Pierre-Yves Granger

Mirror imaging of OBS data

The world’s demand for energy is accelerating, while its hydrocarbon reserves are diminishing. Producers are compelled to explore and produce oil and gas in more challenging environments and to maximize recovery in existing reservoirs. New technology has always been a key to success. One such new technology is seismic acquisition using ocean bottom station (OBS) nodes (Berg et al., 1994; Ronen et al., 2003; Amal et al., 2005; Docherty et al., 2005; Granger et al., 2005).

Combined interpretation of PP and PS data provides direct access to elastic rock properties

Multicomponent seismic has been around for more than 30 years but is still struggling to gain widespread acceptance. Although the benefits of shear-wave exploration are countless, only imaging through gas clouds is regularly implemented—a significant niche perhaps, but a niche nevertheless.

Comparison of different strategies for velocity model building and imaging of PP and PS real data

In 1999, a 2-D/4-C data set acquired with ocean-bottom cable on Mahog-any Field, Gulf of Mexico, was distributed at the SEG-EAGE Research Workshop to test the feasibility of using converted waves to image under a salt diapir. We show and discuss results obtained by several imaging methods—some in the time domain, others in the depth domain—applied to both PP and converted-wave fields ( PS , also referred to as the C -wave). After a review of the standard time-domain approach (DMO, common conversion point or CCP binning, NMO stack, and poststack time processing), we will consider more elaborate approaches. We start with methods that use observations in the unmigrated time domain, inversion of stacking velocities and inversion of picked prestack traveltime. We finish our review with methods that use observations in the migrated domain, migration velocity analysis using prestack time migration, and migration velocity analysis using prestack depth migration. The multicomponent 2-D Mahog-any data set is oriented E-W and was acquired with a 1.5 km 4-C cable at a quasiconstant water depth of 118 m (Figure 1). Maximum offset is 11.5 km. Record length is 10 s with a 2-ms sampling rate. The line was shot vertically above the receivers, and the line direction chosen to minimize 3-D effects. Raw shot gathers show that PP waves were mainly recorded on the P (pressure) and Z (vertical) components. PS waves were essentially recorded on the X (in-line horizontal) component. Some time processing steps specific to OBC acquisition were undertaken—surface-consistent compensation of coupling between the receivers and the sea bottom, P-Z summation for the PP waves, and medium wavelength surface-consistent receiver statics for the PS waves to account for the extremely low S -wave velocity in the near-sea bottom. The polarity of positive offsets was reversed to obtain radial polarity X -component gathers …

Autonomous 4C Nodes used in infill areas to complement streamer data, deepwater case study.

Summary During the summer of 2004 an experimental OBS survey was acquired and processed by CGG over the Girassol field operated by Total Angola, offshore West Africa. Five ARMSS nodes (Autonomous Reservoir Monitoring Seismic System) were deployed in this area at a water depth of 1300 meters. The primary objective of this trial was to verify the operational sequence and performance of this new generation of 4C recording equipment. There were also a number of secondary objectives which were to benchmark the recorded data with a view to infilling the streamer acquisition in this difficult environment and to evaluate the added value of recording four components. In this paper, after a short description of the recording system and the acquisition layout, the results of the processing are compared with streamer data acquired previously in the same area. The 4D capabilities of the node technology are assessed. A comparison of the results proves that nodes could be used in infill areas to complement streamer data.

Improving resolution and seismic quality assurance through field preprocessing

The constant need to improve the resolution of seismic surveys has led to a continuous increase in the number of acquired channels which has, in turn, resulted in a decrease in the station interval and the spatial filtering of the receiver groups. Over a 40-year period, the average channel number has doubled every seven years (an annual rate of 12%). Advances in processing and large dynamic range recording have made it possible to tolerate noisy traces and thus respect the high‐frequency components of the signal. If acquisition technology improves at a similar rate over the next decade, the recording of every individual receiver is realistic.

About compressional, converted mode, and shear statics

Strong near-surface lateral variations, the lack of a smooth shallow refraction marker, and poor signal-to-noise ratio, can, either alone or in combination, induce residual static problems that affect the seismic result in different ways. These depend on the amplitude and wavelength characteristics of the residual anomalies. In addition, as this article will describe, different types of waves—i.e., compressional or noncompressional—require different statics corrections.

Elastic parameter derivations from multi-component data.

The estimation of elastic parameters from seismic data provides lithologic information for reservoir characterisation. In theory, elastic parameters can be derived from conventional seismic, based upon the amplitude versus offset relationship of compressional mode reflectivity. In practice, this approach is difficult to use, because it requires uncommonly favorable conditions: • accurate move-out corrections at long offsets, • high signal-to-noise ratio. Multi-component technology increases the robustness of elastic inversion: • long-offset considerations are no longer mandatory since more data from P and S (or PS) wave modes are available at shorter offsets, • P and S reflectivities are involved in better balanced conditions, allowing a somewhat lower signal-to-noise ratio than for single-wave mode. The price to pay to access this bimodal inversion is the accurate association of P and S (or PS) propagation times, which correspond to the same depth. The proposed approach to reach this accurate association consists in equating two possible derivations of the Vp/Vs ratio: • first, through the P and S (or PS) transit time ratio, • second, through the P and S (or PS) velocity contrasts obtained from P and S (or PS) reflection coefficients. Non-linear optimisation techniques are used to minimize the differences. Once P and S (or PS) times are accurately associated, the side product (Vp/Vs ratio or Poisson’s ratio) is a piece of information in itself. Moreover, elastic inversion can be obtained from a system of Zoeppritz equations involving P and S (or PS) reflectivities, instead of P-mode reflectivity alone.

3D PP-PS joint Stratigraphic Elastic Inversion through combined AVA attributes

Multi-component seismic is increasingly being recognized not only as a solution to imaging problems, particularly where conventional seismic fails, but also as a tool for reservoir characterization. But geologists are often unenthusiastic to extract earth information from multi-mode seismic images because of their visual differences due to their own physical responses, and when the seismic images are equivalent the PS data does not provide any additional information by itself. The stratigraphic inversion is considered as a tool to transform seismic amplitude variations into petrophysical variations. With multicomponent acquisition, the AVA attributes of PP and PS modes are usually accessible, providing the additional shear wave information for a more constrained elastic inversion. Our inversion method simultaneously reconciles amplitude and time information from both PP and PS-wave data by equating the value of γ = Vp/Vs derived from the velocities or transit time ratio (γt ) and the value derived from the reflectivity ratio (γa), providing not only the high-resolution of the Vp/Vs = γr or the Poison ratio but also eventually Vp, Vs and densities (Garotta et al., 2000). A trace by trace inversion using simulated annealing process was described by (Dariu et al., 2003). In this paper we propose to examine some new possibilities and an extension of the method to 3D constraints in order to decrease the sensitivity to the noise and take into account the geological structure.

3D SRME on OBS Data Using Waveform Multiple Modelling.

Summary Surface-consistent data auto-convolution involved in the modeling of surface related multiple reflections (SRME) does not apply easily to Ocean Bottom Survey data unless surface data is available along the OBS shooting locations, or if the receiver distribution allows for wavefield continuation. For cases where only OBC data are available, and in situations with extremely sparse receiver distributions, 3D SRME can still be achieved by using 3D wavefield multiple modeling (WFM SRME). With this method, surface-related multiples are built by modeling the bounces of primaries and multiples within a migrated section representing any arbitrary 3D reflectivity model. Unfortunately, migration of up-going waves from OBS data suffers from the sparseness of the receiver distribution, thus resulting in blanks along the seafloor reconstruction because of the lack of fold and inapplicability of the imaging condition. Instead, down-going first-order multiples can be easily separated from the data after calibration and P-Z differentiation. This data can then be migrated by using the image of the receiver location with respect to the surface of the sea. This image is unambiguous, and allows for a better illumination and imaging of the seafloor, suitable for WFM SRME. This migration method, followed by WFM SRME, has been successfully applied on real OBS (node) data. Results are shown below..

About Gamma ratios and their combinations

The ratio between the compressional to shear velocities (Gamma or Γ = Vp/Vs) is a key parameter in the combination of P and S (or PS) data. It can be derived in several ways. The most obvious are the ratio between the S to P propagation times between associated events (ΓT) and the ratio between P to S normal moveout velocities (ΓV). Comparing P and S (or P and PS) seismic amplitudes also gives access to Gamma ratio (ΓA). The different derivations have different properties involving or not anisotropy effects: for example, the ratio ΓV / ΓT detects the effects of anisotropy and can be a lithology indicator. Some other combinations of Gamma ratios are already in use, such as Γeff, defining the location of the conversion point in PS propagation.