Choo, C.K. (Sarawak Shell Berhad) | Rollett, E. (Sarawak Shell Berhad) | Gallegos, Ida (Sarawak Shell Berhad) | Rosenquist, M. (Shell International Exploration and Production) | Ghaffar, Kamal A. Abd. (PETRONAS Management Unit) | Wong, H.F. (PETRONAS Management Unit)
SeaBed LoggingTM (SBL), a technique that utilises Controlled-Sourced Electromagnetic (CSEM) fields to probe subsurface resistivity, has been applied in Malaysia to decrease the critical risk of having blown traps in thrusted anticlines. Integration of this technology with pre-drill prospect evaluation techniques has successfully de-risked the recent Alpha* discovery. Besides helping to add material reserves, this technology continues to de-risk nearby prospects and improves Shell’s drilling successes in the basin.
Mass density, due to its linear relationship with porosity, has long been recognized as a potential seismic indicator of fluid saturation. Given its dependence on mineral composition density can also be diagnostic for lithology. In this paper we discuss some key aspects of a wide-angle processing and density inversion workflow, and apply it to a heavy-oil reservoir. In this field intra-reservoir shales typically have higher densities than surrounding reservoir sands. This wide-angle workflow yields stable density estimates, from reflected P waves alone, at a resolution suitable for mapping the intra-reservoir shales.
Our field test indicates that data from an additional 15°–20° of reflection-angle aperture, beyond the conventional 40° far-angle limit, act as an effective constraint on the inversion density solution. However, these wide (60°) reflection angles cannot be successfully processed and inverted with conventional workflows. Some of the key wide-angle considerations include anisotropic prestack imaging, a wavelet stretch correction and regularization of the inversion solution based on appropriate statistical constraints.
Anisotropic imaging is required to position reflections from beyond 40° consistent with their corresponding small-angle image time. However, imaging introduces about 50% wavelet stretch in a 60° angle stack. A subsequent wavelet-stretch deconvolution reduced the stretch to about 13% (equivalent to stretch at 30°) in this test. These stretch-corrected angle gathers form the input data for a constrained linear prestack inversion. The constraining term characterizes statistical correlations between elastic properties measured in wellbores local to the field. This improves scaling and continuity of the density amplitudes, over and above the stability achieved by inverting wide-angle data.
We present a technique for the correction of the spread-length bias in the Common-Reflection-Surface stack. Based on the assumption of a linear relationship between spread-length bias and search aperture the attributes and traveltimes are extrapolated to zero aperture and thus to their correct values. The method is related to multiple coherence analyses with different search apertures. The resulting stack and attribute sections form new pseudo pre-stack data volumes which are used for the estimation of the extrapolation operators. For a synthetic data example we show that these corrections are able to significantly improve the results of subsequent applications based on traveltimes and attributes.
The method proposed and implemented in (Pozdniakov et al. (1998)) for imaging scatterers/diffractors in 2D situations modified for 3D heterogeneous media and is applied for mapping of 3D cracked areas, decompression areas and so on within consolidated granitoid subsurface block. This block is chosen as one of the possible sites for subsurface nuclear waste deposit. The approach bases on the use of asymmetric samples from multi offset data in order to avoid regular reflections and to concentrate on scattered/diffracted waves. This is possible because of the almost circular dispersion index for scattering via small intrusions. In the paper results of real data processing are presented.
Next, this approach is applied in order introduce new seismic attribute — intensity of scattered waves. It was computed for some real oil field (Nepsko-Botoubinskoe) in East Siberia region. Regression analysis is performed in order to justify reliability of this seismic attribute as predication factor for estimation of collector capacity.
The degree of geometry matching between 4D base and monitor surveys is commonly considered to be a predictor of the repeatability of the processed image. During survey planning, we can use simulations of monitor source and receiver locations to compute a quantitative measure of geometric repeatability for alternative acquisition approaches. Based on the simulated values of geometric repeatability, empirical predictions of image repeatability can aid in deciding which acquisition approach to use. During monitor survey acquisition, we can apply this process to the actual monitor geometry to evaluate infill opportunities. This paper demonstrates this procedure using a recent deepwater 4D survey.
Controlled Source Electro-Magnetic imaging (CSEM) is a recently developed technology that maps subsurface resistivity variations (Eidesmo et al., 2002). It uses a horizontal electrical dipole (HED) which emits a low frequency electromagnetic (EM) signal into the underlying seabed and downwards. As the upper sediments are effectively partial conductors, the penetration of EM fields is limited by the so-called skin-depth. In practice this means that the technique requires a low frequency EM source, typically between 0.25 – 10 Hz, to allow penetration to about 2500-3000m into the subsurface. At low frequencies, Maxwell’s equations for the electric field component reduce effectively to a diffusion process leading to strong dispersion.
Qian, Zhongping (Enru Liu Edinburgh Anisotropy Project, British Geological Survey) | Li, Xiang-Yang (Enru Liu Edinburgh Anisotropy Project, British Geological Survey) | Wang, Shoudong (ECNPC Geophysical Key Lab, University of Petroleum, Beijing, China)
Here, we present a case study of fracture detection using 3D P-wave seismic data from the Sichuan Basin in Southwest China. A major aspect of this study is the integration of outcrop, core and wireline logs with seismic data for reducing the uncertainties in the seismic results. To guide seismic data analysis, a physical modeling study is also carried out to compare the use of different P-wave seismic attributes and different analysis techniques. The target is a gas reservoir buried at about 1700m depth, and the reservoir rocks are tight sandstones with an average porosity of only about 2%. Fractures are the main fluid pathways. Analysis of core and log data from 21 boreholes reveals that there are two major sets of fractures in the study area striking northeast and northwest, respectively, with an average linear fracture density of about one fracture every two meters. We have processed and analyzed 50km2 of 3D P-wave seismic data in order to evaluate the fracture characteristics between the boreholes. The seismic data is of average quality. Nevertheless with carefully-calibrated processing, the final fracture orientation and intensity maps estimated from the amplitude attributes compare reasonably well with the regional pattern in the area, and the seismic results at the well locations are consistent with the borehole results. The physical modeling study provides a good benchmark for the selected seismic attributes.
In frontier areas of exploration far removed from well control, the phase of seismic data is often in question. Nevertheless, it is still desirable to rapidly indicate and classify the anomalous amplitude variations with offset (AVO) that might be present, in a manner that is independent of the phase. This paper introduces three such AVO “product” indicators: AΔB*, B*ΔA and(AB*), where A and B are the analytic AVO intercept and gradient, and “Δ ” represents the error in predicting one of these from the other. Each of these indicators is phase independent, has zero mean and is sensitive to different classes of anomalies. These classes can be compared with those which are expected based on regional compaction curves for different lithologies and fluids. After a discovery of hydrocarbons is made, the product indicators may be calibrated with known reservoir properties to estimate hydrocarbon volumes, and to assist in the planning of field development.
Measuring the background response
Unless the prestack seismic data is meticulously calibrated against prestack synthetics from abundant well control, it is difficult or impossible to determine AVO in an absolute sense. Usually the best we can do is classify AVO relative to the “background” seismic response; i.e., the AVO of the majority of reflectors. For this reason, the following alternate descriptions of the Castagna et al. (1998) AVO classifications might be useful:
1: A relatively hard zone whose amplitude initially decreases more rapidly than background, but later increases at very high angles.
2: A zone having a similar acoustic impedance to its encasing strata, having a weak near-angle response, but whose reflection magnitude greatly increases with angle. Sometimes, a polarity reversal can be seen.
3: A relatively soft zone whose reflection magnitude increases with angle.
4: A relatively soft zone whose reflection magnitude either stays the same or decreases in magnitude less rapidly than background The background response is found by correlating the analytic intercept and gradient traces over a sliding window in space and time, usually centered around each analysis point. Within such a window, the joint L2 statistics between intercept and gradient become σa2= <|A|2> , σa2= <|B|2> and correlation coefficient r =
Lp background statistics
L2 background statistics, while easy to understand and to compute, are often fooled by a minority population of strong seismic events within the background window. To make the statistics more robust to such events, L p statistics can be used, where 0 < p ≤ 2.
The phase-independent product indicators provide a convenient way to screen prestack seismic data for AVO anomalies (defined as any departure from background behavior) and to classify them. The procedure adapts to slowly varying changing in overburden and can compensate for systematic AVO induced by the processing. Because of its phase independence, the indicators cannot distinguish the top of a reservoir from its base.
Estimation of near-borehole formation compressional slowness is of significant value for petrophysical and geomechanical applications. Probing the near-borehole (shallow) formation and measuring the radial variation of slowness near-borehole can help identify damaged or altered zones, which is valuable information for wellbore stability and optimal well completion. To obtain the properties of the nonaltered zone, it is necessary to probe the formation as deeply as possible, which requires using an acoustic tool with a sufficiently long source-to-receiver (TR) spacing and a large array aperture.
A recently developed sonic tool implements these characteristics and hence meets these objectives (i.e., probing shallow and deep). In addition to these hardware enhancements, a robust and automatic inversion scheme that provides a two-dimensional(2D) image of the formation compressional slowness near-borehole has been developed. This technique is based on the inversion of transit times estimated from the waveform recorded by the tool.
This inversion scheme is based on an analytical approach, making the implementation of the algorithm fast, robust, and suitable for the wellsite environment. In this paper, we demonstrate how the theoretical improvements, summarized here, enable presentation of a robust and reliable 2D image of the formation compressional slowness variation in the near borehole in real time and with minimal user interaction. A real field data example will be presented and discussed to illustrate this new profiling technique.
Kaldy, W. John (BP America Inc.) | Hartman, Ken (BP America Inc.) | Sen, Pranab (BP America Inc.) | Barousse, Chuck (BP America Inc.) | Stauber, Doug (BP America Inc.) | Xu, Ellen (Xiaoxia) (BP Summer Intern)
This study was performed to determine if a 4D monitor survey could be acquired using shorter cables than were used for the baseline survey without significantly degrading the seismic response to reservoir changes. If so, this could reduce acquisition and processing costs, improve acquisition repeatability and reduce cycle time. We chose an existing monitor survey possessing high signal to noise ratio and clear 4D response to test this idea. Study results indicate that a 4D response can clearly be seen on the short cable data; however it is more difficult to interpret because events are less continuous, and the long offset amplitude contributions have been removed. Another consideration is that intercept and gradient volumes will be of poor quality and will not be of use in examining the seismic response.