Converted-wave Imaging Research Articles

Application of multi-component seismic exploration in the exploration and production of lithologic gas reservoirs

The multi-component seismic exploration technique has drawn great attention in the petroleum industry because it enlarges the S-wave information, reduces the ambiguity in reservoir prediction, and improves the prediction and identification possibility of reservoir fluids. To push forward the application and development of the technique, the 2D and 3D multi-component technical tests have been carried out since 2002 in the Sulige Gasfield, Ordos Basin; the Guang'an Gasfield, Sichuan Basin; the Xushen Gasfield, Songliao Basin; and the Sanhu area, Basin, Qaidam Basin. The imaging of the converted wave is better than that of the P-wave for the gas-bearing structures in the deep igneous body of the Songliao Basin and the Sanhu area, and can define the reservoir boundaries more accurately. In the description of the tight sand gas reservoirs of the Sulige and Guang'an Gasfields, the converted wave imaging improves the accuracy of reservoir prediction and fluid identification, paving the way for the arrangement of wells.

Applications of Non-Rigid Matching to 3D converted-wave (PS) imaging

To compensate for lateral or temporal divergence of converted-wave (PS) imaging as a function of azimuth, a two-tiered workflow for applying a non rigid matching (NRM) process is utilized. The resultant product is a final enhanced 3D PS volume with superior stack response and continuity from the optimum combination of two distinct azimuth sectors of a PS prestack time migration (PrSTM) dataset. The method allows for the crossline artifacts from the effect of azimuthal anisotropy on the converted-wave moveout to be almost completely removed. Furthermore, the severe acquisition footprint, from insufficient crossline aperture as a result of a sub-optimum survey design, is effectively mitigated. Seismic data examples of 3D inlines, crosslines and time slices taken from a proprietary 3D/4C OBC survey from the Gulf of Mexico acquired and processed in 2006, demonstrate the compelling benefits of the NRM application and the robustness of the developed workflow. Finally, the output NRM displacement attributes (time-shift values) are found to possess a qualitative value that are not only powerful indicators of azimuthal anisotropy, but also through calibration, may yield valuable information on the magnitude of shear splitting and principal directions of polarization.

Multicomponent prestack depth migration using the elastic screen method

A 3D multicomponent prestack depth-migration method is presented. An elastic-screen propagator based on one-way wave propagation with a wide-angle correction is used to extrapolate both source and receiver wavefields. The elastic-screen propagator neglects backscattered waves but can handle forward multiple-scattering effects, such as focusing/defocusing, diffraction, interference, and conversions between P- and S-waves. Vector-imaging conditions are used to generate a P-P image and a P-S converted-wave image. The application of the multicomponent elastic propagator and vector-imaging condition preserves more information carried by the elastic waves. It also solves the polarization problem of converted-wave imaging. Partial images from different sources with correct polarizations can be stacked to generate a final image. Numerical examples using 2D synthetic data sets are presented to show the feasibility of this method.

05/00056 Proposal of a new rhelogical model of a highly loaded coal-water mixture (CWM): Matsuo, S. Kagaku Kogaku Ronbunshu, 2003, 29, (4), 526–533. (In Japanese)

The multi-component seismic exploration technique has drawn great attention in the petroleum industry because it enlarges the S-wave information, reduces the ambiguity in reservoir prediction, and improves the prediction and identification possibility of reservoir fluids. To push forward the application and development of the technique, the 2D and 3D multi-component technical tests have been carried out since 2002 in the Sulige Gasfield, Ordos Basin; the Guang'an Gasfield, Sichuan Basin; the Xushen Gasfield, Songliao Basin; and the Sanhu area, Basin, Qaidam Basin. The imaging of the converted wave is better than that of the P-wave for the gas-bearing structures in the deep igneous body of the Songliao Basin and the Sanhu area, and can define the reservoir boundaries more accurately. In the description of the tight sand gas reservoirs of the Sulige and Guang'an Gasfields, the converted wave imaging improves the accuracy of reservoir prediction and fluid identification, paving the way for the arrangement of wells.

05/00057 Synthesis and characterization of vegetable oil derived esters: evaluation for their diesel additive properties: Dmytryshyn, S. L. et al. Bioresource Technology, 2004, 92, (1), 55–64

The multi-component seismic exploration technique has drawn great attention in the petroleum industry because it enlarges the S-wave information, reduces the ambiguity in reservoir prediction, and improves the prediction and identification possibility of reservoir fluids. To push forward the application and development of the technique, the 2D and 3D multi-component technical tests have been carried out since 2002 in the Sulige Gasfield, Ordos Basin; the Guang'an Gasfield, Sichuan Basin; the Xushen Gasfield, Songliao Basin; and the Sanhu area, Basin, Qaidam Basin. The imaging of the converted wave is better than that of the P-wave for the gas-bearing structures in the deep igneous body of the Songliao Basin and the Sanhu area, and can define the reservoir boundaries more accurately. In the description of the tight sand gas reservoirs of the Sulige and Guang'an Gasfields, the converted wave imaging improves the accuracy of reservoir prediction and fluid identification, paving the way for the arrangement of wells.

Shallow, high-resolution converted-wave seismology for coal exploration

Despite the considerable successes of multi-component seismology in the petroleum industry, there has been relatively little effort devoted to shallow, high-resolution converted-wave imaging in the coal sector. By analogy to petroleum-scale applications, converted-wave imaging in the coal environment offers interesting possibilities for independent validation of mapped structures, clearer imaging in the shallow sub-surface, and detection of gas, sandstone channels and/or fracture swarms. Over the past two years Velseis Pty Ltd has conducted the first experiments in Australia to utilise shallow, high-resolution multi-component data and converted-wave technology to image coal seams. Three 2D multi-component coal-seismic datasets have been acquired in the Bowen Basin, Australia. Only minimal changes to conventional recording equipment and procedures have been required. A conventional dynamite source has been used, with a single, multi-component geophone replacing the conventional array of vertical geophones at each receiver. Converted-wave processing algorithms developed within the petroleum sector have been successfully applied to the three trial datasets. This has involved specialised approaches to S-wave receiver statics, PS normal moveout and common conversion-point binning. Considerable experimentation to fine tune processing parameters and the converted-wave processing sequence has been necessary for optimum handling of the shallow, high-resolution data. Overall the processing of the PS data has been significantly more challenging, and has required more geological input, than conventional P-wave processing. This research has demonstrated that converted-wave imagery is viable in the shallow environment. The derived PS images can extend the interpretation achieved with conventional P-wave images.

High resolution 3D seismic imaging using 3C data from large downhole seismic arrays

Bjorn Paulsson, Martin Karrenbach, Paul Milligan, Alex Goertz, and Alan Hardin of Paulsson Geophysical Services, with John O'Brien and Don McGuire of Anadarko Petroleum Corporation explain why recording multi-component seismic data using receivers positioned deep in the earth, and closer to the target-zone, can overcome many of the limitations experienced by surface 3D seismic methods. Borehole seismic surveys, commonly known as Vertical Seismic Profiling (VSP), have been an industry standard technique for several decades. In the past, however, these data have been used primarily for check-shot type velocity surveys and for reflection mapping at the well location in a one-dimensional fashion. This 1D measurement can be extended to 2D by using one or more walk-away lines of surface source points. The 2D method works well enough for imaging simple layered stratigraphy, but in a complex reservoir a full 3D data acquisition and imaging solution needs to be pursued. Inserting seismic sensors deep into oil and gas wells, as shown in Figure 1, allows the recording of much higher frequencies as compared to placing sensors at the Earth’s surface. The reason for this is simple: seismic waves have to propagate only once through the weathered layer in a confined zone near the source. In contrast, during surface seismic surveys, waves must travel through the weathered layer twice. Each traversal of the weathered layer attenuates high frequencies much more than the low frequencies, thus reducing the image resolution. The frequency content of borehole seismic data is typically more than twice that of surface seismic data, which provides an increase in subsurface resolution. In addition to recording higher frequency data, borehole seismic sensors provide a number of other advantages: borehole seismic data typically achieve a much higher signal-tonoise ratio than surface seismic data. The combination of a quiet borehole environment and strong sensor coupling to the borehole wall enables such high signal-to-noise ratio. Surface geophones, on the other hand, are generally poorly coupled in weathered rock and exposed to cultural and environmental noise at the surface. Good sensor coupling in the borehole enables three-component (3C) seismic data to be recorded with high vector fidelity. This ultimately allows shear and converted-wave imaging as well as the determination of anisotropy by shear wave splitting analysis (see, e.g., Maultzsch, 2003). Combining P and S wave images allows for attribute inversions of rock properties, such as fluid content, pore pressure, stress direction and fracture patterns. O’Brien et al. (2004b) use time lapse borehole seismic to map changes in such critical attributes for production monitoring purposes. Another advantage of borehole seismic surveys is a favourable geometry to illuminate complex structures such as sub-salt targets, salt flanks or steeply dipping faults. The 3D image volume that can be generated from a large downhole seismic array data is shown in Figure 1. The typical 3D borehole seismic image volume is cone shaped with the top of the cone coincident with the top receiver in the borehole array. The size of the base of the cone is determined by the depth of the image volume and the offset of the sources.

MULTI-COMPONENT SEISMIC—THE TOOL FOR ALL REASONS

Marine multi-component seismic, known as 4C, is an emerging seismic technology providing improved and sometimes unique solutions to many common problems. In the marine environment the seismic sensors have to be placed on the sea-floor to capture converted or shear wave modes that cannot propagate through liquid media. Although this means increased acquisition cost, the improved information content makes it money well spent to better image and characterise reservoirs.The 4C solutions fall into two major groups of five. First there are the imaging solutions:Improved standard P-wave imaging. Improved converted wave (P-S) resolution in the shallow sediments. Converted wave imaging through gas clouds. Converted wave imaging of low impedance contrast reservoirs. Improved sub-salt and sub-basalt imaging with converted waves. The second group consists of the five characterisation solutions:Improved fracture characterisation by means of P-S waves. Qualitative 4D or time-lapse characterisation of fractured reservoirs with low intrinsic permeability. Improved lithology and fluid characterisation by combining the information in the two wave modes. Improved quantitative time-lapse evaluation of pressure and saturation changes. Improved characterisation of drilling hazards by combined evaluation of the two wave modes. So far the most popular 4C solutions are imaging through gas and improved P-wave imaging of Jurassic reservoirs in the North Sea, for example the Statfjord, Brent and Beryl fields. However, as the technology is developing and maturing, the characterisation solutions will probably be the most common applications of 4C in the near future.

Using converted shear waves to image reservoirs with low-impedance contrast

Imaging sand/shale sequences is problematic when the impedance contrast between them is very small, a problem commonly encountered in basins with Tertiary clastics. Impedance trends for sand and shale in these basins display higher impedances for shales than for sands at shallow depths; however, sands exhibit higher impedances than shales at greater depths. That implies a crossover between the trends at some depth and that it is going to be difficult to image sands near the crossover depth with traditional seismic surveys. Sometimes stacking far-offset data is a solution because a strong AVO gradient can generate significant reflections at high angles of incidence, even if the normal-incidence reflection coefficient is close to zero. Converted waves can, in some cases, image the reservoir. The question is when because there is no generally accepted insight regarding what conditions favor converted-wave imaging. In other words, why does converted-wave imaging work very well in some reservoirs and not so well in others? Three conditions must exist for converted shear-wave imaging to be preferable to conventional P-P imaging: 1. A very small acoustic impedance contrast results in very weak reflections and thereby poor images. 2. The offset dependence of P-P amplitudes is not useful because (a) a small contrast in Poisson's ratio across the contact between seal and reservoir makes the P-P AVO gradient small, resulting in weak amplitudes at all offsets, or (b) velocity distribution in the overburden makes it impossible to achieve large angles of incidence at the reservoir level. 3. A large shear-wave impedance contrast generates strong converted waves. The first point simply states the obvious—converted-wave imaging is cost effective only when traditional P-P imaging fails, and P-P imaging fails when the acoustic-impedance contrast is close to zero. Point …