Page 72 - Geology of Carbonate Reservoirs

TERTIARY ROCK PROPERTIES 53

period is called the relaxation time and is typically known as the T2 relaxation time.
An advantage offered by this log is that measurements of relaxation time in liquid -

filled pores are a measure of the volume of liquid in the pores. The total liquid
volume represents total porosity. Additionally, the liquid volume represents the pore
volume that, if samples of the reservoir rock are recovered and examined under the
microscope, can be compared with measurements of pore geometry. Pore geometry,
the size and shape of the pores in two dimensions, can then be classifi ed according
to the triangular, genetic classification of carbonate porosity in order to provide a

geological origin for different reservoir pore types (Genty et al., 2007 ). Ultimately,
reservoir zones with dominant pore types can be identified and related to the geo-

logical events that produced them. In short, a geological concept can be developed
for identifying and mapping specific reservoir zones based on their porosity

characteristics.

2.5.2 Tertiary Rock Properties and the Seismograph

The seismograph measures reflected or refracted seismic impulses as they bounce

off or pass through layered rocks. Reflection seismology was once used only to
identify subsurface structural anomalies. Today, the greatly improved technology
and data processing methods make it possible to identify not only structural and
stratigraphic features but also, under ideal circumstances, reservoir rock and fl uid
properties. Seismic stratigraphy, the forerunner of today ’ s sequence stratigraphy, is
one of today ’ s most powerful methods for interpreting stratigraphic architecture.
Modern data processing techniques for analyzing seismic wave characteristics such
as frequency, amplitude, polarity, spatial distribution, and shear wave characteristics
enable geophysicists to make vastly more sophisticated interpretations than were
possible only a decade ago. The advent of 3D seismology has greatly advanced our
ability to interpret subsurface structure, stratigraphy, and even reservoir character-

istics. The 3D method is sufficiently powerful that in some settings, particularly in

sand− shale sequences, individual depositional bodies such as fluvial channels, deltas,

and turbidites can be identified and mapped spatially and targeted for drilling based
on whether they contain hydrocarbons, particularly gas. Today ’ s computer technol-
ogy and software can generate vivid displays of facies architecture — depositional
facies or stratigraphic features — but however vivid the displays may be, the technol-
ogy is not without limitations. The vivid technological displays of reservoir charac-
teristics require contrast in seismic velocities, or differences in acoustic impedance,
between the reservoir and its enclosing strata. The seismograph only records acous-

tic waves that have been reflected from acoustic interfaces in the subsurface; it does
not record fundamental rock properties such as texture, grain type, sedimentary
structures, or taxonomic diversity. It can not distinguish between depositional, dia-
genetic, or fracture porosity. Those distinctions have to be inferred by seismic inter-
preters who, with modern data acquisition and processing techniques, can use

reflection characteristics to help identify seismic signatures of reservoirs, particu-
larly gas reservoirs, because gas - filled pores react to seismic pulses much more pro-

foundly than oil - filled pores (Brown, 1999 ).

Acquiring good seismic reflections from a target reservoir interval depends on
the impedance contrast between the target interval and the rocks that enclose it
and on the thickness of the target interval as compared to the impulse wavelength.