The Azeri, Chirag, Gunashli (ACG) field is located offshore Azerbaijan. The reservoirs are multilayered sandstones forming traps within a major anticlinal structure. Proven crude oil reserves are estimated to contain 5.4 billion barrels of oil. In the past this area has been studied in regional detail but not at the reservoir scale with respect to the fluvio-deltaic sediments filling the northern shore of the ancient South Caspian Sea. The aim of this study is carried out the sedimentological, cyclostratigraphical analysis and reservoir characterization of Balakhany X Formation within the Productive Series which is considered to be one of the significant producing horizons. To be able to achieve this objective, a 30m thick section, which is mainly composed of siliciclastics, has been studied in detail on Balakhany X cores from C01 well Azeri field. In this study, detailed lithofacies analyses were performed and sandstone, mudstone, siltstone facies were recognized in the studied interval of the Balakhany X Formation. Litharenites and sublitharenites sandstones are the most abundant in the succession. Sedimentological analysis such as grain-size sphericity, provenance, XRD, SEM and grain surface texture were performed and their relationship with depositional environment were discussed. The grain size distribution of the samples along the succession shows distribution of fine to very fine sands. Sorting of sandstones ranges between moderately well to very well sorted. The provenance analysis of sandstones based on modal analysis of thin sections related to recycled orogen. According to interpretation of grain size parameters and grain surface textures analysis the main transporting agent of sands observed as wind, wave and river agents. High resolution cyclostratigraphy studies based on cm-m scaled cyclic occurrences of lithofacies along the measured section were performed. Milankovitch, sub-Milankovitch and millennial cycles were determined along the studied section. The petrophysical analysis revealed good to very good (18 to 24%) porosity and good permeability (10 to 538mD) in Balakhany X Formation. The porosity and permeability are affected by both textural and compositional controls. Grain size distribution along the reservoir section is fine to very fine sands. Influence of compaction was observed by the fractures and dissolutions on the sand grains. The calcite cement, grain-size variation, sorting and compaction are the main factors controlling porosity and permeability.

Two hydrogeologic models explore reflux dolomitization using two outcrop datasets at different scales to constrain transient boundary conditions and heterogeneous petrophysical properties. A platform-scale petrophysical model of the Permian San Andres Formation was built from outcrop and subsurface data following a reservoir modeling approach that preserves outcrop heterogeneity and incorporates a sequence stratigraphic framework. This model was used as input for hydrogeological simulations of hypersaline fluid flow and solute transport during the accumulation and compaction of the platform. Boundary conditions change over time, as relative sealevel fluctuations drive sedimentation, depositional environment migration, topographic gradients, and location, size and salinity of the brine source. The potential volume and distribution of dolomite formed is inferred by a magnesium mass-balance. The composite result of reflux events at various orders of stratigraphic hierarchy is a complex dolomite pattern that resembles that observed on San Andres outcrops. Dolostone bodies across the platform may be generated by different combinations of favorable conditions, including proximity to the brine source, zones of higher permeability, permeability contrasts, and latent reflux. A meter-scale reactive transport model of the Albian Upper Glen Rose Formation simulates deposition of three high-frequency cycles punctuated by three brine reflux events. The simulator determines flow, solute and reactive transport along the flow paths, revealing the spatial and temporal distribution of calcite dissolution, and precipitation of dolomite and sulfate. The model recreates fully and partially dolomitized cycles within the time and lithological constrains on Glen Rose outcrops. Our results show that the distribution of dolomite within a high-frequency cycle may be the net result of intercycle processes, whereby dolomitizing fluids sourced from younger cycles flow across stratigraphically significant boundaries. We also show that variations in dolomite abundance and the unfulfilled dolomitization potential control the contemporaneous propagation of multiple dolomite fronts and the coalescence of discrete dolomite bodies. Results show that reflux is an effective and efficient mechanism to dolomitize carbonate formations that progresses simultaneously with sediment accumulation. Dolomitization is the cumulative result of many short-lived reflux events, sourced in different locations and times, and amalgamation of successive dolostone bodies. This model contrasts with previous studies that approached dolomitization of a carbonate platform as a discrete reflux event and current interpretations that relate dolomite bodies to their most immediate stratigraphic surfaces. / text

Le Buntsandstein, localisé dans le graben du Rhin supérieur, apparait comme une cible intéressante pour la géothermie, associant une formation argilo-gréseuse à l’anomalie thermique régionale. Cette étude vise à caractériser les propriétés pétrophysiques de ces grès ainsi que la fracturation les affectant, dans le but de fournir un modèle conceptuel de la formation qui servira de guide pour son exploitation futur. Les faciès sédimentaires sont composés par cinq faciès pétrographiques (grès propres, grès à enrobage argileux, grès à matrice argileuse, grès silicifiés et grès à ciment carbonaté), qui se répartissent dans des proportions variables et contrôlent une partie des propriétés pétrophysiques mesurées à l’échelle matricielle. La comparaison des données pétrophysiques, des données macroscopiques issues d’une analyse de gradients de température, des données de modélisation et de la fracturation permet de construire un modèle de circulation dans le réservoir. Ces analyses mettent en avant le rôle de la zone endommagée des zones de faille pour le transfert de fluides à grande échelle, mais aussi celui de deux faciès sédimentaires : les grès déposés dans un environnement de Playa Lake et fluvio-éolien. L’analyse de différents affleurements montre que la fracturation évolue en fonction de la situation dans la pile sédimentaire et en fonction de la situation par rapport aux accidents tectoniques majeures. / The Buntsandstein, located in the Upper Rhine Graben, appears to be an easy target forgeothermal exploitation, linking sandstone and clay with the regional thermal anomaly. This study aims at characterizing petrophysical characteristics of these sandstones as well as the fracturation affecting them, with the intention of providing a conceptual model of the formation which will act as guide for future exploitation. The sedimentary facies are composed by five petrographical facies (clean sandstones, sandstones with clayed coating, clay matrix sandstones, silicified sandstones and carbonated matrix sandstones) which split with variable proportions and control a part of petrophysical properties measured at matrix scale. The comparison between petrophysical data, macroscopic data from temperature gradient analysis, modelling data and fracturing, allows the building of a Buntsandstein Sandstones fluids circulation conceptual model. This analysis points the role of the damage zone of fault zones for fluids transfer at large scale, but also that of two sedimentary facies: marginal erg and Playa Lake. The analysis of different outcrops shows that the fracturation evolves according to the situation in the sedimentary pile and according to the situation in comparison with major tectonic accidents.

A seqüência mesozóica da bacia de Ucayali é a maior produtora de gás e condensado do Peru. A área do trabalho, denominada Grande Camisea, fica na parte sul da bacia e, na atualidade, pertence à companhia Plupetrol Peru Corporation. Neste trabalho, foi aplicado um método de interpretação de perfis de indução em um poço petrolífero no sector San Martin do campo Camisea (QuickLook Interpretation method). O objetivo consiste na caracterização do reservatório de San Martín utilizando um método de interpretação rápida de perfis elétricos e, assim, fornecer uma visão geral no entendimento de parâmetros de poços e reservatórios, de zonas produtivas e suas características petrofísicas de porosidade e de saturação do óleo. Para validar a interpretação, foram utilizadas a descrição geológica de testemunhos e amostras de calha, descrição e informação do sistema petrolífero do campo e a geologia regional da zona de interesse da bacia. Desta forma, foi possível apresentar uma comparação entre os valores obtidos através dos métodos detalhados executados pela Pluspetrol e o método rápido de interpretação aplicado aqui, assim como o desvio entre ambos os resultados. / The Mesozoic sequence of the Ucayali basin is the main producer of gas and condensate of Peru. The work area is called Gran Camisea, located in the south part of the basin, and, in the present time, belongs to the company Plupetrol Peru Corporation. In this work, a well log interpretation method was used in a gas well in San Martin area, part of the Camisea field. The goal is the characterization of the reservoir of San Martín using a Quick Look log interpretation method, and thus to supply a general view in the understanding of well and reservoirs parameters, productive zones and its petrophysics characteristics of porosity and saturation. To validate the interpretation, besides using the geologic description of well cores and cutting sampling, it was used the description and information of the petroleum system of Camisea gas field and its regional geology. It was possible to present a comparison between Pluspetrol values, obtained through detailed methods, and those from the Quick Look log interpretation method used here, as well as an analysis of convergence between both results.

A seqüência mesozóica da bacia de Ucayali é a maior produtora de gás e condensado do Peru. A área do trabalho, denominada Grande Camisea, fica na parte sul da bacia e, na atualidade, pertence à companhia Plupetrol Peru Corporation. Neste trabalho, foi aplicado um método de interpretação de perfis de indução em um poço petrolífero no sector San Martin do campo Camisea (QuickLook Interpretation method). O objetivo consiste na caracterização do reservatório de San Martín utilizando um método de interpretação rápida de perfis elétricos e, assim, fornecer uma visão geral no entendimento de parâmetros de poços e reservatórios, de zonas produtivas e suas características petrofísicas de porosidade e de saturação do óleo. Para validar a interpretação, foram utilizadas a descrição geológica de testemunhos e amostras de calha, descrição e informação do sistema petrolífero do campo e a geologia regional da zona de interesse da bacia. Desta forma, foi possível apresentar uma comparação entre os valores obtidos através dos métodos detalhados executados pela Pluspetrol e o método rápido de interpretação aplicado aqui, assim como o desvio entre ambos os resultados. / The Mesozoic sequence of the Ucayali basin is the main producer of gas and condensate of Peru. The work area is called Gran Camisea, located in the south part of the basin, and, in the present time, belongs to the company Plupetrol Peru Corporation. In this work, a well log interpretation method was used in a gas well in San Martin area, part of the Camisea field. The goal is the characterization of the reservoir of San Martín using a Quick Look log interpretation method, and thus to supply a general view in the understanding of well and reservoirs parameters, productive zones and its petrophysics characteristics of porosity and saturation. To validate the interpretation, besides using the geologic description of well cores and cutting sampling, it was used the description and information of the petroleum system of Camisea gas field and its regional geology. It was possible to present a comparison between Pluspetrol values, obtained through detailed methods, and those from the Quick Look log interpretation method used here, as well as an analysis of convergence between both results.

A seqüência mesozóica da bacia de Ucayali é a maior produtora de gás e condensado do Peru. A área do trabalho, denominada Grande Camisea, fica na parte sul da bacia e, na atualidade, pertence à companhia Plupetrol Peru Corporation. Neste trabalho, foi aplicado um método de interpretação de perfis de indução em um poço petrolífero no sector San Martin do campo Camisea (QuickLook Interpretation method). O objetivo consiste na caracterização do reservatório de San Martín utilizando um método de interpretação rápida de perfis elétricos e, assim, fornecer uma visão geral no entendimento de parâmetros de poços e reservatórios, de zonas produtivas e suas características petrofísicas de porosidade e de saturação do óleo. Para validar a interpretação, foram utilizadas a descrição geológica de testemunhos e amostras de calha, descrição e informação do sistema petrolífero do campo e a geologia regional da zona de interesse da bacia. Desta forma, foi possível apresentar uma comparação entre os valores obtidos através dos métodos detalhados executados pela Pluspetrol e o método rápido de interpretação aplicado aqui, assim como o desvio entre ambos os resultados. / The Mesozoic sequence of the Ucayali basin is the main producer of gas and condensate of Peru. The work area is called Gran Camisea, located in the south part of the basin, and, in the present time, belongs to the company Plupetrol Peru Corporation. In this work, a well log interpretation method was used in a gas well in San Martin area, part of the Camisea field. The goal is the characterization of the reservoir of San Martín using a Quick Look log interpretation method, and thus to supply a general view in the understanding of well and reservoirs parameters, productive zones and its petrophysics characteristics of porosity and saturation. To validate the interpretation, besides using the geologic description of well cores and cutting sampling, it was used the description and information of the petroleum system of Camisea gas field and its regional geology. It was possible to present a comparison between Pluspetrol values, obtained through detailed methods, and those from the Quick Look log interpretation method used here, as well as an analysis of convergence between both results.

Orientador: Alexandre Campane Vidal / Dissertação (mestrado) - Universidade Estadual de Campinas, Faculdade de Engenharia Mecânic e Instituto de Geociências / Made available in DSpace on 2018-08-27T08:43:25Z (GMT). No. of bitstreams: 1 Melani_LeandroHartleben_M.pdf: 3371940 bytes, checksum: aa652f57862226b62a1290a140070c87 (MD5) Previous issue date: 2015 / Resumo: A análise petrofísica é essencial para caracterização de reservatórios de hidrocarboneto, fornecendo parâmetros para avaliação do potencial econômico do campo. Este estudo foi realizado em um reservatório carbonático fraturado da Formação Quissamã, Bacia de Campos, composto predominantemente por calcarenitos e calcirruditos da Formação Quissamã, o qual foi denominado de Campo B. Este reservatório é essencialmente microporoso, com porosidade média a alta (15-30%) e, em geral, apresenta baixa permeabilidade de matriz (0,1-10 mD). As relações petrofísicas podem ser bastante complexas em reservatórios carbonáticos, em função da maior heterogeneidade na distribuição de fácies e porosidade nestas rochas. O grau de complexidade torna-se ainda mais elevado para o caso de reservatórios fraturados. Foi desenvolvido neste estudo um fluxo de trabalho para caracterização petrofísica da matriz deste reservatório carbonático, através da utilização de dados de perfis elétricos e de plugues. O objetivo do trabalho foi identificar possíveis comportamentos de fluxo distintos e definir regiões do campo com provável contribuição de fluxo intergranular. Para isto, é indispensável entender a relação entre os controles geológicos e o comportamento dinâmico do reservatório. A partir da análise das propriedades petrofísicas da matriz foram reconhecidas duas regiões do reservatório com comportamentos de fluxo distintos, diretamente influenciados pela heterogeneidade do sistema poroso. Na área sul foi constatado baixíssima permeabilidade de matriz, decorrente do amplo predomínio de microporosidade, que confere esta característica de fluxo às rochas. Na área norte foram observados os melhores índices de permeabilidade de matriz para o campo, associados à contribuição de fluxo intergranular, devido à preservação de porções significativas de macroporosidade original. As altas taxas de produtividade registradas nos dados de produção para poços da região sul indicam a presença de fraturas. O sistema de fraturas tem pequeno impacto sobre a porosidade total deste reservatório, porém tem grande contribuição para o regime de fluxo, desempenhando um importante papel na produção comercial do campo. Foi investigado também o impacto associado aos parâmetros de Archie - coeficientes de cimentação (m) e saturação (n) - no cálculo de saturação de água (Sw) para este reservatório carbonático fraturado. Para investigar este impacto foram gerados e comparados quatro cenários de Sw baseados em valores de m e n distintos. Foram realizadas três análises principais: (I) valores de Sw e espessura porosa com óleo (HPhiSo) foram comparados para cada cenário. Os resultados mostraram considerável variação nos valores obtidos para ambos os parâmetros (Sw - HPhiSo). (II) Análise baseada nos valores de corte e Net Pay. Foi observado que os valores de corte devem ser redefinidos de acordo com a variação da curva de saturação de água, para que seja mantida a mesma espessura de Net Pay em um dado reservatório. (III) Análise da influência dos valores de corte individual e global na variação de espessura de Net Pay foi avaliada para todos os poços para o cenário C2. Variações pequenas indicam que um valor de corte global é válido para este campo. Os resultados do estudo mostram que valores imprecisos dos parâmetros de Archie podem conduzir a erros na avaliação de reservas / Abstract: Petrophysical analysis plays a vital role in reservoirs characterization, providing parameters to assess the economic potential of the field. This study was performed in a fractured carbonate reservoir of Quissamã Formation, Campos Basin, mostly composed of calcarenites and calcirudites of Quissamã Formation, which it was named Field B. This reservoir is essentially microporous, characterized by medium to high porosity (15-25%) and, in general, low matrix permeability (0.1-10 mD). The petrophysical relationships can be considerably complex in carbonate reservoirs, due to the greater heterogeneity in facies and porosity distribution of these rocks. The complexity became even higher in particular case of fractured reservoirs. It was developed in this paper a general workflow for petrophysical characterization of this Albian carbonate reservoir, using well log data and plugs samples. The goals of this paper were to identify different flow behaviors and to define areas of the field with possible intergranular flow contribution. It is extremely important therefore to understand the relationship between the geological controls and the dynamic behavior of the reservoir. The petrophysical analysis of matrix properties enabled to recognize two reservoir zones with distinct flow behaviors, directly influenced by the porous system heterogeneity. In the southern area it was found very low matrix permeability, due to the large occurrence of microporosity. In the northern area it were found the best matrix permeability values of B Field, related to the contribution of intergranular flow due to the original macroporosity preservation. The high initial production rates obtained from production data of wells located in the southern portion indicate the presence of fractures. The fracture system has a small impact on the percentage of total reservoir porosity, but it has a large contribution to the flow domain, playing an important role in the commercial production of the field. It was also investigated the impact associated with Archie?s parameters - Cementation Factor (m) and Saturation Exponent (n) - in the determination of water saturation (Sw) in this fractured carbonate reservoir. To investigate this impact, four Sw scenarios were generated by applying different m and n values and compared with one another. Three main analyses were performed according to m and n variations: (I) the average values of Sw and Hydrocarbon Pore Volume Height (HPhiSo) were compared for each scenario. The results showed a considerable variation in the average values for both. (II) The second analysis was based on the cut-off and Net Pay values. The results showed that cut-off values must be changed according to the variation given by a water saturation curve, whatever the Sw scenario, in order to keep the same Net Pay values. (III) The differences between global and individual cut-offs on Net Pay thickness were analyzed for all wells for the scenario C2. Insignificant variations indicate that a global cut-off value is acceptable for this field. The results show that inaccurate values of Archie?s parameters can lead to gross errors in reserves evaluation / Mestrado / Reservatórios e Gestão / Mestre em Ciências e Engenharia de Petróleo

Les carottes, extraites lors des forages de puits de pétrole, font partie des éléments les plus importants dans la chaîne de caractérisation de réservoir. L’acquisition de celles-ci à travers un scanner médical permet d’étudier de façon plus fine les variations des types de dépôts. Le but de cette thèse est d’établir les liens entre les imageries scanners 3D de carottes, et les différentes propriétés pétrophysiques et géologiques. Pour cela la phase de modélisation des images, et plus particulièrement des textures, est très importante et doit fournir des descripteurs extraits qui présentent un assez haut degrés de confiance. Une des solutions envisagée pour la recherche de descripteurs a été l’étude des méthodes paramétriques permettant de valider l’analyse faite sur les textures par un processus de synthèse. Bien que ceci ne représente pas une preuve pour un lien bijectif entre textures et paramètres, cela garantit cependant au moins une confiance en ces éléments. Dans cette thèse nous présentons des méthodes et algorithmes développés pour atteindre les objectifs suivants : 1. Mettre en évidence les zones d’homogénéités sur les zones carottées. Cela se fait de façon automatique à travers de la classification et de l’apprentissage basés sur les paramètres texturaux extraits. 2. Établir les liens existants entre images scanners et les propriétés pétrophysiques de la roche. Ceci se fait par prédiction de propriétés pétrophysiques basées sur l’apprentissage des textures et des calibrations grâce aux données réelles. . / Cores extracted, during wells drilling, are essential data for reservoirs characterization. A medical scanner is used for their acquisition. This feature provide high resolution images improving the capacity of interpretation. The main goal of the thesis is to establish links between these images and petrophysical data. Then parametric texture modelling can be used to achieve this goal and should provide reliable set of descriptors. A possible solution is to focus on parametric methods allowing synthesis. Even though, this method is not a proven mathematically, it provides high confidence on set of descriptors and allows interpretation into synthetic textures. In this thesis methods and algorithms were developed to achieve the following goals : 1. Segment main representative texture zones on cores. This is achieved automatically through learning and classifying textures based on parametric model. 2. Find links between scanner images and petrophysical parameters. This is achieved though calibrating and predicting petrophysical data with images (Supervised Learning Process).

La compréhension d'un système pétrolier nécessite la caractérisation pétrographique de tous les éléments et les processus le composant. Dans ce travail, plusieurs exemples de roches mères, roches réservoirs et roches couvertures provenant de bassins pétroliers différents, ont été étudiés afin de décrire les méthodes pétrographique classiques et mettre en place des nouvelles. Ces dernières telles que : la création d'une cinétique de transformation d'un kérogène composé de deux types de matière organiques (programmation), analyse macérale et l'étude des microfractures par analyse d'images, la diffraction à rayon X ainsi que la tomographie ont permis la caractérisation de la roche mère. Quant aux roches réservoirs, les méthodes d'analyse d'image des propriétés pétrophysiques, la microscopie MSCL ainsi que les paramètres de mouillabilité permettent la description de la qualité de ces réservoirs et leurs préservations au cours du temps à cause des phénomènes de recristallisation, dissolution, circulation de fluide et de réaction TSR/BSR. Les roches couvertures étudiées dans ce travail sont celles des argilites callovo-oxfordienne, utilisant la diffraction à rayon X ainsi que l'analyse d'image et la tomographie. Ces méthodes ont facilité la compréhension de leurs comportements au cours du temps, leurs capacités de sorption/désorption et leurs fiabilités de stockage de déchets nucléaire. Enfin, la modélisation pétrolière avec Petromod permet de déterminer les fonctionnements des systèmes pétroliers. La modélisation par percolation est plus proche de la réalité des bassins pétroliers que celle de Darcy/Hybride / Understanding oil systems requires petrographic characterization of all elements and process that compose it. In this work, several examples of source rocks, reservoir rocks and seal from different petroleum basins have been studied in order to describe conventional petrographic methods and develop new ones. The new ones as: a program of transformation kinetic of kerogene composed of two types of organic matter, maceral analysis and microfractures study using images analysis, the diffraction X-ray and tomography allowed source rock description. As for, reservoir rocks, methods of petrophysical characterization by images analysis, MSCL Microscopy and wettability parameters permit reservoir quality description and their preservation over time due to recrystalization and dissolution phenomena, fluid flow and TSR/BSR reaction. The cap rocks studied in this thesis are those of Callovo-Ordovician argillites, using X-Ray diffraction as well as images analysis and tomography. Those methods facilitated the understanding of argillites behavior over time, their sorption/desorption ability and their reliability of nuclear waste storage. Finally, Modeling using Petromod helps to determine petroleum systems functioning. Modeling by percolation method gives results closer to oil basins reality, than by Darcy/Hybrid method

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.