reservoir geomecanics

374 Reservoir geomechanics
Figure 11.19 are somewhat different than those introduced previously. In this case, the
abscissa represents total stress, rather than effective stress, such that one can plot pore
pressure, as well as the stress magnitudes on the diagram. Hence, the conditions under
which the caprock hydrofracs is one in which the pore pressure in the sand reservoir
(P ss
p
) reaches the value of the least principal stress in the shale (left edge of Mohr circle).
Note that the pore pressure in the sand, P ss
p ,exceeds Psh p , the pore pressure in the shale.
The conditions under which dynamic fault slip occurs is shown in Figure 11.19b.
Note that as in the hydrofrac case, the pore pressure in the reservoir at the top of
the structure exceeds that in the shale but does not reach the value of the least principal
stress. Rather, because of the presence of the reservoir-bounding fault at the top of the
structure, the pore pressure induces slip at a pressure in the reservoir, P ss
p ,atwhich the
Mohr circle touches the failure line. Hence, slip on the reservoir bounding fault occurs
at a lower pressure than that required for hydraulic fracturing. In other words, breach of
the sealing faulting and fluid migration may occur at an earlier stage as is often assumed.
Under conventional structural controls on reservoir column heights (or capillary leakage),
the pore pressure in the sand is below that in the shale (such that there is no centroid)
and below that at which either hydraulic fracturing or fault slip occurs (Figure 11.19c).
We apply these concepts to the South Eugene Island 330 field located 160 km offshore
of Lousiana in the Gulf of Mexico following the study of Finkbeiner, Zoback et al.
(2001). South Eugene Island 330 is a Pliocene-Pleistocene salt-withdrawal minibasin
bounded by the north and east by a down to the south growth fault system (Alexander and
Flemings 1995). A cross-section of the field is shown in Figure 2.6aandamap of the OI
sand, one of the major producers in the area, is shown in Figure 2.7. There were several
questions that motivated the Finkbeiner, Zoback et al. (2001) study, including why there
are such different hydrocarbon columns in adjacent compartments (as illustrated for
fault blocks A and B in the OI sand in Figure 2.7). Note that while there is an oil column
of several hundred feet in fault blocks A, D and E there is a very large gas column (and
much smaller oil columns) in fault blocks B and C. While fault blocks B and C (and
D and E) appear to be in communication across the faults that separate them, fault
blocks A and B (and C and D) are clearly separated. As there appears to be an ample
source of hydrocarbons to fill these reservoirs (S. Hippler, personal communication),
why are fault blocks A, D and E not filled-to-spill? Astill more fundamental question
about this oil field is of how such a large volumes of hydrocarbons could have filled
these extremely young sand reservoirs separated by large thicknesses of essentially
impermeable shale (Figure 2.6). The South Eugene Island field is one of the largest
Plio-Pleistocene oil and gas reservoirs in the world and yet the manner in which the
reservoirs have been filled is not clear (Anderson, Flemings et al. 1994).
To examine these questions, Finkbeiner, Zoback et al. (2001) made a detailed examination
of pressures in various reservoirs. As shown in Figure 11.20a, in South Eugene
Island fault block A, the JD, KE, LF, NH and OI sands all indicate clear centroid effects
with the gas (or oil) pressure at the top of the reservoirs exceeding the shale pore pressure
at equivalent depths (Figure 2.8b). However, only in the OI sand does there appear