The offshore lease sales scheduled in 2008 imply additional demand for seismic acquisition or data-library use ahead.

Perhaps one of the most hotly debated topics in the service sector today is the outlook for the offshore seismic industry. Like much of the market in the service space, it is currently enjoying a sustained period of high demand, tight supply and record-high margins. Full-year operating margins for 2007 set records for many seismic companies.

At the same time, the outlook appears bright with growth in the use of long-offset 2-D, 3-D and multi-azimuth surveys as well as record high oil prices.

Historically, this segment of the service industry has been a model of boom and bust with seismic operators investing in new offshore vessels and vast multiclient acquisition surveys at the peak of the cycle, only to find that, when commodity prices drop, their upstream clients reduce their data-acquisition programs.

The industry has responded by expanding the offshore seismic fleet to meet demand growth. While the perception is that upstream players can’t find oil and gas and will therefore consume all additional seismic capacity, there is little evidence that the fundamental drivers of demand have changed.

Based on our outlook for upstream exploration spending, current consensus estimates for seismic revenue growth through 2009 appear broadly achievable. However, the risk appears skewed to the downside if exploration spending as a percent of overall capex does not continue to trend up, or if oil prices moderate. Furthermore, while earnings and cash-flow forecasts look reasonable, margins should begin to fall in late 2008 or early 2009, especially for low-end seismic operators or multiclient players.

The market

The roughly $10-billion geophysical market is split between three segments: data library, software and processing (49%), data acquisition (39%) and equipment (12%), according to Spears & Associates, a Tulsa-based consulting firm. Of the three segments, the most identifiable segment (acquisition) accounts for only 40% of activity, while processing, software and library accounts for nearly 50%.

Breaking down the sector further shows that of the global market, the offshore tends to dominate, accounting for about 60% of total seismic expenditures.

The land-offshore split should come as little surprise. While seismic activity has ramped up in the U.S. related to development of onshore unconventional gas resources, the average land survey is smaller and cheaper. Furthermore, the basins conducive to land surveys are largely limited to North America, Algeria, Russia, Libya and the Middle East. Elsewhere, tree cover and rough terrain rapidly escalate the cost and thus are major inhibiting factors.

The largest players are Schlumberger’s WesternGeco with a 29% market share, CGG- Veritas with 23% and PGS with 12%. Combined, these companies have 64% of the market on a revenue basis. This is unlikely to change materially, given that these three names represent market leaders from a technology standpoint as well, and they have been active in consolidating new-boat additions to the offshore seismic fleet.

The largest segment—data library, software and processing—represents the purchasing of existing data from multiclient surveys. Data demand is often a factor of upcoming licensing rounds as oil and gas companies investigate prospects and plan for which blocks they will submit a bid.
The average working seismic vessel has some six streamers, but the new fleet will average 14 streamers per vessel. The number of streamers operating by 2010 will be about double the 2006 level.

Licensing rounds

Some countries have consistent license or bid rounds every year, such as the U.S. in the Gulf of Mexico, Norway and the U.K. North Sea. This creates a base load of demand. But few attractive new areas, outside of India and the Arctic, have upcoming rounds to drive incremental multiclient growth.

Similar to past cycles, the acquisition and equipment segments are exposed to the capacity expansion, which at 15% annually (based on streamer capacity) is two times greater than the drilling-rig expansion under way.

Much like the drilling market, the most susceptible markets appear to be the low-end 2-D data slice and multiclient surveys, while boats with high stream counts, that are capable of shooting wide-azimuth surveys and Arctic surveys, appear more likely to hold pricing and margins.

Today, the seismic business finds itself once again on the crest of a wave, reporting record returns and seeing strong demand for its end products. The industry has responded by expanding its fleet to meet this apparent demand. Knowing whether this is enough, just right or too much capacity, as is also the case for the offshore drillers, is the challenge.

There are approximately 78 seismic vessels currently operating with 16 en route to locations, 16 in the shipyard and 23 newbuilds on the way, according to ODS-Petrodata and company reports.

At first sight, the addition of 23 vessels over the next three years does not look particularly onerous. However, streamer additions represent a better measure of seismic capacity, given that a boat with 16 streamers towed behind it could theoretically shoot the same amount of seismic data as a boat with four streamers in a quarter of the time. While this is not strictly true due to a number of factors, it represents a reasonable approximation and suggests that streamer capacity growth is a greater cause of concern.

During the next three or four years, the streamer growth is significant. Based on current plans, some 330 additional streamers will be in use by 2010 on those 23 newbuilds. The fleet should thus expand at a compound annual growth rate of 15% through the end of this decade, meaning that by 2010, the number of streamers operating will be about 100% above the 2006 level.

Wide azimuth

Since 1980, 3-D seismic has proved to be critical in many of the new basins, with some of the latest 3-D technology allowing imaging of small-scale channel sands, such as those seen offshore Angola. This has reduced the risk that individual (often expensive) wells would hit oil or gas from one in 10 to less than one in two wells drilled—making numerous basins prospective.

A recent variation, 4-D seismic, adds a fourth dimension—time. The seismic images are being reshot through time from the same locations to see changes in fluid flows within the reservoir. 4-D has been particularly effective in the North Sea clastic reservoirs such as those found in the Brent and Forties fields.

While 2-D, 3-D and 4-D form the basic suite of seismic techniques, innovations continue to emerge in data acquisition, processing and amplitude-offset/azimuth methods.

One of the most interesting innovations to emerge in the past five years is wide-azimuth and multi-azimuth surveys. Instead of towing a number of seismic streamers near each other behind a vessel, the survey is conducted with a wider spread of streamers or a number of cross lines.

The purpose is to “shine as much light” as possible by getting multiple data points, across multiple azimuths or reflections off the same horizon. This in turn allows better calibration of the data and better noise reduction, creating clearer images of the major rock intervals.

The move to wide azimuth is driven by two trends: subsalt drilling in the Gulf of Mexico and the desire to drill much deeper. As the seismic wave goes lower into the subsurface, the amount of noise relative to the signal increases, weakening the clarity of the image. Using wide azimuth addresses this issue.

Wide azimuth is accomplished by either running multiple boats in parallel or a single boat in a multiple pattern. An emerging technique is to use a sequence of narrow azimuths comprising six to 12 passes over the core area in a rose or spoke pattern that creates a central area or hub that is heavily crisscrossed, with multiple traces at multiple azimuth.

The first commercial wide-azimuth marine survey was conducted by Veritas (prior to its merger with CGG) for BP in the Green Canyon area of the Gulf of Mexico in the winter of 2004-2005. Shortly thereafter, a “rich azimuth” survey (a combination of multi-azimuth and wide azimuth) was acquired by another seismic contractor for BHP Billiton over an area near the BP survey.

These surveys targeted subsalt reservoirs with known seismic-imaging challenges, and their improved results prompted the wider adoption of the technology for other offshore projects.

The complexities of wide-azimuth data acquisition are significant due to the number of seismic vessels involved, often working in obstructed areas offshore. Thus the costs are also significant and would probably, in most commodity environments, be prohibitive.

However, with offshore drilling-rig costs also very high now (recent deepwater dayrates are above $500,000), the relative cost savings of reducing the number of dry holes, or limiting the number of appraisal wells that need to be drilled, is material.

Electromagnetic 3-D

The application of 3-D seismic combined with electromagnetic (EM) recording is likely to represent the greatest advance in offshore seismic surveying since the advent of 3-D. It remains in its infancy, but the technique appears poised to once again reduce prospect risk and dry holes, potentially lowering overall finding and development costs.

Many players have begun to step in, including Schlumberger, EMGS of Norway, and PGS, which recently acquired MTEM, a private company that specializes in multi-transient EM surveys.

EM recording is not new, but its use offshore has been relatively limited and is new. EM measures the resistivity of the rock type below the surface.

Its potential is great because the greatest risk to a geologic prospect is the presence or absence of hydrocarbons, whereas 10 or 15 years ago the risk was whether or not the subsurface structure was present, due to poor seismic imaging and processing. The latter are now largely understood, thanks to advances in 3-D.

The offshore lease sales scheduled in 2008 imply additional demand for seismic acquisition or data-library use ahead.

Today, there are two methods to record EM data: controlled-source electromagnetics (CSEM) which uses a node-based system, and multi-transient electromagnetics (MTEM), which relies on a cable-based system to record the seismic signal.

In CSEM, nodes or electrical receivers are placed on the sea floor. In MTEM, cables are placed below the sea surface but not on the sea floor, allowing multiple readings to be taken more quickly and repeat lines to be recorded when the signal-to-noise ratio is too low. This system can be used in shallow water as well as deep. In general data quality is expected to be better with MTEM.

Conclusion

By far the greatest challenge for investors in the seismic industry is understanding the demand outlook. While it is clear the E&P industry is struggling to replace the reserve base and will have to drill incrementally more wells over time, this fails to quantify what the primary drivers of seismic demand growth are and how they change through time.

Broadly speaking, there are three ways to look at seismic demand: seismic revenue versus capex or upstream cash-flow generation, seismic capacity related to rig capacity, and upcoming licensing rounds.

The revenue generation of the seismic players shows a strong correlation to both the overall services market and, more importantly, the cash-flow generation and capex of the upstream players.

This article is adapted from a report by Benjamin P. Dell, senior E&P and energy services analyst with Bernstein Research, a unit of Alliance Bernstein, in New York.