American Oil and Gas Reporter - January 2012 - 112

Tech Trends 2012
One of the key goals of geophysical analysis is to identify
"sweet spots" and understand how to best exploit them with the
drill bit. However, it did not take long in shale plays to realize
that sweet spots differed radically between conventional and unconventional reservoirs. In conventional geologic settings, sweet
spots are defined by pay quality, traps and sealing mechanisms.
The primary value-adding role of seismic imaging in conventional fields is in the exploration phase, or finding reservoir targets
and delineating the best locations to drill them. Finding and drilling
cost tends to be the largest component of total well cost.
In unconventional plays, however, the sweet spot is defined by
fracture orientation and the degree of fracture intensity within a
dense, ultralow permeability shale or tight sand. In these plays,
the key issue is not finding reservoir targets, but understanding how
to design drilling plans to intersect natural fractures at optimal points
within the formation, and aid in completion and stimulation strategies to maximize the stimulated reservoir volume (natural fractures plus hydraulically induced fractures). Completion cost usually represents the largest percentage of total well cost in unconventional reservoirs. In the Eagle Ford Shale, for instance, frac costs
are estimated between $3 million and $5 million a well, accounting for 60 percent or more of total well cost.
In a practical sense, the reservoir is "created" in unconventional plays by enhancing pathways for production, which means geophysics is focused on imaging extremely subtle features within
the rock matrix that act as controls on production. This key difference has led to innovations in applying seismic technology to
FIGURE 1
P-P and P-SV Arrival Times and Reflectivity
0

Azimuth (degrees)
80
120

160

1.0

Time (s)

1.2

1.4

1.6
1.8

Time (s)

2.0

2.2

2.4

Azimuth-dependent P-P arrival time and reflectivity from fractured
carbonate targets A and B are shown in the top panel, while the
bottom panel shows azimuth-dependent P-SV arrival time and reflectivity from the same targets. P-P reflectivity changes little with
azimuth, but P-SV reflectivity varies significantly.

112 THE AMERICAN OIL & GAS REPORTER

define drilling and completion strategies in unconventional
plays. For example, the required level of imaging detail has driven the uptake of high-resolution, high-channel count land 3-D surveys, while the need to assess the effectiveness of hydraulic fracturing treatments has made real-time microseismic imaging a routine tool. Interestingly, these innovations are delivering benefits
already in conventional settings as well.
Shear Waves
Success in shale plays comes down to how well natural fractures can be identified. Consequently, there is great value in any
technology that helps recognize the presence of fractures, determine their azimuth orientation, and provide a means to categorize areas with high or low fracturing intensity.
Multicomponent seismic technology is one such technology.
Seismic sources generate three fundamental wave modes: compressional (P), shear horizontal (SH) and shear vertical (SV). Historically, the industry has focused almost exclusively on P and
largely ignored shear. Yet, it is well established by laboratory measurements and case histories that shear waves are far more sensitive to the presence of fractures than P waves.
Seismic waves can be thought of in terms of how each wave
mode displaces the earth as it propagates through bulk layers. To
put it simply, a P wave senses the earth's fabric in a vertical direction, whereas shear energy senses the fabric of the earth in a
horizontal direction. When a shear wave encounters fractures,
which are more vertical than they are horizontal (intersecting fractures is a key reason wells are drilled horizontally perpendicular to frac systems rather than vertically in the same direction),
it reacts to the presence of the fracture far more than does a compressional wave. Consequently, because S waves primarily
sense horizontally, shear energy is better at detecting natural fractures and reacting to their properties.
If structure is the only concern, as is the case in many conventional carbonate oil fields, operators can get by with only P-wave
analysis. But for a well that is a stratigraphic trap, one must understand lateral changes in rock properties, which are independent of the structure. Elastic wave field seismic stratigraphy applies exactly the same interpretation principles to two sets of data-P
and S wave responses-and the resulting integrated analysis provides a better definition of the rock distribution, facies distribution, depositional environment, etc.
Shear waves are a little more challenging to acquire and process
than are P waves, but the fact that they react differently to vertical fractures underscores the importance of multicomponent seismology in unconventional settings. Companies are beginning to
find that reservoir characterizations are more accurate in conventional reservoirs when both P and S waves are interpreted, regardless of the type of rock system.
Fracture Intensity
Fracture intensity is critically important in unconventional plays
for both short-term initial productivity and longer-term reserves recovery. It is almost always better to drill in an area where
fractures are more numerous and spaced more closely. Shear waves
are able to distinguish areas of high fracture intensity. When a
shear wave illuminates a fracture interval, it splits into two "daughter" modes: fast and slow (unlike a P wave, which does not split).
The particle displacement vector of the fast shear mode is ori-

American Oil and Gas Reporter - January 2012

Table of Contents for the Digital Edition of American Oil and Gas Reporter - January 2012