Search NASA⌕ Search

SEARCH · Search NASA

Results for “FLUID INJECTION”

Search indexed NASA NTRS and DOE OSTI research on propulsion, heat transfer, battery materials and energy systems. Follow report and document links to the original sources.

Quote a phrase for an exact phrase match. Source license links do not imply unrestricted reuse.

At least 109 records · Page 6
All sourcesNASA NTRSDOE OSTI
DOE OSTI2025

Stratigraphy‐Induced Localization of Microseismicity During CO 2 Injection in Illinois Basin

Abstract Subsurface fluid injection stimulates complex hydromechanical interaction, necessitating the integration of geomechanical data across spatial and temporal scales to consider the sophisticated behavior. Induced seismic response is usually associated with the complex reservoir architecture and pre‐existing features that are three‐dimensional, such as local stratigraphy, fractures, faults, and other discontinuities. This study encompasses laboratory characterization of the coupled hydromechanical response of cores extracted from rock formations in Illinois Basin: reservoir ‐ Mt. Simon sandstone, basal seal ‐ Argenta sandstone, and crystalline basement ‐ Precambrian rhyolite. High‐resolution numerical modeling allows considering the three‐dimensional complexity of the Illinois Basin Decatur Project with spatial resolution comparable to one of the active seismic surveys. A detailed reconstruction of the evolving state of stress in formations lacking direct stress measurements is achieved by numerical modeling that integrated laboratory‐derived hydromechanical properties, a porosity‐permeability relationship, active seismic data, and an inverted three‐dimensional porosity distribution. It appears that the microseismic clusters, mainly observed in the crystalline basement during the injection, are linked to zones experiencing more critically stressed conditions prior to injection. These zones have a potential for reactivation during the injection and are attributed to the specific local stratigraphy of the injection site, as well as transfer of triggering perturbations during the injection.

Bondarenko, N. [University of Illinois Urbana‐Cham↗
DOE OSTI2018

Seismic Analysis of Spatio-Temporal Fracture Generation During EGS Resource Development

This DOE GTO funded project was a collaborative effort between Array Information Technology and the University of California at Berkeley. The project goal is to improve technology to assess in-situ stress magnitude and orientation, kinematic fracture parameters, rupture size, rupture orientation as well as temporal changes and volumetric distribution of the injected fluid during Enhanced Geothermal System (EGS) resource development. The project leveraged high-frequency seismic data recorded by the LBNL 34-station permanent geophone network and seismic broadband data recorded by a temporary 33-station seismometer network that operated in The Geysers during the injection phase of the DOE GTO funded EGS demonstration project at the well Prati-32. The operation of the broadband network with high station density and good azimuthal coverage to monitor the injection phase produced an unprecedented dataset that is typically unavailable for EGS operations. The two datasets offer the advantages of studying the parameters under investigation over a broader frequency band and the higher sensitivity of the broadband seismometers resulted in a richer dataset with a lower magnitude of completeness. Moment tensor (MT) inversion have been employed to develop a catalog of earthquake source solutions including moment tensor and finite source rupture area. This resulted in a 168-event waveform-based seismic moment tensor catalog for events 0.7≤Mw≤3.9 based on a semi-automated moment tensor analysis technique. The MT solutions were used for in-situ stress estimation during the EGS injection phases. We found an approximate 15-degree counterclockwise rotation of the least compressive stress sigma-3, and a rotation of the maximum compressive stress sigma-1 toward the vertical as the injected volume of water increased. We developed a rupture-area magnitude scaling relationship of The Geysers earthquakes obtained from finite-source inversion for fault slip that reveals a very high correlation to published results. Based on the rupture area-magnitude relationship we mapped Mw from the LBNL earthquake catalog to estimate the activated fracture area, its location and orientation within the injection volume of Prati-32. The double-difference Wadati (DDW) technique was applied to high-accuracy P- and S-wave differential travel times derived from waveform cross correlation to image fluid saturation in the subsurface based on Vp/Vs-ratio. The recently developed technique has been applied to estimate temporal changes of fluid distribution in fault zones and in volcanic regions but not yet in engineered geo-reservoirs. The improvement of the technology includes high-resolution waveform cross correlation applied to the high-quality datasets with lower magnitude of completeness resulting in a higher number of recorded events. The improvement allowed to estimate both, the spatial and temporal distribution of injected fluids and the state of the injected fluid during reservoir stimulation. Results of the DDW analysis revealed the development of an injection-derived steam plume during the early injection phase, particularly in the northern part of the Prati-32 study area.

15 GEOTHERMAL ENERGY↗
DOE OSTI2021

Pore-scale CFD simulations of clay mobilization in natural porous media due to fresh water injection

The present work investigates mechanisms of permeability impairment as a result of low-salinity fluid injection into brine-saturated porous media containing dispersible clays. Here, we present a computational fluid dynamics model at the pore-scale to simulate detachment, migration and straining of fine particles in porous media. The model uses an immersed boundary method to simulate the motion of clay fines in a fluid. In addition to the hydrodynamic forces, we model the Derjaguin-Landau-Verwey-Overbeek forces (DLVO) between clay fines and grains. Our simulations show the impact of the injected fluid's salinity and velocity on the concentration of clay fines retained on the grain surface. We see clay particles dislodging from the grain surface in clusters of up to 12 particles. Our simulation results also demonstrate clogging of narrow pore spaces by the detached particles from the grain surfaces.

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

Fault slip controlled by stress path and fluid pressurization rate

Abstract The practice of injecting fluids into the crust is linked to regional increases in seismicity. Increasing fluid pressure along preexisting faults is believed to enhance seismicity rates by reducing the shear stress required for slip, but the processes that cause faults to slip under conditions of fluid pressurization are poorly constrained. We use experimental rock deformation to investigate the controls of fluid pressurization and pressurization rates on fault slip style. We show that pore fluid pressurization is less effective that mechanical changes in fault normal stress at initiating accelerated slip events. Fluid pressurization enhances the total slip, slip velocity, and shear stress drop of events initiated by mechanical changes in normal stress, and these parameters are correlated with pressurization rate, but not the magnitude of fluid pressure. This result is consistent with field‐scale observations and indicates that processes active at the pore network scale affect induced seismicity.

French, Melodie E.↗
DOE OSTI2020

Abstract for Joint Work Statement 5 (AGMT-1005) between National Energy Technology Laboratory (NETL) and ExxonMobil Research and Engineering Company (EMRE) to Umbrella CRADA (AGMT-0922)

NETL and EMRE will focus on fundamental questions aimed at understanding the controlling factors on tight oil production flow paths and how those flow paths are impacted by the hydraulic fracturing fluids and processes. Key questions for the Parties to explore include the following: Are there geochemical reactions between hydrocarbon producing tight reservoir rocks and water from the hydraulic fracturing process? To what extent does this alteration impact oil production? By further characterizing the flow paths near the fracture-matrix interface, what is the relative impact of geochemical process compared to geomechanical changes on production? This research focuses on rock types found in the Permian Basin. The research drives along two main thrusts: 1) Inorganic geochemistry studies involving representative rock types, connate fluids (hydrocarbons and water), and injected fluids (fracturing water) will be conducted in order to bound the kinetics of key mineral reactions; 2) Computed tomography (CT) for characterization of flow paths as a function of geochemical and geomechanical processes associated with hydraulic fracture creation and reservoir production. The objective of this characterization is to ultimately develop new insights into the role geochemical and geomechanical effects play on production. The work will include studying mechanical damage near the rock-fracture interface and how it impacts flow properties.

02 PETROLEUM↗
DOE OSTI2018

Potential Experimental Topics for EGS Collab Experiment 3

To facilitate the success of FORGE, the DOE GTO has initiated a new research effort, the EGS Collab project, which will utilize readily accessible underground facilities that can refine our understanding of rock mass response to stimulation and provide a test bed at intermediate (~10 m) scale for the validation of thermal-hydrological-mechanical-chemical modeling approaches as well as novel monitoring tools. The first two EGS Experiments 1 and 2 are planned be performed under different stress/fracture conditions, and will evaluate different stimulation processes: Experiment 1 will focus on hydrofracturing of a competent rock mass, while Experiment 2 will concentrate on hydroshearing of a rock mass that contains natural fractures. Experiment 3 is scheduled to begin in 2019 will build off the lessons learned in Experiments 1 and 2 and will investigate alternate stimulation and operation methods to improve heat extraction in an EGS reservoir. This paper evaluates potential experiments that could potentially be conducted in Experiment 3. The two technical parameters defining energy extracted from EGS reservoirs with the highest economic uncertainty and risk are the production well flow rates and the reservoir thermal drawdown rate. A review of historical and currently on-going EGS studies has identified that over 1/2 of the projects have identified heat extraction challenges during their operation associated with these two parameters as well as some additional secondary issues. At present, no EGS reservoir has continuously produced flow rates on the order of 80 kg/s. Short circuiting (i.e. early thermal breakthrough) has been identified in numerous cases. In addition, working fluid loss (i.e. the difference between the injected fluid mass and the extracted fluid mass as compared to the injected mass) has been as high as 90%. Finally, the engineering aspects of operating a true EGS multi-fracture reservoir such as repairing/modifying fractures and controlling working fluid fluxes within multiple fractures for the effective EGS fracture management has not been sufficiently studied. To examine issues such as these, EGS Collab Experiment 3 may be conducted in the testbeds prepared for Experiments 1 and 2 by improving the previously performed stimulations, or conducted at a new site performing new stimulations with alternate method. Potential experiments may include using different stimulation and working fluids, evaluating different stimulation methods, using proppants to enhance permeability, and other high-risk high-reward methods that can be evaluated at the 10-m scale environment.

15 GEOTHERMAL ENERGY↗
DOE OSTI2018

Potential Experimental Topics for EGS Collab Experiment 3

To facilitate the success of FORGE, the DOE GTO has initiated a new research effort, the EGS Collab project, which will utilize readily accessible underground facilities that can refine our understanding of rock mass response to stimulation and provide a test bed at intermediate (~10 m) scale for the validation of thermal-hydrological-mechanical-chemical modeling approaches as well as novel monitoring tools. The first two EGS Experiments 1 and 2 are planned be performed under different stress/fracture conditions, and will evaluate different stimulation processes: Experiment 1 will focus on hydrofracturing of a competent rock mass, while Experiment 2 will concentrate on hydroshearing of a rock mass that contains natural fractures. Experiment 3 is scheduled to begin in 2019 will build off the lessons learned in Experiments 1 and 2 and will investigate alternate stimulation and operation methods to improve heat extraction in an EGS reservoir. This paper evaluates potential experiments that could potentially be conducted in Experiment 3. The two technical parameters defining energy extracted from EGS reservoirs with the highest economic uncertainty and risk are the production well flow rates and the reservoir thermal drawdown rate. A review of historical and currently on-going EGS studies has identified that over ½ of the projects have identified heat extraction challenges during their operation associated with these two parameters as well as some additional secondary issues. At present, no EGS reservoir has continuously produced flow rates on the order of 80 kg/s. Short circuiting (i.e. early thermal breakthrough) has been identified in numerous cases. In addition, working fluid loss (i.e. the difference between the injected fluid mass and the extracted fluid mass as compared to the injected mass) has been as high as 90%. Finally, the engineering aspects of operating a true EGS multi-fracture reservoir such as repairing/modifying fractures and controlling working fluid fluxes within multiple fractures for the effective EGS fracture management has not been sufficiently studied. To examine issues such as these, EGS Collab Experiment 3 may be conducted in the testbeds prepared for Experiments 1 and 2 by improving the previously performed stimulations, or conducted at a new site performing new stimulations with alternate method. Potential experiments may include using different stimulation and working fluids, evaluating different stimulation methods, using proppants to enhance permeability, and other high-risk high-reward methods that can be evaluated at the 10-m scale environment.

15 GEOTHERMAL ENERGY↗
DOE OSTI2022

Cubic-meter scale laboratory fault re-activation experiments to improve the understanding of induced seismicity risks

Abstract To understand fluid induced seismicity, we have designed a large-scale laboratory experiment consisting of a one-cubic-meter sandstone with an artificial fault cut and fluid-injection boreholes. The sandstone block is assembled in a true triaxial loading frame and equipped with 38 piezoelectric sensors to locate and characterise acoustic emission events. The differential stress on the artificial fault is increased in stages to bring it towards a critically stressed state. After each stage of differential stress increase, fluids are injected at low pressures through boreholes to test the potential of fault re-activation. In addition, a high-pressure injection was conducted that created a hydraulic fracture from the injection borehole towards the artificial fault. The newly generated fluid pathway resulted in an activation of the complete block through a stick–slip movement. We compare acoustic emission measurements from the laboratory experiment with seismicity observations from the field-scale CO 2 injection at Decatur, Illinois, U.S., and conclude that the existence of fluid pathways plays a decisive role for the potential of induced seismicity.

47 OTHER INSTRUMENTATION↗
DOE OSTI2015

Atomization and dense-fluid breakup regimes in liquid rocket engines

Until recently, modern theory has lacked a fundamentally based model to predict the operating pressures where classical sprays transition to dense-fluid mixing with diminished surface tension. In this paper, such a model is presented to quantify this transition for liquid-oxygen–hydrogen and n-decane–gaseous-oxygen injection processes. The analysis reveals that respective molecular interfaces break down not necessarily because of vanishing surface tension forces but instead because of the combination of broadened interfaces and a reduction in mean free molecular path. When this occurs, the interfacial structure itself enters the continuum regime, where transport processes rather than intermolecular forces dominate. Using this model, regime diagrams for the respective systems are constructed that show the range of operating pressures and temperatures where this transition occurs. The analysis also reveals the conditions where classical spray dynamics persists even at high supercritical pressures. As a result, it demonstrates that, depending on the composition and temperature of the injected fluids, the injection process can exhibit either classical spray atomization, dense-fluid diffusion-dominated mixing, or supercritical mixing phenomena at chamber pressures encountered in state-of-the-art liquid rocket engines.

33 ADVANCED PROPULSION SYSTEMS↗
DOE OSTI2021

On the feasibility of using physics-informed machine learning for underground reservoir pressure management

In this work, we evaluate the feasibility of using physics-informed machine learning (PIML) for underground energy-related pressure management. To this end, we develop a PIML framework to manage underground reservoir pressures by training neural networks to determine fluid extraction rates for dedicated extraction wells during fluid injection operations given a range of reservoir conditions (e.g., transmissivity and storativity). We implement an automatically-differentiable analytical physics model of fluid flow in porous media within the PIML framework as a proxy for more complicated models. This allows us to execute a sufficient number of training scenarios to fully evaluate the feasibility of using PIML to support pressure management activities. We quantify the number of physics-model parameters required for automatic differentiation to become more efficient than finite-difference gradient calculations. We use a simple scenario with a single injector, extractor, and critical location for our feasibility analysis. We evaluate the effect of the size of the training dataset (i.e., the number of reservoir condition samples) on the accuracy and efficiency of the PIML framework. For an equivalent number of model evaluations, the larger training dataset took less time to train and produced a neural network that was able to more accurately manage reservoir pressures. We also evaluate the effect of the training dataset batch size (i.e., number of reservoir condition samples used to update the neural network coefficients during training; i.e., how the training dataset is partitioned). While training ran faster with larger batch sizes, they produced neural networks that managed pressures less accurately. We demonstrate the approach on a more complex scenario involving 10 injectors, 10 extractors, and 4 critical locations (a relatively high well density of 20 wells/km2). We provide the number of forward and adjoint model evaluations required in each case as an indication of the feasibility of using PIML for pressure management when more complicated physics models with longer execution times are used.

54 ENVIRONMENTAL SCIENCES↗
DOE OSTI2025

Fracture Network Quantification for Enhanced Reservoir Characterization in CO2 Storage Sites

Presentation slides on “Fracture Network Quantification for Enhanced Reservoir Characterization in CO2 Storage Sites” for the CCUS 2025 conference held in Houston, Texas March 3-5, 2025. Accurate reservoir characterization is fundamental for the safe and efficient operation of carbon capture, utilization, and storage (CCUS) projects. This process is not only critical during initial site selection but also plays a key role in continuously updating reservoir geomodels throughout injection operations to effectively manage subsurface storage sites. Our primary objective is to develop a comprehensive understanding of fracture networks within CO2 injection reservoirs, which are critical for predicting the behavior of injected fluids, ensuring storage integrity post-injection, and mitigating risks such as leakage or induced seismicity.

artifical intelligence / machine learning (AI/ML)↗
DOE OSTI2019

MINERALOGICAL AND TEXTURAL CONTROLS ON SHEAR STRENGTH, SLIP STABILITY AND PERMEABILITY OF FAULTS

Induced seismicity resulting from fluid injection into the subsurface related to water and CO2 disposal, hydraulic fracturing and the stimulation of geothermal reservoirs present an important societal concern. These human activities involve the injection of large volumes of pressurized fluid into the subsurface, potentially at high rates, raising local pore pressures and disturbing the pristine local stress regime by lowering effective normal stress on pre-existing faults and fractures. The reduction of effective normal stress may trigger fault/fracture reactivation and in some cases result in hazardous seismic ruptures. Effective management and engineering of anthropogenic seismic events requires substantial understanding in the mechanisms, especially for the controlling factors on coupled rheological and transport response, including fault shear strength, slip stability, and permeability evolution during such events. In this study, we explore the coupled rheological and transport response of faults and fractures during reactivation as controlled by two fundamental controlling properties, viz., mineralogy and textural features. We approach this problem through shear experiments on analog faults and fractures via laboratory and numerical experiments. Specifically, we investigate: (1) the influence of frictionally weak minerals (talc) in mixtures of mineral analogs featuring contrasting frictional properties, (2) the influence of iron oxide grain coatings on quartz aggregates, and (3) the influence of fracture roughness in mated fractures on the ensemble shear strength, slip stability, and permeability evolution during reactivation events. We address the following questions in this study: (1) how much and what distribution of frictionally weak minerals is required to induce significant weakening in faults consisting of a matrix of frictionally strong minerals, (2) how does a pre-imposed weak mineral layer influence the rheological and transport behavior of faults, (3) what is the influence of a trace amount of grain coating materials introduce on the coupled behavior of faults, and finally (4) how do asperity height and wave length control the ensemble behavior of faults. These questions are explicitly answered in the following.

58 GEOSCIENCES↗
DOE OSTI2017

Pressure Monitoring to Detect Fault Rupture Due to CO 2 Injection

The capacity for fault systems to be reactivated by fluid injection is well-known. In the context of CO 2 sequestration, however, the consequence of reactivated faults with respect to leakage and monitoring is poorly understood. Using multi-phase fluid flow simulations, this study addresses key questions concerning the likelihood of ruptures, the timing of consequent upward leakage of CO 2 , and the effectiveness of pressure monitoring in the reservoir and overlying zones for rupture detection. A range of injection scenarios was simulated using random sampling of uncertain parameters. These include the assumed distance between the injector and the vulnerable fault zone, the critical overpressure required for the fault to rupture, reservoir permeability, and the CO 2 injection rate. We assumed a conservative scenario, in which if at any time during the five-year simulations the critical fault overpressure is exceeded, the fault permeability is assumed to instantaneously increase. For the purposes of conservatism we assume that CO 2 injection continues ‘blindly’ after fault rupture. We show that, despite this assumption, in most cases the CO 2 plume does not reach the base of the ruptured fault after 5 years. As a result, one possible implication of this result is that leak mitigation strategies such as pressure management have a reasonable chance of preventing a CO 2 leak.

58 GEOSCIENCES↗
DOE OSTI2021

Constraining maximum event magnitude during injection-triggered seismicity

Abstract Understanding mechanisms controlling fluid injection-triggered seismicity is key in defining strategies to ameliorate it. Recent triggered events (e.g. Pohang, Mw 5.5) have exceeded predictions of average energy release by a factor of >1000x, necessitating robust methodologies to both define critical antecedent conditions and to thereby constrain anticipated event size. We define maximum event magnitudes resulting from triggering as a function of pre-existing critical stresses and fluid injection volume. Fluid injection experiments on prestressed laboratory faults confirm these estimates of triggered moment magnitudes for varied boundary conditions and injection rates. In addition, observed ratios of shear slip to dilation rates on individual faults signal triggering and may serve as a measurable proxy for impending rupture. This new framework provides a robust method of constraining maximum event size for preloaded faults and unifies prior laboratory and field observations that span sixteen decades in injection volume and four decades in length scale.

58 GEOSCIENCES↗
DOE OSTI2020

Alternative, Less Water-Intensive, Fracturing Fluids for Enhanced Geothermal Systems

Four fracturing fluids; water, CO2, CO2 with water, and CO2 with an aqueous solution of a CO2-reactive polymer, poly(allylamine) (PAA, 1wt%) were evaluated using a high-temperature true-triaxial fracturing apparatus and ½ foot side granite cubic samples. All three CO2-based fracturing fluids, CO2, CO2 with water, and CO2 with aqueous PAA fractured granite at higher breakdown pressures, high transient flow rates, and produce higher-conductivity fractures as compared to water. Additionally, faster pressurization rates with CO2-based fracturing fluids (obtained when fracturing at constant flow rate mode) are found to be associated with higher fracture conductivities. When partially saturating the rock sample with PAA solution followed by fracturing with CO2, the volume expansion caused by CO2-induced cross-linking of PAA leads to a faster pressure increase due to the associated stress generated and increase in viscosity. It was also found that CO2 as a fracturing fluid injected in hot dry rock (HDR) attain the highest fracture conductivity only when injected at very high flow rates, followed very closely by the CO2/PAA fracturing fluid system that generates fractures with, on average, similarly high conductivity values though independently of injection flow rate and using 1/6 of the mass of CO2 as compared to CO2 in HDR. Breakdown pressures were also similar for CO2 stimulation in HDR and CO2/PAA fluid system under identical injection flow rates. It is concluded that CO2 (when injected in HDR) and CO2/PAA are the fluids of choice for stimulation of granitic rock samples under the studied geothermal P/T conditions. CO2/PAA, however, offer the following three additional advantages; 1) it requires significantly lower volumes of CO2, 2) fracture permeability is independent of injection flow rate, and 3) the reversible (previously reported) viscosity increase is beneficial to transport proppants if they are ever developed enhanced geothermal systems.

Jian, Guoqing↗
DOE OSTI2018

SECARB Geochemical Data

Hydrotest, gas composition, injection fluid, mass spectrometer, and U-tube gas sample analysis data gathered during SECARB project at Cranfield oil site in Mississippi. Geochemical data collected as part of geologic characterization phase of SECARB. Associated Publications: Lu, J., Cook, P. J., Hosseini, S. A., Yang, C., Romanak, K. D., Zhang, T., Freifeld, B. M., Smyth, R. C., Zeng, H., and Hovorka, S. D., 2012, Complex fluid flow revealed by monitoring CO 2 injection in a fluvial formation: Journal of Geophysical Research, v. 117, B03208, doi:10.1029/2011JB008939. Lu, J., Kharaka, Y. K., Thordsen, J. J., Horita, J., Karamalidis, A., Griffith, C., Hakala, J. A., Ambats, G., Cole, D. R., Phelps, T. J., Manning, M. A., Cook, P. J., and Hovorka, S. D., 2012, CO 2 -rock-brine interactions in Lower Tuscaloosa Formation at Cranfield CO2 sequestration site, Mississippi, U.S.A.: Chemical Geology, v. 291, p. 269-277. Yang, C., Hovorka, S. D., Treviño, R. H., and Delgado-Alonso, J., 2015, Integrated framework for assessing impacts of CO 2 leakage on groundwater quality and monitoring-network efficiency: case study at a CO 2 enhanced oil recovery site: Environmental Science &Technology, v. 49, p. 8887–8898, doi:10.1021/acs.est.5b01574.

carbon capture and storage↗
DOE OSTI2023

High Fidelity Modeling of WELL58-32 DFITS

Between 2017 and 2019, a series of injection tests were performed at pilot vertical well 58-32 at the Utah FORGE site. These injection activities were conducted in three distinct zones, isolated with packers and bridge plugs during the tests. Zone 1 consists of an open-hole section at the toe of the well, whereas Zones 2 and 3 are three-meter long cased and perforated sections. Several injection cycles were conducted in each zone. A detailed description of the geology of the FORGE site, of well 58-32 and of all injection cycles can be found in (Xing et al., 2020). The injection cycles included Diagnostic Fracture Injection Tests (DFITs). DFITs comprise two primary stages: an injection (pump-in) phase, where controlled fluid injection is employed to create a small hydraulic fracture in the surrounding rock, followed by a shut-in phase, where injection ceases, allowing observation of the formation’s pressure response. Utilizing methodologies such as the G-function analysis, DFITs provide valuable insights, including fracture closure pressure and the Instantaneous Shut-in Pressure (ISIP) and can be employed to estimate the minimum horizontal stress.

42 ENGINEERING↗
DOE OSTI2012

Pore accessibility by methane and carbon dioxide in coal as determined by neutron scattering

Contrast-matching ultrasmall-angle neutron scattering (USANS) and small-angle neutron scattering (SANS) techniques were used for the first time to determine both the total pore volume and the fraction of the pore volume that is inaccessible to deuterated methane, CD{sub 4}, in four bituminous coals in the range of pore sizes between {approx}10 {angstrom} and {approx}5 {micro}m. Two samples originated from the Illinois Basin in the U.S.A., and the other two samples were commercial Australian bituminous coals from the Bowen Basin. The total and inaccessible porosity were determined in each coal using both Porod invariant and the polydisperse spherical particle (PDSP) model analysis of the scattering data acquired from coals both in vacuum and at the pressure of CD{sub 4}, at which the scattering length density of the pore-saturating fluid is equal to that of the solid coal matrix (zero average contrast pressure). The total porosity of the coals studied ranged from 7 to 13%, and the volume of pores inaccessible to CD{sub 4} varied from {approx}13 to {approx}36% of the total pore volume. The volume fraction of inaccessible pores shows no correlation with the maceral composition; however, it increases with a decreasing total pore volume. In situ measurements of the structure of one coal saturated with CO{sub 2} and CD{sub 4} were conducted as a function of the pressure in the range of 1-400 bar. The neutron scattering intensity from small pores with radii less than 35 {angstrom} in this coal increased sharply immediately after the fluid injection for both gases, which demonstrates strong condensation and densification of the invading subcritical CO{sub 2} and supercritical methane in small pores.

01 COAL, LIGNITE, AND PEAT↗