Seismic inversion is the leading method to map and quantify changes in time-lapse (4D) seismic datasets, with applications ranging from monitoring hydrocarbon-producing fields to geological CO2 storage. However, the process of inverting seismic data for reservoir properties is a notoriously ill-posed inverse problem due to the band-limited and noisy nature of seismic data. This comes with additional challenges for 4D applications, given the inaccuracies in the repeatability of time-lapse acquisition surveys. Consequently, adding prior information to the inversion process in the form of properly crafted regularization terms is essential to obtain geologically meaningful subsurface models and 4D effects. In this thesis, I propose a joint inversion-segmentation algorithm for 4D seismic inversion, which integrates total variation and segmentation priors as a way to counteract the missing frequencies and noise present in 4D seismic data. I validate the algorithm with synthetic and field seismic datasets and benchmark it against state-of-the-art 4D inversion techniques. The proposed algorithm shows three main advantages: 1. it produces high-resolution baseline and monitor acoustic impedance models, 2. by leveraging similarities between multiple seismic datasets, the proposed algorithm mitigates the non-repeatable noise and better highlights the real seismic time-lapse changes, and 3. it simultaneously provides a volumetric classification of the acoustic impedance 4D difference model based on user-defined classes, i.e., percentages of seismic time-lapse changes. Such advantages may enable more robust stratigraphic/structural and quantitative 4D seismic interpretation and provide more accurate inputs for dynamic reservoir simulations.

Reservoir heterogeneity plays an important role in oil field economics and completion strategies. We herein characterize the reservoir heterogeneity of the Early Jurassic Navajo Sandstone in the Justensen Flat/Devils Canyon area of the San Rafael Swell, Utah. These outcrops are located approximately 60 kilometers (45 mi) east of the recently discovered Covenant oil field which is located in the central Utah thrust belt exploration play. The reservoir for the Covenant field is the Navajo Sandstone. This study can serve as an outcrop analogue for this developing play and other eolian reservoirs worldwide. There are eight facies within the Navajo Sandstone in the Justensen Flat/Devils Canyon area based on differences in primary and secondary sedimentary structures, sedimentary texture, petrology, porosity/permeability, and other macro-scale features of the outcrop. Three facies were deposited by eolian dunes. These serve as the primary reservoir facies of the Navajo in the Justensen Flat/Devils Canyon area, displaying relatively high porosity and permeability (approximately 28 percent porosity and 100 mD of permeability). Five interdune facies display finer grain size, more abundant cement, and relatively lower porosity and permeability (approximately 18 percent porosity and 29 mD of permeability). Four of the five inderdune facies have variable porosity and permeability or are not laterally extensive (tens of meters). These four facies act as baffles to fluid flow within the reservoir. One interdune facies, the Wavy Algal Matted facies (WAM), displays very low porosity (10 percent) and permeability (0.265 mD) based on 4 samples, and is laterally extensive in the field area (greater than 1 km2). There are nine facies in the Wolverine Federal 17-3 core from the Covenant Field, four of which are tidally influenced. This is unique compare to the Justensen Flat/Devils Canyon outcrop. Tidal influence was apparently present in western Utah but did not have a direct influence on sedimentation 60 kilometers (45 mi) to the east. The Large Trough Cross-stratified (LTC) facies, which serves as the primary reservoir of the Navajo Sandstone, was observed in both outcrop and core. The laterally extensive, low permeability WAM facies was also present in both core and outcrop, suggesting the possibility of reservoir partitioning within oil fields having eolian reservoirs similar to the Navajo Sandstone.

The Lower Triassic Sinbad Limestone Member of the Moenkopi Formation has produced minor amounts of oil in the Grassy Trail Creek field near Green River, Utah and is present below much of central Utah including the recently discovered Covenant field. Superb outcrops of this thin (15 m), mixed carbonate-silicilastic unit in the San Rafael Swell permit detailed analysis of its vertical and lateral reservoir heterogeneity. Vertically, the Sinbad Limestone comprises three facies associations: (A) a basal storm-dominated, well-circulated skeletal-oolitic-peloidal limestone association, (B) a storm-dominated, poorly-circulated hummocky cross-stratified siliciclastic/peloidal association, and (C) a capping peritidal cross-bedded oolitic dolograinstone association. Eleven microfacies are present in 14 measured sections within the Sinbad Limestone. Lateral variation is most pronounced in the upper part of the basal limestone where storm-deposited beds pinch out over a lateral distance of one kilometer. Otherwise, individual beds and microfacies display a large degree of lateral homogeneity and regional persistence. Diagenesis is strongly controlled by microfacies. Diagenetic elements include marine fibrous calcite cements, micritized grains, compaction, dissolution and neomorphism of aragonite grains, meteoric cements, pressure dissolution, and dolomitization. The paragenetic sequence progresses from marine to meteoric to burial. Marine and meteoric cements occlude much of the depositional porosity. Hydrocarbon-lined interparticle and separate vug (largely molds) pores (1-5%) characterize the skeletal-oolitic limestones with permeability ranging from 0-100 md. Low permeability/porosity characterizes the middle silicilastic unit. The best reservoir qualities (permeability 400 md) occur in portions of the dolomitized oolitic grainstones that form the upper 2 to 3 m of the Sinbad Limestone. Fracture analysis of the studied area indicates a strong NW-SE trend. Fracture spacing is associated with lithology. Fracturing of limestone possibly displays a higher dependence upon bed thickness and microfacies type. The degree of dolomitization controls and increases fracture spacing while siltstones display more closely spaced fractures. The basal limestone unit is an oil storage unit, medial siltstones are flow baffles/barriers, and the dolostone caprock is an oil flow unit. If good connectivity through fractures can be obtained between the dolostone and limestone units, the Sinbad Limestone has potential to serve as a reservoir. This study will not only aid in future Sinbad exploration, but will serve as a model for parasequence-scale intervals in thicker mixed carbonate-siliciclastic successions.

Understanding thickness variation and facies transitions in the mudstone-rich part of the Upper Middle Jurassic (Callovian) Entrada Sandstone depositional system is critical for constraining the paleogeography and evaluating the economic potential of Utah's Entrada Sandstone. Facies of the Entrada Sandstone in south-central Utah are dominated by mudstone-rich intertidal facies that were widespread within the Jurassic seaway. Intertidal deposits interfinger basinward with subtidal ooid-bearing shoals and bars, and landward supratidal sabkha, and erg-margin eolian deposits. Three sections were measured to improve understanding of the lateral and vertical facies transitions. Variations in thickness indicate the rate of developing accommodation space was high along the southwestern shoreline and relatively low along the northeastern shoreline during Callovian time. Although accommodation space was highest in the west, sediment supply from the west kept pace with, and eventually outpaced subsidence. In the east, sediment supply was significant but at one time was outpaced by subsidence, creating a complete range of facies, from subtidal to supratidal deposits. Along this eastern shoreline, erg-margin coastal dunes associated with the larger erg to the east eventually prograded westward. The variation in subsidence, sediment supply, and sediment source makes sequence stratigraphic correlation difficult. Reservoir-quality sandstones are associated with muddy sections of the Entrada Sandstone within the San Rafael Swell. Porosity and permeability of the facies in this area indicate excellent reservoir potential in three of eight facies that were studied. Porosities of these potential reservoirs ranged from 11-22%, with permeabilities ranging from 44-430md. These high quality reservoir facies are surrounded by muddy, low reservoir-quality rocks, creating conditions amenable to the development of stratigraphic hydrocarbon traps. Based on further study and a modern analog at the north of the Gulf of California, Hicks and others' (2010) depositional model for the Entrada Sandstone of south-central Utah has been modified to include newly interpreted facies. This improved depositional model may have predictive power in exploring for stratigraphic and combination traps within the Entrada system of Utah and analogous depositional systems throughout the world.

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Reservoir characterization is an essential step in the oil/gas exploration process and is of great significance in the evaluation of oil/gas resources. To evaluate the production potential of the Lower Huron shale in the central Appalachian Basin, matrix permeability, Raman spectroscopy, Fourier Transform infrared spectroscopy (FTIR), and atomic force microscopy (AFM) were used in this study. According to the experimental results, matrix permeability is relatively high for a shale gas formation, suggesting great production potential of shale gas resources in this region. Additionally, four shale samples with varying thermal maturity were characterized by the complementary Raman and FTIR spectroscopy, and curve-fitting results successfully demonstrated the change of chemical structures with the evolution of thermal maturity. Raman spectroscopy results show that the curve fitted G band position and the band separation between the G band and D1 band tend to increase with the rise of thermal maturity level. Results of FTIR spectroscopy show that the aromaticity level and the condensation extent of aromatic rings show an increasing tendency with the increase of maturation level. Moreover, mechanical properties of these four shale samples were characterized by AFM. Results show that Young's modulus is in the range of 8.20 GPa - 12.94 GPa, which is in the normal range compared with the results from other shale formations. Additionally, scanned results show an increasing tendency for Young's modulus of the organic components with the rise of thermal maturity level in these shale samples. The potential reason for this phenomenon was also explored, specifically, the growth of aromatic groups and the decrease of the CH2/CH3 ratio may be possible reasons for the rise of Young's modulus of organic components in these shale samples. This work is meaningful for the evaluation of shale gas resources, especially emerging plays, in the central Appalachian Basin, and it also provides a valuable database for relevant research on shale matrix permeability, Raman, FTIR and AFM. / Master of Science / Reservoir characterization is important in evaluating the production potential of unconventional resources. The purpose of this work is to characterize key reservoir properties of shale samples from the central Appalachian Basin to provide support for improved shale gas production in this region. This work includes the analysis of matrix permeability testing, Raman and Fourier Transform infrared spectroscopy (FTIR) characterization, and atomic force microscopy (AFM) mapping. Matrix permeability testing results show that the matrix permeability of these six samples is relatively high for a shale gas formation, suggesting great production potential of shale gas resources in this region. Additionally, four shale samples with different thermal maturity were scanned using Raman and FTIR spectroscopy, and mineral components of these same four samples were also identified by the FTIR analysis. Processed Raman data show that two important measures, the G band position and the difference between the G band position and D1 band position, tend to increase with the rise of thermal maturity. FTIR results show that the aromaticity rings would likely be compressed due to the increased number of aromaticity rings. Also, AFM provides a high-resolution map for the Young's modulus, a measure of material stiffness, of these four samples. The modulus value is in the normal range compared with scans from other shale formations. In addition, the modulus value tends to increase with the increase of thermal maturity level. The increase of aromatic rings and the decrease of the CH2/CH3 ratio can be regarded as potential reasons for the change of modulus value. This work has potential to improve the production design of shale gas resources, especially emerging plays, in the central Appalachian Basin and can be regarded as a valuable reference for other similar research.

The CO2SINK (and CO2MAN) project is the first onshore CO2 storage project in Europe. The research site is located near the town of Ketzin, close to Potsdam in Germany. Injection started in June 2008, with a planned injection target of 100,000 tonnes of CO2. In February 2011, around 45, 000 tons of CO2 had been injected into the saline aquifer at an approximate depth of 630 m. This thesis focuses on time-lapse analysis of borehole seismic data, surface seismic data and reservoir characterization at the Ketzin site. Baseline Moving Source Profiling (MSP) data were acquired in the borehole Ketzin 202/2007 (OW2), along seven lines in 2007. The zero-offset Vertical Seismic Profile (VSP) data were acquired in the same borehole. The main objective of the VSP and MSP survey was to generate high-resolution seismic images around the borehole. After modeling and data processing, the sandy layers within the Stuttgart Formation can potentially be imaged in the VSP and MSP data whereas reflections from these layers are not as clearly observed in the 3D surface seismic data. 2D and pseudo-3D time-lapse seismic surveys were conducted at the Ketzin site. Interpretation of 2D baseline and repeat stacks shows that no CO2 leakage related time lapse signature is observable where the 2D lines allow monitoring of the reservoir. This is consistent with the time-lapse results of the 3D surveys showing an increase in reflection amplitude just centered around the injection well. The results from the pseudo-3D surveys are also consistent with the 3D seismic time-lapse studies and show that the sparse pseudo-3D geometry can be used to qualitatively map the CO2 in the reservoir with significantly less effect than the full 3D surveying. The 2nd pseudo-3D repeat survey indicates preferential migration of the CO2 to the west. There are no indications of migration into the caprock on either of the repeat surveys. Amplitude Versus Offset (AVO) analysis was performed on both 2D and 3D repeat surveys. A Class 3 AVO anomaly is clearly observed on the 3D repeat data and matches the synthetic modeling well. No AVO anomaly was observed on the 2D repeat data, which was anticipated, but the result shows signs of a pressure response at the reservoir level in the data. Reflection coefficients were calculated using surface seismic data (3D and pseudo-3D) at the site. Pre-injection calculations agree well with calculations from logging data. Post-injection calculations are in general agreement with the seismic modeling, but generally show higher amplitudes than those expected. The full 3D data show a better image of the reflection coefficients before and after injection than the pseudo-3D data and can potentially be used to make quantitative calculations of CO2 volumes. The pseudo-3D data only provide qualitative information.

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[pt] A inversão sísmica é o processo de transformar dados de Sísmica de Reflexão em valores quantitativos de propriedades petroelásticas das rochas. Esses valores, por sua vez, podem ser correlacionados com outras propriedades ajudando os geocientistas a fazer uma melhor interpretação que resulta numa boa caracterização de um reservatório de petróleo. Existem vários algoritmos tradicionais para Inversão Sísmica. Neste trabalho revisitamos a Inversão Colorida (Impedância Relativa), a Inversão Recursiva, a Inversão Limitada em Banda e a Inversão Baseada em Modelos. Todos esses quatro algoritmos são baseados em processamento digital de sinais e otimização. O presente trabalho busca reproduzir os resultados desses algoritmos através de uma metodologia simples e eficiente baseada em Redes Neurais e na pseudo-impedância. Este trabalho apresenta uma implementação dos algoritmos propostos na metodologia e testa sua validade num dado sísmico público que tem uma inversão feita pelos métodos tradicionais. / [en] Seismic inversion is the process of transforming Reflection Seismic data into quantitative values of petroleum rock properties. These values, in turn, can be correlated with other properties helping geoscientists to make a better interpretation that results in a good characterization of an oil reservoir.There are several traditional algorithms for Seismic Inversion. In this work we revise Color Inversion (Relative Impedance), Recursive Inversion, Bandwidth Inversion and Model-Based Inversion. All four of these algorithms are based on digital signal processing and optimization. The present work seeks to reproduce the results of these algorithms through a simple and efficient methodology based on Neural Networks and pseudo-impedance. This work presents an implementation of the algorithms proposed in the methodology and tests its validity in a public seismic data that has an inversion made by the traditional methods.