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Hydrocarbon play assessment of any hydrocarbon reservoir unit depends on the porosity, permeability, hydrocarbon saturation and water saturation of petrophysical model distributions and seismic reflections of reservoir rocks. The objective of the study is to resolve the ambiguities that are associated with hydrocarbon play assessment of an X-field in the Niger Delta basin. This was achieved through the use of pre-conditioned attributes, fault delineating seismic attributes such as coherence, variance and quantitative definition of the reservoir units of petrophysical model distributions, through the adoption of an integrated methodology of 3D seismic and well log data. A quick look examination of the well log signatures revealed numerous reservoir sand units, but only three hydrocarbon-bearing reservoir sands were of interest to us (RS1, RS2 and RS3). From the quantitative interpretation of well logs, the three identified reservoir sands were evaluated in terms of porosity, permeability, hydrocarbon saturation, shale volume, movable hydrocarbon index and water saturation. Effective porosity values of 24.56, 23.01 and 24.00% were obtained for Well 1, Well 2 and Well 4, respectively. This supports the known or already established porosity range of Agbada Formation of Niger Delta with range 28–32%. The hydrocarbon saturation for RS2 is 68.51% for Well 4, for RS3 72.49% for Well 3 and for RS2 74.16% and for RS3 77.34% for Well 2. RS2 of 79.51% and RS3 of 80.99% for Well 1 were obtained. This shows how prolific the reservoir sand units are with hydrocarbon accumulation tendencies. Structural analysis revealed a highly faulted system that depicts a typical tectonic setting of the Niger Delta basin, and the computed attributes like coherence, and variance shows an optimum visualization of the faulting system. This implies that the trapping mechanism of the field is of both anticlinal and fault-assisted closure and also the viability of the reservoir units is high from the computed petrophysical parameters.

A reservoir characterization study, using petrophysical and petrographic analyses, has been made on the Paleocene Farewell Formation in the Taranaki Basin, New Zealand, based on five selected wells. Farewell Formation is largely a sandstone formation belonging to the Kapuni Group. The integrated study has shown that Farewell Formation is a good promising reservoir with average effective porosity of 17.7% and permeability of 415 mD. The petrographic study indicates the occurrence of abundant intergranular and secondary pores. It also proved that the Farewell Formation has been affected by several diagenetic features. Compaction, cementation and clay mineral authigenesis are the most common. Quartz and feldspar overgrowths have been recorded in many samples, and secondary porosity due to dissolution is also observed. In general, good reservoir quality features are dominant in the Farewell Formation and diagenesis has little effect on the reservoir quality. These findings are supported by well log interpretation results, which confirm good sand and net pay zones are available with very low average water saturation (24.9%).

The need of hydrocarbon producing countries to increase reserves has led energy companies to explore the deposits available in source rocks that might be over-pressured and thus, strict rules are required for their development. Overpressure, which may result in wellbore stability problems, could result from several causes such as mechanical effects, dynamic transfer, chemical stress, thermal stress, among others, in which undercompaction is frequently the main cause, generated when the sediment deposition velocity exceeds the fluid ejection rate. The expansion of fluids generated by thermal stresses and the reduction of porosity caused by chemical stresses may be among the other causes of overpressure in shales. The new methodology presented in this paper makes it possible to determine the pressure due to thermal stresses caused by the cracking of kerogen and oil in shales. In addition, petrophysical and geochemical models are considered in order to precisely ascertain the increase in pore pressure due to temperature and fluid expansion. An increase of 20% in pressure is seen when compared with undercompaction. As a result of this methodology, the mud window was optimized and the hydrocarbons, generated under subsurface the conditions (pressure, temperature) analysed, were quantified. RESUMEN La necesidad de los países productores de hidrocarburos por incrementar sus reservas, ha conducido a las empresas del sector energético a explorar los yacimientos de roca generadora, los cuales, pueden estar sobrepresionados, obligando a establecer reglas estrictas para su desarrollo. Problemas de estabilidad de pozos pueden ser generados por esta sobrepresión, que es causada por esfuerzos mecánicos, la transferencia dinámica, esfuerzos químicos, termales, entre otros; siendo la sub-compactación la causa principal, generada cuando la velocidad de deposición del sedimento excede la velocidad de expulsión del fluido. Específicamente, al estudiar los Shales se deben incluir causas adicionales que propician tal sobrepresión, entre estas causas se puede citar, la expansión de fluidos generada por los esfuerzos térmicos y la reducción de la porosidad causada por esfuerzos químicos. Este trabajo presenta una metodología novedosa, que permite determinar la presión de poro incluyendo los esfuerzos térmicos originados por el craqueo del kerógeno y el aceite en el shale. Además, considera el acople de los modelos petrofísico y geoquímico, con la finalidad de conocer en profundidad el incremento de la presión de poro, debido a la temperatura y la expansión de fluidos. Como resultado, se evidencia un aumento de la presión de poro del 20%, en comparación a sólo considerarse la sub-compactación como variable de influencia. Con esta metodología se optimizan las ventanas de estabilidad y se cuantifican los hidrocarburos que pudieron generarse bajo las condiciones de presión y temperatura analizadas.

Orientador: Érika Tomie Koroishi Blini Dissertação (mestrado) - Universidade Estadual de Campinas, Faculdade de Engenharia Mecânica e Instituto de Geociências Resumo: Os reservatórios naturalmente fraturados apresentam desafios devido a coexistência de dois meios distintos (matriz e fratura). Neste tipo de reservatório, não apenas as características intrínsecas das fraturas e das matrizes devem ser caracterizadas, mas também as interações entre esses dois meios devem ser modeladas com precisão. A presença de fraturas conectadas e permeáveis fornece um caminho preferencial de fluxo, dificultando a recuperação de óleo presente na matriz, resultando em baixos fatores de recuperação. No entanto, boas recuperações finais podem ser obtidas, desde que se otimize a vazão de injeção e se gerencie adequadamente a produção de água. Neste trabalho, uma nova metodologia experimental para a preparação do meio poroso com fratura induzida foi desenvolvida com o objetivo de estudar o efeito da vazão de injeção na recuperação de óleo em reservatórios carbonáticos naturalmente fraturados. Para isso, três rochas carbonáticas de um reservatório do pré-sal brasileiro foram utilizadas. As amostras foram cortadas com uma serra metálica, sendo cada metade referente às matrizes. Para a representação da fratura foi utilizado um espaçador POM (Lie, 2013). Esferas de vidro foram utilizadas para preencher as grades do espaçador, com o intuito de criar meios porosos artificiais. A porosidade e a permeabilidade das matrizes, da fratura e do modelo (matrizes e fratura) foram determinadas com porosímetro e permeabilímetro a gás. Para o estudo da influência da vazão de injeção foram feitos três ensaios de deslocamento. A amostra do primeiro e do terceiro ensaio foi preparada de modo a apresentar uma saturação inicial de água. Esse processo foi feito por deslocamento forçado a vácuo no coreholder. No segundo ensaio, a amostra foi completamente saturada com óleo. As três amostras foram envelhecidas para simular as condições de reservatório. Nos ensaios, durante a injeção de água do mar sintética nas amostras envelhecidas, utilizaram-se duas vazões de injeção, uma alta (0,1 ml/min) e uma baixa (0,05 ml/min), para cada amostra. Na primeira amostra, a injeção foi iniciada a alta vazão e, após três semanas, diminuiu-se para a baixa. Na segunda e terceira amostra, a injeção foi iniciada a baixa vazão e posteriormente foi aumentada. Tomografia computadorizada de raios-X foi utilizada no primeiro e terceiro ensaio para observar a distribuição da porosidade e das saturações no meio poroso. Conseguiu-se estudar o efeito da vazão de injeção num meio poroso fraturado de forma muito mais próxima do presente no reservatório, com uma pressão de soterramento e de poros, de uma temperatura e uma molhabilidade tendendo a preferencial ao óleo. Os resultados mostraram que não foi possível associar um aumento da recuperação de óleo com a baixa vazão injeção nos meios porosos com fratura induzida representativos dos reservatórios carbonáticos do pré-sal brasileiro em estudo Abstract: Naturally fractured reservoirs present challenges due to the coexistence of two distinct media (matrix and fracture). In this type of reservoir, not only the intrinsic characteristics of fractures and matrices should be characterized, but also the interactions between these two media must be accurately modeled. The presence of connected fractures provides a preferential flow path, making it difficult to recover the oil present in the matrix, resulting in low recovery factors. However, good final recoveries can be obtained, if the injection flow rate is optimized, and the water production is properly managed. In this work, a new experimental methodology for porous media preparation with induced fracture was developed aiming to study the effect of the injection flow rate on oil recovery in naturally fractured carbonate reservoirs. For this, three carbonate rocks from a Brazilian pre-salt reservoir were used. The samples were cut with a metal saw, each half being the matrices. A POM spacer was used to represent the fracture (Lie, 2013). Glass beads were used to fill the spacer grids in order to create artificial porous media. The porosity and permeability of the matrices, the fracture and the model (matrices and fracture) were determined with a gas porosimeter and permeabilimeter. For the study of the injection flow rate, three displacement tests were performed. The sample from the first and third test was prepared with an initial water saturation. In the second test, the sample was completely saturated with oil. The three samples were aged to simulate the reservoir conditions. In the tests, two injections flow rate, one high (0.1 ml/min) and one low (0.05 ml/min), were used for each sample during the synthetic sea water injection into the aged samples. In the first sample, the injection was started at high flow rate and, after three weeks, decreased to low. In the second and third sample, the injection was started at low flow rate and then increased. X-ray computed tomography was used in the first and third tests to evaluate the porosity and saturation distribution in the porous medium. It was possible to study the effect of the injection flow rate on a fractured porous media much closer to the present in the reservoir, with an overburden and pore pressure, a temperature and a wettability tending to preferential to the oil. The results showed that it was not possible to associate an increase on oil recovery with the low injection flow rate in the porous media with induced fracture representative of the Brazilian pre-salt carbonate reservoirs under study Mestrado Reservatórios e Gestão Mestra em Ciências e Engenharia de Petróleo

Steam‐driven eruptions, both phreatic and hydrothermal, expel exclusively fragments of non‐juvenile rocks disintegrated by the expansion of water as liquid or gas phase. As their violence is related to the magnitude of the decompression work that can be performed by fluid expansion, these eruptions may occur with variable degrees of explosivity. In this study we investigate the influence of liquid fraction and rock petrophysical properties on the steam‐driven explosive energy. A series of fine‐grained heterogeneous tuffs from the Campi Flegrei caldera were investigated for their petrophysical properties. The rapid depressurization of various amounts of liquid water within the rock pore space can yield highly variable fragmentation and ejection behaviors for the investigated tuffs. Our results suggest that the pore liquid fraction controls the stored explosive energy with an increasing liquid fraction within the pore space increasing the explosive energy. Overall, the energy released by steam flashing can be estimated to be 1 order of magnitude higher than for simple (Argon) gas expansion and may produce a higher amount of fine material even under partially saturated conditions. The energy surplus in the presence of steam flashing leads to a faster fragmentation with respect to gas expansion and to higher ejection velocities imparted to the fragmented particles. Moreover, weak and low permeability rocks yield a maximum fine fraction. Using experiments to unravel the energetics of steam‐driven eruptions has yielded estimates for several parameters controlling their explosivity. These findings should be considered for both modeling and evaluation of the hazards associated with steam‐driven eruptions., Key Points Experimental studies to unravel the steam‐driven eruption energeticsInfluence of liquid fraction and rock petrophysical properties on the explosive energySteam flashing results in a faster fragmentation with respect to gas expansion and into higher ejection velocities of fragmented material

Geological and petrophysical parameters are critical in evaluating the production potential of prospective shale gas plays and their economic viability for commercial development. However, based on the US experience, these characteristics can vary widely. Furthermore, the non-marine shale plays of the Cooper Basin, South Australia are distinctively different from the marine shale plays in the US. Non-marine shale may consist of higher clay content and, thus, may be less responsive to hydraulic fracturing due to the increased ductility. Conversely, the availability of sufficient amounts of quartz and siderite may counteract this effect and maintain brittleness. In this study, the mineral, total organic and gas content, thermal maturity, Poisson's ratio and Young's modulus data obtained from the Roseneath and Murteree formations of the Cooper Basin have been compared with US shale formations. The results show that the formations compare well in terms of thickness, thermal maturity, Young's modulus and Poisson's ratio, but not in clay mineral content and formation temperature and values for TOC, porosity and gas-in-place are comparatively lower. To determine whether such plays are economically viable will require technical, as well as economic, analysis of the hydraulic fracturing process, including the potential for horizontal and vertical well development or basin centred gas developments. A shale play that has unfavourable prospects may have upfront infrastructure and major capital costs that outweigh the potential receipts from gas production. Beach Energy, South Australia

Submitted by Jesiel Ferreira Gomes (jesielgomes@ufcg.edu.br) on 2018-04-17T20:50:16Z No. of bitstreams: 1 CAYO CÉSAR CORTEZ PONTES – DISSERTAÇÃO (PPGEPM) 2017.pdf: 8158516 bytes, checksum: db5e0ee4565586d1704ae50ddc242d41 (MD5) Made available in DSpace on 2018-04-17T20:50:16Z (GMT). No. of bitstreams: 1 CAYO CÉSAR CORTEZ PONTES – DISSERTAÇÃO (PPGEPM) 2017.pdf: 8158516 bytes, checksum: db5e0ee4565586d1704ae50ddc242d41 (MD5) Previous issue date: 2017-02-23 Bandas de deformação são estruturas rúpteis que ocorrem em arenitos porosos e podem alterar as propriedades físicas, comportamento mecânico e hidráulico das rochas, resultando na compartimentação de reservatórios. O objetivo deste trabalho foi compreender a variação das propriedades de Resistência à Compressão Uniaxial (UCS), porosidade, Razão de Poisson, Módulos de Young e incompressibilidade nos diferentes elementos arquiteturais da zona de falha: protólito não deformado, zona de dano e núcleo da falha. Para isso realizamos perfis para medição de parâmetros estruturais e geomecânicos com auxílio do esclerômetro (Schmidt Hammer), análises laboratoriais de porosidade, tanto por meio digital em seção delgada como por permoporosímetro a gás, cálculos dos módulos de Young, incompressibilidade e Razão de Poisson. Os resultados indicam que no afloramento correspondente ao núcleo da falha os valores de UCS foram até três vezes maiores que aqueles na zona de dano e quatro vezes maiores que a zona não deformada. A porosidade apresenta decréscimo médio de 10% na zona de dano e até 75% no núcleo da falha. A porosidade estimada por medições em permoporosímetro a gás, módulos de Young, incompressibilidade e Razão de Poisson foram calculados no núcleo da falha. Nesse elemento arquitetural as zonas com bandas possuem resistência até duas vezes maior que a zona sem banda, com efeito no módulo de Young e no módulo de incompressibilidade, porém ambas com deformação ocorrida em caráter rúptil, evidenciado pelo atributo Razão de Poisson. Concluímos assim que bandas de deformação afetam diretamente as propriedades físicas de arenito em diferentes níveis de intensidade. A ocorrência de tais heterogeneidades podem ter impactos importantes na produção já que impõe anisotropias aos reservatórios. Deformation bands are brittle structures that occur in porous sandstones and may change the physical properties, geomechanical and hydraulic behavior of the rock, leading to the compartmentation of reservoirs. The objective of this research was to understand the variation of the properties of uniaxial compressive strength (UCS), porosity, Poisson’s ratio, Young’s and incompressibility’s modulus in different architectural elements of fault zone: protolith, damage zone and fault core. For this we extracted profiles for the measurement of structural and geomechanics with aid of Schmidt hammer, laboratorial analysis of porosity, both thin section digital means and by gas permoporosimeter, and Young’s, incompressibility and Poisson’s ratio calculations. The results indicate that in outcroup corresponding to the nucleus of fault the UCS values were up to three times higher than those in the damage zone and four times higher than the protolith. The porosity shows an average decrease of 10% in the damage zone and up to 75% in the fault core. Porosity by gas, Young’s and incompressibility modulus and Poisson’s ratios was calculated in core fault. In this architectural element with bands have resistance up to twice times than zone without bands, marked in the Young’s mo dulus as well as the incompressibility’s modulus, however both with deformation occurring in a brittle character, evidenced by Poisson’s ratio. We conclude that deformation bands directly affect the physics properties of sandstones in different levels of intensity. The occurrence of such heterogeneities may have important impacts on the production since it imposes anisotropies to the reservoirs.

Submitted by MILENA CRISTINA ROSA null (mcr.geol@gmail.com) on 2016-11-14T15:14:03Z No. of bitstreams: 1 Dissertacao_Rosa_Milena.pdf: 19467400 bytes, checksum: fa91b5605b8ee38726bb63bf4d4271da (MD5) Approved for entry into archive by Felipe Augusto Arakaki (arakaki@reitoria.unesp.br) on 2016-11-17T15:10:31Z (GMT) No. of bitstreams: 1 rosa_mc_me_rcla.pdf: 19467400 bytes, checksum: fa91b5605b8ee38726bb63bf4d4271da (MD5) Made available in DSpace on 2016-11-17T15:10:31Z (GMT). No. of bitstreams: 1 rosa_mc_me_rcla.pdf: 19467400 bytes, checksum: fa91b5605b8ee38726bb63bf4d4271da (MD5) Previous issue date: 2016-09-20 Conselho Nacional de Desenvolvimento Científico e Tecnológico (CNPq) Na Bacia de Campos, os reservatórios carbonáticos da Formação Coqueiros do Grupo Lagoa Feia, de idade eobarremiana-neoaptiana, representaram grandes e importantes descobertas de campos produtores de hidrocarbonetos na década de 70. O avanço dos conceitos geodinâmicos e geotectônicos sobre as novas e potenciais acumulações na seção rifte das Bacias Marginais Brasileiras, a partir de 2007, retomaram os reservatórios formados por rochas carbonáticas como atrativos alvos de estudos, devidos principalmente a grande importância econômica atribuída a esses reservatórios. O principal objetivo deste trabalho foi compreender a distribuição das propriedades físicas dos reservatórios carbonáticos formados por depósitos do tipo coquinas (rudstones e grainstones de moluscos bivalves) e definir os principais fatores petrofísicos que caracterizam os níveis-reservatório (e.g. densidade, índice de radioatividade, composição mineralógica e de rocha, etc.) e os fatores que controlariam a qualidade do mesmo (e.g. porosidade, saturação de água e permeabilidade) com o intuito de compreender a distribuição geométrica do seu sistema permo-poroso. O presente estudo fez uso de métodos geológicos/geofísicos, como interpretação estratigráfica de perfis de poços, cálculos petrofísicos, interpretação de dados sísmicos 3D e interpretação e correlação de atributos sísmicos. Dentre os resultados obtidos, a análise estratigráfica permitiu definir os limites de sequências, em ciclos de 3°ordem, das quatro sequências deposicionais (Sequência Clástica Basal; Sequência Talco-Estevensíta; Sequência das Coquinas e Sequência Clástica-Evaporítica) que compõem o Grupo Lagoa Feia. A Sequência das Coquinas, que é o foco deste estudo, apresenta uma divisão, interna aos seus depósitos de coquinas, em seis níveis-reservatórios (um na Coquina Superior e cinco na Coquina Inferior) onde os limites estratigráficos estão associados a ciclos de 4°ordem. A análise petrofísica indicou que o principal nível produtor na área está na Coquina Inferior 4 (CI-4), e é o que apresenta as melhores respostas de espessura (35 à 100 m) e altas qualidades potenciais de reservatório para o Campo de Linguado (valores médios de Igr = 0,1; PHIE = 11%, Sw ≤ 18%), enquanto que no Campo de Pampo, os níveis CI-4 (valores médios de Igr = 0,15; PHIE = 7,5%, Sw ≤ 30%) e CI-2 (valores médios de Igr = 0,13; PHIE = 7%, Sw ≤ 26 %) apresentam potencial para reservatório. Finalmente, a análise dos mapas, construídos com a integração da informação de poço e os atributos sísmicos, mostra uma distribuição da propriedade PHIE, para o nível-reservatório CI-4, com alta influência da estruturação tectônica, indicando os mais altos valores seguindo as principais estruturas com direção NW-SE. O controle deposicional é um importante condicionante da qualidade permo-porosa, nesse principal nível-reservatório, isso porque a tectônica ativa e intermitente proporcionou a abertura de espaços de acomodação e a formação de barreiras que atuaram na seleção das fácies de alta energia, no acúmulo, no retrabalhamento e na consequente formação e preservação das melhores condições para a formação desses reservatórios. No entanto, para o nível-reservatório Coquina Superior (CS) a distribuição da propridade PHIE mostra que a tectônica-estrutural não influencia no seu sistema permo-poroso e consequente qualidade desse nível-reservatório, assim como na distribuição de suas espessuras. Tal análise nos leva a conclusão de que os fatores deposicionais como as oscilações climáticas foram os responsáveis na seleção e no retrabalhamento para a formação dos bancos de coquinas, assim como, os processos diagenéticos foram os que, possivelmente, mais influenciaram na distribuição permo-porosa dos níveis-reservatório superiores. In the Campos Basin, the eobarremian-neoaptian carbonate reservoirs from Coqueiros Formation, Lagoa Feia Group, represented large and important discoveries of hydrocarbon fields in the 70´s. The advances in geodynamic and geotectonic concepts about new and potential accumulations on rift section of Marginal Brazilian Basins, from 2007, brought again the carbonate reservoirs rocks as attractive studies targets, mainly due to great economic importance attached to these reservoirs. The main objective was to understand the distribution of physical properties on carbonate reservoirs composed by coquinas deposits (rudstones and grainstones of bivalve molluscs), define the main petrophysical factors that characterize those reservoir levels (eg density, radioactivity content, mineralogical and rock composition, etc.) and factors that could control the quality (eg, porosity, water saturation and permeability) in order to understand the geometric distribution of its permo-porous system. This study employed geological/geophysical methods such as well logs stratigraphic interpretation, petrophysical calculations, 3D seismic interpretation and seismic attributes interpretation and correlation. Among the results, the stratigraphic analysis has identified limits, in 3 rd order cycles, to four depositional sequences (Basal Clastic Sequence, Talc-Stevensitic Sequence; Coquinas Sequence and Clastic-Evaporitic Sequence) that belong to Lagoa Feia Group. The Coquinas Sequence, focus of this work, shows a split, internally to its coquinas deposits in six reservoir levels (one in Upper Coquina and five in the Lower Coquina) where the stratigraphic limits are associated with 4 th order cycles. The petrophysical analysis indicated that the main producer level are at Lower Coquina 4 (CI-4), with the best thickness responses (35 to 100 m) and high potential reservoir qualities for Linguado Field (average values of Igr = 0,10; PHIE = 11%, Sw ≤ 18%), while in Pampo field, CI-4 level (average values of Igr = 0,15; PHIE = 7.5%, Sw ≤ 30%) and CI-2 level (average values of Igr = 0,13; PHIE = 7%, Sw ≤ 26%) have both reservoir potential. Finally, the map analysis, built with integration of well information and seismic attributes, shows a distribution of PHIE for CI-4 with high tectonicstructural influence, indicating higher values following the main structures with NW-SE direction. The depositional control is an important determinant of permo-porous system quality at CI-4 level, the main reservoir level, it is because the active and intermittent tectonic afforded the opening of depositional spaces and the formation of barriers to act on selection of high-energy facies, accumulation, reworking and consequent generation and preservation of the best conditions for reservoirs best quality. However, the Upper Coquina level reservoir distribution of PHIE shows that tectonic-structural does not influence its permo-porous system and reservoir quality, as well as the distribution of its thickness. This analysis leads us to the conclusion that the depositional factors, such as climatic variations were responsible to the selection and reworking of coquinas banks, as well as diagenetic processes were possibly most influenced the permo-porous system distribution on higher reservoir levels. CNPq: 134409/2014-0

The aim of this article is to provide a qualitative and quantitative description of Lower&ndash, Upper Cretaceous detrital rocks (Escucha and Utrillas sandstones) in order to explore their potential use as CO2 reservoirs based on their petrographic and petrophysical characteristics. Optical microscopy (OpM) and scanning electron microscopy (SEM) aided by optical image analysis (OIA) were used to get qualitative and quantitative information about mineralogy, texture and pore network structure. Complementary analyses by X-ray fluorescence (XRF) and X-ray diffraction (XRD) were performed to refine the mineralogical information and to obtain whole rock geochemical data. Furthermore, mercury injection capillary pressure analysis (MICP), the gas permeameter test (GPT) and the hydraulic test (HT) were applied to assess the potential storage capacity and the facility of fluid flow through the rocks. Both of these factors have an outstanding importance in the determination of CO2 reservoir potential. The applied petrophysical and petrographic methods allowed an exhaustive characterization of the samples and a preliminary assessment of their potential as a CO2 reservoir. The studied conglomerates and sandstones have a porosity range of 8&ndash, 26% with a dominant pore size range of 80&ndash, 500 &mu, m. The grain skeleton consists of quartz (95%), very minor potassium feldspars (orthoclase) and a small amount of mica (muscovite and chlorite). According to these preliminary results, among the studied varieties, the Escucha sandstones have the most favorable properties for CO2 geological storage at the rock matrix scale.

Fluctuating commodity prices have repeatedly put the mining industry under pressure to increase productiveness and efficiency of their operations. Current procedures often rely heavily on manual analysis and interpretation although new technologies and analytical procedures are available to automate workflows. Grade control is one such issue where the laboratory assay turn-around times cannot beat the shovel. We propose that for iron ore deposits in the Pilbara geophysical downhole logging may provide the necessary and sufficient information about rock formation properties, circumventing any need for real-time elemental analysis entirely. This study provides an example where petrophysical downhole data is automatically classified using a neuro-adaptive learning algorithm to differentiate between different rock types of iron ore deposits and for grade estimation. We exploit a rarely used ability in a spectral gamma-gamma density tool to gather both density and iron content with a single geophysical measurement. This inaccurate data is then put into a neural fuzzy inference system to classify the rock into different grades and waste lithologies, with success rates nearly equal to those from laboratory geochemistry. The steps outlined in this study may be used to produce a workflow for current logging tools and future logging-while-drilling technologies for real-time iron ore grade estimation and lithological classification.

The use of borehole imaging tools has become widespread in recent years with more specialized studies of reservoir properties, particularly in highly-porous and fractured carbonate systems. In this study, the Formation MicroScanner (FMS) borehole imaging tool and conventional well log data have been used to study the secondary porosity of the dolomitic Alamein Formation in the Alamein Field, north Western Desert, Egypt. Based on well log analyses of the formation from Tourmaline-1X and N.Alamein-6X wells, we show that secondary porosity occurs across the formation, and is filled mostly with hydrocarbon. We also show that the formation has good average effective porosity and hydrocarbon saturation. FMS images of the Tourmaline-1X well confirms that the formation is intermittently vuggy with solution-filled channels from the top to its base. The vug pores are observed to be well-connected, which supports good effective porosity values interpreted from petrophysical data. An additional set of core photographs of the Alamein Formation from N.Alamein-5X well confirms the presence of secondary pores, which are filled by hydrocarbon, and exhibit intense fluorescence under UV light. Our results show that the abundance of secondary porosity in Alamein Formation would play a key role in evaluating its reservoir quality and reservoir performance.

Orientador: Alexandre Campane Vidal Dissertação (mestrado) - Universidade Estadual de Campinas, Faculdade de Engenharia Mecânic e Instituto de Geociências 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

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Günümüzde Afrika?nın Batı kıyısı boyunca devam eden ve Güney Amerika?nın doğu kıyısında çökelen traverten kayaçların ana rezervuar özelliği (porozite, geçirimlilik, diyajenez) taşıdıkları belirlenmiştir. Böylece, Batı Anadolu?da hazne kaya özelliği sergileyen traverten çökelleri, Denizli Havzası?nın güneydoğusunda Aşağıdağdere köyünde yer alan Kelkaya traverten sahasının incelenmesine olanak sağlamıştır. Kelkaya travertenleri depolanma konumlarına göre iki grupta incelenmiştir. 1) Alt seviyede, deniz seviyesine göre 515-560 metreler arasında yer alan yamaç travertenleri, 2) Üst seviyede 595-650 metreler arasında yer alan şelale tufaları. Yamaç, çöküntü ve tümsek depolanma sistemi içerisinde 5 farklı fasiyes tespit edilmiştir. Yamaç depolanma sistemi, düz, teras (rim ve havuz) ve şelale fasiyesinden oluşur. Bu yamaç sistemini üzerleyen (onlap) bataklık havuz fasiyesi, eski toprak seviyesi (litoklast) ise çöküntü depolanma sistemini oluşturur. Lokal, küçük tümsek çökeller, yamaç depolanma sistemi içerisinde gelişmiştir. Yamaç ve çöküntü depolanma sisteminde gelişen en yaygın litotipler sırasıyla kristalin kabuk ve mikrit traverten olarak belirlenmiştir. Çökelme dokusu ve mikroorganizma faaliyetleri etkisi altında gelişen diyajenez süreçleri ile duraylı izotop analizleri, kristalin çalı çökellerinden oluşan kristalin kabuk, koyu ve açık renkli mikrit litotiplerin birbirinden ayrılmasına yardımcı olmuştur. Daha sonra bu litotiplerin sedimantolojik özellikleri, petrofiziksel özellikleri ile ilişkilendirilmiştir. Bunun için bu çalışmada polarize ve elektron mikroskop, duraylı izotop analizleri, görüntü analizi, temel karot analizleri olarak adlandırılan helyum ve hava geçirgenliği ile civa enjeksiyon testleri traverten çökellerine uygulanmıştır. Petrografik gözlemlere göre bu çalışmada kuruma büzülme, organik bozunma, çimentolanma ve sparimikritleşme diyajenez süreçleri tespit edilmiştir. Kuruma-büzülme, laminalanmaya paralel bir dizi birincil fenestral boşlukların açığa çıkmasına neden olur. Diğer yandan, diğer diyajenez süreçleri ikincil olarak gözlü (vug), moldik (mouldic), kamış biyomoldik (reed-biomouldic) ve organik boşlukları açığa çıkarır. Görüntü analizine göre organik boşluklar, biyomoldik boşluk türlerinden ayırt edilmiştir. Buna göre, bu çalışmada organik porozite adı altında yeni bir porozite sınıflaması ortaya çıkmıştır. Petrofiziksel açıdan koyu renkli mikrit litotipinde gözlenen çimentolanma ve sparimikritleşme, gözlü (vug) ve biyomoldik boşlukların daralmasına neden olurken, açık renkli mikrit litotipinde gözlenen kuruma büzülme, boşlukların giderek büyümesine yol açar. Traverten örneklerinin ?13C değerleri +2.7 ile +6.2? (VPDB) arasında, ?18O değerleri ise -8.7 ile -7.5 ? (VPDB) arasında değişir. Karbon izotop değerleri, güneyden kuzeye doğru yanal olarak bir azalma gösterir. Diğer yandan, oksijen izotop değerlerinde belirgin bir değişim gözlenmemiştir. Ancak, farklı fasiyeslerde gözlenen bir litotipin farklı ?13C değerleri verdiği ortaya çıkmıştır. Bu çalışmada ?13C değeri (6.18 ?VPDB), en fazla teras havuz fasiyesinin koyu renkli mikrit litotipinde gözlenirken, en az tümsek fasiyesinin kamış litotipinde (3.2 ?VPDB) meydana gelir. Ayrıca bu fasiyeslerdeki kristalin kabuk litotipinin ?13C değeri, teras havuzundaki bakteriyal çalı litotipinin ?13C değerine (5.27 ?VPDB) yakındır. Temel karot analizlerine göre porozite değerleri yüksekten düşük değerlere doğru sırasıyla açık renkli mikrit (~ 38 %), kamış (~ 22 %), bakteriyal çalı (~ 21 %) olarak tespit edilmiştir. Koyu renkli mikrit (~ 15 %), kristalin kabuk (~ 16 %) ve eski toprak seviyelerin (~ 15 %) porozite değerleri, diğer üç litotipten düşük olmakla birlikte hemen hemen birbirine yakın değerler sergiledikleri fark edilmiştir. Düzeltilmiş hava geçirgenlik değerleri ise yüksekten düşük değerlere doğru sırasıyla kristalin kabuk (~ 45 mD), eski toprak seviyesi (~ 7 mD) ve koyu renkli mikrit (~ 1.25 mD) olarak belirlenmiştir. Anizotropiden dolayı, genellikle düşey doğrultudaki geçirimlilik değerleri, yatay doğrultudan daha fazladır. Bu durum, yatay doğrultuya göre düşey doğrultudaki boşlukların düzenli dağılım göstermesinden kaynaklanır. Tümsek fasiyesinde kamış litotipi, en fazla porozite (~ 22 %) ve en az geçirimlilik (~ 0.1 mD) değerleri sergiler. Bu durum, kamış biyomoldik boşlukların enine ya da dik kesilmesinden kaynaklanır. Görüntü analizine göre bu boşlukların dik kesilmesi ile küçük boşluk boğaz çapları meydana gelmiştir. Civa doygunluğu, küçük boşluklardan ziyade büyük boşluk boyutlarında daha fazla gözlenmesinden dolayı, küçük boşlukların geçirimlilik değerlerinde belirgin bir azalma meydana gelir. Civa enjeksiyon testine göre, kristalin kabuk litotipinde mezoboşluklar geniş bir aralık sergilemiştir. Ancak, bu litotipte apeks noktasının oluşması ise kaotik dağılıma sahip mikroboşlukların varlığını işaret etmektedir. Bu mikroboşluklar da düzensiz boşluk dağılımını ifade eder. Böylece, düzensiz boşluk boyut dağılımı, geçirimliliğin azalması ile doğru orantılıdır. Bu görüşü, kristalin kabuk litotipinde hesaplanan yerdeğiştirme basıncının 100 psia üzerinde saptanması da yardımcı olur. Diğer yandan, koyu renkli mikrit litotipindeki düzeltilmemiş hava geçirgenlik değerlerinin kristalin kabuk litotipinden fazla olmasını, 100 psia?dan daha az bir değere sahip olan hesaplanmış yer değiştirme basıncı destekler. Bu çalışmada kapiler basınç , ıslatımsız civa doygunluğu ile ilişkilendirildiğinden dolayı, bu yorumlamalar Sneider (1988) tarafından belirlenen ilkelere uygun değildir. Bu yüzden, kristalin kabuk ve koyu renkli mikrit litotipinin örtü kaya özelliği sergilediği ortaya çıkmıştır. Anahtar Kelimeler: traverten, litotip, porozite sınıflaması, petrofiziksel, temel karot analizi, civa enjeksiyon testi. At the present time, it is pointed out that travertine rocks are primary reservoir (diagenesis, porosity, permeability) rock, especially deposited in the offshore South America and along the west coast of Africa. So that, travertine deposits exhibiting the reservoir rock properties in West Anatolia allow the examination of Kelkaya travertine field area, which is located in Aşağıdağdere village, in the south-east of the Denizli extensional basin. The occurrences in different elevations display mainly two depositional settings: (1) Slope deposits developed towards the north, located at the lower altitudes (515 to 560 m) and (2) Waterfall tufa deposits located at the upper altitudes (560 to 650 m). Five different facies are present into three depositional systems which consist of slope, depression and mound depositional systems. Slope depositional system consists of smooth, terrace which forms pools and rims and cascade facies, whereas depression depositional system arise from paleosol (lithoclast), marsh pool facies which subdivided into dark and light coloured pool facies. The marsh pool facies is onlap to slope facies. Locally, small mound deposits are developed inside of slope depositional system. The most common lithotypes developed in slope and depression depositional systems consist of crystalline crusts and micrite travertine, respectively. According to both depositional fabrics and diagenesis processes developed under microorganism activity and stable isotopic analysis help especially crystalline crust consisted of crystalline shrub deposits, dark and light micrite lithotypes to be separated from each other. Then, the sedimantological properties of these lithotypes are correlated to its petrophysical characteristics. Hence, the polarization and electron microscope, stable isotope analysis, image analysis, routine core analysis consisted of helium porosity and air permeability, mercury injection porosimetry are performed to travertine deposits in this study. According to petrographic observations, shrinkage, organic decomposition, cementation and sparmicritazition diagenesis processes are established in this study. The shrinkage result to a lot of primary fenestral pores which is parallel to lamination. On the other hand, other diagenetic processes bring out secondary vuggy, mouldic, reed-biomouldic and organic pores. Based on imagine analysis, organic pores distinguish from biomouldic pores. Hence, a new porosity classification which is referred to organic porosity is introduced in this study. In terms of petrophysical characterizations, cementation and sparimicritization which is observed in dark coloured micrite lithotype lead to closure of vuggy and biomouldic pore spaces, whereas shrinkage found in light coloured micrite lithotype result gradually to be enlarged of pore spaces. The 13C and ?18O values of the travertine samples vary between +2.7 to +6.2? (VPDB) and -8.7 to -7.5 ? (VPDB), respectively. ?13C values of travertine deposits show laterally a decrease from south to north of field area. On the other hand, a clear shift is apparent in the ?18O values. However, it is found out the same lithotype appeared in different facies provide different ?13C values. While the ?13C value of 6.18 (? (VPDB) appeared in the darkest coloured micrite lithotype of terrace pool facies, the least depleted value of (3.2 ? (VPDB) occurs in reed lithotype of mound facies in this study. In addition to, the ?13C value of crystalline crust lithotype from terrace rim is close to its bacterial shrub lithotype (5.27 (?VPDB) from terrace pool. According to routine core analysis, helium porosity values are described for light coloured micrite (~ 38 %), reed (~ 22 %), bacterial shrub lithotypes (~ 21 %) towards from highest to lowest values, respectively. Its dark coloured micrite (~ 15 %), crystalline crust (~ 16 %) and paleosol (~ 15 %) are lesser than other three lithotypes and they exhibit close values to each other. On the other hand, corrected air permeability values is determined as crystalline crust (~ 45 mD), paleosol (~ 7 mD) and dark coloured micrite (~ 1.25 mD) towards from highest to lowest values, respectively. Because of anizotropy, permeability values from vertical direction are more than it from horizontal direction. This suggests that a lot of pores of vertical direction relative to horizontal have uniform porosity distribution. Reed lithotype from mound facies shows much porosity (~ 22 %) and less permeability (~ 0.1 mD) values. This results is due to pores of both the longitudunal and crosscut reed-molds. According to image analysis, these pores of longitudunal consist of small pore throat sizes which posses lower diameters. Although large pore sizes instead of small pore size have much mercury saturation values, a clear decrease occurs in permeability values of small pores. According to mercury injection porosimetry, mesopores formed in crystalline crust lithotype exhibit a wide distribution. However, the existence of apex point has indicated that it involves much micropores which show chaotic distribution. These micropores suggest to be had patchy pore distribution which leads to decrease uncorrected air permeability. Calculated displacement pressure of crystalline crust which is a value (183 psia) over 100 psia supports this interpretation. On the other hand, it (93 psia) having lesser a value than 100 psia supports that the uncorrected air permeability values of dark coloured micrite lithotype are higher than in the crystalline crust lithotype. However, capillarity pressure relates to non-wetting mercury saturation in this study. So, these interpretations do not correspond to principles which is described by Schneider (1988). Indeed, it is found out that both crystalline crust and dark coloured micrite lithotype exhibit cap rock properties. Key Words: travertine, lithotype, porosity classification, petrophysical, routine core analysis, mercury injection test.

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.; 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., 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 Harşit granitoid in northeastern Turkey, comprises four separate granite units that are apparently unfoliated. The Harşit granitoid was investigated here by using microstructural, petrofabric and anisotropy of magnetic susceptibility (AMS) data. The structural data of the granitoid were found to be highly compatible with the zonation recognized from AMS measurements. The orientation of magnetic fabrics within the granite units indicates that tectonic deformation might have occurred coevally with the magmatic emplacement of the intrusion. When we evaluated the manners on the scale of the pluton that the disruption took place in the form of uplifting, probably related to a rapid migration of the volcanic front and the documented change from deep sea sedimentation predominant until late Cretaceous to shallower environments during the Paleocene. The possible tectonic control of fault systems on the ascent and emplacement of the granitic magma in the study area, however, cannot be completely ruled out because the Harşit granitoid is situated at or very near the NAF systems in northern Anatolia. In any case, the intrusion is clearly discordant to the regional deformational features formed during the collisional events between the Eurasia and Anatolia plates in northern Turkey. © 2011 Springer Basel AG.

A history matching workflow, as typically used for updating of petrophysical reservoir model properties, is modified to include structural parameters including the top reservoir and several fault properties: position, slope, throw and transmissibility. A simple 2D synthetic oil reservoir produced by waterflooding is used to demonstrate issues related to observability and identifiability of structural uncertainties. A series of history matching experiments are performed that demonstrate the potential for estimation of uncertain structural parameter values. The experiments are performed with ensemble-based assisted history matching schemes that allow for the proper characterization of prior uncertainties, and in principle enable the updating of both model parameters and the dynamic states such as pressures and saturations. The results show that the approach works well when individual structural parameters are estimated and suggest further scope for building a fully integrated workflow that includes the improved construction of geo-models into the history matching loop. Copyright 2011, Society of Petroleum Engineers.

The need for an improved ability to "see into the earth" has resulted in the use of geophysical techniques, especially the electrical resistivity method, in engineering and environmental investigations. The major challenge in the use of electrical resistivity measurements however is the interpretation of the electrical response. This is due to the lack of adequate understanding of the relationships between the physical factors controlling the engineering behavior of geomaterials (earth materials) and their measurable electrical parameters. This research work therefore sets out to investigate the linkages between engineering and petrophysical properties of geomaterials and their geoelectrical parameters. This goal is achieved through the development of laboratory equipments and the conduction of both laboratory and field studies. The laboratory experiments involve the measurement of the complex resistivity responses of natural and artificial soil samples under varying effective stress conditions. The field study involves the characterization of subsurface fracture parameters from field electrical measurements in complex fractured terrains at selected farming communities in Ghana.The results from this study improve on our knowledge and understanding of the influence of fundamental engineering properties of geomaterials on their electrical responses. It results will aid in the interpretation of field electrical measurements and provide a means for engineering properties of geomaterials to be estimated from measurable electrical parameters. It will also contribute towards using non-invasive electrical measurements to locate weak zones in the subsurface, assess and monitor the stability conditions of soil units and assist in the environmental impact assessment of anthropogenic activities on groundwater resources in complex fractured terrain.

The Levelland and Slaughter fields combined have produced over 1.6 billion bbls from 1937 to date from 6000 wells and currently produce 6% of the oil in Texas. Most of the field is under water and CO2 flood operations. This project investigates reservoir and petrophysical characteristics of various areas in the Levelland Slaughter field in order to assess relation to performance of secondary and tertiary recovery. The benefits would be to use this relationship to identify depositional environment/facies where little to no core data exists. In areas where no flood has been installed, the relationships developed herein could assist in the ability to predict flood recovery and the method of development. The Levelland Slaughter field is similar to several other ramp type, carbonate fields in the Permian Basin. Results once applied and proved successful in the Levelland Slaughter field not only could be applied to many other fields in the Permian Basin, but also to similar oil reservoirs all over the world. The first objective was to divide the field into areas of like depositional environments. This entailed identifying depositional environments via log, core and production analysis. The objective is to integrate geology and production into the study to ascertain whether like data can be considered, especially in an east west sequence across Levelland Slaughter. There are three depositional environments at Levelland Slaughter as follows; shelf with shoals, lagoonal and intertidal/near shore. Once subdivided, relationships between petrophysical properties and secondary recovery rates are developed utilizing Lucia’s rock fabric classification and production plot methods demonstrated by Reza Fassihi of BP. Fassihi demonstrated the method of plotting water cut against fractional secondary oil recovered enabled one to derive the matrix/fracture flow and storage capacity relationships. Based on curves developed by Fassihi, one can conclude there is little to no natural fracturing in the reservoirs in the Levelland Slaughter field. Lucia demonstrated that by plotting porosity against permeability in carbonate reservoirs, one could derive the type of rock fabric and detect facies changes. Net pay for primary and secondary recovery can be different and are dependent primarily on permeability and water saturation. Water saturation varies within the pay zone in lower permeability reservoir rock. Below a given permeability, water saturation increases and become movable. In consideration of the fore going, a typical Levelland well in the 1950’s produced water free, but later, prior to waterflooding, produces 20 to 50% water cut. For secondary waterflood recovery considerations, a critical water saturation exist where an oil bank does not develop, thus resulting in prolong recovery periods or little to no recovery from that particular reservoir rock. From the Lucia classification and Fassihi plots, it appears that most of the rock fabrics are similar and only differ in permeability. This is possibly due to anhydrite inclusion that was deposited in the more permeable rock, thus leaving the lower permeability mudstone porosity intact. Some localized areas could have improved reservoir due to subtle changes in elevation. These elevation changes are critical in the western area because small sea level changes caused substantial areas to go from subtidal to intertidal to supratidal/mud flats. Each of the fore mentioned steps resulting in a reduction in reservoir quality due to salt precipitation or anhydrite inclusions. This does not apply to shoal areas, located at shelf margins, because they were never supratidal, thus there are no evaporates. Thus the higher permeability rock demonstrates higher primary recoveries as well as much greater Secondary to Primary ratios (S:P).

We develop and validate a new method to estimate secondary porosity and effective permeability of fractured and vuggy carbonate formations based on the numerical simulation of the process of mud-filtrate invasion. The method includes the geological characterization of core measurements and their integration with well logs and fluid production measurements. Applications of the new method are focused to the interpretation of data acquired in a carbonate reservoir in the Barinas-Apure Basin in southwest Venezuela, which is a triple-porosity system exhibiting inter-crystalline, intra-crystalline, moldic, vuggy (connected and non-connected) and fractured porosity, all embedded in a tight matrix. Rock-core data and image logs indicate that vugs are the mayor component of secondary porosity whereas fractures and interconnected vugs account for most of the permeability. The initial phase of our method consists of integrating core measurements with conventional and non-conventional well logs to calculate static and dynamic petrophysical properties via formation evaluation methods typically used to assess carbonate formations. Starting with the petrophysical variables calculated from standard formation-evaluation procedures, we simulate the process of invasion with both water- and oil-base muds. Resulting spatial distributions of water saturation and salt concentration give rise to spatial distributions of electrical resistivity which are used to calculate laterolog and induction logs. Comparison of simulated logs and measurements provides an effective means to assess whether the petrophysical properties calculated with standard interpretation methods are reliable. Specifically, if the calculated values of porosity and permeability are not correct the simulation of mud-filtrate invasion and resistivity logs will yield a poor match with measurements. In such cases, we update both variables until securing a good match between measurements and simulations. We find that permeability and porosity values estimated with our method reproduce values observed for the entire fluid-flow network system (well test data and core observations). Differences between simulations are measurements are diagnostic of presence of vugs and/or fractures. This procedure was tested on several key wells with and without core measurements, borehole images, and well-testing measurements. We conclusively find that our updated values of porosity and permeability are in very good agreement with the properties of the global petrophysical system. Differences between porosity and permeability values before and after simulation of the process of invasion are reliable indicators of presence and influence of vugs and/or fractures in the displacement of hydrocarbons by mud filtrate.

State of the art X-ray micro-computed tomography (micro-CT) of reservoir rock samples and cuttings allows reconstruction of the pore network with micrometric spatial resolution that is suitable for further petrophysical and fluid flow properties evaluation. Synchrotron tomographic beam lines, compared to conventional micro-CT systems, allow better 3D representation of the pore space. The digital rock volume is used for medial axis extraction and for 3D pore space morphological characterization (i.e. connectivity, pore-body/throat size, shape factors, etc.). The medial axis is generally derived by computed intensive digital-thinning operations for skeletonization of the digital rock volume. The alternative method we describe in this work, allows to extract the 3D centered and shortest paths to follow in order to go through the pore space from any given point to another one using simple and well-established mathematical methods. Even if we do not consider explicitly fluid flow, one path can be viewed as the streamline of the fastest fluid thread for laminar flow regime that a particle follows to go through the pore space from an intrusion point to an exiting point of the digital sample. The method is very fast, processing large voxel volumes in seconds, and it is also amenable to parallelization. The conductance of the irregular cross-sections of the throats is calculated with a fast finite element method (f.e.m.) that assumes fully developed laminar flow in axial direction. The network is solved as a linear system and the absolute permeability derived. The paper reports the results of application on real oil reservoir sandstone samples and shows the potential to predict petrophysical properties from rock material (i.e. drilling cuttings or crushed side wall cores) not suitable for conventional analyses.

The E-series on Šandrovac field consists of the following reservoirs: E, E&#8217 ; , E&#8217 ; &#8217 ; , and E&#8217 ; &#8217 ; &#8217 ; . Šandrovac structure has also been affected by intensive tectonics, which is why faults divide the structure into a whole series of smaller and larger blocks. All the oil-bearing rocks of the Šandrovac field are finely- to medium-grained, and loosely- to medium-bonded quartz sandstones with plagioclastics/?/ and laminar minerals. Through the analysis of the existing cores and conventional e-logging diagrams &#8211 ; to isolate individual sandy layers within each reservoir, in order to be able to follow their distribution and provide adequate mappings for them (contour, thicknesses, and effective thicknesses maps). As shown in this work, the preliminary results of the study (average petrophysical properties and their correlations) correspond to the SP derived zones, contoured on the basis of observed similarity criterion.

© 2021 Society of Exploration Geophysicists. Reuse is subject to SEG terms of use and conditions. SEG-prepared Accepted version is presented without modification., Quantitative estimation of subsurface water and ice content values is critical for the understanding and modeling of permafrost evolution in alpine regions. Geophysical methods permit the assessment of subsurface conditions in a noninvasive and quasi-continuous manner; in particular, the combination of seismic refraction tomography (SRT) and electrical resistivity tomography (ERT) through a petrophysical model can quantitatively estimate ground water and ice content values. For the Hoher Sonnblick study area (3106 m.a.s.l., Austrian Alps), we have investigated the improved estimation of water and ice content values based on SRT, ERT, and ground-penetrating radar data collected in June and October 2019. We solve for the water and ice content values following different approaches, namely, (1) the independent inversion and subsequent transformation of the imaging results to the target parameters through a petrophysical model and (2) the petrophysical joint inversion (PJI) of the data sets. Supported by a synthetic study, we determine that the incorporation of structural and porosity constraints in PJI allows for an improved quantitative characterization of subsurface conditions. For our measurements at Hoher Sonnblick, constrained PJI resolves a shallow debris layer characterized by high air content and porosity, on top of a layer with lower porosity corresponding to fractured gneiss, and the bedrock layer with the lowest porosity. For both time steps, we find high water content at the lower end of the investigated area. Substantial variations in the subsurface ice content resolved between June and October 2019 indicate a correlation between the high water content and the meltwater discharge within the debris layer. Our results demonstrate that constrained PJI permits an improved characterization of subsurface hydrologic parameters in alpine permafrost environments.

A history matching workflow, as typically used for updating of petrophysical reservoir model properties, is modified to include structural parameters including the top reservoir and several fault properties: position, slope, throw and transmissibility. A simple 2D synthetic oil reservoir produced by waterflooding is used to demonstrate issues related to observability and identifiability of structural uncertainties. A series of history matching experiments are performed that demonstrate the potential for estimation of uncertain structural parameter values. The experiments are performed with ensemble-based assisted history matching schemes that allow for the proper characterization of prior uncertainties, and in principle enable the updating of both model parameters and the dynamic states such as pressures and saturations. The results show that the approach works well when individual structural parameters are estimated and suggest further scope for building a fully integrated workflow that includes the improved construction of geo-models into the history matching loop.