface remains unclear. Here we perform fracture shearing and fluid flow experiments on artificially fabricated fractures with specified roughness to investigate the role of fracture roughness on frictional properties and permeability evolution. Given the experimental conditions, we observe that rough fractures show high roughness ratio S q /L w and return higher frictional strength due to the presence of cohesive interlocking asperities. Rough fracture surfaces show velocity strengthening behavior in the initial shearing stage, which may evolve to velocity neutral and velocity weakening at greater displacements—suggesting a dynamic weakening that rough fractures become less stable with shearing. The surface roughness exerts a dominant control on permeability evolution over the entire shearing history. Permeability declines monotonically by about 2 orders of magnitude for smooth fractures. For high roughness fractures, the permeabilities evolve episodically due to cycled compaction and dilation during shearing. With a slip distance of 6 to 8 mm, permeability of the rough surface may enhance up to an order of magnitude, but significant permeability reduction may also occur for rough samples when asperities are highly worn with gouge clogging flow paths. However, there is no obvious correlation between permeability evolution and frictional behavior for rough fracture samples when fractures are subject to sudden sliding velocity changes.

58 GEOSCIENCES↗
DOE OSTI2021

Episodic Earthquake Swarms in the Mineral Mountains, Utah Driven by the Roosevelt Hydrothermal System

Over 1,000 earthquakes (-2.0 < M < 2.0), identified using a matched-filter method, occurred in the Mineral Mountains, Utah between 2016 and 2019. The enhanced catalog is complete down to M -0.9 and contains roughly 15 times more events than originally cataloged. Earthquake relocation of ~800 earthquakes shows that activity is concentrated in a <2 km long E-W striking narrow zone, ~4 km east of the Roosevelt hydrothermal system. Two fault orientations, both N-S and E-W parallel to the Opal Mound and Mag Lee faults, respectively, are observed after computing composite focal mechanisms of highly similar earthquakes. Looking solely at the temporal distribution of the seismicity, we identify 15 periods of swarm-like activity, with two major clusters occurring in December 2016, recorded by three stations, and in October 2019 recorded by eight stations. The October 2019 swarm, the best recorded sequence in the area, provides evidence for the underlying triggering mechanism. We show that a complex mechanism of fluid diffusion and aseismic slip is responsible for the swarm evolution with migration velocities reaching 10 km/day. We hypothesize that these episodic swarms in the Mineral Mountains are primarily driven by migrating fluids that originate within the Roosevelt hydrothermal system.

58 GEOSCIENCES↗
DOE OSTI2024

Numerical investigation of multiphase flow through self-affine rough fractures

Multiphase flow through fractures has great significance in subsurface energy recovery and gas storage applications. Different fracture and flow properties affect flow through a fracture which is difficult to control in laboratory experiments. Here, we perform lattice Boltzmann simulations in an ensemble of synthetically generated fractures. Drainage simulations are performed at different capillary numbers, wettability, and viscosity ratios. We track the invading front and quantify breakthrough saturations and show that roughness and wettability have a strong effect on fluid invasion through a complex fracture. Invading a more viscous fluid results in more stable displacement regardless of the capillary number while at very low capillary numbers, fluid migration is dependent on the inherent structure of the fracture. We develop a fluid displacement phase diagram in a single rough fracture and compare our results from that in the literature. Finally, we extend the phase diagrams across multiple fractures and demonstrate the importance of natural fracture features of roughness and wettability in identifying stable versus unstable displacement regimes during multiphase flow through rough fractures. Our work presents an end-to-end numerical pathway for testing on experimental data and expanding numerical data sets for testing combinations of different physical phenomenon and make valuable predictions on fluid flow through rough fractures.

02 PETROLEUM↗
DOE OSTI2022

Simulation study of chemo-mechanical impacts of CO 2 injection in morrow b sandstone reservoir

Here, this study investigates the impacts of geomechanical and geochemical changes on carbon storage in a partially depleted oil reservoir, using results from four different coupled simulation models. Models were used to examine the relative importance of storage mechanisms, and how changing reservoir parameters might affect these mechanisms through time. The study uses data from a Morrowan sandstone reservoir in the Farnsworth Unit (FWU), Ochiltree County, Texas which is currently undergoing CO 2 enhanced oil recovery (EOR). Partially depleted oil reservoirs such as the FWU offer attractive carbon utilization and/or storage targets because of existing infrastructure and economic benefits from incremental oil recovery as well as tax credits. However, prediction of storage capacity or long-term fluid migration in these fields can be difficult because of the wide variation in formation fluids and operational histories that may have undergone. CO 2 injection can cause complex geomechanical and geochemical responses in a reservoir as a result of interplay between dynamic changes in pore pressure, reservoir temperature, fluid composition, and interactions between formation fluids, CO 2 , and reservoir rock. Thus, multiple coupled numerical simulation models must be developed and used to more precisely understand what CO 2 storage mechanisms are most significant, as well as the long-term fate of the stored CO 2 . Our study used results from hydrodynamic, coupled hydro-geomechanical, coupled hydro-geochemical, and coupled hydro-geomechanical-geochemical models to examine how changes in geomechanical and geochemical properties can impact the injectivity or storage capacity of CO 2 . Models simulated historical field operations and then forward-modeled a water-alternate-gas (WAG) operation for 20 years, followed by a 1000-year post-injection monitoring. The work demonstrates that in this specific reservoir, geomechanical impacts appear to be more significant than any geochemical processes, which showed minimal impact on reservoir properties. Furthermore, these simulation scenarios corroborated other studies showing more than 90% of CO 2 injected are being stored and will remain stored in the reservoir. The study was able to draw on a rich set of data from this currently operational project for the work. Because the Morrow is a widespread oil-bearing reservoir in the midcontinent of the United States and is fairly typical of many sandstone reservoirs elsewhere, the study has significance beyond the boundaries of our field area.

58 GEOSCIENCES↗
DOE OSTI2021

Recent seismicity at Ceboruco Volcano (Mexico)

Magma and related hydrothermal fluid movement, and their interaction with solid rock, in active volcanic regions, generate a wide variety of seismic waves whose characterization can mitigate the risk of a potential eruption. Located in the western region of the Trans-Mexican Volcanic Belt, Ceboruco Volcano, whose last eruptive period was 1870–1875, is considered to be one of the most hazardous volcanoes in Mexico. We have conducted a detailed study of the seismicity in the surroundings of Ceboruco's volcanic edifice to assess the current state of this volcano. A dense temporary seismic network with 25 seismic stations in an area of 16 km × 16 km was deployed between November 2016 and July 2017, as part of the P-24 project of the CeMIEGeo consortium; this effort has allowed the detection of 81 earthquakes concentrated beneath the crater with depths between 4 and 8 km. In this study, we observe that the recorded seismicity occurs in swarms, and we specifically identify four sequences that we characterize in detail via the first focal mechanisms available for this volcano. Our results suggest a change in the local seismicity distribution compared to earlier observations, which reported seismic activity near the volcano edifice associated with fluid migration along zones of weakness related to the extensional stresses of the Tepic-Zacoalco rift. The changes in seismic patterns and obtained focal mechanisms are consistent with observed fluid effects at many geothermal sites worldwide, but also could suggest resumption of activity at this currently dormant volcano.

58 GEOSCIENCES↗
DOE OSTI2024

Risk Considerations of Transitioning CO2-EOR Field to CO2 storage Field: Case Study

In the United States (U.S.), carbon dioxide (CO2) injection wells at EOR sites are currently regulated as Class II wells under the U.S. Environmental Protection Agency’s (EPA) Underground Injection Control (UIC) program while dedicated geological CO2 storage (GCS) wells are considered Class VI wells. A CO2-EOR facility considering a transitioning from tertiary oil recovery to injecting CO2 for the primary purpose of long-term storage is required to obtain a Class VI permit where this transition poses an increased risk to underground sources of drinking water. This study considers how transitioning operations from CO2-EOR to storage can impact reservoir plume and pressure transient in the storage envelope, and how these changes could impact area of review and potential unwanted fluid migration. We developed a case study to assess subsurface response and leakage risks associated with a representative, hypothetical operation in a carbonate reservoir. This reservoir transitions from tertiary hydrocarbon recovery to dedicated GCS. Reservoir simulations were run for a set of credible CO2-EOR scenarios to estimate distributions of fluids phases and pressures throughout the model domain after CO2 flooding as well as forecasting the behavior of the reservoir after the transition to a dedicated storage phase. The evolutions from all simulated scenarios were used as the basis for leakage risk quantification using the National Risk Assessment Partnership’s Open-Source Integrated Assessment Model (NRAP-Open-IAM) with a novel reduced-order model to estimate time-dependent leakage of CO2, brine, and hydrocarbon fluids through potentially leaky wells. Results include a description of reservoir response, an estimate of the areal extent that could potentially be impacted by leakage to underground sources of drinking water, and estimates of the magnitude of potential leakage. Considerations for dedicated storage injection well selection, injectivity, and injection scheme performance and potential leakage risk are presented, with implications for risk assessment of well transition discussed. This study presents a risk-based workflow for the Class II to Class VI well transition. Integrating credible numerical simulation of viable CO2-EOR to dedicated CO2 storage with quantitative risk assessment tools, such as the NRAP-Open-IAM, will provide a valuable means to devise operational scenarios and inform decision-making related to storage benefit, leakage risk, and liability. Presented at the SPE/AAPG/SEG Carbon Capture Utilization and Storage Conference in Houston, TX, March 11-13, 2024.

Liu, Guoxiang↗
DOE OSTI2019

Analysis of land-based CSEM data for CO2 monitoring at Bell Creek, MT

Monitoring subsurface fluid migration is critical to any CO2 injection operation like enhanced oil recovery or carbon storage. The controlled-source electromagnetic (CSEM) method provides a promising low-cost, non-invasive alternative to conventional monitoring methods. To investigate the use of CSEM for monitoring CO2 injection, we are conducting a time-lapse charged well casing CSEM survey at the Bell Creek oil field. There, CO2 is injected into the reservoir for enhanced oil recovery, which also results in incidental carbon storage. From October 2017 to October 2018 we completed three field campaigns, and we plan to complete one more in July 2019. We have analyzed the signal strength and variance of the time-lapse CSEM data. Difference data signal strength well exceeds the standard deviation of the data, and it agrees with estimates of expected signal strength derived from numerical modeling. This analysis indicates that our survey can detect the change in conductivity within the reservoir due to fluid movement.

time-lapse, land CSEM, monitoring, processing↗