Page 112 - Origin and Prediction of Abnormal Formation Pressures

92 A. GUREVICH, G.V. CHILINGAR, J.O. ROBERTSON AND E AMINZADEH

in Azerbaijan. Upward migrating fluids, especially gas, can significantly increase
pressure in the beds they intrude. As a result, the effective stress (total overburden
stress minus the fluid pore pressure) is reduced, whereas porosity remains the same.
Under such circumstances, well-logging methods may provide incorrect pressure values.
Therefore, the effects of pressure increase, caused by vertical fluid migration, should
be recognized and current pressure detection methods should be improved or, in some
cases, substituted by other methods for such zones.
Excess pressure, caused by the fluid column height, can also invalidate usage of
(1) standard porosity/pressure relations, and (2) well-logging pressure determination
methods in shales lying above such pools.
To confirm their validity, investigators compared calculated pressures in shales
with 'equilibrium' drilling mud pressures. Abnormal pressure gradients were mostly
calculated from the weight of mud columns; therefore, pressure drops due to mud
movement were not taken into account, although the head loss due to the friction
is appreciable in most cases. In some papers, reference was made to a 'static mud
pressure', which does not provide the necessary accuracy of pressure evaluation during
drilling or a trip.
Wellbore wall deformations also cannot be considered an ideal reference point.
Plasticity of shales depends on (a) mineral composition, (b) amount and nature of bound
water, and (c) the amount of 'dry' contacts and crystal bonds. Although the pressure
excess over the hydrostatic pressure contributes to the plasticity of shales, it is neither
the primary nor the only cause of plasticity. If wellbore pressure is lower than the
pressure in shales saturated with gas, expansion of gas will contribute to heaving and
sloughing of shale into the wellbore. But in the case of high plasticity, shale can flow
into the wellbore, even without the presence of abnormal fluid pressure, just under
the geostatic pressure of the overburden. Under such circumstances the 'equilibrium'
pressure of the drilling mud cannot be used to confirm calculated pressures in shales
and, thus, the validity of well-logging methods.
Calculation from well-logs show pressure gradients of 0.015-0.018 MPa/m in very
thin shale beds. It is not convincing that shale beds of about 1 to 6 m in thickness can
sustain a pressure excess above that in the adjacent sand beds for a geological period of
time. There is a real possibility that pressure in such shales, calculated from well-log
measurements, was overestimated because of lithological changes in the shale from the
external boundary of a layer to its center caused by normal cyclicity in sedimentation:
sand content increases and porosity decreases from the center outward. Calculated pore
pressure values decrease with time since the beginning of production (fluid withdrawal).
If they respond to an additional pressure difference during such a short period of
time, how could they maintain the pressure in geological time with a very significant
difference between the shale and sand pore pressures?
(4) In the Azerbaijan fields, calculated/measured pressures in shales are higher than
pressures in the sandstone reservoirs. This is only possible if the reservoirs have a
lateral conductivity high enough to discharge the excess volume of fluids to the surface
or into shallow aquifers. Therefore, for data reliability evaluation and better pressure
prediction, this conductivity and total regional and local hydrodynamic scenarios should
be analyzed for each reservoir much more thoroughly than it was done previously.