Zhang, Yang (Earth Resources Laboratory, Massachusetts Institute of Technology) | Campman, Xander (Earth Resources Laboratory, Massachusetts Institute of Technology) | Grandi, Samantha (Earth Resources Laboratory, Massachusetts Institute of Technology) | Chi, Shihong (Earth Resources Laboratory, Massachusetts Institute of Technology) | Willis, Mark E. (Earth Resources Laboratory, Massachusetts Institute of Technology) | Toksöz, M. Nafi (Earth Resources Laboratory, Massachusetts Institute of Technology) | Burns, Daniel R. (Earth Resources Laboratory, Massachusetts Institute of Technology)
We model seismic wave propagation in a reservoir with discrete fracture zones using a finite difference program, which implements the Coates-Schoenberg formulation for fractured media. We study the behavior of scattered energy in the direction perpendicular and parallel to fracture strike. In the modeled data, we observe variations in the coherence of seismic energy and interference between backward and forward scattered energy. The observed scattered energy contains information about the fracture zones. We develop a method to extract the dominant coherent back sctattered energy. The fracture spacing is then estimated from the frequency wave-number spectrum of this back scattered energy. Results show that our method gives quite accurate estimates for several different spacings.
Ash, Michael R. (Department of Earth Sciences) | Wheeler, Michael (Department of Earth Sciences) | Miller, Hugh (Department of Earth Sciences) | Farquharson, Colin G. (Department of Earth Sciences, INCO Innovation Centre, Memorial University of Newfoundland) | Dyck, Alfred V. (INCO Innovation Centre, Memorial University of Newfoundland)
This paper presents the preliminary results of inverting potential field data collected over the Voisey's Bay Nickel-Copper-Cobalt deposit in Labrador, Canada. The gravity inversion is constrained by incorporating geocellular models derived from drill log data. Adding constraints to the inversion directs the solution toward acceptable, geologically meaningful results.
Marine CSEM data processing techniques have evolved rapidly to accommodate the proliferation of marine controlled-source electromagnetic (CSEM) surveys. Processing methods developed for marine MT surveys are not directly applicable to marine CSEM data. Basic marine CSEM data processing eliminates the signature of the acquisition system and extracts the normalized spectral response of the earth from the receiver time series data. More sophisticated methods have been developed to simplify interpretation and to ensure that the highestquality data are available for inversion. These methods include determining the 3D receiver orientations by inversion, extending the range of useful offsets by noise suppression, and minimizing the effect of air waves by model-based subtraction.
Marine CSEM exploration is a direct hydrocarbon detection technology that exploits the resistivity contrast between hydrocarbon reservoirs and the surrounding sediments. Since the earliest commercial surveys in the West Africa offshore (Ellingsrud et al, 2002; Srnka et al, 2005), acquisition, processing, and interpretation methods have evolved rapidly. These surveys use receivers deployed on the seafloor and a deep-towed source. The measured fields are analyzed to investigate sub-seafloor structures and determine the nature of the targeted reservoir. Typically, surveys have a number of towlines crossing over the target and receivers positioned primarily along those towlines. The source is towed about 50 meters above the seafloor while all receivers are recording. After completing the towlines, receivers are recovered and the recorded data are downloaded so the data can be processed and interpreted offline. The land counterpart, controlled source audio-frequency magnetotellurics (CSAMT), has been used since its introduction in the mid-1970s (Goldstein and Strangway, 1975). Since CSAMT surveys typically measure both electric and magnetic fields, data processing mimics standard MT processing techniques (Egbert and Booker, 1986). In marine CSEM surveys, it is often the case that only electric fields are measured. As a result, MT techniques cannot be directly applied. Also, new challenges and problems have arisen in the marine environment. In this paper, we discuss the basics of marine CSEM data processing and techniques for orienting the receivers, reducing background noise, and suppressing air waves.
Basic Steps of Data Processing
The essence of data processing is to transform the receiver, transmitter, and navigation data into an interpretable form. Receiver fields, source current, and navigation data are all recorded in the time domain. As interpretation is currently done in the frequency domain, the amplitude and phase of the EM response are required. Basic processing steps include spectral decomposition (transforming data from time to frequency domain), receiver and source normalization, and source-receiver geometry construction (merging navigation data with processed EM fields):
• Spectral Decomposition: For spectral decomposition, the time series data are binned and each bin is tagged with a time corresponding to its center. Spectral decomposition on each bin could be done with the Fourier transform. However, since the source transmits only a small number of pre-selected frequencies, the amplitude and phase at those frequencies are computed more efficiently by a least-squares fit.
An increasing interest in gas hydrates as a potential energy source gave reason for numerous field studies, laboratory and numerical experiments, that have revealed some interesting aspects of sediments containing gas hydrates. While there exist several models explaining observed increased seismic velocities, the mechanism of formation of gas hydrates and the reasons for observed strong attenuation are not fully understood. Two rock physical models are controversly debated: one attributes occurrence of hydrates to the properties of the rock's matrix, the other relates presence of hydrates to the properties of the pore fluid. In our approach we assume, that an occurrence of hydrates affects the properties of the fluid and the solid phase of the host sediment. A poroelastic generalization of the O'Doherty-Anstey theory indicates that this would result in increased values for attenuation. To work with realistic models of multilayered, poroelastic media and to account for observed strong fluctuations in hydrate-bearing sedimentary layers we investigate exponentially correlated, random media. Numerical and analytical results confirm, that correlated fluctuations in properties of the frame, grain and fluid cause significant attenuation values. Especially in the lower seismic frequency range they are comparable to those observed in field measurements.
Multi-component seismic data offer not only seismic reflections of pure compressional wave (PP) but also of converted shear waves (PSV and PSH) resulting from conversions at stratum interfaces in the subsurface. Different types of waves have different responses to subsurface geology. The reflection amplitude responses of different types of waves have been investigated and compared through a numerical modeling study. The shot-receiver offset and azimuthal angle have been varied relative to the subsurface anisotropy symmetry direction. Our results show that PSV data are more sensitive to azimuthal anisotropy than PP data.
This makes the converted wave a better tool for subsurface azimuthal anisotropy (or fracture) detection. The study also demonstrates that the higher-order term in PP-wave amplitude versus offset (AVO) expression (beyond the traditional intercept and slope terms) can be important for fracture detection. Feasibility modeling study before field application is essential to better understand the relative importance of each term in the azimuthal AVO response and the appropriate incidence angle range for azimuthal anisotropy detections.
Multi-component seismic technology has proved useful in imaging targets below gas chimneys, and imaging reservoir rocks with low P-wave impedance contrast but high shear impedance contrast relative to overburden rocks and in lithology discrimination. The motivation of this study is to explore the potential benefits of multi-component seismic data in fracture detection. The focus of this study is to compare the sensitivity to azimuthal anisotropy between P-wave to P-wave (PP) reflection and P-wave to SV-wave (PSV) reflection under ideal conditions without considering the effects of noise and tuning. Through this comparison study, we want to see what type of wave, which parameters, and what incident angle range are better for azimuthal anisotropy detection. A Transversely Isotropic model with a Vertical symmetry axis (VTI) is a good description for horizontally layered sediments, especially shale formations. A Horizontally Transverse Isotropy (HTI) model is usually used to describe fractured rock with a system of parallel vertical fractures.
The seismic wave reflection from a VTI/HTI interface provides an ideal basic model for studying the responses of reflection seismic amplitude with azimuthal anisotropy. Earlier theoretical work (Vavrycuk, 1998 and 1999; Ruger, 1997 and 1998) on such a model has laid the foundation for fracture detection using PP waves.
More recent work (Vavrycuk, 1999; Cherepanov, 2004) on a PSV reflection from a VTI/HTI interface has laid a framework of fracture detection using PS waves in parallel to that of PP waves. In our modeling study, we use both of those analytical approximations and exact solutions of the reflection amplitudes to perform azimuthal AVO analyses and comparisons based on the simple VTI/HTI interface model.
The PP and PSv reflection amplitudes are normally approximated as serial expansions in terms of the incidence angle (or offset). The azimuthal dependence of the reflection amplitude is included in the expansion coefficients of the incidence angle. The PP reflection from a VTI/HTI interface under the condition of small rock property contrast and small incidence angle is approximated as (Vavrycuk, 1998 and 1999; Ruger, 1997 and 1998),
2 D industry seismic data acquired in the Focsani Basin of Romania prove ideal for imaging deep crustal structures related to the tectonic evolution of one of the youngest yet deepest basins in the world. Fundamental plate tectonics research blends with oil exploration techniques to provide an image of the upper 60 km of the basin. The purpose of this study was to identify the best processing techniques that would provide deep information while preserving the shallow data.
Processing of 2D shallow (5s) seismic data is presently done routinely with software that was developed for this purpose. However no software is designed for the sole purpose of processing deep seismic data. Here we present processing steps undertaken for processing 2 seismic lines with recording time of 20s TWTT using Landmark ProMAX seismic processing package. The deep seismic data presented here were collected in the Focsani Basin of the SE Carpathian foreland as part of oil exploration activities.
The acquisition parameters are exploration-type, only the record length being increased to 20s. Some of the main problems of processing the data were related to signal depth penetration and its recovery, attenuation of multiples and velocity analysis. Standard industry offsets did not provide sufficient NMO and the thickness of the basin further complicated removal of multiples. The evolution of the basin is at odds, spatially and temporally with the formation of the Eastern Carpathians and to this effect the study of the deeper crustal structure was envisioned as a way of providing constraints on the main tectonic processes involved in the development of the SE Carpathian region.
The foreland basin in front of the SE Carpathians, Romania, formed during and after the Alpine continental collision bears significance due to its
(1) rich and extensively exploited oil fields,
(2) vicinity to the intermediate depth Vrancea Seismogenic Zone,
(3) thick sedimentary cover (~ 18 km Miocene-Quaternary),
(4) ongoing subsidence (~ 2mm/year),
(5) localized and unusually low topography,
(6) crustal scale faults oriented NNW-SSE,
(7) documented normal faults concentric to the Vrancea area and
(8) wide spread, low magnitude shallow seismicity.
One of the most debatable features associated with the SE Carpathians fold and thrust belt is the significant concentration of intermediate depth earthquakes (70-210 km) in an extremely confined and vertical volume, named Vrancea Seismogenic Zone. In the context of plate tectonics this seismicity was interpreted as being produced by the sinking of an oceanic slab. However, new interpretations envision an entirely different process, namely continental delamination of over thickened continental lithosphere (Knapp et al., 2005), also responsible for the active subsidence of the Focsani Basin. In a broader sense, this study examines the relationships between crustal foreland basin deformation and VSZ, foreland deformation at the crustal scale suggesting a geometric association with the Vrancea mantle source region and implying a mechanical coupling of the seismogenic body with the overlying crust. Part of the SE Carpathian foredeep, the Focsani Basin is made up of sands, shale and evaporites that thicken to the west.
We present a methodology to improve the prediction of reservoir quality by combining principles of sequence stratigraphy and rock physics. The purpose of our study is to demonstrate how we can obtain critical sedimentological parameters and relative trends of their spatial variation from sequence stratigraphic interpretation. In turn, these sedimentological parameters can serve as constraints in rock physics modeling thereby reducing uncertainty in predicting reservoir properties from seismic amplitude.
Natural fractures are often responsible for enhancing production in oil and gas reservoirs. Drill locations are defined from an overlay of three key reservoir attribute maps. Seismic attributes are calibrated to clay content measured in existing well control by wire line logs to define fracture-prone brittle reservoir. Gas sensitive seismic attributes such as the phase gradient (an AVO attribute first developed by GeoSpectrum) are used to define a prospective fairway. Natural fractures are predicted using seismic lineament mapping in the reservoir section. Successful drilling results from 5 new wells indicate the new interpretation method is ready for commercialization, and gas exploration and development.
Stacking combines a collection of noisy seismic gathers, such as NMO-corrected CMP gathers or migrated gathers, into a single less noisy seismic section. Existing techniques stack each gather independently, and in the process, ignore the tremendous structure of seismic signals. We propose a novel technique called
Liu, Enru (British Geological Survey, Edinburgh, UK) | Chapman, Mark (British Geological Survey, Edinburgh, UK) | Li, Xiangyang (British Geological Survey, Edinburgh, UK) | Loizou, Nick (Department of Trade and Industry, London, UK)