The Leading Edge; 2005; v. 24; no. Supplement;
p. S72-S78; DOI: 10.1190/1.2112393
© 2005 Society of Exploration Geophysicists
The evolution of the interpreter's toolkit—past, present, and future
Rocky Roden
Rocky Ridge Resources, Centerville, Texas, USA
Geophysical interpreters today take for granted the availability and access to computer workstation environments loaded with 2D/3D seismic surveys, well logs, geological studies, and GIS information. To appreciate what interpreters have at their disposal today, I have made an attempt to review the evolution of interpretation tools from the inception of SEG in 1930 to the present in 25-year increments. I have also described some possible interpretation scenarios for the year 2030, SEG's 100th Anniversary (Table 1). Obviously, I was not personally involved in interpretation in 1930 and 1955 (I was 2 years old), but I have talked with several veterans of the oil industry and reviewed numerous books and papers (especially the November 1980 issue of GEOPHYSICS which commemorates SEG's 50th Anniversary). I have been directly involved in interpretation for the 1980 and 2005 periods.
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The TIAC Center, in Calgary, Canada in 1964, performed digital seismic data processing for clients. The computer printouts in the foreground show the much-improved 2D resolution made possible by digital seismic.
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1930
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In 1930 the new field of exploration geophysics vis-à-vis petroleum was undergoing major changes. The first discovery of an oil field by geophysical methods (1924) was the use of the Eötvös torsion balance to map the Nash salt dome in Brazoria County, Texas. The refraction seismic method was used in conjunction with the torsion balance to make numerous spectacular oil discoveries around salt domes in the late 1920s. The first oil discovery by refraction methods (1924) was either the Orchard Dome in Texas or the Golden Lane area in Mexico (the Mexican well was ultimately determined noncommercial). But in 1930 the refraction method was being replaced by the newer reflection seismic approach. The reflection method evolved from work by Reginald Fessenden who developed a sonic sounder to find icebergs (after the sinking of the Titanic). The first discovery by the reflection method was the Maud Field in Oklahoma in 1927. J.C. Karcher employed this technology to develop reflection seismographs for Geophysical Research Corporation (GRC), an Amerada subsidiary. By 1928 two recording trucks with two cameras were employed to get four traces per shot. By 1930, six-channel systems were employed. GRC employed 70% of the world's seismic explorationists by the end of the 1920s; however, in 1930, Karcher, backed by Everette De Golyer (one of Amerada's key executives and probably the most famous petroleum geologist in the world) split with GRC and formed Geophysical Service Incorporated (GSI), which eliminated GRC's monopoly and encouraged the development of numerous contract companies using reflection methods. Other contributors to early seismic developments were Burton McCollum (who sold various patents to the Texas Company), the Petty Geophysical Engineering Company, as well as several oil companies such as Amerada, Marland (Conoco), Gulf, Humble, Shell, Sun, Texaco, and Atlantic. By the early 1930s, the reflection method was the most widely used of all geophysical techniques, a status it still retains.
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A "seiscrop" interpretation table, circa 1982.
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Interpretations of early reflection data were, by our standards, crude and usually under difficult conditions. Much hinged on the skill of the party chief who supervised all operations and made all key decisions. Seismic data were recorded directly on fast-moving photographic paper, and it often required several shots to obtain satisfactory records. They were developed in the field immediately after the recording to ensure that adequate data had been captured. When the records came in from the field, they were washed (to remove the last vestiges of the developing fluid) and hung up to dry. A computer (this was a job title for a crew member, not a machine) applied appropriate annotation and made corrections (usually including a weathering correction) to put all records on a common datum. This is when the interpretation began, and it was usually done by the party chief. The actual interpretation process of that era was very basic: Reflections of interest were "picked" and possibly associated with a particular formation; times were posted to a reproducible shot-point base map; and the map was contoured by hand. This was the critical step and "good" contouring (which attempted to account for ground roll, surface conditions, etc.) was highly valued. Because data were very sparse, interpretation was often closer to art than science. The hand-contoured map was then sent up the corporate ladder where final decisions were made.
There were early attempts to properly migrate seismic data. The basics of migration were known—Karcher even migrated some of the original reflection data he collected in his famous experiments in Oklahoma in 1921! But migration in the modern sense, actually manipulating the traces, did not arrive on the scene for several decades. In this era, a migrated section was drafted; it did not contain actual seismic traces.
This interpretation scenario, in one form or another, existed until reproducible recording became available in the 1950s. This moved the interpreter into an office. It was no longer done by the party chief (who, as a result, was soon reclassified as party manager). The tools of the interpreter did not vary much in this period. More information gradually became available (e.g., well logs, check-shot velocity surveys, better knowledge of local geology) but the basic interpretation process remained timing the data and posting it on the map and, until 3D became routine more than 50 years later, hand contouring was the big interpretive step.
In 1930 the accepted body of knowledge about seismic methods was very small. Only a few universities offered courses in the subject, formal textbooks on exploration geophysics did not appear until 1940, and pertinent articles in scientific journals were difficult to find. The interpreters of 1930 were truly pioneers, developing the science upon which future generations would soon expand.
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1955
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As Allen (1980) describes, by the end of the 1930s seismic systems typically had up to 12 channels, up to 6 or more geophones per channel, mixed channels, and automatic volume control. Static corrections were made from uphole times, and velocities were determined from well information and refraction and reflection profiles. The 1940s saw the use of 24-channel systems, AGC filters, trace mixing, and the use of several geophones per channel. However, after World War II and into the 1950s, three significant developments would shape the future of exploration geophysics: magnetic tape recording, the CDP method, and research by MIT's Geophysical Analysis Group (GAG) that laid the groundwork for identifying reflections from noise via the then brand-new digital concepts.
Magnolia Petroleum Company (Mobil) is credited with developing the first multichannel magnetic tape recording system, which was adopted universally. In 1954 GSI advanced the magnetic-disc field recording system with numerous advances including a playback system that allowed making weathering corrections, elevation changes, and accounting for geometrical effects of different recording layouts. In 1955, a patent was awarded to Harry Mayne for the "common depth point (CDP)" method. However, it was not until 1958 that the method became practical after magnetic playback equipment was developed to account for necessary prestack corrections including normal moveout. In 1953, GAG in cooperation with industry, aggressively pursued signal analysis and processing techniques to help make seismic interpretations. Enders Robinson's mathematical work at GAG on "predictive decomposition" laid the groundwork for deconvolution and the ultimate transition to digital recordings.
In 1955 essentially all interpretation was still being performed in the field, but exciting new developments were occurring. With the advent of magnetic tape recording, seismic record sections from "continuous profiling" evolved and would soon become standard. This procedure gave a continuous set of reflection points along a profile line. Prior to this, interpretations were made from large individual seismic records laid out adjacent to each other, quite often at different scales and varying quality. Before magnetic recordings, as described in the preceding section, individual shot records had to be developed from film, and a common scene at the field site was strips of film hanging with chemicals dripping on the ground. In areas of significant dip, seismic lines were hand-migrated using maximum diffraction curves based on any available velocity information. Continuous velocity logs (sonic logs) were employed to compute reflection coefficients which led to "synthetic" seismograms. 2D and 3D model studies were now possible. Gravity work declined after 1950 as reflection seismology became the standard technique for interpreting structures. From 1930 to 1955, Dobrin (1960) indicates that interpretation from geophysics yielded 22.5 billion barrels of oil and 134 trillion cubic feet of gas in the United States alone. This represents between a third to a half of all the hydrocarbons discovered in this time frame.
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1980
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The CDP method, developed in the 1950s, became the standard approach in seismic acquisition in the 1960s. Conoco's development of vibroseis, as an alternative to dynamite, made acquisition on land more flexible. The development of the streamer in the late 1940s and marine sources, such as the Bolt air gun in the 1960s, along with integrated navigation systems dramatically expanded seismic acquisition offshore. However, the most far-reaching impact on seismic exploration since the pioneering days was the digital revolution. Digital technology allowed recording signals in millisecond intervals, resulting in higher fidelity data, and produced data that could be "enhanced" by a trip (or several trips) through a digital computer. By the early 1970s, 48-channel acquisition was standard and the resulting data were subjected, prior to interpretation, to multichannel processing, deconvolution, velocity filtering, automated statics, velocity analysis, migration, inversion, and noise reduction.
In 1967, Exxon conducted the first 3D seismic survey in the Friendswood Field near Houston. GSI and several oil companies advanced 3D acquisition and processing technology in the 1970s; however, the widespread application of 3D seismic would not evolve until the first commercial interpretation workstations were developed in 1984. 3D would, within a few years of the appearance of workstations, become the dominant seismic technique used in the industry.
With the advent of digital technology in the early 1960s, acquisition was of course still conducted in the field, but the data were then sent to a processing center and interpretation was now done at the oil company's office instead of in the field. Up until about 1970, the prevailing thought in the industry was that structural information was the only thing that could be extracted from seismic data. However, in the late 1960s and early 1970s, several oil companies recognized the association of seismic amplitudes with hydrocarbons, predominantly gas. Thus started the "bright spot" revolution which resulted in the discovery of significant hydrocarbons and the emphasis in acquisition and processing of "true amplitude" data that ultimately led to numerous direct detection methods. Another significant interpretation advance was the 1977 publication of AAPG Memoir 26, Seismic Stratigraphy—Applications to Hydrocarbon Exploration. In this book, Peter Vail and associates at Exxon described seismic stratigraphic principles that helped interpreters make depositional, facies, and lithology determinations from reflection patterns and helped develop global sea-level charts related to the stratigraphic record. Also as a result of this publication, interpreters became aware of the benefits of seismic attributes generated from amplitude data.
In 1980, interpretations were made from 2D seismic on paper sections in wiggle trace variable area format. Color sections were available, but not the norm for interpreters. Engineering rules, one and ten part dividers, and map colors were the interpreter's tools. Typical interpretation approaches included viewing down the side of paper sections, correlating horizons, tying faults, and identifying structural features. Tying loops or correlating horizons over intersecting 2D lines involved folding paper sections at intersections for correlations and making any necessary time shift corrections. Horizon times were hand-posted to maps (some digitizing tablets were employed) along with the location of faults and then hand-contoured. The phase of the data was usually unknown, and time maps were converted to depth maps based on velocity information from sonic logs, check shots, and seismic velocities. Both stacked and migrated paper sections were interpreted because understanding diffraction patterns was a key component in interpreting faults and structures. Companies had drafting departments that took these hand-drawn maps and generated polished products for presentation to management or partners.
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2005
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For interpreters, the development of workstations in the mid-1980s made interpretation of 3D seismic data practical because they allowed the handling and manipulation of the very large amounts of data generated by a 3D survey. The ability to view 2D and 3D seismic data in workstation environments in various color combinations in raster or variable intensity displays was one of the biggest advances in the evolution of seismic interpretation. The general consensus in the 1980s was that 3D surveys were good for development settings, but not always necessary for exploration plays. In the following decade, 3D surveys would become the dominant seismic approach for all settings, development, exploitation, and exploration.
In the early 1980s, Ostrander demonstrated how gas reservoirs could generate an increasing amplitude with offset on gathers and began the AVO (amplitude variation with offset) approach to interpretation. AVO had some success in helping find hydrocarbons in the 1980s, but it was not until Rutherford and Williams (1989) described AVO responses in different geological settings (AVO classes 1–3) that interpreters began to apply AVO analysis more extensively.
In the late 1980s, dip moveout (DMO) became routinely applied to seismic processing, which more accurately positioned CDP data in settings with dipping beds. In the 1990s, Amoco patented the use of coherency analysis for interpretation, a technique which correlated portions of a trace with surrounding traces using various seismic attributes. This technique proved to be very important in more accurately interpreting faults and stratigraphic changes.
Over the last 20 years there have been numerous additional advances in processing; among the most prominent are 
-p and Radon transforms, 2D/3D reflection tomography approaches, f-x deconvolution, various wavelet transform techniques, and processing for anisotropy. In seismic acquisition, 24-bit recordings became standard, 4–6 streamer cables became routine offshore (even though some vessels can tow more than a dozen streamers), ocean bottom cables were employed, and instrumentation and navigation systems improved dramatically.
For the interpreters, advances in seismic time and depth migration have tremendously increased the ability to make more accurate interpretations. In the 1980s, 2D and 3D time-migration algorithms advanced, and poststack depth migration was routinely employed. The 1990s saw significant advances in prestack time and depth migration and by the end of the decade, these approaches were advanced with the use of multiple CPU cluster environments which permitted tremendous computer processing capabilities.
Time-lapse or 4D (i.e., 3D surveys repeated over time to monitor how reservoir properties—such as fluids, temperature, pressure—change throughout the life of the producing field) seismic began to evolve in the early 1990s. This approach was especially applied to the North Sea to the extent of having permanently emplaced sensors in some fields.
From the 1990s until today, multicomponent technology has advanced, whether collecting converted-wave data (4-C) in marine environments or full nine-component information onshore. Even though multicomponent approaches are promising, interpretations with shear-wave data are not yet routine.
Over the last few years there have been significant advances in visualization for interpretation. Whether viewing data in large visionariums with dozens of people or making interpretations from high-resolution displays in a smaller team setting with stereoscopic capabilities, visualization has enabled multidiscipline collaboration and helped make better decisions in exploration and development.
Today, seismic interpretations are typically made on two- or three-monitor workstations. Workstation environments are evolving from UNIX systems to PC-based computers. Interpreters discuss projects in terms of gigabytes and terabytes of storage. Most interpretations today are made on prestack time migrated data with prestack depth (either Kirchhoff or wave-equation migration) data in certain areas. 2D data are still used in interpretation, but usually when 3D is not available. Workstation environments allow interpretation of not only seismic attributes (e.g. amplitude envelope, instantaneous phase, coherency, etc.), but the 3D visualization of these different data types. Geostatistics allows the correlation of one or more seismic and well parameters for significant geologic trends. Maps, cross-sections, time and horizon slices, well bore locations and projections, and opacity 3D displays are all easily generated in today's workstation environment.
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A typical data processing center in the early 1980s.
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Without question the last few years have seen a trend toward reservoir geophysics as we try to efficiently and effectively produce fields, and this has opened up an entirely new area of interpretation. Our data sets are getting larger as we generate numerous volumes of different data types. Some of today's applications even allow the integration of gathers in the interpretation workflow which requires even more data storage and management capabilities. Interpreters today have the ability to employ different AVO approaches, inversion technologies (acoustic impedance and elastic impedance), numerous modeling solutions (normal incidence, AVO, ray tracing, hydrocarbon substitution, etc.), geostatistical analysis, seismic attributes and different depth conversion techniques. Artificial intelligence and neural network applications are being employed for everything from wavelet shape classification for facies analysis to correlation of geologic and seismic information. The interpreter's toolkit in 2005, with a workstation environment with astonishing computer power and visualization capability, is in dramatic, almost unbelievable, contrast to the crude evaluations made in the field in 1930.
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2030
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Speculating about the future of interpretation is an awesome challenge because human knowledge doubles every 10 years and computer power doubles every 18 months. In the past decade, more scientific knowledge has been created than in all human history. The interpretation environment over the next 25 years will obviously benefit from the advance of several technologies that are already in use in our industry. Even though multicomponent technology is not in the mainstream today, the future will probably have full-vector wavefield imaging with composite displays differentiating fluids and lithology. Neural networks will be able to train on geophysical, geological, and engineering data and make geological environment and production estimations. Geostatistics will advance to the point that the spatial continuity of numerous geologic/geophysical variables will be more accurately computed. As AVO is further integrated in the interpretation workflow, our understanding of rock physics and fluid identification will increase. Prestack depth migration should improve to the point that all seismic interpretations will be performed on depth data. Time processing only will be a step in processing to get the final depth output. Because of broadband data transmission capabilities beyond what is available today, data will be instantly transmitted from the field to a processing center, or perhaps processing will be performed quickly on site with high-powered but easily portable computers. Another future scenario would involve the interpreter receiving field data in the office real time, making a few key decisions, and then funneling the data into different processing flows.
In the next 25 years, scientists (and virtually everyone else) expect an explosion of computer power that will change the face of our industry (and probably nearly everything else as well). Nanotechnology and miniaturization of microprocessors will be so plentiful that intelligent systems will be everywhere—leading to what some have already named "the intelligent oilfield." The Internet will literally consist of millions of networks creating a worldwide "intelligent planet." The implications for our industry, and specifically the interpreter, are profound. However, scientists indicate that around 2020, our ability to etch ever-smaller transistors onto silicon wafers will end as we reach a size limit at the molecular level. New untested and unexplored technologies may evolve from optical and molecular computers, to DNA and quantum computers. So what will be in the interpreter's toolkit in the year 2030? Use your imagination.
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Conclusion
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Today, the direction of geophysical interpretation is toward production, where integration of technologies and disciplines are employed to optimize recovery from existing fields and develop new fields quickly. In other words, geophysical technology is becoming more of a tool for production than exploration. However, with the evolution of new geophysical technologies, perhaps new exploration trends will be discovered that are beyond our vision today.
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Suggested reading
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"Amplitude-versus-offset in gas sands" by Rutherford and Williams (GEOPHYSICS, 1989). Exploration Seismology by Sheriff and Geldart (Cambridge, 1995). Geophysical Prospecting by Dobrin (McGraw-Hill, 1960). Geophysics in the Affairs of Mankind by Lawyer et al. (SEG, 2001). "Plane-wave reflection coefficients for gas sands at nonnormal angles of incidence" by Ostrander (GEOPHYSICS, 1984). "Seismic method" by Allen (GEOPHYSICS, 1980). Seismic Stratigraphy-applications to hydrocarbon exploration (AAPG Memoir 26, 1977). Visions by Kaku (Anchor Press, 1997).
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Acknowledgments:
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I thank Mike Forrest for sharing his experiences on Shell seismic field crews in the 1950s and Lee Lawyer for his extensive knowledge of pioneering history of our geophysical profession.
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Footnotes
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Rocky R. Roden received a bachelor's degree from Lamar University and a master's (in geological and geophysical oceanography) from Texas A&M University. His 30-year career includes employment with Maxus, Pogo Producing, Decca Survey, Texaco, and Respol-YPF where he was chief geophysicist and involved in projects around the world. He presently consults with Seismic Micro-Technology, is a principle in the Rose and Associates DHI Risk Analysis Consortium, and advises several oil companies on technical and prospect evaluation issues.
Copyright © 2008 by Society of Exploration Geophysicists
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