Pre-stack Simultaneous Inversion Research Articles

Seismic inversion for organic richness and fracture gradient in unconventional reservoirs: Eagle Ford Shale, Texas

A method using Eagle Ford organic shale from Texas predicts key unconventional reservoir properties, total organic carbon (TOC), and fracture pressure gradient (FG). Applying petrophysical and rock-physics models from previous work to the available well-log data generates the required logs for calibration, i.e., shear sonic, TOC, organic porosity, and saturation. Prestack seismic data can be evaluated using synthetic forward modeling and can be conditioned further to improve AVO response. Simultaneous prestack inversion to derive acoustic-impedance (AI) and shear-impedance (SI) volumes can be run, and TOC can be derived from those volumes by linear interpolation. Fracture gradient (which also can be thought of as “frackability”) is related directly to Poisson's ratio and effective stress and can be estimated from elastic properties. The fracture gradient is related nonlinearly and inversely to TOC, i.e., assuming laterally and vertically homogeneous pore-pressure distribution inside the spatially limited block of the Eagle Ford Shale, higher TOC results in lower FG and hence better frackability.

Shale-gas reservoir-prediction study in Daanzhai, Eastern Sichuan Basin

In recent years, the economic viability of large-scale shale-gas exploration and development projects has been impacted directly by improvements in horizontal-well drilling and hydraulic-fracturing technologies. However, results from multiple shale-gas projects indicate that accurate reservoir descriptions and resulting predictions of sweet spots are also crucial to maximize production from those projects. Accurate reservoir description results in the most appropriate placement of well locations and trajectories, hydraulic-fracture design, and reservoir engineering. The successful experience in shale-gas exploration and development outside China can aid in the search for the most favorable geologic characteristics and rock-physical properties and the examination of appropriate well-log interpretation and seismic-reservoir-prediction technologies for a shale-gas study in the eastern area of Sichuan Basin, China. Favorable parameters in a shale-gas reservoir are mid- to high kerogen content, low clay volumes, high brittleness, high effective porosity, and high permeability, along with well-developed microfractures. Of those parameters, mid- to high total organic carbon (TOC) is favorable for shale-gas accumulation, and high brittleness is beneficial to hydraulic-fracture propagation. Hence, the aim is to find sweet spots with high TOC and high brittleness. Starting with petrophysical analyses that combine laboratory measurements, core data, and well logs, a statistical model is used to estimate relative volumes and compositions of TOC and minerals and to establish a qualitative evaluation criterion for shale-gas reservoirs in this area. Petrophysical modeling and rock-property analyses establish the relationship among petrophysical properties (such as TOC, effective porosity, and gas saturation) and elastic properties (such as P-impedance, VP/VS ratio, Poisson's ratio, and Young's modulus) of the formation, which are related to brittleness. Rock-property analysis, prestack simultaneous inversion, and facies-fluid probability-analysis technologies help to predict favorable development zones for the shale-gas reservoir. Finally, the values of brittleness, TOC, and shale-gas lithology volume are combined to predict the sweet spots of the gas shale and to guide subsequent developments.

Prestack seismic inversion versus neural-network analysis: A case study in the Scarab field offshore Nile Delta, Egypt

In clastic depositional systems such as those encountered in the Nile Delta Basin, simultaneous prestack seismic-amplitude inversion is an effective method for detecting and appraising gas-bearing sandstone reservoirs. However, the method has limitations concerning the requirement of a reliable set of wavelets, suitable wireline logs, and a sufficiently dense initial model. The neural-network analysis method is an alternative technique which sometimes can provide similar or better results and does not require significant volumes of data. Simultaneous prestack inversion was applied over the Scarab field, West Delta Deep Marine concession, offshore Egypt. The field comprises submarine channel-based gas reservoirs that extend laterally over 20 km2. Six wells were analyzed in a rock-physics study prior to performing inversion. Three angle gathers (near: 0–15°; mid: 15–30°; far: 30–45°) were inverted for P-wave impedance (ZP), S-wave impedance (ZS), P-wave velocity (VP), S-wave velocity (VS), VP/VS, and density (ρ) using the prestack inversion method. Neural-network analysis was performed using full-stack seismic data along with well logs in the training stage, followed by cross-validation of results and rendering of VP, VS, VP/VS, and density volumes. The VP/VS volumes produced from the two methods were used to infer water saturation (Sw). Direct comparisons were made between neural-network and prestack inversion results at a blind-well location to assess the relative quality of each method. Results suggest that application of the proposed neural-network method leads to reliable inferences. Hence, using the neural-network method alone or along with the prestack inversion method has a positive impact on reserves growth and increased production.

Rock physics analysis: a tool for lithology and fluid prediction in the Gulf of Thailand

SUMMARY The Tertiary rift basins of the Gulf of Thailand are major hydrocarbon producing areas. The reservoirs in these basins are mostly fluvial sands of Miocene and Oligocene age. Gas is found mostly in central basins whereas there are more oil discoveries in western marginal basins. The main objective of this study is to understand the vertical and spatial trends of different rock physics parameters which can be used to differentiate lithology and fluids in these basins. Cross-plot and fluid substitution analysis were performed to determine lithology and/or fluid sensitive rock properties. Cross-plot analysis shows that sands have low P-velocity and density at shallow depths as compared to shale but the contrast of P-velocity between sand and shale decreases significantly at deeper levels. However, density shows significant contrast between sand and shale throughout the zone of interest and is therefore a more useful lithology discriminator. Density can also distinguish highly gas-saturated sands (80%) from water-wet sands throughout the zone of interest. On the other hand, oil-bearing sands cannot be so easily discriminated from water-wet sands. In comparison Vp/Vs can only successfully resolve high porosity sands (>16%) and gas sands when used in combination with P impedance. This regional rock physics study indicates that appropriate inversion techniques for lithology and fluid prediction studies need to be considered carefully. Post stack P-impedance volumes generated by inversion are very useful at shallower levels down to 1900 to 2000 metres but at deeper levels, density volumes generated by pre-stack simultaneous inversion are more appropriate.

Seismic characterization of a Mississippi Lime resource play in Osage County, Oklahoma, USA

With the advent of horizontal drilling and hydraulic fracturing in the Midcontinent, USA, fields once thought to be exhausted are now experiencing renewed exploitation. However, traditional Midcontinent seismic analysis techniques no longer provide satisfactory reservoir characterization for these unconventional plays; new seismic analysis methods are needed to properly characterize these radically innovative play concepts. Time processing and filtering is applied to a raw 3D seismic data set from Osage County, Oklahoma, paying careful attention to velocity analysis, residual statics, and coherent noise filtering. The use of a robust prestack structure-oriented filter and spectral whitening greatly enhances the results. After prestack time migrating the data using a Kirchhoff algorithm, new velocities are picked. A final normal moveout correction is applied using the new velocities, followed by a final prestack structure-oriented filter and spectral whitening. Simultaneous prestack inversion uses the reprocessed and time-migrated seismic data as input, along with a well from within the bounds of the survey. With offsets out to 3048 m and a target depth of approximately 880 m, we can invert for density in addition to P- and S-impedance. Prestack inversion attributes are sensitive to lithology and porosity while surface seismic attributes such as coherence and curvature are sensitive to lateral changes in waveform and structure. We use these attributes in conjunction with interpreted horizontal image logs to identify zones of high porosity and high fracture density.

Calibration of prestack simultaneous impedance inversion using rock physics

This paper represents the third installment in a sequence of reservoir characterization articles that follow a workflow whose ultimate goal is to understand and predict the rock properties of a reservoir away from well control. The first article (Singleton, 2008) described a method to detect anomalous seismic attenuation. This was important because seismic data at the well location have a steep falloff in amplitude caused by high attenuation in and above the reservoir interval. The second article (Singleton, 2009) dealt with the seismic gathers that were input into the inversion process. It is of the utmost importance that the quality of data input into a simultaneous prestack inversion be as high as possible. Errors in seismic gathers (low SNR, resolution loss from excessive NMO stretch, nonflat reflectors, offset amplitude problems, multiples, etc.) are broadcast straight into the inversion impedance volumes, so this is a critical step in geophysical reservoir characterization.

The effects of seismic data conditioning on prestack simultaneous impedance inversion

It is well known among the seismic data processing community that the demands of reservoir characterization are far more rigorous than those of structural interpretation. Further, the undesired prestack seismic phenomena that need to be diminished or removed prior to reservoir characterization are also well known. The objective of this paper is to quantify the advantages of performing prestack data conditioning prior to reservoir characterization. Three specific seismic properties that will be addressed are: (1) signal-to-noise ratio (SNR), (2) offset-dependent frequency loss, and (3) gather alignment.

The use of seismic attenuation to aid simultaneous impedance inversion in geophysical reservoir characterization

The current state-of-the-art in reservoir characterization is to input properly conditioned gathers into a prestack simultaneous impedance inversion workflow. Simultaneous inversion is defined as the simultaneous solution of all unknown quantities in a reflectivity equation. If two-term inversion is run, then the outputs are P-impedance (AI) and S-impedance (SI). These two quantities are then crossplotted and pay zones delineated using polygons created from a similar crossplot of upscaled AI and SI well logs.

Seismically-driven appraisal and development: A case study from Bolivia's Chaco Basin

Through integration of multiple geophysical and geologic techniques, we significantly reduced the geotechnical risk associated with several prospects of Cretaceous reservoirs in an area of Bolivia's Chaco Basin, and we verified our interpretations through the successful drilling of those prospects. The approach encompassed basin modeling, joint well, and seismic prestack simultaneous inversion, rock properties and seismic attribute interpretation, AVO/AVA, flat seismic events, and spectral decomposition. The joint interpretation enabled fine-scale adjustments of the structural and depositional model that were tested repeatedly by the drill bit. To date, seven successful wells have been drilled in the new trend.