Reservoir Description From Seismic Lithologic Parameter Estimation
Authors: de Buyl M. , Guidish T. , Bell F. 
Published: December 2007

Modern three-dimensional (3D) seismic data assist not only in delineating reservoir geometry, but also in predicting porosity and lithology variations away from well control. This case study of and oil-producing channel sand in the Taber/Turin area, Alta., Canada illustrates the improvement in reservoir characterization achieved with an integrated approach incorporating both well and seismic information.

Introduction

Two independent reservoir models were constructed for an oil-bearing channel-sand reservoir in the Taber/Turin area, Alta. The first reservoir description was based on log and core data from six producing and two dry wells drilled within a portion of the field producing and two dry wells drilled within a portion of the field on which a 3D seismic survey was acquired. The second reservoir model was supplemented by petrophysical parameters derived from the seismic lithologic modeling (SLIM) of the 3D seismic reflection data. This new forward SLIM technique can unravel the wavelet interference effects of closely spaced reflectors and allow reliable estimates of reservoir parameters for thin intervals. In this study, detailed geologic model of the reservoir, enhanced by the results of the lithologic modeling technique, is constructed from a synergistic approach. This model depicts subtle structural and stratigraphic features that cannot be mapped from the available well data alone. Structural maps of the top of the reservoir and maps of the petrophysical parameters of the producing interval were developed. petrophysical parameters of the producing interval were developed. These include thickness, interval velocity, porosity, and porosity/thickness maps. porosity/thickness maps. The increased accuracy in predicting reservoir variation attained by incorporating seismic control is demonstrated by comparison of the projections of respective model parameters at two new well locations that were not included in the modeling.

Background

Historically, reservoir descriptions have been based primarily on well data interpretation to derive geologic structural models and maps of such reservoir parameters as thickness, porosity, and permeability. The contribution of seismic data in building reservoir permeability. The contribution of seismic data in building reservoir models is generally limited to structural mapping of faults and of a seismic marker near the reservoir, while petrophysical properties derived from well log and core data are smoothly interpolated properties derived from well log and core data are smoothly interpolated between well locations. Continuous information about reservoir parameter variations, however, can be inferred from the seismic data processed with a variety of velocity modeling techniques. A lithologic modeling approach was implemented on a 3D seismic data set acquired from an oil field in the Taber/Turin area to map the extent of the discontinuous reservoir sand. From that data set and available well control, a detailed interpretation of the geologic model, including structural, stratigraphic, and petrophysical parameters of the thin producing reservoir was developed. The integrated model derived producing reservoir was developed. The integrated model derived from combining the 3D seismic survey with well depth provides a degree of detail that cannot be attained from well data alone. Moreover, this synergistic approach exposes potential discrepancies between various sources of information or in assumptions made during the data interpretation process. The benefit of the integrated methodology is to produce a model that is compatible with all the data and hence is more reliable. This study includes a discussion of the method used to construct the seismically controlled reservoir model, an analysis of its reliability, and a comparison of the results with a reservoir model based solely on the well data available within the seismic survey area. Before acquisition of the 3D survey, four producing and two dry wells had been drilled. Because of the irregular distribution of the reservoir sand, which is attributed to its fluvial environment of deposition, it is difficult to identify the optimum locations for development drilling. The general stratigraphy of the area is shown in Fig. 1. A detailed discussion of the stratigraphy is found in Refs. 2 and 3. The oil-producing glauconitic sand complex belongs to the Upper Mannville formation. This reservoir lies approximately 980 m [3,215 ft] below the surface and is 15 to 30 m [50 to 100 ft] thick in the producing area. The reservoir interval exhibits lower interval velocities than the overlying siltstone, providing the acoustic contrast that reflects seismic energy. Where the sand pinches out or loses its porosity, the interval velocity increases and even exceeds that of the overlying siltstone in the nonproducing area of the survey. This results in a lateral change in the polarity of the seismic reflection marking the top of the glauconitic formation, from a peak in the producing area to a trough in the nonproducing area. Below the glauconitic formation lies the Lower Mannville ostracod zone that caps the Taber sand infilling the paleotopography carved by the Mississippian unconformity. Locally, the glauconitic sand truncates the ostracod zone, allowing communication with the underlying aquiferous Taber sand. This provides the waterdrive in this stratigraphically controlled oil field. The 3D seismic survey covers a 4 × 10(3) m [1-acre] area. The survey was acquired with a vibroseis source generating 16 downsweeps from 80 to 14 Hz [80 to 14 cycles/sec]. The 12- to 16-fold data were generated with 40-m [130-ft] source-to-receiver spacing that resulted in 88 east/west in-lines with 20-m [65-ft] subsurface coverage. In the north/south direction, 111 cross lines at 20-m [65-ft] intervals were processed. In addition to normal moveout and static corrections, the data were wavelet-deconvolved and migrated in 3D to preserve true amplitudes. Fig. 2 is a base map of the 3D survey showing the locations of the producing wells (Wells C through H) and the two dry wells (Wells A and B), as well as the position and a sample seismic traverse cut through the 3D data cube. Wells G and H were drilled after the 3D survey. The latest producing wells (Wells I and J) were drilled during the course of this study and their data became available only after it was completed. These two new wells are used to test the accuracy of the two separate reservoir description methods by comparing the ability of both approaches to predict various parameters of the reservoir model at the two new locations. parameters of the reservoir model at the two new locations. JPT

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