It doesn’t seem that long ago when the introduction of wireless seismic data acquisition revolutionized the field of geophysics – making obsolete the need to drag a spiderweb of bulky seismic cables from one location to another and frequently repairing their damaged wires from roving vehicles, weather and technical glitches.
Today, wireless seismic is a staple in the industry, but the methods by which data is acquired are experiencing a revolution all over again.
Thanks in large part to a boom in wireless recording systems, GPS satellite technology, affordable and low-powered receivers, and inexpensive cloud storage, geophysicists are able to install up to 100,000 seismic detectors on the ground – roughly 10 times the amount than a decade ago. With all sending data on the subsurface, their quantity and concentration are so great that subsurface images are more detailed and clearer than ever, said Peter Duncan, AAPG Member and president and CEO of MicroSeismic, Inc.
“These huge systems with autonomous nodes provide better signal-to-noise ratios, a better image of the subsurface, and it’s actually costing less than before,” Duncan said.
And through these vast fields of wireless seismic arrays, geophysicists can now operate numerous vibrator trucks simultaneously, as opposed to years ago when trucks had to “fire” vibrations into the earth one at a time to avoid cross-signals.
New technology and computer enhancements now allow geophysicists to distinguish and separate data, which is recorded using many seismic sources all working at the same time, explained David Monk, director of geophysics at Apache Corp and a past president of the Society of Exploration Geophysicists. This “selective hearing” is akin to the “cocktail party effect”, or a person’s ability to focus on a single conversation at a party despite multiple conversations taking place at the same time. This advancement has rapidly sped up the process of seismic data collection.
Referring to a current seismic data collection project of more than 4,000 square-kilometers in Egypt, Monk oversaw more than 40 vibrator trucks equipped with GPS coordinates and operating instructions for the drivers. Each generated seismic source signals into the ground without concern about the location of the other trucks or when they were vibrating.
“Simultaneous operation of the Vibroseis units means that data is recorded many times faster than it could have been previously,” he said, adding that the project will take around nine months to complete. “Had we recorded this survey sequentially 10 years ago, it would have taken more than five years to acquire the data.” In other words, “This never would have been done,” he said.
Glenn Winters, 2019 SEG Steering Committee general chairman, introduced this year’s conference with similar statistics: A 50 square-mile survey shot in 2010 would have taken 50 days. Today, he said it takes 17 days because of lighter, wireless equipment and less vibrator time.
Lower Frequencies, Higher Detail
Furthermore, vibrating trucks have begun using lower frequencies. Unlike higher frequencies that can get “eaten up by the earth,” Monk explained that lower frequencies can penetrate deeper into the subsurface and reflect a much more detailed picture of the rocks.
In the last several years, this technology, initially used offshore, has now been adapted for onshore use. “New seismic data with broad bandwidth allows interpreters to not just see the rock boundaries, such as the bumps and dips, but to see the properties of the layers, how hard the rocks are, their porosity and density,” he said.
Fast Track to Expertise
Artificial intelligence and machine learning also are contributing to seismic advances. Taking best practices from other fields, such as medicine, robotics and information management, which have been honing this technology, geophysicists are using artificial intelligence and machine learning to fine-tune the interpretation of seismic data.
“Sometimes machines discover patterns by themselves and sometimes we, the geophysicists, have recognized patterns, captured them mathematically and used the machine to find more of those patterns,” Duncan said. “Either way, there has been a huge growth in the technology.”
Perhaps 20 or 30 years ago, a geophysicist might have spent an entire career working in a single area, such as one part of the Gulf of Mexico, and became an expert in it – especially because interpretations were done by hand and on paper.
Today, some interpretations can be completed in as little as several hours. “A geoscientist is exposed to much more data now,” Duncan said, “and they can become more competent more quickly and can easily move around from area to area.”
In the field of microseismic technology, Duncan said he is preparing to corner the market on reading the subsurface in unconventional wells in terms of real-time economics. With a July 2019 announcement at URTeC of FracRx, a product set to launch before next summer, Duncan is laying the groundwork to be able to tell operators precisely when to start or stop fracturing, based on rate of return.
Will an extra 15 minutes of pumping fluid into a well change a network of fractures, opening additional conduits for the flow of oil in a financially profitable way, or will it be a waste of money? Duncan and MicroSeismic are planning to take the “pump and pray” factor out of the game.
For years, he has used microseismic technology to monitor the vibrations of rocks as they were fractured and then mapped the network of fracs. Then operators pushed him more. They wanted an algorithm to show in a dynamic sense how their fracs would drain over time. Duncan and his company delivered. Then, operators asked to compare different fracturing techniques in different wells. They delivered on that request, too.
An advocate for monitoring every well using permanent, shallow, buried array monitoring systems, Duncan said the low cost of $2,000 per stage or less is typically more affordable than temporary above-ground or reservoir-depth downhole monitoring.
“It has been observed that 20 percent of the completion stages deliver 80 percent of a well’s hydrocarbons,” Duncan said. “Yet operators continue to frac blindly. They think it costs too much to monitor a large percentage of their wells. It doesn’t. Would you let a surgeon perform orthoscopic surgery on you when he can’t see what he’s operating upon?”
Duncan and MicroSeismic are further upping the game by developing a system that will let operators know when they should continue pumping fluid into wells and when they should stop. “They need someone to predict whether an extra 20 minutes of pumping will result in a positive return,” Duncan said.
By placing geophones in the shallow wellbores roughly 1,000 feet apart, Duncan said he can monitor, in real time, the fracture pattern created, model how that pattern will produce, and predict the financial return on the effort. Such buried arrays require one-tenth the number of stations compared to a temporary surface array, and reduce the cost of monitoring significantly.
As such geophysical technology continues to advance, it appears that operators can look forward to making decisions based on current data and future projections, rather than on mistakes of the past.