GULF OF MEXICO: Deep-shelf hydrocarbons feature salt influence, shift of rock facies down-dip

Gulf of Mexico speculative 3D seismic programs by contractors. Due to overlapping surveys, some colors may not exactly match the legend. Maps courtesy of Energy Graphics, Inc. Contractors shown are those who have elected to be included in the Energy Graphics, Inc. 3D seismic database for Intellex software users.

What a difference a year makes. In 2000, the US offshore petroleum industry focused on Gulf of Mexico deepwater and ultra-deepwater prospects. This year, the Minerals Management Service (MMS) has given the industry a new target - deep shelf gas. MMS is granting royalty relief on wells drilled below 15,000 ft, so there is new incentive to press the drilling and economic envelope into higher temperature and higher pressured regimes in the deeper sediments of the Gulf of Mexico shelf.

In searching the deeper shelf, explorers have many choices, but a major question remains: should 2D or 3D seismic be used? Most companies have libraries of older 2D data available for immediate review, especially over their active field production. This may be sufficient to identify possible deeper targets. After identifying possible targets, smaller 3D data sets can be purchased for detail work.

The accompanying maps show the 3D speculative data available on the shelf from the seismic contractors. Coverage is extensive, with only a few areas lacking 3D seismic. For those areas, plenty of older 2D programs exist, which can be examined and reprocessed for a deeper image.

The MMS move to encourage deeper drilling has caused some oil and gas producers to take a second look at deep-shelf potential. Of course, over the past few years, most of the majors sold their shelf fields to independent oil companies as the majors raised capital to chase the US Gulf deepwater plays, which was stimulated by earlier MMS royalty relief incentives.

Since the independents now control producing acreage on the shelf, they will likely take the lead in chasing the deeper potential. Even so, several majors are likely to back into some of the more prospective new plays by helping fund some wells for a working interest. At the same time, independents also are likely to spread the risk of costlier deep wells with joint venture partners.

New targets

So what are the new targets to be chased? Depending on field location, the 15,000 ft minimum depth for royalty relief will either place the bit in the existing productive trend (Miocene, Pliocene, Pleistocene) or more likely the trend immediately to the north of the producing field. Producing trends in the US Gulf tend to parallel the coastline and are younger in age than fields discovered further from shore.

The major difference the deeper penetration brings is that the productive facies will be shifted farther down-dip in the rock genetic units. If the field reservoir is an offshore bar, then delta-front sands or basin floor fans of an older rock series would be the deeper target.

There are significant problems to overcome when drilling deeper, because the deeper into the shelf section a well is drilled, the more likely salt movement has manipulated and contorted the sediments. As always, understanding the salt movement history of an area will be a key to identifying sedimentation patterns and locating new productive zones. Higher pressures and temperatures, which are common below 15,000 ft, may create some problems for mud systems and wireline tools.

Offset issues

Will the existing seismic coverage be sufficient to image the deeper sediments? The short answer is "yes," with the caveat that salt and infrastructure force limitations on streamer seismic programs. First, imaging beneath salt is problematic due to salt's variable shape and thickness. In some cases, salt distorts the returning signal away from the path of the vessel and streamer creating a shadow zone.

Streamer surveys have a narrow azimuth (signal capture angle) and are directional in nature. This can only be improved by new shooting in a different orientation, by collecting a wider azimuth wide-tow survey, or by an ocean bottom cable survey. If this is required to get a useable image, then a second problem becomes evident - existing infrastructure. The US Gulf shelf is full of producing structures that hinder wide tows by modern vessels. Subsea wellheads, connecting flowlines, and pipelines are a problem for bottom cable surveys. These problems can be overcome, but the solutions are expensive.

For the short term, the industry's better option may be to reach into the archives of older 2D data. The goal is to find a program vintage that has enough offset to "see" deep, but was shot at a time when vessels could pass across the area without veering to avoid production platforms. Seismic contractors may find their older libraries in demand once more. New processing technology may allow those older data sets one more life cycle.

Data sales

The geophysical industry is in much better health than it was last year. Revenues have improved dramatically (as much as 62% for one company) and profits are up. There is plenty of data available, and the quality is excellent. Most oil and gas producers will find what they need, although data prices have firmed due to increased demand.

Overall, this availability is an excellent situation for the producers and will help maximize the effectiveness of exploration capital. Most programs are available off-the-shelf, and little proprietary shooting will be needed, unless there are specific problems to be solved.

The bulk of seismic money will likely be spent on reprocessing. Older datasets will have to be tuned for deeper horizons and significant amounts of velocity work will be needed to account for salt influence and other structural complexities. New, larger computer systems allow much more processing flexibility than was available in the past, so producers may experiment a bit to improve deep images.

Future

Where do geophysical contractors go next in the Gulf of Mexico? Without more acreage available for leasing, the US Gulf is fairly well shot out. Regional 2D grids crisscross the US Gulf. Three-dimensional seismic blankets both the shelf and the deepwater regions, thanks to high capacity vessels. Also, 3D-4C is expensive and not really needed at this point.

Multi-component seismic (4C) is where 3D seismic was during the late 1970s. Geoscientists knew how to capture the signal, but processing was not previously able to handle the complexities. Interpretation of the 4C data is still in its formative stages. This technique is the longer term future, but 4C will see limited application until significant need develops for its improvements over 3D seismic.

The near term future appears to lie in applying modern processing techniques to older data sets. Reprocessing techniques will go a long way in helping oil companies identify targets in the deep shelf, which can then be tightened with new proprietary surveys and, of course, tested with the drill bit.

Editor's Note: The accompanying maps have been limited to 3D speculative seismic programs on the Gulf of Mexico shelf. Some programs that extend into deeper water are truncated to emphasize shelf coverage. Contact geophysical contractors for detailed coverage maps.