2.1.1 1920–1980


During World War I, Ludger Mintrop had invented a portable seismograph for the German army to use to locate Allied artillery. In 1921 he founded the company Seismos to do geophysical exploration. Seismos was hired to conduct


seismic exploration in Texas and Louisiana. One of the crews pinpointed the Orchard Dome in Texas in 1924, making this the first discovery of commercial quantities of oil using seismic. Large-scale marine seismic surveying did not appear until 1944 when Superior and Mobil began refraction shooting for salt domes offshore Louisiana with geophones planted on the sea bottom. Te floating streamer was first used in 1949–50. In the marine environment, dynamite was used as source until 1965 when alternatives were developed, in particular the airgun seismic source. In the 1960s the digital revolution took analogue data to digital recording, followed by large-scale application of the computer in the processing and interpretation of seismic data. Prior to the 1970s geophysicists


believed that noise in the seismic recordings was so much stronger than the seismic signal that only structural information could be extracted. However, in the early 1970s, oil companies recognised ‘bright spots’ – strong seismic reflection amplitudes associated with hydrocarbons, predominantly gas. Furthermore, in the mid-1970s it was shown that depositional patterns could be interpreted in the seismic data. Some of what had previously been regarded as noise was actually geological signal! In 1967, Exxon


conducted the first 3D seismic survey in the


Figure 2.4: With 3D seismic acquistion the geophysicist can image, in detail, the faults, layering and sedimentary structures that can trap hydrocarbons.


(Ship image from B. Dragoset, 2005. The Leading Edge, 24:S46– S71, and Western Geophysical. ’3’ seismic data and analysis from F. Aminzadeh, and P. de Groot, 2006, Neural Networks and Other Soft Computing Techniques with Applications in the Oil Industry, EAGE Book Series, ISBN 90–73781–50–7. Visualisation by J. Louie.)


59


Figure 2.3: Illustration of the basic difference between the 2D and 3D seismic survey geometries. The dashed lines suggest subsurface structure contour lines. For 2D surveys, the spacing between adjacent sail lines will typically be 1 km or greater. The reflections from the subsurface are assumed to lie directly below the sail line, providing an image in two dimensions (horizontal and vertical) – hence the name ‘2D’. A subsurface picture of the geology thus has to be painstakingly reconstructed by interpreting and intelligently guessing what goes on in between the lines. 3D surveys in the beginning were acquired by towing one cable and making many parallel passes with short spacing through the survey area. Next, multiple streamers, separated by 25–200m, were used while shooting closely spaced lines. Because of this close spacing, it is possible to represent the data as 3D seismic cubes. Cubes can be viewed as they are or analysed in greater detail by computer-generating vertical, horizontal (time-slices), or inclined sections through them, as well as sections along interpreted horizons. Courtesy Jack Caldwell: OGP Report No. 448 An Overview of Marine Seismic Operations; www.ogp.org.uk


Friendswood Field near Houston. In 1972, Geophysical Services International (GSI), supported by six oil companies, launched a major research project to evaluate 3D seismic at the Bell Lake field in south-eastern New Mexico. Te first marine 3D survey was acquired by Exxon in 1974.


© Jack Caldwell: IOGP


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