pore pressure prediction in the niger delta – lessons ... - Ikon Science

Pore Pressure Prediction in the Niger Delta
- lessons learnt from regional analysis
affected by hydrocarbon buoyancy effects. Hydrocarbons are suggested both by fluids gradients from
the pressure tests and by resistivity log response. Shales in-between the sand units are interpreted
using the under-compaction techniques mentioned previously, to have pressures above those in the
reservoirs, a common feature of the Deep- and Ultra-Deep offshore. These sands are laterally-drained
and allow horizontal pressure escape to shallower levels in the Delta and/or seabed. Supportive evidence
for this lateral drainage is seen where comparing pressures in the two deepest sands in the well i.e. the
deepest sand has pressure test data that records lower overpressures than the sand above, at shallower
stratigraphic intervals, implying differential drainage of pressures. Towards the base of the Late Miocene,
sand units are rare, and, as shale-lithology dominate, pressures increase, recorded by increases in mudweight.
Several kicks are reported in this well at this level, taken in thin sand units, therefore suggesting
this increasing shale pressure were not predicted pre-drill. Using the pressure tests at a depth of 9850
feet TVDss (or 7417 feet TVDbml) and an age of this sand unit as approximately the Top Middle Miocene
of 11.6 Ma, and the relationship displayed in Figure 4, predicts the FRD for this sedimentation rate of 638
feet (or 194m) per Ma in this well to be 0.9 km or 2950 feet TVDbml (or 5400 TVDss). The shale pressures
at depth, using the implied pore pressure trend for shales, gives a close matches to the kick data close
to the base of the Late Miocene interval i.e. using this method alone would have successfully predicted
the shale pressures and prevented drilling problems.
Figure 4 Sedimentation Rate vs. FRD (Swarbrick et al, 2002). Green arrow represents Nile Delta data (see Figure 3).
Blue arrow is data from a Niger Delta well in the study.
As part of the Study, we analysed “FRD’s” from 15 selected wells all with well-defined stratigraphy, gamma
ray, sonic, resistivity and density logs and pressure data – to complete this analysis, all of these criteria
need to be fulfilled. The majority of these wells give a close match between extrapolating our shalebased
interpretation to intersect the hydrostatic line, and a calculation of FRD based on sedimentation