Figure 1. EMGS has improved EM receiver technology using experience from more than 230 commercial surveys and 8,000 receiver deployments. Advances like extended dynamic range detection, ultra-low noise electronics and horizontally-rigid arms extend water- and target-depth capability. Dissolvable anchors minimize environmental impact and remove potential seabed hazards following a survey. (Photo courtesy of EMGS)
Since the Schlumberger brothers first ran an electrical wireline log in 1927, this type of measurement has been a common tool for oil and gas exploration. Sending an electrical pulse into the earth and measuring the relative resistance within certain formations gives log analysts a better sense of where the hydrocarbons are hiding.

Turning a log-scale measurement into a reservoir-scale survey would take several more decades. But 80 years later a few enterprising companies offer this type of survey. And the information they’re acquiring could have a revolutionary impact on success rates in the future.

History
The most commonly used methods of measuring resistivity, generally termed electromagnetics (EM), fall generally into two categories, magnetotellurics, a passive measurement using the earth’s natural electrical field as a source, and controlled-source electromagnetics (CSEM), using sources towed near the seafloor as the electrical source. It is CSEM that seems to have taken the industry by storm.

Sifting through the complex past of this technology is likely to ruffle some feathers since at one point most of today’s fierce competitors were colleagues working on a common research project. Len Srnka at ExxonMobil was awarded a patent in the 1980s, but much credit goes to Terje Eidesmo and Svein Ellingsrud, who in the late 1990s pioneered the first successful application of CSEM for the detection of hydrocarbons.

“They had been doing borehole logging, and they noticed that when they were logging horizontal wells they were sometimes seeing farther into the formation than one would expect in a vertical well,” said Mark Wilkinson, president of EMGS Americas. The two men determined that it would be possible to put receivers on the seafloor, deploy a source and find hydrocarbons.

Statoil applied for a patent in 1998, and in 1999 Eidesmo and Ellingsrud approached Steven Constable at Scripps Institute of Oceanography to review a new method they were calling seabed logging. Constable noted that several universities and institutes had been working on seafloor EM for non hydrocarbon-related studies, but that the method proposed for hydrocarbon detection was a novel concept.

A full-scale trial led by Statoil took place over the Girassol field offshore Angola in 2000. This was successful, and the first patent was awarded in 2001. The towed source was supplied
by Southampton University. Scripps provided many of the receivers based on its work with AOA Geophysics.

Figure 2. EMGS has engineered a 1,250 ampere signal strength source coupled with fully customizable output wave shapes and GPS positioning to help detect hydrocarbons deeper than weaker sources. Surface handling equipment ensures safe and efficient operations aboard EMGS’ four-vessel fleet. (Photo courtesy of EMGS)

One year later ExxonMobil commissioned an EM survey with equipment provided by Scripps, AOA Geomarine Operations (AGO) and the University of Southampton. Those results were also encouraging.

This may seem like a boring history lesson, but the players in this arena have since squared off to become the three major CSEM contractors in the industry. Statoil spun off its team, headed by Eidesmo and Ellingsrud, and that company is now EMGS. Some of the researchers at the University of Southampton are now lead scientists at Offshore Hydrocarbon Mapping plc (OHM). And AGO was bought by Schlumberger in 2004.



Figure 3. A 2-D CSEM resistivity cross-section corendered with seismic data from an OHM survey collected for Rockhopper Exploration, North Falkland Basin, 2006. A discrete resistor at the target reservoir level (1.5 km) is clearly mapped despite the nearby presence of shallow resistive basement and the complications of atmospheric effects due to shallow water. (Image courtesy of OHM)


The technology

The fact that less than 10 years has elapsed from first field study to full-blown commercialization says something about the excitement surrounding EM technology. While researchers can argue the finer points, the blunt reality is this — when the technology is appropriately applied and integrated with other data such as seismic, it can provide what seismic typically can’t — a direct hydrocarbon indicator.

It also works well in deep water. Combine those two simple statements, and the cost savings of not drilling dry holes in deep water fields begin to add up pretty quickly.
“I can’t understand anybody drilling a deepwater well without having applied this tool,” Wilkinson said. “The cost to do a seabed logging survey to confirm a drilling decision pales compared to the cost of drilling a deepwater well.”

The basics of CSEM are quite straightforward. Receivers are deployed on the seabed in lines or grids. The receivers are sensitive to the earth’s electrical and magnetic fields.
A dipole source connected by umbilical to a source vessel is towed about 100 ft (30 m) above the seabed emitting a low-frequency electromagnetic field. The energy radiates into the earth. In relatively conductive media (typical of deepwater clastic settings) the energy decays exponentially as it diffuses into the subsurface. When a resistive formation such as those containing oil and gas are encountered, the electromagnetic field is distorted, and the magnitude of this distortion contains information about the depth, shape and size of the resistive formation encountered. Seabed receivers measure these field distortions in terms of amplitude and phase changes in the received electrical and magnetic signals. After a set period of time, the receivers are triggered to float back to the surface, where they are recovered and their stored data downloaded.

At a very basic level it’s like taking a resistivity well log and laying it on its side. But while well logs penetrate a few feet, EM surveys must penetrate thousands of feet. Recent advances in the technology have pushed the boundaries of this depth of penetration, although very deep formations will still be imaged poorly.

On the other hand, EM data makes a nice complement to seismic data, which typically gives better vertical resolution than horizontal resolution. EM data may be depth-limited but can often delineate the boundaries of a reservoir with surprising accuracy.

EM companies insist that other data be integrated and that CSEM data are not meant to be a substitute for seismic. To that end, they offer services to help their clients integrate the data.

“Most companies don’t have much internal expertise in really understanding the strengths and weaknesses of EM data,” said Larry Scott, vice president of OHM. “They need to know how to meaningfully weigh those strengths and limitations against the strengths and limitations of well log data, seismic data, etc.

“When you’re working with our team, you don’t just get an image; you get an appreciation of how to risk this information against other information.”

Market acceptance and case studies
Industry acceptance has been quicker with EM than with some of its predecessors, notably 3-D seismic. But companies still struggle to convince their potential clients that the tool has merit.

“You’ve got some companies that have taken the technology onboard early on, and then you have the ‘show me’ companies who want to see someone else use it successfully first,” said Alastair Fenwick, sales and marketing manager for AGO. “Then you’ve got the ones who won’t use it until it’s fully developed.”

Figure 4. AGO navigation instrument room on the Toisa Valiant. (Photo courtesy of AGO)
Added Dave Pratt, chief executive officer of OHM, “It’s a fact that the oil industry is a slow technology adopter. It’s clear that with the industry being as busy as it is right now, people’s appetite and time to sit down and consider new technology is severely limited.
“But the back of the technology adoption has been broken. The conversations we’re having with oil companies are less about explaining how the technology works and more about how it might work in their particular geological problem.”

It was worse a few years ago when these companies were just forming. “When we started in 2002, we gave presentations where people fell asleep,” Pratt said. “We gave presentations where people laughed and compared us to witch doctors and various other unflattering things. I’m pleased to say that everyone has eaten their words.”

It helps to have a solid case study to back things up. OHM has been working with a small independent called Rockhopper in the Falkland Basin. Pratt said that many companies who have had success with CSEM have little incentive to share their stories because they view it as a competitive advantage. But Rockhopper didn’t have that luxury.

“They only operate in one basin, so the fact that we significantly de-risked the hydrocarbon potential of that basin was market-sensitive information for them, and they had to share it,” Pratt said.

He added that the EM data acquired over the area did a better job than the seismic of mapping the geological features of the basin.

“If you want to see the value created by a technology like EM, Rockhopper is a good case study because their share price effectively doubled when they announced to the stock market that they had encouraging results.”

EMGS has been fortunate to have majors like Shell and Statoil publish positive results about their surveys. Wilkinson said that in one case, Shell had a block in the Campos Basin and needed to make a drill-or-drop decision. EM data failed to find a resistive body in the block, allowing Shell to walk away without drilling a costly dry hole.

The future
Another case study led to an even more interesting find. A company had three structures of interest. Seabed logging confirmed that only two of them had a resistive signal. However, another resistive anomaly showed up on the EM data that hadn’t been imaged by the seismic survey.

EMGS has determined that this type of data could lead to a much more “frontier exploration” application for the technology. Using a concept they call “scanning,” they’re planning a move from tighter surveys meant to delineate known reservoirs to coarser surveys that look for general resistive anomalies that can later be delineated by tighter EM and seismic surveys.
“Imagine a world with no exploration risk,” Wilkinson said. “You would really like to know that the well you’re drilling is the well you should be drilling.

“If I could deliver to you chunks of data with the resistive anomalies highlighted, then you could combine that with your 2-D or 3-D seismic. The seismic would give you structure, and the EM would give a suggestion as to fluid content. It would radically change your view of that acreage.”

OHM is working on better integration with other forms of data. Last summer OHM and Rock Solid Images announced an initiative to integrate seismic and well log data with CSEM data.
“The objective is to develop frameworks for integrating EM with seismic and with well log information to give a quantitative answer to reservoir engineers that tells them rock and fluid properties,” Pratt said. “In our first project we worked on integrated seismic and EM over a shallowwater gas field in the North Sea. We were able to produce images that showed gas saturation within the reservoir quantitatively, and we tied those back to the well for calibration to give a very sensible piece of information that just hasn’t been available before.

“We’re doing commercial work based on that early research project. But we’re still at the beginning of a very long road.”

AGO has taken a more studied approach, working with its clients on proof-of-concept studies to raise their comfort level with the technology. But Fenwick said that AGO’s integration with both Schlumberger and WesternGeco will have it well-positioned for the future.
“It makes sense being a part of Schlumberger because the company has 75+ years of experience using EM in the borehole,” he said. “That knowledge of the subsurface is a good match with the technology at AGO. We’re able to take advantage of their worldwide research and development resources as well.”

WesternGeco brings vast experience in seismic acquisition and processing, and while Fenwick said they’re not likely to be doing seismic surveys and CSEM surveys off the same platform, their expertise with running multiple crews, deploying equipment, etc., gives AGO a big advantage. CSEM data could be incorporated into WesternGeco’s multiclient seismic database in the future.

AGO, jointly with WesternGeco, is currently enhancing its Gulf of Mexico multiclient seismic database with the integration of marine magnetotellurics (MMT), which better defines the salt bodies and therefore improves the final imaging.

“The main benefit of EM is that it reduces the uncertainty and therefore drilling costs,” Fenwick said. “It will result in fewer dry holes. We just need
to convince the industry that it’s a worthwhile tool.”
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