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The AAPG/Datapages Combined Publications Database

AAPG Special Volumes


Chapter from: SG 42:  Applications of 3-D Seismic Data to Exploration and Production

Edited by: 
Paul Weimer and Thomas L. David

Bob A. Hardage, Raymond A. Levey, Previous HitVirginiaNext Hit Previous HitPendletonNext Hit, James Simmons, and Rick Edson


Published 1996 as part of Studies in Geology 42
Copyright © 1996 The American Association of Petroleum Geologists.  All Rights Reserved.

*Editorial Note: Page numbers in this digital version (HTML and PDF) do not correspond to those of the hardcopy.
Otherwise, the two are the same.


Chapter 3: 3-D Seismic Imaging and Interpretation of Fluvially Deposited Thin-Bed Reservoirs

Bob A. Hardage*, Raymond A. Levey*, Previous HitVirginiaNext Hit Previous HitPendletonNext HitÝ, James Simmons*, and Rick Edson*


Hardage, B. A., R. A. Levey, V. Previous HitPendletonTop, J. Simmons, and R. Edson, 3-D seismic imaging and interpretation of fluvially deposited thin-bed reservoirs, in P. Weimer and T. L. Davis, eds., AAPG Studies in Geology No. 42 and SEG Geophysical Developments Series No. 5, AAPG/SEG, Tulsa, p. 27-34.

old as 40 years, existed inside this 3-D grid, and the logs recorded in these wells allowed us to make a reasonably thorough geologic analysis of the Frio reservoirs. As shown in Figure 2, we acquired additional data in several wells (the circled dots) to supplement the historic well log, production, and reservoir pressure data bases. These supplemental data consisted of modern well logs, cores, and various pressure tests. Vertical seismic profile (VSP) data were recorded in the well inside the triangle shown near the center of the 3-D grid.


The emphasis in this case study was on demonstrating how geologic and engineering data are essential in interpreting depositionally generated reservoir compartment boundaries in 3-D seismic images. The seismic interpretation at Stratton Field was particularly challenging, because most of the Frio reservoirs were thin (<15 ft [<5 m]), and they were closely stacked, in some areas separated by only 10-15 ft (3-5 m) vertically. These conditions required precise calibration of stratigraphic depth versus seismic traveltime to extract a depositional stratal surface from the 3-D data volume that would reliably depict the areal distribution of a particular Frio thin-bed reservoir.

We used VSP data as the primary measurement to define where a specific thin-bed reservoir was positioned in the 3-D seismic data volume. The locations of the VSP calibration well we used is shown in Figure 2. The zero-offset VSP data recorded in this well were used to establish the precise depth-versus-time control needed for the thin-bed interpretation. These VSP data are shown in Figure 3, where the zero-offset image is spliced into a north-south vertical slice from the 3-D data volume passing through the VSP well. The VSP image has a wider range of frequency components (10-120 Hz) than does the 3-D seismic image (10-80 Hz), and we made no attempt to equalize the spectral bandwidths of these two images when constructing Figure 3. The figure also shows a graphic representation of the stratigraphic column penetrated by the VSP well. Only producing or potentially producing Frio reservoirs are shown in this diagram, and not all of the reservoirs are labeled by name. The top and base of each reservoir are accurately positioned in terms of two-way VSP traveltime, and because there is no difference between the VSP time datum and the 3-D time datum in this instance, the reservoirs are also correctly positioned vertically inside the 3-D seismic data volume at the VSP well.

Using these VSP traveltime control data, we knew exactly where each thin-bed reservoir belonged in the 3-D seismic reflection waveform at the VSP well. We then extended this thin-bed calibration away from the VSP well and across the entire 7.6-mi2 (19.7-km2) area imaged by the 3-D data.

We now show the results of this thin-bed interpretational procedure at Stratton Field and support the interpretations with geologic and engineering control.


We investigated the following problem: "How do fluvial depositional processes create compartmented gas reservoirs?" Using vertical seismic profile (VSP) data to define where selected thin-bed gas reservoirs were positioned in a 3-D seismic data volume, we created horizon slices through this 3-D image that showed the reflection amplitude behavior across the depositional surfaces where targeted thin-bed reservoirs were located. We saw intriguing meander features on these 3-D amplitude displays, which appeared to be realistic depictions of intermeshed fluvial channels. We then overlaid well-log cross sections on these 3-D seismic images, which inferred the depositional environments that were found by wells that penetrated the reservoir system, and these geologic constraints confirmed that the imaged meander features were indeed channels.

The most important nonseismic data that we used to understand how 3-D seismic images can reveal reservoir compartment boundaries were various forms of reservoir engineering data that proved which wells shared a common pressure compartment and which wells did not. Using these engineering constraints, we showed that many of the seismically imaged channel features created reservoir compartment boundaries that impeded lateral fluid flow. Equally important, we showed that some seismically imaged channels had minimal effect on lateral flow and did not form compartment boundaries. We concluded that in any effort where 3-D seismic data are used to infer the internal compartmentalized architecture of a reservoir system, good quality reservoir engineering control, such as pressure interference tests and pressure decline curves, must be incorporated into the 3-D interpretation.

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