One of the most important, but often ignored, factors affecting the transport and the seismic properties of hydrocarbon reservoir is pore shape. Transport properties depend on the dimensions, geometry, and distribution of pores and cracks. Knowledge of pore shape distribution is needed to explain the often-encountered complex interrelationship between seismic parameters (e.g. seismic velocity) and the independent physical properties (e.g. porosity) of hydrocarbon reservoirs. However, our knowledge of reservoir pore shape distribution is very limited. This dissertation employs a pore structure parameter via a rock physics model to characterize mean reservoir pore shape. The parameter was used to develop a new physical concept of critical clay content in the context of pore compressibility as a function of pore aspect ratio for a better understanding of seismic velocity as a function of porosity. This study makes use of well log dataset from offshore Norway and from North Viking Graben in the North Sea. In the studied North Sea reservoir, porosity and measured horizontal permeability was found to increase with increasing pore aspect ratio (PAR). PAR is relatively constant at 0.23 for volumes of clay (V_cl) less than 32% with a significant decrease to 0.04 for V_cl above 32%. The point of inflexion at 32% in the PAR –V_cl plane is defined as the critical clay volume. Much of the scatters in the compressional velocity-porosity cross-plots are observed where V_cl is above this critical value. For clay content higher than the critical value, Hertz-Mindlin (HM) contact theory over-predicts compressional velocity (V_p) by about 69%. This was reduced to 4% when PAR distribution was accounted for in the original HM formulation. The pore structure parameter was also used to study a fractured carbonate reservoir in the Sichuan basin, China. Using the parameter, the reservoir interval can be distinguished from those with no fracture. The former has a pore structure parameter value that is ≥ 3.8 whereas it was < 3.8 for the latter. This finding was consistent with the result of fracture analysis, which was based on FMI image. The results from this dissertation will find application in reservoir characterization as the industry target more complex, deeper, and unconventional reservoirs.

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