Conduct a poll among E&P folks regarding seismic, and it’s likely the consensus would be that advanced seismic technology – especially 3-D and 4-D – is the greatest thing to happen since sliced bread and cold beer debuted.
If you’re among these believers, you may need to reach for a cold one before reading further.
According to a recent oil and gas capital spending survey, 3-D/4-D seismic has dropped to third place in the technology hierarchy.
Taking their place at the top on this scale is hydraulic fracturing, which ranks as the most important technology for exploration and development, followed by horizontal drilling.
Barclay’s Capital conducted the survey late last year.
This is a total one-eighty from the phenomenon that kicked off in the mid-1990s when 3-D seismic began its rapid ascent as the must-have technology in E&P. Even in places where it wasn’t needed, most investors refused to let you in the door if your prospect lacked 3-D.
All of which begs the question: What will the world of seismic now do for an encore?
Seismic technology’s rise to fame came about at a time when the companies were heavily focused on growing their reserves and production organically through the drill bit during the 1990s, noted G. Allen Brooks, managing director at Parks Paton Hoepfl & Brown.
The sudden drop on the technology favorites list, he said, could be blamed on the industry’s newest darling: the ubiquitous shale plays.
“The shale gas phenomenon has come to drive virtually the entire industry’s E&P efforts in the United States, and now even overseas areas,” Brooks said.
Once it became clear that a shale is not a shale – they differ considerably, in both the mechanical and the mineralogical sense – the race was on to figure how best to produce these complex, often-intimidating reservoirs.
The new number one industry technology, hydraulic fracturing, is used to get the hydrocarbons to move out of the dense shales at an economical rate. Gas molecules normally migrate perhaps only a few feet in a year in nano-darcy matrix permeability when left on their own, according to AAPG member Randy La Follette, manager of shale gas technology at BJ Services in Tomball, Texas.
Horizontal drilling enables staged fracs and more economical, efficient production. The single pad with its multi-laterals going into the formation also leaves a smaller footprint in what often are urban areas.
Ironically, seismic may be set to ascend back to the top of the tech popularity list – before most folks knew it had been knocked down a couple of notches.
“We’re seeing early signs of the industry probably shifting back to emphasizing seismic more going forward,” Brooks said. “The industry is saying seismic can be a very positive contributor to our success with shales.”
Whereas seismic data initially had – at best – a minor role with most shales, that has changed considerably as the geoscientists attempt to better understand just what they are dealing with in order to devise the best drilling plan.
Both the seismic technology and the applications are becoming evermore esoteric, demonstrating in large part that the shale plays and seismic no doubt will long be joined at the hip, so to speak.
Consider sweet spot I D, for example.
Vector Seismic Data Processing in Denver formed a consortium in 2009 to identify the seismic signature of fractured reservoirs in the Middle Bakken Shale via multi component seismic data. This ultimately led the company to determine that differences in the seismic image of shear waves over producing wells vs. dry holes in the Bakken formation are key for drilling success, according to AAPG member Scott Stockton, executive vice president at Vector.
Among the latest trends in seismic data acquisition in shales is multi-client 3-D surveys, which can be sizeable.
Global Geophysical, for example, has multiple crews shooting multi-client data across the increasingly active Eagle Ford shale play in south Texas. Further north, Geokinetics signed up more than 985 square miles of multi-client work in northeast Colorado in the Niobrara shale over a six-week period and then quickly booked another 644-square-mile multi-shoot in southeast Wyoming’s Niobrara.
“Based on comments I hear, seismic is looking similar to the early ‘90s, where it’s cycle driven by some of the new hardware that allows more channel counts, ease of operation in areas hard to explore,” Brooks said.
In particular he sees potential for wireless or cableless systems – not just for conventional acquisition, but also for shales.
Brooks became intrigued with the potential for wireless systems when OYO Geospace announced the sale of a 7,000 single channel GSR wireless seismic data acquisition system to BGP Inc., a subsidiary of China National Petroleum Corporation and one of the largest seismic data acquisition companies globally.
BGP has entered into a joint venture with ION Geophysical, which is home to cable seismic systems in addition to its wireless system, FireFly®.
Wireless systems, in particular, can be crucial to data acquisition in certain shale plays where cables are too bulky and cumbersome – not to mention potentially destructive.
Brooks points to the Marcellus play in the northeast United States, which he says is a tough area topographically for seismic operations. Depending on the play, cable-averse situations include tree cover, small land parcels and proximity to populated urban areas.
Even in the fairly wide-open western United States, rugged terrain can be near impossible to traverse with a load of heavy, cumbersome cables.
“The critical consideration for a wireless system has been for customers to verify through use the performance claims,” Brooks said. “That appears to be happening.”