Academic literature on the topic 'Subsurface permeability'
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Journal articles on the topic "Subsurface permeability"
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Lu, Ning, Edward M. Kwicklis, and Joe P. Rousseau. "Determining Fault Permeability from Subsurface Barometric Pressure." Journal of Geotechnical and Geoenvironmental Engineering 127, no. 9 (September 2001): 801–8. http://dx.doi.org/10.1061/(asce)1090-0241(2001)127:9(801).
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Gardner, W. Payton, Stephen J. Bauer, and Scott Broome. "Investigating Fracture Network Deformation Using Noble Gas Release." Geofluids 2021 (May 19, 2021): 1–16. http://dx.doi.org/10.1155/2021/6697819.
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We investigate deformation mechanics of fracture networks in unsaturated fractured rocks from subsurface conventional detonation using dynamic noble gas measurements and changes in air permeability. We dynamically measured the noble gas isotopic composition and helium exhalation of downhole gas before and after a large subsurface conventional detonation. These noble gas measurements were combined with measurements of the subsurface permeability field from 64 discrete sampling intervals before and after the detonation and subsurface mapping of fractures in borehole walls before well completion. We saw no observable increase in radiogenic noble gas release from either an isotopic composition or a helium exhalation point of view. Large increases in permeability were observed in 13 of 64 discrete sampling intervals. Of the sampling intervals which saw large increases in flow, only two locations did not have preexisting fractures mapped at the site. Given the lack of noble gas release and a clear increase in permeability, we infer that most of the strain accommodation of the fractured media occurred along previously existing fractures, rather than the creation of new fractures, even for a high strain rate event. These results have significant implications for how we conceptualize the deformation of rocks with fracture networks above the percolation threshold, with application to a variety of geologic and geological engineering problems.
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Karlstrom, L., A. Zok, and M. Manga. "Near-surface permeability in a supraglacial drainage basin on the Llewellyn Glacier, Juneau Icefield, British Columbia." Cryosphere 8, no. 2 (March 27, 2014): 537–46. http://dx.doi.org/10.5194/tc-8-537-2014.
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Abstract. Supraglacial channel networks link time varying melt production and meltwater routing on temperate glaciers. Such channel networks often include components of both surface transport in streams and subsurface porous flow through near-surface ice, firn or snowpack. Although subsurface transport if present will likely control network transport efficacy, it is the most poorly characterized component of the system. We present measurements of supraglacial channel spacing and network properties on the Juneau Icefield, subsurface water table height, and time variation of hydraulic characteristics including diurnal variability in water temperature. We combine these data with modeling of porous flow in weathered ice to infer near-surface permeability. Estimates are based on an observed phase lag between diurnal water temperature variations and discharge, and independently on measurement of water table surface elevation away from a stream. Both methods predict ice permeability on a 1–10 m scale in the range of 10−10–10−11 m2. These estimates are considerably smaller than common parameterizations of surface water flow on bare ice in the literature, as well as smaller than most estimates of snowpack permeability. For supraglacial environments in which porosity/permeability creation in the subsurface is balanced by porous flow of meltwater, our methods provide an estimate of microscale hydraulic properties from observations of supraglacial channel spacing.
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Miller, Matthew J., Kartic Khilar, and H. Scott Fogler. "Aging of Foamed Gel Used for Subsurface Permeability Reduction." Journal of Colloid and Interface Science 175, no. 1 (October 1995): 88–96. http://dx.doi.org/10.1006/jcis.1995.1433.
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Wang, Chenyu, Yan Dong, Jingyu Gao, Handong Tan, Yingge Wang, and Weiyu Dong. "Three-Dimensional Forward Modeling and Inversion Study of Transient Electromagnetic Method Considering Inhomogeneous Magnetic Permeability." Applied Sciences 14, no. 24 (December 13, 2024): 11660. https://doi.org/10.3390/app142411660.
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Traditional studies on Transient Electromagnetic Method (TEM) typically assume that the subsurface medium is non-magnetic. However, in regions with igneous rock accumulations or where the subsurface is rich in ferromagnetic minerals, neglecting the magnetic properties of the underground medium may lead to erroneous interpretations for TEM data. This paper conducts a 3-D TEM forward modeling and inversion study considering the non-uniformity cases of magnetic permeability. 3-D TEM forward modeling employs an edge-based finite element method using unstructured grids and a second-order implicit backward Euler method, achieving a modeling algorithm that simultaneously considers non-uniform models of magnetic permeability and resis-tivity. The accuracy of the modeling algorithm is verified by comparing it with the analytical solution of a homogeneous half-space model and the solution of a 1-D TEM forward modeling algorithm. 3-D TEM inversion employs the L-BFGS algorithm and synthetic examples considering non-uniform magnetic permeability are presented. The inversion results show good recovery for the resistivity and magnetic permeability models. Comparisons with the inversion results that neglect the non-uniformity of magnetic permeability validate the importance of considering the variation of permeability in 3-D TEM forward modeling and inversion.
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Karlstrom, L., A. Zok, and M. Manga. "Near-surface permeability in a supraglacial drainage basin on the Llewellyn glacier, Juneau Ice Field, British Columbia." Cryosphere Discussions 7, no. 6 (November 4, 2013): 5281–306. http://dx.doi.org/10.5194/tcd-7-5281-2013.
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Abstract. Supraglacial channel networks link time varying solar forcing and melt water routing on temperate glaciers. We present measurements of supraglacial channel spacing and network properties on the Juneau Icefield, subsurface water table height, and time variation of hydraulic characteristics including diurnal variability in water temperature. We combine these data with modeling of porous flow in weathered ice to infer near-surface permeability. Estimates are based on an observed phase lag between diurnal water temperature variations and discharge, and independently on measurement of water table surface elevation away from a stream. Both methods predict ice permeability on a 1–10 m scale in the range of 10–10–10–11 m2. These estimates are considerably smaller than common parameterizations of surface water flow on bare ice in the literature, as well as smaller than estimates of snowpack permeability. For supraglacial environments in which porosity/permeability creation in the subsurface is balanced by porous flow of melt water, our methods provide an estimate of microscale hydraulic properties from macroscale, remote observations of supraglacial channel spacing.
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Karczmarczyk, Agnieszka. "PHOSPHORUS REMOVAL FROM DOMESTIC WASTEWATER IN HORIZONTAL SUBSURFACE FLOW CONSTRUCTED WETLAND AFTER 8 YEARS OF OPERATION – A CASE STUDY." JOURNAL OF ENVIRONMENTAL ENGINEERING AND LANDSCAPE MANAGEMENT 12, no. 4 (December 31, 2004): 126–31. http://dx.doi.org/10.3846/16486897.2004.9636833.
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Horizontal subsurface flow constructed wetlands can effectively treat high levels of biochemical oxygen demand (BOD) and suspended solids. They are also effective as phosphorus trap but usually for a short time. This phenomenon was observed in the presented case study, an example of subsurface flow reed bed filled with “improved” site soil where it was assumed that the permeability of bed would increase as a result of reed penetration. Fine grained site soil was initially effective trap for phosphorus from wastewater. However, during operation clogging of bed media proceeded and phosphorus sorption capacity used up. In general, the longevity of subsurface flow wetlands as phosphorus sinks depends on the hydraulic load, phosphorus load and the type of the media used in bed construction. To be effective as phosphorus sorbent, substrate should contain high levels of Ca, Al and Fe oxides and possess suitable sorption capacity, quick time of reaction and suitable permeability.
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Shokrollahi, Amin, Syeda Sara Mobasher, Kofi Ohemeng Kyei Prempeh, Parker William George, Abbas Zeinijahromi, Rouhi Farajzadeh, Nazliah Nazma Zulkifli, Mohammad Iqbal Mahammad Amir, and Pavel Bedrikovetsky. "CO2 Storage in Subsurface Formations: Impact of Formation Damage." Energies 17, no. 17 (August 23, 2024): 4214. http://dx.doi.org/10.3390/en17174214.
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The success of CO2 storage projects largely depends on addressing formation damage, such as salt precipitation, hydrate formation, and fines migration. While analytical models for reservoir behaviour during CO2 storage in aquifers and depleted gas fields are widely available, models addressing formation damage and injectivity decline are scarce. This work aims to develop an analytical model for CO2 injection in a layer-cake reservoir, considering permeability damage. We extend Dietz’s model for gravity-dominant flows by incorporating an abrupt permeability decrease upon the gas-water interface arrival in each layer. The exact Buckley-Leverett solution of the averaged quasi-2D (x, z) problem provides explicit formulae for sweep efficiency, well impedance, and skin factor of the injection well. Our findings reveal that despite the induced permeability decline and subsequent well impedance increase, reservoir sweep efficiency improves, enhancing storage capacity by involving a larger rock volume in CO2 sequestration. The formation damage factor d, representing the ratio between damaged and initial permeabilities, varies from 0.016 in highly damaged rock to 1 in undamaged rock, resulting in a sweep efficiency enhancement from 1–3% to 50–53%. The developed analytical model was applied to predict CO2 injection into a depleted gas field.
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Eggertsson, Guðjón H., Jackie E. Kendrick, Joshua Weaver, Paul A. Wallace, James E. P. Utley, John D. Bedford, Michael J. Allen, et al. "Compaction of Hyaloclastite from the Active Geothermal System at Krafla Volcano, Iceland." Geofluids 2020 (July 11, 2020): 1–17. http://dx.doi.org/10.1155/2020/3878503.
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Hyaloclastites commonly form high-quality reservoir rocks in volcanic geothermal provinces. Here, we investigated the effects of confinement due to burial following prolonged accumulation of eruptive products on the physical and mechanical evolution of surficial and subsurface (depths of 70 m, 556 m, and 732 m) hyaloclastites from Krafla volcano, Iceland. Upon loading in a hydrostatic cell, the porosity and permeability of the surficial hyaloclastite decreased linearly with mean effective stress, as pores and cracks closed due to elastic (recoverable) compaction up to 22-24 MPa (equivalent to ~1.3 km depth in the reservoir). Beyond this mean effective stress, denoted as P∗, we observed accelerated porosity and permeability reduction with increasing confinement, as the rock underwent permanent inelastic compaction. In comparison, the porosity and permeability of the subsurface core samples were less sensitive to mean effective stress, decreasing linearly with increasing confinement as the samples compacted elastically within the conditions tested (to 40 MPa). Although the surficial material underwent permanent, destructive compaction, it maintained higher porosity and permeability than the subsurface hyaloclastites throughout the experiments. We constrained the evolution of yield curves of the hyaloclastites, subjected to different effective mean stresses in a triaxial press. Surficial hyaloclastites underwent a brittle-ductile transition at an effective mean stress of ~10.5 MPa, and peak strength (differential stress) reached 13 MPa. When loaded to effective mean stresses of 33 and 40 MPa, the rocks compacted, producing new yield curves with a brittle-ductile transition at ~12.5 and ~19 MPa, respectively, but showed limited strength increase. In comparison, the subsurface samples were found to be much stronger, displaying higher strengths and brittle-ductile transitions at higher effective mean stresses (i.e., 37.5 MPa for 70 m sample, >75 MPa for 556 m, and 68.5 MPa for 732 m) that correspond to their lower porosities and permeabilities. Thus, we conclude that compaction upon burial alone is insufficient to explain the physical and mechanical properties of the subsurface hyaloclastites present in the reservoir at Krafla volcano. Mineralogical alteration, quantified using SEM-EDS, is invoked to explain the further reduction of porosity and increase in strength of the hyaloclastite in the active geothermal system at Krafla.
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Izadi, Mohammad, and Ali Ghalambor. "A New Approach in Permeability and Hydraulic-Flow-Unit Determination." SPE Reservoir Evaluation & Engineering 16, no. 03 (July 4, 2013): 257–64. http://dx.doi.org/10.2118/151576-pa.
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Summary Building an integrated subsurface model is one of the main goals of major oil and gas operators to guide the field-development plans. All field-data acquisitions from seismic, well logging, production, and geomechanical monitoring to enhanced-oil-recovery (EOR) operations can be affected by the accurate details incorporated in the subsurface model. Therefore, building a realistic integrated subsurface model of the field and associated operations is essential for a successful implementation of such projects. Furthermore, using a more reliable model can, in turn, provide the basis in the decision-making process for control and remediation of formation damage. One of the key identifiers of the subsurface model is accurately predicting the hydraulic-flow units (HFUs). There are several models currently used in the prediction of these units on the basis of the type of data available. The predictions that used these models differ significantly because of the assumptions made in the derivations. Most of these assumptions do not adequately reflect realistic subsurface conditions, thus increasing the need for better models. A new approach has been developed in this study for predicting the petrophysical properties and improving the reservoir characterization. The Poiseuille flow equation and Darcy equation were coupled, taking into consideration the irreducible water saturation in the pore network. The porous medium was introduced as a domain containing a bundle of tortuous capillary tubes with irreducible water lining the pore wall. A series of routine and special core analysis was performed on 17 Berea sandstone samples, and the petrophysical properties were measured and X-ray diffraction (XRD) analysis was conducted. In building the petrophysical model, it was initially necessary to assume an ideal reservoir with 17 different layers, each layer representing one Berea sample. Afterward, by the iteration and calibration of the laboratory data, the number of HFUs was determined by use of the common HFU model and the proposed model accordingly. A comparative study shows that the new model provides a better distribution of HFUs and prediction of the petrophysical properties. The new model provides a better match with the experimental data collected than the models currently used in the prediction of such parameters. The good agreement observed for the Berea sandstone experimental data and the model predictions by use of the new permeability model shows a wider range of applicability for various reservoir conditions. In addition, the model has been applied to a series of core-analysis data on low-permeability Medina sandstone, Appalachian basin, northwest Pennsylvania. The flow-unit distribution by use of the proposed model shows a better flow-zone distinction, and the permeability/ porosity relationship has a higher confidence coefficient.
Dissertations / Theses on the topic "Subsurface permeability"
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Silliman, Stephen Edward Joseph 1957. "Stochastic analysis of high-permeability paths in the subsurface." Diss., The University of Arizona, 1986. http://hdl.handle.net/10150/191120.
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Subsurface fluids may travel along paths having a minimum permeabilility greater than the effective permeability of the rock. This may have an important impact on contaminant migration. A stochastic approach related to percolation theory is advanced to address the question of what is the probability that a high permeability path extends across a given volume of the subsurface. The answer is sought numerically through subdividing the volume of interest into a three-dimensional grid of elements and assigning a random permeability to each element. Four permeability processes are considered: 1) Stationary with independence between grid elements; 2) Stationary and autocorrelated; 3) Nonstationary due to conditioning on measured values; and 4) Random rock volume included in grid. The results utilizing data from fractured granites suggest that in large grids, at least one path having a minimum permeability in excess of the "effective" rock permeability will cross the grid. Inclusion of autocorrelation causes an increase in the expected value of the minimum permeability of such a path. It also results in a significantly increased variance of this permeability. Conditioning on field permeabilities reduces the variance of this value over that obtained by unconditional, correlated simulation, but still produces a variance greater than that obtained when independence was assumed. When conditioning is performed, the mean of the minimum permeabilities along these paths is dependent on the principal axis of the path. Finally, including a random rock volume by allowing the length of the grid to be random increases the variance of the minimum permeability.
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Tangpithakkul, Rawee. "Study of permeability of pavement base materials." Ohio University / OhioLINK, 1997. http://rave.ohiolink.edu/etdc/view?acc_num=ohiou1184344573.
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Burns, Susan Elizabeth. "Development, adaptation, and interpretation of cone penetrometer sensors for geoenvironmental subsurface characterization." Diss., Georgia Institute of Technology, 1997. http://hdl.handle.net/1853/23358.
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Kinoshita, Chihiro. "Changes in Subsurface Hydrological Systems Produced by Earthquakes: Observations from Borehole Monitoring." Kyoto University, 2018. http://hdl.handle.net/2433/232257.
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Eymold, William Karl. "The Evaluation of Subsurface Fluid Migration using Noble Gas Tracers and Numerical Modeling." The Ohio State University, 2020. http://rave.ohiolink.edu/etdc/view?acc_num=osu1591894015888803.
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Mohammed, Ibrahim Ali. "Permeability variation due to clogging in a simulated landfill drainage layer." Ohio : Ohio University, 1994. http://www.ohiolink.edu/etd/view.cgi?ohiou1178136048.
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Gisquet, Franck. "Les drains dolomitiques super-K : géométries, hétérogénéités-réservoirs, origines : La Formation Khuff en subsurface (Permo-Trias, Qatar-Iran) et un analogue à l'affleurement (Jurassique supérieur, Provence - France)." Thesis, Aix-Marseille, 2012. http://www.theses.fr/2012AIXM4760.
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La partie supérieure de la Formation Khuff est un réservoir représentant le plus grand champ gazier mondial, d'âge Permien supérieur à Trias inférieur. Il est formé de la succession de calcaires, de dolomies et de sulfates. Sa production est principalement contrôlée par des intervalles d'épaisseur généralement inférieure à 10 m, totalement dolomitisés, appelés super-drains ou super-K, connectés sur plusieurs dizaines de kilomètres.Les objectifs de l'étude sont (1) de définir la mise en place et l'extension des super-drains dans un cadre stratigraphique, (2) de comprendre la diagenèse contrôlant leurs propriétés réservoirs et (3) de comparer la mise en place des corps dolomitiques stratiformes précoces ou tardifs liés aux failles à ceux d'un analogue à l'affleurement, à savoir les formations calcaréo-dolomitiques d'âge Jurassique supérieur en Provence.Pour les atteindre, des analyses sédimento-diagénétiques (sédimentologiques, pétrographiques et géochimiques) ont été entreprises sur les deux objets d'études du réservoir de subsurface et de l'analogue réservoir d'affleurement. Pour ce dernier, une modélisation en 3D de corps diagénétiques liés aux failles a été réalisée. Les principaux résultats sont que :- les localisations des super-drains ont été contrôlées par la dynamique sédimentaire de séquences à basse fréquences (SBF) et à haute fréquence (SHF) ;- des super-drains sont localisés au sommet des SBF sous les discontinuités d'émersions et à la limite des fronts de dolomitisation de reflux différéThe upper part of the Khuff Formation includes the biggest gas reserves in the world, from Upper Permian to Lower Triassic age. It is composed by the succession of limestone, dolomite and sulfate. The gas production is mainly driven by layers typically thinner than 10 m, fully dolomitised, and called super-drains or super-K and connected over several dozen kilometers.The goals of this study are (1) to define the formation and the extension of super-K layers in a stratigraphic framework, (2) to understand the diagenesis controlling their reservoir properties and (3) to compare the creation of early stratabound and late fault-related dolomite bodies with an outcrop analogue, from the limestone and dolomite formations from Provence from Upper Jurassic age.To reach this goal, sedimento-diagenetic analyses (sedimentological, petrographical and geochemical) have been carried out on studied objects, the subsurface reservoir and the outcrop analogue reservoir. For the latter, 3D modelling of fault-related dolomite bodies have been realised. The main results are:- the locations of super-K have been controlled by the sedimentary dynamics of low frequency sequences (SBF) and high frequency sequences (SHF) ;- some super-K are located at the top of SBF under emersion unconformities and at the rim of dolomitisation fronts associated to postponed reflux. The reflux was made of brines, coming from synsedimentary dolomite bodies associated with marine transgressions that followed the emersions. This model is corroborated by an outcrop analogue, which is a dolomite reservoir underlying a long lasting emersion unconformity
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Zech, Alraune [Verfasser], Sabine [Akademischer Betreuer] Attinger, and Olaf [Akademischer Betreuer] Kolditz. "Impact of Aqifer Heterogeneity on Subsurface Flow and Salt Transport at Different Scales : from a method determine parameters of heterogeneous permeability at local scale to a large-scale model for the sedimentary basin of Thuringia / Alraune Zech. Gutachter: Sabine Attinger ; Olaf Kolditz." Jena : Thüringer Universitäts- und Landesbibliothek Jena, 2014. http://d-nb.info/1048047229/34.
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Klein, Amelie. "Étude multi-paramètrique de l'évolution des systèmes hydrothermaux : apports à la compréhension des systèmes volcaniques en cours de réactivation." Electronic Thesis or Diss., Université Clermont Auvergne (2021-...), 2024. http://theses.bu.uca.fr/nondiff/2024UCFA0125_KLEIN.pdf.
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L'activité hydrothermale volcanique présente des risques permanents liés à l'émission de gaz toxiques provenant à la fois du sol et des fumerolles. Cependant, des risques plus difficilement prévisibles peuvent également survenir tels que les explosions phréatiques ou l'effondrement des flancs. La présence d'un système hydrothermal a des implications importantes pour l'interprétation des signaux provenant du système magmatique. Par conséquent, la distribution spatiale et l'évolution temporelle des signaux géophysiques et géochimiques sur les volcans hydrothermaux donnent des informations cruciales pour la détection des précurseurs de l'activité éruptive.La Soufrière de Guadeloupe est actuellement dans une phase de réactivation qui a débuté en 1992 et dont l'intensité a augmenté en 2018. Afin de mieux comprendre le système hydrothermal de La Soufrière, nous avons effectué plusieurs cartographies du dégazage diffus du CO2 de la température et du Potentiel Spontané (PS) au niveau du dôme entre 2021 et 2024. Ce travail représente la première cartographie du PS depuis plus d'une décennie et la première quantification du dégazage de CO2 sur le sommet. Il fournit une image actualisée de la distribution de la circulation des fluides souterrains et les flux de chaleur et de CO2 associés. Nous proposons également une méthodologie numérique basée sur un modèle physique et des images thermiques des panaches de fumerolles permettant d'améliorer la quantification des flux des principales fumerolles de La Soufrière.En comparant nos mesures entre elles et à celles des études antérieures, nous constatons que la circulation des fluides hydrothermaux dans le secteur nord-est du sommet a augmenté de manière significative au cours de ces dernières années. Les profondeurs de condensation des fluides hydrothermaux ascendants suggèrent que ce développement peut être dû à un changement de la distribution de la perméabilité souterraine liée aux déformations du dôme. En parallèle, nous avons étudié la dynamique des flux hydrothermaux à l'aide d'une série temporelle du PS sur deux ans. Cette analyse montre des variations diurnes et semi-diurnes liées aux marées atmosphériques. Enfin, nous analysons la réponse du système hydrothermal aux précipitations, à la sismicité et à la température des fumerolles. Les résultats obtenus montrent que le secteur nord-est du sommet est fortement interconnecté et met en évidence le contrôle de la dynamique du système hydrothermal par les principales fractures du sommet.Cette thèse propose une image de la distribution actuelle et de l'évolution spatiotemporelle de la circulation des fluides hydrothermaux à La Soufrière de Guadeloupe. Nos résultats ont permis d'identifier les zones pour la surveillance future. De plus, les jeux de données acquises permettront de mieux contraindre les modèles issus d'autres méthodes géophysiques afin de déterminer l'état interne du dôme et d'évaluer les risques potentiels liés au dégazage passif, à l'altération ou à la pressurisation des fluidesVolcanic hydrothermal activity poses unpredictable hazards like phreatic explosions or flank collapse, as well as pervasive hazards such as the emission of hot, toxic gases from steaming ground and fumaroles. The presence of a hydrothermal system has important implications for interpreting signals from the magmatic system. Therefore, the spatial distribution and temporal evolution of geophysical and geochemical signals at volcanoes with long-lived hydrothermal systems provide crucial information for detecting precursors of eruptive activity.La Soufrière de Guadeloupe volcano is currently undergoing a phase of unrest, which started in 1992 and saw an increase in intensity in 2018. To advance the understanding of the shallow hydrothermal system at La Soufrière, we repeatedly mapped diffuse CO2 degassing, ground temperature and self-potential across the dome summit from 2021 to 2024. This work represents the first mapping of self-potential in over a decade and the first quantification of CO2 degassing over the entire summit. It provides an up-to-date picture of the distribution of subsurface fluid circulation and the associated ground heat and CO2 fluxes. We also outline a numerical approach to improve the quantification of the fumarole fluxes based on a physical plume model and thermal images of the fumarole plumes and use this to calculate heat and mass fluxes from La Soufrière's major fumaroles.Our multi-parameter mappings, repeated self-potential profiles, and comparisonswith previous studies show that hydrothermal fluid circulation in the northeastern summit sector has significantly increased over the last decade. Estimated condensation depths of ascending hydrothermal fluids suggest that this development may be due to a change in the distribution of subsurface permeability, which is likely related to the dome displacement field. The short-term dynamics of hydrothermal fluid circulation are investigated using a two-year self-potential time series. We observe diurnal and semidiurnal variations linked to atmospheric tides. Finally, we analyse the response of the shallow hydrothermal system to precipitation, seismicity and fumarole temperature.This shows that the northeastern summit sector is highly interconnected and highlights the strong structural control of the hydrothermal system dynamics by the main summit fractures.This work provides a picture of the current distribution and spatiotemporal evolution of shallow hydrothermal fluid circulation at La Soufrière de Guadeloupe. This helps us to identify the preferred zones for future monitoring. The datasets generated will help to constrain models from other geophysical methods to infer the internal state of the dome and assess potential hazards related to passive degassing, alteration or fluid pressurisation
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Silliman, Stephen Edward Joseph. "Stochastic analysis of high-permeability paths in the subsurface." 1986. http://etd.library.arizona.edu/etd/GetFileServlet?file=file:///data1/pdf/etd/azu_e9791_1986_615_sip1_w.pdf&type=application/pdf.
Full textBooks on the topic "Subsurface permeability"
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Doveton, John H. Principles of Mathematical Petrophysics. Oxford University Press, 2014. http://dx.doi.org/10.1093/oso/9780199978045.001.0001.
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The pioneering work of Gus Archie moved log interpretation into log analysis with the introduction of the equation that bears his name. Subsequent developments have mixed empiricism, physics, mathematical algorithms, and geological or engineering models as methods applied to petrophysical measurements in boreholes all over the world. Principles of Mathematical Petrophysics reviews the application of mathematics to petrophysics in a format that crystallizes the subject as a subdiscipline appropriate for the workstations of today. The subject matter is of wide interest to both academic and industrial professionals who work with subsurface data applied to energy, hydrology, and environmental issues. This book is the first of its kind, in that it addresses mathematical petrophysics as a distinct discipline. Other books in petrophysics are either extensive descriptions of tool design or interpretation techniques, typically in an ad hoc treatment. It covers mathematical methods that are applied to borehole and core petrophysical measurements to estimate rock properties of fluid saturation, pore types, permeability, mineralogy, facies, and reservoir characterization. These methods are demonstrated by a variety of case studies and summaries of applications. Principles of Mathematical Petrophysics is an invaluable resource for all people working with data related to petrophysics.
Book chapters on the topic "Subsurface permeability"
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Manstein, Alexander K., and Mikhail I. Epov. "Subsurface Permeability for Groundwater Study Using Electrokinetic Phenomenon." In Water Security in the Mediterranean Region, 87–95. Dordrecht: Springer Netherlands, 2011. http://dx.doi.org/10.1007/978-94-007-1623-0_7.
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Liu, Hui-Hai. "Generalization of Darcy’s Law: Non-Darcian Liquid Flow in Low-Permeability Media." In Fluid Flow in the Subsurface, 1–43. Cham: Springer International Publishing, 2016. http://dx.doi.org/10.1007/978-3-319-43449-0_1.
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Bernard, D., M. Danis, and M. Quintard. "Effects of Permeability Anisotropy and Throw on the Transmissivity in the Vicinity of a Fault." In Hydrogeological Regimes and Their Subsurface Thermal Effects, 119–28. Washington, D. C.: American Geophysical Union, 2013. http://dx.doi.org/10.1029/gm047p0119.
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Clauser, Christoph. "Conductive and Convective Heat Flow Components in the Rheingraben and Implications for the Deep Permeability Distribution." In Hydrogeological Regimes and Their Subsurface Thermal Effects, 59–64. Washington, D. C.: American Geophysical Union, 2013. http://dx.doi.org/10.1029/gm047p0059.
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Wong, Teng-fong, and Wenlu Zhu. "Brittle faulting and permeability evolution: Hydromechanical measurement, microstructural observation, and network modeling." In Faults and Subsurface Fluid Flow in the Shallow Crust, 83–99. Washington, D. C.: American Geophysical Union, 1999. http://dx.doi.org/10.1029/gm113p0083.
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Sigda, John M., Laurel B. Goodwin, Peter S. Mozley, and John L. Wilson. "Permeability alteration in small-displacement faults in poorly lithified sediments: Rio Grande Rift, Central New Mexico." In Faults and Subsurface Fluid Flow in the Shallow Crust, 51–68. Washington, D. C.: American Geophysical Union, 1999. http://dx.doi.org/10.1029/gm113p0051.
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Heynekamp, Michiel R., Laurel B. Goodwin, Peter S. Mozley, and William C. Haneberg. "Controls on fault-zone architecture in poorly lithified sediments, Rio Grande Rift, New Mexico: Implications for fault-zone permeability and fluid flow." In Faults and Subsurface Fluid Flow in the Shallow Crust, 27–49. Washington, D. C.: American Geophysical Union, 1999. http://dx.doi.org/10.1029/gm113p0027.
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Noland, Scott, and Edward Winner. "Activated Carbon Injection for In-Situ Remediation of Petroleum Hydrocarbons." In Advances in the Characterisation and Remediation of Sites Contaminated with Petroleum Hydrocarbons, 549–89. Cham: Springer International Publishing, 2023. http://dx.doi.org/10.1007/978-3-031-34447-3_16.
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AbstractIn-situ remediation of petroleum hydrocarbons (PHCs) using activated carbon (AC) is an emerging technology intended to enhance sorption and biodegradation mechanisms in soil and groundwater systems. The combination of pore types, source material, activation process, and grind of a particular AC influences its efficacy in subsurface remediation. When high-energy injection techniques are employed, installation of carbon-based injectate (CBI) slurries can be conducted in practically any geological setting, from sandy aquifers to low-permeability zones and weathered or fractured rock. Following an adequate CBI installation throughout the target treatment zone or as a permeable reactive barrier, dissolved PHC concentrations are typically observed to rapidly decrease. After a new equilibrium is formed, PHC concentrations typically decrease over time due to the biodegradation. PHC biodegradation, in association with the CBIs, is indicated by the presence of appropriate microbial communities found to grow on AC and is supported by multiple lines of evidence. Further research is encouraged to optimize the biodegradation and regeneration processes of CBI products for in-situ remediation of PHCs.
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Munholland, Jonah, Derek Rosso, Davinder Randhawa, Craig Divine, and Andy Pennington. "Advances in Low-Temperature Thermal Remediation." In Advances in the Characterisation and Remediation of Sites Contaminated with Petroleum Hydrocarbons, 623–53. Cham: Springer International Publishing, 2023. http://dx.doi.org/10.1007/978-3-031-34447-3_18.
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AbstractRemediation through traditional high-temperature thermal techniques (over 100 °C) are designed to remove contaminants like petroleum hydrocarbons via enhanced mobilization and volatilization. However, remedies of this nature can require significant infrastructure, capital, operational and maintenance costs, along with high energy demands and carbon footprints. Conversely, low-temperature thermal approaches (in the mesophilic range of ~15–40 °C) are an inexpensive and more sustainable method that can enhance the physical, biological, and chemical processes to remove contaminants. Heat transfer properties of subsurface sediments and other geological materials do not vary considerably and are relatively independent of grain size, unlike hydraulic properties that can vary several orders of magnitude within a site and often limit the pace of remediation of many in-situ technologies. Therefore, low-temperature thermal remediation is a promising alternative that can remediate contaminant mass present in both high- and low-permeability settings, including fractured rock. Emergence of risk-based non-aqueous phase liquid management approaches and sustainable best management practices further offer a platform for low-temperature thermal remedies to advance petroleum hydrocarbon remediation with lower capital and operational costs. Case studies demonstrating this approach along with preliminary sustainability comparisons of the associated reduced energy use and carbon footprint are described in this chapter.
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Ferreira, Marco A. R., Mike West, and Herbert K. H. Lee David Higdon Zhuoxin Bi. "Multi-scale Modelling of 1-D Permeability Fields." In Bayesian Statistics 7, 519–27. Oxford University PressOxford, 2003. http://dx.doi.org/10.1093/oso/9780198526155.003.0032.
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Abstract Permeability plays an important role in subsurface fluid flow studies, being one of the most important quantities for the prediction of fluid flow patterns. The estimation of permeability fields is therefore critical and necessary for the prediction of the behavior of contaminant plumes in aquifers and the production of petroleum from oil fields. In general, there are two types of information that can be used in the estimation of the permeability field: static data and dynamic data. Static data can be regarded as measurements of the permeability field, and are available at different levels of resolution as a result of geological studies, well tests, and laboratory measurements. Dynamic data are obtained through the production from a collection of wells, being the production history in the case of a mature oil field or the result of tracer experiments in the case of aquifers. To incorporate the dynamic data in formal statistical analysis, corresponding likelihood functions for the high-dimensional random field parameters representing the permeability field can be computed with the help of a fluid flow simulator (FFS). The FFS can run at different scales of resolution of the permeability field, lower levels providing faster but less accurate results. In this paper, we incorporate the static information available at the different scales of resolution by using a multi-scale time series model as a prior for 1-D permeability fields. Estimation of the multi-scale permeability field is then performed using an MCMC algorithm with an embedded . FFS running at different scales to incorporate the dynamic data. We use simulated data to study the performance of the proposed approach with respect to the recovery of the original permeability field.
Conference papers on the topic "Subsurface permeability"
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Stavland, A., D. Strand, and K. Langaas. "Water Control – How to Use Oil Soluble." In SPE Norway Subsurface Conference. SPE, 2024. http://dx.doi.org/10.2118/218474-ms.
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Abstract We describe a new concept to selectively reduce the water production from watered-out zones in oil wells: Heat an oil soluble compound to a temperature above its melting temperature and inject it into the formation as a liquid. When cooled to reservoir temperature, the chemical compound solidifies and reduces the formation permeability. Because of its oil solubility, the solidified compound is dissolved where oil is flowing. After a clean-up period, the oil permeability is fully regained. In the watered-out zones, the permeability reduction is permanent, simply because the solidified compound is not soluble in water. The concept has a large environmental improvement potential for the oil industry. By reducing production from watered-out zones, it will also reduce unwanted recycling of any injected water. Environmental savings might include power reduction and associated CO2 emission reduction linked to water treatment of produced and injected water, less need of chemicals to treat produced and injected water, and less produced water disposals to sea.Paraffin wax is a promising candidate. A paraffin wax with melting temperature of 61°C was injected at 70°C into a core plug. When lowering the temperature to 50°C, the injected wax resulted in stable permeability reduction. Brine backproduction for extended periods did not help to regain the permeability and the water permeability changed from initially 80 md to 1 md. During oil backproduction the oil permeability regained with less than 10 pore volumes of oil. The core flooding results agree well with bulk experiments of wax solubility in oil.Warmer reservoirs require waxes (or similar compounds) with higher melting temperature. Here we report results from the use of the hard carnauba wax, with melting temperature of 84°C. We confirmed that the wax melting temperature can be lowered, either by dilution of the hard wax in oil or by preparing a paraffin-carnauba blend. Core flood experiments with pure carnauba wax, carnauba wax diluted in oil and paraffin-carnauba blend all revealed excellent injectivity of the melted wax and the flow behavior was understood by two-phase oil-water flood. The water permeability, after a shut-in period, was low and stable while oil partly dissolved the solidified wax. However, the clean-up time for the carnauba-treated cores was significantly longer than for the paraffinic ones. We observed that dissolution rate depends on type of oil. Hexane (C6) revealed more rapid permeability regain than C10 and C16 alkanes. One explanation for the long clean-up period can be that the carnauba-containing waxes contributed to a more severe wetting alteration. Other wax alternatives with high melting temperature exists and are part of future research.Thinking ahead on oil field operational aspects, the concept seems ideal for low-volumes bull heading injection, where the whole near well area is treated with an invasion depth of a few feet. Temperature control of the wax before entering the porous rock will be paramount.
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Taheri, A., and E. P. Ford. "Two-Phase Relative Permeability in Wellbore Microannulus and its Significance in Long-Term Risk Assessment." In SPE Norway Subsurface Conference. SPE, 2024. http://dx.doi.org/10.2118/218438-ms.
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Summary In plug and abandonment (P&A) wells, the interface between the steel casing and cement in a typical wellbore may debond and establish leakage pathways called microannulus. This study aims to understand the behavior of two-phase flow of water and gas in the microannulus and evaluate the relative importance of absolute and effective permeabilities on long-term leakage potential. In this study, we conducted experiments to quantitatively determine the relative permeabilities of water and gas within the microannulus established at the interface between a 9 5/8-inch cemented casing and the enclosed cement matrix. To do this, we saturated a cell with water and introduced nitrogen from the bottom at incrementally increasing pressure, aiming to identify the gas breakthrough pressure within water-filled leakage pathways. Two-phase relative permeabilities were computed using the Brooks-Corey and van Genuchten models, which establish relationships among capillary pressure, saturation, and relative permeability at each pressure step in this unsteady-state approach. These tests were carried out in the short term to verify repeatability and in the long term to assess how cement and casing alterations affect two-phase relative permeabilities. Furthermore, we conducted a simulation sensitivity study to express the relative significance of absolute and effective permeabilities in terms of long-term leakage potential. This study reveals that the conventional X-curve relative permeability inadequately captures the two-phase flow behavior in leaky wellbores. Furthermore, it illustrates that even with alteration in cement and casing as well as variations in microannulus size over time, relative permeability remains quite stable. These results imply that in the studied P&A cases where two phases flow within the microannulus, comprehending this complex two-phase flow behavior in the microannulus and applying an accurate representative relative permeability model are critical for effectively assessing the long-term leakage risks. This research contributes significantly to the understanding of multiphase flow dynamics within the microannulus and underscores the critical significance of utilizing representative relative permeability models, as opposed to the commonly used X-curve relative permeability, in the analysis of fluid flow behavior and assessing associated risks.
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Akbar, M. N. A., and R. Myhr. "Dynamic Reservoir Rock Typing for Supercritical CO2-Brine System in Sandstone." In SPE Norway Subsurface Conference. SPE, 2024. http://dx.doi.org/10.2118/218449-ms.
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Abstract Dynamic reservoir rock typing is a critical yet infrequently explored aspect of CO2 storage, essential for evaluating flow characterization in dynamic reservoir modeling within aquifer reservoirs. This study introduces a new insight into the establishment of dynamic reservoir rock types for the supercritical CO2-brine system, leveraging relative permeability data and implementing it into 3D numerical reservoir simulation. Our research draws on 22 sandstone core plugs obtained from potential CO2 storage aquifers in Alberta, Canada, encompassing measurements of relative permeabilities during primary drainage and secondary imbibition cycles. The rock typing methodology employed incorporates pore geometry and pore structure (PGS), in conjunction with the True Effective Mobility (TEM) function, to comprehensively characterize multi-phase fluid flow properties in rocks. Subsequently, we visualize the outcomes of the rock typing process through 1D and 3D model representations, including the simulation of flow characteristics through compositional numerical modeling for geological CO2 storage. As a result, four rock groups were established based on pore geometry and pore structure relationships in the studied samples. The critical findings are that the obtained results demonstrate clear groupings of similar TEM-function curves based on relative permeabilities of both brine and CO2, observed in both drainage and imbibition experiments. Averaged relative permeability curves were derived from the TEM-function and subsequently converted them into conventional relative permeability values for each rock type. Notably, 3D numerical simulations of flow dynamics unveiled unique and contrasting multi-phase fluid behavior within each rock group, particularly evident in saturation profiles over time. Furthermore, we evaluated the correlation between residual CO2 trapping and irreducible water saturation within the rock samples. Our findings suggest an inversely proportional relationship, indicating that higher irreducible water saturation leads to lower residual CO2 trapping. As a novelty, combining PGS rock typing and TEM-function analysis facilitated the effective and efficient grouping of capillary pressure and relative permeability data, ensuring high consistency and minimized overlap in each rock type. Moreover, this approach offers an alternative solution for averaging relative permeability data within each rock type that can greatly reduce the uncertainty of defining relative permeability input and accelerate the process of dynamic reservoir modeling.
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Fitzsimons, D., O. Johansen, B. Legler, and S. Lubeseder. "Rock Type Modelling of a Heterogeneous Tidal Reservoir of the Tilje Formation." In SPE Norway Subsurface Conference. SPE, 2024. http://dx.doi.org/10.2118/218462-ms.
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Abstract Heterolithic tidal reservoirs, like those of the Tilje Formation, are challenging to model. In addition to primary facies, diagenetic overprint adds to the heterogeneous character of the reservoir. A rock type modelling approach is presented to enable the use and integration of conventional core data, whole core computer tomography (CT) scans, wireline data and well test data to characterise the reservoir. Whole core CT data oriented to image log has allowed paleocurrent data, depositional facies and rock types to be interpreted at very fine scale. The combination of these data allows a better understanding of permeability distribution and anisotropy. Permeability for given porosity class can have several orders of magnitude difference. The best rock type has permeability in excess of 1000 mD due to the presence of chlorite coating around grains which prevents the development of quartz overgrowths expected at the burial depths of the reservoir (4.5–5 km TVDSS). Rock type with reduced grainsize and/or thicker chlorite coating have reduced pore throats reducing permeability to 10 to 100 mD. In the absence of chlorite coating permeabilities are below 1 mD. Well test interpretation suggests the presence of barriers close to the well bore with good connectivity in alternate directions. It is not known if the barriers are due to sealing faults or due to depositional or diagenetic features. The geological model has been built to ensure that the heterogeneity observed in logs and core and the response from well test is captured to allow production and injection well scenarios to be tested. Rock types have been classified on the basis of Rock Quality Index (RQI) which is related to both original depositional textures (sorting and grain size) and diagenesis. Once defined at the plug scale whole core CT scans have been used to propagate the rock type in cored intervals. The resulting rock type curve was then used as a training data set for machine learning algorithms to populate rock types in un-cored intervals. Permeability thickness (kh) from well tests has been used to quality control and calibrate the rock type model. Once propagated to wells a multi scenario 3D rock type model was built.
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Bandara, Yasas W., Ismarullizam Mohd Ismail, Natasya Ng, and Caleb Siew. "Design Configuration for Autonomous Inflow Control Valve Technology for Newly Drilled Well in a Mature Field in Malaysia – Model vs Reality." In SPE Norway Subsurface Conference. SPE, 2024. http://dx.doi.org/10.2118/218428-ms.
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Abstract Design of an ICD (Inflow Control Device) completion is initially determined based on the static and dynamic models prepared during pre-drilling stage of the well. However, actual well properties available post-drilled are quite different from the pre-drilled properties, and the completion must be optimized. The objective of this study is to address the challenges on pre- and post-completion designs which was conducted for a gas and water control application in redevelopment phase infill well in a mature field in Malaysia. All types of ICD completions are designed based on the static simulation for selected time steps of a dynamic simulation. The autonomous inflow control valve (AICV) is an advanced ICD that can also choke/close unwanted gas and water. The number of AICVs are determined based on the initial maximum oil production rate, despite permeability and gas/water saturation. Therefore, several sensitivities were conducted to determine optimum production rate with an AICV completion. The compartmentalization and distribution of AICVs mainly depended on the well constraints. Although, the required number of AICV are same for the post drill completion, packers and AICV joint placement were adjusted based on the drilling log data. Drilling logs indicated that permeabilities of the post-drilling were about 1/10 of the expected permeabilities of the model and high permeability zones were concentrated to localized zones compared to distributed high permeability in the model. Localized high permeable zones create challenging situations to place the required number of AICV joints in respective compartments due to length constraints. The completion design was re-optimized based on the new permeability profile and new constraints. Packers were placed in low permeability zones to maximize the effect of zonal isolation. Additional packers were installed to delay the gas transport to oil producing compartments in case of a gas breakthrough in neighboring compartment. The number of AICV joints utilized in the well was lower compared to the originally predicted number of joints due to shorter TD of the well. For the well, the number of AICV joints utilized was 38 out of 45 joints. The well started production with desired oil rate at 1500 BOPD with minimal gas and water production with productivity index (PI) 2x better than expected.
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Orr, Robert, Dag Chun Standnes, Torleif Holt, and Martin Raphaug. "The Effect of Oxidation of Core Material on Steady State Relative Permeability of Oil and Water." In SPE Norway Subsurface Conference. SPE, 2022. http://dx.doi.org/10.2118/209542-ms.
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Abstract Laboratory core flooding experiments performed are used to predict fluid flow behaviour in the reservoir. Most reservoirs are in a reduced state. However, iron minerals in the extracted cores may become oxidized going from the reservoir to the laboratory. Oxidation of the core can affect wettability and thereby relative permeability curves used for reservoir simulation studies. The aim of this work was to study the potential effect of core oxidation on relative permeability. Steady state relative permeability experiments with in-situ saturation measurements and use of live oil have been performed on one composite core at 10 different saturations. The core was tested under three different conditions: oxidized (Exp. 1), reduced (Exp. 2) and re-oxidised (Exp. 3). The core was cleaned, fluid saturated and aged before each test. In Exp. 2, the core plug was chemically reduced. All fluids used in this experiment were oxygen free. In Exp. 3 the core plug was treated using fluids to oxidise the core. Fluids injected and extracted, and core samples were analysed using a range of methods. Results showed that the measured relative permeability curves from Exp. 2 and 3 were similar and significantly different from the results from Exp. 1. The attempt to restore the core material to the initial state (oxidized) after Exp. 2 by exposing the core material to fluids with oxygen was seemingly not successful. The observation was also supported by unsteady state flooding measurements which indicated that as long as the core remained fluid saturated, it behaved as a reduced core, even after extensive exposure to oxygen containing liquids. The crossing point of the oil and water relative permeabilities indicate that the core was more water wet in reduced state compared to before the oxidized state. Differences in chemical composition were also detected between extracts from Exp. 1 - 3. The conclusion is that significant differences in steady state relative permeabilities of oil and water in oxidized and reduced states were observed for the iron containing core investigated. The results also indicate that if the core is kept fluid saturated, effects of oxidation may be significantly delayed.
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Jettestuen, E., O. Aursjø, J. O. Helland, J. L. Vinningland, and A. Hiorth. "Workflow for Direct Pore-Scale Simulation of Relative Permeability and Capillary Pressure Curves with Hysteresis at Low Capillary Numbers." In SPE Norway Subsurface Conference. SPE, 2024. http://dx.doi.org/10.2118/218427-ms.
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Abstract We propose an efficient workflow to estimate relative permeability and capillary pressure curves directly from pore-scale images for capillary dominated flows. In this workflow, we use a method to determine saturation configurations, and by coupling these configurations to a single-phase lattice Boltzmann fluid flow solver, we can impose higher order boundary conditions at the phase interfaces and avoid spurious currents and phase mixing. This removes some of the common drawbacks when employing multiphase fluid solvers: it improves numerical accuracy, and it increases the computational speed, compared to full two-phase simulations.
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Cimic, Miljenko, Michael Sadivnyk, Oleksandr Doroshenko, and Stepan Kovalchuk. "Influence of Abandonment Pressure on Recoverable Reserves, Special Application to the Depleted Dnipro-Donetsk Basin Reservoirs." In SPE Eastern Europe Subsurface Conference. SPE, 2021. http://dx.doi.org/10.2118/208523-ms.
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Abstract Volumetric gas reservoirs are driven by the compressibility of gas and a formation rock, and the ultimate recovery factor is independent of the production rate but depends on the reservoir pressure. The gas saturation in the volumetric reservoir is constant, and the gas volume is reduced causing pressure drop in the reservoir. Due to this reason, it is crucial to minimize the abandonment pressure to the lowest possible level. Concerning Dnipro-Donetsk Basin (DDB) gas reservoirs, it is widespread to recover sometimes more than 90% of the OGIP. Often, OGIP was estimated not considering lower permeability gas layers due to inaccurate logging equipment used in the past, causing that such layers were not included in the total netpay. This is one of the reasons for OGIP overestimation and higher recovery factors. On many P/Z graphs, we observe that at certain drawdown, lower permeability reservoirs kick in lifting up P/Z plot curve. Abandonment pressure is a major factor in determining recovery efficiency. Permeability and skin are usually the most critical factors in determining the magnitude of the abandonment pressure. Reservoirs with low permeability will have higher abandonment pressures than reservoirs with high permeability. A specific minimum flow rate must be sustained to keep the well unloading process, and a higher permeability will permit this minimum flow rate at lower reservoir pressure. Abandonment pressure will depend on wellhead pressure, friction and hydrostatic pressures in the system, pressure drop in reservoir, and pressure drop due to skin. This last factor is often neglected, which sometimes leads to a significant reduction of the recovery factor. It is common practice that skin factor and pressure drop due to the skin are solved with well stimulation. Also, well stimulation has its limits concerning the level of reservoir pressure. It is very common that the stimulation effect of low reservoir pressure well is negligible or even negative. This is caused by the minimum required drawdown to flow back a stimulating aqueous fluid out of the reservoir. The required minimum drawdown is caused by the Phase Trapping Coefficient (PTC), which drives reservoir stimulation fluid cleaning behavior. For water drive gas reservoirs, Cole (1969) suggests that the recovery is substantially less than recovery from bounded gas reservoirs. As a rule of thumb, recovery from a water-drive reservoir will be approximately 50 to 75% of the initial gas in place. The structural location of producing wells and the degree of water coning are essential considerations in determining ultimate recovery. In the cases studied in this paper, we consider gas and rock expansion reservoir energy, if abandonment pressure needs to be coupled with a water drive, then it is recommended to use a numerical, not analytical approach.
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Hoq, A., Y. Caline, R. E. Flatebø, A. N. Martin, M. Rylance, D. M. Milton-Tayler, M. Magallanes, M. Olsen, and R. Hatlebakk. "Extensive Testing of Glass-Based Chemical Consolidation on Carbonate Reservoir." In SPE Norway Subsurface Conference. SPE, 2024. http://dx.doi.org/10.2118/218426-ms.
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Abstract Chemical consolidation of carbonate reservoirs offers the possibility of increasing the production and longevity of wells while minimizing the associated operational expenses. A novel glass-based chemical solution has been tested to understand the potentially beneficial consolidation and treatment effects that this can have on a chalk reservoir. The testing and modeling results, along with operational application methods will be shared and discussed within this paper. Over 80 core flood injection tests were performed to investigate the injection parameters and results on post-treatment strength and permeability. A variety of strength measurements were used to understand the full impact on the resulting strength properties. Over 20 fracture embedment tests with proppants were conducted to determine the strengthening effects in the chalk face and assess the resulting permeability in propped fractures. The results of all these tests and models are compiled and compared to understand the trends and relationships in order to determine the most effective injection parameters and post-treatment effects achievable in the chalk reservoir. The laboratory results have demonstrated that this chemical solution can strengthen intact cores, consolidate chalk powder, strengthen the chalk face in proppant fractures, all while retaining a high degree of the original permeability, and in some cases increasing it. If field trials can replicate the same outcome, there is the potential to increase drawdown limits, reduce chalk production, alleviate productivity decline, ultimately boosting production potential, and concurrently mitigating the risks of deferred production and operational costs associated with interventions. This could be a solution for new wells on the Valhall field to help sustain stable production rates and prolong the longevity of the wells. Glass-based chemical solutions are new to the industry and present the opportunity for unique solutions to the consolidation and sealing challenges we face. This novel chemical solution is now ready for evaluation through suitable field trials and its core technology could potentially have applications beyond carbonate consolidation.
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Roostaei, Alireza, Steve Pride, Eirik Jenssen, Reidar Birkeland, Robert Ritschel, Neal Hughes, and Grethe Ledsaak. "Dvalin Gas Field Developments and Optimization by Using the Inflow Tracer Technology Information." In SPE Norway Subsurface Conference. SPE, 2022. http://dx.doi.org/10.2118/209531-ms.
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Abstract This paper describes how the information from inflow tracer technology was used to optimise the trajectory of a well during the development phase of Dvalin field. The Dvalin field is a high temperature (HT) gas field in the central part of the Norwegian Sea that consists of two separate structures. Each structure has two high perm streaks, the shallower of which was thought to have good reservoir properties whereas there was more uncertainty around the deeper one, the suspicion being that it was of a lower quality. During the exploration phase a DST was performed and it was uncertain if only the upper high permeability streak flowed on the assumption the mud was not optimised for the application. Additionally, the lower high permeability streak was not easily identifiable on the logs, although it was clear from the core. The initial field development concept consisted of drilling four production wells. Due to the uncertainties around the lower reservoir section, it was seen as highly beneficial to obtain information in the early development phase and, due to the challenging environment (HT and subsea), the choice of monitoring technologies was extremely limited. Inflow tracers were therefore chosen for the four planned producers, a technology whereby unique permanent chemical tracers are integrated into polymer rods which are then deployed as part of the lower completion. They remain dormant until encountering a specific target fluid – in this case oil-based mud (OBM). Once activated, they will release into the target fluid for a certain designed life period (in this case for a few months) and flow to surface upon opening the well where they will be sampled and analysed. The analysed data is then interpreted to confirm the zonal clean up and flow contribution. The initial drilling plan consisted of slanted wells penetrating both, the upper and lower high permeability streak. In the event, the inflow tracer from the first well confirmed that the lower reservoir section not only cleaned up effectively but, crucially, demonstrated good productivity the operator could prove they selected the optimal mud and also the presence and contribution of a lower high permeability streak. In addition, a decision was made to change the configuration of the final well from slanted to horizontal in the upper zone, resulting in a 4x increase in well productivity where the tracers played a key role in the decision process. Monitoring well performance at the zonal level is a challenge, especially in HT and subsea wells. In this case inflow tracer technology was successfully used to provide validation of clean-up and flow contribution and thereby helped to optimize the drilling plan and well productivity in the course of the field development thereby increasing the value of the project.
Reports on the topic "Subsurface permeability"
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Wilson, B., S. Mordensky, Circe Verba, K. Rabjohns, and F. Colwell. An Evaluation of Subsurface Microbial Activity Conditional to Subsurface Temperature, Porosity, and Permeability at North American Carbon Sequestration Sites. Office of Scientific and Technical Information (OSTI), June 2016. http://dx.doi.org/10.2172/1327812.
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Bruno, Michael, Kang Lao, Jean Young, and Juan Ramos. The Use of Advanced Percussion Drilling to Improve Subsurface Permeability for Enhanced Geothermal Systems. Office of Scientific and Technical Information (OSTI), January 2019. http://dx.doi.org/10.2172/1491407.
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Brydie, Dr James, Dr Alireza Jafari, and Stephanie Trottier. PR-487-143727-R01 Modelling and Simulation of Subsurface Fluid Migration from Small Pipeline Leaks. Chantilly, Virginia: Pipeline Research Council International, Inc. (PRCI), May 2017. http://dx.doi.org/10.55274/r0011025.
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The dispersion and migration behavior of hydrocarbon products leaking at low rates (i.e. 1bbl/day and 10 bbl/day) from a pipeline have been studied using a combination of experimental leakage tests and numerical simulations. The focus of this study was to determine the influence of subsurface engineered boundaries associated with the trench walls, and the presence of a water table, upon the leakage behavior of a range of hydrocarbon products. The project numerically modelled three products including diesel, diluted bitumen (dilbit) and gasoline; which were chosen to span a range of fluid types and viscosities. Laboratory simulations of leakage were carried out for the most viscous product (i.e. dilbit) in order to capture plume dispersion in semi-real time, and to allow numerical predictions to be assessed against experimental data. Direct comparisons between observed plume dimensions over time and numerically predicted behavior suggested a good match under low moisture conditions, providing confidence that the numerical simulation was sufficiently reliable to model field-scale applications. Following a simulated two year initialization period, the leakage of products, their associated gas phase migration, thermal and geomechanical effects were simulated for a period of 365 days. Comparisons between product leakage rate, product type and soil moisture content were made and the spatial impacts of leakage were summarized. Variably compacted backfill within the trench, surrounded by undisturbed and more compacted natural soils, results porosity and permeability differences which control the migration of liquids, gases, thermal effects and surface heave. Dilbit migration is influenced heavily by the trench, and also its increasing viscosity as it cools and degases after leakage. Diesel and gasoline liquid plumes are also affected by the trench structure, but to a lesser extent, resulting in wider and longer plumes in the subsurface. In all cases, the migration of liquids and gases is facilitated by higher permeability zones at the base of the pipe. Volatile Organic Compounds (VOCs) migrate along the trench and break through at the surface within days of the leak. Temperature changes within the trench may increase due liquid migration, however the change in predicted temperature at the surface above the leak is less than 0.5�C above background. For gasoline, the large amount of degassing and diffusion through the soil results in cooling of the soil by up to 1�C. Induced surface displacement was predicted for dilbit and for one case of diesel, but only in the order of 0.2cm above baseline. Based upon the information gathered, recommendations are provided for the use and placement of generic leak detection sensor types (e.g liquid, gas, thermal, displacement) within the trench and / or above the ground surface. The monitoring locations suggested take into account requirements to detect pipeline leakage as early as possible in order to facilitate notification of the operator and to predict the potential extent of site characterization required during spill response and longer term remediation activities.
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Sun, S., F. R. Brunton, T. R. Carter, J. R. Clarke, H. A J Russell, K. Yeung, A. Cachunjua, and J. Jin. Porosity and permeability variations in the Silurian Lockport Group and A-1 carbonate unit, southwestern Ontario. Natural Resources Canada/CMSS/Information Management, 2023. http://dx.doi.org/10.4095/331902.
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This is the first regional porosity/permeability study to incorporate petroleum industry laboratory core analyses submitted to the Ontario government and managed by Ontario's Oil Gas and Salt Resources Library. This study comprises 11,759 analyses for the Early Silurian Lockport Group of southwestern Ontario from 150 drill cores. The Lockport Group consists of a cyclic succession of dolostones and minor limestones comprising, in ascending order: Gasport, Goat Island, Eramosa, and Guelph formations. This stacked carbonate succession was deposited on an eastward-deepening carbonate ramp, extending from Michigan, through southwestern Ontario, to Ohio, Pennsylvania and New York. It is overlain disconformably by restricted marine carbonates, evaporites and mixed shales of the Salina Group, whereas unconformably underlain by one of four formations that include, the Lions Head (a stratigraphic equivalent of part of the Rochester), DeCew, Rochester and Irondequoit. To ensure appropriate stratigraphic assignment of the laboratory test intervals, a quality assurance/quality control review on formational tops was carried out on the 150 cores that were tested. This regional subsurface work resulted in the reassignment of 846 formation tops that were verified by examination of drill core, drill cuttings, and geophysical well data including gamma-ray, neutron and density logs. Core analysis datasets have been validated by summarizing laboratory protocols and standards and reconciling data fields in the core analysis database with auxiliary data, including geophysical logs, thin sections, and core examinaion. This auxiliary data was then used to identify data outliers to update the core analysis database. The measurements of porosity and permeability were then assigned a formation rank plotted on a subregional scale. Average porosity and permeability values have been divided into statistical populations for each formation assigned by three depositional realms. The southwestern Ontario study area has been divided into three paleogeographic settings, based on distinctive lithofacies that correspond to different carbonate depositional regimes and regions of paleokarstification. From northwest to southeast, the lithofacies reflect an inner to outer carbonate ramp setting designated as area 1-3 from northwest to southeast. Area 1 is the inter-pinnacle karst region and includes some of thepinnacle structures within the Lockport Group. This region has the most significant paleokarstification of the upper Lockport Group (Guelph and Goat Island formations) and overlying Salina Group A-unit. Area 2 has rare pinnacle structures, where no porosity/permeability core analyses data are available. Area 3 is the middle to outer portion of the Lockport carbonate ramp, with local development of reef mound phases in the lower Goat Island and Gasport formations. The porosity and permeability variability corresponds with areal distribution of paleokarstification and resulting diagenetic phases in Area 1, and lithofacies variations and temporal/spatial history of karstification in Area 3. Higher porosity and permeability generally coincide with greater thicknesses of the oil and gas reservoir within pinnacles in Area 1 and reef mound phases of Lockport Group and lower Salina Group A-1 Carbonate in Area 3. Within inter-pinnacle karst regions in Area 1, average porosity for each formation is consistently high with little variations. In Area 3, a general increase of porosity and permeability towards the southeast corresponds with lithofacies ranging from restricted lagoonal/platform interior deposits to carbonate bank deposits with local development of reef mound phases in the Gasport and Goat Island formations. There has been significant erosion and karstification within and at the tops of these pinnacles, resulting in higher porosity and permeability of the Guelph and upper Goat Island formations, and the overlying Salina Group A-1 unit. Paleokarstic events have enhanced various porosity types, including intercrystalline, moldic, irregular and fenestral vugs, and cavities.
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Russo, David, Daniel M. Tartakovsky, and Shlomo P. Neuman. Development of Predictive Tools for Contaminant Transport through Variably-Saturated Heterogeneous Composite Porous Formations. United States Department of Agriculture, December 2012. http://dx.doi.org/10.32747/2012.7592658.bard.
Full textAbstract:
The vadose (unsaturated) zone forms a major hydrologic link between the ground surface and underlying aquifers. To understand properly its role in protecting groundwater from near surface sources of contamination, one must be able to analyze quantitatively water flow and contaminant transport in variably saturated subsurface environments that are highly heterogeneous, often consisting of multiple geologic units and/or high and/or low permeability inclusions. The specific objectives of this research were: (i) to develop efficient and accurate tools for probabilistic delineation of dominant geologic features comprising the vadose zone; (ii) to develop a complementary set of data analysis tools for discerning the fractal properties of hydraulic and transport parameters of highly heterogeneous vadose zone; (iii) to develop and test the associated computational methods for probabilistic analysis of flow and transport in highly heterogeneous subsurface environments; and (iv) to apply the computational framework to design an “optimal” observation network for monitoring and forecasting the fate and migration of contaminant plumes originating from agricultural activities. During the course of the project, we modified the third objective to include additional computational method, based on the notion that the heterogeneous formation can be considered as a mixture of populations of differing spatial structures. Regarding uncertainly analysis, going beyond approaches based on mean and variance of system states, we succeeded to develop probability density function (PDF) solutions enabling one to evaluate probabilities of rare events, required for probabilistic risk assessment. In addition, we developed reduced complexity models for the probabilistic forecasting of infiltration rates in heterogeneous soils during surface runoff and/or flooding events Regarding flow and transport in variably saturated, spatially heterogeneous formations associated with fine- and coarse-textured embedded soils (FTES- and CTES-formations, respectively).We succeeded to develop first-order and numerical frameworks for flow and transport in three-dimensional (3-D), variably saturated, bimodal, heterogeneous formations, with single and dual porosity, respectively. Regarding the sampling problem defined as, how many sampling points are needed, and where to locate them spatially in the horizontal x₂x₃ plane of the field. Based on our computational framework, we succeeded to develop and demonstrate a methdology that might improve considerably our ability to describe quntitaively the response of complicated 3-D flow systems. The results of the project are of theoretical and practical importance; they provided a rigorous framework to modeling water flow and solute transport in a realistic, highly heterogeneous, composite flow system with uncertain properties under-specified by data. Specifically, they: (i) enhanced fundamental understanding of the basic mechanisms of field-scale flow and transport in near-surface geological formations under realistic flow scenarios, (ii) provided a means to assess the ability of existing flow and transport models to handle realistic flow conditions, and (iii) provided a means to assess quantitatively the threats posed to groundwater by contamination from agricultural sources.
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Soil Influences on water balance in wetlands may impact wetland effectiveness in achieving different restoration objectives. Washington, D.C: USDA Natural Resources Conservation Service, August 2020. http://dx.doi.org/10.32747/2020.8135351.nrcs.
Full textAbstract:
This report summarizes a study that explores how surface water and groundwater interactions vary with soil hydraulic conditions (e.g., low vs. high soil permeability) in the Mid-Atlantic Coastal Plain. In addition, implications of wetland soil characteristics on wetland restoration and management are discussed in the report. Analysis indicates there is less interaction between surface water and groundwater in wetlands with low permeability subsurface soils than in wetlands with high permeability subsurface soils. Groundwater levels had little impact on surface water levels when subsurface soils were of low permeability. In contrast the wetland with highly permeable subsurface soils showed a more consistent relationship between surface water level and groundwater level, and greater contribution of groundwater to wetland surface water. These results have implications for conservation planning and wetland restoration. Wetland restoration over low permeability soils may yield a higher carbon holding capacity and may be more effective at nitrogen removal via denitrification because of the potential for the wetland to maintain surface water for longer periods of time