Geological Factors Can Lead to Poor Matches

Contributors: Satinder Chopra

The traditional tool interpreters have used to establish correspondences between subsurface stratigraphy and surface-measured seismic data has been synthetic seismograms calculated from well log data.

In some instances, however, it is difficult to create an optimal-quality match between a synthetic seismogram and seismic data.

We consider here possible geological reasons why poor matches sometimes occur – particularly in stratigraphic intervals where rock properties change laterally.


Consider the stratigraphic condition diagrammed on figure 1. Here a well penetrates a sand body that has a lateral dimension less than that of the dominant wavelength λ of an illuminating seismic wavefield.

Because sonic and density log data acquired in the well indicate a change in acoustic impedance at the top and base of the sand unit (interfaces A and B), a synthetic seismogram calculation using these logs will create a seismic reflection at the top and base of the sand.

However, surface seismic data will not show such reflection events, because the lateral dimension of the sand body is too small to create a reflected wavefront. For a seismic wavefield having a dominant wavelength λ, the sand body along this particular profile is a point diffractor, not a reflector.

You may see a diffraction in unmigrated seismic data, but after the data are migrated the sand body probably would appear as only a mild amplitude variation on one or two data traces – and would be ignored by an interpreter.

The principle illustrated by this example is that a synthetic seismogram will imply a reflection should be at the depth of the sand body, but migrated seismic data would not. This difference exists, even though the log data are correct and the synthetic seismogram calculation is accurate, because log data measure rock properties within only a meter or so of a wellbore.

In contrast, a seismic wavefield averages rock properties over an appreciable area having a diameter of the order of its dominant wavelength λ.


The reverse of this situation also can occur – that is, a synthetic seismogram can indicate no reflection is present at a depth where surface seismic data show a bold reflection.

A stratigraphic condition that could create such a discrepancy is illustrated on figure 2; here a well passes through a gap having a dimension of the order of λ between two laterally extensive sands.

Because log data acquired in the well indicate no impedance changes over the depth interval local to the sand bodies, a synthetic seismogram calculation will produce no reflection event. However, both migrated and unmigrated seismic data will show a reasonably continuous reflection event across the well position, with perhaps a slight amplitude anomaly at the well coordinate.

Again, the log data are correct, the synthetic seismogram calculation is correct and the seismic data are correct – yet the synthetic seismogram and the seismic data do not agree.

The difference is caused by the fact that log data measure geological properties over a distance of one meter or less, but seismic data respond to geological properties over a distance of several tens of meters.

If one-meter geology is significantly different from 50-meter and 100-meter geology, there often will be mismatches between synthetic seismograms and seismic reflection data.

Comments (0)

 

Geophysical Corner

The Geophysical Corner is a regular column in the EXPLORER that features geophysical case studies, techniques and application to the petroleum industry.

VIEW COLUMN ARCHIVES

Image Gallery

See Also: Book

Desktop /Portals/0/images/_site/AAPG-newlogo-vertical-morepadding.jpg?width=50&h=50&mode=crop&anchor=middlecenter&quality=90amp;encoder=freeimage&progressive=true 4380 Book

See Also: Bulletin Article

The geometries of clay smears produced in a series of direct shear experiments on composite blocks containing a clay-rich seal layer sandwiched between sandstone reservoir layers have been analyzed in detail. The geometries of the evolving shear zones and volume clay distributions are related back to the monitored hydraulic response, the deformation conditions, and the clay content and strength of the seal rock. The laboratory experiments were conducted under 4 to 24 MPa (580–3481 psi) fault normal effective stress, equivalent to burial depths spanning from less than approximately 0.8 to 4.2 km (0.5 to 2.6 mi) in a sedimentary basin. The sheared blocks were imaged using medical-type x-ray computed tomography (CT) imaging validated with optical photography of sawn blocks. The interpretation of CT scans was used to construct digital geomodels of clay smears and surrounding volumes from which quantitative information was obtained. The distribution patterns and thickness variations of the clay smears were found to vary considerably according to the level of stress applied during shear and to the brittleness of the seal layer. The stiffest seal layers with the lowest clay percentage formed the most segmented clay smears. Segmentation does not necessarily indicate that the fault seal was breached because wear products may maintain the seal between the individual smear segments as they form. In experiments with the seal layer formed of softer clays, a more uniform smear thickness is observed, but the average thickness of the clay smear tends to be lower than in stiffer clays. Fault drag and tapering of the seal layer are limited to a region close to the fault cutoffs. Therefore, the comparative decrease of sealing potential away from the cutoff zones differs from predictions of clay smear potential type models. Instead of showing a power-law decrease away from the cutoffs toward the midpoint of the shear zone, the clay smear thickness is either uniform, segmented, or undulating, reflecting the accumulated effects of kinematic processes other than drag. Increased normal stress improved fault sealing in the experiments mainly by increasing fault zone thickness, which led to more clay involvement in the fault zone per unit of source layer thickness. The average clay fraction of the fault zone conforms to the prediction of the shale gouge ratio (SGR) model because clay volume is essentially preserved during the deformation process. However, the hydraulic seal performance does not correlate to the clay fraction or SGR but does increase as the net clay volume in the fault zone increases. We introduce a scaled form of SGR called SSGR to account for increased clay involvement in the fault zone caused by higher stress and variable obliquity of the seal layer to the fault zone. The scaled SGR gives an improved correlation to seal performance in our samples compared to the other algorithms.
Desktop /Portals/0/PackFlashItemImages/WebReady/Three-dimensional-structure-of-experimentally-produced.jpg?width=50&h=50&mode=crop&anchor=middlecenter&quality=90amp;encoder=freeimage&progressive=true 3722 Bulletin Article

Umiat field in northern Alaska is a shallow, light-oil accumulation with an estimated original oil in place of more than 1.5 billion bbl and 99 bcf associated gas. The field, discovered in 1946, was never considered viable because it is shallow, in permafrost, and far from any infrastructure. Modern drilling and production techniques now make Umiat a more attractive target if the behavior of a rock, ice, and light oil system at low pressure can be understood and simulated.

The Umiat reservoir consists of shoreface and deltaic sandstones of the Cretaceous Nanushuk Formation deformed by a thrust-related anticline. Depositional environment imparts a strong vertical and horizontal permeability anisotropy to the reservoir that may be further complicated by diagenesis and open natural fractures.

Experimental and theoretical studies indicate that there is a significant reduction in the relative permeability of oil in the presence of ice, with a maximum reduction when connate water is fresh and less reduction when water is saline. A representative Umiat oil sample was reconstituted by comparing the composition of a severely weathered Umiat fluid to a theoretical Umiat fluid composition derived using the Pedersen method. This sample was then used to determine fluid properties at reservoir conditions such as bubble point pressure, viscosity, and density.

These geologic and engineering data were integrated into a simulation model that indicate recoveries of 12%–15% can be achieved over a 50-yr production period using cold gas injection from five well pads with a wagon-wheel configuration of multilateral wells.

Desktop /Portals/0/PackFlashItemImages/WebReady/Integrated-reservoir-characterization-and-simulation-of.jpg?width=50&h=50&mode=crop&anchor=middlecenter&quality=90amp;encoder=freeimage&progressive=true 7968 Bulletin Article

See Also: CD DVD

Desktop /Portals/0/images/_site/AAPG-newlogo-vertical-morepadding.jpg?width=50&h=50&mode=crop&anchor=middlecenter&quality=90amp;encoder=freeimage&progressive=true 4573 CD-DVD

A collection of fifteen papers originally published by the American Association of Petroleum Geologists, Gulf Coast Section-Society for Sedimentary Geology (GCS-SEPM), Marine and Petroleum Geology (Elsevier), Tectonophysics (Elsevier), Gulf Coast Association of Geological Societies (GCAGS), American Geophysical Union, and The Geological Society of London.

Desktop /Portals/0/PackFlashItemImages/WebReady/CD-GS6-Salt-Tectonics-A-Compendium-of-Influential-Papers.jpg?width=50&h=50&mode=crop&anchor=middlecenter&quality=90amp;encoder=freeimage&progressive=true 3478 CD-DVD