Abstract
As a critical reservoir rock, carbonates (e.g., limestone, dolomite, and chalk) are less investigated than the clastic sediments from the perspective of rock physics. Rock physics is an essential tool to link geophysical responses (core plugs, logging, and seismic data) with geological information. Lab-scaled measurements (e.g., porosity, P-, and S-wave velocity) of core plugs can assist us to calibrate the logging data as well as simulating the physical properties under the in-situ environment. Rock physics modeling built on the measurements will have a sound meaning for the input parameters.

The porosities and velocities of twenty-one water-saturated carbonate samples are measured in the laboratory. Their porosities range from 19% to 36%, by assuming a constant grain density of 2.71 g/cc. Then we measure P- and S-wave velocities of these twenty-one plugs in the unloading trend (confining pressure varies from 2500 to 1000 psi) with the same pore pressure control at 400 psi. Measured results of Vp, Vs, and Vp/Vs ratios suggest that elastic properties of these carbonates are sensitive to the pressure, which accords with their poor consolidated nature. Their velocities and moduli present negative correlations with porosity. To better characterize these carbonates' properties, we utilize inclusion models by dividing the pores into stiff pores with a pore aspect ratio close to 1 and soft pores with a pore aspect ratio close to 0.01. The porosity of soft pores is determined from the fluid volume increase in the pore pressure pump during the unloading process. The behaviors of carbonates under pressures can be well explained with the open or close of soft pores: with decreasing differential pressure, the soft pores will gradually open and can increase P- and S-wave velocities.

Abstract
Estimation of the VTI parameters from laboratory anisotropy measurement is challenging even when the dimensions of the rock sample are known and measuring angles are controllable.��It is natural to believe that more challenges will be encountered in estimation of anisotropy parameters from the field seismic data. Using synthetic multi-layer VTI model, we apply the commonly used Tsvankin�s (2012) procedure to estimate the VTI parameters and test its sensitivity to the layering effect, vertical interval velocity error, source-receive offset and time picking error.�The testing results show that the methodology is theoretically well established.��But it is extremely sensitive to time picking error and layering effect, which might make the methodology unfeasible in practical application even for seismic data with excellent quality control.

Abstract
Ultra-low porosity and permeability, inhomogeneous fracture distribution, and complex storage space together make the effectiveness evaluation of tight carbonate reservoirs difficult. Aiming at the carbonate reservoirs of the Da'anzhai Formation in Sichuan Basin, based on petrophysical experiments and logging response characteristics, I investigated the storage properties of matrix pores and the characteristics of fracture development to establish a method for the characterization of effectiveness of tight reservoirs. Mercury injection and NMR experiments show that the conventional relationship between porosity and permeability cannot fully reflect the fluid flow behavior in tight matrix pores. Under reservoir conditions, the tight reservoirs still possess certain storage space and permeability, which are controlled by the matrix pore structure. The degree of fracture development is crucial to the productivity and quality of tight reservoirs. By combining the fracture development similarity of the same type of reservoirs and the fracture development heterogeneity in the same block, a three-level classification method of fracture development was established on the basis of fracture porosity distribution and its cumulative features. Then, combining with the actural production data, I divided the effective reservoirs into three classes: Class I with developed fractures and pores, and high-intermediate productivity; Class II with moderately developed fractures and pores or of fractured type, and intermediate-low productivity; Class III with poorly developed fractures and matrix pores, and extremely low productivity. Accordingly log classification standards were set up. Production data shows that it is highly consistent with the reservoir productivity level, providing a new approach for the effectiveness evaluation of tight reservoirs.

Abstract
In this study, we investigate the reported ultrasonic measurements of core samples of organic shale and our lab measurements. We focus on Vp/Vs ratios, P-impedance, and velocity anisotropies for different types of organic shales. A layered model is constructed to explain why the silica-rich shales tend to have higher S-wave anisotropy and calcareous shales tend to have higher P-wave anisotropy. The modeling results of the ratio of anisotropic parameters (Thomsen, 1986), gamma/epsilon, remain approximately as constants in the silica-rich and calcareous shales. Hence, gamma/epsilon�ratio may be potentially treated as an indicator for mineralogical composition in shale reservoirs. We also observe linear trends between Thomsen�s parameters, epsilon�and delta, in the calcareous shale. Additionally,�Poisson�s ratios in a transverse isotropic (TI) medium, exhibit a linear relationship in silica-rich shales and clay-rich shales, providing insights for characterizing mineralogical composition of organic shales.

Abstract
The deposition of organic matter along with sediments is a complex phenomena. Several factors control for the organic matter production, destruction, dilution and preservation. Researchers have identified three different types of pores in organic rich shales. They are inter particle and intra particle pores in non-organic part of the shales and intra particle pores (nano pores) in the organic matter. Inter particle pores in non-organics and intra particle pores in organic matter contribute for the hydrocarbon production from the shale gas reservoirs. An attempt has also been made to understand how the kerogen content and its level of maturity will affect seismic anisotropy for different shale reservoirs from the published data.