An Interval velocity profile is usually used to predict pore pressure especially where existing calibration well data are scarce (Fig. 1) . However, using seismic velocity to predict pore pressure in a proposed well location is not the only decisive answer. The velocity changes in the shale (i.e., low-permeability beds) are result of compaction disequilibrium and additional secondary petrophysical alterations, such as cementation and diagenesis. In addition to these aforementioned factors, subsurface pressure profile development in shale and sand is greatly impacted by the basin geological setting, pressure decay process, and the presence of hydrocarbon.
The mistake of assuming there is immediacy between the pressure in the sand and the interbedded shale leads to serious drilling and exploration assessment problems. Understanding the geological setting of the explored basin, compartmentalization, and the expected hydrocarbon pressure are essential to establish this relationship. The structural setting of a prospect and the fault plane lithology juxtaposition play a substantial role in pressure differential distribution in sand vs. shale. On the structural crest, the pore pressure in the sand usually exceeds the predicted pore pressure in the shale. The presence of hydrocarbon, especially gas, frequently leads to a significant increase of the reservoir pore pressure relative to the pore pressure estimated in the seal shale.
To establish this relationship and foresee the pore pressure shifts between seals and reservoirs, several issues should be considered:
- Pressure decay, sedimentation rate and aging
- The geological setting
- Centroid effect due to the structural relief
- Hydrocarbon presence.
Pressure decay and sedimentation rate. The rate of sedimentation accompanied by the subsiding of the basin, to accommodate for the influx of sediments, is responsible for the pore pressure acceleration. This is due to the increase of the principal stress (overburden). In active basins where the sedimentation rate exceeds or equals the rate of accommodation pore pressure accelerates with depth (Fig. 2) . On the other hand, in basins where deposition has been ceased, pressure decay takes place.
The rate of pressure decay is subjected to the communication between the deeper section and the shallow compartments. The communication usually takes place across the seals and/or through structural passages such as faults, amalgamated sediments, and gouge zones. The decay across the seals is very slow and does not cause a great shift between the measured and predicted pore pressure. In case of structural failure, the communication between the deep and shallow compartments leads to a pressure regression and accelerates the pressure decay in the seals. Therefore, the pressure in the sand (MPP) regresses very fast (Fig. 3) relative to the pressure regression in the shale (PPP). The misfit in this case depends on the time lapse between the structural failures and the rate of decay in the seal (Fig. 4) .
Deposits, geometry and facies change. In fluvial clastic basins, sediments are deposited in different architectural forms and lithology. They range from mouth bars in the shallow water to basin floor fans in the abyss. High and low sea level stands play an essential role in the vertical distribution of seals and compartments. This complex facies laid out on a spatial scale in a basin results in creating zones of communication between amalgamated permeable beds. These breaching zones usually exist at the shallow up-dip flanks where coarse deposits dominate.
In this case the pressure profile is represented by a hydrostatic gradient at the shallow section (normally pressured). The pore pressure (PP) will show a progressive gradient, in the upper effective seal (geopressure cap). The pressure gradient (PG) returns to the hydrostatic gradient, as soon as the drill bit penetrates a sand body in this abnormally pressured section. The cascade progressive trend accelerates with depth until the borehole trajectory penetrates a reservoir type rock in communication with a shallower one. As a result, reservoir pressure (MPP) shows a regression and returns to the same envelope of the shallow bed that has the same gradient (Fig. 5) . The porosity profile (velocity derived) usually echoes the pressure behavior in seals.
Fault surface and lithology juxtaposition. The fault displacement contemporaneous to either sedimentation or post- lithification brings different lithology in contact. In the growth fault system sand sediment shows a substantial thickening on the downthrown side. Therefore, the fault surface exhibits a sealing segment where shale beds obstruct fluid flow from the juxtaposing sand. On the other hand, where permeable beds meet, communication takes place (Fig. 6) . › Salt-sediment interface Along the salt-sediment interface dragging and brecciation take place. This gouge interface sometimes acts as a good fluid flow path. On the other hand, where sandy facies pinch out down dip from this interface a perfectly sealed compartment exists.
The pore pressure profile of a borehole targeting the multiple closures on a salt basin flank will follow the same concept. Pressure progression takes place in the geopressured section as long as the salt-sediment interface is sealed. On the other hand, pressure regression happens where sand beds communicate with shallower reservoir-type rocks through the gouged interface. The velocity profile usually accounts for the compaction disequilibrium in the shale rather than the pressure gradients envelope shifts in the reservoir type beds (Fig. 7) .
Centroid effect. The centroid concept predicts how the pressure in the reservoir and the top seal changes as a result of structural relief. The concept assumes that PPP and MPP are equal at a hypothetical point (centroid) on the structure. The sand subsurface pressure profile follows the hydrostatic gradient whereas seals follow a higher gradient. Up-dip from the centroid, the sand pressure exceeds the shale pressure at the shale-sand interface depending on the structural gain. On the other hand, down-dip MPP exhibits lesser value than the overlying PPP (Fig. 8) .
Hydrocarbon accumulation. Hydrocarbons are usually lighter than the formation water. The pressure gradient of fresh water is 0.433 psi/ft. The pressure gradient of light oil (s.g. 0.85 g/cc) is about 0.37 psi/ft and about 0.086 psi/ft for gas (s.g. 0.20 g/cc). › These gradients possess a linear trend in permeable reservoir- type rock. In oil-or gas-bearing sand the hydrocarbon gradient overrides the formation water gradient envelopes and inflates the original pressure in the compartment (Fig. 9) . The new excess pressure generated by the presence of hydrocarbon and the capillary forces substantially increases the pore pressure in the cap seal, especially at the sand/shale interface. Interval velocity can miss this localized relatively thin zone owing to acquisition, processing and sampling.
It is important to diagnose the shift in pore pressure envelopes across bedding interfaces, especially between shale and sand. Depositional geometry, unconformities, and structural failures (i.e., f