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Seismic moves into 21st century Technical evolution enables assembly of increasingly detailed subsurface information; radical changes in seismic began in 1970s Alan Bailey Petroleum News
Way back in the early days of oil and gas exploration in northern Alaska, seismic crews would wend their way across the tundra in Cat trains. Dynamite was the technology of choice for creating the sound waves that echo off subsurface rock formations to provide information about underground structures. And the end products of the surveys were printed, two-dimensional seismic cross-sections of the subsurface, containing only enough detail to depict major geologic features.
Change in the 1970s
But by the 1970s, the approach toward surveying was starting to undergo radical change, as people became increasingly aware of the importance of protecting the delicate Arctic environment, and as evolving seismic technologies began to improve the quality of the seismic images.
Instead of using ground-damaging dynamite, people started to create seismic sound waves using a technique known as vibroseis, in which a vibrator pad below a purpose-built truck transmits sound vibrations into the ground, Jon Anderson, ConocoPhillips Alaska chief geophysicist, exploration and land, told Petroleum News.
Vibroseis has now become the standard sound source for on-land seismic surveys, with the equipment and its hydraulic-powered vibration systems becoming increasingly reliable, Anderson said.
Offshore, air guns near the sea surface rather than explosives have become the standard source for seismic sound — a seismic survey vessel moving along a survey line tows an array of air guns and streamers of geophones, the devices that surveyors use to detect the seismic sound signals.
And along the seacoast off Alaska’s North Slope, where the water is too shallow for a traditional marine survey, a technique called ocean bottom seismic in which surveyors lay cabled geophones along the seafloor has enabled geophysicists to bridge what used to be a gap in coverage between onshore and offshore seismic coverage, Tom Walsh, principal partner and manager of Petrotechnical Resources of Alaska, told Petroleum News.
At the same time, dramatic advances in computer and recording technology, including the miniaturization of components and the ability to use small devices to record vast amounts of data, have greatly reduced the size and weight of the recording equipment that needs to be deployed on the tundra.
“The dog house where all the recording is done … used to be the size of a semi-trailer, filled with equipment,” Anderson said. “Now there’s a guy in this fairly small box with a computer.”
“The recording equipment itself is probably a tenth of the weight that it was 10 years ago, 15 years ago even,” said Michael Faust, offshore exploration manager for ConocoPhillips Alaska.
Improved vehicles And coupled with the reduction in weight of the equipment have come major improvements in vehicle designs, to enable seismic crews to operate on the tundra in the winter without marking or, worse still, tearing up the tundra surface.
“One of the biggest things is the fact that back in the old days everything was steel tracked vehicles and they were all skid steered,” Faust said. “Nowadays everything’s articulated steering — rubber tracked vehicles with very low pressure on the tundra.”
The growing awareness of environmental protection that has accompanied these equipment improvements has led to an expectation nowadays of zero environmental impact. In the 1970s people just went out and shot seismic; in the 1980s it became a question of trying not to cause damage during a seismic survey; today, companies won’t shoot seismic if they may cause any damage, Faust said.
And that’s in part been a question of changing people’s attitudes — for example, nowadays a crewmember will always pocket a used cigarette butt, rather than dropping it onto the ground, Faust said.
Improved efficiency Surveying efficiency has also improved greatly over the years.
Thirty years ago a survey crew would place wooden stakes in the ground using triangulation techniques, to mark out source and receiver locations, Anderson said. But GPS receivers that can instantly pinpoint equipment locations have done away with the need for that time-consuming manual survey procedure.
And the designs of the surveys themselves have improved, thanks to the availability of technology that enables the recording and processing of vast amounts of seismic data.
So, whereas years ago crews would obtain more data by setting off more seismic shots, nowadays people can increase data quantities by using more geophones. In fact it is possible to reduce the number of sound source shots needed to obtain high-resolution data.
“Now you can get great data with very little source impact,” Faust said.
And by the judicious placement of the vibrator points and the geophones, it is also possible to reduce the amount of ground traversing done by the seismic survey vehicles. Increasing the number of recording points, for example, might make it possible to increase the spacing between adjacent routes taken by the vibrator vehicle from, say, 500 feet to 1,500 feet while still obtaining the same quality of seismic image, Faust explained.
Geophone development The last few decades have seen major improvements in geophone technology, with digital recording now replacing older analogue technologies. Modern electronics have reduced the size of these devices, Anderson said. The devices are now more robust and reliable than they used to be — whereas a survey crew used to deploy at least a dozen geophones at each recording location to ensure the capture of usable data, crews have reduced that number now almost down to one per station, Anderson said.
Geophones are strung out across the ground along cable runs, rather like a huge string of Christmas tree lights — the logistics of transporting cable and managing the cable runs forms a significant component of carrying out a seismic survey on land. But a new generation of wireless geophones has just come on the market. These use lithium batteries, have built in GPS receivers and contain miniature recorders with 10 gigabyte flash drives, Faust said.
The wireless geophones offer the enticing prospect of being able to simply drop geophones in position on the tundra, without the need for vehicles to transport and lay cabling. However, there are problems with battery life in the low temperatures of the Arctic winter, Faust said. And finding the devices in the snow of a North Slope winter seismic survey season might present some interesting challenges.
A fairly recent development that has seen some use on the North Slope is a type of geophone that can simultaneously record sound vibrations in three different directions, rather than just the single sound pressure variations recorded by a traditional device, Faust said. The three-component geophones enable geophysicists to distinguish between pressure waves and shear waves in the seismic signals. That distinction enables data processing that provides invaluable insights into the physical properties of the subsurface rocks.
The use of state-of-the-art, high-resolution 3-D seismic surveying for oilfield development has introduced a new problem for seismic surveyors: how to deal with ambient industrial noise that can obscure the seismic signals detected by the geophones, Jon Konkler, senior development geophysicist for BP Exploration (Alaska), told Petroleum News.
The seismic industry has developed technologies for determining the noise at an oilfield location and extracting that noise from the seismic recordings.
“We can’t stop the noise in the field, but as long as we know when it is and where it is and can pinpoint where it’s coming from that helps a lot in processing that noise,” Konkler said.
Computer technology Alongside improved field acquisition technology, modern computer and communications technology probably represents the biggest single enabling factor in the huge strides that the seismic industry has made in the past few decades.
The ability to record and process the vast amount of data originating from many thousands of geophones responding to multiple pulses from a vibroseis unit or underwater airgun array has opened the door to ever increasing data resolution from a decreased environmental footprint. And state-of-the-art computer technology has revolutionized seismic processing, visualization and interpretation (see “Computer technology has revolutionized seismic” in this publication).
“Computer power has enabled a lot of advances in all technologies, and seismic is one of the benefactors,” Konkler said.
And those advances in computer processing have led to a vastly improved ability to locate and pinpoint oil and gas reservoirs, leading to improved drilling success rates and the ability to locate the more elusive pools of subsurface oil and gas.
But the demands for interactive viewing of seismic and other data are driving a need for ever-more-powerful computer networks, to shunt massive quantities of data between server computers and computer workstations. Nowadays, rather than wanting to move one or two gigabytes of data around the network, you might want to move several hundred gigabytes, or maybe even a terabyte, all at once, Konkler said.
“And you want it right now,” Konkler said. “You don’t want to have to sit there and wait for an hour for it to load up on your machine and then find out that your machine can’t hold all that data.”
The rapid evolution of computer technology has also led to some interesting issues relating to the use of old seismic data, perhaps acquired several decades ago. That old seismic can represent a high-dollar exploration investment and can often prove invaluable when re-assessing a region for new exploration. And modern processing can often extract more information from the data than was apparent to the geoscientists who originally interpreted the data.
But the old data was typically stored on reels of magnetic tape using a variety of recording formats, several of which have become obsolete. So, a whole industry has evolved around services that enable the retrieval of data from old tapes. And ConocoPhillips, for example, transfers its old data onto modern media about every five years, rather than risk losing valuable data that could have a future use, Faust said.
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