Careful, careful … The environmentally sensitive regions of the American West are sparking increasing interest in new cable free seismic systems.
Take a field rife with infrastructure and in a particularly sensitive environment, deploy a cable seismic system and…
Ouch!
The data acquisition process can be unbelievably tedious – and the imaging maybe not the greatest.
As a result, companies are showing increasing interest in new cable free systems.
In addition to commercially proven nodes for marine acquisition, cable-free land systems, such as Fairfield’s Z Land and ION’s FireFly, are also generating buzz among the industry players.
A world-first deployment of cableless full-wavefield single sensors in a 3-D onshore seismic survey took place in the winter of 2006-07 at the BP-operated Wamsutter Field in Wyoming.
The operation used the FireFly system and was part of a seismic field trial that also included the largest onshore U.S. 3-D VSP, according to AAPG member Craig Cooper, land seismic project coordinator for North America gas business unit at BP.
The field trial’s intent was to test the viability of emerging seismic technologies and to enhance understanding of the value of seismic data as a development tool for reservoir and fracture characterization – not just in the Wamsutter Field but in tight gas plays in general, Cooper noted.
Made-to-Order Locale
When you consider the challenging scene – Wamsutter is a heavily developed active field, and Wyoming is a kind of environmental hot-bed – this is a made-to-order locale to test an acquisition system sans cables.
The primary reservoirs at Wamsutter are the Cretaceous Almond sands, which have a gross interval thickness of 500 feet and occur at an average depth of 10,000 feet.
In the locale of the seismic action, the Almond play is a heterogeneous, thin-bedded reservoir comprised of lower coastal plain shallow marine sands, shales and coals. This makeup presents a complex challenge to well-based predictions and to seismic imaging in the inter-well areas, according to AAPG member Rosemarie Ramkhelawan, senior geophysicist at BP.
The first order of business at the field trial focused on the 3-D VSP, which was acquired in a single borehole.
“The shot coverage was almost the same as the full seismic survey,” Ramkhelawan said. “What makes it 3-D is, instead of just shooting a line of shots, they shot a big areal patch of shots into a single borehole that had many, many receivers in it.”
The VSP was acquired with 8,000 feet of receiver tool having 160 3C geophones spaced 50 feet apart, from a depth of 2,500 to 10,500 feet, according to Ramkhelawan.
“This is the largest geophone array ever deployed in a single borehole,” she said, adding that the data processing using all three recorded components resulted in excellent quality P-wave imaging.
“The achievable bandwidth is double that of the surface seismic, allowing more detailed mapping of the internal character of the Almond interval,” Ramkhelawan said. “Nine surfaces are interpretable on the VSP data within the Almond interval compared to four to five on the surface seismic data.”
Making Informed Choices
The surface survey using the FireFly system and 3-component VectorSeis sensors was implemented by Global Geophysical Services and was centered on the VSP, covering a circular area of approximately 28 square miles.
The uncooperative participant was Mother Nature.
“There were challenging conditions,” said Alex Calvert, full-wave land R&D manager at ION. “Usually Wyoming is dry, but that winter it snowed significantly.
“This slowed things a bit,” he added, “but they still were able to acquire the full survey in less than 10 days of shooting time.”
Despite the challenges that included high winds generating significant noise and battery depletion associated with burial beneath the heavy snow, the operation successfully delivered a unique high density, full azimuth, full wavefield data set for analysis, according to Calvert.
A processing flow was designed to provide BP with a quick early look at the data and also to test a number of emerging technologies.
One of these is OVT (offset vector tiling), which preserves offset and azimuth integrity.
“This (OVT) has actually been around since the early ‘90s,” Calvert said, “but hasn’t really taken off.
“I think there are a number of reasons for that,” he said, “with one of them being that some of the surveys at the time weren’t dense enough to sort in the OVT domain – but this one was suitably dense.
“Also, the processing tools that were around at the time weren’t well suited to the sort of wide azimuth data sets this processing approach produces,” Calvert added.
He noted there is a growing realization that azimuthal anisotropy, which is the variation of seismic velocities as a function of direction, can provide insights into potential fractures that control well recovery and also stress that controls well fracing.
“OVT lets you analyze this azimuthal anisotropy after migration, and that’s potentially very valuable to the clients,” he said. “That takes out some of the first order structural effects that can be a problem.”
Ramkhelawan noted that the field trials enabled BP to study the seismic response, understand how the reservoir heterogeneity was setting up the response and to make informed choices around how and where to employ enhanced seismic imaging as a tool.
This knowledge is looked on as a large step change for the asset.
“It has been one of a number of factors enabling BP to move to a pad development approach,” Ramkhelawan said, “batch drilling the low risk areas of the field and releasing skilled resources to focus on the higher risk, more complex opportunities around the core area.”