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At least 145 records · Page 8
All sourcesNASA NTRSDOE OSTI
DOE OSTI2016

Characterization of immiscible fluid displacement processes with various capillary numbers and viscosity ratios in 3D natural sandstone

We characterize the influence of reservoir conditions upon multiphase flow, we calculated fluid displacements (drainage processes) in 3D pore spaces of Berea sandstone using two-phase lattice Boltzmann (LB) simulations. The results of simulations under various conditions were used to classify the resulting two-phase flow behavior into three typical fluid displacement patterns on the diagram of capillary number (Ca) and viscosity ratio of the two fluids (M). In addition, the saturation of the nonwetting phase was calculated and mapped on the Ca–M diagram. We then characterized dynamic pore-filling events (i.e., Haines jumps) from the pressure variation of the nonwetting phase, and linked this behavior to the occurrence of capillary fingering. The results revealed the onset of capillary fingering in 3D natural rock at a higher Ca than in 2D homogeneous granular models, with the crossover region between typical displacement patterns broader than in the homogeneous granular model. Furthermore, saturation of the nonwetting phase mapped on the Ca–M diagram significantly depends on the rock models. These important differences between two-phase flow in 3D natural rock and in 2D homogeneous models could be due to the heterogeneity of pore geometry in the natural rock and differences in pore connectivity. By quantifying two-phase fluid behavior in the target reservoir rock under various conditions (e.g., saturation mapping on the Ca–M diagram), our approach could provide useful information for investigating suitable reservoir conditions for geo-fluid management (e.g., high CO 2 saturation in CO 2 storage).

58 GEOSCIENCES↗
DOE OSTI2019

CO 2 -brine relative permeability and capillary pressure of Tuscaloosa sandstone: Effect of anisotropy

Relative permeability and capillary pressure are known as essential properties that have substantial impacts on the accuracy of reservoir simulations. The effect of small-scale heterogeneity and lamination in the rock structure is often ignored during the measurement of capillary pressure and relative permeability curves in core samples. This study highlights the remarkable impact of anisotropy on the multiphase flow properties of stratified formations. A series of steady-state CO 2 -brine drainage and imbibition tests are conducted at reservoir conditions in horizontal and vertical core samples of the Tuscaloosa sandstone from the Cranfield CO 2 injection site in Mississippi. The relative permeability curves represent an anisotropic behavior influenced by the heterogeneous and laminated structure of realistic rock samples. The CO 2 saturation profiles during drainage and imbibition cycles indicate that the phase distribution in the pore space is controlled by core-scale heterogeneity in the porosity distribution among the laminations that causes capillary pressure inhomogeneity. Using the saturation profile during the imbibition cycle, the trapping characteristic of the horizontal and vertical rock samples are compared and we found that the capillary trapping is less likely in the vertical direction. Furthermore, the centrifuge-measured capillary pressure demonstrates distinctive characteristics for horizontal and vertical core samples. Since the flooding experiments are performed under capillary controlled flow, the capillary pressure contrast in the laminated structure of the rock strongly affects the relative permeability. The presented results can potentially improve the accuracy of the large-scale simulations for the CO 2 post-injection period, in which the vertical displacement has an important role in the plume migration.

58 GEOSCIENCES↗
DOE OSTI2017

Probabilistic Risk Assessment of CO2 Trapping Mechanisms in a Sandstone CO2-EOR Field in Northern Texas, USA

This study employs a polynomial chaos expansion (PCE) technique to develop the reduced order models (ROMs) integrated with the Monte Carlo simulations to quantify uncertainties of CO 2 storage associated with enhanced oil recovery (EOR) in a commercial-scale CO 2 -EOR field. The Morrow B sandstone at the Farnsworth Unit (FWU) EOR field in northern Texas was selected as a case study. A 3-D reservoir model, including simulation of a five-spot injection/production well pattern, was constructed based on the data from well logs and cores, and an updated seismic interpretation in the FWU. Porosity and permeability were considered as sources of uncertainty. The 1000-realization heterogeneous random fields of porosity and permeability were generated based on the variogram analysis on the core measurements of the FWU. Three model outputs of interest include the amount of CO 2 trapped by three trapping mechanisms, i.e. hydrodynamic trapping, oil dissolution trapping, and aqueous dissolution trapping. The total of 25 runs were conducted with the simulations of a 20-year CO 2 -EOR period, and a 20-year monitoring period to develop the ROMs between uncertain model input parameters (i.e., porosity and permeability in this study) and model outputs at the end of simulation for each grid cell using PCE approach. The high coefficient of determination (R 2 ) and small normalized root mean square error (NRMSE) between the simulated (using reservoir modeling) and predicted (using ROMs) CO 2 storage indicate that the ROMs are acceptable and reliable to be used for the predictions. Given the 1000 Monte Carlo samplings of the model input parameters, cumulative distribution functions (CDFs) and uncertainty bounds (10 th and 90 th percentiles) of model outputs were estimated based on ROMs. At the end of simulation, the most injected CO 2 at the FWU was stored by hydrodynamic trapping (between 121,400 and 166,860 tonnes), followed by oil dissolution trapping (between 55,303 and 76,816 tonnes), and aqueous dissolution trapping (between 1979 and 2751 tonnes).

58 GEOSCIENCES↗
DOE OSTI2022

Investigation of enhanced CO 2 storage in deep saline aquifers by WAG and brine extraction in the Minnelusa sandstone, Wyoming

Geological CO 2 sequestration in deep saline aquifers has been extendedly investigated to reach the goal of carbon neutral as large amount of CO 2 can be reduced in a short time. Here, this study investigates the feasibility of water-alternating-gas (WAG) injection and brine extraction on enhancing CO 2 storage in a target deep saline aquifer, Minnelusa Sandstone in the Powder River Basin (PRB) of Wyoming. An integrated numerical model is developed to account for four scenarios: (1) CO 2 continuous injection (CI) through one injection well, (2) WAG injection through one injection well, (3) CO 2 CI through one injection well and brine extraction through one producer, (4) WAG injection through one injection well and brine extraction through one producer. Simulation results suggest that WAG injection and brine extraction corporately make it possible to enhance CO 2 injectivity while securing CO 2 storage safety. For instance, WAG injection considerably reduces structural trapping contribution while enhances dissolved and residual trapping contributions. As for brine extraction, it can decrease the maximum averaged reservoir pressure by 37% and 22% for CI and WAG injection, respectively. Besides, sensitive analyses of the operational parameters for the fourth scenarios are performed. Results reveal that, when the amount of total CO 2 injection has been predetermined, CO 2 injection time and rate within each period of WAG should be small whereas it is preferable to have large water injection time and rate. This is to secure desirable dissolved and residual trapping contributions (store CO 2 with safety). Sensitive degree results confirm that CO 2 injection rate, water injection time, and CO 2 injection time of WAG injection exhibit significant effects on CO 2 storage whereas the impacts of producer bottom-hole pressure (BHP), water injection rate, and CO 2 -water injection time are relatively weaker. This study not only sheds light on achieving double-win goal: enhance CO 2 injectivity and store CO 2 with safety, but also can be a critical reference for other CO 2 storage in deep saline aquifers.

58 GEOSCIENCES↗
DOE OSTI2023

Uncertainty quantification of the convolutional neural networks on permeability estimation from micro-CT scanned sandstone and carbonate rock images

Rock permeability is one of the most crucial properties affecting subsurface fluid flow behaviors. To accurately and robustly estimate the permeability, Digital Rock Physics, including micro-CT scanning technology and direct flow simulations on scanned images, has prevailed in recent years. Besides, machine learning techniques such as convolutional neural networks (CNNs) have been widely adopted and achieved success in permeability estimations directly from rock images. However, existing ML methods used for permeability estimation from rock images lack uncertainty quantification that causes unreliable predictions and overconfident estimations on out-of-distribution (OOD) samples. Here, in this work, we propose a PI3NN-CNN framework to address this problem. PI3NN-CNN consists of a CNN model for absolute permeability estimation and a PI3NN method to quantify the estimation uncertainty. It is able to quantify the uncertainty for in-distribution (InD) data with a desired confidence level, and identify OOD samples to avoid overconfident predictions. We demonstrate the method using micro-CT scanned images from two sandstone and two carbonate rocks. We found that PI3NN-CNN generates accurate predictions for InD samples, while producing high-quality prediction uncertainties regardless of the prediction accuracy. Meanwhile, PI3NN-CNN identifies OOD samples using its special network initialization scheme. The unique feature of PI3NN-CNN makes it applicable to more complex real-world image-based data for robust learning and predictions without overconfident estimations when the ground-truth information is unavailable.

58 GEOSCIENCES↗
DOE OSTI2016

Characterization of heterogeneity in the Heletz sandstone from core to pore scale and quantification of its impact on multi-phase flow

In this paper we present the results of an extensive multiscale characterization of the flow properties and structural and capillary heterogeneities of the Heletz sandstone. We performed petrographic, porosity and capillary pressure measurements on several subsamples. We quantified mm-scale heterogeneity in saturation distributions in a rock core during multi-phase flow using conventional X-ray CT scanning. Core-flooding experiments were conducted under reservoirs conditions (9 MPa, 50 °C) to obtain primary drainage and secondary imbibition relative permeabilities and residual trapping was analyzed and quantified. We provide parameters for relative permeability, capillary pressure and trapping models for further modeling studies. A synchrotron-based microtomography study complements our cm- to mm-scale investigation by providing links between the micromorphology and mm-scale saturation heterogeneities.

54 ENVIRONMENTAL SCIENCES↗
DOE OSTI2016

Mineral changes in cement-sandstone matrices induced by biocementation

Prevention of wellbore CO 2 leakage is a critical component of any successful carbon capture, utilization, and storage program. Sporosarcina pasteurii is a bacterium that has demonstrated the potential ability to seal a compromised wellbore through the enzymatic precipitation of CaCO 3 . In this paper, we investigate the growth of S. pasteurii in a synthetic brine that mimics the Illinois Basin and on Mt. Simon sandstone encased in Class H Portland cement under high pressure and supercritical CO 2 (P CO2 ) conditions. The bacterium grew optimum at 30 °C compared to 40 °C under ambient and high pressure (10 MPa) conditions; and growth was comparable in experiments at high P CO2 . Sporosarcina pasteurii actively induced the biomineralization of CaCO 3 polymorphs and MgCa(CO 3 ) 2 in both ambient and high pressure conditions as observed in electron microscopy. In contrast, abiotic (non-biological) samples exposed to CO 2 resulted in the formation of surficial vaterite and calcite. Finally, the ability of S. pasteurii to grow under subsurface conditions may be a promising mechanism to enhance wellbore integrity.

58 GEOSCIENCES↗
DOE OSTI2017

Visualization and prediction of supercritical CO 2 distribution in sandstones during drainage: An in situ synchrotron X-ray micro-computed tomography study

Pore-scale distribution of supercritical CO 2 (scCO 2 ) exerts significant control on a variety of key hydrologic as well as geochemical processes, including residual trapping and dissolution. Despite such importance, only a small number of experiments have directly characterized the three-dimensional distribution of scCO 2 in geologic materials during the invasion (drainage) process. Here, we present a study which couples dynamic high-resolution synchrotron X-ray micro-computed tomography imaging of a scCO 2 /brine system at in situ pressure/temperature conditions with quantitative pore-scale modeling to allow direct validation of a pore-scale description of scCO2 distribution. The experiment combines high-speed synchrotron radiography with tomography to characterize the brine saturated sample, the scCO 2 breakthrough process, and the partially saturated state of a sandstone sample from the Domengine Formation, a regionally extensive unit within the Sacramento Basin (California, USA). The availability of a 3D dataset allowed us to examine correlations between grains and pores morphometric parameters and the actual distribution of scCO 2 in the sample, including the examination of the role of small-scale sedimentary structure on CO2 distribution. The segmented scCO 2 /brine volume was also used to validate a simple computational model based on the local thickness concept, able to accurately simulate the distribution of scCO 2 after drainage. The same method was also used to simulate Hg capillary pressure curves with satisfactory results when compared to the measured ones. Finally, this predictive approach, requiring only a tomographic scan of the dry sample, proved to be an effective route for studying processes related to CO 2 invasion structure in geological samples at the pore scale.

3D quantitative morphometric analysis↗
DOE OSTI2017

Evolution of permeability and Biot coefficient at high mean stresses in high porosity sandstone

A series of constant mean stress (CMS) and constant shear stress (CSS) tests were performed to investigate the evolution of permeability and Biot coefficient at high mean stresses in a high porosity reservoir analog (Castlegate sandstone). Permeability decreases as expected with increasing mean stress, from about 20 Darcy at the beginning of the tests to between 1.5 and 0.3 Darcy at the end of the tests (mean stresses up to 275 MPa). The application of shear stress causes permeability to drop below that of a hydrostatic test at the same mean stress. Results show a nearly constant rate decrease in the Biot coefficient as the mean stress increases during hydrostatic loading, and as the shear stress increases during CMS loading. In conclusion, CSS tests show a stabilization of the Biot coefficient after the application of shear stress.

58 GEOSCIENCES↗
DOE OSTI2020

Localization of deformation in fluid-saturated sandstone

Herein we discuss a laboratory study of inelastic deformation and localization was conducted to evaluate microseismicity and fracture in fluid-saturated rock. Plane strain compression experiments were performed on oil- and water-saturated Berea sandstone under dry, drained, undrained, and quasi-unjacketed conditions. Parameters associated with the elastic and inelastic material response were accurately measured and used in a constitutive model to predict localization of deformation under the drained and undrained conditions. Acoustic emission (AE) activity was recorded and the onset of inelastic response in fluid-saturated rock, similar to dry rock, coincided with an increase in AE rate. Fracture initiation and propagation were successfully monitored by AE locations. Clustering of AE events and the start of inhomogeneous deformation inferred from displacement measurements are shown to be well correlated with the model prediction of the onset of localized deformation under various rock-fluid interaction conditions.

42 ENGINEERING↗
DOE OSTI2021

Modelling yield cap evolution in sandstone based on brittle creep experiments

The Zenifim Formation is being considered as a potential disposal formation for a deep borehole nuclear repository concept in Israel. Site selection and repository construction are intended to ensure that waste is separated from circulating groundwater, but long-term deformation of the wellbore could potentially create fluid flow pathways. To understand how time-dependent rock strength could affect wellbore stability, here we conducted creep tests under low to moderate confining pressures on retrieved core from the Zenifim formation. During creep, samples strain slowly as gradual damage accumulation progressively weakens the samples. Failure eventually occurred through the near-instantaneous formation of a shear fracture. Experimental results were used to calibrate a continuum damage poro-elastic model for sandstones. The calibrated damage-poro-elastic model successfully simulates different types of loading experiments including quasi-static and creep. The state of strain in experiments is close to yield during loading as the yield cap continuously evolves with damage accumulation. For creep tests, most damage occurs during triaxial loading. Minor damage accumulation occurs under constant load until the final stage of creep, where damage accelerates and promotes unstable fracturing.

58 GEOSCIENCES↗
DOE OSTI2012

Using X-Ray Computed Tomography in Pore Structure Characterization for a Berea Sandstone: Resolution Effect

X-raycomputedtomography (XCT) is a powerful tool for detecting the micro-scale porestructure and has been applied to many natural and synthetic porous media. However, due to the resolution limitations, either non-representative view of the sample or inaccurate results can be produced from the XCT image processing. In this paper, two XCT (micro-CT and CT with synchrotron radiation) with different resolutions of 12.7 μm and 0.35 μm, as well as mercury intrusion porosimetry (MIP) with a minimum detection limit of 3 nm, were used for Berea sandstone to investigate the effect of detecting resolution on the porestructure. Several key porestructure parameters, including porosity, pore size distribution, pore connectivity, surface area, hydraulic radius, and aspect ratio were analyzed in a manner of quantitative comparison between different resolutions of XCT and MIP. The low resolution XCT can capture the large-pore porosity, while overestimates the pore size and pore connectivity. The high resolution XCT is more accurate in describing the pore shape, porosity, pore size; however, it is not representative since narrower detecting pore size range and small volume represented. A representative element volume related to large-pore porosity and probably large-pore connectivity with diameter and height of 2.8 mm is obtained through scale effect analysis. Therefore, selecting an appropriate resolution should be a compromise between the pore size and the representative element volume for the specific property or process of interest.

Environmental Molecular Sciences Laboratory↗
DOE OSTI2020

Comparison of permeability predictions on cemented sandstones with physics-based and machine learning approaches

Permeability prediction has been an important problem since the time of Darcy. Most approaches to solve this problem have used either idealized physical models or empirical relations. In recent years, machine learning (ML) has led to more accurate and robust, but less interpretable empirical models. Using 211 core samples collected from 12 wells in the Garn Sandstone from the North Sea, this study compared idealized physical models based on the Carman-Kozeny equation to interpretable ML models. We found that ML models trained on estimates of physical properties are more accurate than physical models. The results show evidence of a threshold of about 10% volume fraction, above which pore-filling cement strongly affects permeability.

03 NATURAL GAS↗
DOE OSTI2019

Inertial Effects During the Process of Supercritical CO 2 Displacing Brine in a Sandstone: Lattice Boltzmann Simulations Based on the Continuum-Surface-Force and Geometrical Wetting Models

Inertial effects during the process of supercritical CO 2 displacing brine in porous media may not be negligible according to recent studies. Capturing the inertial effects of the physical CO 2 -brine system imposes a requirement on the grid resolution and viscosity to surface tension ratio for pore-scale simulations, which some commonly used simulators may not be able to meet. To fulfill the parameter requirement, we combine the continuum-surface-force based color-gradient lattice Boltzmann (LB) multiphase model and the geometrical wetting model and extend the model to 3D under the multiple-relaxation-time framework. We validate the model via simple benchmarks which show significant improvement over the traditional models. Furthermore, we perform 3D drainage simulations in a heterogeneous micromodel where the simulation result agrees well with experimental data, while our previous work fails to reproduce certain displacement patterns in the experiment due to the use of a traditional LB model that cannot fulfill the parameter requirement. Finally, we perform high-fidelity 3D drainage simulations to study the inertial effects in a Bentheimer sandstone sample. These findings show that stronger inertial effects generally help develop more CO 2 flow pathways for the same capillary number which results in higher CO 2 saturation, consistent with the micromodel results. The phenomena can be found in both low and high capillary number cases, indicating that the inertial effects are not dependent on the mean velocity. In addition, the change of the invasion patterns is not proportional to the change of inertial effects, thus exhibiting threshold behavior.

58 GEOSCIENCES↗
DOE OSTI2024

Evaluation of hydrogen storage in sandstone reservoirs using 1 H nuclear magnetic resonance spectroscopy

Evaluation of the hydrogen storage capacity of porous rocks is crucial for underground hydrogen storage. Using 1 H nuclear magnetic resonance (NMR) spectroscopy, we successfully characterized the hydrogen responses and identified storage mechanisms in Berea sandstone under varying water saturation. Here, the results indicate that the injected hydrogen behaves as a free gas phase and is capable of occupying the empty pore volume regardless of the saturation state. No hysteresis was observed during injection and production cycles.

37 INORGANIC, ORGANIC, PHYSICAL, AND ANALYTICAL CH↗
DOE OSTI2016

Chemical effects of carbon dioxide sequestration in the Upper Morrow Sandstone in the Farnsworth, Texas, hydrocarbon unit

Numerical geochemical modeling was used to study the effects on pore-water composition and mineralogy from carbon dioxide (CO2) injection into the Pennsylvanian Morrow B Sandstone in the Farnsworth Unit in northern Texas to evaluate its potential for long-term CO2 sequestration. Speciation modeling showed the present Morrow B formation water to be supersaturated with respect to an assemblage of zeolite, clay, carbonate, mica, and aluminum hydroxide minerals and quartz. The principal accessory minerals in the Morrow B, feldspars and chlorite, were predicted to dissolve. A reaction-path model in which CO2 was progressively added up to its solubility limit into the Morrow B formation water showed a decrease in pH from its initial value of 7 to approximately 4.1 to 4.2, accompanied by the precipitation of small amounts of quartz, diaspore, and witherite. As the resultant CO2-charged fluid reacted with more of the Morrow B mineral matrix, the model predicted a rise in pH, reaching a maximum of 5.1 to 5.2 at a water–rock ratio of 10:1. At a higher water–rock ratio of 100:1, the pH rose to only 4.6 to 4.7. Diaspore, quartz, and nontronite precipitated consistently regardless of the water–rock ratio, but the carbonate minerals siderite, witherite, dolomite, and calcite precipitated at higher pH values only. As a result, CO2 sequestration by mineral trapping was predicted to be important only at low water–rock ratios, accounting for a maximum of 2% of the added CO2 at the lowest water–rock ratio investigated of 10:1, which corresponds to a small porosity increase of approximately 0.14% to 0.15%.

Ahmmed, Bulbul↗