No description available.

No description available.

An estimation method for predicting the saturated hydraulic conductivity (Ksat) of the soil was developed for common Nova Scotia soil types by examination of historical Ksat records. Detailed statistical analysis was performed to develop useful predictive models for Ksat based on soil physical properties and to determine the confidence limits for specific horizon-soil type combinations. Sensitivity analysis of the Hooghoudt equation was then performed to establish Ksat classes to which the confidence limits could be assigned to complete the development of the estimation method. / Model development processes proved unsuccessful due to the influence of factors not considered by the model due to their qualitative nature. Independent field testing of the estimation method with respect to core and Guelph permeameter measurement techniques produced measured values within the same class as the estimated value 34% of the time for both techniques and values within one estimated class or less 70 and 76% of the time for core and permeameter techniques respectively.

Typescript. / Thesis (Ph. D.)--University of Hawaii at Manoa, 1984. / Bibliography: leaves [187]-199. / Microfiche. / xvii, 199 leaves, bound ill. 29 cm

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Abstract not available

Single-probe formation testers have been used since the 1950s to measure pore pressure and estimate mobility in fluid-bearing formations penetrated by a well. They are widely used in the oil and gas industry, with tens of measurements often made in every newly drilled well as part of the formation evaluation program. Each measurement consists of placing the tool in the wellbore in direct contact with the face of the formation, extracting a small amount of fluid (from 1 to 50 cc) from the rock and analyzing the fluid pressure response of the system. Pressure interpretation is based on models that assume that temperature within the formation tester flowline remains constant during the tool operation. However, formation pressure measurement involves relatively fast volume and pressure changes within the flowline, which result in temperature changes. These temperature changes are modeled semi-analytically and their effect on pressure transients is analyzed. Temperature variations are accounted for by describing the pressure and temperature dependence of fluid density in the continuity equation, and that temperature varies with both space and time. It is considered here that once a temperature change is imposed on the system, the primary mechanism of thermal transport to achieve equilibrium is conduction. Including temperature in the analysis requires taking into account flowline geometry, and well environmental conditions during the measurement-- namely, wellbore temperature and type of drilling fluid in the wellbore, all of which are immaterial in the isothermal analysis. Arguably, pressure behavior during formation tester measurements could be influenced by several factors. All previous studies related to formation testers assume perfect tool performance and provide explanations to pressure behaviors from the reservoir point of view (e.g., Stewart and Witmmann, 1979; Phelps et al., 1984; Proett and Chin, 1996, etc.). The approach followed here is diametrically opposite. The formation is considered `perfect' from the point of view of pressure measurement, and physical phenomena (thermal transients) that may affect the measured pressure signal are studied. The focus is to understand fundamental aspects of the tool performance that can be studied analytically while minimizing, as much as possible, external parameters that add uncertainty. This dissertation was motivated by inconsistencies observed between the pressure behavior in field measurements and existing (isothermal) theory. For instance, false buildups, buildup overshoots and long time required to reach pressure equilibration, have puzzled those involved in the interpretation of formation tester pressure transients for many years. These behaviors can be reproduced in pressure computations when accounting for temperature variations. The focus of this dissertation is on modeling the tool capability to sense pressure transients associated with recompression of formation fluids several inches away from the wellbore, accounting for temperature variations during the measurement. This is relevant because it is desirable to characterize formation properties beyond the region affected by drilling mud filtrate invasion. In practice, a discrepancy is often observed between formation mobility obtained from drawdown, which depends mostly on formation properties near the wellbore, and mobility obtained from the analysis of late-time buildup pressure, which in theory depends on formation properties farther from the wellbore (Moran and Finklea, 1962). This dissertation examines the influence of late-time tool storage effects caused by thermal equilibration of the flowline fluid on the pressure equilibration and buildup mobility interpretation. It was found that in some cases such late-time storage effects could exhibit a behavior that resembles that expected from spherical flow, that is, the flow regime characteristic of single-probe formation testers; and could therefore invalidate mobility determined by isothermal transient pressure analysis. Formation tester flowline and probe design, test parameters (rate and volume), and environmental conditions during the measurement, mostly type of drilling fluid and wellbore temperature, are important variables in determining the magnitude of late-time storage effects, and hence the tool capability to detect a deep formation signal (spherical flow). Temperature variations affecting late-buildup pressure transients were observed to be more pronounced (listed in order of importance): as wellbore temperature increases; drilling fluid is oil-based mud; flowline with large radius components (e.g. > 1 cm); large flowline volume; small probe radius (< 1 cm); and, large drawdown rate. Temperature effects on the late-buildup also tend to be more significant when mobility is in the 0.1 to 10 md/cp range, that is for those formations more likely, in theory, to exhibit spherical flow regime during buildup. / text

Industrial production of hydrogen from the syngas, generated from steam reformation of natural gas or coal gasification, sets conditions for hydrogen separation membranes in terms of operating conditions. An alternative source for hydrogen is a syngas generated by gasification of municipal solid wastes which are likely to set more stringent conditions for the separation membranes. There is therefore, a growing demand for separation membranes with improved permeability and particularly of low cost. Among various alternatives, metallic membranes are particularly attractive due to their high selectivity and permeability for hydrogen, exemplified by palladium (Pd). However, due to high cost of Pd there is still a demand to develop alternative metallic membranes that are of low cost and have improved durability. Efforts have therefore concentrated on either alloying Pd so as to reduce its cost or on alternative membrane compositions of particularly b.c.c. structure. The current study deals with hydrogen separation membranes and aims to develop infrastructure for rapid identification of membrane compositions with improved permeability. The study is made up of three parts / i) development of sputter deposition system that would allow deposition of multiple compositions in a single experiment, ii) development of substrate material that would support the thin film membranes and would allow permeability measurement and iii) development of a set-up to measure the permeability of the thin film membranes. In the present thesis, a sputter deposition system incorporating three targets was successfully constructed. The system as tested with palladium-niobium-titanium (Pd-Nb-Ti) ternary system after necessary adjustment would yield thin films of homogenous thickness (&le / 7%) over a sample area of &asymp / 150 mm diameter. A total of 21 substrates each in 19 mm diameter arranged in triangular form in the substrate holder could successfully be deposited where composition distributions covered a greater portion of Pd-Nb-Ti ternary phase diagram. The structure of the deposited thin films can successfully be controlled by substrate temperature as well as by the pressure of plasma gas (argon). With the help of these parameters, structural diversity can also be produced beside the compositional variation. As for substrates, two materials were investigated. These were titanium dioxide (TiO2) modified porous stainless steel (PSS) and anodic porous alumina (AAO). TiO2 modified PSS due to its associated surface roughness leads to the deposition of films with defected structure which as a result is not gas tight. AAO produced via anodization of aluminum foil had a regular (40-60 nm) pore structure that provides a suitable surface for thin film depositions which could be defect free. However, AAO is very delicate and fragile which makes it difficult to adapt it as a support material for permeability measurement/hydrogen separation purposes. Finally, a set-up was developed for measurement of hydrogen permeability which is capable of measurement over a wide pressure and temperature conditions, i.e. hydrogen pressures up to 10 bar and temperature as high as 450 &deg / C. It is recommended that so as to identify compositions with improved permeability, Nb or a similar metal which has extremely high permeability could be used as a support material. This would tolerate the evaluation of the films which are not totally defect free.

Dans les puits de production d’eau, de pétrole, de gaz et de chaleur géothermique, ou dans les puits d’accès à un stockage d’hydrocarbures, il est précieux de connaître la perméabilité de la formation ou de sa couverture en fonction de la profondeur, soit pour améliorer le modèle de réservoir, soit pour choisir les zones dans lesquelles procéder à des opérations spéciales.On propose une technique qui consiste à balayer la hauteur du découvert par une interface entre deux liquides de viscosités très contrastées. Le débit total qui pénètre la formation à chaque instant est ainsi une fonction de la position de l’interface et de l’historique des pressions dans le puits. On doit alors résoudre un problème inverse : rechercher la perméabilité fonction de la profondeur à partir de l’historique des débits dans le temps. Dans la pratique, le puits est équipé d’un tube central. Le balayage est effectué par injection d’un liquide à pression d’entrée constante dans le tube central et soutirage d’un autre liquide par l’espace annulaire. On mesure les débits d’injection et de soutirage dont la différence est le débit qui entre dans la formation.Pour valider et améliorer cette technique, on a d’abord utilisé une maquette simulant un découvert multi-couches disponible au LMS. On a exploité aussi des essais en place réalisés dans la couverture peu perméable d’un stockage souterrain de gaz. Dans ces essais, un liquide visqueux placé dans le découvert était déplacé par un liquide moins visqueux (méthode dite « opening »). Les couches plus perméables étaient correctement identifiées (Manivannan et al. 2017), mais une estimation quantitative était un défi en raison des phénomènes transitoires qui affectent le voisinage immédiat des puits. De plus, le rayon investigué dans le massif était petit.La thèse a relevé ces défis en proposant un essai légèrement différent et une nouvelle technique d’interprétation. Les essais avec une maquette modifiée ont montré la supériorité d’une méthode « closing » dans laquelle le puits est d’abord rempli du liquide le moins visqueux. On ménage une période de stabilisation avant l’injection du liquide visqueux pour réduire les effets transitoires ; elle permet aussi d’estimer la perméabilité moyenne et l’influence de la zone endommagée à la paroi (le « skin »).Puis on conduit l’essai proprement dit. L’historique des débits mesurés en tête de puits constitue le profil d’injection dont on déduit le profil de perméabilité.. Cette estimation suppose un écoulement monophasique dans chaque couche et la même « skin » pour toute la formation. Les incertitudes principales portent sur les pressions de formation et les variations possibles du « skin ». Elles sont estimées au moyen d’un calcul analytique. On a vérifié sur la maquette que les profils de perméabilité estimés présentent une bonne concordance avec les perméabilités mesurées avant les essais.On a réalisé un essai sur un sondage de 1750 m de long atteignant une couche de sel dont on a correctement estimé la perméabilité moyenne pendant la période de stabilisation. Toutefois elle était si faible (4.0E-21 m²) que l’utilisation de deux fluides n’a pas permis de faire une différence entre les diverses parties du puits. / In wells producing water, oil, gas or geothermal energy, or in access wells to hydrocarbon storage, it is critical to evaluate the permeability of the formation as a function of depth, to improve the reservoir model, and also to identify the zones where additional investigation or special completions are especially useful.A new technique is proposed, consisting of scanning the open hole (uncased section of the wellbore) with an interface between two fluids with a large viscosity contrast. The injection rate into the formation depends on interface location and well pressure history. An inverse problem should be solved: estimate permeability as a function of depth from the evolution of flow rates with time. The wells are usually equipped with a central tube. The scanning is done by injecting a liquid in the central tube at constant wellhead pressure. Injection and withdrawal rates are measured at the wellhead; the difference between these two rates is the formation injection rate.To validate and improve this technique, we used a laboratory model mimicking a multi-layer formation, already available at LMS. We also made use of in-situ tests performed on an ultra-low permeable cap rock above an underground gas storage reservoir. In these tests, a viscous fluid contained in the open hole was displaced by a less-viscous fluid (a method called opening WTLog). The more permeable layers were correctly identified (Manivannan et al. 2017), but a quantitative estimation was challenging due to transient phenomena in the vicinity of the wellbore (near-wellbore zone). In addition, the investigation radius was small.These challenges are addressed by proposing a slightly modified test procedure and a new interpretation workflow. Laboratory tests with a modified test setup showed the advantages of the ‘closing’ method in which the well is filled with a less-viscous fluid at the start of the test. We also added a stabilization period before the injection of viscous fluid to minimize the transient effects; this period is also used to estimate the average permeability of the open hole and the effect of near-wellbore damage (skin).Then the test proper is performed (closing WTLog). The injection profile of the less-viscous fluid is computed from the wellhead flow rate history. A permeability profile is estimated from the injection profile. The permeability estimation considers a monophasic flow in each layer and the same skin value for all the formation layers. Major uncertainties in the permeability estimates are caused by formation pressures and heterogeneities in skin values; they are estimated using an analytical formula. We have verified on the laboratory setup that the estimated permeability profiles are well correlated to the permeabilities measured before the tests.An attempt was made to perform a WTLog in a 1750-m long wellbore opening in a salt formation. The first phase was successful and the average permeability was correctly assessed. However, this permeability was so small (4.0E-21 m² or 4 nD) that the gauges and the flowmeters were not accurate enough to allow a clear distinction between the permeabilities of the various parts of the open hole.

Salzkavernen gelten als vielversprechende Möglichkeit Wasserstoff unter Tage zu speichern. Da aktuell keine Salzkaverne zur kommerziellen Wasserstoffspeicherung in Deutschland existiert, wurden Forschungsvorhaben initiiert, um offene Fragen in diesem Bereich zu klären. Die vorliegende Arbeit beschäftigt sich mit der Bestimmung der Dichtheit eines ausgewählten technischen Bohrungsbarriereelements: der letzten zementierten Rohrtour. Laborative Permeabilitätsmessungen stellen eine Möglichkeit dar, den Nachweis der Dichtheit zu erbringen. Zur Messung der Permeabilität werden zwei Versuchsanlagen gebaut, die auf einem instationären Messprinzip basieren. Mit Hilfe dieser Anlagen wird die Durchlässigkeit von Einzelmaterialproben und Verbundproben bestehend aus Steinsalz, Anhydrit, Zementstein und Futterrohr bestimmt und bewertet. Zur Auswertung der Versuche wird eine Software programmiert, die die eindimensionale Strömungsgleichung mit Hilfe der Finiten-Volumen-Methode numerisch löst. Die Arbeit beschreibt die weltweiten Erfahrungen im Bereich untertägiger Wasserstoffspeicherung. Weiterhin wird der Stand der Technik von Permeabilitätsmessungen dargestellt und die Eigenschaften des verwendeten Messverfahrens beschrieben. Mit Hilfe der Auswertung von Dichtheitstest kann gezeigt werden, dass die Anlagen zum Nachweis niedrigster Permeabilitäten geeignet sind. Das grundliegende mathematische Modell und dessen numerische Approximation wird hergeleitet. Die numerischen Fehler und der Modellfehler werden mit Hilfe einer Genauigkeitsanalyse bestimmt. Über die Analyse der Messunsicherheiten der Eingangsparameter erfolgt eine Abschätzung der Messunsicherheit der berechneten Permeabilität. Die Ergebnisse der Permeabilitätsmessungen zeigen, dass der untersuchte Zementstein dichte Verbunde mit Steinsalz und Futterrohr gegenüber Wasserstoff ausbilden kann. Als wichtigste Einflussgröße auf die Permeabilität wird der Effektivdruck identifiziert. Ein Einfluss der Messgase (Wasserstoff und Methan) auf das Strömungsverhalten kann, mit Ausnahme des Klinkenberg-Effekts, nicht nachgewiesen werden. Erfahrungen aus dem Bereich der Erdgasspeicherung sind prinzipiell auf die Wasserstoffspeicherung übertragbar. Die Ergebnisse der Untersuchungen sind in die Erstellung eines Leitfadens zur Errichtung von Wasserstoffkavernen für Genehmigungsbehörden und zukünftige Investoren eingeflossen.