Fuming, Ruan (China Oilfield Services Limited) | Kai, Yang (China Oilfield Services Limited) | Qiuyun, Wu (China Oilfield Services Limited) | Yaoqiang, Zhu (China Oilfield Services Limited) | Lie, Li (CNOOC China Limited)
Summary: In recent years, broadband seismic acquisition and processing technology has become the hotspot of research and application of marine seismic exploration, slant streamer seismic acquisition technology is a reflection of the broadband seismic exploration technology. It is good to remove ghost wave and broaden the collected seismic data band. China National Offshore Oil Corp (CNOOC) applies the independently developed single-hydrophone short trace spacing streamer acquisition system "HQI-Seis" to make slant streamer broadband seismic acquisition in the west Wenchang A recessed area of the Pearl River Mouth Basin of the northern part of the South China Sea. In the process of seismic data acquisition and data processing, we use the method different from conventional marine seismic exploration technology, which enhances the low-frequency energy of the seismic data, broadens the band, especially improves the quality of the middle deep seismic data significantly, and achieves satisfactory geological effects. Introduction: The northern part of the South China Sea is a great potential for the field of oil and gas exploration in China's coastal waters(Zhu W.L. 2008).
Sun, Sam Zandong (China University of Petroleum) | Wang, Yonggang (China University of Petroleum) | Sun, Xuekai (China University of Petroleum) | Yue, Hangyu (China University of Petroleum) | Yang, Wenkui (China University of Petroleum) | Li, Chenjian (China University of Petroleum)
Although prestack seismic data contains more abundant information in amplitude and traveltime than the poststack seismic data for estimating Q values, the waveforms or spectrum of reflectors are strongly altered by nearby reflectors or side lobes. It will interfere the calculation of spectrum and thus degrade the precision of Q estimation, several methods based on prestack data have been developed to solve this problem. Different from the usual, we propose a method based on the Modified S-Transform (MST) to estimate Q factor values from prestack CMP gathers. Q estimations can be obtained with regression analysis based on the relation of spectral ratio slope and the square of offset. Then, we utilize the resultant Q model to compensate the amplitude loss and correct phase distortion. Results from synthetic data and real data demonstrate that MST is more capable in improving the accuracy of Q value estimations. Applications on inverse Q filtering and prestack Q migration greatly improve the imaging resolution. While Q migration can obtain amplitude preserved gathers and corrects the phase to some extent, which contributes to better reservoir descriptions.
In this paper, an inversion method for fracture-related layer properties based on elastic impedance data is presented. Firstly, qP-qP reflection coefficients between the two weakly anisotropic HTI half-space media is studied, after which the expression of reflection coefficients is linearized. Then, a simplified HTI elastic impedance formula is derived. Finally, a workflow for extracting fracture properties from elastic impedance data is proposed. Test on theoretical model and its synthetic seismic data shows that the proposed method obtains a reliable and expected result.
Summary Classification of different lithofacies and petrotypes is one of the main objectives of modern quantitative seismic interpretation. In this application we illustrate the PSVM method to differentiate limestone from shale in a Barnett Shale gas play. The PVSM's low complexity feature compared to the standard vector machines could be well exploited in a data intensive computation such as the 3D seismic lithofacies classification. The paper reports two applications of this technique one for waveform classification and the other for the classification of well data. In both these applications PSVM classification results showed strong agreement with structural and stratigraphic interpretation results.
Anisotropy parameters provide vital information for surface and borehole seismic data processing, imaging and interpretation. The objective of this research is to introduce a reliable technique, for estimating local seismic anisotropy using both P- and SV-wave from VSP data in VTI media where the overburden is heterogeneous.
The technique uses P- and SV-wave vertical slowness components and polarization angles in VTI media to estimate Thomsen parameter δ and anellipticity parameter ƞ. The proposed method is applied to a synthetic VSP data with anisotropic properties. The estimated δ and ƞ parameters, using both P- and SV-wave data, show better correlation with anisotropy parameters in the model compared to the technique that only uses P- wave data.
We introduce an efficient time/amplitude warping tool, which was originally developed for registration-based waveform inversion. Time and amplitude warping functions are modeled with piecewise cubic polynomials and they are obtained by solving a nonconvex optimization problem iteratively in a multiscale fashion from low to high frequencies. In order to seed the frequency sweep at zero frequency, low frequency augmented signals are used for the optimization problem. Such low frequency augmented signals are generated via nonlinear transformations. We investigate the effect of different low frequency augmented signals on optimization. We also demonstrate time/amplitude warping of complicated seismic traces and applications of time warping to 4D data.
Source mechanism of the ultrasonic transducer located in anisotropic region is being evaluated by moment tensor inversion with full waveform seismograms, which are collected from the physical modeling experiment designed to simulate the microseismic survey in the laboratory. Two inversions are carried out for layered VTI media by either using only SV-wave or both P- and SV-wave. The result suggests the transducer source can be described by two dipole forces. Both wave modes have to be involved in the inversion to avoid biased result.
Summary We demonstrate using viscoelastic modeling followed by dual velocity RTM imaging that ocean bottom node (OBN) survey is needed in a gas-obscured zone in Malaysia. Scattering caused by "geobodies" filled or partially filled with gas will distort the P-wave propagation. S-wave, on the other hand, is less sensitive to the geobodies, and therefore has a good chance for imaging through gasobscured zones. However, when intrinsic Q (or attenuation) is present in the overburden, the ability of PSconverted wave imaging will be degraded. The reliability and resolution of PSconverted wave imaging also depends on the accuracy of velocity models used for RTM imaging.
The amplitude-variation-with-offset (AVO) inversion is an important technology in estimating elastic parameters which are sensitive to reservoirs and fluid. The fluid factor based on the Biot-Gassmann equation is very popular in the fluid discrimination study. However, in the deep reservoir, seismic data with low signal-to-noise ratio often lack the information of large angle of incidence. Therefore, the three-term AVO inversion will not be stable. The main purpose of this study is to help improve the stability of fluid factor inversion for deep reservoir. Under the guidance of the theory of multi-porous media theory, we derive a new two term AVO approximate equation in terms of Gassmann fluid term and shear modulus. The new equation has the nearly same accuracy as the three term AVO equation. The analysis of information contained in reflections demonstrated that the information content didn’t lose, so we can utilize the two term AVO approximation equation to invert the fluid factor to discriminate the fluid saturated in deep reservoir. The L1 norm regularization and smooth model constraints were performed in the inversion method. Tests on synthetic data and field data application show that both fluid factor and shear modulus can be estimated reasonably. Therefore, it can be used for fluid discrimination in deep reservoir.
In the past, the anisotropy community has asserted that we are unable to distinguish between the effects of stress-aligned vertical micro-cracks (arising from unequal horizontal stresses), and vertical aligned macro-fractures that flow fluids. This assertion is one manner of phrasing the hypothesis that we are unable to determine the scale (size) of the fracture causing the azimuthal anisotropy. This paper asserts: 1) that the result of unequal horizontal stress is azimuthal traveltimes, best quantified as P-P azimuthal interval velocities following azimuthal prestack depth migration, and 2) that the information concerning vertical aligned macro-fractures that flow fluids is best evident in azimuthal amplitudes (P-P, etc.) of said processed data, with the caveat that all the standard issues of bed thickness, removal of noise, preservation of signal, temporal resolution, and spatial resolution constrained by the proper bin size, given a geologic dip on the beds, a fold, and offsets equal to target depths, are present and operative. Having looked at azimuthal reflection seismic data for more than thirty years, and having seen a consistent pattern in field data, I offer the above two assertions as hypotheses to be tested against current and future datasets, both field data and model data, provided that these model data come from algorithms using orthorhombic, monoclinic and/or triclinic symmetries.