This year has been a busy one for oil and gas exploration. In addition to some truly mind-boggling discoveries (see shaded box), oil and service companies continued to push the limits of hardware and software technology to solve tough physics problems inherent in “looking” into solid material. Here is a snapshot of some of the major exploration technology advances in 2012.


Schlumberger unveiled the IsoMetrix marine isometric seismic technology and IsoMetrix family of marine seismic products in June, which output isometrically sampled point-receiver data in crossline and inline directions, capturing returning wavefield in 3-D.

According to the company, the new acquisition technology was developed through a 10-year research and engineering program to provide the most accurate images of the subsurface ever recorded. The IsoMetrix system uses calibrated, multisensory micro-electromechanical sensor technology with sensors measuring both acoustic pressure and vertical and crossline acceleration throughout the frequency range. It also facilitates high-resolution near-surface characterization, well integrity planning, and 4-D repeatability, and measurements are provided as customer deliverables.

WesternGeco researchers announced the first commercial job using simultaneous sources in a marine survey. Conducted by WesternGeco for Apache and its partners offshore Australia, the approach was characterized as “a complete revolution in acquisition technology.”

“With every additional source you put out, you increase the productivity of the seismic crew in a linear fashion,” said Craig Beasley, chief geophysicist for WesternGeco and a Schlumberger senior fellow. “If you shoot two sources, you collect twice as much data.”

Conventional versus IsoMetrix

Conventional (top) versus IsoMetrix (bottom) data are exhibited in a North Sea time slice. (Image courtesy of Schlumberger)

Apache first started considering marine simultaneous sources in 2010 while doing tests at the Forties field in the North Sea. The company acquired a test to understand the concept and to see if it was feasible. Those tests gave the company confidence to try the acquisition methodology in a commercial setting.

The survey was done on a single vessel usually configured with flip-flop sources. “It’s not what we would have predicted would be our first commercial job,” Beasley said. “But it’s pleasing to see the technology demonstrated in that challenging environment, because it opens the door for simultaneous sources in virtually any marine acquisition.”

CGGVeritas designed StagSeis to reduce E&P risk by providing illumination for the best seismic images in the most challenging areas where conventional wide-azimuth acquisition fails to image targets below complex overburdens. It employs a staggered multivessel design acquisition configuration producing ultra-long offsets up to 20 km (12 miles) and full-azimuth coverage up to 10 km (6 miles) for improved illumination. It is BroadSeis-compatible, adding enhanced frequency bandwidth, which will further improve deep imaging, according to the company.

ION has launched the Calypso next-generation redeployable seabed acquisition system, which the company said is designed to operate at twice the depth and deliver twice the operational efficiency of its predecessor system.

The system leverages tilt-insensitive multicomponent VectorSeis digital sensors that provide enhanced broadband seismic data, and it also features buoy-based recording; a rugged design capable of operating in 5 m to 2,000 m (16 ft to 6,562 ft) water depth; and an unlimited number of cables with twice the length (12 km to 24 km or 7 miles to 15 miles), which shortens cycle time and increases production.

To image an acquisition project in dense hardwood forests, Tesla Exploration Inc. selected INOVA Geophysical’s autonomous nodal technology, Hawk. After validating the Hawk system firsthand, Tesla purchased 10,000 Hawk stations (30,000 channels) configured to support up to three analog channels plus a digital VectorSeis 3-C sensor interface for its upcoming projects. The first project covered 207 sq km (80 sq miles) and required 7,200 Hawk stations. Because of Hawk’s lightweight frame, crews were able to transport the stations and batteries throughout the densely wooded region efficiently. The use of VectorSeis multi-component digital sensors further reduced station weight.

Silixa’s Intelligent Distributed Acoustic Sensor (iDAS) and ULTIMA Distributed Temperature Sensor provide the opportunity to connect borehole measurements to the reservoir by means of a single unobtrusive sensor (i.e. fiber-optic cable) installed in the wellbore.

The fiber-optic sensor assembly typically includes a single-mode fiber used to measure acoustic responses from seismic sources. Silixa’s iDAS data acquisition system has the ability to sample a 10-km (6-mile) fiber at 10 kHz, which equates to one acoustic measurement per 1 m (3 ft) of fiber, creating up to a 10-km long fiber-optic acoustic array. The fiber-optic acoustic array has the potential to be used like a continuous string of mechanical geophone receivers placed along the entire length of the well to measure changes in formation fluid saturations or image subsurface geologic structure. Standard seismic sources are used to generate the acoustic signal in a nearby well or at surface and are detected by the distributed fiber-optic sensor assembly. The high-density fiber-optic array has an order of magnitude greater spatial resolution than is typically recorded using standard seismic receivers, because of cost limitations. Once the fiber-optic assembly is installed, cross-well seismic, vertical seismic profile, and 2-D seismic surveys can be performed on demand as required.


The Wiband seismic data processing technology developed by ION Geophysical Corp.’s GX Technology group provides structural and stratigraphic high-resolution images through the use of conventional towed streamers. According to ION, the new Wiband broadband solution is not deterred by source or receiver notches (or “ghosts”) in the frequency spectrum that typically limit image resolution in marine exploration. The technology does not introduce phase distortion and instead improves images by reprocessing legacy or new acquisition data.

“We take advantage of the properties of the ghost,” said Nick Bernitsas, senior vice president of ION’s GX Technology group. “These properties are somewhat predictable. We can use those properties to then eliminate the ghosts.” He added that the new processing technology will give operators the opportunity to reprocess legacy data.

Using a model-based inversion, Geotrace is computing accurate compressional velocity (Vp), shear velocity (Vs), and density. From these quantities, it is further possible to calculate Young’s modulus and Poisson’s ratio, which in turn are used for describing brittleness and ductility in reservoir rocks. Brittleness and ductility are of chief interest in organic shales where hydraulic fracturing is necessary to produce hydrocarbons.

Model-based inversion uses a global optimization algorithm to solve the least-squares problem by minimizing the difference between the recorded seismic data and modeled seismic responses of an initial earth model with rock properties Vp, Vs, and density. The initial earth model is created from Vp, Vs, and density logs, as well as calibrated seismic velocity fields, which are propagated through layers that define zonal boundaries identifiable in the seismic data. The inversion then computes the initial modeled responses based on full Zoeppritz equations and its linearized approximation to model the seismic wave energy partitioning between two layers of different rock properties. The final earth model is obtained through optimized iterations until the convergence criteria have been met. Once the model is final, other elastic moduli, Young’s, shear, bulk, Poisson’s ratio, Lam?’s, and P-wave modulus can be computed for rock and fluid prediction, prospect evaluation, reservoir characterization, and fracture description.


Transform Software and Services launched its analytic interpretation and modeling (AIM) system. Built on a variety of proprietary algorithmic and technological enhancements, AIM represents a new approach to optimizing petroleum exploration and field development decisions.

AIM is powered by TerraSuite, Transform’s multiuser, multidiscipline E&P software platform. Transform has leveraged the capabilities of analytics seen in financial, sports, and consumer markets to create streamlined workflows specifically designed to address the complexity and subtlety of modern conventional and unconventional reservoirs.

By taking a unified approach to statistics, pattern recognition, automation, visualization, and more, AIM contributes to several business efficiencies, including reduced cycle times, better use of human and capital resources, and superior understanding of subsurface characteristics and reservoir performance.

Landmark’s DecisionSpace Geology software gives mainstream geologists access to tools that promise to revolutionize operational geology workflows. In addition to traditional correlation, cross-section, and mapping tools, DecisionSpace Geology combines classic geologic concepts in sequence stratigraphy and structural geology with automated processes that enhance quality and efficiency. New Dynamic Frameworks to Fill capabilities enable geologists and geophysicists to build a geometrically correct 3-D framework model while they are interpreting. All geological and geophysical workflows leverage this integrated, multisurface framework, which incorporates tools such as conformance technology, an advanced topology engine, and dynamic updating.

Paradigm has developed EarthStudy 360, a method to recover azimuthal seismic data in situ, in depth, and with full amplitude coverage of more than 360°. The tool recovers full-azimuth data at subsurface locations in a similar way to how borehole tools sample formations. Two distinct “decompositions” of the recorded wavefield (full-azimuth reflection angle gathers and full-azimuth structural gathers) produce images of the subsurface that can be used by interpreters to better understand anisotropy, stress and fractures, small-scale discontinuities, and even geomechanical properties derived from transformations of amplitude data.

Hampson-Russell Software and Services’ HRS-9 software suite features new architecture that includes a common intuitive interface and data management system to improve custom workflows. The software interface acts as a dashboard, integrating all functionality from previously separate programs into a single application. Additional advancements include multi-threaded 64-bit computing, allowing for the managed use of multiple CPU cores; batch processing for optimum resource scheduling; and the ability to crosslink output and input processes.

ffA has released the GeoTeric seismic interpretation workflow software to improve decision-making while processing, interpreting, and modeling large volumes of seismic data in less time. The 3-D seismic software can be applied in conventional and unconventional reservoir analysis to directly translate geophysical data into geological information, while making interpretation workflows more efficient. The GeoTeric suite features the Adaptive Geobodies technology used to extract 3-D geobodies in areas such as braided channels or karst systems, where it would be impossible for other conventional seismic interpretation techniques.


Schlumberger added the Litho Scanner high-definition spectroscopy service to its Scanner Family rock and fluid characterization services. The Litho Scanner service measures an enhanced suite of elements, including carbon, magnesium, and aluminum, in real time to help provide a detailed description of complex reservoirs, including unconventional, shaly sand, and carbonate. In addition, this latest wireline service provides a standalone quantitative determination of total organic carbon, critical for the evaluation of shale reservoirs.

Schlumberger also introduced the Saturn 3-D radial probe as the newest module for the MDT modular formation dynamics tester. With the Saturn probe, customers can now obtain pressure measurements and fluid samples where they were not previously possible, due to reservoir conditions.

The Saturn probe is comprised of four elliptical suction probes mounted at 90° intervals circumferentially around the tool, providing the largest surface flow area of any probe in the industry – more than 500 times that of a standard probe.