1. PITFALLS IN 3-D SEISMIC INTERPRETATION<br />Today’s geophysical workstations are splendid tools but they are only tools. Unfortunately too many interpreters are expecting to find the solution to their problem in the workstation! The skill remains the thoughtful geological interpretation of geophysical data. As a consultant, I am often in a position to review seismic interpretations by others. It gives me the opportunity to reflect on how geoscientists can improve interpretations and avoid pitfalls. All too often I am in contact with seismic interpreters who have misidentified a horizon, failed to understand the phase and polarity of their data, distorted the result with a poor use of color, used an inappropriate attribute, failed to recognize a significant data defect, or are still frightened by machine autotracking.<br />On one occasion I was invited to listen to a presentation on seismic attributes and my opinion was sought. We were shown a map of Attribute no. 1, then we were shown a map of Attribute no. 2, then we were shown a map of Attribute no. 3. At this point I interjected: quot;
What is the objective of this study and how do these maps relate to that objective?quot;
quot;
I am gathering all the evidence for the study of this reservoirquot;
was the response. We were then shown Attribute no. 4, Attribute no. 5, and Attribute no. 6.<br />I could not contain myself any longer: quot;
Could you please explain how you selected these particular attributes?quot;
quot;
Oh, they are all very important!quot;
Then the show continued with Attribute no. 7, Attribute no. 8, Attribute no. 9……..He was selecting attributes because they existed on his workstation. Sadly too many workstation users today are button pushers seeking the silver bullet rather than analytical thinkers using the workstation as a tool.<br />On another occasion I was shown some rather elaborate AVO and Converted Wave work, and the optimum drilling location for this sand was being determined on this basis. I then discovered that the sand was 5 meters thick at a depth of 5000 m. I did some quick calculations and determined that the sand thickness was about one fortieth of a wavelength! Experience dictates that a fortieth of a wavelength is never seismically visible. For Tertiary gas sands with large impedance contrasts, the Limit of Visibility can, at best, be one thirtieth of a wavelength! We cannot benefit from the more advanced techniques available today until some basic issues of seismic resolution have been well understood.<br />The precision of machine autotrackers is typically around one-quarter of a millisecond? In good data this precision represents geology and must be exploited. Thus autotrackers are indispensable tools of modern interpretation. Yet some interpreters are frightened of them feeling that the human must stay in direct control of the placement of the horizon. Others have not figured out how to parameterize the tracker in moderate quality data. Manual tracking is not only time consuming but it introduces imprecision that can obscure detailed geology. Derivatives of autotracked time maps, such as residual, dip and azimuth can yield vital structural detail not visible in any other way.<br />Data phase and polarity critically determine seismic character. Character is more important than amplitude in directly identifying hydrocarbons with seismic data. Figure 1 shows the four principal phase and polarity expressions (Zero Phase American polarity, Zero Phase European polarity, and ±900 phase) of a low impedance hydrocarbon sand. Two intermediate characters are also shown. Once data phase and polarity is determined, hydrocarbon character can be predicted, and this is of major importance in analyzing prospectivity in younger sediments. Regrettably I observe interpreters extracting amplitude and locating wells on the resultant map without regard for the detailed character on the vertical section.<br />Figure 1. Phase and Polarity Circle showing six of the possible seismic characters for a low impedance gas sand.<br />Character is also key in making an effective well tie and thus correctly identifying seismic horizons. Too many interpreters take a well top (measured in depth) and a velocity (to convert to time) and locate the horizon at that exact point on the seismic section. So why do interpreters not think more deeply about phase and polarity, and about tuning effects? I believe that every seismic interpreter, particularly with an objective beyond structure, has the responsibility to determine or verify the phase and polarity of his or her data. Many dry holes have been drilled by those who failed to do so!<br />The choice between horizon amplitude and windowed amplitude is another common pitfall. Windowed amplitude is more modern, but this doesn’t mean that we use it to the exclusion of horizon amplitude that has been available for 20 years. RMS (root mean square) amplitude seems to be the most popular type of windowed amplitude. This has splendid application for various reconnaissance endeavors. The squaring of the amplitude values within the window gives the high amplitudes maximum opportunity to stand out above the background contamination. RMS amplitude over a large flat or structured time window can be used to identify many small bright spots at different levels within a formation. Horizon amplitude, extracted along the high-precision autotrack, is preferable for studying a single reservoir. Most workstations use curve fitting to interpolate a high-precision amplitude value at the exact crest of the reflection.<br />Horizon amplitude suffers no contamination but requires that the horizon has been correctly identified and tracked. This also requires that phase and polarity have been properly understood so that the well tie can be correctly made using character. Horizon slices thus remain the best amplitude displays for selecting the optimum drilling location or measuring the area of a reservoir. We should make every effort to consider the amplitude on the top reflection and the amplitude on the base reflection.<br />Figure 2 shows two high amplitudes targeted by an exploratory well. This data is American polarity, so red-over-blue (trough-over-peak) is the character of low impedance prospective sand. The upper high amplitude has this character and has also high amplitude-over-background. Both amplitudes were originally drilling objectives but, on the basis of character, we can observe that the lower amplitude is blue-over-red indicating that it is a hard bed and thus most probably unprospective.<br />Figure 2. Two high amplitude reflection pairs targeted by the same well. Note the different characters.<br />Seismic data can contain defects caused by the acquisition and processing, and interpreters must attempt to understand these. Amplitude is full of geologic information, so amplitude must be preserved as thoroughly as possible in data processing. The presence of surface obstacles or the lack of access (no permit) causes reduced and variable seismic coverage. This tends to be the principal acquisition-induced problem facing interpreters of land surveys. Amplitude changes and pseudo-faults can both result from this type of defect. Figure 3 shows a high amplitude considered to be very prospective and the corresponding horizon slice on the top sand (red) reflection. The reduction in amplitude to the south had been interpreted as the limit of the hydrocarbon. In fact data disruption caused by reduced surface coverage is the reason for the reduction in amplitude. Compensating for this effect makes the prospect twice the previous size. <br />Figure 3. High amplitude prospective reflection pair affected by reduced surface coverage, and corresponding horizon slice.<br />3-D seismic data should be collected and processed in a regular manner. Irregularities in coverage can easily introduce effects that can be confused with geology. Today’s interpreter must appreciate the defects in his data and understand what effect they have on his interpretation.<br />Recommendations to help today’s interpreter get more geology out of 3-D seismic data in a reasonable period of time are outlined below. These will also help avoid common interpretation pitfalls. Seismic interpretation today involves a delicate balance between geophysics, geology and computer science. As interpreters we must be continuously learning to improve our understanding of geophysics, of geology and of the workstation.<br />Expect detailed subsurface information<br />Don’t rely on the workstation to find the answer<br />Use all the data<br />Understand the data and appreciate its defects<br />Use time (or depth) slices / horizontal sections<br />Visualize subsurface structure<br />Use machine autotracking and snapping<br />Select the color scheme with care<br />Question data phase and polarity<br />Tie seismic data to well data on character<br />Try to believe seismic amplitude<br />Understand the seismic attributes you use<br />Prefer horizon attributes to windowed attributes for detailed work<br />Use techniques that maximize signal-to-noise ratio<br />[The data examples are from Pemex in Mexico. I thank my colleagues there for the release of this data and for the discussions that led to the understanding of them.]<br />Dim Spots in Seismic Images as Hydrocarbon Indicators*<br /> <br />Alistair R. Brown1<br /> <br />Search and Discovery Article #40514 (2010)<br />Posted March 12, 2010<br /> <br />*Adapted from the Geophysical Corner column, prepared by the author, in AAPG Explorer, February, 2010, and entitled “Good News: A Dim Future Isn't Bad”. Editor of Geophysical Corner is Bob A. Hardage (bob.hardage@beg.utexas.edu). Managing Editor of AAPG Explorer is Vern Stefanic; Larry Nation is Communications Director.<br />General statement<br />Everyone has heard of a bright spot – a high seismic amplitude caused by hydrocarbon. Much oil and gas has been found by drilling anomalous bright reflections, particularly in younger sediments. But how many explorationists have found hydrocarbon with dim spots – a reduction in amplitude caused by hydrocarbon? When water in a porous rock is replaced by hydrocarbon, the acoustic impedance (the product of density and velocity) of the rock universally reduces in magnitude. The effect diminishes with depth, but the change is always in the same direction – a decrease in impedance. The observed seismic phenomenon depends on the impedance of the reservoir, and on the magnitude of the impedance change, relative to the impedance of the embedding rock.<br />Figure 1. (Right) Generalized curves showing how the acoustic impedances of gas sands, water sands and shales increase with depth. Bright spots occur above depth A, where there is a large contrast in shale and gas-sand impedances but a modest difference between shale and water-sand impedances. Polarity reversals occur between depths A and B, where water-sand impedance is greater than shale impedance but gas-sand impedance is less than shale impedance. Dim spots occur below depth B, where the three impedance curves converge and there are only small impedance contrasts between shale and either type of sand, brine-filled or gas-filled. (Left) Examples of seismic reflectivity for each of the three sand/shale impedance regimes, taken from AAPG Memoir 42 (sixth edition).<br />Theory<br />Compaction of sand and shale causes their acoustic impedances to increase with depth and age (Figure 1), but these impedances normally increase at different rates. For young, shallow clastic rocks, sands typically have lower impedance than shales – but for older, deeper clastic rocks, sands typically have higher impedance than shales. Note the crossover of the shale impedance and sand impedance curves on the figure.<br />When a water sand has lower impedance than its embedding shale, changing the water in the pores to hydrocarbon increases the sand-shale impedance contrast and thus increases seismic reflection amplitude, which results in a bright spot. When a water sand or other reservoir rock has higher impedance than its embedding shale, replacing the water in the pores with hydrocarbon decreases the impedance contrast, and the result is a dim spot.<br />Figure 1 shows normal compaction curves for one local area. Because these are trends generally applicable to many areas, no numbers are assigned to the axes. The crossovers of the curves cause the phenomena bright spot, polarity reversal and dim spot to occur in this ordered sequence with increasing depth. Thus, once an interpreter has established one seismic hydrocarbon indicator (say, polarity reversal), this depth-dependent trend provides a valuable guideline for the nature of the hydrocarbon indicator that should be expected at a deeper or shallower target.<br />Examples<br />Notice on Figure 1 there is a data example illustrating each of the seismic reflection phenomena. The dim spot example illustrates a strong oil-water contact reflection, but the reflection from the top of the oil sand is low amplitude and difficult to see because it is a dim spot. The above argument means that dim spots occur deeper than bright spots, but they are a well-understood and valid type of seismic reflection phenomenon. Some hydrocarbon has been found with dim spots, and some hydrocarbon fields have been developed using dim spot phenomena. Thus we must recognize the existence of dim spots and start looking for more of them! As we do so, however, we must realize that dim spots are difficult to recognize and to apply because:<br />Deeper seismic data have poorer resolution.<br />Deeper seismic data often have a lower signal-to-noise ratio.<br />It is more difficult to be confident of an interpretation involving reduced amplitude than an interpretation involving increased amplitude because more ambiguities are involved in low-amplitude data.<br />Conclusion<br />An interpreter must consider all the characteristics of hydrocarbon reflections, not just dimness (or brightness), and in AAPG Memoir 42 (sixth edition) the author lists 17 characteristics observable on seismic data that are properly displayed on a workstation. In addition there are special techniques like AVO and converted waves that provide additional evidence. We all know that the easiest oil and gas has been found and that future exploration challenges must involve innovative technological applications and smarter explorationists. Dim spots are thus an opportunity of the future, and the emerging generation of geoscientists should accept the challenge. The future of direct observation of hydrocarbons may be dim indeed!<br />Reference<br />Brown, Alistar R., 2004, Reservoir Identification, AAPG Memoir 42 and SEG Investigations in Geophysics, No. 9, Chapter 5, p. 153-197.<br />