In March 2011, Statoil revealed that after extensive logging and examination of preliminary results for the Kiwi well drilled with the Discoverer Americas drillship in Egypt’s El Dabaa Licence (block 9) west of the Nile Delta that the well was dry and that the drilling ship is on its way back to the Gulf of Mexico.
In Cuba, a reportedly $17m wildcat offshore project by Petrobras’ Cuban subsidiary Brasoil and Sherritt International to explore for hydrocarbons off Cuba’s north-central coast in under review after a well also came in dry. In a brief statement Brasoil said that “although reservoir quality rock was encountered while drilling, the operator has no plans to test at this time. Structural information gained from the well shall be incorporated into a reevaluation of the structure to decide the best forward plan.”
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In February 2011, the Norwegian Petroleum Directorate said that a wildcat well drilled by Aker Barents in the Ormen Lange field in the Norwegian Sea is dry and will be plugged and sealed.
As these companies found out, the risk of coming up dry is all to real and so are the consequences. The answer, however, might well come down to technology and the ability to accurately ‘predict’ and model the scenario. High rewards, however, are never likely to involve low risk, but how close are oil companies to stacking the odds in their favor?
Electro magnetic imaging
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The deployment of electro magnetic (EM) imaging technology for offshore hydrocarbon exploration also know as seabed logging (SBL) is becoming an increasingly popular addition to traditional seismic surveying with some companies reporting that the combination may reduce the odds of drilling a dry hole upwards from one in four.
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By GlobalDataHeadquartered in Trondheim, Norway EMGS ASA (EMGS) offers a range of EM services including, data acquisition, modeling, processing and integration and interpretation. EMGS says that its surveys have correctly predicted the fluid levels in reservoirs in over 90% of the cases where the company has drilling results and says that EM data fits well with seismic data.
According to EMGS the first commercial depth migration of EM data was undertaken in 2004 and represented a significant milestone as the data could be correlated with seismic and other available geographical information.
EMGS spokesperson Chris Guldberg Said that “Shell and EMGS have a JIP (joint industry plan) to plan and design the next generation of 3D (three dimensional) marine CSEM (controlled-source electromagnetic) source, receiver, and positioning system.”
“This project aims to provide a step change in CSEM surveying’s depth of penetration and resolution. The hope is that the next-generation system will at least double the number of hydrocarbon prospects that can be evaluated with CSEM,” said Guldberg.
Building expertise and confidence in CSEM is key according to EMGS, “The main challenge for oil companies lies in retrieving the value it can add to exploration, particularly in combination with seismic and other data,” said Guldberg. “Several companies have developed internal marine CSEM expertise and built up confidence in its use through experience and internal research. Several more companies are close to achieving this level of confidence.”
EMGS deploys purpose built EM vessels with experienced CSEM personnel to acquire data. The modeling can be 2D (two dimensional) or 3D, depending on the cleints needs, with the capability to make 70 trillion calculations per second. In terms of integration and interpretation, the company says that the depth converted 3D CSEM data can be co-rendered to asscertain if the acoustic and resistivity hydrocarbon indicators coincide or it can offer a more sophisticated CSEM inversion using well-log and seismic data to produce one model for all the data in SEG-Y format.
The challenge of new technology
In regard to operational challenges, Guldberg is confident, “We have overcome most of the operational challenges. Originally, EM was percieved as a deep water technology. Technology developments have enabled us to move into shallow water, and we have now performed surveys in water depths ranging from approximately 30m to 3500m.”
Oil and gas companies however, are notoriously conserative in their ways and take time to adopt and adapt a different way of working. “EM is still a relatively new technology in the offshore oil and gas industry,” said Guldberg. “Industry adoption will continue to pick up when more companies see the advantages of integrating CSEM, seismic, well-log, and other data. Recent technology innovations have expanded the application of 3D EM beyond traditional de-risking of drilling decisions and into areas like frontier scanning, shallow water applications, delineation and appraisal, as well as imaging of high resistive geological layers such as salt and basalt.”
One issue that has come up is that the sun is entering a period of high activity over the next few years, geomagnetic storms, some possibly severe, will be more common and navigation systems and geologic exploration, power grids and more could be affected.
Guldberg says that such storms are not a problem. “We have acquired more than 16,000km² of 3D EM data in the Barents Sea, where geomagnetic storms are most frequent,” said Guldberg. “In other words, this is not a problem, largely due to the fact that we have an accurate, high-power source.” Guldberg said that EMGS’ Marine Magnetotelluric (MT) surveys are ideal for areas that are susceptible to geomagnetic storms. EMGS says that MT is an especially useful technique for areas where the topography has, “High-impedance volcanic rocks or salt make the interpretation of other geophysical data challenging.”
With the easy-to-get hydrocarbons largely found and exploited, finding the deep and/or the unconventional offshore resources that are more expensive to locate using EM techniques properly applied alongside conventional technology could swing the odds against coming up dry.
