Visual estimation of wavelet phase

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One of the most important questions an interpreter should ask when first viewing a seismic image is “what is the phase of these data?” The answer to this question, which refers to the phase of the source wavelet in the processed data, is critical to interpretation because it relates seismic response to geology. Fundamentally the response to a given subsurface boundary across which there is an acoustic impedance contrast varies for different source wavelets.

In the ideal case the source wavelet for a given data set is determined using wavelet extraction techniques; however, there are many situations in which an interpreter must estimate wavelet phase “on the fly” because there is neither the time nor the software for doing a complete and accurate wavelet extraction. At these times an interpreter must make a visual estimate of wavelet phase using a few simple but certainly not absolute or foolproof criteria.

Before making a visual estimate of wavelet phase, an interpreter must know the polarity convention used in display of his data. These conventions or “standards” are not global and vary among different user communities, countries and continents. If not described beforehand, an interpreter should never hesitate to ask about the display convention being used for data he’s viewing for the first time. Following is the SEG polarity standard as defined in the SEG Dictionary of Applied Geophysics (4th ed., 2002):

This convention is also known as positive standard polarity, and its reverse is called negative standard polarity.

The most important step in visually estimating wavelet phase is to select a reflection which can be confidently identified as the seismic response to a subsurface boundary across which there is a well-known and consistent acoustic impedance contrast. Equally important is to ensure that this boundary is sharp (step-like) and isolated, that is, there is no interference in its reflection response from the responses to over- or underlying reflectors (this depends on the distance to the adjacent reflectors and the resolving power of the seismic wavelet). The following table from Herron (2011) lists boundaries which can satisfy these two conditions, some being more reliable (“best”) than others (“use with care”):

Many interpreters who work regularly with marine seismic data use the seafloor reflection as an indicator of wavelet phase because the acoustic impedance contrast between seawater and sediment is almost always positive and the seawater/sediment boundary is well-defined and isolated. The significance of using a seismic “flat spot” is that the acoustic impedance contrast between hydrocarbon- and brine-saturated rocks is almost always positive. The importance of “flat” in “flat spot,” within the larger context of “bright spots” and “direct hydrocarbon indicators (DHIs),” is that this flatness allows an interpreter to conclude that the thickness of the hydrocarbon accumulation where the “flat spot” is observed is above tuning, that is, the hydrocarbon-saturated portion of the reservoir is seismically resolved (the response at the upper seal-to-hydrocarbon-saturated reservoir boundary is separate from the response at the lower hydrocarbon-saturated to brine-saturated reservoir boundary). This satisfies the condition that the “flat spot” reflection is isolated and can be used for visual estimation of wavelet phase.

Figure 1 shows a pronounced “flat spot” on a seismic line from the Gulf of Mexico displayed with the SEG positive standard polarity convention (Herron, 2011). This image uses a variable-density trace format which is suitable for estimating wavelet phase but not necessarily the format of choice for everyone; some interpreters prefer to view data with a wiggle trace overlay on a variable-density display or a variable area-wiggle display because these formats more clearly show the curvilinear shape of individual traces (Figure 2 illustrates the four most common trace display formats). The “flat spot” is a high-amplitude symmetric peak, and based on this observation an interpreter can reasonably infer that the data are approximately zero-phase. Independent well-to-seismic ties confirm that this “flat spot” correlates to the hydrocarbon/water contact in an established producing reservoir. Notice that as the hydrocarbon-bearing interval above the “flat spot” thins to the right the seismic responses from the top (trough) and base (peak) of this interval interfere, giving rise to a “trough-over-peak” reflection. Some interpreters cautiously use this trough-over-peak signature, with prior knowledge or assumption of rock properties, to directly identify thin pay sands which are at or below seismic resolution. Two examples of this trough-over-peak signature are visible in the upper left quadrant of Figure 1.

The problem with using boundaries such as top and/or base of salt, top of volcanics and basement (which can take on a variety of geologic and economic meanings) for estimating wavelet phase is that these boundaries often may be gradational and not sharply defined, so their seismic responses are effectively composite responses to multiple, closely-spaced impedance contrasts rather than to a single, well-known impedance contrast. At the same time, the impedance properties of the materials above and below these boundaries, especially for basement, are not necessarily well known or regionally consistent, and so neither the magnitude nor the sign of the impedance contrast across such boundaries can be inferred confidently without well control. Finally, reflections such as the base of salt or basement most often are observed at considerable depth on a seismic section, and so their character is more likely to be suspect in terms of image fidelity (more so reflection focusing rather than positioning).