By Arthur Thompson, retired EPRCo Scientist
A new technology offers the potential to do what classical, oil-exploration technologies cannot: detect the presence of mobile hydrocarbons in porous rock with seismic spatial resolution.
Seismology is the workhorse of hydrocarbon exploration. Before any wells are drilled, seismic studies reveal rock structures that might trap hydrocarbon fluids. Electromagnetic methods have relatively poor spatial resolution, but they are used to high-grade hydrocarbon prospects by identifying high-resistivity zones associated with resistive, hydrocarbon fluids. With input from geology, and possibly gravity and magnetic surveys, a plausible case can be made for the existence of viable reservoirs. However, these surveys taken at the Earth’s surface, do not directly detect hydrocarbons; they do not distinguish between oil, gas, and water; and they do not determine if there are mobile pore fluids. These methods locate rock structures that are possible hydrocarbon traps, and they measure the electric, magnetic, and density properties.
A new exploration technology locates mobile hydrocarbons through the coupling between electric currents and seismic waves. There have been speculations for decades that seismic waves generate electromagnetic responses. It is supposed that seismic pressure gradients create motion of charged fluid in pore spaces. This motion creates time-varying electric fields. Electromagnetic signals occurring contemporaneously with or prior to earthquakes might originate in such fluid motions. However, some published laboratory and theoretical studies concerning hydrocarbon exploration conclude that signals from seismic-to-electromagnetic (SE) conversion at reservoirs are too small to be useful. Recent field tests show that these predictions are too pessimistic.
ExxonMobil supported research on electromagnetic-to-seismic (ES) coupling over several decades. Thompson and Gist detected both SE and ES conversions from 300-meter-deep gas sands. Thompson et al. imaged gas accumulations 1000 m deep and oil reservoirs in carbonates 1500 m deep. These field studies were limited by the state of supporting technology, particularly seismic sensors immune to electromagnetic pickup and programmable, high-power electromagnetic sources. Recent advances in technology, combined with the experience gained in the field tests, make it feasible to gather data from deeper targets with substantially less effort than was required before 2007.
The signals measured in the field are orders of magnitude larger than predicted from either laboratory measurements or theories based on microscopic fluid motions. When the overburden resistivity is the order of a few ohm-meter or larger, ES coupling may be useful to depths of 5000 meters. ES conversions have limited use in high conductivity basins such as the Gulf Coast, where the electromagnetic attenuation is large.
There is strong evidence that the converted ES and SE signals occur at twice the frequency of the source waveform and may contain other harmonics of the fundamental frequency. Harmonics of the source fundamental frequency are generated when conversion occurs at the interface between reservoir rock and adjacent rock. Such an interface contains a gradient in compositions for both the rock matrix and the pore fluid. The physics is exactly analogous to the p-n junction in semiconductor physics. The gradient in compositions produces an internal electric potential gradient that couples to an applied electric field. Just as for a p-n junction or transistor, an AC current is rectified, and internal stresses alternate during an AC cycle. The alternating internal stresses produce seismic waves. The ExxonMobil work finds that electrical inhomogeneity in reservoirs and the internal electric fields at boundaries between different kinds of rock can increase the ES coupling efficiency by several orders of magnitude.
The nonlinear, frequency-doubling of electroseismic conversion is a qualitatively new observation in geophysics that could have broad implications. Frequency doubling increases the spatial resolution of the image and should occur in electromagnetic surveying and in spontaneous potential logging.
Large ES amplitudes require both high resistivity and mobile fluid. When resistive hydrocarbon displaces saline solution in pores, the ES amplitude increases by a factor of 100 to 1000. Reservoirs generate high amplitude conversions when the signals from deep aquifers are too small to detect. When there are mobile fluids, an applied electric field polarizes internal electric fields, changes the internal stresses, and generates a seismic wave. When pores are so small that fluids are immobile, the polarization is suppressed, and the amplitude is reduced. Granites, shale, and other tight rock do not yield large ES signals. No other remote detection method or combination of methods is sensitive to these variables while providing seismic resolution.
ES amplitude is not sensitive to the rock compressibility. A hard rock, such as a carbonate, that has good permeability and hydrocarbon saturation will respond with large ES amplitudes. Seismology is relatively insensitive to the presence of hydrocarbon in hard rock because the seismic properties are dominated by the matrix properties, independent of the pore saturation.
The ES amplitude is further enhanced when there is gas in the pore space. So the identity of the pore fluid may be revealed by the amplitude of the ES conversion. The ES amplitude from oil is much larger than that from water. The amplitude from gas is larger than oil, and the seismic amplitude from gas has a distinct angular dependence.
On land, the logistics and costs of electroseismic surveying are similar to seismic surveys. As techniques are improved, it is anticipated that ES surveying will be less expensive than seismology because operating the electromagnetic source is less expensive than operating vibrators, and ES surveying requires a smaller footprint on land. Off-shore applications are feasible, but they are untested.