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

Submitted by Jesiel Ferreira Gomes (jesielgomes@ufcg.edu.br) on 2018-04-17T23:15:52Z No. of bitstreams: 1 FELIPE DE OLIVEIRA APOLINÁRIO – DISSERTAÇÃO (PPGEPM) 2016.pdf: 5151929 bytes, checksum: f4706d54cb97c9b01a64299ddb28cd7d (MD5) / Made available in DSpace on 2018-04-17T23:15:52Z (GMT). No. of bitstreams: 1 FELIPE DE OLIVEIRA APOLINÁRIO – DISSERTAÇÃO (PPGEPM) 2016.pdf: 5151929 bytes, checksum: f4706d54cb97c9b01a64299ddb28cd7d (MD5) Previous issue date: 2016-09-06 / Capes / O presente trabalho teve como objetivo analisar a influência da saturação fluida nas propriedades elásticas de rochas carbonáticas, bem como a eficácia dos modelos de substituição de fluidos e de simulação computacional. Foram estudadas 9 amostras de rochas carbonáticas, sendo dois calcários laminados e sete tufas. As medições de velocidade foram realizadas em amostras secas, saturadas com água ou com óleo, sob diferentes pressões efetivas. A simulação de propagação de ondas foi feita no COMSOL Multiphysics 5.1, utilizando o Avizo Fire 8.1 para a criação das amostras digitais. Análise por difração de raios X (DRX) foi realizada para determinar a composição das amostras de rocha. Os resultados obtidos nos ensaios laboratoriais e nas simulações computacionais foram comparados com as estimativas dos modelos de substituição de fluidosGassmann, Biot e Brown & Korringa. Foi observado que a saturação das amostras com agua ou óleo geraram aumentos nas velocidades de propagação de onda P, porém sem apresentar um comportamento padrão. Para o caso das ondas S, a saturação por óleo predominantemente gerou aumentos nas velocidades, com exceção para os casos em que as amostras possuíam porosidade secundária do tipo vugular, devido à pouca influência que o óleo oferece para o módulo de cisalhamento nestes casos. A saturação por água resultou em diminuições das velocidades de propagação de onda S devido ao aumento da densidade total. Também foi constatado que o modelo de Gassmann foi o mais efetivo na estimativa de velocidades de onda P e S, enquanto que o de Biot mostrou-se eficaz apenas para a estimativa de velocidades de ondas S, sendo ineficiente para a estimativa de velocidades de ondas P, com erros de até 20%. A simulação computacional gerou resultados superdimensionados, porém que evidenciam que um aperfeiçoamento da metodologia, tal como o aumento do número de pontos de leitura pode gerar resultados mais próximos dos obtidos laboratorialmente e de maior confiabilidade. / This research aimed to analyze the influence of the saturating fluid in carbonate rocks, as well as verify the effectiveness of the fluid substitution models and computational simulations of wave propagation. To do so, nine carbonate rock samples were analyzed, which two of them were laminated limestones and seven were carbonate tufas. The measurement of velocities were made in dry, water saturated and oil saturated samples, under different effective pressures. The wave propagation simulations were made in COMSOL Multiphysics 5.1 using Avizo Fire 8.1 to generate the digital rock samples. The results obtained in lab procedures and in computer simulations were compared with the estimated velocities of the fluid substitution models of Gassmann, Biot and Brown & Korringa. It was observed that the saturation of the samples with water or oil resulted in an increasing of P-wave velocities, however without a pattern. The saturation with oil resulted in most cases in an increasing of S-wave velocities, the exceptions occurred in samples which had vugular porosity, due to the small influence of the oil in the shear modulus in this cases. T he saturation with water resulted in a decreasing of S-wave velocities due to the increment of the bulk density. It was found that the Gassmann’s model was more effective than the other two models in estimating P-wave and S-wave velocities. Biot’s model generated unsatisfying results to P-wave velocities, with errors up to 20%. However, this model had a good accuracy in estimating S-wave velocities. The computer simulations produced mainly overestimated results, though it was shown that an optimization of methodology, such as and addition in the number of the measure points, could improve the quality of the data, providing more representative results.