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A Passive Approach to Healthy Oil Production
Lisa M. Pinsker

Most oil fields need a little bit of coaxing. When oil drillers tap into a new reservoir, they often have to pump fluids into the ground before any oil comes back out. Every time fluid enters and leaves the ground, it changes the rock below — causing it to bend, break or fold. By continuously listening to these changes, like a doctor listens to a beating heart with a stethoscope, scientists can monitor the health of the reservoir, says Peter Duncan, president of MicroSeismic, Inc., in Houston, Texas.

Bitumen, or heavy oil, can be difficult to extract from the ground. The injection of steam into the production well increases flow of the oil, and a new application of a tool called passive seismic is allowing researchers to monitor what happens belowground as the steam makes its way through the reservoir. Courtesy of Syncrude Canada Ltd.

Such real-time monitoring is only one use of an emerging tool called passive seismic. It’s a new twist on old earthquake technology, allowing oil field managers not only to measure the movement of fluid belowground — and thus optimize production — but also to map out reservoirs without the high cost and environmental impact that often accompany traditional seismic mapping.

Explosive beginnings

One of the major challenges facing petroleum exploration and production is the uneven distribution of the resource, which makes the extraction of oil and gas — sometimes abundant in areas that are politically unstable, economically downtrodden or environmentally sensitive — either impossible or too expensive. Of the estimated 3 trillion barrels of recoverable oil in the world, 24 percent has been produced and 29 percent has been discovered, according to an assessment conducted in 2000 by the U.S. Geological Survey (USGS). Similarly, of the 2.5 trillion barrels of natural gas equivalent, 11 percent of the resource has been produced and 31 percent has been discovered.

Although the USGS assessment is conservative and does not include all areas of the world, it shows that much oil and gas remains to be both found and extracted. New technologies promise to help by better characterizing reservoirs — thus opening new avenues for exploration and increasing efficiency at fields already drilled for oil.

Typically, companies use explosives or another source of sound to send waves through the ground (or the seafloor) in their first step to explore for petroleum. They measure the travel time and type of waves and use that information to visualize a reservoir. It’s similar, Duncan says, to the way a bat uses sound to determine where the objects are in the air.

These sound sources have created controversy in areas such as the Western United States and in marine environments, when the source (air guns, thumper trucks, explosives) runs up against environmental restrictions. For example, this year, environmental groups sued the Bureau of Land Management for approving a project by Denver-based Bill Barrett Corp., to use thumper trucks for a conventional seismic survey to explore Nine Mile Canyon in Utah for natural gas (see Geotimes, July 2004). The lawsuit has since been dropped, but in general, environmental permitting (and litigation) can add tremendous cost to exploration projects, in addition to the costs associated with the heavy equipment. In some cases, potential environmental impacts make exploration impossible. But there is another way to measure sound waves without using an active source. Earth itself can provide all the sound waves necessary to map a given spot.

A new view

“Passive seismic uses very much the same equipment for listening, the same microphones that listen for the sound waves, but this time we’re not going to use any artificial source,” Duncan says. What the microphones are listening for are very small earthquakes called microseisms. “These aren’t your concrete-smashing, building-crushing earthquakes,” he says. “These are small little creaks and groans that are going off in the planet all the time as it responds to various tectonic forces.”

It’s all earthquake seismology, says Shawn Maxwell, manager of petroleum services at ESG Canada in Kingston, Ontario. “The basic science has been around for years and years,” he says. Indeed, passive seismic studies were part of an early Moon research project to map its internal structure. And modern seismic arrays for monitoring earthquakes, such as those in Parkfield, Calif., use the same basic technology. “The only new part of what we’re doing is addressing new problems,” Maxwell says.

The first applications of the technology Maxwell worked with were in mine safety and for characterizing nuclear waste storage facilities. Over the past decade, the oil and gas industry has slowly begun experimenting with using natural microseisms instead of conventional seismic techniques to piece together what the reservoir looks like in advance of drilling. But passive seismic can also do something more exciting, Duncan says: track changes in the reservoir over time.

Some companies try to accomplish this task through 4-D conventional seismic techniques, which are also relatively new, taking several snapshot surveys of the reservoir over time and then putting them together — “kind of like going to the doctor and getting an ultrasound or MRI once every four months, or six months.” But passive seismic is unique in that it can relay real-time information about changes in the reservoir, thus acting as a “stethoscope on the chest.”

Here, instead of using Earth’s natural snaps and creaks to map the subsurface, companies are locating induced microseisms, created by the injection of fluids to help stimulate or enhance oil production. This new application of the technology had a huge push forward on the Ekofisk field in the North Sea in 1997. Geologists with Phillips were producing oil there and noticed that the area was undergoing substantial subsidence: “The reservoir was compacting and getting thinner and the platform in the North Sea was getting closer and closer to the water surface,” Duncan says.

Maxwell, who worked on the monitoring effort, says that they usually would have used conventional seismology (with air guns) to understand what was happening, but that the waves would not have been able to properly move through a gas cloud that was sitting in the center of the field. “It was sort of a blind spot for reflection seismology, so the idea was to try to listen and see if we could see the faults just by the induced seismicity,” he says. And it worked: They were able to map out small-scale faults that may have been difficult to identify otherwise. That success, Maxwell says, was the start of real-time application of passive seismic.

Liquid assets

When Maxwell was doing his geophysics doctoral work at Queen’s University in Kingston, Canada, some 10 years ago, the application of real-time passive seismic was considered the “holy grail” for the oil and gas industry. While the industry has played with the idea of the technology for years, it has only been in the last five years that companies have started making these services commercially available. “There’s been a huge uptake in interest in the technology and in the number of different companies actually using it,” Maxwell says.

Mike Mayerhofer of Pinnacle Technologies calibrates a hydraulic-fracture model in real time at a site in Wyoming. Hydraulic fractures stimulate petroleum flow in a well, and passive seismic data show geologists and engineers how the fractures are growing, and thus where the remaining oil is located. Courtesy of Pinnacle Technologies.

The largest application of the technology is for hydraulic fracturing. Once considered an enhanced recovery technique, hydraulic fracturing is now a standard practice for drilling in many reservoirs, and particularly in North America, says Chris Wright, founder of Pinnacle Technologies in San Francisco, Calif. “We’re stimulating the well to produce more than it could have produced naturally.” And many reservoirs will not produce oil or gas without such fracturing, Wright says.

For a typical “frac job,” drillers will pump hundreds of thousands to millions of gallons of fluid and thousands of pounds of sand or ceramic materials, called proppant, into the ground to create a fracture that might grow a few hundred feet to a few thousand feet long. “After the fluid leaks out into the formation, the proppant stays behind and leaves a conductive pathway from the rock containing the oil and gas back to your well bore,” Wright explains. “So now it will flow much more oil and gas after it’s drilled than it would have if it wasn’t hydraulically fractured.” That pumping process can take anywhere from half an hour to eight hours, he says.

More than 75 percent of North American oil wells are fractured, Wright says. While that number is at only 20 percent globally, it will grow to 75 percent in 20 years, he says. That’s in part because passive seismic is giving drillers an unprecedented view of the fracture at work, thus increasing its usefulness to oil drillers.

In the past, the most common thing people did to monitor a hydraulic fracture was nothing, Wright says. “They pumped a fracture, the production got better, and everyone was happy.” But sometimes, drillers might have tried to pump a larger fracture and ended up encountering water or unwelcome gases; they did not know what was happening belowground, despite some models developed to help predict fracture growth. “The problem the engineers running the fracs face is that they do not know what direction the fractures grow in and what kind of lengths they’re achieving,” Maxwell says.

With passive seismic, drillers can set up an array of sensors downhole, and a fiber optic or electric wire line will transmit data to the surface. Those sensors measure acoustic waves, showing changes in the rocks below as the pumped fluid moves and creates microseisms. And because the data are arriving at the surface in real time, engineers can make quick decisions regarding the fracture.

“A geophysicist is right there, monitoring the data and running some analysis software that quickly locates where these microseisms are,” Wright says. That engineer can then confer with the oil company’s engineer to decide whether to stop the fracture, expand the fracture or where to move wells to better follow where the remaining oil is located.

This dynamic process lets the clients decide what to do with their drill holes, which is especially important, Wright says, considering that oftentimes the cost of drilling a single well can be in the $1 million range.

The same idea is applicable to secondary recovery techniques, in which drillers pump steam, gas or water into the drill hole to help bring oil to the production wells, Maxwell says. In Canada, where ESG operates, steam injection is a popular technique, as the country’s western half has heavy oil that needs extra coaxing to be pumped out (see story in this issue).

“The essential question they have is much like for the fracture: Where is the steam going once it enters the ground?” Maxwell says. As steam enters, it is under pressure and creates thermal changes in the rock, and thus a huge change in the material properties of the subsurface. Again, passive seismic can listen for those changes.

Maxwell points to a recent paper presented at the meeting of the Society of Exploration Geophysicists (SEG) in October, at which geologist Peter McGillivray from ShellCanada presented promising results from monitoring a steam-injection well with passive seismic systems. It was the cornerstone paper, Maxwell says, of a jam-packed session on various applications of the emerging technology.

At Peace River in northwestern Alberta, estimated in-place reserves are 8 to 10 billion barrels of heavy oil. Although the field has been in operation for more than 40 years using steam injection to liquefy the oil, no one has been certain about the processes taking place within the reservoir. At the SEG presentation, McGillivray reported success in mapping where the steam goes after injection.

Knowing such information, Maxwell says, can help oil drillers identify where the oil is that might have been missed by the injection process. “The biggest issue with a lot of oil reservoirs is that you might get 25 percent of the reserves recovered, and the rest of it would just be bypassed,” he says.

Taking the application a step further, researchers may one day be able to map out another injection process: carbon dioxide. Many scientists have been exploring the prospect of storing, or sequestering, carbon from the atmosphere into ocean or land basins, and using already-drilled production wells might be a good solution, says Maxwell, who presented a paper on monitoring carbon dioxide injection at the SEG meeting.

“The carbon-dioxide injection part of the technology is something the industry is already doing for secondary recovery, to inject gas to help push fluids toward producing oil,” he says. “Whenever you start to pump something into the ground, it is always critical that you know where it’s going so that you don’t have surprises.” In this case, people would be able to find out if any of the gas is escaping and thus evaluate a reservoir’s carbon sequestration potential.

Getting smart

Researchers at Pinnacle Technologies have plans to eventually combine passive seismic with another tool that has been successful in monitoring hydraulic fractures, a specially designed downhole tiltmeter. Developed by the company, the tiltmeters measure the actual deformation of rock, Wright says. And like passive seismic, the technology is still relatively new.

The merging of tiltmeters and passive seismic into a single process to monitor hydraulic fractures represents a larger trend toward creating a more integrated system that can continuously monitor reservoir health. Several companies are working toward that goal in different ways and currently have long-term monitoring services available.

This trend, Duncan says, is mostly driven from the fact that “at least in the United States, most of the oil is in the fields we’ve already found, and what we’re doing is trying to increase our recovery efficiency.” The idea of a “smart oil field” is to optimize production by making detailed measurements of what is happening belowground and then trying to adjust production of that field in real time in response to those observations — “rather than just sticking a well in and sucking on it,” Duncan says.

It’s new ground, Duncan says, and challenging. “There’s not a lot of case history — not a lot of doctors you can go to and say teach me what a good valve and a bad valve sound like,” he says. So a whole new area of research is trying to better understand how to interpret the data coming up to the surface.

While companies investigate those new lines of research, other companies, such as MicroSeismic, are using passive seismic to replace or supplement conventional explosive seismic surveys in mapping out reservoirs, especially in environmentally sensitive areas. The oil industry, however, has yet to buy into the idea completely, Duncan says.

Still, some major oil and service companies, including Shell and Schlumberger (which is already offering passive seismic services), are experimenting with real-time monitoring techniques. With time, Duncan says, this type of monitoring is “going to become something that people are doing as a matter of course.”

Indeed, Wright says that since his company first started more than a decade ago, it has seen 35 percent growth every year in hydraulic fracturing services alone. Last year, a total of 500 fractures were monitored with passive seismic, Duncan estimates. Companies conducted less than two dozen additional projects for monitoring other fluid or gas injections with passive seismic. “It’s still a pretty small penetration,” Wright says, but the market will continue to grow.

For Maxwell, seeing a technology first used to help with mine safety evolve into a tool for the oil and gas industry, and now potentially into application for sequestering carbon, is rewarding and exciting. “It’s always interesting if you can somehow bring in an environmental aspect to your work,” he says. “It’s nice to have the green side of the technology.”

Pinsker is managing editor of Geotimes.

"Two suits on land use: Gas exploration in Utah," Geotimes, July 2004
"Global Oil Hot Spots," Geotimes, December 2004

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