Multicomponent Acquisition Research Articles

Multi-component seismic-resolution analysis using finite-difference acquisition modelling

Various rules-of-thumb (e.g. Fresnel radius, Rayleigh limit) are commonly used to predict seismic resolution, based on the dominant frequency on the image. However, seismic resolution ultimately depends on more fundamental parameters including survey design, source bandwidth, geology, and data processing. A more instructive analysis is possible via numerical modelling of the acquisition process. Here we demonstrate the improved insight available with this approach, using examples taken from the petroleum and coal sectors.We use viscoelastic finite-difference modelling to simulate 2D multi-component acquisition sequences. The ability to allow for anelastic attenuation is important as it permits a more realistic comparison of the resolution achievable on P-wave and converted-wave (PS) imagery.An examination of vertical resolution for a wedge model on a petroleum scale indicates that processed P-wave sections have poorer resolution (62 m) than predicted by the Widess (20 m) and Rayleigh (40 m) resolution limits. For this model the vertical resolution for the PS data is comparable to that of the P-wave data. This is in agreement with the theoretical relative-resolution relationship.A second example examines detection of lens-like features at petroleum depth. The resolving ability on the P-wave imagery is broadly consistent with analytical predictions appropriate to migrated data (100 m laterally and 40 m vertically). Again PS resolution is comparable to P resolution.Analysis of a typical coal target suggests that barren-zones of width 5–10 m can be resolved. The interplay of wavelength and attenuation is such that the PS image is likely to exhibit comparable, or slightly reduced, lateral resolution, provided statics are not a problem. Resolution can be downgraded significantly if statics are more severe, and in practice this is likely to have greater impact on the PS image.Realistic numerical modelling, simulating the full acquisition and processing sequence, leads to a more pragmatic understanding of seismic resolution issues. It is a valuable tool for survey planning and image interpretation.

Modelagem e migração em profundidade 2D em meios com simetria polar local

This paper shows a technique based on the phase-shift method (PSM) to implement pre-stack depth migration on locally transverse isotropic media (LTI), with the symmetry axis direction varies continually along the layers. For seismic modeling, a generalization of the finite differences method for the solution of the elastic wave equation was used. With this procedure, it was possible to accommodate seismic modeling on LTI media defined by six parameters at each grid point, i.e. , density, P and S wave propagation velocities along the local symmetry axis, Thomsen parameters and the direction of the local symmetry axis itself. In order to separate from the seismograms the qP and qSV wavefields, an algorithm based on the Christoffel equation was implemented. The migration for each common shot gather is implemented solely by phase-shift based algorithms, which means that not only the depropagation of the registered wavefield, but also the generation of the time matrices involved in the imaging condition were obtained in this manner for each set of parameters at each depth level. The migration results using qP-qP and qP-qSV reflections show that the horizons were located precisely, and that the process is stable in relation to the symmetry axis variations. The proposed method is for multicomponent seismic acquisitions and might be applied to marine seismic data using streamers, or Ocean Bottom Cables or vertical cables. Since the proposed method uses phase-shift algorithms, its parallel implementation can be highly efficient.

MEMS sensors: Some issues for consideration

The development of purpose-built multicomponent data acquisition systems based on MEMS (Micro Electro Mechanical System) digital accelerometers has resulted in improved data quality, more efficient field operations, and diminished multicomponent acquisition costs. This, coupled with advances in processing and interpretation of converted-wave (PS) multicomponent seismic data, has renewed enthusiasm for using multicomponent data to address issues poorly resolved by P-wave information alone.

Wideband spectral matrix filtering for multicomponent sensors array

As multicomponent (3C or 4C) seismic acquisitions are now commonly used, specific processings for multicomponent data sets are required. The aim of this paper is to present a new wavefield filter for multicomponent seismic data. The proposed method is derived from a recent technique used for single component data, which takes into account the wideband characteristics of the signal. The multicomponent extended method incorporates the polarization information and processes the various components in a global way instead of treating them independently. The proposed method is based on the computation of a global spectral matrix which gathers all the frequential and component interactions. We prove that the eigenvalue decomposition of a reduced matrix issued from this global matrix enables an efficient separation in two complementary spaces: one contains the signal and the other, the noise. The results obtained on synthetic and real data are presented and compared with others methods in order to assess the performances of our algorithm.

Anadarko Basin survey shows value of multicomponent acquisition

In this case study of a survey in the Anadarko Basin, Oklahoma, Steve Roche, Mark Wagaman, and Howard Watt of Veritas DGC in Houston show that using both P-wave and converted shear wave data provides better gas production estimates. Interpretation of multicomponent data holds great promise for the exploration and development of oil and gas. Shear-wave propagation is sensitive only to rigidity and density, while compressional-wave propagation is sensitive to rigidity, density and compressibility. Interpreting both P- and S-wave reflectivity offers the ability to discriminate lithology, porosity, fractures and possibly fluid content. Recent advances in seismic recording systems, sensor technology and data processing methods are such that the use of multicomponent data for exploration and development is now an economic reality. Specific case studies such as the Anadarko Basin data show the viability of recording converted-wave data. As the industry moves towards 3C recording there also needs to be assurance that P-wave data quality will not be compromised. These data demonstrate that 3C single-sensor P-wave data quality will meet, and possibly exceed, data recorded using conventional P-wave only surveys, if proper attention is given to the signal-to-noise characteristics in the survey area. This may require higher station density and/or a finer group interval in many cases. This paper has three parts, a description of the North Emerald 3C3D test and resulting P-wave (PP) and converted-wave (PS) data quality, relating the P-wave and converted-wave reflectivity to natural gas production from the Springer Formation, and comparing single sensor MEMS recording to six element geophone array data.

Recent advances in geophysical technology: introduction and review

In many basins and especially those in NW Europe, 3D seismic data have become a necessary prerequisite to development, appraisal and, almost routinely, exploration drilling, but equally they are rarely seen as being sufficient. Why is this, when the majority of industry analysts recognize the value of 3D seismic data to an oil company’s exploration portfolio: are geophysicists too successful at marketing? Are we victims of promising too much, or should we see this hunger for ever more subsurface information as encouragement to refine existing technologies further and to develop new ones? In September 2002, the Geological Society meeting on exploration in volcanic margins heard about a successful strategy of ‘drilling the bumps’, which led to the discovery of the Marjun hydrocarbon accumulation, the first in Faroese waters. Petex 2002 was told that the biggest UK North Sea discovery for a decade had not used ‘geophysical malarkey’. Is seismic technology inadequate, or has it reached its limits as the targets get ever tougher? Evidently, as the remaining basins become covered by seismic surveys, the easy finds are becoming fewer. Having consumed roughly half the world’s proven reserves, new reserves must be found using ever more imaginative geological hypotheses, and remote sensing technologies will need to give access to ever more information and provide discrimination to test the hypotheses and reduce the risk. The quest for resolution is unrelenting and finer spatial sampling is providing significant improvements in imaging. Honouring well information requires more realistic, anisotropic velocity models for pre-stack depth migration which furnish images that are better representations of the drillable geology. The need to qualify the data in a seismic survey has resulted in so many auxiliary measurements of the acquisition system itself that the subsurface data are almost in a minority, but this brings improved, quantified repeatability, with the potential to drive down time-lapse seismic noise and reveal subtle, production-related reservoir changes. Qualified amplitudes and careful control during processing allow inversion for elastic parameters of the subsurface. With good petrophysical and geomechanical models, elastic inversions can benefit both the reservoir engineer and the driller and offer further potential for multi-component acquisition in reservoir characterization. Salt, basalt or complex tectonic overburdens pose their own challenges to imaging and encourage potential field measurements to complement seismic data in velocity model building and the prediction of reservoir rocks or fluids. Very long offsets and very low seismic frequencies may also have a rô le to play in these environments. Breakthroughs in data handling and visualization technology allow us to take full benefit of these improvements. The stimulus for innovation is as strong as ever and, even if the immediate economic context is uncertain, the industry is responding. This paper will review several of the current technology trends and offer some speculation on the road ahead.

Optimal use of PP and PS time‐lapse stacks for fluid–pressure discrimination

ABSTRACTThe combined use of time‐lapse PP and PS seismic data is analysed for optimal discrimination between pressure and saturation changes. The theory is based on a combination of the well‐known Gassmann model and the geomechanical grain model derived by Hertz and Mindlin. A key parameter in the discrimination process is the opening angle between curves representing constant changes in PP and PS reflectivity plotted against pressure and saturation changes. The optimal discrimination angle in the pressure–saturation space is 90° and this is used to determine optimal offset ranges for both PP and PS data. For typical production scenarios, we find an optimal offset range corresponding to an angle of incidence of 25–30°, for both PP and PS data. For gas we find slightly different results. This means that conventional survey parameters used in marine multicomponent acquisition should be sufficient for the purpose of estimating pressure and fluid saturation changes during production.

Geophysical monitoring of subsurface CO2

Geological storage of CO2 will require accurate, high-resolution geophysical monitoring to map the subsurface flow paths and the phase state of the fluids. Existing and potential monitoring methods include seismic (both surface and borehole), electromagnetics, gravity, and well logging. Seismic methods are expected be the main form of monitoring as it is cost effective and covers the whole area of interest. When used in a time-lapse sense, areal mapping of the injected CO2 is possible with existing technology. However, improvements in resolution are required to detect leakage and identify preferential flow paths. Multi-component seismic acquisition may be necessary to discriminate between changes in saturation and pressure within the CO2 reservoir. Passive monitoring of induced microseismic events may prove to be an effective way to evaluate the effects from the injection of CO2 on the integrity of the cap rock and provide early warning of fracturing or fault reactivation. Supporting geophysical methods will be needed for accurate quantitative interpretation of the seismic data. The geological setting and the availability of wells and pre-existing baseline data will have a profound influence on the choice of any additional geophysical methods. Electromagnetic methods have lower resolution than seismic, but are far more sensitive to changes in fluid saturation and may detect anomalies that are too subtle to interpret from seismic data alone. Gravity surveys are relatively cheap to acquire on land, but improvements in measurement sensitivity and constrained inversion methods are required before gravity can be of value for monitoring subsurface CO2 in the supercritical state.

Interpretation and practical applications of 4C-3D seismic data, East Cameron gas fields, Gulf of Mexico

Rapid advancements in multicomponent acquisition methods and processing techniques have led to numerous applications for converted wave (C-wave) data that are increasingly used for exploration and exploitation of oil and gas. However, the increased prevalence of multicomponent seismic applications means that interpreters must face many difficult challenges: how to register P-wave time to C-wave time, determine the best methodology for interpreting C-wave data, and/or how to apply the C-wave interpretation in assessing the risks of exploration and exploitation prospects. This paper addresses these issues and attempts to guide the interpreter through the multicomponent data interpretive process with numerous examples from two East Cameron gas fields in the Gulf of Mexico.

Some requirements for PS-mode acquisition

For land seismic surveys, it is still commonly thought that switching from conventional to multicomponent acquisition merely requires replacing vertical receivers with 3C receivers. This may work in some but not all cases. Fortunately, when it doesn't, the situation may be rectified by accounting for the physics of PS-mode propagation. In fact, this is often the prerequisite for obtaining comparable resolution of P and PS reflections at the target level—the condition for obtaining full benefit from the combined use of P and PS data for determining appropriate exploration attributes and seismic inversion.

Converted‐wave seismic exploration: Applications

Converted seismic waves (specifically, downgoing P‐waves that convert on reflection to upcoming S‐waves are increasingly being used to explore for subsurface targets. Rapid advancements in both land and marine multicomponent acquisition and processing techniques have led to numerous applications for P‐S surveys. Uses that have arisen include structural imaging (e.g., “seeing” through gas‐bearing sediments, improved fault definition, enhanced near‐surface resolution), lithologic estimation (e.g., sand versus shale content, porosity), anisotropy analysis (e.g., fracture density and orientation), subsurface fluid description, and reservoir monitoring. Further applications of P‐S data and analysis of other more complicated converted modes are developing.

Processing the Hod 3D multicomponent OBS survey, comparing parallel and orthogonal acquisition geometries

The Hod 3D multicomponent ocean-bottom seismic (OBS) survey was acquired to image the reservoir through a gas cloud. Data were acquired with shot lines both along the receiver cables (in-line or parallel shooting) and orthogonal to the receiver cables (cross-line shooting).

A proposed polarity standard for multicomponent seismic data

This paper proposes a multicomponent acquisition and preprocessing polarity standard that will apply generally to the three Cartesian geophone components and the hydrophone or microphone components of a 2‐D or 3‐D multicomponent survey on land, at the sea bottom, acquired as a vertical seismic profile, vertical‐cable, or marine streamer survey. We use a four‐component ocean‐bottom data set for purposes of illustration and example. A primary objective is a consistent system of polarity specifications to facilitate consistent horizon correlation among multicomponent data sets and enable determination of correct reflectivity polarity.The basis of this standard is the current SEG polarity standard, first enunciated as a field‐recording standard for vertical geophone data and hydrophone streamer data. It is founded on a right‐handed coordinate system: z positive downward; x positive in the forward line direction in a 2‐D survey, or a specified direction in a 3‐D survey, usually that of the receiver‐cable lines; and y positive in the direction 90° clockwise from x. The polarities of these axes determine the polarity of ground motion in any component direction (e.g., downward ground motion recording as positive values on the vertical‐geophone trace). According also to this SEG standard, a pressure decrease is to be recorded as positive output on the hydrophone trace. We also recommend a cyclic indexing convention, [W, X, Y, Z] or [0, 1, 2, 3], to denote hydrophone or microphone (pressure), inline (radial) geophone, crossline (transverse) geophone, and vertical geophone, respectively.We distinguish among three kinds of polarity standard: acquisition, preprocessing, and final‐display standards. The acquisition standard (summarized in the preceding paragraph) relates instrument output solely to sense of ground motion (geophones) and of pressure change (hydrophones). Polarity considerations beyond this [involving, e.g., source type, wave type (P or S), direction of arrival, anisotropy, tap‐test adjustments, etc.] fall under preprocessing polarity standards. We largely defer any consideration of a display standard.

SVD for multioffset linearized inversion: Resolution analysis in multicomponent acquisition

Acquisition of the full elastic response (compressional and shear) of the subsurface is an important technology in the seismic industry because of its potential to improve the quality of seismic data and to infer accurate information about rock properties (fluid type and rock lithology). In the framework of 3-D propagation in 1-D media, we propose a computational tool to analyze the information about elastic parameters contained in the amplitudes of reflected waves with offset. The approach is based on singular value decomposition (SVD) analysis of the linearized elastic inversion problem and can be applied to any particular seismic data. We applied this tool to examine the type of information in the model space that can be retrieved from sea‐bottom multicomponent measurements. The results are compared with those obtained from conventional streamer acquisition techniques. We also present multiparameter linearized inversion results obtained from synthetic data that illustrate the resolution of elastic parameters. This approach allows us to investigate the reliability of the elastic parameters estimated for different offset ranges, wave modes, data types, and noise levels involved in data space.

IRMA: A tunable infrared multicomponent acquisition system for plasma diagnostics

A compact and transportable infrared multicomponent acquisition (IRMA) system based on infrared absorption spectroscopy has been developed for plasma diagnostics and control. The IRMA system contains four independent tunable diode lasers which can be temporally multiplexed and directed into plasma reactors or into a multipass cell for exhaust gas detection. Rapid scan software with real-time line shape analysis provides simultaneous measurements of the absolute concentrations of several molecular species.