Amazing how quickly the industry can become accustomed to what is still arguably brand-new technology. Wide-azimuth acquisition? So six months ago. Reverse time migration? Been there, done that.

ION’s Intelligent Acquisition [IA] Arctic solution was recently deployed from Octio’s GeoExplorer in Northeast Greenland. (Image courtesy of ION)

This is not to imply that these technologies aren’t adding incredible value to the geophysics toolkit. It’s just that we’ve been hearing a lot about them over the past couple of years.

So this year E&P asked geophysical researchers to tell us what’s really new and cutting-edge. Mind you, the technologies and methodologies listed below are the tip of the iceberg. But they are representative of the next wave of exploration technologies that will continue to make oil and gas just a little easier to find and produce.

Marine acquisition

Where to start? The marine environment has been undergoing tremendous scrutiny when it comes to acquisition techniques.

Marine Vibroseis. One of the more interesting developments being undertaken by several companies as well as a joint industry program (JIP) is the possibility of using marine vibrators rather than airguns as a seismic source offshore.

WesternGeco’s Continuous Line Acquisition process saves considerable acquisition time. (Image courtesy of WesternGeco)

The JIP, organized by the International Association of Oil & Gas Producers, is studying this possibility at least in part because of the concern about the impact of airgun noise on marine mammals. While studies remain inconclusive, these concerns include interference that could lead to behavioral changes, strandings, hearing loss, communication problems, and undesirable effects on fish populations and other ecosystem populations such as plankton.

Marine vibrators would be placed on the seabed much the way a Vibroseis truck sits on the ground in land acquisition. Environmentally these sources have the

potential for less impact. Tests to date indicate excellent source-signature stability in shallow water as well as repeatability, important for time-lapse work.

This figure is from Sambell et al 2009 showing the preliminary results of the high-density wide-azimuth survey acquired by CGGVeritas: The vintage seismic section (right) is compared to “state-of-the-art” processing applied with a preliminary prestack time migrated section (left) from the new WAZ survey. (Image courtesy of PDO and CGGVeritas)



Technical issues include poorer low-frequency performance than airguns and masking, and there is also a debate between a hydraulic system and an electric system.
Also, availability and high start-up costs are a barrier.

Arctic acquisition. In recent years, the Arctic region has emerged as an area of renewed exploration interest. By some estimates, the Arctic contains upwards of 30% of the world’s remaining undiscovered hydrocarbon resource base. E&P activities have never been easy to conduct in the Arctic, and seismic is no exception.

Harsh weather conditions provide a narrow weather window for acquisition operations, and even then ice can wreak havoc with streamers and introduce unwanted noise into any seismic datasets that are acquired.

ION Geophysical has taken an integrated approach involving new acquisition technology, navigation and positioning software, and data processing techniques. The methodology has been successfully field-trialed in a just-completed regional seismic program offshore Greenland with the backing of several of the world’s largest oil and gas companies.

According to Joe Gagliardi, ION’s manager of Arctic program development, “The challenges of undertaking geophysical programs in the Arctic cut across all aspects of the seismic workflow and, as a consequence, require an integrated approach. We’ve been undertaking regional seismic programs in the Arctic for the last several years on behalf of major E&P operators, and we had some ideas about what might work.

Figures a and b show the separation of the P mode using conventional derivative operators and the anisotropic spatially varying pseudo derivative operators, respectively. 4a shows the residual S wave mode (at coordinates x = 13 km and z = 7 km) in the P panel, caused by the strong reflections from the salt bottom. In contrast, 4b shows no wave mode residual. These wavefields, composed of well-separated P and S modes, are essential to producing clean seismic images. (Images courtesy of Paul Sava and Jia Yan)



“We knew several highly prospective areas of the Arctic had been bypassed by seismic acquisition due to the risk posed by operating in the presence of ice. We believed there was a real opportunity to unlock, but only if we were to develop a solution custom-designed for the Arctic. We found the perfect field trial opportunity during our regional BasinSPAN seismic program offshore Greenland.”

The first challenge is to protect sensitive seismic equipment from the ice itself. Although a Polar Class icebreaker is used to clear a path for the seismic vessel following behind it, chunks of ice still remain in the wakes of the boats. The company designed a proprietary towing arrangement that deflects any free ice from the path of the streamer cables. With the path cleared for the streamers, streamer steering technologies ensure that the cables stay in the “fairway” of open water.

Other elements include a solid streamer cable that is less prone to failure in cold waters and to buoyancy loss at deeper tow depths than conventional foam-matrix cables as well as streamer positioning systems that use specially designed high-declination compasses that are less susceptible to the inaccuracies of operating near the northern magnetic pole.

Processing enhancements also have been made. “We’ve extended the pre- and post-shot listen times by 10 seconds in our recording system, which allows us to record the noise associated with breaking ice,” Gagliardi said. “By recording the noise, we can separate it out of the wavefield and better isolate the desired signal during processing. In addition, we’ve pioneered some other techniques over the last several Arctic shooting seasons that now allow us to remove the back-scatter or ‘ice multiples’ that occur when the source energy reverberates off the underside of pack or floating ice near the surface.”

Continuous line acquisition. Sometimes technology benefits from a new way of deploying it. This is the case with WesternGeco’s Continuous Line Acquisition (CLA) methodology. As vessels traditionally spend up to 50% of production time in line change, CLA simply helps remove some of the dead time during vessel turns, resulting in faster and more efficient marine acquisition.

The ability to shoot through the turns is made possible by steerable streamers and processing enabled by single-sensor technology such as Q-Marine. “In the past, seismic streamers were formed from analog groups,” said Rob Ross, marine marketing manager for WesternGeco. “A number of measurements were hard-wired together within the streamer to form the information that was subsequently processed. That way of forming the group was adequate for attenuating some random noise and getting an improved signal-to-noise ratio on the cable.

“But for extreme environmental conditions such as rough weather, or when the turning of the cable created a crossflow in the current, the noise levels were very high.”

Single-sensor hydrophones are each digitized separately, enabling the contractor to characterize the noise as well as the signal better, Ross said.

Understanding the positioning of the cables during the turns has also been a barrier in the past. But new positioning solutions provide a higher number of ranges, offering more robust outlier detection and requiring less smoothing and filtering.

“Commercial application of CLA as a component of a rich-azimuth (RAZ) geometry has shown that data acquired in this manner can be acquired and imaged while offering substantial savings to customers,” Ross said.

Typically, it takes more than 70 days to acquire just one single-azimuth 3-D and undershoot.?However, during a recent CLA survey for BHP Billiton in the Gulf of Mexico, the acquisition of the full RAZ dataset took only 100 days. “This shows considerable time saving capabilities,” said Ross. “A big factor in this efficiency is the conversion of the line change time to productive time.”

CLA is primarily intended for exploration and time-lapse baselines since reservoir monitoring depends upon a higher fidelity signal and exact repeats of baseline data are required, he added.

Fiber-optic permanent monitoring. PGS, on the other hand, has developed a system that is very much meant for reservoir monitoring. It has moved into the permanent monitoring, “life-of-field seismic” arena with its OptoSeis system, a fully fiber-optic solution meant to be permanently installed to provide cost savings in repeat surveys over ocean-bottom cable systems or nodes while also providing the shear-wave component of seismic measurements, which marine streamers cannot do.

PGS chose the fiber-optic route because these systems provide several advantages over conventional electrical systems. For one, they have a fully passive “wet end,” the array placed on the seabed over the reservoir. No in-sea electricity is required.

They also are capable of surviving longer periods of time in the field. The sensors are placed in fully molded housings/pads that are much less susceptible to water intrusion than electrical components. And the silica-based material of optical fibers is better suited to surviving a subsea environment than the metal components used in electrical systems.

The system has a high dynamic range, high signal-to-noise ratio, low cross-talk, and low cross-axis distortion. The PGS system also has the advantage of redundancy as well as not being susceptible to coherent noise from anywhere in the array other than at the sensors. System telemetry gives it a very high channel count per fiber, making it economical in large deployments.

“People should think of this as a real option to improve recovery from their reservoirs,” said Samir Seth, vice president fiber-optics in PGS’s Commercialization and New Ventures division. “It’s a chance to find oil bypassed in existing reservoirs as well as to optimize recovery from initiatives such as waterfloods, as it provides information about what has happened deep in the reservoir.”

Land acquisition

There have been various interesting hot trends in land. One has been the increased availability of cableless systems, which provide similar data quality to cabled systems but can be deployed more quickly and efficiently, particularly in tough terrain or in populated areas. Another move has been to vastly increase the channel count and acquire much denser surveys.

CGGVeritas is acquiring a survey for Petroleum Development Oman (PDO) that is one of a new generation of high-density wide-azimuth (WAZ) surveys. To achieve the geophysical objectives, the CGGVeritas joint venture in Oman and the wider Middle East region, Ardiseis, worked closely with PDO to create a “super crew” of 25,000 channels working 24 hours a day. The first results of this crew were presented by PDO Chief Geophysicist Bob Sambell at the recent European Association of Geoscientists and Engineers (EAGE) Conference.

The new survey uses a dense, wide-azimuth geometry with a 656- by 82-ft (200- by 25-m) receiver grid and a 164- by 164-ft (50- by 50-m) source grid, which gives a fold of 4,000 and useful crossline offsets. The resulting data, processed using the latest wide-azimuth techniques, gave what PDO quoted as a “spectacular improvement” in image quality, which has allowed the company to identify new prospects in the south of Oman.

The poor image quality of existing datasets drove the decision to establish this high-end crew. Typical vintage surveys had narrow geometries of four geophone lines with a fold of 100, sparse 164-ft inline receiver interval, and a sparse shot grid. This was not sufficient to provide adequate sampling of the signal and noise or adequate illumination and resulted in poor-quality images of the target.

“Dense WAZ techniques require an initial investment of more channels and vibrator fleets, but source-to-receiver ratios keep layout and pickup crews at the same levels as well as their necessary logistical support,” said Dave Kennedy, land acquisition quality manager with CGGVeritas. “Any additions come in the form of another shift in terms of personnel… Your day shift might consist of 350 personnel, while your night shift would only be 50 personnel. This allows a near doubling of production for just a relatively small incremental increase in the cost of personnel.”

In his EAGE paper, Sambell wrote, “A reasonable estimate of ‘return on investment’ from the expected additional discoveries would pay the cost of the survey 100 times over, and the proper structural definition of fields will lead to greater production and lower development costs… Technologically, only the surface has been scratched.”

Things are moving fast, and since the EAGE in June there have been further developments. In Oman CGGVeritas has implemented simultaneous single-vibrator acquisition on the current survey being acquired for PDO, which is setting new production records of more than 17,000 shots per day (with an average of 785 per hour).

Elsewhere in the Middle East, another CGGVeritas super crew equipped with 40,000 channels is acquiring the most densely sampled land wide-azimuth survey ever conducted. The geometry is far denser than current marine wide-azimuth surveys and provides unmatched wavefield sampling. It also uses a dense grid (394 by 25 ft or 120 by 7.5 m) of point receivers and high-performance vibroseis techniques to acquire shots on a 295- by 25-ft (90- by 7.5-m) grid, which is unprecedented. This remarkable survey has nearly 36 million traces per square kilometer, and recording operations are generating more than 2 TB of field data a day. Again, CGGVeritas will be using the latest wide-azimuth processing technology to realize the full potential of this data, and the results are eagerly awaited.

Processing and interpretation

As mentioned before, reverse time migration (RTM) has been a recent attention-getter because of its ability to better image beneath complex structures such as salt diapirs. But at the Center for Wave Phenomenon at the Colorado School of Mines, one focus is on making sense of multicomponent data. This requires elastic RTM, not the acoustic RTM that is currently being applied.

Dr. Paul Sava, an assistant professor in geophysics at the university, explained the difference. “Today’s technology uses acoustic waves,” he said. “If it’s boiled down to the core, it means that we treat the earth as a liquid. People have to do all sorts of acrobatics to bring this approximation closer to the real world. Thus, they tweak the liquid world to behave more like a solid. A little bit.”

The reality, he said, is that to understand things like anisotropy and attenuation, the earth must be treated like an elastic object.

Researchers exploring multicomponent seismic have known this for years, but they just now are developing the types of algorithms necessary to make this shift.

Meanwhile, the acceptance of this technology proves to be a challenge because interpreters get overwhelmed by the larger volume of data. They often wonder what they are really looking at, especially in complex geologic environments.

“I keep hearing that multicomponent is not always adding value,” Sava said. “The technology is less developed, and so people don’t get as much as they are hoping for out of it. Therefore, they don’t acquire as much multicomponent data, or they acquire them only in desperate situations. Breaking that downward spiral requires us to look at the technology and get the best we can out of multicomponent data, and that’s why we looked at RTM for elastic imaging.”

In an abstract for a paper that ran in Geophysics in 2008, Sava and co-author Jia Yan wrote, “In isotropic media, the vertical and horizontal components of the data commonly are taken as proxies for the P [compressional] and S [shear] wave modes, which are imaged independently with the acoustic wave equations. This procedure works only if the vertical and horizontal components accurately represent P- and S-wave modes, which generally is not true.”

Their suggested alternative uses the full vector fields for wavefield reconstruction and imaging. Multicomponent data are used as a boundary condition for a numerical solution to the elastic wave equation.

“For vector wavefields, a simple component-by-component cross-correlation between two wavefields leads to artifacts caused by cross-talk between the unseparated wave modes,” they write. “We can separate elastic wavefields after reconstruction in the subsurface and implement the imaging condition as cross-correlation of pure wave modes instead of the Cartesian components of the displacement wavefield.”

The process is not simple. “Of course, it requires more computers, more data,” Sava said. “There’s no free lunch here.

“Things become more complicated, but at the same time they bring us closer to the rocks because if we understand mode conversions, we understand more about the physical properties of the rocks.”