Virtual Source Looks 'Underneath'

Breaking Through the Seismic Shields

There are certain technologies in the oil and gas industry that might best be described as überhigh-tech.

A relative newcomer to this category is virtual source technology, whereby seismic data receivers downhole can be turned into sources.

It’s all about the math.

Simply put, a surface-based seismic source can be mathematically transposed to a deep position by wavefield extrapolation and become a virtual source, according to Bob Hardage, senior research scientist at the Bureau of Economic Geology, University of Texas at Austin, and editor of the EXPLORER’s Geophysical Corner.

These virtual sources can be specifically positioned in the wellbore beneath horizons that would distort the energy emanating from the surface source.  

This can make all the difference in subsurface evaluation, given that oil and gas deposits often accumulate in reservoirs beneath certain rocks that have the capability to “hide” the reservoir by causing the downward traveling seismic ray paths to bend away from the troublesome rocks, Hardage noted.

They effectively conceal the hydrocarbons.

Following a seismic survey, the acquired data are processed and relied on to image structures and evaluate rock properties and fluid movement. But what you see via the data is not necessarily what you get with the drillbit – particularly in locales where there’s complex overburden and energy-distorting horizons such as salt interfering with the subsurface picture.

Virtual source technology is designed to circumvent this problem, enabling high resolution imaging of the reflectors beneath the problem surfaces.

Factors for Success

The technique was invented and patented by Rodney Calvert, chief scientist for geophysics, and research geophysicist Andrey Bakulin, both at Shel’s Bellaire Technology Center in Houston.

Hardage, writing in the July EXPLORER, called it “an emerging and valuable seismic technology that will allow you, in some cases, to image geology that is difficult to see with other imaging strategies.”

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There are certain technologies in the oil and gas industry that might best be described as überhigh-tech.

A relative newcomer to this category is virtual source technology, whereby seismic data receivers downhole can be turned into sources.

It’s all about the math.

Simply put, a surface-based seismic source can be mathematically transposed to a deep position by wavefield extrapolation and become a virtual source, according to Bob Hardage, senior research scientist at the Bureau of Economic Geology, University of Texas at Austin, and editor of the EXPLORER’s Geophysical Corner.

These virtual sources can be specifically positioned in the wellbore beneath horizons that would distort the energy emanating from the surface source.  

This can make all the difference in subsurface evaluation, given that oil and gas deposits often accumulate in reservoirs beneath certain rocks that have the capability to “hide” the reservoir by causing the downward traveling seismic ray paths to bend away from the troublesome rocks, Hardage noted.

They effectively conceal the hydrocarbons.

Following a seismic survey, the acquired data are processed and relied on to image structures and evaluate rock properties and fluid movement. But what you see via the data is not necessarily what you get with the drillbit – particularly in locales where there’s complex overburden and energy-distorting horizons such as salt interfering with the subsurface picture.

Virtual source technology is designed to circumvent this problem, enabling high resolution imaging of the reflectors beneath the problem surfaces.

Factors for Success

The technique was invented and patented by Rodney Calvert, chief scientist for geophysics, and research geophysicist Andrey Bakulin, both at Shel’s Bellaire Technology Center in Houston.

Hardage, writing in the July EXPLORER, called it “an emerging and valuable seismic technology that will allow you, in some cases, to image geology that is difficult to see with other imaging strategies.”

Shell already is benefiting from applying the virtual source technique in vertical seismic profiles (VSP). These VSPs have been shot conventionally in exploration and development wells to acquire more accurate estimates of the rock velocities along the borehole and to better image the structure in the area surrounding the well, according to AAPG member Jorge Lopez, project leader and principal technical expert for reservoir geophysics at Shell.

The conventional VSPs also are used in the production phase to monitor changes over time.

Here’s the blueprint for the virtual source application, according to Shell:

  • In virtual source VSPs, the sources are located on the surface and the receivers are downhole, just as with traditional VSP.
  • The sources are activated in the normal standard sequence, and the downhole receivers record the energy from the source.
  • Simple mathematical algorithms are used to convert this recorded energy to a sharp pulse, making it possible for each receiver to be turned into a virtual undisturbed pulse source.
  • Other receivers in the borehole can record from this virtual source to provide a higher resolution seismic image around the borehole.

Virtual source technology generates both pressure and shear waves, making it possible to derive added information from the seismic.

Borehole orientation is a factor in the technology’s effectiveness.

“We always need sensors in the borehole, but they’re more useful if they’re deployed in a way to give you virtual source surveys,” Lopez said. “That will normally mean the borehole will be deviated or horizontal, because then each of the sensors will be along a line and can be turned into sources that can then produce an image below the borehole.

“For applications related to reservoir monitoring,” he added, “we normally prefer essentially horizontal wells.”

Test Runs

There are certain situations where virtual source technology is implemented via a vertical borehole, and the application works quite well.

This was the case at the Zuidwending salt cavern modeling study in the Netherlands, where the salt flanks were imaged from within the salt in order to nail down the location of the flanks of a salt dome being converted into a cavern for underground gas storage.

“With salt caverns, you’re imaging something to the side of the borehole,” Lopez said. “We were imaging the salt flank surface, which is parallel to the borehole. The sensors and reflectors must be parallel to each other, so they can both be vertical or both horizontal.

“We’ve now completed execution of the salt cavern survey, and it was very successful, ” Lopez noted. “We’ve seen the salt flank image and have the distance from the borehole to the salt flank, which is more precise than what was known before.

“The uncertainty bar was significantly reduced because of the survey.”

Shell also completed a successful look-ahead VSP exploration application trial in the Gulf of Mexico in 2006. The look-ahead VSP with virtual sources was tested on a walkaway VSP data set, which was acquired while a well was drilling through a thick salt mass.

Unknown hazards lying ahead of the drill bit are relatively commonplace in the Gulf with its many widespread salt sheets. The objective of the Gulf trial was to detect intra-salt hazards while drilling and to accurately predict the base of salt in advance.

“In this case we were in the salt and an inclusion was observed on the seismic, and we weren’t sure if it was an artifact or a real potential problem,” Lopez said. “Also, once you approach the base of the salt the geology can be quite complex, and you need a good prediction for depth because the driller must be ready to react.

“As you drill through the salt, the pressures beneath are often unpredictable,” Lopez noted, “and if you don’t have a good estimate of the depth of your objective, you can be surprised.

“One of the successes of this look-ahead VSP was to see ahead of the bit and predict the depth of these two hazards – the inclusion and base salt – very precisely.”

Another Dimension

Virtual source monitoring is becoming a complementary tool to conventional 4-D seismic technology, which is used to monitor changes in producing reservoirs and to observe results of the stimulation methods used for enhanced recovery, according to Lopez.

As opposed to conventional 4-D, the virtual source receivers are buried permanently, overcoming the repeatability issues that often arise with 4-D acquisition, i.e., the inability to accurately repeat the receiver location.

A virtual source survey has been put into play at the Peace River Field in Canada, where a complicated, near-surface layer distorts the conventional seismic picture in this heavy-oil field, which is being produced via the steam injection enhanced recovery process.

It’s uncertain where the steam goes because it doesn’t follow a uniform path. Even when the process is repeated, the steam chooses the path of least resistance.

“What we’re looking for is a way of producing a high resolution image of the reservoir over time so we can see where the steam goes, ” Lopez said. “This is a traditional 4-D, but the problem is the Peace River Field has some shallow distortions such as glacial channels, so the images are not of good enough quality.

“Also, the shallow subsurface changes over time because of seasonal changes, so the 4-D signals are not easily repeatable and you can’t accurately map the steam front.”

The virtual source application here was a test along a transect versus the entire area. A comparison of the surface seismic with zero-offset virtual source image reveals the improved resolution of the cap rock and reservoir images obtained via the virtual source.

“With the virtual source survey, we’re able to remove all of the effects that occur above the reservoir and just concentrate on the reservoir and get a higher fidelity measurement, ” Lopez said. “This was a pilot test, and we’re trying to deploy an areal test of the Peace River Field now.”

Going Deeper

When using the virtual source technique, the extent of the image coverage is maximized when the sensors are deployed in wells drilled parallel to the reflectors, e.g., horizontal wellbores drilled above essentially level geology.

A reliable and inexpensive method to drill horizontal wells for observation could enable the technology to be enhanced to the point where one could create a grid of sensors and virtual sources below seismic-distorting obstacles to essentially implement a seismic survey below the obstacles.

In case you’re thinking there are numerous horizontal wells already drilled, you’re right. The problem is that the producing horizontals are of no use because they’re already in the reservoir.

“You want something above the reservoir to image below,” Lopez said. “It will be deployed between the surface and the reservoir at some intermediate depth that has to be below anything distorting your image, and enough above the reservoir because you don’t want to be too close – the closer to the reservoir, the smaller the image becomes.

“I see a time where we have many horizontal wells drilled for observation below the shallow distortions, ” Lopez said, “so we’ll have essentially a buried seismic survey underneath complexities.

“We’re picking up momentum on getting there.”

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