Seismic reflection coefficient equation for the fluid-saturated porous reservoirs under the effect of in situ stress is of great importance to broad fields such as geofluid discrimination, in situ stress prediction, and safe production. However, the stress effect on seismic reflection coefficient in porous reservoirs is poorly understood. To fill this knowledge gap, an approximate seismic reflection coefficient equation for fluid-saturated porous reservoirs under horizontal stress was proposed to model the natural effect of horizontal stress on seismic reflection response. We first revisited the acoustoelasticity (AE) theory and used it to characterize the impact of horizontal stress on skeleton anisotropy. Then, the effective elastic stiffness tensor and the corresponding spatial perturbation in the stressed fluid-saturated porous reservoirs were established under the assumption of fluid incompressibility, which were further employed to derive the approximate seismic reflection coefficient equation based on the elastic inverse scattering theory. By comparing our equation to the exact one, we confirmed its validity within the moderate incidence angles and stresses. The effects of horizontal stress on the P-wave amplitude variation with angle and azimuth (AVAZ) characteristics and seismic response were thoroughly investigated. It was shown that the horizontal stress significantly influenced the amplitude magnitude and seismic phases. Furthermore, the derived reflection coefficient equation was inserted into the Bayesian inversion scheme to estimate the geofluid indicator and other elastic parameters. Synthetic test and filed application showed a reasonable agreement between the inverted result and drilling data, which illustrated the feasibility and stability of our inversion method.

The vertically transverse isotropic (VTI) reservoirs subjected to horizontal in situ stress are frequently encountered in the subsurface, which can be approximately treated as an orthorhombic medium in the framework of acoustoelasticity. However, the seismic estimation for anisotropy parameters in such stress-induced reservoirs is still poorly studied. To address this issue, we derive a linearized reflection coefficient equation in stress-induced orthorhombic media by means of the theories of acoustoelasticity and elastic inverse scattering. The acoustoelasticity theory is utilized to characterize the effective elastic stiffness tensor in a stress-induced orthorhombic medium. The introduction of two dimensionless stress-induced anisotropy (SIA) parameters eliminates the need for third-order elastic constants (3oECs). Then, the stiffness perturbation is presented under the weak-anisotropy hypothesis and is substituted into the scattering function to derive the linearized reflection coefficient equation in stress-induced orthorhombic media. The feasibility of our reflection coefficient equation within the range of moderate stress (or moderate SIA) is confirmed by comparing it to the exact solution. Incorporating the wavelet effect, our reflection coefficient equation as a forward operator is utilized to establish a step-wise Bayesian inversion approach to estimate the anisotropy parameters. Specifically, the SIA parameters are inverted from the amplitude differences in seismic data at different azimuths in the first step. Next, the obtained parameters as the prior dataset are input into the second-step procedure to predict the VTI parameters with partial angle-stacked seismic data. Synthetic and field tests illustrate the robustness and effectiveness of our approach.

In hydrocarbon exploration and development, fluid indicators that can directly identify reservoir hydrocarbons from seismic data are of great significance for seismic interpretation in the fracture-induced horizontal transversely isotropic (HTI) reservoirs. In this paper, based on the unified elastic wave theory of the medium, a new anisotropic fluid indicator is constructed incorporating squirt flow effect between the cracks of rocks. The novel anisotropic fluid indicator can better reflect the influence of pore fluid within the rock on wave propagation. Compared with conventional elastic parameters, the new established anisotropic fluid indicator is more sensitive to oil/gas. Subsequently, by combining the perturbation of the elastic stiffness component in fluid-saturated fractured porous media and the inverse scattering function, an anisotropic PP-wave reflection coefficient is derived in terms of an anisotropic fluid indicator incorporating squirt flow effect and fracture weaknesses. The comparison of Rüger’s equation and the new reflection coefficient equation confirms the validity of our equation for parameter estimation. Further our reflection coefficient equation is used to establish an anisotropic frequency-dependent azimuthal amplitude variation with offset (AVO) inversion method to estimate the anisotropic fluid indicator and fracture weaknesses. The feasibility of the inversion method is verified by the field data application in eastern China, which demonstrates that the anisotropic fluid indicator with the squirt flow effect is certainly sensitive to the gas-bearing fractured reservoirs, and can provide a more effective method for fluid identification in gas-fractured reservoirs.

With the continuous development of oil and gas exploration, anisotropic medium has become an important target of oil and gas exploration. Both anisotropy and wave-induced fluid flow have significant influence on fluid identification, but the existing fluid identification methods cannot concurrently consider the impacts of medium anisotropy and wave-induced fluid flow. Therefore, to improve the fluid detection accuracy in anisotropic medium, an anisotropic media solid-liquid decoupling fluid factor with squirt flow effect suitable for the transversely isotropic media with a horizontal symmetry axis (HTI) is constructed based on the theory of rock physics. The fluid sensitivity analysis indicates that the new fluid factor exhibits the highest sensitivity for fluid indication. By introducing the nearly constant Q model to account for viscoelasticity, a reflectivity equation in terms of the new anisotropic media solid-liquid decoupling fluid factor incorporating the squirt flow is derived. Subsequently, a prestack seismic frequency-dependent amplitude variation with angle and azimuth (AVAZ) inversion method is developed. The inversion method takes advantage of the information of offset, azimuth, and frequency contained in seismic data. Synthetic and field examples illustrate the reliability and stability of the proposed prestack seismic frequency-dependent AVAZ inversion method in estimating the new anisotropic media solid-liquid decoupling fluid factor. Our method can serve as a complementary approach to enhance the accuracy of fluid detection in anisotropic reservoirs.

Accurate prediction for formation pressure is crucial for many practical scenarios in the field of oil and gas exploration, such as evaluating reservoir sweet spots. As formation depth gradually increases, the influence of diagenesis on formation pressure becomes more dominant. However, the diagenesis effect is still not well considered in the existing formation pressure methods. To address this issue, a seismic formation pressure prediction method incorporating the diagenesis effect is developed based on the depth-dependent diagenetic function. The proposed method concurrently incorporates the information of normal compaction trend, bulk modulus, and clay content. A diagenetic function is introduced into the classic effective stress theory to describe the diagenesis effect on depth dependency of formation pressure. The normal compaction trend is established using the rock physics model. The bulk modulus and clay content that are included in the prediction method are estimated from the pre-stack seismic data, respectively, with the linear Gray reflection coefficient equation and the proposed nonlinear reflection coefficient equation, where the Markov chain Monte Carlo (MCMC) method is used to obtain the optimal inversion results. Finally, the estimated normal compaction trend, bulk modulus, and clay content are employed to calculate the formation pressure. The proposed method has been applied in Xinjiang work area.