Thesis (doctoral)--Universität Wien.. / Thematic catalog: leaves 11-110. Includes bibliographical references (leaves 1-3).

Thesis--University of Pennsylvania. / Vol. 2 contains the author's transcription in score of 14 of Gassmann's divertimenti. "Thematic catalogue of Florian Gassmann's divertimenti": v. 2, leaves 145-161. Includes bibliographical references. Also issued in print.

Thesis--University of Pennsylvania. / Vol. 2 contains the author's transcription in score of 14 of Gassmann's divertimenti. "Thematic catalogue of Florian Gassmann's divertimenti": v. 2, leaves 145-161. Includes bibliographical references.

Carbonate reservoirs are usually diffcult to map and identify in seismic sections due to their complex structure, lithology and diagenetic frabrics. The Midland Basin, located in the Permian Basin of West Texas, is an excellent example of these complex carbonate structures. In order to obtain a better characterization and imaging of the carbonate buildups, an acoustic impedance inversion is proposed here. The resolution of the acoustic impedance is the same as the input seismic data, which is greatly improved with the addition of the low frequency content extracted from well data. From the broadband volume, high resolution maps of acoustic impedance distributions were obtained, and therefore the locations of carbonate buildups were easily determined. A correlation between acoustic impedance and porosity extracted from well data shows that areas with high acoustic impedance were correlated with low porosity values, whereas high porosities were located in areas of low acoustic impedance. Theoretical analyses were performed using the time-average equation and the Gassmann equation. These theoretical models helped to understand how porosity distributions affect acoustic impedance. Both equations predicted a decrease in acoustic impedance as porosity increases. Inversion results showed that average porosity values are 5% [plus or minus] 5%, typical for densely cemented rocks. Previous studies done in the study area indicate that grains are moderately to well-sorted. This suggests that time-average approximation will overestimate porosity values and the Gassmann approach better predicts the measured data. A comparison between measured data and the Gassmann equation suggests that rocks with low porosities (less than 5%) tend to have high acoustic impedance values. On the other hand, rocks with higher porosities (5% to 10%) have lower acoustic impedance values. The inversion performed on well data also shows that the fluid bulk modulus for currently producing wells is lower than in non-productive wells, (wells with low production rates for brine and hydrocarbons), which is consistent with pore fluids containing a larger concentration of oil. The acoustic impedance inversion was demonstrated to be a robust technique for mapping complex structures and estimating porosities as well. However, it is not capable of differentiating different types of carbonate buildups and their origin.

Carbonate reservoirs are usually diffcult to map and identify in seismic sections due to their complex structure, lithology and diagenetic frabrics. The Midland Basin, located in the Permian Basin of West Texas, is an excellent example of these complex carbonate structures. In order to obtain a better characterization and imaging of the carbonate buildups, an acoustic impedance inversion is proposed here. The resolution of the acoustic impedance is the same as the input seismic data, which is greatly improved with the addition of the low frequency content extracted from well data. From the broadband volume, high resolution maps of acoustic impedance distributions were obtained, and therefore the locations of carbonate buildups were easily determined. A correlation between acoustic impedance and porosity extracted from well data shows that areas with high acoustic impedance were correlated with low porosity values, whereas high porosities were located in areas of low acoustic impedance. Theoretical analyses were performed using the time-average equation and the Gassmann equation. These theoretical models helped to understand how porosity distributions affect acoustic impedance. Both equations predicted a decrease in acoustic impedance as porosity increases. Inversion results showed that average porosity values are 5% [plus or minus] 5%, typical for densely cemented rocks. Previous studies done in the study area indicate that grains are moderately to well-sorted. This suggests that time-average approximation will overestimate porosity values and the Gassmann approach better predicts the measured data. A comparison between measured data and the Gassmann equation suggests that rocks with low porosities (less than 5%) tend to have high acoustic impedance values. On the other hand, rocks with higher porosities (5% to 10%) have lower acoustic impedance values. The inversion performed on well data also shows that the fluid bulk modulus for currently producing wells is lower than in non-productive wells, (wells with low production rates for brine and hydrocarbons), which is consistent with pore fluids containing a larger concentration of oil. The acoustic impedance inversion was demonstrated to be a robust technique for mapping complex structures and estimating porosities as well. However, it is not capable of differentiating different types of carbonate buildups and their origin.

The permeability in siliclastic rocks can vary due to different pore geometries. The pore properties of a formation can also have significant effects on reflection coefficient. The pore structure of clastic rock may be predicted from a wave reflection using mathematical models. Biot-Gassmann and Sun’s equations are examples of two models which were used in this research to quantify the pore property. The purpose of this thesis is to measure variations in porosity and permeability using 3-D time lapsed seismic during a CO_(2) flood. CO_(2) sequestration EOR will most likely cause permanent diagenetic effects that will alter pore geometry and permeability. This research shows compelling evidence that the pore structure changes in an active CO_(2) flood at the Delhi Holt-Bryant reservoir can be measured with acoustic data. The pore property change is measured by using the Baechle ratio, the Gassmann model, and the Sun framework flexibility factor. The change in the pore properties of the formation also indicates a increase in the permeability of the reservoir as a result of CO_(2) interaction.

Time-lapse seismic is a modern technology for monitoring production-induced changes in and around a hydrocarbon reservoir. Time-lapse (4D) seismic may help locate undrained areas, monitor pore fluid changes and identify reservoir compartmentalization. Despite several successful 4D projects, there are still many challenges related to time-lapse technology. Perhaps the most important are to perform quantitative time-lapse and to model and interpret time-lapse effects in thin layers. The former requires one to quantify saturation and pressure effects on rock elastic parameters. The latter requires an understanding of the combined response of time-lapse effects in thin layers and overcoming seismic vertical resolution limitation. / This thesis presents an integrated study of saturation and pressure effects on elastic properties. Despite the fact that Gassmann fluid substitution is standard practice to predict time-lapse saturation effects, its validity in the field environment rests upon a number of assumptions. The validity of Gassmann equations, ultimately, can only be tested in real geological environments. In this thesis I developed a workflow to test Gassmann fluid substitution by comparing saturated P-wave moduli computed from dry core measurements with those obtained from sonic and density logs. The workflow has been tested on a turbidite reservoir from the Campos Basin, offshore Brazil. The results show good statistical agreement between the P-wave elastic moduli computed from cores using the Gassmann equations and the corresponding moduli computed from log data. This confirms that all the assumptions of the Gassmann theory are adequate within the measurement error and natural variability of elastic properties. These results provide further justification for using the Gassmann theory to interpret time-lapse effects in this sandstone reservoir and in similar geological formations. / Pressure effects on elastic properties are usually obtained by laboratory measurements, which can be affected by core damage. I investigated the magnitude of this effect on compressional-wave velocities by comparing laboratory experiments and log measurements. I used Gassmann fluid substitution to obtain low-frequency saturated velocities from dry core measurements taken at reservoir pressure, thus mitigating the dispersion effects. The analysis is performed for an unusual densely cored well from which 43 cores were extracted over a 45 m thick turbidite reservoir. These computed velocities show very good agreement with the sonic-log measurements. This is encouraging because it implies that core damages that may occur while bringing the core samples to the surface are small and do not adversely affect the measurement of elastic properties on these core samples. Should core damage have affected our measurements, we would have expected a systematic difference between properties measured in situ and on the recovered. This confirms that, for this particular region, the effect of core damage on ultrasonic measurements is less than the measurement error. Consequently, stress sensitivity of elastic properties as obtained from ultrasonic measurements are adequate for quantitative interpretation of time-lapse seismic data. / In some circumstances, stress sensitivity may not be obtained by ultrasonic measurements. Cores may be affected by damage, bias in the plugging process and scale effects and therefore may not be representative of the in situ properties. Consequently it is desirable to obtain this dependence from an alternative method. This other approach ideally should provide the pressure - velocity dependence from an intact rock. Few methods can sample the in situ rock. Seismic, for instance, provides in situ information, but lacks vertical resolution. Well logs, on the other hand, can provide high vertical resolution information, but usually are not available before and after production changes. I propose a method to assess the in situ pressure - velocity dependence using well data. I apply this method to a reservoir made up of sandstone. I used 23 wells drilled and logged in different stages of development of a hydrocarbon field providing rock and fluid properties at different pressures. For each well logged at a specific time, pore pressure, velocity and porosity, among other properties, are known. Pore pressure is accessed from a Repeat Formation Tester (RFT). As a field depletes and new wells are drilled and logged, similar data sets related to different stages of depletion are available. I present an approach expanding Furre et al. (2009) study incorporating porosity and obtaining a three dimensional relationship with velocity and pressure. The idea is to help to capture rock property variability. / Quantitative time-lapse studies require precise knowledge of the response of rocks sampled by a seismic wave. Small-scale vertical changes in rock properties, such as those resulting from centimetre scale depositional layering, are usually undetectable in both seismic and standard borehole logs (Murphy et al., 1984). I present a methodology to assess rock properties by using X-ray computed tomography (CT) images along with laboratory velocity measurements and borehole logs. This methodology is applied to rocks extracted from around 2.8 km depth from offshore Brazil. This improved understanding of physical property variations may help to correlate stratigraphy between wells and to calibrate pressure effects on velocities, for seismic time-lapse studies. / Small scale intra-reservoir shales have a very different response from sands to fluid injection and depletion, and thus may have a strong effect on the equivalent properties of a heterogeneous sandstone reservoir. Since shales have very low permeability, an increase of pore pressure in the sand will cause an increase of confining pressure in the intra-reservoir shale. I present a methodology to compute the combined seismic response for depletion and injection scenarios as a function of net to gross (NTG or sand – shale fraction). This approach is appropriate for modelling time-lapse effects of thin layers of sandstones and shales in repeated seismic surveys when there is no time for pressure in shale and sand to equilibrate. I apply the developed methodology to analyse the sand - shale combined response to typical shale and sandstone stress sensitivities for an oil field located in Campos Basin, Brazil. For a typical NTG of 0.6, there is a difference of approximately 35% in reflection coefficient during reservoir depletion from the expected value if these shales are neglected. Consequently, not considering the small shales intra-reservoir may mislead quantitative 4D studies. / The results obtained in this research are aimed to quantify pressure and saturation effects on elastic properties. New methodologies and workflows have been proposed and tested using real data from South America (Campos Basin) datasets. The results of this study are expected to guide future time-lapse studies in this region. Further investigations using the proposed methodologies are necessary to verify their applicability in other regions.

Worldwide interest in gas production from shale formations has rapidly increased in recent years, mostly by the successful development of gas shales in North America. The Haynesville Shale is a productive gas shale resource play located in Texas and Louisiana. It produces primarily through enhanced exposure to the reservoir and improved permeability resulting from horizontal drilling and hydraulic fracturing. Accordingly, it is important to estimate the reservoir properties that influence the elastic and geomechanical properties from seismic data. This thesis estimates pore shapes, which affect the transport, elastic, and geomechancial properties, from wellbore seismic velocity in the Haynesville Shale. The approach for this work is to compare computed velocities from an appropriate rock physics model to measured velocities from well log data. In particular, the self-consistent approximation was used to calculate the model-based velocities. The Backus average was used to upscale the high-frequency well log data to the low-frequency seismic scale. Comparisons of calculated velocities from the self-consistent model to upscaled Backus-averaged velocities (at 20 Hz and 50 Hz) with a convergence of 0.5% made it possible to estimate pore aspect ratios as a function of depth. The first of two primary foci of this approach was to estimate pore shapes when a single fluid was emplaced in all the pores. This allowed for understanding pore shapes while minimizing the effects of pore fluids. Secondly, the effects of pore fluid properties were studied by comparing velocities for both patchy and uniform fluid saturation. These correspond to heterogeneous and homogeneous fluid mixing, respectively. Implementation of these fluid mixtures was to model them directly within the self-consistent approximation and by modeling dry-rock velocities, followed by standard Gassmann fluid substitution. P-wave velocities calculated by the self-consistent model for patchy saturation cases had larger values than those from Gassmann fluid substitution, but S-wave velocities were very similar. Pore aspect ratios for variable fluid properties were also calculated by both the self-consistent model and Gassmann fluid substitution. Pore aspect ratios determined for the patchy saturation cases were the smallest, and those for the uniform saturation cases were the largest. Pore aspect ratios calculated by Gassmann fluid substitution were larger because the velocity is inversely related to the aspect ratio in this particular modeling procedure. Estimates of pore aspect ratios for uniform saturation were 0.051 to 0.319 with the average of 0.171 from the velocity modeling using the self-consistent model. For patchy saturation, the aspect ratios were 0.035 to 0.296 with a mean of 0.145. These estimated pore aspect ratios from the patchy saturation case within the self-consistent model are considered the most reasonable set of values I determined. This is because the most likely in-situ fluid distribution is heterogeneous due to the extremely low permeability of the Haynesville Shale. Estimated pore aspect ratios using this modeling help us to understand elastic properties of the Haynesville Shale. In addition, this may help to find zones that correspond to optimal locations for fracturing the shale while considering brittleness and in-situ stress of the formation. / text

Kyoto University (京都大学) / 0048 / 新制・課程博士 / 博士(工学) / 甲第17130号 / 工博第3620号 / 新制||工||1549(附属図書館) / 29869 / 京都大学大学院工学研究科社会基盤工学専攻 / (主査）教授 松岡 俊文, 教授 小池 克明, 教授 清野 純史 / 学位規則第4条第1項該当

[pt] As reservas de óleos pesados têm obtido grande importância devido à diminuição das reservas de óleos leves e ao aumento dos preços do petróleo. Porém, precisa-se de aumentar a viscosidades destes óleos pesados para que possam fluir até superfície. Para reduzir a viscosidade foi escolhida a técnica de recuperação térmica SAGD (Steam Assisted Gravity Drainage) pelos seus altos valores de recobro. A redução da viscosidade é atingida pela transmissão de calor ao óleo pela injeção de vapor, porém uma parte deste calor é transmitida à rocha. Esta transmissão de calor junto com a produção de óleo geram uma variação no estado de tensões no reservatório o que por sua vez geram fenômenos geomecânicos. Os simuladores convencionais avaliam de uma forma muito simplificada estes fenômenos geomecânicos, o que faz necessários uma abordagem mais apropriada que acople o escoamento dos hidrocarbonetos e a transmissão de calor com a deformação da rocha. As mudanças no reservatório, especialmente a variação da saturação, afetam as propriedades sísmicas da rocha, as quais podem ser monitoradas para acompanhar o avanço da frente de vapor. A simulação fluxo-térmica-composicional-geomecânica é integrada à sísmica de monitoramento 4D da injeção de vapor (a través da física de rochas). Existe uma grande base de dados, integrada por propriedades dos fluidos do reservatório (PVT) (usado no arquivo de entrada de simulação de fluxo) e uma campanha de mecânica das rochas. Foram simulados vários cenários geomecânicos considerando a plasticidade e variação da permeabilidade. Foram avaliadas várias repostas geomecânicas e de propriedades de fluidos no pico de pressão e final do processo SAGD. A resposta geomecânica pode ser observada, porém foi minimizada devido à baixa pressão de injeção, sendo o mecanismo de transmissão de calor um fator importante na produção de óleo (pela redução da viscosidade) e a separação vertical entre poços. Foi também significativa à contribuição da plasticidade no aumento da produção de hidrocarbonetos. A impedância acústica foi calculada usando a Equação de substituição de fluidos de Gassmann. Os sismogramas sintéticos de incidência normal (para monitorar o avanço da frente o câmara de vapor) mostraram a área afetada pela injeção de vapor, porém com pouca variação devida principalmente à rigidez da rocha. / [en] The heavy oil reserves have gained importance due to the decreasing of the present light oil reserves. Although it is necessary to reduce the oil viscosity and makes it flows to surface. For its high recovery factor the SAGD (Steam Assited Gravity Drainage) thermal process was selected. The viscosity reduction is achieved by heat transfer from steam to oil, but some part of this heat goes to rock frame. This heat transfer together with oil production change the initial in-situ stress field what creates geomechanical effects. The conventional flux simulators have a very simplified approach of geomechanical effects, so it is necessary to consider a more suitable approach that considers the coupling between oil flux and heat transfer with rock deformation. The changes within the reservoir, specially the saturation change, affect the seismical rock properties which can be used to monitor the steam chamber growth. The flux-thermal geomechanics is integrated to steam chamber monitoring 4D seismic (through the rock physics). There is a great data base, integrated by reservoir fluid properties (PVT) (used in reservoir simulation dataset) and a rock mechanics campaign. Several scenaries were simulated considering the plasticity and permeability variation. Several geomechanical responses and flux properties at peak pressure and end of SAGD process were evaluated. The geomechanical response can be observed, but was minimized due to low steam injection pressure, being the heat transfer an important in oil production (for the viscosity reduction) and the vertical well separation, too. The plasticity has a significant contribution in the increment of oil production. Acoustic impedance was calculated by using Gassmann fluid substitution approach. 2D Synthetic seismograms, normal incidence (to monitor the steam camera front advance), showed the area affected by steam injection, but with little variation due principally to rock stiffness.