Dissertations / Theses on the topic 'Petrophysical propertie'

A significant challenge to the petrophysical evaluation of shale gas systems can be attributed to the conductivity behaviour of clay minerals. This is compounded by centimetre to sub-millimetre vertical and lateral heterogeneity in formation geological and therefore petrophysical properties. Despite this however, we remain reliant on Archie based methods for determining water saturation (Sw), and hence the free gas saturation (1-Sg) in shale gas systems. There is however significant uncertainty in both how resistivity methods are applied and the saturation estimates they produce, due largely as Archie parameter inputs (e.g. a, m, n, and Rw) are difficult to determine in shale gas systems, where obtaining a water sample, or carrying out laboratory experiments on recovered core is often technically impractical. This research assesses the geological implications for, and controls on, variations in pseudo Archie parameters in the Bossier and Haynesville Shale Formations in the northern Gulf of Mexico basin. Investigation has particularly focused on the numerical analysis and systematic modification of Archie parameter values to minimise the error between core SW (Dean Stark analysis) and computed Sw values. Results show that the use of optimised Archie parameters can be effective in predicting SW, particularly in the Haynesville formation, but identifies systematic bias in generated Archie parameters that precludes their accurate physical interpretation. Analysis also suggests that variability in the resistivity (Rt) log response is the principal source of error in Sw estimates in the Bossier Shale. Moreover, results suggest that where clay volume exceeds 28%, the resistivity response becomes increasingly variable and elevated, indicating an apparent clay associated ‘excess resistivity’. This is explained by a geologically consistent model that links increasing clay volume to bulk pore water freshening, supported by empirical adaptations that allow for improved Archie parameter selection and a further reduction in the error of Sw estimates.

In comparison to sandstone reservoirs, carbonate exploration is commonly more challenging because of intrinsic heterogeneities, occurring at all scales of observation and measurement. Heterogeneity in carbonates can be attributed to variable lithology, chemistry/mineralogy, pore types, pore connectivity, and sedimentary facies. These intrinsic complexities can be related to geological processes controlling carbonate production and deposition, and to changes during their subsequent diagenesis. The term 'heterogeneity' is rarely defined and almost never numerically quantified in petrophysical analysis although it is widely stated that carbonate heterogeneities are poorly understood. This work has investigated how heterogeneity can be defined and how we can quantify this term by describing a range of statistical heterogeneity measures (e.g. Lorenz and Dykstra-Parsons coefficients). These measures can be used to interpret variation in wireline log data, allowing for comparison of their heterogeneities within individual and multiple reservoir units. Through this investigation, the Heterogeneity Log has been developed by applying these techniques to wireline log data, over set intervals of 10, 5, 2 and 1m, through a carbonate reservoir. Application to petrophysical rock characterisation shows a strong relationship to underlying geological heterogeneities in carbonate facies, mud content and porosity. Zones of heterogeneity identified through the successions show strong correlation to fluid flow zones. By applying the same statistical measures of heterogeneity to established flow zones it is possible to rank these units in terms of their internal heterogeneity. Both increased and decreased heterogeneity is documented with high reservoir quality in different wireline measurements, this can be related to underlying geological heterogeneities. Heterogeneity Logs can be used as a visual indicator of where to focus sampling strategies to ensure intrinsic variabilities are captured.

Faults can have significant impact on reservoir productivity. Understanding the factors that controls the fluid flow properties of fault rocks provides a sound basis to assess the impact of faults on reservoirs productivity. Therefore, different aspects that affect the fluid flow within siliciclastic fault formations were investigated in this research project. Fault rock samples from a number of locations were analysed including: (i) core samples from central and southern North Sea fields; (ii) and outcrop samples from the 90 Fathom fault, Northumberland, UK and Miri airport road exposure, Malaysia as well as the Hopeman fault from Invernesshire, UK. The impact of faults on fluid flow was assessed by integrating the data from QXRD analysis, microstructural examination, X-ray tomography, mercury porosimetry for pore size distribution, absolute and relative permeability measurements as well as capillary pressure tests. Single phase and multiphase flow properties which were conducted at a range of stresses are the most comprehensive collection of high quality fault rock data. The permeability measurements made using gas gave higher values than with brine, which in turn gave higher values that when measured using distilled water permeability. The differences in permeability could be the results of clay particles swelling; mobilisation and retaining within the confined pore throats, although these effects depend on the rock mineralogy and pore fluid composition. Moreover, the permeability stress sensitivity was investigated. The results showed that at low confining stresses the permeability of the fault rock core samples showed high sensitivity to stress, whereas at higher confining stresses the permeability was less pronounced to stress. This might be due to the core damage effects and the microfractures formed due to stress release, which were observed from SEM images. The pore radius calculated from gas slippage parameters at low confining pressures was in the same order of magnitude as the micro fracture width. The micro cracks could be easily closed due to stress increase hence resulted in reduction of permeability. Overall, the stress sensitivity of fault rocks from outcrop is less than that from core. This is consistent with the idea that stress sensitivity is mainly the result of the presence of grain boundary microfractures formed as core is brought to the surface. This indicates that permeability measurements made on outcrop samples may be more reliable. Another key finding was that the published permeability data (e.g. Fisher and Knipe, 2001) compared with present study data which is obtained at in-situ stress using formation compatible brines showed that the published data may not be inaccurate as the use of distilled water gives lower permeability than brines and low stresses resulted in higher permeability than in-situ stress measurements. Therefore, the results indicate that two different laboratory practices used in previous studies partially cancel each other out so that the existing data is yet valuable. The effective gas permeability were also measured at a range of stresses and it was observed that the samples with lower absolute permeabilities were more stress sensitive to stress than high permeable samples. The relative permeability results obtained were incorporated into a specific example of synthetic reservoir model. These suggested that faults formed within low permeability sands might act as a barrier to fluid flow.

Shale is the most abundant and the least known type of sedimentary rock. It is found in every basin associated with hydrocarbon depositions and is notorious for its complicated properties. This thesis is dedicated to investigation of the compaction trends of rock physics and petrophysical properties of shale. It is supplemented with in-depth analysis of shale microstructure as a key parameter controlling the macroscopic anisotropic properties of shale.

Key petrophysical properties of reservoir sequences are determined by their individual mineral compositions, and are routinely evaluated through the analysis of cores and geophysical well logs. However, mineralogical studies are seldom incorporated in reservoir assessment. The objectives of the study were to investigate the influence of mineralogy on petrophysical properties of petroleum reservoir beds and the application of mineralogical studies in reservoir evaluation. Mineralogical analyses were performed on core samples from the Plover Formation, the principal reservoir sequence in the Northwest Shelf area of Australia, intersected in two separate wells in the Laminaria petroleum field. The techniques used included X-ray powder and oriented-aggregate analysis, optical microscopy and whole rock geochemistry. Quantification of each mineral phase based on whole-rock powder data was performed using the Rietveld-based Siroquant technique. Results from the Siroquant assay were used as an indicator of mineralogy for the individual samples and were compared with core plug and geophysical log data. X-ray micro-tomography analysis of selected samples was also performed. The reservoir sequences in both wells were sand-dominated, consisted mostly of quartz, clay mineral matrix and cement of silica, pyrite or calcite. The abundance of clay minerals increased in the shale and shaly sandstone intervals. Comparison of mineralogical and core plug analyses of samples from the same depths showed that the down-hole variations in porosity, permeability, grain density and radioactivity were accompanied by changes in mineralogy. Higher proportion of clay minerals in shales was indicated by higher gamma log signals. The gamma log may be taken as an indicator of shaliness only in intervals where kaolinite is proportional to the quantity of illitic clays. Sonic log and neutron log porosity values are comparable with core plug porosity data in sandstone intervals. However, clay minerals increase the sonic log response, thereby increasing porosity in shaly intervals. Clay minerals tend to decrease the neutron log response causing higher porosity indication in shales, similar to that expected in sandstones. Routine density log analysis underestimated porosity values because of the contribution of dense minerals to the bulk density of the formation. Use of laboratory determined grain and fluid densities resulted in improved density log porosity compared to core porosity. X-ray tomography analysis revealed an overall positive correlation between mineralogy and porosity data. Routine geophysical log evaluation revealed inconsistent results when compared to core analysis data because of the influence of minerals on various logs. It is essential that mineralogical studies be included in reservoir assessment. X-ray tomography may provide an alternative approach in evaluating porosity and mineralogy.

Mudstones are of considerable scientific and economic importance as they are the dominant sedimentary rock type, forming the main repository of Earth history and having significance to numerous aspects of petroleum exploration and production, and many other industries. This study investigated the sedimentological characteristics of 150 diverse mudstone samples. The novel integration of grain size analysis combined with petrographic observations lead to a framework in which six mudstone grain size distribution (GSD) types are defined. The grain size types proposed are remarkably consistent in their form and characteristics and can be understood in terms of well constrained physical processes of deposition. The basis for this definition reflects largely the relative contributions of a flocculated, clay-rich component and an unflocculated silt/sand-rich grain size component. Integration of grain size data, pore size data and petrographic observations suggests a critical division between: (a) flocdominated mudrocks whose structure is supported by the clay matrix; and (b) silt-rich mudrocks whose structure is supported by a silt/fine sand framework. Floc-dominated mudrocks with clay matrix support develop low permeabilities and become very good capillary seals at relatively shallow depths. In contrast, silt-rich mudrocks with framework support only become low permeability units and very good capillary seals at much greater levels of compaction. The framework proposed here can form the basis of predictive flow and seal capacity models for mudrocks. A combined PCAcluster analysis approach to the grain size based classification of mudstones showed that of the six types defined in Chapter 2, types 1 — 4 (floc — silt mixtures) were consistently partitioned from types 5 — 6 (silt or sand rich mixtures). An attempt was made to quantify the distribution of key pore parameters, such as mean pore size, by grouping the data to reflect the matrix (grain size types 1 — 4) and framework (grain size types 5 — 6) support regimes and dividing into 5% porosity bins. The statistical distribution of pore network properties could not be verified, principally due to a combination of sparse sample numbers and highly variable nature of this data. This work illustrates that variability in mudstone pore size distributions is not constrained solely by lithology (support regime) and porosity, and thus that other factors must be taken into account if their evolution during compaction is to be understood.

The development of hydrocarbon energy resources from shale, a fine-grained, low-permeability geological formation, has altered the global energy landscape. Constricting pressure exerted on a shale formation has a significant effect on the rock's apparent permeability. Gas flow in low-permeability shales is significantly different from liquid flow due to the Klinkenberg effect caused by gas molecule slip at the nanopore wall surfaces. This has the effect of increasing apparent permeability (i.e., the measured permeability). Optimizing the conductivity of the proppant assembly is another critical component of designing subsurface hydrocarbon production using hydraulic fracturing. Significant fracture conductivity can be achieved at a much lower cost than conventional material costs, according to the optimal partial-monolayer proppant concentration (OPPC) theory. However, hydraulic fracturing performance in unconventional reservoirs is problematic due of the complex geomechanical environment, and the experimental confirmation and investigation of the OPPC theory have been rare in previous studies. In this dissertation, a novel multiphysics shale transport (MPST) model was developed to account for the coupled multiphysics processes of geomechanics, fluid dynamics, and the Klinkenberg effect in shales. Furthermore, A novel multi-physics multi-scale multi-porosity shale gas transport (M3ST) model was developed based on the MPST model research to investigate shale gas transport in both transient and steady states, and a double-exponential empirical model was also developed as a powerful substitute for the M3ST model for fitting laboratory-measured apparent permeability. Additionally, throughout the laboratory experiment of fracture conductivity with proppant, the four visible stages documented the evolution of non-monotonic conductivity and proppant concentration. The laboratory methods and empirical model were then applied to the shale plugs from Central Appalachia to investigate the formation properties there. The benefits of developing these regions wisely include a smaller surface footprint, reduced infrastructure requirements, and lower development costs. The developed MPST, M3ST, double-exponential empirical models and research findings shed light on the role of multiphysics mechanisms, such as geomechanics, fluid dynamics and transport, and the Klinkenberg effect, in shale gas transport across multiple spatial scales in both steady and transient states. The fracture conductivity experiments successfully validate the theory of OPPC and illustrate that proppant embedment is the primary mechanism that causes the competing process between fracture width and fracture permeability and consequently the non-monotonic fracture conductivity evolution as a function of increasing proppant concentration. The laboratory experimental facts and the numerical fittings in this study provided critical insights into the reservoir characterization in Central Appalachia and will benefit the reservoir development using non-aqueous fracturing techniques such as CO2 and advanced proppant technologies in the future.
Doctor of Philosophy
Production of oil and gas from the extremely tight rock has changed the global energy industry, including job growth, energy security, and environment protection. However, the oil and gas production from the tight rock is difficult because of the complex rock properties. Hydraulic fracking can resolve the issue and contribute to the high production. The higher and safer production needs us to have a better understanding of oil and gas flow under the ground. A series of laboratory experiment were conducted, and a new shale gas transport model is introduced in this dissertation to explain the oil and gas flow under the complicated scenarios. The experimental results show that many factors can impact the oil and gas flow, and the model can match the experimental results very well. A few statistical methods are also used in the data analysis. The optimization of proppant pack is another important component of hydraulic fracking. Proppant particles are usually man-made ceramic tiny balls, which will be injected into the underground to keep the fractures from closing during the production. From the previous papers, it is possible to achieve high fracture conductivity at a much lower cost than traditional proppant costs. Many groups of laboratory experiment were conducted to demonstrate this guess. Many rock samples in the experiment are from Central Appalachian area, which can help the resource development in this area. The developed model and experimental research findings in this study provided critical insights into the role of the many physics mechanisms on shale gas transport, proppant optimization, and hydraulic fracking.

This thesis presents two new sensors for measuring permeability and acoustic properties on slabbed core samples in the petrophysics laboratory. Prototypes were built to demonstrate that the new techniques are viable. The permeability sensor is the first non-contact, high spatial resolution, permeameter ever to have been developed; it has been called a micro-permeameter. It was calibrated using both synthetic and real rock samples. The collected data were compared with results from the industry-standard CoreLab PDPK-400 mini-permeameter. The comparison shows that the new micro-permeameter is much faster than the CoreLab instrument. In addition, the new micro-permeameter is more sensitive to permeability changes and yet still makes more repeatable measurements. The uniqueness of the new micro-permeameter project resulted in the granting of US patent No. 6715341 (see Appendix D). The acoustic sensor developed is laser-based for the excitation stage only, and piezoelectric-based for the detection stage. The laser was tuned to generate acoustic waves in the rock without harming the rock surface. The new experimental method is comparable with exploration seismic surveys, but unique in the petrophysics laboratory. As a result, seismic software may be used to analyse the collected data. A significant discovery was made that not only was the new laser-acoustic system able to identify the standard direct-wave events, but also it reflected and refracted events never identified in petrophysics laboratory before. The standard velocity measurements for the pressure- wave (Yp) and the shear-wave (Ys) may now be made with a far greater accuracy than is possible with the established single-path method. Furthermore, the accuracy may now be measured statistically, rather than as an estimate. Direct measurements of amplitude-versus-offset (AYO) phenomena, which are impossible with the established method, may now be made. The results could be used to calibrate exploration seismic data, with fewer assumptions than the standard approach.

Carbonate reservoirs contain approximately two-thirds of the world's oil and gas reserves (Al-Anzi et al., 2003). Carbonates often pose a significant problem when it comes to understanding their reservoir quality because of their heterogeneous nature, which is caused by both the variety of processes occurring depositionally and their high susceptibility to diagenetic alterations. In order to fully characterise the behaviour of carbonate rocks in the subsurface is it important to understand their textural heterogeneity and also how faulting can modify their textures. Deformation in fault zones causes the petrophysical properties (e.g. porosity, permeability and velocity) to alter from the background values. For example, fracturing in damage zones surrounding faults increase the permeability, creating conduits to fluids, conversely, fault cores often act as barriers, created by pore occluding processes. However, faulting in carbonate rocks is often complicated by their textural variations, leading to a variety of deformation microstructures, and each will create different petrophysical properties. This thesis aims to understand how faulting effects different carbonate rocks and analyse the controls on any alterations to the petrophysical properties (porosity, permeability and velocity) into the fault zones. Alterations to the permeability are important to unravel in order to assess the fluid flow potential and hydraulic properties of a rock. Understanding the alterations to the velocity can help to better image faults at depth and to provide information on their microstructures.

In my three-year full time PhD study, I presented a critical literature review in microwave-assist coal permeability enhancement. Focus on the research gaps, I carried out a series of laboratory experiments to study the effect of microwave power, treatment time, and water saturation on microwave heating/fracturing effect of coal. I also proposed various numerical models to study microwave’s effect on coal permeability in laboratory scale and field scale.

Petrophysical properties (permeability, ultrasonic velocity and electrical properties) of tight gas sandstones are found to be more stress dependent at ambient conditions than at in-situ stresses. Analyses of the petrophysical properties measured at wide ranges of net stresses coupled with scanning electron microscopy (SEM) images indicate the presence of microfractures formed during or after drilling might play a major role on the stress dependency of the properties. Yet, the stress dependencies of the properties diminish as the net stress increases. This could be explained by partial or complete closure of the microfractures. Drawdown experiments were conducted to further analyse the stress dependency of permeability at reservoir conditions and to mimic the gas production from a tight gas sandstone reservoir. Results showed all the petrophysical properties were less stress dependent at higher net stress (>3000 psi) which was consistent with the theory of the microfracture closure. Drawdown tests (5000-7000 psi net stress) showed the least stress dependent of permeability. Net stress is often defined as the difference between the confining pressure (Pcon) and the pore pressure (Pp) with the assumption that changes in pore pressure and confining pressure have an equal effect on the permeability. The introduction of an effective stress coefficient χ into the simple net stress (Pcon – χ Pp) provides better understanding and quantitative analyses of which pressure has more effect on the gas permeability. This was investigated by measuring the gas permeability under 12 different combinations of confining stress and pore pressure. Biot’s coefficients that are dependent on the elastic properties of the samples were calculated and correlated with the determined coefficient χ. The determined effective stress coefficients for permeability were less than unity indicating less effect of the change in the pore pressure compared to the change of the confining stress. Comparison between capillary pressure data obtained from porous plate and vapour desorption methods using air-brine system and capillary pressure obtained from mercury injection (MICP) technique has shown discrepancies. Several factors identified as the key causes of the discrepancies are the equilibration time required for the porous plate and vapour desorption, the impact of injecting mercury on the delicate clay in the samples, the conversion factor of MICP to air-brine capillary pressure. The impact of stress on MICP measurements were analysed by conducting MICP under stress using a custom-built equipment. Results indicated capillary pressure was stress dependent similar to the other petrophysical properties. Also, permeabilities estimated from MICP models showed a better correlation with permeabilities measured at stresses equivalent to the displacement pressures of the samples, which confirmed the effect of stress on MICP measurements of the tight sandstones.

>Magister Scientiae - MSc
Pletmos Basin is a Mesozoic half graben located in the southern part of South Africa and has undergone numerous tectonic changes which involve alteration of structure and reworking of sediments. Clay diagenesis has become a more prominent factor affecting the quality of the tight shaly sandstone reservoirs in the southern Pletmos Basin. The present study focused on Block 11a as a primary area of interest .The tight sandstone reservoirs encountered in the four wells, viz. Ga-Q1, Ga- Q2, Ga-Z1 and Ga- E2 were studied using four different methods to incorporate and infer the overall diagenetic effect on the reservoirs, caused by materials of argillaceous origin. The methods adopted in the present research are formation evaluation using wireline logs and calibration of core data using Interactive Petrophysics software, thin section petrography, X-Ray Diffraction (XRD) and, Scanning Electron Microscope (SEM) along with Energy Dispersive X-Ray Spectroscopy (EDS). The availability of core samples were limited to wells Ga- Q1 and well Ga- Z1. Four reservoirs within the Cretaceous age were identified in each well and the best reservoirs were associated with facies B and D.
2022-04-30

Borehole breakouts provide valuable information with respect to the evaluation of the in-situ stress direction and magnitude, and also verification of any geomechanical models built for a specific field. Identifying the locations along a borehole where the breakouts form is therefore very important. On the other hand, the borehole geometry (defined as width and depth of breakouts), which is a critical factor in completion and production optimisation design, can also be estimated from the back analysis of breakout information. While breakout width has been widely used in obtaining an estimate of the maximum horizontal stress magnitude, few studies have been reported on the estimation of breakout depth and the information it may provide.Caliper and image logs are customarily used to identify and characterise borehole enlargement zones; in particular, the breakouts. However, these methods are limited in their applications in many instances. In addition, good quality image logs are not available in many wells including old wells. This leads to a need for the development of a new approach to identify the location of borehole enlargements along a wellbore.This research aims to understand the mechanisms under which breakouts form with respect to a rock’s physical and mechanical properties. Petrophysical logs, which are often acquired in most of the drilled wells, show correlations with mechanical properties of the rock. Therefore, this research attempts to develop an approach to identify the location of borehole enlargement zones using the information gained from petrophysical logs.This research introduces a new multi-variable approach based on various data processing techniques (including wavelet, classifiers, and neural networks) to extract rock properties from different petrophysical logs. This information was combined using a robust data fusion technique which determined the location of the enlarged borehole. The results demonstrated the accuracy of the location of the borehole enlargement identified along a borehole compared to that observed using calipers and image logs.In addition, there were correlations between breakout width and depth measurements when measurements taken from high quality acoustic image logs were used. Elastic and elastoplastic finite element numerical models also showed how breakout width and depth could change due to a change in different rock properties. The models were verified by comparing results of numerical analysis with real observations from field data.

Core flooding experiments were conducted in this research to evaluate changes in petrophysical properties of a number of carbonate samples (limestone, dolostone and chalk). The experiments involved carbonated brine flooding, CO2 enhanced oil recovery (CO2-EOR), and Water-Alternating Gas (WAG) processes performed under in-situ reservoir conditions.

Orientadores: Euclides Jose Bonet, Marco Antonio Schreiner Moraes
Dissertação (mestrado) - Universidade Estadual de Campinas, Faculdade de Engenharia Mecanica
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Resumo: Este trabalho tem como objetivos o estudo e a aplicação do processo de estimativa de propriedades petrofisicas a partir de informações obtidas em imagens petrográficas bidimensionais. O método assume a hipótese da homogeneidade estatística, e utiliza a simulação estocástica para a reconstrução do modelo tridimensional do meio poroso. A caracterização geométrica do meio simulado permite a elaboração de um modelo de rede para a simulação do fluxo e a estimativa da permeabilidade, fator de formação, pressão capilar por injeção de mercúrio e relação índice de resistividade versus saturação de água. Esta metodologia é aplicada a quatro sistemas porosos com diferentes níveis de heterogeneidade. Os resultados demonstram que estimativas confiáveis dependem da utilização de uma resolução apropriada de aquisição das imagens, que permita a identificação de poros e gargantas que efetivamente controlem as propriedades de fluxo do sistema. As curvas de pressão capilar simuladas sugerem a necessidade da composição de escalas. As propriedades elétricas são afetadas pela porosidade das amostras e sua confiabilidade é restrita a sistemas preferencialmente molháveis pela água
Abstract: The aim of this work is to investigate and apply a method for predicting petrophysical properties ftom bidimensional petrographic image data. Based on the assumption of statistical homogeneity, the method uses stochastic simulation to reconstruct the porous media tridimensional structure. The geometrical characterization of the simulated media allows the construction of a network model to simulate fluid flow and estimate permeability, formation factor, mercury capillary pressure curves and resistivity index as function of water saturation. This method is applied to four porous systems with different heterogeneity levels. The results demonstrate that good predictions depend on the appropriate image aquisition resolution, which identifies pores and throats that effectively control the flow properties of the system. The capillary pressure curves suggest the necessity of scale composition. The electrical properties are affected by samples porosity, with reliable estimates being restricted to water-wet systems
Mestrado
Mestre em Engenharia de Petróleo

Tight sandstones are becoming an increasingly important source of natural gas due to a combination of increased demand and decline in production from conventional reservoirs. Tight gas sandstones have vast quantities of gas which can extend for thousands of square miles, yet there are many problems that encounter the production from these reservoirs. For example, the production rate is not only low relative to that in conventional reservoirs, but drops dramatically with increasing the total effective stress. In addition, tight reservoirs have very low permeability (poor reservoir quality) and the identification of sweet spots (regions of high fracture density) is of great importance. This research, firstly, explores the stress dependence of tight sandstones properties mainly the stress dependence of gas permeability (absolute, effective and relative) and the stress dependence of ultrasonic velocity (dry and water partially saturated), in addition to microstructural analysis. Secondly, a finite difference wave propagation code, WAVE, is used to highlight the seismic attributes which can be used to detect sweet spots. Microstructural analysis indicated that tight sandstones have variable microstructure where the microstructure of some tight samples is characterized by isolated pore spaces and narrow pore throats (may exhibit crack like shapes). Low porosity « 10%), low permeability « 0.1 mD) samples are found to be more permeability stress sensitive than high porosity, high permeability samples. It should be emphasized, however, that laboratory measurements conducted at low stress conditions (~ < 3000-4000 psi) might overestimate in situ stress changes. This is because microcracks density develops during coring (stress release) and stress changes at low stress conditions are likely to be related primarily to changes in microcracks aspect ratio. In an attempt to correlate stress changes of permeability to that of ultrasonic velocity, the results showed quite broad scatter and there is no quantitative measure between the stress sensitivity of permeability to that of ultrasonic velocity. Using finite difference wave propagation modelling, scattered waves (e.g. P-S converted waves and/or Rayleigh waves) might be a potential seismic attribute in the detection of sweet spots.

An investigation into petrophysical properties of potential gas shales from the Perth and Canning Basins has been performed to understand the interrelationship between shale composition, geochemical properties and pore structural parameters. The following measurements were done on the samples:• Low pressure nitrogen adsorption and mercury porosimetry technique for determination of the pore structural properties,• Gas expansion method for determining the effective porosity,• High pressure methane adsorption for determination of the adsorbed gas capacity.

Volcanic rocks can host significant hydrocarbon resources but are poorly understood in terms of their reservoir properties: especially their porosity and permeability characteristics. Basaltic lavas and volcaniclastic outcrops around Tenerife and basaltic lava flows from the Large Igneous Provinces of the Deccan Traps and the Faroe Islands were studied as potential “reservoir analogues” to compare with existing hydrocarbon discoveries in volcanic rocks. These studies together with the analysis of subsurface samples from South America permitted the geochemical and petrophysical properties of several volcanic reservoir analogues to be examined. Field observations of flow morphology and continuity of defined lava flow facies, were integrated with conventional core porosity and permeability measurements and the results of a micro-focus X-ray tomography (µCT) study to characterize the petrophysical properties of various volcanic rocks. Application of µCT allows the quantification and 3D visualisation of the pore space down to a µm scale and thus provides unprecedented insights into pore morphologies. When combined with traditional petrographic observations, this provides a powerful tool with which to analyse porosity development. Vesicles and fractures are the principle controls upon effective porosity development with permeability often controlled by the degree of vesiculation. Samples with vesicle densities greater than 20 % show significantly higher permeabilities and higher effective porosities due to the increased degree of vesicle coalescence forming connected networks. Individual lava flows can be divided into base, core and top facies, with lava piles comprising repeated cycles of these distinct facies. The best reservoir quality occurs in basalt flow tops (mean µCT ? = 21.85%) where vesicular porosity dominates. Reservoir quality significantly decreases in the tight flow cores, where primary porosity is controlled by cooling joints (fracture porosity) and inter-crystalline micro-porosity (mean µCT ? = 2.32%). Flow bases show variable reservoir potential due to the presence of breccia and/or vesiculation, depending upon the eruption environment (e.g. subaerial v subaqueous) and original geochemistry (e.g. acidic v basaltic) of the lava (mean µCT ? = 9.70%). The most porous horizons are the flow tops of each successive lava flow, whilst connectivity (permeability) between these horizons is via primary cooling joints or secondary fractures. Volcaniclastic lithologies of, tuff, ignimbrite, scoria and pumice, have the highest porosity and permeability (mean µCT ? = 48.09%). Distribution of the various volcanic facies is influenced by the magma chemistry, cooling rate and mode of eruption. The primary porosity and the permeability of the rocks may be subsequently modified either to create additional porosity and permeability by tectonic fracturing and dissolution during burial or weathering, or occlude porosity through the precipitation of secondary minerals and the alteration of primary minerals. Given volcanic rocks can exhibit high porosity (especially within flow top internal zones and to as lesser extent flow bases) these lithologies can form viable reservoirs. The stacking of successive flows results in a layer cake stratigraphy, with the more porous and permeable flow tops and bases separated by relatively impervious flow cores. Should sufficient fractures and cooling joints exist, then these reservoir horizons will be in communication with each other, permitting charging of hydrocarbons. The conclusion of this thesis is that despite low permeabilities, volcanic rocks are good hydrocarbon prospects, and understanding the distribution of these key internal zones and their characteristic porosities and permeabilities will enhance hydrocarbon exploration within these unconventional reservoirs.

>Magister Scientiae - MSc
With the latest advancements in the Pletmos Basin it is imperative to understand and study how sandstone reservoirs are affected by clay minerals. Clay minerals are an influential component in sandstone reservoirs worldwide and thus have an impact on the reservoir quality and petrophysical properties. The present research was aimed at assessing the effects of clay minerals on the petrophysical properties of sandstone reservoirs from the Offshore Pletmos Basin. This was done by integrating geological (wireline logs and core analysis), geochemical (XRD and pore water chemistry) and petrographical (QEMSCAN and thin section petrography) analysis to highlight the effects of clay minerals on the intrinsic properties (porosity, permeability and fluid saturation) on reservoirs encountered within the two wells (Ga- Q1 and Ga – S1). The results highlight pervasive quartz cementation as well as the presence of clay minerals: Glauconite (Illite group), Kaolinite (Kaolinite group), Clinochlore (Chlorite group) as the dominant clay minerals and Calcite as the dominant cement in both well Ga – Q1 and well Ga – S1. The most abundant clay mineral in both wells is Glauconite. This clay mineral had a more profound effect on the petrophysical parameters compared to the other clay minerals. The clay minerals occur as pore–filling Kaolinite and pore–bridging Glauconite and pore–lining Clinochlore. As a result, the clay minerals affected the pore connectivity (permeability) more than the pore spaces (porosity). This is confirmed by the petrophysical analysis where both wells have extremely low permeability and good porosity values. The study concludes that the presence of Glauconite, Kaolinite, Clinochlore and Calcite in both wells (Ga-Q1 and Ga-S1) had an adverse effect on the permeability more compared to the porosity in sandstone reservoirs. Due to the high volume of clay and high clay mineral content in well Ga-Q1, the petrophysical parameters were more adversely affected compared to well Ga-S1. As a result, we see better petrophysical properties (porosity and permeability) in the sandstone reservoir from well Ga-S1 due to intense bioturbation. The reservoir quality of well Ga-S1 is much better compared to well Ga – Q1 because water saturation averages at 42% and gas saturation averages at 58%, has decent porosity averages at 12% but low permeability ranges of 0, 1 – 4mD.
2021-09-30

Thesis (MSc)--Stellenbosch University, 2011.
ENGLISH ABSTRACT: This study presents an outcrop characterisation and modelling of the excellently exposed Permian Kookfontein Formation of the Ecca Group in the Tanqua-Karoo sub-Basin. The sedimentary modelling (i.e. facies architecture and geometry) and petrophysical characterisation followed a hierarchical and deterministic approach. Quantitative outcrop data were based on the thirteen sedimentary cycles that characterise this stratigraphic succession at the Pienaarsfontein se Berg locality; and these data were analysed using a combination of detailed sedimentary log, gamma ray log and photopanel analysis, as well as petrographic thin-section and grain size-based petrophysical analysis. Based on texture and sedimentary structures, twelve depofacies are recognised which are broadly grouped into four lithofacies associations i.e. sandstone facies, heterolithic facies, mudstone facies and soft-sediment deformation facies; these depofacies and lithofacies form the basic building blocks for the flooding surface-bounded facies succession (i.e. cycle). Also, based on sediment stacking and cycle thickness patterns as well as relative position to the shelf break, the succession is sub-divided into: (1) the lower Kookfontein member (i.e. cycles 1 to 5) exhibiting overall upward thickening and coarsening succession with progradational stacking pattern; representing deposition of mid-slope to top-slope/shelf-margin succession, and (2) the upper Kookfontein member (i.e. cycles 6 to 13) exhibiting overall upward thickening and coarsening succession with aggradational stacking pattern; representing deposition of top-slope/shelf-margin to outer shelf succession. Lateral juxtaposition of observed vertical facies variations across each cycle in an inferably basinwards direction exhibits upward change in features, i.e. decrease in gravity effects, increase in waves and decrease in slope gradient of subsequent cycles. This systematic upward transition in features, grading vertically from distal to proximal, with an overall upward thickening and coarsening progradational to aggradational stacking pattern indicates a normal regressive prograding delta. However, in detail, cycles 1-3 show some anomalies from a purely thickening and coarsening upward succession. Deposition of each cycle is believed to result from: (1) primary deposition by periodic and probably sporadic mouthbar events governed by stream flow dynamics, and (2) secondary remobilisation of sediments under gravity. The facies distribution, architecture and geometry which governs the sedimentary heterogeneity within the deltaic succession is therefore mainly a consequence of the series of mouthbar flooding events governed by sediment supply and base-level changes. These series of flooding events resulted in the delineation of the studied stratigraphic interval into two main parasequence sets, i.e. transgressive sequence set and the overlying regressive sequence set. This delineation was aided through the identification of a maximum flooding surface (i.e. maximum landwards shift in facies) above Cycle 3 in the field. The architecture and geometry of the ensuing deposystem is interpreted to have been a river-dominated, gravitationally reworked and waveinfluenced shelf edge Gilbert-type delta. Widespread distribution of soft-sediment deformation structures, their growth-style and morphology within the studied succession are empirically related to progradation of Gilbert-type mouthbars over the shelf break as well as the slope gradients of the Kookfontein deltaic clinoformal geometry. Analysis of hypothetical facies stacking and geometrical models suggests that the Kookfontein sedimentary cyclicity might not be accommodation-driven but rather sediment supply-driven. The workflow employed for petrophysical evaluation reveals that the distribution of reservoir properties within the Kookfontein deltaic sandbody geometries is strongly influenced both by depositional processes and by diagenetic factors, the latter being more important with increased burial depth. The reservoir quality of the studied sandstones decreases from proximal mouthbar sands, intermediate delta front to distal delta front facies. The major diagenetic factors influencing the reservoir quality of the studied sandstones are mechanical compaction, chemical compaction (pressure solution) and authigenic pore-filling cements (quartz cement, feldspar alteration and replacement, calcite cement, chlorite and illite). Mechanical compaction was a significant porosity reducing agent while cementation by authigenic quartz and clay minerals (i.e. illite and chlorite) might play a major role in permeability distribution. The porosity-permeability relationship trends obtained for the studied sandstones show that there is a linear relationship between porosity and permeability. The relative timing of diagenetic events as well as the percentages of porosity reduction by compaction and cementation indicates that compaction is much more responsible for porosity reduction than cementation. The described internal heterogeneity in this work is below the resolution (i.e. mm-scale) of most conventional well-logs, and therefore could supplement well-log data especially where there is no borehole image and core data. The combination of ‗descriptive‘ facies model and schematic geological model for this specific delta, and petrophysical characterisation make the results of this study applicable to any other similar ancient deposystem and particularly subsurface reservoir analogue.
AFRIKAANSE OPSOMMING: Hierdie studie bied ‘n dagsoomkarakterisering en -modellering van die duidelik blootgelegde Permiese Kookfontein-formasie van die Ecca-groep in die Tankwa-Karoo-subkom. Wat die sedimentêre modellering (d.w.s. fasiesargitektuur en -geometrie) en petrofisiese karakterisering betref is ‘n hiërargiese en deterministiese benadering gevolg. Kwantitatiewe dagsoomdata is gebaseer op dertien sedimentêre siklusse wat hierdie stratigrafiese opeenvolging in die Pienaarsfontein se Berg-lokaliteit kenmerk; en die data is geanaliseer met behulp van ‘n kombinasie van gedetailleerde sedimentêre seksie, gammastraal-profiel en fotopaneelanalises, asook petrografiese slypplaatjie- en korrelgrootte-gebaseerde petrofisiese analises. Op grond van tekstuur en sedimentêre strukture is twaalf afsettingsfasies onderskei wat rofweg in vier assosiasies van litofasies gegroepeer kan word: sandsteenfasies, heterolitiese fasies, moddersteenfasies en sagtesediment-deformasiefasies. Hierdie afsettingsfasies en litofasies vorm die basiese boustene vir die fasiesopeenvolging (d.w.s. siklus) wat oorstromingsoppervlakgebonde is. Verder word die opeenvolging aan die hand van sedimentstapeling en skilusdiktepatrone, asook relatiewe posisie tot die rakbreuk, in die volgende onderverdeel: (1) die benede-Kookfontein-deel (d.w.s. siklus 1 tot 5), wat in die geheel ‘n opwaartse verdikkings- en vergrowwingsopeenvolging met ‘n progradasiestapelpatroon vertoon en die afsetting van middelhelling-tot-boonstehelling- of rakrand-opeenvolging verteenwoordig, en (2) die benede-Kookfontein-deel (d.w.s. siklus 6 tot 13) wat in die geheel ‘n opwaartse verdikkings- en vergrowwingsopeenvolging met ‘n aggradasiestapelpatroon vertoon en die afsetting van boonste helling- of rakrand-tot-buiterakopeenvolging verteenwoordig. Die laterale jukstaposisie van waargenome vertikale fasiesvariasies oor elke siklus heen, in ‘n afleibare komwaartse rigting, vertoon opwaartse verandering wat kenmerke betref, naamlik afname in gravitasiegevolge, toename in golwe en afname in die hellinggradiënt van daaropvolgende siklusse. Hierdie stelselmatige opwaartse oorgang van kenmerke, wat vertikaal van distaal tot proksimaal gradiënteer en in die geheel opwaartse verdikking en vergrowwing in ‘n progradasie-tot-aggradasie-stapelpatroon vertoon, dui op ‘n normale regressiewe progradasiedelta. Van naby beskou, vertoon siklus 1-3 egter bepaalde afwykings van ‘n suiwer opwaartse verdikkings- en vergrowwingsopeenvolging. Die afsettings van elke siklus is vermoedelik die gevolg van: (1) primêre afsetting deur periodieke en waarskynlik sporadiese mondversperringsgebeure wat deur stroomvloeidinamika beheer word, en (2) sekondêre hermobilisering van sedimente deur gravitasie. Die fasiesverspreiding, -argitektuur en -geometrie wat die sedimentêre heterogeniteit in die deltaïese opeenvolging beheer, is dus hoofsaaklik ‘n gevolg van die reeks oorstromingsgebeure by die mondversperring, wat deur sedimentvoorsiening en basisvlakveranderings beheer word. Hierdie reeks oorstromingsgebeure het gelei tot die delineasie van die bestudeerde stratigrafiese interval volgens twee hoofparasekwensie stelle, naamlik die transgressiewe opeenvolgings- en die oordekkende, regressiewe opeenvolgingsgroep. Dié delineasie word ondersteun deur die feit dat ‘n maksimum oorstromingsoppervlak (d.w.s. maksimum landwaartse verskuiwing in fasies) bo siklus 3 in die veld uitgeken is. Die argitektuur en geometrie van die daaropvolgende afsettingstelsel word geïnterpreteer as behorende tot ‘n Gilbert-rakranddelta wat deur ‘n rivier gedomineer, deur gravitasie herbewerk en deur golfwerking beïnvloed is. Die wye verspreiding van sagtesediment-deformasiestrukture, en die groeiwyse en morfologie daarvan binne die bestudeerde opeenvolging, is empiries verwant aan die progradasie van Gilbertmondversperrings oor die rakbreuk heen, asook aan die hellinggradiënte van die Kookfontein-deltaïese, klinoformele geometrie. Die analise van hipotetiese fasiesstapeling en geometriese modelle dui daarop dat die Kookfontein-sedimentêre siklisiteit dalk nie deur akkommodasieruimte gedryf word nie, maar deur sedimentvoorsiening. Die werkvloei wat vir petrofisiese evaluering gebruik is dui daarop dat die verspreiding van reservoir-eienskappe in die Kookfontein- deltaïese sandliggaam geometries sterk beïnvloed word deur afsettingsprosesse en diagenetiese faktore. Die diagenetiese faktore word belangriker op groter begrawing diepte. Die reservoir-aard van die bestudeerde sandgesteentes neem algaande af van proksimale mondversperring-sandsoorte tot intermediêre deltafront tot distale deltafrontfasies. Die hoof-diagenetiese faktore wat die reservoir-kenmerke van die bestudeerde sandsteensoorte beïnvloed is meganiese verdigting, chemiese verdigting (oplossingsdruk) en outigeniese porievullingsement (kwartssement, veldspaatomsetting en -vervanging, kalsietsement, chloriet en illiet). Meganiese verdigting is ‘n beduidende poreusheidreduseermiddel, terwyl sementering deur outigeniese kwarts- en kleiminerale (d.w.s. illiet en chloriet) moontlik ‘n belangrike rol by permeabiliteitsverspreiding kan speel. Die poreusheid-permeabiliteit-verhoudingstendense wat bekom is vir die bestudeerde sandsteensoorte dui daarop dat daar ‘n lineêre verhouding tussen poreusheid en permeabiliteit bestaan. Die relatiewe tydberekening van diagenetiese gebeure, asook die persentasie poreusheidvermindering deur verdigting en sementering, dui daarop dat verdigting baie meer as sementering tot poreusheidvermindering bydra. Die interne heterogeniteit wat in hierdie werk beskryf word, is onder die resolusie (d.w.s. mm-skaal) van die meeste konvensionele boorgatopnames, en kan dus boorgatopnamedata aanvul, veral waar daar geen boorgatafbeelding en kerndata bestaan nie. Die kombinasie van die 'deskriptiewe‘ fasiesmodel en skematiese geologiese model vir hierdie spesifieke delta, asook petrofisiese karakterisering, beteken dat die resultate van hierdie studie op enige ander soortgelyke antieke afsettingstelsels toegepas kan word, maar veral op suboppervlakreservoir-analoogstelsels.

Magister Scientiae - MSc (Earth Science)
The Orange basin is relatively underexplored with 1 well per every 4000km2 with only the Ububhesi gas field discovery. Block 1 is largely underexplored with only 3 wells drilled in the entire block and only well A?F1 inside the 1500km2 3?D seismic data cube, acquired in 2009. This study is a reservoir characterization of well A?F1, utilising the acquired 3?D seismic data and re?analysing and up scaling the well logs to create a static model to display petrophysical properties essential for reservoir characterization. For horizon 14Ht1, four reservoir zones were identified, petro?physically characterized and modelled using the up scaled logs. The overall reservoir displayed average volume of shale at 24%, good porosity values between 9.8% to 15.3% and permeability between 2.3mD to 9.5mD. However, high water saturation overall which exceeds 50% as per the water saturation model, results in water saturated sandstones with minor hydrocarbon shows and an uneconomical reservoir.

Bien que les zones de failles représentent un très petit volume de la croute terrestre, elles influencent grandement ses propriétés hydromécaniques. Ce travail compare des analyses multidisciplinaires, de hautes précisions, de deux zones de failles aux propriétés contrastées : l’une est une zone de failles mature de plusieurs kilomètres de long, l’autre s’étend seulement sur quelques centaines de mètres. Leurs propriétés architecturales, hydromécaniques et de résistance mécanique ont été caractérisées dans le but d’améliorer la compréhension des couplages entre l’évolution de leurs propriétés hydromécaniques et leur potentiel de réactivation. Un protocole de caractérisation in-situ des propriétés hydrauliques et mécaniques a été mis au point. Il intègre des analyses microstructurales, des descriptions détaillées des propriétés pétrophysiques à plusieurs échelles. Les deux zones de failles étudiées montrent toutes deux des relations entre leurs histoires diagénétiques, les propriétés initiales des formations sédimentaires et leurs propriétés actuelles hydromécaniques. Il a été mis en évidence que le paramètre le plus important gouvernant le comportement hydromécanique des zones de failles est la continuité de sa zone d’endommagement. Une zone de failles mature aura une zone d’endommagement relativement continue alors qu’une zone de failles non-mature aura une zone d’endommagement hétérogène caractérisée par une alternance de niveaux fracturés et non-fracturés. Ces contrastes architecturaux dépendent des propriétés initiales de la roche intacte. Au sein de la série sédimentaire, les variations de la résistance à la compression (σc) de la roche intacte induisent différents mécanismes d’accommodations des déformations. Il en résulte une architecture de zone de failles présentant de fortes variations d’épaisseur, caractérisée par une alternance de niveaux très perméables et très déformables avec des niveaux imperméables et peu déformables
Although fault zones represent a very small volume of the crust, they highly influence the crust’s mechanical and fluid flows properties. This work compares high definition trans-disciplinary analyses of two fault zones with highly contrasted properties. One is a mature fault zone of plurikilometer length, and the other is a small fault zone of a few hundred meters length. We have characterized the architectural, hydromechanical and strength properties of these faults to improve the understanding of the coupling between fault zones hydromechanical properties and their potential activation. A protocol to characterize in the field (on outcropping segments) the faults hydraulic and mechanical properties has been conducted through the coupling of micro-structural analyses, detailed rock physical descriptions at the rock mass several scales. The two studied fault zones despite their different sizes display some similarities. Both show a strong coupling between the fault zone diagenetic history, the initial properties of the sedimentary layers and the fault zone current hydraulic and mechanical properties. We show that the most important parameter governing the hydromechanical behaviors of fault zones is the continuity of the damage zones. A mature fault zone will have a relatively continuous damage zone while a small fault zone will contain a more heterogeneous damage zone characterized by an alternation of fractured and un-fractured layers. These architectural contrasts of damage zones also depend on the initial intact rock properties of the sedimentary series. Contrasted initial intact rock strengths (σc) induce contrasted strain accommodation mechanisms in the fault zone compartments, and an associated fault zone architecture that displays large thickness variations, characterized by alternate high-permeable-low-stiff and low-permeable-high-stiff layers in the damage zone

The understanding of multiphase flow properties is essential for the exploitation of hydrocarbon reserves in a reservoir; these properties in turn are dependent on the geometric properties and connectivity of the pore space. The determination of the pore size distribution in carbonate reservoirs remains challenging; carbonates exhibit complex pore structures comprising length scales from nanometers to several centimeters. A major challenge to the accurate evaluation of these reservoirs is accounting for pore scale heterogeneity on multiple scales. This is the topic of this thesis. Conventionally, this micron scale information is achieved either by building stochastic models using 2D images or by combining log and laboratory data to classify pore types and their behaviour. None of these capture the true 3D connectivity vital for flow characterisation. We present here an approach to build realistic 3D network models across a range of scales to improve property estimation through employment of X-ray micro-Computed Tomography (μCT) and Focussed Ion Beam Tomography (FIBT). The submicron, or microporous, regions are delineated through a differential imaging technique undertaken on x-ray CT providing a qualitative description of microporosity. Various 3-Phase segmentation methods are then applied for quantitative characterisation of those regions utilising the attenuation coefficient values from the 3D tomographic images. X-ray micro-CT is resolution limited and can not resolve the detailed geometrical features of the submicron pores. FIB tomography is used to image the 3D pore structure of submicron pores down to a scale of tens of nanometers. We describe the experimental development and subsequent image processing including issues and difficulties resolved at various stages. The developed methodology is implemented on cores from producing wackstone and grainstone reservoirs. Pore network models are generated to characterise the 3D interconnectivity of pores. We perform the simulations of petrophysical properties (permeability and formation resistivity) directly on the submicron scale image data. Simulated drainage capillary pressure curves are matched with the experimental data. We also present some preliminary results for the integration of multiscale pore information to build dual-scale network models. The integration of multiscale data allows one to select appropriate effective medium theories to incorporate sub-micron structure into property calculations at macro scale giving a more realistic estimation of properties.

Orientadores: Sandro Guedes de Oliveira, Lúcia Duarte Dillon
Dissertação (mestrado) - Universidade Estadual de Campinas, Instituto de Física Gleb Wataghin
Made available in DSpace on 2018-08-17T17:53:23Z (GMT). No. of bitstreams: 1 Abreu_ElitaSelmarade_M.pdf: 3986219 bytes, checksum: 3254aa4fe691af01904819c1fb348ada (MD5) Previous issue date: 2010
Resumo: O principal propósito dessa dissertação é estudar modelos de meio efetivo de física de rochas que conecte as propriedades petrofísicas e as propriedades elásticas, assim como a sua aplicação na investigação dessas propriedades em rochas carbonáticas. Inicialmente será feita uma introdução a alguns modelos de física de rochas para meio efetivo, conhecidos como modelo de Voigt-Reuss-Hill, modelo de Kuster & Toksöz, modelo Diferencial de Meio Efetivo e relação de Gassmann, com objetivo de estabelecer os parâmetros que serão medidos e utilizados no desenvolver do trabalho. Após essa parte introdutória, baseado no modelo de Xu-Payne, foram realizadas uma série de análises de atributos geométricos, como a distribuição de tipos de poros, obtidas através de lâminas petrográficas com intuito de descrever a correlação entre as propriedades petrofísicas e elásticas e assim poder calibrar o modelo teórico utilizado na predição dessas propriedades. Dessa forma, o modelo calibrado passa a desempenhar um papel mais condizente com o sistema poroso da rocha permitindo uma melhor correlação entre os parâmetros elásticos e petrofísicos. Os resultados obtidos mostram que a utilização da informação de lâminas petrográficas, na parametrização do modelo, torna o método mais robusto na predição e conexão das propriedades elásticas e petrofísicas de rochas carbonáticas, tornando confiável a mudança de escala rocha-perfil, bem como possibilitando a predição qualitativa de propriedade permo-porosas a partir da velocidade da rocha
Abstract: The main purpose of this dissertation is to study rock physics effective models that connect the petrophysics and elastic properties as well as its application on the investigation of these properties on carbonate rocks. Firstly, we make an introduction to some rock physics of effective models as: Voig-Reuss-Hill, Kuster&Toksöz, Differential Effective Medium, Gassmann¿s Relation, aiming at establishing the parameters that will be measured and used latter. After this introductory part and based on the Xu-Payne model, several geometric factors analysis was done like pore types distribution, obtained by thin sections, with the intention of describing the correlation between the petrophysics and elastic properties. In this way, the model becomes more compatible with the rock porous medium, allowing a better correlation between the petrophysics and elastic parameters. Our results show that using the thin section information on the model parametrization, the predictability and connectivity of petrophysics and elastic properties applied to carbonate rocks become more robust, making trustable the upscale rock-well log and also enabling the permo-porosity properties prediction, in a qualitative way, through the velocity measurements
Mestrado
Física
Mestra em Física

Les dépôts gravitaires carbonatés peuvent former d'importants volumes à la transition plate-forme/bassin; notamment en domaine tropical où les biotopes néritiques carbonatés sont de prolifiques usines à sédiments pouvant être redéposés dans le milieu marin profond adjacent. Ce travail porte sur les dépôts gravitaires carbonatés d'âge Crétacé de la Péninsule du Gargano (SE Italie). Une cartographie géologique détaillée et la modélisation numérique 3D (supportées par un MNT obtenu par LIDAR héliporté) ont été couplées à des analyses sédimentologiques et biostratigraphiques afin de caractériser l'évolution spatiale et temporelle de systèmes de dépôts gravitaires distincts. Les surfaces stratigraphiques 3D ont été restaurées afin d'évaluer l'impact de la paléo-topographie sur la distribution spatiale et la géométrie des corps. La corrélation avec les séries de plate-forme de même âge a permis d'établir les relations entre nature des resédimentations (sables vs. brèches) et le niveau marin. Les données qualitatives et quantitatives d'affleurements ont permis de générer des modèles numériques 3D de lithofacies à partir de méthodes de simulations stochastiques. Enfin, des mesures des paramètres physiques des roches ont été couplées à des analyses pétrographiques afin de d'évaluer l'impact de la fabrique sédimentaire et des types poreux sur les propriétés acoustiques et réservoirs de ces carbonates. Cette approche multidisciplinaire démontre l'importance du couplage de méthodes d'analyses de terrain dites «traditionelles» avec des donnés numériques et la modélisation 3D afin d'améliorer la caractérisation et les modèles des systèmes et réservoirs sédimentaires
Carbonate gravity flow deposits can form significant volumes at the platform-to-basin transition; especially because tropical shallow-water carbonate environments are major sediment factories, the products of which, early lithified or not, are likely to be redeposited in the adjacent deep marine domain. This work has focused on the Cretaceous resedimented carbonates of the Gargano Peninsula (SE Italy). Extensive geological mapping and 3-D numerical modelling (supported by a LIDAR DEM) were associated to sedimentologic and biostratigraphic analyses to assess the spatial and temporal evolution of distinct deep-water depositional systems. Key 3-D stratigraphic surfaces were restored to investigate the impact of the paleo-topography on the geometry and spatial distribution of the gravity flow deposits. Correlation with the coeval shallow-water platform series has served to assess the relationships between the nature of the resedimented carbonates (i.e. bioclastic sands versus breccias) and sea level. Qualitative and quantitative outcrop data were transferred into 3-D numerical models of lithofacies that were generated at seismic scale with stochastic simulation methods. Finally, petrophysical measurements were coupled with quantitative petrographic analyses to assess the impact of sedimentary fabrics and pore types on acoustic and reservoir properties of carbonate gravity flow deposits. This multidisciplinary approach demonstrates that coupling traditional field work analyses with outcrop numerical data (e.g. LIDAR-derived) and 3-D geological modelling is a relevant method for improving outcrop characterization and conceptual models of sedimentary systems and reservoirs

Depuis une dizaine d'années, une volonté internationale de réduction des émissions de gaz à effet de serre s'est développée, afin de limiter leur concentration dans l'atmosphère. Ainsi, il est envisagé de récupérer le CO₂ issu d'activités humaines fortement émettrices afin de le réinjecter dans le sous-sol à l'état supercritique. Hors du panache de CO₂ supercritique, ce gaz se dissout dans la saumure et l'acidifie. Deux phénomènes ont alors lieu. Ils constituent la base des études menées au cours de cette thèse : (i) le devenir des espèces chimiques mobilisées par la dissolution des minéraux, et (ii) les variations des propriétés d'écoulements induites par la réactivité de la roche encaissante. Pour étudier ces phénomènes, des expériences ont été menées sur les carbonates de Lavoux et de St-Emilion. Ces deux échantillons naturels ont été sélectionnés pour leur composition minérale modèle qui assure une forte réactivité dans le contexte de l'étude, et l'absence d'argile et de matière organique qui limite la complexité du système géochimique. Les expériences menées sont de deux types. En autoclave, la compétition entre dissolution et sorption des éléments traces est mise en avant et permet d'investiguer des conditions variant de celles de la surface (20°C – 1 atm) à celles d'un site de stockage (40°C – 90 bar de CO₂) en passant par des intermédiaires de pression (30 et 60 bar). Les effets de la salinité de la saumure, de la concentration initiale en cations divalents ainsi que de l'état de l'échantillon solide (poudre, plug) sont étudiés. D'autre part, un dispositif expérimental a été développé au cours de cette thèse. Il permet d'étudier les propriétés de diffusion d'éléments traces à travers une carotte dans des conditions représentatives de celles d'un réservoir de stockage de CO₂. Les résultats expérimentaux obtenus mettent en évidence à la fois l'impact de la dissolution sur la mobilisation des espèces chimiques, la compétition entre différents cations pour la sorption et les conséquences de cette sélectivité sur le transport et la disponibilité des espèces chimiques. L'étude pétrophysique des échantillons réagis met en évidence une augmentation de la porosité, et une tendance à l'uniformisation du réseau de pore. Les données obtenues dans les expériences en batch permettent d'obtenir par simulation les paramètres de sorption du système pour les différents éléments traces, en fonction des conditions de pression. Grâce à ces différents résultats, la surveillance de sites de stockage géologique de CO₂ est possible dans différentes formations, et permet un suivi à la fois des flux des espèces chimiques et des propriétés d'écoulement
Over the last decade, an international will to reduce the emissions of greenhouse gases in the atmosphere developed, in order to limit their atmospheric concentration. Thus, to deal with the large amounts of CO₂ produced by human activities, this gas is to be injected under supercritical state in the underground. Outside the CO₂ plume, this gas dissolves within brine and acidifies it. Two phenomena occurs then. They are the main subject of this work: (i) the fate of chemical species mobilized by mineral dissolution, and (ii) the evolution of flooding properties induced by mineral reactivity. To study those phenomena, experiments were carried out on the Lavoux and the Saint-Emilion carbonates. Those two natural samples were selected because their mineralogical composition ensures a high reactivity and limits the complexity of the geochemical system, as they contain neither clays nor organic matter. Two types of experiments were carried out. Competition between dissolution and sorption was studied in batch reactors, from conditions similar to those of the surface (20°C – 1 atm) to those of a storage site (40°C – 90 bar of CO₂), passing by intermediate pressures (30 and 60 bar). The parameters investigated are salinity, initial concentration of divalent cations, and the state of solid samples (powder, core). On the other hand, an experimental setting was developed during the thesis project. It allows the study of trace elements diffusion through a core in CO₂ geological storage conditions. The experimental results evidence the impact of dissolution on chemical species mobilization, competition between those species regarding sorption and consequences of this selectivity on transport and availability of those chemical species. The petrophysical study of reacted samples evidence a porosity increase and the homogenization of the porous network. The data resulting from the batch experiments are used as input data for simulations, in order to estimate sorption parameters of trace elements in the systems investigated. Thanks to those results, the monitoring of CO₂ geological storage sites is possible within several different geological formations, and allows to track both flux of chemical species and flooding properties evolution

Le stockage géologique est aujourd'hui envisagé dans plusieurs domaines tels que le stockage de CO2 ou celui de déchets nucléaires. C'est un projet à long terme qui nécessite un protocole d'étude particulier afin de déterminer et comprendre la formation envisagée, notamment en termes de mécanismes de transports. Les formations étudiées sont fonction du type de stockage dans le sens où un stockage de gaz ou de déchet radioactifs ne vont pas requérir les mêmes besoins. Dans le cas d'un stockage de CO2, la formation hôte doit posséder de bonnes propriétés réservoirs afin de, notamment, faciliter l'injection. Pour un stockage de déchets radioactifs, la formation hôte doit retenir au maximum les éventuelles fuites de fluides contaminés, c'est pourquoi les sites de stockage envisagés sont au sein de formation très peu poreuse et très peu perméable, argilite ou granite notamment.Les travaux présentés dans cette thèse sont liés à deux projets de stockage. Le premier a pour but l'étude pétrophysique d'une formation potentiellement hôte d'un stockage de CO2 dans le Bassin Parisien, la formation carbonatée de l'Oolithe Blanche. Cette formation, composée de trois faciès principaux, présente de faibles propriétés réservoir qui sont influencées par trois paramètres microstructuraux : la nature du liant, la quantité de compaction et, enfin, la taille des pores et leur distribution.Le second projet est basé sur l'étude d'un analogue structurale au laboratoire de Meuse/Haute-Marne de l'Andra pour le stockage de déchets radioactifs. Cet analogue est situé dans l'archipel Maltais, qui présente une structure tabulaire très proche de celle observée dans la région du laboratoire de Meuse/Haute-Marne : calcaire/argile/calcaire. Notre étude a permis la mise en évidence de plusieurs périodes de mouvement de fluides oxydants, dont une traversant l'ensemble de la formation argileuse, remettant ainsi en cause ses propriétés d'imperméabilité
Geological storage is now considered as a technical solution for CO2 storage andnuclear waste management (for high-level and intermediate-level long-lived radioactivewaste). A geological storage is a long term project which implies a particular protocol in orderto better determine and to better understand the host rock, especially in terms of transportmechanisms. The geological formations studied are chosen in function of their storagecapacity because gas storage or nuclear waste storage do not need the same requirements.In case of CO2 storage, the host formation must provide good reservoir properties in order tofacilitate the injection. Here, the safety of the storage is guaranteed by traps (structural,residual, mineral) and by the presence of a cap rock. Concerning nuclear waste storage, thehost must retain at best the potential radioactive fluids and gaz leaks, and this is the reasonwhy storage sites are studied within low porous and low permeable formation, like argillite orgranite.The work presented in the PhD thesis is related to two storage projects. The first oneis focused on the petrophysical study of a potential host for CO2 storage in the Paris Basin,the “Oolithe Blanche” carbonate formation. The second project is an analogue study of thesedimentary structure explored in the Meuse/Haute-Marne laboratory. This laboratory isstudied by ANDRA to be the first nuclear waste storage in a deep geological formation inFrance. The analogue was found in maltese archipelagos, which presents almost the sametabular structure as the one observed in the Meuse/Haute-Marne laboratory:limestone/clay/limestone affected by a weak tectonique deformation.In the first part, the Oolithe Blanche Formation study allowed to determine thereservoir properties of the three principals facies of the formation. This study was realized onplugs sampled on quarries in Burgundy (France). Those facies are characterized by differentenvironmental processes and deposit energy; nonetheless, they are all located within ashoreface depositional environment. They are composed of ooids, pellets and bioclasts invarying proportions. The reservoir properties studied showed the Oolithe Blanche Formationis a microporous one. Microstructural parameters which influence reservoir properties are:the cement type (sparite or micrite), amount of compaction characterized by the cementquantity and the contact between elements and, at last, the pore size distribution withinporous elements (micro, meso, macropores).The second part of this project is focused on a more petrophysical study which aimedat characterizing the pore network influence (volume, shape in space) on acoustic velocities,6electrical conductivity and on permeability. The study is completed by the use of permeabilitypredictive models based on mercury porosimetry spectra.The maltese archipelagos study is based on observations made by Missenard et al.(in prep.) .), Rocher et al., (2008) and Missenard et al. (2009, 2011) on the Blue ClayFormation, thick clay formation (~ 100 m) and on the underlying Globigerina Limestone. Theclay formation presents an important fracture network characterized by gypsum filling and byan oxidizing zone near the fractures. A similar oxidation, in the shape of lobes andmushrooms, is observed within the Globigerina Limestone.This study is also divided in two parts. In the first one, the focus is on the study ofgypsum filling fractures. Studying this filling is directly linked with the storage topic, because,in the case of a nuclear waste storage, the absence of fractures and fluid motion is animportant condition to insure the storage security. In the case of gypsums filling, the study isbased on geochemical measurements on oxygen (δ18O), sulphur (δ34S) and strontiumisotopes (87Sr/86Sr) coupled with a fluid inclusion study, all measurements performed ongypsum crystal. Those analyses allow us to propose a downward fluids circulation modelthrought the clays. Fluids source which is at the origin of gypsum’s precipitation seems to beyounger than the hosted formation. Because of the position of the maltese islands, inMediterranean sea, one potential source is the Messinian evaporites, which Sr isotopic ratiocorresponds well to our data set.The second part of the maltese study concerns the oxidation shape observed withinthe Globigerina Limestone. The aim is to determine the processes which allowed thisoxidation. The main question is: are those structures the results of an internal heterogeneityin the rock or the sign of a stop in a fluid motion (stop of the fluid or stop of the oxidizingmechanism)? In order to answer those questions we based our interpretaion on the skeletonof the rock (mineralogy, magnetic mineralogy, microstructural study, geochemistry), on poreand porosity (porosity measurements, mercury porosimetry…), on permeability and on therock anisotropy (susceptibility of magnetic anisotropy (SMA) and acoustic velocitiesanisotropy). Some conflicting differences on the dataset exist, especially on anisotropy data,which can suppose some complex processes

Les propriétés pétrophysiques des réservoirs silicoclastiques sont influencées par de nombreux facteurs sédimentaires et diagénétiques. Les principaux phénomènes diagénétiques affectant les réservoirs sont généralement la cimentation de quartz et les compactions mécanique et chimique. Des réservoirs gréseux ayant des contextes géologiques différents ont été considérés dans cette étude ; les réservoirs carbonifères d'origine deltaïque-marine du bassin des Palmyrides-Sud en Syrie et les réservoirs cambro-ordoviciens du bassin de Sbaa en Algérie. Cette thèse consiste à établir l'histoire diagénétique, déterminer les contrôles sédimentaires et structuraux influençant l'évolution des phénomènes diagénétiques, caractériser l'habitus des cristaux authigènes de quartz formés autour les grains détritiques et aussi mettre en relation les différentes contrôles sédimentaires et diagénétiques sur les caractéristiques des pores et ainsi que sur la variation de la perméabilité. L'histoire diagénétique entre le réservoir du bassin de Sbaa se caractérise par une forte cimentation de quartz composée de trois phases Q1, Q2 /et Q3, par tapissage illitique et ainsi par une importante compaction chimique liée à certains faciès glaciaires et également une cimentation d'argiles principalement en illite mais surtout dans les champs d'Oued Zine et de Bou Hadid. A l'exception du champ de Hassi Ilatou, où une faible cimentation de quartz composée de Q1 a eu lieu. Alors que la diagenèse des réservoirs gréseux du bassin des Palmyrides-Sud est représentée par une faible cimentation de quartz composée d'une seule phase Q1, une absence de compaction chimique, ainsi qu'une cimentation d'argiles dominée par la chlorite et les kaolins. Les analyses microthermométriques des inclusions fluides dans les surcroissances de quartz mettent en évidence une silicification se déroulant principalement entre 100 et 160°C dans les deux bassins. D'après la reconstitution de l'histoire thermique de bassin, cet intervalle de température a été atteint entre le Viséen et la fin du Namurien dans le bassin de Sbaa et au Crétacé supérieur-Paléocène dans le bassin des Palmyrides-Sud. Les analyses isotopiques indiquent une eau originelle météorique et marine, progressivement réchauffée lors de l'enfouissement, et s'enrichissant au fur et à mesure en ¹⁸O dans les pores intergranulaires et des fluides évolués et chauds à l'origine des filonnets. L'habitus des cristaux authigènes de quartz et la forme de croissance montrent une relation avec les phases de ciment de quartz, son taux et la présence/absence de gaz. En effet, des cristaux à prisme court, tronqués par des facettes additionnelles, et des cristaux trapus caractérisent les grès cimentés par une seule phase de quartz authigène, et une fréquence importante des cristaux de quartz à multiples nucléas est constatée dans ces grès. Des cristaux à prisme développé et rarement des cristaux à prisme court caractérisent les grès contenant deux phases du ciment de quartz. Des cristaux peu développés et limités à quelques faces sont présents dans les grès cimentés par trois phases du ciment de quartz dans la paléozone à eau du réservoir dans le champ ODZ. Une forme de croissance en escalier est présente uniquement dans ces derniers grès. La présence des inclusions à hydrocarbures dans les surcroissances de quartz dans la partie supérieure du réservoir ordovicien du champ de Oued Zine indique que la mise en place des hydrocarbures dans le réservoir a été contemporaine à la cimentation de quartz à des températures 100-140°C en raison de la paléostructure anticlinale dans ce champ. Un deuxième épisode a eu lieu suite à la fracturation hercynienne à des températures comprises entre 117-185°C qui augmente vers le nord-ouest du bassin. La composition du gaz dans les inclusions monophasées (92 ± 5 mole %) est comparable à la composition actuelle du gaz dans le réservoir.

Le stockage géologique du CO2 est l'une des diverses technologies étant explorées afin de réduire les émissions de carbone atmosphérique des processus industriels (i.e. combustion de l'énergie fossile). L'une des spécifiques caractéristiques de l'injection du CO2 en profondeur reste la possibilité de réactions géochimiques (dissolution-précipitation) entre la saumure réactive mobile (e.g. eau de formation enrichie en CO2) et la roche encaissante durant l'évolution spatiale et temporelle du CO2, conduisant à des modifications dans la structure des pores et par conséquent dans les propriétés d'écoulement du réservoir (e.g. la perméabilité k). Donc, ces changements structuraux peuvent largement contrôler l'injectivité, ainsi que le champ de pression dans le réservoir et aussi la propagation du CO2. Il demeure ainsi crucial d'explorer les changement dans les propriétés de réservoirs (e.g. structurales et hydrodynamiques) induits durant une injection de CO2 et explicitement les relations existantes entre eux (e.g. k ou surface réactive-Sr versus porosité- , k versus hétérogénéité de la roche), afin de développer des outils de modélisation prédictive des processus de transport et réactionnels se produisant durant une injection de CO2 et d'évaluer de façon fiable les risques. Dans le cas des réservoirs carbonatés, l'application des modèles prédictifs de transport réactif demeure toujours un enjeu, car contrainte par la forte hétérogénéité en leur sein ainsi que par l'incertitude dans la cinétique de réactions des minéraux carbonatés dans ce contexte. Dans cette optique, nous avons réalisé des expériences de percolation à travers des échantillons de roches carbonatées dans les conditions thermodynamiques de stockage en profondeur (T = 100°C et P =12 MPa). L'évolution de la perméabilité est suivie au cours des expériences ; et la variation de la porosité est calculée à partir des résultats d'analyses chimiques au ICP-AES des fluides de sortie échantillonnés. L'investigation des modifications apportées à la structure des pores est réalisée par le biais de la Micro-Tomographie haute résolution à rayon X, acquise au synchrotron de Grenoble (e.g. ESRF). Dépendant du régime de dissolution, contrôlé par la fabrique de la roche réservoir et la composition chimique de la saumuré chargée en CO2 (e.g. PCO2 engagée), on a observé qu'une modification de la structure de la roche peut soit améliorer soit détériorer (résultat atypique en contexte de dissolution) la valeur de la perméabilité k. Mots clés : Stockage géologique du CO2, transport, réactions géochimiques, structure des pores, propriétés hydrodynamiques, expériences de percolation de CO2, micro-tomographie à rayon X
Geological storage of CO2 is one of diverse technologies being explored to reduce atmospheric carbon from industrial processes (i.e. fossil fuel combustion). One of the specific features of CO2 injection is the possibility of geochemical reactions (dissolution – precipitation) between mobile reactive brine (e.g. formation water enriched in CO2) and the host rock during the spatial and temporal evolution of CO2. That leads to modifications in the pore structure which in turn change the flow dynamics of the reservoir (e.g. the permeability k). Then, theses structural modifications can largely control the injectivity, so that the pressure field in the reservoir and also the CO2 propagation. Accordingly, it is crucial to explore the changes in the reservoir properties (e.g. structural and hydrodynamic) induced during a CO2 injection and specially the relationships between them (e.g. k or reactive surface-Sr versus porosity- , k versus rock heterogeneity), for developing predictive modelling tools of the transport and reaction processes occurring during a CO2 injection and reliable risk assessment. In the case of carbonate rocks, the application of the predictive models of transport and reaction is still challenging, because of their high heterogeneity so that the incertitude in the reaction kinetics of carbonate minerals. From this perspective, we realized brine-enriched in CO2 percolation experiments through carbonate rock samples in thermodynamic conditions expected during CO2 injection in deep reservoirs (T = 100°C et P =12 MPa). The permeability changes k(t) is monitored during the experiments and the porosity variation is calculated from chemical analyses of the sampled outlet fluids, using ICP-EAS. The pore structure modifications are investigated from high resolution X ray micro tomography images acquired from the synchrotron of Grenoble (ESRF). Depending to the dissolution regime, controlled by the reservoir rock fabric and the chemical composition of the brine (e.g. PCO2), we observed that a modification of pore structure can either improve (atypical result in dissolution context) or impair the value of the permeability k. Keywords: CO2 geological storage, transport, geochemical reactions, pore structure, hydrodynamic properties, brine enriched in CO2 percolation experiments, X ray microtomography

La géothermie est considérée comme une source d'énergie propre et inépuisable à échelle humaine. Actuellement, le rendement des centrales géothermiques est limité à l'exploitation de fluides de températures inférieures à 350 °C. L'association de l'activité tectonique et volcanique aux dorsales océaniques fait de l'Islande un lieu où l'extraction de fluides supercritiques (T> 375 °C) peut être envisagée. Cette exploitation pourrait multiplier par dix la puissance électrique délivrée par le système géothermal. Ces fluides peuvent-ils circuler dans la croûte océanique ? Ce travail propose de contraindre les observations géophysiques et de prédire le fonctionnement des réservoirs géo-hydrothermaux de très haute température par l'étude des propriétés physiques des basaltes. La première approche est focalisée sur l'étude de roches ayant accueilli une circulation hydrothermale par le passé. L'étude de ces roches au site ODP 1256, montre que leur porosité est associée à la présence de minéraux d'altération hydrothermale du facies amphibolite (T> 500 °C). La seconde approche a consisté à recréer, en laboratoire, les conditions des systèmes hydrothermaux, à très haute température, afin de prédire les propriétés mécaniques et électriques des basaltes dans ces conditions. Les résultats mécaniques indiquent que la transition fragile/ductile, souvent associée à une forte décroissance de perméabilité, intervient à une température d'environ 550 °C. La mise en place d'une cellule de mesure de la conductivité électrique de haute température a fourni les premiers résultats utiles à l'analyse des données géophysiques. Appliqués aux conditions de la croûte basaltique Islandaise, ces résultats indiquent que des fluides hydrothermaux pourraient circuler au moins transitoirement à l'état supercritique jusqu'à ~ 5 km de profondeur.

Автором запропоновано новий підхід до методики визначення адсорбційної здатності гірських порід за рахунок введення параметра адсорбційної водонасиченості та досліджено його зв'язок з фільтраційно-ємнісними властивостями і з закупоркою порового простору порід-колекторів у присвердловинній зоні пласта. Встановлено, що однією із важливих причин істотного зниження фільтраційно-ємнісних властивостей проникних порід у присвердловинній зоні є низька мінералізація фільтратів промивних рідин та вміст в них таких розповсюджених хімреагентів як карбоксиметилцелюлози (КМЦ) та конденсованої сульфіт-спиртової барди (КССБ). Застосування нової розробленої автором установки для лабораторних петрофізичних досліджень, яка зменшує контактний електричний опір та створює умови, наближені до пластових, а також використання нових методичних прийомів вивчення адсорбційної водонасиченості дозволило провести високоточні вимірювання петрофізичних параметрів на зразках гірських порід-колекторів та розробити алгоритм поділу їх на характерні групи, що відрізняються ступенем впливу на них промивних рідин. За результатами статистичної обробки і аналізу даних фізичного моделювання на зразках керну, петрофізичних і геофізичних досліджень, автор подас нову методику оцінки погіршення фільтраційно-ємнісних властивостей проникних пластів у присвердловинній зоні під дією фільтратів бурових розчинів у процесі буріння свердловин.
В диссертации освещаются разные подходы к проблемам изучения изменения фильтрационно-ёмкостных свойств пород-коллекторов в прискважинной зоне, которые охватывают отдельные разделы петрофизики, геофизики, физики нефтегазового пласта и физической химии. Показано, что проникновение в породу-коллектор фильтрата промывочной жидкости и её твёрдой фазы при бурении скважин определяется рядом факторов, основными из которых являются перепад давления, размер поровых каналов, зёрен скелета породы и частиц твёрдой фазы промывочной жидкости. Автором предложен новый подход к методике определения адсорбционной способности горных пород за счёт введения параметра адсорбционной водоиасыщенности, а также исследована его связь с фильтрационно-ёмкостными свойствами и с закупоркой порового пространства пород-коллекторов в прискважинной части пласта. Применение новой разработанной автором установки для петрофизических исследований в условиях, моделирующих пластовые, а также использование новых методических приёмов изучения адсорбционной водонасыщенности позволило провести высокоточные измерения петрофизических параметров на образцах керна и разработать алгоритм разделения пород-колекторов на характерные группы, различающиеся по степени влияния на них фильтратов промывочных жидкостей. Установлено, что одной из важнейших причин существенного снижения фильтрационно-ёмкостных свойств проницаемых пород в прискважинной зоне является низкая минерализация промывочных жидкостей и наличие в ней таких распространённых химреагентов как карбоксиметилцеллюлозы (КМЦ) и конденсированной сульфит-спиртовой барды (КССБ). На основе статистического анализа результатов физического моделирования на образцах керна и геолого-геофизических данных автор представляет новую методику прогнозирования и оценки закупорки прискважинной зоны пластов-коллекторов под воздействием проникающего фильтрата промывочных жидкостей в процессе бурения скважин. Апробация представленного в Диссертации метода оценки закупорки пород-коллекторов на конкретных нефтегазовых месторождениях показала его высокую еффективность. Результаты обработки геологической, технологической и геофизической информации согласно приведенного алгоритма по продуктивных горизонтах Перекоповского, Коржевского и других нефтегазоконденсатных месторождений показали, что для пластов-коллекторов со значительной зоной проникновения фильтрата бурового раствора, наблюдаются повышенные прогнозированные коэффициенты закупорки. Это подтверждается также результатами опробования нефтегазоносных объектов. Из пластов с позитивной характеристикой об их продуктивности, но с повышенными значениями коэффициентов закупорки эффективного порового пространства (К3 >17 %) промышленного притока углеводородной продукции не получено. Рекомендуется таким пластам уделять особое внимание при эксплуатации месторождения (применять различные физико-химические методы интенсификации притока, учитывать временной фактор восстановления проницаемости прискважинной части пласта при депрессиях).
The author has offered a new approach to methods of defining absorptive capacity of geological material due to use of absorptive water saturation parameter, its connection with filtrational-storage properties and with clogging of porous space of reservoir rocks in well bore zone was researched. It was defined that one of important reasons of considerable degradation of permeable rocks filtrational -storage properties in well bore zone is low mineralization of washing fluids filtrates and content of such widely-spread chemical agents as carboxymethyl cellulose (CMC) and condensed spent sulfite-alcohol liquor (CSAL) in them. Application of new equipment which was developed by the author for laboratory petrophysical research, which reduces contact electrical resistance and creates conditions close to reservoir rock ones, as well as application of new methodological research techniques of absorptive water saturation made it possible to fulfill high-precision measurement of petrophysical parameters on reservoir rocks samples and to develop an algorithm of their division by typical groups characterized with washing fluids influence upon them. According to the results of statistical treatment and analysis of physical modeling data on core samples, petrophysical and geological-geophysical research, the author introduces new methods of estimation of permeable beds filtrational-storage properties worsening in well bore zone under the influence of drilling fluid filtrates during well-drilling procedure.

La sédimentation marine récente dans les fosses de subduction est caractérisée par l'interstratification de sédiments hémipélagiques et de turbidites localement intercalées avec les coulées de débris, qui peuvent résulter de la destabilisation des pentes continentales par de tremblements de terre. La marge d’Equateur est constituée par une forte érosion tectonique qui contribue à la formation d'une fosse profonde remplie d'une suite complexe de faciès sédimentaires. La sédimentation par écoulements gravitaires est omniprésente le long de la marge et les faciès vont de dépôts de transport de masse d'épaisseur métriques latéralement continus à des turbidites d'épaisseur centimétriques isolées intercalées avec des couches d'hémipélagites, de volcanoclastiques et de téphras. Nous présentons l'interprétation de la bathymétrie, des profils sismiques à haute résolution et des données pétrophysiques des carottes sédimentaires. L'objectif de cette étude est de décrire la complexité morphologique à la frontière équatorienne de la plaque de Nazca où un ensemble d'aspérités marines profondes ont subducté à différentes échelles, et ses conséquences sur la distribution latérale des sédiments dans les différents sous-bassins. La marge équatorienne comprend trois segments géomorphologiques: Le segment nord, situé au nord de la crête Carnegie, est caractérisé par une large (5-10 km) et profonde fosse (3800-4000 m), une pente continentale ravinée et une plate-forme (10-40 km de large) avec subsidence active. Le segment central en face de la crête de Carnégie montre une fosse étroite (0-5 km de large) et peu profonde (3100-3700 m), la pente escarpée et ravinée, sans canyons, et plateau continental étroit de 15 à 40 km de large caractérisé par des zones d'affaissement et de soulèvement actifs. Enfin, le segment sud, situé au sud de la crête Carnegie, présente une large (5-10 km) et profonde fosse (4000-4700 m), une pente continentale pauvre en sédiments avec des systèmes de canyons bien définis et une large plate-forme de subsidence (20-50 km). La dynamique sédimentaire le long de la marge est évaluée par l'analyse de 15 carottes sédimentaires dont la description visuelle, les photographies à haute résolution, l'imagerie par rayons X, les données XRF et les propriétés pétrophysiques conduisent à l'identification de 11 faciès sédimentaires caractérisant 7 processus sédimentaires: dépôts de turbidite, hémipélagites, téphras, dépôts de coulées de débris, homogénites, des slumps et des dépôts de carbonate de ooze. Les âges des dépôts sont définis par la datation au radiocarbone des sédiments hémipélagites. Les âges vont de 500 à 48000 ans BP. Les profils sismiques à haute résolution permettent de définir 3 echo-faciès: transparent, stratifiés et chaotiques. Le facies transparent est principalement associé aux dépôts d'homogénites, le facies stratifié est associé aux dépôts interstratifiés turbiditique-hémipélagique et le facies chaotique est associé à des dépôts gravitaires grossiers. Le remplissage de la fosse représente un enregistrement lacunaire mais important de l'histoire de la marge de subduction. De grandes coulées de débris se déplaçant vers l'est dans les deux séquences inférieures du remplissage de la fosse sont initiées le long de la paroi extérieure de la fosse, le long de grandes failles normales dues à la flexion de la plaque océanique subductante. Les sédiments de la séquence supérieure du remplissage qui nappent la fosse sont plus largement fournis par la paroi interne de la fosse mais avec un fort contrôle de la ride de Carnegie. En conséquence, la profondeur, la fréquence, l'épaisseur, la composition et la disposition latérale des dépôts sédimentaires varient grandement entre le nord et le sud. Les grands méga-lits simples, les slumps, les coulées de débris et les homogénites sont situés dans les segments nord et sud. Ils sont déclenchés par de grands escarpements de failles régionales, dans le Nord
Recent deep marine sedimentation in subduction trenches is characterized by the inter-stratification of hemipelagic and turbidite sediments locally interbedded with debris flow, which can result from continental slope shaking triggered by earthquakes. The active margin of Ecuador comprises tectonic erosion that contributes to the formation of a deep trench filled by a complex suite of sedimentary facies. Gravity flow sedimentation is ubiquitous along the margin and facies range from laterally continuous m-thick mass transport deposits to isolated cm-thick turbidites intercalated with hemipelagite, volcanoclastics and tephra. In this study we show interpretation of swath bathymetry, high-resolution seismic profiles and petrophysical data from cores. The objective is to describe the morphologic complexity on the Ecuadorian border of the Nazca plate where a set of deep marine asperities is subducting at different scales, and their consequences on the distribution of sediments in the different sub-basins. Ecuadorian margin comprises three geomorphological segments: The northern segment, northward of the Carnegie Ridge, is characterized by a wide (5-10 km) and deep trench (3800 – 4000 m), a gentler gullied continental slope and a shelf (10-40 km wide) with active subsidence. The central segment facing the Carnegie Ridge, is strongly influenced by the subduction of the Carnegie ridge which induces a narrow (0–5 km wide) and shallow trench (3100 – 3700 m depth), a steep and gullied slope with no canyons and a 15–40 km wide shelf characterized by areas with active subsidence and uplift. Finally, the southern segment, southward of the Carnegie Ridge, presents a wide (5–10 km) and deep (4000–4700 m) trench, a starved continental slope with well-defined canyon systems and a wide subsiding shelf (20–50 km). The sedimentary dynamics along the margin is evaluated by the analysis of 15 cores. Visual description, high-resolution photographs, X-Ray imagery, XRF data and petrophysical properties led to the identification of 11 sedimentary facies that characterize seven sedimentary processes: turbidites, hemipelagites, tephras, debris flows, homogenites, slumps, and ooze carbonate deposits. Age of the deposits is defined by radiocarbon age dating of hemipelagic sediments. Ages range from 500 to 48,000 years BP. High-resolution seismic profiles allow definition of three echo-facies: transparent, layered and chaotic. Transparent echo-facies is mainly associated to homogenite deposits, layered echo-facies is associated to the turbiditic-hemipelagic interbedded deposits and chaotic echo-facies is associated to reworked gravity flow deposits. The trench fill represents a lacunar but important record of the subduction margin history. Large eastward debris flows in the lower two sequences of the trench fill are provided by the trench outer wall as a results of slope failures along normal faults due to the downward bending of the oceanic plate. The sediment of the upper sequence of the trench fill draping the trench floor, are largely provided by the inner trench wall strongly controlled by the Carnegie Ridge. As a result, depth, frequency, thickness, composition and lateral disposition of the deposits vary greatly from those at north and south. The large, simple mega-beds like slump, debris flows and homogenites are located at the northern and southern segments. They were triggered by large regional faults in the North and enhanced by the activity of sets of splay faults in the South overhanging the seafloor at the slope toe. Small-size, fluid rich events were triggered by subduction of isolated seamounts at the edges of the Carnegie Ridge due to frequent but small destabilizations of an inner trench wall preconditioned by the impacts of successive seamounts. Sets of partly volcanoclastic turbidites in central segment might have been triggered by the complex interaction of slope and continental shelf deformation by seamount subduction

The objective of my research has been to define the interactions between fluid and rock properties at different environmental conditions and observation scale to reduce the uncertainty in the carbonate reservoir characterization. Here, I integrate field observations, subsurface data, petrophysical and frictional laboratory measurements focusing on carbonate-bearing rocks to better constrain factors controlling fluid-rock interactions with applications to active petroleum systems. In particular, I focus on the Burano-Bolognano carbonate petroleum system that extends from the northern sector of the Majella mountain to the Cigno/Vallecupa oil fields, in Abruzzo Region (Central Italy). This area is of particular interest because of the following reasons: It has received great attention by oil companies in the past for its structural, stratigraphic, and geodynamic evolution, which led it to be an important target for hydrocarbon exploration during the past century. For this reason, it is characterized by a public dense dataset of wells, reports, maps, etc. It allows to study all petroleum system elements (with the exception of the source rock), such as: reservoir, seal, traps, and migration pathways at field scale. It allows to understand the influence of subsurface fluids on the petrophysical properties of carbonate reservoir rocks since the outcropping portions of reservoir interval are both clean and hydrocarbon-saturated. This allows measuring and comparing the variations of petrophysical properties between hydrocarbon-bearing and hydrocarbon-free samples. It is regarded as an analogue of a faulted and fractured reservoir for other carbonate petroleum systems worldwide and in particular in the Adriatic area. The results of my research quantify the influence of fluid properties in changing of the petrophysical and frictional properties of the bearing-carbonate rocks. The presence of viscous fluids, such as heavy hydrocarbons, at ambient temperature defines an increase of the wave velocities respect to those of the unsaturated samples and determines a possible strengthening and stiffening of the reservoir rock. With increasing temperature, distinct downward trends are recorded, especially for the P-wave velocities. Moreover, the presence of fluids along faults promotes a slow slip behaviour, which was more marked with the presence of clay minerals along fault surface. Finally, starting from these results, I simulate the evolution of the Burano-Bolognano petroleum system and the related fluids movements, inferring that within this petroleum system the vertically hydrocarbon migration is driven by fractures/faults and the subsequently lateral migration determinates a gradual oil biodegradation with an increase of its density.

Understanding pore network structure of a porous medium and fluid flow in the pore network has been an interest to researchers for decades. This study focuses on the characterization and simulation of the pore networks in petroleum reservoir rocks using conventional characterization techniques. A Representative Elemental Volume (REV) model is developed which simulates the pore network as a series of non-interconnected capillary tubes of varying sizes. The model implements mercury porosimetry (MP) results and capillary pressure principles to calculate the size of each bundle of capillary tubes based on a pore throat size distribution produced by the MP experiment. It also implements electrical properties of the rocks to estimate the average length of the capillary tubes. To verify the validity of the simulated network, permeability is calculated for the simulated network using Poiseuille’s flow principles for capillary tubes. Preliminary work showed that the model is capable of simulating the pore network reasonably well because permeability estimations for the simulated network matched measurements. In this study, MP and nuclear magnetic resonance (NMR) tests as well as centrifuge and permeability tests are performed on a suite of 11 sandstone and carbonate rock samples. Because electrical tests were not available, average length of flow paths is calculated with an alternative method that uses porosity to calculate tortuosity. Permeability estimations of the simulated network are compared with measurements. Estimations are also compared to other predictions using methods that implement MP and NMR data to simulate the pore network and the results show that the developed REV model out performs all the other techniques.
October 2015

With the recent increase in natural gas production, the demand for college educated petroleum engineers has increased. A greater number of high school graduates are now applying to petroleum engineering degree programs, however, the admission requirements to petroleum engineering schools are becoming increasingly stricter. Secondary educators have a greater challenge to better prepare students to compete for these positions and there is a need to introduce petrophysical concepts to students in the most effective manner. One petrophysical concept is porosity of rock. In this report, background information on rock formation and porosity of rocks is provided along with a brief summary on how 3D printers operate. But primarily, a lesson plan is presented to teach rock porosity in a novel way using 3D printed enlargements of porous rock from x-ray microtomography images of packed sand. The hypothesis was that students will gain greater understanding of petrophysical properties when using 3D prints of rocks. The porosity lesson with a lab using the 3D printed rocks was taught to a treatment group of 20 upcoming 6th graders. A porosity lesson without the use of 3D printed rocks was didactically taught to a control group of 14 additional 6th graders. Because of time limitations, not all of the students from the treatment group were able to experience all elements of the lab. However, every student in the control group received instruction and practice on how to calculate porosity of rock. The treatment group showed greater gain in learning the abstract concept about porosity that rocks of similar structure will have equivalent porosity regardless of grain size. However, the control group indicated greater gain learning the fundamental concepts of the definition of porosity, how to calculate porosity, and at being able to transfer their knowledge of percent porosity to a general problem about percentages. Despite the limited sample size and other sources of error, using 3D printed enlargements of rock was found to enhance students’ abilities to visualize abstract petrophysical properties. However, benefits from didactic instruction of fundamental concepts of petrophysical properties were found as well.
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It is widely recognised that inverted fault zones form economically significant structures for subsurface fluid exploration and production. Inverted fault zones are formed by the contractional reactivation and reversal of pre-existing extensional fault zones. Recognising the reverse-reactivation of normal faults in sedimentary basins is fundamental, as the reconfiguration of fault geometries has implications for overall basin geometry, sediment accommodation and supply, and fluid flow pathways. This is particularly important for understanding the modification or creation of petroleum system elements through time, which in turn allows for increased targeted exploration. Notwithstanding the broad economic relevance of inverted fault zones, integrated multi-scale (from micrometre-scale to outcrop-scale) studies on the structural, petrophysical, and geochemical properties of inverted fault zones within porous reservoir rocks are limited. This thesis characterises the structural, petrophysical, and geochemical properties of inverted fault zones from two localities, the Otway Basin (Australia) and Bristol Channel Basin (United Kingdom), in order to understand how inverted faults influence fluid flow at a range of scales. To address this, this thesis has two main topics of focus: (1) identify the influence of inverted faults on surrounding lithology by assessing the relationship between faults, damage zones around faults, and fractures related to fault growth; and (2) identify how subsurface fluids flow, interact, and modify their surrounds by assessing the geochemistry of fluids in fractures and thereby constraining the source, evolution, and migration of fluids preserved in fractures. An integrated, multi-scale approach is crucial for improving the prediction of subsurface fluid flow beyond the wellbore. In order to understand the influence of inverted faults on surrounding lithology, an inverted fault (Castle Cove Fault) in the Otway Basin, southeast Australia, is the focus of the first two chapters of this thesis. The geometries and relative chronologies of natural fractures adjacent to the Castle Cove Fault are investigated. Structural mapping in the hanging wall damage zone reveals three sets of shear fractures that are geometrically related to the Castle Cove Fault. Inversion of the Castle Cove Fault has resulted in the development of an extensive network of fractures and complex fold structures, and inversion would have subsequently improved the outcrop-scale permeability structure of the damage zone for fluid migration. At the micrometre-scale, the permeability structure has also been influenced by fault inversion. Petrophysical and petrographical analyses in the hanging wall damage zone show that microstructural changes due to faulting have enhanced the micrometre-scale permeability structure of the Eumeralla Formation. These microstructural changes have been attributed to the formation of microfractures and destruction of original pore-lining chlorite morphology as a result of fault deformation. Consequently, inversion has subsequently improved the micrometre-scale permeability structure of the damage zone adjacent to the Castle Cove fault plane. Characterisation of the permeability structure adjacent to reverse-reactivated faults at a range of scales will aid with predicting fluid flow associated with inversion structures. Structural and geochemical analyses in the next two chapters of this thesis aim to understand how subsurface fluids flow and characterise the source, evolution, and migration pathways of fluids preserved in inverted fault zones. The geochemical evolution of fluids precipitated as calcite and siderite-cemented concretions and fractures throughout the eastern Otway Basin have been investigated. Pore fluids were sourced from both meteoric water and sea water during the deposition of the Eumeralla Formation and pore fluid evolution was strongly influenced by diagenetic reactions and increased temperature during burial. Using a similar analytical approach, the geochemical evolution of fluids precipitated as calcite and gypsum-cemented fractures throughout the eastern Bristol Channel Basin have vibeen investigated. The main source of fluids were connate pore waters, which were altered by diagenetic reactions within their host lithologies and subsequently redistributed through migration along faults and their associated damage zones. Knowledge of the source, evolution, and migration pathways of these fluids provides valuable insights for understanding the development of inverted sedimentary basins through time. Consequently, integrated studies on the multi-scaled permeability structure of inverted fault zones and the fluids preserved within them will ultimately improve fluid exploration and monitoring strategies in sedimentary basins.
Thesis (Ph.D.) -- University of Adelaide, Australian School of Petroleum (ASP), 2019

The Upper Devonian Grosmont reservoir in Alberta, Canada, is the single largest carbonate bitumen reservoir in the world, with an estimated 400 billion barrels of bitumen in place. The Grosmont bitumen formed from light crude oil via extensive biodegradation, which produced extremely high in-situ viscosities of >1 million cP. Forty nine samples from fifteen wells were selected for rheological behavior, viscosity, and biodegradation pattern analysis. In addition, various methods of viscosity determination were compared. Results indicate that the Grosmont bitumen is essentially a non-Newtonian fluid at in-situ conditions, exhibiting a distinctive shear-thinning behavior at T < 40C. Neglecting this character will cause inaccurate viscosity measurements. The viscosity variations in the Grosmont reservoir are cyclic with depth and are stratigraphically controlled. The bitumen exhibits 3 levels of biodegradation. Biodegradation parameters from hopanes and tricyclic terpanes may potentially be used for bitumen quality prediction.

Reliable assessment of static and dynamic petrophysical properties of hydrocarbon-bearing reservoirs is critical for estimating hydrocarbon reserves, identifying good production zones, and planning hydro-fracturing jobs. Conventional well-log interpretation methods are adequate to estimate static petrophysical properties (i.e., porosity and water saturation) in formations consisting of thick beds. However, they are not as reliable when estimating dynamic petrophysical properties such as absolute permeability, movable hydrocarbon saturation, and saturation-dependent capillary pressure and relative permeability. Additionally, conventional well-log interpretation methods do not take into account shoulder-bed effects, radial distribution of fluid saturations due to mud-filtrate invasion, and differences in the volume of investigation of the various measurements involved in the calculations. This dissertation introduces new quantitative methods for petrophysical and compositional evaluation of water- and hydrocarbon-bearing formations based on the combined numerical simulation and nonlinear joint inversion of conventional well logs. Specific interpretation problems considered are those associated with (a) complex mineral compositions, (b) mud-filtrate invasion, and (c) shoulder-bed effects. Conventional well logs considered in the study include density, photoelectric factor (PEF), neutron porosity, gamma-ray (GR), and electrical resistivity. Depending on the application, estimations yield static petrophysical properties, dynamic petrophysical properties, and volumetric/weight concentrations of mineral constituents. Assessment of total organic carbon (TOC) is also possible in the case of hydrocarbon-bearing shale. Interpretation methods introduced in this dissertation start with the detection of bed boundaries and population of multi-layer petrophysical properties with conventional petrophysical interpretation results or core/X-Ray Diffraction (XRD) data. Differences between well logs and their numerical simulations are minimized to estimate final layer-by-layer formation properties. In doing so, the interpretation explicitly takes into account (a) differences in the volume of investigation of the various well logs involved, (b) the process of mud-filtrate invasion, and (c) the assumed rock-physics model. Synthetic examples verify the accuracy and reliability of the introduced interpretation methods and quantify the uncertainty of estimated properties due to noisy data and incorrect bed boundaries. Several field examples describe the successful application of the methods on (a) the assessment of residual hydrocarbon saturation in a tight-gas sand formation invaded with water-base mud (WBM) and a hydrocarbon-bearing siliciclastic formation invaded with oil-base mud (OBM), (b) estimation of dynamic petrophysical properties of water-bearing sands invaded with OBM, (c) estimation of porosity and volumetric concentrations of mineral and fluid constituents in carbonate formations, and (d) estimation of TOC, total porosity, total water saturation, and volumetric concentrations of mineral constituents in the Haynesville shale-gas formation. Comparison of results against those obtained with conventional petrophysical interpretation methods, commercial multi-mineral solvers, and core/XRD data confirm the advantages and flexibility of the new interpretation techniques introduced in this dissertation for the quantification of petrophysical and compositional properties in a variety of rock formations.
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