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Resolution Undergoing Revolution

Wide azimuths combat salt 'blur'

You usually hear a lot about revolutions.

So it’s a little strange that we haven’t heard more about the revolution taking place in the Gulf of Mexico.

Especially since this revolution will spread around the world to other basins with salt, and exploration geologists will have to know as much about it as possible.

The development of seismic work in the Gulf is going in every direction right now – on purpose. It’s a sea change brought about by necessity.

Faced with deepwater drilling costs that can reach $100 million per well, exploration teams are demanding the very best imaging possible for subsalt prospects.

In response, seismic acquisition has expanded to capture data over a wider swath of water, and to gather perspective from a number of different directions.

That’s producing a new, sharper look at prospects below the Gulf salt.

Call it a revolution in resolution.

Offshore, the angle of linear horizontal direction is known as “azimuth” – and until recently, seismic shoots typically took place with a vessel towing streamers along one azimuth.

This approach has some serious limitations. The line of data captured will be limited to the width covered by the streamer spread, maybe a kilometer at most.

And the sound or energy source will be on the same vessel, also limiting the width of capture.

At the same time, this narrow-azimuth seismic acquisition tackles the area of interest from only one direction, like seeing a three-dimensional object with one eye and without being able to move around.

“In the Gulf of Mexico, we realized we couldn’t image below these complex salt overburdens with our narrow-azimuth seismic to meet our field development and exploration challenges,” said Tim Summers, advanced imaging technology director for BP in Houston.

The Need to Go Wide

Confronted by the challenge of evaluating subsalt Gulf prospects in the 1990s, the industry had developed innovative approaches to seismic acquisition and processing.

Techniques like prestack depth migration for large 3-D surveys helped overcome the blurring effect of salt layers.

“It’s just like optics,” Summers noted. “If you’ve got a table with a top of beveled glass and you’ve got an object under the glass, the glass distorts the image. That’s all the salt is doing – it’s distorting the seismic image of the reservoir.”

But improvements through reprocessing and refinement began to hit a limit. BP then reached for more data by acquiring two or more azimuths of seismic over several prospects.

“We were shooting dual-azimuth in the early to mid-’90s. We got evidence we needed more azimuths as early as that and further increased the number of azimuths on some fields,” Summers said.

Image Caption

WesternGeco’s four-vessel approach to wide-azimuth seismic utilizes two recording vessels towing streamers with sources plus two source-only vessels. The distance between each vessel is 1,200 meters, and the crossline offset from the source of the first recording vessel to the farthest streamer on recording vessel two is 4,200 meters. Graphic courtesy of WesternGeco

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You usually hear a lot about revolutions.

So it’s a little strange that we haven’t heard more about the revolution taking place in the Gulf of Mexico.

Especially since this revolution will spread around the world to other basins with salt, and exploration geologists will have to know as much about it as possible.

The development of seismic work in the Gulf is going in every direction right now – on purpose. It’s a sea change brought about by necessity.

Faced with deepwater drilling costs that can reach $100 million per well, exploration teams are demanding the very best imaging possible for subsalt prospects.

In response, seismic acquisition has expanded to capture data over a wider swath of water, and to gather perspective from a number of different directions.

That’s producing a new, sharper look at prospects below the Gulf salt.

Call it a revolution in resolution.

Offshore, the angle of linear horizontal direction is known as “azimuth” – and until recently, seismic shoots typically took place with a vessel towing streamers along one azimuth.

This approach has some serious limitations. The line of data captured will be limited to the width covered by the streamer spread, maybe a kilometer at most.

And the sound or energy source will be on the same vessel, also limiting the width of capture.

At the same time, this narrow-azimuth seismic acquisition tackles the area of interest from only one direction, like seeing a three-dimensional object with one eye and without being able to move around.

“In the Gulf of Mexico, we realized we couldn’t image below these complex salt overburdens with our narrow-azimuth seismic to meet our field development and exploration challenges,” said Tim Summers, advanced imaging technology director for BP in Houston.

The Need to Go Wide

Confronted by the challenge of evaluating subsalt Gulf prospects in the 1990s, the industry had developed innovative approaches to seismic acquisition and processing.

Techniques like prestack depth migration for large 3-D surveys helped overcome the blurring effect of salt layers.

“It’s just like optics,” Summers noted. “If you’ve got a table with a top of beveled glass and you’ve got an object under the glass, the glass distorts the image. That’s all the salt is doing – it’s distorting the seismic image of the reservoir.”

But improvements through reprocessing and refinement began to hit a limit. BP then reached for more data by acquiring two or more azimuths of seismic over several prospects.

“We were shooting dual-azimuth in the early to mid-’90s. We got evidence we needed more azimuths as early as that and further increased the number of azimuths on some fields,” Summers said.

“This led to the recognition of need for wide-azimuth, and by 2003 we had developed the techniques that enabled us to go do it,” he added.

In the 2004-06 period, the company carried out two large deepwater field trials in the Gulf of Mexico, using wide-azimuth towed streamer over its Mad Dog field and ocean-bottom nodes over the Atlantis field.

Each of these was an industry-first, at-scale field trial of wide-azimuth seismic for sub-salt imaging.

Since then, the Gulf of Mexico has become both a hotbed of experimentation and a proving ground for multiple-azimuth, wide-azimuth and complex-azimuth or rich-azimuth seismic surveys.

Differences That Matter

It’s important to distinguish among those approaches.

“Multiple-azimuth is when we acquire narrow-azimuth conventional surveys, but in multiple directions,” said AAPG member Jerry Kapoor, newly named manager of the WesternGeco’s Subsalt Center of Excellence in Houston.

Kapoor previously was the North American advanced imaging group manager for WesternGeco.

Dual-azimuth combines acquisition in two directions, multi-azimuth in three to six directions, he said.

By contrast, “wide-azimuth is where you’re acquiring a wider swath of data at the same time using several vessels. Currently, we use four vessels,” Kapoor explained.

“Rich azimuth is when you do a combination of multi-azimuth and wide-azimuth. You acquire wide-azimuth, but in multiple directions,” he said.

Multiple-azimuth acquisition requires only one vessel.

Wide-azimuth seismic can employ three or four vessels. At Mad Dog, BP has used two separate source vessels in addition to the streamer-towing vessel.

The source vessels were at the leading and trailing edges of the array and offset along the cross-line direction for multiple boat passes.

In WesternGeco’s four-vessel arrangement, two vessels tow streamers in conjunction with two other source vessels.

At the highest end of acquisition, multiple vessels capture wide-azimuth seismic in multiple directions.

This is not cheap – but it is worthwhile and high-value when surveys lead to sizable discoveries, increased output and longer reservoir life.

Kapoor said wide-azimuth acquisition may be three times as expensive as a narrow-azimuth survey. Width of the line, which can exceed four kilometers, is also a factor.

“The wider you go, the more expensive it gets,” he said.

Combining wide-azimuth and multi-azimuth might involve multiple times the cost, although some efficiencies exist.

“Better productivity in acquiring data while turning from one azimuth to another and reducing line change time can compensate for the extra cost of additional azimuths,” Kapoor said.

“For smaller surveys, line change time can be equivalent to recording time and thus a significant overhead,” he added.

And multi-azimuth surveys do allow some flexibility in avoiding bad weather conditions, Kapoor observed.

“Depending upon currents and wave direction,” he said, “you can reduce your downtime considerably by choosing the optimum direction you want to shoot in.”

A Full Set of Tools

Summers tends to look at wide-azimuth seismic as a set of tools to be selected and used according to the project at hand. This depends on subsurface imaging challenge and exploration to production objectives.

“At BP, we see wide-azimuth seismic as a toolkit that encompasses a string of technologies,” he explained.

“In shallow water, we can get wide-azimuth seismic from ocean-bottom cables, and we’ve been doing that for quite some time, such as at BP’s permanent installation over Valhalla in the North Sea used for reservoir monitoring,” he said.

“Scaling up wide-azimuth towed streamer surveys is best for very large surveys oriented toward exploration and appraisal, while “ocean-bottom node systems are very well-suited to field development and production-scale surveys in deepwater,” according to Summers.

“All of this new acquisition has required improved and new processing algorithms,” he noted, and handling the huge amounts of data – facilitated by increased computer capacity – is essential in the new subsalt work.

“You acquire five to six times as much data as you would conventionally,” Kapoor said. “You get a lot higher fold, as well.”

WesternGeco is in the fifth phase of a multiclient, wide-azimuth survey in the Gulf of Mexico, which already has covered almost 900 OCS blocks, Kapoor said.

Data goes through fast-track processing for a preliminary look, then additional processing for refinement.

“We’ve already put out products that look pretty good compared with the conventional surveys with just fast-track processing. But we’re doing further processing to help us build better velocity models,” Kapoor said.

“We’re also developing multiple-attenuation techniques that are more suitable for wide-azimuth seismic,” he added. “This data probably will be reprocessed many times in the coming years.”

Leading the Way

Large-scale, offshore wide-azimuth surveys for subsalt imaging represent a fairly recent development for the industry.

Other forms of multi-azimuth and wide-azimuth already are being applied globally. BP’s multi-azimuth surveys in Egypt since 2004, for example, and wide-azimuth using ocean-bottom cable in many basins.

Wide-azimuth land surveys have been around much longer, in part because the streamer-width limitation doesn’t exist on land. You can spread out geophones and cables onshore and leave them for acquisition.

But onshore wide-azimuth surveys haven’t had the robustness of offshore work.

“In land surveys we acquired data with wide-azimuth, but the fold was not very high at each azimuth,” Kapoor said.

Because wide-azimuth gathers so much data, processing can help eliminate multiples, those seismic events made by energy reflected more than once. Dropping out the weaker signals isn’t a perfect solution, however.

“It doesn’t attenuate all multiples,” Kapoor noted. “There are certain types of multiples that are still fairly strong.

“And because of the complexity of the salt geometry, there are areas where you don’t get any illumination,” he added. “You don’t get any rays coming back to be recorded.”

Getting Better

On a global scale, wide-azimuth seismic concepts for subsalt imaging undoubtedly will spread to other subsalt play areas. Kapoor said offshore West Africa, India and Brazil are natural next steps.

“There are a lot of other places that will be looking at this technology,” he said. “But right now, it’s pretty heavy in the Gulf of Mexico.”

Despite the much higher cost of wide-azimuth over conventional seismic surveys, soaring exploration costs and attractive potential returns have convinced oil companies of its value.

Multiclient surveys, like those conducted in the Gulf by WesternGeco, CGGVeritas and others, reduce the per-company cost.

“The economics are there,” Kapoor noted.

Looking ahead, Summers sees the following challenges for offshore wide-azimuth and multi-azimuth work:

  • Improving acquisition design.
  • Continuously developing the processing toolkit.
  • Developing new and better interpretation workflows.

“Ultimately, what we would like is a shot and a receiver at every survey point. If we could afford it, that’s what we’d do. But you just can’t afford it,” he said.

Of course, the newest thing is only the newest until the next thing comes along. A new revolution could be on the way in offshore seismic.

Call it a revolution of revolutions.

“We’re looking at, ‘Can we acquire full-azimuth data?’ We’ve done some tests where we’ve acquired data in circles, which we call a coil shoot,” Kapoor explained.

“You acquire multiple circles so you get full-azimuth,” he said. “And we can actually do that with one vessel instead of multiple vessels.”

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