3-D Seismic Interpretation:

A Primer for Geologists

Edited by Bruce S. Hart


3-D Seismic Interpretation: A Primer for Geologists - 3-D seismic technology is spreading out beyond the domain of the petroleum industry. The environmental and mining industries and academic groups are collecting and interpreting 3-D seismic data. Increasing numbers of geologists (often with little or no geophysical training) are being exposed to the technology, or results derived therefrom. Despite this interest, there are few opportunities for the practicing geologists (or engineer) to become acquainted with 3-D seismic technology at the appropriate level. This course is an attempt to fill that gap.

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    This course seeks to help geologists or other professionals (e.g., engineers) with little or no geophysical training to understand how and why 3-D seismic data are acquired, processed and interpreted. There are few opportunities for these people to become acquainted with the technology, although it is likely that geologists in a variety of fields (stratigraphy, structural geology, mineral exploration, environmental geology, etc.) will be increasingly exposed to results that are based on 3-D seismic interpretations. This course is designed to fill that training gap. It will emphasize the qualitative, rather than quantitative, aspects of seismic technology.

    No two-day course can qualify someone to be a seismic interpreter - 3-D or otherwise. Additionally, there will be no hands-on practice with interpretation software. Learning the basics of how to use some software packages can take several days. I prefer to focus on the underlying principles of the technology rather than on the mechanics of where to search for applications in menu bars. This course aims to familiarize class participants with the methods and terminology employed by 3-D seismic interpreters. In this way, following the class, participants will be in a more capable position to understand the implications of results based on 3-D interpretations (and possible “problems” with those results!) and the potential for using 3-D seismic data in their own particular fields of interest.

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    Three-dimensional (3-D) seismic data are having a phenomenal impact on the petroleum exploration and development industry. According to some estimates, technological advances (including 3-D seismic, horizontal drilling and other technologies) have caused exploration and development costs in some companies to drop by as much as 75% in recent years, whereas wildcat drilling success rates in some areas are approaching 40-50%. One major oil company reported that switching from 2-D seismic to 3-D seismic technology caused the number of dry holes (wells drilled without producing oil or gas) the company drilled to fall from 53% to 25%. Other, similar successes have been documented elsewhere (e.g., Nestvold, 1996; Aylor, 1998). Declining world oil prices in the decade since 1985 are thought to have led to nearly 450,000 job losses in the United States’ hydrocarbon exploration and production industry, and yet during that time demand for those resources was steady or even increased. Together, these observations suggest that the petroleum industry is becoming faster and better (i.e., more efficient) at finding and producing hydrocarbon reserves, and most analysts agree that 3-D seismic technology has contributed greatly to these improvements.

    Simply put, 3-D seismic data provide the most accurate and continuous volume of information that can be obtained to image stratigraphy, structure and rock properties. Routinely in the petroleum industry, interpretations based on well data, outcrop analogs or 2-D seismic have been shown to be wrong, to varying degrees, by drilling. These same data types are often used as the basis of

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    Figure 2.1 illustrates the general principle of the seismic reflection method. We start with some acoustic pulse (a "bang") that generates an expanding wavefront. The bang is located at some elevation "A" (ground surface, water surface, etc). At any given point along the expanding wavefront, we can imagine a raypath that is perpendicular to the wavefront. The wavefront will expand until it reaches some interface, here located at depth "B", that causes some of the energy to be reflected back to the surface where it can be recorded. What is physically measured by the recording instruments (located back at the "surface") are: a) the strength of the reflected energy, and b) the time it takes for the energy to travel from the surface down to the reflecting horizon, then back up to the surface again. This time is referred to as the two-way traveltime or "TWT". In principle, if we measure the TWT at many points along an interface, we can get a picture of the relief on that interface - echosounders are a good example of this process.

    In reality, we have some other things to worry about. First, we are generally interested in many interfaces, not just one. Although some of the energy from the bang will be reflected, some will be transmitted through each interface as well. Furthermore, we need to understand what dimensions of features can physically be imaged with seismic methods. We must understand something about the acoustic pulses that are used to illuminate the

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    The data recorded by seismic receivers in the field bears little resemblance to geology. The objective of seismic processing is to take the field data and produce as clear an image of the geology as possible. In the past, the steps of data acquisition, data processing and data interpretation were carried out by separate groups who had (it seemed) little communication between them. The results were not always optimal. The need for integration all long the workflow is now generally realized. For example, data acquisition people need to know the depth to the targets of interest, their dimensions and structural dips. Seismic processing incorporates “judgment calls” that can affect the interpretability of the data. Also, increasing numbers of seismic interpreters are interactively reprocessing seismic data themselves in order to enhance features of interest.

    One of the primary problems related to reflection seismology that needs to be overcome is that the reflections we wish to record are very weak. Many of the methods used during acquisition and processing are designed to amplify the reflections of interest and to help boost the signal-to-noise ratio. This theme will be emphasized throughout this chapter.

    To be a good interpreter, one needs to have some understanding (albeit qualitative) of the steps involved in data acquisition and processing. This chapter will introduce some of the basic concepts in these two fields. The focus will be on 2-D seismic acquisition and processing as it is best to understand the relatively simplified procedures involved in 2-D work before

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    In previous times it was considered that the interpretation phase of a seismic project began when the processing people delivered a “final stack” (perhaps not even migrated) data set to the geophysical interpreter. Today, it is realized that the interpretation truly begins at the survey design phase, when choices about offsets, line orientation, source characteristics etc. are made. These choices can influence the interpretability of the resultant data. For example, a survey designed for deep targets may not have the high frequencies or fold needed to image stratigraphic details at shallow levels. Alternatively, the spacing between midpoints (seismic traces) might be too great to image subsurface features of interest (e.g., “shoestring” sandstones). The interpretive choices continue through the processing phase, as processors make decisions (often based on time/money considerations) that influence the character, and also interpretability of the stacked seismic data. Realizing the importance of processing, some larger companies routinely send their field data out to two or more processing shops and compare the results.

    Another change from previous times is that an increasing amount of processing is occurring during the interpretation phase, interactively, by the interpreter. As noted at the end of the last chapter, interpreters can now interactively evaluate the effects of different processing routines (filtering, trace balancing, deconvolution, etc.) on stacked, migrated data sets (“post-stack processing”). This type of analysis might be employed to enhance certain aspects of the data, remove unwanted noise or to match two or more data sets of different vintages.

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    As mentioned at the beginning of the last chapter, the interpretation phase of a seismic project is considered by many to begin at the survey design phase. It is during this phase that the acquisition parameters are planned, and these can have a significant impact on what size of subsurface body can be imaged, how well they will be imaged and so on. These same considerations apply to the collection of 3-D seismic data as well.

    To understand the need for 3-D seismic acquisition geometries, we need to go back to looking at how 2-D seismic data are acquired. It will be recalled (Chapter 3) that for most 2-D work the sources and receivers are spread out in a line. Reflections are assumed to come from the piane through the earth that corresponds to that line. In reality however, the acoustic energy from the shot expands out spherically (i.e., in 3 dimensions) from the source location. As such, reflected energy can be received from features (e.g., faults, reefs, channels) that are located outside of the piane of the section. These reflections, sometimes referred to as “sideswipe”, will be recorded and show up in the 2-D seismic data. Since the true subsurface stratigraphy and structure are generally unknown, the features can be mistakenly thought to He in the piane of the seismic section. In fact, the interpreter may have no way of telling where the reflections come from, even if he/she cari recognize the features as sideswipe. The result

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    As mentioned in Chapter 1, and elsewhere in this work, the 3-D seismic interpretation does not rely solely on seismic data. Instead, good interpreters (or good interpretation teams) try to integrate as many other types of data as possible into their interpretations. This might include well log data, production data, pressure data, and other types of geologic, geophysical and engineering data. The idea is to make the interpretation as robust as possible. That is, an interpretation that explains the seismic observations, but does not agree with what is known about the geology or production data, needs to be rejected. Multidisciplinary skills and approaches are required in order to maximize the return on the investment made in collecting and processing the data (Hart, 1997). This represents a significant change from the times when geophysicists alone were responsible for looking at, and interpreting, seismic data.

    Not only has the philosophy of the interpretation process changed, the mechanics of the process have also changed. The use of interactive workstations to view and interpret seismic data (Chapter 5) has dramatically improved productivity. Interpreters can now play “what if” games more rapidly (this might be done when the seismic data are ambiguous). Automation of some tasks is now possible. The interpreter can view his/her data in ways that were not possible when working with paper images. New data can quickly be incorporated into the interpretation process to update or revise existing interpretations. Different vintages of seismic data, perhaps including multiple

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    Until this point, we have dealt with 3-D seismic in the abstract sense, i.e., the focus has been on general principles rather than on concrete examples of what types of things that the technology can accomplish. This chapter will present selected case studies that illustrate some accomplishments (and limitations) of 3-D interpretations. The studies are drawn from projects that the author has worked on personally. Brown (1999) and Weimer and Davis (1996) present many other excellent case studies that illustrate other uses of the technology, interpretation approaches and concepts that are not presented here. Two other good sources are The Leading Edge and First Break. Geophysics has had some good case studies lately, including a few that dealt with shallow, high-resolution (“environmental”) surveys. Trade magazines {World Oil, Oil and Gas Journal, etc.) also publish case studies.

    Locations of the study areas are provided in Figure 7.1. The first case study deals with a small 3-D seismic survey collected in central New York. It shows some of the limitations that one can run into when working with a limited data set. Next, the offshore Gulf of Mexico is the scene for a multidisciplinary study of how depositional features control production from Pleistocene shelf margin deltas. The structural geology of that same area is the focus of the third case study. This work discusses the three-dimensional evolution of a growth fault array and shows how 3-D seismic data can be exploited to study structural problems. Finally, we will

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    The material presented! in this course has illustrated uses of 3-D seismic to define subsurface structure, stratigraphy and rock properties. We have touched briefly on the physical basis of the seismic method, how seismic data (2-D and 3-D) are acquired and processed, the advantages of 3-D seismic over other methods, interpretation techniques, and looked at some case studies where 3-D seismic technology has been applied. No two-day short course can make a participant an expert in this or any other field. Furthermore, hands-on experience with 3-D seismic data on a powerful computer will be needed to truly grasp the speed and power of the technology. However, participants in this course should now be in a position to understand the “hows and whys”, and so be in a better position to: a) determine whether 3-D seismic technology is right for them in a given project, b) evaluate the results of a 3-D seismic interpretation, and с) by tracking down references provided in these notes, know where to go for more information.

    Most of the focus in this course has been on petroleum applications of 3-D seismic technology, because that is where the technology has been developed. It remains to be demonstrated that this petroleum industry approach can be adapted to “academic” branches of the earth science. It also remains to be seen whether certain techniques (e.g., seismic attribute studies) can be adapted to the study of 3-D GPR data. However, if a geoscience project aims to define subsurface structure, stratigraphy

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