Better Resolution Or Coincidence?

Many attempts have been made throughout the history of modern seismic to image thin beds (<1/4 of dominant wavelength) by extracting higher frequencies from seismic. In addition to simply imaging zones below normal resolution, two of the more common goals to aid in reservoir development are:

  • To define pinch-outs of producing zones.
  • To resolve internal bed geometries.

Techniques to enhance seismic frequencies are critical to achieve optimum thin bed resolution.

The most common post-stack method is spectral whitening or boosting the amplitudes of all frequencies within a certain bandpass to the same level. The problem with this method is that it does not discriminate noise from signal. Noise is boosted along with the subsurface signal and, depending on the signal-to-noise ratio (SNR), whitening may fail to extract the very information we hope to resolve.

Other techniques such as coherence cube technology and seismic inversion also can help define some of the thin bed properties we seek through a different approach but can still be limited by the inherent bandwidth of standard seismic.

This column focuses on application of a method that attempts to separate the signal from the noise while enhancing only the high frequency "earth signal" -- a technique that helped identify new well locations in thinly bedded reservoirs that would not have otherwise been drilled.

More importantly, it helped to nearly quadruple daily production rates and add significant new reserves to a 27-year-old Gulf of Mexico field.


The example used here comes from South Marsh Island Block 128 Field (Figure 1). The discovery well for this prolific field was drilled in June 1974. The field is a stratigraphically complex, salt cored NW-SE trending anticline bounded on the west by a large down-to-the-west fault.

Reservoir age ranges from Angulogerina B (Early Pliestocene) to Lenticulina 1 (Late Pliocene) at depths of 4,500 to 9,000 feet subsea. Paleobathymetry ranges from inner neritic at the shallower levels to upper bathyl in the deeper zones, with all reservoirs being normally pressured.

The field has seven exploratory wells and 93 development wells, including sidetracks, drilled from four offshore platforms. In January 2000, cumulative production was 115 MMBO and 203 BCF, and average daily production rates were 3,500 BO and 4 MMCF.

Structural interpretation there had been difficult from the outset with various interpreters producing different structural pictures (the lack of seismically mapped faulting was the variable in the interpretations). Even with the acquisition of proprietary, first generation 3-D seismic in 1989, the uncertainties persisted.

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Many attempts have been made throughout the history of modern seismic to image thin beds (<1/4 of dominant wavelength) by extracting higher frequencies from seismic. In addition to simply imaging zones below normal resolution, two of the more common goals to aid in reservoir development are:

  • To define pinch-outs of producing zones.
  • To resolve internal bed geometries.

Techniques to enhance seismic frequencies are critical to achieve optimum thin bed resolution.

The most common post-stack method is spectral whitening or boosting the amplitudes of all frequencies within a certain bandpass to the same level. The problem with this method is that it does not discriminate noise from signal. Noise is boosted along with the subsurface signal and, depending on the signal-to-noise ratio (SNR), whitening may fail to extract the very information we hope to resolve.

Other techniques such as coherence cube technology and seismic inversion also can help define some of the thin bed properties we seek through a different approach but can still be limited by the inherent bandwidth of standard seismic.

This column focuses on application of a method that attempts to separate the signal from the noise while enhancing only the high frequency "earth signal" -- a technique that helped identify new well locations in thinly bedded reservoirs that would not have otherwise been drilled.

More importantly, it helped to nearly quadruple daily production rates and add significant new reserves to a 27-year-old Gulf of Mexico field.


The example used here comes from South Marsh Island Block 128 Field (Figure 1). The discovery well for this prolific field was drilled in June 1974. The field is a stratigraphically complex, salt cored NW-SE trending anticline bounded on the west by a large down-to-the-west fault.

Reservoir age ranges from Angulogerina B (Early Pliestocene) to Lenticulina 1 (Late Pliocene) at depths of 4,500 to 9,000 feet subsea. Paleobathymetry ranges from inner neritic at the shallower levels to upper bathyl in the deeper zones, with all reservoirs being normally pressured.

The field has seven exploratory wells and 93 development wells, including sidetracks, drilled from four offshore platforms. In January 2000, cumulative production was 115 MMBO and 203 BCF, and average daily production rates were 3,500 BO and 4 MMCF.

Structural interpretation there had been difficult from the outset with various interpreters producing different structural pictures (the lack of seismically mapped faulting was the variable in the interpretations). Even with the acquisition of proprietary, first generation 3-D seismic in 1989, the uncertainties persisted.

The geoscientists working the field were aware of the stratigraphic variations between wells but were hard pressed to visualize this level of depositional complexity with the currently available seismic. Distinguishing between faulting and stratigraphic discontinuities was problematic at best, leading to complex fault patterns that were suspiciously "ungeologic."

Furthermore, many of the reservoir thicknesses were below standard seismic resolution -- thus impossible to map with much reliability.

A 1994 vintage speculative 3-D dataset was reprocessed in early 1998, employing target-oriented prestack Kirchoff time migration in an attempt to resolve some of these issues. Field acquisition employed a 4,000-meter streamer with 25-meter group and shot intervals, four millisecond sample rate and an eight second record length. A 15,000-foot migration aperture was selected to optimize imaging of dipping reflectors.

Overall imaging was greatly improved, leading to the conclusion that many of the discontinuities previously interpreted as faulting were in fact stratigraphic variation. Pressure data supported the fact that certain wells were in separate compartments, but this was still not clearly imaged in the 3-D seismic.

In hope of resolving these stratigraphic details, a post-stack frequency enhancement routine was applied to the reprocessed data. This technique employs a branch of mathematics originally developed in quantum mechanics for treating technically unsolvable systems (undetermined equations) in combination with the math evolved for the decoding of encrypted messages.

After all, this is essentially what the seismic trace is.


In the data set, two wells were selected as calibration wells. The selection criteria dictated that good quality logs of velocity and density data be available for synthetic seismogram generation.

Velocity survey information also was incorporated. The logs were carefully edited by experienced petrophysicists to compensate for washouts, cycle skipping and any other problems. The consequent reflectivity series were convolved with 50, 60, 75 and 80 hertz Ricker wavelets to produce synthetic seismograms. These served as calibration points and quality control for the seismic processing.

The synthetic traces were compared to the data to optimize parameters of the high frequency data volume. At frequencies approaching 120 hertz, non-geologic "artifacts" or events not correlative to the log-generated synthetic traces appeared in the data, so the data was filtered back to the point where these artifacts disappeared. The resultant high frequency data was integrated with well information to identify and evaluate new drilling targets.

Acoustic impedance inversion was also employed to support the results and, in some cases, was a determining factor for picking drillsites.

In June 2000, the partners initiated a multi-well drilling program to test some of the identified opportunities, including two wells drilled early in the field's development.

  • The B-6 was drilled in the field's southern portion in April 1976 and encountered 47 feet of net oil pay in two zones.
  • The B-9 was drilled 2,300 feet to the southwest of the B-6 in June 1976 and encountered 149 feet of net oil pay in four zones.

Both are directional platform wells drilled into generally east dipping strata with no water contacts encountered by either well in any pay zone.

For this article we concentrate on a reservoir referred to as the L-10 zone, a Lentic-1 age horizon.

The first generation interpretation (Figure 2) shows a geologist's subsurface log cross-section between the B-6 and B-9 wells connecting all of the L series sands (L-1 thru L-10). Note that the L-1 zone in the updip B-9 wellbore is interpreted as absent in the down dip B-6 wellbore. All other L series horizons (L-4, 6 and 10) are shown to be continuous except for variations in thickness and log character.

This correlation generally was accepted by the partners during the early stages of field development. However, after years of production, the bottom hole pressure (BHP) profiles show a divergent trend between these two zones (Figure 3), demonstrating that they could not be in communication with each other. Furthermore, the L-10 zone (-7021 SSTVD) in the B-9 well watered out in September 1991, after producing 2,083 MBO and 2,369 MMCF. The L-10 completion (-7587 SSTVD) in the B-6 well continued to produce until watering out in April 1994 after recovering 539 MBO and 690 MMCF.

How do we explain the fact that the updip well watered out before the down dip well? Clearly some type of stratigraphic separation exists, but can we define it with seismic data?


Before the application of the frequency enhancement technique, the standard frequency reprocessed version of the 1994 vintage speculative 3-D data (Figure 4) was used to study the accuracy of reservoir correlations. Figure 5 shows the location of an arbitrary seismic line from the 3-D volume as A-A'. It directly connects the B-6 and B-9 wells, showing their SP and resistivity log curves overlain on the data.

The red trough seismic event representing the L-10 is indicated by the arrows.

Note that the reflector is essentially continuous between the B-6 and B-9 wells. This leads to a revised cross-section (Figure 6) where the L-10 sandstone correlation from the B-6 well has shifted to a shallower sand in the B-9 well.

Maintaining the original nomenclature for the reservoirs, the L-4 and L-6 zones in the B-6 well are now shown as absent in the B-9 well. More importantly, the L-10 zone of interest ties to a continuous reflector that now connects it to what was previously identified as the L-1 in the B-9 well.

A revelation? Maybe -- but does other information verify this? Records indicate that there is a pressure difference of over 1,000 psi between these two zones, suggesting that they cannot be in the same reservoir.

Once again standard bandwidth seismic fails to resolve the correct correlation.

Remember, we want to image a zone that according to logs is on the order of 20-40 feet in gross thickness. Although our data quality is very good, we are limited by the inherent bandwidth of the data. The dominant frequency in the zone of interest is roughly 25 hertz with the high end imaging at 48 hertz. The interval velocity is 8,850 feet/second, making the dominant tuning thickness about 89 feet (1/4 wavelength) with the thinnest possible resolution at 47 feet.

We may expect to see a reflection at the top of the zone, but imaging the base is not achievable -- and, due to bandwidth limitations, not resolvable as a separate seismic event. The pay is not associated with a classic "bright spot," so an amplitude extraction does little to reveal any reservoir boundaries.

In addition, the 3-D seismic suggests that the separation is not fault-related. Yet pressure and production data confirm that we are dealing with two separate reservoirs. The separation must be stratigraphic.

It is now time to apply the high frequency version of the 3-D dataset to see if it can image what we know exists.


Figure 7 is the same A-A' arbitrary seismic line shown in Figure 4, except that the frequency enhancement technique has been applied. The dominant frequency is now 45 hertz, making the dominant tuning thickness roughly 49 feet. The upper end signal frequencies, however, extend to 80 hertz, allowing resolution of beds as thin as 27 feet.

The individual reservoir units now begin to tie discreet events on the seismic. The zone of interest is again indicated by the arrows. Note that the event that ties the L-10 zone in the B-6 well appears to have a break or termination before it reaches the B-9 well. It is interpreted as a stratigraphic pinch-out and explains the reservoir separation indicated by the pressure and production data. This prompts a reinterpretation of the geologic cross-section (Figure 8) that honors the break in correlation seen by the high frequency data.

This version exhibits more stratigraphic discontinuity than any previous interpretation. It also offers an interpretation that reconciles the pressure and production history and defines a new drilling target.

Is this coincidence or truly the product of higher seismic resolution?

Next month: More successes from the South Marsh Island Field as high frequency seismic targets development drillsites.